FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 ---------------------------------- (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________to ___________ Exact Name of Commission Registrant State or other IRS Employer File as specified Jurisdiction of Identification Number in its charter Incorporation Number - ----------- -------------- --------------- -------------- 1-12609 PG&E Corporation California 94-3234914 1-2348 Pacific Gas and California 94-0742640 Electric Company Pacific Gas and Electric Company PG&E Corporation 77 Beale Street One Market, Spear Tower P.O. Box 770000 Suite 2400 San Francisco, California 94177 San Francisco, California 94105 - ----------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Pacific Gas and Electric Company PG&E Corporation (415) 973-7000 (415) 267-7000 - ----------------------------------------------------------------------- Registrant's telephone number, including area code Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No _________ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock Outstanding July 28, 1999: PG&E Corporation 383,949,779 shares Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999 TABLE OF CONTENTS PAGE PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME........................1 CONSOLIDATED BALANCE SHEET..............................2 STATEMENT OF CONSOLIDATED CASH FLOWS ...................4 PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME........................5 CONDSOLIDATED BALANCE SHEET.............................6 STATEMENT OF CONSOLIDATED CASH FLOWS....................8 NOTE 1: GENERAL...........................................9 NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING........9 NOTE 3: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS..15 NOTE 4: ACQUISITIONS AND SALES...........................16 NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES...........17 NOTE 6: COMMITMENTS AND CONTINGENCIES....................17 NOTE 7: SEGMENT INFORMATION..............................20 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................22 COMPETITIVE AND REGULATORY ENVIRONMENT....................23 The Competitive Environment in the Evolving Energy Industry........................................23 California Industry Restructuring......................24 New England Electricity Market.........................30 Regulatory Matters.....................................31 RESULTS OF OPERATIONS.....................................34 LIQUIDITY AND FINANCIAL RESOURCES.........................40 ENVIRONMENTAL MATTERS.....................................42 YEAR 2000.................................................42 PRICE RISK MANAGEMENT ACTIVITIES..........................44 LEGAL MATTERS.............................................44 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.........................................45 PART II. OTHER INFORMATION ITEM 5. OTHER INFORMATION.........................................46 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................46 SIGNATURE..........................................................48
PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS <TABLE> PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME (in millions, except per share amounts) <CAPTION> Three months ended June 30, Six months ended June 30, 1999 1998 1999 1998 -------- -------- -------- -------- <S> <C> <C> <C> <C> Operating Revenues Utility $ 2,233 $ 2,117 $ 4,318 $ 4,143 Energy commodities and services 2,587 2,670 5,759 4,997 -------- -------- -------- -------- Total operating revenues 4,820 4,787 10,077 9,140 -------- -------- -------- -------- Operating Expenses Cost of energy for utility 664 576 1,319 1,258 Cost of energy commodities and services 2,365 2,472 5,286 4,624 Operating and maintenance, net 774 770 1,572 1,571 Depreciation and decommissioning 563 412 1,004 666 -------- -------- -------- -------- Total operating expenses 4,366 4,230 9,181 8,119 -------- -------- -------- -------- Operating Income 454 557 896 1,021 Interest expense, net 192 196 393 393 Other income, net 39 (8) 60 7 -------- -------- -------- -------- Income Before Income Taxes 301 353 563 635 Income taxes 121 179 227 322 -------- -------- -------- -------- Net Income $ 180 $ 174 $ 336 $ 313 ======== ======== ======== ======== Weighted Average Common Shares Outstanding 367 382 370 382 Earnings Per Common Share, Basic $ .49 $ .46 $ .91 $ .82 Earnings Per Common Share, Diluted $ .46 $ .46 $ .83 $ .82 Dividends Declared Per Common Share $ .30 $ .30 $ .60 $ .60 <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PG&E CORPORATION CONSOLIDATED BALANCE SHEET (in millions) <CAPTION> Balance at June 30, December 31, 1999 1998 ------------- ------------ <S> <C> <C> ASSETS Current Assets Cash and cash equivalents $ 284 $ 286 Short-term investments 37 55 Accounts receivable Customers, net 1,569 1,856 Energy marketing 571 507 Price Risk Management 716 1,416 Inventories and prepayments 770 835 -------- -------- Total current assets 3,947 4,955 Property, Plant, and Equipment Utility 22,658 23,996 Wholesale and retail unregulated business operations Electric generation 1,900 1,967 Gas transmission 3,387 3,347 Construction work in progress 398 407 Other 171 127 -------- -------- Total property, plant, and equipment (at original cost) 28,514 29,844 Accumulated depreciation and decommissioning (11,038) (12,026) -------- -------- Net property, plant, and equipment 17,476 17,818 Other Noncurrent Assets Regulatory assets 5,520 6,347 Nuclear decommissioning funds 1,238 1,172 Other 3,245 2,942 -------- -------- Total noncurrent assets 10,003 10,461 -------- -------- TOTAL ASSETS $ 31,426 $ 33,234 ======== ======== <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PG&E CORPORATION CONSOLIDATED BALANCE SHEET (in millions) <CAPTION> Balance at June 30, December 31, 1999 1998 ------------ ------------ <S> <C> <C> LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 877 $ 1,644 Current portion of long-term debt 549 338 Current portion of rate reduction bonds 282 290 Accounts payable Trade creditors 775 1,001 Other 543 443 Regulatory balancing accounts 685 79 Energy marketing 475 381 Accrued taxes 738 103 Price risk management 708 1,412 Other 873 1,064 -------- -------- Total current liabilities 6,505 6,755 Noncurrent Liabilities Long-term debt 6,895 7,422 Rate reduction bonds 2,181 2,321 Deferred income taxes 3,263 3,861 Deferred tax credits 251 283 Other 3,836 3,746 -------- -------- Total noncurrent liabilities 16,426 17,633 Preferred Stock of Subsidiaries 480 480 Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 300 300 Common Stockholders' Equity Common stock 5,391 5,862 Reinvested earnings 2,324 2,204 -------- -------- Total common stockholders' equity 7,715 8,066 Commitments and Contingencies (Notes 2 and 6) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 31,426 $ 33,234 ======== ======== <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PG&E CORPORATION STATEMENT OF CONSOLIDATED CASH FLOWS (in millions) <CAPTION> For the six months ended June 30, 1999 1998 ---------- ---------- <S> <C> <C> Cash Flows From Operating Activities Net income $ 336 $ 313 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization and decommissioning 1,004 666 Deferred income taxes and tax credits-net (630) (31) Other deferred charges and noncurrent liabilities (401) (74) Loss on sale of assets - 21 Net effect of changes in operating assets and liabilities: Accounts receivable - trade 287 100 Regulatory balancing accounts payable 606 365 Inventories and prepayments 65 42 Price risk management assets and liabilities, net (4) (24) Accounts payable - trade (226) (187) Accrued taxes 635 165 Other working capital (56) (135) Other-net 21 29 --------- --------- Net cash provided by operating activities 1,637 1,250 --------- --------- Cash Flows From Investing Activities Capital expenditures (740) (925) Proceeds from the sale of assets 1,014 - Other-net - 14 --------- --------- Net cash used by investing activities 274 (911) --------- --------- Cash Flows From Financing Activities Net borrowings (repayments) under credit facilities (767) 473 Long-term debt issued - 199 Long-term debt matured, redeemed, or repurchased (491) (644) Preferred stock redeemed or repurchased - (63) Common stock issued 32 33 Common stock repurchased (503) (1,123) Dividends paid (225) (240) Other-net 23 (21) --------- --------- Net cash used by financing activities (1,931) (1,386) --------- --------- Net Change in Cash and Cash Equivalents (20) (1,047) Cash and Cash Equivalents at January 1 341 1,397 --------- --------- Cash and Cash Equivalents at June 30 $ 321 $ 350 ========= ========= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 385 $ 394 Income taxes 87 209 <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME (in millions) <CAPTION> Three months ended June 30, Six months ended June 30, 1999 1998 1999 1998 -------- -------- -------- ------- <S> <C> <C> <C> <C> Electric utility $ 1,828 $ 1,708 $ 3,361 $ 3,270 Gas utility 405 409 957 873 -------- -------- -------- -------- Total operating revenues 2,233 2,117 4,318 4,143 -------- -------- -------- -------- Operating Expenses Cost of electric energy 526 453 935 927 Cost of gas 138 123 384 331 Operating and maintenance, net 608 672 1,234 1,370 Depreciation, amortization, and decommissioning 509 375 891 597 -------- -------- -------- -------- Total operating expenses 1,781 1,623 3,444 3,225 -------- -------- -------- -------- Operating Income 452 494 874 918 Interest expense, net 148 159 302 321 Other income, net 11 27 22 64 -------- -------- -------- ------- Income Before Income Taxes 315 362 594 661 Income taxes 137 169 263 312 -------- -------- -------- ------- Net Income 178 193 331 349 Preferred dividend requirement 6 7 12 15 -------- -------- -------- ------- Income Available for Common Stock $ 172 $ 186 $ 319 $ 334 ======== ======== ======== ======= <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (in millions) <CAPTION> Balance at June 30, December 31, 1999 1998 ------------ ----------- <S> <C> <C> ASSETS Current Assets Cash and cash equivalents $ 85 $ 73 Short-term investments 18 17 Accounts receivable Customers, net 1,144 1,383 Related parties 29 14 Inventories Fuel oil and nuclear fuel 159 187 Gas stored underground 156 130 Materials and supplies 165 159 Prepayments 34 50 --------- --------- Total current assets 1,790 2,013 Property, Plant, and Equipment Electric 15,493 16,924 Gas 7,165 7,072 Construction work in progress 211 273 --------- --------- Total property, plant, and equipment (at original cost) 22,869 24,269 Accumulated depreciation and decommissioning (10,315) (11,397) --------- --------- Net property, plant, and equipment 12,554 12,872 Other Noncurrent Assets Regulatory assets 5,465 6,288 Nuclear decommissioning funds 1,238 1,172 Other 673 605 -------- -------- Total noncurrent assets 7,376 8,065 -------- -------- TOTAL ASSETS $ 21,720 $ 22,950 ======== ======== <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PACIFIC GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (in millions) <CAPTION> Balance at June 30, December 31, 1999 1998 ------------ ----------- <S> <C> <C> LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ - $ 668 Current portion of long-term debt 453 260 Current portion of rate reduction bonds 282 290 Accounts payable Trade creditors 526 718 Related parties 65 60 Regulatory balancing accounts 685 79 Other 338 374 Accrued taxes 585 2 Other 484 561 -------- ------- Total current liabilities 3,418 3,012 Noncurrent Liabilities Long-term debt 5,051 5,444 Rate reduction bonds 2,181 2,321 Deferred income taxes 2,424 3,060 Deferred tax credits 250 283 Other 2,212 2,045 -------- ------- Total noncurrent liabilities 12,118 13,153 Preferred Stock With Mandatory Redemption Provisions 137 137 Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures 300 300 Stockholders' Equity Preferred stock without mandatory redemption provisions Nonredeemable 145 145 Redeemable 142 142 Common stock 1,607 1,707 Additional paid in capital 1,971 2,094 Reinvested earnings 1,882 2,260 -------- -------- Total stockholders' equity 5,747 6,348 Commitments and Contingencies (Notes 2 and 6) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 21,720 $ 22,950 ======== ======== <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
<TABLE> PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED CASH FLOWS (in millions) <CAPTION> For the six months ended June 30, 1999 1998 ----------- ----------- <S> <C> <C> Cash Flows From Operating Activities Net income $ 331 $ 349 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 891 597 Deferred income taxes and tax credits-net (669) (79) Other deferred charges and noncurrent liabilities (189) 327 Net effect of changes in operating assets and liabilities: Accounts receivable 239 43 Regulatory balancing accounts payable 606 (138) Inventories and prepayments 12 19 Accounts payable - trade (192) (45) Accrued taxes 583 154 Other working capital (71) (58) Other-net 27 13 --------- --------- Net cash provided by operating activities 1,568 1,182 --------- --------- Cash Flows From Investing Activities Capital expenditures (600) (671) Proceeds from sale of assets 1,014 - Other-net - 83 --------- --------- Net cash used by investing activities 414 (588) --------- --------- Cash Flows From Financing Activities Net repayments under credit facilities (668) - Long-term debt matured, redeemed, or repurchased (369) (618) Preferred stock redeemed or repurchased - (63) Common stock repurchased (725) (800) Dividends paid (208) (230) Other-net 1 (8) --------- --------- Net cash used by financing activities (1,969) (1,719) --------- --------- Net Change in Cash and Cash Equivalents 13 (1,125) Cash and Cash Equivalents at January 1 90 1,223 --------- --------- Cash and Cash Equivalents at June 30 $ 103 $ 98 ========= ========= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 282 $ 315 Income taxes 226 260 <FN> The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. </TABLE>
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: GENERAL Basis of Presentation: - ---------------------- This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and Pacific Gas and Electric Company (the Utility), a regulated subsidiary of PG&E Corporation. The Notes to Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries, including the Utility (collectively, the Corporation). The Utility's consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. The Utility's financial position and results of operations are the principal factors affecting the Corporation's consolidated financial position and results of operations. This quarterly report should be read in conjunction with the Corporation's and the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1998 Annual Report on Form 10-K. PG&E Corporation and the Utility believe that the accompanying statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. All significant intercompany transactions have been eliminated from the consolidated financial statements. Certain amounts in the prior year's consolidated financial statements have been reclassified to conform to the 1999 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, and liabilities and the disclosure of contingencies. Actual results could differ from these estimates. NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING In 1998, California became one of the first states in the country to implement electric industry restructuring legislation and establish a competitive market for electric generation. In a transition to a competitive market, the restructuring legislation recognized that market-based revenues may not be sufficient to recover (that is, collect from customers) all of the Utility's generation costs. The restructuring legislation provides the California investor-owned utilities the opportunity to recover such uneconomic generation costs (called transition costs) until the earlier of December 31, 2001, or when the utilities have recovered their authorized transition costs as determined by the California Public Utilities Commission (CPUC). The period during which transition costs may be recovered is called the transition period. The legislation permits certain transition costs to be recovered after the transition period. The restructuring legislation has four principal elements: (1) the establishment of a competitive market framework, (2) an electric rate freeze and rate reduction, (3) the recovery of transition costs, and (4) divestiture of utility-owned generation facilities. Each element is discussed below.
