UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| /X/ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20042006
OR
| / / | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | For the transition period from ___________ to ___________ |
Commission File Number | Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, zip code telephone number | I.R.S. Employer Identification Number |
| 1-16305 | PUGET ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-1969407 |
| 1-4393 | PUGET SOUND ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-0374630 |
Securities registered pursuant to Section 12(b) of the Act:
| | Title Of Each Class | Name Of Each Exchange On Which Listed |
Puget Energy, Inc. | Common Stock, $0.01 par value | NYSE |
| | Preferred Share Purchase Rights | NYSE |
| | | |
Puget Sound Energy, Inc.
| 8.4% Capital Securities | NYSE |
Securities registered pursuant to Section 12(g) of the Act:
| | Title Of Each Class | |
Puget Sound Energy, Inc. | Preferred Stock (cumulative, $100 par value) | |
| | 8.231% Capital Securities | |
Puget Sound Energy, Inc. meets the conditions set forth in General Instructions I(1)I (1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
| Puget Energy, Inc. | Yes | /X/ | No | / / | | Puget Sound Energy, Inc. | Yes | /X/ | No | / / |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| Puget Energy, Inc. | Yes | / / | No | /X/ | | Puget Sound Energy, Inc. | Yes | / / | No | /X/ |
Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
| | Puget Energy, Inc. | Yes | /X/ | No | / / | | Puget Sound Energy, Inc. | Yes | /X/ | No | / / |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. / /
Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
| Puget Energy, Inc. | Large accelerated filer | /X/ | Accelerated filer | / / | Non-accelerated filer | / / |
| Puget Sound Energy, Inc. | Large accelerated filer | / / | Accelerated filer | / / | Non-accelerated filer | /X/ |
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).12b-2 of the Act)
| | Puget Energy, Inc. | Yes | /X/ / | No | / /X/ | | Puget Sound Energy, Inc. | Yes | / / | No | /X/ |
The aggregate market value of the voting stock held by non-affiliates of Puget Energy, Inc., computed by reference to the price at which the common stock was last sold, as of the last business day of Puget Energy’s most recently completed second fiscal quarter was approximately $2,127,279,000.$2,411,121,000. The number of shares of Puget Energy, Inc.’s common stock outstanding at February 23, 200521, 2007 was 99,889,474116,723,205 shares.
All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.
Documents Incorporated by Reference
Portions of the Puget Energy, Inc. proxy statement for its 20052007 Annual Meeting of Shareholders to be filed with the Commission pursuant to Regulation 14A not later than 120 days after December 31, 20042006 are incorporated by reference in Part III hereof.
This Annual Report on Form 10-K is a combined report being filed separately by two different registrants: Puget Energy, Inc. and Puget Sound Energy, Inc. Puget Sound Energy, Inc. makes no representation as to the information contained in this report relating to Puget Energy, Inc. and the subsidiaries of Puget Energy, Inc. other than Puget Sound Energy, Inc. and its subsidiaries.
| AFUDC | Allowance for Funds Used During Construction |
| BPA | Bonneville Power Administration |
| CAISO | California Independent System Operator |
COE | United States Army Corps of Engineers |
| Dth | Dekatherm (one Dth is equal to one MMBtu) |
| Ecology | Washington State Department of Ecology |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FIN | Financial Accounting Standards Board Interpretation |
| FPA | Federal Power Act |
HCPIRP | Habitat Conservation PlansIntegrated Resource Plan |
| InfrastruX | InfrastruX Group, Inc. |
kW | Kilowatts (one kilowatt equals one thousand watts) |
| kWh | Kilowatt HoursHour (one kWh equals one thousand watt hours) |
| LIBOR | London Interbank Offered Rate |
| LNG | Liquefied Natural Gas |
| MMBtu | One Million British Thermal Units |
| MMS | Minerals Management Service of the United States |
| MW | MegawattsMegawatt (one MW equals one thousand kW) |
| MWh | Megawatt HoursHour (one MWh equals one thousand kWh) |
NOPRNinth Circuit | NoticeUnited States Court of Proposed RulemakingAppeals for the Ninth Circuit |
| NYSE | New York Stock Exchange |
| PCA | Power Cost Adjustment |
| PCORC | Power Cost Only Rate Case |
| PGA | Purchased Gas Adjustment |
| PG&E | Pacific Gas & Electric Company |
| PSE | Puget Sound Energy, Inc. |
| PUDs | Washington Public Utility Districts |
| Puget Energy | Puget Energy, Inc. |
| PURPA | Public Utility Regulatory Policies Act |
| RFP | Request for Proposal |
| RTO | Regional Transmission Organization |
| SEC | United States Securities and Exchange Commission |
| SFAS | Statement of Financial Accounting Standards |
SMDTenaska | FERC Standard Market DesignTenaska Power Fund, L.P. |
| Washington Commission | Washington Utilities and Transportation Commission |
| WECO | Western Energy Company |
Puget Energy, Inc. (Puget Energy) and Puget Sound Energy (PSE) are including the following cautionary statements in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE. This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “future,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue” or similar expressions identify forward-looking statements.
Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. Puget Energy’s and PSE’s expectations, beliefs and projections are expressed in good faith and are believed by Puget Energy and PSE, as applicable, to have a reasonable basis, including without limitation management’s examination of historical operating trends, data contained in records and other data available from third parties; but there can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.
In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for Puget Energy and PSE to differ materially from those discussed in forward-looking statements include:
Risks relating to the regulated utility business (PSE)
· | governmental· | Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, financings,cost recovery, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, operation of distribution and transmission facilities (gas and electric), licensing of hydroelectric operations and gas storage facilities, recovery of other capital investments, recovery of power and gas costs, recovery of regulatory assets and present or prospective wholesale and retail competition; |
· | financial· | Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, emissions, natural resources, and fish and wildlife (including the Endangered Species Act); |
| · | The ability to recover changes in enacted federal, state or local tax laws through revenue in a timely manner; |
| · | Natural disasters, such as hurricanes, earthquakes, floods, fires and landslides, which can cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials; |
| · | Commodity price risks associated with procuring natural gas and power in wholesale markets that impact customer loads; |
| · | Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers; |
| · | Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways and also adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from itsit suppliers; |
· | wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks; |
·
· | theThe effect of wholesale market structures (including, but not limited to, newregional market design such as Grid West, a regionaldesigns or transmission organization, and Standard Market Design);organizations) or other related federal initiatives; |
| · | PSE electric or gas distribution system failure, which may impact PSE’s ability to adequately deliver gasenergy supply to its customers; |
· | · | Changes in weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenues, thus impacting net income; |
| · | Weather, which can have a potentially serious impact on PSE’s revenues and its ability to procure adequate supplies of gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies; |
· | variable hydroelectric· | Variable hydro conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities; |
· | plant· | Plant outages, which can have an adverse impact on PSE’s expenses as it procures adequate supplieswith respect to repair costs, added costs to replace the lost energy or dispatcheshigher costs associated with dispatching a more expensive resource; |
· | the· | The ability of gas or electric plant to operate as intended, which if not in proper operating condition or design could limit the capacity of the operating plant;intended; |
· | the· | The ability to renew contracts for electric and gas supply and the price of renewal; |
· | blackouts· | Blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can have an impact onaffect PSE’s ability to deliver loadpower or natural gas to its customers; |
· | the· | The ability to restart generation following a regional transmission disruption; |
· | failure· | Failure of the interstate gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver gas supply to its customers; |
· | the ability to relicense FERC hydroelectric projects at a cost-effective level; |
·
· | theThe amount of collection, if any, of PSE’s receivables from the California Independent System Operator (CAISO) and other parties and the amount of refunds found to be due from PSE to the CAISO or other parties; |
· | industrial,· | Industrial, commercial and residential growth and demographic patterns in the service territories of PSE; |
· | general· | General economic conditions in the Pacific Northwest, which might impact customer consumption or affect PSE’s accounts receivable; and |
· | the· | The loss of significant customers or changes in the business of significant customers, which may result in changes in demand for PSE’s services.services; |
Risks relating to the non-regulated utility service business (InfrastruX Group, Inc.)
· | the ability of Puget Energy to complete a sale of its interests in InfrastruX to a third party under reasonable terms; |
·
· | the failure of InfrastruX to service its obligations under its credit agreement, in which case Puget Energy, as guarantor, may be required to satisfy these obligations, which could have a negative impact on Puget Energy’s liquidity and access to capital; |
· | the inability to generate internal growth at InfrastruX, which could be affected by, among other factors, InfrastruX’s ability to expand the range of services offered to customers, attract new customers, increase the number of projects performed for existing customers, hire and retain employees and open additional facilities; |
· | the effect of competition in the industry in which InfrastruX competes, including from competitors that may have greater resources than InfrastruX, which may enable them to develop expertise, experience and resources to provide services that are superior in quality or lower in price; |
· | the extent to which existing electric power and gas companies or prospective customers will continue to outsource services in the future, which may be impacted by, among other things, regional and general economic conditions in the markets InfrastruX serves; |
· | delinquencies, including those associated with the financial conditions of InfrastruX’s customers; |
· | the impact of any goodwill impairments on the results of operations of InfrastruX arising from its acquisitions, which could have a negative effect on the results of operations of Puget Energy; |
· | the impact of adverse weather conditions that negatively affect operating conditions and results; |
· | the ability to obtain adequate bonding coverage and the cost of such bonding; and |
· | the perception of risk associated with its business due to a challenging business environment. |
Risks relating to both the regulated and non-regulated businesses
· | theThe impact of acts of God, terrorism, flu pandemic or similar significant events; |
· | the ability of Puget Energy, PSE and InfrastruX to access the capital markets to support requirements for working capital, construction costs and the repayment of maturing debt; |
·
· | capitalCapital market conditions, including changes in the availability of capital or interest rate fluctuations; |
· | changes in Puget Energy’s or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy, PSE and InfrastruX; |
·
· | legal and regulatory proceedings; |
· | the ability to recover changes in enacted federal, state or local tax laws through revenue in a timely manner; |
· | changes in, adoption of and compliance with laws and regulations including environmental and endangered species laws, regulations, decisions and policies concerning the environment, natural resources, and fish and wildlife (including the Endangered Species Act); |
· | employeeEmployee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive; |
· | the ability to obtain and keep patent or other intellectual property rights to generate revenue; |
·
· | theThe ability to obtain adequate insurance coverage and the cost of such insurance; |
· | · | Future losses related to corporate guarantees provided by Puget Energy as a part of the impactssale of natural disasters such as earthquakes, hurricanes, floods, fires or landslides;its InfrastruX subsidiary; and |
· | the impact of adverse weather conditions that negatively affect operating conditions and results; |
·
· | theThe ability to maintain effective internal controls over financial reporting; andreporting. |
· | the ability to maintain customers and employees. |
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, Puget Energy and PSE undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. You are also advised to consult the quarterly reports on Form 10-Q and current reports on Form 8-K, as well as Item 1A-“Risk Factors” on this Form 10-K.
Puget Energy, Inc. (Puget Energy) is an energy services holding company incorporated in the Statestate of Washington in 1999. All of its operations are conducted through its subsidiaries,subsidiary, Puget Sound Energy, Inc. (PSE), a utility company, and InfrastruX Group, Inc. (InfrastruX), a construction services company. Puget Energy has no significant assets other than the stock of its subsidiaries. Subject to limited exceptions,PSE. On May 7, 2006, Puget Energy is exempt from regulationsold its 90.9% interest in InfrastruX Group, Inc. (InfrastruX) and therefore the financial position and results of operations for InfrastruX are presented as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935.discontinued operations. Puget Energy and PSE are collectively referred to herein as “the Company.” The following table provides the percentages of Puget Energy’s consolidated continuing operating revenues and net income generated and assets held by the reportableoperating segments:
Segment | Percent of Revenue | | Percent of Net Income | | Percent of Assets | |
| | 2004 | 2003 | | 2002 | | 2004 | | 2003 | | 2002 | | 2004 | | 2003 | | 2002 | |
Puget Sound Energy1 | | 85.3 | % | 85.4 | % | | 85.8 | % | | 224.2 | % | | 98.1 | % | | 87.4 | % | | 94.5 | % | | 92.7 | % | | 92.2 | % |
| InfrastruX | | 14.4 | % | 14.3 | % | | 13.8 | % | | (127.8 | )% | | 1.5 | % | | 8.6 | % | | 4.3 | % | | 6.0 | % | | 5.5 | % |
| Other subsidiaries | | 0.3 | % | 0.3 | % | | 0.4 | % | | 3.6 | % | | 0.4 | % | | 4.0 | % | | 1.2 | % | | 1.3 | % | | 2.3 | % |
Segment | Percent of Revenue | Percent of Net Income | Percent of Assets |
| | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 |
| Puget Sound Energy | 99.7% | 99.7% | 99.7% | 103.3% | 91.7% | 224.2% | 99.0% | 94.8% | 94.2% |
InfrastruX1,2 | 0% | 0% | 0% | 0% | 6.1% | (127.8)% | 0% | 4.2% | 4.6% |
Other3 | 0.3% | 0.3% | 0.3% | (3.3)% | 2.2% | 3.6% | 1.0% | 1.0% | 1.2% |
______________________________________________
1 | Net income for PSEInfrastruX is presented on a discontinued operations basis beginning in 2005 and therefore does not present operating revenue. Operating revenue in 2004 has been reclassified as net income for common stock due to $5.2 million and $7.8 million of preferred stock dividend being treated as an other deduction atdiscontinued operations.
|
2 | In 2004, Puget Energy recorded Goodwill impairment of $76.6 million after-tax which resulted in 2003a loss at InfrastruX. |
3 | Includes subsidiaries of PSE and 2002, respectivelyPuget Energy holding company operations. 2006 includes the impact of the establishment and funding of a charitable foundation. |
Additional financial data regarding these segments are included in Note 24, to the Consolidated Financial Statements included with this report.
Puget Energy Strategy
Puget Energy is the parent company of the largest electric and natural gas utility headquartered in the Statestate of Washington, primarily engaged in the business of electric transmission, distribution, and generation and natural gas transmission and distribution. Puget Energy’s business strategy is to generate stable earnings and cash flow by focusing primarily on the regulated utility business conducted through PSE. The key elements of this strategy include:
Focus on regulated utility business. PSE intends to continue to focus on its core electric and natural gas transmission and distribution utility business, offering reliable electric and gas service atin a fair value to PSE’s customers.
Add electric generation and delivery infrastructure to meet customer needs. Ensuring reliable, low-cost energy supply is one of PSE’s highest priorities. As regional demand for energy continues to grow, PSE’s committed power supply resources will not be adequate to meet anticipated demand, especially as existing long-term power purchase contracts begin to expire. Accordingly, PSE is continually seeking new electric power resource generation and long term purchase power agreements to meet load requirements and ensure stable cost-based energy supply within its service territory. During 2004, PSE made the following strides in this goal:
· | Purchased a 49.85% interest in a 250 MW capacity gas-fired generation facility in western Washington, which went into service in April 2004. |
· | Signed a two-year purchase power agreement in the second quarter 2004 with a utility for 85 MW of energy with delivery beginning January 1, 2005. |
· | Signed a non-binding letter of intent in September 2004 to purchase a wind generation facility with up to 230 MW of generation to be developed in central Washington State. |
· | Signed a non-binding letter of intent in October 2004 to purchase a wind generation facility with up to 150 MW of generation to be developed in eastern Washington State. |
Rebuild financial strength to fund energy infrastructure and manage energy portfolio. PSE intends to focus on the regulated business to improve its credit quality and liquidity and to provide predictable earnings to attract investors in Puget Energy.
Provide return to Puget Energy shareholderscost effective manner through earnings growth and dividends. Generate return and attract equity capital through growth in PSE earnings and dividends.
Achieve PSE earnings growth. PSE earnings will grow through rebuilding common equity and increasing ratebase by adding generating and delivery resources where needed with timely cost recovery. Puget Energy was able to invest additional capital in PSE through the sale of its common stock.
After completing a strategic review of InfrastruX, Puget Energy has decided to exit the construction services sector. Puget Energy’s Board of Directors approved the decision on February 8, 2005. The decision to exit the business is the result of the Company’s need to invest in the core utility business to acquire or construct energy generating resources and energy delivery infrastructure. During 2005, Puget Energy intends to monetize its interest in InfrastruX through sale or third party recapitalization and invest the proceeds in PSE.
PUGET SOUND ENERGY, INC.Puget Sound Energy, Inc.
PSE is a public utility incorporated in the Statestate of Washington.Washington in 1960. PSE furnishes electric and gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region of the Statestate of Washington.
At December 31, 2004,2006, PSE had approximately 1,001,2001,039,400 electric customers, consisting of 884,500918,200 residential, 110,500114,600 commercial, 3,9003,800 industrial and 2,3002,800 other customers; and approximately 672,000713,000 gas customers, consisting of 619,000658,100 residential, 50,20052,100 commercial, 2,700 industrial and 100 transportation customers. At December 31, 2004,2006, approximately 324,200342,200 customers purchased both electricity and gas from PSE. For the year 2004,In 2006, PSE added approximately 23,50021,300 electric customers and approximately 27,40019,400 gas customers, representing annualized customer growth rates of 2.4%2.1% and 4.2%2.8%, respectively. During 2004,2006, PSE’s billed retail and transportation revenues from electric utility operations were derived 47%49.3% from residential customers, 44%42.8% from commercial customers, 7%6.3% from industrial customers and 2%1.6% from transportation and other customers. PSE’s retail revenues from gas utility operations were derived 63%63.2% from residential customers, 30%30.4% from commercial customers, 5%5.2% from industrial customers and 2%1.2% from transportation customers.customers in 2006. During this period the largest customer accounted for approximately 1%1.2% of PSE’s operating revenues.
PSE is affected by various seasonal weather patterns throughout the year and therefore, utility revenues and associated expenses are not generated evenly during the year. Variations in energyEnergy usage by consumers occur from season to seasonvaries seasonally and from month to month within a season,monthly primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales in the first and fourth quarters of the year. Sales of electricity to wholesale customers also vary by quarter and year depending principally upon fundamental market factors and weather conditions. PSE has a purchased gas adjustment (PGA) mechanism in retail gas rates to recover variations in gas supply and transportation costs. PSE also has a power cost adjustment (PCA) mechanism in electric rates to recover variations in electricity costs on a shared basis between customers and PSE.with customers.
In the five-year period ended December 31, 2004,2006, PSE’s gross electric utility plant additions were $786 million$1.5 billion and retirements were $290$300.6 million. In the same five-year period, ended December 31, 2004, PSE’s gross gas utility plant additions were $586$686.7 million and retirements were $74$92.1 million. In the same five-year period, PSE’s gross common utility plant additions were $128$273.6 million and retirements were $33$50.3 million. Gross electric utility plant at December 31, 20042006 was approximately $4.4$5.3 billion, which consisted of 60%54.2% distribution, 26%31.6% generation, 6%6.2% transmission and 8%8.0% general plant and other. Gross gas utility plant as ofat December 31, 20042006 was approximately $1.9$2.1 billion, which consisted of 85%93.0% distribution 7% transmission and 8%7.0% general plant and other. Gross common utility general and intangible plant at December 31, 20042006 was approximately $410$458.3 million.
INFRASTRUX GROUP, INC.InfrastruX Group, Inc.
InfrastruX, a non-regulated construction services business, was incorporated in the Statestate of Washington in 2000 to pursue the non-regulated construction services business. InfrastruX provides infrastructure construction services to the electric and gas utility industries. InfrastruX has acquired 12 companies, primarily in the Midwest, Texas, south-central and eastern United States, that are engaged in some or all of the following services and activities in their respective regions or nationally:
· | Electric: Overhead and underground power line and cable construction, installation and maintenance, including high-voltage transmission and distribution lines, copper and fiberoptic cables; duct installation; revitalization and damage prevention for underground power lines and cables using the patented Cablecure® treatment; substation construction; and other specialty services for new and existing infrastructures.
|
· | Gas: Large-diameter pipeline installation and maintenance; service lines and meters; conventional river crossings and bridge maintenance; cathodic protection; power station fabrication and installation; vacuum excavation; hydrostatic testing; internal pipeline inspection; product pipelines; and other specialty services for distribution and transmission pipeline services including small, mid-size and large-bore directional drilling for virtually all pipeline diameters and soil conditions.
|
Following a strategic review of InfrastruX conducted by2000. On May 7, 2006, Puget Energy management, on February 8, 2005, Puget Energy’s Board of Directors decided to exit the utility construction services sector. During 2005, Puget Energy intends to monetizesold its 90.9% interest in InfrastruX through a sale or third party recapitalization and to invest the proceeds in PSE. The costs associated with exiting the InfrastruX business cannot be quantified at this time. However,an affiliate of Tenaska Power Fund, L.P. (Tenaska). Puget Energy believes that such costs will not be material given the effects of the impairment charge recorded in the fourth quarter 2004.
InfrastruX is affected by seasonal weather conditions and, therefore, revenues and associated expenses are not generated evenly during the year. InfrastruX will usually experience its highest revenues in the second and third quarter of the year, as spring and summer months are routinely the most productive time of yearaccounted for the construction industry due to longer daylight hours and generally better weather conditions.
InfrastruX’s operating strategy revolves around leveraging the synergies of a core group of outstanding infrastructure construction contractors whose asset base, expertise, local knowledge, relationships and years of successful operations form a strong base for a growing business. The ability to share workforce, production equipment and expertise within and between regional geographies allows InfrastruX to provide local support for its customers and also move quickly to provide additional services as needs arise. The formation of regional service centers in 2003, where appropriate, is providing enhanced oversight and control as well as cost efficiencies surrounding back office operations, equipment control and other operational areas.
The construction services industry is both highly competitive and highly fragmented as a result of low barriers to entry, the historical geographic segmentation of utility customers and the natural limitations of service delivery. Competitors of InfrastruX include large established and emerging national companies and many smaller regional companies.discontinued operation.
EMPLOYEESEmployees
At February 23, 2005,21, 2007, Puget Energy had no employees and its subsidiariesPSE had approximately 4,9002,400 full-time employees:
Puget Sound Energy | 2,200 |
InfrastruX | 2,700 |
Total Puget Energy | 4,900 |
employees. Approximately 1,1001,142 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) or the United Association of Plumbers and Pipefitters (UA). The current labor contracts with the IBEW and UA run through March 31, 2007 and 2006,September 30, 2010, respectively.
Approximately 300 InfrastruX employees are represented by The Company is currently in contract discussions with the IBEW, UA, United Steelworkers of America, Laborers International Union of North America or other unions. Some unions have annual contract renewals while others have multiple-year contracts.IBEW.
CORPORATE LOCATIONCorporate Location
Puget Energy’s and PSE’s principal executive offices are located at 10885 NE 4th Street, Suite 1200, Bellevue, Washington 98004 and the telephone number is (425) 454-6363.
AVAILABLE INFORMATIONAvailable Information
The Company’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available or may be accessed free of charge through the Investors section of the Company’s website at www.pse.com as soon as reasonably practicablewww.pugetenergy.com after the reports are electronically filed with, or furnished to, the SEC. It is not intended that the Company’s websiteUnited States Securities and the information contained therein or connected thereto be incorporated into this Annual Report on Form 10-K.Exchange Commission (SEC). Information may also be obtained via the SEC Internet website at www.sec.gov.
In addition, the following corporate governance materials of the Company are available in the Investors section of the Company’s website and a copy will be mailed upon request. Requests should be made to Puget Energy, Inc., Investor Services, P.O. Box 97034, PSE-08S,PSE-08N, Bellevue, Washington 98009-9734.
| · | Corporate Governance Guidelines; |
| · | Corporate Ethics and Compliance Code; |
· | Audit Committee, Governance and Public Affairs Committee and Compensation and Leadership Development Committee charters;· | Charters of Board Committees; and |
| · | Code of Ethics for the Company’s Chief Executive Officer and senior financial officers. |
If the Company waives any material provision of its Code of Ethics for its Chief Executive Officer (CEO) and senior financial officers or its Corporate Ethics and Compliance Code, or substantively changes the codes for any specific officer, the Company will disclose that waiver on its website within fivefour business days.
NEW YORK STOCK EXHANGE CERTIFICATIONNew York Stock Exchange Certification
On May 6, 2004,24, 2006, the Chief Executive OfficerCEO of Puget Energy and PSE filed a Section 303A.12(a) CEO Certification with the New York Stock Exchange.Exchange (NYSE). The CEO Certification attests that the Chief Executive OfficerCEO is not aware of any violations by the Company of the NYSE’s Corporate Governance Listing Standards.
PSE is subject to the regulatory authority ofof: (1) the WashingtonFederal Energy Regulatory Commission as to retail utility rates, accounting, the issuance of securities and certain other matters and (2) FERC(FERC) with respect to the transmission of electric energy, the resale of electric energy at wholesale, accounting and certain other matters; and (2) the Washington Utilities and Transportation Commission (Washington Commission) as to retail rates, accounting, the issuance of securities and certain other matters.
ELECTRIC REGULATION AND RATES
WASHINGTON COMMISSION MATTERS
On February 18, 2005, the Washington Commission approved a 4% general tariff electric rate case increase to recover higher costs of providing electric service to customers. The rate increase will increase electric revenues by approximately $56.6 million annually effective March 4, 2005. In the order, the Washington Commission also approved a capital structure containing 43% common equity with a return on common equity of 10.3%. In the proceeding PSE had filed a request for an increase of 7.1% or $99.8 million annually on final rebuttal during the rate case, reflecting updated power costs for increases in natural gas prices for generating plants.
The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a disallowance of $25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which was recorded by PSE as a Purchased Electricity expense in the second quarter 2004. The order also established guidelines for future recovery of Tenaska costs. The amounts were determined to be a $25.6 million disallowance for the PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period (July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s methodology of 50% disallowance on the return on the Tenaska regulatory asset due to projected costs exceeding the benchmark during the period. For the PCA 3 period, approximately $5.6 million was disallowed in the period July 1, 2004 through December 31, 2004, primarily as a reduction to Electric Operating Revenue. While the Washington Commission did not expressly address the disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE estimated the disallowance for the PCA 2 period to be approximately $12.2 million if the Washington Commission were to follow the same methodology as they have ordered for the PCA 3 period. Therefore, PSE recorded a $12.2 million disallowance to Purchased Electricity expense in the second quarter 2004 for the 50% disallowance of the return on the Tenaska regulatory asset in accordance with the Washington Commission’s methodology discussed in their order of May 13, 2004 for a cumulative impact on earnings of $43.4 million in 2004 for the PCA 1, PCA 2 and PCA 3 periods. PSE has filed the PCA 2 period compliance filing and anticipates it will be concluded no later than the first quarter 2005. As a result of the disallowance recorded, the PCA customer deferral was expensed and a reserve was established for amounts not previously deferred under the PCA mechanism. The reserve balance as of December 31, 2004 was $3.2 million, which is expected to be utilized in 2005 as excess power costs are shared through the PCA mechanism.
PSE filed the PCA 2 period compliance filing in August 2004 and received an order from the Washington Commission on February 23, 2005. In the PCA 2 compliance order, the Washington Commission approved the Washington Commission staff’s recommendation for an additional return related to the Tenaska regulatory asset in the amount of $6.1 million related to the period July 1, 2003 through December 31, 2003. Washington Commission staff’s recommendation was opposed by certain other parties. This amount alters the PCA deferral and is subject to reconsideration and appeal by other parties. Parties have 10 days from February 23, 2005 to file for reconsideration and 30 days to appeal the order. Once the statutory appeal process has concluded and the Washington Commission issues its final order, PSE will determine if recording a regulatory asset is appropriate.
In the May 13, 2004 order, the Washington Commission established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
The Washington Commission guidelines for determining future recovery of the Tenaska costs (gas costs, recovery of the Tenaska regulatory asset and return on the Tenaska regulatory asset) are as follows:
1. | The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
2. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs. |
3. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
a) | actual Tenaska costs that exceed the benchmark; or |
b) | the return on the Tenaska regulatory asset. |
4. | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs. |
The Washington Commission confirmed that if the Tenaska gas costs are deemed prudent, PSE will recover the full amount of actual gas costs and the recovery of the Tenaska regulatory asset even if the benchmark is exceeded.
In the first quarter 2004, a counterparty of a physical gas supply contract for one of PSE’s electric generating facilities notified PSE that it would be unable to deliver physical gas supply beginning in November 2005 through the end of the contract in June 2008. In October 2004, PSE and the counterparty reached a settlement on the non-deliverable period of November 2005 through June 2008. The agreement allows PSE to recover a portion of the present value of the difference in future market prices of physical gas and the original contract price, for a total recovery of approximately $10.1 million. In October 2004, PSE entered into a new contract with another counterparty for the period November 2005 through June 2008 to replace the physical gas supply from the previously mentioned amended contract. Also, in the fourth quarter 2004, an accounting order was approved by the Washington Commission to defer the counterparty settlement amount as a regulatory liability and amortize the benefit over the period of November 2005 through June 2008 as a reduction in Electric Generation Fuel expense. In its accounting order, the Washington Commission reserved the right to review the prudence of the level of settlement payments agreed to and the cost of the replacement contract during any affected PCA periods going forward.
On June 20, 2002, the Washington Commission issued final regulatory approval of the comprehensive electric rate settlement submitted by PSE, key constituents and customer groups, Washington Commission staff and the Washington State Attorney General’s Public Counsel Section. The authorization granted PSE a 4.6% electric general rate increase that began July 1, 2002, which was intended to generate approximately $59 million in additional revenue annually. In addition, the settlement provided for an 8.76% overall return on capital based on a projected capital structure with an equity component of 40% and an authorized 11% return on common equity. The settlement resolved all electric and gas cost allocation issues and established an 8.76% overall return on capital.
The settlement also included a Power Cost Adjustment (PCA) mechanism that triggers if PSE’s costs to provide customers’ electricity falls outside certain bands from a normalized level of power costs established in the electric general rate case. The cumulative maximum pre-tax earnings exposure due to power cost variations over the four-year period ending June 30, 2006 is limited to $40 million plus 1% of the excess. Upon expiration of the $40 million cumulative cap, the annual power cost variability is subject to the bands in the table below. All significant variable power supply cost drivers are included in the PCA mechanism (hydroelectric generation variability, market price variability for purchased power and surplus power sales, natural gas and coal fuel price variability, generation unit forced outage risk and wheeling cost variability).
Upon expiration of the cumulative cap, the most significant risks are hydroelectric generation variability and wholesale market prices of natural gas and power. On an annual July through June basis, the PCA mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers in the following manner:
ANNUAL POWER COST AVAILABILITY | CUSTOMERS’ SHARE | COMPANY’S SHARE1 |
| +/- $20 million | 0% | | 100% | |
| +/- $20 - $40 million | 50% | | 50% | |
| +/- $40 - $120 million | 90% | | 10% | |
| +/- $120 million | 95% | | 5% | |
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1 | Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40 million plus 1% of the excess. Power cost variation after June 30, 2006 will be apportioned on an annual basis, based on the graduated scale.
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Interest will be accrued on any overcollection or undercollection of the customers’ share of the excess power cost that is deferred. PSE can request a PCA rate surcharge, if for any 12-month period, the actual or projected deferred power costs exceed $30 million. PSE’s cumulative share of the excess power costs through December 31, 2004 was $35.0 million, principally because of adverse hydroelectric conditions, escalating wholesale gas and power costs in 2003 and 2004 and a May 2004 Washington Commission order in the PCA 1 compliance filing which stated PSE was not prudent in managing the Tenaska electric generation facility gas cost and ordered PSE to adjust its PCA deferral account to reflect a disallowance for the PCA 1 period (July 1, 2002 through June 30, 2003). PSE’s share of the excess power costs, including the effect of the Tenaska disallowance, was $36.5 million in 2004 compared to $34.8 million in 2003. As a result of the Tenaska disallowance reserve, any further increases in variable power costs in excess of the cap under the PCA mechanism through June 2006 would be apportioned 99% to customers and 1% to PSE. PSE is required to file a compliance filing with the Washington Commission annually by August 31, in relation to the power costs under the PCA mechanism for the relevant 12 month period ending June 30.
The settlement also gave PSE the financial flexibility to rebuild its common equity ratio to at least 39% over a three-and-one-half-year period, with milestones of 34%, 36% and 39% at the end of 2003, 2004 and 2005, respectively. If PSE should fail to meet this schedule, it would be subject to a 2% rate reduction penalty. As of December 31, 2004, PSE has restored its common equity ratio to a 40.1% level, exceeding the required level for 2004 by 4.1%.
In the settlement of the 2001 Electric General Rate Proceeding, the Washington Commission and PSE agreed to create a limited-scope proceeding called a Power Cost Only Rate Case (PCORC) that would periodically reset power cost rates. The main objective of the PCORC proceeding is to provide for timely review of new resource acquisitions and inclusion of those costs into rates by the time the new resource goes into service. To achieve this objective, the Washington Commission and PSE have agreed to a non-binding, expedited five-month timeline rather than the statutory 11-month timeline that is allowed in a general rate case.
On October 24, 2003, PSE filed a PCORC proceeding under this 2001 rate case provision for the acquisition and recovery in rates of a 49.85% interest in the Frederickson 1 generating facility, located in Washington State. On April 23, 2004, the acquisition of the Frederickson 1 generating facility was approved by FERC. Prior to that approval, on April 7, 2004, the Washington Commission issued an order in PSE’s PCORC granting approval for the acquisition of the Frederickson 1 generating facility as well. As a result of these approvals, PSE completed the acquisition in the second quarter 2004. In its order, the Washington Commission found the acquisition to be prudent and the costs associated with the generating facility reasonable. The costs associated with the generating facility, including projected baseline gas costs, are approved for recovery in rates. The Washington Commission subsequently ordered on May 13, 2004, an increase of cost recovery in rates of $44.1 million annually, beginning May 24, 2004, which includes the ownership, operation and fuel costs of the Frederickson 1 generating facility.
RESIDENTIAL AND SMALL FARM EXCHANGE BENEFIT CREDIT
In June 2001, PSE and Bonneville Power Administration (BPA) entered into an amended settlement agreement regarding the Residential Purchase and Sale Program, under which PSE’s residential and small farm customers receive the benefits of federal power. Completion of this agreement enabled PSE to continue to provide a Residential and Farm Energy Exchange Benefit Credit to residential and small farm customers. The amended settlement agreement provides that, for its residential and small farm customers, PSE will receive; (a) cash payment benefits during the period July 1, 2001 through September 30, 2006, and (b) benefits in the form of power or cash payments during the period October 1, 2006 through September 30, 2011. Under the amended settlement agreement regarding the Residential Purchase and Sale Program, PSE reduces residential and small farm customers’ revenue on a per kWh basis through the Residential and Farm Energy Exchange Benefit Credit. The credit has no impact on PSE’s electric margin or net income, as a corresponding reduction is included in purchased electricity expenses.
In June 2002, PSE entered into an agreement with BPA, which modified the payment provisions of the June 2001 amended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement for an eight month period beginning February 2003, for a total deferral of $27.7 million. Except for certain adjustments tied to a BPA rate adjustment clause, BPA is to begin paying back the amount deferred with interest over a 60-month period beginning October 1, 2006.
In January 2003, PSE filed revised tariff sheets with the Washington Commission to reflect this modification to the agreement between PSE and BPA. The Washington Commission accepted the tariff changes and the Residential and Farm Energy Exchange Benefit Credit was changed to $0.01740 per kWh from $0.01817 per kWh for the period February 15, 2003 through September 30, 2006.
On June 30, 2003, BPA adopted its final Record of Decision in the February 2003 rate case, which established a formula under the BPA rate adjustment clause to be used in adjusting the rate that will affect the level of residential exchange benefits for PSE’s customers. The adjustment under the formula went into effect on October 1, 2003, resulting in both a reduction of benefits of $1.0 million a month for a 12-month period and, under the modified amended settlement agreement mentioned above, an offsetting acceleration of the payment of the above-described $27.7 million deferral. The net result is no change in the cash being received from BPA for the 12-month period, but a reduction in the total benefits to be received in the October 1, 2003 through September 30, 2011 period.
In May 2004, PSE and BPA entered into an agreement that modified the payment of benefits under the amended settlement agreement for the period October 1, 2006 through September 30, 2011. The agreement provides that all benefits in this period will be in the form of cash payments only and defined a new methodology to be used to calculate the residential benefits. In addition, PSE agreed to waive payment of approximately one-half of an available reduction-in-risk discount and deferred payment of the other half of the discount, plus interest, until October 2007.
For 2004 and 2003, the Residential and Farm Energy Exchange Benefit credited to customers was $182.6 million and $181.9 million, respectively, with a related offset to power costs. PSE received payments from BPA in the amount of $175.9 million and $147.9 million during 2004 and 2003, respectively. The difference between the customers’ credit and the amount received from BPA either increases or decreases the previously deferred amount owed to customers. The aggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. Absent certain adjustments tied to the BPA rate adjustment clause described above, the modified amended settlement agreement will provide for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for a pass-through of the same amount to eligible residential and small farm customers.
There are several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the amended settlement agreement and the May 2004 agreement between BPA and PSE described above. BPA rates used in such amended settlement agreement between BPA and PSE for determining the amounts of money to be paid to PSE by BPA under the amended settlement agreement and other agreements described above during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. It is not clear what impact, if any, review of such rates and the above described U.S. Ninth Circuit Court of Appeals actions may have on PSE.
PSE’s market-based rate tariff was accepted by FERC in an order dated January 29, 1999. Pursuant to this order, PSE is required to file an updated market power analysis every three years. On August 11, 2004, PSE filed an updated market power analysis with FERC as required by a FERC order dated May 13, 2004. The August 11, 2004 filing was supplemented by additional filings on September 24, 2004 and November 19, 2004. On December 20, 2004, FERC issued an order (December 20 order) finding that PSE had not provided sufficient information for FERC to determine if PSE had passed the generation market power screens with respect to wholesale sales within PSE’s control area. The order instituted an investigation under Section 206 of the Federal Power Act (FPA) and established a prospective refund date of February 27, 2005. Both the proceeding and the refund effective date affect only wholesale sales at market-based rates by PSE inside its own control area. On February 1, 2005, PSE submitted to FERC additional information in accordance with the December 20 order. PSE has been in discussions with FERC staff to ensure that this supplemental filing addresses the staff’s issues. Although PSE anticipates a favorable outcome to this matter, there can be no assurance that the outcome will not materially impact PSE.
On November 1, 1999, PSE acquired Encogen Northwest, LP (Encogen) whose sole asset is a natural gas-fired cogeneration facility located in Washington State. With the approval of the Washington Commission, the Encogen facility has been operated as part of PSE’s least cost generation dispatch portfolio to serve its native load obligations since it was acquired in 1999. Two wholly-owned subsidiaries of PSE, GP Acquisition Corporation and LP Acquisition Corporation, are the general and limited partners of Encogen, respectively. On December 29, 2004, PSE filed an application with FERC pursuant to Section 203 of the FPA to transfer the Encogen facility to PSE and eliminate the various subsidiaries via an Agreement and Plan of Merger (Merger). On February 15, 2005, FERC issued an order authorizing the Encogen plant to be transferred to PSE. PSE anticipates completing the Merger in 2005.
GAS REGULATION AND RATESRegulation
In 2003, the Washington Commission’s Pipeline Safety staff conducted a natural gas standard inspection for three counties within Washington State in which PSE operates gas pipelines. The inspection included a review of procedures, records and operations and maintenance activities. On June 29, 2004, the Washington Commission issued a complaint to PSE related to that inspection, alleging certain violations of Washington Commission regulations. In December 2004, PSE and the Washington Commission resolved the issues. PSE agreed to a penalty of $0.5 million, and also agreed to update certain natural gas operating practices. PSE’s financial results in 2004 reflect the impact of this penalty. In addition, the resolution included the potential for future penalties of up to $0.2 million in the next ten years if certain operational goals are not met. The Washington Commission approved the settlement on January 31, 2005.
PSE has a PGA mechanism in retail gas rates to recover variations in gas supply and transportation costs. The PGA mechanism passes through to customers these variations in gas rates, and therefore PSE’s gas margin and net income are not affected by changes in the PGA rates. The following rate adjustments were approved by the Washington Commission in relation to the PGA mechanism during 2004, 2003 and 2002:
| EFFECTIVE DATE | PERCENTAGE INCREASE (DECREASE) IN RATES | ANNUAL INCREASE (DECREASE) IN REVENUES (DOLLARS IN MILLIONS) |
| October 1, 2004 | 17.6% | | $121.7 | |
| October 1, 2003 | 13.3% | | 78.8 | |
| April 10, 2003 | 20.1% | | 103.6 | |
| November 1, 2002 | (12.5)% | | (70.6 | ) |
| September 1, 2002 | (7.3)% | | (45.0 | ) |
| June 1, 2002 | (21.2)% | | (138.9 | ) |
On February 18, 2005, the Washington Commission approved a 3.5% general tariff gas rate case increase to recover higher costs of providing natural gas service to customers. The rate increase will increase gas revenues by approximately $26.3 million annually, effective March 4, 2005. In the order, the Washington Commission also approved a capital structure containing 43% common equity with a return on common equity of 10.3%. In the proceeding, PSE had filed a request for an increase of 6.3% or $46.2 million annually on final rebuttal during the rate case for gas customers.
On August 28, 2002, the Washington Commission approved a 5.8% gas rate increase in general rates to recover higher costs of providing natural gas services to customers. The increase was intended to provide approximately $35.6 million annually in revenues. This rate increase became effective September 1, 2002.
FEDERAL REGULATION
Since the mid-1990s, FERC has required public utilities operating under the FPA to provide open access of their transmission systems to third parties under tariffs approved by FERC. There has been no material effect on the financial statements of PSE as a result of open access.
FERC Order No. 2000, issued on December 20, 1999, required all utilities subject to its jurisdiction that own, operate or control transmission facilities to either voluntarily form or participate in a Regional Transmission Organization (RTO) or Independent System Operator (ISO); or, alternatively, to describe its efforts to participate in an RTORTO/ISO or the obstacles to such participation. PSE hashad been an active participant in regional efforts to form an RTORTO/ISO in the Pacific Northwest since the issuance of Order No. 2000. Currently, PSE is workinghas continued to work with nineBPA and other utilities onregional transmission owners to address the formation of an RTOtransmission related issues in the region via a new organization known as Grid West. Any decision by PSE to participate in Grid West (or other RTO proposal) will depend on the ultimate formColumbiaGrid.
The Energy Policy Act of the organization including terms and conditions2005 (EPAct 2005) added a requirement for participation. Furthermore, any such decision will require approval of FERC, the Washington Commission and the boards of directors of the participating utilities. PSE cannot predict the outcome of efforts to form or participate in an RTO or whether any future decision to join (or not join) an RTO will have a material impact on the financial condition, results of operations or liquidity of the Company.
On July 31, 2002, FERC issued its Notice of Proposed Rulemaking on Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). On April 28, 2003, FERC issued a white paper entitled “Wholesale Power Market Platform” (White Paper) that significantly modified the proposal outlined in the SMD NOPR. A modification of the wholesale electricity markets as provided in either the SMD NOPR or the White Paper would have major implications for the delivery of electric energy throughout the United States. Major elements of FERC’s proposal include: (a) a change to allow FERC to exercise jurisdiction over the non-rate terms and conditions for bundled retail sales, but leave the rate component under state jurisdiction; (b) require vertically integrated utilities to joincertify an RTO or an Independent System Operator (ISO) to operate their transmission systems; and (c) require regionsElectric Reliability Organization (ERO) to develop an approach to manage congestion, encourage efficient use ofmandatory and enforceable electric system reliability standards. FERC has certified the transmission grid and promote the use of the lowest cost generation. State regulators, congressional delegates and industry representatives have pointed out that the western North American electricity market has unique characteristics that may not readily lend itselfElectric Reliability Corporation (NERC) as the ERO to develop these standards subject to FERC review and approval. Once approved, the market design proposedreliability standards will apply to PSE and will be enforced by FERC. In addition, Congress has proposed, but not passed, draft legislation that would requirethe ERO subject to FERC oversight. PSE expects the standards to delay and reconsider its market design proposal. PSE cannot predict the outcome of the SMD NOPR or whether the ultimate resolution will havebecome mandatory in June 2007. Failure to comply with these reliability standards once they become mandatory could result in a material impact on the financial condition, results of operations or liquidity of the Company.
penalty.
STATE REGULATIONState Regulation
ThePSE’s retail electric utility business in the State of Washingtonservice is fully regulated and provides service to its customers under cost-based tariff rates.by the Washington Commission. PSE is not aware of any proposals or prospects for retail deregulation in the Statestate of Washington.
PSE’s retail gas service is also regulated by the Washington Commission. Since 1986, PSE has been offering gas transportation as a separate service to industrial and commercial customers who choose to purchase their gas supply directly from producers and gas marketers. The continued evolution of the natural gas industry, resulting primarily from FERC Orders 436, 500 and 636, has served to increase the ability of large gas end-users to independently obtain gas supply from third parties and transportation services directly from the interstate pipelines or other third parties. Although PSE has not lost any substantial industrial or commercial load as a result of such activities, in certain years up to 160 customers annually have taken advantage of unbundled transportation service. In 2004, 129 commercial and industrial customers, on average, chose to use such service. The shifting of customers between sales and transportation service does not materially impact utility margin, as PSE earns similar margins on transportation service as it does onand large-volume, interruptible gas sales.
Electric Regulation and Rates
Power Cost Adjustment Mechanism. On June 20, 2002, the Washington Commission approved a PCA mechanism that triggers if PSE’s costs to provide electricity falls outside certain bands established in an electric rate case. The cumulative maximum pre-tax earnings exposure due to power cost variations over the four-year period ending June 30, 2006 was limited to $40.0 million plus 1.0% of the excess. In October 2005, the Washington Commission approved a shift to an annual PCA measurement period from January through December starting in 2007. On January 5, 2007, the Washington Commission approved the PCA mechanism for continuation under the same annual graduated scale without a cumulative cap for excess power costs. All significant variable power supply cost variables (hydroelectric and wind generation, market price for purchased power and surplus power, natural gas and coal fuel price, generation unit forced outage risk and transmission cost) are included in the PCA mechanism.
The PCA mechanism apportions increases or decreases in power costs, on a calendar year basis, between PSE and its customers on a graduated scale:
Annual Power Cost Variability | July-December 2006 Power Cost Variability1 | Customers’ Share | Company’s Share2 |
| +/- | $20 million | +/- | $10 million | 0 | % | 100 | % |
| +/- | $20 - $40 million | +/- | $10 - $20 million | 50 | % | 50 | % |
| +/- | $40 - $120 million | +/- | $20 - $60 million | 90 | % | 10 | % |
| +/- | $120 million | +/- | $60 million | 95 | % | 5 | % |
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1 | In October 2005, the Washington Commission in its Power Cost Only Rate Case order allowed for a reduction to the power cost variability amounts to half the annual power cost variability for the period July 1, 2006 through December 31, 2006. |
2 | Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40.0 million plus 1.0% of the excess. Power cost variation after December 31, 2006 will be apportioned on a calendar year basis, without a cumulative cap. |
Electric General Rate Case. On January 5, 2007, the Washington Commission issued its order in PSE’s electric general rate case filed in February 2006, approving a general rate decrease for electric customers of $22.8 million or 1.3% annually. The rates for electric customers were effective January 13, 2007. In its order, the Washington Commission approved a weighted cost of capital of 8.4%, or 7.06% after-tax, and a capital structure that included 44.0% common equity with a return on equity of 10.4%. The Washington Commission had earlier approved (on June 28, 2006) a power cost only rate case (PCORC) increase of $96.1 million annually effective July 1, 2006.Power Cost Only Rate Case. A limited-scope proceeding called a PCORC was created in 2002 by the Washington Commission to periodically reset power cost rates. The main objective of the PCORC proceeding is to provide for timely review of new resource acquisitions costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission agreed to an expedited five-month PCORC decision timeline rather than the statutory 11-month timeline for a general rate case.
On October 20, 2005, the Washington Commission approved a PCORC filing that increased electric rates 3.7% or $55.6 million annually. Included in the increase is the recovery of capital and operating costs of the Hopkins Ridge wind generating facility. The Hopkins Ridge wind generating facility was completed on November 27, 2005. As a wind generating facility, Hopkins Ridge is eligible for Federal Production Tax Credits (PTCs) that will ultimately offset some of the costs associated with generating power from Hopkins Ridge. The PTC is a tax credit provided by the federal government for generating electricity from certain renewable resources. The current amount of the tax credit is $0.019 per kilowatt hour (kWh) for wind generation and may be subject to inflation adjustments over time. The tax credit can be claimed for 10 years for a new wind project put into service prior to January 1, 2008. The use of the credit is restricted to offset only 25.0% of current taxes payable. Unused credits can be carried forward for up to 20 years. In the Washington Commission’s October 2005 order, a new tariff schedule was approved which provides for the pass through to ratepayers of all benefits of the PTCs of the Hopkins Ridge project. This mechanism (a PTC Tracker) will pass through to the customer the actual PTCs of the Hopkins Ridge project as they are generated. The PTC Tracker would not be subject to the sharing bands in the PCA. The credits passed through to the customer will be adjusted by the carrying costs of unused PTCs. Since the customer is receiving the benefit of the tax credits as they are generated and the Company does not receive a credit from the IRS until the tax credits are utilized, the Company is reimbursed its carrying costs for funds through this calculation.
Gas General Rate Case. On January 5, 2007, the Washington Commission issued its order in PSE’s gas general rate case, granting an increase in gas rates of Contents$29.5 million or 2.8% annually, effective January 13, 2007. In its order the Washington Commission approved the same weighted cost of capital of 8.4%, or 7.06% after-tax, and capital structure that included 44.0% common equity with a return on equity of 10.4%, as allowed for the Company’s electric operations.
Purchased Gas Adjustment. PSE has a purchased gas adjustment (PGA) mechanism in retail gas rates to recover variations in gas supply and transportation costs. Variations in gas rates are passed through to customers, therefore PSE’s gas margin and net income are not affected by such variations. On September 27, 2006, the Washington Commission approved a revision of PSE’s PGA tariff schedule that went into effect on October 1, 2006. The tariff changes will increase gas revenue approximately $95.1 million, or 10.2%, on an annual basis. The rate increase authorized PSE to recover higher projected future gas and gas transportation costs, as well as to collect an accumulated deficit (receivable) balance in its PGA balancing account over a 24-month period (beginning October 1, 2006). The PGA rate change will increase PSE’s gas revenue, but will not impact the Company’s net income as the increased revenue will be offset by increased purchased gas costs.
The following rate adjustments were approved by the Washington Commission in relation to the PGA mechanism during 2006, 2005 and 2004:
| Effective Date | Percentage Increase in Rates | Annual Increase in Revenues (Dollars In Millions) |
| October 1, 2006 | 10.2% | $ 95.1 |
| October 1, 2005 | 14.7% | 121.6 |
| October 1, 2004 | 17.6% | 121.7 |
TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | |
| Generation and purchased power, MWh | | | | | | | |
| Company-controlled resources | | | 7,048,270 | | | 6,965,840 | | | 6,996,276 | |
| Contracted resources | | | 9,421,546 | | | 11,021,471 | | | 12,085,729 | |
Non-firm energy purchased1 | | | 6,164,457 | | | 5,179,302 | | | 4,795,045 | |
| Total generation and purchased power | | | 22,634,273 | | | 23,166,613 | | | 23,877,050 | |
| Less: losses and company use | | | (1,432,686 | ) | | (1,338,401 | ) | | (1,341,126 | ) |
| Total energy sales, MWh | | | 21,201,587 | | | 21,828,212 | | | 22,535,924 | |
| Electric energy sales, MWh | | | | | | | | | | |
| Residential | | | 10,028,150 | | | 9,845,854 | | | 9,845,527 | |
| Commercial | | | 8,449,566 | | | 8,222,166 | | | 8,012,538 | |
| Industrial | | | 1,352,660 | | | 1,372,815 | | | 1,416,107 | |
| Other customers | | | 94,034 | | | 93,438 | | | 90,840 | |
| Total energy billed to customers | | | 19,924,410 | | | 19,534,273 | | | 19,365,012 | |
| Unbilled energy sales - net increase (decrease) | | | (40,217 | ) | | 65,082 | | | (102,811 | ) |
| Total energy sales to customers | | | 19,884,193 | | | 19,599,355 | | | 19,262,201 | |
Sales to other utilities and marketers1 | | | 1,317,394 | | | 2,228,857 | | | 3,273,723 | |
| Total energy sales, MWh | | | 21,201,587 | | | 21,828,212 | | | 22,535,924 | |
| Less: optimization purchases for sales to other utilities and marketers | | | -- | | | (62,200 | ) | | (2,596,505 | ) |
| Transportation, including unbilled | | | 1,988,965 | | | 2,020,562 | | | 2,307,081 | |
| Net electric energy sales and transported, MWh | | | 23,190,552 | | | 23,786,574 | | | 22,246,500 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Generation and purchased power, MWh | | | | | | | |
| Company-controlled resources | | | 6,845,323 | | | 6,902,040 | | | 7,048,270 | |
| Contracted resources | | | 9,625,381 | | | 9,606,880 | | | 9,421,546 | |
| Non-firm energy purchased | | | 8,185,198 | | | 7,299,139 | | | 6,164,457 | |
| Total generation and purchased power | | | 24,655,902 | | | 23,808,059 | | | 22,634,273 | |
| Less: losses and Company use | | | (1,489,008 | ) | | (1,448,214 | ) | | (1,432,686 | ) |
| Total energy sales, MWh | | | 23,166,894 | | | 22,359,845 | | | 21,201,587 | |
__________________________
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Electric energy sales, MWh | | | | | | | |
| Residential | | | 10,593,340 | | | 10,321,984 | | | 10,028,150 | |
| Commercial | | | 8,939,155 | | | 8,647,478 | | | 8,449,566 | |
| Industrial | | | 1,368,672 | | | 1,357,973 | | | 1,352,660 | |
| Other customers | | | 78,078 | | | 105,388 | | | 94,034 | |
| Total energy billed to customers | | | 20,979,245 | | | 20,432,823 | | | 19,924,410 | |
| Unbilled energy sales - net increase (decrease) | | | 119,800 | | | 40,015 | | | (40,217 | ) |
| Total energy sales to customers | | | 21,099,045 | | | 20,472,838 | | | 19,884,193 | |
| Sales to other utilities and marketers | | | 2,067,849 | | | 1,887,007 | | | 1,317,394 | |
| Total energy sales, MWh | | | 23,166,894 | | | 22,359,845 | | | 21,201,587 | |
| Transportation, including unbilled | | | 2,091,981 | | | 2,030,457 | | | 1,988,965 | |
| Electric energy sales and transportation, MWh | | | 25,258,875 | | | 24,390,302 | | | 23,190,552 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Electric operating revenues by classes (thousands): | | | | | | | |
| Residential | | $ | 788,237 | | $ | 690,184 | | $ | 628,869 | |
| Commercial | | | 702,754 | | | 629,008 | | | 580,973 | |
| Industrial | | | 103,043 | | | 93,922 | | | 88,779 | |
| Other customers | | | 66,470 | | | 76,153 | | | 58,007 | |
Operating revenues billed to customers1 | | | 1,660,504 | | | 1,489,267 | | | 1,356,628 | |
| Unbilled revenues - net increase (decrease) | | | 20,749 | | | 9,548 | | | (813 | ) |
| Total operating revenues from customers | | | 1,681,253 | | | 1,498,815 | | | 1,355,815 | |
| Transportation, including unbilled | | | 11,488 | | | 9,027 | | | 10,707 | |
| Sales to other utilities and marketers | | | 85,004 | | | 105,027 | | | 56,512 | |
| Total electric operating revenues | | $ | 1,777,745 | | $ | 1,612,869 | | $ | 1,423,034 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Number of customers served (average): | | | | | | | |
| Residential | | | 909,876 | | | 893,576 | | | 877,711 | |
| Commercial | | | 111,672 | | | 111,587 | | | 109,238 | |
| Industrial | | | 3,696 | | | 3,877 | | | 3,980 | |
| Other | | | 2,637 | | | 2,426 | | | 2,197 | |
| Transportation | | | 18 | | | 17 | | | 17 | |
| Total customers (average) | | | 1,027,899 | | | 1,011,483 | | | 993,143 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Average kWh used per customer: | | | | | | | |
| Residential | | | 11,643 | | | 11,551 | | | 11,425 | |
| Commercial | | | 80,048 | | | 77,495 | | | 77,350 | |
| Industrial | | | 370,312 | | | 350,264 | | | 339,864 | |
| Other | | | 29,609 | | | 43,441 | | | 42,801 | |
| Average revenue billed per customer: | | | | | | | | | | |
| Residential | | $ | 866 | | $ | 772 | | $ | 716 | |
| Commercial | | | 6,293 | | | 5,637 | | | 5,318 | |
| Industrial | | | 27,880 | | | 24,225 | | | 22,306 | |
| Other | | | 25,207 | | | 31,390 | | | 26,403 | |
| Average retail revenues per kWh sold: | | | | | | | | | | |
| Residential | | $ | 0.0744 | | $ | 0.0669 | | $ | 0.0627 | |
| Commercial | | | 0.0786 | | | 0.0727 | | | 0.0688 | |
| Industrial | | | 0.0753 | | | 0.0692 | | | 0.0656 | |
| Average retail revenue per kWh sold | | | 0.0763 | | | 0.0695 | | | 0.0655 | |
| Heating degree days | | | 4,476 | | | 4,489 | | | 4,421 | |
Percent of normal - NOAA 30-year average | | | 93.3 | % | | 93.6 | % | | 91.8 | % |
Load factor2 | | | 52.4 | % | | 57.4 | % | | 53.5 | % |
_______________
1 | Non-firm energy purchased and Sales to other utilities and marketers in 2003 and 2002 were revised as a result of Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective January 1, 2004. MWh from other utility and marketers/non-firm energy purchased in 2003 and 2002 were reduced 2,941,707 MWh and 2,789,353 MWh, respectively.
|
TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | |
| Electric operating revenues by classes (thousands): | | | | | | | |
| Residential | | $ | 628,869 | | $ | 603,722 | | $ | 616,522 | |
| Commercial | | | 580,973 | | | 556,038 | | | 536,021 | |
| Industrial | | | 88,779 | | | 88,201 | | | 90,121 | |
| Other customers | | | 58,007 | | | 54,259 | | | 26,500 | |
Operating revenues billed to customers1 | | | 1,356,628 | | | 1,302,220 | | | 1,269,164 | |
| Unbilled revenues - net increase (decrease) | | | (813 | ) | | 4,193 | | | (7,118 | ) |
| Total operating revenues from customers | | | 1,355,815 | | | 1,306,413 | | | 1,262,046 | |
| Transportation, including unbilled | | | 10,707 | | | 11,542 | | | 15,551 | |
Sales to other utilities and marketers2 | | | 56,512 | | | 84,994 | | | 75,595 | |
| Less: optimization purchases for sales to other utilities and marketers | | | -- | | | (2,206 | ) | | (64,448 | ) |
| Total electric operating revenues | | $ | 1,423,034 | | $ | 1,400,743 | | $ | 1,288,744 | |
| Number of customers served (average): | | | | | | | | | | |
| Residential | | | 874,205 | | | 854,088 | | | 839,878 | |
| Commercial | | | 109,660 | | | 108,479 | | | 104,273 | |
| Industrial | | | 3,953 | | | 3,952 | | | 3,953 | |
| Other | | | 2,194 | | | 2,060 | | | 1,932 | |
| Transportation | | | 17 | | | 16 | | | 16 | |
| Total customers (average) | | | 990,029 | | | 968,595 | | | 950,052 | |
| Average retail revenues per kWh sold: | | | | | | | | | | |
| Residential | | $ | 0.0627 | | $ | 0.0617 | | $ | 0.0632 | |
| Commercial | | | 0.0688 | | | 0.0680 | | | 0.0675 | |
| Industrial | | | 0.0656 | | | 0.0650 | | | 0.0649 | |
| Average retail revenue per kWh sold | | | 0.0655 | | | 0.0646 | | | 0.0651 | |
| Average revenue billed to residential customers | | $ | 719 | | $ | 711 | | $ | 741 | |
| Average kWh used by residential customers | | | 11,471 | | | 11,528 | | | 11,723 | |
| Heating degree days | | | 4,421 | | | 4,527 | | | 4,946 | |
Percent of normal- NOAA 30-year average | | | 91.8 | % | | 94.4 | % | | 103.1 | % |
| Load factor | | | 53.5 | % | | 58.9 | % | | 61.6 | % |
__________________________
1 | Operating revenues in 2004 2003 and 2002 were reduced by $0.8 million $7.7 million and $12.7 million, respectively, as a result of the Company’s sale of $237.7 million of its investment in customer-owned conservation measures in 1995 and 1997. Beginning in July 2003, these related revenues were consolidated as a result of Financial Accounting Standards Board Interpretation No. 46. (See Operating Revenues-Electric in Management’s Discussion and Analysis and Note 1 to the Consolidated Financial Statements.) As of October 2004, the conservation trust bond was fully redeemedpaid and any excess collection wascollections were recorded as a reduction in revenues. |
2 | Sales to other utilities and marketers in 2003 and 2002 were revised as a result of Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective January 1, 2004. Revenues from other utilities and marketers in 2003 and 2002 were reducedAverage usage by $108.7 million and $77.1 million, respectivelycustomers divided by their maximum usage.
|
At December 31, 2004,2006, PSE’s electric power resources werehad a total capacity of approximately 4,351 MW.4,456 megawatts (MW). PSE’s historical peak load of approximately 4,847 MW occurred on December 21, 1998. In order to meet an extreme winter peak load, PSE supplementsmay supplement its electric power resources with winter-peaking call options and other instruments that may include, but are not limited to, weather-related hedges and exchange agreements. During 2004, PSE’s total electric energy production was supplied 31.1% by its own resources, 23.1% through long-term contracts with several ofWhen it is more economical to purchase power than to run the Washington Public Utility Districts (PUDs) that own hydroelectric projects onCompany’s generation, PSE will purchase in the Columbia River, and 18.6% from other firm purchases. Short-term wholesale purchases, net of sales to other utilities and marketers, accounted for 22.7% of energy production in 2004.short-term markets.
The following table shows PSE’s electric energy supply resources at December 31, 20042006 and 2003,2005 and energy production during the year:
| | | PEAK POWER RESOURCES AT DECEMBER 31, | | ENERGY PRODUCTION | | Peak Power Resources At December 31 | Energy Production |
| | | 2004 | | 2003 | | 2004 | | 2003 | | 2006 | 2005 | 2006 | 2005 |
| | | MW | | % | | MW | | % | | MWh | | % | | MWh | | % | | MW | % | MW | % | MWh | % | MWh | % |
| Purchased resources: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Columbia River PUD contracts | | | 1,350 | | 31.0 | % | | 1,349 | | 30.0 | % | | 5,231,691 | | 23.1 | % | | 5,191,346 | | 22.4 | % | 1,164 | 26.1% | 1,212 | 28.3% | 5,692,366 | 23.1% | 5,397,825 | 22.7% |
Other hydroelectric1 | | | 177 | | 4.1 | % | | 177 | | 3.9 | % | | 600,557 | | 2.7 | % | | 622,900 | | 2.7 | % | 168 | 3.8% | 164 | 3.8% | 653,362 | 2.6% | 590,263 | 2.5% |
Other producers1 | | | 1,011 | | 23.2 | % | | 1,210 | | 26.9 | % | | 3,589,298 | | 15.9 | % | | 5,207,225 | | 22.5 | % | 932 | 20.9% | 944 | 22.1% | 3,279,575 | 13.3% | 3,618,792 | 15.2% |
Short-term wholesale energy purchases2 | | | N/A | | N/A | | N/A | | N/A | | 6,164,457 | | 27.2 | % | | 5,179,302 | | 22.4 | % | N/A | N/A | N/A | N/A | 8,185,276 | 33.2% | 7,299,139 | 30.7% |
| Total purchased | | | 2,538 | | 58.3 | % | | 2,736 | | 60.8 | % | | 15,586,003 | | 68.9 | % | | 16,200,773 | | 70.0 | % | 2,264 | 50.8% | 2,320 | 54.2% | 17,810,579 | 72.2% | 16,906,019 | 71.1% |
| Company-controlled resources: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Hydroelectric | | | 234 | | 5.4 | % | | 304 | | 6.7 | % | | 1,130,180 | | 5.0 | % | | 1,238,900 | | 5.3 | % | 234 | 5.3% | 234 | 5.5% | 949,276 | 3.9% | 879,493 | 3.7% |
| Coal | | | 677 | | 15.6 | % | | 677 | | 15.1 | % | | 5,119,002 | | 22.6 | % | | 4,950,734 | | 21.4 | % | 677 | 15.2% | 677 | 15.8% | 4,800,028 | 19.5% | 5,175,799 | 21.7% |
| Natural gas/oil | | | 902 | | 20.7 | % | | 778 | | 17.4 | % | | 799,088 | | 3.5 | % | | 776,206 | | 3.3 | % | 902 | 20.2% | 902 | 21.0% | 723,190 | 2.9% | 813,078 | 3.4% |
Wind3 | | 379 | 8.5% | 150 | 3.5% | 372,829 | 1.5% | 33,670 | 0.1% |
| Total Company-controlled | | | 1,813 | | 41.7 | % | | 1,759 | | 39.2 | % | | 7,048,270 | | 31.1 | % | | 6,965,840 | | 30.0 | % | 2,192 | 49.2% | 1,963 | 45.8% | 6,845,323 | 27.8% | 6,902,040 | 28.9% |
| Total | | | 4,351 | | 100.0 | % | | 4,495 | | 100.0 | % | | 22,634,273 | | 100.0 | % | | 23,166,613 | | 100.0 | % | 4,456 | 100.0% | 4,283 | 100.0% | 24,655,902 | 100.0% | 23,808,059 | 100.0% |
__________________________ _______________
1 | Power received from other utilities is classified between hydroelectric and other producers based on the character of the utility system used to supply the power or, if the power is supplied from a particular resource, the character of that resource. |
2 | Short-term wholesale purchases net of resalesresale of 1,317,3942,067,849 MWh and 2,228,8571,887,007 MWh account for 22.7%27.1% and 14.1%24.7% of energy production for 20042006 and 2003,2005, respectively. |
3 | 2006 represents Hopkins Ridge and Wild Horse wind projects. Wild Horse began commercial operations on December 22, 2006. 2005 represents Hopkins Ridge, which began commercial operations on November 27, 2005. |
LEAST COST PLANIntegrated Resource Plans
PSE is required by the Washington Commission to file electric and gas Integrated Resource Plans (IRP) every two years. The next plan will be filed in May 2007. PSE filed its electric Least Cost Plan on April 30, 2003 with the Washington Commission. The plan supportedIRP in May 2005 that supports a strategy of diverse electric power and demand resource acquisitions including resources fueled by natural gas and coal, renewable resources (e.g. wind), wind and shared resources. A Least Cost Plan Update was filed in August 2003, which integratedbiomass) and the implementation of energy efficiency programs into the resource mix.strategies. The Least Cost Planelectric IRP was followed withby an all-source request for proposal (RFP) issued on November 1, 2005. The Washington Commission approved the proposed acquisition of a gas combined-cycle combustion turbine, and the issuing of a wind resource Request for Proposal (RFP) in December 2003. An all-source RFP was issued in February 2004. PSE is in the process of updating its Least Cost Plan which is expected to be filed with the Washington Commission in the first half ofon October 28, 2005.
Based uponon PSE’s projected customer usage for electricity and its current electric generation resources, PSE projectsexpects that future energy needs will exceed current purchased and Company-controlled power resources. The projectedexpected average MW shortfall at December 31, 2004 for the period 2006-20102007 through 2011 is as follows:
| | 2006 | 2007 | 2008 | 2009 | 2010 |
Projected MW Shortfall1 | 208 | 263 | 305 | 360 | 457 |
| | 2007 | 2008 | 2009 | 2010 |
Projected average MW shortfall1 | 283 | 305 | 362 | 457 |
________________________________________
1 | Estimated using all resources under long-term contractcontracts and Company-controlled resources. Also includes anticipated acquisitions of the Hopkins Ridge and Wild Horse wind projects which are currently under review.facilities. |
PSE signedexpects to address this shortfall position with the use of a non-binding lettercombination of intent on October 29, 2004 to acquire a 100% interest in a 150 MW (52 average MW) wind powered electric generation facility to be developed in eastern Washington State. PSE anticipates spending up to $200 million onnew long-term power contracts and the project, which it will solely own once complete. This total includes approximately $180 million to acquire and construct the wind plant, $10 million to fund upgrades to the transmission systemspurchase or construction of BPA and other regional transmission providers and approximately $10 million on financing and other costs. The proposed purchase transaction could occur as early as the end of the first quarter 2005, and if completed, construction on the project is anticipated to be completed sometime between late 2005 and mid 2006.new generating resources.
On September 1, 2004, PSE signed a second non-binding letter of intent to acquire a 100% interest in a 230 MW (77 average MW) wind powered electric generation facility to be developed in central Washington State. The estimated cost of the project is approximately $300 million, depending on design options. The proposed transaction is anticipated to be completed on or before January 1, 2006 and construction on the project is anticipated to be completed in 2006.
COMPANY–CONTROLLED ELECTRIC GENERATION RESOURCESCompany - Controlled Electric Generation Resources
At December 31, 2004,2006, PSE has the following plants with an aggregate net generating capacity of 1,8132,192 MW:
| PLANT NAME | PLANT TYPE | NET CAPACITY (MW) | YEAR INSTALLED | |
| Plant Name | | Plant Type | Net Capacity (MW) | Year Installed |
| Colstrip Units 1 & 2 (50% interest) | Coal | 307 | | 1975 & 1976 | Coal | 307 | 1975 & 1976 |
| Colstrip Units 3 & 4 (25% interest) | Coal | 370 | | 1984 & 1986 | Coal | 370 | 1984 & 1986 |
| Fredonia Units 1 & 2 | Dual-fuel combustion turbines | 207 | | 1984 | Dual-fuel combustion turbines | 207 | 1984 |
| Fredrickson Units 1 & 2 | Dual-fuel combustion turbines | 147 | | 1981 | |
| Frederickson Units 1 & 2 | | Dual-fuel combustion turbines | 147 | 1981 |
| Whitehorn Units 2 & 3 | Dual-fuel combustion turbines | 147 | | 1981 | Dual-fuel combustion turbines | 147 | 1981 |
| Fredonia Units 3 & 4 | Dual-fuel combustion turbines | 107 | | 2001 | Dual-fuel combustion turbines | 107 | 2001 |
| Frederickson Unit 1 (49.85% interest) | Natural gas combined cycle | 124 | | 2002; Purchased 2004 | Natural gas combined cycle | 124 | 2002 |
| Encogen | Natural gas cogeneration | 167 | | 1993 | Natural gas cogeneration | 167 | 1993 |
| Crystal Mountain | Internal combustion | 3 | | 1969 | Internal combustion | 3 | 1969 |
| Upper Baker River | Hydroelectric | 91 | | 1959 | Hydroelectric | 91 | 1959 |
| Lower Baker River | Hydroelectric | 79 | | Reconstructed 1960; Upgraded 2001 | Hydroelectric | 79 | 1925; reconstructed 1960; upgraded 2001 |
| Snoqualmie Falls | Hydroelectric | 42 | | 1898 to 1911 and 1957 | Hydroelectric | 44 | 1898 to 1911 & 1957 |
| Electron | Hydroelectric | 22 | | 1904 to 1929 | Hydroelectric | 22 | 1904 to 1929 |
| Wild Horse | | Wind | 229 | 2006 |
| Hopkins Ridge | | Wind | 150 | 2005 |
| Total Net Capacity | | | 2,194 | |
COLSTRIP GENERATING FACILITYGoldendale Generating Station
In June 2004,On February 21, 2007, PSE and Western Energy Company (WECO),acquired the supplierGoldendale Generating Station, a 277 MW capacity natural gas generating facility in the state of coal to Colstrip Units 1 & 2, entered into a binding arbitration and settled a dispute concerning pricesWashington, from the Calpine Corporation through its bankruptcy proceeding. PSE paid for coal supplied. The binding decision retroactively set a new baseline cost per ton of coal purchased by PSE for Colstrip Units 1 & 2 supplied from July 31, 2001, and is applicable$120.0 million for the remaining term of the coal supply agreement through December 2009. The decision resulted in a $6.9 million charge that was recorded in the second quarter 2004. Of the $6.9 million charge, $5.0 million was included in the PCA mechanism. PSE had previously accrued a $1.6 million reserve in the fourth quarter 2003 related to the arbitration.
On April 29, 2004, the Minerals Management Service of the United States Department of the Interior (MMS) issued an order to WECO to pay additional royalties concerning coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of an additional $1.1 million in royalties for coal mined from federal land between 1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a settlement agreement entered into in February 1997 among PSE, WECO and Montana Power Company that resolved disputes that were then pending. The order seeks to impute the price charged to PSE based on the other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is supporting WECO’s appeal of the order, but is also evaluating the basis of the claim. PSE accrued a loss reserve in the amount of $1.1 million in connection with this matter in the second quarter 2004.
In addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. PSE’s share of the alleged additional royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest in Colstrip Units 3 & 4. Other parties may attempt to assert claims against WECO if the MMS position prevails. The transportation agreement provides for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is monitoring the process. PSE believes that the Colstrip Units 3 & 4 owners have reasonable defenses in this matter based upon its review. Neither the outcome of this matter nor the associated costs can be predicted at this time.
In September 2004, the owners of Colstrip Units 1 & 2 (PSE and PPL Montana) entered into a tentative settlement agreement with certain homeowners in the Colstrip town site area concerning a lawsuit filed in May 2003. In December 2004, the plaintiffs retained new counsel and postponed further settlement discussions until more discovery is completed. The lawsuit alleged certain domestic water wells may have been contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond. The tentative settlement agreement would require extending municipal water to the homeowners and abandoning the existing wells. The total estimated cost of the settlement ranges from $1.4 million to $1.5 million. As a result of this tentative settlement agreement, PSE recorded a $0.7 million reserve in the third quarter 2004 for its 50% ownership of the Colstrip Units 1 & 2 project. The settlement agreement would not resolve certain other claims by residents within the city limits. PSE cannot predict the outcome or any potential financial impact of the claims by the residents within the city limits at this time.generating facility.
FERC HYDROELECTRIC PROJECTS AND LICENSESHydroelectric Projects And Licenses
As part of its hydroelectric operations, PSE is required to obtain operating licenses from FERC. A typical license contains mandatory conditions of operation, such as flow rate requirements, adherence to certain ramping protocols for outages, maintenance of reservoir levels, equipment upgrade projects and fish and wildlife mitigation projects.projects for a 30 to 50 year period. The licensing and relicensing processes involve harmonizing conflicting rights and obligations of numerous governmental, non-governmental and private parties, and dealing with issues that may include environmental compliance, fish protection and mitigation, water quality, Native American rights, title claims, operational and capital improvements and flood control. As a result, a number of political, compliance and financial risks can arise from the licensing and relicensing processes. FERC regulates dam safety and administers proceedings under the Federal Power Act (FPA) to license jurisdictional hydropower projects.
PSE owns three operating hydroelectric projects: the Baker River project, the Snoqualmie Falls project and the Electron project. ThePSE’s White River project ceased operations as a hydroelectric generating resource in January 2004. The Baker River and Snoqualmie Falls projects are operating under the jurisdiction of FERC. FERC regulates dam safety and administers proceedings under the FPA to license jurisdictional hydropower projects. FERC licenses are generally issued for a term of 30 to 50 years.
Baker River project.The Baker River project consists of the Lower Baker Development (constructed in 1925) and the Upper Baker Development (constructed in 1959). The Baker River project’s current annual license expires on April 30, 2006,2007, and PSE submitted an application for a new license to FERC on April 30, 2004. On November 30, 2004, PSE and 23 parties, comprised of federal,(federal, state and local governmental organizations, Native American Indian tribes, environmental and other nongovernmental entitiesnon-governmental entities) filed a proposed comprehensive settlement agreement on all issues relating to the relicensing of the Baker River project. The proposed settlement includes a set of proposed license articles and, if approved by FERC without material modification, would allow for a new license forof 45 years or more. The proposed settlement would require an investment of approximately $360$360.0 million over the next 30 years (capital expenditures and operations and maintenance cost) in order to implement the conditions of the new license over the next 30 years.license. The proposed settlement is subject to contingencies that have yet to be resolved and is subject to additional regulatory approvals yet to be attained from various agencies.agencies and other contingencies that have yet to be resolved. A Final Environmental Impact Statement was issued by FERC on September 8, 2006. However, FERC has not yet ruled on the proposed settlement and its ultimate outcome remains uncertain. Assuming that settlement contingencies are resolved and additional regulatory approvals are obtained in a timely manner and on favorable terms, a decision by FERC could occur by April 2006.
Snoqualmie Falls project.The Snoqualmie Falls project built in 1898, had its original license issued May 13, 1975, which was made effective retroactive to March 1, 1956, and expired on December 31, 1993. PSE filed its application to relicense the project on November 25, 1991, and operated the project pursuant to annual licenses issued by FERC since the original license expired. On June 29, 2004, FERC granted PSE a new 40-year operating license for the Snoqualmie Falls project.by FERC on June 29, 2004. PSE estimates that the investment required to implement the conditions of the new license agreement will cost approximately $44$44.0 million. These conditions include modified operating procedures and various project upgrades that include better protection of fish, development of riparian habitat to promote fish propagation, increased minimum flows in the Snoqualmie River during low-water periods and the development of recreational amenities near the down-river power house. On July 29, 2004, the Snoqualmie Tribe and certain other parties filed a request for rehearing of the new license and a request to stay the FERC license. On March 1, 2005, FERC has not ruledissued an Order on this requestRehearing and the outcome remains uncertain. In the meantime, because a stay has not been issued, the Company is proceeding with its plan of rehabilitation necessary to comply with the terms of the new license.
Electron project. The Electron project was built in 1904. The project’s capacity is currently 22 MW. In 1977, the project was determined to be a “pre-1935” project under the FPA and therefore not subject to FERC jurisdiction. In this status, the project can continue to operate without a FERC license absent “post-1935” construction of a nature sufficient to invoke FERC’s jurisdiction. PSE does not anticipate undertaking any betterments or improvementsDismissing Stay Request. Appeals to the project that would entail “post-1935” construction.
The project also operates in compliance withU.S. Court of Appeals by the termsSnoqualmie Tribe and conditionsby PSE have been consolidated. Oral arguments were held on February 8, 2007. An adverse ruling from the Court or adverse action by FERC if the license issuance is remanded could impact PSE’s future use of a “Resource Enhancement Agreement” with the Puyallup Indian Tribe. This agreement resolved the Tribe’s long-standing claims for resource and other damages allegedly associated with the construction and operation of the project. The agreement also provides that in 2018 PSE must decide to either retire the project by 2026 or, in lieu of retirement, undertake significant upgrades that would likely invoke FERC jurisdiction. The outcome of these deliberations is not expected to have a material impact upon the financial condition, results of operations or liquidity of the Company.this generating asset.
White River project.project. The White River project was built in 1911 and was operated as a hydropower facility until January 15, 2004. PSE submitted a license application to FERC in 1983, and in December 1997, FERC issued a proposed license for the project. PSE appealed the 1997 license because it contained terms and conditions that would render ongoing operations of the project uneconomic relative to alternative resources. In November 2003, PSE determined that it could no longer continue to economically operate the project due to additional conditions primarily related to two listings under the Endangered Species Act. On December 23, 2003, PSE notified FERC that it rejected the 1997 license for the White River project and on January 15, 2004, generation of electricity ceased at the White River project. PSE is actively seeking to sell the project and the municipal water rights associated with the project to one or more entities interestedentities. In June 2003, Ecology approved an application for new municipal water rights related to the White River project reservoir. After an appeal in maintainingJuly 2004, this decision was remanded back to Ecology for further analysis of non-hydropower operations. On December 21, 2006, PSE entered into a Purchase and Sale Agreement with the reservoir for commercial purposes.Cascade Land Conservancy to sell certain rights and interests in a portion of former project properties, although the closing of the sale is subject to contingencies that have yet to be resolved.
In the PCORC Order issued onOn April 7, 2004, the Washington Commission approved PSE’s recovery on the unamortized White River plant investment. At December 31, 2004,2006, the White River project net book value totaled $65.1$69.1 million, which included $46.4$43.4 million of net utility plant, $14.8$17.1 million of capitalized FERC licensing costs, $3.1$4.3 million of costs related to construction work in progress and $0.8$1.8 million related to dam operations and safety. PSE sought recovery of the relicensing, other construction work in progress and dam operations and safety costs totaling $18.7 million in its general rate filing of April 2004, over a 10-year amortization period. In the third quarter 2004,On February 18, 2005, the Washington Commission staff recommended that PSE be allowedapproved the recovery of the White River net utility plant costs noted above, but defer any amortizationdid not allow current recovery of the FERC licensing costs and other related costs until all costs associated with selling the White River plant and any sales proceeds are known. In its February 18, 2005 general rate case order, the Washington Commission found this treatment reasonable, and adopted all of the staff recommendations.
In January 2001, certain environmental groups gave notice of their intent to sue for alleged violations of the Endangered Species Act, but no such lawsuit has been filed. In May 2004, the Puyallup Indian Tribe gave PSE notice of intent to sue for an alleged violation of water quality laws associated with the release of water from the White River project reservoir. No such lawsuit has been filed and PSE is in discussion with the Puyallup Indian Tribe regarding their concerns. Additionally, PSE has sought, and is awaiting, further direction from the Washington State Department of Ecology (Ecology) as to whether any additional actions are necessary to maintain compliance with applicable water quality laws.
Homeowners and others interested in preserving the project reservoir (Lake Tapps) have expressed concern over the possible loss of the reservoir and there has been a solicitation of interest in a potential lawsuit against PSE to preserve the reservoir, but no such lawsuit has been filed to date.
In September 2004, the Company renewed its contract with the United States Army Corps of Engineers (COE) to maintain operation of the White River diversion dam to support the COE’s ongoing operation of its Mud Mountain Dam fish passage facilities. The agreement provides for reimbursement of a portion of PSE’s operating costs and directs PSE to operate the diversion dam in accordance with measures determined by federal agencies to be necessary to protect listed species and habitat. This contract expires in September 2005, although the COE has expressed its desire to extend the term for a period of time necessary to allow the COE to develop a plan to acquire the diversion dam from the Company.
In June 2003, Ecology approved an application for new municipal water rights related to the White River project reservoir. This approval was sought in connection with PSE’s ongoing efforts to sell the White River project to be used for commercial purposes. An appeal of Ecology’s decision approving the new municipal water rights was subsequently filed with the Washington State Pollution Control Hearings Board. In July 2004, this decision was remanded back to Ecology for further analysis of non-hydropower operations. The Company has been advised by Ecology that Ecology anticipates issuing a revised decision by the end of 2005; however, no firm date has been set for any such revised decision. Any proceeds from the sale of the White River assets and water rights will reduce the balance of the deferred regulatory asset. Neither the outcome of this matter nor any potential associated costsfinancial impacts can be predicted at this time.
