Puget Energy’s basic earnings per common share have been computed based on weighted average common shares outstanding of 99,371,000 and 99,271,000 for the three and six months ended June 30, 2004, respectively, and 93,928,000 and 93,833,000 for the three and six months ended June 30, 2003.
Puget Energy’s diluted earnings per common share have been computed based on weighted average common shares outstanding of 99,371,000 and 99,786,000 for the three and six months ended June 30, 2004, respectively, and 94,440,000 and 94,346,000 for the three and six months ended June 30, 2003, respectively. These shares include the dilutive effect of securities related to employee and director equity plans. The effects of employee and director stock compensation plans for the three month period ended June 30, 2004 are anti-dilutive and are therefore excluded from the calculation of diluted loss per share for that period. Had the employee and director equity plans not had an anti-dilutive effect on earnings per share, the diluted common shares for the three months ended June 30, 2004 would have been 99,885,000.
Puget Energy operates in primarily two business segments: regulated utility operations, or PSE, and utility construction services, or InfrastruX. Puget Energy’s regulated utility operation generates, purchases, transports and sells electricity and purchases, transports and sells natural gas. One minor non-utility business segment, a PSE subsidiary, which is a real estate investment and development company, is described as other. Reconciling items between segments are not material. Financial data for business segments are as follows:
(Dollars in Thousands)
Three Months Ended June 30, 2004
| PSE
| InfrastruX
| Other
| Total
|
| Revenues | | | $ | 422,570 | | $ | 92,816 | | $ | 553 | | $ | 515,939 | |
| Depreciation and amortization | | | | 56,505 | | | 4,553 | | | 64 | | | 61,122 | |
| Income tax | | | | (5,322 | ) | | 2,504 | | | (111 | ) | | (2,929 | ) |
| Operating income | | | | 30,610 | | | 4,641 | | | (35 | ) | | 35,216 | |
| Interest charges, net of AFUDC | | | | 41,814 | | | 1,428 | | | 51 | | | 43,293 | |
| Minority interest in earnings | | | | -- | | | 289 | | | -- | | | 289 | |
| Net income (loss) | | | | (9,634 | ) | | 2,940 | | | (86 | ) | | (6,780 | ) |
|
| Goodwill, net at June 30, 2004 | | | $ | -- | | $ | 133,069 | | $ | -- | | $ | 133,069 | |
| Total assets at June 30, 2004 | | | | 5,247,686 | | | 358,700 | | | 71,132 | | | 5,677,518 | |
|
Three Months Ended June 30, 2003
| PSE
| InfrastruX
| Other
| Total
|
| Revenues | | | $ | 431,147 | | $ | 92,343 | | $ | 570 | | $ | 524,060 | |
| Depreciation and amortization | | | | 54,661 | | | 4,601 | | | 59 | | | 59,321 | |
| Income tax | | | | 2,290 | | | 2,568 | | | (26 | ) | | 4,832 | |
| Operating income | | | | 61,958 | | | 4,325 | | | 124 | | | 66,407 | |
| Interest charges, net of AFUDC | | | | 44,814 | | | 1,148 | | | 18 | | | 45,980 | |
| Minority interest in earnings | | | | -- | | | 282 | | | -- | | | 282 | |
| Net income | | | | 17,562 | | | 2,833 | | | 1,997 | | | 22,392 | |
|
Six Months Ended June 30, 2004
| PSE
| InfrastruX
| Other
| Total
|
| Revenues | | | $ | 1,090,757 | | $ | 167,571 | | $ | 1,080 | | $ | 1,259,408 | |
| Depreciation and amortization | | | | 112,312 | | | 8,971 | | | 127 | | | 121,410 | |
| Income tax | | | | 33,899 | | | 2,118 | | | (234 | ) | | 35,783 | |
| Operating income | | | | 139,410 | | | 5,578 | | | (93 | ) | | 144,895 | |
| Interest charges, net of AFUDC | | | | 83,828 | | | 2,784 | | | 102 | | | 86,714 | |
| Minority interest in earnings | | | | -- | | | 246 | | | -- | | | 246 | |
| Net income (loss) | | | | 57,220 | | | 2,560 | | | (195 | ) | | 59,585 | |
|
Six Months Ended June 30, 2003
| PSE
| InfrastruX
| Other
| Total
|
| Revenues | | | $ | 1,000,608 | | $ | 163,020 | | $ | 1,069 | | $ | 1,164,697 | |
| Depreciation and amortization | | | | 109,194 | | | 7,960 | | | 112 | | | 117,266 | |
| Income tax | | | | 36,787 | | | (528 | ) | | (61 | ) | | 36,198 | |
| Operating income | | | | 155,773 | | | 1,846 | | | 173 | | | 157,792 | |
| Interest charges, net of AFUDC | | | | 91,170 | | | 2,457 | | | 18 | | | 93,645 | |
| Minority interest in earnings | | | | -- | | | (50 | ) | | -- | | | (50 | ) |
| Net income (loss) | | | | 65,543 | | | (609 | ) | | 2,046 | | | 66,980 | |
|
At December 31, 2003
| PSE
| InfrastruX
| Other
| Total
|
| Goodwill, net | | | $ | -- | | $ | 133,302 | | $ | -- | | $ | 133,302 | |
| Total asset | | | | 5,257,157 | | | 342,332 | | | 75,196 | | | 5,674,685 | |
|
(4) Accounting for Derivative Instruments and Hedging Activities
Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into both physical and financial contracts to manage its energy resource portfolio including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
During the three months ended June 30, 2004, 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 $2.8 million compared to an increase in earnings of approximately $44,000 for the three months ended June 30, 2003. In 2004, a portion of the unrealized gain is deferred in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” due to the Company expecting to reach the $40 million Power Cost Adjustment (PCA) mechanism in the fourth quarter of 2004. When these transactions are realized, they will be reflected in the PCA calculation.
During the six months ended June 30, 2004, 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 $2.9 million compared to an increase in earnings of approximately $0.5 million for the six months ended June 30, 2003.
PSE has a contract with a counterparty whose debt ratings have been below investment grade since 2002. The contract, a physical gas supply contract for one of PSE’s electric generating facilities, was marked-to-market beginning in the fourth quarter of 2003. Although the counterparty continues to fully perform on the physical supply contract, the counterparty’s credit ratings have remained weak. Prior to October 1, 2003, the contract was designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as management deemed that delivery is not probable through the term of the contract, which expires December 2008.
Another physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market beginning in the first quarter of 2004. The counterparty notified PSE in the first quarter of 2004 that it believes it will be unable to deliver physical gas supply beginning November 2005 through the end of the contract in June 2008. PSE concluded that it is no longer probable that the counterparty will perform on this contract through the end of the term of the contract. The contract was previously designated as a normal purchase under SFAS No. 133. PSE has also concluded that it is appropriate to reserve a portion of the marked-to-market gain on this contract, due to the risk of the counterparty not performing, beginning November 2005 through the end of the contract as delivery is not probable during this time period. As a result, PSE recorded an unrealized gain to earnings, net of a reserve, of $2.3 million in the second quarter of 2004. Approximately $2.2 million of the unrealized gain will be reversed as transactions settle in 2004.
(5) Intangibles(Puget Energy Only)
Identifiable intangible assets acquired as a result of acquisitions of InfrastruX companies are amortized over the expected useful lives of the assets, which range from four to 20 years. Identifiable intangible assets are as follows:
At June 30, 2004
(Dollars in thousands)
| Gross
Intangibles
| Accumulated
Amortization
| Net
Intangibles
|
| Covenant not to compete | | | $ | 4,178 | | $ | 2,330 | | $ | 1,848 | |
| Developed technology | | | | 14,190 | | | 2,809 | | | 11,381 | |
| Contractual customer relationships | | | | 4,702 | | | 1,108 | | | 3,594 | |
| Patents | | | | 997 | | | 83 | | | 914 | |
|
| Total | | | $ | 24,067 | | $ | 6,330 | | $ | 17,737 | |
| |
|
At December 31, 2003
(Dollars in thousands)
| Gross
Intangibles
| Accumulated
Amortization
| Net
Intangibles
|
| Covenant not to compete | | | $ | 4,178 | | $ | 2,009 | | $ | 2,169 | |
| Developed technology | | | | 14,190 | | | 2,454 | | | 11,736 | |
| Contractual customer relationships | | | | 4,702 | | | 747 | | | 3,955 | |
| Patents | | | | 915 | | | 68 | | | 847 | |
|
| Total | | | $ | 23,985 | | $ | 5,278 | | $ | 18,707 | |
| |
|
The identifiable intangible asset amortization expense for the three and six months ended June 30, 2004 was $0.5 million and $1.0 million, respectively, and $0.5 million and $1.0 million, respectively, for the same periods in 2003. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:
(Dollars in thousands)
| 2004
| 2005
| 2006
| 2007
| 2008
|
| Future Intangible Amortization | | | $ | 1,146 | | $ | 2,086 | | $ | 1,732 | | $ | 1,385 | | $ | 1,301 | |
(6) Asset Retirement Obligation
On January 1, 2003 the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company recorded an after-tax charge to income of $0.2 million in the first quarter of 2003 for the cumulative effect of the accounting change.
The Company identified various asset retirement obligations at January 1, 2003, which were included in the cumulative effect of the accounting change. The Company has an obligation (1) to dismantle two leased electric generation turbine units and deliver the turbines to the nearest railhead at the termination of the lease in 2009; (2) to remove certain structures as a result of re-negotiations with the Department of Natural Resources of a now expired lease; (3) to replace or line all cast iron pipes in its service territory by 2007 as a result of a 1992 Washington Commission order; and (4) to restore ash holding ponds at a jointly-owned coal-fired electric generating facility in Montana.
The following table describes all changes to the Company’s asset retirement obligation liability during 2004:
(Dollars in thousands)
At June 30, 2004
| Amount
|
| Asset retirement obligation at December 31, 2003 | | | $ | 3,421 | |
| Liability recognized in the period | | | | -- | |
| Liability settled in the period | | | | -- | |
| Accretion expense | | | | 49 | |
|
| Asset retirement obligation at June 30, 2004 | | | $ | 3,470 | |
| |
|
(7) Stock Compensation(Puget Energy Only)
The Company has various stock-based compensation plans which prior to 2003 were accounted for according to Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” The Company is applying SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Had the Company used the fair value method of accounting specified by SFAS No. 123 for all grants at their grant date rather than prospectively implementing SFAS No. 123, net income and earnings per share would have been as follows:
| | Three Months Ended
June 30,
| Six Months Ended
June 30,
|
(Dollar in thousands, except per share)
| 2004
| 2003
| 2004
| 2003
|
| Income (loss) for common stock, as reported | | | $ | (6,780 | ) | $ | 20,598 | | $ | 59,585 | | $ | 63,319 | |
| Add: Total stock-based employee compensation expense included | | |
| in net income, net of tax | | | | 827 | | | 1,953 | | | 1,466 | | | 2,510 | |
| Less: Total stock-based employee compensation expense per the | | |
| fair value method of SFAS No. 123, net of tax | | | | (949 | ) | | (999 | ) | | (1,678 | ) | | (1,891 | ) |
|
| Pro forma income (loss) for common stock | | | $ | (6,902 | ) | $ | 21,552 | | $ | 59,373 | | $ | 63,938 | |
| |
|
| Earnings per share: | | |
| Basic as reported | | | $ | (0.07 | ) | $ | 0.22 | | $ | 0.60 | | $ | 0.68 | |
| Diluted as reported | | | $ | (0.07 | ) | $ | 0.22 | | $ | 0.60 | | $ | 0.67 | |
|
| Basic and diluted pro forma | | | $ | (0.07 | ) | $ | 0.23 | | $ | 0.60 | | $ | 0.68 | |
(8) Retirement Benefits
The following summarizes the net periodic benefit cost for the three months ended June 30.
