On March 28, 2003, the IRS filed various proofs of claim for periods through 2001 prior to that date. If there were additional tax liabilities claimed by the IRS, these would be satisfied by fundstaxes in the Enron bankruptcy, estate aheadincluding a claim for approximately $111 million in respect to income tax, interest, and penalties for taxable years for which PGE was included in Enron's consolidated tax return. The IRS seeks to apply $63 million in tax refunds admittedly due Enron against these claims. IRS claims for taxes and prepetition interest have a priority over claims of general unsecured Enron creditors, but claims for postpetition interest would not be allowed,prepetition penalties have no priority and claims for postpetition interest are not allowable in bankruptcy. The Company, along with other corporations in Enron's consolidated tax returns that are not in bankruptcy, are severally liable for prepetition penalties would be treated on a parand postpetition interest, as well as any portion of the claim allowed in the bankruptcy that the IRS does not collect from the debtors.
Enron's management has informed PGE management that Enron is negotiating with the claims of general unsecured creditors.
Although management cannot predict with certainty the outcome of the IRS audit, based on the above, it believes it is unlikely at this time, that any tax claimsin an attempt to resolve issues raised by the IRS would exceedclaims. If the substantial NOLs availableparties do not reach a settlement, the bankruptcy court will decide the actual amount, if any, owed to the Enron consolidatedgovernment in respect to tax, returns. Claims for postpetition interest, and claims for penalties,penalties.
To the extent, if any, could not be offset by these NOLs. Ifthat the IRS did seek payment and Enron did not pay, the IRS could look to one or more members of the consolidated group, including PGE. If the IRS didwould look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that are available for recovery in Enron's bankruptcy proceeding, or to otherwise seek to obtain contributions from the other solvent members of the consolidated group. As a result, management believes the income tax, interest, and penalty exposure to PGE would not be material related(related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's con solidated tax returns.consolidated returns) would not be material. No reserves have been established by PGE for any amounts related to this issue.
PGE management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.
Enron Debtor in Possession Financing- PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a debtor in possession credit agreement with Citicorp USA, Inc. and JP MorganJPMorgan Chase Bank. The agreement was amended and restated in July 2002. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged share s of PGE stock or to exercise control over PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.
Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.
Enron Auction Processes Related to PGE
On May 3, 2002,PGE has been informed by Enron management that the proposal Enron presented to its Unsecured CreditorsCreditors' Committee a proposal under whichon May 3, 2002 to separate certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and operatedoperate them prospectively as a new integrated power and pipeline company. If Enron's proposal werecompany has been withdrawn. Enron continues to be adopted,pursue the inclusionsale of PGE inthrough the new company would be subject to potential sale to a different buyer under a Section 363 auction process which would be supervised by the Bankruptcy Court. Enron's proposal has not been endorsed or approved by the Unsecured Creditors' Committee and is one of many options Enron may pursue.
Onthat it announced on August 27, 2002, Enron announced that it has commenced a formal sales process for its interests in certain major assets, including PGE. In its announcement, Enron indicated that it is extending invitations to visit electronic data rooms containing information on 12 of its most valuable businesses to a broad universe of potential bidders with whom Enron has executed confidentiality agreements.
Enron's announcement stated that the sales process continues Enron's efforts to maximize value and enhance recovery for its creditors. Enron and its advisors, in consultation with the Unsecured Creditors' Committee and its advisors, will evaluate all offers received to determine the combination of bids that maximizes the value of all assets.
Enron and its advisors received initial indications of interest in October 2002. However, Enron has stated that it reserves the right not to sell any of its assetsPGE if the bids received are not deemed fully reflective of the assets'its value.
There can be no assurance as to whether PGE will be sold to a bidder in the auction process described above or ultimately be included in a new integrated power and pipeline company under the proposal presented by Enron to its Unsecured Creditors' Committee in May 2002. A sale of PGE under either scenario would require the consideration and approval of regulatory agencies, including the OPUC.
Enron management has informed PGE that if PGE is not sold in the auction process, it is anticipated that the shares of PGE stock owned by Enron would be distributed over time to creditors of Enron in connection with Enron's plan of reorganization. It is also anticipated that PGE's stock would be listed on a national stock exchange and would be publicly traded. In connection with the distribution to creditors, it is expected that PGE would be governed by an independent Board of Directors. Until these processes resultresolution of the bankruptcy case and distribution of the PGE shares, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of Enron's stakeholders.
Enron has filed a filingmotion with the Bankruptcy Court to extend the time to file its plan of reorganization to June 30, 2003. Until the plan of reorganization or another filing related to the sale of PGE is filed with the Bankruptcy Court and approved, management cannot assess itsthe impact on PGE's business and operations.operations of a sale or the distribution of PGE's stock to Enron's creditors.
Note 8 - New Accounting StandardsAsset Retirement Obligations
PGE adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003. SFAS No. 143 requires the recognition of anyAsset Retirement Obligations (AROs), measured at estimated fair value, for legal obligations related to the dismantlement and restoration costs associated with retiringthe retirement of tangible long-lived assets in the period in which the liability is incurred. Upon initial recognition of AROs that are measurable, the probability weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. Capitalized asset retirement costs are depreciated over the life of the related asset, with accretion of the ARO liability classified as an operating expense on the income statement.Statement of Inc ome. Both amounts are included in Depreciation and Amortization expense for Utility plant and Other Income (Deductions) for Other property on the Statement of Income.
Regulation - Pursuant to regulation, AROs of rate-regulated long-lived assets are included in depreciation expense allowed in rates. Any differences in the timing of recognition of costs for financial reporting and rate-making purposes are deferred as a regulatory asset or regulatory liability under SFAS No.71. PGE is requiredexpects any changes in estimated AROs to comply with SFAS No. 143 beginning January 1,be incorporated in future rates. Substantially all significant AROs are included in rate regulation.
Also through regulation, PGE collects in rates removal costs for certain assets that do not have associated legal asset retirement obligations. At March 31, 2003, and is currently evaluating the impactPGE has an estimated $212 million regulatory liability for these removal costs recorded in Accumulated Depreciation.
Cumulative Effect -Upon adoption of SFAS No. 143, PGE recorded a $2 million after-tax gain in earnings from the cumulative effect of a change in accounting principle related to its tangible long-lived assets, substantially all of which are includedother property. This transition adjustment represents a difference in rate-regulated operations.
using a straight-line amortization vs. accretion methodology under SFAS No. 146, Accounting143.
The $11 million transition adjustment for Costs Associatedrate-regulated utility plant, consisting of the Boardman and Colstrip coal plants, Beaver and Coyote Springs gas turbine plants, and the Bull Run hydro project, is deferred as a regulatory liability pursuant to SFAS No. 71.
The ARO associated with Exit or Disposal Activities, requires the recognitionTrojan plant was recorded on a nominal dollar basis at the time of a liability forits abandonment in 1993, with costs related to exit or disposal activities when the costs are incurred. Previous accounting guidance required the liability to be recovered through regulation recorded at the date of commitment to an exit or disposal plan. PGE is required to comply with SFAS No. 146 beginning January 1, 2003. PGE does not expectas a regulatory asset. With the adoption of SFAS No. 146143, the regulatory asset and the related ARO for the Trojan plant were reduced by $96 million to have an effect on its financial statements.
Note 9 - Preferred Stock
On September 30, 2002, a single share of a new class of Limited Voting Junior Preferred Stock (Stock) was issued by PGEadjust the balances to an independent party. The new classestimated fair value as required by SFAS No. 143.
Asset Retirement Obligations Activity -Upon adoption of stock, created by an amendmentSFAS No. 143, PGE recorded AROs of $15 million for utility plant and $1 million for other property and adjusted the ARO for the Trojan Plant to PGE's Articles of Incorporation, was issued following approval by the Bankruptcy Court, Debtor-in-Possession lenders, the OPUC, and PGE's board of directors.$80 million.
The Stock has a par value of $1.00, a liquidation preferencefollowing presents the proforma effects to the Common Stock as to par value but junior to existing preferred stock, an optional redemption right,balances and activities in AROs for the accounting periods reported herein had SFAS No. 143 been in effect for all periods:
Proforma | Proforma | |||
Three Months Ended | Year Ended | |||
March 31, 2003 | December 31, 2002 | |||
Beginning Balance | $ 96 | $104 | ||
Activity | ||||
AROs incurred | - | - | ||
Expenditures (Trojan) | (6) | (18) | ||
Accretion | 1 | 6 | ||
Revisions | - | 4 | ||
Ending Balance | $ 91 | $ 96 | ||
Unrecognized Asset Retirement Obligations
PGE has certain restrictions on transfer. The Stock also has voting rights,tangible long-lived assets for which limit, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings (Bankruptcy) without the consent of the holder of the share of Stock. The consent of the holder of the share of StockAROs are not measurable. An ARO will not be required ifto be recorded when circumstances change. The assets that may require removal when the reason forplant is no longer in service include the Bankruptcy is to implement a transaction pursuant to which all of PGE's debt will be paid or assumed without impairment.
Note 10 - Long-term Debt
On October 10, 2002, PGE issued $150 million of 8-1/8% First Mortgage Bonds, maturing February 2010. The bonds were issued as a private placement. Net proceeds from this issueOak Grove hydro project and transmission and distribution plant located on public right-of-ways and on certain easements. Management believes that these assets will be used to reduce short-term debt, refinance current maturities of long-term debt, and for other general corporate purposes.
On October 28, 2002, PGE issued $100 million of 5.6675% First Mortgage Bonds, maturing October 2012. The bonds were issued as a private placement. The Company purchased a policy insuring the principal and interest payments on the bonds, which will add approximately 1.5% to annual interest costs. Net proceeds from this issue will be used to reduce short-term debt, refinance current maturities of long-term debt, and for other general corporate purposes.
On October 29, 2002, PGE utilized a portion of the proceeds from the above two bond issuesin utility operations for the early retirement of $150 million in variable rate First Mortgage Bonds due December 16, 2002.foreseeable future.
In addition to the issuance of new long-term debt, management believes that PGE has the ability to use its existing lines of credit, along with cash from operations, to provide the Company with sufficient liquidity to meet its day-to-day cash requirements.
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Results of Operations
The following review of PGE's results of operations should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this report. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, quarterly operating earnings are not necessarily indicative of results to be expected for calendar year 2002.2003.
20022003 Compared to 20012002 for the Three Months Ended September 30March 31
PGE's net income in the thirdfirst quarter of 20022003 was $8$21 million, compared to a net loss of $5$36 million in the thirdfirst quarter of 2001. The increase resulted primarily from higher margins on2002. Earnings were unfavorably impacted by a 4% decline in retail energy sales, asresulting from both warmer weather in the cost of purchased power and generation decreased significantly from the thirdfirst quarter of 2003 and Oregon's continued slow economy. A power cost adjustment mechanism in place during 2002 partially offset the negative earnings impact of lower energy sales in last year.year's first quarter. In addition, the thirdCompany recorded an after tax provision of approximately $7 million in the first quarter of 2001, PGE sold power in excess of its retail load at prices significantly lower than the cost of such power, which had been previously purchased under forward contracts at higher prevailing prices.
PGE purchases wholesale power to meet its retail load as the Company's generating resources are not currently sufficient to meet the demand of retail customers. The Company uses both long-term and short-term purchased power contracts to supplement its thermal and hydroelectric generation to respond to seasonal fluctuations in the retail demand for electricity and variability in generating plant operations. Purchases are also made if they are less than the cost of operating the Company's generating facilities. Wholesale power is purchased in advance to meet forecasted demand, to provide continuing reliability in the event that actual demand exceeds forecasted demand, and to provide for potential outages when conditions threaten future supply. PGE purchases power in the forward market in advance of need, especially when the wholesale market is volatile and future supplies are uncertain.
During most of the 2000-2001 period, reliability concerns were heightened as wholesale market prices were high and volatile and region-wide demand approached supply. These factors, along with forecasted poor hydro conditions, an expected two-year lag in the availability of new generation, and speculation and concerns2003 related to potential FERC-imposedamounts due PGE for certain prior year wholesale price caps, led to predictions of regional power supply shortageselectricity sales made in the winter and summer of 2001 and abnormally high power prices.
The inability to sell excess power at prices covering the cost of such power, combined with poor hydro conditions, led to last year's third-quarter loss.In addition, although PGE was able to defer for future recovery from customers substantial third quarter 2001 power costs, it was also necessaryCalifornia. Results for the Company to absorb considerably higher costs last year under termsfirst quarter of the power cost mechanism then2003 include a $2 million gain from a cumulative effect of a change in effect. Last year's third quarter results also included a nonrecurring $12 million (before taxes) third quarter positive adjustment reflecting results of PGE's SAVE program, under which the Company is allowed recovery in rates of certain costs and incentivesaccounting principle related to the installationadoption of energy efficiency measures.SFAS No. 143.
The following table summarizes Operating Revenues and Energy Sales for the three-month periods ending September 30, 2002first quarter of 2003 and 2001:2002:
| Operating Revenues | ||||||||||
| Three Months Ended |
|
| ||||||||
| September 30, |
|
| ||||||||
| 2002 |
| 2001 |
| Increase/(Decrease) | ||||||
| (In Millions) |
| Amount |
| % | ||||||
Retail | $ | 352 |
| $ | 237 |
| $ | 115 |
| 49% | |
Wholesale - Non Trading |
| 113 |
|
| 235 |
|
| (122) |
| (52%) | |
Wholesale - Trading (net) |
| (1) |
|
| 2 |
|
| (3) |
| * | |
Other |
| (6) |
|
| 6 |
|
| (12) |
| * | |
Total Operating Revenues | $ | 458 |
| $ | 480 |
| $ | (22) |
| (5%) | |
(* not meaningful)
Three Months Ended | ||||||||
March 31, | Increase/(Decrease) | |||||||
Operating Revenues | 2003 | 2002 | Amount | % | ||||
(In Millions) | ||||||||
| ||||||||
Retail | $ 347 | $ 405 | $ (58) | (14%) | ||||
Wholesale (Non-Trading) | 110 | 60 | 50 | 83% | ||||
Other Operating Revenues: | ||||||||
Trading Activities - net | - | (1) | 1 | * | ||||
Other | 14 | - | 14 | * | ||||
Total Operating Revenues | $ 471 | $ 464 | $ 7 | 2% | ||||
Energy Sales | ||||||||
(In Thousands of MWhs) | ||||||||
Retail | 4,752 | 4,942 | (190) | (4%) | ||||
Wholesale (Non-Trading) | 2,672 | 1,817 | 855 | 47% | ||||
Trading Activities | 2,570 | 1,994 | 576 | 29% | ||||
Total Energy Sales | 9,994 | 8,753 | 1,241 | 14% | ||||
(*not meaningful) | ||||||||
The decrease in total OperatingRetail Revenues fromwas caused primarily by lower prices and energy sales. As provided in the third quarter ofOPUC's 2001 was due to significantly lower wholesale prices for sales of energy in excess ofgeneral rate order, PGE reduced its retail customer requirements. Therates on January 1, 2003 to reflect a decrease in Wholesale - Non Trading revenues is attributable to a 67% average price decrease from last year's third quarter due to market forces within the region, including the effects of improved hydro conditions, lower natural gas prices, conservation, and a reduction in demand due to the continued slow economy. Wholesale - Non Trading sales volume increased 46% as energy marketing activity returned from the low levels of 2001 caused by price volatility and uncertainty related to the western energy crisis, with power purchases in excess of retail customer requirements sold in the wholesale market. The increase in Retail revenues was due primarily to a general rate increase that became effective October 1, 2001; energy sales increased 2%, with an approximate 9,500 (1.3%) increase in total customers since the end of last year's third quarter partially offset by a slow economy and energy conservation. The decrease in Other operating revenues was due largely to lower prices on sales of natural gas in excess of generating requirements, as power purchases economically displaced higher priced thermal generation. For further information regarding Wholesale - Trading activities, see Note 2, Price Risk Management, in the Notes to Financial Statements.
The following table indicates retail and wholesale energy sales for the third quarters of 2002 and 2001:
Megawatt-Hours Sold (thousands) | |||
2002 | 2001 | ||
Retail | 4,600 | 4,509 | |
Wholesale - Non Trading | 3,733 | 2,565 | |
Wholesale - Trading | 2,774 | 1,498 | |
Purchased power and fuel costs decreased $70 million (18%) due to both lower prices for power purchases and reduced thermal generation. Lower regional power and natural gas prices resulted in a 56% drop in the average cost of firm power purchases from last year's third quarter. Combined with lower prices for spot market purchases and a 46% decrease in thermal generation, PGE's averageprojected 2003 variable power cost was 57% of last year's third quarter (for further information, see "Power Supply" in the Financial and Operating Outlook section). A 17% increase in total system load resulting from higher wholesale activity, due to both the Company's increased participation in the wholesale energy market and from the sale of power in excess of retail requirements, partially offset the effect of the average cost decrease. Purchased power and fuel expense for the third quarter of 2001 included an $87 million credit related to PGE's power cost mechanism. Although PGE was able to defer this amount for future rate recovery, it was necessary for the Company to absorb $54 million in costs exceeding the power cost baseline established by the OPUC under the mechanism then in effect. In the third quarter of 2002, it was necessary for the Company to absorb $12 million under the power cost mechanism currently in effect.costs. (See "Power Cost Mechanisms""Retail Rate Changes" in the Financial and Operating Outlook section for further information).
PGE Retail energy generation decreased 42%sales declined from last year's thirdfirst quarter dueas a result of both warmer temperatures and increased conservation efforts, with average use for residential and commercial customers declining about 8% and 3%, respectively. Such decreases more than offset an approximate 6,400 increase in total customers during the last year. Increased Wholesale (Non-Trading) Revenues resulted from both higher energy sales and higher market prices. Sales volume increased significantly as energy marketing activity returned from lower levels in last year's first quarter caused by price volatility and uncertainty related to the cost and availa bility of power in western markets. Average wholesale power prices increased 24%, reflecting both planned maintenanceincreased natural gas prices and adverse hydro conditions in the region. The increase in Other Operating Revenues was primarily related to sales of natural gas in excess of generating plant requirements, as power purchases in the wholesale market economically displaced more expensive gas-fired thermal generation. Such sales in the first quarter of 2003 resulted in a $6 million gain, compared to a loss of $8 million in the first quarter of 2002.
Purchased Power and Fuel expense increased $27 million (11%). The economic displacement of combustion turbine generation with lower cost power purchases during the first quarter of 2003 resulted in an 11% decrease in PGE's average variable power cost from the first quarter of 2002. PGE reduced output from its combustion turbine plants by 35% and planned maintenance outages atreplaced it with power purchases that cost an average of 20% less than in the first quarter of 2002; this more than offset a 10% increase in total system load resulting from higher wholesale energy sales. Purchased Power and Fuel expense in the first quarter of 2002 included a $27 million credit related to the Company's coal fired generating plants. Despite significantly improvedpower cost mechanism then in effect, while the first quarter of 2003 includes a $16 million charge for the amortization of costs deferred under the mechanism in 2001 and 2002 which were recovered from customers in the first quarter of 2003. There is currently no power cost adjustment mechanism in place for 2003. Also included i n first quarter 2003 expense is an $11.5 million provision for uncollectible accounts receivable for wholesale electricity sales in the California market. (For further information, see Note 5, Receivables - California Wholesale Market, in the Notes to Financial Statements).
Due to expected adverse hydro conditions in the region, PGE has filed an application with the OPUC seeking deferral, for future recovery from customers, of hydro replacement power costs for the period February 11, 2003 (application date) through December 31, 2003. Operating results for the first quarter of 2003 do not reflect the deferral of such costs, pending OPUC consideration of the Company's hydro energy production decreased 16%, reflecting the January 1, 2002 sale of a 33.33% interestapplication. See "Hydro Replacement Power Costs" in the Company's Pelton Round Butte project.Financial and Operating Outlook section for further information.
Company generation approximated that of last year's first quarter, as a 17% increase in coal-fired generation and a 6% increase in production from PGE's hydro plants largely offset the reduction in combustion turbine generation. Total Company generation met approximately 37%44% of PGE's retail load during the thirdfirst quarter of 2003, compared to 66%43% last year, as lower cost power purchases were utilized to replace higher cost generation.year.
The following table indicates PGE's total system load (including both retail and wholesale) for the third quarters of 2002 and 2001 (excludeswholesale but excluding energy trading activities). Average variable power costs exclude the effect of PGE's power cost mechanisms on purchased power and fuel costs.
Megawatt/Variable Power Costs | |||||
Megawatt-Hours (thousands) | Average Variable Power Cost (Mills/kWh) | ||||
2002 | 2001 | 2002 | 2001 | ||
Generation | 1,809 | 3,146 | 16.6 | 14.4 | |
Firm Purchases | 5,408 | 3,890 | 42.8 | 98.1 | |
Spot Purchases | 1,361 | 324 | 15.8 | 26.8 | |
Total Send-Out | 8,578 | 7,360 | 34.8* | 60.7* | |
(*includes wheeling costs) | |||||
Operating expenses (excluding purchased power and fuel, depreciation and amortization, and taxes) increased $2 million (3%). Administrative and other expenses increased $3 million, with increased corporate overhead expenses, including certain employee benefit costs, partially offset by a reduction in customer support expenses, due primarily to a change in accounting for energy efficiency expenses. Beginning March 1, 2002, as provided by Oregon energy restructuring legislation (Senate Bill 1149), conservation, renewable resource, and weatherization measures are funded by a 3% Public Purpose Charge from retail customers and administered by the non-profit Energy Trust of Oregon. All incurred energy efficiency expenses (previously included in Operating expenses), and related amounts received from the Energy Trust, are included within Other income. Production and distribution expenses decreased by $1 million, due primarily to the termination of fees previously paid to the Confederated Tribes of Warm Springs related to the operation of PGE's Pelton Round Butte hydroelectric project. Such fees, which totaled $2 million in last year's third quarter, are no longer required due to the sale of a 33.33% interest in the project to the Tribes in January 2002. This was partially offset by a $1 million increase in service restoration and other distribution expenses.
Depreciation and amortization expense increased $10 million due primarily to the effect of last year's nonrecurring $12 million regulatory credit reflecting final 2000 and estimated 2001 results of PGE's SAVE program. A $6 million increase in depreciation of utility plant, due to both normal property additions and higher depreciation rates established in the Company's 2001 general rate case, was largely offset by amortization of certain regulatory liabilities, related to certain refunds to customers, and other regulatory amortization.
Taxes other than income taxes increased $2 million primarily due to higher franchise fees resulting from increased retail revenue.
Income taxes increased $21 million primarily due to higher taxable income in this year's third quarter. In addition, there were certain nonrecurring credit adjustments recorded in the third quarter of 2001 related to prior years' amended tax returns and deferred tax and audit adjustments.
