UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF |
For the fiscal year ended December 31, 20022003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
|
| Exact name of registrant as specified | I.R.S. | |||
| in its charter, state of incorporation, | Employer | |||
| Commission | address of principal executive offices, | Identification | ||
| File Number | telephone number | |||
| 1-16305 | PUGET ENERGY, INC. | 91-1969407 | ||
| A Washington | Corporation. | |||
| 10885 N.E. 4th Street, Suite 1200 | ||||
| Bellevue, Washington 98004-5591 | ||||
| (425) 454-6363 |
| 1-4393 | PUGET SOUND ENERGY, INC. | 91-0374630 | |
| A Washington | |||
| 10885 N.E. 4th Street, Suite 1200 | |||
| Bellevue, Washington 98004-5591 | |||
| (425) 454-6363 |
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, | N.Y.S.E. | ||
| Preferred Share Purchase Rights | N.Y.S.E. | ||
| Puget Sound Energy, Inc. 8.4% Capital Securities | N.Y.S.E. |
Securities registered pursuant to Section 12(g) of the Act:
| TITLE OF EACH CLASS | ||
| Puget Sound Energy, Inc. Preferred Stock, (cumulative, $100 par value) |
Securities registered pursuant to Section 12(b) of the Act:
| 8.231% Capital Securities |
Puget Sound Energy, Inc. meets the conditions set forth in General Instructions 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 whether the registrant:registrants: (1) hashave 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 registrant wasregistrants were required to file such reports), and (2) hashave been subject to such filing requirements for the past 90 days.
Yes/X/ No/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 the registrantPuget Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).
Yes/X/ No/Yes /X/ No /
/
Indicate by check mark whether Puget Sound Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).
Yes / / No /X /
The aggregate market value of the voting stock held by non-affiliates of Puget Energy, Inc. at June 28, 200230, 2003 (the last business day of Puget Energy’s most recently completed second fiscal quarter), was approximately $1,807,769,393.$2,238,688,000. The number of shares of Puget Energy, Inc.‘s common stock outstanding at February 28, 2003,27, 2004 was 93,827,455.99,246,495 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 20032004 Annual Meeting of Shareholders to be filed with the Commission pursuant to Regulation 14A not later than 120 days after December 31, 20022003 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. (Puget Energy) and Puget Sound Energy, Inc. (PSE). PSEPuget 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 PSEPuget Sound Energy, Inc. and its subsidiaries.
INDEX
| Definitions |
| Forward-Looking Statements |
| Part I |
| Part II |
| Part III |
| AFUDC | Allowance for Funds Used During Construction | |
| BPA | Bonneville Power Administration | |
| CAISO | California Independent System Operator | |
| Chelan | Public Utility District No. 1 of Chelan County, Washington | |
| Dth | Dekatherm (one Dth is equal to one MMBtu) | |
| FASB | Financial Accounting Standards Board | |
| FERC | Federal Energy Regulatory Commission | |
| FIN | Financial Accounting Standards Board Interpretation | |
| FPA | Federal Power Act | |
| InfrastruX | InfrastruX Group, Inc. | |
| KW | Kilowatts | |
| kWh | Kilowatt Hours | |
| LIBOR | London Interbank Offered Rate | |
| LNG | Liquefied Natural Gas | |
| MMBtu | One Million British Thermal Units | |
| MW | Megawatts (one MW equals one thousand KW) | |
| MWh | Megawatt Hours | |
| NOPR | ||
| NWP | Williams Northwest Pipeline Corporation | |
| PCA | Power Cost Adjustment | |
| 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 | |
| SFAS | Statement of Financial Accounting Standards | |
| SMD | FERC Standard Market Design | |
| Washington Commission | Washington Utilities and Transportation Commission |
Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) are including the following cautionary statement 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, assumptions of future events or performance. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue” or similar expressions identify forward-looking statements.
Forward-looking statements involve risks and uncertainties which 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,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 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, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation and construction of hydro,electric generating facilities, distribution and transmission facilities, licensing of hydro operations, recovery of other capital investments, recovery of power and gas costs, recovery of regulatory assets, and present or prospective wholesale and retail competition;
the bankruptcy filing by Enron Corporation, financial difficulties byof 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;
wholesale market disruption, which may result in a deterioration in market liquidity, increase the risk of counterparty default, by counterpartiesaffect the regulatory and legislative process in unpredictable ways, limit the availability of and access to capital credit markets, affect wholesale natural gas and electricity markets that owe PSE money energy prices and/or energy;
continued deterioration of liquidity in the forward markets in which PSE transacts hedgesimpede PSE’s ability to manage its energy portfolio risks which can limit PSE’s abilityrisks;
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;
hydroelectric conditions, which can have a potentially serious impact on electric capacity and PSE’s ability to generate electricity;
the stability and liquidity of wholesale energy markets generally, including the effect of price controls by FERC on the availability and price of wholesale energy purchases and sales in the western United States;
the effect of wholesale and possible future retail competition (including, but not limited to, electric retail wheeling and transmission system access);
the amount of collection, if any, of PSE’s receivablereceivables from the California Independent System Operator (CAISO) and the amount of refunds found to be due from PSE to the CAISO or others;
industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
general economic conditions in the Pacific Northwest;
the loss of significant customers or changes in the business of significant customers, which may result in changes in demand for PSE's services;
| Risks relating to the non-regulated utility service business (InfrastruX Group, Inc.) |
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 ability of InfrastruX to integrate acquired companies withwithin existing operations without substantial costs, delays or other operational or financial problems, which involves a number of special risks;
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 both price and quality;
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 associated with the financial conditions of InfrastruX’sInfrastruX'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;
and| Risks relating to both the regulated and non-regulated businesses |
the impact of acts of terrorism or similar significant events, such as the attack on September 11, 2001;
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;
capital 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;
changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies;
employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;
the ability to obtain adequate insurance coverage and the cost of such insurance.
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.
GENERAL
Puget Energy, Inc. (Puget Energy) is an energy services holding company incorporated in the State of Washington in 1999. All of its operations are conducted through its subsidiaries, 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, Puget Energy is exempt from regulation as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935. Puget Energy and PSE are collectively referred to herein as “the Company.” The following table provides the percentages of Puget Energy’s consolidated operating revenues and net income generated and assets held by the reportable segments:
| Segment | Percent of Revenue | Percent of Net Income | Percent of Assets | Segment | Percent of Revenue | Percent of Net Income | Percent of Assets | |||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |||||||||||
| Puget Sound Energy | 86.2% | 92.9% | 98.2% | 88.3% | 75.0% | 105.6 % | 92.1% | 93.4% | 96.1% | 86 | .0% | 86 | .2% | 92 | .9% | 98 | .2% | 88 | .3% | 75 | .0% | 92 | .6% | 92 | .2% | 93 | .5% | |
| InfrastruX | 13.4% | 6.0% | 1.4% | 8.0% | 2.4% | (0.3)% | 5.6% | 4.2% | 1.9% | 13 | .7% | 13 | .4% | 6 | .0% | 1 | .5% | 8 | .0% | 2 | .4% | 6 | .0% | 5 | .5% | 4 | .0% | |
| Other subsidiaries | 0.4% | 1.1% | 0.4% | 3.7% | 22.6% | (5.3)% | 2.3% | 2.4% | 2.0% | 0 | .3% | 0 | .4% | 1 | .1% | 0 | .3% | 3 | .7% | 22 | .6% | 1 | .4% | 2 | .3% | 2 | .5% | |
Additional financial data regarding these segments isare included in Note 2019 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 State of Washington, State, primarily engaged in the business of electricityelectric 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 |
| Add electric generation and delivery infrastructure to meet customer needs. Ensuring stable, cost-based 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. The collapse of the merchant energy industry has resulted in the cancellation or delay of power plant construction projects that were expected to meet the region’s supply needs at competitive prices. Accordingly, |
| Rebuild financial strength to fund energy infrastructure and manage energy portfolio.PSE intends to focus on the regulated business to provide credit quality, liquidity and |
| Provide return to Puget Energy |
| Achieve PSE earnings growth.PSE earnings will grow through rebuilding common equity and increasing the 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. |
| Focus on InfrastruX growth.Focus on internal earnings growth opportunities within the InfrastruX subsidiaries. |
PUGET SOUND ENERGY, INC.
PSE is a public utility incorporated in the State of Washington. PSE furnishes electric and gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region of Washington State.
the State of Washington.
At December 31, 2002,2003, PSE had approximately 958,000977,700 electric customers, consisting of 845,200861,900 residential, 106,900109,700 commercial, 3,9004,000 industrial and 2,0002,100 other customers; and approximately 622,000644,600 gas customers, consisting of 572,300593,800 residential, 46,80048,000 commercial, 2,8002,700 industrial and 100 transportation customers. At December 31, 20022003, approximately 305,300310,900 customers purchased both forms of energy from PSE. For the year 2002,2003, PSE added approximately 17,40019,700 electric customers and approximately 16,00022,600 gas customers, representing annualized growth rates of 1.8%2.1% and 2.6%,3.6% respectively. During 20022003, PSE’s billed retail and transportation revenues from electric utility operations, excluding conservation trust collections, were derived 48% from residential customers, 42%43% from commercial customers, 7% from industrial customers and 3%2% from transportation and other customers. PSE’s retail revenues from gas utility operations were derived 62%64% from residential customers, 31%29% from commercial customers, 5% from industrial customers and 2% from transportation customers. During this period the largest customer accounted for approximately 1% 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 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 in the first and fourth quarters of the year. Sales of electricity to wholesale customers also vary by quarter and year depending principally upon streamflow conditions for the generation of surplus hydroelectric power after serving customer requirementseconomic factors and the market demand by wholesale customers.weather conditions. PSE has a Purchased Gas Adjustmentpurchased gas adjustment (PGA) mechanism (PGA) in retail gas rates to recover variations in gas supply and transportation costs. PSE also has a Power Cost Adjustmentpower cost adjustment (PCA) mechanism (PCA) in electric rates to recover variations in electricity costs on a shared basis between customers and PSE.
DuringIn the five-year period from January 1, 1998 throughended December 31, 2002,2003, PSE’s gross electric utility plant additions were $894$941 million and retirements were $184$210 million. In the five-year period ended December 31, 2002,2003, PSE’s gross gas utility plant additions were $565$551 million and retirements were $72$76 million. In the same five-year period, PSE’s gross common utility plant additions were $328$211 million and retirements were $32$45 million. Gross electric utility plant at December 31, 20022003 was approximately $4.2$4.3 billion, which consisted of 59% distribution, 26%27% generation, 7%6% transmission and 8% general plant and other. Gross gas utility plant as of December 31, 20022003 was approximately $1.6$1.7 billion, which consisted of 86% distribution, 6% transmission and 8% general plant and other. Gross common utility general and intangible plant as ofat December 31, 20022003 was approximately $379$391 million.
INFRASTRUX GROUP, INC.
InfrastruX was incorporated in the State of Washington in 2000 to pursue the non-regulated construction services business. InfrastruX is a national leader in providing infrastructure construction services to the electric and gas utility industries. InfrastruX has acquired eleven12 companies, primarily in the south/Texas, and the north-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: |
The InfrastruX construction services business 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 quarters of the year.
INFRASTRUX OPERATING STRATEGYyear, as spring and summer months are routinely the most productive time of year for the construction industry due to longer daylight hours and generally better weather conditions.
In InfrastruX’s initial three years, InfrastruX focused on acquiring and expanding business services inoperating strategy revolves around leveraging the natural gas and electric utilitysynergies of a core group of outstanding infrastructure market that have an established regional presence and are positioned to expand their market position. Implementation of InfrastruX’s strategy involved identifying acquisition targets with established operational experience and customerconstruction contractors whose asset base, expertise, local knowledge, relationships and years of successful operations form a strong management team. InfrastruX’s current operating strategy depends primarily upon generating internal growth through the addition of newbase 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 expansionalso move quickly to provide additional services as needs arise. The formation of services offered to existing customers rather than external growth through acquisitions.
INFRASTRUX COMPETITIONregional 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. Puget Energy believes that InfrastruX’s competitive strengths, including a diverse customer base, long-standing relationships with several key customers and operational expertise in construction services will benefit InfrastruX, but there can be no assurance that a competitor will not be able to develop expertise, experience and resources to provide services that are superior in quality or price to InfrastruX’s services.
MARKET OUTLOOK
InWhile the general outlook appears to be improving, in the near term, InfrastruX’s market opportunities will continue to be limitedconstrained by the general economic and utility industry downturn that will resulthas resulted in reduced spending on infrastructure construction, including large pipeline and utility projects, by many of InfrastruX'sInfrastruX’s customers. As a result, competition on project bids will increase,continue to be very strong, which may reduce profit margins and adversely impact revenue and operational growth. Puget Energy believesmanagement continues to believe that in the long-termlong term the opportunities for InfrastruX are excellent given an aging transmission and distribution infrastructure, forecast forforecasted growth in energy demand and the need for greater network infrastructure construction services.
EMPLOYEES
As ofAt December 31, 2002,2003, Puget Energy and its subsidiaries had approximately 4,6605,164 full-time employees:
| Puget Sound Energy | ||
| InfrastruX | ||
| Total Puget Energy |
Approximately 1,100 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) andor the United Association of Plumbers and Pipefitters (UA). PSE has renegotiated contract extensionsThe labor contracts with the IBEW and UA run through 2007 and 2006, respectively.
Approximately 200400 InfrastruX employees are represented by the IBEW, UA, United Steelworkers of America, and Laborers International Union of North America.America or other unions. Some unions have annual contract renewals while others are multiple-year.have multiple-year contracts.
CORPORATE LOCATIONSLOCATION
Puget Energy’s and PSE’s principal executive offices are located at 411 108th Avenue10885 N.E., 4th Street, Suite 1200, Bellevue, Washington 98004 and itsthe telephone number is (425) 454-6363. The Company’s principal executive offices will be relocating in July 2003 to 10885 N.E. 4th Street, Bellevue, Washington 98004.
AVAILABLE INFORMATION
The Annual ReportCompany’s website address is www.pse.com. The Company’s reports on Form 10-K, Quarterly Reportsquarterly reports on Form 10-Q, Current Reportscurrent reports on Form 8-K and amendments to those reports filed or furnished pursuant to SectionsSection 13(a) andor 15(d) of the Securities Exchange Act of 1934 as amended, are available or may be accessed free of charge through the Investors section of the Company’s website as soon as reasonably practical after the reports are electronically filed with, or furnished to, the SEC. The Company’s website and the information contained therein or connected thereto are not intended to be incorporated into this Annual Report on Form 10-K.
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 to Puget Energy’s website at www.pse.com.Energy, Inc., Investor Services, P.O. Box 97034, PSE-08S, Bellevue, Washington 98009-9734:
If the Company waives any material provision of UTILITY INDUSTRY OVERVIEW On December 20, 1999, FERC issued Order 2000 to advance the formationRegional Transmission Organizations (RTOs). This regulation required each public utility that owns, operates or controls facilitiesEthics for the transmissionCompany’s Chief Executive Officer and senior financial officers.electric energy in interstate commerce to file with FERC by October 15, 2000 plansits Code of Ethics for formingits Chief Executive Officer and participating in an RTO. FERC’s goal is to promote efficiency in wholesale electricity marketssenior financial officers or its Corporate Ethics and to reduce prices electricity consumers pay toCompliance Code, or substantively changes the lowest price possiblecodes for reliable service. On October 16, 2000, PSE andany specific officer, the Company will disclose that waiver on its website within five other utilities filed with FERC their proposal for an independent transmission company, which would serve six states. The independent transmission company would be a member of the planned regional transmission organization. Any final proposal that emerges is subject to approval by FERC and relevant state public utility commissions. FERC has also issued a Notice of Proposed Rulemaking on Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The SMD NOPR would have major implications for the delivery of electric energy throughout the United States if enacted in its proposed form. Major elements of FERC’s proposal include: (a) the use of Network Access Service to replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff; (b) vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems; (c) the formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. 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 and transportation services. 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 2002, 134 commercial and industrial customers, on average, chose to use such service. The shifting of customers from sales to transportation does not materially impact utility margin, as PSE earns similar margins on transportation service as it does on large volume, interruptible gas sales. The electric utility business in Washington State is fully regulated. There are no proposals or prospects for retail deregulation in Washington State anticipated in the foreseeable future.
REGULATION AND RATES
PSE is subject to the regulatory authority of (1) the Washington Commission as to retail utility rates, accounting, the issuance of securities and certain other matters and (2) FERC with respect to the transmission of electric energy, the resale of electric energy at wholesale, accounting and certain other matters. (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Rate Matters”.)
ELECTRIC RATES AND REGULATIONSREGULATION
On March 28, 2002,October 24, 2003, PSE filed a request with the Washington Commission approved a settlement agreement which resolved the Company’s request for an interimto increase its electric rates $64.4 million to recover higher projected power supply costs. The proposed rate increase and significant financial issuesincludes, among other things, the recovery of the projected costs associated with PSE’s proposed acquisition of a 49.85% share of Frederickson Power LP’s Frederickson 1 generation facility (250 MW) located near Tacoma, Washington.
On January 30, 2004, the Washington Commission staff filed testimony responding to PSE’s filing. The Washington Commission staff’s testimony finds that the decision to acquire the interest in the Company’s electricFrederickson 1 plant was prudent and gas general rate cases. As a result, an interimthat PSE’s costs to do so were reasonable. Accordingly, the Washington Commission staff recommended to the Washington Commission that PSE’s costs be recovered in rates. No other party filed testimony questioning the decision or costs to acquire the Frederickson 1 plant. Favorable treatment of this acquisition will benefit PSE’s customers and PSE going forward.
In the same proceeding, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate surchargeincrease. Among other things, they propose that a significant amount of $25 million wasPSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in effect for the period April 1, 2002 through June 30, 2002. The three important financial issueselectric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were resolved foravailable in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If the Washington Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and their positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power cost only rate case is expected by mid-April 2004. Another step in completing the acquisition of the power generating facility is to obtain the approval of FERC in accordance with the Federal Power Act (FPA). In December 2003, FERC issued an order in a case involving Oklahoma Gas & Electric Company (OGE) that suggested that FERC would scrutinize these transactions. In the OGE case, FERC has decided to hold hearings to analyze the effects on market share and transmission availability that would flow from the OGE acquisition. PSE took that decision into account when it filed its application in January 2004. FERC issued a letter on February 12, 2004 in response to PSE’s filing seeking additional information. PSE responded to the request on February 27, 2004, and still anticipates FERC approval of the acquisition in early 2004.
PSE is currently preparing to file a general tariff electric rate case with the Washington Commission in the second quarter of 2004. The resolution of the general rate case includedmay be up to an 11-month process from the equity capital ratio,time the return on equity and adoption of an electric power cost adjustment mechanism.general rate case is filed.
On June 20, 2002, the Washington Commission issued final regulatory approval of the comprehensive electric-rateelectric 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 willbegan July 1, 2002, which was intended to generate approximately an additional $59 million in additional revenue annually that began July 1, 2002.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 includesincluded a 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 yearfour-year period ending June 30, 2006 is limited to $40 million plus 1% of the excess. 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). On an annual July through June basis, the mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers in the following manner:
| Annual Power Cost Variability | Customers' Share | Company's Share (1) | |||
| +/- $20 million | 0 | % | 100 | % | |
| +/- $20-$40 million | 50 | % | 50 | % | |
| +/- $40-$120 million | 90 | % | 10 | % | |
| +/- $120+ million | 95 | % | 5 | % | |
(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.
Interest will be accrued on any overcollection or undercollection of the customers’ share of the excess power cost that is deferred. The CompanyPSE can request a PCA rate surcharge if for any 12 month12-month period the actual or projected deferred power costs exceedsexceed $30 million. PSE’s cumulative share of the power costs through December 31, 20022003 was $5.2$40 million. BecausePrincipally because of adverse hydro conditions and escalating gas costs for electric generation in 2003, PSE anticipates reachingreached the $40 million cumulative cap under the PCA mechanism byin the fourth quarter of 2003. During 2003, PSE’s share of the excess power costs was $34.8 million compared to $5.2 million for 2002. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE. PSE is required to file a Compliance Filing with the Washington Commission annually on June 30, in relation to the power costs under the PCA mechanism.
The settlement also givesgave PSE the financial flexibility to rebuild its common equity ratio to at least 39% over a three and a half yearthree-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, 2003, PSE has restored its common equity ratio to a 40% level, exceeding the required level for 2003 by 6%.
RESIDENTIAL AND SMALL FARM EXCHANGE CREDIT
OnIn June 13, 2001, the Washington Commission approvedPSE and Bonneville Power Administration (BPA) entered into an amended settlement agreement regarding the Residential Purchase and Sale Agreement (Agreement) between PSE and the BPA,Program, under which PSE’s residential and small farm customers would continue to receive the benefits of federal power. Completion of this agreement enabled PSE to continue to provide and in fact increase, effective January 1, 2002, thea Residential and Farm Energy Exchange CreditBenefit credit to residential and small farm customers. The Agreementamended settlement agreement provides that, for its residential and small farm customers, PSE will receivereceive: (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. The amended settlement agreement regarding the Residential Purchase and Sale Program provides PSE’s residential and small farm customers the benefits of lower-cost federal power.
On June 17, 2002, PSE entered into an agreement with the BPA, which amendedmodified the payment provisions of the Agreementamended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement. To implement this agreement for rate purposes, the Washington Commission approved tariff revisions that were intended to (a) transfer the Residential and Farm Energy Exchange credit in effect since October 1, 1995 in the amount of $0.01085 per kWh, to general rates effective July 1, 2001 and (b) to provide a supplemental Residential and Farm Exchange credit for eligible residential and small farm customers. On June 26, 2002, the Washington Commission then transferred the portion of the credit that had been in general rates back into Schedule 194. The Residential and Farm Exchange Benefit Supplemental Rider schedule was retitled Residential and Farm Energy Exchange Benefit, the portion of the credit that had been in general rates was transferred back into Schedule 194, and the credit was set at $0.01456 per kWh for the period July 1, 2002 through September 30, 2002, $0.01817 per kWh for the period October 1, 2002 through May 31, 2006 and $0.02302 per kWh for the period June 1, 2006 through September 30, 2006. The approval of these revised tariffs by the Washington Commission was effective July 1, 2002. In January 2003, PSE filed tariff sheets with the Washington Commission to reflect a modification to the agreement between PSE and the BPA that would reduce the Residential and Farm Energy Exchange Benefit credit. Under the modified agreement, BPA will deferdeferred paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred will bewas $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA is enteringentered into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA are agreeingagreed to BPA’s deferral of payments in theirits fiscal year 2003. The total cumulative amount to be deferred under the agreement with PSE and other such agreements equals $55 million, an amount that will help BPA address its current financial difficulties.million. Absent certain adjustments tied to a BPA rate adjustment clause, BPA will begin paying back the amount deferred with interest over the sixty-month60-month period beginning NovemberOctober 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 approvedaccepted the tariff changes and the RiderResidential 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. The deferralOn June 30, 2003, BPA adopted its final Record of Decision in the February 2003 rate case, which established a formula under the BPA benefitsrate adjustment clause to be used in adjusting the rate that will not have any impact on PSE earnings, as it is a direct pass-through to PSE customers.
BPA’s rate case may affect the level of residential exchange benefits for PSE’s customers. For 2002,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.
For 2003 and 2002, the Residential and Farm Energy Exchange Benefit credited to customers were $152.8was $181.9 million and $156.8 million, respectively, with a related offset to power costs. PSE received payments from BPA in the amount of $147.9 million and $171.2 million during 2002.2003 and 2002, respectively. The difference between the customers’ credit and the amount received from BPA iseither increases or decreases the previously deferred and creditedamount owed to customers in later periods.customers. The differenceaggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. TheAbsent certain adjustments tied to the BPA rate adjustment clause described above, the modified Agreement, if it goes into effect, wouldamended 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 customerscustomers.
On October 23, 2003, PSE signed conditional settlement agreements including a Stipulation and Agreement for Settlement, a Waiver and Covenant Not to Sue, and an Amendment No. 1 to the amended settlement agreement. These conditional settlement agreements, which are now void because certain conditions were not satisfied, included provisions for the dismissal of certain lawsuits regarding residential exchange benefits, an elimination of the same amount. The leveladjustment mentioned above for the 12-month period commencing October 1, 2003, the deferral of the receipt of certain benefits, a change in the methodology used to calculate residential benefits in the October 1, 2006 through September 30, 2011 period, and elimination of a risk premium that would otherwise have been payable by BPA credit does not affect PSE’s earnings, sinceunder certain conditions under the credit is a direct pass-through to residential customers. The credit does affect the net rates paid by those customers.
amended settlement agreement.
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 contractamended settlement agreement and the conditional settlement agreements between BPA and the CompanyPSE described above. BPA rates used in such contractamended settlement agreement between BPA and the CompanyPSE for determining the amounts of money to be paid to the CompanyPSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC on an interim basis, subjectFERC. 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 refund with interest.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 District Court and U.S. Ninth Circuit Court of Appeals actions may have on the Company.PSE.
GAS RATES AND REGULATION
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 during 2003, 2002 and 2001:
| EFFECTIVE DATE | PERCENTAGE INCREASE (DECREASE) IN RATES | ANNUAL INCREASE (DECREASE) IN REVENUES (DOLLARS IN MILLIONS) | ||||||
| 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) | ||||
| September 1, 2001 | (8 | .9)% | (81 | .1) | ||||
| January 12, 2001 | 26 | .4% | 163 | .5 | ||||
On August 28, 2002, the Washington Commission approved a 5.8% gas rate increase in general rates to cover higher costs of providing natural gas serviceservices to customers. ThisThe increase willwas intended to provide approximately $35.6 million annually in revenues and was offset by an annual $45 million or 7.3% PGArevenues. This rate reduction, also approved on August 28, 2002. Both rate actionsincrease became effective September 1, 2002. The PGA mechanism passes through
PSE is currently preparing to customers increases or decreasesfile a general tariff gas rate case with the Washington Commission in the second quarter of 2004. The resolution of the general rate case may be up to an 11-month process from the time the general rate case is filed.
UTILITY INDUSTRY OVERVIEW
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. As a result of open access, there has been no material effect on the financial statements of PSE.
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). The SMD NOPR would have major implications for the delivery of electric energy throughout the United States if enacted in its proposed form. Major elements of FERC’s proposal include: (a) The use of Network Access Service would replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff. (b) Vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems. (c) Regional State Advisory Committees and other regional entities would form to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. State regulators and industry representatives have pointed out that the western North American electricity market has unique characteristics that may not readily lend themselves to the SMD NOPR proposed by FERC. FERC has expressed its willingness to offer regional flexibility in its order on RTO West, Docket Nos. RT01-35-005 and RT01-35-007, issued September 18, 2002. In April 2003, FERC issued a white paper responding to concerns of state regulators regarding the impact of the SMD NOPR proposal on the western market. PSE cannot predict the outcome of the SMD NOPR or whether the ultimate resolution will have a material impact on the financial condition, results of operations or liquidity of the Company.
STATE REGULATION
The electric utility business in the State of Washington is fully regulated and provides service to its customers under cost-based tariff rates. PSE is not aware of any proposals or prospects for retail deregulation in the State of Washington.
Since 1986 PSE has been offering gas transportation as a separate service to industrial and commercial customers who choose to purchase their gas supply portiondirectly from producers and gas marketers. The continued evolution of the natural gas service rates based upon changes inindustry, resulting primarily from FERC Orders 436, 500 and 636, has served to increase the priceability of naturallarge 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 the change in PGA rates. On May 24, 2002, the Washington Commission allowed a PGA rate reduction that was filed on May 6, 2002, effective June 1, 2002, lowering overall natural gas rates by 21.2%. This ended a temporary surcharge that went into effect September 1, 2001. On September 30, 2002, PSE filed a proposal with the Washington Commissionend-users to reduce naturalindependently obtain gas supply rates under the PGA for a third time in 2002. The Washington Commission approved the proposal on October 30, 2002 and transportation services. Although PSE lowered gas rates overall through the PGA by approximately 12.5% effective November 1, 2002. Ashas not lost any substantial industrial or commercial load as a result of sharp increasessuch activities, in certain years up to 160 customers annually have taken advantage of unbundled transportation service; in 2003, 134 commercial and industrial customers, on average, chose to use such service. The shifting of customers from sales to transportation does not materially impact utility margin, as PSE earns similar margins on transportation service as it does on large-volume, interruptible gas costs during 2000 and 2001, PSE filed two PGA and deferral amortization filings with the Washington Commission which were approved. The PGA filings allowed PSE to recover increased gas costs. As a result, gas rates to all sales customers increased by an average of 30.2% on August 1, 2000, and 26.4% on January 12, 2001. Subsequent declines in gas costs led to PSE obtaining approval of another PGA and deferral amortization filing in 2001 resulting in an average 8.9% reduction in gas rates on September 1, 2001.sales.
| TWELVE MONTHS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Generation and Purchased Power-kWh (thousands): | |||||||||||
| Company controlled resources | 6,996,276 | 9,684,087 | 9,502,386 | ||||||||
| Contracted resources | 12,085,729 | 11,901,762 | 14,735,707 | ||||||||
| Non-firm energy purchased | 7,584,398 | 6,987,319 | 14,290,196 | ||||||||
| Total generation and purchased power | 26,666,403 | 28,573,168 | 38,528,289 | ||||||||
| Less losses and company use | (1,341,126 | ) | (1,152,840 | ) | (1,582,446 | ) | |||||
| Total energy sold, kWh | 25,325,277 | 27,420,328 | 36,945,843 | ||||||||
| Electric energy sales, kWh (thousands): | |||||||||||
| Residential | 9,845,527 | 9,555,264 | 9,810,393 | ||||||||
| Commercial | 8,012,538 | 7,953,165 | 7,677,032 | ||||||||
| Industrial | 1,416,107 | 2,540,722 | 4,026,344 | ||||||||
| Other customers | 90,840 | 154,749 | 219,435 | ||||||||
| Total energy billed to customers | 19,365,012 | 20,203,900 | 21,733,204 | ||||||||
| Unbilled energy sales - net increase (decrease) | (102,811 | ) | (278,392 | ) | 118,908 | ||||||
| Total energy sales to customers | 19,262,201 | 19,925,508 | 21,852,112 | ||||||||
| Sales to other utilities and marketers | 6,063,076 | 7,494,820 | 15,093,731 | ||||||||
| Total energy sales, kWh | 25,325,277 | 27,420,328 | 36,945,843 | ||||||||
| Less: optimization purchases for sales to other | (2,596,505 | ) | (2,512,478 | ) | (745,113 | ) | |||||
| utilities and marketers | |||||||||||
| Transportation, including unbilled | 2,307,081 | 363,826 | -- | ||||||||
| Net electric energy sales and transported, kWh | 25,035,853 | 25,271,676 | 36,200,730 | ||||||||
| Electric operating revenues by classes (thousands): | |||||||||||
| Residential | $ | 616,522 | $ | 583,714 | $ | 587,780 | |||||
| Commercial | 536,021 | 509,134 | 476,052 | ||||||||
| Industrial | 90,121 | 281,161 | 292,975 | ||||||||
| Other customers | 26,500 | 25,351 | 98,888 | ||||||||
| Operating revenues billed to customers1 | 1,269,164 | 1,399,360 | 1,455,695 | ||||||||
| Unbilled revenues - net increase (decrease) | (7,118 | ) | (70,615 | ) | 66,700 | ||||||
| Total operating revenues from customers | 1,262,046 | 1,328,745 | 1,522,395 | ||||||||
| Transportation, including unbilled | 15,551 | 2,537 | 6 | ||||||||
| Sales to other utilities and marketers | 152,736 | 1,021,376 | 1,249,294 | ||||||||
| Less: optimization purchases for sales to other | (64,448 | ) | (487,431 | ) | (139,376 | ) | |||||
| utilities and marketers | |||||||||||
| Total electric operating revenues | $ | 1,365,885 | $ | 1,865,227 | $ | 2,632,319 | |||||
| Number of customers served (average): | |||||||||||
| Residential | 839,878 | 826,187 | 811,443 | ||||||||
| Commercial | 104,273 | 100,015 | 98,758 | ||||||||
| Industrial | 3,953 | 4,012 | 4,111 | ||||||||
| Other | 1,932 | 1,758 | 1,548 | ||||||||
| Transportation | 16 | 5 | -- | ||||||||
| Total customers (average) | 950,052 | 931,977 | 915,860 | ||||||||
| Average retail revenues per kWh sold: | |||||||||||
| Residential | $ | 0.0632 | $ | 0.0628 | $ | 0.0617 | |||||
| Commercial | 0.0675 | 0.0655 | 0.0638 | ||||||||
| Industrial | 0.0649 | 0.1120 | 0.0739 | ||||||||
| Average retail revenue per kWh sold | 0.0651 | 0.0701 | 0.0647 | ||||||||
| Average revenue billed to residential customers | $ | 741 | $ | 726 | $ | 745 | |||||
| Average kWh used by residential customers | 11,723 | 11,565 | 12,090 | ||||||||
| Heating degree days | 4,946 | 4,993 | 4,970 | ||||||||
| Percent of normal of 30-year average | 100.8 | % | 101.7 | % | 100.9 | % | |||||
| Load factor | 61.6 | % | 59.8 | % | 62.2 | % | |||||
| TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||
| Generation and purchased power-kWh (thousands): | |||||||||||
| Company-controlled resources | 6,965,840 | 6,996,276 | 9,684,087 | ||||||||
| Contracted resources | 11,021,471 | 12,085,729 | 11,901,762 | ||||||||
| Non-firm energy purchased | 8,121,009 | 7,584,398 | 6,987,319 | ||||||||
| Total generation and purchased power | 26,108,320 | 26,666,403 | 28,573,168 | ||||||||
| Less losses and company use | (1,338,401 | ) | (1,341,126 | ) | (1,152,840 | ) | |||||
| Total energy sold, kWh | 24,769,919 | 25,325,277 | 27,420,328 | ||||||||
| Electric energy sales, kWh (thousands): | |||||||||||
| Residential | 9,845,854 | 9,845,527 | 9,555,264 | ||||||||
| Commercial | 8,222,166 | 8,012,538 | 7,953,165 | ||||||||
| Industrial | 1,372,815 | 1,416,107 | 2,540,722 | ||||||||
| Other customers | 93,438 | 90,840 | 154,749 | ||||||||
| Total energy billed to customers | 19,534,273 | 19,365,012 | 20,203,900 | ||||||||
| Unbilled energy sales - net increase (decrease) | 65,082 | (102,811 | ) | (278,392 | ) | ||||||
| Total energy sales to customers | 19,599,355 | 19,262,201 | 19,925,508 | ||||||||
| Sales to other utilities and marketers | 5,170,564 | 6,063,076 | 7,494,820 | ||||||||
| Total energy sales, kWh | 24,769,919 | 25,325,277 | 27,420,328 | ||||||||
| Less: optimization purchases for sales to other | |||||||||||
| utilities and marketers | (62,200 | ) | (2,596,505 | ) | (2,512,478 | ) | |||||
| Transportation, including unbilled | 2,020,562 | 2,307,081 | 363,826 | ||||||||
| Net electric energy sales and transported, kWh | 26,728,281 | 25,035,853 | 25,271,676 | ||||||||
| Electric operating revenues by classes (thousands): | |||||||||||
| Residential | $ | 603,722 | $ | 616,522 | $ | 583,714 | |||||
| Commercial | 556,038 | 536,021 | 509,134 | ||||||||
| Industrial | 88,201 | 90,121 | 281,161 | ||||||||
| Other customers | 54,259 | 26,500 | 25,351 | ||||||||
| Operating revenues billed to customers1 | 1,302,220 | 1,269,164 | 1,399,360 | ||||||||
| Unbilled revenues - net increase (decrease) | 4,193 | (7,118 | ) | (70,615 | ) | ||||||
| Total operating revenues from customers | 1,306,413 | 1,262,046 | 1,328,745 | ||||||||
| Transportation, including unbilled | 11,542 | 15,551 | 2,537 | ||||||||
| Sales to other utilities and marketers | 193,714 | 152,736 | 1,021,376 | ||||||||
| Less: optimization purchases for sales to other | |||||||||||
| utilities and marketers | (2,206 | ) | (64,448 | ) | (487,431 | ) | |||||
| Total electric operating revenues | $ | 1,509,463 | $ | 1,365,885 | $ | 1,865,227 | |||||
| Number of customers served (average): | |||||||||||
| Residential | 854,088 | 839,878 | 826,187 | ||||||||
| Commercial | 108,479 | 104,273 | 100,015 | ||||||||
| Industrial | 3,952 | 3,953 | 4,012 | ||||||||
| Other | 2,060 | 1,932 | 1,758 | ||||||||
| Transportation | 16 | 16 | 5 | ||||||||
| Total customers (average) | 968,595 | 950,052 | 931,977 | ||||||||
| Average retail revenues per kWh sold: | |||||||||||
| Residential | $ | 0.0617 | $ | 0.0632 | $ | 0.0628 | |||||
| Commercial | 0.0680 | 0.0675 | 0.0655 | ||||||||
| Industrial | 0.0650 | 0.0649 | 0.1120 | ||||||||
| Average retail revenue per kWh sold | 0.0646 | 0.0651 | 0.0701 | ||||||||
| Average revenue billed to residential customers | $ | 711 | $ | 741 | $ | 726 | |||||
| Average kWh used by residential customers | 11,528 | 11,723 | 11,565 | ||||||||
| Heating degree days | 4,527 | 4,946 | 4,993 | ||||||||
| Percent of normal - NOAA 30-year average | 94.4% | 103.1% | 104.1% | ||||||||
| Load factor | 73.5% | 61.6% | 59.8% | ||||||||
1Operating revenues in 2003, 2002 and 2001 and 2000 were reduced by $7.7 million, $12.7 million and $31.0 million and $35.4 million, respectively, as a result of PSE's sale of $237.7 million of its investment in customer-owned conservation measures. Beginning July 2003, these related revenues are now 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.)
ELECTRIC SUPPLY
At December 31, 2002,2003, PSE’s peak electric power resources were approximately 4,577,1354,537,495 KW. PSE’s historical peak load of approximately 4,847,000 KW occurred on December 21, 1998. In order to meet an extreme winter peak load, PSE supplements its electric power resources with call options and other instruments that may include, but are not limited to, weather relatedweather-related hedges and exchange agreements. During 2002,2003, PSE’s total electric energy production was supplied 26.2%26.7% by its own resources, 22.5%19.9% through long-term contracts with several of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River and 22.9%22.3% from other firm purchases. Non-firmShort-term wholesale purchases, net of resales,sales to other utilities and marketers, accounted for 7.4%14.1% of energy purchases in 2002.2003.
The following table shows PSE’s electric energy supply resources at December 31, 20022003 and 2001,2002, and energy production during the year:
| PEAK POWER RESOURCES AT DECEMBER 31, | ENERGY PRODUCTION (IN THOUSANDS) |
| 2003 | 2002 | 2003 | 2002 | |||||||||||||||||||||||||||||||
| 2002 | 2001 | 2002 | 2001 | |||||||||||||||||||||||||||||||
| KW | % | KW | % | kWh | % | kWh | % | KW | % | KW | % | kWh | % | kWh | % | |||||||||||||||||||
| Purchased resources: | ||||||||||||||||||||||||||||||||||
| Columbia River PUD contracts | 1,391,000 | 30 | .4% | 1,431,900 | 28 | .8% | 5,988,118 | 22 | .5% | 4,230,574 | 14 | .8% | 1,349,460 | 29 | .8% | 1,391,000 | 30 | .4% | 5,191,346 | 19 | .9% | 5,988,118 | 22 | .5% | ||||||||||
| Other hydro1 | 175,660 | 3 | .8% | 535,660 | 10 | .8% | 717,215 | 2 | .7% | 964,628 | 3 | .4% | 177,160 | 3 | .9% | 175,660 | 3 | .8% | 622,900 | 2 | .4% | 717,215 | 2 | .7% | ||||||||||
| Other producers1 | 1,209,675 | 26 | .4% | 1,211,675 | 24 | .4% | 5,380,396 | 20 | .2% | 6,706,560 | 23 | .4% | 1,209,675 | 26 | .7% | 1,209,675 | 26 | .4% | 5,207,225 | 19 | .9% | 5,380,396 | 20 | .2% | ||||||||||
| Non-firm energy purchases2 | N/A | N/A | N/A | N/A | 7,584,398 | 28 | .4% | 6,987,319 | 24 | .5% | ||||||||||||||||||||||||
| Short-term wholesale energy purchases2 | N/A | N/A | N/A | N/A | 8,121,009 | 31 | .1% | 7,584,398 | 28 | .4% | ||||||||||||||||||||||||
| Total purchased | 2,776,335 | 60 | .6% | 3,179,235 | 64 | .0% | 19,670,127 | 73 | .8% | 18,889,081 | 66 | .1% | 2,736,295 | 60 | .4% | 2,776,335 | 60 | .6% | 19,142,480 | 73 | .3% | 19,670,127 | 73 | .8% | ||||||||||
| Company-controlled resources: | ||||||||||||||||||||||||||||||||||
| Hydro | 300,000 | 6 | .6% | 300,000 | 6 | .0% | 1,351,540 | 5 | .1% | 1,101,373 | 3 | .9% | 310,400 | 6 | .8% | 300,000 | 6 | .6% | 1,238,900 | 4 | .7% | 1,351,540 | 5 | .1% | ||||||||||
| Coal | 700,000 | 15 | .3% | 700,000 | 14 | .1% | 4,627,901 | 17 | .3% | 5,038,834 | 17 | .6% | 700,000 | 15 | .4% | 700,000 | 15 | .3% | 4,950,734 | 19 | .0% | 4,627,901 | 17 | .3% | ||||||||||
| Natural gas/oil | 800,800 | 17 | .5% | 790,800 | 15 | .9% | 1,016,835 | 3 | .8% | 3,543,880 | 12 | .4% | 790,800 | 17 | .4% | 800,800 | 17 | .5% | 776,206 | 3 | .0% | 1,016,835 | 3 | .8% | ||||||||||
| Total Company controlled | 1,800,800 | 39 | .4% | 1,790,800 | 36 | .0% | 6,996,276 | 26 | .2% | 9,684,087 | 33 | .9% | ||||||||||||||||||||||
| Total Company-controlled | 1,801,200 | 39 | .6% | 1,800,800 | 39 | .4% | 6,965,840 | 26 | .7% | 6,996,276 | 26 | .2% | ||||||||||||||||||||||
| Total | 4,577,135 | 100 | .0% | 4,970,035 | 100 | .0% | 26,666,403 | 100 | .0% | 28,573,168 | 100 | .0% | 4,537,495 | 100 | .0% | 4,577,135 | 100 | .0% | 26,108,320 | 100 | .0% | 26,666,403 | 100 | .0% | ||||||||||
PSE submitted a preliminary least-cost plan to balance future energy resourcesfiled its electric Least Cost Plan on April 30, 2003 with energy needs to the Washington Commission onCommission. The plan supported a strategy of diverse electric power resource acquisitions including resources fueled by natural gas and coal, renewable resources (e.g., wind) and shared resources. A Least Cost Plan Update was filed in August 2003, which integrated conservation programs into the resource mix. The Least Cost Plan was followed with the proposed acquisition of a gas combined-cycle combustion turbine, and the issuing of a wind resource RFP in December 31, 2002. PSE plans to meet its resource needs either through asset acquisition, building its own generation, or entering into additional power purchase agreements, and pursuing energy conservation. PSE will submit its final least-cost plan to the Washington Commission2003. An all-source RFP was issued in the spring of 2003.February 2004.
COMPANY-CONTROLLED ELECTRIC GENERATION RESOURCES
In totalAt December 31, 2003, PSE has the following plants with an aggregate net generating capabilitycapacity of 1,800,8001,801,200 KW:
Plant Name | Plant Type | Total KW Capacity | Year Installed | Plant Type | Total KW Capacity | Year Installed | |||||
| Colstrip 1&2 (50% interest) | Coal | 330,000 | 1975 & 1976 | ||||||||
| Colstrip 3&4 (25% interest) | Coal | 370,000 | 1984 & 1986 | ||||||||
| Colstrip 1 & 2 (50% interest) | Coal | 330,000 | 1975 & 1976 | ||||||||
| Colstrip 3 & 4 (25% interest) | Coal | 370,000 | 1984 & 1986 | ||||||||
| Upper Baker River | Hydro | 91,000 | 1959 | Hydro | 91,000 | 1959 | |||||
| Lower Baker River | Hydro | 79,000 | Reconstructed 1960 Upgraded 2001 | Hydro | 79,000 | Reconstructed 1960 | |||||
| White River | Hydro | 70,000 | 1911 | ||||||||
| Upgraded 2001 | |||||||||||
| White River3 | Hydro | 70,000 | 1911 | ||||||||
| Snoqualmie Falls | Hydro | 44,000 | 1898 to 1911 and 1957 | Hydro | 44,400 | 1898 to 1911 and 1957 | |||||
| Electron | Hydro | 26,000 | 1904 to 1929 | Hydro | 26,000 | 1904 to 1929 | |||||
| Fredonia 1 & 2 | Dual fuel combustion turbines | 210,000 | 1984 | ||||||||
| Fredonia Units 1 & 2 | Dual-fuel combustion turbines | 210,000 | 1984 | ||||||||
| Fredrickson Units 2 & 3 | Dual fuel combustion turbines | 150,000 | 1981 | Dual-fuel combustion turbines | 150,000 | 1981 | |||||
| Whitehorn Units 2 & 3 | Dual fuel combustion turbines | 150,000 | 1981 | Dual-fuel combustion turbines | 150,000 | 1981 | |||||
| Fredonia 3 & 4 | Dual fuel combustion turbines | 108,000 | 2001 | ||||||||
| Fredonia Units 3 & 4 | Dual-fuel combustion turbines | 108,000 | 2001 | ||||||||
| Encogen | Natural gas cogeneration | 170,000 | 1993 | Natural gas cogeneration | 170,000 | 1993 | |||||
| Crystal Mountain | Internal combustion | 2,800 | 1969 | Internal combustion | 2,800 | 1969 | |||||
1Power received from other utilities is classified between hydro 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.
2Non-firm Short-term wholesale purchases net of resales of 5,170,564 MWh and 6,063,076 kWhMWh for 2003 and 7,494,820 kWh for 2002, and 2001 respectively, account for 7.4%14.1% and (2.4%)7.4% of energy purchases.
3 Effective January 15, 2004, the White River generating plant ceased operations as a result of PSE rejecting the FERC license.
All PSE and PPL Montana, the other owner of these generating facilities, exceptColstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana plants,will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are located inpart of PSE’s service territories.
PCA mechanism.
On December 19,October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE was issued a 50-year license by FERCused the coal as fuel for its existingshare of the Colstrip Units 3 & 4 generating plant. PSE’s coal price for that period was reduced by a settlement PSE and operatingWestern Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.
FERC HYDROELECTRIC LICENSES
As part of its hydroelectric operations, PSE is required to obtain 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. 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, private landowner 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.
PSE owns four hydroelectric projects: the Baker River Project, the Snoqualmie Falls Project, the Electron Project and the White River project which includes authorizationProject. 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 install an additional 14,000 KW generating unit. PSE has filedlicense jurisdictional hydropower projects. FERC licenses are generally issued for a rehearing withterm of 30-50 years. The Baker River and Snoqualmie Falls Projects are currently in FERC onrelicensing proceedings. Relicensing proceedings involve multiple parties and interests, and frequently take several years to complete. Relicensing proceedings also invoke the jurisdiction of other federal and state agencies, and these agencies determine various matters that affect the terms and conditions of the license relatedFERC license. The Electron Project is not subject to measures designed to enhance salmon runs on theFERC jurisdiction. The White River because those conditions may makeProject was shut down on January 15, 2004 as a result of PSE’s rejection of the plant uneconomicFERC license that made the project uneconomical to operate. On June 30, 1999 FERC issued
Baker River Project. The Baker River Project consists of the Lower Baker Development (constructed in 1925) and the Upper Baker Development (constructed in 1959) and is located upstream of the confluence of the Baker and Skagit Rivers in Whatcom and Skagit Counties. The project has a stay in the license proceeding. This additional time allows PSE, federal land agencies, state agencies, local governments and public interest groups to resolve common issues and explore alternatives relating to the plant’s continued operation and economics.current authorized capacity of 170.0 MW. The licensing proceeding is ongoing. In April 2001, PSE gave FERC notice of its intent to renew the licenseproject was licensed for its existing and operating 170,000 KW Baker Project.50 years, effective May 1, 1956. The 50-yearproject’s current license expires on April 30, 2006, withand PSE will issue its Notice of Intent to file a new license application due in April 2004. In 2002,Consultation has been
initiated with the National Marine Fisheries Service and United States Fish and Wildlife Service under Section 7 of the Endangered Species Act, and consultation is ongoing with PSE continued working with FERC, federal, state and local governments, Native American tribes, public interest groups and citizens to defineacting as the non-federal representative during said consultation. PSE anticipates submitting a new license application to relicense the project on or before April 30, 2004.
Snoqualmie Falls Project. The Snoqualmie Falls Project, built in 1898, was the world’s first electric generating facility to be built totally underground. It is located 3.5 miles downstream of the confluence of the North, Middle and South Forks of the Snoqualmie River. The project has a current authorized capacity of 44.4 MW. The original license of the project was issued May 13, 1975, effective March 1, 1956, and terminated on December 31, 1993. PSE filed its application to relicense the project on November 25, 1991, and has been operating the project pursuant to annual licenses issued by FERC since the original license expired.
All necessary federal and state review processes prerequisite to FERC’s issuance of a new license were completed as of October 2003. The Snoqualmie Tribe filed an appeal of the State of Washington, Department of Ecology’s water quality certification in November 2003, which appeal is presently pending before the Washington State Pollution Control Hearings Board. The matter is set for hearing on March 22, 2004. The outcome of this matter is not expected to have a material impact upon the financial condition, results of operations or liquidity of the Company.
Electron Project.The Electron Project was built in 1904 in the upper reaches of the Puyallup River. The project’s capacity is currently 26.0 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 improvements to the project that would entail “post-1935” construction.
The project also operates in compliance with the terms and conditions throughof a collaborative process.“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 initialagreement 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.
White River Project. The White River Project was built in 1911 and was operated as a hydropower facility until January 15, 2004. The project’s capacity was 70.0 MW. For many years, the project was believed to fall outside of the jurisdiction of the FPA. In the 1970s, FERC’s jurisdiction over the project was established. PSE submitted a license application to FERC in 1983. In December 1997, FERC issued a proposed license for the existingproject. 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 related to two listings under the Endangered Species Act. On December 23, 2003, PSE notified FERC of its intent to reject the 1997 license, cease generation of electricity and terminate the FERC licensing proceeding. PSE is actively seeking to sell the project to one or more entities interested in maintaining the reservoir for commercial purposes.
On December 29, 2003, PSE entered into a one-year 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 Snoqualmie Falls project expired in December 1993,costs and directs PSE continues to operate the diversion dam in accordance with measures determined by federal agencies to be necessary to protect listed species and habitat. 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. 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.
On December 10, 2003, PSE filed a petition with the Washington Commission for an Accounting Order which will allow for rate recovery of the unrecovered investment in the project. The resolution of this projectmatter will be decided in the power cost only rate case, which is expected by mid-April 2004. The Washington Commission staff’s testimony in PSE’s pending power cost only rate case proceeding supports PSE’s petition. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset. To meet the demands of PSE’s retail customers, electric generation after January 15, 2004 will be purchased from the wholesale energy market.
NEW GENERATION RESOURCES
In October 2003, PSE completed negotiations to purchase a 49.85% interest in a 275 MW (250 MW capacity with 25 MW planned capital improvements) gas-fired electric generating facility located within Western Washington. The purchase will add approximately 137 MW of electric generation capacity to serve PSE’s retail customers. PSE submitted a power cost only rate case in October 2003 to the Washington Commission to recover the approximately $80 million cost of the new generating facility and other power costs. The power cost only rate case is expected to last approximately five months, with an order anticipated to be issued in mid-April 2004. Accordingly, the acquisition of the plant, subject to favorable approval by the Washington Commission, could be completed by April 2004. In addition, the acquisition will require approval from FERC under a temporary license.the FPA. PSE filed its application in January 2004 with FERC and anticipates approval in early 2004.
In addition, PSE has issued an RFP to acquire approximately 50 average MW of energy from wind power for its electric-resource portfolio and is continuing the FERC application processcurrently evaluating responses to relicense this project.request. PSE issued an RFP in February 2004 for an additional 305 MW of electric power resource generation with proposals due back in March 2004.
COLUMBIA RIVER ELECTRIC ENERGY SUPPLY CONTRACTS
During 2002,2003, approximately 22.5%19.9% of PSE’s energy output was obtained at an average cost of approximately 13.96 mills$0.0164 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 pays a proportionate share of the annual debt service and operating and maintenance costs of each project in proportion to the contractual shares that PSE has rights to from such project. Such 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 maintenance, repairs or replacements or license requirements.requirements, or changes to annual operating and maintenance expenses are required.
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 that 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, 20022003, PSE’s aggregate annual capacity from all units of the Rock Island Project was 455,340413,900 KW. PSE’s share of output of the additional Rock Island units may be reduced by up to 10% per year whichyear. Chelan began July 1, 2000, subject to a maximum aggregate reductionwithdrawing 5% of 50%, upon the exercise of rights of withdrawal by Chelanpower from the additional Rock Island units for use in meeting its local service area.load on July 1, 2000. 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 is as follows:
| Date of Withdrawal | Withdrawal Percentage | PSE Capacity after Withdrawal | Withdrawal Percentage | PSE Capacity after Withdrawal |
| July 1, 2002 | 10% | 85% | ||
| July 1, 2003 | 10% | 75% | 10% | 75% |
| February 1, 2005 | 10% | 65% | 10% | 65% |
| July 1, 2005 | 10% | 55% | 10% | 55% |
| November 1, 2006 | 5% | 50% | 5% | 50% |
PSE has contracted to purchase from Chelan 38.9% (505,000 KW of peak capacity as of December 31, 2002)2003) 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% (261,000 KW as of December 31, 2002)2003) 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 also be due for periods into the future. Since April 2003, Douglas County PUD and Colville Tribe representatives have discussed settlement of this issue. The settlement discussions may lead to a resolution of the claim. A settlement of this claim could affect the quantity or the price of the output of the Wells Project purchased by PSE. PSE has contracted to purchase from Grant County PUD 8.0% (72,000 KW as of December 31, 2002)2003) of the annual output of the Priest Rapids Development and 10.8% (98,000 KW of peak capacity as of December 31, 2002)2003) of the annual output of the Wanapum Development, which percentages remain unchanged for the remainder of the contractsoriginal 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 contractscontracts' 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’sCounty 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, they haveFERC 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 April 16, 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.
ELECTRIC 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 relating to Washington Public Power Supply System Nuclear Project No. 3, in which PSE had a 5% interest, PSE is entitled to receive electric power from BPA, beginning January 1, 1987, electric power during the months of November through April. Under the contract, PSE is guaranteed to receive not less than 191,667 MWh in each contract year until PSE has received total deliveries of 5,833,333 MWh. PSE expects the contract to be in effect until at least June 2008. Also pursuant to the 1985 settlement agreement, BPA has an option to request that PSE deliver up to 6456 MW of exchange energy to BPA in all months except May, July and August for contract year 2002/2003.2003 — 2004.
On DecemberOctober 31, 2002,2003, a 15 year15-year contract for the purchase of firm power contractand energy between Avista CorporationPacifiCorp and PSE expired under the terms of the agreement. The contract provided for the delivery of 100 MW of capacity and 657,000 MWh of energy from the Avista system annually (75 annual average MW). On October 27, 1988, PSE executed a 15-year contract for the purchase of firm power and energy from PacifiCorp. Under the terms of the agreement, PSE receives 120 average MW of energy and 200 MW of peak capacity. This contract expires on October 31, 2003.capacity annually.
On October 1, 1989, PSE signed a contract with The Montana Power Company, which subsequently sold its utility assets to Northwestern EnergyNorthWestern Corporation (NorthWestern) in 2002 under which Northwestern Energy2002. Under the contract, NorthWestern provides PSE from its share of Colstrip Unit 4, 71 average MW of energy (97 MW of peak capacity) over a 21-year period. This contract expires in December 2010. On September 14, 2003, NorthWestern filed a voluntary petition for relief under Chapter 11 of 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. PSE and NorthWestern entered into a settlement of one outstanding dispute concerning transmission losses associated with power deliveries to PSE under the 21-year power purchase agreement PSE has with NorthWestern. That settlement was approved by the bankruptcy court on December 11, 2003. PSE does not expect the filing of NorthWestern’s petition to have a material impact upon the financial condition, results of operations or liquidity of the Company.
PSE executed an exchange agreement with Pacific Gas & Electric Company (PG&E) which became effective on January 1, 1992. Under the agreement, 300 MW of capacity together with up to 413,000 MWh of energy are exchanged seasonally every year on a unit-for-unit basis.each year. No payments are made under this agreement. PG&E is a summer peaking utility and will provideprovides power during the months of November through February. PSE is a
winter peaking utility and will provideprovides power during the months of June through September. Each party may terminate the contract for various reasons.
upon notifying the other party at least five years in advance. On December 20, 2001, PSE notified PG&E of its intent to terminate the agreement as of the end of 2006. In October 1997 a 10-year power exchange agreement betweenMay 2002, PG&E responded and stated its view that PSE’s notice was void due to PG&E’s bankruptcy. PSE and Powerex (a subsidiary of a British Columbia utility) became effective. Under this agreement Powerex pays PSE forhas not responded to the right to deliver power 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.PG&E letter.
ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITY GENERATORS
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 most significant of these are the contracts described below which PSE entered into in 1989, 1990 and 1991 with operators of natural gas-fired cogeneration projects. 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 MW of energy and 123 MW of capacity, beginning in April 1993, from Sumas Cogeneration Company, L.P., 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, 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.
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, L.P., 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, 20022003 was $231.0$216.7 million, which will be recovered in electric rates overthrough 2011. In the next nine years. In addition, PSEpower cost only rate case, the Washington Commission staff has identified a portion of this asset as a possible disallowance for the future rate recovery. The power cost only rate case order from the Washington Commission is responsible for any potential tax indemnification to the seller imposed by the Internal Revenue Service up to a maximum of $30 million.expected in mid-April 2004.
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.agreement. The balance of the regulatory asset at December 31, 2003 is $11.0 million, which will be recovered in electric rates through 2008. In the power cost only rate case, the Washington Commission staff has identified a portion of this asset as a possible disallowance for future rate recovery. The power cost only rate case order from the Washington Commission is expected in mid-April 2004.
ELECTRIC TRANSMISSION CONTRACTS WITH OTHER UTILITIES
PSE has entered into numerous transmission contracts with BPA to integrate electric generation resources and energy contracts into the PSE system. These transmission contracts specify that PSE will pay based on the contracted level of transmission service, regardless of actual use.
The general transmission agreement with BPA provides for the integration of PSE’s share of the Colstrip Project and the PG&E exchange. The hourly demand limit is 1,161 MW. This contract is effective through July 31, 2014.
PSE has an additional six transmission agreements with BPA to integrate PSE’s share of the Mid-Columbia hydro projects. The hourly demand limit of all six contracts totals 1,136 MW. The contracts have remaining terms from 2 to 15 years.
PSE’s transmission expenses for integrating its firm resources was $35.1 million in 2003. 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.