| | Pension Benefits
| Other Benefits
|
(Dollars in thousands)
| 2004
| 2003
| 2004
| 2003
|
| Service cost | | | $ | 2,663 | | $ | 2,071 | | $ | 50 | | $ | 44 | |
| Interest cost | | | | 6,075 | | | 6,101 | | | 438 | | | 457 | |
| Expected return on plan assets | | | | (9,753 | ) | | (9,720 | ) | | (222 | ) | | (234 | ) |
| Amortization of prior service cost | | | | 790 | | | 805 | | | 77 | | | 77 | |
| Recognized net actuarial (gain) loss | | | | 282 | | | (672 | ) | | -- | | | (85 | ) |
| Amortization of transition (asset) obligation | | | | (277 | ) | | (276 | ) | | 105 | | | 105 | |
| Special recognition of prior service costs | | | | -- | | | 48 | | | -- | | | -- | |
|
| Net periodic benefit cost (income) | | | $ | (220 | ) | $ | (1,643 | ) | $ | 448 | | $ | 364 | |
| |
|
The following summarizes the net periodic benefit cost for the six months ended June 30.
| | Pension Benefits
| Other Benefits
|
(Dollars in thousands)
| 2004
| 2003
| 2004
| 2003
|
| Service cost | | | $ | 5,171 | | $ | 4,142 | | $ | 100 | | $ | 88 | |
| Interest cost | | | | 12,041 | | | 12,203 | | | 876 | | | 914 | |
| Expected return on plan assets | | | | (19,553 | ) | | (19,440 | ) | | (444 | ) | | (467 | ) |
| Amortization of prior service cost | | | | 1,595 | | | 1,610 | | | 154 | | | 155 | |
| Recognized net actuarial (gain) loss | | | | 564 | | | (1,344 | ) | | -- | | | (171 | ) |
| Amortization of transition (asset) obligation | | | | (552 | ) | | (552 | ) | | 210 | | | 209 | |
| Special recognition of prior service costs | | | | -- | | | 95 | | | -- | | | -- | |
|
| Net periodic benefit cost (income) | | | $ | (734 | ) | $ | (3,286 | ) | $ | 896 | | $ | 728 | |
| |
|
The Company previously disclosed in its financial statements for the year ended December 31, 2003 that it expected pension plan contributions to be $11.1 million in 2004. During the three and six months ended June 30, 2004, the actual cash contributions to the pension plans were $0.5 million and $1.0 million, respectively. In addition, some plan participants chose lump sum pension payments of $9.7 million and deferred them under the Company’s deferred compensation plan in the first quarter of 2004. Based on this activity, the Company anticipates contributing an additional $0.4 million to the Company’s non-qualified supplemental retirement plan in 2004.
During the three and six months ended June 30, 2004, actual other post-retirement medical benefit plan contributions were $0.4 million and $0.8 million, respectively, and the Company expects to make additional contributions of $0.8 million for a total of $1.6 million in 2004.
(9) Tenaska Disallowance
The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a one-time disallowance of $25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which was recorded as a Purchased Electricity expense. The order also established guidelines for future recovery of Tenaska costs. PSE filed a petition for reconsideration and clarification to address certain issues arising from the May 13, 2004 order. As a result, the Washington Commission issued an order on June 7, 2004 denying PSE’s petition for reconsideration, and denying in part, and granting in part, PSE’s petition for clarification. In its order of June 7, 2004, the Washington Commission clarified the financial impact of the disallowance for costs relating to the return on PSE’s Tenaska regulatory asset in the PCA 1 and 3 periods. The amounts were determined to be a $25.6 million one-time disallowance for the PCA 1 period; an estimated disallowance of $11.3 million for the PCA 3 period (July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s methodology of 50% disallowance on the return on the Tenaska regulatory asset due to projected costs exceeding the benchmark during the period. For the PCA 3 period, approximately $5.6 million would be disallowed in the period July 1, 2004 through December 31, 2004, primarily as a reduction to Electric Operating Revenue, for a cumulative impact on earnings of $31.2 million in 2004 for the PCA 1 and 3 periods for PSE. The PCA 3 reduction in Electric Operating Revenue is the result of the Washington Commission’s order that reflected a reduction in rates of approximately $9.9 million annually. This reduction is to reflect the Washington Commission’s estimate of the Tenaska disallowance for the PCA 3 period. While the Washington Commission did not expressly address the disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE estimates the disallowance for the PCA 2 period to be approximately $12.2 million if the Washington Commission were to follow the same methodology as they have ordered for the PCA 3 period. While PSE reserves the right to address the merits of any disallowance in its PCA 2 compliance filing which will be filed in the third quarter of 2004, PSE recorded a $12.2 million disallowance to Purchased Electricity expense in the second quarter of 2004 for the 50% disallowance of the return on the Tenaska regulatory asset in accordance with the Washington Commission’s methodology discussed in their order of May 13, 2004. As a result of the disallowance recorded, the PCA customer deferral of $17.6 million at March 31, 2004 was expensed and a reserve was established to offset future PCA customer deferrals. The reserve balance as of June 30, 2004 was $13.6 million, which is expected to be utilized over the remaining months in 2004 as the excess power costs are shared through the PCA mechanism. The cumulative amount attributable to the disallowance recorded in the second quarter of 2004 was $37.8 million ($24.5 million after-tax) and the total for 2004 is expected to be approximately $43.4 million ($28.1 million after-tax).
Prior to the Tenaska disallowance, PSE’s excess power costs under the PCA mechanism were at the $40 million cap whereas with the Tenaska disallowance the excess power costs at June 30, 2004 are $26.5 million. The excess power costs from June 30, 2004 until the PCA mechanism cap of $40 million is reached, which is expected in November 2004, will be offset by the Tenaska disallowance reserve of $13.6 million for the PCA 1 and 2 periods that was recorded in the second quarter of 2004. Consequently, PSE does not expect earnings through year-end 2004, based on current market conditions, to be impacted by excess power costs.
Below is a summary of the Tenaska disallowances by quarter through December 31, 2004:
Quarter ending
(Dollars in millions)
| 7/02 - 6/03
PCA 1
(ordered/final)
| 7/03 - 6/04
PCA 2
(estimated)
| 7/04 - 12/04
PCA 3
(estimated)
| Total
|
| June 30, 2004 | | $ 25 | .6 | $ 12 | .2 | $ -- | | $ 37 | .8 |
| September 30, 2004 | | | -- | | -- | 2 | .8 | 2 | .8 |
| December 31, 2004 | | | -- | | -- | 2 | .8 | 2 | .8 |
| |
|
| Total | | $ 25 | .6 | $ 12 | .2 | $ 5 | .6 | $ 43 | .4 |
| |
|
In the May 13, 2004 order, the Washington Commission established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
| The Washington Commission guidelines for determining future recovery of the Tenaska costs are as follows: |
| 1. | The Washington Commission will determine if PSE's gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
| 2. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs. |
| 3. | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
| a) | | Actual Tenaska costs that exceed the benchmark or; |
| b) | | The return on the Tenaska regulatory asset (return on the asset would be added last to all other relevant Tenaska costs). |
| 4. | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs (gas, return of and return on Tenaska Regulatory Asset). |
The Washington Commission confirmed that if the Tenaska costs are deemed prudent, PSE will recover the full amount of actual costs and the return of the Tenaska regulatory asset even if the benchmark is exceeded. The projected costs and projected benchmark costs for Tenaska are as follows:
(Dollars in millions)
| Remainder
2004
| 2005
| 2006
| 2007
| 2008
| 2009
| 2010
| 2011
|
| Projected Tenaska costs (*) | | | $ | 96 | .9 | $ | 193 | .7 | $ | 188 | .3 | $ | 181 | .9 | $ | 177 | .8 | $ | 166 | .1 | $ | 159 | .9 | $ | 127 | .7 |
| Projected Tenaska benchmark costs | | | | 85 | .6 | | 159 | .5 | | 167 | .9 | | 175 | .2 | | 182 | .2 | | 189 | .5 | | 197 | .2 | | 157 | .2 |
| |
|
| Over (under) benchmark costs | | | $ | 11 | .3 | $ | 34 | .2 | $ | 20 | .4 | $ | 6 | .7 | $ | (4 | .4) | $ | (23 | .4) | $ | (37 | .3) | $ | (29 | .5) |
| |
|
| Projected 50% disallowance based on | | |
| Washington Commission methodology | | | $ | 5 | .6 | $ | 10 | .9 | $ | 8 | .0 | $ | 3 | .3 | $ | 0 | .5 | $ | | -- | $ | | -- | $ | | -- |
| |
|
_________________
* Projection will change based on market conditions of gas and replacement power costs.
(10) New Accounting Pronouncements
In January 2003, FASB issued Financial Interpretation No. 46 “Consolidation of Variable Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. FIN 46 requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements must be included in the consolidated financial statements of the business entity. The adoption of FIN 46 for all interests in variable interest entities created after January 31, 2003 was effective immediately. For variable interest entities created before February 1, 2003, it was effective July 1, 2003. The adoption of FIN 46R was effective March 31, 2004. The Company has evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance, and therefore it was consolidated in the third quarter of 2003. As a result, revenues increased while conservation amortization and interest expense increased by the corresponding amount with no impact on earnings. FIN 46R also impacted the treatment of the Company’s mandatorily redeemable preferred securities of a subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities). Previously, these trust preferred securities were consolidated into the Company’s operations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities in the fourth quarter of 2003. This change had no impact on the Company’s results of operations. The Company evaluated its purchase power agreements and determined that three counterparties may be considered variable interest entities. As a result, PSE submitted requests for information in the first quarter of 2004 to those parties; however, the parties refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity. PSE also determined it does not have a contractual right to such information. PSE will periodically submit requests for information in the future to determine if FIN 46R is applicable.
For the three purchase power agreements that may be considered variable interest entities under FIN 46R, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the purchase power agreements. If at any time the counterparties cannot deliver energy to PSE, PSE would have to buy energy in the wholesale market at prices which could be higher or lower than the purchase power agreement prices. PSE’s Purchased Electricity expense for the three and six months ended June 30, 2004 for these three entities was $42.5 million and $110.0 million, respectively.
In December 2003, SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (SFAS No. 132R), was revised to include various additional disclosure requirements. SFAS No. 132R is effective for fiscal years ending after December 15, 2003.
The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) at its July 2003 meeting came to a consensus concerning EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03.” The consensus reached was that determining realized gains and losses on physically settled derivative contracts not held for trading purposes reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Based on the guidance in EITF No. 03-11, the Company determined that its non-trading derivative instruments should be reported net and implemented this treatment effective January 1, 2004. Consequently, both Electric Operating Revenues and Purchased Electricity for the three and six months ended June 30, 2003 have been reduced by $33.8 million and $69.1 million, respectively, to reflect the netting addressed by EITF No. 03-11 with no effect on net income.
On May 19, 2004, FASB issued FASB Staff Position (FSP) No. FAS 106-2 “Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003” as the result of the new Medicare Prescription Drug and Modernization Act which was signed into law in December 2003. The law provides a subsidy for plan sponsors that provide prescription drug benefits to Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based upon an actuarial assessment, PSE will not be eligible for such subsidies, thus FSP No. 106-2 will have no impact on PSE’s retiree medical plans.
On June 17, 2004, FASB issued a proposed interpretation titled “Accounting for Conditional Asset Retirement Obligations” which is an interpretation of FASB No. 143 “Accounting for Asset Retirement Obligations”. The proposed interpretation would address the issue of whether FASB No. 143 requires an entity to recognize a liability for a legal obligation to perform asset retirement when the asset retirement activities are conditional on a future event, and if so, the timing and valuation of the recognition. This proposed interpretation could potentially have an impact on the Company as assets that were previously outside the scope of FASB No. 143 may be subject to its terms based on the interpretation. Comments on the proposed interpretation were due August 1, 2004.
