II. Further Utility Financial Relief

In this section, we consider whether either or both utilities require additional rate relief to (1) meet immediate cash flow needs; and (2) meet the going-forward costs of procuring power for their customers. We have the authority to grant the utilities a rate increase whether or not the rate freeze is over. We recognize the Emergency Procurement Surcharge (EPS) granted in D.01-01-018 is now permanent under AB1X. We do not consider here the method by which the utilities will meet the substantial debt they have incurred in purchasing power in the past, recognizing that this is the subject of current negotiations with the governor and legislature, and future Commission proceedings.

A. The Utilities' Rate Proposal

1. PG&E's Request

PG&E claims it needs to increase in retail rates by an additional two-cents per kWh beyond that already granted in D.01-01-018. In its proposed "Rate Stabilization Plan" filed November 22, 2000, PG&E proposed a trigger mechanism to raise rates by one cent per kWh each time undercollected power costs exceeded a certain level. Because of the high wholesale prices that have been experienced since the November 2000 filing, PG&E's proposed trigger would have been activated twice since then, resulting in a two cent per kWh rate increase. On this basis, PG&E sets its requested increase at two-cents per kWh.

PG&E claims that the one-cent rate interim increase granted in D. 01-01-018 has not improved its financial circumstances, that it is unable to access credit to keep current with its maturing debts, and that its bonds are now rated at junk-bond status. PG&E has begun defaulting on wholesale power payments, and cannot pay additional power bills that are coming due. PG&E is also experiencing problems securing natural gas for its gas customers, and problems with trade creditors in the normal course of business.

PG&E's proposed two-cent increase is intended to cover (1) its shortfalls since the first of this year when CDWR began to procure power on behalf of PG&E and (2) existing cash flow needs.³

2. Edison's Request

Edison originally sought a 30% rate increase in this proceeding. After the Commission granted one-cent/kWh increase in D.01-01-018, Edison's remaining request here is for a 20% rate increase, or an additional two-cents/kWh. Edison claims that failure to grant the remaining 20% increase will prevent the utility from meeting its past and present financial obligations.

In its rebuttal testimony, Edison changes its request and states that if CDWR is purchasing its full net short position, it does not need any rate relief on a going forward basis.⁴ However, Edison does not believe that CDWR interprets its obligation to require procurement of the entire net short position. If CDWR does not assume full responsibility for Edison's net short position, then Edison claims the 20% increase is still required.

B. Independent Report Findings

In order to provide for an independent verification of the utilities' claims concerning the extent and urgency of the financial problems facing them, we authorized independent consultants to be retained by the Commission in D.00-12-067. The consultants were to conduct an independent review to assess the utilities' claims of financial distress and their credit and liquidity position. The scope of the consultants' review included review of the flow of funds among the utilities, the holding companies, and their affiliates.

The firm of KPMG LLP (KPMG) conducted the review of Edison and the firm of Barrington-Wellesley Group, Inc. (BWG) conducted the review of PG&E. These consultants have concluded their reviews and issued reports to the Commission on their findings on January 29 and January 30, 2001, respectively. Each of the reports was entered into evidence, and panels of sponsoring consultants testified and were subject to cross-examination.

Each of the two reports covered essentially the same following general areas of concern relating to each of the utilities:

Credit and Default Relationships

Power Purchases and Cash Flows

Cash Conservation Activities

Accounting Mechanisms to Track Stranded Cost Recovery

Inter-Company Cash Flows

Affiliate Earnings in the California Energy Market

Federal Income Tax Refunds

The reports essentially confirm that the cash flow problems asserted by the utilities do pose a serious threat that could lead to bankruptcy proceedings. We review the key findings of the consultant reports below.

1. PG&E Report Findings

The BWG report concludes that PG&E has made accurate representations of its borrowing capability, credit condition and potential events of default. BWG concludes that PG&E cannot obtain the credit it needs. BWG confirms that PG&E and its parent, PG&E Corp. have lost access to the commercial paper markets and are using their bank lines of credit to pay maturing commercial paper as it comes due.

