The pro forma asset retirement obligation liability balances as if SFAS No. 143 had been adopted on January 1, 1999 (rather than January 1, 2003) are as follows:
The pro forma income statement effect as if SFAS No. 143 had been adopted on January 1, 1999 (rather than January 1, 2003) is as follows:
The Company has various stock compensation plans which, as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation”, are accounted for in accordance with APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The exercise price of stock option grants outstanding was the market value of the stock on the date of grant, so no compensation expense was recorded in the income statement for the options. There was, however, compensation expense related to other stock compensation plans. Had the Company used the fair value method of accounting specified by SFAS No. 123 net income and earnings per share would have been as follows:
| | Three Months Ended
September 30
| Nine Months Ended
September 30
|
(Dollar in thousands, except per share)
| 2003
| 2002
| 2003
| 2002
|
| Income for common stock, as reported | | | $ | 9,885 | | $ | 6,572 | | $ | 73,204 | | $ | 60,467 | |
| Add: Total stock-based employee compensation expense | | | | 421 | | | 2,642 | | | 2,931 | | | 2,923 | |
| included in net income, net of tax | | |
| Less: Total stock-based employee compensation expense per | | | | (680 | ) | | (778 | ) | | (2,571 | ) | | (2,159 | ) |
| the fair value method of SFAS 123, net of tax | | |
|
| Pro forma income for common stock | | | $ | 9,626 | | $ | 8,436 | | $ | 73,564 | | $ | 61,231 | |
|
| Earnings per share: | | |
| Basic as reported | | | $ | 0.10 | | $ | 0.07 | | $ | 0.78 | | $ | 0.69 | |
| Diluted as reported | | | $ | 0.10 | | $ | 0.07 | | $ | 0.77 | | $ | 0.69 | |
| Basic pro forma | | | $ | 0.10 | | $ | 0.10 | | $ | 0.78 | | $ | 0.70 | |
| Diluted pro forma | | | $ | 0.10 | | $ | 0.10 | | $ | 0.78 | | $ | 0.70 | |
| (8) | New Accounting Pronouncements |
In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46 – “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51 – “Consolidated Financial Statements” to certain entities in which equity investors do not have controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. This Interpretation requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements must be included in the consolidated financial statements of the business entity. The adoption of this Interpretation for all interests in variable interest entities created after January 31, 2003 was effective on that date. For variable interest entities created before February 1, 2003, it is effective with the first fiscal year or interim period beginning after December 15, 2003 as amended by the FASB in September 2003. The Company has evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance. This transaction was consolidated in the third quarter of 2003. As a result, revenues increased $3.9 million while conservation amortization and interest expense increased by the corresponding amount with no impact on earnings. At September 30, 2003, the balance sheet assets and liabilities have been increased by $8.0 million.
In May 2003, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 150 – “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. SFAS 150 establishes the requirements for classifying and measuring as liabilities certain financial instruments that embody obligations to redeem the financial instrument by the issuer. The adoption of SFAS 150 is effective with the first fiscal year or interim period beginning after June 15, 2003, however, on November 5, 2003 FASB deferred for an indefinite period certain mandatorily redeemable noncontrolling interests associated with finite-lived subsidiaries. The Comapny does not have any noncontrolling interests in subsidiaries and is therefore, not affected by the deferral. Prior periods will not be restated for the new presentation.
SFAS 150 requires the Company to classify its mandatorily redeemable preferred stock and the corporation obligated, mandatorily redeemable preferred securities of a subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities) 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. The Company previously classified the dividends associated with the trust preferred securities as interest expense.
Effective April 10, 2003 and October 1, 2003, the Washington Commission approved increases in the Purchased Gas Adjustment (PGA) gas rates of approximately $103.6 million annually, or 20.1%, and $78.8 million annually, or 13.3%, respectively. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in gas prices. PSE’s gas margin and net income are not affected by the changes in the PGA rates.
PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $10.1 million at September 30, 2003, recorded at the Company’s original cost. The managing members of the limited liability corporations have sole discretion over fund management and investment decisions of both funds. Although the Company is not aware of any significant matters that would impair the long-term value of its investments, the Emerging Issues Task Force of the Financial Accounting Standards Board is currently reviewing the definition of what constitutes an other-than temporary impairment and its application to certain investments recorded at cost. Under the terms of the limited liability corporation agreements establishing the funds, one fund will continue through December 31, 2003 and the other through December 31, 2007. The Company’s original cost in the fund that will terminate on December 31, 2003, was $2.1 million at September 30, 2003, or approximately the amount the Company believes it will receive in distributions from the fund in the fourth quarter of 2003. The book value of the Company’s members capital account in the second fund as reported by the fund manager is below the Company’s recorded original cost of the investment. The Company’s original cost in the second fund was $8.0 million at September 30, 2003 and the Company has a future funding obligation of $0.6 million. The fund manager continues to report that the Company’s original cost is within the projected range of the future anticipated fund value.
PSE and Western Energy Company, the supplier of coal to PSE’s Colstrip power plants, are engaged in a dispute and binding arbitration process concerning the price of coal that PSE will pay under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The parties are over $1 per ton apart on their view as to the proper price for coal under that contract, and the arbitration would resolve that question in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. A $1 per ton increase or decrease in the price of coal would have a corresponding effect on PSE’s power costs of approximately $1.4 million annually and if the price were retroactive to July 30, 2001, the corresponding effect on power costs would be $3.2 million. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s power cost adjustment mechanism.
In October 2003, PSE received notice from Western Energy Company that the Montana Department of Revenue is alleging underpayment of royalties on coal purchased by PSE from Western Energy Company from 1997 to 2000. PSE used the coal as fuel for its Colstrip Units 3 & 4 generating plants. The dispute is likely to lead to a more formal process or litigation to review those purchases and to determine whether PSE may owe more royalties, taxes or penalties. The Montana Department of Revenue seeks a payment of approximately $1.1 million plus applicable Montana State taxes on such payments. PSE will defend this claim vigorously. PSE cannot predict the outcome of this issue at this early date.
On October 24, 2003, PSE filed a power cost only rate case for an increase in its electric rates related to higher power costs and the proposed investment in a 275 MW power generating plant. PSE intends to acquire a 49.85% interest in the power generating plant. The acquisition and power cost only rate case is subject to regulatory approval from the Washington Commission. The proposed rate increase of 4.7% or $64.4 million annually, if approved, would go into effect in April 2004 after a five month regulatory review.
In 2003 the Colville Confederated Tribes presented a claim to Douglas County PUD based upon allegedly due past annual charges for the Wells Hydroelectric Project for the use of Colville tribal lands. The Tribes claimed that annual charges would also be due for periods into the future. Since April of 2003, Douglas County PUD and Colville representatives have discussed settlement of this issue. PSE purchases 31.3% of the power generated by the Wells Project. A settlement of this claim could affect the amount of energy PSE receives under the terms of PSE’s purchased electricity contract or the price of the output of the Wells Hydroelectric Project purchased by PSE.
The White River Hydroelectric Generation Project (the Project) was built in 1911 by PSE and has been in continuous operation ever since. The Project generates electricity to serve PSE’s retail electric customers with an annual average output of approximately 35 megawatts. In 1983, the Company applied for an original FERC License for this Project. In December of 1997, FERC issued a proposed license that was appealed by the Company and various natural resource agencies. The Company appealed the license because it contained terms and conditions that would render ongoing operations of the Project uneconomic relative to alternative resources. In 1998, 2001 and in 2003 FERC granted a stay of the license order (and related appeals) to afford interested parties the opportunity for settlement negotiations. This stay expires in January of 2004. If settlement has not been reached by the end of the stay, in order to keep the Project in operation the Company would likely be required to implement the license order pending FERC’s disposition of the Company’s appeal. Implementation of the license order would require the Company to make capital expenditures and incur annual operating costs that would make the Project uneconomic. The Company has concluded that it is unlikely that a settlement addressing the deficiencies of the 1997 FERC license will be reached before the stay expires, and anticipates advising FERC in January that it intends to withdraw its license application and retire the Project. To this end, the Company is negotiating with a consortium of municipalities interested in acquiring the Project as a source for a municipal water supply. The Company is also discussing an interim “non-power” operations agreement with the U.S. Army Corps of Engineers. This interim agreement would address the Corps’ interest in keeping the Project’s diversion dam in operation and thereby facilitate the Corps’ ongoing responsibilities to provide fish passage for the Corps’ upstream flood control project (Mud Mountain Dam). Keeping the Project in operation is also a matter of importance to the surrounding community that wants to preserve the reservoir for financial, recreational and aesthetic purposes. The outcome of these various negotiations and discussions is uncertain at this time, as is the magnitude of any financial impact on the Company associated therewith. However, in any event, it is unlikely that the Project will be in service as a generation resource of the Company after January of 2004. As a result, PSE will petition the Washington Commission for an accounting order in the fourth quarter of 2003. This petition will request authorization for the appropriate accounting and rate making disposition of this Project to be retired. At September 30, 2003, the White River Project net book value totals $69.0 million, which includes $47.6 million of net utility plant, $15.0 million of capitalized FERC licensing costs and $6.4 million of costs related to construction work in progress.
