[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
| /X/ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
[ ]
| / / | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from ___________ to ___________ |
Commission File Number | Exact name of registrant as specified | |
| in its charter, state of incorporation, | ||
address of principal executive offices, | ||
telephone number | I.R.S. Employer Identification Number |
| 1-16305 | PUGET ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-1969407 |
| 1-4393 | PUGET SOUND ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-0374630 |
Title Of Each Class | Name Of Each Exchange On Which Listed | ||
Puget Energy, Inc. | Common Stock, $0.01 par value | ||
| Preferred Share Purchase Rights | NYSE | ||
Puget Sound Energy, Inc. | 8.4% Capital Securities |
Title Of Each Class | |||
Puget Sound Energy, Inc. | Preferred Stock (cumulative, $100 par value) | ||
| 8.231% Capital Securities |
| Yes | /X/ | No | / / |
| Puget Energy, Inc. | Yes | /X/ | No | / / | Puget Sound Energy, Inc. | Yes | / / | No | /X/ |
| Submission of Matters to a Vote of Security Holders | ||||
| Selected Financial Data | |||
| Financial Statements and Supplementary Data | |||
| AFUDC | Allowance for Funds Used During Construction |
| BPA | Bonneville Power Administration |
| CAISO | California Independent System Operator |
| COE | United States Army Corps of Engineers |
| Dth | Dekatherm (one Dth is equal to one MMBtu) |
| Ecology | Washington State Department of Ecology |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FIN | Financial Accounting Standards Board Interpretation |
| FPA | Federal Power Act |
| HCP | Habitat Conservation Plans |
| InfrastruX | InfrastruX Group, Inc. |
| kW | Kilowatts (one kilowatt equals one thousand watts) |
| kWh | Kilowatt Hours (one kWh equals one thousand watt hours) |
| LIBOR | London Interbank Offered Rate |
| LNG | Liquefied Natural Gas |
| MMBtu | One Million British Thermal Units |
| MMS | Minerals Management Service |
| MW | Megawatts (one MW equals one thousand |
| MWh | Megawatt Hours (one MWh equals one thousand kWh) |
| NOPR | Notice of Proposed Rulemaking |
| NYSE | New York Stock Exchange |
| 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 |
| SEC | United States Securities and Exchange Commission |
| SFAS | Statement of Financial Accounting Standards |
| SMD | FERC Standard Market Design |
| Washington Commission | Washington Utilities and Transportation Commission |
| WECO | Western Energy Company |
| · |
| · | financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways and also adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers; |
| · | wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks; |
| · | the effect of wholesale market structures (including, but not limited to, new market design such as Grid West, a regional transmission organization, and Standard Market Design); |
| · | PSE electric or gas distribution system failure, which may impact PSE’s ability to adequately deliver gas supply to its customers; |
| · | weather, which can have a potentially serious impact on PSE’s revenues and its ability to procure adequate supplies of gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies; |
| · | variable hydroelectric conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities; |
| · | plant outages, which can have an adverse impact on PSE’s expenses as it procures adequate supplies to replace the lost energy or dispatches a more expensive resource; |
| · | the ability of gas or electric plant to operate as intended, which if not in proper operating condition or design could limit the capacity of the operating plant; |
| · | the ability to renew contracts for electric and gas supply and the price of renewal; |
| · | blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can have an impact on PSE’s ability to deliver load to its customers; |
| · | the ability to restart generation following a regional transmission disruption; |
| · | failure of the interstate gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver gas supply to its customers; |
| · | the ability to relicense FERC hydroelectric projects at a cost-effective level; |
| · | the amount of collection, if any, of PSE’s receivables from the California Independent System Operator (CAISO) and other parties, and the amount of refunds found to be due from PSE to the |
| · | industrial, commercial and residential growth and demographic patterns in the service territories of PSE; |
| · | general economic conditions in the Pacific Northwest, which might impact customer consumption or affect PSE’s accounts receivable; and |
| · | the loss of significant customers or changes in the business |
| · |
| · |
| · | the inability to generate internal growth at InfrastruX, which could be affected by, among other factors, InfrastruX’s ability to expand the range of services offered to customers, attract new customers, increase the number of projects performed for existing customers, hire and retain employees and open additional facilities; |
| · | the effect of competition in the industry in which InfrastruX competes, including from competitors that may have greater resources than InfrastruX, which may enable them to develop expertise, experience and resources to provide services that are superior in quality or lower in price; |
| · | the extent to which existing electric power and gas companies or prospective customers will continue to outsource services in the future, which may be impacted by, among other things, regional and general economic conditions in the markets InfrastruX serves; |
| · | delinquencies, including those associated with the financial conditions of InfrastruX’s customers; |
| · | the impact of any goodwill impairments on the results of operations of InfrastruX arising from its acquisitions, which could have a negative effect on the results of operations of Puget Energy; |
| · | the impact of adverse weather conditions that negatively affect operating conditions and results; |
| · | the ability to obtain adequate bonding coverage and the cost of such bonding; and |
| · | the perception of risk associated with its business due to a challenging business environment. |
| · | the impact of acts of terrorism or similar significant events; |
| · | the ability of Puget Energy, PSE and InfrastruX to access the capital markets to support requirements for working capital, construction costs and the repayment of maturing debt; |
| · | 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; |
| · | the ability to recover changes in enacted federal, state or local tax laws through revenue in a timely manner; |
| · | changes in, adoption of and compliance with laws and regulations including environmental and endangered species laws, regulations, decisions and policies concerning the environment, natural resources, and fish and wildlife (including the Endangered Species Act); |
| · | employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive; |
| · | the ability to obtain and keep patent or other intellectual property rights to generate revenue; |
| · | the ability to obtain adequate insurance coverage and the cost of such insurance; |
| · | the impacts of natural disasters such as earthquakes, hurricanes, floods, fires or landslides; |
| · | the impact of adverse weather conditions that negatively affect operating conditions and results; |
| · | the ability to maintain effective internal controls over financial reporting; and |
| · | the ability to maintain customers and employees. |
Segment | Percent of Revenue | Percent of Net Income | Percent of Assets | ||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||||||||||||
Puget Sound Energy1 | 85.3 | % | 85.4 | % | 85.8 | % | 224.2 | % | 98.1 | % | 87.4 | % | 94.5 | % | 92.7 | % | 92.2 | % | |||||||||
| InfrastruX | 14.4 | % | 14.3 | % | 13.8 | % | (127.8 | )% | 1.5 | % | 8.6 | % | 4.3 | % | 6.0 | % | 5.5 | % | |||||||||
| Other subsidiaries | 0.3 | % | 0.3 | % | 0.4 | % | 3.6 | % | 0.4 | % | 4.0 | % | 1.2 | % | 1.3 | % | 2.3 | % | |||||||||
| Segment | Percent of Revenue | Percent of Net Income | Percent of Assets | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |||||||||||
| Puget Sound Energy | 86 | .0% | 86 | .2% | 92 | .9% | 98 | .2% | 88 | .3% | 75 | .0% | 92 | .6% | 92 | .2% | 93 | .5% | |
| InfrastruX | 13 | .7% | 13 | .4% | 6 | .0% | 1 | .5% | 8 | .0% | 2 | .4% | 6 | .0% | 5 | .5% | 4 | .0% | |
| Other subsidiaries | 0 | .3% | 0 | .4% | 1 | .1% | 0 | .3% | 3 | .7% | 22 | .6% | 1 | .4% | 2 | .3% | 2 | .5% | |
| 1 | Net income for PSE is presented as net income for common stock due to $5.2 million and $7.8 million of preferred stock dividend being treated as an other deduction at Puget Energy in 2003 and 2002, respectively |
| · |
| · | Signed a two-year purchase power agreement in the second quarter |
| · | Signed a non-binding letter of intent in September 2004 to purchase a wind |
| · | Signed a non-binding letter of intent in October 2004 to purchase a wind generation facility with up to 150 MW of |
| · | Electric: Overhead and underground power line and cable construction, installation and maintenance, including high-voltage transmission and distribution lines, copper and fiberoptic cables; duct installation; revitalization and damage prevention for underground power lines and cables using the patented Cablecure® treatment; substation construction; and other specialty services for new and existing infrastructures. |
| · | Gas: Large-diameter pipeline installation and maintenance; service lines and meters; conventional river crossings and bridge maintenance; cathodic protection; power station fabrication and installation; vacuum excavation; hydrostatic testing; internal pipeline inspection; product pipelines; and other specialty services for distribution and transmission pipeline services including small, mid-size and large-bore directional drilling for virtually all pipeline diameters and soil conditions. |
| Puget Sound Energy | |
| InfrastruX | |
| Total Puget Energy | 4,900 |
| · | Corporate Governance Guidelines; |
| · | Corporate Ethics and Compliance Code; |
| · | Audit Committee, Governance and Public Affairs Committee and Compensation and Leadership Development Committee charters; and |
| · | Code of Ethics for the Company’s Chief Executive Officer and senior financial officers. |
| 1. | The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
| 2. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs. |
| 3. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
| a) | actual Tenaska costs that exceed the benchmark; or |
| b) | the return on the Tenaska regulatory asset. |
| 4. | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs. |
market prices of physical gas and the original contract price, for a total recovery of approximately $10.1 million. In October 2004, PSE believes thatentered into a new contract with another counterparty for the fuel cost disallowances proposedperiod November 2005 through June 2008 to replace the physical gas supply from the previously mentioned amended contract. Also, in the fourth quarter 2004, an accounting order was approved by the Washington Commission staff are legallyto defer the counterparty settlement amount as a regulatory liability and factually deficient, and PSE filedamortize the benefit over the period of November 2005 through June 2008 as a reduction in Electric Generation Fuel expense. In its rebuttal case on February 13, 2004. Washington Commission staff is independent fromaccounting order, the Washington Commission in such a litigated proceeding and their positions do not represent an indicationreserved the right to review the prudence of the final outcomelevel of settlement payments agreed to and the cost 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 may be up to an 11-month process from the time the general rate case is filed.
replacement contract during any affected PCA periods going forward.
| 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.
ANNUAL POWER COST AVAILABILITY | CUSTOMERS’ SHARE | COMPANY’S SHARE1 | ||
| +/- $20 million | 0% | 100% | ||
| +/- $20 - $40 million | 50% | 50% | ||
| +/- $40 - $120 million | 90% | 10% | ||
| +/- $120 million | 95% | 5% | ||
| 1 | Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40 million plus 1% of the excess. Power cost variation after June 30, 2006 will be apportioned on an annual basis, based on the graduated scale. |
FERC. Prior to that approval, on April 7, 2004, the Washington Commission issued an order in PSE’s PCORC granting approval for the acquisition of the Frederickson 1 generating facility as well. As a result of these approvals, PSE completed the acquisition in the second quarter 2004. In its order, the Washington Commission found the acquisition to be prudent and the costs associated with the generating facility reasonable. The costs associated with the generating facility, including projected baseline gas costs, are approved for recovery in rates. The Washington Commission subsequently ordered on May 13, 2004, an increase of cost recovery in rates of $44.1 million annually, beginning May 24, 2004, which includes the ownership, operation and fuel costs of the Frederickson 1 generating facility.
| 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 | ||||
2002:
| EFFECTIVE DATE | PERCENTAGE INCREASE (DECREASE) IN RATES | ANNUAL INCREASE (DECREASE) IN REVENUES (DOLLARS IN MILLIONS) | ||
| October 1, 2004 | 17.6% | $121.7 | ||
| October 1, 2003 | 13.3% | 78.8 | ||
| April 10, 2003 | 20.1% | 103.6 | ||
| November 1, 2002 | (12.5)% | (70.6 | ) | |
| September 1, 2002 | (7.3)% | (45.0 | ) | |
| June 1, 2002 | (21.2)% | (138.9 | ) | |
| 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% | ||||||||
TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Generation and purchased power, MWh | ||||||||||
| Company-controlled resources | 7,048,270 | 6,965,840 | 6,996,276 | |||||||
| Contracted resources | 9,421,546 | 11,021,471 | 12,085,729 | |||||||
Non-firm energy purchased1 | 6,164,457 | 5,179,302 | 4,795,045 | |||||||
| Total generation and purchased power | 22,634,273 | 23,166,613 | 23,877,050 | |||||||
| Less: losses and company use | (1,432,686 | ) | (1,338,401 | ) | (1,341,126 | ) | ||||
| Total energy sales, MWh | 21,201,587 | 21,828,212 | 22,535,924 | |||||||
| Electric energy sales, MWh | ||||||||||
| Residential | 10,028,150 | 9,845,854 | 9,845,527 | |||||||
| Commercial | 8,449,566 | 8,222,166 | 8,012,538 | |||||||
| Industrial | 1,352,660 | 1,372,815 | 1,416,107 | |||||||
| Other customers | 94,034 | 93,438 | 90,840 | |||||||
| Total energy billed to customers | 19,924,410 | 19,534,273 | 19,365,012 | |||||||
| Unbilled energy sales - net increase (decrease) | (40,217 | ) | 65,082 | (102,811 | ) | |||||
| Total energy sales to customers | 19,884,193 | 19,599,355 | 19,262,201 | |||||||
Sales to other utilities and marketers1 | 1,317,394 | 2,228,857 | 3,273,723 | |||||||
| Total energy sales, MWh | 21,201,587 | 21,828,212 | 22,535,924 | |||||||
| Less: optimization purchases for sales to other utilities and marketers | -- | (62,200 | ) | (2,596,505 | ) | |||||
| Transportation, including unbilled | 1,988,965 | 2,020,562 | 2,307,081 | |||||||
| Net electric energy sales and transported, MWh | 23,190,552 | 23,786,574 | 22,246,500 | |||||||
1 | Non-firm energy purchased and Sales to other utilities and marketers in 2003 and 2002 were revised as a result of Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective January 1, 2004. MWh from other utility and marketers/non-firm energy purchased in 2003 and 2002 were reduced 2,941,707 MWh and 2,789,353 MWh, respectively. |
TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Electric operating revenues by classes (thousands): | ||||||||||
| Residential | $ | 628,869 | $ | 603,722 | $ | 616,522 | ||||
| Commercial | 580,973 | 556,038 | 536,021 | |||||||
| Industrial | 88,779 | 88,201 | 90,121 | |||||||
| Other customers | 58,007 | 54,259 | 26,500 | |||||||
Operating revenues billed to customers1 | 1,356,628 | 1,302,220 | 1,269,164 | |||||||
| Unbilled revenues - net increase (decrease) | (813 | ) | 4,193 | (7,118 | ) | |||||
| Total operating revenues from customers | 1,355,815 | 1,306,413 | 1,262,046 | |||||||
| Transportation, including unbilled | 10,707 | 11,542 | 15,551 | |||||||
Sales to other utilities and marketers2 | 56,512 | 84,994 | 75,595 | |||||||
| Less: optimization purchases for sales to other utilities and marketers | -- | (2,206 | ) | (64,448 | ) | |||||
| Total electric operating revenues | $ | 1,423,034 | $ | 1,400,743 | $ | 1,288,744 | ||||
| Number of customers served (average): | ||||||||||
| Residential | 874,205 | 854,088 | 839,878 | |||||||
| Commercial | 109,660 | 108,479 | 104,273 | |||||||
| Industrial | 3,953 | 3,952 | 3,953 | |||||||
| Other | 2,194 | 2,060 | 1,932 | |||||||
| Transportation | 17 | 16 | 16 | |||||||
| Total customers (average) | 990,029 | 968,595 | 950,052 | |||||||
| Average retail revenues per kWh sold: | ||||||||||
| Residential | $ | 0.0627 | $ | 0.0617 | $ | 0.0632 | ||||
| Commercial | 0.0688 | 0.0680 | 0.0675 | |||||||
| Industrial | 0.0656 | 0.0650 | 0.0649 | |||||||
| Average retail revenue per kWh sold | 0.0655 | 0.0646 | 0.0651 | |||||||
| Average revenue billed to residential customers | $ | 719 | $ | 711 | $ | 741 | ||||
| Average kWh used by residential customers | 11,471 | 11,528 | 11,723 | |||||||
| Heating degree days | 4,421 | 4,527 | 4,946 | |||||||
Percent of normal- NOAA 30-year average | 91.8 | % | 94.4 | % | 103.1 | % | ||||
| Load factor | 53.5 | % | 58.9 | % | 61.6 | % | ||||
| 1 | Operating revenues in 2004, 2003 and 2002 were reduced by $0.8 million, $7.7 million and $12.7 million, respectively, as a result of the Company’s sale of $237.7 million of its investment in customer-owned conservation measures in 1995 and 1997. Beginning in July 2003, these related revenues were consolidated as a result of Financial Accounting Standards Board Interpretation No. 46. (See Operating Revenues-Electric in Management’s Discussion and Analysis and Note 1 to the Consolidated Financial Statements.) As of October 2004, the conservation trust bond was fully redeemed and any excess collection was recorded as a reduction in revenues. |
| 2 | Sales to other utilities and marketers in 2003 and 2002 were revised as a result of Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective January 1, 2004. Revenues from other utilities and marketers in 2003 and 2002 were reduced by $108.7 million and $77.1 million, respectively |
PEAK POWER RESOURCES AT DECEMBER 31, | ENERGY PRODUCTION | ||||||||||||||||||||||||
| 2004 | 2003 | 2004 | 2003 | ||||||||||||||||||||||
| MW | % | MW | % | MWh | % | MWh | % | ||||||||||||||||||
| Purchased resources: | |||||||||||||||||||||||||
| Columbia River PUD contracts | 1,350 | 31.0 | % | 1,349 | 30.0 | % | 5,231,691 | 23.1 | % | 5,191,346 | 22.4 | % | |||||||||||||
Other hydroelectric1 | 177 | 4.1 | % | 177 | 3.9 | % | 600,557 | 2.7 | % | 622,900 | 2.7 | % | |||||||||||||
Other producers1 | 1,011 | 23.2 | % | 1,210 | 26.9 | % | 3,589,298 | 15.9 | % | 5,207,225 | 22.5 | % | |||||||||||||
Short-term wholesale energy purchases2 | N/A | N/A | N/A | N/A | 6,164,457 | 27.2 | % | 5,179,302 | 22.4 | % | |||||||||||||||
| Total purchased | 2,538 | 58.3 | % | 2,736 | 60.8 | % | 15,586,003 | 68.9 | % | 16,200,773 | 70.0 | % | |||||||||||||
| Company-controlled resources: | |||||||||||||||||||||||||
| Hydroelectric | 234 | 5.4 | % | 304 | 6.7 | % | 1,130,180 | 5.0 | % | 1,238,900 | 5.3 | % | |||||||||||||
| Coal | 677 | 15.6 | % | 677 | 15.1 | % | 5,119,002 | 22.6 | % | 4,950,734 | 21.4 | % | |||||||||||||
| Natural gas/oil | 902 | 20.7 | % | 778 | 17.4 | % | 799,088 | 3.5 | % | 776,206 | 3.3 | % | |||||||||||||
| Total Company-controlled | 1,813 | 41.7 | % | 1,759 | 39.2 | % | 7,048,270 | 31.1 | % | 6,965,840 | 30.0 | % | |||||||||||||
| Total | 4,351 | 100.0 | % | 4,495 | 100.0 | % | 22,634,273 | 100.0 | % | 23,166,613 | 100.0 | % | |||||||||||||
| 1 |
| 2003 | 2002 | 2003 | 2002 | ||||||||||||||
| KW | % | KW | % | kWh | % | kWh | % | ||||||||||
| Purchased resources: | |||||||||||||||||
| Columbia River PUD contracts | 1,349,460 | 29 | .8% | 1,391,000 | 30 | .4% | 5,191,346 | 19 | .9% | 5,988,118 | 22 | .5% | |||||
| Other hydro1 | 177,160 | 3 | .9% | 175,660 | 3 | .8% | 622,900 | 2 | .4% | 717,215 | 2 | .7% | |||||
| Other producers1 | 1,209,675 | 26 | .7% | 1,209,675 | 26 | .4% | 5,207,225 | 19 | .9% | 5,380,396 | 20 | .2% | |||||
| 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 | 2,736,295 | 60 | .4% | 2,776,335 | 60 | .6% | 19,142,480 | 73 | .3% | 19,670,127 | 73 | .8% | |||||
| Company-controlled resources: | |||||||||||||||||
| Hydro | 310,400 | 6 | .8% | 300,000 | 6 | .6% | 1,238,900 | 4 | .7% | 1,351,540 | 5 | .1% | |||||
| Coal | 700,000 | 15 | .4% | 700,000 | 15 | .3% | 4,950,734 | 19 | .0% | 4,627,901 | 17 | .3% | |||||
| Natural gas/oil | 790,800 | 17 | .4% | 800,800 | 17 | .5% | 776,206 | 3 | .0% | 1,016,835 | 3 | .8% | |||||
| Total Company-controlled | 1,801,200 | 39 | .6% | 1,800,800 | 39 | .4% | 6,965,840 | 26 | .7% | 6,996,276 | 26 | .2% | |||||
| Total | 4,537,495 | 100 | .0% | 4,577,135 | 100 | .0% | 26,108,320 | 100 | .0% | 26,666,403 | 100 | .0% | |||||
| 2 | Short-term wholesale purchases net of resales of 1,317,394 MWh and 2,228,857 MWh account for 22.7% and 14.1% of energy production for 2004 and 2003, respectively. |
PSE is in the process of updating its Least Cost Plan which is expected to be filed with the Washington Commission in the first half of 2005.
| 2006 | 2007 | 2008 | 2009 | 2010 | |
Projected MW Shortfall1 | 208 | 263 | 305 | 360 | 457 |
| 1 | Estimated using all resources under long-term contract and Company-controlled resources. Also includes anticipated acquisitions of the Hopkins Ridge and Wild Horse wind projects which are currently under review. |
| Plant Name | 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 | |
| Upper Baker River | Hydro | 91,000 | 1959 | |
| Lower Baker River | Hydro | 79,000 | Reconstructed 1960 | |
| Upgraded 2001 | ||||
| White River3 | Hydro | 70,000 | 1911 | |
| Snoqualmie Falls | Hydro | 44,400 | 1898 to 1911 and 1957 | |
| Electron | Hydro | 26,000 | 1904 to 1929 | |
| Fredonia Units 1 & 2 | Dual-fuel combustion turbines | 210,000 | 1984 | |
| Fredrickson Units 2 & 3 | Dual-fuel combustion turbines | 150,000 | 1981 | |
| Whitehorn Units 2 & 3 | Dual-fuel combustion turbines | 150,000 | 1981 | |
| Fredonia Units 3 & 4 | Dual-fuel combustion turbines | 108,000 | 2001 | |
| Encogen | Natural gas cogeneration | 170,000 | 1993 | |
| Crystal Mountain | Internal combustion | 2,800 | 1969 |
| PLANT NAME | PLANT TYPE | NET CAPACITY (MW) | YEAR INSTALLED | |
| Colstrip Units 1 & 2 (50% interest) | Coal | 307 | 1975 & 1976 | |
| Colstrip Units 3 & 4 (25% interest) | Coal | 370 | 1984 & 1986 | |
| Fredonia Units 1 & 2 | Dual-fuel combustion turbines | 207 | 1984 | |
| Fredrickson Units 1 & 2 | Dual-fuel combustion turbines | 147 | 1981 | |
| Whitehorn Units 2 & 3 | Dual-fuel combustion turbines | 147 | 1981 | |
| Fredonia Units 3 & 4 | Dual-fuel combustion turbines | 107 | 2001 | |
| Frederickson Unit 1 (49.85% interest) | Natural gas combined cycle | 124 | 2002; Purchased 2004 | |
| Encogen | Natural gas cogeneration | 167 | 1993 | |
| Crystal Mountain | Internal combustion | 3 | 1969 | |
| Upper Baker River | Hydroelectric | 91 | 1959 | |
| Lower Baker River | Hydroelectric | 79 | Reconstructed 1960; Upgraded 2001 | |
| Snoqualmie Falls | Hydroelectric | 42 | 1898 to 1911 and 1957 | |
| Electron | Hydroelectric | 22 | 1904 to 1929 | |
process. PSE and PPL Montana,believes that the other ownerColstrip Units 3 & 4 owners have reasonable defenses in this matter based upon its review. Neither the outcome of this matter nor the associated costs can be predicted at this time.
time.
initiated withOn November 30, 2004, PSE and 23 parties comprised of federal, state and local governmental organizations, Native American Indian tribes, environmental and other nongovernmental entities filed a proposed comprehensive settlement agreement on all issues relating to the National Marine Fisheries Service and United States Fish and Wildlife Service under Section 7relicensing of the Endangered Species Act,Baker River project. The proposed settlement includes a set of proposed license articles and, consultation is ongoing with PSE acting as the non-federal representative during said consultation. PSE anticipates submittingif approved by FERC without material modification, would allow a new license applicationfor 45 years or more. The proposed settlement would require an investment of approximately $360 million (capital expenditures and operations and maintenance cost) in order to relicenseimplement the projectconditions of the new license over the next 30 years. The proposed settlement is subject to contingencies that have yet to be resolved and is subject to additional regulatory approvals yet to be attained from various agencies. FERC has not yet ruled on or beforethe proposed settlement and its ultimate outcome remains uncertain. Assuming that settlement contingencies are resolved and additional regulatory approvals are obtained in a timely manner and on favorable terms, a decision by FERC could occur by April 30, 2004.