COLUMBIA RIVER ELECTRIC ENERGY SUPPLY CONTRACTSColumbia River Electric Energy Supply Contracts
During 2004,2006, approximately 23.1% of PSE’s energy output was obtained at an average cost of approximately $0.0146$0.014 per kWh through long-term contracts with several of the Washington PUDs that own and operate hydroelectric projects on the Columbia River. PSE’s purchases of power from the Columbia River projects are on a “cost of service” basis under which PSE paysagrees to pay a proportionate share of the annual debt service, and operating and maintenance costs ofand other expenses associated with each project in proportion to the contractual shares that PSE has rights to from such project. SuchPSE’s payments are not contingent upon the projects being operable, which means PSE is required to make the payments even if power is not being delivered. These projects are financed through substantially level debt service payments, and their annual costs may vary over the term of the contracts as additional financing is required to meet the costs of major repairs, replacements, license requirements, or changes to annual operating and maintenance expenses are required.operable.
PSE has contracted to purchase from Chelan County PUD (Chelan) a 50% share of the output of the original units of the Rock Island project, which percentage will remain unchanged for the duration of the contract which expires in 2012. PSE has also contracted to purchase the output of the additional Rock Island units for the duration of the contract. As of December 31, 2004, PSE’s aggregate capacity from all units2006, the Company was entitled to purchase portions of the Rock Island project was 413.9 MW. PSE’s share ofpower output of the additional Rock Island units may be reduced by up to 10% per year. On July 1, 2000, Chelan began withdrawing 5% of the power from the additional Rock Island units for use in meeting its local load. The maximum withdrawal that Chelan may make from the additional units is 50%. The schedule of withdrawals by Chelan for the additional Rock Island units isPUDs’ projects as follows:set forth:
DATE OF WITHDRAWAL | WITHDRAWAL PERCENTAGE | PSE % OF CAPACITY AFTER WITHDRAWAL |
| February 1, 2005 | 10% | 65% |
| July 1, 2005 | 10% | 55% |
| November 1, 2006 | 5% | 50% |
| | | | Company’s Annual Amount Purchasable (Approximate) |
| Project | Contract Exp. Date | License Exp. Date | % of Output | | Megawatt Capacity |
Chelan County PUD:1 | | | | | |
| Rock Island Project | | | | | |
| Original units | 2012 | 2029 | 50.0 | } | 330 |
| Additional units | 2012 | 2029 | 50.0 |
| Rocky Reach Project | 2011 | 2006 | 38.9 | | 501 |
| Douglas County PUD: | | | | | |
| Wells Project | 2018 | 2012 | 29.9 | | 251 |
Grant County PUD:2,3 | | | | | |
| Priest Rapids Development | TBD | TBD | 4.3 | | 39 |
| Wanapum Development | 2009 | TBD | 10.8 | | 106 |
| Total | | | | | 1,227 |
PSE has contracted to purchase from Chelan 38.9% (505 MW of peak capacity as of December 31, 2004) of the annual output of the Rocky Reach project, which percentage remains unchanged for the remainder of the contract which expires in 2011._______________
PSE has contracted to purchase from Douglas County PUD 31.3% (261 MW as of December 31, 2004) of the annual output of the Wells project, the percentage of which remains unchanged for the remainder of the contract which expires in 2018. Early in 2003, the Colville Confederated Tribes (Colville Tribe) presented a claim to Douglas County PUD based upon allegedly unpaid past annual charges for the Wells Hydroelectric project for the use of Colville Tribal lands. The Colville Tribe also claimed that annual charges would be due for periods into the future. On November 1, 2004, Douglas County PUD entered into a settlement with the Colville Tribe concerning claims that the Colville Tribe had asserted against Douglas County PUD for the use by the Wells project of Tribal lands. PSE approved the settlement and participated in the filing Douglas County PUD made on November 23, 2004 seeking FERC approval. The settlement was approved in a FERC order on February 11, 2005. It is unlikely that any party will seek a rehearing of that FERC order, of which the deadline for doing so is March 13, 2005. When the settlement becomes final, the effects on PSE will be through modestly increased power costs, and a reduction in the amount of power delivered to PSE due to the allocation to the Colville Tribe. The Colville Tribe’s allocation will be treated as an encroachment to the project, thus reducing the amount of power available for purchase by others.1 | On February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement and a related Transmission Agreement for 25.0% of the output of Chelan’s Rocky Reach and Rock Island hydro electric generating facilities located on the mid-Columbia River in exchange for PSE paying 25.0% of the operating costs of the facilities. PSE’s share of the output represents approximately 487 MW of capacity and 243 average MW of energy. The agreements terminate in 2031 and provide that PSE will begin to receive power upon expiration of PSE’s existing long-term contracts with Chelan for the Rocky Reach and Rock Island output (expiring in 2011 and 2012, respectively). PSE made a non-refundable capacity reservation payment of $89.0 million as required by the agreements. The Washington Commission determined the prudence of PSE entering into the new Chelan contract and confirmed the treatment of the $89.0 million as a regulatory asset as part of its order in PSE’s General Rate Case on January 5, 2007. |
2 | Under terms of the 2001 Grant contract extensions, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. The new contracts’ terms began in November of 2005 for the Priest Rapids Development and will beginin November of 2009 for the Wanapum Development. |
3 | PSE’s share of power from the 2001 contract declines over time as Grant County PUD’s load increases. PSE’s share of the Wanapum Development will remain at 10.8% until November 2009 and will be adjusted annually thereafter for the remaining term of the new contracts. PSE’s share of the Priest Rapids Development declined to approximately 4.3% in 2006 and will be adjusted annually for the remaining term of the new contract. |
PSE has contracted to purchase from Grant County PUD 8.0% (72 MW as of December 31, 2004) of the annual output of the Priest Rapids Development and 10.8% (98 MW of peak capacity as of December 31, 2004) of the annual output of the Wanapum Development, which percentages remain unchanged for the remainder of the original contract terms which expire in 2005 and 2009, respectively. On December 28, 2001, PSE signed a contract offer for new contracts for the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. Grant County PUD filed an application for new license for the Priest Rapids project on October 29, 2003. The new contracts’ terms begin in November 2005 for the Priest Rapids Development and in November 2009 for the Wanapum Development. Unlike the current contracts, in the new contracts, PSE’s share of power from the developments declines over time as Grant County PUD’s load increases.
On March 8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant County PUD’s new contracts unreasonably restrain trade and violate various sections of the FPA and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, FERC has ordered Grant County PUD to remove specific sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing was requested but was denied by FERC on April 16, 2003. Both the Yakama Nation and Grant County PUD have appealed the FERC decision and the appeals have been consolidated in the Ninth Circuit Court of Appeals.
ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH OTHER UTILITIESElectric Energy Supply Contracts and Agreements With Other Utilities
PSE has entered into long-term firm purchased power contracts with other utilities in the West region. PSE is generally not obligated to make payments under these contracts unless power is delivered.
Under a 1985 settlement agreement with BPA relating to Washington PublicBonneville Power Supply System Nuclear Project No. 3 (WNP-3)Association (BPA), in which PSE had a 5 percent interest, PSE is entitled to receive exchange energy from BPA during the months of November through April. The power PSE receives,April, which amounts to 4736.5 average MW of energy and 82 MW of capacity for contract year 2004-2005, is tied to the equivalent annual availability factor of several surrogate nuclear plants similar in design to WNP-3.2006-2007. BPA has an option to request that PSE deliver up to 6331.2 average MW of exchange energy to BPA in all months except May, July and August for contract year 2004 - 2005.2006-2007. The contract terminates June 30, 2017, but may be endedterminated earlier if the number of surrogate operating years of the longest running surrogate unit is less than 30 years.under certain circumstances.
On October 1, 1989, PSE signed a contract with The Montana Power Company which subsequently sold its utility assets to NorthWestern Corporation (NorthWestern) in 2002. Under the contract, NorthWestern provides PSEfor 71 average MW of energy (97 MW of peak capacity) over a 21-year period. This contract expires inthrough December 2010. On November 1, 2004 NorthWestern emerged from bankruptcy protection under Chapter 11The contract deliveries are contingent on the combined availability of Colstrip Units 3 & 4. The contract payments consist of a fixed monthly payment and an energy payment based on commodity and transportation costs for coal. The fixed payment may be reduced if the U.S. Bankruptcy Code. PSE has several long-term contracts with NorthWestern under which PSE jointly owns facilities or purchases power or transmission services from NorthWestern. Duringdelivered energy is less than the bankruptcy proceeding NorthWestern affirmed its continued performance under alladjusted energy entitlement (equal to an equivalent availability of these agreements.approximately 73.0%) for the contract year.
In January 1992, PSE executed an exchange agreement with Pacific Gas & Electric Company (PG&E). Under the agreement, to exchange 300 MW of capacity together with up to 413,000 MWhmegawatt hours (MWh) of energy are exchanged seasonally each year. No payments are made under this agreement. PG&E is a summer peaking utility and provides power during the months of November through February.February and PSE is a winter peaking utility and provides power during the months of June through September. Each party may terminate the contract upon notifying the other party at least five yearsyear prior notice.
Under an agreement with Powerex expiring in advance.
In February 1996, a 10-year power exchange agreement between PSE and Powerex (a subsidiary of a British Columbia, Canada utility) became effective. Under this agreement,2006, Powerex pays PSE for the right to deliver up to 1,200,000 MWh annually to PSE at the Canadian border in exchange for PSE delivering power to Powerex at various locations in the United States. The agreement also allows Powerex to make up any exchange volumes not used up to two years after the end of the annual period.
ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITY GENERATORSElectric Energy Supply Contracts and Agreements With Non-Utility Generators
As required by the federal Public Utility Regulatory Policies Act (PURPA), PSE has entered into long-term firm purchased power contracts with non-utility generators. The most significant of thesecontracts are the contracts described below which PSE entered into in 1989, 1990, and 1991 with operators of natural gas-fired cogeneration projects.below. PSE purchases the net electrical output of these three projects at fixed and annually escalating prices, which were intended to approximate PSE’s avoided cost of new generation projected at the time these agreements were made.
On February 24, 1989, PSE executed a 20-year contract to purchase 108 average MWAs of energy and 123 MW of capacity, beginning in April 1993, from Sumas CogenerationDecember 31, 2006, the Company LP, which owns and operates a natural gas-fired cogeneration project located in Sumas, Washington.
On June 29, 1989, PSE executed a 20-year contract to purchase 70 average MW of energy and 80 MW of capacity, beginning October 11, 1991,purchased the power output from the March Point Cogeneration Company (March Point), which owns and operates a natural gas-fired cogeneration facility known as March Point Phase I located at the Equilon refinery in Anacortes, Washington. On December 27, 1990, PSE executed a second contract (having a term coextensive with the first contract) to purchase an additional 53 average MW of energy and 60 MW of capacity, beginning in January 1993, from another natural gas-fired cogeneration facility owned and operated by March Point, which facility is known as March Point Phase II and is located at the Equilon refinery in Anacortes, Washington.following:
On March 20, 1991, PSE executed a 20-year contract to purchase 216 average MW of energy and 245 MW of capacity, beginning in April 1994, from Tenaska Washington Partners, LP, which owns and operates a natural gas-fired cogeneration project located near Ferndale, Washington. In December 1997 and January 1998, PSE and Tenaska Washington Partners entered into revised agreements in which PSE became the principal natural gas supplier to the project and power purchase prices under the Tenaska contract were revised to reflect market-based prices for the natural gas supply. PSE obtained an order from the Washington Commission creating a regulatory asset related to the $215 million restructuring payment. Under terms of the order, PSE was allowed to accrue as an additional regulatory asset one-half the carrying costs of the deferred balance over the first five years, which ended December 2002. The balance of the regulatory asset at December 31, 2004 was $202.0 million, which will be recovered in electric rates through 2011.
In December 1999, PSE bought out the remaining 8.5 years of one of the natural gas supply contracts serving Encogen from Cabot Oil & Gas Corporation (Cabot) which provided approximately 60% of the plant’s natural gas requirements. PSE became the replacement gas supplier to the project for 60% of the supply under the terms of the Cabot agreement. The balance of the regulatory asset at December 31, 2004 was $9.3 million, which will be recovered in electric rates through 2008.| Contract | Plant Type | Contract Exp. Date | Megawatt Capacity | Average Megawatts of Energy |
| Sumas Cogeneration Company | Natural gas cogeneration | 2013 | 135 | 108 |
| March Point Cogeneration Company: | | | | |
| March Point Phase I | Natural gas cogeneration | 2011 | 80 | 70 |
| March Point Phase II | Natural gas cogeneration | 2011 | 60 | 53 |
| Tenaska Washington Partners, LP | Natural gas cogeneration | 2011 | 245 | 216 |
| Total | | | 520 | 447 |
ELELCTRIC TRANSMISSION CONTRACTS WITH OTHER UTILITIESElectric Transmission Contracts With Other Utilities
PSE has entered into numerous transmission contracts with BPA to integrate electric generation and contracted resources and energy contracts into the PSE system to serve native load.PSE’s system. These transmission contracts specify thatrequire PSE willto pay for transmission service based on the contracted megawattMW level of demand, regardless of actual use. Any costs incurred are recovered through the PCA mechanism.
Other agreements notably the Westside Northern Intertie Agreement and the AC Intertie Capacity Ownership Agreement provide actual capacity ownership type rights to PSE.or capacity ownership rights. PSE’s annual charges are also based on contracted megawatt amounts.MW volumes. Capacity on these agreements that areis not committed for native load or other uses areis available for sale to third parties on PSE’s Open Access Same Time Information System (OASIS). PSE purchases short term transmission services from a variety of providers, including BPA.
The transmission agreements with BPA provide, among other things, the integration of PSE’s energy resources including PSE’s share of the Mid-Columbia hydroelectric projects, the Colstrip project and the PG&E exchange. The agreements have various terms ranging from specified dates in the 1 to 14 year time frame to life-of-facilities, the latter being in effect as long as the transmission facilities themselves are fully functional. Collectively, the agreementscollectively and have an aggregate demand limit in excess of 2,2002,600 MW.
In April 2004,2006, BPA and PSE enteredsigned agreements for a total of 650 MW from the Mid-Columbia area into a two-year contract with BPAPSE’s system. Service under these agreements commenced November 1, 2006 and will continue until November 30, 2007 and contain rights to integratecontinue service beyond the output of PSE’s recently acquired share of the Frederickson 1 plant. The hourly demand limit of this contract is 150 MW.
PSE’s transmission expenses for integrating its firm resources was $34.7 million in 2004. The transmission rates used by BPA for these contracts are effective through September 30, 2005. BPA rates change from time to time based upon BPA’s rate cases.
On December 6, 2004, BPA offered a proposed transmission rate case settlement agreement to BPA’s transmission customers. Under the terms of the settlement agreement, the BPA IR Rate, the rate at which PSE receives the vast majority of its transmission service from BPA, will increase 17.6%. On January 6, 2005, BPA reached settlement with all its customers. BPA must file the settlement agreement with FERC and wait for FERC’s approval before rates can go into effect. It is anticipated that rates will go into effect October 1, 2005.termination date.
TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | |
| Gas operating revenues by classes (thousands): | | | | | | | |
| Residential | | $ | 478,969 | | $ | 401,717 | | $ | 428,569 | |
| Commercial firm | | | 187,262 | | | 149,671 | | | 167,434 | |
| Industrial firm | | | 30,472 | | | 24,164 | | | 28,312 | |
| Interruptible | | | 46,900 | | | 34,046 | | | 48,889 | |
| Total retail gas sales | | | 743,603 | | | 609,598 | | | 673,204 | |
| Transportation services | | | 12,968 | | | 13,796 | | | 12,851 | |
| Other | | | 12,735 | | | 10,836 | | | 11,100 | |
| Total gas operating revenues | | $ | 769,306 | | $ | 634,230 | | $ | 697,155 | |
| Number of customers served (average): | | | | | | | | | | |
| Residential | | | 605,505 | | | 583,439 | | | 565,003 | |
| Commercial firm | | | 48,457 | | | 46,813 | | | 45,916 | |
| Industrial firm | | | 2,678 | | | 2,685 | | | 2,727 | |
| Interruptible | | | 576 | | | 611 | | | 650 | |
| Transportation | | | 129 | | | 134 | | | 122 | |
| Total customers | | | 657,345 | | | 633,682 | | | 614,418 | |
| Gas volumes, therms (thousands): | | | | | | | | | | |
| Residential | | | 489,036 | | | 500,116 | | | 500,672 | |
| Commercial firm | | | 217,346 | | | 216,951 | | | 218,716 | |
| Industrial firm | | | 36,751 | | | 36,890 | | | 39,142 | |
| Interruptible | | | 65,425 | | | 61,739 | | | 81,045 | |
| Total retail gas volumes, therms | | | 808,558 | | | 815,696 | | | 839,575 | |
| Transportation volumes | | | 201,642 | | | 209,497 | | | 207,852 | |
| Total volumes | | | 1,010,200 | | | 1,025,193 | | | 1,047,427 | |
| Working gas volumes in storage at year end, therms (thousands): | | | | | | |
| Jackson Prairie | | | 70,986 | | | 60,365 | | | 64,583 | |
| Clay Basin | | | 55,044 | | | 49,314 | | | 51,225 | |
| Average therms used per customer: | | | | | | | | | | |
| Residential | | | 808 | | | 857 | | | 886 | |
| Commercial firm | | | 4,485 | | | 4,634 | | | 4,763 | |
| Industrial firm | | | 13,723 | | | 13,739 | | | 14,354 | |
| Interruptible | | | 113,585 | | | 101,046 | | | 124,685 | |
| Transportation | | | 1,563,116 | | | 1,563,410 | | | 1,703,705 | |
| Average revenue per customer: | | | | | | | | | | |
| Residential | | $ | 791 | | $ | 689 | | $ | 759 | |
| Commercial firm | | | 3,864 | | | 3,197 | | | 3,647 | |
| Industrial firm | | | 11,379 | | | 9,000 | | | 10,382 | |
| Interruptible | | | 81,424 | | | 55,722 | | | 75,214 | |
| Transportation | | | 100,527 | | | 102,955 | | | 105,336 | |
| Average revenue per therm sold: | | | | | | | | | | |
| Residential | | $ | 0.979 | | $ | 0.803 | | $ | 0.855 | |
| Commercial firm | | | 0.862 | | | 0.690 | | | 0.766 | |
| Industrial firm | | | 0.829 | | | 0.655 | | | 0.723 | |
| Interruptible | | | 0.717 | | | 0.551 | | | 0.603 | |
| Average retail revenue per therm sold | | | 0.920 | | | 0.747 | | | 0.802 | |
| Transportation | | | 0.064 | | | 0.066 | | | 0.062 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Gas operating revenues by classes (thousands): | | | | | | | |
| Residential | | $ | 697,631 | | $ | 592,361 | | $ | 478,969 | |
| Commercial firm | | | 279,977 | | | 234,342 | | | 187,262 | |
| Industrial firm | | | 43,994 | | | 38,380 | | | 30,472 | |
| Interruptible | | | 68,753 | | | 56,928 | | | 46,900 | |
| Total retail gas sales | | | 1,090,355 | | | 922,011 | | | 743,603 | |
| Transportation services | | | 13,269 | | | 13,277 | | | 12,968 | |
| Other | | | 16,494 | | | 17,227 | | | 12,735 | |
| Total gas operating revenues | | $ | 1,120,118 | | $ | 952,515 | | $ | 769,306 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Number of customers served (average): | | | | | | | |
| Residential | | | 649,373 | | | 629,563 | | | 610,181 | |
| Commercial firm | | | 51,007 | | | 50,148 | | | 49,050 | |
| Industrial firm | | | 2,618 | | | 2,651 | | | 2,688 | |
| Interruptible | | | 470 | | | 528 | | | 574 | |
| Transportation | | | 122 | | | 129 | | | 129 | |
| Total customers | | | 703,590 | | | 683,019 | | | 662,622 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Gas volumes, therms (thousands): | | | | | | | |
| Residential | | | 533,370 | | | 510,026 | | | 489,036 | |
| Commercial firm | | | 236,753 | | | 225,389 | | | 217,346 | |
| Industrial firm | | | 41,185 | | | 38,576 | | | 36,751 | |
| Interruptible | | | 65,016 | | | 61,769 | | | 65,425 | |
| Total retail gas volumes, therms | | | 876,324 | | | 835,760 | | | 808,558 | |
| Transportation volumes | | | 206,367 | | | 198,504 | | | 201,642 | |
| Total volumes | | | 1,082,691 | | | 1,034,264 | | | 1,010,200 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Working gas volumes in storage at year end, therms (thousands): | | | | | | | |
| Jackson Prairie | | | 68,141 | | | 70,303 | | | 70,986 | |
| AECO hub - Canada | | | 14,810 | | | 14,820 | | | -- | |
| Clay Basin | | | 91,090 | | | 38,857 | | | 55,044 | |
| Average therms used per customer: | | | | | | | | | | |
| Residential | | | 821 | | | 810 | | | 801 | |
| Commercial firm | | | 4,642 | | | 4,494 | | | 4,431 | |
| Industrial firm | | | 15,731 | | | 14,551 | | | 13,672 | |
| Interruptible | | | 138,332 | | | 116,987 | | | 113,981 | |
| Transportation | | | 1,691,533 | | | 1,538,791 | | | 1,563,116 | |
| Average revenue per customer: | | | | | | | | | | |
| Residential | | $ | 1,074 | | $ | 941 | | $ | 785 | |
| Commercial firm | | | 5,489 | | | 4,673 | | | 3,818 | |
| Industrial firm | | | 16,804 | | | 14,478 | | | 11,336 | |
| Interruptible | | | 146,283 | | | 107,818 | | | 81,707 | |
| Transportation | | | 108,762 | | | 102,922 | | | 100,527 | |
| Average revenue per therm sold: | | | | | | | | | | |
| Residential | | $ | 1.308 | | $ | 1.161 | | $ | 0.979 | |
| Commercial firm | | | 1.183 | | | 1.040 | | | 0.862 | |
| Industrial firm | | | 1.068 | | | 0.995 | | | 0.829 | |
| Interruptible | | | 1.057 | | | 0.922 | | | 0.717 | |
| Average retail revenue per therm sold | | | 1.244 | | | 1.103 | | | 0.920 | |
| Transportation | | | 0.064 | | | 0.067 | | | 0.064 | |
| Heating degree days | | | 4,476 | | | 4,489 | | | 4,421 | |
Percent of normal - NOAA 30-year average | | | 93.3 | % | | 93.6 | % | | 91.8 | % |
PSE currently purchases a blended portfolio of gas supplies ranging from long-term firm to daily gas supplies from a diverse group of major and independent natural gas producers and marketers in the United States and Canada. PSE also enters into short-term physical and financial fixed price derivative instruments to hedge the cost of gas to serve its customers. All of PSE’s gas supply is ultimately transported through the facilities of Williams Northwest Pipeline Corporation (NWP), the sole interstate pipeline delivering directly into the western Washington area.Washington. Delivery of gas supply to PSE’s gas system is therefore dependent upon the operations of NWP.
| | | 2004 | | 2003 | | 2006 | | 2005 | |
| PEAK FIRM GAS SUPPLY AT DECEMBER 31 | | | Dth per Day | | | % | | | Dth per Day | | | % | | |
| Peak Firm Gas Supply at December 31 | | Dth per Day | | % | | Dth per Day | | % | |
| Purchased gas supply: | | | | | | | | | | | | | | | | | | | | | |
| British Columbia | | | 198,000 | | | 22.7 | % | | 171,000 | | | 20.0 | % | | 235,000 | | | 24.3 | % | | 205,400 | | | 22.1 | % |
| Alberta | | | 50,000 | | | 5.7 | % | | 78,000 | | | 9.2 | % | | 60,000 | | | 6.2 | % | | 60,000 | | | 6.5 | % |
| United States | | | 145,000 | | | 16.6 | % | | 100,000 | | | 11.7 | % | | 145,700 | | | 15.1 | % | | 167,800 | | | 18.1 | % |
| Total purchased gas supply | | | 393,000 | | | 45.0 | % | | 349,000 | | | 40.9 | % | | 440,700 | | | 45.6 | % | | 433,200 | | | 46.7 | % |
| Purchased storage capacity: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Clay Basin | | | 48,000 | | | 5.5 | % | | 55,800 | | | 6.5 | % | | 76,000 | | | 7.9 | % | | 45,200 | | | 4.9 | % |
| Jackson Prairie | | | 55,100 | | | 6.3 | % | | 55,100 | | | 6.4 | % | | 55,100 | | | 5.7 | % | | 55,100 | | | 5.9 | % |
| LNG | | | 70,500 | | | 8.1 | % | | 70,500 | | | 8.2 | % | |
| AECO hub - Canada | | | 16,700 | | | 1.7 | % | | 16,700 | | | 1.8 | % |
| Liquefied natural gas | | | 70,500 | | | 7.3 | % | | 70,500 | | | 7.6 | % |
| Total purchased storage capacity | | | 173,600 | | | 19.9 | % | | 181,400 | | | 21.1 | % | | 218,300 | | | 22.6 | % | | 187,500 | | | 20.2 | % |
| Owned storage capacity: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Jackson Prairie | | | 294,700 | | | 33.7 | % | | 294,700 | | | 34.4 | % | | 294,700 | | | 30.5 | % | | 294,700 | | | 31.8 | % |
| Propane-air and other | | | 12,500 | | | 1.4 | % | | 30,500 | | | 3.6 | % | | 12,500 | | | 1.3 | % | | 12,500 | | | 1.3 | % |
| Total owned storage capacity | | | 307,200 | | | 35.1 | % | | 325,200 | | | 38.0 | % | | 307,200 | | | 31.8 | % | | 307,200 | | | 33.1 | % |
| Total peak firm gas supply | | | 873,800 | | | 100.0 | % | | 855,600 | | | 100.0 | % | | 966,200 | | | 100 | % | | 927,900 | | | 100.0 | % |
| Other and commitments with third parties | | | (53,100 | ) | | | | | (53,200 | ) | | | | | (44,400 | ) | | | | | (41,400 | ) | | | |
| Total net peak firm gas supply | | | 820,700 | | | | | | 802,400 | | | | | | 921,800 | | | | | | 886,500 | | | | |
All peak firm gas supplies and storage are connected to PSE’s market with firm transportation capacity.
For baseload and peak-shaving purposes, PSE supplements its firm gas supply portfolio by purchasing natural gas, injecting it into underground storage facilities and withdrawing it during the peak winter heating season. Storage facilities at Jackson Prairie in western Washington and at Clay Basin in Utah are used for this purpose. Jackson Prairie is also used for daily balancing of load requirements on PSE’s gas system. PSE has been in the process of expanding the storage capacity at Jackson Prairie since March 2003, and plans to continue doing so through 2008. At the end of this project, PSE will have added approximately 2,000,000 Dekatherms (one Dekatherm, or Dth, is equal to one million British thermal units or MMBtu) of additional working storage capacity. Peaking needs are also met by using PSE-owned gas held in NWP’s liquefied natural gas (LNG) facility at Plymouth, Washington, by producing propane-air gas at a plant owned by PSE and located on its distribution system, and by interrupting service to customers on interruptible service rates.
PSE expects to meet its firm peak-day requirements for residential, commercial and industrial markets through its firm gas purchase contracts, firm transportation capacity, firm storage capacity and other firm peaking resources. PSE believes it will be able to acquire incremental firm gas supply to meet anticipated growth in the requirements of its firm customers for the foreseeable future.
GAS SUPPLY PORTFOLIOGas Supply Portfolio
For the 2004-20052006-2007 winter heating season, PSE contracted for approximately 22.7%24.3% of its expected peak-day gas supply requirements from sources originating in British Columbia, Canada under a combination of long-term, medium-term and seasonal purchase agreements. Long-term gas supplies from Alberta represent approximately 5.7%6.2% of the peak-day requirements. Long-term and winter peaking arrangements with U.S. suppliers make up approximately 16.6%15.1% of the peak-day portfolio. The balance of the peak-day requirements is expected to be met with gas stored at Jackson Prairie, gas stored at Clay Basin and AECO hub (AECO), LNG held at NWP’s Plymouth facility and propane-air and other resources, which represent approximately 40.0%36.2%, 5.5%7.9%, 8.1%1.7%, 7.3% and 1.4%1.3%, respectively, of expected peak-day requirements. PSE also has the ability to curtail service to industrial and commercial customers on interruptible service rates during a peak-day event.
During 2004, approximately 32% of gas supplies purchased by PSE originated in British Columbia while 20% originated in Alberta and 48% originated in the United States. The currentDecember 2006 firm long-term gas supply portfolio consistsconsisted of arrangements with 1220 producers and gas marketers, with no single supplier representing more than 4%6.0% of expected peak-day requirements. Contracts have remaining terms ranging from less than one1 year to ten8 years.
During 2006, approximately 37.9% of gas supplies purchased by PSE originated in British Columbia while 18.4% originated in Alberta and 43.7% originated in the United States. PSE’s firm gas supply portfolio has flexibility in its transportation arrangements so that some savings can be achieved when there are regional price differentials between gas supply basins. The geographic mix of suppliers and daily, monthly and annual take requirements permit some degree of flexibility in managing gas supplies during off-peak periods to minimize costs. Gas is marketed outside PSE’s service territory (off-system sales) whenever on-system customer demand requirements permit.
GAS STORAGE CAPACITYGas Storage Capacity
PSE holds storage capacity in the Jackson Prairie and Clay Basin underground gas storage facilities adjacent to NWP’s pipeline.pipeline and at AECO in Alberta, Canada adjacent to Nova Gas Transmission, Ltd. (TransCanada-Alberta). These facilities represent 45.5%45.8% of the expected peak-day portfolio. The Jackson Prairie facility, operated and one-third owned by PSE, is used primarily for intermediate peaking purposes since it is able to deliver a large volume of gas over a relatively short time period. Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE has peak firm delivery capacity of over 349,000 Dekatherms (one Dekatherm, or Dth, is equal to one million British thermal units or MMBtu) per day and total firm storage capacity exceeding 8,100,000of over 8,600,000 Dth at the facility. The location of the Jackson Prairie facility in PSE’s market area increases supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day gas requirements. PSE has been in the process of expanding the storage capacity at Jackson Prairie since March 2003, and plans to continue through 2008. At the end of this project, PSE will have added approximately 2,000,000 Dth of additional working storage capacity. In order to meet the growing peaking requirements in the region, PSE and other owners of Jackson Prairie obtained FERC authorization on February 5, 2007 to increase deliverability of the project from 884,000 Dth per day to 1,196,000 Dth per day. PSE’s share of this expansion, 104,000 Dth per day, is expected to cost $15.0 million and be in-service by November 2008. The Clay Basin storage facility is a supply area storage facility that is used primarily to reduce portfolio costs through injections and withdrawals that take advantage of market price volatility and is also used for system reliability. After the releasePSE holds 13,400,000 Dth of capacity in 2004, PSE retained maximum firm withdrawal capacity of over 60,000 Dth per day from the Clay Basin facility with total storage capacity of almost 7,419,000 Dth. The Clay Basin capacity is held under two long-term contracts with remaining terms of 86 years and 1513 years. The capacity release contracts PSE has with multiple parties at theexchanged 2,000,000 Dth of this Clay Basin capacity for 2,000,000 Dth of AECO storage facility have remaining termscapacity, which includes withdrawal capacity of three months as of December16,700 Dth per day and terminates March 31, 2004, with automatic renewal for 12-month terms.2008. After this exchange, PSE’s maximum firm withdrawal capacity and total storage capacity at Clay Basin is over 110,00076,000 Dth per day and exceeds 13,000,00011,000,000 Dth, respectively, when PSE has not released any of the capacity.respectively.
LNG AND PROPANE-AIR RESOURCESand Propane-Air Resources
LNG and propane-air resources provide gas supply on short notice for short periods of time. Due to their typically high cost and slow cycle times, these resources are normally utilized as the supply of last resort in extreme peak-demand periods, typically lasting a few hours or days. PSE has a long-term contract for storage of 241,700 Dth of PSE-owned gas as LNG at NWP’s Plymouth facility, which equates tois approximately three and one-half daysday’s supply at a maximum daily deliverability of 70,500 Dth. PSE owns storage capacity for approximately 1.5 million gallons of propane. The propane-air injection facilities are capable of delivering the equivalent of 10,000 Dth of gas per day for up to twelve days directly into PSE’s distribution system.
In 2004, a 6,000 Dth capacity LNG storage facility was completed in Gig Harbor. In 2006, PSE expanded the capacity to 10,600 Dth. The purpose of the facility is to provide a supplemental supply of natural gas during periods of high demand, improve overall system reliability and eliminate the need for portable LNG operations in the Gig Harbor area. Included in the facility are a transport trailer, storage tank, transfer station and send out skid.
GAS TRANSPORTATION CAPACITYGas Transportation Capacity
PSE currently holds firm transportation capacity on pipelines owned by NWP, Gas Transmission Northwest (a TransCanada company, “GTN”), TransCanada Pipelines, Ltd. (TransCanada), and Duke Energy Gas Transmission (Westcoast).Westcoast. Accordingly, PSE pays fixed monthly demand charges for the right, but not the obligation, to transport specified quantities of gas from receipt points to delivery points on such pipelines each day for the term or terms of the applicable agreements.
PSE and WNG CAP I, a wholly-owned subsidiary of PSE, hold firm year-round capacity on NWP through various contracts. PSE and WNG CAP I participate in the secondary pipeline capacity market to achieve savings for PSE’s customers. As a result, PSE and WNG CAP I hold approximately 465,000520,000 Dth per day of capacity due to capacity release and segmentation transactions on NWP that provides firm delivery to PSE’s service territory. In addition, PSE holds approximately 413,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of gas stored gasin Jackson Prairie and the Plymouth LNG facility during the heating season. PSE has firm transportation capacity on NWP that supplies the Frederickson 1 generating facility ofwith approximately 22,000 Dth per day, with a remaining term of 1412 years. PSE has released certain segments of its firm capacity with third parties to effectively lower transportation costs. PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from less than 1 year to 1210 years. However, PSE has either the unilateral right to extend the contracts under their current terms or the right of first refusal to extend such contracts under current FERC orders. PSE’s firm transportation capacity on Gas Transmission Northwest’sGTN’s pipeline, totaling approximately 90,000 Dth per day, has a remaining term of 1917 years.
PSE’s firm transportation capacity on Westcoast’s pipeline totalingis approximately 40,00097,000 Dth per day has a remaining term of 10 years foruntil October 31, 2012, then approximately 25,00086,000 Dth per day until October 31, 2014, then approximately 41,000 Dth per day until October 31, 2017 and a remaining term of 14 years forthereafter approximately 15,000 Dth per day.day until October 31, 2018. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the Frederickson 1 generating facility, totaling approximately 22,000 Dth per day, with a remaining term of 108 years. PSE’sPSE has firm capacity on TransCanada’s Alberta and British Columbia transportation systems, totaling approximately 80,000 Dth per day, phases in year to year renewalday. PSE has annual rollover rights beginning in 2006.for this capacity. In addition, PSE has firm transportation capacity on TransCanada’s pipelines commencing in 2008 with a term of 15 years, totaling approximately 8,000 Dth per day.
During 2003, NWP took one of its two parallel pipelines serving western Washington from British Columbia out of service as a result of a second failure of the affected pipeline. Together, these two pipelines had the ability to flow approximately 1,300,000 Dth per day of gas from British Columbia. The loss of the affected pipeline reduced this ability to approximately 950,000 Dth per day. Subsequent to testing and remediation efforts, portions of the affected line were returned to service in 2004, increasing the ability to flow gas from British Columbia to approximately 1,100,000 Dth per day. If the affected pipeline is not completely returned to service, the loss could potentially decrease PSE’s overall NWP capacity by 5%. In December 2004, NWP filed a request for authorization from FERC to replace all of the lost capacity through construction of new facilities. NWP expects to complete such Capacity Replacement project by the end of 2006. The cost of the Capacity Replacement project is expected to increase the cost for services that PSE receives from NWP by approximately 20% beginning in 2007. PSE expects that the increase will be entirely recoverable from customers through the existing PGA mechanism. To date, the loss of capacity has not adversely impacted PSE’s ability to serve its gas customers, but customers on interruptible tariff rate schedules could be curtailed during peak events. PSE expects to continue meeting its customer needs throughout the pipeline capacity replacement period, and PSE has back-up oil supply for its combustion turbines.
CAPACITY RELEASERelease
FERC provided a capacity release mechanism as the means for holders of firm pipeline and storage entitlements to temporarily or permanently relinquish unutilized capacity to others in order to recoup all or a portion of the cost of such capacity. Capacity may be released through several methods including open bidding and by pre-arrangement. PSE continues to successfully mitigate a portion of the demand charges related to both storage and NWP pipeline capacity not utilized during off-peak periods through capacity release. PSE also utilizes capacity release mechanisms to acquire additional assets to serve its growing service territory. WNG CAP I, was formed to providea PSE subsidiary, provides additional flexibility and benefits from capacity release.release transactions. Capacity release benefits are passed on to customers through the PGA mechanism.
PSE offers programs designed to help new and existing residential, commercial and industrial customers use energy efficiently. PSE uses a variety of mechanisms including cost-effective financial incentives, information and technical services to enable customers to make energy-efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices. Energy efficiency programs reduce customer consumption of energy thus reducing energy margins. The impact of load reductions is adjusted in rates at each general rate case.
PSE's two-year savings goals are set based on the Integrated Resource Plan and in conjunction with the Conservation Resource Advisory Group per the terms of the 2002 Conservation Stipulation Agreement. For 2004-2005, the minimum savings goals for the two-year period to avoid a “penalty” mechanism were set at 23.2 average MW and 3.5 million therms while the “stretch” goals were set at 39.2 average MW and 5 million therms. PSE achieved 39.34 average MW and 6 million therms of cost-effective energy savings during the two-year timeframe, exceeding its goals.
For 2006-2007, the sum of the annual savings goals for the two-year period is set at 33 average MW and 3.4 million therms. If conservation savings are less than 75.0% of the minimum goal, PSE will be subject to a penalty of $0.8 million. If savings are between 75.0% and 89.0% of the minimum, the penalty is $0.5 million, and between 90.0% and 99.0% of the minimum, the penalty is $0.2 million. Actual results through December 31, 2006 for the 2006-2007 period are 18.98 average MWs and 2.4 million therms.
Since May 1997, PSE has recovered electric energy efficiency (or conservation) expenditures through a tariff rider mechanism. The rider mechanism allows PSE to defer the efficiency expenditures and amortize them to expense as PSE concurrently collects the efficiency expenditures in rates over a one-year period. As a result of the rider, electric energy efficiency expenditures have no effect on earnings.
Since 1995, PSE has been authorized by the Washington Commission to defer gas energy efficiency (or conservation) expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows PSE to defer efficiency expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows PSE to recover an Allowanceallowance for Funds Usedfunds used to Conserve Energyconserve energy on any outstanding balance that is not being recovered in rates. As a result of the tracker mechanism, gas energy efficiency expenditures have no impact on earnings.
Energy efficiency programs reduce customer consumption of energy thus impacting energy margins. The impact of load reductions are adjusted in rates at each general rate case.
The Company’s operations are subject to environmental laws and regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental and energy laws and regulations, the Company cannot determine the impact such laws may have on its existing and future facilities. (See Note 23
Greenhouse Gas Policy
PSE recognizes the growing concern that increased atmospheric concentrations of greenhouse gases contribute to climate change. PSE believes that climate change is a very important issue that requires careful analysis and responses. PSE’s policy is to take cost-effective measures to mitigate and/or offset greenhouse gas emissions from our energy activities while maintaining a dependable, cost-effective and diverse energy portfolio mix that will sustain our customers’ needs now and into the Consolidated Financial Statements for further discussionfuture. PSE is taking and will continue to take appropriate steps to meet the goal of environmental sites.)providing cost-effective and reliable energy while decreasing the impact on climate change through the implementation of these measures. The full PSE Greenhouse Gas Policy is available at www.pse.com.
REGULATION OF EMISSIONSRegulation Of Emissions
PSE has an ownershipfacilities are subject to regulation of emissions, including PSE’s interest in coal-fired, steam-electric generating plants at Colstrip, Montana which are subject to regulation of emissions and other regulatory requirements. PSE also ownsits combustion turbine units in western Washington, which are capable of being fueled by natural gas or diesel fuel. These combustion turbines are operated to comply with emission limits set forth in their respective air operating permits.
units. There is no assurance that in the future environmental laws and regulations affecting sulfur dioxide, carbon monoxide particulate matter or nitrogen oxide emissions maywill not be further restricted,more restrictive, or that restrictions on greenhouse gas emissions, such as carbon dioxide, or other combustion byproducts, such as mercury, may not be imposed.imposed at the federal or state level.
Emissions Inventory
During 2006, PSE’s total electric retail load of 21,099,045 MWh was served from a supply portfolio of owned and purchased resources. Since 2002, PSE has voluntarily undertaken an inventory of its greenhouse gas (GHG) emissions associated with this portfolio. Such inventory follows the protocol established by the World Resource Institute GHG Protocol (GHG Protocol). The most recent data indicate that PSE’s total GHG emissions (direct and indirect) from its electric supply portfolio in 2005 were 12,999,051 tons (CO2e). Approximately 54.3% of these emissions (approximately 7,058,313 tons) are associated with PSE’s ownership and contractual interests in the 2,200 MW Colstrip, Montana coal-fired steam electric generation facility (the “Facility”).
Colstrip is a significant part of the diversified portfolio PSE owns and/or operates for its customers. Consequently, while Colstrip remains a significant portion of our overall GHG emissions, PSE’s overall emissions strategy demonstrates a concerted effort to manage our customers’ needs with an appropriate balance of new renewable generation, existing generation owned and/or operated by PSE, and significant energy efficiency efforts.
With ongoing development of state and federal initiatives intended to address climate change, the challenge to develop strategic solutions is more complicated than ever. However, PSE believes that now is the time to act. Consequently it is PSE’s intent to incorporate into the IRP a long-term strategic goal that will adhere to the objectives of our recently published Greenhouse Gas Policy.
On May 18, 2005, the Environmental Protection Agency (EPA) enacted the Clean Air Mercury Rule (CAMR) that will permanently cap and reduce mercury emissions from coal-fired power plants. The Montana Board of Environmental Review approved a more stringent rule to limit mercury emissions from coal-fired plants on October 16, 2006 (0.9 lbs/TBtu, instead of the federal 1.4 lbs/TBtu). The Colstrip owners are still evaluating the potential impact of the new rule and it is still unknown whether the new rule will be appealed. Preliminary treatment technology studies undertaken by the Colstrip owners estimate that PSE’s portion of the costs to comply with the new rule could be as much as $75.0 million in construction expenditures; this number could change as new information becomes available.
In December 2003, Colstrip Units 1 & 2 and 3 & 4 receivedthe EPA issued an information request from the Environmental Protection Agency (EPA) relating to their compliance withAdministrative Consent Order (ACO) which alleged violation of the Clean Air Act New Source Review regulations. PSE is currently in discussions withpermit requirement to submit, for review and approval by the EPA, concerningan analysis and proposal for reducing emissions of nitrogen oxide to address visibility concerns upon the information request. Neitheroccurrence of certain triggering events which EPA asserts occurred in 1980. Although Colstrip owners believe that the outcomeACO is unfounded, the Colstrip owners signed a settlement agreement in December 2006 that is now awaiting signature by EPA, and then will be entered by the court. The agreement includes installation of this matter nor any potential associated costs can be predicted at this timelow nitrogen oxide equipment installation on Colstrip Units 3 & 4 which will cost PSE approximately $2.65 million.
FEDERAL ENDANGERED SPECIES ACTFederal Endangered Species Act
Since the 1991, listing of the Snake River Sockeye salmon as an endangered species, a total of eightthirteen species of salmon and steelhead have been listed as threatened or endangered species under the Endangered Species Act, which influences hydroelectric operations. Most directly associated with project operations,While the Upper Columbia River Steelhead and the Upper Columbia Spring Chinook were listed as endangered species by the National Marine Fisheries Service in August 1997 and March 1999, respectively. To address this exposure,most significant impacts have affected the Mid-Columbia PUDs, initiated consultation with federal and state agencies, Native American tribes and non-governmental organizations to secure operational protection through long-term settlements and habitat conservation plans (HCPs) for each affected project. The agreement provisions include fish protection and enhancement measures for the next 50 years. The HCPs received the support of the resource agencies, have been adopted by FERC and generally obligate the PUDs to achieve certain levels of passage efficiency for downstream migrants at their hydroelectric facilities and to fund certain habitat conservation measures. Grant County PUD reached an agreement with the various parties in 2004 in a form substantially similar to the HCPs adopted by Douglas County PUD and Chelan County PUD. FERC issued an order approving that settlement and terminating the Mid-Columbia fish proceeding as to all parties on December 16, 2004.
The proposed listings of Puget Sound Chinook salmon and spring Chinook salmon as endangered species for the upper Columbia River were approved in March 1999. The Company does not expect the listing of spring Chinook salmon as an endangered species for the upper Columbia River to result in markedly differing conditions for operations from previous listings in the area.
The completed listings of Coastal/Puget Sound Distinct Population Segment of Bull Trout as an endangered species in the fall of 1999 and Puget Sound Chinook salmon in the winter of 2001 are causing a number of changes to operations of governmental agencies and private entities in the region, including PSE. These changesESA impacts may adversely affect hydroelectric plant operations and permit issuance for facilities construction, and increase costs for processes and facilities. Because PSE relies substantially less on hydroelectric energy from the Puget Sound area than from the Mid-Columbia River and also because the impact on PSE operations, in the Puget Sound area is not likely to impair significant generating resources, the impact of listing for Puget Sound Chinook salmon and Bull Trout, while potentially representing cost exposure and operational constraints, should be proportionately less than the effects of the Columbia River listings.constraints. PSE is actively engaging the federal agencies to address Endangered Species Act issues for PSE’s generating facilities. Consultation with federal agencies is ongoing.
The executive officers of Puget Energy as of December 31, 20042006 are listed below. Puget Energy considers the Chief Executive Officer of InfrastruX to be an executive officer of Puget Energy. For their business experience during the past five years, please refer to the table below regarding Puget Sound Energy’s executive officers. Officers of Puget Energy are elected for one-year terms.
NAMEName
| AGEAge
| OFFICESOffices
|
| S. P. Reynolds | 5658 | Chairman, President and Chief Executive Officer since January 2002.May 2005; President and Chief Executive Officer, 2002 - 2005. Director since January 2002. |
| J. W. Eldredge | 5456 | Vice President, Corporate Secretary and Chief Accounting Officer since April 1999.May 2005; Corporate Secretary and Chief Accounting Officer 1999 - 2005. |
| D. E. Gaines | 4749 | Vice President Finance and Treasurer since March 2002. |
M. T. Lennon | 42 | President and Chief Executive Officer of InfrastruX since April 2003, President of InfrastruX, 2002 - 2003. Prior to joining InfrastruX, he served as Managing Director of Lennon Smith Advisors, LLC, an investment banking firm, 2000 - 2002. |
| J. L. O’Connor | 4850 | Senior Vice President General Counsel, Chief Ethics and Compliance Officer since October 2005; Vice President and General Counsel, since January 2003.2003 - 2005. |
| B. A. Valdman | 4143 | Senior Vice President Finance and Chief Financial Officer since January 2004. |
The executive officers of Puget Sound Energy as of December 31, 20042006 are listed below along with their business experience during the past five years. Officers of Puget Sound Energy are elected for one-year terms.
NAMEName
| AGEAge
| OFFICESOffices
|
| S. P. Reynolds | 5658 | Chairman, President and Chief Executive Officer andsince May 2005; Director since January 2002; President and Chief Executive Officer 2002 - 2005; President and Chief Executive Officer of Reynolds Energy International, 1998 - 2002. |
| D. P. Brady | 4042 | Senior Vice President Customer Service, Information Technology and Chief Information Officer since October 2005; Vice President Customer Services since February 2003;2003 - 2005; Director and Assistant to Chief Operating Officer, 2002 - 2003. Prior to joining PSE, he was Managing Director of Irvine Associates Merchant Banking Group, 2001 - 2002; Executive Vice President-Operations of Orcom Solutions, 2000 - 2001.2002. |
| P. K. Bussey | 4850 | Senior Vice President Corporate Affairs since October 2005; Vice President Regional and Public Affairs, since September 2003.2003 - 2005. Prior to joining PSE, he was President of the Washington Round Table, 1996 - 2003. |
| J. W. Eldredge | 5456 | Vice President, Corporate Secretary, Controller and Chief Accounting Officer since May 2001; Corporate Secretary, Controller and Chief Accounting Officer, 1993 - 2001. |
| D. E. Gaines | 4749 | Vice President Finance and Treasurer since March 2002; Vice President and Treasurer, 2001 - 2002; Treasurer, 1994 - 2001.2002. |
| K. J. Harris | 4042 | Senior Vice President Regulatory Policy and Energy Efficiency since October 2005; Vice President Regulatory and Government Affairs, since February 2003;2003 - 2005; Vice President Regulatory Affairs, 2002 - 2003; Director Load Resource Strategies and Associate General Counsel, 2001 - 2002; Associate General Counsel, 1999 - 2001. |
J. L. Henry | 59 | Senior Vice President Energy Efficiency and Customer Services since February 2003; Director of Major Accounts, 2001 - 2003; Director Construction and Technical Field Services 2000 - 2001.2002. |
| E. M. Markell | 5355 | Senior Vice President Energy Resources since February 2003; Vice President Corporate Development, 2002 - 2003. Prior to joining PSE, he was Chief Financial Officer, Club One, Inc., 2000 - 2002. |
| S. McLain | 4850 | Senior Vice President Operations since February 2003; Vice President Operations - Delivery, 1999 - 2003. |
| M. D. Mellies | 46 | Vice President Human Resources since October 2005. Prior to joining PSE, she was General Manager of Human Resources at Microsoft, 2002 - 2005. |
| J. L. O’Connor | 4850 | Senior Vice President General Counsel, Chief Ethics and Compliance Officer since October 2005; Vice President and General Counsel, since January 2003.2003 - 2005. Prior to joining PSE, she was interim General Counsel, Starbucks Corporation, 2002; Senior Vice President and Deputy General Counsel, Starbucks Corporation, 2001 - 2002; Vice President and Assistant General Counsel, Starbucks Corporation, 1998 - 2001.2002. |
J. M. RyanC. E. Shirley | 4253 | Vice President Risk Management and Strategic PlanningEnergy Efficiency Services since April 2004; Vice PresidentOctober 2005; Director Energy Portfolio Management, 2001Efficiency Services, 2002 - 2004.2005. Prior to joining PSE, shehe was Managing DirectorSenior Manager of North American Marketing of TransAlta USA, 2001; Managing Director Origination of Merchant Energy Group of the Americas, Inc., 1997Services for Snohomish County Public Utility District, 1995 - 2001.2002. |
| B. A. Valdman | 4143 | Senior Vice President Finance and Chief Financial Officer since December 2003. Prior to joining PSE, he was Managing Director with JP Morgan Securities, Inc., 2000 - 2003 and a member of the Natural Resource Group of JP Morgan Securities, Inc. since 1993 and a banker with JP Morgan since 1987.2003. |
| P. M. Wiegand | 5254 | Vice President Project Development and Contract Management since July 2003; Vice President Corporate Planning, 2003; Vice President Corporate Planning and Performance, 2002 - 2003; Vice President Risk Management and Strategic Planning, 2000 - 2002. |
The following risk factors, in addition to other factors and matters discussed elsewhere in this report, should be carefully considered. The risks and uncertainties described below are not the only risks and uncertainties that Puget Energy and PSE may face. Additional risks and uncertainties not presently known or currently deemed immaterial also may impair PSE’s business operations. If any of the following risks actually occur, Puget Energy’s and PSE’s business, results of operations and financial conditions would suffer.
RISKS RELATING TO THE UTILITY BUSINESS
The actions of regulators can significantly affect PSE’s earnings, liquidity and business activities.
The rates that PSE is allowed to charge for its services is the single most important item influencing its financial position, results of operations and liquidity. PSE is highly regulated and the rates that it charges its customers are determined by the Washington Commission.
PSE is also subject to the regulatory authority of the Washington Commission with respect to accounting, the issuance of securities and certain other matters, and the regulatory authority of FERC with respect to the transmission of electric energy, the resale of electric energy at wholesale, accounting and certain other matters. Policies and regulatory actions by these regulators could have a material impact on PSE’s financial position, results of operations and liquidity.
PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed or recovery is delayed.
The Washington Commission determines the rates PSE may charge to its retail customers based on a normalized cost of producing power. If in a specific year PSE’s costs are higher than normal, rates will not be sufficient to permit PSE to earn the allowed return or to cover its costs and recovery of energy costs will be deferred until subsequent ratemaking proceedings. In addition, the Washington Commission decides what level of expense and investment is reasonable and prudent in providing service. If the Washington Commission decides that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates. For these reasons, the rates authorized by the Washington Commission may not be sufficient to earn the allowed return or recover the costs incurred by PSE in a given period.
The PCA mechanism by which variations in PSE’s power costs are apportioned between it and its customers could experience significant increase in expenses.
PSE has a PCA mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which are set in part based on normalized assumptions about weather and hydro conditions. Excess power costs or power cost savings will be apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism without operation of any cap.
PSE may be unable to acquire energy supply resources to meet projected customer needs or may fail to successfully integrate such acquisitions.
PSE projects that future energy needs will exceed current purchased and Company-controlled power resources. As part of PSE’s business strategy, it plans to acquire additional electric generation and delivery infrastructure to meet customer needs. If PSE cannot acquire further additional energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could significantly increase its expenses and reduce earnings and cash flows. Additionally, PSE may not be able to timely recover some or all of those increased expenses through ratemaking.
While PSE expects to identify the benefits of new energy supply resources prior to their acquisition and integration, it may not be able to achieve the expected benefits of such energy supply sources.
The Company’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, increased customer demand for energy, recurrence of low availability of hydroelectric resources, outages of its generating facilities or a failure to deliver on the part of its suppliers.
The utility business involves many operating risks. If PSE’s operating expenses, including the cost of purchased power and natural gas, significantly exceed the levels recovered from retail customers for an extended period of time, its cash flow and earnings would be negatively affected. Factors which could cause purchased power and gas costs to be higher than anticipated include, but are not limited to, high prices in western wholesale markets during periods when PSE has insufficient energy resources to meet its load requirements and/or high volumes of energy purchased in wholesale markets at prices above the amount recovered in retail rates due to:
| · | Increases in demand due, for example, either to weather or customer growth; |
| · | Below normal energy generated by PSE-owned hydroelectric resources due to low streamflow conditions; |
| · | Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers; |
| · | Failure to perform on the part of any party from which PSE purchases capacity or energy; and |
| · | The effects of large-scale natural disasters, such as the hurricanes recently experienced in the southern United States. |
PSE’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
PSE owns and operates coal, gas-fired, hydro, wind-powered and oil-fired generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels. Included among these risks are:
| · | Increased prices for fuel and fuel transportation as existing contracts expire; |
| · | Facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply; |
| · | Disruptions in the delivery of fuel and lack of adequate inventories; |
| · | Labor disputes; |
| · | Inability to comply with regulatory or permit requirements; |
| · | Disruptions in the delivery of electricity; |
| · | Operator error; |
| · | Terrorist attacks; and |
| · | Catastrophic events such as fires, explosions, floods or other similar occurrences. |
PSE is subject to the commodity price, delivery and credit risks associated with the energy markets.
In connection with matching loads and resources, PSE engages in wholesale sales and purchases of electric capacity and energy, and, accordingly, is subject to commodity price risk, delivery risk, credit risk and other risks associated with these activities. Credit risk includes the risk that counterparties owing PSE money or energy will breach their obligations. Should the counterparties to these arrangements fail to perform, PSE may be forced to enter into alternative arrangements. In that event, PSE’s financial results could be adversely affected. Although PSE’s models take into account the expected probability of default by counterparties, actual exposure to a default by a particular counterparty could be greater than the models predict.
To lower its financial exposure related to commodity price fluctuations, PSE may use forward delivery agreements, swaps and option contracts to hedge commodity price risk with a diverse group of counterparties. However, PSE does not always cover the entire exposure of its assets or positions to market price volatility and the coverage will vary over time. To the extent PSE has unhedged positions or its hedging procedures do not work as planned, fluctuating commodity prices could adversely impact its results of operations.
Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures and reduce earnings and cash flows.
PSE is in the process of renewing the federal licenses for its Baker River hydroelectric project and implementing the federal licensing requirements for the Snoqualmie Falls hydroelectric project. The relicensing process is a political and public regulatory process that involves sensitive resource issues. PSE cannot predict with certainty the conditions that may be imposed during the relicensing process, the economic impact of those requirements, whether new licenses will ultimately be issued, modified, or whether PSE will be willing to meet the relicensing requirements to continue operating these hydroelectric projects.
Costs of compliance with environmental and endangered species laws are significant and the cost of compliance with new environmental or endangered species laws and the incurrence of environmental liabilities could adversely affect PSE’s results of operations.
PSE’s operations are subject to extensive federal, state and local regulation relating to environmental and endangered species protection. To comply with these legal requirements, PSE must spend significant sums on environmental and endangered species monitoring, pollution control equipment and emission fees. New environmental and endangered species laws and regulations affecting PSE’s operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to PSE or its facilities, which may substantially increase environmental and endangered species expenditures made by it in the future. Compliance with these or other future regulations could require significant capital expenditures by PSE and adversely affect PSE’s financial position, results of operations, cash flows and liquidity. In addition, PSE may not be able to recover all of its costs for environmental expenditures through electric and natural gas rates at current levels in the future.
With respect to endangered species laws, the listing or proposed listing of several species of salmon in the Pacific Northwest is causing a number of changes to the operations of hydroelectric generating facilities on Pacific Northwest rivers, including the Columbia River. These changes could reduce the amount, and increase the cost, of power generated by hydroelectric plants owned by PSE or in which PSE has an interest and increase the cost of the permitting process for these facilities.
Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated, regardless of whether the liabilities arose before, during or after the time the facility was owned or operated. The incurrence of a material environmental liability or the new regulations governing such liability could result in substantial future costs and have a material adverse effect on PSE’s results of operations and financial condition.
The Company’s business is dependent on its ability to successfully access capital markets.
The Company relies on access to both short-term money markets as a source of liquidity and longer-term capital markets to fund its utility construction program and other capital expenditure requirements not satisfied by cash flow from its operations. If the Company is unable to access capital at competitive rates, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected.
Certain market disruptions or a downgrade of the Company’s credit rating may increase the Company’s cost of borrowing or adversely affect the ability to access one or more financial markets.
A downgrade in the Company’s credit rating could negatively affect its ability to access capital and the ability to hedge in wholesale markets.
Standard and Poor’s and Moody’s Investor Services rate PSE’s senior secured debt at “BBB” with a stable outlook and “Baa2” with a stable outlook, respectively. Although the Company is not aware of any current plans of S&P or Moody’s to lower their respective ratings on PSE’s debt, the Company cannot be assured that such credit ratings will not be downgraded.
Although neither Puget Energy nor PSE has any rating downgrade provisions in its credit facilities that would accelerate the maturity dates of outstanding debt, a downgrade in the Companies’ credit ratings could adversely affect their ability to renew existing or obtain access to new credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the spreads over the index and commitment fee increase as PSE’s corporate credit ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs.
Any downgrade below investment grade of PSE’s senior secured debt could allow counterparties in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security, all of which would expose PSE to additional costs.
The Company’s operating results fluctuate on a seasonal and quarterly basis.
PSE’s business is seasonal and weather patterns can have a material impact on its operating performance. Because natural gas is heavily used for residential and commercial heating, demand depends heavily on weather patterns in PSE’s service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. However, the recent increase in the price of natural gas may result in decreased customer demand, despite normal or lower than normal temperatures. Demand for electricity is also greater in the winter months associated with heating. Accordingly, PSE’s operations have historically generated less revenues and income when weather conditions are milder in the winter. In the event that the Company experiences unusually mild winters, results of operations and financial condition could be adversely affected.
The Company may be adversely affected by legal proceedings arising out of the electricity supply situation in the western power markets, which could result in refunds or other liabilities.
The Company is involved in a number of legal proceedings and complaints with respect to power markets in the western United States. Most of these proceedings relate to the significant increase in the spot market price of energy in western power markets in 2000 and 2001, which allegedly contributed to or caused unjust and unreasonable prices and allegedly may have been the result of manipulations by certain other parties. These proceedings include, but are not limited to, refund proceedings and hearings in California and the Pacific Northwest and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters. Accordingly, there can be no guarantee that these proceedings, individually or in the aggregate, will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.
The Company may be negatively affected by its inability to attract and retain professional and technical employees.
The Company’s ability to implement a workforce succession plan is dependent upon the Company’s ability to employ and retain skilled professional and technical workers in an aging workforce. Without a skilled workforce, the Company’s ability to provide quality service to PSE’s customers and meet regulatory requirements will be challenged and could affect earnings.
The Company may be adversely affected by extreme events in which the Company is not able to promptly respond and repair the electric and gas infrastructure system.
The Company must maintain an emergency planning and training program to allow the Company to quickly respond to extreme events. Without emergency planning, the Company is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers. In addition, a slow response to extreme events may have an adverse affect on earnings as customers may be without electricity and gas for an extended period of time.
The Company may be negatively affected by unfavorable changes in the tax laws or their interpretation.
Changes in tax law, related regulations, or differing interpretation or enforcement of applicable law by the Internal Revenue Service or other taxing jurisdiction could have a material adverse impact on the Company’s financial statements. The tax law, related regulations and case law are inherently complex. The Company must make judgments and interpretations about the application of the law when determining the provision for taxes. Disputes over interpretations of tax laws may be settled with the taxing authority upon examination or audit. The Company’s tax obligations include income, real estate, sales and use, business and occupation and employment-related taxes and ongoing appeals issues related to these taxes. These judgments may include reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by the taxing authorities.
RISKS RELATING TO PUGET ENERGY’S CORPORATE STRUCTURE
As a holding company, Puget Energy is subject to restrictions on its ability to pay dividends.
As a holding company with no significant operations of its own, the primary source of funds for the payment of dividends to its shareholders is dividends PSE pays to Puget Energy. PSE is a separate and distinct legal entity and has no obligation to pay any amounts to Puget Energy, whether by dividends, loans or other payments. The ability of PSE to pay dividends or make distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay dividends on its common stock, will depend on its earnings, capital requirements and general financial condition. If Puget Energy does not receive adequate distributions from PSE, it may not be able to make or may have to reduce dividend payments on its common stock.
PSE’s payment of common stock dividends to Puget Energy is restricted by provisions of covenants applicable to its preferred stock and long-term debt contained in its restated articles of incorporation and electric and gas mortgage indentures. Puget Energy’s Board of Directors reviews the dividend policy periodically in light of the factors referred to above and cannot assure shareholders of the amount of dividends, if any, that may be paid in the future.
Future sales of Puget Energy’s common stock on the public market could lower the stock price.
Puget Energy may sell additional shares of common stock in public offerings, through the stock purchase and dividend reinvestment plan or through common stock offering programs which it has entered into with two financial institutions. Puget Energy cannot predict the size of future issuances of common stock, or the effect, if any, that future issuances and sales of shares of common stock will have on the market price of common stock. Sales of substantial amounts of common stock, or the perception that such sales could occur, may adversely affect the prevailing market price of common stock.
The market price for common stock is uncertain and may fluctuate significantly.
Puget Energy cannot predict whether the market price of its common stock will rise or fall. Numerous factors influence the trading price of its common stock. These factors may include changes in financial condition, results of operations and prospects, legal and administrative proceedings and political, economic, financial and other factors that can affect the capital markets generally, the stock exchanges on which Puget Energy’s common stock is traded and its business segments.
Certain provisions of law, as well as provisions in the restated articles of incorporation, bylaws and shareholders rights plan, may make it more difficult for others to obtain control of Puget Energy.
Puget Energy is a Washington corporation and certain anti-takeover provisions of Washington laws apply and create various impediments to the acquisition of control of Puget Energy or to the consummation of certain business combinations. In addition, Puget Energy’s restated articles of incorporation, bylaws and shareholders rights plan contain provisions which may make it more difficult to remove incumbent directors or effect certain business combinations with Puget Energy without the approval of the Board of Directors. These provisions of law and of Puget Energy’s corporate documents, individually or in the aggregate, could discourage a future takeover attempt which individual shareholders might deem to be in their best interests or in which shareholders would receive a premium for their shares over current prices.
None.
The principal electric generating plants and underground gas storage facilities owned by PSE are described under Item 1, Business - Electric Supply and Gas Supply. PSE owns its transmission and distribution facilities and various other properties. Substantially all properties of PSE are subject to the liens of PSE’s mortgage indentures. PSE’s corporate headquarters is housed in a leased building located in Bellevue, Washington.
InfrastruX operates a fleet of vehicles and equipment that it uses in its utility construction business. Its fleet is composed of owned and leased trucks and other specialized equipment such as backhoes, trenchers, boring machines, cranes and other equipment required to perform its work. InfrastruX owns some of the facilities out of which it operates and rents the remaining facilities. The majority of InfrastruX’s owned facilities are subject to liens under existing debt and lines of credit. InfrastruX’s corporate headquarters is housed in a leased building located in Bellevue, Washington.
See the section under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations-Proceedings Relating to the Western Power Market.
Contingencies arising out of the normal course of the Company’s business exist at December 31, 2004. The ultimate resolution of these issues are not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.
None.
Puget Energy’s common stock, the only class of common equity of Puget Energy, is traded on the New York Stock Exchange under the symbol “PSD.” At February 23, 2005,21, 2007, there were approximately 40,40036,800 holders of record of Puget Energy’s common stock. The outstanding shares of PSE’s common stock, the only class of common equity of PSE, are held by Puget Energy and are not traded.
The following table shows the market price range of, and dividends paid on, Puget Energy’s common stock during the periods indicated in 20042006 and 2003.2005. Puget Energy and its predecessor companies have paid dividends on common stock each year since 1943 when such stock first became publicly held.
| | 2004 | | 2003 | 2006 | 2005 |
| | PRICE RANGE | DIVIDENDS | | PRICE RANGE | DIVIDENDS | Price Range | Dividends | Price Range | Dividends |
| QUARTER ENDED | HIGH | LOW | PAID | | HIGH | LOW | PAID | |
| Quarter Ended | | High | Low | Paid | High | Low | Paid |
| March 31 | $23.92 | | $21.59 | | $0.25 | | | $23.00 | | $18.10 | | $0.25 | | $21.68 | $20.26 | $0.25 | $24.60 | $21.30 | $0.25 |
| June 30 | 22.88 | | 20.51 | | 0.25 | | | 24.40 | | 20.78 | | 0.25 | | 21.62 | 20.13 | 0.25 | 23.56 | 20.73 | 0.25 |
| September 30 | 23.00 | | 21.05 | | 0.25 | | | 24.17 | | 21.02 | | 0.25 | | 22.86 | 21.20 | 0.25 | 24.36 | 22.05 | 0.25 |
| December 31 | 24.81 | | 22.27 | | 0.25 | | | 23.99 | | 22.14 | | 0.25 | | 25.91 | 22.72 | 0.25 | 23.70 | 20.21 | 0.25 |
The amount and payment of future dividends will depend on Puget Energy’s financial condition, results of operations, capital requirements and other factors deemed relevant by Puget Energy’s Board of Directors. The Board of Directors’ current policy is to pay out approximately 60%60.0% of normalized utility earnings in dividends.
Puget Energy’s primary source of funds for the payment of dividends to its shareholders is dividends received from PSE. PSE’s payment of common stock dividends to Puget Energy is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in PSE’s Restated Articles of Incorporation and electric and gas mortgage indentures. Under the most restrictive covenants of PSE, earnings reinvested in the business unrestricted as to payment of cash dividends were approximately $274.4$398.9 million at December 31, 2004.2006.
The following tables show selected financial data. Puget Energy became the holding company for PSE on January 1, 2001 pursuant to a plan of exchange in which each share of PSE common stock was exchanged on a one-for-one basis for Puget Energy common stock. Puget Energy results are not on a comparable basis as InfrastruX had acquisitions from 2000 to 2003.
Puget Energy Summary of Operations (Dollars in Thousands, Except per share data) |
| Years Ended December 31 | 2006 | 2005 | 2004 | 2003 1 | 2002 |
Operating revenue 2 | $ | 2,905,693 | $ | 2,573,210 | $ | 2,198,877 | $ | 2,041,016 | $ | 1,995,652 |
| Operating income | | 326,616 | | 303,163 | | 287,678 | | 297,723 | | 294,074 |
| Net income from continuing operations | | 167,224 | | 146,283 | | 125,410 | | 114,600 | | 100,597 |
| Net income | | 219,216 | | 155,726 | | 55,022 | | 116,197 | | 110,052 |
| Basic earnings per common share from continuing operations | | 1.44 | | 1.43 | | 1.26 | | 1.21 | | 1.13 |
| Basic earnings per common share | | 1.89 | | 1.52 | | 0.55 | | 1.23 | | 1.24 |
| Diluted earnings per common share from continuing operations | | 1.44 | | 1.42 | | 1.26 | | 1.20 | | 1.13 |
| Diluted earnings per common share | | 1.88 | | 1.51 | | 0.55 | | 1.22 | | 1.24 |
| Dividends per common share | $ | 1.00 | $ | 1.00 | $ | 1.00 | $ | 1.00 | $ | 1.21 |
| Book value per common share | | 18.29 | | 17.52 | | 16.24 | | 16.71 | | 16.27 |
| Total assets at year end | $ | 7,066,039 | $ | 6,609,951 | $ | 5,851,219 | $ | 5,708,724 | $ | 5,772,132 |
| Long-term debt | | 2,608,360 | | 2,183,360 | | 2,069,360 | | 1,955,347 | | 2,021,832 |
| Preferred stock subject to mandatory redemption | | 1,889 | | 1,889 | | 1,889 | | 1,889 | | 43,162 |
| Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | | -- | | -- | | -- | | -- | | 300,000 |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | 37,750 | | 237,750 | | 280,250 | | 280,250 | | -- |
Puget Energy Summary of Operations (Dollars in Thousands, Except Per Share Data) |
| Years Ended December 31 | 2004 | 20031 | 2002 | 20012 | 20003 |
Operating revenue4 | $ | 2,568,813 | $ | 2,382,803 | $ | 2,315,181 | $ | 2,886,560 | $ | 3,302,296 |
| Operating income | | 216,751 | | 305,175 | | 309,669 | | 297,121 | | 363,872 |
Net income before cumulative effect of accounting change | | 55,022 | | 116,366 | | 110,052 | | 113,175 | | 193,831 |
Net income from continuing operations5 | | 55,022 | | 116,197 | | 110,052 | | 98,426 | | 184,837 |
Basic earnings per common share from continuing operations | | 0.55 | | 1.23 | | 1.24 | | 1.14 | | 2.16 |
| Diluted earnings per common share from continuing operations | | 0.55 | | 1.22 | | 1.24 | | 1.14 | | 2.16 |
| Dividends per common share | $ | 1.00 | $ | 1.00 | $ | 1.21 | $ | 1.84 | $ | 1.84 |
| Book value per common share | | 16.25 | | 16.71 | | 16.27 | | 15.66 | | 16.61 |
| Total assets at year end | $ | 5,833,369 | $ | 5,699,002 | $ | 5,772,133 | $ | 5,668,481 | $ | 5,677,266 |
| Long-term obligations | | 2,212,532 | | 1,969,489 | | 2,160,276 | | 2,127,054 | | 2,170,797 |
| Preferred stock subject to mandatory redemption | | 1,889 | | 1,889 | | 43,162 | | 50,662 | | 58,162 |
| Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | | -- | | -- | | 300,000 | | 300,000 | | 100,000 |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | 280,250 | | 280,250 | | -- | | -- | | -- |
__________________________
1 | In 2003, FASB issued Interpretation No. 46 (FIN 46) which required the consolidation of PSE’s 1995 Conservation Trust Transaction. As a result, revenues and expenseexpenses increased $5.7 million with no effect on net income, and assets and liabilities increased $4.2 million in 2003. FIN 46 also required deconsolidation of PSE’s trust preferred securities that are now classified as junior subordinated debt. This deconsolidation has no impact on assets, liabilities, receivables or earnings for 2003. |
2 | In 2001, SFAS No. 133 was implemented, which required derivative instruments to be valued at fair price.2
|
3 | Amounts represent PSE activity prior to the formation of Puget Energy as a holding company of PSE on January 1, 2001.
|
4 | Operating Electric Revenues and Purchased Electricity expenses in 2003 and 2002 were revised as a result of implementing Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective on January 1, 2004. Operating Electric Revenues and Purchased Electricity expense for Puget Energy and Puget Sound Energy were reduced by $108.7 million and $77.1 million in 2003 and 2002, respectively, with no effect on net income. Information for 2001 and 2000 is not available, and therefore revenue and expense were not adjusted for the effects of EITF No. 03-11 in those years. |
Puget Sound Energy Summary of Operations (Dollars in Thousands) |
| Years Ended December 31 | 2006 | 2005 | 2004 | 20031 | 2002 |
Operating revenue 2 | $ | 2,905,693 | $ | 2,573,210 | $ | 2,198,877 | $ | 2,041,016 | $ | 1,995,652 |
| Operating income | | 327,490 | | 303,496 | | 288,241 | | 297,904 | | 294,593 |
| Net income for common stock | | 176,740 | | 146,769 | | 126,192 | | 114,735 | | 101,117 |
| Total assets at year end | $ | 7,061,413 | $ | 6,339,800 | $ | 5,579,756 | $ | 5,359,104 | $ | 5,453,390 |
| Long-term debt | | 2,608,360 | | 2,183,360 | | 2,064,360 | | 1,950,347 | | 2,021,832 |
| Preferred stock subject to mandatory redemption | | 1,889 | | 1,889 | | 1,889 | | 1,889 | | 43,162 |
| Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | | -- | | -- | | -- | | -- | | 300,000 |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | 37,750 | | 237,750 | | 280,250 | | 280,250 | | -- |
_______________
5 1 | Net income in 2000 includes preferred stock dividend accrual at PSE, which is treated as an other deduction at Puget Energy starting JanuarySee note 1 2001.above.
|
2 | See note 2 above. |
Puget Sound Energy Summary of Operations (Dollars in Thousands) |
| Years Ended December 31 | 2004 | 20031 | 2002 | 20012 | 2000 |
Operating revenue3 | $ | 2,198,877 | $ | 2,041,016 | $ | 1,995,652 | $ | 2,712,774 | $ | 3,302,296 |
| Operating income | | 288,241 | | 297,904 | | 294,593 | | 288,480 | | 363,8872 |
Net income before cumulative effect of accounting change | | 126,192 | | 120,055 | | 108,948 | | 119,130 | | 193,831 |
Income for common stock from continuing operations | | 126,192 | | 114,735 | | 101,117 | | 95,968 | | 184,837 |
| Total assets at year end | $ | 5,564,087 | $ | 5,359,104 | $ | 5,453,390 | $ | 5,439,253 | $ | 5,677,266 |
| Long-term obligations | | 2,064,360 | | 1,950,347 | | 2,021,832 | | 2,053,815 | | 2,170,797 |
| Preferred stock subject to mandatory redemption | | 1,889 | | 1,889 | | 43,162 | | 50,662 | | 58,162 |
Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | | -- | | -- | | 300,000 | | 300,000 | | 100,000 |
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | 280,250 | | 280,250 | | -- | | -- | | -- |
__________________________
1 | In 2003, FASB issued Interpretation No. 46 (FIN 46) which required the consolidation of PSE’s 1995 Conservation Trust Transaction. As a result, revenues and expense increased $5.7 million with no effect on net income, and assets and liabilities increased $4.2 million in 2003. FIN 46 also required deconsolidation of PSE’s trust preferred securities that are now classified as junior subordinated debt. This deconsolidation has no impact on assets, liabilities, receivables or earnings for 2003.
|
2 | In 2001, SFAS No. 133 was implemented, which required derivative instruments to be valued at fair price.
|
3 | Operating Electric Revenues and Purchased Electricity Expenses in 2003 and 2002 were revised as a result of implementing Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective on January 1, 2004. Operating Electric revenues and Purchased Electricity expense for Puget Energy and Puget Sound Energy were reduced by $108.7 million and $77.1 million in 2003 and 2002, respectively, with no effect on net income. Information for 2001 and 2000 is not available, and therefore revenue and expense were not adjusted for the effects of EITF No. 03-11 in those years.
|
CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this annual report on Form 10-K. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy’s and Puget Sound Energy’s (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “ plans,” “predicts,” “projects,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy’s and PSE’s actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report. Except as required by law, neither Puget Energy nor PSE undertakes an obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed with the United States Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect Puget Energy’s and PSE’s business, prospects and results of operations.
OVERVIEW
Puget Energy, Inc. (Puget Energy) is an energy services holding company and all of its operations are conducted through its two subsidiaries. These subsidiaries are PSE,subsidiary Puget Sound Energy (PSE), a regulated electric and gas utility company, andcompany. Puget Energy owned a 90.9% interest in InfrastruX, a utility construction and services company. On February 8, 2005, following a strategic reviewcompany, until it was sold to an affiliate of InfrastruX, Puget Energy’s BoardTenaska Power Fund, L.P. (Tenaska) on May 7, 2006. After repayment of Directors decideddebt, adjustments for working capital, transaction costs and distributions to exit the utility construction services sector.minority interests, Puget Energy intends to monetizereceived $95.9 million for its 90.9% interest in InfrastruX in the second quarter 2006. The sale resulted in an after-tax gain of $29.8 million for the twelve months ended December 31, 2006. The $95.9 million net proceeds Puget Energy received from the sale of InfrastruX were used to support PSE through an equity contribution of $65.0 million and a loan of $24.3 million. In addition, Puget Energy established a charitable foundation, Puget Sound Energy Foundation, in the second quarter 2006 with a contribution of $15.0 million from the net proceeds from the sale or recapitalizationof InfrastruX along with investment income of $0.4 million on the cash proceeds and to investa federal income tax benefit of $5.3 million from funding the proceeds of such monetization in its regulated utility subsidiary, PSE.Puget Sound Energy Foundation.
PUGET SOUND ENERGYPuget Sound Energy
PSE generates revenues from the sale of electric and gas services, mainly to residential and commercial customers within Washington State. A majorityPSE’s operating revenues and associated expenses are not generated evenly during the year. Variations in energy usage by consumers occur from season to season and from month to month within a season, primarily as a result of PSE’s revenues are generatedweather conditions. PSE normally experiences its highest retail energy sales and subsequently higher power costs during the winter heating season in the first and fourth quarters duringof the winter heating seasonyear and its lowest sales in Washington State.the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult.
As a regulated utility company, PSE is subject to Federal Energy Regulatory Commission (FERC) and Washington Utilities and Transportation Commission (Washington Commission) regulation which may impact a large array of business activities, including limitation of future rate increases; directed accounting requirements that may negatively impact earnings; licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent to the utility industry as a whole, including weather changes affecting purchases and sales of energy; outages at owned and non-owned generation plants where energy is obtained; storms or other events which can damage gas and electric distribution and transmission lines; and energy trading and wholesale market stability over time.time and significant evolving environmental legislation.
PSE’s main operational goal has beenobjective is to provide reliable, safe and cost-effective energy to its customers. To help accomplish this goal,objective, PSE is attemptingimplementing a strategy to be more self-sufficient in energy generation resources. Owning more generation resources rather than purchasing power through contracts and on the wholesale market is intended to allow customers’ rates to remain stable. PSE is continually exploring new electric-power resource generation and long-term purchase power agreements to meet this goal. During 2004, PSE made progressThe completion of the Hopkins Ridge wind project in 2005 and the Wild Horse wind project in December 2006 are two steps in reaching this goal:
goal. The Hopkins Ridge wind project provides a rated capacity of 150 megawatts (MW) or 52 average MW. The Wild Horse wind project provides a rated capacity of 229 MW or 73 average MW. These projects are considered to be non-firm energy due to the reliance on wind to produce the energy.
· | Purchased a 49.85% interest in a 250 MW capacity gas-fired generation facility in western Washington, which went into service in April 2004. |
· | Signed a two-year purchase power agreement in the second quarter 2004 with another utility for 85 MW of energy with delivery beginning January 1, 2005. |
· | Signed a non-binding letter of intent in September 2004 to purchase a wind generation facility with up to 230 MW of generation to be developed in central Washington State. |
· | Signed a non-binding letter of intent in October 2004 to purchase a wind generation facility with up to 150 MW of generation to be developed in eastern Washington State. |
These transactionsThe Hopkins Ridge wind project and proposed transactions arethe Wild Horse wind project were included as part of PSE’s energy resource portfolio in its long-term electric Least Cost PlanIRP that was filed August 29, 2003May 2, 2005 with the Washington Commission. The plan supports a strategy of diverse resource acquisitions including resources fueled by natural gas and coal, renewable resources and shared resources.PSE isresources. The IRP was followed by issuing an all-source request for proposal (RFP) on November 1, 2005.
In addition, on February 21, 2007, PSE acquired the Goldendale Generating Station, a 277 MW capacity natural gas generating facility in the processstate of updatingWashington, from the Calpine Corporation through its Least Cost Planbankruptcy proceeding. PSE paid $120.0 million for the generating facility.
In August 2006, PSE announced the selection of seven projects for further discussion and expects to filepossible negotiation as a result of the updated plan with the Washington Commission2005 RFP process. In aggregate, these outside sources, if completed, would generate approximately 1,100 MW of long-term power supply in the first halftotal. The outcome of 2005.such discussion and negotiation are not known at this time.
INFRASTRUXNON-GAAP FINANCIAL MEASURES
FollowingThe following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as two other financial measures, Electric Margin and Gas Margin, that are considered “non-GAAP financial measures.” Generally, a strategic reviewnon-GAAP financial measure is a numerical measure of InfrastruX conducteda Company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of Electric Margin and Gas Margin is intended to supplement investors’ understanding of the Company’s operating performance. Electric Margin and Gas Margin are used by Puget Energy management, on February 8, 2005, Puget Energy’s Boardthe Company to determine whether the Company is collecting the appropriate amount of Directors decidedenergy costs from its customers to exit the utility construction services sector. During 2005, Puget Energy intends to monetize its interest in InfrastruX through a sale or third party recapitalizationallow recovery of operating costs. Our Electric Margin and to invest the proceeds in PSE. The costs associated with exiting the InfrastruX business cannot be quantified at this time. However, Puget Energy believes that such costs willGas Margin measures may not be material given the effectscomparable to other companies’ Electric Margin and Gas Margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of the impairment charge recorded in the fourth quarter 2004.