Competitive Market Framework: - ----------------------------- To create a competitive generation market, a Power Exchange (PX) and an Independent System Operator (ISO) began operating on March 31, 1998. During the transition period, the Utility is required to bid or schedule into the PX and ISO markets all of the electricity generated by its power plants and electricity acquired under contractual agreements with unregulated generators. Also during the transition period, the Utility is required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier. The ISO schedules delivery of electricity for all market participants. The Utility continues to own and maintain a portion of the transmission system, but the ISO controls the operation of the system. For the three- and six-month periods ended June 30, 1999 and 1998, the cost of electric energy for the Utility, reflected on the Statement of Consolidated Income, is comprised of the cost of PX purchases, ancillary services (standby power and miscellaneous services) purchased from the ISO, cost of transmission, and the cost of Utility generation, net of sales to the PX as follows: <TABLE> <CAPTION> Three months ended June 30, Six months ended June 30, 1999 1998 1999 1998 -------- -------- -------- -------- <S> <C> <C> <C> <C> (in millions) Cost of electric generation $ 398 $ 490 $ 768 $ 964 Cost of purchases from the PX 174 110 326 110 Cost of ancillary services 111 86 221 86 Proceeds from sales to the PX (157) (233) (380) (233) -------- -------- -------- -------- Cost of electric energy $ 526 $ 453 $ 935 $ 927 -------- -------- -------- -------- </TABLE> The Utility's cost of energy is recovered from retail customers under the terms of the restructuring plan. Rate Freeze and Rate Reduction: - ------------------------------- Legislation required an electric rate freeze and an electric rate reduction to extend throughout the transition period. The Utility has held rates for its larger customers at 1996 levels, and it will hold their rates at that level until the end of the transition period. On January 1, 1998, the Utility reduced electric rates for its residential and small commercial customers by 10 percent from 1996 levels, and it will hold their rates at that level until the end of the transition period. Collectively, these actions are called a rate freeze. To pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion of its transition costs with the proceeds from rate reduction bonds. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of these transition costs until after the transition period. During the rate freeze, the rate reduction bond debt service will not increase the Utility customers' electric rates. If the transition period ends before December 31, 2001, the Utility will be obligated to return a portion of the bond proceeds to customers. The timing and exact amount of such portion, if any, has not yet been determined. The frozen rates include a component for transition cost recovery. Transition costs are being recovered from all Utility distribution customers through a nonbypassable charge regardless of the customer's choice of
electricity supplier. As the customer charge for transition costs is nonbypassable, the Utility believes that the availability of choice to its customers will not have a material impact on its ability to recover transition costs. Revenues from frozen electric rates provide for the recovery of authorized Utility costs, including transmission and distribution service, public purpose programs, nuclear decommissioning, and rate reduction bond debt service. To the extent the revenues from frozen rates exceed authorized Utility costs, the remaining revenues constitute the competitive transition charge (CTC), which recovers the transition costs. These CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes and certain other factors. Transition Cost Recovery: - ------------------------- Market-based revenues through sales to the PX may not be sufficient to recover all of the Utility's generation costs. Under the California restructuring legislation, the Utility has the opportunity to recover its transition costs until the earlier of December 31, 2001, or when the Utility has recovered its authorized transition costs as determined by the CPUC, although certain transition costs can be recovered after the transition period. At the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market-based revenues. Transition costs consist of: (1) above-market sunk costs (costs associated with Utility-owned generation assets that are fixed and unavoidable and currently included in the Utility customers' electric rates) and future costs, such as costs related to removal of Utility-owned generation facilities, (2) costs associated with the Utility's long-term contracts to purchase power at above-market prices from qualifying facilities and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods, to be included in rates in subsequent periods.) Above-market sunk costs result when the book value of a facility is in excess of its market value. Conversely, below-market sunk costs result when the market value of a facility is in excess of its book value. The total amount of generation facility costs to be included as transition costs will be based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. These above- and below-market sunk costs are related to generating facilities that are classified as either non-nuclear or nuclear sunk costs. The Utility cannot determine the exact amount of above-market non-nuclear sunk costs that will be recoverable as transition costs until a market valuation process (through appraisal, sale, or other valuation method) is completed for each of its non-nuclear generation facilities. Several of these valuations occurred in 1997 and 1998, when the Utility agreed to sell seven of its electric generation plants to third parties. The total market value of these facilities resulted in sales proceeds that exceeded the book value and therefore has reduced the amount of transition costs remaining to be recovered. The remainder of the valuation process is expected to be completed by December 31, 2001. The Utility's remaining non-nuclear generation facilities consist primarily of its hydroelectric generation system. If the market value of the Utility's hydroelectric facilities is determined based upon any method other than a sale of the facilities to a third party, a material charge to Utility earnings could result. Any excess
of market value over book value would be used to reduce other transition costs. (See Generation Divestiture below.) Nuclear generation sunk costs were determined separately through a CPUC proceeding and were subject to a final verification audit that was completed in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power Plant (Diablo Canyon) accounts at December 31, 1996, resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. The independent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, that questioned $200 million of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to Diablo Canyon's recoverable costs that resulted from the report. At this time, the Utility cannot predict what actions, if any, the CPUC may take regarding the audit report. Costs associated with the Utility's long-term contracts to purchase electric power at above-market prices are included as transition costs. Over the remaining life of these contracts the Utility estimates that it will purchase 322 million megawatt-hours of electric power. To the extent that the individual contract prices are above the market price, the Utility is collecting the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. The contracts expire at various dates through 2028. The total amount of the above-market costs under long-term contracts will be based on several variables, including the capacity factors of the related generating facilities and future market prices for electricity. During the six-month period ended June 30, 1999, the average price paid per kilowatt-hour (kWh) under the Utility's long-term contracts for electric power was 6.1 cents per kWh. The average cost of electric energy for energy purchased at market rates from the PX for the six-month period ended June 30, 1999, was 2.6 cents per kWh. Generation-related regulatory assets and obligations (net generation- related regulatory assets) are included as transition costs. At June 30, 1999, the Utility's generation-related net regulatory assets totaled $4.5 billion. Most transition costs can be recovered until December 31, 2001. This recovery period is significantly shorter than the recovery period of the generation assets prior to restructuring and is referred to as accelerated recovery. Accordingly, the Utility is amortizing its transition costs, including most generation-related regulatory assets over the transition period. During the transition period, the Utility is receiving a reduced return on common equity for all of its generation assets, including those generation assets reclassified to regulatory assets. The reduced return on common equity is 6.77 percent. Certain transition costs can be recovered through a non-bypassable charge to distribution customers after December 31, 2001. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing long-term contracts to purchase power, discussed above, (3) up to $95 million of transition costs after the transition period to the extent that the recovery of such costs during the transition period was displaced by the recovery of electric industry restructuring implementation costs, and (4) transition costs financed by the rate reduction bonds. Transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. In addition, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission the nuclear facility. During the rate freeze, the charge for these costs will not
increase the Utility customers' electric rates. Excluding these exceptions, the Utility will write off any transition costs not recovered during the transition period. Revenues provided for the recovery of most non-nuclear transition costs are based upon the acceleration of such costs within the transition period. For Diablo Canyon transition costs, revenues provided for transition cost recovery are based on: (1) an established incremental cost incentive price (ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs and capital additions, and (2) the accelerated recovery of the investment in Diablo Canyon from a period ending in 2016 to a five-year period ending December 31, 2001. In a pending proceeding, the CPUC is currently considering whether the Utility may continue to recover revenues based on the ICIP through December 31, 2001, or must cease recovery of such revenues if it has completed recovery of all other utility generation-related transition costs prior to that date. The Utility is amortizing its eligible transition costs, including generation-related regulatory assets, over the transition period in conjunction with the available CTC revenues. Effective January 1, 1998, the Utility started collecting these eligible transition costs through the nonbypassable CTC. For the six months ended June 30, 1999, regulatory assets related to electric utility restructuring decreased by $813 million, which reflects the recovery of eligible transition costs. During the transition period, the CPUC reviews the Utility's compliance with the accounting methods established in the CPUC's decisions governing transition cost recovery and the amount of transition costs requested for recovery. The CPUC is currently reviewing non-nuclear transition costs amortized during the first six months of 1998. Generation Divestiture: - ----------------------- In 1998, the Utility completed the sale of three fossil-fueled generation plants for $501 million. These three fossil-fueled plants had a combined book value at the time of the sale of $346 million and had a combined capacity of 2,645 megawatts (MW). On April 16, 1999, the Utility sold three other fossil-fueled generation plants for $801 million. At the time of sale, these three fossil-fueled plants had a combined book value of $256 million and had a combined capacity of 3,065 MW. On May 7, 1999, the Utility sold its complex of geothermal generation facilities for $213 million. At the time of sale, these facilities had a combined book value of $244 million and had a combined capacity of 1,224 MW. The Utility will retain a liability for required environmental remediation related to all of its fossil-fueled generation and geothermal generation plants of any pre-closing soil or groundwater contamination at the plants it has or will sell. The Utility records its estimated liability for the retained environmental remediation obligation as part of the determination of the gain or loss on the sale of each plant. Any gains from the sale of the Utility-owned generation plants will be used to offset other transition costs. Likewise, any losses from the sale of Utility-owned generation plants are recoverable as transition costs. PG&E Corporation does not believe sales of any generation facilities to a third party will have a material impact on its results of operations.