(11) Other
On April 5, 2004, PSE filed general tariff electric and gas rate cases with the Washington Commission. The rate cases propose increases of 5.7% or $81.6 million annually and 6.3% or $47.2 million annually for electric and gas customers, respectively. These increases are intended to recover costs associated with extending and upgrading facilities to serve a growing number of gas and electric customers as well as strengthen PSE financially to serve its customers. The resolution of the general rate cases may be up to an 11-month process from the time the general rate cases were filed.
On April 23, 2004, the acquisition of a 49.85% interest in the Fredrickson 1 generating facility was approved by FERC. Prior to that approval, on April 7, 2004, the Washington Commission issued an order in PSE’s power cost only rate case granting approval for the acquisition of the Fredrickson 1 generating facility as well. As a result of these approvals, PSE completed the acquisition in the second quarter of 2004 and added $80.8 million in utility plant. In its order, the Washington Commission found the acquisition to be prudent and the costs associated with the generating facility reasonable. The costs associated with the generating facility, including projected baseline gas costs, are approved for recovery in rates.
On May 13, 2004, the Washington Commission also approved other adjustments to power costs that resulted in an increase of cost recovery in rates of $44.1 million annually, beginning May 24, 2004 which includes the ownership, operation and fuel costs of the Fredrickson 1 generating facility.
In the second quarter of 2004, PSE incurred a $6.9 million charge related to a binding arbitration settlement between PSE and Western Energy Company (WECO), the supplier of coal to Colstrip 1 & 2. The binding decision retroactively set a new baseline cost of coal per ton supplied from July 31, 2001, and is applicable for the remaining term of the coal supply agreement through December 2009. Of the second quarter charge of $6.9 million, $5.0 million is included in the PCA mechanism. PSE had previously accrued a reserve of $1.6 million in the fourth quarter 2003 related to the arbitration.
On April 29, 2004, the Minerals Management Service of the United States Department of the Interior issued an order to pay additional royalties to WECO, concerning coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of an additional $1.1 million in royalties for coal mined from federal lands between 1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a settlement agreement entered into in February 1997 among PSE, WECO and Montana Power Company that resolved disputes that were then pending. The order seeks to impute the price charged to PSE based on the other Colstrip 3 & 4 owners’ contractual amounts. PSE is supporting WECO’s appeal of the order, but is also evaluating the basis of the claim. PSE accrued a loss reserve in the amount of $1.1 million in the second quarter of 2004 charging Electric Generation Fuel expense in connection with this matter.
In addition, the Management Service of the United States Department of the Interior issued two orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. PSE’s share of the alleged additional royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest in Colstrip 3 & 4. The transportation agreement provides for the construction and operation of a conveyor system that runs several miles from the mine to the Colstrip 3 & 4 units. WECO has appealed these orders and PSE is monitoring the process. PSE believes that the Colstrip 3 & 4 owners have reasonable defenses in this matter based upon its review. Neither the outcome of this matter nor the associated costs can be predicted at this time.
On July 15, 2004, PSE issued $200 million in floating rate senior notes under its existing $500 million shelf registration statement, reducing the available balance for future issuances under the registration statement to $300 million. The notes float at the three-month LIBOR rate plus 0.30%, mature on July 14, 2006, and can be redeemed at any time after January 15, 2005. PSE used the net proceeds from the sale of the floating rate senior notes to repay outstanding amounts under its commercial paper and accounts receivable securitization programs, including amounts incurred to repay long-term debt, and will also be used to redeem $55 million in principal amount of first mortgage bonds at a premium of 3.68% on August 14, 2004.
In 2003, the Washington Commission’s Pipeline Safety staff conducted a natural gas standard inspection for three counties within Washington State in which PSE operates gas pipeline activities. The inspection included a review of procedures, records, and operations and maintenance activities. On June 29, 2004, the Washington Commission issued a complaint to PSE related to those inspections. The Washington Commission’s complaint alleges certain violations of Washington Commission regulations and determined a maximum aggregated fine for the violations of $4.5 million, although the Washington Commission’s Pipeline Safety staff recommended a fine of $1.3 million. PSE is investigating this matter and will meet with the Pipeline Safety staff to review both the allegations and the invitation by the Washington Commission to jointly explore resolution. PSE believes it has reasonable defenses in this matter based upon a preliminary review. Neither the outcome of this matter nor the associated costs, including potential fines, can be predicted at this time.
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.
Overview
Puget Energy is an energy services holding company and all of its operations are conducted through its two subsidiaries. These subsidiaries are PSE, a regulated electric and gas utility company, and InfrastruX, a utility construction and services company.
Puget Sound Energy
PSE generates revenues from the sale of electric and gas services, mainly to residential and commercial customers within Washington State. A majority of PSE’s revenues are generated in the first and fourth quarters during the winter heating season in Washington State.
As a regulated utility company, PSE is subject to FERC and Washington Commission regulation which may impact a large array of business activities, including limitation of future rate increases; directed accounting requirements that may negatively impact earnings; licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent to the utility industry as a whole including weather changes affecting purchases and sales of energy; outages at owned and non-owned generation plants where energy is obtained; storms which can damage distribution and transmission lines; and energy trading and wholesale market stability over time.
PSE’s main operational goal is to provide cost-effective and stable energy prices to its customers. To help accomplish this goal, PSE is attempting to be more self-sufficient in energy generation resources. Owning more generation resources rather than purchasing power through contracts and on the wholesale market is intended to allow customers’ rates to remain stable. As such, on April 7, 2004, PSE obtained approval from the Washington Commission to complete its purchase of a 49.85% interest in a 250 MW capacity gas-fired generation facility within Western Washington. In addition, PSE has signed a two-year purchase power agreement in the second quarter of 2004 with a utility for 85 MW of energy with delivery beginning January 1, 2005. These transactions are part of PSE’s long-term electric Least Cost Plan that was filed August 29, 2003 with the Washington Commission. The plan supports a strategy of diverse resource acquisitions including resources fueled by natural gas and coal, renewable resources and shared resources.
InfrastruX
InfrastruX generates revenues mainly from maintenance services and construction contracts in the midwest, Texas, south-central and eastern United States regions. A majority of its revenues are generated during the second and third quarters, which are generally the most productive quarters for the construction industry due to longer daylight hours and generally better weather conditions.
InfrastruX is subject to risks associated with the construction industry including inability to adequately estimate costs of projects that are bid upon under fixed-fee contracts; continued economic downturn that limits the amount of projects available thereby reducing available profit margins from increased competition; the ability to integrate acquired companies within its operations without significant cost; and the ability to obtain adequate financing and bonding coverage to continue expansion and growth.
InfrastruX’s goals are continued growth and expansion into underdeveloped utility construction markets and to utilize its acquired entities to capitalize on depth of expertise, asset base, geographical location and workforce to provide services that local contractors cannot. InfrastruX has acquired 12 entities since 2000 to fuel growth and diversify into these underdeveloped markets.
Puget Energy is currently evaluating strategic options related to its investment in InfrastruX.
Results of Operations
Puget Energy
All of the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX. Puget Energy’s net loss for the three months ended June 30, 2004 was $6.8 million on operating revenues of $515.9 million compared with net income of $22.4 million on operating revenues of $524.1 million for the same period in 2003. Loss for common stock was $6.8 million for the three months ended June 30, 2004 compared to income for common stock of $20.6 million for the same period in 2003. Puget Energy’s basic and diluted loss per share was $0.07 for the three months ended June 30, 2004 compared to basic and diluted earnings per share of $0.22 for the same period of 2003.
Puget Energy’s income for common stock for the three months ended June 30, 2004 was negatively impacted by a decrease in PSE’s income of $27.4 million compared to the same period in 2003. This negative change was due primarily to a $24.5 million after-tax disallowance of the return on the regulatory asset for the Tenaska gas supply buyout cost under the Company’s Power Cost Adjustment (PCA) mechanism as a result of a Washington Commission order in the Company’s Power Cost Only Rate Case (PCORC). See further discussion under PSE’s “Electric Rate Matters”.
For the six months ended June 30, 2004, Puget Energy’s net income was $59.6 million on operating revenues of $1.3 billion compared to net income of $67.0 million on operating revenues of $1.2 billion for the same period in 2003. Income for common stock was $59.6 million for the six months ended June 30, 2004 compared to $63.3 million for the same period in 2003. Basic and diluted earnings per common share were $0.60 for the six months ended June 30, 2004 and $0.68 and $0.67 per common share, respectively, for the same period in 2003.
Puget Energy’s income for common stock for the six months ended June 30, 2004 was also negatively impacted by the $24.5 million after-tax disallowance of the return on the regulatory asset for the Tenaska gas supply buyout cost, partially offset by higher energy sales resulting from more normal temperatures in the first quarter of 2004 as compared to warmer temperatures in the same period in 2003. Puget Energy’s income for common stock was also positively impacted by a $3.2 million increase in earnings from InfrastruX (net of minority interest) for the six months ended June 30, 2004 compared to the same period in 2003 due in part to improved operating efficiencies and improvement in weather conditions compared to 2003 which positively impacted productivity.
Puget Sound Energy
The changes to items affecting net income for the three and six months ended June 30, 2004, in comparison to the same periods in 2003, are summarized in the table below.
Comparative Three and Six Months Ended
June 30, 2004 vs. June 30, 2003
Increase (Decrease)
(Dollars in Millions)
| | Three Months
Ended
| Six Months
Ended
|
| Operating revenue changes: | | | | | | | | |
| Electric: | | |
| Residential sales | | | $ | (4 | .8) | $ | 8 | .9 |
| Commercial sales | | | | 3 | .0 | | 9 | .1 |
| Industrial sales | | | | (0 | .9) | | (1 | .7) |
| Transportation sales | | | | (1 | .1) | | (2 | .0) |
| Sales to other utilities and marketers | | | | (7 | .9) | | (18 | .3) |
| Other | | | | 0 | .4 | | 3 | .5 |
|
| Total electric operating change | | | | (11 | .3) | | (0 | .5) |
|
| Gas: | | |
| Residential sales | | | | (3 | .4) | | 52 | .9 |
| Commercial sales | | | | 3 | .7 | | 31 | .6 |
| Industrial sales | | | | 1 | .5 | | 5 | .4 |
| Transportation sales | | | | (0 | .2) | | (0 | .3) |
| Other | | | | 1 | .1 | | 1 | .0 |
|
| Total gas operating change | | | | 2 | .7 | | 90 | .6 |
|
| Total operating revenue change | | | | (8 | .6) | | 90 | .1 |
|
| Operating expense changes: | | |
| Energy costs: | | |
| Purchased electricity | | | | 16 | .0 | | 7 | .3 |
| Purchased gas | | | | 6 | .3 | | 81 | .8 |
| Electric generation fuel | | | | 9 | .9 | | 8 | .8 |
| Residential exchange power cost credit | | | | 1 | .6 | | (0 | .1) |
| Unrealized gain increase on derivative instruments | | | | (2 | .8) | | (2 | .4) |
| Utility operations and maintenance: | | |
| Production operations and maintenance | | | | (0 | .9) | | (1 | .3) |
| Low income program pass through expenses | | | | (1 | .0) | | (2 | .7) |
| Other utility operations and maintenance | | | | 1 | .2 | | 7 | .1 |
| Depreciation and amortization | | | | 1 | .9 | | 3 | .1 |
| Conservation amortization | | | | (1 | .5) | | (1 | .0) |
| Taxes other than income taxes | | | | (0 | .3) | | 9 | .0 |
| Income taxes | | | | (7 | .6) | | (3 | .0) |
|
| Total operating expense change | | | | 22 | .8 | | 106 | .6 |
| Other income change (net of tax) | | | | (0 | .7) | | (1 | .4) |
| Interest charges change | | | | (3 | .0) | | (7 | .3) |
| Cumulative effect of an accounting change (net of tax) | | | | | -- | | (0 | .2) |
|
| Net income change | | | $ | (29 | .1) | $ | (10 | .4) |
| |
|
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.
