ML20217G515

1997 PG&E Corp Annual Rept

ML20217G515
Person / Time
Site:	Diablo Canyon, Humboldt Bay
Issue date:	12/31/1997
From:	Glynn R, Tomkins J PACIFIC GAS & ELECTRIC CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
NUDOCS 9804020377
Download: ML20217G515 (66)

Text

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Pacific Gasand

, Electric Coupany James E.Tomkins 245 Marnet Street.floom 862 uc a Safety Assessement and d

'"*M Mad Code N98 i

PO Box 770000 March 27,1998 San f rancmco. CA 94W 415 973 8115

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PG&E Letter DCL-98-042 HBL-98-004 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 l

Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 Docket No. 50-133, OP-DPR-7 Humboldt Bay Unit 3 i 1997 Annual Financial Report

Dear Commissioners and Staff:

Pursuant to 10 CFR 50.71(b) and 10 CFR 140.15(b)(1), enclosed are 15 copies of PG&E's Annual Report and Financial Information for the calendar year 1997, i I

Sincerely, I l- l J mes E. Tomkins l

l Enclosure I

cc: Steven D. Bloom Ira P. Dinitz Ellis W. Merschoff Kenneth E. Perkins 'I O Qb ff David L. Proulx Louis L. Wheeler

~ GRC/2013 9804020377 971231 PDR- ADOCK 05000133 I PDR

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1997 p PG&ECorporation Report Annual i

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Financial highlights idoHars in milHons, except per share amounts) 1997' 1996 . % Change For the Year Operating revenues $ 15,400 $ 9,610 ' 60.2

~ Operating income ' $ 1,728 $ 1,896 (8.9)

Net income $ 716 $ 722 (0.8)

Earnings per common share, liasic and Diluted $ 1.75 $ 1.75 -

Dividends declared per common share $ 1.20 $ 1.77 (32.2)

' Capital expenditures (including AFUDC) - $ 1,870 $ 1,404 33.2 At Year End

'Ibtal assets ' S 30,557 $ 26,237 16.5

. Number of common shareholders 180,000 198,000 (9.1)

Number of common shares outstanding 417,665,891 403,504,292 3.5 Number of employees 23,500 22,000 6.8 PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. The Corporation's businesses provide energy services throughout the U.S. and in Australia. PG&E Corporation's Northern and Central Californla energy utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to one of every 20 Americans. PG&E Corporation's four unregulated businesses provide a wide range of energy products and services on a national basis: U.S. Generating Company develops, builds, operates, owns, and manages power generation facilities to supply wholesale

. and industrial customers; PG&E Gas Transmission owns and operates approximately 10,000 miles of natural gas pipelines, natural gas storage facilities, and natural gas processing plants in the Pacific Northwest,

' Texas, and Australia; PG&E Energy Services provides customers nationwide with competitively priced natural gas and electricity, and services to manage and make more efficient their energy consumption; and PG&E Energy Trading purchases and resells energy commodities and related financial instruments in major domestic markets, serving PG&E Corporation's other unregulated businesses, unaffiliated utilities, and large end-use customers.

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i etter to Shareholders 1997 was a year of great change in our domestic energy marketplace and of significant progress by

- PG& E Corporation in becoming the premier energy services company.

The_B usin es s_ Environ rn ent_

Across the nation, many retail energy consumers are on the threshold of being able - for the first time - to purchase gas and electricity from competitive energy providers and not exclusively from their local utility companies. Some electricity customers, and many natural gas customers, already have begun to choose unregulated suppliers.

And utilities, increasingly focused on being delivery companies, find customers demanding continuous improvement in safety, reliability, and responsiveness.

Amorg the major forces driving these fundamental changes are customers who want better service, higher quality, and lower prices; competitors who want access to new business opportunities; and regulators and legislators who want more competition in the energy marketplace.

These forces were particularly active in California where our utility business serves 13 million people.Throughout the year, the California enerFy marketplace reacted to the state's landmark energy deregulation legislation signed into law in late 1996.

In 1997, PG&E Corporation focused primarily on opportunities presented in California and in the rapidly changing energy markets in other key regions of the U.S.

Our utility business, Pacific Gas and Electric Company, participated in development of the programs, procedures, and systems that will enable California energy con sumers to be among the first in the nation to enjoy the benefits of competition and choice. These included implementing

' the systems and protocols necessary for the reliable transfer of resp (msibility for operating California's electric transmission grid to the new state-operated Independent System Operator. They also included building the customer billing and information systems required to facilitate customers'

. ability to choose from an array of competitive suppliers.

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We also were successful in bringing increased

• In the last nine months of 1997, our retail energy competition to the natural gas operations of our utility senices subsidiary, PG&E Energy Services, opened 17 sales business. In 1997, we received regulatory approval of the offices, hired nearly 300 employees, and signed agree-Gas Accord, a comprehensive plan to restructure the way ments to provide energy ser ices worth almost $1 billion.

natural gas is bought, transported, and sold in the state.

• Our unregulated energy commodities trading The Gas Accord increases the ability of customers to business, PG&E Energy Trading, established sales and choose from competitive gas r,uppliers and is expected to supply offices across the U.S. and Canada with a portfolio result in lower natural gas prices and significant savings of 500 wholesale customers and trading partners.

for customers over the next five years.

• We took important steps to prepare for deregu-Our unregulated businesses moved forward to take lation in California, under which utilities are encouraged advantage of the opening of the competitive energy mar- to divest their power plants to non-utilities who then will ketplace. Since the formation of PG& E Corporation at the compete in the supply marketplace. We reached agree-beginning of the year, we have progressed significantly from ment and received regulatory approval to sell three of our concept to reality in establishing the family of companies that utility-owned fossil-fueled power plants to Duke Energy comprise our unregulated group. This has included building for $501 million. The sale of our remaining utility-owned new businesses and acquiring strategic assets from others. fossil-fueled and geothermal plants is slated for 1998.

Within our unregulated group, we are organized

• Our nuclear plant, Diablo Canyon, was again along four functional business activities: electrie generation, rated a No. I performer by the Institute of Nuclear gas transmission, energy services, and energy trading. Power Operations GNPO). Diablo Canyon has held an We have assembled a team drawn from inside and outside INPO No. I rating ever since INPO began its rating our company, putting people with skills and experience in program. Diablo Canyon is the only nuclear power plant leadership positions in each of these activities. with such a record.

_199LAccomplishments _ _

• We acquired a major gas pipeline business in

• We articulated our vision of the Corporation's Texas by completing our acquisitions of Teco Pipeline utility and unregulated businesses, emphasizing our focus Company and the natural gas services business of Valero  !

on regional U.S. energy markets and our intention to Energy Corporation. With these actions, we added more develop shareholder value in each operating business than 8,500 miles of natural gas pipelines as well as natural activity and between them. gas processing and storage facilities, establishing PG&E

• The stock market rewarded our strategy with a Gas Transmission as a major player in the important stock price increase in 1997 of 44.3 percent. Tbgether Texas marketplace.

with our dividend, total return to sha.rcholders in 1997

• We sharpened our focus on non-utility electric was 51.9 percent. generation. We exited the international power plant 2

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development business with the sale to Ilechtel Enterprises return on equity when our 1999 General Rate Case goes of our interest in the International Generating Company. into effect.

And we expanded our domestic generation business In our unregulated businesses, we will continue to with our purchase of llechtei's interest in U.S. Generating focus on attractive regional U.S. energy markets. Our Company (USGen), now the focal point of PG&E objective is for each unregulated business toincrease finan-Corporation's unregulated generation business. cial performance, u hile making safety, customer service, and

• We were selected by the New England Electric competitiveness the hallmarks of these operations.

System to acquire its non-nuclear electric generating Our goal in all of this is to increase shareholder value l assets, one of the largest such transactions to date in the again in 1998, and to be recognized as the premier energy )

U.S. When this transaction closes in 1998, USGen will services company by our eustomers, our employees, and our l i

become the largest non-utility electric generating com- shareholders.

pany focused solely on the domestic marketplace. _ . Stan Skinner _

_ Wiia t's_ N ext _ As we conclude this review of 1997, I want to personally in 1997 we provided exceptional stock price appreciation acknowledge the contributions of Stan Skinner, who and total shareholder return, despite essentially " flat" retired as CEO and Chairman in 1997 after a distinguished earnings. The Corporation's 1997 carnings were $1.75 per 33-year career with Pacific Gas and Electric Company share, equal to the $1.75 per share earned in 1996. We are and PG&E Corporation. Stan led the company through a pleased with the overall value we returned to shareholders very challenging period of electric deregulation. IIis in 1997, and are dedicated to delivering substantial and foresight and leadership positioned us for futme success.

predictable grow th in earnings in 1998 and beyond. Thank you, Stan.

'Ib achieve this goal, our utility business will continue to focus on delivering safe, reliable, and responsive senice, i on moving forward aggressively to implement California's R I"' n D . G l y n n , J r .

change to a competitive marketplace, and on positioning Chairman of the Board. Chief Executive Officer, and President the company to carn our full authorized utility rate of February 9.1998 3

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Question & Answer In 1997, more than 95 percent of the Corporation's earnings came from its utility operations, Pacific Gas e al Electric Company. In the future, what percentage of your earn-t ings will come from the Corporation's unregulated business?

I'd be disappointed if our unregulated business wasn't contributing 25 percent to 30 percent of PG&E Corporation's earnings in the next five years.

1 As you move forward with your national energy strategy, what are the major risks you face?

A one big risus undue daay in opening enugy markts nationany to consumer choice. Our strategy for our unregulated activities is based on capturing opportunities created as these markets open to competition. We want consumers around the nation to have choice in their energy providers, and we want our strategy to succeed as consumers benefit from choice.

Now that competition in the energy industry is a reality, u hat is PGA E Corporation doing

1. .. to effectivel y meet competitise challenges and position itself as the A In 1997, we aggressively expanded our business enterprises across the U.S. We establishe presence in parts of the country where we were hardly know n a year earlier - from Texas to New England.

offices have been opened from San Francisco to Long Island and staffed with some of the most talented and innovative people in the business. The PG&E Corporation identity is national in scope and national in its business strategies. This is the beginning, not the completion, of such strategies.

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Robert D Glynn, Jr.

Chairrnan of the Board.

Chief Executive Officer, and President Many American energy services companies are moving aggressivelyinto foreign markets.

j What is PG& E Corporation's position on overseas investment?

We currendy have a small investment in Australia, where the business and regulatory climates are positive. We do not rule out further investments in that country, but we are not presently seeking additional investments in overseas markets. 'Ibday, domestic energy markets are the principal focus of our human and financial resources.

i llow does your strategy emisioa producing superior growth and value for shareholders from your unregulated business?

A our strategy is m budd a nad< mal presence to sansfy cusmmus' nteds for compendve <nergy commodities and services. The main elements are electric generation, natural gas transmission, and sales at the w holesale and retail level. We plan to achieve operational excellence in each of these, to deliver superior value from each, and to create additional value from the synergies between them. Within this strategy we are focusing on specific attractive regional markets - such as the Northeast, Texas, and the West -in which we are building the scope and scale necessary for profitability.

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Why is the company selling pow er plant assets in California while purchasing them in other parts of the country?

A The domoduleude genuadon mada is evolving imo uommodity marke with power prices deter-mined in the marketplace, rather than set through regulation. Our strategy is quite simple: we are divesting power plant assets currently owned by our California utility where our returns would be unacceptably low under state regulation, and we are investing in power plant assets through U.S. Generating Company in regions with attractive markets where we can create shareholder value as an unregulated plant owner and operator.

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Q~ lj h [g g 3 A Utihty Headquarters a Service Ares Our utility, Pacific Gas and Electric Company, provides gas and electric service to Northern and Central j California, the nation's premier marketplace which,in 1997, outpaced the country in job and income growth.

California has been in the forefront of the nation in deregulating the market for electricity. This year customer choice is expected to become a reality in California as customers begin exercising their option to select an electricity provider from more than 170 competing companies. ,

The primary business of Pacific Gas and Electric Company in this newly competitive energy market will be the transmission and delivery of energy. We will provide these services to customers regardless of which company they choose for their gas and electric supply. We also will continue to provide natural gas and electricity to customers who wish to remain with the company rather than select an alternative supplier.

Last year Pacific Gas and Electric Company moved aggressively to succeed in this competitive environment and improve its financial performance, establishing three fundamental goals:

• To continue to improve the safe, reliable energy services we provide; a 'Ib implement California Assembly Ilill 1890 (AH 1890), the law passed in California in 1996 that is the framework for creating consumer choice in the state's electric utility industry; and

Ib position Pacific Gas and Electric Company to earn the full return as authorized by the California Public Utilities Commission (CPUC).

We made solid progress in all three areas during 1997.

_._ Safe _fletiar' Service _

In 1997, as part of our ongoing program to maintain safe and reliable energy service for our customers, we spent more than 51 billion to enhance the dependability of our gas and electric transmission and distribu-7

tion systems, and to accommodate new customer demand driven by strong economic growth in our California market. During the year, we:

• Tested and treated nearly 400,000 utility poles and replaced more than 16,000 of them;

• Completed more than 9,500 substation maintenance projects, made 115,000 separate equipment repairs, and devoted 800,000 work-hours performing preventive maintenance;

• Trimmed about 2.1 million trees, the largest sirigle-year total in company history;

• Added about 1,700 megawatts of new substation and feeder capacity in areas where demand for j

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energy is growing rapidly, such as the high-tech manufacturing center, Silicon Valley; and

= Continued our program ofimprovements to our customer call centers -improvements which add to the excellent existing ability of our customer service representatives to respond quickly and effectively to calls for service assistance, especially during storm-related emergencies.

These efforts are already producing results, and underscore Pacific Gas and Electric Company's commitment to provide high quality eneigy service to all our customers. For example, our average response time to customer calls has been reduced from almost two-and-one-half minutes to under 20 seconds. And the " excellent" rating on quality of service evaluations by our customers has gone from 42 percent to 50 percent in a year.

I m p le m e n tin g _ Ele c tr.ic_ D e r e g ul a tio n_in_C alif orn ia_

As a framework for deregulating California's electric utility industry, California Assembly Bill 1890 (AB 1890) provides immediate consumer benefits. All 1890 also establishes obligations which the state's utilities must meet, and provides them with opportunities to recover some of the costs of the transition to an open market.

For example, All 1890 mandates a 10 percent electric rate decrease for all residential and small business customers in California, w hich went into effect on January 1,1998. This decrease will save customers

$400 million in 1998.

All 1890 also created a mechanism to finance this immediate customer benefit through a new type of security known as rate reduction bonds. Approximately $3 billion of rate reduction bonds were successfully issued on behalf of the company in December 1997, the first such transaction in the nation.

The company was successful during the year in meeting its obligations to create a competitive energy market.

We completed - under enormous time pressure - the many complex procedural, computer, and organizational changes needed to enable our customers to choose electricity from alternative providers.

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i We announced the sale of three of our fossil-fueled power plants located in California to Duke Energy Power Services, Inc., for $501 million. This sale was an important milestone in separating genera-tion sources from transmission and distribution facilities as part of deregulation of California's electric utility industry.

And we brought to a highly successful conclusion several years of work on a Gas Accord that elimi-nates many long-standing barriers to a competitive natural gas transportation market in California.

_ Earning _theluthorized fleturn_

Despite the huge challenges posed by the dramatic change in gas and electricity markets, Pacific Gas and Electric Company reported earnings of $735 million in 1997, a two percent increase over the prior year.

Ilowever, our current revenues do not cover the full cost to maintain our transmission and distribution systems and to provide responsive customer service. As a result, we have earned less than the full return on investment authorized by the CPUC.

PaciGc Gas and Electric Company is taking steps to improve its fiz.ancial performance.

We have requested an increase in revenues that accurately reDects the full cost of our ser ice relia-bility programs. This request, w hich is expected to take effect January 1,1999, will be considered by the CPUC during 1998, a And we have redoubled our efforts to rigorously control costs through a " Smart Spending and Smart Savings" campaign. Through this effort, the company is improving the way goods and services are pur-chased and used, climinating unnecessary expenditures, and revising work practices that hinder efficiency.

We are committed to improving our service and strengthening our electric and gas systems. We are equally committed to providing PG&E Corporation's shareholders with a solid return on their investment.

We are confident that the efforts we are taking will enable us to achieve success in meeting these goals.

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A USGen Headquarters a indicates states where USGen has plants ir operation, plants under development and/or pending acquisitions.

U.S. Generating Company (USGen) was formed in 1989 as a partnership of PG&E Corporation and llechtel ,

1 Enterprises, Inc. In 1997, PG&E Corporation acquired llechtel's interest, making USGen a wholly owned  ;

subsidiary of the Corporation.

USGen develops, builds, operates, owns, and manages power generation facilities that meet whole-sale and industrial customer needs, and that satisfy local community requirements for environmentally and economically beneficial generating options. I At year end, USGen had interest in 15 operating plants in eight states totalling 3,265 megawatts.

These plants achieved an outstanding performance record in 1997, producing more than 97 percent of the capacity requested by their customers.

During the year, USGen's plants and its energy trading affiliate (now part of PG&E EnerFy Trading) j sold more than 38 million megawatt-hours of electricity to the wholesale market.

In August 1997 USGen was selected to acquire the non-nuclear generating business of the New England Electric System (NEES) for $1.59 billion. The acquisition includes three fossil-fueled electric generating plants,15 hydroelectric facilities, and more than 20 electricity purchase contracts.

Together, these comprise more than 5,100 megawatts of generating and purchased-power capacity. The transaction is expected to be completed in 1998.

Upon completion, USGen will become America's largest, competitive electric generator. Its power plant portfolio will exceed 8,000 megawatts of capacity.

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p USGen's 1997 accomplishments point to the company's continuing growth in the competitive power market. Our strategy for growth flows from USGen's competitive success in plant operations, its power plant development and acquisition activities, and its integrated marketing and customer sales. .

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A PG&E Gas Transmission Headquarters is Indicates states where PG&E Gas Transmission has operations.

PG&E Gas Transmission, our unregulated natural gas company, owns and operates facilities in three geographic regions: the Pacific Northu est, Texas, and Queensland, Australia. In addition, we own an interest in natural gas pipelines in the Northeast. Our operations include approximately 10,000 miles of natural gas pipelines, natural gas storage facilities, and natural gas liquids processing plants.

In 1997, PG&E Gas Transmission achieved several significant accomplishments:

• We completed the acquisition of major assets that now give PG&E Corporation a presence in markets that include New England, the Pacific Northwest, and Texas.

• We continued to operate safe, reliable, and environmentally responsible pipelines.

• We delivered a record 875 billion cubic feet of natural gas over our Northwest system while operating at almost 100 percent reliability. This 612-mile pipeline links Western Canada's abun-dant and economic natural gas supplies to U.S. markets.

• In Texas, we set a record by producing more than 100,000 barrels of natural gas liquids per day with more than 99 percent operating reliability. We also entered into, renew ed, or renegotiated gas sales, transportation or processing agreements representing more than $390 million of annual revenue.

During 1997, we completed the acquisition of Texas-based Teco Pipeline Company and Valero Natural Gas Company, the natural gas services business of Valero Energy Cornpany. These acquisitions

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I added more than 8,500 miles of natural pipeline,7.2 billion cubic feet of natural gas storage, and nine {

natural gas liquids processing plants to PG&E Gas Transmission. PG&E Gas Transmission is among the top five natural gas liquids processors in the U.S.

PG&E Gas Transmission now has the capability in the Texas Gulf Coast to provide integrated service - all e way from gathering a producer's natural gas to processing it, storing it and delivering it to other market centers within the state or for further transportation elsewhere.

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4 A PG&E Energy Services Headquarters e indicates states where PG&E Ene.py Services has rnajor offices supporting national sales activities.

PG& E Energy Services, headquartered in San Francisco, is a nationwide energy services and commodities supplier, with offices in more than 20 major cities across the United States.

PG& E Energy Services provides commercial, industrial, and institutional customers with a wide range of services, including competitively priced electric and gas commodities, billing and infonnation management services. rgy management services, regulatory and rate analysis, and power quality solutions.

Since April 1. , when it began doing business as PG&E Energy Services, the company has grown I from 40 employees to more than 300 and has signed agreements valued at almost $1 billion in revenue.

During the year, we acquired liarakat & Chamberlin Inc. (IICI), a national consulting firm based in Oakland, California; IICI's subsidiary, Creston Financial Group; and Utility Service Associates, a hilling analysis and management firm located in Columbia, South Carolina. These acquisitions significantly add to PG& E Energy Services' competitiveness by increasing our expertise to provide customers with energy consulting, financing, and billing management services.

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• i PG&E Energy Services has entered into agreements to supply electricity to numerous major firms 6-and organizations in California, including:

• Atore than 800 existing AlcDonald's restaurants and corporate regional offices, as well as future . (

AlcDonald's restaurants to be built statewide; the estimated revenue from this agreement is more than $180 million during the life of the contract;

• Afore than 400 Safeway and Vons facilities and 12 distribution, manufacturing, and food process-ing sites throughout California;-

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• More than 50011lockbuster stores throughout California;

• Approximately 600 California retail drug stores owned by Rite Aid, including the former Thrifty PayLess chain, as well as two distribution centers;

• Approximately 55 campuses of the Community College League of California;

• The Association of Bay Area Governments, a joint powers agency of nine counties and 95 cities throughout the San Francisco Ilay Area; and

• Four California manufacturing facilities of dessert topping makerJ.A1. Smucker.