PG&E's debt principal and interest payments due in 2001 total $3.2 billion. BWG reports that PG&E has exhausted its borrowing capability under existing lines of credit and is one the verge of default under the provisions of many of its loan agreements. Under its short-term credit agreements, PG&E is required to make payments when due and will be in default if accounts payable arising in the ordinary course of business of $100 million or more become overdue. PG&E Corp.'s loan agreements contain default provisions that are similar to those of PG&E regarding the payment of debts when due.

Credit ratings downgrades in January 2001 by Standard & Poor's and Moody's below minimum investment grade ratings for PG&E and PG&E Corp constitute an event of default under the PG&E Corp. bank lines of credit agreements and under one of PG&E's bank line of credit agreements. Beginning January 16, 2001, the banks have refused to allow draw-downs under the PG&E and PG&E Corp. credit agreements, and the companies are not paying maturing commercial paper obligations as they become due.

BWG also found, however, that PG&E would likely have positive cash reserves through at least March, 2001, and through April or May if CDWR assumes the obligation to procure PG&E's wholesale power other than existing QF and bilateral contracts. BWG projected PG&E's daily cash balances for the period through March 30, 2001 using a range of market clearing prices. By a March 15, 2001 Assigned Commissioner's Ruling, we reopened the record to consider updating the financial balances of PG&E. The update indicates that PG&E's cash balance increased significantly from $827 million on January 31, 2001 to$2.508 billion as of March 8, 2001.⁵ During the same period, its outstanding obligations due and in default increased from $1.542 billion on January 31, 2001 to $3.324 billion on March 8, 2001. Thus, the growth rate in cash on hand exceeded the growth in debts due and in default between the end of January and early March 2001. We view this update as an improvement from the cash position evaluated by BWG in its January 30^th report. The updated financial information does not cause us to change the conclusions we reach in this section.

2. Edison Report Findings

The KPMG report finds that Edison has exercised all available lines of credit and has been unable to extend or renew credit as obligations become due. Edison's share of secured and unsecured debt that is due in 2001 is $242 million. Edison's loan agreements provide for specific clauses with respect to default whereby the underlying debt becomes immediately due and payable. Credit rating agencies downgraded Edison's credit ratings on most of its rated indebtedness to below investment grade during January 2001. The market has ceased to purchase Edison's commercial paper even on an overnight basis.

Since the KPMG Report was released, several creditors have formed a credit committee in anticipation of forcing Edison into involuntary bankruptcy. To help alleviate liquidity concerns, Edison suspended payment of certain obligations, including payments for electric power, and has not declared dividends on its preferred stock that normally would have been paid in February and March 2001.

KPMG developed a summary cash flow forecasting model that reflected a range of assumptions regarding power cost per MWh and payment timing to cover the utility's net short position and QF power contracts. KPMG reports that under the assumptions tested, Edison would improve its cash flow position and retain cash at least through March 31, 2001. KPMG did not include the impact of the one-cent per kWh rate increase granted in D.01-01-018 in its cash flow assumptions.

As noted previously, the March 15^th Assigned Commissioner's Ruling reopened the record to consider admitting late-filed updates as to the utilities financial information. The updates indicate that Edison's cash balance improved slightly from $1.5 billion at the end of January 2001 to $1.6 billion by early March 2001. The balance of debts due and in default increased from $1.24 billion to $1.77 billion over the same period. Thus, while debts grew somewhat faster than cash for Edison, the overall ratio between cash and debt has remained relatively stable during that time interval. The updated financial information does not change the conclusions we reach in this section.

3. Parties' Positions

PG&E states that BWG's assessment of its cash paying ability is incomplete and misleading, even assuming CDWR were to assume responsibility for purchasing all of PG&E's net short position. BWG's assessment assumes PG&E does not pay outstanding energy procurement liabilities which exceed $3 billion, does not pay off $872 million of commercial paper that has matured or will mature by March 31, 2001, and does not pay off $938 million borrowed from its bank lines of credit. PG&E claims that failure to factor in these payment obligations ignores the risk that PG&E could be forced into bankruptcy by its unpaid creditors.

PG&E states its requested two cent/kWh increase will allow it to begin to cover additional power cost shortfalls it has accrued since the first of the year, as well as shortfalls it anticipates until CDWR begins purchasing PG&E's full net short position.