In May 1998, the Utility notified the CPUC that it does not plan to retain its hydroelectric generation assets as part of the Utility. In December 1998, the Utility filed with the CPUC its proposed appraisal process for valuing its hydroelectric facilities. The Utility withdrew its proposal in March 1999 when the CPUC clarified that the CPUC proceeding would only apply to assets to be retained in the Utility. The Utility currently is evaluating alternative strategies with respect to the valuation and disposition of its hydroelectric facilities, including a potential transfer of the facilities to another PG&E Corporation affiliate. Meanwhile, the California legislature is reviewing legislative proposals that would address hydroelectric facilities valuation and divestiture issues on an interim or permanent basis. If legislation setting a valuation were enacted and the legislated valuation was materially higher than the value ultimately recognized in connection with the sale or other disposition of the assets, the Utility could suffer a material loss upon the sale or other disposition of the hydroelectric assets. If such legislation were enacted, we expect that the Utility would challenge the legality of legislation adopting such excess or interim valuation. Although legislation could be passed prior to the close of the legislative session in September 1999, the Corporation and Utility are unable to predict the nature or likelihood of enactment of any such legislation. At June 30, 1999, the book value of the Utility's net investment in hydroelectric generation assets was approximately $0.8 billion, excluding approximately $0.5 billion of net investment reclassified as regulatory assets recoverable as transition costs. The value of the hydroelectric assets is expected to exceed their book value by a material amount. In connection with legislative discussions concerning the hydroelectric assets, some third parties have publicly speculated that the value of the hydroelectric assets could be in excess of $3 billion. If the market value of the hydroelectric generation assets is determined by any method other than a sale of the assets to a third party, a material charge to Utility earnings could result. Any excess of market value over the $0.8 billion book value would be used to reduce other transition costs, including the remaining $0.5 billion of regulatory assets related to the hydroelectric generation assets. The timing and nature of any such charge is dependent upon the valuation method and procedure adopted, and the method of implementation, which could occur as soon as the third quarter of 1999. Financial Impact of Electric Industry Restructuring: - ---------------------------------------------------- The Utility's ability to continue recovering its transition costs will be dependent on several factors, including: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the determined value of the Utility's hydroelectric generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, (6) the extent to which the Utility's authorized revenues to recover distribution and transmission costs are increased or decreased, and (7) the market price of electricity. Given the current evaluation of these factors, PG&E Corporation believes that the Utility will recover its transition costs under the terms of the approved transition plan. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge.
NOTE 3: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS The following table is a summary of the contract or notional amounts and maturities of PG&E Corporation's contracts used for non-hedging activities related to commodity price risk management as of June 30, 1999. Short and long positions pertaining to derivative contracts used for hedging activities as of June 30, 1999, are immaterial. Maximum Natural Gas, Electricity, Purchase Sale Term in and Natural Gas Liquids Contracts (Long) (Short) Years - --------------------------------------------------------------------- (billions of MMBtu equivalents (1)) Non-Hedging Activities Swaps 3.90 3.73 7 Options 1.14 0.96 5 Futures 0.29 0.34 2 Forward Contracts 2.93 2.98 9 (1) One MMBtu is equal to one million British thermal units. PG&E Corporation's electric power contracts, measured in megawatts, were converted to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt- hour. PG&E Corporation's natural gas liquids contracts were converted to MMBtu equivalents using an appropriate conversion factor for each type of natural gas liquids product. Volumes shown for swaps represent notional volumes that are used to calculate amounts due under the agreements and do not represent volumes exchanged. Moreover, notional amounts are indicative only of the volume of activity and are not a measure of market risk. PG&E Corporation's net gains (losses) on swaps, options, futures, and forward contracts held during the three- and six-month periods ended June 30, 1999 are as follows: For the three- For the six- months ended months ended June 30, 1999 June 30, 1999 - -------------------------------------------------------------------------- (in millions) Swaps $(131) $ 2 Options (29) (35) Futures 22 (20) Forward contracts 131 95 ------ ----- Net gain (loss) $ (7) $ 42
The following table discloses the estimated fair values of price risk management assets and liabilities as of June 30, 1999. The ending and average fair values and associated carrying amounts of derivative contracts used for hedging purposes are not material as of June 30, 1999. Average Ending Fair Value Fair Value - -------------------------------------------------------------------------- (in millions) Assets Non-Hedging Activities Swaps $ 890 $ 248 Options 107 74 Futures 240 45 Forward Contracts 744 743 ------ ------ Total $1,981 $1,110 Noncurrent portion 394 Current portion $ 716 Liabilities Non-Hedging Activities Swaps $ 821 $ 231 Options 128 83 Futures 272 59 Forward Contracts 645 616 ------ ------ Total $1,866 $ 989 Noncurrent portion 281 Current portion $ 708 The credit exposure of the five largest counterparties comprised approximately $285 million of the total credit exposure associated with financial instruments used to manage price risk. Counterparties considered to be investment grade or higher comprise 67 percent of the total credit exposure. NOTE 4: ACQUISITIONS AND SALES In September 1998, PG&E Corporation, through its indirect subsidiary USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES). The acquisition has been accounted for using the purchase method of accounting. Accordingly, the purchase price has been allocated to the assets purchased and the liabilities assumed based upon a preliminary assessment of the fair values at the date of acquisition. Including fuel and other inventories and transaction costs, PG&E Corporation's financing requirements for this acquisition were approximately $1.8 billion, funded through an aggregate of $1.3 billion of PG&E Generating Company (PG&E Gen) and USGenNE debt and a $425 million equity contribution from PG&E Corporation. (On June 1, 1999, U.S. Generating Company changed its name to PG&E Generating Company). The net purchase price has been
preliminarily allocated as follows: (1) electric generating assets of $2.3 billion classified as property, plant, and equipment; (2) receivable for support payments of $0.8 billion; and (3) contractual obligations of $1.3 billion classified as current liabilities and other noncurrent liabilities. The assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of 4,000 MW. In addition, USGenNE assumed 23 multi-year power-purchase agreements representing an additional 800 MW of production capacity. USGenNE entered into agreements with NEES as part of the acquisition, which: (1) provide that NEES shall make support payments over the next ten years to USGenNE for the purchase power agreements; and (2) require that USGenNE provide electricity to NEES under contracts that expire over the next six to eleven years. NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has outstanding 12 million shares of 7.90 percent cumulative quarterly income preferred securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to the Utility 371,135 shares of common securities with an aggregate liquidation value of approximately $9 million. The only assets of the Trust are deferrable interest subordinated debentures issued by the Utility with a face value of approximately $309 million, an interest rate of 7.90 percent, and a maturity date of 2025. NOTE 6: COMMITMENTS AND CONTINGENCIES Nuclear Insurance: - ------------------ The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). Under this insurance, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective assessments of $17 million (property damage) and $5 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. The Utility has secondary financial protection which provides an additional $9.5 billion in coverage, which is mandated by federal legislation. It provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, then the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation: - -------------------------- The Utility may be required to pay for environmental remediation at sites where the Utility has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances, even if the Utility did not deposit those substances on the site.
The Utility records a liability when site assessments indicate remediation is probable and a range of reasonably likely cleanup costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility had an accrued liability at June 30, 1999, of $294 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. Of the $294 million liability, discussed above, the Utility has recovered $136 million and expects to recover $129 million in future rates. Additionally, the Utility is mitigating its costs by obtaining recovery of its costs from insurance carriers and from other third parties as appropriate. Environmental remediation at identified sites may be as much as $482 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated. The Utility estimated this upper limit of the range of costs using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or outcomes change. Further, as discussed in Generation Divestiture above, the Utility will retain the pre-closing remediation liability associated with divested generation facilities. PG&E Corporation believes the ultimate outcome of these matters will not have a material impact on its or the Utility's financial position or results of operations. Legal Matters: - -------------- Chromium Litigation: Several civil suits are pending against the Utility in California state courts. The suits seek an unspecified amount of compensatory and punitive damages for alleged personal injuries and, in some cases, property damage, resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and Topock, California. Two of these suits on behalf of six individuals also name PG&E Corporation as a defendant. Currently, there are claims pending on behalf of approximately 1,700 individuals. The Utility is responding to the suits and asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual
defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. PG&E Corporation believes that the ultimate outcome of these matters will not have a material impact on its or the Utility's financial position or results of operations. Texas Franchise Fee Litigation: In connection with PG&E Corporation's acquisition of Valero Energy Corporation, now known as PG&E Gas Transmission Texas (PG&E GTT), PG&E GTT succeeded to the litigation described below. PG&E GTT and various of its affiliates are defendants in at least two class action suits and five separate suits filed by various Texas cities. Generally, these cities allege, among other things, that: (1) owners or operators of pipelines occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities; and (2) the gas marketers failed to pay the cities for accessing and utilizing the pipelines located in the cities to flow gas under city streets. Plaintiffs also allege various other claims against the defendants for failure to secure the cities' consent. Damages are not quantified. In 1998, a jury trial was held in the separate suit brought by the City of Edinburg (the City). This suit involved, among other things, a particular franchise agreement entered into by a former subsidiary of PG&E GTT (now owned by Southern Union Gas Company (SU)) and the City and certain conduct of the defendants. On December 1, 1998, based on the jury verdict, the court entered a judgment in the City's favor, and awarded damages of $5.3 million, and attorneys' fees of up to $3.5 million plus interest. The court found that various PG&E GTT and SU defendants were jointly and severally liable for $3.3 million of the damages and all the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable for $1.4 million of the damages. The court did not clearly indicate the extent to which the PG&E GTT defendants could be found liable for the remaining damages. The PG&E GTT defendants are in the process of appealing the judgment. PG&E Corporation believes that the ultimate outcome of these matters could have a material adverse impact on its financial position or its results of operations. The Utility's 1999 General Rate Case (GRC): - ------------------------------------------- In December 1997, the Utility filed its 1999 GRC application with the CPUC. During the GRC process, the CPUC examines the Utility's distribution costs to determine the amount the Utility may charge customers. The Utility has requested distribution revenue increases to maintain and improve gas and electric distribution reliability, safety, and customer service. The requested revenues, as updated, include an increase of $445 million in electric base revenues and an increase of $377 million in gas base revenues over authorized 1998 revenues. The Office of Ratepayer Advocates (ORA) branch of the CPUC has recommended a decrease of $80 million in electric revenues and an increase of $104 million in gas base revenues. Recommendations by the ORA do not represent the positions of the CPUC. In December 1998, the CPUC issued a decision on interim rate relief in the GRC. The decision granted the Utility's request to increase its electric revenues by $445 million and its gas revenues by $377 million on an interim basis pending a decision in the GRC. The decision allows the Utility to
reflect the revenue increases, resulting from the Utility request, in regulatory assets recorded under regulatory adjustment mechanisms approved by the CPUC. The decision does not increase any electric or gas rates billed to customers on an interim basis. Due to a delay in the issuance of a decision in the Utility's GRC, the Utility's 1999 earnings are based on the authorized amount of revenues in effect during 1998 and do not include any portion of the requested revenue increase. When a final decision in the GRC is issued by the CPUC, the Utility's regulatory assets and net income will be adjusted to reflect any differences between the amount of revenues currently being recognized and the amount approved in the final decision. Any such adjustment could have a material impact on the Utility's and PG&E Corporation's results of operations. NOTE 7: SEGMENT INFORMATION PG&E Corporation's reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions. PG&E Corporation's reportable segments are described below. Utility: PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to one of every 20 Americans. Wholesale Business Operations: PG&E Corporation's wholesale business operations consist of PG&E Gen which develops, builds, operates, owns, and manages power generation facilities that serve wholesale and industrial customers; PG&E Gas Transmission (PG&E GT) which owns and operates approximately 9,000 miles of natural gas pipelines, approximately 500 miles of natural gas liquids pipelines, a storage facility, and natural gas processing plants in the Pacific Northwest (PG&E GT NW) and Texas; and PG&E Energy Trading (PG&E ET) which purchases and sells energy commodities and provides risk management services to customers in major North American markets, including, serving PG&E Corporation's other non-utility businesses, unaffiliated utilities, marketers, municipalities, and large end-use customers. Retail Business Operations: PG&E Corporation's retail business operations consist of PG&E Energy Services (PG&E ES) which provides competitively priced electricity, natural gas, and related services to industrial, commercial, and institutional customers.