PG&E Energy Services also has been selected by Neiman Alarcus to provide comprehensive informe. tion and billing management services to all 35 of its stores and several support facilities throughout the U.S.

And we have completed more than 650 gas sales agreements with customers across the country, including the NewJersey llealth Care Purchasing Group and Pepsi-Cola General llottlers, Inc., which operates 72 facilities in 10 states.

- As more energy markets across the nation are opened to consumer choice and competition, PG&E Energy Services is positioned to provide customers xith significant value: energy solutions that save time and money.

PG&E Energy Services offers customers one of the largest teams of product experts, energy engineers, and customer service representatives in the energy services industry. And it is backed by the substantial resources of PG&E Corporation's other unregulated businesses, including competitive power supplies from U.S. Generating Company, natural gas transport and natural gas liquids from PG&E Gas Transmission, and wholesale energy commodities from PG&E Energy Trading.

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A PG&E Energy Trading Headquarters 3 Indicates states where PG&E Energy Trading has major offices supporting national trading activities.

PG& E Energy Trading, headquartered in llouston, Texas, was formed in 1997 through the consolidation of ,

the separate power and natural gas trading functions previously operated by companies owned or acquired by PG&E Corporation.

We purchase bulk volumes of power and natural gas from our affiliated companies - U.S.

Generating and PG&E Gas Transmission - and from the wholesale market. We then schedule, transport, and resell these commodities, either directly or through our retail affiliate, PG&E Energy Services -

repackaging them to meet customers' individual delivery, price, and reliability needs. We also provide risk management services to PG&E Corporation's other unregulated businesses and to wholesale customers.

PG& E Energy Trading has emerged as a significant participant in the U.S. wholesale natural gas and electricity marketplace. With trading floors in llouston, Bethesda, and Calgary - staffed by more than 150 professionals - we meet the energy commodity needs of more than 500 wholesale customers.

During 1997, PG&E Energy Trading successfully combined the best practices of a series of previously separate trading organizations, and built a strong team of talented professionals. We are now positioned to provide innovative products to satisfy customers throughout North America, leveraging the energy portfolio created by PG& E Corporation's other unregulated businesses.

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y Selected Financial Data (in millions, except per share ernounts) 1997 1996 1995 1994 1993 PGaiE C o rp o ra tio n'"

For the Year Operating revenues $15,400 $ 9,610 $ 9,622 $10,350 $10,550 Operating income 1,728 1,896 2,763 2,424 2,560 Net income 716 722 1,269 950 1,002 Earnings per common share 1.75 1.75 2.99 2.21 2.33 Dividends declared per common share 1.20 1.77 1.96 1.96 1.88 At Year End flook value per common share 5 2!,30 5 20.73 $ 20.77 5 20.07 $ 19.77 Conunon stock price per share 30.31 21.00 28.38 24.38 35.13

'Ibtal assets 30,557 26,237 26,871 27,738 27,234 1,ong-term debt (excluding current portions) 7,659 7,770 H,049 8,676 9,292 Itate reduction bonds (excluding current portions) 2,776 - - - -

Preferred stock and securities of subsidiary with mandatory redemption provisions (escluding current portions) 437 437 437 137 75 Pacific Gas and Electric Company For the Yeer Operating revenues S 9,495 $ 9,610 S 9,622 $10,350 $10,550 Operating income 1,831 1,H96 2,763 2,424 2,560 Income available for common stock 735 722 1,269 950 1,002 At Year End

'Ibtal assets $25,147 $26,237 $26,871 $27,738 $27,234 1,ong-term debt (excluding current portions) 6,218 7,770 H,049 H,676 9,292 Rate reduction bonds (excluding current portions) 2,776 - -- - -

Preferred stock and securities with mandatory redemption provisions (excluding current portions) 437 437 437 137 75

" PG& E Corporation became the holding company for Pacific Gas and Electric Company on Jannary 1,1997. The Selected l'inancial Data of PGN E Corporation and Pacific Gas and Electric Company for the 3 ears 1991 through 1996 are identkal because the) represent the accounts of Pacific Gas and Electric Company as the predemsor of PG A E Corporation. See .\lanagementi Discuwinn and Analysn of Consolidated Results of Operations and l'inancial Cnndition for further dncuuion of the hohhng company formation and matters rel.ning to certain data ab.ne.

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Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition San Francisco-based PG& E Cor[mration provides ecergy Energy Services and Comrnodities: We provide customers senices throughout the United States and Australia. We nationwide with competitively-priced natural gas and elec-were formed as a holding company on January 1,1997, to tricity and senices to manage and make more efficient respond to new business opportunities and changes in the their energy consumption through PG& E Energy Senices energy industry. As a result, Pacific Gas and Electric Com- (PG& E ES).

pany became a subsidiary ofits new parent holding com. Through PG& E Energy Trading (PG&E ET), we pur-pany, PGN E Corporation, and its ow nership interest in its chase and resell energy commodities and related financial unregulated subsidiaries was transferred to PG&E Corpora- instruments in major domestic markets, serving PG&E tion. Under our new corporate structure, we provide inte- Corgmration's other unregidated businesses, unaffiliated grated energy senices through our various business lines: utilities, and large end-use customers.

Pscific Gas and Electric Company (Utility) Overview Our Utility provides gas and electric senice to Northern This is a combined annual report of PGAE Corporation and Central Cahfornia. Our Utility is regulated by the and Pacific Gas and Electric Company. Therefore, our California Public Utilities Connnission (CPUC), the Federal Atanagement's Discussion and Analysis of Consolidated Energy Regulatory Commission (FERC), and the Nuclear Results of Operations and Financial Condition apply to both Regulatory Commission, among others. PG& E Corporation and the Utility. PG& E Corporation's consolidated financial statements include the accounts of Unregulated Business Operations PG&E Corimration and its wholly owned and controlled We provide a wide range ofintegrated energy products and subsidiaries, including the Utility (collectively, the senices designed to take advantage of the opening of the Corporation). Our Utility's consolidated financial state-competitive energy marketplace throughout the United ments include its accounts as well as those ofits w holly States. Through our other subsidiaries, we provide the fol- owned and controlled subsidiaries. Ilecause PG& E Corpora-lowing energy senices: tion did not become the holding company for the Utility untilJanuary 1,1997, the 1995 and 1996 consolidated finan-Gas Transmission: We own and operate approximately cial statements represent the accounts of the Utility on a 10,000 miles of natural gas pipelines, natural gas storage consolidated basis as predecessor of PGA E Corporation, facilities, and natural gas processing plants in the Pacific Alanagement's Discussion and Analysis shouhl be read in Northwest, Texas, and Australia through PG&E Gas conjunction with the consolidated financial statements.

Transmission (PG& E GT). PG& E GT's Pacific Northw est in Alanagement's Discussion and Analysis, we explain the operations are regulated by the FERC, and its Texas opera- results of operations for the years 1995 through 1997 and tions are regulated by the Texas Railroad Conunissmn. discuss our financial condition. Our discussion of financial condition includes:

Electric Generation: We deselop, build, operate, own,

• energy industry restructuring and how this restructuring and manage power generation facilities across the United will influence future results of operations.

States through U.S. Generating Company (USGen). In 1998,

• liquidity and capital resources, including discussions of USGen expects to complete the acquisition of the New capital financing activities, estimated capital spending for F.ngland Electric System fossil fuel and hydroelectric p<mer the next three years, and uncertainties that could affect plants. This acquisition is discuwed further in the future results, and l l

Acquisitions and Sales section below.

• risk management activities. l 17  ;

.j

Management's Discussion and Analysis of Consolidated Results of Operations.and. Financial Condition This combined annual report, including our Letter to The following table shows our results of operations and Shareholders above and our discussion of results of opera- total assets for 1997,1996, and 1995. The results of opera-tions and financial condition below, contains forward-look- tions for PG&E Corporation on a stand-alone basis and ing statements that involve risks and uncertainties. Also, intercompany climinations have been shown as Corporate words such as " estimates,"

• expects," " anticipates," " plans," and Other.

co,w.i.

" believes," and similar expressions identify forward-h>oking un,.v..n.w so o. .no uwv on. con. om., w statements involving risks and uncertainties.

These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric and gas indus- 1997 Operating revenues S 9,495 56,351 5(46) $15,400 tries, the outcome of the regulatory proceedings related to 13,67.,

Operau.ng expenses i, 664 6.433 (425) those restructurings, our Utility's ability to collect revenues Operating income (loss) sufficient to recover transition costs in accordance with its before income taxes S 1.831 $ (H2) $ (21) $ 1,728 cost recovery plan, the impact of our recent or planned income available for acquisitions as discussed in the Acquisitions and Sales sec- common stock $ 735 $ H $ (27) $ 716 tion below, the approval of our Utility's 1999 General Rate li,tal assets $25,147 56.224 5 (814) S30.557 Case application resulting in the Utility's ability to earn its 1996 authorired rate of return as discussed in the Letter to operating revenues s 8,989 s 679 S (58) S 9,610

,19 595 (60) 7,714 Sharehohlers above and in the Regulatory Activity section Operatfng expenses helow, and our ability to successfully compete outside our f, "" " ""'#

_, g ggg g g g g g9 traditional regulated markets, as discussed in the Letter to Income available for Shareholders above. The ultimate impacts on future results common stock s 707 s 15 5 - S 722 ofincreased competition, the changing regulatory emiron- li,tal assets $23,567 $2,858 5 (188) 526.237 ment, our expansion into r.ew businesses and markets, and 1995 the CPUC's decision on the 1999 General Rate Case appli. Operanng revenues S 9,243 5 447 5 (68) $ 9,622 perating expenses 6.556 376 C3) 6,859 cation are uncertain, but all are expected to fundamentally U P **I"F I "C"**

change how we conduct our business.The outcome of $ 71 5 2,763 before income taxes S 2.687 5 5 these changes and other matters discussed below may cause income available for future results to differ materially from historic results, or common stock $ 1.210 5 59 $ - 5 1.269 from results or outcomes currently expected or sought by Thtal assets $24,689 S2,578 $ (396) $26,871 PG& E Corporation.

Earnings Per Common share: Ilasic and diluted earn-Results of Operations ings per common share were $1.75, $1.75, and $2.99 for in this section, w e provide the components of our earnings '

. 1997,1996, and 1995, respectively. Earnings per common for 1997,1996, and 1995. We then explam. why operatmg share were affected by the activity discussed below.

revenues and expenses for 1997 and 1996 were different from the year before.

IN L

I i

l Ut/lity Results: to gas revenues was offset by a corresponding revenue 1997 COMPARED TO 1996 decrease ordered in the 1996 General Rate Case.

Our Utility operating revenues in 1997 increased $506 mil- Our Utility operating expenses increased $623 million in lion from 1996. The largest portion of the increase was due 1996 primarily due to charges for gas transportation com-to transition cost recovery related to the revisions in the mitments, increases in gas and purchased power prices, Diablo Canyon Nuclear Power Plant (Diablo Canyon) increases in expenses related to transmission and distribu-retemaking structure discussed in Electric Transition Plan tion system reliability, and increases in litigation costs.

below. A portion of the increase is due to increased revenues o associated with electric transmission and distribution system Unregulated Business Results:

reliability auth6rized by California Assembly Ilill 1890, 1997 COMPARED TO 1996

' the electric industry restructuring legislation. There was Our unregulated business operating revenues in 1997 also an increase in energy cost revenues to recover energy increased $5,672 million from 1996. This was primarily

. cost increases and changes in sales volume provided by our due to a $4,524 million increase in energy commodities and Utility's energy rate recovery mechanism. Under energy senices revenues from the acquisitions of Energy Source rate recovery mechanisms, energy rate revenues generally (ES) in December 1996, Teco Pipeline Company (Teco) equal energy costs and, thus, increases in the cost of energy in January 1997, and Valero Energy Corporation (Valero)

' do not affect operating income. inJuly 1997. Also contributing to the increase were the Our Utility operating expenses in 1997 increased $485 new revenues from the gas pipeline operations of Teco

' million from 1996. The increase was due primarily to the and Valero.

increase in Diablo Canyon depreciation (w hich provided the Our unregtdated business operating expenses in 1997 revenue increases discussed above for recovery of the increased $5,838 million from 1996 which essentially increased depreciation) and the increase in cost of energy. reflects the increase in the cost of gas for resale due to the This increase was partially offset by a decrease in exp:nses above acquisitions and our expansion into the energy com-for several 1996 one-time charges associated with gas trans- modities and services industry.

. portation commitments and a 1996 one-time charge due to Other income increased in 1997 compared to 1996 a litigation reserve. primarily due to the gain on the sale ofInternational Other income increased in 1997 compared to 1996 pri- Generating Company, Ltd. which was partially offset by marily due to a gain on the buyout of a long-term contract write-downs of certain nonregulated investments.

for gas transportation service.

1996 COMPARED TO 1995 1996 COMPARED TO 1995 Our unregulated business operating revenues and operating Our Utility operating revenues in 1996 decreased $254 expenses in 1996 increased $232 and $219 million, respec-million from 1995 due to revenue reduction: ordered in the tively, from 1995 primarily due to the purchase of ES in 1996 General Rate Case. The revenue decrease was also due December 1996. This purchase created $283 million of to a decline in the Diablo Canyon generation price, as pro- revenue but was offset by an increase in the cost of gas vided in the Diablo Canyon rate case settlement. This lower for resale. The increase in both operating revenues and

. generation price was partially offset by higher net genera- operating expenses was partially offset by a decrease due

. tion, which was a result of fewer scheduled refuelings in to the sale of DALEN Corporation in 1995.

' 1996 compared to 1995 We maintain an automatic adjust- Other income decreased in 1996 compared to 1995

. ment clause (Gas llalancing Account) pursuant to which primarily due to write-downs of certain nonregulated

1996 revenues were increased to reflect the increase in gas . investments in 1996.

/ prices in 1996 as compared to 1995. Ilowever, this increase 19

Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition Common Stock Dividend: Our conunon stock dividend that all generators have comparable access. California utili-is based on a number of financial considerations, including ties will retain ownership of utility trannnission facilities sustainability, financial flexibility, and competitiveness with but will relinquish operating control to the 150. Competing investment opportunities of similar risk. Our current quar- electric providers will bid their electric commodity into terly conunon stock dividend is $.30 per wmmon share, the PX.The PX will accept the lowest bids to satisfy the which corresponds to an annualized dividend of $1.20 per aggregate electric demand and establish a market price.

conunon share. Customers choosing to buy power directly from non-regu-The CPUC set a number of conditions uhen PG&E lated generators or retailers will pay for that generation Corporation was formed as a holding company. One of based upon negotiated contracts. The PX and Iso are these conditions requires our Utility to maintain, on aver- expected to be operational by March 31,1998.

age, its CPUC-authorized capital structure, potentially limit- CPUC regulation requires our Utility to purchase all elec-ing the amount of dividends our Utility may pay PG&E tric power for its retail customers from the PX. And, we must Corporation. At December 31,1997, our Utility was in bid all of our Utility-generated electric power to the PX.

compliance with its CPUC-authorized capital structure. We Generation resenues currently make up approximately believe that our Utility will continue to meet this condition 30 percent of our total Utility revenues. The competitive in the future without affecting our ability to pay conunon market environment will significantly change the way our stock dividends to common shareholders. Utility earns revenues. Over the past several years, w e have been taking steps to prepare for these changes. We have Financial Condition been working with the CPUC to ensure a smooth transition We begin this section by discussing the energy industry. into the competitive market environment. And, we have We also discuss how the Corporation is resimnding to made strategic investments throughout the nation that will restructuring on a national level, including recent and further position us as a national energy provider. The fol-planned acquisitions. We then discuss liquidity and capital lowing sections discuss the transition plan. A discussion of resources and our risk management activities. the investments w e have made is included in Our Response to Changes in Our Industry, below.

Energy Industry:

The Electric Business: ELECTRIC TRANSITION PLAN California has been in the forefront of the nation's move In the new competitive market, our Utility's generation rev-towards competitive energy markets. In 1998, Californians enues uill be determined principally by the market through will be able to choose who will provide their electric power. sales to the PX. Ilowever, market-based revenues may not Customers within our Utility's service territory can purchase be sufficient to reem er (that is, to collect from customers) electricity (1) from our Utility,(2) from retail electricity all generation costs resulting from past CPUC decisions.

providers (for example, marketers including our energy 'Ib recover these uneconomic costs, called " transition costs,

senice subsidiary, brokers, and aggregators), or (3) directly and to ensure a smooth transition to the competitive envi-from unregulated power generators. Our Utility will con- ronment, our Utility in conjunction with other California tinue to provide distribution services to substantially all electric utilities, the CPUC, state legislators, consumer advo-electric consumers within its service territory, cates, and others, developed a transition plan, in the form of

'Ib create this competitive generation marker, California state legislation, to position California for the new market has established a Power Exchange (PX; and an Independent environment.

Systems Operator (Iso). The PX will be an open electric marketplace w here electricity prices are set. The Iso will oversee California's electric transmission grid making sure 20 k _ _ _ __ _ .

There are three principal elements to this transition plan: included in our Utility customers' electric rates) and future

' (1) an electric rate freeze and rate reduction, (2) recovery costs, such as costs related to plant removal, (2) costs asso-

'of transition costs, and (3) economie divestiture of Utility- ciated with the Utility's long-term contracts to purchase owned generation facilities. Each one of these three ele- power at above-market prices from Qualifying Facilities ments, the impact of the transition plan on our Utility's (QF) and other power suppliers, and (3) generation-related customers, and the impact of the transition plan on our regulatory assets and obligations. (In general, regulatory application of Statement of Financial Accounting Standards assets are expenses deferred in the current or prior periods (SFAS) No. 71, " Accounting for the Effects of Certain Tvpes to be included in rates in subsequent perkxis.) Transition of Regulation," are discussed below, The transition plan costs that are disallowed by the CPUC for collection fmm will remain in effect until the earlier of March 31,2002, or Utility customers will be written off. Each of the types of when we have recovered our authorized transition costs as eligible transition costs are discussed below.

determined by the CPUC.This period is referred to as the Sunk costs associated with Utility-owned generation transition period. At the conclusion of the transition period, facilities are currently included in our Utility customers' we will be at risk to recover any of our Utility's remaining rates. Above-market sunk costs are those whose values generation costs through market-based revenues. recorded on our balance sheet (book value) are expected to be in excess of their market values. Conversely, below-mar-

• Rate Freeze and Rate Reduction ket sunk costs are those whose market values are expected The first element of the transition plan is an electric rate to be in excess of their book values. In general, the total freeze ar,d an electric rate reduction. During 1997, electric amount of sunk costs to be included as transition costs will rates for our Utility's customers were hehl at 1996 levels. be based on the aggregate of above-market and below-mar-EffectiveJanuary 1,1998, we reduced electric rates for our ket values. The above-market portion of sunk costs is eligi-Utility's residential and small commercial customers by ble for recovery as a transition cost. The below-market t o percent and will hold their rates at that level. The rate portion of sunk costs will reduce other unrecovered transi-freeze will continue until the end of the transition period. tion costs. A valuation of Utility-owned generation facilities

'Ib pay for the 10 percent rate reduction, we financed where the market value exceeds the book value could result

$2.9 billion of our transition costs with rate reduction in a material charge if the Utility retains the facility. This is bonds.See Cash Flows from Financing Activities below. because any excess of market value over book value would be used to reduce other transition costs without being

• Transition Cost Recovery collected in rates.