In addition, PG&E states that its rate increase request is appropriate because it will provide assurances to lenders and creditors, improve the price signal being received by electricity customers, and there is no legal impediment if the rate freeze is over.

Edison states that the KPMG report confirms its serious financial distress. It states that the EPS authorized in D.01-01-018 is far less than what it requires if it continues to have any procurement responsibility. Edison states that its request for an additional 20% increase is not necessary if it is not responsible for its net short since January 17, 2001, the effective date of AB1X. As long as there is any uncertainty associated with its continued financial obligation for ongoing procurement costs, including associated ancillary services, unaccounted for energy, ISO fees, and ISO purchases in the real time markets, then all aspects of its request are absolutely needed.

Evidence was introduced and briefs filed by a number of other parties representing consumer advocate, customer groups, and Enron arguing that no additional rate increase is warranted at this time.⁶ These parties generally argue that the utilities have not justified the need to burden customers with further increases given the various sources of funds and other remedies available to the utilities.

C. Discussion

1. Framework and Criteria for Evaluating Need for Further Relief

Our inquiry regarding further rate relief in this phase of the proceeding is focused only on going-forward utility operations. We do not consider in this order what rate relief, if any, may be warranted to recover the utilities' past undercollections. Consistent with D.99-10-007, we do not address comprehensive longer term remedies that may be warranted to restore the utilities' overall financial integrity.

In considering the need for interim relief herein, we first make findings on the status of the utilities financial condition with respect to cash liquidity, credit capacity, and solvency. The need for rate increases is assessed in relation to the potential for the utilities to continue to meet their obligation to serve by utilizing all cash and credit resources available from all other feasible sources and measures before raising customers' retail rates. Thus, one major criterion of the need for emergency rate relief in this phase of the proceeding is whether the utilities can meet essential day-to-day cash flow requirements. Precisely because the financial problems facing the utilities are extraordinary and unprecedented, it is particularly important to consider creative solutions to the financial problems rather than simply to look to ratepayers as a convenient target for shouldering the full brunt of power bill increases that are issue here. The burden of proof remains with the utilities to justify the need for another substantial rate increase.

The utilities' financial problems involve two interrelated aspects. The most immediate problem involves a liquidity crisis, that is, the risk that insufficient cash is available for the utility to pay bills as they become due. The second financial problem involves the risk of insolvency (i.e., negative net worth). Insolvency occurs when the sum of a firm's debts exceeds the fair value of the firm's property. (U.S. Code, Title 11, Chapter 1, Section 101(32)(A).) The severity of these financial problems has led to concern over whether one or both of the utilities may enter into bankruptcy either voluntarily or involuntarily, which may then lead to resulting adverse impacts on the utilities' ability to offer reliable customer service at reasonable rates.

Against this backdrop, we now consider the requests of the utilities to raise rates.

4. The Rate Freeze Compact

Under the rate freeze provisions of Section 368(a) rates were frozen at a level intended to create "headroom" or margin from which stranded costs could be recovered on an accelerated basis. The opportunity for the utilities to recover stranded uneconomic investments also entailed some risk that costs incurred by the utilities might rise above the rate freeze level.⁷

Just because actual costs have now turned out to be significantly higher than anticipated in 1996, the utilities should still be held accountable for the risks that they agreed to take. The original quid pro quo underlying the rate freeze must not be ignored.

We agree with Aglet that price deregulation in California has failed to deliver its promises of lower rates and reduced regulation. Since April 1998, ratepayers have paid billions of dollars in excess of market costs to support recovery of utility transition costs. Ratepayers did not cause the utility liquidity problems, have not benefited from electric industry restructuring, and should not bear the cost recovery risks imposed by AB 1890.

In D.01-01-018, we granted a rate increase while the rate freeze was on because we needed to address an unprecedented financial crisis and the risks of bankruptcy. That emergency increase was only intended to permit the utilities to continue to operate, however, until more intensive scrutiny could be applied to their requested rate increases. We retain the emergency authority to grant a further rate increase here if it is justified.

