ITEM 2. MANAGEMENT's DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION

San Francisco-based PG&E Corporation provides integrated energy services.

PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation and its various business lines:
-Pacific Gas and Electric Company (Utility) -Unregulated Business Operations consisting of:
- Gas Transmission through PG&E Gas Transmission;
- Electric Generation through U.S. Generating Company (USGen);
- Energy Commodities and Services through PG&E Energy Trading and PG&E Energy Services.

In this MD&A, we explain the results of operations for the three- and nine-month periods ended September 30, 1998, as compared to the corresponding periods in 1997, and discuss our financial condition. Our discussion of financial condition includes:
- changes in the energy industry and how we expect these changes to influence future results of operations;
- liquidity and capital resources, including discussions of capital financing activities, and uncertainties that could affect future results; and
- risk management activities.

This Quarterly Report Form 10-Q, including our discussion of results of operations and financial condition below, contains forward-looking statements that involve risks and uncertainties. These statements are based on the beliefs and assumptions of management and on information currently available to management. Words such as "estimates," "expects," "anticipates," "plans," "believes," and similar expressions identify forward-looking statements involving risks and uncertainties. Actual results may differ materially from those expressed in the forward-looking statements.

The most important factor that could affect future results and that would cause actual results to differ materially from those expressed in the forward looking statements, or from historical results, is the outcome and potential impact of Proposition 9. If the voters approve and the courts uphold Proposition 9, then Proposition 9 would overturn major provisions of California's electric industry restructuring legislation. Other important factors include, but are not limited to: (1) the ongoing restructuring of the electric and gas industries in California and nationally; (2) the outcome of the regulatory proceedings related to the restructuring; (3) the Utility's ability to collect revenues sufficient to recover transition costs in accordance with its transition cost recovery plan, specifically in light of Proposition 9; (4) the planned sale of the Utility-owned fossil-fueled electric generating plants, which may be altered if the voters approve Proposition 9; (5) the impact of, and our ability to successfully integrate, our acquisitions, including the New England Electric System (NEES) and the Texas assets; (6) the potential impact from internal or external Year 2000 problems; (7) the outcome of the Utility's Cost of Capital proceeding; (8) approval of the Utility's 1999 General Rate Case application providing the Utility the opportunity to earn its authorized rate of return; (9) increased competition; (10) our ability to expand into and to compete successfully in new markets as the passage of Proposition 9 may stall electric industry restructuring nationally; and (11) fluctuations in the prices of commodity gas and electricity and our ability to successfully hedge against such price risk. We discuss each of these items in greater detail below.

RESULTS OF OPERATIONS

In this section, we provide the components of our earnings for the three- and nine-month periods ended September 30, 1998, and 1997. We then explain why operating revenues and expenses varied from 1998 to 1997.

The following table shows results of operations for the three- and nine- month periods ended September 30, 1998, and 1997, and total assets at September 30, 1998, and 1997. The results for unregulated business operations include the Corporation on a stand-alone basis.

(in millions)
                                         Unregulated
                                           Business     Elimin-
                                Utility   Operations    ations     Total
                               --------   ------------  -------   -------
For the three months ended
September 30,
1998
Operating revenues             $ 2,563      $ 2,930    $ (186)   $ 5,307
Operating expenses               2,037        2,914      (186)     4,765
                               -------      -------     ------   -------
Operating income                   526           16         -        542
Income available for
      common stock                 199           11         -        210

1997
Operating revenues             $ 2,541      $ 1,565     $ (43)   $ 4,063
Operating expenses               1,915        1,563       (43)     3,435
                               -------      -------     -------  -------
Operating income                   626            2         -        628
Income available for
      common stock                 269          (12)        -        257

For the nine months ended
September 30,
1998
Operating revenues             $ 6,706      $ 8,263    $ (522)   $14,447
Operating expenses               5,257        8,145      (522)    12,880
                               -------      -------     ------   -------
Operating income                 1,449          118         -      1,567
Income available for
      common stock                 533          (10)        -        523
Total assets at September 30   $22,468      $ 9,577    $ (347)   $31,698

1997
Operating revenues             $ 7,094      $ 3,485    $  (68)   $10,511
Operating expenses               5,653        3,463       (68)     9,048
                               -------      -------     -------  -------
Operating income                 1,441           22         -      1,463
Income available for
      common stock                 554           68         -        622
Total assets at September 30   $23,895      $ 5,903    $ (383)   $29,415

The California Public Utility Commission (CPUC) requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay the Corporation. At September 30, 1998, the Utility was in compliance with its CPUC-authorized capital structure. The Utility believes that it will continue to meet this condition in the future without affecting the Corporation's ability to pay common stock dividends. However, if the voters approve and the courts uphold Proposition 9, then the Utility would be required to write off generation-related regulatory assets. Such a loss would severely impair the Corporation's ability to pay dividends to its common shareholders.

Utility operating expenses increased $122 million for the three-month period and decreased $396 million for the nine-month period ended September 30, 1998, as compared to the same periods in 1997. Operating expenses for the nine-month period ended September 30, 1998, declined primarily as a result of; (1) decreased fuel costs at power plants, primarily due to plant sales; (2) decreased costs associated with Qualifying Facilities (QFs) due to the expiration of the fixed price periods in many QF contracts; (3) lower transmission pipeline demand charges; and (4) expense deferrals related to electric industry restructuring. Increased expenses incurred for system reliability and accelerated amortization of regulatory assets recovered under the transition plan established by the restructuring legislation partially offset these decreases. As previously indicated, electric industry restructuring provides for recovery of certain costs in future periods. Some costs, associated with the expense deferrals mentioned above, will be recovered as electric sales volumes increase during seasonal fluctuations. Others relate to transition costs, which will be recovered over the term of the rate reduction bonds.

