Word Document

Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Increase Rates and Charges for Electric and Gas Service Effective on January 1, 1999.

                      (U 39 M)

Application 97-12-020

(Filed December 12, 1997)

Investigation into the Reasonableness of Expenses Related to the Out-Of-Service Status of Pacific Gas and Electric Company's El Dorado Hydroelectric Project and the Need to Reduce Electric Rates Related To This Non-Functioning Electric Generating Facility.

Investigation 97-11-026

(Filed November 19, 1997)

Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Decrease its Rates and Charges for Electric and Gas Service, and Increase Rates and Charges for Pipeline Expansion Service.

            (Electric and Gas) (U 39 M)

Application 94-12-005

(Filed December 9, 1994)

Order Instituting Investigation Into Rates, Charges, and Practices of Pacific Gas and Electric Company.

Investigation 95-02-015

(Filed February 22, 1995)


"(e) As to an electrical corporation that is also a gas corporation serving more than four million California customers, so long as any cost recovery plan adopted in accordance with this section satisfies subdivision (a), it shall also provide for annual increases in base revenues, effective January 1, 1997, and January 1, 1998, equal to the inflation rate for the prior year plus two percentage points, as measured by the consumer price index. The increase shall do both of the following:


"(1) Remain in effect pending the next general rate case review, which shall be filed not later than December 31, 1997, for rates that would become effective in January 1999. For purposes of any commission-approved performance-based ratemaking mechanism or general rate case review, the increases in base revenue authorized by this subdivision shall create no presumption that the level of base revenue reflecting those increases constitute the appropriate starting point for subsequent revenues.


"(2) Be used by the utility for the purposes of enhancing its transmission and distribution system safety and reliability, including, but not limited to, vegetation management and emergency response. To the extent the revenues are not expended for system safety and reliability, they shall be credited against subsequent safety and reliability base revenue requirements. Any excess revenues carried over shall not be used to pay any monetary sanctions imposed by the commission." (Emphasis added.)

 

Electric Department

Gas Department

Total

Request

NOI (September 1997)

703

506

1,209

Application (December 1997)

693

501

1,193

March Update (April 1998)

572

460

1,032

Comparison Exhibit (October 1998)

445

377

822


"We note that in the currently ongoing PG&E GRC proceeding for test year 1999 (Application 97-12-020/I.97-11-026), PG&E appears to take the same position on pension funding policy that it did in the case at issue here. The same is true for ORA. Hearings have been completed in the current GRC, the issues are virtually identical, and the [Administrative Law Judge (ALJ)] has all of the arguments presented in that case before him for determination. For reasons of economy and efficiency, we will thus consolidate the rehearing on this issue with the current case." (D.98-12-096, p. 3.)


"All income from the employer was received by or accrued to the public official prior to the time he or she became a public official; the income was received in the normal course of the previous employment; and there was no expectation by the public official at the time he or she assumed office of renewed employment with the former employer." (Fair Political Practices Commission Regulation 18703.3(b).)


A modest gas rate increase (3% to 7%) might be appropriate, but PG&E's proposed 25% rate increase is way out of line, and is not justified by inflation or by natural gas prices.


By proposing a 25% gas rate increase, it appears that PG&E is attempting to offset the effect on the company of the statutory 10% electric rate reduction and subsidize electric operations on the basis of gas rates alone. (This is a particular concern of gas-only customers and customers who say that PG&E encouraged them to convert from electric to gas appliances.)


PG&E's rates are among the highest in the nation, and the company is already earning high or adequate profits.


Customers with fixed or low incomes will be harmed by a large gas rate increase, as will elderly customers who require more heating than other customers.


PG&E should do more to cut costs and become more efficient before asking the Commission for rate increases.


It seems that PG&E is constantly asking for rate increases.


PG&E has failed to spend previously authorized funds that were earmarked for tree trimming, so the Commission should not authorize additional funding for this purpose.


Customers should receive the promised savings from energy industry restructuring and deregulation efforts, not more rate increases.


Shareholders, not customers, should pay for nuclear decommissioning.


As a result of the proposed electric revenue increase and the tracking of the increased amounts in regulatory accounts, a significant electric rate increase may occur after the rate freeze is over.


While no one wants rate increases, they are necessary. Dependable utility services are vital to the state's economy, and the Commission should ensure that PG&E has the funding needed to maintain its utility distribution system for safety and reliability and to provide responsive customer service.


PG&E may have to lay off workers and reduce service quality if the requested rate increases are not granted.


PG&E provides good, affordable utility service.


PG&E is a good corporate citizen which provides important community services.


PG&E has heard loud and clear from the Commission, customers and the Legislature that its level of service in 1995, when PG&E's last rate case was approved, did not meet either the Commission's or customers' expectation, and that PG&E must improve its service and compliance to meet these expectations. (Comments, pp. 6-7, emphasis in original.)


"In a general rate setting proceeding, the commission determines for a test period the utility expense, the utility rate base, and the rate of return to be allowed. Using those figures, the commission determines the revenue requirement, and then fixes the rate for the consumers to produce sufficient income to meet the revenue requirement. . . . [(] The rates are fixed in the general proceedings on the basis of historical data. Adjustments may be made in that proceeding for anticipated future extraordinary changes. [Citation.] It is obvious revenue, expense, and rate base arrived at on historical data will not remain constant in future years when the rates take effect. The assumption underlying fixing of future rates on historical data is that for future years changes in the revenue, expense, and rate base will vary proportionately so that the utility will receive a fair rate of return.' (California Manufacturers Assn. v. Public Utilities Commission (1979) 24 Cal.3d 251, 256-257 [155 Cal. Rptr. 664, 595 P.2d 98].)" (City and County of San Francisco v. Public Utilities Commission (1985) 39 Cal.3d 523, 531 [217 Cal. Rptr. 43, 703 P.2d 381].)"


"Successful regulation of great public utility corporations, with their properties and their services ramifying in every direction, with vast revenues flowing in continuously, with nationwide alliances, and clearing-houses of technical information and expert service, is no simple and easy matter. The utilities stand ready at all times to save the Commission from exerting itself. They stand ready to produce all the facts which they themselves declare to be pertinent and to explain them to the Commission, and to tell the Commission what its duty is. But the more there is of this, the more the Commission needs time, and money, and experience to do its own investigating, and get to the bottom of things. Very few states appropriate enough funds to enable the Commissions to do their work independently. The only way for a Commission to act quickly is to do what the companies tell it to do, and often the consumers as well as the utilities are impatient of delay.


"If the Commission depends upon the consumers or the municipalities to present the public side of the controversy, the evidence in most cases will be heavily one-sided. A group of consumers, or an individual municipality -- perhaps a small one -- or a loosely associated group of municipalities, working from the outside with no funds except what `they dig out of their jeans' with no hope of ever getting it back, are pitted against the companies having all the inside experience and knowledge, and able to tap the consumers' till with confidence that whatever they spend to defeat the consumers will be added to the cost of service and taxed back in the rates which the consumers themselves will have to pay. If the municipalities or the consumers spend a dollar of their own money, the utility will spend two and make them pay in the bargain. Financial resources, experience, inside knowledge, expert affiliations, great things at stake and continuity of interest, combine to give the utilities an overwhelming advantage in the presentation of their cases before Commission and Courts." (Dr. Delos F. Wilcox, Journal of Land and Public Utility Economics, July, 1926; as quoted in California Railroad Commission, pamphlet by Commissioner Ray C. Wakefield, January 15, 1941, pp. 12-13, emphasis added.)


"The inescapable fact is that the ultimate burden of proof of reasonableness, whether it be in the context of test-year estimates, prudence reviews outside a particular test year, or the like, never shifts from the utility which is seeking to pass its costs of operations onto ratepayers on the basis of the reasonableness of those costs.7 Whenever the utility comes before this Commission seeking affirmative rate relief, it fully exposes its operations to our scrutiny and review. It may justify the reasonableness of its request and its operations by making at least a prima facie case of reasonableness, even in the absence of opposition. Where it faces opposition, its reasonableness showing is naturally a more difficult undertaking." (D.87-12-067, 27 CPUC2d 1, 21.)