Other miscellaneous income decreased $2 million, due primarily to a reserve for interest accrued on the Merger Receivable from Enron in the third quarter of 2002 and to lower interest income related to the Company's power cost mechanism. These were partially offset by the $3 million reversal of a credit reserve established in December 2001 related to income taxes receivable from Enron (for further information, see Note 4, Related Party Transactions, in the Notes to Financial Statements).
2002 Compared to 2001 for the Nine Months Ended September 30
PGE's net income in the first nine months of 2002 was $60 million, compared to $67 million in the same period for 2001. Last year's results included an $11 million gain from a cumulative effect of a change in accounting principle resulting from the adoption of SFAS No. 133 on January 1, 2001. The $4 million increase in net income before the effect of last year's accounting change was due primarily to increased margin on energy sales, as power prices decreased significantly from last year. Last year's resultscontracts) for the first nine months included a nonrecurring $12 million (before taxes) positive adjustment reflecting resultsquarter of PGE's SAVE program. The effect of higher retail rates was partially offset by lower retail energy sales caused by a slowed economy2003 and customer conservation efforts. In addition, last year's results for the first nine months reflect the sale of excess power at prices significantly lower than the cost of such power, previously purchased under forward contracts a t higher prevailing prices. In addition, although PGE was able to defer substantial power costs in the first nine months of 2001, it was also necessary for the Company to absorb considerably higher costs last year under terms of the power cost mechanism then in effect.
The following table summarizes Operating Revenues for the nine-month periods ending September 30, 2002 and 2001:
| Operating Revenues | |||||||||
| Nine Months Ended |
|
| |||||||
| September 30, |
|
| |||||||
| 2002 |
| 2001 |
| Increase/(Decrease) | |||||
| (In Millions) |
| Amount |
| % | |||||
Retail | $ | 1,095 |
| $ | 749 |
| $ | 346 |
| 46% |
Wholesale - Non Trading |
| 274 |
|
| 1,014 |
|
| (740) |
| (73%) |
Wholesale - Trading (net) |
| (1) |
|
| (9) |
|
| 8 |
| * |
Other |
| (7) |
|
| 23 |
|
| (30) |
| * |
Total Operating Revenues | $ | 1,361 |
| $ | 1,777 |
| $ | (416) |
| (23%) |
(* not meaningful)
The decrease in total Operating Revenues from the first nine months of 2001 was due to significantly lower wholesale prices for sales of energy in excess of retail customer requirements. The decrease in Wholesale - Non Trading revenues is attributable to a 79% average price decrease from the first nine months of last year due to market forces within the region, including the effects of improved hydro conditions, lower natural gas prices, conservation, and a reduction in demand due to a slowing economy. Wholesale - Non Trading sales volume increased 31% as energy marketing activity returned from lower levels in 2001 caused by price volatility and uncertainty related to the western energy crisis. In addition, power purchases in excess of retail requirements were sold in the wholesale market; in last year's first nine months, such purchases were used to replace low hydro generation to meet retail load. The increase in Retail revenues was due primarily to a general rate increase that became ef fective October 1, 2001; energy sales decreased 2% as a slowing economy and conservation more than offset an approximate 9,500 (1.3%) increase in total customers from the end of last year's third quarter. Other operating revenues decreased $22 million due largely to lower prices on sales of natural gas in excess of generating requirements, as power purchases economically replaced higher cost thermal generation. For further information regarding Wholesale - Trading activities, see Note 2, Price Risk Management, in the Notes to Financial Statements.
The following table indicates retail and wholesale energy sales for the nine-month periods ending September 30, 2002 and 2001:
Megawatt-Hours Sold (thousands) | |||
2002 | 2001 | ||
Retail | 13,920 | 14,172 | |
Wholesale - Non Trading | 9,378 | 7,140 | |
Wholesale - Trading | 8,761 | 2,695 | |
Purchased power and fuel costs decreased $458 million (35%) due to lower prices for power purchases, lower fuel costs, and reduced thermal generation. Due to both lower regional power and natural gas prices, the average cost of firm power purchases was approximately half that of the first nine months of 2001. Combined with lower prices for spot market purchases and a 47% decrease in thermal generation, PGE's average variable power cost was 57% of last year's first nine months (for further information, see "Power Supply" in the Financial and Operating Outlook section). Purchased power and fuel costs in the first nine months of 2002 include a credit of approximately $26 million related to the Company's current power cost mechanism, compared to an $87 million credit in the first nine months of 2001 under the former mechanism. The current year credit reflects lower revenues from the base established in the Company's most recent rate proceeding. Although PGE was able to defer substantial power costs last year for future recovery from customers, it was necessary for the Company to absorb $54 million in costs that exceeded the baseline established by the OPUC under the power cost mechanism then in effect. In the first nine months of 2002, under the current power cost mechanism, it was necessary to absorb $28 million, which contributed to the decrease in this year's costs from those of last year. (See "Power Cost Mechanisms" in the Financial and Operating Outlook section for further information).
Energy generation from PGE's plants decreased 40% from last year's first nine months due to both planned maintenance and economic displacement of combustion turbine generation and planned maintenance and forced repair outages at the Company's coal fired generating plants. Improved stream flows resulted in hydro energy production almost equal to that of 2001's first nine months despite the loss in generation attributable to the January 1, 2002 sale of a 33.33% interest in the Company's Pelton Round Butte project. Total Company generation met approximately 37% of PGE's retail load during the first nine months of 2002, compared to 62% last year, as lower cost power purchases were utilized to displace higher cost company generation.
The following table indicates PGE's total system load (including both retail and wholesale) for the first nine months of 2002 and 2001 (excludes energy trading activities).2002. Average variable power costs exclude the effect of credits to purchased power and fuel costs related to PGE's power cost mechanisms, as discussed above.
Megawatt/Variable Power Costs | Megawatt/Variable Power Costs | ||||||||||
Megawatt-Hours (thousands) | Average Variable Power Cost (Mills/kWh) | Megawatt-Hours (thousands) | Average Variable Power Cost (Mills/kWh) | ||||||||
2002 | 2001 | 2002 | 2001 | 2003 | 2002 | 2003 | 2002 | ||||
Generation | 5,519 | 9,261 | 15.6 | 19.5 | 2,254 | 2,269 | 22.8 | 16.1 | |||
Firm Purchases | 15,397 | 11,679 | 42.5 | 84.2 | 4,777 | 4,013 | 36.7 | 52.3 | |||
Spot Purchases | 3,219 | 1,298 | 18.7 | 134.0 | 793 | 829 | 46.9 | 25.3 | |||
Total Send-Out | 24,135 | 22,238 | 35.1* | 61.5* | 7,824 | 7,111 | 35.6* | 39.9* | |||
(*includes wheeling costs) | |||||||||||
(*includes wheeling costs)
Operating expensesExpenses (excluding purchased powerPurchased Power and fuel, depreciationFuel, Depreciation and amortization,Amortization, and taxes) increased $8decreased $2 million (4%(3%). Administrative and otherEffective with the March 1, 2002 implementation of Oregon's energy restructuring law, PGE no longer directly provides energy efficiency measures to its retail customers, with such services now administered by the non-profit Energy Trust of Oregon. The resulting decrease in energy efficiency expenses was partially offset by increased $9 million as corporate overhead expenses including(including certain employee benefit costs, increased $6 million and customer support expenses increased $3 million due tocosts), increased provisions for uncollectible customer accounts, and certain customer support expenses.
Depreciation and Amortization expense increased $13 million (31%) due to costs relateddecreased amortization of regulatory liabilities, including credits given to customers in 2002 for gains on certain nonrecurring property sales, and increased amortization of computer software, including the implementation of aCompany's new customer information and billing system. Production and distribution expenses approximatedIn addition, last year's first nine months as lower plant maintenance expensesquarter amortization expense included credits to establish regulatory assets related to the sale of the Pelton Round Butte hydroelectric project and the terminationdeferral, for future recovery from customers, of fees to the Confederated Tribes of Warm Springs were largely offset by higher delivery system costs including tree trimming and other distribution-related work.
Depreciation and amortization expense increased $5 million. Increased depreciation of utility plant, due to both normal property additions and higher depreciation rates established in the Company's 2001 general rate case, resulted in a $19 million increase. In addition, a nonrecurring $12 million regulatory credit related to PGE's SAVE program was recorded in the third quarterimplementation of 2001. Such increases from last year's first nine months were partially offset by increased amortization of regulatory liabilities, related to various refunds to customers.Oregon's electricity restructuring law.
Taxes other than income
Income taxes increased $4decreased $13 million primarily due to higher franchise fees resulting from increased retail revenue.lower taxable income.
Income taxes increased $21 million primarily due to higher taxable income in this year's first nine months. In addition, there were certain nonrecurring credit adjustments recorded in the first nine months of 2001 related to prior years' amended tax returns and deferred tax and audit adjustments.
Other miscellaneous income decreased $5 million, caused primarily by a $5 million reserve for interest accrued on the Merger Receivable from Enron in the first nine months of 2002, a $4 million decrease in the allowance for equity funds used during construction (AFDC) and certain non-utility interest income, a $2 million provision to reflect a decrease in the estimated net realizable value of a gas turbine currently held for sale by the Company, and the $1 million write-off of certain non-utility investments. These were partially offset by a $3 million increase in interest income related to the Company's power cost mechanism, a $2 million reduction in market value losses on trust owned life insurance assets, and the $3 million reversal of a credit reserve established in December 2001 related to income taxes receivable from Enron (for further information, see Note 4, Related Party Transactions, in the Notes to Financial Statements).
Capital Resources and Liquidity
Review of Cash Flow Statement
Cash Provided by Operations is used to meet the day-to-day cash requirements of PGE. Supplemental cash is obtained from external borrowings, as needed.
A significant portion of cash from operations comes from depreciation and amortization of utility plant, charges whichthat are recovered in customer revenues but require no current cash outlay. Changes in accounts receivable and accounts payable can also be significant contributors or users of cash.
Cash provided by operating activities totaled $271$81 million in thethis year's first nine months of 2002quarter compared to $110$76 million used in the same period last year. The increase is due primarily to a $288 million reduction in cash collateral deposit requirements with certain wholesale customers related to the settlement of certain energy contracts, and to a $102 million increase inincreased payments received from wholesalesales to retail electricity sales.customers.
Investing Activities consist primarily of improvements to PGE's distribution, transmission, generation, and general plantgeneration facilities. A $32$4 million reductionincrease in capital expenditures in the first nine monthsquarter of 20022003 is primarily attributable to reduced expenditures for transmissionimprovements and expansion of the PGE's distribution construction. Such decreases were partially offset by increased expenditures relatedsystem to support both new and existing customers within the Company's new customer information and billing system which became operational in August 2002. Capital expenditures in the first nine months of 2001 include $6 million related to construction of a new 24.5 megawatt combustion turbine unit at the Beaver plant site.service territory.
Financing Activitiesprovide supplemental cash for both day-to-day operations and capital requirements as needed. PGE currently relies on short-term bank loans and cash from operations, revolving credit facilities, and long-term financing activities to managesupport such requirements. Although PGE has traditionally utilized commercial paper borrowings in meeting its day-to-day financing requirements. cash requirements, the Company has been unable to access the commercial paper market due to ratings reductions by credit rating agencies.
During the first nine monthsquarter of 2002,2003, PGE repurchased $39 million of the $142 million in Pollution Control Bonds that were remarketed on May 1, 2003 (see below). In addition, the Company reduced its short-term borrowings by $104 million. It repaid $129 million in outstanding commercial paper, utilizing both cash collateral deposits returned by wholesale customers and cash from operations, and borrowed $25 million under its committed credit lines. In addition, PGE paid $15 million in matured First Mortgage Bonds and $7$2 million of conservation bonds and other long-term debt, retired $2 million of preferred stock, and paid $2$1 million in preferred stock dividends.dividends during the first quarter of 2003. No common stock cash dividends were declared in 2002 or in the first quarter of 2003. In July 2002, upon approval of the Company's board of directors, PGE made a non-cash dividend of $27 million to Enron related to the transfer of a receivable balance due from PGH (for further information, see Note 4, Related Party Trans actions, in the Notes to Financial Statements). No other common stock dividends were declared in the first nine months of 2002; management continues to evaluate future declaration of common stock dividends in light of expected cash requirements and other considerations.PGH.
In June 2002, PGE entered into a new $72 million 364-day revolving credit facility with a group of commercial banks, replacing a $200 million credit facility that expired in June 2002. The Company also has a $150 million revolving credit facility that expires in July 2003. Both facilities are secured by First Mortgage Bonds issued by the Company.
On October 10, 2002,April 8, 2003, PGE issued $150$50 million of 8-1/8%5.279% First Mortgage Bonds, maturing February 2010, and on October 28, 2002, PGEApril 2013. The bonds were issued $100 million of 5.6675% First Mortgage Bonds, maturing October 2012.as a private placement. The Company purchased a policy insuring the principal and interest payments on the bonds issued October 28th,Bonds which will add approximately 1.5%1.0% to annual interest costs. Both bond issues were private placements, with netNet proceeds from both issues tothis issue will be used to reduce short-term debt, refinance current maturities of long-term debt and for other general corporate purposes.
On October 29, 2002,May 1, 2003, PGE utilizedremarketed $142 million of Pollution Control Bonds for a portionterm of six years at fixed rates of 5.20% (for $121 million of the proceeds of these two bond issues for the early retirement of $150 million in variable ratebonds) and 5.45% (for $21 million). The bonds are secured by First Mortgage Bonds due December 16, 2002.
PGE has $49 million in long-term debt maturing in 2003, consisting of $40 million in First Mortgage Bonds that mature in August and $9 million of conservation bonds maturing throughout the year. The Company anticipates meeting these obligations through the sale of other long-term debt or the use of its existing credit facilities. In addition, PGE expects to re-market $142 million of unsecured tax-exempt pollution control bonds that will be put back to PGE in May 2003. If the bonds are not re-marketed, PGE anticipates using proceeds from the sale of other long-term debt to pay the bonds.
PGE currently plans to utilize letters of credit to provide funding assurance for certain future decommissioning activities at Trojan. Decommissioning funding assurance is requiredissued by the Nuclear Regulatory Commission for the amount by which total estimated future radiological decommissioning costs exceed actual balances in decommissioning trust accounts. It is currently anticipated that such funding assurance, for an estimated initial amount of $25 million, will be required upon completion of the transfer of spent nuclear fuel to an on-site storage facility in October 2003. Such amount would decrease through late 2005, as radiological decommissioning is completed. The timing and amount of actual funding assurance requirements are subject to change. PGE does not expect that such obligation will have a material effect on its financing requirements.Company.
The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in itsPGE's Articles of Incorporation and the Indenture securing its First Mortgage Bonds.the bonds. As of September 30, 2002,March 31, 2003, PGE has the capability to issue additional First Mortgage Bonds in amounts sufficient to meet its anticipated capital and operating requirements.
PGE is evaluating alternatives for the replacement of its existing revolving credit lines, consisting of a $72 million facility expiring in June 2003 and a $150 million facility expiring in July 2003. Such alternatives include their replacement by a new revolving credit facility and/or issuance of First Mortgage Bonds. The Company's existing revolving credit facilities contain a material adverse change clause and financial covenants that limit consolidated indebtedness, as such term is defined in the facilities, to 60% of total capitalization, and require a minimum 2.25:1 ratio of earnings before interest and taxes to consolidated interest expense. PGE's indebtedness to total capitalization and interest coverage ratios at March 31, 2003 were 44.2% and 2.32:1, respectively. Both facilities are secured by First Mortgage Bonds. In addition, the revolving credit facilities prohibit the payment of any cash dividends by PGE to Enron.
Credit Ratings
PGE's secured and unsecured debt ratings continue to be investment grade from both Moody's Investors Service (Moody's) and Standard and Poor's (S&P), with Fitch Ratings (Fitch) currently carrying a below investment grade rating on the Company, citing PGE's reduced financial flexibility resulting from the Company's status as a subsidiary of an insolvent parent and a difficult capital market environment.
PGE'sCompany. PGE 's current credit ratings are as follows:
Moody's | S&P | Fitch | ||||||
First Mortgage Bonds | Baa2 | BBB+ | BB+ | |||||
Senior unsecured debt | Baa3 | BBB | BB- | |||||
Preferred stock | Ba2 | BBB- | B | |||||
Commercial paper |
| A-2 | Withdrawn | |||||
| Negative |
|
|
|
In order to increase the degree of insulation between PGE and its insolvent parent company, PGE on September 30, 2002 created a new class of Limited Voting Junior Preferred Stock and issued a single share of such stock to an independent party. The stock has voting rights which limit PGE's right to commence a voluntary bankruptcy proceeding without the consent of the holder of the share. For further information, see Note 9, Preferred Stock, in the Notes to Financial Statements.
Should Moody's and S&P reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. On March 31, 2003, PGE had posted, in the form of letters of credit, $22 million of collateral. Based on PGE'sthe Company's non-trading and trading portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of November 1, 2002March 31, 2003, the approximate amount of additional collateral that could be requested upon such a downgrade event is $117$50 million and decreases to approximately $46$44 million by year-end 2002.2003. In addition to collateral calls, such a credit rating reduction would likely have an adverse effect on the terms and conditions of future long-term debt. In addition, any such rating reductions would increase interest rates and fees on PGE's two revolving credit facilities, increasing the cost of funding its day-to-dayday-to- day working capital requirements.
The Company's
PGE's does not have the ability to access the commercial paper market has been adversely affected bydue to the May 2002 ratings reduction for commercial paper by Moody's and Fitch. Management believes that it has the ability to use its existing lines of credit, along with cash from operations, to provide the Company with sufficient liquidity to meet its day-to-day cash requirements.
On May 5, 2003, Fitch issued a press release to announce that PGE's Rating Watch status has been revised from Negative to Positive and that, upon finalization of bank revolver financing, expected to occur by the end of May 2003, it would likely upgrade PGE's secured debt to investment grade.
Although measures of PGE's financial performance, including financial ratios, remain strong, due to continuing uncertainty regarding the impact of Enron's bankruptcy on PGE, management is unable to predict what actions, if any, will be taken by the rating agencies in the future. However, it does believe there are sufficient structural and regulatory mechanisms to protect the Company's assets from Enron and its creditors and there are no economic incentives for Enron to cause PGE to file for bankruptcy protection.
Financial and Operating Outlook
Retail Customer Growth and Energy Sales
Weather adjusted retail energy sales decreased 1.1% for the three months ended March 31, 2003, compared to the same period last year. Industrial sector energy sales were flat, with commercial and residential sales down 0.4% and 2.2%, respectively. PGE forecasts continued flat retail energy sales in 2003, with no growth from 2002 due to Oregon's continued slow economy.
Power Supply
Hydro conditions in the region remain below normal levels. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, currently project the January-to-July runoff at 84% of normal, compared to 97% of normal in 2002.
PGE generated 51% of its retail load requirement in the first quarter of 2003, with hydro generation comprising about 7% of the Company's requirement; short- and long-term purchases were utilized to meet the remaining load. PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers.
The amount of surplus electric generating capability in the western United States, the amount of annual snow pack and its impact on hydro generation, the number and credit quality of wholesale marketers and brokers participating in the energy trading markets, the availability and price of natural gas as well as other fuels, and the availability and pricing of electric and gas transmission all contributed to and have an impact on the wholesale price and availability of electricity. PGE will continue its participation in the wholesale energy marketplace in order to manage its power supply risks and acquire the necessary electricity and fuel to meet the needs of its retail customers and administer its current long-term wholesale contracts. In addition, the Company will continue its trading activities to participate in electricity, natural gas, and crude oil markets.
Enron Bankruptcy
InCommencing in December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE nor numerous other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members, and its stock has been suspendedde-listed from trading on the New York Stock Exchange. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal regulators, including the FERC and the State of Oregon. In March 2002, Enron, substantially all of its subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.
Although PGE is not included in the Enron bankruptcy, it has been affected. The Company has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating. In addition, PGE was also included among those Enron subsidiariesentities suspended from contracting with the federal government. AlthoughThe suspension, which expired in March 2003, had no federal, state, or local governmental entity has ceased to transact business with PGE, and the BPA has stated that the suspension does not affect its sales and purchases of electricity with PGE, the Company believes it does not merit suspension and has begun the process to be removed from the suspension. Management believes the suspension will not have a material adverse effect on PGE business andor operations.
In addition to the general effects discussed above, PGE may have potential exposure to certain liabilities and asset impairments as a result of Enron's bankruptcy. These are:
1. Amounts Due from Enron and Enron-Supported Affiliates in Bankruptcy - As described in Note 4, Related Party Transactions, in the Notes to Financial Statements, PGE is owed approximately $79$82 million from Enron relating to the Merger Receivable (including accrued interestinterest) by Enron at March 31, 2003 (Merger Receivable). Such amount was to September 30, 2002).have been paid by Enron to PGE for price reductions granted to customers, as agreed to by Enron at the time it acquired PGE in 1997. Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the entire amount of this receivable, of which $74 million was recorded in December 2001. On October 15, 2002, PGE submitted proofproofs of claimsclaim to the Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, including $73 million for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, due to uncertainties associated with other receivable balances from Enron and its subsidiary companies which are part of the bankruptcy proceedings, a credit reserve has been established for the entire $2 million remaining balance of such receivablereceivables at September 30, 2002.March 31, 2003.
2. Control Controlled Group Liability - Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plans and tax obligations of Enron.
Pension Plans
Funding Status
The pension plan for the employees of PGE (the PGE Plan) is separate from the Enron pension planCorp. Cash Balance Plan (the Enron Plan). As ofAlthough at December 31, 2001,2002 the total fair value of PGE Plan had assets that exceededwas $16 million lower than the present value of all accrued benefitsprojected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis, and,the PGE Plan remains over-funded on an accumulated benefit obligation basis by about $30 million. Enron's management believes, on a plan termination basis. Based on discussions with Enron management, it ishas informed PGE management's understanding that, as of December 31, 2001,2002, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $90$52 million on a SFAS No. 87 basis and approximately $120$182 million on a plan termination basis. For additional information regarding PGE'sFurther, Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases. The claims are duplicative in nature, representing unliquidated claims for PBGC insurance premiums (the "Premium Claims") and unliquidated claims for due but unpaid minimum funding contributions (the "Contribution C laims") under the Internal Revenue Code of 1986, as amended (the "Tax Code") 29 U.S.C. Section 1082 and claims for unfunded benefit liabilities (the "UBL Claims"). Enron and the relevant sponsors of the defined benefit plans are current on their PBGC premiums and their contributions to the pension plan, see below under "PGE Pension Plan"plans. Therefore, Enron has valued the Premium Claims and the Contribution Claims at $0. The total amount of the UBL Claims is $305.5 million (including $271 million for the Enron Plan, and $24.8 million for the PGE Plan). In addition, Enron management has informed PGE that the PBGC has informally alleged in pleadings filed with the Bankruptcy Court that the UBL claim related to the Enron Plan could increase by as much as 100%. PBGC has provided no support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.