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.
Electric margin decreased $37.6 million and $16.0 million for the three and six months ended June 30, 2004 compared to the same periods in 2003 primarily as a result of the disallowance ordered by the Washington Commission in the PCORC which resulted in a $37.8 million pre-tax regulatory disallowance ($1.3 million of which flowed through the PCA mechanism). Additionally, electric energy sales for the three months ended June 30, 2004 were lower than the same period in the prior year due to warmer than normal weather conditions in the second quarter 2004 compared with colder than normal weather conditions in the same period in the prior year. The lower electric margin for the six months ended June 30, 2004 was partially offset by near normal weather conditions in the first quarter 2004 in comparison with warmer than normal weather conditions for the same period in 2003.
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, 2004 and 2003 is detailed further as follows:
Electric Margin for the Three and Six Months Ended
June 30, 2004 and June 30, 2003
(Dollars in Millions)
| | Three Months Ended
June 30,
| Six Months Ended
June 30,
|
| | 2004
| 2003
| 2004
| 2003
|
| Electric retail sales revenue | | | $ | 280 | .9 | $ | 285 | .7 | $ | 648 | .4 | $ | 633 | .4 |
| Electric transportation revenue | | | | 2 | .4 | | 3 | .4 | | 4 | .6 | | 6 | .6 |
| Other electric revenue-gas supply resale | | | | 0 | .6 | | 2 | .2 | | 4 | .0 | | 7 | .3 |
|
| Total electric revenue for margin | | | | 283 | .9 | | 291 | .3 | | 657 | .0 | | 647 | .3 |
| Adjustments for amounts included in revenue: | | |
| Pass-through tariff items | | | | (5 | .6) | | (11 | .3) | | (14 | .1) | | (24 | .3) |
| Pass-through revenue-sensitive taxes | | | | (20 | .9) | | (20 | .5) | | (47 | .0) | | (45 | .4) |
| Residential Exchange Credit | | | | 35 | .4 | | 37 | .0 | | 89 | .8 | | 89 | .7 |
|
| Net electric revenue for margin | | | | 292 | .8 | | 296 | .5 | | 685 | .7 | | 667 | .3 |
| Minus power costs: | | |
| Fuel | | | | (21 | .0) | | (11 | .1) | | (35 | .0) | | (26 | .2) |
| Purchased electricity, net of sales to other | | |
| utilities and marketers | | | | (132 | .0) | | (143 | .3) | | (330 | .8) | | (326 | .5) |
|
| Total electric power costs | | | | (153 | .0) | | (154 | .4) | | (365 | .8) | | (352 | .7) |
|
| Electric margin before PCA | | | | 139 | .8 | | 142 | .1 | | 319 | .9 | | 314 | .6 |
| Tenaska disallowance reserve through May 23, 2004 | | | | (36 | .5) | | | -- | | (36 | .5) | | | -- |
| Power cost deferred under the PCA | | | | 5 | .3 | | 4 | .1 | | 19 | .3 | | 4 | .1 |
|
| Electric margin | | | $ | 108 | .6 | $ | 146 | .2 | $ | 302 | .7 | $ | 318 | .7 |
| |
|
Gas margin decreased $4.6 million for the three months ended June 30, 2004 compared to the same period in 2003 due primarily to warmer than normal weather conditions in comparison with the same period in 2003. Gas margin for the six months ended June 30, 2004 increased $0.9 million due primarily to near normal weather conditions in the first quarter 2004 in comparison with the same period in 2003.
Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory. Gas margin for the three and six months ended June 30, 2004 and 2003 is detailed further as follows:
Gas Margin for the Three and Six Months Ended
June 30, 2004 and June 30, 2003
(Dollars in Millions)
| | Three Months Ended
June 30,
| Six Months Ended
June 30,
|
| | 2004
| 2003
| 2004
| 2003
|
| Gas retail revenue | | | $ | 112 | .6 | $ | 110 | .8 | $ | 382 | .0 | $ | 292 | .1 |
| Gas transportation revenue | | | | 3 | .1 | | 3 | .3 | | 6 | .5 | | 6 | .8 |
|
| Total gas revenue for margin | | | | 115 | .7 | | 114 | .1 | | 388 | .5 | | 298 | .9 |
| Adjustments for amounts included in revenue: | | |
| Gas revenue hedge | | | | | -- | | | -- | | | -- | | 0 | .2 |
| Pass-through tariff items | | | | (0 | .5) | | (0 | .8) | | (1 | .6) | | (2 | .4) |
| Pass-through revenue-sensitive taxes | | | | (9 | .9) | | (9 | .7) | | (32 | .1) | | (24 | .6) |
|
| Net gas revenue for margin | | | | 105 | .3 | | 103 | .6 | | 354 | .8 | | 272 | .1 |
| Minus purchased gas costs | | | | (63 | .7) | | (57 | .4) | | (226 | .1) | | (144 | .3) |
|
| Gas margin | | | $ | 41 | .6 | $ | 46 | .2 | $ | 128 | .7 | $ | 127 | .8 |
| |
|
Operating Revenues — Electric
Electric operating revenues for the three months ended June 30, 2004 were $303.1 million, a decrease of $11.3 million compared to the same period in 2003, due primarily to lower sales to residential customers and sales to other utilities and marketers which decreased $4.8 million and $7.9 million, respectively. Residential and sales to other utilities and marketers volumes for the three months ended June 30, 2004 decreased by 76.4 million kWh and 347.9 million kWh, respectively, or 3.4% and 55.3%, compared to the same period in 2003. The residential decrease was mainly attributable to warmer than normal weather conditions for the three months ended June 30, 2004 as compared to colder than normal weather conditions in the same period in 2003. The reduction in sales volumes to other utilities and marketers was a result of lower wholesale electric sales.
Electric operating revenues for the six months ended June 30, 2004 were $695.6 million, an increase of $0.5 million compared to the same period in 2003. This flat revenue change is mainly attributed to the fact that overall weather conditions for the six months ended June 30, 2004 were slightly warmer than normal. With the first and fourth quarters being PSE’s highest volume months from colder weather, near normal weather in the first quarter offset warmer than normal weather conditions in the second quarter, despite an overall slightly warmer than normal period for the six months ending June 30, 2004. Electric operating revenues for the six months ended June 30, 2004 also were impacted by a $2.1 million increase related to new electric operating rates that became effective May 24, 2004 for the Fredrickson 1 generating facility.
PSE’s other electric operating revenues for the three and six months ended June 30, 2004 increased $0.4 million and $3.5 million, respectively, due in part to the implementation of FIN 46R. FIN 46R required PSE to consolidate PSE’s 1995 conservation trust transaction in the third quarter of 2003. The consolidation increased revenues, while conservation amortization and interest expense increased by a corresponding amount with no impact on earnings.
For the three and six months ended June 30, 2004, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers were $37.0 million and $94.0 million, respectively, with a related offset to power costs. PSE received payments from the Bonneville Power Administration (BPA) in the amount of $44.0 million and $102.6 million during the three and six months ended June 30, 2004, respectively. The difference between the customers’ credit and the amount received from BPA either increases or decreases the previously deferred amount owed to customers. The aggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. Absent certain adjustments tied to the BPA rate adjustment clause, the modified amended settlement agreement provides for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for a pass-through of the same amount to eligible residential and small farm customers. See discussion under PSE’s “Electric Rate Matters” for additional residential exchange information.
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 June 30, 2004, PSE’s receivable from the California Independent System Operators (CAISO) and other counter-parties, net of reserves, was $21.3 million. See the discussion of the CAISO receivable and California proceedings under “Proceedings Relating to the Western Power Market.”
Operating Revenues — Gas
Gas operating revenues for the three and six months ended June 30, 2004 were $119.5 million and $395.2 million, respectively, an increase of $2.7 million and $90.6 million, respectively, compared to the same periods in 2003. Increases in the purchased gas adjustment (PGA) rate increased revenues approximately $11.9 million and $81.8 million for the three and six month periods ended June 30, 2004, respectively. The revenue increase for the three month period ended June 30, 2004 was partially offset by lower sales volumes from warmer than normal weather in the second quarter 2004 compared with the same period in the prior year. Residential and commercial gas sales volumes decreased 17.1 million and 4.1 million therms, respectively, or decreased 20.1% and 7.9% for the three months ended June 30, 2004 compared to the same period in 2003. Residential and commercial gas sales volumes decreased 1.0 million and increased 3.9 million therms, respectively, or decreased 0.4% and increased 2.7% for the six months ended June 30, 2004 compared with the same period in 2003.
PSE has a PGA mechanism in retail gas rates to recover expected gas costs (gas supply and transportation costs) by deferring as a receivable or liability, any gas costs that exceed or fall short of the amount in PGA rates and accrues interest on any deferred balances under the PGA. Therefore, PSE’s gas margin and net income is not affected by changes in the PGA rates. The PGA had an asset balance at June 30, 2004 of $9.7 million and a liability balance of $14.3 million at June 30, 2003.
The following rate adjustments were approved by the Washington Commission in relation to the PGA during 2003 that affect changes in gas revenue for the three and six months ended June 30, 2004 compared to the same periods in the prior year:
Effective Date
| Percentage Increase in
Rates
| Annual Increase
in Revenues
(Dollars in millions)
|
| October 1, 2003 | | | 13.3 % | | | $ | 78 | .8 |
| April 10, 2003 | | | 20.1 % | | | | 103 | .6 |
Operating Expenses
Purchased electricityexpenses increased $16.0 million and $7.3 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. The increase was primarily due to a $37.8 million disallowance of the return on the Tenaska gas supply regulatory asset. The increase was partially offset by lower purchases due to increased generation at PSE generating facilities in the second quarter of 2004 compared to the same period in 2003, and lower wholesale electricity prices in the first quarter of 2004 compared to the same period in 2003.
The July 8, 2004 Columbia Basin Runoff Forecast published by the National Weather Service Northwest River Forecast Center indicated that the total forecasted runoff into the Grand Coulee reservoir for the period January through July 2004 would be 83% of normal. This compares to 86% of normal for the same period in 2003. Hydroelectric power is a large percentage of PSE’s power portfolio.
Purchased gas expenses increased $6.3 million and $81.8 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. The increase was primarily due to increased usage as a result of more normal temperatures in the first quarter of 2004 and higher PGA rates compared to the same periods in 2003. Gas costs are passed through to customers through the PGA mechanism with no impact on gas margin or net income.
Electric generation fuel expense increased $9.9 million and $8.8 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003 primarily from increased generation at PSE generation facilities, including Fredrickson 1 which went in service in May 2004. In addition, PSE incurred a $6.9 million charge in June 2004 related to a binding arbitration settlement between PSE and Western Energy Company (WECO), the supplier of coal to Colstrip 1 & 2. The binding decision retroactively set a new baseline cost of coal per ton supplied from July 31, 2001, and is applicable for the remaining term of the coal supply agreement through December 2009. Of the second quarter charge of $6.9 million, $5.0 million is included in the PCA mechanism. PSE had previously accrued a reserve of $1.6 million in the fourth quarter 2003 related to the arbitration.