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion of the Company’s financial condition and results of operations contains forward-looking statements that involve risks and uncertainties, such as statements of the Company’s plans, objectives, expectations and intentions. Words such as “anticipate,” “believe,” “expect,” “future” and “intend” and similar expressions are used to identify forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. The Company’s actual results could differ materially from those anticipated in these forward-looking statements for many reasons, including the factors described below and under the caption “Forward-Looking Statements” at the beginning of this report. You should not place undue reliance on these forward-looking statements, which apply only as of the date of this Form 10-Q.
Results of Operations
Puget Energy
All of the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX. Puget Energy’s net income for the three months ended September 30, 2003 was $11.0 million on operating revenues of $515.6 million, compared with net income of $8.5 million on operating revenues of $458.5 million for the same period in 2002. Income for common stock was $9.9 million for the third quarter of 2003 compared to $6.6 million for the third quarter of 2002. Puget Energy’s basic and diluted earnings per share were $0.10 for the third quarter of 2003 compared to $0.07 for the third quarter of 2002.
For the first nine months of 2003, Puget Energy’s net income was $78.0 million on operating revenues of $1.7 billion, compared to net income of $66.4 million on operating revenues of $1.7 billion for the corresponding period in 2002. Income for common stock was $73.2 million for the first nine months of 2003 and $60.5 million for the same period in 2002. Puget Energy’s basic and diluted earnings per common share were $0.78 and $0.77, respectively, for the nine months ended September 30, 2003 and $0.69 for the same period in 2002.
Puget Energy’s income for common stock was impacted by PSE’s income for common stock for the three months ended September 30, 2003 of $8.4 million compared to $2.8 million for the same period in 2002. The improved results were due primarily to customer growth, improved gas margin, lower costs associated with long term equity incentive plans, gains from corporate owned life insurance and lower interest expense, partially offset by higher variable power costs. Puget Energy’s income for common stock was negatively impacted by a decrease in InfrastruX’s income for common stock (net of minority interest) of $2.3 million for the three months ended September 30, 2003 compared to the same period in 2002 due in part to fewer summer electric transmission repair and maintenance projects and a lower margin mix of work performed by InfrastruX companies.
Puget Energy’s income for common stock was impacted by PSE’s income for common stock for the nine months ended September 30, 2003 of $72.4 million compared to $53.3 million for the same period in 2002. The improved results were due primarily to improved electric and gas margins resulting from general tariff rate increases implemented in the third quarter of 2002 and lower interest expense, partially offset by SFAS 133 unrealized gains decrease from the prior year. Puget Energy’s income for common stock was negatively impacted by a decrease in InfrastruX’s income for common stock (net of minority interest) of $6.5 million for the nine months ended September 30, 2003 compared to the same period in 2002 due to increased insurance costs, competitive pressures on profit margins, and unusually severe weather which affected revenues and productivity in the first half of 2003.
Puget Sound Energy
The table below sets forth changes in the results of operations for Puget Sound Energy and its subsidiaries.
Comparative Three and Nine Months Ended
September 30, 2003 vs. September 30, 2002
Increase (Decrease)
(Dollars in Millions) |
| | Three
Month
Period
| Nine
Month
Period
|
| Operating revenue changes: | | | | | | | | |
| Electric interim and general rate increase | | | $ | -- | | $ | 10.5 | |
| BPA Residential Exchange Credit | | | | (6.7 | ) | | (23.4 | ) |
| Electric sales to other utilities and marketers | | | | 32.3 | | | 110.9 | |
| Electric conservation trust credit | | | | 2.8 | | | 1.0 | |
| Electric transportation revenue | | | | (2.2 | ) | | (3.6 | ) |
| Electric load and other | | | | 17.8 | | | 34.5 | |
|
| Total electric operating change | | | | 44.0 | | | 129.9 | |
|
| Gas PGA rate and load change | | | | 9.2 | | | (166.6 | ) |
| Gas general rate increase in base rates | | | | 2.3 | | | 22.8 | |
| Gas transportation revenue and other | | | | 0.9 | | | 1.8 | |
|
| Total gas operating change | | | | 12.4 | | | (142.0 | ) |
|
| Other operating revenue change | | | | (0.1 | ) | | (3.8 | ) |
|
| Total operating revenue change | | | | 56.3 | | | (15.9 | ) |
|
| Operating expense changes: | | |
| Energy costs: | | |
| Purchased electricity | | | | 42.1 | | | 164.2 | |
| Purchased gas | | | | 4.3 | | | (144.6 | ) |
| Electric generation fuel | | | | 4.4 | | | (49.3 | ) |
| Residential exchange power cost credit | | | | (6.5 | ) | | (22.4 | ) |
| Unrealized gain decrease on derivative instruments | | | | 1.2 | | | 12.5 | |
| Utility operations and maintenance: | | |
| Production operations and maintenance | | | | (1.0 | ) | | (3.8 | ) |
| Personal energy management expenses | | | | (1.4 | ) | | (5.2 | ) |
| Low income program pass through expenses | | | | 0.3 | | | 4.8 | |
| Other utility operations and maintenance | | | | 0.9 | | | 7.3 | |
| Other operations and maintenance | | | | -- | | | (0.3 | ) |
| Depreciation and amortization | | | | 1.5 | | | 3.0 | |
| Conservation amortization | | | | 5.7 | | | 13.9 | |
| Taxes other than income taxes | | | | 2.6 | | | (11.8 | ) |
| Income taxes | | | | 2.5 | | | 7.5 | |
|
| Total operating expense change | | | | 56.6 | | | (24.2 | ) |
| Other income change (net of tax) | | | | 2.4 | | | 1.6 | |
| Interest charges change | | | | (2.7 | ) | | (8.2 | ) |
| Cumulative effect of an accounting change (net of tax) | | | | -- | | | 0.1 | |
|
| Net income change | | | $ | 4.8 | | $ | 18.0 | |
|
PSE’s operating revenues and associated expenses are not generated evenly during the year. Variations in energy usage by consumers occur from season to season and from month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales during the heating season in the first and fourth quarters of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult. The following is additional information pertaining to the changes outlined in the above table.
Electric margin decreased $2.0 million for the three months ended September 30, 2003 compared to the same period in 2002 primarily as a result of underrecovered variable power costs of $5.8 million, offset by higher sales of electricity to retail customers. Electric margin increased $21.1 million for the nine months ended September 30, 2003 compared to the same period in 2002 due primarily to the non-recurrence of 2002 losses associated with the resale of excess gas supply for electricity generation. Electric margin is electric sales to retail and transportation customers less pass-through tariff items, revenue sensitive taxes, and the cost of generating and purchasing electric energy sold to customers including transmission costs to bring electric energy to PSE’s service territory.
Electric margin for the three and nine months ended September 30, 2003 and September 30, 2002 is detailed further as follows:
Electric Margin for the Three and Nine Months Ended
September 30, 2003 and September 30, 2002
(Dollars in Millions)
| | Three Months Ended
September 30
| Nine Months Ended
September 30
|
| | | | | 2003 | | | 2002 | | | 2003 | | | 2002 | |
| |
|
| Electric retail sales revenue | | | $ | 279 | .3 | $ | 272 | .1 | $ | 912 | .7 | $ | 920 | .3 |
| Electric transportation revenue | | | | 2 | .6 | | 4 | .8 | | 9 | .2 | | 12 | .9 |
| Other electric revenue-gas supply resale | | | | 0 | .3 | | (4 | .4) | | 7 | .9 | | (23 | .0) |
|
| Total electric revenue for margin | | | | 282 | .2 | | 272 | .5 | | 929 | .8 | | 910 | .2 |
| Adjustments for amounts included in revenue: | | |
| Pass-through tariff items | | | | (11 | .0) | | (8 | .2) | | (35 | .4) | | (19 | .3) |
| Pass-through revenue-sensitive taxes | | | | (20 | .5) | | (19 | .2) | | (65 | .9) | | (65 | .0) |
| Residential Exchange Credit | | | | 32 | .9 | | 26 | .4 | | 122 | .6 | | 100 | .1 |
|
| Net electric revenue for margin | | | | 283 | .6 | | 271 | .5 | | 951 | .1 | | 926 | .0 |
| Minus Power Costs: | | |
| Fuel | | | | (21 | .2) | | (16 | .9) | | (47 | .4) | | (96 | .7) |
| Purchased electricity, net of sales to other | | | | (122 | .8) | | (113 | .0) | | (445 | .2) | | (391 | .9) |
| utilities and marketers | | |
|
| Total electric power costs | | | | (144 | .0) | | (129 | .9) | | (492 | .6) | | (488 | .6) |
|
| Electric Margin | | | $ | 139 | .6 | $ | 141 | .6 | $ | 458 | .5 | $ | 437 | .4 |
|
Gas margin increased $6.5 million for the three months ended September 30, 2003 compared to the same period in 2002 due primarily to an increase of $2.3 million resulting from the $35 million annual, 5.8%, general gas tariff rate increase effective September 1, 2002. Gas margin increased $12.0 million for the nine months ended September 30, 2003 compared to the same period in 2002 due primarily to an increase of $22.8 million resulting from the 5.8% general gas tariff rate increase effective September 1, 2002 offset by gas therm sales declining 7.3% due to warmer weather in the first quarter of 2003. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.