Segment information for the three- and six-month periods ended June 30, 1999 and 1998, respectively, were as follows: <TABLE> <CAPTION> Wholesale Retail ---------------------------------- ------- PG&E GT Parent ---------------- & Elimi- Utility PG&E Gen NW Texas PG&E ET PG&E ES nations(1) Total ------- ------- ------- ------- ------- ------- ------- ------- (in millions) For the three month period ended: - --------------------------------- June 30, 1999 <S> <C> <C> <C> <C> <C> <C> <C> <C> Operating revenues $ 2,231 $ 253 $ 39 $ 397 $1,767 $ 138 $ (5) $ 4,820 Intersegment revenues 2 1 13 39 257 4 (316) - ------- ------- ------- ------- ------- ------- ------- ------- Total operating revenues 2,233 254 52 436 2,024 142 (321) 4,820 Net income 172 19 13 (8) 1 (14) (3) 180 June 30, 1998 Operating revenues $ 2,116 $ 115 $ 46 $ 431 $1,983 $ 92 $ 4 $ 4,787 Intersegment revenues 1 - 12 91 77 - (181) - ------- ------- ------- ------- ------- ------- ------- ------- Total operating revenues 2,117 115 58 522 2,060 92 (177) 4,787 Net income 186 34 15 (19) 1 (14) (29) 174 For the six month period ended: - ------------------------------- June 30, 1999 Operating revenues $ 4,314 $ 541 $ 85 $ 710 $4,163 $ 269 $ (5) $10,077 Intersegment revenues 4 2 25 83 492 8 (614) - ------- ------- ------- ------- ------- ------- ------- ------- Total operating revenues 4,318 543 110 793 4,655 277 (619) 10,077 Net income 319 51 28 (32) (2) (22) (6) 336 Total assets at June 30, 1999 21,720 3,868 1,158 2,587 2,067 192 (166) 31,426 June 30, 1998 Operating revenues $ 4,141 $ 199 $ 94 $ 864 $3,700 $ 135 $ 7 $ 9,140 Intersegment revenues 2 - 25 173 137 - (337) - ------- ------- ------- ------- ------- ------- ------- ------- Total operating revenues 4,143 199 119 1,037 3,837 135 (330) 9,140 Net income 334 43 30 (29) - (25) (40) 313 Total assets at June 30, 1998 23,618 1,224 1,168 2,713 1,863 106 (501) 30,191 <FN> (1) Net income on intercompany positions recognized by segments using mark to market accounting is eliminated. Intercompany transactions are also eliminated. </TABLE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS PG&E Corporation (the Corporation) is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's businesses provide energy services throughout North America. PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company (the Utility), provides natural gas and electric service to one of every 20 Americans. PG&E Corporation's four other businesses provide a wide range of energy products and services through its wholesale and retail business operations. PG&E Corporation's wholesale business operations consist of PG&E Generating Company (PG&E Gen), formerly known as U.S. Generating Company, which develops, builds, operates, owns, and manages power generation facilities that serve wholesale and industrial customers; PG&E Gas Transmission (PG&E GT) which owns and operates approximately 9,000 miles of natural gas pipelines, approximately 500 miles of natural gas liquids pipelines, a storage facility, and natural gas processing plants in the Pacific Northwest (PG&E GT NW) and Texas (PG&E GTT); and PG&E Energy Trading (PG&E ET) which purchases and sells energy commodities and provides risk management services to customers in major North American markets, including, serving PG&E Corporation's other non-utility businesses, unaffiliated utilities, marketers, municipalities, and large end-use customers. PG&E Corporation's retail business operations consist of PG&E Energy Services (PG&E ES) which provides competitively priced electricity, natural gas, and related services to industrial, commercial, and institutional customers. This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and Pacific Gas and Electric Company. It includes separate consolidated financial statements for each entity. The consolidated financial statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, and PG&E Corporation's other wholly owned and controlled subsidiaries. The consolidated financial statements of the Utility reflect the accounts of the Utility and its wholly owned subsidiaries. This Management's Discussion and Analysis (MD&A) should be read in conjunction with the consolidated financial statements included herein. Further, this quarterly report should be read in conjunction with the Corporation's and the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1998 Annual Report on Form 10-K. This combined Quarterly Report on Form 10-Q, including this MD&A, contains forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on the beliefs and assumptions of management which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes", "speculates", and other similar expressions. Factors that could cause future results to differ materially from those expressed in or implied by the forward-looking statements or historical results include the impact or outcome of: - - the pace and extent of the ongoing restructuring of the electric and gas industries across the United States; - - the outcome of regulatory and legislative proceedings and operational changes related to industry restructuring, including the valuation of the Utility's hydroelectric generation facilities and changes in the Utility's business processes and systems;
- - any changes in the amount the Utility is allowed to collect (recover) from its customers for certain costs which prove to be uneconomic under the new competitive market (called transition costs) in accordance with the Utility's plan for recovering those costs; - - the successful integration and performance of our recently acquired assets; - - our ability to successfully compete outside our traditional regulated markets; - - internal and external Year 2000 software and hardware issues; - - the outcome of the Utility's various regulatory proceedings, including: the 1999 general rate case; the proposal to adopt performance based ratemaking (PBR); the transmission rate case applications; and post-transition period ratemaking proceedings; - - fluctuations in commodity gas and electric prices and our ability to successfully manage such price fluctuations; and - - the pace and extent of competition in the California generation market and its impact on the Utility's costs and resulting collection of transition costs. Although the ultimate impacts of the above factors are uncertain, these and other factors may cause future earnings to differ materially from results or outcomes we currently seek or expect. Each of these factors is discussed in greater detail in this MD&A. In this MD&A, we first discuss our competitive and regulatory environment. We then discuss earnings and changes in our results of operations for the three- and six-month periods ended June 30, 1999 and 1998. Finally, we discuss liquidity and financial resources, various uncertainties that could affect future earnings, and our risk management activities. Our MD&A applies to both PG&E Corporation and the Utility. Competitive and Regulatory Environment This section provides a discussion of the competitive environment in the evolving energy industry, the California electric industry restructuring, the New England electricity market, and regulatory matters. The Competitive Environment in the Evolving Energy Industry - ----------------------------------------------------------- Historically, energy utilities operated as regulated monopolies within specific service territories where they were essentially the sole suppliers of natural gas and electricity services. Under this model, the energy utilities owned and operated all of the businesses necessary to procure, generate, transport, and distribute energy. These services were priced on a combined (bundled) basis, with rates charged by the energy companies designed to include all of the costs of providing these services. Now, energy utilities face intensifying pressures to make competitive those activities that are not natural monopoly services. The most significant of these services are electricity generation and natural gas supply. The driving forces behind these competitive pressures are customers who believe they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators are responding to those customers and competitors by providing more competition in the energy industry. Regulators and legislators are requiring utilities to "unbundle" rates (separate their various energy services and the prices of those services). This allows customers to compare unit prices of the Utility and other providers when selecting their energy service provider. In the natural gas industry, Federal Energy Regulatory Commission (FERC) Order 636 required interstate pipeline companies to divide their services
into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate gas pipelines must provide transportation service regardless of whether the customer (typically a local gas distribution company) buys the gas commodity from the pipeline. In the electric industry, the Public Utilities Regulatory Policies Act of 1978 specifically provided that unregulated companies could become wholesale generators of electricity and that utilities were required to purchase and use power generated by these unregulated companies in meeting their customers' needs. The National Energy Policy Act of 1992 was designed to increase competition in the wholesale unregulated generation market by requiring access to electric utility transmission systems by all wholesale unregulated generators, sellers, and buyers of electricity. Now, an increasing number of states throughout the country either have implemented plans or are considering proposals to separate the generation from the transmission and distribution of electricity through some form of electric industry restructuring. To date, the states, not the federal government, have taken the initiative on electric industry restructuring at the retail level. While at least five bills mandating deregulation of the electric industry were introduced in the U.S. Congress over the past two years, none have been passed. As a result, the pace, extent, and methods for restructuring the electric industry vary widely throughout the country. For instance, as of June 30, 1999, twenty states have enacted electric industry restructuring legislation, including California, Texas, Illinois, Pennsylvania, New Jersey, Massachusetts, Rhode Island, and Connecticut. Other states, such as Oregon, are seriously considering restructuring proposals. There also are some states that have passed legislation precluding or significantly slowing down deregulation. Differences in how individual states view electric industry restructuring often relate to the existing unit cost of energy supplies within each state. Generally, states having higher energy unit costs are moving more quickly to deregulate energy supply markets. Implementation of our national energy strategy depends, in part, upon the opening of energy markets to provide customer choice of supplier. Undue delays by states or federal legislation to deregulate the electric generation and natural gas supply business could impact the pace of growth of our wholesale and retail business operations. California Industry Restructuring - --------------------------------- The Electric Business: In 1998, California became one of the first states in the country to implement electric industry restructuring. Today, many Californians may choose to purchase their electricity from investor-owned utilities such as Pacific Gas and Electric Company, or unregulated retail electricity suppliers (for example, marketers, including PG&E Energy Services, brokers, and aggregators). The restructuring contemplates that the investor-owned utilities, including the Utility, will continue to provide distribution services to substantially all customers within their service territories, including providing electricity to customers who choose not to be served by another service provider. The restructuring legislation recognized that market-based revenues may not be sufficient to recover (that is, collect from customers) all of the Utility's generation costs. The restructuring legislation provides the California investor-owned utilities the opportunity to recover such uneconomic generation costs (called transition costs) until the earlier of
December 31, 2001, or when the utilities have recovered their authorized transition costs as determined by the California Public Utilities Commission (CPUC). The period during which transition costs may be recovered is called the transition period. The legislation permits certain transition costs to be recovered after the transition period. California electric industry restructuring legislation has four principal elements: (1) the establishment of a competitive market framework, (2) an electric rate freeze and rate reduction, (3) the recovery of transition costs, and (4) divestiture of utility-owned generation facilities. Each element is discussed below. Competitive Market Framework: To create a competitive generation market, a Power Exchange (PX) and an Independent System Operator (ISO) began operating on March 31, 1998. During the transition period, the Utility is required to bid or schedule into the PX and ISO markets all of the electricity generated by its power plants and electricity acquired under contractual agreements with unregulated generators. Also during the transition period, the Utility is required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier. The ISO schedules delivery of electricity for all market participants. The Utility continues to own and maintain a portion of the transmission system, but the ISO controls the operation of the system. During 1998 and 1999, the Utility continued its efforts to develop and implement changes to its business processes and systems, including the customer information and billing system, to accommodate electric industry restructuring. To the extent that the Utility is unable to develop and implement such changes in a successful and timely manner, there could be an adverse impact on the Utility's or PG&E Corporation's future results of operations. Rate Freeze and Rate Reduction: Legislation required an electric rate freeze and an electric rate reduction to extend throughout the transition period. The Utility has held rates for its larger customers at 1996 levels, and it will hold their rates at that level until the end of the transition period. On January 1, 1998, the Utility reduced electric rates for its residential and small commercial customers by 10 percent from 1996 levels, and it will hold their rates at that level until the end of the transition period. Collectively, these actions are called a rate freeze. To pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion of its transition costs with the proceeds from rate reduction bonds. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of these transition costs until after the transition period. During the rate freeze, the rate reduction bond debt service will not increase the Utility customers' electric rates. If the transition period ends before December 31, 2001, the Utility will be obligated to return a portion of the bond proceeds to customers. The timing and exact amount of such portion, if any, has not yet been determined. The frozen rates include a component for transition cost recovery. Transition costs are being recovered from all Utility distribution customers through a nonbypassable charge regardless of the customer's choice of electricity supplier. As the customer charge for transition costs is nonbypassable, the Utility believes that the availability of choice to its customers will not have a material impact on its ability to recover transition costs.