2006.
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 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 currently evaluating responses topredicted at this 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.
time.
even if power is not being delivered. These projects are financed through substantially level debt service payments, and their annual costs may vary over the term of the contracts as additional financing is required to meet the costs of major repairs, or replacements, or license requirements, or changes to annual operating and maintenance expenses are required.
| Date of Withdrawal | Withdrawal Percentage | PSE Capacity after Withdrawal |
| July 1, 2003 | 10% | 75% |
| February 1, 2005 | 10% | 65% |
| July 1, 2005 | 10% | 55% |
| November 1, 2006 | 5% | 50% |
DATE OF WITHDRAWAL | WITHDRAWAL PERCENTAGE | PSE % OF CAPACITY AFTER WITHDRAWAL |
| February 1, 2005 | 10% | 65% |
| July 1, 2005 | 10% | 55% |
| November 1, 2006 | 5% | 50% |
winter peaking utility and provides power during the months of June through September. Each party may terminate the contract upon notifying the other party at least five years in advance. On December 20, 2001,
annual period.
| TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas operating revenues by classes (thousands): | |||||||||||
| Residential | $ 401,717 | $ 428,569 | $ 486,761 | ||||||||
| Commercial firm | 149,671 | 167,434 | 196,904 | ||||||||
| Industrial firm | 24,164 | 28,312 | 37,411 | ||||||||
| Interruptible | 34,046 | 48,889 | 71,997 | ||||||||
| Total retail gas sales | 609,598 | 673,204 | 793,073 | ||||||||
| Transportation services | 13,796 | 12,851 | 11,780 | ||||||||
| Other | 10,836 | 11,100 | 10,218 | ||||||||
| Total gas operating revenues | $ 634,230 | $ 697,155 | $ 815,071 | ||||||||
| Number of customers served (average): | |||||||||||
| Residential | 583,439 | 565,003 | 548,497 | ||||||||
| Commercial firm | 46,813 | 45,916 | 45,998 | ||||||||
| Industrial firm | 2,685 | 2,727 | 2,789 | ||||||||
| Interruptible | 611 | 650 | 833 | ||||||||
| Transportation | 134 | 122 | 112 | ||||||||
| Total customers | 633,682 | 614,418 | 598,229 | ||||||||
| Gas volumes, therms (thousands): | |||||||||||
| Residential | 500,116 | 500,672 | 494,648 | ||||||||
| Commercial firm | 216,951 | 218,716 | 214,713 | ||||||||
| Industrial firm | 36,890 | 39,142 | 42,287 | ||||||||
| Interruptible | 61,739 | 81,045 | 98,733 | ||||||||
| Total retail gas volumes, therms | 815,696 | 839,575 | 850,381 | ||||||||
| Transportation volumes | 209,497 | 207,852 | 188,196 | ||||||||
| Total volumes | 1,025,193 | 1,047,427 | 1,038,577 | ||||||||
| Working gas volumes in storage at year end, therms (thousands): | |||||||||||
| Jackson Prairie | 60,365 | 64,583 | 59,537 | ||||||||
| Clay Basin | 49,314 | 51,225 | 73,800 | ||||||||
| Average therms used per customer: | |||||||||||
| Residential | 857 | 886 | 902 | ||||||||
| Commercial firm | 4,634 | 4,763 | 4,668 | ||||||||
| Industrial firm | 13,739 | 14,354 | 15,162 | ||||||||
| Interruptible | 101,046 | 124,685 | 118,527 | ||||||||
| Transportation | 1,563,410 | 1,703,705 | 1,680,321 | ||||||||
| Average revenue per customer: | |||||||||||
| Residential | $ 689 | $ 759 | $ 887 | ||||||||
| Commercial firm | 3,197 | 3,647 | 4,281 | ||||||||
| Industrial firm | 9,000 | 10,382 | 13,414 | ||||||||
| Interruptible | 55,722 | 75,214 | 86,431 | ||||||||
| Transportation | 102,955 | 105,336 | 105,179 | ||||||||
| Average revenue per therm sold: | |||||||||||
| Residential | $ 0.803 | $ 0.855 | $ 0.984 | ||||||||
| Commercial firm | 0.690 | 0.766 | 0.917 | ||||||||
| Industrial firm | 0.655 | 0.723 | 0.885 | ||||||||
| Interruptible | 0.551 | 0.603 | 0.729 | ||||||||
| Average retail revenue per therm sold | 0.747 | 0.802 | 0.933 | ||||||||
| Transportation | 0.066 | 0.062 | 0.063 | ||||||||
TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Gas operating revenues by classes (thousands): | ||||||||||
| Residential | $ | 478,969 | $ | 401,717 | $ | 428,569 | ||||
| Commercial firm | 187,262 | 149,671 | 167,434 | |||||||
| Industrial firm | 30,472 | 24,164 | 28,312 | |||||||
| Interruptible | 46,900 | 34,046 | 48,889 | |||||||
| Total retail gas sales | 743,603 | 609,598 | 673,204 | |||||||
| Transportation services | 12,968 | 13,796 | 12,851 | |||||||
| Other | 12,735 | 10,836 | 11,100 | |||||||
| Total gas operating revenues | $ | 769,306 | $ | 634,230 | $ | 697,155 | ||||
| Number of customers served (average): | ||||||||||
| Residential | 605,505 | 583,439 | 565,003 | |||||||
| Commercial firm | 48,457 | 46,813 | 45,916 | |||||||
| Industrial firm | 2,678 | 2,685 | 2,727 | |||||||
| Interruptible | 576 | 611 | 650 | |||||||
| Transportation | 129 | 134 | 122 | |||||||
| Total customers | 657,345 | 633,682 | 614,418 | |||||||
| Gas volumes, therms (thousands): | ||||||||||
| Residential | 489,036 | 500,116 | 500,672 | |||||||
| Commercial firm | 217,346 | 216,951 | 218,716 | |||||||
| Industrial firm | 36,751 | 36,890 | 39,142 | |||||||
| Interruptible | 65,425 | 61,739 | 81,045 | |||||||
| Total retail gas volumes, therms | 808,558 | 815,696 | 839,575 | |||||||
| Transportation volumes | 201,642 | 209,497 | 207,852 | |||||||
| Total volumes | 1,010,200 | 1,025,193 | 1,047,427 | |||||||
| Working gas volumes in storage at year end, therms (thousands): | ||||||||||
| Jackson Prairie | 70,986 | 60,365 | 64,583 | |||||||
| Clay Basin | 55,044 | 49,314 | 51,225 | |||||||
| Average therms used per customer: | ||||||||||
| Residential | 808 | 857 | 886 | |||||||
| Commercial firm | 4,485 | 4,634 | 4,763 | |||||||
| Industrial firm | 13,723 | 13,739 | 14,354 | |||||||
| Interruptible | 113,585 | 101,046 | 124,685 | |||||||
| Transportation | 1,563,116 | 1,563,410 | 1,703,705 | |||||||
| Average revenue per customer: | ||||||||||
| Residential | $ | 791 | $ | 689 | $ | 759 | ||||
| Commercial firm | 3,864 | 3,197 | 3,647 | |||||||
| Industrial firm | 11,379 | 9,000 | 10,382 | |||||||
| Interruptible | 81,424 | 55,722 | 75,214 | |||||||
| Transportation | 100,527 | 102,955 | 105,336 | |||||||
| Average revenue per therm sold: | ||||||||||
| Residential | $ | 0.979 | $ | 0.803 | $ | 0.855 | ||||
| Commercial firm | 0.862 | 0.690 | 0.766 | |||||||
| Industrial firm | 0.829 | 0.655 | 0.723 | |||||||
| Interruptible | 0.717 | 0.551 | 0.603 | |||||||
| Average retail revenue per therm sold | 0.920 | 0.747 | 0.802 | |||||||
| Transportation | 0.064 | 0.066 | 0.062 | |||||||
| 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. | |||||||||
| 2004 | 2003 | ||||||||||||
| PEAK FIRM GAS SUPPLY AT DECEMBER 31 | Dth per Day | % | Dth per Day | % | |||||||||
| Purchased gas supply: | |||||||||||||
| British Columbia | 198,000 | 22.7 | % | 171,000 | 20.0 | % | |||||||
| Alberta | 50,000 | 5.7 | % | 78,000 | 9.2 | % | |||||||
| United States | 145,000 | 16.6 | % | 100,000 | 11.7 | % | |||||||
| Total purchased gas supply | 393,000 | 45.0 | % | 349,000 | 40.9 | % | |||||||
| Purchased storage capacity: | |||||||||||||
| Clay Basin | 48,000 | 5.5 | % | 55,800 | 6.5 | % | |||||||
| Jackson Prairie | 55,100 | 6.3 | % | 55,100 | 6.4 | % | |||||||
| LNG | 70,500 | 8.1 | % | 70,500 | 8.2 | % | |||||||
| Total purchased storage capacity | 173,600 | 19.9 | % | 181,400 | 21.1 | % | |||||||
| Owned storage capacity: | |||||||||||||
| Jackson Prairie | 294,700 | 33.7 | % | 294,700 | 34.4 | % | |||||||
| Propane-air and other | 12,500 | 1.4 | % | 30,500 | 3.6 | % | |||||||
| Total owned storage capacity | 307,200 | 35.1 | % | 325,200 | 38.0 | % | |||||||
| Total peak firm gas supply | 873,800 | 100.0 | % | 855,600 | 100.0 | % | |||||||
| Other and commitments with third parties | (53,100 | ) | (53,200 | ) | |||||||||
| Total net peak firm gas supply | 820,700 | 802,400 | |||||||||||
transportation arrangements. Gas and services are marketed outside PSE’s service territory (off-system sales) whenever on-system customer demand requirements permit.between gas supply basins. The geographic mix of suppliers and daily, monthly and annual take requirements permit some degree of flexibility in managing gas supplies during off-peak periods to minimize costs.
GAS TRANSPORTATION CAPACITY PSE currently holds firm transportation capacity on pipelines owned by NWP, Gas Transmission Northwest and Duke Energy Gas 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 and WNG CAP I, a wholly-owned subsidiary of PSE, hold firm year-round capacity on NWP through various contracts. PSE and WNG CAP I participate in the secondary pipeline capacity market to achieve savings for PSE’s customers. As a result, PSE and WNG CAP I hold approximately 465,000 Dth per day of capacity due to capacity release and segmentation transactions on NWP which provides firm delivery tois marketed outside 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 NWP have remaining terms ranging from less than 1 year to 13 years. However, PSE has either the unilateral right to extend the contracts under their current terms or the right of first refusal to extend such contracts under current FERC orders. PSE’s firm transportation capacity on Gas Transmission Northwest’s pipeline, totaling approximately 90,000 Dth per day, has a remaining term of 20 years. PSE’s firm transportation capacity on Duke Energy Gas Transmission’s pipeline, totaling approximately 40,000 Dth per day, has 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 contract obligations to PSE, which may include new pipeline construction or purchase of firm capacity from customers of NWP who have excess capacity. PSE does not expect the line to 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 itsterritory (off-system sales) whenever on-system customer needs throughout the pipeline repair or remediation period.demand requirements permit.
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. Consultation with federal agencies is ongoing.
NAME | AGE | OFFICES |
| S. P. Reynolds | 56 | President and Chief Executive Officer since January 2002. Director since January 2002. |
| J. W. Eldredge | Corporate Secretary and Chief Accounting Officer since April 1999. | |
| D. E. Gaines | Vice President Finance and Treasurer since March 2002. | |
| M. T. Lennon | 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 - | |
| J. L. | Vice President and General Counsel since January 2003. | |
| B. A. Valdman | 41 | Senior Vice President Finance and Chief Financial Officer since January 2004. |
NAME | AGE | OFFICES |
| S. P. Reynolds | 56 | President and Chief Executive Officer and Director since January 2002; President and Chief Executive Officer of Reynolds Energy International, 1998 - |
| D. P. Brady | 40 | Vice President Customer Services since February 2003; Director and Assistant to Chief Operating Officer, 2002 - 2003. Prior to joining PSE, he was Managing Director of Irvine Associates Merchant Banking Group, 2001 - 2002; Executive Vice President-Operations of Orcom Solutions, 2000 - |
| P. K. Bussey | Vice President Regional and Public Affairs since September 2003. Prior to joining PSE, he was President of the Washington Round Table, 1996 - 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. | |
| D. E. Gaines | Vice President Finance and Treasurer since March 2002; Vice President and Treasurer, 2001 - 2002; Treasurer, 1994 - 2001. | |
| K. J. Harris | Vice President | |
| J. L. Henry | Senior Vice President Energy Efficiency and Customer Services since February 2003; Director of Major Accounts, 2001 - 2003; Director Construction and Technical Field Services | |
| E. M. Markell | 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 - | |
| S. McLain | Senior Vice President Operations since February 2003; Vice President Operations - Delivery, 1999 - 2003. | |
| J. L. | 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. | |
| J. M. Ryan | 42 | Vice President Risk Management and Strategic Planning since April 2004; Vice President Energy Portfolio Management, |
| B. A. Valdman | 41 | Senior Vice President Finance and Chief Financial Officer since December 2003. Prior to joining PSE, he was Managing Director with JP Morgan Securities, Inc., 2000 - 2003 and a member of the |
| P. M. Wiegand | Vice President Project Development and Contract Management since July 2003; Vice President Corporate Planning, 2003; Vice President Corporate Planning and Performance, 2002 - 2003; Vice President Risk Management and Strategic Planning 2000 - |
The majority of InfrastruX’s owned facilities are subject to liens under existing debt and lines of credit. InfrastruX’s corporate headquarters is housed in a leased building located in Bellevue, Washington.
| | 2003 | | 2002 | | |||||||||
| PRICE RANGE | DIVIDENDS | PRICE RANGE | DIVIDENDS | ||||||||||
| QUARTER ENDED | HIGH | LOW | PAID | HIGH | LOW | PAID | |||||||
| March 31 | $ | 23.00 | $ | 18.10 | $ | 0.25 | $ | 23.60 | $ | 19.20 | $ | 0.46 | |
| June 30 | 24.40 | 20.78 | 0.25 | 21.23 | 19.27 | 0.25 | |||||||
| September 30 | 24.17 | 21.02 | 0.25 | 22.50 | 16.63 | 0.25 | |||||||
| December 31 | 23.99 | 22.14 | 0.25 | 22.64 | 18.75 | 0.25 | |||||||
2004 | 2003 | ||||||||||||
| PRICE RANGE | DIVIDENDS | PRICE RANGE | DIVIDENDS | ||||||||||
| QUARTER ENDED | HIGH | LOW | PAID | HIGH | LOW | PAID | |||||||
| March 31 | $23.92 | $21.59 | $0.25 | $23.00 | $18.10 | $0.25 | |||||||
| June 30 | 22.88 | 20.51 | 0.25 | 24.40 | 20.78 | 0.25 | |||||||
| September 30 | 23.00 | 21.05 | 0.25 | 24.17 | 21.02 | 0.25 | |||||||
| December 31 | 24.81 | 22.27 | 0.25 | 23.99 | 22.14 | 0.25 | |||||||
2004.
| 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 | -- | -- | -- | -- | ||||||
Puget Energy Summary of Operations (Dollars in Thousands, Except Per Share Data) | ||||||||||
| Years Ended December 31 | 2004 | 20031 | 2002 | 20012 | 20003 | |||||
Operating revenue4 | $ | 2,568,813 | $ | 2,382,803 | $ | 2,315,181 | $ | 2,886,560 | $ | 3,302,296 |
| Operating income | 216,751 | 305,175 | 309,669 | 297,121 | 363,872 | |||||
Net income before cumulative effect of accounting change | 55,022 | 116,366 | 110,052 | 113,175 | 193,831 | |||||
Net income from continuing operations5 | 55,022 | 116,197 | 110,052 | 98,426 | 184,837 | |||||
Basic earnings per common share from continuing operations | 0.55 | 1.23 | 1.24 | 1.14 | 2.16 | |||||
| Diluted earnings per common share from continuing operations | 0.55 | 1.22 | 1.24 | 1.14 | 2.16 | |||||
| Dividends per common share | $ | 1.00 | $ | 1.00 | $ | 1.21 | $ | 1.84 | $ | 1.84 |
| Book value per common share | 16.25 | 16.71 | 16.27 | 15.66 | 16.61 | |||||
| Total assets at year end | $ | 5,833,369 | $ | 5,699,002 | $ | 5,772,133 | $ | 5,668,481 | $ | 5,677,266 |
| Long-term obligations | 2,212,532 | 1,969,489 | 2,160,276 | 2,127,054 | 2,170,797 | |||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | 43,162 | 50,662 | 58,162 | |||||
| Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | -- | -- | 300,000 | 300,000 | 100,000 | |||||
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | 280,250 | 280,250 | -- | -- | -- | |||||
| 1 | In 2003, |
| 2 | In 2001, SFAS No. 133 was implemented, which required derivative instruments to be valued at fair |
| 3 | Amounts represent PSE activity prior to the formation of Puget Energy as a holding company of PSE on January 1, 2001. |
| 4 | Operating Electric Revenues and Purchased Electricity expenses in 2003 and 2002 were revised as a result of implementing Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective on January 1, 2004. Operating Electric Revenues and Purchased Electricity expense for Puget Energy and Puget Sound Energy were reduced by $108.7 million and $77.1 million in 2003 and 2002, respectively, with no effect on net income. Information for 2001 and 2000 is not available, and therefore revenue and expense were not adjusted for the effects of EITF No. 03-11 in those years. |
| 5 | Net income in 2000 includes preferred stock dividend accrual at PSE, which is treated as an other deduction at Puget Energy starting January 1, 2001. |
Puget Sound Energy Summary of Operations (Dollars in Thousands) | ||||||||||
| Years Ended December 31 | 2004 | 20031 | 2002 | 20012 | 2000 | |||||
Operating revenue3 | $ | 2,198,877 | $ | 2,041,016 | $ | 1,995,652 | $ | 2,712,774 | $ | 3,302,296 |
| Operating income | 288,241 | 297,904 | 294,593 | 288,480 | 363,8872 | |||||
Net income before cumulative effect of accounting change | 126,192 | 120,055 | 108,948 | 119,130 | 193,831 | |||||
Income for common stock from continuing operations | 126,192 | 114,735 | 101,117 | 95,968 | 184,837 | |||||
| Total assets at year end | $ | 5,564,087 | $ | 5,359,104 | $ | 5,453,390 | $ | 5,439,253 | $ | 5,677,266 |
| Long-term obligations | 2,064,360 | 1,950,347 | 2,021,832 | 2,053,815 | 2,170,797 | |||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | 43,162 | 50,662 | 58,162 | |||||
Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | -- | -- | 300,000 | 300,000 | 100,000 | |||||
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | 280,250 | 280,250 | -- | -- | -- | |||||
| 1 | In 2003, FASB issued Interpretation No. 46 (FIN 46) which required the consolidation of PSE’s 1995 Conservation Trust Transaction. As a result, revenues and expense increased $5.7 million with no effect on net income, and assets and liabilities increased $4.2 million in 2003. FIN 46 also required deconsolidation of PSE’s trust preferred securities that are now classified as junior subordinated debt. This deconsolidation has no impact on assets, liabilities, receivables or earnings for 2003. |
| 2 | In 2001, SFAS No. 133 was implemented, which required derivative instruments to be valued at fair price. |
| 3 | Operating Electric Revenues and Purchased Electricity Expenses in 2003 and 2002 were revised as a result of implementing Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective on January 1, 2004. Operating Electric revenues and Purchased Electricity expense for Puget Energy and Puget Sound Energy were reduced by $108.7 million and $77.1 million in 2003 and 2002, respectively, with no effect on net income. Information for 2001 and 2000 is not available, and therefore revenue and expense were not adjusted for the effects of EITF No. 03-11 in those years. |
licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent to the utility industry as a whole, including weather changes affecting purchases and sales of energy; outages at owned and non-owned generation plants where energy is obtained; storms or other events which can damage electric distribution and transmission lines; and energy trading and wholesale market stability over time.
| · | Purchased a 49.85% interest in a 250 MW capacity gas-fired generation facility in western Washington, which went into service in April 2004. |
| · | Signed a two-year purchase power agreement in the second quarter 2004 with another utility for 85 MW of energy with delivery beginning January 1, 2005. |
| · | Signed a non-binding letter of intent in September 2004 to purchase a wind generation facility with up to 230 MW of generation to be developed in central Washington State. |
| · | Signed a non-binding letter of intent in October 2004 to purchase a wind generation facility with up to 150 MW of generation to be developed in eastern Washington State. |
resources.PSE is in the process of updating its Least Cost Plan and expects to file the updated plan with the Washington Commission in the first half of 2005.
| 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 | ||||||||||||||
| The following table displays the details of electric margin changes from 2003 to 2004. |
| ELECTRIC MARGIN | |||||||||||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | CHANGE | PERCENT CHANGE | |||||||||
| Electric retail sales revenue | $ | 1,310.9 | $ | 1,272.7 | $ | 38.2 | 3.0 | % | |||||
| Electric transportation revenue | 10.7 | 11.5 | (0.8 | ) | (7.0 | ) | |||||||
| Other electric revenue-gas supply resale | 11.5 | 9.1 | 2.4 | 26.4 | |||||||||
| Total electric revenue for margin | 1,333.1 | 1,293.3 | 39.8 | 3.1 | |||||||||
| Adjustments for amounts included in revenue: | |||||||||||||
| Pass-through tariff items | (25.4 | ) | (45.2 | ) | 19.8 | 43.8 | |||||||
| Pass-through revenue-sensitive taxes | (94.2 | ) | (91.0 | ) | (3.2 | ) | (3.5 | ) | |||||
| Residential exchange credit | 174.5 | 173.8 | 0.7 | 0.4 | |||||||||
| Net electric revenue for margin | 1,388.0 | 1,330.9 | 57.1 | 4.3 | |||||||||
| Minus power costs: | |||||||||||||
| Fuel | (80.7 | ) | (65.0 | ) | (15.7 | ) | (24.2 | ) | |||||
| Purchased electricity, net of sales to other utilities and marketers | (660.3 | ) | (635.2 | ) | (25.1 | ) | (4.0 | ) | |||||
| Total electric power costs | (741.0 | ) | (700.2 | ) | (40.8 | ) | (5.8 | ) | |||||
| Electric margin before PCA | 647.0 | 630.7 | 16.3 | 2.6 | |||||||||
| Tenaska disallowance reserve through May 23, 2004 | (36.5 | ) | -- | (36.5 | ) | * | |||||||
| Tenaska reserve turnaround | 10.5 | -- | 10.5 | * | |||||||||
| Power cost deferred under the PCA mechanism | 19.1 | 3.5 | 15.6 | * | |||||||||
| Electric margin | $ | 640.1 | $ | 634.2 | $ | 5.9 | 0.9 | % | |||||
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 effectPCORC rate increase. PSE incurred $34.8 million in excess power costs in 2003 before reaching the $40 million PCA mechanism cap in 2003. In addition, the PCORC rate increase of 3.2% related to the generalFrederickson 1 generating facility became effective on May 24, 2004. This rate case.increase provided an additional $6.5 million to electric margin in 2004 to recover utility operation and maintenance costs, depreciation and property taxes related to the Frederickson 1 generating facility. Also, retail customer kWh sales (residential, commercial and industrial customers) increased 1.5% in 2004 compared to 2003, which along with a change in customer class usage provided an additional $11.7 million to electric margin. These increases were partially offset by the disallowance of certain gas costs for the Tenaska generating facility also ordered in the PCORC, which resulted in a $43.4 million reduction of electric margin in 2004. In addition, a charge of $3.6 million associated with Colstrip Units 1 & 2 coal supply repricing arbitration and Colstrip Units 3 & 4 royalty charge resulted in a negative impact to electric margin. 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.