Gas margin for the three and nine months ended September 30, 2003 and September 30, 2002 is detailed further as follows:
Gas Margin for the Three and Nine Months Ended
September 30, 2003 and September 30, 2002
(Dollars in Millions)
| | Three Months Ended
September 30
| Nine Months Ended
September 30
|
| | | | | 2003 | | | 2002 | | | 2003 | | | 2002 | |
| |
|
| Gas retail revenue | | | $ | 71 | .9 | $ | 60 | .4 | $ | 364 | .0 | $ | 507 | .8 |
| Gas transportation revenue | | | | 3 | .6 | | 3 | .1 | | 10 | .5 | | 9 | .0 |
|
| Total gas revenue for margin | | | | 75 | .5 | | 63 | .5 | | 374 | .5 | | 516 | .8 |
| Adjustments for amounts included in revenue: | | |
| Gas revenue hedge | | | | | -- | | | -- | | 0 | .2 | | | -- |
| Pass-through tariff items | | | | (0 | .4) | | (0 | .3) | | (2 | .9) | | (0 | .9) |
| Pass-through revenue-sensitive taxes | | | | (6 | .0) | | (5 | .0) | | (30 | .6) | | (42 | .1) |
|
| Net gas revenue for margin | | | | 69 | .1 | | 58 | .2 | | 341 | .2 | | 473 | .8 |
| Minus Purchased Gas Costs | | | | (35 | .5) | | (31 | .1) | | (179 | .8) | | (324 | .4) |
|
| Gas Margin | | | $ | 33 | .6 | $ | 27 | .1 | $ | 161 | .4 | $ | 149 | .4 |
|
Operating Revenues — Electric
Electric operating revenues for the three months ended September 30, 2003 were $343.5 million, an increase of $44.0 million compared to the same period in 2002 due primarily to wholesale electric sales to other utilities and marketers which increased $32.3 million from greater surplus volumes due in part to hedging expected hydro shortfall in energy production and higher prices in the wholesale electricity market. These wholesale sales revenues are a part of the Company’s Power Cost Adjustment (PCA) mechanism. Wholesale sales volumes increased by 188.6 million kWh or 18.4% to 1.2 billion kWh as a result of warmer temperatures compared to the same period in 2002 in the Pacific Northwest which provided excess electric energy supplies for sales to the wholesale market as a result of lower than expected retail sales and a slight improvement in the forecast of adverse hydro conditions, providing more hydro production than was originally forecasted. Retail sales revenue increased $7.2 million due primarily to increased commercial customer sales. Retail sales volume increased 3.4% to 4.3 billion kWh from 4.2 billion kWh for the same period in 2002.
Electric operating revenues for the nine months ended September 30, 2003 were $1.1 billion, an increase of $129.9 million compared to the same period in 2002, due primarily to wholesale electric sales to other utilities and marketers which increased $110.9 million from greater surplus volumes due in part to hedging expected hydro shortfall in energy production, and to higher prices in the wholesale electricity market. Wholesale sales volumes increased by 1.9 billion kWh or 80.5% to 4.3 billion kWh as a result of warmer-than-normal temperatures in the Pacific Northwest which provided excess electric energy supplies for sales to the wholesale market as a result of excess generation from the combustion turbines and higher than expected hydro production. Temperatures based on heating-degree-days measured at Seattle-Tacoma airport during the nine month period ended September 30, 2003 were 7.7% warmer than normal as compared to heating-degree-days being 8.3% cooler than normal during the nine month period ended September 30, 2002. Retail sales revenue decreased $7.6 million due primarily to $25 million of interim rate relief ended June 30, 2002 and warmer temperatures in 2003 offset by the effect of a 4.6% electric general rate increase effective July 1, 2002 that increased electric revenue by approximately $10.5 million in the first nine months of 2003. Retail sales volume was 14.1 billion kWh, up slightly from the equivalent period in 2002.
On June 20, 2002, the Washington Commission approved and adopted the settlement stipulation in the general rate case, putting new rates into effect on July 1, 2002. PSE established a Power Cost Adjustment (PCA) mechanism in the rate case settlement. The PCA mechanism will account for differences in PSE’s modified actual power costs relative to a power cost baseline. The mechanism will account for a sharing of costs and benefits that are graduated over four levels of power cost variances, with an overall cap of $40 million (+/-) over the four year period July 1, 2002 through June 30, 2006 plus 1% of the excess over $40 million. PSE’s share of the costs through September 30, 2003 was $29.9 million, $24.7 million of which was incurred in the first nine months of 2003. PSE expects to reach the $40 million cap by the end of 2003. Utility customers’ share of the costs, which were deferred for later recovery, through September 30, 2003 was $4.1 million, all of which was incurred in the second quarter of 2003.
On June 11, 2001, PSE and BPA entered into an amended settlement agreement regarding the Residential Purchase and Sale Program, under which PSE’s residential and small farm customers would continue to receive benefits of federal power. Completion of this agreement enabled PSE to continue to provide a Residential and Farm Energy Exchange Benefit credit to residential and small farm customers. The amended settlement agreement provides that, for its residential and small farm customers, PSE will receive (a) cash payment benefits during the period July 1, 2001 through September 30, 2006 and (b) benefits in the form of power or cash payments during the period October 1, 2006 through September 30, 2011.
Under the Residential Purchase and Sale Program, PSE reduces residential and small farm customers revenue on a per kWh basis through the Residential and Farm Energy Exchange Benefit credit. The credit has no impact on PSE’s electric margin or net income as a corresponding reduction is included in purchased electricity expenses. The Residential Purchase and Sale Program provides PSE’s residential and small farm customers benefits of lower-cost federal power.
On June 17, 2002, PSE entered into an agreement with BPA which amended the payment provisions of the amended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement. Under the modified agreement, BPA deferred paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred was $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA entered into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA agreed to BPA’s deferral of payments in their fiscal year 2003. The total cumulative amount deferred under the agreement with PSE and other such agreements equals $55 million. Absent certain adjustments tied to a BPA rate adjustment clause, BPA is to begin paying back the amount deferred with interest over the sixty-month period beginning October 1, 2006. In January 2003, PSE filed revised tariff sheets with the Washington Commission to reflect this modification to the agreement between PSE and BPA. The Washington Commission accepted the tariff changes and the BPA credit was changed to $0.01740 per kWh, from $0.01817 per kWh, for the period February 15, 2003 through September 30, 2006. On June 30, 2003, BPA adopted its final Record of Decision in the February 2003 rate case, which established a formula under the BPA rate adjustment clause to be used in adjusting the rate which will affect the level of residential exchange benefits for PSE’s customers. The adjustment under the formula went into effect on October 1, 2003, resulting in both a reduction of benefits of $1.2 million a month for a twelve month period and, under the modified agreement mentioned above, an offsetting acceleration of the payment of the above-described $27.7 million deferral. The net result is no change in the cash being received from BPA for the twelve month period, but a reduction in the total benefits to be received in the October 1, 2003 through September 30, 2011 period.
For the three and nine months ended September 30, 2003, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers were $34.3 million and $128.1 million, respectively, with a related offset to power costs. PSE received payments from BPA in the amount of $33.5 million and $104.0 million during the three and nine months ended September 30, 2003, respectively. The difference between the customers’ credit and the amount received from BPA reduces the previously deferred amount owed to customers. The aggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. Absent certain adjustments tied to a BPA rate adjustment clause described above, the modified amended settlement agreement will provide for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for pass-through of the same amount to eligible residential and small farm customers.
On October 23, 2003, PSE signed conditional settlement agreements including a Stipulation and Agreement for Settlement, a Waiver and Covenant Not to Sue, and an Amendment No. 1 to the amended settlement agreement. These conditional settlement agreements, which will be void unless certain conditions are satisfied, include provisions for the dismissal of certain lawsuits regarding residential exchange benefits, an elimination of the adjustment mentioned above for the twelve month period commencing October 1, 2003, the deferral of the receipt of certain benefits, a change in the methodology used to calculate residential benefits in the October 1, 2006 through September 30, 2011 period, and elimination of a risk premium that would otherwise have been payable by BPA under certain conditions under the amended settlement agreement. The conditions which would render the conditional settlement agreements void include a condition that approximately 70 public agency utilities sign a Waiver and Covenant Not to Sue by January 21, 2004, and that no party withdraws its signature by February 20, 2004. Under the conditional settlement agreements, the reduction in benefits mentioned above of $1.2 million a month for twelve months will be eliminated and PSE will defer a total of $37.6 million in the eight month period beginning February 2004, and $27.6 million a year for the two year period beginning October 2004, for a total deferral of $92.9 million. This money will be returned with interest in equal payments over the 60 month period beginning October 2006. If the conditional settlement agreements signed October 23, 2003 are not voided, the benefits to be received from BPA will be reduced, absent certain adjustments tied to a BPA rate adjustment clause, for the January 2003 through September 2006 period from $630.6 million to $537.7 million with the remaining $92.9 million being paid, plus interest, in the October 2006 through September 2011 period.
There are several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which the petitioners assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the contract between BPA and PSE. BPA rates used in such contract between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. It is not clear what impact, if any, review of such rates and the above-described U.S. Ninth Circuit Court of Appeals actions may have on PSE. PSE cannot presently predict whether or not the above described conditional settlement agreements will be rendered void or result in the dismissal of any or all of the above described U. S. Ninth Circuit Court of Appeals actions.