Revenues from frozen electric rates provide for the recovery of authorized Utility costs, including transmission and distribution service, public purpose programs, nuclear decommissioning, and rate reduction bond debt service. To the extent the revenues from frozen rates exceed authorized Utility costs, the remaining revenues constitute the competitive transition charge (CTC), which recovers the transition costs. These CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes and certain other factors. Transition Cost Recovery: Market-based revenues through sales to the PX may not be sufficient to recover all of the Utility's generation costs. Under the California restructuring legislation, the Utility has the opportunity to recover its transition costs until the earlier of December 31, 2001, or when the Utility has recovered its authorized transition costs as determined by the CPUC, although certain transition costs can be recovered after the transition period. At the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market-based revenues. Transition costs consist of: (1) above-market sunk costs (costs associated with Utility-owned generation assets that are fixed and unavoidable and currently included in the Utility customers' electric rates) and future costs, such as costs related to removal of Utility-owned generation facilities, (2) costs associated with the Utility's long-term contracts to purchase power at above-market prices from qualifying facilities and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods, to be included in rates in subsequent periods.) Above-market sunk costs result when the book value of a facility is in excess of its market value. Conversely, below-market sunk costs result when the market value of a facility is in excess of its book value. The total amount of generation facility costs to be included as transition costs will be based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. These above- and below-market sunk costs are related to generating facilities that are classified as either non-nuclear or nuclear sunk costs. The Utility cannot determine the exact amount of above-market non-nuclear sunk costs that will be recoverable as transition costs until a market valuation process (through appraisal, sale, or other valuation method) is completed for each of its non-nuclear generation facilities. Several of these valuations occurred in 1997 and 1998, when the Utility agreed to sell seven of its electric generation plants to third parties. The total market value of these facilities resulted in sales proceeds that exceeded the book value and therefore has reduced the amount of transition costs remaining to be recovered. The remainder of the valuation process is expected to be completed by December 31, 2001. The Utility's remaining non-nuclear generation facilities consist primarily of its hydroelectric generation system. If the market value of the Utility's hydroelectric facilities is determined based upon any method other than a sale of the facilities to a third party, a material charge to Utility earnings could result. Any excess of market value over book value would be used to reduce other transition costs. (See Generation Divestiture below.) Nuclear generation sunk costs were determined separately through a CPUC proceeding and were subject to a final verification audit that was completed in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power Plant (Diablo Canyon) accounts at December 31, 1996, resulted in the issuance
of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. The independent accounting firm also issued an agreed- upon special procedures report, requested by the CPUC, that questioned $200 million of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to Diablo Canyon's recoverable costs that resulted from the report. At this time, the Utility cannot predict what actions, if any, the CPUC may take regarding the audit report. Costs associated with the Utility's long-term contracts to purchase electric power at above-market prices are included as transition costs. Over the remaining life of these contracts the Utility estimates that it will purchase 322 million megawatt-hours of electric power. To the extent that the individual contract prices are above the market price, the Utility is collecting the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. The contracts expire at various dates through 2028. The total amount of the above-market costs under long-term contracts will be based on several variables, including the capacity factors of the related generating facilities and future market prices for electricity. During the six-month period ended June 30, 1999, the average price paid per kilowatt-hour (kWh) under the Utility's long-term contracts for electric power was 6.1 cents per kWh. The average cost of electric energy for energy purchased at market rates from the PX for the six-month period ended June 30, 1999, was 2.6 cents per kWh. Generation-related regulatory assets and obligations (net generation- related regulatory assets) are included as transition costs. At June 30, 1999, the Utility's generation-related net regulatory assets totaled $4.5 billion. Most transition costs can be recovered until December 31, 2001. This recovery period is significantly shorter than the recovery period of the generation assets prior to restructuring and is referred to as accelerated recovery. Accordingly, the Utility is amortizing its transition costs, including most generation-related regulatory assets over the transition period. During the transition period, the Utility is receiving a reduced return on common equity for all of its generation assets, including those generation assets reclassified to regulatory assets. The reduced return on common equity is 6.77 percent. Certain transition costs can be recovered through a non-bypassable charge to distribution customers after December 31, 2001. These costs include: (1) certain employee-related transition costs, (2) above-market payments under existing long-term contracts to purchase power, discussed above, (3) up to $95 million of transition costs after the transition period to the extent that the recovery of such costs during the transition period was displaced by the recovery of electric industry restructuring implementation costs, and (4) transition costs financed by the rate reduction bonds. Transition costs financed by the issuance of rate reduction bonds are expected to be recovered over the term of the bonds. In addition, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission the nuclear facility. During the rate freeze the charge for these costs will not increase the Utility customers' electric rates. Excluding these exceptions, the Utility will write off any transition costs not recovered during the transition period. Revenues provided for the recovery of most non-nuclear transition costs are based upon the acceleration of such costs within the transition period. For Diablo Canyon transition costs, revenues provided for transition cost
recovery are based on: (1) an established incremental cost incentive price (ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs and capital additions, and (2) the accelerated recovery of the investment in Diablo Canyon from a period ending in 2016 to a five-year period ending December 31, 2001. In a pending proceeding, the CPUC is currently considering whether the Utility may continue to recover revenues based on the ICIP through December 31, 2001, or must cease recovery of such revenues if it has completed recovery of all other utility generation-related transition costs prior to that date. The Utility is amortizing its eligible transition costs, including generation-related regulatory assets, over the transition period in conjunction with the available CTC revenues. Effective January 1, 1998, the Utility started collecting these eligible transition costs through the nonbypassable CTC. For the six months ended June 30, 1999, regulatory assets related to electric utility restructuring decreased by $813 million, which reflects the recovery of eligible transition costs. During the transition period, the CPUC reviews the Utility's compliance with the accounting methods established in the CPUC's decisions governing transition cost recovery and the amount of transition costs requested for recovery. The CPUC is currently reviewing non-nuclear transition costs amortized during the first six months of 1998. Generation Divestiture: In 1998, the Utility completed the sale of three fossil-fueled generation plants for $501 million. These three fossil-fueled plants had a combined book value at the time of the sale of $346 million and had a combined capacity of 2,645 megawatts (MW). On April 16, 1999, the Utility sold three other fossil-fueled generation plants for $801 million. At the time of sale, these three fossil-fueled plants had a combined book value of $256 million and had a combined capacity of 3,065 MW. On May 7, 1999, the Utility sold its complex of geothermal generation facilities for $213 million. At the time of sale, these facilities had a combined book value of $244 million and had a combined capacity of 1,224 MW. The Utility will retain a liability for required environmental remediation related to all of its fossil-fueled generation and geothermal generation plants of any pre-closing soil or groundwater contamination at the plants it has or will sell. The Utility records its estimated liability for the retained environmental remediation obligation as part of the determination of the gain or loss on the sale of each plant. Any gains from the sale of the Utility-owned generation plants will be used to offset other transition costs. Likewise, any losses from the sale of Utility-owned generation plants are recoverable as transition costs. PG&E Corporation does not believe sales of any generation facilities to a third party will have a material impact on its results of operations. In May 1998, the Utility notified the CPUC that it does not plan to retain its hydroelectric generation assets as part of the Utility. In December 1998, the Utility filed with the CPUC its proposed appraisal process for valuing its hydroelectric facilities. The Utility withdrew its proposal in March 1999 when the CPUC clarified that the CPUC proceeding would only apply to assets to be retained in the Utility. The Utility currently is evaluating alternative strategies with respect to the valuation and disposition of its hydroelectric facilities, including a potential transfer of the facilities to another PG&E Corporation affiliate. Meanwhile, the California legislature is reviewing legislative proposals that would address hydroelectric facilities
valuation and divestiture issues on an interim or permanent basis. If legislation setting a valuation were enacted and the legislated valuation was materially higher than the value ultimately recognized in connection with the sale or other disposition of the assets, the Utility could suffer a material loss upon the sale or other disposition of the hydroelectric assets. If such legislation were enacted, we expect that the Utility would challenge the legality of legislation adopting such excess or interim valuation. Although legislation could be passed prior to the close of the legislative session in September 1999, the Corporation and Utility are unable to predict the nature or likelihood of enactment of any such legislation. At June 30, 1999, the book value of the Utility's net investment in hydroelectric generation assets was approximately $0.8 billion, excluding approximately $0.5 billion of net investment reclassified as regulatory assets recoverable as transition costs. The value of the hydroelectric assets is expected to exceed their book value by a material amount. In connection with legislative discussions concerning the hydroelectric assets, some third parties have publicly speculated that the value of the hydroelectric assets could be in excess of $3 billion. If the market value of the hydroelectric generation assets is determined by any method other than a sale of the assets to a third party, a material charge to Utility earnings could result. Any excess of market value over the $0.8 billion book value would be used to reduce other transition costs, including the remaining $0.5 billion of regulatory assets related to the hydroelectric generation assets. The timing and nature of any such charge is dependent upon the valuation method and procedure adopted, and the method of implementation, which could occur as soon as the third quarter of 1999. Financial Impact: The Utility's ability to continue recovering its transition costs will be dependent on several factors including: (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the determined value of the Utility's hydroelectric generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, (6) the extent to which the Utility's authorized revenues to recover distribution and transmission costs are increased or decreased, and (7) the market price of electricity. Given the current evaluation of these factors, PG&E Corporation believes that the Utility will recover its transition costs under the terms of the approved transition plan. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge. The Gas Business: Restructuring of the natural gas industry on both the national and the state level has given choices to California utility customers to meet their gas supply needs. The Gas Accord Settlement (Accord), a multi-party settlement approved by the CPUC in 1997, continues the process of restructuring the gas industry in California. The Accord was implemented in March 1998, and has four principal elements: 1. The Accord separates or "unbundles" the rates for the Utility's gas transportation system. The Utility now offers transmission, distribution, and storage services as separate and distinct services to its noncore customers. Unbundling gives these customers the opportunity to select from a menu of services offered by the Utility and enables them to pay only for the services that they use. Unbundling also makes access to the transmission system possible for all gas marketers and shippers, as well as noncore end- users. As a result, the Accord makes the Utility's transmission system more accessible to a greater number of customers.