On April 29, 2004, the Minerals Management Service of the United States Department of the Interior issued an order to pay additional royalties to WECO, concerning coal purchased by PSE for Colstrip Units 3 & 4. The order seeks payment of an additional $1.1 million in royalties for coal mined from federal lands between 1997 and June 30, 2000. During that period, PSE’s coal price was reduced by a settlement agreement entered into in February 1997 among PSE, WECO and Montana Power Company that resolved disputes that were then pending. The order seeks to impute the price charged to PSE based on the other Colstrip 3 & 4 owners’ contractual amounts. PSE is supporting WECO’s appeal of the order, but is also evaluating the basis of the claim. PSE accrued a loss reserve in the amount of $1.1 million in the second quarter of 2004 charging Electric Generation Fuel expense in connection with this matter.
In addition, the Management Service of the United States Department of the Interior issued two orders to WECO in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. PSE’s share of the alleged additional royalties is $1.8 million, which is equivalent to PSE’s 25% ownership interest in Colstrip 3 & 4. The transportation agreement provides for the construction and operation of a conveyor system that runs several miles from the mine to the Colstrip 3 & 4 units. WECO has appealed these orders and PSE is monitoring the process. PSE believes that the Colstrip 3 & 4 owners have reasonable defenses in this matter based upon its review. Neither the outcome of this matter nor the associated costs can be predicted at this time.
Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with BPA decreased $1.6 million and increased an insignificant amount for the three and six months ended June 30, 2004, respectively, when compared to the same periods in 2003. The overall decrease in the second quarter 2004 was a result of decreased residential electrical load. The residential exchange credit is a pass-through tariff item with a corresponding credit in electric operating revenue. It has no impact on electric margin or net income.
Unrealized gain on derivative instruments for the three and six months ended June 30, 2004 increased $2.8 million and $2.4 million, respectively, compared with the same periods in 2003. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into both physical and financial contracts to manage its energy resource portfolio including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
PSE has a contract with a counterparty whose debt ratings have been below investment grade since 2002. The contract, a physical gas supply contract for one of PSE’s electric generating facilities, was marked-to-market beginning in the fourth quarter of 2003. Although the counterparty continues to fully perform on the physical supply contract, the counterparty’s credit ratings have remained weak. Prior to October 1, 2003, the contract was designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as management deemed that delivery is not probable through the term of the contract, which expires December 2008.
Another physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the first quarter of 2004. The counterparty notified PSE in the first quarter 2004 that it believes it will be unable to deliver physical gas supply beginning November 2005 through the end of the contract in June 2008. PSE concluded that it is no longer probable that the counterparty will perform on this contract through the end of the term of the contract. The contract was previously designated as a normal purchase under SFAS No. 133. PSE has also concluded that it is appropriate to reserve a portion of the marked-to-market gain on this contract due to the risk of the counterparty not performing, beginning November 2005 through the end of the contract as delivery is not probable during this time period. As a result, PSE recorded an unrealized gain, net of a reserve, of $2.3 million in the second quarter 2004. Approximately $2.2 million of the unrealized gain will be reversed as transactions settle in 2004.
Production operations and maintenanceexpense decreased $0.9 million and $1.3 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. The decrease primarily relates to lower overhaul maintenance performed on Colstrip Units 1 & 2 in the second quarter 2004 compared to the same period in 2003.
Low-income Programcosts, which are a pass-through tariff item, decreased $1.0 million and $2.7 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. Low-income program costs are dependent upon the amount collected from customers through rates.
Other utility operations and maintenancecosts increased $1.2 million and $7.1 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. The increase is due primarily to a $1.9 million and $6.4 million increase in storm damage costs for the three and six months ended June 30, 2004, respectively. The increase in storm costs for the three months ended June 30, 2004 were associated with a sudden windstorm in April 2004. The storm costs for the six months ended June 30, 2004, were also affected by a severe ice storm in January 2004.
Depreciation and amortization expense increased $1.9 million and $3.1 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003 due primarily to the effects of new plant placed into service during 2004 and the latter half of 2003.
Taxes other than income taxes decreased $0.3 million and increased $9.0 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. The overall increase for the six months ended June 30, 2004 was primarily due to higher municipal and state excise taxes which are revenue based.
Income taxes decreased $7.6 million and $3.0 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003 as a result of lower pre-tax operating income partially offset by the non-recurrence of one-time tax benefits in the second quarter 2003.
Other incomedecreased $0.7 million and $1.4 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. The decrease is primarily due to a gain on the sale of securities in May 2003 of $1.9 million. In addition, PSE incurred a fine of $0.3 million at its Jackson Prairie facility in June 2004 resulting from a U.S. Department of Transportation safety inspection conducted in 2001.
Interest charges decreased $3.0 million and $7.3 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. This decrease is primarily due to the redemption or maturity of $217.0 million of Medium-Term Notes with interest rates ranging from 6.07% to 8.59% since December 31, 2002, 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% in March 2003. The decrease in interest expense was partially offset by the issuance of $150 million of 3.363% Senior Notes in May 2003 and the consolidation of the conservation trust bonds due to FIN 46R.
Also included in earnings per share are preferred stock dividend accrual expenses. During the three and six months ended June 30, 2004, preferred stock dividend accrual expense decreased $1.8 million and $3.7 million, respectively, compared with the same periods in 2003. This decrease is due to the redemption of $41.3 million of $100 par value 7.75% preferred stock in August 2003 and $60.0 million of $25 par value 7.45% preferred stock in November 2003.
InfrastruX
The changes to items affecting net income for the three and six months ended June 30, 2004 in comparison with the same periods in 2003 are summarized in the table below.
Comparative Three and Six Months Ended
June 30, 2004 vs. June 30, 2003
Increase (Decrease)
(Dollars in Millions)
| | Three Months
Ended
| Six Months
Ended
|
| Operating revenue change: | | | | | | | | |
| Non-utility construction services | | | $ | 0 | .5 | $ | 4 | .6 |
|
| Operating expense changes: | | |
| Other operations and maintenance | | | | 1 | .0 | | (2 | .6) |
| Depreciation and amortization | | | | -- | | | 1 | .0 |
| Taxes other than income taxes | | | | (0 | .8) | | (0 | .2) |
| Income taxes | | | | -- | | | 2 | .7 |
|
| Total operating expense change | | | | 0 | .2 | | 0 | .9 |
|
| Other income change | | | | 0 | .1 | | 0 | .1 |
| Interest charges change | | | | 0 | .3 | | 0 | .3 |
| Minority interest change | | | | -- | | | 0 | .3 |
|
| Net income change | | | $ | 0 | .1 | $ | 3 | .2 |
| |
|
The following is additional information pertaining to the changes outlined in the above table.
InfrastruX revenue increased $0.5 million and $4.6 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003 due primarily to the acquisition of one company late in the second quarter of 2003, which contributed $5.9 million and $12.4 million to the three and six months ended June 30, 2004, respectively. The increase was partially offset by lower revenues from existing companies as a result of exiting unprofitable business lines and the completion of a large project in 2003 that was not repeated in 2004. InfrastruX operations are seasonal, with its highest revenues typically in the second and third quarters of the year.
InfrastruX operations and maintenanceexpenses increased $1.0 million for the three months ended June 30, 2004 compared to the same period in 2003 as a result of slightly higher core company revenues and the timing of expenditures related to core company revenues. Operations and maintenance expenses decreased $2.6 million for the six months ended June 30, 2004 compared to the same period in 2003 as a result of overall increased operating efficiencies and implemented cost control measures.
Depreciation and amortizationexpense changed by an insignificant amount and increased $1.0 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003 primarily due to an increase in assets through a company acquisition late in the second quarter of 2003.
Income taxes changed by an insignificant amount and increased $2.7 million during the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003 due primarily to higher operating income in the first quarter of 2004.
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, 2004:
| Puget Energy | | Payments Due Per Period
|
Contractual Obligations
(Dollars in millions)
| Total
| 2004
| 2005-2006
| 2007-2008
| 2009 and
Thereafter
|
| Short-term debt | | | $ | 52 | .4 | $ | 50 | .4 | $ | 2 | .0 | $ | | -- | $ | | -- |
| Long-term debt | | | | 2,165 | .3 | | 60 | .0 | | 126 | .7 | | 444 | .6 | | 1,534 | .0 |
| Junior subordinated debentures payable | | |
| to a subsidiary trust (1) | | | | 280 | .3 | | | -- | | | -- | | | -- | | 280 | .3 |
| Mandatorily redeemable preferred stock | | | | 1 | .9 | | | -- | | | -- | | | -- | | 1 | .9 |
| Service contract obligations | | | | 178 | .8 | | 10 | .2 | | 43 | .5 | | 50 | .5 | | 74 | .6 |
| Capital lease obligations | | | | 7 | .3 | | 0 | .9 | | 3 | .8 | | 2 | .3 | | 0 | .3 |
| Non-cancelable operating leases | | | | 63 | .5 | | 9 | .0 | | 25 | .1 | | 19 | .0 | | 10 | .4 |
| Fredonia combustion turbines lease (2) | | | | 67 | .4 | | 2 | .2 | | 8 | .7 | | 8 | .5 | | 48 | .0 |
| Energy purchase obligations | | | | 5,022 | .8 | | 535 | .8 | | 1,510 | .1 | | 1,184 | .3 | | 1,792 | .6 |
| Financial hedge obligations | | | | (36 | .5) | | (10 | .0) | | (17 | .9) | | (8 | .6) | | | -- |
| Non-qualified pension funding | | | | 28 | .6 | | 1 | .1 | | 3 | .1 | | 4 | .5 | | 19 | .9 |
|
| Total contractual cash obligations | | | $ | 7,831 | .8 | $ | 659 | .6 | $ | 1,705 | .1 | $ | 1,705 | .1 | $ | 3,762 | .0 |
| |
|
| | | Amount of Commitment
Expiration Per Period
|
Commercial Commitments
(Dollars in millions)
| Total
| 2004
| 2005-2006
| 2007-2008
| 2009 and
Thereafter
|
| Guarantees (3) | | | $ | 136 | .0 | $ | | -- | $ | | -- | $ | 136 | .0 | $ | | -- |
| Liquidity facilities - available (4) | | | | 321 | .8 | | | -- | | | -- | | 321 | .8 | | | -- |
| Lines of credit - available (5) | | | | 31 | .9 | | 3 | .6 | | 18 | .8 | | 9 | .5 | | | -- |
| Energy operations letter of credit | | | | 0 | .5 | | 0 | .5 | | | -- | | | -- | | | -- |
|
| Total commercial commitments | | | $ | 490 | .2 | $ | 4 | .1 | $ | 18 | .8 | $ | 467 | .3 | $ | | -- |
| |
|
_________________
| (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) | See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below. |
| (3) | In May 2004, InfrastruX signed a three-year credit agreement with a group of banks to provide up to $150 million in financing. Under the credit agreement, Puget Energy is the guarantor of the line of credit. Certain InfrastruX subsidiaries also have certain borrowing capacities for working capital purposes of which Puget Energy is not a guarantor. |
| (4) | At June 30, 2004, PSE had available a three-year $350 million unsecured credit agreement and a three-year $150 million receivables securitization facility. At June 30, 2004, PSE had $0.4 million of receivables available for sale under its receivables securitization facility. See “Accounts Receivable Securitization Program” under “Off-Balance Sheet Arrangements” below for further discussion. The credit agreement and securitization facility provide credit support for an outstanding letter of credit totaling $0.5 million and commercial paper of $28.1 million, thereby effectively reducing the available borrowing capacity under these liquidity facilities to $321.8 million. |
| (5) | Puget Energy has a $15 million line of credit with a bank. At June 30, 2004, $5.0 million was outstanding, reducing the available borrowing capacity under this line of credit to $10.0 million. InfrastruX has $186.7 million in lines of credit with various banks to fund capital credit requirements of InfrastruX and its subsidiaries. InfrastruX and its subsidiaries had outstanding loans of $160.3 million and letters of credit of $4.5 million at June 30, 2004, effectively reducing the available borrowing capacity under these lines of credit to $21.9 million. |
Puget Sound Energy. The following are PSE's aggregate contractual obligations and commercial commitments as of June 30, 2004:
| Puget Sound Energy | | Payments Due Per Period
|
Contractual Obligations
(Dollars in millions)
| Total
| 2004
| 2005-2006
| 2007-2008
| 2009 and
Thereafter
|
| Short-term debt | | | $ | 28 | .1 | $ | 28 | .1 | $ | | -- | $ | | -- | $ | | -- |
| Long-term debt | | | | 2,002 | .8 | | 52 | .5 | | 112 | .0 | | 304 | .5 | | 1,533 | .8 |
| Junior subordinated debentures payable | | |
| to a subsidiary trust (1) | | | | 280 | .3 | | | -- | | | -- | | | -- | | 280 | .3 |
| Mandatorily redeemable preferred stock | | | | 1 | .9 | | | -- | | | -- | | | -- | | 1 | .9 |
| Service contract obligations | | | | 178 | .8 | | 10 | .2 | | 43 | .5 | | 50 | .5 | | 74 | .6 |
| Non-cancelable operating leases | | | | 50 | .1 | | 5 | .3 | | 17 | .6 | | 16 | .8 | | 10 | .4 |
| Fredonia combustion turbines lease (2) | | | | 67 | .4 | | 2 | .2 | | 8 | .7 | | 8 | .5 | | 48 | .0 |
| Energy purchase obligations | | | | 5,022 | .8 | | 535 | .8 | | 1,510 | .1 | | 1,184 | .3 | | 1,792 | .6 |
| Financial hedge obligations | | | | (36 | .5) | | (10 | .0) | | (17 | .9) | | (8 | .6) | | | -- |
| Non-qualified pension funding | | | | 28 | .6 | | 1 | .1 | | 3 | .1 | | 4 | .5 | | 19 | .9 |
|
| Total contractual cash obligations | | | $ | 7,624 | .3 | $ | 625 | .2 | $ | 1,677 | .1 | $ | 1,560 | .5 | $ | 3,761 | .5 |
| |
|
| | | Amount of Commitment
Expiration Per Period
|
Commercial Commitments
(Dollars in millions)
| Total
| 2004
| 2005-2006
| 2007-2008
| 2009 and
Thereafter
|
| Liquidity facilities - available (3) | | | $ | 321 | .8 | $ | | -- | $ | | -- | $ | 321 | .8 | $ | | -- |
| Energy operations letter of credit | | | | 0 | .5 | | 0 | .5 | | | -- | | | -- | | | -- |
|
| Total commercial commitments | | | $ | 322 | .3 | $ | 0 | .5 | $ | | -- | $ | 321 | .8 | $ | | -- |
| |
|
_________________
(1) See note (1) above.