| GAS MARGIN | |||||||||||||
(DOLLARS IN MILLION) TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | CHANGE | PERCENT CHANGE | |||||||||
| Gas retail revenue | $ | 743.6 | $ | 609.6 | $ | 134.0 | 22.0 | % | |||||
| Gas transportation revenue | 13.0 | 13.8 | (0.8 | ) | (5.8 | ) | |||||||
| Total gas revenue for margin | 756.6 | 623.4 | 133.2 | 21.4 | |||||||||
| Adjustments for amounts included in revenue: | |||||||||||||
| Gas revenue hedge | -- | 0.2 | (0.2 | ) | * | ||||||||
| Pass-through tariff items | (3.6 | ) | (3.8 | ) | 0.2 | 5.3 | |||||||
| Pass-through revenue-sensitive taxes | (59.3 | ) | (48.5 | ) | (10.8 | ) | (22.3 | ) | |||||
| Net gas revenue for margin | 693.7 | 571.3 | 122.4 | 21.4 | |||||||||
| Minus purchased gas costs | (451.3 | ) | (327.1 | ) | (124.2 | ) | (38.0 | ) | |||||
| Gas margin | $ | 242.4 | $ | 244.2 | $ | (1.8 | ) | (0.7 | )% | ||||
| 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 | |||||||||||
| (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 ENERGYto 2004.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | CHANGE | PERCENT CHANGE | |||||||||
| Electric operating revenues: | |||||||||||||
| Residential sales | $ | 628.9 | $ | 603.7 | $ | 25.2 | 4.2 | % | |||||
| Commercial sales | 581.0 | 556.0 | 25.0 | 4.5 | |||||||||
| Industrial sales | 88.8 | 88.2 | 0.6 | 0.7 | |||||||||
| Transportation sales | 10.7 | 11.5 | (0.8 | ) | (7.0 | ) | |||||||
| Sales to other utilities and marketers | 56.5 | 82.8 | (26.3 | ) | (31.8 | ) | |||||||
| Other | 57.1 | 58.5 | (1.4 | ) | (2.4 | ) | |||||||
| Total electric operating revenues | $ | 1,423.0 | $ | 1,400.7 | $ | 22.3 | 1.6 | % | |||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | CHANGE | PERCENT CHANGE | |||||||||
| Gas operating revenues: | |||||||||||||
| Residential sales | $ | 479.0 | $ | 401.7 | $ | 77.3 | 19.2 | % | |||||
| Commercial sales | 225.8 | 178.2 | 47.6 | 26.7 | |||||||||
| Industrial sales | 38.8 | 29.7 | 9.1 | 30.6 | |||||||||
| Transportation sales | 13.0 | 13.8 | (0.8 | ) | (5.8 | ) | |||||||
| Other | 12.7 | 10.8 | 1.9 | 17.6 | |||||||||
| Total gas operating revenues | $ | 769.3 | $ | 634.2 | $ | 135.1 | 21.3 | % | |||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | CHANGE | PERCENT CHANGE | |||||||||
| Purchased electricity | $ | 723.6 | $ | 714.5 | $ | 9.1 | 1.3 | % | |||||
| Electric generation fuel | 80.8 | 65.0 | 15.8 | 24.3 | |||||||||
| Purchased gas | 451.3 | 327.1 | 124.2 | 38.0 | |||||||||
| Utility operations and maintenance | 291.2 | 289.7 | 1.5 | 0.5 | |||||||||
| Depreciation and amortization | 228.6 | 220.1 | 8.5 | 3.9 | |||||||||
| Conservation amortization | 22.7 | 33.5 | (10.8 | ) | (32.2 | ) | |||||||
| Taxes other than income taxes | 209.0 | 194.9 | 14.1 | 7.2 | |||||||||
| Income taxes | 77.1 | 70.9 | 6.2 | 8.7 | |||||||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2004 | 2003 | CHANGE | PERCENT CHANGE | |||||||||
| Other income (net of tax) | $ | 4.4 | $ | 1.6 | $ | 2.8 | 175.0 | % | |||||
| Interest charges | 166.4 | 179.4 | (13.0 | ) | (7.2 | ) | |||||||
| Preferred stock dividends | -- | 5.2 | (5.2 | ) | (100.0 | ) | |||||||
(DOLLARS IN MILLIONS) YEARS ENDED DECEMBER 31 | 2004 | 2003 | CHANGE | PERCENT CHANGE | |||||||||
| Operating revenue: | |||||||||||||
| Non-utility construction services | $ | 369.9 | $ | 341.8 | $ | 28.1 | 8.2 | % | |||||
| Other operations and maintenance | $ | 320.2 | $ | 302.4 | $ | 17.8 | 5.9 | % | |||||
| Depreciation and amortization | 18.3 | 16.8 | 1.5 | 8.9 | |||||||||
| Goodwill impairment | 91.2 | -- | 91.2 | * | |||||||||
| Income taxes | (1.8 | ) | 1.6 | (3.4 | ) | (212.5 | ) | ||||||
| Interest charges | $ | 6.5 | $ | 5.5 | $ | 1.0 | 18.2 | % | |||||
| Minority interest | 7.1 | (0.2 | ) | 7.3 | * | ||||||||
| ELECTRIC MARGIN | |||||||||||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | CHANGE | PERCENT CHANGE | |||||||||
| Electric retail sales revenue | $ | 1,272.7 | $ | 1,260.9 | $ | 11.8 | 0.9 | % | |||||
| Electric transportation revenue | 11.5 | 15.6 | (4.1 | ) | (26.3 | ) | |||||||
| Other electric revenue-gas supply resale | 9.1 | (20.4 | ) | 29.5 | 144.6 | ||||||||
| Total electric revenue for margin | 1,293.3 | 1,256.1 | 37.2 | 3.0 | |||||||||
| Adjustments for amounts included in revenue: | |||||||||||||
| Pass-through tariff items | (45.2 | ) | (32.1 | ) | (13.1 | ) | (40.8 | ) | |||||
| Pass-through revenue-sensitive taxes | (91.0 | ) | (88.5 | ) | (2.5 | ) | (2.8 | ) | |||||
| Residential exchange credit | 173.8 | 150.0 | 23.8 | 15.9 | |||||||||
| Net electric revenue for margin | 1,330.9 | 1,285.5 | 45.4 | 3.5 | |||||||||
| Minus power costs: | |||||||||||||
| Fuel | (65.0 | ) | (113.5 | ) | 48.5 | 42.7 | |||||||
Purchased electricity, net of sales to other utilities and marketers | (635.2 | ) | (557.1 | ) | (78.1 | ) | (14.0 | ) | |||||
| Total electric power costs | (700.2 | ) | (670.6 | ) | (29.6 | ) | (4.4 | ) | |||||
| Electric margin before PCA | 630.7 | 614.9 | 15.8 | 2.6 | |||||||||
| Power cost deferred under the PCA mechanism | 3.5 | -- | 3.5 | * | |||||||||
| Electric margin | $ | 634.2 | $ | 614.9 | $ | 19.3 | 3.1 | % | |||||
| GAS MARGIN | |||||||||||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | CHANGE | PERCENT CHANGE | |||||||||
| Gas retail revenue | $ | 609.6 | $ | 673.2 | $ | (63.6 | ) | (9.4 | )% | ||||
| Gas transportation revenue | 13.8 | 12.9 | 0.9 | 7.0 | |||||||||
| Total gas revenue for margin | 623.4 | 686.1 | (62.7 | ) | (9.1 | ) | |||||||
| Adjustments for amounts included in revenue: | |||||||||||||
| Gas revenue hedge | 0.2 | 0.6 | (0.4 | ) | (66.7 | ) | |||||||
| Pass-through tariff items | (3.8 | ) | (2.3 | ) | (1.5 | ) | (65.2 | ) | |||||
| Pass-through revenue-sensitive taxes | (48.5 | ) | (54.3 | ) | 5.8 | 10.7 | |||||||
| Net gas revenue for margin | 571.3 | 630.1 | (58.8 | ) | (9.3 | ) | |||||||
| Minus purchased gas costs | (327.1 | ) | (405.0 | ) | 77.9 | 19.2 | |||||||
| Gas margin | $ | 244.2 | $ | 225.1 | $ | 19.1 | 8.5 | % | |||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | CHANGE | PERCENT CHANGE | |||||||||
| Electric operating revenues: | |||||||||||||
| Residential sales | $ | 603.7 | $ | 616.5 | $ | (12.8 | ) | (2.0 | )% | ||||
| Commercial sales | 556.0 | 536.0 | 20.0 | 3.7 | |||||||||
| Industrial sales | 88.2 | 90.1 | (1.9 | ) | (2.1 | ) | |||||||
| Transportation sales | 11.5 | 15.6 | (4.1 | ) | (26.2 | ) | |||||||
| Sales to other utilities and marketers | 82.8 | 11.1 | 71.7 | * | |||||||||
| Other | 58.5 | 19.4 | 39.1 | 201.5 | |||||||||
| Total electric operating revenues | $ | 1,400.7 | $ | 1,288.7 | $ | 112.0 | 8.7 | % | |||||
OPERATING REVENUES – GAS2003.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | CHANGE | PERCENT CHANGE | |||||||||
| Gas operating revenues: | |||||||||||||
| Residential sales | $ | 401.7 | $ | 428.6 | $ | (26.9 | ) | (6.3 | )% | ||||
| Commercial sales | 178.2 | 209.5 | (31.3 | ) | (14.9 | ) | |||||||
| Industrial sales | 29.7 | 35.1 | (5.4 | ) | (15.4 | ) | |||||||
| Transportation sales | 13.8 | 12.9 | 0.9 | 7.0 | |||||||||
| Other | 10.8 | 11.1 | (0.3 | ) | (2.7 | ) | |||||||
| Total gas operating revenues | $ | 634.2 | $ | 697.2 | $ | (63.0 | ) | (9.0 | )% | ||||
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | CHANGE | PERCENT CHANGE | |||||||||
| Purchased electricity | $ | 714.5 | $ | 568.2 | $ | 146.3 | 25.7 | % | |||||
| Electric generation fuel | 65.0 | 113.5 | (48.5 | ) | (42.7 | ) | |||||||
| Residential exchange power cost credit | (173.8 | ) | (149.9 | ) | (23.9 | ) | (15.9 | ) | |||||
| Purchased gas | 327.1 | 405.0 | (77.9 | ) | (19.2 | ) | |||||||
| Unrealized (gain) loss on derivative instruments | 0.1 | (11.6 | ) | 11.7 | 100.8 | ||||||||
| Utility operations and maintenance | 289.7 | 286.2 | 3.5 | 1.2 | |||||||||
| Depreciation and amortization | 220.1 | 215.3 | 4.8 | 2.2 | |||||||||
| Conservation amortization | 33.4 | 17.5 | 15.9 | 90.9 | |||||||||
| Taxes other than income taxes | 194.9 | 202.4 | (7.5 | ) | (3.7 | ) | |||||||
| Income taxes | 70.9 | 52.8 | 18.1 | 34.2 | |||||||||
any gas costs that exceed or fall short of the amount in PGA mechanism rates and accrues interest under the PGA.PGA mechanism. The PGA liability balance at December 31, 2003 was $12.0 million compared to a liability balance of $83.8 million at December 31, 2002.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.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | CHANGE | PERCENT CHANGE | |||||||||
| Other income (net of tax) | $ | 1.6 | $ | 5.2 | $ | (3.6 | ) | (69.2 | )% | ||||
| Interest charges | 179.4 | 190.9 | (11.5 | ) | (6.0 | ) | |||||||
| Preferred stock dividends | 5.2 | 7.8 | (2.6 | ) | (33.3 | ) | |||||||
| 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.
INFRASTRUX2003 COMPARED TO 2002InfrastruX revenueincreased $22.3decreased $2.6 million in 2003 compared to 2002 due to the redemption of the 7.45% series preferred stock not subject to mandatory redemption for both sinking fund requirements and total redemption of the remaining shares in the series at par value plus accrued dividends in 2003.
(DOLLARS IN MILLIONS) TWELVE MONTHS ENDED DECEMBER 31 | 2003 | 2002 | CHANGE | PERCENT CHANGE | |||||||||
| Non-utility construction services revenue | $ | 341.8 | $ | 319.5 | $ | 22.3 | 7.0 | % | |||||
| Other operations and maintenance | $ | 302.4 | $ | 270.7 | $ | 31.7 | 11.7 | % | |||||
| Depreciation and amortization | 16.8 | 13.5 | 3.3 | 24.4 | |||||||||
| Income taxes | 1.6 | 6.7 | (5.1 | ) | (76.1 | ) | |||||||
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 $22.8 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 EXPENSESPurchased 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-priced wholesale market forced PSE to purchase additional energy during that period to meet retail electric customer loads. In a normal water year, PSE obtains about 38% of its energy supply from low-cost hydroelectric facilities, primarily from dams below Grand Coulee on the Columbia River. PSE’s share of the power costs through December 31, 2002 was $5.2 million.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 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. 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 $14.8 million after-tax transition loss was recorded in 2001 from recognizing the cumulative effect of this change in accounting principle.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 Units 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-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 recorded under SFAS No. 87, “Employers’ Accounting for 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 66.8% of the annual qualified pension income of $17.7 million for 2002 was recorded as a reduction in operations and maintenance expense compared to 58.0% of $20.0 million for 2001. PSE’sother operations and maintenanceexpenses decreased $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 $6.6 million in 2002 compared to 2001 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 taxesdecreased $5.0 million in 2002 compared to 2001 due primarily to a decrease in revenue-based Washington State excise tax and municipal tax. This was 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-year period ending June 30, 2001 related to Oregon State property tax bills on PSE’s long-term Third AC Transmission Intertie contract.Income taxesdecreased $24.1 million in 2002 compared to 2001. The decrease in 2002 included a total of $10.3 million in refunds at PSE which are composed of $4.1 million related to the audit of the Company’s 1998 and 1999 federal income tax returns, a $3.5 million reduction to expense representing an adjustment to 2001 federal income taxes based on the 2001 federal tax return and a $2.7 million reduction in expense 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 $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 $4.5 million in 2002 compared to 2001 primarily as a result 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.
INFRASTRUX2002 COMPARED TO 2001InfrastruX 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 $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-price projects.InfrastruX operations 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 operations 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 InfrastruX 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 were completed.Income taxesincreased $3.7 million in 2002 compared to 2001 due primarily to the acquisition of companies 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 InfrastruX’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.
CAPITAL RESOURCES AND LIQUIDITY
| Puget Energy | Payments Due Per Period | ||||||||||||||||
| CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | Total | 2004 | 2005- 2006 | 2007- 2008 | 2009 and Thereafter | ||||||||||||
| Long-term debt | $ | 2,216 | .3 | $ | 246 | .8 | $ | 128 | .3 | $ | 307 | .3 | $ | 1,533 | .9 | ||
| Short-term debt | 13 | .9 | 13 | .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 | |||||||
| Capital lease obligations | 6 | .5 | 1 | .6 | 2 | .9 | 2 | .0 | -- | ||||||||
| Non-cancelable operating leases | 72 | .5 | 18 | .0 | 25 | .1 | 19 | .0 | 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 | $ | 7,685 | .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 | 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 | $ | -- | |||
Puget Energy | Payments Due Per Period | |||||||||
CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter | |||||
| Long-term debt | $ | 2,251.4 | $ | 38.9 | $ | 552.0 | $ | 339.5 | $ | 1,321.0 |
| Short-term debt | 8.3 | 8.3 | -- | -- | -- | |||||
Junior subordinated debentures payable to a subsidiary trust1 | 280.3 | -- | -- | -- | 280.3 | |||||
| Mandatorily redeemable preferred stock | 1.9 | -- | -- | -- | 1.9 | |||||
| Service contract obligations | 168.6 | 21.5 | 48.6 | 47.7 | 50.8 | |||||
| Capital lease obligations | 7.0 | 2.0 | 3.6 | 1.4 | -- | |||||
| Non-cancelable operating leases | 129.5 | 19.3 | 37.3 | 26.8 | 46.1 | |||||
Fredonia combustion turbines lease2 | 65.3 | 4.6 | 8.6 | 8.3 | 43.8 | |||||
| Energy purchase obligations | 4,988.2 | 929.4 | 1,491.0 | 1,278.2 | 1,289.6 | |||||
| Financial hedge obligations | 20.0 | 6.2 | 11.9 | 1.9 | -- | |||||
| Pension funding | 45.7 | 4.3 | 8.2 | 9.8 | 23.4 | |||||
| Total contractual cash obligations | $ | 7,966.2 | $ | 1,034.5 | $ | 2,161.2 | $ | 1,713.6 | $ | 3,056.9 |
Amount of Committment Expiration Per Period | ||||||||||
COMMERCIAL COMMITMENTS (DOLLARS IN MILLIONS) | Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter | |||||
Guarantees3 | $ | 131.0 | $ | -- | $ | 131.0 | $ | -- | $ | -- |
Liquidity facilities - available4 | 349.5 | -- | 349.5 | -- | -- | |||||
Lines of credit - available5 | 53.6 | 25.4 | 28.2 | -- | -- | |||||
| Energy operations letter of credit | 0.5 | 0.5 | -- | -- | -- | |||||
| Total commercial commitments | $ | 534.6 | $ | 25.9 | $ | 508.7 | $ | -- | $ | -- |
In 1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling preferred securities (Trust Securities) to investors and |
See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” |
In |
At December 31, |
Puget Energy has a $15 million line of credit with a bank. At December 31, |
| 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 | $ | -- | $ | -- | ||||
Puget Sound Energy | Payments Due Per Period | |||||||||
CONTRACTUAL OBLIGATIONS (DOLLARS IN MILLIONS) | Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter | |||||
| Long-term debt | $ | 2,095.4 | $ | 31.0 | $ | 406.0 | $ | 337.4 | $ | 1,321.0 |
Junior subordinated debentures payable to a subsidiary trust1 | 280.3 | -- | -- | -- | 280.3 | |||||
| Mandatorily redeemable preferred stock | 1.9 | -- | -- | -- | 1.9 | |||||
| Service contract obligations | 168.6 | 21.5 | 48.6 | 47.7 | 50.8 | |||||
| Non-cancelable operating leases | 116.4 | 12.8 | 31.6 | 26.0 | 46.0 | |||||
Fredonia combustion turbines lease2 | 65.3 | 4.6 | 8.6 | 8.3 | 43.8 | |||||
| Energy purchase obligations | 4,988.2 | 929.4 | 1,491.0 | 1,278.2 | 1,289.6 | |||||
| Financial hedge obligations | 20.0 | 6.2 | 11.9 | 1.9 | -- | |||||
| Pension funding | 45.7 | 4.3 | 8.2 | 9.8 | 23.4 | |||||
| Total contractual cash obligations | $ | 7,781.8 | $ | 1,009.8 | $ | 2,005.9 | $ | 1,709.3 | $ | 3,056.8 |
Amount of Commitment Expiration Per Period | ||||||||||
COMMERCIAL COMMITMENTS (DOLLARS IN MILLIONS) | Total | 2005 | 2006- 2007 | 2008- 2009 | 2010 & Thereafter | |||||
Liquidity facilities - available3 | $ | 349.5 | $ | -- | $ | 349.5 | $ | -- | $ | -- |
| Energy operations letter of credit | 0.5 | 0.5 | -- | -- | -- | |||||
| Total commercial commitments | $ | 350.0 | $ | 0.5 | $ | 349.5 | $ | -- | $ | -- |
See note |
See note |
See note |
Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the third party. The amount of receivables sold by Rainier Receivables is not permitted to exceed $150 million at any time. However, the maximum amount may be less than $150 million depending on the outstanding eligible amount of PSE’s receivables, which fluctuate with the seasonality of energy sales to customers.
respectively.
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 $20.0 million in 2004, 2005 and 2006, respectively. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.
CAPITAL RESOURCES
in 2003, which positively impacted cash flow from operating activities. Cash flow from operating activities also improved $27.7 million through recovery of collateral deposits in 2004 compared to no funding during 2002. Cash used for taxes payable increaseda return of collateral deposits in 2003 compared to 2002 by $31.7 million.
from energy supply counterparties.
| · | approximately $281 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $468 million |
| · | approximately $417 million of additional first mortgage bonds under PSE’s gas mortgage indenture based on approximately $695 million of gas bondable property available for issuance, subject to an interest coverage ratio limitation of 1.75 times net earnings available for interest, which PSE exceeded at December 31, 2004; |
| · | approximately $486.3 million of additional preferred stock at an assumed dividend rate of 6.625%; and |
| · | approximately $273.2 million of unsecured long-term debt. |
CREDIT RATINGS
| Ratings | ||
| Standard & Poor’s | Moody’s | |
Puget Sound Energy | ||
| Corporate credit/issuer rating | BBB- | Baa3 |
| Senior secured debt | BBB | Baa2 |
| Shelf debt senior secured | BBB | (P)Baa2 |
| Trust preferred securities | BB | |
| Preferred stock | BB | Ba2 |
| Commercial paper | A-3 | P-2 |
| Revolving credit facility | * | Baa3 |
| Ratings outlook | Positive | Stable |
Puget Energy | ||
| Corporate credit/issuer rating | BBB- | Ba1 |
facilities
.| · | common stock of Puget Energy, and |
| · | senior notes of PSE, secured by a pledge of PSE’s first mortgage bonds. |
In March 2003, PSE refinanced $161.9bonds at a premium of 3.68% on August 14, 2004. It is anticipated that the $200 million in floating rate senior notes will be paid off with a combination of its Pollution Control Bonds to 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 repaylong-term debt and redeem high-cost preferred stock. internally generated funds.
| · | $18.5 million medium term notes with interest rates ranging from 6.07% to 6.10%; |
| · | $30.0 million medium term notes at an interest rate of 7.80% in May 2004; |
| · | $4.2 million conservation trust bonds at an interest rate of 6.45% during 2004; |
| · | $55.0 million medium term notes at an interest rate of 7.35% in August 2004; and |
| · | $50.0 million medium term notes at an interest rate of 7.70% in December 2004. |
2004.
2003. The proceeds from sales of stock under these plans are used for general corporate needs.
(DOLLARS IN MILLIONS) QUARTER ENDING | 7/02 - 6/03 PCA 1 (ordered/final) | 7/03 - 6/04 PCA 2 (estimated) | 7/04 - 12/04 PCA 3 (estimated) | Total |
| June 30, 2004 | $ 25.6 | $ 12.2 | $ -- | $ 37.8 |
| September 30, 2004 | -- | -- | 2.8 | 2.8 |
| December 31, 2004 | -- | -- | 2.8 | 2.8 |
| Total | $ 25.6 | $ 12.2 | $ 5.6 | $ 43.4 |
| 1. | The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
| 2. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will fully recover its Tenaska costs. |
| 3. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
| a) | actual Tenaska costs that exceed the benchmark; or |
| b) | the return on the Tenaska regulatory asset. |
| 4. | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs. |
(DOLLARS IN MILLIONS) | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 | 2011 | |||||||||||||||
| Projected Tenaska costs * | $ | 194.5 | $ | 197.2 | $ | 189.0 | $ | 180.3 | $ | 170.3 | $ | 162.9 | $ | 170.0 | ||||||||
| Projected Tenaska benchmark costs | 159.7 | 167.9 | 175.2 | 182.2 | 189.5 | 197.2 | 213.8 | |||||||||||||||
| Over (under) benchmark costs | $ | 34.8 | $ | 29.3 | $ | 13.8 | $ | (1.9 | ) | $ | (19.2 | ) | $ | (34.3 | ) | $ | (43.8 | ) | ||||
| Projected 50% disallowance based on Washington Commission methodology | $ | 10.5 | $ | 8.8 | $ | 5.8 | $ | 1.6 | $ | -- | $ | -- | $ | -- | ||||||||
CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO) RECEIVABLE AND CALIFORNIA REFUND PROCEEDINGS
However, there can be no assurances in that regard because litigation is subject to numerous uncertainties and PSE operates withinis unable to predict the western wholesale market and made sales into the California energy market during the fourth quarterultimate outcome of 2000 through the CAISO. In August of 2000, San Diego Gas & Electric Company filed a complaint at FERC (Docket No. EL00-95) seeking price caps on energy sold into the CAISO and the California Power Exchange (PX) markets. The complaint also sought refunds of prices charged above any such caps put in place. In response to the complaint, after a number of ordersthese matters. Accordingly, there can be no guarantee that attempted to address the California energy crisis in a variety of manners, FERC issued an Order on June 19, 2001 that imposed caps on prices beginning the next day. On July 25, 2001, FERC ordered an evidentiary hearing in Docket No. EL00-95 to determine the amount of refunds due to California energy buyers, including the CAISO, for purchases madethese proceedings, either individually or in the spot markets operated by the CAISO during the period October 2, 2000 through June 20, 2001. 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” estimates of amounts owed and owing. The certification also stated that the amounts owing should be adjusted for interest, a calculation the Administrative Law Judge did not make. The FERC staff issued a report in August 2002 (Docket No. PA02-2) that, among other things, recommended 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. This methodology of calculating the cost of natural gas further reduced the amount owed by the CAISO to PSE for sales made during 2000 and 2001. 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 between $23.6 million and $34.2 million. On November 20, 2002, FERC issued an Order on Motion for Discovery Order in Docket No. EL00-95 that granted a motion to allow parties to “adduce” additional evidence into the refund proceedings “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 permitted the parties to conduct discovery and file any such evidence with FERC. In their March 3, 2003 filing, the California parties reiterated their allegations of market manipulation against PSE and approximately 60 other companies. PSE and the other parties responded 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 caseaggregate, will not be finally resolved before formal appellate review.
CALIFORNIA RECEIVABLE In 2001, PG&Ematerially 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 constrainingadversely affect 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 netfinancial condition, results of the CAISO cost re-runs and the application of the refund calculations will extinguishoperations 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 PROCEEDINGliquidity.