The second element of the transition plan is recovery of We will not be able to determine the exact amount of transition costs. Transition cost recovery has five parts for sunk costs that will be recoverable as transition costs until a

. detennining: (1) uhich costs are eligible for reemery as market valuation pmcess (appraisal, spin, or sale) is com-transition costs,(2) when they can be recovered,(3) how pleted for each of our Utility's generation facilities. The first transition cost revenues will be determined, (4) how transi- of these valuations occurred in 1997 when we agreed to sell

tion costs will be expensed, and (5) what happens when tran- three Utility. owned electric plants for $501 million.The sition cost revenues differ from the related expenses. Each sale is expected to close during 1998. (See Generation of these five parts is disctissed below. Divestiture below.)The rest of the valuation process will be

' The first part of transition cost recovery is detennining completed by December 31,2001. At December 31,1997, which Utility costs are eli Fible for recovery as transition our Utility's net investment in Diablo Canyon and Utility-costs. These costs include: (1) above-market sunk costs owned non-nuclear generation facilities was $3.7 billion

- (sunk costs are costs associated with Utility-owned generat- and $2.7 billion, respectively, including the plants to be

' ing

facilitics that are fixed and unavoklable and currendy sold in 1998, 21 L s

Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition Our Utility has agreed to purchase electric power from purchase contracts discussed above, and 0) unrecovered QFs and other power suppliers under long-tenn contracts electric industry restructuring implementation costs. In expiring on various dates through 2028. Over the hfe of addition, transition costs fmanced by the issuance of rate these contracts, the Utility estimates that it will purchase reduction bonds are expected to be recovered over the term appnnimately 360 million megawatt-hours (.wh) at an of the bonds. Further, the Utility's nuclear deconunissioning aggregate average price of 6.3 cents per kilowatt-hour costs are being recovered through a CPUC-authorized (kWh). To the extent that this price is above the market charge, w hich will extend until sufficient funds exist to price, our Utility will be able to collect the difference decommission the facility. During the rate freeze, this between the contract price and the market price from cus- charge will not increase our Utility customers' electric rates, tomers, as a transition cost, over the tenn of the contract. Excluding these exceptions, we will write-off any transition In addition, a i of December 31,1997, we have accumu- usts not recovered during the transition period.

lated approximately $1.5 billi<m of generation-related net The third part in transition cost recovery is detennining regulatory assets. The net regulatory assets are eligible for the amount of electric utility revenues under frozen rates recovery as transition costs. that are availabh: to recover eligible transition costs. As The CPUC has the ultimate authority to detennine directed by th: CPUC, we have separated, or unbundled, the which costs are eligible to be recovered as transition costs. Utility's previously authorized cost-of-senice electric rev-Reviews by the CPUC to detennine the reasonableness of enues into separate categories. Unbundling enables us to transition costs are being conducted and will continue to be allocate revenue provided by frozen electric rates into trans-conducted throughout the transition period, mission, distribution, public purpose programs, and genera-The second part of transition cost recovery is detennin- tion based upon their respective cost of senice. Revenues ing w hen eligibic transition costs can be recosered. Under prmided by frozen rates will also be used to recover other the transition plan, most transition costs must be recovered authorized Utility costs, including nuclear decommis-by March 31,2002. This rccovery period is significantly sioning, rate reduction bond debt senice, and transition shorter than the recovery period of the related assets prior cost recovery.

to restructuring. Recovery of transition costs during this The portion of the unbundled revenue to be provided for shorter period is referred to as accelerated recovery. The transition cost recovery is based upon mechanisms approved CPUC believes that acceleration reduces risks associated by the CPUC. Revenue prmided for recovery of most non-with recovery of all our Utility's generation assets, including nuclear transition costs is based upon their acceleration Diablo Canyon and hydroelectric facilities. As a result,in within the transition period. For nuclear transition costs, accordance with the transition plan, we are receiving a resenues provided for transition cost recovery are based on:

reduced return for all of our Utility-owned genetation (1) an established Incremental Cost Incenthe Price per facilities. In 1997, the reduced return was 7.13 percent as LWh generated by Diablo Canyon to recover certain ongo-compared to an authorized return of 9.45 percent. The ing costs and capital additions, and (2) the acceleration of .

reduced return on non-nuclear generation assets, effective our investment in Diablo Canyon from a period ending in July 28,1997, resulted in a $24 million decrease in earnings 2016 to a five-year period ending December 31,2001.

($0.06 per share)in 1997 and will have a continued impact The fourth part of transition cost recovery addresses the throughout the transition period. depreciation and amortization of transition costs. Based on Although most transition costs must be recovered by our Utility's evaluation of the transition plan and state legis-March 31,2002, certain transition costs can be included in lation and CPUC decisions related to the transition plan, our customers' electric rates after the transition period. These Utility is depreciating Diablo Canyon over a five-year period costs include: (1) certain employee-related transition costs, ending December 31,2001. The change in depreciable life

- (2) above-market payments under existing QF and power- increased Diablo Canyon's depreciation expense for 1997, as l 21 t

1 i

compared to 1996, by $583 million. In addition, most gener _ California utilities produced a siF nificant portion of the l

~ ation-related regulatory assets are behig amortized on a state's electric generation needs. In a cmnpetitive market,

< straight-line basis la accordance with their recovery under the CPUC is concerned that this level of generation may  ;

- the tramition plan, beginningJanuary 1,1998. Further, ugmn give existing utilities undue influence on the PX price.

i valuation of gem ration facilities, any losses will be amortized As part of the transition plan, we have agreed to sell a over the remaining transition period as a transition cost. Any significant portion of our generation facilities to alleviate gains will be recognized and used to reduce other transition this concern.

costs at the time of valuation in 1997, we agreed to sell three electric Utility-owned in the fifth part of transition cost recovery we compare fossil-fueled generating plants to Duke Energy through an (1) revenues provided for transition cost recovery with auction process.The aggregate bid accepted for these plants (2) the costs associated with accelerated recovery including was $501 million. These three fossil-fueled plants have a the depreciation of Diablo Canyon and the amortization combined lumk value at December 31,1997, of approxi-of regulatory assets. If the revenues exceed the accelerated mately $370 million and a combined capacity of 2,645 ests, certain transition costs may be further accelerated megawatts (MW). The three power plants were Alorro llay, until all tramition costs are recmcred or Alarch 31,2002, Atoss Landing, and Oakland, whichever is earlier, if the accelerated costs exceed the rev- The sales have been approved by the CPUC. Ilowever, enues, the costs will be deferred. At the end of the transition they are still subject to approval of the transfer of various  ;

(

period, any overcollection of these amounts will be returned permits and licenses. Additionally, the Utility will retain to customers. liability for required emironmental remediation of any pre-Our Utility's ability to recover its transition costs during closing soil or groundwater contamination at these plants.

the transition period will be dependent on several factors. As a result of retaining such en ironmental remediation lia-These factors include:(1) the continued application of bility, we do not expect any material adverse impact on the

- the regulatory framework established by the CPUC and state Utility's or our financial position or results of operations.

legislation,(2) the amount of transition costs approved by We expect the sale of these three plants to close in 1998, the CPUC,(3) the market value of our Utility-owned gener- We plan to conduct another auction of our four remain-

. ation facilities,(4) future Utility sales levels,(5) future ing Utility-owned fossil-fueled plants and our Utility-owned Utility fuel and operating costs. (6) the extent to w hich our geothermal facilities in the first half of 1998. These addi-Utility's authorized revenues to recover distribution costs tional plants have a combined generating capacity of 4,718 are increased or decreased, and (7) the market price of elec- MW and a combined book value at December 31,1997, of tricity. Given our current evaluation of these factors, we appmsimately $790 million.

believe that we will recover our transition costs. Also, we '1bgether the eight power plants represent 98 percent of

believe that our regulatory assets and Utility-owned genera- the Utility's fossil-fueled generating capacity and all of the tion plants are not impaired. Ilowever, a change in one or Utility's geothermal generating capacity. The eight plants more of these factors could affect the probability of recovery currently generate appmximately 22 percent of the Utility's of transition costs and result in a material charge. total electric sales. The Utility is currently evaluating its During 1997, th'e difference between billed revenues and options related to its remaining generation facilities and authorized revenues was used to recover transition costs, _ may decide not to retain its economic invesunent in those including most of the accelerated Diablo Canyon sunk costs. facilities. During the transition period, the proceeds from the sale of our plants will be used to offset transition costs

~* Generation Divestiture associated with other Utility electric generation facilities.

The third element of the transition plan is the economic Therefore, we do not expect any material adverse impact on

' divestiture of Utility 7 owned generation facilities. In 1997, the Utility's or our financial position or results of operations 23

Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition from any of these divestitures. is derived. Under the transition plan, generation-related

.. regulatory assets are eligible for recovery as transition costs

• C,ustomer impacts of.I.ransitmn Plan fnnn customers of our Utihty's electrie distribution busi-Under the transition plan, once the PX and Iso are opera-ness. Accordingly, they have been allocated to that business.

tmnal, all electric customers may choose their electric com-As we believe the recovery of our transition costs from these modity provider. During the transition period, all customers

. . customers is probable, the discontinuation of application wd. l be billed for electricity used, for transmission and distn-of SFAS No. 7I to our Utility's generation business did not bution senices, for public pur[nse programs, and for recov-have a material effect on our financial statements. As of cry of transition costs. Customers u ho choose to purchase December 31,199/, we have recorded approximately $1.5 their electricity from non-Utility energy providers w. dl see a billion of generation.related regulatory assets.

change m. their total bill only to the extent that their con-

. . Given the current regulatorv environment, our Utility's tracted electne commodity price differs from the PX 1,nce.

electric transmission business and most areas of the Utility's Transioon costs are being recovered from all Utility distn-electric distribution business are expected to remain rate bution customers through a nonbypassable charge regard- ,

regulated and, as a result, we wdl continue to apply the less of the.ir chm.ce m commodity provider. As transition provisions of SFAS No. 71. Ilowever, as discussed above, costs are nonbypassable, we do not believe that the availabil-once the ISO and PX are operational, unregulated electric ny of choice to our customers uill ha$e a material u.npact on providers may provide their customers with billing and our ability to recover transition costs.

in addition to supplying conunodity electric pow er, metering services. In the future, electric providers may be

. allowed to provide other distnbution services (such as cus-once the Iso and PX are operational, commodity electne tomer inquiries and uncollectibles). Any discontinuance of providers will be able to choose the method of billing their si As No. 71 for these portions of our Utiliry electric distri-customers and w hether to provide their customers with bution business is not expected to hase a material adverse metering services. M.e w d. i track cost mings that result impact on the Utility's or our fmancial position or results u hen billing, metering, and related senices within our of operations.

Utility's senice territory are pnivided by another entity.

Once these cost savings, or credits, are approved by the The Gas Business:

CPUC and the customer's energy provider is perfonning

,Through our Utih.ty, we sell natural gas and provide natural billing and metering services, we will reduce the customer's gas transportation senices to our customers. C,urrently, our bill by the savings. The electric provider will then charge .

, , customers inay buy gas dFeetly flom competing suppliers their customers for these sen1ces.10 the extent that these and purchase gas transmission- and distribution-only ser-credits equate to our actual cost sasings from reduced vices fnnn us. Our Utility transmission system transports billing, metering, and related senices, we do not expect a gas thnmghout Cabfornia to our distribution system which, material adverse impact on the Utility's or our fmancial in turn, dehvers gas to end.use customers. Utility transmis-condition or results of operau. ons.

sion and distribution senices for all customers have histori-

• The Transition Plan and SF.% No. 71 cally been " bundled" or sohl together at a combined rate.

In 1997, to comply with new accounting guidance, w'e dis- Est of our industrial and larger commercial (noncore) cus-l continued the application of SFAs No. 71 for the generation romers purchase their commodity gas fnnn marketers and l portion of our Utility business. The new accounting guid- brokers. Substantially all residential and smaller conunercial j ance requirts that regulatory assets and liabilities (both (core) customers huy their conunodity gas as well as trans- I those in existence today and those created under the tenns mission and distribution senices from us In order to ensure of the transition plan) be allocated to the iurtion of the competitive prices for our customers, we negotiate short-business from uhich the source of the regulated cash flows tenn supply arrangements uith numerous providers.

24

Restructuring of the natural gas industry on both the our Utility and various other parties. Resolution of these national and the state level has given choices to California issues did not have a material adverse impact on the utility customers to meet their gas supply needs. The Utility's or our financial position or results of operations.

. Gas Accord Settlement (Accord), a multi-party settlement approved by the CPUC in 1997, continues the process of The Accord also establishes gas transmission rates for the restructuring the gas industry in California.The Accord is period from Alarch 1998 through December 2002 for our expected to be implemented in Alarch 1998. Alore speciG- Utility's core and noncore customers and climinates regula-cally, the Accord has four principal elements: tory protection for variations in sales volumes for noncore 1.The Accord separates or "unbundles" the rates for our transmission revenues. As a result, we will be at risk for Utility's gas transportation system. Once the Accord is variations between actual and forecasted noncore transmis-implemented, we will offer transmission and distribution sion throughput volumes. However, we do not expect these services as separate and distinct senices to our noncore variations to have a material adverse impact on the Utility's cmtomers. Unbundling will give these customers the or our financial position or results of operations. Rates for opportunity to select from a menu of services offered by distribution senices will continue to be set by the CPUC the Utility and will enable them to pay only for the ser- and designed to provide us an opportunity to recover our vices that they use. Unbundling will aho make access to costs of senice and include a return on our investment.

J the transmission system possible for all gas marketers and shippers, as well as noncore end-users. As a result, the Our Responu to Changrs in Our Industry:

Accord will make our Utility's transmission system more ACQUISITIONS AND SALES accessible to a greater number of customers. Over the past several years, we have taken steps to take 2.The Accord increases the opportunity for our Utility's advantage of the changing electric and gas markets and to core customers to select the commodity gas supplier of become a national energy company. In order to accomplish this, we have made several investments to position ourselves k their choice. Greater customer choice will increase com-petition among suppliers providing gas to core customers to expand and to integrate in the gas transmission market, and will reduce our role in purchasing gas for such cus- the energy trading market, the retail energy senices market, tomers. Despite these changes, we will continue to pur- and the unregulated electric generation market.These chase Fas as a regulated supplier for those who request it. investments are highlighted below.

3. The Accord changes the way in w hich our Ursty's costs in 1997, we created a gas transmission business in Texas, of purchasing gas for core customers through 2002 are through the acquisitions of'feco Pipeline Company (Teco) regulated. Prior to 1994, we were authorized to collect all and Valero Energy Corporation's (Valero) natural gas and costs of purchased gas through rates as long as the CPUC natural gas liquids business. Teco was acquired for appmxi-deemed the costs to be reasonable.The Accord replaces mately $378 million, consisting of $317 million of PG&E the CPUC reasonableness re iews with the core procure- Corporation common stock and the purchase of a $61 mil-

' ment incentive mechanism (CPIA1), a form ofincentive lion note. Valero was acquired for approximately $1.5 bil-g ratemaking. Apart from a " tolerance band" constructed lion, consisting of 31 million shares of PG&E Corporation

. around market benchmarks, the CPIA1 will reward us if common stock along with the assumption of approximately we are able to buy gas for our core customers at a price . $780 million in long-term debt. Valero pipeline operations below a speciGed market index price and penalize us if we have averaged approximately $147 million in revenues and buy gas at a price above the market index price. Actual expenses each month since August 1997.Teco pipeline

core procurement costs measured from 1994 through operations have averaged approximately $6 million in rev-1997 have generally been within the cpl.\1 tolerance band. enues and expenses each month sinceJanuary 1997.

4.The~ Accord settled various regulatory issues involving Further,in 1997, we strengthened our presence in the

~

, 25 .;

.. .. . . . _ _ _}

Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition unregulated electric generation market. We completed our Our national energy strategy does not currently con-acquisition of our partner's interests in three U.S. template continued investment in international generation Generating Company (USGen) partnerships w e previously projects. Therefore, in 1997, we sold to flechtel our interest jointly owned with Bechtel Enterprises, he. (llechtcl). We in International Generating Company, Ltd., a joint venture are now the sole owner of USGen, the largest independent between PG& E Corporation and Bechtel, together with all power developer and manager operating in the United of our related project interests. The sale has resulted in an States, U.S. Operating Sen-ices Company, USGen's opera- after-tax gain of approximately $120 million, which u as tions and maintenance affiliate, and its power marketing recorded in 1997.

af61iate USGen Power Services, LP. Additionally, we have acquired all or part of Hechtel's interest in several power REGULATORY ACTI\ TIT projects that are affidiated with USGen. Through its afGli- This section discusses items affecting future Utility ates, USGen has ownership or management interests in 15 authorized revenues: the 1999 General Rate Case; a 1998 electric generating facilities operating in eight states. Revenue Adjustment associated uith the electric transition Additionally,in 1997, USGen was selected to buy a port- plan,' discussed above; and the 1998 Cost of Capital folio of electric generating assets and power supply contracts Proceeding. Any requested change in authorized electric from the New England Electric System (NEES) for $1.59 revenues resulting from any of these proceedings would not billion, plus $85 million for early retirement and sever- impact our Utility's customer electric rates because these ance costs previously committed to by NEES. Including rates are frozen in accordance with the electric transition fuel and other inventories and transaction costs, Onancing plan. How ever, increases in authorized electric revenues requirements are expected to total approximately $1.75 would reduce the amount of revenue available to reem er billion, of w hich appmximately $1 billion will be funded transition costs.

through a combination of project level debt as well as debt of USGen. In addition, $750 million of equity will be con-

• The Utility's 1999 General Rate Case (GRC) tributed over two years and will be financed initially using in December 1997, we filed our 1999 GRC application with short-term debt of PG&E Corporation. The assets contain the CPUC. During the GRC process, the CPUC examines a balance of hydro, coal, oil, and natural gas generation our Utility's non-fuel relates' costs to determine the amount facilities. The acquisition is subject to regulatory approval, we can charge customers. In our application, we requested among other conditions. We expect the acquisition to be an increase in our Utility's authorized revenues, effective completed in the second half of 1998. January 1,1999. The requested increase consists of an Maximizing the benefits of the gas transmission, electric increase of $693 million in electric utility resenues and an generation, and energy senice supply businesses on a increase of $501 million in gas utility revenues over autho-national level requires procurement, scheduling, and risk rized 1997 revenues.

inanagement capabilities. In order to assure the efneient The 1999 GRC will not affect the authorized revenues of management of the risks and rewards of supplying our cus- electric and gas transmission senices or of gas storage ser-tomers' energy needs and to optimize our corporate assets, vices. The authorized revenues for each of these senices are we have combined the trading and risk management busi- determined in other proceedings.

nesses of Energy Source (acquired in 1996), Teco, and Electric transmission revenues for 1998 are expected to Valero to form PG&E Energy Trading (PG&E ET). PG&E be authorized by the FFRC. In 1997, we filed an application

- ET purchases and resells energy conunodities and related with the FERC requesting electric transmission revenues financial instruments in major domestic markets, sening of $305 million. The requested rever.uc is consistent with PG& E Corporation's other unregulated businesses, unaffili- electric transmission revenues in CPUC-authorized 1997 sted utilities, and large end-use customers, electric rates. The FERC-authorized rates will be effective 26 t

once the Iso and PX are operational. Cash from operations exceeded capital requirements for -

' Also, revenues associated with gas transmission and stor- all years presented.

age services were authorized as part of the Gas Accord. See Gas Ilusiness, above, for a discussion of the Gas Accord. Cash Flers from Financing Acrivitics:

PG&E CORPORKrlON iThe Utility's 1998 Electric Revenue Adjnstment During 1997, we issued $752 and $317 million of common The electric transition plan (see Electric Ilusiness above) stock to acquire Valero and Teco, respectively. These allows for increases in rnenues previously authorized in the acquisitions did not require the use of cash. We also issued 1996 GRC for system safety and reliability. The CPUC $54 million of common stock through the Dividend increased 1997 authorized revenues for these services by Reinvestment Plan and the employee Long-Term incentive

$160 million. %c CPUC also authorized an additional $86 Plan. Also in 1997, we repurchased $804 million of our million in 1998 for system safety and reliability. common stock on the open market and paid dividends of

$524 million.

~

• The Utility's 1998 Cost of Capital Proceeding During 1996 and 1995, we issued $220 and $140 million The CPUC authorized a cost of capital for the Utility's gas shares of common stock, respectively, through the employee and electrie distribution assets in 1998 of 9.17 percent. The Savings Fund Plan, the Dividend Reinvestment Plan, and authorized 1998 cost of common equity is 11.20 percent the employee Long-Term Incentive Plan. In 1996, we which is lower than the 11.60 percent authorized for 1997. repurchased $455 million shares of our common stock and The CPUC contends that this decrease reflects the level of paid dividends of $844 million. In 1995, we repurchased business and regulatory risks the Utility now faces. The $601 million shares of our common stock and paid divi-authorized cost of capital will decrease 1998 authorized dends of $H91 million.

electric and gas revenue by approximately $25 million and in previous years, the lloard of Directors (floard) autho-

$9 million, respectively.The Utility has requested a rehear- rized us to repurchase up to $2 billion of our common stock ing of the Cost of Capital decision. We believe that business on the open market or in n gotiated transactions. In 1997, and regulatory risks have not been reduced and that our the lloard increased this authorization to a total of $4 bil-requested cost of common equity of 12.25 percent is more lion. Through December 31,1997, the Corporation had appropriate.The rehearing is expected to occur in 1998. repurchased approximately 52.3 billion ofits common stock Consistent with the rate freeze, there will be no change under this program. As part of this 11oard authorization,in in electric rates in 1998 and the low er authorized reve- January 1998, the Corporation entered into a specific trans-nues will be offset by additional transition cost recovery, action to repurchase 37 million shares of common stock at As discussed above, the CPUC separately reduced the autho- $30.3125 per share. In connection with this transaction, the rized return on our Utility's electric generation.related Corporation has entered into a forward contract with an assets to 7.13 perrent. Also, the return on our Utility's elec- investment institution. The Corporation will retain the risk tric transmission-related assets will be determined by the ofincreases and the benefit of decreases in the price of the

~ Fl:RC in 1998. Finally, the return on our U'tility's gas trans- common shares purchased through the forward contract.

mission and storage businesses was incorporated in rates .This obligation will not be terminated until the investment established in the Gas Accord. institution has replaced the shares sold to the Corpration through purchases on the open market or through privately Liquidity and Capital Resources: negotiated transactions. The contract is anticipated to Cash Flows from Operating Activities: expire by December 31,1998.