InfrastruX generates revenues mainly from maintenance services and construction contracts in the Midwest, Texas, south-central and eastern United States. Generally, the majority of its revenues are generated during the second and third quarters, which are typically the most productive quarters for the construction industry due to longer daylight hours and generally better weather conditions.
InfrastruX is subject to risks associated with the construction industry, including inability to adequately estimate costs of projects that are bid on under fixed-fee contracts; continued economic downturn that limits the amount of projects available thereby reducing available profit margins due to increased competition; the ability to integrate acquired companies within its operations without significant cost; and the ability to obtain adequate financing and bonding coverage to continue expansion and growth.
InfrastruX’s main goals have been continued growth and expansion into underdeveloped utility construction markets and to utilize its acquired entities to capitalize on depth of expertise, asset base, geographical location and workforce to provide services that local contractors cannot provide. InfrastruX has acquired 12 entities since 2000.operating performance.
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PUGET ENERGYPuget Energy
All the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX.subsidiary PSE. Net income in 20042006 was $219.2 million on operating revenues from continuing operations of $2.9 billion compared to $155.7 million on operating revenues from continuing operations of $2.6 billion in 2005 and $55.0 million on operating revenues from continuing operations of $2.6$2.2 billion in 2004. Income from continuing operations in 2006 was $167.2 million compared to $116.2$146.3 million on operating revenues of $2.4 billion in 20032005 and $110.1$125.4 million on operating revenues of $2.3 billion in 2002.2004.
Basic earnings per share in 2004 were2006 was $1.89 on 116.0 million weighted average common shares outstanding compared to $1.52 on 102.6 million weighted average common shares outstanding in 2005 and $0.55 on 99.5 million weighted average common shares outstanding in 2004. Diluted earnings per share in 2006 was $1.88 on 116.5 million weighted average common shares outstanding compared to $1.23$1.51 on 94.8103.1 million weighted average common shares outstanding in 20032005 and $1.24 on 88.4 million weighted average common shares outstanding in 2002. Diluted earnings per share in 2004 were $0.55 on 99.9 million weighted average common shares outstanding in 2004. Included in basic earnings per share for 2006 was $0.45 compared to $1.22 on 95.3$0.09 and $(0.71) for 2005 and 2004, respectively, related to discontinued operations. Included in diluted earnings per share for 2006 was $0.45 compared to $0.09 and $(0.71) for 2005 and 2004, respectively, related to discontinued operations.
Income from continuing operations excluding the impact of the charitable contribution to the Puget Sound Energy Foundation was $177.0 million weighted average common shares outstanding in 2003for 2006. Management of the Company believes it is useful to present income from continuing operations and $1.24 on 88.8 million weighted average common shares outstanding in 2002.diluted earnings excluding the impact of the charitable contribution because it represents a more accurate measure of operating performance and facilitates period-to-period comparisons. Basic and diluted earnings per share from continuing operations were $1.52 for the twelve months ended December 31, 2006, excluding the impact of the charitable contribution to the Puget Sound Energy Foundation. A reconciliation to amounts under GAAP is as follows:
(Dollars in millions, except per share amounts) | | Twelve Months Ended December 31, 2006 |
| Income from continuing operations, as reported | | $ | 167.2 |
| Add: Impact of charitable contribution to Foundation, net of tax | | | 9.8 |
| Income from continuing operations, excluding charitable contribution | | $ | 177.0 |
| Earnings per share: | | | |
| Basic and diluted earnings per share before cumulative effect of accounting change from continuing operations, as reported | | $ | 1.44 |
| Add: Impact of charitable contribution to Foundation | | | 0.08 |
| Basic and diluted earnings per share before cumulative effect of accounting change from continuing operations, excluding charitable contribution | | $ | 1.52 |
Net income in 2004 was adversely impacted by an2006 benefited from income from discontinued operations of InfrastruX non-cash goodwill impairment charge of $91.2$51.9 million ($76.6(after-tax) compared to $9.5 million after(after-tax) for 2005. Puget Energy’s income from discontinued operations for 2006 includes $7.3 million related to the reversal of a carrying value adjustment recorded in 2005 as well as $10.0 million related to the anticipated realization of a deferred tax and minority interest) and a $43.4 million ($28.2 million after-tax) disallowanceasset associated with the sale of the return onbusiness. Natural gas and electric margins increased by $22.6 million and $46.0 million, respectively, for 2006 compared to 2005, which positively impacted net income. The increase in natural gas margins resulted from increased natural gas general tariff rates and increased sales volumes. The increase in electric margins was the Tenaska gas supply regulatory asset as a result of a Washington Commission order in PSE’s Power Cost Only Rate Caseincreased sales volumes, overrecovery of power costs under the power cost adjustment (PCA) mechanism and two power cost only rate case (PCORC). Net income was also negatively impacted by an increase in depreciation expense of $10.0 million, primarily due to the acquisition of Frederickson rate increases effective November 1, 2005 and other PSE infrastructure projects. These negative impacts were offset by improved electric margins of $5.9 million compared to 2003 and lower interest expense at PSE of $13.0 million. In addition, 2004 was not impacted by one-time tax benefits of $7.9 million or the write-down of $6.1 million in the carrying value of a non-utility venture capital investment in 2003.July 1, 2006. Net income in 2004 was positively impacted by a $4.3 million increase in InfrastruX’s net income, excluding the goodwill impairment charge and net of minority interest. The net income increase at InfrastruX was due to improved operating efficiencies and improvements in weather conditions compared to 2003, which positively impacted productivity.
Net income in 20032005 was positively impacted by an increase in PSE’s net income from continuing operations of $10.9$20.6 million due to increased electric and gas margins primarily from a general gas rate increase effective September 1, 2002 and from increased sales volumes for electric and gas loads compared to 2002. In addition, net income in 2003 was positively impacted by lower interest expenses of $11.5$73.4 million. This increase was offset by a $6.1 million downward adjustment in the carrying value of a non-utility venture capital investment in the fourth quarter 2003; a $4.8 million increase in depreciation and amortization; and an $11.7 million decrease in gains on derivative instruments due primarily to a 2002 gain from de-designated contracts from a non-creditworthy counterparty under Statementhigher Tenaska disallowance in 2004 of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In addition, federal tax benefits decreased in 2003 to $9.3$43.4 million compared to $10.3$4.1 million in 2002. Net2005. Increased electricity and gas sales volumes increased margin by $24.5 million as compared to 2004. Gas margin also increased $17.3 million as a result of the 2005 gas general rate case. Offsetting the increases were higher operations and maintenance costs of $42.1 million and depreciation and amortization of $13.0 million. In addition, income was also negatively impacted by a decrease in InfrastruX’s net income of $7.7from discontinued operations increased $79.9 million in 20032005 compared to 2002, net of minority interest,2004 primarily due to unusually wet weather affecting productivitylower non-cash impairments and favorable industry conditions in the first quarter 2003 and increased competition in the marketplace.utility construction services sector.
PUGET SOUND ENERGY
PSE’s operating revenues and associated expenses are not generated evenly during the year. Variations in energy usage by consumers occur from season to season and from month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales during the heating season in the first and fourth quarters of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult.
PUGET SOUND ENERGYPuget Sound Energy
2004 COMPARED TO 20032006 compared to 2005
ENERGY MARGINSEnergy Margins
| The following table displays the details of electric margin changes from 2003 to 2004. |
| | | ELECTRIC MARGIN | |
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | CHANGE | | PERCENT CHANGE | |
| Electric retail sales revenue | | $ | 1,310.9 | | $ | 1,272.7 | | $ | 38.2 | | | 3.0 | % |
| Electric transportation revenue | | | 10.7 | | | 11.5 | | | (0.8 | ) | | (7.0 | ) |
| Other electric revenue-gas supply resale | | | 11.5 | | | 9.1 | | | 2.4 | | | 26.4 | |
| Total electric revenue for margin | | | 1,333.1 | | | 1,293.3 | | | 39.8 | | | 3.1 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (25.4 | ) | | (45.2 | ) | | 19.8 | | | 43.8 | |
| Pass-through revenue-sensitive taxes | | | (94.2 | ) | | (91.0 | ) | | (3.2 | ) | | (3.5 | ) |
| Residential exchange credit | | | 174.5 | | | 173.8 | | | 0.7 | | | 0.4 | |
| Net electric revenue for margin | | | 1,388.0 | | | 1,330.9 | | | 57.1 | | | 4.3 | |
| Minus power costs: | | | | | | | | | | | | | |
| Fuel | | | (80.7 | ) | | (65.0 | ) | | (15.7 | ) | | (24.2 | ) |
| Purchased electricity, net of sales to other utilities and marketers | | | (660.3 | ) | | (635.2 | ) | | (25.1 | ) | | (4.0 | ) |
| Total electric power costs | | | (741.0 | ) | | (700.2 | ) | | (40.8 | ) | | (5.8 | ) |
| Electric margin before PCA | | | 647.0 | | | 630.7 | | | 16.3 | | | 2.6 | |
| Tenaska disallowance reserve through May 23, 2004 | | | (36.5 | ) | | -- | | | (36.5 | ) | | * | |
| Tenaska reserve turnaround | | | 10.5 | | | -- | | | 10.5 | | | * | |
| Power cost deferred under the PCA mechanism | | | 19.1 | | | 3.5 | | | 15.6 | | | * | |
| Electric margin | | $ | 640.1 | | $ | 634.2 | | $ | 5.9 | | | 0.9 | % |
* Percent change not applicable.
Electric margin increased $5.9 million in 2004 compared to 2003 due primarily to an increase in kWh sales and the PCORC rate increase. PSE incurred $34.8 million in excess power costs in 2003 before reaching the $40 million PCA mechanism cap in 2003. In addition, the PCORC rate increase of 3.2% related to the Frederickson 1 generating facility became effective on May 24, 2004. This rate increase provided an additional $6.5 million to electric margin in 2004 to recover utility operation and maintenance costs, depreciation and property taxes related to the Frederickson 1 generating facility. Also, retail customer kWh sales (residential, commercial and industrial customers) increased 1.5% in 2004 compared to 2003, which along with a change in customer class usage provided an additional $11.7 million to electric margin. These increases were partially offset by the disallowance of certain gas costs for the Tenaska generating facility also ordered in the PCORC, which resulted in a $43.4 million reduction of electric margin in 2004. In addition, a charge of $3.6 million associated with Colstrip Units 1 & 2 coal supply repricing arbitration and Colstrip Units 3 & 4 royalty charge resulted in a negative impactchanges from 2005 to electric margin.2006. Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.
| | | Electric Margin | |
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
Electric operating revenue1 | | $ | 1,777.7 | | $ | 1,612.9 | | $ | 164.8 | | | 10.2 | % |
| Less: Other electric operating revenue | | | (51.8 | ) | | (62.5 | ) | | 10.7 | | | 17.1 | |
| Add: Other electric operating revenue - gas supply resale | | | 16.4 | | | 26.1 | | | (9.7 | ) | | (37.2 | ) |
| Total electric revenue for margin | | | 1,742.3 | | | 1,576.5 | | | 165.8 | | | 10.5 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (35.9 | ) | | (26.9 | ) | | (9.0 | ) | | (33.5 | ) |
| Pass-through revenue-sensitive taxes | | | (117.4 | ) | | (104.9 | ) | | (12.5 | ) | | (11.9 | ) |
| Net electric revenue for margin | | | 1,589.0 | | | 1,444.7 | | | 144.3 | | | 10.0 | |
| Minus power costs: | | | | | | | | | | | | | |
Purchased electricity1 | | | (917.8 | ) | | (860.4 | ) | | (57.4 | ) | | (6.7 | ) |
Electric generation fuel1 | | | (97.3 | ) | | (73.3 | ) | | (24.0 | ) | | (32.7 | ) |
Residential exchange1 | | | 163.6 | | | 180.5 | | | (16.9 | ) | | (9.4 | ) |
| Total electric power costs | | | (851.5 | ) | | (753.2 | ) | | (98.3 | ) | | (13.1 | ) |
Electric margin2 | | $ | 737.5 | | $ | 691.5 | | $ | 46.0 | | | 6.7 | % |
_______________
1 | As reported on PSE’s Consolidated Statement of Income. |
2 | Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense. |
Electric margin increased $46.0 million in 2006 compared to 2005 primarily due to the effects of the general rate case rate increase effective March 4, 2005 and the PCORC rate increases effective November 1, 2005 and July 1, 2006 which increased margin by $27.5 million. Retail customer kilowatt hour (kWh) sales (residential, commercial and industrial customers) increased 3.1% in 2006 compared to 2005, which provided $21.8 million to electric margin. Electric margin also increased by $12.9 million due to overrecovery of excess power cost under the PCA mechanism. Electric margin increased by $1.2 million due to the reduction of the Tenaska disallowance in the PCA mechanism. These increases were partially offset by a $11.2 million decrease related to production tax credits (PTCs) provided to customers through tariff rates, which are trued-up to actual PTCs taken in an annual true-up process and the non-recurring benefit of a February 23, 2005 Washington Commission order allowing recovery of power costs that lowered electric margin by $6.0 million.
The following table displays the details of gas margin changes from 20032005 to 2004.
| | | GAS MARGIN | |
(DOLLARS IN MILLION) TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | CHANGE | | PERCENT CHANGE | |
| Gas retail revenue | | $ | 743.6 | | $ | 609.6 | | $ | 134.0 | | | 22.0 | % |
| Gas transportation revenue | | | 13.0 | | | 13.8 | | | (0.8 | ) | | (5.8 | ) |
| Total gas revenue for margin | | | 756.6 | | | 623.4 | | | 133.2 | | | 21.4 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Gas revenue hedge | | | -- | | | 0.2 | | | (0.2 | ) | | * | |
| Pass-through tariff items | | | (3.6 | ) | | (3.8 | ) | | 0.2 | | | 5.3 | |
| Pass-through revenue-sensitive taxes | | | (59.3 | ) | | (48.5 | ) | | (10.8 | ) | | (22.3 | ) |
| Net gas revenue for margin | | | 693.7 | | | 571.3 | | | 122.4 | | | 21.4 | |
| Minus purchased gas costs | | | (451.3 | ) | | (327.1 | ) | | (124.2 | ) | | (38.0 | ) |
| Gas margin | | $ | 242.4 | | $ | 244.2 | | $ | (1.8 | ) | | (0.7 | )% |
* Percent change not applicable.
Gas margin decreased $1.8 million in 2004 compared to 2003 primarily due to overall warmer weather in 2004 compared to 2003, partially offset by customer additions in 2004. Heating degree days decreased 2.3% in 2004 compared to 2003, which resulted in a 1.5% reduction in therm sales.2006. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.
| | | Gas Margin | |
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
Gas operating revenue1 | | $ | 1,120.1 | | $ | 952.5 | | $ | 167.6 | | | 17.6 | % |
| Less: Other gas operating revenue | | | (16.5 | ) | | (17.2 | ) | | 0.7 | | | 4.1 | |
| Total gas revenue for margin | | | 1,103.6 | | | 935.3 | | | 168.3 | | | 18.0 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (7.1 | ) | | (5.7 | ) | | (1.4 | ) | | (24.6 | ) |
| Pass-through revenue-sensitive taxes | | | (86.3 | ) | | (73.1 | ) | | (13.2 | ) | | (18.1 | ) |
| Net gas revenue for margin | | | 1,010.2 | | | 856.5 | | | 153.7 | | | 17.9 | |
Minus purchased gas costs1 | | | (723.2 | ) | | (592.1 | ) | | (131.1 | ) | | (22.1 | ) |
Gas margin2 | | $ | 287.0 | | $ | 264.4 | | $ | 22.6 | | | 8.5 | % |
_______________1 | As reported on PSE’s Consolidated Statement of Income. |
2 | Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense. |
Gas margin increased $22.6 million in 2006 compared to 2005. Gas margin increased $12.6 million due to a 4.7% increase in gas therm volume sales; $7.0 million of the increase was a result of the gas general tariff rate case which was effective March 4, 2005. These increases were partially offset by a $1.5 million decrease in margin related to customer mix and pricing.
ELECTRIC OPERATING REVENUESElectric Operating Revenues
The table below sets forth changes in electric operating revenues for PSE from 20032005 to 2004.2006.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | CHANGE | | PERCENT CHANGE | | |
(Dollars in Millions) Twelve Months Ended December 31 | | | 2006 | | 2005 | | Change | | Percent Change | |
| Electric operating revenues: | | | | | | | | | | | | | | | | | | |
| Residential sales | | $ | 628.9 | | $ | 603.7 | | $ | 25.2 | | | 4.2 | % | | $ | 788.2 | | $ | 690.2 | | $ | 98.0 | | | 14.2 | % |
| Commercial sales | | | 581.0 | | | 556.0 | | | 25.0 | | | 4.5 | | | | 702.8 | | | 629.0 | | | 73.8 | | | 11.7 | |
| Industrial sales | | | 88.8 | | | 88.2 | | | 0.6 | | | 0.7 | | | | 103.0 | | | 93.9 | | | 9.1 | | | 9.7 | |
| Other retail sales, including unbilled revenue | | | | 35.4 | | | 23.3 | | | 12.1 | | | 51.9 | |
| Total retail sales | | | | 1,629.4 | | | 1,436.4 | | | 193.0 | | | 13.4 | |
| Transportation sales | | | 10.7 | | | 11.5 | | | (0.8 | ) | | (7.0 | ) | | | 11.5 | | | 9.0 | | | 2.5 | | | 27.8 | |
| Sales to other utilities and marketers | | | 56.5 | | | 82.8 | | | (26.3 | ) | | (31.8 | ) | | | 85.0 | | | 105.0 | | | (20.0 | ) | | (19.0 | ) |
| Other | | | 57.1 | | | 58.5 | | | (1.4 | ) | | (2.4 | ) | | | 51.8 | | | 62.5 | | | (10.7 | ) | | (17.1 | ) |
| Total electric operating revenues | | $ | 1,423.0 | | $ | 1,400.7 | | $ | 22.3 | | | 1.6 | % | | $ | 1,777.7 | | $ | 1,612.9 | | $ | 164.8 | | | 10.2 | % |
Electric retail sales increased $193.0 million for 2006 compared to 2005 due primarily to rate increases related to the PCORC and the electric general rate case and increased retail customer usage. The PCORC and electric general rate case provided a combined additional $68.7 million to electric operating revenues increased $22.3 million in 2004for 2006 compared to 2003 due to increases in residential and commercial customer usage and the effect of the PCORC rate increase. Residential and commercial2005. Retail electricity usage increased 182,296626,207 MWh or 1.9% and 227,400 MWh or 2.8%, respectively, from 2003.3.1% for 2006 compared to 2005. The increase in electricity usage was mainly the result of a 1.6% higher average number of customers served in 20042006 compared to 2003. Average customers for the residential and commercial customer classes increased 2.4% and 1.1%, respectively, from 2003. In addition, the PCORC rate increase became effective on May 24, 2004 and provided a $24.5 million increase in electric operating revenue, net of a $5.8 million rate reduction due to the Tenaska disallowance.
Sales to other utilities and marketers decreased $26.3 million from 2003 primarily due to higher retail electric sales, which reduced excess generation for sale to the wholesale market. In 2003, warmer than normal temperatures, mainly in the first quarter, and improved hydroelectric conditions as compared to the original hydroelectric forecast provided excess energy supplies for sale to the wholesale market.2005.
During 2004,2006, the benefits of the Residential and Small Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $182.6$171.3 million compared to $181.9$189.0 million in 2003.for 2005. This credit also reducesreduced power costs by a corresponding amount with no impact on earnings. See Item 1, Business - Regulation
Transportation sales increased $2.5 million for 2006 compared to 2005 due to an increase in sales volume of 61,524 MWh or 3.0%.
Sales to other utilities and Rates - Residential and Small Farm Exchange Benefit Credit for further discussion.
During 2003, PSE collected in its electric general rate tariff as a reductionmarketers decreased $20.0 million compared to revenue and remitted2005 due primarily to a grantor trust $7.7 million. This was a resultdecrease in the wholesale market price of PSE’s 1995 saleelectricity in 2006 as compared to 2005 offset by an increase of future180,842 MWh in 2006 from 2005.
Other electric revenues decreased $10.7 million in 2006 compared to 2005, primarily associated with its investmentnatural gas purchased for electric generation needs that was subsequently sold rather than used by PSE or gains from electric generation financial derivatives on gas sold. The following electric rate changes were approved by the Washington Commission in conservation assets. The impact of the 1995 sale of revenue was offset by reductions in conservation amortization2007, 2006 and interest expense. PSE’s 1995 conservation trust transaction was consolidated in the third quarter 2003 to meet the guidance of Financial Accounting Standards Board (FASB) Interpretation No. 46 (FIN 46) and, as a result, revenues increased $5.7 million in 2004 while conservation amortization and interest expense increased by a corresponding amount with no impact on earnings. The 1995 conservation trust assets were fully satisfied during September 2004.2005:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| Electric General Rate Case | March 4, 2005 | 4.1 | % | $ 57.7 |
| Power Cost Only Rate Case | November 1, 2005 | 3.7 | % | 55.6 |
| Power Cost Only Rate Case | July 1, 2006 | 5.9 | % | 45.3 1 |
| Electric General Rate Case | January 13, 2007 | (1.3 | )% | (22.8) |
_______________
1 | The rate increase is for the period July 1, 2006 through December 31, 2006. The annualized basis of the PCORC rate increase is $96.1 million. |
GAS OPERATING REVENUESGas Operating Revenues
The table below sets forth changes in gas operating revenues for PSE from 20032005 to 2004.2006.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | CHANGE | | PERCENT CHANGE | | |
(Dollars in Millions) Twelve Months Ended December 31 | | | 2006 | | 2005 | | Change | | Percent Change | |
| Gas operating revenues: | | | | | | | | | | | | | | | | | | |
| Residential sales | | $ | 479.0 | | $ | 401.7 | | $ | 77.3 | | | 19.2 | % | | $ | 697.6 | | $ | 592.4 | | $ | 105.2 | | | 17.8 | % |
| Commercial sales | | | 225.8 | | | 178.2 | | | 47.6 | | | 26.7 | | | | 335.7 | | | 281.3 | | | 54.4 | | | 19.3 | |
| Industrial sales | | | 38.8 | | | 29.7 | | | 9.1 | | | 30.6 | | | | 57.1 | | | 48.3 | | | 8.8 | | | 18.2 | |
| Total retail sales | | | | 1,090.4 | | | 922.0 | | | 168.4 | | | 18.3 | |
| Transportation sales | | | 13.0 | | | 13.8 | | | (0.8 | ) | | (5.8 | ) | | | 13.3 | | | 13.3 | | | -- | | | 0.0 | |
| Other | | | 12.7 | | | 10.8 | | | 1.9 | | | 17.6 | | | | 16.4 | | | 17.2 | | | (0.8 | ) | | (4.7 | ) |
| Total gas operating revenues | | $ | 769.3 | | $ | 634.2 | | $ | 135.1 | | | 21.3 | % | | $ | 1,120.1 | | $ | 952.5 | | $ | 167.6 | | | 17.6 | % |
Gas operating revenuesretail sales increased $135.1$168.4 million or 21.3% in 2004for 2006 compared to 20032005 due primarily to higher Purchased Gas Adjustmentpurchased gas adjustment (PGA) mechanism rates in 2004.2006, approval of a 3.5% gas general rate increase effective March 4, 2005 and higher retail customer gas usage. The PGA mechanism rate charged to customers has increased twice since April 2003 reflecting the higher cost of natural gas provided to customers. On September 24, 2003, the Washington Commission approved a PGA mechanism rate increase of 13.3% annually across all classes of customers effective October 1, 2003.2005 that provided $113.2 million in gas revenues for 2006 compared to 2005. In addition, the gas general rate case increase provided an additional $7.0 million in gas operating revenues for 2006 compared to in 2005. The remaining increase in gas retail revenues was primarily due to an increase in customers of 3.0% and higher gas sales of 48.4 million therms or $43.8 million for 2006 compared to 2005.
The following gas rate changes were approved by the Washington Commission in 2007, 2006 and 2005:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| Gas General Rate Case | March 4, 2005 | 3.5 | % | $ 26.3 |
| Purchased Gas Adjustment | October 1, 2005 | 14.7 | % | 121.6 |
| Purchased Gas Adjustment | October 1, 2006 | 10.2 | % | 95.1 |
| Gas General Rate Case | January 13, 2007 | 2.8 | % | 29.5 |
Operating Expenses
The table below sets forth significant changes in operating expenses for PSE from 2005 to 2006.
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
| Purchased electricity | | $ | 917.8 | | $ | 860.4 | | $ | 57.4 | | | 6.7 | % |
| Electric generation fuel | | | 97.3 | | | 73.3 | | | 24.0 | | | 32.7 | |
| Residential exchange | | | (163.6 | ) | | (180.5 | ) | | 16.9 | | | 9.4 | |
| Purchased gas | | | 723.2 | | | 592.1 | | | 131.1 | | | 22.1 | |
| Utility operations and maintenance | | | 354.6 | | | 333.3 | | | 21.3 | | | 6.4 | |
| Depreciation and amortization | | | 262.3 | | | 241.6 | | | 20.7 | | | 8.6 | |
| Conservation amortization | | | 32.3 | | | 24.3 | | | 8.0 | | | 32.9 | |
| Taxes other than income taxes | | | 255.7 | | | 233.7 | | | 22.0 | | | 9.4 | |
| Income taxes | | | 97.2 | | | 89.6 | | | 7.6 | | | 8.5 | |
Purchased electricity expenses increased $57.4 million in 2006 compared to 2005 primarily due to a 3.1% increase in retail customer sales volumes and a 9.6% increase in wholesale sales volumes. Total purchased power for 2006 increased 904,560 MWh, or a 5.4% increase over 2005. Increase in the purchased power volumes offset by slightly lower wholesale prices caused an increase of $19.2 million in 2006. The increase in costs also reflected the recovery of previously deferred excess power costs of $12.7 million due to lower power costs in 2006 than the baseline PCA mechanism rate as compared to a deferral of excess power costs of $15.7 million in 2005. Also contributing to the increase in costs was a Washington Commission order that allowed PSE to reflect additional power costs totaling $6.0 million during the PCA 2 period of July 1, 2003 through December 31, 2003, in 2005. In addition, transmission and other expenses increased $5.0 million due in part to increased kWh sales to customers.
PSE’s hydroelectric production and related power costs in 2006 were positively impacted by above-normal precipitation and snow pack in the Pacific Northwest region, which resulted in the runoff above Grand Coulee Reservoir to be 106.0% of normal as compared to a below normal runoff of 88.0% in 2005. The January Early Bird Columbia Basin Runoff Forecast published by the National Weather Service Northwest River Forecast Center indicated that the total forecasted runoff above Grand Coulee Reservoir for the period January through July 2007 would be near historical averages.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric capacity and energy and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales and through other risk management techniques.
Electric generation fuel expense increased $24.0 million in 2006 compared to 2005 primarily due to an increase of $17.4 million in the cost of fuel at PSE-controlled combustion turbine generating facilities due to higher costs of natural gas offset by slightly lower volumes of electricity generated and an increase in the cost of coal at Colstrip generating facilities of $6.6 million compared to 2005.
Residential exchange credits associated with the Residential Purchase and Sale Agreement with the Bonneville Power Association (BPA) decreased $16.9 million in 2006 compared to 2005 as a result of lower residential and small farm customer electric rates. The residential exchange credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on electric margin or net income. Effective October 1, 2006, the annual payment PSE receives from BPA decreased to $105.5 million for the period through September 30, 2007. This will have no impact on PSE’s earnings as this payment is passed through to customers through a lower residential exchange tariff credit.
Purchased gas expenses increased $131.1 million in 2006 compared to 2005 primarily due to an increase in PGA rates as approved by the Washington Commission and higher customer therm sales. The PGA mechanism allows PSE to recover expected gas costs, and defer, as a receivable or liability, any gas costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism receivable balance at December 31, 2006 and December 31, 2005 was $39.8 million and $67.3 million, respectively. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable balances. A receivable balance in the PGA mechanism reflects a current underrecovery of market gas cost through rates. For further discussion on PGA rates see Item 1 - Business - Gas Regulation and Rates.
Utility operations and maintenance expense increased $21.3 million in 2006 compared to 2005 primarily due to higher production costs of $11.9 million related to a major overhauls of Colstrip Units 1 and 4, the Hopkins Ridge wind project which became operational on November 26, 2005, soil remediation costs at PSE’s Crystal Mountain electric generation station site and costs to repair a failure of PSE’s Whitehorn Unit 2 combustion turbine generator. $7.2 million of the increase was due to higher electric distribution system restoration costs as a result of a series of severe winter storms. In addition, customer service and call center costs increased $3.8 million and gas operations and distribution costs increased $2.0 million. These increases were slightly offset by a decrease of $3.6 million in other expenses. PSE anticipates operation and maintenance expense to increase in future years as investments in new generating resources and energy delivery infrastructure are completed. The timing and amounts of increases will vary depending on when new generating resources come into service.
A series of severe wind storms occurred during 2006 for which PSE incurred significant costs, including a wind storm that occurred in December 2006 that resulted in a loss of electric service to over 700,000 of PSE’s customers. PSE incurred over $72.0 million in estimated costs related to this wind storm, the majority of which were deferred in accordance with the Washington Commission’s orders. In total, PSE deferred $92.3 million of storm costs in 2006 as a result of a Washington Commission order that allowed deferral of qualified storm costs in excess of $7.0 million. Qualifying storm costs are those that exceed the Institute of Electrical and Electronics Engineers (IEEE) standard for determining system average interruption duration index.
Conservation amortization increased $8.0 million in 2006 compared to 2005 due to higher authorized recovery of electric conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.
Depreciation and amortization expense increased $20.7 million in 2006 compared to 2005 due primarily to the effects of new generating and electric and gas distribution system plant placed in service, of which $8.1 million is from placing the Hopkins Ridge wind project in service on November 26, 2005.
Taxes other than income taxes increased $22.0 million in 2006 compared to 2005 primarily due to increases in revenue-based Washington State excise tax and municipal tax due to increased operating revenues. Revenue sensitive excise and municipal taxes have no impact on earnings. Excluding the impact of revenue sensitive taxes, taxes other than income taxes decreased $3.8 million primarily as a result of 2006 property tax reduction settled with the Washington State Department of Revenue in August 2006 which resulted in a lower valuation for tax purposes in 2006 as compared to 2005.
Income taxes increased $7.6 million in 2006 compared to 2005 was the result of higher taxable income slightly offset by a lower effective tax rate influenced by PTCs and the true-up of the prior year federal income tax provision which resulted in an expense in 2006 versus a benefit in 2005.
Other Income, Other Expenses, Other Income Taxes and Interest Charges
The table below sets forth significant changes in other income and interest charges for PSE from 2005 to 2006.
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
| Other income | | $ | 29.6 | | $ | 16.8 | | | 12.8 | | | 76.2 | % |
| Other expenses | | | (10.0 | ) | | (11.1 | ) | | 1.1 | | | 9.9 | |
| Income taxes | | | (1.4 | ) | | 2.6 | | | (4.0 | ) | | * | |
| Interest charges | | | 169.0 | | | 165.0 | | | 4.0 | | | 2.4 | |
| * | Percent change not applicable or meaningful. |
Other income increased $12.8 million in 2006 compared to 2005 primarily due to an increase in the accrual of carrying costs on regulatory assets and an increase in the equity portion of allowance for funds used during construction (AFUDC).
Other expenses decreased by $1.1 million due to a decrease in long-term share based incentive plan costs offset by certain regulatory penalty expenses incurred in 2006.
Income taxes on other income and expenses increased $4.0 million in 2006 as compared to 2005 is a result of the increase in other income.
Interest charges increased $4.0 million in 2006 compared to 2005 due primarily to interest expense of $6.4 million related to an increase in debt due to construction projects offset by an increase in the debt AFUDC credit. .
InfrastruX
On May 7, 2006, Puget Energy sold its 90.9% interest in InfrastruX to an affiliate of Tenaska, resulting in after-tax cash proceeds of approximately $95.9 million, an after-tax gain of $29.8 million for 2006. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005 and 2006.
Under the terms of the sale agreement, Puget Energy remains obligated for certain representations and warranties made by InfrastruX concerning its business through May 7, 2008. Puget Energy obtained a representation and warranty insurance policy and deposited $3.7 million into an escrow account as retention under the policy. As of December 31, 2006, long-term restricted cash in the amount of $3.8 million is included in the accompanying balance sheets and represents Puget Energy’s maximum exposure related to those commitments. Puget Energy also agreed to indemnify the purchaser for certain potential future losses related to one of InfrastruX’s subsidiaries through May 7, 2011, with the maximum amount of loss not to exceed $15.0 million. A liability in the amount of $5.0 million is included in the accompanying balance sheets as of December 31, 2006, which represents Puget Energy’s estimate of the fair value of the amount potentially payable using a probability-weighted approach to a range of future cash flows. Puget Energy also provided an environmental guarantee as part of the sale agreement. Puget Energy believes it will not have a future loss in connection with the environmental guarantee.
For 2006, Puget Energy reported InfrastruX related income from discontinued operations, including gain on sale, of $51.9 million compared to $9.5 million for 2005 (in each case, net of taxes and minority interest). Puget Energy’s income from discontinued operations for 2006 includes $7.3 million related to the reversal of a carrying value adjustment recorded in 2005 as well as $10.0 million related to the anticipated realization of a deferred tax asset associated with the sale of the business.
InfrastruX's operating revenue through May 7, 2006 was $138.6 million compared to $393.3 million for the twelve months ended December 31, 2005. Pre-tax income for the twelve months ended December 31, 2006 was $9.9 million compared to $36.4 million for the same period in 2005.
Puget Sound Energy
2005 compared to 2004
Energy Margins
The following table displays the details of electric margin changes from 2004 to 2005. Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.
| | | Electric Margin | |
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
Electric operating revenue1 | | $ | 1,612.9 | | $ | 1,423.0 | | $ | 189.9 | | | 13.3 | % |
| Less: Other electric operating revenue | | | (62.5 | ) | | (44.8 | ) | | (17.7 | ) | | (39.5 | ) |
| Add: Other electric revenue-gas supply resale | | | 26.1 | | | 11.4 | | | 14.7 | | | 128.9 | |
| Total electric revenue for margin | | | 1,576.5 | | | 1,389.6 | | | 186.9 | | | 13.4 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (26.9 | ) | | (25.4 | ) | | (1.5 | ) | | (5.9 | ) |
| Pass-through revenue-sensitive taxes | | | (104.9 | ) | | (94.2 | ) | | (10.7 | ) | | (11.4 | ) |
| Net electric revenue for margin | | | 1,444.7 | | | 1,270.0 | | | 174.7 | | | 13.8 | |
| Minus power costs: | | | | | | | | | | | | | |
Purchased electricity1 | | | (860.4 | ) | | (723.6 | ) | | (136.8 | ) | | (18.9 | ) |
Electric generation fuel1 | | | (73.3 | ) | | (80.8 | ) | | 7.5 | | | 9.3 | |
Residential exchange1 | | | 180.5 | | | 174.5 | | | 6.0 | | | 3.4 | |
| Total electric power costs | | | (753.2 | ) | | (629.9 | ) | | (123.3 | ) | | (19.6 | ) |
Electric margin2 | | $ | 691.5 | | $ | 640.1 | | $ | 51.4 | | | 8.0 | % |
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1 | As reported on PSE’s Consolidated Statement of Income. |
2 | Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense. |
Electric margin increased $51.4 million in 2005 compared to 2004 primarily as a result of the Tenaska disallowance recorded in May 2004, and ongoing Tenaska disallowances, which reduced margin by $43.4 million for 2004 compared to $4.1 million in 2005. Other items that increased margin include a 3.0% increase in retail customer usage which contributed $18.7 million to margin. These increases were partially offset by a reduction in transmission and transportation revenues in 2005 compared to 2004 which reduced electric margin by $2.7 million. Customers also received a reduction in revenue of $2.6 million related to production tax credits for the Hopkins Ridge wind generating facility which lowered electric revenue and margin. These credits vary quarter to quarter and over time the amounts credited to customers through lower electric rates will equal the amount used for federal income taxes. A lower authorized return on electric generating facilities that became effective on March 4, 2005 also lowered electric margin by $2.3 million.
The following table displays the details of gas margin changes from 2004 to 2005. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.
| | | Gas Margin | |
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Gas operating revenue | | $ | 952.5 | | $ | 769.3 | | $ | 183.2 | | | 23.8 | % |
| Less: Other gas operating revenue | | | (17.2 | ) | | (12.7 | ) | | (4.5 | ) | | (35.4 | ) |
Total gas revenue for margin1 | | | 935.3 | | | 756.6 | | | 178.7 | | | 23.6 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (5.7 | ) | | (3.6 | ) | | (2.1 | ) | | (58.3 | ) |
| Pass-through revenue-sensitive taxes | | | (73.1 | ) | | (59.3 | ) | | (13.8 | ) | | (23.3 | ) |
| Net gas revenue for margin | | | 856.5 | | | 693.7 | | | 162.8 | | | 23.5 | |
Minus purchased gas costs1 | | | (592.1 | ) | | (451.3 | ) | | (140.8 | ) | | (31.2 | ) |
Gas margin2 | | $ | 264.4 | | $ | 242.4 | | $ | 22.0 | | | 9.1 | % |
1 | As reported on PSE’s Consolidated Statement of Income. |
2 | Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense. |
Gas margin increased $22.0 million for 2005 compared to 2004. Gas margin increased $17.3 million as a result of the gas general tariff rate increase of 3.5% effective March 4, 2005. In addition, therm sales increased 2.4% for 2005 compared to 2004, which provided $5.8 million to gas margin and changes in customer class usage provided $3.9 million to gas margin.
Electric Operating Revenues
The table below sets forth changes in electric operating revenues for PSE from 2004 to 2005.
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Electric operating revenues: | | | | | | | | | |
| Residential sales | | $ | 690.2 | | $ | 628.9 | | $ | 61.3 | | | 9.7 | % |
| Commercial sales | | | 629.0 | | | 581.0 | | | 48.0 | | | 8.3 | |
| Industrial sales | | | 93.9 | | | 88.8 | | | 5.1 | | | 5.7 | |
| Other retail sales, including unbilled revenue | | | 23.3 | | | 12.2 | | | 11.1 | | | 91.0 | |
| Total retail sales | | | 1,436.4 | | | 1,310.9 | | | 125.5 | | | 9.6 | |
| Transportation sales | | | 9.0 | | | 10.7 | | | (1.7 | ) | | (15.9 | ) |
| Sales to other utilities and marketers | | | 105.0 | | | 56.5 | | | 48.5 | | | 85.8 | |
| Other | | | 62.5 | | | 44.9 | | | 17.6 | | | 39.2 | |
| Total electric operating revenues | | $ | 1,612.9 | | $ | 1,423.0 | | $ | 189.9 | | | 13.3 | % |
Electric retail sales increased $125.5 million for 2005 compared to 2004 due primarily to rate increases related to the PCORC and the electric general rate case and increased retail customer usage. The PCORC and electric general rate case provided a combined additional $66.5 million to electric operating revenues for 2005 compared to 2004, which provided approximately $24.5 million in electric operating revenues. Retail electricity usage increased 588,645 MWh or 3.0% for 2005 compared to 2004. The increase in electricity usage was mainly the result of a 1.8% higher average number of customers served in 2005 compared to 2004.
During 2005, the benefits of the Residential and Small Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $189.0 million compared to $182.6 million for 2004. This credit also reduced power costs by a corresponding amount with no impact on earnings.
Sales to other utilities and marketers increased $48.5 million compared to 2004 primarily due to an increase of 569,613 MWh sold related to excess generation and energy available for sale on the wholesale market. This resulted primarily from normal streamflows for hydroelectric generation in the third quarter as compared to below normal streamflows that were expected. The increase in MWh sold was due to differences in timing of the need for power to serve base load and actual weather conditions.
Other electric revenues increased $17.6 million for 2005 compared to 2004, primarily from the sale of excess non-core gas purchased for intended electric generation. Non-core gas sales are included in the PCA mechanism calculation as a reduction in determining costs.
The following electric rate changes were approved by the Washington Commission in 2005 and 2004:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| Power Cost Only Rate Case | May 24, 2004 | 3.2 | % | $ 44.1 |
| Electric General Rate Case | March 4, 2005 | 4.1 | % | 57.7 |
| Power Cost Only Rate Case | November 1, 2005 | 3.7 | % | 55.6 |
Gas Operating Revenues
The table below sets forth changes in gas operating revenues for PSE from 2004 to 2005.
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Gas operating revenues: | | | | | | | | | |
| Residential sales | | $ | 592.4 | | $ | 479.0 | | $ | 113.4 | | | 23.7 | % |
| Commercial sales | | | 281.3 | | | 225.8 | | | 55.5 | | | 24.6 | |
| Industrial sales | | | 48.3 | | | 38.8 | | | 9.5 | | | 24.5 | |
| Total retail sales | | | 922.0 | | | 743.6 | | | 178.4 | | | 24.0 | |
| Transportation sales | | | 13.3 | | | 13.0 | | | 0.3 | | | 2.3 | |
| Other | | | 17.2 | | | 12.7 | | | 4.5 | | | 35.4 | |
| Total gas operating revenues | | $ | 952.5 | | $ | 769.3 | | $ | 183.2 | | | 23.8 | % |
Gas retail sales increased $178.4 million for 2005 compared to 2004 due to higher PGA mechanism rates in 2005, approval of a 3.5% general gas rate increase in the gas general rate case effective March 4, 2005 and higher customer gas usage. The Washington Commission approved a third PGA mechanism rate increaseincreases effective October 1, 2004 that increased rates 17.6% annually. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. For 2004,2005, the effects of the PGA mechanism rate increases provided an increase of $137.0$123.8 million in gas operating revenues. TheseIn addition, the gas general rate increases were partially offset with lower therm sales due to 2.3% fewer heating degree daysincrease provided an additional $17.3 million in 2004gas operating revenue for 2005 compared to 2003.2004. An increase of 3.1% in the average number of customers and lower temperatures in 2005 increased retail customer usage by 27.2 million therms or approximately $25.0 million in retail gas operating revenues.
The following gas rate adjustments were approved by the Washington Commission in 2005 and 2004:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| PGA | October 1, 2004 | 17.6 | % | $ 121.7 |
| Gas General Rate Case | March 4, 2005 | 3.5 | % | 26.3 |
| PGA | October 1, 2005 | 14.7 | % | 121.6 |
OPERATING EXPENSESOperating Expenses
The table below sets forth significant changes in operating expenses for PSE and its subsidiaries from 20032004 to 2004.2005.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | CHANGE | | PERCENT CHANGE | | |
(Dollars in Millions) Twelve Months Ended December 31 | | | 2005 | | 2004 | | Change | | Percent Change | |
| Purchased electricity | | $ | 723.6 | | $ | 714.5 | | $ | 9.1 | | | 1.3 | % | | $ | 860.4 | | $ | 723.6 | | $ | 136.8 | | | 18.9 | % |
| Electric generation fuel | | | 80.8 | | | 65.0 | | | 15.8 | | | 24.3 | | | | 73.3 | | | 80.8 | | | (7.5 | ) | | (9.3 | ) |
| Residential exchange | | | | (180.5 | ) | | (174.5 | ) | | (6.0 | ) | | (3.4 | ) |
| Purchased gas | | | 451.3 | | | 327.1 | | | 124.2 | | | 38.0 | | | | 592.1 | | | 451.3 | | | 140.8 | | | 31.2 | |
| Utility operations and maintenance | | | 291.2 | | | 289.7 | | | 1.5 | | | 0.5 | | | | 333.3 | | | 291.2 | | | 42.1 | | | 14.5 | |
| Depreciation and amortization | | | 228.6 | | | 220.1 | | | 8.5 | | | 3.9 | | | | 241.6 | | | 228.6 | | | 13.0 | | | 5.7 | |
| Conservation amortization | | | 22.7 | | | 33.5 | | | (10.8 | ) | | (32.2 | ) | |
| Taxes other than income taxes | | | 209.0 | | | 194.9 | | | 14.1 | | | 7.2 | | | | 233.7 | | | 209.0 | | | 24.7 | | | 11.8 | |
| Income taxes | | | 77.1 | | | 70.9 | | | 6.2 | | | 8.7 | | | | 89.6 | | | 77.1 | | | 12.5 | | | 16.2 | |
Purchased electricity expenses increased $9.1$136.8 million in 20042005 compared to 20032004 as a result of increased power purchases from higher customer usage and higher wholesale market prices offset by a $36.5 million disallowance associated withreduction in the Tenaska generating facility as ordered bydisallowance related to the return on the Tenaska gas supply regulatory asset. The reduction of $39.3 million related to the Tenaska disallowance from 2004 included a February 23, 2005 Washington Commission order concerning PSE’s compliance filing related to the PCA 2 period of July 1, 2003 through June 30, 2004. In its order, the Washington Commission determined that PSE was allowed to reflect additional power costs totaling $6.0 million during the PCA 2 period of July 1, 2003 through December 31, 2003. These costs were reflected in the PCORC. This decrease was partially offset by lower purchases ofPCA mechanism, which resulted in a reduction in purchased electricity due toexpense for 2005. Total purchased power for 2005 increased generation at PSE generating facilities. Total generation at PSE generating facilities in 2004 increased 82,4301,336,501 MWh, or 1.2% in 2004 compared to 2003.an 8.6% increase over 2004.
PSE’s hydroelectric production and related power costs in 2005 and 2004 and 2003 have continued to bewere negatively impacted by below-normal winter precipitation and reduced snow pack in the Pacific Northwest region. The January 3, 20054, 2006 Columbia Basin Runoff Summary published by the National Weather Service Northwest River Forecast Center indicated that the total observed runoff above Grand Coulee Reservoir for the period January through December 20042005 was 88%88.0% of normal, which compares to 87% of normalapproximates the total observed runoff for the same period in 2003. PSE cannot determine if this trend of lower than normal runoff will continue in future years nor what impact such a trend may have on the amount of electricity that will need to be purchased. PSE had previously reached the $40 million cumulative cap under the PCA mechanism in 2003 primarily due to increased power costs and adverse hydroelectric conditions. In 2004, PSE fell below the $40 million cumulative cap due to the Tenaska disallowance. Under the PCA mechanism, continued excess power costs and further increases in variable power costs through June 30, 2006 will be apportioned 99% to customers and 1% to PSE. PSE has reserved the Tenaska disallowance and as a result any future excess power costs will be offset by the reserve. For further discussion see Item 1 - Business - Regulation and Rates - Electric Regulation and Rates - Washington Commission Matters.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric capacity and energy, and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its core energy portfolio through short-term and intermediate-term off-system physical purchases and sales, and through other risk management techniques.2004.
Electric generation fuel expense increased $15.8decreased $7.5 million in 20042005 compared to 2003 as a result of higher fuel costs for PSE-controlled gas-fired generation facilities and the addition of the Frederickson 1 generating facility, which was purchased and went into service in April 2004. In addition, the 12 months ended December 31, 2004 includesprimarily due to a $6.9 million charge recorded in 2004 related to a binding arbitration settlement between PSE and Western Energy Company (WECO),and PSE. Excluding this settlement, electric generation fuel costs decreased $0.6 million related to overall lower cost of gas for combustion turbine units and cost of gas at those facilities totaling $5.6 million. The decrease in lower cost of gas was partially offset by an increase of the suppliercost of coal to Colstrip Units 1 & 2. The binding decision retroactively set a new baseline cost per ton of coal supplied from July 31, 2001, and is applicable to the remaining term of the coal supply agreement through December 2009. Of the $6.9 million charge, $5.0 million is includedin 2005 compared to 2004 due to higher generation at Colstrip generating facilities of 56,797 MWh. Costs associated with electric generation fuel are reflected in the PCA mechanism. PSE had previously accrued a reserve
The reduction in electric generation fuel was also the result of $1.6the Hopkins Ridge wind generation facility beginning operations on November 27, 2005. Generation from the Hopkins Ridge generation facility does not include fuel expenses in its operation.
Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA increased $6.0 million in the fourth quarter 2003 related2005 compared to the arbitration.
The 12 months ended December 31, 2004 also includes a loss reserve of $1.1 million recorded in the second quarter 2004 related to an order issued to WECO by the Minerals Management Services of the United States Department of the Interior (MMS) on April 29, 2004, to pay additional royalties concerning coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of royalties for coal mined from federal land between 1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a settlement agreement entered into in February 1997 among PSE, WECO and Montana Power Company that resolved disputes that were then pending. The order seeks to impute the price charged to PSE based on the other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is supporting WECO’s appeal of the order, but is also evaluating the basis of the claim.
In addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royaltiesincreased residential and small farm customer electric load. The residential exchange credit is a pass-through tariff item with a corresponding credit in connection withelectric operating revenue, received by WECO from the Colstrip Units 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. PSE’s share of the alleged additional royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest in Colstrip Units 3 & 4. Other parties may attempt to assert claims against WECO if the MMS position prevails. The transportation agreement provides for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip Units 3 & 4. WECOthus it has appealed these orders and PSE is monitoring the process. Based upon its review, PSE believes that the Colstrip Units 3 & 4 owners have reasonable defenses in this matter. Neither the outcome of this matter nor the associated costs can be predicted at this time.no impact on electric margin or net income.
Purchased gas expenses increased $124.2$140.8 million in 20042005 compared to 20032004 primarily due to an increase in PGA rates as approved by the Washington Commission. The PGA mechanism allows PSE to recover expected gas costs, and defer, as a receivable or liability, any gas costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism had a receivable balance at December 31, 2005 and 2004 ofwas $67.3 million and $19.1 million, compared to a liability balance of $12.0 million at December 31, 2003.respectively. A receivable balance in the PGA mechanism reflects a current underrecovery of market gas cost through rates and a liability balance reflects a current overrecovery of gas cost. For further discussion on PGA rates see Item 1 - Business - Gas Regulation and Rates.rates.
Utility operations and maintenanceexpense increased $1.5$42.1 million in 20042005 compared to 20032004 which includes a decreasean increase of $1.8$4.3 million related to low-income program costs that are passed-through in retail rates with no impact on earnings. As a result, the pre-tax impact on net income from utility operations and maintenance for 2005 was an increase of $3.3$37.7 million. The increase for 2005 includes increases of $26.2 million related to higher gas distribution system expenses, planned maintenance costs for PSE-owned energy production facilities, electric distribution system costs, regulatory commission expense for rate cases and administrative costs. The production operation and maintenance increase for 2005 also includes a $1.5 million loss reserve associated with an arbitration panel’s ruling in favor of the Muckleshoot Indian Tribe relating to the operation of a fish hatchery on the White River recorded in the second quarter 2005. These increases were partially offset by lower storm damage repair costs of $5.5 million for 2005 due primarily to a $3.2 million increase inless severe weather and outages. Total storm damage costs primarily from a severe ice storm that hit the Pacific Northwestfor 2005 totaled $3.6 million compared to $9.1 million in January 2004. PSE anticipates operation and maintenance expense to increase in future years as PSE invests in new generating resources and energy delivery infrastructure.
Depreciation and amortization expense increased $8.5$13.0 million in 20042005 compared to 20032004 due primarily to the effects of new generating and electric and gas distribution system plant placed in service during 2004, including $80.8 million in costs for the Frederickson 1 generating facility and $32.82005. New plant placed in service in 2005 includes $170.9 million for the Everett Delta gas transmission line. PSE anticipates depreciation expense will increaseHopkins Ridge wind project in future years as PSE invests in new generating resources and energy delivery infrastructure.
Conservation amortization decreased $10.8 million in 2004 compared to 2003 due to the conservation trust assets being fully amortized in September 2004. Conservation amortization is a pass-through tariff item with no impact on earnings.November 2005.
Taxes other than income taxes increased $14.1$24.7 million in 20042005 compared to 20032004 primarily due to increases in revenue-based Washington State excise tax and municipal tax due to increased operating revenues. Revenue sensitive excise and municipal taxes have no impact on earnings.
Income taxes increased $6.2$12.5 million in 20042005 compared to 20032004 as a result of higher taxable income and the non-recurrence in 2004 of $9.3 million in income tax benefits in 2003 offset by athe one-time income tax benefit of $1.4 million in 2004 related to a 2001 tax audit.
OTHER INCOME, INTEREST CHARGES AND PREFERRED STOCK DIVIDENDSOther Income and Interest Charges
The table below sets forth significant changes in other income and interest charges and preferred stock dividends for PSE and its subsidiaries from 20032005 to 2004.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2004 | | 2003 | | CHANGE | | PERCENT CHANGE | |
| Other income (net of tax) | | $ | 4.4 | | $ | 1.6 | | $ | 2.8 | | | 175.0 | % |
| Interest charges | | | 166.4 | | | 179.4 | | | (13.0 | ) | | (7.2 | ) |
| Preferred stock dividends | | | -- | | | 5.2 | | | (5.2 | ) | | (100.0 | ) |
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Other income | | $ | 16.8 | | $ | 11.0 | | $ | 5.8 | | | 52.7 | % |
| Other expenses | | | (11.1 | ) | | (9.5 | ) | | (1.6 | ) | | (16.8 | ) |
| Interest charges | | | 165.0 | | | 166.4 | | | (1.4 | ) | | (0.8 | ) |
Other incomeincreased $2.8$5.8 million (after-tax)in 2005 compared to 2004 primarily due to increases in the non-recurrenceequity portion of a $4.0allowance for funds used during construction and an increase in revenue from PSE’s basic ordering agreement for energy management projects with the U.S. Navy.
Other expenses decreased by $1.6 million investment write-down in 2003 relatedprimarily due to a non-utility venture capital investment and a $0.9 million collectiondecrease in 2004 of a note previously written-off in 2002. These increases were partially offset withlong-term incentive plan costs due to not meeting the non-recurrence of a $1.9 million gain from a security sale in 2003 and the non-recurrence of gains on corporate life insurance of $1.7 million in 2003.performance condition.
Interest chargesdecreased $13.0$1.4 million in 2005 compared to 2004 due to the redemption of $157.7$231.0 million of long-term debt with rates ranging from 6.07%3.40% to 7.80%6.93% in 2004,2005. Also, in May 2005, PSE redeemed $42.5 million of PSE's 8.231% Capital Trust Preferred Securities (classified as Junior Subordinated Debentures of the Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities on the balance sheet). These redemptions and resulting decreases in interest expense were partially offset withby the issuance of $200$250.0 million and $150.0 million of variable-ratelong-term senior notes in July 2004.
Preferred stock dividends decreased $5.2May 2005 and October 2005, respectively. In addition, debt AFUDC credited to interest expense increased $4.1 million in 2004 due to the redemption on November 1, 2003 of the 7.45% series preferred stock not subject to mandatory redemption. The series was redeemed at par value plus accrued dividends.increased construction activity in 2005.
INFRASTRUXInfrastruX
2005 compared to 2004 COMPARED TO 2003
The table below sets forth significant changes in revenues and expenses for InfrastruX from 2003 to 2004.
(DOLLARS IN MILLIONS) YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | CHANGE | | PERCENT CHANGE | |
| Operating revenue: | | | | | | | | | |
| Non-utility construction services | | $ | 369.9 | | $ | 341.8 | | $ | 28.1 | | | 8.2 | % |
| | | | | | | | | | | | | | |
| Other operations and maintenance | | $ | 320.2 | | $ | 302.4 | | $ | 17.8 | | | 5.9 | % |
| Depreciation and amortization | | | 18.3 | | | 16.8 | | | 1.5 | | | 8.9 | |
| Goodwill impairment | | | 91.2 | | | -- | | | 91.2 | | | * | |
| Income taxes | | | (1.8 | ) | | 1.6 | | | (3.4 | ) | | (212.5 | ) |
| | | | | | | | | | | | | | |
| Interest charges | | $ | 6.5 | | $ | 5.5 | | $ | 1.0 | | | 18.2 | % |
| Minority interest | | | 7.1 | | | (0.2 | ) | | 7.3 | | | * | |
* Percent change not applicable.
| (Dollars in Millions) | | 2005 | | 2004 | |
| Income from operations reported by InfrastruX | | $ | 11.4 | | $ | 6.8 | |
| Goodwill impairment | | | (13.9 | ) | | (91.2 | ) |
| Tax provision on goodwill impairment | | | -- | | | 24.9 | |
| Net (loss) at InfrastruX | | | (2.5 | ) | | (59.5 | ) |
| Goodwill impairment not recognized at Puget Energy | | | 13.9 | | | -- | |
| InfrastruX depreciation and amortization not recorded by Puget Energy, net of tax | | | 10.8 | | | -- | |
| Puget Energy tax benefit (valuation allowance) from goodwill impairment | | | 1.9 | | | (18.0 | ) |
| Carrying value adjustment to estimated fair value and transaction costs | | | (12.4 | ) | | -- | |
| Minority interest in income from discontinued operations | | | (2.2 | ) | | 7.1 | |
| Income (loss) from discontinued operations | | $ | 9.5 | | $ | (70.4 | ) |
InfrastruX revenuesincreased $28.1 million due in part to the acquisition of one company late in the second quarter 2003 which added $12.4 million to revenues. Revenues from existing companies increased $8.7 million in 2004 compared to 2003 due to strong performance in the electric transmission sector of the construction services industry and new business in the Midwest region of the United States.
Other operations and maintenanceexpensesincreased $17.8 million due to increased utility construction in 2004 compared to 2003 and the acquisition of one company late in the second quarter 2003, which accounted for $11.8 million of the increase.
Depreciation and amortization expense increased $1.5 million in 2004 compared to 2003 primarily due to an increase in assets through a company acquisition late in the second quarter 2003 which accounted for $0.8 million of the increase and implementation of an integrated information technology platform across InfrastruX.
Goodwill impairment.In the fourth quarter 2004, as part of the required annual goodwill impairment review as required byaccordance with Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill144, Puget Energy adjusted the carrying value of its investment in InfrastruX to the estimate of fair value, less cost to sell, at December 31, 2005. After reflecting a $12.4 million carrying value adjustment and Other Intangible Assets,”charge for transaction costs in 2005, Puget Energy’s equity investment in InfrastruX recorded a non-cash, pre-tax goodwill impairment charge of $91.2 million. This charge reflectedwas $43.5 million at December 31, 2005 compared to $33.8 million at December 31, 2004. Puget Energy’s carrying value under SFAS No. 144 as compared to the estimated fair value forof its InfrastruX in light of ongoing challenges ininvestment was not impacted by the utility construction services sector.
Income taxesdecreased $3.4 million in 2004 compared to 2003. Included in the change was a $25.0 million deferred income tax benefit associated with thenon-cash goodwill impairment charge, offsetrecorded by InfrastruX under SFAS No. 142 due to discontinued operations of InfrastruX. As a $18.0 million valuation allowance against the deferred tax benefit asresult, Puget Energy doesdid not expect to utilize the full benefit. The remaining change in income tax was primarily the result of higher taxable income at InfrastruX in 2004 compared to 2003.
Interest charges increased $1.0 million in 2004 compared to 2003 primarily due to a higher average debt balance in 2004 than in 2003 and higher interest rates.
Minority interestincreased $7.3 million in 2004 compared to 2003 as a result of the change in net loss associated with the goodwill impairment charge in 2004.
PUGET SOUND ENERGY
2003 COMPARED TO 2002
ENERGYMARGINS
The following table displays the details of electric margin changes from 2002 to 2003.
| | | ELECTRIC MARGIN | |
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2003 | | 2002 | | CHANGE | | PERCENT CHANGE | |
| Electric retail sales revenue | | $ | 1,272.7 | | $ | 1,260.9 | | $ | 11.8 | | | 0.9 | % |
| Electric transportation revenue | | | 11.5 | | | 15.6 | | | (4.1 | ) | | (26.3 | ) |
| Other electric revenue-gas supply resale | | | 9.1 | | | (20.4 | ) | | 29.5 | | | 144.6 | |
| Total electric revenue for margin | | | 1,293.3 | | | 1,256.1 | | | 37.2 | | | 3.0 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (45.2 | ) | | (32.1 | ) | | (13.1 | ) | | (40.8 | ) |
| Pass-through revenue-sensitive taxes | | | (91.0 | ) | | (88.5 | ) | | (2.5 | ) | | (2.8 | ) |
| Residential exchange credit | | | 173.8 | | | 150.0 | | | 23.8 | | | 15.9 | |
| Net electric revenue for margin | | | 1,330.9 | | | 1,285.5 | | | 45.4 | | | 3.5 | |
| Minus power costs: | | | | | | | | | | | | | |
| Fuel | | | (65.0 | ) | | (113.5 | ) | | 48.5 | | | 42.7 | |
Purchased electricity, net of sales to other utilities and marketers | | | (635.2 | ) | | (557.1 | ) | | (78.1 | ) | | (14.0 | ) |
| Total electric power costs | | | (700.2 | ) | | (670.6 | ) | | (29.6 | ) | | (4.4 | ) |
| Electric margin before PCA | | | 630.7 | | | 614.9 | | | 15.8 | | | 2.6 | |
| Power cost deferred under the PCA mechanism | | | 3.5 | | | -- | | | 3.5 | | | * | |
| Electric margin | | $ | 634.2 | | $ | 614.9 | | $ | 19.3 | | | 3.1 | % |
* Percent change not applicable.
Electric margin increased $19.3 million for 2003 compared to 2002 due primarily to the non-recurrence of losses associated with the resale of gas supply for electric generation in 2002 and increased MWh sales of 1.5%. Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of generating and purchasing electric energy sold to customers including transmission costs to bring electric energy to PSE’s service territory.
The following table displays the details of gas margin changes from 2002 to 2003.
| | | GAS MARGIN | |
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2003 | | 2002 | | CHANGE | | PERCENT CHANGE | |
| Gas retail revenue | | $ | 609.6 | | $ | 673.2 | | $ | (63.6 | ) | | (9.4 | )% |
| Gas transportation revenue | | | 13.8 | | | 12.9 | | | 0.9 | | | 7.0 | |
| Total gas revenue for margin | | | 623.4 | | | 686.1 | | | (62.7 | ) | | (9.1 | ) |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Gas revenue hedge | | | 0.2 | | | 0.6 | | | (0.4 | ) | | (66.7 | ) |
| Pass-through tariff items | | | (3.8 | ) | | (2.3 | ) | | (1.5 | ) | | (65.2 | ) |
| Pass-through revenue-sensitive taxes | | | (48.5 | ) | | (54.3 | ) | | 5.8 | | | 10.7 | |
| Net gas revenue for margin | | | 571.3 | | | 630.1 | | | (58.8 | ) | | (9.3 | ) |
| Minus purchased gas costs | | | (327.1 | ) | | (405.0 | ) | | 77.9 | | | 19.2 | |
| Gas margin | | $ | 244.2 | | $ | 225.1 | | $ | 19.1 | | | 8.5 | % |
Gas margin increased $19.1 million in 2003 compared to 2002 due torecord the effects of the gas general rate increase effective September 1, 2002 that resultedgoodwill impairment under SFAS No. 142 in a $24.2 million increase in revenues in 2003. The increase was offset by a 2.1% decline in therm sales in 2003. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.2005.
ELECTRIC OPERATING REVENUES
The table below sets forth significant changes in electric operating revenues for PSE from 2002 to 2003.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2003 | | 2002 | | CHANGE | | PERCENT CHANGE | |
| Electric operating revenues: | | | | | | | | | | | | | |
| Residential sales | | $ | 603.7 | | $ | 616.5 | | $ | (12.8 | ) | | (2.0 | )% |
| Commercial sales | | | 556.0 | | | 536.0 | | | 20.0 | | | 3.7 | |
| Industrial sales | | | 88.2 | | | 90.1 | | | (1.9 | ) | | (2.1 | ) |
| Transportation sales | | | 11.5 | | | 15.6 | | | (4.1 | ) | | (26.2 | ) |
| Sales to other utilities and marketers | | | 82.8 | | | 11.1 | | | 71.7 | | | * | |
| Other | | | 58.5 | | | 19.4 | | | 39.1 | | | 201.5 | |
| Total electric operating revenues | | $ | 1,400.7 | | $ | 1,288.7 | | $ | 112.0 | | | 8.7 | % |
*Percent change not applicable.
Electric operating revenues increased $112.0 million in 2003 compared to 2002 due primarily to an increase of $71.7 million in wholesale electric sales to other utilitiesCapital Resources and marketers from greater surplus volumes. Wholesale sales volumes increased by 640,176 MWh or 94.5% compared to 2002. Retail sales volumes increased 337,154 MWh or 1.8% as a result of increased usage by commercial customers in 2003 compared to 2002. Electric operating revenues also increased by $27.4 million due primarily to the non-occurrence of 2002 losses on the sale of excess gas supply used for electric generation.
During 2003, the benefits of the Residential and Farm Energy Exchange Credit to customers reduced revenues by $181.9 million compared to $156.8 million in 2002. This credit also reduced power costs by a corresponding amount with no impact on earnings.
During 2003, PSE collected in its electric general rate tariff as a reduction to revenue and remitted to a grantor trust $7.7 million compared to $12.7 million for 2002 as a result of PSE’s 1995 sale of future electric revenues associated with its investment in conservation assets. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expense. PSE’s 1995 conservation trust transaction was consolidated in the third quarter 2003 to meet the guidance of FIN 46 and, as a result, revenues increased $5.7 million while conservation amortization and interest expense increased by a corresponding amount with no impact on earnings. This amount was also forwarded to the grantor trust and any cash balance at the grantor trust was reported as restricted cash on the balance sheet.
GAS OPERATING REVENUES
The table below sets forth significant changes in gas operating revenues for PSE from 2002 to 2003.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2003 | | 2002 | | CHANGE | | PERCENT CHANGE | |
| Gas operating revenues: | | | | | | | | | |
| Residential sales | | $ | 401.7 | | $ | 428.6 | | $ | (26.9 | ) | | (6.3 | )% |
| Commercial sales | | | 178.2 | | | 209.5 | | | (31.3 | ) | | (14.9 | ) |
| Industrial sales | | | 29.7 | | | 35.1 | | | (5.4 | ) | | (15.4 | ) |
| Transportation sales | | | 13.8 | | | 12.9 | | | 0.9 | | | 7.0 | |
| Other | | | 10.8 | | | 11.1 | | | (0.3 | ) | | (2.7 | ) |
| Total gas operating revenues | | $ | 634.2 | | $ | 697.2 | | $ | (63.0 | ) | | (9.0 | )% |
Regulated gas utility revenues in 2003 compared to 2002 decreased by $63.0 million or 9.0% due primarily to lower PGA mechanism rates in 2003 as a result of refunding the previous overcollection of PGA mechanism gas costs. In addition, warmer temperatures in 2003 resulted in 8.5% fewer heating degree days as compared to 2002 resulting in lower therm sales.
PGA mechanism rates charged to customers were lower in 2003 compared to 2002 as a result of rate decreases of 7.3% and 12.5% which took effect September 1, 2002 and November 1, 2002, respectively, offset by a rate increase of 20.1% which took effect April 10, 2003, and another rate increase of 13.3% effective October 1, 2003.
OTHER OPERATING REVENUES
Other operating revenues decreased $3.8 million in 2003 compared to 2002 primarily due to a decrease in property sales gains for Puget Western, Inc., a PSE subsidiary, which generates a majority of its revenue through the development and sale of property.
OPERATING EXPENSES
The table below sets forth significant changes in operating expenses for PSE and its subsidiaries from 2002 to 2003.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2003 | | 2002 | | CHANGE | | PERCENT CHANGE | |
| Purchased electricity | | $ | 714.5 | | $ | 568.2 | | $ | 146.3 | | | 25.7 | % |
| Electric generation fuel | | | 65.0 | | | 113.5 | | | (48.5 | ) | | (42.7 | ) |
| Residential exchange power cost credit | | | (173.8 | ) | | (149.9 | ) | | (23.9 | ) | | (15.9 | ) |
| Purchased gas | | | 327.1 | | | 405.0 | | | (77.9 | ) | | (19.2 | ) |
| Unrealized (gain) loss on derivative instruments | | | 0.1 | | | (11.6 | ) | | 11.7 | | | 100.8 | |
| Utility operations and maintenance | | | 289.7 | | | 286.2 | | | 3.5 | | | 1.2 | |
| Depreciation and amortization | | | 220.1 | | | 215.3 | | | 4.8 | | | 2.2 | |
| Conservation amortization | | | 33.4 | | | 17.5 | | | 15.9 | | | 90.9 | |
| Taxes other than income taxes | | | 194.9 | | | 202.4 | | | (7.5 | ) | | (3.7 | ) |
| Income taxes | | | 70.9 | | | 52.8 | | | 18.1 | | | 34.2 | |
Purchased electricity expenses increased $146.3 million in 2003 compared to 2002. PSE’s hydroelectric production and related power costs in 2003 were negatively impacted by below-normal winter precipitation and snow pack in the Pacific Northwest region associated with an El Nino weather condition. The January 25, 2004 Columbia Basin Runoff Summary published by the National Weather Service Northwest River Forecast Center indicated that the total observed runoff above Grand Coulee Reservoir for the period January through December 2003 was 87% of normal. This compared to 108% of normal for the same period in 2002.
Electric generation fuel expense decreased $48.5 million in 2003 compared to 2002 as a result of lower fuel costs for PSE-controlled gas-fired generation facilities and the result of not operating the generating facilities due to available lower-cost wholesale power supply.
Residential exchange credits associated with the Residential Purchase and Sale Agreement with Bonneville Power Administration (BPA) increased $23.9 million in 2003 compared to 2002 due to the impact of a full year’s increased Residential and Farm Energy Exchange credit rate. The rate increased in January, March and October of 2002 for residential and small farm customers. Discussion of the amended Residential Purchase and Sale Agreement between PSE and BPA can be found under Item 1 - Business - Regulation and Rates - Residential and Small Farm Exchange Benefit Credit. The residential exchange credits are passed through to eligible residential and small farm customers by a corresponding reduction in revenues.
Purchased gas expenses decreased $77.9 million in 2003 compared to 2002 primarily due to a 2.1% decrease in sales volume, which was partially offset by an increase in PGA rates. The PGA mechanism allows PSE to recover expected gas costs. PSE defers, as a receivable or liability, any gas costs that exceed or fall short of the amount in PGA mechanism rates and accrues interest under the PGA mechanism. The PGA liability balance at December 31, 2003 was $12.0 million compared to a liability balance of $83.8 million at December 31, 2002.
Unrealized losses on derivative instruments increased $11.7 million in 2003 compared to 2002 as a result of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and settled in 2002. The unrealized gains and losses recorded in the income statement are the result of the change in the market value of derivative instruments not meeting cash flow hedge criteria.
Utility operations and maintenanceexpense increased $3.5 million in 2003 compared to 2002, which included an increase of $3.3 million related to a full year of low-income program costs that were passed-through in retail rates with no impact on earnings. As a result, the pre-tax impact on net income from utility operations and maintenance expense was an increase of $0.2 million due primarily to an increase in electric overhead and underground line costs, gas distribution main costs, least cost planning costs, due diligence costs for power resource acquisition, certain costs associated with preparing the PCORC and meter reading expenses. The overall increase in utility operations and maintenance expenses was partially offset by a $2.0 million reduction of production operations and maintenance costs in 2003 compared to 2002 due to decreased operating costs of PSE’s combustion turbine plants which were operated at lower levels in 2003 than in 2002 due to lower wholesale power prices. In addition, PSE’s Personal Energy ManagementTM energy-efficiency program costs decreased $6.3 million in 2003 compared to 2002 reflecting a decreased emphasis on the program in light of relatively moderate energy prices and cancellation of the Time of Use program in November 2002. Also included in the results was pension income related to PSE’s defined benefit pension plan which is allocated between capital and operations and maintenance expense based on the distribution of labor costs in accordance with FERC guidelines. As a result, approximately 67.0% of the annual qualified pension income of $12.9 million for 2003 was recorded as a reduction in operations and maintenance expense compared to 66.8% or $17.7 million for 2002. During the fourth quarter 2003, the Pacific Northwest region was hit by a severe windstorm that caused significant damage to PSE’s electric distribution system. The windstorm was considered a “catastrophic event” under Washington Commission guidelines and as a result, PSE was able to defer the repair cost of $10.1 million for later recovery in retail rates.
Depreciation and amortization expense increased $4.8 million in 2003 compared to 2002 due primarily to the effects of a new plant placed in service during the past year.
Conservation amortization increased $15.9 million in 2003 compared to 2002 due to increased conservation expenditures and the result of consolidating the off-balance sheet conservation trust beginning July 1, 2003 in accordance with FIN 46. The consolidation of the conservation trust increased conservation amortization by $5.7 million for the period July through December 2003. Pass-through conservation costs are recovered through an electric conservation rider, a gas conservation tracker mechanism and a conservation trust rate schedule with no impact to earnings.
Taxes other than income taxes decreased $7.5 million in 2003 compared to 2002 primarily due to the 2002 property tax expense of $5.2 million related to the State of Oregon property tax bills covering a six-year period ending June 30, 2001 not recurring in 2003, a $1.4 million reduction in expense in the second quarter 2003 related to the settlement of the State of Oregon property tax bills and a $2.8 million decrease in revenue-based Washington State excise tax and municipal tax. This was offset by a $1.6 million increase in Washington State property taxes.
Income taxes increased $18.1 million in 2003 compared to 2002 as a result of increased income offset by true-ups related to filing the prior year’s income tax returns, which reduced income tax expense by $3.0 million and a $6.2 million reduction in tax expense related to the favorable resolution of a federal income tax matter from 1997 to 2002 in the second quarter 2003. The increase was also the result of 2002 tax benefits totaling $10.3 million. The $10.3 million was composed of a $4.1 million refund related to the audit of the Company’s 1998 and 1999 federal income tax returns, a $3.5 million reduction to income tax expense representing an adjustment to 2001 federal income tax based on the 2001 federal tax return and a $2.7 million reduction in expense related to a refund of federal income taxes for 2000.
OTHER INCOME, INTEREST CHARGES AND PREFERRED STOCK DIVIDENDS
The table below sets forth changes in other income, interest charges and preferred stock dividends for PSE and its subsidiaries from 2002 to 2003.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2003 | | 2002 | | CHANGE | | PERCENT CHANGE | |
| Other income (net of tax) | | $ | 1.6 | | $ | 5.2 | | $ | (3.6 | ) | | (69.2 | )% |
| Interest charges | | | 179.4 | | | 190.9 | | | (11.5 | ) | | (6.0 | ) |
| Preferred stock dividends | | | 5.2 | | | 7.8 | | | (2.6 | ) | | (33.3 | ) |
Other income, net of federal income tax, decreased $3.6 million compared to 2002 reflecting a $4.0 million after-tax downward adjustment of the carrying value of a non-utility venture capital investment in the fourth quarter 2003.
Interest charges decreased $11.5 million for 2003 compared to 2002 primarily due to a decrease in long-term and short-term debt outstanding of $12.0 million and the maturity of $72.0 million of Medium-Term Notes with interest rates ranging from 6.20% to 7.02% during 2003, the early redemption of $123.0 million of Medium-Term Notes with interest rates ranging from 7.19% to 8.59% during 2003, and the refinancing of $161.9 million of Pollution Control Bonds with interest rates ranging from 5.875% to 7.25% to rates ranging from 5.00% to 5.10%. The decrease in interest expense was partially offset by the issuance of $150 million of senior notes, with an interest rate of 3.36%, in May 2003. PSE was able to pay maturing notes and redeem other notes mainly with additional equity investments by Puget Energy in 2003 and 2002.
Preferred stock dividendsdecreased $2.6 million in 2003 compared to 2002 due to the redemption of the 7.45% series preferred stock not subject to mandatory redemption for both sinking fund requirements and total redemption of the remaining shares in the series at par value plus accrued dividends in 2003.
INFRASTRUX
2003 COMPARED TO 2002
The table below sets forth significant changes in revenues and expenses for InfrastruX from 2002 to 2003.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | | 2003 | | 2002 | | CHANGE | | PERCENT CHANGE | |
| Non-utility construction services revenue | | $ | 341.8 | | $ | 319.5 | | $ | 22.3 | | | 7.0 | % |
| | | | | | | | | | | | | | |
| Other operations and maintenance | | $ | 302.4 | | $ | 270.7 | | $ | 31.7 | | | 11.7 | % |
| Depreciation and amortization | | | 16.8 | | | 13.5 | | | 3.3 | | | 24.4 | |
| Income taxes | | | 1.6 | | | 6.7 | | | (5.1 | ) | | (76.1 | ) |
Non-utility construction services revenue increased $22.3 million in 2003 due primarily to acquisitions of several companies during 2002 and 2003, which contributed to an increase of $44.4 million. Excluding the impact of acquisitions, InfrastruX revenue decreased $22.1 million from 2002 due primarily to general market weakness and changing activities on certain lines of business. InfrastruX records revenues as services are performed or on a percent of completion basis for fixed-price projects.
Other operations and maintenance expenses increased $31.7 million in 2003 compared to 2002 due primarily to acquisitions of several companies during 2002 and 2003, which contributed to an increase of $37.1 million. Excluding the impact of acquisitions, operations and maintenance expenses decreased $5.4 million from 2002 due to lower productivity. The decrease, excluding the impact of acquisitions, was not proportionate to the decline in revenues due to the impact of severe wet weather on productivity during the first quarter 2003 as well as the high costs of completing work in low-volume activities in 2003.
Depreciation and amortization expense increased by $3.3 million in 2003 compared to 2002 due to acquisitions during 2003 and 2002, which were not owned during the full year of 2002.
Income taxes decreased $5.1 million in 2003 compared to 2002 due to lower income.
