SOAH DOCKET NO. 473-00-1020

PUC DOCKET NO. 22355

APPLICATION OF RELIANT ENERGY,	§	BEFORE THE STATE OFFICE

INC. FOR APPROVAL OF UNBUNDLED	§

COST OF SERVICE RATE PURSUANT	§	OF

TO PURA § 39.201 AND PUBLIC	§

UTILITY COMMISSION	§

SUBSTANTIVE RULE § 25.344	§	ADMINISTRATIVE HEARINGS

Contact: Denise Hardcastle

Phone: (713) 207-5767

Fax: (713) 207-9840

November 14, 2000

TABLE OF CONTENTS

Description	Page

Applicant Reliant Energy, Incorporated's Initial Brief on ECOM Issues	3-76

Electronic Filename:

11-14 ECOM brief.wpd

Certificate of Service	79

Table of Contents

Description	Page

I.	Introduction	3

II.	Costs in the ECOM model	6

A.	Environmental cleanup costs	6

B.	STP operations and maintenance expense	11

C.	Coal/lignite price forecasts	13

D.	Classification of disputed expense as "Other Generation"

administrative and general expense and escalation of

administrative and general expenses	23

E.	Dayton gas storage facility	30

F.	Environmental operations and maintenance expense	32

G.	Tax issues (CTS, ITC, etc.)	34

H.	Economic viability/gas plant analysis	39

I.	Capital plant additions	41

J.	Mitigation obligations	43

K.	Rate of return	45

L.	Capital structure	50

III.	Revenues in the ECOM model	51

A.	Plant capacity factors	51

1.	Nuclear	51

2.	Coal/Lignite	54

B.	STP license extension	56

C.	Joint Operating Agreement	57

D.	Dispatch assumptions	59

E.	Reallocation of customers from industrial class to commercial class	63

F.	Excess earnings	65

G.	Redirected depreciation and excess earnings	71

IV.	Conclusion	76

Certificate of Service	79

SOAH DOCKET NO. 473-00-1020

PUC DOCKET NO. 22355

APPLICATION OF RELIANT ENERGY,	§	BEFORE THE STATE OFFICE

INC. FOR APPROVAL OF UNBUNDLED	§

COST OF SERVICE RATE PURSUANT	§	OF

TO PURA § 39.201 AND PUBLIC	§

UTILITY COMMISSION	§

SUBSTANTIVE RULE § 25.344	§	ADMINISTRATIVE HEARINGS

APPLICANT RELIANT ENERGY, INCORPORATED'S

INITIAL BRIEF ON ECOM ISSUES

Reliant Energy, Incorporated ("Reliant Energy" or "Company") files its Initial Brief on ECOM Issues in PUC Docket No. 22355, SOAH Docket No. 473-00-1020.

I. Introduction

In 1999 the Texas Legislature enacted landmark legislation deregulating parts of the electric industry and giving retail electric customers a choice of electric providers for the first time.1 That legislation, which originated as Senate Bill 7 ("SB 7"), allows utilities with generation assets whose market value is less than their net book value to recover those verifiable, non-mitigable "stranded costs" from ratepayers. See PURA § 39.001 (stating that one of the goals of the legislation is to "allow utilities with uneconomic generation-related assets and purchased power contracts to recover the reasonable excess costs over market of those assets and purchased power contracts").

To determine stranded costs, the Legislature adopted a process that includes an initial estimate and a final true-up. The initial estimate requires utilities identified in 1998 as having potentially stranded costs to calculate estimated stranded costs using the "ECOM model" developed by the Public Utility Commission ("Commission" or "PUC") in 1996.2 See PURA § 39.201(h); see generally Reliant Energy Ex. A-33. The final true-up is a market-based determination of stranded costs that will occur in 2004. See PURA § 39.262 (c). This docket involves the initial estimate – use of the ECOM model to calculate estimated stranded costs for purposes of setting a competition transition charge ("CTC").

The ECOM model consists of a series of linked Microsoft Excel spreadsheets that calculate stranded costs using specified inputs. Reliant Energy Ex. A-15 at 3. The Commission has generally prescribed the nature and value of many of the key inputs. Id. Other inputs are required to be company-specific inputs based on historical data. See PUC Docket No. 22344, Order No. 14 at 4.

The ECOM model estimates the difference between what generation revenues would have been under continued rate regulation and what generation revenues would be under competition. Reliant Energy Ex. A-17 at 3. In other words, the ECOM model estimates lost revenues resulting from the transition to competition. Id.; see also Staff Ex. 1 at 5.

Using the ECOM inputs dictated by the Commission, Reliant Energy calculated its estimated stranded costs to be approximately $15.78 million. See Reliant Energy Ex. A-39 at 1. Because it is not feasible to set a CTC based on that total, however, Reliant Energy is asking that the CTC be set at zero for the period from 2002 to 2004. Tr. at 580.

The Staff and Intervenors,3 on the other hand, claim that Reliant Energy has "negative" stranded costs; that is, they contend that the market value of Reliant Energy's generation assets exceeds the book value of those assets. Therefore, they seek a negative CTC or other adjustments that would reflect this purported negative ECOM.

For the reasons discussed in this brief, Reliant Energy believes that the Staff's and Intervenors' ECOM calculations are wrong, and that the ECOM number of $15.78 million, or potentially a greater number, is a more reasonable estimate of stranded costs.4 But even if the Staff and Intervenors were correct, a negative CTC is not permissible. In its November 10, 2000 Order in this docket, the Commissioners stated that "no CTC should be established in any of these UCOS dockets unless the ECOM model calculates a positive result for the subject utility." Order on Certified Issues at 8. Although the Commission discussed other measures such as ceasing or reversing redirected depreciation and excess earnings prior to 2004, those procedures are also improper, as Reliant Energy will explain in Section III.G. below.

Before addressing contested issues, however, Reliant Energy wants to make clear its position on stranded cost recovery. The Company's goal in the final true-up in 2004 is to recover the December 31, 2001 book value of generation assets, adjusted for the calculations in PURA §§ 39.262(d), 39.262(e) and 39.263. Should the market value be greater than that adjusted book value amount, Reliant Energy will not seek to retain the excess. Therefore, regardless of the amount of mitigation, market value or CTC, ratepayers will be made whole.

II. Costs in the ECOM Model

To compare the revenues under regulation with revenues under competition, as required by the ECOM model, it is necessary to calculate the costs that the Company would incur under each of those scenarios. See generally Reliant Energy Ex. A-31 at 61. The parties have raised the following issues concerning costs in the ECOM model.

A.	Environmental Cleanup Costs

In Order No. 14 in PUC Docket 22344, the Commission ruled that "PURA § 39.263 limits recovery of environmental cleanup costs in the UCOS proceedings to those costs incurred before January 1, 2002." Order No. 14 at 8. Consistent with that ruling, the Commission concluded that costs incurred before that date should be reflected in the ECOM costs:

[T]he Commission concludes that environmental cleanup costs incurred before January 1, 2002 should be reflected in the in setting [sic] the CTC in this proceeding.

The Commission also concludes that, as a matter of policy, utilities should be encouraged to clean up their plants sooner rather than later. This policy is consistent with the requirement in PURA § 39.263 that incurred costs can be recovered. An actual expenditure is however not required to meet this requirement. Although an estimate alone will not be enough to allow recovery, one backed up by invoices or some type of binding commitments should suffice.

Order No. 14 at 8-9 (emphasis added).

William G. Rice testified that Reliant Energy will have incurred $487 million in environmental cleanup costs by January 1, 2002. See Reliant Energy Ex. A-17 at 23 (stating that $487 million "is the amount that will actually be incurred by January 1, 2002"). In addition, Ernie McWilliams, Jr. testified at length about the firm commitments that Reliant Energy has for the $487 million of environmental costs, as required by Order No. 14. See Reliant Energy Ex. A-13 at 3-4; Reliant Energy Ex. A-14 at 3. No party even cross-examined Mr. McWilliams on that issue. Taken together, the testimony of Mr. Rice and Mr. McWilliams demonstrates conclusively that Reliant Energy has made firm commitments to incur the $487 million of environmental cleanup costs before January 1, 2002. See also OPC Ex. 5 at 23 (OPC witness Falkenberg conceding, "I do not dispute that the Company has firm commitments for $487 million total environmental cleanup costs").

The Staff also agreed that the $487 million should be included in Reliant Energy's ECOM costs. A September 14, 2000 memo from Staff member Brian Almon to Staff member Darryl Tietjen is attached to the Direct Testimony of Mr. Tietjen. That memo states, "I agree that Reliant's environmental cleanup cost of $487 million should be included in the ECOM analysis. This amount is discussed in Rice's and McWilliams' supplemental testimony as being incurred by 1/1/02." Staff Ex. 1 at 21. Therefore, that amount should be included in the ECOM costs.

Several Intervenors oppose inclusion of some or all of the $487 million in Reliant Energy's ECOM costs, but their arguments for doing so rest on erroneous and unreasonable interpretations of Order No. 14 and PURA § 39.263. First, TIEC, Houston, and OPC claim that Order No. 14 means the amounts for environmental cleanup costs must be spent by January 1, 2002. TIEC Ex. 1 at 16; Houston Ex. 8 at 38; OPC Ex. 5 at 22-23. Because Reliant Energy will not have spent all of the $487 million by that time, they argue, it cannot include the entire amount in the ECOM costs.

But Order No. 14 does not say that the environmental amounts must be spent before January 1, 2002. In fact, Order No. 14 expressly says that an actual expenditure is not required. The costs need only to have been incurred by that date. If the Commission had meant to say that the costs have to be spent, and not just incurred, by January 1, 2002, it would have said so. It did not.

The only way the Intervenors can maintain their erroneous argument in the face of Order No. 14 is to claim that the terms "incurred" and "spent" mean the same thing. See, e.g., Tr. at 360 (TIEC witness Iverson stating that Reliant Energy "will have had to have spent it by January 1st, 2002"); Tr. at 903. But that argument is directly contrary to the Commission's own interpretation of the word "incurred" in a similar context. PURA § 39.263(a) allows "capital costs incurred by an electric utility to improve air quality before January 1, 2002" to be included as net invested capital in the annual reports utilities must file. (Emphasis added). When it promulgated the rule implementing PURA § 39.263 in PUC Project No. 21406, the Commission specifically defined when environmental cleanup costs are "incurred": "For purposes of this section, the electric utility or affiliated power generation company has incurred costs if it has expended funds or has committed to expend funds under the terms of a written agreement." See 25 Tex. Reg. 9447, 9465 (2000) (emphasis added) (promulgating PUC Substantive Rule § 25.261).5 As the emphasized language indicates, the utility need not have actually spent funds; it incurs costs by "committing to expend funds under the terms of a written agreement." Thus, the Intervenors' argument contradicts the Commission's own interpretation of "incurred," as that term is used in PURA § 39.263(a). Because Reliant Energy has committed to expend the $487 million under the terms of written agreements, that amount should be included in the ECOM costs.

Moreover, the Commission has already considered and rejected the Intervenors' contention that "incurred" means "spent." In Project No. 21406, TIEC also argued that Rule 25.261 should be written to state that environmental cleanup costs are eligible for recovery only if the utility has actually expended the funds. 25 Tex. Reg. at 9458. The Commission rejected TIEC's argument: "The commission interprets the language of PURA § 39.263 to require only that costs be reasonably expected to be incurred in order to meet the statutory deadlines for 'incurring' costs." Id.

The Intervenors next complain that Reliant Energy should not have included the $487 million in the environmental cleanup costs because it did not perform the economic feasibility test outlined in PURA § 39.263(c). See OPC Ex. 1 at 21; Houston Ex. 8 at 36-39; Tr. at 356. That argument is clearly wrong.

First, Order No. 14 sets forth specific guidelines for including environmental cleanup costs in ECOM costs; a plant economic screening is not among them. Nor should it be, because the Plant Economic Adjustment mechanism in the ECOM model satisfies any economic screening analysis required.6 See Reliant Energy Ex. A-17 at 24-25; Tr. at 259 (Mr. Rice testifying, "The ECOM model performs its own cost benefit analysis through the plant economic adjustment mechanism."). It is also important to note that the ECOM instructions do not provide for an economic screening outside the Plant Economic Adjustment.

Second, the Intervenors' interpretation would make it impossible to include environmental cleanup costs in the ECOM total. As TIEC witness Katherine Iverson admitted on cross-
examination, companies such as Reliant Energy have not been able to file for approval of environmental costs because the PUC only recently approved PUC Substantive Rule 25.261, which establishes the procedures for implementation of PURA § 39.263. Tr. at 353, 359; see also 25 Tex. Reg. at 9447 (stating that Rule 25.261 "is necessary to implement" PURA § 39.263). Thus, no company has even been able to apply for approval of environmental costs, much less have those costs approved. If the Commission intended for it to be impossible for utilities to include environmental costs in the ECOM estimate, which is the logical result of the Intervenors' arguments, the Commission would not have needed to address environmental costs at all in either Order No. 14 or Section VIII of the UCOS-RFP instructions. See Reliant Energy Ex. A-14 at 4. Certainly the Commission would not have stated in Order No. 14 that "environmental cleanup costs incurred before January 1, 2002 should be reflected" in the ECOM total if it believed that it was impossible to include such costs in that ECOM total. Instead, the Commission reasonably presumed that the Plant Economic Adjustment would disallow uneconomic environmental investments.

If any further evidence is needed that the Commission did not intend to impose impossible conditions on recovery of environmental cleanup costs, the preamble to the order adopting PUC Substantive Rule 25.261 provides that evidence. In the preamble, the Commission expressly stated, "The provisions of the proposed rule do not preclude recovery of all or a portion of estimated environmental cleanup costs in the UCOS cases." 25 Tex. Reg. at 9460. The Commission also stated that including the reasonably estimated environmental cleanup costs in the initial CTC "would be consistent with the commission's rate filing package instructions for the UCOS cases and with the legislature's directive in PURA § 39.201(g) that the initial CTC be established based upon all reasonably forecasted stranded costs." Id.

It is also noteworthy that in that preamble the Commission rejected TIEC's attempt to delay recovery of all environmental cleanup costs until 2004. The language originally proposed for Rule 25.261 would have allowed recovery of environmental cleanup costs only in the 2004 true-up, and TIEC asked the Commission to retain that provision. See 25 Tex. Reg. at 9464 ("TIEC strongly supported the proposed rule's determination that environmental cleanup costs will only be eligible for stranded cost recovery during the ECOM true-up proceeding."). The Commission, however, rejected TIEC's arguments and changed the rule to allow recovery of environmental cleanup costs before 2004: "This rule does not prohibit recovery of estimated environmental cleanup costs through mechanisms other than the true-up." Id. Yet TIEC and other Intervenors are asking the ALJ to do exactly what the Commission refused to do – make it impossible for Reliant Energy to recover the environmental cleanup costs until 2004.

In addition to the legal reasons, the Intervenors' arguments contradict the policy articulated by the Commission in Order No. 14, which states that "as a matter of policy, utilities should be encouraged to clean up their plants sooner rather than later." Order No. 14 at 8. As noted above, the Intervenors' interpretation would discourage early cleanup because it would be impossible to include any environmental cleanup costs in the initial ECOM estimate.