It is permissible, subject to applicable law, for separate pension plans established by companies in the same controlled group to be merged. Enron could direct that the PGE Plan be merged with the Enron Plan. If the plans were merged, theany excess assets in the PGE Plan would reduce the deficiency in the Enron Plan. However, if the plans are not merged, the deficiency in the Enron Plan could become the responsibility of the PBGC, which insures pension plans, including the PGE Plan and the Enron Plan, and the PGE Plan's surplus would be undiminished. Merging the plans would reduce the value of PGE, the stock of which is an asset available to Enron's creditors. PGE's management believes that it is unlikely that either Enron or Enron's creditors would agree to support merging the two plans.
Although the Enron Plan is underfunded and Enron is in bankruptcy,
Enron cannot itself terminate the Enron Plan while it is underfunded unless it provides at least 60 days notice and the PBGC, in the case of solvent entities, or the Bankruptcy Court, in the case of insolvent entities, determines that each member of Enron's controlled group, including PGE, is in financial distress, as defined in ERISA. In the opinion of management, PGE is a solvent entity that does not meet the financial distress test. Consequently, management believes that it is unlikely that Enron can unilaterally terminate the Enron Plan.Plan while it is underfunded. However, Enron could, with consent of the PBGC (see discussion below), seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with ERISA.
The PBGC does have the authority, either by agreement with the Planplan administrator or upon application to and approval by a Federal District Court, to terminate and take over control of underfunded pension plans in certain circumstances. In order to initiate this process, the PBGC must determine that either the minimum funding standard for the plan (see discussion below) has not been met, or that the plan will not be able to pay benefits when due, or that there is a reasonable risk that long-run losses to the PBGC will be unreasonably increased or that certain distributions have been made from the plan. The court must determine that plan termination is necessary to protect participants, the plan, or the PBGC.
Upon termination of aan underfunded pension plan, all members of the controlled group of the plan sponsor become jointly and severally liable for the underfunding, but are not obligated to pay until a demand for payment is made by the PBGC. The PBGC can demand payment from one or more of the members of the controlled group. If payment of the full amount demanded is not made, a lien in favor of the PBGC automatically arises against all of the assets of each member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the aggregate net worth of all controlled group members. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien does not take priority over other previously perfected liens on the assets of a member of the controlled group. Substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Management believes that any lien asserted byb y the PBGC would be subordinate to that lien.
PGE management has been informed by Enron management that on November 15, 2002, Enron informed its employees that it is taking steps to terminate the Enron Plan. As an initial step in terminating the Enron Plan, Enron amended the Enron Plan to cease monthly accruals effective January 1, 2003, so that only interest credits would accrue after that date. Enron also informed its employees that it intends to seek the approval of its Unsecured Creditors' Committee and the U.S. Bankruptcy Court to fully fund and then terminate the Enron Plan in a standard termination. Approval to terminate the Enron Plan also will be requested from the PBGC and the IRS. Enron informed its employees that, if approved, the termination process could take 12 months or longer.
PGE management believes that the proposal to fully fund the Enron Plan and terminate it in a standard termination, if approved and consummated, should eliminate any need for the PBGC to attempt to collect from PGE any liability related to the termination of the Enron Plan. There can be no assurance at this time that the funding and termination will be approved by the Unsecured Creditors' Committee or the Bankruptcy Court or that, upon such approval, Enron will have the ability to obtain funding on acceptable terms.
If the PBGC did look solely to PGE to pay any underfunded amount in respect of the Enron Plan, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover any contributions from the other solvent members of Enron's controlled group. Until such time as the Enron Plan is terminated and the PBGC makes a demand on PGE to pay some or all of theany underfunded amount, PGE has no liability for the underfunded amount and no termination liens arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any underfunded amount assessed by the PBGC. No reserves have been established by PGE for any amounts related to this issue.
Minimum Funding Obligation
If the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in the amount of the missed funding automatically arises against the assets of every member of the controlled group. The lien is in favor of the plan, but may be enforced by the PBGC. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien would not take priority over other previously perfected liens on the assets of a member of the controlled group. If Enron does not timely satisfy its minimum funding obligation in excess of $1 million, a lien will arise against the assets of PGE and all other members of the Enron controlled group. The PBGC would be entitled to perfect the lien and enforce it in favor of the Enron Plan against the assets of PGE and other members of the Enron controlled group. However, substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. PGE management believes that any lien asserted by the PBGC would be subordinate to that lien.
Based on discussions with Enron management, PGE management understands that Enron has made all required contributions to date through Octoberand the next contribution is not due until July 15, 2002.2003. PGE does not know if Enron will make contributions as they become due. Management is unable to predict if Enron will miss a payment and, if so, whether the PBGC would seek to have PGE make any or all of the payment. If the PBGC did look solely to PGE to pay the missed payment, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover contributions from the other solvent members of the Enron controlled group. Until Enron misses contributions exceeding $1 million, PGE has no liability and no liens will arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any missed payments demanded by the PBGC. No reserves have beenbee n established by PGE for any amounts related to this issue.
Retiree Health Benefits
Under COBRA, retirees of a bankrupt employer who lose coverage under a group health plan of the employer as a result of certain bankruptcy proceedings are entitled to elect continuation of health coverage in a group health plan maintained by the bankrupt employer or a member of its controlled group. PGE management understands, based on discussion with Enron management, that Enron provides a plan for health insurance for certain retirees, and that the actuarial liability for such coverage amounted to approximately $70 million at December 31, 2001.2001 (the most recent date for which information is available). Management further understands that to meet its obligation, Enron hashad set aside approximately $34 million of assets in a VEBA trust whichthat may be protected under ERISA from Enron's creditors, leaving an unfunded liability of approximately $36 million at December 31, 2001.
In the event that Enron terminates its retiree group health plan, the retirees must be provided the opportunity to purchase continuing coverage from Enron's group health plan, , if any, or the appropriate group health plan of another member of the controlled group. Neither Enron nor any member of the controlled group would be required to fully fund the benefit or create new plans to provide coverage, and retirees would not be entitled to choose from which plan to obtain coverage. Retirees electing to purchase COBRA coverage would be provided the same coverage that is provided to similarly situated retirees under the most appropriate plan in the Enron controlled group. Retirees electing to continue coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire coverage under COBRA. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.
Management believes that in the event Enron terminates retiree coverage, any material liability to PGE associated with Enron retiree health benefits is unlikely for two reasons. First, based on discussion with Enron management, PGE management understands that most of the retirees that would be affected by termination of the Enron plan are from solvent members of the controlled group and few, if any, live in Oregon. Management believes that it is unlikely that any PGE plans would be found to be the most appropriate to provide COBRA coverage. Second, even if a PGE plan were selected, management believes that retirees in good health should be able to find less expensive coverage from other providers, which will reduce the number of retirees electing COBRA coverage. Management believes that the additional cost to PGE to provide coverage to a limited number of retirees that are unable to acquire other coverage because they are hard to insure or have preexisting conditions will not be material.materi al. No reserves have been established by PGE for any amounts related to this issue.
Income Taxes
Under regulations issued by the U.S. Treasury Department, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with Portland General Corporation.PGC. Based on discussions with Enron's management, PGE management understands that Enron has treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001.2001 and becoming a member of Enron's consolidated group once again on December 24, 2002. On December 31, 2002, PGE and Enron entered into a tax sharing agreement pursuant to which PGE agreed to make payments to Enron that approximate the income taxes for which PGE would be liable if it were not a member of Enron's consolidated group. As of April 30, 2003, PGE has paid $21 million to Enron under the tax sharing agreement.
Enron's management has provided the following information to PGE:
A. Enron's consolidated tax returns through 1995 have been audited and are closed. Management understands that the IRS is currently auditinghas completed an audit of the consolidated tax returns for 1996-2001. Enron's consolidated tax return for 2001 was filed on September 13, 2002 and Enron expects this return and claims by the IRS, if any, to be included in the bankruptcy process, as described below.
B.
- For years 1996-1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which
will bewas carried back to the tax year 2000,and is anticipated to result infor which Enron seeks a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries substantial NOLs for any additional income tax liabilities that may result from theongoingnegotiation of the claim stemming from the IRS audit for the periods in which PGE was a member of Enron's consolidated federal income tax returns.However, - Enron's 2002 tax return has not yet been filed. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2002. Enron expects that, in addition to offsetting its income tax liabilities for years before 2002, these NOLs will be sufficient to fully offset Enron's regular and alternative minimum income tax liabilities for 2002 and its regular income tax liability for all subsequent periods through the
extentdate of consummation of its plan of reorganization. - Enron believes that
such audit results in interest owing byall of the requirements for re-consolidation of PGE with the Enron consolidated groupfor periods after Enron filed its bankruptcy petition ("postpetition interest") or in penalties that would nothavea statutory priority over general unsecured creditors,been met. However, because of theIRS could seek to collect such amounts from consolidated group members not in bankruptcy, such as PGE. The last day thatinherently factual nature of theIRSdetermination of the re-consolidation, there canfile a proof of claim for prepetition taxes in the bankruptcy case is March 31, 2003. It is anticipatedbe no assurance that the IRS willfile a proof of claim through 2001 prior toagree with this position. In the event thatdate. If there were additional tax liabilities claimed bythe IRSthese would be satisfied by fundsdoes not agree and the matter is not resolved in the bankruptcyestate aheadproceeding (or otherwise), PGE will have an administrative expense claim against Enron for any amounts paid by PGE to Enron under the tax sharing agreement. Enron management believes that all administrative expense claims will be paid in full.
On March 28, 2003, the IRS filed various proofs of claim for taxes in the Enron bankruptcy, including a claim for approximately $111 million in respect to income tax, interest, and penalties for taxable years for which PGE was included in Enron's consolidated tax return. The IRS seeks to apply $63 million in tax refunds admittedly due Enron against these claims. IRS claims for taxes and prepetition interest have a priority over claims of general unsecured Enron creditors, but claims for postpetition interest would not be allowed,prepetition penalties have no priority and claims for postpetition interest are not allowable in bankruptcy. The Company, along with other corporations in Enron's consolidated tax returns that are not in bankruptcy, are severally liable for prepetition penalties would be treated on a parand postpetition interest, as well as any portion of the claim allowed in the bankruptcy that the IRS does not collect from the debtors.
Enron's management has informed PGE management that Enron is negotiating with the claims of general unsecured creditors.
Although management cannot predict with certainty the outcome of the IRS audit, based on the above, it believes it is unlikely at this time that any tax claimsin an attempt to resolve issues raised by the IRS would exceedclaims. If the substantial NOLs availableparties do not reach a settlement, the bankruptcy court will decide the actual amount, if any, owed to the Enron consolidatedgovernment in respect to tax, returns. Claims for postpetition interest, and claims for penalties,penalties.
To the extent, if any, could not be offset by these NOLs. Ifthat the IRS did seek payment and Enron did not pay, the IRS could look to one or more members of the consolidated group, including PGE. If the IRS didwould look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that are available for recovery in Enron's bankruptcy proceeding, or to otherwise seek to obtain contributions from the other solvent members of the consolidated group, who are not debtors in the bankruptcy case.group. As a result, management believes the income tax, interest, and penalty exposure to PGE would not be material related(related to any future liabilities from Enron's consolidated tax returns during the per iodperiod PGE was a member of Enron's consolidated tax returns.returns) would not be material. No reserves have been established by PGE for any amounts related to this issue.
ManagementPGE management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.
PGE management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis.assets. Neither PGE nor Enron have guaranteed the obligations of the other. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General CorporationPGC in 1997 (Merger Conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis.
Neither
PGE management does managementnot believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern. PGE believes that in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely the holder of PGE's common stock, and PGE, as a debtor in possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. As debtor in possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management. PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) creditors. No dividends could be paid to Enron, no assets could be sold, and no other transfertr ansfer of funds could be made except with the approval of the Bankruptcy Court after notice to PGE's creditors. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers. Since the issue of whether a Bankruptcy Court has the authority to supersede state regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course. On September 30, 2002, the Company issued to an independent shareholder a single share of a new $1.00 par value class of Limited Voting Junior Preferred Stock which limits, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings without the consent of the shareholder.
Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy. For additional information, see Note 7, Enron Bankruptcy, in the Notes to Financial Statements.
Enron Debtor in Possession Financing
PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a debtor in possession credit agreement with Citicorp USA, Inc. and JP MorganJPMorgan Chase Bank. The agreement was amended and restated in July 2002. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control over PG Eov er PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.
Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy. For additional information, see Note 7, Enron Bankruptcy, in the Notes to Financial Statements.
Enron Auction Processes Related to PGE
On May 3, 2002,PGE has been informed by Enron management that the proposal Enron presented to its Unsecured Creditors' Committee a proposal under whichon May 3, 2002 to separate certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and operatedoperate them prospectively as a new integrated power and pipeline company. If Enron's proposal werecompany has been withdrawn. Enron continues to be adopted,pursue the inclusionsale of PGE inthrough the new company would be subject to potential sale to a different buyer under a Section 363 auction process which would be supervised by the Bankruptcy Court. Enron's proposal has not been endorsed or approved by the Unsecured Creditors' Committee and is one of many options Enron may pursue.
Onthat it announced on August 27, 2002, Enron announced that it has commenced a formal sales process for its interests in certain major assets, including PGE. In its announcement, Enron indicated that it is extending invitations to visit electronic data rooms containing information on 12 of its most valuable businesses to a broad universe of potential bidders with whom Enron has executed confidentiality agreements.
Enron's announcement stated that the sales process continues Enron's efforts to maximize value and enhance recovery for its creditors. Enron and its advisors, in consultation with the Unsecured Creditors' Committee and its advisors, will evaluate all offers received to determine the combination of bids that maximizes the value of all assets.
Enron and its advisors received initial indications of interest in October 2002. However, Enron has stated that it reserves the right not to sell any of its assetsPGE if the bids received are not deemed fully reflective of the assets'its value.
There can be no assurance as to whether PGE will be sold to a bidder in the auction process described above or ultimately be included in a new integrated power and pipeline company under the proposal presented by Enron to its Unsecured Creditors' Committee in May 2002. A sale of PGE under either scenario would require the consideration and approval of regulatory agencies, including the OPUC.
Enron management has informed PGE that if PGE is not sold in the auction process, it is anticipated that the shares of PGE stock owned by Enron would be distributed over time to creditors of Enron in connection with Enron's plan of reorganization. It is also anticipated that PGE's stock would be listed on a national stock exchange and would be publicly traded. In connection with the distribution to creditors, it is expected that PGE would be governed by an independent Board of Directors. Until these processes resultresolution of the bankruptcy case and distribution of the PGE shares, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of Enron's stakeholders.
Enron has filed a filingmotion with the Bankruptcy Court to extend the time to file its plan of reorganization to June 30, 2003. Until the plan of reorganization or another filing related to the sale of PGE is filed with the Bankruptcy Court and approved, management cannot assess itsthe impact on PGE's business and operations.operations of a sale or the distribution of PGE's stock to Enron's creditors.
Public Ownership Initiatives
In August 2002, the City Council of Portland, Oregon passed a resolution authorizing the expenditure of up to $500,000 for professional advice regarding the City's potential acquisition of PGE, including possible condemnation of the Company's assets. The City has signed a confidentiality agreement with Enron to permit it to participate in the Enron auction process relating to PGE.
Initiative petitions are beingwere circulated in counties within which PGE serves retail customers by groups attempting to gatherMultnomah County that obtained sufficient signatures to place measuresa measure on March and May 2003 ballots. Ifan election ballot (expected to be in the fall of 2003) that, if passed, these measures could result in the formation of a Peoples' Utility Districts (PUDs) whichDistrict (PUD) in Multnomah County. In addition, if this measure succeeds, the expressed intent of its supporters is to hold additional elections to expand the boundaries of the district to include all of PGE's service territory. If a PUD is formed, it would have the authority to acquirecondemn PGE's distribution assets within the boundaries of the district. Oregon law prohibits the PUD districts.from condemning thermal generation plants. It is uncertain under Oregon law whether the PUD would be able to condemn PGE's hydro generation plants.
Public hearings, as required by Oregon law, have been held and will continue regarding the proposed PUD. PGE opposes the formation of the PUD and will oppose any efforts to condemn the Company's assets.
Complaints to OPUC
Income Taxes
On March 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) filed a petition to open an investigation and a complaint with the OPUC with respect to the amount of federal, state, and local income taxes paid by PGE since 1997. On March 31, 2003, the OPUC rejected the request for an investigation, but the complaint remains. On May 8, 2003, PGE filed with the OPUC its answer and a motion to dismiss the complaint.
Limited Voting Junior Preferred Stock
On May 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) served the OPUC with a complaint filed in Marion County Circuit Court on March 17, 2003 seeking to vacate OPUC Order 02-674 in which the OPUC granted authority to the Company to issue a share of Limited Voting Junior Preferred Stock. The complaint alleges that the OPUC did not follow the proper procedure in issuing the Order. The complaint seeks to have the matter remanded to the OPUC for further proceedings. PGE intends to intervene in the case and oppose the relief sought by the Complainants. For further information, see Note 4, Common and Preferred Stock, in PGE's report on Form 10-K for the year ended December 31, 2002.
Retail Rate Changes
Power Cost MechanismsPrice Decrease - 2003
InThe OPUC's 2001 general rate order contains a Power Cost Stipulation that requires annual updates of PGE's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines of Oregon's energy restructuring law that allow businesses direct access to protect bothenergy service suppliers, a Resource Valuation Mechanism (RVM) utilizes a combination of market prices and the value of the Company's resources to establish power costs and set rates for energy services. The RVM process requires that PGE andadjust its customersrates if its projected power costs change from price volatilitythose included in its 2001 general rate case. It provides for an adjustment, filed annually on November 15, which is effective January 1 of the following year.
PGE's first annual revision of its power supply costs under the RVM process forecast a reduction in the wholesalecost of power and natural gas markets,from that utilized in the Company's 2001 general rate case. Accordingly, the OPUC has authorized reductions in the Company's retail prices, effective January 1, 2003. Price decreases range from 2% for residential customers to between 9% and 17% for commercial and industrial customers. Rates for business customers are affected more by wholesale energy market prices, which have decreased in the 2003 forecast. The smaller decrease in residential rates reflects the cost of electricity from BPA, which increased its rates in October 2002, as well as PGE's cost of generation. Based upon projected energy sales, it is estimated that such price decreases will reduce PGE's 2003 revenues by approximately $100 million.
Included in the price reduction is the effect of the OPUC's disallowance, based upon a prudence review, of approximately $15 million related to four power purchase contracts, entered into in the first half of 2001, providing 125 megawatts of on-peak delivery in 2003.
The new prices also reflect a resolution regarding the recovery period for PGE's power cost mechanism covering the period October 2001 through December 2002. This amount includes the effect of a settlement stipulation related to estimated 2003 power costs, in which PGE agreed to reduce its recovery under the power cost mechanism by approximately $4.6 million; such reduction was recorded by the Company in 2002.
Power Cost Adjustment Mechanisms
As actual power costs in any year may differ substantially from those costs used in rate determination, the OPUC in 2001 authorized power cost adjustment mechanisms that allowed the Company to defer for later recovery from retail customers actual net variable power costs which differdiffered from certain baseline amounts approved by the OPUC. Duringamounts. Under the initial power cost mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received OPUC approval to recover the approximate $91 million balance (including $7 million of interest), over a 3 1/2-year period of 3-1/2 years (April 1, 2002 - September 30, 2005). Such recovery is being offset byAt March 31, 2003, the refund ofremaining balance to be collected was approximately $22 million in customer credits over the period April 1, 2002 through December 31, 2002, with no net effect on customer rates during this time. Such customer credits consist of a final distribution received in 2000 related to PGE's terminated member ship in Nuclear Electric Insurance Limited (NEIL).$67 million.
In its August 2001 general rate order, the OPUC approved a Power Cost Adjustmentpower cost adjustment mechanism extending fromfor the period October 1, 2001 through the end ofDecember 2002. Under this mechanism, PGE shares with its retail customersdeferred $41 million in power costs, representing the difference between actual net variable power costs and the amount used to establish base energy rates, on October 1, 2001. In addition, PGE shares with customersas well as the difference between actual energy revenues and a pre-determined base. A portion of the net difference between pre-determined levels and actual net variable power costs and revenues (termed "Power Cost Variance") isThe deferred amount, subject to recovery (or refund). Any Power Cost Variance exceeding $28 milliona prudence review and audit by the OPUC, is shared with PGE customers, with any variance between $28 million and $38 million shared equally. Of the next $62 million (up to $100 million), PGE will collect or refund 85% of the variance, and of the next $100 million (up to $200 million), PGE will collect or refund 90% of the variance. For variances that exceed $200 million, PGE will collect or refund 95% of the variance.
A Power Cost Adjustment Account is maintained to record both the calculated Power Cost Variance and amounts actuallybeing collected from or refundedlarge industrial customers over a one-year period (2003) and over a two-year period (2003-2004) from all other customer classes. At March 31, 2003, the balance to customers. Any tariff rate adjustments, calculated on a quarterly basis, are subject to review and approval by the OPUC. In the first twelve months of the mechanism,be collected was approximately $26 million was deferred for future recovery from retail customers, all of which applied to the first nine months of 2002. On October 7, 2002,$31 million.
Although PGE filed with the OPUC a proposed tariff rate schedule that provides for collection from retail customers of the deferred power cost variance beginning in November 2002. The proposed tariff would have no net effect on customer rates, as the period over which it is currently collecting deferred power costs (applicable to the January 2001 - September 2001 period of the initial mechanism) would be extended in order to offset the increase resulting from the collection of deferred costs applicable to the period October 1, 2001 throu gh the end of 2002. Under the Company's proposal, PGE would collect both deferred balances by approximately 2006-2007. PGE willdoes not have a power cost adjustment mechanism in place for 2003.
2003, the Company has filed with the OPUC an application to defer for later ratemaking treatment increases in power costs related to expected adverse hydro conditions (see "Hydro Replacement Power Costs" below for further information).
Hydro Replacement Power Cost Forecast/Rate ReductionCosts - 2003
A region-wide drought throughout the Pacific Northwest has resulted in adverse hydro conditions for PGE and other utilities, with early forecasts indicating hydro conditions significantly below normal. In anticipation of the effects of such conditions, PGE has begun to acquire replacement power resources for the expected shortfall in hydro-based power, incurring substantially higher variable power costs than those contained in the Company's current rates.