CAPITAL RESOURCES AND LIQUIDITYLiquidity
CAPITAL REQUIREMENTSCapital Requirements
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTSContractual Obligations and Commercial Commitments
Puget Energy. The following are Puget Energy’s aggregate consolidated (including PSE) contractual obligations and commercial commitments as of December 31, 2004:31:
Puget Energy | | | | |
CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter |
| Long-term debt | $ | 2,251.4 | $ | 38.9 | $ | 552.0 | $ | 339.5 | $ | 1,321.0 |
| Short-term debt | | 8.3 | | 8.3 | | -- | | -- | | -- |
Junior subordinated debentures payable to a subsidiary trust1 | | 280.3 | | -- | | -- | | -- | | 280.3 |
| Mandatorily redeemable preferred stock | | 1.9 | | -- | | -- | | -- | | 1.9 |
| Service contract obligations | | 168.6 | | 21.5 | | 48.6 | | 47.7 | | 50.8 |
| Capital lease obligations | | 7.0 | | 2.0 | | 3.6 | | 1.4 | | -- |
| Non-cancelable operating leases | | 129.5 | | 19.3 | | 37.3 | | 26.8 | | 46.1 |
Fredonia combustion turbines lease2 | | 65.3 | | 4.6 | | 8.6 | | 8.3 | | 43.8 |
| Energy purchase obligations | | 4,988.2 | | 929.4 | | 1,491.0 | | 1,278.2 | | 1,289.6 |
| Financial hedge obligations | | 20.0 | | 6.2 | | 11.9 | | 1.9 | | -- |
| Pension funding | | 45.7 | | 4.3 | | 8.2 | | 9.8 | | 23.4 |
| Total contractual cash obligations | $ | 7,966.2 | $ | 1,034.5 | $ | 2,161.2 | $ | 1,713.6 | $ | 3,056.9 |
| Puget Energy | | Payments Due Per Period |
Contractual Obligations (Dollars in Millions) | | | Total | | | 2007 | | | 2008- 2009 | | | 2010- 2011 | | | 2012 & Thereafter |
| Long-term debt including interest | | $ | 5,444.4 | | $ | 294.9 | | $ | 654.8 | | $ | 741.0 | | $ | 3,753.7 |
| Short-term debt including interest | | | 328.1 | | | 328.1 | | | -- | | | -- | | | -- |
Junior subordinated debentures payable to a subsidiary trust including interest1 | | | 101.2 | | | 3.1 | | | 6.2 | | | 6.2 | | | 85.7 |
| Mandatorily redeemable preferred stock | | | 1.9 | | | -- | | | -- | | | -- | | | 1.9 |
| Service contract obligations | | | 159.8 | | | 30.7 | | | 69.0 | | | 45.6 | | | 14.5 |
| Non-cancelable operating leases | | | 120.3 | | | 15.5 | | | 50.3 | | | 21.4 | | | 33.1 |
Fredonia combustion turbines lease 2 | | | 65.4 | | | 6.1 | | | 12.5 | | | 46.8 | | | -- |
| Energy purchase obligations | | | 6,176.3 | | | 1,001.1 | | | 1,666.3 | | | 992.3 | | | 2,516.6 |
| Contract initiation payment/collateral requirement | | | 18.5 | | | -- | | | -- | | | 18.5 | | | -- |
| Financial hedge obligations | | | 3.6 | | | 2.2 | | | 1.4 | | | -- | | | -- |
| Purchase obligations | | | 44.6 | | | 10.5 | | | 34.1 | | | -- | | | -- |
| Non-qualified pension and other benefits funding and payments | | | 47.2 | | | 6.6 | | | 7.4 | | | 9.1 | | | 24.1 |
| Total contractual cash obligations | | $ | 12,511.3 | | $ | 1,698.8 | | $ | 2,502.0 | | $ | 1,880.9 | | $ | 6,429.6 |
| Puget Energy | | Amount of Commitment Expiration Per Period |
Commercial Commitments (Dollars in Millions) | | | Total | | | 2007 | | | 2008- 2009 | | | 2010- 2011 | | | 2012 & Thereafter |
Indemnity agreements 3 | | $ | 8.8 | | $ | -- | | $ | 3.8 | | $ | -- | | $ | 5.0 |
Credit agreement - available 4 | | | 281.5 | | | -- | | | -- | | | 281.5 | | | -- |
Receivable securitization facility5 | | | 90.0 | | | -- | | | -- | | | 90.0 | | | -- |
| Energy operations letter of credit | | | 0.5 | | | 0.5 | | | -- | | | -- | | | -- |
| Total commercial commitments | | $ | 380.8 | | $ | 0.5 | | $ | 3.8 | | $ | 371.5 | | $ | 5.0 |
| | | | Amount of Committment Expiration Per Period |
COMMERCIAL COMMITMENTS | Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter |
Guarantees3 | $ | 131.0 | $ | -- | $ | 131.0 | $ | -- | $ | -- |
Liquidity facilities - available4 | | 349.5 | | -- | | 349.5 | | -- | | -- |
Lines of credit - available5 | | 53.6 | | 25.4 | | 28.2 | | -- | | -- |
| Energy operations letter of credit | | 0.5 | | 0.5 | | -- | | -- | | -- |
| Total commercial commitments | $ | 534.6 | $ | 25.9 | $ | 508.7 | $ | -- | $ | -- |
_______________________ _______________
1 | In 1997, and 2001, PSE formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling preferred securities (Trust Securities) to investors and issuing common securities to PSE. The proceeds from the sale of Trust Securities were used by the TrustsTrust to purchase Junior Subordinated Debentures (Debentures) from PSE. The Debentures are the sole assets of the Trusts and PSE owns all common securities of the Trusts. |
2 | See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below. |
3 | In May 2004, InfrastruX signed a three-year credit agreement with a group of banks to provide up to $150 million in financing. Under the creditInfrastruX sale agreement, Puget Energy is the guarantorobligated for certain representations and warranties concerning InfrastruX’s business and anti-trust inquiries. The fair value of the line of credit. Certain InfrastruX subsidiaries also have certain borrowing capacities for working capital purposes of whichbusiness warranty is $3.8 million at December 31, 2006 and the obligation expires on May 7, 2008. Puget Energy is not a guarantor.also agreed to indemnify the buyer relating to an inquiry of an InfrastruX subsidiary and the fair value of the warranty was $5.0 million at December 31, 2006. See “InfrastruX” above for further discussion.
|
4 | At December 31, 2004,2006, PSE had available a $350$500.0 million unsecured credit agreement expiring in June 2007April 2011. The credit agreement provides credit support for letters of credit and commercial paper. At December 31, 2006, PSE had $0.5 million for an outstanding letter of credit and $218.0 million commercial paper outstanding, effectively reducing the available borrowing capacity to $281.5 million. |
5 | At December 31, 2006, PSE had available a $150$200.0 million receivables securitization facility that expires in December 2005. At2010. $110.0 million was outstanding under the receivables securitization facility at December 31, 2004, PSE had no amounts2006 thus leaving $90.0 million available. The facility allows receivables to be used as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables, available for sale under its receivables securitization facility.which fluctuate with the seasonality of energy sales to customers. See “Accounts Receivable“Receivables Securitization Program” under “Off-Balance Sheet Arrangements”Facility" below for further discussion. The credit agreement and securitization facility provide credit support for an outstanding letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under these liquidity facilities to $349.5 million. |
5 | Puget Energy has a $15 million line of credit with a bank. At December 31, 2004, $5.0 million was outstanding, leaving $10.0 million available to borrow under the agreement. Puget Energy reduced the borrowing capacity under this line of credit to $5.0 million on February 1, 2005. InfrastruX has $186.7 million in lines of credit with various banks to fund capital credit requirements of InfrastruX and its subsidiaries. InfrastruX and its subsidiaries had $139.3 million outstanding under their credit agreements and letters of credit of $3.8 million at December 31, 2004, effectively reducing the available borrowing capacity under these lines of credit to $43.6 million.
|
Puget Sound Energy. The following are PSE’s aggregate contractual obligations and commercial commitments as of December 31:
Puget Sound Energy | | Payments Due Per Period |
Contractual Obligations (Dollars in Millions) | | | Total | | | 2007 | | | 2008- 2009 | | | 2010- 2011 | | | 2012 & Thereafter |
| Long-term debt including interest | | $ | 5,444.4 | | $ | 294.9 | | $ | 654.8 | | $ | 741.0 | | $ | 3,753.7 |
| Short-term debt including interest | | | 352.5 | | | 352.5 | | | -- | | | -- | | | -- |
Junior subordinated debentures payable to a subsidiary trust including interest1 | | | 101.2 | | | 3.1 | | | 6.2 | | | 6.2 | | | 85.7 |
| Mandatorily redeemable preferred stock | | | 1.9 | | | -- | | | -- | | | -- | | | 1.9 |
| Service contract obligations | | | 159.8 | | | 30.7 | | | 69.0 | | | 45.6 | | | 14.5 |
| Non-cancelable operating leases | | | 120.3 | | | 15.5 | | | 50.3 | | | 21.4 | | | 33.1 |
Fredonia combustion turbines lease 2 | | | 65.4 | | | 6.1 | | | 12.5 | | | 46.8 | | | -- |
| Energy purchase obligations | | | 6,176.3 | | | 1,001.1 | | | 1,666.3 | | | 992.3 | | | 2,516.6 |
| Contract initiation payment/collateral requirement | | | 18.5 | | | -- | | | -- | | | 18.5 | | | -- |
| Financial hedge obligations | | | 3.6 | | | 2.2 | | | 1.4 | | | -- | | | -- |
| Purchase obligations | | | 44.6 | | | 10.5 | | | 34.1 | | | -- | | | -- |
| Non-qualified pension and other benefits funding and payments | | | 47.2 | | | 6.6 | | | 7.4 | | | 9.1 | | | 24.1 |
| Total contractual cash obligations | | $ | 12,535.7 | | $ | 1,723.2 | | $ | 2,502.0 | | $ | 1,880.9 | | $ | 6,429.6 |
Puget Sound Energy. The following are PSE’s aggregate contractual and commercial commitments as of December 31, 2004:2006:
Puget Sound Energy | | | | Payments Due Per Period |
CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter |
| Long-term debt | $ | 2,095.4 | $ | 31.0 | $ | 406.0 | $ | 337.4 | $ | 1,321.0 |
Junior subordinated debentures payable to a subsidiary trust1 | | 280.3 | | -- | | -- | | -- | | 280.3 |
| Mandatorily redeemable preferred stock | | 1.9 | | -- | | -- | | -- | | 1.9 |
| Service contract obligations | | 168.6 | | 21.5 | | 48.6 | | 47.7 | | 50.8 |
| Non-cancelable operating leases | | 116.4 | | 12.8 | | 31.6 | | 26.0 | | 46.0 |
Fredonia combustion turbines lease2 | | 65.3 | | 4.6 | | 8.6 | | 8.3 | | 43.8 |
| Energy purchase obligations | | 4,988.2 | | 929.4 | | 1,491.0 | | 1,278.2 | | 1,289.6 |
| Financial hedge obligations | | 20.0 | | 6.2 | | 11.9 | | 1.9 | | -- |
| Pension funding | | 45.7 | | 4.3 | | 8.2 | | 9.8 | | 23.4 |
| Total contractual cash obligations | $ | 7,781.8 | $ | 1,009.8 | $ | 2,005.9 | $ | 1,709.3 | $ | 3,056.8 |
Puget Sound Energy | Amount of Commitment Expiration Per Period |
Commercial commitments (Dollars in Millions) | | | Total | | | 2007 | | | 2008- 2009 | | | 2010- 2011 | | | 2012 & Thereafter |
Credit agreement - available 3 | | $ | 281.5 | | $ | -- | | $ | -- | | $ | 281.5 | | $ | -- |
Receivable securitization facility4 | | | 90.0 | | | -- | | | -- | | | 90.0 | | | -- |
| Energy operations letter of credit | | | 0.5 | | | 0.5 | | | -- | | | -- | | | -- |
| Total commercial commitments | | $ | 372.0 | | $ | 0.5 | | $ | -- | | $ | 371.5 | | $ | -- |
| | | | | Amount of Commitment Expiration Per Period |
| Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter |
Liquidity facilities - available3 | $ | 349.5 | $ | -- | $ | 349.5 | $ | -- | $ | -- |
| Energy operations letter of credit | | 0.5 | | 0.5 | | -- | | -- | | -- |
| Total commercial commitments | $ | 350.0 | $ | 0.5 | $ | 349.5 | $ | -- | $ | -- |
______________________________________
3 | See note 4 above. |
4 | See note 5 above. |
OFF-BALANCE SHEET ARRANGEMENTSOff-Balance Sheet Arrangements
ACCOUNTS RECEIVABLE SECURITIZATION PROGRAMFredonia 3 and 4 Operating Lease
In order to provide a source of liquidity to PSE at an attractive cost, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE in December 2002. Pursuant to the Receivables Sales Agreement, PSE sold all its utility customers’ accounts receivable and unbilled utility revenues to Rainier Receivables. Concurrently with entering into the Receivables Sales Agreement, Rainier Receivables entered into a Receivables Purchase Agreement with PSE and a third party. The Receivables Purchase Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the third party. The amount of receivables sold by Rainier Receivables is not permitted to exceed $150 million at any time. However, the maximum amount may be less than $150 million depending on the outstanding eligible amount of PSE’s receivables, which fluctuate with the seasonality of energy sales to customers.
The receivables securitization facility is the functional equivalent of a revolving line of credit secured by receivables. In the event Rainier Receivables elects to sell receivables under the Receivables Purchase Agreement, Rainier Receivables is required to pay fees to the purchasers that are comparable to interest rates on a revolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables held by the purchasers declines until Rainier Receivables elects to sell additional receivables to the purchasers.
The receivables securitization facility expires in December 2005, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At December 31, 2004, Rainier Receivables had fully utilized its $150 million available balance under the receivable securitization facility, and therefore had no additional available balances to be sold under it.
During the years ended December 31, 2004 and 2003, Rainier Receivables sold a cumulative $600.2 million and $348.0 million of receivables, respectively.
FREDONIA 3 AND 4 OPERATING LEASE.
PSE leases two combustion turbines for its Fredonia 3 and 4 electric generating facility pursuant to a master operating lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE at any time. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At December 31, 2004,2006, PSE’s outstanding balance under the lease was $56.3$51.1 million. The expected residual value under the lease is the lesser of $37.4 million or 60%60.0% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87%87.0% of the unamortized value of the equipment.
UTILITY CONSTRUCTION PROGRAMUtility construction Program
Utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficienciessupport reliability of PSE’s energy delivery systems. Construction expenditures, excluding equity AllowanceAFUDC and customer refundable contributions, were $575.1 million for Funds Used During Construction (AFUDC), were $393.9 million in 2004.2006. Utility construction expenditures, in 2005, 2006excluding AFUDC and 2007 are expected to be $380 million, $400 million and $384 million, respectively, excluding amounts for new generation resources currently under evaluation. New generation resources under evaluation consist of two separate wind generation projects thatother than the Wild Horse project (which will be determined as the company proceeds through the integrated resource planning process) are anticipated to be completedthe following in 20052007, 2008 and 2006, respectively. The first project, if completed in 2005, is anticipated to have a total cost of approximately $200 million. The second project, if completed in 2006, is anticipated to have a total cost range of approximately $300 to $350 million. 2009:
Capital Expenditure Projections (Dollars in Millions) | | 2007 | | 2008 | | 2009 | |
| Energy delivery, technology and facilities | | $ | 530 | | $ | 555 | | $ | 640 | |
| New resources | | | 120 | | | 70 | | | 210 | |
| Total expenditures | | $ | 650 | | $ | 625 | | $ | 850 | |
The proposed utility construction expenditures and any new generation resource expenditures if acquired,that may be incurred are anticipated to be funded with a combination of cash from operations, short-term debt, long-term debt and equity. Construction expenditure estimates, including the new generation resources, are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.
NEW GENERATION RESOURCESNew Generation Resources
In April 2004,On December 22, 2006, PSE completedplaced into service the purchase of a 49.85% interest in Frederickson 1, a gas-fired electric generating station located in western Washington. The purchase has added $80.8 million in utility plant and approximately 124 MW of electric generation capacity to serve PSE’s retail customers. PSE submitted a PCORC in October 2003 to the Washington Commission to recover the cost of the new generating facility and other power costs. The acquisition of Frederickson 1 was approved by the Washington Commission on April 7, 2004 and was also approved by FERC under the Federal Power Act on April 23, 2004.
In September and October 2004, PSE signed two non-binding letters of intent to obtain a 100% ownership interest in both the proposed Wild Horse wind power project (Wildproject. Wild Horse project) and the Hopkins Ridge wind power project (Hopkins Ridge project). The projects areis located in central and eastern Washington State. The Wild Horse wind project is expectedfeatures 127 turbines providing up to have approximately 100229 MW, generating enough wind-fueled electricity on average to 130 wind turbinesserve 76,000 of the Company’s electric customers in Western Washington and generate from 150 to 230 MW of power or 77 average MW, depending on the final design agreement. The Hopkins Ridge project is expected to generate approximately 150 MW of power or 52 average MW. Both projects will require final binding agreements between PSE and the developers. Such agreements are expected to be executed in 2005.Kittitas County.
OTHER ADDITIONS
Other property, plant and equipment additions were $15.5 million in 2004. Puget Energy expects InfrastruX’s capital additions to be $18.0 million in 2005. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.
CAPITAL RESOURCESCapital Resources
CASH FROM OPERATIONSCash From Operations
Cash generated from operations for 2006 was $185.5 million, which is 23.7% of the year ended December 31, 2004 was $456.4 million. During that period, $92.3$783.4 million in cash was used for AFUDC and payment of dividends. Consequently, cash flows available for utility construction expenditures and other capital expenditures were $364.1 million or 87.7% of the $415.4 million in construction expenditures (net of AFUDC and customer refundable contributions) and other capital expenditure requirements for 2004.expenditures. For the year ended December 31, 2003,2005, cash generated from operations was $317.9$255.8 million $90.0which is 42.1% of the $608.0 million of which was used for AFUDC and payment of dividends. Therefore, cash flows available for utility construction expenditures and other capital expenditures were $227.9 million, or 77.1% of the $295.7 million in construction expenditures (net of AFUDC and customer refundable contributions) and other capital expenditure requirements for 2003. expenditures.
The overall cash generated from operating activities in 2004 increased $138.5for 2006 decreased $70.3 million compared to 2003.2005. The increasedecrease was partially the resultprimarily attributable to deferred storm damage costs of increases in PGA rates$92.3 million and to a non-refundable capacity reservation payment of $89.0 million in April 2003, October 20032006 for the Chelan PUD power sales agreement which will begin providing power to PSE at the end of 2011. In addition, $37.7 million of cash collateral related to natural gas supply contracts was returned in 2006 and October 2004, combined with lower$55.0 million was received in 2005 for funds received from a gas pipeline capacity contract obligation of Duke Energy Marketing and Trading. Further, there was an increase of $83.4 million in payments made for accounts payable related to energy purchases which contributed to the decrease. Partially offsetting the decrease was an increase in accounts receivable balances of $139.7 million as compared to 2005 which was primarily attributable to the change in the accounts receivable securitization program. In addition, there was an increase in cash paid underreceived for the PGA mechanism for liability balancespurchased gas receivable adjustment of $75.8 million, a beneficial increase in 2003 forthe change of the power cost adjustment of $30.4 million, an increase in accrued expenses of $15.9 million and a total positivedecrease in BPA prepaid transmission of $10.8 million in 2005 that further offset the decrease in cash flow of $40.8 million. Cashgenerated from operating activities also increased $27.7 million due to higher cash payments received from BPA than provided to customers under the residential exchange program compared to 2003 when PSE provided customers more cash than BPA paid to PSE. In addition, changes in deferred taxes contributed $15.2 million to positive cash flow. In 2004, PSE did not fund the qualified pension plan compared to funding $26.5 million in 2003, which positively impacted cash flow from operating activities. Cash flow from operating activities also improved $27.7 million through recovery of collateral deposits in 2004 compared to a return of collateral deposits in 2003 from energy supply counterparties.
FINANCING PROGRAMFinancing Program
Financing utility construction requirements and operational needs are dependent upon the cost and availability of external funds through capital markets and from financial institutions. Access to funds is dependentdepends upon factors such as general economic conditions, regulatory authorizations and policies and Puget Energy’s and PSE’s credit ratings.
RESTRICTIVE COVENANTSRestrictive Covenants
In determining the type and amount of future financing, PSE may be limited by restrictions contained in its electric and gas mortgage indentures, restated articles of incorporation and certain loan agreements. The goodwill impairment at Puget Energy does not cause any violations of financial covenants at Puget Energy or PSE. Under the most restrictive tests, at December 31, 2004,2006, PSE could issue:
| · | approximately $281$262.0 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $468$437.0 million of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, 2004;2006; |
| · | approximately $417$365.0 million of additional first mortgage bonds under PSE’s gas mortgage indenture based on approximately $695$608.0 million of gas bondable property available for issuance, subject to an interest coverage ratio limitationlimitations of 1.75 times and 2.0 times net earnings available for interest (as defined in the gas utility mortgage), which PSE exceeded at December 31, 2004;2006; |
| · | approximately $486.3$802.8 million of additional preferred stock at an assumed dividend rate of 6.625%6.5%; and |
| · | approximately $273.2$688.8 million of unsecured long-term debt. |
At December 31, 2004,2006, PSE had approximately $3.6$4.0 billion in electric and gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest. SFAS No. 158 will not have an impact on PSE’s ratebase.
CREDIT RATINGSCredit Ratings
Neither Puget Energy nor PSE has had any rating downgrade triggers that would accelerate the maturity dates of outstanding debt. However, a downgrade in the companies’ credit ratings could adversely affect their ability to renew existing, or obtain access to new, credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the spreads over the index and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. In addition, downgrades in any or a combination of PSE’s debt ratings may allow counterparties on a contract by contract basis in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security.
The ratings of Puget Energy and PSE, as of February 23, 2005,21, 2007, were:
| | Ratings |
| | Standard & Poor’s | Moody’s |
Puget Sound Energy | | |
| Corporate credit/issuer rating | BBB- | Baa3 |
| Senior secured debt | BBB | Baa2 |
| Shelf debt senior secured | BBB | (P)Baa2 |
| Trust preferred securities | BB | Ba1 |
| Preferred stock | BB | Ba2 |
| Commercial paper | A-3 | P-2 |
| Revolving credit facility | * | Baa3 |
| Ratings outlook | PositiveStable | Stable |
Puget Energy | | |
| Corporate credit/issuer rating | BBB- | Ba1 |
______________________________________
| * | *Standard & Poor’s does not rate PSE’s credit facilities.
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Neither Puget Energy nor PSE has any debt outstanding that would accelerate debt maturity upon a credit rating downgrade. However, a ratings downgrade could adversely affect the ability to renew existing, or obtain access to new, credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the borrowing costs and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. In addition, downgrades in any or a combination of PSE’s debt ratings may prompt counterparties on a contract by contract basis in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security.
SHELF REGISTRATIONS, LONG-TERM DEBT AND COMMON STOCK ACTIVITYShelf Registrations, Long-Term Debt and Common Stock Activity
In January 2004,On March 16, 2006, Puget Energy and PSE filed a shelf registration statement with the Securities and Exchange Commission for the offering on a delayed or continuous basis, of up to $500 million of:
| · | common stock of Puget Energy, andEnergy; |
| · | senior notes of PSE, secured by a pledge of PSE’s first mortgage bonds. |
On July 15, 2004, PSE issued $200 million in floating rate senior notes under its existing $500 million shelf registration statement, reducing the available balance for issuance under the shelf registration statement to $300 million. The notes float at the three-month LIBOR rate plus 0.30%, (2.37% at December 31, 2004), mature on July 14, 2006, and can be redeemed at par any time after January 15, 2005. PSE used the net proceeds from the sale of the floating rate senior notes to repay outstanding amounts under its commercial paper and accounts receivable securitization programs, including amounts incurred to repay long-term debt, and also used the proceeds to redeem $55 million in principal of first mortgage bonds at a premium of 3.68% on August 14, 2004. It is anticipated that the $200 million in floating rate senior notes will be paid off with a combination of long-term debt and internally generated funds.
During 2004, PSE redeemed the following long-term debt:
· | $18.5 million medium term notes with interest rates ranging from 6.07% to 6.10%;bonds; |
| · | $30.0 million medium term notes at an interest ratepreferred stock of 7.80% in May 2004; |
· | $4.2 million conservation trust bonds at an interest rate of 6.45% during 2004; |
· | $55.0 million medium term notes at an interest rate of 7.35% in August 2004;PSE; and |
| · | $50.0 million medium term notes at an interest ratetrust preferred securities of 7.70% in December 2004.Puget Sound Energy Capital Trust III. |
The registration statement is valid for three years and does not specify the amount of securities that the Company may offer. The Company is subject to restrictions under PSE’s indentures and articles of incorporation on the amount of first mortgage bonds, unsecured debt and preferred stock that the Company may issue.
On September 18, 2006, PSE completed the issuance of $300.0 million of senior secured notes at a rate of 6.274%, which are due on March 15, 2037. The net proceeds from the issuance of the senior notes of approximately $297.4 million will be used to repay PSE’s outstanding short-term debt which was incurred primarily to fund construction programs. The yield to maturity of the $300.0 million senior secured notes was 6.29% after the settlement of two forward starting swap contracts.
On June 30, 2006, PSE redeemed for $200.0 million all of the outstanding shares of 8.40% Trust Originated Preferred Securities of The Puget Sound Energy Capital Trust II (classified as Junior Subordinated Debentures of the Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities on the balance sheet) at $25.0 par value per share plus accrued interest to the redemption date.
On June 30, 2006, PSE completed the issuance of $250.0 million of senior secured notes at a rate of 6.724% which are due on June 15, 2036. The net proceeds from the issuance of the senior notes of approximately $247.8 million were used to redeem $200.0 million of 8.40% Trust Originated Preferred Securities of the Puget Sound Energy Capital Trust II, which were redeemed at par on June 30, 2006, and to repay a portion of PSE’s short-term debt. The short-term debt was incurred to repay $46.0 million of 8.06% senior notes that matured June 19, 2006. The yield to maturity of the $250.0 million senior secured notes was 6.17% after the settlement of two forward starting swap contracts.
Based on PSE's goal to become a more vertically integrated utility, it is expected that further issuances of debt, equity or a combination of the two will be necessary in the future. The structure, timing and amount of such financings depend on market conditions and financing needed.
LIQUIDITY FACILITIES AND COMMERCIAL PAPERLiquidity Facilities and Commercial Paper
PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs.
In May 2004,
PSE Credit Facilities
The Company has two committed credit facilities that provide, in aggregate, $700.0 million in short-term borrowing capability. These include a $500.0 million credit agreement and a $200.0 million accounts receivable securitization facility. The unsecured credit agreement can be terminated by either party upon written notice. PSE pays a varying interest rate on outstanding borrowings based on terms entered into at the time of the borrowings.
Demand Promissory Note. On June 1, 2006, PSE entered into a three-year, $350revolving credit facility with its parent, Puget Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE may borrow up to $30.0 million from Puget Energy, subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted average interest rate of (a) PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) the interest rate available under the receivable securitization facility of PSE Funding, Inc., a PSE subsidiary, which is the LIBOR rate plus a marginal rate. At December 31, 2006, the outstanding balance of the Note was $24.3 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.
Credit Agreement. In March 2005, PSE entered into a five-year, $500.0 million unsecured credit agreement with a group of banks which replaced its previous $250 million unsecured credit agreement.banks. In April 2006, PSE also has a $150 million receivables securitization program which expires in December 2005. At December 31, 2004, PSE had available $350 million in the unsecuredamended this credit agreement and no amounts under its $150 million receivable securitization facility, both of whichto extend the expiration date from April 2010 to April 2011. The agreement is primarily used to provide credit support for outstanding commercial paper and outstanding letters of credit. Under the terms of the credit agreement, PSE pays a floating interest rate on outstanding borrowings based either on the agent bank’s prime rate or on LIBOR plus a marginal rate based on PSE’s long-term credit rating at the time of borrowing. PSE pays a commitment fee on any unused portion of the credit agreement which is also based on long-term credit ratings of PSE. At December 31, 2004,2006, there was $0.5 million outstanding under a letter of credit and no$218.0 million commercial paper outstanding, effectively reducing the available borrowing capacity under these liquidity facilitiesthe credit facility to $349.5$281.5 million.
In May 2004, InfrastruX
Receivables Securitization Facility. PSE entered into a three-year, $150 million credit agreementfive-year Receivable Sales Agreement with PSE Funding, Inc. (PSE Funding), a groupwholly owned subsidiary, on December 20, 2005. Pursuant to the Receivables Sales Agreement, PSE sells all of banks, replacing its previous $150 million credit agreement. Puget Energy is the guarantor of the line of credit.utility customer accounts receivable and unbilled utility revenues to PSE Funding. In addition, InfrastruX’s subsidiaries have an additional $36.7PSE Funding entered into a Loan and Servicing Agreement with PSE and two banks. The Loan and Servicing Agreement allows PSE Funding to use the receivables as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables which fluctuate with the seasonality of energy sales to customers. All loans from this facility will be reported as short-term debt in the financial statements.
The PSE Funding facility expires in December 2010, and is terminable by PSE and PSE Funding upon notice to the banks. During 2006, PSE Funding borrowed a cumulative amount of $441.0 million secured by accounts receivable. There was $110.0 million in lines of credit with various banks, for a total capacity for InfrastruX and its subsidiaries of $186.7 million under their line of credit agreements. Borrowings available for InfrastruX are used to fund acquisitions and working capital requirements of InfrastruX and its subsidiaries. At December 31, 2004, InfrastruX and its subsidiaries had $139.3 million outstanding under their credit agreements and letters of credit of $3.8 million, effectively reducing the available borrowing capacity under these lines of credit to $43.6 million.
Puget Energy has a $15 million credit agreement expiring in May 2006 with a bank. On February 1, 2005, Puget Energy reduced the borrowing capacity of this credit agreement to $5.0 million. Under the terms of the agreement, Puget Energy pays a floating interest rate on borrowings based on LIBOR. The interest rate is set for one, two, or three-month periods at the option of Puget Energy with interest due at the end of each period. Puget Energy also pays a commitment fee on any unused portion of the credit facility. Puget Energy had $5.0 million outstanding under the credit agreementloans that were secured by accounts receivable pledged at December 31, 2004.2006. The borrowing available under the receivables securitization at December 31, 2006 was $90.0 million.
STOCK PURCHASE AND DIVIDEND REINVESTMENT PLANStock Purchase and Dividend Reinvestment Plan
Puget Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy’s common stock. Since new shares of common stock may be purchased directly from Puget Energy, funds received may be used for general corporate purposes. Puget Energy issued common stock from the Stock Purchase and Dividend Reinvestment Plan of $15.2$13.5 million (681,491(615,648 shares) in 20042006 compared to $15.5$14.5 million (721,340(656,267 shares) in 2003.2005. The proceeds from sales of stock under these plans are used for general corporate needs.
COMMON STOCK OFFERING PROGRAMSCommon Stock Offering Programs
To provide additional financing options, Puget Energy entered into agreements in July 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to time through these institutions as sales agents, or as principals. Sales of the common stock, if any, may be made by means of negotiated transactions or in transactions that may be deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under the Securities Act of 1933, including in ordinary brokers’ transactions on the New York Stock Exchange (NYSE) at market prices.
OTHEROther
TENASKA DISALLOWANCEIRS Audit. As a matter of course, the Company’s tax returns are routinely audited by federal, state and city tax authorities. In May of 2006, the IRS completed its examination of the company’s 2001, 2002 and 2003 federal income tax returns. The Company is formally appealing two IRS audit adjustments. The first adjustment relates to the receivable balance due from the California Independent System Operator (CAISO). The IRS claims that the deduction was not valid for the 2003 tax year and would require repayment of approximately $14.5 million in tax. The Company believes the deduction is valid and intends to vigorously defend the deduction. Any potential tax payment (excluding interest) would have no impact on earnings, as it would be recognized as a deferred tax asset. If the Company is unsuccessful, a charge for interest expense would apply.
The second IRS audit adjustment relates to the company’s accounting method with respect to capitalized internal labor and overheads. In its 2001 tax return, PSE claimed a deduction when it changed its tax accounting method with respect to capitalized internal labor and overheads. Under the new method, the Company could immediately deduct certain costs that it had previously capitalized. In the audit, the IRS disallowed the deduction. On August 2, 2005, the Internal Revenue Service and the Treasury Department issued Revenue Ruling 2005-53 and related Regulations. The Revenue Ruling and the Regulations required utility companies, including PSE, to adopt a less advantageous method of accounting and to repay the accumulated tax benefits. Through September 30, 2005, the Company claimed $66.3 million in accumulated tax benefits. PSE accounted for the accumulated tax benefits as temporary differences in determining its deferred income tax balances. Consequently, the repayment of the tax benefits did not impact earnings but did have a cash flow impact of $33.2 million in the fourth quarter 2005 and $33.1 million in 2006. As of December 31, 2006, the full tax benefit had been repaid. There is some uncertainty in the new guidance. PSE believes that the new Regulations required the Company to repay the accumulated tax benefits over the 2005 and 2006 tax years and that the tax deductions claimed on the Company’s tax returns were appropriate based on the applicable statutes, Regulations and case law in effect at the time. However, there is no assurance that PSE’s appeal will prevail. If the Company is unsuccessful, a charge for interest expense would apply.
On October 19, 2005, PSE filed an accounting petition with the Washington Commission to defer the capital costs associated with repayment of the deferred tax. The Washington Commission had reduced PSE’s ratebase by $72.0 million in its order of February 18, 2005. The accounting petition was approved by the Washington Commission on October 26, 2005, for deferral of additional capital costs beginning November 1, 2005 using PSE’s allowed net of tax rate of return. The Washington Commission granted cost recovery of these deferred carrying costs over two years, beginning January 13, 2007.
Tenaska Disallowance.The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a disallowance of $25.6 million foraccumulated costs under the PCA 1 period (July 1, 2002 through June 30, 2003), which was recorded by PSE as a Purchased Electricity expense in the second quarter 2004. The order also established guidelinesmechanism for future recovery of Tenaskathese excess costs. The amounts were determined to be a $25.6 million disallowance for the PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period (July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s methodology of 50% disallowance on the return on the Tenaska regulatory asset due to projected costs exceeding the benchmark during the period. For the PCA 3 period, approximately $5.6 million was disallowedincrease in the period July 1, 2004 through December 31, 2004, primarily as a reduction to Electric Operating Revenue. While the Washington Commission did not expressly addresspurchased electricity expense resulting from the disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE estimated the disallowance for the PCA 2 period to be approximately $12.2totaled $9.0 million, if the Washington Commission were to follow the same methodology as they have ordered for the PCA 3 period. Therefore, PSE recorded a $12.2$4.1 million disallowance to Purchased Electricity expense in the second quarter 2004 for the 50% disallowance of the return on the Tenaska regulatory asset in accordance with the Washington Commission’s methodology discussed in its order of May 13, 2004 for a cumulative impact on earnings ofand $43.4 million in 2006, 2005 and 2004, for the PCA 1, PCA 2 and PCA 3 periods. As a result of the disallowance recorded, the PCA customer deferral was expensed and a reserve was established for amounts not previously deferred under the PCA mechanism.respectively. The reserve balance as of December 31, 2004 was $3.2 million, which is expected to be utilized in 2005 as excess power costs are shared through the PCA mechanism.
PSE filed the PCA 2 period compliance filing in August 2004 and received an order from the Washington Commission on February 23, 2005. In the PCA 2 compliance order, the Washington Commission approved the Washington Commission staff’s recommendation for an additional return related to the Tenaska regulatory asset in the amount of $6.1 million related to the period July 1, 2003 through December 31, 2003. Washington Commission staff’s recommendation was opposed by certain other parties. This amount alters the PCA deferral and is subject to reconsideration and appeal by other parties. Parties have 10 days from February 23, 2005 to file for reconsideration and 30 days to appeal the order. Once the statutory appeal process has concluded and the Washington Commission issues its final order, PSE will determine if recording a regulatory asset is appropriate.
In the May 13, 2004 order, the Washington Commissionalso established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
Below is a summary ofIn August 2004 PSE filed the Tenaska disallowances by quarter through December 31, 2004:
(DOLLARS IN MILLIONS) QUARTER ENDING | 7/02 - 6/03 PCA 1 (ordered/final) | 7/03 - 6/04 PCA 2 (estimated) | 7/04 - 12/04 PCA 3 (estimated) | Total |
| June 30, 2004 | $ 25.6 | $ 12.2 | $ -- | $ 37.8 |
| September 30, 2004 | -- | -- | 2.8 | 2.8 |
| December 31, 2004 | -- | -- | 2.8 | 2.8 |
| Total | $ 25.6 | $ 12.2 | $ 5.6 | $ 43.4 |
ThePCA 2 period compliance and received an order from the Washington Commission guidelineson February 23, 2005. In the PCA 2 compliance order, the Washington Commission approved the Washington Commission staff’s recommendation for determining future recovery of the Tenaska costs (gas costs, recovery ofan additional return related to the Tenaska regulatory asset and return onin the Tenaska regulatory asset) are as follows:
1. | The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
2. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will fully recover its Tenaska costs. |
3. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
a) | actual Tenaska costs that exceed the benchmark; or |
b) | the return on the Tenaska regulatory asset. |
4. | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs. |
amount of $6.0 million related to the period July 1, 2003 through December 31, 2003.
The Washington Commission confirmed that if the Tenaska gas costs are deemed prudent, PSE will recover the full amount of actual gas costs and the recovery of the Tenaska regulatory asset even if the benchmark is exceeded. Due to fluctuations in forward market prices of gas, the amount and timing of any potential disallowance related to Tenaska can change significantly day to day. The projected costs and projected benchmark costs for Tenaska have been updated as of December 31, 2004 to reflect higher2006 based on current forward market gas prices and are as follows:
(DOLLARS IN MILLIONS) | | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | |
(Dollars in Millions) | | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | |
| Projected Tenaska costs * | | $ | 194.5 | | $ | 197.2 | | $ | 189.0 | | $ | 180.3 | | $ | 170.3 | | $ | 162.9 | | $ | 170.0 | | | $ | 208.6 | | $ | 225.8 | | $ | 218.8 | | $ | 211.5 | | $ | 201.7 | |
| Projected Tenaska benchmark costs | | | 159.7 | | 167.9 | | 175.2 | | 182.2 | | 189.5 | | 197.2 | | 213.8 | | | | 174.8 | | | 182.9 | | | 189.9 | | | 197.4 | | | 205.6 | |
| Over (under) benchmark costs | | $ | 34.8 | | $ | 29.3 | | $ | 13.8 | | $ | (1.9 | ) | $ | (19.2 | ) | $ | (34.3 | ) | $ | (43.8 | ) | | $ | 33.8 | | $ | 42.9 | | $ | 28.9 | | $ | 14.1 | | $ | (3.9 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Projected 50% disallowance based on Washington Commission methodology | | $ | 10.5 | | $ | 8.8 | | $ | 5.8 | | $ | 1.6 | | $ | -- | | $ | -- | | $ | -- | | | $ | 7.8 | | $ | 6.4 | | $ | 4.9 | | $ | 3.1 | | $ | -- | |
* | _______________________
*Projection will change based on market conditions of gas and replacement power costs.
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PROCEEDINGS RELATING TO THE WESTERN POWER MARKETProceedings Relating to the Western Power Market
The following discussion summarizes the status as of the date of this report of ongoing proceedings inrelating to the western power markets to which PSE is a party relating to the Western power markets.party. PSE intends tois vigorously defend againstdefending each of these cases and does not expect the ultimate resolution of these proceedings in the aggregate to have a material adverse impact on the financial condition, results of operations or liquidity of the Company. However, there can be no assurances in that regard because litigationcases. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters. Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.
1. | California Receivable and California Refund Proceeding. In 2001, PG&E and Southern California Edison failed to pay the California Independent System Operator Corporation (CAISO) and the California PX for energy purchases. The CAISO in turn failed to pay various energy suppliers, including PSE, for energy sales made by PSE into the California energy market during the fourth quarter 2000. Both PG&E and the California PX filed for bankruptcy in 2001, further constraining PSE’s ability to receive payments due to bankruptcy court controls placed on the distribution of funds by the California PX and the escrow of funds owed by PG&E for purchases during the fourth quarter 2000 are owed by the California PX.
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California Receivable and California Refund Proceeding. Since 2001, PSE has held a receivable relating to unpaid bills for power that PSE sold in 2000 into the markets maintained by the CAISO. At December 31, 2006, the net receivable for such sales was approximately $21.2 million. PSE’s ability to recover all or a portion of this amount is uncertain. At this time there is no reasonable basis under applicable financial accounting rules to adjust PSE’s net receivable because the outcome of further court and FERC actions is uncertain and any likely financial impact cannot be quantified.In 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CAISO and the California PX during the period October 2, 2000 through June 20, 2001 (refund period). FERC also ordered that if the refunds required by the formula it adopted would cause a seller to recover less than its actual costs for the refund period, the seller is allowed to document its costs and limit its refund liability commensurately. Consistent with those orders, PSE filed a fuel cost adjustment claim and a portfolio cost claim. Recovery of those amounts is uncertain, but the amount owed to PSE under all FERC orders to date is included in the PSE net receivable amount. FERC has not issued a final order determining “who owes how much to whom” in the California Refund Proceeding, and it is not clear when such an order will be issued.
In the course of the California Refund Proceeding, FERC has issued dozens of orders. Most have been taken up on appeal before the United States Court of Appeals for the Ninth Circuit (Ninth Circuit), which has issued opinions on some issues in the last several years. These cases are described below in the section, “California Litigation.”
a.California Litigation. Lockyer v. FERC. On September 9, 2004, the Ninth Circuit issued a decision on the California Attorney General’s challenge to the validity of FERC’s market-based rate system. This case was originally presented to FERC upon complaint that the adoption and implementation of market rate authority was flawed. FERC dismissed the complaint after all sellers refiled summaries of transactions with California entities during 2000 and 2001. The Ninth Circuit upheld FERC’s authority to authorize sales of electric energy at market-based rates, but found the requirement that all sales at market-based rates be contained in quarterly reports filed with FERC to be integral to a market-based rate tariff. The California parties, among others, have interpreted the decision as providing authority to FERC to order refunds for different time frames and based on different rationales than are currently pending in the California Refund Proceedings, discussed above in “California Refund Proceeding.” The decision itself remands to FERC the question of whether to allow refunds. On December 28, 2006, PSE and several other energy sellers filed a petition for a writ of certiorari to the U.S. Supreme Court. The U.S. Supreme Court has not yet acted on that petition. PSE cannot predict the scope, nature or ultimate resolution of this case. That additional uncertainty may make the outcomes of certain other western energy market cases less predictable than previously anticipated. | California Refund Proceeding. On July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CAISO and the California PX during the period October 2, 2000 through June 20, 2001 (refund period). The CAISO continues its efforts to prepare revised settlement statements based on newly recalculated costs and charges for spot market sales to California during the refund period and currently estimates that it will determine “who owes what to whom” in early 2005. On September 2, 2004, FERC issued an order selecting Ernst & Young LLP as the independent auditor of fuel cost allowance claims made by sellers, including PSE. A review of that claim is pending, awaiting further guidance from FERC.
Many of the numerous orders that FERC issued in Docket No. EL00-95 are on appeal and have been consolidated before the United States Court of Appeals for the Ninth Circuit as a result of a case management conference conducted on September 21, 2004. FERC filed the record on November 22, 2004. The Ninth Circuit ordered on October 22, 2004 that briefing proceed in two rounds. The first round is limited to three issues: (1) which parties are subject to FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; (3) which categories of transactions are subject to refunds.
Procedures will be established for the remaining issues, if necessary, after the court’s disposition of the first round of issues. Following a second case management conference on November 9, 2004, the Ninth Circuit consolidated certain petitions for review for briefing of the first round of issues to be completed by March 1, 2005 and set oral argument hearings for April 12 and 13, 2005. Opening briefs were filed on December 29, 2004. PSE joined the brief of the Competitive Supplier Group, which argued that FERC has proposed to require payment of refunds without proper notice to sellers, without proper limits on the type of transactions affected and without a finding that the transactions subject to refund in fact produced prices that were just and reasonable. Respondents’ briefs in support of FERC were due February 9, 2005.
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CPUC v. FERC. On August 2, 2006, the Ninth Circuit decided that FERC erred in excluding potential relief for tariff violations for periods that pre-dated October 2, 2000 and additionally ruled that FERC should consider remedies for transactions previously considered outside the scope of the proceedings. The August 2, 2006 decision may adversely impact PSE’s ability to recover the full amount of its CAISO receivable. The decision may also expose PSE to claims or liabilities for transactions outside the previously defined “refund period.” At this time the ultimate financial outcome for PSE is unclear. The deadline for seeking rehearing of the August 2, 2006 decision is April 29, 2007, and it is likely that some parties will seek rehearing. In addition, parties have been engaged in court-sponsored settlement discussions, and those discussions may result in some settlements. PSE is studying the court’s decision, but is unable to predict either the outcome of the proceedings or the ultimate financial effect on PSE.
b. California Class Actions. In 2002, Reliant Energy Services (Reliant) and Duke Energy Trading & Marketing (Duke) cross-complained against PSE in several class actions filed in California arising from the California energy crisis. Duke and Reliant settled the underlying cases and subsequently dismissed the cross-complaints against the cross-defendants, including PSE. | CAISO Receivable. PSE has a bad debt reserve and a transaction fee reserve applied to the CAISO receivable, such that PSE’s net receivable from the CAISO as of December 31, 2004 is approximately $21.3 million. PSE estimates the range for the receivable to be between $21.3 million and $22.4 million, which includes estimated credits for fuel and power purchase costs and interest. In its October 16, 2003 Order on Rehearing in this docket, FERC expressly adopted and approved a stipulation that confirmed that two of PSE’s “non-spot market” transactions are not subject to mitigation in the Refund Proceeding. On October 17, 2003, PSE formally presented CAISO with a request that payment be made on these amounts. The CAISO responded to the letter on November 13, 2003, expressing an unwillingness to take the issue up separately or in advance of its cost re-run activities. PSE continues to pursue the issue in filings through FERC processes.
On May 6, 2004, the Los Angeles Department of Water and Power filed a motion at FERC in Docket No. EL00-95 requesting that FERC issue an order permitting monies to be disbursed from the California PX Settlement Clearing Account and an escrow account be established as part of PG&E’s bankruptcy proceeding. The bulk of the monies owed by the CAISO, including the monies owed to PSE, are held in those two accounts. PSE filed an answer in support of the motion on May 21, 2004, and awaits an order from FERC.
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2. | Pacific Northwest Refund Proceeding.In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC supplied for the California markets. FERC dismissed PSE’s complaint on December 15, 2000, although PSE filed for rehearing in January 2001. When FERC issued its June 19, 2001 order in Docket No. EL00-95, imposing west-wide price constraints on energy sales, PSE moved to withdraw its rehearing request and its complaint in Docket No. EL01-10, on the basis that the relief PSE sought was fully provided. Various parties, including the Port of Seattle and the cities of Seattle and Tacoma, moved to intervene in the proceeding. They asserted the ability to adopt PSE’s complaint to obtain retroactive refunds for numerous transactions, including many that were not within the scope of the PSE complaint. The proceeding became commonly referenced as the “Pacific Northwest Refund Proceeding,” despite the fact that the original complainant, PSE, did not seek retroactive refunds. A preliminary evidentiary hearing was held in September 2001, and an Administrative Law Judge recommendation against refunds followed. In December 2002, FERC issued an order permitting additional discovery and the submission of any additional evidence (parallel to the order issued in the California Refund Proceeding) that reopened the matter to permit parties to introduce any evidence they claimed to have of market manipulation. A few parties made filings, asserting market manipulation in early March 2003, and numerous parties, including PSE, responded to those allegations in late March 2003. On June 25, 2003, FERC issued an order terminating the proceeding, largely on procedural, jurisdictional and equitable grounds. Various parties filed rehearing requests on July 25, 2003. On November 10, 2003, FERC affirmed an order terminating the Pacific Northwest Refund Proceeding, (Docket No. EL01-10), largely on procedural, jurisdictional and equitable grounds. Seven petitions for review, including PSE’s, are now pending before the United States Court of Appeals for the Ninth Circuit. Opening briefs were filed on January 14, 2005. PSE’s opening brief addressed procedural flaws underlying the action of FERC. Specifically, PSE argued that because PSE’s complaint in the underlying docket was withdrawn as a matter of law on July 9, 2001, FERC erred in relying on it to serve as the basis to initiate a “preliminary” investigation into whether refunds for individually negotiated bilateral transactions in the Pacific Northwest were appropriate. Briefing is expected to be completed in the first half of 2005.
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3. | Orders to Show Cause. On June 25, 2003, FERC issued two show cause orders pertaining to its western market investigations that commenced individual proceedings against many sellers. One show cause order investigated 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order. On June 25, 2003, FERC issued two show cause orders pertaining to its western market investigations that commenced individual proceedings against many sellers. One show cause order (Docket Nos. EL03-180, et seq.) sought to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order. In an order dismissing many of the already-named respondents in the “partnerships” proceeding on January 22, 2004, FERC stated that it did not intend to proceed further against other parties. |
The second show cause order (Docket Nos. EL03-137, et seq.) named PSE (Docket No. EL03-169) and approximately 54 other entities that allegedlyalleg-edly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE and FERC staff filed a proposed settlement of all issues pending against PSE in those proceedings on August 28, 2003. The proposed settlement, which admits no wrongdoing on the part of PSE, would result in a payment of $17,092a nominal amount to settle all claims. FERC approved the settlement on January 22, 2004. The California parties filed for rehearing of that order, repeating arguments that had already been addressed by FERC.order. On March 17, 2004, PSE filed a motionmoved to dismiss the California parties’ rehearing request and awaits FERC action on that motion.
4. | Pacific Northwest Refund Proceeding. In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC ordered for the California markets. FERC dismissed PSE’s complaint, but PSE challenged that dismissal. On June 19, 2001, FERC ordered price caps on energy sales throughout the West. Various parties, including the Port of Seattle and the cities of Seattle and Tacoma, then moved to intervene in the proceeding seeking retroactive refunds for numerous transactions. The proceeding became known as the “Pacific Northwest Refund Proceeding,” though refund claims were outside the scope of the original complaint. On June 25, 2003, FERC terminated the proceeding on procedural, jurisdictional and equitable grounds and on November 10, 2003, FERC on rehearing, confirmed the order terminating the proceeding. Petitions for review, including PSE’s, are now pending before the Ninth Circuit. The Ninth Circuit held argument on the petitions on January 8, 2007, and the matter now awaits that court's decision. Port of Seattle Suit. On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle against 22 energy sellers, including PSE, alleging that their conduct during 2000 and 2001 constituted market manipulation, violated antitrust laws and damaged the Port of Seattle. The Port had a contract to purchase its energy supply from PSE at the time. The Port’s contract linked the price of the energy sold to the Port to an index price for energy sold at wholesale at the Mid-Columbia trading hub. The Port alleged that the Mid-Columbia price was inten-tionally affected improperly by the defendants, including PSE, and alleges damages of over $30 million. On May 12, 2004, the district court dismissed the lawsuit. The Port of Seattle filed an appeal to the United States Court of Appeals for the Ninth Circuit, and on September 13, 2004, filed a brief in the Ninth Circuit arguing that the district court erred in dismissing its claims. Responses to the Port’s brief were filed November 2, 2004. The parties await oral argument to be scheduled. |
5. | Wah Chang v. Avista Corp., PSE and others.In June 2004, Puget Energy and PSE were served a federal summons and complaint by Wah Chang, an Oregon company. Wah Chang claims that during 1998 through 2001 the Company and other energy companies (and in a separate complaint, energy marketers) engaged in various fraudulent and illegal activities including the transmittal of electronic wire communications to transmit false or misleading information to manipulate the California energy market. The claims include submitting false information such as energy schedules and bids to the California PX, CAISO, electronic trading platforms and publishers of energy indexes, alleges damages of not less than $30 million and seeks treble and punitive damages, attorneys’ fees and costs. The complaint is similar to the allegations made by the Port of Seattle currently on appeal in the Ninth Circuit. The Judicial Panel on Multi District Litigation consolidated this case with another pending Multi District case and transferred it to Federal District Court in San Diego on August 20, 2004. The defendants in both cases filed motions to dismiss on October 25, 2004. Wah Chang opposed the motions to dismiss, and replies in support of the motions to dismiss were filed on January 12, 2005. On February 11, 2005, approximately three weeks after hearing oral argument, the Court dismissed both cases on the grounds that FERC has the exclusive jurisdiction over plaintiff’s claims and the filed rate doctrine and Federal preemption barred the court from hearing the plaintiff’s claims.
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6. | California Litigation.Attorney General Cases. On May 31, 2002, FERC conditionally dismissed a complaint filed on March 20, 2002 by the California Attorney General in Docket No. EL02-71 that alleged violations of the FPA by FERC and all sellers (including PSE) of electric power and energy into California. The complaint asserted that FERC’s adoption and implementation of market rate authority was flawed and, as a result, individual sellers such as PSE were liable for sales of energy at rates that were “unjust and unreasonable.” The condition for dismissal was that all sellers refile transaction summaries of sales to (and, after a clarifying order issued on June 28, 2001, purchases from) certain California entities during 2000 and 2001. PSE refiled such transaction summaries on July 1 and July 8, 2002. The order of dismissal went on appeal to the Ninth Circuit Court of Appeals. On September 9, 2004, the Ninth Circuit issued a decision on the California Attorney General’s challenge to the validity of FERC’s market-based rate system (Lockyer v. FERC). This case was originally presented to FERC. The Ninth Circuit upheld FERC’s authority to authorize sales of electric energy at market based rates, but found the requirement that all sales at market-based rates be contained in quarterly reports filed with FERC to be integral to a market-based rate tariff. The California parties, among others, have interpreted the decision as providing authority to FERC to order refunds for different time frames and based on different rationales than are currently pending in the California Refund Proceedings, discussed above in “California Refund Proceeding.” The decision itself defers the question of whether to seek refunds to FERC. PSE, along with other defendants in the proceeding, sought rehearing of the Ninth Circuit’s decision on October 25, 2004. The Ninth Circuit has yet to issue an order on the rehearing request. Because the current Ninth Circuit decision may open new periods of transactions to refund claims under new theories, PSE cannot predict the scope, nature or ultimate resolution of this case. That additional uncertainty may make the outcomes of certain other western energy market cases less predictable than previously anticipated.
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In addition, the day after the initial FERC decision in theLockyer case, the California Attorney General filed similar claims in state court in California, including one suit against PSE. These complaints alleged that the wholesale seller defendants in the California energy market engaged in anti-competitive behavior in violation of the California Business Practices Act for sales in the California energy market (Lockyer v. Transalta).The complaint asserted that each such “violation” subjects PSE to a fine of up to $2,500 plus an award of attorneys’ fees and asserts that there were “thousands” of such violations. Those cases were removed to federal court and dismissed. On October 12, 2004, the Ninth Circuit issued a decision affirming the dismissal of all 13 complaints filed by the California Attorney General, including a complaint against PSE. The Ninth Circuit decision concluded that the opinions inPeople of the State of California ex rel. Bill Lockyer v. Dynegy, et al. andPublic Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, Inc., decided earlier this year by the Ninth Circuit, controlled the outcome of the matters and warranted dismissal. Because no party sought rehearing or filed a petition for certiorari to the Supreme Court of the United States, the Ninth Circuit’s order is the final determination of this matter.
California Class Actions. In May 2002, PSE was served with two cross-complaints, by Reliant Energy Services and Duke Energy Trading & Marketing, respectively, in six consolidated class actions filed in Superior Court in San Diego, California. Plaintiffs in the lawsuit seek, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest and penalties. The cross-complaints asserted essentially that the cross-defendants, including PSE, were also participants in the California energy market at the relevant times, and that any remedies ordered against some market participants should be ordered against all. Reliant and Duke also seek indemnification and conditional relief as buyers in transactions involving cross-defendants should the plaintiffs prevail. The case was removed to federal court and some of the newly added defendants, including PSE, moved to dismiss the action. In December 2002, the federal district court remanded the proceeding to state court, an action which Duke and Reliant later appealed to the Ninth Circuit. The appeal stayed further action in the state court proceeding pending the outcome of the appeal. The cross-complaintsAfter briefing and the addition of the 40 new defendants raised issues of foreign sovereign immunity, jurisdiction and indemnity in the case, all of which are now part of the appeal. In June 2003, PSE and other defendants filed motions to respond to the indemnity issues. On May 13, 2004,oral argument on March 30, 2006, the Ninth Circuit issued an order grantingdismissing the case.
Wah Chang Suit. In June 2004, Wah Chang, an Oregon company, filed suit in federal court against Puget Energy and PSE, status asamong others. The complaint is similar to the allegations made by the Port of Seattle described above. The case was dismissed on the grounds that FERC has the exclusive jurisdiction over plaintiff’s claims. On March 10, 2005, Wah Chang filed a cross-appellant but did not permit PSEnotice of appeal to participate in the oral argument heard on June 14, 2004. On December 8, 2004, the Ninth Circuit issued an opinion affirming the district court’s decisionCircuit. Oral argument is scheduled to remand the case to state court. Powerex filed a petition for rehearing which argues that although not immune from suit, as a government entity it should be allowed to litigate in federal, not state court. Powerex’s petition for rehearing stays issuance of the mandate to remand pending the outcome of its rehearing request.take place on April 10, 2007.
CRITICAL ACCOUNTING POLICIES AND ESTIMATESCritical Accounting Policies And Estimates
The preparation of financial statements in conformity with Generally Accepted Accounting Principlesgenerally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following accounting policies represent those that management believes are particularly important to the financial statements and that require the use of estimates, assumptions and judgment to describe matters that are inherently uncertain.
REVENUE RECOGNITIONRevenue Recognition.
Utility revenues are recognized when the basis of service is rendered, which includes estimates to determine amounts relating to services rendered but not billed. Unbilled electricity revenue is determined by taking MWh generated and purchased less estimated system losses and billed MWh plus unbilled MWh balance at the last true-up date. The estimated system loss percentage for electricity is determined by reviewing historical billed MWh to generated and purchased MWh. The estimated unbilled MWh balance is then multiplied by the estimated average revenue per MWh. Unbilled gas revenue is determined by taking therms delivered to PSE less estimated system losses, prior month unbilled therms and billed therms. The estimated system loss percentage for gas is determined by reviewing historical billed therms to therms delivered to customers.customers, which vary little from year to year. The estimated current month unbilled therms is then multiplied by estimated average rate schedule revenue per therm. Non-utility revenue is recognized when services are performed or upon the sale of assets, or on a percentage of completion basis for fixed-price contracts.assets. The recognition of revenue is in conformity with Generally Accepted Accounting Principles,generally accepted accounting principles, which requiresrequire the use of estimates and assumptions that affect the reported amounts of revenue.
The following table represents the sensitivity of the estimate of system losses for both electricity and gas in calculating unbilled revenues assuming an additional 0.1% increase in the estimated system loss factor since the last annual true-up:
| | GAS REVENUE DECREASE (MILLIONS) | ELECTRIC REVENUE DECREASE (MILLIONS) |
| 0.1% increase in loss factor | $0.4 | $0.6 |
REGULATORY ACCOUNTINGRegulatory Accounting.
As a regulated entity of the Washington Commission and FERC, PSE prepares its financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The application of SFAS No. 71 results in differences in the timing and recognition of certain revenues and expenses in comparison with businesses in other industries. The rates that are charged by PSE to its customers are based on cost base regulation reviewed and approved by the Washington Commission and FERC. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, 20042006 in the amount of $645.3$838.5 million and $185.7$191.6 million, respectively, and regulatory assets and liabilities of $610.5$674.3 million and $176.7$241.9 million, respectively, at December 31, 2003..2005. PSE expects to fully recover these regulatory assets and liabilities through its rates. If future recovery of costs ceases to be probable, PSE would be required to write off these regulatory assets and liabilities. In addition, if at some point in the future PSE determines that it no longer meets the criteria for continued application of SFAS No. 71, PSE could be required to write off its regulatory assets and liabilities.
Also encompassed by regulatory accounting and subject to SFAS No. 71 are the PCA and PGA mechanisms. The PCA and PGA mechanisms mitigate the impact of commodity price volatility upon the Company and are approved by the Washington Commission. The PCA mechanism provides for a sharing of costs and benefits that arevary from baseline rates over a graduated over four levels of power cost variances with an overall cap of $40 million (+/-) plus 1% of the excess over the $40 million cap over the four-year period ending June 30, 2006. The PCA mechanism will continue after July 1, 2006, within certain sharing bands.scale. See Item 1 - Business - Regulation and Rates - Electric Regulation and Rates for further discussion regarding the PCA mechanism. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. PSE expects to fully recover these regulatory assets through its rates. However, both mechanisms are subject to regulatory review and approval by the Washington Commission on a periodic basis.
DERIVATIVESDerivatives.
Puget Energy uses derivative financial instruments primarily to manage its energy commodity price risks and may enter into certain financial derivatives to manage interest rate risk. Derivative financial instruments are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. Accounting for derivatives continues to evolve through guidance issued by the Derivatives Implementation Group (DIG) of the Financial Accounting Standards Board (FASB). To the extent that changes by the DIG modify current guidance, including the normal purchases and normal sales determination, the accounting treatment for derivatives may change.
To manage its electric and gas portfolios, Puget Energy enters into contracts to purchase or sell electricity and gas. These contracts are considered derivatives under SFAS No. 133 unless a determination is made that they qualify for the normal purchases and normal sales exception. If the exception applies, those contracts are not marked-to-market and are not reflected in the financial statements until delivery occurs.
The availability of the normal purchasespurchase and normal salessale exception to specific contracts is based on a determination that a resource is available for a forward sale and similarly a determination that at certain times existing resources will be insufficient to serve load. This determination is based on internal models that forecast customer demand and generation supply. The models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice and resource availability. The critical assumptions used in the determination of the normal purchases and normal sales exception are consistent with assumptions used in the general planningenergy portfolio management process.
Energy and financial contracts that are considered derivatives may be eligible for designation as cash flow hedges. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of derivatives not designated as cash flow hedges is recorded in current period earnings.
PSE values derivative instruments based on daily quoted prices from numerous independent energy brokerage services. When external quoted market prices are not available for derivative contracts, PSE uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis.
PENSION AND OTHER POSTRETIREMENT BENEFITSPension and Other Postretirement Benefits.
Puget Energy has a qualified defined benefit pension plan covering substantially all employees of PSE. For 2004, 2003Qualified pension expense of $1.0 million was recorded in 2006 and 2002, qualified pension income of $8.0 million, $12.9$2.6 million and $17.7$8.0 million respectively, was recorded in the financial statements.statements for 2005 and 2004, respectively. Of these amounts, approximately 63.3%56.6%, 67.0%63.0% and 66.8%63.3% offset utility operations and maintenance expense in 2004, 20032006, 2005 and 2002,2004, respectively, and the remaining amounts were capitalized. Qualified pension expense is expected to be $1.7 million in 2007.
PSE’s pension and other postretirement benefits income or costs are dependentdepend on several factors and assumptions, including plan design, of the plan, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care cost trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and also its projected benefit obligation.
The follow table reflects the estimated sensitivity associated withCompany has selected an expected return on plan assets based on a change in certain actuarial assumptions (each assumption change is presented mutually exclusivehistorical analysis of other assumption changes):
| | | CHANGE IN ASSUMPTION | | IMPACT ON PROJECTED BENEFIT OBLIGATION INCREASE (DECREASE) | | IMPACT ON 2004 PENSION INCOME INCREASE (DECREASE) | |
(DOLLARS IN THOUSANDS) | | | | PENSION BENEFITS | | OTHER BENEFITS | | | | | |
| Increase in discount rate | | 50 basis points | $ | (20,548 | ) | $ | (3,635 | ) | $ | 1,261 | | $ | 354 | |
| Decrease in discount rate | | 50 basis points | | 22,595 | | | 3,891 | | | (48 | ) | | (377 | ) |
| Increase in return of plan assets | | 50 basis points | | * | | | * | | | 2,370 | | | 71 | |
| Decrease in return on plan assets | | 50 basis points | | * | | | * | | | (2,370 | ) | | (71 | ) |
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* Calculation not applicable.
Qualified pension income is expected to decline to $2.5 million in 2005 as a result of lower actual returns on pension assets during the last three years and declining expected rates of return and the Company’s investment mix, market conditions, inflation and other factors. The Company’s accounting policy for calculating the market-related value of assets is based on pension funda five-year smoothing of asset gains/losses measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. During 2004,2006, PSE made no cash contributions to the qualified defined benefit plan and expects to make no contributions in 2005.2007.
The following table reflects the estimated sensitivity associated with a change in certain significant actuarial assumptions (each assumption change is presented mutually exclusive of other assumption changes):
| | | Change in Assumption | | Impact on Projected Benefit Obligation Increase (Decrease) | | Impact on 2006 Pension Income Increase (Decrease) | |
(Dollars in Thousands) | | | | Pension Benefits | | Other Benefits | | Pension Benefits | | Other Benefits | |
| Increase in discount rate | | 50 basis points | | $ | (23,144 | ) | $ | (3,291 | ) | $ | 2,014 | | $ | 296 | |
| Decrease in discount rate | | 50 basis points | | | 24,458 | | | 3,537 | | | (2,188 | ) | | 299 | |
| Increase in return of plan assets | | 50 basis points | | | * | | | * | | | 2,277 | | | 73 | |
| Decrease in return on plan assets | | 50 basis points | | | * | | | * | | | (2,277 | ) | | (73 | ) |
| * | Calculation not applicable. |
GOODWILL AND INTANGIBLES (PUGET ENERGY ONLY)California Receivable.
On January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective and as a result Puget Energy ceased amortization of goodwill. Puget Energy performs an annual impairment review to determine if any impairment exists. In performing the goodwill impairment test, Puget Energy compares the present value of the future cash flows of estimated earnings of InfrastruX which reflects prospective market price information from prospective buyers to the adjusted carrying value of recorded equity. If goodwill is determined to have an impairment, Puget Energy will record in the period of determination an impairment charge to earnings.
Intangibles with finite lives are amortized based on the expected pattern of use or on a straight-line basis over the expected periods to be benefited. The goodwill and intangibles recorded on the balance sheet of Puget Energy are the result of acquisition of companies by InfrastruX. During 2004, Puget Energy recorded a non-cash goodwill impairment charge of $91.2 million, or $76.6 million after-tax and minority interest. As a result, the goodwill balance at December 31, 2004 was $43.5 million. Intangible assets have not been impaired and the balance at December 31, 2004 was $16.7 million.
CALIFORNIA RESERVE
PSE operates within the western wholesale market and has made sales into the California energy market. At December 31, 2000, PSE’s receivables from the CAISO and other counterparties net of reserves, werewas $41.8 million. PSE received the majority of the partial payments for sales made in the fourth quarter 2000 in the first quarter 2001 and has since received a small amount of payments. At December 31, 2004,2006, such remaining receivables net of reserves, were approximately $21.3$21.2 million.
During 2003, FERC issued an order in the California Refund Proceeding adopting in part and modifying in part FERC’s earlier findings by the Administrative Law Judge. Based on the order,calculation of existing FERC orders issued to date, PSE has determined that the receivablesreceivable balance at December 31, 20042006 is collectible from the CAISO. However, PSE’s ability to collect all or a portion of this amount may be impaired by future FERC orders or decisions by the Ninth Circuit.
NEW ACCOUNTING PRONOUNCEMENTSStock Compensation
In December 2004, FASB issued. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R), which revises SFAS No. 123, “Accounting For Stock-Based Compensation.Payment,” SFAS No. 123R requires companies that issue share-based payment awardsusing the modified-prospective transition method. Results for prior periods have not been restated, as provided for under the modified-prospective method. Prior to employees for goods or services to recognize as2006, stock-based compensation expense, the fair value of the expected vested portion of the award as of the grant date over the vesting period of the award. Forfeitures that occur before the award vesting date will be adjusted from the total compensation expense, but once the award vests, no adjustment to compensation expense will be allowed for forfeitures or unexercised awards. In addition, SFAS No. 123R would require recognition of compensation expense of all existing outstanding awards that are not fully vested for their remaining vesting period as of the effective date thatplans were not accounted for under a fair value method of accounting at the time of their award. SFASaccording to Accounting Principles Board (APB) No. 123R is effective25, “Accounting for reporting periods beginning after June 15, 2005. The Company is currently evaluating what impact the application of SFAS No. 123R will have on its operations. The Company had adopted the fair value provisions ofStock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for StockStock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock compensation awards granted subsequent to January 1, 2003, while grants prior to 2003 continued to be accounted for using the intrinsic value method of APB No. 25.
The adoption of SFAS 123R resulted in a cumulative benefit from an accounting change of $0.1 million, after tax, for the quarter ended March 31, 2006. The cumulative effect adjustment is the result of the inclusion of estimated forfeitures occurring before award vesting dates in the computation of compensation expense for unvested awards. As a result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before income taxes and net income from continuing operations for the twelve months ended December 31, 2006 is $0.1 million and $0.1 million higher, respectively, than if it had continued to account for share-based compensation under SFAS No. 123 due to the inclusion of estimated forfeitures in compensation cost. There is no difference between basic and diluted earnings per share for income from continuing operations for the twelve months ended December 31, 2006, under SFAS No. 123R as compared to earlier methods.
The fair value of the stock-based grants is based on the closing price of the Company’s common stock on the date of measurement and historical performance of the certain share grants and prospective analysis using the Capital Asset Pricing Model and expected EPS growth rates. Based Compensation”on this analysis, the Company’s total shareholder returns would need to significantly increase as compared to other companies to have a material impact on the Company’s financial statements. Shares granted prior to 2006 were valued using the Black-Scholes option pricing model.
New Accounting Pronouncements
At its June 15, 2006 meeting, FASB’s EITF approved the issuance of EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in January 2003.the Income Statement (That Is, Gross versus Net Presentation).” The Company’s policy is to report state utility taxes and municipal taxes on a gross basis. The EITF concluded that these requirements should be applied to financial reports for interim and annual periods beginning after December 15, 2006, which will be the quarter ended March 31, 2007, for the Company. The adoption of EITF Issue No. 06-3 is not expected to have a material impact on the Company’s financial statements.
In December 2004,July 2006, FASB issued FASB Staff PositionInterpretation No. 109-1, “Application48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109, Accounting” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,Taxes.” FIN 48 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, the Tax Deductiontax position should only be recognized when it is more likely than not, based on Qualified Production Activities Providedtechnical merits, that the position will be sustained upon examination by the American Jobs Creation Acttaxing authority. Second, a tax position, that meets the recognition threshold, should be measured at the largest amount that has a greater than 50.0% likelihood of 2004” (FSP No. 109-1). FSP No. 109-1 states thatbeing sustained.
FIN 48 was effective for the staff position related to deductionsCompany as of January 1, 2007. The change in net assets as a result of the American Jobs Creation Act (the Act) shouldadopting FIN 48 will be treated as a “special deduction”, as describedchange in SFAS No. 109, “Accounting For Income Taxes” and therefore has noaccounting method. The cumulative effect of the change will be recorded to retained earnings. Adjustments to regulatory accounts, if any, will be based on deferred tax assets or liabilities existing at the enactment date.other applicable accounting standards. The Company is currently in the process of evaluating the provisions of FIN 48 to determine the potential impact, of FSP No. 109-1 (which was effective upon issuance) andif any, deduction available under the Act. Any deduction available, if determined, is applicable toadoption will have on the Company’s 2005 tax year.
On May 19, 2004, FASB issued FASB Staff Position (FSP) No. 106-2 “Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003” as the result of the new Medicare Prescription Drug and Modernization Act which was signed into law in December 2003. The law provides a subsidy for plan sponsors that provide prescription drug benefits to Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based on an actuarial assessment, PSE will not be eligible for such subsidies, thus FSP No. 106-2 will have no impact on PSE’s retiree medical plans.
The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) at its July 2003 meeting came to a consensus concerning EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03.” The consensus reached was that determining whether realized gains and losses on physically settled derivative contracts not held for trading purposes are reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Based on the guidance by EITF No. 03-11, the Company determined that its non-trading derivative instruments should be reported net and implemented this treatment effective January 1, 2004. As a result of the implementation, Electric Revenue and Purchased Electricity Expense both decreased $108.7 million in 2003 and $77.1 million in 2002, respectively, with no impact on financial position or net income.
In March 2004, the EITF came to a consensus concerning EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies.” The consensus reached was that an investment in a limited liability company should be accounted for using the equity method for investments greater than 3% to 5%.statements. The adoption of EITF No. 03-16FIN 48 is effective for reporting periods beginning after Junenot expected to have a material impact on the Company’s retained earnings. Management’s estimated impact of adoption is subject to change due to potential changes in interpretation of FIN 48 by the FASB or other regulatory bodies and the finalization of the Company’s adoption efforts.
On September 15, 2004, with any adjustments being accounted for as a cumulative effect of a change in accounting principle. The Company reviewed its investments and determined one investment held by PSE met the criteria established in EITF No. 03-16.
In May 2003,2006, FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.157, “Fair Value Measurements.” SFAS No. 150 establishes157 standardizes the requirements for classifying and measuring as liabilities certain financial instruments that embody obligations to redeem the financial instruments by the issuer. The adoptionmeasurement of fair value when it is required under GAAP. SFAS No. 150 is effective with the first fiscal year or interim period beginning after June 15, 2003. However, on November 5, 2003 FASB deferred for an indefinite period certain mandatorily redeemable noncontrolling interests associated with finite-lived subsidiaries. The Company does not have any noncontrolling interest in finite-lived subsidiaries and therefore is not affected by the deferral. Prior periods will not be restated for the new presentation.
SFAS No. 150 requires the Company to classify its mandatorily redeemable preferred stock as liabilities. As a result, the corresponding dividends on the mandatorily redeemable preferred stock are classified as interest expense on the income statement with no impact on net income.
In January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. FIN 46R requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements must be included in the consolidated financial statements of the business entity. The adoption of FIN 46R for all interests in variable interest entities created after January 31, 2003 was effective immediately. For variable interest entities created before February 1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was effective March 31, 2004. The Company has evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance, and therefore it was consolidated in the third quarter 2003. As a result, electricity revenues for 2003 increased $5.7 million, while conservation amortization and interest expense increased by the corresponding amount with no impact on earnings. FIN 46R also impacted the treatment of the Company’s mandatorily redeemable preferred securities of a wholly owned subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities). Previously, these trust-preferred securities were consolidated into the Company’s operations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities (junior subordinated debt) in the fourth quarter 2003. This change had no impact on the Company’s results of operations. The Company also evaluated its purchase power agreements and determined that three counterparties may be considered variable interest entities. As a result, PSE submitted requests for information to those parties; however, the parties have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity. PSE also determined that it does not have a contractual right to such information. PSE will continue to submit requests for information to the counterparties on a quarterly basis to determine if FIN 46R is applicable.
For the three purchase power agreements that may be considered variable interest entities under FIN 46R, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the purchase power agreements. If at any time the counterparties cannot deliver energy to PSE, PSE would have to buy energy in the wholesale market at prices which could be higher or lower than the purchase power agreement prices. PSE’s Purchased Electricity expense for 2004 and 2003 for these three entities was $251.2 million and $273.9 million, respectively.
In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143), which157 is effective for fiscal years beginning after JuneNovember 15, 2002. SFAS No. 143 requires legal obligations associated with2007, which will be the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company adopted the new rules on asset retirement obligations onyear beginning January 1, 2003. As a result, the Company recorded a $0.2 million charge to income2008, for the cumulative effect of this accounting change.
In November 2004, FASB reached a decision concerning a proposed interpretationCompany. The adoption of SFAS No. 143 titled “Accounting for Conditional Asset Retirement Obligations.” The proposed interpretation addresses the issue of whether SFAS No. 143 requires an entity157 is not expected to recognizehave a liability for a legal obligation to perform asset retirement when the asset retirement activities are conditional on a future event, and if so, the timing and valuation of the recognition. The decision reached by FASB was that there are no instances where a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation. This, if part of the final issued interpretation, could potentially have anmaterial impact on the Company as assets that were previously considered outside the scope of SFAS No. 143 may be subject to the terms of the proposed interpretation. FASB indicated that the final interpretation is anticipated to be issued in the first quarter 2005, with an effective date for fiscal years ending after December 15, 2005, and with any adjustment accounted for as a cumulative effect of an accounting change. The Company is currently evaluating what impact this proposed interpretation may have on the Company if issued.Company’s financial statements.
| QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ENERGY PORTFOLIO MANAGEMENTEnergy Portfolio Management
The regulatory mechanismsCompany has energy risk policies and procedures to manage commodity and volatility risks. The Company’s Energy Management Committee establishes the Company’s energy risk management policies and procedures, and monitors compliance. The Energy Management Committee is comprised of certain Company officers and is overseen by the Audit Committee of the PGA and the PCA mitigate the impactCompany’s Board of commodity price volatility on the Company. The PGA mechanism passes through increases and decreases in the cost of natural gas supply to customers. The PCA mechanism provides for a sharing of costs and benefits that are graduated over four levels of power cost variances with an overall cap of $40 million (+/-) plus 1% of the excess over the $40 million cap over the four-year period ending June 30, 2006.Directors.
The Company is focused on commodity price exposure and risks associated with volumetric variability in the gas portfolio and electric portfolio for its customers. Gas and electric portfolio exposure is managed in accordance with Company polices and procedures. The Risk Management Committee, which is composed of Company officers, provide policy-level and strategic direction for management of the energy portfolio. The Audit Committee of the Company’s Board of Directors periodically assesses risk management policies.
The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted resources exposes the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk management function monitors and manages these risks using analytical models and tools. The Company manages its energy supply portfolio to achieve three primary objectives:
· | ensure that physical energy supplies are available to serve retail customer requirements; |
· | manage portfolio risks to limit undesired impacts on the Company’s costs; and |
· | maximize the value of the Company’s energy supply assets. |
The Companyportfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading revenues. Therefore wholesale market transactions are focused on balancing the Company’s energy portfolio, reducing costs and risks where feasible, and reducing volatility in wholesale costs and margin in the portfolio. In order to manage risks effectively, thetrading. The Company enters into physical and financial transactions, which are appropriate for the service territory of the Company and are relevant to its regulated electric and gas portfolios.
The risk metrics the Company employs are aimed at assessing exposure for the purposes of developing strategies to reduce the potential exposure on a cost-effective basis in regulated utilityhedges open gas and electric portfolios. Specifically,positions to reduce both the amount ofportfolio risk and the volatility risk in prices. The exposure is defined by time period and by portfolio. Itposition is determined through statistical methods aimed at forecasting risk.
The energyby using a probabilistic risk management staffsystem that models forecasted load requirements and expected resource availability, and projects100 scenarios of how the net deficit or surplus position resulting from any imbalance between load requirements and existing resources. However, the portfolios are subject to major sources of variability (e.g., hydroelectric generation, outage risk, regional economic factors, temperature-sensitive retail sales and market prices forCompany’s gas and power supplies). At certain times, these sources of variability can mitigate portfolio imbalancesportfolios will perform under various weather, hydro and at other times they can exacerbate portfolio imbalances. Becauseunit performance conditions. The objective of the volumetric and cost variability within the electric and gas portfolios, the Company runs market simulations to model potential risk scenarios. In this way, strategies can be developed to address the expected case as well as other potential scenarios. Resources in the gas portfolio include gas supply arrangements, gas storage and gas transportation contracts. Resources in the electric portfolio include power purchase agreements, generating resources and transmission contracts.hedging strategy is:
The Company’s energy risk management staff develops hedging strategies to manage deficit or surplus positions in the portfolios. The Company’s energy risk policy states that hedging and optimization strategies will be consistent with Company objectives. The Company relies on risk analysis, operational factors, professional judgment of its employees and fundamental analysis. The Company will engage in transactions that reduce risks in its electric and gas portfolios, and optimize unused capacity where possible. Cost and reliability factors are considered in its hedging strategies. The Company’s hedging activities are aimed at removing risks from the Company’s electric and gas portfolios, giving important consideration to cost of hedges and lost opportunity in order to find a balance between price stability and least cost. The hedge strategies for the gas and electric portfolios incorporate risk analysis, operational factors and professional judgment of its employees as well as fundamental analysis. Programmatic hedge plans are developed to ensure disciplined hedging, and discretion is used in hedging within specific guidelines of the programmatic hedge plans approved by the Risk Management Committee. Most hedges can be implemented in ways that retain the Company’s ability to use its energy supply optimization opportunities. Some hedges are structured similarly to insurance instruments, where the Company pays an insurance premium to protect against certain extreme conditions.
Without jeopardizing the security of supply within its portfolio, the Company also engages in optimizing the portfolio. Optimization may take the form of utilizing excess capacity, shaping flexible resources to capture their highest value and utilizing transmission capacity through third party transactions. As a result, portions of the Company’s energy portfolio are monetized through the use of forward price instruments which help reduce overall costs. | · | ensure physical energy supplies are available to reliably and cost-effectively serve retail load; |
| · | prudent management of energy portfolio risks to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders; and |
| · | reduce power costs by extracting the value of the Company’s assets. |
The Company has entered into master netting agreements with counterparties when available to mitigate credit exposure to those counterparties. The Company believes that entering into such agreements reduces risk of settlement default for the ability to make only one net payment. In addition, the Company believes risk is mitigated with an improved position in potential counterparty bankruptcy situations due to a consistent netting approach.
At December 31, 2004,2006, the Company had a short-term asset of $0.9 million and a short-term liability of $0.9 million, primarily as a result of de-designating gas financial contracts. These contracts were related to electric generation that was subject tono longer probable. During 2006, the Company recorded a range of netting provisions, including both stand alone agreements anddecrease in earnings for the provisions associated with the Western Systems Power Pool agreement of which many energy supplierschange in the western United States are a part.
Transactions that qualify asmarket value of derivative instruments not meeting the normal purchase normal sale exception or cash flow hedge transactionscriteria under SFAS No. 133 are recorded on the balance sheet at fair value. Changesof $0.1 million compared to a decrease in fair valueearnings of the Company’s derivatives are recorded each period in current earnings or other comprehensive income. Short-term derivative contracts$0.5 million for the purchase2005 and salean increase of electricity are valued based on daily quoted prices from an independent energy brokerage service. Valuations$0.5 million for short-term and medium-term natural gas financial derivatives are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas financial derivatives are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using market quotes and a Monte Carlo simulation based model approach.2004.
At December 31, 2004, the Company2006, PSE had an after-tax neta short-term asset of approximately $20.0$9.2 million and a long-term asset of $6.8 million as well as a short-term liability of $8.0 million and a long-term liability of $0.4 million related to energy contracts designated as cash flow hedges that represent forward financial purchases of gas supply for electric generation from PSE-owned electric plants in future periods. These contracts were designated as qualifying cash flow hedges and a corresponding unrealized gain of $4.9 million, net of tax, was recorded in other comprehensive income. OfIf it is determined that it is uneconomical to run the amountplants in the future period, the hedging relationship is ended and the cash flow hedge is de-designated and any unrealized gains and losses are recorded in the income statement. Gains and losses, when these de-designated cash flow hedges are settled, are recognized in energy costs and are included as part of the PCA mechanism. At December 31, 2005, the Company had an unrealized gain recorded in other comprehensive income 99% of the mark-to-market gain beginning February 1, 2005 has been reclassified out$43.2 million (net of other comprehensive incometax), before SFAS No.71 deferrals of $6.3 million, related to a deferred account in accordance with SFAS No. 71 due to the Company expecting to reach the $40 million cap under the PCA mechanism. The Company also had energy contracts that were marked-to-market at a gain of $1.2 million after-tax through current earningswhich met the criteria for the 12 months ended December 31, 2004. These mark-to-market adjustments were primarily the result of excluding certain contracts from the normal purchase normal sale exceptiondesignation as cash flow hedges under SFAS No. 133. A portionThis was mainly the result of higher forward market prices for natural gas and electricity at December 31, 2005 compared to December 31, 2006.
At December 31, 2006, the mark-to-market adjustments beginning February 1, 2005, has been reclassified toCompany had a deferred account in accordance with SFAS No. 71 dueshort-term asset of $6.8 million and a short-term liability of $61.6 million as well as a long-term asset of $0.1 million related to the Company expecting to reach the $40 million cap under the PCA mechanism. The Company also had a liability of approximately $12.1 millionhedges of gas contracts.contracts to serve natural gas customers. All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 due to the PGA mechanism. The PGA mechanism passes on to customersAll increases and decreases in the cost of natural gas supply. supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism. At December 31, 2005, the Company had a net asset of $25.7 million related to the hedge of gas contracts to serve natural gas customers.
A hypothetical 10% increase10.0% decrease in the market prices of natural gas and electricity would increasedecrease the fair value of qualifying cash flow hedges by approximately $5.5$5.0 million after-tax and would increase current earningshave no effect for those contracts marked-to-market in earnings by an immaterial amount.earnings.
Energy Derivative Contracts Gain(Loss) (Dollars in Millions) | Amounts | |
| Fair value of contracts outstanding at December 31, 2005 | | $ | 93.6 | |
| Contracts realized or otherwise settled during 2006 | | | (34.1 | ) |
| Changes in fair values of derivatives | | | (106.7 | ) |
| Fair value of contracts outstanding at December 31, 2006 | | $ | (47.2 | ) |
ENERGY DERIVATIVE CONTRACTS (DOLLARS IN MILLIONS) | | AMOUNTS | |
| Fair value of contracts outstanding at December 31, 2003 | | | | $ | 12.6 | |
| Contracts realized or otherwise settled during 2004 | | | | | (9.8 | ) |
| Changes in fair values of derivatives | | | | | 6.9 | |
| Fair value of contracts outstanding at December 31, 2004 | | | | $ | 9.7 | |
| | FAIR VALUE OF CONTRACTS WITH SETTLEMENT DURING YEAR | Fair Value of Contracts with Settlement During Year |
SOURCE OF FAIR VALUE | 2005 | 2006- 2007 | 2008- 2009 | 2010 AND THEREAFTER | TOTAL FAIR VALUE | |
Source of Fair Value (Dollars in Millions) | | 2007 | 2008- 2009 | 2010- 2011 | 2012 and Thereafter | Total Fair Value |
| Prices actively quoted | $ (3.8) | $ 6.3 | $ -- | $ -- | $ 2.5 | $(53.7) | $6.5 | -- | $(47.2) |
| Prices provided by other external sources | -- | 5.4 | 1.8 | -- | 7.2 | -- | -- | -- |
| Prices based on models and other valuation methods | $ (3.8) | $ 11.7 | $ 1.8 | $ -- | $ 9.7 | $(53.7) | $6.5 | -- | $(47.2) |
INTEREST RATE RISKCredit Risk
The Company is exposed to credit risk primarily through buying and selling electricity and gas to serve customers. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, exposure monitoring and exposure mitigation.
It is possible that extreme volatility in energy commodity prices could cause the Company to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2006, approximately 99.0% of the counterparties comprising the sources of our energy portfolio are rated at least investment grade by the major rating agencies and 1.0% are either rated below investment grade or are not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.
Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate notes and leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes bank borrowings, commercial paper, line of credit facilities and accounts receivable securitization to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. The Company did not have any swap instruments outstanding on fixed rate debt as of December 31, 20042006 or 2003.2005, however from time to time the Company may enter into treasury lock or forward starting swap contracts to hedge interest rate exposure related to anticipated debt issuance. The carrying amounts and the fair values of Puget Energy’sthe Company’s debt instruments are:
| | 2004 | | 2003 |
(DOLLARS IN MILLIONS) | CARRYING AMOUNT | | | CARRYING AMOUNT | FAIR VALUE |
| Financial liabilities: | | | | | |
| Short-term debt | $ 8.3 | $ 8.3 | | $ 13.9 | $ 13.9 |
Long-term debt- fixed-rate1 | 2,051.4 | 2,194.8 | | 2,216.3 | 2,409.6 |
Long-term debt- variable-rate1 | 200.0 | 199.9 | | -- | -- |
| | | 2006 | | 2005 | |
(Dollars in Millions) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| Financial liabilities: | | | | | | | | | |
| Short-term debt | | $ | 328.0 | | $ | 328.0 | | $ | 41.0 | | $ | 41.0 | |
| Short-term debt owed by PSE to Puget Energy | | | 24.3 | | | 24.3 | | | -- | | | -- | |
Long-term debt - fixed-rate1 | | | 2,733.4 | | | 2,823.3 | | | 2,264.4 | | | 2,416.6 | |
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1 | PSE’s carrying value and fair value of both fixed-rate and variable-rate long-term debt in 2004 was $2,095.4 million and $2,238.7 million, respectively. PSE’s carrying value and fair value of fixed-rate long-term debt was the same as Puget Energy’s debt in 2003 was $2,053.0 million2006 and $2,250.4 million, respectively.2005.
