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 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 $25.6 million for the three months ended June 30, 2003 compared to the same period in 2002 primarily as a result of $25.0 million of rate relief in effect only during the interim period of April 1, 2002 through June 30, 2002 and an increase in power costs of $20.8 million which includes the Company’s portion of underrecovered power costs of $7.3 million, and lower margins due to warmer temperatures. These decreases were partially offset by an increase of $17.9 million resulting from the general tariff rate increase effective July 1, 2002. Electric margin increased $22.8 million for the six months ended June 30, 2003 compared to the same period in 2002 primarily due to $27.3 million resulting from the general tariff rate increase effective July 1, 2002 offset by the Company’s portion of underrecovered power costs of $18.9 million. 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 six months ended June 30, 2003 and June 30 2002 is detailed further as follows:
Gas margin increased $6.2 million for the three months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $7.5 million resulting from the 5.8% general gas tariff rate increase effective September 1, 2002. Gas margin increased $5.5 million for the six months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $20.7 million resulting from the 5.8% general gas tariff rate increase effective September 1, 2002 offset by gas therm sales declining 9.9% due to warmer weather. 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 six months ended June 30, 2003 and June 30, 2002 is detailed further as follows:
Gas Margin for the Three and Six Months Ended
June 30, 2003 and June 30 2002
(Dollars in Millions)
| Three Months Ended
June 30
| Six Months Ended
June 30
|
| 2003
| 2002
| 2003
| 2002
|
| Gas retail revenue | | | $ | 110 | .7 | $ | 138 | .6 | $ | 292 | .1 | $ | 447 | .4 |
| Gas transportation revenue | | | | 3 | .4 | | 3 | .0 | | 6 | .8 | | 5 | .9 |
|
| Total gas revenue for margin | | | | 114 | .1 | | 141 | .6 | | 298 | .9 | | 453 | .3 |
| Adjustments for amounts included in revenue: | | |
| Gas revenue hedge | | | | | -- | | | -- | | 0 | .2 | | | -- |
| Pass-through tariff items | | | | (0 | .8) | | (0 | .3) | | (2 | .4) | | (0 | .6) |
| Pass-through revenue-sensitive taxes | | | | (9 | .7) | | (12 | .8) | | (24 | .6) | | (37 | .1) |
|
| Net gas revenue for margin | | | | 103 | .6 | | 128 | .5 | | 272 | .1 | | 415 | .6 |
| Minus Purchased Gas Costs | | | | (57 | .4) | | (88 | .5) | | (144 | .3) | | (293 | .3) |
|
| Gas Margin | | | $ | 46 | .2 | $ | 40 | .0 | $ | 127 | .8 | $ | 122 | .3 |
|
Operating Revenues — Electric
Electric operating revenues for the three months ended June 30, 2003 were $348.2 million, an increase of $32.1 million compared to the same period in 2002 due primarily to wholesale electric sales to other utilities and marketers which increased $40.2 million due to greater surplus volumes due in part to hedging expected hydro shortfall in energy production and higher prices in the wholesale electricity market. In February 2003, the National Rivers Forecast Center predicted streamflows in the Columbia River Basin would be approximately 76% of normal while actual streamflows were approximately 89% for the six months ended June 30, 2003, resulting in additional hydro production. Wholesale sales volumes increased by 1.0 billion kWh or 129.2% to 1.8 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 a reduction in retail sales and additional hydro production creating excess energy supply. Temperatures based on heating-degree-days measured at Seattle-Tacoma airport during the three month period ended June 30, 2003 were about normal, while second quarter 2002 temperatures were 12% colder than normal. Retail sales revenue decreased $7.7 million due primarily to $25 million of interim rate relief ended June 30, 2002 offset by the effect of a 4.6% electric general rate increase effective July 1, 2002 that increased electric revenue by approximately $17.9 million in 2003. Retail sales volume increased 1.7% to 4.5 billion kWh from 4.4 billion kWh for the same period in 2002.