Whether the rate freeze remains in effect or not, this Commission still has a statutory obligation to ensure that the utilities continue to provide reliable service at just and reasonable rates. No regulated utility may adjust any rates except upon a showing and a determination by this Commission that such rate increases are justified, pursuant to § 454. In this decision, as we scrutinize more closely the basis for further rate increases beyond those granted in D.00-01-018, we remain mindful of the standard set forth in § 451 which provides:

All charges demanded or received by any public utility, or by any two or more public utilities, for any product or commodity furnished or to be furnished or any service rendered or to be rendered shall be just and reasonable. Every unjust or unreasonable charge demanded or received for such product or commodity or service is unlawful. Every public utility shall furnish and maintain such adequate, efficient, just, and reasonable service, instrumentalities, equipment, and facilities, including telephone facilities, as defined in Section 54.1 of the Civil Code, as are necessary to promote the safety, health, comfort, and convenience of its patrons, employees, and the public. All rules made by public utility affecting or pertaining to its charges or service to the public shall be just and reasonable.

5. Effects of Rate Proposal on Bankruptcy

One of the considerations underlying whether to grant further rate relief in this decision is the prospect for avoiding bankruptcy. Although the utilities have defaulted on certain debt obligations, that does not necessarily mean that bankruptcy is inevitable. Creditors' interests are not necessarily served by forcing the utilities into a bankruptcy court where creditors may realize only partial or zero recovery of certain defaulted debt obligations. At least up until the present time, creditors have been willing show patience in waiting the utilities to work out alternative remedies for outstanding debts to be paid without resorting to bankruptcy proceedings.

Moreover, parties disagree as to whether ratepayers would in fact be any worse off by letting the utilities go into bankruptcy if it cannot otherwise be avoided without further rate increases.

CIU argues there will be a substantial impact on customers and the California economy if we grant the requested rate relief. Assuming an equal cents per kWh allocation of PG&E's increase, as proposed, the cumulative rate increase (including the one-cent-per-kWh approved in D.01-01-018) would be 27% for residential customers, 45% for large firm users, and 75% for large non-firm customers. (California Industrial Users Brief; pp. 9-10.) PG&E has not presented any analysis of the adverse effects on the California economy that would result from such burdensome rate increases.

Finally, PG&E's witness Campbell testified that even with the two cent/kWh rate increase, he couldn't say if PG&E would be able to avoid bankruptcy, and that the two cents may accomplish nothing.⁸

Based upon our review of the evidence in this phase of the proceeding, we find that the utilities are indeed facing unprecedented financial problems. The BWG and KPMG report findings, specifically those regarding the utilities' cash flow difficulties and inability to obtain additional credit, generally confirm that the financial problems facing the utilities are serious in nature. Although the utilities take issue with certain statements made in the reports, they essentially agree with the overall findings of the reports. We conclude that the reports provide reliable independent assessments of the financial state of the utilities. These reports make factual findings concerning the status of the utilities' financial condition covering the period under examination, but present no recommendations as to the utilities' need for further retail rate increases going forward. (RT 1049; Heaton/BWG/Energy Division Panel)

While acknowledging that serious financial problems exist, we note that both reports find that each of the utilities will continue to have positive cash balances at least through the end of March 2001. Moreover, the one-cent per kWh increase granted in D.01-01-018 that has since been extended indefinitely will provide a further source of cash flow relief that was not factored into the consultant's cash flow assessments.

As we discuss below, parties have also identified other sources of positive cash flow that are available and that were not taken into account by the utilities in explaining the basis for their requested increase.

6. AB1X

AB1X may provide the utilities a significant source of cash flow relief going forward. This legislation authorizes, but does not require, CDWR to purchase electric power and to sell power to retail end-user customers and to local publicly-owned electric utilities, with specific exceptions. AB1X adds Section 80002 to the Water Code. This section provides that nothing in this new law shall be construed to reduce or modify any electrical corporation's obligation to serve.

Section 360.5, also added by AB1X, requires the Commission to calculate a California Procurement Adjustment (CPA), which then becomes a portion of the utility retail rate. The statute defines the CPA as "the difference between the generation related component of the retail rate [on January 5, 2001] and the sum of the costs of the utility's own generation, qualifying facility contracts, existing bilateral contracts and ancillary services." The determination of the CPA will be addressed in separate order, and that issue is not before us here. The assigned ALJ for that phase of the proceeding has already adopted an expedited schedule to determine the CPA revenue requirement and rates necessary to recover it on an interim basis pursuant to Water Code Section 80114. Once an interim CPA revenue requirement is established, we will also establish an interim allocation as required by Section 360.5.