"The staff sets forth the long-standing and proper rule. It is settled that in order to raise rates it is incumbent on the utility to justify the increase before the Commission. (Northern Cal. Power Company (1912) 1 CRC 315.) The utility seeking an increase in rates has the burden of showing by clear and convincing evidence that it is entitled to such increase. The presumption is that the existing rates are reasonable and lawful. Any doubts must be resolved against the party upon whom rests the burden of proof. (Southern Counties Gas Company (1952) 51 CPUC 533; Citizens Utilities Company (1953) 52 CPUC 637; Park Water Company (1955) 54 CPUC 498.)


"This Commission is charged with the responsibility of ensuring that all charges, demanded or received by any public utility, shall be just and reasonable. (Pub. Util. Code § 451.) No public utility shall raise any rate except upon a showing before the Commission and a finding by the Commission that such increase is justified. (Pub. Util. Code § 454.) (See City of Los Angeles v Public Utilities Commission (1975) 15 Cal 3d 680.)


"To meet the burden of presenting clear and convincing evidence of the need for an increase, the applicant must produce evidence having the greatest probative force. (Railroad Commission v Pacific Gas & Electric Company (1938) 302 US 388.) The credibility of witnesses and the probative value of their testimony are questions for the trier of fact. (Leonard v Watsonville Community Hospital (1956) 47 Cal 2d 509, 518.) It is for the Commission to arrive at its findings from the consideration of conflicting evidence and undisputed evidence from which conflicting inferences may reasonably be drawn. (Southern Pacific Company v Public Utilities Commission (1953) 41 Cal 2d 354, 362, appeal dismissed, 348 US 919, 98 L ed 414.)


"The Commission may form its own conclusions as to the probative value of the evidence before it. (Market Street Railway v Railroad Commission (1945) 324 US 548, 89 L ed 1171.) The Commission may choose its own criteria or method of arriving at its decision, even if irregular, providing unreasonableness is not clearly established. (Pacific Telephone & Telegraph v Public Utilities Commission (1965) 62 Cal 2d 634; American Toll Bridge Company v Railroad Commission (1939) 307 US 486; 83 L ed 1414.) When the utility has not sustained the burden of satisfying the Commission that the proposed increase in rates is justified, the application will be denied (E. L. Anderson (1930) 34 CRC 676.)


"The foregoing are the precepts which we must employ in considering the record before us." (D.90642, 2 CPUC2d 89, 98-99.)


"In summary, it is clear that in light of SB 779, the Commission in this general rate case must be diligent and comprehensive in its examination of the whole record and its weighing of all the evidence. The Commission no longer should expect that its reference to `any evidence' will be sufficient to immunize it from judicial review by a Supreme Court arguably reticent about second-guessing the Commission on complex ratemaking principles and huge administrative records. Instead, the expanded principles of judicial review enacted by SB 779 will put an increased premium on the ability of the Commission to separate the `wheat from the chaff' in complex cases such as this, and then to explain and evaluate, in understandable terms and on paper, how it has arrived at its decision on the major disputed issues in the case." (PG&E Opening Brief, pp. 483-484.)


"How the revenue requirement increase is characterized is irrelevant to the Commission's decision in this case. The Commission must authorize total base revenues for the electric and gas departments, which the record supports." (PG&E Reply Brief, p. 7.)


"Speakers raised concerns about high rates, but most emphasized concerns about service quality generally, PG&E's response to the 1995 rainstorms, and cut-backs in utility employees. Some asserted that PG&E employees exhibit indifference and a lack of knowledge and training. Rural customers expressed concern about what they perceived to be their low priority status on PG&E's system and asked the Commission to consider their unique safety needs. Some speakers perceive a reduced commitment to system maintenance and raised concerns about whether the PG&E billing system could adequately process a late payment charge." (D.95-12-055, 63 CPUC2d 570, 583.)


". . . [W]e expect that this general rate case may be the last for PG&E. We consider PG&E's revenue requirement with that in mind; that is, we intend to scrutinize all expenses carefully and with an eye toward cutting those expenses which are not well-documented or supported by PG&E." (D.95-12-055, 63 CPUC2d 570, 585.)


"It has long been argued that public utilities subject to rate of return type regulation have an incentive to engage in `gold-plating' of their assets, [footnote omitted] and in fact the [Federal Communications Commission] in adopting price cap regulation did so in part to reverse this so-called `A-J effect.' [footnote omitted] Significantly, when a utility is faced with the impending termination of rate of return regulation, it confronts what might best be described as a `super A-J effect,' because it not only has the traditional incentive to overcapitalize, but now has to `beat the clock' to get as much spending done while it still has the ability to recover those costs from captive customers under rate of return regulation." (ORA/Selwyn, Ex. 86, p. 38.)


1823. The commission shall periodically review and monitor the development and use of any operations model used by any public utility. The commission or any party may use the output of these operations models as evidence in a proceeding or hearing, withoutintroducing into evidence the full methodology used to generate this output, if the commission has monitored that operations model continuously for at least 12 months before the hearing or proceeding and has reviewed and verified the operations model for accuracy no more than three months before the hearing or proceeding. However, no party shall be prohibited from reasonably cross-examining any witness who introduces this evidence.


(b) "Operations model" means a computer model that replicates, lists, describes, or forecasts a public utility's internal functions, including, but not limited to, its accounting procedures, cash management procedures, personnel assignments and procedures, and inventory control.


"PG&E notes that by spending significantly more than authorized in 1996 the company's return on equity has been adversely impacted. (PG&E/Randolph, Ex. 2, p. 1-15.) The more pertinent evidence is that in eight of the eleven years from 1985 through 1995 PG&E was earning more than the authorized rate of return. (Exs. 60, 61.) During the same time period PG&E was significantly underspending its authorized electric and gas distribution maintenance budget. The fact that the company has placed the system back in a decent state of repair by spending more than the currently authorized amount is no basis for imposing significantly higher costs on ratepayers on a going forward basis under the guise they are demanding greater reliability. Granting PG&E's request would result in future ratepayers paying for PG&E management's poor decisions." (ORA Opening Brief, p. 21.)


"The purpose of a general rate case is to develop and adopt sound, informed estimates of the reasonable costs to be incurred in the test year. We know that our adopted levels of revenues and expenses may be at variance with actual experience. However, we must be sufficiently informed to know that adopting a given estimate makes sense. Part of this process involves making sure that we do not repeatedly approve revenues to meet a one-time cost. When a utility's expense estimate includes the performance of a task it had planned to accomplish with previously authorized funds, we will want to know why the utility did not spend its funds as planned the first time around and will be hesitant to charge ratepayers twice for the same expense. In addition, we want to be confident that the activities being undertaken by the utility are lawful and otherwise consistent with public policy." (D.92-12-019, 46 CPUC2d 538, 555.)

 

PG&E

($)

Average

($)

PG&E Greater than Average

(%)

Median

($)

PG&E Greater than Median

(%)

Average- Excluding Highest, Lowest

($)

PG&E Greater than rev. Average

(%)

Average Excluding 5 Highest, 5 Lowest

($)

PG&E Greater than rev. Average

(%)

 

(1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

Distribution Plant Per Mile

85,096

76,800

11

60,069

42

69,277

23

64,723

31

Distribution Net Plant Per Mile

50,066

50,398

-1

39,761

26

45,646

10

42,560

18

Distribution O&M Per Mile

3,359

3,054

10

2,262

49

2,616

28

2,480

35

Customer Account Per Customer

49.7

41.4

20

39.0

27

41.1

21

40.6

22

Customer Service Per Customer

23.0

20.6

12

16.8

37

19.5

18

18.5

24


"[i]t is theoretically inappropriate and methodologically indefensible to use the historic performance of vertically integrated electric utilities to evaluate the operating efficiency of a utility in providing transmission, distribution and customer service functions..." (Exhibit 88, p. 5.)

 

PG&E

ORA

Enron

Weil

Operating Account Totals

128,833

122,218

120,762

122,218

Maintenance Account Totals

260,487

166,393

159,627

161,818

Total O&M

389,321

288,611

280,389

284,036


Service reliability investments appeared to have not been optimally allocated or expended. Reactive spending was increasing relative to preventive spending, some maintenance program expenses had declined as overall expenditures have been squeezed, and divisions had historically underspent their budgets.