In October 1997, a 10-year power exchange agreement between PSE and Powerex (a subsidiary of a British Columbia utility) became effective. Under this agreement, 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.
| TWELVE MONTHS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas operating revenues by classes (thousands): | ||||||||||||||||||||||
| Residential | $ | 428,569 | $ | 486,761 | $ | 372,900 | $ 401,717 | $ 428,569 | $ 486,761 | |||||||||||||
| Commercial firm | 167,434 | 196,904 | 144,046 | 149,671 | 167,434 | 196,904 | ||||||||||||||||
| Industrial firm | 28,312 | 37,411 | 27,832 | 24,164 | 28,312 | 37,411 | ||||||||||||||||
| Interruptible | 48,889 | 71,997 | 44,485 | 34,046 | 48,889 | 71,997 | ||||||||||||||||
| Total retail gas sales | 673,204 | 793,073 | 589,263 | 609,598 | 673,204 | 793,073 | ||||||||||||||||
| Transportation services | 12,851 | 11,780 | 12,137 | 13,796 | 12,851 | 11,780 | ||||||||||||||||
| Other | 11,100 | 10,218 | 10,911 | 10,836 | 11,100 | 10,218 | ||||||||||||||||
| Total gas operating revenues | $ | 697,155 | $ | 815,071 | $ | 612,311 | $ 634,230 | $ 697,155 | $ 815,071 | |||||||||||||
| Number of customers served (average): | ||||||||||||||||||||||
| Residential | 565,003 | 548,497 | 532,333 | 583,439 | 565,003 | 548,497 | ||||||||||||||||
| Commercial firm | 45,916 | 45,998 | 44,817 | 46,813 | 45,916 | 45,998 | ||||||||||||||||
| Industrial firm | 2,727 | 2,789 | 2,863 | 2,685 | 2,727 | 2,789 | ||||||||||||||||
| Interruptible | 650 | 833 | 835 | 611 | 650 | 833 | ||||||||||||||||
| Transportation | 122 | 112 | 98 | 134 | 122 | 112 | ||||||||||||||||
| Total customers | 614,418 | 598,229 | 580,946 | 633,682 | 614,418 | 598,229 | ||||||||||||||||
| Gas volumes, therms (thousands): | ||||||||||||||||||||||
| Residential | 500,672 | 494,648 | 517,561 | 500,116 | 500,672 | 494,648 | ||||||||||||||||
| Commercial firm | 218,716 | 214,713 | 221,170 | 216,951 | 218,716 | 214,713 | ||||||||||||||||
| Industrial firm | 39,142 | 42,287 | 48,348 | 36,890 | 39,142 | 42,287 | ||||||||||||||||
| Interruptible | 81,045 | 98,733 | 103,446 | 61,739 | 81,045 | 98,733 | ||||||||||||||||
| Total retail gas volumes, therms | 839,575 | 850,381 | 890,525 | 815,696 | 839,575 | 850,381 | ||||||||||||||||
| Transportation volumes | 207,852 | 188,196 | 204,035 | 209,497 | 207,852 | 188,196 | ||||||||||||||||
| Total volumes | 1,047,427 | 1,038,577 | 1,094,560 | 1,025,193 | 1,047,427 | 1,038,577 | ||||||||||||||||
| Working-gas volumes in storage at year end, therms (thousands): | ||||||||||||||||||||||
| Working gas volumes in storage at year end, therms (thousands): | ||||||||||||||||||||||
| Jackson Prairie | 64,583 | 59,537 | 67,827 | 60,365 | 64,583 | 59,537 | ||||||||||||||||
| Clay Basin | 51,225 | 73,800 | 28,275 | 49,314 | 51,225 | 73,800 | ||||||||||||||||
| Average therms used by customer: | ||||||||||||||||||||||
| Average therms used per customer: | ||||||||||||||||||||||
| Residential | 886 | 902 | 972 | 857 | 886 | 902 | ||||||||||||||||
| Commercial firm | 4,763 | 4,668 | 4,935 | 4,634 | 4,763 | 4,668 | ||||||||||||||||
| Industrial firm | 14,354 | 15,162 | 16,887 | 13,739 | 14,354 | 15,162 | ||||||||||||||||
| Interruptible | 124,685 | 118,527 | 123,888 | 101,046 | 124,685 | 118,527 | ||||||||||||||||
| Transportation | 1,703,705 | 1,680,321 | �� | 2,081,989 | 1,563,410 | 1,703,705 | 1,680,321 | |||||||||||||||
| Average revenue per customer: | ||||||||||||||||||||||
| Residential | $ | 759 | $ | 887 | $ | 701 | $ 689 | $ 759 | $ 887 | |||||||||||||
| Commercial firm | 3,647 | 4,281 | 3,214 | 3,197 | 3,647 | 4,281 | ||||||||||||||||
| Industrial firm | 10,382 | 13,414 | 9,721 | 9,000 | 10,382 | 13,414 | ||||||||||||||||
| Interruptible | 75,214 | 86,431 | 53,275 | 55,722 | 75,214 | 86,431 | ||||||||||||||||
| Transportation | 105,336 | 105,179 | 123,846 | 102,955 | 105,336 | 105,179 | ||||||||||||||||
| Average revenue per therm sold: | ||||||||||||||||||||||
| Residential | $ | 0.855 | $ | 0.984 | $ | 0.720 | $ 0.803 | $ 0.855 | $ 0.984 | |||||||||||||
| Commercial firm | 0.766 | 0.917 | 0.651 | 0.690 | 0.766 | 0.917 | ||||||||||||||||
| Industrial firm | 0.723 | 0.885 | 0.576 | 0.655 | 0.723 | 0.885 | ||||||||||||||||
| Interruptible | 0.603 | 0.729 | 0.430 | 0.551 | 0.603 | 0.729 | ||||||||||||||||
| Average retail revenue per therm sold | 0.802 | 0.933 | 0.662 | 0.747 | 0.802 | 0.933 | ||||||||||||||||
| Transportation | 0.062 | 0.063 | 0.059 | 0.066 | 0.062 | 0.063 | ||||||||||||||||
GAS SUPPLY
PSE currently purchases a blended portfolio of gas supplies ranging from long-term firm short-term firm and non-firmto daily gas supplies from a diverse group of major and independent producers and gas marketers in the United States and Canada. PSE also enters into short-term physical and financial derivative instruments to hedge the cost of gas to serviceserve its customers. All of PSE’s gas supply is ultimately transported through the facilities of Williams/Williams Northwest Pipeline Corporation (NPC)(NWP), the sole interstate pipeline delivering directly into the Western Washington area.
| 2002 | 2001 | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Peak Firm Gas Supply at December 31 | Dth per Day | % | Dth per Day | % | ||||||||||
| Purchased gas supply: | ||||||||||||||
| British Columbia | 145,500 | 18 | .2% | 181,800 | 22 | .5% | ||||||||
| Alberta | 64,900 | 8 | .1% | 65,800 | 8 | .1% | ||||||||
| United States | 113,800 | 14 | .2% | 51,400 | 6 | .4% | ||||||||
| Total purchased gas supply | 324,200 | 40 | .5% | 299,000 | 37 | .0% | ||||||||
| Purchased storage capacity: | ||||||||||||||
| Clay Basin | 63,000 | 7 | .9% | 96,600 | 11 | .9% | ||||||||
| Jackson Prairie | 47,600 | 5 | .9% | 47,500 | 5 | .9% | ||||||||
| LNG | 70,800 | 8 | .8% | 70,700 | 8 | .7% | ||||||||
| Total purchased storage capacity | 181,400 | 22 | .6% | 214,800 | 26 | .5% | ||||||||
| Owned storage capacity: | ||||||||||||||
| Jackson Prairie | 265,000 | 33 | .1% | 265,000 | 32 | .8% | ||||||||
| Propane-air injection | 30,000 | 3 | .8% | 30,000 | 3 | .7% | ||||||||
| Total owned storage capacity | 295,000 | 36 | .9% | 295,000 | 36 | .5% | ||||||||
| Total peak firm gas supply | 800,600 | 100 | .0% | 808,800 | 100 | .0% | ||||||||
All peak firm gas supplies and storage are connected to PSE's market with firm transportation capacity.
| 2003 | 2002 | ||||||||
| Peak Firm Gas Supply at December 31 | Dth per | % | Dth per | % | |||||
| Purchased gas supply: | |||||||||
| British Columbia | 167,200 | 20 | .8% | 145,500 | 18 | .2% | |||
| Alberta | 76,700 | 9 | .6% | 64,900 | 8 | .1% | |||
| United States | 98,400 | 12 | .3% | 113,800 | 14 | .2% | |||
| Total purchased gas supply | 342,300 | 42 | .7% | 324,200 | 40 | .5% | |||
| Purchased storage capacity: | |||||||||
| Clay Basin | 54,900 | 6 | .8% | 63,000 | 7 | .9% | |||
| Jackson Prairie | 54,200 | 6 | .8% | 47,600 | 5 | .9% | |||
| LNG | 69,400 | 8 | .6% | 70,800 | 8 | .8% | |||
| Total purchased storage capacity | 178,500 | 22 | .2% | 181,400 | 22 | .6% | |||
| Owned storage capacity: | |||||||||
| Jackson Prairie | 251,600 | 31 | .4% | 265,000 | 33 | .1% | |||
| Propane-air injection | 30,000 | 3 | .7% | 30,000 | 3 | .8% | |||
| Total owned storage capacity | 281,600 | 35 | .1% | 295,000 | 36 | .9% | |||
| Total peak firm gas supply | 802,400 | 100 | .0% | 800,600 | 100 | .0% | |||
| 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 at generally lower prices in months of low market demand for gas, injecting it into underground storage facilities and withdrawing it during the winter heating season. Storage facilities at Jackson Prairie in Western Washington and at Clay Basin in Utah are used for this purpose. 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 ownedPSE-owned gas held in NPC’sNWP’s liquefied natural gas (LNG) facility at Plymouth, Washington, and by producing propane-air gas at a plant owned by PSE and located on its distribution system.system, and interrupting service to customers on interruptible service rates.
In 1998, PSE took assignment from a third party of a peaking gas supply service contract whereby PSE can divert up to 48,000 DekathermsDth per day (one Dekatherm, or Dth, is equal to one million British thermal units or MMBtu) of gas it supplies to Tenaska away from the Tenaska Cogeneration Facility and toward its core gas load by causing Tenaska to operate its facility on distillate fuel and paying any additionalthe replacement costs of the distillate fuel for such operation.operations.
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 PORTFOLIO
For the 2002-20032003-2004 winter heating season, PSE contracted for approximately 18.2%20.8% of its expected peak-day gas supply requirements from sources originating in British Columbia under a combination of long-term, medium-term and winter-peakingseasonal purchase agreements. Long-term gas supplies from Alberta represent approximately 8.1%9.6% of the peak-day requirements. Long-term and winter peaking arrangements with U.S. suppliers and gas stored at Clay Basin make up approximately 22.1%19.1% of the peak-day portfolio. The balance of the peak-day requirements is expected to be met with gas stored at Jackson Prairie, LNG held at NPC’sNWP’s Plymouth facility and propane-air resources, which represent approximately 39.0%38.2%, 8.8%8.6% and 3.8%3.7%, respectively, of expected peak-day requirements. PSE also has the ability to curtail service to wholesale-level customers on interruptible service rates during a peak-day event.
During 2002,2003, approximately 40%35% of gas supplies purchased by PSE originated in British Columbia while 21%22% originated in Alberta and 39%43% originated in the United States.
The current firm, long-term gas supply portfolio consists of arrangements with 1722 producers and gas marketers, with no single supplier representing more than 11%12% of expected peak-day requirements. Contracts have remaining terms ranging from less than 1one year to 9 years, with an average term of less than one year. With the exception of fixed price hedges for the period November 2002 through October 2003 making up a portion of the minimum planned customer requirements, gas supply contracts contain market-sensitive pricing provisions based on several published indices.eight years.
PSE’s firm gas supply portfolio is structured to capitalize on regional price differentials when they arise.arise due to the nature of its
transportation arrangements. Gas and services are marketed outside PSE’s service territory (off-system sales) whenever on-system customer demand requirements permit. The geographic mix of suppliers and daily, monthly and annual take requirements permit a highsome degree of flexibility in managing gas supplies during off-peak periods to minimize costs.
GAS TRANSPORTATION CAPACITY
PSE currently holds firm transportation capacity on pipelines owned by NPCNWP, Gas Transmission Northwest and PG&EDuke Energy Gas Transmission-Northwest (PGT).Transmission. 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 holdsand WNG CAP I, a wholly-owned subsidiary of PSE, hold firm year-round capacity on NPC’sNWP through various contracts. PSE and WNG CAP I participate in the secondary pipeline totaling 447,493capacity market to achieve savings for PSE’s customers. As a result, PSE and WNG CAP I hold approximately 465,000 Dth per day acquired under several agreements at various times.of capacity due to capacity release and segmentation transactions on NWP which 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 stored gas during the heating season. PSE has exchanged certain segments of its firm capacity with third parties to effectively lower transportation costs. PSE’s firm transportation capacity contracts with NPCNWP have remaining terms ranging from 2less than 1 year to 13.813 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 PGT’sGas Transmission Northwest’s pipeline, totaling 90,392approximately 90,000 Dth per day, has a remaining term of 2120 years. WNG CAP I, a wholly-owned subsidiary of PSE, holds PSE’s firm year-roundtransportation capacity on NPC’sDuke Energy Gas Transmission’s pipeline, totaling 75,494approximately 40,000 Dth per day, acquired under several agreements. WNG CAP I’shas a remaining term of 11 years for approximately 25,000 Dth per day and has a remaining term of 16 years for approximately 15,000 Dth per day.
During 2003, NWP took one of its two parallel pipelines that serve Western Washington 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. Prior to the second failure, the affected line had been operating at 80% of its maximum allowable operating pressure. If the affected pipeline is not returned to service, the loss could potentially decrease PSE’s overall NWP capacity by 12%. NWP is exploring options to meet firm transportationcontract obligations to PSE, which may include new pipeline construction or purchase of firm capacity contracts with NPCfrom customers of NWP who have remaining terms ranging from 1 yearexcess capacity. PSE does not expect the line to 13.5 years.
remain out of service indefinitely, and this event, to date, has not adversely impacted PSE’s ability to serve its customers. PSE expects to continue meeting its customer needs throughout the pipeline repair or remediation period.
GAS STORAGE CAPACITY
PSE holds storage capacity in the Jackson Prairie and Clay Basin underground gas storage facilities adjacent to NPC’sNWP’s pipeline. 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 NPC’sNWP’s one-third stake in Jackson Prairie, PSE has peak firm delivery capacity of over 318,000349,000 Dth per day and total firm storage capacity exceeding 7,500,0007,900,000 Dth at the facility. The location of the Jackson Prairie facility in PSE’s market area ensures supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day gas requirements. 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 utilizedalso used for withdrawals over the entire winter, capturing savings due to injecting lower cost gas supplies during the summer.system reliability. After the release of capacity, PSE hasretains maximum firm withdrawal capacity of over 64,00055,000 Dth per day from the Clay Basin facility with total storage capacity of almost 6,700,000 Dth. The capacity is held under two contracts with remaining terms of 1110 and 1716 years. PSE hasThe capacity release contracts PSE has with multiple parties at the Clay Basin storage facility withhave remaining terms ranging from 3 to 15of three months. PSE’s maximum firm withdrawal capacity and total storage capacity at Clay Basin is over 110,000 Dth per day and exceeds 13,000,000 Dth, respectively, when PSE has not released any of the capacity.
LNG AND 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, 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 contractscontract for storage of approximately 240,000241,700 Dth of PSE ownedPSE-owned gas as LNG at NPC’sNWP’s Plymouth facility, which equates to approximately three and one-half days’ supply at a maximum daily deliverability of 72,00070,500 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 30,000 Dth of gas per day for up to four days directly into PSE’s distribution system.
CAPACITY RELEASE
FERC provided a capacity release mechanism as the means for holders of firm pipeline and storage entitlements to temporarily 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 NPCNWP pipeline capacity not utilized during off-peak periods through capacity release. WNG CAP I a wholly-owned subsidiary of PSE, was formed to provide additional flexibility and benefits from capacity release. Capacity release benefits are passed on to customers through the PGA.
ENERGY CONSERVATION
PSE offers programs designed to help new and existing customers use energy efficiently. PSE uses a variety of mechanisms including cost effectivecost-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.
Since May 1997, PSE has recovered electric energy conservation expenditures through a tariff rider mechanism. The rider mechanism allows PSE to defer the conservation expenditures and amortize them to expense as PSE concurrently collects the conservation expenditures in rates over a one-year period. As a result of the rider, there is no effect on earnings.
Since 1995, PSE has been authorized by the Washington Commission to defer gas energy conservation expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows PSE to defer conservation expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows PSE to recover an Allowance for Funds Used to Conserve Energy (AFUCE) on any outstanding balance that is not being recovered in rates.
ENVIRONMENT
Puget Energy’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, Puget Energy cannot determine the impact such laws may have on its existing and future facilities. (See Note 1618 to the Consolidated Financial Statements for further discussion of environmental sites.)
REGULATION OF EMISSIONS
PSE has an ownership interest in coal-fired, steam-electric generating plants at Colstrip, Montana, which are subject to regulation of emissions and other regulatory requirements. PSE also owns 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.
There is no assurance that in the future environmental regulations affecting sulfur dioxide, carbon monoxide, particulate matter or nitrogen oxide emissions may not be further restricted, or that restrictions on greenhouse gas emissions, such as carbon dioxide, or other combustion byproducts, such as mercury, may not be imposed.
FEDERAL ENDANGERED SPECIES ACT
Since the 1991 listing of the Snake River Sockeye salmon as an endangered species, one more species of salmon has been listed and two more have been proposed which may further influence operations. Upper Columbia River Steelhead was listed by National Marine Fisheries Service in August 1997. Anticipating the Steelhead listing, the Mid-Columbia PUDs initiated consultation with the federal and state agencies, Native American tribes and non-governmental organizations to secure operational protection through a long-term settlement and habitat conservation plan which includes fish protection and enhancement measurementmeasures for the next 50 years. The negotiations have concluded among the Chelan and Douglas County PUDs and various fishery agencies, and final agreement is subject to a National Environmental Policy Act review and power purchaser approval. Generally, the agreement obligates 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 has yet to reach agreement on these issues.
The proposed listings of Puget Sound Chinook salmon and spring Chinook salmon for the upper Columbia River were approved in March 1999. The Company does not expect the listing of spring Chinook salmon for the upper Columbia River should notto 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 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 changes may adversely affect hydro plant operations and permit issuance for facilities construction, and increase costs for processprocesses and facilities. Because PSE relies substantially less on hydroelectric energy from the Puget Sound area than from the Mid-Columbia River and 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. PSE is actively engaging the federal agencies to address Endangered Species Act issues for PSE’s generating facilities. The consultationConsultation with the federal agencies is ongoing.
EXECUTIVE OFFICERS OF THE REGISTRANTS REGISTRANTS
The executive officers of Puget Energy as of February 28, 2003January 31, 2004 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.
| NAME | AGE | OFFICES | |||
| S. P. Reynolds | President and Chief Executive Officer since January 2002. Director since January 2002. | ||||
| J. | |||||
| Corporate Secretary and Chief Accounting Officer since April 1999. | |||||
| D. E. Gaines | 46 | Vice President Finance and Treasurer since March 2002. | |||
| 41 | 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, and Managing Director of Emerge Corporation, 1999 - - 2000. | ||||
| J. L. O' Connor | 47 | Vice President and General Counsel since January 2003. | |||
| B. A. | Senior Vice President Finance and Chief Financial Officer since January | ||||
The executive officers of Puget Sound Energy as of February 28, 2003January 31, 2004 are listed below along with their business experience during the past five years. Officers of Puget Sound Energy are elected for one-year terms.
| NAME | AGE | OFFICES | |||
| President and Chief Executive Officer since January 2002; President and Chief Executive Officer of Reynolds Energy International, 1998 - 2002; | |||||
| Vice President Customer Services since February 2003; Director and Assistant to Chief Operating Officer, 2002 - | |||||
| 47 | Vice President Regional and Public Affairs since September 2003. Prior to joining PSE, he was President of the Washington Round Table, 1996 - 2003. | ||||
| M. N. Clements | 44 | Vice President Human Resources and Labor Relations since September 2003. Prior to joining PSE, she was Vice President of Human Resources of Eddie Bauer, Inc., 1998 - 2003. | |||
| J. W. Eldredge | Vice President, Corporate Secretary, Controller and Chief Accounting Officer since May 2001; Corporate Secretary, Controller and Chief Accounting Officer, 1993 - 2001. | ||||
| 46 | Vice President Finance and Treasurer since March 2002; Vice | ||||
| Vice President Engineering and Contracting since October 2003; Vice President Energy Supply, | |||||
| Vice President Governmental and Regulatory Relations since February 2003; Vice President Regulatory Affairs, 2002 - 2003; Director Load Resource Strategies and Associate General Counsel, 2001 - 2002; Associate General Counsel, 1999 - 2001. | |||||
| Senior Vice President Energy Efficiency and Customer Services since February 2003; Director of Major Accounts, 2001 - 2003; Director Construction and Technical Field Services | |||||
| 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; Vice President | |||||
| S. McLain | Senior Vice President Operations since February 2003; Vice President Operations - Delivery, 1999 - | ||||
| Vice President and General Counsel since January 2003. 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. | |||||
| Vice President Energy Portfolio Management since December 2001. Prior to joining PSE, she was Managing Director of North American Marketing of TransAlta USA, 2001; Managing Director Origination of Merchant Energy Group of the Americas, Inc., 1997 - 2001. |
| Senior Vice President Finance and Chief | ||
| P. M. Wiegand | 51 | Vice President Project Development and |
| Contract Management since July 2003; Vice President Corporate Planning, |
ITEM 2. PROPERTIES
The principal electric generating plants and underground gas storage facilities owned by PSE are described under Item 1, — Business —“Business – Electric Supply and Gas Supply.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.mortgage indentures.
InfrastruX operates a fleet of vehicles and machinesequipment that it uses in its utility construction business. Its fleet is comprisedcomposed 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.
ITEM 3. LEGAL PROCEEDINGS
See the section titled “Proceedings Relating to the Western Power Market” under Item 7, “Management’s Discussion and Analysis of Financial ConditionsCondition and Results of Operations” and the “Litigation” section of Note 16 of this Annual Report on Form 10-K.
Operations.” Contingencies arising out of the normal course of the Company’s business exist at December 31, 2002.2003. 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS
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. As of“PSD.” At December 31, 20022003, there were approximately 45,20043,200 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 20022003 and 2001.2002. Puget Energy and its predecessor companies have paid dividends on common stock each year since 1943 when such stock first became publicly held.
| Price Range | Dividends | Price Range | Dividends | | 2003 | | 2002 | | ||||||||||||||||||
| Quarter Ended | High | Low | Paid | High | Low | Paid | ||||||||||||||||||||
| PRICE RANGE | DIVIDENDS | PRICE RANGE | DIVIDENDS | |||||||||||||||||||||||
| QUARTER ENDED | QUARTER ENDED | HIGH | LOW | PAID | HIGH | LOW | PAID | |||||||||||||||||||
| March 31 | $23 | .60 | $19 | .20 | $0 | .46 | $27 | .75 | $20 | .63 | $0 | .46 | $ | 23.00 | $ | 18.10 | $ | 0.25 | $ | 23.60 | $ | 19.20 | $ | 0.46 | ||
| June 30 | 21 | .23 | 19 | .27 | 0 | .25 | 26 | .24 | 22 | .54 | 0 | .46 | 24.40 | 20.78 | 0.25 | 21.23 | 19.27 | 0.25 | ||||||||
| September 30 | 22 | .50 | 16 | .63 | 0 | .25 | 26 | .95 | 20 | .50 | 0 | .46 | 24.17 | 21.02 | 0.25 | 22.50 | 16.63 | 0.25 | ||||||||
| December 31 | 22 | .64 | 18 | .75 | 0 | .25 | 23 | .11 | 18 | .51 | 0 | .46 | 23.99 | 22.14 | 0.25 | 22.64 | 18.75 | 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 anticipated to pay out approximately 60% 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 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 $202.7$235.9 million at December 31, 2002.2003.
ITEM 6. SELECTED FINANCIAL DATA
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 | 20031 | 2002 | 20012 | 2000 | 1999 | ||||||
| Operating revenue | $ | 2,491,523 | $ | 2,392,322 | $ | 2,886,560 | $ | 3,302,296 | $ | 2,067,944 | |
| Operating income | 305,175 | 309,669 | 297,121 | 363,872 | 307,816 | ||||||
| Net income before cumulative effect | |||||||||||
| of accounting change | 121,517 | 117,883 | 121,588 | 193,831 | 185,567 | ||||||
| Income for common stock from | |||||||||||
| continuing operations | 116,197 | 110,052 | 98,426 | 184,837 | 174,502 | ||||||
| Basic earnings per common | |||||||||||
| share from continuing operations | 1.23 | 1.24 | 1.14 | 2.16 | 2.06 | ||||||
| Diluted earnings per common share | |||||||||||
| from continuing operations | 1.22 | 1.24 | 1.14 | 2.16 | 2.06 | ||||||
| Dividends per common share | 1.00 | 1.21 | 1.84 | 1.84 | 1.84 | ||||||
| Book value per common share | 16.71 | 16.27 | 15.66 | 16.61 | 16.24 | ||||||
| Total assets at year end | $ | 5,674,685 | $ | 5,772,133 | $ | 5,668,481 | $ | 5,677,266 | $ | 5,264,605 | |
| Long-term obligations | 1,969,489 | 2,160,276 | 2,127,054 | 2,170,797 | 1,783,139 | ||||||
| Preferred stock not subject to | |||||||||||
| mandatory redemption | -- | 60,000 | 60,000 | 60,000 | 60,000 | ||||||
| Preferred stock subject to | |||||||||||
| mandatory redemption | 1,889 | 43,162 | 50,662 | 58,162 | 65,662 | ||||||
| Corporation obligated, mandatorily | |||||||||||
| redeemable preferred securities of | |||||||||||
| subsidiary trust holding solely | |||||||||||
| junior subordinated debentures | |||||||||||
| of the corporation | -- | 300,000 | 300,000 | 100,000 | 100,000 | ||||||
| Junior subordinated debentures of | |||||||||||
| the corporation payable to a | |||||||||||
| subsidiary trust holding | |||||||||||
| mandatorily redeemable | |||||||||||
| preferred securities | 280,250 | -- | -- | -- | -- | ||||||
| PUGET SOUND ENERGY SUMMARY OF OPERATIONS (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) | |||||||||||
| YEARS ENDED DECEMBER 31 | 20031 | 2002 | 20012 | 2000 | 1999 | ||||||
| Operating revenue | $ | 2,149,736 | $ | 2,072,793 | $ | 2,712,774 | $ | 3,302,296 | $ | 2,067,944 | |
| Operating income | 297,904 | 294,593 | 288,480 | 363,872 | 307,816 | ||||||
| Net income before cumulative effect of | |||||||||||
| accounting change | 120,055 | 108,948 | 119,130 | 193,831 | 185,567 | ||||||
| Income for common stock from | |||||||||||
| continuing operations | 114,735 | 101,117 | 95,968 | 184,837 | 174,502 | ||||||
| Total assets at year end | $ | 5,334,787 | $ | 5,453,390 | $ | 5,439,253 | $ | 5,677,266 | $ | 5,264,605 | |
| Long-term obligations | 1,950,347 | 2,021,832 | 2,053,815 | 2,170,797 | 1,783,139 | ||||||
| Preferred stock not subject to | |||||||||||
| mandatory redemption | -- | 60,000 | 60,000 | 60,000 | 60,000 | ||||||
| Preferred stock subject to mandatory | |||||||||||
| redemption | 1,889 | 43,162 | 50,662 | 58,162 | 65,662 | ||||||
| Corporation obligated, mandatorily | |||||||||||
| redeemable preferred securities of | |||||||||||
| subsidiary trust holding solely | |||||||||||
| junior subordinated debentures of | |||||||||||
| the corporation | -- | 300,000 | 300,000 | 100,000 | 100,000 | ||||||
| Junior subordinated debentures of the | |||||||||||
| corporation payable to a subsidiary | |||||||||||
| trust holding mandatorily | |||||||||||
| redeemable preferred securities | 280,250 | -- | -- | -- | -- | ||||||
| 1 | In 2003, the 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, 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 value. |
| YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||
| Operating revenue | $ | 2,392,322 | $ | 2,886,560 | $ | 3,302,296 | $ | 2,067,944 | $ | 1,923,856 | |||||||
| Operating income | 309,669 | 297,121 | 363,872 | 307,816 | 295,098 | ||||||||||||
| Income before cumulative effect of | 117,883 | 121,588 | 193,831 | 185,567 | 169,612 | ||||||||||||
| accounting change | |||||||||||||||||
| Income for common stock from continuing | 110,052 | 98,426 | 184,837 | 174,502 | 156,609 | ||||||||||||
| operations | |||||||||||||||||
| Basic and diluted earnings per common share | 1.24 | 1.14 | 2.16 | 2.06 | 1.85 | ||||||||||||
| from continuing operations | |||||||||||||||||
| Dividends per common share | 1.21 | 1.84 | 1.84 | 1.84 | 1.84 | ||||||||||||
| Book value per common share | 16.27 | 15.66 | 16.61 | 16.24 | 16.00 | ||||||||||||
| Total assets at year-end | $ | 5,657,491 | $ | 5,546,977 | $ | 5,556,669 | $ | 5,145,606 | $ | 4,709,687 | |||||||
| Long-term obligations | 2,149,733 | 2,127,054 | 2,170,797 | 1,783,139 | 1,475,106 | ||||||||||||
| Preferred stock not subject to mandatory | 60,000 | 60,000 | 60,000 | 60,000 | 95,075 | ||||||||||||
| redemption | |||||||||||||||||
| Preferred stock subject to mandatory | 43,162 | 50,662 | 58,162 | 65,662 | 73,162 | ||||||||||||
| redemption | |||||||||||||||||
| Corporation obligated, mandatorily | 300,000 | 300,000 | 100,000 | 100,000 | 100,000 | ||||||||||||
| redeemable preferred securities of | |||||||||||||||||
| subsidiary trust holding solely junior | |||||||||||||||||
| subordinated debentures of the | |||||||||||||||||
| corporation | |||||||||||||||||
Puget Sound EnergySummary of Operations(Dollars in thousands)
| YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||
| Operating revenue | $ | 2,072,793 | $ | 2,712,774 | $ | 3,302,296 | $ | 2,067,944 | $ | 1,923,856 | |||||||
| Operating income | 294,593 | 288,480 | 363,872 | 307,816 | 295,098 | ||||||||||||
| Income before cumulative effect of | 108,948 | 119,130 | 193,831 | 185,567 | 169,612 | ||||||||||||
| accounting change | |||||||||||||||||
| Income for common stock from continuing | 101,117 | 95,968 | 184,837 | 174,502 | 156,609 | ||||||||||||
| operations | |||||||||||||||||
| Total assets at year-end | $ | 5,338,748 | $ | 5,317,750 | $ | 5,556,669 | $ | 5,145,606 | $ | 4,709,687 | |||||||
| Long-term obligations | 2,021,832 | 2,053,815 | 2,170,797 | 1,783,139 | 1,475,106 | ||||||||||||
| Preferred stock not subject to mandatory | 60,000 | 60,000 | 60,000 | 60,000 | 95,075 | ||||||||||||
| redemption | |||||||||||||||||
| Preferred stock subject to mandatory | 43,162 | 50,662 | 58,162 | 65,662 | 73,162 | ||||||||||||
| redemption | |||||||||||||||||
| Corporation obligated, mandatorily | 300,000 | 300,000 | 100,000 | 100,000 | 100,000 | ||||||||||||
| redeemable preferred securities of | |||||||||||||||||
| subsidiary trust holding solely junior | |||||||||||||||||
| subordinated debentures of the | |||||||||||||||||
| corporation | |||||||||||||||||
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL 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 PSE’s objectives, expectations and intentions. 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. 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. 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 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 is an energy services holding company and all of its operations are conducted through its two subsidiaries. These subsidiaries are PSE, a regulated electric and gas utility company, and InfrastruX, a utility construction and services company.
PUGET SOUND ENERGY
PSE generates revenues from the sale of electric and gas services, mainly to residential and commercial customers within Washington State. A majority of PSE’s revenues are generated in the first and fourth quarters during the winter heating season in Washington State.
As a regulated utility company, PSE is subject to FERC and 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 which can damage transmission lines; and energy trading and wholesale market stability over time.
PSE’s main operational goal has been to provide cost-effective and stable energy prices to its customers. To help accomplish this goal, PSE is attempting 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. As such, PSE is in the process of purchasing a 49.85% interest in a 275 MW (250 MW capacity with 25 MW planned capital improvements) gas-fired generation facility within Western Washington, which is currently before the Washington Commission for approval in the power cost only rate case, with an expected order by mid-April 2004. In addition, the purchase will also require approval from FERC. PSE has filed its application with FERC and anticipates approval in early 2004. This purchase is the first step of PSE’s long-term electric Least Cost Plan that was filed April 30, 2003 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.
INFRASTRUX
InfrastruX generates revenues mainly from maintenance services and construction contracts in the south/Texas, north-central and eastern United States. A majority of its revenues are generated during the second and third quarters which are generally 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 upon under fixed-fee contracts; continued economic downturn that limits the amount of projects available thereby reducing available profit margins from 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. InfrastruX has acquired 12 entities since 2000, including one acquisition in 2003.
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PUGET ENERGY
All of the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX. Net income in 20022003 was $121.3 million on operating revenues of $2.5 billion, compared to $117.9 million on operating revenues of $2.4 billion compared toin 2002 and $106.8 million on operating revenues of $2.9 billion in 2001 and $193.8 million on operating revenues of $3.3 billion in 2000.2001. Income for common stock was $116.2 million in 2003, compared to $110.1 million in 2002 compared toand $98.4 million in 2001 and $184.8 million in 2000.2001.
Basic and diluted earnings per share in 20022003 were $1.23 on 94.8 million weighted average common shares outstanding compared to $1.24 on 88.4 million weighted average common shares outstanding compared toin 2002 and $1.14 on 86.4 million weighted average common shares outstanding in 2001 and $2.162001. Diluted earnings per share were $1.22 on 85.495.3 million weighted average common shares outstanding compared to $1.24 on 88.8 million weighted average common shares outstanding in 2000.2002 and $1.14 on 86.7 million weighted average common shares outstanding in 2001.
Net income in 2003 was positively impacted by an increase in utility net income of $10.9 million due to increased electric and gas margins primarily from a full year’s effect of the September 1, 2002 general gas rate increase 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 $11.4 million. This was offset by a $6.1 million downward adjustment in the carrying value of a non-utility venture capital investment in the fourth quarter of 2003, a $4.8 million increase in depreciation and amortization and an $11.7 million decrease in gains on derivative instruments due to a 2002 gain from de-designated contracts from a non-creditworthy counterparty under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In addition, federal tax refunds decreased in 2003 to $9.3 million compared to $10.3 million in 2002. Net income was also negatively impacted by a decrease in InfrastruX net income of $7.7 million, net of minority interest, due to unusually wet weather affecting productivity in the first quarter of 2003 and increased competition in the marketplace.
Net income in 2002 was positively impacted by an increase in utility net income of $23.9$4.6 million from 2001 due to increased electric and gas margins resulting from general tariff rate increases. In addition, net income was positively impacted by $10.9$10.3 million of one-time federal tax refunds in 2002. Net income in 2002 was negatively impacted by a decrease in non-utility net income of $19.8$22.8 million primarily due to a decline in property sales from 2001 at PSE’s real estate investment and development subsidiary, Puget Western, Inc., and aan $8.0 million gain on PSE’s sale of the assets in its ConneXt subsidiary in August 2001. This was partially offset by an increase of $6.9 million in net income, net of minority interest, at InfrastruX.
Total kilowatt-hourkWh energy sales to retail consumers in 20022003 were 19.319.6 billion compared with 19.3 billion in 2002 and 19.9 billion in 2001 and 21.9 billion in 2000.2001. Kilowatt-hour sales to wholesale customers were 5.1 billion in 2003, 3.5 billion in 2002 and 5.0 billion in 2001 and 14.2 billion in 2000. Kilowatt-hours transported to transportation customers under a new tariff established in 2001 were 2.3 billion in 2002 and 364 million in 2001. Kilowatt-hours transported to transportation customers under a terminated pilot program were 164 thousand2.0 billion in 2000.2003, 2.3 billion in 2002 and 0.4 billion in 2001.
Total gas sales to retail consumers in 20022003 were 839.6815.7 million therms compared with 839.6 million therms in 2002 and 850.4 million therms in 2001 and 890.5 million therms in 2000.2001. Total gas sales to transportation customers in 20022003 were 209.5 million therms compared to 207.9 million therms compared within 2002 and 188.2 million therms in 2001.
PUGET SOUND ENERGY
The table below sets forth changes in the results of operations for PSE and its subsidiaries.
| INCREASE (DECREASE) OVER PRECEDING YEAR (DOLLARS IN MILLIONS) YEARS ENDED DECEMBER 31 | 2003 | 2002 | ||||||||||||||||||
| Operating revenue changes: | ||||||||||||||||||||
| Electric interim and general rate increase | $ | 2 | .3 | $ | 57 | .0 | ||||||||||||||
| BPA residential exchange credit | (25 | .1) | (49 | .7) | ||||||||||||||||
| Electric sales to other utilities and marketers | 103 | .2 | (445 | .7) | ||||||||||||||||
| Electric revenue sold at index rates to retail customers | (4 | .4) | (183 | .9) | ||||||||||||||||
| Electric conservation trust credit | 5 | .0 | 18 | .3 | ||||||||||||||||
| Electric transportation revenue | (4 | .0) | 13 | .0 | ||||||||||||||||
| Electric load and other | 66 | .6 | 91 | .7 | ||||||||||||||||
| Total electric operating change | 143 | .6 | (499 | .3) | ||||||||||||||||
| Gas general rate increase | 24 | .2 | 11 | .8 | ||||||||||||||||
| Gas retail load and PGA rate change | (86 | .4) | (131 | .7) | ||||||||||||||||
| Gas transportation revenue and other | (0 | .7) | 2 | .0 | ||||||||||||||||
| Total gas operating change | (62 | .9) | (117 | .9) | ||||||||||||||||
| Other revenue | (3 | .8) | (22 | .8) | ||||||||||||||||
| Total operating revenue change | 76 | .9 | (640 | .0) | ||||||||||||||||
| Operating expense changes: | ||||||||||||||||||||
| Energy costs: | ||||||||||||||||||||
| Purchased electricity | 177 | .8 | (273 | .3) | ||||||||||||||||
| Residential exchange power cost credit | (23 | .9) | (74 | .1) | ||||||||||||||||
| Purchased gas | (77 | .9) | (132 | .4) | ||||||||||||||||
| Electric generation fuel | (48 | .5) | (167 | .9) | ||||||||||||||||
| Unrealized gain/loss on derivative instruments | 11 | .7 | (0 | .4) | ||||||||||||||||
| Utility operations and maintenance: | ||||||||||||||||||||
| Production operations and maintenance | (2 | .0) | 2 | .3 | ||||||||||||||||
| Personal energy management expenses | (6 | .3) | (5 | .9) | ||||||||||||||||
| Low-income program pass-through expenses | 3 | .3 | 3 | .8 | ||||||||||||||||
| Other utility operations and maintenance | 8 | .4 | 20 | .2 | ||||||||||||||||
| Other operations and maintenance | (0 | .4) | (6 | .9) | ||||||||||||||||
| Depreciation and amortization | 4 | .8 | 6 | .6 | ||||||||||||||||
| Conservation amortization | 16 | .0 | 11 | .0 | ||||||||||||||||
| Taxes other than income taxes | (7 | .5) | (5 | .0) | ||||||||||||||||
| Income taxes | 18 | .1 | (24 | .1) | ||||||||||||||||
| Total operating expense change | 73 | .6 | (646 | .1) | ||||||||||||||||
| Other income change (net of tax) | (3 | .6) | (11 | .8) | ||||||||||||||||
| Interest charges change | (11 | .4) | 4 | .5 | ||||||||||||||||
| Cumulative effect of implementation of accounting change (net of tax) | 0 | .2 | (14 | .8) | ||||||||||||||||
| Net income change | $ | 10 | .9 | $ | 4 | .6 | ||||||||||||||
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. The following is additional information pertaining to the changes outlined in the above table.
Electric margin increased $19.3 million for 2003 compared to 2002 due primarily to the non-reoccurrence of losses associated with the
resale of gas supply for electric generation. Electric margin increased $2.7 million from 2001 to 2002 as a result of an increase in kWh sales and the full-year effect of the general rate case. 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 for 2001 through 2003 was:
| ELECTRIC MARGIN | |||||||||||||||||
| (DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31: | 2003 | 2002 | 2001 | ||||||||||||||
| Electric retail sales revenue | $ | 1,272 | .7 | $ | 1,260 | .9 | $ | 1,366 | .3 | ||||||||
| Electric transportation revenue | 11 | .5 | 15 | .5 | 2 | .5 | |||||||||||
| Other electric revenue-gas supply resale | 9 | .1 | (20 | .3) | (35 | .4) | |||||||||||
| Total electric revenue for margin | 1,293 | .3 | 1,256 | .1 | 1,333 | .4 | |||||||||||
| Adjustments for amounts included in revenue: | |||||||||||||||||
| Pass-through tariff items (conservation and low-income tariffs) | (45 | .2) | (32 | .1) | (36 | .6) | |||||||||||
| Pass-through revenue-sensitive taxes | (91 | .0) | (88 | .5) | (94 | .5) | |||||||||||
| Residential exchange credit | 173 | .8 | 150 | .0 | 75 | .9 | |||||||||||
| Net electric revenue for margin | 1,330 | .9 | 1,285 | .5 | 1,278 | .2 | |||||||||||
| Minus power costs: | |||||||||||||||||
| Electric generation fuel | (65 | .0) | (113 | .5) | (281 | .4) | |||||||||||
| Purchased electricity, net of sales to other utilities and | (635 | .2) | (557 | .1) | (384 | .6) | |||||||||||
| marketers | |||||||||||||||||
| Total electric power costs | (700 | .2) | (670 | .6) | (666 | .0) | |||||||||||
| Electric margin before PCA | 630 | .7 | 614 | .9 | 612 | .2 | |||||||||||
| Power cost deferred under the PCA | 3 | .5 | -- | -- | |||||||||||||
| Electric margin | $ | 634 | .2 | $ | 614 | .9 | $ | 612 | .2 | ||||||||
Gas margin increased $19.1 million in 2003 compared to 2002 due to the effects of the gas general rate increase effective September 1, 2002. Gas margin increased $19.5 million in 2002 compared to 2001 due primarily to the gas general rate increase effective September 1, 2002 and increased usage by customers. 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 for 2001 through 2003 was:
| GAS MARGIN | |||||||||||
| (DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31: | 2003 | 2002 | 2001 | ||||||||
| Gas retail revenue | $ | 609 | .6 | $ | 673 | .2 | $ | 793 | .1 | ||
| Gas transportation revenue | 13 | .8 | 12 | .9 | 11 | .8 | |||||
| Total gas revenue for margin | 623 | .4 | 686 | .1 | 804 | .9 | |||||
| Adjustments for amounts included in revenue: | |||||||||||
| Gas revenue hedge | 0 | .2 | 0 | .6 | -- | ||||||
| Pass-through tariff items (conservation and low-income tariffs) | (3 | .8) | (2 | .3) | (0 | .5) | |||||
| Pass-through revenue-sensitive taxes | (48 | .5) | (54 | .3) | (61 | .4) | |||||
| Net gas revenue for margin | 571 | .3 | 630 | .1 | 743 | .0 | |||||
| Minus purchased gas costs | (327 | .1) | (405 | .0) | (537 | .4) | |||||
| Gas margin | $ | 244 | .2 | $ | 225 | .1 | $ | 205 | .6 | ||
PUGET SOUND ENERGY
2003 COMPARED TO 2002
OPERATING REVENUES – ELECTRIC
Electric operating revenues increased $143.6 million in 2003 compared to 2002 due primarily to an increase of $103.2 million in wholesale electric sales to other utilities and marketers from greater surplus volumes. Wholesale sales volumes increased by 1.6 billion kWh or 47.4% compared to 2002. Retail sales volumes increased 1.8% to 19.6 billion kWh 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 reduces power costs by a corresponding amount with no impact on earnings. See Item 1, Business – Regulation and Rates – Residential and Small Farm Exchange Credit for further discussion.
During 2003, PSE collected in its electric general rate tariff as a reduction to revenue and remitted to a grantor trust $7.7 million as 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 of 2003 to meet the guidance of FASB Interpretation No. 46 (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 is reported as restricted cash on the balance sheet. At December 31, 2003, the balance sheet assets and liabilities have increased by $4.2 million.
PSE operates within the western wholesale market and has made sales into the California energy market. During the fourth quarter of 2000, PSE made sales to the California energy market on which the receivable amount is still outstanding. At December 31, 2003, PSE’s receivable from the California Independent System Operator (CAISO) and other counterparties, net of reserves, was $23.6 million. See the discussion of the CAISO receivable and California proceedings under “Proceedings Relating to the Western Power Market.”
OPERATING REVENUES – GAS
Regulated gas utility revenues in 2003 compared to 2002 decreased by $62.9 million or 9.0% due primarily to lower Purchased Gas Adjustment (PGA) rates in 2003 as a result of refunding the previous overcollection of PGA 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 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. On September 24, 2003, the Washington Commission approved a PGA rate increase of an annual average of 13.3% across all groups of customers effective October 1, 2003. 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 (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) and net income are not affected by changes under the PGA.
OTHER REVENUES
Other operating revenues decreased $3.8 million primarily due to a decrease in property sales for Puget Western, Inc. which generates a majority of its revenue through the development and sale of property.
OPERATING EXPENSES
Purchased electricityexpenses increased $177.8 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 compares to 108% of normal for the same period in 2002. PSE reached the $40 million cumulative cap under the PCA mechanism in 2003 primarily due to increased power costs and adverse hydro conditions. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE.
To meet customer demand, PSE dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydro 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 and intermediate-term off-system physical purchases and sales, and through other risk management techniques. A PSE Risk Management Committee oversees energy portfolio exposures.
Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with 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 “Regulation and Rates – Residential and Small Farm Exchange Credit.” The residential exchange credits are passed through to eligible residential and small farm customers by a corresponding reduction in revenues.
Purchased gasexpenses 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 gas market prices. The PGA 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 rates and accrues interest under the PGA. 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.
Electric generation fuelexpense 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.
Unrealized gains/losses on derivative instrumentsincreased $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 204.0settled 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. (For further discussion see Note 15.)
PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the mark-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.
Production operations and maintenancecosts decreased $2.0 million therms in 2003 compared to 2002 due primarily 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.
PSE’sPersonal Energy ManagementTMenergy-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.
TheLow-Income Programapproved by the Washington Commission in the general rate case settlement began in July 2002, which resulted in increased costs of $3.3 million in 2003 compared to 2002. These costs are fully recovered in retail rates beginning at the program’s inception on July 1, 2002 for electric service and September 1, 2002 for gas service.
Other utility operations and maintenancecosts increased $8.4 million in 2003 compared to 2002 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 power cost only rate case and meter reading expenses. Also included in the results is pension income related to PSE’s defined benefit pension plan recorded under SFAS No. 87, “Employers’ Accounting for Pensions.” Pension and benefit costs are 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% of $17.7 million for 2002. Qualified pension income is expected to decline to $8.6 million in 2004. During the fourth quarter of 2003, the Puget Sound region was hit by a severe windstorm that caused significant damage to PSE’s electric distribution system. The windstorm is 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 amortizationexpense increased $4.8 million in 2003 compared to 2002 due primarily to the effects of new plant placed in service during the past year.
Conservation amortizationincreased $16.0 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 taxesdecreased $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 of 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 the State of Washington property taxes.
Income taxesincreased $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 that 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 of 2003. The increase is also the result of the 2002 refunds totaling $10.3 million. The $10.3 million is 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
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 of 2003.
INTEREST CHARGES
Interest charges decreased $11.4 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 3.363% Senior Notes 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. RESULTS OF OPERATION OF PUGET ENERGY
INFRASTRUXINCREASE (DECREASE) OVER PRECEDING YEAR
YEARS ENDED DECEMBER 31
(Dollars in millions)2002 2001 Operating revenue changes: Electric interim rate increase $ 25 .0 $ -- Electric general rate increases 32 .0 12 .5 BPA residential exchange credit (49 .7) 11 .2 Electric sales to other utilities and marketers (443 .2) (587 .0) Electric revenue sold at index rates to retail customers (183 .9) (82 .4) Electric conservation trust credit 18 .3 4 .4 Electric transportation revenue 13 .0 2 .5 Optimization sales and purchases to other utilities (2 .5) 11 .0 Electric conservation incentive credit -- (19 .5) Electric load and other 91 .7 (119 .8) Total electric operating change (499 .3) (767 .1) Gas retail revenue change (131 .7) 203 .8 Gas general rate increase 11 .8 -- Gas transportation revenue and other 2 .0 (1 .1) Total gas operating change (117 .9) 202 .7 InfrastruX revenue 145 .7 128 .8 Other revenue (22 .7) 19 .8 Total other operating revenue change 123 .0 148 .6 Total operating revenue change (494 .2) (415 .8) Operating expense changes: Energy costs: Purchased electricity (273 .3) (708 .6) Residential exchange credit (74 .1) (34 .8) Purchased gas (132 .4) 204 .5 Fuel (167 .9) 98 .4 Unrealized (gain)/loss on derivative instruments (0 .4) (11 .2) Utility operations and maintenance : Production operations and maintenance 2 .3 2 .8 Personal energy management expenses (5 .9) 11 .1 Low income program pass through expenses 3 .8 -- Other utility operations and maintenance 20 .2 11 .8 InfrastruX operations and maintenance 122 .6 106 .6 Other operations and maintenance (6 .2) (10 .5) Depreciation and amortization 11 .2 21 .0 Conservation amortization 11 .0 (0 .3) Taxes other than income taxes 2 .8 10 .2 Income taxes (20 .5) (50 .0) Total operating expense change (506 .8) (349 .0) Other income change (net of tax) (9 .1) 9 .5 Interest charges change 6 .3 15 .0 Minority interest in earnings of consolidated subsidiary change 0 .9 -- Cumulative effect of implementation of accounting change (net of tax) (14 .7) 14 .7 Net income change $ 11 .0 $ (87 .0)
| INCREASE (DECREASE) OVER PRECEDING YEAR (DOLLARS IN MILLIONS) YEARS ENDED DECEMBER 31 | 2003 | 2002 | ||||||
| Operating revenue change: | ||||||||
| Other operating revenue | $ | 22 | .3 | $ | 145 | .7 | ||
| Operating expense change: | ||||||||
| Other operations and maintenance | 31 | .7 | 122 | .6 | ||||
| Depreciation and amortization | 3 | .3 | 4 | .6 | ||||
| Taxes other than income taxes | 0 | .5 | 7 | .8 | ||||
| Income taxes | (5 | .1) | 3 | .7 | ||||
| Total operating expense change | 30 | .4 | 138 | .7 | ||||
| Other income change (net of tax) | (0 | .3) | 2 | .7 | ||||
| Interest charges change | -- | 1 | .9 | |||||
| Minority interest change | (0 | .7) | 0 | .9 | ||||
| Net income change | $ | (7 | .7) | $ | 6 | .9 | ||
The following additional information pertains to the changes outlined in the table above:above.
INFRASTRUX
2003 COMPARED TO 2002
InfrastruX revenueincreased $22.3 million in 2003 compared to 2002 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.
InfrastruX operations and maintenanceexpenses 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 of 2003 as well as the high costs of completing work in low-volume activities in 2003.
Depreciation and amortizationincreased 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 taxesdecreased $5.1 million in 2003 compared to 2002 due to lower income.
PUGET SOUND ENERGY
2002 COMPARED TO 2001
OPERATING REVENUES – ELECTRIC
Electric operating revenues decreased $499.3 million in 2002 compared to 2001 due primarily to a decrease of $443.2$445.7 million in wholesale electric sales to other utilities and marketers due to lower surplus volumes and substantially lower prices in the wholesale electricity market. Wholesale sales volumes decreased by 1.5 billion kWh or 30.4%. Retail sales revenue decreased 7.7% primarily as a result of industrial and commercial customers on market index rates switching to transportation rate tariffs beginning in July 2001, as allowed by a Washington Commission order dated April 5, 2001 authorizing the establishment of a new electric transportation rate tariff. The decrease was offset by an interim electric rate surcharge in effect during the period April 1, 2002 through June 30, 2002, which increased electric revenue by $25 million, and a 4.6% electric general rate increase effective July 1, 2002, which increased electric revenue by approximately $32 million in 2002. Transportation revenues increased $13.0 million and volume increased 1.9 billion kWh in 2002.
To meet customer demand, PSE dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydro 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 and intermediate-term off-system physical purchases and sales, and through other risk management techniques. PSE’s Risk Management Committee oversees energy price risk matters.
PSE operates its combustion turbine plants located in Western Washington primarily as peaking plants when it is cost-effective to do so. During 2001, PSE had operated its combustion turbine plants extensively to meet both on-system and regional load requirements largely due to adverse hydroelectric conditions in the Pacific Northwest. For 2002, PSE did not operate the combustion turbines to the extent it did in 2001 since market prices did not support the dispatching of these units, and PSE could serve its customers with lower costlower-cost resources. As a result, sales to other utilities and marketers declined in 2002 due to low wholesale energy prices and the reduction in operations of the combustion turbines.
On June 20, 2002, the Washington Commission approved and adopted the settlement stipulation in the general rate case, putting new rates into effect on July 1, 2002. PSE established2002 and establishing a PCA mechanism in the rate case settlement. The PCA mechanism will account for differences in PSE’s modified actual power costs relative to a power cost baseline. The mechanism would account for a sharing of costs and benefits that are graduated over four levels of power cost variances, with an overall cap of $40 million (+/-) over the four yearfour-year period July 1, 2002 through June 30, 2006. PSE’s share of the cost through December 31, 2002 was $5.2 million. The factors influencing the variability of power costs included in the proposal are primarily weather or market related. PSE will be allowed to file for rate increases to implement limited power supply cost increases related to new resources.
On June 13, 2001, the Washington Commission approved an amended Residential Purchase and Sale Agreement between PSE and the BPA, under which PSE’s residential and small farm customers would continue to receive benefits of federal power. Completion of this agreement enabled PSE to continue to provide, and in fact increase, effective January 1, 2002, the Residential and Farm Energy Exchange 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. On June 17, 2002 PSE entered into an agreement with the BPA which amended the payment provisions of the Amended Settlement Agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement. To implement this agreement for rate purposes, the Washington Commission approved tariff revisions that were intended (a) to transfer the Residential and Farm Energy Exchange credit in effect since October 1, 1995 in the amount of $0.01085 per kWh, to general rates effective July 1, 2001 and (b) to provide a supplemental Residential and Farm Exchange credit for eligible residential and small farm customers. On June 26, 2002, the Washington Commission then transferred the portion of the credit that had been in general rates back into Schedule 194. The Residential and Farm Exchange Benefit Supplemental Rider schedule was retitled Residential and Farm Energy Exchange Benefit, the portion of the credit that had been in general rates was transferred back into Schedule 194, and the credit was set at $0.01456 per kWh for the period July 1, 2002 through September 30, 2002, $0.01817 per kWh for the period October 1, 2002 through May 31, 2006 and $0.02302 per kWh for the period June 1, 2006 through September 30, 2006. The approval of these revised tariffs by the Washington Commission was effective July 1, 2002. In January 2003, PSE filed tariff sheets with the Washington Commission to reflect a modification to the agreement between PSE and the BPA that would reduce the Residential and Farm Energy Exchange Benefit credit. Under the modified agreement, BPA will defer paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred will be $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA is entering into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA are agreeing to BPA’s deferral of payments in their fiscal year 2003. The total cumulative amount to be deferred under the agreement with PSE and other such agreements equals $55 million, an amount that will help BPA address its current financial difficulties. Absent certain adjustments, BPA will begin paying back the amount deferred with interest over the sixty-month period beginning November 2006. The Washington Commission approved the tariff changes and the Rider credit was changed to $0.01740 for the period February 15, 2003 through September 30, 2006. BPA’s rate case may affect the level of residential exchange benefits for PSE’s customers. For 2002, the benefits of the Residential and Farm Energy Exchange credited to customers were $152.8 million with a related offset to power costs. PSE received payments from BPA in the amount of $171.2 million during 2002. The difference between the customers’ credit and the amount received from BPA is deferred and will be credited to customers in later periods. The difference is recorded on PSE’s balance sheet as restricted cash. The modified Agreement will provide for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for pass-through to eligible residential and farm customers of the same amount. There are several actions in the Ninth Circuit Court of Appeals against BPA, in which the petitioners 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 contract between BPA and the Company described above. BPA rates used in such contract between BPA and the Company for determining the amounts of money to be paid to the Company during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC on an interim basis, subject to refund with interest. It is not clear what impact, if any, review of such rates and the above-described Ninth Circuit Court of Appeals actions may have on the Company. In 2002, PSE collected and remitted to a grantor trust $12.7 million as a result of PSE’s sale of future electric revenues associated with its investment in conservation assets in its electric general rate tariff. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amounts owed by the trust to its bondholders was $18.9 million December 31, 2002.
OPERATING REVENUES – GAS
Regulated gas utility revenues in 2002 compared to 2001 decreased by $117.9 million due primarily to PGA rate decreases as a result of lower natural gas prices that are passed through to customers. Gas delivered for transportation customers increased $1.1 million or 19.7 million therms in 2002.
On August 29, 2001, the Washington Commission approved a decrease in PSE’s natural gas rates of 8.9% due to lower natural gas costs purchased for customers under terms of the PGA mechanism effective September 1, 2001. Also, on May 24, 2002, the Washington Commission allowed a decrease in PGA rates of 21.2% to become effective on June 1, 2002. This ended a temporary surcharge that went into effect September 1, 2001. 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.
On August 28, 2002, the Washington Commission approved a 5.8% gas service rate increase in revenue to cover higher costs of providing natural gas service to customers. This service-related increase in revenues of approximately $35.6 million annually was offset by an annual $45 million or 7.3% PGA rate reduction, also approved on August 28, 2002. Both rate actions became effective September 1, 2002.
On September 30, 2002, PSE filed a proposal with the Washington Commission to reduce natural gas supply rates under the PGA for a third time in 2002. The Washington Commission approved the proposal on October 30, 2002 and PSE lowered gas rates through the PGA by approximately 12.5% effective November 1, 2002.
OTHER REVENUES
Other operating revenues decreased $22.7$22.8 million primarily due to a $22.9 million decrease in the gross margin on property sales from PSE’s real estate investment and development subsidiary, Puget Western, Inc.
OPERATING EXPENSES
Purchased electricityexpenses decreased $273.3 million in 2002 compared to 2001 due to the dramatic decline of wholesale electricity prices since June 2001 and an 83-day unplanned outage of one of PSE’s 104 MW combustion turbine electric generating units located at its Fredonia generating station from February 21, 2001 to May 14, 2001, resulting in higher purchased electricity costs during 2001. In addition, the historic low hydroelectric power generation conditions experienced in 2001 in a high pricedhigh-priced wholesale market forced PSE to purchase additional energy during that period to meet retail electric customer loads.
PSE’s hydroelectric production and related power costs in 2003 are expected to be impacted negatively by drought conditions in the Pacific Northwest region associated with El Nino weather conditions. The Northwest Rivers Forecast Center on February 6, 2003 predicted that streamflows in the Columbia River Basin above Grand Coulee Dam would be only 76 percent of normal. In a normal water year, PSE obtains about 38 percent38% of its energy supply from low-cost hydroelectric facilities, primarily from dams below Grand Coulee on the Columbia River. If the forecasted streamflow reductions occur, PSE will need to replace that low-cost hydropower with more expensive thermally-generated and purchased power. PSE’s share of the power costs through December 31, 2002 was $5.2 million. Because of adverse hydro conditions in 2003, PSE anticipates reaching the $40 million cumulative cap under the PCA mechanism by the frouth quarter of 2003. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to cutomers and 1% to PSE.
Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with BPA increased $74.1 million in 2002 compared to 2001 due to the amended Residential Purchase and Sale Agreement between PSE and BPA as discussed in Operating Revenues – Electric reflecting increased benefits passed on to residential and small farm customers. As of July 2001, all residential exchange credits are passed through to eligible residential and small farm customers by a corresponding reduction in revenues.
Purchased gasexpenses decreased $132.4 million in 2002 compared to 2001 primarily due to the impact of decreased gas costs, which are passed through to customers through the PGA mechanism, offset by a 1% increase in sales volumes. The PGA 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 rates and accrues interest under the PGA. The PGA balance was a receivable at December 31, 2001 of $37.2 million while the balance at December 31, 2002 was a liability of $83.8 million.
Electric generation fuelexpense decreased $167.9 million in 2002 compared to 2001 as a result of decreased generation costs at PSE-controlled combustion turbine facilities and lower wholesale energy prices. These facilities operated at much higher levels during 2001 compared to 2002 to meet retail electric customer loads due to adverse hydroelectric conditions in 2001.
Unrealized gains/losses on derivative instrumentsduring 2002 resulted in a decrease in expense of $0.4 million pre-tax ($0.3 million after-tax).million. 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. In addition, SFAS No. 133 was adopted on January 1, 2001, and as a result, a one-time $14.7$14.8 million after-tax transition loss was recorded in 2001 from recognizing the cumulative effect of this change in accounting principle. (For further discussion see Note 17).
Production operations and maintenancecosts increased $2.3 million in 2002 compared to 2001 due primarily to a $2.0 million pre-tax charge related to an industrial accident at Colstrip unitsUnits 1 and 2, of which PSE is a 50% owner, overall higher operating costs for the Colstrip generating facilities and the settlement of a combustion turbine insurance claim.
PSE’sPersonal Energy ManagementTMenergy-efficiency program costs decreased $5.9 million in 2002 compared to 2001, 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.
A newLow-incomeLow-Income Programapproved by the Washington Commission in the general rate case settlement began in July 2002 which resulted in increased costs of $3.8 million in 2002 compared to 2001. These costs are fully recovered in retail rates beginning at the program’s inception on July 1, 2002 for electric and September 1, 2002 for gas.
Other utility operations and maintenancecosts increased $20.2 million in 2002 compared to 2001 due primarily to higher expense related to a one-time PSE employee severance cost totaling $4.2 million related to strategic outsourcing of operations work to service providers, and an overall increase in administrative and meter reading expenses. Also included in the results is pension income related to PSE’s defined benefit pension plan forrecorded under SFAS No. 87, “Employers’ Accounting for Pensions”.Pensions.” Pension and benefit costs are allocated between capital and operations and maintenance expenses based on the distribution of labor costs in accordance with FERC accounting instructions. As a result, approximately 65.9%66.8% of the annual qualified pension income of $17.7 million for 2002 was recorded as a reduction in operationoperations and maintenance expense compared to 58%58.0% of $20.0 million for 2001. Qualified pension income is expected to decline to $9.6 million in 2003 as a result of lower actual returns on pension assets during the last three years and declining expected rates of return on pension fund assets.