For these reasons the Intervenors' strained arguments opposing the inclusion of the environmental cleanup costs in the ECOM total are erroneous, and the entire $487 million should be included in Reliant Energy's costs for ECOM purposes.

B.	STP Operations and Maintenance Expense

When Reliant Energy ran the ECOM model, it used the 1999 figure as the base year for operations and maintenance ("O&M") expense at the South Texas Project nuclear plant, in accordance with the ECOM filing instructions. See Reliant Energy Ex. A-17 at 18. For subsequent years, Reliant Energy increased that 1999 amount by the 1% escalation rate allowed by the Commission for nuclear O&M.

OPC and Houston claim that Reliant Energy should not have used the 1999 O&M amount because it was abnormally high. OPC Ex. 5 at 35; Houston Ex. 8 at 44. Instead, they claim that Reliant Energy should have used the lower 1998 amount. Id.; Tr. at 917-18. By assuming the 1998 O&M amount rather than the 1999 amount, OPC reduced the ECOM total by $274 million. Houston claims the adjustment should reduce the ECOM total by $100 million. Houston Ex. 8 at 44. Those reductions are erroneous.

The Commission's instructions for running the ECOM model require use of the 1999 O&M costs. Tr. at 918. Thus, if Reliant Energy had used the 1998 figure, as OPC and Houston contend was proper, Reliant Energy would have violated the ECOM filing instructions. OPC witness Randall Falkenberg admitted as much on cross-examination. See Tr. at 919.

Mr. Falkenberg nevertheless claims that Reliant Energy should have ignored the ECOM filing instructions because of the general duty to mitigate stranded costs in SB 7. Tr. at 919 ("I believe that the law that's written down in SB 7 takes precedence over the ECOM model instructions."). But that argument proves far too much. Under Mr. Falkenberg's reasoning, a utility would have to ignore the inputs required by the ECOM instructions any time the utility could imagine some other input that would yield a lower stranded cost number. Such an interpretation would destroy the Commission's efforts to create a standard ECOM model that can be used by all utilities and understood by all other parties.

Mr. Falkenberg's argument is also contrary to sound valuation practices because it attempts to isolate only one input that is favorable to Mr. Falkenberg's client and to adjust that single input. But Mr. Falkenberg ignores other costs that may have been abnormally low in 1999. In promulgating the ECOM model instructions, the Staff established a specific period to determine costs, thereby avoiding the type of "cherry-picking" that Mr. Falkenberg seeks to engage in by criticizing the use of 1999 data. It is improper to adjust one arguably aberrational cost without investigating and adjusting all other aberrational costs as well.

For these reasons, Reliant Energy correctly used the 1999 O&M costs for STP as the baseline to escalate those costs.

C.	Coal/Lignite Price Forecasts

Reliant Energy uses coal at two sites, the W. A. Parish plant and the Limestone plant. Reliant Energy Ex. A-5 at 3 and 9. The Parish plant is licensed to burn only low-sulfur Powder River Basin ("PRB") coal. Reliant Energy Ex. A-8 at 6. Although the Limestone plant burns lignite coal from an adjoining mine, the lignite contract ties the price of lignite to PRB coal, which can also be burned at Limestone. Tr. at 145-48. Five producers account for virtually all PRB production. Reliant Energy Ex. A-8 at 6. Only two railroads serve the PRB. Id. Of the two, only one serves the northern portion of the PRB. Reliant Energy Ex. A-8 at 6. No witness disputes these facts.

Reliant Energy witness C. J. Mitcham testified that the cost of coal is determined by two factors: the cost of the commodity itself and the cost of transportation from the PRB to Reliant Energy's plants. Reliant Energy Ex. A-5 at 6. While spot market coal accounts for 39% of Reliant Energy's volume of PRB coal, spot market purchases account for only 6% of the total delivered cost of PRB coal. Tr. at 1126-27. Reliant Energy currently buys most of its coal under long-term contracts. Id. All transportation from the PRB, which accounts for 75% of the delivered cost of spot coal, occurs pursuant to long-term contracts. Reliant Energy Ex. A-5 at 7; Tr. at 1127. Those long-term contracts generally run through 2009. Reliant Energy Ex. A-5 at 6. No witness disputes Reliant Energy's coal price forecast through 2009. See Houston Ex. 8 at 36 (Mr. Norwood recommending adjustment of forecast prices after 2009); OPC Ex. 5 at 26; GCCC Ex. 6 at 4 (Mr. Andersen recommending changes to HL&P's forecast "for years beyond 2009"); Staff Ex. 3 at 6 (stating that HL&P's forecast is reasonable for 2000 through 2009).

Ms. Mitcham also testified that application of an inflation escalator to current spot prices is no longer an appropriate method of forecasting coal prices. Reliant Energy Ex. A-5 at 4-5. Relying on her extensive experience and interaction with coal producers and rail transporters, Ms. Mitcham testified that coal producers and transporters will increase prices to capture the margin between current prices and the price at which utilities would dispatch gas-fired units instead of coal-fired units. Id. Ms. Mitcham's expertise as a coal and rail contract negotiator is unchallenged and unmatched by any other witness. The facts upon which Ms. Mitcham relies are essentially undisputed. The economic behavior she predicts, based upon those facts, is consistent with sound, recognized principles of economic theory. The arguments asserted against her forecast are based on inaccurate information and a paucity of actual expertise in the coal production and transportation markets. Finally, the alternative forecasts offered are unrealistic.

1.	Ms. Mitcham is by far the most qualified witness to testify regarding coal pricing practices and industry conditions.

Through her position as Reliant Energy's Vice President, Fuel & Energy Management, Ms. Mitcham has acquired considerable knowledge regarding the coal and rail transportation markets. She has conducted numerous coal supply and transportation negotiations. Tr. at 155-158. She is active in numerous coal and rail industry organizations and has worked closely with transporters and others on industry issues. Id. at 158-159. Staff witness Andy Curtis acknowledged Ms. Mitcham's knowledge of the industry and success as a manager of coal costs. Reliant Energy Ex. A-37 at 6-7.

In contrast, those who dispute her testimony have no such qualifications. Tr. at 437-439 (Andersen); Tr. at 585-586 (Norwood); Tr. at 872-875 (Falkenberg). Mr. Norwood and Mr. Falkenberg frankly confess their lack of expertise. See Tr. at 595 (Mr. Norwood admitting, "Quite frankly, I'm not what you would consider a fuels consultant or expert."); Tr. at 872 (Mr. Falkenberg answering "No" to the question, "But you are not an expert on the coal market, are you?"). Only staff witness Curtis actively monitors the coal industry through routine reading. Reliant Energy Ex A-37 at 5-6.

2.	The facts upon which Ms. Mitcham relies are essentially undisputed.

Most of the facts relied upon by Ms. Mitcham are either undisputed or actually agreed to by one or more witnesses. Ms. Mitcham testified that there now exists a significant margin between the price of coal-fired generation and the price of gas-fired generation. Reliant Energy Ex. A-5 at 5. No witness disputes this demonstrable fact. Indeed, while disputing the ability to do so, Staff witness Mr. Curtis acknowledged that coal producers "would certainly like to get the convergence price . . . ," (Staff Ex. 3 at 9), and that railroads determine their prices based upon "whatever the market would bear." Reliant Ex. A-37 at 18. No witness disputes Ms. Mitcham's calculation of the highest coal price at which Reliant Energy would continue to fully dispatch its Parish coal units ahead of available gas units. See Reliant Energy Ex. A-5 at 8 and Figure CJM-2S. The existence of the margin, Ms. Mitcham's definition of that margin, and the desire of coal producers and transporters to capture that margin are well established by the record.

Ms. Mitcham cites numerous characteristics of the coal production and transportation markets that will contribute to producers and transporters being able to capture much of the margin that undeniably exists. Both the production and transportation of coal are becoming highly concentrated. Reliant Energy Ex. A-8 at 6; Reliant Energy Ex. A-37 at 9 (Curtis deposition); Tr. at 877-878 (Falkenberg); Tr. at 442 (Anderson); Tr. at 599-600 (Norwood). In the PRB, five producers account for 97% of all production, four of those for 90% and the two largest for 60%. Reliant Energy Ex. 5 at 6. As noted above, only two railroads serve the PRB, and some customers have access to only one of those. Reliant Energy Ex. A-8 at 6. Ms. Mitcham testified that both coal producers and transporters have discussed with her the possibility of tying their prices in some way to electric power prices and that producers have stopped offering long-term contracts at current market prices. Reliant Energy Ex. A-5 at 5. These facts are confirmed by the sources relied on by Mr. Norwood and Mr. Falkenberg. The Electric Power Research Institute ("EPRI") study to which Mr. Norwood is a contributor is entitled "Railroad Consolidation and Market Power" and begins with the observation that the "railroad industry is shrinking into a handful of mega-carriers." Reliant Energy Ex. A-32 at iii. In its discussion of the BNSF, one of the two carriers serving the PRB, the EPRI Study notes, "BNSF already has experience in complex contracting. The railroad has entered into agreements where its pricing is based on off-system sales and gas prices . . . ." Id. at 5-20. A study by the U.S. Energy Information Agency (EIA), upon whom Mr. Falkenberg relies, describes the coal production industry as follows:

Western mines have consolidated reserves through mergers and buyouts . . . . Consolidation of reserves, concentration of companies, and even release of untimely leaseholds have marked the decade so far.

Reliant Energy Ex. A-35 at 9. The 2000 annual report of Peabody, one of the PRB coal producers, notes that Peabody has tied the price of coal to the price of power in some instances. Reliant A-26 at 4.

Ms. Mitcham's description of the factors driving coal producers and transporters to raise prices is also undisputed. Ms. Mitcham testified that the vast majority of Reliant Energy's coal supply is subject to long-term contracts at prices well above the spot market price of coal, but that these contracts will expire in and around 2009. Reliant Energy Ex. A-5 at 6. No other witness disputes this fact. It is also undisputed that PRB coal producers are currently subsidized by such above-market, long-term contracts. See Reliant Energy Ex. A-37 at 17-18. As one EIA study notes:

For the present, the remaining high-priced contracts negotiated in the late 1970s and early 1980s serve to subsidize operating costs, especially in the southern PRB in Wyoming. . . . [I]t is anticipated by some that PRB coal prices will have to rise as the last of the old contracts expire over the next few years.

Reliant Energy Ex. A-35 at 15.

Staff witness Mr. Curtis, the only other witness with any meaningful knowledge of the coal industry, recognizes many of the facts relied on by Ms. Mitcham. He acknowledges that utilities currently have higher than normal coal stockpiles. Reliant Energy Ex. A.-37 at 10 and 14-15. He acknowledges that PRB producers currently benefit from long-term contracts with prices as high as three or four times market prices. Id. at 17. Both of these facts support the conclusion that current spot prices are depressed. Mr. Curtis recognizes that producer productivity gains have "plateaued." Id. at 25-26. He notes that railroads have lacked capital resources necessary for investment in improvements, id. at 14, and that coal producers must invest in additional loading capability before they can expand production, id. at 31. These facts confirm the need of both coal producers and railroads for higher spot prices as above-market long-term contracts expire.

3.	Given the undisputed facts, Ms. Mitcham's testimony is consistent with sound economic theory.

Contrary to suggestions by some witnesses (see, e.g., GCCC Ex. 6 at 13), the pricing behavior described by Ms. Mitcham is entirely consistent with economic theory. Reliant Energy witness Mark E. Meitzen testified that "price leadership," whereby one seller establishes a price and other sellers follow suit, "is most likely to emerge when (a) the industry is tightly oligopolistic, (b) sellers' products are close substitutes, (c) cost curves are similar, (d) there are barriers to entry of new rivals, and (e) demand for the industry's output is relatively inelastic." Reliant Energy Ex. A-9 at 4-5. No party challenged Dr. Meitzen's description of price leadership or offered any credible economic testimony on the issue. Indeed, most of the cross-examination of Dr. Meitzen sought to adopt the price leadership behavior he described and apply it in other areas of the ECOM case.

Dr. Andersen, offered as an economist, did not dispute the price leadership theory described by Dr. Meitzen. Instead, he argued that it could not occur in the coal and rail industries. GCCC Ex. 6 at 13-14. As described below, his testimony on this point is founded on his erroneous assumptions that there are roughly 100 PRB producers (as opposed to five) and that antitrust laws afford protections that he later admitted do not exist.

Indeed, Mr. Meitzen's theory finds support in the record evidence. The EPRI Study listed by Mr. Norwood among his qualifications states, "Reducing the number of players makes possible price 'coordination' in a more stable, but less competitive market." Reliant Energy Ex. 32 at 1-4. Given the consolidation of PRB producers and transporters, the increasing demand for low-sulfur PRB coal, and the large investment necessary for new entrants, it is very reasonable to suggest that producers and transporters will engage in price leadership or coordination in an effort to secure available margins. Indeed, the EPRI Study notes that railroads are currently more focused on building margins than market share. Id. at iv. Similarly, the Bear, Stearns & Co. Inc. Equity Research report produced by Ms. Mitcham concludes:

[F]urther industry consolidation and a shifting ownership structure should focus producers toward profitability rather than market share. Coal should benefit from a heightened attention to fuel input costs within a deregulated power market.

Reliant A-27 at 3. Ms. Mitcham's testimony, in combination with the undisputed economic testimony of Dr. Meitzen, clearly comports with reasonable economic theory.

4.	Intervenors' efforts to counter Ms. Mitcham's testimony are unreliable because they are based on inaccurate and incomplete understanding of the facts.

While Dr. Andersen claimed to be qualified to testify regarding antitrust law and policy, (GCCC Ex. 6 at 13), his testimony was so fraught with inaccuracies and misstatements as to lose all credibility. Dr. Andersen's testimony assumed that the "market for coal is national." Id. at 13. Of course, it is not. Reliant Energy is limited to using PRB coal. Reliant Energy Ex. A-5 at 5-6. Nor are there "a relatively large number of coal producers," as Dr. Andersen asserts. GCCC Ex. 6 at 13. As discussed above, five producers account for 97% of all production in the PRB; four of those account for 90% of all production and the two largest for 60%. Reliant Energy Ex. A-5 at 6. On cross-examination, Dr. Andersen admitted that he was unfamiliar with these facts. Tr. at 440-442. Moreover, Dr. Andersen was unaware that the Limestone plant is served by only one railroad. Id. at 462. Dr. Andersen also testified that U.S. antitrust laws would prevent price leadership among coal producers and transporters. GCCC Ex. 6 at 13. On cross-examination, however, he confirmed that the railroads are immune from some antitrust laws, but that he "didn't think of it at the time that the testimony was prepared." Tr. at 465. Consequently, when Dr. Andersen himself testified that Ms. Mitcham's price theory might be achieved by "a sweeping consolidation of the coal industry" but that such a consolidation "would likely violate the Clayton Act," it is impossible to escape the conclusion that, without his knowledge and despite the Clayton Act, exactly such a consolidation has occurred. In short, Dr. Andersen admitted that the assumptions upon which his conclusions are based are inaccurate, but he nevertheless continued to assert the same conclusion. Dr. Andersen's mistakes and inaccuracies overwhelm any possible credibility for his testimony.