Unregulated business operations contributed $23 million more in net income for the three-month period ended September 30, 1998, than in the same period in 1997, and $78 million less in net income in the nine-month period ended September 30, 1998, than in the same periods in 1997. The decrease for the nine-month period ended September 30, 1998, is due to the loss on sale of our Australian holdings (See Acquisitions and Sales, below.) The decrease was also due to the $110 million gain that the Corporation recognized in the second quarter 1997 on the sale of its interest in International Generating Company, Ltd. The second quarter 1997 gain was partially offset by write-downs of certain unregulated investments of approximately $41 million.

FINANCIAL CONDITION

We begin this section by discussing the energy industry. We also discuss how we are responding to restructuring on a national level, including a recent acquisition. We then discuss liquidity and capital resources and our risk management activities.

COMPETITION AND CHANGING REGULATORY ENVIRONMENT:

The Utility Electric Generation Business:

On March 31, 1998, California became one of the first states in the country to allow open competition in the electric generation business. Today, many Californians may choose an energy service provider, which will provide their electric power generation. The Utility's customers may choose to purchase electricity: (1) from the Utility; (2) from retail electricity providers (for example, marketers including our energy service subsidiary, brokers, and aggregators); or (3) directly from unregulated power generators. Our Utility expects to continue to provide distribution services to substantially all electric consumers within its service territory.

(QFs) and Diablo Canyon. These resources for operational or reliability reasons are considered "must-take" units and operate under cost-of-service contracts. After scheduling must-take resources, the ISO satisfies the remaining aggregate demand with purchases from the PX and purchases of necessary generation and ancillary services to maintain grid reliability. To meet the ISO's demand, the PX accepts the lowest bids from competing electric providers, which establishes a market price. Customers choosing to buy power directly from non-regulated generators or retailers will pay for that generation based upon negotiated contracts.

CPUC regulation requires the Utility to sell all of its generated electric power and must-take electric power purchased from external power producers to the PX. The Utility must then purchase all electric power for its retail customers from the PX. For the three- and nine-month periods ended September 30, 1998, the Cost of energy for utility, reflected on the Statement of Consolidated Income, is comprised of the cost of PX purchases, ancillary services purchased from the ISO, and the cost of Utility generation, net of sales to the PX (in millions) as follows:

                                For the three-      For the nine-
                                months ended        months ended
                                September 30, 1998  September 30, 1998
                                ------------------  ------------------

Cost of electric generation          576               1,566
Cost of purchases from the PX        379                 489
Net cost of ancillary services       130                 169
Proceeds from sales to the PX       (422)               (608)
                                   ------              ------
Cost of electric energy              663               1,616
Utility cost of gas                   51                 333
                                   ------              ------
Cost of energy for Utility           714               1,949

In developing state legislation to implement a competitive market, involved parties believed that our Utility's market-based revenues would not be sufficient to recover (that is, to collect from customers) all generation costs. Many of these costs resulted from past CPUC decisions. To recover these uneconomic costs, called transition costs, and to ensure a smooth transition to the competitive environment, a transition plan was developed in the form of state legislation to position California for the new market environment. The California Legislature passed the legislation and the Governor signed it in 1996. As discussed below in California Voter Initiative, on November 3, 1998, Californians will vote on Proposition 9, which would overturn major portions of the current electric utility restructuring legislation and would have a material adverse impact on the Utility and the Corporation.

There are two principal elements of the transition plan established by restructuring legislation: (1) an electric rate freeze and rate reduction; and (2) recovery of transition costs. Both of these elements, and the impact of the approved transition plan on our Utility's customers, are discussed below. The restructuring legislation transition period ends December 31, 2001. At the conclusion of the transition period, we will be at risk to recover any of our Utility's remaining generation costs through market-based revenues.

As authorized by the restructuring legislation, to pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion of its transition costs with rate reduction bonds, which have maturities ranging from three months to ten years. The bonds defer recovery of a portion of the transition costs until after the transition period. Pending the outcome of Proposition 9, the Utility expects to recover the transition costs associated with the rate reduction bonds over the term of the bonds.

The costs of Utility-owned generation facilities currently are included in the Utility customers' rates. Above-market facility costs result when book value is in excess of market value. Conversely, below-market facility costs result when market value is in excess of book value. The total amount of generation facility costs to be included as transition costs will be based on the aggregate of above-market and below-market values. The above- market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. A valuation of a Utility-owned generation facility where the market value exceeds the book value could result in a material charge if the valuation of the facility is determined based upon any method other than a sale of the facility to a third party. This is because any excess of market value over book value would be used to reduce other transition costs, without increasing the book value of the plant assets.

The Utility will not be able to determine the exact amount of generation facility costs that will be recoverable as transition costs until a market valuation process (appraisal or sale) is completed for each of the Utility's generation facilities. The first of these valuations occurred on July 1, 1998, when the Utility sold three Utility-owned electric generation plants for $501 million. (See Utility Generation Divestiture, below.) For generation facilities that the Utility has not divested, the CPUC will approve the methodology to be used in the market valuation process.

The above-market portion of costs associated with the Utility's long-term contracts to purchase power at above-market prices from QFs and other power suppliers also are eligible to be recovered as transition costs. The Utility has agreed to purchase electric power from these suppliers under long-term contracts expiring on various dates through 2028. Over the life of these contracts, the Utility estimates that it will purchase approximately 345 million megawatt-hours at an aggregate average price of

6.5 cents per kilowatt-hour. To the extent that this price is above the market price, the Utility expects to collect the difference between the contract price and the market price from customers, as a transition cost, over the terms of the contracts.

Generation-related regulatory assets, net of regulatory obligations, also are eligible for transition cost recovery. As of September 30, 1998, the Utility has accumulated approximately $6.0 billion of these assets net of certain obligations, including the amounts reclassified from Property, plant, and equipment, discussed in Utility Generation Impairment below.