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
| 1. | California Receivable and California Refund Proceeding. In 2001, PG&E and Southern California Edison failed to pay the California Independent System Operator Corporation (CAISO) and the California PX for energy purchases. The CAISO in turn failed to pay various energy suppliers, including PSE, for energy sales made by PSE into the California energy market during the fourth quarter 2000. Both PG&E and the California PX filed for bankruptcy in 2001, further constraining PSE’s ability to receive payments due to bankruptcy court controls placed on the distribution of funds by the California PX and the escrow of funds owed by PG&E for purchases during the fourth quarter 2000 are owed by the California PX. |
| a. | California Refund Proceeding. On July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CAISO and the California PX during the period October 2, 2000 through June 20, 2001 (refund period). The CAISO continues its efforts to prepare revised settlement statements based on newly recalculated costs and charges for spot market sales to California during the refund period and currently estimates that it will determine “who owes what to whom” in early 2005. On September 2, 2004, FERC issued an order selecting Ernst & Young LLP as the independent auditor of fuel cost allowance claims made by sellers, including PSE. A review of that claim is pending, awaiting further guidance from FERC. Many of the numerous orders that FERC issued in Docket No. EL00-95 are on appeal and have been consolidated before the United States Court of Appeals for the Ninth Circuit as a result of a case management conference conducted on September 21, 2004. FERC filed the record on November 22, 2004. The Ninth Circuit ordered on October 22, 2004 that briefing proceed in two rounds. The first round is limited to three issues: (1) which parties are subject to FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; (3) which categories of transactions are subject to refunds. Procedures will be established for the remaining issues, if necessary, after the court’s disposition of the first round of issues. Following a second case management conference on November 9, 2004, the Ninth Circuit consolidated certain petitions for review for briefing of the first round of issues to be completed by March 1, 2005 and set oral argument hearings for April 12 and 13, 2005. Opening briefs were filed on December 29, 2004. PSE joined the brief of the Competitive Supplier Group, which argued that FERC has proposed to require payment of refunds without proper notice to sellers, without proper limits on the type of transactions affected and without a finding that the transactions subject to refund in fact produced prices that were just and reasonable. Respondents’ briefs in support of FERC were due February 9, 2005. |
| b. | CAISO Receivable. PSE has a bad debt reserve and a transaction fee reserve applied to the CAISO receivable, such that PSE’s net receivable from the CAISO as of December 31, 2004 is approximately $21.3 million. PSE estimates the range for the receivable to be between $21.3 million and $22.4 million, which includes estimated credits for fuel and power purchase costs and interest. In its October 16, 2003 Order on Rehearing in this docket, FERC expressly adopted and approved a stipulation that confirmed that two of PSE’s “non-spot market” transactions are not subject to mitigation in the Refund Proceeding. On October 17, 2003, PSE formally presented CAISO with a request that payment be made on these amounts. The CAISO responded to the letter on November 13, 2003, expressing an unwillingness to take the issue up separately or in advance of its cost re-run activities. PSE continues to pursue the issue in filings through FERC processes. On May 6, 2004, the Los Angeles Department of Water and Power filed a motion at FERC in Docket No. EL00-95 requesting that FERC issue an order permitting monies to be disbursed from the California PX Settlement Clearing Account and an escrow account be established as part of PG&E’s bankruptcy proceeding. The bulk of the monies owed by the CAISO, including the monies owed to PSE, are held in those two accounts. PSE filed an answer in support of the motion on May 21, 2004, and awaits an order from FERC. |
| 2. | Pacific Northwest Refund Proceeding.In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC supplied for the California markets. FERC dismissed PSE’s complaint on December 15, 2000, although PSE filed for rehearing in January 2001. When FERC issued its June 19, 2001 order in Docket No. EL00-95, imposing west-wide price constraints on energy sales, PSE moved to withdraw its rehearing request and its complaint in Docket No. EL01-10, on the basis that the relief PSE sought was fully provided. Various parties, including the Port of Seattle and the cities of Seattle and Tacoma, moved to intervene in the proceeding. They asserted the ability to adopt PSE’s complaint to obtain retroactive refunds for numerous transactions, including many that were not within the scope of the PSE complaint. The proceeding became commonly referenced as the “Pacific Northwest Refund Proceeding,” despite the fact that the original complainant, PSE, did not seek retroactive refunds. A preliminary evidentiary hearing was held in September 2001, and an Administrative Law Judge recommendation against refunds followed. In December 2002, FERC issued an order permitting additional discovery and the submission of any additional evidence (parallel to the order issued in the California Refund Proceeding) that reopened the matter to permit parties to introduce any evidence they claimed to have of market manipulation. A few parties made filings, asserting market manipulation in early March 2003, and numerous parties, including PSE, responded to those allegations in late March 2003. On June 25, 2003, FERC issued an order terminating the proceeding, largely on procedural, jurisdictional and equitable grounds. Various parties filed rehearing requests on July 25, 2003. On November 10, 2003, FERC affirmed an order terminating the Pacific Northwest Refund Proceeding, (Docket No. EL01-10), largely on procedural, jurisdictional and equitable grounds. Seven petitions for review, including PSE’s, are now pending before the United States Court of Appeals for the Ninth Circuit. Opening briefs were filed on January 14, 2005. PSE’s opening brief addressed procedural flaws underlying the action of FERC. Specifically, PSE argued that because PSE’s complaint in the underlying docket was withdrawn as a matter of law on July 9, 2001, FERC erred in relying on it to serve as the basis to initiate a “preliminary” investigation into whether refunds for individually negotiated bilateral transactions in the Pacific Northwest were appropriate. Briefing is expected to be completed in the first half of 2005. |
| 3. | Orders to Show Cause. On June 25, 2003, FERC issued two show cause orders pertaining to its western market investigations that commenced individual proceedings against many sellers. One show cause order (Docket Nos. EL03-180, et seq.) sought to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order. In an order dismissing many of the already-named respondents in the “partnerships” proceeding on January 22, 2004, FERC stated that it did not intend to proceed further against other parties. |
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 pendingthe California parties’ rehearing request, and is scheduled to be heardawaits FERC action 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.that motion.
| 4. | Port of Seattle Suit. On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle against 22 energy sellers, alleging that their conduct during 2000 and 2001 constituted market manipulation, violated antitrust laws and damaged the Port of Seattle. The Port had a contract to purchase its energy supply from PSE at the time. The Port’s contract linked the price of the energy sold to the Port to an index price for energy sold at wholesale at the Mid-Columbia trading hub. The Port alleged that the Mid-Columbia price was inten-tionally affected improperly by the defendants, including PSE, and alleges damages of over $30 million. On May 12, 2004, the district court dismissed the lawsuit. The Port of Seattle filed an appeal to the United States Court of Appeals for the Ninth Circuit, and on September 13, 2004, filed a brief in the Ninth Circuit arguing that the district court erred in dismissing its claims. Responses to the Port’s brief were filed November 2, 2004. The parties await oral argument to be scheduled. |
| 5. | Wah Chang v. Avista Corp., PSE and others.In June 2004, Puget Energy and PSE were served a federal summons and complaint by Wah Chang, an Oregon company. Wah Chang claims that during 1998 through 2001 the Company and other energy companies (and in a separate complaint, energy marketers) engaged in various fraudulent and illegal activities including the transmittal of electronic wire communications to transmit false or misleading information to manipulate the California energy market. The claims include submitting false information such as energy schedules and bids to the California PX, CAISO, electronic trading platforms and publishers of energy indexes, alleges damages of not less than $30 million and seeks treble and punitive damages, attorneys’ fees and costs. The complaint is similar to the allegations made by the Port of Seattle currently on appeal in the Ninth Circuit. The Judicial Panel on Multi District Litigation consolidated this case with another pending Multi District case and transferred it to Federal District Court in San Diego on August 20, 2004. The defendants in both cases filed motions to dismiss on October 25, 2004. Wah Chang opposed the motions to dismiss, and replies in support of the motions to dismiss were filed on January 12, 2005. On February 11, 2005, approximately three weeks after hearing oral argument, the Court dismissed both cases on the grounds that FERC has the exclusive jurisdiction over plaintiff’s claims and the filed rate doctrine and Federal preemption barred the court from hearing the plaintiff’s claims. |
| 6. | California Litigation.Attorney General Cases.
|
moved to dismiss it on the grounds that the issues are within the exclusive or primary jurisdiction of FERC. dismissed. On March 25, 2003, the court granted the motion for dismissal. The order of dismissal is now on appeal toOctober 12, 2004, the Ninth Circuit issued a decision affirming the dismissal of all 13 complaints filed by the California Attorney General, including a complaint against PSE. The Ninth Circuit decision concluded that the opinions inPeople of the State of California ex rel. Bill Lockyer v. Dynegy, et al. andPublic Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, Inc., decided earlier this year by the Ninth Circuit, controlled the outcome of the matters and warranted dismissal. Because no party sought rehearing or filed a petition for certiorari to the Supreme Court of Appeals. PSE does not expect any material adverse impacts on the financial conditionUnited States, the Ninth Circuit’s order is the final determination of the Company from these matters.
this matter.
GAS REVENUE DECREASE (MILLIONS) | ELECTRIC REVENUE DECREASE (MILLIONS) | |
| 0.1% increase in loss factor | $0.4 | $0.6 |
DERIVATIVES
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.
All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis.
CHANGE IN ASSUMPTION | IMPACT ON PROJECTED BENEFIT OBLIGATION INCREASE (DECREASE) | IMPACT ON 2004 PENSION INCOME INCREASE (DECREASE) | ||||||||||||||
(DOLLARS IN THOUSANDS) | PENSION BENEFITS | OTHER BENEFITS | PENSION BENEFITS | OTHER BENEFITS | ||||||||||||
| Increase in discount rate | 50 basis points | $ | (20,548 | ) | $ | (3,635 | ) | $ | 1,261 | $ | 354 | |||||
| Decrease in discount rate | 50 basis points | 22,595 | 3,891 | (48 | ) | (377 | ) | |||||||||
| Increase in return of plan assets | 50 basis points | * | * | 2,370 | 71 | |||||||||||
| Decrease in return on plan assets | 50 basis points | * | * | (2,370 | ) | (71 | ) | |||||||||
DEFINED BENEFIT PENSION PLAN
During 2004, Puget Energy hasrecorded a qualified defined benefit pension plan covering substantially all employeesnon-cash goodwill impairment charge of PSE. For 2003, 2002$91.2 million, or $76.6 million after-tax and 2001 qualified pension income of $12.9 million, $17.7 million and $20.0 million, respectively,minority interest. As a result, the goodwill balance at December 31, 2004 was 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,$43.5 million. Intangible assets have not been impaired 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 $8.6 million inbalance at December 31, 2004 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.
was $16.7 million.
CALIFORNIA INDEPENDENT SYSTEM OPERATOR RESERVE
NEW ACCOUNTING PRONOUNCEMENTS
Investments in Limited Liability Companies.” The consensus reached was that an investment in a limited liability company should be accounted for using the equity method for investments greater than 3% to 5%. The adoption of EITF No. 03-16 is effective for reporting periods beginning after June 15, 2004, with any adjustments being accounted for as a cumulative effect of a change in accounting principle. The Company reviewed its investments and determined one investment held by PSE met the criteria established in EITF No. 03-16.
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 Postretirement Benefits” (SFAS No. 132R), was revised to include various additional disclosure requirements. SFAS No. 132R is effective for fiscal years ending after December 15, 2003.
$273.9 million, respectively.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
an accounting change. The Company is exposedcurrently evaluating what impact this proposed interpretation may have on the Company if issued.
| QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
PORTFOLIO MANAGEMENT
electric portfolio for its customers. Gas and electric portfolio exposure is managed in accordance with Company polices and procedures. The Risk Management Committee, which is composed of Company officers, provide policy-level and strategic direction for management of the energy portfolio. The Audit Committee of the Company’s Board of Directors periodically assesses risk management policies.
| · | ensure that physical energy supplies are available to serve retail customer requirements; |
| · | manage portfolio risks to limit undesired impacts on the Company’s costs; and |
| · | maximize the value of the Company’s energy supply assets. |
part.
| 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 | |||
ENERGY DERIVATIVE CONTRACTS (DOLLARS IN MILLIONS) | AMOUNTS | ||||||
| Fair value of contracts outstanding at December 31, 2003 | $ | 12.6 | |||||
| Contracts realized or otherwise settled during 2004 | (9.8 | ) | |||||
| Changes in fair values of derivatives | 6.9 | ||||||
| Fair value of contracts outstanding at December 31, 2004 | $ | 9.7 | |||||
FAIR VALUE OF CONTRACTS WITH SETTLEMENT DURING YEAR | |||||
SOURCE OF FAIR VALUE (DOLLARS IN MILLIONS) | 2005 | 2006- 2007 | 2008- 2009 | 2010 AND THEREAFTER | TOTAL FAIR VALUE |
| Prices actively quoted | $ (3.8) | $ 6.3 | $ -- | $ -- | $ 2.5 |
| Prices provided by other external sources | -- | 5.4 | 1.8 | -- | 7.2 |
| Prices based on models and other valuation methods | $ (3.8) | $ 11.7 | $ 1.8 | $ -- | $ 9.7 |
| 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 | |||
| 2004 | 2003 | ||||
(DOLLARS IN MILLIONS) | CARRYING AMOUNT | FAIR VALUE | CARRYING AMOUNT | FAIR VALUE | |
| Financial liabilities: | |||||
| Short-term debt | $ 8.3 | $ 8.3 | $ 13.9 | $ 13.9 | |
Long-term debt- fixed-rate1 | 2,051.4 | 2,194.8 | 2,216.3 | 2,409.6 | |
Long-term debt- variable-rate1 | 200.0 | 199.9 | -- | -- | |
| 1 | PSE’s carrying value and fair value of both fixed-rate and variable-rate long-term debt in 2004 was $2,095.4 million and $2,238.7 million, respectively. PSE’s carrying value and fair value of fixed-rate long-term debt in 2003 was $2,053.0 million and $2,250.4 million, respectively. |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES UnderIn the supervisionthird quarter 2004, the Company entered into two treasury lock contracts to hedge against potential rising interest rate exposure for a debt offering anticipated to be performed in the first half of 2005. A treasury lock is a financial arrangement between the Company and 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 effectivenessa counterparty whereby one of the Companies’ disclosure controlsparties will be required to make a payment to the other party on a specific valuation date based upon the change in value of a 30-year treasury bond. If interest rates rise related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would receive a payment from the counterparty for the change in the bond value. Alternatively, if interest rates decrease related to the hedged debt from the date of issuance of the treasury lock instruments, the Company would pay the counterparty for the change in bond value. These treasury lock contracts were designated under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period being presented net of tax in other comprehensive income. All financial hedge contracts of this type are reviewed by senior management and procedures (as defined in Rule 13a-14(c) underpresented to the Securities Exchange Act of 1934) asPricing Committee 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 this item with respect to Puget Energy is incorporated herein by reference to the material under “Available Information” in Part I of this report and “Proposal — Election of Directors,” “Directors Continuing in Office”, “BoardBoard 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 2004 Annual Meeting of Shareholders (Commission File No. 1-16305). Reference is also madeare approved prior 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 11. EXECUTIVE COMPENSATION
PUGET ENERGY The information required by this item with respect to Puget Energy is incorporated herein by reference to the material under “Director Compensation,” “Executive Compensation” and “Employment Contracts, Termination of Employment and Change-In-Control Arrangements” in Puget Energy’s proxy statement for its 2004 Annual Meeting of Shareholders (Commission File No. 1-16305).
PUGET SOUND ENERGY The information called for by Item 11 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 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
EQUITY COMPENSATION PLAN INFORMATION The following table sets forth information regarding the 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 ofexecution. At December 31, 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 | 1,194,480 | (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 units2004, the unrealized loss associated with the two treasury lock contracts was $11.3 million that qualify as cash flow hedges and is included in other comprehensive income. A hypothetical 10% decrease in the Company’s deferred compensation plans that are payableinterest rate of a 30-year treasury note would result in stock, plus cash for any fractional shares,an additional loss of which all are currently vested.
TREASURY LOCK CONTRACTS (DOLLARS IN MILLIONS) |
SUMMARY OF EQUITY COMPENSATION PLANS NOT APPROVED BY SHAREHOLDERS
NON-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). 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 vestscontracts outstanding 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, 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-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-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, 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. PRINCIPAL ACCOUNTANT FEES AND SERVICES
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 | |
| $ -- | ||
| Contracts realized or otherwise settled during 2004 | -- | |
| Changes in fair values of | (11.3) | |
| Fair value of contracts outstanding at December 31, | $ (11.3) |
The Audit Committees of the Company have adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent auditor. The policies are designed to ensure that the provision of these services does not impair the auditor’s independence. Under the policies, unless a type of service to be provided by the independent auditor has received general pre-approval, it will require specific pre-approval by 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 fees, as well as any changes in terms, conditions and fees relating to the engagement, are subject to specific pre-approval by the Audit Committees. In addition, on an annual basis, the Audit Committees grant general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent auditor. 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 members. The member or members to whom such authority is delegated shall report any pre-approval decisions to the 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 non-audit services were pre-approved.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
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.
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.
CONSOLIDATED FINANCIAL STATEMENTS: | ||||
PUGET ENERGY: | ||||
| 2003 and 2002 | ||||
| 2003 | ||||
for the years ended December 31, 2004, 2003 and 2002 | ||||
for the years ended December 31, 2004, 2003 and | ||||
| 2002 | ||||
for the years ended December 31, 2004, 2003 and 2002 | ||||
PUGET SOUND ENERGY: | ||||
| 2002 | ||||
for the years ended December 31, 2004, 2003 and 2002 | ||||
for the years ended December 31, 2004, 2003 and 2002 | ||||
for the years ended December 31, 2004, 2003 and 2002 | ||||
| Combined Puget Energy and Puget Sound Energy Notes to Consolidated Financial Statements | ||||
for the years ended December 31, 2004, 2003 and 2002 | ||||
| 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. | ||||
The accompanying consolidated financial statements of
| · | Our Board has adopted clear corporate governance guidelines. |
| · | With the exception of the Chief Executive Officer, the Board members are independent of the Company and its management. |
| · | All members of our key Board committees - the Audit Committee, the Compensation and Development Committee and the Governance and Public Affairs Committee - are independent of the Company and its management. |
| · | The independent members of our Board meet regularly without the presence of Puget Energy and Puget Sound Energy management. |
| · | The Charters of our Board committees clearly establish their respective roles and responsibilities. |
| · | The Company has adopted a Compliance and Ethics Code with a hotline (through an independent third party) available to all employees, and our Audit Committee has procedures in place for the anonymous submission of employee complaints on accounting, internal accounting controls, or auditing matters. The Compliance Program is led by a senior officer of the Company. |
| · | Our internal audit control function maintains critical oversight over the key areas of our business and financial processes and controls, and reports directly to our Board Audit Committee. |
| /s/ Stephen P. Reynolds | /s/ Bertrand A. Valdman | /s/ James W. Eldredge | ||
| Stephen P. Reynolds | Bertrand A. Valdman | James W. Eldredge | ||
President and Chief Executive Officer | Senior Vice President Finance And Chief Financial Officer | Corporate Secretary and Chief Accounting Officer |
Obligations”.
PricewaterhouseCoopers LLPObligations”.