Assessment of service reliability issues focused attention on the questionable condition of several major asset classes: wood poles, tree trimming, and overhead equipment.


"We adopt PG&E's estimate for tree trimming in the test year with PG&E's assurances that the lower budget for tree trimming reflects cost savings rather than a reduced effort in tree trimming." (D.95-12-055, 63 CPUC2d 570, 604.)


The Performance Incentive Program encouraged employees to spend less than the budgeted amount, increasing the risk of deferring or discontinuing gas and electric preventative maintenance programs.


Preventative maintenance programs were budget driven, not service-reliability driven, which leads to deferring or eliminating programs.


There was a "cut cost at any cost or we will find someone who will" philosophy, which adversely affected upward communication within the company.


Preventative maintenance programs appeared to have been insufficiently funded.


The link between the planning concepts of service reliability and the funding of preventative maintenance programs was not evident in either the planning phase or the resource allocation phase.


Reductions in the budget each year failed to demonstrate an understanding of the potential degradation in service quality which results in underfunding future preventative maintenance programs.


Generally, Divisions were not complying with PG&E preventative maintenance requirements.


Some districts had stopped performing preventative maintenance and were managing maintenance in a 100% reactive mode.


Inspection, maintenance, and repair of both overhead and underground electrical distribution facilities was not being performed consistent with PG&E standards due to a lack of accountability, lack of performance measures, and lack of data regarding the costs of such efforts.


"[W]hen Arthur Andersen reviewed the [vegetation management] program two years later, they found that `a substantial percentage' of the vegetation management efforts continued to be spent on more expensive non-routine trimming, that despite the large budget, tree-related outages continued to be a primary cause of unplanned outages and that about half of those were believed to be avoidable, and that the Division Managers who had the responsibility for system reliability had `little or no' control over this program, which heavily impacted system reliability. The report also noted that some divisions had expressed concern that this program was `not functioning adequately to reduce tree related outages.' One of the implied weaknesses in the newly centralized program was that no one really knew the number of trees that needed to be trimmed each year by location, and thus that resources were not being assigned appropriately." (Exhibit 81, pp. 36-37.)


PG&E's preventative maintenance documents varied significantly in technical depth, ranging from insufficient to overly detailed.


General organization was good, but the documents were scattered among other materials rather than grouped into an overall maintenance document.


A wide variety of forms, lists, and secondarily referenced materials appear to make it difficult to manage and control the information over long periods and complicate detailed analysis.


Significant responsibility for detailed implementation has been delegated to the division level, although only 50% of the divisions appear to have any documented maintenance plans.


"Based on the record in this proceeding, we cannot find that PG&E was unreasonable. This is not to say that PG&E's customer services, maintenance programs, or employee reductions were or are reasonable. Rather, the record does not permit us to reach the conclusion that PG&E failed to fulfill its obligation to provide reasonable levels of service and safety to its customers." (Id., p. 500.)


"[A]ll three reports noted that the preventive maintenance activities were driven by budgets rather than by system needs. Bain and Arthur Andersen noted that divisions had incentives to cut back on preventive maintenance in favor of reactive maintenance practices, and that as a result many had done so. Indeed, Arthur Andersen concluded that some divisions were relying nearly exclusively on reactive maintenance practices. The result of making such a change is that, in the short term, maintenance costs might go down. However, in the long term, overall system costs will go up as early equipment replacement and system failures become more common." (Exhibit 81, pp. 41-42.)


"years of mismanagement in which funds provided by ratepayers for tree trimming activities were diverted to other purposes resulting in an ever more inefficient tree-trimming operation." (ORA Opening Brief, p. 96.)


"The costs associated with this mismanagement cannot be quantified but are clearly embedded in the recorded 1996 figures which PG&E uses as a base year." (Id.)


that PG&E's maintenance practices were deficient when [it] made an opposite assertion on the same issue in a prior proceeding involving the same practices." (Id.)

Party

Operating Accounts

Maintenance Accounts

     

PG&E

1996 Adjusted Recorded*

1996 Adjusted Recorded*

ORA

1996 Adjusted Recorded

4-Year Average (1993-1996)

Enron

3-Year Average (1995-1997)

5-Year Average (1992-1996)

Weil

Supports ORA's Forecast

5-Year Average (1992-1996)

TURN

Supports ORA's Forecast

Supports ORA's Forecast

CFBF

Disallowance**

Disallowance**


"As a general proposition, use of averages and trends is superior to reliance on a single base year, at least for stable utility functions like distribution, because averages and trends incorporate more historical data. The role of distribution has been relatively unchanged by electric restructuring." (Weil Opening Brief, p. 21.)


"If recorded expenses in an account have been relatively stable for three or more years, the 1987 recorded expense is an appropriate base estimate for 1990.


"If recorded expenses in an account have shown a trend in a certain direction over three or more years, the 1987 level is the most recent point in the trend and is an appropriate base estimate for 1990.


"For those accounts which have significant fluctuations in recorded expenses from year to year, or which are influenced by weather or other external forces beyond the control of the utility, an average of recorded expenses over a period of time (typical four years) is a reasonable base expense for the 1990 test year." (D.89-12-057, 34 CPUC2d 199, 231.)


"Absent a specific explanation of why 1987 recorded data best reflects the estimated 1990 expenses of an account with fluctuating expense levels and no discernible trends, we find it most appropriate to use a four-year average as the base 1990 estimate." (Id., 238.)

 

PG&E

PG&E

ORA

ORA

ENRON

Year

Gross

Net

Gross

Net

Net

1997

$ 745

$ 713

$ 442

$ 386

$ 417

1998

$ 843

$ 763

$ 355

$ 229

$ 422

1999

$ 792

$ 709

$ 449

$ 394

$ 430

Total

$2,380

$2,184

$1,245

$1,009

$1,269


"The forecasted capital additions requested for 1997, 1998, and 1999 were based on the 1997 capital budget for the major work categories (MWCs). The development of the 1997 budget began in mid 1996 based on input from field offices and was subsequently reviewed and adjusted by the general office staff. The 1997 overall capital expenditures by MWC were either escalated by 2 percent or adjusted by the general office staff to estimate the capital expenditures for 1998 and 1999. Each MWC capital expenditure was further divided into two categories: the first included projects exceeding one million dollars and the second included projects under one million dollars. This was accomplished by identifying and adding the cost of projects over one million dollars and subtracting it from the overall MWC capital expenditures forecast to obtain the expenditures for projects under one million dollars." (Exhibit 73, p. 11C-3.)

Description of Project/Category

Amount (Millions)

   

All distribution projects justified solely on the basis of emergency criteria where capacity is not needed to serve normal loads until after 1999. Includes disallowances of 1997 spending.

$55

   

Fifteen percent of named projects for 1998 and 1999 in MWC 06 to reflect installation of capacity before it is used and useful, due to forecasting errors at the DPA level.

$85

   

Contingency funds for "other projects" added to MWC 06 and MWC 08 in PG&E's March 1998 update and May 1998 workpapers.

$90

   

Adjustment to MWC 16 (New Business) for consistency with PG&E's sales forecast and to reflect reductions in unit costs included in internal documents but not in the GRC filing.

$56

   

Adjustments to Work Required by Others (MWC 10, $20 million) and Emergency Response (MWC 17, $40 million) for work identified but unlikely to be spent.

$60

   

Adjustment to reduce backlog of meters (MWC 25), reflecting reductions in PG&E's 1998 and 1999 spending by amount by which PG&E increased 1997 spending above projections.

$ 4


"Between the March update and the May update, PG&E canceled $120 million in specific projects. About half of those specific projects were highly questionable projects to spend millions of dollars to add emergency capacity. The first indication that these emergency capacity projects were canceled was when TURN sent a series of data requests regarding the basis for these projects. This fact strongly suggests that PG&E did not want to pursue controversial projects for which the Commission might deny funding.


"However, PG&E still wanted the money without the controversy. So, after identifying a number of new specific projects, PG&E simply transferred the rest of the money into unidentified `other projects.'


* * *


"Unidentified projects were about 20% of the total when the application was filed. They are now nearly 40% of the total. This change makes no sense. PG&E's plans should become more definite, not less definite, as time passes. Yet PG&E has adopted the attitude that the Commission should trust that it will spend the money it requested, spend it fast, and spend it prudently, if not on projects questioned by TURN, then on other supposedly worthy projects, even if it does not happen to know what those projects might be." (Exhibit 369, pp. 49-50.)