2. The Accord increases the opportunity for the Utility's core customers to select the commodity gas supplier of their choice. Greater customer choice increases competition among suppliers providing gas to core customers and reduces the Utility's role in purchasing gas for such customers. Despite these changes, the Utility continues to purchase gas as a regulated supplier for those who request it, serving a majority of core customers in its service territory. 3. The Accord changes the way in which the Utility's costs of purchasing gas for core customers through 2002 are regulated. The Accord replaces CPUC reasonableness reviews with the core procurement incentive mechanism (CPIM), a form of incentive ratemaking that provides the Utility a direct financial incentive to procure gas and transportation services at the lowest reasonable costs by comparing all procurement costs to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are considered reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, ratepayers and shareholders share savings or costs, respectively. 4. The Accord settled various regulatory issues involving the Utility and various other parties. Resolution of these issues did not have a material adverse impact on the Utility's or our financial position or results of operations. The Accord also establishes gas transmission rates within California for the period from March 1998 through December 2002 for the Utility's core and noncore customers and eliminates regulatory protection for variations in sales volumes for noncore transmission revenues. As a result, the Utility is at risk for variations between actual and forecasted noncore transmission throughput volumes. However, we do not expect these variations to have a material adverse impact on the Utility's or our financial position or results of operations. Rates for gas distribution services will continue to be set by the CPUC and designed to provide the Utility an opportunity to recover its costs of service and include a return on its investment. The regulatory mechanisms for setting gas distribution rates are discussed below under Regulatory Matters. New England Electricity Market: - ------------------------------- Three New England states where our wholesale businesses operate electric generation facilities (Massachusetts, New Hampshire, and Rhode Island) were, like California, among the first states in the country to introduce electric industry restructuring. Connecticut also has passed electric industry restructuring legislation. As a result of this restructuring and certain other regulatory initiatives, the wholesale unregulated electricity market in New England features a bid-based market and an ISO. In September 1998, PG&E Corporation, through its indirect subsidiary USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generation assets and power supply contracts from New England Electric System (NEES). The purchased assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of about 4,000 MW. Including fuel and other inventories and transaction costs, the financing requirements for this transaction were approximately $1.8 billion, funded through an aggregate of $1.3 billion of PG&E Gen and USGenNE debt and a $425 million equity contribution from PG&E Corporation. The net purchase price has been allocated as follows: (1) electric generating assets of $2.3
billion, (2) receivable for support payments of $0.8 billion, and (3) out of market contractual obligations of $1.3 billion, relating to acquired power purchase agreements, gas agreements and standard offer agreements. As part of the New England electric industry restructuring, the local utility companies providing service to retail customers were required to offer Standard Offer Service (SOS) to their customers. Retail customers may select alternative suppliers at any time. The SOS is intended to provide customers with a price benefit (the commodity electric price offered to the retail customer is expected to be less than the market price) for the first several years, followed by a price disincentive that is intended to stimulate the retail market. Retail customers may continue to receive SOS through June 30, 2002, in New Hampshire (subject to early termination on December 31, 2000, at the discretion of the New Hampshire Public Service Commission), through December 31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island. However, if any customers elect to have their electricity provided by an alternate supplier, they are precluded from going back to the SOS. In connection with the purchase of the generation assets, we entered into agreements to supply the electric capacity and energy requirements necessary for NEES to meet its SOS obligations. NEES is responsible for passing on to us the revenues generated from the SOS. USGenNE, is currently serving the SOS electric capacity and energy requirements for NEES, except for New Hampshire's SOS. On March 1, 1999, Constellation Power Source, Inc. assumed this component of the SOS upon winning a competitive bidding solicitation. Like California utilities, the New England utilities entered into agreements with unregulated companies to provide energy and capacity at prices that are anticipated to be in excess of market prices. We assumed NEES' contractual rights and duties under several of these power-purchase agreements, which in aggregate provide for 800 MW of capacity. However, NEES will make support payments to us toward the cost of these agreements. The support payments by NEES total $1.1 billion in the aggregate (undiscounted) and are due in monthly installments from September 1998 through January 2008. In certain circumstances, with our consent, NEES may make a full or partial lump sum accelerated payment. Initially, approximately 90 percent of the acquired operating capacity, including capacity and energy generated by other companies and provided to us under power-purchase agreements, is dedicated to providing services to customers receiving SOS. To the extent that customers eligible to receive SOS chose alternate suppliers, this percentage will decrease. As customers choose alternate suppliers, a greater proportion of the output of the acquired operating capacity will be subject to market prices. Regulatory Matters: - ------------------- The Utility is the only subsidiary with significant regulatory activity at this time. Items affecting future Utility authorized revenues include: the 1999 general rate case, the 1999 cost of capital proceeding, the distribution performance based ratemaking application, FERC transmission rate cases, the CPUC's gas strategy order instituting rulemaking, the Diablo Canyon sunk costs audit, and post transition period ratemaking proceeding. These items are discussed below. Any requested change in authorized electric revenues resulting from any of these proceedings would not impact the Utility's customer electric rates through the transition period because these rates are frozen in accordance with the electric transition plan. However, the amount of remaining revenues providing for the recovery of transition costs would be affected.
The 1999 General Rate Case (GRC): In December 1997, the Utility filed its 1999 GRC application with the CPUC. During the GRC process, the CPUC examines the Utility's distribution costs to determine the amount the Utility may charge customers. The Utility has requested distribution revenue increases to maintain and improve gas and electric distribution reliability, safety, and customer service. The requested revenues, as updated, include an increase of $445 million in electric base revenues and an increase of $377 million in gas base revenues over authorized 1998 revenues. The Office of Ratepayer Advocates (ORA) branch of the CPUC has recommended a decrease of $80 million in electric revenues and an increase of $104 million in gas base revenues. Recommendations by the ORA do not represent the positions of the CPUC. In December 1998, the CPUC issued a decision on interim rate relief in the GRC. The decision granted the Utility's request to increase its electric revenues by $445 million and its gas revenues by $377 million on an interim basis pending a decision in the GRC. The decision allows the Utility to reflect the revenue increases, resulting from the Utility request, in regulatory assets recorded under regulatory adjustment mechanisms approved by the CPUC. The decision does not increase any electric or gas rates billed to customers on an interim basis. Due to a delay in the issuance of a decision in the Utility's GRC, except for the impacts of the cost of capital decision, discussed below, the Utility's 1999 earnings are based on the authorized amount of revenues in effect during 1998 and do not include any portion of the requested revenue increase. When a final decision in the GRC is issued by the CPUC, the Utility's regulatory assets and net income will be adjusted to reflect any differences between the amount of revenues currently being recognized and the amount approved in the final decision. Any such adjustment could have a material impact on the Utility's and PG&E Corporation's results of operations. The 1999 Cost of Capital Proceeding: In June 1999, the CPUC issued a final decision in the Utility's 1999 Cost of Capital proceeding. The decision adopts a return on common equity (ROE) of 10.6 percent for the Utility's electric distribution and gas distribution assets, and an overall return on utility rate base of 8.75 percent in 1999. These are reductions from the Utility's 1998 authorized ROE of 11.2 percent and overall return of 9.17 percent. The decision maintains the Utility's authorized capital structure for 1999 at 46.2 percent long-term debt, 5.8 percent preferred stock, and 48 percent common equity. The decision is retroactive to January 1, 1999. The decision has reduced the Utility's base revenues for the six-months ended June 30, 1999 as compared to the six-months ended June 30, 1998, by $23.1 million and $7.3 million for electric and gas distribution, respectively. The Distribution Performance Based Ratemaking (PBR) Application: The Utility filed an amended distribution PBR proposal with the CPUC in February 1999. If approved as filed, the distribution PBR will determine the Utility's gas and electric distribution revenues for the years 2000 through 2004. Under the Utility's proposal, distribution revenues for the years 2000 through 2004 would be determined by multiplying total distribution revenues by a rate formula. The rate formula would be based principally on inflation less a proposed productivity factor of 1.1 percent and 0.82 percent for electric distribution and gas distribution, respectively. These productivity
factors will be fixed for the five year duration of the PBR. The Utility has proposed different rate formulas for gas customers, small electric customers (principally residential and commercial customers) and large electric customers. The proposal also includes a sharing mechanism for earnings that are significantly above or below the authorized weighted average cost of capital. In addition, the proposed PBR includes rewards and penalties that will depend upon the Utility's ability to achieve performance standards for electric distribution reliability; maintenance, repair, and replacement; customer service; and employee safety. The procedural schedule in the PBR proceeding has been suspended pending the issuance of a proposed decision in the Utility's 1999 GRC proceeding. A final decision in the PBR proceeding is not expected to be issued until mid-2000. The Utility has applied for interim relief, which would make the final decision effective on January 1, 2000. FERC Transmission Rate Cases: Since April 1, 1998, all electric transmission revenues are authorized by FERC. During 1998, the FERC issued orders that put into effect various rates to recover electric transmission costs from the Utility's former bundled rate transmission customers. These rates are subject to refund. On April 14, 1999, the Utility filed a settlement with FERC which, if approved, allows the Utility to recover $168 million for the period of April 1998 through October 1998, and $177 million for the period of November 1998 through May 1999. The Utility does not expect a material impact on its financial position or results of operations resulting from the settlement. On May 27, 1999, FERC approved, subject to refund, the Utility's March 30, 1999, request to begin recovering, as of May 31, 1999, $324 million annually in revenues from its former bundled retail transmission customers. The CPUC's Gas Strategy Order Instituting Rulemaking: In January 1998, the CPUC opened a rulemaking proceeding to explore changes in the natural gas industry, including the possible further unbundling of services to promote competition, streamlining regulation for noncompetitive services, mitigating the potential for anti-competitive behavior, and establishing appropriate consumer protections. In 1998, the Governor of California signed Senate Bill 1602, allowing the CPUC to investigate issues associated with the further restructuring of natural gas services but prohibiting the CPUC from enacting any such gas industry restructuring decisions prior to January 1, 2000. On July 8, 1999, the CPUC issued a decision identifying options for restructuring the natural gas industry. In the decision, the CPUC reaffirmed the structure of the Gas Accord and stated that it seeks to explore that market structure that maintains the utilities' traditional role of providing fully integrated default service to core customers while removing obstacles to competitive offering of gas commodity, transmission, storage, balancing, and certain other services. The CPUC requested all interested parties to try to settle various issues raised in the decision within 60 days, and if that effort is unsuccessful, to move to hearings on the costs, benefits, and other factors affecting these proposals, with initial testimony due in late September 1999. The CPUC closed the existing rule-making proceedings and opened a new investigative proceeding to explore in more detail the anticipated costs and benefits associated with the different market structure options the CPUC has identified. The CPUC's goal is to submit a final report to the California Legislature on gas restructuring possibly in the first quarter of next year.
The Diablo Canyon Sunk Costs Audit: In August 1998, an independent accounting firm retained by the CPUC completed a financial verification audit of the Utility's Diablo Canyon plant accounts as of December 31, 1996. The audit resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. (Sunk costs are costs associated with Utility-owned generating facilities that are fixed and unavoidable and currently included in the Utility customers' electric rates.) The independent accounting firm also issued an agreed-upon special procedures report which questioned $200 million of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to Diablo Canyon's recoverable costs, which resulted from the report. At this time, the Utility cannot predict what actions, if any, the CPUC may take regarding the audit report. Post-Transition Period Ratemaking Proceeding: In a pending proceeding, the CPUC currently is considering the ratemaking mechanism under which the Utility's transition cost recovery would be completed, the rate freeze would end, and post-transition rates would be established, consistent with the electric industry restructuring legislation and the Utility's transition cost recovery plan. In this proceeding, the CPUC is considering whether the Utility may continue to recover revenues for its Diablo Canyon nuclear transition costs based on the incremental cost incentive price (ICIP) through December 31, 2001, or must cease recovery of such revenues if the Utility has completed recovery of all other generation related transition costs before that date. The ICIP was established effective January 1, 1997, as a performance-based mechanism to recover Diablo Canyon's variable and other operating costs and capital addition costs. The ICIP mechanism establishes a rate per kWh generated by the facility. This rate is based upon a fixed forecast of ongoing costs, capital additions, and capacity factors for the period 1997 through 2001. The fixed forecast of ICIP for 1999, 2000, and 2001 is $3.37 per Kwh, $3.43 per kWh, and $3.49 per kWh, respectively. The ICIP revenues, based on an assumed capacity factor of 83.6%, for 1999, 2000, and 2001, are projected to be $532 million, $542 million, and $552 million, respectively. If the ICIP mechanism is discontinued before December 31, 2001, the price for Diablo Canyon generation may be lower or higher than the ICIP prices depending on market conditions, which would result in lower or higher revenues than the projected ICIP revenues. The average cost of electric energy for energy purchased at market rates from the PX for the six-months ended June 30, 1999, was 2.6 cents per kWh. Results of Operations In this section, we present the components of our results of operations for the three- and six-month periods ended June 30, 1999 and 1998. Due to a delay in the issuance of a decision in the Utility's GRC, except for the impacts of the cost of capital decisions, discussed above, the Utility's 1999 earnings are based on the authorized amount of revenues in effect during 1998 and do not include any portion of the requested revenue increase. When a final decision in the GRC is issued by the CPUC, the Utility's regulatory assets and net income will be adjusted to reflect any differences between the amount of revenues currently being recognized and the amount approved in the final decision. Any such adjustment could have a material impact on the Utility's and PG&E Corporation's results of operations. The table below shows for the three- and six-month periods ended June 30, 1999 and 1998, respectively, certain items from our Statement of Consolidated Income detailed by (1) Utility, (2) wholesale, and (3) retail business
operations of PG&E Corporation. (In the "Total" column, the table shows the combined results of operations for these three groups.) The information for PG&E Corporation (the "Total" column) excludes transactions between its subsidiaries (such as the purchase of natural gas by the Utility from the unregulated business operations). Following this table we discuss earnings and explain why the components of our results of operations varied for the three- and six-month periods ended June 30, 1999, as compared to the same periods in 1998.