(2) See note (2) above.
(3) See note (4) 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, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE in December 2002. Pursuant to the Receivables Sales Agreement, PSE sold all 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 a third party. The Receivables Purchase Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the third party. The amount of receivables sold by Rainier Receivables is not permitted to exceed $150 million at any time. However, the maximum amount may be less than $150 million depending on the outstanding amount of PSE’s receivables, which fluctuate with the seasonality of energy sales to customers.
The receivables securitization 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 fees to the purchasers that are comparable to interest rates on a revolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables held by the purchasers declines until Rainier Receivables elects to sell additional receivables to the purchasers.
The receivables securitization facility has a three-year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At June 30, 2004, Rainier Receivables had sold $145.0 million of accounts receivable and the maximum receivables available for sale was $0.4 million.
During the three and six months ended June 30, 2004, Rainier Receivables sold a cumulative $145.0 million and $267.0 million of receivables. No amounts were sold for the same periods in 2003.
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 August 2004. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At June 30, 2004, PSE’s outstanding balance under the lease was $57.7 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.
New Generation Resources
In April 2003, PSE completed the purchase of a 49.85% interest in a gas-fired electric generating station located within Western Washington (Fredrickson 1). The purchase has added $80.8 million in utility plant at June 30, 2004 and approximately 124 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 cost of the new generating facility and other power costs. The acquisition of Fredrickson 1 was approved by the Washington Commission on April 7, 2004 and was also approved by FERC under the Federal Power Act on April 23, 2004. In addition, PSE has issued a request for proposals to acquire up to 355 average MW of electric power resources, including generation energy from wind power for its electric-resource portfolio and is currently evaluating responses.
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 $158.8 million and $224.6 million for the three and six months ended June 30, 2004. PSE estimates construction expenditures will total approximately $408 million in 2004, which includes the acquisition of the 49.85% interest in the Fredrickson 1 generating facility. Expenditures in 2005 and 2006 are expected to be $359 million and $327 million, respectively, excluding amounts for new generating resources currently under evaluation. 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 $4.9 million and $10.6 million for the three and six months ended June 30, 2004. Puget Energy expects InfrastruX’s capital additions to be $16.2 million in 2004, $18.0 million in 2005, and $20.0 million in 2006. Capital addition estimates are subject to periodic review and adjustment in light of changing economic and regulatory factors.
Capital Resources
Cash From Operations.Cash generated from operations for the six months ended June 30, 2004 was $291.7 million. During the period, $45.4 million in cash was used for AFUDC and payment of dividends. Consequently, cash flows available for utility construction expenditures and other capital expenditures were $246.3 million or 102.0% of the $241.4 million in construction expenditures (net of AFUDC) and other capital expenditure requirements for the period. For the same period in 2003, cash generated from operations was $154.5 million, $44.9 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 six months ended June 30, 2003 were $109.6 million, or 73.3% of the $149.5 million in construction expenditures. The increase in cash generated from operations from 2004 compared to 2003 is primarily due to the utilization of the accounts receivable securitization program starting in December 2003 and collection of accounts receivable. These items combined provided $76.3 million additional operating cash flow for the six months ended June 2004 compared with the same period in 2003. In addition, increases in the PGA mechanism rates in April and October 2003 provided an additional $47.8 million in operating cash flow.
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 are 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 2004 and 2005 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, 2004, PSE could issue: |
| • | approximately $982 million of first mortgage bonds, as PSE has approximately $1.8 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 at an assumed interest rate of approximately 5.6% on a ten-year first mortgage bond. PSE’s interest coverage ratio at June 30, 2004 was 2.8 times net earnings available for interest. PSE currently has $3.7 billion in electric and gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest; |
| • | approximately $280.2 million of additional preferred stock at an assumed dividend rate of 7.25%; and |
| • | approximately $256.9 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 interest rate spreads over the index and commitment fee increase as PSE’s secured long-term debt ratings decline. An interest rate 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, respectively. 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 4, 2004 were:
| | Ratings
|
| | Standard & Poor’s
| Moody’s
|
| Puget Sound Energy | | |
|
| Corporate credit/issuer rating | BBB- | Baa3 |
| Senior secured debt | BBB | Baa2 |
| Shelf debt senior secured | BBB | (P)Baa2 |
| Trust preferred securities | BB | Ba1 |
| Preferred stock | BB | Ba2 |
| Commercial paper | A-3 | P-2 |
| Revolving credit facility | * | Baa3 |
| Ratings outlook | Positive | Stable |
| |
| Puget Energy |
|
| Corporate credit/issuer rating | BBB- | Ba1 |
* Standard & Poor’s does not rate credit facilities.
| Shelf Registrations. In January 2004, Puget Energy and PSE filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $500 million of: |
| • | | common stock of Puget Energy, |
| • | | senior notes of PSE, secured by a pledge of PSE’s first mortgage bonds. |
On July 15, 2004, PSE issued $200 million in floating rate senior notes under its existing $500 million shelf registration statement, reducing the available balance for issuance under the shelf registration statement to $300 million. The notes float at the three-month LIBOR rate plus 0.30%, mature on July 14, 2006, and can be redeemed at any time after January 15, 2005. PSE used the net proceeds from the sale of the floating rate senior notes to repay outstanding amounts under its commercial paper and accounts receivable securitization programs, including amounts incurred to repay long-term debt, and will also be used to redeem $55 million in principal amount of first mortgage bonds at a premium of 3.68% on August 14, 2004.
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.
In May 2004, PSE entered into a three-year, $350 million unsecured credit agreement with a group of banks which replaced its previous $250 million unsecured credit agreement. PSE also has 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 June 30, 2004, PSE had available $350 million in the unsecured credit agreement and $0.4 million available from the receivable securitization facility (net of $145.0 million sold), which provide credit support for outstanding commercial paper and outstanding letters of credit. At June 30, 2004, there was $28.1 million outstanding under the commercial paper program and $0.5 million under the letters of credit, effectively reducing the available borrowing capacity under the liquidity facilities to $321.8 million.
In May 2004, InfrastruX entered into a three-year, $150 million credit agreement with a group of banks, replacing its previous $150 million credit agreement. Puget Energy is the guarantor of the line of credit. As a result, InfrastruX paid off $134 million of the previous credit agreement under the new credit facility. In addition, InfrastruX’s subsidiaries have an additional $36.7 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 June 30, 2004, InfrastruX and its subsidiaries had outstanding loans of $160.3 million and letters of credit of $4.5 million effectively reducing the available borrowing capacity under these lines of credit to $21.9 million.
In May 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 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. Puget Energy has $5.0 million outstanding under the credit agreement at June 30, 2004.
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 $3.8 million (178,551 shares) and $7.7 million (354,176 shares) for the three and six months ended June 30, 2004 compared to $3.9 million (176,806 shares) and $7.6 million (369,571 shares) for the same periods in 2003.
Common Stock Offering Programs. To provide additional financing options, Puget Energy entered into agreements in July 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to 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.
Other
FERC Hydroelectric Licenses
Baker River Project. The Baker River Project is located upstream of the confluence of the Baker and Skagit Rivers in Whatcom and Skagit Counties and consists of the Lower Baker Development (constructed in 1925) and the Upper Baker Development (constructed in 1959). The Baker River Project’s current license expires on April 30, 2006, and PSE submitted an application for a new license on April 30, 2004. In addition, PSE continues to work with numerous interested participants to achieve a comprehensive settlement agreement to be submitted to FERC during the fall 2004.
Snoqualmie Falls Project. The Snoqualmie Falls Project, built in 1898, had its original license issued May 13, 1975, which was made effective retroactively to March 1, 1956, and expired on December 31, 1993. PSE filed its application to relicense the project on November 25, 1991, and has been operating the project pursuant to annual licenses issued by FERC since the original license expired. On June 29, 2004, FERC granted PSE a new 40-year operating license for the Snoqualmie Falls Project. PSE estimates that the capital investment required to implement the conditions of the new license agreement will cost approximately $44 million. These conditions include modified operating procedures and various project upgrades that include better protection of fish, development of riparian habitat to promote fish propagation, increased minimum flows in the Snoqualmie River during low-water periods and the development of recreational amenities near the down-river power house. PSE accepted the FERC license in July 2004.
Electric Rate Matters
On April 5, 2004, PSE filed a general tariff electric rate case with the Washington Commission. The electric rate case proposes a 5.7% or $81.6 million annual increase to electric rates to recover costs associated with extending and upgrading facilities to serve a growing number of electric customers as well as strengthen PSE financially to serve its customers. The resolution of the electric general rate case may be up to an 11-month process from the time the electric general rate case was filed.