Electric operating revenues for the six months ended June 30, 2003 were $765.2 million, an increase of $85.8 million compared to the same period in 2002 due primarily to wholesale electric sales to other utilities and marketers which increased $80.4 million due to greater surplus volumes due in part to hedging expected hydro shortfall in energy production and higher prices in the wholesale electricity market. Wholesale sales volumes increased by 1.7 billion kWh or 127.6% to 3.1 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 a reduction in retail sales and additional hydro production creating excess energy supply. Temperatures based on heating-degree-days measured at Seattle-Tacoma airport during the six month period ended June 30, 2003 were 4.7% warmer than normal as compared to heating-degree-days being 9.2% cooler than normal during the six month period ended June 30, 2002. Retail sales revenue decreased $14.8 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 $27.3 million in 2003. Retail sales volume decreased 0.8% to 9.8 billion kWh from 9.9 billion kWh for the same 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 cost through June 30, 2003 was $24.1 million, $18.9 million of which was incurred in the first six months of 2003. Utility customers’ share of the costs, which were deferred for later recovery, through June 30, 2003 was $4.1 million, all of which was incurred in the second quarter of 2003. The factors influencing the variability of power costs included in the proposal are primarily weather and market related.
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 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 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 will defer paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred will be $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA is entering into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA are agreeing to BPA’s deferral of payments in their fiscal year 2003. The total cumulative amount to be deferred under the agreement with PSE and other such agreements equals $55 million, an amount that will help BPA address its current financial difficulties. Absent certain adjustments, BPA will begin paying back the amount deferred with interest over the sixty-month period beginning October 2006. In January 2003, PSE filed revised tariff sheets with the Washington Commission to reflect this modification to the agreement between PSE and the 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 for adjusting the rate which will affect the level of residential exchange benefits for PSE’s customers. However, the actual rate level adjustment BPA expects to put into effect October 1, 2003 has not yet been established.
For the three and six months ended June 30, 2003, the benefits of the Residential and Farm Energy Exchange credited to customers were $38.7 million and $93.8 million, respectively, with a related offset to power costs. PSE received payments from BPA in the amount of $33.5 million and $70.5 million during the three and six months ended June 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, 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 farm customers.
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 on an interim basis, subject to refund with interest. It is not clear what impact, if any, review of such rates and the above-described U.S. Ninth Circuit Court of Appeals actions may have on PSE. PSE and other investor owned utilities are presently negotiating a potential settlement of the U.S. Ninth Circuit actions, whereby the litigation would be dismissed and BPA’s discretion over the level of 2007-2011 benefits would be reduced in consideration of a reduction in current period benefits. PSE cannot presently predict the outcome of the settlement negotiations.
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 three and six months ended June 30, 2003, PSE collected in its electric general rate tariff and remitted to a grantor trust $3.8 million and $7.7 million as compared to $2.7 million and $5.8 million for the same periods 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 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. PSE received a payment of approximately $1.3 million on the amount owed in the second quarter of 2003. At June 30, 2003, PSE’s receivable from the California Independent System Operators (CAISO) and other counter-parties, net of reserves, was $24.1 million.
Operating Revenues — Gas
Retail gas revenue for the three and six month periods ended June 30, 2003 decreased by $27.9 million and $154.3 million from the same periods in 2002, respectively, which included the effect of a 5.8% gas general rate increase effective September 1, 2002 that increased gas revenue by approximately $7.5 million and $20.7 million for the three and six month periods ended June 30, 2003, respectively. Retail gas sales volumes decreased 7.4% from 158.5 million therms for the three months ended June 30, 2002 to 146.8 million therms for the three months ended June 30, 2003 and decreased 13.0% from 505.5 million therms for the six months ended June 30, 2002 to 440.0 million therms for the six months ended June 30, 2003 due primarily to warmer temperatures in the Pacific Northwest.
Purchased Gas Adjustment (PGA) rates charged to customers were lower in the three and six month periods ended June 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. Gas supply costs are passed through to customers in the PGA. 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 $63.7 million and $122.1 million for the three and six month periods ended June 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 July 9, 2003 seasonal water supply forecast published by the National Weather Service indicated that the total forecast runoff into the Grand Coulee reservoir for the period January through July 2003 would be 89% of normal. This compares to 108% of normal for the same period in 2002. The National Weather Service forecast runoff into the Grand Coulee reservoir for the later period of April through September 2003 is similar to the January through July 2003 period and is expected to be 88% of normal. Primarily due to adverse hydro conditions in 2003, the Company anticipates reaching the $40 million cumulative cap under the PCA mechanism by the end of 2003. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE. PSE’s share of power costs, in excess of those set in rates, through June 30, 2003 was $24.1 million.
Purchased gas expenses decreased $31.1 million and $149.0 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002. The decrease was due to lower consumption volumes as a result of warmer than normal temperatures and the impact of decreased gas costs, which are 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 June 30, 2002 of $91.4 million compared to a liability balance at June 30, 2003 of $14.3 million.