PSE’sother operations and maintenanceexpenses decreased $6.2$6.9 million in 2002 compared to 2001 primarily due to a decrease in operating expenses at ConneXt, the assets of which were sold in the third quarter of 2001.
Depreciation and amortizationexpense increased $11.2$6.6 million in 2002 compared to 2001 of which $6.6 million is due primarily to the effects of additional plant placed into service at PSE during 2002.
Conservation amortizationincreased $11.0 million in 2002 compared to 2001 due to increased conservation expenditures. These costs are recovered in conservation rider and tracker mechanisms with no impact to earnings.
Taxes other than income taxesincreased $2.8 million, of which PSE’s decreased $5.0 million in 2002 compared to 2001 due primarily to a decrease in revenue basedrevenue-based Washington State excise tax and municipal tax. This iswas offset by a municipal tax expense of $1.7 million recorded in 2002 related to various claims by cities that PSE underpaid municipal taxes owed as a result of not collecting the tax in certain rural areas that were annexed by cities. The offset also includes a one-time property tax expense of $5.2 million covering a six yearsix-year period ending June 30, 2001 related to Oregon State of Oregon property tax bills on PSE’s long-term Third AC Transmission Intertie contract.
Income taxesdecreased $20.5$24.1 million in 2002 compared to 2001, of which PSE’s income taxes decreased by $24.1 million.2001. The decrease in 2002 includesincluded a total of $10.3 million in one-time refunds at PSE which are composed of which $4.7$4.1 million was recorded in the second quarter of 2002 related to the audit of the Company’s 1998 and 1999 federal income tax returns. Of this amount, $4.1 million reduced current tax expense and the balance, $0.6 million, was recorded as a deferred income tax liability. The decrease at PSE also includesreturns, a $3.5 million reduction to expense representing an adjustment to 2001 federal income taxtaxes based on the 2001 federal tax return filedand a $2.7 million reduction in the third quarter of 2002. The decrease in 2002 also includes flow-through benefits reducing federal income taxes of $2.7 millionexpense recorded in the fourth quarter of 2002 related to a refund of federal income taxes for 2000.
OTHER INCOME
Other income, net of federal income tax, decreased $9.1$11.8 million in 2002 compared to 2001 due primarily to a one-time $8.0 million after-tax gain realized by PSE on the sale of ConneXt’s assets in the third quarter of 2001.
INTEREST CHARGES
Interest charges, which consist of interest and amortization on long-term debt and other interest, increased $6.3$4.5 million in 2002 compared to 2001 of which PSE’s increased $4.4 millionprimarily as a result primarily of a full year’s interest expense on the issuance of $200 million 8.40% Trust Preferred Securities in May 2001. Other interest expense increased due primarily to a PGA liability (over-recovery of gas costs in rates) in 2002 compared to a PGA asset (under-recovery of gas costs in rates) in 2001. Under the PGA mechanism, interest is accrued on deferred balances.
INFRASTRUX
2002 COMPARED TO 2001
InfrastruX revenueincreased $145.7 million in 2002 compared to 2001 due primarily to acquisitions of several companies during 2001 and 2002, which contributed to an increase of $127.0$126.0 million. Excluding the impact of acquisitions, InfrastruX revenue increased $18.7 million from 2001 and was impacted positively by ice storm restoration work performed in Oklahoma by InfrastruX’s Texas companies and continued strong performance of remediation services in the utility industry. InfrastruX records revenues as services are performed or on a percent of completion basis for fixed pricefixed-price projects.
InfrastruX operationoperations and maintenanceexpenses increased $122.6 million in 2002 compared to 2001 primarily due to acquisitions during 2001 and 2002, which contributed to an increase of $103.8 million. Excluding the impact of acquisitions, InfrastruX operationoperations and maintenance expenses increased $18.9 million from 2001 and were impacted by the increase of corporate infrastructure to support a growing organization, additional costs of direct wages, construction costs and higher insurance costs incurred to support an increased revenue base.
Depreciation and amortizationincreased by $4.6 million in 2002 compared to 2001 due to acquisitions during 2001 and 2000, which contributed $3.5 million. Increases in depreciation of $1.1 million from core companies were due primarily to the acquisition of strategic assets to support areas of the companyInfrastruX where significant growth opportunities exist.
Taxes other than income taxesincreased $7.8 million in 2002 compared to 2001 primarily due to a $7.3 million increase in payroll tax resulting from an increased workforce as acquisitions have beenwere completed.
Income taxesincreased $3.7 million in 2002 compared to 2001 due primarily to the acquisition of companies acquired during 2001 and 2002. Acquired companies accounted for an increase of $5.8 million offset by a reduction in the effective tax rate due to certain non-deductible or partially deductible items.
Interest chargesincreased $1.9 million in 2002 compared to 2001 due to an increase in the amount drawn on itsInfrastruX’s revolving credit facilities primarily used for funding acquisitions.
Other income,net of federal income tax, increased $2.7 million in 2002 compared to 2001 due primarily to implementation of SFAS No. 142 which ceased amortization of goodwill. Goodwill amortization expense in 2001 was $2.8 million.PUGET SOUND ENERGY2001 COMPARED TO 2000OPERATING REVENUES — ELECTRIC Electric operating revenues decreased $767.1 million in 2001 compared to 2000 due to an overall average 0.9% general rate increase effective January 1, 2001 offset by sales to other utilities and marketers which decreased $587.0 million in 2001 due primarily to lower wholesale power volumes of 9.3 billion kWh and lower surplus capacity. Electric revenues in 2001 decreased due to lower regulated sales to customers, decreased prices and kilowatt-hours sold related to electric energy sales to other utilities and marketers and lower prices on market-index sales. This latter group of customers can choose another supplier or self-generate their energy needs. Several index rate customers switched to transportation rate tariffs beginning in July 2001 as allowed by a Washington Commission order dated April 5, 2001 authorizing the establishment of a transportation tariff. On June 19, 2001, FERC implemented price controls on wholesale electricity in the western states. Several factors contributed to the dramatic decline in wholesale electric prices by the end of the second quarter of 2001 and, therefore, greatly diminished the value of PSE’s excess electric energy during that period and into the foreseeable future. PSE and other western utilities filed an appeal asking FERC to review its June 19, 2001 order and make modifications to the price controls to stabilize wholesale prices in California and prevent the energy problems from spreading to other states. On December 19, 2001, FERC issued an order on clarification and rehearing addressing, in part, PSE’s petition for rehearing on the June 19, 2001 order. PSE and other entities have sought further rehearing and clarification of the December 19, 2001 order.
Electric revenues were reduced by approximately $19.5 million in 2001 compared to 2000 related to a customer conservation incentive credit which was approved by the Washington Commission on April 25, 2001. The conservation incentive credit was to reduce customers’ bills by $0.05 per kWh for each kWh reduction in excess of 10% from the same billing period in the prior year through December 31, 2001. On November 7, 2001, the Washington Commission approved PSE’s request to terminate the conservation incentive credit program effective November 8, 2001. Revenues from electric customers in 2001 were reduced by a Residential and Farm Energy Exchange credit tariff in place since October 1, 1995. Under the rate plan approved by the Washington Commission in its merger order, PSE reflected in customers’ bills the level of Residential Exchange benefits in place at the time of the merger with Washington Energy Company in 1997. On January 29, 1997, PSE and BPA signed an agreement under which PSE received payments from BPA of approximately $235 million over an approximate five-year period that ended June 2001. These payments were recorded as a reduction of purchased electricity expenses. As a result of lower usage by residential and farm customers in 2001, the residential and farm exchange credit decreased by $11.2 million as compared to 2000. For calendar 2001, the benefits of the Residential and Farm Energy Exchange credited to customers was $103.1 million as compared to an offsetting reduction in Purchased Electricity Expense of $75.9 million. Eligible residential and small farm customers received credits to their bills in the same amount. In 2001, PSE collected and remitted to two grantor trusts $31.0 million as a result of PSE’s sale of future electric revenues associated with its investment in conservation assets in its electric general rate tariff. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amounts owed by the trusts to its bondholders were $31.8 million at December 31, 2001. On April 15, 2001, the Washington Commission issued an order allowing PSE’s large industrial customers whose rates were linked to a market index to choose their supplier of electricity or to self-generate. If an industrial customer chooses an alternate supplier, PSE will provide the transportation of electricity to the customer’s premises and charge that customer for the service.OPERATING REVENUES – GAS Regulated gas utility sales revenue in 2001 compared to 2000 increased by $202.7 million from the prior year due primarily to higher natural gas prices which are passed through to customers in the PGA. Total gas volumes, including transported gas, decreased 5.1% in 2001 from 2000. Transportation and other revenue decreased $1.1 million or 15.8 million therms as industrial customers curtailed usage due to higher natural gas prices and water heater rental revenue declined.OTHER REVENUES Other revenues increased $19.8 million in 2001 compared to 2000 due primarily to increased gross margins on property sales at PSE’s real estate investment and development subsidiary Puget Western, Inc.OPERATING EXPENSESPurchased electricityexpenses decreased $708.6 million in 2001 compared to 2000. The decrease in 2001 was due primarily to lower volumes and significantly lower prices for non-firm power purchases from other utilities and marketers due to declining prices in the West Coast power market beginning in the second half of 2001.Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with BPA increased $34.8 million in 2001 compared to 2000 due to the terms set out in the 1997 Residential Exchange Termination Agreement and the 2001 Residential Purchase and Sale Agreement between PSE and BPA discussed in Operating Revenues – Electric. Beginning July 2001, all residential exchange credits are passed through to eligible residential and small farm customers by a corresponding reduction in revenues.Purchased gasexpenses increased $204.5 million in 2001 compared to 2000 primarily due to the impact of increased gas costs, which are passed through to customers through the PGA mechanism, offset by a 5.1% decrease in sales volumes.Electric generation fuelexpense increased $98.4 million in 2001 compared to 2000 as a result of increased generation and higher fuel costs at combustion turbine facilities. These facilities operated at much higher levels in 2001 compared to the same period in 2000 due to adverse hydroelectric conditions.
Unrealized gains/losses on derivative instruments— During 2001, an increase to operating earnings of approximately $11.2 million pre-tax ($7.3 million after-tax) was recognized for unrealized gains associated with electric derivative transactions and a $14.7 million after-tax transition adjustment loss was recorded from recognizing the cumulative effect of this change in accounting principle. (For further discussion see Note 17.)Production operations and maintenancecosts increased $2.8 million in 2001 compared to 2000 due primarily to an approximately $2.1 million increase in lease costs associated with PSE’s Fredonia 3 and 4 electric generation units offset by reduced operating costs resulting from the sale of the Centralia generating station in May 2000 and a net cost of $2.9 million after estimated insurance recovery to repair the PSE-owned Fredonia combustion turbine unit #1, which was out of service from February 21, 2001 through May 14, 2001. PSE’sPersonal Energy ManagementTMenergy-efficiency program costs increased $11.1 million in 2001, reflecting a full year of implementation compared to 2000. PSE began providing Personal Energy ManagementTM billing information to electric customers in December 2000.Other utility operations and maintenancecosts increased $11.8 million in 2001 compared to 2000 due primarily to repair costs associated with storm and earthquake damage in 2001, increased meter reading expenses associated with providing Personal Energy ManagementTM, and a one-time insurance recovery received in 2000. PSE’sother operations and maintenanceexpenses decreased $10.5 million in 2001 compared to 2000 primarily due to a decrease in operating expenses at ConneXt, the assets of which were sold in the third quarter of 2001.Depreciation and amortizationexpenses increased $21.0 million in 2001 compared to 2000 due to the effects of new plant placed into service during 2001, including ConsumerLinX, a customer information and billing system, which was placed into service in phases through late 2000 and early 2001.Taxes other than income taxesincreased $10.2 million in 2001 of which $5.0 million was attributed to PSE as a result of increases in municipal taxes and state excise taxes that are revenue based.Income taxesdecreased by $50.0 million in 2001 of which $52.9 million was attributed to PSE due to lower revenues and lower wholesale prices in the second half of the year.OTHER INCOME Other income, net of federal income tax, increased $9.5 million in 2001 compared to 2000 due primarily to $11.8 million of reserves established in 2000 for a write-down to the fair values of certain assets held for sale by Hydro Energy Development Corp. to their net realizable values not recurring in 2001, $4.8 million of other income realized by Puget Western, Inc. on investments in 2000 not recurring in 2001, $7.4 million of increase in other income of ConneXt primarily from sales of assets in 2001, offset by reductions in other income in 2001 for additional amortization of goodwill from acquisitions by InfrastruX, officer incentive compensation accruals, and decreased other interest and dividend income.
INTEREST CHARGES Interest charges, which consist of interest and amortization on long-term debt and other interest, increased $15.0 million in 2001, of which $11.3 million at PSE was attributed to a full year’s interest expense on the issuance of $25 million 7.61% Senior Medium-Term Notes, Series B in September 2000 and the issuance of $260 million 7.69% Senior Medium-Term Notes, Series C, in November 2000. In addition, interest was incurred on the issuance of $200 million 8.4% Trust Preferred Securities in May 2001. Other interest expense decreased $16.9 million compared to 2000 as a result of lower weighted average interest rates and lower average daily short-term borrowings.
INFRASTRUX2001 COMPARED TO 2000InfrastruX revenueincreased $128.8 million in 2001 compared to 2000. InfrastruX was formed in June 2000 and completed two acquisitions late in the third quarter of 2000. An additional six companies were acquired in 2001.InfrastruX operation and maintenanceexpenses increased $106.6 million in 2001 compared to 2000 due to limited operations in 2000 compared to a full year of operations and significant acquisition activity in 2001.Depreciation and amortizationincreased $6.6 million in 2001 compared to 2000 due to the completion of six acquisitions in 2001.Income taxesincreased $2.5 million in 2001 compared to 2000 due to the profitability of companies acquired during 2000 and 2001.Interest chargesincreased $3.5 million in 2001 compared to 2000 due to an increase in the amount drawn on its revolving credit facilities primarily used for funding acquisitions.
CAPITAL RESOURCES AND LIQUIDITY
CAPITAL REQUIREMENTS
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
Puget EnergyEnergy.. The following are Puget Energy's aggregate consolidated (including PSE) contractual and commercial commitments as of December 31, 2002:2003:
| Puget Energy | Puget Energy | Payments Due Per Period | Puget Energy | Payments Due Per Period | ||||||||||||||||||||||||||||||
| Contractual Obligations (Dollars in millions) | Total | 2003 | 2004-2005 | 2006-2007 | 2008 and Thereafter | |||||||||||||||||||||||||||||
| CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | Total | 2004 | 2005- 2006 | 2007- 2008 | 2009 and Thereafter | ||||||||||||||||||||||||||||
| Long-term debt | $ | 2,223 | .0 | $ | 73 | .2 | $ | 297 | .4 | $ | 216 | .0 | $ | 1,636 | .4 | $ | 2,216 | .3 | $ | 246 | .8 | $ | 128 | .3 | $ | 307 | .3 | $ | 1,533 | .9 | ||||
| Short-term debt | 47 | .3 | 47 | .3 | -- | -- | -- | 13 | .9 | 13 | .9 | -- | -- | -- | ||||||||||||||||||||
| Trust preferred securities (1) | 300 | .0 | -- | -- | -- | 300 | .0 | |||||||||||||||||||||||||||
| Preferred dividends (2) | 1 | .1 | 1 | .1 | -- | -- | -- | |||||||||||||||||||||||||||
| Junior subordinated debentures payable to a | ||||||||||||||||||||||||||||||||||
| subsidiary trust (1) | 280 | .3 | -- | -- | -- | 280 | .3 | |||||||||||||||||||||||||||
| Mandatorily redeemable preferred stock | 1 | .9 | -- | -- | -- | 1 | .9 | |||||||||||||||||||||||||||
| Service contract obligations | 190 | .2 | 19 | .4 | 40 | .7 | 43 | .4 | 86 | .7 | 181 | .0 | 21 | .7 | 45 | .0 | 47 | .4 | 66 | .9 | ||||||||||||||
| Capital lease obligations | 8 | .3 | 2 | .0 | 3 | .2 | 2 | .2 | 0 | .9 | 6 | .5 | 1 | .6 | 2 | .9 | 2 | .0 | -- | |||||||||||||||
| Non-cancelable operating leases | 66 | .1 | 18 | .2 | 23 | .8 | 14 | .6 | 9 | .5 | 72 | .5 | 18 | .0 | 25 | .1 | 19 | .0 | 10 | .4 | ||||||||||||||
| Fredonia combustion turbines lease (3) | 77 | .4 | 5 | .0 | 9 | .7 | 9 | .4 | 53 | .3 | ||||||||||||||||||||||||
| Fredonia combustion turbines lease (2) | 69 | .6 | 4 | .5 | 8 | .7 | 8 | .5 | 47 | .9 | ||||||||||||||||||||||||
| Energy purchase obligations | 4,603 | .8 | 849 | .6 | 951 | .1 | 827 | .9 | 1,975 | .2 | 4,737 | .4 | 928 | .2 | 1,245 | .0 | 1,036 | .7 | 1,527 | .5 | ||||||||||||||
| Financial hedge obligations | (21 | .5) | (6 | .3) | (7 | .6) | (6 | .3) | (1 | .3) | 67 | .0 | 30 | .5 | 17 | .7 | 18 | .8 | -- | |||||||||||||||
| Non-qualified pension funding | 38 | .6 | 11 | .1 | 3 | .1 | 4 | .5 | 19 | .9 | ||||||||||||||||||||||||
| Total contractual cash obligations | $ | 7,495 | .7 | $ | 1,009 | .5 | $ | 1,318 | .3 | $ | 1,107 | .2 | $ | 4,060 | .7 | $ | 7,685 | .0 | $ | 1,276 | .3 | $ | 1,475 | .8 | $ | 1,444 | .2 | $ | 3,488 | .7 | ||||
| Amount of Commitment Expiration Per Period | |||||||||||||||||
| Commercial Commitments (Dollars in millions) | Total | 2003 | 2004-2005 | 2006-2007 | 2008 and Thereafter | ||||||||||||
| Guarantees (4) | $ | 127 | .0 | $ | -- | $ | 127 | .0 | -- | -- | |||||||
| Liquidity facilities - available (5) | 369 | .7 | 219 | .7 | 150 | .0 | -- | -- | |||||||||
| Lines of credit - available (6) | 35 | .8 | 12 | .8 | 23 | .0 | -- | -- | |||||||||
| Energy operations letter of credit (7) | 0 | .5 | 0 | .5 | -- | -- | -- | ||||||||||
| Total commercial commitments | $ | 533 | .0 | $ | 233 | .0 | $ | 300 | .0 | -- | -- | ||||||
| Amount of Commitment Expiration Per Period | |||||||||||||||||
| COMMERCIAL COMMITMENTS (DOLLARS IN MILLIONS) | Total | 2004 | 2005- 2006 | 2007- 2008 | 2009 and Thereafter | ||||||||||||
| Guarantees (3) | $ | 137 | .0 | $ | -- | $ | 137 | .0 | $ | -- | $ | -- | |||||
| Liquidity facilities - available (4) | 288 | .5 | 249 | .5 | 39 | .0 | -- | -- | |||||||||
| Lines of credit - available (5) | 39 | .1 | 26 | .1 | 3 | .0 | 10 | .0 | -- | ||||||||
| Energy operations letter of credit (6) | 0 | .5 | 0 | .5 | -- | -- | -- | ||||||||||
| Total commercial commitments | $ | 465 | .1 | $ | 276 | .1 | $ | 179 | .0 | $ | 10 | .0 | $ | -- | |||
| (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) and lending the proceeds to PSE. The proceeds from the sale of Trust Securities were used by the Trusts 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) |
|
In April 2001, PSE revised its master operating lease to $70 million plus interest with a financial institution. See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below for further discussion. |
In June 2001, InfrastruX signed a credit agreement with several banks to provide up to $150 million in financing. Under the credit agreement, Puget Energy is the guarantor of the line of credit. Certain InfrastruX subsidiaries also have certain borrowing capacities for working capital purposes of which Puget Energy is not the guarantor. |
At December 31, |
Puget Energy has a $15 million line of credit with a bank. At December 31, 2003, $5.0 million was outstanding, reducing the available borrowing capacity under this line of credit to $10 million. InfrastruX |
In May 2002, PSE provided an energy trading counterparty a letter of credit in the amount of $0.5 million to satisfy the counterparty’s credit requirements following PSE’s senior unsecured debt downgrade in October 2001. The letter of credit has been renewed and expires on |
Puget Sound EnergyEnergy.. The following are PSE’sPSE's aggregate contractual and commercial commitments as of December 31, 2002:2003:
| Puget Sound Energy | Payments Due Per Period | ||||||||||||||||
| Contractual Obligations (Dollars in millions) | Total | 2003 | 2004-2005 | 2006-2007 | 2008 and Thereafter | ||||||||||||
| Long-term debt | $ | 2,093 | .9 | $ | 72 | .0 | $ | 169 | .5 | $ | 216 | .0 | $ | 1,636 | .4 | ||
| Short-term debt | 30 | .3 | 30 | .3 | -- | -- | -- | ||||||||||
| Trust preferred securities (1) | 300 | .0 | -- | -- | -- | 300 | .0 | ||||||||||
| Preferred dividends (2) | 1 | .1 | 1 | .1 | -- | -- | -- | ||||||||||
| Service contract obligations | 190 | .2 | 19 | .4 | 40 | .7 | 43 | .4 | 86 | .7 | |||||||
| Non-cancelable operating leases | 51 | .8 | 12 | .6 | 16 | .9 | 13 | .0 | 9 | .3 | |||||||
| Fredonia combustion turbines lease (3) | 77 | .4 | 5 | .0 | 9 | .7 | 9 | .4 | 53 | .3 | |||||||
| Energy purchase obligations | 4,603 | .8 | 849 | .6 | 951 | .1 | 827 | .9 | 1,975 | .2 | |||||||
| Financial hedge obligations | (21 | .5) | (6 | .3) | (7 | .6) | (6 | .3) | (1 | .3) | |||||||
| Total contractual cash obligations | $ | 7,327 | .0 | $ | 983 | .7 | $ | 1,180 | .3 | $ | 1,103 | .4 | $ | 4,059 | .6 | ||
| Amount of Commitment Expiration Per Period | |||||||||||||||||
| Commercial Commitments (Dollars in millions) | Total | 2003 | 2004-2005 | 2006-2007 | 2008 and Thereafter | ||||||||||||
| Liquidity facilities - available (4) | $ | 369 | .7 | $ | 219 | .7 | $ | 150 | .0 | -- | -- | ||||||
| Energy operations letter of credit (5) | 0 | .5 | 0 | .5 | -- | -- | -- | ||||||||||
| Total commercial commitments | $ | 370 | .2 | $ | 220 | .2 | $ | 150 | .0 | -- | -- | ||||||
| Puget Sound Energy | Payments Due Per Period | ||||||||||||||||
| CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | Total | 2004 | 2005- 2006 | 2007- 2008 | 2009 and Thereafter | ||||||||||||
| Long-term debt | $ | 2,053 | .0 | $ | 102 | .6 | $ | 112 | .0 | $ | 304 | .5 | $ | 1,533 | .9 | ||
| Junior subordinated debentures payable to a | |||||||||||||||||
| subsidiary trust (1) | 280 | .3 | -- | -- | -- | 280 | .3 | ||||||||||
| Mandatorily redeemable preferred stock | 1 | .9 | -- | -- | -- | 1 | .9 | ||||||||||
| Service contract obligations | 181 | .0 | 21 | .7 | 45 | .0 | 47 | .4 | 66 | .9 | |||||||
| Non-cancelable operating leases | 55 | .5 | 10 | .7 | 17 | .6 | 16 | .8 | 10 | .4 | |||||||
| Fredonia combustion turbines lease (2) | 69 | .6 | 4 | .5 | 8 | .7 | 8 | .5 | 47 | .9 | |||||||
| Energy purchase obligations | 4,737 | .4 | 928 | .2 | 1,245 | .0 | 1,036 | .7 | 1,527 | .5 | |||||||
| Financial hedge obligations | 67 | .0 | 30 | .5 | 17 | .7 | 18 | .8 | -- | ||||||||
| Non-qualified pension funding | 38 | .6 | 11 | .1 | 3 | .1 | 4 | .5 | 19 | .9 | |||||||
| Total contractual cash obligations | $ | 7,484 | .3 | $ | 1,109 | .3 | $ | 1,449 | .1 | $ | 1,437 | .2 | $ | 3,488 | .7 | ||
| Amount of Commitment Expiration Per Period | |||||||||||||||||
| COMMERCIAL COMMITMENTS (DOLLARS IN MILLIONS) | Total | 2004 | 2005- 2006 | 2007- 2008 | 2009 and Thereafter | ||||||||||||
| Liquidity facilities - available (3) | $ | 288 | .5 | $ | 249 | .5 | $ | 39 | .0 | $ | -- | $ | -- | ||||
| Energy operations letter of credit (4) | 0 | .5 | 0 | .5 | -- | -- | -- | ||||||||||
| Total commercial commitments | $ | 289 | .0 | $ | 250 | .0 | $ | 39 | .0 | $ | -- | $ | -- | ||||
| (1) | See note (1) |
| (2) | See |
| (3) | See |
| (4) | See note |
|
OFF-BALANCE SHEET ARRANGEMENTS CONSERVATION TRUST In 1995 and 1997, PSE sold a stream of future electric revenues associated with $237.7 million of its investment in conservation assets in its electric general rate tariff to two grantor trusts. As a result of this sale, PSE collects these revenues from its electric customers and remits them to the trusts. On August 29, 2001, PSE purchased the remaining 1997 trust securities. During 2002, PSE collected and remitted $12.7 million to the 1995 trust as compared to $31.0 million for both trusts in 2001. The remaining principal expected to be collected on behalf of the 1995 trust is $18.9 million at December 31, 2002.
ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM
In order to provide a source of liquidity for PSE in December 2002,at attractive cost of capital rates, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE, pursuantin December 2002. Pursuant to whichthe Receivables Sales Agreement, PSE sold all of its utility customerscustomer 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 several financial institutions.a third party. The Receivables Purchase
Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the financial institutions.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 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 of the receivables fees that are analogouscomparable 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.
The receivables securitization facility has a three yearthree-year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At December 31, 2002 there were no amounts outstanding under the2003, Rainier Receivables had sold $111.0 million in accounts receivable securitization facility.
and the maximum remaining receivables available for sale was $39.0 million.
FREDONIA 3 AND 4 OPERATING LEASE In April 2001, PSE revised its master operating lease to $70 million plus interest with a financial institution. Under this revised agreement PSE leases two combustion turbines for its Fredonia 3 and 4 electric generation facility.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 cancelledcanceled by PSE after three years.August 2004. Payments under the lease vary with changes in the London inter-bank offered rateInterbank Offered Rate (LIBOR). At December 31, 2002,2003, PSE’s outstanding balance under the lease was $61.7$59.1 million. Lease payments assume a LIBOR of 1.38%. The expected residual value under the lease is the lesser of $37.4 million or 60% 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 87% of the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency.
deficiency up to a maximum of 87% of the unamortized value of the equipment.
UTILITY CONSTRUCTION PROGRAM
Current utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of PSE’s energy delivery systems. Construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC), were $224.2$270.0 million in 2002.2003. PSE expects construction expenditures will be approximately $271.9$424.0 million $265.3in 2004, which includes $80.0 million for new generating resources subject to regulatory approval. The proposed generating resource, if approved in 2004, will be funded initially with short-term debt. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.
NEW GENERATION RESOURCES
In October 2003, PSE completed negotiations to purchase a 49.85% interest in a 275 MW (250 MW capacity with 25 MW planned capital improvements) gas-fired electric generating facility located within PSE’s service territory. The purchase will add approximately 137 MW of electric generation capacity to serve PSE’s retail customers. PSE submitted a power cost only rate case in October 2003 to the Washington Commission to recover the approximately $80 million cost of the new generating facility and other power costs. The power cost only rate case is expected to last approximately five months. Accordingly, the acquisition of the plant is subject to approval by the Washington Commission, and is expected by mid-April 2004. In addition, the acquisition will require approval from FERC. PSE filed its application in January 2004 with FERC and anticipates approval in early 2004.
In addition, PSE has issued an RFP to acquire approximately 50 average MW of energy from wind power for its electric-resource portfolio. PSE issued an RFP in February 2004 for approximately 305 MW of thermal and other generation with proposals due back in March 2004.
OTHER ADDITIONS
Other property, plant and equipment additions were $15.5 million in 2003. Puget Energy expects InfrastruX’s capital additions to be $16.2 million, $18.0 million and $265.0$20.0 million in 2003, 2004, 2005 and 2005,2006, respectively. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.OTHER ADDITIONS Other property, plant and equipment additions were $11.6 million in 2002. Puget Energy expects InfrastruX’s capital additions to be $16.6 million, $19.0 million, and $21.0 million in 2003, 2004 and 2005, respectively. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.
CAPITAL RESOURCES
CASH FROM OPERATIONS
Cash generated from operations (nettotaled $323.0 million at December 31, 2003. During the period, $87.2 million in cash was used for AFUDC and payment of dividendsdividends. Consequently, cash available for utility construction expenditures and AFUDC) totaled $944.8other capital expenditures was $235.7 million for the three-year period 2000-2002, and provided 117.7%or 77.7% of the $803.1$303.5 million of utilityin construction expenditures (net of AFUDC) and other capital expenditure requirements for thatthe period. Internal cash generation (net of dividends and AFUDC) provided 254.8% of total capital expenditure requirementsFor the same period in 2002, 57.7% in 2001,cash generated from operations was $709.7 million, $99.3 million of which was used for AFUDC and 57.2% in 2000. Puget Energy and PSE expect to continue financing thepayment of dividends. Therefore, cash available for utility construction programexpenditures and other capital expenditure requirements with internallyexpenditures at December 31, 2002 was $610.4 million. The reduction in cash generated fundsfrom operations in 2003 was primarily due to refunds reducing the PGA balance and externally financed capital.the reduction in cash received related to deferred tax items in 2002.
During 2002, PSE received $121.0 million in excess of actual gas costs from customers through the PGA mechanism compared to refunds to customers through the PGA mechanism of $71.8 million for 2003. Cash from deferred income taxes decreased $93.8 million due primarily to federal income tax refunds and deferred tax credits in 2002 that did not occur in 2003. There was also a $21.4 million decrease in cash flows as a result of returning collateral to an energy trading counterparty in 2003 compared to a $21.4 million increase in cash flow from receiving the collateral in 2002. Cash from materials and supplies decreased $36.8 million due predominantly to higher gas injections in 2003 as compared to 2002 in order to increase gas storage levels. Cash used for accounts payable decreased $27.9 million due to fewer accrued incentives and operating-related costs at the end of 2003. In 2003, PSE also funded the qualified pension plan in the amount of $26.5 million
compared to no funding during 2002. Cash used for taxes payable increased in 2003 compared to 2002 by $31.7 million.
FINANCING PROGRAM
Financing utility construction requirements and operational needs is dependent upon the amount of internally generated funds and the cost and availability of external funds through capital markets and from financial institutions. Access to funds is dependent upon factors such as general economic conditions, regulatory authorizations and policies, and Puget Energy’s and PSE’s credit ratings.
RESTRICTIVE COVENANTS
In determining the type and amount of future financing, PSE may be limited by restrictions contained in its electric and gas mortgage indentures, articles of incorporation and certain loan agreements. Under the most restrictive tests, at December 31, 2002,2003, PSE could issue:
approximately $466.8$927.9 million of additional first mortgage bonds at an assumed interest rate of 5.92% on a ten-year first mortgage bond due to a limitation of the interest coverage ratio. (PSE hasbased upon approximately $1.2$1.5 billion of electric and gas bondable property available for use for issuance of up to $700.8 million of first mortgage bonds, subject to the interest coverage ratio limitation of 2.0 times net earnings available for interest. PSE’s interest coverage ratio at December 31, 20022003 was 2.42.9 times net earnings available for interest);
approximately $157.1$454.5 million of additional preferred stock at an assumed dividend rate of 7.75%7.25%; and
approximately $243.5$261.3 million of unsecured long-term debt.
CREDIT RATINGS
Neither Puget Energy nor PSE has any rating downgrade triggers that would accelerate the maturity dates of outstanding debt. However, a downgrade in the senior unsecuredcompanies’ credit ratings could adversely affect the companies’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. A further downgrade in commercial paper ratings could preclude entirely PSE’s ability to issue commercial paper. 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 current ratings of Puget Energy and PSE, as of February 13, 2003, are:March 8, 2004, were:
| Ratings | ||
| Standard & | ||
| Puget Sound Energy | ||
| Corporate credit/issuer rating | BBB- | Baa3 |
| Senior secured debt | BBB | Baa2 |
| Shelf debt senior secured | BBB | (P)Baa2 |
| | ||
| Preferred stock | BB | Ba2 |
| Commercial paper | A-3 | P-2 |
| | ||
| Revolving credit facility | * | Baa3 |
| Ratings outlook | Positive | Stable |
| Corporate credit/issuer rating | BBB- | Ba1 |
* No ratings provided.Standard & Poor’s does not rate credit facilities.
Moody's Investors Service has stated that its negative outlook is based upon uncertainty about the outcome of investigations by FERC of western power markets. Moody's remains concerned about what conclusions will ultimately be drawn by FERC with respect to year 2000 sales in western power markets and what other steps they might take as the investigation runs its full course.
SHELF REGISTRATIONS, LONG-TERM DEBT AND COMMON STOCK ACTIVITY
In February 2002,January 2004, 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 principal amount of:
common stock of Puget Energy,
andsenior notes of PSE, secured by a pledge of PSE'sPSE’s first mortgage bonds,
unsecured debentures of In March 2003, PSE and
trust preferred securities of Puget Sound Energy Capital Trust III.
On November 5, 2002, Puget Energy sold 5.75 million shares of common stock in a public offering. The net proceeds of approximately $114.6 million were invested in PSE to reduce its debt. PSE is expected to refinancerefinanced $161.9 million of its Pollution Control Bonds seriesto lower the weighted average interest rate from 6.77% to 5.01%. In June 2003, PSE issued $150 million principal amount of senior notes. The proceeds of $149.1 million were used to repay debt. In November 2003, Puget Energy sold an additional 4.55 million shares of common stock. The proceeds of $100.1 million were invested in PSE and mainly used to repay debt and redeem high-cost preferred stock. During 2003, PSE redeemed the following long-term debt:
LIQUIDITY FACILITIES AND COMMERCIAL PAPER
PSE's short-term borrowings and sales of commercial paper are used to provide working capital for the utility construction program. On December 23, 2002, PSE entered intohas a $250 million unsecured 364-day credit agreement with various banks which expires in June 2004 and a $150 million 3-yearthree-year receivables securitization program. These facilities replaced PSE's entire $375program which expires in December 2005. The receivables available for sale under the securitization program may be less than $150 million bank linedepending on the outstanding amount of creditPSE’s receivables which was scheduledfluctuate with the seasonality of energy sales to terminate on February 13, 2003.customers. At December 31, 2002,2003, PSE had available $400.0$250 million in the unsecured credit agreement and $39 million available from the receivables securitization facility (net of liquidity facilities,$111 million sold), which in part provide credit support for outstanding commercial paper and outstanding letters of $30.3credit. At December 31, 2003, there were no outstanding amounts under its commercial paper program and $0.5 million under the letters of credit, effectively reducing the available borrowing capacity under the liquidity facilities to $369.7$288.5 million.
On May 27, 2003, Puget Energy entered into a $15 million, three-year credit agreement with a bank. Under the terms of the agreement, Puget Energy will pay a floating interest rate on borrowings based on the 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 will also pay a commitment fee on any unused portion of the credit facility. On May 30, 2003, Puget Energy borrowed $5 million under the credit agreement. The proceeds of the loan were invested in InfrastruX, which used the proceeds to acquire a construction services company in New Mexico.
In June 2001, InfrastruX signed a three-year credit agreement with several banks to provide up to $150 million in financing. Puget Energy is the guarantor of the line of credit. In addition, InfrastruX'sInfrastruX’s subsidiaries have an additional $29.8$34.7 million in lines of credit with various banks. Borrowings available for InfrastruX are used to fund acquisitions and working capital requirements of InfrastruX and its subsidiaries. At December 31, 2002,2003, InfrastruX and its subsidiaries had outstanding loans of $144.0$150.9 million and letters of credit of $4.7 million, effectively reducing the available borrowing capacity under these lines of credit to $35.8$29.1 million.
STOCK PURCHASE AND DIVIDEND REINVESTMENT PLAN
Puget Energy has a stock purchaseStock Purchase and dividend reinvestment planDividend Reinvestment Plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy'sEnergy’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 $15.5 million (721,340 shares) in 2003 compared to $16.9 million (801,205 shares) in 2002 compared2002.
COMMON 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 $25.6 million (1,119,568 shares) in 2001. The decrease in the Stock Purchase and Dividend Reinvestment Plan from 2002 to 2001 was largely attributable to the reductiontime through these institutions as sales agents, or as principals. Sales of the common stock, dividendif 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 May 15, 2002 to a quarterly dividendthe New York Stock Exchange at market prices. In October 2003, Puget Energy sold 100,600 shares of $0.25 per share.common stock under its program with Cantor Fitzgerald & Company. Puget Energy received approximately $2.3 million in net proceeds from these sales.
RATE MATTERS - ELECTRIC On March 28, 2002, the Washington Commission approved and adopted an unopposed settlement stipulation to resolve the interim phase of the rate case, in order to allow $25 million in additional revenue to be recovered in rates over an approximate period of three months, commencing April 1, 2002. On June 6, 2002, the parties and intervenors to the general rate case filed a settlement stipulation for electric and common issues, which called for an electric general rate increase of $59 million annually. On June 20, 2002, the Washington Commission approved and adopted the settlement stipulation in the general case, putting new rates into effect on July 1, 2002. PSE established a PCA mechanism in the rate case settlement. The PCA mechanism will account for differences in PSE's modified actual power costs relative to a power cost baseline. The mechanism would account for a sharing of costs and benefits that are graduated over four levels of power cost variances, with an overall cap of $40 million (+/-) over the four year period July 1, 2002 through June 30, 2006. The factors influencing the variability of power costs included in the proposal are primarily weather or market related. PSE will be allowed to file for rate increases to implement limited power supply cost increases related to new resources. PSE’s share of the power costs through December 31, 2002 was $5.2 million. Because of adverse hydro conditions in 2003, PSE anticipates reaching the $40 million cumulative cap under the PCA mechanism by the fourth quarter of 2003. Under the PCA mechanism, further increases in variable power costs through June, 30, 2006 would be apportioned 99% to customers and 1% to PSE.
RATE MATTERS - GAS On August 29, 2001 the Washington Commission approved a decrease in PSE's natural gas rates of 8.9% due to lower natural gas costs purchased for customers under terms of the PGA mechanism effective September 1, 2001. Also, on May 24, 2002 the Washington Commission allowed a decrease in PGA rates of 21.2% to become effective on June 1, 2002. This ended a temporary surcharge that went into effect September 1, 2001. 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. On August 28, 2002, the Washington Commission approved a 5.8% gas service rate increase in revenue to cover higher costs of providing natural gas service to customers. This service-related increase in revenues of approximately $35.6 million annually was offset by an annual $45 million or 7.3% PGA rate reduction, also approved on August 28, 2002. On September 30, 2002, PSE filed a proposal with the Washington Commission to reduce natural gas supply rates under the PGA for the third time in 2002. The Washington Commission approved the proposal on October 30, 2002 and PSE lowered gas rates through the PGA by approximately 12.5% effective November 1, 2002.
PROCEEDINGS RELATING TO THE WESTERN POWER MARKET
While PSE cannot predict the outcome of any of the individual ongoing proceedings relating to the western power markets, PSE generally is pleased that FERC appears to be narrowing the issues under review in the cases pending before it. The narrowing of issues allows PSE to compare the allegations in the various proceedings with PSE’s relevant records and to better anticipate the likely outcome of each case. In the aggregate, PSE does not expect the ultimate resolution of the issues and cases discussed below to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.
CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO) RECEIVABLE AND CALIFORNIA
REFUND PROCEEDINGS
PSE operates within the western wholesale market and made sales into the California energy market during the fourth quarter of 2000 through the CAISO. In 2001, PG&E and Southern California Edison defaultedAugust of 2000, San Diego Gas & Electric Company filed a complaint at FERC (Docket No. EL00-95) seeking price caps on payment obligations owed to various energy suppliers, including the CAISO. The CAISO in turn defaulted on its payment obligations to PSE and various other energy suppliers. On March 1, 2002, Southern California Edison paid its past due energy obligations tosold into the CAISO and various other parties; however, those funds were not used to pay the outstanding balanceCalifornia Power Exchange (PX) markets. The complaint also sought refunds of the CAISO obligations to PSE. PSE is continuing to pursue recovery of the CAISO receivable. On October 1, 2002, the CAISO determined a refund was due to PSE totaling $2.2 millionprices charged above any such caps put in connection with a FERC order of August 27, 2002 that determined parties that paid the CAISO transmission access charges for energy delivered into the CAISO's control area in calendar 2000 had been overcharged by the CAISO. PSE received $1.1 million of this refund on October 8, 2002, which was creditedplace. In response to the CAISO receivable, reducingcomplaint, after a number of orders that attempted to address the receivable balance recorded by PSE to $66.9 million. PSE hasCalifornia energy crisis in a bad debt reserve and a transaction fee reserve totaling $41.5 million in connection withvariety of manners, FERC issued an Order on June 19, 2001 that imposed caps on prices beginning the CAISO receivable, such that the net receivable at December 31, 2002 was $25.4 million. The balance of the refund has not been paid by the CAISO.next day.
On July 25, 2001, FERC ordered an evidentiary hearing (Docketin Docket No. EL00-95)EL00-95 to determine the amount of refunds due to California energy buyers, including the CAISO, for purchases made in the spot markets operated by the CAISO during the period October 2, 2000 through June 20, 2001. Hearings on the FERC California refund proceeding commenced in August 2002 in San Francisco, California, and concluded in Washington, DC in September 2002.
On December 12, 2002, the Administrative Law Judge conducting the hearings issued his certification of proposed findings on California refund liability to FERC. The certification includes an appendix that reflects what the Administrative Law Judge labeled as "ballpark"“ballpark” estimates of amounts owed and owing. (The Judge did not make exact findings, because the report contemplates further calculations by the CAISO.) The report also enters various findings within the text of the opinion, but those findings are not reflected in the appendix. The appendix indicates that the net cash position as of March 2002 for PSE would be an amount due to PSE of $61.9 million, and the refund PSE would owe to the CAISO would be $26.3 million--making a net receivable for PSE of $35.6 million. The appendix calculations did not include, however, two stipulations and/or findings from the body of the opinion that excluded certain PSE transactions from refund liability, primarily because they were not "spot market" transactions. Applying those stipulations would reduce the refund PSE would owe by $6.4 million, and make the net PSE receivable approximately $42.0 million. The certification also statesstated that the amounts owing should be adjusted for interest, a calculation the Administrative Law Judge did not make. FERC has expressed an intention to act on the Administrative Law Judge's certification--and any other submissions in the docket, as discussed below--in the spring of 2003. The projected schedule for resolution of the refund proceedings could change significantly, however, if FERC were to adopt changes in the refund methodology employed during the hearings, as proposed in the FERC's Staff's report discussed below.
The FERC Staffstaff issued a report in August 2002 (Docket No. PA02-2) that, among other things, recommendsrecommended that FERC modify the methodology for calculating refunds in the California refund proceeding (Docket No. EL00-95) by adopting, as a proxy for the cost of natural
gas, producing basin spot prices plus transportation costs, instead of reported spot prices for natural gas at California delivery points. If adopted as proposed, thisThis methodology of calculating the cost of natural gas would reducefurther reduced the amount owed by the CAISO to PSE for sales made during 2000 and 2001. PSE's estimates indicate that the changes in methodology would reduce PSE's net receivable to approximately $18 million (as compared to the $42.0 million, calculated by the Administrative Law Judge). The current net receivable recorded by PSE is $23.6 million. The CAISO receivable range including the effects of the CAISO refund and estimates of the gas price adjustment, including interest is $25.4between $23.6 million and $34.2 million. On August 13, 2002, FERC issued a notice (Docket No. EL00-95) requesting comments on: (1) whether the method used to determine the cost of natural gas for the refund calculation in the California refund proceeding should be modified; (2) whether the FERC Staff's substitute method is appropriate and, if not, what method should be used; and (3) what is the proper way to reflect the effects of scarcity on price. PSE jointly sponsored testimony and filed comments in opposition to the recommendations in the FERC Staff's report on October 15, 2002. The issue remains pending before FERC and no schedule for decision has been announced.
On November 20, 2002, FERC issued an Order on Motion for Discovery Order in theDocket No. EL00-95 docket that granted a motion to allow parties to "adduce"“adduce” additional evidence into the refund proceedings "that“that is either indicative or counter-indicative of market manipulation."” The order also authorized an appointment of an Administrative Law Judge as a discovery master, and permitspermitted the parties to conduct discovery and file any such evidence "no later than February 28, 2003." On February 10, 2003 FERC issued an order on "clarification" that provides for reply submissions by any party on or before March 17, 2003. Like the November 20 discovery order, the February 10 order expressly states that the Commission intends to "finalize the issues in these dockets expeditiously" and observes that the Commission sees "no need for additional discovery procedures following the February 28, 2003 submission of evidence." On February 24, 2003, FERC extended the filing deadlines towith FERC. In their March 3, 2003 for the initial submissions and March 20, 2003 for replies, due to the east coast blizzard. In the March 3 filing, by the California parties they reiterated their allegations of market manipulation against PSE and approximately 60 other companies. PSE and the other parties are expected to respondresponded on March 20, 2003.
On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket No. EL00-95 that substantially adopted the recommendations that the Administrative Law Judge made on December 12, 2002, except that the Order also substantially adopted the FERC staff gas price recommendation made in its August 2002 report. On October 16, 2003, FERC issued an Order on Rehearing that largely left the refund calculation methodologies established by the March 26, 2003 Order unchanged. The Order on Rehearing gives the CAISO a deadline to perform its “cost re-runs” (which are expected to establish actual amounts owing and owed) of five months from October 16, 2003. In February 2004, however, FERC issued an order giving the CAISO an indefinite period of time to complete its cost re-runs, subject to the CAISO filing monthly reports of its progress and its expected completion dates. The CAISO’s current estimates are that it will be unable to complete the cost re-run process any earlier than August 2004. Until the CAISO completes its cost re-run process, little other activity can take place in the FERC docket.
The March 26, 2003 Order on Proposed Findings on Refund Liability also permitted generators to make a filing to recover actual fuel costs that exceeded the calculated proxy price under the staff methodology. PSE made such a filing on May 12, 2003. The California parties objected to all fuel cost filings on May 21, 2003. The Order on Rehearing issued on October 16, 2003 postpones resolution of this issue, so PSE’s application for fuel cost recovery remains pending.
The Order on Rehearing issued on October 16, 2003 also expressly adopted and approved a stipulation that confirmed that two PSE “non-spot-market” transactions were not subject to refund. The total gross revenue associated with the transactions is approximately $26.0 million. On October 17, 2003, PSE sent a demand letter to the CAISO seeking payment of the amount due. The CAISO responded to the letter with its own letter of November 14, 2003, expressing an unwillingness to take the issue up separately or in advance of its “cost re-run” activities. PSE has not yet formally responded to that letter.
Because of the numerous orders FERC has issued in Docket No. EL00-95 over a period of more than three years, more than 80 appeals from the proceeding have already been lodged with the U.S. Ninth Circuit Court of Appeals. The Ninth Circuit’s usual practice has been to consolidate those appeals as they are filed, and hold the appellate proceedings in abeyance pending a final determination by FERC of the issues before it. PSE has no ability to predict how soon the Ninth Circuit may choose to take up these matters for consideration on their merits, but the California parties have attempted to initiate a more active review from time to time. It is likely that the case will not be finally resolved before formal appellate review.
CALIFORNIA RECEIVABLE
In 2001, PG&E and Southern California Edison defaulted on payment obligations owed to various energy suppliers, including the CAISO and the California PX. The CAISO in turn defaulted on its payment obligations to PSE and various other energy suppliers. The California PX itself filed bankruptcy in 2001, further constraining PSE’s ability to receive payments due to controls placed on the California PX’s distribution of funds by the California PX bankruptcy court and due to the fact that the vast majority of funds owed directly to the CAISO are owed by the California PX. In addition, the California PX’s inverse condemnation action against the State of California may influence the delivery of funds to energy sellers such as PSE. PSE has a bad debt reserve and a transaction fee reserve applied to the CAISO receivables, such that the net receivable at December 31, 2003 was $23.6 million. On March 1, 2002, Southern California Edison paid its past due energy obligations to the CAISO, the California PX and various other parties; however, those funds were not used to pay the outstanding balance of the CAISO obligations to PSE.
In summary, the developments in the California Refund Proceeding described in the above section have the likely effect of reducing PSE’s gross receivable balance due from the CAISO to an amount approximately equivalent to collecting payment on the two “non-spot-market” transactions removed from the Refund Proceeding. PSE is attempting early collection of proceeds associated with those sales while recognizing that the ultimate resolution of the Refund Proceeding may be more distant in the future. PSE anticipates that the net results of the CAISO cost re-runs and the application of the refund calculations will extinguish or offset the CAISO receivable apart from the balance associated with the two “non-spot-market” transactions. PSE is continuing to pursue recovery of the CAISO receivable.
PACIFIC NORTHWEST REFUND PROCEEDING
In October 2000, PSE filed a complaint at FERC (creating 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 the EL01-10 Docket, 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 denied the rehearing requests, and the matter has now been appealed to the Ninth Circuit Court of Appeals. PSE has filed its own appeal, on the basis that it had an absolute right to withdraw the complaint before any other party intervened. The California parties also sought rehearing on one new issue decided in the November 10, 2003 order, which request was denied by FERC on February 9, 2004. It is expected that all appeals from this proceeding will be consolidated and resolved together.
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 proceeding seeks to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order, and in an order dismissing many of the already-named respondents in the “partnerships” proceedings on January 22, 2004, FERC stated that they had determined not to proceed further against other parties. Accordingly, PSE does not expect to be named in the case.
The second show cause proceeding investigated approximately 55 entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE is one of the entities named in the “gaming” show cause order (Docket No. EL03-169). On July 16, 2003, CAISO provided data to FERC in connection with the “gaming” show cause order that indicated that, under the standards adopted by FERC in the June 25, 2003 orders, CAISO’s previously reported claims against PSE as to “ricochet” transactions completely disappear. Consistent with the show cause orders’ invitation to attempt settlement, PSE and FERC staff filed a settlement of all issues pending against PSE in those proceedings on August 28, 2003. The proposed settlement admits no wrongdoing on the part of PSE, but would result in the payment of $17,092 to settle all claims. The California parties and a few others filed oppositions to PSE’s settlement (and all others) on September 30, 2003. PSE replied to those arguments on October 20, 2003. The presiding Administrative Law Judge certified and recommended the PSE settlement to FERC on November 18, 2003. In January 2004, FERC issued an Order Approving Contested Settlement Agreement that finds PSE’s settlement to be in the public interest. On February 23, 2004, motions for rehearing were filed by the Port of Seattle and the California parties (the California Attorney General, the California Public Utilities Commission, the California Electricity Oversight Board, PG&E and Southern California Edison). PSE continues to believe that the orders to show cause do not raise new issues or concerns nor will they have a material adverse impact on the financial condition, results of operations or liquidity of the Company.
ANOMALOUS BIDDING INVESTIGATION
On June 25, 2003, FERC issued an order commencing a new investigatory proceeding, Docket No. IN03-10, to be conducted through its Office of Market Oversight and Investigations (OMOI). That docket is to review each seller’s bids into the CAISO or California PX markets that exceeded $250/MWh during the period of May 1, 2000 to October 1, 2000. The OMOI is to determine if each such entity’s bids show a pattern or an effort to manipulate the market, and if they do, to consider whether the entity should be required to disgorge any improper profits earned as a result of such patterns or efforts. PSE received a data request from the OMOI in this proceeding about its bids and responded on July 24, 2003. PSE has not received further information requests since responding. There is no established timetable for this proceeding, but FERC has indicated that it expects to work diligently to review the practices of each seller and to resolve the matter expeditiously. PSE does not expect any material adverse impacts on the financial condition of the Company from this FERC investigation.
PORT OF SEATTLE SUIT
On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle, Washington against 22 energy sellers into the California market, alleging that the conduct of those sellers during 2000 and 2001 constituted market manipulation, violated antitrust laws and damaged the Port of Seattle, which had a contract to purchase its complete energy supply from PSE at the time. The Port’s contract with PSE 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 intentionally affected improperly by the defendants, including PSE. PSE moved to dismiss this case; other defendants moved to transfer the matter to a multi-district litigation panel in California. A conditional transfer order was issued in July 2003. After further proceedings before the judicial panel on multi-district litigation, an order transferring the case to the Southern District of California was entered on December 15, 2003. PSE’s motion to dismiss remains pending and is scheduled to be heard on March 26, 2004 in San Diego, California. PSE does not expect any material adverse impacts on the financial condition of the Company from this matter.
CALIFORNIA 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 Federal Power ActFPA by FERC and all sellers (including PSE) of electric power and energy into California. The complaint asserted that FERC'sFERC’s adoption and implementation of market rate authority was flawed and, as a result, that individual sellers such as PSE were liable for sales of energy at rates that were "unjust“unjust and unreasonable."” The condition for dismissal was that all sellers re-filerefile 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 re-filedrefiled such transaction summaries on July 1 and July 8, 2002. The order of dismissal is now on appeal to the Ninth Circuit Court of Appeals.
On the same day as FERC'sFERC’s order of dismissal in Docket No. EL02-71 was entered, the California Attorney General announced it had filed individual complaints against a number of sellers, including PSE, in California Superior Court in San Francisco. That complaint allegesalleged that PSE'sPSE’s sales to California violated the requirements of the Federal Power ActFPA and that, as such, the sales also violated certain sections of the California Business Practices Act forbidding unlawful business practices. The complaint assertsasserted that each such "violation"“violation” subjects PSE to a fine of up to $2,500 plus an award of attorneys'attorneys’ fees and asserts that there were "thousands"“thousands” of such violations. PSE has removed that suit to federal court and has
moved to dismiss it on the grounds that the issues are within the exclusive or primary jurisdiction of FERC. ThatOn March 25, 2003, the court granted the motion was arguedfor dismissal. The order of dismissal is now on September 26, 2002 and the question is under submissionappeal to the judge.Ninth Circuit Court of Appeals. PSE does not expect any material adverse impacts on the financial condition of the Company from these matters.
CALIFORNIA CLASS ACTIONS
During May 2002, PSE was served with two cross-complaints, by Reliant Energy Services and Duke Energy Trading & Marketing, respectively, in six consolidated class actions pending in Superior Court in San Diego, California. The original complaints in the action, which were brought by or on behalf of electricity purchasers in California, allege that the original (approximately 40) defendants manipulated the wholesale electricity markets in violation of various California Business Practices Act or Cartwright Act (antitrust) provisions. The 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 assert essentially that the cross-defendants, including PSE, were also participants in the energy market in California at the relevant times, and that any remedies ordered against some market participants should be ordered against all. Reliant Energy Services and Duke Energy Trading & Marketing also seek indemnity and conditional relief as a buyer in transactions involving cross-defendants should the plaintiffs prevail. Those cross-complaints added over 30 new defendants, including PSE, to litigation that had been pending since 2000 and had been set for trial in state court. Some of the newly added defendants removed the litigation to federal court. The federal court in San Diego remanded the case to the California Statestate court in an order issued in December 2002. PSE and numerous other defendants added by the cross-complaints have moved to dismiss these claims. Those motions were argued on September 19, 2002, but the federal judge did not rule on those motions in his order remanding the case to state court. The remand order is now being reconsidered. PSE and the other defendants that moved to dismiss the claims intend to submit their motion to the appropriate court at the earliest practical date. As a result of the various motions, no trial date is set at this time.
OTHER PROCEEDINGS On May 8, 2002, FERC issued PSE does not expect the ultimate resolution of these matters to have a data request concerning specific trading strategies described in memos prepared by Enron Corporation to all sellers, including PSE,material adverse impact on the financial condition, results of wholesale electricity and/operations or ancillary services to the CAISO and/or the California Power Exchange Corporation during the years 2000-2001. On May 21 and May 22, 2002, FERC issued additional data requests to all sellers of wholesale electricity or natural gas in the western United States, including PSE, concerning "wash" or "roundtrip" trading activities. Eachliquidity of the three requests required the sellers to respond with an affidavit concerning the seller's use or knowledge of various trading practices identified in the request. In response to the data requests, PSE conducted a review of its activities and informed FERC that it did not engage in the trading activity described in the applicable request. In October 2002, PSE provided information in response to a request by the U.S. Commodity Futures Trading Commission (CFTC) for information about a limited number of specific transactions with regional counterparties which have been the subject of an investigation by the CFTC. PSE's own review of these trades concluded that all the transactions were lawful and served normal business purposes. In January 2003, PSE was asked to provide additional information to the CFTC, primarily concerning the results of any PSE internal investigation as to its trading activities and reports to indices. PSE responded to that request by providing information in February 2003. In December 2002, PSE was named as one of more than 30 defendants in two class actions, one filed in the federal district court in Seattle and the other in Multnomah County Circuit Court in Oregon. PSE was served with the complaint and summons in the Washington federal court case on February 3, but as of March 7, 2003 had not been served in the Oregon case. Nonetheless, the Oregon case was removed to Oregon federal court by Reliant Energy Services on February 5, 2003. The complaints allege that they are brought on behalf of all retail customers in Washington and Oregon, respectively, and seek relief against the defendants (each of which is a seller of electric energy at wholesale in certain markets) for "unfair or deceptive acts," "fraud by concealment," negligence and for an accounting. No specific amounts of damages are pled in the complaints. PSE cannot predict the outcome of any of these ongoing proceedings relating to the western power markets, or whether the ultimate impact on PSE will be material.Company.
OTHER On October 2, 2002, the United Association of Plumbers and Pipefitters ratified with PSE a new four-year collective bargaining agreement. Effective dates for the new contract are October 1, 2002 to October 1, 2006. The contract covers approximately 300 PSE employees. In addition, on December 3, 2002, the International Brotherhood of Electrical Workers ratified an agreement to extend their collective bargaining agreement with PSE through March 31, 2007. This contract covers approximately 800 PSE employees. 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). The SMD NOPR would have major implications for the delivery of electric energy throughout the U.S if enacted in its proposed form. Major elements of FERC's proposal include: (a) the use of Network Access Service to replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff; (b) Vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems; (c) The formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. State regulators and industry representatives have pointed out that the Western North American electricity market has unique characteristics that may not readily lend itself to the Standard Market Design proposed by FERC. FERC has expressed its willingness to offer regional flexibility in its order on RTO West, Docket Nos. RT01-35-005 and RT01-35-007, Issued September 18, 2002. On December 20, 2002, FERC issued a Notice extending the deadline for comments addressing market design for the Western Interconnection to February 18, 2003, but the notice also indicates FERC "will accept late-filed comments through February 28, 2003." The Company has filed comments.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with Generally 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 areas represent those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain:uncertain.
REVENUE RECOGNITION
Utility revenue is recognized when the basis of service is rendered, including estimates used for unbilled revenue. Unbilled kWh are determined by taking kWh generated and purchased less billed kWh and estimated system losses. The estimated system losses are determined by reviewing historical billed kWh to generated and purchased kWh. This amount is then multiplied by the estimated average revenue per kWh. Non-utility revenue is recognized when services are performed, or upon the sale of assets.assets, or on a percentage of completion basis for fixed-price contracts. The recognition of revenue is in conformity with Generally Accepted Accounting Principles, which requires the use of estimates and assumptions that affect the reported amounts of revenue.
FERCREGULATORY ACCOUNTING
Puget Energy'sEnergy’s regulated subsidiary, PSE, prepares its financial statements in accordance with Generally Accepted Accounting Principlesthe provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and in conformity with FERC'sFERC’s uniform system of accounts. The Washington Commission also requires PSE to use FERC'sFERC’s uniform system of accounts.
COST BASED REGULATION Puget Energy's The reason PSE prepares its financial statements in accordance with SFAS No. 71 is that its rates and tariffs are regulated subsidiary, PSE, is subject to regulation by the Washington Commission and FERC. The rates that are charged by PSE to its customers are based upon cost base regulation reviewed and approved by these regulatory commissions. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities in the amount of $483.7$461.8 million and $406.1 million as of December 31, 2002.2003 and 2002, respectively. If at some point in the future Puget Energy determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to PSE, Puget Energy could be required to write off its regulatory assets and liabilities.
DERIVATIVES
Puget Energy uses derivative financial instruments primarily to manage its commodity price risks. Derivative financial instruments are accounted for under Statement of Financial Accounting Standards (SFAS)SFAS No. 133, - "Accounting“Accounting for Derivative Instruments and Hedging Activities",Activities,” as amended by SFAS No. 138.138 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. 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 normal purchases and normal sales exclusion. If the exclusion applies, those contracts are not marked-to-market and are not reflected in the financial statements until delivery occurs.
The availability of the normal purchases and normal sales exclusion 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 normal purchases and normal sales are consistent with assumptions used in the general planning process.
Energy 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.
When external quoted market prices are not available for derivative contracts, PugetPSE uses a valuation model which uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.