Net cash pr ovided by operating activities totaled $2.6, inJanuary 1997, we established a $500 million revolving j

$2.6,'and $3.3 billion in 1997,1996,'and 1995, respectively.

credit facility, and iri August 1997, we entered into an  !

l 4

27

Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition additional $500 million tem;mrary credit facility. Iloth of and fixed interest rate pollution control mortgage bonds and these credit facilities are to be used for general corporate loan agreements u hich were replaced with variable interest purp>ses.There were no borrowings under these facilities rate imilution control loan agreements.

at December 31,1997. In December 1997, a subsidiary of the Utilityissued During 1997, our unregulated business operations issued $2.9 billion of rate reduction bonds through a special pur-

$ 'nillion and retired $109 million oflong-term debt. Also pose entity established by the California Infrastructure and in IW7, we assumed approximately $780 million oflong- Economic Development flankJrhe proceeds will be used by tenn debt in connection with the acquisition of Valero. the Utility to retire debt and reduce equity. The bonds will in 1996, we entered into additional loan agreements of facilitate a 10 percent rate reduction for residential and eli-

$92 million to finance the PG& E Gas Transmission acquisi- gible small commercial customers, effectiveJanuary 1,1998.

tion of assets in Queensland, Australia. During the term of the bonds, the Utility will collect from During 1995, our unregulated business operations issued its residential and small commercial customers a separate

$400 million of bonds,570 million of medium-term notes, nonbypassable charge on behalf of the special purpose entity and $109 million of commercial paper which is classified as to recover principal, interest, and related costs of the bonds.

long-term debt. Substantially all of the proceeds from the The bonds are secured by the separate charge, which does debt issued in 1995 were used to refinance outstanding debt. not belong to the Utility. The bonds are not secured by the The classification of conuuercial paper as long-term debt is Utility's assets. While the bonds are reflected as a long-term based on the availability of committed credit facilities expir- liability on our balance sheet, creditors of the Utility do not ing in 2000 and management's intent to maintain such have any recourse to revenues from the separate charge.

amounts in excess of one year. The Utility maintains a $1 billion revolving credit facility which expires in 2002. The facility may be extended annu-UTILITY ally for additional one-year periods utmn mutual agreement In 1997,1996, and 1995, our Utility redeemed or repur- betueen the Utility and the banks.There were no borrow-chased $225, $1,113, and $758 million, respectively, oflong- ings under this credit facility in 1997 or 1996, term debt to manage the overall balance of our Utility's The table below provides information about our debt capital structure. Long-tenn debt maturing during 1997, obligations and the rate reduction bonds at December 31,1997:

1996, and 1995 was not refinanced. l In 1997, our Utility issued $360 million of variable rate pollution control bonds and repurchased the same amount of fixed-rate pollution control bonds.

In 1996, our Utility repurchased $988 million of variable impacted maturity ttate 1998 1999 2000 2001 2002 Thereafter Totai

• Im mdhonst 1,ong-term debt 14xed rate $659 $294 5460 $330 $$15 $4,712 $6,970 Average interest rate 5.H% 6.3% 6.0% 7.8% 7.7% 7.2% 6.9%

Variable rate ' - - - - - $1,348 $1,348 Rate reduction bonds $125 5265 5280 $300 $290 $ 1,641 52.901 Average interest rate 5.9% 6.0% 6.2% 6.2% 6.3% 6.4% 6.3%

+The fair uhu ut kmg-term dela and rnic reductsen imenk m ewntully the ume as the lex,k salue. l 28

}

i 1

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i Cash Flowsfrom investing Activiti:s: Year 2000:

The primary uses of cash for im esting activities are additions in 1995, we began and presently continue to review and to property, plant, and equipment; unregulated invesunents assess our computer and information systems in anticipation in partnerships; and acquisitions. of the year 2000. At that time, our software programs and systems for critical financial and operational information Capital Spending will be required to recognize this date in the next millen-Our estimated capital spending for the next three years is nium. The Year 2000 issue exists because many computer shown below: programs use only two digits to identify a year in the date field and were developed without considering the impact of

w. .ao.o ou.a. n " " " the upcoming change in the century. We currently expect to

""'""" complete critical software conversion modifications by the Uuhty capital requirements $1,835 $1,739 51,617 ,

Other capital requirements 2,091 246 192 end of 1998. We do not currently anu,cipate any maternal Maruring debt obligations and adverse impact on the Utility's or our fmancial position or sinking funds 784 559 740 results of operations as a result of the Year 2000 issue.

'Etal $4,710 52,544 $2,549 Accounting for Decommissioning Expense:

Utility expenditures will be primarily for improvements In 1996, the Financial Accounting Standards Board issued to facilities to enhance their efficiency and reliability, to an Exposure Draft (ED) entitled " Accounting for Certain extend their useful lives, and to comply with environmental Liabilities Related to Closure and Removal of Long-Lived laws and regtdations. Assets." A revised ED is expected in 1998. If the ED is Other capital expenditures will be primarily for the pur- adopted as currently proposed:(1) annual expense for power chase of electric generating assets and power supply con- plant decommissioning could increase, and (2) the estimated tracts for NEES, discussed above in Acquisitions and Sales. total cost for power plant decommissioning could be recorded as a liability, with recognition of an increase in the Environmental 3latters: cost of the related pow er plant, rather than accrued over We are subject to laws and regulations established to both time as accumulated depreciation. We do not believe that improve and maintain the quality of the environment. this change, ifimpkmented as proposed, would have a Where our properties contain hazardous sulntances, these material adverse impact on the Utility's or our financial laws and regulations require us to remove or remedy the position or results of operations. (See Note 2 of Notes to effect on the environment. Consolidated Financial Statements for discussion of electric At December 31,1997, the Utility expects to spend $232 industry restructuring.)

million for clean-up costs at identified sites over the next 30 years, if other responsible parties fail to pay or identified 1,cgal Matters:

outcomes change, then these costs may be as much as $442 In the normal course of business, the Corporation and the million. Of the $232 million, the Utility expects to recover Utility are named as a party in a number of claims and law-

$157 million in future rates. The liability also includes $58 suits. Substantially all of these have been litigated or settled million related to power plant decommissioning for emi- with no material adverse impact on either the Utility's or ronmental clean-up, which the Utility recovered through our financial position or results of operations. See Note 13 depreciation. Additionally, the Utility is seeking recovery of of Notes to Consolidated Financial Statements for further

. smts from insurance carriers and from other third parties. discussion of significtmt pending legal marters.

(See Note 13 of Notes to Consolidated Financial Statements.)

29

a J

- Inflation: The fair value of market risk sensitive instruments Financial statements, which are prepared in accordance with (which includes our hedging and non-hedging instruments generally accepted accounting principles, reimrt operating described above) as of December 31,1997, is immaterial for results in tenns of historic costs and do not evaluate the financial instruments subject to commodity price risk.

impact ofinflation. Additionally, as of December 31,1997, the Corporation cal-Intiation affects our construction costs, operating culated value-at-risk based on a 95 percent confidence level expenses, and interest charges. In addition, the Utility's elec- using five-day holding periods. Using this methodology, the tric revenues will not reflect the impact ofinflation due to potential for near-term losses in future earnings, fair values, the current electric rate freeze. Ilowever, inflation at the and cash flows from reasonably possible near-term changes levels currently being experienced is not expected to have a in market in ices for financial instruments subject to com-material adverse impact on the Utility's or our financial modity pu s is immaterial.

position or future results of operations. We anticipate an increase in the level of trading and risk management activity in 1998 due to expected growth in our

' Price Risk Management: We have established an officer- unregtdated national energy businesses and a continuing level price risk management committee and adopted a price effort to manage enticipated price risks in our Utility busi-risk management policy approved by the Board for our trad- ness. Our Utility manages price risk independently from the ing and risk management activities. The price risk manage- activities in our unregulated businesses.

ment committee oversees implementation of our policy, approves the trading and price risk management policies of our subsidiaries, and monitors compliance with the policy.

Our price risk management policy allows derivatives to be used for both hedging and non-hedging purposes (a derivative is a contract uhose value is dependent on or derived from the value of some underlying asset). We use derivatives for hedging purposes primarily to offset under-lying commodity price risks. We also participate in markets using derivatives to create liquidity and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. Our price risk management policy and the trading and risk management policies of our subsidiaries prohibit the use of derivatives u hose payment formula includes a multiple of some underlying asset.

In 1997, we approved and implemented trading and risk' management policies for pG& E ET and continued to seek regulatory appnival to manage conunodity price risks

- in our Utility business.

30 r

PG&E Corporation Statement of Consolidated Income On millions. except per share amounts) Year ended December 31, 1997 1996 1995 Operating Revenues Utility S 9,495 $8,989 59,243 Energy commodities and senices 5,905 621 379 Total operating revenues . 15,400 9,610 9,622 Operrating E x pen se s Cost of energy for utility 2,974 2,709 2,403 Cost of energy commodities and services 5,511 356 47 Operating and maintenance ' 3,298 3,427 3,049 Depreciation and decommissioning 1,889 1,222 1,360

'Ibtal operating expenses 13,672 7,714 6,859 0perating ineome 1,728 1,896 2,763 Interest expense, net (665) (632) (678)

Other income and expense 201 13 79 income Before income Taxes 1,264 1,277 2,164 Income taxes 548 555 895 Net income S 716 5 722 5 1,269 Weighted Average Common Shares Outstanding 410 413 424 Earnings Per Common Share, Basic and Diluted $ 1.75 S 1.75 $ 2.99 Dividends Declared Per Common Share $ 1.20 $ 1.77 $ 1.96 The accompanymg Lies to the f:unwlidated Innancial statements are an integral part of this statement.

31

PG6E Corporation Consolidated Balance Sheet I (in rnillions) At December *1, 1997 1996 Assets Current Assets-Cash and cash equivalents S 237 $ 131 Short-term investments 1,160- 13 Accounts receivable Customers, net 1,514 1,152 Regulatory balancing accounts 658 444 Energy marketing 830 387

' Inventories and prepayments 626 584

'lbtal current assets 5,025 2,711 Property, Plent, and Equipment Utility 32,972 31,716 Gas transmission 3,484 1,594 Other 57 -

'Ibral property, plant, and equipment (at original cost) 36,513 33,310 Accumulated depreciation and decoinmissioning (16,041) (14,302)

Net property, plant, and equipment 20,472 19,008 Other Noncurrent Assets Regulatory assets 2,337 2,518 Nudear decommissioning fund 3 1,024 883 Other 1,699 1,117

'Ibtal noncurrent assets 5,060 4,518 Total Assets $ 30,557 $ 26,237

)

i 32 f

L-

PG&E Corporation Consolidated Balance Sheet firi mbHions) At December 31, 1997 1996

' Liabilities and Equity Current Liabilities Short-term borrowings S 103 $ 681 Current portion oflong-term debt 659 210 Current portion of rate reduction Imnds 125 -

Accounts payable Trade creditors 754 490 Other 620 548 Energy marketing 758 388 Accrued taxes 226 310 Other 739 653 lbtal current liabilities 3,984 3,280 Noncurrent Liabilities Long-term debt 7,659 7,770 Rate reduction Imnds 2,776 -

Deferred income taxes 4,029 3,941 Deferred tax credits 339 380 Other 2,034 1,663 lbtal noncurrent liabilities 16,837 13,754 Preferred Stock of Subsidiary With Mandatory Redemption Provisions 6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137 Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures, 7.90%,12,000,000 shares, due 2025 300 300 Stockholders

• Equity Preferred stock of subsidiary, par value $25, authorized 75,000,000 shares Without mandatory redemption provisions Nonredeemable-5% to 6%, outstandmg 5,784,825 shares 145 145 Redeemable-4.36% to 7.44%, outstanding 10,297,4(H shares 257 257 Conunon stock, no par value, authorized 800,000,000 shares; issued and outstanding, 417,665,891 and 403,504,292 shares 6,366 5,728

~ Reinvested earnings 2,531 2,636

'Ibtal stockholders' equity 9,299 8,766 Commitments and Contingencies (Notes 1,2,3,4,12, and 13) - -

Total Liabilities and Stockholders' Equity $ 30,557 5 26,237 The accompnying Notn to the conu,tidated rinwcht statemenn are an integral part of this avstement.

\

se ,

PG&E Corporation Statement of Consolidated Cash Flows On millions) Year ended Decemtier 31, 1997 1996 1995 Cash Flows From Operating Activities Net income $ 716 $ 722 $ 1,269 Adjustments to reconcile net income to net cash provided by operating activities:

1)cpreciation, decommissioning, and amortization 2,014 1,316 1,449 Deferred income taxes and tax credits-net (159) (150) (116)

Other deferred charges and noncurrent liabilities 159 22 (25)

Gain on sale of assets (120) - -

' Net elfeet of changes in operating assets and liabilities:

Accounu. receivable (242) (70) 200 Regulatory balancing accounts receivable (74) 302 499 Inventories (4) 32 32 Accounts payable 210 217 62 Accrued taxes (54) 36 (162)

Other working capital (85) (6) 8

' Other-net 257 160 99 Net cash provided by operating activities 2,618 2,581 3,315 Cash Flows From Investing Activities Capital expenditures (1,822) (1,230) (945)

Investments in unregulated projects (75) (70) (157)

Acquisitions (41) (159) -

Proceeds from sale of assets 146 -

340 Other-net 21 (120) (123)

Net cash used by investing activities (1,771) (1,579) (885)

Cash Flows From Financing Activities Net increase (decrease) in short-term lwirrowings (587) (115) 305 long-term debt issued 386 1,088 591 1 ong-term debt matured, redeemed, or repurchased-nct (961) (1,472) (1,297)

Proceeds from issuance of rate reduction lumds 2,881 - -

Preferred stock redectned or repurchased - -

(358)

Utility obligated mandatorily redeemable preferred securities issued - -

300 Common stock issued 54 220 140 Common stock repurchased (804) (455) (601)

Dividends paid (524) (844) (891)

Other-net (39) (14) (22)

Net cash used by financing activitics 406 (1,592) (1,833)

._ Net Change in Cash and Cash Equivalents 1,253 (590) 597 Cash and Cash Equivalents at January 1 144 734 137 Cash and Cash Equivalents at December 31 $ 1,397 $ 144 $ 734 Supplemental dischnures of cash flow infonnation Cash paid for:

Interest (net of amounts capitalized) $ 624 5 598 $ 645 Income taxes 801 640 1,126 The accompanying Notes to the Conwlhlated Financial Sutements are an integral part of this statement.

34

PG&E Corporation Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities Preferred Preferred Stock of Stock of Subsidiary Subsidiary Total Without With Additional Common Mandatory Mandatory Common Paid-in Reinvested Stock Redemption Redemption (dollars in millions) Stock Capital Ecrnings Equity Provisions Provisions 8alance December 31,1994 $2,151 $3,806 $2,677 $8,634 $733 $137 Net income 1,269 1,269 Common stock issued (5,316,876 shares) 27 113 140 Common ,tock repurchased (21,533,977 shares) (108) (195) (298) (601)

Preferred securities issued "

(12,000,009 shares) 300 Preferred stock redeemed (13,237,554 shares) (8) (8) (331)

Cash' dividends declared Conunon stock (830) (830)

Other (5) (5)

Balance December 31,1995 2,070 3,716 2,813 8,599 402 437 Net income 722 722 Cornmon stock issued (9,290,102 shares) 47 173 220 l Cominon stock repurchased l (19,811,396 shares) (99) (182) (174) (455)

Cash dividends tjeclared Common stock (729) (729)

Other 3 4 7 I

Balance December 31,1996 2,018 3,710 2,636 8,364 402 437 Net income 716 716 Ilokling company formation 3,710 (3,710) -

Common stock issued (2,302,544 shares) 54 54 Acquisitions (45,683,005 shares) 1,069 1,069 Common stock repurchased (33,823,950 shares) (496) (308) (804)

Cash dividends declared Common stock (485) (485)

Other 11 (28) (17)

Balance' Dec em be r 31,1997 $6,3 r,6 $ -- $2,531 $8,897 $402 $437 o Relates to utility obhpted mandatorily redennable preferred setuntics of trust holding solely Utihty subordmated dchentures.

The accompanying Notes to the Consohdated Financial statements are an integral part of this statement.

I I

i

)

35 l I

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Pac 6fic Gas and flectsic Company Statement of Consolidated income On millions) Year ended December 31, 1997 1996 1995 Operating Revenues 57,691 $7,160 $7,387 Electric utility 1,804 1,t'29 1,856

. Gas utility Energy commodities and sersicu 621 379 9,495 9,610 9,622

'Ibtal operating revenues

. Operating E xpenses 2,501 2,261 2,117 Cost of electric energy Cost of gas 473 448 286 Cost of energy wmmodities and services -

356 47 2,905 3,427 3,049 Operating and maintenance 1,785 1.222 1,360 Depreciation and decommissioning "Ihtal operating expenses 7,664 7,714 6,859 Operating income 1,831 1,896 2,763 Interest expense, net (570) (632) (678)

Other income and expense i16 46 149 income Before income Taxes 1,377 1,310 2,234 Income taxes 609 555 895 Net income 768 755 1,339 Preferred dividend requirement and redemption premium 33 33 70 Incomo Available for Common Stock 5 735 S 722 S1,269 The atmmpanyteeg Ltes to the Conmlidateil Fmantial. Statements are an integral part of this stateinent.

36 w___-. .

Pacific Gas and Electric Company Statement of Consolidated Cash Flows (in mHhons) Year ended December 31, 1997 1996 1995 Cash Flows From Operating Activities Net income $ 768 $ 755 $ 1,339 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, decommissioning, and amortization 1,914 1,316 1,449 Deferred income taxes and tax credits-net- (182) (150) (I16)

Other deferred charges and noncurrent liabilities 167 22 (25)

Net effect of changes in operating assets and liabilities:

Accounts receivable (582) (70) 200 Regulatory balancing accounts receivable (74) 302 499 inventories - 12 32 32 Accounts payable (80) 217 62 A.ccrued taxes (62) 36 (162)

Other working capital (128) (6) 8

- Other-net 15 127 29 Net cash provided by operating activities 1,768 2,581 3,315 Cash Flows From investing Activities Capital expenditures (1,522) (1,230) (945)

Investments in unregulated projects -

(70) (157)

Acquisitions (159) -

Proceeds from sale of assets 340 Other-net (117) (120) (123)

Net cash used by investing activities (1,639) (1,579) (885)

Cash Flows From Financing Activities Net increase (decrease)in short-term borrowings (681) (115) 305 Long-term debt issued 355 1,088 591 Long-terin debt matured, redeemed, or repurchased nct (852) (1,472) (1,297)

Proceeds from issuance of rate reduction bonds 2,881 - -

Preferred stock redeemed or repurchased - -

(353)

Company obligated mandatorily redeemable preferred securities issued - -

300 Dividends paid (739) (844) (891)

Other-net (14) (249) (488)

Net cash used by financing activities 950 (1,592) (1,833)

Not Change.in Cash and Cash Equivalents 1,079 (590) 597 Cash and Cash Equivalents at January 1 144 734 137-Cash and Cash Equivalents at December 31 -$1,223 $ 144 $ 73*

Supplemental disekisures of cash flow information Ca.sh paid for:

Interest (net of amounts capitalized) $ 547 s 598 $ 645

. Incomi' taxes 841 640 1,126 The munipanpng Notes to the Conmhd ned l'inancial Statements are an integral part of this state c 37

Pacific Gas and Electris Company Consolidated Balance Sheet (in miHions) At Decemtier 31, 1997 1996 Assets Current Assets

' Cash and cash equivalents S 80 $ 131 Short-term investments 1,143 13

' Accounts receivable Customers, net 1,204 1,152 Regulatory balancing accounts 658 +44 Related parties 459 -

Energy marketing - 387 Inventories anti prepayments 523 584

'Ibtal current assets 4,067 2,711

- Prope rt y, Pla nt, a n d E q uipm e nt Electric 26,033 25,052 Gas 6,939 8,258

'Ibtal protwrty, plant, and equipment (at original cost) 32,972 33,310 Accumulated depreciation and decommissioning (15,558) (14,302)

Net property, plant, and equipment 17,414 19,008 Other Noncurrent Assets Regulatory assets 2,283 2,518 Nuclear decommissioning funds 1,024 883 Other 359 1,117

'Ibtal noncurrent assets 3,666 4,518 Total Assets $ 25,147 $ 26,237 38.

. . . . . . , . . ~ . . . . .- .. . - . . . , . .