On July 1, 2002,February 11, 2003, PGE filed with the OPUC an updated 2003 power cost forecast that estimated a reductionApplication for Deferral of Hydro Replacement Power Costs, in which the Company requests authorization to defer for later ratemaking treatment increases in power costs utilized inincurred from the application date through December 31, 2003. The Company's most recent general rate filing. The updated forecast projected a 7 to 13 percent price decreaseapplication requests authorization for the Company's business customers and a one percent decrease for residential customers. Rates for business customers are affected more by wholesale energy market prices, which have decreased significantly in recent months. Benefits to residential customers are expected to be smaller as their rates are affected more by PGE's costsdeferral of generation and electricity from BPA, which increased its rates on October 1, 2002.
On October 30, 2002, the OPUC issued an order that addressed several issues related to recovery of projected 2003 net variable power costs, among other things, the rate treatment of certain power purchase contracts that provide for delivery of power in 2003. In the order, the OPUC disallowed as imprudent about $15 million of power costs related to four forward power purchase contracts that were entered in early 2001 during the energy crisis when power prices were high and volatile. The order will result in an additional overall rate reduction of approximately two percent for PGE's retail customers. The exact amount95% of the rate reduction will be determined upon the Company's mid-November 2002 filing of final power cost recovery for 2003. New prices, reflecting the above reductions, will be effective January 1, 2003.
In addition, since PGE will not have a power cost adjustment mechanism in place in 2003, variancesdifference between actual net variable power costs and those allowed in current rates, with interest accrued at PGE's authorized rate of return. As proposed, the finaldeferral would be adjusted for the impact that changes in load would otherwise have on net variable power costs. Although the amount set in rates forof the deferral would be determined over the course of the year, PGE estimates that the amount could range from $20 million to $60 million. The application is currently pending before the OPUC.
Preliminary Power Cost Filing - 2004
On April 1, 2003, PGE submitted a Resource Valuation Mechanism filing with the OPUC containing an estimate of 2004 power costs based upon preliminary information that will be reflectedupdated later in 2003. The filing forecasts retail price increases for both residential and nonresidential customers ranging from 2.5 percent to 5 percent, based upon the effect of higher wholesale power, coal, and natural gas prices on PGE's 2003 earnings.costs. Final adjustments will be determined in November 2003.
Electric Power Industry Restructuring
Oregon's electric energy industry restructuring plan, implemented on March 1, 2002, provides all of PGE's commercial and industrial customers direct access to competing energy suppliers. The RVM document filed by the Company with the OPUC on April 1, 2003 includes proposed changes that will facilitate the ability of such customers to make decisions related to direct access service and electricity pricing options. Residential and small business customers can continue to purchase electricity from a "portfolio" of rate options that include a basic service rate, a time of use rate, and renewable resource rates.
Integrated Resource Plan
Under OPUC rules implementing Oregon's electric industry restructuring law, electric utilities were required to file a resource plan, including an evaluation of, and recommendations regarding, the disposition of existing generating resources. Such recommendations were required to facilitate a fully competitive market, provide consumers fair, non-discriminatory access to competitive markets, and retain the benefit of low-cost resources for customers.
Although the OPUC has not adopted final rules governing resource plan updates,In August 2002, PGE filed ana new Integrated Resource Plan in August 2002, updating its plan filed in late 2000.Plan. In its updated plan,Plan, PGE describes its strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, least cost, and supply reliability. The planPlan, which considers resource actions over the next two to three years, includes reduced reliance on volatile short-term wholesale power contracts and increased emphasis on longer-term supplies linked to the output of specific power plants.supplies. It also considers future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, long-term power purchases, and meeting seasonal peaking requirements through seasonal exchanges, demand-side management, capacity tolling contracts, and combustion turbine development.
PGE filed a variety of measures. The plan includes continuing support for Oregon's electricity restructuring plan and for additional methodssupplement to address unique needs of individual customers.the Plan on February 28, 2003. The OPUC has initiated a schedule for input and review, with an acknowledgement of PGE's pl anthe Company's Plan, as supplemented, anticipated by mid-2003. PGE then anticipates issuing a request for proposals (RFP) to acquire energy and capacity resources. The Company will continue to evaluate its options with regard to the construction of additional generation, including a 650-MW gas turbine plant adjacent to it's Beaver plant site (Port Westward Generating Project), considering the availability of reasonably priced medium to long-term power purchases from the market. PGE will continue to monitor changes in early 2003.economic conditions and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers.
Based upon results of the RFP process, PGE will update its action plan with specific resource recommendations and request acknowledgement that the Company's final action plan is consistent with least cost planning principles established by the OPUC.
PGE Pension Plan
PGE and its actuary are in the process of evaluating the effects of changing conditions in the financial markets on the net periodic pension cost (NPPC), benefit obligations and funding status of PGE's pension plan (Plan). The discount rate used to calculate current benefit obligations under the Plan (which is based on rates at which pension benefits could be effectively settled) could be adjusted downward by as much as three-quarters of a percent from the 7.25% rate used at the beginning of 2002 depending upon activity in the bond market during the remainder of 2002. Due to this lower discount rate and also due to plan experience differences as compared to earlier assumptions, the projected benefit obligation (PBO) is anticipated to be much higher at December 31, 2002 than the PBO at December 31, 2001.
Additionally, based on PGE's latest evaluation through October 2002, it appears that the fair value of Plan assets at December 31, 2002 will be materially lower than the fair value of Plan assets at December 31, 2001. The primary cause of the reduction in value is the lower market value of the portfolio of assets in the Plan trust. However, the long-term rate of return on assets, derived from an assessment by our asset management consultant of the expected returns from the various classes of assets in the Plan trust, is not expected to change from the previous year.
The Plan's positive funding status of $91 million at December 31, 2001, could move to an underfunded position by year-end 2002 if recent financial market conditions continue. A minimum liability recognition is not expected, however, since the fair value of Plan assets is expected to remain above the accumulated benefit obligation (ABO). The NPPC projection for 2003 is expected to continue to provide a credit to income, although a much lower credit than in 2002.
Receivables - California Wholesale Market
As of November 1, 2002,March 31, 2003, PGE has net accounts receivable balances totaling approximately $66$62 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that may be affectedthe majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).
On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code.
PGE is pursuing collection of all past due amounts through the PX and PG&E bankruptcy proceeding and has filed a proof of claim in each of the proceedings. Management continues to assess PGE's exposure relative to its California receivables and has established reserves of $29 million related to this receivable amount, including $11.5 million recorded in the first quarter of 2003. The Company is examining numerous options, including legal, regulatory, and other means to pursue collection of any amounts ultimately not received through the bankruptcy process. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables.
Management believes that the outcome of this matter will not have a material adverse impact on the financial condition of two major California utilities. Significant increases in wholesale power prices in the last halfCompany, but may have a material impact on the results of 2000 and in early 2001 severely affected the financial stability of both companies and resulted in the declaration of bankruptcy by one of the utilities. A credit reserve has been established by PGEoperations for amounts due under wholesale electricity contracts. For further information, see Note 5, Receivables-California Wholesale Market, in the Notes to Financial Statementsfuture reporting periods.
Refunds on Wholesale Transactions
California
In a June 19, 2001 order adopting a price mitigation program for 11 states within the WSCCWECC area, the FERC referred to a settlement judge the issue of refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and the PX.
On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering an evidentiary hearing proceeding to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Hearings were held in February and March 2002 to determine the appropriate proxy prices to use and which sales were exempt from refunds because they had been made pursuant to orders of the Department of Energy. Further hearings were held in August through October, 2002, to determine how to calculatethe method of calculation of amounts owed to, and refunds owed by, sellers into the California market. Using the established methodology, the Company's potential refund obligation is currently estimated to be in the range of $20 million to $30 million. Final determination of refunds is to be made after review by FERC of calculations filed by the ISO. PGE will have the opportunity to challenge the FERC's determination of the amount of any proposed refunds.
On August 13, 2002, the FERC staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in the Company's potential refund obligation. The FERC asked for comments on the staff's recommendation, and on October 15, 2002, PGE, along with several other utilities, filed comments with the FERC objecting to the FERC staff's recommendations. Subsequent to the issuance of the FERC's August 13, 2002 report, several companies disclosed that some of their gas traders reported incorrect prices to the firms that report gas indices. In addition, on September 23, 2002, a FERC administrative law judge issued an order in a complaint case against El Paso Natural Gas Company, finding that El Paso had manipulated the gas market by withholding capacity. Also, in October 2002, a former Vice President and Managing Director of Enron's West Power Trading Division entered a guil tyg uilty plea to conspiracy to commit wire fraud in connection with California's energy market.
In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds. Although no final dollar amounts were included in the certification, the recommended methodology indicated a potential refund by PGE of $20 million to $30 million.
Appeals of the FERC orders establishing the refund methodology have been filed and are pending in the Ninth Circuit Federal Court of Appeals. On August 21, 2002 the Ninth Circuit issued an order requiring the FERC to reopen the record to allow the parties to adducepresent additional evidence of market manipulation. In compliance with this order, the FERC authorized all parties to conduct further inquiry and to submit additional evidence of market manipulation. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.
On March 3, 2003, numerous parties filed documents addressing possible market manipulation. The most comprehensive filings were by the California parties. In addition to alleging that the markets were manipulated and that the refund cases should thus be expanded, they alleged that numerous sellers, including PGE, participated in various strategies that affected the market adversely. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of the California parties.
On March 26, 2003, the FERC has not yet determinedissued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge, issued in December 2002, but modifying the methodology it had previously ordered for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates that the new methodology could increase the amount of the potential refunds by approximately $20 million. Although further proceedings will be necessary to determine exactly how the comments or these subsequent eventsnew methodology will affect the refund liability, the Company now estimates its potential liability to be between $20 million and $50 million.
PGE does not agree with several aspects of the FERC's methodology usedfor determining potential refunds. On April 25, 2003, PGE joined a group of utilities in filing a request for rehearing of various aspects of the refund hearings.March 26, 2003 order, including the repricing of the gas cost component of the proxy price from which refunds are to be calculated.
Pacific Northwest
In the July 25, 2001 order, the FERC hearings have also been heldcalled for a preliminary evidentiary hearing to determineexplore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest by PGE and other suppliers from December 25, 2000 through June 20, 2001. A FERC Administrative Law JudgeDuring that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order dated September 24, 2001, that the claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action. Several of
In December 2002, the complainants inFERC re-opened this case haveto allow parties to conduct further discovery. In coordination with the order in the California refund case (described above), the FERC authorized all parties to conduct further inquiry and to submit additional evidence. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.
On March 3, 2003, numerous parties filed motionsdocuments addressing possible market manipulation. The most comprehensive filings were by the City of Tacoma. In addition to reopenalleging that the hearing, with such motions awaitingmarkets were manipulated and that the refund cases should thus be expanded, they alleged that numerous sellers, including PGE, participated in various strategies that adversely affected the market. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of these parties.
On March 26, 2003, the FERC action. FERCindicated that it might issue an order to remand the case for a determination of refunds. The remand could consider allinclude the appointment of a settlement judge or additional hearings to determine refund amounts, if any. At this time, the factors discussed above in reaching a decision whether to grant such motions.Company does not know what the order may require or what sanctions may be sought.
Potential Refund Mitigation
The FERC has indicated that any refunds PGE may be required to pay related to California sales can be offset by accounts receivable related to sales in California.California (as discussed in Note 5, Receivables - California Wholesale Market). As indicated in Note 5, PGE has established reserves of $29 million related to the receivable amount. The FERC has also indicated that interest on both refunds and offsetting accounts receivable will be computed from the effective dates of the applicable transactions; such interest has not yet been recorded by the Company.
In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism.mechanism in effect at the time. This could potentiallyfurther mitigate the financial effect of any refunds made or received by the Company.
See Note 5, Receivables - California Wholesale Market,
Management cannot predict the ultimate outcome of these matters. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.
Show Cause Order
Pursuant to the FERC Staff's Final Report on Price Manipulation in Western Markets, issued in Docket No. PA02-2-000, the FERC indicated, in a press release issued on March 26, 2003, that it intends to issue orders to PGE and Note 6, Refunds on Wholesale Transactions,36 other entities that participated in the NotesCalifornia wholesale market in 2000 and 2001, requiring that each entity show cause why their behaviors during that time period did not constitute gaming in violation of tariffs issued by the California Independent System Operator (ISO) and the California Power Exchange (PX). The FERC indicated that possible sanctions for any entity found to Financial Statements for further information.have violated the tariffs include disgorging unjust profits associated with the violations, or other appropriate remedies. Based on its internal investigations to date, PGE does not believe that it violated ISO or PX tariff provisions.
Wholesale Price Mitigation
In June 2001, the FERC adopted a price mitigation program for the power system serving 11 Western states, adopting a new benchmark formula limiting prices for electricity sold in the spot markets at all times throughout the region through September 2002. The program appliesapplied to power generators, marketers, and investor-owned utilities under FERC jurisdiction, as well as public power providers, municipal utilities, and electric cooperatives that use FERC-regulated transmission lines.
Under the program, a ceiling price iswas set by FERC for wholesale electricity sold in the spot market coordinated by the California Independent System Operator (ISO) and in markets in the other Western states. Such price, initially set at $91.87/MWh, reflectsreflected specified fuel, operations, and maintenance costs, and iswas based upon the bid submitted by the highest cost gas-fired generating unit supplying power during a Stage 1 supply emergency.
In December 2001, the FERC temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the ISO, recognizing differences between Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. The changes, including a ceiling price of $108/MWh, were in effect until May 1, 2002, at which time the previous methodology and ceiling price again became effective.
In July 2002, the FERC raised the ceiling price on Western wholesale electricity prices from $91.87/MWh to $250/MWh, effective October 31, 2002. The new ceiling price applies to all sales of electricity in the WSCC.WECC. In addition to the new price ceiling, the FERC order established conditions and rules guiding participation in Western wholesale electricity markets, including automatic price mitigation procedures to be implemented during periods of tight supplies.
Federal Investigations - Wholesale Power Markets
On February 13, 2002, the FERC initiated a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. On March 5, 2002, all sellers with wholesale sales in the U.S. portion of the WSCCWECC were directed to provide certain historical and projected information for all energy transactions in calendar years 2000 and 2001. Although PGE was not specifically named inIn April 2002, the FERC directive, the Company bought and sold power in the region during the relevant period and voluntarily submitted the requested information. Additionally, on March 15, 2002 the FERC enforcement staff issued a subpoena to Enron, which Enron then forwarded to the Company. In response to this subpoena, the Company provided information related to its trading organization, its trading policies and procedures, its price curves and their derivation, and its trading position reports.
As a result of an internal investigation, PGE discovered that it had failed to properly post on a public web site information about some of its energy transactions with an affiliate, Enron Power Marketing, Inc. The preliminary results of this investigation were disclosed to FERC Staff on April 15, 2002 and final results on August 1, 2002. This issue was subsequently included in the investigation in Docket No. EL02-114-000 described below.
Enron Trading Strategies
In early May 2002, Enron provided memos to the FERC receivedthat contained information contained in memos released by Enron, indicating that Enron, through its subsidiary Enron Power Marketing, Inc. (EPMI), may have engaged in several types of trading strategies that raised questions regarding potential manipulation of electricity and natural gas prices in California in 2000-2001. On May 8, 2002, the FERC ordered all sellers of wholesale electricity or ancillary services into the California markets during 2000-2001 to respond to the FERC whether they engaged in any transactions falling within any of the enumerated types of trading strategies, and, if they did, to provide information about the transactions. OnAlthough PGE was not specifically named in the FERC order, on May 22, 2002, PGE voluntarily submitted the results of its investigation to the FERC. The material submitted to FERC did not show any instances where the Company engaged in or knowingly aided deceptive or misleading trading strategies. However, PGE reported that iti t was among other intermediaries in a series of trading activities that occurred on 15 days from April through June 2000 where EPMI was found to be at both ends of the transaction chain (revised from 17 days, as initially reported).chain. The trading transactions identified during the 15-day period moved about 2,300 (revised from 2,500, as initially reported) megawatt hours (0.12%) of the total 2 million megawatt hours traded by PGE on those days, and about 0.02% of the total 13 million megawatt hours traded by PGE during the three-month period. The services provided by PGE may have been used by EPMI as a step in one of the enumerated strategies. In addition, it is conceivable that in the normal course of business, PGE could have provided services to third parties that may have resulted in PGE being used, unknowingly, as an intermediary in partial execution of one or more of the enumerated strategies.
On June 4, 2002, the FERC issued an order to PGE and three other companies to show cause why their authority to charge market-based rates should not be revoked. SuchThe order statesstated that the companies' responses to the FERC's May 8, 2002 data request (discussed above) are indicative of a failure to cooperate with its investigation. PGE believes that it has fully cooperated with the FERC's inquiry. On June 14, 2002, PGE filed a response with the FERC, indicating that a thorough review of Company documents again found no evidence of deception or market manipulation by PGE. PGE believes that it has fully cooperated with the FERC's inquiry.
On August 13, 2002, the FERC issued two orders initiating investigations into instances of possible misconduct by PGE and certain other companies. In the first order (Docket No. EL02-114-000), the FERC ordered investigation of PGE and Enron Power Marketing, Inc. (EPMI)EPMI related to possible violations of their codes of conduct, the FERC's standards of conduct, and the companies' market-based rate tariffs, and whether PGE has cooperated by providing all relevant information related to the FERC's May 22,8, 2002 data request and June 4 Show Cause Order. In the second order (Docket No. EL02-115-000), the FERC ordered investigation of Avista Corporation and Avista Energy, Inc. (collectively, Avista) with respect to, among other things, transactions in which Avista engaged in or facilitated the trading strategies identified in the Enron memoranda or acted as a middleman with respect to sales of electric energy between PGE and EPMI. PGE and EPMI are included as parties to the investigation. In the eventin that violations are determined to have occurred, the investigations will address remedies, including possible revocation of the companies' market-based rate authority and potential refunds for future wholesale activity.
Docket. In the orders, the FERC established OctoberOctobe r 15, 2002 as the refund"refund effective date. Purchasers" Issues involving PGE and EPMI in Docket No. EL02-115-000 have now been consolidated into Docket No. EL02-114-000. If PGE were to lose its market-based rate authority, purchasers of electric energy from PGE at market-based rates after thisthe refund effective date could be entitled to a refund of the difference between the market-based raterates and cost-based rates deemed just and reasonable by the FERC.
On December 10, 2002, the FERC iftrial staff released a Revised Statement of Asserted Violations (Revised Statement) and its initial testimony in its investigation of PGE (Docket No. EL02-114-000). The assertions in the Revised Statement and testimony are limited to PGE's self-reported failure to properly post information about some of its energy transactions with EPMI, and alleged violations for affiliate dealings with EPMI relating to a series of transactions that occurred on certain days in April-June 2000, involving PGE, EPMI, and Avista Corporation. The latter transactions were previously reported by PGE to lose itsFERC on May 22, 2002 in response to the FERC's May 8, 2002 data request. The trial staff recommended a remedy of revocation of PGE's market-based rate authority.authority for two years, and a requirement that PGE's application for reinstatement of market-based rates include documentation supporting revised procedures to ensure that posting errors and violations of affiliate rules do not occu r again. The City of Tacoma, Washington filed testimony seeking a refund from PGE of $3.2 million. The California Attorney General and the California Public Utilities Commission (California Parties) have filed testimony that PGE should refund amounts to compensate market participants for PGE's alleged unlawful conduct, but the testimony specifies no amount of refunds.
Certain
PGE's initial response testimony in Docket No. EL02-114-000 was filed on February 24, 2003. In its testimony, PGE describes the posting transactionserrors it self-reported, most of which were discovered by PGEtechnical in nature and self reportedmay in fact not have been in error. The Company also described the cooperation it has extended to the FERC, the investigative staff, and the trial staff in April 2002. Theproviding all requested information to aid the investigation. PGE also provided testimony that the April-June 2000 transactions involving Avista were reported to the FERC by PGE in the Company's May 22, 2002 response to a data request issued by the FERC on May 8, 2002.with EPMI did not involve violations of affiliate rules, except for certain posting errors.
Pre-hearing conferences have been held in both dockets.
The hearing in Docket No. EL02-114-000 is scheduled to begin on April 1, 2003;June 2, 2003, with an initial decision from the hearingpresiding FERC judge scheduled for July 17, 2003. The procedural schedule in theDocket No. EL02-115-000 docket is currently scheduledsuspended pending further revisions to begin on April 28, 2003, although the administrative law judge has indicated preference for a more accelerated schedule.settlement proposal submitted between Avista and FERC trial staff.
PGE will continue to cooperate to the fullest extent with the investigations. PGE continues to believe that it has fully complied with the FERC investigation initiated on February 13, 2002, and that it has not engaged in deception or market manipulation.
Wash Sales - ElectricityPower Supply
On May 21, 2002,Hydro conditions in the FERC issued a data requestregion remain below normal levels. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and requestother cooperating agencies, currently project the January-to-July runoff at 84% of normal, compared to 97% of normal in 2002.
PGE generated 51% of its retail load requirement in the first quarter of 2003, with hydro generation comprising about 7% of the Company's requirement; short- and long-term purchases were utilized to meet the remaining load. PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for admissions to all sellerselectricity both within its service territory and from its wholesale customers.
The amount of surplus electric generating capability in the western United States, the amount of annual snow pack and its impact on hydro generation, the number and credit quality of wholesale electricity and/or ancillary servicesmarketers and brokers participating in the U.S. portionenergy trading markets, the availability and price of natural gas as well as other fuels, and the WSCC duringavailability and pricing of electric and gas transmission all contributed to and have an impact on the years 2000-2001. Such request ordered sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. Althoughwholesale price and availability of electricity. PGE was not listedwill continue its participation in the data request, PGE conducted an investigation and submitted the resultswholesale energy marketplace in a response to the FERC on May 31, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request to the extent that such activities artificially inflated trading volumes, revenues or market prices. PGE's response also noted that it had no reason or incentive to artificially inflate trading volumes or revenues, as the primary purpose of its wholesale trading operations isorder to manage riskits power supply risks and reduce costs foracquire the necessary electricity and fuel to meet the needs of its retail customers by balancing load requirements and maximizingadminister its current long-term wholesale contracts. In addition, the value of owned generat ionCompany will continue its trading activities to participate in electricity, natural gas, and purchase contracts to the extent that available supply exceeds the needs of the Company's firm customers.crude oil markets.
Wash Sales - Natural GasEnron Bankruptcy
On May 22, 2002,Commencing in December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE nor numerous other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members, and its stock has been de-listed from the New York Stock Exchange. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal regulators, including the FERC issued a data request and request for admissions tothe State of Oregon. In March 2002, Enron, substantially all sellers of natural gasits subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.
Although PGE is not included in the U.S. portion of the WSCCEnron bankruptcy, it has been affected. The Company has been included in requests for documents related to Congressional and in Texas during the years 2000-2001. Such request ordered such sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. PGE conducted an investigation and submitted the results in a response to the FERC on June 5, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request.