Like Dr. Andersen, Mr. Falkenberg's argument concerning market theory is seriously undermined by his misstatements regarding coal markets. He places heavy reliance on the Surface Transportation Board for rail price regulation. OPC Ex. 5 at 25. He was unfamiliar, however, with the pricing dominance formula that forms the basis for STB regulation and makes challenges by shippers very difficult. Tr. at 877; see Reliant Energy Ex. A-8 at 6-7. Mr. Falkenberg's confidence in supply and demand rests on two additional mistaken assumptions. First, Mr. Falkenberg asserts a "decline in use of coal for electric power generation." OPC Ex. 5 at 25. While there may or may not be some decline in overall reliance on coal, the demand for relatively clean PRB coal is likely to increase. Reliant Energy Ex. A-36 at 84 (EIA Annual Energy Outlook 2000, Figure 109); Reliant Energy Ex. A-27 at 4 (Bear Stearns report). Mr. Falkenberg also posits that "the tendency to improve coal mining productivity will continue to produce soft prices." OPC Ex. 5 at 25. Improvements in productivity require capital investment. As discussed above, suppliers are relying on long-term, above market contracts to supply that capital, and most of those long-term contracts will expire over the next ten years. In the absence of those contracts, any improvement in productivity will require significantly higher spot prices to fund capital improvements. Reliant Energy Ex. 8 at 12. Even assuming higher rates of productivity in PRB mines, supply is further constrained by available railcar loading and terminal facilities. See id.; Reliant Energy Ex. A-37 at 22. As recently as last spring, the mine that supplies roughly half of Reliant Energy's PRB coal needs reached full capacity on its loading facilities. Reliant Energy Ex. 8 at 12. Mr. Falkenberg's testimony is little more than a regurgitation of past pricing methodologies propped up by incomplete and inaccurate notions of how coal supply and transportation markets operate.

Mr. Norwood's criticism of Ms. Mitcham's testimony is no more complex than the assertion that it produces higher projected prices than past forecasts. Houston Ex. 8 at 34-35.

My point is a very simple, basic point. She's assuming that the spot price of coal, which is now a dollar by her testimony, is going to be over $2 in 2010, and no other Texas utility is predicting that – or even close to that. It's about three times the growth projected by your counterparts. I just think that's an unfounded, unrealistic and inconsistent assumption.

Tr. at 685. Such criticism says nothing regarding the merits of Ms. Mitcham's pricing theory and simply ridicules – without answering – her original contention that the past is a poor predictor of future coal prices. Reliant Energy Ex. A-5 at 4.

While acknowledging their incentive to do so, Mr. Curtis objects that, in his view, "neither the coal miners nor the railroads can dictate prices" to the extent Ms. Mitcham predicts. Staff Ex. 3 at 9. He cites a recent article noting that producers have been unable to raise prices by attempting to constrain supply. Id. at 9-10. Until long-term, above-market contracts begin to expire, however, the real incentive for miners to exercise pricing discipline does not exist. He also suggests that if Ms. Mitcham's convergence theory were truly viable, someone would already be buying coal under such arrangements. Id. at 10. In fact, however, they are. As noted above, the President of Peabody COALTRADE boasts that her company has tied the price of coal to the price of power. Reliant A-26 at 4. Furthermore Ms. Mitcham testified that she personally negotiated with the BNSF Railroad for an indexed rate and was told by them that the number of requests for such a rate structure has increased dramatically and that several contracts have been executed over the last year. Reliant Energy Ex. A-8 at 16. The idea is not only viable; it is a reality. This new pricing strategy is not driven solely by the needs of coal suppliers and carriers. The new pricing strategies address buyers' concerns as well. Id. Specifically, power generators in a deregulated market are willing to tie coal prices to gas prices in order to minimize risk and lock in margins. Id.

5.	Intervenors' price forecasts are simply unrealistic.

Intervenor witnesses characterize the increased coal price forecast by Ms. Mitcham as unrealistic. Yet these same witnesses would have the Commission assume a 40-year period with no significant increase in coal prices. Tr. at 461 (Andersen). As an alternative, Intervenors offer nothing more than a "business-as-usual" forecasting method; but they cannot rebut Ms. Mitcham's testimony that business will soon be far from usual. Moreover, the method they advocate to predict prices 20 years from now has been a poor predictor in the past. Indeed, Dr. Andersen readily admits that application to 1980 coal prices of an escalator like that proposed by Intervenors would not have produced an accurate forecast of current prices. The Intervenors' method is also inconsistent with the expressed and observed desire of both coal producers and transporters to shift their focus from market share to margins. Finally, the Intervenors' forecasts simply ignore the undeniable expiration of long-term contracts at the end of this decade. They assume that coal producers will be willing and able to stand idly by while their revenues plummet. The undisputed evidence regarding market concentration and the need of both producers and transporters for infusions of capital indicate otherwise.

For all of the reasons cited above, Reliant Energy's coal forecast is reasonable and appropriate for use in the ECOM model.

D.	Classification of Disputed Expense as "Other Generation" Administrative and General Expense and Escalation of Administrative and General Expenses

Before 1999 Reliant Energy classified certain fixed expenses as administrative and general ("A&G") expenses. Reliant Energy Ex. A-17 at 9. After reviewing FERC accounting rules and definitions in 1999, Reliant Energy reclassified those fixed expenses to the O&M category, although that reclassification did not change the nature of the expenses, which continued to be fixed rather than variable.7 Id.

When Reliant Energy filed its Schedules II-D-1 and II-D-2 of the Rate Filing Package in this docket in March 2000, these fixed expenses were reflected in the O&M category into which they had been reclassified in 1999, for a total O&M expense of $338.7 million. See Reliant Energy Ex. A-25 at 2241. For purposes of ECOM and its distinct treatment of fixed versus variable expenses, however, Reliant Energy returned $81.48 million of fixed expenses to the A&G category to reflect the true nature of those expenses. Id. at 8. Accordingly, when Reliant Energy ran its ECOM model, it included $257.25 million as variable O&M expenses for generation plant and $81.48 million as fixed A&G expenses for generation plant. See Reliant Energy Ex. A-39 at 10 (Part V contains O&M expense and Part VII contains A&G expense).

The distinction between fixed and variable expenses is important because only variable expenses are subject to the Plant Economic Adjustment. The Staff discussion of the 1996 order establishing the ECOM model noted that the "Plant Economics" tab of the model "calculates, by resource type, the fixed and variable components of generation costs . . . for each year of the forecast period." See Reliant Energy Ex. A-33 at 23 (emphasis added). To determine whether a particular asset group (e.g., nuclear plant) is economical, the revenues attributable to that asset group "are compared to the variable costs of operating the asset group during each year of the forecast period." Id. The fixed costs are not compared to revenues under the Plant Economic Adjustment. Thus, fixed and variable costs must be treated separately. See also id. at 20 (noting that the ECOM model separates fixed from variable costs of generation).

The expenses that Reliant Energy reclassified to the "Other Generation" A&G category for ECOM purposes included administrative, fuel and energy management, planning and accounting, shared services and corporate overhead expenses. See Reliant Energy Ex. A-17 at 11. It is clear that those expenses are fixed, rather than variable. Salaries of fuel purchasers, for example, do not vary with a particular plant's output. See Tr. at 385 (Ms. Iverson admitting that accounting salaries do not vary with generation output); id. at 932 (Mr. Falkenberg admitting the same). Nor does corporate overhead increase or decrease simply because a plant's output changes. Therefore, those expenses are fixed and should not be included in the Plant Economic Adjustment mechanism. Id. at 10. Further, because the only resource type exempt from the Plant Economic Adjustment is the "Other Generation" category, Reliant Energy properly classified the expenses in the "Other Generation" category.

Several of the Intervenors have criticized Reliant Energy for allocating the $81.48 million of fixed expenses to the A&G category of the ECOM model. See, e.g., TIEC Ex. 1 at 7; Houston Ex. 8 at 32; OPC Ex. 5 at 40-41. They have also complained because Reliant Energy included those fixed expenses in the "Other Generation" category of the model, rather than including them in the fuel-type categories. See TIEC Ex. 1 at 7. Finally, they have argued that Reliant Energy erred by escalating that amount through 2028, rather than reducing it as plants retire. TIEC Ex. 1 at 9. Each of those criticisms is misplaced.

First, the allocation of the $81.48 million to A&G is proper for the reason set forth above – the amount represents fixed costs, not variable costs. Reliant Energy allocated those costs to "Other Generation" rather than to particular fuel types for the same reason: The "Other Generation" category of expenses is not considered in the Plant Economic Adjustment calculations, and thus is an appropriate place to include costs that are fixed rather than variable. Conversely, expenses for specified fuel types (Gas/Oil, Coal/Lignite, Nuclear) are variable and accordingly are subject to the Plant Economic Adjustment.

The Intervenors suggest that all operating costs are variable. See Tr. at 386. That is simply not true. As discussed above, costs such as salaries and corporate overhead do not vary with output. Indeed, the Commission recognized in the 1996 report issued as part of the ECOM development process that "[i]nclusion of specific cost categories in fixed costs is a matter of interpretation." Reliant Energy Ex. A-33 at 16.

The Intervenors also argue that it is inappropriate to classify the $81.48 million of fixed expenses as "Other Generation" because that category is reserved for "resource types." See Tr. at 382 (Ms. Iverson testifying, "I really know that other generation is intend[ed] to be a resource type."). But the Merriam Webster's Collegiate Dictionary defines "resource" as a "source of supply or support." Id. at 383 (emphasis added). The expenses that Reliant Energy has placed within "Other Generation" are clearly related to support functions and therefore are resources. Thus, they are properly included within "Other Generation." Moreover, "Other Generation" is the only category that is not subject to the Plant Economic Adjustment, and thus is the only place that fixed A&G costs could be included in the model.

Ms. Iverson and other Intervenor witnesses nevertheless claim that the Other Generation category can include only "resource types" such as wind and hydro. See Tr at 379 (TIEC witness Ms. Iverson: "It could include hydro. It could include wind"); Houston Ex. 8 at 8. They have no authority for that position, however, and even OPC witness Randall Falkenberg testified to the contrary on cross-examination:

Q.	What is your understanding [of] what other generation means?

A.	It's my understanding that that is things like the accounting – the accountant that we talked about, people who are purchasing fuels, certain engineering support functions, that sort of thing.

Tr. at 933-34.

Moreover, hydro and wind facilities are "plants," as Ms. Iverson admitted on cross-
examination. Tr. at 378. Yet placing them in the "Other Generation" category would exempt them from the Plant Economic Adjustment completely. Id. at 379. Thus, under Intervenors' argument, a utility with a wind or hydro plant could make hundreds of millions of dollars of uneconomic investment in the plant, and it would never go through the Plant Economic Adjustment. Ms. Iverson admitted as much, and she further agreed that such a result is illogical.8 Id. at 380-81. Yet she is asking the ALJ to accept her argument anyway. Reliant Energy, on the other hand, submits that the only logical interpretation of the ECOM model is to assume that the "Other Generation" category is the proper place to capture fixed costs that the ECOM model excludes from the Plant Economic Adjustment. See Tr. at 1284 (Mr. Rice testifying, "The fact that the other generation does not go through the plant economic adjustment clearly indicates that it's not considered to be a plant.").

The Intervenors next complain that the A&G expenses are not reduced as plants are retired. See, e.g., TIEC Ex. 1 at 12. Thus, they argue, the A&G total is disproportionately large in the later years of the ECOM model. It is true that the Commission could have provided for reduction of Other Generation expenses as plants are retired, but it did not do so. By the same token, the Commission could have reduced the $500/kW capital cost assumption for combined cycle plants to reflect the fact that current costs are lower or to reflect anticipated technological improvements that will likely lower that capital cost in future years. See,.e.g., Reliant Energy Ex. A-15 at 9-11. But in fact the Commission did not make either of the adjustments. If the Intervenors want to adjust one of the ECOM model features because it has the effect of decreasing stranded costs, it is also appropriate to adjust those features that effectively increase stranded costs. In both cases, the result would be a change in the ECOM model, which the Commission has not allowed.

By definition and design the ECOM model is a compromise between a simple, easy to use model and a more complex, realistic depiction of the world. See Reliant Energy Ex. A-33 at 8 (stating that in creating the model the Staff tried to balance "ease of implementation and administration, level of precision, comprehensibility, and availability of data"). The escalation of A&G costs is simply an example of one area in which the model's creators chose simplicity of administration rather than absolute precision.

Ms. Iverson mistakenly claims the Commission effectively ordered that A&G expenses be reduced as plants are retired by mandating in the 1998 Report that A&G expenses be escalated based on a dollars-per-megawatt-hour basis. See TIEC Ex. 1 at 13. But Ms. Iverson ignores the fact that the Legislature did not follow the 1998 Report with respect to escalation of O&M and A&G expenses. In PURA § 39.201(h), the Legislature dictated generally that the ECOM model referenced in the 1998 Report would be used to estimate stranded costs, but expressly excepted O&M and A&G escalation: "Growth rates in generating plant operations and maintenance costs and allocated administrative and general costs shall be benchmarked by comparing those costs to the best available information on cost trends for comparable generating plants." See PURA § 39.201(h). Consistent with that directive, the Commission has adopted new escalation rates for O&M and A&G. See Reliant Energy Ex. A-33 at 63 (requiring the use of escalation rates different from those in the 1998 ECOM Report); see also Tr. at 375 (Ms. Iverson agreeing that the A&G escalation rate was calculated on a basis other than the 1998 ECOM Report).

Moreover, in the ECOM instructions, the Commission did not require that A&G expenses be calculated on a dollars-per-megawatt-hour basis. See Reliant Energy Ex. A-31 at 63 (subsection "g"); Tr. at 375 (Ms. Iverson admitting that the filing instructions do not require A&G expenses to be calculated on a dollar per megawatt hour basis). Rather, the Commission simply stated in those instructions that generation A&G costs should be escalated by a rate derived from a weighted average of fuel types. Id.

Finally, an August 1999 memo prepared by Staff member Hal Hughes demonstrates that the Staff considered it appropriate to escalate A&G expenses on a total-dollar basis, rather than on the dollars-per-megawatt-hour basis advocated by Ms. Iverson. See Reliant Energy Ex. 30 at 58. Thus, Ms. Iverson's reliance on the 1998 Report is misplaced with respect to escalation of A&G expenses.

It is important to realize that the ECOM model is flawed in numerous respects. As Ms. Iverson noted when discussing the exclusion of "Other Generation" from the Plant Economic Adjustment, the ECOM model is not "logical," and "it could be improved." Tr. at 382. Reliant Energy agrees that the ECOM model is imperfect, and that it could be improved in several respects. But that simply raises the question of how to apply an imperfect model. Reliant Energy believes that it has followed the correct approach by including demonstrably fixed costs in the category that is not subject to the Plant Economic Adjustment, and by escalating those expenses in accordance with the ECOM model instructions. This allows variable costs to vary in accordance with the Plant Economic Adjustment calculations and allows fixed costs to remain fixed. The Intervenors, on the other hand, would create a fiction by assuming that fixed costs are variable and therefore subjecting them to disallowance under the Plant Economic Adjustment. Thus, the Intervenors would add new disallowance procedures that are not in the ECOM model instructions.