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) FOR YEARS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Operating revenues: | ||||||||||
| Electric | $ | 1,423,034 | $ | 1,400,743 | $ | 1,288,744 | ||||
| Gas | 769,306 | 634,230 | 697,155 | |||||||
| Non-utility construction services | 369,936 | 341,787 | 319,529 | |||||||
| Other | 6,537 | 6,043 | 9,753 | |||||||
| Total operating revenues | 2,568,813 | 2,382,803 | 2,315,181 | |||||||
| Operating expenses: | ||||||||||
| Energy costs: | ||||||||||
| Purchased electricity | 723,567 | 714,469 | 568,230 | |||||||
| Electric generation fuel | 80,772 | 64,999 | 113,538 | |||||||
| Residential exchange | (174,473 | ) | (173,840 | ) | (149,970 | ) | ||||
| Purchased gas | 451,302 | 327,132 | 405,016 | |||||||
| Unrealized (gain) loss on derivative instruments | (526 | ) | 106 | (11,612 | ) | |||||
| Utility operations and maintenance | 291,232 | 289,702 | 286,220 | |||||||
| Other operations and maintenance | 322,517 | 303,972 | 273,157 | |||||||
| Depreciation and amortization | 246,842 | 236,866 | 228,743 | |||||||
| Conservation amortization | 22,688 | 33,458 | 17,501 | |||||||
| Goodwill impairment | 91,196 | -- | -- | |||||||
| Taxes other than income taxes | 221,981 | 208,395 | 215,429 | |||||||
| Income taxes | 74,964 | 72,369 | 59,260 | |||||||
| Total operating expenses | 2,352,062 | 2,077,628 | 2,005,512 | |||||||
| Operating income | 216,751 | 305,175 | 309,669 | |||||||
| Other income (deductions): | ||||||||||
| Other income | 4,292 | 1,564 | 5,458 | |||||||
| Interest charges: | ||||||||||
| AFUDC | 5,420 | 3,343 | 1,969 | |||||||
| Interest expense | (178,419 | ) | (187,316 | ) | (198,346 | ) | ||||
| Mandatorily redeemable securities interest expense | (91 | ) | (1,072 | ) | -- | |||||
| Preferred stock dividends of subsidiary | -- | (5,151 | ) | (7,831 | ) | |||||
| Minority interest in earnings of consolidated subsidiary | 7,069 | (177 | ) | (867 | ) | |||||
| Net income before cumulative effect of accounting change | 55,022 | 116,366 | 110,052 | |||||||
| Cumulative effect of implementation of accounting change (net of tax) | -- | 169 | -- | |||||||
| Net income | $ | 55,022 | $ | 116,197 | $ | 110,052 | ||||
| Common shares outstanding weighted average (in thousands) | 99,470 | 94,750 | 88,372 | |||||||
| Diluted shares outstanding weighted average (in thousands) | 99,911 | 95,309 | 88,777 | |||||||
Basic earnings per common share before cumulative effect of accounting change | $ | 0.55 | $ | 1.23 | $ | 1.24 | ||||
Basic earnings per common share for cumulative effect of accounting change | -- | -- | -- | |||||||
| Basic earnings per common share | $ | 0.55 | $ | 1.23 | $ | 1.24 | ||||
Diluted earnings per common share before cumulative effect of accounting change | $ | 0.55 | $ | 1.22 | $ | 1.24 | ||||
Diluted earnings per common share for cumulative effect of accounting change | -- | -- | -- | |||||||
| Diluted earnings per common share | $ | 0.55 | $ | 1.22 | $ | 1.24 | ||||
|
| (Dollars in thousands, except per share amounts) 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 | ||||||||
| Non-utility construction services | 341,787 | 319,529 | 173,786 | ||||||||
| Other | 6,043 | 9,753 | 32,476 | ||||||||
| Total operating revenues | 2,491,523 | 2,392,322 | 2,886,560 | ||||||||
| 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 | 303,972 | 273,157 | 156,731 | ||||||||
| Depreciation and amortization | 236,866 | 228,743 | 217,540 | ||||||||
| Conservation amortization | 33,458 | 17,501 | 6,493 | ||||||||
| Taxes other than income taxes | 208,395 | 215,429 | 212,582 | ||||||||
| Income taxes | 72,369 | 59,260 | 79,838 | ||||||||
| Total operating expenses | 2,186,348 | 2,082,653 | 2,589,439 | ||||||||
| Operating income | 305,175 | 309,669 | 297,121 | ||||||||
| Other income | 1,564 | 5,458 | 14,526 | ||||||||
| Income before interest charges | 306,739 | 315,127 | 311,647 | ||||||||
| Interest charges: | |||||||||||
| AFUDC | (3,343 | ) | (1,969 | ) | (4,446 | ) | |||||
| Interest expense | 187,316 | 198,346 | 194,505 | ||||||||
| Mandatorily redeemable securities interest expense | 1,072 | -- | -- | ||||||||
| Total interest charges | 185,045 | 196,377 | 190,059 | ||||||||
| Minority interest in earnings of consolidated subsidiary | 177 | 867 | -- | ||||||||
| Net income before cumulative effect of accounting change | 121,517 | 117,883 | 121,588 | ||||||||
| Cumulative effect of implementation of accounting change (net of tax) | 169 | -- | 14,749 | ||||||||
| Net income | 121,348 | 117,883 | 106,839 | ||||||||
| Less: preferred stock dividends accrual | 5,151 | 7,831 | 8,413 | ||||||||
| Income for common stock | $ | 116,197 | $ | 110,052 | $ | 98,426 | |||||
| Common shares outstanding weighted average | 94,750 | 88,372 | 86,445 | ||||||||
| Diluted shares outstanding weighted average | 95,309 | 88,777 | 86,703 | ||||||||
| Basic earnings per common share before | |||||||||||
| cumulative effect of accounting change | $ | 1.23 | $ | 1.24 | $ | 1.31 | |||||
| Basic earnings for cumulative effect of accounting change | -- | -- | (0.17 | ) | |||||||
| 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 | |||||
| (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 | ||||
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| Utility plant: | |||||||
| Electric plant | $ | 4,389,882 | $ | 4,265,908 | |||
| Gas plant | 1,881,768 | 1,749,102 | |||||
| Common plant | 409,677 | 390,622 | |||||
| Less: Accumulated depreciation and amortization | (2,452,969 | ) | (2,325,405 | ) | |||
| Net utility plant | 4,228,358 | 4,080,227 | |||||
| Other property and investments: | |||||||
| Goodwill, net | 43,503 | 133,302 | |||||
| Intangibles, net | 16,680 | 18,707 | |||||
| Other | 257,785 | 250,084 | |||||
| Total other property and investments | 317,968 | 402,093 | |||||
| Current assets: | |||||||
| Cash | 19,771 | 27,481 | |||||
| Restricted cash | 1,633 | 2,537 | |||||
| Accounts receivable, net of allowance for doubtful accounts | 216,304 | 227,115 | |||||
| Unbilled revenues | 140,391 | 131,798 | |||||
| Purchased gas adjustment receivable | 19,088 | -- | |||||
| Materials and supplies, at average cost | 107,356 | 85,128 | |||||
| Current portion of unrealized gain on derivative instruments | 8,087 | 7,593 | |||||
| Prepayments and other | 20,360 | 12,200 | |||||
| Total current assets | 532,990 | 493,852 | |||||
| Other long-term assets: | |||||||
| Regulatory asset for deferred income taxes | 127,252 | 142,792 | |||||
| Regulatory asset for PURPA buyout costs | 211,241 | 227,753 | |||||
| Unrealized gain on derivative instruments | 13,765 | 8,624 | |||||
| Power cost adjustment mechanism | -- | 3,605 | |||||
| Other | 401,795 | 340,056 | |||||
| Total other long-term assets | 754,053 | 722,830 | |||||
| Total assets | $ | 5,833,369 | $ | 5,699,002 | |||
| (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 | |
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| Capitalization: | |||||||
(See Consolidated Statements of Capitalization ) | |||||||
| Common equity | $ | 1,622,276 | $ | 1,655,046 | |||
| Total shareholders’ equity | 1,622,276 | 1,655,046 | |||||
| Redeemable securities and long-term debt: | |||||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | |||||
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | 280,250 | 280,250 | |||||
| Long-term debt | 2,212,532 | 1,969,489 | |||||
| Total redeemable securities and long-term debt | 2,494,671 | 2,251,628 | |||||
| Total capitalization | 4,116,947 | 3,906,674 | |||||
| Minority interest in consolidated subsidiary | 4,648 | 11,689 | |||||
| Current liabilities: | |||||||
| Accounts payable | 239,520 | 214,357 | |||||
| Short-term debt | 8,297 | 13,893 | |||||
| Current maturities of long-term debt | 38,933 | 246,829 | |||||
| Purchased gas adjustment liability | -- | 11,984 | |||||
| Accrued expenses: | |||||||
| Taxes | 77,698 | 77,451 | |||||
| Salaries and wages | 13,829 | 12,712 | |||||
| Interest | 29,005 | 32,954 | |||||
| Current portion of unrealized loss on derivative instruments | 19,261 | 3,636 | |||||
| Tenaska disallowance reserve | 3,156 | -- | |||||
| Other | 61,155 | 46,378 | |||||
| Total current liabilities | 490,854 | 660,194 | |||||
| Long-term liabilities: | |||||||
| Deferred income taxes | 810,726 | 755,235 | |||||
| Long-term portion of unrealized loss on derivative instruments | 249 | -- | |||||
| Other deferred credits | 409,945 | 365,210 | |||||
| Total long-term liabilities | 1,220,920 | 1,120,445 | |||||
| Commitments and contingencies | |||||||
| Total capitalization and liabilities | $ | 5,833,369 | $ | 5,699,002 | |||
| (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 | ||||
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| Common equity: | |||||||
Common stock $0.01 par value, 250,000,000 shares authorized, 99,868,368 and 99,074,070 shares outstanding at December 31, 2004 and 2003 | $ | 999 | $ | 991 | |||
| Additional paid-in capital | 1,621,756 | 1,603,901 | |||||
| Earnings reinvested in the business | 13,853 | 58,217 | |||||
Accumulated other comprehensive income (loss)- net of tax | (14,332 | ) | (8,063 | ) | |||
| Total common equity | 1,622,276 | 1,655,046 | |||||
Preferred stock subject to mandatory redemption- cumulative- $100 par value: * | |||||||
4.84% series-150,000 shares authorized, 14,583 shares outstanding at December 31, 2004 and 2003 | 1,458 | 1,458 | |||||
4.70% series-150,000 shares authorized, 4,311 shares outstanding at December 31, 2004 and 2003 | 431 | 431 | |||||
| Total preferred stock subject to mandatory redemption | 1,889 | 1,889 | |||||
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | 280,250 | 280,250 | |||||
| Long-term debt: | |||||||
| First mortgage bonds and senior notes | 1,933,500 | 1,891,158 | |||||
| Pollution control revenue bonds: | |||||||
| Revenue refunding 2003 series, due 2031 | 161,860 | 161,860 | |||||
| Other notes | 156,105 | 163,313 | |||||
Unamortized discount- net of premium | -- | (13 | ) | ||||
| Long-term debt due within one year | (38,933 | ) | (246,829 | ) | |||
| Total long-term debt excluding current maturities | 2,212,532 | 1,969,489 | |||||
| Total capitalization | $ | 4,116,947 | $ | 3,906,674 | |||
| 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 | ||||||||
Common Stock | Accumulated | ||||||||||||||||||
(DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31, 2004, 2003 & 2002 | Shares | Amount | Additional Paid-in Capital | Retained Earnings | Other Comprehensive Income | Total Amount | |||||||||||||
| Balance at December 31, 2001 | 87,023,210 | $ | 870 | $ | 1,358,946 | $ | 32,229 | $ | (29,321 | ) | $ | 1,362,724 | |||||||
| Net income | -- | -- | -- | 110,052 | -- | 110,052 | |||||||||||||
| Common stock dividend declared | -- | -- | -- | (105,687 | ) | -- | (105,687 | ) | |||||||||||
| Common stock issued: | |||||||||||||||||||
| New issuance | 5,750,000 | 57 | 114,639 | -- | -- | 114,696 | |||||||||||||
| Dividend reinvestment plan | 801,205 | 8 | 16,900 | -- | -- | 16,908 | |||||||||||||
| Employee plans | 68,252 | 1 | 550 | -- | -- | 551 | |||||||||||||
| Other | (8 | ) | -- | (6,420 | ) | (198 | ) | -- | (6,618 | ) | |||||||||
| Other comprehensive income | -- | -- | -- | -- | 31,161 | 31,161 | |||||||||||||
| Balance at December 31, 2002 | 93,642,659 | $ | 936 | $ | 1,484,615 | $ | 36,396 | $ | 1,840 | $ | 1,523,787 | ||||||||
| Net income | -- | -- | -- | 116,197 | -- | 116,197 | |||||||||||||
| Common stock dividend declared | -- | -- | -- | (93,965 | ) | -- | (93,965 | ) | |||||||||||
| Common stock issued: | |||||||||||||||||||
| New issuance | 4,650,600 | 47 | 102,231 | -- | -- | 102,278 | |||||||||||||
| Dividend reinvestment plan | 721,340 | 7 | 15,447 | -- | -- | 15,454 | |||||||||||||
| Employee plans | 59,475 | 1 | 1,616 | -- | -- | 1,617 | |||||||||||||
| Other | (4 | ) | -- | (8 | ) | (411 | ) | -- | (419 | ) | |||||||||
| Other comprehensive loss | -- | -- | -- | -- | (9,903 | ) | (9,903 | ) | |||||||||||
| Balance at December 31, 2003 | 99,074,070 | $ | 991 | $ | 1,603,901 | $ | 58,217 | $ | (8,063 | ) | $ | 1,655,046 | |||||||
| Net income | -- | -- | -- | 55,022 | -- | 55,022 | |||||||||||||
| Common stock dividend declared | -- | -- | -- | (99,386 | ) | -- | (99,386 | ) | |||||||||||
| Common stock issued: | |||||||||||||||||||
| New issuance | 5,195 | -- | 68 | -- | -- | 68 | |||||||||||||
| Dividend reinvestment plan | 681,491 | 7 | 15,170 | -- | -- | 15,177 | |||||||||||||
| Employee plans | 107,612 | 1 | 2,617 | -- | -- | 2,618 | |||||||||||||
| Other comprehensive loss | -- | -- | -- | -- | (6,269 | ) | (6,269 | ) | |||||||||||
| Balance at December 31, 2004 | 99,868,368 | $ | 999 | $ | 1,621,756 | $ | 13,853 | $ | (14,332 | ) | $ | 1,622,276 | |||||||
(DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Net income | $ | 55,022 | $ | 116,197 | $ | 110,052 | ||||
| Other comprehensive income, net of tax: | ||||||||||
| Unrealized holding losses on marketable securities during the period | -- | (45 | ) | (1,359 | ) | |||||
Reclassification adjustment for realized gains on marketable securities included in net income | -- | (1,518 | ) | -- | ||||||
| Foreign currency translation adjustment | 275 | 80 | 63 | |||||||
| Minimum pension liability adjustment | 157 | (1,122 | ) | (2,098 | ) | |||||
| Unrealized gains on derivative instruments during the period | 6,820 | 8,576 | 2,853 | |||||||
Reversal of unrealized (gains) losses on derivative instruments settled during the period | (10,418 | ) | 181 | 31,702 | ||||||
| Deferral related to power cost adjustment mechanism | (3,103 | ) | (16,055 | ) | -- | |||||
| Other comprehensive income (loss) | (6,269 | ) | (9,903 | ) | 31,161 | |||||
| Comprehensive income | $ | 48,753 | $ | 106,294 | $ | 141,213 | ||||
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 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 | |||||
(DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Operating activities: | ||||||||||
| Net income | $ | 55,022 | $ | 116,197 | $ | 110,052 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
| Depreciation and amortization | 246,842 | 236,866 | 228,743 | |||||||
Deferred income taxes and tax credits- net | 72,702 | 57,470 | 151,318 | |||||||
| Gain from sale of securities | -- | (2,889 | ) | -- | ||||||
| Net unrealized (gains) losses on derivative instruments | (526 | ) | 106 | (11,612 | ) | |||||
| Other (including conservation amortization) | 10,103 | 18,683 | (18,827 | ) | ||||||
| Cash collateral received from (returned to) energy supplier | 6,320 | (21,425 | ) | 21,425 | ||||||
| Increase (decrease) in residential exchange program | 1,668 | (25,989 | ) | 21,201 | ||||||
| Goodwill impairment | 91,196 | -- | -- | |||||||
| Pension plan funding | -- | (26,521 | ) | -- | ||||||
| Change in certain current assets and liabilities: | ||||||||||
| Accounts receivable and unbilled revenue | 2,218 | 37,769 | 46,860 | |||||||
| Materials and supplies | (22,228 | ) | (14,727 | ) | 22,088 | |||||
| Prepayments and other | (8,159 | ) | (738 | ) | 141 | |||||
| Purchased gas receivable /liability | (31,073 | ) | (71,826 | ) | 121,039 | |||||
| Accounts payable | 25,163 | 6,464 | 34,351 | |||||||
| Taxes payable | 247 | 13,405 | (18,260 | ) | ||||||
| Tenaska disallowance reserve | 3,156 | -- | -- | |||||||
| Accrued expenses and other | 3,709 | (4,939 | ) | (4,603 | ) | |||||
| Net cash provided by operating activities | 456,360 | 317,906 | 703,916 | |||||||
| Investing activities: | ||||||||||
Construction and capital expenditures- excluding equity AFUDC | (409,403 | ) | (285,510 | ) | (235,786 | ) | ||||
| Energy efficiency expenditures | (24,852 | ) | (18,579 | ) | (11,356 | ) | ||||
| Restricted cash | 905 | 20,106 | (18,871 | ) | ||||||
| Cash received from sale of securities | -- | 3,161 | -- | |||||||
| Refundable cash received for customer construction projects | 13,424 | 5,045 | 5,787 | |||||||
| Investments by InfrastruX | -- | (10,659 | ) | (41,602 | ) | |||||
| Other | 1,747 | 2,151 | (15,761 | ) | ||||||
| Net cash used by investing activities | (418,179 | ) | (284,285 | ) | (317,589 | ) | ||||
| Financing activities: | ||||||||||
Decrease in short-term debt- net | (5,596 | ) | (33,402 | ) | (301,281 | ) | ||||
| Dividends paid | (86,873 | ) | (86,671 | ) | (97,321 | ) | ||||
| Issuance of common stock | 5,413 | 106,659 | 120,214 | |||||||
| Issuance of bonds and notes | 343,841 | 319,497 | 107,518 | |||||||
| Redemption of preferred stock | -- | (60,000 | ) | -- | ||||||
| Redemption of mandatorily redeemable preferred stock | -- | (41,273 | ) | (7,500 | ) | |||||
| Redemption of trust preferred stock | -- | (19,750 | ) | -- | ||||||
| Redemption of bonds and notes | (308,708 | ) | (357,510 | ) | (119,281 | ) | ||||
| Other | 6,032 | (10,359 | ) | (4,363 | ) | |||||
| Net cash used by financing activities | (45,891 | ) | (182,809 | ) | (302,014 | ) | ||||
| Increase (decrease) in cash from net income | (7,710 | ) | (149,188 | ) | 84,313 | |||||
| Cash at beginning of year | 27,481 | 176,669 | 92,356 | |||||||
| Cash at end of year | $ | 19,771 | $ | 27,481 | $ | 176,669 | ||||
Supplemental Cash Flow Information: | ||||||||||
| Cash payments for: | ||||||||||
| Interest (net of capitalized interest) | $ | 182,419 | $ | 192,845 | $ | 200,392 | ||||
| Income taxes (net refunds) | (1,232 | ) | (2,777 | ) | (81,652 | ) | ||||
| (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 | ||||||
(DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Operating revenues: | ||||||||||
| Electric | $ | 1,423,034 | $ | 1,400,743 | $ | 1,288,744 | ||||
| Gas | 769,306 | 634,230 | 697,155 | |||||||
| Other | 6,537 | 6,043 | 9,753 | |||||||
| Total operating revenues | 2,198,877 | 2,041,016 | 1,995,652 | |||||||
| Operating expenses: | ||||||||||
| Energy costs: | ||||||||||
| Purchased electricity | 723,567 | 714,469 | 568,230 | |||||||
| Electric generation fuel | 80,772 | 64,999 | 113,538 | |||||||
| Residential exchange | (174,473 | ) | (173,840 | ) | (149,970 | ) | ||||
| Purchased gas | 451,302 | 327,132 | 405,016 | |||||||
| Unrealized (gain) loss on derivative instruments | (526 | ) | 106 | (11,612 | ) | |||||
| Utility operations and maintenance | 291,232 | 289,702 | 286,220 | |||||||
| Other operations and maintenance | 1,342 | 1,203 | 1,602 | |||||||
| Depreciation and amortization | 228,566 | 220,087 | 215,317 | |||||||
| Conservation amortization | 22,688 | 33,458 | 17,501 | |||||||
| Taxes other than income taxes | 208,989 | 194,857 | 202,381 | |||||||
| Income taxes | 77,177 | 70,939 | 52,836 | |||||||
| Total operating expenses | 1,910,636 | 1,743,112 | 1,701,059 | |||||||
| Operating income | 288,241 | 297,904 | 294,593 | |||||||
| Other income (deductions): | ||||||||||
| Other income | 4,362 | 1,587 | 5,215 | |||||||
| Interest charges: | ||||||||||
| AFUDC | 5,420 | 3,343 | 1,969 | |||||||
| Interest expense | (171,740 | ) | (181,707 | ) | (192,829 | ) | ||||
| Mandatorily redeemable securities interest expense | (91 | ) | (1,072 | ) | -- | |||||
| Net income before cumulative effect of accounting change | 126,192 | 120,055 | 108,948 | |||||||
| Cumulative effect of implementation of accounting change (net of tax) | -- | 169 | -- | |||||||
| Net income | 126,192 | 119,886 | 108,948 | |||||||
| Less: preferred stock dividends accrual | -- | 5,151 | 7,831 | |||||||
| Income for common stock | $ | 126,192 | $ | 114,735 | $ | 101,117 | ||||
| (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 | |||||
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| Utility plant: | |||||||
| Electric plant | $ | 4,389,882 | $ | 4,265,908 | |||
| Gas plant | 1,881,768 | 1,749,102 | |||||
| Common plant | 409,677 | 390,622 | |||||
| Less: Accumulated depreciation and amortization | (2,452,969 | ) | (2,325,405 | ) | |||
| Net utility plant | 4,228,358 | 4,080,227 | |||||
| Other property and investments | 157,670 | 160,280 | |||||
| Current assets: | |||||||
| Cash | 12,955 | 14,778 | |||||
| Restricted cash | 1,633 | 2,537 | |||||
| Accounts receivable, net of allowance for doubtful accounts | 138,792 | 155,649 | |||||
| Unbilled revenues | 140,391 | 131,798 | |||||
| Purchased gas adjustment receivable | 19,088 | -- | |||||
| Materials and supplies, at average cost | 97,578 | 77,206 | |||||
| Current portion of unrealized gain on derivative instruments | 8,087 | 7,593 | |||||
| Prepayments and other | 6,247 | 6,285 | |||||
| Total current assets | 424,771 | 395,846 | |||||
| Other long-term assets: | |||||||
| Regulatory asset for deferred income taxes | 127,252 | 142,792 | |||||
| Regulatory asset for PURPA buyout costs | 211,241 | 227,753 | |||||
| Unrealized gain on derivative instruments | 13,765 | 8,624 | |||||
| Power cost adjustment mechanism | -- | 3,605 | |||||
| Other | 401,030 | 339,977 | |||||
| Total other long-term assets | 753,288 | 722,751 | |||||
| Total assets | $ | 5,564,087 | $ | 5,359,104 | |||
| (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 | ||||
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| Capitalization: | |||||||
(See Consolidated Statements of Capitalization): | |||||||
| Common equity | $ | 1,592,433 | $ | 1,555,469 | |||
| Total shareholders’ equity | 1,592,433 | 1,555,469 | |||||
| Redeemable securities and long-term debt: | |||||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | |||||
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | 280,250 | 280,250 | |||||
| Long-term debt | 2,064,360 | 1,950,347 | |||||
| Total redeemable securities and long-term debt | 2,346,499 | 2,232,486 | |||||
| Total capitalization | 3,938,932 | 3,787,955 | |||||
| Current liabilities: | |||||||
| Accounts payable | 229,747 | 206,465 | |||||
| Current maturities of long-term debt | 31,000 | 102,658 | |||||
| Purchased gas adjustment liability | -- | 11,984 | |||||
| Accrued expenses: | |||||||
| Taxes | 81,634 | 82,342 | |||||
| Salaries and wages | 13,829 | 12,712 | |||||
| Interest | 29,005 | 32,954 | |||||
| Current portion of unrealized loss on derivative instruments | 19,261 | 3,636 | |||||
| Tenaska disallowance reserve | 3,156 | -- | |||||
| Other | 34,918 | 26,514 | |||||
| Total current liabilities | 442,550 | 479,265 | |||||
| Long-term liabilities: | |||||||
| Deferred income taxes | 787,179 | 731,944 | |||||
| Long-term portion of unrealized loss on derivative instruments | 249 | -- | |||||
| Other deferred credits | 395,177 | 359,940 | |||||
| Total long-term liabilities | 1,182,605 | 1,091,884 | |||||
| Commitments and contingencies | |||||||
| Total capitalization and liabilities | $ | 5,564,087 | $ | 5,359,104 | |||
| (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 | ||||
| (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 | ||||
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| 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 | 609,467 | 604,451 | |||||
| Earnings reinvested in the business | 138,678 | 100,186 | |||||
| Accumulated other comprehensive income (loss) - net of tax | (14,750 | ) | (8,206 | ) | |||