Other
On June 17, 2002, the U.S. Commodity Futures Trading Commission (CFTC),regulatory investigations, with which regulates futures contracts traded on U.S. exchanges, subpoenaed documents from PGE regarding the Company's electricity and natural gas trading, including any "wash" trading used to inflate revenue and trading volume. PGE forwarded documents previously prepared for the FERC investigation (described above).it is fully cooperating. In addition, PGE has been requested to provide information and documentswas included among those Enron entities suspended from contracting with respect to variousthe federal and state actions and investigations of Enron.government. The suspension, which expired in March 2003, had no material adverse effect on PGE business or operations.
PGE is cooperating and will continue to cooperate
In addition to the fullest extent with these investigations.
Antitrust Litigation
In late 2001, the State of Californiageneral effects discussed above, PGE may have potential exposure to certain liabilities and numerous individuals, businesses and California cities, counties and other governmental entities filed class action law suits ("Wholesale Electricity Antitrust Cases") against various individuals, utilities, generators, traders and other entities, including Duke Energy Trading and Marketing, LLC; Duke Energy Morro Bay, LLC; Duke Energy Moss Landing, LLC; Duke Energy South Bay, LLC and Duke Energy Oakland, LLC (Duke Parties) and Reliant Energy Services, Inc.; Reliant Ormond Beach, Inc.; Reliant Energy Etiwanda, Inc.; Reliant Energy Ellwood, Inc.; Reliant Energy Mandalay, Inc.; Reliant Energy Coolwater, Inc. (Reliant Parties), alleging that activities related to the purchase and sale of electricity in California in 2000 and 2001 violated California antitrust and unfair competition laws. The complaint seeks, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest, and penaltie s. The plaintiffs have sought to have the case dismissed on jurisdictional grounds.
The Duke Parties filed a cross complaint against PGE and other utilities, generators, traders and other entities not named in the Wholesale Electricity Antitrust Cases, alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose on the Duke Parties under the Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. An open extension of time for PGE and the other utilities to respond to the cross complaint has been agreed to by the parties until 30 days after a ruling on jurisdiction is made in the original case.
The Reliant Parties also have filed a cross complaint against PGE and the other utilities, generators, traders and other entities similar to the cross complaint filed by the Duke Parties. The parties have stipulated to place this case in abeyance until 30 days after a ruling on jurisdiction is made.
In September 2002, the Court heard arguments on Motions to Sever and Remand by plaintiffs and Motions to Dismiss by cross-defendants.
At this time, management is unable to make any assessment of, or determination with respect to, these complaints.
California Attorney General Complaint
In May 2002, the Attorney General of California filed a complaint in state court alleging failure of PGE to comply with FERC approval requirements for its market based sales of power in California. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price"; no specific damage claim is stated. In July 2002, PGE filed a Notice of Removal to U.S. District Court and a Motion to Dismiss on preemptive grounds. The Attorney General moved to remand to state court, which was denied. The Attorney General filed an appeal to the Ninth Circuit Court of Appeals of the denial of the motion to remand, and moved to stay action in the District Court pending the outcome of the appeal. The District Court, finding the appeal frivolous, refused to stay the case. Motions to dismiss the case were argued on September 26, 2002 and are currently under advisement by the District Court.At this time, management is unable to make any assessment of, or determination with respect to, this complaint.
Trojan Investment Recovery
Due to the closure of the Trojan nuclear plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals and regulatory actions have taken place. Asasset impairments as a result of a settlement agreement that was implementedEnron's bankruptcy. These are:
1. Amounts Due from Enron and Enron-Supported Affiliates in 2000, the recovery of the Trojan plant investment is no longer includedBankruptcy - As described in rates charged to customers. The Company continues to collect for costs related to the decommissioning of the plant. (For further information, see Note 3, Legal and Environmental Matters,4, Related Party Transactions, in the Notes to Financial Statements)Statements, PGE is owed approximately $82 million (including accrued interest) by Enron at March 31, 2003 (Merger Receivable). Such amount was to have been paid by Enron to PGE for price reductions granted to customers, as agreed to by Enron at the time it acquired PGE in 1997. Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the entire amount of this receivable, of which $74 million was recorded in December 2001. On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, including $73 million for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, due to uncertainties associated with other receivable balances from Enron subsidiary companies which are part of the bankruptcy proceedings, a reserve has been established for the entire $2 million remaining balance of such receivables at March 31, 2003.
2. Controlled Group Liability - Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plans and tax obligations of Enron.
Pension Plans
Funding Status
The pension plan for the employees of PGE (the PGE Plan) is separate from the Enron Corp. Cash Balance Plan (the Enron Plan). Although at December 31, 2002 the total fair value of PGE Plan assets was $16 million lower than the projected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis, the PGE Plan remains over-funded on an accumulated benefit obligation basis by about $30 million. Enron's management has informed PGE that, as of December 31, 2002, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $52 million on a SFAS No. 87 basis and approximately $182 million on a plan termination basis. Further, Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases. The claims are duplicative in nature, representing unliquidated claims for PBGC insurance premiums (the "Premium Claims") and unliquidated claims for due but unpaid minimum funding contributions (the "Contribution C laims") under the Internal Revenue Code of 1986, as amended (the "Tax Code") 29 U.S.C. Section 1082 and claims for unfunded benefit liabilities (the "UBL Claims"). Enron and the relevant sponsors of the defined benefit plans are current on their PBGC premiums and their contributions to the pension plans. Therefore, Enron has valued the Premium Claims and the Contribution Claims at $0. The total amount of the UBL Claims is $305.5 million (including $271 million for the Enron Plan, and $24.8 million for the PGE Plan). In addition, Enron management has informed PGE that the PBGC has informally alleged in pleadings filed with the Bankruptcy Court that the UBL claim related to the Enron Plan could increase by as much as 100%. PBGC has provided no support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.
It is permissible, subject to applicable law, for separate pension plans established by companies in the same controlled group to be merged. Enron could direct that the PGE Plan be merged with the Enron Plan. If the plans were merged, any excess assets in the PGE Plan would reduce the deficiency in the Enron Plan. However, if the plans are not merged, the deficiency in the Enron Plan could become the responsibility of the PBGC, which insures pension plans, including the PGE Plan and the Enron Plan, and the PGE Plan's surplus would be undiminished. Merging the plans would reduce the value of PGE, the stock of which is an asset available to Enron's creditors. PGE's management believes that it is unlikely that either Enron or Enron's creditors would agree to support merging the two plans.
Enron cannot itself terminate the Enron Plan while it is underfunded unless it provides at least 60 days notice and the PBGC, in the case of solvent entities, or the Bankruptcy Court, in the case of insolvent entities, determines that each member of Enron's controlled group, including PGE, is in financial distress, as defined in ERISA. In the opinion of management, PGE is a solvent entity that does not meet the financial distress test. Consequently, management believes that it is unlikely that Enron can unilaterally terminate the Enron Plan while it is underfunded. However, Enron could, with consent of the PBGC (see discussion below), seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with ERISA.
The PBGC does have the authority, either by agreement with the plan administrator or upon application to and approval by a Federal District Court, to terminate and take over control of underfunded pension plans in certain circumstances. In order to initiate this process, the PBGC must determine that either the minimum funding standard for the plan (see discussion below) has not been met, or that the plan will not be able to pay benefits when due, or that there is a reasonable risk that long-run losses to the PBGC will be unreasonably increased or that certain distributions have been made from the plan. The court must determine that plan termination is necessary to protect participants, the plan, or the PBGC.
Upon termination of an underfunded pension plan, all members of the controlled group of the plan sponsor become jointly and severally liable for the underfunding, but are not obligated to pay until a demand for payment is made by the PBGC. The PBGC can demand payment from one or more of the members of the controlled group. If payment of the full amount demanded is not made, a lien in favor of the PBGC automatically arises against all of the assets of each member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the aggregate net worth of all controlled group members. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien does not take priority over other previously perfected liens on the assets of a member of the controlled group. Substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Management believes that any lien asserted b y the PBGC would be subordinate to that lien.
PGE management has been informed by Enron management that on November 15, 2002, Enron informed its employees that it is taking steps to terminate the Enron Plan. As an initial step in terminating the Enron Plan, Enron amended the Enron Plan to cease monthly accruals effective January 1, 2003, so that only interest credits would accrue after that date. Enron also informed its employees that it intends to seek the approval of its Unsecured Creditors' Committee and the U.S. Bankruptcy Court to fully fund and then terminate the Enron Plan in a standard termination. Approval to terminate the Enron Plan also will be requested from the PBGC and the IRS. Enron informed its employees that, if approved, the termination process could take 12 months or longer.
PGE management believes that the proposal to fully fund the Enron Plan and terminate it in a standard termination, if approved and consummated, should eliminate any need for the PBGC to attempt to collect from PGE any liability related to the termination of the Enron Plan. There can be no assurance at this time that the funding and termination will be approved by the Unsecured Creditors' Committee or the Bankruptcy Court or that, upon such approval, Enron will have the ability to obtain funding on acceptable terms.
If the PBGC did look solely to PGE to pay any underfunded amount in respect of the Enron Plan, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover any contributions from the other solvent members of Enron's controlled group. Until the Enron Plan is terminated and the PBGC makes a demand on PGE to pay some or all of any underfunded amount, PGE has no liability for the underfunded amount and no termination liens arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any underfunded amount assessed by the PBGC. No reserves have been established by PGE for any amounts related to this issue.
Minimum Funding Obligation
If the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in the amount of the missed funding automatically arises against the assets of every member of the controlled group. The lien is in favor of the plan, but may be enforced by the PBGC. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien would not take priority over other previously perfected liens on the assets of a member of the controlled group. If Enron does not timely satisfy its minimum funding obligation in excess of $1 million, a lien will arise against the assets of PGE and all other members of the Enron controlled group. The PBGC would be entitled to perfect the lien and enforce it in favor of the Enron Plan against the assets of PGE and other members of the Enron controlled group. However, substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. PGE management believes that any lien asserted by the PBGC would be subordinate to that lien.
Based on discussions with Enron management, PGE management understands that Enron has made all required contributions to date and the next contribution is not due until July 15, 2003. PGE does not know if Enron will make contributions as they become due. Management is unable to predict if Enron will miss a payment and, if so, whether the PBGC would seek to have PGE make any or all of the payment. If the PBGC did look solely to PGE to pay the missed payment, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover contributions from the other solvent members of the Enron controlled group. Until Enron misses contributions exceeding $1 million, PGE has no liability and no liens will arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any missed payments demanded by the PBGC. No reserves have bee n established by PGE for any amounts related to this issue.
Retiree Health Benefits
Under COBRA, retirees of a bankrupt employer who lose coverage under a group health plan of the employer as a result of certain bankruptcy proceedings are entitled to elect continuation of health coverage in a group health plan maintained by the bankrupt employer or a member of its controlled group. PGE management understands, based on discussion with Enron management, that Enron provides a plan for health insurance for certain retirees, and that the actuarial liability for such coverage amounted to approximately $70 million at December 31, 2001 (the most recent date for which information is available). Management further understands that to meet its obligation, Enron had set aside approximately $34 million of assets in a VEBA trust that may be protected under ERISA from Enron's creditors, leaving an unfunded liability of approximately $36 million at December 31, 2001.
In the event that Enron terminates its retiree group health plan, the retirees must be provided the opportunity to purchase continuing coverage from Enron's group health plan, if any, or the appropriate group health plan of another member of the controlled group. Neither Enron nor any member of the controlled group would be required to fully fund the benefit or create new plans to provide coverage, and retirees would not be entitled to choose from which plan to obtain coverage. Retirees electing to purchase COBRA coverage would be provided the same coverage that is provided to similarly situated retirees under the most appropriate plan in the Enron controlled group. Retirees electing to continue coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire coverage under COBRA. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.
Management believes that in the event Enron terminates retiree coverage, any material liability to PGE associated with Enron retiree health benefits is unlikely for two reasons. First, based on discussion with Enron management, PGE management understands that most of the retirees that would be affected by termination of the Enron plan are from solvent members of the controlled group and few, if any, live in Oregon. Management believes that it is unlikely that any PGE plans would be found to be the most appropriate to provide COBRA coverage. Second, even if a PGE plan were selected, management believes that retirees in good health should be able to find less expensive coverage from other providers, which will reduce the number of retirees electing COBRA coverage. Management believes that the additional cost to PGE to provide coverage to a limited number of retirees that are unable to acquire other coverage because they are hard to insure or have preexisting conditions will not be materi al. No reserves have been established by PGE for any amounts related to this issue.
Income Taxes
Under regulations issued by the U.S. Treasury Department, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with PGC. Based on discussions with Enron's management, PGE management understands that Enron has treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and becoming a member of Enron's consolidated group once again on December 24, 2002. On December 31, 2002, PGE and Enron entered into a tax sharing agreement pursuant to which PGE agreed to make payments to Enron that approximate the income taxes for which PGE would be liable if it were not a member of Enron's consolidated group. As of April 30, 2003, PGE has paid $21 million to Enron under the tax sharing agreement.
Enron's management has provided the following information to PGE:
A. Enron's consolidated tax returns through 1995 have been audited and are closed. Management understands that the IRS has completed an audit of the consolidated tax returns for 1996-2001.
- For years 1996-1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries substantial NOLs for any additional income tax liabilities that may result from the negotiation of the claim stemming from the IRS audit for the periods in which PGE was a member of Enron's consolidated federal income tax returns.
- Enron's 2002 tax return has not yet been filed. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2002. Enron expects that, in addition to offsetting its income tax liabilities for years before 2002, these NOLs will be sufficient to fully offset Enron's regular and alternative minimum income tax liabilities for 2002 and its regular income tax liability for all subsequent periods through the date of consummation of its plan of reorganization.
- Enron believes that all of the requirements for re-consolidation of PGE with the Enron consolidated group have been met. However, because of the inherently factual nature of the determination of the re-consolidation, there can be no assurance that the IRS will agree with this position. In the event that the IRS does not agree and the matter is not resolved in the bankruptcy proceeding (or otherwise), PGE will have an administrative expense claim against Enron for any amounts paid by PGE to Enron under the tax sharing agreement. Enron management believes that all administrative expense claims will be paid in full.
On March 28, 2003, the IRS filed various proofs of claim for taxes in the Enron bankruptcy, including a claim for approximately $111 million in respect to income tax, interest, and penalties for taxable years for which PGE was included in Enron's consolidated tax return. The IRS seeks to apply $63 million in tax refunds admittedly due Enron against these claims. IRS claims for taxes and prepetition interest have a priority over claims of general unsecured creditors, but claims for prepetition penalties have no priority and claims for postpetition interest are not allowable in bankruptcy. The Company, along with other corporations in Enron's consolidated tax returns that are not in bankruptcy, are severally liable for prepetition penalties and postpetition interest, as well as any portion of the claim allowed in the bankruptcy that the IRS does not collect from the debtors.
Enron's management has informed PGE management that Enron is negotiating with the IRS in an attempt to resolve issues raised by the IRS claims. If the parties do not reach a settlement, the bankruptcy court will decide the actual amount, if any, owed to the government in respect to tax, interest, and penalties.
To the extent, if any, that the IRS would look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that are available for recovery in Enron's bankruptcy proceeding, or to otherwise seek to obtain contributions from the other solvent members of the consolidated group. As a result, management believes the income tax, interest, and penalty exposure to PGE (related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's consolidated returns) would not be material. No reserves have been established by PGE for any amounts related to this issue.
PGE management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.
PGE management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Neither PGE nor Enron have guaranteed the obligations of the other. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and PGC in 1997 (Merger Conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis.
PGE management does not believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern. PGE believes that in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely the holder of PGE's common stock, and PGE, as a debtor in possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. As debtor in possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management. PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) creditors. No dividends could be paid to Enron, no assets could be sold, and no other tr ansfer of funds could be made except with the approval of the Bankruptcy Court after notice to PGE's creditors. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers. Since the issue of whether a Bankruptcy Court has the authority to supersede state regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course. On September 30, 2002, the Company issued to an independent shareholder a single share of a new $1.00 par value class of Limited Voting Junior Preferred Stock which limits, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings without the consent of the shareholder.
Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy. For additional information, see Note 7, Enron Bankruptcy, in the Notes to Financial Statements.
Enron Debtor in Possession Financing
PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a debtor in possession credit agreement with Citicorp USA, Inc. and JPMorgan Chase Bank. The agreement was amended and restated in July 2002. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control ov er PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.
Enron Auction Processes Related to PGE
PGE has been informed by Enron management that the proposal Enron presented to its Unsecured Creditors' Committee on May 3, 2002 to separate certain of Enron's core energy assets, including PGE, from Enron's bankruptcy estate and operate them prospectively as a new integrated power and pipeline company has been withdrawn. Enron continues to pursue the sale of PGE through the auction process that it announced on August 27, 2002. However, Enron has stated that it reserves the right not to sell PGE if the bids received are not deemed fully reflective of its value. A sale of PGE would require the consideration and approval of regulatory agencies, including the OPUC.
Enron management has informed PGE that if PGE is not sold in the auction process, it is anticipated that the shares of PGE stock owned by Enron would be distributed over time to creditors of Enron in connection with Enron's plan of reorganization. It is also anticipated that PGE's stock would be listed on a national stock exchange and would be publicly traded. In connection with the distribution to creditors, it is expected that PGE would be governed by an independent Board of Directors. Until resolution of the bankruptcy case and distribution of the PGE shares, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of Enron's stakeholders.
Enron has filed a motion with the Bankruptcy Court to extend the time to file its plan of reorganization to June 30, 2003. Until the plan of reorganization or another filing related to the sale of PGE is filed with the Bankruptcy Court and approved, management cannot assess the impact on PGE's business and operations of a sale or the distribution of PGE's stock to Enron's creditors.
Public Ownership Initiatives
In August 2002, the City Council of Portland, Oregon passed a resolution authorizing the expenditure of up to $500,000 for professional advice regarding the City's potential acquisition of PGE, including possible condemnation of the Company's assets. The City has signed a confidentiality agreement with Enron to permit it to participate in the Enron auction process relating to PGE.
Initiative petitions were circulated in Multnomah County that obtained sufficient signatures to place a measure on an election ballot (expected to be in the fall of 2003) that, if passed, could result in the formation of a Peoples' Utility District (PUD) in Multnomah County. In addition, if this measure succeeds, the expressed intent of its supporters is to hold additional elections to expand the boundaries of the district to include all of PGE's service territory. If a PUD is formed, it would have the authority to condemn PGE's distribution assets within the boundaries of the district. Oregon law prohibits the PUD from condemning thermal generation plants. It is uncertain under Oregon law whether the PUD would be able to condemn PGE's hydro generation plants.
Public hearings, as required by Oregon law, have been held and will continue regarding the proposed PUD. PGE opposes the formation of the PUD and will oppose any efforts to condemn the Company's assets.
Union GrievancesComplaints to OPUC
Grievances
Income Taxes
On March 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) filed a petition to open an investigation and a complaint with the OPUC with respect to the amount of federal, state, and local income taxes paid by PGE since 1997. On March 31, 2003, the OPUC rejected the request for an investigation, but the complaint remains. On May 8, 2003, PGE filed with the OPUC its answer and a motion to dismiss the complaint.
Limited Voting Junior Preferred Stock
On May 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) served the OPUC with a complaint filed in Marion County Circuit Court on March 17, 2003 seeking to vacate OPUC Order 02-674 in which the OPUC granted authority to the Company to issue a share of Limited Voting Junior Preferred Stock. The complaint alleges that the OPUC did not follow the proper procedure in issuing the Order. The complaint seeks to have the matter remanded to the OPUC for further proceedings. PGE intends to intervene in the case and oppose the relief sought by the Complainants. For further information, see Note 4, Common and Preferred Stock, in PGE's report on Form 10-K for the year ended December 31, 2002.
Retail Rate Changes
Power Cost Price Decrease - 2003
The OPUC's 2001 general rate order contains a Power Cost Stipulation that requires annual updates of PGE's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines of Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, a Resource Valuation Mechanism (RVM) utilizes a combination of market prices and the value of the Company's resources to establish power costs and set rates for energy services. The RVM process requires that PGE adjust its rates if its projected power costs change from those included in its 2001 general rate case. It provides for an adjustment, filed annually on November 15, which is effective January 1 of the following year.
PGE's first annual revision of its power supply costs under the RVM process forecast a reduction in the cost of power from that utilized in the Company's 2001 general rate case. Accordingly, the OPUC authorized reductions in the Company's retail prices, effective January 1, 2003. Price decreases range from 2% for residential customers to between 9% and 17% for commercial and industrial customers. Rates for business customers are affected more by wholesale energy market prices, which have decreased in the 2003 forecast. The smaller decrease in residential rates reflects the cost of electricity from BPA, which increased its rates in October 2002, as well as PGE's cost of generation. Based upon projected energy sales, it is estimated that such price decreases will reduce PGE's 2003 revenues by approximately $100 million.
Included in the price reduction is the effect of the OPUC's disallowance, based upon a prudence review, of approximately $15 million related to four power purchase contracts, entered into in the first half of 2001, providing 125 megawatts of on-peak delivery in 2003.
The new prices also reflect a resolution regarding the recovery period for PGE's power cost mechanism covering the period October 2001 through December 2002. This amount includes the effect of a settlement stipulation related to estimated 2003 power costs, in which PGE agreed to reduce its recovery under the power cost mechanism by approximately $4.6 million; such reduction was recorded by the Company in 2002.
Power Cost Adjustment Mechanisms
As actual power costs in any year may differ substantially from those costs used in rate determination, the OPUC in 2001 authorized power cost adjustment mechanisms that allowed the Company to defer for later recovery from retail customers actual net variable power costs which differed from certain baseline amounts. Under the initial power cost mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received OPUC approval to recover the approximate $91 million balance (including interest) over a 3 1/2-year period (April 2002 - September 2005). At March 31, 2003, the remaining balance to be collected was approximately $67 million.
In its August 2001 general rate order, the OPUC approved a power cost adjustment mechanism for the period October 2001 through December 2002. Under this mechanism, PGE deferred $41 million in power costs, representing the difference between actual net variable power costs and the amount used to establish base energy rates, as well as the difference between actual energy revenues and a pre-determined base. The deferred amount, subject to a prudence review and audit by the OPUC, is being collected from large industrial customers over a one-year period (2003) and over a two-year period (2003-2004) from all other customer classes. At March 31, 2003, the balance to be collected was approximately $31 million.
Although PGE does not have a power cost adjustment mechanism in place for 2003, the Company has filed with the OPUC an application to defer for later ratemaking treatment increases in power costs related to expected adverse hydro conditions (see "Hydro Replacement Power Costs" below for further information).
Hydro Replacement Power Costs - 2003
A region-wide drought throughout the Pacific Northwest has resulted in adverse hydro conditions for PGE and other utilities, with early forecasts indicating hydro conditions significantly below normal. In anticipation of the effects of such conditions, PGE has begun to acquire replacement power resources for the expected shortfall in hydro-based power, incurring substantially higher variable power costs than those contained in the Company's current rates.