GOODWILL AND INTANGIBLES (PUGET ENERGY ONLY)
On January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective and as a result Puget Energy ceased amortization of goodwill. During 2001, Puget Energy recorded approximately $2.8 million of goodwill amortization. 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 InfrastruX with 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 on a straight-line basis over the expected periods to be benefited. The Company believes thatgoodwill and intangibles recorded on the riskbalance sheet of non-performancePuget Energy are the result of acquisition of companies by its counterparties is remote.InfrastruX.
DEFINED BENEFIT PENSION PLAN
Puget Energy has a qualified defined benefit pension plan covering substantially all employees of PSE. For 2003, 2002 2001 and 20002001 qualified pension income of $12.9 million, $17.7 million and $20.0 million, and $16.6 million, respectively, has beenwas recorded in the financial statements. Of these amounts, approximately 67.0%, 66.8% and 58.0% offset utility operations and maintenance expense in 2003, 2002 and 2001, respectively, and the remaining amounts were capitalized. Changes in market values of stocks or interest rates will affect the amount of income that Puget Energy can record in its financial statements in future years. Qualified pension income is expected to decline to $9.6$8.6 million in 20032004 as a result of lower actual returns on pension assets during the last three years and declining expected rates of return on pension fund assets. During 2003, PSE made a cash contribution to the qualified defined benefit plan of $26.5 million and is not expected to make a cash contribution to this qualified plan in 2004.
STOCK-BASED COMPENSATION
During 2002, PSE transitioned 462 service jobs that had previously been heldThe Company has various stock-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 PSE employees to outside service providers. Under SFAS No. 88 "Employers' Accounting123, “Accounting for SettlementsStock-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 CurtailmentsDisclosure.” The Company will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of Defined Benefit Pension Plans and for Termination Benefits," PSE recorded a curtailment loss of approximately $0.3 million.APB No. 25.
CALIFORNIA INDEPENDENT SYSTEM OPERATOR RESERVE
PSE operates within the western wholesale market and has made sales into the California energy market. DuringAt December 31, 2000, PSE’s receivables from the first quarterCAISO and other counterparties, net of 2001,reserves, were $41.8 million. PSE received the majority of the partial payments for sales made in the fourth quarter of 2000.2000 in the first quarter of 2001 and has since received a small amount of payments. At December 31, 2000, PSE's receivables from the CAISO and other counter-parties, net of reserves, were $41.8 million. At December 31, 2002,2003, such receivables, net of reserves, were approximately $25.4$23.6 million. The Company calculated
During 2003, FERC issued an order in the reserve basedCalifornia Refund Proceeding adopting in part and modifying in part FERC’s earlier findings by the Administrative Law Judge. Based upon estimated credit quality and collection from the CAISOorder, PSE has determined that the receivables balance at December 31, 2002.2003 is collectible from the CAISO. See "Proceedings“Proceedings Related to the Western Power Market"Market” under Management'sManagement’s Discussion and Analysis of Financial Condition and Results of OperationOperations for further discussion.
NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, Financial Accounting Standards Board issued Interpretation No. 46 - "Consolidation of Variable Interest Entities" (FIN 46). FIN 46, clarifieswhich was further revised in December 2003 with FIN 46R, clarified the application of Accounting Research Bulletin No. 51, - "Consolidated“Consolidated Financial Statements"Statements,” to certain entities in which equity investors do not have controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. This InterpretationFIN 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 this InterpretationFIN 46R for all interests in variable interest entities created after January 31, 2003 is effective immediately. For variable interest entities created before February 1, 2003, it is effective July 1, 2003. The Company ishas 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 processthird quarter of determining2003. As a result, revenues for 2003 increased $5.7 million, while conservation amortization and interest expense increased by the impactscorresponding amount with no impact on earnings. At December 31, 2003, the balance sheet assets and liabilities increased by $4.2 million. FIN 46R also impacted the treatment of this Interpretation.the Company’s mandatorily redeemable preferred securities of a 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 of 2003. This change had no impact on the Company’s results of operations for 2003. The Company is evaluating its purchase power agreements and any other agreements to determine if FIN 46R will have an impact on the financial statements.
On January 1, 2002,In May 2003, the FASB issued SFAS No. 142, "Goodwill150, “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, the 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 are not 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 December 2003, SFAS No. 132, “Employers’ Disclosures about Pensions and Other Intangible Assets" becamePostretirement Benefits” (SFAS No. 132R), was revised to include various additional disclosure requirements. SFAS No. 132R is effective and as a result, Puget Energy ceased amortization of goodwill associated with the InfrastruX business. During 2001, Puget Energy had approximately $2.8 million of goodwill amortization. Puget Energy performed an initial impairment review of goodwill and will perform an annual impairment review thereafter. The initial review was completed during the first half of 2002, and did not result in an impairment charge. Puget Energy then performed its annual impairment review as of October 31, 2002 and determined that its goodwill was not impaired.for fiscal years ending after December 15, 2003.
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting“Accounting for Asset Retirement Obligations,"” 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 will adoptadopted the new rules on asset retirement obligations on January 1, 2003. ApplicationAs a result, the Company recorded a $0.2 million charge to income for the cumulative effect of this accounting change. In addition, the new rules is not expectedCompany reclassified $124.9 million and $114.6 million in 2003 and 2002, respectively, from accumulated depreciation to result in a material increase in net property, plant and equipment or expense.
regulatory liability.
The Emerging Issues TaskTax Force of the Financial Accounting Standards Board (EITF or Task Force)(EITF) at its June 2002July 2003 meeting came to a consensus on one of three items included inconcerning EITF Issue 02-3 "AccountingNo. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Contracts InvolvedTrading Purposes as Defined in Energy Trading and Risk Management Activities" (EITF 02-3).Issue No. 02-03.” The Task Force has agreedconsensus reached was that all mark-to-marketdetermining whether realized gains and losses on energyphysically settled derivative contracts not held for trading contracts whether realized or unrealized will be shown netpurposes reported in the income statement (costs offset against revenues), irrespectiveon a gross or net basis is a matter of whetherjudgment that depends on the contract is physically settled. The presentation will be applicable to financial statements for periods ending after July 15, 2002. The Company performs risk management activities to optimizerelevant facts and circumstances. Based on the value of energy supply and transmission assets and to ensure that physical energy supply is available to meet the customer demand loads. The Company also purchases energy when demand exceeds available suppliesguidance in its portfolio; likewiseEITF No. 03-11, the Company makes sales to other utilitiesdetermined that its non-trading derivative instruments should be reported net and marketers when surplus energy is available. These transactions are part of the Company's normal operations to meet retail load. The Company has reclassified all settled transactions that meet the definition of optimization (trading transactions that optimize hydro resources, and purchases and sales between trading points) net in the income statement to conform to the new presentation required under EITF 02-3. The Company previously reported these transactions when settled in a gross manner in the income statement in electric operatingimplemented this treatment effective January 1, 2004. Consequently, revenue and purchased electricity expense. Unrealized gains or losses onwill be reduced as a result of netting any non-trading derivative instruments that are required to be marked-to-market remain reflected in unrealized (gain) loss on derivative instruments on Puget Energy's and PSE's income statement as required by SFAS No. 133. The adoption ofmeet the EITF 02-3 does not have any impact on the previously reported net income of the Company. The following optimization transactions were recorded in electric operating revenue:03-11 criteria.
| Years Ended December 31; (Dollars in thousands) | 2002 | 2001 | 2000 | ||||||||
| Optimization sales | $ | 66,992 | $ | 492,447 | $ | 133,361 | |||||
| Optimization purchases | 64,448 | 487,431 | 139,376 | ||||||||
| Net margin on optimization transactions | $ | 2,544 | $ | 5,016 | $ | (6,015 | ) | ||||
ITEM 7A.7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks, including changes in commodity prices and interest rates.
PORTFOLIO MANAGEMENT
The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted resources does exposeexposes the Company and its customers to some volumetric and commodity price risks.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:
The portfolio is subject to major sources of variability (e.g., hydro generation, outage risk, regional economic factors, temperature-sensitive retail sales, and market prices for gas and power supplies). At certain times, these sources of variability can mitigate portfolio imbalances; at other times they can exacerbate portfolio imbalances.
The Company’s energy risk 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 secondthird priority is to fully optimize excess capacity or flexibility within the wholesale portfolio. Most hedges can be implemented in ways that retain the Company’s ability to use its energy supply optimization opportunities. Still otherOther hedges are structured similarly to insurance instruments, where PSE pays an insurance premium to protect against certain extreme conditions.
Portfolio exposure is managed in accordance with Company polices and procedures. The Risk Management Committee, which is composed of Company officers, provides policy-level and strategic direction for management of the energy portfolio. The Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee.
The prices of energy commodities are subject to fluctuations due to unpredictable factors including weather, generation outages and other factors which impact supply and demand. The volumetric and commodity price risk is a consequence of purchasing energy at fixed and variable prices and providing deliveries at different tarifftariffs and variable prices. Costs associated with ownership and operation of production facilities are another component of this risk. The Company may use forward physical delivery agreements swaps and option contractsfinancial derivatives for the purpose of hedging commodity price risk. Without jeopardizing the security of supply within its portfolio, the Company will also engage in optimizing the portfolio. Optimization may take the form of utilizing excess capacity, shaping flexible resources to capture their highest value, utilizing transmission capacity or capitalizing on market price movement. As a result, portions of the Company’s energy portfolio are monetized through the use of forward price instruments.
The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility upon the Company. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. 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.
Transactions that qualify as hedge transactions under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, are recorded on the balance sheet at fair value. Changes in fair value of the Company’s derivatives are recorded each period in current earnings or other comprehensive income. Short-term derivative contracts for the purchase and sale of electricity are valued based upon daily quoted prices from an independent energy brokerage service. Valuations 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.
At December 31, 2002,2003, the Company had an after-tax net liabilityasset of approximately $7.5$16.2 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain recorded in other comprehensive income. Of the amount in other comprehensive income.income, 99% has been reclassified out of other comprehensive income to a deferred account due to the Company reaching the $40 million cap under the PCA mechanism. The Company also had energy contracts that were marked-to-market at a loss through current earnings for 20022003 of $7.5 million after-tax.$0.1 million. A hypothetical 10% increase in the market prices of natural gas and electricity would increase the fair value of qualifying cash flow hedges by approximately $5.2 million after-tax and would reduceincrease current earnings for those contracts marked-to-market in earnings by an immaterial amount. In addition, the Company believes its PCA and the PGA mechanism mitigate a portion of this risk. Market risk is managed subject to parameters established by the Board of Directors. The Company has established a Risk Management Committee composed of Company officers that monitors compliance with the Company’s policies and procedures. In addition, the Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee. The fair value of energy contracts that are recorded in the balance sheet of the Company are comprised of the following (net of tax):
| Derivative Contracts (Dollars in millions) | Amounts | ||||
| Fair value of contracts outstanding December 31, 2001 | $ | (35 | .4) | ||
| Contracts realized or otherwise settled during 2002 | 39 | .9 | |||
| Changes in fair values of derivatives | 6 | .7 | |||
| Fair value of contracts outstanding at December 31, 2002 | $ | 11 | .2 | ||
| Fair Value of Contracts with Settlement During Year | |||||||||||
| Source of Fair Value (Dollars in millions) | 2003 | 2004-2005 | 2006-2007 | 2008 and Thereafter | Total fair value | ||||||
| Prices based on models and other valuation methods | $ 1 | .3 | $ 4 | .9 | $ 4 | .1 | $ 0 | .9 | $ 11 | .2 | |
| DERIVATIVE CONTRACTS (DOLLARS IN MILLIONS) | Amounts | ||||
| Fair value of contracts outstanding December 31, 2002 | $ | 11 | .2 | ||
| Contracts realized or otherwise settled during 2003 | (1 | .4) | |||
| Changes in fair values of derivatives | 2 | .8 | |||
| Fair value of contracts outstanding at December 31, 2003 | $ | 12 | .6 | ||
| Fair Value of Contracts with Settlement During Year | |||||||||||||||||
| SOURCE OF FAIR VALUE (DOLLARS IN MILLIONS) | 2004 | 2005-2006 | 2007-2008 | 2009 and Thereafter | Total fair value | ||||||||||||
| Prices based on models and other valuation methods | $ | 4 | .0 | $ | 6 | .3 | $ | 2 | .3 | $ | -- | $ | 12 | .6 | |||
Short-term derivative contracts for the purchase and sale of electricity are valued based upon daily quoted prices from an independent energy brokerage service. Values for short-term and medium-term natural gas swap contracts are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas swap contracts are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using a modified Black-Scholes model approach.
INTEREST RATE RISK
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate leases and 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 does utilizeutilizes bank borrowings, commercial paper, and 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 to manage the interest rate risk associated with these debts anddebts. The Company did not have any swap instruments outstanding as of December 31, 20022003 or 2001.2002. The carrying amounts and fair values of Puget Energy’s fixed-rate debt instruments are:
| (Dollars in millions) | 2002 CARRYING AMOUNT | 2002 FAIR VALUE | 2001 CARRYING AMOUNT | 2001 FAIR VALUE | |||||
| Financial liabilities: | |||||||||
| Short-term debt | $ 47 | .3 | $ �� 47 | .3 | $ 348 | .6 | $ 348 | .6 | |
| Long-term debt | 2,223 | .0 | 2,381 | .8 | 2,246 | .7 | 2,131 | .2 | |
| 2003 | 2002 | ||||||||||
| (DOLLARS IN MILLIONS) | CARRYING AMOUNT | FAIR VALUE | CARRYING AMOUNT | FAIR VALUE | |||||||
| Financial liabilities: | |||||||||||
| Short-term debt | $ 13 | .9 | $ 13 | .9 | $ 47 | .3 | $ 47 | .3 | |||
| Long-term debt | 2,216 | .3 | 2,385 | .3 | 2,237 | .1 | 2,395 | .9 | |||
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9.9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Under the supervision and with the participation of Puget Energy’s and PSE’s management, including the Companies’ President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Energy and PSE have evaluated the effectiveness of the Companies’ disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934) as of the end of the period covered by this annual report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer of Puget Energy and PSE concluded that these disclosure controls and procedures are effective.
CHANGES IN INTERNAL CONTROLS
There have been no significant changes in Puget Energy’s or PSE’s internal control over financial reporting during the quarter ended December 31, 2003 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s or PSE’s internal control over financial reporting.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
PUGET ENERGY
The information required by Part IIIthis 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 — Election of Directors,” “Directors Continuing in Office”, “Board of Directors and Corporate Governance” and “Security Ownership of Directors and Executive Officers — Section 16(a) Beneficial Ownership Reporting Compliance” in Puget Energy’s proxy statement for its 20032004 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 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).
ITEM 10. DIRECTORS AND11. EXECUTIVE OFFICERS OF THE REGISTRANTCOMPENSATION
PUGET ENERGY
The information required by this item with respect to PSEPuget Energy is incorporated herein by reference to the material under “Election of Directors” and “Security Ownership of Directors and Executive Officers — Section 16(a) Beneficial Ownership Reporting Compliance” in Puget Energy’s proxy statement for its 2003 Annual Meeting of Shareholders (Commission File No. 1-16305), which is filed as Exhibit 99.3 to this report. Reference is also made to the information regarding PSE’s executive officers set forth in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item with respect to PSE is incorporated herein by reference to the material under “Structure and Compensation of Board of Directors—Director“Director Compensation,” “Executive Compensation” and “Employment Contracts, Termination of Employment and Change-In-Control Arrangements” in Puget Energy’s proxy statement for its 20032004 Annual Meeting of Shareholders (Commission File No. 1-16305), which.
PUGET SOUND ENERGY
The information called for by Item 11 with respect to PSE is filed as Exhibit 99.3omitted pursuant to this report.General Instruction 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 AND RELATED STOCKHOLDER MATTERS
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information regarding ourthe common stock that may be issued upon the exercise of options, warrants and other rights granted to employees, consultants or directors under all of the Puget Energy existing equity compensation plans, as of December 31, 2002.2003.
| (a) | (b) | (c) | ||||||
| Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (#) | Weighted-average exercise price of outstanding options, warrants and rights ($) | Number of securities remaining available for issuance under equity compensation plans (excluding securities reflected in column (a)) (#) | |||||
| Equity compensation plans approved by security holders | 40,000 | $22.51 | 1,322,051 | (2)(3) | ||||
| Equity compensation plans not aproved by security holders | 260,000 | (1) | | $22.51 | (1) | | 56,967 | (4)(5) |
| Total | 300,000 | $22.51 | 1,379,018 | |||||
| (a) | (b) | (c) | ||||||
| Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||
| Equity compensation plans approved by security holders | 40,000 | $22.51 | 1,194,480 | (1)(2)(3) | ||||
| Equity compensation plans not aproved by security holders | 260,000 | (4) | | $22.51 | (4) | | 41,879 | (5) |
| Total | 300,000 | $22.51 | 1,236,359 | |||||
The table does not include 43,554 deferred stock units in the Company’s deferred compensation plans that are payable in stock, plus cash for any fractional shares, of which all are currently vested.
| (1) | Includes 259,662 shares remaining available for issuance under Puget Energy’s Employee Stock Purchase Plan. |
| (2) | Includes 934,818 shares remaining available for issuance under Puget Energy’s Amended and Restated 1995 Long-Term Incentive Plan (performance shares). Depending on the level of achievement of performance goals, the performance shares may be paid out at zero shares at minimum achievement level, 790,922 shares at target level, or 1,181,103 at maximum level. Because there is no exercise price associated with performance shares, such shares are not included in the weighted-average price calculation. |
| (3) | In addition to stock options, Puget Energy may also grant stock awards, performance awards and other stock-based awards under the Puget Energy Amended and Restated 1995 Long-Term Incentive Plan. |
| (4) | Does not include stock options that were assumed by PSE in connection with its acquisition of Washington Energy Company. The assumed options are for the purchase of |
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SUMMARY OF EQUITY COMPENSATION PLANS NOT APPROVED BY SHAREHOLDERS
Non-Plan GrantsNON-PLAN GRANTS
On January 7, 2002, Puget Energy granted Stephen P. Reynolds, President and Chief Executive Officer of Puget Energy and PSE, two non-qualified stock option grants outside of any equity incentive plan adopted by Puget Energy (the “Non-Plan Grants”)Non-Plan Grants). These stock option grants were an inducement to Mr. Reynolds’ employment and in lieu of participation in the Companies’ Supplemental Executive Retirement Plan. One of the Non-Plan Grants made to Mr. Reynolds is for 150,000 shares of Puget Energy common stock and vests at a rate of 20% per year, for full vesting after five years. The other Non-Plan Grant made to Mr. Reynolds is for 110,000 shares of Puget Energy common stock and vests at a rate of 25% per year, for full vesting after four years. The exercise price of both Non-Plan Grants is $22.51 per share, equal to 100% of the fair market value of Puget Energy common stock on the date of grant. As of December 31, 2002,2003, all of the 260,000 shares subject to the Non-Plan Grants remained outstanding. Except as expressly provided in the option agreement relating to each of the Non-Plan Grants, the Non-Plan Grants are subject to the terms and conditions of the Company’s Amended and Restated 1995 Long-Term Incentive Plan.
Upon a change of control (as defined in the Employment Agreement between Puget Energy and Mr. Reynolds, dated January 7, 2002), both Non-Plan Grants will become fully vested and immediately exercisable. If Mr. Reynolds’ employment or service relationship with Puget Energy is terminated by Puget Energy without cause or by Mr. Reynolds with good reason, the vesting and exercisability of the Non-Plan Grants will be accelerated as follows: (1) the vesting and exercisability of the 150,000 share150,000-share Non-Plan Grant will be accelerated such that the total number of shares vested and exercisable will be calculated as if the option had vested on a daily basis over the four-year period through the date of termination and (2) the vesting and exercisability of the 110,000 share110,000-share Non-Plan Grant will be accelerated by two years. For purposes of the Non-Plan Grants, the terms “cause” and “good reason” have the meanings given to them in the Employment Agreement between Puget Energy and Mr. Reynolds, dated January 1, 2002.
Subject to the provisions regarding a change of control and termination of employment or service relationship by Puget Energy without cause or by Mr. Reynolds for good reason, as described above, upon termination of Mr. Reynolds’ employment or service relationship with
Puget Energy for any reason, the unvested portion of the Non-Plan Grants will terminate automatically and the vested portion may be exercised as follows: (1) generally, on or before the earlier of three months after termination and the expiration date of the option, (2) if termination is due to retirement, disability or death, on or before the earlier of one year after termination and the expiration date of the option, or (3) if death occurs after termination, but while the option is still exercisable, on or before the earlier of one year after the date of death and the expiration date of the option.
The Non-Plan Grants provide for the payment of the exercise price of options by any of the following means: (1) cash, (2) check, (3) tendering shares of Puget Energy’s common stock, either actually or by attestation, already owned for at least six months (or any shorter period necessary to avoid a charge to Puget Energy’s earnings for financial reporting purposes) that on the day prior to the exercise date have a fair market value equal to the aggregate exercise price of the shares being purchased, (4) delivery of a properly executed exercise notice, together with irrevocable instructions to a brokerage firm designated by Puget Energy to deliver promptly to Puget Energy the aggregate amount of sale or loan proceeds to pay the option exercise price and any withholding tax obligations that may arise in connection with the exercise or (5) any other method permitted by the plan administrator.
BENEFICIAL OWNERSHIP OF PUGET SOUND ENERGY
As of December 31, 2002,2003, all of the issued and outstanding shares of PSE’s common stock were held beneficially and of record by Puget Energy.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
ITEM 14. CONTROLS PRINCIPAL ACCOUNTANT FEES AND PROCEDURESSERVICES
Evaluation The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent auditors, for the year ended December 31 were as follows:
| 2003 | 2002 | ||||||||
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | PUGET ENERGY | PSE | |||||
| Audit fees1 | $ | 850 | $ | 453 | $ | 791 | $ | 324 | |
| Audit related fees2 | 261 | 147 | 195 | 151 | |||||
| Tax fees3 | 200 | 168 | 288 | 139 | |||||
| All other fees4 | -- | -- | 23 | -- | |||||
| Total | $ | 1,311 | $ | 768 | $ | 1,297 | $ | 614 | |
| 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 2003 fees are estimated and include an aggregate amount of approximately $167,000 and $277,000 billed to Puget Energy and PSE, respectively, through December 31, 2003. The 2002 fees include an aggregate amount of $100,000 and $297,000 billed to Puget Energy and PSE, respectively, through December 31, 2002. |
| 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. |
| 4 | For 2002, other fees consisted of financial information systems design and implementation fees relating to the final portion of work on the implementation of Puget Sound Energy's ConsumerLinX customer information system, initiated in 2001 and completed in February 2002. |
The Audit Committees of disclosure controlsthe Company have adopted policies for the pre-approval of all audit and procedures.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 supervisionpolicies, unless a type of service to be provided by the independent auditor has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee.
The annual audit services engagement terms and with the participation of Puget Energy’s and PSE’s management, including the Companies’ President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Energy and PSE have evaluated the effectiveness of the Companies’ disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934) within 90 days of the filing date of this annual report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer of Puget Energy and PSE concluded that these disclosure controls and procedures are effective.Changes in internal controls. There have been no significantfees, as well as any changes in Puget Energy’s or PSE’s internal controls or in other factors that could significantly affect internal controls subsequentterms, conditions and fees relating to the dateengagement, 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. With respect to each proposed pre-approved service, the independent auditor 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 evaluation, includingmembers. The member or members to whom such authority is delegated shall report any corrective actions with regardpre-approval decisions to significant deficienciesthe Audit Committees at their next scheduled meeting. The Audit Committees do not delegate responsibilities to pre-approve services performed by the independent auditor to management.
For 2003 all audit and material weaknesses.non-audit services were pre-approved.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
| (a) | Documents filed as part of this report: |
| 1) | Financial statement schedules |
| 2) | Exhibits — see index on page 111. |
| (b) | Reports on Form 8-K: |
Puget Energy and Puget Sound Energy |
| 1) | Form 8-K |
| 2) | Form 8-K dated November 4, 2003 — Item 5 Other Events, related to Puget Energy’s |
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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, INC. | |
| /s/ Stephen P. Reynolds | /s/ Stephen P. Reynolds | |
| Stephen P. Reynolds | Stephen P. Reynolds | |
| President and Chief Executive Officer | President and Chief Executive Officer | |
| Date: March | Date: March | |
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.
| SIGNATURE | | TITLE | | DATE | |
| (Puget Energy and PSE unless otherwise noted) | |||||
| /s/ Douglas P. | Chairman of the Board | March | |||
| (Douglas P. | |||||
| /s/ Stephen P. Reynolds | President, Chief Executive Officer and Director | ||||
| (Stephen P. Reynolds) | |||||
| /s/ | Senior Vice President Finance and Chief Financial Officer | ||||
| ( | |||||
| /s/ James W. Eldredge | Corporate Secretary and Chief Accounting Officer | ||||
| (James W. Eldredge) | |||||
| /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. | |||||
CERTIFICATIONS OF PUGET ENERGY
I, Stephen P. Reynolds, certify that:
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Date: March 10, 2003
I, Stephen A. McKeon, certify that:
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Date: March 10, 2003
I, Stephen P. Reynolds, certify that:
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Date: March 10, 2003
I, Stephen A. McKeon, certify that:
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Date: March 10, 2003
REPORT OF MANAGEMENT
PUGET ENERGY, INC.
and
PUGET SOUND ENERGY, INC.
The accompanying consolidated financial statements of Puget Energy, Inc. and Puget Sound Energy, Inc. have been prepared under the direction of management, which is responsible for their integrity and objectivity. The statements have been prepared in accordance with generally accepted accounting principles and include amounts based on judgments and estimates by management where necessary. Management also prepared the other information in the Annual Report on Form 10-K and is responsible for its accuracy and consistency with the financial statements.
Puget Energy and Puget Sound Energy maintain a system of internal control which, in management’s opinion, provides reasonable assurance that assets are properly safeguarded and transactions are executed in accordance with management’s authorization and properly recorded to produce reliable financial records and reports. The system of internal control provides for appropriate division of responsibility and is documented by written policy and updated as necessary. Puget Sound Energy’s internal audit staff assesses the effectiveness and adequacy of the internal controls on a regular basis and recommends improvements when appropriate. Management considers the internal auditor’s and independent auditor’s recommendations concerning Puget Energy’s and Puget Sound Energy’s internal controls and takes steps to implement those that they believe are appropriate in the circumstances.
In addition, PricewaterhouseCoopers LLP, the independent accountants,auditors, have performed audit procedures deemed appropriate to obtain reasonable assurance about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial statements through the audit committee, which is composed solely of outside Directors.Directors and two of those Directors qualify as financial experts under the rules adopted by the Securities and Exchange Commission. The audit committee meets regularly with management, the internal auditors and the independent auditors, jointly and separately, to review management’s process of implementation and maintenance of internal accounting controls and auditing and financial reporting matters. The internal and independent auditors have unrestricted access to the audit committee.
| /s/ Stephen P. Reynolds | /s/ | /s/ James W. Eldredge | ||
| Stephen P. Reynolds | James W. Eldredge | |||
| President and Chief Executive Officer | Senior Vice President Finance and Chief Financial Officer | Corporate Secretary and Chief Accounting Officer |
REPORT OF INDEPENDENT ACCOUNTANTSAUDITORS
To the Shareholders of Puget Energy, Inc.:
In our opinion, the consolidated financial statements listed on page 57in the accompanying index of this Annual Report on Form 10-K present fairly, in all material respects, the financial position of Puget Energy, Inc. and its subsidiaries at December 31, 20022003 and 2001,2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed on page 100in the accompanying index of the document 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 auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 described in Note 1715 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities as required by Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities.”
As described in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations as required by Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.”
PricewaterhouseCoopers LLP
Seattle, WashingtonFebruary 12, 2003March 5, 2004
REPORT OF INDEPENDENT AUDITORS
To the Shareholder of Puget Sound Energy, Inc.:
In our opinion, the consolidated financial statements listed on page 57in the accompanying index of this Annual Report on Form 10-K present fairly, in all material respects, the financial position of Puget Sound Energy, Inc. and its subsidiaries at December 31, 20022003 and 2001,2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed on page 100in the accompanying index of the document 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 auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 described in Note 1715 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities as required by Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities.”
As described in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations as required by Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.”
PricewaterhouseCoopers LLP
Seattle, WashingtonFebruary 12, 2003March 5, 2004
Consolidated Financial Statements, Financial Statement Schedule Covered by the Foregoing Report of Independent Accountants and Exhibits
| CONSOLIDATED FINANCIAL STATEMENTS: PUGET ENERGY: Consolidated Statements of Income for the years ended December 31, 2003, 2002 |
| Consolidated Balance Sheets, December 31, |
| Consolidated Statements of Capitalization, December 31, |
| Consolidated Statements of Common Shareholders' Equity for the years ended December 31, 2003, 2002 |
| Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 2002 |
| Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 |
| PUGET SOUND ENERGY: Consolidated Statements of Income for the years ended December 31, 2003, 2002 |
| Consolidated Balance Sheets, December 31, |
| Consolidated Statements of Capitalization, December 31, |
| Consolidated Statements of Common Shareholders' Equity for the years ended December 31, 2003, 2002 |
| Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 2002 |
| Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 |
| NOTES: Combined Puget Energy and Puget Sound Energy Notes to Consolidated Financial Statements |
| |
| SCHEDULE: |
| II. | Valuation and Qualifying Accounts and Reserves for the |
| 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. |
| 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. |
| Exhibit Index |
| Puget Energy Consolidated Statements of |
| INCOME |
| (Dollars in thousands, except per share amounts) FOR YEARS ENDED DECEMBER 31 | (Dollars in thousands, except per share amounts) FOR YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | (Dollars in thousands, except per share amounts) FOR YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||||||||
| Operating revenues: | ||||||||||||||||||||||
| Electric | $ | 1,365,885 | $ | 1,865,227 | $ | 2,632,319 | $ | 1,509,463 | $ | 1,365,885 | $ | 1,865,227 | ||||||||||
| Gas | 697,155 | 815,071 | 612,311 | 634,230 | 697,155 | 815,071 | ||||||||||||||||
| Non-utility construction services | 341,787 | 319,529 | 173,786 | |||||||||||||||||||
| Other | 329,282 | 206,262 | 57,666 | 6,043 | 9,753 | 32,476 | ||||||||||||||||
| Total operating revenues | 2,392,322 | 2,886,560 | 3,302,296 | 2,491,523 | 2,392,322 | 2,886,560 | ||||||||||||||||
| Operating expenses: | ||||||||||||||||||||||
| Energy costs: | ||||||||||||||||||||||
| Purchased electricity | 645,371 | 918,676 | 1,627,249 | 823,189 | 645,371 | 918,676 | ||||||||||||||||
| Residential exchange | (149,970 | ) | (75,864 | ) | (41,000 | ) | (173,840 | ) | (149,970 | ) | (75,864 | ) | ||||||||||
| Purchased gas | 405,016 | 537,431 | 332,927 | 327,132 | 405,016 | 537,431 | ||||||||||||||||
| Fuel | 113,538 | 281,405 | 182,978 | |||||||||||||||||||
| Unrealized gain on derivative instruments | (11,612 | ) | (11,182 | ) | -- | |||||||||||||||||
| Electric generation fuel | 64,999 | 113,538 | 281,405 | |||||||||||||||||||
| Unrealized (gain) loss on derivative instruments | 106 | (11,612 | ) | (11,182 | ) | |||||||||||||||||
| Utility operations and maintenance | 286,220 | 265,789 | 240,094 | 289,702 | 286,220 | 265,789 | ||||||||||||||||
| Other operations and maintenance | 273,157 | 156,731 | 60,612 | 303,972 | 273,157 | 156,731 | ||||||||||||||||
| Depreciation and amortization | 228,743 | 217,540 | 196,513 | 236,866 | 228,743 | 217,540 | ||||||||||||||||
| Conservation amortization | 17,501 | 6,493 | 6,830 | 33,458 | 17,501 | 6,493 | ||||||||||||||||
| Taxes other than income taxes | 215,429 | 212,582 | 202,398 | 208,395 | 215,429 | 212,582 | ||||||||||||||||
| Income taxes | 59,260 | 79,838 | 129,823 | 72,369 | 59,260 | 79,838 | ||||||||||||||||
| Total operating expenses | 2,082,653 | 2,589,439 | 2,938,424 | 2,186,348 | 2,082,653 | 2,589,439 | ||||||||||||||||
| Operating income | 309,669 | 297,121 | 363,872 | 305,175 | 309,669 | 297,121 | ||||||||||||||||
| Other income | 5,458 | 14,526 | 5,061 | 1,564 | 5,458 | 14,526 | ||||||||||||||||
| Income before interest charges | 315,127 | 311,647 | 368,933 | 306,739 | 315,127 | 311,647 | ||||||||||||||||
| Interest charges: | ||||||||||||||||||||||
| AFUDC | (1,969 | ) | (4,446 | ) | (9,303 | ) | (3,343 | ) | (1,969 | ) | (4,446 | ) | ||||||||||
| Interest expense | 198,346 | 194,505 | 184,405 | 187,316 | 198,346 | 194,505 | ||||||||||||||||
| Mandatorily redeemable securities interest expense | 1,072 | -- | -- | |||||||||||||||||||
| Total interest charges | 196,377 | 190,059 | 175,102 | 185,045 | 196,377 | 190,059 | ||||||||||||||||
| Minority interest in earnings of consolidated subsidiary | 867 | -- | -- | 177 | 867 | -- | ||||||||||||||||
| Net income before cumulative effect of accounting change | 117,883 | 121,588 | 193,831 | 121,517 | 117,883 | 121,588 | ||||||||||||||||
| Cumulative effect of implementation of accounting change (net of tax) | -- | 14,749 | -- | 169 | -- | 14,749 | ||||||||||||||||
| Net income | 117,883 | 106,839 | 193,831 | 121,348 | 117,883 | 106,839 | ||||||||||||||||
| Less preferred stock dividends accrual | 7,831 | 8,413 | 8,994 | |||||||||||||||||||
| Less: preferred stock dividends accrual | 5,151 | 7,831 | 8,413 | |||||||||||||||||||
| Income for common stock | $ | 110,052 | $ | 98,426 | $ | 184,837 | $ | 116,197 | $ | 110,052 | $ | 98,426 | ||||||||||
| Common shares outstanding weighted average | 88,372 | 86,445 | 85,411 | 94,750 | 88,372 | 86,445 | ||||||||||||||||
| Diluted shares outstanding weighted average | 88,777 | 86,703 | 85,690 | 95,309 | 88,777 | 86,703 | ||||||||||||||||
| Basic and diluted earnings per common share before | ||||||||||||||||||||||
| Basic earnings per common share before | ||||||||||||||||||||||
| cumulative effect of accounting change | $ | 1.24 | $ | 1.31 | $ | 2.16 | $ | 1.23 | $ | 1.24 | $ | 1.31 | ||||||||||
| Basic and diluted for cumulative effect of accounting change | -- | (0.17 | ) | -- | ||||||||||||||||||
| Basic earnings for cumulative effect of accounting change | -- | -- | (0.17 | ) | ||||||||||||||||||
| Basic and diluted earnings per common share | $ | 1.24 | $ | 1.14 | $ | 2.16 | ||||||||||||||||
| Basic earnings per common share | $ | 1.23 | $ | 1.24 | $ | 1.14 | ||||||||||||||||
| Diluted earnings per common share before | ||||||||||||||||||||||
| cumulative effect of accounting change | $ | 1.22 | $ | 1.24 | $ | 1.31 | ||||||||||||||||
| Diluted earnings for cumulative effect of accounting change | -- | -- | (0.17 | ) | ||||||||||||||||||
| Diluted earnings per common share | $ | 1.22 | $ | 1.24 | $ | 1.14 | ||||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Energy Consolidated Balance Sheets |
| ASSETS |
| (DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2003 | 2002 | ||||||
| Utility plant: | ||||||||
| Electric plant | $ | 4,265,908 | $ | 4,229,352 | ||||
| Gas plant | 1,749,102 | 1,645,865 | ||||||
| Common plant | 390,622 | 378,844 | ||||||
| Less: Accumulated depreciation and amortization | (2,325,405 | ) | (2,223,190 | ) | ||||
| Net utility plant | 4,080,227 | 4,030,871 | ||||||
| Other property and investments: | ||||||||
| Investment in Bonneville Exchange Power Contract | 47,609 | 51,136 | ||||||
| Goodwill, net | 133,302 | 125,555 | ||||||
| Intangibles, net | 18,707 | 18,652 | ||||||
| Non-utility property, net | 91,932 | 80,855 | ||||||
| Other | 110,543 | 101,932 | ||||||
| Total other property and investments | 402,093 | 378,130 | ||||||
| Current assets: | ||||||||
| Cash | 27,481 | 176,669 | ||||||
| Restricted cash | 2,537 | 18,871 | ||||||
| Accounts receivable, net of allowance for doubtful accounts | 227,115 | 279,623 | ||||||
| Unbilled revenues | 131,798 | 112,115 | ||||||
| Materials and supplies, at average cost | 85,128 | 70,402 | ||||||
| Current portion of unrealized gain on derivative instruments | 7,593 | 3,741 | ||||||
| Prepayments and other | 12,200 | 11,323 | ||||||
| Total current assets | 493,852 | 672,744 | ||||||
| Other long-term assets: | ||||||||
| Regulatory asset for deferred income taxes | 142,792 | 167,058 | ||||||
| Regulatory asset for PURPA buyout costs | 227,753 | 243,584 | ||||||
| Unrealized gain on derivative instruments | 8,624 | 9,870 | ||||||
| PCA mechanism | 3,605 | -- | ||||||
| Other | 315,739 | 269,876 | ||||||
| Total other long-term assets | 698,513 | 690,388 | ||||||
| Total assets | $ | 5,674,685 | $ | 5,772,133 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Energy Consolidated Balance Sheets |
| (Dollars in thousands) AT DECEMBER 31 | 2002 | 2001 | ||||||
| Utility plant: | ||||||||
| Electric plant | $ | 4,229,352 | $ | 4,167,920 | ||||
| Gas plant | 1,645,865 | 1,551,439 | ||||||
| Common plant | 378,844 | 362,670 | ||||||
| Less: Accumulated depreciation and amortization | (2,337,832 | ) | (2,194,048 | ) | ||||
| Net utility plant | 3,916,229 | 3,887,981 | ||||||
| Other property and investments: | ||||||||
| Investment in Bonneville Exchange Power Contract | 51,136 | 54,663 | ||||||
| Goodwill, net | 125,555 | 102,151 | ||||||
| Intangibles, net | 18,652 | 16,059 | ||||||
| Non-utility property, net | 80,855 | 48,369 | ||||||
| Other | 101,932 | 96,007 | ||||||
| Total other property and investments | 378,130 | 317,249 | ||||||
| Current assets: | ||||||||
| Cash | 176,669 | 92,356 | ||||||
| Restricted cash | 18,871 | -- | ||||||
| Accounts receivable, net of allowance for doubtful accounts | 279,623 | 279,321 | ||||||
| Unbilled revenues | 112,115 | 147,008 | ||||||
| Purchased gas receivable | -- | 37,228 | ||||||
| Materials and supplies, at average cost | 70,402 | 90,333 | ||||||
| Current portion of unrealized gain on derivative instruments | 3,741 | 3,315 | ||||||
| Prepayments and other | 11,323 | 11,277 | ||||||
| Total current assets | 672,744 | 660,838 | ||||||
| Other long-term assets: | ||||||||
| Regulatory asset for deferred income taxes | 167,058 | 193,016 | ||||||
| Regulatory asset for PURPA buyout costs | 243,584 | 244,635 | ||||||
| Unrealized gain on derivative instruments | 9,870 | 3,317 | ||||||
| Other | 269,876 | 239,941 | ||||||
| Total other long-term assets | 690,388 | 680,909 | ||||||
| Total assets | $ | 5,657,491 | $ | 5,546,977 | ||||
| (DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2003 | 2002 | |||
| Capitalization: | |||||
| (See Consolidated Statements of Capitalization): | |||||
| Common equity | $ | 1,655,046 | $ | 1,523,787 | |
| Preferred stock not subject to mandatory redemption | -- | 60,000 | |||
| Total shareholders' equity | 1,655,046 | 1,583,787 | |||
| Redeemable securities and long-term debt: | |||||
| Preferred stock subject to mandatory redemption | 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 | 280,250 | -- | |||
| Long-term debt | 1,969,489 | 2,160,276 | |||
| Total redeemable securities and long-term debt | 2,251,628 | 2,503,438 | |||
| Total capitalization | 3,906,674 | 4,087,225 | |||
| Minority interest in consolidated subsidiary | 11,689 | 10,629 | |||
| Current liabilities: | |||||
| Accounts payable | 214,357 | 205,619 | |||
| Short-term debt | 13,893 | 47,295 | |||
| Current maturities of long-term debt | 246,829 | 76,837 | |||
| Purchased gas liability | 11,984 | 83,811 | |||
| Accrued expenses: | |||||
| Taxes | 77,451 | 62,562 | |||
| Salaries and wages | 12,712 | 11,441 | |||
| Interest | 32,954 | 37,942 | |||
| Current portion of unrealized loss on derivative instruments | 3,636 | 2,410 | |||
| Other | 46,378 | 44,130 | |||
| Total current liabilities | 660,194 | 572,047 | |||
| Long-term liabilities: | |||||
| Deferred income taxes | 755,235 | 730,675 | |||
| Other deferred credits | 340,893 | 371,557 | |||
| Total long-term liabilities | 1,096,128 | 1,102,232 | |||
| Commitments and contingencies | -- | -- | |||
| Total capitalization and liabilities | $ | 5,674,685 | $ | 5,772,133 | |
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Energy Consolidated |
| CAPITALIZATION |
| (Dollars in thousands) AT DECEMBER 31 | 2002 | 2001 | ||||||
| Capitalization: | ||||||||
| (See Consolidated Statements of Capitalization): | ||||||||
| Common equity | $ | 1,523,787 | $ | 1,362,724 | ||||
| Preferred stock not subject to mandatory redemption | 60,000 | 60,000 | ||||||
| Preferred stock subject to mandatory redemption | 43,162 | 50,662 | ||||||
| Corporation obligated, mandatorily redeemable preferred | ||||||||
| securities of subsidiary trust holding solely junior | ||||||||
| subordinated debentures of the corporation | 300,000 | 300,000 | ||||||
| Long-term debt | 2,149,733 | 2,127,054 | ||||||
| Total capitalization | 4,076,682 | 3,900,440 | ||||||
| Minority interest in consolidated subsidiary | 10,629 | -- | ||||||
| Current liabilities: | ||||||||
| Accounts payable | 205,619 | 167,426 | ||||||
| Short-term debt | 47,295 | 348,577 | ||||||
| Current maturities of long-term debt | 73,206 | 119,523 | ||||||
| Purchased gas liability | 83,811 | -- | ||||||
| Accrued expenses: | ||||||||
| Taxes | 62,562 | 70,708 | ||||||
| Salaries and wages | 11,441 | 14,746 | ||||||
| Interest | 37,942 | 42,505 | ||||||
| Current portion of unrealized loss on derivative instruments | 2,410 | 35,145 | ||||||
| Other | 47,761 | 46,178 | ||||||
| Total current liabilities | 572,047 | 844,808 | ||||||
| Long-term liabilities: | ||||||||
| Deferred income taxes | 730,675 | 605,315 | ||||||
| Unrealized loss on derivative instruments | -- | 75 | ||||||
| Other deferred credits | 267,458 | 196,339 | ||||||
| Total long-term liabilities | 998,133 | 801,729 | ||||||
| Commitments and contingencies | -- | -- | ||||||
| Total capitalization and liabilities | $ | 5,657,491 | $ | 5,546,977 | ||||
| (DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2003 | | 2002 | |||||
| Common equity: | ||||||||
| Common stock $0.01 par value, 250,000,000 shares authorized, 99,074,070 and | ||||||||
| 93,642,659 shares outstanding at December 31, 2003 and 2002 | $ | 991 | $ | 936 | ||||
| Additional paid-in capital | 1,603,901 | 1,484,615 | ||||||
| Earnings reinvested in the business | 58,217 | 36,396 | ||||||
| Accumulated other comprehensive income (loss) - net of tax | (8,063 | ) | 1,840 | |||||
| Total common equity | 1,655,046 | 1,523,787 | ||||||
| Preferred stock not subject to mandatory redemption - cumulative - $25 par value:* | ||||||||
| 7.45% series II - 2,400,000 shares authorized, 0 and 2,400,000 shares outstanding at | ||||||||
| December 31, 2003 and 2002 | -- | 60,000 | ||||||
| Total preferred stock not subject to mandatory redemption | -- | 60,000 | ||||||
| Preferred stock subject to mandatory redemption - cumulative - $100 par value: * | ||||||||
| 4.84% series - 150,000 shares authorized, | ||||||||
| 14,583 and 14,808 shares outstanding at December 31, 2003 and 2002 | 1,458 | 1,481 | ||||||
| 4.70% series - 150,000 shares authorized, | ||||||||
| 4,311 shares outstanding at December 31, 2003 and 2002 | 431 | 431 | ||||||
| 7.75% series - 750,000 shares authorized, | ||||||||
| 0 and 412,500 shares outstanding at December 31, 2003 and 2002 | -- | 41,250 | ||||||
| Total preferred stock subject to mandatory redemption | 1,889 | 43,162 | ||||||
| Corporation obligated mandatorily redeemable preferred securities of | ||||||||
| subsidiary trust holding solely junior subordinated debentures of the | -- | 300,000 | ||||||
| corporation | ||||||||
| Junior subordinated debentures of the corporation payable to a subsidiary trust | ||||||||
| holding mandatorily redeemable preferred securities | 280,250 | -- | ||||||
| Long-term debt: | ||||||||
| First mortgage bonds and senior notes | 1,891,158 | 1,932,000 | ||||||
| Pollution control revenue bonds: | ||||||||
| Revenue refunding 1991 series, due 2021 | -- | 50,900 | ||||||
| Revenue refunding 1992 series, due 2022 | -- | 87,500 | ||||||
| Revenue refunding 1993 series, due 2020 | -- | 23,460 | ||||||
| Revenue refunding 2003 series, due 2031 | 161,860 | -- | ||||||
| Other notes | 163,313 | 143,281 | ||||||
| Unamortized discount - net of premium | (13 | ) | (28 | ) | ||||
| Long-term debt due within one year | (246,829 | ) | (76,837 | ) | ||||
| Total long-term debt excluding current maturities | 1,969,489 | 2,160,276 | ||||||
| Total capitalization | $ | 3,906,674 | $ | 4,087,225 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| (Dollars in thousands) | ||||||||
| AT DECEMBER 31 | 2002 | 2001 | ||||||
| Common equity: | ||||||||
| Common stock $0.01 par value, 250,000,000 shares authorized, 93,642,659 | ||||||||
| and 87,023,210 shares outstanding at December 31, 2002 and 2001 | $ | 936 | $ | 870 | ||||
| Additional paid-in capital | 1,484,615 | 1,358,946 | ||||||
| Earnings reinvested in the business | 36,396 | 32,229 | ||||||
| Accumulated other comprehensive income (loss) - net of tax | 1,840 | (29,321 | ) | |||||
| Total common equity | 1,523,787 | 1,362,724 | ||||||
| Preferred stock not subject to mandatory | ||||||||
| redemption - cumulative - $25 par value: * | ||||||||
| 7.45% series II 2,400,000 shares authorized and outstanding | 60,000 | 60,000 | ||||||
| Total preferred stock not subject to mandatory redemption | 60,000 | 60,000 | ||||||
| Preferred stock subject to mandatory redemption - cumulative - $100 par value: * | ||||||||
| 4.84% series - 150,000 shares authorized, 14,808 shares outstanding | 1,481 | 1,481 | ||||||
| 4.70% series - 150,000 shares authorized, | ||||||||
| 4,311 shares outstanding | 431 | 431 | ||||||
| 7.75% series - 750,000 shares authorized, | ||||||||
| 412,500 and 487,500 shares outstanding | 41,250 | 48,750 | ||||||
| Total preferred stock subject to mandatory redemption | 43,162 | 50,662 | ||||||
| Corporation obligated, mandatorily redeemable preferred | ||||||||
| securities of subsidiary trust holding solely junior | ||||||||
| subordinated debentures of the corporation | 300,000 | 300,000 | ||||||
| Long-term debt: | ||||||||
| First mortgage bonds and senior notes | 1,932,000 | 2,009,000 | ||||||
| Pollution control revenue bonds: | ||||||||
| Revenue refunding 1991 series, due 2021 | 50,900 | 50,900 | ||||||
| Revenue refunding 1992 series, due 2022 | 87,500 | 87,500 | ||||||
| Revenue refunding 1993 series, due 2020 | 23,460 | 23,460 | ||||||
| Other notes | 129,107 | 75,762 | ||||||
| Unamortized discount - net of premium | (28 | ) | (45 | ) | ||||
| Long-term debt due within one year | (73,206 | ) | (119,523 | ) | ||||
| Total long-term debt excluding current maturities | 2,149,733 | 2,127,054 | ||||||
| Total capitalization | $ | 4,076,682 | $ | 3,900,440 | ||||
| * Puget Energy has 50,000,000 shares authorized for $0.01 par value preferred stock. PSE has |
The accompanying notes are an integral part of the consolidated financial statements.
| Common Stock | Additional | Accumulated Other | ||||||||||||||||||
| (Dollars in thousands) YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 | Shares | Amount | Paid-in Capital | Retained Earnings | Comprehensive Income | Total Amount | ||||||||||||||
| Balance at December 31, 1999 | 84,922,405 | $ | 849,224 | $ | 454,982 | $ | 66,019 | $ | 8,848 | $ | 1,379,073 | |||||||||
| Net income | -- | -- | -- | 193,831 | -- | 193,831 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (9,067 | ) | -- | (9,067 | ) | ||||||||||||
| Loss on preferred stock redemptions | -- | -- | 1,181 | (1,181 | ) | -- | -- | |||||||||||||
| Common stock dividend declared | -- | -- | -- | (156,929 | ) | -- | (156,929 | ) | ||||||||||||
| Common stock issued on dividend reinvestment | 981,549 | 9,816 | 13,295 | -- | -- | 23,111 | ||||||||||||||
| plan | ||||||||||||||||||||
| Other | (163 | ) | (2 | ) | 721 | -- | -- | 719 | ||||||||||||
| Other comprehensive income | -- | -- | -- | -- | (4,098 | ) | (4,098 | ) | ||||||||||||
| Balance at December 31, 2000 | 85,903,791 | $ | 859,038 | $ | 470,179 | $ | 92,673 | $ | 4,750 | $ | 1,426,640 | |||||||||
| Net income | -- | -- | -- | 106,839 | -- | 106,839 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (8,485 | ) | -- | (8,485 | ) | ||||||||||||
| Common stock dividend declared | -- | -- | -- | (158,798 | ) | -- | (158,798 | ) | ||||||||||||
| Reclassification of par value in connection | -- | (858,179 | ) | 858,179 | -- | -- | -- | |||||||||||||
| with the formation of Puget Energy | ||||||||||||||||||||
| Common stock issued on dividend reinvestment | 1,119,568 | 11 | 25,551 | -- | -- | 25,562 | ||||||||||||||
| plan | ||||||||||||||||||||
| Other | (149 | ) | -- | 5,037 | -- | -- | 5,037 | |||||||||||||
| Other comprehensive income | -- | -- | -- | -- | (34,071 | ) | (34,071 | ) | ||||||||||||
| Balance at December 31, 2001 | 87,023,210 | $ | 870 | $ | 1,358,946 | $ | 32,229 | $ | (29,321 | ) | $ | 1,362,724 | ||||||||
| Net income | -- | -- | -- | 117,883 | -- | 117,883 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (7,904 | ) | -- | (7,904 | ) | ||||||||||||
| 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 | ) | (125 | ) | -- | (6,545 | ) | ||||||||||
| 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 | |||||||||
The accompanying notes are an integral part of the consolidated financial statements.
| (Dollars in thousands) FOR YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | ||||||||
| Net income | $ | 117,883 | $ | 106,839 | $ | 193,831 | |||||
| Other comprehensive income, net of tax: | |||||||||||
| Unrealized holding losses on marketable securities during the period | (1,359 | ) | (1,823 | ) | (938 | ) | |||||
| Reclassification adjustment for realized gains on marketable | -- | (5 | ) | (3,160 | ) | ||||||
| securities included in net income | |||||||||||
| Foreign currency translation adjustment | 63 | -- | -- | ||||||||
| Minimum pension liability adjustment | (2,098 | ) | (5,148 | ) | -- | ||||||
| Transition adjustment for unrealized gain on derivative instruments | -- | 286,928 | -- | ||||||||
| as of January 1, 2001 | |||||||||||
| Unrealized gains (losses) on derivative instruments during the period | 2,853 | (131,420 | ) | -- | |||||||
| Reversal of unrealized (gains) losses on derivative instruments | 31,702 | (182,603 | ) | -- | |||||||
| settled during the period | |||||||||||
| Other comprehensive income (loss) | 31,161 | (34,071 | ) | (4,098 | ) | ||||||
| Comprehensive income | $ | 149,044 | $ | 72,768 | $ | 189,733 | |||||
The accompanying notes are an integral part of the consolidated financial statements.
| (Dollars in thousands) FOR YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | ||||||||
| Operating activities: | |||||||||||
| Net income | $ | 117,883 | $ | 106,839 | $ | 193,831 | |||||
| Adjustments to reconcile net income to net cash | |||||||||||
| provided by operating activities: | |||||||||||
| Depreciation and amortization | 228,743 | 217,540 | 196,513 | ||||||||
| Deferred income taxes and tax credits - net | 151,318 | 11,464 | (7,446 | ) | |||||||
| Gain from sale of securities | -- | -- | (6,476 | ) | |||||||
| Net unrealized (gains) losses on derivative instruments | (11,612 | ) | 3,567 | -- | |||||||
| Other (including conservation amortization) | 10,872 | (4,465 | ) | (7,276 | ) | ||||||
| Cash collateral received from energy supplier | 21,425 | -- | -- | ||||||||
| Change in certain current assets and liabilities | |||||||||||
| Accounts receivable and unbilled revenue | 46,860 | 147,575 | (220,568 | ) | |||||||
| Materials and supplies | 22,088 | 10,611 | (29,760 | ) | |||||||
| Prepayments and other | 141 | 936 | (1,742 | ) | |||||||
| Purchased gas receivable/liability | 121,039 | 58,822 | (62,350 | ) | |||||||
| Accounts payable | 34,351 | (254,944 | ) | 232,402 | |||||||
| Taxes payable | (18,260 | ) | (33,288 | ) | 31,308 | ||||||
| Accrued expenses and other | (971 | ) | 33,631 | 1,847 | |||||||
| Net cash provided by operating activities | 723,877 | 298,288 | 320,283 | ||||||||
| Investing activities: | |||||||||||
| Construction expenditures - excluding equity AFUDC | (224,165 | ) | (247,435 | ) | (296,480 | ) | |||||
| Additions to other property, plant and equipment | (11,621 | ) | (5,193 | ) | -- | ||||||
| Energy conservation expenditures | (11,356 | ) | (15,591 | ) | (6,931 | ) | |||||
| Restricted cash | (18,871 | ) | -- | -- | |||||||
| Proceeds from sale of investment in Cabot preferred stock | -- | -- | 51,463 | ||||||||
| Proceeds from sale of Centralia plant | -- | -- | 37,449 | ||||||||
| Proceeds from sale of securities | -- | -- | 6,757 | ||||||||
| Investments by InfrastruX | (41,602 | ) | (75,591 | ) | (85,506 | ) | |||||
| Repayment from/(loans to) Schlumberger | -- | 51,948 | (20,874 | ) | |||||||
| Other | (15,761 | ) | (16,446 | ) | (14,138 | ) | |||||
| Net cash used by investing activities | (323,376 | ) | (308,308 | ) | (328,260 | ) | |||||
| Financing activities: | |||||||||||
| Increase (decrease) in short-term debt - net | (301,281 | ) | (32,406 | ) | (226,395 | ) | |||||
| Dividends paid | (97,321 | ) | (141,709 | ) | (142,886 | ) | |||||
| Issuance of common stock | 120,214 | -- | -- | ||||||||
| Issuance of trust preferred stock | -- | 200,000 | -- | ||||||||
| Redemption of preferred stock | (7,500 | ) | (7,500 | ) | (7,503 | ) | |||||
| Issuance of bonds and long-term debt | 40,000 | 70,250 | 510,000 | ||||||||
| Redemption of bonds and notes | (65,937 | ) | (19,000 | ) | (150,980 | ) | |||||
| Other | (4,363 | ) | (3,642 | ) | (3,583 | ) | |||||
| Net cash provided (used) by financing activities | (316,188 | ) | 65,993 | (21,347 | ) | ||||||
| Increase (decrease) in cash from net income | 84,313 | 55,973 | (29,324 | ) | |||||||
| Cash at beginning of year | 92,356 | 36,383 | 65,707 | ||||||||
| Cash at end of year | $ | 176,669 | $ | 92,356 | $ | 36,383 | |||||
| Supplemental Cash Flow Information: | |||||||||||
| Cash payments for: | |||||||||||
| Interest (net of capitalized interest) | $ | 200,392 | $ | 191,004 | $ | 176,895 | |||||
| Income taxes (net of refunds) | (81,652 | ) | 87,470 | 114,100 | |||||||
The accompanying notes are an integral part of the consolidated financial statements.
| (Dollars in thousands) FOR YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | ||||||||
| Operating revenues: | |||||||||||
| Electric | $ | 1,365,885 | $ | 1,865,227 | $ | 2,632,319 | |||||
| Gas | 697,155 | 815,071 | 612,311 | ||||||||
| Other | 9,753 | 32,476 | 57,666 | ||||||||
| Total operating revenues | 2,072,793 | 2,712,774 | 3,302,296 | ||||||||
| Operating expenses: | |||||||||||
| Energy costs: | |||||||||||
| Purchased electricity | 645,371 | 918,676 | 1,627,249 | ||||||||
| Residential exchange | (149,970 | ) | (75,864 | ) | (41,000 | ) | |||||
| Purchased gas | 405,016 | 537,431 | 332,927 | ||||||||
| Fuel | 113,538 | 281,405 | 182,978 | ||||||||
| Unrealized gain on derivative instruments | (11,612 | ) | (11,182 | ) | -- | ||||||
| Utility operations and maintenance | 286,220 | 265,789 | 240,094 | ||||||||
| Other operations and maintenance | 1,602 | 8,546 | 60,612 | ||||||||
| Depreciation and amortization | 215,317 | 208,720 | 196,513 | ||||||||
| Conservation amortization | 17,501 | 6,493 | 6,830 | ||||||||
| Taxes other than income taxes | 202,381 | 207,365 | 202,398 | ||||||||
| Income taxes | 52,836 | 76,915 | 129,823 | ||||||||
| Total operating expenses | 1,778,200 | 2,424,294 | 2,938,424 | ||||||||
| Operating income | 294,593 | 288,480 | 363,872 | ||||||||
| Other income | 5,215 | 17,053 | 5,061 | ||||||||
| Income before interest charges | 299,808 | 305,533 | 368,933 | ||||||||
| Interest charges: | |||||||||||
| AFUDC | (1,969 | ) | (4,446 | ) | (9,303 | ) | |||||
| Interest expense | 192,829 | 190,849 | 184,405 | ||||||||
| Total interest charges | 190,860 | 186,403 | 175,102 | ||||||||
| Net income before cumulative effect of accounting change | 108,948 | 119,130 | 193,831 | ||||||||
| Cumulative effect of implementation of accounting change (net of tax) | -- | 14,749 | -- | ||||||||
| Net income | 108,948 | 104,381 | 193,831 | ||||||||
| Less preferred stock dividends accrual | 7,831 | 8,413 | 8,994 | ||||||||
| Income for common stock | $ | 101,117 | $ | 95,968 | $ | 184,837 | |||||
The accompanying notes are an integral part of the consolidated financial statements.
| (Dollars in thousands) AT DECEMBER 31 | 2002 | 2001 | ||||||
| Utility plant: | ||||||||
| Electric plant | $ | 4,229,352 | $ | 4,167,920 | ||||
| Gas plant | 1,645,865 | 1,551,439 | ||||||
| Common plant | 378,844 | 362,670 | ||||||
| Less: Accumulated depreciation and amortization | (2,337,832 | ) | (2,194,048 | ) | ||||
| Net utility plant | 3,916,229 | 3,887,981 | ||||||
| Other property and investments: | ||||||||
| Investment in Bonneville Exchange Power Contract | 51,136 | 54,663 | ||||||
| Non-utility property, net | 1,699 | 1,105 | ||||||
| Other | 101,922 | 94,762 | ||||||
| Total other property and investments | 154,757 | 150,530 | ||||||
| Current assets: | ||||||||
| Cash | 161,475 | 82,708 | ||||||
| Restricted cash | 18,871 | -- | ||||||
| Accounts receivable, net of allowance for doubtful accounts | 208,702 | 235,348 | ||||||
| Unbilled revenues | 112,115 | 147,008 | ||||||
| Purchased gas receivable | -- | 37,228 | ||||||
| Materials and supplies, at average cost | 63,563 | 85,318 | ||||||
| Current portion of unrealized gain on derivative instruments | 3,741 | 3,315 | ||||||
| Prepayments and other | 8,907 | 7,405 | ||||||
| Total current assets | 577,374 | 598,330 | ||||||
| Other long-term assets: | ||||||||
| Regulatory asset for deferred income taxes | 167,058 | 193,016 | ||||||
| Regulatory asset for PURPA buyout costs | 243,584 | 244,635 | ||||||
| Unrealized gain on derivative instruments | 9,870 | 3,317 | ||||||
| Other | 269,876 | 239,941 | ||||||
| Total other long-term assets | 690,388 | 680,909 | ||||||
| Total assets | $ | 5,338,748 | $ | 5,317,750 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| (Dollars in thousands) AT DECEMBER 31 | 2002 | 2001 | ||||||
| Capitalization: | ||||||||
| (See Consolidated Statements of Capitalization): | ||||||||
| Common equity | $ | 1,426,121 | $ | 1,267,654 | ||||
| Preferred stock not subject to mandatory redemption | 60,000 | 60,000 | ||||||
| Preferred stock subject to mandatory redemption | 43,162 | 50,662 | ||||||
| Corporation obligated, mandatorily redeemable preferred | ||||||||
| securities of subsidiary trust holding solely junior | ||||||||
| subordinated debentures of the corporation | 300,000 | 300,000 | ||||||
| Long-term debt | 2,021,832 | 2,053,815 | ||||||
| Total capitalization | 3,851,115 | 3,732,131 | ||||||
| Current liabilities: | ||||||||
| Accounts payable | 193,602 | 154,600 | ||||||
| Short-term debt | 30,340 | 338,168 | ||||||
| Current maturities of long-term debt | 72,000 | 117,000 | ||||||
| Purchased gas liability | 83,811 | -- | ||||||
| Accrued expenses: | ||||||||
| Taxes | 64,433 | 70,210 | ||||||
| Salaries and wages | 11,441 | 14,746 | ||||||
| Interest | 37,942 | 42,505 | ||||||
| Current portion of unrealized loss on derivative instruments | 2,410 | 35,145 | ||||||
| Other | 25,456 | 25,178 | ||||||
| Total current liabilities | 521,435 | 797,552 | ||||||
| Long-term liabilities: | ||||||||
| Deferred income taxes | 715,579 | 601,001 | ||||||
| Unrealized loss on derivative instruments | -- | 75 | ||||||
| Other deferred credits | 250,619 | 186,991 | ||||||
| Total long-term liabilities | 966,198 | 788,067 | ||||||
| Commitments and contingencies | -- | -- | ||||||
| Total capitalization and liabilities | $ | 5,338,748 | $ | 5,317,750 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| (Dollars in thousands) AT DECEMBER 31 | 2002 | 2001 | ||||||
| Common equity: | ||||||||
| Common stock ($10 stated value) - 15,000,000 shares | ||||||||
| authorized, 85,903,791 shares outstanding | $ | 859,038 | $ | 859,038 | ||||
| Additional paid-in capital | 498,335 | 382,592 | ||||||
| Earnings reinvested in the business | 66,971 | 55,345 | ||||||
| Accumulated other comprehensive income (loss) - net | 1,777 | (29,321 | ) | |||||
| Total common equity | 1,426,121 | 1,267,654 | ||||||
| Preferred stock not subject to mandatory | ||||||||
| redemption - cumulative - $25 par value:* | ||||||||
| 7.45% series II - 2,400,000 shares authorized and outstanding | 60,000 | 60,000 | ||||||
| Total preferred stock not subject to mandatory redemption | 60,000 | 60,000 | ||||||
| Preferred stock subject to mandatory redemption - cumulative | ||||||||
| $100 par value:* | ||||||||
| 4.84% series - 150,000 shares authorized, | ||||||||
| 14,808 shares outstanding | 1,481 | 1,481 | ||||||
| 4.70% series - 150,000 shares authorized, | ||||||||
| 4,311 shares outstanding | 431 | 431 | ||||||
| 7.75% series - 750,000 shares authorized, 412,500 and 487,500 | ||||||||
| shares outstanding | 41,250 | 48,750 | ||||||
| Total preferred stock subject to mandatory redemption | 43,162 | 50,662 | ||||||
| Corporation obligated, mandatorily redeemable preferred | ||||||||
| securities of subsidiary trust holding solely junior | ||||||||
| subordinated debentures of the corporation | 300,000 | 300,000 | ||||||
| Long-term debt: | ||||||||
| First mortgage bonds and senior notes | 1,932,000 | 2,009,000 | ||||||
| Pollution control revenue bonds: | ||||||||
| Revenue refunding 1991 series, due 2021 | 50,900 | 50,900 | ||||||
| Revenue refunding 1992 series, due 2022 | 87,500 | 87,500 | ||||||
| Revenue refunding 1993 series, due 2020 | 23,460 | 23,460 | ||||||
| Unamortized discount - net of premium | (28 | ) | (45 | ) | ||||
| Long-term debt due within one year | (72,000 | ) | (117,000 | ) | ||||
| Total long-term debt excluding current maturities | 2,021,832 | 2,053,815 | ||||||
| Total capitalization | $ | 3,851,115 | $ | 3,732,131 | ||||
*13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock.