| Total common equity | 1,592,433 | 1,555,469 | |||||
Preferred stock subject to mandatory redemption - cumulative $100 par value:* | |||||||
4.84% series- 150,000 shares authorized, 14,583 shares outstanding at December 31, 2004 and 2003 | 1,458 | 1,458 | |||||
4.70% series- 150,000 shares authorized, 4,311 shares outstanding at December 31, 2004 and 2003 | 431 | 431 | |||||
| Total preferred stock subject to mandatory redemption | 1,889 | 1,889 | |||||
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | 280,250 | 280,250 | |||||
| Long-term debt: | |||||||
| First mortgage bonds and senior notes | 1,933,500 | 1,891,158 | |||||
| Pollution control revenue bonds: | |||||||
| Revenue refunding 2003 series, due 2031 | 161,860 | 161,860 | |||||
Unamortized discount- net of premium | -- | (13 | ) | ||||
| Long-term debt due within one year | (31,000 | ) | (102,658 | ) | |||
| Total long-term debt excluding current maturities | 2,064,360 | 1,950,347 | |||||
| Total capitalization | $ | 3,938,932 | $ | 3,787,955 | |||
| 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 | ||||||||
(DOLLARS IN THOUSANDS) | Common Stock | Additional | Accumulated Other | ||||||||||||||||
FOR YEARS ENDED DECEMBER 31, 2004, 2003 & 2002 | Shares | Amount | Paid-in Capital | Retained Earnings | Comprehensive Income | Total Amount | |||||||||||||
| Balance at December 31, 2001 | 85,903,791 | $ | 859,038 | $ | 382,592 | $ | 55,345 | $ | (29,321 | ) | $ | 1,267,654 | |||||||
| Net income | -- | -- | -- | 108,948 | -- | 108,948 | |||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (7,904 | ) | -- | (7,904 | ) | |||||||||||
| Common stock dividend declared | -- | -- | -- | (89,418 | ) | -- | (89,418 | ) | |||||||||||
| Investment received from Puget Energy | -- | -- | 115,736 | -- | -- | 115,736 | |||||||||||||
| Other | -- | -- | 7 | -- | -- | 7 | |||||||||||||
| Other comprehensive income | -- | -- | -- | -- | 31,098 | 31,098 | |||||||||||||
| Balance at December 31, 2002 | 85,903,791 | $ | 859,038 | $ | 498,335 | $ | 66,971 | $ | 1,777 | $ | 1,426,121 | ||||||||
| Net income | -- | -- | -- | 119,886 | -- | 119,886 | |||||||||||||
| Preferred stock dividend declared | -- | -- | -- | (5,562 | ) | -- | (5,562 | ) | |||||||||||
| Common stock dividend declared | -- | -- | -- | (81,109 | ) | -- | (81,109 | ) | |||||||||||
| Investment received from Puget Energy | -- | -- | 106,124 | -- | -- | 106,124 | |||||||||||||
| Other | -- | -- | (8 | ) | -- | -- | (8 | ) | |||||||||||
| Other comprehensive loss | -- | -- | -- | -- | (9,983 | ) | (9,983 | ) | |||||||||||
| Balance at December 31, 2003 | 85,903,791 | $ | 859,038 | $ | 604,451 | $ | 100,186 | $ | (8,206 | ) | $ | 1,555,469 | |||||||
| Net income | -- | -- | -- | 126,192 | -- | 126,192 | |||||||||||||
| Common stock dividend declared | -- | -- | -- | (87,700 | ) | -- | (87,700 | ) | |||||||||||
| Investment received from Puget Energy | -- | -- | 5,016 | -- | -- | 5,016 | |||||||||||||
| Other comprehensive loss | -- | -- | -- | -- | (6,544 | ) | (6,544 | ) | |||||||||||
| Balance at December 31, 2004 | 85,903,791 | $ | 859,038 | $ | 609,467 | $ | 138,678 | $ | (14,750 | ) | $ | 1,592,433 | |||||||
(DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Net income | $ | 126,192 | $ | 119,886 | $ | 108,948 | ||||
| Other comprehensive income, net of tax: | ||||||||||
| Unrealized holding losses on marketable securities during the period | -- | (45 | ) | (1,359 | ) | |||||
Reclassification adjustment for realized gains on marketable securities included in net income | -- | (1,518 | ) | -- | ||||||
| Minimum pension liability adjustment | 157 | (1,122 | ) | (2,098 | ) | |||||
| Unrealized gains on derivative instruments during the period | 6,820 | 8,576 | 2,853 | |||||||
Reversal of unrealized (gains) losses on derivative instruments settled during the period | (10,418 | ) | 181 | 31,702 | ||||||
| Deferral related to power cost adjustment mechanism | (3,103 | ) | (16,055 | ) | -- | |||||
| Other comprehensive income (loss) | (6,544 | ) | (9,983 | ) | 31,098 | |||||
| Comprehensive income | $ | 119,648 | $ | 109,903 | $ | 140,046 | ||||
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 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 | |||||
| (DOLLARS IN THOUSANDS) FOR YEARS ENDED DECEMBER 31 | 2003 | 2002 | 2001 | ||||||||
| Operating activities: | |||||||||||
| Net income | $ | 119,886 | $ | 108,948 | $ | 104,381 | |||||
| Adjustments to reconcile net income | |||||||||||
| to net cash provided by operating activities: | |||||||||||
| Depreciation and amortization | 220,087 | 215,317 | 208,720 | ||||||||
| Deferred federal income taxes and tax credits - net | 49,276 | 140,536 | 7,151 | ||||||||
| Gain from sale of securities | (2,889 | ) | -- | -- | |||||||
| Net unrealized (gains) losses on derivative instrumen | 106 | (11,612 | ) | 3,567 | |||||||
| Other (including conservation amortization) | (6,353 | ) | 18,711 | 2,375 | |||||||
| 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 | 33,370 | 61,539 | 148,393 | ||||||||
| Materials and supplies | (13,643 | ) | 21,755 | 8,460 | |||||||
| Prepayments and other | 2,622 | (1,501 | ) | 2,507 | |||||||
| Purchased gas receivable (liability) | (71,826 | ) | 121,039 | 58,822 | |||||||
| Accounts payable | 12,863 | 38,893 | (247,931 | ) | |||||||
| Taxes payable | 17,910 | (13,646 | ) | (33,785 | ) | ||||||
| Accrued expenses and other | (4,120 | ) | 277 | 21,952 | |||||||
| Net cash provided by operating activities | 309,343 | 721,681 | 284,612 | ||||||||
| Investing activities: | |||||||||||
| Construction expenditures - excluding equity AFUDC | (269,973 | ) | (224,165 | ) | (247,435 | ) | |||||
| Energy conservation expenditures | (18,579 | ) | (11,356 | ) | (15,591 | ) | |||||
| Restricted cash | 20,106 | (18,871 | ) | -- | |||||||
| Proceeds from sale of securities | 3,161 | -- | -- | ||||||||
| Repayment from Schlumberger | -- | -- | 51,948 | ||||||||
| Other | 3,671 | (14,472 | ) | (16,446 | ) | ||||||
| Net cash used by investing activities | (261,614 | ) | (268,864 | ) | (227,524 | ) | |||||
| Financing activities: | |||||||||||
| Decrease in short-term debt - net | (30,340 | ) | (307,828 | ) | (38,845 | ) | |||||
| Dividends paid | (86,671 | ) | (97,321 | ) | (141,709 | ) | |||||
| Issuance of bonds | 304,465 | 40,000 | -- | ||||||||
| Issuance of trust preferred stock | -- | -- | 200,000 | ||||||||
| 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 | (356,860 | ) | (117,000 | ) | (19,000 | ) | |||||
| Investment from Puget Energy | 106,124 | 115,736 | -- | ||||||||
| Other | (10,121 | ) | (137 | ) | (3,709 | ) | |||||
| Net cash used by financing activities | (194,426 | ) | (374,050 | ) | (10,763 | ) | |||||
| Increase (decrease) in cash from net income | (146,697 | ) | 78,767 | 46,325 | |||||||
| Cash at beginning of year | 161,475 | 82,708 | 36,383 | ||||||||
| Cash at end of year | $ | 14,778 | $ | 161,475 | $ | 82,708 | |||||
| Supplemental Cash Flow Information: | |||||||||||
| Cash payments for: | |||||||||||
| Interest (net of capitalized interest) | $ | 187,256 | $ | 194,876 | $ | 187,347 | |||||
| Income taxes (net of refunds) | (1,456 | ) | (81,973 | ) | 87,020 | ||||||
(DOLLARS IN THOUSANDS FOR YEARS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Operating activities: | ||||||||||
| Net income | $ | 126,192 | $ | 119,886 | $ | 108,948 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
| Depreciation and amortization | 228,566 | 220,087 | 215,317 | |||||||
Deferred federal income taxes and tax credits- net | 72,446 | 49,276 | 140,536 | |||||||
| Gain from sale of securities | -- | (2,889 | ) | -- | ||||||
| Net unrealized (gain) loss on derivative instruments | (526 | ) | 106 | (11,612 | ) | |||||
| Other (including conservation amortization) | 20,806 | 14,591 | (8,277 | ) | ||||||
| Cash collateral received from (returned to) energy suppliers | 6,320 | (21,425 | ) | 21,425 | ||||||
| Increase (decrease) in Residential Exchange Program | 1,668 | (25,989 | ) | 21,201 | ||||||
| Pension plan funding | -- | (26,521 | ) | -- | ||||||
| Change in certain current assets and current liabilities: | ||||||||||
| Accounts receivable and unbilled revenue | 8,264 | 33,370 | 61,539 | |||||||
| Materials and supplies | (20,372 | ) | (13,643 | ) | 21,755 | |||||
| Prepayments and other | 38 | 2,622 | (1,501 | ) | ||||||
| Purchased gas receivable / liability | (31,073 | ) | (71,826 | ) | 121,039 | |||||
| Accounts payable | 23,282 | 12,863 | 38,893 | |||||||
| Taxes payable | (707 | ) | 17,910 | (13,646 | ) | |||||
| Tenaska disallowance reserve | 3,156 | -- | -- | |||||||
| Accrued expenses and other | (2,664 | ) | (4,120 | ) | 277 | |||||
| Net cash provided by operating activities | 435,396 | 304,298 | 715,894 | |||||||
| Investing activities: | ||||||||||
Construction expenditures- excluding equity AFUDC | (393,891 | ) | (269,973 | ) | (224,165 | ) | ||||
| Energy efficiency expenditures | (24,852 | ) | (18,579 | ) | (11,356 | ) | ||||
| Restricted cash | 905 | 20,106 | (18,871 | ) | ||||||
| Cash received from sale of securities | -- | 3,161 | -- | |||||||
| Refundable cash received for customer construction projects | 13,424 | 5,045 | 5,787 | |||||||
| Other | 1,444 | 3,671 | (14,472 | ) | ||||||
| Net cash used by investing activities | (402,970 | ) | (256,569 | ) | (263,077 | ) | ||||
| Financing activities: | ||||||||||
Decrease in short-term debt- net | -- | (30,340 | ) | (307,828 | ) | |||||
| Dividends paid | (87,700 | ) | (86,671 | ) | (97,321 | ) | ||||
| Issuance of bonds and notes | 200,000 | 304,465 | 40,000 | |||||||
| Redemption of preferred stock | -- | (60,000 | ) | -- | ||||||
| Redemption of mandatorily redeemable preferred stock | -- | (41,273 | ) | (7,500 | ) | |||||
| Redemption of trust preferred stock | -- | (19,750 | ) | -- | ||||||
| Redemption of bonds and notes | (157,658 | ) | (356,860 | ) | (117,000 | ) | ||||
| Investment from Puget Energy | 5,016 | 106,124 | 115,736 | |||||||
| Other | 6,093 | (10,121 | ) | (137 | ) | |||||
| Net cash used by financing activities | (34,249 | ) | (194,426 | ) | (374,050 | ) | ||||
| Increase (decrease) in cash from net income | (1,823 | ) | (146,697 | ) | 78,767 | |||||
| Cash at beginning of year | 14,778 | 161,475 | 82,708 | |||||||
| Cash at end of year | $ | 12,955 | $ | 14,778 | $ | 161,475 | ||||
Supplemental Cash Flow Information: | ||||||||||
| Cash payments for: | ||||||||||
| Interest (net of capitalized interest) | $ | 175,772 | $ | 187,256 | $ | 194,876 | ||||
| Income taxes (net refunds) | (1,042 | ) | (1,456 | ) | (81,973 | ) | ||||
assets.
| (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 | 142 | .8 | 167 | .1 | |||||||
| 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 | 26 | .0 | 21 | .9 | ||||||
| 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 | 23 | .4 | 27 | .8 | ||||||
| Deferred gains on property sales | 3 years | (10 | .1) | (14 | .4) | ||||||
| Purchased gas payable | 1 year | (5 | .4) | (83 | .8) | ||||||
| Various other regulatory liabilities | 1 to 17 years | (5 | .2) | (5 | .9) | ||||||
| Net regulatory assets and liabilities | $ | 461 | .8 | $ | 406 | .1 | |||||
(DOLLARS IN MILLIONS) | REMAINING AMORTIZATION PERIOD | 2004 | 2003 | |||||||
| PURPA electric energy supply contract buyout costs | 4 to 7 years | $ | 211.2 | $ | 227.8 | |||||
| Deferred income taxes | *** | 127.3 | 142.8 | |||||||
| White River relicensing and other costs | * | 65.3 | 20.8 | |||||||
| Investment in Bonneville Exchange Power contract | 12 years | 44.1 | 47.6 | |||||||
| Environmental remediation | * | 42.3 | 41.6 | |||||||
| Deferred AFUDC | 30 years | 30.4 | 30.3 | |||||||
| Tree watch costs | 10 years | 28.3 | 29.0 | |||||||
Storm damage costs- electric | 3.5 years | 21.1 | 26.0 | |||||||
| Purchased Gas Adjustment (PGA) receivable | * | 19.1 | -- | |||||||
| Colstrip common property | 19 years | 13.9 | 14.6 | |||||||
| PGA deferral of unrealized losses on derivative instruments | *** | 12.1 | 3.3 | |||||||
| Various other regulatory assets | 1 to 26 years | 30.2 | 23.1 | |||||||
| Power Cost Adjustment (PCA) mechanism | * | -- | 3.6 | |||||||
| Cost of removal | ** | (132.4 | ) | (124.9 | ) | |||||
| PCA deferral of unrealized gain on derivative instrument | * | (30.8 | ) | (24.3 | ) | |||||
| Gas Supply contract settlement | 3.5 year | (10.1 | ) | -- | ||||||
| Deferred gains on property sales | 3 years | (4.5 | ) | (10.1 | ) | |||||
| Tenaska disallowance reserve | 1 year | (3.2 | ) | -- | ||||||
| Purchased Gas Adjustment payable | *** | -- | (12.0 | ) | ||||||
| Various other regulatory liabilities | 1 to 22 years | (4.7 | ) | (5.4 | ) | |||||
| Net regulatory assets and liabilities | $ | 459.6 | $ | 433.8 | ||||||
rates.
RESTRICTED CASHrespectively
12).
As a result of the tracker mechanism, gas energy efficiency expenditures have no impact on earnings.
| ANNUAL POWER COST VARIABILITY | CUSTOMERS' SHARE | COMPANY'S SHARE1 | ||
| +/- $20 million | 0% | 100% | ||
| +/- $20 million - $40 million | 50% | 50% | ||
| +/- $40 million - $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 cost variation is capped at a cumulative $40 million plus 1% of the excess. Power cost variation after June 30, 2006 will be apportioned on an annual basis, based on the graduated scale. |
The graduated scale isPGA mechanism allows PSE to recover expected gas costs, and defer, 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 | % | |
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 as amended by SFAS No. 138 and SFAS No. 149. (See Note 15 for further discussion.) The Company has established policies and procedures to manage these risks. A Risk Management Committee separate from the business units that createmanages these risks monitors compliance with policiesusing analytical models and procedures.tools. In addition, the Audit Committee of the Company’s Board of Directors has oversightperiodically assesses risk management policies.
| · | ensure that physical energy supplies are available to serve retail customer requirements; |
| · | manage portfolio risks to limit undesired impacts on the Company’s costs; and |
| · | maximize the value of the Company’s energy supply assets. |
| (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 | |||||
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) YEARS ENDED DECEMBER 31 | 2004 | 2003 | 2002 | |||||||
| Net income, as reported | $ | 55,022 | $ | 116,197 | $ | 110,052 | ||||
Add: Total stock-based employee compensation expense included in net income, net of tax | 2,641 | 4,180 | 4,103 | |||||||
Less: Total stock-based employee compensation expense per the fair value method of SFAS No. 123, net of tax | (3,303 | ) | (3,314 | ) | (3,495 | ) | ||||
| Pro forma net income | $ | 54,360 | $ | 117,063 | $ | 110,660 | ||||
| Earnings per common share: | ||||||||||
| Basic as reported | $ | 0.55 | $ | 1.23 | $ | 1.24 | ||||
| Diluted as reported | $ | 0.55 | $ | 1.22 | $ | 1.24 | ||||
| Basic pro forma | $ | 0.55 | $ | 1.24 | $ | 1.25 | ||||
| Diluted pro forma | $ | 0.54 | $ | 1.23 | $ | 1.25 | ||||
At times the Company will enter into treasury lock transactions to hedge against the potential rising interest rates. The transaction, when settled, will be amortized over the related debt issuance life.
NEW ACCOUNTING PRONOUNCEMENTS2003.
if issued.
| 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
UTILITY PLANT (DOLLARS IN THOUSANDS) AT DECEMBER 31 | ESTIMATED USEFUL LIFE (YEARS) | 2004 | 2003 | |||
Electric, gas and common utility plant classified by prescribed accounts at original cost: | ||||||
| Distribution plant | 10-60 | $ 4,219,720 | $ 4,030,570 | |||
| Production plant | 40-100 | 1,150,781 | 1,144,354 | |||
| Transmission plant | 30-95 | 426,543 | 379,889 | |||
| General plant | 10-35 | 346,472 | 344,781 | |||
| Construction work in progress | NA | 129,966 | 121,622 | |||
| Intangible plant (including capitalized software) | 3-29 | 283,179 | 270,235 | |||
| Plant acquisition adjustment | 21 | 76,623 | 76,623 | |||
| Underground storage | 50-80 | 23,089 | 22,362 | |||
| Liquefied natural gas storage | 14-50 | 12,345 | 2,348 | |||
| Plant held for future use | -- | 7,296 | 7,608 | |||
| Other | 27-34 | 5,313 | 5,240 | |||
| Less accumulated provision for depreciation | (2,452,969 | ) | (2,325,405 | ) | ||
| Net utility plant | $ 4,228,358 | $ 4,080,227 |
NON-UTILITY PLANT (DOLLARS IN THOUSANDS) AT DECEMBER 31 | ESTIMATED USEFUL LIFE (YEARS) | 2004 | 2003 | |||
| Non-utility plant | 3-20 | $ 138,656 | $ 122,926 | |||
| Intangibles | 5-20 | 24,056 | 23,985 | |||
| Less accumulated depreciation and amortization | (52,947 | ) | (36,272 | ) | ||
| Net non-utility plant and intangibles | $ 109,765 | $ 110,639 |
| (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 | |||
liability:
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| Asset retirement obligation at beginning of year | $ | 3,421 | $ | -- | |||
| Liability recognized in transition | -- | 3,592 | |||||
| Liability settled in the period | -- | (261 | ) | ||||
| Accretion expense | 95 | 90 | |||||
| Asset retirement obligation at December 31 | $ | 3,516 | $ | 3,421 | |||
| (DOLLARS IN THOUSANDS) | |||
| Pro forma amounts of liability for asset retirement obligation at | $ 3,497 | ||
| Pro forma amounts of liability for asset retirement obligation at December 31, 2002 | 3,592 | ||
| (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 | |||||
| (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) | 2003 | 2002 | |||||
| Net income, as reported | $ | 116,197 | $ | 110,052 | |||
| Add: SFAS No. 143 transition adjustment, net of tax | 169 | -- | |||||
| Less: Pro forma accretion expense, net of tax | -- | (62 | ) | ||||
| Pro forma net income | $ | 116,366 | $ | 109,990 | |||
| Earnings per share: | |||||||
| Basic as reported | $ | 1.23 | $ | 1.24 | |||
| Diluted as reported | $ | 1.22 | $ | 1.24 | |||
| Basic pro forma | $ | 1.23 | $ | 1.24 | |||
| Diluted pro forma | $ | 1.22 | $ | 1.24 | |||
2003.
| 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 $100 PAR VALUE | ||||||||||
4.70% SERIES | 4.84% SERIES | 7.75% SERIES | ||||||||
| Shares outstanding December 31, 2001 | 4,311 | 14,808 | 487,500 | |||||||
| Acquired for sinking fund: | ||||||||||
| 2002 | -- | -- | (75,000 | ) | ||||||
| 2003 | -- | -- | (75,000 | ) | ||||||
| 2004 | -- | -- | -- | |||||||
| Called for redemption or reacquired and canceled: | ||||||||||
| 2002 | -- | -- | -- | |||||||
| 2003 | -- | (225 | ) | (337,500 | ) | |||||
| 2004 | -- | -- | -- | |||||||
| Shares outstanding December 31, 2004 | 4,311 | 14,583 | -- | |||||||
| SERIES | DUE | 2003 | 2002 | SERIES | DUE | 2003 | 2002 | |
| 6.20% | 2003 | $ -- | $ 3,000 | 7.61% | 2008 | $ 25,000 | $ 25,000 | |
| 6.23% | 2003 | -- | 1,500 | 6.46% | 2009 | 150,000 | 150,000 | |
| 6.24% | 2003 | -- | 1,500 | 6.61% | 2009 | 3,000 | 3,000 | |
| 6.30% | 2003 | -- | 20,000 | 6.62% | 2009 | 5,000 | 5,000 | |
| 6.31% | 2003 | -- | 5,000 | 7.12% | 2010 | 7,000 | 7,000 | |
| 6.40% | 2003 | -- | 11,000 | 7.96% | 2010 | 225,000 | 225,000 | |
| 7.02% | 2003 | -- | 30,000 | 7.69% | 2011 | 260,000 | 260,000 | |
| 6.25% | 2004 | -- | 40,000 | 8.20% | 2012 | -- | 30,000 | |
| 6.07% | 2004 | 10,000 | 10,000 | 8.59% | 2012 | -- | 5,000 | |
| 6.10% | 2004 | 8,500 | 8,500 | 6.83% | 2013 | 3,000 | 3,000 | |
| 7.70% | 2004 | 50,000 | 50,000 | 6.90% | 2013 | 10,000 | 10,000 | |
| 7.80% | 2004 | 30,000 | 30,000 | 7.35% | 2015 | 10,000 | 10,000 | |
| 6.92% | 2005 | 11,000 | 11,000 | 7.36% | 2015 | 2,000 | 2,000 | |
| 6.93% | 2005 | 20,000 | 20,000 | 6.74% | 2018 | 200,000 | 200,000 | |
| 6.58% | 2006 | 10,000 | 10,000 | 9.57% | 2020 | 25,000 | 25,000 | |
| 8.06% | 2006 | 46,000 | 46,000 | 8.25% | 2022 | -- | 25,000 | |
| 8.14% | 2006 | 25,000 | 25,000 | 8.39% | 2022 | -- | 7,000 | |
| 7.02% | 2007 | 20,000 | 20,000 | 8.40% | 2022 | -- | 3,000 | |
| 7.04% | 2007 | 5,000 | 5,000 | 7.19% | 2023 | -- | 3,000 | |
| 7.75% | 2007 | 100,000 | 100,000 | 7.35% | 2024 | 55,000 | 55,000 | |
| 8.40% | 2007 | -- | 10,000 | 7.15% | 2025 | 15,000 | 15,000 | |
| 3.363% | 2008 | 150,000 | -- | 7.20% | 2025 | 2,000 | 2,000 | |
| 6.51% | 2008 | 1,000 | 1,000 | 7.02% | 2027 | 300,000 | 300,000 | |
| 6.53% | 2008 | 3,500 | 3,500 | 7.00% | 2029 | 100,000 | 100,000 | |
| Total | $1,887,000 | $1,932,000 |
In June 2003, the Company issued $150 million in first mortgage bonds, which are due June 2008.
| SERIES | DUE | 2004 | 2003 | SERIES | DUE | 2004 | 2003 | |||||||
| 6.07% | 2004 | $ -- | $10,000 | 6.46% | 2009 | 150,000 | 150,000 | |||||||
| 6.10% | 2004 | -- | 8,500 | 6.61% | 2009 | 3,000 | 3,000 | |||||||
| 7.70% | 2004 | -- | 50,000 | 6.62% | 2009 | 5,000 | 5,000 | |||||||
| 7.80% | 2004 | -- | 30,000 | 7.12% | 2010 | 7,000 | 7,000 | |||||||
| 6.92% | 2005 | 11,000 | 11,000 | 7.96% | 2010 | 225,000 | 225,000 | |||||||
| 6.93% | 2005 | 20,000 | 20,000 | 7.69% | 2011 | 260,000 | 260,000 | |||||||
| Variable | 2006 | 200,000 | -- | 6.83% | 2013 | 3,000 | 3,000 | |||||||
| 6.58% | 2006 | 10,000 | 10,000 | 6.90% | 2013 | 10,000 | 10,000 | |||||||
| 8.06% | 2006 | 46,000 | 46,000 | 7.35% | 2015 | 10,000 | 10,000 | |||||||
| 8.14% | 2006 | 25,000 | 25,000 | 7.36% | 2015 | 2,000 | 2,000 | |||||||
| 7.02% | 2007 | 20,000 | 20,000 | 6.74% | 2018 | 200,000 | 200,000 | |||||||
| 7.04% | 2007 | 5,000 | 5,000 | 9.57% | 2020 | 25,000 | 25,000 | |||||||
| 7.75% | 2007 | 100,000 | 100,000 | 7.35% | 2024 | -- | 55,000 | |||||||
| 3.363% | 2008 | 150,000 | 150,000 | 7.15% | 2025 | 15,000 | 15,000 | |||||||
| 6.51% | 2008 | 1,000 | 1,000 | 7.20% | 2025 | 2,000 | 2,000 | |||||||
| 6.53% | 2008 | 3,500 | 3,500 | 7.02% | 2027 | 300,000 | 300,000 | |||||||
| 7.61% | 2008 | 25,000 | 25,000 | 7.00% | 2029 | 100,000 | 100,000 | |||||||
| Total | $1,933,500 | $1,887,000 | ||||||||||||
required amount.
| AT DECEMBER 31 (DOLLARS IN THOUSANDS) SERIES | DUE | 2003 | 2002 | |
| 2003A Series - 5.00% | 2031 | $138,460 | $ -- | |
| 2003B Series - 5.10% | 2031 | 23,400 | -- | |
| 1993 Series - 5.875% | 2020 | -- | 23,460 | |
| 1991 Series - 7.05% | 2021 | -- | 27,500 | |
| 1991 Series - 7.25% | 2021 | -- | 23,400 | |
| 1992 Series - 6.80% | 2022 | -- | 87,500 | |
| Total | $161,860 | $161,860 | ||
AT DECEMBER 31 (DOLLARS IN THOUSANDS) | |||
| SERIES | DUE | 2004 | 2003 |
2003A Series- 5.00% | 2031 | $ 138,460 | $ 138,460 |
2003B Series- 5.10% | 2031 | 23,400 | 23,400 |
| Total | $ 161,860 | $ 161,860 | |
was $4.2 million.
| 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 |
| 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 |
PUGET ENERGY (DOLLARS IN THOUSANDS) | 2005 | 2006 | 2007 | 2008 | 2009 | THEREAFTER |
| Maturities of: | ||||||
| Long-term debt | $ 38,933 | $ 292,276 | $ 259,866 | $ 181,089 | $ 158,441 | $ 1,320,860 |
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | 2005 | 2006 | 2007 | 2008 | 2009 | THEREAFTER |
| Maturities of: | ||||||
| Long-term debt | $ 31,000 | $ 281,000 | $ 125,000 | $ 179,500 | $ 158,000 | $ 1,320,860 |
| (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 impact2003.