The restructuring legislation specifies that the Utility must recover most transition costs by December 31, 2001. This recovery period is significantly shorter than the recovery period of the related assets prior to restructuring. Effective January 1, 1998, as authorized by the CPUC in consideration of the restructuring legislation, the Utility is recording amortization of most generation-related regulatory assets over the transition period. The CPUC believes that the shortened recovery period reduces risks associated with recovery of all the Utility's generation assets, including Diablo Canyon and hydroelectric facilities. Accordingly, the Utility is receiving a reduced return for all of its Utility-owned generation facilities. In 1998, the reduced return on common equity for these facilities is 6.77 percent.

Although the Utility must recover most transition costs by December 31, 2001, certain transition costs may be included in customers' electric rates after the transition period. These costs include: (1) certain employee- related transition costs; (2) above-market payments under existing QF and power-purchase contracts discussed above; and (3) unrecovered electric industry restructuring implementation costs. In addition, transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds through the collection of the Fixed Transition Amount (FTA) charge from customers. Further, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission Diablo Canyon and Humboldt Nuclear Power Plants. During the rate freeze, the FTA and nuclear decommissioning charges will not increase the Utility customers' electric rates. Excluding these specific items, the Utility will write off any transition costs not recovered during the transition period.

Effective January 1, 1998, the Utility has been collecting eligible transition costs through a CPUC-authorized nonbypassable charge called the competition transition charge (CTC). The amount of revenue collected from frozen rates for recovery of transition costs is subject to seasonal fluctuations in the Utility's sales volumes. Revenues available for the purpose of recovering transition costs exceeded transition cost expense for the three-month period ended September 30, 1998, by $154 million. During the nine-month period ended September 30, 1998, transition cost expense exceeded associated revenues available for recovery of transition costs by $349 million. In accordance with CPUC rate treatment of transition costs, the Utility deferred this excess as a regulatory asset. The Utility expects to recover this regulatory asset during the remainder of the transition period.

During the transition period, the CPUC will review the accounting methods used by the Utility to recover transition costs and the amount of transition costs requested for recovery. The CPUC is currently reviewing non-nuclear transition costs amortized in the first half of 1998. The Utility expects the CPUC to issue decisions regarding these reviews in the second quarter of 1999. At this time, the amount of transition cost disallowances, if any, cannot be predicted.

In addition, on August 31, 1998, an independent accounting firm retained by the CPUC completed its financial verification audit of the Utility's Diablo Canyon plant accounts at December 31, 1996. The audit resulted in

the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. (Sunk costs are costs associated with Utility- owned generating facilities that are fixed and unavoidable and currently included in the Utility customers' electric rates.) The independent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, which questioned $200 million of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to Diablo Canyon's recoverable costs, which resulted from the report. At this time, the amount of transition cost disallowances, if any, cannot be predicted.

The Utility's ability to recover its transition costs during the transition period will be dependent on several factors. The primary factor is whether voters approve and the courts uphold Proposition 9, which would eliminate transition cost recovery with certain exceptions. If Proposition 9 is defeated, the factors that continue to affect the Utility's ability to recover transition costs include: (1) the continued application of the regulatory framework established by the CPUC and state legislation; (2) the amount of transition costs ultimately approved for recovery by the CPUC; (3) the market value of the Utility-owned generation facilities; (4) future Utility sales levels; (5) future Utility fuel and operating costs; (6) the extent to which the Utility's authorized revenues to recover distribution costs are increased or decreased; and (7) the market price of electricity.

On July 1, 1998, the Utility completed the sale of three electric Utility-owned fossil-fueled generating plants to Duke Energy Power Services Inc. (Duke) for $501 million. These three fossil-fueled plants had a combined book value at July 1, 1998, of approximately $351 million and a combined capacity of 2,645 MW. The three power plants are located at Morro Bay, Moss Landing, and Oakland.

The Utility will continue to operate and maintain the plants under a two- year operating and maintenance agreement. Additionally, the Utility will retain the liability for required environmental remediation of any pre- closing soil or groundwater contamination at these plants. Although the Utility is retaining such environmental remediation liability, the Utility does not expect any material impact on its or PG&E Corporation's financial position or results of operations.

In July 1998, the Utility agreed with the City and County of San Francisco to permanently close Hunters Point Power Plant when reliable alternative electricity resources are operational. The CPUC approved this agreement in October 1998, allowing the Utility to recover the existing book value of Hunters Point and the plant's environmental remediation and decommissioning costs. Hunters Point is a fossil-fueled plant with a generating capacity of 423 MW and a book value, including plant-related regulatory assets, at September 30, 1998, of $33 million.

Subject to the outcome of Proposition 9, the Utility currently intends to sell its fossil-fueled and geothermal facilities: Potrero, Pittsburg, Contra Costa, and Geysers power plants. These fossil-fueled and geothermal facilities have a combined generating capacity of 4,289 MW and a combined book value at September 30, 1998, of approximately $592 million. The Utility is scheduled to receive final bids to purchase these plants in November 1998, and to complete the sale of these plants in 1999.

Any net gains from the sale of our Utility-owned fossil-fueled and geothermal plants will be used to offset other transition costs. As a result, we do not believe the sales will have a material impact on our results of operations.

In 1997, the Utility informed the CPUC that it does not intend to retain its remaining 4,000 MW of hydroelectric facilities as part of the Utility. These remaining facilities have a combined book value at September 30, 1998, of approximately $1.6 billion. As discussed above, any method of disposition of assets other than through sale to a third party could result in a material charge to the extent that the market value, as determined by the CPUC, is in excess of book value.