The accompanying notes are an integral part of the consolidated financial statements.
| Puget |
| COMMON |
| Common Stock | Additional | Accumulated Other | ||||||||||||||||||
| (Dollars in thousands) YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 | Shares | Amount | Paid-in Capital | Retained Earnings | Comprehensive Income | Total Amount | ||||||||||||||
| Balance at December 31, 1999 | 84,922,405 | $ | 849,224 | $ | 454,982 | $ | 66,019 | $ | 8,848 | $ | 1,379,073 | |||||||||
| Net income | -- | -- | -- | 193,831 | -- | 193,831 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (9,067 | ) | -- | (9,067 | ) | ||||||||||||
| Loss on preferred stock redemptions | -- | -- | 1,181 | (1,181 | ) | -- | -- | |||||||||||||
| Common stock dividend declared | -- | -- | -- | (156,929 | ) | -- | (156,929 | ) | ||||||||||||
| Common stock issued on dividend reinvestment | 981,549 | 9,816 | 13,295 | -- | -- | 23,111 | ||||||||||||||
| plan | ||||||||||||||||||||
| Other | (163 | ) | (2 | ) | 721 | -- | -- | 719 | ||||||||||||
| Other comprehensive income | -- | -- | -- | -- | (4,098 | ) | (4,098 | ) | ||||||||||||
| Balance at December 31, 2000 | 85,903,791 | $ | 859,038 | $ | 470,179 | $ | 92,673 | $ | 4,750 | $ | 1,426,640 | |||||||||
| Net income | -- | -- | -- | 104,381 | -- | 104,381 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (8,485 | ) | -- | (8,485 | ) | ||||||||||||
| Common stock dividend declared | -- | -- | -- | (133,224 | ) | -- | (133,224 | ) | ||||||||||||
| Return of Capital to Puget Energy | -- | -- | (86,556 | ) | -- | -- | (86,556 | ) | ||||||||||||
| Other | -- | -- | (1,031 | ) | -- | -- | (1,031 | ) | ||||||||||||
| Other comprehensive income | -- | -- | -- | -- | (34,071 | ) | (34,071 | ) | ||||||||||||
| 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 | |||||||||
| (Dollars in thousands) FOR YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | ||||||||
| Net income | $ | 108,948 | $ | 104,381 | $ | 193,831 | |||||
| Other comprehensive income, net of tax: | |||||||||||
| Unrealized holding losses on marketable securities during the period | (1,359 | ) | (1,823 | ) | (938 | ) | |||||
| Reclassification adjustment for realized gains on marketable | -- | (5 | ) | (3,160 | ) | ||||||
| securities included in net income | |||||||||||
| Minimum pension liability adjustment | (2,098 | ) | (5,148 | ) | -- | ||||||
| Transition adjustment for unrealized gain on derivative | -- | 286,928 | -- | ||||||||
| instruments at January 1, 2001 | |||||||||||
| Unrealized gains (losses) on derivative instruments during the | 2,853 | (131,420 | ) | -- | |||||||
| period | |||||||||||
| Reversal of unrealized (gains) losses on derivative instruments | 31,702 | (182,603 | ) | -- | |||||||
| settled during the period | |||||||||||
| Other comprehensive income (loss) | 31,098 | (34,071 | ) | (4,098 | ) | ||||||
| Comprehensive income | $ | 140,046 | $ | 70,310 | $ | 189,733 | |||||
| Common Stock | Additional | Accumulated Other | ||||||||||||||||||
| (DOLLARS IN THOUSANDS) YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 | Shares | Amount | Paid-in Capital | Retained Earnings | Comprehensive Income | Total Amount | ||||||||||||||
| Balance at December 31, 2000 | 85,903,791 | $ | 859,038 | $ | 470,179 | $ | 92,673 | $ | 4,750 | $ | 1,426,640 | |||||||||
| Net income | -- | -- | -- | 106,839 | -- | 106,839 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (8,485 | ) | -- | (8,485 | ) | ||||||||||||
| Common stock dividend declared | -- | -- | -- | (158,798 | ) | -- | (158,798 | ) | ||||||||||||
| Reclassification of par value in connection | -- | |||||||||||||||||||
| with the formation of Puget Energy | -- | (858,179 | ) | 858,179 | -- | -- | -- | |||||||||||||
| Common stock issued on dividend reinvestment plan | 1,119,568 | 11 | 25,551 | -- | -- | 25,562 | ||||||||||||||
| Other | (149 | ) | -- | 5,037 | -- | -- | 5,037 | |||||||||||||
| Other comprehensive income | -- | -- | -- | -- | (34,071 | ) | (34,071 | ) | ||||||||||||
| Balance at December 31, 2001 | 87,023,210 | $ | 870 | $ | 1,358,946 | $ | 32,229 | $ | (29,321 | ) | $ | 1,362,724 | ||||||||
| Net income | -- | -- | -- | 117,883 | -- | 117,883 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (7,904 | ) | -- | (7,904 | ) | ||||||||||||
| 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 | ) | (125 | ) | -- | (6,545 | ) | ||||||||||
| 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 | -- | -- | -- | 121,348 | -- | 121,348 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (5,562 | ) | -- | (5,562 | ) | ||||||||||||
| 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 | ) | -- | -- | (8 | ) | |||||||||||
| Other comprehensive income | -- | -- | -- | -- | (9,903 | ) | (9,903 | ) | ||||||||||||
| Balance at December 31, 2003 | 99,074,070 | $ | 991 | $ | 1,603,901 | $ | 58,217 | $ | (8,063 | ) | $ | 1,655,046 | ||||||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Energy Consolidated Statements of |
| COMPREHENSIVE INCOME |
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||
| Net income | $ | 121,348 | $ | 117,883 | $ | 106,839 | |||||
| Other comprehensive income, net of tax: | |||||||||||
| Unrealized holding losses on marketable securities during the period | (45 | ) | (1,359 | ) | 1,823 | ) | |||||
| Reclassification adjustment for realized gains on marketable securiti | |||||||||||
| included in net income | (1,518 | ) | -- | (5 | ) | ||||||
| Foreign currency translation adjustment | 80 | 63 | -- | ||||||||
| Minimum pension liability adjustment | (1,122 | ) | (2,098 | ) | 5,148 | ) | |||||
| Transition adjustment for unrealized gain on derivative instruments a | |||||||||||
| of January 1, 2001 | -- | -- | 286,928 | ||||||||
| Unrealized gains (losses) on derivative instruments during the period | 8,576 | 2,853 | (131,420 | ) | |||||||
| Reversal of unrealized (gains) losses on derivative instruments settl | |||||||||||
| during the period | 181 | 31,702 | (182,603 | ) | |||||||
| Deferral related to PCA | (16,055 | ) | -- | -- | |||||||
| Other comprehensive income (loss) | (9,903 | ) | 31,161 | (34,071 | ) | ||||||
| Comprehensive income | $ | 111,445 | $ | 149,044 | $ | 72,768 | |||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Energy Consolidated Statements of |
| CASH FLOWS |
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||
| Operating activities: | |||||||||||
| Net income | $ | 121,348 | $ | 117,883 | $ | 106,839 | |||||
| Adjustments to reconcile net income to net cash | |||||||||||
| provided by operating activities: | |||||||||||
| Depreciation and amortization | 236,866 | 228,743 | 217,540 | ||||||||
| Deferred income taxes and tax credits - net | 57,470 | 151,318 | 11,464 | ||||||||
| Gain from sale of securities | (2,889 | ) | -- | -- | |||||||
| Net unrealized (gains) losses on derivative instrument | 106 | (11,612 | ) | 3,567 | |||||||
| Other (including conservation amortization) | (7,412 | ) | 330 | (4,465 | ) | ||||||
| Cash collateral received from (returned to) energy supplier | (21,425 | ) | 21,425 | -- | |||||||
| Pension plan funding | (26,521 | ) | -- | -- | |||||||
| Change in certain current assets and liabilities | |||||||||||
| Accounts receivable and unbilled revenue | 37,769 | 46,860 | 147,575 | ||||||||
| Materials and supplies | (14,727 | ) | 22,088 | 10,611 | |||||||
| Prepayments and other | (738 | ) | 141 | 936 | |||||||
| Purchased gas receivable (liability) | (71,826 | ) | 121,039 | 58,822 | |||||||
| Accounts payable | 6,464 | 34,351 | (254,944 | ) | |||||||
| Taxes payable | 13,405 | (18,260 | ) | (33,288 | ) | ||||||
| Accrued expenses and other | (4,939 | ) | (4,603 | ) | 33,631 | ||||||
| Net cash provided by operating activities | 322,951 | 709,703 | 298,288 | ||||||||
| Investing activities: | |||||||||||
| Construction and capital expenditures - excluding equity AFU | (285,510 | ) | (235,786 | ) | (252,628 | ) | |||||
| Energy conservation expenditures | (18,579 | ) | (11,356 | ) | (15,591 | ) | |||||
| Restricted cash | 20,106 | (18,871 | ) | -- | |||||||
| Proceeds from sale of securities | 3,161 | -- | -- | ||||||||
| Investments by InfrastruX | (10,659 | ) | (41,602 | ) | (75,591 | ) | |||||
| Repayment from Schlumberger | -- | -- | 51,948 | ||||||||
| Other | 2,151 | (15,761 | ) | (16,446 | ) | ||||||
| Net cash used by investing activities | (289,330 | ) | (323,376 | ) | (308,308 | ) | |||||
| Financing activities: | |||||||||||
| Increase (decrease) in short-term debt - net | (33,402 | ) | (301,281 | ) | (32,406 | ) | |||||
| Dividends paid | (86,671 | ) | (97,321 | ) | (141,709 | ) | |||||
| Issuance of common stock | 106,659 | 120,214 | -- | ||||||||
| Issuance of trust preferred stock | -- | -- | 200,000 | ||||||||
| Issuance of bonds and long-term debt | 319,497 | 107,518 | 70,250 | ||||||||
| Redemption of preferred stock | (60,000 | ) | -- | -- | |||||||
| Redemption of mandatorily redeemable preferred stock | (41,273 | ) | (7,500 | ) | (7,500 | ) | |||||
| Redemption of trust preferred stock | (19,750 | ) | -- | -- | |||||||
| Redemption of bonds and notes | (357,510 | ) | (119,281 | ) | (19,000 | ) | |||||
| Other | (10,359 | ) | (4,363 | ) | (3,642 | ) | |||||
| Net cash provided (used) by financing activities | (182,809 | ) | (302,014 | ) | 65,993 | ||||||
| Increase (decrease) in cash from net income | (149,188 | ) | 84,313 | 55,973 | |||||||
| Cash at beginning of year | 176,669 | 92,356 | 36,383 | ||||||||
| Cash at end of year | $ | 27,481 | $ | 176,669 | $ | 92,356 | |||||
| Supplemental Cash Flow Information: | |||||||||||
| Cash payments for: | |||||||||||
| Interest (net of capitalized interest) | $ | 192,845 | $ | 200,392 | $ | 191,004 | |||||
| Income taxes (net of refunds) | (2,777 | ) | (81,652 | ) | 87,470 | ||||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Sound Energy Consolidated Statements of |
| INCOME |
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||
| Operating revenues: | |||||||||||
| Electric | $ | 1,509,463 | $ | 1,365,885 | $ | 1,865,227 | |||||
| Gas | 634,230 | 697,155 | 815,071 | ||||||||
| Other | 6,043 | 9,753 | 32,476 | ||||||||
| Total operating revenues | 2,149,736 | 2,072,793 | 2,712,774 | ||||||||
| Operating expenses: | |||||||||||
| Energy costs: | |||||||||||
| Purchased electricity | 823,189 | 645,371 | 918,676 | ||||||||
| Residential exchange | (173,840 | ) | (149,970 | ) | (75,864 | ) | |||||
| Purchased gas | 327,132 | 405,016 | 537,431 | ||||||||
| Electric generation fuel | 64,999 | 113,538 | 281,405 | ||||||||
| Unrealized (gain) loss on derivative instruments | 106 | (11,612 | ) | (11,182 | ) | ||||||
| Utility operations and maintenance | 289,702 | 286,220 | 265,789 | ||||||||
| Other operations and maintenance | 1,203 | 1,602 | 8,546 | ||||||||
| Depreciation and amortization | 220,087 | 215,317 | 208,720 | ||||||||
| Conservation amortization | 33,458 | 17,501 | 6,493 | ||||||||
| Taxes other than income taxes | 194,857 | 202,381 | 207,365 | ||||||||
| Income taxes | 70,939 | 52,836 | 76,915 | ||||||||
| Total operating expenses | 1,851,832 | 1,778,200 | 2,424,294 | ||||||||
| Operating income | 297,904 | 294,593 | 288,480 | ||||||||
| Other income | 1,587 | 5,215 | 17,053 | ||||||||
| Income before interest charges | 299,491 | 299,808 | 305,533 | ||||||||
| Interest charges: | |||||||||||
| AFUDC | (3,343 | ) | (1,969 | ) | (4,446 | ) | |||||
| Interest expense | 181,707 | 192,829 | 190,849 | ||||||||
| Mandatorily redeemable securities interest expense | 1,072 | -- | -- | ||||||||
| Total interest charges | 179,436 | 190,860 | 186,403 | ||||||||
| Net income before cumulative effect of accounting change | 120,055 | 108,948 | 119,130 | ||||||||
| Cumulative effect of implementation of accounting change (net of ta | 169 | -- | 14,749 | ||||||||
| Net income | 119,886 | 108,948 | 104,381 | ||||||||
| Less preferred stock dividends accrual | 5,151 | 7,831 | 8,413 | ||||||||
| Income for common stock | $ | 114,735 | $ | 101,117 | $ | 95,968 | |||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Sound Energy Consolidated Balance Sheets |
| ASSETS |
| (DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2003 | 2002 | ||||||
| Utility plant: | ||||||||
| Electric plant | $ | 4,265,908 | $ | 4,229,352 | ||||
| Gas plant | 1,749,102 | 1,645,865 | ||||||
| Common plant | 390,622 | 378,844 | ||||||
| Less: Accumulated depreciation and amortization | (2,325,405 | ) | (2,223,190 | ) | ||||
| Net utility plant | 4,080,227 | 4,030,871 | ||||||
| Other property and investments: | ||||||||
| Investment in Bonneville Exchange Power Contract | 47,609 | 51,136 | ||||||
| Non-utility property, net | 2,150 | 1,699 | ||||||
| Other | 110,521 | 101,922 | ||||||
| Total other property and investments | 160,280 | 154,757 | ||||||
| Current assets: | ||||||||
| Cash | 14,778 | 161,475 | ||||||
| Restricted cash | 2,537 | 18,871 | ||||||
| Accounts receivable, net of allowance for doubtful account | 155,649 | 208,702 | ||||||
| Unbilled revenues | 131,798 | 112,115 | ||||||
| Materials and supplies, at average cost | 77,206 | 63,563 | ||||||
| Current portion of unrealized gain on derivative instrumen | 7,593 | 3,741 | ||||||
| Prepayments and other | 6,285 | 8,907 | ||||||
| Total current assets | 395,846 | 577,374 | ||||||
| Other long-term assets: | ||||||||
| Regulatory asset for deferred income taxes | 142,792 | 167,058 | ||||||
| Regulatory asset for PURPA buyout costs | 227,753 | 243,584 | ||||||
| Unrealized gain on derivative instruments | 8,624 | 9,870 | ||||||
| PCA mechanism | 3,605 | -- | ||||||
| Other | 315,660 | 269,876 | ||||||
| Total other long-term assets | 698,434 | 690,388 | ||||||
| Total assets | $ | 5,334,787 | $ | 5,453,390 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Sound Energy Consolidated |
| CAPITALIZATION AND LIABILITIES |
| (DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2003 | 2002 | ||||||
| Capitalization: | ||||||||
| (See Consolidated Statements of Capitalization): | ||||||||
| Common equity | $ | 1,555,469 | $ | 1,426,121 | ||||
| Preferred stock not subject to mandatory redemption | -- | 60,000 | ||||||
| Total shareholders' equity | 1,555,469 | 1,486,121 | ||||||
| Redeemable securities and long-term debt: | ||||||||
| Preferred stock subject to mandatory redemption | 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 securiti | 280,250 | -- | ||||||
| Long-term debt | 1,950,347 | 2,021,832 | ||||||
| Total redeemable securities and long-term debt | 2,232,486 | 2,364,994 | ||||||
| Total capitalization | 3,787,955 | 3,851,115 | ||||||
| Current liabilities: | ||||||||
| Accounts payable | 206,465 | 193,602 | ||||||
| Short-term debt | -- | 30,340 | ||||||
| Current maturities of long-term debt | 102,658 | 72,000 | ||||||
| Purchased gas liability | 11,984 | 83,811 | ||||||
| Accrued expenses: | ||||||||
| Taxes | 82,342 | 64,433 | ||||||
| Salaries and wages | 12,712 | 11,441 | ||||||
| Interest | 32,954 | 37,942 | ||||||
| Current portion of unrealized loss on derivative instruments | 3,636 | 2,410 | ||||||
| Other | 26,514 | 25,456 | ||||||
| Total current liabilities | 479,265 | 521,435 | ||||||
| Long-term liabilities: | ||||||||
| Deferred income taxes | 731,944 | 715,579 | ||||||
| Other deferred credits | 335,623 | 365,261 | ||||||
| Total long-term liabilities | 1,067,567 | 1,080,840 | ||||||
| Commitments and contingencies | -- | -- | ||||||
| Total capitalization and liabilities | $ | 5,334,787 | $ | 5,453,390 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Sound Energy Consolidated Statements of |
| CAPITALIZATION |
| (DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2003 | 2002 | ||||||
| Common equity: | ||||||||
| Common stock ($10 stated value) - 150,000,000 shares | ||||||||
| authorized, 85,903,791 shares outstanding | $ | 859,038 | $ | 859,038 | ||||
| Additional paid-in capital | 604,451 | 498,335 | ||||||
| Earnings reinvested in the business | 100,186 | 66,971 | ||||||
| Accumulated other comprehensive income (loss) - net | (8,206 | ) | 1,777 | |||||
| Total common equity | 1,555,469 | 1,426,121 | ||||||
| Preferred stock not subject to mandatory redemption - cumulative - $25 par value | ||||||||
| 7.45% series II - 2,400,000 shares authorized, 0 and 2,400,000 shares outstandi | ||||||||
| at December 31, 2003 and 2002 | -- | 60,000 | ||||||
| Total preferred stock not subject to mandatory redemption | -- | 60,000 | ||||||
| Preferred stock subject to mandatory redemption - cumulative | ||||||||
| $100 par value:* | ||||||||
| 4.84% series - 150,000 shares authorized, | ||||||||
| 14,583 and 14,808 shares outstanding at December 31, 2003 and 2002 | 1,458 | 1,481 | ||||||
| 4.70% series - 150,000 shares authorized, | ||||||||
| 4,311 shares outstanding at December 31, 2003 and 2002 | 431 | 431 | ||||||
| 7.75% series - 750,000 shares authorized, | ||||||||
| 0 and 412,500 shares outstanding at December 31, 2003 and 2002 | -- | 41,250 | ||||||
| Total preferred stock subject to mandatory redemption | 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 | 280,250 | -- | ||||||
| Long-term debt: | ||||||||
| First mortgage bonds and senior notes | 1,891,158 | 1,932,000 | ||||||
| Pollution control revenue bonds: | ||||||||
| Revenue refunding 1991 series, due 2021 | -- | 50,900 | ||||||
| Revenue refunding 1992 series, due 2022 | -- | 87,500 | ||||||
| Revenue refunding 1993 series, due 2020 | -- | 23,460 | ||||||
| Revenue refunding 2003 series, due 2031 | 161,860 | -- | ||||||
| Unamortized discount - net of premium | (13 | ) | (28 | ) | ||||
| Long-term debt due within one year | (102,658 | ) | (72,000 | ) | ||||
| Total long-term debt excluding current maturities | 1,950,347 | 2,021,832 | ||||||
| Total capitalization | $ | 3,787,955 | $ | 3,851,115 | ||||
*13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value
preferred stock.
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Sound Energy Consolidated Statements of |
| COMMON SHAREHOLDERS’ EQUITY |
| Common Stock | Additional | Accumulated Other | ||||||||||||||||||
| (DOLLARS IN THOUSANDS) YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 | Shares | Amount | Paid-in Capital | Retained Earnings | Comprehensive Income | Total Amount | ||||||||||||||
| Balance at December 31, 2000 | 85,903,791 | $ | 859,038 | $ | 470,179 | $ | 92,673 | $ | 4,750 | $ | 1,426,640 | |||||||||
| Net income | -- | -- | -- | 104,381 | -- | 104,381 | ||||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (8,485 | ) | -- | (8,485 | ) | ||||||||||||
| Common stock dividend declared | -- | -- | -- | (133,224 | ) | -- | (133,224 | ) | ||||||||||||
| Return of capital to Puget Energy | -- | -- | (86,556 | ) | -- | -- | (86,556 | ) | ||||||||||||
| Other | -- | -- | (1,031 | ) | -- | -- | (1,031 | ) | ||||||||||||
| Other comprehensive income | -- | -- | -- | -- | (34,071 | ) | (34,071 | ) | ||||||||||||
| 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 Ener | -- | -- | 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 Ener | -- | -- | 106,124 | -- | -- | 106,124 | ||||||||||||||
| Other | -- | -- | (8 | ) | -- | -- | (8 | ) | ||||||||||||
| Other comprehensive income | -- | -- | -- | -- | (9,983 | ) | (9,983 | ) | ||||||||||||
| Balance at December 31, 2003 | 85,903,791 | $ | 859,038 | $ | 604,451 | $ | 100,186 | $ | (8,206 | ) | $ | 1,555,469 | ||||||||
| Puget Sound Energy Consolidated Statements of |
| COMPREHENSIVE INCOME |
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||
| Net income | $ | 119,886 | $ | 108,948 | $ | 104,381 | |||||
| Other comprehensive income, net of tax: | |||||||||||
| Unrealized holding losses on marketable securities during the period | (45 | ) | (1,359 | ) | (1,823 | ) | |||||
| Reclassification adjustment for realized gains on marketable securiti | |||||||||||
| included in net income | (1,518 | ) | -- | (5 | ) | ||||||
| Minimum pension liability adjustment | (1,122 | ) | (2,098 | ) | (5,148 | ) | |||||
| Transition adjustment for unrealized gain on derivative instruments | |||||||||||
| January 1, 2001 | -- | -- | 286,928 | ||||||||
| Unrealized gains (losses) on derivative instruments during the period | 8,576 | 2,853 | (131,420 | ) | |||||||
| Reversal of unrealized (gains) losses on derivative instruments settl | |||||||||||
| during the period | 181 | 31,702 | (182,603 | ) | |||||||
| Deferral related to PCA | (16,055 | ) | -- | -- | |||||||
| Other comprehensive income (loss) | (9,983 | ) | 31,098 | (34,071 | ) | ||||||
| Comprehensive income | $ | 109,903 | $ | 140,046 | $ | 70,310 | |||||
The accompanying notes are an integral part of the consolidated financial statements.
| Puget Sound Energy Consolidated Statements of |
| CASH FLOWS |
| (Dollars in thousands) FOR YEARS ENDED DECEMBER 31 | 2002 | 2001 | 2000 | |||||||||||||||||||
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||||||||||||
| Operating activities: | ||||||||||||||||||||||
| Net income | $ | 108,948 | $ | 104,381 | $ | 193,831 | $ | 119,886 | $ | 108,948 | $ | 104,381 | ||||||||||
| Adjustments to reconcile net income | ||||||||||||||||||||||
| to net cash provided by operating activities: | ||||||||||||||||||||||
| Depreciation and amortization | 215,317 | 208,720 | 196,513 | 220,087 | 215,317 | 208,720 | ||||||||||||||||
| Deferred federal income taxes and tax credits - net | 140,536 | 7,151 | (7,446 | ) | 49,276 | 140,536 | 7,151 | |||||||||||||||
| Gain from sale of securities | -- | -- | (6,476 | ) | (2,889 | ) | -- | -- | ||||||||||||||
| Net unrealized (gains) losses on derivative instruments | (11,612 | ) | 3,567 | -- | ||||||||||||||||||
| Net unrealized (gains) losses on derivative instrumen | 106 | (11,612 | ) | 3,567 | ||||||||||||||||||
| Other (including conservation amortization) | 18,711 | 2,375 | (7,276 | ) | (6,353 | ) | 18,711 | 2,375 | ||||||||||||||
| Cash collateral received from energy supplier | 21,425 | -- | -- | |||||||||||||||||||
| Cash collateral received from (returned to) energy supplier | (21,425 | ) | 21,425 | -- | ||||||||||||||||||
| Pension plan funding | (26,521 | ) | -- | -- | ||||||||||||||||||
| Change in certain current assets and current liabilities: | ||||||||||||||||||||||
| Accounts receivable and unbilled revenue | 61,539 | 148,393 | (220,568 | ) | 33,370 | 61,539 | 148,393 | |||||||||||||||
| Materials and supplies | 21,755 | 8,460 | (29,760 | ) | (13,643 | ) | 21,755 | 8,460 | ||||||||||||||
| Prepayments and other | (1,501 | ) | 2,507 | (1,742 | ) | 2,622 | (1,501 | ) | 2,507 | |||||||||||||
| Purchased gas receivable/liability | 121,039 | 58,822 | (62,350 | ) | ||||||||||||||||||
| Purchased gas receivable (liability) | (71,826 | ) | 121,039 | 58,822 | ||||||||||||||||||
| Accounts payable | 38,893 | (247,931 | ) | 232,402 | 12,863 | 38,893 | (247,931 | ) | ||||||||||||||
| Taxes payable | (13,646 | ) | (33,785 | ) | 31,308 | 17,910 | (13,646 | ) | (33,785 | ) | ||||||||||||
| Accrued expenses and other | 277 | 21,952 | 1,847 | (4,120 | ) | 277 | 21,952 | |||||||||||||||
| Net cash provided by operating activities | 721,681 | 284,612 | 320,283 | 309,343 | 721,681 | 284,612 | ||||||||||||||||
| Investing activities: | ||||||||||||||||||||||
| Construction expenditures - excluding equity AFUDC | (224,165 | ) | (247,435 | ) | (296,480 | ) | (269,973 | ) | (224,165 | ) | (247,435 | ) | ||||||||||
| Energy conservation expenditures | (11,356 | ) | (15,591 | ) | (6,931 | ) | (18,579 | ) | (11,356 | ) | (15,591 | ) | ||||||||||
| Restricted cash | (18,871 | ) | -- | -- | 20,106 | (18,871 | ) | -- | ||||||||||||||
| Proceeds from sale of investment in Cabot preferred stock | -- | -- | 51,463 | |||||||||||||||||||
| Proceeds from sale of Centralia plant | -- | -- | 37,449 | |||||||||||||||||||
| Proceeds from sale of securities | -- | -- | 6,757 | 3,161 | -- | -- | ||||||||||||||||
| Investments by InfrastruX | -- | -- | (85,506 | ) | ||||||||||||||||||
| Repayment from/(loans to) Schlumberger | -- | 51,948 | (20,874 | ) | ||||||||||||||||||
| Repayment from Schlumberger | -- | -- | 51,948 | |||||||||||||||||||
| Other | (14,472 | ) | (16,446 | ) | (14,138 | ) | 3,671 | (14,472 | ) | (16,446 | ) | |||||||||||
| Net cash used by investing activities | (268,864 | ) | (227,524 | ) | (328,260 | ) | (261,614 | ) | (268,864 | ) | (227,524 | ) | ||||||||||
| Financing activities: | ||||||||||||||||||||||
| Increase (decrease) in short-term debt - net | (307,828 | ) | (38,845 | ) | (226,395 | ) | ||||||||||||||||
| Decrease in short-term debt - net | (30,340 | ) | (307,828 | ) | (38,845 | ) | ||||||||||||||||
| Dividends paid | (97,321 | ) | (141,709 | ) | (142,886 | ) | (86,671 | ) | (97,321 | ) | (141,709 | ) | ||||||||||
| Issuance of bonds | 40,000 | -- | 510,000 | 304,465 | 40,000 | -- | ||||||||||||||||
| Issuance of trust preferred stock | -- | 200,000 | -- | -- | -- | 200,000 | ||||||||||||||||
| Redemption of preferred stock | (7,500 | ) | (7,500 | ) | (7,503 | ) | (60,000 | ) | -- | -- | ||||||||||||
| Redemption of mandatorily redeemable preferred stock | (41,273 | ) | (7,500 | ) | (7,500 | ) | ||||||||||||||||
| Redemption of trust preferred stock | (19,750 | ) | -- | -- | ||||||||||||||||||
| Redemption of bonds and notes | (117,000 | ) | (19,000 | ) | (150,980 | ) | (356,860 | ) | (117,000 | ) | (19,000 | ) | ||||||||||
| Investment from Puget Energy | 115,736 | -- | -- | 106,124 | 115,736 | -- | ||||||||||||||||
| Other | (137 | ) | (3,709 | ) | (3,583 | ) | (10,121 | ) | (137 | ) | (3,709 | ) | ||||||||||
| Net cash used by financing activities | (374,050 | ) | (10,763 | ) | (21,347 | ) | (194,426 | ) | (374,050 | ) | (10,763 | ) | ||||||||||
| Increase (decrease) in cash from net income | 78,767 | 46,325 | (29,324 | ) | (146,697 | ) | 78,767 | 46,325 | ||||||||||||||
| Cash at beginning of year | 82,708 | 36,383 | 65,707 | 161,475 | 82,708 | 36,383 | ||||||||||||||||
| Cash at end of year | $ | 161,475 | $ | 82,708 | $ | 36,383 | $ | 14,778 | $ | 161,475 | $ | 82,708 | ||||||||||
| Supplemental Cash Flow Information: | ||||||||||||||||||||||
| Cash payments for: | ||||||||||||||||||||||
| Interest (net of capitalized interest) | $ | 194,876 | $ | 187,347 | $ | 176,895 | $ | 187,256 | $ | 194,876 | $ | 187,347 | ||||||||||
| Income taxes (net of refunds) | (81,973 | ) | 87,020 | 114,100 | (1,456 | ) | (81,973 | ) | 87,020 | |||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
NOTES
To Consolidated Financial Statements of Puget Energy and Puget Sound Energy
NOTE 1.
Summary of Significant Accounting Policies
BASIS OF PRESENTATION
Puget Energy is an exempt public utility holding company under the Public Utility Holding Company Act of 1935. Puget Energy owns Puget Sound Energy (PSE) and is a majority owner of InfrastruX Group, Inc. (InfrastruX),. PSE is a public utility incorporated in the State of Washington corporation.furnishing electric and gas service in a territory covering 6,000 square miles, primarily in the Puget Sound region. InfrastruX is a non-regulated construction service company incorporated in the State of Washington which provides construction services to the electric and gas utility industries primarily in the south/Texas, north-central and eastern United States.
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 majority 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”.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 yearcurrent-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. The Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q are available at the Securities and Exchange Commission website at www.sec.gov or at Puget Energy’s website at www.pse.com.
UTILITY PLANT
The costs of additions to utility plant, including renewals and betterments, are capitalized at original cost. Costs include indirect costs such as engineering, supervision, certain taxes, and pension and other employee benefits, and an allowance for funds used during construction. Replacements of minor items of property are included in maintenance expense. The original cost of operating property togetheris charged to accumulated depreciation and costs associated with removal cost,of property, less salvage, is charged to accumulated depreciationthe cost of removal regulatory liability when the property is retired and removed from service.
NON-UTILITY PROPERTY, PLANT AND EQUIPMENT
The costs of other property, plant and equipment are stated at 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 ASSETS
The Company evaluates impairment of long-lived assets in accordance with 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 are impaired and how losses, if any, should be recognized. The Company believes that the net cash flows are sufficient to cover the carrying value of theits assets.
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 2003, 2.9% in 2002 and 3.0% in 2001 and 2.9% in 2000;2001; depreciable gas utility plant was 3.5% in 2003, 3.3% in 2002 and 3.5% in 2001 and 3.3% in 2000;2001; and depreciable common utility plant was 4.7% in 2003, 4.3% in 2002 and 3.1% in 2001 and 1.9% in 2000.2001. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets ranging from 3 to 50 years.
CASH
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.
MATERIAL AND SUPPLIES
Material and supplies consists primarily of materials and supplies used in the operation and maintenance of the electric and gas systems, coal, diesel and natural gas held for generation, and 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 AGREEMENTS
The Company accounts for its regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”.Regulation.” SFAS No. 71 requires the Company to defer certain costs that would otherwise be charged to expense, if it is 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;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 applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, the Company capitalizes certain costs in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.
The Company is allowed a return on the net regulatory assets and liabilities of 8.76% for both electric rates beginning July 1, 2002 and gas rates beginning September 1, 2002. The 2001 allowed rate of return was 8.94% for electric rates and 9.15% for gas rates. The net regulatory assets and liabilities at December 31, 20022003 and 2001,2002 included the following:
| (Dollars in millions) | REMAINING AMORTIZATION PERIOD | 2002 | 2001 | |||||||||||||||||||
| (DOLLARS IN MILLIONS) | (DOLLARS IN MILLIONS) | REMAINING AMORTIZATION PERIOD | 2003 | 2002 | ||||||||||||||||||
| PURPA electric energy supply contract buyout costs | 5 to 8 years | $ | 227 | .8 | $ | 243 | .6 | |||||||||||||||
| Deferred income taxes | $ | 167 | .1 | $ | 193 | .0 | 142 | .8 | 167 | .1 | ||||||||||||
| PURPA electric energy supply contract buyout costs | 6 to 9 years | 243 | .6 | 244 | .6 | |||||||||||||||||
| Investment in BEP exchange contract | 14 years | 51 | .1 | 54 | .7 | |||||||||||||||||
| Unamortized energy conservation charges | 1 to 3 years | 8 | .2 | 15 | .2 | |||||||||||||||||
| Investment in Bonneville Exchange Power contract | 13 years | 47 | .6 | 51 | .1 | |||||||||||||||||
| Environmental remediation | * | 41 | .5 | 41 | .6 | |||||||||||||||||
| Deferred AFUDC | 30 years | 30 | .3 | 29 | .9 | |||||||||||||||||
| Tree watch costs | 10 years | 29 | .0 | 26 | .5 | |||||||||||||||||
| Storm damage costs - electric | 4 years | 21 | .9 | 26 | .6 | 4 years | 26 | .0 | 21 | .9 | ||||||||||||
| Purchased gas receivable/(payable) | 1 year | (83 | .8) | 37 | .2 | |||||||||||||||||
| Deferred AFUDC | 30 years | 29 | .9 | 28 | .5 | |||||||||||||||||
| Environmental remediation | 41 | .6 | 14 | .4 | ||||||||||||||||||
| White River relicensing and other costs | * | 20 | .8 | -- | ||||||||||||||||||
| Colstrip common property | 20 years | 14 | .6 | 15 | .3 | |||||||||||||||||
| PCA mechanism | * | 3 | .6 | -- | ||||||||||||||||||
| Cost of removal | ** | (124 | .9) | (114 | .6) | |||||||||||||||||
| Various other regulatory assets | 1 to 21 years | 24 | .4 | 47 | .7 | 1 to 21 years | 23 | .4 | 27 | .8 | ||||||||||||
| Deferred gains on property sales | 3 years | (14 | .4) | (17 | .3) | 3 years | (10 | .1) | (14 | .4) | ||||||||||||
| Purchased gas payable | 1 year | (5 | .4) | (83 | .8) | |||||||||||||||||
| Various other regulatory liabilities | 1 to 17 years | (5 | .9) | (6 | .7) | 1 to 17 years | (5 | .2) | (5 | .9) | ||||||||||||
| Net regulatory assets and liabilities | $ | 483 | .7 | $ | 637 | .9 | $ | 461 | .8 | $ | 406 | .1 | ||||||||||
* Amortization period to be determined.
** 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 meet 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 FASB Statement No. 71".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.
The Company, in prior years, incurredIncluded within the regulatory assets are deferred costs associated with its 5% interestgas supply contracts with Tenaska and Cabot of $216.7 million and $11.0 million, respectively, at December 31, 2003. These regulatory assets were designed to be recovered in future rates. In the power cost only rate case, the Washington Commission staff has identified a now-terminated nuclear generating project (identified hereinportion of these assets as Investment in Bonneville Exchange Power (BEP)). Under termsa possible disallowance for future rate recovery based on an interpretation of a settlement agreement1994 Washington Commission order by the Washington Commission staff. The Company believes the disallowance proposed by the Washington Commission staff is legally and actually deficient. The power cost only rate case order from the Washington Commission is expected in mid-April 2004.
In accordance with guidance provided by the Bonneville Power Administration (BPA), which settled claims ofSecurities and Exchange Commission, the Company relatingreclassified from accumulated depreciation to construction delays associated with that project, the Company is receiving powera regulatory liability $124.9 million and $114.6 million in 2003 and 2002, respectively, for non-legal cost of removal for utility plant. These amounts are collected from the federal power system resources marketed by BPA. The Company’s remaining investment in BEP is included in rate base and amortized on a straight-line basis over the life of the settlement agreement (amortization is included in purchased electricity expense). The Company has regulatory assets of approximately $243.6 million related to the buyout of purchased power and gas sales contracts of two non-utility generation projects. Washington Commission accounting orders have approved payments pursuant to these contracts for deferral and collection in rates over the remaining life of the energy supply contracts.PSE’s customers through depreciation expense.
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 as a non-cash item to other income and interest charges currently. Cash inflow related to AFUDC does not occur until these charges are reflected in rates.
The AFUDC rate allowed by the Washington Commission for gas utility plant additions was 8.76% beginning September 1, 2002 and 9.15% in 2001 and 2000.2001. The allowed AFUDC rate on electric utility plant was 8.76% beginning July 1, 2002 and 8.94% in 2001 and 2000.2001. 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 $1.6 million for 2003, $2.6 million for 2002 and $2.7 million for 2001 and $2.8 million for 2000.2001. The deferred asset is being amortized over the average useful life of the Company'sCompany’s non-project utility plant.
REVENUE RECOGNITION
Operating utility revenues are recorded on the basis of service rendered, which includes estimated unbilled revenue. Non-utility subsidiaries recognize revenue when services are performed, upon the sale of assets or on a percent of completion basis for fixed priced contracts.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Allowance for doubtful accounts is calculated based upon historical write-offs as compared to operating revenues. The Company has also provided for a 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 2003 and 2002 and 2001 was $45.4$45.8 million and $47.0$45.4 million, respectively. PSE’s allowance for doubtful accounts for 2003 and 2002 and 2001 was $43.5$44.0 million and $45.2$43.5 million, respectively.
RESTRICTED CASH
Restricted cash represents cash to be used for specific purposes. Approximately $17.8 million in restricted cash was received from BPA under the amended Residential Purchase and Sale Agreement for residential and small farm customers who receive a credit on their bills for the Residential and Farm Energy Exchange credit tariff. The restricted amount is the excess paid by the BPA over the credit provided to these customers. All funds received will be credited to these customers in the future. Approximately $1.1 million in restricted cash wasrepresents funds held by Puget Western, a PSE subsidiary, for a real estate development project that a city requires to ensure work is completed either by the Company or by the city. Approximately $1.4 million in restricted cash represents funds held for payment of principal and interest for conservation trust debt.
SELF-INSURANCE
The Company currently has no insurance coverage for storm damage and is self-insured for a portion of the risk associated with comprehensive liability, industrial accidentsworkers’ compensation claims and catastrophic property losses.losses other than storm related. With approval of the Washington Commission, PSE is able to defer for collection in future rates certain uninsured storm damage costs associated with major storms.
FEDERAL INCOME TAXES
The Company normalizes, with the approval of the Washington Commission, certain income tax items. Deferred taxes have been determined under 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 11.)
ENERGY CONSERVATION
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 conservation expenditures through a tariff rider mechanism. The rider mechanism allows the Company to defer the conservation expenditures and amortize them to expense as PSE concurrently collects the conservation expenditures in rates over a one-year period. As a result of the rider, there is no effect on earnings per share.
Since 1995, the Company has been authorized by the Washington Commission to defer gas energy conservation expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows the Company to defer conservation expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows the Company to recover an Allowance for Funds Used to Conserve Energy (AFUCE) on any outstanding balance that is not being recovered in rates.
RATE ADJUSTMENT MECHANISMMECHANISMS
The Company has a Power Cost Adjustmentpower cost adjustment (PCA) mechanism that provides for an automatic rate adjustment 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 Company’s cumulative maximum pre-tax earnings exposure due to power cost variations over the four yearfour-year period ending June 30, 2006 is limited to $40 million plus 1% of the excess. All significant variable power supply cost drivers are included in the power cost adjustmentPCA 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 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 once the Company reaches its cap of $40 million.
The differences between the actual cost of the Company’s gas supplies and gas transportation contracts and that currently allowed by the Washington Commission are deferred and recovered or repaid through the purchased gas adjustment (PGA) mechanism.
The graduated scale is as follows:
| Annual Power Cost Variability | Customer’s Share | Company's Share1 | |||
| +/- $20 million | 0 | % | 100 | % | |
| +/- $20 million - $40 million | 50 | % | 50 | % | |
| +/- $40 million - $120 million | 90 | % | 10 | % | |
| +/- $120+ million | 95 | % | 5 | % | |
NATURAL 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 for space heating by its firm customers. Due to the variability in weather and other factors, however, the Company holds contractual rights to gas supplies and transportation and storage capacity in excess of its immediate requirements to serve firm customers on its distribution system for much of the year which, therefore, are 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, from such activities 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 does not reflectnets the sales revenue orand associated cost of sales for these transactions in its income statement.purchased gas.
ENERGY RISK MANAGEMENT
The Company’s energy related businesses are exposed to risks related to changes in commodity prices and volumetric changes in its loads and resources. The Company’s energy risk management function manages the Company’s core electric and gas supply portfolios to achieve three primary objectives:
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The Company enters into physical and financial instruments for the purpose of hedging commodity price risk. Gains or losses on these derivatives are accounted for pursuant to SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 138.138 and SFAS No. 149. (See Note 1715 for further discussion.) The Company has established policies and procedures to manage these risks. A Risk Management Committee separate from the business units that create these risks monitors compliance with policies and procedures. In addition, the Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee.
ACCOUNTING FOR DERIVATIVES
On January 1, 2001, theThe Company adoptedfollows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 138.138 and SFAS No. 133149, which requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. Under SFAS No. 149, any purchases from trading companies are now required to be marked-to-market if the party does not have physical plant to back up the transaction. This adoption did not have a significant effect on the Company in 2003. Certain contracts that would otherwise be considered derivatives are exempt from this SFAS No. 133 if they qualify for a normal purchase and 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 and normal sale exception. However, certain of these contracts are derivatives and, pursuant to SFAS No. 133, are reported at their fair value in 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 when the transaction that they are hedging is recorded as income. The Company designates a derivative instrumentsinstrument as a qualifying cash flow hedge if the change in the fair value of the derivative is highly effective at offsetting the changes in the fair value of 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. Finally, changesChanges 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 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.
| 1 | Over the four-year period July 1, 2002 through June 30, 2006, the Company's share of per-tax cost variation is capped at a cumulative $40 million plus 1% of the excess. |
STOCK-BASED COMPENSATION
The Company has various stockstock-based compensation plans which are described more fully in Note 14. As allowed by SFAS No. 123, “Accountingprior to 2003 were accounted for Stock-Based Compensation”, the Company accounts for the plans according to APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations.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 exercise price of stock options granted was the market value of the stock on the date of grant, so no compensation expense was recorded in the income statement for the options. There was, however, compensation expense relatedCompany will apply SFAS No. 123 accounting prospectively to other stock compensation plans.awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. 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:
| Years Ended December 31; (Dollars in thousands, except per share) | 2002 | 2001 | 2000 | ||||||||
| Income for common stock, as reported | $ | 110,052 | $ | 98,426 | $ | 184,837 | |||||
| Add: Total stock-based employee compensation expense included in | 4,103 | 1,352 | 2,553 | ||||||||
| net income, net of tax | |||||||||||
| Less: Total stock-based employee compensation expense per the | (3,495 | ) | (2,429 | ) | (1,941 | ) | |||||
| fair value method of SFAS 123, net of tax | |||||||||||
| Pro forma income for common stock | $ | 110,660 | $ | 97,349 | $ | 185,449 | |||||
| Earnings per share: | |||||||||||
| ��Basic and diluted as reported | $ | 1.24 | $ | 1.14 | $ | 2.16 | |||||
| Basic pro forma | $ | 1.25 | $ | 1.13 | $ | 2.17 | |||||
| Diluted pro forma | $ | 1.25 | $ | 1.12 | $ | 2.16 | |||||
| (Dollars in thousands, except per share amounts) Years Ended December 31 | 2003 | 2002 | 2001 | ||||||||
| Income for common stock, as reported | $ | 116,197 | $ | 110,052 | $ | 98,426 | |||||
| Add: Total stock-based employee compensation expense included | |||||||||||
| in net income, net of tax | 4,180 | 4,103 | 1,352 | ||||||||
| Less: Total stock-based employee compensation expense per the fair | |||||||||||
| value method of SFAS No. 123, net of tax | (3,314 | ) | (3,495 | ) | (2,429 | ) | |||||
| Pro forma income for common stock | $ | 117,063 | $ | 110,660 | $ | 97,349 | |||||
| Earnings per share: | |||||||||||
| Basic as reported | $ | 1.23 | $ | 1.24 | $ | 1.14 | |||||
| Diluted as reported | $ | 1.22 | $ | 1.24 | $ | 1.14 | |||||
| Basic pro forma | $ | 1.24 | $ | 1.24 | $ | 1.13 | |||||
| Diluted pro forma | $ | 1.23 | $ | 1.25 | $ | 1.12 | |||||
DEBT RELATED COSTS
Debt premium, discountpremiums, discounts and expenses 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.
GOODWILL AND INTANGIBLES (PUGET ENERGY ONLY)
On January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective and as a result Puget Energy ceased amortization of goodwill. During 2001, Puget Energy recorded approximately $2.8 million of goodwill amortization. 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 on a straight-line basis over the expected periods to be benefited. For those acquisitions occurring subsequent to June 30, 2001, there was no amortization of goodwill. For acquisitions made prior to June 30, 2001, goodwill and intangibles were amortized on a straight-line basis over the expected periods to be benefited, up to 30 years through December 31, 2001. The goodwill and intangibles recorded on the balance sheet of Puget Energy are the result of InfrastruX acquiringseveral acquisitions of companies during 2000 through 2002.by InfrastruX.
EARNINGS PER COMMON SHARE (PUGET ENERGY ONLY)
Basic earnings per common share has been computed based on weighted average common shares outstanding of 94,750,000, 88,372,000 and 86,445,000 for 2003, 2002 and 85,411,000 for 2002, 2001, and 2000, respectively. Diluted earnings per common share has been computed based on weighted average common shares outstanding of 95,309,000, 88,777,000 and 86,703,000 for 2003, 2002 and 85,690,000 for 2002, 2001, and 2000 respectively, which includes the dilutive effect of securities related to employee stock-based compensation plans.
ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM
Rainier Receivables, Inc., is 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 have an agreement whereby Rainier Receivables can sell, on a revolving basis, up to $150.0$150 million of those receivables. The current agreement expires in December 2005. Rainier Receivables is obligated to pay fees that approximate the third partythird-party purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. At December 31, 2002, there were2003, Rainier Receivables sold $111 million of receivables compared to no borrowings outstanding under the receivable securitization program.sales at December 31, 2002.
NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, – “Consolidation of Variable Interest Entities” (FIN 46)., which was further revised in December 2003 with FIN 46 clarifies46R, which clarified the application of Accounting Research Bulletin No. 51, – “Consolidated Financial Statements”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. This Interpretation 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 this Interpretation for all interests in variable interest entities created after January 31, 2003 is effective immediately. For variable interest entities created before February 1, 2003, it is effective July 1, 2003. The Company ishas 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 processthird quarter of determining2003. As a result, electricity revenues for 2003 increased $5.7 million, while conservation amortization and interest expense increased by the impactscorresponding amount with no impact on earnings. At December 31, 2003, the balance sheet assets and liabilities increased by $4.2 million. FIN 46R also impacted the treatment of this Interpretation.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 of 2003. This change had no impact on the Company’s results of operations for 2003. The Company is evaluating its purchase power agreements and any other agreements to determine if FIN 46R will have an impact on the financial statements.
On January 1, 2002,In May 2003, the FASB issued SFAS No. 142, “Goodwill150, “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 the 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 December 2003, SFAS No. 132, “Employers’ Disclosures about Pensions and Other Intangible Assets” becamePostretirement Benefits” (SFAS No. 132R), was revised to include various additional disclosure requirements. SFAS No. 132R is effective and as a result, Puget Energy ceased amortization of goodwill. During 2001, Puget Energy recorded approximately $2.8 million of goodwill amortization. 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. Puget Energy then performed its annual impairment review as of October 31, 2002 and determined that its goodwill was not impaired.for fiscal years ending after December 15, 2003. (See Note 12.)
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” 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 will adoptadopted the new rules on asset retirement obligations on January 1, 2003. ApplicationAs a result, the Company recorded a $0.2 million charge to income for the cumulative effect of the new rules is not expected to result in a material increase in net property, plant and equipment or expense.
this accounting change. (See Note 2.)
The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF or Task Force) at its June 2002July 2003 meeting came to a consensus on one of three items included inconcerning EITF Issue 02-3 “AccountingNo. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Contracts InvolvedTrading Purposes’ as Defined in Energy Trading and Risk Management Activities” (EITF 02-3).Issue No. 02-03.” The Task Force has agreedconsensus reached was that all mark-to-marketdetermining whether realized gains and losses on energyphysically settled derivative contracts not held for trading contracts whether realized or unrealized will be shown netpurposes reported in the income statement (costs offset against revenues), irrespectiveon a gross or net basis is a matter of whetherjudgment that depends on the contract is physically settled. The presentation is applicable to financial statements for periods ending after July 15, 2002. The Company performs risk management activities to optimizerelevant facts and circumstances. Based on the value of energy supply and transmission assets and to ensure that physical energy supply is available to meet the customer demand loads. The Company also purchases energy when demand exceeds available supplies in its portfolio; likewiseguidance by EITF No. 03-11, the Company makes sales to other utilities and marketers when surplus energy is available. These transactions are part of the Company’s normal operations to meet retail load. The Company has reclassified all settled transactionsdetermined that meet the definition of optimization (trading transactions that optimize hydro resources, and purchases and sales between trading points) net in the income statement to conform to the new presentation required under EITF 02-3. The Company previously reported these transactions when settled in a gross manner in the income statement in electric operating revenue and purchased electricity expense. Unrealized gains or losses onits non-trading derivative instruments that are required toshould be marked-to-market remain reflected in unrealized (gain) loss on derivative instruments on Puget Energy’s and PSE’s income statement as required by SFAS No. 133. The adoption of EITF 02-3 does not have any impact on the previously reported net income of the Company. The following optimization transactions were recorded in electric operating revenue:and will implement this treatment effective January 1, 2004.
| Years Ended December 31; (Dollars in thousands) | 2002 | 2001 | 2000 | ||||||||
| Optimization sales | $ | 66,992 | $ | 492,447 | $ | 133,361 | |||||
| Optimization purchases | 64,448 | 487,431 | 139,376 | ||||||||
| Net margin on optimization transactions | $ | 2,544 | $ | 5,016 | $ | (6,015 | ) | ||||
NOTE 2.
Utility and Non-Utility Plant
Utility plant at December 31, 2002 and 2001 included the following:
| (Dollars in thousands) At December 31 | 2002 | 2001 | ||||||
| Electric, gas and common utility plant classified by | ||||||||
| prescribed accounts at original cost: | ||||||||
| Distribution plant | $ | 3,911,725 | $ | 3,736,590 | ||||
| Production plant | 1,126,173 | 1,117,099 | ||||||
| Transmission plant | 368,959 | 361,662 | ||||||
| General plant | 365,409 | 376,119 | ||||||
| Construction work in progress | 108,658 | 123,307 | ||||||
| Plant acquisition adjustment | 76,623 | 76,623 | ||||||
| Intangible plant (including capitalized software) | 260,043 | 255,619 | ||||||
| Underground storage | 22,291 | 21,872 | ||||||
| Liquefied natural gas | 644 | -- | ||||||
| Plant held for future use | 8,729 | 8,331 | ||||||
| Other | 4,807 | 4,807 | ||||||
| Less accumulated provision for depreciation | (2,337,832 | ) | (2,194,048 | ) | ||||
| Net utility plant | $ | 3,916,229 | $ | 3,887,981 | ||||
Non-utility plant and intangibles at December 31, 2002 and 2001 included the following:
| (Dollars in thousands) At December 31 | 2002 | 2001 | ||||||
| Non-utility plant | $ | 100,481 | $ | 58,318 | ||||
| Intangibles | 21,933 | 18,004 | ||||||
| Less accumulated depreciation and amortization | (22,907 | ) | (11,894 | ) | ||||
| Net non-utility plant and intangibles | $ | 99,507 | $ | 64,428 | ||||
| UTILITY PLANT (DOLLARS IN THOUSANDS) At December 31 | 2003 | 2002 | ||||||
| Electric, gas and common utility plant classified | ||||||||
| prescribed accounts at original cost: | ||||||||
| Distribution plant | $ | 4,030,570 | $ | 3,911,725 | ||||
| Production plant | 1,144,354 | 1,126,173 | ||||||
| Transmission plant | 379,889 | 368,959 | ||||||
| General plant | 344,781 | 365,409 | ||||||
| Construction work in progress | 121,622 | 108,658 | ||||||
| Plant acquisition adjustment | 76,623 | 76,623 | ||||||
| Intangible plant (including capitalized software | 270,235 | 260,043 | ||||||
| Underground storage | 22,362 | 22,291 | ||||||
| Liquefied natural gas storage | 2,348 | 644 | ||||||
| Plant held for future use | 7,608 | 8,729 | ||||||
| Other | 5,240 | 4,807 | ||||||
| Less accumulated provision for depreciation | (2,325,405 | ) | (2,223,190 | ) | ||||
| Net utility plant | $ | 4,080,227 | $ | 4,030,871 | ||||
| NON-UTILITY PLANT (DOLLARS IN THOUSANDS) At December 31 | 2003 | 2002 | ||||||
| Non-utility plant | $ | 122,926 | $ | 100,481 | ||||
| Intangibles | 23,985 | 21,933 | ||||||
| Less accumulated depreciation and amortizati | (36,272 | ) | (22,907 | ) | ||||
| Net non-utility plant and intangibles | $ | 110,639 | $ | 99,507 | ||||
The non-utility plant is composed primarily of the property, plant and equipment of InfrastruX. The 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 of 2003 for the cumulative effect of the accounting change. In accordance with guidance provided by the Securities and Exchange Commission, the Company reclassified $124.9 million in 2003 and $114.6 million in 2002 for non-legal cost of removal on utility plant from accumulated depreciation to a regulatory liability. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
The Company identified various asset retirement obligations at January 1, 2003, which were included in the cumulative effect of the accounting change. The Company has an obligation (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 renegotiations with the Department of Natural Resources of a now-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.
The following table describes all changes to the Company’s asset retirement obligation liability during 2003:
| (DOLLARS IN THOUSANDS) AT DECEMBER 31, 2003 | Amount | ||||
| Asset retirement obligation at December 31, 2002 | $ | -- | |||
| Liability recognized in transition | 3,592 | ||||
| Liability settled in the period | (261 | ) | |||
| Accretion expense | 90 | ||||
| Asset retirement obligation at December 31, 2003 | $ | 3,421 | |||
The pro forma asset retirement obligation liability balances as if SFAS No. 143 had been adopted on January 1, 2000 (rather than January 1, 2003) are as follows:
| (DOLLARS IN THOUSANDS) | |||
| Pro forma amounts of liability for asset retirement obligation at December 31, 2000 | $3,405 | ||
| Pro forma amounts of liability for asset retirement obligation at December 31, 2001 | 3,497 | ||
| Pro forma amounts of liability for asset retirement obligation at December 31, 2002 | 3,592 | ||
The pro forma income statement effect as if SFAS No. 143 had been adopted on January 1, 2000 (rather than January 1, 2003) is as follows:
| (Dollars in thousands, except per share amounts) | 2003 | 2002 | 2001 | ||||||||
| Income for common stock, as reported | $ | 116,197 | $ | 110,052 | $ | 98,426 | |||||
| Add: SFAS No. 143 transition adjustment, net of tax | 169 | -- | -- | ||||||||
| Less: Pro forma accretion expense, net of tax | -- | (62 | ) | (60 | ) | ||||||
| Pro forma income for common stock | $ | 116,366 | $ | 109,990 | $ | 98,366 | |||||
| Earnings per share: | |||||||||||
| Basic as reported | $ | 1.23 | $ | 1.24 | $ | 1.14 | |||||
| Diluted as reported | $ | 1.22 | $ | 1.24 | $ | 1.14 | |||||
| Basic pro forma | $ | 1.23 | $ | 1.24 | $ | 1.14 | |||||
| Diluted pro forma | $ | 1.22 | $ | 1.24 | $ | 1.13 | |||||
NOTE 3.