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2004 | 2003 | |||||
| Short-term borrowings outstanding: | |||||||
| InfrastruX bank line of credit borrowings | $ | 8,297 | $ | 13,893 | |||
| Weighted average interest rate | 2.47 | % | 2.59 | % | |||
| Financing arrangements: | |||||||
Puget Energy line of credit1 | $ | 15,000 | $ | 15,000 | |||
InfrastruX revolving credit facilities2 | 186,725 | 184,725 | |||||
PSE line of credit3 | 350,000 | 250,000 | |||||
PSE receivables securitization program4 | 150,000 | 150,000 | |||||
| 1 | Includes $5.0 million outstanding at December 31, 2004, leaving $10.0 million available under the agreement. On February 1, 2005, Puget Energy reduced the capacity to $5.0 million. |
| 2 | The revolving credit facility requires InfrastruX and its subsidiaries to maintain certain financial covenants, including requirements to maintain certain levels of net worth and debt coverage. The agreement also places certain restrictions on expenditures, other indebtedness and executive compensation. For 2004 and 2003, InfrastruX had $143.1 million and $155.6 million outstanding under the credit facilities, effectively reducing available borrowing capacity to $43.6 million and $29.1 million, respectively. |
| 3 | Provides liquidity support for PSE’s outstanding commercial paper and letters of credit in the amount of $0.5 million in 2004 and 2003, effectively reducing the available borrowing capacity under these credit lines to $349.5 million and $249.5 million, respectively. There was no commercial paper outstanding at December 31, 2004 and 2003. |
| 4 | Provides liquidity support for PSE’s outstanding letters of credit and commercial paper. At December 31, 2004, PSE had sold $150.0 million in receivables, leaving no amounts available to borrow under the receivables securitization program. At December 31, 2003, PSE had sold $111.0 million in receivables. |
1 Includes $5.0 million outstanding at December 31, 2003, effectively reducing the available borrowing capacity to $10.0 million.Contents
| 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 | ||||||
The2003.
| 2004 | 2003 | ||||||||||||
(DOLLARS IN MILLIONS) | CARRYING AMOUNT | FAIR VALUE | CARRYING AMOUNT | FAIR VALUE | |||||||||
| Financial assets: | |||||||||||||
| Cash | $ | 19.8 | $ | 19.8 | $ | 27.5 | $ | 27.5 | |||||
| Restricted cash | 1.6 | 1.6 | 2.5 | 2.5 | |||||||||
| Equity securities | 1.9 | 1.9 | 3.6 | 3.6 | |||||||||
| Notes receivable and other | 71.4 | 71.4 | 63.6 | 63.6 | |||||||||
| Energy derivatives | 21.9 | 21.9 | 16.2 | 16.2 | |||||||||
| Financial liabilities: | |||||||||||||
| Short-term debt | $ | 8.3 | $ | 8.3 | $ | 13.9 | $ | 13.9 | |||||
| Preferred stock subject to mandatory redemption | 1.9 | 1.9 | 1.9 | 1.9 | |||||||||
Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | 280.3 | 290.9 | 280.3 | 304.6 | |||||||||
Long-term debt- fixed-rate1 | 2,051.4 | 2,194.8 | 2,216.3 | 2,409.6 | |||||||||
Long-term debt- variable-rate1 | 200.0 | 199.9 | -- | -- | |||||||||
| Energy derivatives | 19.5 | 19.5 | 3.6 | 3.6 | |||||||||
| 1 | PSE’s carrying value and fair value of both fixed-rate and variable-rate long-term debt in 2004 was $2,095.4 million and $2,238.7 million, respectively. PSE’s carrying value and fair value of fixed-rate long-term debt in 2003 was $2,053.0 million and $2,250.4 million, respectively. |
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) There was included as a component of other comprehensive income net of deferred taxes of $0.8 million for 2002.no preferred stock redeemed in 2004.
| (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 | |
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | |
| AT DECEMBER 31 | OPERATING | CAPITAL | OPERATING |
| 2004 | $ 25,751 | $ 2,086 | $ 17,618 |
| 2003 | 26,842 | 2,696 | 19,301 |
| 2002 | 26,386 | 2,486 | 20,176 |
| (DOLLARS IN THOUSANDS) | 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 | |
| (DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | |
| AT DECEMBER 31 | OPERATING | CAPITAL | OPERATING |
| 2005 | $ 19,311 | $ 1,988 | $ 12,791 |
| 2006 | 19,804 | 2,057 | 16,034 |
| 2007 | 17,500 | 1,558 | 15,524 |
| 2008 | 15,174 | 1,032 | 14,496 |
| 2009 | 11,591 | 343 | 11,459 |
| Thereafter | 46,140 | -- | 46,045 |
| Total minimum lease payments | $ 129,520 | $ 6,978 | $ 116,349 |
(DOLLARS IN THOUSANDS) AT DECEMBER 31 | 2005 | 2006 | 2007 | 2008 | 2009 |
| Lease receipts | $ 1,182 | $ 1,182 | $ 1,182 | $ 1,182 | $ 985 |
Puget Energy.
| 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 | ||||||||
PUGET ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Charged to operating expense: | ||||||||||
Current- federal | $ | 7,607 | $ | 18,119 | $ | (84,149 | ) | |||
Current- state | 75 | (2,046 | ) | (774 | ) | |||||
| Deferred -federal | 70,522 | 56,004 | 144,230 | |||||||
Deferred- state | (2,647 | ) | 927 | 614 | ||||||
| Deferred investment tax credits | (593 | ) | (635 | ) | (661 | ) | ||||
| Total charged to operations | 74,964 | 72,369 | 59,260 | |||||||
| Charged to miscellaneous income: | ||||||||||
| Current | (5,344 | ) | (288 | ) | (3,276 | ) | ||||
| Deferred | 2,470 | (1,805 | ) | 1,228 | ||||||
| Total charged to miscellaneous income | (2,874 | ) | (2,093 | ) | (2,048 | ) | ||||
| Cumulative effect of accounting change | -- | (91 | ) | -- | ||||||
| Total income taxes | $ | 72,090 | $ | 70,185 | $ | 57,212 | ||||
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Charged to operating expense: | ||||||||||
Current- federal | $ | 5,825 | $ | 22,154 | $ | (81,839 | ) | |||
Current- state | (21 | ) | (1,460 | ) | (548 | ) | ||||
| Deferred -federal | 71,966 | 50,880 | 135,884 | |||||||
Deferred- state | -- | -- | -- | |||||||
| Deferred investment tax credits | (593 | ) | (635 | ) | (661 | ) | ||||
| Total charged to operations | 77,177 | 70,939 | 52,836 | |||||||
| Charged to miscellaneous income: | ||||||||||
| Current | (5,306 | ) | (276 | ) | (3,406 | ) | ||||
| Deferred | 2,470 | (1,805 | ) | 1,228 | ||||||
| Total charged to miscellaneous income | (2,836 | ) | (2,081 | ) | (2,178 | ) | ||||
| Cumulative effect of accounting change | -- | (91 | ) | -- | ||||||
| Total income taxes | $ | 74,341 | $ | 68,767 | $ | 50,658 | ||||
| 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% | ||||||||||||||
PUGET ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Income taxes at the statutory rate | $ | 42,016 | $ | 65,295 | $ | 58,846 | ||||
| Increase (decrease): | ||||||||||
| Depreciation expense deducted in the financial statements in excess of tax depreciation, net of depreciation treated as a temporary difference | 10,723 | 9,130 | 10,041 | |||||||
| AFUDC included in income in the financial statements but excluded from taxable income | (2,270 | ) | (1,809 | ) | (1,387 | ) | ||||
| Accelerated benefit on early retirement of depreciable assets | (1,297 | ) | (1,879 | ) | (1,469 | ) | ||||
| Investment tax credit amortization | (593 | ) | (635 | ) | (661 | ) | ||||
| Energy Efficiency expenditures - net | (134 | ) | 8,096 | 6,259 | ||||||
| Tax benefit of reduced salvage values | -- | -- | (10,193 | ) | ||||||
| IRS issue resolution | -- | (6,209 | ) | -- | ||||||
| Goodwill impairment | 10,276 | -- | -- | |||||||
| Valuation allowance | 17,988 | -- | -- | |||||||
| Preferred stock dividends of subsidiary | -- | 1,803 | 2,741 | |||||||
| Sate income taxes net of the federal income tax benefit | (2,566 | ) | (877 | ) | (104 | ) | ||||
| Other - net | (2,053 | ) | (2,730 | ) | (6,861 | ) | ||||
| Total income taxes | $ | 72,090 | $ | 70,185 | $ | 57,212 | ||||
| Effective tax rate | 62.2 | % | 37.6 | % | 34.0 | % | ||||
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Income taxes at the statutory rate | $ | 70,187 | $ | 66,028 | $ | 55,862 | ||||
| Increase (decrease): | ||||||||||
Depreciation expense deducted in the financial statements in excess of tax depreciation, net of depreciation treated as a temporary difference | 10,723 | 9,130 | 10,041 | |||||||
AFUDC included in income in the financial statements but excluded from taxable income | (2,270 | ) | (1,809 | ) | (1,387 | ) | ||||
| Accelerated benefit on early retirement of depreciable assets | (1,297 | ) | (1,879 | ) | (1,469 | ) | ||||
| Investment tax credit amortization | (593 | ) | (635 | ) | (661 | ) | ||||
| Energy Efficiency expenditures - net | (134 | ) | 8,096 | 6,259 | ||||||
| Tax benefit of reduced salvage values | -- | -- | (10,193 | ) | ||||||
| IRS issue resolution | -- | (6,209 | ) | -- | ||||||
| Sate income taxes net of the federal income tax benefit | (14 | ) | (949 | ) | (356 | ) | ||||
| Other - net | (2,261 | ) | (3,006 | ) | (7,438 | ) | ||||
| Total income taxes | $ | 74,341 | $ | 68,767 | $ | 50,658 | ||||
| Effective tax rate | 37.1 | % | 36.5 | % | 31.7 | % | ||||
| 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
PUGET ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Plant and equipment | $ | 665,407 | $ | 622,462 | $ | 588,182 | ||||
| Capitalized overhead costs | 72,448 | 70,834 | 72,220 | |||||||
| Software amortization | 37,484 | 41,044 | 41,408 | |||||||
| Pensions and compensation | 15,367 | 16,890 | 29,099 | |||||||
| Bonneville Exchange Power | 14,078 | 15,204 | 15,537 | |||||||
| Energy Efficiency charges | 10,320 | 9,446 | 16,473 | |||||||
| Other deferred tax liabilities | 68,587 | 68,351 | 46,655 | |||||||
| Subtotal deferred tax liabilities | 883,691 | 844,231 | 809,574 | |||||||
| Contributions in aid of construction | (41,525 | ) | (46,520 | ) | (44,770 | ) | ||||
| Goodwill | (18,683 | ) | 4,192 | 2,106 | ||||||
| Other deferred tax assets | (30,745 | ) | (46,668 | ) | (36,235 | ) | ||||
| Subtotal deferred tax assets | (90,953 | ) | (88,996 | ) | (78,899 | ) | ||||
| Valuation allowance | 17,988 | -- | -- | |||||||
| Subtotal net deferred tax assets | (72,965 | ) | (88,996 | ) | (78,899 | ) | ||||
| Total | $ | 810,726 | $ | 755,235 | $ | 730,675 | ||||
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Plant and equipment | $ | 645,826 | $ | 607,203 | $ | 578,137 | ||||
| Capitalized overhead costs | 72,448 | 70,834 | 72,220 | |||||||
| Software amortization | 37,484 | 41,044 | 41,408 | |||||||
| Pensions and compensation | 15,367 | 16,890 | 29,099 | |||||||
| Bonneville Exchange Power | 14,078 | 15,204 | 15,537 | |||||||
| Energy Efficiency charges | 10,320 | 9,446 | 16,473 | |||||||
| Other deferred tax liabilities | 63,926 | 64,511 | 43,710 | |||||||
| Subtotal deferred tax liabilities | 859,449 | 825,132 | 796,584 | |||||||
| Contributions in aid of construction | (41,525 | ) | (46,520 | ) | (44,770 | ) | ||||
| Other deferred tax assets | (30,745 | ) | (46,668 | ) | (36,235 | ) | ||||
| Subtotal deferred tax assets | (72,270 | ) | (93,188 | ) | (81,005 | ) | ||||
| Total | $ | 787,179 | $ | 731,944 | $ | 715,579 | ||||
| PENSION BENEFITS | OTHER BENEFITS | ||||||||||||
| (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2004 | 2003 | |||||||||
Change in benefit obligation: | |||||||||||||
| Benefit obligation at beginning of year | $ | 400,041 | $ | 369,692 | $ | 29,220 | $ | 31,693 | |||||
| Service cost | 10,343 | 8,284 | 189 | 175 | |||||||||
| Interest cost | 24,082 | 24,406 | 1,670 | 1,828 | |||||||||
| Amendments | -- | 940 | -- | -- | |||||||||
| Actuarial (gain) loss | 37,628 | 19,354 | 963 | (2,194 | ) | ||||||||
| Special recognition of prior service costs | -- | 190 | -- | -- | |||||||||
| Benefits paid | (32,357 | ) | (22,825 | ) | (2,050 | ) | (2,282 | ) | |||||
| Benefit obligation at end of year | $ | 439,737 | $ | 400,041 | $ | 29,992 | $ | 29,220 | |||||
| PENSION BENEFITS | OTHER BENEFITS | |||||||||||||
| (DOLLARS IN THOUSANDS) | 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 | ) | ||||
Change in plan assets: | |||||||||||||
| Fair value of plan assets at beginning of year | $ | 428,586 | $ | 343,960 | $ | 15,431 | $ | 16,160 | |||||
| Actual return on plan assets | 51,395 | 79,488 | 1,184 | 98 | |||||||||
| Employer contribution | 11,356 | 27,963 | 1,394 | 1,455 | |||||||||
| Benefits paid | (32,357 | ) | (22,825 | ) | (2,050 | ) | (2,282 | ) | |||||
| Fair value of plan assets at end of year | $ | 458,980 | $ | 428,586 | $ | 15,959 | $ | 15,431 | |||||
| Funded status | $ | 19,243 | $ | 28,545 | $ | (14,033 | ) | $ | (13,789 | ) | |||
| Unrecognized actuarial (gain) loss | 72,428 | 48,217 | (2,019 | ) | (2,895 | ) | |||||||
| Unrecognized prior service cost | 12,760 | 15,949 | 2,403 | 2,712 | |||||||||
| Unrecognized net initial (asset) obligation | (163 | ) | (1,267 | ) | 3,365 | 3,783 | |||||||
| Net amount recognized | $ | 104,268 | $ | 91,444 | $ | (10,284 | ) | $ | (10,189 | ) | |||
Amounts recognized on statement of financial position consist of: | |||||||||||||
| Prepaid benefit cost | $ | 120,748 | $ | 112,737 | $ | -- | $ | -- | |||||
| Accrued benefit liability | (32,042 | ) | (38,704 | ) | (10,284 | ) | (10,189 | ) | |||||
| Intangible asset | 7,351 | 9,043 | -- | -- | |||||||||
| Accumulated other comprehensive income | 8,211 | 8,368 | -- | -- | |||||||||
| Net amount recognized | $ | 104,268 | $ | 91,444 | $ | (10,284 | ) | $ | (10,189 | ) | |||
| PENSION BENEFITS | OTHER BENEFITS | |||||
| 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 | ||||||
BENEFIT OBLIGATION ASSUMPTIONS | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |
| Discount rate | 5.60% | 6.25% | 6.75% | 5.60% | 6.25% | 6.75% | |
| Rate of compensation increase | 4.50% | 4.50% | 4.50% | -- | -- | -- | |
| Medical trend rate | -- | -- | -- | 12.00% | 9.00% | 10.00% | |
| PENSION BENEFITS | OTHER BENEFITS | ||||||
BENEFIT COST ASUMPTIONS | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |
| Discount rate | 6.25% | 6.75% | 7.25% | 6.25% | 6.75% | 7.25% | |
| Return on plan assets | 8.25% | 8.25% | 9.25% | 5-8.25% | 6-7.00% | 6-8.25% | |
| Rate of compensation increase | 4.50% | 4.50% | 4.50% | -- | -- | -- | |
| Medical trend rate | -- | -- | -- | 9.00% | 10.00% | 6.50% | |
| PENSION BENEFITS | OTHER BENEFITS | |||||||||||||||||||
| (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
| PENSION BENEFITS | OTHER BENEFITS | ||||||||||||||||||
| (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||||||
Components of net periodic benefit cost: | |||||||||||||||||||
| Service cost | $ | 10,343 | $ | 8,284 | $ | 8,474 | $ | 189 | $ | 175 | $ | 168 | |||||||
| Interest cost | 24,082 | 24,406 | 25,858 | 1,670 | 1,828 | 1,930 | |||||||||||||
| Expected return on plan assets | (39,106 | ) | (38,880 | ) | (43,032 | ) | (858 | ) | (934 | ) | (906 | ) | |||||||
| Amortization of prior service cost | 3,189 | 3,220 | 2,990 | 309 | 309 | 90 | |||||||||||||
| Recognized net actuarial gain | 1,128 | (2,688 | ) | (5,120 | ) | (239 | ) | (341 | ) | (229 | ) | ||||||||
| Amortization of transition (asset) obligation | (1,104 | ) | (1,104 | ) | (1,136 | ) | 418 | 418 | 470 | ||||||||||
| Plan curtailment | -- | -- | (1,353 | ) | -- | -- | 1,691 | ||||||||||||
| Special recognition of prior service costs | -- | 190 | 1,683 | -- | -- | -- | |||||||||||||
| Net pension benefit cost (income) | $ | (1,468 | ) | $ | (6,572 | ) | $ | (11,636 | ) | $ | 1,489 | $ | 1,455 | $ | 3,214 | ||||
| 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% | -- |
| 2004 | 2003 | ||||
PENSION BENEFITS | OTHER BENEFITS | PENSION BENEFITS | OTHER BENEFITS | ||
| Short-term investments and cash | 2.4% | 100.0% | 3.0% | 100.0% | |
| Equity securities | 67.8% | -- | 63.8% | -- | |
| Fixed income securities | 18.2% | -- | 22.9% | -- | |
| Mutual funds (equity and fixed income) | 11.6% | -- | 10.3% | -- | |
| (DOLLARS IN THOUSANDS) | 2004 | 2005 | 2006 | 2007 | 2008 | 2009-2013 |
| Total benefits | $ 35,697 | $ 25,940 | $ 26,939 | $ 28,806 | $ 28,202 | $157,821 |
| (Dollars in Thousands) | 2005 | 2006 | 2007 | 2008 | 2009 | 2010-2014 | |||||
| Total benefits | $29,768 | $30,202 | $31,256 | $32,904 | $33,253 | $180,516 |
| 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 | ) | ||||||||
| 2004 | 2003 | |||||||||||
(DOLLARS IN THOUSANDS) | 1% INCREASE | 1% DECREASE | 1% INCREASE | 1% DECREASE | ||||||||
| Effect on post-retirement benefit obligation | $ 552 | $ (477 | ) | $ 589 | $ (529 | ) | ||||||
| Effect on service and interest cost components | 31 | (28 | ) | 38 | (35 | ) | ||||||
| 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% |
| ALLOCATION | ||||||
| ASSET CLASS | MINIMUM | TARGET | MAXIMUM | |||
| Short-term investments and cash | -- | -- | 5% | |||
| Equity securities | 40% | 70% | 95% | |||
| Fixed-income securities | 20% | 30% | 40% | |||
| Real estate | -- | -- | 10% | |||
| 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 | ||||||||||
2002:
| 2004 | 2003 | 2002 | |||||||||||||||||
Shares (in thousands) | Weighted Average Exercise Price | Shares (in thousands) | Weighted Average Exercise Price | Shares (in thousands) | Weighted Average Exercise Price | ||||||||||||||
| Outstanding at beginning of year | 2,618 | $ | 4.36 | 2,643 | $ | 4.31 | 1,995 | $ | 4.05 | ||||||||||
| Granted | 10 | 5.00 | 176 | 5.00 | 725 | 5.00 | |||||||||||||
| Exercised | -- | -- | -- | -- | -- | -- | |||||||||||||
| Canceled | (99 | ) | 4.75 | (201 | ) | 4.20 | (77 | ) | 4.09 | ||||||||||
| Outstanding at end of year | 2,529 | $ | 4.35 | 2,618 | $ | 4.36 | 2,643 | $ | 4.31 | ||||||||||
| Options exercisable at year end | 2,056 | $ | 4.20 | 1,837 | $ | 4.12 | 802 | $ | 4.02 | ||||||||||
Weighted average fair value of options granted during the year | $2.41 | $2.41 | $2.23 | ||||||||||||||||
| 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 | ||
2004:
Shares Outstanding (in thousands) | Weighted Average Contractual Life (in years) | Weighted Average Exercise Price | ||||
| Exercise Prices | ||||||
| $4.00 | 1,641 | 6.10 | $ 4.00 | |||
| $5.00 | 888 | 7.47 | 5.00 | |||
| 2,529 | 6.59 | $ 4.35 | ||||
OTHER PLANS In addition to current stock compensation plans, the Company also has outstandingand 43,033 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 executivesrespectively.
| 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% | |
2002:
| 2004 | 2003 | 2002 | ||||||||
| 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 | 2.8 | % | 2.8 | % | 4.05 | % | ||||
Expected lives- years | 4.0 | 4.0 | 4.0 | |||||||
| Expected stock volatility | 70.0 | % | 70.0 | % | 70.0 | % | ||||
| Performance awards | ||||||||||
| Risk-free interest rate | 2.59 | % | 2.35 | % | 4.0 | % | ||||
Expected lives- years | 3.0 | 4.0 | 4.0 | |||||||
| Expected stock volatility | 22.24 | % | 23.85 | % | 23.71 | % | ||||
| Dividend yield | 4.45 | % | 4.86 | % | 8.85 | % | ||||
| Employee Stock Purchase Plan | ||||||||||
| Risk-free interest rate | 1.28 | % | 1.07 | % | 1.65 | % | ||||
| Expected lives - years | 0.5 | 0.5 | 0.5 | |||||||
| Expected stock volatility | 9.89 | % | 19.47 | % | 26.97 | % | ||||
| Dividend yield | 4.42 | % | 4.39 | % | 5.81 | % | ||||
The Company has adopted
There was no impact on earnings for the 12 months ended December 31, 2004 and 2003.
| (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 |
tax expense.
| (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 |
There were no acquisitions in 2004.
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) FOR THE YEARS ENDED DECEMBER 31 | 2003 | 2002 | |||||
| Operating revenues | $ | 2,396,802 | $ | 2,391,981 | |||
| Net income | 116,636 | 112,813 | |||||
| Basic earnings per common share | $ | 1.23 | $ | 1.28 | |||
| Diluted earnings per common share | $ | 1.22 | $ | 1.27 | |||
- assigned $0.1 million to patents with an amortization period of 17 years, $1.7 million to contractual customer relationships with an amortization period of 10 years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is 9.6 years.