Under the guidance of EITF 97-4 and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," an impairment analysis was required of the generating assets no longer subject to the guidance of SFAS No. 71. The Utility compared the cash flows from all sources, including CTC revenues, to the cost of the generating facilities and found that the assets were not impaired. During the second quarter of 1998, the Staff of the Securities and Exchange Commission (SEC) issued interpretive guidance regarding the application of EITF 97-4 and SFAS No. 121. The guidance states that an impairment analysis should exclude CTC revenues from the recovery stream. Under this interpretation, the Utility performed the impairment analysis excluding CTC revenues and determined that $3.9 billion of its generation facilities were impaired. Because the Utility expects to recover the impaired assets as a transition cost under the transition plan established by the restructuring legislation, discussed above, the Utility recorded a regulatory asset for the impaired amounts as required by EITF 97-4. Accordingly, at June 30, 1998, this amount was reclassified from Property, Plant, and Equipment to Regulatory assets on the accompanying balance sheets. In addition, prior year balances were reclassified.

Regardless of the customer's choice of electric commodity provider, during the transition period, customers will be billed for electricity used, for transmission and distribution services, for public purpose programs, and for recovery of transition costs. Customers who choose to purchase their electricity from non-Utility energy providers will see a change in their

total bill only to the extent that their contracted electric commodity price differs from the PX price. Transition costs are being recovered from substantially all Utility distribution customers through a nonbypassable charge regardless of their choice in commodity provider. We do not believe that the availability of choice to our customers will have a material impact on our ability to recover transition costs.

In addition to supplying commodity electric power, commodity electric providers may choose the method of billing their customers and whether to provide their customers with metering services. We are tracking cost savings that result when billing, metering, and related services within our Utility's service territory are provided by another entity. Once these cost savings, or credits, are approved by the CPUC and the customer's energy provider is performing billing and metering services, we will: (1) refund the savings to customers where the Utility provides the billing for these services; or (2) remit the savings to the electric providers where the electric provider bills for these services. The electric providers then will charge their customers for these services. To the extent that these credits equate to our actual cost savings from reduced billing, metering, and related services, we do not expect a material impact on the Corporation's or the Utility's financial condition or results of operations.

Proposition 9 would overturn major provisions of California's electric industry restructuring legislation. Proposition 9 proposes to: (1) require the Utility and the other California investor-owned utilities to provide a 10 percent rate reduction to their residential and small commercial customers in addition to the 10 percent rate reduction mandated by the electric restructuring legislation; (2) eliminate transition cost recovery for nuclear generation plants and related assets and obligations (other than reasonable decommissioning costs); (3) eliminate transition cost recovery for non-nuclear generation plants and related assets and obligations (other than costs associated with QFs), unless the CPUC finds that the utilities would be deprived of the opportunity to earn a fair rate of return; and (4) prohibit the collection of any customer charges necessary to pay principal and interest on the rate reduction bonds or, if a court finds that such prohibition is not legal, require that utility rates be reduced to fully offset the cost of the customer surcharges.

If the voters approve Proposition 9, then legal challenges by the California utilities and others, including the Utility, would ensue. The Utility intends to vigorously challenge Proposition 9 as unconstitutional and to seek an immediate stay of its provisions pending court review of the merits of its challenge.

If Proposition 9 is approved, and if the Utility were unable to conclude that it is probable that Proposition 9 ultimately would be found invalid, then under applicable accounting principles the Utility would be required to write off generation-related regulatory assets, which would no longer be probable of recovery because of reductions in future revenues. The Utility anticipates that such a write-off would range from a minimum of approximately $2.2 billion pre-tax to a maximum of approximately $5.0 billion pre-tax. This pre-tax loss would result in an after-tax loss ranging from $1.3 billion to $2.9 billion, or $3 to $8 per share. The amount of the write-off is dependent on how the courts and regulatory agencies interpret and apply the provisions of Proposition 9. The maximum $2.9 billion write-off would represent 48% of the Utility's total common stockholders' equity of $6.0 billion at September 30, 1998.

The $2.9 billion maximum after-tax loss would eliminate the Utility's retained earnings of $2.2 billion at September 30, 1998, and the Utility would be unable to meet certain capital-related regulatory and legal conditions. In addition, this loss would reduce the common equity ratio of the Utility's ratemaking capital structure from approximately 48% to approximately 32%, which is below the 48% equity ratio mandated by the CPUC. Such a loss would severely impair the Utility's ability to pay dividends to its preferred shareholders and the Corporation's ability to pay dividends to its common shareholders. Also, the Utility is concerned that its credit rating could drop to low investment grade or even below investment grade. This would immediately and substantially reduce the market value of the Utility's $5.8 billion in debt securities, increase the cost of raising new debt capital, and may preclude the use of certain financial instruments for raising capital.

The duration and amount of the rate decrease contemplated by Proposition 9 is uncertain and, if Proposition 9 is approved, will be subject to interpretation by the courts and regulatory agencies. However, if all provisions of Proposition 9 ultimately are upheld against legal challenge and interpreted in an adverse manner, the amount of the average earnings reductions could be approximately $200 million per year, or over $16 million per month, from now through 2001 (assuming rates are reduced to offset the charges for the rate reduction bonds) and approximately $50 million per year from 2002 (based on rates under current regulatory decisions, assuming such decisions are in effect after the latest date on which the rate freeze would otherwise end) to 2007 (the longest maturity date of the rate reduction bonds). The earnings reduction estimates depend on how the courts and regulators interpret Proposition 9 and how future rate changes unrelated to Proposition 9 (such as changes resulting from the General Rate Case proceeding, discussed below) affect the Utility's electric revenues.

As discussed in Transition Cost Recovery, above, the Utility is recovering most of its transition costs under a rate freeze through the transition period, which ends by December 31, 2001. If Proposition 9 is immediately implemented, even on a temporary basis pending judicial review, then the Utility's opportunity to recover transition costs will be reduced each month. Depending on market conditions, this reduction could amount to as much as $115 million per month, on average.