On April 23, 2004, the acquisition of a 49.85% interest in the Fredrickson 1 generating facility was approved by FERC. Prior to that approval, on April 7, 2004, the Washington Commission issued an order in PSE’s power cost only rate case granting approval for the acquisition of the Fredrickson 1 generating facility as well. As a result of these approvals, PSE completed the acquisition in the second quarter of 2004. In its order, the Washington Commission found the acquisition to be prudent and the cost associated with the generating facility reasonable. The costs associated with the generating facility, including projected baseline gas costs, are approved for recovery in rates.
On May 13, 2004, the Washington Commission also approved other adjustments to power costs that resulted in an increase of cost recovery in rates of $44.1 million annually, beginning May 24, 2004 which includes the ownership, operation and fuel costs of the Fredrickson 1 generating facility.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project, because the 1997 license would have made the White River generation project uneconomical to produce electricity. PSE owns the facilities and associated water rights of the project. As a result of rejecting the license, generation of electricity ceased at the White River Project on January 15, 2004. In the same proceeding described above on April 7, 2004, the Washington Commission approved PSE’s recovery on the unamortized White River Plant investment. At June 30, 2004, the White River Project net book value totaled $65.0 million, which included $47.1 million of net utility plant, $14.8 million of capitalized FERC licensing costs and $3.1 million of costs related to construction work in progress. PSE is seeking recovery of the relicensing and other construction work in progress costs totaling $17.9 million in its general rate filing of April 2004, over a 10-year amortization period. The outcome of this matter is expected no later than the first quarter of 2005.
In June 2003, the Washington State Department of Ecology (WSDE) approved an application for new municipal water rights related to the White River Project reservoir. This approval was sought in connection with PSE’s ongoing efforts to sell the White River Project to be used for commercial purposes. An appeal of the water rights determination made by the WSDE for the project has been pending before the Washington State Department of Ecology Pollution Control Hearings Board (PCHB). A series of briefs were filed during the second quarter 2004 regarding whether to remand the water rights determination to the WSDE for further analysis because the project is not currently generating power. On July 1, 2004, the PCHB informed the parties by letter that it would issue an order remanding the water rights determination to WSDE for further consideration and to suspend the hearing schedule pending remand period. The parties are currently waiting for issuance of that order.
In May 2004, the Puyallup Indian Tribe gave PSE notice of intent to sue for an alleged violation of water quality laws associated with the release of water from the White River Project reservoir. No such lawsuit has been filed and PSE is in discussion with the Puyallup Indian Tribe regarding their concerns. Additionally, PSE has sought, and is awaiting, further direction from the WSDE as to whether any additional actions are necessary to maintain compliance with applicable water quality laws.
In June 2001, PSE and the Bonneville Power Administration (BPA) entered into an amended settlement agreement regarding the Residential Purchase and Sale Program, under which PSE’s residential and small farm customers 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 payment during the period October 1, 2006 through September 30, 2011.
In June 2002, PSE entered into an agreement with BPA, which modified the payment provisions of the June 2001 amended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement for an eight month period beginning February 2003, for a total deferral of $27.7 million. Absent certain adjustments tied to a BPA rate adjustment clause, BPA is to begin paying back the amount deferred with interest over a 60-month period beginning October 1, 2006. In January 2003, PSE filed revised tariff sheets with the Washington Commission to reflect this modification to the agreement, which was approved by the Washington Commission.
In June 2003, BPA adopted its final Record of Decision in its February 2003 rate case, which established a formula under the BPA rate adjustment clause to be used in adjusting the rate that would affect the level of residential exchange benefits for PSE’s customers. The adjustment was approved by FERC on an interim basis and went into effect October 1, 2003. FERC issued final approval of this formula in May 2004.
In May 2004, PSE and BPA entered into an agreement that modified the payment of Residential Exchange Program benefits for the period October 1, 2006 through September 30, 2011. The agreement provides that all benefits in this period will be in the form of cash payments only and defined a new methodology to be used to calculate the residential benefits. In addition, PSE agreed to waive payment of approximately one-half of an available reduction-in-risk discount and deferred payment of the other half of the discount, plus interest, until October 2007.
Tenaska Disallowance. The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a one-time disallowance of $25.6 million for the PCA 1 period (July 1, 2002 through June 30, 2003), which was recorded as a Purchased Electricity expense. The order also established guidelines for future recovery of Tenaska costs. PSE filed a petition for reconsideration and clarification to address certain issues arising from the May 13, 2004 order. As a result, the Washington Commission issued an order on June 7, 2004 denying PSE’s petition for reconsideration, and denying in part, and granting in part, PSE’s petition for clarification. In its order of June 7, 2004, the Washington Commission clarified the financial impact of the disallowance for costs relating to the return on PSE’s Tenaska regulatory asset in the PCA 1 and 3 periods. The amounts were determined to be a $25.6 million one-time disallowance for the PCA 1 period; an estimated disallowance of $11.3 million for the PCA 3 period (July 1, 2004 to June 30, 2005), based upon applying the Washington Commission’s methodology of 50% disallowance on the return on the Tenaska regulatory asset due to projected costs exceeding the benchmark during the period. For the PCA 3 period, approximately $5.6 million would be disallowed in the period July 1, 2004 through December 31, 2004, primarily as a reduction to Electric Operating Revenue, for a cumulative impact on earnings of $31.2 million in 2004 for the PCA 1 and 3 periods for PSE. The PCA 3 reduction in Electric Operating Revenue is the result of the Washington Commission’s order that reflected a reduction in rates of approximately $9.9 million annually. This reduction is to reflect the Washington Commission estimate of the Tenaska disallowance for the PCA 3 period. While the Washington Commission did not expressly address the disallowance for the PCA 2 period (July 1, 2003 through June 30, 2004), PSE estimates the disallowance for the PCA 2 period to be approximately $12.2 million if the Washington Commission were to follow the same methodology as they have ordered for the PCA 3 period. While PSE reserves the right to address the merits of any disallowance in its PCA 2 compliance filing which will be filed in the third quarter of 2004, PSE recorded a $12.2 million disallowance to Purchased Electricity expense in the second quarter of 2004 for the 50% disallowance of the return on the Tenaska regulatory asset in accordance with the Washington Commission’s methodology discussed in their order of May 13, 2004. As a result of the disallowance recorded, the PCA customer deferral of $17.6 million at March 31, 2004 was expensed and a reserve was established to offset future PCA customer deferrals. The reserve balance as of June 30, 2004 was $13.6 million, which is expected to be utilized over the remaining months in 2004 as the excess power costs are shared through the PCA mechanism. The cumulative amount attributable to the disallowance recorded in the second quarter of 2004 was $37.8 million ($24.5 million after-tax) and the total for 2004 is expected to be approximately $43.4 million ($28.1 million after-tax).
Prior to the Tenaska disallowance, PSE’s excess power costs under the PCA mechanism were at the $40 million cap whereas with the Tenaska disallowance the excess power costs at June 30, 2004 are $26.5 million. The excess power cost from June 30, 2004 until the PCA mechanism cap of $40 million is reached, which is expected in November 2004, will be offset by the Tenaska disallowance reserve of $13.6 million for the PCA 1 and 2 periods that was recorded in the second quarter of 2004. Consequently, PSE does not expect earnings through year-end 2004, based on current market conditions, to be impacted by excess power costs.
Below is a summary of the Tenaska disallowances by quarter through December 31, 2004:
Quarter ending
(Dollars in millions)
| 7/02 - 6/03
PCA 1
(ordered/final)
| 7/03 - 6/04
PCA 2
(estimated)
| 7/04 - 12/04
PCA 3
(estimated)
| Total
|
| June 30, 2004 | | $ 25 | .6 | $ 12 | .2 | $ -- | | $ 37 | .8 |
| September 30, 2004 | | | -- | | -- | 2 | .8 | 2 | .8 |
| December 31, 2004 | | | -- | | -- | 2 | .8 | 2 | .8 |
| |
|
| Total | | $ 25 | .6 | $ 12 | .2 | $ 5 | .6 | $ 43 | .4 |
| |
|
In the May 13, 2004 order, the Washington Commission established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
The Washington Commission guidelines for determining future recovery of the Tenaska costs are as follows: |
| 1. | | The Washington Commission will determine if PSE's gas purchasing plan and gas purchases for Tenaska are prudent through the PCA compliance filings. |
| 2. | | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, and if PSE’s actual Tenaska costs fall at or below the benchmark, it will recover fully its Tenaska costs. |
| 3. | | If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but its actual Tenaska costs exceed the benchmark, PSE will only recover 50% of the lesser of: |
| a) | | Actual Tenaska costs that exceed the benchmark or; |
| b) | | The return on the Tenaska regulatory asset (return on the asset would be added last to all other relevant Tenaska costs). |
| 4. | | If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all Tenaska costs (gas, return of and return on Tenaska Regulatory Asset). |
The Washington Commission confirmed that if the Tenaska costs are deemed prudent, PSE will recover the full amount of actual costs and the return of the Tenaska regulatory asset even if the benchmark is exceeded. The projected costs and projected benchmark costs for Tenaska are as follows:
(Dollars in millions)
| Remainder
2004
| 2005
| 2006
| 2007
| 2008
| 2009
| 2010
| 2011
|
| Projected Tenaska costs (*) | | | $ | 96 | .9 | $ | 193 | .7 | $ | 188 | .3 | $ | 181 | .9 | $ | 177 | .8 | $ | 166 | .1 | $ | 159 | .9 | $ | 127 | .7 |
| Projected Tenaska benchmark costs | | | | 85 | .6 | | 159 | .5 | | 167 | .9 | | 175 | .2 | | 182 | .2 | | 189 | .5 | | 197 | .2 | | 157 | .2 |
| |
|
| Over (under) benchmark costs | | | $ | 11 | .3 | $ | 34 | .2 | $ | 20 | .4 | $ | 6 | .7 | $ | (4 | .4) | $ | (23 | .4) | $ | (37 | .3) | $ | (29 | .5) |
| |
|
| Projected 50% disallowance based on | | |
| Washington Commission methodology | | | $ | 5 | .6 | $ | 10 | .9 | $ | 8 | .0 | $ | 3 | .3 | $ | 0 | .5 | $ | | -- | $ | | -- | $ | | -- |
| |
|
_________________
* Projection will change based on market conditions of gas and replacement power costs.
Gas Rate Matters
On April 5, 2004, PSE filed a general tariff gas rate case with the Washington Commission. The gas rate case proposes a 6.3% or $47.2 million annual increase to gas rates to recover costs associated with extending and upgrading facilities to serve a growing number of gas customers as well as strengthen PSE financially to serve its customers. The resolution of the gas general rate case may be up to an 11-month process from the time the gas general rate case was filed.
In 2003, the Washington Commission’s Pipeline Safety staff conducted a natural gas standard inspection for three counties within Washington State in which PSE operates gas pipeline activities. The inspection included a review of procedures, records, and operations and maintenance activities. On June 29, 2004, the Washington Commission issued a complaint to PSE related to those inspections. The Washington Commission’s complaint alleges certain violations of Washington Commission regulations and determined a maximum aggregated fine for the violations of $4.5 million, although the Washington Commission’s Pipeline Safety staff recommended a fine of $1.3 million. PSE is investigating this matter and will meet with the Pipeline Safety staff to review both the allegations and the invitation by the Washington Commission to jointly explore resolution. PSE believes it has reasonable defenses in this matter based upon a preliminary review. Neither the outcome of this matter nor the associated costs, including potential fines, can be predicted at this time.
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, 2003 includes a summary 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, 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. | CAISO Receivable and California Refund Proceeding. In 2001, PG&E and Southern California Edison defaulted on payment obligations owed to various energy suppliers, including the California Independent System Operator Corporation (CAISO) and the California PX. 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. The California PX filed for bankruptcy in 2001, further constraining PSE’s ability to receive payments due to controls placed on the California PX’s distribution of funds by the California PX bankruptcy court and due to the fact that the vast majority of funds owed directly to the CAISO are owed by the California PX. |
| a. | | California Refund Proceeding.On July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers, 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 No. EL00-95 that substantially adopted the recommendations made by an Administrative Law Judge on December 12, 2002, except that the Order also substantially adopts the FERC Staff gas price recommendation from the FERC 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 allows generators to offset their actual gas costs against their refund liability. The CAISO currently estimates that it will be unable to complete the initial financial clearing as to “who owes what to whom” prior to December 2004.