On February 11, 2003, PGE filed with the OPUC an Application for Deferral of Hydro Replacement Power Costs, in which the Company requests authorization to defer for later ratemaking treatment increases in power costs incurred from the application date through December 31, 2003. The Company's application requests authorization for the deferral of 95% of the difference between actual net variable power costs and those allowed in current rates, with interest accrued at PGE's authorized rate of return. As proposed, the deferral would be adjusted for the impact that changes in load would otherwise have on net variable power costs. Although the amount of the deferral would be determined over the course of the year, PGE estimates that the amount could range from $20 million to $60 million. The application is currently pending before the OPUC.
Preliminary Power Cost Filing - 2004
On April 1, 2003, PGE submitted a Resource Valuation Mechanism filing with the OPUC containing an estimate of 2004 power costs based upon preliminary information that will be updated later in 2003. The filing forecasts retail price increases for both residential and nonresidential customers ranging from 2.5 percent to 5 percent, based upon the effect of higher wholesale power, coal, and natural gas prices on PGE's costs. Final adjustments will be determined in November 2003.
Electric Power Industry Restructuring
Oregon's electric energy industry restructuring plan, implemented on March 1, 2002, provides all of PGE's commercial and industrial customers direct access to competing energy suppliers. The RVM document filed by the Company with the OPUC on April 1, 2003 includes proposed changes that will facilitate the ability of such customers to make decisions related to direct access service and electricity pricing options. Residential and small business customers can continue to purchase electricity from a "portfolio" of rate options that include a basic service rate, a time of use rate, and renewable resource rates.
Integrated Resource Plan
In August 2002, PGE filed a new Integrated Resource Plan. In its Plan, PGE describes its strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. The Plan, which considers resource actions over the next two to three years, includes reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. It also considers future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, long-term power purchases, and meeting seasonal peaking requirements through seasonal exchanges, demand-side management, capacity tolling contracts, and combustion turbine development.
PGE filed a supplement to the Plan on February 28, 2003. The OPUC has initiated a schedule for input and review, with an acknowledgement of the Company's Plan, as supplemented, anticipated by mid-2003. PGE then anticipates issuing a request for proposals (RFP) to acquire energy and capacity resources. The Company will continue to evaluate its options with regard to the construction of additional generation, including a 650-MW gas turbine plant adjacent to it's Beaver plant site (Port Westward Generating Project), considering the availability of reasonably priced medium to long-term power purchases from the market. PGE will continue to monitor changes in economic conditions and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers.
Based upon results of the RFP process, PGE will update its action plan with specific resource recommendations and request acknowledgement that the Company's final action plan is consistent with least cost planning principles established by the OPUC.
Receivables - California Wholesale Market
As of March 31, 2003, PGE has net accounts receivable balances totaling approximately $62 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).
On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code.
PGE is pursuing collection of all past due amounts through the PX and PG&E bankruptcy proceeding and has filed a proof of claim in each of the proceedings. Management continues to assess PGE's exposure relative to its California receivables and has established reserves of $29 million related to this receivable amount, including $11.5 million recorded in the first quarter of 2003. The Company is examining numerous options, including legal, regulatory, and other means to pursue collection of any amounts ultimately not received through the bankruptcy process. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables.
Management believes that the outcome of this matter will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.
Refunds on Wholesale Transactions
California
In a June 19, 2001 order adopting a price mitigation program for 11 states within the WECC area, the FERC referred to a settlement judge the issue of refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and the PX.
On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering an evidentiary hearing proceeding to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Hearings were held in February and March 2002 to determine the appropriate proxy prices to use and which sales were exempt from refunds because they had been made pursuant to orders of the Department of Energy. Further hearings were held in August through October, 2002, to determine the method of calculation of amounts owed to, and refunds owed by, sellers into the California market.
On August 13, 2002, the FERC staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in the Company's potential refund obligation. The FERC asked for comments on the staff's recommendation, and on October 15, 2002, PGE, along with several other utilities, filed comments with the FERC objecting to the FERC staff's recommendations. Subsequent to the issuance of the FERC's August 13, 2002 report, several companies disclosed that some of their gas traders reported incorrect prices to the firms that report gas indices. In addition, on September 23, 2002, a FERC administrative law judge issued an order in a complaint case against El Paso Natural Gas Company, finding that El Paso had manipulated the gas market by withholding capacity. Also, in October 2002, a former Vice President and Managing Director of Enron's West Power Trading Division entered a g uilty plea to conspiracy to commit wire fraud in connection with California's energy market.
In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds. Although no final dollar amounts were included in the certification, the recommended methodology indicated a potential refund by PGE of $20 million to $30 million.
Appeals of the FERC orders establishing the refund methodology have been filed and are pending in the Ninth Circuit Federal Court of Appeals. On August 21, 2002 the Ninth Circuit issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation. In compliance with this order, the FERC authorized all parties to conduct further inquiry and to submit additional evidence of market manipulation. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.
On March 3, 2003, numerous parties filed documents addressing possible market manipulation. The most comprehensive filings were by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respectCalifornia parties. In addition to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, which allegealleging that the lossesmarkets were caused by Enron's manipulation of the stock, seek binding arbitration under Local 125's collective bargaining agreement on behalf of all present and retired bargaining unit members. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. PGE has filed a Motion for Declaratory Relief in the Multnomah County Circuit Court for the State of Oregon, seeking a declaratory ruling that the grievances are not subject to arbitration under the collective bargaining agreement, that the grievances are preempted by ERISA,manipulated and that the conduct complainedrefund cases should thus be expanded, they alleged that numerous sellers, including PGE, participated in various strategies that affected the market adversely. On March 20, 2003, PGE, both individually and as part of is directed against Enron, not PGE. The IBEW f ileda group of similar utilities, filed responses rebutting the claims of the California parties.
On March 26, 2003, the FERC issued an answer and counterclaimorder in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge, issued in December 2002, but modifying the methodology it had previously ordered for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates that the new methodology could increase the amount of the potential refunds by approximately $20 million. Although further proceedings will be necessary to determine exactly how the new methodology will affect the refund liability, the Company now estimates its potential liability to be between $20 million and $50 million.
PGE does not agree with several aspects of the FERC's methodology for determining potential refunds. On April 25, 2003, PGE joined a group of utilities in filing a request for rehearing of various aspects of the March 26, 2003 order, including the repricing of the gas cost component of the proxy price from which refunds are to be calculated.
Pacific Northwest
In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action.
In December 2002, the FERC re-opened this case to allow parties to conduct further discovery. In coordination with the order in the California refund case (described above), the FERC authorized all parties to conduct further inquiry and to submit additional evidence. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.
On March 3, 2003, numerous parties filed documents addressing possible market manipulation. The most comprehensive filings were by the City of Tacoma. In addition to alleging that the markets were manipulated and that the refund cases should thus be expanded, they alleged that numerous sellers, including PGE, participated in various strategies that adversely affected the market. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of these parties.
On March 26, 2003, the FERC indicated that it might issue is arbitrable,an order to remand the case for a determination of refunds. The remand could include the appointment of a settlement judge or additional hearings to determine refund amounts, if any. At this time, the Company does not know what the order may require or what sanctions may be sought.
Potential Refund Mitigation
The FERC has indicated that any refunds PGE may be required to pay related to California sales can be offset by accounts receivable related to sales in California (as discussed in Note 5, Receivables - California Wholesale Market). As indicated in Note 5, PGE has established reserves of $29 million related to the receivable amount. The FERC has also indicated that interest on both refunds and offsetting accounts receivable will be computed from the effective dates of the applicable transactions; such interest has not yet been recorded by the Company.
In addition, any refunds paid or received by PGE filed a reply that deniedapplicable to spot market electricity transactions on and after January 1, 2001 in California and the counterclaim and raised four affirmative defenses. The Circuit Court has set a trial datePacific Northwest may be eligible for inclusion in the calculation of May 22, 2003. net variable power costs under the Company's power cost mechanism in effect at the time. This could further mitigate the financial effect of any refunds made or received by the Company.
Management cannot predict the ultimate outcome of these grievances.matters. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.
Environmental MatterShow Cause Order
A 1997 investigationPursuant to the FERC Staff's Final Report on Price Manipulation in Western Markets, issued in Docket No. PA02-2-000, the FERC indicated, in a press release issued on March 26, 2003, that it intends to issue orders to PGE and 36 other entities that participated in the California wholesale market in 2000 and 2001, requiring that each entity show cause why their behaviors during that time period did not constitute gaming in violation of a portion of the Willamette River known as the Portland Harbor, conductedtariffs issued by the EPA, revealed significant contamination of sediments withinCalifornia Independent System Operator (ISO) and the harbor. Subsequently,California Power Exchange (PX). The FERC indicated that possible sanctions for any entity found to have violated the EPA included Portland Harbortariffs include disgorging unjust profits associated with the violations, or other appropriate remedies. Based on the federal National Priority list pursuantits internal investigations to the federal Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund").
In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the Portland Harbor sediments. Whiledate, PGE does not believe that it is responsibleviolated ISO or PX tariff provisions.
Wholesale Price Mitigation
In June 2001, the FERC adopted a price mitigation program for any contaminationthe power system serving 11 Western states, adopting a new benchmark formula limiting prices for electricity sold in Portland Harbor,the spot markets at all times throughout the region through September 2002. The program applied to power generators, marketers, and investor-owned utilities under FERC jurisdiction, as well as public power providers, municipal utilities, and electric cooperatives that use FERC-regulated transmission lines.
Under the program, a ceiling price was set by FERC for wholesale electricity sold in May 2000, the Company entered intospot market coordinated by the California Independent System Operator (ISO) and in markets in the other Western states. Such price, initially set at $91.87/MWh, reflected specified fuel, operations, and maintenance costs, and was based upon the bid submitted by the highest cost gas-fired generating unit supplying power during a "Voluntary Agreement for Remedial Investigation and Source Control Measures" ("Voluntary Agreement") with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement.Stage 1 supply emergency.
In December 2001, the FERC temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the ISO, recognizing differences between Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. The changes, including a ceiling price of $108/MWh, were in effect until May 1, 2002, at which time the previous methodology and ceiling price again became effective.
In July 2002, the FERC raised the ceiling price on Western wholesale electricity prices from $91.87/MWh to $250/MWh, effective October 31, 2002. The new ceiling price applies to all sales of electricity in the WECC. In addition to the new price ceiling, the FERC order established conditions and rules guiding participation in Western wholesale electricity markets, including automatic price mitigation procedures to be implemented during periods of tight supplies.
Federal Investigations - Wholesale Power Markets
On February 13, 2002, the FERC initiated a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. On March 5, 2002, all sellers with wholesale sales in the U.S. portion of the WECC were directed to provide certain historical and projected information for all energy transactions in calendar years 2000 and 2001. In April 2002, the Company submitted the requested information. Additionally, on March 15, 2002 the FERC enforcement staff issued a subpoena to Enron, which Enron then forwarded to the Company. In response to this subpoena, the Company provided information related to its trading organization, its trading policies and procedures, its price curves and their derivation, and its trading position reports.
As a result of an internal investigation, PGE receiveddiscovered that it had failed to properly post on a public web site information about some of its energy transactions with an affiliate, Enron Power Marketing, Inc. The preliminary results of this investigation were disclosed to FERC Staff on April 15, 2002 and final results on August 1, 2002. This issue was subsequently included in the investigation in Docket No. EL02-114-000 described below.
Enron Trading Strategies
In early May 2002, Enron provided memos to the FERC that contained information indicating that Enron, through its subsidiary Enron Power Marketing, Inc. (EPMI), may have engaged in several types of trading strategies that raised questions regarding potential manipulation of electricity and natural gas prices in California in 2000-2001. On May 8, 2002, the FERC ordered all sellers of wholesale electricity or ancillary services into the California markets during 2000-2001 to respond to the FERC whether they engaged in any transactions falling within any of the enumerated types of trading strategies, and, if they did, to provide information about the transactions. Although PGE was not specifically named in the FERC order, on May 22, 2002, PGE voluntarily submitted the results of its investigation to the FERC. The material submitted to FERC did not show any instances where the Company engaged in or knowingly aided deceptive or misleading trading strategies. However, PGE reported that i t was among other intermediaries in a series of trading activities that occurred on 15 days from April through June 2000 where EPMI was found to be at both ends of the EPAtransaction chain. The trading transactions identified during the 15-day period moved about 2,300 megawatt hours (0.12%) of the total 2 million megawatt hours traded by PGE on those days, and about 0.02% of the total 13 million megawatt hours traded by PGE during the three-month period. The services provided by PGE may have been used by EPMI as a "Noticestep in one of Potential Liability" regarding the Harborton Substation facility. Such notice included a "Portland Harbor Initial General Notice List" containing sixty-eightenumerated strategies. In addition, it is conceivable that in the normal course of business, PGE could have provided services to third parties that may have resulted in PGE being used, unknowingly, as an intermediary in partial execution of one or more of the enumerated strategies.
On June 4, 2002, the FERC issued an order to PGE and three other companies to show cause why their authority to charge market-based rates should not be revoked. The order stated that the EPAcompanies' responses to the FERC's May 8, 2002 data request (discussed above) are indicative of a failure to cooperate with its investigation. On June 14, 2002, PGE filed a response indicating that a thorough review of Company documents again found no evidence of deception or market manipulation by PGE. PGE believes may be Potentially Responsible Partiesthat it has fully cooperated with the FERC's inquiry.
On August 13, 2002, the FERC issued two orders initiating investigations into instances of possible misconduct by PGE and certain other companies. In the first order (Docket No. EL02-114-000), the FERC ordered investigation of PGE and EPMI related to possible violations of their codes of conduct, the FERC's standards of conduct, and the companies' market-based rate tariffs, and whether PGE has cooperated by providing all relevant information related to the FERC's May 8, 2002 data request and June 4 Show Cause Order. In the second order (Docket No. EL02-115-000), the FERC ordered investigation of Avista Corporation and Avista Energy, Inc. (collectively, Avista) with respect to, among other things, transactions in which Avista engaged in or facilitated the Portland Harbor Superfund Site.trading strategies identified in the Enron memoranda or acted as a middleman with respect to sales of electric energy between PGE and EPMI. PGE and EPMI are included as parties in that Docket. In the orders, the FERC established Octobe r 15, 2002 as the "refund effective date." Issues involving PGE and EPMI in Docket No. EL02-115-000 have now been consolidated into Docket No. EL02-114-000. If PGE were to lose its market-based rate authority, purchasers of electric energy from PGE at market-based rates after the refund effective date could be entitled to a refund of the difference between the market-based rates and cost-based rates deemed just and reasonable by the FERC.
On December 10, 2002, the FERC trial staff released a Revised Statement of Asserted Violations (Revised Statement) and its initial testimony in its investigation of PGE (Docket No. EL02-114-000). The assertions in the Revised Statement and testimony are limited to PGE's self-reported failure to properly post information about some of its energy transactions with EPMI, and alleged violations for affiliate dealings with EPMI relating to a series of transactions that occurred on certain days in April-June 2000, involving PGE, EPMI, and Avista Corporation. The latter transactions were previously reported by PGE to FERC on May 22, 2002 in response to the FERC's May 8, 2002 data request. The trial staff recommended a remedy of revocation of PGE's market-based rate authority for two years, and a requirement that PGE's application for reinstatement of market-based rates include documentation supporting revised procedures to ensure that posting errors and violations of affiliate rules do not occu r again. The City of Tacoma, Washington filed testimony seeking a refund from PGE of $3.2 million. The California Attorney General and the California Public Utilities Commission (California Parties) have filed testimony that PGE should refund amounts to compensate market participants for PGE's alleged unlawful conduct, but the testimony specifies no amount of refunds.
PGE's initial response testimony in Docket No. EL02-114-000 was filed on February 24, 2003. In accordanceits testimony, PGE describes the posting errors it self-reported, most of which were technical in nature and may in fact not have been in error. The Company also described the cooperation it has extended to the FERC, the investigative staff, and the trial staff in providing all requested information to aid the investigation. PGE also provided testimony that the April-June 2000 transactions with EPMI did not involve violations of affiliate rules, except for certain posting errors.
The hearing in Docket No. EL02-114-000 is scheduled to begin on June 2, 2003, with an initial decision from the presiding FERC judge scheduled for July 17, 2003. The procedural schedule in Docket No. EL02-115-000 is currently suspended pending further revisions to a settlement proposal submitted between Avista and FERC trial staff.
PGE will continue to cooperate with the Voluntary Agreement, in March 2001,investigations. PGE submitted a final investigation plancontinues to the DEQ for approval. DEQ approved the plan and in June 2001, PGE performed initial investigations and remedial activities based upon the approved investigation plan. Such investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.
In February 2002, PGE submitted a final investigation report to the DEQ summarizing its investigations conducted in accordancebelieve that it has fully complied with the May 2000 Voluntary Agreement. The report indicatedFERC investigation initiated on February 13, 2002, and that such investigations demonstrated that there is no likely presentit has not engaged in deception or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The report concluded that the Harborton Substation facility was not a source of contamination to the Willamette River because no likely sources of hazardous substance releases were identified. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.market manipulation.
The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign, nor has it signed, such an order. Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE. (For further information, see Note 3, Legal and Environmental Matters, in the Notes to Financial Statements).
Retail Customer Growth and Energy Sales
Weather adjusted retail energy sales decreased 2.2% for the nine months ended September 30, 2002, compared to the same period last year. Manufacturing sector sales declined 2.5%, with most segments of this sector down from last year. Excluding the effects of the Demand Buyback program, in which PGE paid large customers to reduce their load during peak demand periods in 2001, manufacturing sector sales declined about 9%. Commercial and residential energy sales were down 3.4% and 0.6%, respectively. PGE forecasts retail energy sales in 2002 will remain down somewhat from last year, as continued customer growth is offset by both a slow economy and increased conservation efforts.
Power Supply
Hydro conditions in the region have significantly improved from last year.remain below normal levels. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, indicatecurrently project the January-to-July runoff at 97%84% of normal, compared to 55%97% of normal last year.in 2002.
PGE generated 37%51% of its retail load requirement in the first nine monthsquarter of 2002,2003, with hydro generation comprising about 9%7% of the Company's requirement; short- and long-term purchases were utilized to meet the remaining load. Due to increased customer use of air conditioning, PGE's summer load has become increasingly sensitive to high temperatures. On August 13, 2002, a new summer record for electricity consumption (3,408 megawatts) was set; this exceeded the Company's previous summer peak consumption of 3,341 in July 1998. The Pacific Northwest peak season continues to be in winter months, when home and business heating and lighting cause the highest demand. PGE's all-time peak of 4,073 megawatts occurred in December 1998.
PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers. Although
The amount of surplus generation has diminished in recent years due to economic and population growthelectric generating capability in the western United States, recent constructionthe amount of new generating plants has increasedannual snow pack and its impact on hydro generation, the region's capacitynumber and credit quality of wholesale marketers and brokers participating in the energy trading markets, the availability and price of natural gas as well as other fuels, and the availability and pricing of electric and gas transmission all contributed to and have an impact on the wholesale price and availability of electricity. PGE will continue its participation in the wholesale energy marketplace in order to manage its power supply risks and acquire the necessary electricity and fuel to meet the needs of its power needs.retail customers and administer its current long-term wholesale contracts. In addition, a reductionthe Company will continue its trading activities to participate in demand from a slowing economy and increased conservation efforts, along with increasedelectricity, natural gas, supplies and federal price mitigation, have together resulted in significantly lower market prices for both electricity and natural gas than in the first nine months of 2001.crude oil markets.
Hydroelectric Project RemovalEnron Bankruptcy
On October 24, 2002,Commencing in December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE entered into an agreement withnor numerous other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members, and its stock has been de-listed from the New York Stock Exchange. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal agencies, conservation groups, and others that provides for the removal of the Company's 22-MW Bull Run hydroelectric project on the Sandy River,regulators, including the MarmotFERC and Little Sandy Dams.the State of Oregon. In March 2002, Enron, substantially all of its subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.
Although PGE is not included in the Enron bankruptcy, it has been affected. The Company has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating. In addition, PGE was included among those Enron entities suspended from contracting with the agreement provides forfederal government. The suspension, which expired in March 2003, had no material adverse effect on PGE business or operations.
In addition to the protectiongeneral effects discussed above, PGE may have potential exposure to certain liabilities and asset impairments as a result of threatened fish speciesEnron's bankruptcy. These are:
1. Amounts Due from Enron and the transfer of 1,500 acres of PGE-owned land to a nonprofit organization toward the creation of a 5,000-acre wildlife and public recreation area. The agreement provides for the removal of the Marmot DamEnron-Supported Affiliates in 2007 and the Little Sandy DamBankruptcy - As described in 2008.
PGE's license on the Bull Run project, issued by the FERC, expires in November 2004 and will not be renewed. Under the terms of the agreement, the project will operate until the removal of Little Sandy Dam. PGE's current rates include recovery of its remaining plant investment through the end of the project's existing license period. Such rates also include recovery, over a ten-year period beginning October 2001, of about $16 million in estimated decommissioning costs.
New Accounting Standards
See Note 8, New Accounting Standards,4, Related Party Transactions, in the Notes to Financial Statements, PGE is owed approximately $82 million (including accrued interest) by Enron at March 31, 2003 (Merger Receivable). Such amount was to have been paid by Enron to PGE for informationprice reductions granted to customers, as agreed to by Enron at the time it acquired PGE in 1997. Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the entire amount of this receivable, of which $74 million was recorded in December 2001. On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, including $73 million for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, due to uncertainties associated with other receivable balances from Enron subsidiary companies which are part of the bankruptcy proceedings, a reserve has been established for the entire $2 million remaining balance of such receivables at March 31, 2003.
2. Controlled Group Liability - Enron's bankruptcy has raised questions regarding newpotential PGE liability for certain employee benefit plans and tax obligations of Enron.
Pension Plans
Funding Status
The pension plan for the employees of PGE (the PGE Plan) is separate from the Enron Corp. Cash Balance Plan (the Enron Plan). Although at December 31, 2002 the total fair value of PGE Plan assets was $16 million lower than the projected benefit obligation on a SFAS No. 143,87 (Employers' Accounting for Asset Retirement Obligations, andPensions) basis, the PGE Plan remains over-funded on an accumulated benefit obligation basis by about $30 million. Enron's management has informed PGE that, as of December 31, 2002, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $52 million on a SFAS No. 146, Accounting87 basis and approximately $182 million on a plan termination basis. Further, Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases. The claims are duplicative in nature, representing unliquidated claims for Costs AssociatedPBGC insurance premiums (the "Premium Claims") and unliquidated claims for due but unpaid minimum funding contributions (the "Contribution C laims") under the Internal Revenue Code of 1986, as amended (the "Tax Code") 29 U.S.C. Section 1082 and claims for unfunded benefit liabilities (the "UBL Claims"). Enron and the relevant sponsors of the defined benefit plans are current on their PBGC premiums and their contributions to the pension plans. Therefore, Enron has valued the Premium Claims and the Contribution Claims at $0. The total amount of the UBL Claims is $305.5 million (including $271 million for the Enron Plan, and $24.8 million for the PGE Plan). In addition, Enron management has informed PGE that the PBGC has informally alleged in pleadings filed with Exitthe Bankruptcy Court that the UBL claim related to the Enron Plan could increase by as much as 100%. PBGC has provided no support (statutory or Disposal Activities.otherwise) for this assertion and Enron management disputes the validity of any such claim.