In addition to the potential impacts on the Utility discussed above, during any such litigation, Proposition 9 may adversely affect the secondary market for the rate reduction bonds. Further, the collection of the FTA charges necessary to pay the rate reduction bonds while the litigation is pending would be precluded, unless an immediate stay is granted. Even if a stay is granted immediately, there may be terms and conditions imposed in connection with the stay that may adversely affect the cash flow for timely interest payments on the rate reduction bonds. The failure to pay interest when due could give rise to an event of default. Finally, if Proposition 9 is upheld against legal challenge, then the primary source for payments on the rate reduction bonds would become unavailable and holders of the rate reduction bonds could incur a loss of their investment.

The Utility Electric Transmission Business:

Utility electric transmission revenues are under FERC jurisdiction. In December 1997, the FERC put into effect rates to recover annual retail electric transmission revenues of $301 million, effective March 31, 1998, the operational date of the ISO and PX. The authorized revenues were consistent with Utility electric transmission revenues in CPUC-authorized 1997 electric rates. In May 1998, the FERC allowed a $30 million increase in retail electric transmission revenues, effective October 30, 1998. All 1998 retail electric transmission revenues are subject to refund pending

rate review proceedings by the FERC. The Utility does not expect a material change in transmission revenues resulting from the FERC's final decision.

The Utility Electric Distribution Business:

During the second quarter of 1998, the CPUC issued various decisions in which it indicated its support for competition within the electric distribution market. We believe that these regulatory pronouncements are not consistent with prior CPUC policy on distribution competition, including duplicative distribution facilities. Moreover, we believe that these pronouncements have increased substantially the uncertainty surrounding the future role of California's electric utility distribution companies. In addition, we believe that the CPUC made these statements without a comprehensive examination of such fundamental issues as: (1) recovery of electric distribution transition costs; (2) the shifting of costs among customer classes and geographic regions; (3) the economic and environmental impacts of distribution competition; and (4) the distribution utilities' statutory obligation to serve.

During the third quarter of 1998, the FERC issued a decision requiring the Utility to provide wholesale transmission service to an irrigation district. The district requested 16 points of interconnection with the Utility's distribution facilities in order to serve 19 customers. The Utility believes that the requested service is equivalent to retail wheeling. The FERC decision may further facilitate duplicate electric distribution facilities.

At this time, we cannot predict the extent that the CPUC or the FERC will allow the future construction of duplicative distribution facilities by other providers or the impact that future duplicative distribution facilities and increased competition will have on the Utility's future financial condition and results of operations.

The Utility Gas Business:

In March 1998, the Utility implemented a CPUC-approved accord with a broad coalition of customer groups and industry participants that adopted market- oriented policies in the Utility's natural gas transmission business. The accord unbundled the Utility's gas transmission and storage services from its distribution services and established gas transmission and storage rates for the period March 1998 through December 2002. In addition, the accord increases the opportunity for the Utility's residential and small commercial
(core) customers to purchase gas from competing suppliers.

In January 1998, the CPUC opened a rulemaking proceeding to further expand market-oriented policies in California's gas industry. Policies under consideration included the additional unbundling of services, streamlining regulation for noncompetitive services, mitigating the potential for anti-competitive behavior, and establishing appropriate consumer protections. As required by the CPUC, several gas utilities, including the Utility, and other interested parties filed reports with the CPUC about gas market conditions. On August 6, 1998, the CPUC issued an order requiring the utilities to file cost and rate undbundling applications with the CPUC by February 26, 1999.

However, in August 1998, the California Legislature passed and the Governor signed Senate Bill (SB) 1602, which requires the CPUC to submit to the Legislature any findings or recommendations that would direct further natural gas industry restructuring for core customers. SB 1602 also prohibits the CPUC from enacting any such decision prior to January 1, 2000. In light of this new law, the CPUC issued an order on October 8, 1998, stating that it would not enforce its order from August 6, 1998. The CPUC

plans to prepare a report for the Legislature identifying its proposed long term market structure for the natural gas industry after hearings scheduled to be held in January 1999. In concurrence with the new law, the CPUC will not adopt a final market structure policy before January 1, 2000. At this time, we cannot predict the outcome of these proceedings and their impact on our financial position and results of operations.

Unregulated Business Operations:

We provide a wide range of integrated energy products and services designed to take advantage of the competitive energy marketplace throughout the United States. Through our unregulated subsidiaries, we: (1) provide gas transmission services in Texas and the Pacific Northwest; (2) develop, build, operate, own, and manage electric generation facilities across the country; (3) provide customers nationwide with services to manage and make more efficient their energy consumption; and (4) purchase and resell energy commodities and related financial instruments. In providing integrated energy products and services, we continually evaluate the composition of our assets.

PG&E Corporation:

PG&E Corporation became the holding company of the Utility in 1997. At that time, we transferred the unregulated subsidiaries of the Utility to PG&E Corporation. A condition of the CPUC's approval of the holding company formation was that the CPUC's Office of Ratepayer Advocates (ORA) oversee an audit of transactions between the Utility and its affiliates for the period 1994 to 1996. The audit report, completed in November 1997, was critical of the Utility's affiliate transaction internal controls and compliance. The auditors recommended imposing conditions affecting the financing and business composition of the Corporation.

In April 1998, the Utility filed testimony with the CPUC opposing the recommended conditions. Hearings were completed in September 1998 to determine if the additional recommended conditions should be imposed on PG&E Corporation. We expect a final CPUC decision in early 1999.

If the CPUC imposed the recommended financial conditions on the Corporation without modification, then such conditions could have an adverse impact on future results of operations.