<TABLE> <CAPTION> Wholesale Retail --------------------------------- ------- PG&E GT Parent ---------------- & Elimi- Utility PG&E Gen NW Texas PG&E ET PG&E ES nations(1) Total ------- ------- ------- ------- ------- ------- ------- ------- (in millions) For the three-month period ended: - --------------------------------- June 30, 1999 <S> <C> <C> <C> <C> <C> <C> <C> <C> Operating revenues $ 2,233 $ 254 $ 52 $ 436 $2,024 $ 142 $ (321) $ 4,820 Operating expenses 1,781 247 23 444 2,024 165 (318) 4,366 Operating income 454 Other income, net 39 Interest expense, net 192 Income taxes 121 Net income 180 EBITDA (2) 954 42 40 12 2 (21) (6) 1,023 June 30, 1998 Operating revenues $ 2,117 $ 115 $ 58 $ 522 $2,060 $ 92 $ (177) $ 4,787 Operating expenses 1,623 55 23 532 2,058 114 (175) 4,230 Operating income 557 Other income, net (8) Interest expense, net 196 Income taxes 179 Net income 174 EBITDA (2) 867 63 45 5 4 (21) (21) 942 For the six-month period ended: - ---------------------------------------------- June 30, 1999 Operating revenues $ 4,318 $ 543 $ 110 $ 793 $4,655 $ 277 $ (619) $10,077 Operating expenses 3,444 494 50 827 4,660 315 (609) 9,181 Operating income 896 Other income, net 60 Interest expense, net 393 Income taxes 227 Net income 336 EBITDA (2) 1,749 108 81 5 (1) (33) (13) 1,896 June 30, 1998 Operating revenues $ 4,143 $ 199 $ 119 $1,037 $3,837 $ 135 $ (330) $ 9,140 Operating expenses 3,225 121 48 1,045 3,835 174 (329) 8,119 Operating income 1,021 Other income, net 7 Interest expense, net 393 Income taxes 322 Net income 313 EBITDA (2) 1,505 86 94 18 4 (37) (17) 1,653 <FN> (1) Net income on intercompany positions recognized by segments using mark to market accounting is eliminated. Intercompany transactions are also eliminated. (2) EBITDA measures earnings (after preferred dividends) before interest expense (net of interest income), income taxes, depreciation and amortization. </TABLE>
Overall Results: - ---------------- Net income increased $6 million for the three-month period ended June 30, 1999, as compared to the same period in 1998 primarily because in the second quarter of 1998, the Corporation recognized a $.06 per share charge related to the disposition of its investment in its Australian holdings resulting from the 22 percent currency devaluation of the Australian dollar against the U.S. dollar. In addition, 1999 results continue to reflect a decrease in the effective income tax rate resulting from the expansion of business activities outside of California. These increases in net income were partially offset by a reduction in Utility net income due to the disposition of its generating assets in 1998 and 1999, the cost of capital decision discussed above, and a decrease in PG&E Gen's income resulting from a decrease in portfolio management activity compared to 1998 levels. Net income for the six-month period ended June 30, 1999, was $336 million compared to $313 million for the same period in 1998. This increase was attributable to the fact that, in 1998, the Corporation recognized a non- recurring charge related to the disposition of its Australian holdings discussed above. Utility earnings were less in 1999 than the comparable period in 1998 as result of the disposition of its generating facilities, discussed below, and a lower authorized cost of capital on its distribution business. Operating Revenues: - ------------------- Utility: Utility operating revenues increased by $116 million for the three-month period ended June 30, 1999, as compared to the same period in 1998. Most of the increase is attributed to a $43 million increase in revenues from residential and small commercial electric customers reflecting customer growth. In addition, 1998 revenues were $30 million less than 1999 revenues due to abnormally high rainfall, which reduced demand for irrigation water pumping in the second quarter of 1998. Utility operating revenues increased by $175 million for the six-month period ended June 30, 1999, as compared to the same period in 1998. This increase is primarily due to: (1) a $79 million increase in revenues from residential and small commercial electric customers reflecting customer growth, (2) a $110 million increase in gas residential sales reflecting cooler temperatures, particularly during the first three months of 1999, and (3) a $30 million increase in commercial and agricultural electric sales, discussed above. Partially offsetting these increases is $54 million of lower sales to medium and large electric customers leaving for direct access. Wholesale Business Operations: Operating revenues associated with wholesale business operations increased by $11 million for the three-month period ended June 30, 1999, as compared to the same period in 1998. The increase principally relates to increased revenues from PG&E Gen's acquisition of a portfolio of electric generating assets and power supply contracts from NEES in the third quarter of 1998. This increase was partially offset by a decline in the proportion of natural gas volumes shipped for resale at PG&E GTT, lower interruptible sales at PG&E GT NW, and lower gas commodity trading at PG&E ET.
Operating revenues associated with wholesale business operations increased $909 million for the six-month period ended June 30, 1999, as compared to the same period in 1998. This increase was a result of increased gas and electric commodity trading at PG&E ET and PG&E Gen's acquisition of a portfolio of electric generating assets and power supply contracts from NEES in the third quarter of 1998. These increases were partially offset by a decline in operating revenues resulting from declines in proportion of natural gas volumes shipped for resale at PG&E GTT and lower interruptable sales at PG&E GT NW. Retail Business Operations: Operating revenues associated with the retail business operations increased $50 million and $142 million for the three- and six-month periods ended June 30, 1999, as compared to the same period in 1998. These increases were primarily due to sales of electricity in California. Operating Expenses: - ------------------- Utility: Utility operating expenses increased $158 million and $219 million for the three- and six-month periods ended June 30, 1999, respectively, as compared to the same periods in 1998 as a result of higher purchased gas volumes from the increase in residential gas sales due to cooler weather in the first quarter, ISO Grid Management charges in the current year, and increased recovery of stranded costs (transition costs). Partially offsetting this increase is decreased fuel, depreciation, and environmental costs due to plant sales. Wholesale Business Operations: Operating expenses for the wholesale business increased $70 million for the three-month period ended June 30, 1999, as compared to the same period in 1998. This increase reflects increased operating costs at PG&E Gen resulting from the acquisition of the New England assets discussed above. The increase was partially offset by a decline in the volumes of gas commodities purchased at PG&E ET and decreased operating expenses at PG&E GTT, resulting from a decline in gas purchased for resale. Operating expenses for the wholesale business operations increased $982 million for the six-month period ended June 30, 1999, as compared to the same period in 1998. This increase reflects increased volumes of energy commodities purchased at PG&E ET and operating costs associated with the New England assets at PG&E Gen. These increases were partially offset by decreased operating expenses at PG&E GTT. The year to date operating expenses include approximately $6 million of restructuring and severance costs at the Gas Transmission business unit. Retail Business Operations: Operating expenses for our retail business operations increased $51 million and $141 million for the three- and six-month periods ended June 30, 1999, respectively, as compared to the same periods in 1998. This increase is due to the increased electric commodity sales of our energy services business. Income Taxes: - ------------- Income taxes decreased $58 million and $95 million for the three- and six- month periods ended June 30, 1999, as compared to the same periods in 1998,
due to a lower effective state income tax rate resulting from our expanded business operations outside of California. EBITDA: - ------- Utility: EBITDA increased $87 million and $244 million for the three- and six-month periods ended June 30, 1999, respectively, as compared to the same periods in 1998. This increase is generally due to an increase in operating revenues as discussed above, partially offset by an increase in operating expenses resulting from higher purchased gas volumes for increased residential gas sales in the first quarter; and ISO grid management charges in the current year. Wholesale: EBITDA decreased $21 million for the three-month period ended June 30, 1999, as compared to the same period in 1998. This decrease is a result of lower interruptable sales at PG&E GT NW and reduced portfolio management activity at PG&E Gen, partially offset by an increase in natural gas liquids sales margins at PG&E GTT. For the six-month period ended June 30, 1999, EBITDA decreased by $9 million as compared to the same period in 1998. This decrease is due to a decline in operating revenues resulting from declines in the proportion of natural gas volumes shipped for resale at PG&E GTT and lower interruptable sales at PG&E GT NW. The decrease in EBITDA is partially offset by higher revenues resulting from PG&E Gen's acquisition of a portfolio of electric generating assets and power supply contracts from NEES in the third quarter of 1998. Stock Dividend: - --------------- We base our common stock dividend on a number of financial considerations, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk. Our current quarterly common stock dividend is $.30 per common share, which corresponds to an annualized dividend of $1.20 per common share. We continually review the level of our common stock dividend taking into consideration the impact of the changing regulatory environment throughout the nation, the resolution of asset dispositions, the operating performance of our business units, and our capital and financial resources in general. The CPUC requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay PG&E Corporation. During 1999, the Utility has been in compliance with its CPUC-authorized capital structure. PG&E Corporation and the Utility believe that this requirement will not affect PG&E Corporation's ability to pay common stock dividends. However, depending on the outcome of the legislative and regulatory process surrounding the valuation and divestiture of the Utility's hydroelectric facilities discussed in "Generation Divestiture" above, certain valuation or disposition methodologies, other than a sale of the facilities to a third party, could necessitate a waiver of the CPUC's authorized capital structure in order to permit PG&E Corporation or the Utility to continue paying common stock dividends at the current level.
Liquidity and Financial Resources Cash Flows from Operating Activities: Net cash provided by PG&E Corporation's operating activities totaled $1,637 million and $1,250 million during the six-month period ended June 30, 1999 and 1998, respectively. Net cash provided by the Utility's operating activities totaled $1,568 million and $1,182 million during the six-month period ended June 30, 1999 and 1998, respectively. Cash Flows from Financing Activities: PG&E Corporation: We fund investing activities from cash provided by operations after capital requirements and, to the extent necessary, external financing. Our policy is to finance our investments with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to the Utility, complies with regulatory guidelines. Based on cash provided from operations and our investing and disposition activities, we may repurchase equity and long-term debt in order to manage the overall size and balance of our capital structure. During the six-month period ended June 30, 1999 and 1998, we issued $32 million and $33 million of common stock, respectively, primarily through the Dividend Reinvestment Plan and the stock option plan component of the Long- Term Incentive Program. During the six-month period ended June 30, 1999 and 1998, we declared dividends on our common stock of $220 million and $229 million, respectively. During the six-month period ended June 30, 1999 and 1998, we repurchased $503 million and $1,123 million of our common stock, respectively. These repurchases were executed through accelerated share repurchase programs. Under the most recent agreement, PG&E Corporation purchased 16.6 million shares of its common stock. PG&E Corporation retains the risk of increases and the benefit of decreases in the price of the common shares purchased by the counterparty. The counterparty may make purchases on the open market or through privately negotiated transactions until the counterparty has replaced the shares sold to PG&E Corporation. PG&E Corporation may elect to settle its obligations under such arrangement with either cash or shares of its common stock. For the three- and six-month periods ended June 30, 1999, this agreement caused the $0.03 and $0.08 dilution, respectively, reflected in PG&E Corporation's diluted earnings per share. This dilution will be eliminated when the associated forward contract is settled. We maintain a number of credit facilities throughout our organization to support commercial paper programs, letters of credit, and other short term liquidity requirements. At PG&E Corporation, we maintain two $500 million revolving credit facilities, one of which expires in November 1999 and the other in 2002. The PG&E Corporation credit facilities are used to support the commercial paper program and other liquidity needs. The facility expiring in 1999 may be extended annually for additional one-year periods upon agreement between the lending institutions and us. There was $516 million of commercial paper outstanding at June 30, 1999. PG&E Gen maintains two credit facilities of $550 million each. One agreement expires in August 1999 and the other in 2003. The total amount outstanding at June 30, 1999, backed by the facilities, was $858 million in commercial paper. Of these loans, $550 million is classified as noncurrent in the consolidated balance sheet.