PG&E expresses uncertainty as to whether CDWR will bear full responsibility for utility power procurement other than existing QF and bilateral contracts. Although PG&E had originally assumed that CDWR would purchase whatever daily power was needed after the passage of AB1X in accordance with legal requirements, PG&E claims that CDWR appears not to agree.

Edison expresses a similar concern that CDWR apparently believes it is not responsible for the entire net short position even though Edison contends that such was the premise underlying the passage of AB1X. Edison states that if CDWR would acknowledge responsibility for procuring all net short needs and all costs related to those needs, Edison would not require immediate rate relief beyond a continuation of the EPS. Absent this assumption, Edison claims that it still needs the two-cents per kWh increase. Edison fails to provide any cash flow analysis, however, regarding what portion of the two-cents per kWh it would need assuming some portion of the its net short position was procured by CDWR.

We recognize that the language in AB1X is permissive. CDWR is not required to cover the utilities' net short position. At the present time, CDWR is still making purchases that cover a substantial portion of each utility's net short position. In any event, even though each utility may still have to cover a share of procurement costs on a going forward basis, our record indicates their total procurement costs may be less than their total utility generation rate component. (RT 2067; Florio/TURN).

Under cross examination by ORA, PG&E's witness claimed that a two-cent-per-kWh increase is still required even if CDWR covers PG&E's entire net short position, including ancillary services. Yet under further examination by ALJ Walwyn, PG&E's witness conceded that its two-cent increase fails to account for any offsetting relief from CDWR covering at least some portion of PG&E's prospective wholesale power payments. (Tr. 1583:2-7). Therefore, before a utility rate increase to cover a shortfall in power costs could be properly be justified, the CDWR revenue requirement first needs to be determined regarding the portion of purchased power costs it will procure under AB1X. Without providing a cash flow analysis factoring in any expected financial relief to be provided by CDWR, PG&E has failed to lay a proper foundation to support its claimed need for the two-cents per kWh rate increase.

7. Financial Assistance from Parent Companies

We observed in D.01-01-018 that the utilities' holding companies could provide an additional source of potential funding for cash shortfalls. We recognize that the cash resources available from the holding companies may be insufficient to fully address the utilities' cash flow problems. Nonetheless, we believe that further investigation is warranted to explore the extent to which holding company cash resources can and should be used to provide a source of capital to help alleviate the utilities cash flow problems.

Both PG&E and Edison oppose any requirement upon their holding companies to provide funding assistance to the utilities in meeting their cash flow needs. Yet PG&E's financial witness testified that PG&E's holding company management does not believe there is anything that legally precludes it from infusing money into the utility to pay for utility operating costs. (RT 1537-38; PG&E/Campbell).

In D.99-04-068, we prescribed that:

"Ordering Paragraph 17 of D.96-11-017 is modified to read as follows: 'The capital requirements of PG&E, as determined to be necessary and prudent to meet the obligation to serve or to operate the utility in a prudent and efficient manner, shall be given first priority by PG&E Corporation's Board of Directors.' (Ordering Paragraph 8)

In view of this directive, we conclude that further scrutiny is warranted concerning whether PG&E Corporation has properly complied with its obligation to give first priority to the utility.

The sheer magnitude of the funds transferred from each utility to its holding company since transition period beginning in 1996, coupled with the meager level of funds flowing back in the other direction raises serious questions as to what further responsibility the holding companies should have in assisting the utilities. As revealed in cross-examination of PG&E witness Campbell in the previous phase of this proceeding, disbursements from PG&E to the parent company, PG&E Corp., during the transition period were approximately $9.6 billion. Out of this total, PG&E Corp. issued dividends (both common and preferred stock) of approximately $1.5 billion. PG&E also repurchased stock in the amount of approximately $2.8 billion and retired approximately $2.8 billion of debt. PG&E recognized that market problems were beginning to occur in June of 2000, but still decided to declare a third-quarter dividend. PG&E did not consider establishing a contingency fund or retaining cash to cushion its risk, because it believed that "its generally conservative financial profile and financing practices would adequately provide cushion against . . . a reasonable range of contingencies." (TR: 409.) Now that events have extended beyond the "reasonable range of contingencies," PG&E has turned to the ratepayers for relief.