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In the thirdsecond quarter 2004,2006, the Company entered intosettled two treasury lockforward starting swap contracts which originated in May 2005. The purpose of the forward starting swap contracts was to hedge against potential rising interest rate exposure for a debt offering anticipated to be performed in the first half of 2005. A treasury lock is a financial arrangement between the Company and a counterparty whereby one of the parties will be required to make a payment to the other party$200.0 million that was completed on a specific valuation date based upon the change in value of a 30-year treasury bond. If interest rates rise related to the hedged debtJune 30, 2006. PSE received $21.3 million from the date of issuance ofcounterparties when the treasury lock instruments, the Company would receive a payment from the counterparty for the change in the bond value. Alternatively, if interest rates decrease related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would pay the counterparty for the change in bond value. These treasury lock contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period presented net of tax in other comprehensive income. In the second quarter 2006, the settlement of these instruments resulted in a gain of $13.9 million after-tax, which was recorded in other comprehensive income.
In the third quarter 2006, the Company entered into and settled two forward starting swap contracts. The purpose of the forward starting swap contracts was to hedge a debt offering of $300.0 million that was priced on September 13, 2006. PSE paid $0.6 million to the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value being presented net of tax in other comprehensive income. In the third quarter 2006, the settlement of these instruments resulted in a loss of $0.4 million after tax, which was recorded in other comprehensive income. In accordance with SFAS No. 133, the loss will be amortized out of other comprehensive income to current earnings as an increase to interest expense over the life of the new debt issued.
The ending balance in other comprehensive income related to settled swaps contracts at December 31, 2006 was a net loss of $8.5 million after-tax and accumulated amortization. This compares to a loss of $22.4 million in other comprehensive income after-tax and accumulated amortization at December 31, 2005. All financial hedge contracts of this type are reviewed by senior management and presented to the Securities Pricing Committee of the Board of Directors and are approved prior to execution. At December 31, 2004, the unrealized loss associated with the two treasury lock contracts was $11.3 million that qualify as cash flow hedges and is included in other comprehensive income. A hypothetical 10% decrease in the interest rate of a 30-year treasury note would result in an additional loss of $12.1 million net of tax in other comprehensive income.The treasury lock contracts will settle completely in 2005.
TREASURY LOCK CONTRACTS
(DOLLARS IN MILLIONS)
| AMOUNTS |
Fair value of contracts outstanding at December 31, 2003 | $ -- |
Contracts realized or otherwise settled during 2004 | -- |
Changes in fair values of derivatives | (11.3) |
Fair value of contracts outstanding at December 31, 2004 | $ (11.3) |
| FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
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CONSOLIDATED FINANCIAL STATEMENTS: | |
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PUGET ENERGY: | |
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for the years ended December 31, 2004, 20032006, 2005 and 20022004 | |
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for the years ended December 31, 2004, 20032006, 2005 and 20022004 | |
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for the years ended December 31, 2004, 20032006, 2005 and 20022004 | |
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PUGET SOUND ENERGY: | |
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for the years ended December 31, 2004, 20032006, 2005 and 20022004 | |
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for the years ended December 31, 2004, 20032006, 2005 and 20022004 | |
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for the years ended December 31, 2004, 20032006, 2005 and 20022004 | |
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CombinedNOTES To Consolidated Financial Statements of Puget Energy and Puget Sound Energy Notes to Consolidated Financial Statements | Energy: |
| Note 1. | |
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SCHEDULE: | |
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for the years ended December 31, 2004, 20032006, 2005 and 20022004 | |
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| All other schedules have been omitted because of the absence of the conditions under which they are required, or because the information required is included in the financial statements or the notes thereto. | |
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| Financial statements of PSE’s subsidiaries are not filed herewith inasmuch as the assets, revenues, earnings and earnings reinvested in the business of the subsidiaries are not material in relation to those of PSE. | |
REPORT OF MANAGEMENT AND STATEMENT OF RESPONSIBILITY Puget Energy, Inc.
and
PUGET SOUND ENERGY, INC.Puget Sound Energy, Inc.
Puget Energy, Inc. and Puget Sound Energy, Inc. (the Company) management assumes accountability for maintaining compliance with our established financial accounting policies and for reporting our results with objectivity and integrity. The Company believes it is essential for investors and other users of the consolidated financial statements to have confidence that the financial information we provide is timely, complete, relevant, and accurate. Management is also responsible to present fairly Puget Energy’s and Puget Sound Energy’s consolidated financial statements, prepared in accordance with generally accepted accounting principles.
Management, with oversight of the Board of Directors, established and maintains a strong ethical climate under the guidance of our Corporate Ethics and Compliance Program so that our affairs are conducted to high standards of proper personal and corporate conduct. Management also established an internal control system that provides reasonable assurance as to the integrity and accuracy of the consolidated financial statements. These policies and practices reflect corporate governance initiatives that are compliant with the corporate governance requirements of the Sarbanes-Oxley Act of 2002, including:
| · | Our Board has adopted clear corporate governance guidelines. |
| · | With the exception of the Chief Executive Officer,Chairman of the Board, the Board members are independent of the Company and its management. |
| · | All members of our key Board committees - the Audit Committee, the Compensation and Development Committee and the Governance and Public Affairs Committee - are independent of the Company and its management. |
| · | The independent members of our Board meet regularly without the presence of Puget Energy and Puget Sound Energy management. |
| · | The Charters of our Board committees clearly establish their respective roles and responsibilities. |
| · | The Company has adopted a ComplianceCorporate Ethics and EthicsCompliance Code with a hotline (through an independent third party) available to all employees, and our Audit Committee has procedures in place for the anonymous submission of employee complaints on accounting, internal accounting controls or auditing matters. The Compliance Program is led by a senior officerthe Chief Ethics and Compliance Officer of the Company. |
| · | Our internal audit control function maintains critical oversight over the key areas of our business and financial processes and controls, and reports directly to our Board Audit Committee. |
Management is confident that the internal control structure is operating effectively and will allow the Company to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, reports directly to the Audit Committee of the Board of Directors. PricewaterhouseCoopers LLP’s accompanying report on our consolidated financial statements is based on its examinationaudit conducted in accordance with auditing standards generally accepted inprescribed by the United States,Public Company Accounting Oversight Board, including a review of our internal control structure for purposes of designing their audit procedures. Our independent registered accounting firm has reported on the effectiveness of our internal control over financial reporting as required under Section 404 of the Sarbanes-Oxley Act of 2002. The Company is confident in the effectiveness of our internal controls and our ability to meet the requirements of this newly enacted legislation.
We are committed to improving shareholder value and accept our fiduciary oversight responsibilities. We are dedicated to ensuring that our high standards of financial accounting and reporting as well as our underlying system of internal controls are maintained. Our culture demands integrity and we have confidence in our processes, our internal controls, and our people, who are objective in their responsibilities and who operate under a high level of ethical standards.
| /s/ Stephen P. Reynolds | | /s/ Bertrand A. Valdman | | /s/ James W. Eldredge |
| Stephen P. Reynolds | | Bertrand A. Valdman | | James W. Eldredge |
Chairman, President and Chief Executive Officer | | Senior Vice President Finance Andand Chief Financial Officer
| | Vice President, Corporate Secretary and Chief Accounting Officer |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have completed an integrated auditaudits of Puget Energy Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement scheduleschedules
In our opinion, the consolidated financial statements listed in the accompanying index, present fairly, in all material respects, the financial position of Puget Energy, Inc. and its subsidiaries at December 31, 20042006 and 2003,December 31, 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20042006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement scheduleschedules listed in the accompanying indexpresents present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement scheduleschedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement scheduleschedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As describeddiscussed in Note 24 to the consolidated financial statements, effective January 1, 2004, the Company changed its method of accountingthe manner in which it accounts for realized gains and losses on physically settled derivative contracts not held for trading purposes as required by EITF Issue No. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Definedconditional asset retirement obligations in Issue No. 02-03”. 2005.
As describeddiscussed in Note 216 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accountingthe manner in which it accounts for asset retirement obligations as required by Statement of Financial Accounting Standards No. 143 “Accountingshare-based compensation in 2006.
As discussed in Note 14 to the consolidated financial statements, the Company changed the manner in which it accounts for Asset Retirement Obligations”.defined pension and other postretirement plans in 2006.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’sManagement's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 20042006 based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004,2006, based on criteria established inInternal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
/s/PricewaterhouseCoopers LLP
Seattle, WashingtonWA
March 1, 20052007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have completed an integrated auditaudits of Puget Sound Energy Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the accompanying index, present fairly, in all material respects, the financial position of Puget Sound Energy, Inc. and its subsidiaries at December 31, 20042006 and 2003,December 31, 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20042006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As describeddiscussed in Note 24 to the consolidated financial statements, effective January 1, 2004, the Company changed its method of accountingthe manner in which it accounts for realized gains and losses on physically settled derivative contracts not held for trading purposes as required by EITF Issue No. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Definedconditional asset retirement obligations in Issue No. 02-03”. 2005.
As describeddiscussed in Note 216 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accountingthe manner in which it accounts for asset retirement obligations as required by Statement of Financial Accounting Standards No. 143 “Accountingshare-based compensation in 2006.
As discussed in Note 14 to the consolidated financial statements, the Company changed the manner in which it accounts for Asset Retirement Obligations”.defined pension and other postretirement plans in 2006.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’sManagement's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 20042006 based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004,2006, based on criteria established inInternal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
/s/PricewaterhouseCoopers LLP
Seattle, WashingtonWA
March 1, 20052007
PugetPuget Energy Consolidated Statements of(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) FOR YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | | |
(Dollars in Thousands, except per share amounts) For Years Ended December 31 | | | 2006 | | 2005 | | 2004 | |
| Operating revenues: | | | | | | | | | | | | | | |
| Electric | | $ | 1,423,034 | | $ | 1,400,743 | | $ | 1,288,744 | | | $ | 1,777,745 | | $ | 1,612,869 | | $ | 1,423,034 | |
| Gas | | | 769,306 | | | 634,230 | | | 697,155 | | | | 1,120,118 | | | 952,515 | | | 769,306 | |
| Non-utility construction services | | | 369,936 | | | 341,787 | | | 319,529 | | |
| Other | | | 6,537 | | | 6,043 | | | 9,753 | | | | 7,830 | | | 7,826 | | | 6,537 | |
| Total operating revenues | | | 2,568,813 | | | 2,382,803 | | | 2,315,181 | | | | 2,905,693 | | | 2,573,210 | | | 2,198,877 | |
| Operating expenses: | | | | | | | | | | | | | | | | | | | | |
| Energy costs: | | | | | | | | | | | | | | | | | | | | |
| Purchased electricity | | | 723,567 | | | 714,469 | | | 568,230 | | | | 917,801 | | | 860,422 | | | 723,567 | |
| Electric generation fuel | | | 80,772 | | | 64,999 | | | 113,538 | | | | 97,320 | | | 73,318 | | | 80,772 | |
| Residential exchange | | | (174,473 | ) | | (173,840 | ) | | (149,970 | ) | | | (163,622 | ) | | (180,491 | ) | | (174,473 | ) |
| Purchased gas | | | 451,302 | | | 327,132 | | | 405,016 | | | | 723,232 | | | 592,120 | | | 451,302 | |
| Unrealized (gain) loss on derivative instruments | | | (526 | ) | | 106 | | | (11,612 | ) | | | 71 | | | 472 | | | (526 | ) |
| Utility operations and maintenance | | | 291,232 | | | 289,702 | | | 286,220 | | | | 354,590 | | | 333,256 | | | 291,232 | |
| Other operations and maintenance | | | 322,517 | | | 303,972 | | | 273,157 | | | | 3,041 | | | 2,657 | | | 2,326 | |
| Depreciation and amortization | | | 246,842 | | | 236,866 | | | 228,743 | | | | 262,341 | | | 241,634 | | | 228,566 | |
| Conservation amortization | | | 22,688 | | | 33,458 | | | 17,501 | | | | 32,320 | | | 24,308 | | | 22,688 | |
| Goodwill impairment | | | 91,196 | | | -- | | | -- | | |
| Taxes other than income taxes | | | 221,981 | | | 208,395 | | | 215,429 | | | | 255,712 | | | 233,742 | | | 208,989 | |
| Income taxes | | | 74,964 | | | 72,369 | | | 59,260 | | | | 96,271 | | | 88,609 | | | 76,756 | |
| Total operating expenses | | | 2,352,062 | | | 2,077,628 | | | 2,005,512 | | | | 2,579,077 | | | 2,270,047 | | | 1,911,199 | |
| Operating income | | | 216,751 | | | 305,175 | | | 309,669 | | | | 326,616 | | | 303,163 | | | 287,678 | |
| Other income (deductions): | | | | | | | | | | | | | | | | | | | | |
| Other income | | | 4,292 | | | 1,564 | | | 5,458 | | | | 29,962 | | | 16,803 | | | 11,044 | |
| Charitable contributions | | | | (15,000 | ) | | -- | | | -- | |
| Other expense | | | | (9,999 | ) | | (11,063 | ) | | (9,517 | ) |
| Income taxes | | | | 3,784 | | | 2,569 | | | 2,835 | |
| Interest charges: | | | | | | | | | | | | | | | | | | | | |
| AFUDC | | | 5,420 | | | 3,343 | | | 1,969 | | | | 15,874 | | | 9,493 | | | 5,420 | |
| Interest expense | | | (178,419 | ) | | (187,316 | ) | | (198,346 | ) | | | (183,922 | ) | | (174,591 | ) | | (171,959 | ) |
| Mandatorily redeemable securities interest expense | | | (91 | ) | | (1,072 | ) | | -- | | | | (91 | ) | | (91 | ) | | (91 | ) |
| Preferred stock dividends of subsidiary | | | -- | | | (5,151 | ) | | (7,831 | ) | |
| Minority interest in earnings of consolidated subsidiary | | | 7,069 | | | (177 | ) | | (867 | ) | |
| Net income from continuing operations | | | | 167,224 | | | 146,283 | | | 125,410 | |
| Income (loss) from discontinued segment (net of tax) | | | | 51,903 | | | 9,514 | | | (70,388 | ) |
| Net income before cumulative effect of accounting change | | | 55,022 | | | 116,366 | | | 110,052 | | | | 219,127 | | | 155,797 | | | 55,022 | |
| Cumulative effect of implementation of accounting change (net of tax) | | | -- | | | 169 | | | -- | | | | 89 | | | (71 | ) | | -- | |
| Net income | | $ | 55,022 | | $ | 116,197 | | $ | 110,052 | | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Common shares outstanding weighted average (in thousands) | | | 99,470 | | | 94,750 | | | 88,372 | | | | 115,999 | | | 102,570 | | | 99,470 | |
| Diluted shares outstanding weighted average (in thousands) | | | 99,911 | | | 95,309 | | | 88,777 | | | | 116,457 | | | 103,111 | | | 99,911 | |
Basic earnings per common share before cumulative effect of accounting change | | $ | 0.55 | | $ | 1.23 | | $ | 1.24 | | |
Basic earnings per common share for cumulative effect of accounting change | | | -- | | | -- | | | -- | | |
| Basic earnings per common share before cumulative effect from accounting change | | | $ | 1.44 | | $ | 1.43 | | $ | 1.26 | |
| Basic earnings per common share from discontinued operations | | | | 0.45 | | | 0.09 | | | (0.71 | ) |
| Cumulative effect from accounting change | | | | -- | | | -- | | | -- | |
| Basic earnings per common share | | $ | 0.55 | | $ | 1.23 | | $ | 1.24 | | | $ | 1.89 | | $ | 1.52 | | $ | 0.55 | |
Diluted earnings per common share before cumulative effect of accounting change | | $ | 0.55 | | $ | 1.22 | | $ | 1.24 | | |
Diluted earnings per common share for cumulative effect of accounting change | | | -- | | | -- | | | -- | | |
| Diluted earnings per common share before cumulative effect from accounting change | | | $ | 1.44 | | $ | 1.42 | | $ | 1.26 | |
| Diluted earnings per common share from discontinued operations | | | | 0.44 | | | 0.09 | | | (0.71 | ) |
| Cumulative effect from accounting change | | | | -- | | | -- | | | -- | |
| Diluted earnings per common share | | $ | 0.55 | | $ | 1.22 | | $ | 1.24 | | | $ | 1.88 | | $ | 1.51 | | $ | 0.55 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Balance Sheets (DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | | |
(Dollars in Thousands) At December 31 | | | 2006 | | 2005 | |
| Utility plant: | | | | | | | | | | |
| Electric plant | | $ | 4,389,882 | | $ | 4,265,908 | | | $ | 5,334,368 | | $ | 4,802,363 | |
| Gas plant | | | 1,881,768 | | | 1,749,102 | | | | 2,146,048 | | | 1,991,456 | |
| Common plant | | | 409,677 | | | 390,622 | | | | 458,262 | | | 439,599 | |
| Less: Accumulated depreciation and amortization | | | (2,452,969 | ) | | (2,325,405 | ) | | | (2,757,632 | ) | | (2,602,500 | ) |
| Net utility plant | | | 4,228,358 | | | 4,080,227 | | | | 5,181,046 | | | 4,630,918 | |
| Other property and investments: | | | | | | | | |
| Goodwill, net | | | 43,503 | | | 133,302 | | |
| Intangibles, net | | | 16,680 | | | 18,707 | | |
| Other | | | 257,785 | | | 250,084 | | |
| Total other property and investments | | | 317,968 | | | 402,093 | | |
| Other property and investments | | | | 151,462 | | | 157,321 | |
| Current assets: | | | | | | | | | | | | | | |
| Cash | | | 19,771 | | | 27,481 | | | | 28,117 | | | 16,710 | |
| Restricted cash | | | 1,633 | | | 2,537 | | | | 839 | | | 1,047 | |
| Accounts receivable, net of allowance for doubtful accounts | | | 216,304 | | | 227,115 | | | | 253,613 | | | 294,509 | |
| Secured pledged accounts receivable | | | | 110,000 | | | 41,000 | |
| Unbilled revenues | | | 140,391 | | | 131,798 | | | | 202,492 | | | 160,207 | |
| Purchased gas adjustment receivable | | | 19,088 | | | -- | | | | 39,822 | | | 67,335 | |
| Materials and supplies, at average cost | | | 107,356 | | | 85,128 | | | | 43,501 | | | 36,491 | |
| Current portion of unrealized gain on derivative instruments | | | 8,087 | | | 7,593 | | |
| Fuel and gas inventory, at average cost | | | | 115,752 | | | 91,058 | |
| Unrealized gain on derivative instruments | | | | 16,826 | | | 75,037 | |
| Prepayments and other | | | 20,360 | | | 12,200 | | | | 9,228 | | | 7,596 | |
| Deferred income taxes | | | | 1,175 | | | -- | |
| Current assets of discontinued operations | | | | -- | | | 107,434 | |
| Total current assets | | | 532,990 | | | 493,852 | | | | 821,365 | | | 898,424 | |
| Other long-term assets: | | | | | | | | | | | | | | |
| Restricted cash | | | | 3,814 | | | -- | |
| Regulatory asset for deferred income taxes | | | 127,252 | | | 142,792 | | | | 115,304 | | | 129,693 | |
| Regulatory asset for PURPA buyout costs | | | 211,241 | | | 227,753 | | | | 167,941 | | | 191,170 | |
| Unrealized gain on derivative instruments | | | 13,765 | | | 8,624 | | | | 6,934 | | | 28,464 | |
| Power cost adjustment mechanism | | | -- | | | 3,605 | | | | 6,357 | | | 18,380 | |
| Other | | | 401,795 | | | 340,056 | | | | 611,816 | | | 388,468 | |
| Long-term assets of discontinued operations | | | | -- | | | 167,113 | |
| Total other long-term assets | | | 754,053 | | | 722,830 | | | | 912,166 | | | 923,288 | |
| Total assets | | $ | 5,833,369 | | $ | 5,699,002 | | | $ | 7,066,039 | | $ | 6,609,951 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Balance Sheets (DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | | |
(Dollars in Thousands) At December 31 | | | 2006 | | 2005 | |
| Capitalization: | | | | | | | | | | |
(See Consolidated Statements of Capitalization ) | | | | | | | | | | |
| Common equity | | $ | 1,622,276 | | $ | 1,655,046 | | | $ | 2,116,029 | | $ | 2,027,047 | |
| Total shareholders’ equity | | | 1,622,276 | | | 1,655,046 | | | | 2,116,029 | | | 2,027,047 | |
| Redeemable securities and long-term debt: | | | | | | | | | | | | | | |
| Preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | | | | 1,889 | | | 1,889 | |
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 280,250 | | | 280,250 | | | | 37,750 | | | 237,750 | |
| Long-term debt | | | 2,212,532 | | | 1,969,489 | | | | 2,608,360 | | | 2,183,360 | |
| Total redeemable securities and long-term debt | | | 2,494,671 | | | 2,251,628 | | | | 2,647,999 | | | 2,422,999 | |
| Total capitalization | | | 4,116,947 | | | 3,906,674 | | | | 4,764,028 | | | 4,450,046 | |
| Minority interest in consolidated subsidiary | | | 4,648 | | | 11,689 | | |
| Minority interest in discontinued operations | | | | -- | | | 6,816 | |
| Current liabilities: | | | | | | | | | | | | | | |
| Accounts payable | | | 239,520 | | | 214,357 | | | | 379,579 | | | 346,490 | |
| Short-term debt | | | 8,297 | | | 13,893 | | | | 328,055 | | | 41,000 | |
| Current maturities of long-term debt | | | 38,933 | | | 246,829 | | | | 125,000 | | | 81,000 | |
| Purchased gas adjustment liability | | | -- | | | 11,984 | | |
| Accrued expenses: | | | | | | | | | | | | | | |
| Taxes | | | 77,698 | | | 77,451 | | | | 54,977 | | | 112,860 | |
| Salaries and wages | | | 13,829 | | | 12,712 | | | | 32,122 | | | 15,034 | |
| Interest | | | 29,005 | | | 32,954 | | | | 36,915 | | | 31,004 | |
| Current portion of unrealized loss on derivative instruments | | | 19,261 | | | 3,636 | | |
| Tenaska disallowance reserve | | | 3,156 | | | -- | | |
| Unrealized loss on derivative instruments | | | | 70,596 | | | 9,772 | |
| Deferred income tax | | | | -- | | | 10,968 | |
| Other | | | 61,155 | | | 46,378 | | | | 43,889 | | | 35,694 | |
| Current liabilities of discontinued operations | | | | -- | | | 55,791 | |
| Total current liabilities | | | 490,854 | | | 660,194 | | | | 1,071,133 | | | 739,613 | |
| Long-term liabilities: | | | | | | | | | | | | | | |
| Deferred income taxes | | | 810,726 | | | 755,235 | | | | 745,095 | | | 738,809 | |
| Long-term portion of unrealized loss on derivative instruments | | | 249 | | | -- | | |
| Unrealized loss on derivative instruments | | | | 415 | | | -- | |
| Other deferred credits | | | 409,945 | | | 365,210 | | | | 485,368 | | | 513,023 | |
| Long-term liabilities of discontinued operations | | | | -- | | | 161,644 | |
| Total long-term liabilities | | | 1,220,920 | | | 1,120,445 | | | | 1,230,878 | | | 1,413,476 | |
| Commitments and contingencies | | | | | | | | |
| Commitments and contingencies (Note 22) | | | | | | | | |
| Total capitalization and liabilities | | $ | 5,833,369 | | $ | 5,699,002 | | | $ | 7,066,039 | | $ | 6,609,951 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Statements of
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | | |
(Dollars in Thousands) At December 31 | | | 2006 | | 2005 | |
| Common equity: | | | | | | | | | | |
Common stock $0.01 par value, 250,000,000 shares authorized, 99,868,368 and 99,074,070 shares outstanding at December 31, 2004 and 2003 | | $ | 999 | | $ | 991 | | |
| Common stock $0.01 par value, 250,000,000 shares authorized, 116,576,636 and 115,695,463 shares outstanding at December 31, 2006 and 2005 | | | $ | 1,166 | | $ | 1,157 | |
| Additional paid-in capital | | | 1,621,756 | | | 1,603,901 | | | | 1,969,032 | | | 1,948,975 | |
| Earnings reinvested in the business | | | 13,853 | | | 58,217 | | | | 172,529 | | | 69,407 | |
Accumulated other comprehensive income (loss)- net of tax | | | (14,332 | ) | | (8,063 | ) | | | (26,698 | ) | | 7,508 | |
| Total common equity | | | 1,622,276 | | | 1,655,046 | | | | 2,116,029 | | | 2,027,047 | |
Preferred stock subject to mandatory redemption- cumulative- $100 par value: * | | | | | | | | | | | | | | |
4.84% series-150,000 shares authorized, 14,583 shares outstanding at December 31, 2004 and 2003 | | | 1,458 | | | 1,458 | | |
4.70% series-150,000 shares authorized, 4,311 shares outstanding at December 31, 2004 and 2003 | | | 431 | | | 431 | | |
4.84% series -150,000 shares authorized, 14,583 shares outstanding at December 31, 2006 and 2005 | | | | 1,458 | | | 1,458 | |
4.70% series -150,000 shares authorized, 4,311 shares outstanding at December 31, 2006 and 2005 | | | | 431 | | | 431 | |
| Total preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | | | | 1,889 | | | 1,889 | |
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 280,250 | | | 280,250 | | | | 37,750 | | | 237,750 | |
| Long-term debt: | | | | | | | | | | | | | | |
| First mortgage bonds and senior notes | | | 1,933,500 | | | 1,891,158 | | | | 2,571,500 | | | 2,102,500 | |
| Pollution control revenue bonds: | | | | | | | | | | | | | | |
| Revenue refunding 2003 series, due 2031 | | | 161,860 | | | 161,860 | | | | 161,860 | | | 161,860 | |
| Other notes | | | 156,105 | | | 163,313 | | | | -- | | | -- | |
Unamortized discount- net of premium | | | -- | | | (13 | ) | |
| Long-term debt due within one year | | | (38,933 | ) | | (246,829 | ) | | | (125,000 | ) | | (81,000 | ) |
| Total long-term debt excluding current maturities | | | 2,212,532 | | | 1,969,489 | | | | 2,608,360 | | | 2,183,360 | |
| Total capitalization | | $ | 4,116,947 | | $ | 3,906,674 | | | $ | 4,764,028 | | $ | 4,450,046 | |
* Puget Energy has 50,000,000 shares authorized for $0.01 par value preferred stock. Puget Sound Energy has 13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock. The preferred stock is available for issuance under mandatory and non-mandatory redemption provisions.
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Statements of | | | Common Stock | | | | | | Accumulated | | | | |
(DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31, 2004, 2003 & 2002 | | Shares | | Amount | | Additional Paid-in Capital | | Retained Earnings | | Other Comprehensive Income | | Total Amount | | |
| Balance at December 31, 2001 | | | 87,023,210 | | $ | 870 | | $ | 1,358,946 | | $ | 32,229 | | $ | (29,321 | ) | $ | 1,362,724 | | |
| Net income | | | -- | | -- | | -- | | 110,052 | | -- | | 110,052 | | |
| Common stock dividend declared | | | -- | | -- | | -- | | (105,687 | ) | | -- | | (105,687 | ) | |
| Common stock issued: | | | | | | | | | | | | | | | |
| New issuance | | | 5,750,000 | | 57 | | 114,639 | | -- | | -- | | 114,696 | | |
| Dividend reinvestment plan | | | 801,205 | | 8 | | 16,900 | | -- | | -- | | 16,908 | | |
| Employee plans | | | 68,252 | | 1 | | 550 | | -- | | -- | | 551 | | |
| Other | | | (8 | ) | | -- | | (6,420 | ) | | (198 | ) | | -- | | (6,618 | ) | |
| Other comprehensive income | | | -- | | -- | | -- | | -- | | 31,161 | | 31,161 | | |
| | | | | | | | | | | | | | | | |
| Balance at December 31, 2002 | | | 93,642,659 | | $ | 936 | | $ | 1,484,615 | | $ | 36,396 | | $ | 1,840 | | $ | 1,523,787 | | |
| Net income | | | -- | | -- | | -- | | 116,197 | | -- | | 116,197 | | |
| Common stock dividend declared | | | -- | | -- | | -- | | (93,965 | ) | | -- | | (93,965 | ) | |
| Common stock issued: | | | | | | | | | | | | | | | |
| New issuance | | | 4,650,600 | | 47 | | 102,231 | | -- | | -- | | 102,278 | | |
| Dividend reinvestment plan | | | 721,340 | | 7 | | 15,447 | | -- | | -- | | 15,454 | | |
| Employee plans | | | 59,475 | | 1 | | 1,616 | | -- | | -- | | 1,617 | | |
| Other | | | (4 | ) | | -- | | (8 | ) | | (411 | ) | | -- | | (419 | ) | |
| Other comprehensive loss | | | -- | | -- | | -- | | -- | | (9,903 | ) | | (9,903 | ) | |
| | | | | | | | | | | | | | | | |
| (Dollars in Thousands) | | | Common Stock | Additional | | | | Accumulated Other | | | |
For Years Ended December 31, 2006, 2005 & 2004 | | | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Comprehensive Income | | Total Amount | |
| Balance at December 31, 2003 | | | 99,074,070 | | $ | 991 | | $ | 1,603,901 | | $ | 58,217 | | $ | (8,063 | ) | $ | 1,655,046 | | | | 99,074,070 | | $ | 991 | | $ | 1,603,901 | | $ | 58,217 | | $ | (8,063 | ) | $ | 1,655,046 | |
| Net income | | | -- | | -- | | -- | | 55,022 | | -- | | 55,022 | | | | -- | | | -- | | -- | | | 55,022 | | | -- | | | 55,022 | |
| Common stock dividend declared | | | -- | | -- | | -- | | (99,386 | ) | | -- | | (99,386 | ) | | | -- | | | -- | | -- | | | (99,386 | ) | | -- | | | (99,386 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| New issuance | | | 5,195 | | -- | | 68 | | -- | | -- | | 68 | | | | 5,195 | | | -- | | 68 | | | -- | | | -- | | | 68 | |
| Dividend reinvestment plan | | | 681,491 | | 7 | | 15,170 | | -- | | -- | | 15,177 | | | | 681,491 | | | 7 | | 15,170 | | | -- | | | -- | | | 15,177 | |
| Employee plans | | | 107,612 | | 1 | | 2,617 | | -- | | -- | | 2,618 | | | | 107,612 | | | 1 | | 2,617 | | | -- | | | -- | | | 2,618 | |
| Other comprehensive loss | | | -- | | -- | | -- | | -- | | (6,269 | ) | | (6,269 | ) | | | -- | | | -- | | -- | | | -- | | | (6,269 | ) | | (6,269 | ) |
| Balance at December 31, 2004 | | | 99,868,368 | | $ | 999 | | $ | 1,621,756 | | $ | 13,853 | | $ | (14,332 | ) | $ | 1,622,276 | | | | 99,868,368 | | $ | 999 | | $ | 1,621,756 | | $ | 13,853 | | $ | (14,332 | ) | $ | 1,622,276 | |
| Net income | | | | -- | | | -- | | -- | | | 155,726 | | | -- | | | 155,726 | |
| Common stock dividend declared | | | | -- | | | -- | | -- | | | (100,172 | ) | | -- | | | (100,172 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | |
| New issuance | | | | 15,009,991 | | | 150 | | 309,744 | | | -- | | | -- | | | 309,894 | |
| Dividend reinvestment plan | | | | 656,267 | | | 6 | | 14,545 | | | -- | | | -- | | | 14,551 | |
| Employee plans | | | | 160,837 | | | 2 | | 2,930 | | | -- | | | -- | | | 2,932 | |
| Other comprehensive loss | | | | -- | | | -- | | -- | | | -- | | | 21,840 | | | 21,840 | |
| Balance at December 31, 2005 | | | | 115,695,463 | | $ | 1,157 | | $ | 1,948,975 | | $ | 69,407 | | $ | 7,508 | | $ | 2,027,047 | |
| Net income | | | | -- | | | -- | | -- | | | 219,216 | | | -- | | | 219,216 | |
| Common stock dividend declared | | | | -- | | | -- | | -- | | | (116,094 | ) | | -- | | | (116,094 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | |
| Dividend reinvestment plan | | | | 614,548 | | | 6 | | 13,481 | | | -- | | | -- | | | 13,487 | |
| Employee plans | | | | 266,625 | | | 3 | | 6,576 | | | -- | | | -- | | | 6,579 | |
| Other comprehensive loss | | | | -- | | | -- | | -- | | | -- | | | (15,553 | ) | | (15,553 | ) |
| Adjustment to initially apply SFAS No. 158, net of tax of $(12,420) | | | | -- | | | -- | | -- | | | -- | | | (18,653 | ) | | (18,653 | ) |
| Balance at December 31, 2006 | | | | 116,576,636 | | $ | 1,166 | | $ | 1,969,032 | | $ | 172,529 | | $ | (26,698 | ) | $ | 2,116,029 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Statements of (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | |
| Net income | | $ | 55,022 | | $ | 116,197 | | $ | 110,052 | |
| Other comprehensive income, net of tax: | | | | | | | | | | |
| Unrealized holding losses on marketable securities during the period | | | -- | | | (45 | ) | | (1,359 | ) |
Reclassification adjustment for realized gains on marketable securities included in net income | | | -- | | | (1,518 | ) | | -- | |
| Foreign currency translation adjustment | | | 275 | | | 80 | | | 63 | |
| Minimum pension liability adjustment | | | 157 | | | (1,122 | ) | | (2,098 | ) |
| Unrealized gains on derivative instruments during the period | | | 6,820 | | | 8,576 | | | 2,853 | |
Reversal of unrealized (gains) losses on derivative instruments settled during the period | | | (10,418 | ) | | 181 | | | 31,702 | |
| Deferral related to power cost adjustment mechanism | | | (3,103 | ) | | (16,055 | ) | | -- | |
| Other comprehensive income (loss) | | | (6,269 | ) | | (9,903 | ) | | 31,161 | |
| Comprehensive income | | $ | 48,753 | | $ | 106,294 | | $ | 141,213 | |
(Dollars in Thousands) For Years Ended December 31 | | 2006 | 2005 | 2004 |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Other comprehensive income (loss): | | | | | | | | | | |
| Foreign currency translation adjustment, net of tax of $(176), $(49) and $148, respectively | | | (327 | ) | | (91 | ) | | 275 | |
| Minimum pension liability adjustment, net of tax of $2,376, $0 and $0, respectively | | | 2,873 | | | 925 | | | 157 | |
| Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $(17,669), $26,799 and $3,672, respectively | | | (32,813 | ) | | 49,770 | | | 6,820 | |
| Reversal of net unrealized (gains) losses on energy derivative instruments settled during the period, net of tax of $(2,972), $(10,319) and $(5,610), respectively | | | (5,519 | ) | | (19,164 | ) | | (10,418 | ) |
| Gain (loss) from settlement of financing cash flow hedge contracts, net of tax of $7,239, $(12,363) and $0, respectively | | | 13,443 | | | (22,960 | ) | | -- | |
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $289, $245 and $0, respectively | | | 537 | | | 455 | | | -- | |
| Deferral of energy cash flow hedges related to power cost adjustment mechanism, net of tax of $3,367, $6,949 and $(1,671), respectively | | | 6,253 | | | 12,905 | | | (3,103 | ) |
| Other comprehensive income (loss) | | | (15,553 | ) | | 21,840 | | | (6,269 | ) |
| Comprehensive income | | $ | 203,663 | | $ | 177,566 | | $ | 48,753 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Statements of (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | | |
(Dollars in Thousands) For Years Ended December 31 | | | 2006 | | 2005 | | 2004 | |
| Operating activities: | | | | | | | | | | | | | | |
| Net income | | $ | 55,022 | | $ | 116,197 | | $ | 110,052 | | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 246,842 | | | 236,866 | | | 228,743 | | | | 262,341 | | | 241,634 | | | 246,842 | |
Deferred income taxes and tax credits- net | | | 72,702 | | | 57,470 | | | 151,318 | | | | 20,613 | | | (56,852 | ) | | 72,702 | |
| Gain from sale of securities | | | -- | | | (2,889 | ) | | -- | | |
| Net unrealized (gains) losses on derivative instruments | | | (526 | ) | | 106 | | | (11,612 | ) | |
| Power cost adjustment mechanism | | | | 12,023 | | | (18,380 | ) | | 3,605 | |
| Non cash return on regulatory assets | | | | (12,438 | ) | | -- | | | -- | |
| Amortization of gas pipeline capacity assignment | | | | (10,632 | ) | | -- | | | -- | |
| Gain on sale of InfrastruX | | | | (29,765 | ) | | -- | | | -- | |
| InfrastruX carrying value impairment adjustment | | | | (7,269 | ) | | 7,269 | | | -- | |
| InfrastruX goodwill impairment | | | | -- | | | -- | | | 91,196 | |
| Net unrealized (gain) loss on derivative instruments | | | | 71 | | | 472 | | | (526 | ) |
| Other (including conservation amortization) | | | 10,103 | | | 18,683 | | | (18,827 | ) | | | 13,600 | | | 1,131 | | | 8,166 | |
| Cash collateral received from (returned to) energy supplier | | | 6,320 | | | (21,425 | ) | | 21,425 | | |
| Increase (decrease) in residential exchange program | | | 1,668 | | | (25,989 | ) | | 21,201 | | |
| Goodwill impairment | | | 91,196 | | | -- | | | -- | | |
| Pension plan funding | | | -- | | | (26,521 | ) | | -- | | |
| Cash collateral received from (returned to) energy suppliers | | | | (22,020 | ) | | 15,700 | | | 6,320 | |
| Gas pipeline capacity assignment | | | | -- | | | 55,000 | | | -- | |
| BPA prepaid transmission | | | | -- | | | (10,750 | ) | | -- | |
| Chelan PUD contract initiation | | | | (89,000 | ) | | -- | | | -- | |
| Storm damage deferred costs | | | | (92,331 | ) | | -- | | | -- | |
| Change in certain current assets and liabilities: | | | | | | | | | | | | | | | | | | | | |
| Accounts receivable and unbilled revenue | | | 2,218 | | | 37,769 | | | 46,860 | | | | (78,179 | ) | | (217,861 | ) | | 2,218 | |
| Materials and supplies | | | (22,228 | ) | | (14,727 | ) | | 22,088 | | | | (6,093 | ) | | (4,945 | ) | | (39,740 | ) |
| Fuel and gas inventory | | | | (24,694 | ) | | (25,163 | ) | | 17,512 | |
| Prepayments and other | | | (8,159 | ) | | (738 | ) | | 141 | | | | (4,319 | ) | | 273 | | | (8,159 | ) |
| Purchased gas receivable /liability | | | (31,073 | ) | | (71,826 | ) | | 121,039 | | |
| Purchased gas receivable / liability | | | | 27,513 | | | (48,246 | ) | | (31,073 | ) |
| Accounts payable | | | 25,163 | | | 6,464 | | | 34,351 | | | | 36,038 | | | 119,416 | | | 25,163 | |
| Taxes payable | | | 247 | | | 13,405 | | | (18,260 | ) | | | (53,826 | ) | | 38,047 | | | 247 | |
| Tenaska disallowance reserve | | | 3,156 | | | -- | | | -- | | | | -- | | | (3,156 | ) | | 3,156 | |
| Accrued expenses and other | | | 3,709 | | | (4,939 | ) | | (4,603 | ) | | | 24,658 | | | 6,496 | | | 3,709 | |
| Net cash provided by operating activities | | | 456,360 | | | 317,906 | | | 703,916 | | | | 185,507 | | | 255,811 | | | 456,360 | |
| Investing activities: | | | | | | | | | | | | | | | | | | | | |
Construction and capital expenditures- excluding equity AFUDC | | | (409,403 | ) | | (285,510 | ) | | (235,786 | ) | | | (749,516 | ) | | (583,594 | ) | | (409,403 | ) |
| Energy efficiency expenditures | | | (24,852 | ) | | (18,579 | ) | | (11,356 | ) | | | (33,865 | ) | | (24,428 | ) | | (24,852 | ) |
| Restricted cash | | | 905 | | | 20,106 | | | (18,871 | ) | | | (3,605 | ) | | 586 | | | 905 | |
| Cash received from sale of securities | | | -- | | | 3,161 | | | -- | | |
| Cash proceeds from property sales | | | | 936 | | | 24,291 | | | 1,315 | |
| Refundable cash received for customer construction projects | | | 13,424 | | | 5,045 | | | 5,787 | | | | 12,253 | | | 9,869 | | | 13,424 | |
| Investments by InfrastruX | | | -- | | | (10,659 | ) | | (41,602 | ) | |
| Cash proceeds from sale of InfrastruX, net of cash disposed | | | | 263,575 | | | -- | | | -- | |
| Other | | | 1,747 | | | 2,151 | | | (15,761 | ) | | | 5,500 | | | 5,906 | | | 432 | |
| Net cash used by investing activities | | | (418,179 | ) | | (284,285 | ) | | (317,589 | ) | | | (504,722 | ) | | (567,370 | ) | | (418,179 | ) |
| Financing activities: | | | | | | | | | | | | | | | | | | | | |
Decrease in short-term debt- net | | | (5,596 | ) | | (33,402 | ) | | (301,281 | ) | |
Change in short-term debt and leases - net | | | | 290,224 | | | 36,512 | | | (5,596 | ) |
| Dividends paid | | | (86,873 | ) | | (86,671 | ) | | (97,321 | ) | | | (104,332 | ) | | (88,071 | ) | | (86,873 | ) |
| Issuance of common stock | | | 5,413 | | | 106,659 | | | 120,214 | | | | 5,878 | | | 317,607 | | | 5,413 | |
| Issuance of bonds and notes | | | 343,841 | | | 319,497 | | | 107,518 | | | | 550,000 | | | 400,000 | | | 343,841 | |
| Redemption of preferred stock | | | -- | | | (60,000 | ) | | -- | | |
| Redemption of mandatorily redeemable preferred stock | | | -- | | | (41,273 | ) | | (7,500 | ) | |
| Net payments made to minority shareholders of InfrastruX | | | | (10,451 | ) | | -- | | | -- | |
| InfrastruX debt redeemed | | | | (141,221 | ) | | -- | | | -- | |
| Redemption of trust preferred stock | | | -- | | | (19,750 | ) | | -- | | | | (200,000 | ) | | (42,500 | ) | | -- | |
| Redemption of bonds and notes | | | (308,708 | ) | | (357,510 | ) | | (119,281 | ) | |
| Other | | | 6,032 | | | (10,359 | ) | | (4,363 | ) | |
| Net cash used by financing activities | | | (45,891 | ) | | (182,809 | ) | | (302,014 | ) | |
| Redemption of bonds, notes and leases | | | | (83,875 | ) | | (260,615 | ) | | (308,708 | ) |
| Settlement of derivatives | | | | 20,682 | | | (35,323 | ) | | -- | |
| Issuance costs and other | | | | (2,467 | ) | | (12,928 | ) | | 6,032 | |
| Net cash provided (used) by financing activities | | | | 324,438 | | | 314,682 | | | (45,891 | ) |
| Increase (decrease) in cash from net income | | | (7,710 | ) | | (149,188 | ) | | 84,313 | | | | 5,223 | | | 3,123 | | | (7,710 | ) |
| Cash at beginning of year | | | 27,481 | | | 176,669 | | | 92,356 | | | | 22,894 | | | 19,771 | | | 27,481 | |
| Cash at end of year | | $ | 19,771 | | $ | 27,481 | | $ | 176,669 | | | $ | 28,117 | | $ | 22,894 | | $ | 19,771 | |
Supplemental Cash Flow Information: | | | | | | | | | | | |
Supplemental cash flow information: | | | | | | | | | | | |
| Cash payments for: | | | | | | | | | | | | | | | | | | | | |
| Interest (net of capitalized interest) | | $ | 182,419 | | $ | 192,845 | | $ | 200,392 | | |
| Income taxes (net refunds) | | | (1,232 | ) | | (2,777 | ) | | (81,652 | ) | |
| Interest (net of debt AFUDC) | | | $ | 167,789 | | $ | 182,054 | | $ | 182,419 | |
| Income taxes (net of refunds) | | | | 129,100 | | | 126,807 | | | (1,232 | ) |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements of (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | | |
(Dollars in Thousands) For Years Ended December 31 | | | 2006 | | 2005 | | 2004 | |
| Operating revenues: | | | | | | | | | | | | | | |
| Electric | | $ | 1,423,034 | | $ | 1,400,743 | | $ | 1,288,744 | | | $ | 1,777,745 | | $ | 1,612,869 | | $ | 1,423,034 | |
| Gas | | | 769,306 | | | 634,230 | | | 697,155 | | | | 1,120,118 | | | 952,515 | | | 769,306 | |
| Other | | | 6,537 | | | 6,043 | | | 9,753 | | | | 7,830 | | | 7,826 | | | 6,537 | |
| Total operating revenues | | | 2,198,877 | | | 2,041,016 | | | 1,995,652 | | | | 2,905,693 | | | 2,573,210 | | | 2,198,877 | |
| Operating expenses: | | | | | | | | | | | | | | | | | | | | |
| Energy costs: | | | | | | | | | | | | | | | | | | | | |
| Purchased electricity | | | 723,567 | | | 714,469 | | | 568,230 | | | | 917,801 | | | 860,422 | | | 723,567 | |
| Electric generation fuel | | | 80,772 | | | 64,999 | | | 113,538 | | | | 97,320 | | | 73,318 | | | 80,772 | |
| Residential exchange | | | (174,473 | ) | | (173,840 | ) | | (149,970 | ) | | | (163,622 | ) | | (180,491 | ) | | (174,473 | ) |
| Purchased gas | | | 451,302 | | | 327,132 | | | 405,016 | | | | 723,232 | | | 592,120 | | | 451,302 | |
| Unrealized (gain) loss on derivative instruments | | | (526 | ) | | 106 | | | (11,612 | ) | | | 71 | | | 472 | | | (526 | ) |
| Utility operations and maintenance | | | 291,232 | | | 289,702 | | | 286,220 | | | | 354,590 | | | 333,256 | | | 291,232 | |
| Other operations and maintenance | | | 1,342 | | | 1,203 | | | 1,602 | | | | 1,211 | | | 1,304 | | | 1,342 | |
| Depreciation and amortization | | | 228,566 | | | 220,087 | | | 215,317 | | | | 262,341 | | | 241,634 | | | 228,566 | |
| Conservation amortization | | | 22,688 | | | 33,458 | | | 17,501 | | | | 32,320 | | | 24,308 | | | 22,688 | |
| Taxes other than income taxes | | | 208,989 | | | 194,857 | | | 202,381 | | | | 255,712 | | | 233,742 | | | 208,989 | |
| Income taxes | | | 77,177 | | | 70,939 | | | 52,836 | | | | 97,227 | | | 89,629 | | | 77,177 | |
| Total operating expenses | | | 1,910,636 | | | 1,743,112 | | | 1,701,059 | | | | 2,578,203 | | | 2,269,714 | | | 1,910,636 | |
| Operating income | | | 288,241 | | | 297,904 | | | 294,593 | | | | 327,490 | | | 303,496 | | | 288,241 | |
| Other income (deductions): | | | | | | | | | | | | | | | | | | | | |
| Other income | | | 4,362 | | | 1,587 | | | 5,215 | | | | 29,606 | | | 16,803 | | | 11,044 | |
| Other expense | | | | (9,999 | ) | | (11,063 | ) | | (9,517 | ) |
| Income taxes | | | | (1,462 | ) | | 2,569 | | | 2,835 | |
| Interest charges: | | | | | | | | | | | | | | | | | | | | |
| AFUDC | | | 5,420 | | | 3,343 | | | 1,969 | | | | 15,874 | | | 9,493 | | | 5,420 | |
| Interest expense | | | (171,740 | ) | | (181,707 | ) | | (192,829 | ) | | | (183,922 | ) | | (174,367 | ) | | (171,740 | ) |
| Interest expense on Puget Energy note | | | | (845 | ) | | -- | | | -- | |
| Mandatorily redeemable securities interest expense | | | (91 | ) | | (1,072 | ) | | -- | | | | (91 | ) | | (91 | ) | | (91 | ) |
| Net income before cumulative effect of accounting change | | | 126,192 | | | 120,055 | | | 108,948 | | | | 176,651 | | | 146,840 | | | 126,192 | |
| Cumulative effect of implementation of accounting change (net of tax) | | | -- | | | 169 | | | -- | | | | 89 | | | (71 | ) | | -- | |
| Net income | | | 126,192 | | | 119,886 | | | 108,948 | | |
| Less: preferred stock dividends accrual | | | -- | | | 5,151 | | | 7,831 | | |
| Income for common stock | | $ | 126,192 | | $ | 114,735 | | $ | 101,117 | | |
| Net income for common stock | | | $ | 176,740 | | $ | 146,769 | | $ | 126,192 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Balance Sheets (DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | | |
(Dollars in Thousands) At December 31 | | | 2006 | | 2005 | |
| Utility plant: | | | | | | | | | | |
| Electric plant | | $ | 4,389,882 | | $ | 4,265,908 | | | $ | 5,334,368 | | $ | 4,802,363 | |
| Gas plant | | | 1,881,768 | | | 1,749,102 | | | | 2,146,048 | | | 1,991,456 | |
| Common plant | | | 409,677 | | | 390,622 | | | | 458,262 | | | 439,599 | |
| Less: Accumulated depreciation and amortization | | | (2,452,969 | ) | | (2,325,405 | ) | | | (2,757,632 | ) | | (2,602,500 | ) |
| Net utility plant | | | 4,228,358 | | | 4,080,227 | | | | 5,181,046 | | | 4,630,918 | |
| Other property and investments | | | 157,670 | | | 160,280 | | | | 151,462 | | | 157,321 | |
| Current assets: | | | | | | | | | | | | | | |
| Cash | | | 12,955 | | | 14,778 | | | | 28,092 | | | 16,709 | |
| Restricted cash | | | 1,633 | | | 2,537 | | | | 839 | | | 1,047 | |
| Accounts receivable, net of allowance for doubtful accounts | | | 138,792 | | | 155,649 | | | | 253,613 | | | 299,938 | |
| Secured pledged accounts receivable | | | | 110,000 | | | 41,000 | |
| Unbilled revenues | | | 140,391 | | | 131,798 | | | | 202,492 | | | 160,207 | |
| Purchased gas adjustment receivable | | | 19,088 | | | -- | | | | 39,822 | | | 67,335 | |
| Materials and supplies, at average cost | | | 97,578 | | | 77,206 | | | | 43,501 | | | 36,491 | |
| Current portion of unrealized gain on derivative instruments | | | 8,087 | | | 7,593 | | |
| Fuel and gas inventory, at average cost | | | | 115,752 | | | 91,058 | |
| Unrealized gain on derivative instruments | | | | 16,826 | | | 75,037 | |
| Prepayments and other | | | 6,247 | | | 6,285 | | | | 8,659 | | | 7,023 | |
| Deferred income taxes | | | | 1,175 | | | -- | |
| Total current assets | | | 424,771 | | | 395,846 | | | | 820,771 | | | 795,845 | |
| Other long-term assets: | | | | | | | | | | | | | | |
| Regulatory asset for deferred income taxes | | | 127,252 | | | 142,792 | | | | 115,304 | | | 129,693 | |
| Regulatory asset for PURPA buyout costs | | | 211,241 | | | 227,753 | | | | 167,941 | | | 191,170 | |
| Unrealized gain on derivative instruments | | | 13,765 | | | 8,624 | | | | 6,934 | | | 28,464 | |
| Power cost adjustment mechanism | | | -- | | | 3,605 | | | | 6,357 | | | 18,380 | |
| Other | | | 401,030 | | | 339,977 | | | | 611,598 | | | 388,009 | |
| Total other long-term assets | | | 753,288 | | | 722,751 | | | | 908,134 | | | 755,716 | |
| Total assets | | $ | 5,564,087 | | $ | 5,359,104 | | | $ | 7,061,413 | | $ | 6,339,800 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Balance Sheets (DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | | |
(Dollars in Thousands) At December 31 | | | 2006 | | 2005 | |
| Capitalization: | | | | | | | | | | |
(See Consolidated Statements of Capitalization): | | | | | | | | | �� | |
| Common equity | | $ | 1,592,433 | | $ | 1,555,469 | | | $ | 2,092,283 | | $ | 1,986,621 | |
| Total shareholders’ equity | | | 1,592,433 | | | 1,555,469 | | |
| Total shareholder’s equity | | | | 2,092,283 | | | 1,986,621 | |
| Redeemable securities and long-term debt: | | | | | | | | | | | | | | |
| Preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | | | | 1,889 | | | 1,889 | |
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 280,250 | | | 280,250 | | | | 37,750 | | | 237,750 | |
| Long-term debt | | | 2,064,360 | | | 1,950,347 | | | | 2,608,360 | | | 2,183,360 | |
| Total redeemable securities and long-term debt | | | 2,346,499 | | | 2,232,486 | | | | 2,647,999 | | | 2,422,999 | |
| Total capitalization | | | 3,938,932 | | | 3,787,955 | | | | 4,740,282 | | | 4,409,620 | |
| Current liabilities: | | | | | | | | | | | | | | |
| Accounts payable | | | 229,747 | | | 206,465 | | | | 379,494 | | | 346,490 | |
| Short-term debt | | | | 328,055 | | | 41,000 | |
| Short-term debt owed to Puget Energy | | | | 24,303 | | | -- | |
| Current maturities of long-term debt | | | 31,000 | | | 102,658 | | | | 125,000 | | | 81,000 | |
| Purchased gas adjustment liability | | | -- | | | 11,984 | | |
| Accrued expenses: | | | | | | | | | | | | | | |
| Taxes | | | 81,634 | | | 82,342 | | | | 55,365 | | | 111,900 | |
| Salaries and wages | | | 13,829 | | | 12,712 | | | | 31,591 | | | 15,034 | |
| Interest | | | 29,005 | | | 32,954 | | | | 37,031 | | | 31,004 | |
| Current portion of unrealized loss on derivative instruments | | | 19,261 | | | 3,636 | | |
| Tenaska disallowance reserve | | | 3,156 | | | -- | | |
| Unrealized loss on derivative instruments | | | | 70,596 | | | 9,772 | |
| Deferred income taxes | | | | -- | | | 10,968 | |
| Other | | | 34,918 | | | 26,514 | | | | 43,889 | | | 30,932 | |
| Total current liabilities | | | 442,550 | | | 479,265 | | | | 1,095,324 | | | 678,100 | |
| Long-term liabilities: | | | | | | | | | | | | | | |
| Deferred income taxes | | | 787,179 | | | 731,944 | | | | 749,033 | | | 739,162 | |
| Long-term portion of unrealized loss on derivative instruments | | | 249 | | | -- | | |
| Unrealized loss on derivative instruments | | | | 415 | | | -- | |
| Other deferred credits | | | 395,177 | | | 359,940 | | | | 476,359 | | | 512,918 | |
| Total long-term liabilities | | | 1,182,605 | | | 1,091,884 | | | | 1,225,807 | | | 1,252,080 | |
| Commitments and contingencies | | | | | | | | |
| Commitments and contingencies (Note 22) | | | | | | | | |
| Total capitalization and liabilities | | $ | 5,564,087 | | $ | 5,359,104 | | | $ | 7,061,413 | | $ | 6,339,800 | |
The accompanying notes are an integral part of the consolidated financial statementsstatements.
Puget Sound Energy Consolidated Statements of
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | | |
(Dollars in Thousands) At December 31 | | | 2006 | | 2005 | |
| Common equity: | | | | | | | | | | |
Common stock ($10 stated value)- 150,000,000 shares authorized, 85,903,791 shares outstanding. | | $ | 859,038 | | $ | 859,038 | | |
Common stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791 shares outstanding | | | $ | 859,038 | | $ | 859,038 | |
| Additional paid-in capital | | | 609,467 | | | 604,451 | | | | 996,737 | | | 924,154 | |
| Earnings reinvested in the business | | | 138,678 | | | 100,186 | | | | 263,206 | | | 196,248 | |
| Accumulated other comprehensive income (loss) - net of tax | | | (14,750 | ) | | (8,206 | ) | | | (26,698 | ) | | 7,181 | |
| Total common equity | | | 1,592,433 | | | 1,555,469 | | | | 2,092,283 | | | 1,986,621 | |
Preferred stock subject to mandatory redemption - cumulative $100 par value:* | | | | | | | | |
4.84% series- 150,000 shares authorized, 14,583 shares outstanding at December 31, 2004 and 2003 | | | 1,458 | | | 1,458 | | |
4.70% series- 150,000 shares authorized, 4,311 shares outstanding at December 31, 2004 and 2003 | | | 431 | | | 431 | | |
| Preferred stock subject to mandatory redemption - cumulative - $100 par value:* | | | | | | | | |
4.84% series - 150,000 shares authorized, 14,583 shares outstanding at December 31, 2006 and 2005 | | | | 1,458 | | | 1,458 | |
4.70% series - 150,000 shares authorized, 4,311 shares outstanding at December 31, 2006 and 2005 | | | | 431 | | | 431 | |
| Total preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | | | | 1,889 | | | 1,889 | |
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 280,250 | | | 280,250 | | | | 37,750 | | | 237,750 | |
| Long-term debt: | | | | | | | | | | | | | | |
| First mortgage bonds and senior notes | | | 1,933,500 | | | 1,891,158 | | | | 2,571,500 | | | 2,102,500 | |
| Pollution control revenue bonds: | | | | | | | | | | | | | | |
| Revenue refunding 2003 series, due 2031 | | | 161,860 | | | 161,860 | | | | 161,860 | | | 161,860 | |
Unamortized discount- net of premium | | | -- | | | (13 | ) | |
| Long-term debt due within one year | | | (31,000 | ) | | (102,658 | ) | | | (125,000 | ) | | (81,000 | ) |
| Total long-term debt excluding current maturities | | | 2,064,360 | | | 1,950,347 | | | | 2,608,360 | | | 2,183,360 | |
| Total capitalization | | $ | 3,938,932 | | $ | 3,787,955 | | | $ | 4,740,282 | | $ | 4,409,620 | |
*13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock, both of which are available for issuance under mandatory and non-mandatory redemption provisions.
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements of (DOLLARS IN THOUSANDS) | | Common Stock | | Additional | | | | Accumulated Other | | | | |
FOR YEARS ENDED DECEMBER 31, 2004, 2003 & 2002 | | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Comprehensive Income | | Total Amount | | |
| Balance at December 31, 2001 | | | 85,903,791 | | $ | 859,038 | | $ | 382,592 | | $ | 55,345 | | $ | (29,321 | ) | $ | 1,267,654 | | |
| Net income | | | -- | | -- | | -- | | 108,948 | | -- | | 108,948 | | |
| Preferred stock dividend declared | | | -- | | -- | | -- | | (7,904 | ) | | -- | | (7,904 | ) | |
| Common stock dividend declared | | | -- | | -- | | -- | | (89,418 | ) | | -- | | (89,418 | ) | |
| Investment received from Puget Energy | | | -- | | -- | | 115,736 | | -- | | -- | | 115,736 | | |
| Other | | | -- | | -- | | 7 | | -- | | -- | | 7 | | |
| Other comprehensive income | | | -- | | -- | | -- | | -- | | 31,098 | | 31,098 | | |
| | | | | | | | | | | | | | | | |
| Balance at December 31, 2002 | | | 85,903,791 | | $ | 859,038 | | $ | 498,335 | | $ | 66,971 | | $ | 1,777 | | $ | 1,426,121 | | |
| Net income | | | -- | | -- | | -- | | 119,886 | | -- | | 119,886 | | |
| Preferred stock dividend declared | | | -- | | -- | | -- | | (5,562 | ) | | -- | | (5,562 | ) | |
| Common stock dividend declared | | | -- | | -- | | -- | | (81,109 | ) | | -- | | (81,109 | ) | |
| Investment received from Puget Energy | | | -- | | -- | | 106,124 | | -- | | -- | | 106,124 | | |
| Other | | | -- | | -- | | (8 | ) | | -- | | -- | | (8 | ) | |
| Other comprehensive loss | | | -- | | -- | | -- | | -- | | (9,983 | ) | | (9,983 | ) | |
| | | | | | | | | | | | | | | | |
| (Dollars in Thousands) | | | Common Stock | | Additional | | | | | | | |
For Years Ended December 31, 2006, 2005 & 2004 | | | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Income | | Total Amount | |
| Balance at December 31, 2003 | | | 85,903,791 | | $ | 859,038 | | $ | 604,451 | | $ | 100,186 | | $ | (8,206 | ) | $ | 1,555,469 | | | | 85,903,791 | | $ | 859,038 | | $ | 604,451 | | $ | 100,186 | | $ | (8,206 | ) | $ | 1,555,469 | |
| Net income | | | -- | | -- | | -- | | 126,192 | | -- | | 126,192 | | | | -- | | | -- | | | -- | | | 126,192 | | | -- | | | 126,192 | |
| Common stock dividend declared | | | -- | | -- | | -- | | (87,700 | ) | | -- | | (87,700 | ) | | | -- | | | -- | | | -- | | | (87,700 | ) | | -- | | | (87,700 | ) |
| Investment received from Puget Energy | | | -- | | -- | | 5,016 | | -- | | -- | | 5,016 | | | | -- | | | -- | | | 5,016 | | | -- | | | -- | | | 5,016 | |
| Other comprehensive loss | | | -- | | -- | | -- | | -- | | (6,544 | ) | | (6,544 | ) | | | -- | | | -- | | | -- | | | -- | | | (6,544 | ) | | (6,544 | ) |
| Balance at December 31, 2004 | | | 85,903,791 | | $ | 859,038 | | $ | 609,467 | | $ | 138,678 | | $ | (14,750 | ) | $ | 1,592,433 | | | | 85,903,791 | | $ | 859,038 | | $ | 609,467 | | $ | 138,678 | | $ | (14,750 | ) | $ | 1,592,433 | |
| Net income | | | | -- | | | -- | | | -- | | | 146,769 | | | -- | | | 146,769 | |
| Common stock dividend declared | | | | -- | | | -- | | | -- | | | (89,199 | ) | | -- | | | (89,199 | ) |
| Investment received from Puget Energy | | | | -- | | | -- | | | 314,687 | | | -- | | | -- | | | 314,687 | |
| Other comprehensive loss | | | | -- | | | -- | | | -- | | | -- | | | 21,931 | | | 21,931 | |
| Balance at December 31, 2005 | | | | 85,903,791 | | $ | 859,038 | | $ | 924,154 | | $ | 196,248 | | $ | 7,181 | | $ | 1,986,621 | |
| Net income | | | | -- | | | -- | | | -- | | | 176,740 | | | -- | | | 176,740 | |
| Common stock dividend declared | | | | -- | | | -- | | | -- | | | (109,782 | ) | | -- | | | (109,782 | ) |
| Investment received from Puget Energy | | | | -- | | | -- | | | 72,583 | | | -- | | | -- | | | 72,583 | |
| Other comprehensive income | | | | -- | | | -- | | | -- | | | -- | | | (15,226 | ) | | (15,226 | ) |
| Adjustment to initially apply SFAS No. 158, net of tax of $(12,420) | | | | -- | | | -- | | | -- | | | -- | | | (18,653 | ) | | (18,653 | ) |
| Balance at December 31, 2006 | | | | 85,903,791 | | $ | 859,038 | | $ | 996,737 | | $ | 263,206 | | $ | (26,698 | ) | $ | 2,092,283 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements of (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | |
| Net income | | $ | 126,192 | | $ | 119,886 | | $ | 108,948 | |
| Other comprehensive income, net of tax: | | | | | | | | | | |
| Unrealized holding losses on marketable securities during the period | | | -- | | | (45 | ) | | (1,359 | ) |
Reclassification adjustment for realized gains on marketable securities included in net income | | | -- | | | (1,518 | ) | | -- | |
| Minimum pension liability adjustment | | | 157 | | | (1,122 | ) | | (2,098 | ) |
| Unrealized gains on derivative instruments during the period | | | 6,820 | | | 8,576 | | | 2,853 | |
Reversal of unrealized (gains) losses on derivative instruments settled during the period | | | (10,418 | ) | | 181 | | | 31,702 | |
| Deferral related to power cost adjustment mechanism | | | (3,103 | ) | | (16,055 | ) | | -- | |
| Other comprehensive income (loss) | | | (6,544 | ) | | (9,983 | ) | | 31,098 | |
| Comprehensive income | | $ | 119,648 | | $ | 109,903 | | $ | 140,046 | |
(Dollars in Thousands) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Net income | | $ | 176,740 | | $ | 146,769 | | $ | 126,192 | |
| Other comprehensive income (loss): | | | | | | | | | | |
| Minimum pension liability adjustment, net of tax of $2,376, $0 and $0, respectively | | | 2,873 | | | 925 | | | 157 | |
| Net unrealized gains (losses) on energy derivative instruments during the period, net of tax of $(17,669), $26,799, and $3,672, respectively | | | (32,813 | ) | | 49,770 | | | 6,820 | |
| Reversal of net unrealized (gains) losses on energy derivative instruments settled during the period, net of tax of $(2,972), $(10,319) and $(5,610), respectively | | | (5,519 | ) | | (19,164 | ) | | (10,418 | ) |
| Gain (loss) from settlement of financing cash flow hedge contracts, net of tax of $7,239, $(12,363) and $0, respectively | | | 13,443 | | | (22,960 | ) | | -- | |
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $289, $245 and $0, respectively | | | 537 | | | 455 | | | -- | |
| Deferral of energy cash flow hedges related to power cost adjustment mechanism, net of tax of $3,367, $6,949 and $(1,671), respectively | | | 6,253 | | | 12,905 | | | (3,103 | ) |
| Other comprehensive income (loss) | | | (15,226 | ) | | 21,931 | | | (6,544 | ) |
| Comprehensive income | | $ | 161,514 | | $ | 168,700 | | $ | 119,648 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements of (DOLLARS IN THOUSANDS FOR YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | | |
(Dollars in Thousands) For Years Ended December 31 | | | 2006 | | 2005 | | 2004 | |
| Operating activities: | | | | | | | | | | | | | | |
| Net income | | $ | 126,192 | | $ | 119,886 | | $ | 108,948 | | | $ | 176,740 | | $ | 146,769 | | $ | 126,192 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 228,566 | | | 220,087 | | | 215,317 | | | | 262,341 | | | 241,634 | | | 228,566 | |
Deferred federal income taxes and tax credits- net | | | 72,446 | | | 49,276 | | | 140,536 | | | | 34,283 | | | (57,597 | ) | | 72,446 | |
| Gain from sale of securities | | | -- | | | (2,889 | ) | | -- | | |
| Power cost adjustment mechanism | | | | 12,023 | | | (18,380 | ) | | 3,605 | |
| Amortization of gas pipeline capacity assignment | | | | (10,632 | ) | | -- | | | -- | |
| Non cash return on regulatory assets | | | | (12,438 | ) | | -- | | | -- | |
| Net unrealized (gain) loss on derivative instruments | | | (526 | ) | | 106 | | | (11,612 | ) | | | 71 | | | 472 | | | (526 | ) |
| Other (including conservation amortization) | | | 20,806 | | | 14,591 | | | (8,277 | ) | | | 17,335 | | | (4,803 | ) | | 18,869 | |
| Cash collateral received from (returned to) energy suppliers | | | 6,320 | | | (21,425 | ) | | 21,425 | | | | (22,020 | ) | | 15,700 | | | 6,320 | |
| Increase (decrease) in Residential Exchange Program | | | 1,668 | | | (25,989 | ) | | 21,201 | | |
| Pension plan funding | | | -- | | | (26,521 | ) | | -- | | |
| Gas pipeline capacity assignment | | | | -- | | | 55,000 | | | -- | |
| BPA prepaid transmission | | | | -- | | | (10,750 | ) | | -- | |
| Chelan PUD contract initiation | | | | (89,000 | ) | | -- | | | -- | |
| Storm damage deferred costs | | | | (92,331 | ) | | -- | | | -- | |
| Change in certain current assets and current liabilities: | | | | | | | | | | | | | | | | | | | | |
| Accounts receivable and unbilled revenue | | | 8,264 | | | 33,370 | | | 61,539 | | | | (64,961 | ) | | (221,960 | ) | | 8,264 | |
| Materials and supplies | | | (20,372 | ) | | (13,643 | ) | | 21,755 | | | | (7,010 | ) | | (4,808 | ) | | (37,884 | ) |
| Fuel and gas inventory | | | | (24,694 | ) | | (25,163 | ) | | 17,512 | |
| Prepayments and other | | | 38 | | | 2,622 | | | (1,501 | ) | | | (1,636 | ) | | (776 | ) | | 38 | |
| Purchased gas receivable / liability | | | (31,073 | ) | | (71,826 | ) | | 121,039 | | | | 27,513 | | | (48,246 | ) | | (31,073 | ) |
| Accounts payable | | | 23,282 | | | 12,863 | | | 38,893 | | | | 33,004 | | | 116,743 | | | 23,282 | |
| Taxes payable | | | (707 | ) | | 17,910 | | | (13,646 | ) | | | (56,535 | ) | | 30,265 | | | (707 | ) |
| Tenaska disallowance reserve | | | 3,156 | | | -- | | | -- | | | | -- | | | (3,156 | ) | | 3,156 | |
| Accrued expenses and other | | | (2,664 | ) | | (4,120 | ) | | 277 | | | | 30,588 | | | (2,201 | ) | | (2,664 | ) |
| Net cash provided by operating activities | | | 435,396 | | | 304,298 | | | 715,894 | | | | 212,641 | | | 208,743 | | | 435,396 | |
| Investing activities: | | | | | | | | | | | | | | | | | | | | |
Construction expenditures- excluding equity AFUDC | | | (393,891 | ) | | (269,973 | ) | | (224,165 | ) | | | (745,239 | ) | | (568,381 | ) | | (393,891 | ) |
| Energy efficiency expenditures | | | (24,852 | ) | | (18,579 | ) | | (11,356 | ) | | | (33,865 | ) | | (24,428 | ) | | (24,852 | ) |
| Restricted cash | | | 905 | | | 20,106 | | | (18,871 | ) | | | 208 | | | 586 | | | 905 | |
| Cash received from sale of securities | | | -- | | | 3,161 | | | -- | | |
| Cash received from property sales | | | | 936 | | | 24,291 | | | 1,315 | |
| Refundable cash received for customer construction projects | | | 13,424 | | | 5,045 | | | 5,787 | | | | 12,253 | | | 9,869 | | | 13,424 | |
| Other | | | 1,444 | | | 3,671 | | | (14,472 | ) | | | 5,500 | | | 6,006 | | | 129 | |
| Net cash used by investing activities | | | (402,970 | ) | | (256,569 | ) | | (263,077 | ) | | | (760,207 | ) | | (552,057 | ) | | (402,970 | ) |
| Financing activities: | | | | | | | | | | | | | | | | | | | | |
Decrease in short-term debt- net | | | -- | | | (30,340 | ) | | (307,828 | ) | | | 287,055 | | | 41,000 | | | -- | |
| Dividends paid | | | (87,700 | ) | | (86,671 | ) | | (97,321 | ) | | | (109,782 | ) | | (89,199 | ) | | (87,700 | ) |
| Issuance of bonds and notes | | | 200,000 | | | 304,465 | | | 40,000 | | | | 550,000 | | | 400,000 | | | 200,000 | |
| Redemption of preferred stock | | | -- | | | (60,000 | ) | | -- | | |
| Redemption of mandatorily redeemable preferred stock | | | -- | | | (41,273 | ) | | (7,500 | ) | |
| Loan from Puget Energy | | | | 24,303 | | | -- | | | -- | |
| Redemption of trust preferred stock | | | -- | | | (19,750 | ) | | -- | | | | (200,000 | ) | | (42,500 | ) | | -- | |
| Redemption of bonds and notes | | | (157,658 | ) | | (356,860 | ) | | (117,000 | ) | | | (81,000 | ) | | (231,000 | ) | | (157,658 | ) |
| Settlement of derivatives | | | | 20,682 | | | (35,323 | ) | | -- | |
| Investment from Puget Energy | | | 5,016 | | | 106,124 | | | 115,736 | | | | 70,114 | | | 314,687 | | | 5,016 | |
| Other | | | 6,093 | | | (10,121 | ) | | (137 | ) | |
| Net cash used by financing activities | | | (34,249 | ) | | (194,426 | ) | | (374,050 | ) | |
| Issuance costs and other | | | | (2,423 | ) | | (10,597 | ) | | 6,093 | |
| Net cash provided (used) by financing activities | | | | 558,949 | | | 347,068 | | | (34,249 | ) |
| Increase (decrease) in cash from net income | | | (1,823 | ) | | (146,697 | ) | | 78,767 | | | | 11,383 | | | 3,754 | | | (1,823 | ) |
| Cash at beginning of year | | | 14,778 | | | 161,475 | | | 82,708 | | | | 16,709 | | | 12,955 | | | 14,778 | |
| Cash at end of year | | $ | 12,955 | | $ | 14,778 | | $ | 161,475 | | | $ | 28,092 | | $ | 16,709 | | $ | 12,955 | |
Supplemental Cash Flow Information: | | | | | | | | | | | |
Supplemental cash flow information: | | | | | | | | | | | |
| Cash payments for: | | | | | | | | | | | | | | | | | | | | |
| Interest (net of capitalized interest) | | $ | 175,772 | | $ | 187,256 | | $ | 194,876 | | |
| Income taxes (net refunds) | | | (1,042 | ) | | (1,456 | ) | | (81,973 | ) | |
| Interest (net of debt AFUDC) | | | $ | 164,389 | | $ | 172,986 | | $ | 175,772 | |
| Income taxes (net of refunds) | | | | 123,100 | | | 126,591 | | | (1,042 | ) |
The accompanying notes are an integral part of the consolidated financial statements.
To Consolidated Financial Statements of Puget Energy and Puget Sound Energy
NOTE 1.1. Summary of Significant Accounting Policies
BASIS OF PRESENTATIONBasis of Presentation
Puget Energy, Inc. (Puget Energy) is an exempt public utilitya holding company under the Public Utility Holding Company Act of 1935. Puget Energythat owns Puget Sound Energy (PSE) and hasuntil May 7, 2006, a 90.9% ownership interest in InfrastruX Group, Inc. (InfrastruX). PSE is a public utility incorporated in the State of Washington andthat furnishes electric and gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region.
The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the common shares of PSE and owned a 90.9% interest in InfrastruX isuntil it was sold on May 7, 2006. The results of PSE and InfrastruX are presented on a consolidated basis. The financial position and results of operations for InfrastruX are presented as discontinued operations. At the time that it was owned by Puget Energy, InfrastruX was a non-regulated utility construction service company incorporated in the Statestate of Washington, which provides construction services to the electric and gas utility industries primarily in the Midwest, Texas, south-central and eastern United States regions.
The consolidated financial statements of Puget Energy include the accounts of Puget Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the common shares of PSE and holds a 90.9% interest in InfrastruX. The results of PSE and InfrastruX are presented on a consolidated basis. PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. Minority interests of InfrastruX’s operating results are reflected in Puget Energy’s consolidated financial statements. Certain amounts previously reported have been reclassified to conform with current year presentations with no effect on total equity or net income.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
UTILITY PLANTUtility Plant
The cost of additions to utility plant, including renewals and betterments, are capitalized at original cost. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits, and an allowance for funds used during construction. Replacements of minor items of property and major maintenance are included in maintenance expense. The original cost of operating property is charged to accumulated depreciation and costs associated with removal of property, less salvage, isare charged to the cost of removal regulatory liability when the property is retired and removed from service.
NON-UTILITY PROPERTY, PLANT AND EQUIPMENTNon-Utility Property, Plant and Equipment
The costs of other property, plant and equipment are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacement of minor items is expensed on a current basis. Gains and losses on assets sold or retired are reflected in earnings.
ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETSAccounting for the Impairment of Long-Lived Assets
The Company evaluates impairment of long-lived assets in accordance with SFASStatement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 establishes accounting standards for determining if long-lived assets, including assets to be disposed of, are impaired and how losses, if any, should be recognized. The Company believes that the netpresent value of the estimated future cash flows areinflows from the use and eventual disposition of long-lived assets is sufficient to cover therecover their carrying value of its assets.values.
DEPRECIATION AND AMORTIZATION
For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is comprised of software, small tools and office equipment. The depreciation of automobiles, trucks, power-operated equipment and tools is allocated to asset and expense accounts based on usage. The annual depreciation provision stated as a percent of average original cost of depreciable electric utility plant was 2.9% in 2004, 20032006, 2005 and 2002;2004; depreciable gas utility plant was 3.3% in 2006 and 3.4% in 2004, 3.5% in 2003both 2005 and 3.3% in 2002;2004; and depreciable common utility plant was 4.6%5.1% in 2004, 4.7%2006, 4.8% in 20032005 and 4.3%4.6 % in 2002.2004. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
CASHCash
All liquid investments with maturities of three months or less at the date of purchase are considered cash. The Company maintains cash deposits in excess of insured limits with certain financial institutions.
RESTRICTED CASHRestricted Cash
Restricted cash represents cash to be used for specific purposes. The restricted cash balance was $1.6$0.8 million and $1.0 million at December 31, 2004. Approximately $1.1 million in restricted cash2006 and 2005, respectively, which represents funds held by Puget Western, Inc., a PSE subsidiary, for a real estate development project. Approximately $0.4The long-term restricted cash balance was $3.8 million which represents funds held for paymentmanagement’s estimate of principalthe aggregate fair value of the amount potentially payable under certain representations and interest for conservation trust debt and approximately $0.1 million represents payments from the Bonneville Power Administration under the Residential and Farm Energy Exchange Benefit Credit program in excess of credits provided to customers.warranties made by InfrastruX concerning its business.
MATERIAL AND SUPPLIESMaterial and Supplies
Material and supplies consists primarily of materials and supplies used in the operation and maintenance of the electric and gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. These items are recorded at lower of cost or market value using the weighted average cost method.
Fuel and Gas Inventory
Fuel and gas inventory is used in the generation of electricity and for future sales to the Company’s gas customers. Fuel inventory consists of coal, diesel, and natural gas heldused for generation, andgeneration. Gas inventory consists of natural gas and liquefied natural gas held in storage for future sales. These items are recorded at the lower of cost or market value primarily using the weighted average cost method.
REGULATORY ASSETS AND LIABILITIESRegulatory Assets and Liabilities
The Company accounts for its regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires the Company to defer certain costs that would otherwise be charged to expense, if it iswere probable that future rates will permit recovery of such costs. Accounting under SFAS No. 71 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, the Company classifies regulatory assets and liabilities as long-term assets or liabilities. The exception is the purchased gas adjustment receivable which is a current asset.
The Company iswas allowed a return on the net regulatory assets and liabilities of 8.75% for electric rates beginning July 1, 2002 and gas rates beginning September 1, 2002. The 20012002 through March 3, 2005. Effective March 4, 2005 based on the 2004 general rate case, the Company is allowed ratea return on the net regulatory assets and liabilities of return was 8.94%8.4%, or 7.06% after-tax, for both electric rates and 9.15% for gas rates. The net regulatory assets and liabilities at December 31, 20042006 and 20032005 included the following:
(DOLLARS IN MILLIONS) | | REMAINING AMORTIZATION PERIOD | | 2004 | | 2003 | |
| PURPA electric energy supply contract buyout costs | | | 4 to 7 years | | $ | 211.2 | | $ | 227.8 | |
| Deferred income taxes | | | *** | | | 127.3 | | | 142.8 | |
| White River relicensing and other costs | | | * | | | 65.3 | | | 20.8 | |
| Investment in Bonneville Exchange Power contract | | | 12 years | | | 44.1 | | | 47.6 | |
| Environmental remediation | | | * | | | 42.3 | | | 41.6 | |
| Deferred AFUDC | | | 30 years | | | 30.4 | | | 30.3 | |
| Tree watch costs | | | 10 years | | | 28.3 | | | 29.0 | |
Storm damage costs- electric | | | 3.5 years | | | 21.1 | | | 26.0 | |
| Purchased Gas Adjustment (PGA) receivable | | | * | | | 19.1 | | | -- | |
| Colstrip common property | | | 19 years | | | 13.9 | | | 14.6 | |
| PGA deferral of unrealized losses on derivative instruments | | | *** | | | 12.1 | | | 3.3 | |
| Various other regulatory assets | | | 1 to 26 years | | | 30.2 | | | 23.1 | |
| Power Cost Adjustment (PCA) mechanism | | | * | | | -- | | | 3.6 | |
| Cost of removal | | | ** | | | (132.4 | ) | | (124.9 | ) |
| PCA deferral of unrealized gain on derivative instrument | | | * | | | (30.8 | ) | | (24.3 | ) |
| Gas Supply contract settlement | | | 3.5 year | | | (10.1 | ) | | -- | |
| Deferred gains on property sales | | | 3 years | | | (4.5 | ) | | (10.1 | ) |
| Tenaska disallowance reserve | | | 1 year | | | (3.2 | ) | | -- | |
| Purchased Gas Adjustment payable | | | *** | | | -- | | | (12.0 | ) |
| Various other regulatory liabilities | | | 1 to 22 years | | | (4.7 | ) | | (5.4 | ) |
| Net regulatory assets and liabilities | | | | | $ | 459.6 | | $ | 433.8 | |
(Dollars in Millions) | | Remaining Amortization Period | | 2006 | | 2005 | |
| PURPA electric energy supply contract buyout costs | | | 1.5 to 5 years | | $ | 167.9 | | $ | 191.2 | |
| Deferred income taxes | | | * | | | 115.3 | | | 129.7 | |
Storm damage costs - electric | | | ** | | | 101.1 | | | 15.0 | |
| Chelan PUD contract initiation | | | *** | | | 95.5 | | | -- | |
| White River relicensing and other costs | | | **** | | | 69.1 | | | 66.1 | |
| PGA deferral of unrealized (gain) losses on derivative instruments | | | * | | | 54.8 | | | (25.7 | ) |
| Purchased gas adjustment (PGA) receivable | | | * | | | 39.8 | | | 67.3 | |
| Investment in Bonneville Exchange Power contract | | | 10 years | | | 37.0 | | | 40.6 | |
| Environmental remediation | | | **** | | | 36.3 | | | 34.2 | |
| Deferred AFUDC | | | 30 years | | | 33.3 | | | 32.0 | |
| Tree watch costs | | | 8.3 years | | | 19.8 | | | 24.2 | |
| Colstrip common property | | | 17 years | | | 12.5 | | | 13.2 | |
| Hopkins Ridge prepaid transmission upgrade | | | ***** | | | 8.9 | | | 10.8 | |
| Power cost adjustment (PCA) mechanism | | | * | | | 6.4 | | | 18.4 | |
| Carrying costs on income tax payments | | | * | | | 6.2 | | | -- | |
| Various other regulatory assets | | | 1 to 25 years | | | 34.6 | | | 31.6 | |
Total Regulatory Assets | | | | | $ | 838.5 | | $ | 648.6 | |
| Cost of removal | | | ****** | | $ | (127.1 | ) | $ | (125.3 | ) |
| Deferred credit gas pipeline capacity | | | 10.8 years | | | (44.4 | ) | | (55.0 | ) |
| Deferred gains on property sales | | | 3 years | | | (11.1 | ) | | (11.4 | ) |
| Gas supply contract settlement | | | 1.5 years | | | (5.7 | ) | | (9.5 | ) |
| PCA deferral of unrealized gain on derivative instruments | | | * | | | -- | | | (11.1 | ) |
| Various other regulatory liabilities | | | 1 to 21 years | | | (3.3 | ) | | (3.9 | ) |
Total Regulatory Liabilities | | | | | $ | (191.6 | ) | $ | (216.2 | ) |
| Net regulatory assets and liabilities | | | | | $ | 646.9 | | $ | 432.4 | |
*Amortization period to be determined. _______________
**The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
| * | ***Amortization period varies depending on timing of underlying transactions.
|
| ** | Amortization period for storm costs deferred in 2006 to be determined in a future Washington Commission rate proceeding. |
| *** | Amortization period will start in 2011 for a 20 year period. |
| **** | Amortization period to be determined in a future Washington Commission rate proceeding. |
| ***** | Amortization varies and based upon BPA tariff rate and FERC interest rate. |
| ****** | The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. |
If the Company, at some point in the future, determines that all or a portion of the utility operations no longer meetmeets the criteria for continued application of SFAS No. 71, the Company would be required to adopt the provisions of SFAS No. 101, “Regulated Enterprises - Accounting for the Discontinuation of Application of FASBFinancial Accounting Standards Board (FASB) Statement No. 71.” Adoption of SFAS No. 101 would require the Company to write off the regulatory assets and liabilities related to those operations not meeting SFAS No. 71 requirements. Discontinuation of SFAS No. 71 could have a material impact on the Company’s financial statements.