Reliant Energy properly included the $81.48 million of A&G expense in "Other Generation," and it escalated that expense in accordance with the ECOM instructions. Therefore, the proposed adjustments by OPC, Houston and TIEC are erroneous.

E.	Dayton Gas Storage Facility

The Dayton Gas Storage Facility ("Dayton") is an underground storage facility in which Reliant Energy stores natural gas. Reliant Energy Ex. A-17 at 18. It allows the Company to reduce its costs of gas by withdrawing gas from the facility during peak usage periods, while injecting gas during other periods of time. Id. at 19.

Reliant Energy does not own Dayton; instead, it stores gas at the facility pursuant to a lease arrangement. Id. The operator of Dayton is contractually bound to provide storage capacity through 2014, and Reliant Energy is bound to make annual payments of approximately $13 million to the operator. Id. Because the payments are fixed in nature, Reliant Energy included them as "Other Generation" expenses in the ECOM model. That treatment is appropriate, because Other Generation assets are not subject to the Plant Economic Adjustment. Id. at 19-20.

Despite the fixed nature of the Dayton expenses, Houston and GCCC argue that those expenses should be included as part of the Gas/Oil category of assets in the ECOM model, which is subject to the Plant Economic Adjustment. Houston Ex. 8 at 31-34; GCCC Ex. 6 at 14-15. But that proposed reclassification would erroneously transform fixed costs into variable costs and therefore would subject the costs to the Plant Economic Adjustment. To the extent the Plant Economic Adjustment disallowed any of the Dayton expenses, Reliant Energy would be unable to recover expenses that are truly fixed.9 See Reliant Energy Ex. A-17 at 20. As noted above in connection with A&G expenses, using the Plant Economic Adjustment to disallow fixed costs such as the Dayton facility contract cost is contrary to the logic of the ECOM model. See, e.g., Reliant Energy Ex. A-33 at 10 (stating in connection with natural gas costs that "[n]on-commodity costs . . . shall be identified separately and projected by the utility throughout the forecast period" (emphasis added)).

GCCC further argues that the Dayton costs should not be included in ECOM expenses because Reliant Energy has not accounted for any benefit from the facility. GCCC Ex. 6 at 15. Nothing in the ECOM instructions, however, provides that every cost must have a corresponding benefit. But even if those instructions did require a showing of some benefit, GCCC would be wrong. The Dayton facility benefits Reliant Energy by allowing it to realize the gas prices mandated by the Commission in Docket No. 22344. See Reliant Energy Ex. A-17 at 21. In other words, the ECOM model assumes a flat rate for gas, with no "swing" adder to reflect the premium that gas suppliers demand to provide gas that follows the variable load. By using gas stored at the Dayton facility, Reliant Energy can avoid paying a "swing" adder and therefore can presumably purchase gas at the price set in the ECOM model. Therefore, the benefits Reliant Energy receives from the Dayton facility are inherently reflected in the gas price forecast that was mandated for use in the ECOM model. Accordingly, GCCC's argument should be rejected.

The 1996 Order that led to the development of the ECOM model expressly states that "some other categories, such as contractual obligations for fuel and purchased power could be added to fixed costs," and that "those costs not classified in the general category 'fixed costs' fall into the general category of 'variable costs.'" Reliant Energy Ex. A-33 at 16.10 The Dayton facility is a fuel contractual obligation, and therefore is properly categorized as a fixed cost. See Reliant Energy Ex. A-17 at 20. Accordingly, the contentions that the Dayton facility costs should be excluded from the ECOM model are erroneous.

F.	Environmental Operations and Maintenance Expense

As discussed above in section II.A., Reliant Energy included in the ECOM amount $487 million for environmental cleanup costs authorized by PURA § 39.263(a) and Order No. 14. Along with that $487 million of environmental capital costs, Reliant Energy included $21 million to account for additional O&M costs associated with the capital equipment. See Reliant Energy Ex. A-17 at 25.

Including O&M expense for the environmental capital expenditures is necessary and appropriate because the installation of new equipment carries with it the obvious need for O&M expenses. If such expenses are not included, the equipment would be unable to run for any significant period of time, and the generating unit would fall out of compliance with environmental laws and regulations. Id. at 26. Moreover, the Commission has implicitly recognized that these O&M expenses are appropriate by allowing for O&M expenses generally to be included in the ECOM costs. It is important to note, however, that the environmental O&M expenses are treated as variable costs, meaning that they are subject to the Plant Economic Adjustment. Id. Therefore, they will be excluded to the extent a particular asset group is uneconomic under the ECOM model.

Despite the necessity for O&M on environmental equipment, TIEC and Houston have complained about Reliant Energy's inclusion of the O&M expense in the ECOM costs. See TIEC Ex. 1 at 15; Houston Ex. 8 at 39. Neither party's criticism has any merit.

TIEC argues that Reliant Energy's inclusion of environmental O&M expense is contrary to statements made by the Commission in PUC Project No. 21406. TIEC Ex. 1 at 15. As discussed above in section II.A., however, it is not necessary for utilities to apply for and obtain approval under PUC Substantive Rule 25.261 in order to include environmental cleanup costs in the initial estimate of stranded costs. See Reliant Energy Ex. A-17 at 5. Moreover, it would be patently unreasonable to apply Rule 25.261 to the ECOM calculation, because the rule is so new that no party has even been able to apply for approval. Reliant Energy submits that it is absurd to interpret statutes and rules in such a way that it would be impossible to satisfy them. See Tex. Gov't Code Ann. § 311.021 (Vernon 1998) (stating that in enacting a statute the Legislature is presumed to have intended a just and reasonable result and to have intended a result feasible of execution); see also Rodriguez v. Service Lloyds Ins. Co., 997 S.W.2d 248, 254 (Tex. 1999) (noting that administrative rules are construed in the same manner as statutes). Finally, the Plant Economic Adjustment accomplishes the primary goal of Rule 25.261, ensuring that uneconomic variable expenses are not included in the ECOM total.

Houston argues that the ECOM or UCOS-RFP instructions do not expressly provide for inclusion of forecasted environmental O&M expenses in the ECOM model. Houston Ex. 8 at 39. But the instructions do not forbid inclusion of environmental O&M expenses in the ECOM costs, either. In fact, the instructions are silent on the issue. Reliant Energy Ex. A-31. Under these circumstances, the most reasonable approach is to include the O&M costs necessarily associated with environmental expenditures in order to capture the actual generation costs attributable to Reliant Energy's production plant.

Houston also argues that the environmental O&M expenses are improper because O&M expense must be based on the 1999 base year costs. Id. It is true that the environmental O&M costs were not in the 1999 balance, but the environmental capital costs associated with those O&M costs had not been incurred by that time. Thus, like TIEC, Houston seeks to impose an impossible condition on the Company.

G.	Tax Issues (CTS, ITC, etc.)

1.	Consolidated Tax Savings

Reliant Energy currently files a consolidated tax return on behalf of itself and its various subsidiaries. See Tr. at 690. GCCC and OPC claim that the filing of a consolidated return gives rise to consolidated tax savings, and that those purported savings must be reflected in the ECOM total. See GCCC Ex. 8 at 13-14; OPC Ex. 5 at 42-43. The purpose of ECOM, however, is to quantify estimated stranded costs. GCCC's proposed consolidated tax adjustment relies on backward-looking historical costs, which are completely irrelevant to such quantification. See Reliant Energy Ex. 4 at 4; see also Tr. at 704 (stating that a "consolidated tax savings adjustment will be based on 15 years of data").

Moreover, Reliant Energy has submitted a Business Separation Plan that, if approved by the Commission, would separate the current consolidated company into two unrelated companies. Tr. at 697. Unrelated companies cannot file consolidated tax returns. Therefore, the tax savings projected by GCCC is speculative at best.

Further, neither the 1996 nor the 1998 ECOM model required a consolidated tax savings adjustment. See generally Reliant Energy Ex. A-33; TIEC Ex. 7. Nor did the Commission raise the issue of consolidated tax adjustments in the generic issues addressed in PUC Docket 22344. Tr. at 707 (GCCC witness Michael Arndt admitting that the "issue of consolidated tax savings was not specifically addressed" in the generic proceeding). Thus, there is no authority for Intervenors' claims that a consolidated tax adjustment is appropriate.

Finally, Mr. Arndt's consolidated tax savings adjustment is based on a theory used in PUC Docket No. 14965, a rate case involving Central Power and Light Company. See Tr. at 704. But Docket 14965 did not involve the ECOM model. Id. Moreover, that case is now on appeal, and the propriety of the consolidated tax savings adjustment is one of the primary issues in that appeal. See Central Power and Light Company v. Public Utility Comm'n, et al., No. 03-99-00111-CV (Tex. App.–Austin, July 27, 2000) (currently pending on motion for rehearing).

For these reasons, the consolidated tax savings adjustment proposed by some of the Intervenors would be erroneous.

2.	Investment Tax Credits

Investment tax credits ("ITCs") were enacted by the United States Congress in 1962 to encourage companies to modernize their facilities. Reliant Energy Ex. A-4 at 1. In effect, the Congress sought to encourage construction by giving companies a rebate off their tax liabilities to the extent of the ITCs claimed in any given year. Id. at 1-2. In essence, ITCs reduce the amount of income taxes currently payable in a given year. Reliant Energy Ex. A-2 at 8.

Although the Tax Reform Act of 1986 repealed ITC provisions, Reliant Energy had realized ITCs on tax returns prior to the repeal. Reliant Energy made an election to defer ITCs in the years realized and then amortized them as a reduction of income tax expense over the book or regulatory lives of the property giving rise to the ITCs. Id. Thus, unamortized generation-related ITC balances remain on Reliant Energy's balance sheet.

In Order No. 14 the Commission determined that ITCs should be included in the ECOM calculation as a reduction of income tax expense. PUC Docket 22344, Order No. 14 at 12. Reliant Energy complied with the order, although the Company believes that the inclusion of ITCs in ECOM after January 1, 2002 may violate federal income tax normalization requirements.11 Reliant Energy Ex. A-3 at 2. This is because generation property ceases to be public utility property for income tax purposes beginning January 1, 2002, when generation property is deregulated. Id. In fact, the IRS has previously determined in Private Letter Ruling ("PLR") 8730013 that the normalization rules would be violated if the ITCs were left on the utility's regulatory books of account and flowed through to the ratepayers after the property to which they relate becomes deregulated. Id.12

In spite of the normalization violation, GCCC witness Michael Arndt proposes that the generation-related ITCs "must be recognized in the Commission's ECOM determination." GCCC Ex. 8 at 8. Mr. Arndt's arguments are incorrect, however, because they are founded on false premises.

First, Mr. Arndt apparently misunderstands what ITCs are, because he repeatedly characterizes them as customer-funded capital. See, e.g., id. at 4-5 (referring to ITCs as "customer funded capital accumulated from approximately 1962 to 1986 through charges to ratepayers for noncash federal income tax expenses under normalization accounting"); id. at 8 (stating that "the unamortized generation-related ITC balances are customer contributed funds created by charging ratepayers for noncash federal income tax expenses in prior years"). But utility customers did not, in fact, finance the ITCs. Rather, the United States Treasury supplied the funding for the ITCs. See Reliant Energy Ex. A-4 at 2. Thus, there was no customer funding. Further, to the extent Mr. Arndt is implying that the ITCs realized on Reliant Energy's tax returns should have gone to customers in the years claimed, he is incorrect; to have done so would have resulted in a normalization violation because Reliant Energy has elected to amortize ITCs through its cost of service over the life of the plant. Id.

Customers have benefitted from the ITCs, however. Rates charged to customers have been reduced ratably by ITC amortization as the property is used to provide service. Thus, the ITC amortization has reduced Reliant Energy's cost of service and thereby has lowered rates. Id.

Second, Mr. Arndt erroneously dismisses PLR 8730013 by claiming that "private letter rulings do not have the force and effect of law, and are merely the opinion of staff members" of the IRS. GCCC Ex. 8 at 8. While the conclusions in a private letter ruling are binding only upon the taxpayer to which it is issued, the IRS maintains consistency in its ruling policy. Reliant Energy Ex. A-4 at 3. In addition, the IRS has issued a General Counsel Memorandum (GCM 39651) explaining its position on PLR 8730013, which indicates that the IRS intended for PLR 8730013 to set forth its general position on deregulation issues. Id.

Nor is it relevant that PLR 8730013 dealt with a telecommunications utility, as Mr. Arndt would have the ALJ believe. The tax normalization rules discussed in PLR 8730013 apply to all rate-regulated utilities, including both telecommunications and electric utilities. Id. at 4.

Third, Mr. Arndt has mistakenly claimed that unamortized ITCs are regulatory liabilities under Generally Accepted Accounting Principles ("GAAP") and the Federal Energy Regulatory Commission's Uniform System of Accounts ("USOA"). GCCC Ex. 8 at 6-7. Unamortized ITC is not a regulatory liability under GAAP or the USOA. Reliant Energy defers the ITC on its balance sheet and reflects it in net income over the productive life of the related asset. Reliant Energy Ex. A-4 at 2. This does not meet the definition of a regulatory liability under GAAP or the USOA. Id.

Fourth, Mr. Arndt has misstated the disposition of the ITCs by claiming that Reliant Energy "intends to transfer a portion of the generation-related ITC benefits to stockholders as an extraordinary income as soon as the generation related assets become deregulated (i.e., January 1, 2002)." GCCC Ex. 8 at 7-8. Reliant Energy will amortize the unamortized ITC to the Company's net income as required by the tax normalization rules and GAAP. Reliant Energy Ex. A-4 at 3. Thus, the generation related unamortized ITC would not be immediately recorded as extraordinary income upon deregulation. Id.

Because the inclusion of ITCs in ECOM after January 1, 2002 would violate normalization requirements, and because Mr. Arndt's arguments supporting Order No. 14 are uniformly erroneous, it is necessary to exclude ITCs from the ECOM calculation for years after 2001.

3.	Excess Accumulated Deferred Income Taxes

Mr. Arndt has also complained that Reliant Energy has approximately $53 million of unamortized excess accumulated deferred federal income taxes ("excess ADFIT"), and that this amount represents "customer supplied funds." GCCC Ex. 8 at 11. Accordingly, he argues that the amount should be included in the ECOM calculation.

Contrary to Mr. Arndt's assertions, accumulated deferred income taxes represent an interest-
free loan from the U.S. Treasury, not the utility's customers. The excess ADFIT amount came into being because the United States tax laws forgave a portion of the loan that Reliant Energy received through a reduction in the tax rate.

