Entergy Texas, Inc. v. Public Utility Commission of Texas, Office of Public Utility Counsel, and Texas Industrial Energy Consumers

Opinion

ACCEPTED 03-14-00709-CV 4377970 THIRD COURT OF APPEALS AUSTIN, TEXAS 3/5/2015 9:28:45 AM JEFFREY D. KYLE CLERK No. 03-14-00709-CV

IN THE FILED IN 3rd COURT OF APPEALS THIRD COURT OF APPEALS AUSTIN, TEXAS AT AUSTIN 3/5/2015 9:28:45 AM JEFFREY D. KYLE ENTERGY TEXAS, INC., Clerk Appellant, v.

PUBLIC UTILITY COMMISSION OF TEXAS, Appellee.

Appeal from the 53rd Judicial District Court, Travis County, Texas The Honorable Amy Clark Meachum, Judge Presiding

________________________________________________________________

APPELLANT’S REPLY BRIEF

_________________________________________________________________

John F. Williams State Bar No. 21554100 jwilliams@dwmrlaw.com Marnie A. McCormick State Bar No. 00794264 mmccormick@dwmrlaw.com DUGGINS WREN MANN & ROMERO, LLP 600 Congress Ave., Ste. 1900 (78701) P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax

ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC.

ORAL ARGUMENT REQUESTED March 2015

TABLE OF CONTENTS

TABLE OF CONTENTS ........................................................................................... i

INDEX OF AUTHORITIES.................................................................................... iii

ARGUMENT AND AUTHORITIES ........................................................................1

I. The CGS program is the result of legislative choices that differ dramatically from traditional utility regulation. ..............................................1

II. The Commission has ignored part of the legislative enactment, contrary to the most basic rules of statutory construction. ..............................2

A. The Commission's order is not sustainable on an undecided factual theory. ........................................................................................4

B. The Commission’s error is not harmless. ..............................................7

C. The 2011 CenterPoint case does not support the Commission’s interpretation of the CGS statute. ........................................................13

1. The statute at issue in CenterPoint authorized recovery of very specific costs; the CGS statute is not so limited. ..............13

2. Here, ETI seeks to recover the very type of costs the CGS statute authorizes it to recover. ........................................14

D. The principle of cost-causation does not justify the Commission’s disregard of language in the CGS statute....................17

1. This issue is a red herring. ........................................................17

2. Though it may not be clear which customers should pay “unrecovered costs,” it is clear that ETI may not be required to absorb them. ...........................................................19

3. The Commission’s brief casts doubt upon whether it would be patently unfair to allocate “unrecovered costs” to ineligible customers. .............................................................19

4. If the statute inescapably dictates an unpalatably unfair result, the solution was to decline to adopt the program. .........21

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E. Other traditional ratemaking principles do not trump the plain language of the CGS statute. ...............................................................21

1. The CGS statute is an exception to the traditional regulatory scheme. ....................................................................21

2. PURA 11.002 does not shed any light on the proper interpretation of the CGS statute. .............................................22

3. The concept of “regulatory lag” does not absolve the Commission of its duty to follow the plain language of the statute. .................................................................................23

4. The reference to discount rates in the CGS statute supports ETI’s argument. ..........................................................24

III. The Commission’s decision not to allow ETI to recover all of its costs of implementing the CGS tariff is reversible because it, too, contradicts the plain language of the statute..................................................26

IV. The Commission’s decision not to allow ETI to recover interest on its unrecovered costs is reversible because the CGS statute entitles ETI to all of its unrecovered costs. ...........................................................................27