In accordance with guidance provided by the Securities and Exchange Commission (SEC), the Company reclassified from accumulated depreciation to a regulatory liability $132.4$127.1 million and $124.9$125.3 million in 20042006 and 2003,2005, respectively, for cost of removal for utility plant. These amounts are collected from PSE’s customers through depreciation rates.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant and is credited to interest expense and as a non-cash item to other income and interest charges currently.income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates.
The AFUDC rate allowed by the Washington Utilities and Transportation Commission (Washington Commission) for gas utility plant additions was 8.4% beginning March 4, 2005 and 8.76% beginningfor the period September 1, 2002 and 9.15% in 2001.through March 3, 2005. The allowed AFUDC rate on electric utility plant was 8.4% beginning March 4, 2005 and 8.76% beginningfor the period July 1, 2002 and 8.94% in 2001.through March 3, 2005. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, the Company capitalizes the excess as a deferred asset, crediting miscellaneous income. The amounts included in income were $2.7 million for 2006, $2.8 million for 2005 and $1.4 million for 2004, $1.6 million for 2003 and $2.6 million for 2002.2004. The deferred asset is being amortized over the average useful life of the Company’s non-project electric utility plant.
OTHER COMPREHENSIVECalifornia Reserve
Items presentPSE operates within the western wholesale market and has made sales into the California energy market. During 2003, FERC issued an order in the Consolidated StatementsCalifornia Refund Proceeding adopting in part and modifying in part FERC’s earlier findings by the Administrative Law Judge. The amount of Comprehensive Income for Puget Energy and PSE are presented netthe receivable, $21.2 million at December 31, 2006 is subject to the outcome of applicable tax at a 35% statutory rate.the ongoing litigation.
REVENUE RECOGNITIONRevenue Recognition
Operating utility revenues are recorded on the basis of service rendered which includes estimated unbilled revenue. Sales to other utilities are recorded on a net servicerevenue rendered basis in accordance with Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03.” Non-utility subsidiaries recognize revenue when services are performed or upon the sale of assets orassets.
PSE collected Washington State excise taxes (which are a component of general retail rates) and municipal taxes of $203.7 million, $178.0 million and $153.4 million for 2006, 2005 and 2004, respectively. The Company’s policy is to report such taxes on a percentgross basis in operating revenues and taxes other than income taxes in the accompanying consolidated statements of completion basis for fixed priced contracts.income.
ALLOWANCE FOR DOUBTFUL ACCOUNTSAllowance for Doubtful Accounts
An allowance for doubtful accounts is provided for energy customer accounts based upon a historical experience rate of write-offs of energy accounts receivable as compared to operating revenues. The allowance account is adjusted monthly for this experience rate. Energy accounts are considered past due 15 business days after the billing cycle. Once an account is past due, a 1% late payment fee is accrued per month for each month an account is past due. When an account is past due, the Company may assist the customer with the use of special payment arrangements. If no payment arrangements are made or if no contact is made from the customer, the Company has the option of stopping service. Once service is stopped or the customer leaves the service area, a final bill is mailed. Energy accounts are deemed uncollectible 74 business days after the final bill due date and are written off against the allowance account. The late payment fee continues to be accrued on past due accounts until they are written off.
Other non-energy receivable balances are reserved for in the allowance account based on facts and circumstances surrounding the receivable, indicating some or all of the balance is uncollectible. Once exhaustive efforts have been made to collect these other receivables, the allowance account and corresponding receivable balance are written off.
The Company has provided for a $41.5 million reserve for fiscal 2000 sales transactions related to the California Independent System Operator and counterparties based upon probability of collection.
Puget Energy’s allowance for doubtful accounts for 2004at December 31, 2006 and 20032005 was $46.0$2.8 million and $45.8$3.1 million, respectively. PSE’s allowance for doubtful accounts for 2004 and 2003 was $44.2 million and $44.0 million, respectively
SELF-INSURANCESelf-Insurance
The Company currently has no insurance coverage for storm damage and environmental contamination that would occur in a current year on company-owned property. The Company is self-insured for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. With approval of theThe Washington Commission PSE is able to deferhas approved the deferral of certain uninsured storm damage costs that exceed $7.0 million of qualifying storm damage costs for collection in future rates certain uninsured storm damage costs associated with major storms.if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.
FEDERAL INCOME TAXESFederal Income Taxes
Puget Energy and its subsidiaries file consolidated federal income tax returns. Income taxes are allocated to the subsidiaries on the basis of separate company computations of taxable income or loss. The Company normalizes, with the approval of the Washington Commission,provides for deferred taxes on certain assets and liabilities that are reported differently for income tax items. Deferred taxes have been determined underpurposes than for financial reporting purposes, as required by SFAS No. 109. Investment tax credits are deferred and amortized based on the average useful life of the related property in accordance with regulatory and income tax requirements. (See Note 12).109, “Accounting for Income Taxes.”
ENERGY EFFICIENCYEnergy Efficiency
The Company offers programs designed to help new and existing customers use energy efficiently. The primary emphasis is to provide information and technical services to enable customers to make energy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices.
Since May 1997, the Company has recovered electric energy efficiency expenditures through a tariff rider mechanism. The rider mechanism allows the Company to defer the efficiency expenditures and amortize them to expense as PSE concurrently collects the efficiency expenditures in rates over a one-year period. As a result of the rider mechanism, electric energy efficiency expenditures have no impact on earnings.
Since 1995, the Company has been authorized by the Washington Commission to defer gas energy efficiency expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows the Company to defer efficiency expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows the Company to recover an Allowanceallowance for Funds Usedfunds used to Conserve Energyconserve energy on any outstanding balance that is not being recovered in rates. As a result of the tracker mechanism, gas energy efficiency expenditures have no impact on earnings.
Energy efficiency programs reduce customer consumption of energy thus impacting energy margins. The impact of load reductions areis adjusted in rates at each general rate case.
RATE ADJUSTMENT MECHANISMSRate Adjustment Mechanisms
The Company has a power cost adjustment (PCA) mechanism that provides for an automatica rate adjustment process if PSE’s costs to provide customers’ electricity falls outside certain bands from a normalized level of power costs established in thean electric general rate case. On October 20, 2005, the Washington Commission approved an amendment to the PCA mechanism changing the PCA period to a calendar year beginning January 1, 2007. The Company’s cumulative maximum pre-tax earnings exposure dueWashington Commission also made provision to reduce the graduated scale to half the annual excess power cost variations overcosts for the four-year period ending June 30,July 1, 2006 is limited to $40 million plus 1% of the excess.through December 31, 2006 without a cap on excess power costs. All significant variable power supply cost drivers are included in the PCA mechanism (hydroelectric generation variability, market price variability for purchased power and surplus power sales, natural gas and coal fuel price variability, generation unit forced outage risk and wheeling cost variability). The PCA mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers. Any unrealized gains and losses from derivative instruments accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” are deferred in proportion to the cost-sharing arrangement under the PCA mechanism. On January 10, 2007, the Washington Commission approved the PCA mechanism oncewith the Company reaches itssame annual graduated scale but without a cap of $40 million.
on excess power costs.
The graduated scale is as follows:
| ANNUAL POWER COST VARIABILITY | CUSTOMERS' SHARE | COMPANY'S SHARE1 | |
Annual Power Cost Variability | | July 2006 - December 2006 Power Cost Variability1 | Customers’ Share | Company’s Share2 |
| +/- $20 million | 0% | | 100% | | +/- $10 million | 0% | 100% |
| +/- $20 million - $40 million | 50% | | 50% | | +/- $10 - $20 million | 50% | 50% |
| +/- $40 million - $120 million | 90% | | 10% | | +/- $20 - $60 million | 90% | 10% |
| +/- $120+ million | 95% | | 5% | | |
+/- $120 + million | | +/- $60 million | 95% | 5% |
_______________________ _______________
1 | In October 2005, the Washington Commission in its power cost only rate case order made a provision to reduce the power cost variability amounts to half the annual power cost variability for the period July 1, 2006 through December 31, 2006. |
2 | Over the four-year period July 1, 2002 through June 30, 2006 the Company’s share of pre-tax cost variation iswas capped at a cumulative $40$40.0 million plus 1% of the excess. Power cost variation after June 30,December 31, 2006 will be apportioned on an annual basis, based on the graduated scale.scale without a cap. |
The differences between the actual cost of PSE’s gas supplies and gas transportation contracts and thatcosts currently allowed by the Washington Commission are deferred and recovered or repaid through the purchased gas adjustment (PGA) mechanism. The PGA mechanism allows PSE to recover expected gas costs, and defer, as a receivable or liability, any gas costs that exceed or fall short of this expected gas cost amount in the PGA mechanism rates, including interest.
NATURAL GAS OFF-SYSTEM SALES AND CAPACITY RELEASENatural Gas Off-System Sales and Capacity Release
The Company contracts for firm gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, however, the Company holds contractual rights to gas supplies, and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party gas sales, exchanges and capacity releases. The Company sells excess gas supplies, enters into gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate gas pipeline capacity and gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, the Company nets the sales revenue and associated cost of sales for these transactions in purchased gas.
ENERGY RISK MANAGEMENT
The Company serves its regulated electric customers with an electric portfolio of owned and contracted resources. As a result, the portfolio exposes the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company also serves its regulated gas customers with a gas portfolio of contracted resources which exposes the Company’s customers to commodity price risks in the PGA mechanism. The Company’s energy risk management function monitors and manages these risks using analytical models and tools. In addition, the Audit Committee of the Company’s Board of Directors periodically assesses risk management policies.
The Company manages its energy supply portfolio to achieve three primary objectives:
· | ensure that physical energy supplies are available to serve retail customer requirements; |
· | manage portfolio risks to limit undesired impacts on the Company’s costs; and |
· | maximize the value of the Company’s energy supply assets. |
ACCOUNTING FOR DERIVATIVES
The Company follows the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 which requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. Certain contracts that would otherwise be considered derivatives are exempt from SFAS No. 133 if they qualify for a normal purchase normal sale exception. The Company enters into both physical and financial contracts to manage its energy resource portfolio. The majority of these contracts qualify for the normal purchase normal sale exception.exception for the purpose of serving retail load. However, those contracts that do not meet the normal purchase or normal sale exception are derivatives and, pursuant to SFAS No. 133, are reported at their fair value inon the balance sheet. Changes in their fair value are reported in earnings unless they meet specific hedge accounting criteria, in which case changes in their fair market value are recorded in comprehensive income until the time the transaction that they are hedging is recorded as income.in earnings. The Company designates a derivative instrument as a qualifying cash flow hedge if the change in the fair value of the derivative is highly effective atin offsetting the changes in the fair value ofcash flows attributable to an asset, a liability or a forecasted transaction. To the extent that a portion of a derivative designated as a hedge is ineffective, changes in the fair value of the ineffective portion of that derivative are recognized currently in earnings. Changes in the market value of derivative transactions related to obtaining gas for the Company’s retail gas business are deferred as regulatory assets or liabilities as a result of the Company’s PGA mechanism and recorded in earnings as the transactions are executed. In addition, once
Stock-Based Compensation
Prior to 2006, the Company reaches the $40 million PCA cap, any unrealized gains or losses are deferred in proportion to the cost-sharing arrangement under the PCA.
STOCK-BASED COMPENSATION
The Company hashad various stock-based compensation plans which prior to 2003, were accounted for according to APBAccounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company appliesapplied SFAS No. 123 accounting to stock compensation awards granted fromsubsequent to January 1, 2003, on, while grants that were made in years prior to 2003 arecontinued to be accounted for using the intrinsic value method of APB No. 25. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. Results for prior periods have not been restated, as provided for under the modified-prospective method.
Had the Company used the fair value method of accounting specified by SFAS No. 123 for all grants at their grant date rather than prospectively implementing SFAS No. 123, net income and earnings per share would have been as follows:
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) YEARS ENDED DECEMBER 31 | | 2004 | | 2003 | | 2002 | | |
(Dollars in Thousands, except per share amounts) Years Ended December 31 | | | 2005 | | 2004 | |
| Net income, as reported | | $ | 55,022 | | $ | 116,197 | | $ | 110,052 | | | $ | 155,726 | | $ | 55,022 | |
Add: Total stock-based employee compensation expense included in net income, net of tax | | | 2,641 | | | 4,180 | | | 4,103 | | | | 1,652 | | | 2,457 | |
Less: Total stock-based employee compensation expense per the fair value method of SFAS No. 123, net of tax | | | (3,303 | ) | | (3,314 | ) | | (3,495 | ) | | | (2,195 | ) | | (2,603 | ) |
| Pro forma net income | | $ | 54,360 | | $ | 117,063 | | $ | 110,660 | | | $ | 155,183 | | $ | 54,876 | |
| Earnings per common share: | | | | | | | | | | | | | | | | | |
| Basic as reported | | $ | 0.55 | | $ | 1.23 | | $ | 1.24 | | | $ | 1.52 | | $ | 0.55 | |
| Diluted as reported | | $ | 0.55 | | $ | 1.22 | | $ | 1.24 | | | $ | 1.51 | | $ | 0.55 | |
| Basic pro forma | | $ | 0.55 | | $ | 1.24 | | $ | 1.25 | | | $ | 1.51 | | $ | 0.55 | |
| Diluted pro forma | | $ | 0.54 | | $ | 1.23 | | $ | 1.25 | | | $ | 1.51 | | $ | 0.55 | |
DEBT RELATED COSTSDebt Related Costs
Debt premiums, discounts, expenses and expensesamounts received or incurred to settle hedges are amortized over the life of the related debt. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment. At times the Company will enter into treasury lock transactions to hedge against the potential rising interest rates. The transaction, when settled, will be amortized over the related debt issuance life.
GOODWILL AND INTANGIBLES (PUGET ENERGY ONLY)
On January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective and as a result PugetEarnings Per Common Share (Puget Energy ceased amortization of goodwill. Puget Energy performed an initial impairment review of goodwill and an annual impairment review thereafter. The initial review was completed during the first half of 2002, which did not result in an impairment charge. Goodwill is reviewed annually to determine if any impairment exists. If goodwill is determined to have an impairment, Puget Energy would record in the period of determination an impairment charge to earnings. Intangibles with finite lives are amortized based on the expected pattern of use or on a straight-line basis over the expected periods to be benefited. The goodwill and intangibles recorded on the balance sheet of Puget Energy are the result of several acquisitions of companies by InfrastruX.
In 2004, InfrastruX recorded a $91.2 million ($76.6 million after tax and minority interest) impairment charge related to goodwill from acquired companies. See Note 18.
EARNINGS PER COMMON SHARE (PUGET ENERGY ONLY) Only)
Basic earnings per common share has been computed based on weighted average common shares outstanding of 115,999,000, 102,570,000 and 99,470,000 94,750,000for 2006, 2005 and 88,372,000 for 2004, 2003 and 2002, respectively. Diluted earnings per common share has been computed based on weighted average common shares outstanding of 116,457,000, 103,111,000 and 99,911,000 95,309,000for 2006, 2005 and 88,777,000 for 2004, 2003 and 2002, respectively, which includes the dilutive effect of securities related to employee stock-based compensation plans. In 2006, 46,000 shares related to stock options were excluded from the diluted weighted average common share calculation due to their antidilutive effect.
ACCOUNTS RECEIVABLE SECURITIZATION PROGRAMAccounts Receivable Securitization Program
On December 20, 2005, PSE entered into a five-year Receivable Sales Agreement with PSE Funding, Inc. (PSE Funding), a wholly owned, bankruptcy-remote subsidiary of PSE, formed for the purpose of purchasing customers’ accounts receivable, both billed and unbilled. The results of PSE Funding are consolidated in the financial statements of PSE. The accounts receivable are sold at estimated fair value, based on the present value of discounted cash flows taking into account anticipated credit losses, the speed of payments and the discount rate commensurate with the uncertainty involved. The PSE Funding agreement replaces the Rainier securitization facility that was terminated on December 20, 2005. In addition, PSE Funding entered into a Loan and Servicing Agreement with PSE and two banks. The Loan and Servicing Agreement allows PSE Funding to use the receivables as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables which fluctuate with the seasonality of energy sales to customers. The PSE Funding receivables securitization facility expires in December 2010, and is terminable by PSE and PSE Funding upon notice to the banks. PSE Funding had $110.0 million of loans secured by accounts receivable pledged as collateral at December 31, 2006.
Rainier Receivables, Inc. is(Rainier Receivables) was a wholly owned, bankruptcy-remote subsidiary of PSE formed in December 2002 for the purpose of purchasing customers’ accounts receivable, both billed and unbilled, of PSE. Rainier Receivables and PSE havehad an agreement whereby Rainier Receivables canwould sell, on a revolving basis, up to $150$150.0 million of those eligible receivables. The current agreement expires inexpired December 20, 2005. Rainier Receivables iswas obligated to pay fees that approximate the third-party purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. At December 31, 2004, Rainier Receivables had sold $150 million
Consolidated Statements of receivables comparedCash Flows
PSE funds cash dividends paid to $111 millionthe shareholders of receivables soldPuget Energy. These funds are reflected in the Consolidated Statement of Cash Flows of Puget Energy as if Puget Energy received the cash from PSE and paid the dividends directly to the shareholders.
Comprehensive income includes net income, foreign currency translations, changes in the minimum pension liability, unrealized gains and losses on derivative instruments, reversals of unrealized gains and losses on derivative instruments, settlements and amortization of cash flow hedge contracts and deferrals of cash flow hedges related to the power cost mechanism. The following table presents the Company’s accumulated other comprehensive gain (loss) net of tax at December 31, 2003.31:
| (Dollars in Thousands) | | 2006 | | 2005 | |
| Unrealized gains (losses) on derivatives during the period | | $ | 9,584 | | $ | 42,397 | |
| Reversal of unrealized (gains) losses on derivatives during the period | | | (4,691 | ) | | 761 | |
| Adjustment to PCA | | | -- | | | (6,253 | ) |
| Settlement of cash flow hedge contract | | | 13,447 | | | 67 | |
| Amortization of cash flow hedge contracts | | | (21,972 | ) | | (22,505 | ) |
| Minimum pension liability adjustment | | | (4,413 | ) | | (7,286 | ) |
| Adjustment to initially apply SFAS No. 158 | | | (18,653 | ) | | -- | |
| Total PSE, net of tax | | $ | (26,698 | ) | $ | 7,181 | |
| Foreign currency translation adjustment | | | -- | | | 327 | |
| Total Puget Energy, net of tax | | $ | (26,698 | ) | $ | 7,508 | |
NOTE 2.New Accounting Pronouncements
On September 29, 2006, FASB issued SFAS No. 158, “Employer’s Accounting for Retired Benefit Pension and Other Postretirement Plans.” See Note 14, “Retirement Benefits” for discussion of the new statement.
On September 15, 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 standardizes the measurement of fair value when it is required under generally accepted accounting principles (GAAP). SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, which will be the year beginning January 1, 2008, for the Company. The adoption of SFAS No. 157 is not expected to have a material impact on the Company’s financial statements.
In July 2006, FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, the tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing authority. Second, a tax position, that meets the recognition threshold, should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained.
FIN 48 was effective for the Company as of January 1, 2007. The change in net assets as a result of adopting FIN 48 will be treated as a change in accounting method. The cumulative effect of the change will be recorded to retained earnings. Adjustments to regulatory accounts, if any, will be based on other applicable accounting standards. The Company is currently in the process of evaluating the provisions of FIN 48 to determine the potential impact, if any, the adoption will have on the Company’s financial statements. The adoption of FIN 48 is not expected to have a material impact on the Company’s retained earnings. Management’s estimated impact of adoption is subject to change due to potential changes in interpretation of FIN 48 by the FASB or other regulatory bodies and the finalization of the Company’s adoption efforts.
At its June 15, 2006 meeting, FASB’s Emerging Issues Task Force (EITF) approved the issuance of EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” EITF No. 06-3 requires companies to disclose whether or not the taxes collected from customers and remitted to government authorities are reported on a gross (included in revenues and costs) or a net (excluded from revenues) basis. In addition, for any such taxes that are reported on a gross basis, a company should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The EITF concluded that these requirements should be applied to financial reports for interim and annual periods beginning after December 15, 2006, which will be the quarter ended March 31, 2007, for the Company.
In December 2004, FASB issued SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R), which revises SFAS No. 123, “Accounting For Stock-Based Compensation.” SFAS No. 123R requires companies that issue share-based payment awards to employees for goods or services to recognize as compensation expense the fair value of the expected vested portion of the award as of the grant date over the vesting period of the award. Forfeitures that occur before the award vesting date will be adjusted from the total compensation expense, but once the award vests, no adjustment to compensation expense will be allowed for forfeitures or unexercised awards. In addition, SFAS No. 123R would requirerequires recognition of compensation expense of all existing outstanding awards that are not fully vested for their remaining vesting period as of the effective date that were not accounted for under a fair-valuefair value method of accounting at the time of their award. SFAS No. 123R is effective for reporting periods beginning after June 15, 2005. TheEffective January 1, 2006, the Company is currently evaluating what impactadopted the applicationfair value recognition provisions of SFAS No. 123R, will have on its operations. The Company had adopted“Share-Based Payment,” using the fair value provisions of SFAS No. 123 “Accounting for Stock Based Compensation” in January 2003.
In December 2004, FASB issued FASB Staff Position No. 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP No. 109-1). FSP No. 109-1 states that the staff position related to deductions as a result of the American Jobs Creation Act (the Act) should be treated as a “special deduction”, as described in SFAS No. 109, “Accounting For Income Taxes” and therefore has no effect on deferred tax assets or liabilities existing at the enactment date. The Company is currently evaluating the impact of FSP No. 109-1 (which was effective upon issuance) and any deduction available under the Act. Any deduction available, if determined, is applicable to the Company’s 2005 tax year.
On May 19, 2004, FASB issued FASB Staff Position (FSP) No. 106-2 “Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003” as the result of the new Medicare Prescription Drug and Modernization Act which was signed into law in December 2003. The law provides a subsidy for plan sponsors that provide prescription drug benefits to Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based upon an actuarial assessment, PSE will not be eligible for such subsidies, thus FSP No. 106-2 will have no impact on PSE’s retiree medical plans.
The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) at its July 2003 meeting came to a consensus concerning EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03.” The consensus reached was that determining whether realized gains and losses on physically settled derivative contracts not held for trading purposes are reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Based on the guidance by EITF No. 03-11, the Company determined that its non-trading derivative instruments should be reported net and implemented this treatment effective January 1, 2004. As a result of the implementation, Electric Revenue and Purchased Electricity Expense both decreased $108.7 million in 2003 and $77.1 million in 2002, respectively, with no impact on financial position or net income.modified-prospective transition method.
In March 2004, the EITF came to a consensus concerning EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies.” The consensus reached was that an investment in a limited liability company (LLC) should be accounted for using the equity method for investments greater than 3% to 5%. The adoption of EITF No. 03-16 is effective for reporting periods beginning after June 15, 2004, with any adjustments being accounted for as a cumulative effect of a change in accounting principle. The Company reviewed its investments and determined one investment held by PSE met the criteria established in EITF No. 03-16.
In May 2003, FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes the requirements for classifying and measuring as liabilities certain financial instruments that embody obligations to redeem the financial instruments by the issuer. The adoption of SFAS No. 150 is effective with the first fiscal year or interim period beginning after June 15, 2003. However, on November 5, 2003 FASB deferred for an indefinite period certain mandatorily redeemable noncontrolling interests associated with finite-lived subsidiaries. The Company does not have any noncontrolling interest in finite-lived subsidiaries and therefore, is not affected by the deferral. Prior periods will not be restated for the new presentation.
SFAS No. 150 requires the Company to classify its mandatorily redeemable preferred stock as liabilities. As a result, the corresponding dividends on the mandatorily redeemable preferred stock are classified as interest expense on the income statement with no impact on income for common stock.
In January 2003,2005, FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities”47 (FIN 46)47), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. FIN 46 requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements must be included in the consolidated financial statements of the business entity. The adoption of FIN 46 for all interests in variable interest entities created after January 31, 2003 was effective immediately. For variable interest entities created before February 1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was effective March 31, 2004. The Company evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction met this guidance, and therefore it was consolidated in the third quarter 2003. As a result, electricity revenues for 2003 increased $5.7 million, while conservation amortization and interest expense increased by the corresponding amount with no impact on earnings. FIN 46R also impacted the treatment of the Company’s mandatorily redeemable preferred securities of a wholly owned subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities). Previously, these trust-preferred securities were consolidated into the Company’s operations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities (junior subordinated debt) in the fourth quarter 2003. This change had no impact on the Company’s results of operations. The Company also evaluated its purchase power agreements and determined that three counterparties may be considered variable interest entities. As a result, PSE submitted requests for information to those parties; however, the parties have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity. PSE also determined that it does not have a contractual right to such information. PSE will continue to submit requests for information to the counterparties in the future to determine if FIN 46R is applicable.
For the three purchase power agreements that may be considered variable interest entities under FIN 46R, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the purchase power agreements. If at any time the counterparties cannot deliver energy to PSE, PSE would have to buy energy in the wholesale market at prices which could be higher or lower than the purchase power agreement prices. PSE’s Purchased Electricity expense for 2004 and 2003 for these three entities was $251.2 million and $273.9 million, respectively.
In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143) which is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company adopted the new rules on asset retirement obligations on January 1, 2003. As a result, the Company recorded a $0.2 million charge to income for the cumulative effect of this accounting change. (See Note 3.)
In November 2004, FASB reached a decision concerningfinalized a proposed interpretation of SFAS No. 143 titled, “Accounting for Conditional Asset Retirement Obligations.” The proposed interpretation addresses the issue of whether SFAS No. 143 requires an entity to recognize a liability for a legal obligation to perform asset retirement when the asset retirement activities are conditional on a future event, and if so, the timing and valuation of the recognition. The decision reached by FASB was that there are no instances where a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation. This, if part ofFIN 47 was effective for the final issued interpretation, could potentially have an impact on the Company as assets that were previously considered outside the scope of SFAS No. 143 may be subject to the terms of the proposed interpretation. FASB indicated that the final interpretation is anticipated to be issued in the first quarter 2005, with an effective date for fiscal years ending afteryear ended December 15, 2005, with any adjustmentand was required to be accounted for as a cumulative effect of an accounting change. The Company is currently evaluating what impact this proposed interpretation may haveadopted FIN 47 in the fourth quarter 2005, which resulted in the recognition of a cumulative effect for the asset retirement obligations amounting to $0.1 million after-tax.
On May 19, 2004, FASB issued FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” as the result of the new Medicare Prescription Drug Improvement and Modernization Act which was signed into law in December 2003. The law provides a subsidy for plan sponsors that provide prescription drug benefits to Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based on new Medicare regulations issued in May 2005, the Company if issued.determined that it provides benefits at a higher level than provided under Medicare Part D, and therefore would qualify for federal tax subsidies.
NOTE 3. Discontinued Operations and Corporate Guarantees (Puget Energy Only)
On May 7, 2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P. (Tenaska). After repayment of debt, adjustments for working capital, transaction costs and distributions to minority interests, Puget Energy received after-tax cash proceeds of approximately $95.9 million for its 90.9% interest in InfrastruX in the second quarter 2006. The sale resulted in an after-tax gain of $29.8 million for the nine months ended September 30, 2006. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005 and 2006.
Under the terms of the sale agreement, Puget Energy is obligated for certain representations and warranties made by InfrastruX concerning its business. Puget Energy obtained a representation and warranty insurance policy and deposited $3.7 million into an escrow account to serve as retention under the policy. As of December 31, 2006, long-term restricted cash in the amount of $3.8 million is included in the accompanying balance sheets; that amount represents management’s estimate of the aggregate fair value of the amount potentially payable under those representations and warranties and is Puget Energy’s maximum exposure related to those commitments. The obligation expires May 7, 2008. Should Tenaska make any such claims against Puget Energy, payment for the claims would be made from the escrow account, and total payments are limited to $3.7 million plus any interest earned while the funds are held in the escrow account. Puget Energy also agreed to indemnify Tenaska for certain potential future losses related to one of InfrastruX’s subsidiary companies. Under the indemnity agreement, Puget Energy is liable for certain costs with the maximum amount of loss not to exceed $15.0 million. As of December 31, 2006, a liability in the amount of $5.0 million is included in the accompanying balance sheets; that amount represents Puget Energy’s estimate of the fair value of the amount potentially payable using a probability-weighted approach to a range of future cash flows. The obligation expires May 7, 2011. Puget Energy also provided an environmental guarantee as part of the sale agreement. Under the terms of the agreement, Tenaska will be responsible for the first $0.1 million of environmental claims, Tenaska and Puget Energy will share the next $6.4 million equally and Puget Energy will be responsible for the next $3.5 million. Puget Energy believes it will not have a future loss in connection with the environmental guarantee. For 2006, Puget Energy reported InfrastruX related income from discontinued operations (net of taxes and minority interest), including gain on sale, of $51.9 million compared to $9.5 million (net of taxes and minority interest) for 2005. Puget Energy’s income from discontinued operations for 2006 includes $7.3 million related to the reversal of a carrying value adjustment recorded in 2005 as well as $10.0 million related to the anticipated realization of a deferred tax asset associated with the sale of the business in accordance with EITF No. 93-17, “Recognition of Deferred Tax Assets for a Parent Company’s Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation.”
| | | Twelve Months Ended December 31, | |
| (Dollars in Thousands) | | 20061 | | 2005 | | 2004 | |
| Revenues | | $ | 138,573 | | $ | 393,294 | | $ | 369,936 | |
| Goodwill impairment | | | -- | | | -- | | | (91,196 | ) |
| Operating expenses (including interest expense) | | | (128,605 | ) | | (356,934 | ) | | (357,990 | ) |
| Pre-tax income | | | 9,968 | | | 36,360 | | | (79,250 | ) |
| Income tax expense | | | (3,544 | ) | | (12,204 | ) | | 1,793 | |
| Puget Energy carrying value adjustment of InfrastruX | | | 7,269 | | | (7,269 | ) | | -- | |
| Puget Energy cost of sale related to InfrastruX, net of tax | | | (937 | ) | | (5,195 | ) | | -- | |
| Puget Energy deferred tax basis adjustment of InfrastruX | | | 9,966 | | | -- | | | -- | |
| Gain on sale, net of tax | | | 29,765 | | | -- | | | -- | |
| Minority interest in income of discontinued operations | | | (584 | ) | | (2,178 | ) | | 7,069 | |
| Income (loss) from discontinued operations | | $ | 51,903 | | $ | 9,514 | | $ | (70,388 | ) |
_______________1 | Results for January 1, 2006 to May 7, 2006, the date InfrastruX was sold. |
In accordance with SFAS No. 144, InfrastruX discontinued depreciation and amortization of its assets effective February 8, 2005. This discontinuation of depreciation and amortization resulted in $16.8 million ($10.8 million after-tax) and $6.7 million ($4.3 million after-tax) lower depreciation and amortization expense than otherwise would have been recorded as continuing operations for 2006 and 2005, respectively. Puget Energy recorded $0.2 million and $2.1 million of amortization expense related to the intangible assets of InfrastruX for 2005 and 2004, respectively.
Puget Energy’s balance sheet at December 31, 2006 does not include InfrastruX assets and liabilities as a result of the disposition in May 2006. InfrastruX’s summarized assets and liabilities, including intercompany balances eliminated in consolidation, at December 31, 2005 were:
(Dollars in thousands) | | December 31, 2005 | |
| Assets: | | | |
| Cash | | $ | 6,187 | |
| Accounts receivable | | | 78,842 | |
| Other current assets | | | 22,405 | |
| Total current assets | | | 107,434 | |
| Goodwill | | | 43,886 | |
| Intangibles | | | 14,443 | |
| Non-utility property and other | | | 108,784 | |
| Total long-term assets | | | 167,113 | |
| Total assets | | $ | 274,547 | |
(Dollars in thousands) | | December 31, 2005 | |
| Liabilities: | | | |
| Accounts payable | | $ | 9,178 | |
| Short-term debt | | | 3,809 | |
| Current maturities of long-term debt | | | 6,477 | |
| Other current liabilities | | | 36,327 | |
| Total current liabilities | | | 55,791 | |
| Deferred income taxes | | | 24,645 | |
| Long-term debt | | | 120,013 | |
| Other deferred credits | | | 16,986 | |
| Total long-term liabilities | | | 161,644 | |
| Total liabilities | | $ | 217,435 | |
NOTE 3.4. Utility and Non-Utility Plant
UTILITY PLANT (DOLLARS IN THOUSANDS) AT DECEMBER 31 | ESTIMATED USEFUL LIFE (YEARS) | | 2004 | | 2003 | | |
Utility Plant (Dollars In Thousands) At December 31 | | | Estimated Useful Life (Years) | | 2006 | | 2005 | |
Electric, gas and common utility plant classified by prescribed accounts at original cost: | | | | | | | | | | | | | |
| Distribution plant | 10-60 | | $ 4,219,720 | | $ 4,030,570 | | | | 10-65 | | $ | 4,887,304 | | $ | 4,469,818 | |
| Production plant | 40-100 | | 1,150,781 | | 1,144,354 | | | | 20-100 | | | 1,694,569 | | | 1,326,383 | |
| Transmission plant | 30-95 | | 426,543 | | 379,889 | | | | 40-95 | | | 331,210 | | | 440,679 | |
| General plant | 10-35 | | 346,472 | | 344,781 | | | | 10-35 | | | 367,806 | | | 363,382 | |
| Whitehorn capital lease | | | | 10 | | | 23,004 | | | -- | |
| Construction work in progress | NA | | 129,966 | | 121,622 | | | | NA | | | 206,459 | | | 216,513 | |
| Intangible plant (including capitalized software) | 3-29 | | 283,179 | | 270,235 | | | | 3-29 | | | 297,939 | | | 288,509 | |
| Plant acquisition adjustment | 21 | | 76,623 | | 76,623 | | | | 21-34 | | | 77,871 | | | 77,871 | |
| Underground storage | 50-80 | | 23,089 | | 22,362 | | | | 50-80 | | | 24,389 | | | 23,880 | |
| Liquefied natural gas storage | 14-50 | | 12,345 | | 2,348 | | | | 14-50 | | | 14,217 | | | 12,339 | |
| Plant held for future use | -- | | 7,296 | | 7,608 | | | | NA | | | 8,315 | | | 9,153 | |
| Other | 27-34 | | 5,313 | | 5,240 | | | | NA | | | 5,595 | | | 4,891 | |
| Less accumulated provision for depreciation | | | (2,452,969 | ) | (2,325,405 | ) | |
| Less: accumulated provision for depreciation | | | | | | | (2,757,632 | ) | | (2,602,500 | ) |
| Net utility plant | | | $ 4,228,358 | | $ 4,080,227 | | | | | | $ | 5,181,046 | | $ | 4,630,918 | |
Jointly owned generating plants service costs are included in utility plant service cost. The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2006. These amounts are also included in the Utility Plant table above.
NON-UTILITY PLANT (DOLLARS IN THOUSANDS) AT DECEMBER 31 | ESTIMATED USEFUL LIFE (YEARS) | | 2004 | | 2003 | |
| Non-utility plant | 3-20 | | $ 138,656 | | $ 122,926 | |
| Intangibles | 5-20 | | 24,056 | | 23,985 | |
| Less accumulated depreciation and amortization | | | (52,947 | ) | (36,272 | ) |
| Net non-utility plant and intangibles | | | $ 109,765 | | $ 110,639 | |
| | | | Company’s Share |
Jointly Owned Generating Plants (Dollars in Thousands) | Energy Source (Fuel) | Company’s Ownership Share | Plant in Service at Cost | Accumulated Depreciation |
| Colstrip Units 1 & 2 | Coal | 50% | $ 228,480 | $ (146,703) |
| Colstrip Units 3 & 4 | Coal | 25% | 479,228 | (272,003) |
| Colstrip Units 1 - 4 Common Facilities | Coal | * | 252 | (157) |
| Frederickson 1 | Gas | 49.85% | 73,740 | (6,281) |
_______________
* | The Company’s ownership is 50% for Colstrip Units 1 & 2 and 25% for Colstrip Units 3 & 4. |
Financing for a participant’s ownership share in the projects is provided by such participant. The Company’s share of related operating and maintenance expenses is included in corresponding accounts in the Consolidated Statements of Income.
Non-Utility Plant (Dollars In Thousands) At December 31 | | Estimated Useful Life (Years) | | 2006 | | 2005 | |
| Non-utility plant | | | 6-20 | | $ | 2,948 | | $ | 3,113 | |
| Less: accumulated provision for depreciation | | | | | | (446 | ) | | (445 | ) |
| Net non-utility plant | | | | | $ | 2,502 | | $ | 2,668 | |
Non-utility plant is composed primarily of the property, plantland and equipment of InfrastruX.land rights that are not included in rate-based property. Non-utility plant and accumulated depreciation isare included in “other” under “other property and investments” in the Puget Energy and PSE balance sheet. Intangibles are composed of patents, contractual customer relationships and other amortizable intangible assets of InfrastruX.
On January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company recorded an after-tax charge to income of $0.2 million in the first quarter 2003 for the cumulative effect of the accounting change. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.sheets.
The Company identified various asset retirement obligations at January 1, 2003,under SFAS No. 143, “Accounting for Asset Retirement Obligations,” upon initial adoption, and in 2005 identified additional asset retirement obligations to replace bare steel natural gas pipe and for the future removal of wind turbine generators. In March 2005, FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations” (ARO), which were includedprovides guidance on when an asset retirement obligation that is conditional on a future event should be recognized. The Company adopted FIN 47 in the cumulative effectfourth quarter 2005 which resulted in the recognition of additional ARO. FIN 47 also requires that if an entity has any ARO for which no amount has been recognized, the existence of the accounting change. TheARO must be disclosed with the reasons why the liability has not been recognized.
Prior to the adoption of FIN 47, the Company hasrecognized an obligation to: (1) to dismantle two leased electric generation turbine units and deliver the turbines to the nearest railhead at the termination of the lease in 2009; (2) to remove certain structures as a result of renegotiationsre-negotiations with the Department of Natural Resources of a now-expirednow expired lease; (3) to replace or line all cast iron pipes in its service territory by 2007 as a result of a 1992 Washington Commission order; and (4) to restore ash holding ponds at a jointly owned coal-fired electric generating facility in Montana.Montana; (5) replace all unprotected bare steel gas pipe in its service territory by 2015 as a result of a January 31, 2005 Washington Commission order; and (6) remove wind turbine generators and related equipment, improvements and fixtures at the termination of the related leases. The adoption of FIN 47 in the fourth quarter 2005 resulted in recognition of additional ARO to: (1) dispose of treated wood poles; (2) dispose of oil containing PCBs and the related equipment that held the oil; (3) remove asbestos in facilities that have been identified for remodeling or demolition; and (4) disconnect abandoned pipelines, purge the pipelines of gas and cut and cap their supplies of gas. In 2006, the Company recognized ARO for the decommissioning costs of the Frederickson facility at the end of its service life and costs related to wood poles, gas mains and contaminated oil in equipment placed in service in 2006.
The following table describes all changes to the Company’s asset retirement obligation liability:
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | | |
(Dollars in Thousands) At December 31 | | | 2006 | | 2005 | |
| Asset retirement obligation at beginning of year | | $ | 3,421 | | $ | -- | | | $ | 28,274 | | $ | 3,516 | |
| Liability recognized in transition | | | -- | | | 3,592 | | | | -- | | | 22,084 | |
| New asset retirement obligation liability recognized in the period | | | | 487 | | | 2,841 | |
| Liability settled in the period | | | -- | | | (261 | ) | | | (1,351 | ) | | (382 | ) |
| Accretion expense | | | 95 | | | 90 | | | | 946 | | | 215 | |
| Asset retirement obligation at December 31 | | $ | 3,516 | | $ | 3,421 | | | $ | 28,356 | | $ | 28,274 | |
The Company has identified the following obligations which were not recognized at December 31, 2006: (1) a legal obligation under the Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sale. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated currently; (2) an obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated currently; (3) an obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely, therefore the liability cannot be reasonably estimated currently; (4) a legal obligation under the state of Washington environmental laws to remove and properly dispose of certain under and above ground storage fuel tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore the liability cannot be reasonably estimated currently; and (5) a potential legal obligation, arising (if at all) upon the expiration of an existing FERC hydropower license, were FERC to then order project decommissioning. Regardless, given the value of ongoing generation, flood control, and other benefits provided by these projects, PSE believes that the potential for decommissioning is both remote and cannot be reasonably estimated.
The pro forma asset retirement obligation liability balances as if SFAS No. 143, as interpreted by FIN 47, had been adopted on January 1, 2002December 31, 2003 (rather than January 1, 2003)December 31, 2005) are as follows:
(DOLLARS IN THOUSANDS)Dollars in Thousands) | |
Pro forma amounts of liability for asset retirement obligation at January 1, 2002 | $ 3,497 |
Pro forma amounts of liability for asset retirement obligation at December 31, 20022003 | 3,592$ 25,281 |
| Pro forma amounts of liability for asset retirement obligation at December 31, 2004 | 25,297 |
The pro forma income statement effect as if SFAS No. 143, as interpreted by FIN 47, had been adopted on January 1, 2002December 31, 2003 (rather than January 1, 2003)December 31, 2005) is as follows:
| (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) | | 2003 | | 2002 | | |
| (Dollars in Thousands, except per share amounts) | | | 2005 | | 2004 | |
| Net income, as reported | | $ | 116,197 | | $ | 110,052 | | | $ | 155,726 | | $ | 55,022 | |
| Add: SFAS No. 143 transition adjustment, net of tax | | | 169 | | | -- | | | | -- | | | -- | |
| Add: FIN 47 transition adjustment, net of tax | | | | 71 | | | -- | |
| Less: Pro forma accretion expense, net of tax | | | -- | | | (62 | ) | | | -- | | | -- | |
| Pro forma net income | | $ | 116,366 | | $ | 109,990 | | | $ | 155,797 | | $ | 55,022 | |
| Earnings per share: | | | | | | | | | | | | | | |
| Basic as reported | | $ | 1.23 | | $ | 1.24 | | | $ | 1.52 | | $ | 0.55 | |
| Diluted as reported | | $ | 1.22 | | $ | 1.24 | | | $ | 1.51 | | $ | 0.55 | |
| Basic pro forma | | $ | 1.23 | | $ | 1.24 | | | $ | 1.52 | | $ | 0.55 | |
| Diluted pro forma | | $ | 1.22 | | $ | 1.24 | | | $ | 1.51 | | $ | 0.55 | |
On November 1, 2003, all the authorized and outstanding 2.4 million shares of the $25 par value 7.45% Series preferred stock not subject to mandatory redemption were redeemed at par value plus accrued dividends. There were no other redemptions or reacquired shares of this preferred stock series in 2003.
NOTE 5.Preferred Share Purchase Right
On October 23, 2000, the Board of Directors declared a dividend of one preferred share purchase right (a Right) for each outstanding common share of Puget Energy. The dividend was paid on December 29, 2000 to shareholders of record on that date. The Rights will become exercisable only if a person or group acquires 10% or more of Puget Energy’s outstanding common stock or announces a tender offer which, if consummated, would result in ownership by a person or group of 10% or more of the outstanding common stock. Each Right will entitle the holder to purchase from Puget Energy one one-hundredth of a share of preferred stock with economic terms similar to that of one share of Puget Energy’s common stock at a purchase price of $65,$65.0, subject to adjustments. The Rights expire on December 21, 2010, unless redeemed or exchanged earlier by Puget Energy.
NOTE 6.Dividend Restrictions
The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in the Company’s Restated Articles of Incorporation and Mortgage Indentures. Under the most restrictive covenants of PSE, earnings reinvested in the business unrestricted as to payment of cash dividends were approximately $274.4$398.9 million at December 31, 2004.2006. For the years 2004, 20032006, 2005 and 2002,2004, the aggregate dividends declared per share declared by Puget Energy were $1.00, $1.00, and $1.21,$1.00, respectively.
Under the general rate settlement, PSE must rebuildpaid cash dividends on its common equity ratiostock to at least 39%, with milestonesPuget Energy of 35%$109.8 million, $89.2 million and 39% at the end of$87.7 million for 2006, 2005 and 2004, and 2005, respectively. If PSE should fail to meet the schedule, it would be subject to a 2% rate reduction penalty. The common equity ratio for PSE at December 31, 2004 was 40.1%.
NOTE 7.Redeemable Securities
| | | PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION $100 PAR VALUE | |
| | | 4.70% SERIES | | 4.84% | | 7.75% | |
| Shares outstanding December 31, 2001 | | | 4,311 | | | 14,808 | | | 487,500 | |
| Acquired for sinking fund: | | | | | | | | | | |
| 2002 | | | -- | | | -- | | | (75,000 | ) |
| 2003 | | | -- | | | -- | | | (75,000 | ) |
| 2004 | | | -- | | | -- | | | -- | |
| Called for redemption or reacquired and canceled: | | | | | | | | | | |
| 2002 | | | -- | | | -- | | | -- | |
| 2003 | | | -- | | | (225 | ) | | (337,500 | ) |
| 2004 | | | -- | | | -- | | | -- | |
| Shares outstanding December 31, 2004 | | | 4,311 | | | 14,583 | | | -- | |
See “Consolidated Statements of Capitalization” for details on specific series.
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
The Company is required to deposit funds annually in a sinking fund sufficient to redeem the following number of shares of each series of preferred stock at $100 per share plus accrued dividends: 4.70% Series and 4.84% Series, 3,000 shares each. All previous sinking fund requirements have been satisfied. The $100 par value 7.75% Series preferred stock subject to mandatory redemption was fully redeemed at $102.07 per share plus accrued dividends on August 15, 2003. At December 31, 2004,2006, there were 34,68928,689 shares of the 4.70% Series and 18,19212,192 shares of the 4.84% Series acquired by the Company and available for future sinking fund requirements. Upon involuntary liquidation, all preferred shares are entitled to their par value plus accrued dividends.
The preferred stock subject to mandatory redemption may also be redeemed by the Company at the following redemption prices per share plus accrued dividends: 4.70% Series, $101.00 and 4.84% Series, $102.00.
JUNIOR SUBORDINATED DEBENTURES OF THE CORPORATION PAYABLE TOJunior Subordinated Debentures Of The Corporation Payable To A SUBSIDIARY TRUST HOLDING MANDATORILY REDEEMABLE PREFERRED SECRUITIESSubsidiary Trust Holding Mandatorily Redeemable Preferred Securities
In 1997 and 2001, the Company formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling common and preferred securities (Trust Securities). The proceeds from the sale of Trust Securities were used to purchase Junior Subordinated Debenturesjunior subordinated debentures (Debentures) from the Company. The Debentures are the sole assets of the Trusts and the Company owns all common securities of the Trusts.
The Debentures of Trust I and Trust II have an interest rate of 8.231% and 8.40%8.4%, respectively, and a stated maturity date of June 1, 2027 and June 30, 2041, respectively. The Trust Securities are subject to mandatory redemption at par on the stated maturity date of the Debentures. The Trust Securities in theOn June 30, 2006, PSE called all of PSE’s 8.4% Capital Trust I may be redeemed earlier, under certain conditions, at the optionPreferred Securities (classified as junior subordinated debentures of the Company.corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities on the balance sheets). The Capital Trust II Securities may bewere redeemed at any time on or after June 30, 2006 at par under certain conditions, at the option of the Company. Dividendsand dividends relating to the preferred securities arewere paid and included in interest expense for all periods presented.expense. The Capital Trust Preferred Securities were redeemed using the proceeds of senior notes issued at an interest rate of 6.724%.
FIRST MORTGAGE BONDS AND SENIOR NOTESAT DECEMBER 31 (DOLLARS IN THOUSANDS)First Mortgage Bonds and Senior Notes (Dollars in Thousands) At December 31 |
| Series | | Due | | 2006 | | 2005 | | Series | | Due | | 2006 | | 2005 |
| 6.58 | % | 2006 | $ | -- | $ | 10,000 | | 7.69 | % | 2011 | $ | 260,000 | $ | 260,000 |
| 8.06 | % | 2006 | | -- | | 46,000 | | 6.83 | % | 2013 | | 3,000 | | 3,000 |
| 8.14 | % | 2006 | | -- | | 25,000 | | 6.90 | % | 2013 | | 10,000 | | 10,000 |
| 7.02 | % | 2007 | | 20,000 | | 20,000 | | 5.197 | % | 2015 | | 150,000 | | 150,000 |
| 7.04 | % | 2007 | | 5,000 | | 5,000 | | 7.35 | % | 2015 | | 10,000 | | 10,000 |
| 7.75 | % | 2007 | | 100,000 | | 100,000 | | 7.36 | % | 2015 | | 2,000 | | 2,000 |
| 3.363 | % | 2008 | | 150,000 | | 150,000 | | 6.74 | % | 2018 | | 200,000 | | 200,000 |
| 6.51 | % | 2008 | | 1,000 | | 1,000 | | 9.57 | % | 2020 | | 25,000 | | 25,000 |
| 6.53 | % | 2008 | | 3,500 | | 3,500 | | 7.15 | % | 2025 | | 15,000 | | 15,000 |
| 7.61 | % | 2008 | | 25,000 | | 25,000 | | 7.20 | % | 2025 | | 2,000 | | 2,000 |
| 6.46 | % | 2009 | | 150,000 | | 150,000 | | 7.02 | % | 2027 | | 300,000 | | 300,000 |
| 6.61 | % | 2009 | | 3,000 | | 3,000 | | 7.00 | % | 2029 | | 100,000 | | 100,000 |
| 6.62 | % | 2009 | | 5,000 | | 5,000 | | 5.483 | % | 2035 | | 250,000 | | 250,000 |
| 7.12 | % | 2010 | | 7,000 | | 7,000 | | 6.724 | % | 2036 | | 250,000 | | -- |
| 7.96 | % | 2010 | | 225,000 | | 225,000 | | 6.274 | % | 2037 | | 300,000 | | -- |
| | | | | | | | | Total | $ | 2,571,500 | $ | 2,102,500 |
| SERIES | | DUE | | 2004 | | 2003 | | SERIES | | DUE | | 2004 | | 2003 |
| 6.07% | | 2004 | | $ -- | | $10,000 | | 6.46% | | 2009 | | 150,000 | | 150,000 |
| 6.10% | | 2004 | | -- | | 8,500 | | 6.61% | | 2009 | | 3,000 | | 3,000 |
| 7.70% | | 2004 | | -- | | 50,000 | | 6.62% | | 2009 | | 5,000 | | 5,000 |
| 7.80% | | 2004 | | -- | | 30,000 | | 7.12% | | 2010 | | 7,000 | | 7,000 |
| 6.92% | | 2005 | | 11,000 | | 11,000 | | 7.96% | | 2010 | | 225,000 | | 225,000 |
| 6.93% | | 2005 | | 20,000 | | 20,000 | | 7.69% | | 2011 | | 260,000 | | 260,000 |
| Variable | | 2006 | | 200,000 | | -- | | 6.83% | | 2013 | | 3,000 | | 3,000 |
| 6.58% | | 2006 | | 10,000 | | 10,000 | | 6.90% | | 2013 | | 10,000 | | 10,000 |
| 8.06% | | 2006 | | 46,000 | | 46,000 | | 7.35% | | 2015 | | 10,000 | | 10,000 |
| 8.14% | | 2006 | | 25,000 | | 25,000 | | 7.36% | | 2015 | | 2,000 | | 2,000 |
| 7.02% | | 2007 | | 20,000 | | 20,000 | | 6.74% | | 2018 | | 200,000 | | 200,000 |
| 7.04% | | 2007 | | 5,000 | | 5,000 | | 9.57% | | 2020 | | 25,000 | | 25,000 |
| 7.75% | | 2007 | | 100,000 | | 100,000 | | 7.35% | | 2024 | | -- | | 55,000 |
| 3.363% | | 2008 | | 150,000 | | 150,000 | | 7.15% | | 2025 | | 15,000 | | 15,000 |
| 6.51% | | 2008 | | 1,000 | | 1,000 | | 7.20% | | 2025 | | 2,000 | | 2,000 |
| 6.53% | | 2008 | | 3,500 | | 3,500 | | 7.02% | | 2027 | | 300,000 | | 300,000 |
| 7.61% | | 2008 | | 25,000 | | 25,000 | | 7.00% | | 2029 | | 100,000 | | 100,000 |
| | | | | | | | | Total | | $1,933,500 | | $1,887,000 |
In January 2004, the CompanyOn March 16, 2006, Puget Energy and PSE filed a shelf-registrationshelf registration statement with the Securities and Exchange CommissionSEC for the offering on a delayed or continuous basis, of up to $500 million of any combination of common stock, senior notes, preferred stock, and trust preferred securities of Puget Sound Energy Capital Trust III. The registration statement is valid for three years and principaldoes not specify the amount of securities that the Company may offer.
On June 30, 2006, PSE completed the issuance of $250.0 million of senior secured notes secured byat a pledgerate of first mortgage bonds. In July 2004, PSE issued $200 million in floating rate senior notes under its existing $500 million registration statement.6.724%, which are due on June 15, 2036. The notes have a floating interest rate which is based on the three-month LIBOR rate plus 0.30% (2.37% at December 31, 2004), and mature in July 2006. The Company called and paid off five series of first mortgage bonds in 2004, totaling $153.5 million. The Company repaid the bonds using both cash on hand andnet proceeds from the $200issuance of the senior notes of approximately $247.8 million floatingwere used to redeem $200.0 million of 8.40% Capital Trust Preferred Securities, which were redeemed at par on June 30, 2006, and to repay a portion of PSE’s short-term debt. On September 18, 2006, PSE completed the issuance of $300.0 million of senior secured notes at a rate of 6.274%, which are due on March 15, 2037. The net proceeds from the issuance of the senior notes.notes of approximately $297.4 million were used to repay PSE’s outstanding short-term debt which was incurred primarily to fund construction programs.
Substantially all utility properties owned by the Company are subject to the lien of the Company’s electric and gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must be at least twice the annual interest charges on outstanding first mortgage bonds. At December 31, 2004,2006, the earnings available for interest exceeded the required amount.
POLLUTION CONTROL BONDSPollution Control Bonds
The Company has outstanding two series of Pollution Control Bonds.Bonds outstanding. On February 19, 2003, the Board of Directors approved the refinancing of all Pollution Control Bonds series, which were issued in March 2003. Amounts outstanding were borrowed from the City of Forsyth, Montana (the City). The City obtained the funds from the sale of Customized Pollution Control Refunding Bonds issued to finance pollution control facilities at Colstrip Units 3 & 4.
Each series of bonds is collateralized by a pledge of PSE’s first mortgage bonds, the terms of which match those of the Pollution Control Bonds. No payment is due with respect to the related series of first mortgage bonds so long as payment is made on the Pollution Control Bonds.
AT DECEMBER 31 (DOLLARS IN THOUSANDS) |
| SERIES | DUE | 2004 | 2003 |
2003A Series- 5.00% | 2031 | $ 138,460 | $ 138,460 |
2003B Series- 5.10% | 2031 | 23,400 | 23,400 |
| Total | | $ 161,860 | $ 161,860 |
(Dollars in Thousands) At December 31 | |
| Series | | Due | | 2006 | | 2005 | |
2003A Series - 5.00% | | 2031 | | $ | 138,460 | | $ | 138,460 | |
2003B Series - 5.10% | | 2031 | | | 23,400 | | | 23,400 | |
| Total | | | | | $ | 161,860 | | $ | 161,860 | |
CONSERVATION TRUST FINANCINGS
In October 2004, the 6.45% Conservation Trust Bonds matured. PSE originally consolidated the 1995 Conservation Trust Bonds when FIN 46 went into effect in July 2003. The balance at December 31, 2003 was $4.2 million.
LONG-TERM REVOLVING CREDIT FACILITY (PUGET ENERGY ONLY)
Puget Energy has a $15.0 million revolving credit facility available through a bank. At December 31, 2004, there was $5.0 million outstanding at a weighted average interest rate of 3.07%, leaving $10.0 million available under the facility. On February 1, 2005, Puget Energy reduced the borrowing capacity under this credit facility to $5.0 million.
InfrastruX and its subsidiaries have signed credit agreements with several banks for up to $186.7 million, which expire at various dates from 2005 to 2007. Under the InfrastruX credit agreement, Puget Energy is the guarantor of $150.0 million of the line of credit. InfrastruX has borrowed $143.1 million at a weighted average interest rate of 2.96%, leaving a balance of $43.6 million available under the lines of credit at December 31, 2004. InfrastruX also has $18.4 million in equipment financing agreements with various vendors. These agreements mature at various dates from 2005 to 2009 and carry interest rates up to 7.45%.
LONG-TERM DEBT MATURITIESLong-Term Debt Maturities
The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:
PUGET ENERGY (DOLLARS IN THOUSANDS) | 2005 | 2006 | 2007 | 2008 | 2009 | THEREAFTER |
| Maturities of: | | | | | | |
| Long-term debt | $ 38,933 | $ 292,276 | $ 259,866 | $ 181,089 | $ 158,441 | $ 1,320,860 |
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | 2005 | 2006 | 2007 | 2008 | 2009 | THEREAFTER | |
Puget Energy and Puget Sound Energy (Dollars in Thousands) | | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | Thereafter | |
| Maturities of: | | | | | | | | | | | | | | |
| Long-term debt | $ 31,000 | $ 281,000 | $ 125,000 | $ 179,500 | $ 158,000 | $ 1,320,860 | | $ | 125,000 | | $ | 179,500 | | $ | 158,000 | | $ | 232,000 | | $ | 260,000 | | $ | 1,778,860 | |
NOTE 9.Related Party Transactions
During 2006, Puget Energy established the Puget Sound Energy Foundation to aid qualifying nonprofit organizations that help support initiatives that back economic and environmental sustainability with a $15.0 million contribution to the Foundation from a portion of the proceeds from the sale of InfrastruX. The contribution was recorded as other income (deduction) expense. The Puget Sound Energy Foundation was established by Puget Energy as a nonprofit organization whose results are not consolidated by Puget Energy.
On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE may borrow up to $30.0 million from Puget Energy, subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted average interest rate of (a) PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) the interest rate available under the receivable securitization facility of PSE Funding, Inc., a PSE subsidiary, which is the London Interbank Offered Rate (LIBOR) rate plus a marginal rate. At December 31, 2006, the outstanding balance of the Note was $24.3 million and the interest rate was 5.54%. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.
NOTE 10. Liquidity Facilities and Other Financing Arrangements
At December 31, 2004,2006, PSE had short-term borrowing arrangements that included a $350five-year $500.0 million unsecured line of credit agreement with a group of banks and a $150five-year $200.0 million receivables securitization program. These arrangements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The line ofbank credit agreement allows the Company to make floating rate advances at either LIBOR plus a spread or the banks’ prime rate and Eurodollar advances at LIBOR plus a spread, and contains “credit sensitive” pricing with various spreads associated with various credit rating levels. The line ofbank credit agreement also allows for issuing standby letters of credit up to the entire lineamount of the credit agreement. In April 2006, PSE amended this credit agreement amount. The line of credit agreement expires in June 2007.to extend the expiration date from April 2010 to April 2011.
On December 20, 2005, PSE has entered into a Receivablesfive-year Receivable Sales Agreement with Rainier Receivables, Inc.,PSE Funding, a wholly owned subsidiary of PSE, inreplacing the Rainier Receivables securitization facility that was terminated on December 2002.20, 2005. Pursuant to the Receivables Sales Agreement, PSE sells all of its utility customer accounts receivable and unbilled utility revenues to Rainier Receivables.PSE Funding. In addition, Rainier ReceivablesPSE Funding entered into a Receivables PurchaseLoan and Servicing Agreement with PSE and a third party.two banks. The Receivables PurchaseLoan and Servicing Agreement allows Rainier ReceivablesPSE Funding to selluse the receivables purchased from PSEas collateral to secure short-term loans, not exceeding the third party. The amountlesser of receivables sold by Rainier Receivables is not permitted to exceed $150$200.0 million at any time. However,or the maximum amount may be less than $150 million depending on theborrowing base of eligible outstanding amount of PSE’s receivables which fluctuate with the seasonality of energy sales to customers.
The receivables securitization facility is the functional equivalent of a secured revolving line of credit. In the event Rainier Receivables elects to sell receivables under the Receivables Purchase Agreement, Rainier Receivables is required to pay the purchasers fees that are comparable to interest rates on a revolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables purchased by the purchasers declines until Rainier Receivables elects to sell additional receivables to the purchasers.
TheFunding receivables securitization facility expires in December 2005, but2010, and is terminable by PSE and Rainier ReceivablesPSE Funding upon notice to the receivables purchasers.banks. During the year ended2006, PSE Funding borrowed a cumulative amount of $441.0 million secured by accounts receivable and had $110.0 million of loans secured by accounts receivable pledged as collateral at December 31, 2006. During 2005 and 2004, Rainier Receivables had sold a cumulative amount of $351.9 million and $600.2 million in accounts receivable, andrespectively. At December 31, 2005, PSE Funding had $150.0$41.0 million of loans secured by accounts receivable sold under the program at December 31, 2004. There were no additional amounts available to be sold under the program at December 31, 2004. During the year ended December 31, 2003, Rainier Receivables had sold a cumulative amount of $348.0 million in accounts receivable and had $111.0 million sold under the program at December 31, 2003.pledged as collateral.
In addition, PSE has agreements with certain banks to borrow on an uncommitted, as available, basis at money market rates quoted by the banks. There are no costs, other than interest, for these arrangements. PSE also uses commercial paper to fund its short-term borrowing requirements. The following table presents the liquidity facilities and other financing arrangements at December 31, 20042006 and 2003.2005.
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | | 2004 | | 2003 | |
| Short-term borrowings outstanding: | | | | | | | |
| InfrastruX bank line of credit borrowings | | $ | 8,297 | | $ | 13,893 | |
| Weighted average interest rate | | | 2.47 | % | | 2.59 | % |
| Financing arrangements: | | | | | | | |
Puget Energy line of credit1 | | $ | 15,000 | | $ | 15,000 | |
InfrastruX revolving credit facilities2 | | | 186,725 | | | 184,725 | |
PSE line of credit3 | | | 350,000 | | | 250,000 | |
PSE receivables securitization program4 | | | 150,000 | | | 150,000 | |
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Committed financing arrangements: | | | | | |
PSE line of credit 1 | | $ | 500,000 | | $ | 500,000 | |
PSE receivables securitization program 2 | | | 200,000 | | | 200,000 | |
| Uncommitted financing agreements: | | | | | | | |
PSE Unsecured Credit Agreement 3 | | | -- | | | 20,000 | |
Puget Energy Demand Promissory Note 4 | | | 30,000 | | | -- | |
__________________________________
1 | Includes $5.0 million outstanding at December 31, 2004, leaving $10.0 million available under the agreement. On February 1, 2005, Puget Energy reduced the capacity to $5.0 million.
|
2 | The revolving credit facility requires InfrastruX and its subsidiaries to maintain certain financial covenants, including requirements to maintain certain levels of net worth and debt coverage. The agreement also places certain restrictions on expenditures, other indebtedness and executive compensation. For 2004 and 2003, InfrastruX had $143.1 million and $155.6 million outstanding under the credit facilities, effectively reducing available borrowing capacity to $43.6 million and $29.1 million, respectively.
|
3 | Provides liquidity support for PSE’s outstanding commercial paper and letters of credit in the amount of $218.5 million in 2006 and $0.5 million in 2004 and 2003,2005, effectively reducing the available borrowing capacity under thesethis credit linesline to $349.5$281.5 million and $249.5$499.5 million, respectively. There was $218.0 million of commercial paper outstanding at December 31, 2006 and no commercial paper outstanding at December 31, 2004 and 2003.2005. |
4 2
| Provides liquidity support for PSE’s outstanding letters of credit and commercial paper. At December 31, 2004,2006, PSE Funding had sold $150.0borrowed $110.0 million, in receivables, leaving no amounts$90.0 million available to borrow under the receivables securitization program. At December 31, 2003,2005, PSE Funding had sold $111.0$41.0 million of loans secured by accounts receivable pledged as collateral under the accounts receivable securitization program. |
3 | An uncommitted, unsecured credit agreement with a bank to borrow at terms that varied with market conditions and the length of the loan. The agreement was terminated and no longer in receivables.effect at December 31, 2006. |
4 | PSE has a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30 million subject to approval by Puget Energy. At December 31, 2006, the outstanding balance on the note was $24.3 million. The outstanding balance and related interest are eliminated on Puget Energy’s balance sheet upon consolidation. |
NOTE 10.11. Estimated Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 20042006 and 2003.2005.
| | | 2004 | | 2003 | | | 2006 | | 2005 | |
(DOLLARS IN MILLIONS) | | CARRYING AMOUNT | | FAIR VALUE | | CARRYING AMOUNT | | FAIR VALUE | | |
| (Dollars in millions) | | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| Financial assets: | | | | | | | | | | | | | | | | | | |
| Cash | | $ | 19.8 | | $ | 19.8 | | $ | 27.5 | | $ | 27.5 | | | $ | 28.1 | | $ | 28.1 | | $ | 16.7 | | $ | 16.7 | |
| Restricted cash | | | 1.6 | | | 1.6 | | | 2.5 | | | 2.5 | | | | 0.8 | | | 0.8 | | | 1.0 | | | 1.0 | |
| Equity securities | | | 1.9 | | | 1.9 | | | 3.6 | | | 3.6 | | | | 2.0 | | | 2.0 | | | 2.0 | | | 2.0 | |
| Notes receivable and other | | | 71.4 | | | 71.4 | | | 63.6 | | | 63.6 | | | | 71.1 | | | 71.1 | | | 72.9 | | | 72.9 | |
| Energy derivatives | | | 21.9 | | | 21.9 | | | 16.2 | | | 16.2 | | | | 23.8 | | | 23.8 | | | 103.5 | | | 103.5 | |
| Long-term restricted cash | | | | 3.8 | | | 3.8 | | | -- | | | -- | |
| Financial liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Short-term debt | | $ | 8.3 | | $ | 8.3 | | $ | 13.9 | | $ | 13.9 | | | $ | 328.0 | | $ | 328.0 | | $ | 41.0 | | $ | 41.0 | |
Short-term debt owed by PSE to Puget Energy1 | | | | 24.3 | | | 24.3 | | | -- | | | -- | |
| Preferred stock subject to mandatory redemption | | | 1.9 | | | 1.9 | | | 1.9 | | | 1.9 | | | | 1.9 | | | 1.3 | | | 1.9 | | | 1.4 | |
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 280.3 | | | 290.9 | | | 280.3 | | | 304.6 | | | | 37.8 | | | 43.2 | | | 237.8 | | | 247.5 | |
Long-term debt- fixed-rate1 | | | 2,051.4 | | | 2,194.8 | | | 2,216.3 | | | 2,409.6 | | |
Long-term debt- variable-rate1 | | | 200.0 | | | 199.9 | | | -- | | | -- | | |
Long-term debt - fixed-rate2 | | | | 2,733.4 | | | 2,823.3 | | | 2,264.4 | | | 2,416.6 | |
| Energy derivatives | | | 19.5 | | | 19.5 | | | 3.6 | | | 3.6 | | | | 71.0 | | | 71.0 | | | 9.8 | | | 9.8 | |
___________________________________
1 | PSE’s carrying value and fair valueShort-term debt owed by PSE to Puget Energy is eliminated upon consolidation of both fixed-rate and variable-rate long-term debt in 2004 was $2,095.4 million and $2,238.7 million, respectively. Puget Energy.
|
2 | PSE’s carrying value and fair value of fixed-rate long-term debt was the same as Puget Energy’s debt in 2003 was $2,053.0 million2006 and $2,250.4 million, respectively.2005. |
The carrying amount of equity securities is considered to be a reasonable estimate of fair value.value due to limited market pricing and based on the market value as reported by the fund manager. The fair value of outstanding bonds including current maturities is estimated based on quoted market prices. The fair value of the preferred stock subject to mandatory redemption is estimated based on dealer quotes. The fair value of the junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities is estimated based on dealer quotes. The carrying values of short-term debt and notes receivable are considered to be a reasonable estimate of fair value. The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of fair value.
Derivative instruments have been used by the Company on a limited basis and are recorded at fair value. The Company has a policy that financial derivatives are to be used only to mitigate business risk.
In 2003, PSE redeemed the 7.75% mandatorily redeemable preferred stock. 75,000 shares were redeemed in February 2003 at the par value of $100 per share and the remaining 337,500 shares were redeemed in August 2003 at $102.07 per share. Also in 2003, 19,750 shares of the 8.231% Capital Trust I preferred stock were redeemed at $990 per share, leaving 80,250 shares still outstanding. There was no preferred stock redeemed in 2004.
NOTE 11.Leases
AllThe Company leases buildings and assets under operating leases. In October 2006, the Company entered into an agreement to purchase certain assets at the Whitehorn generating site, which historically had been leased under an operating lease. The purchase agreement resulted in the classification of PSE’s leases are operating leases.the Whitehorn lease as a capital lease. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the amortization of the leased asset has been modified so that total interest and amortization is equal to the rental expense allowed for rate-making purposes. Interest accretion for 2006 was immaterial and capital lease amortization was $0.4 million for 2006. Certain leases contain purchase options and renewal and escalation provisions. Operating and capital lease paymentsRent expense net of sublease receipts were:
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE |
| AT DECEMBER 31 | OPERATING | CAPITAL | OPERATING |
| 2004 | $ 25,751 | $ 2,086 | $ 17,618 |
| 2003 | 26,842 | 2,696 | 19,301 |
| 2002 | 26,386 | 2,486 | 20,176 |
| (Dollars in Thousands) |
| At December 31 |
| 2006 | | $ | 24,184 | |
| 2005 | | | 17,145 | |
| 2004 | | | 17,618 | |
Payments received for the subleases of properties were approximately $0.1 million, $1.4$0.1 million and $2.6$0.1 million for the years ended December 31,2006, 2005 and 2004, 2003 and 2002, respectively.
Future minimum lease payments for non-cancelable leases net of sublease receipts are:
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | |
| AT DECEMBER 31 | OPERATING | CAPITAL | OPERATING | |
| 2005 | $ 19,311 | $ 1,988 | $ 12,791 | |
| 2006 | 19,804 | 2,057 | 16,034 | |
| (Dollars in Thousands) | | | | | | |
| At December 31 | | | Operating | | Capital | |
| 2007 | 17,500 | 1,558 | 15,524 | | $ | 13,834 | | $ | 1,605 | |
| 2008 | 15,174 | 1,032 | 14,496 | | | 13,976 | | | 1,605 | |
| 2009 | 11,591 | 343 | 11,459 | | | 12,600 | | | 23,453 | |
| 2010 | | | | 11,237 | | | -- | |
| 2011 | | | | 10,996 | | | -- | |
| Thereafter | 46,140 | -- | 46,045 | | | 36,239 | | | -- | |
| Total minimum lease payments | $ 129,520 | $ 6,978 | $ 116,349 | | $ | 98,882 | | $ | 26,663 | |
PSE leases a portion of its owned gas transmission pipeline infrastructure under a non-cancelable operating lease to a third party. The lease expires in 2009. Future minimum lease payments to be received by PSE under this lease are:
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2005 | 2006 | 2007 | 2008 | 2009 | |
(Dollars in Thousands) At December 31 | | | 2007 | | 2008 | | 2009 | |
| Lease receipts | $ 1,182 | $ 985 | | $ | 1,182 | | $ | 1,182 | | $ | 886 | |
In 2004, Puget Energy acquired $2.1 million in assets under capital leases, which is a non-cash investing activity for the Statement of Cash Flows for Puget Energy.
The details of income taxes on continuing operations are as follows:
PUGET ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | | |
| Puget Energy | | | | | | | | |
| (Dollars In Thousands) | | | 2006 | | 2005 | | 2004 | |
| Charged to operating expense: | | | | | | | | | | | | | | |
Current- federal | | $ | 7,607 | | $ | 18,119 | | $ | (84,149 | ) | |
Current- state | | | 75 | | | (2,046 | ) | | (774 | ) | |
| Deferred -federal | | | 70,522 | | | 56,004 | | | 144,230 | | |
Deferred- state | | | (2,647 | ) | | 927 | | | 614 | | |
| Current: | | | | | | | | |
| Federal | | | $ | 62,122 | | $ | 145,342 | | $ | 5,506 | |
| State | | | | 979 | | | 1,936 | | | (21 | ) |
| Deferred - federal | | | | 33,673 | | | (58,116 | ) | | 71,864 | |
| Deferred investment tax credits | | | (593 | ) | | (635 | ) | | (661 | ) | | | (503 | ) | | (553 | ) | | (593 | ) |
| Total charged to operations | | | 74,964 | | | 72,369 | | | 59,260 | | | | 96,271 | | | 88,609 | | | 76,756 | |
| Charged to miscellaneous income: | | | | | | | | | | | | | | | | | | | | |
| Current | | | (5,344 | ) | | (288 | ) | | (3,276 | ) | | | (4,596 | ) | | (3,338 | ) | | (5,305 | ) |
| Deferred | | | 2,470 | | | (1,805 | ) | | 1,228 | | | | 812 | | | 769 | | | 2,470 | |
| Total charged to miscellaneous income | | | (2,874 | ) | | (2,093 | ) | | (2,048 | ) | | | (3,784 | ) | | (2,569 | ) | | (2,835 | ) |
| Cumulative effect of accounting change | | | -- | | | (91 | ) | | -- | | | | 48 | | | (38 | ) | | -- | |
| Total income taxes | | $ | 72,090 | | $ | 70,185 | | $ | 57,212 | | | $ | 92,535 | | $ | 86,002 | | $ | 73,921 | |
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | | |
| Puget Sound Energy | | | | | | | | |
| (Dollars In Thousands) | | | 2006 | | 2005 | | 2004 | |
| Charged to operating expense: | | | | | | | | | | | | | | |
Current- federal | | $ | 5,825 | | $ | 22,154 | | $ | (81,839 | ) | |
Current- state | | | (21 | ) | | (1,460 | ) | | (548 | ) | |
| Deferred -federal | | | 71,966 | | | 50,880 | | | 135,884 | | |
Deferred- state | | | -- | | | -- | | | -- | | |
| Current: | | | | | | | | |
| Federal | | | $ | 62,825 | | $ | 146,110 | | $ | 5,825 | |
| State | | | | 979 | | | 1,936 | | | (21 | ) |
| Deferred - federal | | | | 33,926 | | | (57,864 | ) | | 71,966 | |
| Deferred investment tax credits | | | (593 | ) | | (635 | ) | | (661 | ) | | | (503 | ) | | (553 | ) | | (593 | ) |
| Total charged to operations | | | 77,177 | | | 70,939 | | | 52,836 | | | | 97,227 | | | 89,629 | | | 77,177 | |
| Charged to miscellaneous income: | | | | | | | | | | | | | | | | | | | | |
| Current | | | (5,306 | ) | | (276 | ) | | (3,406 | ) | | | 650 | | | (3,338 | ) | | (5,305 | ) |
| Deferred | | | 2,470 | | | (1,805 | ) | | 1,228 | | | | 812 | | | 769 | | | 2,470 | |
| Total charged to miscellaneous income | | | (2,836 | ) | | (2,081 | ) | | (2,178 | ) | | | 1,462 | | | (2,569 | ) | | (2,835 | ) |
| Cumulative effect of accounting change | | | -- | | | (91 | ) | | -- | | | | 48 | | | (38 | ) | | -- | |
| Total income taxes | | $ | 74,341 | | $ | 68,767 | | $ | 50,658 | | | $ | 98,737 | | $ | 87,022 | | $ | 74,342 | |
The following is a reconciliation of the difference between the amount of income taxes computed by multiplyingcompares pre-tax book income byat the federal statutory rate of 35% to the actual income tax rate and the amount of income taxesexpense in the Consolidated Statements of Income for the Company:Income:
PUGET ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | |
| Income taxes at the statutory rate | | $ | 42,016 | | $ | 65,295 | | $ | 58,846 | |
| Increase (decrease): | | | | | | | | | | |
| Depreciation expense deducted in the financial statements in excess of tax depreciation, net of depreciation treated as a temporary difference | | | 10,723 | | | 9,130 | | | 10,041 | |
| AFUDC included in income in the financial statements but excluded from taxable income | | | (2,270 | ) | | (1,809 | ) | | (1,387 | ) |
| Accelerated benefit on early retirement of depreciable assets | | | (1,297 | ) | | (1,879 | ) | | (1,469 | ) |
| Investment tax credit amortization | | | (593 | ) | | (635 | ) | | (661 | ) |
| Energy Efficiency expenditures - net | | | (134 | ) | | 8,096 | | | 6,259 | |
| Tax benefit of reduced salvage values | | | -- | | | -- | | | (10,193 | ) |
| IRS issue resolution | | | -- | | | (6,209 | ) | | -- | |
| Goodwill impairment | | | 10,276 | | | -- | | | -- | |
| Valuation allowance | | | 17,988 | | | -- | | | -- | |
| Preferred stock dividends of subsidiary | | | -- | | | 1,803 | | | 2,741 | |
| Sate income taxes net of the federal income tax benefit | | | (2,566 | ) | | (877 | ) | | (104 | ) |
| Other - net | | | (2,053 | ) | | (2,730 | ) | | (6,861 | ) |
| Total income taxes | | $ | 72,090 | | $ | 70,185 | | $ | 57,212 | |
| Effective tax rate | | | 62.2 | % | | 37.6 | % | | 34.0 | % |
| Puget Energy | | | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | | 2004 | |
| Income taxes at the statutory rate | | $ | 90,947 | | $ | 81,275 | | $ | 69,766 | |
| Increase (decrease): | | | | | | | | | | |
| Utility plant depreciation differences | | | 9,307 | | | 9,534 | | | 10,723 | |
| AFUDC excluded from taxable income | | | (7,987 | ) | | (4,536 | ) | | (2,270 | ) |
| Capitalized Interest | | | 5,806 | | | 3,026 | | | 1,471 | |
| Production Tax Credit | | | (7,019 | ) | | (564 | ) | | -- | |
| Other - net | | | 1,481 | | | (2,733 | ) | | (5,769 | ) |
| Total income taxes | | $ | 92,535 | | $ | 86,002 | | $ | 73,921 | |
| Effective tax rate | | | 35.6 | % | | 37.0 | % | | 37.1 | % |
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | |
| Income taxes at the statutory rate | | $ | 70,187 | | $ | 66,028 | | $ | 55,862 | |
| Increase (decrease): | | | | | | | | | | |
Depreciation expense deducted in the financial statements in excess of tax depreciation, net of depreciation treated as a temporary difference | | | 10,723 | | | 9,130 | | | 10,041 | |
AFUDC included in income in the financial statements but excluded from taxable income | | | (2,270 | ) | | (1,809 | ) | | (1,387 | ) |
| Accelerated benefit on early retirement of depreciable assets | | | (1,297 | ) | | (1,879 | ) | | (1,469 | ) |
| Investment tax credit amortization | | | (593 | ) | | (635 | ) | | (661 | ) |
| Energy Efficiency expenditures - net | | | (134 | ) | | 8,096 | | | 6,259 | |
| Tax benefit of reduced salvage values | | | -- | | | -- | | | (10,193 | ) |
| IRS issue resolution | | | -- | | | (6,209 | ) | | -- | |
| Sate income taxes net of the federal income tax benefit | | | (14 | ) | | (949 | ) | | (356 | ) |
| Other - net | | | (2,261 | ) | | (3,006 | ) | | (7,438 | ) |
| Total income taxes | | $ | 74,341 | | $ | 68,767 | | $ | 50,658 | |
| Effective tax rate | | | 37.1 | % | | 36.5 | % | | 31.7 | % |
| Puget Sound Energy | | | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | | 2004 | |
| Income taxes at the statutory rate | | $ | 96,417 | | $ | 81,827 | | $ | 70,187 | |
| Increase (decrease): | | | | | | | | | | |
| Utility plant depreciation differences | | | 9,307 | | | 9,534 | | | 10,723 | |
| AFUDC excluded from taxable income | | | (7,987 | ) | | (4,536 | ) | | (2,270 | ) |
| Capitalized interest | | | 5,806 | | | 3,026 | | | 1,471 | |
| Production Tax Credit | | | (7,019 | ) | | (564 | ) | | -- | |
| Other - net | | | 2,213 | | | (2,265 | ) | | (5,769 | ) |
| Total income taxes | | $ | 98,737 | | $ | 87,022 | | $ | 74,342 | |
| Effective tax rate | | | 35.8 | % | | 37.2 | % | | 37.1 | % |
The Company’s deferred tax liability at December 31, 2004, 20032006, 2005 and 20022004 is composed of amounts related to the following types of temporary differences:
PUGET ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | |
| Plant and equipment | | $ | 665,407 | | $ | 622,462 | | $ | 588,182 | |
| Capitalized overhead costs | | | 72,448 | | | 70,834 | | | 72,220 | |
| Software amortization | | | 37,484 | | | 41,044 | | | 41,408 | |
| Pensions and compensation | | | 15,367 | | | 16,890 | | | 29,099 | |
| Bonneville Exchange Power | | | 14,078 | | | 15,204 | | | 15,537 | |
| Energy Efficiency charges | | | 10,320 | | | 9,446 | | | 16,473 | |
| Other deferred tax liabilities | | | 68,587 | | | 68,351 | | | 46,655 | |
| Subtotal deferred tax liabilities | | | 883,691 | | | 844,231 | | | 809,574 | |
| Contributions in aid of construction | | | (41,525 | ) | | (46,520 | ) | | (44,770 | ) |
| Goodwill | | | (18,683 | ) | | 4,192 | | | 2,106 | |
| Other deferred tax assets | | | (30,745 | ) | | (46,668 | ) | | (36,235 | ) |
| Subtotal deferred tax assets | | | (90,953 | ) | | (88,996 | ) | | (78,899 | ) |
| Valuation allowance | | | 17,988 | | | -- | | | -- | |
| Subtotal net deferred tax assets | | | (72,965 | ) | | (88,996 | ) | | (78,899 | ) |
| Total | | $ | 810,726 | | $ | 755,235 | | $ | 730,675 | |
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | | |
| Plant and equipment | | $ | 645,826 | | $ | 607,203 | | $ | 578,137 | | |
| Puget Energy | | | | | | |
| (Dollars In Thousands) | | | 2006 | | 2005 | |
| Utility plant and equipment | | | $ | 736,368 | | $ | 700,415 | |
| Capitalized overhead costs | | | 72,448 | | | 70,834 | | | 72,220 | | | | -- | | | 33,166 | |
| Software amortization | | | 37,484 | | | 41,044 | | | 41,408 | | |
| Pensions and compensation | | | 15,367 | | | 16,890 | | | 29,099 | | |
| Bonneville Exchange Power | | | 14,078 | | | 15,204 | | | 15,537 | | |
| Energy Efficiency charges | | | 10,320 | | | 9,446 | | | 16,473 | | |
| Other deferred tax liabilities | | | 63,926 | | | 64,511 | | | 43,710 | | | | 96,486 | | | 97,197 | |
| Subtotal deferred tax liabilities | | | 859,449 | | | 825,132 | | | 796,584 | | | | 832,854 | | | 830,778 | |
| Contributions in aid of construction | | | (41,525 | ) | | (46,520 | ) | | (44,770 | ) | | | (58,038 | ) | | (49,171 | ) |
| Other deferred tax assets | | | (30,745 | ) | | (46,668 | ) | | (36,235 | ) | | | (30,896 | ) | | (31,830 | ) |
| Subtotal deferred tax assets | | | (72,270 | ) | | (93,188 | ) | | (81,005 | ) | | | (88,934 | ) | | (81,001 | ) |
| Total | | $ | 787,179 | | $ | 731,944 | | $ | 715,579 | | | $ | 743,920 | | $ | 749,777 | |
Deferred taxThe above amounts shown above result from temporary differences for tax and financial statement purposes. Deferred tax provisions are not recordedhave been classified in the income statement for certain temporary differences between tax and financial statement purposes because they are not allowed for ratemaking purposes.Consolidated Balance Sheets as follows:
| Puget Energy | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | |
| Current deferred taxes | | $ | (1,175 | ) | $ | 10,968 | |
| Non-current deferred taxes | | | 745,095 | | | 738,809 | |
| Total | | $ | 743,920 | | $ | 749,777 | |
| Puget Sound Energy | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | |
| Utility plant and equipment | | $ | 736,368 | | $ | 700,415 | |
| Capitalized overhead costs | | | -- | | | 33,166 | |
| Other deferred tax liabilities | | | 100,425 | | | 97,550 | |
| Subtotal deferred tax liabilities | | | 836,793 | | | 831,131 | |
| Contributions in aid of construction | | | (58,038 | ) | | (49,171 | ) |
| Other deferred tax assets | | | (30,897 | ) | | (31,830 | ) |
| Subtotal deferred tax assets | | | (88,935 | ) | | (81,001 | ) |
| Total | | $ | 747,858 | | $ | 750,130 | |
The above amounts have been classified in the Consolidated Balance Sheets as follows:
| Puget Sound Energy | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | |
| Current deferred taxes | | $ | (1,175 | ) | $ | 10,968 | |
| Non-current deferred taxes | | | 749,033 | | | 739,162 | |
| Total | | $ | 747,858 | | $ | 750,130 | |
The Company calculates its deferred tax assets and liabilities under SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires recording deferred tax balances, at the currently enacted tax rate, for all temporary differences between the book and tax bases ofon assets and liabilities including temporary differencesthat are reported differently for which noincome tax purposes than for financial reporting purposes. For ratemaking purposes, deferred taxes had been previouslyare not provided because of use of flow-through tax accounting for ratemaking purposes.certain temporary differences. Because of prior and expected future ratemaking treatment for temporary differences for which flow-through tax accounting has been utilized, PSE has established a regulatory asset for income taxes recoverable through future rates related to those differences has also been established by PSE. At December 31, 2004, thedifferences. The balance of this asset was $127.3 million.