To meet customer demand, PSE dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydro capacity and energy, and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its core energy portfolio through short and intermediate-term off-system physical purchases and sales, and through other risk management techniques. A PSE Risk Management Committee oversees energy portfolio exposures.
During the six months ended June 30, 2003, PSE collected in its electric general rate tariff and remitted to a grantor trust $7.7 million as compared to $5.8 million for the same period in 2002 as a result of PSE’s 1995 sale of future electric revenues associated with its investment in conservation assets. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amount owed by the trust to its bondholders was $11.6 million at June 30, 2003. PSE’s 1995 conservation trust transaction was consolidated in the third quarter of 2003 to meet the guidance of FASB Interpretation No.46 (FIN 46) and, as a result, revenues increased $3.9 million while conservation amortization and interest expense increased by a corresponding amount with no impact on earnings. At September 30, 2003, the balance sheet assets and liabilities have increased by $8.0 million.
PSE operates within the western wholesale market and has made sales into the California energy market. During the fourth quarter of 2000, PSE made such sales to the California energy market on which the receivable amount is still outstanding. At September 30, 2003, PSE’s receivable from the California Independent System Operators (CAISO) and other counter-parties, net of reserves, was $24.1 million. See the discussion of the CAISO receivable and California proceedings under “Proceedings Relating to the Western Power Market”.
Operating Revenues — Gas
Retail gas revenue for the three and nine month periods ended September 30, 2003 increased by $11.5 million and decreased by $143.8 million from the same periods in 2002, respectively, which included the effect of a $35 million annual or 5.8%, gas general rate increase effective September 1, 2002 that increased gas revenue by approximately $2.3 million and $22.8 million for the three and nine month periods ended September 30, 2003, respectively. Retail gas sales volumes increased 10.0% from 78.1 million therms for the three months ended September 30, 2002 to 85.9 million therms for the three months ended September 30, 2003 and decreased 9.9% from 583.6 million therms for the nine months ended September 30, 2002 to 525.9 million therms for the nine months ended September 30, 2003 due primarily to warmer temperatures in the Pacific Northwest in the first quarter of 2003.
Purchased Gas Adjustment (PGA) rates charged to customers were lower in the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 as a result of rate decreases of 7.3% and 12.5% which took effect September 1, 2002 and November 1, 2002, respectively, offset by a rate increase of 20.1% which took effect April 10, 2003. On September 24, 2003 the Washington Commission approved the PGA rate increase of an annual average of 13.3% across all groups of customers effective October 1, 2003. The PGA mechanism passes through to customers increases or decreases in the gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in gas pipeline transportation costs.
PSE’s gas margin (gas sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory) and net income are not affected by changes under the PGA.
Operating Expenses
Purchased electricityexpenses increased $42.1 million and $164.2 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. PSE’s hydroelectric production and related power costs in 2003 have been negatively impacted by below normal winter precipitation and snow pack in the Pacific Northwest region associated with an El Nino weather condition. The October 2, 2003 Columbia Basin Runoff Summary published by the National Weather Service Northwest River Forecast Center indicated that the total observed runoff above Grand Coulee reservoir for the period January through September 2003 was 84% of normal. This compares to 102% of normal for the same period in 2002. The Company anticipates reaching the $40 million cumulative cap under the PCA mechanism by the end of 2003 primarily due to increased power costs and adverse hydro conditions. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE. PSE’s share of power costs, in excess of those set in rates, through September 30, 2003 was $29.9 million.
Purchased gasexpenses increased $4.3 million and decreased $144.6 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. The three month ended increase was primarily due to an increase in gas market prices from the third quarter of 2002 to the third quarter of 2003. The nine month ended decrease was due to lower consumption volumes as a result of warmer than normal temperatures and the impact of decreased gas costs, which were passed through to customers through the PGA mechanism. 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 liability at September 30, 2003 of $6.8 million compared to a liability balance at September 30, 2002 of $98.6 million.
Electric generationfuel expense increased $4.4 million and decreased $49.3 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. The three month increase is due to higher gas supply costs and increased generation from our combustion turbine units from 2002 to 2003. The nine month decrease is due to lower fuel costs for PSE controlled gas-fired generation facilities which were not operated due to lower cost of wholesale power supply.
Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with BPA increased $6.5 million and $22.4 million for the three and nine month periods ended September 30, 2003 when compared to the same periods in 2002, due to an increase in the Residential and Farm Energy Exchange credit rate in January, March, and October of 2002. For further details, see the amended Residential Purchase and Sale Agreement between PSE and BPA discussion in Operating Revenues – Electric.
Unrealized gain on derivative instrumentsdecreased $1.2 million and $12.5 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due to changes in the market value of derivative instruments and the reversal of previously recorded unrealized gains when underlying energy supply contracts were settled. During the three months ended September 30, 2003 the Company recorded a decrease in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $0.9 million pre-tax ($0.6 million after-tax) compared to an increase of $0.3 million pre-tax ($0.2 million after-tax), for the same period in 2002. During the nine months ended September 30, 2003 the Company recorded a decrease in earnings of approximately $0.4 million pre-tax ($0.2 million after-tax) compared to an increase of $12.1 million pre-tax ($7.8 million after-tax) for the same period in 2002. An $11.7 million pre-tax gain in 2002 represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002.
The Company has two contracts outstanding with a counterparty whose senior unsecured debt ratings are currently below investment grade. The first contract is a fixed for floating price natural gas swap contract for which the Company has collected a collateral deposit in the amount of $27.3 million from the counterparty to guarantee performance. The financial contract will expire in June 2008 and is accounted for as a cash flow hedge under SFAS No. 133. The second is a physical gas supply contract expiring in December 2008, which has been designated as a normal purchase under SFAS No. 133. The counterparty has continuously performed on both contracts since the contracts were entered into in 2000 and the Company believes it is probable that the counterparty will continue to perform. The Company will continue to monitor the performance of the counterparty.
Production operations and maintenancecost decreased $1.0 million and $3.8 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002. The three month decrease is primarily attributable to $0.8 million in electric generating facility maintenance inspections of combustion turbines during 2002 that did not recur in 2003. The nine month decrease is due primarily to a $4.0 million pre-tax charge in the second quarter of 2002 related to an industrial accident at Colstrip Units 1 and 2 (of which PSE is a 50% owner) which did not recur in 2003.
PSE’s Personal Energy ManagementTMenergy-efficiency program costs decreased $1.4 million and $5.2 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002, reflecting a cancellation of the Company’s Time of Use program in November 2002.
ALow-income Programapproved by the Washington Commission in the general rate case settlement began in July 2002, which resulted in increased costs of $0.3 million and $4.8 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002. These costs are fully recovered through a surcharge 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 $0.9 million and $7.3 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due primarily to an increase in electric overhead and underground line costs, gas distribution main costs, administrative and general salaries, and meter reading expenses.
Depreciation and amortizationexpense for PSE increased $1.5 million and $3.0 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due primarily to the effects of new plant placed into service during the past year.
Conservation amortizationexpense increased $5.7 million and $13.9 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due to increased conservation expenditures and the result of consolidating the off-balance sheet conservation trust beginning July 1, 2003 in accordance with FIN 46, “Consolidation of Variable Interest Entities”. Pass-through conservation costs are recovered through an electric conservation rider, a gas conservation tracker mechanism and a conservation trust rate schedule with no impact to earnings.
Taxes other than income taxesincreased $2.6 million and decreased $11.8 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 primarily due to lower municipal and state excise taxes which are revenue based. In addition, PSE reached a settlement with the Oregon State Department of Revenue related to a property tax dispute resulting in a $1.4 million reduction in the second quarter of 2003 of amounts previously accrued as expense.
Income taxesincreased $2.5 million and $7.5 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002. Included in the three months ended September 30, 2003 and 2002 were true-ups related to filing the prior year’s income tax returns that reduced income tax expense by $3.0 million and $3.5 million respectively. The nine months ended September 30, 2003 includes a $6.2 million reduction in tax expense related to a favorable resolution of a federal income tax matter from 1997 to 2002 in the second quarter of 2003.
Other Income
Other income increased $2.4 million and $1.6 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002 due primarily to lower costs for long-term equity incentive plans and gains received on corporate owned life insurance.
Interest Charges
Interest charges decreased $2.7 million for the three months ended and $8.2 million for the nine months ended September 30, 2003 compared to the same periods in 2002. Interest on long-term debt decreased $3.0 million for the three months ended and $9.2 million for the nine months ended September 30, 2003, compared to the same periods in 2002. The decrease in interest expense is primarily due to the maturity of $25 million of 7.625% Medium Term Notes in the fourth quarter of 2002, maturity of $58 million of Medium Term Notes with interest rates ranging from 6.23% to 7.02% during 2003, the early redemption of $19.7 million of 8.231% Capital Trust I Preferred Securities, the early redemption of $83 million of Medium Term Notes with interest rates ranging from 7.190% to 8.59% during 2003, and the refinancing of $161.9 million of Pollution Control Bonds with interest rates ranging from 5.875% to 7.25% to rates ranging from 5.00% to 5.10%. The decrease in interest expense was partially offset by the issuance of $150 million of 3.363% Senior Notes in May 2003.
InfrastruX
The table below sets forth changes in the results of operations for InfrastruX, net of minority interest.