! i i

Pacific Gas and Electric Company Consolidated Balance Sheet On millions) At December 31, 1997 1996 Liabilities and Equity Current Liabilities Short-term borrowings 5 - $ 681 ,

1 Current [xirtion oflong-term debt 580 210 125 -

Current ['w>rtiori of rate reduction bonds Accounts payable Trade creditors 441 490 Related parties 134 -

Other 578 548 Energy marketing -

388 Accrued taxes 229 310 Deferred income taxes 149 157 Other - 373 496-

"Ibtal current liabilities 2,609 3,280 Noncurrent Liabilities Long-term debt 6,218 7,770 l

Rate reduction honds 2,776 -

i Deferred income taxes 3,304 3,941 Deferred tax credits 338 380 )

I Other 1,810 1,663

'Ihtal noncurrent liabilities 14,446 13,754 Preferred Stock With Mandatory Redemption Provisions l 6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137 i Company Obligated Mandatorily Redeemable Preferred Securitles of Trust Holding Solely Utility Subordinated Debentures, 7.90%,12,000,000 shares, duc 2025 300 300 Stockholders' Equity Preferred stock, par value 525, authorized 75,000,000 shares Without mandatory redemption provisions -

Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145 Retteemable-4.36% to 7.44%, outstanding 10,297,404 shares 257 257 Common stock, no par value, authorized 800,000,000 shares, 403,504,292 shares outstanding, each year 4,582 5,728 Reinvested earnings 2,671 2,636

'lbtal Stockholders' equity 7,655 8,766 Commitments and Contingencies (Notes 1,2,3,12, and 13) - -

Total Liabilities and Stockholders' Equity 5 25,147 $ 26,237 The actnrnpanpng Notes to the Consolidated Financial Statements are an integral part of this statement, 39

Pacific Gas and Electric Company Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities Preferred Preferred Stock Stock Total Without With Additional Common Mandatory Mendatory Conmon Paid-in Reinvested Stock Redemption Redemption (dollars in miHions) Stock Capital Earnmgs Equity Provisions Provisions Balance December 31,1994 $2,151 $ 3,806 52,677 58,634 5733 S137 Net inciune 1,339 1.339 Onnmon Stock issued (5,316,876 shares) 27 113 140 Omunon snick repurchased (21,533,977 shares) (108) (195) (298) (601)

Preferred securities issuett "

(12,000,000 shares) 300 Preferred stock redeemed (13,237,554 shares) (H) (14) (22) (331)

Cash dividends declared Preferred stock (56) (56)

Common stock (830) (830)

Other (5) (5)

Balance December 31,1995 2,070 3,716 2,811 H,599 402 437 Net inctane 755 755 Conimon stock issued (9,290,102 shares) 47 173 220 Common stock repurchased (19,Hi l,396 shares) (99) (182) (174) (455)

Cash dividends declared Preferred stock (33) (33)

Coinmon stock (729) (729)

Other 3 4 7 8alance December 31,1996 2,018 3,710 2,636 8,364 402 437 Net income 76H 768 1lolding cotnpany formation (1,i46) (1,146)

Cash dividends declared Preferred stock (33) (33)

Cot 9 mon stock (699) (699)

Other (1) (1)

Balance Deeembar 31,1997 $2,018 $2,564 $2,671 $7,253 S402 5437

" Relates to Corrpany obligated mandatorily redeemable prt-ferred securitiu of trust holdmy solci) Utility udordinated debentures.

Thw accompanying Mies to the Cunsohdated I'mandal Suitms ut, are 4n integral part of this stancment.

f 40

Notes to Consolidated Financial Statements Note 1- Operations: The Coqmration is a national energy com-Significant Accounting Policies pany providing electric and gas utility services through its  ;

I regulated subsidiary Pacific Gas and Electric Company and Basis of Presentation: PG&E Corporation bccame the other energy related services through its unregulated inte-holding company of Pacific Gas and Electric Company (the grated subsidiaries. The Utility generates electricity and Utility) onJanuary 1,1997. Prior to that time, the Utility procures, transmits, and distributes both electricity and nat- i was the predecessor of PG& E Coqmration. The Utility's ural gas to customers throughout most of Northern and interests in its unregulated subsidiaries were transferred to Central California.

PG& E Corporation. Through its other subsidiaries, the Corporation:

This is a combined annual report of PcaE Corporation . Owns and operates natural gas pipelines, natural gas i and the Utility. Therefore, the Notes to Consolidated storage facilities, and natural gas processing plants in the 1 Financial Statements apply to both pc&E Corporation and Pacific Northwest, Texas, and Australia.

the Utility. PG&E Corporation's consolidated financial . Develops, builds, operates, owns, and manages power statements include the accounts of PG&E Corporation and generation facilities across the United States.

its w holly owned and controlled subsidiaries, including the

• Provides customers nationwide with competitively-priced Utility (collectively, the Corporation). The Utility's con- natural gas and electricity and services to manage and solidated financial statements include its accounts as w cll make more efficient their energy consumption.

as those ofits u holly owned and controlled subsidiaries.

• Purchases and resells energy commodities and related PG& E Corporation and the Utility have identical 1995 and financial instruments in major domestic markets, serving 1996 consolidated financial statements because they each PG& E Corporation's other unregulated businesses, unaffil-represent the accounts of the Utility as a predecessor of iated utilities, and large end-use customers.

PG&E Corporation. All significant intercompany transac-tions have been climinated from the consolidated financial Regulation and SFAS No. 71: The Utilityis regulated statements. Certain amounts in the prior years' consolidated by the CPt;c, the FERC, and the Nuclear Regulatory financial sinements have ken reclassified to conform to Commission, anmng others. The gas transmission business the 1997 presentation. in the Pacific Northwest is regulated by the FERC.The gas i The preparation of financial statements in conformity transmission business in Texas is regulated by the Texas with generally accepted accounting principles (GAAP) Railroad Commission.

requires management to make estimates and assumptions. The Corporation and the Utility account for the finan-These estimates and assumptions affect the reported cial effect of regulation in accordance with Statement of amounts of res enucs, expenses, assets, and liabilities and Financial Accounting Standards (SFAS) No. 71, " Accounting the disch>sure of contingencies. Actual resuhs could differ for the Effects of Certain Types of Regidation " This state-from these estimates. ment allows them to record certain regtdatory assets and Accounting principles utilized include those necessary liabilities u hich will be included in future rates and would for rate-regulated enterprises w hich reflect the rate- not be recorded under GAAP for nonregulated entities. In making policies of the California Public Utilities Com- addition, SFAs No.121, " Accounting for the Impairment mission (cpl?C) and the Federal Energy Regulatory of Long-1.ived Assets and for Long-Lived Assets to be Commission (FERC). Disposed Of," requires the Corporation and the Utility to w rite off regulatory assets u hen they are no longer probable of recovery. On an ongoing basis, the Corporation and the Utility review their regulatory assets and liabilities for the continued applicability of SFAS No. 71 and the effect of SFAS No.121.

41

. Notes to Consolidated Financial Statements  ;

i l

Net regulatory c 3ets including regulatory balancing These instruments include forward ccmtracts invoking the accounts receivable and net regulatory liabilities are com- physical delivery of an energy commmlity, swaps, futures, prised of the following: options, and other contractual arrangements. Additionally, the Corporation engages in hedging activities using futures, !

o=~ha n ""

options, and swaps to hedge the impact of market fluctua-("""* " '

tions on energy commodity prices, interest rates, and Electric industry restructuring transition costv" $ 1,5 3 ),

Unamortized loss, nct of gain, on reacquired debt 296 foreign currencies.The Utih.ty manages pr ce nsk m. depen-Regulatory assets for deferred income in 278 dently from the activities in our unregulated businesses.

Regulatory balancing accounts (net) 235 The Corporation's net gains and losses associated Other (net) 174 gy,g g g with price risk management activmes during 1997 were immaterial.

Debee R 1996

%mmi Property, Plant, and Equipment: Plant additions and Reyulatory assets for deferred income tax $1,0 3 replacements are capitalized. The capitalized costs include Lbamortired loss, net of gam, on reacquired debt 377 labor, materials, construction overhead, and an allowance Diablo Canyon regulatory assets 3G4 Regulatory balancing accounts (net) 323 for funds used during construction (AFUDC) or capitalized Other (net) 355 interest. AFUDC is the estimated cost of debt and equity 52.752 funds used to finance regulated plant additions.The Utility

+su h L Henric Indo ery Re,eructurmg Nr further dacumon recovers AFUDC in rates through depreciation expense over the usefullife of the related asset.

- Revenues and Regulatory Dalancing Accounts: The original cost of retired plant and removal costs less

' Electric and gas utility revenues recorded by the Utility salvage value is charged to accumulated depreciation upon include amounts for senices rendered but unbilled at the retirement of plant in senice.

end of the year. The Utility also reconk revenues for Property, plant, and equipment is depreciated using a changes in regulatory balancing accounts established by the straight-line remaining-life method. The Utility's composite.

CPUC. Specifically, sales balancing accounts accumulate depreciation rates were 5.00,3.65, and 4.09 percent for the differences beturen authorized and actual base revenues, years ended December 31,1997,1996, and 1995, respec-Energy cost balancing accounts accumulate differences tively. The increase in the comimsite rate in 1997 as com-between the actual cost of gas and electric energy and the pared to 1996 and 1995 reflects higher depreciation revenues designater, for recovery of such costs. Recovery of expense associated with Diablo Canyon Nuclear Power gas and electric energy costs through energy cost balancing Plant (Diablo Canyon). See Note 2, Electric Industry accounts is subject to reasonableness resiews by the CPUC. Restructuring.

The regidatory balancing accounts accmuulate balances .

imtil they are refunded to _or received from Utility cus. Gains and Losses on Reacquired Debt: Anygains and tomers through authorized rate adjustments. losses on reacquired debt associated with regulated opera-tions that are subject to the provisions ofSFAS No. 71 are Accounting for Deriva'tive Instruments: The Corpora. deferred and amortized over the remaining original lives of tion, through its subsidiaries, engages in price risk manage, die debt reacquired, consistent with ratemaking principles, ment activities for both non. hedging and hedging purposes. Gains and losses on reacquired debt associated with unregu-The Corporation conducts non-hedging activities princi. lated operations are recognized in earnings at the time such

pally through its unregulated subsidiary, PG& E Energy debt is reacquired.

Trading (PG& E ET), using a variety of financial instruments.

t 42

inventories: Stored nuclear fuelinventory is stated at costs as determined by the CPUC.This period is referred lower of average cost or market. Nuclear fuel in the reactor to as the transition period. At the coaciusion of the transi-is amortired based on the amount of energy output. Other tion period, the Utility will be at risk to recover any ofits inventories include materials and supplies, gas stored under- remaining generation costs through market-based revenues.

ground, and fuel oil. Materials and supplies and gas stored underground are valued at average cost. Fuel oil is valued by a Rate Freeze and Rate Reduction the last-in-first-out method. During 1997, electric rates for the Utility's customers were held at 1996 levels. EffectiveJanuary 1,1998, the Utility Cash Equivalents and Short-Term Investments: reduced electric rates for its residential and small commer-Cash equivalents (stated at cost, w hich appmximates mar- cial customers by 10 percent and will hold their rates at ket) include working funds. The Utility's short-term invest- that level. The rate freeze will continue until the end of the ments consist primarily of money market funds and some transition period, commercial paper with original maturities of three months 'Ib pay for :he 10 percent rate reduction, the Utility or less. These investments were made with the proceeds financed $2.9 billion ofits transition costs with rate reduc-from the issuance of the rate reduction bonds. See Note 7, tion Imnds. See Note 7, Rate Reduction 13onds.

Rate Reduction Ilonds.

• Transition Cost Recovery

}

I Note 2 Costs eligible for transition cost recovery include: (1) alxwe-I

' Electric Industry Restructuring market sunk costs (sunk costs are costs associated with Utility-owned generating facilities that are fixed and 1997 was the first year of California's transition into a new unavoidable and currendy included in the Utility customers' competitive electric generation market. In the new competi- electric rates) and future costs, such as costs related to plant tive market, the Utility's generation revenues will be deter- removal,(2) costs associated with the Utility's long-term j mined principally by the market. Ilowever, market-based contracts to purchase power at almve-market prices from l revenues may not be sufficient to recover (that is, to collect Qualifying Facilities (QF) and other [mwer suppliers, and from customers) certain generation costs resulting from past (3) generation-related regulatory assets and obligations. (in CPUC decisions. 'Ib recmcr these uneconomic costs, called general, regulatory assets are expenses deferred in the cur-

" transition cmts," and to ensure a somoth transition to the rent or prior periods to be included in rates in subsequent competitive environment, the Utility,in conjunction with periods.) Transition costs that are disallow ed by the CPUC other California electric utilities, the CPUC, state legisla- for collection from customers will be written off.

tors, consumer advocates, and others, deseloped a transition Sunk costs associated with Utility-owned generation i

plan in the form of state legislation, to position California facilities are currently included in the Utility customers' for the new market environment. rates. Above-mulet sunk costs are those w hose values There are three principal elements to this transition plan: recorded on the Utility's balance sheet (book value) are

. (1) an electric rate freeze and rate reduction,(2) reemery of expected to be in excess of their market values. Conversely, transition costs, and (3) economic divestiture of Utility- below-market sunk costs are thme whose market values are owned generation facilities. Each one of these three ele- expected to be in excess of their lxmk values. In general, ments and the impact of the transition plan on the the total amount of sunk costs to be included as transition application of Sl%S No. 71 are di., cussed below. The transi- costs will be based on the aggregate of almve-market and

~t ion plan will remain in effect until the earlier of March 31, below-market values. The almve-market portion of sunk 2002, or when the Utility recovers its authorized transition- costs is eligible for recovery as a transition cost The below-market portion of sunk costs will reduce other unrecovered M

Notes to Consolidated Financial Statements transition costs. A valuation of Utihty-owned generation during this shorter period is referred to as accelerated facilities where the market value creceds the lxx>k value recovery. The CPUC believes that acceleration reduces risks could result in a material charge if the Utility retains the associated uith recmery of all utility generation assets, facility.This is because any excew ofinarket value over lumk including Diablo Canyon and hydn>clectric facilities. As a value would be used to reduce other transition costs without result, in acconlance with the transition plan, the Utility is being collected in rates. receiving a reduced return for all ofits generation facilities.

The Utility will not be able to detennine the exact in 1997, the reduced return was 7.13 percent as compared amount of sunk costs that will be recoverable as transition to an authorized return of 9.45 percent. The reduced return costs until a market valuation process (appraisal, spin, on non-nuclear generation assets, effectiveJuly 28,1997, or sale)is completed for each of the Utility's generation resulted in a S24 million decrease in carnings (5.06 per facilities.The first of these valuations occurred in 1997 share)in 1997 and will base a continued impact throughout when the Utility agreed to sell three ofits electric plants for the transition period.

$501 million. This sale is expeted to close during 1998 Ahhough most transition costs must be recovered by (see Generation Divestiture below).The rest of the valua- .\ larch 31,2002, certain transition costs can be included in tion pnicess will be completed by Decend>cr 31,2001. At customers' electne rates after the transition period. These December 31,1997, the Utility's net invesunent in Diablo costs include:(i) certain employec-rebted transition costs, Canyoti and non-nuclear generation facilities was $3.7 bil. (2) above-market payments under existing QF and power-lion and $2.7 billion, respectively, including the plants to purchase contracts, and 0) unrecovered electric industry be sold in 1998. restructuring implementation costs. In add tion, transition The Utility has agreed to purchase electric power from costs Gnanced by the issuance of rate reduction innds QFs and other power suppliers under long-term contracts are expected to be recmered over the term of the bonds.

expiring on s arious dates through 2028. Over the life of l'urther, the Utility's nuclear decommissioning costs are these contracts, the Utility estimates that it will purchase being recovered through a CPUC-authorized charge w hich apprmimately 360 million megawatt-hours (MWh) at an uill extend until suf6cient funds exist to decommission the average aggregate price of 6.3 cents per kilowatt-hour facility. During the rate free /e, this charge will not increase (LWh). 'Ib the extent that this price is above the market Utility customers' electric rates. Excluding these exceptions, price, the Utility uill be able to collect the difference the Utility will w rite-off any transition costs not recovered between the contract price and the market price from cus- during the transition period.

tomers, as a transition cost, over the tenn of the contract. Under the terms of the transition plan, as directed by the in addition, as of December 31,1997, the Utility has CPUC, the Utility has separated, or unbundled, its pre i-accumulated appnnimately $1.5 billion of generation- ously authorized cost-of-sen-ice electric revenues into sepa-related net regulatory assets. The net regulatory assets are rate categories. Unbundling enables the Utility to allocate eligible for recmcry as transition costs. revenue provided by froien electric rates into transmission, The CPUC has the uhimate authority to detennine distribution, public purpose programs, and generation based w hich costs are eligible to be recovered as transition costs. upon their respective wst of senice. Revenues prmided by Reviews by the CPUC to detennine the reasonableness of frozen rates will also be used to recover other authorir.ed

- transition costs are being conducted and will continue to be Utility costs, including nuclear decommissioning, rate c<mducted throughout the transition period. reduction bond debt senice, and transition cost reemery.

- Under the transition plan, most transition costs must be The portion of the unbundled rnenue to be provided for recovered by Alarch 31,2002. This reemety period is sig- transition cost recovery is based upon mechanisms approved nificantly shoner than the recovery period of the related by the CPUC. Rnenue provided for recovery of most non-assets prior to restructuring. Recovery of transition costs nuclear transition costs is based upon their acceleration 44

)

within the transition period. For nuclear transition costs, ity. Given its current evaluation of these factors, the Utility revenues provided for transition cost recovery are based on believes that it will recover its transition costs. Also, the (1) an established Incremental Cost incentive Price per Utility believes that its regulatory assets and generation kWh generated by Diablo Canyon to reem er certain ongo- facilities are not impaired.1-low ever, a change in one or j ing costs and capital additions, and (2) the acceleration of more of these factors could affect the probability of recm ery )

reemcry of the Utilityiinvestment in Diablo Canyon from of transition costs and result in a material charge. I a period cnding in 2016 to a five-year period ending During 1997, the difference between billed revenues and December 31,2001, authorized revenues was used to recover transition costs, .!

liased on the Utility's evaluation of the transition plan including nmst of the accelerated Diablo Canyon sunk costs.

1 and state legislation and CPUC decisions related to the tran- l 1

sition plan, the Utility is depreciating Diablo Canyon over a

• Generation Divestiture j l

five-year period ending December 31,2001. The change In 1997, California utilities produced a signi6 cant portion of in depreciable life increased Diablo Canyon's depreciation the statei electric generation needs. In a competitive mar-experne for 1997, as compared to 1996, by $583 million. Let, the CPUC is concerned that this level of generation may In addition, most generation-related regulatory assets are give existing utilities undue in6uence on the market price being amortized on a straight-line basis, in accordance Ihr power. As part of the transition plan, the Utility has with their recovery under the transition plan, beginning on agreed to sell a signi6 cant portion ofits generation facilities January 1,1998. Further, upon s aluation of generation to alleviate this concern.

facilities, any losses will be amortized mer the remaining in 1997, the Utility agreed to sell three fossil-fueled transition period as a transition cost. Any gains will be rec- electric generating plants to Duke Energy through an auc-ognized and used to reduce other transition costs at the time tion process. The aggregate bid accepted for these plants of valuation. was $501 million. These three plants bas e a combined book Any difference betw een (1) revenues provided for transi- value at December 31,1997, of approximately 5370 million tion cost recovery and (2) the cmts associated with acceler- and a combined capacity of 2M5 megawatts (MW).

ated reem ery, including the depreciation of Diablo Canyon The three p<m er plants w ere Morro llay, Moss Landing, and the amortization of regulatory assets, is being tracked. If and Oakland.

the revenues exceed the accelerated costs, certain transition The sales have been approved by the CPUC. Ilowever, costs may be further accelerated until all transition costs are they are still subject to approval of the transfer of various reem ered or March 31,2002, w hichever is earlier. If the permits and licenses. Additionally, the Utility will retain lia-accelerated costs exceed the revenues, the costs will be bility for required environmental remediation of any pre-deferred. At the end of the transition period, any mercollee- closing soil or groundwater contamination at these plants.

tion of these ammmts will be returned to customers. The Utility does not expect any material adverse impact on The Utility's ability to recover its transition costs during its financial position or results of operations as a result of the transition period will be dependent on ses eral factors. retaining such environmental remediation liability. The These factors include:(1) the continued application of the Utility expects the sale of these three plants to close in 1998.

regidatory framework established by the CPUC and state The Utility plans to conduct another auction ofits legislation,(2) the amount of tran<ition costs approved by four remaining Utility-owned fossil-fueled plants and its the CPUC,(3) the market value of Utility-owned generation geothermal facilities in the first half of 1998. These addi.

facilities,(4) future Utility sales levels,(5) future Utility fuel tional plants have a combined generating capacity of H and operating costs,(6) the extent to w hich the Utility's 4,718 MW and a combined book value at December 31, authorized revenues to recover distribution costs are 1997, of approximately $790 million.

increased or decreased, and (7) the market price of electric- "Ibgether the eight power plants represent 98 percent of the Utility's fossil-fueled generating capacity and all of the 45

Notes to Consolidated Financial Statements Utility's geothennal generating capacity. The eight plants lated approximately $1.5 billion of generation-related generate approximately 22 percent of the Utilityi total elec- regulatory assets which are eligible for collection from dis-tric sales. The Utility is currently evaluating its options tribution customers and which the Utility considers proba-related to its remaining generation facilities and may decide ble of recovery. Substantially all regulatory assets are not to retain its economic investment in those facilities. reflected on the Utility's and PG&E Corporation's balance During the transition period, the proceeds from the sale of sheets in regulatory balancing accounts and regulatory the plants will be used to offset transition costs associated assets. In addition, alxne-market generation-related sunk with other Utility electric generation facilities. Therefore, costs, which will be detennined as part of the market the Corporation does not expect any material adverse valuation process discussed a6ve, and alme-market QF impact on its or the Utility's financial position or results costs will be eligible for collection from distribution of operations from any of these divestitures. customers.