Puget Energy’s management has determined that a portion of the deferred tax asset related to InfrastruX goodwill impairment will not be realized and has provided a valuation allowance of $18.0$115.3 million at December 31, 20042006 and $129.7 million at December 31, 2005.
IRS Audit
As a matter of course, the Company’s tax returns are routinely audited by federal, state and city tax authorities. In May of 2006, the IRS completed its examination of the company’s 2001, 2002 and 2003 federal income tax returns. The Company is formally appealing two IRS audit adjustments. The first adjustment relates to reducethe receivable balance due from the California Independent System Operator (CAISO). The IRS claims that the deduction was not valid for the 2003 tax year and would require repayment of approximately $14.5 million in tax. Management of Puget Energy believes the deduction is valid and intends to vigorously defend the deduction. Any potential tax payment (excluding interest) would have no impact on earnings, as it would be recognized as a deferred tax asset. If the Company is unsuccessful, a charge for interest expense would apply.
The second IRS audit adjustment relates to the company’s accounting method with respect to capitalized internal labor and overheads. In its 2001 tax return, PSE claimed a deduction when it changed its tax accounting method with respect to capitalized internal labor and overheads. Under the new method, the Company could immediately deduct certain costs that it had previously capitalized. In the audit, the IRS disallowed the deduction. On August 2, 2005, the Internal Revenue Service and the Treasury Department issued Revenue Ruling 2005-53 and related Regulations. The Revenue Ruling and the Regulations required utility companies, including PSE, to adopt a less advantageous method of accounting and to repay the accumulated tax benefits. Through September 30, 2005, the Company claimed $66.3 million in accumulated tax benefits. PSE accounted for the accumulated tax benefits as temporary differences in determining its deferred income tax balances. Consequently, the repayment of the tax benefits did not impact earnings but did have a cash flow impact of $33.2 million in the fourth quarter 2005 and $33.1 million in 2006. As of December 31, 2006, the full tax benefit had been repaid. There is some uncertainty in the new guidance. PSE believes that the new Regulations required the Company to repay the accumulated tax benefits over the 2005 and 2006 tax years and that the tax deductions claimed on the Company’s tax returns were appropriate based on the applicable statutes, Regulations, and case law in effect at the time. However, there is no assurance that PSE’s appeal will prevail. If the Company is unsuccessful, a charge for interest expense would apply.
On October 19, 2005, PSE filed an accounting petition with the Washington Commission to defer the capital costs associated with repayment of the deferred tax. The Washington Commission had reduced PSE’s ratebase by $72 million in its order of February 18, 2005. The accounting petition was approved by the Washington Commission on October 26, 2005, for deferral of additional capital costs beginning November 1, 2005 using PSE’s allowed net of tax assetrate of return. The Washington Commission granted amortization of these deferred carrying costs over two years, beginning January 13, 2007.
Accounting for Uncertainty in Income Taxes
In July 2006, FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to itsbe taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing authority. Second, a tax position, that meets the recognition threshold, should be measured at the largest amount that has a greater than 50% likelihood of being sustained.
FIN 48 was effective for the Company as of January 1, 2007. The change in net assets as a result of adopting FIN 48 will be treated as a change in accounting method. The cumulative effect of the change will be recorded to retained earnings. Adjustments to regulatory accounts, if any, will be based on other applicable accounting standards. The Company is currently in the process of evaluating the provisions of FIN 48 to determine the potential impact, if any, the adoption will have on the Company’s financial statements. The adoption of FIN 48 is not expected to have a material impact on the Company’s retained earnings. Management’s estimated realizable value.impact of adoption is subject to change due to potential changes in interpretation of FIN 48 by the FASB or other regulatory bodies and the finalization of the Company’s adoption efforts.
On September 29, 2006, FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” SFAS No. 158 is effective for fiscal years ending after December 15, 2006, which is the year ended December 31, 2006 for the Company. SFAS No. 158 was adopted prospectively as required by the statement. SFAS No. 158 requires the Company to report the overfunded or underfunded status of defined benefit postretirement plans in the Company’s consolidated balance sheet. An overfunded status would result in the recognition of an asset and an underfunded status would result in the recognition of a liability. This amount is to be measured as the difference between the fair value of plan assets and the projected benefit obligation.
The Company has a defined benefit pension plan with a cash balance feature covering substantially all PSE employees. Benefits are a function of age, salary and service. Additionally Puget Energy also maintains a non-qualified supplemental retirement plan for officers and certain director-level employees. The annual measurement date is December 31 of each year.
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. These benefits are provided principally through an insurance company whose premiums are based on the benefits paid during the year.
| | | PENSION BENEFITS | | OTHER BENEFITS | |
| (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2004 | | 2003 | |
Change in benefit obligation: | | | | | | | | | |
| Benefit obligation at beginning of year | | $ | 400,041 | | $ | 369,692 | | $ | 29,220 | | $ | 31,693 | |
| Service cost | | | 10,343 | | | 8,284 | | | 189 | | | 175 | |
| Interest cost | | | 24,082 | | | 24,406 | | | 1,670 | | | 1,828 | |
| Amendments | | | -- | | | 940 | | | -- | | | -- | |
| Actuarial (gain) loss | | | 37,628 | | | 19,354 | | | 963 | | | (2,194 | ) |
| Special recognition of prior service costs | | | -- | | | 190 | | | -- | | | -- | |
| Benefits paid | | | (32,357 | ) | | (22,825 | ) | | (2,050 | ) | | (2,282 | ) |
| Benefit obligation at end of year | | $ | 439,737 | | $ | 400,041 | | $ | 29,992 | | $ | 29,220 | |
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | | | 2006 | | 2005 | |
Change in benefit obligation: | | | | | | | | | |
| Benefit obligation at beginning of year | | | $ | 454,519 | | $ | 438,635 | | $ | 26,251 | | $ | 31,094 | |
| Service cost | | | | 12,554 | | | 11,549 | | | 361 | | | 305 | |
| Interest cost | | | | 24,668 | | | 23,855 | | | 1,522 | | | 1,409 | |
Amendment1 | | | | -- | | | -- | | | -- | | | 359 | |
| Actuarial loss (gain) | | | | 4,774 | | | 3,236 | | | 1,261 | | | (4,796 | ) |
| Benefits paid | | | | (27,505 | ) | | (22,756 | ) | | (2,189 | ) | | (2,120 | ) |
| Benefit obligation at end of year | | | $ | 469,010 | | $ | 454,519 | | $ | 27,206 | | $ | 26,251 | |
_______________1 | The Company has an amendment related to changes in eligibility criteria. |
Change in plan assets: | | | | | | | | | |
| Fair value of plan assets at beginning of year | | $ | 428,586 | | $ | 343,960 | | $ | 15,431 | | $ | 16,160 | |
| Actual return on plan assets | | | 51,395 | | | 79,488 | | | 1,184 | | | 98 | |
| Employer contribution | | | 11,356 | | | 27,963 | | | 1,394 | | | 1,455 | |
| Benefits paid | | | (32,357 | ) | | (22,825 | ) | | (2,050 | ) | | (2,282 | ) |
| Fair value of plan assets at end of year | | $ | 458,980 | | $ | 428,586 | | $ | 15,959 | | $ | 15,431 | |
| Funded status | | $ | 19,243 | | $ | 28,545 | | $ | (14,033 | ) | $ | (13,789 | ) |
| Unrecognized actuarial (gain) loss | | | 72,428 | | | 48,217 | | | (2,019 | ) | | (2,895 | ) |
| Unrecognized prior service cost | | | 12,760 | | | 15,949 | | | 2,403 | | | 2,712 | |
| Unrecognized net initial (asset) obligation | | | (163 | ) | | (1,267 | ) | | 3,365 | | | 3,783 | |
| Net amount recognized | | $ | 104,268 | | $ | 91,444 | | $ | (10,284 | ) | $ | (10,189 | ) |
Amounts recognized on statement of financial position consist of: | | | | | | | | | | | | | |
| Prepaid benefit cost | | $ | 120,748 | | $ | 112,737 | | $ | -- | | $ | -- | |
| Accrued benefit liability | | | (32,042 | ) | | (38,704 | ) | | (10,284 | ) | | (10,189 | ) |
| Intangible asset | | | 7,351 | | | 9,043 | | | -- | | | -- | |
| Accumulated other comprehensive income | | | 8,211 | | | 8,368 | | | -- | | | -- | |
| Net amount recognized | | $ | 104,268 | | $ | 91,444 | | $ | (10,284 | ) | $ | (10,189 | ) |
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2006 | | 2005 | |
Change in plan assets: | | | | | | | | | |
| Fair value of plan assets at beginning of year | | | $ | 481,444 | | $ | 458,980 | | $ | 15,668 | | $ | 15,959 | |
| Actual return on plan assets | | | | 75,278 | | | 43,119 | | | 1,699 | | | 696 | |
| Employer contribution | | | | 3,391 | | | 2,101 | | | 669 | | | 1,133 | |
| Benefits paid | | | | (27,505 | ) | | (22,756 | ) | | (2,189 | ) | | (2,120 | ) |
| Fair value of plan assets at end of year | | | $ | 532,608 | | $ | 481,444 | | $ | 15,847 | | $ | 15,668 | |
| Funded status at end of year | | | $ | 63,598 | | $ | 26,925 | | $ | (11,359 | ) | $ | (10,583 | ) |
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2006 | | 2005 | |
Amounts recognized in Statement of Financial Position consist of: | | | | | | | | | |
| Noncurrent assets | | | $ | 101,708 | | $ | -- | | $ | -- | | $ | -- | |
| Current liabilities | | | | (4,533 | ) | | -- | | | (50 | ) | | -- | |
| Noncurrent liabilities | | | | (33,577 | ) | | -- | | | (11,309 | ) | | -- | |
| Total | | | $ | 63,598 | | $ | -- | | $ | (11,359 | ) | $ | -- | |
Amounts recognized in Accumulated Other Comprehensive Income consist of: | | | | | | | | | | | | | | |
| Net loss (gain) | | | $ | 29,984 | | $ | -- | | $ | (6,341 | ) | $ | -- | |
| Prior service cost / (credit) | | | | 6,452 | | | -- | | | 2,862 | | | -- | |
| Transition obligations / (assets) | | | | -- | | | -- | | | 2,529 | | | -- | |
| Total | | | $ | 36,436 | | $ | -- | | $ | (950 | ) | $ | -- | |
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets and the funded status, measured as the difference between the fair value of plan assets and the benefit obligation for the non-qualified pension plan which has accumulated benefit obligations in excess of plan assets, were $38.9$38.1 million, $31.8none, and $(38.1) million, and none, respectively, as of December 31, 2004.2006. For the qualified pension plan the projected benefit obligation, accumulated benefit obligation and fair value of plan assets and the funded status were $400.9$430.9 million, $380.0$532.6 million and $459.0$101.7 million, respectively, as of December 31, 2004.2006.
The projected benefit obligation, accumulated benefit obligationfair value of plan assets and fair valuethe funded status of plan assets for the non-qualified pension plan, which has accumulated benefit obligations in excess of plan assets, were $45.0$39.2 million, $38.6none, and $(39.2) million, and none, respectively, as of December 31, 2003.2005. For the qualified pension plan, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets, and the funded status were $355.1$415.3 million, $339.7$481.4 million and $428.6$66.1 million, respectively, as of December 31, 2003.2005.
| | | Pension Benefits | | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2004 | |
Components of net periodic benefit cost: | | | | | | | | | | | | | | |
| Service cost | | $ | 12,553 | | $ | 11,549 | | $ | 10,249 | | | $ | 361 | | $ | 305 | | $ | 283 | |
| Interest cost | | | 24,667 | | | 23,855 | | | 24,016 | | | | 1,522 | | | 1,409 | | | 1,736 | |
| Expected return on plan assets | | | (37,572 | ) | | (37,928 | ) | | (39,106 | ) | | | (871 | ) | | (878 | ) | | (858 | ) |
| Amortization of prior service cost | | | 2,341 | | | 2,867 | | | 3,033 | | | | 534 | | | 466 | | | 465 | |
| Amortization of net loss (gain) | | | 5,230 | | | 3,354 | | | 1,221 | | | | (273 | ) | | (612 | ) | | (332 | ) |
| Amortization of transition (asset) obligation | | | -- | | | (163 | ) | | (1,104 | ) | | | 418 | | | 418 | | | 418 | |
| Net periodic benefit cost (income) | | $ | 7,219 | | $ | 3,534 | | $ | (1,691 | ) | | $ | 1,691 | | $ | 1,108 | | $ | 1,712 | |
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2006 | | 2005 | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | |
| (Increase) / decrease during year under SFAS 132R | | | $ | (497 | ) | $ | -- | | $ | -- | | $ | -- | |
| (Increase) / decrease due to adoption of SFAS 158 | | | | 29,647 | | | -- | | | (950 | ) | | -- | |
| Total change in other comprehensive income for year | | | $ | 29,150 | | $ | -- | | $ | (950 | ) | $ | -- | |
| | | Before Application of Statement 158 | | Adjustments | | After Application of Statement 158 | |
| (Dollars in Thousands) | | Pension Plan | | Other Benefits | | Pension Plan | | Other Benefits | | Pension Plan | | Other Benefits | |
Transition Adjustments for Statement of Financial Position: | | | | | | | | | | | | | |
| Prepaid benefit cost | | $ | 122,274 | | $ | -- | | $ | (122,274 | ) | $ | -- | | $ | -- | | $ | -- | |
| Accrued benefit (liability) | | | (33,056 | ) | | (12,309 | ) | | 33,056 | | | 12,309 | | | -- | | | -- | |
| Intangible asset | | | 4,027 | | | -- | | | (4,027 | ) | | -- | | | -- | | | -- | |
| Accumulated other comprehensive income, (pre-tax) | | | 6,789 | | | -- | | | 29,647 | | | (950 | ) | | 36,436 | | | (950 | ) |
| Noncurrent asset | | | -- | | | -- | | | 101,708 | | | -- | | | 101,708 | | | -- | |
| Current liability | | | -- | | | -- | | | (4,533 | ) | | (50 | ) | | (4,533 | ) | | (50 | ) |
| Noncurrent liability | | | -- | | | -- | | | (33,577 | ) | | (11,309 | ) | | (33,577 | ) | | (11,309 | ) |
| Total | | $ | 100,034 | | $ | (12,309 | ) | $ | -- | | $ | -- | | $ | 100,034 | | $ | (12,309 | ) |
The estimated net loss (gain) and prior service cost (credit) for the pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2007 are $4.7 million and $2.0 million, respectively. The estimated net loss (gain), prior service cost (credit) and transition obligation (asset) for the other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2007 are $(0.2) million, $0.5 million and $0.4 million.
In accounting for pension and other benefit obligations and costs under the plans, the following weighted average actuarial assumptions were used:
| | PENSION BENEFITS | | OTHER BENEFITS | | Pension Benefits | | Other Benefits | |
BENEFIT OBLIGATION ASSUMPTIONS | 2004 | 2003 | 2002 | | 2004 | 2003 | 2002 | |
Benefit Obligation Assumptions | | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| Discount rate | 5.60% | 6.25% | 6.75% | | 5.60% | 6.25% | 6.75% | | | 5.80 | % | | 5.60 | % | | 5.60 | % | | 5.80 | % | | 5.60 | % | | 5.60 | % |
| Rate of compensation increase | 4.50% | 4.50% | 4.50% | | -- | | | 4.50 | % | | 4.50 | % | | 4.50 | % | | -- | | -- | | -- | |
| Medical trend rate | -- | -- | | 12.00% | 9.00% | 10.00% | | | -- | | -- | | -- | | | 10.00 | % | | 11.00 | % | | 12.00 | % |
| | | | | |
| | PENSION BENEFITS | | OTHER BENEFITS | |
BENEFIT COST ASUMPTIONS | 2004 | 2003 | 2002 | | 2004 | 2003 | 2002 | |
| Discount rate | 6.25% | 6.75% | 7.25% | | 6.25% | 6.75% | 7.25% | |
| Return on plan assets | 8.25% | 8.25% | 9.25% | | 5-8.25% | 6-7.00% | 6-8.25% | |
| Rate of compensation increase | 4.50% | 4.50% | 4.50% | | -- | |
| Medical trend rate | -- | -- | | 9.00% | 10.00% | 6.50% | |
| | | Pension Benefits | | Other Benefits | |
Benefit Cost Assumptions | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| Discount Rate | | | 5.60 | % | | 5.60 | % | | 6.25 | % | | 5.60 | % | | 5.60 | % | | 6.25 | % |
| Return on plan assets | | | 8.25 | % | | 8.25 | % | | 8.25 | % | | 4.3-8 | % | | 4.3-8 | % | | 4.3-8.25 | % |
| Rate of compensation increase | | | 4.50 | % | | 4.50 | % | | 4.50 | % | | -- | | | -- | | | -- | |
| Medical trend rate | | | -- | | | -- | | | -- | | | 11.00 | % | | 12.00 | % | | 9.00 | % |
The assumed medical inflation rate used to determine benefit obligations is 10.0% in 2007 grading down to 6.0% in 2011. A 1% change in the assumed medical inflation rate would have the following effects:
| | | 2006 | | 2005 | |
| (Dollars in Thousands) | | 1% Increase | | 1% Decrease | | 1% Increase | | 1% Decrease | |
| Effect on post-retirement benefit obligation | | $ | 752 | | $ | (666 | ) | $ | 437 | | $ | (378 | ) |
| Effect on service and interest cost components | | | 42 | | | (38 | ) | | 30 | | | (27 | ) |
The Company has usedselected the expected return on plan assets based on ana historical analysis of rates of return over the past 50 years relevant toand the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors and adjusted accordingly. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is as follows. The market-related value of assets is based on a five-year smoothing of asset gains/losses measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.
| | | PENSION BENEFITS | | OTHER BENEFITS | |
| (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | | 2004 | | 2003 | | 2002 | |
Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 10,343 | | $ | 8,284 | | $ | 8,474 | | $ | 189 | | $ | 175 | | $ | 168 | |
| Interest cost | | | 24,082 | | | 24,406 | | | 25,858 | | | 1,670 | | | 1,828 | | | 1,930 | |
| Expected return on plan assets | | | (39,106 | ) | | (38,880 | ) | | (43,032 | ) | | (858 | ) | | (934 | ) | | (906 | ) |
| Amortization of prior service cost | | | 3,189 | | | 3,220 | | | 2,990 | | | 309 | | | 309 | | | 90 | |
| Recognized net actuarial gain | | | 1,128 | | | (2,688 | ) | | (5,120 | ) | | (239 | ) | | (341 | ) | | (229 | ) |
| Amortization of transition (asset) obligation | | | (1,104 | ) | | (1,104 | ) | | (1,136 | ) | | 418 | | | 418 | | | 470 | |
| Plan curtailment | | | -- | | | -- | | | (1,353 | ) | | -- | | | -- | | | 1,691 | |
| Special recognition of prior service costs | | | -- | | | 190 | | | 1,683 | | | -- | | | -- | | | -- | |
| Net pension benefit cost (income) | | $ | (1,468 | ) | $ | (6,572 | ) | $ | (11,636 | ) | $ | 1,489 | | $ | 1,455 | | $ | 3,214 | |
The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year endedending December 31, 20052007 are $2.0$4.5 million and $1.4$0.3 million, respectively. The full amount of the pension funding for 20052007 is for the Company’s non-qualified supplemental retirement plan.
The fair value of the plan assets of the pension benefits and other benefits are invested as follows at December 31:
| | 2004 | | 2003 | | 2006 | | 2005 | |
| | PENSION BENEFITS | OTHER BENEFITS | | PENSION BENEFITS | OTHER BENEFITS | | Pension Benefits | | Other Benefits | | Pension Benefits | | Other Benefits | |
| Short-term investments and cash | 2.4% | 100.0% | | 3.0% | 100.0% | | | 2.7 | % | | -- | | | 2.4 | % | | 1.9 | % |
| Equity securities | 67.8% | -- | | 63.8% | -- | | | 62.9 | % | | -- | | | 62.3 | % | | -- | |
| Fixed income securities | 18.2% | -- | | 22.9% | -- | | | 14.8 | % | | 13.4 | % | | 15.3 | % | | 17.3 | % |
| Mutual funds (equity and fixed income) | 11.6% | -- | | 10.3% | -- | | | 19.6 | % | | 86.6 | % | | 20.0 | % | | 80.8 | % |
The expected total benefits to be paid under both plans for the next five years and the aggregate total to be paid for the five years thereafter isare as follows:
| (Dollars in Thousands) | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | 2010-2014 |
| Total benefits | $29,768 | | $30,202 | | $31,256 | | $32,904 | | $33,253 | | $180,516 |
The assumed medical inflation rate used to determine benefit obligations is 12.0% in 2005 grading to 6.0% in 2011. A 1% change in the assumed medical inflation rate would have the following effects:
| | 2004 | | 2003 | |
(DOLLARS IN THOUSANDS) | 1% INCREASE | | 1% DECREASE | | 1% INCREASE | | 1% DECREASE | |
| Effect on post-retirement benefit obligation | | $ 552 | | | $ (477 | ) | | $ 589 | | | $ (529 | ) |
| Effect on service and interest cost components | | 31 | | | (28 | ) | | 38 | | | (35 | ) |
| (Dollars in Thousands) | 2007 | 2008 | 2009 | 2010 | 2011 | 2012-2016 |
| Total benefits | $33,797 | $31,578 | $32,817 | $35,350 | $35,028 | $197,315 |
The Company has a Retirement Committee that establishes investment policies, objectives and strategies for the purposedesigned to balance expected return with a prudent level of obtaining the optimum return for the pension benefit plans, while also keeping with the assumption of prudent risk and the Retirement Committee’s total return objectives.risk. All changes to the investment policies are reviewed and approved by the Retirement Committee prior to being implemented.
The Retirement Committee contracts with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Committee has established investment allocation percentages by asset classes as follows:
| | ALLOCATION | | Allocation | |
| ASSET CLASS | MINIMUM | TARGET | MAXIMUM | |
| Asset Class | | | Minimum | Target | Maximum |
| Short-term investments and cash | -- | | -- | | 5% | | | | -- | | | -- | | | 5 | % |
| Equity securities | 40% | | 70% | | 95% | | | | 40 | % | | 70 | % | | 95 | % |
| Fixed-income securities | 20% | | 30% | | 40% | | | | 15 | % | | 30 | % | | 55 | % |
| Real estate | -- | | -- | | 10% | | | | -- | | | -- | | | 10 | % |
On May 19, 2004, FASB issued FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” as the result of the new Medicare Prescription Drug Improvement and Modernization Act which was signed into law in December 2003. The law provides a subsidy for plan sponsors that provide prescription drug benefits to Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based on new Medicare regulations issued in May 2005, the Company determined that it provides benefits at a higher level than provided under Medicare Part D, and therefore would qualify for federal tax subsidies.
The Company has qualified Employee Investment Plans under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options.
Puget Energy’sThe Company’s contributions to the Employee Investment Plans were $7.6$7.9 million, $7.1$6.9 million and $6.9$6.3 million for the years 2004, 20032006, 2005 and 2002, respectively.
PSE’s contributions to the Employee Investment Plan were $6.3 million, $6.1 million and $6.1 million for the years 2004, 2003 and 2002, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.
NOTE 15.16. Stock-based Compensation Plans
ThePrior to 2006, the Company hashad various stockstock-based compensation plans which prior to 2003, were accounted for according to APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company appliesapplied SFAS No. 123 accounting to stock compensation awards granted fromsubsequent to January 1, 2003, on, while grants that were made in years prior to 2003 arecontinued to be accounted for using the intrinsic value method of APB No. 25. TotalEffective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. Results for prior periods have not been restated, as provided for under the modified-prospective method.
The adoption of SFAS No. 123R resulted in a cumulative benefit from an accounting change of $0.1 million, net of tax, for the quarter ended March 31, 2006. The cumulative effect adjustment is the result of the inclusion of estimated forfeitures occurring before award vesting dates in the computation of compensation expense relatedfor unvested awards.
As a result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before income taxes and net income from continuing operations at December 31, 2006, is $0.1 million and $0.1 million higher, respectively, than if it had continued to account for share-based compensation under SFAS No. 123 due to the plans was $4.1 million, $6.4 millioninclusion of estimated forfeitures in compensation cost. There is no difference between basic and $6.3 million in 2004, 2003 and 2002, respectively.diluted earnings per share for income from continuing operations at December 31, 2006 under SFAS No. 123R as compared to earlier methods.
The Company’s shareholder-approved Long-Term Incentive Plan (LTI Plan), established in 1995 after approval by shareholders, encompasses many of the awards granted to employees. Established in 1995 andThe plan was amended and restated in 1997, the2005, and approved by shareholders. The LTI Plan applies to officers and key employees of the Company. AwardsCompany and awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are either purchased on the open market.market or are a new issuance. The 2006 cycle included a grant of restricted stock, which was added to reduce the volatility of the plan. Beginning with the 2004 share grants, plan participants meeting the Company’s stock ownership guidelines can elect to be paid up to 50.0% of the share award in cash. The maximum number of shares that may be purchased or issued as new shares for the LTI Plan is 1,200,000.4,200,000.
PERFORMANCE SHARE GRANTSPerformance Share Grants
Each year theThe Company generally awards performance share grants annually under the LTI Plan. These are granted to key employees and vest at the end of three years for grants made in 2004, 2005 and 2006. Grants made in 2003 vest over a four years for grants made prior to 2004 with the finalyear period. The number of shares awarded and total expense recorded dependingdepends on aPuget Energy’s performance measure. as compared to other companies and service quality indices for customer service.
Compensation expense related to performance share grants was $(1.6) million, $1.0 million and $2.5 million $5.1for 2006, 2005 and 2004, respectively. As of December 31, 2006, $3.0 million of total unrecognized compensation cost, net of forfeitures, related to nonvested performance share grants. That cost is expected to be recognized over a weighted-average period of 1.7 years. A summary of the performance shares activity is as follows:
| Performance shares grants outstanding: | | 2006 | |
| Beginning of Year | | | 907,983 | |
| Granted | | | 152,254 | |
| Vested | | | (40,851 | ) |
| Cancelled* | | | (572,393 | ) |
| Forfeited | | | (68,782 | ) |
| End of Year | | | 378,211 | |
_______________
* | Performance shares at December 31, 2006 were cancelled because performance modifiers were not achieved. |
During 2006 there were four active grant cycles. The two remaining grants outstanding at December 31, 2006 were as follows:
| | | Performance Share Grants Cycles as of December 31, 2006 | |
| Performance share grants cycle: | | 2006 | | 2005 | |
| Number of awards granted | | | 152,254 | | | 251,660 | |
| Estimated forfeiture rate | | | 10.10 | % | | 11.80 | % |
| Estimated forfeited awards | | | 15,378 | | | 29,696 | |
| Weighted average fair value (per share) | | $ | 24.77 | | $ | 21.20 | |
Measurement of Performance Share Grants
The portion of the performance share grants that can be paid in cash is classified and $5.5 millionaccounted for 2004, 2003as a liability under SFAS No. 123R. As a result, the expense recognized over the performance period for a portion of the performance share grants will equal the fair value (i.e. cash value) of the award as of the last day of the performance period times the number of awards that are earned. Furthermore, SFAS No. 123R requires that the quarterly expense recognized during the performance period is based on the fair value of the performance share grants as of the end of the most recent quarter. Prior to the end of the performance period, compensation costs for the liability portion of performance share grants are based on the awards’ most recent quarterly fair values and 2002, respectively.the number of months of service rendered during the performance period. The fair value of the performance awards granted in 2004, 2003 and 2002 was $19.70, $17.29 and $14.82, respectively. There were a total of 272,307 performance awards granted in 2004 of which 16,046 were also forfeited in 2004. In 2003 and 2002 there were 349,912 and 248,158 awards granted, respectively, of which 79,749 and 40,640, respectively, have been forfeited to date. As of December 31, 2004, there are four active grant cycles for a total of 730,786 share grants outstanding although they mayis based on the closing price of the Company’s common stock on the date of measurement. The fair value of the 2006 performance share grants takes into consideration the historical performance of the performance share grants and prospective analysis using the Capital Asset Pricing Model and expected EPS growth rates. Shares granted prior to 2006 were valued using the Black-Scholes option pricing model. A small percentage of the performance share grants are classified as equity awards because the employee does not all be awarded.have the option to receive the payment of these awards in cash. The equity portion is valued at the closing price of the Company’s common stock on the grant date.
STOCK OPTIONSStock Options
In 2002, Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and an additional 260,000 options outside of the LTI Plan (for a total of 300,000 non-qualified stock options) to the presidentChairman, President and chief executive officer.Chief Executive Officer. These options can be exercised at the grant date market price of $22.51 per share and vest yearlyannually over four and five years although vesting is accelerated under certain conditions.the options would become fully vested upon a change of control of the Company or an employment termination without cause. The options expire 10 years from the grant date.date and have a remaining contractual term of approximately 6 years. All 300,000 options remained outstanding at December 31, 2004,2006, with 135,000270,000 options exercisable. At December 31, 2003 and 2002, 67,5002005, 202,500 options and 0 options, respectively, were exercisable. The fair value of the options at the grant date was $3.37$3.33 per share. FollowingCompensation expense related to stock options was immaterial to the intrinsicfinancial statements for 2006. The total fair value method of APB 25, no compensation expensestock options vested during 2006 and 2005 was recorded for these options.$0.2 million and $0.2 million, respectively. The fair value of the stock option award was estimated on the date of grant using the Black-Scholes option valuation model.
RESTRICTED STOCK AND RESTRICTED STOCK UNITSRestricted Stock
In 2006, 2005, 2004 2003 and 20022003, the Company granted 107,555 shares, 50,000 shares, 40,000 shares 11,000 shares and 30,00011,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market.market or as a new issuance. Under the 2006 grant, the shares vest 15.0% on January 1, 2007, 25.0% vest on January 1, 2008, and the remaining 60.0% vest on January 1, 2009 based upon a performance and service condition. Under the 2005 grant, 40,000 shares vest in one installment on the date of the 2008 Annual Shareholders’ Meeting based upon performance criteria and the remaining 10,000 shares vest equally over three years. The 2004 grant vests 8,000 shares in three years 12,000and the remaining 32,000 shares in four years and the remaining 20,000 shares in five years. OfFor the 2003 shares issued,grant, 1,000 vested in 2003 with the remaining shares vesting evenly over the following five years. The 2002 shares
At December 31, 2006, there were fully vested as of December 2003. In 2002, the Company also issued 50,000205,656 total shares of nonvested restricted stock outsideand the weighted average grant date fair value of the LTI Plan as approved by the Puget Energy Boardthese shares was $22.02. There was $1.7 million of Directors. These shares were recorded as a separate component of stockholders’ equity and vest evenlytotal unrecognized compensation cost related to nonvested restricted stock at December 31, 2006. That cost is expected to be recognized over a five-year period.weighted-average period of 1.6 years. Compensation expense related to the restricted shares was $0.5 million, $0.6$2.0 million and $0.5$0.7 million in 2004, 2003for 2006 and 2002,2005, respectively. Dividends are paid on all outstanding shares of restricted stock and are accounted for as a Puget Energy common stock dividend, not as compensation expense. The weighted average grant date fair value for all outstanding shares of restricted stock granted in 2004, 20032006 and 20022005 was $23.55, $23.29$21.32 and $21.94,$21.86, respectively. During 2006, 15,333 shares of restricted stock vested and 2,566 shares of restricted stock were forfeited. No restricted stock was forfeited during 2005. The fair value of the restricted stock is based on the closing price of the Company’s common stock on the date of grant.
Restricted Stock Units
In 2004, the Company also granted 10,000 restricted stock units outside of the LTI Plan but subject to the terms and conditions of the plan. The units vest 2,000 shares in three years 3,000and the remaining 8,000 shares in four yearsyears. At December 31, 2006, there were 10,000 total shares of nonvested restricted stock units and the remaining 5,000 shares in fiveweighted average fair value of these units was $25.36. There was $0.1 million of total unrecognized compensation cost related to nonvested restricted stock units as of December 31, 2006. That cost is expected to be recognized over a weighted-average period of 1.3 years. TheseThere were no restricted stock units granted or forfeited during 2006 and 2005. The restricted stock units will be settled in cash aswhen they become vested.vested at the end of each cycle. Dividends are paid on the outstanding stock units and are accounted for as compensation expense. Compensation expense related to the restricted stock units agreement was $0.1 million in 2004.for 2006 and 2005. The weighted average grant date fair value forof the restricted stock units was $23.55.is based on the closing price of the Company’s common stock at each reporting period.
RETIREMENT EQUIVALENT STOCKRetirement Equivalent Stock
The Company has a retirement equivalent stock agreement inunder which in lieu of participating in the Company’s executive supplemental retirement plan, the presidentChairman, President and chief executive officerChief Executive Officer is granted performance-based stock equivalents in January of each year, which are deferred under the Company’s deferred compensation plan. In 2006, 2005, 2004 and 2003, the Company awarded 8,218, 6,063, 6,469 and 4,319 shares, respectively, which vest over a period of seven years from January 1, 2002 to May 2008 at 15%15.0% per year for the first six years and the remaining 10%10.0% in the seventh year. Dividends areThe weighted average grant date fair value for the retirement equivalent stock was $20.42, $24.70, $23.77 and $22.05 for 2006, 2005, 2004 and 2003, respectively.
At December 31, 2006, there were 6,268 total shares of nonvested retirement equivalent stock units and the weighted average grant date fair value of these units was $22.60. There was $0.1 million unrecognized compensation cost related to nonvested retirement equivalent stock units as of December 31, 2006. That cost is expected to be recognized over a weighted-average period of 1.4 years. The equivalent value of dividends is paid on the accumulated retirement equivalent stock equivalents accumulated in the deferred compensation account in the form of Puget Energy common stock, which isunits and added to the deferred compensation account. Compensation expense related to the retirement equivalent stock agreement was $0.2 million and $0.1 million in 2004 as well as in 2003. The weighted average grant date fair value for the2006 and 2005, respectively. During 2006, 8,043 retirement equivalent stock was $23.77 and $22.05 for 2004 and 2003 respectively. There were no grants in 2002.units vested. The fair value of the restricted stock is based on the closing price of the Company’s common stock on the date of grant.
EMPLOYEE STOCK PURCHASE PLANEmployee Stock Purchase Plan
The Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six-month intervals at the end of which the participating employees receive shares for 85%85.0% of the lower of the stock’s fair market price at the beginning or the end of the six-month period. A maximum of 500,000 shares may be sold to employees under the plan. In 2004 and 2003, 52,716 and 38,940 shares were issued for the ESPP, respectively. In 2002, 18,252 shares were issued and 19,407 shares were purchased for the plan.plan through May 2007. At December 31, 2004, 206,9462006, 82,318 shares maycould still be sold to employees under the plan. In 2006 and 2005, 66,496 and 58,132 shares were issued for the ESPP, respectively. Under the SFAS No. 123 accounting that the Company adopted in 2003 and under SFAS No. 123R, the ESPP is considered to be compensation expense. Total compensation expense relatedcompensatory and the amount is immaterial to the ESPP was $0.2 million in 2004 and $0.2 million in 2003.financial statements. Dividends are not paid on ESPP shares until they are purchased by employees and thus are accounted for as dividends, not compensation expense. The weighted average fair value of the purchase rights granted in 2004, 2003 and 2002 was $3.74, $4.25 and $4.19, respectively.
INFRASTRUX STOCK OPTION PLAN
The InfrastruX stock option plan, established in 2000, has 3,862,500 shares of InfrastruX stock authorized to be granted to officers, key employees and non employee directors of InfrastruX. The options generally vest within four years and expire 10 years from the grant date. The following summarizes InfrastruX option information for 2004, 2003 and 2002:
| | | 2004 | | 2003 | | 2002 | |
| | | Shares (in thousands) | | Weighted Average Exercise Price | | Shares (in thousands) | | Weighted Average Exercise Price | | Shares (in thousands) | | Weighted Average Exercise Price | |
| Outstanding at beginning of year | | | 2,618 | | $ | 4.36 | | | 2,643 | | $ | 4.31 | | | 1,995 | | $ | 4.05 | |
| Granted | | | 10 | | | 5.00 | | | 176 | | | 5.00 | | | 725 | | | 5.00 | |
| Exercised | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | |
| Canceled | | | (99 | ) | | 4.75 | | | (201 | ) | | 4.20 | | | (77 | ) | | 4.09 | |
| Outstanding at end of year | | | 2,529 | | $ | 4.35 | | | 2,618 | | $ | 4.36 | | | 2,643 | | $ | 4.31 | |
| Options exercisable at year end | | | 2,056 | | $ | 4.20 | | | 1,837 | | $ | 4.12 | | | 802 | | $ | 4.02 | |
Weighted average fair value of options granted during the year | | $2.41 | $2.41 | $2.23 |
The following summarizes InfrastruX’s outstanding option information at December 31, 2004:
| | Shares Outstanding (in thousands) | Weighted Average Contractual Life (in years) | Weighted Average Exercise Price |
| Exercise Prices | | | |
| $4.00 | 1,641 | | 6.10 | | $ 4.00 | |
| $5.00 | 888 | | 7.47 | | 5.00 | |
| | 2,529 | | 6.59 | | $ 4.35 | |
Non-Employee Director Stock options awarded under the InfrastruX plan were generally granted at the InfrastruX market price on the date of grant although some options were granted at a discount requiring InfrastruX to record compensation expense. With those options and the prospective adoption of SFAS No. 123 fair value accounting in 2003, InfrastruX recorded compensation expense related to options granted in 2004, 2003 and 2002 of $0.1 million, $0.2 million and $0.1 million, respectively.
NON-EMPLOYEE DIRECTOR STOCK PLANPlan
The Company has a director stock plan approved in 1997 and effective beginning in 1998, for all non employeenon-employee directors of Puget Energy and PSE. An amended and restated plan was approved by shareholders in 2005. Under the plan, which has a 10-year term and which, subject to shareholder approval, will be amended and restated at the May 2005 Annual Meeting, non employeethrough December 31, 2015, non-employee directors receive a minimum of two-thirdsportion of their quarterly retainer fees in Puget Energy stock except that 100%100.0% of quarterly retainers are paid in Puget Energy stock until the director holds a number of shares equal in value to two years of their retainer fees. Directors may optionallychoose to continue to receive their entire retainer in Puget Energy stock. The compensation expense related to the director stock plan was $0.6$0.5 million and $0.4 million in 2006 and $0.2 million in 2004, 2003 and 2002,2005, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 100,000350,000 shares. As of December 31, 2004, 15,2302006, 34,166 shares had been issued or purchased for the director stock plan and 64,83892,807 deferred, for a total of 80,068126,973 shares. As of December 31, 2003 and 20022005, the number of shares that had been purchased for the director stock plan was 9,90225,221 and 6,916, respectively, and the number that had been deferred was 48,219 and 36,117, respectively,77,741, for a total of 58,121 and 43,033 shares, respectively.102,962 shares.
The Company used the Black-Scholes option pricing model to determine the fair value of certain stock-based awards to employees. The following assumptions were used for awards grantedoutstanding in 2004, 20032006 and 2002:2005.
| | | 2004 | 2003 | 2002 | |
| Stock issuance cycle | | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | |
| Stock options | | | | | | | | | | | | | | | | | | | | | |
| Risk-free interest rate | | | -- | | | -- | | | 4.32 | % | | | * | | * | | * | | * | | 4.32 | % |
Expected lives- years | | | -- | | | -- | | | 4.50 | | | | * | | * | | * | | * | | 4.5 | |
| Expected stock volatility | | | -- | | | -- | | | 23.62 | % | | | * | | * | | * | | * | | 23.62 | % |
| Dividend yield | | | -- | | | -- | | | 5.00 | % | | | * | | * | | * | | * | | 5.00 | % |
| InfrastruX stock option plan | | | | | | | | | | | |
| Risk-free interest rate | | | 2.8 | % | | 2.8 | % | | 4.05 | % | |
Expected lives- years | | | 4.0 | | | 4.0 | | | 4.0 | | |
| Expected stock volatility | | | 70.0 | % | | 70.0 | % | | 70.0 | % | |
| Performance awards | | | | | | | | | | | | | | | | | | | | | | |
| Risk-free interest rate | | | 2.59 | % | | 2.35 | % | | 4.0 | % | | | ** | | 2.50 | % | | 2.59 | % | | 2.35 | % | | * | |
Expected lives- years | | | 3.0 | | | 4.0 | | | 4.0 | | | | 3.0 | | 3.0 | | 3.0 | | 4.0 | | * | |
| Expected stock volatility | | | 22.24 | % | | 23.85 | % | | 23.71 | % | | | ** | | 15.10 | % | | 22.24 | % | | 23.85 | % | | * | |
| Dividend yield | | | 4.45 | % | | 4.86 | % | | 8.85 | % | | | * | | 4.18 | % | | 4.45 | % | | 4.86 | % | | * | |
| Employee Stock Purchase Plan | | | | | | | | | | | | | | | | | | | | | | |
| Risk-free interest rate | | | 1.28 | % | | 1.07 | % | | 1.65 | % | | | 4.96 | % | | 2.68 | % | | 1.28 | % | | 1.07 | % | | * | |
| Expected lives - years | | | 0.5 | | | 0.5 | | | 0.5 | | | | 0.5 | | 0.5 | | 0.5 | | 0.5 | | * | |
| Expected stock volatility | | | 9.89 | % | | 19.47 | % | | 26.97 | % | | | 9.79 | % | | 13.98 | % | | 9.89 | % | | 19.47 | % | | * | |
| Dividend yield | | | 4.42 | % | | 4.39 | % | | 5.81 | % | | | 4.55 | % | | 4.17 | % | | 4.42 | % | | 4.39 | % | | * | |
* | Not applicable |
** | Fair value is determined by end of period market value. |
The expected lives of the securities represent the estimated period of time until exercise and are based on the vesting period of the award and the historical exercise experience of similar awards. All participants were assumed to have similar exercise behavior. Expected volatility is based on historical volatility over the approximate expected term of the option.
NOTE 16.17. Accounting for Derivative Instruments and Hedging Activities
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into both physical and financial contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase normal sale exception.(NPNS) exception to derivative accounting rules if they meet certain criteria. Generally, NPNS applies if PSE deems the counterparty creditworthy, has energy resources within the western region to allow for physical delivery of the energy and if the transaction is within PSE’s forecasted load requirements. Those contracts that do not meet normal purchase normal saleNPNS exception or cash flow hedge criteria are marked-to-market to current earnings in the income statement, subject to deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) for energy related derivatives due to the Power Cost Adjustment (PCA)PCA mechanism and purchased gas adjustment (PGA) mechanism.
The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted electric generation resources exposes the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk portfolio management function monitors and manages these risks using analytical models and tools.
The Company is not engaged in the business of assuming risk for the purpose of realizing speculative trading revenues. Therefore, wholesale market transactions are focused on balancing the Company’s energy portfolio, reducing costs and risks where feasible, and reducing volatility in wholesale costs and margin in the portfolio. In order to manage risks effectively, the Company enters into physical and financial transactions which are appropriate for the service territory of the Company and are relevant to its regulated electric and gas portfolios.
The Company’s energy riskportfolio management staff develops hedging strategies for the Company’s energy supply portfolio. The first priority is to obtain reliable supply for delivery to the Company’s retail customers. The second priority is to protect against unwanted risk exposure. The third priority is to optimize excess capacity or flexibility within the energy portfolio.
The Company has entered into master netting agreements with counterparties when available to mitigate credit exposure to those counterparties. The Company believes that entering into such agreements reduces risk of settlement default for the ability to make only one net payment. In addition, the Company believes risk is mitigated with an improved position in potential counterparty bankruptcy situations due to a consistent netting approach.
At December 31, 2004,2006, the Company was subject to a range of netting provisions, including both stand alone agreements and the provisions associated with the Western Systems Power Pool agreement, of which many energy suppliers in the western United States are a part.
ForDuring the yeartwelve months ended December 31, 2004,2006, the Company recorded an increasea decrease in earnings for the change in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria of approximately $0.1 million compared to a decrease in earnings of approximately $0.5 million compared to a decreaseand an increase of $0.1$0.5 million for 2003. Of the 2004 gain, $0.7 million unrealized gain represented cash flow hedges that were de-designatedtwelve months ended December 31, 2005 and reclassified from other comprehensive income into earnings. As of December 31, 2004 respectively.
At December 31, 2006, the Company had an unrealized loss recorded in other comprehensive income of $6.5 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. In 2004, a portion of the total unrealized gain of cash flow hedge transactions in other comprehensive income and marked-to-market gain in the income statement were deferred under SFAS No. 71 due to the Company expecting to reach the $40 million cap under the PCA mechanism in the first quarter 2005. When these transactions are realized they will be reflected in the PCA mechanism calculation. As of December 31, 2003, the Company had annet unrealized gain recorded in other comprehensive income of $0.2$4.9 million (net of tax)after-tax related to energy contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges associated with these energy contracts that will reverse and be settled into the income statement during 20052007 is approximately $0.7 million.
At December 31, 2006, PSE hashad a contract withshort-term asset of $9.2 million and a counterparty whose debt ratings have been below investment grade since 2002. The contract,long-term asset of $6.8 million as well as short-term liability of $8.0 million and a physicallong-term liability of $0.4 million related to energy contracts designated as cash flow hedges that represent forward financial purchases of gas supply contract for one of PSE’s electric generating facilities, was marked-to-market beginninggeneration from PSE-owned electric plants in future periods. If it is determined that it is uneconomical to run the plants in the fourth quarter 2003. Althoughfuture period, the counterparty continueshedging relationship is ended and the cash flow hedge is de-designated and any unrealized gains and losses are recorded in the income statement. Gains and losses when these de-designated cash flow hedges are settled are recognized in energy costs and are included as part of the PCA mechanism. At December 31, 2005, the Company had an unrealized gain recorded in other comprehensive income of $43.2 million (net of tax), before SFAS No. 71 deferrals of $6.3 million, related to fully perform onenergy contracts which met the physical supply contract, the counterparty’s credit ratings have remained weak. Prior to October 1, 2003, the contract was designatedcriteria for designation as a normal purchasecash flow hedges under SFAS No. 133. PSE has concluded that it is appropriateThis was mainly the result of higher forward market prices for natural gas and electricity at December 31, 2005 compared to reserveDecember 31, 2006.
At December 31, 2006, the mark-to-market gain on this contract dueCompany also had a short-term asset of $6.8 million and a short-term liability of approximately $61.6 million and a long-term asset of $0.1 million related to the credit qualityhedge of gas contracts to serve natural gas customers. All mark-to-market adjustments relating to the counterpartynatural gas business have been reclassified to a deferred account in accordance with SFAS No. 133 guidance,71 due to the purchased gas adjustment (PGA) mechanism. The PGA mechanism passes increases and decreases in the cost of natural gas supply to customers. As the gains and losses on the hedges are realized in future periods, they will be recorded as management deemed that delivery is not probable throughgas costs under the term of the contract, which expires December 2008. There was no impact on earnings for the 12 months endedPGA mechanism. At December 31, 2004 and 2003.2005, the company had a net asset of $25.7 million related to the hedge of gas contracts to serve natural gas customers.
In the firstsecond quarter 2004,2006, the counterparty of another physical gas supply contract for one of PSE’s electric generating facilities notified PSE that it would be unable to deliver physical gas supply beginningCompany settled two forward starting swap contracts originating in November 2005 through the end of the contract in June 2008. Since physical delivery for the life of the contract was no longer probable, the contract no longer met the criteria for normal purchase exception under SFAS No. 133. Therefore, the contract was marked-to-market in the first quarter 2004, with an offsetting reserve for the portion of the mark-to-market gain applicable to the impaired period of November 2005 through June 2008. In October 2004, PSE and the counterparty reached a settlement on the non-deliverable period of November 2005 through June 2008. The agreement allows PSE to recover a portion of the present value of the difference in future market prices of physical gas and the original contract price, for a total recovery of approximately $10.1 million. In the fourth quarter 2004, an accounting order was approved by the Washington Commission to defer the counterparty settlement amount as a regulatory liability and amortize the benefit over the period of November 2005 through June 2008 as a reduction in Electric Generation Fuel expense. The amended contract meets the criteria for normal purchase exception under SFAS No. 133 since delivery for the life of the contract is probable. In October 2004, PSE entered into a new contract with another counterparty for the period November 2005 through June 2008 to replace the physical gas supply from the previously mentioned amended contract. This new contract meets the normal purchase exception under SFAS No. 133.
The Company entered into treasury lock transactions to hedge against the potential rising treasury rate component of the interest rate on planned debt issuances.May 2005. The purpose of the treasury lock isforward starting swap contracts was to lock in the base component of the interest rate on the planned issuance at current period favorable levels.
In the third quarter 2004, the Company entered into two treasury lock contracts to hedge against potential rising interest rate exposure for a debt offering anticipated to be performed in the first half of 2005. A treasury lock is a financial arrangement between the Company and a counterparty whereby one of the parties will be required to make a payment to the other party$200.0 million that was completed on a specific valuation date based upon the change in value of aJune 30, year treasury bond. If interest rates rise related to the hedged debt2006. PSE received $21.3 million from the date of issuance ofcounterparties when the treasury lock instruments, the Company would receive a payment from the counterparty for the change in the bond value. Alternatively, if interest rates decrease related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would pay the counterparty for the change in bond value. These treasury lock contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period being presented net of tax in other comprehensive income. WhenIn the second quarter 2006, the settlement of these treasury lockinstruments resulted in a gain of $13.9 million after-tax, which was recorded in other comprehensive income.
In the third quarter 2006, the Company settled two forward starting swap contracts are settled upon issuanceoriginating in September 2006. The purpose of the forward starting swap contracts was to hedge a $300.0 million debt any gain oroffering that was priced on September 13, 2006. PSE paid $0.6 million to the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value presented net of tax in other comprehensive income. In the third quarter of 2006, the settlement of these instruments resulted in a loss of $0.4 million after-tax, which was recorded in other comprehensive income. In accordance with SFAS No. 133, the loss will be amortized fromout of other comprehensive income to current earnings as an increase to interest expense over the 30 year life of the issued debt. At December 31, 2004, the unrealized loss associated with these two treasury lock contracts was $11.3 million ($7.4 million net of tax) and is includednew debt issued.
The ending balance in other comprehensive income. Bothincome related to swaps contracts at December 31, 2006 was a loss of $8.5 million after-tax and accumulated amortization. This compares to a loss of $22.4 million in other comprehensive income after-tax and accumulated amortization at December 31, 2005 related to forward starting swaps and previously settled treasury rate lock hedges will settle in 2005.contracts.
NOTE 17.18. Acquisitions (Puget Energy Only)Colstrip Matters
During 2002, InfrastruX acquired 100%In May 2003, approximately 50 plaintiffs brought an action against the owners of three companies basedColstrip which has since been amended to add additional claims. The lawsuit alleges that certain domestic water wells and the Colstrip water supply pond were contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond, that seepage from Colstrip Units 1 & 2 have decreased property values and that seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. In December 2005, Colstrip Unit 1 & 2 owners extended city water to certain residents who lived near the plant, including the domestic well plaintiffs. Discovery is ongoing and the case is currently scheduled for trial in Texas forJanuary 2008.
On May 18, 2005, the Environmental Protection Agency (EPA) enacted the Clean Air Mercury Rule (CAMR) that will permanently cap and reduce mercury emissions from coal-fired power plants. The Montana Board of Environmental Review approved a total pricemore stringent rule to limit mercury emissions from coal-fired plants on October 16, 2006 (0.9 lbs/TBtu, instead of $49.7 million,the federal 1.4 lbs/TBtu). The Colstrip owners are still evaluating the potential impact of the new Montana rule and duringit is still unknown whether the second quarter 2003 acquired 100%new rule will be appealed. Preliminary treatment technology studies undertaken by the Colstrip owners estimate that PSE’s portion of one additional company based in New Mexico for $11.8 million. InfrastruX made no acquisitions in 2004. All purchases were funded in the form of cash and preferred or common stock.
These companies provide utility infrastructure services which are relevantcosts to InfrastruX’s operating strategy including: installing, replacing and restoring underground cables and pipes for utilities and telecommunications providers; pipeline construction, maintenance and rehabilitation services forcomply with the natural gas and petroleum industries, including directional drilling and vacuum excavation; and distribution and transmission-oriented overhead electric construction services to electric utilities and cooperatives.
The acquisitions have been accounted for using the purchase method of accounting and, accordingly, the operating results of these companies have been included in Puget Energy’s consolidated financial statements since their acquisition dates. Goodwill additions representing the excess of cost over the net tangible and identifiable intangible assets at the time of purchase were approximately $7.7new rule could be as much as $75.0 million in construction expenditures, but this number could change as new information becomes available.
In December 2003, and $23.5 million in 2002. Of the additions to goodwill in 2003 and 2002, no amounts were deductible for calculating income tax expense.
The pro forma combined revenue, net income and earnings per common share of Puget Energy presented below give effect to the acquisitions as if they had occurred on January 1, 2002. These results are not necessarily indicativeEPA issued an Administrative Consent Order (ACO) which alleged violation of the resultsClean Air Act permit requirement to submit, for review and approval by the EPA, an analysis and proposal for reducing emissions of operationsnitrogen oxide to address visibility concerns upon the occurrence of certain triggering events which EPA asserts occurred in 1980. Although Colstrip owners believe that would have occurred had the acquisitionsACO is unfounded, the Colstrip owners signed a settlement agreement in December 2006 that is now awaiting signature by the EPA, and then will be entered by the court. The agreement includes installation of these companies been consummatedlow nitrogen oxide equipment installation on Colstrip Units 3 & 4 which will cost PSE approximately $2.65 million.
On June 15, 2005, the EPA issued the Clean Air Visibility Rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology requirements for electric generating units, including presumptive limits for sulfur dioxide and nitrogen oxide controls for large units. Colstrip was originally required to submit analyses of visibility impacts for Colstrip 1 & 2 by December 2006 but the periodEPA has not yet completed the required preliminary analyses. PSE cannot yet determine the need for or costs of additional controls to comply with this rule, which they are being given effect. There were no acquisitions in 2004.could be significant.
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) FOR THE YEARS ENDED DECEMBER 31 | | 2003 | | 2002 | |
| Operating revenues | | $ | 2,396,802 | | $ | 2,391,981 | |
| Net income | | | 116,636 | | | 112,813 | |
| Basic earnings per common share | | $ | 1.23 | | $ | 1.28 | |
| Diluted earnings per common share | | $ | 1.22 | | $ | 1.27 | |
| (Dollars in thousands) | | 2006 | | 2005 | | 2004 | |
| Taxes other than income taxes: | | | | | | | |
| Real estate and personal property | | $ | 39,832 | | $ | 44,472 | | $ | 43,843 | |
| State business | | | 107,140 | | | 93,893 | | | 82,408 | |
| Municipal and occupational | | | 97,671 | | | 85,154 | | | 72,405 | |
| Other | | | 33,144 | | | 30,841 | | | 27,766 | |
| Total taxes other than income taxes | | $ | 277,787 | | $ | 254,360 | | $ | 226,422 | |
| Charged to: | | | | | | | | | | |
| Operating expense | | $ | 255,712 | | $ | 233,742 | | $ | 208,989 | |
| Other accounts, including construction work in progress | | | 22,075 | | | 20,618 | | | 17,433 | |
| Total taxes other than income taxes | | $ | 277,787 | | $ | 254,360 | | $ | 226,422 | |
NOTE 18.20. GoodwillRegulation and Intangibles (Puget Energy Only)Rates
EffectiveElectric Regulation and Rates
Storm Damage Deferral Accounting
On February 18, 2005, the Washington Commission issued a general rate case order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $7.0 million annually may be deferred for qualifying storm damage costs that meet the IEEE outage criteria for system average interruption duration index. In 2006, PSE incurred $103.2 million in storm-related electric transmission and distribution system restoration costs, of which $92.3 million was deferred for future recovery in electric rates and will be determined in a future general rate case.
Electric General Rate Case
On January 5, 2007, the Washington Commission issued its order in PSE’s electric general rate case filed in February 2006, approving a general rate decrease for electric customers of $22.8 million or 1.3% annually. The rates for electric customers are effective beginning January 13, 2007. In its order, the Washington Commission approved a weighted cost of capital of 8.4%, or 7.06% after-tax, and a capital structure that included 44.0% common equity with a return on equity of 10.4%. The Washington Commission had earlier approved (on June 28, 2006) a power cost only rate case (PCORC) increase of $96.1 million annually effective July 1, 2006.
Power Cost Only Rate Case
PCORC, a limited-scope proceeding, was created in 2002 Puget Energy adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which required all goodwill amortizationby the Washington Commission to cease on January 1, 2002. Puget Energy allocates goodwillperiodically reset power cost rates. The main objective of the PCORC proceeding is to reporting units based on the excess purchase price over tangible and identifiable intangible assets. SFAS No. 142 also requires Puget Energy to perform an annual impairmentprovide for timely review of goodwill. In addition to the annual review, Puget Energy is required to perform an impairment reviewnew resource acquisitions costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission agreed to an eventexpedited five-month PCORC decision timeline rather than the statutory 11-month timeline for a general rate case.
On October 20, 2005, the Washington Commission approved a PCORC filing that increased electric rates 3.7% or circumstance arises$55.6 million annually. Included in the increase is the recovery of capital and operating costs of the Hopkins Ridge wind generating facility. The Hopkins Ridge wind generating facility was completed on November 27, 2005. As a wind generating facility, Hopkins Ridge is eligible for Federal Production Tax Credits (PTCs) that will ultimately offset some of the costs associated with generating power from Hopkins Ridge. The PTC is a tax credit provided by the Federal government for generating electricity from certain renewable resources. The current amount of the tax credit is $0.019 per kilowatt hour (kWh) for wind generation and may be subject to inflation adjustments over time. The tax credit can be claimed for 10 years for a new wind project put into service prior to January 1, 2008. The use of the credit is restricted to offset only 25% of current taxes payable. Unused credits can be carried forward for up to 20 years.
In the Washington Commission’s October 2005 order, a new tariff schedule was approved which provides for the pass through to ratepayers of all benefits of the PTCs for the Hopkins Ridge project. This mechanism (a PTC Tracker) will pass through to the customer the actual production tax credits of the Hopkins Ridge project as they are generated. The PTC Tracker would indicatenot be subject to the fair value wouldsharing bands in the PCA. The credits passed through to the customer will be belowadjusted by the carrying costs of unused PTCs. Since the customer is receiving the benefit of the tax credits as they are generated and the Company does not receive a credit from the IRS until the tax credits are utilized, the Company is reimbursed its carrying value. In the fourth quarter 2004, as part of its annual goodwill review, Puget Energy recorded a non-cash goodwill impairment of $91.2 million ($76.6 million after tax and after minority interest) to operating expenses related to its investment in InfrastruX. The valuation of the goodwill was based on the present value of the future cash flows of estimated earnings of InfrastruX which reflect prospective market price information from prospective buyers. In 2004, Puget Energy began evaluating its strategic optionscosts for its InfrastruX investment and on February 8, 2005 Puget Energy decided to exitfunds through this utility construction services business.
Identifiable assets acquired as a result of acquisitions of companies are amortized based on the expected pattern of use or on a straight-line basis over the expected periods to be benefited, which ranges from 5 to 20 years. In 2004, a patent was completed and added to intangibles for $0.1 million with an amortization period of 16 years. In 2003, a total of $2.1 million was added to intangible assets- assigned $0.1 million to patents with an amortization period of 17 years, $1.7 million to contractual customer relationships with an amortization period of 10 years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is 9.6 years.
AT DECEMBER 31, 2004 (DOLLARS IN THOUSANDS) | | Intangibles | | Accumulated Amortization | | Net Intangibles | |
| Covenant not to compete | | $ | 4,178 | | $ | 2,748 | | $ | 1,430 | |
| Developed technology | | | 14,190 | | | 3,163 | | | 11,027 | |
| Contractual customer relationships | | | 4,702 | | | 1,374 | | | 3,328 | |
| Patents | | | 986 | | | 91 | | | 895 | |
| Total | | $ | 24,056 | | $ | 7,376 | | $ | 16,680 | |
AT DECEMBER 31, 2003 (DOLLARS IN THOUSANDS) | | Gross Intangibles | | Accumulated Amortization | | Net Intangibles | |
| Covenant not to compete | | $ | 4,178 | | $ | 2,009 | | $ | 2,169 | |
| Developed technology | | | 14,190 | | | 2,454 | | | 11,736 | |
| Contractual customer relationships | | | 4,702 | | | 747 | | | 3,955 | |
| Patents | | | 915 | | | 68 | | | 847 | |
| Total | | $ | 23,985 | | $ | 5,278 | | $ | 18,707 | |
The identifiable intangible amortization expense for the year ended December 31, 2004 was $2.1 million compared to $2.1 million and $1.9 million for 2003 and 2002, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:
| (Dollars in Thousands) | 2005 | 2006 | 2007 | 2008 | 2009 |
| Future intangible amortization | $ 2,207 | $1,732 | $1,385 | $1,301 | $1,276 |
NOTE 19.Tenaska Disallowancecalculation.
Production Tax Credit
On October 30, 2006, PSE revised its PTC electric tariff to increase the credit to customers from $13.1 million to $28.8 million, effective January 1, 2007. The credit is based on expected wind generation and reflects the true-up of prior years’ credits provided to customers versus credits for actual wind generation taken for federal income taxes and the addition of Wild Horse to the wind portfolio.
PCA Mechanism
On June 20, 2002, the Washington Commission approved a PCA mechanism that triggers if PSE’s costs to provide customers’ electricity falls outside certain bands established in an electric rate case. The cumulative maximum pre-tax earnings exposure due to power cost variations over the four-year period ending June 30, 2006 was limited to $40.0 million plus 1.0% of the excess. In October 2005, the Washington Commission approved a shift to an annual PCA measurement period from January through December starting in 2007. On January 5, 2007, the Washington Commission approved the PCA mechanism for continuation under the same annual graduated scale without a cumulative cap for excess power costs. All significant variable power supply cost variables (hydroelectric and wind generation, market price for purchased power and surplus power, natural gas and coal fuel price, generation unit forced outage risk and transmission cost) are included in the PCA mechanism.
The PCA mechanism apportions increases or decreases in power costs, on a calendar year basis, between PSE and its customers on a graduated scale:
Annual Power Cost Variability | July-December 2006 Power Cost Variability1 | Customers’ Share | Company’s Share2 |
| +/- | $20 million | +/- | $10 million | 0 | % | 100 | % |
| +/- | $20 - $40 million | +/- | $10 - $20 million | 50 | % | 50 | % |
| +/- | $40 - $120 million | +/- | $20 - $60 million | 90 | % | 10 | % |
| +/- | $120 million | +/- | $60 million | 95 | % | 5 | % |
_____________
1 | In October 2005, the Washington Commission in its Power Cost Only Rate Case order allowed for a reduction to the power cost variability amounts to half the annual power cost variability for the period July 1, 2006 through December 31, 2006. |
2 | Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40.0 million plus 1.0% of the excess. Power cost variation after December 31, 2006 will be apportioned on a calendar year basis, without a cumulative cap. |
On April 26, 2006, the Washington Commission approved an accounting petition on a temporary basis to defer an $89.0 million one-time capacity reservation charge along with accrual of interest at the authorized after-tax rate of return. As part of the general rate case order of January 5, 2007, the Washington Commission approved the regulatory accounting treatment that had been approved in the accounting petition. The payment was made in relation to an agreement for the purchase of power from Chelan County PUD (Chelan). PSE and Chelan have entered into an agreement which provides for the purchase of 25.0% of the output of Chelan’s Rock Island (622 megawatts (MW)) and Rocky Reach (1,237 MW) dams on the Columbia River. The agreement called for PSE to make a one-time payment of $89.0 million on April 27, 2006. Then, upon the expiration of the existing contracts in 2011, PSE will begin purchasing 25.0% of the output at the projects’ costs for the next 20 years.
On January 25, 2006, the Washington Commission approved an accounting order to defer, as a regulatory liability, two payments in the amount of $42.0 million and $13.0 million received from Duke Energy Trading and Marketing (Duke) in December 2005 in return for assuming the gas transportation capacity on Northwest Pipeline and Westcoast Pipeline from Duke Energy Trading and Marketing. The regulatory liability will be amortized to gas costs from January 2006 through October 2017 based upon the approved schedule. These credits are an offset to gas transportation costs that are in excess of PSE’s gas transportation capacity needs. The $42.0 million payment was received to compensate the Company for the Northwest capacity payments that must be made until February 2011 when the capacity will be needed to serve load. The $13.0 million payment was received to compensate the Company for the difference between the assumed tariff rates and market value of the Westcoast Pipeline capacity through October 2017.
On April 7, 2004, the Washington Commission approved PSE’s recovery on the unamortized White River plant investment. At December 31, 2006, the White River project net book value totaled $69.1 million, which included $43.4 million of net utility plant, $17.1 million of capitalized FERC licensing costs, $4.3 million of costs related to construction work in progress and $1.8 million related to dam operations and safety. On February 18, 2005, the Washington Commission approved the recovery of the White River net utility plant costs but did not allow current recovery of FERC licensing costs and other related costs until all costs associated with selling the White River plant and any sales proceeds are known. Any proceeds from the sale of the White River assets and water rights will reduce the balance of the deferred regulatory asset. Neither the outcome of this matter nor any potential associated financial impacts can be predicted at this time.
Gas Regulation and Rates
Gas General Rate Case
On January 5, 2007, the Washington Commission issued its order in PSE’s gas general rate case, granting an increase for gas customers of $29.5 million or 2.8% annually, effective beginning January 13, 2007. In its order the Washington Commission approved the same weighted cost of capital of 8.4% or 7.06% after-tax and capital structure that included 44.0% common equity with a return on equity of 10.4%, consistent with the Company’s electric operations.
Purchased Gas Adjustment
PSE has a PGA mechanism in retail gas rates to recover variations in gas supply and transportation costs. Variations in gas rates are passed through to customers, therefore PSE’s gas margin and net income are not affected by such variations. On September 27, 2006, the Washington Commission approved a revision of PSE's PGA tariff schedule that went into effect on October 1, 2006. The tariff changes will increase gas revenue approximately $95.1 million, or 9.9%, on an annual basis. The rate increase authorized PSE to recover higher projected future gas and gas transportation costs, as well as to collect an accumulated deficit (receivable) balance in its PGA balancing account over a 24-month period (beginning October 1, 2006). The PGA rate change will increase PSE's gas revenue, but will not impact the Company's net income as the increased revenue will be offset by increased purchased gas costs. The following rate adjustments were approved by the Washington Commission in relation to the PGA mechanism during 2006, 2005 and 2004:
| Effective Date | Percentage Increase in Rates | Annual Increase in Revenues (Dollars In Millions) |
| October 1, 2006 | 10.2% | $ 95.1 |
| October 1, 2005 | 14.7% | 121.6 |
| October 1, 2004 | 17.6% | 121.7 |
The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a disallowance of $25.6 million foraccumulated costs under the PCA 1 period (July 1, 2002 through June 30, 2003), which was recorded by PSE as a Purchased Electricity expense in the second quarter 2004. The order also established guidelinesmechanism for future recovery of Tenaskathese excess costs. The amounts were determined to be a $25.6 million disallowance for the PCA 1 period and an estimated disallowance of $11.3 million for the PCA 3 period (July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s methodology of 50% disallowance on the return on the Tenaska regulatory asset due to projected costs exceeding the benchmark during the period. For the PCA 3 period, approximately $5.6 million was disallowedincrease in the period July 1, 2004 through December 31, 2004, primarily as a reduction to Electric Operating Revenue. While the Washington Commission did not expressly addresspurchased electricity expense resulting from the disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE estimated the disallowance for the PCA 2 period to be approximately $12.2totaled $9.0 million, if the Washington Commission were to follow the same methodology as they have ordered for the PCA 3 period. Therefore, PSE recorded a $12.2$4.1 million disallowance to Purchased Electricity expense in the second quarter 2004 for the 50% disallowance of the return on the Tenaska regulatory asset in accordance with the Washington Commission’s methodology discussed in their order of May 13, 2004 for a cumulative impact on earnings ofand $43.4 million in 2006, 2005 and 2004, for the PCA 1, PCA 2 and PCA 3 periods. As a result of the disallowance recorded, the PCA customer deferral was expensed and a reserve was established for amounts not previously deferred under the PCA mechanism.respectively. The reserve balance as of December 31, 2004 was $3.2 million, which is expected to be utilized in 2005 as excess power costs are shared through the PCA mechanism.
PSE filed the PCA 2 period compliance filing in August 2004 and received an order from the Washington Commission on February 23, 2005. In the PCA 2 compliance order, the Washington Commission approved the Washington Commission staff’s recommendation for an additional return related to the Tenaska regulatory asset in the amount of $6.1 million related to the period July 1, 2003 through December 31, 2003. Washington Commission staff’s recommendation was opposed by certain other parties. This amount alters the PCA deferral and is subject to reconsideration and appeal by other parties. Parties have 10 days from February 23, 2005 to file for reconsideration and 30 days to appeal the order. Once the statutory appeal process has concluded and the Washington Commission issues its final order, PSE will determine if recording a regulatory asset is appropriate.
In the May 13, 2004 order, the Washington Commissionalso established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
Below is a summary of the Tenaska disallowances by quarter through December 31, 2004:
(DOLLARS IN MILLIONS) QUARTER ENDING | | | 7/02 - 6/03 PCA 1 (ordered/final | ) | | 7/03 - 6/04 PCA 2 (estimated | ) | | 7/04 - 12/04 PCA 3 (estimated | ) | | Total | |
| June 30, 2004 | | $ | 25.6 | | $ | 12.2 | | $ | -- | | $ | 37.8 | |
| September 30, 2004 | | | -- | | | -- | | | 2.8 | | | 2.8 | |
| December 31, 2004 | | | -- | | | -- | | | 2.8 | | | 2.8 | |
| Total | | $ | 25.6 | | $ | 12.2 | | $ | 5.6 | | $ | 43.4 | |
The Washington Commission guidelines for determining future recovery of the Tenaska costs (gas costs, recovery of the Tenaska regulatory asset and return on the Tenaska regulatory asset) are as follows:
1. | The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
2. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs. |
3. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
a) | actual Tenaska costs that exceed the benchmark or; |
b) | the return on the Tenaska regulatory asset. |
4. | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs. |
The Washington Commission confirmed that if the Tenaska gas costs are deemed prudent, PSE will recover the full amount of actual gas costs and the recovery of the Tenaska regulatory asset even if the benchmark is exceeded.
NOTE 20.Colstrip Matters
In September 2004, the owners of Colstrip Units 1 & 2 (PSE and PPL Montana) entered into a tentative settlement agreement with certain homeowners in the Colstrip town site area concerning a lawsuit filed in May 2003. In December 2004, the plaintiffs retained new counsel and postponed further settlement discussions until more discovery is completed. The lawsuit alleged certain domestic water wells may have been contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond. The tentative settlement agreement would require extending municipal water to the homeowners and abandoning the existing wells. The total estimated cost of the settlement ranges from $1.4 million to $1.5 million. As a result of this tentative settlement agreement, PSE recorded a $0.7 million reserve in the third quarter 2004 for its 50% ownership of the Colstrip Units 1 & 2 project. The settlement agreement would not resolve certain other claims by residents within the city limits. PSE cannot predict the outcome or any potential financial impact of the claims by the residents within the city limits at this time.
In June 2004, PSE and Western Energy Company (WECO), the supplier of coal to Colstrip Units 1 & 2, entered into a binding arbitration and settled a dispute concerning prices paid for coal supplied. The binding decision retroactively set a new baseline cost per ton of coal purchased by PSE for Colstrip Units 1 & 2 supplied from July 31, 2001, and is applicable for the remaining term of the coal supply agreement through December 2009. The decision resulted in a $6.9 million charge that was recorded in the second quarter 2004. Of the $6.9 million charge, $5.0 million was included in the PCA mechanism. PSE had previously accrued a $1.6 million reserve in the fourth quarter 2003 related to the arbitration.
On April 29, 2004, the Minerals Management Service of the United States Department of the Interior (MMS) issued an order to WECO to pay additional royalties concerning coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of an additional $1.1 million in royalties for coal mined from federal land between 1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a settlement agreement entered into in February 1997 among PSE, WECO and Montana Power Company that resolved disputes that were then pending. The order seeks to impute the price charged to PSE based on the other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is supporting WECO’s appeal of the order, but is also evaluating the basis of the claim. PSE accrued a loss reserve in the amount of $1.1 million in connection with this matter in the second quarter 2004.
In addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. PSE’s share of the alleged additional royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest in Colstrip Units 3 & 4. Other parties may attempt to assert claims against WECO if the MMS position prevails. The transportation agreement provides for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is monitoring the process. PSE believes that Colstrip Units 3 & 4 owners have reasonable defenses in this matter based upon its review. Neither the outcome of this matter nor the associated costs can be predicted at this time.
On December 5, 2003, Colstrip Units 1 & 2 and 3 & 4 received an information request from the Environmental Protection Agency (EPA) relating to their compliance with the Clean Air Act New Source Review regulations. PSE is currently in discussions with the EPA concerning the information request. Neither the outcome of this matter nor any potential associated costs can be predicted at this time.
NOTE 21.Taxes Other Than Income Taxes
PUGET ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | |
| Taxes other than income taxes: | | | | | | | |
| Real estate and personal property | | $ | 45,121 | | $ | 45,660 | | $ | 48,890 | |
| State business | | | 82,408 | | | 75,523 | | | 77,527 | |
| Municipal and occupational | | | 72,405 | | | 64,861 | | | 67,770 | |
| Other | | | 39,479 | | | 38,273 | | | 37,029 | |
| Total taxes other than income taxes | | $ | 239,413 | | $ | 224,317 | | $ | 231,216 | |
| Charged to: | | | | | | | | | | |
| Operating expense | | $ | 221,980 | | $ | 208,395 | | $ | 215,429 | |
| Other accounts, including construction work in progress | | | 17,433 | | | 15,922 | | | 15,787 | |
| Total taxes other than income taxes | | $ | 239,413 | | $ | 224,317 | | $ | 231,216 | |
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | | 2004 | | 2003 | | 2002 | |
| Taxes other than income taxes: | | | | | | | |
| Real estate and personal property | | $ | 43,843 | | $ | 44,757 | | $ | 48,408 | |
| State business | | | 82,408 | | | 75,524 | | | 77,527 | |
| Municipal and occupational | | | 72,405 | | | 64,861 | | | 67,770 | |
| Other | | | 27,766 | | | 25,638 | | | 24,463 | |
| Total taxes other than income taxes | | $ | 226,422 | | $ | 210,780 | | $ | 218,168 | |
| Charged to: | | | | | | | | | | |
| Operating expense | | $ | 208,989 | | $ | 194,857 | | $ | 202,381 | |
| Other accounts, including construction work in progress | | | 17,433 | | | 15,923 | | | 15,787 | |
| Total taxes other than income taxes | | $ | 226,422 | | $ | 210,780 | | $ | 218,168 | |
NOTE 22.Other
On September 24, 2004, the Washington Commission approved PSE’s request for a Purchased Gas Adjustment (PGA) mechanism rate increase filed on August 31, 2004. The approved request will increase rates and revenues by approximately 17.6% or $121.7 million annually. The increase in PGA mechanism rates was to recover higher market prices of natural gas sold to customers. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in gas prices. PSE’s gas margin and net income are not affected by the change in PGA mechanism rates.
In 2003, the Washington Commission’s Pipeline Safety staff conducted a natural gas standard inspection for three counties within Washington State in which PSE operates gas pipelines. The inspection included a review of procedures, records and operations and maintenance activities. On June 29, 2004, the Washington Commission issued a complaint to PSE related to that inspection, alleging certain violations of Washington Commission regulations. In December 2004, PSE and the Washington Commission resolved the issues. PSE agreed to a penalty of $0.5 million, and also agreed to update certain natural gas operating practices. In addition, the resolution included the potential for future penalties of up to $0.2 million in the next ten years if certain operational goals are not met. The Washington Commission approved the settlement on January 31, 2005.
In September 2004, a natural gas fire destroyed a home and took the life of a PSE customer. The cause of the fire remains under investigation by PSE, the Washington Commission and other parties. PSE has tendered the matter to its general liability insurer. Neither the potential regulatory nor litigation outcomes of this matter nor the final associated costs can be predicted at this time.
On February 18, 2005, the Washington Commission approved a 3.5% general tariff gas rate case increase and a 4% general tariff electric rate case increase. The increases were $26.3 million annually for gas customers and $56.6 million for electric customers effective March 4, 2005. In the order, the Washington Commission also approved a capital structure of 43% common equity with a return on common equity of 10.3%.