Edison's parent company is Edison International (EIX), and Edison's other affiliated companies include Edison Mission Energy, Edison Mission Marketing and Trading, and Edison Capital. EIX is dependent upon dividends from its subsidiaries and from financings for its cash flow needs. Out of an approximate $5 billion in dividends and transfers received from its subsidiaries over the four-year-and-eleven-month period ended November 30, 2000, approximately $4.75 billion was attributable to Edison.

For the same period, EIX paid dividends to its common shareholders of $1.9 billion and repurchased common shares for $2.7 billion. Also, EIX made capital contributions to the Mission Group in the amount of $2.5 billion (of which $2.3 billion was made in 1999). These outflows and the cash used by the holding company operations totaled $7.1 billion. During 1999, EIX issued $1.9 billion in long term and short-term debt to support such contributions.

In January 2000, EIX, in a manner similar to PGC, took ring-fencing action that separates the Mission Group affiliates from Edison.

The Commission has placed notice on its public agenda of a proposal to open a new investigation to consider whether the utilities and their corporate parents are complying with the Commission's rules regarding utility holding companies. Our record shows that the holding companies and affiliates of each utility could serve as a source of additional funds for PG&E and Edison. We should not increase rates for retail customers until we have examined the holding companies' obligations to provide financial support to the utilities.

8. Proceeds from Income Tax Refunds

The BWG report discusses the large tax refund that is attributable to PG&E's 2000 losses. PG&E Witness Campbell testified that PG&E Corporation may receive a substantial income tax refund during the first half of 2001, and that most-if not all-of this refund will be returned to PG&E which originated the net operating losses. Counsel for PG&E later confirmed all of the refund due PG&E on a stand-alone basis would be flowed back to PG&E from its parent and that portions of the refund had already been received.

Similarly, income tax refunds are due to be received by Edison. Edison's counsel stated EIX would not be filing its taxes until September, 2001 and that the $420 million refund portion due Edison on a stand-alone basis would be flowed through to Edison.

9. Restructuring of QF Contracts

Another potential means of stretching existing cash resources is through the restructuring of QF power contracts. During cross examination, PG&E's witness conceded that if current negotiations to restructured QF contracts are successful, PG&E could cover the QF payments and still have some surplus available to satisfy its obligations to the CDWR under the existing one-cent increase already granted in January 2001 (Tr. 1584:16-18). Therefore, we find that utilities has failed to justify a proposed two-cent increase in view of the failure to take into account the potential for QF contract payment restructuring.

10. Setting prices for Diablo Canyon and SONGS at Cost-Based Levels

Both TURN and ORA testify that the Incremental Cost Incentive Proposal (ICIP) pricing mechanism for PG&E's Diablo Canyon nuclear plant and Edison's portion of the San Onofre Nuclear Generating Station (SONGS) provides prices far above cost levels to the utilities. If the utilities were to price these units under cost of service ratemaking, there would be more room in the generation component of rates to fund purchases of electricity. This is an issue we should explore further in AB1X implementation.

11. Management Decisions Affecting Cash Flow

As an additional factor in considering the justification for a rate increase, various parties raise the issue of utility management responsibility, and whether utility management could have reasonably taken actions sooner to conserve cash resources in anticipation of subsequent need for such resources.

ORA, for example, attempted to investigate the prudence of PG&E's utility decision-making in the context of the mounting utility debt in the TRA under-collection. (Koundinya, ORA, Tr. Vol. 16, p. 2181-82). Because PG&E has not yet responded to ORA discovery requests, ORA recommends that a more thorough investigation into the prudence of utility financial policies and bidding practices be conducted in another phase of this proceeding, (Ex. 81, pp. 3-9).