Comparative Three and Nine Months Ended
September 30, 2003 vs. September 30, 2002
Increase (Decrease)
(Dollars in Millions)
| Three
Month
Period
| Nine
Month
Period
|
| Operating revenue change: | | | | | | | | |
| Other operating revenue | | | $ | 0 | .8 | $ | 26 | .9 |
|
| Operating expense changes: | | |
| Other operations and maintenance | | | | 5 | .3 | | 36 | .7 |
| Depreciation and amortization | | | | 0 | .4 | | 2 | .8 |
| Taxes other than income taxes | | | | (0 | .4) | | (0 | .3) |
| Income taxes | | | | (2 | .1) | | (5 | .5) |
|
| Total operating expense change | | | | 3 | .2 | | 33 | .7 |
| Other Income (net of tax) change | | | | | -- | | (0 | .1) |
| Interest charges change | | | | 0 | .1 | | 0 | .2 |
| Minority interest change | | | | (0 | .2) | | (0 | .6) |
|
| Net income change | | | $ | (2 | .3) | $ | (6 | .5) |
|
The following is additional information pertaining to the changes outlined in the above table.
InfrastruX revenueincreased $0.8 million and $26.9 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due primarily to acquisitions of several companies during 2002 and one in 2003, which contributed an increase of $10.5 million and $35.3 million, respectively. Revenues from existing companies decreased overall for the three and nine month periods ended September 30, 2003 by $9.8 million and $8.4 million, respectively, due primarily to a reduction in summer electric transmission work in the Southwest/South Central region.
InfrastruX operation and maintenanceexpenses increased $5.3 million and $36.7 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due to the additional costs related to acquired companies, weather-related problems in the first half of 2003 that impacted efficiency and productivity and increases in insurance costs.
Depreciation and amortizationexpense increased by $0.4 million and $2.8 million for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 due to acquisitions during 2002 and additional assets placed in service to support growth as well as to replace aging equipment.
Income taxesdecreased $2.1 million during the three month period ended September 30, 2003 compared to the same period in 2002 due primarily to lower operating income contributed from acquired companies. Income taxes decreased $5.5 million for the nine month period ended September 30, 2003 compared to the same period in 2002 due to a decrease in revenue.
Capital Expenditures, Capital Resources and Liquidity
Capital Requirements
Contractual Obligations and Commercial Commitments
Puget Energy.The following are Puget Energy's aggregate consolidated (including PSE) contractual obligations and commercial commitments as of September 30, 2003:
| Puget Energy | Payments Due Per Period
|
|---|
Contractual Obligations
(Dollars in millions)
| Total
| 2003
| 2004-2005
| 2006-2007
| 2008 and
Thereafter
|
| Long-term debt | | | $ | 2,254 | .1 | $ | 19 | .4 | $ | 315 | .0 | $ | 206 | .3 | $ | 1,713 | .4 |
| Short-term debt | | | | 26 | .5 | | 26 | .5 | | | -- | | | -- | | | -- |
| Trust preferred securities (1) | | | | 280 | .3 | | | -- | | | -- | | | -- | | 280 | .3 |
| Mandatorily redeemable preferred stock | | | | 1 | .9 | | | -- | | | -- | | | -- | | 1 | .9 |
| Preferred stock and preferred dividends (2) | | | | 61 | .5 | | 61 | .5 | | | -- | | | -- | | | -- |
| Service contract obligations | | | | 175 | .6 | | 4 | .8 | | 40 | .7 | | 43 | .4 | | 86 | .7 |
| Capital lease obligations | | | | 25 | .9 | | 2 | .2 | | 14 | .2 | | 8 | .4 | | 1 | .1 |
| Non-cancelable operating leases | | | | 70 | .7 | | 7 | .7 | | 31 | .3 | | 21 | .1 | | 10 | .6 |
| Fredonia combustion turbines lease (3) | | | | 70 | .8 | | 1 | .2 | | 8 | .9 | | 8 | .6 | | 52 | .1 |
| Energy purchase obligations | | | | 4,685 | .1 | | 290 | .4 | | 1,370 | .5 | | 954 | .2 | | 2,070 | .0 |
| Financial hedge obligations | | | | 20 | .0 | | 1 | .8 | | 11 | .3 | | 6 | .0 | | 0 | .9 |
|
| Total contractual cash obligations | | | $ | 7,672 | .4 | $ | 415 | .5 | $ | 1,791 | .9 | $ | 1,148 | .0 | $ | 4,217 | .0 |
| | Amount of Commitment
Expiration Per Period
|
|---|
Commercial Commitments
(Dollars in millions)
| Total
| 2003
| 2004-2005
| 2006-2007
| 2008 and
Thereafter
|
| Guarantees (4) | | | $ | 136 | .0 | $ | | -- | $ | 136 | .0 | $ | | -- | $ | | -- |
| Liquidity facilities – available (5) | | | | 329 | .0 | | 240 | .2 | | 88 | .8 | | | -- | | | -- |
| Lines of credit – available (6) | | | | 34 | .4 | | | -- | | 24 | .4 | | 10 | .0 | | | -- |
| Energy operations letter of credit (7) | | | | 0 | .5 | | | -- | | 0 | .5 | | | -- | | | -- |
|
| Total commercial commitments | | | $ | 499 | .9 | $ | 240 | .2 | $ | 249 | .7 | $ | 10 | .0 | $ | | -- |
| | (1) | In 1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling preferred securities (Trust Securities) to investors and issuing common securities to PSE. The proceeds from the sale of Trust Securities were used by the Trusts to purchase Junior Subordinated Debentures (Debentures) from PSE. The Debentures are the sole assets of the Trusts and PSE owns all common securities of the Trusts. |
| | (2) | On July 7, 2003, the Board of Directors of PSE declared a dividend payable on October 1, 2003 for preferred stock outstanding on September 1, 2003. The preferred stock was redeemed at par for $60 million on November 1, 2003, and PSE paid dividends for the period between October 1, 2003 and November 1, 2003. |
| | (3) | See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below. |
| | (4) | In June 2001, InfrastruX signed a three-year credit agreement with several banks to provide up to $150 million in financing. Under the credit agreement, Puget Energy is the guarantor of the line of credit. |
| | (5) | At September 30, 2003, PSE had available a $250 million unsecured credit agreement and a three year $150 million receivables securization facility. At September 30, 2003, PSE had available $88.8 million of receivables for sale under its receivables securitization facility. See “Accounts Receivable Securitization Program” under “Off-Balance Sheet Arrangements” below. The credit agreement and securitization facility provide credit support for outstanding commercial paper totaling $9.3 million and an outstanding letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under these liquidity facilities to $329.0 million. |
| | (6) | Puget Energy has a $15 million line of credit with a bank. At September 30, 2003, $5 million was outstanding, reducing the available borrowing capacity under this line of credit to $10 million. InfrastruX has $31.7 million in lines of credit with various banks, and a $150 million line of credit guaranteed by Puget Energy, which fund capital requirements of InfrastruX and its subsidiaries. InfrastruX and its subsidiaries had outstanding loans of $153.2 million and letters of credit of $4.1 million at September 30, 2003, effectively reducing the available borrowing capacity under these lines of credit to $24.4 million. |
| | (7) | In May 2002, PSE provided an energy trading counterparty a letter of credit in the amount of $0.5 million to satisfy the counterparty’s credit requirements following PSE’s senior unsecured debt downgrade in October 2001. The letter of credit has been renewed and expires on March 15, 2004. |
Puget Sound Energy.The following are PSE’s aggregate contractual obligations and commercial commitments as of September 30, 2003:
| Puget Sound Energy | Payments Due Per Period
|
|---|
Contractual Obligations
(Dollars in millions)
| Total
| 2003
| 2004-2005
| 2006-2007
| 2008 and
Thereafter
|
| Long-term debt | | | $ | 2,110 | .8 | $ | 14 | .0 | $ | 177 | .4 | $ | 206 | .0 | $ | 1,713 | .4 |
| Short-term debt | | | | 9 | .3 | | 9 | .3 | | | -- | | | -- | | | -- |
| Trust preferred securities (1) | | | | 280 | .3 | | | -- | | | -- | | | -- | | 280 | .3 |
| Mandatorily redeemable preferred stock | | | | 1 | .9 | | | -- | | | -- | | | -- | | 1 | .9 |
| Preferred stock and preferred dividends (2) | | | | 61 | .5 | | 61 | .5 | | | -- | | | -- | | | -- |
| Service contract obligations | | | | 175 | .6 | | 4 | .8 | | 40 | .7 | | 43 | .4 | | 86 | .7 |
| Non-cancelable operating leases | | | | 51 | .7 | | 5 | .4 | | 19 | .2 | | 17 | .7 | | 9 | .4 |
| Fredonia combustion turbines lease (3) | | | | 70 | .8 | | 1 | .2 | | 8 | .9 | | 8 | .6 | | 52 | .1 |
| Energy purchase obligations | | | | 4,685 | .1 | | 290 | .4 | | 1,370 | .5 | | 954 | .2 | | 2,070 | .0 |
| Financial hedge obligations | | | | 20 | .0 | | 1 | .8 | | 11 | .3 | | 6 | .0 | | 0 | .9 |
|
| Total contractual cash obligations | | | $ | 7,467 | .0 | $ | 388 | .4 | $ | 1,628 | .0 | $ | 1,235 | .9 | $ | 4,214 | .7 |
| | Amount of Commitment
Expiration Per Period
|
|---|
Commercial Commitments
(Dollars in millions)
| Total
| 2003
| 2004-2005
| 2006-2007
| 2008 and
Thereafter
|
| Liquidity facilities – available (4) | | | $ | 329 | .0 | $ | 240 | .2 | $ | 88 | .8 | $ | | -- | $ | | -- |
| Energy operations letter of credit (5) | | | | 0 | .5 | | | -- | | 0 | .5 | | | -- | | | -- |
|
| Total commercial commitments | | | $ | 329 | .5 | $ | 240 | .2 | $ | 89 | .3 | $ | | -- | $ | | -- |
(1) See note (1) above.