ACQUISITIONS AND SALES:

In July 1998, the Corporation sold its Australian energy holdings to Duke Energy International, LLP (DEI), a subsidiary of Duke Energy Corporation. The assets, located in the southeast corner of the Australian state of Queensland, include a 627-kilometer gas pipeline, pipeline operations, and trading and marketing operations.

The sale to DEI represents a premium on the price in local currency of the Corporation's 1996 investment in the assets. However, the transaction resulted in a non-recurring charge of $.06 per share in the second quarter, primarily due to the 22 percent currency devaluation of the Australian dollar against the U.S. dollar during the past two years.

On September 1, 1998, the Corporation, through its subsidiary U.S. Generating Company (USGen), completed the acquisition of a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES) for $1.59 billion, plus $85 million for early retirement and severance costs previously committed to by NEES. The acquisition has been accounted for using the purchase method of accounting.

Accordingly, the purchase price has been preliminarily allocated to the assets purchased and the liabilities assumed based upon the fair values at the date of acquisition.

Including fuel and other inventories and transaction costs, the Corporation's financing requirements total approximately $1.8 billion, funded through $1.3 billion of USGen debt and a $425 million equity contribution. The net purchase price has been preliminarily allocated as follows: (1) Property, plant, and equipment of $2.3 billion; (2) Receivable for support payments of $0.8 billion; and (3) Contractual obligations of $1.3 billion. The assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of 4,000 megawatts (MW). In addition, USGen assumed 25 multi-year power purchase agreements representing an additional 800 MW of production capacity. USGen entered into agreements with NEES as part of the acquisition, which: (1) provide that NEES shall make support payments over the next ten years to USGen for the purchase power agreements; and (2) require that USGen provide electricity to NEES under contracts that expire over the next four to twelve years.

The Corporation acquired NEES's generating facilities and power supply contracts in anticipation of deregulation of the electric industry in several New England states. In Massachusetts, electric industry restructuring legislation opened retail competition in the electric generation business on March 1, 1998. However, a referendum requesting voters to approve the continuation of this legislation in Massachusetts is on the November 1998 ballot. If the voters vote to reject the legislation, then the restructuring legislation in Massachusetts will be repealed. The Corporation does not expect that a repeal of the Massachusetts legislation, which relates primarily to the retail electricity market, would have a material impact on its results of operations or financial position.

YEAR 2000:

The Year 2000 issue exists for the Corporation because many software and embedded systems use only two digits to identify a year in a date field, and were developed without considering the impact of the upcoming change in the century. Some of these systems are critical to our operations and business processes and might fail or function incorrectly if not repaired or replaced with Year 2000 ready products. By "ready", we mean that the system is remediated so that it will perform its essential functions. We define "software" as both computer programming that has been developed by the Corporation for its own purposes ("in-house software") and that purchased from vendors ("vendor software"). "Embedded systems" refers to both computing hardware and other electronic monitoring, communications, and control systems that have microprocessors within them.

Our Year 2000 project focuses on those systems that are critical to our business. By "critical" we mean those systems the failure of which would directly and adversely affect our ability to generate or deliver our products and services or otherwise affect revenues, safety, or reliability for such a period of time as to lead to unrecoverable consequences. For these critical systems, we have adopted a phased approach to address Year 2000 issues. The primary phases include: (1) an enterprise-wide inventory, in which systems critical to our business are identified; (2) assessment, in which critical systems are evaluated as to their readiness to operate after December 31, 1999; (3) remediation, in which critical systems that are not Year 2000 ready are made so, either through modifications or replacement;
(4) testing, in which remediation is validated by checking the ability of the critical system to operate within the Year 2000 time frame; and
(5) certification, in which systems are formally acknowledged to be Year 2000 ready, and acceptable for production or operation.

Our Year 2000 project is proceeding generally on schedule. For in-house and vendor software, we have completed the inventory phase and have identified approximately 1,000 critical systems. Additional software that requires Year 2000 remediation may be discovered as we continue with the assessment, remediation, and testing phases. We estimate that roughly 40 percent of identified, critical, in-house software has been remediated, with completion of remediation of remaining in-house software scheduled for the end of 1998. We estimate that roughly 10 percent of critical vendor software has been remediated and received. Our corporate milestone for receipt of all remediated vendor software is March 1999. We plan to finish testing remediated in-house and vendor software by May 1999 and expect to complete the certification phase for software by July 1999.

We also have completed the inventory of all embedded systems, although additional embedded items that require Year 2000 repair or replacement may be discovered as we continue with the assessment, remediation, and testing phases. Remediation of all critical embedded systems is planned to be completed by April 1999. We expect to finish testing of these remediated systems by August 1999, and plan to complete the certification phase for embedded systems by October 1999.

We are testing remediated software and embedded systems both for ability to handle Year 2000 dates, including appropriate leap year calculations, and to assure that code repair has not affected the base functionality of the code. Software and embedded systems are tested individually and where judged appropriate will be tested in an integrated manner with other systems, with dates and data advanced and aged to simulate Year 2000 operations. Testing, by its nature, however, cannot comprehensively address all future combinations of dates and events. Therefore, some uncertainty will remain after testing is completed as to the ability of code to process future dates, as well as the ability of remediated systems to work in an integrated fashion with other systems.

We also depend upon external parties, including customers, suppliers, business partners, gas and electric system operators, government agencies, and financial institutions, to reliably deliver their products and services. To the extent that any of these parties experience Year 2000 problems in their systems, the demand for and the reliability of our services may be adversely affected. The primary phases we have undertaken to deal with external parties are: (1) inventory, in which critical business relationships are identified; (2) action planning, in which we develop a series of actions and a time frame for monitoring expected external party compliance status; (3) assessment, in which the likelihood of external party Year 2000 readiness is periodically evaluated; and (4) contingency planning, in which appropriate plans are made to be ready to deal with the potential failure of an external party to be Year 2000 ready.