At June 30, 1999, PG&E GTT had $54 million of outstanding short-term bank borrowings related to three separate credit facilities. These lines may be cancelled upon demand and bear interest at each respective bank's quoted money market rate. The borrowings are unsecured and unrestricted as to use. On June 30, 1999, PG&E GTT redeemed $69 million of its senior notes, resulting in a gain on redemption of approximately $1.7 million. PG&E GT NW maintains a $100 million revolving credit facility which expires in the year 2002, but has a one-year renewal option. PG&E GT NW also maintains a $50 million 364-day credit facility which expires in the year 2000, but can be extended for successive 364-day periods. No amounts were outstanding under either of these credit facilities at June 30, 1999. At June 30, 1999, PG&E GT NW had an outstanding commercial paper balance of $97 million, which is classified as noncurrent. Utility: During the six-month period ended June 30, 1999, the Utility repurchased 20 million shares of its common stock from PG&E Corporation for an aggregate purchase price of $725 million to maintain its authorized capital structure. During the six-month period ended June 30, 1999 and 1998, the Utility declared dividends on its common stock of $195 million and $100 million. The Utility's long-term debt that either matured, was redeemed, or was repurchased during the six-month period ended June 30, 1999 totaled $348 million. Of this amount, (1) $148 million related to the Utility's rate reduction bonds maturing; (2) $109 million related to the Utility's repurchase of various mortgage bonds; (3) $67 million related to the Utility's maturity of the Utility's 5.5 percent mortgage bonds; and (4) $24 million related to the maturities and redemption of various of the Utility's medium term notes. The Utility maintains a $1 billion revolving credit facility, which expires in 2002. The Utility may extend the facility annually for additional one-year periods upon agreement with the banks. This facility is used to support the Utility's commercial paper program and other liquidity requirements. The Utility did not have any outstanding debt related to this credit facility at June 30, 1999. Additionally, no commercial paper or bank notes were outstanding at June 30, 1999. Cash Flows from Investing Activities: The primary uses of cash for investing activities are additions to property, plant, and equipment; unregulated investments in partnerships; and acquisitions. The Utility's GRC application contained estimates of capital spending for 1999 in the amount of $1.6 billion, excluding capital expenditures for divested fossil and geothermal power plants. These estimates were reflected in the amount of base revenues requested by the Utility in its GRC filing. If the CPUC ultimately authorizes base revenues that are significantly lower than those requested by the Utility, the Utility's level of prospective capital expenditures will be reduced and actual expenditures could differ materially. The Utility has sold its remaining fossil generation facilities and its geothermal generation facilities. These sales closed in April and May 1999. The sales generated proceeds of $1,014 million.
Environmental Matters: We are subject to laws and regulations established to both maintain and improve the quality of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove those substances or remedy effects on the environment. At June 30, 1999, the Utility expects to spend $294 million over the next 30 years for cleanup costs at identified sites. If other responsible parties fail to pay or expected outcomes change, then these costs may be as much as $482 million. Of the $294 million, the Utility has recovered $136 million (including remediation of generation plants divested, discussed above) and expects to recover another $129 million in future rates. The Utility mitigates its cost by seeking recovery from insurance carriers and other third parties. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in the estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimated costs using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or expected outcomes change. Year 2000: The Year 2000 issue exists because many computer programs use only two digits to refer to a year, and were developed without considering the impact of the upcoming change in the century. If PG&E Corporation's mission-critical computer systems fail or function incorrectly due to not being made Year 2000 ready, they could directly and adversely affect our ability to generate or deliver our products and services or could otherwise affect revenues, safety, or reliability for such a period of time as to lead to unrecoverable consequences. Our plan to address the Year 2000 issues focuses primarily on mission- critical systems whose components are categorized as in-house software, vendor software, embedded systems, and computer hardware. The four primary phases of our plan to address these systems are inventory and assessment, remediation, testing, and certification. Certification occurs when mission-critical systems are formally determined to be Year 2000 ready. "Year 2000 ready" means that a system is suitable for continued use into the year 2000. Once Year 2000 ready, additional standards and processes are imposed to prevent systems from being compromised. Our Year 2000 project is generally proceeding on schedule. The following table indicates our Year 2000 progress as of July 26, 1999. Year 2000 Readiness of Mission-Critical Items Remediation Testing Certification Completed Completed Completed - ---------------------------------------------------------------------- In-house software 100% 99% 99% Vendor software 100% 100% 100% Embedded systems 100% 100% 81% Computer hardware 100% 100% 100%
The percentages above reflect approximations based on a uniform reporting system that combines subsidiary results to provide a consistent, corporate- wide view and are derived using standard rounding conventions. Even where 100% is reported, there may be remaining items. Moreover, changes in inventories, or issues uncovered in subsequent phases for an item previously reported as completed, may lead to downward adjustments in percentages from period to period. Even after systems are certified, we are continuing various kinds of validation and quality assurance efforts, and may do so into the year 2000. The Utility routinely reports Year 2000 progress to the CPUC, North American Electric Reliability Council (NERC), and the Nuclear Regulatory Commission (NRC). The Utility has notified NERC and the NRC that it is Year 2000 ready, with limited exceptions. In addition to internal systems, we also depend upon external parties, including customers, suppliers, business partners, gas and electric system operators, government agencies, and financial institutions to support the functioning of our business. To the extent that any of these parties are considered mission-critical to our business and experience Year 2000 problems in their systems, our mission-critical business functions may be adversely affected. To deal with this vulnerability, we have a four phased approach for dealing with external parties: (1) inventory, (2) action planning, (3) risk assessment, and (4) contingency planning. The contingency planning process also addresses exposures that could result from failures in our own essential business systems. Contingency plans will be revised throughout 1999 as necessary. The Utility's contingency plans are being incorporated into its emergency plans and may include measures such as emergency back-up and recovery procedures, augmenting automated applications with manual processes, and identification of alternate suppliers. Electric transmission and generation plans are coordinated with those of the ISO and PX and are consistent with Western Systems Coordinating Council and NERC recommendations and NRC guidelines. The plans will be tested in Utility and electric-industry drills in which the Utility participates throughout 1999, and updated as necessary. As of June 30, 1999, we estimate total costs to address Year 2000 problems to be $223 million, of which $97 million is attributed to the Utility. Included are systems replaced or enhanced for general business purposes and whose implementation schedules are critical to our Year 2000 readiness. Through June 1999, we spent approximately $166 million, of which $91 million was capitalized. The remaining $75 million was expensed. Future costs, including contingency funds, to address Year 2000 issues are expected to be $57 million, of which $23 million will be capitalized. The remaining $34 million will be expensed. Based on our current schedule for the completion of Year 2000 tasks, we expect to secure Year 2000 readiness of our mission-critical systems by the end of the third quarter of 1999. However, as our current schedule is partially dependent on the efforts of third parties, their delays and other factors we are not able to predict, may cause our schedule to change. Although we expect our efforts and those of our external parties to be successful, given the complex interaction of today's computing and communications systems, we cannot be certain we will be completely successful. Accordingly, we have considered the most reasonably likely worst case Year 2000 scenarios that could affect us or the Utility, and we believe that they mainly involve public overreaction before and during the New Year period that could create localized telephone problems due to congestion,
temporary gasoline shortages, and curtailment of natural gas usage by customers. In addition, it is reasonably likely that there will be minor technical failures such as localized telephone outages and small isolated malfunctions in our computer systems that will be immediately repaired. None of these reasonably likely scenarios are expected to have a material adverse impact on the Utility's or our financial position, results of operations, or cash flows. Nevertheless, if we, or third parties with which we have significant business relationships, fail to achieve and sustain Year 2000 readiness of mission-critical systems, there could be a material adverse impact on the Utility and our financial position, results of operations, and cash flows. Price Risk Management Activities: PG&E Corporation's daily value-at-risk for commodity price sensitive derivative instruments as of June 30, 1999, is $4.8 million for trading activities and $0.7 million for non-trading activities. In November 1998, the Emerging Issues Task Force of the Financial Accounting Standards Board released Issue 98-10, Accounting for Energy Trading and Risk Management Activities. This Issue states that all energy- related contracts entered into with the objective of generating profits on or from exposure to shifts or changes in market prices be marked to market with the gains and losses reflected in the income statement. The Task Force stipulates implementation for fiscal years beginning after December 15, 1998. PG&E Corporation adopted this standard on January 1, 1999. The effect of adoption on earnings and the financial position of PG&E Corporation was immaterial. On July 8, 1999, the CPUC authorized the Utility to recover the costs of participating in the California Power Exchange block forward market. Legal Matters: In the normal course of business, both the Utility and PG&E Corporation are named as parties in a number of claims and lawsuits. (See Note 6 of Notes to Consolidated Financial Statements for further discussion of significant pending legal matters.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK PG&E Corporation's and Pacific Gas and Electric Company's primary market risk results from changes in energy prices and interest rates. We engage in price risk management activities for both non-hedging and hedging purposes. Additionally, we may engage in hedging activities using futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. (See Risk Management Activities, above.)
PART II. OTHER INFORMATION Item 5. Other Information ----------------- A. Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends Pacific Gas and Electric Company's earnings to fixed charges ratio for the six months ended June 30, 1999 was 2.84. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 1999 was 2.70. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707 and 33-61959, relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: Exhibit 11 Computation of Earnings Per Common Share Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company Exhibit 27.1 Financial Data Schedule for the six months ended June 30, 1999 for PG&E Corporation Exhibit 27.2 Financial Data Schedule for the six months ended June 30, 1999 for Pacific Gas and Electric Company (b) The following Current Reports on Form 8-K were filed during the second quarter of 1999 and through the date hereof (1): 1. March 24, 1999 Item 5. Other Events Proposed decision in Pacific Gas and Electric Company's Cost of Capital Proceeding 2. April 15, 1999 Item 5. Other Events Announcement of postponement of scheduled release of first quarter earnings. 3. June 10, 1999 Item 5. Other Events Final decision in Pacific Gas and Electric Company's Cost of Capital Proceeding
4. June 11, 1999 - Form 8-K/A to Form 8-K dated February 17, 1999 Item 4. Changes in Registrant's Certifying Accountants. Item 7. Financial Statements, Pro Forma Financial Information, and Exhibits (1) Unless otherwise noted, all Current Reports on Form 8-K were filed under both Commission File Number 1-12609 (PG&E Corporation) and Commission File Number 1-2348(Pacific Gas and Electric Company)
SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized. PG&E CORPORATION and PACIFIC GAS AND ELECTRIC COMPANY CHRISTOPHER P. JOHNS August 4, 1999 By ________________________ CHRISTOPHER P. JOHNS Vice President and Controller (PG&E Corporation) Vice President and Controller (Pacific Gas and Electric Company)
Exhibit Index Exhibit No. Description of Exhibit 11 Computation of Earnings Per Common Share 12.1 Computation of Ratio of Earnings to Fixed Charges for Pacific Gas and Electric Company 12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company 27.1 Financial Data Schedule for the six months ended June 30, 1999 for PG&E Corporation 27.2 Financial Data Schedule for the six months ended June 30, 1999 for Pacific Gas and Electric Company