Preferred Stock
| PREFERRED STOCK | ||
| | NOT SUBJECT TO MANDATORY REDEMPTION $25 PAR VALUE | SUBJECT TO MANDATORY REDEMPTION $100 PAR VALUE |
| Shares outstanding December 31, 1999 | 2,400,000 | 656,619 |
| Acquired for sinking fund: | ||
| 2000 | -- | (75,000) |
| 2001 | -- | (75,000) |
| 2002 | -- | (75,000) |
| Called for redemption or reacquired and canceled: | ||
| 2000 | -- | -- |
| 2001 | ||
| 2002 | -- | -- |
| Shares outstanding December 31, 2002 | 2,400,000 | 431,619 |
See “Consolidated Statements On November 1, 2003, all the outstanding 2.4 million shares of Capitalization” for details on specific series.
Thethe $25 par value 7.45% Series Preferredpreferred stock not subject to mandatory redemption may bewere redeemed at par on or after November 1, 2003.
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 and 7.75% Series, 37,500 shares. All previous sinking fund requirements have been satisfied. At December 31, 2002, there were 40,689 shares of the 4.70% Series and 24,192 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 There were no other redemptions or reacquired shares of this 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. The 7.75% Series may be redeemed by the Company, subject to certain restrictions, at $102.58 per share plus accrued dividends through February 15, 2003, and at per share amounts which decline annually to a price of $100 after February 15, 2007.
COMPANY-OBLIGATED, 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 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%, 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 Securitiesseries in the Capital Trust I may be redeemed earlier, under certain conditions, at the option of the Company. The Capital Trust II Securities may be redeemed at any time on2002 or after June 30, 2006 at par, under certain conditions, at the option of the Company. Dividends relating to preferred securities are included in interest expense. On February 26, 2003, the Company repurchased 19,750 shares of the 8.231% Trust Securities.2001.
NOTE 4.
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 rightRight 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, subject to adjustments. The Rights expire on December 21, 2010, unless earlier redeemed or exchanged by Puget Energy.
NOTE 5.
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 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 $202.7$235.9 million at December 31, 2002.2003. For the years 2003, 2002 and 2001, the aggregate dividends declared per share were $1.00, $1.21 and $1.84, respectively.
Under the general rate settlement, PSE must rebuild its common equity ratio to at least 39%, with milestones of 34%, 35% and 39% at the end of 2003, 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, 20022003 was 36.1%40.0%.
NOTE 6.
Redeemable Securities
| PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION $100 PAR VALUE | |||||||
| | 4.70% SERIES | 4.84% SERIES | 7.75% SERIES | ||||
| SHARES OUTSTANDING DECEMBER 31, 2000 | 4,311 | 14,808 | 562,500 | ||||
| Acquired for sinking fund | |||||||
| 2001 | -- | -- | (75,000 | ) | |||
| 2002 | �� | -- | -- | (75,000 | ) | ||
| 2003 | -- | -- | (75,000 | ) | |||
| Called for redemption or reacquired and canceled: | |||||||
| 2001 | -- | -- | -- | ||||
| 2002 | -- | -- | -- | ||||
| 2003 | -- | (225 | ) | (337,500 | ) | ||
| Shares outstanding December 31, 2003 | 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 and 7.75% Series, 37,500 shares. 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, 2003, there were 37,689 shares of the 4.70% Series and 21,192 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 TO A SUBSIDIARY 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 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%, 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 the Capital Trust I may be redeemed earlier, under certain conditions, at the option of the Company. The Capital Trust II Securities may be redeemed at any time on or after June 30, 2006 at par, under certain conditions, at the option of the Company. Dividends relating to preferred securities are included in interest expense for all periods presented. On February 26, 2003, the Company repurchased 19,750 shares of the 8.231% Trust Securities.
NOTE 6.7.
Long-Term Debt
FIRST MORTGAGE BONDS AND SENIOR NOTES
AT DECEMBER 31 (Dollars in thousands)(DOLLARS IN THOUSANDS)
| SERIES | DUE | 2002 | 2001 | SERIES | DUE | 2002 | 2001 | DUE | 2003 | 2002 | SERIES | DUE | 2003 | 2002 | |
| 7.07% | 2002 | $ -- | $ 27,000 | 6.51% | 2008 | $ 1,000 | |||||||||
| 7.15% | 2002 | -- | 5,000 | 6.53% | 2008 | 3,500 | |||||||||
| 7.53% | 2002 | -- | 10,000 | 7.61% | 2008 | 25,000 | |||||||||
| 7.625% | 2002 | -- | 25,000 | 6.46% | 2009 | 150,000 | |||||||||
| 7.85% | 2002 | -- | 30,000 | 6.61% | 2009 | 3,000 | |||||||||
| 7.91% | 2002 | -- | 20,000 | 6.62% | 2009 | 5,000 | |||||||||
| 6.20% | 2003 | 3,000 | 7.12% | 2010 | 7,000 | 2003 | $ -- | $ 3,000 | 7.61% | 2008 | $ 25,000 | ||||
| 6.23% | 2003 | 1,500 | 7.96% | 2010 | 225,000 | 2003 | -- | 1,500 | 6.46% | 2009 | 150,000 | ||||
| 6.24% | 2003 | 1,500 | 7.69% | 2011 | 260,000 | 2003 | -- | 1,500 | 6.61% | 2009 | 3,000 | ||||
| 6.30% | 2003 | 20,000 | 8.20% | 2012 | 30,000 | 2003 | -- | 20,000 | 6.62% | 2009 | 5,000 | ||||
| 6.31% | 2003 | 5,000 | 8.59% | 2012 | 5,000 | 2003 | -- | 5,000 | 7.12% | 2010 | 7,000 | ||||
| 6.40% | 2003 | 11,000 | 6.83% | 2013 | 3,000 | 2003 | -- | 11,000 | 7.96% | 2010 | 225,000 | ||||
| 7.02% | 2003 | 30,000 | 6.90% | 2013 | 10,000 | 2003 | -- | 30,000 | 7.69% | 2011 | 260,000 | ||||
| 6.25% | 2004 | 40,000 | -- | 7.35% | 2015 | 10,000 | 2004 | -- | 40,000 | 8.20% | 2012 | -- | 30,000 | ||
| 6.07% | 2004 | 10,000 | 7.36% | 2015 | 2,000 | 2004 | 10,000 | 8.59% | 2012 | -- | 5,000 | ||||
| 6.10% | 2004 | 8,500 | 6.74% | 2018 | 200,000 | 2004 | 8,500 | 6.83% | 2013 | 3,000 | |||||
| 7.70% | 2004 | 50,000 | 9.57% | 2020 | 25,000 | 2004 | 50,000 | 6.90% | 2013 | 10,000 | |||||
| 7.80% | 2004 | 30,000 | 8.25% | 2022 | 25,000 | 2004 | 30,000 | 7.35% | 2015 | 10,000 | |||||
| 6.92% | 2005 | 11,000 | 8.39% | 2022 | 7,000 | 2005 | 11,000 | 7.36% | 2015 | 2,000 | |||||
| 6.93% | 2005 | 20,000 | 8.40% | 2022 | 3,000 | 2005 | 20,000 | 6.74% | 2018 | 200,000 | |||||
| 6.58% | 2006 | 10,000 | 7.19% | 2023 | 3,000 | 2006 | 10,000 | 9.57% | 2020 | 25,000 | |||||
| 8.06% | 2006 | 46,000 | 7.35% | 2024 | 55,000 | 2006 | 46,000 | 8.25% | 2022 | -- | 25,000 | ||||
| 8.14% | 2006 | 25,000 | 7.15% | 2025 | 15,000 | 2006 | 25,000 | 8.39% | 2022 | -- | 7,000 | ||||
| 7.02% | 2007 | 20,000 | 7.20% | 2025 | 2,000 | 2007 | 20,000 | 8.40% | 2022 | -- | 3,000 | ||||
| 7.04% | 2007 | 5,000 | 7.19% | 2023 | -- | 3,000 | |||||||||
| 7.75% | 2007 | 100,000 | 7.02% | 2027 | 300,000 | 2007 | 100,000 | 7.35% | 2024 | 55,000 | |||||
| 7.04% | 2007 | 5,000 | 7.00% | 2029 | 100,000 | ||||||||||
| 8.40% | 2007 | 10,000 | Total | $1,932,000 | $2,009,000 | 2007 | -- | 10,000 | 7.15% | 2025 | 15,000 | ||||
| 3.363% | 2008 | 150,000 | -- | 7.20% | 2025 | 2,000 | |||||||||
| 6.51% | 2008 | 1,000 | 7.02% | 2027 | 300,000 | ||||||||||
| 6.53% | 2008 | 3,500 | 7.00% | 2029 | 100,000 | ||||||||||
| Total | $1,887,000 | $1,932,000 | |||||||||||||
In January 2002,June 2003, the Company issued $40.0$150 million of First Mortgage Bondsin first mortgage bonds, which are due June 2008. In January 2004. In February 2002,2004, the Company 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 any combination of common stock of Puget Energy and principal amount of Senior Notes secured by a pledge of First Mortgage Bonds, Unsecured Debentures or Trust Preferred Securities. In February 2003, thefirst mortgage bonds. The Company notified investors of its intent to call threecalled and paid off 15 series of first mortgage bonds in 2003, totaling $20$195 million. The Company will repayrepaid the bonds using cash on hand.
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, 2002,2003, the earnings available for interest were 2.42.9 times the annual interest charges.
POLLUTION CONTROL BONDS
The Company has outstanding threetwo series of Pollution Control Bonds. On February 19, 2003, the Board of Directors approved the refinancing of all Pollution Control Bonds series. The new series 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 and 4.
Each series of bonds is collateralized by a pledge of PSE’s First Mortgage Bonds,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 Bondsfirst mortgage bonds so long as payment is made on the Pollution Control Bonds.
| AT DECEMBER 31 (DOLLARS IN THOUSANDS) SERIES | DUE | 2003 | 2002 | ||||||||||||
| SERIES | DUE | 2002 | 2001 | ||||||||||||
| 2003A Series - 5.00% | 2031 | $138,460 | $ -- | ||||||||||||
| 2003B Series - 5.10% | 2031 | 23,400 | -- | ||||||||||||
| 1993 Series - 5.875% | 2020 | $ | 23,460 | $ | 23,460 | 2020 | -- | 23,460 | |||||||
| 1991 Series - 7.05% | 2021 | 27,500 | 27,500 | 2021 | -- | 27,500 | |||||||||
| 1991 Series - 7.25% | 2021 | 23,400 | 23,400 | 2021 | -- | 23,400 | |||||||||
| 1992 Series - 6.80% | 2022 | 87,500 | 87,500 | 2022 | -- | 87,500 | |||||||||
| Total | $ | 161,860 | $ | 161,860 | $161,860 | $161,860 | |||||||||
On February 19,CONSERVATION TRUST FINANCINGS
In July 2003, FIN 46 required PSE to consolidate the Board of Directors approved the refinancing of all Pollution Control Bonds series. It is anticipated that the refinancing1995 Conservation Trust Transaction. The balance of the Pollution Control Bonds6.45% bonds was $4.2 million at December 31, 2003, and they will be completedmature in March or April 2003.
2004.
LONG-TERM REVOLVING CREDIT FACILITY (PUGET ENERGY ONLY)
Puget Energy has a $15.0 million revolving credit facility available through a local bank. At December 31, 2003, there was $5.0 million outstanding at a weighted average interest rate of 2.86%, leaving $10.0 million available under the facility. Puget Energy is the guarantor of this credit facility.
InfrastruX and its subsidiaries have signed credit agreements with several banks for up to $179.8$184.7 million, which expire in 20032004 and 2004.2005. Under the InfrastruX credit agreement, Puget Energy is the guarantor of $150.0 million of the line of credit. InfrastruX has borrowed $144.0$155.6 million at a weighted average interest rate of 3.27%2.61%, leaving a balance of $35.8$29.1 million available under the lines of credit at December 31, 2002.
2003. InfrastruX also has $19.3 million in equipment financing agreements with various vendors. These agreements mature at various dates from 2004 to 2009 and carry interest rates from 0% to 9.65%.
LONG-TERM DEBT MATURITIES
The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:
| (Dollars in thousands) | 2003 | 2004 | 2005 | 2006 | 2007 | Thereafter | |||||||
| Maturities of: | |||||||||||||
| Long-term debt | $73,206 | $265,848 | $31,525 | $81,000 | $135,000 | $1,636,360 |
| PUGET ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 | Thereafter |
| Maturities Of: Long-term debt | $246,829 | $37,526 | $90,771 | $127,404 | $179,896 | $1,533,892 |
| (Dollars in thousands) | 2003 | 2004 | 2005 | 2006 | 2007 | Thereafter | |||||||
| Maturities of: | |||||||||||||
| Long-term debt | $72,000 | $138,473 | $31,000 | $81,000 | $135,000 | $1,636,360 |
| PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 | Thereafter |
| Maturities Of: Long-term debt | $102,658 | $31,000 | $81,000 | $125,000 | $179,500 | $1,533,847 |
NOTE 7.8.
Liquidity Facilities and Other Financing Arrangements
At December 31, 2002,2003, PSE had short-term borrowing arrangements that included a $250 million unsecured 364-day line of credit with various banks and a $150 million 3-yearthree-year receivables securitization program. These agreements replaced a $375 million line of credit, which would have expired on February 13, 2003. The new agreements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The line of credit allows the Company to make floating rate advances at prime plus a spread and Eurodollar advances at LIBOR plus a spread. The agreement contains “credit sensitive” pricing with various spreads associated with various credit rating levels. The agreement also allows for drawing letters of credit up to $50 million.
PSE has 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 sells all of its utility customer accounts receivable and unbilled utility revenues to Rainier Receivables. In addition, 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 amount of PSE’s receivables which fluctuate with the seasonality of energy sales to customers.
The receivables securitization program allowsfacility is the Companyfunctional equivalent of a secured revolving line of credit. In the event Rainier Receivables elects to draw against eligiblesell receivables atunder the Receivables Purchase Agreement, Rainier Receivables is required to pay the purchasers fees that are comparable to interest rates on a rate equalrevolving 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 that of high grade commercial paper.sell additional receivables to the purchasers.
The receivables securitization facility has a three-year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. During the year ended December 31, 2003, Rainier Receivables had sold $348.0 million in accounts receivable. At December 31, 2003, Rainier Receivables had sold $111.0 million in accounts receivable and the maximum remaining receivables available for sale was $39.0 million.
In addition, PSE has agreements with severalcertain banks to borrow on an uncommitted, as available, basis at money-marketmoney 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, 20022003 and 2001.2002.
| (Dollars in thousands) At December 31 | 2002 | 2001 | |||
| Short-term borrowings outstanding: | |||||
| Commercial paper notes | $ 30,340 | $123,168 | |||
| Bank line of credit borrowings | -- | 215,000 | |||
| Puget Energy bank line of credit borrowings | 16,955 | 10,409 | |||
| Weighted average interest rate | 3.21% | 2.72% | |||
| InfrastruX revolving credit facility1 | 179,750 | 170,500 | |||
| PSE credit availability2 | 250,000 | 375,000 | |||
| PSE receivable securitization program | 150,000 | -- | |||
| (DOLLARS IN THOUSANDS) | ||
| At December 31 | 2003 | 2002 |
| Short-term borrowings outstanding: | ||
| Commercial paper notes | $ -- | $ 30,340 |
| InfrastruX bank line of credit borrowings | 13,893 | 16,955 |
| Weighted average interest rate | 2.59% | 2.81% |
| Financing arrangements: | ||
| Puget Energy line of credit1 | $ 15,000 | $ -- |
| InfrastruX revolving credit facilities2 | 184,725 | 179,750 |
| PSE line of credit 3 | 250,000 | 250,000 |
| PSE receivables securitization program4 | 150,000 | 150,000 |
The Company has, on occasion, entered into interest rate swap agreements to reduce the impact of changes in interest rates on portions of its floating-rate debt. There were no such agreements outstanding at December 31, 2003 and 2002.
1 Includes $5.0 million outstanding at December 31, 2003, effectively reducing the available borrowing capacity to $10.0 million.
2The 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 2003 and 2002, InfrastruX had $155.6 million and 2001.$144.0 million outstanding under the credit facilities, effectively reducing available borrowing capacity to $29.1 million and $35.8 million, respectively.
3Provides liquidity support for PSE's outstanding commercial paper in the amount of $0.5 million and $30.3 million for 2003 and 2002, respectively, effectively reducing the available borrowing capacity under these credit lines to $249.5 million and $219.7 million, respectively.
4Provides liquidity support for PSE's outstanding letters of credit and commercial paper. At December 31, 2003, PSE had sold $111.0 million in receivables, effectively reducing the available borrowing capacity to $39.0 million. There were no receivables sold as of December 31, 2002.
NOTE 8.9.
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, 20022003 and 2001: 2002:
| 2002 | 2002 | 2001 | 2001 | |
| CARRYING | FAIR | CARRYING | FAIR | |
| (Dollars in millions) | AMOUNT | VALUE | AMOUNT | VALUE |
| Financial assets: | |||||||||
| Cash | $ 176 | .7 | $ 176 | .7 | $ 92 | .3 | $ 92 | .3 | |
| Restricted cash | 18 | .9 | 18 | .9 | -- | -- | |||
| Equity securities3 | 10 | .4 | 10 | .4 | 12 | .8 | 12 | .8 | |
| Notes receivable and other | 41 | .5 | 41 | .5 | 40 | .0 | 40 | .0 | |
| Energy derivatives | 13 | .6 | 13 | .6 | 6 | .6 | 6 | .6 | |
| Financial liabilities: | |||||||||
| Short-term debt | 47 | .3 | 47 | .3 | 348 | .6 | 348 | .6 | |
| Preferred stock subject to mandatory redemption | 43 | .2 | 42 | .4 | 50 | .7 | 49 | .3 | |
| Corporation obligated, mandatorily redeemable | 300 | .0 | 303 | .1 | 300 | .0 | 301 | .8 | |
| preferred securities of subsidiary trust holding | |||||||||
| solely junior subordinated debentures of the | |||||||||
| corporation | |||||||||
| Long-term debt4 | 2,223 | .0 | 2,381 | .8 | 2,246 | .7 | 2,131 | .2 | |
| Energy derivatives | 2 | .4 | 2 | .4 | 35 | .2 | 35 | .2 | |
| 2003 | 2002 | |||||||||||||
| (DOLLARS IN MILLIONS) | CARRYING AMOUNT | FAIR VALUE | CARRYING AMOUNT | FAIR VALUE | ||||||||||
| Financial assets: | ||||||||||||||
| Cash | $ | 27 | .5 | $ | 27 | .5 | $ | 176 | .7 | $ | 176 | .7 | ||
| Restricted cash | 2 | .5 | 2 | .5 | 18 | .9 | 18 | .9 | ||||||
| Equity securities1 | 3 | .6 | 3 | .6 | 10 | .4 | 10 | .4 | ||||||
| Notes receivable and other | 44 | .9 | 44 | .9 | 41 | .5 | 41 | .5 | ||||||
| Energy derivatives | 16 | .2 | 16 | .2 | 13 | .6 | 13 | .6 | ||||||
| Financial liabilities: | ||||||||||||||
| Short-term debt | $ | 13 | .9 | $ | 13 | .9 | $ | 47 | .3 | $ | 47 | .3 | ||
| Preferred stock subject to mandatory redemption | 1 | .9 | 1 | .9 | 43 | .2 | 42 | .4 | ||||||
| Corporation obligated, mandatorily redeemable | ||||||||||||||
| preferred securities of subsidiary trust holdin | ||||||||||||||
| solely junior subordinated debentures of the | ||||||||||||||
| corporation | -- | -- | 300 | .0 | 303 | .1 | ||||||||
| Junior subordinated debentures of the corporatio | ||||||||||||||
| payable to a subsidiary trust holding mandatori | ||||||||||||||
| redeemable preferred securities | 280 | .3 | 304 | .6 | -- | -- | ||||||||
| Long-term debt2 | 2,216 | .3 | 2,408 | .7 | 2,237 | .1 | 2,395 | .9 | ||||||
| Energy derivatives | 3 | .6 | 3 | .6 | 2 | .4 | 2 | .4 | ||||||
The fair value of equity securities is based on valuations provided by the investment 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 and corporation obligated, mandatorily redeemable preferred securities of a subsidiary trust holding solely junior subordinated debentures of the corporation is estimated based on dealer quotes.
|
|
|
|
The carrying valuevalues 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.
1 The 2002 carrying amount includes an adjustment of $2.4 million, to report the available-for-sale securities at market value. This amount (or unrealized gain) was included as a component of other comprehensive income net of deferred taxes of $0.8 million for 2002.
2 PSE's carrying and fair value of long-term debt for 2003 was $2,053.0 million and $2,250.4 million, respectively.
NOTE 10.
Leases
All of PSE’s leases are operating leases. Certain leases contain purchase options and renewal and escalation provisions. Operating and capital lease payments net of sublease receipts were:
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | ||
| At December 31 | Operating | Capital | Operating | |
| 2003 | $26,842 | $2,696 | $19,301 | |
| 2002 | 26,368 | 2,486 | 20,176 | |
| 2001 | 25,373 | 1,966 | 20,135 | |
Payments received for the subleases of properties were approximately $1.4 million, $2.6 million and $2.5 million for the years ended December 31, 2003, 2002 and 2001, 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 | |
| 2004 | $17,967 | $1,611 | $10,651 | |
| 2005 | 13,858 | 1,522 | 8,939 | |
| 2006 | 11,278 | 1,391 | 8,763 | |
| 2007 | 9,660 | 913 | 8,696 | |
| 2008 | 9,355 | 1,051 | 8,132 | |
| Thereafter | 10,346 | -- | 10,346 | |
| Total minimum lease payments | $72,464 | $6,488 | $55,527 | |
Future minimum sublease receipts for non-cancelable subleases are $0.1 million for 2004.
NOTE 11.
Income Taxes
The details of income taxes are as follows:
| 2003 | 2002 | 2001 | ||||||||||||||||||
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | PUGET ENERGY | PSE | PUGET ENERGY | PSE | ||||||||||||||
| Charged to operating expense: | ||||||||||||||||||||
| Current - federal | $ | 18,119 | $ | 22,154 | $ | (84,149 | ) | $ | (81,839 | ) | $ | 58,749 | $ | 58,331 | ||||||
| Current - state | (2,046 | ) | (1,460 | ) | (774 | ) | (548 | ) | 1,347 | 1,232 | ||||||||||
| Deferred - net federal | 56,004 | 50,880 | 144,230 | 135,884 | 19,945 | 18,040 | ||||||||||||||
| Deferred -net state | 927 | -- | 614 | -- | 485 | -- | ||||||||||||||
| Deferred investment tax credits | (635 | ) | (635 | ) | (661 | ) | (661 | ) | (688 | ) | (688 | ) | ||||||||
| Total charged to operations | 72,369 | 70,939 | 59,260 | 52,836 | 79,838 | 76,915 | ||||||||||||||
| Charged to miscellaneous income: | ||||||||||||||||||||
| Current | (288 | ) | (276 | ) | (3,276 | ) | (3,406 | ) | 6,272 | 6,272 | ||||||||||
| Deferred - net | (1,805 | ) | (1,805 | ) | 1,228 | 1,228 | (2,259 | ) | (2,259 | ) | ||||||||||
| Total charged to miscellaneous income | (2,093 | ) | (2,081 | ) | (2,048 | ) | (2,178 | ) | 4,013 | 4,013 | ||||||||||
| Cumulative effect of accounting change | (91 | ) | (91 | ) | -- | -- | (7,942 | ) | (7,942 | ) | ||||||||||
| Total income taxes | $ | 70,185 | $ | 68,767 | $ | 57,212 | $ | 50,658 | $ | 75,909 | $ | 72,986 | ||||||||
The following is a reconciliation of the difference between the amount of income taxes computed by multiplying pre-tax book income by the statutory tax rate and the amount of income taxes in the Consolidated Statements of Income for the Company:
| 2003 | 2002 | 2001 | ||||||||||||||||||
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | PUGET ENERGY | PSE | PUGET ENERGY | PSE | ||||||||||||||
| Income taxes at the statutory rate | $ | 67,098 | $ | 66,028 | $ | 61,587 | $ | 55,862 | $ | 63,962 | $ | 62,079 | ||||||||
| Increase (decrease): | ||||||||||||||||||||
| Depreciation expense deducted in | ||||||||||||||||||||
| the financial statements in exce | ||||||||||||||||||||
| of tax depreciation, net of | ||||||||||||||||||||
| depreciation treated as a | ||||||||||||||||||||
| temporary difference | 9,130 | 9,130 | 10,041 | 10,041 | 11,726 | 11,726 | ||||||||||||||
| AFUDC included in income in the | ||||||||||||||||||||
| financial statements but exclude | ||||||||||||||||||||
| from taxable income | (1,809 | ) | (1,809 | ) | (1,387 | ) | (1,387 | ) | (2,126 | ) | (2,126 | ) | ||||||||
| Accelerated benefit on early | ||||||||||||||||||||
| retirement of depreciable assets | (1,879 | ) | (1,879 | ) | (1,469 | ) | (1,469 | ) | (319 | ) | (319 | ) | ||||||||
| Investment tax credit amortizatio | (635 | ) | (635 | ) | (661 | ) | (661 | ) | (689 | ) | (689 | ) | ||||||||
| Energy conservation expenditures | ||||||||||||||||||||
| net | 8,096 | 8,096 | 6,259 | 6,259 | 6,859 | 6,859 | ||||||||||||||
| Tax benefit of reduced salvage | ||||||||||||||||||||
| values | -- | -- | (10,193 | ) | (10,193 | ) | -- | -- | ||||||||||||
| IRS issue resolution | (6,209 | ) | (6,209 | ) | -- | -- | -- | -- | ||||||||||||
| State income taxes net of the | ||||||||||||||||||||
| federal income tax benefit | (877 | ) | (949 | ) | (104 | ) | (356 | ) | 1,191 | 801 | ||||||||||
| Other - net | (2,730 | ) | (3,006 | ) | (6,861 | ) | (7,438 | ) | (4,695 | ) | (5,345 | ) | ||||||||
| Total income taxes | $ | 70,185 | $ | 68,767 | $ | 57,212 | $ | 50,658 | $ | 75,909 | $ | 72,986 | ||||||||
| Effective tax rate | 36.6% | 36.5% | 32.5% | 31.7% | 41.5% | 41.15% | ||||||||||||||
The Company’s deferred tax liability at December 31, 2003, 2002 and 2001 is composed of amounts related to the following types of temporary differences:
| 2003 | 2002 | 2001 | ||||||||||||||||||
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | PUGET ENERGY | PSE | PUGET ENERGY | PSE | ||||||||||||||
| Utility plant | $ | 607,203 | $ | 607,203 | $ | 578,137 | $ | 578,137 | $ | 570,982 | $ | 570,982 | ||||||||
| Energy conservation charges | 9,446 | 9,446 | 16,473 | 16,473 | 23,782 | 23,782 | ||||||||||||||
| Contributions in aid of construction | (46,520 | ) | (46,520 | ) | (44,770 | ) | (44,770 | ) | (36,044 | ) | (36,044 | ) | ||||||||
| Bonneville Exchange Power | 15,204 | 15,204 | 15,537 | 15,537 | 17,897 | 17,897 | ||||||||||||||
| Cabot gas contract purchase | 3,503 | 3,503 | 4,157 | 4,157 | 4,477 | 4,477 | ||||||||||||||
| Deferred revenue | (4,680 | ) | (4,680 | ) | (5,292 | ) | (5,292 | ) | (5,904 | ) | (5,904 | ) | ||||||||
| Software amortization | 41,044 | 41,044 | 41,408 | 41,408 | -- | -- | ||||||||||||||
| Capitalized overhead costs | 70,834 | 70,834 | 72,220 | 72,220 | -- | -- | ||||||||||||||
| Other | 59,201 | 35,910 | 52,805 | 37,709 | 30,125 | 25,811 | ||||||||||||||
| Total | $ | 755,235 | $ | 731,944 | $ | 730,675 | $ | 715,579 | $ | 605,315 | $ | 601,001 | ||||||||
Puget Energy’s totals of $755.2 million and $730.7 million for 2003 and 2002 consist of deferred tax liabilities of $876.5 million and $841.7 million net of deferred tax assets of $121.3 million and $111.0 million, respectively.
PSE’s totals of $731.9 million and $715.6 million for 2003 and 2002 consist of deferred tax liabilities of $852.4 million and $824.2 million net of deferred tax assets of $120.5 million and $108.6 million, respectively.
Deferred tax amounts shown above result from temporary differences for tax and financial statement purposes. Deferred tax provisions are not recorded in the income statement for certain temporary differences between tax and financial statement purposes because they are not allowed for ratemaking purposes.
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 of assets and liabilities, including temporary differences for which no deferred taxes had been previously provided because of use of flow-through tax accounting for ratemaking purposes. Because of prior and expected future ratemaking treatment for temporary differences for which flow-through tax accounting has been utilized, a regulatory asset for income taxes recoverable through future rates related to those differences has also been established by PSE. At December 31, 2003, the balance of this asset was $142.8 million.
NOTE 9.12.
Retirement Benefits
The Company has a defined benefit pension plan with a cash balance feature covering substantially all of its utility employees. Benefits are a function of age, salary and service. Additionally, Puget Energy 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) | 2003 | 2002 | 2003 | 2002 | ||||||||||
| Change in benefit obligation: | ||||||||||||||
| Benefit obligation at beginning of year | $ | 369,692 | $ | 400,461 | $ | 31,693 | $ | 29,115 | ||||||
| Service cost | 8,284 | 8,474 | 175 | 168 | ||||||||||
| Interest cost | 24,406 | 25,858 | 1,828 | 1,930 | ||||||||||
| Amendments1 | 940 | 3,073 | -- | 3,493 | ||||||||||
| Actuarial loss | 19,354 | 2,055 | (2,194 | ) | (419 | ) | ||||||||
| Plan curtailment2 | -- | (9,518 | ) | -- | (553 | ) | ||||||||
| Special adjustments2 | 190 | 10,872 | -- | -- | ||||||||||
| Benefits paid | (22,825 | ) | (71,583 | ) | (2,282 | ) | (2,041 | ) | ||||||
| Benefit obligation at end of year | $ | 400,041 | $ | 369,692 | $ | 29,220 | $ | 31,693 | ||||||
| Change in plan assets: | ||||||||||||||
| Fair value of plan assets at beginning | $ | 343,960 | $ | 443,512 | $ | 16,160 | $ | 15,978 | ||||||
| Actual return on plan assets | 79,488 | (40,849 | ) | 98 | 650 | |||||||||
| Employer contribution | 27,963 | 12,880 | 1,455 | 1,573 | ||||||||||
| Benefits paid | (22,825 | ) | (71,583 | ) | (2,282 | ) | (2,041 | ) | ||||||
| Fair value of plan assets at end of yea | $ | 428,586 | $ | 343,960 | $ | 15,431 | $ | 16,160 | ||||||
| Funded status | $ | 28,545 | $ | (25,732 | ) | $ | (13,789 | ) | $ | (15,533 | ) | |||
| Unrecognized actuarial gain (loss) | 48,217 | 66,784 | (2,895 | ) | (1,878 | ) | ||||||||
| Unrecognized prior service cost | 15,949 | 18,228 | 2,712 | 3,021 | ||||||||||
| Unrecognized net initial (asset) obliga | (1,267 | ) | (2,371 | ) | 3,783 | 4,201 | ||||||||
| Net amount recognized | $ | 91,444 | $ | 56,909 | $ | (10,189 | ) | $ | (10,189 | ) | ||||
| Amounts recognized on statement of | ||||||||||||||
| financial position consist of: | ||||||||||||||
| Prepaid benefit cost | $ | 112,737 | $ | 73,361 | $ | (10,189 | ) | $ | (10,189 | ) | ||||
| Accrued benefit liability | (38,704 | ) | (34,253 | ) | -- | -- | ||||||||
| Intangible asset | 9,043 | 10,555 | -- | -- | ||||||||||
| Accumulated other comprehensive income | 8,368 | 7,246 | -- | -- | ||||||||||
| Net amount recognized | $ | 91,444 | $ | 56,909 | $ | (10,189 | ) | $ | (10,189 | ) | ||||
1 In 2002, the Company had $3.1 million in pension benefit plan amendments due to changes in employment contracts, the addition of new entrants to the plan and the vesting of certain non-vested participants who were affected by the transition of service jobs to service providers. The Company had $3.5 million in other benefit plan amendments due to an increase in the Company's contribution to the retiree medical plan.
2 In 2002, the Company had a $9.5 million curtailment credit and $9.2 million in special adjustments to the pension benefit plan related to the transition of service jobs to service providers. The Company also had a $1.7 million special adjustment to the pension benefit plan related to the non-qualified pension benefit plan required to reflect the special benefit agreement given upon termination of a plan participant.
In accounting for pension and other benefit costs under the plans, the following weighted average actuarial assumptions were used:
| PENSION BENEFITS | OTHER BENEFITS | |||||
| 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |
| Discount rate | 6.25% | 6.75% | 7.25% | 6.25% | 6.75% | 7.25% |
| Return on plan assets | 8.25% | 8.25% | 9.50% | 6-7.00% | 6-7.00% | 6-8.25% |
| Rate of compensation increa | 4.50% | 4.50% | 5.0% | -- | -- | -- |
| Medical trend rate | -- | -- | -- | 9.00% | 10.00% | 6.50% |
The Company has used the expected return on plan assets based on an analysis of rates of return over the past 50 years relevant to 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.
| PENSION BENEFITS | OTHER BENEFITS | |||||||||||||||||||
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | ||||||||||||||
| Components of net periodic benefit cost: | ||||||||||||||||||||
| Service cost | $ | 8,284 | $ | 8,474 | $ | 9,862 | $ | 175 | $ | 168 | $ | 243 | ||||||||
| Interest cost | 24,406 | 25,858 | 26,734 | 1,828 | 1,930 | 2,022 | ||||||||||||||
| Expected return on plan assets | (38,880 | ) | (43,032 | ) | (46,222 | ) | (934 | ) | (906 | ) | (947 | ) | ||||||||
| Amortization of prior service cost | 3,220 | 2,990 | 2,960 | 309 | 90 | (34 | ) | |||||||||||||
| Recognized net actuarial gain | (2,688 | ) | (5,120 | ) | (7,570 | ) | (341 | ) | (229 | ) | (109 | ) | ||||||||
| Amortization of transition (asset) obligation | (1,104 | ) | (1,136 | ) | (1,230 | ) | 418 | 470 | 627 | |||||||||||
| Plan curtailment | -- | (1,353 | ) | -- | -- | 1,691 | -- | |||||||||||||
| Special recognition of prior service costs | 190 | 1,683 | 108 | -- | -- | -- | ||||||||||||||
| Net pension benefit cost (income) | $ | (6,572 | ) | $ | (11,636 | ) | $ | (15,358 | ) | $ | 1,455 | $ | 3,214 | $ | 1,802 | |||||
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the non-qualified pension plan, which has accumulated benefit obligations in excess of plan assets, were $45.0 million, $38.6 million and $0, respectively, as of December 31, 2003. For the qualified pension plan the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $355.1 million, $339.7 million and $428.6 million, respectively, as of December 31, 2003.
The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year ended December 31, 2004 are $11.1 million and an insignificant amount, respectively. The full amount of the pension funding for 2004 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:
| 2003 | 2002 | |||
| PENSION BENEFITS | OTHER BENEFITS | PENSION BENEFITS | OTHER BENEFITS | |
| Short-term investments and cash | 3.0% | 100.0% | 4.1% | 100.0% |
| Equity securities | 63.8% | -- | 55.7% | -- |
| Fixed income securities | 22.9% | -- | 31.2% | -- |
| Mutual funds | 10.3% | -- | 9.0% | -- |
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 is as follows:
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009-2013 |
| Total benefits | $ 35,697 | $ 25,940 | $ 26,939 | $ 28,806 | $ 28,202 | $157,821 |
The assumed medical inflation rate is 9.0% in 2004 decreasing to 6.0% in 2007. A 1% change in the assumed medical inflation rate would have the following effects:
| 2003 | 2002 | |||||||||||||
| (DOLLARS IN THOUSANDS) | 1% INCREASE | 1% DECREASE | 1% INCREASE | 1% DECREASE | ||||||||||
| Effect on post-retirement benefit obligation | $ | 589 | $ | (529 | ) | $ | 580 | $ | (515 | ) | ||||
| Effect on service and interest cost components | 38 | (35 | ) | 36 | (32 | ) | ||||||||
The Company has a Retirement Committee that establishes investment policies, objectives and strategies for the purpose 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. 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 | |||
| ASSET CLASS | MINIMUM | TARGET | MAXIMUM |
| Domestic large capitalization equity securities | 30% | 42% | 50% |
| Domestic small capitalization equity securities | -- | 8% | 15% |
| Fixed-income securities | 20% | 30% | 40% |
| Foreign equity securities | 10% | 20% | 30% |
| Real estate | -- | -- | 10% |
| Short-term investments and cash | -- | -- | 5% |
NOTE 13.
Employee Investment Plans
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’s contributions to the Employee Investment Plans were $7.1 million, $6.9 million and $8.0 million for the years 2003, 2002 and 2001, respectively.
PSE’s contributions to the Employee Investment Plan were $6.1 million, $6.1 million and $6.8 million for the years 2003, 2002 and 2001, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.
NOTE 14.
Stock-based Compensation Plans
The Company has various stock 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 will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Total compensation expense related to the plans was $6.4 million, $6.3 million and $2.1 million in 2003, 2002 and 2001, respectively.
The Company’s shareholder-approved Long-Term Incentive Plan (LTI Plan) encompasses many of the awards granted to employees. Established in 1995 and amended and restated in 1997, the LTI Plan applies to officers and key employees of the Company. Awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are purchased on the open market. The maximum number of shares that may be purchased for the LTI Plan is 1,200,000.
PERFORMANCE SHARE GRANTS
Each year the Company awards performance share grants under the LTI Plan. These are granted to key employees and vest at the end of four years with the final number of shares awarded depending on a performance measure. The Company records compensation expense related to the shares based on the performance measure and changes in the market price of the stock. Compensation expense related to performance share grants was $5.1 million, $5.5 million and $2.3 million for 2003, 2002 and 2001, respectively. The fair value of the performance awards granted in 2003, 2002 and 2001 was $17.29, $14.82 and $17.86, respectively. There were a total of 334,608 performance awards granted in 2003, 247,184 in 2002 and 183,881 in 2001. As of December 31, 2003, there are four active grant cycles for a total of 790,922 share grants outstanding although they may not all be awarded.
STOCK 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 president and chief executive officer. These options can be exercised at the grant date market price of $22.51 per share and vest yearly over four and five years although vesting is accelerated under certain conditions. The options expire 10 years from the grant date. All 300,000 options remained outstanding at December 31, 2003, with 67,500 options exercisable. No options were exercisable at December 31, 2002. The fair value of the options at the grant date was $3.37 per share. Following the intrinsic value method of APB 25, no compensation expense was recorded for these options. No additional options were granted in 2003.
RESTRICTED STOCK
In 2003 and 2002, the Company granted 11,000 shares and 30,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market. Of the 2003 shares issued, 1,000 shares vested in 2003. The remaining shares will vest evenly over the next five years. The 2002 shares were fully vested as of December 2003. In 2002 the Company also issued 50,000 shares of restricted stock outside of the LTI Plan as approved by the Puget Energy Board of Directors. These shares were recorded as a separate component of stockholders’ equity and vest evenly over a five-year period. Compensation expense related to the restricted shares was $0.6 million and $0.5 million in 2003 and 2002, respectively. No restricted shares were issued in 2001. Dividends are paid on all outstanding restricted stock and are accounted for as a Puget Energy stock dividend, not as compensation expense. The weighted average grant date fair value for all outstanding shares of restricted stock granted in 2003 and 2002 was $23.29 and $21.94, respectively.
EMPLOYEE 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% 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. Prior to 2002, the Company purchased shares for the plan on the open market. As of the second offering of 2002, the Company began issuing common stock for the ESPP rather than purchasing stock. In 2003, 38,940 shares were issued for the ESPP. In 2002, 18,252 shares were issued and 19,407 shares were purchased for the plan, and in 2001, 45,659 shares were purchased. At December 31, 2003, 259,662 shares may still be sold to employees under the plan. Under the SFAS No. 123 accounting that the Company adopted in 2003, ESPP is considered to be compensation expense. Total compensation expense related to the ESPP was $0.2 million in 2003. 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 2003, 2002 and 2001 was $4.25, $4.19 and $4.35, 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 2003, 2002 and 2001:
| 2003 | 2002 | 2001 | |||||||||||
| 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 | 2,643 | $ 4 | .31 | 1,995 | $ 4 | .05 | -- | $ -- | |||||
| Granted | 176 | 5 | .00 | 725 | 5 | .00 | 2,043 | 4 | .05 | ||||
| Exercised | -- | -- | -- | -- | -- | -- | |||||||
| Canceled | (201 | ) | 4 | .20 | (77 | ) | 4 | .09 | (48 | ) | 4 | .00 | |
| Outstanding at end of year | 2,618 | $ 4 | .36 | 2,643 | $ 4 | .31 | 1,995 | $ 4 | .05 | ||||
| Options exercisable at year end | 1,837 | $ 4 | .12 | 802 | $ 4 | .02 | 791 | $ 4 | .00 | ||||
| Weighted average fair value of options granted during the year | $2.41 | $2.23 | $1.60 | ||||||||||
The following summarizes InfrastruX's outstanding option information at December 31, 2003:
| Shares Outstanding (in thousands) | Weighted Average Contractual Life (in years) | Weighted Average Exercise Price | ||
| Exercise Prices | ||||
| $4.00 | 1,666 | 7.11 | $4.00 | |
| $5.00 | 952 | 8.42 | 5.00 | |
| 2,618 | 7.59 | $4.36 | ||
Stock options awarded under the InfrastruX plan were generally granted at the InfrastruX market price on the date of grant although some options have been granted at a discount requiring InfrastruX to record compensation expense. With the prospective adoption of SFAS No. 123 fair value accounting in 2003, InfrastruX also recorded compensation expense related to options granted in 2003. Compensation expense of $0.2 million and $0.1 million related to stock options was recorded in 2003 and 2002, respectively.
NON-EMPLOYEE DIRECTOR STOCK PLAN
The Company has a director stock plan created in 1998 for all non-employee directors of Puget Energy and PSE. Under the plan which has a 10-year term, non-employee directors receive a minimum of two-thirds of their quarterly retainer fees in Company stock except that 100% of quarterly retainers are paid in Company stock until the director holds a number of shares equal to two years of common stock in value of their retainer. Directors may optionally receive their entire retainer in Company stock. The compensation expense related to the director stock plan was $0.4 million, $0.2 million and $0.1 million in 2003, 2002 and 2001, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 100,000 shares. As of December 31, 2003, 9,902 shares had been purchased for the director stock plan and 48,219 deferred, for a total of 58,121 shares.
OTHER PLANS
In addition to current stock compensation plans, the Company also has outstanding shares related to two plans that were in effect prior to the 1997 merger between Puget Sound Power and Light (PSP&L) and Washington Energy Company (WECO). There are 2,400 vested, unexercised stock appreciation rights from the PSP&L Incentive Plan Awards granted to executives of PSP&L. These were granted in 1994, have an exercise price of $20.75 and expire 10 years after the grant date. There are also 11,301 vested, unexercised options from the WECO Incentive Stock Option Plan granted to key employees of WECO. The options were granted between 1994 and 1996 with exercise prices ranging from $15.55 to $23.11 and expire 10 years from the date of grant. These are generally paid out as stock appreciation rights at the discretion of the grantees. The Company records compensation expense each quarter related to the PSP&L and WECO shares as the difference between the exercise price and the current market price. Compensation expense related to the WECO plan was immaterial in 2003 and 2002, and $(0.2) million in 2001. Compensation expense related to the PSP&L plan was immaterial in 2003 and 2002, and $(0.1) million in 2001.
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 granted in 2003, 2002 and 2001:
| 2003 | 2002 | 2001 | |||||
| Stock options | |||||||
| Risk-free interest rate | -- | 4 | .32% | -- | |||
| Expected lives - years | -- | 4 | .50 | -- | |||
| Expected stock volatility | -- | 23 | .62% | -- | |||
| Dividend yield | -- | 5 | .00% | -- | |||
| InfrastruX stock option plan | |||||||
| Risk-free interest rate | 2 | .80% | 4 | .05% | 4 | .87% | |
| Expected lives - years | 4 | .00 | 4 | .00 | 4 | .00 | |
| Expected stock volatility | 60 | .00% | 60 | .00% | 50 | .00% | |
| Performance awards | |||||||
| Risk-free interest rate | 2 | .35% | 4 | .00% | 4 | .99% | |
| Expected lives - years | 4 | .00 | 4 | .00 | 4 | .00 | |
| Expected stock volatility | 23 | .85% | 23 | .71% | 20 | .76% | |
| Dividend yield | 4 | .86% | 8 | .85% | 7 | .67% | |
| Employee Stock Purchase Plan | |||||||
| Risk-free interest rate | 1 | .07% | 1 | .65% | 4 | .26% | |
| Expected lives - years | 0 | .50 | 0 | .50 | 0 | .50 | |
| Expected stock volatility | 19 | .47% | 26 | .97% | 19 | .04% | |
| Dividend yield | 4 | .39% | 5 | .81% | 7 | .72% | |
NOTE 15.
Accounting for Derivative Instruments and Hedging Activities
The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income statement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
In addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with no significant impact on the financial statements.
On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.
NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)
During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of cash and preferred or common stock. The 2003 acquisition includes a contingency which requires InfrastruX to make additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
These companies provide utility infrastructure services which are relevant 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 for 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 $7.7 million in 2003 and $23.5 million in 2002.
During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to the annual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 |
| Reported income for common stock | $ 116,197 | $ 110,052 | $ 98,426 |
| Add back goodwill amortization, net of tax | -- | -- | 2,826 |
| Adjusted income for common stock | $ 116,197 | $ 110,052 | $ 101,252 |
| Basic earnings per share | |||
| Reported income for common stock | $ 1.23 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.23 | $ 1.24 | $ 1.17 |
| Diluted earnings per share | |||
| Reported income for common stock | $ 1.22 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.22 | $ 1.24 | $ 1.17 |
Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 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 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 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. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.
| AT DECEMBER 31, 2003 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | 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 | |
| AT DECEMBER 31, 2002 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | Net Intangibles | |
| Covenant not to compete | $ 3,908 | $1,105 | $ 2,803 | |
| Developed technology | 14,190 | 1,744 | 12,446 | |
| Contractual customer relationships | 3,042 | 383 | 2,659 | |
| Patents | 793 | 49 | 744 | |
| Total | $21,933 | $3,281 | $18,652 | |
The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 |
| Future intangible amortization | $ 2,101 | $ 2,075 | $ 1,746 | $ 1,363 | $ 1,340 |
The pro forma combined revenues, 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, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.
| (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) FOR THE YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 |
| Operating revenues | $ 2,505,523 | $ 2,469,122 | $ 3,056,824 |
| Net income for common | 116,636 | 112,813 | 104,338 |
| Basic earnings per common share | $ 1.23 | $ 1.28 | $ 1.21 |
| Diluted earnings per common share | $ 1.22 | $ 1.27 | $ 1.20 |
NOTE 17.
Other
PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.
NOTE 18.
Commitments and Contingencies
COMMITMENTS – ELECTRIC
For the year ended December 31, 2003, approximately 19.9% of the Company’s energy output was obtained at an average cost of approximately $0.01641 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” basis under which the Company pays a proportionate share of the annual cost of each project in direct proportion to the amount of power annually purchased by the Company from such project. Such payments are not contingent upon the projects being operable. 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, 2003, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:
| BONDS OUTSTANDING | COMPANY'S ANNUAL AMOUNT PURCHASABLE (APPROXIMATE) | ||||||||||||
| PROJECT | CONTRACT EXP. DATE | LICENSE1 EXP. DATE | 12/31/032 (MILLIONS) | % OF OUTPUT | MEGAWATT CAPACITY | COSTS3 (MILLIONS) | |||||||
| Rock Island | |||||||||||||
| Original units | 2012 | 2029 | $ 121 | .7 | 50.0 | 414 | $ 41 | .9 | |||||
| Additional units | 2012 | 2029 | 331 | .5 | 75.0 | ||||||||
| Rocky Reach | 2011 | 2006 | 394 | .7 | 38.9 | 505 | 29 | .6 | |||||
| Wells | 2018 | 2012 | 151 | .3 | 31.3 | 261 | 6 | .9 | |||||
| Priest Rapids4 | 2005 | 2005 | 184 | .7 | 8.0 | 72 | 2 | .6 | |||||
| Wanapum4 | 2009 | 2005 | 186 | .5 | 10.8 | 98 | 4 | .1 | |||||
| Total | $ 1,370 | .4 | 1,350 | $ 85 | .1 | ||||||||
The Company’s estimated payments for power purchases from the Columbia River are $84.6 million for 2004, $81.4 million for 2005, $78.4 million for 2006, $81.4 million for 2007, $82.6 million for 2008 and in the aggregate, $123.5 million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with other utilities in 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 $76.0 million for 2004, $77.7 million for 2005, $78.6 million for 2006, $80.7 million for 2007, $82.6 million for 2008 and in the aggregate, $433.3 million thereafter through 2037. 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 $211.4 million for 2004, $217.3 million for 2005, $232.9 million for 2006, $211.9 million for 2007, $212.1 million for 2008 and in the aggregate, $746.0 million thereafter through 2012.
The following table summarizes the Company’s estimated obligations for future power purchases:
| (DOLLARS IN MILLIONS) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 & THERE- AFTER | TOTAL |
| Columbia River projects | $ 84.6 | $ 81.4 | $ 78.4 | $ 81.4 | $ 82.6 | $ 123.5 | $ 531.9 |
| Other utilities | 76.0 | 77.7 | 78.6 | 80.7 | 82.6 | 433.3 | 828.9 |
| Non-utility generators | 211.4 | 217.3 | 232.9 | 211.9 | 212.1 | 746.0 | 1,831.6 |
| Total | $ 372.0 | $ 376.4 | $ 389.9 | $ 374.0 | $ 377.3 | $ 1,302.8 | $ 3,192.4 |
| 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 affirm the Company'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, 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: 43.7% at Rock Island; 58.3% at Rocky Reach; 94.5% at Priest Rapids; 79.6% at Wanapum; and 6.2% at Wells. |
| 3 | The components of 2003 costs associated with the interest portion of debt service are: Rock Island, $22.6 million for all units; Rocky Reach, $9.4 million; Wells, $8.2 million; Priest Rapids, $0.8 million; and Wanapum, $0.6 million. |
| 4 | 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 contract 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 Act 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, it 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 has been requested. |
Total purchased power contracts provided the Company with approximately 11.0 million, 12.1 million and 11.9 million MWh of firm energy at a cost of approximately $479.2 million, $466.1 million and $496.3 million for the years 2003, 2002 and 2001, 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, 2003:
| COMPANY'S SHARE | ||||||||||||||
| (DOLLARS IN MILLIONS) | ENERGY SOURCE (FUEL) | COMPANY'S OWNERSHIP SHARE | PLANT IN SERVICE AT COST | ACCUMULATED DEPRECIATION | ||||||||||
| Colstrip 1 & 2 | Coal | 50% | $ 207 | $ 133 | ||||||||||
| Colstrip 3 & 4 | Coal | 25% | 464 | 240 | ||||||||||
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.
PSE and PPL Montana, the other owner of Colstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s PCA mechanism.
On October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE used the coal as fuel for its share of Units 3 & 4 of the Colstrip generating plant. PSE’s coal price for that period was reduced by a settlement PSE and Western Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.
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 per day of natural gas for operation of Tenaska’s 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 $22.0 million in 2004.
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 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 $8.5 million in 2004, $8.7 million in 2005, $9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter. 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 of 6.5 years. The obligations under these contracts are $15.9 million in 2004, $16.7 million in 2005, $17.5 million in 2006, $18.4 million in 2007 and $12.9 million in the aggregate thereafter.
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. Commitments under these contracts are $3.0million in 2004, $10.3 million in 2005, $1.1 million in 2006, $0.4 million in 2007 and $0.1 million thereafter.
GAS 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 20 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Two of PSE’s long-term firm gas supply agreements, that expire November 2004, obligate the Company to purchase a minimum annual quantity at market-based contract prices. If the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. PSE didn’t incur such charges in 2003. The Company incurred demand charges in 2003 for firm gas supply, firm transportation service and firm storage and peaking service of $24.7 million, $47.9 million and $5.3 million, respectively. WNG Cap I incurred demand charges in 2003 for firm transportation service of $9.4 million.
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) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 & THERE- AFTER | TOTAL |
| Firm gas supply | $ 18.7 | $ 1.5 | $ 1.0 | $ 0.5 | $ 0.5 | $ 1.5 | $ 23.7 |
| Firm transportation service | 66.6 | 58.8 | 57.0 | 57.0 | 48.0 | 122.7 | 410.1 |
| Firm storage service | 11.3 | 11.6 | 7.8 | 7.7 | 7.7 | 48.2 | 94.3 |
| Total | $ 96.6 | $ 71.9 | $ 65.8 | $ 65.2 | $ 56.2 | $ 172.4 | $ 528.1 |
SERVICE CONTRACT
On August 30, 2001, PSE and Alliance Data Systems Corp. 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 its ConneXt subsidiary. 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 $21.7 million in 2004, $22.2 million in 2005, $22.8 million in 2006, $23.4 million in 2007, $24.0 million in 2008 and $66.9 million in the aggregate thereafter.
SURETY BOND
The Company has a self-insurance surety bond in the amount of $5.9 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.
ENVIRONMENTAL
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 these 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. The Company believes a significant portion of its past and future environmental remediation costs are 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, 2003.
ELECTRIC SITES
The Company has expended approximately $18.1 million related to the remediation activities covered by the Washington Commission’s order and has accrued approximately $1.6 million as a liability for future remediation costs for these and other remediation activities. To date, the Company has recovered approximately $18.8 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 trends.
GAS SITES
The Company has expended approximately $65.9 million related to the remediation activities covered by a Washington Commission order and has accrued approximately $32.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $59.6 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.
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 trends.
LITIGATION
There are several actions in the U.S. Ninth Circuit Court of Appeals 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, a number of contracts, including the amended settlement agreement regarding the Residential Purchase and Sale Program and the conditional settlement agreements between BPA and PSE which modified the payment provisions of the Residential Purchase and Sale Program. BPA rates used in such amended settlement agreement between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits 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 may have on PSE.
Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 2003. 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.
NOTE 19.
Segment Information
Puget Energy operates in primarily two business segments: regulated utility operations, or PSE, and construction services, or InfrastruX. 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 State of Washington. InfrastruX specializes in construction services to other gas and electric utilities primarily in the south/Texas and the north-central and eastern United States.
One minor non-utility business segment, a PSE subsidiary, which is a real estate investment and development company is described as other. The assets of ConneXt, the development and marketing of customer information and billing system software segment, were sold during the third quarter of 2001. The third quarter results of 2001 included an $8.0 million after-tax gain related to the ConneXt sale. Reconciling items between segments are not significant.
Financial data for business segments are as follows:
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||
| 2003 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $2,143,693 | $341,787 | $ 6,043 | $2,491,523 |
| 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 | 121,348 |
| Goodwill, net | -- | 133,302 | -- | 133,302 |
| Total assets | 5,257,157 | 342,332 | 75,196 | 5,674,685 |
| Construction expenditures - excluding equity AFUDC | 269,973 | -- | -- | 269,973 |
| Additions to other property, plant and equipment | -- | 15,536 | -- | 15,536 |
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||
| 2002 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $2,063,040 | $319,529 | $ 9,753 | $2,392,322 |
| Depreciation and amortization | 215,097 | 13,426 | 220 | 228,743 |
| Income tax | 50,600 | 6,703 | 1,957 | 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 | 117,883 |
| 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 |
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||
| 2001 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $2,680,298 | $173,786 | $ 32,476 | $2,886,560 |
| Depreciation and amortization | 208,705 | 8,820 | 15 | 217,540 |
| Income tax | 68,005 | 2,956 | 8,877 | 79,838 |
| Operating income | 273,751 | 8,702 | 14,668 | 297,121 |
| Interest charges, net of AFUDC | 186,403 | 3,656 | -- | 190,059 |
| Net income | 80,137 | 2,518 | 24,184 | 106,839 |
| Goodwill, net | -- | 102,151 | -- | 102,151 |
| Total assets | 5,300,105 | 229,125 | 139,251 | 5,668,481 |
| Construction expenditures - excluding equity AFUDC | 247,435 | -- | -- | 247,435 |
| Additions to other property, plant and equipment | -- | 5,193 | -- | 5,193 |
NOTE 20.Supplementary Income Statement Information
| (Dollars in thousands) | PUGET ENERGY 2002 | PSE 2002 | PUGET ENERGY 2001 | PSE 2001 | PUGET ENERGY AND PSE 2000 | ||||||
| Taxes other than income taxes: | |||||||||||
| Real estate and personal property | $ 48,890 | $ 48,408 | $ 41,858 | $ 41,588 | $ 47,357 | ||||||
| State business | 77,527 | 77,527 | 85,335 | 84,735 | 83,485 | ||||||
| Municipal and occupational | 67,770 | 67,770 | 71,819 | 71,819 | 65,155 | ||||||
| Other | 37,029 | 24,463 | 33,431 | 29,084 | 30,073 | ||||||
| Total taxes other than income taxes | $231,216 | $218,168 | $232,443 | $227,226 | $226,070 | ||||||
| Charged to: | |||||||||||
| Operating expense | $215,429 | $202,381 | $212,582 | $207,365 | $202,398 | ||||||
| Other accounts, including construction work in progress | 15,787 | 15,787 | 19,861 | 19,861 | 23,672 | ||||||
| Total taxes other than income taxes | $231,216 | $218,168 | $232,443 | $227,226 | $226,070 | ||||||
NOTE 10.LeasesRetirement Benefits
AllThe Company has a defined benefit pension plan with a cash balance feature covering substantially all of PSE’s leasesits utility employees. Benefits are operating leases. Certain leases contain purchase options, renewala function of age, salary and escalation provisions.service. Additionally, Puget Energy maintains a non-qualified supplemental retirement plan for officers and certain director-level employees. The annual measurement date is December 31 of each year.
OperatingIn addition to providing pension benefits, the Company provides certain health care and capital lease payments netlife 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) | 2003 | 2002 | 2003 | 2002 | ||||||||||
| Change in benefit obligation: | ||||||||||||||
| Benefit obligation at beginning of year | $ | 369,692 | $ | 400,461 | $ | 31,693 | $ | 29,115 | ||||||
| Service cost | 8,284 | 8,474 | 175 | 168 | ||||||||||
| Interest cost | 24,406 | 25,858 | 1,828 | 1,930 | ||||||||||
| Amendments1 | 940 | 3,073 | -- | 3,493 | ||||||||||
| Actuarial loss | 19,354 | 2,055 | (2,194 | ) | (419 | ) | ||||||||
| Plan curtailment2 | -- | (9,518 | ) | -- | (553 | ) | ||||||||
| Special adjustments2 | 190 | 10,872 | -- | -- | ||||||||||
| Benefits paid | (22,825 | ) | (71,583 | ) | (2,282 | ) | (2,041 | ) | ||||||
| Benefit obligation at end of year | $ | 400,041 | $ | 369,692 | $ | 29,220 | $ | 31,693 | ||||||
| Change in plan assets: | ||||||||||||||
| Fair value of plan assets at beginning | $ | 343,960 | $ | 443,512 | $ | 16,160 | $ | 15,978 | ||||||
| Actual return on plan assets | 79,488 | (40,849 | ) | 98 | 650 | |||||||||
| Employer contribution | 27,963 | 12,880 | 1,455 | 1,573 | ||||||||||
| Benefits paid | (22,825 | ) | (71,583 | ) | (2,282 | ) | (2,041 | ) | ||||||
| Fair value of plan assets at end of yea | $ | 428,586 | $ | 343,960 | $ | 15,431 | $ | 16,160 | ||||||
| Funded status | $ | 28,545 | $ | (25,732 | ) | $ | (13,789 | ) | $ | (15,533 | ) | |||
| Unrecognized actuarial gain (loss) | 48,217 | 66,784 | (2,895 | ) | (1,878 | ) | ||||||||
| Unrecognized prior service cost | 15,949 | 18,228 | 2,712 | 3,021 | ||||||||||
| Unrecognized net initial (asset) obliga | (1,267 | ) | (2,371 | ) | 3,783 | 4,201 | ||||||||
| Net amount recognized | $ | 91,444 | $ | 56,909 | $ | (10,189 | ) | $ | (10,189 | ) | ||||
| Amounts recognized on statement of | ||||||||||||||
| financial position consist of: | ||||||||||||||
| Prepaid benefit cost | $ | 112,737 | $ | 73,361 | $ | (10,189 | ) | $ | (10,189 | ) | ||||
| Accrued benefit liability | (38,704 | ) | (34,253 | ) | -- | -- | ||||||||
| Intangible asset | 9,043 | 10,555 | -- | -- | ||||||||||
| Accumulated other comprehensive income | 8,368 | 7,246 | -- | -- | ||||||||||
| Net amount recognized | $ | 91,444 | $ | 56,909 | $ | (10,189 | ) | $ | (10,189 | ) | ||||
1 In 2002, the Company had $3.1 million in pension benefit plan amendments due to changes in employment contracts, the addition of sublease receipts were:new entrants to the plan and the vesting of certain non-vested participants who were affected by the transition of service jobs to service providers. The Company had $3.5 million in other benefit plan amendments due to an increase in the Company's contribution to the retiree medical plan.