We have completed our inventory of external contacts and have identified more than 1,000 critical relationships. We soon will complete the action- planning phase for each of these entities. Additional critical relationships may be entered into or discovered as we continue. Assessment of Year 2000 readiness of these external parties will continue through 1999. We expect to complete contingency plans for each of these critical business relationships by July 1999.

We plan to develop contingency plans for our critical software or embedded systems for which we determine Year 2000 repair or replacement is substantially at risk. For example, if the schedule for repairing or replacing a non-compliant system lags and cannot be re-scheduled to meet certain milestones, then we expect to begin an appropriate contingency planning process. These contingency plans would be implemented as necessary, if a remediated system does not become available by the date it is needed. In addition, as described above, we plan to develop contingency plans for the potential failure of critical external parties to fully address their Year 2000 issues.

We also recognize that, given the complex interaction of today's computing and communication systems, we cannot be certain that all of our efforts to have all critical systems Year 2000 ready will be successful. Therefore, irrespective of the progress of the Year 2000 project, we are preparing contingency plans for each subsidiary and essential business function. These plans will take into account the possibility of multiple system failures, both internal and external, due to Year 2000 effects.

These subsidiary and essential business function contingency plans will build on existing emergency and business restoration plans. Although no definitive list of scenarios for this planning has yet been developed, the events that we considered for planning purposes include increased frequency and duration of interruptions of the power, computing, financial, and communications infrastructure. We expect to complete first drafts of these subsidiary and essential business function contingency plans by the beginning of 1999. We anticipate testing and revision of these plans throughout 1999.

Due to the speculative nature of contingency planning, it is uncertain whether our contingency plans to address failure of external parties or internal systems will be sufficient to reduce the risk of material impacts on our operations due to Year 2000 problems.

The Corporation currently is revising and refining its procedures for tracking and reporting costs associated with its Year 2000 effort. From 1997 through September 1998, we have spent approximately $80 million to assess and remediate Year 2000 problems. About $60 million of this cost was for software systems that we replaced for business purposes generally unrelated to addressing Year 2000 readiness, but whose schedule we advanced to meet Year 2000 requirements. The replacement costs for these accelerated systems were capitalized.

We estimate that our future costs to address Year 2000 issues will be approximately $180 million. About $50 million of these remaining Year 2000 costs will be capitalized because they relate to the purchase and installation of systems for general business purposes and the remaining $130 million will be expensed. As we continue to assess our systems and as the remediation, testing, and certification phases of our compliance effort progress, our estimated costs may change. Further, we expect to incur costs in the year 2000 and beyond to remediate and replace less critical software and embedded systems. We do not believe that the incremental cost of addressing Year 2000 issues will have a material impact on the Corporation's or the Utility's financial position or results of operation.

The Corporation's current schedule is subject to change, depending on developments that may arise through further assessment of our systems, and through the remediation and testing phases of our compliance effort. Further, our current schedule is partially dependent on the efforts of third parties, including vendors, suppliers, and customers. Delays by third parties may cause our schedule to change. There also are risks associated with loss of or inability to locate critical personnel to remediate and return to service the identified critical systems. We may fail to locate all systems critical to our business processes that require remediation. A combination of businesses and government entities may fail to be Year 2000 ready, which may lead to a substantial reduction in a demand for our energy services.

Based on our current schedule for the completion of Year 2000 tasks, we believe our plan is adequate to secure Year 2000 readiness of our critical systems. We expect our remediation efforts and those of external parties to be largely successful. Nevertheless, achieving Year 2000 readiness is subject to various risks and uncertainties, many of which are noted above. We are not able to predict all the factors that could cause actual results to differ materially from our current expectations as to our Year 2000

readiness. If we, or third parties with whom we have significant business relationships, fail to achieve Year 2000 readiness with respect to critical systems, there could be a material adverse impact on the Utility's and the Corporation's financial position, results of operations, and cash flows.

LIQUIDITY AND CAPITAL RESOURCES:

During the nine-month period ended September 30, 1998, the Corporation issued $52 million of common stock, primarily through the Dividend Reinvestment Plan and the Stock Option Plan. Also during the nine-month period ended September 30, 1998, the Corporation paid dividends of $355 million and declared dividends of $343 million. The Utility paid dividends of $315 million to PG&E Corporation during the nine-month period ended September 30, 1998. In October 1998, the Utility declared dividends of $100 million payable to the Corporation in October. In October 1998, the Corporation declared the fourth quarter regular common dividend of $.30 per share payable January 15, 1999, to shareholders of record on December 15, 1998.

As of December 31, 1997, the Board of Directors had authorized the repurchase of up to $1.7 billion of our common stock on the open market or in negotiated transactions. As part of this authorization, in January 1998, the Corporation repurchased in a specific transaction 37 million shares of common stock. In connection with this transaction, the Corporation entered into a forward contract with an investment institution. The Corporation settled the forward contract in September 1998. There are no more outstanding shares to be repurchased under this program.

The Corporation maintains a $500 million revolving credit facility, which expires in 2002. In August 1997, we entered into an additional $500 million 364-day credit facility, which expires on November 29, 1998. The Corporation may extend the facilities annually for additional one-year periods upon agreement with the banks. These credit facilities are used for general corporate purposes and support our commercial paper program. The Corporation had $469 million of commercial paper outstanding at September 30, 1998.

On September 1, 1998, USGen entered into a $1.675 billion revolving credit facility. The facility is to be used for general corporate purposes. The total amount outstanding at September 30, 1998, under the facility, was $540 million in eurodollar loans and $788 million in short-term commercial paper.