Mr. Arndt acknowledges that the Commission has not required excess ADFIT to be included in the ECOM amount. GCCC Ex. 8 at 11. Nevertheless, he argues that the excess ADFIT amount should be treated the same as the ITCs. Reliant Energy agrees that the excess ADFIT issue is similar to the ITC issue, but in fact neither excess ADFIT nor ITCs should be included in ECOM.

H.	Economic Viability/Gas Plant Analysis

The ECOM instructions require each utility to "input projected generation costs (in thousand of nominal dollars) in the specified categories on a system wide basis for each of the years 2000 through the projected economic life of each generating unit." Reliant Energy Ex. A-31 at 61. Those instructions do not require a utility to determine whether a particular generating unit is profitable before including its costs and revenues in the ECOM model. That is not to say, however, that no economic screening occurs. As discussed above, the Plant Economic Adjustment mechanism within the ECOM model performs an economic evaluation of incremental variable costs. See Reliant Energy Ex. A-39 at 58-62.

Houston witness Scott Norwood nevertheless claims that Reliant Energy should have conducted a wholly separate and external economic viability screening for each existing generating unit, in addition to the Plant Economic Adjustment, before including those generating units in the ECOM production cost analysis. Houston Ex. 8 at 18-19. In addition, he would then have Reliant Energy allow the ECOM model to conduct a secondary economic screening through the Plant Economic Adjustment calculation. When asked for his authority for the contention that a separate, external economic screening was required, however, Mr. Norwood could come up with nothing more than vague references to SB 7. See Tr. at 615.13

But SB 7 does not in fact require the additional economic viability screening that Mr. Norwood proposes. Rather, PURA § 39.262(i) mandates the methodology used in the 1998 ECOM Report, and that methodology did not require an economic screening other than the Plant Economic Adjustment. See TIEC Ex. 7. Indeed, when the Commission developed the ECOM model in 1996, it expressly considered and rejected Mr. Norwood's argument that costs and revenues should be disaggregated and compared at the individual plant level:

The [ECOM] model is actually a cross between a top-down [lost revenues] approach and a bottom-up asset-by-asset approach. The model disaggregates costs, and allocates sales, by resource type in the same manner as an asset-by-asset approach. Unlike a pure asset-by-asset approach, the model does not disaggregate costs, and allocate sales to the individual plant level. Allocating costs by resource type provides a balance of the [lost revenues] and the asset-by-asset approach by incorporating the relative simplicity of the [lost revenues] approach with the added detail provided by the asset-by-asset approach.

Reliant Energy Ex. A-33 at 18 (emphasis in original); see also Tr. at 611 (Mr. Norwood admitting that the ECOM model "is by definition an aggregated model. So it doesn't even have plant data in it. It has groups of data for types of plants. For all coal plants you have one input.").

Mr. Norwood nevertheless claims that an economic screening test is necessary because a utility could have eight unprofitable gas plants and only two profitable ones, and the Plant Economic Adjustment would allow the two profitable plants to compensate for the losses of the eight unprofitable plants. See Tr. at 616-18. But the Commission made the decision to conduct the Plant Economic Adjustment by fuel-type, rather than by individual plant. Mr. Norwood simply does not agree with the ECOM model and is trying to change the model. See Tr. at 1176 (Mr. Rice testifying, "I believe Mr. Norwood's adjustments that he suggested were changes to the ECOM model logic.").

Moreover, Mr. Norwood's argument proves too much. If the eight supposedly unprofitable gas plants were excluded from the ECOM model, there would be nothing left for the Plant Economic Adjustment to do. Thus, Mr. Norwood is changing the ECOM model by substituting his own economic screening for the Plant Economic Adjustment.

Finally, Mr. Norwood's suggested economic viability test is outside the ECOM model because there are no parameters in the model for such a test. Utilities would have to make certain assumptions in order to perform the screening, but there are no standards in the model, the instructions or elsewhere to guide the utilities in formulating those assumptions.

Houston's efforts to graft a plant-by-plant economic viability screening into the ECOM calculation is not required by the ECOM model and is inconsistent with the Commission's intent in adopting the model. Therefore, it should be rejected in its entirety.

I.	Capital Plant Additions

OPC witness Hugh Higgins reduced Reliant Energy's invested capital for the years 1999-
2001 by $388,324,135 in 1999, $77,266,413 in 2000, and $150,441,298 in 2001 based upon his interpretation of PURA § 39.259(b). OPC Ex. 1 at 10. That adjustment is improper.

First, the 1.5% restriction in PURA § 39.259(b) applies only to generation plant additions. The Legislature's objective was to plan for deregulation of the generation portion of the utility business. The 1.5% threshold is a means for monitoring and promoting thoughtful choices with respect to generation capital plant additions during the transition period. In contrast, it would make little sense for the Legislature to place an arbitrary cap on a utility's investment in transmission and distribution assets, particularly since an investment cap could impair system reliability.

In a similar context in PUC Docket No. 18465, the Commission began preparing for competition by ordering that "the updated net plant in service may reflect capital additions to production plant during the given year in an amount not exceeding one and one half percent (1 ½%) of HL&P's net plant in service." See Reliant Energy Ex. A-24 at 10 (emphasis added). Thus, the Commission has recognized that it makes sense to impose capital addition restraints only on the generation portion of the utility, not on the part of the utility that will remain regulated and subject to traditional prudence reviews.

In his calculations, Mr. Higgins has considered not only capital additions to generation plant, but also capital additions to transmission and distribution plant. Therefore, he has grossly overstated the amount of generation plant capital additions, and his adjustments are wrong.

In addition, Mr. Higgins' exclusions also run afoul of PURA § 39.263(a), which says that the 1.5% limit on investments stated in PURA § 39.259(b) do not apply to "capital costs incurred by an electric utility to improve air quality before January 1, 2002." Mr. Higgins ignored this express exception from the 1.5% investment cap and excluded environmental capital costs along with other capital costs. See Reliant Energy Ex. A-24 at 11. Moreover, it is impossible to determine how much of the amount that Mr. Higgins seeks to exclude represents environmental costs because he has failed to segregate environmental from non-environmental costs. Therefore, exclusion of any capital addition amounts would be improper.

For all of these reasons, Mr. Higgins' proposed disallowance of capital additions is flawed and should be rejected.

J.	Mitigation Obligations

SB 7 provides several tools to mitigate stranded costs. For example, PURA § 39.252(d) requires an electric utility to "pursue commercially reasonable means to reduce its potential stranded costs, including good faith attempts to renegotiate above-cost fuel and purchase power contracts or the exercise of normal business practices to protect the value of its assets." In addition, PURA § 39.254 requires a utility that was reported in the 1998 ECOM Report to have potentially stranded costs to apply excess earnings to the net book value of generation assets, and PURA § 39.256 allows such a utility to redirect depreciation expense related to transmission and distribution assets to net generation plant assets.

Reliant Energy has taken numerous steps to mitigate stranded costs. See Reliant Energy Ex. A-17 at 40; see also OPC Ex. 5 at 59 (Attachment 1). In particular, Reliant Energy has:

•	applied excess earnings to reduce the net book value of its generation assets, even before it was required by statute. Tr. at 894.

•	redirected depreciation from transmission and distribution assets to generation assets, even before the option was created by statute.14 Id.

•	constructed a rail spur at the Parish coal plant to reduce coal transportation costs. Id.

•	entered into a settlement agreement to ensure an adequate lignite supply at the Limestone plant. Id. at 895.

•	renegotiated the Kerr-McGee coal contract. Id.; OPC Ex. 5 at 59.

•	obtained approval to securitize regulatory assets. Tr. at 896.

Recognizing these efforts, Staff witness Darryl Tietjen testified, "Reliant has reasonably pursued efforts to mitigate potential stranded costs through the use of redirected depreciation, excess earnings and securitization. These efforts have been accounted for and are reflected in Reliant's ECOM filing and its securitization case." Staff Ex. 1 at 17. In addition, the Commission found in PUC Docket No. 18465 that Reliant Energy "has demonstrated active mitigation of stranded costs by voluntarily taking $150 million of additional South Texas Project depreciation in 1995 to 1997, and approximately $74 million in additional Trinity Mine depreciation in 1996 and 1997." Reliant Energy Ex. A-34 at 18.

In spite of these numerous mitigation activities, OPC witness Mr. Falkenberg faults Reliant Energy for not taking "aggressive steps to mitigate ECOM." OPC Ex. 5 at 34. For purposes of modeling ECOM, Mr. Falkenberg contends that Reliant Energy should construe the mitigation obligation to include additional duties such as maintaining historical capacity factors, even in the face of O&M expenditures that are declining in real terms because of Commission-mandated benchmark escalators. In fact, in some cases Mr. Falkenberg would require Reliant Energy to improve on those historical capacity factors, even though the plants are aging and Commission-
mandated O&M expenditures are declining in real terms. See Tr. at 898. Finally, to arrive at his proposed capacity factors Mr. Falkenberg has ignored the lifetime capacity factors of plants and has instead chosen only the last few years to set performance standards.

Mr. Falkenberg has no statutory support for his expansive view of mitigation obligations. Id. Moreover, he concedes that to satisfy his mitigation theory, Reliant Energy may have to spend money that it cannot include in the ECOM estimate of costs. Id. Thus, his mitigation theory is outside the ECOM model and should be rejected.

K.	Rate of Return

PURA § 39.201(h), together with PURA § 39.262, requires an electric utility to use the ECOM administrative model referenced in the 1998 ECOM Report, but states that the model must include "updated company-specific inputs." The Commission defined "company-specific inputs" in Order No. 14:

Company-specific inputs include those inputs that are determined by the existence of historic company data for the input. The values for these types of items can generally be found in a company's last rate case. They include items such as rate of return, depreciation, taxes, fuel expenses (except for the portion related to natural gas requirements subject to market based pricing), sales figures, allocation of costs and sales to customer classes, and level of investment.

PUC Docket No. 22344, Order No. 14 at 4. Thus, a utility's rate of return on equity for purposes of the ECOM model is a company-specific input, and the place to find the value for that company-
specific input is in the utility's last rate case.

In calculating its rate of return on equity for purposes of the ECOM model, Reliant Energy used the 11.9% return on equity from its last rate case, PUC Docket No. 12065. Reliant Energy Ex. A-17 at 31. It then applied that rate of return on equity with the capital structure and debt return rate from the historical test year to arrive at an overall rate of return of 9.98%. Id.; see also Reliant Energy Ex. A-21 at 65.

Numerous other parties contested Reliant Energy's use of the 9.98% rate of return, but they disagree among themselves regarding the correct rate and the method for reaching that rate. Staff, for example, has recommended a 9.74% rate of return. See Staff Ex. 1 at 9 But that proposed rate of return is erroneous for several reasons.

First, Staff relies on the wrong case, PUC Docket No. 18465, to arrive at a rate of return. As noted above, PUC Docket No. 12065 was Reliant Energy's last rate case. PUC Docket No. 18465 was not a rate case, but instead was a transition plan proceeding to determine how to mitigate stranded costs. Indeed, in the final order in Docket 18465, the Commission expressly noted that the docket "charts new regulatory waters; it is different from the traditional general rate case." Reliant Energy Ex. 34 at 1; Tr. at 742. Further, in that final order, the Commission stated that Reliant Energy "had a general rate case in Docket 12065." Reliant Energy Ex. 34 at 12; Tr. at 742-43. Therefore, the Commission viewed Docket 12065 as a general rate case, but did not view Docket 18465 as a general rate case. Accordingly, the return on equity used for ECOM should have been the one from Docket 12065.

Second, even if Staff were correct to use a rate of return from Docket 18465, the number it chose was wrong. In Docket 18465, the parties agreed upon a rate of return of 9.95% for purposes of the earnings cap. Reliant Energy Ex. 34 at 9. The Commission then reduced that rate of return to 9.84% to account for "rates that may be considered discounted rates." Id. at 4. In other words, the Commission reduced the rate of return because Reliant Energy was offering discounted rates to some large customers in order to retain their business, and the Commission did not want other ratepayers to have to make up those discounts. Id. at 14-15. In the deregulated market anticipated by the ECOM market, however, generators will be selling at wholesale, not at retail. Tr. at 745. So generators cannot give discounts to customers. Id. And if there are no discounts, the rationale for reducing the 9.95% rate of return to 9.84% disappears, as Staff witness Mr. Tietjen admitted on cross-examination. Id. Thus, if Staff were to prevail on its claim that Docket No. 18465 was Reliant Energy's last rate case, the rate of return should be 9.95%.

Third, Staff erred by reducing the rate of return from 9.84% to 9.74% "to exclude the effects of the losses on reacquired debt for which Reliant received securitization approval in PUC Docket No. 21665." Staff Ex. 1 at 9. Nothing in the ECOM model instructions or the Commission's orders authorizes a reduction in the rate of return from the last rate case. Moreover, no securitization has occurred because of legal proceedings challenging utilities' rights to recover stranded costs. Tr. at 746. Mr. Tietjen admitted on cross-examination that it is possible that the securitization will never happen. Id. at 747. Therefore, reducing the rate of return to account for losses on reacquired debt for securitization is inappropriate.

Further, reducing Reliant Energy's rate of return for ECOM purposes because of speculative developments in another docket is improper. The adjustment made by Staff would essentially be a retroactive and unilateral modification of the settlement agreement in the securitization case. Reliant Energy did not agree in that docket that its settlement of the securitization case would form the basis for penalties in future cases. Reliant Energy Ex. A-17 at 33.

For its part, OPC has recommended a 9.77% rate of return. OPC Ex. 5 at 41-42. But that rate of return is erroneous as well.

As an initial matter, OPC agrees with Reliant Energy that the Company's last rate case was Docket 12065. See OPC Ex. 5 at 41. Nevertheless, OPC proposed that the rate of return be set at 9.77% rather than at 10.03%, which was the actual rate of return set in Docket 12065. Id. at 42; Tr. at 922-23. OPC's rationale for reducing the rate of return by 26 basis points is that 9.77% is the "low end of the range allowed in HL&P's last rate case," and OPC believes that the Commission "should error [sic] on the side of a conservative determination of ECOM" in order to increase headroom and to encourage utilities to mitigate stranded costs. OPC Ex. 5 at 42.

OPC's proposed reduction of the rate of return to 9.77% is erroneous because that rate of return was not used to set Reliant Energy's rates in Docket 12065. Tr. at 922. In fact, the return on equity percentage implied by OPC's rate of return has never been used to set Reliant Energy's rates. Id. at 923. Thus, there is no legal basis to use such a rate in the ECOM model.

Moreover, OPC's argument ignores the lost-revenues approach of the ECOM model. As Reliant Energy explained in its testimony, the ECOM model is designed to measure lost revenues resulting from the transition to competition. Reliant Energy Ex. A-17 at 3. OPC's reduced rate of return would prevent Reliant Energy from recovering the full amount that would have been recoverable in a regulated environment.

TIEC witness Michael Gorman proposes to use 6.95% as the cost of common equity for Reliant Energy, which is the same rate as the Company's cost of long-term debt. See TIEC Ex. 2 at 5. That would lead to a total rate of return of just 7.02%. All of his arguments in favor of such a low rate of return are wrong.