CONCLUSION AND PRAYER .............................................................................29

CERTIFICATE OF COMPLIANCE .......................................................................30

CERTIFICATE OF SERVICE ................................................................................31

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INDEX OF AUTHORITIES

Cases CenterPoint Energy Entex v. Railroad Comm’n of Tex., 213 S.W.3d 364 (Tex. App. – Austin 2006, no pet.).............................................7 CenterPoint Energy Houston Elec., LLC v. Public Util. Comm'n of Tex., 354 S.W.3d 899 (Tex. App. – Austin 2011, no pet.) .................................... 13, 14 CenterPoint Energy, Inc. v. Public Util. Comm’n of Tex., 143 S.W.3d 81 (Tex. 2004) .......................................................................... 28, 29 City of Dallas v. Railroad Comm’n of Tex., No. 03-06-00580-CV, 2008 WL 4823225 *1 (Tex. App. – Austin Nov. 6, 2008, no pet.) ........................................................................................................15 City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179 (Tex. 1994) ................................................................................15 Columbia Med. Ctr. of Las Colinas, Inc. v. Hogue, 271 S.W.3d 238 (Tex. 2008) ..................................................................................4 Continental Imports, Ltd. v. Brunke, No. 03-10-00719-CV, 2011 WL 6938489 *5 (Tex. App. – Austin Dec. 30, 2011, pet. denied) ...................................................7 Hooks v. Texas Dep’t of Water Resources, 611 S.W.2d 417 (Tex. 1981) ..................................................................................7 Houston Mun. Employees Pension Sys. v. Abbott, 192 S.W.3d 862 (Tex. App. – Texarkana 2006, pet. denied).................................4 Jackson v. State Office of Administrative Hearings, 351 S.W.3d 290 (Tex. 2011) ................................................................................21 Office of Public Util. Counsel v. Texas-New Mexico Power Co., 344 S.W.3d 446 (Tex. App. – Austin 2011, pet. denied) .....................................27 Railroad Comm’n of Tex. v. High Plains Natural Gas Co., 628 S.W.2d 753 (Tex. 1981) ................................................................................24 State v. Public Util. Comm’n, 883 S.W.2d 190 (Tex. 1994) ...............................................................................27 State v. Shumake, 199 S.W.3d 279 (Tex. 2006) ..................................................................................3

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Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358 (Tex. 1983) ................................................................................15 Texas Ass'n of Business v. Texas Air Control Bd., 852 S.W.2d 440 (Tex. 1993) ..................................................................................7 Texas Coast Utils. Coalition v. Railroad Comm’n of Tex., 423 S.W.3d 355 (Tex. 2014) .................................................................................4 Texas Nat’l Bank v. Karnes, 717 S.W.2d 901 (Tex. 1986) ...............................................................................12 Statutes Tex. Gov’t Code Ann. § 2001.141...........................................................................12 Tex. Util. Code Ann. § 11.002 .................................................................................22 Tex. Util. Code Ann. § 36.003 .................................................................................19 Tex. Util. Code Ann. § 36.007 .................................................................................25 Tex. Util. Code Ann. § 36.061 .................................................................................28 Tex. Util. Code Ann. § 36.201 .................................................................................24 Tex. Util. Code Ann. § 39.452 ......................................................................... passim Tex. Util. Code Ann. § 39.905 .................................................................................13 Commission Proceedings Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 41791 ..............................................................9 Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment, Docket No. 39896 ......................................................................................................................9

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TO THE HONORABLE THIRD COURT OF APPEALS:

Entergy Texas, Inc. (“ETI”) submits this reply to the briefs of the Public

Utility Commission of Texas (the “Commission” or “PUCT”), Texas Industrial

Energy Consumers (“TIEC”), and the Office of Public Utility Counsel (“OPUC”).

ARGUMENT AND AUTHORITIES

I. The CGS program is the result of legislative choices that differ dramatically from traditional utility regulation.

There is an unwarranted undercurrent of blame running through the

Commission’s brief. Contrary to the Attorney General’s rhetoric, ETI does not

seek a “free lunch,” to “avoid the reality of competition,” or to “maintain its

monopoly” by “designing an unfair program that is sure to be rejected.” Nor is

ETI “insinuating” or “pretending” “nonsense.”1

ETI proposed the competitive generation service (“CGS”) program because

the legislature mandated that it propose one. See Tex. Util. Code Ann.