Electric generation fuel expense decreased $3.6 million and $53.7 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to lower fuel costs for PSE controlled gas-fired generation facilities related to economic dispatch of those facilities.
Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA increased $6.0 million and $15.9 million for the three and six month periods ended June 30, 2003 when compared to the same periods in 2002, due to an increase in the Residential and Farm Energy Exchange credit rate in 2002. For further details, see the amended Residential Purchase and Sale Agreement between PSE and BPA discussion in Operating Revenues – Electric.
Unrealized gains on derivative instruments decreased $0.2 million and $11.2 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to changes in the market value of derivative instruments. During the three months ended June 30, 2003 and 2002, the Company recorded an increase in earnings for the change in the market value of derivative instruments not meeting cash flow hedge criteria of approximately $44 thousand pre-tax ($29 thousand after-tax) and $0.3 million pre-tax ($0.2 million after-tax), respectively. During the six months ended June 30, 2003 and 2002, the Company recorded an increase in earnings of approximately $0.5 million pre-tax ($0.3 million after-tax) and $11.7 million pre-tax ($7.6 million after-tax), respectively. The $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 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 $30.7 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 maintenance cost decreased $2.9 million and $2.7 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 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’sPersonal Energy ManagementTM energy-efficiency program costs decreased $1.5 million and $3.8 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002, reflecting a decreased emphasis on the program in light of relatively moderate energy prices and cancellation of the Time of Use program in November 2002.
A newLow-income Program approved by the Washington Commission in the general rate case settlement began in July 2002 which resulted in increased costs of $1.8 million and $4.6 million for the three and six months ended June 30, 2003 compared to the same periods in 2002. These costs are fully recovered in retail rates beginning at the program’s inception on July 1, 2002 for electric and September 1, 2002 for gas.
Other utility operations and maintenance costs increased $2.9 million for the three months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $1.7 million of energy resources strategic planning and acquisition costs, $1.6 million in administrative and general costs, and $1.1 million of customer accounts and sales expenses, offset by a decrease of $2.5 million related to outsourcing certain operation work which did not recur in 2003. Other utility operations and maintenance costs increased $6.3 million for the six months ended June 30, 2003 compared to the same period in 2002 due primarily to an increase of $2.5 million of electric and gas system operations and maintenance costs, $2.2 million of energy resources strategic planning and acquisition costs, $3.5 million in administrative and general costs, and $2.4 million of customer accounts and sales expenses, offset by a decrease of $4.5 million of severance and benefits costs related to outsourcing certain operation work which did not recur in 2003.
Depreciation and amortizationexpense for PSE increased $0.6 million and $1.5 million for the three and six months ended June 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 amortization expense increased $2.7 million and $8.2 million for the three and six months ended June 30, 2003 compared to the same periods in 2002 due to increased conservation expenditures. These costs are recovered in an electric conservation rider and a gas conservation tracker mechanism with no impact to earnings.
Taxes other than income taxes decreased $6.1 million and $14.4 million for the three and six months ended June 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 reduction recorded in the second quarter of 2003 of $1.4 million of amounts previously accrued as expense.
Income taxes decreased $9.1 million for the three months ended June 30, 2003 compared to the same period in 2002 as a result of lower pre-tax operating income and a one-time $6.2 million tax benefit related to a favorable resolution of a federal income tax matter from 1997 to 2002. Income taxes increased $5.1 million for the six months ended June 30, 2003 compared to the same period in 2002 as a result of higher pre-tax operating income, offset by the $6.2 million reduction described above.
Interest Charges
Interest charges decreased $2.5 million for the three months ended and $5.5 million for the six months ended June 30, 2003 compared to the same periods in 2002. Interest on long-term debt decreased $4.1 million for the three months ended and $6.2 million for the six months ended June 30, 2003, compared to the same periods in 2002. This is primarily a result of the maturity of $107 million of Medium Term Notes with interest rates ranging from 7.07% to 7.91% during the third and fourth quarter of 2002 and the redemption of $19.7 million of 8.231% Capital Trust I Preferred Securities in February 2003, and $60 million in Medium Term Notes with interest rates ranging from 8.2% to 8.59% in May 2003.
InfrastruX
The table below sets forth changes in the results of operations for InfrastruX, net of minority interest.