 

1997

1998

1999

3-Year

         

PG&E's Requested Additions

$745.0

$843.0

$792.0

$2,380.0

         

Adopted Reductions - TURN

        

Emergency Projects

    

$ 5.0

$ 5.0

MWC 06 - 15% Named Projects

    

$ 13.3

$ 13.3

MWC 06 - Other Projects

    

$ 35.1

$ 35.1

MWC 08 - Other Projects

    

$ 2.1

$ 9.6

         
         

MWC 17 - Outage Response

    

$ 19.7

$ 19.7

ORA Pole Replacement

  

$ 10.2

    

Total Adopted Reductions

    

$ 75.2

$ 75.2

         

Adopted Plant Additions

$745.0

$832.8

$716.8

$2,294.6


The frequency of reorganizations and personnel changes has had an unfavorable effect on organizational effectiveness, including the execution and continuity of gas and electric preventive maintenance programs. The result is a lack of clarity of responsibility and accountability.


Key performance measures are not in place to adequately inform Customer Energy Services management and corporate senior management of gas and electric distribution system condition and effectiveness of preventive maintenance program.


The link between the planning concepts of service reliability and the funding of preventive maintenance programs is not evident in either the planning phase or the resource allocation phase.


Budget sources appear to be discretionary if programs are not mandated by external forces such as the Commission or the California Department of Forestry.


Division preventive maintenance program expenditures are controllable costs allowing preventive maintenance resources to be managed to achieve overall division budget targets.


Preventive maintenance programs are budget-driven, not service reliability-driven, which leads to deferring or eliminating the programs.


Preventive maintenance programs appear to have been insufficiently funded.


Current Performance Incentive Plan targets encourage employees to spend less than their amount of allocated dollars which increases the risk of deferring or discontinuing gas and electric preventive maintenance programs.

Account

Description

Amount

     
 

Operation

  

870

Supervision and Engineering

0

871

Distribution Load Dispatching

603

874

Mains and Services

12,882

875

Measuring and Regulation Stations-General

758

876

Measuring and Regulation Stations-Industrial

454

878

Meter and House Regulator Expenses

2,294

879

Customer Installation Expenses

49,956

880

Other Expenses

19,035

881

Rents

0

 

Total Operation

85,982

     
     
 

Maintenance

  

885

Supervision and Engineering

0

886

Structures and Improvements

1,115

887

Mains

17,055

889

Measuring and Regulation Stations-General

1,815

890

Measuring and Regulation Stations-Industrial

1,325

892

Services

11,036

893

Meters and House Regulators

5,793

894

Other Equipment

5,103

 

Total Maintenance

43,242

     
 

Total O&M

129,224


"Notwithstanding PG&E's underspending of budgeted funds in this program every year since 1985, PG&E has kept the program on target: after 40% of the program's timeline has elapsed, PG&E has completed 39% of the program. Apparently, we have funded this program at levels that are higher than required to fulfill program goals." (Id.)

PG&E's and ORA's Positions on

Total Company A&G Expenses

(1996 Dollars in Thousands)

Account

Description

PG&E

ORA

Difference

         

920

Salaries

$113,021

$91,279

$21,742

921

Office Supplies and Expenses

49,316

39,625

9,691

922

Transfer to Construction - Credit

(11,655)

(17,772)

6,117

923

Outside Services Expenses

71,878

45,834

26,044

924

Property Insurance

9,884

10,034

(150)

925

Injuries and Damages

75,248

74,298

950

926

Employee Pensions and Benefits

166,642

103,226

63,416

928

Regulatory Commission Expenses

50

50

0

930.2

Miscellaneous General Expenses

77,448

69,558

7,890

931

Rents

0

0

0

935

Maintenance of General Plant

7,701

7,701

0

         
 

TOTAL

$559,532

$423,833

$135,699


"We believe that holding company costs should not be allowed if they would not have been incurred in the absence of [the holding company] structure and will adopt this position as Commission policy. The Commission has taken the view that determining the corporate structure is a management decision, yet the Commission obviously must be concerned with the public policy concerns for fairness and reasonableness to both shareholders and ratepayers as a result of such management decisions." (Re Pacific Bell (1986) 20 CPUC2d 237, 264.)


"Due to the nature of the activities charged to Account 923, PG&E cannot forecast exactly which legal cases will be active in 1999. The need for legal services results when a claim is filed against PG&E and PG&E cannot exactly predict when a claim will be filed, why it will be filed, or what amount it will be filed for." (Exhibit 423, p. A-60.)


PG&E shall not use the expenses related to claims paid out during the storm as a basis for its pending general rate case for justification of any expense forecast. It is our intent that PG&E not recover these costs from ratepayers in the account used for claims payment recovery, as authorized in the general rate case.

"DRA has not adequately supported its position with regard to funding policy. DRA does not explain why it chose the benchmarks it did or why the midpoint of those benchmarks is sensible. We will adopt PG&E's proposal to set pension costs according to the benefits accruing to current employees, which PG&E refers to as 'normal cost.' This funding level may result in contributions that are ultimately too high if PG&E further reduces its workforce. If this turns out to be the case using the earnings assumptions we adopt here, we will make appropriate adjustments if and when it has a subsequent general review of its rates. If such a review does not occur within three years, PG&E shall file an advice letter no later than December 31, 1999 proposing ratepayer refunds, if any are appropriate pursuant to this discussion." (D.95-12-055, 63 CPUC2d 570, 594.)


"PG&E's 1997 contributions, excluding 1994 Voluntary Retirement Incentive Plan (`VRI') and the amortization of the 'regulatory assets' [FN omitted], were less than the GRC authorized PBOPs costs [FN omitted]; therefore, PG&E must be diverting ratepayer funds for PBOPs to nonPBOPs uses. A refund is mandated under Ordering Paragraph No. 4, D.92-12-015 for these ratepayer dollars which were not placed into a PBOPs trust." (Exhibit 342, p. 9D-7rev.)

PG&E's and ORA's Positions on

Electric and Gas Customer Accounts Expenses

(1996 Dollars in Thousands)

Account

Description

PG&E

ORA

Difference

         

902

Meter Reading

      
 

Electric

$39,532

$34,737

$4,795

 

Gas

31,616

28,163

3,453

 

Subtotal - Electric and Gas

71,148

62,900

8,248

         

903

Customer Records & Collection

      
 

Electric

138,877

81,296

57,581

 

Gas

102,821

63,717

39,104

 

Subtotal - Electric and Gas

241,708

145,013

96,695

         

905

Miscellaneous

      
 

Electric

13,932

8,306

5,626

 

Gas

4,603

0

4,603

 

Subtotal - Electric and Gas

18,535

8,306

10,229

         
 

Totals

      
 

Electric

192,341

124,339

68,002

 

Gas

139,040

91,880

47,160

 

Combined Totals

$331,381

$216,219

$115,162


"To the extent that PG&E retains distribution customers on its system, the costs of PG&E's distribution system (which are relatively fixed, at least in the short term) can be allocated over a larger group of customers. This keeps the distribution component of each customer's rate lower than it otherwise would be, thus increasing the amount of headroom under the rate freeze available for CTC recovery." (D. 97-09-047, mimeo., p. 40.)


"If we sanction restraints on PG&E's ability to compete and if a customer is allowed to uneconomically bypass to an alternate [transmission and distribution] service provider, all of PG&E's remaining ratepayers would be worse off than if Schedules E-TD and E-TDI were adopted and judiciously utilized." (Id., p. 45.)


"(1) Assuring that the funds required for decommissioning are available at the time and in the amount required for protection of the public.


"(2) Minimizing the cost to electric customers of an acceptable level of assurance.


"(3) Structuring payments for decommissioning so that electric customers and investors are treated equitably over time so that customers are charged only for costs that are reasonably and prudently incurred."


(c) The commission shall authorize an electrical corporation to collect sufficient revenues in rates to make the maximum contributions to the fund established pursuant to Section 468A of the United States Internal Revenue Code and applicable regulations, that are deductible for federal and state income tax purposes, and to otherwise recover the revenue requirements associated with reasonable and prudent decommissioning costs of the nuclear facilities for purposes of making contributions into other funds established pursuant to subdivision (a).