On April 23, 2004, the acquisition of a 49.85% interest in the Frederickson 1 generating facility was approved by FERC. Prior to that approval, on April 7, 2004, the Washington Commission had issued an order in PSE’s power cost only rate case granting approval for the acquisition of the Frederickson 1 generating facility. As a result of these approvals, PSE completed the acquisition in the second quarter 2004 and added $80.8 million in utility plant. In its order, the Washington Commission found the acquisition to be prudent and the costs associated with the generating facility reasonable. The costs associated with the generating facility, including projected baseline gas costs, are approved for recovery in rates. On May 13, 2004, the Washington Commission also approved other adjustments to power costs that resulted in an increase of cost recovery in rates of $44.1 million annually, beginning May 24, 2004, which includes the ownership, operation and fuel costs of the Frederickson 1 generating facility.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River project because the 1997 license contained terms and conditions that rendered ongoing operations of the project uneconomical relative to alternative resources. As a result, generation of electricity ceased at the White River project on January 15, 2004. At December 31, 2004,2006, the White River project net book value totaled $65.1$69.1 million, which included $46.4$43.4 million of net utility plant, $14.8$17.1 million of capitalized FERC licensing costs, $3.1$4.3 million of costs related to construction work in progress and $0.8$1.8 million related to dam operation and safety. PSE is sought recovery of the relicensing, other construction work in progress and dam operations and safety costs totaling $18.7 million in its general rate filing of April 2004, over a 10-year amortization period. In the third quarter 2004, the Washington Commission staff recommended that PSE be allowed recovery of the White River net utility plant costs noted above, but defer any amortization of the FERC licensing and other costs until all costs and any sales proceeds are known. In itsOn February 18, 2005, general rate case order, the Washington Commission found this treatment reasonable, and adopted allagreed to allow PSE to recover the White River net utility plant costs noted above. However, amortization of the staff recommendations. FERC licensing and other costs will not begin until all costs and any sales proceeds are known.
In November 2005, Puget Energy sold 15 million shares of common stock to Lehman Brothers Inc. for $312.0 million before underwriting discount. The net proceeds of approximately $309.8 million were invested in PSE and used to repay short-term debt incurred primarily to fund PSE’s construction program.
In January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. FIN 46R requires that if a business entity has minority ownershipa controlling financial interest in a variable interest entity, the financial statements must be included in the consolidated financial statements of the business entity. The adoption of FIN 46R for all interests in a venture capital fund established as a limited liability corporation that seeks long-term capital appreciation by making capital investments in energy sector related businesses.variable interest entities created after January 31, 2003 was effective immediately. For variable interest entities created before February 1, 2003, it was effective July 1, 2003. The Company’s ownership interest inadoption of FIN 46R was effective March 31, 2004 for the fund is less than 20% andCompany. FIN 46R also impacted the managing memberstreatment of the limited liability corporation have sole discretion over fund operations, management and investment decisions. Under the termsCompany’s mandatorily redeemable preferred securities of a wholly owned subsidiary trust holding solely junior subordinated debentures of the limited liability corporation agreement establishing(trust preferred securities). Previously, these trust preferred securities were consolidated into the fund, the fund terminates December 31, 2007. The Company’s carrying valueoperations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the investment in the fund totaled $1.9 million at December 31, 2004, which includescorporation payable to a $6.1 million pre-tax losssubsidiary trust holding mandatorily redeemable preferred securities (junior subordinated debt). This change had no impact on the Company’s original costresults of operations. The Company also evaluated its power purchase agreements and determined that three counterparties may be considered variable interest entities. As a result, PSE submitted requests for information to those parties; however, the parties have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity. PSE determined that it does not have a contractual right to such information. PSE will continue to submit requests for information to the counterparties on a quarterly basis to determine if FIN 46R is applicable.
For the three power purchase agreements that may be considered variable interest entities under FIN 46R, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the fourth quarter 2003. Based onpower purchase agreements. If at any time the guidance from EITF No. 03-16, the Company started accounting for its investmentcounterparties cannot deliver energy to PSE, PSE would have to buy energy in the fund usingwholesale market at prices which could be higher or lower than the equity method accounting. The adoption of the equity method had no cumulative effect on earningspurchase power agreement prices. PSE’s Purchased Electricity expense for the year ended December 31,2006, 2005 and 2004 as PSE had been carrying this investment at fair value, which represents the equity basis, since December 31, 2003. The Company’s future funding obligation to this fund is $0.3 million.
On November 1, 1999, PSE acquired Encogen Northwest, LP (Encogen) whose sole asset is a natural gas-fired cogeneration facility located in Washington State. With the approval of the Washington Commission, the Encogen facility has been operated as part of PSE’s least cost generation dispatch portfolio to serve its native load obligations since itfor these three entities was acquired in 1999. Two wholly-owned subsidiaries of PSE, GP Acquisition Corporation$259.8 million, $267.0 million and LP Acquisition Corporation, are the general and limited partners of Encogen,$251.2 million, respectively. On December 29, 2004, PSE filed an application with FERC pursuant to Section 203 of the FPA to transfer the Encogen facility to PSE and eliminate the various subsidiaries via an Agreement and Plan of Merger (Merger). On February 15, 2005, FERC issued an order authorizing the Encogen plant to be transferred to PSE. PSE anticipates completing the merger in 2005.
NOTE 23.22. Commitments and Contingencies
For the year ended December 31, 2004,2006, approximately 23.1% of the Company’s energy output was obtained at an average cost of approximately $0.0146$0.014 per kWh through long-term contracts with several of the Washington Public Utility Districts (PUDs) owning hydroelectric projects on the Columbia River.
The purchase of power from the Columbia River projects is on a “cost-of-service”pro rata share basis under which the Company pays a proportionate share of the annual cost ofdebt service, operating and maintenance costs and other expenses associated with each project in direct proportion to the amount of power annually purchased by the Companycontractual shares that PSE obtains from suchthat project. SuchIn these instances, PSE’s payments are not contingent upon the projects being operable.operable, which means PSE is required to make the payments even if power is not being delivered. These projects are financed through substantially level debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the lives of the contracts.
As of December 31, 2004,2006, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:
| | | | Total Bonds Outstanding 12/31/062 (Millions) | Company’s Annual Amount Purchasable (Approximate) |
| Project | Contract Exp. Date | License1 Exp. Date | % of Output | | Megawatt Capacity | Cost3 (Millions) |
| Rock Island | | | | | | | |
| Original units | 2012 | 2029 | $ 109.3 | 50.0 | } | 330 | $ 34.4 |
| Additional units | 2012 | 2029 | 322.4 | 50.0 |
Rocky Reach 8 | 2011 | 2006 | 380.2 | 38.9 | | 501 | 27.2 |
| Wells | 2018 | 2012 | 208.4 | 29.9 | | 251 | 11.0 |
Priest Rapids 4,5,6 | TBD7 | TBD7 | 265.5 | 4.3 | | 39 | 9.2 |
Wanapum 4,5,6 | 2009 | TBD7 | 441.8 | 10.8 | | 106 | 4.3 |
| Total | | | $ 1,727.6 | | | 1,227 | $ 86.1 |
| | | | TOTAL BONDS | COMPANY'S ANNUAL AMOUNT |
| | | | OUTSTANDING | PURCHASABLE (APPROXIMATE) |
| | CONTRACT | LICENSE 1 | 12/31/042 | % OF | MEGAWATT | COST3 |
| PROJECT | EXP. DATE | EXP. DATE | (MILLIONS) | OUTPUT | CAPACITY | (MILLIONS) |
| Rock Island | | | | | | |
| Original units | 2012 | | 2029 | | $ 115.8 | | 50.0 | } | 414 | | $ 40.8 | |
| Additional units | 2012 | | 2029 | | 328.4 | | 75.0 |
| Rocky Reach | 2011 | | 2006 | | 383.0 | | 38.9 | 505 | | 24.7 | |
| Wells | 2018 | | 2012 | | 143.3 | | 31.3 | 261 | | 5.2 | |
Priest Rapids4 | 2005 | | 2005 | | 179.7 | | 8.0 | 72 | | 2.4 | |
Wanapum4 | 2009 | | 2005 | | 181.6 | | 10.8 | 98 | | 3.3 | |
| Total | | | $ 1,331.8 | | | 1,350 | | $ 76.4 | |
_____________________
1 | The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. FERC has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirmtheCompany’s contractual rights to receive power under existing terms and conditions even if a new licensee is granted a license prior to expiration of the contract term. |
2 | The contracts for purchases initially were generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings and refinancings,re-financings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration date are: 53.4%77.1% at Rock Island; 60.0%64.6% at Rocky Reach; and 6.6%29.0% at Wells. There are no maturities beyond the contract expiration date of 2035 for Priest Rapids and Wanapum which assumes a 40-year FERC license extension. |
3 | The components of 20042006 costs associated with the interest portion of debt service are: Rock Island, $22.6$13.3 million for all units; Rocky Reach, $9.4$8.2 million; Wells, $7.7$3.2 million; Priest Rapids, $0.7$0.4 million; and Wanapum, $1.0$1.5 million. |
4 | On December 28, 2001, PSE signed a contract offer for three new contracts for related to the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. On May 27, 2005, PSE signed additional amendments to those agreements which provided technical clarifications of certain sections of the agreements and consolidated the terms into two contracts. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. Grant County PUD filed an “Application for New License for the Priest Rapids Project” on October 29, 2003. The new contracts’ terms begin in November of 2005 for the Priest Rapids Development and in November of 2009 for the Wanapum Development. Unlike the current contracts, in the new contracts PSE’s share of power from the developments declines over time as Grant County PUD’s load increases. On March 8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant County PUD’s new contracts unreasonably restrain trade and violate various sections of the Federal Power ActFPA and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, itFERC has ordered Grant County PUD to remove specific sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing haswas requested but was denied by FERC on April16, 2003. Both the Yakama Nation and Grant County PUD have appealed the FERC decision and the appeals have been requested.consolidated in the Ninth Circuit Court of Appeals. The complaint is still pending and is in a mediation process. |
5 | Grant County PUD filed an “Application for New License for the Priest Rapids Project” on October 29, 2003 and the original FERC license expired at the end of October 2005. Grant County PUD continues to operate the Priest Rapids Project under annual license extensions pending issuance of a new FERC license and the new contracts will be concurrent with the new license which will be at least 30 years. |
6 | Unlike PSE’s expiring contracts with Grant County PUD, in the new contracts PSE’s share of power from the Priest Rapids Development and Wanapum Development declines over time as Grant County PUD’s load increases. PSE’s share of the Wanapum Development will remain at 10.8% until November 2009 and will be adjusted annually thereafter for the remaining term of the new contracts. PSE’s share of the Priest Rapids Development declines to approximately 4.3% in 2006 and will be adjusted annually for the remaining term of the new contract. |
7 | To be determined. (See notes 4-6.) |
8 | On February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement and a related Transmission Agreement for 25.0% of the output of Chelan’s Rocky Reach and Rock Island hydroelectric generating facilities located on the mid-Columbia River in exchange for PSE paying 25.0% of the operating costs of the facilities. PSE’s share of the output represents approximately 487 MW of capacity and 243 average MW of energy. The agreements terminate in 2031 and provide that PSE will begin to receive power upon expiration of PSE’s existing long-term contracts with Chelan for the Rocky Reach and Rock Island output (expiring in 2011 and 2012, respectively). The agreements have been approved by both FERC and the WUTC. |
Early in 2003,The following table summarizes the Colville Confederated Tribes (Colville Tribe) presented a claim to Douglas County PUD based upon allegedly unpaid past annual charges for the Wells Hydroelectric project for the use of Colville Tribal lands. The Colville Tribe also claimed that annual charges would also be due for periods into the future. On November 1, 2004, Douglas County PUD entered into a settlement with the Colville Tribe concerning claims that the Colville Tribe had asserted against Douglas County PUD for the use by the Wells project of Tribal lands. PSE approved the settlement and participated in the filing Douglas County PUD made on November 23, 2004 seeking FERC approval. The settlement was approved in a FERC order on February 11, 2005. It is unlikely that any party will seek a rehearing of that FERC order, of which the deadline for doing so is March 13, 2005. When the settlement becomes final, the effects on PSE will be through modestly increased power costs, and a small reduction to the amount of power delivered to PSE due to the allocation to the Colville Tribe. The Tribe’s allocation will be treated as an encroachment to the project, thus reducing the amount of power available for purchase by others.
The Company’s estimated paymentspayment obligations for power purchases from the Columbia River, are $79.9 million for 2005, $80.1 million for 2006, $83.2 million for 2007, $86.9 million for 2008, $89.7 million in 2009, and in the aggregate, $54.6 million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with other utilities inand contracts under non-utility generators under the region. The Company is generally not obligated to make payments under these contracts unless power is delivered. The Company’s estimated payments for firm power purchases from other utilities, excluding the Columbia River projects, are $79.3 million for 2005, $81.5 million for 2006, $82.9 million for 2007, $83.7 million for 2008, $83.5 million in 2009 and in the aggregate, $349.6 million thereafter through 2037.Public Utility Regulatory Policies Act (PURPA). These contracts have varying terms and may include escalation and termination provisions.
As required by the federal Public Utility Regulatory Policies Act (PURPA), PSE entered into long-term firm purchased power contracts with non-utility generators. The Company purchases the net electrical output of four significant projects at fixed and annually escalating prices, which were intended to approximate the Company’s avoided cost of new generation projected at the time these agreements were made. The Company’s estimated payments under these contracts are $210.2 million for 2005, $215.4 million for 2006, $205.3 million for 2007, $205.3 million for 2008, and $207.1 million for 2009, and in the aggregate, $527.4 million thereafter through 2013.
The following table summarizes the Company’s estimated obligations for future power purchases:
(DOLLARS IN MILLIONS) | | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 & THERE- AFTER | | TOTAL | | |
| Columbia River Projects | | $ | 79.9 | | $ | 80.1 | | $ | 83.2 | | $ | 86.9 | | $ | 89.7 | | $ | 54.6 | | $ | 474.4 | | |
| (Dollars in millions) | | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 & There-after | Total |
| Columbia River projects | | $ | 97.7 | $ | 100.0 | $ | 105.0 | $ | 107.2 | $ | 111.6 | $ | 1,762.0 | $ | 2,283.5 |
| Other utilities | | | 79.3 | | | 81.5 | | | 82.9 | | | 83.7 | | | 83.5 | | | 349.6 | | | 760.5 | | | 83.0 | | 83.8 | | 85.9 | | 83.3 | | 37.1 | | 235.1 | | 608.2 |
| Non-utility generators | | | 210.2 | | | 215.4 | | | 205.3 | | | 205.3 | | | 207.1 | | | 527.4 | | | 1,570.7 | | | 200.0 | | 195.4 | | 201.2 | | 199.7 | | 200.1 | | 105.1 | | 1,101.5 |
| Total | | $ | 369.4 | | $ | 377.0 | | $ | 371.4 | | $ | 375.9 | | $ | 380.3 | | $ | 931.6 | | $ | 2,805.6 | | $ | 380.7 | $ | 379.2 | $ | 392.1 | $ | 390.2 | $ | 348.8 | $ | 2,102.2 | $ | 3,993.2 |
Total purchased power contracts provided the Company with approximately 9.6 million, 9.6 million and 9.4 million 11.0 million and 12.1 million MWhmegawatt hours (MWh) of firm energy at a cost of approximately $404.7$421.7 million, $479.2$419.7 million and $466.1$404.7 million for the years 2006, 2005 and 2004, 2003 and 2002, respectively.
The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2004:
| | | | COMPANY'S SHARE |
(DOLLARS IN MILLIONS) | ENERGY SOURCE (FUEL) | COMPANY'S OWNERSHIP SHARE | PLANT IN SERVICE AT COST | ACCUMULATED DEPRECIATION |
| Colstrip Units 1 & 2 | Coal | 50% | $ 207 | | $ 134 | |
| Colstrip Units 3 & 4 | Coal | 25% | 469 | | 250 | |
Financing for a participant’s ownership share in the projects is provided for by such participant. The Company’s share of related operating and maintenance expenses is included in corresponding accounts in the Consolidated Statements of Income.
As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to 48,000 MMBtu (one million British thermal units, equal to one Dth) per day of natural gas for operation of Tenaska’s natural gas-fired cogeneration facility. This obligation continues for the remaining term of the agreement, provided that no deliveries are required during the month of May. The price paid by Tenaska for this gas is reflective of the daily price of gas at the United States/Canada border near Sumas, Washington. PSE has entered into a financial arrangement to hedge a portion, 5,000 MMBtu to 10,000 MMBtu per day, of future gas supply costs associated with this obligation. The Company has a maximum financial obligation under this hedge agreement of $18.9$1.1 million in 2005 and $2.22007. The Company has obligations for gas supply amounting to $8.9 million in 2006.2007 for the Tenaska plant.
As part of its electric operations and in connection with the 1999 buyout of the Cabot gas supply contract, PSE is obligated to deliver to Encogen up to 21,800 MMBtu per day of natural gas for operation of the Encogen natural gas-fired cogeneration facility. This obligation continues for the remaining term of the original Cabot agreement. The Company entered into a financial arrangement to hedge a portion of future gas supply costs associated with this obligation, 10,000 MMBtu per day, for the remaining term of the agreement. The Company has a maximum financial obligation under this hedge agreement of $8.7 million in 2005, $9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter.in 2008. Depending on actual market prices, these costs will be partially, or perhaps entirely, offset by floating price payments received under the hedge arrangement. Encogen has two gas supply agreements that comprise 40% of the plant’s requirements with remaining terms ranging from less than 1 year to 3.52.5 years. The obligations under these contracts are $14.1 million in 2005, $2.2 million in 2006, $2.5$21.9 million in 2007 and $1.4$11.1 million in the aggregate thereafter.2008. The Company has obligations for gas supply amounting to $2.0 million in 2007.
PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are generally classified as normal purchases and normal sales or in some cases recorded at fair value in accordance with SFAS No. 133 and SFAS No. 149. Commitments under these contracts are $138.2$181.2 million in 20052007 and $41.2 thereafter.$19.8 million in 2008.
GAS SUPPLYGas Supply
The Company has also entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of gas supply for its firm customers. Many of these contracts, which have remaining terms from less than 1 year to 1917 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company contracts for all of its long termlong-term gas supply on a firm gas service,basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation. The Company incurred demand charges in 20042006 for firm gas supply, firm transportation service and firm storage and peaking service of $21.4$1.8 million, $63.6$93.5 million and $5.7$8.4 million, respectively. WNG CAP I, a PSE subsidiary, incurred demand charges in 20042006 for firm transportation service of $8.4$3.2 million, which is included in the total Company demand charges. The Company incurred demand charges in 2006 for firm transportation service for the gas supply for its combustion turbines in the amount of $11.6 million, which is included in the total Company demand charges.
The following table summarizes the Company’s obligations for future demand charges through the primary terms of its existing contracts. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change.
DEMAND CHARGE OBLIGATIONS (DOLLARS IN MILLIONS) | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 & THERE- AFTER | TOTAL | |
Demand Charge Obligations (Dollars in millions) | | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 & There-after | Total |
| Firm gas supply | $ 1.8 | $ 1.2 | $ 1.0 | $ 0.8 | $ 0.5 | $ 1.0 | $ 6.3 | $ | 1.8 | $ | 1.0 | $ | 0.5 | $ | 0.5 | $ | 0.5 | $ | -- | $ | 4.3 |
| Firm transportation service | 69.6 | 68.8 | 65.0 | 55.6 | 110.2 | 117.2 | 486.4 | | 109.1 | | 94.8 | | 75.5 | | 35.7 | | 35.7 | | 219.1 | | 569.9 |
| Firm storage service | 11.5 | 10.5 | 7.7 | 40.2 | 85.3 | | 9.4 | | 9.0 | | 7.7 | | 7.7 | | 7.7 | | 21.5 | | 63.0 |
| Total | $ 82.9 | $ 80.5 | $ 73.7 | $ 64.1 | $ 118.4 | $ 158.4 | $ 578.0 | $ | 120.3 | $ | 104.8 | $ | 83.7 | $ | 43.9 | $ | 43.9 | $ | 240.6 | $ | 637.2 |
SERVICE CONTRACTService Contracts
On August 30, 2001, PSE and Alliance Data Systems Corp. (Alliance Data) announced a contract under which Alliance Data will provide data processing and billing services for PSE. In providing services to PSE under the 10-year agreement, Alliance Data will use ConsumerLinX software, PSE’s customer-information software developed by a former subsidiary, ConneXt. Alliance Data acquired the assets of ConneXt, including the exclusive use of the ConsumerLinX software for five years with an option for renewal. Alliance Data will offer ConsumerLinX as part of its integrated, single-source customer relationship management solution for large-scale, regulated utility clients. The obligations under the contract are $22.2 million in 2005, $22.8 million in 2006, $23.4$23.3 million in 2007, $24.0$23.9 million in 2008, $24.6$24.5 million in 2009, and $42.3$25.1 million in the aggregate2010 and $17.1 million thereafter.
In April 2004, PSE acquired a 49.85% interest in the Frederickson 1 generating facility. As part of that acquisition, PSE became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas combined cycle unit. The contract was initiated in December 2000, and runs for the earlier of 96,000 factoryfactored fired hours or 18 years. The contract requires payments based on both a fixed and variable cost component, depending on how much the facility is used. PSE’s share of the estimated obligation under the contract based on projected future use of the facility are $1.1 million in 2005, $1.1 million in 2006, $5.1is $1.2 million in 2007, $1.8$6.3 million in 2008, $1.1 million in 2009, $2.6 million in 2010, $1.9 million in 2011 and $12.2$14.4 million in the aggregate thereafter.
In March 2005, in connection with its purchase of the Hopkins Ridge wind power project, PSE entered into an Operations, Maintenance and Warranty Agreement (OM&W Agreement) with Vestas-American Wind Technology, Inc. (Vestas), pursuant to which Vestas will operate, maintain, service and remedy any defects or deficiencies in the constructed wind turbine generators (WTGs) at Hopkins Ridge and their associated equipment on PSE’s behalf. Vestas also provides certain warranties in relation to the availability, production and noise of the Hopkins Ridge project. The OM&W Agreement provides for a five-year term continuing until November 2010. The annual fee is approximately $2.6 million and will escalate on each January 1 during the term by the Consumer Price Index.
In September 2005, in connection with its purchase of the Wild Horse wind power project, PSE entered into a Service & Maintenance Agreement and a Warranty Agreement (the Agreements) with Vestas-American Wind Technology, Inc. (Vestas American), pursuant to which Vestas American will operate, maintain, service and remedy any defects or deficiencies in the constructed WTGs at Wild Horse and their associated equipment on PSE’s behalf. Vestas American also provides certain warranties in relation to the availability performance of the Wild Horse project. The Agreements provide for a five-year term continuing until November 2011. The first-year annual fee is approximately $5.1 million and will escalate each January 1 thereafter during the term by the Gross Domestic Product Implicit Price Deflator (GDPIPD).
FREDONIAFredonia 3 ANDand 4 OPERATING LEASEOperating Lease
PSE leases two combustion turbines for its Fredonia 3 and 4 electric generating facility pursuant to a master operating lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE at any time. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR).LIBOR. At December 31, 2004,2006, PSE’s outstanding balance under the lease was $56.3$51.1 million. The expected residual value under the lease is the lesser of $37.4 million or 60%60.0% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87%87.0% of the unamortized value of the equipment.
SURETY BONDSurety Bond
The Company has a self-insurance surety bond in the amount for $5.9of $10.1 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.5 million.
ENVIRONMENTALEnvironmental Remediation
The Company is subject to environmental laws and regulations by federal, state and local authorities and has been required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has also been named by the Environmental Protection Agency, the Washington State Department of Ecology, and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring theserelevant sites. Remediation and testing of Company vehicle service facilities and storage yards is also continuing.
During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings.proceedings, subject to Washington Commission review. The Company believes a significant portion of its past and future environmental remediation costs areis recoverable from insurance companies, from third parties or under the Washington Commission’s order.
The information presented here as it relates to estimates of future liability is as of December 31, 2004.
ELECTRIC SITES
The Company has expended approximately $20.8 million related to the remediation activities covered by the Washington Commission’s order and has accrued approximately $1.7 million as a liability for future remediation costs for these and other remediation activities. To date, the Company has recovered approximately $20.0 million from insurance carriers.
Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow.
GAS SITES
The Company has expended approximately $69.6 million related to the remediation activities covered bycustomers under a Washington Commission order and has accrued approximately $30.6 million for future remediation costs for these and other remediation sites. To date,order. At December 31, 2006, the Company has recoveredhad $1.7 million and $34.6 million in deferred electric and gas environmental costs, respectively.
In November, 2006, PSE’s Crystal Mountain Generation Station had an accidental release of approximately $60.7 million from insurance carriers18,000 gallons of diesel oil. PSE crews and other third parties. The Company expectsconsultants responded and worked with applicable state and federal agencies to recover legalcontrol and remediation activities from either insurance companies or customers per Washington Commission orders.
Based on all known factsremove the spilled product. Through February 2007, over 9,500 gallons have been removed. Due to weather and analyses,snow in particular (the site is located very near the Company believes itCrystal Mountain Ski Resort), additional recovery of diesel is not likely thatfeasible until later in 2007. However, the identified environmental liabilitiesremaining recoverable diesel is presumed to be contained within a limited area and largely embedded in soils under the generator station. Total removal costs as of February 14, 2007 are approximately $8.8 million. PSE is currently projecting the total remediation cost to be between $10.3 million and $13.3 million. At December 31, 2006, PSE had an insurance receivable in the amount of $7.9 million accrued associated with the Crystal Mountain electric generating facility oil spill. PSE management will result in a material adverse impact on the Company’s financial position, operating results or cash flow.be filing proof of loss claims with insurers once damage repair costs are known within an acceptable level of precision.
LITIGATIONLitigation
There are several actions in the U.S. Ninth Circuit Court of Appeals (Ninth Circuit) against Bonneville Power Administration (BPA), in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing, a number of contracts,agreements, including the amended settlement agreement regarding(and the Residential Purchase and Sale Program and the conditional settlement agreementsMay 2004 agreement) between BPA and PSE which modifiedregarding the payment provisions of theBPA Residential Purchase and Sale Program. BPA rates used in such amended settlement agreementagreements between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefitsby BPA under such agreements during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. The parties to these various actions presented oral arguments to the U.S. Ninth Circuit Court of Appeals in November 2005. A decision from the Court is anticipated in 2007. A number of parties have claimed that the BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing such agreements. It is not clear what impact, if any, development or review of such rates, review of such agreements and the above described Ninth Circuit actions may have on PSE.
Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 2004. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.
Puget Energy operates in primarily twoone business segments:segment referred to as the regulated utility operations (PSE), whichsegment. The regulated utility segment includes the account receivables securitization program, and construction services (InfrastruX).program. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the Statestate of Washington. InfrastruX specializes in construction services to other gas and electric utilities primarily in the Midwest, Texas, south-central and eastern United States.
One minor non-utility business segment which includes two PSE subsidiaries, and Puget Energy, is described as other. The PSE subsidiaries are a real estate investment, anda development company and a holding company for a small non-utility wholesale generator. Reconciling items between segments are not significant.
After completingPrior to 2005, InfrastruX was a strategic reviewreportable segment of Puget Energy. InfrastruX Puget Energy has decided to exit the utility construction services sector. Puget Energy’s Boardwas sold on May 7, 2006 and is not considered a reportable segment. See Note 3 for InfrastruX summarized financial information and discussion of Directors approved the decision on February 8, 2005. The decision to exit the business is the result of the Company’s need to invest in the core utility business to acquire or construct energy generating resources and energy delivery infrastructure. During 2005, Puget Energy intends to monetize its interest in InfrastruX through sale or third party recapitalization and invest the proceeds in PSE.discontinued operations.
2006 (Dollars in Thousands) | | Regulated Utility | | Other | | Reconciling Item | | Puget Energy Total | |
| Revenues | | $ | 2,897,864 | | $ | 7,829 | | $ | -- | | $ | 2,905,693 | |
| Depreciation and amortization | | | 262,129 | | | 212 | | | -- | | | 262,341 | |
| Income tax | | | 95,271 | | | 1,000 | | | -- | | | 96,271 | |
| Operating income | | | 323,497 | | | 3,119 | | | -- | | | 326,616 | |
| Interest charges, net of AFUDC | | | 183,922 | | | -- | | | -- | | | 183,922 | |
| Net income from continuing operations | | | 172,735 | | | (5,511 | ) | | -- | | | 167,224 | |
| Total assets | | | 6,993,131 | | | 72,908 | | | -- | | | 7,066,039 | |
| Construction expenditures - excluding equity AFUDC | | | 749,516 | | | -- | | | -- | | | 749,516 | |
2005 (Dollars in Thousands) | | Regulated Utility | | Other | | Reconciling Item | | Puget Energy Total | |
| Revenues | | $ | 2,565,384 | | $ | 7,826 | | $ | -- | | $ | 2,573,210 | |
| Depreciation and amortization | | | 241,385 | | | 249 | | | -- | | | 241,634 | |
| Income tax | | | 87,749 | | | 860 | | | -- | | | 88,609 | |
| Operating income | | | 299,541 | | | 3,622 | | | -- | | | 303,163 | |
| Interest charges, net of AFUDC | | | 164,965 | | | 224 | | | -- | | | 165,189 | |
| Net income from continuing operations | | | 142,861 | | | 3,422 | | | -- | | | 146,283 | |
Total assets1 | | | 6,267,012 | | | 68,392 | | | 274,547 | | | 6,609,951 | |
| Construction expenditures - excluding equity AFUDC | | | 568,381 | | | -- | | | -- | | | 568,381 | |
2004 (DOLLARS IN THOUSANDS) | REGULATED UTILITY | INFRASTRUX | OTHER | RECONCILING ITEM | PUGET ENERGY TOTAL |
| Revenues | $ 2,192,340 | $ 369,936 | $ 6,537 | -- | $ 2,568,813 |
| Depreciation and amortization | 228,310 | 18,276 | 256 | -- | 246,842 |
| Goodwill impairment | -- | 91,196 | -- | -- | 91,196 |
| Income tax | 75,755 | (1,793) | 1,002 | -- | 74,964 |
| Operating income (loss) | 285,258 | (70,928) | 2,421 | -- | 216,751 |
| Interest charges, net of AFUDC | 166,411 | 6,460 | 219 | -- | 173,090 |
| Net income (loss) | 123,401 | (70,388) | 2,009 | -- | 55,022 |
| Goodwill, net | -- | 43,503 | -- | -- | 43,503 |
| Total assets | 5,511,631 | 251,097 | 70,641 | -- | 5,833,369 |
| Construction expenditures - excluding equity AFUDC | 393,891 | -- | -- | -- | 393,891 |
| Additions to other property, plant and equipment | -- | 15,512 | -- | -- | 15,512 |
2003 (DOLLARS IN THOUSANDS) | | | OTHER | RECONCILING ITEM2 | |
Revenues1 | $ 2,034,973 | $ 341,787 | $ 6,043 | -- | $ 2,382,803 |
| Depreciation and amortization | 219,851 | 16,779 | 236 | -- | 236,866 |
| Income tax | 69,823 | 1,594 | 952 | -- | 72,369 |
| Operating income | 295,219 | 7,452 | 2,504 | -- | 305,175 |
| Interest charges, net of AFUDC | 179,437 | 5,485 | 123 | -- | 185,045 |
| Net income | 119,144 | 1,766 | 438 | (5,151) | 116,197 |
| Goodwill, net | -- | 133,302 | -- | -- | 133,302 |
| Total assets | 5,281,474 | 342,332 | 75,196 | -- | 5,699,002 |
| Construction expenditures - excluding equity AFUDC | 269,973 | -- | -- | -- | 269,973 |
| Additions to other property, plant and equipment | -- | 15,536 | -- | -- | 15,536 |
2002 (DOLLARS IN THOUSANDS) | | | | | |
Revenues1 | $ 1,985,899 | $ 319,529 | $ 9,753 | -- | $ 2,315,181 |
| Depreciation and amortization | 215,097 | 13,426 | 220 | -- | 228,743 |
| Income tax | 49,733 | 6,703 | 2,824 | -- | 59,260 |
| Operating income | 289,511 | 15,595 | 4,563 | -- | 309,669 |
| Interest charges, net of AFUDC | 190,861 | 5,516 | -- | -- | 196,377 |
| Net income | 104,044 | 9,455 | 4,384 | (7,831) | 110,052 |
| Goodwill, net | -- | 125,555 | -- | -- | 125,555 |
| Total assets | 5,323,129 | 319,248 | 129,756 | -- | 5,772,133 |
| Construction expenditures - excluding equity AFUDC | 224,165 | -- | -- | -- | 224,165 |
| Additions to other property, plant and equipment | -- | 11,621 | -- | -- | 11,621 |
_____________________ 2004 (Dollars in Thousands) | | Regulated Utility | | Other | | Reconciling Item | | Puget Energy Total | |
| Revenues | | $ | 2,192,340 | | $ | 6,537 | | $ | -- | | $ | 2,198,877 | |
| Depreciation and amortization | | | 228,310 | | | 256 | | | -- | | | 228,566 | |
| Income tax | | | 75,754 | | | 1,002 | | | -- | | | 76,756 | |
| Operating income | | | 285,258 | | | 2,420 | | | -- | | | 287,678 | |
| Interest charges, net of AFUDC | | | 166,411 | | | 219 | | | -- | | | 166,630 | |
| Net income from continuing operations | | | 123,401 | | | 2,009 | | | -- | | | 125,410 | |
Total assets1 | | | 5,509,358 | | | 70,641 | | | 271,220 | | | 5,851,219 | |
| Construction expenditures - excluding equity AFUDC | | | 393,891 | | | -- | | | -- | | | 393,891 | |
_______________1 | Revenues for the Regulated Utility segment were reduced $108.7 million and $77.1 million in 2003 and 2002, respectivelyReconciling item consists of assets of InfrastruX which is presented as a result of a reclassification from implementing EITF No. 03-11 on January 1, 2004. The reclassification had no effect on financial position or results ofdiscontinued operations.
|
2 |
Reconciling item is preferred stock dividend accrual at PSE that is treated as an other deduction at Puget Energy.
|
The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentationstatement of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business.
| Puget Energy | | | | | | | |
| (Unaudited; dollars in thousands except per share amounts) | | | | | | | |
| 2006 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 877,735 | | $ | 574,222 | | $ | 519,463 | | $ | 934,273 | |
| Operating income | | | 112,825 | | | 66,540 | | | 52,254 | | | 94,998 | |
| Net income before cumulative effect of accounting change | | | 92,520 | | | 53,529 | | | 15,922 | | | 57,156 | |
| Net income | | | 92,609 | | | 53,529 | | | 15,922 | | | 57,156 | |
| Basic earnings per common share | | $ | 0.80 | | $ | 0.46 | | $ | 0.14 | | $ | 0.49 | |
| Diluted earnings per common share | | $ | 0.79 | | $ | 0.46 | | $ | 0.14 | | $ | 0.49 | |
| (Unaudited; dollars in thousands except per share amounts) | | | | | | | |
| 2005 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 741,653 | | $ | 510,114 | | $ | 490,383 | | $ | 831,061 | |
| Operating income | | | 110,534 | | | 51,919 | | | 47,528 | | | 93,180 | |
| Net income before cumulative effect of accounting change | | | 71,075 | | | 13,895 | | | 5,911 | | | 64,915 | |
| Net income | | | 71,075 | | | 13,895 | | | 5,911 | | | 64,844 | |
| Basic earnings per common share | | $ | 0.71 | | $ | 0.14 | | $ | 0.06 | | $ | 0.60 | |
| Diluted earnings per common share | | $ | 0.71 | | $ | 0.13 | | $ | 0.06 | | $ | 0.60 | |
| Puget Sound Energy | | | | | | | | | |
| (Unaudited; dollars in thousands) | | | | | | | | | |
| 2006 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 877,735 | | $ | 574,224 | | $ | 519,463 | | $ | 934,273 | |
| Operating income | | | 113,002 | | | 66,829 | | | 52,305 | | | 95,353 | |
| Net income before cumulative effect of accounting change | | | 73,750 | | | 30,100 | | | 15,632 | | | 57,168 | |
| Net income | | | 73,839 | | | 30,100 | | | 15,632 | | | 57,168 | |
| (Unaudited; dollars in thousands) | | | | | | | | | |
| 2005 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 741,653 | | $ | 510,114 | | $ | 490,383 | | $ | 831,062 | |
| Operating income | | | 110,555 | | | 52,044 | | | 47,705 | | | 93,195 | |
| Net income before cumulative effect of accounting change | | | 72,182 | | | 12,166 | | | 6,170 | | | 56,323 | |
| Net income | | | 72,182 | | | 12,166 | | | 6,170 | | | 56,252 | |
| (Unaudited; dollars in thousands except per share amounts) | | | | | | | |
| 2004 QUARTER | | FIRST | | SECOND1 | | THIRD | | FOURTH2 | |
| Operating revenues | | $ | 743,470 | | $ | 515,939 | | $ | 514,951 | | $ | 794,452 | |
| Operating income | | | 109,680 | | | 35,216 | | | 53,825 | | | 18,031 | |
| Other income | | | 64 | | | 1,586 | | | 318 | | | 2,324 | |
| Net income (loss) | | | 66,365 | | | (6,780 | ) | | 11,124 | | | (15,687 | ) |
| Basic earnings per common share | | $ | 0.67 | | $ | (0.07 | ) | $ | 0.11 | | $ | (0.16 | ) |
| Diluted earnings per common share | | $ | 0.67 | | $ | (0.07 | ) | $ | 0.11 | | $ | (0.16 | ) |
| | | | | | | | |
| (Unaudited; dollars in thousands except per share amounts) | | | | | | | |
| 2003 QUARTER | | FIRST | | SECOND | | THIRD | | FOURTH | |
Operating revenues3 | | $ | 640,637 | | $ | 524,060 | | $ | 490,258 | | $ | 727,849 | |
| Operating income | | | 91,385 | | | 66,407 | | | 54,389 | | | 92,994 | |
| Other income | | | 704 | | | 2,247 | | | 2,663 | | | (4,050 | ) |
| Net income before cumulative effect of accounting change | | | 42,889 | | | 20,598 | | | 9,885 | | | 42,993 | |
| Net income | | | 42,720 | | | 20,598 | | | 9,885 | | | 42,993 | |
| Basic earnings per common share | | $ | 0.46 | | $ | 0.22 | | $ | 0.10 | | $ | 0.44 | |
| Diluted earnings per common share | | $ | 0.45 | | $ | 0.22 | | $ | 0.10 | | $ | 0.44 | |
| | | | | | | | |
| (Unaudited; dollars in thousands except per share amounts) | | | | | | | |
| 2002 QUARTER | | FIRST | | SECOND | | THIRD | | FOURTH | |
Operating revenues3 | | $ | 720,997 | | $ | 529,803 | | $ | 442,577 | | $ | 621,804 | |
| Operating income | | | 76,571 | | | 76,833 | | | 57,098 | | | 99,168 | |
| Other income | | | 384 | | | 3,441 | | | 230 | | | 1,403 | |
| Net income | | | 24,466 | | | 29,429 | | | 6,572 | | | 49,585 | |
| Basic and diluted earnings per common share | | $ | 0.28 | | $ | 0.34 | | $ | 0.07 | | $ | 0.55 | |
_____________________
1 | The second quarter 2004 includes a disallowance of $36.5 million or $23.7 million after-tax related to a Washington Commission order stating PSE did not prudently manage gas costs for the Tenaska generating facility.Condensed Financial Information of Puget Energy
|
2 | The fourth quarter 2004 includes a non-cash goodwill impairment charge of $91.2 million or $76.6 million after-tax and minority interest related to goodwill at InfrastruX.
|
3 | Operating revenues in 2003 and 2002 were revised as a result of a reclassification due to Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gaines and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03,” which became effective on January 1, 2004. First, second, third and fourth quarter 2003 revenues were reduced by $35.3 million, $33.8 million, $25.3 million and $14.3 million, respectively. First, second, third and fourth quarter 2002 revenues were reduced by $18.1 million, $11.0 million, $15.9 million and $32.1 million, respectively. The impact of EITF No. 03-11 had no effect on financial position or results of operations.
|
Puget Energy Condensed Statements of
INCOME
(Dollars in Thousands, except per share amounts) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Equity in earnings of subsidiary | | $ | 177,585 | | $ | 146,769 | | $ | 126,192 | |
| Other operations and maintenance | | | (1,830 | ) | | (1,354 | ) | | (983 | ) |
| Income taxes | | | 957 | | | 1,021 | | | 420 | |
| Other income (deductions): | | | | | | | | | | |
| Charitable foundation contributions | | | (15,000 | ) | | -- | | | -- | |
| Interest Income | | | 356 | | | -- | | | -- | |
| Interest expense | | | -- | | | (224 | ) | | (219 | ) |
| Income taxes | | | 5,245 | | | -- | | | -- | |
| Net income from continuing operations | | | 167,313 | | | 146,212 | | | 125,410 | |
| Equity in earnings of discontinued subsidiary | | | 51,903 | | | 9,514 | | | (70,388 | ) |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Basic earnings per share from continuing operations | | | 1.44 | | | 1.43 | | | 1.26 | |
| Discontinued operations | | | 0.45 | | | 0.09 | | | (0.71 | ) |
| Basic earnings per share | | $ | 1.89 | | $ | 1.52 | | $ | 0.55 | |
| Diluted earnings per share from continuing operations | | $ | 1.44 | | $ | 1.42 | | $ | 1.25 | |
| Discontinued operations | | | 0.44 | | | 0.09 | | | (0.70 | ) |
| Diluted earnings per share | | $ | 1.88 | | $ | 1.51 | | $ | 0.55 | |
See accompanying notes to the consolidated financial statements.
Puget Energy Condensed
Puget Sound EnergyBALANCE SHEETS
| (Unaudited; dollars in thousands) | | | | | | | | | |
| 2004 QUARTER | | FIRST | | SECOND1 | | THIRD | | FOURTH | |
| Operating revenues | | $ | 668,714 | | $ | 423,123 | | $ | 415,026 | | $ | 692,012 | |
| Operating income | | | 108,845 | | | 30,704 | | | 50,363 | | | 98,330 | |
| Other income | | | 68 | | | 1,570 | | | 356 | | | 2,368 | |
| Net income (loss) | | | 66,898 | | | (9,540 | ) | | 9,647 | | | 59,187 | |
| | | | | | | | | | |
| (Unaudited; dollars in thousands) | | | | | | | | | |
| 2003 QUARTER | | | | SECOND | | THIRD | | FOURTH | |
Operating revenues2 | | $ | 569,960 | | $ | 431,717 | | $ | 397,116 | | $ | 642,224 | |
| Operating income | | | 93,935 | | | 62,120 | | | 51,046 | | | 90,803 | |
| Other income | | | 691 | | | 2,309 | | | 2,620 | | | (4,033 | ) |
| Net income before cumulative effect of accounting change | | | 48,270 | | | 19,614 | | | 9,488 | | | 42,683 | |
| Net income | | | 48,101 | | | 19,614 | | | 9,488 | | | 42,683 | |
| | | | | | | | | | |
| (Unaudited; dollars in thousands) | | | | | | | | | |
| 2002 QUARTER | | FIRST | | SECOND | | THIRD | | FOURTH | |
Operatingrevenues2 | | $ | 660,236 | | $ | 453,681 | | $ | 350,204 | | $ | 531,531 | |
| Operating income | | | 74,732 | | | 72,724 | | | 51,367 | | | 95,769 | |
| Other income | | | 309 | | | 3,455 | | | 210 | | | 1,241 | |
| Net income | | | 25,698 | | | 28,839 | | | 4,701 | | | 49,709 | |
_____________________
1 | The second quarter 2004 includes a disallowance of $36.5 million or $23.7 million after-tax related to a Washington Commission order stating PSE did not prudently manage gas costs for the Tenaska generating facility.
|
2 | Operating revenues in 2003 and 2002 were revised as a result of a reclassification due to Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gaines and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03,” which became effective on January 1, 2004. First, second, third and fourth quarter 2003 revenues were reduced by $35.3 million, $33.8 million, $25.3 million and $14.3 million, respectively. First, second, third and fourth quarter 2002 revenues were reduced by $18.1 million, $11.0 million, $15.9 million and $32.1 million, respectively. The impact of EITF No. 03-11 had no effect on financial position or results of operations.
|
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Assets: | | | | | |
| Investment in & advances to Subs | | $ | 761,686 | | $ | 714,214 | |
| Current assets: | | | | | | | |
| Cash | | | 25 | | | 1 | |
| Receivables from affiliates | | | 24,659 | | | 1,618 | |
| Prepayments and other | | | 570 | | | 573 | |
| Tax receivable | | | 388 | | | -- | |
| Total current assets | | | 25,642 | | | 2,192 | |
| Long-term assets: | | | | | | | |
| Restricted cash | | | 3,813 | | | -- | |
| Deferred income taxes | | | 3,939 | | | 353 | |
| Other | | | 217 | | | 460 | |
| Total long-term assets | | | 7,969 | | | 813 | |
| Total assets | | $ | 795,297 | | $ | 717,219 | |
| Capitalization and liabilities: | | | | | | | |
| Common equity | | $ | 785,432 | | $ | 699,148 | |
| Total capitalization | | | 785,432 | | | 699,148 | |
| Minority interest in discontinued operations | | | -- | | | 6,816 | |
| Current liabilities: | | | | | | | |
| Accounts payable | | | 325 | | | -- | |
| Payable to affiliates | | | -- | | | 5,427 | |
| Taxes | | | -- | | | 960 | |
| Salaries and wages | | | 531 | | | -- | |
| Other | | | -- | | | 4,763 | |
| Total current liabilities | | | 856 | | | 11,150 | |
| Long-term liabilities: | | | | | | | |
| Other deferred credits | | | 9,009 | | | 105 | |
| Total long-term liabilities | | | 9,009 | | | 105 | |
| Total capitalization and liabilities | | $ | 795,297 | | $ | 717,219 | |
See accompanying notes to the consolidated financial statements.
CASH FLOWS
(Dollars in Thousands) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Operating activities: | | | | | | | |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
Deferred income taxes and tax credits - net | | | (3,586 | ) | | (252 | ) | | 63 | |
| Equity in earnings of discontinued subsidiary | | | (51,903 | ) | | (9,514 | ) | | 70,388 | |
| Equity in earnings of subsidiary | | | (177,586 | ) | | (146,769 | ) | | (126,192 | ) |
| Other | | | (94 | ) | | 303 | | | (450 | ) |
| Dividends received from subsidiaries | | | 109,782 | | | 89,199 | | | 87,700 | |
| (Increase) decrease in accounts receivable | | | (355 | ) | | (1,617 | ) | | -- | |
| (Increase) decrease in tax receivable | | | (388 | ) | | 319 | | | (319 | ) |
| (Increase) decrease in prepayments | | | -- | | | -- | | | 9 | |
| Increase (decrease) in accounts payable | | | 325 | | | -- | | | -- | |
| Increase (decrease) in affiliated payables | | | (5,427 | ) | | 4,297 | | | 304 | |
| Increase (decrease) in accrued tax payable | | | (960 | ) | | 960 | | | -- | |
| Increase (decrease) in accrued expenses and other | | | (4,763 | ) | | (208 | ) | | -- | |
| Net cash provided (used) by operating activities | | | 84,261 | | | 92,444 | | | 86,525 | |
| Investing activities: | | | | | | | | | | |
| Cash proceeds from sale of InfrastruX | | | 275,000 | | | -- | | | -- | |
| Increase in restricted cash | | | (3,813 | ) | | -- | | | -- | |
| Investment in subsidiaries | | | (70,114 | ) | | (314,686 | ) | | (5,016 | ) |
| Loans to subsidiaries | | | (24,303 | ) | | -- | | | -- | |
| Net cash provided (used) by investing activities | | | 176,770 | | | (314,686 | ) | | (5,016 | ) |
| Financing activities: | | | | | | | | | | |
| Dividends paid | | | (104,332 | ) | | (88,071 | ) | | (86,873 | ) |
| Common stock issued | | | 5,877 | | | 317,607 | | | 5,413 | |
| Long-term debt and lease payments | | | (151,849 | ) | | (5,000 | ) | | -- | |
| Payments made to minority interest | | | (10,451 | ) | | -- | | | -- | |
| Issue costs of stocks | | | (252 | ) | | (2,293 | ) | | (49 | ) |
| Net cash provided (used) by financing activities | | | (261,007 | ) | | 222,243 | | | (81,509 | ) |
| Increase (decrease) in cash | | | 24 | | | 1 | | | -- | |
| Cash at beginning of year | | | 1 | | | -- | | | -- | |
| Cash at end of year | | $ | 25 | | $ | 1 | | $ | -- | |
See accompanying notes to the consolidated financial statements.
Valuation and Qualifying Accounts and Reserves
Puget Energy (Dollars in Thousands) | | Balance At Beginning of Period | | Additions Charged to Costs and Expenses | | Deductions | | Balance At End Of Period | |
| Year Ended December 31, 2006 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 3,074 | | $ | 7,623 | | $ | 7,935 | | $ | 2,762 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Deferred tax asset valuation allowance | | | 16,075 | | | -- | | | 16,075 | | | -- | |
| Year Ended December 31, 2005 | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,670 | | $ | 8,275 | | $ | 7,871 | | $ | 3,074 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Deferred tax asset valuation allowance | | | 17,988 | | | -- | | | 1,913 | | | 16,075 | |
| Year Ended December 31, 2004 | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,484 | | $ | 7,343 | | $ | 7,157 | | $ | 2,670 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Deferred tax asset valuation allowance | | | -- | | | 17,988 | | | -- | | | 17,988 | |
PUGET ENERGY (DOLLARS IN THOUSANDS) | | BALANCE AT BEGINNING OF PERIOD | | ADDITIONS CHARGED TO COSTS AND EXPENSES | | DEDUCTIONS | | BALANCE AT END OF PERIOD | |
| YEAR ENDED DECEMBER 31, 2004 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 4,359 | | $ | 7,668 | | $ | 7,507 | | $ | 4,520 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Deferred tax asset valuation allowance | | | -- | | | 17,988 | | | -- | | | 17,988 | |
| Tenaska disallowance reserve | | | -- | | | 36,490 | | | 33,334 | | | 3,156 | |
| | | | | | | | | | | |
| YEAR ENDED DECEMBER 31, 2003 | | | | | | | | | | |
Puget Sound Energy (Dollars in Thousands) | | | Balance At Beginning of Period | | Additions Charged to Costs and Expenses | | Deductions | | Balance At End Of Period | |
| Year Ended December 31, 2006 | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 3,863 | | $ | 9,387 | | $ | 8,891 | | $ | 4,359 | | | $ | 3,074 | | $ | 7,623 | | $ | 7,935 | | $ | 2,762 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Industrial accident reserve | | | 2,000 | | | -- | | | 2,000 | | | -- | | |
| Gas transportation contracts reserve | | | 139 | | | -- | | | 139 | | | -- | | |
| Year Ended December 31, 2005 | | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | | $ | 2,670 | | $ | 8,275 | | $ | 7,871 | | $ | 3,074 | |
| Reserve on wholesale sales | | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Year Ended December 31, 2004 | | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | | $ | 2,484 | | $ | 7,343 | | $ | 7,157 | | $ | 2,670 | |
| Reserve on wholesale sales | | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| | | | | | | | | | |
| YEAR ENDED DECEMBER 31, 2002 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 5,488 | | $ | 11,191 | | $ | 12,816 | | $ | 3,863 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Industrial accident reserve | | | -- | | | 4,000 | | | 2,000 | | | 2,000 | |
| Gas transportation contracts reserve | | | 139 | | | -- | | | -- | | | 139 | |
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | | BALANCE AT BEGINNING OF PERIOD | | ADDITIONS CHARGED TO COSTS AND EXPENSES | | DEDUCTIONS | | BALANCE AT END OF PERIOD | |
| Year Ended December 31, 2004 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,484 | | $ | 7,343 | | $ | 7,157 | | $ | 2,670 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Tenaska disallowance reserve | | | -- | | | 36,490 | | | 33,334 | | | 3,156 | |
| | | | | | | | | | |
| YEAR ENDED DECEMBER 31, 2003 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 1,990 | | $ | 9,385 | | $ | 8,891 | | $ | 2,484 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Industrial accident reserve | | | 2,000 | | | -- | | | 2,000 | | | -- | |
| Gas transportation contracts reserve | | | 139 | | | -- | | | 139 | | | -- | |
| | | | | | | | | | |
| YEAR ENDED DECEMBER 31, 2002 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 3,666 | | $ | 11,140 | | $ | 12,816 | | $ | 1,990 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Industrial accident reserve | | | -- | | | 4,000 | | | 2,000 | | | 2,000 | |
| Gas transportation contracts reserve | | | 139 | | | -- | | | -- | | | 139 | |
| CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
PUGET ENERGYPugetEnergy
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2004,2006, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial officerOfficer of Puget Energy concluded that these disclosure controls and procedures are effective.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTINGChanges in Internal Control Over Financial Reporting
There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended December 31, 20042006 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGManagement’s Report on Internal Control Over Financial Reporting
Puget Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of Puget Energy’s President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring OrganizationOrganizations of the Treadway Commission. Based on the assessment, Puget Energy’s management concluded that its internal control over financial reporting was effective as of December 31, 2004.2006.
Puget Energy’s management assessment of the effectiveness of internal control over financial reporting as of December 31, 2004,2006, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
PUGET SOUND ENERGYPuget Sound Energy
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2004,2006, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial officerOfficer of PSE concluded that these disclosure controls and procedures are effective.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTINGChanges in Internal Control Over Financial Reporting
There have been no changes in PSE’s internal control over financial reporting during the quarter ended December 31, 2004,2006, that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGManagement’s Report on Internal Control Over Financial Reporting
PSE’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of PSE’s President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Sound Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring OrganizationOrganizations of the Treadway Commission. Based on the assessment, PSE’s management concluded that its internal control over financial reporting was effective as of December 31, 2004.2006.
PSE’s management assessment of the effectiveness of internal control over financial reporting as of December 31, 2004,2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
None.
ITEM 10. 10.DIRECTORS, EXECUTIVE AND EXECUTIVE OFFICERS OF THE REGISTRANTSCORPORATE GOVERNANCE
PUGET ENERGYPuget Energy
The information required by this item with respect to Puget Energy is incorporated herein by reference to the material under “Available Information” in Part I of this report and “Proposal 1 - Election of Directors,” “Directors Continuing in Office,” “Other Director Information,” “Board of Directors and Corporate Governance”Governance,” “Director Compensation” and “Security Ownership of Directors, Executive Officers and Executive Officers--Section 16(a)Certain Beneficial Ownership Reporting Compliance”Owners” in Puget Energy’s proxy statement for its 20052007 Annual Meeting of Shareholders (Commission file No. 1-16305). Reference is also made to the information regarding Puget Energy’s executive officers set forth in Part I of this report.
PUGET SOUND ENERGYPuget Sound Energy
The information called for by Item 10 with respect to PSE is omitted pursuant to General Instruction I(2)(c) to Form 10-K (omission of information by certain wholly owned subsidiaries).
PUGET ENERGYPuget Energy
The information required by this item with respect to Puget Energy is incorporated herein by reference to the material under “Director Compensation,” “Executive“Compensation Discussion and Analysis” and “Summary Compensation” and “Employment Contracts, Termination of Employment and Change-In-Control Arrangements” in Puget Energy’s proxy statement for its 20052007 Annual Meeting of Shareholders (Commission File No. 1-16305).
PUGET SOUND ENERGYPuget Sound Energy
The information called for by Item 11 with respect to PSE is omitted pursuant to General Instruction I(2)I (2)(c) to Form 10-K (omission of information by certain wholly owned subsidiaries).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS |
PUGET ENERGYPuget Energy
EQUITY COMPENSATION PLAN INFORMATIONEquity Compensation Plan Information
The information required by this item with respect to Puget Energy is incorporated herein by reference to the material under “Equity Compensation Plan Information” in Puget Energy’s proxy statement for its 20052007 Annual Meeting of Shareholders (Commission File No. 1-16305).
BENEFICIAL OWNERSHIP Beneficial Ownership
The information required by this item with respect to Puget Energy is incorporated herein by reference to the material under “Security Ownership of Directors, Executive Officers and Executive Officers”Certain Beneficial Owners” in Puget Energy’s proxy statement for its 20052007 Annual Meeting of Shareholders (Commission File No. 1-16305).
PUGET SOUND ENERGYPuget Sound Energy
EQUITY COMPENSATION PLAN INFORMATIONEquity Compensation Plan Information
The information called for by this item with respect to PSE is omitted pursuant to General Instruction I(2)I (2)(e) to Form 10-K (omission of information by wholly owned subsidiaries).
BENEFICIAL OWNERSHIPBeneficial Ownership
As of December 31, 2004,2006, all of the issued and outstanding shares of PSE’s common stock were held beneficially and of record by Puget Energy.
| CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
None.
| PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accounting firm, for the year ended December 31 were as follows:
| | | 2004 | | 2003 | |
(DOLLARS IN THOUSANDS) | | PUGET ENERGY | | PSE | | PUGET ENERGY | | PSE | |
Audit fees1 | | $ | 2,084 | | $ | 1,695 | | $ | 850 | | $ | 453 | |
Audit related fees2 | | | 82 | | | 82 | | | 261 | | | 147 | |
Tax fees3 | | | 59 | | | 55 | | | 200 | | | 168 | |
| Total | | $ | 2,225 | | $ | 1,832 | | $ | 1,311 | | $ | 768 | |
_____________________| | | 2006 | | 2005 | |
| (Dollars in Thousands) | | Puget Energy | | PSE | | Puget Energy | | PSE | |
Audit fees1 | | $ | 1,653 | | $ | 1,530 | | $ | 2,023 | | $ | 1,422 | |
Audit related fees2 | | | 100 | | | 100 | | | 103 | | | 81 | |
Tax fees3 | | | 34 | | | 34 | | | 45 | | | 33 | |
| Total | | $ | 1,787 | | $ | 1,664 | | $ | 2,171 | | $ | 1,536 | |
_______________1 | For professional services rendered for the audit of Puget Energy’s and PSE’s annual financial statements, reviews of financial statements included in the Companies’ Forms 10-Q and consents and reviews of documents filed with the Securities and Exchange Commission. The 20042006 fees are estimated and include an aggregate amount of $1,251,000$1.1 million and $1,156,000$1.0 million billed to Puget Energy and PSE, respectively, through December 2006. The 2005 fees include an aggregate amount of $1.1 million and $1.0 million billed to Puget Energy and PSE, respectively, through December 31, 2004. The 2003 fees include an aggregate amount of approximately $444,000 and $277,000 billed to Puget Energy and PSE, respectively, through December 31, 2003. In 2004, audit fees included $1,284,000 and $1,120,000 for professional services rendered for the audits of Puget Energy’s and PSE’s assessment of, and the effectiveness of, internal controls over financial reporting (Sarbanes-Oxley 404).2005. |
2 | Consists of employee benefit plan audits, due diligence reviews and assistance with Sarbanes-Oxley readiness. |
3 | Consists of tax planning, consulting and tax return reviews. |
The Audit CommitteesCommittee of the Company havehas adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent auditor. The policies are designed to ensure that the provision of these services does not impair the auditor’s independence. Under the policies, unless a type of service to be provided by the independent auditor has received general pre-approval, it will require specific pre-approval by thean Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by thean Audit Committee.
The annual audit services engagement terms and fees, as well as any changes in terms, conditions and fees relating to the engagement, are subject to specific pre-approval by the Audit Committees. In addition, on an annual basis, the Audit Committees grant general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent auditor.registered public accounting firm. With respect to each proposed pre-approved service, the independent auditorregistered public accounting firm is required to provide detailed back-up documentation to the Audit Committees regarding the specific services to be provided. Under the policies, the Audit Committees may delegate pre-approval authority to one or more of their members. The member or members to whom such authority is delegated shall report any pre-approval decision to an Audit Committee at its next scheduled meeting. The Audit Committees do not delegate responsibilities to pre-approve services performed by the independent auditorregistered public accounting firm to management.
For 20042006 and 2005, all audit and non-audit services were pre-approved.
| EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| a) | Documents filed as part of this report: |
| 2) | Financial Statement Schedules. Financial Statement Schedules of the Company, located on page 123, as required for the years ended December 31, 2004, 20032006, 2005 and 2002,2004, consist of the following: |
| I. | Condensed Financial Information of Puget |
| II. | Valuation of Qualifying Accounts |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUGET ENERGY, INC. | | PUGET SOUND ENERGY |
| | | |
| /s/ Stephen P. Reynolds | | /s/ Stephen P. Reynolds |
| Stephen P. Reynolds | | Stephen P. Reynolds |
| Chairman, President and Chief Executive Officer | | Chairman, President and Chief Executive Officer |
| | | |
Date: March 1, 20052007 | | Date: March 1, 20052007 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each registrant and in the capacities and on the dates indicated.
SIGNATURESignature | TITLETitle | DATEDate |
| | (Puget Energy and PSE unless otherwise noted) |
| | |
/s/ Douglas P. Beighle | Chairman of the Board | March 1, 2005 |
(Douglas P. Beighle) | | |
| | |
| | |
| /s/ Stephen P. Reynolds | Chairman, President Chief Executive Officer and | March 1, 2007 |
| (Stephen P. Reynolds) | DirectorChief Executive Officer | |
| | | |
| | | |
| /s/ Bertrand A. Valdman | Senior Vice President Finance and | |
| (Bertrand A. Valdman) | Chief Financial Officer | |
| | | |
| | | |
| /s/ James W. Eldredge | Vice President, Corporate Secretary and Chief | |
| (James W. Eldredge) | and Chief Accounting Officer | |
| | | |
| | | |
| /s/ William S. Ayer | Director | |
| (William S. Ayer) | | |
| | |
| | |
/s/ Charles W. Bingham | Director | |
(Charles W. Bingham) | | |
| | | |
| | | |
| /s/ Phyllis J. Campbell | Director | |
| (Phyllis J. Campbell) | | |
| | | |
| | | |
| /s/ Craig W. Cole | Director | |
| (Craig W. Cole) | | |
| | | |
| | | |
/s/ Robert L. Dryden | Director | |
(Robert L. Dryden) | | |
| | |
| | |
| /s/ Stephen E. Frank | Director | |
| (Stephen E. Frank) | | |
| | | |
| | |
| /s/ Tomio Moriguchi | Director | |
| (Tomio Moriguchi) | | |
| | | |
| | | |
| /s/ Dr. Kenneth P. Mortimer | Director | |
| (Dr. Kenneth P. Mortimer) | | |
| | | |
| | | |
| /s/ Sally G. Narodick | Director | |
| (Sally G. Narodick) | | |
| | |
| | |
| /s/ Herbert B. Simon | Director | |
| (Herbert B. Simon) | | |
| | |
| | |
| /s/ George W. Watson | Director | |
| (George W. Watson) | | |
Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission and are incorporated herein by reference.
| | 3(i).1 | Restated Articles of Incorporation of Puget Energy (Incorporated by reference to Exhibit 99.2, Puget Energy’s Current Report on Form 8-K fileddated January 2, 2001, Commission File No. 333-77491). |
| | 3(i).2 | Restated Articles of Incorporation of PSE (included as Annex F to the Joint Proxy Statement/Prospectus filed February 1, 1996, Registration No. 333-617). |
| | 3(ii).1 | Amended and Restated Bylaws of Puget Energy dated March 7, 2003 (Exhibit 3(ii).1 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-16305 and 1-4393). |
| | 3(ii).2 | Amended and Restated Bylaws of PSE dated March 7, 2003 (Exhibit 3(ii).2 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-16305 and 1-4393). |
| | 4.1 | Fortieth through Seventy-ninthEighty-fourth Supplemental Indentures defining the rights of the holders of PSE’s Electric Utility First Mortgage Bonds (Exhibit 2-d to Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347; Exhibits 2-e through and including 2-k to Registration No. 2-60200; Exhibit 4-h to Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200; ExhibitsExhibit 2-m to Registration No. 2-37645; ExhibitExhibits 2-o through and including 2-s to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-62883; Exhibit 2-h to Registration No. 2-65831; Exhibit (4)-j-1 to Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393; Exhibits (4)-b and (4)-c to Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278; Exhibit 4.25 to Registration No. 333-41181; Exhibit 4.27 to Current Report on Form 8-K dated March 5, 1999; Exhibit 4.2 to Current Report on formForm 8-K dated November 2, 2000; and Exhibit 4.2 to Current Report on Form 8-K dated June 3, 2003).2003; Exhibit 4.28 to Annual Report on Form 10-K for fiscal year ended December 31, 2004, Commission File No. 1-16305 and 1-4393; Exhibit 4.1 to Current Report on Form 8-K, dated May 23, 2005, Commission File No. 1-16305 and 1-4393; Exhibit 4.30 to Annual Report on Form 10-K for fiscal year ended December 31, 2005, Commission file No. 1-16305 and 1-4393); and Exhibit 4.1 to Current Report on Form 8-K dated September 14, 2006, Commission File No. 1-4393. |
| | 4.2 | Indenture defining the rights of the holders of PSE’s senior notes (incorporated herein by reference to Exhibit 4-a to PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393). |
| | 4.3 | First Supplemental Indenture defining the rights of the holders of PSE’s senior notes, Series A (incorporated herein by reference to Exhibit 4-b to PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393). |
| | 4.4 | Second Supplemental Indenture defining the rights of the holders of PSE’s senior notes, Series B (incorporated herein by reference to Exhibit 4.6 to PSE’s Current Report on Form 8-K, dated March 5, 1999, Commission File No. 1-4393). |
| | 4.5 | Third Supplemental Indenture defining the rights of the holders of PSE’s senior notes, Series C (incorporated herein by reference to Exhibit 4.1 to PSE’s Current Report on Form 8-K, dated November 2, 2000, Commission File No. 1-4393). |
| | 4.6 | Fourth Supplemental Indenture defining the rights of the holders of PSE’s senior notes (incorporated herein by reference to Exhibit 4.1 to PSE’s Current Report on Form 8-K, dated June 3, 2003, Commission File No. 1-4393). |
| | 4.7 | Rights Agreement dated as of December 21, 2000 between Puget Energy and Mellon Investor Services LLC,Wells Fargo Bank, N.A., as Rights Agent (incorporated herein by reference to Exhibit 2.14.1 to PSE’sPuget Energy’s Registration Statement on Form 8-A,S-3, dated January 2, 2001,11, 2007, Commission File No. 1-16305). |
| | 4.8 | Indenture between PSE and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.1 of PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393). |
| | 4.9 | Amended and Restated Declaration of Trust between Puget Sound Energy Capital Trust and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.2 of PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393). |
| | 4.10 | Series A Capital Securities Guarantee Agreement between PSE and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.3 of PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393). |
| | 4.11 | First Supplemental Indenture dated as of October 1, 1959 (Exhibit 4-D to Registration No. 2-17876). |
| | 4.12 | Sixth Supplemental Indenture dated as of August 1, 1966 (Exhibit to Form 8-K for month of August 1966, File No. 0-951). |
| | 4.13 | Seventh Supplemental Indenture dated as of February 1, 1967 (Exhibit 4-M, Registration No. 2-27038). |
| | 4.14 | Sixteenth Supplemental Indenture dated as of June 1, 1977 (Exhibit 6-05 to Registration No. 2-60352). |
| | 4.15 | Seventeenth Supplemental Indenture dated as of August 9, 1978 (Exhibit 5-K.18 to Registration No. 2-64428). |
| | 4.16 | Twenty-second Supplemental Indenture dated as of July 15, 1986 (Exhibit 4-B.20 to Form 10-K for the year ended September 30, 1986, File No. 0-951). |
| | 4.17 | Twenty-seventh Supplemental Indenture dated as of September 1, 1990 (Exhibit 4-B.20, Form 10-K for the year ended September 30, 1998, File No. 10-951). |
| | 4.18 | Twenty-eighth Supplemental Indenture dated as of July 31, 1991 (Exhibit 4-A, Form 10-Q for the quarter ended March 31, 1993, File No. 0-951). |
| | 4.19 | Twenty-ninth Supplemental Indenture dated as of June 1, 1993 (Exhibit 4-A to Registration No. 33-49599). |
| | 4.20 | Thirtieth Supplemental Indenture dated as of August 15, 1995 (incorporated herein by reference to Exhibit 4-A of Washington Natural Gas Company’s S-3 Registration Statement, Registration No. 33-61859). |
| | 4.21 | Thirty-first Supplemental Indenture dated February 10, 1997 (Exhibit 4.30 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-6305 and 1-4393). |
| | 4.22 | Unsecured DebtThirty-second Supplemental Indenture between Puget Sound Energy and Bank One Trust Company, N.A. dated as of May 18, 2001,April 1, 2005, defining the rights of the holders of Puget Sound Energy’s unsecured debentures (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy’s Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393).PSE’s gas utility First Mortgage Bond. |
| | 4.23 | FirstThirty-third Supplemental Indenture to the Unsecured Debt Indenture dated as of May 18, 2001April 27, 2005, defining the rights of 8.40% Subordinated Deferrable Interest Debentures due June 30, 2041 (incorporated herein by reference to Exhibit 4.4 to Puget Sound Energy’s Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393).the holders of PSE’s gas utility First Mortgage Bond. |
| | 4.24 | Amended and Restated Declaration of Trust of Puget Sound Energy Trust II dated as of May 18, 2001 (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393). |
| 4.25 | Preferred Securities Guarantee Agreement, dated May 18, 2001 between Puget Sound Energy and Bank One Trust Company, N.A. for the benefit of the holders of the trust preferred securities of the Puget Sound Energy Trust II (incorporated herein by reference to Exhibit 4.5 to Puget Sound Energy’s Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393). |
| 4.26 | Pledge Agreement dated March 11, 2003 between Puget Sound Energy and Wells Fargo Bank Northwest, National Association, as Trustee (incorporated herein by reference to Exhibit 4.24 to the Company’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 dated July 11, 2003, Commission File No. 333-82940-02). |
| | 4.27 4.25 | Loan Agreement dated as of March 1, 2003, between the City of Forsyth, Rosebud County, Montana and Puget Sound Energy (incorporated herein by reference to Exhibit 4.25 to the Company’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3, dated July 11, 2003, Commission File No. 333-82490-02). |
* | 4.28 | Eightieth Supplemental Indenture dated as of April 30, 2004 defining the rights of the holders of PSE’s First Mortgage Bonds. |
| 10.1 | First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 13-d to Registration No. 2-24252). |
| | 10.2 | First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-p to Registration No. 2-24252). |
| | 10.3 | Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 4-1-a to Registration No. 2-13979). |
| | 10.4 | Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 4-c-1 to Registration No. 2-13979). |
| | 10.5 | Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Priest Rapids Project (Exhibit 4-d to Registration No. 2-13347). |
| | 10.6 | First Amendment to Power Sales Contract dated as of August 5, 1958 between PSE and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (Exhibit 13-h to Registration No. 2-15618). |
| | 10.7 | Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Wanapum Development (Exhibit 13-j to Registration No. 2-15618). |
| | 10.8 | Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Wanapum Development (Exhibit 13-1 to Registration No. 2-21824). |
| | 10.9 | Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-r to Registration No. 2-21824). |
| | 10.10 | Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and PSE (Exhibit 5-b to Registration No. 2-45702). |
| | 10.11 | Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and PSE (Exhibit 5-c to Registration No. 2-45702). |
| | 10.12 | Contract dated June 19, 1974 between PSE and P.U.D. No. 1 of Chelan County (Exhibit D to Form 8-K dated July 5, 1974). |
| | 10.13 | Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and PSE (Colstrip Project) (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.14 | Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.15 | Ownership and Operation Agreement dated as of May 6, 1981 between PSE and other Owners of the Colstrip Project (Colstrip 3 and 4) (Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.16 | Colstrip Project Transmission Agreement dated as of May 6, 1981 between PSE and Owners of the Colstrip Project (Exhibit (10)-58 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.17 | Common Facilities Agreement dated as of May 6, 1981 between PSE and Owners of Colstrip 1 and 2, and 3 and 4 (Exhibit (10)-59 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.18 | Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and PSE (Rocky Reach Project) (Exhibit (10)-66 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.19 | Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and PSE (Rock Island Project) (Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393). |
| | 10.20 | Power Sales Agreement between Northwestern Resources (formerly The Montana Power Company) and PSE dated as of October 1, 1989 (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393). |
| | 10.21 | Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among The Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company , PacifiCorp and PSE (Exhibit (10)-91 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393). |
| | 10.22 | Agreement for Firm Power Purchase (Thermal Project) dated December 27, 1990 among March Point Cogeneration Company, a California general partnership comprising San Juan Energy Company, a California corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation; and PSE (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393). |
| | 10.23 | Agreement for Firm Power Purchase dated March 20, 1991 between Tenaska Washington, Inc., a Delaware corporation, and PSE (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393). |
| | 10.24 | Amendment of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas and Electric Company and PSE (Exhibit (10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393). |
| | 10.25 | Capacity and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific Gas and Electric Company and PSE (Exhibit (10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393). |
| | 10.26 | General Transmission Agreement dated as of December 1, 1994 between the Bonneville Power Administration and PSE (BPA Contract No. DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393). |
| | 10.27 | PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and PSE (BPA Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393). |
| | 10.28 | Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 10-E.2 to Form 10-K for the year ended September 30, 1995, File No. 11271). |
| | 10.29 | Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (Exhibit 10-P to Form 10-K for the year ended September 30, 1994, File No. 1-11271). |
| | 10.30 | Puget Energy, Inc. Non-employee Director Stock Plan. (incorporated herein by reference to Exhibit 99.1 to Puget Energy’s Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-41157-99.) |
** | 10.31 | Amendment No. 1 to the Puget Energy, Inc. Non-employee Director Stock Plan, effective as of January 1, 2003 (Exhibit 10.94 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-16305 and 1-4393). |
** | 10.32 | Puget Energy, Inc. Employee Stock Purchase Plan. (Incorporated herein by reference to Exhibit 99.1 to Puget Energy’s Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-41113-99.) |
** | 10.33 | 1995 Long-Term Incentive Compensation Plan. (Exhibit 10.108 to Annual Report on Form 10-K for the fiscal year ended December 31, 2000, Commission File No. 1-4393 and 1-16305). |
** | 10.34 | 1995 Long-Term Incentive Compensation Plan (Incorporated herein by reference to Exhibit 99.1 to Puget Energy’s Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-61851-99.) |
** | 10.35 | Employment agreement with S. P. Reynolds, Chief Executive Officer and President dated January 7, 2002 (Exhibit 10.104 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2001, Commission File No. 1-16305 and 1-4393). |
| 10.36 | Credit Agreement dated May 27, 2004, among InfrastruX Group, Inc. and various Banks named therein, Union Bank of California as administrative agent. (Exhibit 10.2, Form 10-Q for the quarterly period ended June 30, 2004, Commission File No. 1-4393 and 1-16305). |
| 10.37 | Power Sales Contract dated April 15, 2002, between Public Utility District No. 2 of Grant County, Washington, and PSE, relating to the Priest Rapids Project. (Exhibit 10-1 to Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and 1-4393). |
| | 10.3810.31 | Reasonable Portion Power Sales Contract dated April 15, 2002, between Public Utility District No. 2 of Grant County, Washington, and PSE, relating to the Priest Rapids Project. (Exhibit 10-2 to Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and 1-4393). |
| | 10.3910.32 | Additional Power Sales Contract dated April 15, 2002, between Public Utility districtDistrict No. 2 of Grant County, Washington, and PSE, relating to the Priest Rapids Project. (Exhibit 10-3 to Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and 1-4393). |
| | 10.4010.33 | Amended and Restated Credit Agreement dated May 27, 2004,March 25, 2005 covering PSE and various banks named therein, UnionWachovia Bank of CaliforniaNational Association as administrative agent. (Exhibit 10.1,99.1 to Current Report on Form 10-Q for the quarterly period ended June 30, 2004,8-K, dated March 29, 2005, Commission File No. 1-4393 and 1-16305). |
| | 10.4110.34 | Receivable PurchaseFirst Amendment to the Amended and Restated Credit Agreement dated April 4, 2006 cover PSE and various banks named therein, Wachovia Bank National Association as administrative agent. (Exhibit 10.1 to the Current Report of Form 10-Q, dated March 31, 2006, Commission File Nos. 1-16305 and 1-4393). |
| 10.35 | Loan and Serving Agreement dated December 23, 2002,20, 2005, among PSE, Rainier Receivables,PSE Funding, Inc., and J.P. Morgan Chase Bank One, NA as program agent (Exhibit 10.10710.2 to the Current Report on Form 8-K dated December 22, 2005, Commission File No. 1-4393 and 1-16305). |
| 10.36 | Receivable Sale Agreement dated December 20, 2005, among PSE and PSE Funding, Inc. (Exhibit 10.1 to the Current Report on Form 8-K dated December 22, 2005, Commission File Nos. 1-16305 and 1-4393). |
| ** | 10.37 | Puget Energy, Inc. Non-employee Director Stock Plan. (Appendix B to definitive Proxy Statement, dated March 7, 2005, Commission File No. 1-16305). |
| ** | 10.38 | Puget Energy, Inc. Employee Stock Purchase Plan. (Incorporated herein by reference to Exhibit 99.1 to Puget Energy’s Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-41113-99.) |
| ** | 10.39 | Puget Energy 2005 Long-Term Incentive Plan. (Appendix A to definitive Proxy Statement, dated March 7, 2005, Commission File No. 1-16305). |
| ** | 10.40 | Amendment No. 1 to 2005 Long-Term Incentive Plan of Puget Energy, Inc. (Exhibit 10.1 to the Current Report on Form 8-K, dated February 14, 2006, Commission File Nos. 1-16305 and 1-4393). |
| ** | 10.41 | Employment agreement with S. P. Reynolds, Chief Executive Officer and President dated January 7, 2002 (Exhibit 10.104 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-16305 and 1-4393). |
| 10.42 | Receivable Sale Agreement dated December 23, 2002, among PSE and Rainier Receivables, Inc. |
** | 10.43 | Employment agreement with J.M. Ryan, Vice President Energy Portfolio Management, dated November 30, 2001, (Exhibit 10.109 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-16305 and 1-4393). |
| ** | 10.4410.42 | Change-in-Control AgreementFirst Amendment dated May 10, 2005 to employment agreement with J.M. Ryan, ViceS.P. Reynolds, Chief Executive Officer and President, Energy Portfolio Management, dated November 30, 2001as of January 1, 2002 (Exhibit 10.11010.3 to the AnnualCurrent Report on Form 10-K for the fiscal year ended December 31, 2002,8-K, dated May 12, 2005, Commission File No.Nos. 1-16305 and 1-4393). |
| ** | 10.4510.43 | Change-in-Control AgreementSecond Amendment dated February 9, 2006 to employment agreement with B. A. Valdman, Senior ViceS. P. Reynolds, Chief Executive Officer and President, Financedated as of January 1, 2002 and Chief Financial Officer, dated November 28, 2003amended as of May 10, 2005 (Exhibit 10.8610.2 to the AnnualCurrent Report on Form 10-K for the fiscal year ended December 31, 2003,8-K, dated February 14, 2006, Commission File No.Nos. 1-16305 and 1-4393). |
| ** | 10.46 | Change-in-Control Agreement with S. McLain, Senior Vice President, Operations, dated March 12, 1999. (Exhibit 10.87 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-16305 and 1-4393). |
** | 10.47 | Employment Agreement with M. T. Lennon, President and Chief Executive Officer of InfrastruX, dated May 6, 2002 (Exhibit 10.88 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2003, Commission File No. 1-16305 and 1-4393). |
** | 10.4810.44 | Restricted Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and President, dated January 8, 2004 (Exhibit 10.90 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2003, Commission File No. 1-16305 and 1-4393). |
| ** | 10.4910.45 | Restricted Stock Unit Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, 2004 (Exhibit 10.91 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2003, Commission File No. 1-16305 and 1-4393). |
| ** | 10.5010.46 | Restricted Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and President, dated January 8, 2002 (Exhibit 99.1 to Form S-8 Registration Statement, dated January 8, 2002, Commission File No. 333-76424). |
| ** | 10.5110.47 | NonregulatedNonqualified Stock Option Grant Notice/Agreement with S. P. Reynolds, Chief Executive Officer and President dated March 11, 2002 (Exhibit 99.1 and Exhibit 99.2 to Form S-8 Registration Statement dated March 18, 2002, Commission File No. 333-84426). |
| * | 10.52 | Change-in-Control Agreement with E. M. Markell, Vice President Corporate Development, dated May 7, 2003. |
| * | 10.53 | InfrastruX 2000 Stock Incentive Plan adopted January 26, 2001. |
* | 10.54 | InfrastruX 2000 Stock Incentive Plan Stock Option Grant Notice adopted January 26, 2001. |
* | 10.5510.48 | Puget Sound Energy Amended and Restated Supplemental Executive Retirement Plan for Senior Management dated October 5, 2004. (Exhibit 10.55 to Annual Report on Form 10-K for fiscal year ended December 31, 2005, Commission File No. 1-16305 and 1-4393). |
| ** | 10.5610.49 | Puget Sound Energy Amended and Restated Deferred Compensation Plan for Key Employees dated January 1, 2003. (Exhibit 10.56 to Annual Report on Form 10-K for fiscal year ended December 31, 2005, Commission File No. 1-16305 and 1-4393). |
| ** | 10.5710.50 | Puget Sound Energy Amended and Restated Deferred Compensation Plan for Nonemployee Directors dated October 1, 2000. (Exhibit 10.57 to Annual Report on Form 10-K for fiscal year ended December 31, 2005, Commission File No. 1-16305 and 1-4393). |
** | 10.5810.51 | Summary of Director Compensation (incorporated by reference |
| ** | 10.52 | Performance-Based Restricted Stock Award Agreement with S.P. Reynolds, Chief Executive Officer and President, dated May 12, 2005 (Exhibit 10.4 to Exhibit 99.1 tothe Current Report on Form 8-K, filed February 2,dated May 12, 2005, Commission File Nos. 1-43931-16305 and 1-4393). |
| ** | 10.53 | Form of Amended and Restated Change of Control Agreement between Puget Sound Energy, Inc. and Executive Officers (Exhibit 10.3 to the Current Report on Form 8-K, dated February 14, 2006, Commission File Nos. 1-16305 and 1-4393). |
| ** | 10.54 | Form of Performance-Based Restricted Stock Award Agreement between Puget Sound Energy and Key Employees (Exhibit 10.1 to the Current Report on Form 8-K, dated February 28, 2006, Commission File No. 1-16305). |
| * | 10.55 | Summary of Severance Benefit for B. A. Valdman, Senior Vice President Finance and Chief Financial Officer. |
| * | 10.56 | Restricted Stock Award Agreement with B. A. Valdman, Senior Vice President Finance and Chief Financial Officer, dated December 4, 2003. |
| * | 12.1 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy (2000(2002 through 2004)2006). |
| * | 12.2 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy (2000(2002 through 2004)2006). |
| * | 21.1 | Subsidiaries of Puget Energy. |
| * | 21.2 | Subsidiaries of PSE. |
| * | 23.1 | Consent of PricewaterhouseCoopers LLP. |
| * | 31.1 | Certification of Puget Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Stephen P. Reynolds. |
| * | 31.2 | Certification of Puget Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Bertrand A. Valdman. |
| * | 31.3 | Certification of Puget Sound Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Stephen P. Reynolds. |
| * | 31.4 | Certification of Puget Sound Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Bertrand A. Valdman. |
| * | 32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Stephen P. Reynolds. |
| * | 32.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Bertrand A. Valdman. |
* | Filed herewith. |
** | _____________________
*Filed herewith.
**Management contract or compensating plan or arrangement.
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