Comparative Three and Six Months Ended
June 30, 2003 vs. June 30, 2002
Increase (Decrease)
(Dollars in Millions)
| Three
Month
Period
| Six
Month
Period
|
| Operating revenue change: | | | | | | | | |
| Other operating revenue | | | $ | 16 | .2 | $ | 26 | .1 |
|
| Operating expense changes: | | |
| Other operations and maintenance | | | | 15 | .2 | | 31 | .4 |
| Depreciation and amortization | | | | 1 | .3 | | 2 | .4 |
| Taxes other than income taxes | | | | (0 | .7) | | 0 | .1 |
| Income taxes | | | | 0 | .3 | | (3 | .5) |
|
| Total operating expense change | | | | 16 | .1 | | 30 | .4 |
| Other Income (net of tax) change | | | | 0 | .0 | | (0 | .1) |
| Interest charges change | | | | (0 | .2) | | 0 | .1 |
| Minority interest change | | | | 0 | .1 | | (0 | .4) |
|
| Net income change | | | $ | 0 | .2 | $ | (4 | .1) |
|
The following is additional information pertaining to the changes outlined in the above table.
InfrastruX revenueincreased $16.2 million and $26.1 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due primarily to acquisitions of several companies during 2002 and 2003, which contributed an increase of $11.8 million and $24.8 million, respectively. Existing company revenues increased for the six month period ended June 30, 2003, but were adversely impacted by severe winter weather and snow accumulation in the Northeast and Midwest and by extremely wet winter conditions in the South, resulting in a significant slowdown in utility construction work. InfrastruX operations are seasonal, with its highest revenues typically in the second and third quarters of the year.
InfrastruX operation and maintenance expenses increased $15.2 million and $31.4 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to the additional costs related to acquired companies and weather-related problems in the first half of 2003 that impacted efficiency and productivity.
Depreciation and amortization expense increased by $1.3 million and $2.4 million for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 due to acquisitions during 2002 and additional assets placed in service to support growth.
Income taxes increased $0.3 million the three month period ended June 30, 2003 compared to the same period in 2002 due primarily to operating income contributed from acquired companies. Income taxes decreased $3.5 million for the six month period ended June 30, 2003 compared to the same period in 2002 due primarily to the tax benefit associated with the first quarter 2003 net loss.
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 June 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 (1) | | | $ | 2,276 | .8 | $ | 45 | .9 | $ | 306 | .2 | $ | 211 | .3 | $ | 1,713 | .4 |
| Short-term debt | | | | 53 | .4 | | 53 | .4 | | | -- | | | -- | | | -- |
| Trust preferred securities (2) | | | | 280 | .3 | | | -- | | | -- | | | -- | | 280 | .3 |
| Mandatorily redeemable preferred stock (3) | | | | 36 | .3 | | 34 | .4 | | | -- | | | -- | | 1 | .9 |
| Preferred dividends (4) | | | | 1 | .1 | | 1 | .1 | | | -- | | | -- | | | -- |
| Service contract obligations | | | | 180 | .5 | | 9 | .7 | | 40 | .7 | | 43 | .4 | | 86 | .7 |
| Capital lease obligations | | | | 25 | .8 | | 3 | .7 | | 13 | .5 | | 7 | .5 | | 1 | .1 |
| Non-cancelable operating leases | | | | 70 | .6 | | 9 | .4 | | 30 | .3 | | 20 | .5 | | 10 | .4 |
| Fredonia combustion turbines lease (5) | | | | 71 | .9 | | 2 | .3 | | 8 | .9 | | 8 | .6 | | 52 | .1 |
| Energy purchase obligations | | | | 4,780 | .5 | | 479 | .7 | | 1,300 | .1 | | 931 | .0 | | 2,069 | .7 |
| Financial hedge obligations | | | | (24 | .4) | | (8 | .5) | | (10 | .1) | | (4 | .8) | | (1 | .0) |
|
| Total contractual cash obligations | | | $ | 7,752 | .8 | $ | 631 | .1 | $ | 1,689 | .6 | $ | 1,217 | .5 | $ | 4,214 | .6 |
| | Amount of Commitment
Expiration Per Period
|
|---|
Commercial Commitments
(Dollars in millions)
| Total
| 2003
| 2004-2005
| 2006-2007
| 2008 and
Thereafter
|
| Guarantees (6) | | | $ | 135 | .0 | $ | | -- | $ | 135 | .0 | $ | | -- | $ | | -- |
| Liquidity facilities - available (7) | | | | 290 | .9 | | 209 | .5 | | 81 | .4 | | | -- | | | -- |
| Lines of credit - available (8) | | | | 29 | .6 | | 2 | .9 | | 16 | .7 | | 10 | .0 | | | -- |