"We retain our concern that nuclear decommissioning funds be adequate to cover future decommissioning costs, consistent with the legislative policy enunciated in the Nuclear Power Plant Retirement Act of 1985. We are mindful, however, that today's forecasts of nuclear decommissioning costs occurring 10 to 20 years in the future are very speculative. Forecasts of economic activity and costs out that far into the future are always subject to substantial error. In the case of nuclear decommissioning costs, forecasts are likely to be even more speculative because of the nation's limited experience with such activity. Therefore, we would be fooling ourselves if we believed we could forecast those costs with any precision. Our goal is to have funds on hand that appear reasonably adequate. Moreover, in our efforts to protect future ratepayers from costs incurred by today's ratepayers we do not wish to impose costs on today's ratepayers which, if funding exceeds future costs, would represent a windfall to future ratepayers." (D.95-12-055, 63 CPUC2d 570, 612.)


"In setting an annual nuclear decommissioning revenue requirement, our objective is to provide some insurance against a circumstance which would require significant rate increases in the future to retire plant that has served an earlier generation of users." (Id., 613.)


"Maintaining this [40%] level of contingency accommodates the increasingly uncertain regulatory and business environment in which the plant operates. For example, the estimate of the cost of disposal for low-level radioactive waste assumes that the Ward Valley, California, disposal facility will be operational and supporting decommissioning operations by the year 2000. Any further delay in the scheduled opening of the Ward Valley site will ultimately increase costs." (Exhibit 6, p. 14C-5.)


CIS Rewrite PG&E justifies abandonment of the CIS rewrite project by reference to the Commission's allowance of rate negotiations with large industrial customers, which assertedly changed the scope and cost of the project. However, Enron notes, PG&E witness Karlsson acknowledged that the Commission had been allowing negotiated rates for several years prior to 1993. Moreover, Enron notes, the witness was not aware exactly how the allowance of negotiations with customers would impact a CIS system. Finally, according to Enron, despite Karlsson's testimony that a regulatory "paradigm shift" affecting CIS requirements occurred in 1993, he could not testify as to what events occurred which caused such shift.


nCIS Project PG&E argues that there was a major shift in the Commission's approach to deregulation that rendered the nCIS effort obsolete. In particular, PG&E witness Karlsson referred to the Commission's move from the "Poolco" and wheeling concepts in 1994 and 1995 to the idea of direct access in 1996 and 1997. Enron contends that the witness was unable to clearly delineate the differences between wheeling and direct access, and was unable to identify resulting differences in programming which would compel PG&E to abandon the CIS it had been pursuing.


IBM Integrity Project The fact that a packaged, off-the-shelf solution could improve time-to-market and reduce risk provided justification for the IBM Integrity project. Enron points out that PG&E's witness acknowledged that a packaged solution has reduced flexibility and that "[g]iven the pace of change and new requirements imposes on all California utilities, any off-the-shelf package would have difficulty meeting PG&E"s requirements unless an effective two-way dialogue to set requirements and limit changes was established with the PUC." On cross-examination, the witness admitted that, in the absence of such dialogue to set the requirements for direct access, any off-the shelf package would have had difficulty in meeting PG&E's needs. Enron acknowledges that the regulatory environment was rapidly changing in the 1995-97 time frame, but claims that no one was more aware of that than PG&E. Enron further acknowledges that PG&E's cancellation of the IBM Integrity project in 1997 may have been due to its inability to handle the accelerated requirements for direct access and corresponding additional functionality, but claims that PG&E's decision to go with an inflexible, off-the-shelf system in a time of rapid changes must be questioned.


LCIS/Genesis While this project is not scheduled to be completed until 2001, Enron contends that the inability of PG&E's CIS system to meet Commission mandates for direct access must be considered in evaluating the reasonableness of PG&E's funding request.


1990 GRC In D.89-12-057, the Commission approved $2.3 million per year in incremental expense ($3.2 million per year in 1996 dollars) related to PG&E's requested funding for its CIS Rewrite project. The Commission referred to an estimate by Deloitte, Haskins and Sells (DH&S) that the total cost of the CIS rewrite was $44.3 million, plus or minus 20%, to be incurred over seven years (1989-1995). Of the total, DH&S estimated that $21.5 million could be met by redirecting existing resources to the rewrite effort. Thus, the incremental cost was $22.8 million. (34 CPUC2d 199, 241.) Enron acknowledges PG&E's rebuttal testimony, in which PG&E states that its request in the 1990 GRC was only for incremental funding. Enron counters that the non-incremental part of the project was already embedded in rates.


1993 GRC In PG&E's test year 1993 GRC, the Commission rejected incremental CIS project funding, but accepted an amount for customer billing and accounting equal to recorded 1990 amounts. Enron contends that by doing so, the Commission approved a level of funding which included the previously authorized $2.3 million annually in addition to $3.6 million in annual funding that continued to be embedded in PG&E's rates.


1996 GRC In its 1996 GRC, PG&E sought a 60% increase in funding for Customer Billing and Accounting. The requested amount was based on a showing of its 1993 recorded spending. According to Enron, the result is that from 1996 forward, PG&E's rates have embedded within them the 1993 CIS levels of spending.


"The resources that were to be redirected would continue to perform their current work assignments in addition to the work on the CIS Rewrite. Funds were not to be redirected away from previously approved internal efforts in order to pursue the CIS Rewrite Project." (Exhibit 30, p. 1-44.)


Because it is a dual-commodity utility with over 8 million accounts, and given the complexity of the gas and electric regulatory structure under which it must operate, PG&E of necessity has what is probably the largest CIS system used by any gas and/or electric utility in the nation and perhaps the world.


PG&E's CIS is so highly integrated and complex that even the smallest modifications involve high levels of risk and associated cost.


Electric industry restructuring and emerging gas unbundling present particularly substantial challenges for the CIS, requiring new functionality of the highest degree of complexity.


Although restructuring policies were conceptually developed over several years, most of the specific details, which must be known before programming can begin on the necessary modifications to CIS, were not finalized until 1997, shortly before restructuring was to begin. (See D.97-05-040 and D.97-10-087.) The Commission's timelines for market changes in California were considerably shorter than the 24 to 40 months ideally required for making extensive CIS improvements and replacements.


Given the time constraints for implementing the new market structure, PG&E necessarily chose a method for system implementation that allows for programming development while maintaining system performance. Central CIS functions such as correct tariff implementation, knowing which customers are on the various tariffs and rate options, and consistently billing the customers accurately had to be continuously operable during development and changeover to the new system.


California's existing regulations and tariffs affecting CIS are complex. For example, where Indiana has one state-wide franchise tax, in PG&E's service territory there are dozens of different tax jurisdictions. PG&E contends that there are hundreds of such non-restructuring-related complexities which make a California large utility's CIS more costly than those in most other states.


Massive changes to the CIS are required by California's unprecedented rapid electric restructuring. Modifications in CIS functionality, none of which were set forth specifically enough to begin programming until 1997, include revenue cycle unbundling, a two-page bill, changed wording on the bill, unbundling of the bill, consolidated billing, and third-party billing.


Restructuring requirements add to the number and volume of bills and to the volume of transactions per day, well over and above the 250,000 bills and two million transactions per day PG&E's CIS had to process before restructuring. Multiple-party meter reading, billing coordinated with Energy Service Providers (ESPs), and increased volume of ad hoc reporting are basic features required to implement various restructuring orders.


For the short-term, LCIS modifications are necessary to meet the direct access and Gas Accord requirements and deadlines. The LCIS project will assure that CIS is capable of providing unbundled billing (including calculation and tracking of CTC recovery), direct access [and gas supplier] switching information, direct access record keeping, complete revenue reporting on an unbundled basis, third party billing, customer information to ESPs, and metered data transfer with ESPs. Modifications to CIS will also meet other legal and regulatory compliance items, such as rate changes and refunds, and ongoing system operation and maintenance. These additional new functions require the purchase and installation of new, much more powerful hardware in order to upgrade existing processing equipment, storage capacity, and operating systems, and the purchase and installation of complex new system software.