First, Mr. Gorman's proposed rate of return fails because it is inconsistent with the instructions in Order No. 14 to use the return on equity from the last rate case. The return on equity that Mr. Gorman proposes was never even contemplated by the Commission in the Company's last rate case, Docket No. 12065, or even in Docket 18465 (if that could somehow be construed to be the Company's last rate case). Therefore, a 7.02% return has never been the basis for rates that Reliant Energy charged its customers.

Second, Mr. Gorman argues that recovering stranded costs through a CTC provides for accelerated recovery of generating investments and therefore reduces shareholder risk. TIEC Ex. 5 at 6. In fact, however, the CTC does not reduce risk in the short term. Not until the 2004 true-up will there be any certainty regarding the amount of stranded costs that Reliant Energy will be allowed to recover. Moreover, the actual recovery itself will not be guaranteed until the amount is securitized and a non-bypassable charge is in effect. See Reliant Energy Ex. A-24 at 3; see also Tr. at 1013 (Reliant Energy witness James Brian testifying, "[W]e don't know what's going to happen between now as far as the ECOM calculations that various people have made and what the market will show in 2004.").

Mr. Gorman next argues that stranded costs do not benefit customers, and therefore they should earn a lower rate of return. TIEC Ex. 2 at 6. Absent deregulation, however, the utility would continue to use the generation assets to serve and benefit customers. Moreover, the Commission has expressly found that the assets giving rise to stranded costs were prudent investments and that the expenditures were in the public interest. See Reliant Energy Ex. A-24 at 3. Any costs found imprudent have long since been absorbed by shareholders. Moreover, customers have already received much of the benefit of those assets.

Finally, like OPC, Mr. Gorman ignores the lost-revenues approach of the ECOM model. The reduced rate of return proposed by Mr. Gorman would prevent Reliant Energy from recovering the full amount that would have been recoverable in a regulated environment.

Houston also complains about the rate of return used by Reliant Energy and recommends a 9.95% overall rate of return. Houston Ex. 8 at 40-41. That proposal is flawed, however, because Mr. Norwood uses the capital structure from PUC Docket 12065 to arrive at that figure. As noted below in section II.L., the appropriate capital structure is that from the historical test year, not a capital structure that is approximately eight years old and inconsistent with historical test year data used in other portions of the ECOM calculation. Therefore, Houston's proposed rate of return should be rejected.

L.	Capital Structure

To calculate certain items such as income taxes correctly for purposes of the ECOM model, it is necessary to assume a particular capital structure for the Company.15 Reliant Energy used the historical test year capital structure reflected in Schedule II-C of the UCOS-RFP filing. See Reliant Energy Ex. A-17 at 31-32. That capital structure consists of 59.86% equity, 34.75% long term debt, and 5.39% preferred stock and redeemable trust securities. See Reliant Energy Ex. A-25 at 2233.

Reliant Energy's use of the capital structure from the historical test year is consistent with the use of the historical test year data for numerous other purposes in connection with the ECOM calculation. Nevertheless, OPC, Houston and the Staff complain that Reliant Energy should have used a different capital structure.16 OPC Ex. 5 at 41-42; Houston Ex. 8 at 41; Staff Ex. 1 at 10. All of them are wrong.

OPC and Houston propose the capital structure that existed at the time of Reliant Energy's last rate case, PUC Docket 12065. See OPC Ex. 5 at 42; Houston Ex. 8 at 41. But that capital structure is almost eight years old. See Reliant Energy Ex. A-17 at 32. Neither OPC nor Houston has articulated any valid reason for using such an obsolete capital structure. It is appropriate to use a current capital structure because it is internally consistent with the source of other ECOM inputs and will more accurately reflect the true income taxes that Reliant Energy will be obliged to pay on a going-forward basis.

As noted above, Staff proposed using a rate of return from PUC Docket 18465. But it could not recommend a capital structure from Docket No. 18465, because the Commission did not even calculate a capital structure for Reliant Energy in that case. Staff therefore found a 1996 annual report of Reliant Energy's and derived a capital structure from that report. Staff Ex. 1 at 10. While the 1996 capital structure is more recent than the 1993 capital structure used by OPC, it is still outdated compared to the 1999 historical test year capital structure that Reliant Energy used for ECOM purposes. Thus, the Staff's 1996 capital structure should be rejected as well.

III. Revenues in the ECOM Model

The parties also dispute the amount of revenues that should be included in the model. The following issues address the parties' disagreements with respect to revenues.

A.	Plant Capacity Factors

1.	Nuclear

When it ran the ECOM model, Reliant Energy assumed an initial annual capacity factor of 83% for the South Texas Project ("STP") nuclear plant.17 That capacity factor was based on the goal for STP performance set by the Commission in PUC Docket 14965, Application of Central Power & Light Company for Authorization to Change Rates. See Reliant Energy Ex. A-17 at 48. Beginning in 2011, Reliant Energy assumed a 1% per year reduction in the capacity factor to account for the declining expenditures in real terms for operations and maintenance. Id. at 46.

Both Houston and OPC have criticized the 83% annual capacity factor for STP as being too low. Houston would set the annual capacity factor for STP at 88%, and OPC seeks an annual capacity factor of 91%. Houston Ex. 8 at 29-30; OPC Ex. 5 at 37. Both proposals should be rejected.

The average lifetime capacity factor for STP is currently 71.5%. Reliant Energy Ex. A-17 at 48; Tr. at 920. Even if the worst year's performance is discarded, the average lifetime capacity factor is only 78.4%. See Reliant Energy Ex. A-17 at 48; Tr. at 920. Houston and OPC would have the ALJ ignore these numbers and focus only on the last few years, when STP has enjoyed exceptionally high capacity factors. See Tr. at 642 (Houston witness Mr. Norwood admitting that he based his STP capacity factor on a three-year period). It is patently unreasonable to assume that such performance will continue for the next 28 years, particularly in light of the declining expenditures in real terms for O&M and the increasing age of the plant facilities. In fact, Mr. Falkenberg of OPC admitted on cross-examination that he is not aware of any nuclear plant in the United States that has run at a 91% capacity factor over a 20-year period. Tr. at 921. Similarly, Mr. Norwood acknowledged that he is not aware of any plant in the United States with a capacity factor of 88% over a 20-year period. Id. at 643.

Mr. Falkenberg also admitted on cross-examination that to arrive at the 91% capacity factor, he assumed Reliant Energy spent 2%-5% more in operations and maintenance costs per year than what the Commission allowed in its orders. Tr. at 889. That is a violation of the Commission's orders, as Mr. Falkenberg conceded:

Q.	Well, you're assuming that Reliant Energy is spending more O&M than what is allowed in the ECOM model, aren't you?

A.	Yes. But I'm allowing them the recovery of that in what I did.

Q.	But the Commission doesn't allow that assumption that they spend more than [the] 1 percent escalator, does it?

A.	I'm afraid you're right.

Q.	So you violated the PUC's orders on that, didn't you?

A.	Well, I'm afraid you're right. To the extent that the Commission views that as being more important than just providing the allowance for the O&M for the additional generation, then I would certainly accept that.

Tr. at 890. Because Mr. Falkenberg violated the PUC's orders to arrive at his proposed 91% annual capacity factor, his testimony should be disregarded in its entirety.

Houston's proposed 88% annual capacity factor fares no better. As noted above, that percentage is far above the lifetime average capacity factor of STP, and is significantly higher than the performance standard that the Commission set in PUC Docket 14965. Moreover, Houston has ignored the industry performance data demonstrating that an 88% capacity factor is far outside the zone of reasonableness for a 28-year average. See Reliant Energy Ex. A-17 at 48.

Finally, both OPC and Houston have ignored the natural degradation that undoubtedly occurs when O&M expenditures decrease in real terms each year and plants age. The ECOM instructions permit utilities to escalate O&M expenses by only 1% per year for nuclear units, although the Staff assumes the general inflation rate will be 3% per year. See Reliant Energy Ex. A-17 at 45. Thus, in real terms the ECOM model assumes less O&M expense each year, beginning immediately. Tr. at 636 (Houston witness Mr. Norwood admitting that with respect to O&M Reliant Energy is losing money "in real terms every year from the year 2000 to the end of the model run"). Even so, Reliant Energy did not assume that the degradation will begin immediately; rather, it assumed a 1% per year degradation beginning in 2011, when STP will be more than 20 years old. Id. at 45-46. This assumption is actually conservative, considering that the Commission-mandated annual escalation rate for nuclear units is 1% and the annual general inflation rate is 3%. Id. at 46. Nevertheless, OPC witness Mr. Falkenberg makes no adjustment for the declining O&M budget that results from nuclear benchmark escalators that are far below general rates of inflation.

On behalf of Houston, Mr. Norwood admits that "certainly there's a prospect for some degradation over time." Tr. at 637. He claims although he made no explicit adjustment for degradation, he implicitly did so by reducing the capacity factor from 91% to 88%. Tr. at 644-45. But as noted above, an 88% capacity factor is itself unreasonable. Therefore, that figure does not actually take the degradation into account. Because both OPC and Houston have ignored the decreasing operations and maintenance expenses, their capacity factor testimony is fatally flawed.

The Commission set the 83% capacity factor used by Reliant Energy for STP only three years ago. That percentage remains appropriate, and Intervenors have offered no valid reason to depart from it.

2.	Coal/Lignite

When Reliant Energy ran the PROSYM model, it did not assume a generic capacity factor for its coal/lignite units, as several of the Intervenors did. Instead, Reliant Energy used the PROSYM model to calculate capacity factors based on hourly supply and demand relationships, historical outage rates and unit operating characteristics. In other words, Reliant Energy used capacity factors appropriate for the specific coal/lignite plants in the Company's portfolio. Reliant Energy then reduced the coal units' heat rates and capacity ratings by 1% per year, and increased outage rates by 1% per year, beginning in 2011 to account for unit degradation arising from real declines in O&M expenses for aging plants. See Reliant Energy Ex. A-17 at 45.

Houston apparently claims that Reliant Energy should have assumed an 85% capacity factor for the coal/lignite units, rather than basing the capacity factor on each plant's specific operating characteristics. Houston Ex. 8 at 28. But that proposed adjustment is inappropriate because it is based on only the most recent three years. Id. It is unlikely that the units will continue to perform at that level as they age and receive fewer maintenance dollars. Second, Houston assumed that the coal/lignite units will never be backed down at night. Tr. at 640. Yet Mr. Norwood admits that Reliant Energy's coal/lignite units have historically been backed down at night. Id. at 641. Mr. Norwood offered no explanation for his assumption that the coal/lignite units will operate differently in the future than they have operated in the past. Therefore, Houston's proposed capacity factor for the coal/lignite units does not reflect reality.

Reliant Energy's assumed capacity factors for coal/lignite units are also proper because the 1% per year degradation assumption is reasonable. As with nuclear units, the Commission allowed the O&M expense for coal/lignite units to be escalated at only 1% per year. Reliant Energy Ex. A-17 at 45. Inflation, however, is assumed to be 3% per year. Id. Therefore, O&M expenses begin declining in real terms immediately. Nevertheless, Reliant Energy has not assumed a decline in the coal/lignite efficiency rates until 2011. At that time Reliant Energy's coal/lignite units will be more than 20 years old. Id. at 46. It is entirely reasonable to expect generating units of that vintage to decline in efficiency without adequate expenditures for maintenance. See Reliant Energy Ex. A-14 at 5 ("[A]t some point during the third or fourth decade of a unit's service, increasing annual investment is required to maintain an approximation of the original unit performance, and equipment failures will increase." (emphasis added)). Houston, on the other hand, would require aging plants with inadequate O&M to maintain a performance level established for a short period almost fifteen years earlier, at a time when the plants were obviously newer and the Company was able to expend appropriate O&M amounts.

For these reasons, the adjustment sought by Houston for coal/lignite capacity factors should be rejected.

B.	STP License Extension

In his direct testimony, OPC witness Randall Falkenberg opined that Reliant Energy should have assumed a twenty-year license extension for STP when it ran the ECOM model. See OPC Ex. 5 at 36. According to Mr. Falkenberg, Reliant Energy should not have assumed that the STP plant will be retired in 2028, when its operating license expires, but instead should have assumed that the Nuclear Regulatory Commission ("NRC") will grant an extension for STP to run until 2048. That assumption, of course, would increase Reliant Energy's revenues for ECOM purposes, and Mr. Falkenberg reduced Reliant Energy's ECOM amount by $99 million to account for those purported revenues. Id. at 36.

Mr. Falkenberg's adjustment is improper because it is based upon pure speculation and is outside the ECOM model. See Reliant Energy Ex. A-17 at 52. First, even Mr. Falkenberg admits that Reliant Energy cannot even apply for a license extension until 2008. See Tr. at 914. Moreover, even if Reliant Energy were to apply for the license extension eight years from now, it is far from certain that the NRC would grant the extension, as Mr. Falkenberg also admits. Id.

Mr. Falkenberg further admits that the ECOM model assumes Reliant Energy will be spending less in real terms on O&M between now and 2008. Tr. at 915. Yet he wants the ALJ to ignore that assumption and pretend that the NRC will grant the license extension despite the assumed decline in O&M expenditures. Thus, the assumption that Reliant Energy will obtain a license extension is extremely speculative, and the ECOM total should not be reduced based upon such hypothetical events.

Finally, Mr. Falkenberg's adjustment is outside the ECOM model. Because the Commission's model extends only to 2035, Mr. Falkenberg had to "trend it out" to arrive at assumed revenues and expenses for the years beyond 2035. Tr. at 917. That is clearly a change to the ECOM model and therefore is improper. See also Reliant Energy Ex. A-33 at 8 ("The life of existing assets shall be based on the most recent projections of each asset's economic life.").

C.	Joint Operating Agreement

OPC also criticized Reliant Energy for failing to include in the ECOM revenues half of the purported benefits resulting from the Joint Operating Agreement with the City Public Service Board of San Antonio ("San Antonio"). See OPC Ex. 5 at 38-40. Under that Joint Operating Agreement, which arose as part of a lawsuit settlement, Reliant Energy and San Antonio jointly dispatch their generation resources to achieve the least-cost dispatch for the combined systems of the two utilities. San Antonio is allocated 90% of the total savings arising from the joint dispatch, with Reliant Energy receiving the other 10% savings. Mr. Falkenberg argues that Reliant Energy should have assumed for ECOM purposes that the benefits are shared equally. Accordingly, he reduced the ECOM total by $45 million. Id. at 40.

Mr. Falkenberg's adjustment is erroneous for numerous reasons and should be rejected. First, by claiming that additional benefits should be imputed to Reliant Energy, Mr. Falkenberg is essentially arguing that the settlement was not prudent from Reliant Energy's perspective. But he concedes that the ECOM instructions do not provide for a prudence analysis of utility transactions. Tr. at 905. Therefore, Mr. Falkenberg seeks an adjustment outside the ECOM model.