| Energy operations letter of credit (9) | | | | 0 | .5 | | | -- | | 0 | .5 | | | -- | | | -- |
|
| Total commercial commitments | | | $ | 456 | .0 | $ | 212 | .4 | $ | 233 | .6 | $ | 10 | .0 | $ | | -- |
| (1) | The 2003 long-term debt includes $3 million in first mortgage bonds that had a maturity date in 2023, which were called for redemption by PSE in April 2003. The redemption date is scheduled for August 2003. |
| (2) | In 1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling preferred securities (Trust Securities) and 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. During the first quarter of 2003, PSE repurchased $19.7 million of the Trust Securities. |
| (3) | On July 14, 2003, PSE called outstanding shares of the mandatorily redeemable 7.75% Series Cumulative Preferred Stock, which will be redeemed on August 15, 2003. The redemption price will be $102.07 per share plus accrued dividends. |
| (4) | On April 4, 2003, the Board of Directors of PSE declared a dividend payable on July 1, 2003 for preferred stock outstanding on June 13, 2003. |
| (5) | See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below. |
| (6) | In June 2001, InfrastruX signed a credit agreement with several banks to provide up to $150 million in financing. Under the credit agreement, Puget Energy is the guarantor of the line of credit. |
| (7) | At June 30, 2003, PSE had available a $250 million unsecured 364-day credit agreement and $81.4 million in a receivable securization facility which provides credit support for outstanding commercial paper totaling $40 million and an outstanding letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under this liquidity facility to $290.9 million. At June 30, 2003, the Company had available $81.4 million of receivables for sale under its three year $150.0 million receivables securitization facility. See “Accounts Receivable Securitization Program” under “Off-Balance Sheet Arrangements” below. |
| (8) | Puget Energy has a $15 million line of credit with a bank. Currently, $5 million is outstanding, reducing the available borrowing capacity under this line of credit to $10 million. InfrastruX has $179.1 million in lines of credit with various banks, including the $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 $155.4 million and letters of credit of $4.1 million, effectively reducing the available borrowing capacity under these lines of credit to $19.6 million. |
| (9) | 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 June 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 (1) | | | $ | 2,133 | .9 | $ | 45 | .0 | $ | 169 | .5 | $ | 206 | .0 | $ | 1,713 | .4 |
| Short-term debt | | | | 33 | .0 | | 33 | .0 | | | -- | | | -- | | | -- |
| Trust preferred securities (2) | | | | 280 | .3 | | | -- | | | -- | | | -- | | 280 | .3 |
| Mandatorily redeemable preferred stock (3) | | | | 36 | .3 | | 34 | .4 | | | -- | | | -- | | 1 | .9 |
| Preferred dividends (4) | | | | 1 | .1 | | 1 | .1 | | | -- | | | -- | | | -- |
| Service contract obligations | | | | 180 | .5 | | 9 | .7 | | 40 | .7 | | 43 | .4 | | 86 | .7 |
| Non-cancelable operating leases | | | | 51 | .8 | | 5 | .5 | | 19 | .2 | | 17 | .7 | | 9 | .4 |
| Fredonia combustion turbines lease (5) | | | | 71 | .9 | | 2 | .3 | | 8 | .9 | | 8 | .6 | | 52 | .1 |
| Energy purchase obligations | | | | 4,780 | .5 | | 479 | .7 | | 1,300 | .1 | | 931 | .0 | | 2,069 | .7 |
| Financial hedge obligations | | | | (24 | .4) | | (8 | .5) | | (10 | .1) | | (4 | .8) | | (1 | .0) |
|
| Total contractual cash obligations | | | $ | 7,544 | .9 | $ | 602 | .2 | $ | 1,528 | .3 | $ | 1,201 | .9 | $ | 4,212 | .5 |
| | Amount of Commitment
Expiration Per Period
|
|---|
Commercial Commitments
(Dollars in millions) | Total | 2003 | 2004-2005 | 2006-2007 | 2008 and
Thereafter |
|
| Liquidity facilities - available (6) | | | $ | 290 | .9 | $ | 209 | .5 | $ | 81 | .4 | $ | | -- | $ | | -- |
| Energy operations letter of credit (7) | | | | 0 | .5 | | | -- | | 0 | .5 | | | -- | | | -- |
|
| Total commercial commitments | | | $ | 291 | .4 | $ | 209 | .5 | $ | 81 | .9 | $ | | -- | $ | | -- |
(1) See note (1) above.