It is permissible, subject to applicable law, for separate pension plans established by companies in the same controlled group to be merged. Enron could direct that the PGE Plan be merged with the Enron Plan. If the plans were merged, any excess assets in the PGE Plan would reduce the deficiency in the Enron Plan. However, if the plans are not merged, the deficiency in the Enron Plan could become the responsibility of the PBGC, which insures pension plans, including the PGE Plan and the Enron Plan, and the PGE Plan's surplus would be undiminished. Merging the plans would reduce the value of PGE, the stock of which is an asset available to Enron's creditors. PGE's management believes that it is unlikely that either Enron or Enron's creditors would agree to support merging the two plans.
Enron cannot itself terminate the Enron Plan while it is underfunded unless it provides at least 60 days notice and the PBGC, in the case of solvent entities, or the Bankruptcy Court, in the case of insolvent entities, determines that each member of Enron's controlled group, including PGE, is in financial distress, as defined in ERISA. In the opinion of management, PGE is a solvent entity that does not meet the financial distress test. Consequently, management believes that it is unlikely that Enron can unilaterally terminate the Enron Plan while it is underfunded. However, Enron could, with consent of the PBGC (see discussion below), seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with ERISA.
The PBGC does have the authority, either by agreement with the plan administrator or upon application to and approval by a Federal District Court, to terminate and take over control of underfunded pension plans in certain circumstances. In order to initiate this process, the PBGC must determine that either the minimum funding standard for the plan (see discussion below) has not been met, or that the plan will not be able to pay benefits when due, or that there is a reasonable risk that long-run losses to the PBGC will be unreasonably increased or that certain distributions have been made from the plan. The court must determine that plan termination is necessary to protect participants, the plan, or the PBGC.
Upon termination of an underfunded pension plan, all members of the controlled group of the plan sponsor become jointly and severally liable for the underfunding, but are not obligated to pay until a demand for payment is made by the PBGC. The PBGC can demand payment from one or more of the members of the controlled group. If payment of the full amount demanded is not made, a lien in favor of the PBGC automatically arises against all of the assets of each member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the aggregate net worth of all controlled group members. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien does not take priority over other previously perfected liens on the assets of a member of the controlled group. Substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Management believes that any lien asserted b y the PBGC would be subordinate to that lien.
PGE management has been informed by Enron management that on November 15, 2002, Enron informed its employees that it is taking steps to terminate the Enron Plan. As an initial step in terminating the Enron Plan, Enron amended the Enron Plan to cease monthly accruals effective January 1, 2003, so that only interest credits would accrue after that date. Enron also informed its employees that it intends to seek the approval of its Unsecured Creditors' Committee and the U.S. Bankruptcy Court to fully fund and then terminate the Enron Plan in a standard termination. Approval to terminate the Enron Plan also will be requested from the PBGC and the IRS. Enron informed its employees that, if approved, the termination process could take 12 months or longer.
PGE management believes that the proposal to fully fund the Enron Plan and terminate it in a standard termination, if approved and consummated, should eliminate any need for the PBGC to attempt to collect from PGE any liability related to the termination of the Enron Plan. There can be no assurance at this time that the funding and termination will be approved by the Unsecured Creditors' Committee or the Bankruptcy Court or that, upon such approval, Enron will have the ability to obtain funding on acceptable terms.
If the PBGC did look solely to PGE to pay any underfunded amount in respect of the Enron Plan, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover any contributions from the other solvent members of Enron's controlled group. Until the Enron Plan is terminated and the PBGC makes a demand on PGE to pay some or all of any underfunded amount, PGE has no liability for the underfunded amount and no termination liens arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any underfunded amount assessed by the PBGC. No reserves have been established by PGE for any amounts related to this issue.
Minimum Funding Obligation
If the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in the amount of the missed funding automatically arises against the assets of every member of the controlled group. The lien is in favor of the plan, but may be enforced by the PBGC. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien would not take priority over other previously perfected liens on the assets of a member of the controlled group. If Enron does not timely satisfy its minimum funding obligation in excess of $1 million, a lien will arise against the assets of PGE and all other members of the Enron controlled group. The PBGC would be entitled to perfect the lien and enforce it in favor of the Enron Plan against the assets of PGE and other members of the Enron controlled group. However, substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. PGE management believes that any lien asserted by the PBGC would be subordinate to that lien.
Based on discussions with Enron management, PGE management understands that Enron has made all required contributions to date and the next contribution is not due until July 15, 2003. PGE does not know if Enron will make contributions as they become due. Management is unable to predict if Enron will miss a payment and, if so, whether the PBGC would seek to have PGE make any or all of the payment. If the PBGC did look solely to PGE to pay the missed payment, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover contributions from the other solvent members of the Enron controlled group. Until Enron misses contributions exceeding $1 million, PGE has no liability and no liens will arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any missed payments demanded by the PBGC. No reserves have bee n established by PGE for any amounts related to this issue.
Retiree Health Benefits
Under COBRA, retirees of a bankrupt employer who lose coverage under a group health plan of the employer as a result of certain bankruptcy proceedings are entitled to elect continuation of health coverage in a group health plan maintained by the bankrupt employer or a member of its controlled group. PGE management understands, based on discussion with Enron management, that Enron provides a plan for health insurance for certain retirees, and that the actuarial liability for such coverage amounted to approximately $70 million at December 31, 2001 (the most recent date for which information is available). Management further understands that to meet its obligation, Enron had set aside approximately $34 million of assets in a VEBA trust that may be protected under ERISA from Enron's creditors, leaving an unfunded liability of approximately $36 million at December 31, 2001.
In the event that Enron terminates its retiree group health plan, the retirees must be provided the opportunity to purchase continuing coverage from Enron's group health plan, if any, or the appropriate group health plan of another member of the controlled group. Neither Enron nor any member of the controlled group would be required to fully fund the benefit or create new plans to provide coverage, and retirees would not be entitled to choose from which plan to obtain coverage. Retirees electing to purchase COBRA coverage would be provided the same coverage that is provided to similarly situated retirees under the most appropriate plan in the Enron controlled group. Retirees electing to continue coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire coverage under COBRA. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.
Management believes that in the event Enron terminates retiree coverage, any material liability to PGE associated with Enron retiree health benefits is unlikely for two reasons. First, based on discussion with Enron management, PGE management understands that most of the retirees that would be affected by termination of the Enron plan are from solvent members of the controlled group and few, if any, live in Oregon. Management believes that it is unlikely that any PGE plans would be found to be the most appropriate to provide COBRA coverage. Second, even if a PGE plan were selected, management believes that retirees in good health should be able to find less expensive coverage from other providers, which will reduce the number of retirees electing COBRA coverage. Management believes that the additional cost to PGE to provide coverage to a limited number of retirees that are unable to acquire other coverage because they are hard to insure or have preexisting conditions will not be materi al. No reserves have been established by PGE for any amounts related to this issue.
Income Taxes
Under regulations issued by the U.S. Treasury Department, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with PGC. Based on discussions with Enron's management, PGE management understands that Enron has treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and becoming a member of Enron's consolidated group once again on December 24, 2002. On December 31, 2002, PGE and Enron entered into a tax sharing agreement pursuant to which PGE agreed to make payments to Enron that approximate the income taxes for which PGE would be liable if it were not a member of Enron's consolidated group. As of April 30, 2003, PGE has paid $21 million to Enron under the tax sharing agreement.
Enron's management has provided the following information to PGE:
A. Enron's consolidated tax returns through 1995 have been audited and are closed. Management understands that the IRS has completed an audit of the consolidated tax returns for 1996-2001.
- For years 1996-1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries substantial NOLs for any additional income tax liabilities that may result from the negotiation of the claim stemming from the IRS audit for the periods in which PGE was a member of Enron's consolidated federal income tax returns.
- Enron's 2002 tax return has not yet been filed. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2002. Enron expects that, in addition to offsetting its income tax liabilities for years before 2002, these NOLs will be sufficient to fully offset Enron's regular and alternative minimum income tax liabilities for 2002 and its regular income tax liability for all subsequent periods through the date of consummation of its plan of reorganization.
- Enron believes that all of the requirements for re-consolidation of PGE with the Enron consolidated group have been met. However, because of the inherently factual nature of the determination of the re-consolidation, there can be no assurance that the IRS will agree with this position. In the event that the IRS does not agree and the matter is not resolved in the bankruptcy proceeding (or otherwise), PGE will have an administrative expense claim against Enron for any amounts paid by PGE to Enron under the tax sharing agreement. Enron management believes that all administrative expense claims will be paid in full.
On March 28, 2003, the IRS filed various proofs of claim for taxes in the Enron bankruptcy, including a claim for approximately $111 million in respect to income tax, interest, and penalties for taxable years for which PGE was included in Enron's consolidated tax return. The IRS seeks to apply $63 million in tax refunds admittedly due Enron against these claims. IRS claims for taxes and prepetition interest have a priority over claims of general unsecured creditors, but claims for prepetition penalties have no priority and claims for postpetition interest are not allowable in bankruptcy. The Company, along with other corporations in Enron's consolidated tax returns that are not in bankruptcy, are severally liable for prepetition penalties and postpetition interest, as well as any portion of the claim allowed in the bankruptcy that the IRS does not collect from the debtors.
Enron's management has informed PGE management that Enron is negotiating with the IRS in an attempt to resolve issues raised by the IRS claims. If the parties do not reach a settlement, the bankruptcy court will decide the actual amount, if any, owed to the government in respect to tax, interest, and penalties.
To the extent, if any, that the IRS would look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that are available for recovery in Enron's bankruptcy proceeding, or to otherwise seek to obtain contributions from the other solvent members of the consolidated group. As a result, management believes the income tax, interest, and penalty exposure to PGE (related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's consolidated returns) would not be material. No reserves have been established by PGE for any amounts related to this issue.
PGE management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.
PGE management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Neither PGE nor Enron have guaranteed the obligations of the other. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and PGC in 1997 (Merger Conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis.
PGE management does not believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern. PGE believes that in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely the holder of PGE's common stock, and PGE, as a debtor in possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. As debtor in possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management. PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) creditors. No dividends could be paid to Enron, no assets could be sold, and no other tr ansfer of funds could be made except with the approval of the Bankruptcy Court after notice to PGE's creditors. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers. Since the issue of whether a Bankruptcy Court has the authority to supersede state regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course. On September 30, 2002, the Company issued to an independent shareholder a single share of a new $1.00 par value class of Limited Voting Junior Preferred Stock which limits, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings without the consent of the shareholder.
Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy. For additional information, see Note 7, Enron Bankruptcy, in the Notes to Financial Statements.
Enron Debtor in Possession Financing
PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a debtor in possession credit agreement with Citicorp USA, Inc. and JPMorgan Chase Bank. The agreement was amended and restated in July 2002. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control ov er PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.
Enron Auction Processes Related to PGE
PGE has been informed by Enron management that the proposal Enron presented to its Unsecured Creditors' Committee on May 3, 2002 to separate certain of Enron's core energy assets, including PGE, from Enron's bankruptcy estate and operate them prospectively as a new integrated power and pipeline company has been withdrawn. Enron continues to pursue the sale of PGE through the auction process that it announced on August 27, 2002. However, Enron has stated that it reserves the right not to sell PGE if the bids received are not deemed fully reflective of its value. A sale of PGE would require the consideration and approval of regulatory agencies, including the OPUC.
Enron management has informed PGE that if PGE is not sold in the auction process, it is anticipated that the shares of PGE stock owned by Enron would be distributed over time to creditors of Enron in connection with Enron's plan of reorganization. It is also anticipated that PGE's stock would be listed on a national stock exchange and would be publicly traded. In connection with the distribution to creditors, it is expected that PGE would be governed by an independent Board of Directors. Until resolution of the bankruptcy case and distribution of the PGE shares, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of Enron's stakeholders.
Enron has filed a motion with the Bankruptcy Court to extend the time to file its plan of reorganization to June 30, 2003. Until the plan of reorganization or another filing related to the sale of PGE is filed with the Bankruptcy Court and approved, management cannot assess the impact on PGE's business and operations of a sale or the distribution of PGE's stock to Enron's creditors.
Public Ownership Initiatives
In August 2002, the City Council of Portland, Oregon passed a resolution authorizing the expenditure of up to $500,000 for professional advice regarding the City's potential acquisition of PGE, including possible condemnation of the Company's assets. The City has signed a confidentiality agreement with Enron to permit it to participate in the Enron auction process relating to PGE.
Initiative petitions were circulated in Multnomah County that obtained sufficient signatures to place a measure on an election ballot (expected to be in the fall of 2003) that, if passed, could result in the formation of a Peoples' Utility District (PUD) in Multnomah County. In addition, if this measure succeeds, the expressed intent of its supporters is to hold additional elections to expand the boundaries of the district to include all of PGE's service territory. If a PUD is formed, it would have the authority to condemn PGE's distribution assets within the boundaries of the district. Oregon law prohibits the PUD from condemning thermal generation plants. It is uncertain under Oregon law whether the PUD would be able to condemn PGE's hydro generation plants.
Public hearings, as required by Oregon law, have been held and will continue regarding the proposed PUD. PGE opposes the formation of the PUD and will oppose any efforts to condemn the Company's assets.
Complaints to OPUC
Income Taxes
On March 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) filed a petition to open an investigation and a complaint with the OPUC with respect to the amount of federal, state, and local income taxes paid by PGE since 1997. On March 31, 2003, the OPUC rejected the request for an investigation, but the complaint remains. On May 8, 2003, PGE filed with the OPUC its answer and a motion to dismiss the complaint.
Limited Voting Junior Preferred Stock
On May 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) served the OPUC with a complaint filed in Marion County Circuit Court on March 17, 2003 seeking to vacate OPUC Order 02-674 in which the OPUC granted authority to the Company to issue a share of Limited Voting Junior Preferred Stock. The complaint alleges that the OPUC did not follow the proper procedure in issuing the Order. The complaint seeks to have the matter remanded to the OPUC for further proceedings. PGE intends to intervene in the case and oppose the relief sought by the Complainants. For further information, see Note 4, Common and Preferred Stock, in PGE's report on Form 10-K for the year ended December 31, 2002.
Retail Rate Changes
Power Cost Price Decrease - 2003
The OPUC's 2001 general rate order contains a Power Cost Stipulation that requires annual updates of PGE's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines of Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, a Resource Valuation Mechanism (RVM) utilizes a combination of market prices and the value of the Company's resources to establish power costs and set rates for energy services. The RVM process requires that PGE adjust its rates if its projected power costs change from those included in its 2001 general rate case. It provides for an adjustment, filed annually on November 15, which is effective January 1 of the following year.
PGE's first annual revision of its power supply costs under the RVM process forecast a reduction in the cost of power from that utilized in the Company's 2001 general rate case. Accordingly, the OPUC authorized reductions in the Company's retail prices, effective January 1, 2003. Price decreases range from 2% for residential customers to between 9% and 17% for commercial and industrial customers. Rates for business customers are affected more by wholesale energy market prices, which have decreased in the 2003 forecast. The smaller decrease in residential rates reflects the cost of electricity from BPA, which increased its rates in October 2002, as well as PGE's cost of generation. Based upon projected energy sales, it is estimated that such price decreases will reduce PGE's 2003 revenues by approximately $100 million.
Included in the price reduction is the effect of the OPUC's disallowance, based upon a prudence review, of approximately $15 million related to four power purchase contracts, entered into in the first half of 2001, providing 125 megawatts of on-peak delivery in 2003.
The new prices also reflect a resolution regarding the recovery period for PGE's power cost mechanism covering the period October 2001 through December 2002. This amount includes the effect of a settlement stipulation related to estimated 2003 power costs, in which PGE agreed to reduce its recovery under the power cost mechanism by approximately $4.6 million; such reduction was recorded by the Company in 2002.
Power Cost Adjustment Mechanisms
As actual power costs in any year may differ substantially from those costs used in rate determination, the OPUC in 2001 authorized power cost adjustment mechanisms that allowed the Company to defer for later recovery from retail customers actual net variable power costs which differed from certain baseline amounts. Under the initial power cost mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received OPUC approval to recover the approximate $91 million balance (including interest) over a 3 1/2-year period (April 2002 - September 2005). At March 31, 2003, the remaining balance to be collected was approximately $67 million.
In its August 2001 general rate order, the OPUC approved a power cost adjustment mechanism for the period October 2001 through December 2002. Under this mechanism, PGE deferred $41 million in power costs, representing the difference between actual net variable power costs and the amount used to establish base energy rates, as well as the difference between actual energy revenues and a pre-determined base. The deferred amount, subject to a prudence review and audit by the OPUC, is being collected from large industrial customers over a one-year period (2003) and over a two-year period (2003-2004) from all other customer classes. At March 31, 2003, the balance to be collected was approximately $31 million.
Although PGE does not have a power cost adjustment mechanism in place for 2003, the Company has filed with the OPUC an application to defer for later ratemaking treatment increases in power costs related to expected adverse hydro conditions (see "Hydro Replacement Power Costs" below for further information).
Hydro Replacement Power Costs - 2003
A region-wide drought throughout the Pacific Northwest has resulted in adverse hydro conditions for PGE and other utilities, with early forecasts indicating hydro conditions significantly below normal. In anticipation of the effects of such conditions, PGE has begun to acquire replacement power resources for the expected shortfall in hydro-based power, incurring substantially higher variable power costs than those contained in the Company's current rates.
On February 11, 2003, PGE filed with the OPUC an Application for Deferral of Hydro Replacement Power Costs, in which the Company requests authorization to defer for later ratemaking treatment increases in power costs incurred from the application date through December 31, 2003. The Company's application requests authorization for the deferral of 95% of the difference between actual net variable power costs and those allowed in current rates, with interest accrued at PGE's authorized rate of return. As proposed, the deferral would be adjusted for the impact that changes in load would otherwise have on net variable power costs. Although the amount of the deferral would be determined over the course of the year, PGE estimates that the amount could range from $20 million to $60 million. The application is currently pending before the OPUC.
Preliminary Power Cost Filing - 2004
On April 1, 2003, PGE submitted a Resource Valuation Mechanism filing with the OPUC containing an estimate of 2004 power costs based upon preliminary information that will be updated later in 2003. The filing forecasts retail price increases for both residential and nonresidential customers ranging from 2.5 percent to 5 percent, based upon the effect of higher wholesale power, coal, and natural gas prices on PGE's costs. Final adjustments will be determined in November 2003.
Electric Power Industry Restructuring
Oregon's electric energy industry restructuring plan, implemented on March 1, 2002, provides all of PGE's commercial and industrial customers direct access to competing energy suppliers. The RVM document filed by the Company with the OPUC on April 1, 2003 includes proposed changes that will facilitate the ability of such customers to make decisions related to direct access service and electricity pricing options. Residential and small business customers can continue to purchase electricity from a "portfolio" of rate options that include a basic service rate, a time of use rate, and renewable resource rates.
Integrated Resource Plan
In August 2002, PGE filed a new Integrated Resource Plan. In its Plan, PGE describes its strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. The Plan, which considers resource actions over the next two to three years, includes reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. It also considers future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, long-term power purchases, and meeting seasonal peaking requirements through seasonal exchanges, demand-side management, capacity tolling contracts, and combustion turbine development.
PGE filed a supplement to the Plan on February 28, 2003. The OPUC has initiated a schedule for input and review, with an acknowledgement of the Company's Plan, as supplemented, anticipated by mid-2003. PGE then anticipates issuing a request for proposals (RFP) to acquire energy and capacity resources. The Company will continue to evaluate its options with regard to the construction of additional generation, including a 650-MW gas turbine plant adjacent to it's Beaver plant site (Port Westward Generating Project), considering the availability of reasonably priced medium to long-term power purchases from the market. PGE will continue to monitor changes in economic conditions and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers.
Based upon results of the RFP process, PGE will update its action plan with specific resource recommendations and request acknowledgement that the Company's final action plan is consistent with least cost planning principles established by the OPUC.
Receivables - California Wholesale Market
As of March 31, 2003, PGE has net accounts receivable balances totaling approximately $62 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).
On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code.
PGE is pursuing collection of all past due amounts through the PX and PG&E bankruptcy proceeding and has filed a proof of claim in each of the proceedings. Management continues to assess PGE's exposure relative to its California receivables and has established reserves of $29 million related to this receivable amount, including $11.5 million recorded in the first quarter of 2003. The Company is examining numerous options, including legal, regulatory, and other means to pursue collection of any amounts ultimately not received through the bankruptcy process. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables.
Management believes that the outcome of this matter will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.
Refunds on Wholesale Transactions
California
In a June 19, 2001 order adopting a price mitigation program for 11 states within the WECC area, the FERC referred to a settlement judge the issue of refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and the PX.
On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering an evidentiary hearing proceeding to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Hearings were held in February and March 2002 to determine the appropriate proxy prices to use and which sales were exempt from refunds because they had been made pursuant to orders of the Department of Energy. Further hearings were held in August through October, 2002, to determine the method of calculation of amounts owed to, and refunds owed by, sellers into the California market.
On August 13, 2002, the FERC staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in the Company's potential refund obligation. The FERC asked for comments on the staff's recommendation, and on October 15, 2002, PGE, along with several other utilities, filed comments with the FERC objecting to the FERC staff's recommendations. Subsequent to the issuance of the FERC's August 13, 2002 report, several companies disclosed that some of their gas traders reported incorrect prices to the firms that report gas indices. In addition, on September 23, 2002, a FERC administrative law judge issued an order in a complaint case against El Paso Natural Gas Company, finding that El Paso had manipulated the gas market by withholding capacity. Also, in October 2002, a former Vice President and Managing Director of Enron's West Power Trading Division entered a g uilty plea to conspiracy to commit wire fraud in connection with California's energy market.
In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds. Although no final dollar amounts were included in the certification, the recommended methodology indicated a potential refund by PGE of $20 million to $30 million.
Appeals of the FERC orders establishing the refund methodology have been filed and are pending in the Ninth Circuit Federal Court of Appeals. On August 21, 2002 the Ninth Circuit issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation. In compliance with this order, the FERC authorized all parties to conduct further inquiry and to submit additional evidence of market manipulation. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.