At September 30, 1998, GTT had $130 million of outstanding short-term bank borrowings related to separate short-term credit facilities. The borrowings are unrestricted as to use.

In July 1998, the Utility repurchased $800 million of its common stock from PG&E Corporation, in addition to its $800 million common stock repurchase from PG&E Corporation in April 1998.

The Utility's long-term debt matured, redeemed, or repurchased during the nine-month period ended September 30, 1998, amounted to $962 million. Of

this amount: (1) $249 million related to the Utility's redemption of its 8 percent mortgage bonds due October 1, 2025; (2) $252 million related to the Utility's repurchase of its other mortgage bonds; and (3) $397 million related to the maturity of the Utility's 5 3/8 percent mortgage bonds. The remaining $64 million related primarily to the other scheduled maturity of long-term debt. Also, PG&E Funding retired $193 million of the rate reduction bonds during the nine-month period ended September 30, 1998.

In January 1998, the Utility redeemed its Series 7.44 percent preferred stock with a face value of $65 million. In July 1998, the Utility redeemed its Series 6-7/8 percent preferred stock with a face value of $43 million.

The Utility maintains a $1 billion revolving credit facility, which expires in 2002. The Utility may extend the facility annually for additional one-year periods upon agreement with the banks. There were no borrowings under this credit facility at September 30, 1998.

As discussed above, in Transition Cost Recovery, the CPUC separately reduced the authorized return on common equity (ROE) on our Utility's hydroelectric and geothermal generation assets to 90 percent of the Utility's 1997 adopted cost of debt, or 6.77 percent. The Utility believes that this reduction is inappropriate and has sought a rehearing of this decision.

On May 8, 1998, the Utility filed its 1999 Cost of Capital Application with the CPUC. The Utility requested a return on common equity of 12.1 percent and an overall return on rate base of 9.53 percent for its gas and electric distribution operations. The Utility did not request a change in its currently authorized capital structure of 46.2 percent debt, 5.8 percent preferred equity, and 48 percent common equity.

On August 10, 1998, the CPUC's ORA filed its testimony recommending a ROE of 8.64 percent for electric distribution operations and a ROE of 9.32 percent for gas distribution operations. ORA's recommended ROEs result in recommended overall returns on rate base for electric and gas distribution operations of 7.85 percent and 8.17 percent, respectively. If adopted by the CPUC, then ORA's recommendation would result in decreases for 1999 electric and gas distribution revenues of $162 million and $38 million, respectively, as compared to revenues based upon ROE currently authorized by the CPUC.

The ORA's ROE recommendation for electric distribution operations is due to its perception of the changing economic conditions in the past year, and its perceived reduction in business risk for electric distribution operations as compared to the formerly integrated generation, transmission, and distribution operations. The ORA also believes that the CPUC's method of adjusting the cost of capital annually based on incremental changes in economic factors has led to what the ORA believes have been inflated authorized returns in recent years.

To the extent the actual electric and gas rate bases adopted by the CPUC in the GRC proceeding are less than the rate bases proposed by the Utility, the estimated 1999 revenue reductions from the lower ROEs recommended by the ORA in the cost of capital proceeding would be less. We expect the CPUC to adopt a final decision in the cost of capital proceeding in February 1999, and a final decision in the GRC proceeding in March 1999.

On June 26, 1998, the ORA provided their revenue requirement calculation, which supplements ORA's June 8, 1998, report on the 1999 GRC proceeding. The ORA recommended a decrease of $86 million in electric base revenues and an increase in gas base revenues of $91 million over the Utility's 1998 authorized base revenues.

Hearings for the GRC before an administrative law judge took place from August 24, 1998, through October 16, 1998. The administrative law judge considers testimony and other evidence from many parties, including the ORA. The Utility expects the CPUC to issue a proposed decision by the administrative law judge in February 1999. The CPUC may accept all, part, or none of the ORA's recommendations. We cannot predict the amount of base revenue increase or decrease the CPUC ultimately will approve. In the event of an adverse decision by the CPUC, and if the Utility is unable to lower expenses to conform to the base revenue amounts adopted by the CPUC while maintaining safety and system reliability standards, the ability of the Utility to earn its authorized rate of return for the years 1999 through 2001 would be adversely affected.

The CPUC permitted the Utility to submit a plan for establishing interim rates, effective January 1, 1999, to cover the period between that date and the date the CPUC issues its decision. The CPUC plans to issue a decision on interim rates in December 1998.

The 1999 GRC will not affect the authorized revenues for electric and gas transmission services or for gas storage services. The Utility's authorized revenues for each of these services are determined in other proceedings.

At September 30, 1998, the Utility expects to spend $282 million for clean-up costs at identified sites over the next 30 years. If other responsible parties fail to pay or expected outcomes change, then these costs may be as much as $486 million. Of the $282 million, the Utility has recovered $97 million and expects to recover $162 million in future rates. Additionally, the Utility is seeking recovery of its costs from insurance carriers and from other third parties. Further, as discussed above, the Utility will retain the pre-closing remediation liability associated with divested generation facilities. (See Note 4 of Notes to Consolidated Financial Statements.)

In the second quarter of 1998, the CPUC granted conditional authority to the Utility to use natural gas-based financial instruments to manage the impact of natural gas prices on the cost of electricity purchased pursuant to existing power purchase contracts. Under the authority granted in the CPUC decision, no natural gas-based financial instruments shall have an expiration date later than December 31, 2001. Further, if the rate freeze ends before December 31, 2001, the Utility shall net any outstanding financial instrument contracts through equal and opposite contracts, within a reasonable amount of time. Also during the second quarter, the Utility filed an application with the CPUC to use natural gas-based financial instruments to manage price and revenue risks associated with its natural gas transmission and storage assets. See Note 1 for additional discussion of risk management activities. The Utility currently does not use financial instruments to manage price risk.