2 In 2002, the Company had a $9.5 million curtailment credit and $9.2 million in special adjustments to the pension benefit plan related to the transition of service jobs to service providers. The Company also had a $1.7 million special adjustment to the pension benefit plan related to the non-qualified pension benefit plan required to reflect the special benefit agreement given upon termination of a plan participant.
| (Dollars in thousands) | PUGET ENERGY | PSE | ||||||||
| At December 31 | Operating | Capital | Operating | |||||||
| 2002 | $26,368 | $2,486 | $20,176 | |||||||
| 2001 | 25,373 | 1,966 | 20,135 | |||||||
| 2000 | 18,239 | 653 | 18,239 | |||||||
Payments receivedIn accounting for pension and other benefit costs under the plans, the following weighted average actuarial assumptions were used:
| PENSION BENEFITS | OTHER BENEFITS | |||||
| 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |
| Discount rate | 6.25% | 6.75% | 7.25% | 6.25% | 6.75% | 7.25% |
| Return on plan assets | 8.25% | 8.25% | 9.50% | 6-7.00% | 6-7.00% | 6-8.25% |
| Rate of compensation increa | 4.50% | 4.50% | 5.0% | -- | -- | -- |
| Medical trend rate | -- | -- | -- | 9.00% | 10.00% | 6.50% |
The Company has used the expected return on plan assets based on an analysis of rates of return over the past 50 years relevant to 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.
| PENSION BENEFITS | OTHER BENEFITS | |||||||||||||||||||
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | ||||||||||||||
| Components of net periodic benefit cost: | ||||||||||||||||||||
| Service cost | $ | 8,284 | $ | 8,474 | $ | 9,862 | $ | 175 | $ | 168 | $ | 243 | ||||||||
| Interest cost | 24,406 | 25,858 | 26,734 | 1,828 | 1,930 | 2,022 | ||||||||||||||
| Expected return on plan assets | (38,880 | ) | (43,032 | ) | (46,222 | ) | (934 | ) | (906 | ) | (947 | ) | ||||||||
| Amortization of prior service cost | 3,220 | 2,990 | 2,960 | 309 | 90 | (34 | ) | |||||||||||||
| Recognized net actuarial gain | (2,688 | ) | (5,120 | ) | (7,570 | ) | (341 | ) | (229 | ) | (109 | ) | ||||||||
| Amortization of transition (asset) obligation | (1,104 | ) | (1,136 | ) | (1,230 | ) | 418 | 470 | 627 | |||||||||||
| Plan curtailment | -- | (1,353 | ) | -- | -- | 1,691 | -- | |||||||||||||
| Special recognition of prior service costs | 190 | 1,683 | 108 | -- | -- | -- | ||||||||||||||
| Net pension benefit cost (income) | $ | (6,572 | ) | $ | (11,636 | ) | $ | (15,358 | ) | $ | 1,455 | $ | 3,214 | $ | 1,802 | |||||
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the subleasenon-qualified pension plan, which has accumulated benefit obligations in excess of propertiesplan assets, were approximately $2.6$45.0 million, $2.5$38.6 million and $2.4$0, respectively, as of December 31, 2003. For the qualified pension plan the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $355.1 million, $339.7 million and $428.6 million, respectively, as of December 31, 2003.
The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year ended December 31, 2004 are $11.1 million and an insignificant amount, respectively. The full amount of the pension funding for 2004 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:
| 2003 | 2002 | |||
| PENSION BENEFITS | OTHER BENEFITS | PENSION BENEFITS | OTHER BENEFITS | |
| Short-term investments and cash | 3.0% | 100.0% | 4.1% | 100.0% |
| Equity securities | 63.8% | -- | 55.7% | -- |
| Fixed income securities | 22.9% | -- | 31.2% | -- |
| Mutual funds | 10.3% | -- | 9.0% | -- |
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 is as follows:
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009-2013 |
| Total benefits | $ 35,697 | $ 25,940 | $ 26,939 | $ 28,806 | $ 28,202 | $157,821 |
The assumed medical inflation rate is 9.0% in 2004 decreasing to 6.0% in 2007. A 1% change in the assumed medical inflation rate would have the following effects:
| 2003 | 2002 | |||||||||||||
| (DOLLARS IN THOUSANDS) | 1% INCREASE | 1% DECREASE | 1% INCREASE | 1% DECREASE | ||||||||||
| Effect on post-retirement benefit obligation | $ | 589 | $ | (529 | ) | $ | 580 | $ | (515 | ) | ||||
| Effect on service and interest cost components | 38 | (35 | ) | 36 | (32 | ) | ||||||||
The Company has a Retirement Committee that establishes investment policies, objectives and strategies for the purpose 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. 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 | |||
| ASSET CLASS | MINIMUM | TARGET | MAXIMUM |
| Domestic large capitalization equity securities | 30% | 42% | 50% |
| Domestic small capitalization equity securities | -- | 8% | 15% |
| Fixed-income securities | 20% | 30% | 40% |
| Foreign equity securities | 10% | 20% | 30% |
| Real estate | -- | -- | 10% |
| Short-term investments and cash | -- | -- | 5% |
NOTE 13.
Employee Investment Plans
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’s contributions to the Employee Investment Plans were $7.1 million, $6.9 million and $8.0 million for the years ended2003, 2002 and 2001, respectively.
PSE’s contributions to the Employee Investment Plan were $6.1 million, $6.1 million and $6.8 million for the years 2003, 2002 and 2001, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.
NOTE 14.
Stock-based Compensation Plans
The Company has various stock 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 will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Total compensation expense related to the plans was $6.4 million, $6.3 million and $2.1 million in 2003, 2002 and 2001, respectively.
The Company’s shareholder-approved Long-Term Incentive Plan (LTI Plan) encompasses many of the awards granted to employees. Established in 1995 and amended and restated in 1997, the LTI Plan applies to officers and key employees of the Company. Awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are purchased on the open market. The maximum number of shares that may be purchased for the LTI Plan is 1,200,000.
PERFORMANCE SHARE GRANTS
Each year the Company awards performance share grants under the LTI Plan. These are granted to key employees and vest at the end of four years with the final number of shares awarded depending on a performance measure. The Company records compensation expense related to the shares based on the performance measure and changes in the market price of the stock. Compensation expense related to performance share grants was $5.1 million, $5.5 million and $2.3 million for 2003, 2002 and 2001, respectively. The fair value of the performance awards granted in 2003, 2002 and 2001 was $17.29, $14.82 and $17.86, respectively. There were a total of 334,608 performance awards granted in 2003, 247,184 in 2002 and 183,881 in 2001. As of December 31, 2003, there are four active grant cycles for a total of 790,922 share grants outstanding although they may not all be awarded.
STOCK OPTIONS
In 2002, 2001,Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and 2000,an additional 260,000 options outside of the LTI Plan (for a total of 300,000 non-qualified stock options) to the president and chief executive officer. These options can be exercised at the grant date market price of $22.51 per share and vest yearly over four and five years although vesting is accelerated under certain conditions. The options expire 10 years from the grant date. All 300,000 options remained outstanding at December 31, 2003, with 67,500 options exercisable. No options were exercisable at December 31, 2002. The fair value of the options at the grant date was $3.37 per share. Following the intrinsic value method of APB 25, no compensation expense was recorded for these options. No additional options were granted in 2003.
RESTRICTED STOCK
In 2003 and 2002, the Company granted 11,000 shares and 30,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market. Of the 2003 shares issued, 1,000 shares vested in 2003. The remaining shares will vest evenly over the next five years. The 2002 shares were fully vested as of December 2003. In 2002 the Company also issued 50,000 shares of restricted stock outside of the LTI Plan as approved by the Puget Energy Board of Directors. These shares were recorded as a separate component of stockholders’ equity and vest evenly over a five-year period. Compensation expense related to the restricted shares was $0.6 million and $0.5 million in 2003 and 2002, respectively. Future minimum lease payments No restricted shares were issued in 2001. Dividends are paid on all outstanding restricted stock and are accounted for non-cancelable leases netas a Puget Energy stock dividend, not as compensation expense. The weighted average grant date fair value for all outstanding shares of sublease receipts are:
| (Dollars in thousands) | PUGET ENERGY | PSE | ||||||||
| At December 31 | Operating | Capital | Operating | |||||||
| 2003 | $18,208 | $2,040 | $12,644 | |||||||
| 2004 | 14,694 | 1,774 | 10,404 | |||||||
| 2005 | 9,065 | 1,441 | 6,446 | |||||||
| 2006 | 7,604 | 1,335 | 6,502 | |||||||
| 2007 | 6,998 | 821 | 6,468 | |||||||
| Thereafter | 9,497 | | 925 | | 9,350 | | ||||
| Total minimum lease payments | $66,066 | | $8,336 | | $51,814 | | ||||
Future minimum sublease receipts for non-cancelable subleases are $1 million for 2003.restricted stock granted in 2003 and 2002 was $23.29 and $21.94, respectively.
NOTE 11.Income Taxes
EMPLOYEE STOCK PURCHASE PLAN
The detailsCompany has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six-month intervals at the end of income taxeswhich the participating employees receive shares for 85% 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. Prior to 2002, the Company purchased shares for the plan on the open market. As of the second offering of 2002, the Company began issuing common stock for the ESPP rather than purchasing stock. In 2003, 38,940 shares were issued for the ESPP. In 2002, 18,252 shares were issued and 19,407 shares were purchased for the plan, and in 2001, 45,659 shares were purchased. At December 31, 2003, 259,662 shares may still be sold to employees under the plan. Under the SFAS No. 123 accounting that the Company adopted in 2003, ESPP is considered to be compensation expense. Total compensation expense related to the ESPP was $0.2 million in 2003. Dividends are not paid on ESPP shares until they are purchased by employees and thus are accounted for as follows:dividends, not compensation expense. The weighted average fair value of the purchase rights granted in 2003, 2002 and 2001 was $4.25, $4.19 and $4.35, respectively.
| (Dollars in thousands) | PUGET ENERGY 2002 | PSE 2002 | PUGET ENERGY 2001 | PSE 2001 | PUGET ENERGY AND PSE 2000 | ||||||||||||
| Charged to operating expense: | |||||||||||||||||
| Current - federal | $ | (84,149 | ) | $ | (81,839 | ) | $ | 58,749 | $ | 58,331 | $ | 128,138 | |||||
| Current - state | (774 | ) | (548 | ) | 1,347 | 1,232 | 832 | ||||||||||
| Deferred - net federal | 144,230 | 135,884 | 19,945 | 18,040 | 1,557 | ||||||||||||
| Deferred- net state | 614 | -- | 485 | -- | -- | ||||||||||||
| Deferred investment tax credits | (661 | ) | (661 | ) | (688 | ) | (688 | ) | (704 | ) | |||||||
| Total charged to operations | 59,260 | 52,836 | 79,838 | 76,915 | 129,823 | ||||||||||||
| Charged to miscellaneous income: | |||||||||||||||||
| Current | (3,276 | ) | (3,406 | ) | 6,272 | 6,272 | 7,843 | ||||||||||
| Deferred - net | 1,228 | 1,228 | (2,259 | ) | (2,259 | ) | (10,150 | ) | |||||||||
| Total charged to miscellaneous income | (2,048 | ) | (2,178 | ) | 4,013 | 4,013 | (2,307 | ) | |||||||||
| Cumulative effect of accounting change | -- | -- | (7,942 | ) | (7,942 | ) | -- | ||||||||||
| Total income taxes | $ | 57,212 | $ | 50,658 | $ | 75,909 | $ | 72,986 | $ | 127,516 | |||||||
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 2003, 2002 and 2001:
| 2003 | 2002 | 2001 | |||||||||||
| 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 | 2,643 | $ 4 | .31 | 1,995 | $ 4 | .05 | -- | $ -- | |||||
| Granted | 176 | 5 | .00 | 725 | 5 | .00 | 2,043 | 4 | .05 | ||||
| Exercised | -- | -- | -- | -- | -- | -- | |||||||
| Canceled | (201 | ) | 4 | .20 | (77 | ) | 4 | .09 | (48 | ) | 4 | .00 | |
| Outstanding at end of year | 2,618 | $ 4 | .36 | 2,643 | $ 4 | .31 | 1,995 | $ 4 | .05 | ||||
| Options exercisable at year end | 1,837 | $ 4 | .12 | 802 | $ 4 | .02 | 791 | $ 4 | .00 | ||||
| Weighted average fair value of options granted during the year | $2.41 | $2.23 | $1.60 | ||||||||||
The following issummarizes InfrastruX's outstanding option information at December 31, 2003:
| Shares Outstanding (in thousands) | Weighted Average Contractual Life (in years) | Weighted Average Exercise Price | ||
| Exercise Prices | ||||
| $4.00 | 1,666 | 7.11 | $4.00 | |
| $5.00 | 952 | 8.42 | 5.00 | |
| 2,618 | 7.59 | $4.36 | ||
Stock options awarded under the InfrastruX plan were generally granted at the InfrastruX market price on the date of grant although some options have been granted at a reconciliationdiscount requiring InfrastruX to record compensation expense. With the prospective adoption of SFAS No. 123 fair value accounting in 2003, InfrastruX also recorded compensation expense related to options granted in 2003. Compensation expense of $0.2 million and $0.1 million related to stock options was recorded in 2003 and 2002, respectively.
NON-EMPLOYEE DIRECTOR STOCK PLAN
The Company has a director stock plan created in 1998 for all non-employee directors of Puget Energy and PSE. Under the plan which has a 10-year term, non-employee directors receive a minimum of two-thirds of their quarterly retainer fees in Company stock except that 100% of quarterly retainers are paid in Company stock until the director holds a number of shares equal to two years of common stock in value of their retainer. Directors may optionally receive their entire retainer in Company stock. The compensation expense related to the director stock plan was $0.4 million, $0.2 million and $0.1 million in 2003, 2002 and 2001, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 100,000 shares. As of December 31, 2003, 9,902 shares had been purchased for the director stock plan and 48,219 deferred, for a total of 58,121 shares.
OTHER PLANS
In addition to current stock compensation plans, the Company also has outstanding shares related to two plans that were in effect prior to the 1997 merger between Puget Sound Power and Light (PSP&L) and Washington Energy Company (WECO). There are 2,400 vested, unexercised stock appreciation rights from the PSP&L Incentive Plan Awards granted to executives of PSP&L. These were granted in 1994, have an exercise price of $20.75 and expire 10 years after the grant date. There are also 11,301 vested, unexercised options from the WECO Incentive Stock Option Plan granted to key employees of WECO. The options were granted between 1994 and 1996 with exercise prices ranging from $15.55 to $23.11 and expire 10 years from the date of grant. These are generally paid out as stock appreciation rights at the discretion of the grantees. The Company records compensation expense each quarter related to the PSP&L and WECO shares as the difference between the exercise price and the current market price. Compensation expense related to the WECO plan was immaterial in 2003 and 2002, and $(0.2) million in 2001. Compensation expense related to the PSP&L plan was immaterial in 2003 and 2002, and $(0.1) million in 2001.
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 granted in 2003, 2002 and 2001:
| 2003 | 2002 | 2001 | |||||
| Stock options | |||||||
| Risk-free interest rate | -- | 4 | .32% | -- | |||
| Expected lives - years | -- | 4 | .50 | -- | |||
| Expected stock volatility | -- | 23 | .62% | -- | |||
| Dividend yield | -- | 5 | .00% | -- | |||
| InfrastruX stock option plan | |||||||
| Risk-free interest rate | 2 | .80% | 4 | .05% | 4 | .87% | |
| Expected lives - years | 4 | .00 | 4 | .00 | 4 | .00 | |
| Expected stock volatility | 60 | .00% | 60 | .00% | 50 | .00% | |
| Performance awards | |||||||
| Risk-free interest rate | 2 | .35% | 4 | .00% | 4 | .99% | |
| Expected lives - years | 4 | .00 | 4 | .00 | 4 | .00 | |
| Expected stock volatility | 23 | .85% | 23 | .71% | 20 | .76% | |
| Dividend yield | 4 | .86% | 8 | .85% | 7 | .67% | |
| Employee Stock Purchase Plan | |||||||
| Risk-free interest rate | 1 | .07% | 1 | .65% | 4 | .26% | |
| Expected lives - years | 0 | .50 | 0 | .50 | 0 | .50 | |
| Expected stock volatility | 19 | .47% | 26 | .97% | 19 | .04% | |
| Dividend yield | 4 | .39% | 5 | .81% | 7 | .72% | |
NOTE 15.
Accounting for Derivative Instruments and Hedging Activities
The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income taxes computedstatement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
In addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with no significant impact on the financial statements.
On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by multiplying pre-tax bookrecording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the statutory taxoriginal counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.
NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)
During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of cash and preferred or common stock. The 2003 acquisition includes a contingency which requires InfrastruX to make additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
These companies provide utility infrastructure services which are relevant 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 for 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 $7.7 million in 2003 and $23.5 million in 2002.
During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to the annual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 |
| Reported income for common stock | $ 116,197 | $ 110,052 | $ 98,426 |
| Add back goodwill amortization, net of tax | -- | -- | 2,826 |
| Adjusted income for common stock | $ 116,197 | $ 110,052 | $ 101,252 |
| Basic earnings per share | |||
| Reported income for common stock | $ 1.23 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.23 | $ 1.24 | $ 1.17 |
| Diluted earnings per share | |||
| Reported income for common stock | $ 1.22 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.22 | $ 1.24 | $ 1.17 |
Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 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 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 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. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.
| AT DECEMBER 31, 2003 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | 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 | |
| AT DECEMBER 31, 2002 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | Net Intangibles | |
| Covenant not to compete | $ 3,908 | $1,105 | $ 2,803 | |
| Developed technology | 14,190 | 1,744 | 12,446 | |
| Contractual customer relationships | 3,042 | 383 | 2,659 | |
| Patents | 793 | 49 | 744 | |
| Total | $21,933 | $3,281 | $18,652 | |
The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 |
| Future intangible amortization | $ 2,101 | $ 2,075 | $ 1,746 | $ 1,363 | $ 1,340 |
The pro forma combined revenues, 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, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.
| (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) FOR THE YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 |
| Operating revenues | $ 2,505,523 | $ 2,469,122 | $ 3,056,824 |
| Net income for common | 116,636 | 112,813 | 104,338 |
| Basic earnings per common share | $ 1.23 | $ 1.28 | $ 1.21 |
| Diluted earnings per common share | $ 1.22 | $ 1.27 | $ 1.20 |
NOTE 17.
Other
PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.
NOTE 18.
Commitments and Contingencies
COMMITMENTS – ELECTRIC
For the year ended December 31, 2003, approximately 19.9% of the Company’s energy output was obtained at an average cost of approximately $0.01641 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” basis under which the Company pays a proportionate share of the annual cost of each project in direct proportion to the amount of income taxespower annually purchased by the Company from such project. Such payments are not contingent upon the projects being operable. 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, 2003, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:
| BONDS OUTSTANDING | COMPANY'S ANNUAL AMOUNT PURCHASABLE (APPROXIMATE) | ||||||||||||
| PROJECT | CONTRACT EXP. DATE | LICENSE1 EXP. DATE | 12/31/032 (MILLIONS) | % OF OUTPUT | MEGAWATT CAPACITY | COSTS3 (MILLIONS) | |||||||
| Rock Island | |||||||||||||
| Original units | 2012 | 2029 | $ 121 | .7 | 50.0 | 414 | $ 41 | .9 | |||||
| Additional units | 2012 | 2029 | 331 | .5 | 75.0 | ||||||||
| Rocky Reach | 2011 | 2006 | 394 | .7 | 38.9 | 505 | 29 | .6 | |||||
| Wells | 2018 | 2012 | 151 | .3 | 31.3 | 261 | 6 | .9 | |||||
| Priest Rapids4 | 2005 | 2005 | 184 | .7 | 8.0 | 72 | 2 | .6 | |||||
| Wanapum4 | 2009 | 2005 | 186 | .5 | 10.8 | 98 | 4 | .1 | |||||
| Total | $ 1,370 | .4 | 1,350 | $ 85 | .1 | ||||||||
The Company’s estimated payments for power purchases from the Columbia River are $84.6 million for 2004, $81.4 million for 2005, $78.4 million for 2006, $81.4 million for 2007, $82.6 million for 2008 and in the aggregate, $123.5 million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with other utilities in 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 $76.0 million for 2004, $77.7 million for 2005, $78.6 million for 2006, $80.7 million for 2007, $82.6 million for 2008 and in the aggregate, $433.3 million thereafter through 2037. 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 $211.4 million for 2004, $217.3 million for 2005, $232.9 million for 2006, $211.9 million for 2007, $212.1 million for 2008 and in the aggregate, $746.0 million thereafter through 2012.
The following table summarizes the Company’s estimated obligations for future power purchases:
| (DOLLARS IN MILLIONS) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 & THERE- AFTER | TOTAL |
| Columbia River projects | $ 84.6 | $ 81.4 | $ 78.4 | $ 81.4 | $ 82.6 | $ 123.5 | $ 531.9 |
| Other utilities | 76.0 | 77.7 | 78.6 | 80.7 | 82.6 | 433.3 | 828.9 |
| Non-utility generators | 211.4 | 217.3 | 232.9 | 211.9 | 212.1 | 746.0 | 1,831.6 |
| Total | $ 372.0 | $ 376.4 | $ 389.9 | $ 374.0 | $ 377.3 | $ 1,302.8 | $ 3,192.4 |
| 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 affirm the Company'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, 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: 43.7% at Rock Island; 58.3% at Rocky Reach; 94.5% at Priest Rapids; 79.6% at Wanapum; and 6.2% at Wells. |
| 3 | The components of 2003 costs associated with the interest portion of debt service are: Rock Island, $22.6 million for all units; Rocky Reach, $9.4 million; Wells, $8.2 million; Priest Rapids, $0.8 million; and Wanapum, $0.6 million. |
| 4 | 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 contract 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 Act 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, it 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 has been requested. |
Total purchased power contracts provided the Company with approximately 11.0 million, 12.1 million and 11.9 million MWh of firm energy at a cost of approximately $479.2 million, $466.1 million and $496.3 million for the years 2003, 2002 and 2001, 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, 2003:
| COMPANY'S SHARE | ||||||||||||||
| (DOLLARS IN MILLIONS) | ENERGY SOURCE (FUEL) | COMPANY'S OWNERSHIP SHARE | PLANT IN SERVICE AT COST | ACCUMULATED DEPRECIATION | ||||||||||
| Colstrip 1 & 2 | Coal | 50% | $ 207 | $ 133 | ||||||||||
| Colstrip 3 & 4 | Coal | 25% | 464 | 240 | ||||||||||
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 IncomeIncome.
PSE and PPL Montana, the other owner of Colstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s PCA mechanism.
On October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE used the coal as fuel for its share of Units 3 & 4 of the Colstrip generating plant. PSE’s coal price for that period was reduced by a settlement PSE and Western Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the Company:federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.
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 per day of natural gas for operation of Tenaska’s 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 $22.0 million in 2004.
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 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
| (Dollars in thousands) | PUGET ENERGY 2002 | PSE 2002 | PUGET ENERGY 2001 | PSE 2001 | PUGET ENERGY AND PSE 2000 | ||||||||||||
| Income taxes at the statutory rate | $ | 61,587 | $ | 55,862 | $ | 63,962 | $ | 62,079 | $ | 112,471 | |||||||
| Increase (decrease): | |||||||||||||||||
| Depreciation expense deducted in the | |||||||||||||||||
| financial statements in excess of tax | |||||||||||||||||
| depreciation, net of depreciation | |||||||||||||||||
| treated as a temporary difference | 10,041 | 10,041 | 11,726 | 11,726 | 10,807 | ||||||||||||
| AFUDC included in income in the financial | |||||||||||||||||
| statements but excluded from taxable income | (1,387 | ) | (1,387 | ) | (2,126 | ) | (2,126 | ) | (3,274 | ) | |||||||
| Accelerated benefit on early retirement | |||||||||||||||||
| of depreciable assets | (1,469 | ) | (1,469 | ) | (319 | ) | (319 | ) | (834 | ) | |||||||
| Investment tax credit amortization | (661 | ) | (661 | ) | (689 | ) | (689 | ) | (704 | ) | |||||||
| Energy conservation expenditures - net | 6,259 | 6,259 | 6,859 | 6,859 | 10,634 | ||||||||||||
| Tax benefit of reduced salvage values | (10,193 | ) | (10,193 | ) | -- | -- | -- | ||||||||||
| State income taxes net of the federal income tax benefit | (104 | ) | (356 | ) | 1,191 | 801 | 541 | ||||||||||
| Other - net | (6,861 | ) | (7,438 | ) | (4,695 | ) | (5,345 | ) | (2,125 | ) | |||||||
| Total income taxes | $ | 57,212 | $ | 50,658 | $ | 75,909 | $ | 72,986 | $ | 127,516 | |||||||
| Effective tax rate | 32.5 | % | 31.7 | % | 41.5 | % | 41.1 | % | 39.7 | % | |||||||
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 $8.5 million in 2004, $8.7 million in 2005, $9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter. 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 of 6.5 years. The obligations under these contracts are $15.9 million in 2004, $16.7 million in 2005, $17.5 million in 2006, $18.4 million in 2007 and $12.9 million in the aggregate thereafter.
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. Commitments under these contracts are $3.0million in 2004, $10.3 million in 2005, $1.1 million in 2006, $0.4 million in 2007 and $0.1 million thereafter.
GAS 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 20 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Two of PSE’s long-term firm gas supply agreements, that expire November 2004, obligate the Company to purchase a minimum annual quantity at market-based contract prices. If the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. PSE didn’t incur such charges in 2003. The Company incurred demand charges in 2003 for firm gas supply, firm transportation service and firm storage and peaking service of $24.7 million, $47.9 million and $5.3 million, respectively. WNG Cap I incurred demand charges in 2003 for firm transportation service of $9.4 million.
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) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 & THERE- AFTER | TOTAL |
| Firm gas supply | $ 18.7 | $ 1.5 | $ 1.0 | $ 0.5 | $ 0.5 | $ 1.5 | $ 23.7 |
| Firm transportation service | 66.6 | 58.8 | 57.0 | 57.0 | 48.0 | 122.7 | 410.1 |
| Firm storage service | 11.3 | 11.6 | 7.8 | 7.7 | 7.7 | 48.2 | 94.3 |
| Total | $ 96.6 | $ 71.9 | $ 65.8 | $ 65.2 | $ 56.2 | $ 172.4 | $ 528.1 |
SERVICE CONTRACT
On August 30, 2001, PSE and Alliance Data Systems Corp. announced a contract under which Alliance Data will provide data processing and billing services for PSE. In providing services to PSE under the principal components10-year agreement, Alliance Data will use ConsumerLinX software, PSE’s customer-information software developed by its ConneXt subsidiary. Alliance Data acquired the assets of income taxesConneXt, including the exclusive use of the ConsumerLinX software for five years with an option for renewal. Alliance Data will offer ConsumerLinX as reported:part of its integrated, single-source customer relationship management solution for large-scale, regulated utility clients. The obligations under the contract are $21.7 million in 2004, $22.2 million in 2005, $22.8 million in 2006, $23.4 million in 2007, $24.0 million in 2008 and $66.9 million in the aggregate thereafter.
| (Dollars in thousands) | PUGET ENERGY 2002 | PSE 2002 | PUGET ENERGY 2001 | PSE 2001 | PUGET ENERGY AND PSE 2000 | ||||||||||||
| Current income taxes - federal | $ | (87,425 | ) | $ | (85,245 | ) | $ | 65,021 | $ | 64,603 | $ | 135,981 | |||||
| Current income taxes - state | (774 | ) | (548 | ) | 1,347 | 1,232 | 832 | ||||||||||
| Deferred income taxes: | |||||||||||||||||
| Conservation tax settlement | -- | -- | 963 | 963 | 1,776 | ||||||||||||
| Deferred FAS-133 | 4,064 | 4,064 | (4,028 | ) | (4,028 | ) | -- | ||||||||||
| Cabot preferred stock sale | -- | -- | -- | -- | (10,635 | ) | |||||||||||
| Deferred taxes related to insurance reserves | (1,662 | ) | (1,662 | ) | (1,225 | ) | (1,225 | ) | (384 | ) | |||||||
| Residential Purchase and Sale Agreement - net | -- | -- | 3,390 | 3,390 | 2,226 | ||||||||||||
| Normalized tax benefits of the | |||||||||||||||||
| accelerated cost recovery system | 29,197 | 29,197 | 11,423 | 11,423 | 10,931 | ||||||||||||
| Energy conservation program | (96 | ) | (96 | ) | (1,337 | ) | (1,337 | ) | (1,666 | ) | |||||||
| Environmental remediation | 1,392 | 1,392 | 1,326 | 1,326 | 721 | ||||||||||||
| WNP 3 tax settlement | (1,126 | ) | (1,126 | ) | (1,126 | ) | (1,126 | ) | (1,126 | ) | |||||||
| Demand charges | (8 | ) | (8 | ) | (98 | ) | (98 | ) | (79 | ) | |||||||
| Deferred revenue | 612 | 612 | (5,904 | ) | (5,904 | ) | -- | ||||||||||
| Software amortization | 35,373 | 35,373 | -- | -- | -- | ||||||||||||
| Capitalized overhead costs deducted for tax purposes | 72,220 | 72,220 | -- | -- | -- | ||||||||||||
| Allowance for doubtful accounts | -- | -- | -- | -- | (13,821 | ) | |||||||||||
| Other | 6,106 | (2,854 | ) | 6,845 | 4,455 | 3,464 | |||||||||||
| Total deferred income taxes | 146,072 | 137,112 | 10,229 | 7,839 | (8,593 | ) | |||||||||||
| Deferred investment tax credits - | |||||||||||||||||
| net of amortization | (661 | ) | (661 | ) | (688 | ) | (688 | ) | (704 | ) | |||||||
| Total income taxes | $ | 57,212 | $ | 50,658 | $ | 75,909 | $ | 72,986 | $ | 127,516 | |||||||
SURETY BOND
The Company has a self-insurance surety bond in the amount of $5.9 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.
ENVIRONMENTAL
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 these 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. The Company believes a significant portion of its past and future environmental remediation costs are 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, 2003.
ELECTRIC SITES
The Company has expended approximately $18.1 million related to the remediation activities covered by the Washington Commission’s order and has accrued approximately $1.6 million as a liability for future remediation costs for these and other remediation activities. To date, the Company has recovered approximately $18.8 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 deferred tax liabilityfinancial position, operating results or cash flow trends.
GAS SITES
The Company has expended approximately $65.9 million related to the remediation activities covered by a Washington Commission order and has accrued approximately $32.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $59.6 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.
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 trends.
LITIGATION
There are several actions in the U.S. Ninth Circuit Court of Appeals 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, a number of contracts, including the amended settlement agreement regarding the Residential Purchase and Sale Program and the conditional settlement agreements between BPA and PSE which modified the payment provisions of the Residential Purchase and Sale Program. BPA rates used in such amended settlement agreement between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits 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 may have on PSE.
Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 20022003. 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.
NOTE 19.
Segment Information
Puget Energy operates in primarily two business segments: regulated utility operations, or PSE, and construction services, or InfrastruX. 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 State of Washington. InfrastruX specializes in construction services to other gas and electric utilities primarily in the south/Texas and the north-central and eastern United States.
One minor non-utility business segment, a PSE subsidiary, which is a real estate investment and development company is described as other. The assets of ConneXt, the development and marketing of customer information and billing system software segment, were sold during the third quarter of 2001. The third quarter results of 2001 is comprised of amountsincluded an $8.0 million after-tax gain related to the following types of temporary differences:
| (Dollars in thousands) | PUGET ENERGY 2002 | PSE 2002 | PUGET ENERGY 2001 | PSE 2001 | ||||||||||
| Utility plant | $ | 578,137 | $ | 578,137 | $ | 570,982 | $ | 570,982 | ||||||
| Energy conservation charges | 16,473 | 16,473 | 23,782 | 23,782 | ||||||||||
| Contributions in aid of construction | (44,770 | ) | (44,770 | ) | (36,044 | ) | (36,044 | ) | ||||||
| Bonneville Exchange Power | 15,537 | 15,537 | 17,897 | 17,897 | ||||||||||
| Cabot gas contract purchase | 4,157 | 4,157 | 4,477 | 4,477 | ||||||||||
| Deferred revenue | (5,292 | ) | (5,292 | ) | (5,904 | ) | (5,904 | ) | ||||||
| Software amortization | 41,408 | 41,408 | -- | -- | ||||||||||
| Capitalized overhead costs | 72,220 | 72,220 | -- | -- | ||||||||||
| Other | 52,805 | 37,709 | 30,125 | 25,811 | ||||||||||
| Total | $ | 730,675 | $ | 715,579 | $ | 605,315 | $ | 601,001 | ||||||
Puget Energy’s totals of $730.7 million and $605.3 million for 2002 and 2001 consist of deferred tax liabilities of $841.7 million and $713.8 million net of deferred tax assets of $111.0 million and $108.5 million, respectively. PSE’s totals of $715.6 million and $601.0 million for 2002 and 2001 consist of deferred tax liabilities of $824.2 million and $707.4 million net of deferred tax assets of $108.6 million and $106.4 million, respectively. Deferred tax amounts shown above result from temporary differences for tax and financial statement purposes. Deferred tax provisionsConneXt sale. Reconciling items between segments are not recorded in the income statementsignificant.
Financial data for certain temporary differences between tax and financial statement purposes because theybusiness segments are not allowed for ratemaking purposes.as follows:
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||
| 2003 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $2,143,693 | $341,787 | $ 6,043 | $2,491,523 |
| 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 | 121,348 |
| Goodwill, net | -- | 133,302 | -- | 133,302 |
| Total assets | 5,257,157 | 342,332 | 75,196 | 5,674,685 |
| Construction expenditures - excluding equity AFUDC | 269,973 | -- | -- | 269,973 |
| Additions to other property, plant and equipment | -- | 15,536 | -- | 15,536 |
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||
| 2002 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $2,063,040 | $319,529 | $ 9,753 | $2,392,322 |
| Depreciation and amortization | 215,097 | 13,426 | 220 | 228,743 |
| Income tax | 50,600 | 6,703 | 1,957 | 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 | 117,883 |
| 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 |
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||
| 2001 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $2,680,298 | $173,786 | $ 32,476 | $2,886,560 |
| Depreciation and amortization | 208,705 | 8,820 | 15 | 217,540 |
| Income tax | 68,005 | 2,956 | 8,877 | 79,838 |
| Operating income | 273,751 | 8,702 | 14,668 | 297,121 |
| Interest charges, net of AFUDC | 186,403 | 3,656 | -- | 190,059 |
| Net income | 80,137 | 2,518 | 24,184 | 106,839 |
| Goodwill, net | -- | 102,151 | -- | 102,151 |
| Total assets | 5,300,105 | 229,125 | 139,251 | 5,668,481 |
| Construction expenditures - excluding equity AFUDC | 247,435 | -- | -- | 247,435 |
| Additions to other property, plant and equipment | -- | 5,193 | -- | 5,193 |
NOTE 12.20.
Retirement Benefits
The Company has a defined benefit pension plan with a cash balance feature covering substantially all of its utility employees. Benefits are a function of both age, salary and salary.service. Additionally, Puget Energy 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 | PENSION BENEFITS | OTHER BENEFITS | ||||||||||||||||||||||||||
| (Dollars in thousands) | 2002 | 2001 | 2002 | 2001 | |||||||||||||||||||||||||
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2003 | 2002 | |||||||||||||||||||||||||
| Change in benefit obligation: | |||||||||||||||||||||||||||||
| Benefit obligation at beginning of year | $ | 400,461 | $ | 366,482 | $ | 29,115 | $ | 27,568 | $ | 369,692 | $ | 400,461 | $ | 31,693 | $ | 29,115 | |||||||||||||
| Service cost | 8,474 | 9,862 | 168 | 243 | 8,284 | 8,474 | 175 | 168 | |||||||||||||||||||||
| Interest cost | 25,858 | 26,734 | 1,930 | 2,022 | 24,406 | 25,858 | 1,828 | 1,930 | |||||||||||||||||||||
| Amendments1 | 3,073 | 3,984 | 3,493 | -- | 940 | 3,073 | -- | 3,493 | |||||||||||||||||||||
| Actuarial loss | 2,055 | 15,417 | (419 | ) | 1,101 | 19,354 | 2,055 | (2,194 | ) | (419 | ) | ||||||||||||||||||
| Plan curtailment2 | (9,518 | ) | -- | (553 | ) | -- | -- | (9,518 | ) | -- | (553 | ) | |||||||||||||||||
| Special adjustments2 | 10,872 | -- | -- | -- | 190 | 10,872 | -- | -- | |||||||||||||||||||||
| Benefits paid | (71,583 | ) | (22,018 | ) | (2,041 | ) | (1,819 | ) | (22,825 | ) | (71,583 | ) | (2,282 | ) | (2,041 | ) | |||||||||||||
| Benefit obligation at end of year | $ | 369,692 | $ | 400,461 | $ | 31,693 | $ | 29,115 | $ | 400,041 | $ | 369,692 | $ | 29,220 | $ | 31,693 | |||||||||||||
| Change in plan assets: | |||||||||||||||||||||||||||||
| Fair value of plan assets at beginning of year | $ | 443,512 | $ | 496,468 | $ | 15,978 | $ | 15,661 | |||||||||||||||||||||
| Fair value of plan assets at beginning | $ | 343,960 | $ | 443,512 | $ | 16,160 | $ | 15,978 | |||||||||||||||||||||
| Actual return on plan assets | (40,849 | ) | (32,025 | ) | 650 | 595 | 79,488 | (40,849 | ) | 98 | 650 | ||||||||||||||||||
| Employer contribution | 12,880 | 1,087 | 1,573 | 1,541 | 27,963 | 12,880 | 1,455 | 1,573 | |||||||||||||||||||||
| Benefits paid | (71,583 | ) | (22,018 | ) | (2,041 | ) | (1,819 | ) | (22,825 | ) | (71,583 | ) | (2,282 | ) | (2,041 | ) | |||||||||||||
| Fair value of plan assets at end of year | $ | 343,960 | $ | 443,512 | $ | 16,160 | $ | 15,978 | |||||||||||||||||||||
| Fair value of plan assets at end of yea | $ | 428,586 | $ | 343,960 | $ | 15,431 | $ | 16,160 | |||||||||||||||||||||
| Funded status | $ | (25,732 | ) | $ | 43,051 | $ | (15,533 | ) | $ | (13,137 | ) | $ | 28,545 | $ | (25,732 | ) | $ | (13,789 | ) | $ | (15,533 | ) | |||||||
| Unrecognized actuarial gain | 66,784 | (27,035 | ) | (1,878 | ) | (1,944 | ) | ||||||||||||||||||||||
| Unrecognized actuarial gain (loss) | 48,217 | 66,784 | (2,895 | ) | (1,878 | ) | |||||||||||||||||||||||
| Unrecognized prior service cost | 18,228 | 20,250 | 3,021 | (361 | ) | 15,949 | 18,228 | 2,712 | 3,021 | ||||||||||||||||||||
| Unrecognized net initial (asset)/obligation | (2,371 | ) | (3,873 | ) | 4,201 | 6,894 | |||||||||||||||||||||||
| Unrecognized net initial (asset) obliga | (1,267 | ) | (2,371 | ) | 3,783 | 4,201 | |||||||||||||||||||||||
| Net amount recognized | $ | 56,909 | $ | 32,393 | $ | (10,189 | ) | $ | (8,548 | ) | $ | 91,444 | $ | 56,909 | $ | (10,189 | ) | $ | (10,189 | ) | |||||||||
| Amounts recognized on statement of | |||||||||||||||||||||||||||||
| financial position consist of: | |||||||||||||||||||||||||||||
| Prepaid benefit cost | $ | 73,361 | $ | 54,335 | $ | (10,189 | ) | $ | (8,548 | ) | $ | 112,737 | $ | 73,361 | $ | (10,189 | ) | $ | (10,189 | ) | |||||||||
| Accrued benefit liability | (34,253 | ) | (37,002 | ) | -- | -- | (38,704 | ) | (34,253 | ) | -- | -- | |||||||||||||||||
| Intangible asset | 10,555 | 9,912 | -- | -- | 9,043 | 10,555 | -- | -- | |||||||||||||||||||||
| Accumulated other comprehensive income | 7,246 | 5,148 | -- | -- | 8,368 | 7,246 | -- | -- | |||||||||||||||||||||
| Net amount recognized | $ | 56,909 | $ | 32,393 | $ | (10,189 | ) | $ | (8,548 | ) | $ | 91,444 | $ | 56,909 | $ | (10,189 | ) | $ | (10,189 | ) | |||||||||
1 In 2002, the Company had $3.1 million in pension benefit plan amendments due to changes in employment contracts, the addition of new entrants to the plan and the vesting of certain non-vested participants who were affected by the transition of service jobs to service providers. The Company had $3.5 million in other benefit plan amendments due to an increase in the Company's contribution to the retiree medical plan.
2 In 2002, the Company had a $9.5 million curtailment credit and $9.2 million in special adjustments to the pension benefit plan related to the transition of service jobs to service providers. The Company also had a $1.7 million special adjustment to the pension benefit plan related to the non-qualified pension benefit plan required to reflect the special benefit agreement given upon termination of a plan participant.
In accounting for pension and other benefitsbenefit costs under the plans, the following weighted average actuarial assumptions were used:
| PENSION BENEFITS | OTHER BENEFITS | |||||
| | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 |
| Discount rate | 6.75% | 7.25% | 7.5% | 6.75% | 7.25% | 7.5% |
| Return on plan assets | 8.25% | 9.50% | 9.75% | 6-7.00% | 6-8.25% | 6-8.5% |
| Rate of compensation increase | 4.50% | 5.0% | 5.0% | -- | -- | -- |
| Medical trend rate | -- | -- | -- | 10.00% | 6.5% | 7.0% |
|
|
| PENSION BENEFITS | OTHER BENEFITS | |||||
| 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |
| Discount rate | 6.25% | 6.75% | 7.25% | 6.25% | 6.75% | 7.25% |
| Return on plan assets | 8.25% | 8.25% | 9.50% | 6-7.00% | 6-7.00% | 6-8.25% |
| Rate of compensation increa | 4.50% | 4.50% | 5.0% | -- | -- | -- |
| Medical trend rate | -- | -- | -- | 9.00% | 10.00% | 6.50% |
| PENSION BENEFITS | OTHER BENEFITS | |||||||||||||||||||||||||||||
| (Dollars in thousands) | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | ||||||||||||||||||||||||
| Components of net periodic benefit cost: | ||||||||||||||||||||||||||||||
| Service cost | $ | 8,474 | $ | 9,862 | $ | 9,005 | $ | 168 | $ | 243 | $ | 224 | ||||||||||||||||||
| Interest cost | 25,858 | 26,734 | 25,500 | 1,930 | 2,022 | 1,965 | ||||||||||||||||||||||||
| Expected return on plan assets | (43,032 | ) | (46,222 | ) | (42,280 | ) | (906 | ) | (947 | ) | (892 | ) | ||||||||||||||||||
| Amortization of prior service cost | 2,990 | 2,960 | 2,884 | 90 | (34 | ) | (34 | ) | ||||||||||||||||||||||
| Recognized net actuarial gain | (5,120 | ) | (7,570 | ) | (6,851 | ) | (229 | ) | (109 | ) | (195 | ) | ||||||||||||||||||
| Amortization of transition | ||||||||||||||||||||||||||||||
| (asset)/obligation | (1,136 | ) | (1,230 | ) | (1,230 | ) | 470 | 627 | 627 | |||||||||||||||||||||
| Plan curtailment | (1,353 | ) | -- | -- | 1,691 | -- | -- | |||||||||||||||||||||||
| Special recognition of prior service costs | 1,683 | 108 | 77 | -- | -- | -- | ||||||||||||||||||||||||
| Net pension benefit cost (income) | $ | (11,636 | ) | $ | (15,358 | ) | $ | (12,895 | ) | $ | 3,214 | $ | 1,802 | $ | 1,695 | |||||||||||||||
The Company has used the expected return on plan assets based on an analysis of rates of return over the past 50 years relevant to 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.
| PENSION BENEFITS | OTHER BENEFITS | |||||||||||||||||||
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | ||||||||||||||
| Components of net periodic benefit cost: | ||||||||||||||||||||
| Service cost | $ | 8,284 | $ | 8,474 | $ | 9,862 | $ | 175 | $ | 168 | $ | 243 | ||||||||
| Interest cost | 24,406 | 25,858 | 26,734 | 1,828 | 1,930 | 2,022 | ||||||||||||||
| Expected return on plan assets | (38,880 | ) | (43,032 | ) | (46,222 | ) | (934 | ) | (906 | ) | (947 | ) | ||||||||
| Amortization of prior service cost | 3,220 | 2,990 | 2,960 | 309 | 90 | (34 | ) | |||||||||||||
| Recognized net actuarial gain | (2,688 | ) | (5,120 | ) | (7,570 | ) | (341 | ) | (229 | ) | (109 | ) | ||||||||
| Amortization of transition (asset) obligation | (1,104 | ) | (1,136 | ) | (1,230 | ) | 418 | 470 | 627 | |||||||||||
| Plan curtailment | -- | (1,353 | ) | -- | -- | 1,691 | -- | |||||||||||||
| Special recognition of prior service costs | 190 | 1,683 | 108 | -- | -- | -- | ||||||||||||||
| Net pension benefit cost (income) | $ | (6,572 | ) | $ | (11,636 | ) | $ | (15,358 | ) | $ | 1,455 | $ | 3,214 | $ | 1,802 | |||||
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the non-qualified pension plan, which has accumulated benefit obligations in excess of plan assets, were $39.4$45.0 million, $34.2$38.6 million and $0, respectively, as of December 31, 2002.2003. For the qualified pension plan the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $330.3$355.1 million, $310.1$339.7 million and $344.0$428.6 million, respectively, as of December 31, 2002.2003.
The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year ended December 31, 2004 are $11.1 million and an insignificant amount, respectively. The full amount of the pension funding for 2004 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:
| 2003 | 2002 | |||
| PENSION BENEFITS | OTHER BENEFITS | PENSION BENEFITS | OTHER BENEFITS | |
| Short-term investments and cash | 3.0% | 100.0% | 4.1% | 100.0% |
| Equity securities | 63.8% | -- | 55.7% | -- |
| Fixed income securities | 22.9% | -- | 31.2% | -- |
| Mutual funds | 10.3% | -- | 9.0% | -- |
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 is as follows:
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009-2013 |
| Total benefits | $ 35,697 | $ 25,940 | $ 26,939 | $ 28,806 | $ 28,202 | $157,821 |
The assumed medical inflation rate is 10.0%9.0% in 20032004 decreasing 1.0% per year to 6.0%. in 2007. A 1% change in the assumed medical inflation rate would have the following effects:
| 2002 | 2001 | |||||||||||||
| 1% | 1% | 1% | 1% | |||||||||||
| (Dollars in thousands) | INCREASE | DECREASE | INCREASE | DECREASE | ||||||||||
| Effect on service and interest cost components | $ | 580 | $ | (515 | ) | $ | 625 | $ | (558 | ) | ||||
| Effect on post retirement benefit obligation | 36 | (32 | ) | 47 | (42 | ) | ||||||||
| 2003 | 2002 | |||||||||||||
| (DOLLARS IN THOUSANDS) | 1% INCREASE | 1% DECREASE | 1% INCREASE | 1% DECREASE | ||||||||||
| Effect on post-retirement benefit obligation | $ | 589 | $ | (529 | ) | $ | 580 | $ | (515 | ) | ||||
| Effect on service and interest cost components | 38 | (35 | ) | 36 | (32 | ) | ||||||||
The Company has a Retirement Committee that establishes investment policies, objectives and strategies for the purpose 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. 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 | |||
| ASSET CLASS | MINIMUM | TARGET | MAXIMUM |
| Domestic large capitalization equity securities | 30% | 42% | 50% |
| Domestic small capitalization equity securities | -- | 8% | 15% |
| Fixed-income securities | 20% | 30% | 40% |
| Foreign equity securities | 10% | 20% | 30% |
| Real estate | -- | -- | 10% |
| Short-term investments and cash | -- | -- | 5% |
NOTE 13.
Employee Investment Plans and Employee Stock Purchase Plan
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’s contributions to the Employee Investment Plans were $7.1 million, $6.9 million $8.0 million, and $7.2$8.0 million for the years 2003, 2002 2001 and 2000,2001, respectively.
PSE’s contributions to the Employee Investment Plan were $6.1 million, $6.8$6.1 million and $7.2$6.8 million for the years 2003, 2002 2001 and 2000,2001, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents. The Company also has an Employee Stock Purchase Plan which was approved by shareholders on May 19, 1997, and commenced July 1, 1997, under which options are granted to eligible employees who elect to participate in the plan on January 1st and July 1st of each year. Participants are allowed to exercise those options six months later to the extent of payroll deductions or cash payments accumulated during that six-month period. The option price under the plan during 2002 was 85% of either the fair market value of the common stock at the grant date or the fair market value at the exercise date, whichever was less. Prior to 2002 the Company purchased stock for the plan on the open market. Starting with the purchase rights accumulated under the July 1, 2002 grant the Company began issuing rather than purchasing stock. The Company’s contributions to the plan were $0.1 million, $0.1 million and $0.3 million for 2002, 2001 and 2000, respectively.
NOTE 14.
Stock-based Compensation Plans
The Company has various stock compensation plans which prior to 2003 were accounted for according to APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations.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 will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Total compensation expense related to the plans was $6.4 million, $6.3 million and $2.1 million in 2003, 2002 and $3.9 million in 2002, 2001, and 2000 respectively.
The Company’s shareholder approvedshareholder-approved Long-Term Incentive Plan (LTI Plan) encompasses many of the awards granted to employees. Established in 1995 and amended and restated in 1997, the LTI Plan applies to officers and key employees of the Company. Awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are purchased on the open market. The maximum number of shares that may be purchased for the LTI Plan is 1,200,000.
PERFORMANCE SHARE GRANTS
Each year the Company awards performance share grants under the LTI Plan. These are granted to key employees and vest at the end of four years with the final number of shares awarded depending on a performance measure. The Company records compensation expense related to the shares based on the performance measure and changes in the market price of the stock. Compensation expense related to performance share grants was $5.1 million, $5.5 million and $2.3 million for 2003, 2002 and $3.2 million for 2002, 2001, and 2000, respectively. The fair value of the performance awards granted in 2003, 2002 and 2001 was $17.29, $14.82 and 2000 is $14.82, $17.86, and $14.19 respectively. 247,184There were a total of 334,608 performance awards were granted in 2003, 247,184 in 2002 and 183,881 in 2001 and 204,044 in 2000.2001. As of December 31, 2002,2003, there are four active grant cycles active for a total of 571,719790,922 share grants outstanding although they may not all be awarded.
STOCK 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(for a total of 300,000 non-qualified stock optionsoptions) to the new president and chief executive officer. These options were awardedcan be exercised at the grant date market price of $22.51 per share and vest yearly over four and five years although vesting is accelerated under certain conditions. The options expire 10 years from the grant date. As ofAll 300,000 options remained outstanding at December 31, 2002, no2003, with 67,500 options exercisable. No options were exercisable.exercisable at December 31, 2002. The grant date fair value of the options is $3.37.at the grant date was $3.37 per share. Following the intrinsic value method of APB 25, no compensation expense was recorded for these options.
No additional options were granted in 2003.
RESTRICTED STOCK
In 2003 and 2002, the Company granted 11,000 shares and 30,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market. TheOf the 2003 shares vest monthly with all of theissued, 1,000 shares vested byin 2003. The remaining shares will vest evenly over the next five years. The 2002 shares were fully vested as of December 2003. TheIn 2002 the Company also issued 50,000 shares of restricted stock outside of the LTI Plan as approved by the Puget Energy Board of Directors. These shares were recorded as a separate component of stockholdersstockholders’ equity and vest at the rate of 20% per year.evenly over a five-year period. Compensation expense related to the restricted shares was $0.6 million and $0.5 million in 2002.2003 and 2002, respectively. No restricted shares were issued in 2001 and 2000.2001. Dividends are paid on all outstanding restricted stock and are accounted for as a Puget Energy stock dividend, not as compensation expense. At December 31, 2002 theThe weighted average grant date fair value for all outstanding shares of restricted stock granted in 2003 and 2002 was $21.94.
$23.29 and $21.94, respectively.
EMPLOYEE STOCK PURCHASE PLAN
The Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six monthsix-month intervals at the end of which the participating employees receive shares for 85% of the lower of the stock’s fair market price at the beginning or the end of the six monthsix-month period. A maximum of 500,000 shares may be sold to employees under the plan. ThePrior to 2002, the Company purchased shares for the plan on the open market up untilmarket. As of the most recentsecond offering at which time common stock was issued rather than purchased. Theof 2002, the Company currently plans to issuebegan issuing common stock for the ESPP rather than purchasing stock. In 2003, 38,940 shares were issued for the ESPP. In 2002, 18,252 shares were issued and 19,407 shares were purchased for the plan, and 18,252in 2001, 45,659 shares were issued. 45,659 shares and 48,513 shares were purchased in 2001 and 2000 respectively.purchased. At December 31, 2002 298,6022003, 259,662 shares may still be sold to employees under the plan. Under the SFAS No. 123 accounting that the Company adopted in 2003, ESPP is considered to be compensation expense. Total compensation expense related to the ESPP was $0.2 million in 2003. Dividends are not paid on ESPP shares until they are purchased sharesby employees and thus are accounted for as a Puget Energy stock dividend,dividends, not as compensation expense. The weighted average fair value of the purchase rights granted in 2003, 2002 and 2001 was $4.25, $4.19 and 2000 was $4.19, $4.35, and $3.90 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. No options were granted under the InfrastruX plan in 2000. The following summarizes InfrastruX option information for 2003, 2002 and 2001:
| 2003 | 2002 | 2001 | |||||||||||||||||||
| 2002 | 2001 | Shares (in thousands) | Weighted Average Exercise Price | Shares (in thousands) | Weighted Average Exercise Price | 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 | 1,995 | $4.05 | -- | -- | 2,643 | $ 4 | .31 | 1,995 | $ 4 | .05 | -- | $ -- | |||||||||
| Granted | 725 | 5.00 | 2,043 | $4.05 | 176 | 5 | .00 | 725 | 5 | .00 | 2,043 | 4 | .05 | ||||||||
| Exercised | -- | -- | -- | -- | -- | -- | -- | -- | -- | -- | |||||||||||
| Canceled | (77) | 4.09 | (48) | 4.00 | (201 | ) | 4 | .20 | (77 | ) | 4 | .09 | (48 | ) | 4 | .00 | |||||
| Outstanding at end of year | 2,643 | $4.31 | 1,995 | $4.05 | 2,618 | $ 4 | .36 | 2,643 | $ 4 | .31 | 1,995 | $ 4 | .05 | ||||||||
| Options exercisable at year end | 802 | $4.02 | 791 | $4.00 | 1,837 | $ 4 | .12 | 802 | $ 4 | .02 | 791 | $ 4 | .00 | ||||||||
| Weighted-average fair value of | |||||||||||||||||||||
| options granted during the year | $2.23 | $1.60 | |||||||||||||||||||
| Weighted average fair value of options granted during the year | $2.41 | $2.23 | $1.60 | ||||||||||||||||||
The following summarizes InfrastruXInfrastruX's outstanding option information at December 31, 2002:2003:
| Shares Outstanding (in thousands) | Weighted Average Contractual Life (in years) | Weighted Average Exercise Price | ||||||||
| Shares Outstanding (in thousands | Weighted- Average Contractual Life (in years) | Weighted- Average Exercise Price | ||||||||
| Exercise Prices | ||||||||||
| $4.00 | 1,828 | 9.12 | $4.00 | 1,666 | 7.11 | $4.00 | ||||
| $5.00 | 815 | | 9.31 | | 5.00 | | 952 | 8.42 | 5.00 | |
| 2,643 | | 9.18 | | $4.31 | | |||||
| 2,618 | 7.59 | $4.36 | ||||||||
Stock options awarded under the InfrastruX plan were generally granted at the InfrastruX market price on the date of grant although some options have been granted at a discount requiring InfrastruX to record compensation expense. A totalWith the prospective adoption of SFAS No. 123 fair value accounting in 2003, InfrastruX also recorded compensation expense related to options granted in 2003. Compensation expense of $0.2 million and $0.1 million in compensation expense related to stock options was recorded in 2002.
2003 and 2002, respectively.
NON-EMPLOYEE DIRECTOR STOCK PLAN
The Company has a director stock plan created in 1998 for all non-employee directors of Puget Energy/Energy and PSE. Under the plan which has a 10-year term, non-employee directors receive parta minimum of two-thirds of their quarterly retainer fees in Company stock andexcept that 100% of quarterly retainers are paid in Company stock until the director holds a number of shares equal to two years of common stock in value of their retainer. Directors may optionally receive their entire retainer in Company stock if they choose.stock. The compensation expense related to the director stock plan was $0.4 million, $0.2 million and $0.1 million in 2003, 2002 and $0.3 million in 2002, 2001, and 2000, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 100,000 shares. As of December 31, 2002, 6,9162003, 9,902 shares havehad been purchased for the director stock plan and 36,11748,219 deferred, for a total of 43,03358,121 shares.
OTHER PLANS
In addition to current stock compensation plans, the Company also has outstanding shares related to two plans that were in effect prior to the 1997 merger between Puget Sound Power and Light (PSP&L) and Washington Energy Company (WECO). There are 30,8002,400 vested, unexercised stock appreciation rights from the PSP&L Incentive Plan Awards granted to executives of PSP&L. These were granted in 1993 and 1994, for $27.63 andhave an exercise price of $20.75 respectively, and expire 10 years after the grant date. There are also 17,96011,301 vested, unexercised options from the WECO Incentive Stock Option Plan granted to key employees of WECO. The options were granted between 19931994 and 1996 forwith exercise prices ranging from $15.55 to $23.11 and expire 10 years from the date of grant. These are generally paid out as stock appreciation rights at the discretion of the grantees. The Company records compensation expense each quarter related to the PSP&L and WECO shares as the difference between the exercise price and the current market price. Compensation expense related to the WECO plan was near $0immaterial in 2003 and 2002, and $(0.2) million in 2001 and $0.2 million in 2000.2001. Compensation expense related to the PSP&L plan was near $0immaterial in 2003 and 2002, and $(0.1) million in 2001, and $0.2 million in 2000.
2001.
The Company used the Black-Scholes option pricing model to determine the fair value of certain stock basedstock-based awards to employees. The following assumptions were used for awards granted in 2003, 2002 2001 and 2000:2001:
| 2003 | 2002 | 2001 | ||||||||||||||||
| | 2002 | | 2001 | | 2000 | |||||||||||||
| Stock Options | ||||||||||||||||||
| Stock options | ||||||||||||||||||
| Risk-free interest rate | 4 | .32% | -- | -- | -- | 4 | .32% | -- | ||||||||||
| Expected lives - years | 4 | .50 | -- | -- | -- | 4 | .50 | -- | ||||||||||
| Expected stock volatility | 23 | .62% | -- | -- | -- | 23 | .62% | -- | ||||||||||
| Dividend yield | 5 | .00% | -- | -- | -- | 5 | .00% | -- | ||||||||||
| InfrastruX Stock Option Plan | ||||||||||||||||||
| InfrastruX stock option plan | ||||||||||||||||||
| Risk-free interest rate | 4 | .05% | 4 | .87% | -- | 2 | .80% | 4 | .05% | 4 | .87% | |||||||
| Expected lives - years | 4 | .00 | 4 | .00 | -- | 4 | .00 | 4 | .00 | 4 | .00 | |||||||
| Expected stock volatility | 60 | .00% | 50 | .00% | -- | 60 | .00% | 60 | .00% | 50 | .00% | |||||||
| Performance Awards | ||||||||||||||||||
| Performance awards | ||||||||||||||||||
| Risk-free interest rate | 4 | .00% | 4 | .99% | 6 | .66% | 2 | .35% | 4 | .00% | 4 | .99% | ||||||
| Expected lives - years | 4 | .00 | 4 | .00 | 4 | .00 | 4 | .00 | 4 | .00 | 4 | .00 | ||||||
| Expected stock volatility | 23 | .71% | 20 | .76% | 18 | .59% | 23 | .85% | 23 | .71% | 20 | .76% | ||||||
| Dividend yield | 8 | .85% | 7 | .67% | 9 | .14% | 4 | .86% | 8 | .85% | 7 | .67% | ||||||
| Employee Stock Purchase Plan | ||||||||||||||||||
| Risk-free interest rate | 1 | .65% | 4 | .26% | 5 | .59% | 1 | .07% | 1 | .65% | 4 | .26% | ||||||
| Expected lives - years | 0 | .50 | 0 | .50 | 0 | .50 | 0 | .50 | 0 | .50 | 0 | .50 | ||||||
| Expected stock volatility | 26 | .97% | 19 | .04% | 22 | .73% | 19 | .47% | 26 | .97% | 19 | .04% | ||||||
| Dividend yield | 5 | .81% | 7 | .72% | 8 | .98% | 4 | .39% | 5 | .81% | 7 | .72% | ||||||
NOTE 15.