ORA disputes PG&E's claim that prices were expected to 'come down' after the summer of 2000 and recommends further investigation. ORA also disputes PG&E's claim that the pattern of wholesale prices during the summer of 2000 was 'typical.' The abnormalities in the pattern of wholesale prices in terms of high off-peak prices have been documented in the reports issued by the President of the Public Utilities Commission.⁹ ORA proposes that the Commission investigate if PG&E made prudent use of the block forward market and other hedging instruments to obtain price stability in energy markets.¹⁰

BWG, the independent consultants retained to conduct a financial review of PG&E, opined that "with the information that was available, it would not have been inappropriate to start cash conservation earlier than they did." (Joyner, BWG, Tr. Vol. 8 p. 1051). The BWG Report points out several 'early' indicators of market dysfunction from 1998 to 2000.¹¹ BWG further points out losses incurred by PG&E due to imprudent bidding strategies.¹²

Cash transfers of $4.632 billion were made from the utility to PG&E Corp. over the rate freeze period.¹³ ORA questions the prudence of this transfer in the context of PG&E's overall financial policy. PG&E's financial witness, Mr. Campbell, stated that PG&E's financial performance over the past five years could not be interpreted "as being anything closely approaching that of the average utility in the United States."¹⁴ ORA argues that the Commission should not compensate PG&E for past unsystematic, diversifiable and firm-specific business risks. ORA believes that PG&E's interpretation of its risks, past financial performance and the prudence of its financial policies call for a more detailed showing.

CIU likewise argues that PG&E's management were aware of skyrocketing power prices, but did nothing for a very long time. Although PG&E was aware of wholesale market dysfunction signs as early as summer 1998 (BWG Report; Ex. 28, p. III-1), and expressed concerns about soaring electric prices in summer 2000 (Exh. 37, McManus, pp. 1-3 - 1-4), PG&E continued to count on others to rescue it, according to CIU. PG&E's witness Campbell testified that PG&E was looking to "indications from the Governor, legislators, the FERC, and this Commission that steps would be taken to mitigate high market prices and to maintain the utility's financial strength." (Exh. 39, Campbell, pp. 3-8, lines 24-27). PG&E waited until November 2000, after five months of high market prices, to address the issue of cash conservation¹⁵

CIU also raises questions concerning the management of Edison. While CIU acknowledges that Edison instituted a more aggressive cash conservation plan than did PG&E, Edison still did not initiate its own cash conservation activities until November 2000. CIU argues that Edison should therefore bear the consequences of its slowness to react. (Exh. 34, pp. I-3,V-1). Edison defends its actions stating that "dividends were paid consistent with Edison's long-standing policy and the repurchase of stock was directly related to Edison's compliance with the Commission's requirements to sale [sic] gas-fired generation." (Exh. 58, Kelly, p. 14, lines 15-17). CIU discounts Edison's statement, however, merely as further evidence of Edison's "business-as-usual" attitude even as the financial crisis mounted. CIU also points out that the Commission never required the utility to divest 100% of all gas fired generating plant, but that all divestiture of fossil generation over 50% was entirely voluntary with the utilities, including Edison.

CIU argues that because PG&E and Edison did not take substantial proactive steps sooner to try to conserve cash, they should not now seek to be rescued by ratepayers from the consequences of their own discretionary actions.

GSPC likewise argues that it would be unjust and unreasonable in the extreme to grant a ratepayer bailout of the utilities when the evidence shows that corporate profits were paid out as dividends or otherwise spent without any cash reserve strategy to face the risk of escalating utility procurement costs. GSPC observes, however, that since the money has already been spent, the Commission is left to cope with "after-the-fact" remedies. As one such remedy, GSPC proposes that the Commission whether the current corporate structure should be changed to protect future utility operations from having their cash resources drained from them, or whether further conditions should be imposed if the existing corporate structure is to be maintained.

PG&E defends its management actions with respect to cash conservation measures as a reasonable response to the financial crisis facing it. PG&E witness Yura argues that the purpose of cash conservation measures was not to enable PG&E to cover the high cost of wholesale power, and that such action would have been impossible without a significant increase in revenues. ¹⁶ PG&E also objects to ORA's proposal for a reasonableness review of its management actions, arguing that procurement practices before the end of the AB 1890 rate freeze are per se reasonable.