Given the current regulatory environment, the Utility's

• The Transition Plan and SFAs No. 71 cicetric transmission business and most areas of the distribu-The Utility accounts for the financial effect of regulation in tion business are expected to remain regulated, and as a accordance with SFAS No. 71. This statement allows the result, the Utility will continue to apply the provisions of Utility to record certain regulatory assets and liabilities SFAS No. 71. Ilowever,in Alay 1997, the CPUC issued ]

which wouhl be included in future rates and would not he decisions that allow customers to choose their electricity ,

1 l

recorded under generally accepted accounting principles for provider beginningJanuary 1,1998. The decisions abo nonregulated entities. In addition. SFAS No.121," Account- allow the electricity provider to provide their customers ing for the Impainnent of Long-Lived Assets and for Long- with billing and metering senices, and indicate that electric-Lived Assets to be Disposed Of," requires the Usility to ity providers may be allow ed to provide other distribution w rite off regulatory assets w hen they are no longer probable services (such as customer inquiries and uncollectibles) in of recovery. the future. Any discontinuance of SFAs No. 71 for these in 1997, the Emerging issues Task Force (FITF) of the portions of the Utility's electric distribution business is Financial Accounting Standards lloard (FASil) reached a not expected to hase a material adverse impact on the consensus on Issue No. 97-4," Deregulation of the Pricing Utility's or the Corporation's financial position or results of Electricity - Issues Related to the Application of FASil of operations.

Statements No. 71, Accounting for the Effects of Certain

'lypes of Regulation, and No.101, Regulated Enterprises - Note 3 Accounting for the Discontinuation of Application of FASil Natural Gas Matters Statement No. 71"(EFI F 97-4), w hich prosided authorita-tive guidance on the applicability of SFAS No. 71 during the Gas Accord: In 1998, the Utility will implement a multi-transition period.The ErFF requires the Utility to discon- party settlement, called the Gas Accord (Accord), that will tinue the application of SFAS No. 71 for the generation por- continue to restructure the gas industry in California. The tion ofits operations as ofJuly 24,1997, the effective date of Accord, w hich received CPUC approval in 1997, has four FITF 97-4. The discontinuation of application of SFAs No. principal elements. First, the Accord separates the rates for 71 did not have a material effect on the Utility's financial gas transmission services from gas distribution senices.

statements because EITF 97-4 requires that regulatory assets Second, the Accord increases the opportunity for residential and liabilities (both those in existence today and those cre- and smaller commercial (core) customers to choose the ated under the terms of the transition plan) be alkicated to commodity gas supplier of their choice. Third, the Accord the portion of the business from which the source of the establishes a new way to measure the reasonableness of the regulated cash flows is derived.The Utility has accumu- Utility's gas purchases based upon market indices. Fourth, 46

the Accord settied numerous regulatory issues between the As a result of regulatory changes, the Utility no longer Utility and other parties. The resolution of these issues did pnicures gas for most ofits noncore customers, resulting in not base a material adverse impact on the Utility's or the a decrease in the Utility's need for capacity on these Corporation's financial position or resuhs of operations. pipelines. Despite these changes, the Utility continues to The Accord ako establishes gas transmission rates for the procure gas for substantially all ofits core customers and its perimi from Alarch 1998 through December 2002 for all noncore customers w ho choose bundled service. 'lb the customers and climinates regulatory protection for variations extent that the Utility's current capacity holdings exceed in sales volumes for transmission revenues from industrial demand for gas transportation by its customers, the Utility and larger conunercial(noncore) customers. As a result, the will continue its efforts to broker such excess capacity.

Utility will be at risk for variations between actual and fore-casted noncore transmission throughput volumes. Ilowever, Note 4 thme variations are not expected to have a material adverse Acquisitions and Sales impact on the Utility's or the Corporation's financial posi-tion or results of operations. In December 1996, the Corporation acquired Energy Source, a wholesale commodity marketing company for Transportation Commitments: The Utility has long- approximately $23 million. The acquisition was accounted term gas transportation service contracts with various for as a purchase.

Canadian and interstate pipeline companies. For the dura- InJanuary 1997, the Corporation ac<1uired Teco Pipeline tion of these contracts, the Utility has agreed to pay the Company ('leco) for apprmimately $378 million, consisting pipeline companies an amount each year for capacity rights of $317 million of PG& E Corporation common stock and on their pipelines. The amount that the Utility pays each the purchase of a $61 million note. Teco has invesunents in year varies due to changes in the rates of the pipeline com- natural gas pipelines and gas gathering and processing panies. The total amounts the Utility paid under these con- facilities located in Texas. Teco also owns a gas marketing tracts were approximately $255, $269, and 5245 million in company in Ilouston. The acquisition was accounted for 1997,1996, and 1995, respectively. These amounts include as a purchase.

payments made by the Utility to PG&E Gas Transmission in April 1997, PG& E Enterprises (Enterprises), a w holly (PG&E GT)of approximately S49,557, and $70 million in owned subsidiary of PG& E Corporation, sold its interest in 1997,1996, and 1995, respectively. These payments are International Generating Company, Ltd. (InterGen), a joint eliminated in the consolidated financial statements of the venture between Enterprises and llechtel Enterprises, Inc.

Corporation. Also, a contract for Southwest pipeline capac- (llechtel), and all of its related project interests, to liechtcl.

ity expired in December 1997. 'Ibtal payments associated The sale has resulted in an after-tax gain of approximately with this contract were approximately $149 million in 1997. $120 million.

The following table summarites the Utility's capacity on On July 31,1997, the Corporation completed its acquisi-various pipelines and the related annual payments for capac- tion of Valero Energy Corporation's (Valero) natural gas ity at December 31,1997: business h>cated in Texas. Valero also owns a gas marketing w,, business. PG&E Corporation issued approximately 31 mil-Fi,m Annual c.gua, o...n. h.on shares ofits common stock to acquire Valero along with HWd Charges Contract r ...n. comp.nv iuuci.oi 4.n nuinon.i o p,,.noa the assumption of approximately $780 million in long-term PG& E GT 600 $44 . Oct. 200; debt, equating to a purchase price of approximately $1.5 bil-Transuestern - 200 29 Mar. 2007 lion. The acquisition was accounted for as a purchase.

NOVA 600 20 Oct. 2001 in August 1997, the Corporation announced that as sub-ANG 600 13 Oct. 2005 sidiary, U.S. Generating Company (USGen), had agreed 47

Notes to Consolidated Financial Statements to buy a iwirtfolio of electric generating assets and power the formation of the Corporation, the Utility held $5 par supply contracts from the New England Electric System value common stock. The stock was com erted to PG& E (NEES) for $1.59 billion, plus $NS million for early retire- Cor}mration common stock (no par value) at the formation ment and severance costs previously committed to by NEES. of the holding company.

Including fuel and other imentories and transaction costs, As of December 31,1997, the floard of Directors has financing requirements are expected to total approximately authorized the repurchase of up to $1.7 billion of common

$1.75 billion, of w hich approximately $1 billion will be stock on the open market or in negotiated transactions. In funded through a combination of project level debt as well January 1998, the Corporation repurchased 37 million as debt of USGen. In addition,5750 million of equity will be shares ofits common stock at $30.3125 per share. In con-contributed over two years ami will be fimanced initially nection with this transaction, the Corporation has entered using short-term debt of PG& E Corporation. The assets to into a forward contract with an investment institution. The he acquired contain a balance of hydro, coal, oil, and natural Corporation will retain the risk ofincreases and the benefit gas generation facilities. We expect the acquisit i on to be of decreases in the price of the conunon shares purchased completed in the second half of 1998 The acquisition is through the forward contract. This obligation will not be subject to regulatory approval, among other conditions. terminated until the investment institution has replaced the in September 1997, the Corporation completed an acqui- shares sold to the Corporation through purchases on the sition of tuo partnerships previously jointly owned by it and open market or through privately negotiated transactions.

llechtel. In December 1997, the Corporation closed the The contract is anticipated to expire by December 31,1998.

acquisition of a third such partnership. The Corporation is now the sole owner of USGen, an independent power devel- LTrility:

oper and manager, U.S. Operating Services Company, The CPUC set a number of conditions when PG& E USGen's operations and maintenance affiliate, and USGen's Corporation was formed as a holding company. One of power marketing affiliate, UhGen power Services, LP. these conditions requires the Utility to maintain, on aver-Additionally, the Corporation has acquired all or part of age, its CPUC-authorized capital structure, potentially llechtel's interest in ses eral power projects that are affiliated limiting the amount of dividends the Utility may pay PG& E with UNGen. Corporation. At December 31,1997, the Utility was in in connection with the acquisitions completed in 1996 compliance with its CPUC-authorized capital structure, and 1997, discussed above, the Corporation recorded The Corporation believes that the Utility will continue to approximately $432 million of goodwill, subject to final pur- meet this condition in the future without affecting the chase price adjustments. These amounts will be amortized Corporation's ability to pay common stock dividends to l

on a straight-line basis over a 30 to 40 year period. common shareholders.

Note 5 Preferred Stock: Iloiders of the Utility's nonredeemable Common and Preferred Stock and preferred stock at December 31,1997, base rights to annual Utility Obligated Mandatority Redeemable dividends per share ranging from $1.25 to St.50.

Preferred Securities of Trust Holding Solely The Utility's redeemable preferred stock without manda-Utility Subordinated Debenturea tory redemption provisions is subject to redemption at the Utility's option, in w hole or in part, if the Utility pays the Common Stock; specified redemption price plus accumulated and unpaid PGbE Corporation: dividends through the redemption date. Annual dividends The Corporation has authorized 800 million shares of and redemption prices per share at December 31,1997, no-par common stock of u hich 418 million shares were range from $1.09 to $1.86 and from 525.00 to $27.25, issued and outstanding as of December 31,1997. Prior to respectively. InJanuary 1998, the Utility redeemed all ofits M

7.44% redeemable preferred stock, of which $65 million was The Utility's guarantee of the QUIPS, considered outstanding at December 31,1997, at a redemption price together with the other obligations of the Utility with of $25 per share. respect to the QUIPS, constitutes a full and unconditional The Utility's redeemable preferred stock with manda- guarantee by the Utility of the Trust's contractual obliga-tory redemption provisions consists of 3 million shares of tions under the QUIPS issued by the Trust. The subordi-the 6.57% and 2,5 million shares of the 6.30% series at nated debentures may be redeemed at the Utility's option December 31,1997.The 6.57% series and 6.30% series may beginning in 2000 at par plus accrued interest through the be redeemed at the Utility's option beginning in 2002 and redemption date.The proceeds of any redemption will 2004, respectively, at par value plus accumulated and unpaid be used by the Trust to redeem QUIPS in accordance with dividends through the redemption date. These series of their terms.

preferred stock are subject to mandatory redemption provi- Upon liquidation or dissolution of the Utility, holders of sions entitling them to sinking funds prmiding for the these QUIPS would be entitled to the liquidation preference retirement of stock outstanding. The estimated fair value of of $25 per share plus all accrued and unpaid dividends the Utility's preferred stock with mandatory redemption thereon to the date of payment. The estimated fair value of provisions at December 31,1997, and 1996, was approxi- the Utility's QUIPS at December 31,1997, and 1996, was mately $146 million and $135 million, respectively, based on approximately $3M million and $291 million, respectively, l

quoted market prices, based on quoted market prices.

Dividends on all preferred stock are cumulative. All shares of preferred stock have voting rights and equal pref- Note 6 crence in dividend and liquidation rights. Upon liquidation Long-Term Debt or dissolution of the Utility, holders of preferred stock wouhl be entitled to the par value of such shares plus all Long-term debt at December 31,1997, and 1996, consisted accumulated and unpaid dividends, as specified for the class of the following:

and series.

December 31, 1997 1996 Utility Obligated Mandatorily Redeemable ({i e debt Preferred Securitios of Trust Holding Solely Utility First and refunding mortgage bonds Subordinated Debentures: The Utility, through its Alaturity interest rates 199 b2001 4.63% to 8.75% $ 861 5 880 wholly owned subsidiary, pG& E Capital I (Trust), has out- 2002-2006 5.875% to 7.875% 1,354 1,392 standing 12 million shares of 7.90% cumulative quarterly 2007-2019 6.35% to 8.875% 160 520 2020-2026 535% to 820% 2,498 2,628 income preferred securities (QUIPS), uith an aggregate Principal amounts outstanding 4,873 5,420 liquidation value of $300 million. Concurrent with the Unamortized discount net of premium (42) (50) issuance of the QUIPS, the Trust issued to the Utility 4,831 5,370 Thral mortgage bonds 371,135 shares of common securities with an aggregate lig- Pollution control loan agreements, uidation value of approximately $9 million. The Trust in variable rates, due 2016-2026 1,348 988 turn used the net proceeds from the QUIPS offering and "[ , d N 587 829 issuance of the common stock securities to purchase subor- Debentures,12%, due 2000 - 58 dinated debentures issued by the Utility with a face value of Other long term debt 32 31 Tbtal Utility long-tenn debt 6,798 7,276

. approximately $309 million, an interest rate of 7.9 percent, Long-term debt of unregulated and a maturity date of 2025. These subordinated debentures business operations 1,520 704 are the only assets of the Trust. Proceeds from the sale of Tbtallong-term debt 8,318 7,980 the subordinated debentures were used to redeem and Current portion oflong-term debt 659 210

. repurchase higher-cost preferred stock. 1,ong-tenn debt, net of current portion $7.659 57,770 49

Notes to Consolidated Financial Statements Utility: Repayment Schedule: At December 31,1997,the Mortgage Bonds: Corporation's combined aggregate amounts of maturing All real properties and substantially all personal properties long-term debt and sinking fund requirements, for the of the Utility are subject to the lien of the mortgage bonds, years 1998 through 2002, are $659, $294, $460, $330, and and th I'tility is required to male semi-annual sinking fimd $515 million, respectively. The Utility's share of those sink-payments for the retirement of the bonds. Additional mort- ing fund requirements is $601, $217, $223, $233, and $389 gage bonds may be issued subject to CPUC approval, up to a million, respectively.

maximum total amount outstanding of $10 billion.

The Utility redeemed or repurchased $167 million and Fair Value: The estimated fair value of the Corporation's

$182 million of mortgage bonds in 1997 and 19'16, respec- total long-term debt at December 31,1997, and 1996, was tively, with interest rates ranginF from 5.375 percent to approximately $8.3 billion and $8.0 billion, respectively.

8.875 percent. The estimated fair value of the Utility's total long-term debt included in the total of outstanding mortgage bonds at at December 31,1997, and 1996, was appre imately $7.0 December 31,1997, and 1996, are $705 million of mortgage billina and $7.3 billion, respectively. The estimated fair bonds hdd in trust for the California Pollution Control value oflong-term debt was determined based on quoted Financing Authority (CPCFA) with interest rates ranging market prices, where available. Where quoted market prices from 5.85 percent to 8.875 percent and maturity dates were not available, the estimated fair value was determined ranging from 2007 to 2026. In addition to these mortgage using other valuation techniques (for example, the present bonds, the Utility holds long-term loan agreements with the value of future cash Dows).

CPCFA as described below.

Note 7 Pollution Control Loan Agreements: Rate Reduction Bonds I,oan agreements from the CPCFA totaled $1,348 million and $988 million, respectively, at December 31,1997, and in December 1997, PG&E Funding LLC (SPE), a special-1996. Interest rates on the loans vary with average annual purpose entity wholly owned by the Utility, issued $2.9 bil-interest rates for 1997 ranging from 3.01 percent to lion of rate reduction bonds to the California infrastructure i.92 percent. These loans are subject to redemption by and Economic Development llank Special Pu: pose Trust the holder under certain circumstances. These loans are PG&E-1 (Trust), a special-purpose entity. The terms of the secured by irresocable letters of credit which mature as bonds generally mirror the terms of the pass-thmugh cer-early as 2000. tificates issued by the Trust. The proceeds of the rate reduc-tion bonds were used by the SPE to purchase from the Unregulated Business Operations: Long-term debt of Utility the right, known as " transition property," to be paid a unregulated business operations, as of December 31,1997, specified amount from a nonbypassable tarifflevied on resi-consisted primarily of first mortgage bonds of $409 million, dential and small commercial customers u hich was autho-medium-term and senior notes of $404 million, unsecured rized by the CPUC pursuant to state legislation.

notes and debentures of $397 million, and other long-term The rate reduction bonds have maturities ranging from debt of $310 million. The fixed interest rates on these oblig- ten months to ten years, and bear interest at rates ranging ations range frora 6.33 percent to 9.25 percent, with maturi- from 5.94 percent to 6.48 percent. The bonds are secured ties ranging from 1998 to 2025. solely by the transition property and there is no recourse to Outstanding long-term debt as of December 31,1996, the Utility or the Corporation.

consisted primarily of $470 million of unsecured notes and At December 31,1997, the combined aggregate amounts debentures. and other long-term debt of $231 millon. of maturing rate reduction bonds, for the years 1998 50

~

through 2002, are $125, $265, $280, $300, and $290 million, required no short-term borrowings due to the receipt of the respectively. rate reduction bond proceeds.

The estimated 6ir value of the rate reduction bonds was approximately $2.9 billion at December 31,1997. The esti- Note 9.

mated fair value of the bonds was detennined based on Nuclear Decommissioning quoted market prices.

While the SPEis consolidated with the Utility for purposes Decommissioning of the Utility's nuclear power plants is of these financial statements, the SPE is legally separate from scheduled to begin in 2015 with scheduled completion in the Utility.The assets of the SPE are not available to creditors 2034. Nuclear decommissioning means to safely remove of the Utility or the Corporation, and the transition property nuclear facilities from service and reduce residual radio-I is legally not an asset of the Utility or the Corporation. activity to a level that permits termination of the Nuclear Regulatory Commission license and release of the property Note 8. for unrestricted use.

Short-Term Borrowings The estimated total obligation for nuclear decommis-sioning costs, based on a 1997 site study, is appmximately In January 1997, the Corporation established a $500 million $1.4 billion in 1997 dollars (or $5.1 billion in future dollars).

revolving credit facility, which expires in 2002. In August This estimate assumes after-tax earnmgs on the tax-qualified

^

1997, the Corporation entered into an additional $500 and nontax-qualified decommissioning funds of 6.16 percent million temporary credit facility w hich expires in 1998, and 5.21 percent, respectively, as well as a future annual Both of these credit 6cilities are to be used for general escalation rate of 5.5 percent for decommissioning costs.

corporate purposes.There were no borrowings under these The decommissioning cost estimates are based on the plant credit facilities at December 31,1997. location and cos: characteristics for the Utility's nuclear In addition, the Utility maintains a $1 billion revolving plants. Actual decommissioning costs are expected to vary credit facility which expires in 2002. The facility may be from this estimate because of changes in assumed dates of extended annually for additional one-year periods upon decommissioning, regulatory requirements, technology, and mutual agreement between the Utility and the banks. costs oflabor, materials, and equipment. The estimated total There were no borrowings under this credit facility in obligation is being recognized proportionately over the 1997 or 1996. license of each facility.

At December 31,1997, the Corporation had outstanding l'or the years ended December 31,1997,1996, and

$103 million of short-term bank borrowings at a 6.9 percent 1995, nuclear decommissioning costs recovered in rata weighted average interest rate. In addition to borrowing from were $33, $33, and $54 million, respectively. Based on the banks on a short-term basis, the Corporation and certain of 1997 site study, the amount approved to be recovered in its subsidiaries sell commercial paper, having a maturity of rates in 1998 and annually, until the commencement of

- one to ninety days, to provide financing for various corporate decommissioning,is $33 million.This amount will be purposes. The carry ing amount of short-term borrowings reviewed in future rate proceedings.

approximates fair value. At maturity, commercial paper can At December 31,1997, the total nuclear decommis-

- be either reissued or replaced with borrowings from the sioning obligation accrued was $1.0 billion and was revolving credit facility. At December 31,1997, the included in the balance sheet classification of Corporation had no commercial paper outstanding. Accumulated Depreciation and Deconunissioning.