Other InvestmentsAccounting for Derivative Instruments and Hedging Activities
The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income statement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
In March 1998,addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into an agreementor modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with Schlumberger North America (Schlumberger) (formerly known as CellNet Data Services Inc.), under whichno significant impact on the financial statements.
On January 1, 2001, the Company would lend Schlumberger uprecognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to $35current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.
NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)
During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of multiple draws so that Schlumberger could finance an Automated Meter Reading (AMR) network systemcash and preferred or common stock. The 2003 acquisition includes a contingency which requires InfrastruX to be deployed inmake additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the Company’s service territory. In September 1999, the Company announced it was expanding its AMR network system from 800,000 meters to 1,325,000 meters andadditional amount as a result increased the authorized loan amount to $72 million.goodwill. As of December 31, 2000,2003, no payments were required.
These companies provide utility infrastructure services which are relevant 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 for the outstanding loan balancenatural 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 $7.7 million in 2003 and $23.5 million in 2002.
During 2001, goodwill was $51.9being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to the annual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 |
| Reported income for common stock | $ 116,197 | $ 110,052 | $ 98,426 |
| Add back goodwill amortization, net of tax | -- | -- | 2,826 |
| Adjusted income for common stock | $ 116,197 | $ 110,052 | $ 101,252 |
| Basic earnings per share | |||
| Reported income for common stock | $ 1.23 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.23 | $ 1.24 | $ 1.17 |
| Diluted earnings per share | |||
| Reported income for common stock | $ 1.22 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.22 | $ 1.24 | $ 1.17 |
Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 years. In August2003 a total of $2.1 million was added to intangible assets — assigned $0.1 million to patents with an amortization period of 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 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. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.
| AT DECEMBER 31, 2003 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | 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 | |
| AT DECEMBER 31, 2002 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | Net Intangibles | |
| Covenant not to compete | $ 3,908 | $1,105 | $ 2,803 | |
| Developed technology | 14,190 | 1,744 | 12,446 | |
| Contractual customer relationships | 3,042 | 383 | 2,659 | |
| Patents | 793 | 49 | 744 | |
| Total | $21,933 | $3,281 | $18,652 | |
The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, Schlumberger paid off its outstanding loanrespectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 |
| Future intangible amortization | $ 2,101 | $ 2,075 | $ 1,746 | $ 1,363 | $ 1,340 |
The pro forma combined revenues, 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, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.
| (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) FOR THE YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 |
| Operating revenues | $ 2,505,523 | $ 2,469,122 | $ 3,056,824 |
| Net income for common | 116,636 | 112,813 | 104,338 |
| Basic earnings per common share | $ 1.23 | $ 1.28 | $ 1.21 |
| Diluted earnings per common share | $ 1.22 | $ 1.27 | $ 1.20 |
NOTE 17.
Other
PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $64.1$0.3 million by the end of 2004.
The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.
NOTE 16.18.
CommitmentsAccounting for Derivative Instruments and ContingenciesHedging ActivitiesCOMMITMENTS – ELECTRIC
The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
For the twelve monthsyear ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 approximately 22.5%gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the Company’s energy output was obtainedmark-to-market unrealized loss on physical electric contracts at an average costDecember 31, 2001 that were settled in 2002. As of approximately 13.96 mills 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” basis under whichDecember 31, 2003, the Company pays a proportionate sharehad an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the annual cost of each project in direct proportion to thecriteria for designation as cash flow hedges under SFAS No. 133. The amount of power annually purchased bycash flow hedges that will reverse and be settled into the Company from such project. Such payments are not contingent upon the projects being operable. 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.
income statement during 2004 will be immaterial. As of December 31, 2002, the Company was entitledhad a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to purchase portions ofcontracts which meet the power output ofcriteria for designation as cash flow hedges under SFAS No. 133.
In addition, the PUDs’ projects as set forthCompany has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the following tabulation:
| BONDS OUTSTANDING | COMPANY'S ANNUAL AMOUNT PURCHASABLE (APPROXIMATE) | ||||||||||||
| PROJECT | CONTRACT1 EXP. DATE | LICENSE2 EXP. DATE | 12/31/023 (MILLIONS) | % OF OUTPUT | MEGAWATT CAPACITY | COSTS4 (MILLIONS) | |||||||
| Rock Island | |||||||||||||
| Original units | 2012 | 2029 | $ 102 | .4 | 50.0 | 455 | $ 43 | .3 | |||||
| Additional units | 2012 | 2029 | 333 | .7 | 85.0 | ||||||||
| Rocky Reach | 2011 | 2006 | 408 | .9 | 38.9 | 505 | 26 | .2 | |||||
| Wells | 2018 | 2012 | 165 | .5 | 31.3 | 261 | 9 | .8 | |||||
| Priest Rapids | 2005 | 2005 | 150 | .4 | 8.0 | 72 | 2 | .3 | |||||
| Wanapum | 2009 | 2005 | 136 | .2 | 10.8 | 98 | 4 | .1 | |||||
| Total | $ 1,297 | .1 | 1,391 | $ 85 | .7 | ||||||||
The Company’s estimated payments for power purchases fromthird quarter of 2003 with no significant impact on the Columbia River are $92.7financial statements.
On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for 2003, $82.6 million for 2004, $78.9 million for 2005, $76.5 million for 2006, $79.3 million for 2007 and in the aggregate, $377.9 million thereafter through 2018.
fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
PSE has numerous long-term firm purchased powerhad two contracts with other utilitiesa counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the region.fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.
NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)
During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of cash and preferred or common stock. The Company is generally not obligated2003 acquisition includes a contingency which requires InfrastruX to make additional payments underif certain 2003 and 2004 earnings measures are met. If these contracts unless power is delivered.earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
These companies provide utility infrastructure services which are relevant 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 for 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 Company’s estimated paymentsacquisitions have been accounted for firm power purchases from other utilities, excludingusing the Columbia River projects, are $124.0purchase 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 $7.7 million in 2003 and $23.5 million in 2002.
During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for 2003, $75.5goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million for 2004, $76.3 million for 2005, $77.9 million for 2006, $80.6 million for 2007 and inof intangible assets that no longer met the aggregate, $500.3 million thereafter through 2037. These contracts have varying terms and may include escalation and termination provisions.
|
|
|
|
criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the federal Public Utility Regulatory Policies Act (PURPA), PSE entered into long-term firm purchased power contracts with non-utility generators. The Company purchasesfirst quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to 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 projectedannual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 |
| Reported income for common stock | $ 116,197 | $ 110,052 | $ 98,426 |
| Add back goodwill amortization, net of tax | -- | -- | 2,826 |
| Adjusted income for common stock | $ 116,197 | $ 110,052 | $ 101,252 |
| Basic earnings per share | |||
| Reported income for common stock | $ 1.23 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.23 | $ 1.24 | $ 1.17 |
| Diluted earnings per share | |||
| Reported income for common stock | $ 1.22 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.22 | $ 1.24 | $ 1.17 |
Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 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 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 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. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.
| AT DECEMBER 31, 2003 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | 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 | |
| AT DECEMBER 31, 2002 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | Net Intangibles | |
| Covenant not to compete | $ 3,908 | $1,105 | $ 2,803 | |
| Developed technology | 14,190 | 1,744 | 12,446 | |
| Contractual customer relationships | 3,042 | 383 | 2,659 | |
| Patents | 793 | 49 | 744 | |
| Total | $21,933 | $3,281 | $18,652 | |
The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 |
| Future intangible amortization | $ 2,101 | $ 2,075 | $ 1,746 | $ 1,363 | $ 1,340 |
The pro forma combined revenues, 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, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these agreements were made.companies been consummated for the period for which they are being given effect.
| (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) FOR THE YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 |
| Operating revenues | $ 2,505,523 | $ 2,469,122 | $ 3,056,824 |
| Net income for common | 116,636 | 112,813 | 104,338 |
| Basic earnings per common share | $ 1.23 | $ 1.28 | $ 1.21 |
| Diluted earnings per common share | $ 1.22 | $ 1.27 | $ 1.20 |
NOTE 17.
Other
PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s estimated payments underinvestment in these contracts are $202.7two venture capital funds totaled $3.6 million forat December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 $215.0 million for 2004, $220.3 million for 2005, $227.6 million for 2006, $210.4 million for 2007 and the other terminates December 31, 2007. The Company’s recorded investment in the aggregate, $946.5fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million thereafter through 2012.at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
The following table summarizes the Company’s estimated obligations for future power purchases:
| (Dollars in millions) | 2003 | 2004 | 2005 | 2006 | 2007 | 2008 AND THERE- AFTER | TOTAL | ||||||||||||||||
| Columbia River Projects | $ | 92 | .7 | $ | 82 | .6 | $ | 78 | .9 | $ | 76 | .5 | $ | 79 | .3 | $ | 377 | .9 | $ | 787 | .9 | ||
| Other utilities | 124 | .0 | 75 | .5 | 76 | .3 | 77 | .9 | 80 | .6 | 500 | .3 | 934 | .6 | |||||||||
| Non-utility generators | 202 | .7 | 215 | .0 | 220 | .3 | 227 | .6 | 210 | .4 | 946 | .5 | 2,022 | .5 | |||||||||
| Total | $ | 419 | .4 | $ | 373 | .1 | $ | 375 | .5 | $ | 382 | .0 | $ | 370 | .3 | $ | 1,824 | .7 | $ | 3,745 | .0 | ||
Total purchased power contracts provided the Company with approximately 12.1 million, 11.9 million and 15.1 million MWh of firm energy at a cost of approximately $466.1 million, $496.3 million, and $506.5 million for the years 2002, 2001 and 2000, respectively. 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 per day of natural gas for operation of Tenaska’s 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. The following table indicates the Company’s percentage ownership and the extentcarrying value of the Company’s investment in jointly-owned generating plants in servicethe fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2002:
| COMPANY'S SHARE | ||||||||||||||
| (Dollars in millions) | ENERGY SOURCE (FUEL) | COMPANY'S OWNERSHIP SHARE | PLANT IN SERVICE AT COST | ACCUMULATED DEPRECIATION | ||||||||||
| Colstrip 1 and 2 | Coal | 50% | $ 201 | $ 128 | ||||||||||
| Colstrip 3 and 4 | Coal | 25% | 458 | 226 | ||||||||||
Financing for2003, which reflects the impact of recording a participant’s ownership share$6.1 million pre-tax loss on the Company’s original cost basis in the projects is provided for by such participant.fourth quarter of 2003. The Company’s sharefuture funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of related operating and maintenance expenses is includedcertain portfolio assets in corresponding accounts inits calendar year 2003 financial statements. As a result of this action, the Consolidated Statements of Income. As part ofCompany adjusted its electric operations and in connection withcarrying basis to the 1999 buy-out$2.1 million fair value 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 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 $8.1 million in 2002, $8.2 million in 2003, $8.5 million in 2004, $8.7 million in 2005, $8.9 million in 2006 and $13.9 million thereafter. 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 of 6.5 years. The obligations under these contracts are $12.8 million in 2002, $13.5 million in 2003, $14.2 million in 2004, $14.9 million in 2005, $15.6 million in 2006 and $25.0 million in the aggregate thereafter. PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are classifiedCompany’s capital account as normal purchases and sales in accordance with SFAS No. 133. Commitments under these contracts for 2003 and 2004 total $47.2 million and $1.8 million, respectively.
GAS SUPPLY The Company has also entered into various firm supply, transportation and storage service contracts in order to assure adequate availability of gas supply for its firm customers. Many of these contracts, which have remaining terms from less than 1 year to 21 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Certain of PSE’s firm gas supply agreements also obligate the Company to purchase a minimum annual quantity at market-based contract prices. Generally, if the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. Alternatively, under some of the contracts, the supplier may exercise a right to reduce its subsequent obligation to provide firm gas to the Company. The Company incurred demand charges in 2002 for firm gas supply, firm transportation service and firm storage and peaking service of $27.4 million, $49.0 million and $6.4 million, respectively. WNG Cap I incurred demand charges in 2002 for firm transportation service of $9.4 million. The following tables summarize the Company’s obligations for future demand charges through the primary terms of its existing contracts and the minimum annual take requirements under the gas supply agreements. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change.
| (Dollars in millions) | 2003 | 2004 | 2005 | 2006 | 2007 | 2008 AND THERE-AFTER | TOTAL | ||||||||||||||||
| Firm gas supply | $ | 20 | .6 | $ | 12 | .5 | $ | 1 | .1 | $ | 1 | .1 | $ | 1 | .2 | $ | 2 | .8 | $ | 39 | .3 | ||
| Firm transportation service | 54 | .6 | 44 | .7 | 11 | .6 | 11 | .6 | 11 | .6 | 82 | .1 | 216 | .2 | |||||||||
| Firm storage service | 7 | .2 | 8 | .6 | 7 | .7 | 7 | .7 | 7 | .7 | 55 | .9 | 94 | .8 | |||||||||
| Total | $ | 82 | .4 | $ | 65 | .8 | $ | 20 | .4 | $ | 20 | .4 | $ | 20 | .5 | $ | 140 | .8 | $ | 350 | .3 | ||
| (Therms in thousands) | 2003 | 2004 | 2005 | 2006 | 2007 | 2008 AND THERE- AFTER | TOTAL | ||||||||||||||||
| Firm gas supply | 671,675 | 228,820 | 1,013 | -- | -- | -- | 901,508 | ||||||||||||||||
The Company believes that all demand charges will be recoverable in rates charged to its customers. Further, pursuant to implementation of FERC Order No. 636, the Company has the right to resell or release to others any of its unutilized gas supply or transportation and storage capacity. The Company does not anticipate any difficulty in achieving the minimum annual take obligations shown, as such volumes represent approximately 64% of expected annual sales for 2003 and less than 11% of expected sales in subsequent years. The Company’s current firm gas supply contracts obligate the suppliers to provide, in the aggregate, annual volumes up to those shown below:
| (Therms in thousands) | 2003 | 2004 | 2005 | 2006 | 2007 | 2008 AND THERE- AFTER | TOTAL | ||||||||||||||||
| Firm gas supply | 719,821 | 264,035 | 7,013 | 6,000 | 6,000 | 24,000 | 1,026,869 | ||||||||||||||||
SERVICE CONTRACT On August 30, 2001, PSE and Alliance Data Systems Corp. 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 its ConneXt subsidiary. 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 $19.4 million in 2003, $20.0 million in 2004, $22.5 million in 2005, $23.2 million in 2006, $23.9 million in 2007 and $86.7 million in the aggregate thereafter.
SURETY BOND The Company has a self-insurance surety bond in the amount of $5.2 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.ENVIRONMENTAL The Company is subject to environmental regulation by federal, state and local authorities. The Company has been namedprovided by the Environmental Protection Agency (EPA) and/or the Washington State Department of Ecology 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 as required by federal and state laws and this process is nearing completion. 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. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from either insurance companies, third parties or under the Washington Commission’s order. The information presented here as it relates to estimates of future liability isfund manager as of December 31, 2002.
2003.
ELECTRIC SITESIn the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
The Company has expended approximately $17.7 million related toPSE believes that the remediation activities coveredfuel cost disallowances proposed by the Washington Commission’s orderCommission staff are legally and has accrued approximately $1.7factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, as a liability for future remediationwhich included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs for these and other remediation activities. To date, the Company has recovered approximately $17.2$5.3 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 trends. GAS SITES The Company has expended approximately $62.5 millionof costs related to the remediation activities covered byconstruction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a Washington Commission’s order and has accrued approximately $33.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $58.7 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.regulatory asset.
NOTE 18.
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 trends.LITIGATION Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 2002. 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.NOTE 17.
Accounting for Derivative Instruments and Hedging Activities On January 1, 2001, the
The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”,Activities,” as amended by SFAS No. 138.138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception provided byexception.
For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
The amount of cash flow hedges that will reverse and be settled into the income statement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
In addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with no significant impact on the financial statements.
On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
During the year ended December 31, 2001, the Company recorded an increase to current earnings of approximately $11.2 million pre-tax ($7.2 million after-tax) to record the change in market value of outstanding derivative instruments not meeting cash flow hedge criteria. During the year ended December 31, 2002, the remainder of the contracts whichPSE has had given rise to the income statement losses were settled and resulted in an additional increase to earnings of $11.6 million pre-tax ($7.5 million after-tax). As of December 31, 2002, the Company had a long-term unrealized gain recorded in Other Comprehensive Income of $9.9 million after-tax and a short term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income statement during 2003 will be $4.1 million. In addition, on December 31, 2002 the Company had a short term unrealized gain on derivative contracts for the purchase of natural gas for core gas business of $3.7 million pre-tax. The Company has two contracts outstanding with a counterparty whose senior unsecured debt ratings were downgraded in September 2002 to Ba2 by Moody’s and in November 2002 to BB by Standard & Poor’s.below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the Companynovation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has collected a collateral depositbeen designated since inception in the amount of $21.4 million from the counterparty to guarantee performance. The contract will expire in June 2008 and is accounted for2000 as a qualifying cash flow hedge under SFAS No. 133.hedge. The second iscontract, a physical gas supply contract expiringfor one of PSE’s electric generating facilities was marked-to-market in July 2008 which has beenthe fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. In February 2003,PSE has concluded that it is appropriate to reserve the counterparty’smarked-to-market gain on this contract due to the credit was further downgraded althoughquality of the counterparty continues to perform as required under the terms of the two contracts. The Company believes the risk of non-performance by the counterparty is remote. At October 15, 2001, the Company had recorded a deferred liability of approximately $26.9 million after-tax for financial gas contracts to be used for electric production that until October 15, 2001 were designated as qualifying cash flow hedges. Changes in the market values of these de-designated contracts resulted in the recording of a loss of $7.8 million pre-tax ($5.1 million after-tax) to earnings in the fourth quarter of 2001. In the first quarter of 2002, the loss was reversed in its entirety when all of these contracts were settled or terminated. During 2001, the Financial Accounting Standards Board’s Derivative Implementation Group foraccordance with SFAS No. 133 issued guidance, under Issue C16 – “Applyingas delivery is not probable through the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and Purchased Option Contract” which became effective in the second quarter of 2002 for the Company. Issue C16 establishes that fuel supply contracts that combine a forward contract with a purchased option cannot qualify for the normal purchase and normal sales exception becauseterm of the optionality of the quantity of fuel to be delivered under the contract. A review of the fuel supply contracts by the Company determined that two long-term fuel supply contracts that deliver natural gas to the Company’s Encogen combustion turbine plant contained provisions for the purchase of optional quantities of fuel, and as originally written, would no longer qualify as normal purchase contracts upon implementation of Issue C16. In the second quarter of 2002, the Company signed amendments to those contracts that remove the optional provisions, requiring that the Company purchase 100% of the contractual fuel quantities for the remaining terms of the contracts. As a result, the contracts continue to qualify for the normal purchase-normal sale exception to SFAS 133.
contract, which expires in December 2008.
NOTE 18.Supplemental Quarterly Financial Data (Unaudited) The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation 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) | ||||||||||||||
| 2002 QUARTER | FIRST | SECOND | THIRD | FOURTH | ||||||||||
| Operating revenues | $ | 739,060 | $ | 540,819 | $ | 458,476 | $ | 653,967 | ||||||
| Operating income | 76,571 | 76,833 | 57,098 | 99,168 | ||||||||||
| Other income | 384 | 3,441 | 230 | 1,403 | ||||||||||
| Net income | 26,478 | 31,369 | 8,512 | 51,525 | ||||||||||
| Basic and diluted earnings per common share | $ | 0.28 | $ | 0.34 | $ | 0.07 | $ | 0.55 | ||||||
| (Unaudited; dollars in thousands except per-share amounts) | ||||||||||||||
| 2001 QUARTER | FIRST | SECOND | THIRD | FOURTH | ||||||||||
| Operating revenues | $ | 1,024,234 | $ | 710,295 | $ | 478,966 | $ | 673,064 | ||||||
| Operating income | 130,541 | 66,071 | 45,756 | 54,754 | ||||||||||
| Other income | 1,941 | 1,568 | 7,892 | 3,123 | ||||||||||
| Net income | 72,298 | 19,465 | 6,809 | 8,266 | ||||||||||
| Basic earnings per common share | $ | 0.815 | $ | 0.201 | $ | 0.055 | $ | 0.071 | ||||||
| Diluted earnings per common share | $ | 0.812 | $ | 0.201 | $ | 0.054 | $ | 0.071 | ||||||
| PUGET SOUND ENERGY (Unaudited; dollars in thousands except per-share amounts) | ||||||||||||||
| 2002 QUARTER | FIRST | SECOND | THIRD | FOURTH | ||||||||||
| Operating revenues | $ | 678,299 | $ | 464,697 | $ | 366,103 | $ | 563,694 | ||||||
| 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 | ||||||||||
| (Unaudited; dollars in thousands) | ||||||||||||||
| 2001 QUARTER | FIRST | SECOND | THIRD | FOURTH | ||||||||||
| Operating revenues | $ | 995,694 | $ | 664,827 | $ | 426,195 | $ | 628,058 | ||||||
| Operating income | 130,111 | 61,629 | 42,360 | 54,383 | ||||||||||
| Other income | 2,843 | 2,485 | 8,885 | 2,839 | ||||||||||
| Net income | 72,879 | 17,275 | 5,474 | 8,754 | ||||||||||
Operating revenues for the Company include optimization transactions reported net in the income statement as required by EITF 02-03 effective after June 30, 2002. The operating revenues for all quarters of 2001 and the first and second quarters of 2002 have been reclassified to conform with the current presentation.
NOTE 19.16.
Acquisitions and Intangibles (Puget Energy Only)
During 2001, InfrastruX acquired 100% of six companies based in the eastern United States, mid-west and Texas for a total price of $83.6 million. During 2002, InfrastruX acquired 100% of three additional companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases have beenwere funded in the form of cash and preferred andor common stock. The 2003 acquisition includes a contingency which requires InfrastruX to make additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
These companies provide utility infrastructure services such as:which are relevant to InfrastruX’s operating strategy including: installing, replacing and restoring underground cables and pipes for utilities and telecommunicationtelecommunications providers; pipeline construction, maintenance and rehabilitation services for the natural gas and petroleum industries, including directional drilling and vacuum excavation; and distribution and transmission orientedtransmission-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 of the business at the time of purchase waswere approximately $130.0$7.7 million before amortization. During 2002, InfrastruX addedin 2003 and $23.5 million of goodwill for a balance of $125.6 million net of accumulated amortization.in 2002.
During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which waswere not amortized per SFAS No. 142 – “Goodwill and Other Intangible Assets”.142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. Puget Energy then performedIn addition to the annual impairment review, as of October 31, 2002 and determined that goodwill was not impaired. Puget Energy will perform an annual impairment review hereafter. In addition, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, and 2000, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million and $1.0 million, respectively.million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:
| (Dollars in thousands) | 2002 | 2001 | 2000 |
| Reported income for common stock | $ 110,052 | $ 98,426 | $ 184,837 |
| Add back goodwill amortization, net of tax | -- | 2,826 | 907 |
| Adjusted income for common stock | $ 110,052 | $ 101,252 | $ 185,744 |
| Basic and diluted earnings per share | |||
| Reported income for common stock | $ 1.24 | $ 1.14 | $ 2.16 |
| Add back goodwill amortization | -- | 0.03 | 0.01 |
| Adjusted income for common stock | $ 1.24 | $ 1.17 | $ 2.17 |
| (DOLLARS IN THOUSANDS) | 2003 | 2002 | 2001 |
| Reported income for common stock | $ 116,197 | $ 110,052 | $ 98,426 |
| Add back goodwill amortization, net of tax | -- | -- | 2,826 |
| Adjusted income for common stock | $ 116,197 | $ 110,052 | $ 101,252 |
| Basic earnings per share | |||
| Reported income for common stock | $ 1.23 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.23 | $ 1.24 | $ 1.17 |
| Diluted earnings per share | |||
| Reported income for common stock | $ 1.22 | $ 1.24 | $ 1.14 |
| Add back goodwill amortization | -- | -- | 0.03 |
| Adjusted income for common stock | $ 1.22 | $ 1.24 | $ 1.17 |
Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from five5 to 20 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 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 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. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, with an amortization period of 16.0 years, $3.1 million to contractual customer relationships with an amortization period of 8.3 years and $1.1 million to covenant not to compete with an amortization period of 5.0 years.compete. The total weighted average amortization period for the 2002 additions is 8.0eight years. In 2001, $2.8 million was added to intangible assets, assigned entirely to covenant not to compete with an amortization period of 5.0 years. Total identifiable intangible assets are as follows:
| At December 31, 2001 (Dollars in thousands) | Gross Intangibles | Accumulated Amortization | Net Intangibles |
| Covenant not to compete | $ 3,908 | $1,105 | $ 2,803 |
| Developed technology | 14,190 | 1,744 | 12,446 |
| Contractual customer relationships | 3,042 | 383 | 2,659 |
| Patents | 793 | 49 | 744 |
| Total | $21,933 | $3,281 | $18,652 |
| At December 31, 2002 (Dollars in thousands) | Gross Intangibles | Accumulated Amortization | Net Intangibles |
| Covenant not to compete | $ 2,768 | $364 | $ 2,404 |
| Developed technology | 14,190 | 1,006 | 13,184 |
| Patents | 1,046 | 575 | 471 |
| Total | $18,004 | $1,945 | $16,059 |
| AT DECEMBER 31, 2003 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | 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 | |
| AT DECEMBER 31, 2002 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amoritization | Net Intangibles | |
| Covenant not to compete | $ 3,908 | $1,105 | $ 2,803 | |
| Developed technology | 14,190 | 1,744 | 12,446 | |
| Contractual customer relationships | 3,042 | 383 | 2,659 | |
| Patents | 793 | 49 | 744 | |
| Total | $21,933 | $3,281 | $18,652 | |
The identifiable intangible amortization expense for the year ended December 31, 20022003 was $1.9$2.1 million compared to $1.9 million and $1.1 million for 2002 and $0.3 million for 2001, and 2000, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:
| (Dollars in thousands) | 2003 | 2004 | 2005 | 2006 | 2007 | |||||
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 | |||||
| Future intangible amortization | $1,879 | $1,863 | $1,534 | $1,151 | $ 2,101 | $ 2,075 | $ 1,746 | $ 1,363 | $ 1,340 | |
As InfrastruX acquires more companies the total amortization amount in future periods may change.
The pro forma combined revenues, 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, 2000.2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.
| (Dollars in thousands, except per share amounts) (Unaudited) For the twelve months ended December 31, | 2002 | 2001 | 2000 | |||
| (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) FOR THE YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | |||
| Operating revenues | $ 2,413,122 | $ 3,000,824 | $ 3,577,354 | $ 2,505,523 | $ 2,469,122 | $ 3,056,824 |
| Net income for common | 111,058 | 102,649 | 198,637 | 116,636 | 112,813 | 104,338 |
| Basic earnings per common share | $ 1.26 | $ 1.19 | $ 2.33 | $ 1.23 | $ 1.28 | $ 1.21 |
| Diluted earnings per common share | $ 1.25 | $ 1.18 | $ 2.32 | $ 1.22 | $ 1.27 | $ 1.20 |
NOTE 17.
Other
PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.
NOTE 18.
Commitments and Contingencies
COMMITMENTS – ELECTRIC
For the year ended December 31, 2003, approximately 19.9% of the Company’s energy output was obtained at an average cost of approximately $0.01641 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” basis under which the Company pays a proportionate share of the annual cost of each project in direct proportion to the amount of power annually purchased by the Company from such project. Such payments are not contingent upon the projects being operable. 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, 2003, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:
| BONDS OUTSTANDING | COMPANY'S ANNUAL AMOUNT PURCHASABLE (APPROXIMATE) | ||||||||||||
| PROJECT | CONTRACT EXP. DATE | LICENSE1 EXP. DATE | 12/31/032 (MILLIONS) | % OF OUTPUT | MEGAWATT CAPACITY | COSTS3 (MILLIONS) | |||||||
| Rock Island | |||||||||||||
| Original units | 2012 | 2029 | $ 121 | .7 | 50.0 | 414 | $ 41 | .9 | |||||
| Additional units | 2012 | 2029 | 331 | .5 | 75.0 | ||||||||
| Rocky Reach | 2011 | 2006 | 394 | .7 | 38.9 | 505 | 29 | .6 | |||||
| Wells | 2018 | 2012 | 151 | .3 | 31.3 | 261 | 6 | .9 | |||||
| Priest Rapids4 | 2005 | 2005 | 184 | .7 | 8.0 | 72 | 2 | .6 | |||||
| Wanapum4 | 2009 | 2005 | 186 | .5 | 10.8 | 98 | 4 | .1 | |||||
| Total | $ 1,370 | .4 | 1,350 | $ 85 | .1 | ||||||||
The Company’s estimated payments for power purchases from the Columbia River are $84.6 million for 2004, $81.4 million for 2005, $78.4 million for 2006, $81.4 million for 2007, $82.6 million for 2008 and in the aggregate, $123.5 million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with other utilities in 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 $76.0 million for 2004, $77.7 million for 2005, $78.6 million for 2006, $80.7 million for 2007, $82.6 million for 2008 and in the aggregate, $433.3 million thereafter through 2037. 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 $211.4 million for 2004, $217.3 million for 2005, $232.9 million for 2006, $211.9 million for 2007, $212.1 million for 2008 and in the aggregate, $746.0 million thereafter through 2012.
The following table summarizes the Company’s estimated obligations for future power purchases:
| (DOLLARS IN MILLIONS) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 & THERE- AFTER | TOTAL |
| Columbia River projects | $ 84.6 | $ 81.4 | $ 78.4 | $ 81.4 | $ 82.6 | $ 123.5 | $ 531.9 |
| Other utilities | 76.0 | 77.7 | 78.6 | 80.7 | 82.6 | 433.3 | 828.9 |
| Non-utility generators | 211.4 | 217.3 | 232.9 | 211.9 | 212.1 | 746.0 | 1,831.6 |
| Total | $ 372.0 | $ 376.4 | $ 389.9 | $ 374.0 | $ 377.3 | $ 1,302.8 | $ 3,192.4 |
| 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 affirm the Company'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, 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: 43.7% at Rock Island; 58.3% at Rocky Reach; 94.5% at Priest Rapids; 79.6% at Wanapum; and 6.2% at Wells. |
| 3 | The components of 2003 costs associated with the interest portion of debt service are: Rock Island, $22.6 million for all units; Rocky Reach, $9.4 million; Wells, $8.2 million; Priest Rapids, $0.8 million; and Wanapum, $0.6 million. |
| 4 | 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 contract 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 Act 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, it 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 has been requested. |
Total purchased power contracts provided the Company with approximately 11.0 million, 12.1 million and 11.9 million MWh of firm energy at a cost of approximately $479.2 million, $466.1 million and $496.3 million for the years 2003, 2002 and 2001, 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, 2003:
| COMPANY'S SHARE | ||||||||||||||
| (DOLLARS IN MILLIONS) | ENERGY SOURCE (FUEL) | COMPANY'S OWNERSHIP SHARE | PLANT IN SERVICE AT COST | ACCUMULATED DEPRECIATION | ||||||||||
| Colstrip 1 & 2 | Coal | 50% | $ 207 | $ 133 | ||||||||||
| Colstrip 3 & 4 | Coal | 25% | 464 | 240 | ||||||||||
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.
PSE and PPL Montana, the other owner of Colstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s PCA mechanism.
On October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE used the coal as fuel for its share of Units 3 & 4 of the Colstrip generating plant. PSE’s coal price for that period was reduced by a settlement PSE and Western Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.
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 per day of natural gas for operation of Tenaska’s 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 $22.0 million in 2004.
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 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 $8.5 million in 2004, $8.7 million in 2005, $9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter. 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 of 6.5 years. The obligations under these contracts are $15.9 million in 2004, $16.7 million in 2005, $17.5 million in 2006, $18.4 million in 2007 and $12.9 million in the aggregate thereafter.
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. Commitments under these contracts are $3.0million in 2004, $10.3 million in 2005, $1.1 million in 2006, $0.4 million in 2007 and $0.1 million thereafter.
GAS 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 20 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Two of PSE’s long-term firm gas supply agreements, that expire November 2004, obligate the Company to purchase a minimum annual quantity at market-based contract prices. If the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. PSE didn’t incur such charges in 2003. The Company incurred demand charges in 2003 for firm gas supply, firm transportation service and firm storage and peaking service of $24.7 million, $47.9 million and $5.3 million, respectively. WNG Cap I incurred demand charges in 2003 for firm transportation service of $9.4 million.
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) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 & THERE- AFTER | TOTAL |
| Firm gas supply | $ 18.7 | $ 1.5 | $ 1.0 | $ 0.5 | $ 0.5 | $ 1.5 | $ 23.7 |
| Firm transportation service | 66.6 | 58.8 | 57.0 | 57.0 | 48.0 | 122.7 | 410.1 |
| Firm storage service | 11.3 | 11.6 | 7.8 | 7.7 | 7.7 | 48.2 | 94.3 |
| Total | $ 96.6 | $ 71.9 | $ 65.8 | $ 65.2 | $ 56.2 | $ 172.4 | $ 528.1 |
SERVICE CONTRACT
On August 30, 2001, PSE and Alliance Data Systems Corp. 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 its ConneXt subsidiary. 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 $21.7 million in 2004, $22.2 million in 2005, $22.8 million in 2006, $23.4 million in 2007, $24.0 million in 2008 and $66.9 million in the aggregate thereafter.
SURETY BOND
The Company has a self-insurance surety bond in the amount of $5.9 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.
ENVIRONMENTAL
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 these 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. The Company believes a significant portion of its past and future environmental remediation costs are 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, 2003.
ELECTRIC SITES
The Company has expended approximately $18.1 million related to the remediation activities covered by the Washington Commission’s order and has accrued approximately $1.6 million as a liability for future remediation costs for these and other remediation activities. To date, the Company has recovered approximately $18.8 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 trends.
GAS SITES
The Company has expended approximately $65.9 million related to the remediation activities covered by a Washington Commission order and has accrued approximately $32.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $59.6 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.
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 trends.
LITIGATION
There are several actions in the U.S. Ninth Circuit Court of Appeals 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, a number of contracts, including the amended settlement agreement regarding the Residential Purchase and Sale Program and the conditional settlement agreements between BPA and PSE which modified the payment provisions of the Residential Purchase and Sale Program. BPA rates used in such amended settlement agreement between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits 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 may have on PSE.
Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 2003. 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.
NOTE 20.19.
Segment Information
Puget Energy operates in primarily two business segments: the Regulated Utility Operations,regulated utility operations, or PSE, and Utility Support,construction services, or InfrastruX, which was incorporated in the year 2000.InfrastruX. 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 Washington State.the State of Washington. InfrastruX specializes in contractingconstruction services to other gas and electric utilities primarily in the mid-west, south/Texas and the north-central and eastern United States.
The other principalOne minor non-utility line of business which issegment, a PSE subsidiary, which is a real estate investment and development company. Reconciling items between segments are not material.
company is described as other. The assets of ConneXt, the development and marketing of customer information and billing system software segment, were sold during the third quarter of 2001. The third quarter results of 2001 includeincluded an $8.0 million after-tax gain related to the ConneXt sale. Reconciling items between segments are not significant.
Financial data for business segments are as follows:
| (Dollars in thousands) | REGULATED | PUGET ENERGY | ||||||
| 2002 | UTILITY | INFRASTRUX | OTHER | TOTAL | ||||
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||||||
| 2003 | UTILITY | INFRASTRUX | OTHER | TOTAL | ||||
| Revenues | $2,063,040 | $319,529 | $9,753 | $2,392,322 | $2,143,693 | $341,787 | $ 6,043 | $2,491,523 |
| Depreciation and amortization | 215,097 | 13,426 | 220 | 228,743 | 219,851 | 16,779 | 236 | 236,866 |
| Income tax | 50,600 | 6,703 | 1,957 | 59,260 | 69,823 | 1,594 | 952 | 72,369 |
| Operating income | 289,511 | 15,595 | 4,563 | 309,669 | 295,219 | 7,452 | 2,504 | 305,175 |
| Interest charges, net of AFUDC | 190,860 | 5,517 | -- | 196,377 | 179,437 | 5,485 | 123 | 185,045 |
| Net income | 104,044 | 9,455 | 4,384 | 117,883 | 119,144 | 1,766 | 438 | 121,348 |
| Goodwill, net | -- | 125,555 | -- | 125,555 | -- | 133,302 | -- | 133,302 |
| Total assets | 5,208,487 | 319,248 | 129,756 | 5,657,491 | 5,257,157 | 342,332 | 75,196 | 5,674,685 |
| Construction expenditures - excluding equity AFUDC | 224,165 | -- | 224,165 | 269,973 | -- | 269,973 | ||
| Additions to other property, plant and equipment | -- | 11,621 | -- | 11,621 | -- | 15,536 | -- | 15,536 |
| (Dollars in thousands) | REGULATED | PUGET ENERGY | ||||||
| 2001 | UTILITY | INFRASTRUX | OTHER | TOTAL | ||||
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||||||
| 2002 | UTILITY | INFRASTRUX | OTHER | TOTAL | ||||
| Revenues | $2,680,298 | $173,786 | $32,476 | $2,886,560 | $2,063,040 | $319,529 | $ 9,753 | $2,392,322 |
| Depreciation and amortization | 208,705 | 8,820 | 15 | 217,540 | 215,097 | 13,426 | 220 | 228,743 |
| Income tax | 68,005 | 2,956 | 8,877 | 79,838 | 50,600 | 6,703 | 1,957 | 59,260 |
| Operating income | 273,751 | 8,702 | 14,668 | 297,121 | 289,511 | 15,595 | 4,563 | 309,669 |
| Interest charges, net of AFUDC | 186,403 | 3,656 | -- | 190,059 | 190,861 | 5,516 | -- | 196,377 |
| Net income | 80,137 | 2,518 | 24,184 | 106,839 | 104,044 | 9,455 | 4,384 | 117,883 |
| Goodwill, net | -- | 102,151 | -- | 102,151 | -- | 125,555 | -- | 125,555 |
| Total assets | 5,178,601 | 229,125 | 139,251 | 5,546,977 | 5,323,129 | 319,248 | 129,756 | 5,772,133 |
| Construction expenditures - excluding equity AFUDC | 247,435 | -- | 247,435 | 224,165 | -- | 224,165 | ||
| Additions to other property, plant and equipment | -- | 5,193 | -- | 5,193 | -- | 11,621 | -- | 11,621 |
| (Dollars in thousands) | REGULATED | PUGET ENERGY | ||
| 2000 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $3,244,630 | $44,999 | $12,667 | $3,302,296 |
| Depreciation and amortization | 194,228 | 2,268 | 17 | 196,513 |
| Income tax | 131,262 | 415 | (1,854) | 129,823 |
| Operating income | 363,559 | 865 | (552) | 363,872 |
| Interest charges, net of AFUDC | 174,914 | 188 | -- | 175,102 |
| Net income | 204,720 | (543) | (10,346) | 193,831 |
| Goodwill, net | -- | 57,887 | -- | 57,887 |
| Total assets | 5,339,669 | 106,520 | 110,480 | 5,556,669 |
| Construction expenditures - excluding equity AFUDC | 296,480 | -- | -- | 296,480 |
| (DOLLARS IN THOUSANDS) | REGULATED | PUGET ENERGY | ||
| 2001 | UTILITY | INFRASTRUX | OTHER | TOTAL |
| Revenues | $2,680,298 | $173,786 | $ 32,476 | $2,886,560 |
| Depreciation and amortization | 208,705 | 8,820 | 15 | 217,540 |
| Income tax | 68,005 | 2,956 | 8,877 | 79,838 |
| Operating income | 273,751 | 8,702 | 14,668 | 297,121 |
| Interest charges, net of AFUDC | 186,403 | 3,656 | -- | 190,059 |
| Net income | 80,137 | 2,518 | 24,184 | 106,839 |
| Goodwill, net | -- | 102,151 | -- | 102,151 |
| Total assets | 5,300,105 | 229,125 | 139,251 | 5,668,481 |
| Construction expenditures - excluding equity AFUDC | 247,435 | -- | -- | 247,435 |
| Additions to other property, plant and equipment | -- | 5,193 | -- | 5,193 |
NOTE 21.20.
Impairment of Long-Lived AssetsSupplementary Income Statement Information
| 2003 | 2002 | 2001 | ||||
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | PUGET ENERGY | PSE | PUGET ENERGY | PSE |
| Taxes other than income taxes: | ||||||
| Real estate and personal proper | $ 45,660 | $ 44,757 | $ 48,890 | $ 48,408 | $ 41,858 | $ 41,588 |
| State business | 75,523 | 75,524 | 77,527 | 77,527 | 85,335 | 84,735 |
| Municipal and occupational | 64,861 | 64,861 | 67,770 | 67,770 | 71,819 | 71,819 |
| Other | 38,273 | 25,638 | 37,029 | 24,463 | 33,431 | 29,084 |
| Total taxes other than income tax | $224,317 | $210,780 | $231,216 | $218,168 | $232,443 | $227,226 |
| Charged to: | ||||||
| Operating expense | $208,395 | $194,857 | $215,429 | $202,381 | $212,582 | $207,365 |
| Other accounts, including | ||||||
| construction work in progress | 15,922 | 15,923 | 15,787 | 15,787 | 19,861 | 19,861 |
| Total taxes other than income tax | $224,317 | $210,780 | $231,216 | $218,168 | $232,443 | $227,226 |
SUPPLEMENTALQUARTERLY FINANCIAL DATA
InThe following unaudited amounts, in the fourth quarter of 2000, Hydro Energy Development Corp., a wholly-owned subsidiary of PSE, recorded an after-tax loss of approximately $11.8 million in Other Incomeopinion of the non-regulated business segment. The loss provision represents the difference between the carrying valueCompany, include all adjustments (consisting of 13 small hydroelectric generating projects Hydro Energy Development Corp. was seeking approval to develop in western Washington State and management’s estimate of their net realizable value. Federal and state regulatory agencies that have jurisdiction over the construction and operationnormal recurring adjustments) necessary for a fair presentation of the proposed projects have made it increasingly difficultresults of operations for the interim periods. Quarterly amounts vary during the year due to complete and operate the projects in an economic manner. Hydro Energy Development Corp. owns and operates a 3.7 MW hydroelectric project located in western Washington State.seasonal nature of the utility business.
| PUGET ENERGY | ||||
| (Unaudited; dollars in thousands except per share amounts) | ||||
| 2003 QUARTER | FIRST | SECOND | THIRD | FOURTH |
| Operating revenues | $ 675,961 | $557,856 | $515,567 | $ 742,139 |
| 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 | 44,756 | 22,392 | 11,003 | 43,366 |
| Net income | 44,587 | 22,392 | 11,003 | 43,366 |
| 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 revenues | $ 739,060 | $540,819 | $458,476 | $ 653,967 |
| Operating income | 76,571 | 76,833 | 57,098 | 99,168 |
| Other income | 384 | 3,441 | 230 | 1,403 |
| Net income | 26,478 | 31,369 | 8,512 | 51,525 |
| Basic and diluted earnings per common share | $0.28 | $0.34 | $0.07 | $0.55 |
| (Unaudited; dollars in thousands except per share amounts) | ||||
| 2001 QUARTER | FIRST | SECOND | THIRD | FOURTH |
| Operating revenues | $1,024,234 | $710,295 | $478,966 | $ 673,064 |
| Operating income | 130,541 | 66,071 | 45,756 | 54,754 |
| Other income | 1,941 | 1,568 | 7,892 | 3,123 |
| Net income before cumulative effect of | ||||
| accounting change | 87,047 | 19,465 | 6,809 | 8,266 |
| Net income | 72,298 | 19,465 | 6,809 | 8,266 |
| Basic earnings per common share | $0.815 | $0.201 | $0.055 | $0.071 |
| Diluted earnings per common share | $0.812 | $0.201 | $0.054 | $0.071 |
| PUGET SOUND ENERGY | ||||
| (Unaudited; dollars in thousands) | ||||
| 2003 QUARTER | FIRST | SECOND | THIRD | FOURTH |
| Operating revenues | $ 605,284 | $465,513 | $422,425 | $ 656,514 |
| 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 |
| Operating revenues | $ 678,299 | $464,697 | $366,103 | $ 563,694 |
| 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 |
| (Unaudited; dollars in thousands) | ||||
| 2001 QUARTER | FIRST | SECOND | THIRD | FOURTH |
| Operating revenues | $ 995,694 | $664,827 | $426,195 | $ 628,058 |
| Operating income | 130,111 | 61,629 | 42,360 | 54,383 |
| Other income | 2,843 | 2,485 | 8,885 | 2,839 |
| Net income before cumulative effect of | ||||
| accounting change | 87,628 | 17,275 | 5,474 | 8,754 |
| Net income | 72,879 | 17,275 | 5,474 | 8,754 |
ScheduleSCHEDULE II.
Valuation and Qualifying Accounts and Reserves
| (Dollars in thousands) | BALANCE AT BEGINNING OF PERIOD | ADDITIONS CHARGED TO COSTS AND EXPENSES | DEDUCTIONS | BALANCE AT END OF PERIOD | ||||||||||||||||||||||||
| (DOLLARS IN THOUSANDS) | (DOLLARS IN THOUSANDS) | BALANCE AT BEGINNING OF PERIOD | ADDITIONS CHARGED TO COSTS AND EXPENSES | DEDUCTIONS | BALANCE AT END OF PERIOD | |||||||||||||||||||||||
| PUGET ENERGY | ||||||||||||||||||||||||||||
| YEAR ENDED DECEMBER 31, 2001 | ||||||||||||||||||||||||||||
| Accounts deducted from assets on balance sheet: | ||||||||||||||||||||||||||||
| Allowance for doubtful accounts receivable | $ | 3,863 | $ | 9,387 | $ | 8,891 | $ | 4,359 | ||||||||||||||||||||
| 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 | $ | 5,488 | $ | 11,191 | $ | 12,816 | $ | 3,863 | $ | 5,488 | $ | 11,191 | $ | 12,816 | $ | 3,863 | ||||||||||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | 41,488 | �� | -- | -- | 41,488 | |||||||||||||||||||
| Industrial accident reserve | -- | 4,000 | 2,000 | 2,000 | -- | 4,000 | 2,000 | 2,000 | ||||||||||||||||||||
| Gas transportation contracts reserve | 139 | -- | -- | 139 | 139 | -- | -- | 139 | ||||||||||||||||||||
| YEAR ENDED DECEMBER 31, 2001 | ||||||||||||||||||||||||||||
| Accounts deducted from assets on balance sheet: | ||||||||||||||||||||||||||||
| Allowance for doubtful accounts receivable | $ | 1,538 | $ | 13,458 | $ | 9,508 | $ | 5,488 | ||||||||||||||||||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | ||||||||||||||||||||||||
| Gas transportation contracts reserve | 1,657 | 32 | 1,550 | 139 | ||||||||||||||||||||||||
| PUGET SOUND ENERGY | ||||||||||||||||||||||||||||
| 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 | $ | 1,980 | $ | 3,666 | $ | 11,140 | $ | 12,816 | $ | 1,990 | ||||||||||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | 41,488 | -- | -- | 41,488 | ||||||||||||||||||||
| Industrial accident reserve | -- | 4,000 | 2,000 | 2,000 | -- | 4,000 | 2,000 | 2,000 | ||||||||||||||||||||
| Gas transportation contracts reserve | 139 | -- | -- | 139 | 139 | -- | -- | 139 | ||||||||||||||||||||
| PUGET ENERGY | ||||||||||||||||||||||||||||
| YEAR ENDED DECEMBER 31, 2001 | ||||||||||||||||||||||||||||
| Accounts deducted from assets on balance sheet: | ||||||||||||||||||||||||||||
| Allowance for doubtful accounts receivable | $ | 1,538 | $ | 13,458 | $ | 9,508 | $ | 5,488 | $ | 1,538 | $ | 11,636 | $ | 9,508 | $ | 3,666 | ||||||||||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | 41,488 | -- | -- | 41,488 | ||||||||||||||||||||
| Gas transportation contracts reserve | 1,657 | 32 | 1,550 | 139 | 1,657 | 32 | 1,550 | 139 | ||||||||||||||||||||
| PUGET SOUND ENERGY | ||||||||||||||||||||||||||||
| YEAR ENDED DECEMBER 31, 2001 | ||||||||||||||||||||||||||||
| Accounts deducted from assets on balance sheet: | ||||||||||||||||||||||||||||
| Allowance for doubtful accounts receivable | $ | 1,538 | $ | 11,636 | $ | 9,508 | $ | 3,666 | ||||||||||||||||||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | ||||||||||||||||||||||||
| Gas transportation contracts reserve | 1,657 | 32 | 1,550 | 139 | ||||||||||||||||||||||||
| PUGET ENERGY AND PUGET SOUND ENERGY | ||||||||||||||||||||||||||||
| YEAR ENDED DECEMBER 31, 2000 | ||||||||||||||||||||||||||||
| Accounts deducted from assets on balance sheet: | ||||||||||||||||||||||||||||
| Allowance for doubtful accounts receivable | $ | 1,503 | $ | 7,552 | $ | 7,517 | $ | 1,538 | ||||||||||||||||||||
| Reserve on wholesale sales | -- | 41,488 | -- | 41,488 | ||||||||||||||||||||||||
| Gas transportation contracts reserve | 1,780 | 660 | 783 | 1,657 | ||||||||||||||||||||||||
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 filed 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. |
| 3(ii).2 | Amended and Restated Bylaws of PSE dated March 7, 2003. |
| 4.1 | Fortieth through |
| 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 |
| 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, as Rights Agent (incorporated herein by reference to Exhibit 2.1 to PSE's Registration Statement on Form 8-A, dated January 2, 2001, 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 |
| 4.22 | Unsecured Debt Indenture between Puget Sound Energy and Bank One Trust Company, N.A. dated as of May 18, 2001, 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). |
| 4.23 | First Supplemental Indenture to the Unsecured Debt Indenture dated as of May 18, 2001 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) |
| 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 |
| 4.27 |
| 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 | Pacific Northwest Coordination Agreement executed as of September 15, 1964 among the United States of America, PSE and most of the other major electrical utilities in the Pacific Northwest (Exhibit 13-gg to Registration No. 2-24252). |
| 10.4 | 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). |
| 10.5 | 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). |
| 10.6 | 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). |
| 10.7 | 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). |
| 10.8 | 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). |
| 10.9 | 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). |
| 10.10 | 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). |
| 10.11 | 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). |
| 10.12 | 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). |
| 10.13 | Coal Supply Agreement dated as of July 30, 1971 among Northwestern Resources formerly The Montana Power Company, PSE and Western Energy Company (Exhibit 5-d to Registration No. 2-45702). |
| 10.14 | Contract dated June 19, 1974 between PSE and |
| 10.15 | Loan Agreement dated as of December 1, 1980 and related documents pertaining to Whitehorn turbine construction trust financing (Exhibit 10.52 to Annual Report on Form 10-K for the fiscal year ended December 31, 1980, Commission File No. 1-4393). |
| 10.16 | Coal Transportation Agreement dated as of July 10, 1981 (Exhibit 20-a to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981, Commission File No. 1-4393). |
| 10.17 | Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and PSE dated September 17, 1985 (Exhibit (10)-49 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393). |
| 10.18 | Agreement to Dismiss Claims and Covenant Not to Sue dated September 17, 1985 between Washington Public Power Supply System (Energy Northwest) and PSE (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393). |
| 10.19 | Irrevocable Offer of Washington Public Power Supply System (Energy Northwest) Nuclear Project No. 3 Capability for Acquisition executed by PSE dated September 17, 1985 (Exhibit A of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393). |
| 10.20 | Settlement Exchange Agreement (Bonneville Exchange Power Contract) executed by the United States of America Department of Energy acting by and through the Bonneville Power Administration and PSE dated September 17, 1985 (Exhibit B of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393). |
| 10.21 | Settlement Agreement and Covenant Not to Sue between PSE and Northern Wasco County People's Utility District dated October 16, 1985 (Exhibit (10)-53 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393). |
| 10.22 | Settlement Agreement and Covenant Not to Sue between PSE and Tillamook People's Utility District dated October 16, 1985 (Exhibit (10)-54 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393). |
| 10.23 | Settlement Agreement and Covenant Not to Sue between PSE and Clatskanie People's Utility District dated September 30, 1985 (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393). |
| 10.24 | Stipulation and Settlement Agreement between PSE and Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October 31, 1986 (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1986, Commission File No. 1-4393). |
| 10.25 | 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). |
| 10.26 | 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). |
| 10.27 | 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). |
| 10.28 | 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). |
| 10.29 | 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). |
| 10.30 | Agreement for the Purchase of Power dated as of October 29, 1984 between South Fork II, Inc. and PSE (Weeks Falls Hydro-electric Project) (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| 10.31 | Agreement for the Purchase of Power dated as of October 29, 1984, between South Fork Resources, Inc. and PSE (Twin Falls Hydro-electric Project) (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| 10.32 | Agreement for Firm Purchase Power dated as of January 4, 1988 between the City of Spokane, Washington and PSE (Spokane Waste Combustion Project) (Exhibit (10)-62 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| 10.33 | Agreement for Evaluating, Planning and Licensing dated as of February 21, 1985 and Agreement for Purchase of Power dated as of February 21, 1985 between Pacific Hydropower Associates and PSE (Koma Kulshan Hydro-electric Project) (Exhibit (10)-63 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| 10.34 | 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). |
| 10.35 | 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). |
| 10.36 | Amendment dated as of August 10, 1988 to Agreement for Firm Purchase Power dated as of January 4, 1988 between the City of Spokane, Washington and PSE (Spokane Waste Combustion Project) (Exhibit (10)-76 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393). |
| 10.37 | Agreement for Firm Power Purchase dated October 24, 1988 between Northern Wasco People's Utility District and PSE (The Dalles Dam North Fishway) (Exhibit (10)-77 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393). |
| 10.38 | Agreement for Firm Power Purchase dated as of February 24, 1989 between Sumas Energy, Inc. and PSE (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1989, Commission File No. 1-4393). |
| 10.39 | Settlement Agreement dated as of April 27, 1989 between Public Utility District No. 1 of Douglas County, Washington, Portland General Electric Company (Enron), PacifiCorp, The Washington Water Power Company (Avista) and PSE (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393). |
| 10.40 | Agreement for Firm Power Purchase (Thermal Project) dated as of June 29, 1989 between San Juan Energy Company and PSE (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393). |
| 10.41 | Agreement for Verification of Transfer, Assignment and Assumption dated as of September 15, 1989 between San Juan Energy Company, March Point Cogeneration Company and PSE (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393). |
| 10.42 | 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). |
| 10.43 | Conservation Power Sales Agreement dated as of December 11, 1989 between Public Utility District No. 1 of Snohomish County and PSE (Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393). |
| 10.44 | Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among |
| 10.45 | Settlement Agreement dated as of October 1, 1990 among Public Utility District No. 1 of Douglas County, Washington, PSE, Pacific Power and Light Company (PacifiCorp), The Washington Water Power Company (Avista), Portland General Electric Company (Enron), the Washington Department of Fisheries, the Washington Department of Wildlife, the Oregon Department of Fish and Wildlife, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the Confederated Tribes and Bands of the Yakama Indian Nation, the Confederated Tribes of the Umatilla Reservation, and the Confederated Tribes of the Colville Reservation (Exhibit (10)-95 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393). |
| 10.46 | 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). |
| 10.47 | 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). |
| 10.48 | Amendatory Agreement No. 3 dated August 1, 1991 to the Pacific Northwest Coordination Agreement executed September 15, 1964 among the United States of America, PSE and most of the other major electrical utilities in the Pacific Northwest (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393). |
| 10.49 | Agreement between the 40 parties to the Western Systems Power Pool (PSE being one party) dated July 27, 1991 (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393). |
| 10.50 | Memorandum of Understanding between PSE and the Bonneville Power Administration dated September 18, 1991 (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393). |
| 10.51 | 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). |
| 10.52 | 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). |
| 10.53 | Amendment to Agreement for Firm Power Purchase dated as of September 30, 1991 between Sumas Energy, Inc. and PSE (Exhibit (10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393). |
| 10.54 | Letter Agreement dated October 12, 1992 between Tenaska Washington Partners, L.P. and PSE regarding clarification of issues under the Agreement for Firm Power Purchase (Exhibit (10)-121 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393). |
| 10.55 | Consent and Agreement dated October 12, 1992 between PSE and The Chase Manhattan Bank, N.A., as agent (Exhibit (10)-122 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393). |
| 10.56 | 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). |
| 10.57 | 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). |
| 10.58 | Power Exchange Agreement dated as of September 27, 1995 between British Columbia Power Exchange Corporation and PSE (Exhibit 10.117 to Annual Report on Form 10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393). |
| 10.59 | Service Agreement dated April 14, 1993 between Questar Pipeline Corporation and Washington Natural Gas Company for FSS-1 firm storage service at Clay Basin (Exhibit 10-B Form 10-K for the year ended September 30, 1994, File No. 11271). |
| 10.60 | Firm Transportation Service Agreement dated October 1, 1990 between Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-D to Form 10-K for the year ended September 30, 1994, File No. 11271). |
| 10.61 | Gas Transportation Service Contract dated June 29, 1990 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A to Form 10-Q for the quarter ended March 31, 1993, File No. 0-951). |
| 10.62 | Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A to Form 10-Q for the quarter ended March 31, 1993, File No. 0-951). |
| 10.63 | 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). |
| 10.64 | Gas Transportation Service Contract dated July 15, 1994 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 10-E.3 to Form 10-K for the year ended September 30, 1995, File No. 11271). |
| 10.65 | Amendment to Gas Transportation Service Contract dated August 15, 1994 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 10-E.4 to Form 10-K for the year ended September 30, 1995, File No. 11271). |
| 10.66 | Firm Transportation Service Agreement dated March 1, 1992 between Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-O to Form 10-K for the year ended September 30, 1994, File No. 1-11271). |
| 10.67 | 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). |
| 10.68 | 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-Q to Form 10-K for the year ended September 30, 1994, File No. 1-11271). |
| 10.69 | Firm Transportation Agreement dated October 27, 1993 between Pacific Gas Transmission Company and Washington Natural Gas Company for firm transportation service from Kingsgate (Exhibit 10-T, Form 10-K for the year ended September 30, 1994, File No. 1-11271). |
| 10.70 | Firm Storage Service Agreement and Amendment dated April 30, 1991 between Questar Pipeline Company and Washington Natural Gas Company for firm storage service at Clay Basin filed under cover of Form SE dated December 23, 1991. |
| 10.71 | 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). |
| 10.72 | Amendment No. 1 to the Puget Energy, Inc. Non-employee Director Stock Plan, effective as of January 1, 2003. |
| 10.73 | 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). |
| 10.74 | 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 |
| 10.75 | 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). |
| 10.76 | Employment agreement with S. P. Reynolds, Chief Executive Officer and President dated January 7, 2002. |
| 10.77 | Credit Agreement dated June 29, 2001, among InfrastruX Group, Inc. and various Banks named therein, BankOne, NA as Administrative Agent. (Exhibit 10-1, Form 10-Q for the quarterly period ended June 30, 2001, Commission File No. 1-4393 and 1-16305). |
| 10.78 | 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). |
| 10.79 | 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). |
| 10.80 | Additional 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 10-3 to Form 10-Q for the quarter ended June 30, 2002, File |
| 10.81 | Credit Agreement dated December 23, 2002 covering PSE and various banks named therein, Bank One, NA as administrative agent. |
| 10.82 | Receivable Purchase Agreement dated December 23, 2002 among PSE, Rainier Receivables, Inc., and Bank One, NA as agent. |
| 10.83 | Receivable Sale Agreement dated December 23, 2002 among PSE and Rainier Receivables, Inc. |
| 10.84 | Employment agreement with J.M. Ryan, Vice President Energy Portfolio Management, dated November 30, 2001. |
| 10.85 | Change-in-Control Agreement with J.M. Ryan, Vice President, Energy Portfolio Management, dated November 30, 2001. |
| * | 10.86 | Change-in-Control Agreement with B. A. Valdman, Senior Vice President, Finance and Chief Financial Officer, dated November 28, 2003. |
| * | 10.87 | Change-in-Control Agreement with S. McLain, Senior Vice President, Operations, dated March 12, 1999. |
| * | 10.88 | Change-in-Control Agreement with M. T. Lennon, President and Chief Executive Officer of InfrastruX, dated May 6, 2002. |
| * | 10.89 | Termination Agreement with T.J. Hogan, Senior Vice President, Regional Service and Community Affairs, dated July 31, 2003. |
| * | 10.90 | Restricted Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, 2004. |
| * | 10.91 | Restricted Stock Unit Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, 2004. |
| * | 12.1 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy |
| * | 12.2 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy |
| * | 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 - |
*Filed herewith.