Second, Mr. Falkenberg's argument ignores the factual bases underlying the settlement. The majority of the savings from the Joint Operating Agreement are derived by optimizing San Antonio's coal-fired units, and San Antonio's ratepayers provided the capital to construct those units. See Reliant Energy Ex. A-8 at 2; see also Tr. at 907 (Mr. Falkenberg admitting that "San Antonio's customers provided the capital dollars necessary to construct the coal plants"). Before the parties entered into the Joint Operating Agreement, San Antonio was not fully dispatching those units, but it could have done so by selling excess capacity into the wholesale market. Reliant Energy Ex. A-8 at 2; Tr. at 909. In other words, San Antonio had options other than the Joint Operating Agreement to realize the savings that it now receives under that Agreement. Reliant Energy Ex. A-8 at 2. Therefore, it is unreasonable to assume, as Mr. Falkenberg has, that Reliant Energy could have demanded and obtained half of the savings arising from the joint dispatch.

Third, Mr. Falkenberg's contentions about off-system sales are flatly wrong. As Ms. Mitcham stated in her rebuttal testimony, Reliant Energy and San Antonio have renegotiated the Joint Operating Agreement to provide for a 50/50 sharing of benefits from short-term off-system sales. See Reliant Energy Ex. A-8 at 2. Mr. Falkenberg admitted during cross-examination that he was not aware of that fact when he filed his direct testimony criticizing the treatment of off-system sales. Tr. at 911.

Fourth, it is not even certain whether the Joint Operating Agreement can operate in its current form after ERCOT becomes a single control area. Reliant Energy Ex. A-8 at 3. Mr. Falkenberg nevertheless assumed that the Joint Operating Agreement will remain the same. Moreover, Mr. Falkenberg used an outdated San Antonio estimate that assumes no changes in the electric market to calculate the imputed numbers. Id. Therefore, his conclusions are erroneous and meaningless.

Ms. Mitcham testified that the purported future Joint Operating Agreement savings, if any, are highly uncertain and impossible to model. Reliant Energy Ex. A-8 at 3. For his part, Mr. Falkenberg has merely urged that Reliant Energy must have done something wrong because it was sued by San Antonio and it subsequently settled that lawsuit. Tr. at 901. That simplistic argument betrays a misunderstanding of the litigation process and ignores the particular facts giving rise to the controversy between Reliant Energy and San Antonio.

For all of these reasons, the ALJ should reject OPC's proposed Joint Operating Agreement adjustment.

D.	Dispatch Assumptions

When Reliant Energy ran the ECOM model, it used results from the PROSYM model to determine production costs. Given a particular load forecast, the PROSYM model employs a least-
cost dispatch algorithm to match generation with load. Reliant Energy Ex. A-17 at 41. The PROSYM model inputs include all of Reliant Energy's existing generation units, as well as new CCCT capacity and fuel diversity units, which the 1996 ECOM order assumed to be coal fired units. Id. From those units, PROSYM selects units to run based on their marginal costs.18 Id. PROSYM starts with the most cost-efficient units first and continues to add generating units in economic order, taking into account certain operating characteristics, until the load is satisfied. Id. In other words, the lowest-cost units are dispatched first, and the highest-cost units are dispatched last. When supply exceeds load, the high-cost units are not dispatched at all.

In his Direct Testimony, Mr. Falkenberg of OPC criticizes Reliant Energy for applying the results of the PROSYM model. Those results assume that Reliant Energy's generation output will decrease because output from less efficient units will be displaced by output from new, more efficient units. OPC Ex. 5 at 31. According to Mr. Falkenberg, Reliant Energy should assume that, after allowing for plant retirements, the Company will retain all of its existing generation output for the next 28 years, and that the new units will serve only new, incremental load. Id. at 33; Tr. at 880. The argument is wrong.

First, Mr. Falkenberg's criticism is contrary to the assumptions underlying the ECOM model. In the 1996 report that first outlined the principles underlying the ECOM model, the Commission Staff noted, "It is assumed that new highly efficient generating units will be brought on-line and operated as baseload units, with the less efficient existing units filling an increasing role in the intermediate, load following and peaking resources." Reliant Energy Ex. A-33 at 28 (emphasis added); see also Reliant Energy Ex. A-17 at 44. Thus, the Staff created the ECOM model using a normal economic dispatch assumption – that new, highly efficient units will displace output from older, less efficient units. Reliant Energy implemented that assumption in its PROSYM modeling.

Second, Mr. Falkenberg's argument will not withstand logical analysis. In cross-
examination, Mr. Falkenberg admitted that the Commission set the ECOM market prices high enough to assume that a new combined-cycle unit will make money selling into the market. Tr. at 882. He further admitted that new combined-cycle units will enter the market when they can make money, and that the new combined-cycle units will have lower heat rates than Reliant Energy's units. Id. The logical result of those assumptions is that new combined-cycle units will in fact enter the market, and those units will be more efficient than Reliant Energy's units. Accordingly, the combined-cycle units will displace Reliant Energy's existing generation.

Mr. Falkenberg nevertheless argues that if Reliant Energy's output is displaced in its own service area, it can recoup those lost sales by selling in other service areas within ERCOT. Tr. at 887. That argument, however, is also illogical. If efficient combined-cycle units displace Reliant Energy's sales in the Company's own service area, there is no reason to believe that Reliant Energy would have any more luck selling power from less-efficient facilities in some other service area within ERCOT.19 Presumably the combined-cycle units would be selling in those service areas as well, and would enjoy the same advantages that exist in Reliant Energy's service area.

In essence, Mr. Falkenberg is asking the ALJ to indulge the fiction that only enough new generation will be built to serve new load, and that the new generation will not displace Reliant Energy's generation during off-peak hours. In fact, new generation capacity does not mirror new, incremental load. Recent experience in ERCOT has shown that new generation capacity is growing much faster than new load. See, e.g., TIEC Ex. 4 at 11 (stating that approximately 2,600 megawatts of new generation capacity is in operation or under development in Reliant Energy's service territory alone, and that the new capacity will displace about 19% of Reliant Energy's industrial sales base). Therefore, Mr. Falkenberg's hypothetical symmetry between new supply and new demand is wrong.

Finally, it is important to note that Mr. Falkenberg's complaints about the PROSYM dispatch assumptions, although wrong, involve a relatively small amount of dollars. In his Direct Testimony Mr. Falkenberg lumped his criticisms of the PROSYM model results in with his disagreements about Reliant Energy's degradation assumptions, and he stated that correcting those purported errors "reduces Reliant's ECOM by $621 million." OPC Ex. 5 at 34. On cross-examination, however, Mr. Falkenberg admitted that the great majority of his proposed $621 million reduction arises from the performance degradation assumptions. See Tr. at 887 Thus, even if his criticisms of the PROSYM model were correct, and they are not, the result would be approximately a $20 million reduction of ECOM. Id. ("I think it is around $20 million is the dispatch error, and 600 million is the degradation.").

Houston witness Scott Norwood also criticizes Reliant Energy's dispatch assumptions on the ground that Reliant Energy assumed no degradation in the dependable capacity, outage rates or net heat rate of new coal units modeled as part of the ECOM analysis. Houston Ex. 8 at 27. Unlike constraints placed on Reliant Energy's coal units, however, incremental coal generating units are not constrained by O&M benchmark escalators, as evidenced by the 3% escalation rate that is used by the Commission for purposes of calculating the fuel diversity adder.

In addition, Mr. Norwood takes issue with the assumption that the new coal units will have a zero outage rate. Id. As Mr. Rice explained in his Rebuttal Testimony, however, the new coal units were modeled by Reliant Energy as proxies for the fuel diversity requirement in the ECOM model. Reliant Energy Ex. A-17 at 28. He further explained that new coal units would normally be modeled using a 20% outage rate, but Reliant Energy assumed that all megawatts lost due to outages would be made up by the statutory obligation to provide energy from renewable resources. Id. at 30. Reliant Energy has used a reasonable method to handle the statutory obligation to provide energy from renewable resources. Mr. Norwood simply criticizes Reliant Energy's approach while providing no alternative to handle this statutory obligation.

In summary, Mr. Norwood's arguments ignore the fact that the UCOS-RFP instructions require cost escalation benchmarking for existing units, while exempting new generating unit additions from similar cost escalation constraints. In addition, he criticizes the methodology that Reliant Energy used to model SB 7 mandated renewable resource requirements, while offering no alternative to replace it. Thus, Mr. Norwood's attacks on Reliant Energy's dispatch assumptions are flawed and have no merit.

For these reasons, both OPC's and Houston's challenges to Reliant Energy's dispatch assumptions should be rejected.

E.	Reallocation of Customers from Industrial Class to Commercial Class

In Order No. 14 of PUC Docket 22344, the Commission listed as a company specific input "allocation of costs and sales to customer classes." Order No. 14 at 4. The Commission further noted that the "values for these types of items can generally be found in a company's last rate case." Id. Thus, Reliant Energy allocated sales to industrial, commercial and residential customer classes consistent with customer class definitions and distinctions in prior rate cases. See Reliant Energy Ex. A-17 at 34. The allocations of sales to customer classes for purposes of the ECOM model were also consistent with the allocations in the UCOS-RFP filing generally. Id.; Tr. at 891.

No party questioned this allocation except for OPC, who claimed that Reliant Energy overstated its sales allocation to the industrial class. See OPC Ex. 5 at 26-29. According to OPC witness Falkenberg, any customer class with an annual load factor less than 80% should be classified as commercial, rather than industrial. Id. at 27. Therefore, Mr. Falkenberg proposed reducing Reliant Energy's ECOM total by $226 million. Id. at 29. This proposed reallocation of customer sales is erroneous for numerous reasons.

First, in the ECOM model Reliant Energy followed the customer classifications that it has used for many years. The Commission was well aware of those classifications when the ECOM model was designed, and it provided in the model that sales were to be allocated into industrial, commercial and residential classes. Moreover, Reliant Energy used those traditional classifications in the 1996 and 1998 model runs without objection from the Commission.

Second, Mr. Falkenberg's reallocation would greatly complicate each utility's calculation. Reliant Energy has proposed a consistent, simply and straightforward approach in which traditional commercial customers pay the commercial price, traditional industrial customers pay the industrial price, and traditional residential customers pay the residential price. Mr. Falkenberg's proposal would discard this administratively simple methodology and incorporate complications and distinctions among customers within the industrial class. That is inconsistent with both the letter and the spirit of the ECOM rules. Reliant Energy Ex. A-17 at 36.

Third, Mr. Falkenberg would limit industrial sales to the Large Overhead Service-A ("LOS-
A"), Special Contract and Interruptible customers. Id. at 35. This classification ignores the Large Overhead Service -B ("LOS-B") customers, who are among the highest loads on the Reliant Energy system. Id.; Tr. at 969 (TIEC witness Jeffrey Pollock stating that LOS-B customers are "mainly large, industrial customers operating at 80 percent or better load factors"). In fact, Reliant Energy's LOS-B customer class is composed of major petrochemical and refining facilities owned by such industry giants as Occidental, Lyondell, Air Liquide and Bayer. Reliant Energy Ex. A-17 at 35; Tr. at 970. By pretending that these major industrial customers belong in the commercial class rather than the industrial class, Mr. Falkenberg has erroneously overstated Reliant Energy's commercial revenues and understated industrial revenues.20 See Tr. at 974 (Mr. Pollock stating that "it's unlikely" that LOS-B customers would be commercial customers in Reliant Energy's service territory").

Fourth, Mr. Falkenberg's argument rests on the false premise that retail electric providers in a deregulated market will look at annual class load factors, rather than individual customers' annual load factors, when deciding what rate to offer. In other words, even if some of the customers in Reliant Energy's current LOS-B class have load factors below 80%, others have load factors far above 80%. Tr. at 970 (Mr. Pollock stating that "many" LOS-B customers operate "at 80 percent or better load factors"). Yet Mr. Falkenberg would exclude all of those customers from the industrial class, regardless of any particular customer's annual load factor.

Finally, assuming an allocation other than the one used by the Company in the development of its load forecast would in fact change that forecast, thereby making the forecast inconsistent with those load forecasts used in other parts of the transmission and distribution rate case. It would also lead to a forecast other than the Company-specific load forecast that the ECOM instructions require.

For all of these reasons, Mr. Falkenberg's proposed reallocation should be rejected.

F.	Excess Earnings

As discussed above in connection with mitigation issues, PURA requires utilities identified in the 1998 ECOM Report as having stranded costs to apply excess earnings to net generation plant assets. PURA § 39.254.21 Consistent with the statutory requirement, Reliant Energy assumed for purposes of the ECOM model that it would have excess earnings of $278 million in 1999 to apply to net generation plant assets. See Reliant Energy Ex. A-24 at 8-9. Reliant Energy forecasted an additional $129 million of excess earnings in 2000, and $72 million in excess earnings for 2001. See Reliant Energy Ex. A-39 at 2.

OPC witness Hugh Higgins claims that the excess earnings identified by Reliant Energy for the years 1999, 2000 and 2001 are understated by a total of $1,501,794,036. OPC Ex. 1 at 5. Relying on Mr. Higgins' contentions, Mr. Falkenberg reduced Reliant Energy's ECOM total by that amount. But for the reasons discussed below, Mr. Higgins' claims about purported excess earnings are so deeply flawed that they should be disregarded in their entirety. Therefore, Mr. Falkenberg's adjustment is improper as well.

1.	Net Revenue Adjustments

In projecting the Company's future net revenues, Mr. Higgins did no real analysis of the electric market in which Reliant Energy participates. On cross-examination, he admitted that he did not look at population growth in the Houston area; he did not consider any appliance efficiency changes that might have occurred; he did not look at employment growth information; and he did not examine changes in income levels. Tr. at 493-94. In fact, Mr. Higgins did not look at any economic parameters that might affect revenues. Id. at 494.

The only thing Mr. Higgins did to forecast net revenues was to perform a least squares linear regression analysis using the Company's net revenues for four years, 1996 through 1999.22 Id.; OPC Ex. 1 at 7-8. But his regression analysis is worthless because the data he used is incomplete and flawed.

The data is incomplete because it is based on only four data points. As Mr. Rice testified in rebuttal, "Applying a least squares regression method, which is basically an extrapolation of average increases, to only four data points that have not even been weather adjusted is unlikely to lead to meaningful results." See Reliant Energy Ex. A-17 at 38. Mr. Higgins admitted, "I don't know how many [data] points it takes for accuracy . . . ." Tr. at 496. He claimed to believe that four data points were sufficient, but when pressed for his authority for that statement, he merely replied, "It's just my – just my feeling in that it is."23 Id. Despite his "feeling" about the number of data points needed to perform a least squares linear regression analysis, Mr. Higgins conceded that with respect to data points, "the more the better." Id.

The data is flawed because it is not representative of normal conditions. Mr. Rice testified that the years Mr. Higgins used for his regression analysis contained "near-record energy pricing and related job activity, as well as a period of record temperatures and intense cooling-related electricity usage." Reliant Energy Ex. A-17 at 38. Moreover, Reliant Energy witness Michael Frazier stated that Reliant Energy must adjust "its historical energy sales data to account for the impact of unusually warm or cool temperatures," and that the adjustment "is important due to the highly variable nature of weather on the Texas Gulf Coast and in the HL&P service area." Reliant Energy Ex. A-10 at 7. Even Mr. Falkenberg admitted that weather adjustments are a "standard feature" of ratemaking in Texas, and that 1998 was an abnormally hot year. Tr. at 925-26. Yet Mr. Higgins did not even make an effort to weather-adjust the data for 1998 or any other year. Id. at 497. He further admitted that he did not know whether all four of the years from 1996-99 were hotter than the 30-
year average. Id. at 499.