At December 31,1996, the Utility had outstanding $681 Decommissioning costs recovered in rates are placed in million of commercial paper at a 5.83 percent weighted external trust funds. The earnings on the external trusts

average interest rate. At December 31,1997, the Utility accumulate in the fund balance and are included in the J

51

t Notes to Consolidated Financial Statements balance sheet classification of Other Noncurrent Assets. Note 10:

These funds along with accumulated earnings will be Ernployee Benefit Plans used exclusively for decommissioning and cannot be released from the trust funds until authorized by the Retirement Plans: Several of the Corporation's sub-CPUC. sidiaries provide noncontributory defined benefit pension The following table provides a summary of amortized plans for their employees. The Utility's plan represents sub-cost and fair value of these nuclear decommissioning funds: stantially all of the plan assets and the projected benefit obligation. All descriptions and assumptions are based ive7 ises v.., .. . o-.mu., s i. u. oni, o.i.,.

ori & Utilin's plan which covers the largest number of i.a mmmno empi yees.The schedules below aggregate all of the Amortized cost U.S. government and Corporation's plans, agency issues 1998-2027 $ 422 $373 Pension benefits are based on an employee's years of ser-Equity securities - 257 281 vice and base salary. The Corporation's policy is to fund Municipal bonds and other 1998-2021 70 33 Gross unrealized holding gains 287 199 each year not more than the maximum amount deductible Gross unrealized holding losses (12) (5) for federal income tax purposes and not less than the mini-Fair value $1.024 $H83 inum legal funding requirement.

The following schedule reconciles the plans' funded sta-The proceeds received during 1997 and 1996 from sales tus to the prepaid pension cost or accrued pension liability of securities were approximately $1.4 billion and $1.5 billion recorded on the Consolidated Balance Sheet:

in each year, respectively. During 1997 and 1996, the gross 0"**"' "" ""

realized gains on sales of securities hehl as available-for-sale nommmno were $40 million and $14 million, respectively, and the gross Actuarial present value of benefit obligations realized hwses on sales of securities held as available-for-sale Vested benefits $(3,659) $(3,486)

Nonvested benefits (198) (178) were $24 million and $20 million, respectively. The cost Accumulated benefit obligation (3,857) 0,664) of debt and equity securities sold is determined by specific Effect of projected future compensation identifican,on.

increases (561) (529)

Under the Nuclear Waste Policy Act of 1982, the Projected benefit ubhgation (4,418) (4,193)

Department of Energy (DOE) is responsible for the perma. Plan assets at market value 6.419 5.526 nent storage and disposal of spent nuclear fuel.The Utility Plan assets in excess of projected benefit

. obhgation 2,001 1,333 has signed a contract with the DOE to provide for the dis- Unrecognized prior service cost 121 83 posal of spent nuclear fuel and high-level radioactive waste Unrecognized net gain (2,135) (1,559)

Unrecognized net transition obligation 74 86 from the Utility's nuclear power facilities. The DOE's cur.

rent estimate for an available site to begin accepting physical Prepaid pension cost (accrued pension hability) $ 61 $ (571 possession of the spent nuclear fuelis 2012. At the projected level of operation for Diablo Canyon, the Utility's facilities The Utility's share of the plan assets in excess of pro-are st;fficient to store on-site all spent fuel produced jected benefit obligation for 1997 and 1996 was $2.0 and through approximately 2006. It is likely that an interim or $1.3 billion, respectively. The Utility's share of the prepaid permanent DOE storage facility will not be available for pension cost for 1997 was $75 million and the accrued Diablo Canyon's spent fuel by 2006. The Utility is examin- pension liability for 1996 was $53 million.

ing options for providing additional temporary spent fuel Plan assets consist primarily of common stocks and fixed storage at Diablo Canyon or other facilities, pending dis- income securities. Unrecognized prior service costs and posal or storage at a DOE facility. net gains are amortized on a straight line basis over the 52

average remaining service period of active plan participants. tory defined benefit medical plans for retired employees and The transition obligation is being amortized over 17.5 years their eligible dependents and noncontributory dermed bene-from 1987. fit life insurance plans for retired employees. The Utility's Using the projected unit credit actuarial cost method, net plan represents substantially all of the plan assets and the pension income consisted of the following components: total accumulated postretirement benefit obligation. All descriptions and assumptions are based on the Utility's plan u., .no.o o.c.,no., at ie.1 iese  :.

which covers the largest number of employees. The sched-

"a"'"*"

ules below aggregate all of the Corporation's plans.

Service cost for benefits carned S (101) $(loa $ (83)

Interest cost (313) (302) (291) Most employees retiring at or after age 55 ate eligible for Actual return on plan assets 1,139 811 968 these benefits. The medical benefits are provided through Net amortization and deferral (598) 0 53) (586) plans administered by an insurance carrier or a health main-Net pension income $ 127 5 56 5 8 tenance organization. Certain retirees are responsible for a portion of the costs for these benefits.

The Utility's share of the plan's net pension income The CPUC has authorized the Utility to recover these for 1997,1996, and 1995 was $128, $57, and $8 milhon, benefits for 1993 and beyond. Recovery is based on the respectively. lesser of the annual accounting costs or the annual contribu-Net pension income or cost is calculated using expected tions on a tax-deductible basis to appropriate trusts. The return on plan assets.The difference between actual and policy is to fund each year an amount consistent with the expected return on f an l assets is included in net amortiza- basis for rate recovery.

tion and deferral and is considered in the determination of The following schedule reconciles the medical and life future net pension income or cost. In 1997,1996, and 1995, nsurance plans' funded status to the postretirement benefit actual return on plan assets exceeded expected return liability recorded on the Consolidated Ihlance Sheet:

In conformity with SFAS No. 71, regulatory adjustments o.c.=ber at 1887 1***

have been recorded in the income statement and balance "a"""*"

sheet of the Utility which reflect the difference between Accumulated postretirement benef;t obligation Utility pension .mcome or cost determined for accounting Retirees $(400) $(445) purposes and that for ratemaking, which is based on a fund. Other fully eligible participants (140) (132)

Other active plan p rticipants 067) (344) ing approach.

Total accumidated postretirement benefit The following actuarial assumptions were used in deter-obligation (907) (921) mining the plans' funded status and net pension income. Plan assets at market value H23 666 Year-end assumptions are used to compute funded status, Accumulated postrctirement benefit obligation while prior year-cod assumptions are used to compute net in excess of plan assets (84) (255)

Unrecognized prior service cost 20 22 pension income. Unrecognized net gain (375) (227)

Unrecognized transition obligation 393 420 om.n., at iner insa i.es Accrued postretirement benefit liability 5 (46) $ (40) bn mHhons)

Discount rate 7.5% 7.5% 7.25 %

Rate of future compensation The Utility's share of the accumulated postretirement increases 5% 5%. 5%

benefit obligation in excess of plan assets for W27 and 1996 Expected long-term rate of rerum on plan assets 9% 9% 9% was $64 and $249 million, respectively. The Utility's share of the accrued postretirement benefit liability for 1997 and

Postretirement Benefits Other Than Pensions: 1996 was $29 and $38 million, respectively. j I

' Several of the Corporation's subsidiaries provide contribu- Plan assets consist primarily of common stocks and 53' a-

Notes to Consolidated Financial Statements fixed income securities. Unrecognized prior senice costs 1996, and 1995, actual return on plan assets exceeded are amortized on a straight-line basis over the average expected return.

remaining years of service to full eligibility of active plan participants. Unrecognized net gains are amortized on a Long-term Incertive Prograrn: pG&E Corporation straight-line basis over the average remaining years of maintains a Long-term Incentive Program (Program) which service of active plan participants.The transition obligation provides Ihr grants of stock options to eligible participants is being amortired over 20 years from 1993. with or without associated stock appreciation rights and div-Using the projected unit credit actuarial cost method, net idend equivalents. As of December 31,1997,24.5 million postretirement medical and life insurance cost consisted of shares of common stock have been authorized for award the following components: under the program. At December 31,1997, stock options on 6,181,819 shares, granted at option prices ranging from v... .oo.o o.c.me., si. i887 1998 1995

., $16.75 to $34.25, were outstanding, of w hich 1,902,545 on ma%o.,

wcre exercisable. In 1997, 3,048,400 options were granted Service cost for benefits earned $(2 I) $(22) $(17)

Interest cost (65) (66) (69 at an average option price of 522.55.

Actual return on plan assets 1+4 91 109 Outstanding stock options expire ten years and one day Amort zatim of unrecognized prior g gg gg

, 4 Amortization of transition obhgation (25) (26) (26) tive basis at one-third each year conunencing two years Net amortization and deferral (71) (38) (70) from the date of grant. In 1997,1996, and 1995, stock Net postretirement benefit income options on 232,815,72,960, and 235,568 shares,respec-(cost) S(40) $(63) 5(71) tively, were exerci ed at option prices ranging from $16.75 to S33.13.

The Utility's share of the plan's net postretirement bene- Effective January 1,1996, the Corporation adopted SFAS fit cost ihr 1997,1996, and 1995 was $38, $61, and 571 mil- No.123," Accounting for Stock-Ilased Compensation."

lion, respectively. SFAS No.123 requires the Corporation to disclose stock The discount rate, rate of future compensation increases, option costs based on the fair value of options granted. For and expected long-term rate of return on plan assets used the years ended December 31,1997, and 1996, the fair value in accounting for the postretirement benefit plans for of options granted was not material to the Corporation's 1997,1996, and 1995 were the same as those used for the results of operations or earnings per share, pension plan.

The assumed health care cost trend rate for 1998 is Note 11 approximately 9.5 percent, grading down to an ultimate rate income Taxes in 2005 of approximately 6.0 percent.The effect of a one-percentage-point increase in the assumed health care cost The Corporation files a consolidated federalincome tax trend rate for each future year would increase the accumu- return that includes domestic subsidiaries in which its own-lated postretirement benefit obligation at December 31, ership is 80 percent or more. Income tas expense includes 1997, by approximately $70 million and the 1997 aggregate current and deferred income taxes resulting from operations service and interest costs by approximately 58 million. during the year. Tax credits are amortized over the life of Net postrctirement benefit cost is calculated usinF the related property, expected return on plan assets. The difference between

- actual and expected return on plan assets is included in net amortization and deferral and is considered in the deter-mination of future postretirement benefit cost. In 1997, 54 c_-_--_-___-_____-_____________ .

The significant components ofincome tax expense were:

PGH Corporation Utsuty l

Vaar anded December $1,' 1997 1996 1996 9997 1996 1995 ten melhonal Current S707 $ 705 $1,011 $791 $ 70s $1,011 Deferred (119) (132) (98) (142) .(132) (98)

Tax uedits---net (40) (18) (18) (40) (18) (18)

'fistal income tax expense $548 $ 555 $ 895 $609 $ 555 $ 895 The significant components of net deferred income tax liabilities were:

PG&E Corporation Utahty Dweembot 31, 1997 1996 1C97 1996 Ge milhonal Deferred income tax assets $1,108 $1,308 $ 962 $1,308 Deferred income tax liabilities:

Regulatory balancing accounts 311 294 311 294-Plant in service 3,621 3,624 3,144 3,624

. Income tax regulatory asset 430 454 420 454 Other 924 1,034 540 1,034

'listal deferred income tax liabilities 5,286 5,406 4,415 5,406

'listal net deferred income taxes S4.178 $4,098 $3.453 $4,098 Classification of net deferred income taxes:

Included in current liabilities $ 149 $ 157 $ 149 $ 157 included in noncurrent liabilities 4,029 3,941 3,304 3,941

'fotal net deferred income taxes $4.178 $4.098 $3.453 $4,098 The differences between income taxes and amounts

- determined by applying the federal statutory rate to income

- before income tax expense were:

PG&E Corporation Utihty Year ended December 31, 1997 1996 1996 1997 1996 1995 Federal statutory income tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 %

Increase (decrease) in income tax rate resulting from: j State income tax (net of federal benefit) 5.3 3.8 5.0 4.6 3.7 4.8 )

Effect of regulatory treatment of depreciation differences 8.1 6.0 3.2 7.5 5.9 3.2 l Tax credits-net (3.2) (1.4) (0.8) (2.9) (1.4) (0.8) l Effect oflower taxes on foreign earnings (2.2) - - - - -

l Other-net 0.3 -

(1.0) -

(0.8) (2.1) .

Effective tax rate 43.3 % 43.4 % 41.4 % 44.2 % 42.4 % 40.1% j l

l I

55 l

. . . . . . . . . - .. . . . . . . . . . . ~ . . . . . . . . . .. .

_. .. .. . .. .. . _.....________a

I i

{

Notes to Consolidated Financial Statements i i

i Note 12: The Utility also has c w tracts with various irrigation dis-Commitments tricts and w iter sgencies to purchase hydroelectric power.

Under these contracts, the Utility must make specified Letters of Credit: The Utility uses approximately $335 semi-annual minimum payments w hether or not any energy million in standby letters of credit to secure future workers' is supp!ied (subject to the provider's retention of the FERC's compensation liabilities. authorization) and variable payments for operation and maintenance costs incurred by the prmiders. These con-Restructuring Trust Guarantees: Tax-exempt trusts tracts expire on various dates from 2004 to 2031.These have been established to oversee the development of the costs are also iccoverable in rates. At December 31,1997, operating framework for the competitive generation market the undiscounted future minimum payments under these (See Note 2, Electric Industry Restructuring). The CPUC contracts are 534 million for each of the years 1998 through has authorized California utilities to guarantee bank loans of 2002 and a total of $349 million fu periods thereafter.

up to $?ou million to be used by the trusts for this purpose. Irrigation district and water agency deliveries in the aggre-Uooet uis authorization, the Utility has guaranteed up to a gate account for approximately four percent of the Utility's maximum of $135 mi: lion of these loans. 1997 electric energy requirements.

The amount of energy received and the total payments Power. Purchase Contracts: lly federal law, the Utility is made under all of these power-purchase contracts were:

required to purchase electric energy and capacity provided

• • 'ad*d D*'** b ' i- i'S7 1898 1995 by cogenerators and small power producers. The CPUC Un melhonal established a series af power-purchase contracts and set the Kilowatt-hours received 24,389 26,056 26,468 applicable terms, cor.ditions, price options, and cligibility Energy payments $ 1,157 $1,D6 $ 1,140 requirements. Capacity payments $ 538 $ 521 S 484 Irrigation district and water Under the.se contracts, the Utility is required to make ap ncy payments S 56 5 52 $ 50 payments only when energy is supplied or when capacity commitments are met. The total cost of these payments is Note 13 recoverable in rates. The Utility's contracts with these contingencies power producers expire on various dates through 2028.

'Ibtal energy payments are expected to decline in the years Nuclear insurance: The Utility has insurance coverage 1998 through 2001. 'Ibtal capacity payments are expected to for property damage and business interruption losses as a remain at current levels during this period. Deliveries from member of Nuclear Electric Insurance Limited (NEIL).

these power producers account for approximately IH per- Under this policy, if a nuclear generating facility of a mem-cent of the Utilir>'s 1997 electric energy requirements, and her utility suffers a loss due to a prolonged accidental out-no single contract accounted for more than five percent of age, the Utility may be subject to maximum assessments of the Utility's energy needs. 523 million (property damage) and $7 million (business The Utility has negotiated early tenninetion or suspen- nterruption), in each case per policy period, in the event sion of certain power-purchase contracts. These amounts losses exceed the resources of NEIL {

are expected to be recovered in rates and as such are The Utility has purchased primary insurance of $200 reflected as deferred charges on the accompanying balance million for public liability claims resulting from a nuclear (

sheet. At December 31,1997, the total discounted future I incident. An additional 58.7 billion of coverage is prmided payments remaining under early termination or suspension by secondary financial protection which provides for loss contracts is $53 million. sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in 56

claims in excess of $200 million, the Udlity may be assessed ation at identiGed sites may be as much as $442 million if, up to $159 million per incident, with payments in each year among other things, other potentially responsille parties are limited to a maxinrnn of S20 million per incident. not financially able to contribute to these costs or further investigation indicates that the extent of contamination or Environrnental Remediation: The Corporation may be necessary remediation is greater than anticipated at sites for required to pay for environmental remediation at sites which the Utility is responsible.This upper limit of the where the Corporation has been or may be a potentially range of costs was estimated using assumptions least favor-responsible party under the Comprehensive Environmental able to the Utility, based upon a range of reasonably possible Response, Compensation and Liability Act (CERCLA) or the outcomes. Costs may be higher if the Utility is found to be

' California 1lazardous Substance Account Act.These sites responsible for cleanup costs at additional sites or identifi.

include former manufactured gas plant sites, power plant able possible outcomes change.

sites, and sites used by the Utility for the storage or disposal Or Se 5232 million liability discussed above, the Utility of materials which may be determined to present a signiG- expects to recover $157 million in future rates. The liability cant threat to human health or the environment because of also includes $58 million related to power plant decom-an actual or potential release of hazardous substances. missioning for environmental clean.up, which the Utility Under CERCLA, the Corporation's financial responsibilities recovered through depreciation. Additionally, the Utility may include remediation of hazardous substances, even if is seeking recovery of costs from insurance carriers and the Utility did not deposit those substances on the site. from other third parties. The Corporation believes the The Utility records a liability when site assessments indi- ultimate outcome of these matters will not have a material cate remediation is probable and a range of reasonably likely adverse impact on its or the Utility's Gnancial position or cleanup costs can be estimat-d. The Utility reviews its sites resuhs of operations.

and measures the liability quarterly, by assessing a range of reasonably lit.cly costs for each identified site using cur- Helms Pumped Storage Plant (Helmsh IIelms is a rently available information, including existing technology, three-unit hydroelectric combined generating and pumped presently enacted laws and regulations, experience gained storage plant owned by the Utility. At December 31,1997, at similar sites, and the probable level ofinvolvement and the Utility's net investment was $691 million. This net Anancial condition of other potentially responsible parties. investment is comprised of the pumped storage facility These estimates include costs for site investigations, remedi- (including regulatory assets of $51 million), common plant, ation, operations and maintenance, monitoring, and site and dedicated transmission plant. As part of the 1996 closure. Unless there is a better estimate within this range General Rate Case decision it December 1995, the CPUC ..

' of possible costs, the Utility records the lower end of directed the Utility to perform a cost-effectiveness study of l this range. IIelms. InJuly 1996, the Utility submitted its study, which The cost of the hazardous substance remediation ulti- concluded that the continued operation ofIIelms is cost mately undertaken by'the Utility is diffictdt to estimate. It is effective.The Utility recommended that the CPUC take no reasonably possible that a change in the estimate will occur action and address IIchas along with other generating

. in the near term due to uncertainty concerning the Utility's plants in the context of electric industry restructuring. ]

responsibility, the complexity of environmental laws and Under electric industry restructuring, the uneconomic, regsdations, and the selection of compliance alternatives. ' above-market portion of Helms is eligible for recovery as a The Utility had an accrued liability at December 31,1997, transition cost. Ilowever, the Utility will be placed at risk to of $232 million for hazardous waste remediation costs at recover its future operating costs in the newly restructured those sites, including fossil-fueled power plants, where such electric generation market, costs are probable and quantifiable;Emironmental remedi-

$7 -

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Notes to Consolid ted Financial Statements l I

liccause the CPUC has not specifically addressed the Texas Franchise Fee Litigation: i cost-effectiveness study, the Utility is currently unable to In connection with PG&E Corporation's acquisition of I predict u hether there will be further changes in rate recov- Valero, now known as PG&E Gas Transmission, Texas ery. The Corporation believes that the ultimate outcome Corporation (mT), mT succeeded to the litigation of this matter will not have a material adverse impact on its described below, or the Utility's financial position or results of operations. mT and various ofits affiliates are defendants in at least two class action subs and five separate suits filed by various Legal Matters: Texas cities. The class action suits involve plaintiffs that Chromium Litigation: serve as class representatives for classes consisting of every in 1994 through 1997, several civil suits were filed against municipality in Texas (excluding certain cities which filed the Utility on behalf of approximately 3,000 individuals. separate suits)in which any of the defendants engaged in The suits seek an unspecified amount of compensatory and business activities related to natural gas or natural gas liq.

punitin damages for alleged personal injuries and,in some uids or sold or supplied gas or used public rights-of-way.

cases, property damage, resulting from alleged exposure Generally, these cities allege, among other things, that (1) to chromium in the vicinity of the Utility's gas compressor the defendants that own or operate pipelines have occupied stations at Ilinkley, Kettleman, and 'li> pock. city property and conducted pipeline operations without the The Utility is resp <mding to the suits and asseiting affir- cities' consent and uithout compensating the cities, and n:ative defenses. The Utility will pursue appropriate legal (2) the defendants that are Fas marketers have failed to pay defenses, including statute of limitations or exclusivity of the cities for accessing and utilizing the pipelines located in workers' compensation laws, and factual defenses including the cities to flow gas under city streets. Plaintiffs also allege lack of exposure to chromium and the inability of chromium various other claims against the defendants for failure to to cause certain of the illnesses alleged. secure the cities' consent. Damages are not quantified.

The Corporation believes that the uhimate outcome of The Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or these matters will not hase a material adverse impact on its the Utility's financial position or results of operations. financial position.

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Note 14:

Segment information The Corporation's business segments consist of the Utility and Unregulated llusiness Operations (consisting of gas transtnission, electric generation, and energy services and commodities).