(2) See note (2) above.
(3) See note (3) above.
(4) See note (4) above.
(5) See note (5) above.
(6) See note (7) above.
(7) See note (9) above.
Off-Balance Sheet Arrangements
Conservation Trust.In 1995, PSE sold a stream of future electric revenues associated with $202.3 million of its investment in conservation assets in its electric general rate tariff to a grantor trust in order to obtain financing at rates superior to those otherwise available. As a result of this sale, PSE collects these revenues from its electric customers and remits them to the trust. During the three months ended June 30, 2003, PSE collected and remitted to the grantor trust $3.8 million as compared to $2.7 million for the same period in 2002. 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. Under Financial Accounting Standards Board Interpretation Number 46, “Consolidation of Variable Interest Entities,” PSE will begin consolidating the Conservation Trust in July 2003.
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.
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 June 30, 2003 there were no amounts outstanding under the accounts receivable securitization facility and the maximum receivables available for sale was $81.4 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. Payments under the lease vary with changes in the London inter-bank offered rate (LIBOR). At June 30, 2003, PSE’s outstanding balance under the lease was $60.2 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 $134.6 million for the six months ended June 30, 2003. PSE expects construction expenditures will be approximately $272 million, $325 million and $280 million in 2003, 2004 and 2005, respectively. In addition, PSE anticipates spending up to $250 million for new generating resources in 2004, subject to regulatory approval of the resources and related new revenue requirements. The purchase of any generating resource would be funded through the issuance of long-term debt and equity. PSE may arrange short-term bridge financing for the resources pending the sale of equity and long-term debt. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.
Other Additions.Other property, plant and equipment additions were $6.8 million for the six months ended June 30, 2003. Puget Energy expects InfrastruX’s capital additions to be $16.6 million in 2003. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental, and conservation factors.
Refinancings. PSE refinanced $138.5 million of its outstanding 5.875% to 7.25% series of Pollution Control Bonds on March 11, 2003. The remaining $23.4 million of outstanding 5.875% series Pollution Control bonds was refinanced on April 1, 2003. These outstanding Pollution Control Bonds were refinanced with the proceeds from the issuance of two new series of Pollution Control Bonds: (1) $138.5 million 5.00% series and (2) $23.4 million 5.10% series. Each of these new series of Pollution Control Bonds matures on March 1, 2031.
Capital Resources
Cash From Operations.Cash generated from operations for the six month period ended June 30, 2003 was $154.5 million. During the period, $44.9 million in cash was used for AFUDC and payment of dividends. Consequently, cash available for utility construction expenditures and other capital expenditures was $109.6 million or 73.3% of the $149.5 million in construction expenditures (net of AFUDC) and other capital expenditure requirements for the period. For the same period in 2002, cash generated from operations was $436.0 million, $57.0 million of which was used for AFUDC and payment of dividends. Therefore, cash available for utility construction expenditures and other capital expenditures for the six month period ended June 30, 2002 was $379.0 million. The reduction in cash generated from operations from 2002 is primarily due to refunds reducing the PGA balance. In the six months ended June 30, 2002, PSE received $128.6 million in excess of actual gas costs from customers through the PGA mechanism compared to refunds to customers through the PGA mechanism of $69.5 million for the six months ended June 30, 2003. In addition, cash outflows increased $7.9 million in 2003 due to injection of gas into storage facilities as compared to cash inflows of $29.0 million in 2002 due to withdrawals of gas from storage facilities for a total decrease in cash flow of $36.9 million. Cash from accounts receivables and unbilled revenues decreased by $17.3 million due primarily to 9.2% colder than normal temperatures in the six months ended June 30, 2002 compared to near normal temperatures in 2003.
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 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 June 30, 2003, PSE could issue:
| • | approximately $774.2 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 June 30, 2003 was 2.7 times net earnings available for interest which would allow issuance of approximately $855.4 million of additional first mortgage bonds, at an assumed interest rate of approximately 6% on a ten-year first mortgage bond; |
| • | approximately $342.2 million of additional preferred stock at an assumed dividend rate of 7.75%; and |
| • | approximately $272.9 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 August 7, 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 the $500 million 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.