(2) See note (2) above.
(3) See note (3) above.
(4) See note (5) above.
(5) See note (7) above.
Off-Balance Sheet Arrangements
Accounts Receivable Securitization Program.In order to provide a source of liquidity for PSE at attractive cost of capital rates, in December 2002, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE, pursuant to which PSE sold all of its utility customers accounts receivable and unbilled utility revenues to Rainier Receivables. Concurrently with entering into the Receivables Sales Agreement, Rainier Receivables entered into a Receivables Purchase Agreement with PSE and several financial institutions. The Receivables Purchase Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the financial institutions. The amount of receivables sold by Rainier Receivables is not permitted to exceed $150 million at any time. However, the maximum amount may be less than $150 million depending on the outstanding amount of PSE’s receivables which fluctuate with the seasonality of energy sales to customers.
The receivables securitization facility is the functional equivalent of a secured revolving line of credit. In the event Rainier Receivables elects to sell receivables under the Receivables Purchase Agreement, Rainier Receivables is required to pay the purchasers of the receivables fees that are analogous to interest on a revolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables purchased by the purchasers declines until Rainier Receivables elects to sell additional receivables to the purchasers.
The receivables securitization facility has a three year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At September 30, 2003, Rainier Receivables had sold $7.0 million of accounts receivable and the maximum receivables available for sale was $88.8 million.
Fredonia 3 and 4 Operating Lease.PSE leases two combustion turbines for its Fredonia 3 and 4 electric generation facility pursuant to a master lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE after three years from the inception date of August 1, 2001. Payments under the lease vary with changes in the London inter-bank offered rate (LIBOR). At September 30, 2003, PSE’s outstanding balance under the lease was $59.5 million. The expected residual value under the lease is the lesser of $37.4 million or 60% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87% of the unamortized value of the equipment.
Utility Construction Program.Current utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of PSE’s energy delivery systems. Construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC), were $203.9 million for the nine months ended September 30, 2003. PSE expects construction expenditures will be approximately $272 million in 2003 and will be larger in 2004. PSE anticipates spending approximately $80 million in 2004 for new generating resources and a substantially larger amount in 2005, subject to regulatory approval of the resources and related new revenue requirements. The 2004 resources will be funded initially with short-term debt. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.
New Generation Resources.In October 2003, PSE completed negotiations to purchase a 49.85% interest in a 275 MW gas fired electric generating station located within PSE’s service territory. The purchase will add approximately 137 MW of electric generation capacity to serve PSE’s retail customers. PSE submitted a power cost only rate case in October 2003 to the Washington Commission to recover the approximately $80 million cost of the new generating facility and other power costs. The power cost only rate case is expected to last approximately five months. Accordingly, the acquisition of the plant, subject to favorable approval by the Washington Commission, could be completed by the end of the first quarter of 2004.
In addition, PSE has issued a draft request for proposals (RFP) to acquire approximately 50 average MWs of energy from wind power for its electric-resource portfolio. PSE plans to issue an RFP for approximately 300 MWs of thermal generation in early 2004.
Other Additions.Other property, plant and equipment additions were $10.4 million for the nine months ended September 30, 2003. Puget Energy expects InfrastruX’s capital additions to be $13.0 million in 2003. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental, and conservation factors.
Capital Resources
Cash From Operations.Cash generated from operations for the nine month period ended September 30, 2003 was $206.1 million. During the period, $66.8 million in cash was used for AFUDC and payment of dividends. Consequently, cash flows available for utility construction expenditures and other capital expenditures was $139.3 million or 61.7% of the $225.6 million in construction expenditures (net of AFUDC) and other capital expenditure requirements for the period. PSE funded these 2003 expenditures primarily by drawing upon its cash reserves which were $161.5 million at the end of 2002. For the same period in 2002, cash generated from operations was $566.7 million, $78.1 million of which was used for AFUDC and payment of dividends. Therefore, cash flows available for utility construction expenditures and other capital expenditures for the nine month period ended September 30, 2002 was $488.6 million. The reduction in cash generated from operations in 2003 is primarily due to refunds reducing the PGA balance. In the nine months ended September 30, 2002, PSE received $135.8 million in excess of actual gas costs from customers through the PGA mechanism compared to refunds to customers through the PGA mechanism of $77.0 million for the nine months ended September 30, 2003. Cash from accounts receivables and unbilled revenues decreased by $45.9 million due primarily to colder than normal temperatures in the nine months ended September 30, 2002 compared to warmer than normal temperatures in 2003. Cash from materials and supplies decreased $42.2 million due predominantly to higher gas injections in 2003 as compared to 2002 in order to build up storage levels. Cash from other operating activities also decreased due to an $11.2 million decrease in accrued purchases from 2002 to 2003 and a $27.7 million increase in the amount of cash used to offset customers bills compared to cash received from BPA for the Residential Exchange Program.
Puget Energy and PSE expect to continue financing the utility construction program and other capital expenditure requirements with internally generated funds and externally financed capital.
Financing Program.Financing utility construction requirements and operational needs is dependent upon the cost and availability of external funds through capital markets and from financial institutions. Access to funds is dependent upon factors such as general economic conditions, regulatory authorizations and policies, and Puget Energy’s and PSE’s credit ratings. The Company expects to meet capital and operational needs for the balance of 2003 and 2004 with cash generated from operations and borrowings under its liquidity facilities.
Restrictive Covenants.In determining the type and amount of future financing, PSE may be limited by restrictions contained in its electric and gas mortgage indentures, articles of incorporation and certain loan agreements. Under the most restrictive tests, at September 30, 2003, PSE could issue:
| | • | approximately $983.8 million of first mortgage bonds, as PSE has approximately $1.3 billion of electric and gas bondable property available for use, subject to the interest coverage ratio limitation of 2.0 times net earnings available for interest. PSE’s interest coverage ratio at September 30, 2003 was 2.7 times net earnings available for interest which would allow issuance of approximately $783.2 million of additional first mortgage bonds, at an assumed interest rate of approximately 6% on a ten-year first mortgage bond; |
| | • | approximately $415.6 million of additional preferred stock at an assumed dividend rate of 7.75%; and |
| | • | approximately $262.2 million of unsecured long-term debt. |
Credit Ratings.Neither Puget Energy nor PSE has any rating downgrade triggers that would accelerate the maturity dates of outstanding debt. However, a downgrade in the credit ratings could adversely affect the Companies’ ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the spreads over the index and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. A further downgrade in commercial paper ratings could preclude entirely PSE’s ability to issue commercial paper. In addition, downgrades in any or a combination of PSE’s debt ratings may allow counterparties on a contract by contract basis in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security.
The ratings of Puget Energy and PSE as of November 10, 2003 were:
| | Ratings |
| | Standard & Poor’s | Moody’s |
| Puget Sound Energy | | |
| Corporate credit/issuer rating | BBB- | Baa3 |
| Senior secured debt | BBB | Baa2 |
| Shelf debt senior secured | BBB | Baa2 |
| Senior unsecured | * | * |
| Preferred stock | BB | Ba2 |
| Commercial paper | A-3 | P-2 |
| Subordinate | ** | Ba1 |
| Revolving credit facility | ** | Baa3 |
| Ratings outlook | Stable | Negative |
| Puget Energy |
| Corporate credit/issuer rating | BBB- | Ba1 |
| | * | No ratings provided. S&P and Moody’s have placed an indicative rating of BB+ and Baa3, respectively, on senior unsecured debt were the Company to issue any pursuant to its shelf registration filed in February 2002. To date, the Company has not issued any senior unsecured debt. |
Moody’s Investors Service has stated that its negative outlook is based upon uncertainty about the outcome of investigations by FERC of the Western power markets. Moody’s Investors Service has stated that it would consider a stable outlook if FERC approves the recent agreement reached between PSE and the FERC trial staff. See “Proceedings Relating to the Western Power Market – Orders to Show Cause”.
Shelf Registrations.In February 2002, Puget Energy and PSE filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $500 million of:
| | • | common stock of Puget Energy, |
| | • | senior notes of PSE, secured by a pledge of PSE’s first mortgage bonds, |
| | • | unsecured debentures of PSE, and |
| | • | trust preferred securities of Puget Sound Energy Capital Trust III. |
On November 5, 2003, Puget Energy completed the sale of 4.55 million shares of common stock directly to funds managed by Franklin Advisers, Inc. for $100.1 million. The sale of these shares are expected to be non-dilutive for 2003 and 2004 earnings per share as the common stock replaces high cost preferred stock. Of the net proceeds of the sale, $93.75 million will be invested in PSE to fund redemptions of the preferred stock and $6.25 million balance will be used by PSE for general corporate purposes. Approximately $128.5 million of securities remain available for issuance under the shelf registration at November 5, 2003.