To meet both regulatory and business needs, PG&E is enhancing the LCIS mainframe system, has added an interface to the mainframe so that new Genesis modules can be added to the system and existing data can be accessed, and is partitioning the overall system into functional areas so that individual pieces can be worked on and implemented while minimizing the impact to the balance of the system.


At this time, neither the LCIS nor the Genesis system alone is fully capable of fulfilling PG&E's needs in this new restructured market. The LCIS/Genesis approach was PG&E's least-cost and, by early 1997, its only contingency plan for timely complying with AB 1890 and Commission requirements, once the five-year phase-in of direct access was removed. LCIS/Genesis actually costs about $50 million less than IBM Integrity, which could not timely accommodate direct access with no phase-in.


ORA's sample of 12 comparable utilities is too small to provide reliable results, even though ORA witness Cheng acknowledged that a sample size of 20 to 25 companies was important to obtain valid statistical comparison, and that the minimum would be 10 to 20 companies.


ORA included in its sample utilities with as few as 500,000 customers, without checking that the smaller utilities, or their CIS systems, were adequately comparable to PG&E's. Moreover, ORA included a municipal utility with only 325,000 total gas and electric customers, but 220,000 water customers to exceed the minimum threshold of 500,000 customers. Inclusion of this utility alone reduced ORA's average comparable CIS cost by over $2 million. In addition, according to PG&E's viewpoint, ORA inappropriately excluded larger utilities from its sample.


Most of the utilities in ORA's sample had fewer than one million customers, yet PG&E contends that CIS costs are correlated with the number of accounts. According to PG&E's comparables analysis, CIS costs for utilities with between 500,000 and two million customers are between $22 and $56 million, whereas CIS costs for companies the size of PG&E are between $88 and $144 million. PG&E faults ORA's failure to weight its comparable data for the number of customers.


ORA did not consistently count the number of customers for multiple commodity utilities.


ORA did not conduct sensitivity analysis to test the effects of outside factors on the results of an analysis.


ORA did not normalize the comparable analysis data for scope of CIS work, status (complete, in progress, or planned), project duration, full replacement or upgrade, inflation, multiple commodity, and number of customers.


ORA's comparables analysis relies too heavily on data from the Chartwell CIS Report. Utilities self-report data to Chartwell, and there are no requirements to provide any assurance of consistency of that data among the companies reviewed in this report. ORA's consultant did not call any of the 12 utilities whose Chartwell data it used in its calculations in order to verify that the reported CIS cost figures were current and complete. PG&E contends that published material regarding CIS costs is unreliable because of companies' concerns about fully reporting "sensitive" data, differing accounting practices and dissimilar project management parameters.


ORA included CIS cost data for SoCalGas but excluded Edison and SDG&E. PG&E performed a limited analysis of Edison's CIS upgrade costs, which appear to total upwards of $253 million, including, actual and projected costs of $83 million from 1991 through 1997 and a projection in the Section 376 proceeding of another $170 million from 1998 through 2001 to modify key CIS metering and billing processes.


ORA's analysis assumed that SoCalGas' CIS replacement costs was $62.385 million, but according to PG&E this cost only covered costs in 1996 and 1997, whereas, SoCalGas' total CIS costs were actually $114 million for the project's full duration from 1989 to 1997.


"the Commission finds that CG&E failed to sustain its burden of showing that $62.3 million should be found to be part of the reasonable original cost of the CSS [Computer Service System] asset. Based on the evidence of record in this proceeding, the Commission finds that $32.55 million of the cost of CSS is not reasonable ... As discussed above, lengthy delays contributed significantly to the cost overruns experienced in the developing the CSS. As detailed in the Staff Report and staff testimony, CG&E invested in system where costs greatly exceeded benefits. Given the factors described above, it is unreasonable to expect that significant portion of the CSS costs would be recoverable from ratepayers. Moreover, as indicated by the staff, the company identified only $20 million in tangible benefits associated with the CSS project. Accordingly, the staff's recommendation to allow $29.75 million ... as an estimate of the reasonable cost of the CSS is appropriate." (Ex. 283, p. 11; 1996 Ohio PUC LEXIS 873.)


"Given the pace of change and new requirements imposed on all California utilities, any off-the-shelf package would have difficulty meeting PG&E's requirements unless an effective two-way dialogue to set requirements and limit change was established with the CPUC." (Exhibit 30, p. 3-6.)


"Working cash calculations require a level of precision, complexity and sometimes controversy which are out of proportion to the significance of working cash in the greater scheme of regulation. This is one area where a simple but intuitive calculation, even lacking in imprecision, would be an improvement over the current circumstance. If we revisit this issue in a future case, we hope the parties will propose simpler methods for determining working cash." (D.95-12-055, 63 CPUC2d 570, 617.)


ORA should present a detailed report describing how it has spent the consulting funds. PG&E and other parties should have an opportunity to comment on this report as part of their update testimony. ORA's report should present a recommended allocation of consulting costs to the electric and gas departments.


All consulting costs incurred by ORA in processing this GRC should be borne by PG&E's ratepayers.


Consulting costs allocated to the electric department should be transferred from the memorandum account to the Streamlining Residual Account established pursuant to Advice Letter E-3514.


Consulting costs allocated to the gas department should be transferred to the Core Fixed Cost Account and the Noncore Customer Class charge Account.


"To the extent necessary for determining the utility revenue requirement for regulated services that PG&E will continue to offer, allocations to competitive and monopoly services are at issue in this proceeding. This may include allocations to sub-categories of the UCCs in addition to those identified by PG&E. The need for setting a revenue requirement which does not reflect subsidization of competitive activities necessarily brings such allocation issues into the proceeding. However, I remind parties of the purpose of this GRC as stated previously. It is not a generic unbundling policy proceeding, and it is not a forum for relitigation of matters already resolved by the Commission or for duplicate litigation of matters being addressed in other forums. Thus, for example, electric and gas revenue cycle service issues being addressed in A.97-11-004 and R.98-01-011 respectively will not be litigated in this GRC." (Scoping ACR, mimeo., p. 9.)


..."The utilities have not demonstrated that every type of fixed cost cannot be reduced, that is, made variable, over the medium term....


"However, we are persuaded that some of these fixed A&G costs may remain following divestiture and the end of the period during which the utility operates the plant on behalf of a purchaser. On the other hand, we want the utilities to take actions to reduce their costs, especially as a result of divestiture.


"It is not our intent to deny utilities an opportunity to recover reasonable costs which they actually must incur, but we must balance this with our need to ensure that ratepayers are not paying for costs that no longer exist. To the extent that the fixed A&G costs we have allocated to generation are truly fixed and continue to exist following this period, we will review and reallocate continuing fixed A&G costs to distribution using a streamlined procedure. No procedure was proposed in this proceeding. The Assigned Commissioners in this proceeding shall develop a streamlined process for this reallocation by December 16, 1997." (D.97-08-056, mimeo., p. 24.)


The Public Utilities Commission should have reasonable access to computer programs and models used by public utilities subject to its jurisdiction to improve the quality and efficiency of its regulation.


"Neither the constitution nor case law has ever required automatic rate increases between general rate case applications. Attrition year adjustments are a relatively recent innovation and they are more recent than the cases cited to by Edison in support of maintaining the current attrition mechanism." (Id., 374.)


...We have previously stressed the importance of a comprehensive evaluation of Edison's current operations and revenues in this general rate case so we can have a credible benchmark if we choose to utilize it in the future. ...[P]ermitting subsequent large attrition increases to occur through the minimal review of an advice letter prior to our completed review of Edison's PBR application could skew this benchmark.... (64 CPUC2d 241, 372-73.)


"The proposed profit center treatment would in effect impute to these `Potentially Competitive' service categories outside sources of revenue in amounts minimally sufficient to recover outlays not required to support monopoly function, thereby avoiding ratepayer subsidization of PG&E's competitive ventures. Through the imputation process, the entire amount of 1999 expense levels and capital additions associated with the provision of revenue cycle services would be included in the rate base, but only that portion of PG&E's outlay legitimately required to support monopoly [utility distribution company (UDC)] services would effectively be included in the revenue requirements to be funded by monopoly ratepayers..." (Exhibit 71, p. 7.)


"...ORA recommends that Phase II of this GRC be used to pursue the actual unbundling of these services into profit centers, as discussed above, thus placing PG&E's shareholders at risk for the portion of these costs that represent investments in excess of levels required to service PG&E's ratepayers. In light of the changes occurring in the electric and gas industries, ORA supports full unbundling of PG&E's services. ORA proposes that Phase II of the GRC also be used to apportion PG&E's costs between the following three categories: Monopoly UDC Services; Potentially Competitive Services, such as revenue cycle services; and Fully Competitive Services." (Id., p. 8.)


"Under this approach and for those services that are not fully competitive, costs and revenues in the Monopoly and Potentially Competitive Service categories would be considered in setting PG&E's revenue requirement in this GRC as well as in Phase II. Costs that are exclusively attributable to one or the other of these two categories would be assigned solely to that category, whereas costs that are shared by both categories would be recovered through revenue from both categories." (Id.)

1. Summary 2

2. Background 7

3. Public Participation 24

4. Policy Issues 27

5. Productivity and Cost Studies 65

6. Service Quality 88

7. Electric Revenues, Expenses and Capital 94

8. Gas Revenues, Expenses, and Capital 205

9. Common and Miscellaneous Revenues, Expenses, and Capital 239

Discussion 248

10. Cost Allocation/Separation 457

11. Revenue Requirement 468

12. Other Issues 474

1 SAFSTOR is a condition of monitored safe storage in which the nuclear unit will be maintained until spent fuel is removed from the site and the facility is dismantled. 2 D.99-04-026 dated April 1, 1999 authorized PG&E to transfer and sell certain generating facilities, including its Geysers Geothermal Lake County and Sonoma County Plants, subject to mitigation and other conditions. Thus, the ratemaking mechanism will apply to PG&E's hydroelectric generation. 3 In fact, in some respects PG&E did not perfect its application until much later in the proceeding. A prime example is PG&E's showing on Administrative and General (A&G) expenses. 4 In fact, Commissioner Wood is not still a union member. 5 Noting the duration of hearings and the number of exhibits, Enron referred to "the enormity of the record." (Enron Opening Brief, p. 3.) The American Heritage Dictionary, Office Edition, defines enormity as "1. Extreme wickedness. 2. A monstrous offense or evil; outrage." We, and the ALJ who developed and reviewed the record, cannot disagree with this characterization. 6 Indeed, Commissioner Wakefield observed that the situation for California ratepayers was better in 1941 than the scenario painted by Wilcox: 7 In a footnote at this point, the Commission stated in D.87-12-067 that "[t]he longstanding and proper rule is set forth in D.90642 at 2 CPUC 89, 98-99 and requires that the utility meet its burden by clear and convincing evidence. To meet this burden we have specified that '. . .the applicant must produce evidence having the greatest probative force.'" (D.87-12-067, 27 CPUC2d 1, 169.) 8 Public Utilities Code Section 451, third sentence. We have not had occasion to interpret this language in the specific context of a large scale energy utility, but note that it could be the basis for challenging a pure "market" approach to employment issues. 9 In Section 330(u), the Legislature addressed the issue of work force reductions caused by electrical restructuring. It did so by providing a mechanism in Section 375 to fund the reasonable costs of voluntary severance, retraining, early retirement, outplacement, and related benefits. The Legislature has not conferred equivalent, specific authority on the Commission to authorize funding for work force reductions caused by resetting a utility's authorized revenue requirement to the lowest level consistent with the provision of adequate utility service. 10 Although PG&E used a sample of 100 utilities, data for some categories were available for only 97 utilities. 11 In its reply brief, PG&E appears to argue (at p. 29) that we should accept its forecast because Enron, a competitor of PG&E, is the only party to contest it. We remind PG&E that even if ORA supports, or does not contest, one of its forecasts, PG&E's burden of proof to show the need and reasonableness of a predicted expense never shifts. The failure of ORA (or any other party) to take a position in opposition to PG&E on any issue does not give PG&E a free pass on that issue. 12 While the record reviewed in D.95-09-073 did not support a finding that the condition or management of PG&E's system prior to the early 1995 storms were unreasonable, we did find that employee reductions, extended maintenance cycles, and an inadequate customer service telephone system affected the efficacy of PG&E's response to the storms. (D.95-09-073, 61 CPUC2d 493, 503.) 13 The proposition that PG&E had gone too far in cutting back on expenditures in the years before 1995 is consistent with PG&E's conviction on more than 700 counts of criminal negligence associated with the 1994 Rough and Ready fire in Nevada County. 14 There are other examples of PG&E's having taken different positions on an issue. In its 1996 GRC, PG&E took the position that it could comply with a four foot tree clearance requirement which applied in most of its service territory with a 3.5 year trim cycle. In this GRC, PG&E takes the position that a 3.5 year cycle (or any other cycle-based trim program) is inadequate to meet an 18-inch clearance requirement. Even within this GRC, PG&E has taken varying positions. In its original testimony, PG&E asserts that "all tree trimming expenditure projections assume normal weather patterns." (Exhibit 6, pp. 7-8.) In its rebuttal testimony, PG&E estimates the need for an additional 200,000 tree trims in 1999 to accommodate the excessive amount of rain that occurred during the 1997-98 winter season. (Exhibit 27, pp. 6-29.) (PG&E witness Carruthers acknowledges this contradiction.) 15 PG&E uses the terms "project" and "program" interchangeably to refer to certain non-routine tree removal and replacement activities which are discussed below. 16 During the course of this proceeding, ORA was often frustrated by PG&E's incomplete, changing, and inconsistent vegetation management data. ORA notes, for example, that PG&E's original application testimony did not include a tree trimming budget or unit cost data. Having spent considerable time grappling with the record on this issue, we now share ORA's frustration. 17 In a data response to ORA, PG&E acknowledges that there are no incremental costs associated with the 18-inch clearance requirement adopted by the Commission in D.97-01-044 (other than initial compliance costs incurred in 1997 and 1998) relative to 1996 recorded, if not also authorized spending. In any event, there is no record evidence demonstrating that there are any ongoing incremental costs associated with the 18-inch requirement. 18 PG&E assumed there were 3.5 million trees during at least most of the 1987-1994 period, estimated there were 3.4 million trees in 1993, estimated there were 4.5 million trees in the 1996 GRC, estimated there were six to eight million trees in A.96-04-002, and presented counts of 4.445, 5.0, and 4.832 million trees in this GRC. 19 In May 1996, PG&E installed a new business system based on software provided by SAP AG. Start-up problems with the SAP-based system required adjustments to 1996 recorded data for purposes of developing cost estimates in the GRC application. References to 1996 recorded data include the adjustments where appropriate. 20 In 1996, PG&E ended the use of supervision and engineering accounts (Accounts 580 and 590). Costs formerly recorded in those accounts cascade to the various FERC accounts primarily as a function of how field forces charge their time. PG&E notes there has also been cost shifting between accounts. Also, some costs that were previously recorded as A&G are now recorded in O&M accounts. In its Opening Brief (at p. 109), PG&E presented a similar table showing gross additions recommendations for PG&E and ORA and net additions recommendations (reflecting retirements) for Enron. The net additions recommendations shown in this table for PG&E and ORA are taken from the Comparison Exhibit. (Exhibit 474, p. A-125.) 21 In its opening brief (at p. 109), PG&E presented a similar table showing gross additions recommendations for PG&E and ORA and net additions recommendations (reflecting retirements) for Enron. The net additions recommendations shown in this table for PG&E and ORA are taken from the Comparison Exhibit. (Exhibit 474, p. A-125.) 22 In its Opening Brief (p. 118), PG&E updated this analysis to reflect recorded 1998 peak load information in Exhibit 402. This exhibit was introduced on October 7, 1998 and appears to reflect data available as of October 1, 1998, presumably after the peak distribution load in 1998 was likely to have occurred. PG&E did not indicate any change in the installed capacity of substation transformers from 1997 to 1998. PG&E calculated the 1998 actual utilization factor at 83%. 23 The record (Exhibit 193) discloses that in the face of technology improvement, and now competition, traditional utility industry practice which centered on 70% peak transformer loading is steadily becoming obsolete in favor of higher loading approaching 100% and even greater. Even when emergency loading policies are in place, the underlying report suggests that utilization factors of 85% to 90% are feasible. 24 But see Public Utilities Code Section 734. 25 Public Utilities Code Section 328.2 requires utilities to provide basic bundled gas service, including "after meter services." After meter services are expressly defined to include carbon monoxide investigation. (Public Utilities Code Section 328.1(c).) 26 Even if ORA's 1993 to 1996 averaging approach were applied to this account, we note that the number of Mark and Locate requests increased 28% from 1992 to 1996. PG&E did not show what the change was from 1993 to 1996. 27 PG&E did submit an estimate of transferred A&G expenses in late-filed Exhibit 471. Although ORA requested the information on August 20, 1998, prior to the commencement of hearings, PG&E did not provide the information until after the close of hearings and even then was unable to provide the detail requested. The estimate was not subject to further discovery or cross-examination, and it would be unfair to give it weight in developing our adopted forecast of expenses. 28 As shown in Table 6-2 of Exhibit 28, PG&E should replace distribution pipeline at an average rate of more than 86 miles per year in the final 12 years of the program. In the first 13 years, PG&E replaced distribution pipe at an average rate of 72 miles per year. In contrast, PG&E replaced transmission pipe at an annual rate of 24.1 miles in the first 13 years and needs to replace transmission pipe at an annual rate of 20.1 miles for the remainder of the program. 29 Pursuant to D.96-11-017 (69 CPUC2d 167), on January 1, 1997, PG&E became a subsidiary of its new parent holding company, PG&E Corporation. Pacific Gas Transmission (PGT) and Pacific Enterprises, previously owned by PG&E, became wholly-owned subsidiaries of PG&E Corporation. PG&E's "non-regulated" affiliates are PG&E Energy Services, PG&E U.S. Generating, PG&E Gas Transmission, and PG&E Energy Trading. 30 Overland interviewed 25 PG&E employees and submitted 450 discovery questions. PG&E acknowledges that the Overland review of its A&G expenses was more detailed than reviews conducted in previous GRCs. 31 We have already noted the past problems that PG&E had counting trees in proximity to its distribution system. The record shows that PG&E has also had problems providing the Commission with accurate employee head counts in this GRC. While the highly-touted tree inventory data base has clearly assisted PG&E with its tree counting efforts, we decline to speculate on whether it could be adapted to other purposes. 32 It may be more accurate to characterize PG&E's so-called rebuttal A&G testimony as its initial direct showing. It is perhaps in the area of A&G expenses that PG&E strayed the farthest from the principle that it is unacceptable for utilities to "offer only the most minimal support for their rate requests, choosing instead to wait to see what subjects appear to be of interest to [ORA]," then, in response to ORA's concerns, provide focused rebuttal. (D.92-12-019, 46 CPUC2d 538, 764.) PG&E also managed to run afoul of the ground rules on rebuttal testimony set forth in Appendix B of the April 7, 1998 Scoping ACR. Arguably, the actions of PG&E in this case were even more egregious than the situation the Commission found unacceptable in D.92-12-019, since PG&E did not present its "minimally supported" direct A&G proposal until the time set for rebuttal. 33 In adopting the incremental cost incentive price plan for Diablo Canyon, the Commission found that: 34 PG&E makes the minor point that forecasts cannot be audited in the same way as recorded amounts. We understand ORA's reference to "auditor" to mean one who investigates and analyzes the validity and reliability of PG&E's forecast, not necessarily a licensed financial auditor. ORA's complaint regarding its inability to "audit" PG&E's showing clearly refers to the lack of support in terms of underlying assumptions and calculations for departmental estimates of incremental expenses. 35 There is conflicting evidence on this point. As reported in Exhibit 460, p. 6, PG&E indicated in a data response to ORA that employees are only eligible for severance pay if their position has been eliminated and no other work has been offered or assigned. On cross-examination, PG&E witness Holton testified that employees are also eligible for severance if their position is moved 50 miles or if they are offered a position at a lesser grade. (Tr. V. 47, p. 6010.) We are left to conclude that severance pay for relocated and downgraded positions is not a major factor in our analysis. 36 Ordering Paragraph 1 of D.88-03-072 directed telephone utilities to use "the current aggregate cost method, or cost approach, which normalizes pension cost over the employee's service period for ratemaking and accounting purposes." Ordering Paragraph 2 rejected the use at that time of Financial Accounting Standards Board (FASB) Statement No. 87, which employs the unit credit method, or benefits approach. (27 CPUC2d 550, 557.) 37 We take administrative notice of the USOA definition of Account 902 Items, which includes 20 separate operations exclusive of meter reading proper, which is included in Account 901 and is not addressed apart from Account 902 in this case. 38 With respect to the Quality Contacts Program disallowance, PG&E's application for rehearing of D.95-12-055 was denied by D.98-12-096. 39 PG&E uses the term "basic services" to refer to rate and tariff functions, credit and collections, contract administration, operational work such as providing outage information, and new customer work. Without commenting specifically on each task and activity listed as a basic service in Attachment 8-1 to PG&E's rebuttal testimony (Exhibit 27), we generally accept PG&E's listing of functions which are central to the provision of utility distribution service and are therefore eligible for recovery in distribution rates. 40 PG&E's inclusion of CTM analyses for the first time in its rebuttal testimony represents another example of PG&E's withholding of part its showing until filing rebuttal testimony. 41 Curve types are the time patterns which describe the probability of retirement of a fraction of the initial group in each time period. 42 In D.83-04-013, issued before the enactment of the Nuclear Facility Decommissioning Act of 1985, we provided for a high level of assurance that decommissioning can be accomplished promptly and efficiently, and that such assurance is the single most important criterion for evaluating financing mechanisms. (11 CPUC2d 115, 119.) Assurance was ranked ahead of cost, equity, and flexibility. (Id.) However, this did not mean that the Commission would single-mindedly select the financing alternative with the greatest assurance. The Commission provided that the criteria of cost, equity, and flexibility would temper the selection. (Id., 135.) 43 The Low-Level Radioactive Waste Policy Act, Pub. L. 96-573, 94 Stat. 3347, (42 (( 2021b to 2021j, (1980).) 44 Excess Capacity for the Disposal of Low-Level Radioactive Waste in the United States Means New Compact Sites are Not Needed, F. Gregory Hayden, PhD., Nebraska Commissioner, Central Interstate Low-Level Radioactive Waste Compact Commission, December, 1997. 45 For the reasons discussed earlier, we do not accept the Redwood Alliance's estimates of between $31 million and $160 million in savings. 46 The Commission recently addressed operational problems with PG&E's billing system in D.99-06-056. In doing so, it noted PG&E's testimony that the CIS billing system is "old and fragile," and bears "the burden of over 30 years of changes to a monolithic system not originally designed for either its current roles or to accommodate such dramatic business changes." (D.99-06-056, mimeo., p. 4.) 47 Ratepayer cost would be substantially less than this amount annually and cumulatively, since ratepayers would be amortizing the capital investment and paying return on unamortized investment. 48 We concur with PG&E's determination that, consistent with standard memorandum account treatment, this account should accrue interest based on the three-month commercial paper rate. 49 Where an ORA representative does find it necessary to "roam the halls," Section 771 provides that utility personnel may be present. 50 PG&E has identified sub-categories within the UCCs to determine the revenue requirement and satisfy other existing regulatory requirements. For example, electric restructuring requires the further separation of Electric Generation costs into fossil, geothermal, hydro, and other sub-categories. These sub-categories are not disputed. 51 PG&E refers to this factor as the "M&O labor factor" in its opening brief and as the "A&G Labor Two Factor Allocator" in its reply brief. The four-factor allocator is an arithmetic average of percentages of expenses, gross plant, number of employees, and number of customers. 52 In PG&E's electric tariffs, summer months are defined as the months of May through October, and winter months are defined as the months of November through April. 53 In a motion filed on June 22, 1998, PG&E sought to have stricken those portions of ORA's reports and prepared testimony in which ORA recommended adoption of the profit center framework. The assigned ALJ denied the motion, having concluded that ORA was entitled to demonstrate that its profit center proposal is necessary for determining a reasonable revenue requirement for utility services which may become competitive. We affirm the ruling.

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