The data is also flawed because it ignores known changes that will affect Reliant Energy's load in 2000 and 2001. Reliant Energy's net revenue forecast incorporated expected revenue losses resulting from the General Land Office's sales to public retail customers in 2000 and 2001. Reliant Energy Ex. A-17 at 38. It also accounted for pilot program load losses in 2001 and the lost revenues attributable to increased self-generation. Id.; see also Reliant Energy Ex. A-10 at 24 (noting that "a major driver of future usage is the considerable additional loss of load to self-generation by large industrial customers"). Indeed, TIEC witness Jeffrey Pollock testified that new generation facilities will displace "about 19% of Reliant's entire industrial sales base." TIEC Ex. 4 at 11. Further, Reliant Energy's forecasts considered demand side management programs and the effects of SB 7 provisions on net revenues. Id. Mr. Higgins' forecasting method makes no allowance for any of those changes. See Tr. at 500 (Mr. Higgins admitting that he "did not pay any attention to" items that were not addressed in Reliant Energy's direct testimony). Mr. Higgins' forecast is therefore completely unreliable and should not be incorporated into Mr. Falkenberg's adjustment.`

2.	Operations and Maintenance Adjustments

In calculating Reliant Energy's excess earnings, Mr. Higgins recommends that forecasted O&M expense be reduced by approximately $164 million in 2000 and $169 million in 2001. OPC Ex. 1 at 9. But his simplistic analysis is unsound because he relies solely on the O&M escalators prescribed in Order No. 25 without adjusting for important changes that will occur. For example, Mr. Higgins has assumed that inter-utility transmission payments will remain at $13 million in 2000 and 2001. Beginning in 2000, however, Reliant Energy is required to use the postage stamp methodology to calculate those transmission costs, and the new methodology will sharply increase O&M costs.24 See Reliant Energy Ex. A-24 at 5. Yet Mr. Higgins completely ignored this significant new expense that Reliant Energy will incur in 2000 and 2001. Tr. at 502 ("Now you have ignored the [inter] utility transmission cost payments in your operations and maintenance forecast, haven't you?" "Right, yes, sir, I did.").

In addition, Mr. Higgins also removed Reliant Energy's franchise fee expense from O&M expense forecasts. Reliant Energy Ex. A-24 at 6. Franchise fee expenses are unquestionably O&M expenses, and Mr. Higgins has provided no explanation for omitting these normal and recurring expenses. Adding back these expenses increases O&M expenses by $97 million in 2000 and $99 million in 2001. Id.

In addition to ignoring known changes to O&M expenses, Mr. Higgins erred by applying the O&M escalators set forth in Order No. 25. In fact, Order No. 25 does not address O&M escalators for the ECOM calculation. The O&M escalators in Order No. 25 apply only to the transmission and distribution utility; they do not address generation-related expenses in the ECOM model. Therefore, the escalators in Order No. 25 are inappropriate to use for ECOM purposes and Mr. Higgins' proposed adjustment should be rejected.

3.	Other Adjustments

Mr. Higgins' other adjustments to inflate excess earnings are also groundless. For example, to achieve a smaller amount of depreciation, he reduces Reliant Energy's estimates of invested capital by the amounts of regulatory assets that are approved for securitization, but he fails to make any corresponding adjustments to his projections of total revenues. It is clearly wrong to reduce rate base as if securitization will occur and leave the full amount of base revenues intact for purposes of calculating excess earnings, as if no securitization has occurred. Reliant Energy Ex. A-24 at 8.

Mr. Higgins also misstates the 1999 excess earnings. In HKH-1, he claims that the 1999 excess earnings were $476 million. In fact, the documents that Mr. Higgins attached to his own testimony demonstrate that the correct amount is $278 million. See OPC Ex. 1 at 41 ("1999 Excess Earnings totaling $277.6M"); see also Reliant Energy Ex. A-24 at 9 ("The correct number is $278 million."). By overstating 1999 excess earnings, Mr. Higgins necessarily understated Reliant Energy's actual depreciation for that year by $198 million. Thus, all of his remaining calculations regarding excess earnings are meaningless and should be disregarded.

Moreover, Reliant Energy's forecast of accumulated depreciation and amortization is based on the forecasting of plant additions, normal book depreciation, Construction Work in Progress balance, retirements, salvage and removal costs. Reliant Energy Ex. A-24 at 9. Using this specific forecasted information for each year produces an accumulated depreciation amount that is more accurate than using a historic percentage, which does not reflect changes in the rates of growth of those items. Id. Thus, there should be no adjustment to accumulated depreciation to account for Mr. Higgins' historic percentage calculation.

Finally, Mr. Higgins' federal income tax ("FIT") adjustments are also wrong. He calculates FIT based on the average effective tax rate of 24.558% for the years 1996 through 1999. OPC Ex. 1 at 10. Reliant Energy correctly used current year amounts for amortization of investment tax credits, excess deferred FIT, tax permanents and interest included in return. Those amounts can be, and in fact are, significantly different in 2000 and 2001 than in the years 1996 through 1999. Reliant Energy Ex. A-24 at 8. Therefore, the change proposed by Mr. Higgins is inappropriate and should be rejected.

G.	Redirected Depreciation and Excess Earnings

In the November 10, 2000 prehearing conference, the ALJ ordered Reliant Energy to quantify the amounts of accelerated depreciation, redirected depreciation and excess earnings. Reliant Energy will comply with that order. Nevertheless, as discussed below, Reliant Energy does not believe that the Commission has the legal authority to require utilities, prior to the 2004 stranded cost true-up, to implement measures to address over-recovery of stranded costs through excessive mitigation.

1.	Amounts of Additional Depreciation, Redirected Depreciation and Excess Earnings Applied to Reduce Net Generation Rate Base

As of the end of 1999, Reliant Energy had redirected approximately $393.293 million of depreciation from transmission and distribution assets to generation assets, consistent with SB 7 and the transition plan approved in PUC Docket No. 18465. In 2000, Reliant Energy anticipates that it will redirect another $225.839 million of depreciation to generation assets. The estimated amount for 2001 is $244.789 million. Thus, the total for redirected depreciation by the end of 2001 will be approximately $863.921 million.25

By the end of 1999, Reliant Energy had applied $476.871 million of excess earnings to the net book value of generation assets in accordance with PURA § 39.254 and the Commission Order in Docket No. 18465. In the ECOM model for 2000, Reliant Energy applied another $129.452 million of excess earnings to reduce the net book value of generation assets, as well as $72.605 million in 2001. The total amount of excess earnings applied by the end of 2001 is approximately $678.928 million.

It would be improper to assume for purposes of this docket that the foregoing amounts of redirected depreciation and excess earnings can simply be reversed or offset against transmission and distribution rates to remedy any estimated "excess" mitigation. Redirected depreciation and excess earnings are inputs to the ECOM model, and any changes to the amounts would have ripple effects within the ECOM model. For example, reversing redirected depreciation would increase generation rate base and thereby increase revenue requirements. It would also increase income taxes, property taxes and numerous other inputs. Thus, the ECOM model must be rerun before the effects of reversing mitigation efforts can be quantified.

Moreover, Mr. Norwood did not properly quantify the effect of reversing redirected depreciation, as Houston's counsel has suggested. Mr. Norwood assumed, without foundation, that Reliant Energy has redirected $1.0 billion of depreciation. See Houston Ex. 8 at 43. As noted above, Reliant Energy has not redirected that much depreciation; in fact, it will not have redirected that amount of depreciation by the end of 2001. Therefore, Mr. Norwood's testimony and Figure DSN-
12 are unreliable.

For the reasons discussed below, Reliant Energy does not believe the Commission has authority to order a cessation or reversal of mitigation efforts prior to the stranded cost true-up proceeding in 2004. But even if it did, it would be necessary to rerun the ECOM model to estimate the ensuing effects on the ECOM calculation.

2.	Lack of Legal Authority to Cease or Reverse Redirected Depreciation and Excess Earnings Before 2004

In its Order on Certified Questions in this docket, the Commission indicated that it believes it has the power to order utilities to stop redirection of depreciation and to reverse past redirection of depreciation. See Order on Certified Questions at 12. The Commission further opined in that Order that it has the authority to order utilities to return so-called excess earnings to customers through a power cost recovery factor ("PCRF") or an "excess mitigation charge." Id. at 14.

As noted in the introduction, Reliant Energy's goal in the 2004 true-up is to recover the December 31, 2001 book value of generation assets, as adjusted for the calculations in PURA §§ 39.262(d), 39.262(e) and 39.263. If the market value of the generation assets is greater than the adjusted book value, Reliant Energy will not retain the excess. But that applies in 2004. PURA § 39.254 does not confer any discretion on utilities or the PUC before that time with respect to the application of excess earnings. PURA § 39.254 states that any utility identified in the 1998 ECOM Report as having positive excess costs over market must use the mitigation efforts cataloged in Chapter 39 to reduce the book value of stranded costs. In addition, PURA § 39.254 states that any "positive difference under the report required by Section 39.257(b) shall be applied to the net book value of generation assets." PURA § 39.254 (emphasis added). Thus, to the extent Reliant Energy reports a positive difference between annual revenues and annual costs as provided by PURA § 39.257(b), it must apply that positive difference to the net book value of generation assets. The Commission cannot order Reliant Energy to violate the statute by diverting earnings to ratepayers through a PCRF or "excess mitigation charge." In fact, the utilities do not even have the power to stop applying the positive difference to the net book value of generation assets, because the statute imposes a mandatory duty. See Tex. Gov't Code Ann. § 311.016 (Vernon 1998) (stating that the term "shall" imposes a duty). Reliant Energy respectfully submits that an order to stop or reverse the application of excess earnings to generation plant prior to the true-up proceeding would be contrary to PURA § 39.254 and therefore unlawful.

The Commission also lacks authority to order utilities to cease or reverse redirection of depreciation prior to the 2004 true-up proceeding. PURA § 39.256 makes redirection of depreciation optional, but it is optional with the utility, not the Commission. If the utility decides to redirect depreciation, the Commission has no choice but to accept that redirection:

Any adjustments made to the book value of transmission and distribution assets or the creation of any related regulatory assets resulting from the redirection under this section shall be accepted and applied by the commission for establishing net invested capital and transmission and distribution rates for retail customers in all future proceedings.

PURA § 39.256(c) (emphasis added). This language makes clear that the Commission has a duty to accept and apply the redirection of deprecation. By ordering utilities to cease or reverse redirection of depreciation, the Commission is essentially saying that it does not have to accept and apply the redirected depreciation. But the Commission has no power to violate its governing statute.

Nor is it sufficient to say that Reliant Energy should voluntarily stop redirection of depreciation. Those utilities identified in the 1998 ECOM Report as having potentially stranded costs are under a statutory obligation to mitigate those stranded costs. PURA § 39.254. If they voluntarily cease mitigation efforts, they do so at the risk of being penalized for failing to mitigate stranded costs.

In fact, Reliant Energy does not believe that it has fully mitigated its stranded costs. It is true that the stranded cost amount produced by the ECOM model is essentially zero, but no party can seriously contend that the ECOM model accurately predicts what stranded costs will be in 2004. As Staff witness Darryl Tietjen noted in his testimony, the ECOM model is merely an administrative estimate of ECOM, and "such estimates are inherently uncertain." Staff Ex. 1 at 13. Mr. Tietjen further noted, "The results of the ECOM model can vary quite dramatically with different input assumptions and, as was exceedingly apparent in Docket No. 22344, substantial differences of opinion exist on virtually all these assumptions." Id. Because Reliant Energy believes that it will have stranded costs under the 2004 market-based true-up, prudence militates in favor of continuing mitigation efforts. Moreover, the Commission has adequate tools to use in connection with the true-
up proceeding conducted under PURA § 39.262 to make sure Reliant Energy does not over-recover stranded costs as a result of "the procedures established by this section [PURA § 39.262] or through the application of the measures provided by the other sections of this chapter." See, e.g., PURA §§ 39.254, 39.256.

IV. Conclusion

After the pretrial rulings in this cause, Reliant Energy was left with an ECOM estimate of only $15.78 million. The Staff and Intervenors are asking this tribunal to whittle that number down even further in an effort to create "headroom" for the competitive market.

While that goal may be laudable, the Legislature has established a carefully constructed process for making the transition from regulated to competitive markets. One of the first steps is to determine the CTC, if any. To accomplish this result, SB 7 requires the interim charge to be established by the ECOM model. Reliant Energy has fully complied with this requirement. The Intervenors and Staff quarrel with some of the inputs and assumptions that Reliant Energy has used in the model, but those complaints are erroneous for the reasons described in this brief.

Moreover, the remedies that have been recommended by the Commission relating to the treatment of excess earnings and redirected depreciation are premature. If Reliant Energy has truly over-mitigated stranded costs, PURA § 39.262 allows the Commission to cure that over-recovery only in 2004. There is no statutory basis to do so now.

Reliant Energy reiterates that its goal in the final 2004 true-up is to recover the December 31, 2001 book value of generation assets adjusted for the calculations in PURA §§ 39.262(d), 39.262(e) and 39.263. If the market value of Reliant Energy's generation assets is greater than the adjusted book value of those assets, Reliant Energy does not intend to retain the excess. Therefore, regardless of the amount of mitigation, market value or CTC, ratepayers will be made whole through the true-
up in 2004.

For these reasons, the CTC should be set at zero, and the redirection of depreciation and application of excess earnings to reduce the net book value of generation plant should continue until the end of 2001 in accordance with statute.

Respectfully submitted,

____________________________________

THOMAS B. HUDSON, JR.	HUGH RICE KELLY

State Bar No. 10168500	Executive Vice President and

RON H. MOSS	General Counsel

State Bar No. 14591025	State Bar No. 11220500

Graves, Dougherty, Hearon & Moody, P.C.	GEORGE W. SCHALLES, III

P.O. Box 98	Managing Attorney, Regulatory Law

Austin, Texas 78767	State Bar No. 17725500

(512) 457-5724 Telephone	P.O. Box 61867

(512) 472-8389 Facsimile	Houston, Texas 77208

(713) 207-7418 Telephone

SCOTT E. ROZZELL	(713) 207-0141 Facsimile

State Bar No. 17359800

Baker Botts L.L.P.

910 Louisiana Street

Houston, Texas 77002

(713) 229-1835 Telephone

(713) 229-1522 Facsimile

Certificate of Service

SOAH Docket No. 473-00-1020

PUC Docket No. 22355

I hereby certify that a true and correct copy of the foregoing document was served by either hand delivery, electronic mail, overnight delivery or United States first class mail to all parties on this 14th day of November 2000.

___________________________

Ron H. Moss