Liquidity Facilities and Commercial Paper.PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs.
PSE has a $250 million unsecured credit agreement with various banks which expires in June 2004 and a $150 million 3-year receivables securitization program which expires in December 2005. The receivables available for sale under the securitization program may be less than $150 million depending on the outstanding amount of PSE’s receivables which fluctuate with the seasonality of energy sales to customers. At September 30, 2003, PSE had available $250 million in the unsecured credit agreement and $88.8 million available from the receivable securitization facility (net of $7.0 million sold), which provide credit support for outstanding commercial paper of $9.3 million and outstanding letters of credit of $0.5 million, effectively reducing the available borrowing capacity under the liquidity facilities to $329.0 million.
In June 2001, InfrastruX signed a three-year credit agreement with several banks to provide up to $150 million in financing. Puget Energy is the guarantor of the line of credit. In addition, InfrastruX’s subsidiaries have an additional $31.7 million in lines of credit with various banks. Borrowings available for InfrastruX are used to fund acquisitions and working capital requirements of InfrastruX and its subsidiaries. At September 30, 2003, InfrastruX and its subsidiaries had outstanding loans of $153.2 million and letters of credit of $4.1 million, effectively reducing the available borrowing capacity under these lines of credit to $24.4 million.
On May 27, 2003, Puget Energy entered into a $15 million, three-year credit agreement with a bank. Under the terms of the agreement, Puget Energy will pay a floating interest rate on borrowings based on the London inter-bank offered rate (LIBOR). The interest rate is set for one, two, or three-month periods at the option of Puget Energy with interest due at the end of each period. Puget Energy will also pay a commitment fee on any unused portion of the credit facility. On May 30, 2003, Puget Energy borrowed $5 million under the credit agreement. The proceeds of the loan were invested in InfrastruX, which used the proceeds to acquire a construction services company in New Mexico.
Stock Purchase and Dividend Reinvestment Plan.Puget Energy has a stock purchase and dividend reinvestment plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy’s common stock. Since new shares of common stock may be purchased directly from Puget Energy, funds received may be used for general corporate purposes. Puget Energy issued common stock from the Stock Purchase and Dividend Reinvestment Plan of $4.0 million (184,870 shares) and $11.6 million (554,441 shares) for the three and nine months ended September 30, 2003 compared to $3.2 million (149,545 shares) and $13.0 million (619,655 shares) for the same periods in 2002. The decrease in the shares issued under the Stock Purchase and Dividend Reinvestment Plan from the nine month period ended September 30, 2003 compared to the nine month period ended September 30, 2002 was largely attributable to the reduction of the common stock dividend on May 15, 2002 to a quarterly dividend of $0.25 per share.
Common Stock Offering Programs.To provide additional financing options, Puget Energy entered into agreements on July 10, 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to time through these institutions as sales agents, or as principals. Sales of the common stock, if any, may be made by means of negotiated transactions or in transactions that may be deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under the Securities Act of 1933, including in ordinary brokers’ transactions on the New York Stock Exchange at market prices. On October 14, 2003, Puget Energy sold 100,600 shares of common stock under its program with Cantor Fitzgerald & Company. Puget Energy received approximately $2.3 million in net proceeds from these sales, after deducting an underwriter’s commission of $45,000 and estimated offering expenses payable by Puget Energy.
Proceedings Relating to the Western Power Market
California Independent System Operator (CAISO) Receivable and California Proceedings
Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2002 and Quarterly Report on Form 10-Q for the quarters ended March 31, 2003 and June 30, 2003 include summaries of the Western power market proceedings described below. The following discussion provides a summary of material developments in these proceedings that occurred during the period covered by this report and of any material new proceedings instituted during the last quarter. While PSE cannot predict the outcome of any of the individual ongoing proceedings relating to the Western power markets, PSE generally is pleased that FERC appears to be narrowing the issues under review in the cases pending before it. The narrowing of issues allows PSE to compare the allegations in the various proceedings with PSE’s relevant records and to better anticipate the likely outcome of each case. In the aggregate, PSE does not expect the ultimate resolution of the issues and cases discussed below to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.
| 1. | California Independent System Operator (CAISO) Receivable.In 2001, PG&E and Southern California Edison defaulted on payment obligations owed to various energy suppliers, including the CAISO. The CAISO in turn defaulted on its payment obligations to various energy suppliers, including obligations to PSE relating to sales made by PSE into the California energy market during the fourth quarter of 2000 through the CAISO. After deducting a bad debt reserve and a transaction fee reserve totaling $41.5 million, PSE has a net receivable from the CAISO at September 30, 2003 of $24.1 million. On October 16, 2003, FERC issued its Order on Rehearing in this docket and expressly adopted and approved a stipulation that confirmed 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. |
| 2. | 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, including the CAISO, for purchases made in the spot markets operated by the CAISO during the period October 2, 2000 through June 20, 2001.
On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket EL00-95 that substantially adopted the recommendations made by the Administrative Law Judge on December 12, 2002, except that the Order also substantially adopts the FERC Staff gas price recommendation from the Staff’s August 2002 report. On October 16, 2003, FERC issued its Order on Rehearing that largely leaves the refund calculations established by the March 26 Order unchanged, although the Order postpones resolution of the fuel cost allowance issues until later. Thus PSE’s filing to seek recovery of its actual fuel costs above the amount set using the “Staff methodology” remains pending. On May 21, 2003, the “California Parties” filed a motion to reject all fuel cost adjustment filings, including the filing made by PSE. 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. PSE anticipates that the net results of the re-run and the application of the refund calculation will extinguish the CAISO receivable apart from the amount associated with the two non-spot market transactions described in 1 above. |
| 3. | Pacific Northwest Refund Proceeding.On June 25, 2003, FERC issued an order terminating the Pacific Northwest refund proceeding, Docket EL01-10, 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. |
| 4. | Orders to Show Cause.On June 25, 2003, FERC issued two show cause orders pertaining to its Western market investigations that commenced individual proceedings against many sellers. One show cause proceeding seeks to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE is not named in that show cause order. The second show cause proceeding seeks to investigate approximately 55 entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE is one of the entities named in the “gaming” show cause order. Consistent with the show cause orders’ invitation to attempt settlement, PSE and FERC Staff filed a proposed settlement of all issues pending against PSE in those proceedings on August 28, 2003. The proposed settlement, which admits no wrongdoing on the part of PSE, would result in a payment of approximately $17,000 to settle all claims. The California Parties and a few others filed oppositions to PSE’s settlement (and all others) on September 30, 2003. PSE replied to those arguments on October 20, 2003. PSE continues to believe that the orders to show cause do not raise new issues or concerns or will have a material adverse impact on the financial condition, results of operation or liquidity of the Company. The presiding Administrative Law Judge is expected to determine whether to recommend the settlements to FERC before the end of the year. |
| 5. | 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. There is no established timetable for this proceeding, but FERC 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. |
| 6. | Port of Seattle Suit.On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle 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 has moved to dismiss this case; other defendants have moved to transfer the matter to a multi-district litigation panel in California. A conditional transfer order was issued in July 2003. PSE’s motion to dismiss remains on the docket but further proceedings are on hold pending determination of the multi-district litigation panel on or after November 20, 2003. |
| 7. | California Litigation.San Diego Cases.No material developments have occurred in the two San Diego class actions since previous reports. The plaintiffs allege that all wholesale sellers in the California energy market engaged in anti-competitive behavior in violation of California Business Practices Act. The motions to dismiss, and the appeals of the remand orders, remain pending.Attorney General Case. No material developments have occurred in the California Attorney General suit against PSE since previous reports. The suit filed against a number of sellers, including PSE, alleges that PSE failed to file rates for sales to the CAISO in advance of transactions and thereby violated the California Business Practices Act. The appeal of the order of dismissal remains pending. |
Other
On April 30, 2003, PSE filed its Least Cost Plan with the Washington Commission. This document provides a high level, diversified resource strategy to meet the Company’s growing energy needs. The Least Cost Plan was developed in consultation with numerous external key stakeholders, including staff of the Washington Commission. A Least Cost Plan Update was filed on August 29, 2003, which incorporated new information on conservation resource potentials. On October 3, 2003, the Washington Commission sent the Company a letter formally accepting the Company’s Least Cost Plan as meeting the Washington Commission’s requirements. The Company’s next Least Cost Plan filing is due by May 1, 2005.
On September 14, 2003, NorthWestern Corporation (NorthWestern) filed a voluntary petition for relief under Chapter 11 of the U. S. Bankruptcy Code. PSE has several long-term contracts with NorthWestern under which PSE jointly owns facilities or purchases power or transmission services from NorthWestern. NorthWestern has indicated that it plans to continue to perform under those contracts.
PSE and Western Energy Company, the supplier of coal to PSE’s Colstrip power plants, are engaged in a dispute and binding arbitration process concerning the price of coal that PSE will pay under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The parties are over $1 per ton apart on their view as to the proper price for coal under that contract, and the arbitration would resolve that question in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. A $1 per ton increase or decrease in the price of coal would have a corresponding effect on PSE’s costs of approximately $1.4 million annually and if the price were retroactive to July 30, 2001, the corresponding effect on power costs would be $3.2 million. Fuel supply costs for electric generation after July 1, 2002 are a part of PSE’s power cost adjustment mechanism.