The Corporation's business segment inforniation was:

Pacific Ges and Electric Company Unreguteted Electric Gas Total Business Corporate Utility Utility util,ty Operations and other ** total On millionst 1997 Operating revenues $ 7,691 $1,804 5 9,495 $5,905 5- $15,400 13 90 103 446 (549) -

Intersegment revenues">

7,704 1,H94 9,598 6,35I (549) 15,400

'Ibtal operating revenues 1,521 264 1,785 104 - 1,HH9 Depreciation and decommissioning 1,510 321 1,831 (82) (21) 1,728 Operating income before income taxes'n 1,196 313 1,529 341 - 1,870 Capital expenditures 19,546 5,601 25,147 6,224 (814) 30,557 JIbtal assets at year end "

1996

$ 7,160 $1,829 $ 8,989 $ 621 $- 5 9,610 (

Operating revenues Intersegment revenues'" 12 70 82 58 (140) -

7,172 1,H99 9,071 679 (140) 9,610 lbtal operating revenues 920 256 1,176 46 - 1,222 Depreciation and decommissioning 1,758 52 1,810 84 2 1,896 Operating income before income taxes'"

922 309 1,231 173 - 1,404 Capital expenditures 18,431 5,136 23,567 2,858 (188) 26,237

- Thral assets at year end "

1995 5 7,387 $1,856 $ 9,243 $ 379 $- $ 9,622 Operating revenues Intersegment revenues'" 13 85 98 68 (166) -

7,400 1,941 9,341 447 (166) 9,622 lbtal operating revenues 1,007 267 1,274 H6 - 1,360 Depreciation and decommissioning 2,267 420 2,687 71 5 2,763 Operating income before income taxes *>

680 195 H75 90 -

965 Capital expenditures 19,441 5,248 24,689 2,578 (396) 26,871

• lhtal assets at year end "

Interwgmsnt electnc and gas revenues are accounted for at tariff rates prescribed by the trUC.

M',eneral wrpwate expenes are sikreted in suordance with D RC Uniform System of Acounts and reqinrements of the Cftt dat!tihty includes an alkicFm of conunon plant m service and alinwance for funds uwd dunng mnanwtwn.

"Corpante and other awets sansist of cash and ca.h eqmvalents, shon tenn im en.nenvi, retchahin transferred fmm aftihates and other awets.

"' Includes cona,hdatmg chnunstiunt c

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....._m.,.m..

Quarterly Consolidated Financial Data (Unaudited)

Due to the seasonal nature of the Utility but tnd the an increase in energy cost revenues to recover energy cost scheduled refueling outages for Diablo Canyon, operating increases. Operating expenses increased primarily due to the revenues, operating income, and net income are not gener- increases in Diablo Canyon depreciation and the cost of ated evenly every quarter during the year. energy.

PG&E Corporation I997: 1996:

All four quarters of 1997 re0ceted an increase in revenues in the second quarter of 1996, operating expenses increased and expenses due to the acquisitions discussed in the Notes primarily due to the settlement of a litigation claim. In the to the Consolidated Financial Statements, third quarter of 1996, operating expenses increased primar-In the second quarter of 1997, other income increased ily due to charges for gas transportation commitments.

primarily due to the gain on the sale ofInternational in the fourth quarter of 1996, operating revenues and Generating Company, Ltd., which was partially offset by operating expenses increased primarily due to the purchase write-downs of certain nonregulated investments, of Energy Source in December 1996. Other income decreased due to write-downs of certain nonregulated

. Utility I997: investments.

All four quarters of 1997 reDected an increase in operating The Corporation's common stock is traded on the New revenues primarily due to the revisions to the Diablo York, Paci6c, and Swiss stock exchanges. There were Canyon ratemaking structure, changes in sales volume pro- approximately 180,000 common shareholders of record at vided by the Utility's energy rate recovery mechanisms, and December 31,1997. Dividends are paid on a quarterly basis.

Overte# ended December 31 September 30 June 30 March 31 On mHlions, eucept per share amoun,e) 1997 PG&E Corporation Operating revenues $4,H89 $4,063 $3,083 $3,365 Operating income 265 62H 371 464 Net income 94 257 193 172 Earnings per conunon share, basic and diluted .22 .62 .49 .42 Dividends declared per conunon share .30 .30 .30 .30 Connnon stock price per share Iligh 30.94 24.94 25.00 24.25 low 23.00 22.69 22.38 20.88 Utility Operating revenues $2,401 $2,541 $2,279 $2,274 Operating income 390 626 370 445 Income available for connnon stock 180 269 122 164 1996 PG&E Coporation.and Utility Operating revenues $2,.700 $2,522 $2,139  !?,249 I Operating income 509 525 288 574 Net income 141 225 104 252 F.arnings per common share, basic and diluted .34 .55 .25 .61 Dividends declared per common share .30 .49 .49 .49 Common stock price per share .

Iligh 24.25 23.88 23.75 28.38  !

1,nw. 20.88 19.50 21.50 22.38 l J

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Report of Independent Public Accountants To the Shareholders and the Board of Directors of PG&E Corporation and Pacific Gas and Electric Company; We have audited the accompanying consohdated balance sheets of PG&E Corporation (a California corporation) and subsidiaries and of Pacific Gas and Electric Company (a Cahfornia corporation) and subsidiaries as of December 31,1997, and 1996, and the related statements of consolidated income, cash flows, and common stock equiry, preferred stock, and preferred securities for each of the three years in the period ended December 31,1997.These financial statements are the responsibihty of the management of PG&E Corporation and of Pacific Gas and Electric Company. Our responsibility is to express an opinion on these financial state-ments based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perfonn the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable b. sis for our opinion.

In our opinion, the financial statements referred to above present fairly,in all material respects, the financia! positions of PG& E Corporation and subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of December 31,1997, and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31,1997, in conformit) with generally accepted accounting principles.

ARTIlUR ANDERSEN LLP San Francisco, California February 9,1998 Responsibility for Consolidated Financial Statements At both PG& E Corporation and Pacific Gas and Electric Company (the Utility), management is responsible for the integrity of the accompanying consolidated financial statements. These statements have been prepared in accordance with generally accepted accounting principles. Management considers materiality and uses its best judgment to ensure that such statements reflect fairly the financial position, results of operations, and cash flows of PG&E Corporation and the Utility.

PG& E Corporation and the Utility maintain systems ofinternal controls supported by fonnal policies and pmcedures u hich are communicated throughout PG& E Corporation and the Utility. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and that necessary records are produced for the preparation of consoli-dated financial statements. There are limits inherent in all systems of internal controls, based on the recognition that the costs of such systems should not exceed the benefits to be derived. PG&E Corporation and the Utility believe that their systems ofinternal control provide this appropriate balance. PG& E Corporation management also maintains a staff of internal auditors u ho evaluate the adequacy of, and assess the adherence to, these controls, policies, and procedures for all of PG& E Corporation, including the Utility.

Both PG& E Corporation's and the Utility's consolidated financial statements have been audited by Arthur Andersen LLP, PG&E Corporations independent pubhc accountants.The audit includes a review of the internal accounting controls and perfor-mance of other tests necessary to support an opinion. The auditors' report contains an independent informed judgment as to the fairness, in all material respects, of reported results of operations and financial position.

The Audit Committee of the Board of Directors for PG&E Corporation meets regularly with management, internal auditors, and Arthur Andersen LLP, joindy and separately, to review internal accounting controls and auditing and financial reporting mat-ters. The internal auditors and Arthur Andersen LLP have free access to the Audit Committee, w hich consists of five outside direc-tors.The Audit Committee has reviewed the financial data contained in this report.

PG& E Corporation and the Utility are committed to full compliance with all laws and regulations and to conducting business in accordance with high standards of ethical conduct. Management is taking the steps necessary to ensure that all employees and other agents understand and support this commitment. Guidance for corporate compliance and ethics is prmided by an officers' Ethics Committee and by a Legal Compliance and Business Ethics organir.ation. PG&E Corporation and the Utility believe that these efforts provide reasonable assurance that each of their operations are cmducted in conformity with applicable laws and with their conunitment to ethical conduct.

61

Directors i

I Boards of Directors of Alary S, Aletz Permanent Committees of Nominating and PG&E Corporation and Dean, University Extens n, PG&E Corporation and Compensation Pacific Gas and Unwenity of Cahfornia, Berkeley Pacific Gas and Committee Electric Company

• Electric Company" Remmmends candidates for .

Rebecca Q. Alorgan nomination as directuri, recom-Richard A. Clarke Prnident and Executive Committees rnends mmpenution and employee Chairman of the Board, Retired, Chief Execuuve Of6ccr, Wittun limits, may esercise powers benefit policies and practices, and Pacific Gas and Electric Company Joint Venture: and perfunn dutie< of the Boards. reviews planning for esecutive i Sibcon Valley Network development and succesuun.

(nonprufu collalorauve addinsing .

Ilarry A1.C,onger ernical issues facmg Nheon Wiley)

Robert D. Glynn,Jr., Chair Chainnan of tbr Board, Ilarry A1. Conger C,arl E. Reichardt, Cha,r ilomntake mung Company Richard B. Aladden David A. Coulter Carl E. Reichardt David A11awrerxx, AID Atan S. Aletz Chainnan of the Board and DAid A. Coulter CI E' R'i'h'rd' chid Executive Officer, Retired. I John C. Sawhill Chainuan and Chief Gordon R. Senith..

Welk Fargo & Cony >any and Executive Of6cer, Welb Fargo Bank, NA B'""'""*

• C"'P" d"" '"d Audit Committee Bank of America N'IMA Reviews 6nancial statements and Public Policy John C,. Sawhill President and

'"'""'"*"d'""""I Comm.ttee i C I'CC CUT Chief Execuuve Of6cer, pnelnrn u a cpen ent Reviews puhhc pohcy mues uhich We Chairman, Retired, P" """""" '"u gn candy shui custoinen,

'I he Nature Consen ancy Air hch Communications, Inc. shareholden, employen, or the (mten.ational environmental sml Prnident and Chief Execunvc Arganintion) 1(arry A1. Conger, Chair *'"""*i'i"'d"d"*~

Of6cer, Renred C. la Cm * *"d' Pl '"' '"d P'"E** '"

Air'thm h Cc!!ul'ar addrns such mues.  ;

",'"' E Dd' I Alan Seelenfreund Chainnan of the Board and AI'fY S AIC" Wilharn S. Davila Harry Lauson Williams Alary S. Aletz, Chai r fonner Chief Execuuve Officer, Prnident Ementus, '"^* # #

Mason Corporation The Wu Companics, Inc. (dntributor of pharmaccuncah and amE Da a (reud ynn er)) Finance Commi ttee Rebecca Q. Alorgan heahh care produm)

Reviews long-renn financial and John C. Sawhill capital invntment pohcin and Robert D. Glynn,Jr. Gordon R. Smith

• obicaiva, and uuons required to Chainnan of the Board, President and achieve those objectives.

Chief Executive Of6c-r, and Chid Executive Officer, i Prnident, Paci6c Gas and Electric Onnpany Richard B. Aladden, Chair  !,

PG& E Corporanon and Chainnan of the lioard, Richani A. Clarke Pan 6c Gas and Electric Company llarry Law son Wilhams David A. Coulter PrniJent, Carl E. Reichardt Wilhams Pacific Venturn,Inc. - John C. Saw hill David Al. Lawrence, A1D (venture capnal and real nute. Barry 1.auwon Williams Chairman and consuhing, and mediation)

Chief Executive Of6cer, Kaiser Foundation IIcalth Plan, Inc.

and Kaiser Foundation lioapitak l

[

Richard II. Aladden Chainnan of the Ihurd and Chief Esecutive OtScer, Renred, Podaich Corporation tdiversi6cd fornt prmhicts) l l

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"The comemnion of the Boards of Direttors is the same, except that Gadon R. Suuth is a memter of the Paci6c Gas and Flectric Company Board of Directon only.

• hept for the Enecutive Conmuttee, all Comnuttees bsred above are romnuttees of the PG& F G>rporanon Board of Directon. The Execunve Cmnmnters of the PG& E Corporation amt Paci6c Gas and I?lecmc Conymny Roanh hee the ume members, except that Gordon R. Smnh is a memler of the Paafic Ga and 1Jettnc Company Executive Gunmmee only 62 w

Officers P!&E Corporation Wondy S. Lee Katheryn M. Fong U.S. Generating Company Assistant Corturate Secretary Vice President, Customer Revenue Transactx>ns Joseph R Kearney Robert Chainnan D. Glynn},r.

of the ikiar Eric Afontizambert Presuent and Chief Executive Officer, Assisunt o>rp> rate Secretary RogerJ. Gray Chief Exemnve Officer and President \ ice President, General Servic" Gabn,el II. 'l,ognen, R

'lbny E DiStefano Assistant Trecurer h."""\'""id"""',

Chrism.an.Iribe Senior Vice Pre 4!ent, Robert L. Harris Chief Operaung Officer Ostporate Development \ ice President, Pacific Gas and cinununity Relations Electric Company PG&E Gas Transmission Scott W. Gebhardt Senior \ ice President Russell A1. Jackson Robert D. Glynn,)r- Vice Proident.

Jack EJenkins-Stark President and Chairman of the Ikeard Customer Service Chief Execuuve Omcer

,I,homas M,. Iligh Senior Vice President, G,ordon R. S.mith Admini,tranon and Christopher P. Johns ,Ferrence E. C,iliske

' Esternal Relations Preudent and Vice Prnident and President and Chief Executive OMccr Ce neroller Chief Executive Officer of PG& E Gas 'Iransmission 'Icxas Jack E Jenkins-Stark K.ent A1. Harvey Senior he Praident Junona A.Jonas Senior \ ice Preudent, Chief EinanculOffcer, Vice President. AlichaelJ. AlcDonald Gas and Electric Supply '

Manairing Director of Joseph R Kearney and Treasurer PG& L Gas Transmisuon - Australia senior Vice President Stesen L Kline E. James Macias v;<e presiaent, PG&E Energy Services L, E. Aladdox Senior Vke President and ReFulatory Relations Senior Vice President General _ Manger' Generanon, Iranum.suun,and Scott W. Gebhardt Supply Business Unit Thomas C. Long I!re". dent *"d Alichael E. Rescoe Vice Preudent, Chief E""" 0M'"

Senior Vice Prnident, (;cneral Rate Case Project Chief Einancial Officer, and James K. Ransk>lph senior Vice President and James Seni"r becC. Davis,ent, Treasurer General Manrger, William R. Aluotti Presa.

Disenbution and Customer Service Vice President. Integrated Services C. lltent Stanley Businen Umt Ga and Electric 'lianunisuon Senior Vice President.

liuman Resources William R. D.oucette Senior ha y'remjent.

Daniel D. Richard,Jr. RogerJ. Peters Senior Vice Pmident. Vice President and S'IC' Ilruce R. Worthinpon Gosenunentat and General Counsel Senior Vice President and Regulatory Relanons PG&E Energy Trading General Counsel Robert R Powers Gregory A1. Rueger Vice Presidet, L. E. Aladdox Leslie II. E.verett senior \ ice President and t hablo Canyon Operations and President and Vice President and General Manager, Plant Manager Chief Execuuve Omcer Corgerate Secretary Nuclear Power Gcneration Business Unit 1, rank J. Regan Christopher RJohns Yke President.

Vice Preudent and Shan Ilhattacharya covernmental Relations Controller Vice President, Distribution Engineering and Planning Lawrence E M,omack Jackalyne Pfannenstiel Vice President, Vice Presulent, Nutlear Technical Services Business Planning . Thomas E. Ilottorff Vice President, Rates and Account Services Lm. da L, II. Cheng G, reg S. Pruett Senior usisunt Vice President, Corgurate Secretary Corporate Communicauons Jeffrey D. Ilutler Vice President.

Distribution Operations, Wondy S. Lee Daniel D. Richard,Jr. Mamtenance, and omstruction Assistant Corimrate Secretary

- Vice President.

Governmental Relations Ilarbara Coull Williams Eric Alontizambert Vice President. Assistant Corp > rate Secretary Lm da Y. II, Cheng iluman Re,ources Anistani Corporate Secretary Gabn,el h. ,.ognen, Leslie H. Everett A.s.,istani Toasurer Vice President and Corinrate Secretary 63

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i Shareholder information  !

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l Shareholder Services Office Stock Held in Brokerage Accounts j 77 Beale Street, Room 2600 (" Street Name") l San Francisco, CA 94105-1814 When you purchase your stock and it is held for you by your Call Toll Free 1.800.367.7731 broker, the shares are listed with us in the broker's name, or Fax 415.973.7831 " street name." We do not know the identity of the individual j shareholders who hold their shares in this manner-we For Gnancial and other information about PG&E simply know that a broker holds a number of shares which Corjoration and PaciGc Gas and Electric Company, please may be held for any number ofinvestors. If you hold your visit our web sites, www.pgecorp.com and www.pge.com stock in a street name account, you receive all dividend pay-ments, tax (m ms, publications, and proxy materials through if you have questions about your account or need copies of your broker. If you are receiving unwanted duplicate mail-PG& E Corporation's or Paci6c Gas and Electric Company's ings, you shouki contact your broker to eliminate the publications, please write or call the Shareholder Senices duplications.

Of6ce at:

PG&E Corporation Dividend Reinvestment Plan Manager of Shareholder Services if you imid PG& E Corporation or Pacific Gas and Electric David A1. Kelly Company nock in your own name, rather than through a Atail Code 112611 bn>ka, you may automatically reinvest dividend payments P.O. flox 770000 fnim conunon nNor pafured nock in shares of PG&E San Francisco, CA 94177-0001 Corporation common stock through the Dividend 1.800.367.7731 Reinvestment Plan (the " Plan"). You may obtain a Plan prospectus and enroll by contacting the Shareholder if you have general questions about PGNE Corporation or Services Of6ce. If your certificates are hek! by a broker Paci6e Gas and Electric Company, please write or call the (in " street name"), you are not eligible to participate in Corporate Secretary's Office: the Plan.

Corporate Secretary I eslie 11. Everett Direct Deposit of Dividends If you hold stock in your own name, rather than through One Alarket, Spear'Ibwer, Suite 2400 San Francisco, CA 94105-1 log a broker, you may have your conunon and/or preferred 415.973.2880 dividends transmitted to your bank electronically. You may obtain a direct deposit authorir.ation form by contacting the Sharehohler Senices Of6ce.

Securities analysts, portfolio managers, or other representa-tires of the investment community sho'dd write or call the Replacement of Dividend Checks Investor Relations Of6ce: -If you hoki stock in your own name and do not receive Manager of Investor Relations your dividend check within five business days after the pay-David E. Kaplan inent date, or if a check is lost or destroyed, you shouki One Alarket, Spear'Ibwer, Suite 2400 >tify the Sharehokler Senices Of6ce so that payment may he stopped on the check and a replacement mailed.

San Francisco, CA 94105;l108 415.973.3007 Lost or Stolen Stock Certificates if you hoki stock in your ow n name and your stock certiG-PG&E Corporation cate has been lost, stolen, or in some way destroyed, you General Information should notify the Sharehokler Senices bf6ce inkmediately.

415.973.7000 Pacific Gas and Electric Company General Information 415.973,7000 h Pages 17-64 printed on recycled paper.

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PG&E Corporation Stock Exchange Listings-Pacific Gas and Electric Company PG& E Corporation's common stock is traded on the New Annual Meetings of Shareholders York, Pacific, and Swiss stock exchanges. The official Date: April 15,1998 New York Stock Exchange symbol is "PCG" but PG&E Time: 10:00 a.m. Corporation common stock is listed in daily newspapers Location: Masonic Auditorium under "PG&E" or "PG& E Cp." Local newspaper symbols 1111 California Street may vary.

San Francisco, California Pacific Gas and Electric Company has 12 issues of A joint notice of the annual meetings, joint proxy statement, preferred stock and one preferred security, all of which and proxy fonn are being mailed with this annual report on are listed on the American and Pacific stock exchanges.

or about March 2,1998, to all shareholders of record as of February 17,1998. Newspaper, Issue Symbol First Preferred, Cumulative, 10-K Report Par Value $25 Per Share If you would like a copy of the 1997 Form 10. K Report to the Securities and Exchange Commission, please contact the Redeemable:

Shareholder Services Office, or visit our web sites, 7.04 % PacGE pfU www.pgecorp.com and www.pge. corn 6.875 % PacGE pfX 6.57 % PacGE pfY 1998 Dividend Payment Dates 6.30 % PacGE pfZ 5.00 % PacGE pfD Pacific Gas and PG&E Corporation Electric Company 5.00% Series A PacGEI ifE Conimon Stock Preferred Stock 4.80 % PacGE pfG 4.50 % PacGE pfil January 15 February 15 4.36 % PacGE pf1 April 15 May 15 July 15 August if Non-Redeemable:

October 15 November 15 6.00 % PacGE pfA 5.50 % PacGE pfB 5.00 % PacGE pfC Cumulative Quarterly Income Preferred Securities:

7.90% Series A PG&E CapAQUIPS

• Local newspaper symbols may vary i

,m aa- ,

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1 i PG &E Corporation One Market, Spear Tower Suite 2400 San Francisco, CA 94105 www.pgecorp.com i