Many of the numerous orders that FERC has issued in Docket No. EL00-95 are now on appeal before the United States Court of Appeals for the Ninth Circuit. On March 23, 2004, the Ninth Circuit consolidated most of these appeals. The now consolidated appeals remain in abeyance pursuant to an August 21, 2002, Ninth Circuit order directing FERC to allow parties to file additional evidence on market manipulation.
On April 27, 2004, the Williams Companies and the California Parties filed a settlement agreement at FERC resolving all issues as between Williams and the California Parties, and Williams and any other market participant willing to opt-in to the settlement. FERC approved the settlement on July 2, 2004, and PSE elected to opt-in to the settlement agreement. As a result of opting in, PSE will receive a nominal distribution (approximately $4,382).
On June 28, 2004, Dynegy, Inc. and its subsidiaries and the California Parties filed a settlement agreement at FERC resolving all issues as between Dynegy and the California Parties, and Dynegy and any other market particiapnt willing to opt-in to the settlement. Under the Dynegy settlement, PSE would receive a distribution of $2,193 if it elects to opt-in. FERC has not yet issued an order approving the settlement.
On July 13, 2004, Duke Energy, Inc. announced a settlement with the California Parties. PSE will determine whether to join that settlement when it is filed at FERC.
FERC Staff has indicated an interest in facilitating further settlement discussions among the parties in this proceeding, and held a settlement conference on June 30, 2004. PSE is currently evaluating the discussion held at the settlement conference. |
| b. | | CAISO Receivable. PSE has a bad debt reserve and a transaction fee reserve applied to the CAISO receivable, such that PSE had a net receivable from the CAISO on June 30, 2004 of $21.3 million. PSE estimates the range for the receivable to be between $21.3 million and $23.0 million, including interest. In its October 16, 2003 Order on Rehearing in this docket, FERC expressly adopted and approved a stipulation that confirmed that two of PSE’s “non-spot market” transactions are not subject to mitigation in the Refund Proceeding. On October 17, 2003, PSE formally presented CAISO with a request that payment be made on these amounts. The CAISO responded to the letter on November 13, 2003, expressing an unwillingness to take the issue up separately or in advance of its cost re-run activities. PSE continues to pursue the issue in filings before FERC.
On May 6, 2004, the Los Angeles Department of Water and Power filed a motion at FERC in Docket No. EL00-95 requesting that FERC issue an order permitting monies to be disbursed from the California PX Settlement Clearing Account and an escrow account established as part of PG&E’s bankruptcy proceeding. The bulk of the monies owed by the CAISO, including the monies owed to PSE, are held in those two accounts. PSE filed an answer in support of the motion on May 21, 2004, and awaits an order from FERC. |
| 2. | Pacific Northwest Refund Proceeding.On June 25, 2003, FERC issued an order terminating the Pacific Northwest refund proceeding, Docket No. 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. Seven petitions for review are now pending before the United States Court of Appeals for the Ninth Circuit. On July 1, 2004, the Court issued an order setting a briefing schedule; initial briefs are due on August 5, 2004. Two of the refund proponents in the proceeding, Port of Seattle, Washington, and City of Tacoma, Washington, have moved to toll the briefing schedule on the grounds that the record filed with the Ninth Circuit by FERC is incomplete. The Ninth Circuit rejected a prior motion to toll the briefing schedule, but has not yet acted on the most recent filing by Port of Seattle and Tacoma. |
| 3. | Orders to Show Cause. On June 25, 2003, FERC issued two show cause orders pertaining to its Western market investigations that commenced individual proceedings against many sellers. One show cause order (Docket Nos. EL03-180, et seq.) seeks to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order. In an order dismissing many of the already-named respondents in the “partnerships” proceeding on January 22, 2004, FERC states that it does not intend to proceed further against other parties.
The second show cause order (Docket Nos. EL03-137, et seq.) named PSE (Docket No. EL03-169) and approximately 54 other entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE and FERC Staff filed a proposed settlement of all issues pending against PSE in those proceedings on August 28, 2003. The proposed settlement, which admits no wrongdoing on the part of PSE, would result in a payment of $17,092 to settle all claims. FERC approved the settlement on January 22, 2004. The California Parties filed for rehearing of that order, repeating arguments that have already been addressed by FERC. On March 17, 2004, PSE filed a motion to dismiss the California Parties’ rehearing request, and awaits FERC action on that motion. PSE continues to believe that the orders to show cause do not raise new issues or concerns and will not have a material adverse impact on the financial condition, results of operation or liquidity of the Company. |
| 4. | 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). The OMOI is investigating sellers’ 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. On May 12, 2004, PSE received a letter from the Director of the OMOI stating that the investigation of PSE has been terminated without the need for further proceedings. PSE does not expect any material adverse impacts on the financial condition of the Company from this FERC investigation. |
| 5. | 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 and other defendants moved to dismiss this case. The court heard oral argument on PSE and defendants’ motions to dismiss on March 26, 2004. By an order filed May 12, 2004, the district court granted the motions and dismissed the lawsuit. The Port of Seattle filed an appeal to the United States Court of Appeals for the Ninth Circuit. Briefs currently are due in the fall 2004. |
| 6. | Wah Chang Suit.In June 2004, Puget Energy and PSE were served a federal summons and complaint by Wah Chang, an Oregon company that makes specialty metals and chemicals. Wah Chang claims that during 1998 through 2001 the Company and other energy companies (and in a separate complaint, energy marketers) engaged in various fraudulent and illegal activities including the transmittal of electronic wire communications to transmit false or misleading information to manipulate the California energy market. The claims include submitting false information such as energy schedules and bids to the California PX, California ISO, electronic trading platforms and publishers of energy indexes. The complaint is similar to the complaint made by the Port of Seattle against PSE in 2003. The Wah Chang case is stayed pending an order from the Judicial Panel on Multi-District Litigation to determine whether to transfer the case from the United States District Court for the District of Oregon to the Multi-District Litigation panel. |
| 7. | California Litigation.Attorney General Case. 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 Ninth Circuit heard oral argument on the motions to dismiss on June 14, 2004 and the parties await the court’s ruling. On July 6, 2004, the United States Court of Appeals for the Ninth Circuit ruled in a related case,People of the State of California, ex rel. Bill Lockyer, Attorney General v. Dynegy, et al., that action against jurisdictional utilities based on the California Business Practices Act for wholesale sales made during 2000 and 2001 are preempted by the Federal Power Act, which supports arguments PSE raised in its dismissal motion. The ruling inDynegy may support dismissal of this litigation.California Class Actions. The plaintiffs allege that all wholesale sellers in the California energy market engaged in anti-competitive behavior in violation of the California Business Practices Act. On June 14, 2004, the court heard oral argument on the defendants’ motions to dismiss and the appeals of the remand orders. The parties await the court’s ruling. The holding in theDynegy case is on related issues and may also support dismissal of this action. |
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 exposes the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk management function monitors and manages these risks using analytical models and tools. The Company manages its energy supply portfolio to achieve three primary objectives: |
| • | | Ensure that physical energy supplies are available to serve retail customer requirements; |
| • | | Manage portfolio risks to limit undesired impacts on the Company’s costs; and |
| • | | Maximize the value of the Company’s energy supply assets. |
The 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 tariffs 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 the use of forward price instruments.
The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility upon the Company. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. The PCA mechanism provides for a sharing of costs and benefits that are graduated over four levels of power cost variances with an overall cap of $40 million (+/-) plus 1% of the excess over the $40 million cap over the four-year period ending June 30, 2006.
Transactions that qualify as hedge transactions under SFAS No. 133 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 June 30, 2004, the Company had an after-tax net asset of approximately $23.7 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain recorded in other comprehensive income. Of the amount in other comprehensive income, 99% of the mark-to-market gain beginning November 2004 has been reclassified out of other comprehensive income to a deferred account due to the Company expecting to reach the $40 million cap under the PCA mechanism in accordance with SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”. The Company also had energy contracts that were marked-to-market at a gain of $1.9 million after-tax through current earnings for both the three and six months ended June 30, 2004 primarily the result of excluding certain contracts from the normal purchase normal sale exemption under SFAS No. 133. A portion of the mark-to-market gain beginning November 2004 has been reclassified to a deferred account due to the Company expecting to reach the $40 million cap under the PCA mechanism in accordance with SFAS No. 71. 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 $7.0 million after-tax and would increase current earnings for those contracts marked-to-market in earnings by $0.4 million after-tax as a result of applying SFAS No.71 for the portion that exceeds the $40 million PCA mechanism cap. |
Counterparty Credit Risk. The Company is subject to credit risk from counterparties based on transactions it enters into during the normal course of business. The Company is exposed to risk to the extent that counterparties fail to perform on their contractual obligations. These counterparties include other utilities, energy trading companies, financial institutions and natural gas production companies. The Company mitigates its exposure by transacting with counterparties that meet minimum credit thresholds, setting credit limits and obtaining master agreements. Credit exposures are reviewed daily to ensure transactions continually meet the Company’s standards.
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 utilizes bank borrowings, commercial paper, line of credit facilities and accounts receivable securitization to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments to manage the interest rate risk associated with these debts. The Company did not have any swap instruments outstanding as of June 30, 2004.
| 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’ President and Chief Executive Officer and Senior Vice President 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 President and Chief Executive Officer and Senior Vice President 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
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, 2004. 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 4, 2004. At the annual meeting, the shareholders elected four directors to hold office until the annual meeting of shareholders in 2007 or until their successors are elected and qualified. The vote was as follows:
| | Number of Shares |
|---|
| | For
| Withheld
|
|---|
| Term Expiring 2007 | | | | | |
| Phyllis J. Campbell | | 78,395,328 | | 1,360,643 | |
| Stephen E. Frank | | 77,922,510 | | 1,833,461 | |
| Dr. Kenneth P. Mortimer | | 77,830,163 | | 1,925,808 | |
| Stephen P. Reynolds | | 78,543,032 | | 1,212,939 | |
There were no abstentions and no broker non-votes.
The terms of the following directors continued after the annual meeting:
| | Charles W. Bingham |
| | Robert L. Dryden |
| | Sally G. Narodick |
| | Douglas P. Beighle |
| | Craig W. Cole |
| | Tomio Moriguchi |
| Item 6. | | Exhibits and Reports on Form 8-K |
| (a) | | See Exhibit Index for list of exhibits. |
| | | Filed by Puget Energy and Puget Sound Energy |
| | | Form 8-K dated April 6, 2004, Item 5 — Other Events related to the filing of an electric and gas general rate increase proposal. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on 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, 5 2004 | Chief accounting officer duly authorized to sign this
report on behalf of each registrant |
EXHIBIT INDEX
The following exhibits are filed herewith:
| | 10.1 | | Credit Agreement dated May 27, 2004 between PSE and various banks named therein, Union Bank of California as administrative agent. |
| | 10.2 | | Credit Agreement dated May 27, 2004 between InfrastruX Group, Inc. and various banks name therein, Union Bank of California as administrative agent. |
| | 12.1 | | Statement setting forth computation of ratios of earnings to fixed charges (1999 through 2003 and 12 months ended June 30, 2004) for Puget Energy. |
| | 12.2 | | Statement setting forth computation of ratios of earnings to fixed charges (1999 through 2003 and 12 months ended June 30, 2004) 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. |