In October 2003, PSE received notice from Western Energy Company that the Montana Department of Revenue is alleging underpayment of royalties on coal purchased by PSE from Western Energy Company from 1997 to 2000. PSE used the coal as fuel for its Colstrip Units 3 & 4 generating plants. The dispute is likely to lead to a more formal process or litigation to review those purchases and to determine whether PSE may owe more royalties, taxes or penalties. The Montana Department of Revenue seeks a payment of approximately $1.1 million plus applicable Montana State taxes on such payments. PSE will defend this claim vigorously. PSE cannot predict the outcome of this issue at this early date.
In 2003 the Colville Confederated Tribes presented a claim to Douglas County PUD based upon allegedly due past annual charges for the Wells Hydroelectric Project for the use of Colville tribal lands. The Tribes claimed that annual charges would also be due for periods into the future. Since April of 2003, Douglas PUD and Colville representatives have discussed settlement of this issue. The settlement discussions may lead to a resolution of the claim. PSE purchases 31.3% of the power generated by the Wells Project. A settlement of this claim could affect the amount of energy PSE receives under the terms of PSE’s purchased electricity contract or the price of the output of the Wells Hydroelectric Project purchased by PSE.
White River Hydroelectric Generation Project, FERC No. 2494 (the Project).The Project was built in 1911 by PSE and has been in continuous operation ever since. The Project generates electricity to serve PSE’s retail electric customers with an annual average output of approximately 35 megawatts. In 1983, the Company applied for an original FERC License for this Project. In December of 1997, FERC issued a proposed license that was appealed by the Company and various natural resource agencies. The Company appealed the license because it contained terms and conditions that would render ongoing operations of the Project uneconomic relative to alternative resources. In 1998, 2001 and in 2003 FERC granted a stay of the license order (and related appeals) to afford interested parties the opportunity for settlement negotiations. This stay expires in January of 2004. If settlement has not been reached by the end of the stay, in order to keep the Project in operation the Company would likely be required to implement the license order pending FERC’s disposition of the Company’s appeal. Implementation of the license order would require the Company to make capital expenditures and incur annual operating costs that would make the project uneconomic. The Company has concluded that it is unlikely that a settlement addressing the deficiencies of the 1997 FERC license will be reached before the stay expires, and anticipates advising FERC in January that it intends to withdraw its license application and retire the Project. To this end, the Company is negotiating with a consortium of municipalities interested in acquiring the Project as a source for a municipal water supply. The Company is also discussing an interim “non-power” operations agreement with the U.S. Army Corps of Engineers. This interim agreement would address the Corps’ interest in keeping the Project’s diversion dam in operation and thereby facilitate the Corps’ ongoing responsibilities to provide fish passage for the Corps’ upstream flood control project (Mud Mountain Dam). Keeping the Project in operation is also a matter of importance to the surrounding community that wants to preserve the reservoir for financial, recreational and aesthetic purposes. The outcome of these various negotiations and discussions is uncertain at this time, as is the magnitude of any financial impact on the Company associated therewith. However, in any event, it is unlikely that the Project will be in service as a generation resource of the Company after January of 2004. As a result, PSE will petition the Washington Commission for an accounting order in the fourth quarter of 2003. This petition will request authorization for the appropriate accounting and rate making disposition of this Project to be retired. At September 30, 2003, the White River Project’s net book value totals $69.0 million, which includes $47.6 million of net utility plant, $15.0 million of capitalized FERC licensing costs and $6.4 million of costs related to construction work in progress.
Item 3.Quantitative and Qualitative Disclosure About Market Risk
The Company is exposed to market risks, including changes in commodity prices and interest rates.
Portfolio Management.The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted resources does expose the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk management function monitors and manages these risks using analytical models and tools. The Company manages its energy supply portfolio to achieve three primary objectives:
| | • | Ensure that physical energy supplies are available to serve retail customer requirements; |
| | • | Manage portfolio risks to limit undesired impacts on the Company’s costs; and |
| | • | Optimize the value of the Company’s energy supply assets. |
The portfolio is subject to major sources of variability (e.g., hydro generation, outage risk, regional economic factors, temperature-sensitive retail sales, and market prices for gas and power supplies). At certain times, these sources of variability can mitigate portfolio imbalances; at other times they can exacerbate portfolio imbalances.
The Company’s energy risk management staff develops hedging strategies for the Company’s energy supply portfolio. The first priority is to obtain reliable supply for delivery to the Company’s retail customers. The second priority is to protect against unwanted risk exposure. The third priority is to optimize excess capacity or flexibility within the wholesale portfolio. Most hedges can be implemented in ways that retain the Company’s ability to use its energy supply optimization opportunities. Other hedges are structured similarly to insurance instruments, where PSE pays an insurance premium to protect against certain extreme conditions.
Portfolio exposure is managed in accordance with Company polices and procedures. The Risk Management Committee, which is composed of Company officers, provides policy level and strategic direction for management of the energy portfolio. The Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee.
The prices of energy commodities are subject to fluctuations due to unpredictable factors including weather, generation outages and other factors which impact supply and demand. The volumetric and commodity price risk is a consequence of purchasing energy at fixed and variable prices and providing deliveries at different tariff and variable prices. Costs associated with ownership and operation of production facilities are another component of this risk. The Company may use forward physical delivery agreements and financial derivatives for the purpose of hedging commodity price risk. Without jeopardizing the security of supply within its portfolio, the Company will also engage in optimizing the portfolio. Optimization may take the form of utilizing excess capacity, shaping flexible resources to capture their highest value, utilizing transmission capacity or capitalizing on market price movement. As a result, portions of the Company’s energy portfolio are monetized through use of forward price instruments.
The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility upon the Company. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. The PCA mechanism provides for a sharing of costs and benefits that are graduated over four levels of power cost variances with an overall cap of $40 million (+/-) plus 1% of the excess over the $40 million cap over the four year period ending June 30, 2006.
Transactions that qualify as hedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, are recorded on the balance sheet at fair value. Changes in fair value of the Company’s derivatives are recorded each period in current earnings or other comprehensive income. Short-term derivative contracts for the purchase and sale of electricity are valued based upon daily quoted prices from an independent energy brokerage service. Valuations for short-term and medium-term natural gas financial derivatives are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas financial derivatives are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using market quotes and a Monte Carlo simulation-based model approach.
At September 30, 2003, the Company had an after-tax net asset of approximately $13.0 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain amount in other comprehensive income. The Company also had energy contracts that were marked-to-market through current earnings for the third quarter of 2003 of $0.6 million after-tax. A hypothetical 10% increase in the market prices of natural gas and electricity would increase the fair value of qualifying cash flow hedges by approximately $9.9 million after-tax and would increase current earnings for those contracts marked-to-market in earnings by $0.6 million after-tax.
Interest Rate Risk.The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate leases and long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company does utilize bank borrowings, commercial paper and line of credit facilities to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments to manage the interest rate risk associated with these debts but did not have any swap instruments outstanding as of September 30, 2003.
Item 4.Controls and Procedures
Evaluation of disclosure controls and procedures.Under the supervision and with the participation of Puget Energy’s and PSE’s management, including the Companies’ Chief Executive Officer and Chief Financial Officer, Puget Energy and PSE have evaluated the effectiveness of the Companies’ disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the fiscal quarter covered by this report. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer of Puget Energy and PSE concluded that these disclosure controls and procedures are effective as of the end of the quarter.
Changes in internal controls over financial reporting.There have been no significant changes in Puget Energy’s or PSE’s internal control over financial reporting during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, Puget Energy’s or PSE’s internal control over financial reporting.
PART II OTHER INFORMATION
Item 1.Legal Proceedings
See the section titled “Proceedings Relating to the Western Power Market” under Item 2 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” of this Quarterly Report on Form 10-Q.
Contingencies arising out of the normal course of the Company’s business exist at September 30, 2003. The ultimate resolution of these issues in part or in the aggregate is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.
| Item | 6. | | Exhibits and Reports on Form 8-K |
| | (a) | | See Exhibit Index for list of exhibits. |
| | | | |
| | (b) | | Reports on Form 8-K |
| | | | |
| | | | Filed by Puget Energy & Puget Sound Energy: |
| | | | |
| | | | Form 8-K dated July 23, 2003, Item 9 - Regulation FD Disclosure, related to the release of the second quarter earnings. |
| | | | |
| | | | Form 8-K dated September 2, 2003, Item 5 - Other Events, related to settlement agreement regarding FERC's June 25, 2003 show cause order. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
| | PUGET ENERGY, INC.
PUGET SOUND ENERGY, INC.
|
| | /S/ JAMES W. ELDREDGE
|
| | James W. Eldredge
Corporate Secretary and Chief Accounting Officer |
| | |
| Date: November 12, 2003 | Chief accounting officer and officer duly authorized
to sign this report on behalf of each registrant |
EXHIBIT INDEX
The following exhibits are filed herewith:
| | 12.1 | Statement setting forth computation of ratios of earnings to fixed charges (1998 through 2002 and 12 months ended September 30, 2003) for Puget Energy. |
| | 12.2 | Statement setting forth computation of ratios of earnings to fixed charges (1998 through 2002 and 12 months ended September 30, 2003) for PSE. |
| | 31.1 | Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 31.2 | Chief Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 31.3 | Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 31.4 | Chief Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 32.1 | Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| | 32.2 | Chief Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