We reach no final conclusions in this order as to what actions the utilities should have taken earlier in the process to address their looming cash and credit problems more proactively, or what differences earlier management actions could have made in the amount of cash or credit available. We observe, however, that to the extent that the utilities could have taken proactive measures sooner to conserve cash to deal with their financial problems, there would have been less need to come before the Commission now asking for ratepayers to bear the significant rate burdens that are being requested. We leave open the option of considering in a further phase of this proceeding what measures should have been pursued earlier by the utilities in addressing their cash flow problems in a more proactive manner prior to assuming that ratepayers would bear the burden for such financial problems. As we have previously noted, we are also opening a separate investigation docket to address utility compliance with holding company rules and orders of the Commission. We may consider the need to adopt reform of utility holding company rules based upon the outcome of our further study and investigation.

We take official notice of the two news articles attached to the CIU Phase 1 Brief, reporting that PG&E Corp., the parent company of PG&E, the electric utility, has closed a $1 billion loan agreement to restructure the holding company's debt and to pay obligations on which it has defaulted. ¹⁷ None of the proceeds from the $1 billion loan will be used to support the electric utility's cash needs, but will instead go toward paying fourth quarter dividends to PG&E Corp. common shareholders and paying off other debt obligations of the holding company. PG&E Corp. has defended the loan agreement as making the holding company financially stronger and better positioned to focus its energies on the electric utility's problems. Yet, we view PG&E Corp.'s action as yet more evidence indicating the holding company's priorities are not properly focused on supporting the cash needs of the electric utility. The timing of the refinancing agreement is particularly questionable, coming only one day after PG&E, the utility, defaulted on $1.21 billion in debts to its wholesale suppliers. PG&E Corp.'s $1 billion debt restructuring therefore raises further questions as to how much support the holding company should be providing to the utility before simply assuming that ratepayers will provide a shareholder bailout.

12. Overfunded Pension Assets

The Commission will not jeopardize the availability of pension funds necessary to cover the utility's employees. However, our record indicates the utilities may be able to realize significant savings from exploring further TURN's recommendations in this area

13. Remedial Actions by Governor's Office and State Legislature

As noted by CLECA, Governor Davis' administration and the Legislature are currently engaged with all three of the major electric utilities in discussions regarding remedies to deal with their financial problems. As of this date, the actual terms of any remedies put into place by Sacramento lawmakers remain unknown. Any agreement that may be reached between the utilities and the governor's administration or the state legislature has the potential to help the utilities to regain sound financial footing. We believe that it would be premature to consider granting further rate increases at this time in advance of any potential solutions that may be devised through legislative or gubernatorial channels.

14. Conclusion

In view of the existing cash resources, the possibility that all procurement costs, including a portion of the net short, are covered within the existing generation rate, and the range of strategies and potential remedies available to the utilities to deal with their cash flow crisis, we find no basis for granting the requested rate increases of PG&E and Edison.

As we stated in D.01-01-018, we remain troubled by the utilities' assumption that ratepayers must bear the burden of significant rate increases without the shareholders sharing in the pain. The utilities and their shareholders have received significant financial benefit from industry restructuring thus far. For example, PG&E and Edison have each received the benefit of over $2 billion in cash proceeds from rate reduction bonds. As reported in the monthly TCBA reports, PG&E has received over $9 billion in headroom and other transition cost revenues and Edison has received over $7 billion in such revenues.

Ratepayers are not the only answer to the utilities' dilemma. Before any further electric retail rate increases are granted, a number of additional sources of funds and alternative remedies need to be more fully considered.

Accordingly, in view of all the considerations laid out above, we decline to grant the request of PG&E and Edison, respectively, for an increase of two-cents per kWh. We treat Edison's position as a request for rate relief because under AB1X the utilities retain their obligation to serve responsibilities, including the obligation to purchase power to serve their customers. We assume in this decision that the utilities may be responsible for a portion of their net short position on a going-forward basis but find the evidence indicates this may be covered by the existing generation portion of their rates. The Commission will establish their generation costs in the implementation phase of AB1X and if there are revenue shortfalls the utilities will then have adequate justification to seek a rate increase.