On March 3, 2003, numerous parties filed documents addressing possible market manipulation. The most comprehensive filings were by the California parties. In addition to alleging that the markets were manipulated and that the refund cases should thus be expanded, they alleged that numerous sellers, including PGE, participated in various strategies that affected the market adversely. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of the California parties.
On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge, issued in December 2002, but modifying the methodology it had previously ordered for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates that the new methodology could increase the amount of the potential refunds by approximately $20 million. Although further proceedings will be necessary to determine exactly how the new methodology will affect the refund liability, the Company now estimates its potential liability to be between $20 million and $50 million.
PGE does not agree with several aspects of the FERC's methodology for determining potential refunds. On April 25, 2003, PGE joined a group of utilities in filing a request for rehearing of various aspects of the March 26, 2003 order, including the repricing of the gas cost component of the proxy price from which refunds are to be calculated.
Pacific Northwest
In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action.
In December 2002, the FERC re-opened this case to allow parties to conduct further discovery. In coordination with the order in the California refund case (described above), the FERC authorized all parties to conduct further inquiry and to submit additional evidence. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.
On March 3, 2003, numerous parties filed documents addressing possible market manipulation. The most comprehensive filings were by the City of Tacoma. In addition to alleging that the markets were manipulated and that the refund cases should thus be expanded, they alleged that numerous sellers, including PGE, participated in various strategies that adversely affected the market. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of these parties.
On March 26, 2003, the FERC indicated that it might issue an order to remand the case for a determination of refunds. The remand could include the appointment of a settlement judge or additional hearings to determine refund amounts, if any. At this time, the Company does not know what the order may require or what sanctions may be sought.
Potential Refund Mitigation
The FERC has indicated that any refunds PGE may be required to pay related to California sales can be offset by accounts receivable related to sales in California (as discussed in Note 5, Receivables - California Wholesale Market). As indicated in Note 5, PGE has established reserves of $29 million related to the receivable amount. The FERC has also indicated that interest on both refunds and offsetting accounts receivable will be computed from the effective dates of the applicable transactions; such interest has not yet been recorded by the Company.
In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism in effect at the time. This could further mitigate the financial effect of any refunds made or received by the Company.
Management cannot predict the ultimate outcome of these matters. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.
Show Cause Order
Pursuant to the FERC Staff's Final Report on Price Manipulation in Western Markets, issued in Docket No. PA02-2-000, the FERC indicated, in a press release issued on March 26, 2003, that it intends to issue orders to PGE and 36 other entities that participated in the California wholesale market in 2000 and 2001, requiring that each entity show cause why their behaviors during that time period did not constitute gaming in violation of tariffs issued by the California Independent System Operator (ISO) and the California Power Exchange (PX). The FERC indicated that possible sanctions for any entity found to have violated the tariffs include disgorging unjust profits associated with the violations, or other appropriate remedies. Based on its internal investigations to date, PGE does not believe that it violated ISO or PX tariff provisions.
Wholesale Price Mitigation
In June 2001, the FERC adopted a price mitigation program for the power system serving 11 Western states, adopting a new benchmark formula limiting prices for electricity sold in the spot markets at all times throughout the region through September 2002. The program applied to power generators, marketers, and investor-owned utilities under FERC jurisdiction, as well as public power providers, municipal utilities, and electric cooperatives that use FERC-regulated transmission lines.
Under the program, a ceiling price was set by FERC for wholesale electricity sold in the spot market coordinated by the California Independent System Operator (ISO) and in markets in the other Western states. Such price, initially set at $91.87/MWh, reflected specified fuel, operations, and maintenance costs, and was based upon the bid submitted by the highest cost gas-fired generating unit supplying power during a Stage 1 supply emergency.
In December 2001, the FERC temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the ISO, recognizing differences between Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. The changes, including a ceiling price of $108/MWh, were in effect until May 1, 2002, at which time the previous methodology and ceiling price again became effective.
In July 2002, the FERC raised the ceiling price on Western wholesale electricity prices from $91.87/MWh to $250/MWh, effective October 31, 2002. The new ceiling price applies to all sales of electricity in the WECC. In addition to the new price ceiling, the FERC order established conditions and rules guiding participation in Western wholesale electricity markets, including automatic price mitigation procedures to be implemented during periods of tight supplies.
Federal Investigations - Wholesale Power Markets
On February 13, 2002, the FERC initiated a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. On March 5, 2002, all sellers with wholesale sales in the U.S. portion of the WECC were directed to provide certain historical and projected information for all energy transactions in calendar years 2000 and 2001. In April 2002, the Company submitted the requested information. Additionally, on March 15, 2002 the FERC enforcement staff issued a subpoena to Enron, which Enron then forwarded to the Company. In response to this subpoena, the Company provided information related to its trading organization, its trading policies and procedures, its price curves and their derivation, and its trading position reports.
As a result of an internal investigation, PGE discovered that it had failed to properly post on a public web site information about some of its energy transactions with an affiliate, Enron Power Marketing, Inc. The preliminary results of this investigation were disclosed to FERC Staff on April 15, 2002 and final results on August 1, 2002. This issue was subsequently included in the investigation in Docket No. EL02-114-000 described below.
Enron Trading Strategies
In early May 2002, Enron provided memos to the FERC that contained information indicating that Enron, through its subsidiary Enron Power Marketing, Inc. (EPMI), may have engaged in several types of trading strategies that raised questions regarding potential manipulation of electricity and natural gas prices in California in 2000-2001. On May 8, 2002, the FERC ordered all sellers of wholesale electricity or ancillary services into the California markets during 2000-2001 to respond to the FERC whether they engaged in any transactions falling within any of the enumerated types of trading strategies, and, if they did, to provide information about the transactions. Although PGE was not specifically named in the FERC order, on May 22, 2002, PGE voluntarily submitted the results of its investigation to the FERC. The material submitted to FERC did not show any instances where the Company engaged in or knowingly aided deceptive or misleading trading strategies. However, PGE reported that i t was among other intermediaries in a series of trading activities that occurred on 15 days from April through June 2000 where EPMI was found to be at both ends of the transaction chain. The trading transactions identified during the 15-day period moved about 2,300 megawatt hours (0.12%) of the total 2 million megawatt hours traded by PGE on those days, and about 0.02% of the total 13 million megawatt hours traded by PGE during the three-month period. The services provided by PGE may have been used by EPMI as a step in one of the enumerated strategies. In addition, it is conceivable that in the normal course of business, PGE could have provided services to third parties that may have resulted in PGE being used, unknowingly, as an intermediary in partial execution of one or more of the enumerated strategies.
On June 4, 2002, the FERC issued an order to PGE and three other companies to show cause why their authority to charge market-based rates should not be revoked. The order stated that the companies' responses to the FERC's May 8, 2002 data request (discussed above) are indicative of a failure to cooperate with its investigation. On June 14, 2002, PGE filed a response indicating that a thorough review of Company documents again found no evidence of deception or market manipulation by PGE. PGE believes that it has fully cooperated with the FERC's inquiry.
On August 13, 2002, the FERC issued two orders initiating investigations into instances of possible misconduct by PGE and certain other companies. In the first order (Docket No. EL02-114-000), the FERC ordered investigation of PGE and EPMI related to possible violations of their codes of conduct, the FERC's standards of conduct, and the companies' market-based rate tariffs, and whether PGE has cooperated by providing all relevant information related to the FERC's May 8, 2002 data request and June 4 Show Cause Order. In the second order (Docket No. EL02-115-000), the FERC ordered investigation of Avista Corporation and Avista Energy, Inc. (collectively, Avista) with respect to, among other things, transactions in which Avista engaged in or facilitated the trading strategies identified in the Enron memoranda or acted as a middleman with respect to sales of electric energy between PGE and EPMI. PGE and EPMI are included as parties in that Docket. In the orders, the FERC established Octobe r 15, 2002 as the "refund effective date." Issues involving PGE and EPMI in Docket No. EL02-115-000 have now been consolidated into Docket No. EL02-114-000. If PGE were to lose its market-based rate authority, purchasers of electric energy from PGE at market-based rates after the refund effective date could be entitled to a refund of the difference between the market-based rates and cost-based rates deemed just and reasonable by the FERC.
On December 10, 2002, the FERC trial staff released a Revised Statement of Asserted Violations (Revised Statement) and its initial testimony in its investigation of PGE (Docket No. EL02-114-000). The assertions in the Revised Statement and testimony are limited to PGE's self-reported failure to properly post information about some of its energy transactions with EPMI, and alleged violations for affiliate dealings with EPMI relating to a series of transactions that occurred on certain days in April-June 2000, involving PGE, EPMI, and Avista Corporation. The latter transactions were previously reported by PGE to FERC on May 22, 2002 in response to the FERC's May 8, 2002 data request. The trial staff recommended a remedy of revocation of PGE's market-based rate authority for two years, and a requirement that PGE's application for reinstatement of market-based rates include documentation supporting revised procedures to ensure that posting errors and violations of affiliate rules do not occu r again. The City of Tacoma, Washington filed testimony seeking a refund from PGE of $3.2 million. The California Attorney General and the California Public Utilities Commission (California Parties) have filed testimony that PGE should refund amounts to compensate market participants for PGE's alleged unlawful conduct, but the testimony specifies no amount of refunds.
PGE's initial response testimony in Docket No. EL02-114-000 was filed on February 24, 2003. In its testimony, PGE describes the posting errors it self-reported, most of which were technical in nature and may in fact not have been in error. The Company also described the cooperation it has extended to the FERC, the investigative staff, and the trial staff in providing all requested information to aid the investigation. PGE also provided testimony that the April-June 2000 transactions with EPMI did not involve violations of affiliate rules, except for certain posting errors.
The hearing in Docket No. EL02-114-000 is scheduled to begin on June 2, 2003, with an initial decision from the presiding FERC judge scheduled for July 17, 2003. The procedural schedule in Docket No. EL02-115-000 is currently suspended pending further revisions to a settlement proposal submitted between Avista and FERC trial staff.
PGE will continue to cooperate with the investigations. PGE continues to believe that it has fully complied with the FERC investigation initiated on February 13, 2002, and that it has not engaged in deception or market manipulation.
Wash Sales - Electricity
On May 21, 2002, the FERC issued a data request and request for admissions to all sellers of wholesale electricity and/or ancillary services in the U.S. portion of the WECC during the years 2000-2001. Such request ordered sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. Although PGE was not listed in the data request, PGE conducted an investigation and submitted the results in a response to the FERC on May 31, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request to the extent that such activities artificially inflated trading volumes, revenues or market prices. PGE's response also noted that it had no reason or incentive to artificially inflate trading volumes or revenues, as the primary purpose of its wholesale trading operations is to manage risk and reduce costs for its retail customers by balancing load requirements and maximizing the value of owned generat ion and purchase contracts to the extent that available supply exceeds the needs of the Company's firm customers.
Wash Sales - Natural Gas
On May 22, 2002, the FERC issued a data request and request for admissions to all sellers of natural gas in the U.S. portion of the WECC and in Texas during the years 2000-2001. Such request ordered such sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. PGE conducted an investigation and submitted the results in a response to the FERC on June 5, 2002. PGE denies that it engaged in trading activities described in the FERC data request.
Challenge of the California Attorney General to Market-Based Rates
On March 20, 2002, the California Attorney General filed a complaint with FERC against various sellers in the wholesale power market, alleging that the FERC's market-based rates violate the Federal Power Act ("FPA"), and, even if market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to refile their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of Appeals.
Other
On June 17, 2002, the U.S. Commodity Futures Trading Commission (CFTC), which regulates futures contracts traded on U.S. exchanges, subpoenaed documents from PGE regarding the Company's electricity and natural gas trading, including any "wash" trading used to inflate revenue and trading volume. PGE forwarded documents previously prepared for the FERC investigation (described above). In addition, PGE has been requested to provide information and documents with respect to various federal and state actions and investigations of Enron. PGE will continue to cooperate to the fullest extent with these investigations.
Antitrust Litigation
In late 2001, numerous individuals, businesses, and California cities, counties, and other governmental entities filed a consolidated Master Complaint in their class action law suits (Wholesale Electricity Antitrust Cases) against various individuals, utilities, generators, traders, and other entities, including Duke Energy Trading and Marketing, LLC; Duke Energy Morro Bay, LLC; Duke Energy Moss Landing, LLC; Duke Energy South Bay, LLC and Duke Energy Oakland, LLC (Duke Parties) and Reliant Energy Services, Inc.; Reliant Ormond Beach, Inc.; Reliant Energy Etiwanda, Inc.; Reliant Energy Ellwood, Inc.; Reliant Energy Mandalay, Inc. and Reliant Energy Coolwater, Inc. (Reliant Parties), alleging that activities related to the purchase and sale of electricity in California in 2000 and 2001 violated California antitrust and unfair competition laws. The complaint seeks, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, inte rest, and penalties.
The Duke Parties filed a cross complaint against PGE and other utilities, generators, traders and other entities not named in the Wholesale Electricity Antitrust Cases, alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose on the Duke Parties under the Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. The Reliant Parties have filed a cross complaint against PGE and the other utilities, generators, traders and other entities similar to the cross complaint filed by the Duke Parties. The cases were remanded to Federal Court by certain parties. The parties have stipulated to place the cross complaints in abeyance until 30 days after a ruling on the motions to dismiss the Master Complaint.
On December 13, 2002, a United States District Court signed an order granting the plaintiff's motions to remand the cases to the California state court, but the order was not immediately implemented. The Duke and Reliant Parties filed an appeal to the United States Ninth Circuit Court of Appeals and applied to the District Court for a stay of the remand to the California state court. On January 24, 2003, the District Court denied the application for a stay and set for hearing certain motions for reconsideration. On February 20, 2003, the United States Court of Appeals for the Ninth Circuit issued an Order deciding it had jurisdiction to hear the appeals from the District Court's December 13, 2002 remand order. The Ninth Circuit also issued a stay of the remand order pending the outcome of the appeals and set a briefing schedule that will not be completed until mid-September 2003. As stated above, the cross complaint against PGE will be continued in abeyance until 30 days after a ruling is entered on the motions to dismiss the Master Complaint.
At this time, management is unable to make any assessment of, or determination with respect to, these complaints.
California Attorney General Complaint
In May 2002, the Attorney General of California filed a complaint in state court alleging failure of PGE to comply with the Federal Power Act (FPA) and with the FERC requirements for its market based sales of power in California. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price" or a reasonable price and for each alleged regulatory violation. No specific damage claim is stated. In July 2002, PGE filed a Notice of Removal to U.S. District Court and a Motion to Dismiss on preemptive grounds. The Attorney General moved to remand to state court, which was denied. The Attorney General filed an appeal to the Ninth Circuit Court of Appeals of the denial of the motion to remand, and moved to stay action in the District Court pending the outcome of the appeal. The District Court, finding the appeal frivolous, refused to stay the case. Motions to dismiss the case were argued on Septembe r 26, 2002. On March 25, 2003, the judge dismissed the complaint against PGE. On March 28, 2003, the Attorney General filed a Notice of Appeal with the Ninth Circuit.
Oregon Public Utility Commission Staff Report on Trading Activities
On April 29, 2003, the Staff of the OPUC issued a draft report entitled "Trading Activities by Portland General Electric, PacifiCorp, and Idaho Power Company during the Western Electricity Crisis of 2000-01: Did They Violate Any Oregon Statutes, Rules, or Orders" (Draft Report).
In the Draft Report, the Staff makes two recommendations applicable to PGE: First, that the OPUC affirm that it will hold harmless the customers of PGE, PacifiCorp, and Idaho Power (the Utilities) in the event any penalties are imposed by the FERC or any other authority investigating the trading activities of the Utilities. Second, that the OPUC open a formal investigation of PGE's trading activity in 2000-01. The Staff recommended a two-stage proceeding, with the first stage to address whether PGE mismanaged its trading activities during that period. In the event that the OPUC determined that PGE mismanaged its trading activities, the second stage would address the appropriate relief.
In addition, the Staff recommended that the OPUC delay any decision on an investigation of whether PGE engaged in misconduct with respect to its trading activities until after the FERC issues its decision in its proceeding related to the possible violation by PGE of PGE's code of conduct, the FERC's standards of conduct, and PGE's market-based rate tariffs (Docket No. EL02-114-000). For further information, see "Federal Investigations - Wholesale Power Markets" and "Show Cause Order".
With respect to possible misconduct, the Staff stated that there has been no ruling that any trading activities by PGE broke any federal laws or requirements, and that the effect on the wholesale market of PGE's trading activities currently under investigation by the FERC apparently was small. With respect to possible mismanagement, the Staff stated that it believes that there is a prima facie case that PGE mismanaged certain of its trading activities withan affiliate, EPMI, but acknowledged the case is "not open and shut."
The Draft Report included two other options to the Staff's recommendation. The first option would be to commence a proceeding to determine whether PGE engaged in misconduct and/or mismanagement, with a second proceeding, if needed, to determine what relief, if any, is appropriate. The other option would be to delay any investigation until after the FERC has completed its proceedings.
The Staff requested written comments on the Draft Report by May 21, 2003. The Staff intends to issue its final report in early June 2003 and present its recommendation to the OPUC at that time.
Management does not believe that PGE engaged in any misconduct. In addition, although PGE self-reported to the FERC more than a year ago the failure to post information about certain energy transactions with EPMI, management does not believe that PGE's trading activities with EPMI rise to the level of mismanagement suggested by the Staff. Management cannot at this time predict if the OPUC will conduct an investigation or the possible outcome if an investigation is commenced. However, it believes this matter will not have a material adverse impact on the financial condition or results of operations of the Company.
Trojan Investment Recovery
Due to the closure of the Trojan Nuclear Plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals, and regulatory actions have taken place. As a result of a settlement agreement that was implemented in 2000, the recovery of the Trojan plant investment is no longer included in rates charged to customers. The Company continues to collect for costs related to the decommissioning of the plant.
Although management cannot predict the ultimate outcome of the related legal challenges, it believes that they will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for a future reporting period. For further information, see Note 3, Legal and Environmental Matters, in the Notes to Financial Statements.
Union Grievances
Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. For further information, see Note 3, Legal and Environmental Matters, in the Notes to Financial Statements.
Environmental Matter
A 1997 investigation of a 5.5-mile segment of the Willamette River known as the Portland Harbor, conducted by the EPA, revealed significant contamination of sediments within the harbor. Based upon analytical results of the investigation, the EPA included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) in 2000.
In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the Portland Harbor sediments. In May 2000, the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (the Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement.
In December 2000, PGE received from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. The notice included a "Portland Harbor Initial General Notice List" containing sixty-eight other companies that the EPA believes may be Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.
In accordance with the Voluntary Agreement, in March 2001, PGE submitted a final investigation plan to the DEQ for approval. DEQ approved the plan and in June 2001 PGE performed initial investigations and remedial activities based upon the approved investigation plan. The investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.
In February 2002, PGE submitted a final investigation report to the DEQ summarizing its investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.
The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign, nor has it signed, such an order. Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE.
Management believes that the Company's contribution to the sediment contamination, if any, would qualify it as a de minimis Potentially Responsible Party. Nonetheless, management cannot predict the ultimate outcome of this matter or estimate any potential loss.
Colstrip Project Litigation
On May 5, 2003, Robert & Julie Remington and forty-eight other individuals, unions and businesses filed a suit against PGE and the other owners, designers and operators of the Colstrip coal-fired electric generation plants (Colstrip Project) in Montana alleging that holding and settling ponds at the Colstrip Project have leaked and contaminated groundwater. The plaintiffs allege nuisance, trespass, unjust enrichment, fraud, and negligence, and seek a declaratory judgment of nuisance and trespass, an order that the nuisance be abated, and an unspecified amount for damages, disgorgement of profits, and punitive damages.
Public Utility Holding Company Act of 1935
All of the common stock of PGE is owned by Enron. As the owner of PGE's common stock, Enron is a holding company for purposes of PUHCA. Following Enron's acquisition of PGE in 1997, Enron annually filed on Form U-3A-2 for an exemption from all provisions of PUHCA (except Section 9(a)(2) thereof) under Section 3(a)(1), in accordance with Rule 2 promulgated thereunder. Due to Enron's bankruptcy filing in December 2001, Enron is no longer able to provide necessary financial information needed to file on Form U-3A-2. As a result, in February 2002, Enron filed an application on Form U-1 seeking exemption under Section 3(a)(1). To be eligible for the Section 3(a)(1) exemption it is necessary, among other things, that PGE's utility activities be predominantly intrastate in character.
Following the submission of testimony by the parties to the proceeding, a hearing on Enron's application was held on December 5, 2002. On February 6, 2003, the administrative law judge issued an Initial Decision holding that PGE does not meet the criteria to be predominantly intrastate in character, and denying Enron's application for exemption under 3(a)(1). On February 27, 2003, Enron filed a Petition for Review with the SEC requesting that the SEC review the administrative law judge's Initial Decision, reverse such Initial Decision, and find that Enron is entitled to exemption from PUHCA. Filing of the Petition for Review stays the effect of the Initial Decision until such time as the SEC may act on the Petition for Review. The SEC could act on the Petition for Review at any time. Possible responses of the SEC to the Petition for Review include setting the matter down for further hearings before the full Commission or summarily affirming the Initial Decision. In the event that the Initial Decision is affirmed by the SEC, either summarily or after further hearings, Enron could be required to register as a holding company under PUHCA and PGE would become a subsidiary of a registered holding company.
PUHCA imposes a number of restrictions on the operations of a registered holding company and its subsidiaries, including SEC approval of securities issuances (including those by utility subsidiaries that have not been authorized by the relevant state utility commissions) and engaging directly or indirectly in non-utility businesses. PUHCA also regulates transactions between the affiliates within the holding company system, including the provision of services by holding company affiliates to the system's utilities. If PGE were to become a subsidiary of a registered holding company, it would become subject to regulation by the SEC not only with respect to the acquisition of the securities of other public utilities, but also with respect to, among other things, payment of dividends out of capital and surplus, certain affiliate transactions, issuance of securities, and the acquisition of assets and interests in any other business.
Although PGE is unable to predict whether Enron will retain its status as an exempt holding company, PGE does not believe that becoming a subsidiary of a registered holding company would have a material adverse affect on its financial condition or results of operations. However, the finding that PGE is not an intrastate utility could make it more difficult for any future owner of PGE to obtain a 3(a)(1) exemption from PUHCA.
Information Regarding Forward-Looking Statements
This report contains statements that are forward-looking within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements of expectations, beliefs, plans, objectives, assumptions or future events or performance. Words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," or similar expressions identify forward-looking statements.
Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs and projections are expressed in good faith and are believed by PGE, as applicable, to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that PGE's expectations, beliefs or projections will be achieved or accomplished.
In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include: