Soah Docket No

1 1 SOAH DOCKET NO. 473-01-1634 2 PUC DOCKET NO. 23550 3 4 5APPLICATION OF ENTERGY GULF § BEFORE THE STATE OFFICE 6STATES, INC. FOR THE AUTHORITY § 7TO RECONCILE FUEL COSTS § OF 8 § 9 § ADMINISTRATIVE HEARINGS 10 11 12 13 14 15

DIRECT TESTIMONY

AND EXHIBITS

RANDALL J. FALKENBERG

16 17 18 19 20 ON BEHALF OF THE 21 22 OFFICE OF PUBLIC UTILITY COUNSEL 23 24 25 26 27 RFI CONSULTING, INC. 28 ATLANTA, GEORGIA 29 30 31 JULY 2001

1 TABLE OF CONTENTS 2 3 4 5I. QUALIFICATIONS...... 3 6 7II. INTRODUCTION AND SUMMARY...... 6 8 9III. WILLOW GLEN 5 OUTAGE...... 7 10 11 a. Net replacement power costs should be borne by EGSI’s shareholders. 12 7 13 14 b. EGSI understated replacement power costs...... 11 15 16IV. PURCHASED POWER CONTRACTS...... 13 17 18V. GOOD CAUSE EXCEPTION FOR RIVER BEND PURCHASE...... 21 19 20 21EXHIBITS...... 25 22 23 Exhibit RJF/1 – Outage Cost for Willow Glen 5...... 27 24 Exhibit RJF/2 – Capacity Component of Summer 2000 Purchases...... 31 25 Exhibit RJF/3 – Qualifications of Randall J. Falkenberg ...... 35 26 27ATTACHMENTS...... 47 28 29 Attachment 1 – EGSI Response to OPC-11-2 (Addendum 1) ...... 49 30 Attachment 2 – EGSI Response to OPC-5-1 (Pages 465-466) ...... 53 31 Attachment 3 – EGSI Response to OPC-5-1 (Pages 323-328, 336-338 and 32 496-500) ...... 57 33 Attachment 4 – EGSI Response to Staff 3-18 ...... 73 34 Attachment 5 – EGSI Response to Staff-5-21 ...... 77 35 Attachment 6 – Direct Testimony of Bruce M. Louiselle, Louisiana 36 Public Utility Commission, Docket No. U-25533...... 81

2 Randall J. Falkenberg – Direct Testimony 3 SOAH Docket No. 473-01-1634 4 PUC Docket No. 23550 5 Page 2 of 92 1

1 DIRECT TESTIMONY 2 OF RANDALL J. FALKENBERG 3

4Q. Please state your name and business address.

5A. Randall J. Falkenberg, PMB 362, 8351 Roswell Rd., Atlanta, Georgia 30350.

6Q. What is your occupation and by whom are you employed?

7A. I am a utility rate and planning consultant holding the position of President and

8 Principal with the firm of RFI Consulting, Inc. ("RFI").

9Q. Please describe the consulting services provided by RFI.

10A. RFI provides consulting services in the electric utility industry. The firm provides

11 expertise in system planning, load forecasting, economic analysis, cost of service,

12 revenue requirements, utility energy and fuel cost issues and rate design.

13Q. On whose behalf are you appearing?

14A. I am appearing on behalf of the Office of Public Utility Counsel ("OPC").

16 I. QUALIFICATIONS

17Q. Please describe your education and professional experience.

18A. Exhibit RJF/1 describes my education and experience within the utility industry.

19 I have more than twenty years of experience in the utility industry and have

20 worked for utilities, both as an employee and as a consultant, and as a consultant

21 to major corporations, state and federal government agencies, and public service

22 commissions. I have been directly involved in a number of cases related to the

23 Beaver Valley, Grand Gulf, Limerick, Millstone, Palo Verde, Perry, River Bend,

24 Susquehanna, and Vogtle nuclear generating facilities, and the Bath County,

1 Brandon Shores, Rocky Mountain, TNP-One, Trimble County, and Wilson fossil

2 powered plants concerning the topics of plant cancellation, phase-in, rate base

3 treatment, construction work in progress, prudence, power system reliability, and

4 economics.

5 During my employment with EBASCO Services in the late 1970s, I

6 developed probabilistic production cost and reliability models used in studies for

7 twenty utility companies and the Wisconsin Public Service Commission Staff. I

8 personally directed a number of marginal and avoided cost studies performed for

9 compliance with the Public Utility Regulatory Policies Act of 1978 ("PURPA").

10 At EBASCO, I also participated in a wide variety of consulting projects in the

11 rate, planning, and forecasting areas.

12 In 1982, I accepted the position of Senior Consultant with Energy

13 Management Associates ("EMA"). At EMA I trained and consulted with planners

14 and financial analysts at several utilities in applications of the PROMOD III and

15 PROSCREEN II planning models. In particular, I assisted planners in the

16 application of these models to analyze revenue requirements and the financial

17 impact of alternative expansion plans. I also assisted in EMA's educational

18 seminars and trained utility personnel in revenue requirements analysis,

19 production cost modeling, reliability analysis, and other techniques of generation

20 planning.

21 I co-founded J. Kennedy and Associates (“Kennedy”) in 1984, where I

22 was responsible for the firm's work in the areas of generation planning, reliability

23 analysis, and the rate treatment of new capacity additions. I have presented expert

1 testimony on these and other matters in approximately one hundred cases before

2 the Federal Energy Regulatory Commission (“FERC”) and state regulatory

3 commissions and courts in Arkansas, Connecticut, Florida, Georgia, Kentucky,

4 Louisiana, Maryland, Michigan, Minnesota, New Mexico, New York, North

5 Carolina, Ohio, Pennsylvania, Texas, Utah, and West Virginia. Included in

6 Exhibit RJF/1 is a list of my appearances.

7 In January 2000, I founded RFI Consulting, Inc. At RFI, my practice is

8 comparable to that which I directed at Kennedy, my previous firm.

9Q. Have you previously appeared before the Public Utility Commission of Texas

10 ("PUCT")?

11A. Yes. I testified in El Paso Electric Company Docket No. 9945 regarding the

12 prudence of Palo Verde. I testified in Texas-New Mexico Power Co. Docket No.

13 10200 regarding an imprudence disallowance related to TNP-One. I testified in

14 Houston Lighting & Power Company ("HL&P") Docket No. 11000 regarding

15 certification of the San Jacinto project and filed testimony in HL&P's most recent

16 IRP case, Docket No. 19270. I filed testimony in the most recent Southwestern

17 Public Service Company fuel reconciliation case (Docket No. 19512) and the

18 most recent Central Power and Light Company fuel reconciliation case (Docket

19 No. 20290). I also assisted OPC in the recent HL&P fuel reconciliation. Finally,

20 I also presented testimony quantifying stranded costs in the ECOM phase of the

21 TXU Electric (Docket No. 22350) and Reliant Energy (Docket No. 22355)

22 Unbundling cases.

23Q. Have you testified previously in other cases involving EGSI or other Entergy

1 operating units in other states?

2A. Yes. I filed testimony in the most recent Entergy Gulf States fuel reconciliation

3 case (Docket No. 21111). In that case, my adjustment related to the Nelson 6

4 outage was accepted by the Company. I have also testified in many Gulf States

5 Utilities cases, prior to the merger with Entergy and in cases concerning the

6 merger. In addition, I have testified in a number of Entergy Arkansas Inc. cases.

7 Exhibit RJF/1 summarizes these proceedings.

9 II. INTRODUCTION AND SUMMARY

10Q. What is the purpose of this testimony?

11A. OPC has asked me to review the discovery and testimony filed by EGSI and make

12 recommendations regarding the EGSI fuel reconciliation request for the period

13 March 1999 through August 2000. Specifically, I will address the following

14 issues:

15 1. The proper treatment of replacement power costs resulting from the 4033-hour 16 Willow Glen 5 outage starting in August 1999; 17 18 2. The reasonableness of the EGSI calculation of replacement power costs 19 stemming from the outage. 20 21 3. Regulatory treatment of high cost power purchases that have an implicit 22 capacity cost component included in the energy price. 23 24 4. The request for good cause exception to the fuel rule regarding treatment of 25 profit margins stemming for the purchase of power from the unregulated 30% 26 of River Bend. 27 28Q. What are the conclusions of your testimony? 29 30A. I have concluded as follows:

1 1. The net replacement power costs related to the 4033-hour outage of Willow 2 Glen 5 should not be recovered as part of eligible fuel. These costs resulted 3 from what Entergy officials described as “poor operating practices.” Given 4 the circumstances, this outage was the result of negligence and poor 5 communications on the part of EGSI staff. Ratepayers should not be required 6 to pay for the net replacement power costs. 7 8 2. EGSI has computed the cost or replacement power for this outage was 9 $1,505,823. However, this understates the actual outage cost. I have 10 estimated the total replacement power cost to be $9.234 million.1 11 12 3. The Commission should remove $9.572 million for several “energy only” 13 purchased power contracts from eligible fuel. These contracts provided firm 14 capacity and were intended to provide for required reserve margins. 15 Therefore, they have an implicit capacity related component of cost included 16 in the purchase price. Entergy regulators in Louisiana have already begun to 17 treat costs from such purchases as capacity related, thus removing them from 18 pass through recovery. In fact, the Company itself now recognizes that there 19 is a capacity component to these purchases. I recommend the Texas 20 Commission also implement this approach. 21 22 4. The Commission should deny the EGSI request to allow profit margins on the 23 River Bend purchase to be included as part of eligible fuel. The Company 24 has not demonstrated a legitimate basis for over-riding the Commission’s 25 rules regarding affiliate purchases. The profit component should not be 26 included as part of eligible fuel. This reduces the EGSI eligible fuel cost by 27 $6.349 million. 28

29 III. WILLOW GLEN 5 OUTAGE

30 a. Net Replacement Power Costs Should Be Borne By EGSI’s Shareholders

31Q. Please provide background information concerning this issue.

32A. Willow Glen Unit 5 was on an extended unplanned outage from August 13, 1999

33 until January 29, 2000. This outage was 4032.9 hours long and,according to

34 EGSI’s estimates,resulted in additional power costs of $819,918.2

21 All disallowance figures quoted are on a Total Company basis. OPC witness Mr. Hugh 3 Higgins performs the jurisdictional allocation. 42 See Attachment 1, EGSI’s response to OPC-11-2. 5 Randall J. Falkenberg – Direct Testimony 6 SOAH Docket No. 473-01-1634 7 PUC Docket No. 23550 8 Page 7 of 92 1

1 According to the testimony of EGSI witness Dr. Thomas W. Schnatz, the

2 cause of this outage was a faulty DC battery charger that caused low voltage on

3 the DC system, preventing a safe shutdown of the generator. This situation

4 resulted in a lack of lubrication, causing substantial damage to the generator as it

5 rolled down. There was damage estimated in the millions of dollars to repair.

6 According to an email from Robert Hicks to James Campbell,3 Mr. Hicks’

7 preliminary assessment placed the blame for the event on “poor operating

8 practices.” These included ignoring prior alarms warning of the battery charger

9 problems. Contributing factors included (1) too many distractions in the control

10 room; (2) control room deficiencies; and (3) inadequate communication.4

11Q. Was there a more detailed analysis of the cause of this outage?

12A. Yes. On Monday, August 23, 1999 an incident review meeting was conducted to

13 develop a Root Cause Analysis (“RCA”) of the outage. A summary of this

14 meeting was also included in EGSI’s response to OPC-5-1 and pertinent sections

15 of this summary and other important documents are included as Attachment 3.

16 This review elaborated on the conclusions related to poor operating practices

17 discussed above, and provide more detail. This analysis cites failure to

18 investigate battery alarms and related known problems as contributing factors.

19 According to this in-house assessment, a major problem was the failure of

20 both of the battery chargers, which caused the lack of lubrication. Based on the

21 information contained on page 498 of EGSI’s response to OPC-5-1,5 alarms

22 indicating trouble with the battery charger were noted and logged on August 9th

23 Attachment No. 2 34 Id. 45 Attachment 3. 5 Randall J. Falkenberg – Direct Testimony 6 SOAH Docket No. 473-01-1634 7 PUC Docket No. 23550 8 Page 8 of 92 1

1 and again on August 13th, prior to the event. Thus, there was warning of a

2 potentially serious problem that was not addressed prior to the incident. Given

3 the gravity of the problems associated with a generator shutdown without

4 lubrication, this was clearly a very important situation.

5 Q. According to the testimony of Dr. Schnatz, Entergy fossil plants operated

6 above the NERC national average forced outage rate during 1999. Is this

7 sub-par performance the result of the Willow Glen 5 outage?

8A. Yes. In fact, Dr. Schnatz demonstrates this in Exhibit TWS-6 of his direct

9 testimony. This outage was twenty-four weeks long. Typically, a gas plant of the

10 size of Willow Glen 5 would only expect maintenance [planned] outages

11 averaging 6 weeks per year and a forced outage rate of about 6% (or a total of

12 about 3 weeks per year). As shown in Exhibit TWS-6, without the Willow Glen 5

13 outage, the forced outage rate for EGSI plants would have been comparable to the

14 NERC averages.

15Q. Does EGSI contend that this outage was reasonable and prudent?

16A. Yes. In both its responses to data requests and in Exhibit TWS-5, the Company

17 maintains that this outage was not the result of imprudence. However, in Exhibit

18 TWS-5, the Company does acknowledge some basic facts: (1) the outage was

19 largely caused by problems with the DC system, and that the plant personnel did

20 not respond to warning indicators reporting the battery charger problem; (2) a

21 contributing factor to the outage was the scheduling of critical tasks related to the

22 shutdown of unit 4. Based on some of the documents produced in Attachment 3,

1 the consolidation of the control rooms was considered a contributor to the

2 incident.

3Q. Is it reasonable to allow reconciliation treatment of the replacement power

4 costs?

5A. No. Clearly, given the gravity of the problems associated with the lack of a

6 reliable backup DC power supply and the two forewarnings of a problem, this

7 should not be considered a “prudent” outage. At the very least, EGSI has failed to

8 meet its burden of proving the outage was prudent. Indeed, the Company has

9 really proven just the opposite – that the chain of events leading to the failure was

10 the result of a lack of care. The initial conclusion that “poor operating practices”

11 caused the outage is confirmed by subsequent review within the Company.

12 Customers should not be required to bear the outage costs that result from poor

13 operating practices.

14Q. Would it be reasonable to simply consider this event as “bad luck” or an “act

15 of God,” such as a hurricane, that therefore does not result in costs that

16 should be borne by shareholders?

17A. It is hard to imagine how this could be characterized as simple “bad luck,” given

18 the obvious importance of being able to provide the generator with lubrication

19 during shut down. The mere presence of two battery charger systems indicates

20 that the Company recognized up front the need for an operational backup system.

21 The failure to respond to a known problem (which was first logged several days

22 before the incident) demonstrates a lack of care.

1 b. EGSI Understated Replacement Power Costs.

2Q. Did EGSI compute the amount of additional power costs related to this

3 outage?

4A. Yes. In his response to OPC 11-2,6 Mr. Ralston computes that the outage resulted

5 in $1,505,823 of additional power costs on a total company basis. Mr. Ralston

6 based his calculation on the average capacity factor for Willow Glen 5 of 29%

7 during the 4033-hour outage period.

8Q. Do you agree with Mr. Ralston’s calculation of replacement power costs?

9A. I have some problems with his approach. First, Mr. Ralston acknowledges that,

10 had there been no forced outage, it is more likely that the unit would have been

11 placed in reserve shutdown for some months when replacement power costs were

12 lower than Willow Glen 5 costs.7 In that case, the Company would have placed

13 the unit in reserve shutdown every month from September 1999 to December

14 1999, resulting in a zero net replacement cost for those months and an overall net

15 replacement cost of $2,549,806.8 Because it is likely that Willow Glen 5 would

16 have been in reserve shutdown, I remove all negative values from the months

17 where the replacement power costs were lower than the cost of running Willow

18 Glen 5.

19 I have used the spot price for gas in my analysis to estimate the cost of

20 operating Willow Glen 5 because I believe it is a better estimate of incremental

26 See Attachment No.1. 37 Id. 48 I also believe that it is quite possible that the given the difficulty of re-creating the operation of the 5unit and the replacement power costs, after the fact, it is quite likely that the “negative” values are simply 6the result of simplifications in the model. 7 Randall J. Falkenberg – Direct Testimony 8 SOAH Docket No. 473-01-1634 9 PUC Docket No. 23550 10 Page 11 of 92 1

1 costs. Adjusting the gas price would result in making it economic to operate the

2 plant in January 2000, and result in an increase in the cost of replacement power

3 of $89,283 for that month.

4 However, I find even the August 1999 figures counter intuitive. Based on

5 the avoided cost analysis contained in the Company’s response to OPC-11-2,9 the

6 average cost of replacement power for Willow Glen 5 during the outage was

7 $45/mWh. In contrast, based on its response to OPC-11-3, the Company was

8 purchasing substantial amounts of power during the month at prices well in excess

9 of $100/mWh. In fact, some transactions had a price substantially higher. Thus,

10 it appears that the avoided cost analysis prepared by the Company understates the

11 cost of energy during peak periods.

12Q. Have you recomputed the cost of replacement power for August 1999?

13A Yes. I estimate that the cost of replacement power during on-peak hours (6 a.m.

14 to 10 p.m.) would be $115.42/mWh. This was based on averaging the price of the

15 most expensive on-peak purchases in August 1999, as shown in Schedule FR4.3a-

16 g of the Company’s filing. Review of the information contained in the response

17 to OPC-11-3 verifies that the transactions I used in my analysis were on-peak

18 purchases. I believe that this is a better estimate of the market value of

19 replacement power in peak periods than the avoided cost analysis prepared by the

29 Attachment 1. 3 Randall J. Falkenberg – Direct Testimony 4 SOAH Docket No. 473-01-1634 5 PUC Docket No. 23550 6 Page 12 of 92 1

1 Company. A major reason it is a better estimate is that the Company ignores all

2 purchase transactions in its computation of avoided cost that last longer than one

3 hour. Exhibit RJF/2 summarizes my recommended outage cost calculation. This

4 analysis results in a recommended disallowance of $9.234 million.

6 IV. PURCHASED POWER CONTRACTS

7Q. On page 52 of his testimony, Mr. Turner describes a number of purchased

8 power contracts that EGSI entered into for the summer of 2000. Are there

9 any issues raised by these purchases with respect to the definition of eligible

10 fuel costs?

11A. Yes. Mr. Turner describes a number of steps the Company took to provide for

12 reliable service during the summer of 2000. In a number of cases, the Company

13 obtained power from non-associated companies, under terms and conditions

14 where most (if not all) of the price of power was included in the energy charge.

15 These arrangements include the PECO Purchase, the Reliant and Pan Canadian

16 Unit Contingent Energy and the so called “Liquidated Damages” energy.

17Q. Is this unusual?

18A. Historically, when firm power was sold, the ordinary approach was to sell it under

19 a contract with both a demand and energy charge. This approach had its roots in

20 the FERC’s requirement that power sales contract rates were required to be cost-

1 based. A typical unit contingent sale10 would have a demand charge based on the

2 ownership cost of the unit, and an energy charge based on its variable cost (fuel

3 plus some O&M). In general, under cost-based pricing, a firm purchase contract

4 would have separate demand and energy charges.

5 Over recent years, this cost-based pricing has given way to market based

6 pricing. This has resulted in development of new products, such as “5 by 16”

7 power blocks,11 where the price is on a pure per kWh basis. The prices for the

8 Company’s contracts discussed above (as well as the affiliated 30% River Bend

9 purchase contract) were for the most part pure energy (per kWh) based prices.12

10Q. Are there regulatory implications of this situation?

11A. Yes. The fuel rule expressly prohibits recovery of demand or capacity costs for

12 purchased power as part of eligible fuel.13 The purpose of this type of rule is to

13 prevent double recovery of the costs of generating capacity.

14Q. Please explain that last statement.

15A. Base rates recover some of the costs of electric power, while the remainder are

210 This is a sale where one party effectively leases the output of a specific generator for a 3 period of time from the generator’s owner. The availability of energy in the sale is contingent on 4 the plant being available to operate. 511 This is a purchase of power for the peak 16 hours of the 5 week days. 612 The exception was PECO, which had a small demand charge. 713The fuel rule states as follows: §25.236.Recovery of Fuel Costs 8 (a) Eligible fuel expenses. Eligible fuel expenses include expenses properly recorded in the 9 Federal Energy Regulatory Commission Uniform System of Accounts, numbers 501, 503, 518, 10 536, 547, 555, and 565, as modified in this subsection, as of April 1, 1997, and the items specified 11 in paragraph (7) of this subsection. Any later amendments to the System of Accounts are not 12 incorporated into this subsection. Subject to the commission finding special circumstances under 13 paragraph (6) of this subsection, eligible fuel expenses are limited to: 14 . . . . 15 (4) For Account 555, the electric utility may not recover demand or capacity costs. 16 17 Randall J. Falkenberg – Direct Testimony 18 SOAH Docket No. 473-01-1634 19 PUC Docket No. 23550 20 Page 14 of 92 1

1 recovered in a fuel and purchased power cost recovery factor. Fuel costs were

2 afforded “pass-through” recovery in the past because they were considered to be

3 more volatile in nature. For example, gas prices vary substantially over time, and

4 it is advantageous for the utility to recover such highly fluctuating costs in a fuel

5 recovery process. The same would be true of the fuel component of purchased

6 power, as it could fluctuate as much as the underlying fuel costs. It is important

7 to recognize that this fluctuation in cost is the primary reason for a fuel

8 reconciliation and pass-through process.

9Q. Does load growth impact the issue of pass-through versus base rate

10 recovery?

11A. Yes. Base rates are designed to collect all the remaining costs of the utility (non-

12 fuel costs and costs other than the fuel component of purchased power). For base

13 rates, to the extent that load grows, revenues grow as well. When the utility

14 needs to acquire additional resources to serve increased load, then that cost is a-

15 priori offset by the increase in revenues. In the case of fuel, however, load growth

16 does not have a major effect on average (per unit) fuel costs. Rather, fuel costs

17 can fluctuate independently of load growth. This is why fuel (or the fuel

18 component of purchased power) is recovered separately.

19 The reason for the prohibition against the inclusion of demand or capacity

20 costs in the fuel rule is that there is already a provision for recovery of these costs

21 in base rates. To the extent that load grows, the revenues associated with the

1 resulting costs grow as well. If demand or capacity related purchased power costs

2 are allowed in the fuel recovery process, there is a real danger of collecting the

3 same costs twice. Given the historical fact that most firm power contracts had

4 both a demand and an energy component, this was not a terribly complex issue for

5 regulators to deal with.

6Q. Has that situation now changed?

7A. Yes. In the case at hand, the changes in the market play a role. Many of the

8 power contracts (even firm contracts) available now do not have a separately

9 stated demand charge. No doubt for this reason, EGSI has included as part of

10 eligible fuel all cost for the purchased power contracts discussed above (save for

11 the small demand charge associated with the PECO contract.) However, it is

12 clear that these contracts represent firm capacity resource additions. Thus, they

13 provide value above and beyond the pure supply of non-firm energy. Therefore,

14 some portion of the cost of these contracts should be excluded from eligible fuel,

15 as they represent capacity costs. The Company already recovers capacity costs in

16 its base rates. To the extent that load growth contributed to the need for these

17 contracts, the Company will enjoy revenue growth to offset those costs. This

18 means that if the capacity component of cost in these contracts is not isolated and

19 removed, customers will pay the same costs twice and the fuel rule will be

20 violated.

21Q. Does the language of the fuel rule permit recovery of these costs so long as

22 they are stated on a per kWh basis in the contract?

1A. No. As quoted above in the footnote, the fuel rule states that “For Account

2 555, the electric utility may not recover demand or capacity costs.”14 This

3 language does not say that only “demand charges” (which historically were stated

4 on a per kW basis) were ineligible. Instead the prohibitive language is broad,

5 encompassing any type of demand or capacity cost. Clearly, for the company to

6 rely on these additional resources for purposes of providing service reliability,

7 there is a component of cost related to capacity and not just energy.

8Q. Please distinguish between “capacity” and “energy” costs in this context.

9A. Energy is the ability to do useful work. It powers the air conditioner, television or

10 personal computer. Capacity is the ability to obtain that energy at any time

11 desired. This is much like the difference between the mile driven by a car (which

12 requires fuel) and the availability of the car (which requires an investment or lease

13 payment). Energy costs are like fuel costs for a car, while capacity costs are like

14 the cost of owning a car. For purchased power, the situation used to be more like

15 a rental car, where a lease payment was made (usually on a per diem basis) and

16 the customer provided (or was charged separately on a per mile basis) for gas.

17 Under the current market, purchased power is more like cab fare. Some of the

18 cab fare recovers the cost of owning and driving the car, while some recovers the

19 cost of gasoline. Just because the cab fare may be based on a per-mile charge, it

20 does not mean that only fuel costs are being collected by the cab’s owner.

214 FERC Account 555 is entitled “Purchased Power.” 3 Randall J. Falkenberg – Direct Testimony 4 SOAH Docket No. 473-01-1634 5 PUC Docket No. 23550 6 Page 17 of 92 1

1Q. How do you recommend that this issue be addressed?

2A. The Company has not requested, or even attempted to justify a good cause

3 exception from the fuel rule to allow recovery of these costs in this case.

4 Furthermore, a good cause exception would only be justified under a very narrow

5 set of circumstances. In addition, the good cause exception language of the Texas

6 fuel rule appears to apply only to purchases related to fuel costs, not purchased

7 power.15 For this reason, and to avoid the double collection problem, I

8 recommend that the capacity component of the summer 2000 purchase contracts

9 be identified and disallowed.

10Q. How do you propose to determine that cost component?

11A. I propose to use a 24/76 split between capacity and energy, for reasons I will

12 discuss shortly. Exhibit RJF/3 shows that based on this split, $9.572 million

13 should be removed from EGSI’s Total Company eligible fuel balance.

14Q. Have other regulatory Commissions dealt with this issue?

15A. Yes. In Docket No. U-24889,16 the Louisiana Public Service Commission

16 considered the issue of allocation of costs for these same contracts between

17 capacity and energy for fuel clause recovery purposes. The Louisiana

18 Commission found on pages 22-23 of its Order as follows:

19 “a. The Commission accepts the conclusion reached by Staff and LEUG17 and 20 not disputed by the Companies, that the week-day, on-peak ‘energy only’ 21 contracts have a capacity component due to the reliability and firmness of

215 This will be discussed later as it related to the EGSI request for good cause exception for 3 the affiliated River Bend purchases. 416 In Re: Joint Application Of Entergy Louisiana, Inc. and Entergy Gulf States, Inc. For 5 Authorization to Participate In Contracts For The Purchase Of Capacity And Electric Power For 6 the Summer of 2000. 717 Louisiana Energy Users Group, an industrial consumer association. 8 Randall J. Falkenberg – Direct Testimony 9 SOAH Docket No. 473-01-1634 10 PUC Docket No. 23550 11 Page 18 of 92 1

1 supply they provide, despite the fact that the contracts do not state a 2 capacity charge. 3 4 b. Having recognized the existence of a capacity component in the on-peak 5 week-day “energy only” contracts, we further conclude that the capacity 6 component of those contracts are not recoverable though the FAC… 7 8 . . . . 9 10 c. In accordance with our conclusion that a 34/66 capacity/energy split is 11 appropriate with regard to the on-peak week-day portion of the costs of the 12 “energy only” contracts, we conclude that $11.1 million should be removed 13 from ELI’s FAC and assigned to base rates for purposes of next year’s 14 Formula Rate Plan proceeding, and that $36 million should be removed from 15 EGS’ FAC and assigned to base rate recovery in EGS’ next earnings review 16 proceeding.” 17 18 Q. The footnote in the above discussion indicates that the Louisiana proceeding

19 was pursuant to an application of Entergy companies for approval of these

20 contracts. Did EGSI make any such application in Texas?

21A. No. Based on its response to Staff 3-DGA-1818 the Company did not do so,

22 because it did not believe it was required under either PURA or the Commission’s

23 rules. Had the Company done so, there might have been an opportunity to

24 explore this issue on a prospective, rather than retrospective basis.

25Q. Does Entergy now accept the principle that these types of purchases have

26 both a capacity and energy component?

27A. Yes. In testimony filed in Louisiana Docket No. U-25533, Mr. Bruce M.

28 Louiselle, expert witness for Entergy Louisiana and Entergy Gulf States, revealed

29 that the Entergy System Operating Committee now has determined that these kind

30 of energy only purchases contain a capacity component. This impacts the

218 Attachment No. 4. 3 Randall J. Falkenberg – Direct Testimony 4 SOAH Docket No. 473-01-1634 5 PUC Docket No. 23550 6 Page 19 of 92 1

1 allocation of costs on the Entergy System because it affects the cost allocated in

2 MSS-1 and MSS-3 (tariffs that are governed by the Entergy System Agreement.)

3 Mr. Louiselle testified as follows:

4 “Q. HAS THE SYSTEM RESOLVED THESE ISSUES FOR 2001? 5 A. The Operating Committee has determined that those summer 2001 6 energy-only purchases for the on-peak period (i.e., for the period 7 6:00 a.m. to 10:00 p.m. on weekdays) contain a capacity 8 component. The Operating Committtee has also determined that 9 the portion of the cost of those purchases that appropriately is 10 allocated to capacity is best estimated at 24%.”19 11 12Q. Do you agree with these conclusions? 13 14A. Yes. I do.

15Q. Do you agree with the 24/76 split between capacity and energy?

16A. I believe it is quite conservative. Indeed, Mr. Louiselle demonstrated in his

17 testimony that the capacity component could be as high as 41%. In the earlier [U-

18 24889] Louisiana proceeding, the expert for the LPSC Staff20 also estimated the

19 capacity component was between 40% and 60%. As the Louisiana order quoted

20 above shows, the LPSC used 34%. Nonetheless, I am satisfied to use the 24%

21 figure in this case as the minimum capacity component of the energy-only on-peak

22 purchases. The 24/76 split is now accepted by the Entergy Operating Committee.

23 By using it, we can eliminate at least one source of controversy in this case.

219 See Attachment 6 320Mr. Mathew I. Kahal. 4 Randall J. Falkenberg – Direct Testimony 5 SOAH Docket No. 473-01-1634 6 PUC Docket No. 23550 7 Page 20 of 92 1

1 V. GOOD CAUSE EXCEPTION FOR RIVER BEND PURCHASE

2Q. Does the discussion in the preceding section also have a bearing on the EGSI

3 request for a good cause exception from the fuel rule as related to the River

4 Bend (unregulated portion) purchase?

5A. Yes. The purchase of power from the 30% of River Bend formerly owned by

6 Cajun is also a case where the contract in question was for firm power (contingent

7 on the availability of River Bend) but the pricing was on an energy-only basis. In

8 addition to violating §25.236(a)(4) discussed above, the Company also requests a

9 waiver of §25.236(a)(1).21

10 In this case, providing recovery of a portion of the cost of this purchase is

11 “double-forbidden” under the fuel rule. In addition, the energy-only pricing

12 mechanism used might be additional evidence as to why the fuel rule does not

13 allow a profit on affiliate purchases.

14Q. Please explain.

15A. In this case, it was clearly at the discretion of Entergy as to how the price for the

16 transaction would be structured. If EGSI had used a separately stated demand

17 charge in the River Bend price, it would have obviously failed to qualify for

22125.236(a) (1) For any account, the electric utility may not recover, as part of eligible fuel expense, costs 3incurred after fuel is delivered to the generating plant site, for example, but not limited to, operation and 4maintenance expenses at generating plants, costs of maintaining and storing inventories of fuel at the 5generating plant site, unloading and fuel handling costs at the generating plant, and expenses associated 6with the disposal of fuel combustion residuals. Further, the electric utility may not recover maintenance 7expenses and taxes on rail cars owned or leased by the electric utility, regardless of whether the expenses 8and taxes are incurred or charged before or after the fuel is delivered to the generating plant site. The 9electric utility may not recover an equity return or profit for an affiliate of the electric utility, regardless of 10whether the affiliate incurs or charges the equity return or profit before or after the fuel is delivered to the 11generating plant site. In addition, all affiliate payments must satisfy the Public Utility Regulatory Act 12(PURA) §36.058. 13 14 Randall J. Falkenberg – Direct Testimony 15 SOAH Docket No. 473-01-1634 16 PUC Docket No. 23550 17 Page 21 of 92 1

1 recovery under the fuel rules or procedures in both Louisiana and Texas. By

2 producing a contract with an energy-only price, the Company might have thought

3 it would have a better chance at obtaining full recovery in both states.