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, 2002, Puget Energy sold 5.75 million shares of common stock in a public offering. The net proceeds of approximately $114.6 million were invested in PSE to reduce its debt. On June 4, 2003, PSE issued $150 million of 3.363% Senior Notes, which have a maturity date of June 1, 2008. Proceeds were used to retire long term debt. Approximately $230 million of securities remain available for issuance under the shelf registration as of June 30, 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.
On December 23, 2002, PSE entered into a $250 million unsecured 364-day credit agreement with various banks and a $150 million 3-year receivables securitization program. At June 30, 2003, PSE had available $250 million in the unsecured credit agreement and $81.4 million in the receivable securitization facility, which provide credit support for outstanding commercial paper of $40 million and outstanding letters of credit of $0.5 million, effectively reducing the available borrowing capacity under the liquidity facilities to $290.9 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 $29.1 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 June 30, 2003, InfrastruX and its subsidiaries had outstanding loans of $155.4 million and letters of credit of $4.1 million, effectively reducing the available borrowing capacity under these lines of credit to $19.6 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 $3.9 million (176,806 shares) and $7.6 million (369,571 shares) for the three and six months ended June 30, 2003 compared to $3.3 million (165,996 shares) and $9.8 million (470,110 shares) for the same period in 2002. The decrease in the shares issued under the Stock Purchase and Dividend Reinvestment Plan from the six month period ended June 30, 2002 compared to the six month period ended June 30, 2003 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. No shares have been issued under the agreements as of the filing date of this report.
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 quarter ended March 31, 2003 include summaries of the Western power market proceedings described below. This shortened discussion is intended to enhance readability and understanding by providing 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 June 30, 2003 of $24.1 million. PSE received $1.3 million in the second quarter of 2003 relating to CAISO transactions. As previously described, the March 26, 2003, FERC Order on Proposed Findings on Refund Liability in Docket EL00-95 was silent as to the stipulation regarding two PSE “non-spot-market” transactions. The total gross revenue associated with the transactions is approximately $26 million. On April 25, 2003, PSE requested clarification and/or rehearing to confirm those transactions are not subject to refund. No party has resisted PSE’s request. Based upon the order, PSE has estimated a range related to the net CAISO receivable to be between $24.1 million and $25.6 million, including interest on past due amounts. |
| 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. Rehearing of that Order is pending. The March 26 Order also permitted generators that wished to recover fuel costs above the amount set using the “Staff methodology” to submit their actual cost data by May 12, 2003. On May 12, 2003, PSE filed documents to support recovery of its actual fuel costs above the amount set using the “Staff methodology.” On May 21, 2003, the California parties filed a motion to reject all fuel cost adjustment filings, including the filing made by PSE. |
| 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. Based upon public statements by some of the refund claimants, it is likely they will ultimately appeal that order. |
| 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, though the order states additional parties may be added. 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. On July 16, 2003, CAISO provided data to FERC in connection with the gaming show cause order that indicates that, under the standards adopted by FERC in the June 25 orders, CAISO’s previously reported claims against PSE as to “ricochet” transactions completely disappear. PSE believes the remaining claims (“paper trading” and “cut schedules”) pose minimum exposure for PSE. PSE is to respond to the CAISO filing on or before September 2, 2003. The two show cause orders also expressly encourage the parties to settle the cases with FERC staff. PSE expects to explore that opportunity. PSE does not believe that the orders to show cause raise new issues or concerns or will have a material adverse impact on the financial condition, results of operation or liquidity of the Company. |
| 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 for hearing in September 2003. |
| 7. | Washington and Oregon Class Action Cases Regarding Market Manipulation. In December 2002, PSE was named as one of more than 30 defendants in two class actions, one filed in the federal district court in Seattle and the other in Multnomah County Circuit Court in Oregon. The complaints alleged that they were brought on behalf of all retail customers in Washington and Oregon, respectively, and seek relief against the defendants (each of which is a seller of electric energy at wholesale in certain markets) for “unfair or deceptive acts”, “fraud by concealment”, negligence and for an accounting. No specific amount of damages was pled in the complaints. In May 2003, the plaintiffs in both cases filed motions for voluntary dismissal, which were granted later that same month by both courts. Although the motions expressly reserved the right to refile the complaints, no new case by those plaintiffs or law firms has named PSE. |
Other
On March 31, 2003, PSE released for public comment its least-cost plan for meeting customers’ energy needs through a diversified mix of energy supplies. The plan was open for 30 days of public comment before review by the Washington Commission. After incorporating the comments from the Washington Commission staff, key stakeholder groups, and the public, PSE’s plan was filed with the Washington Commission on April 30, 2003 and will be revised in August 2003 to incorporate forthcoming energy-efficiency data. PSE is actively reviewing new generating resources alternatives.