AT DECEMBER 31, 2004 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amortization | Net Intangibles | |||||||
| Covenant not to compete | $ | 4,178 | $ | 2,748 | $ | 1,430 | ||||
| Developed technology | 14,190 | 3,163 | 11,027 | |||||||
| Contractual customer relationships | 4,702 | 1,374 | 3,328 | |||||||
| Patents | 986 | 91 | 895 | |||||||
| Total | $ | 24,056 | $ | 7,376 | $ | 16,680 | ||||
AT DECEMBER 31, 2003 (DOLLARS IN THOUSANDS) | Gross Intangibles | Accumulated Amortization | Net Intangibles | |||||||
| Covenant not to compete | $ | 4,178 | $ | 2,009 | $ | 2,169 | ||||
| Developed technology | 14,190 | 2,454 | 11,736 | |||||||
| Contractual customer relationships | 4,702 | 747 | 3,955 | |||||||
| Patents | 915 | 68 | 847 | |||||||
| Total | $ | 23,985 | $ | 5,278 | $ | 18,707 | ||||
| (Dollars in Thousands) | 2005 | 2006 | 2007 | 2008 | 2009 |
| Future intangible amortization | $ 2,207 | $1,732 | $1,385 | $1,301 | $1,276 |
(DOLLARS IN MILLIONS) QUARTER ENDING | 7/02 - 6/03 PCA 1 (ordered/final | ) | 7/03 - 6/04 PCA 2 (estimated | ) | 7/04 - 12/04 PCA 3 (estimated | ) | Total | ||||||
| June 30, 2004 | $ | 25.6 | $ | 12.2 | $ | -- | $ | 37.8 | |||||
| September 30, 2004 | -- | -- | 2.8 | 2.8 | |||||||||
| December 31, 2004 | -- | -- | 2.8 | 2.8 | |||||||||
| Total | $ | 25.6 | $ | 12.2 | $ | 5.6 | $ | 43.4 |
| 1. | The Washington Commission will determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
| 2. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs. |
| 3. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
| a) | actual Tenaska costs that exceed the benchmark or; |
| b) | the return on the Tenaska regulatory asset. |
| 4. | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs. |
PUGET ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Taxes other than income taxes: | ||||||||||
| Real estate and personal property | $ | 45,121 | $ | 45,660 | $ | 48,890 | ||||
| State business | 82,408 | 75,523 | 77,527 | |||||||
| Municipal and occupational | 72,405 | 64,861 | 67,770 | |||||||
| Other | 39,479 | 38,273 | 37,029 | |||||||
| Total taxes other than income taxes | $ | 239,413 | $ | 224,317 | $ | 231,216 | ||||
| Charged to: | ||||||||||
| Operating expense | $ | 221,980 | $ | 208,395 | $ | 215,429 | ||||
| Other accounts, including construction work in progress | 17,433 | 15,922 | 15,787 | |||||||
| Total taxes other than income taxes | $ | 239,413 | $ | 224,317 | $ | 231,216 | ||||
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | 2004 | 2003 | 2002 | |||||||
| Taxes other than income taxes: | ||||||||||
| Real estate and personal property | $ | 43,843 | $ | 44,757 | $ | 48,408 | ||||
| State business | 82,408 | 75,524 | 77,527 | |||||||
| Municipal and occupational | 72,405 | 64,861 | 67,770 | |||||||
| Other | 27,766 | 25,638 | 24,463 | |||||||
| Total taxes other than income taxes | $ | 226,422 | $ | 210,780 | $ | 218,168 | ||||
| Charged to: | ||||||||||
| Operating expense | $ | 208,989 | $ | 194,857 | $ | 202,381 | ||||
| Other accounts, including construction work in progress | 17,433 | 15,923 | 15,787 | |||||||
| Total taxes other than income taxes | $ | 226,422 | $ | 210,780 | $ | 218,168 | ||||
COMMITMENTS – ELECTRIC
| 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.
| (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 |
TOTAL BONDS | COMPANY'S ANNUAL AMOUNT | |||||||||||
| OUTSTANDING | PURCHASABLE (APPROXIMATE) | |||||||||||
| CONTRACT | LICENSE 1 | 12/31/042 | % OF | MEGAWATT | COST3 | |||||||
| PROJECT | EXP. DATE | EXP. DATE | (MILLIONS) | OUTPUT | CAPACITY | (MILLIONS) | ||||||
| Rock Island | ||||||||||||
| Original units | 2012 | 2029 | $ 115.8 | 50.0 | } | 414 | $ 40.8 | |||||
| Additional units | 2012 | 2029 | 328.4 | 75.0 | ||||||||
| Rocky Reach | 2011 | 2006 | 383.0 | 38.9 | 505 | 24.7 | ||||||
| Wells | 2018 | 2012 | 143.3 | 31.3 | 261 | 5.2 | ||||||
Priest Rapids4 | 2005 | 2005 | 179.7 | 8.0 | 72 | 2.4 | ||||||
Wanapum4 | 2009 | 2005 | 181.6 | 10.8 | 98 | 3.3 | ||||||
| Total | $ 1,331.8 | 1,350 | $ 76.4 | |||||||||
| 1 | The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees.FERC has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirmthe |
| 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: |
| 3 | The components of |
| 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 |
(DOLLARS IN MILLIONS) | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 & THERE- AFTER | TOTAL | |||||||||||||||
| Columbia River Projects | $ | 79.9 | $ | 80.1 | $ | 83.2 | $ | 86.9 | $ | 89.7 | $ | 54.6 | $ | 474.4 | ||||||||
| Other utilities | 79.3 | 81.5 | 82.9 | 83.7 | 83.5 | 349.6 | 760.5 | |||||||||||||||
| Non-utility generators | 210.2 | 215.4 | 205.3 | 205.3 | 207.1 | 527.4 | 1,570.7 | |||||||||||||||
| Total | $ | 369.4 | $ | 377.0 | $ | 371.4 | $ | 375.9 | $ | 380.3 | $ | 931.6 | $ | 2,805.6 | ||||||||
| 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 | ||||||||||
2004:
| COMPANY'S SHARE | ||||||
(DOLLARS IN MILLIONS) | ENERGY SOURCE (FUEL) | COMPANY'S OWNERSHIP SHARE | PLANT IN SERVICE AT COST | ACCUMULATED DEPRECIATION | ||
| Colstrip Units 1 & 2 | Coal | 50% | $ 207 | $ 134 | ||
| Colstrip Units 3 & 4 | Coal | 25% | 469 | 250 | ||
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 6.5ranging from less than 1 year to 3.5 years. The obligations under these contracts are $15.9 million in 2004, $16.7$14.1 million in 2005, $17.5$2.2 million in 2006, $18.4$2.5 million in 2007 and $12.9$1.4 million in the aggregate thereafter.
| 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 |
DEMAND CHARGE OBLIGATIONS (DOLLARS IN MILLIONS) | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 & THERE- AFTER | TOTAL |
| Firm gas supply | $ 1.8 | $ 1.2 | $ 1.0 | $ 0.8 | $ 0.5 | $ 1.0 | $ 6.3 |
| Firm transportation service | 69.6 | 68.8 | 65.0 | 55.6 | 110.2 | 117.2 | 486.4 |
| Firm storage service | 11.5 | 10.5 | 7.7 | 7.7 | 7.7 | 40.2 | 85.3 |
| Total | $ 82.9 | $ 80.5 | $ 73.7 | $ 64.1 | $ 118.4 | $ 158.4 | $ 578.0 |
2004.
flow.
flow.
Financial data for
| (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.is the result of the Company’s need to invest in the core utility business to acquire or construct energy generating resources and energy delivery infrastructure. During 2005, Puget Energy intends to monetize its interest in InfrastruX through sale or third party recapitalization and invest the proceeds in PSE.
| 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 |
2004 (DOLLARS IN THOUSANDS) | REGULATED UTILITY | INFRASTRUX | OTHER | RECONCILING ITEM | PUGET ENERGY TOTAL |
| Revenues | $ 2,192,340 | $ 369,936 | $ 6,537 | -- | $ 2,568,813 |
| Depreciation and amortization | 228,310 | 18,276 | 256 | -- | 246,842 |
| Goodwill impairment | -- | 91,196 | -- | -- | 91,196 |
| Income tax | 75,755 | (1,793) | 1,002 | -- | 74,964 |
| Operating income (loss) | 285,258 | (70,928) | 2,421 | -- | 216,751 |
| Interest charges, net of AFUDC | 166,411 | 6,460 | 219 | -- | 173,090 |
| Net income (loss) | 123,401 | (70,388) | 2,009 | -- | 55,022 |
| Goodwill, net | -- | 43,503 | -- | -- | 43,503 |
| Total assets | 5,511,631 | 251,097 | 70,641 | -- | 5,833,369 |
| Construction expenditures - excluding equity AFUDC | 393,891 | -- | -- | -- | 393,891 |
| Additions to other property, plant and equipment | -- | 15,512 | -- | -- | 15,512 |
2003 (DOLLARS IN THOUSANDS) | REGULATED UTILITY | INFRASTRUX | OTHER | RECONCILING ITEM2 | PUGET ENERGY TOTAL |
Revenues1 | $ 2,034,973 | $ 341,787 | $ 6,043 | -- | $ 2,382,803 |
| Depreciation and amortization | 219,851 | 16,779 | 236 | -- | 236,866 |
| Income tax | 69,823 | 1,594 | 952 | -- | 72,369 |
| Operating income | 295,219 | 7,452 | 2,504 | -- | 305,175 |
| Interest charges, net of AFUDC | 179,437 | 5,485 | 123 | -- | 185,045 |
| Net income | 119,144 | 1,766 | 438 | (5,151) | 116,197 |
| Goodwill, net | -- | 133,302 | -- | -- | 133,302 |
| Total assets | 5,281,474 | 342,332 | 75,196 | -- | 5,699,002 |
| Construction expenditures - excluding equity AFUDC | 269,973 | -- | -- | -- | 269,973 |
| Additions to other property, plant and equipment | -- | 15,536 | -- | -- | 15,536 |
2002 (DOLLARS IN THOUSANDS) | REGULATED UTILITY | INFRASTRUX | OTHER | RECONCILING ITEM2 | PUGET ENERGY TOTAL |
Revenues1 | $ 1,985,899 | $ 319,529 | $ 9,753 | -- | $ 2,315,181 |
| Depreciation and amortization | 215,097 | 13,426 | 220 | -- | 228,743 |
| Income tax | 49,733 | 6,703 | 2,824 | -- | 59,260 |
| Operating income | 289,511 | 15,595 | 4,563 | -- | 309,669 |
| Interest charges, net of AFUDC | 190,861 | 5,516 | -- | -- | 196,377 |
| Net income | 104,044 | 9,455 | 4,384 | (7,831) | 110,052 |
| Goodwill, net | -- | 125,555 | -- | -- | 125,555 |
| Total assets | 5,323,129 | 319,248 | 129,756 | -- | 5,772,133 |
| Construction expenditures - excluding equity AFUDC | 224,165 | -- | -- | -- | 224,165 |
| Additions to other property, plant and equipment | -- | 11,621 | -- | -- | 11,621 |
| 1 | Revenues for the Regulated Utility segment were reduced $108.7 million and $77.1 million in 2003 and 2002, respectively as a result of a reclassification from implementing EITF No. 03-11 on January 1, 2004. The reclassification had no effect on financial position or results of operations. |
| 2 | Reconciling item is preferred stock dividend accrual at PSE that is treated as an other deduction at Puget Energy. |
| 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 |
| (Unaudited; dollars in thousands except per share amounts) | |||||||||||||
| 2004 QUARTER | FIRST | SECOND1 | THIRD | FOURTH2 | |||||||||
| Operating revenues | $ | 743,470 | $ | 515,939 | $ | 514,951 | $ | 794,452 | |||||
| Operating income | 109,680 | 35,216 | 53,825 | 18,031 | |||||||||
| Other income | 64 | 1,586 | 318 | 2,324 | |||||||||
| Net income (loss) | 66,365 | (6,780 | ) | 11,124 | (15,687 | ) | |||||||
| Basic earnings per common share | $ | 0.67 | $ | (0.07 | ) | $ | 0.11 | $ | (0.16 | ) | |||
| Diluted earnings per common share | $ | 0.67 | $ | (0.07 | ) | $ | 0.11 | $ | (0.16 | ) | |||
| (Unaudited; dollars in thousands except per share amounts) | |||||||||||||
| 2003 QUARTER | FIRST | SECOND | THIRD | FOURTH | |||||||||
Operating revenues3 | $ | 640,637 | $ | 524,060 | $ | 490,258 | $ | 727,849 | |||||
| Operating income | 91,385 | 66,407 | 54,389 | 92,994 | |||||||||
| Other income | 704 | 2,247 | 2,663 | (4,050 | ) | ||||||||
| Net income before cumulative effect of accounting change | 42,889 | 20,598 | 9,885 | 42,993 | |||||||||
| Net income | 42,720 | 20,598 | 9,885 | 42,993 | |||||||||
| Basic earnings per common share | $ | 0.46 | $ | 0.22 | $ | 0.10 | $ | 0.44 | |||||
| Diluted earnings per common share | $ | 0.45 | $ | 0.22 | $ | 0.10 | $ | 0.44 | |||||
| (Unaudited; dollars in thousands except per share amounts) | |||||||||||||
| 2002 QUARTER | FIRST | SECOND | THIRD | FOURTH | |||||||||
Operating revenues3 | $ | 720,997 | $ | 529,803 | $ | 442,577 | $ | 621,804 | |||||
| Operating income | 76,571 | 76,833 | 57,098 | 99,168 | |||||||||
| Other income | 384 | 3,441 | 230 | 1,403 | |||||||||
| Net income | 24,466 | 29,429 | 6,572 | 49,585 | |||||||||
| Basic and diluted earnings per common share | $ | 0.28 | $ | 0.34 | $ | 0.07 | $ | 0.55 | |||||
| 1 | The second quarter 2004 includes a disallowance of $36.5 million or $23.7 million after-tax related to a Washington Commission order stating PSE did not prudently manage gas costs for the Tenaska generating facility. |
| 2 | The fourth quarter 2004 includes a non-cash goodwill impairment charge of $91.2 million or $76.6 million after-tax and minority interest related to goodwill at InfrastruX. |
| 3 | Operating revenues in 2003 and 2002 were revised as a result of a reclassification due to Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gaines and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03,” which became effective on January 1, 2004. First, second, third and fourth quarter 2003 revenues were reduced by $35.3 million, $33.8 million, $25.3 million and $14.3 million, respectively. First, second, third and fourth quarter 2002 revenues were reduced by $18.1 million, $11.0 million, $15.9 million and $32.1 million, respectively. The impact of EITF No. 03-11 had no effect on financial position or results of operations. |
| (Unaudited; dollars in thousands) | |||||||||||||
| 2004 QUARTER | FIRST | SECOND1 | THIRD | FOURTH | |||||||||
| Operating revenues | $ | 668,714 | $ | 423,123 | $ | 415,026 | $ | 692,012 | |||||
| Operating income | 108,845 | 30,704 | 50,363 | 98,330 | |||||||||
| Other income | 68 | 1,570 | 356 | 2,368 | |||||||||
| Net income (loss) | 66,898 | (9,540 | ) | 9,647 | 59,187 | ||||||||
| (Unaudited; dollars in thousands) | |||||||||||||
| 2003 QUARTER | FIRST | SECOND | THIRD | FOURTH | |||||||||
Operating revenues2 | $ | 569,960 | $ | 431,717 | $ | 397,116 | $ | 642,224 | |||||
| Operating income | 93,935 | 62,120 | 51,046 | 90,803 | |||||||||
| Other income | 691 | 2,309 | 2,620 | (4,033 | ) | ||||||||
| Net income before cumulative effect of accounting change | 48,270 | 19,614 | 9,488 | 42,683 | |||||||||
| Net income | 48,101 | 19,614 | 9,488 | 42,683 | |||||||||
| (Unaudited; dollars in thousands) | |||||||||||||
| 2002 QUARTER | FIRST | SECOND | THIRD | FOURTH | |||||||||
Operatingrevenues2 | $ | 660,236 | $ | 453,681 | $ | 350,204 | $ | 531,531 | |||||
| Operating income | 74,732 | 72,724 | 51,367 | 95,769 | |||||||||
| Other income | 309 | 3,455 | 210 | 1,241 | |||||||||
| Net income | 25,698 | 28,839 | 4,701 | 49,709 | |||||||||
| 1 | The second quarter 2004 includes a disallowance of $36.5 million or $23.7 million after-tax related to a Washington Commission order stating PSE did not prudently manage gas costs for the Tenaska generating facility. |
| 2 | Operating revenues in 2003 and 2002 were revised as a result of a reclassification due to Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gaines and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03,” which became effective on January 1, 2004. First, second, third and fourth quarter 2003 revenues were reduced by $35.3 million, $33.8 million, $25.3 million and $14.3 million, respectively. First, second, third and fourth quarter 2002 revenues were reduced by $18.1 million, $11.0 million, $15.9 million and $32.1 million, respectively. The impact of EITF No. 03-11 had no effect on financial position or results of operations. |
| (DOLLARS IN THOUSANDS) | 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 | ||||||
| Reserve on wholesale sales | 41,488 | �� | -- | -- | 41,488 | |||||||||
| Industrial accident reserve | -- | 4,000 | 2,000 | 2,000 | ||||||||||
| Gas transportation contracts reserve | 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 | $ | 1,990 | ||||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | ||||||||||
| Industrial accident reserve | -- | 4,000 | 2,000 | 2,000 | ||||||||||
| Gas transportation contracts reserve | 139 | -- | -- | 139 | ||||||||||
| 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 (DOLLARS IN THOUSANDS) | BALANCE AT BEGINNING OF PERIOD | ADDITIONS CHARGED TO COSTS AND EXPENSES | DEDUCTIONS | BALANCE AT END OF PERIOD | |||||||||
| YEAR ENDED DECEMBER 31, 2004 | |||||||||||||
| Accounts deducted from assets on balance sheet: | |||||||||||||
| Allowance for doubtful accounts receivable | $ | 4,359 | $ | 7,668 | $ | 7,507 | $ | 4,520 | |||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | |||||||||
| Deferred tax asset valuation allowance | -- | 17,988 | -- | 17,988 | |||||||||
| Tenaska disallowance reserve | -- | 36,490 | 33,334 | 3,156 | |||||||||
| YEAR ENDED DECEMBER 31, 2003 | |||||||||||||
| 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 | |||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | |||||||||
| Industrial accident reserve | -- | 4,000 | 2,000 | 2,000 | |||||||||
| Gas transportation contracts reserve | 139 | -- | -- | 139 | |||||||||
PUGET SOUND ENERGY (DOLLARS IN THOUSANDS) | BALANCE AT BEGINNING OF PERIOD | ADDITIONS CHARGED TO COSTS AND EXPENSES | DEDUCTIONS | BALANCE AT END OF PERIOD | |||||||||
| Year Ended December 31, 2004 | |||||||||||||
| Accounts deducted from assets on balance sheet: | |||||||||||||
| Allowance for doubtful accounts receivable | $ | 2,484 | $ | 7,343 | $ | 7,157 | $ | 2,670 | |||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | |||||||||
| Tenaska disallowance reserve | -- | 36,490 | 33,334 | 3,156 | |||||||||
| YEAR ENDED DECEMBER 31, 2003 | |||||||||||||
| Accounts deducted from assets on balance sheet: | |||||||||||||
| Allowance for doubtful accounts receivable | $ | 1,990 | $ | 9,385 | $ | 8,891 | $ | 2,484 | |||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | |||||||||
| Industrial accident reserve | 2,000 | -- | 2,000 | -- | |||||||||
| Gas transportation contracts reserve | 139 | -- | 139 | -- | |||||||||
| YEAR ENDED DECEMBER 31, 2002 | |||||||||||||
| Accounts deducted from assets on balance sheet: | |||||||||||||
| Allowance for doubtful accounts receivable | $ | 3,666 | $ | 11,140 | $ | 12,816 | $ | 1,990 | |||||
| Reserve on wholesale sales | 41,488 | -- | -- | 41,488 | |||||||||
| Industrial accident reserve | -- | 4,000 | 2,000 | 2,000 | |||||||||
| Gas transportation contracts reserve | 139 | -- | -- | 139 | |||||||||
| CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
| CONTROLS AND PROCEDURES |
| CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS |
| PRINCIPAL ACCOUNTANT FEES AND SERVICES |
| 2004 | 2003 | ||||||||||||
(DOLLARS IN THOUSANDS) | PUGET ENERGY | PSE | PUGET ENERGY | PSE | |||||||||
Audit fees1 | $ | 2,084 | $ | 1,695 | $ | 850 | $ | 453 | |||||
Audit related fees2 | 82 | 82 | 261 | 147 | |||||||||
Tax fees3 | 59 | 55 | 200 | 168 | |||||||||
| Total | $ | 2,225 | $ | 1,832 | $ | 1,311 | $ | 768 | |||||
| 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 2004 fees are estimated and include an aggregate amount of $1,251,000 and $1,156,000 billed to Puget Energy and PSE, respectively through December 31, 2004. The 2003 fees include an aggregate amount of approximately $444,000 and $277,000 billed to Puget Energy and PSE, respectively, through December 31, 2003. In 2004, audit fees included $1,284,000 and $1,120,000 for professional services rendered for the audits of Puget Energy’s and PSE’s assessment of, and the effectiveness of, internal controls over financial reporting (Sarbanes-Oxley 404). |
| 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. |
| EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| a) | Documents filed as part of this report: |
| 1) | Financial Statements. See index on page 66. |
| 2) | Financial Statement Schedules. Financial Statement Schedules of the Company located on page 123, as required for the years ended December 31, 2004, 2003 and 2002, consist of the following: |
| II. | Valuation of Qualifying Accounts |
| 3) | Exhibits - see index on page 129. |
PUGET ENERGY, INC. | PUGET SOUND ENERGY | |
| /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 1, 2005 | Date: March 1, 2005 |
| SIGNATURE | TITLE | DATE |
| (Puget Energy and PSE unless otherwise noted) | ||
| /s/ Douglas P. Beighle | Chairman of the Board | March 1, 2005 |
| (Douglas P. Beighle) | ||
| /s/ Stephen P. Reynolds | President, Chief Executive Officer and | |
| (Stephen P. Reynolds) | Director | |
| /s/ Bertrand A. Valdman | Senior Vice President Finance and | |
| (Bertrand A. Valdman) | Chief Financial Officer | |
| /s/ James W. Eldredge | Corporate Secretary and Chief | |
| (James W. Eldredge) | Accounting Officer | |
| /s/ William S. Ayer | Director | |
| (William S. Ayer) | ||
| /s/ Charles W. Bingham | Director | |
| (Charles W. Bingham) | ||
| /s/ Phyllis J. Campbell | Director | |
| (Phyllis J. Campbell) | ||
| /s/ Craig W. Cole | Director | |
| (Craig W. Cole) | ||
| /s/ Robert L. Dryden | Director | |
| (Robert L. Dryden) | ||
| /s/ Stephen E. Frank | Director | |
| (Stephen E. Frank) | ||
| /s/ Tomio Moriguchi | Director | |
| (Tomio Moriguchi) | ||
| /s/ Dr. Kenneth P. Mortimer | Director | |
| (Dr. Kenneth P. Mortimer) | ||
| /s/ Sally G. Narodick | Director | |
| (Sally G. Narodick) | ||
| 3(i).1 | Restated Articles of Incorporation of Puget Energy (Incorporated by reference to Exhibit 99.2, Puget |
| 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, |
| 3(ii).2 | Amended and Restated Bylaws of PSE dated March 7, |
| 4.1 | Fortieth through Seventy-ninth Supplemental Indentures defining the rights of the holders of |
| 4.2 | Indenture defining the rights of the holders of |
| 4.3 | First Supplemental Indenture defining the rights of the holders of |
| 4.4 | Second Supplemental Indenture defining the rights of the holders of |
| 4.5 | Third Supplemental Indenture defining the rights of the holders of |
| 4.6 | Fourth Supplemental Indenture defining the rights of the holders of |
| 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 |
| 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 |
| 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 |
| 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 |
| 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 |
| 4.21 | Thirty-first Supplemental Indenture dated February 10, |
| 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 |
| 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 |
| 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 |
| 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 |
| 4.26 | Pledge Agreement dated March 11, 2003 between Puget Sound Energy and Wells Fargo Bank Northwest, National Association, as Trustee (incorporated herein by reference to Exhibit 4.24 to the |
| 4.27 | Loan Agreement dated as of March 1, 2003, between the City of Forsyth, Rosebud County, Montana and Puget Sound Energy (incorporated herein by reference to Exhibit 4.25 to the |
| * | 4.28 | Eightieth Supplemental Indenture dated as of April 30, 2004 defining the rights of the holders of PSE’s First Mortgage Bonds. |
| 10.1 | First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 13-d to Registration No. 2-24252). |
| 10.2 | First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-p to Registration No. 2-24252). |
| 10.3 |
| Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 4-1-a to Registration No. 2-13979). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| Contract dated June 19, 1974 between PSE and P.U.D. No. 1 of Chelan County (Exhibit D to Form 8-K dated July 5, 1974). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| Power Sales Agreement between Northwestern Resources |
| Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among The Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| 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). |
| Puget Energy, Inc. Non-employee Director Stock Plan. (incorporated herein by reference to Exhibit 99.1 to Puget |
| ** | Amendment No. 1 to the Puget Energy, Inc. Non-employee Director Stock Plan, effective as of January 1, |
| ** | Puget Energy, Inc. Employee Stock Purchase Plan. |
| ** | 1995 Long-Term Incentive Compensation Plan. (Exhibit 10.108 to Annual Report on Form 10-K for the fiscal year ended December 31, 2000, Commission File No. 1-4393 and 1-16305). |
| ** | 1995 Long-Term Incentive Compensation Plan |
| ** | Employment agreement with S. P. Reynolds, Chief Executive Officer and President dated January 7, |
| Credit Agreement dated |
| 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). |
| 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). |
| 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 No. 1-16305 and 1-4393). |
| Credit Agreement dated |
| Receivable Purchase Agreement dated December 23, 2002, among PSE, Rainier Receivables, Inc., and Bank One, NA as |
| Receivable Sale Agreement dated December 23, 2002, among PSE and Rainier Receivables, Inc. |
| ** | Employment agreement with J.M. Ryan, Vice President Energy Portfolio Management, dated November 30, |
| ** | Change-in-Control Agreement with J.M. Ryan, Vice President, Energy Portfolio Management, dated November 30, |
| ** | Change-in-Control Agreement with B. A. Valdman, Senior Vice President, Finance and Chief Financial Officer, dated November 28, |
| ** | Change-in-Control Agreement with S. McLain, Senior Vice President, Operations, dated March 12, 1999. (Exhibit 10.87 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-16305 and 1-4393). |
| ** |
| * |
| * | Restricted Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, |
| ** | Restricted Stock Unit Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, 2004 (Exhibit 10.91 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2003, Commission File No. 1-16305 and 1-4393). | |
| ** | 10.50 | Restricted Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, 2002 (Exhibit 99.1 to Form S-8 Registration Statement, dated January 8, 2002, Commission File No. 333-76424). |
| ** | 10.51 | Nonregulated Stock Option Grant Notice/Agreement with S. P. Reynolds, Chief Executive Officer and President dated March 11, 2002 (Exhibit 99.1 and Exhibit 99.2 to Form S-8 Registration Statement dated March 18, 2002, Commission File No. 333-84426). |
| * | 10.52 | Change-in-Control Agreement with E. M. Markell, Vice President Corporate Development, dated May 7, 2003. |
| * | 10.53 | InfrastruX 2000 Stock Incentive Plan adopted January 26, 2001. |
| * | 10.54 | InfrastruX 2000 Stock Incentive Plan Stock Option Grant Notice adopted January 26, 2001. |
| * | 10.55 | Puget Sound Energy Amended and Restated Supplemental Executive Retirement Plan for Senior Management dated October 5, 2004. |
| * | 10.56 | Puget Sound Energy Amended and Restated Deferred Compensation Plan for Key Employees dated January 1, 2003. |
| * | 10.57 | Puget Sound Energy Amended and Restated Deferred Compensation Plan for Nonemployee Directors dated October 1, 2000. |
| ** | 10.58 | Summary of Director Compensation (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K, filed February 2, 2005, Commission File Nos. 1-4393 and 1-16305). |
| * | 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 |
| * | 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 |
| * | 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 |
| * | 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 |
| * | 32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley |
| * | 32.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley |
*Filed