4Q. How do you respond to the claim made by the Company that it deserves

5 recovery of these costs, on the basis of a good cause exception to the rule?

6A. First, the Company has only requested a good cause exception to §25.236(a)(1)

7 (which forbids an equity return component on affiliate transactions) and not from

8 §25.236(a)(4)(which denies recovery of capacity costs). Thus, the implicit

9 capacity component still would not be eligible for recovery. The discussion

10 above, I think, also illustrates the great danger involved in allowing and

11 encouraging affiliate transactions. Even in cases where the overall price of

12 service from an affiliate is argued to be reasonable, the pricing mechanism can be

13 manipulated (as in this case) to facilitate cost recovery where it might not

14 otherwise occur.

15 In addition, there is always the question of whether the affiliate purchase

16 was needed at all, even if the price is attractive. The Company argues the

17 purchase was needed, but I submit there is a very high burden of proof to meet in

18 the case of affiliate purchases. Thus, the Commission should not grant a waiver

19 in this case.

20Q. What does the fuel rule say about the requirements for a good cause

21 exception?

22A. §25.236(a)(6) states as follows:

23 §25.236(a)(6) Upon demonstration that such treatment is justified by 24 special circumstances, an electric utility may recover as eligible fuel 2 Randall J. Falkenberg – Direct Testimony 3 SOAH Docket No. 473-01-1634 4 PUC Docket No. 23550 5 Page 22 of 92 1

1 expenses fuel or fuel related expenses otherwise excluded in paragraphs (1) 2 - (5) of this subsection. In determining whether special circumstances exist, 3 the commission shall consider, in addition to other factors developed in the 4 record of the reconciliation proceeding, whether the fuel expense or 5 transaction giving rise to the ineligible fuel expense resulted in, or is 6 reasonably expected to result in, increased reliability of supply or lower fuel 7 expenses than would otherwise be the case, and that such benefits received 8 or expected to be received by ratepayers exceed the costs that ratepayers 9 otherwise would have paid or otherwise would reasonably expect to pay. 10 11 This language clearly sets a high standard for granting a good cause exception to

12 the fuel rule. In the case of an affiliate transaction, I would suggest the “bar” is

13 even higher because of the great potential for abuse of these kinds of situations.

14 In addition, I think a fair interpretation of the language above would suggest that

15 exceptions are to be granted in cases where the reliability of fuel supply or lower

16 fuel expenses resulted. In the case at hand, there was no showing that the River

17 Bend purchase increased the reliability of fuel supply or lowered the average (per

18 unit) cost of fuel. In other words, it appears that the good cause exception rule

19 may apply only to fuel, not purchased power.22

20 Further, it should be recognized that the Company is required to provide

21 service at least cost. Simply obtaining resources at an alleged “low” price is not

22 sufficient to obtain a waiver from the fuel rule. That is part of the ordinary course

23 of business that should be expected from a monopoly supplier. There has been no

24 showing made by the Company that the option of purchasing power from any

25 source was lower in cost than the option of building new capacity, for example.

26 All things considered, I recommend denial of EGSI’s request for a good cause

222 Examples of recent cases where utilities have requested good cause exceptions for costs 3 related to fuel or fuel supply include the cost of contract renegotiations (such as in SPS Case No. 4 19512) or the cost of building a rail spur (as in HL&P Case No. 18753). In these cases, the non- 5 eligible costs were argued to reduce fuel costs (on a per unit basis) and/or increase the reliability 6 of supply. 7 Randall J. Falkenberg – Direct Testimony 8 SOAH Docket No. 473-01-1634 9 PUC Docket No. 23550 10 Page 23 of 92 1

1 exception to the fuel rule. As shown on Exhibit RJF/3, this results in a

2 disallowance of $6.349 million from the EGSI request.23

3Q. Does this conclude your testimony?

4A. Yes.

223 See Attachment No. 5, EGSI’s response to Staff-5-SIL-21. 3 Randall J. Falkenberg – Direct Testimony 4 SOAH Docket No. 473-01-1634 5 PUC Docket No. 23550 6 Page 24 of 92