On July 31, 2002, FERC issued its Notice of Proposed Rulemaking on Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The SMD NOPR would have major implications for the delivery of electric energy throughout the U.S if enacted in its proposed form. Major elements of FERC’s proposal include: (a) the use of Network Access Service to replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff; (b) Vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems; (c) The formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. State regulators and industry representatives have pointed out that the western North American electricity market has unique characteristics that may not readily lend itself to the Standard Market Design proposed by FERC. FERC has expressed its willingness to offer regional flexibility in its order on RTO West, Docket Nos. RT01-35-005 and RT01-35-007, issued September 18, 2002. In April 2003, FERC issued a white paper responding to concerns of state regulators regarding the impact of the SMD proposal on the western market. PSE cannot predict the outcome of the SMD NOPR or whether the ultimate resolution will have a material impact on the financial condition, results of operations or liquidity of the Company.
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 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:
(i) Ensure that physical energy supplies are available to serve retail customer requirements;
(ii) Manage portfolio risks to limit undesired impacts on the Company’s financial results and to stabilize earnings; and
(iii) 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 protect against unwanted risk exposure. The second 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. Still 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 delivery agreements, swaps and option contracts 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. Values for short-term and medium-term natural gas swap contracts are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas swap contracts are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using market quotes and a Monte Carlo simulation-based model approach.
At June 30, 2003, the Company had an after-tax net asset of approximately $15.9 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 second quarter of 2003 of $0.4 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 $7.1 million after-tax and would increase current earnings for those contracts marked-to-market in earnings by an immaterial amount.
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 and did not have any swap instruments outstanding as of June 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 Puget Sound Energy’s internal control over financial reporting.
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 June 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 4.Submission of Matters to a Vote of Security Holders
Puget Energy’s annual meeting of shareholders was held on May 13, 2003. At the annual meeting, the shareholders elected three directors to hold office until the annual meeting of shareholders in 2006 or until their successors are elected and qualified. The vote was as follows:
| | Number of Shares |
|---|
| | For
| Withheld
|
|---|
| TERM EXPIRING 2006 | | |
| Douglas P. Beighle | 77,926,652 | 2,276,315 |
| Craig W. Cole | 78,640,366 | 1,562,601 |
| Tomio Moriguchi | 77,983,759 | 2,219,208 |
There were no broker non-votes.
The terms of the following directors continued after the annual meeting:
Charles W. Bingham
Phyllis J. Campbell
Robert Dryden
Kenneth P. Mortimer
Sally G. Narodick
Stephen P. Reynolds
| Item 6. | | Exhibits and Reports on Form 8-K |
| (a) | | See Exhibit Index for list of exhibits. |
| | | Filed by Puget Energy & Puget Sound Energy: |
| | | Form 8-K dated April 23, 2003, Item 9 – Regulation FD Disclosure, related to the release of the first quarter earnings. |
| | | Filed by Puget Sound Energy: |
| | | Form 8-K dated June 6, 2003, Item 5 — Other Events, related to filing Form S-3 for the issuance of $150,000,000 Senior Notes. |
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: August 8, 2003 | Chief accounting officer and officer duly authorized to sign this
report on behalf of each registrant |
The following exhibits are filed herewith:
| 4.1 | Pledge Agreement dated March 11, 2003 between Puget Sound Energy and Wells Fargo Bank Northwest, National Association, as Trustee (incorporated herein by reference to Exhibit 4.24 to the Company’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 dated July 11, 2003, Commission File No. 333-82940-02) |
| 4.2 | Loan Agreement dated as of March 1, 2003, between the City of Forsyth, Rosebud County, Montana and Puget Sound Energy (incorporated herein by reference to Exhibit 4.25 to the Company’s Post-Effective Amendment No.1 to Registration Statement on Form S-3, dated July 11, 2003, Commission file No. 333-82490-02). |
| 12.1 | Statement setting forth computation of ratios of earnings to fixed charges (1998 through 2002 and 12 months ended June 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 June 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. |