§ 39.452(b). Moreover, this is a new program that differs in fundamental respects

from the way utilities have operated under traditional regulation. In crafting the

CGS statute, the legislature both expressly and impliedly rendered certain

traditional ratemaking principles inapplicable or unworkable. For example:

• Utilities subject to traditional regulation are responsible for procuring power for all their customers. The CGS program

1 See PUCT’s Brief at 29 & 30.

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provides a unique opportunity for some customers to contract for their own power.

• Utility rates are traditionally set based upon historical levels of expense. CGS program rates must be set in the same proceeding in which the program itself is created, even though there are no historical CGS expenses.

• Under traditional regulation, utilities charge rates to customers that include generation, transmission, and distribution costs. ETI, however, must charge an “unbundled” transmission services rate to CGS customers, who are deemed not to be “wholesale transmission customers.”

• Because bundled rates are set for the future based upon historical expenses, utilities generally bear the risk that costs will increase before the next rate case. In the CGS statute, the legislature expressly entitled ETI to recover “costs unrecovered as a result of the implementation of” the program.

• In contrast to general ratemaking principles, the legislature in the CGS statute specified that some customers may not bear the burden of unrecovered costs. It protected “manufacturers” who choose not to participate in the program.

• And though PURA generally limits a regulated utility’s ability to offer discount rates and then burden other customers with the costs the discounted customer avoids, CGS program rates “may not be considered to offer a discounted rate.”

The CGS program is not business as usual.

II. The Commission has ignored part of the legislative enactment, contrary to the most basic rules of statutory construction.

Over the lengthy course of the underlying contested case, the parties were

never able to agree unanimously on several issues, including the scope of ETI’s

entitlement to recover costs, the extent to which the CGS program may cause ETI

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not to recover costs embedded in its bundled rates, and who may fairly be required

to pay for any of those unrecovered costs.2 Though appellees continue to debate

the latter two issues, they are not bases for the agency order under review. The

Commission avoided those issues by defining the term “unrecovered costs” as

excluding production-related costs embedded in ETI’s bundled rates.3

The CGS statute entitles ETI “to recover any costs unrecovered as a result of

the implementation of the tariff.” Tex. Util. Code Ann. § 39.452(b). The breadth

of those words, and their failure to exclude any category of costs, cannot

reasonably be disputed. Nevertheless, the Commission has declared that the statute

authorizes ETI to recover only certain costs – specifically, those “of”

implementing the program. The Commission has effectively written several words

out of the statute, as illustrated below:

The utility’s rates shall be set … to recover any costs unrecovered as a result of the implementation of the tariff….

This interpretation violates the paramount rule of statutory construction that

statutes must be construed according to their plain language. E.g., State v.

Shumake, 199 S.W.3d 279, 284 (Tex. 2006). The truest manifestation of what

legislators intended is what they enacted: the literal text they voted on. Texas

Coast Utils. Coalition v. Railroad Comm’n of Tex., 423 S.W.3d 355, 363 n.16

2 Administrative Record (“AR”) Part I, Binder 2, Item 119 (Final Order at FOFs 11, 14, 18, 19, 27, 32-48, 52-56 & COLs 1-2). 3 AR Part I, Binder 2, Item 119 (Final Order at 6, 7-8, 11, FOFs 49-51, COL 2).

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(Tex. 2014). The legislature is presumed to have chosen its words with care, and

statutes should not be construed to render legislatively enacted words superfluous.

E.g., Columbia Med. Ctr. of Las Colinas, Inc. v. Hogue, 271 S.W.3d 238, 256

(Tex. 2008). Moreover, when the meaning of a statute is plain from its text, rules

of construction or other extrinsic aids cannot be used to create ambiguity. E.g.,

Houston Mun. Employees Pension Sys. v. Abbott, 192 S.W.3d 862, 864 (Tex. App.

– Texarkana 2006, pet. denied). The Commission may not disregard or rewrite the

unambiguous mandate of the CGS statute.

A. The Commission's order is not sustainable on an undecided factual theory.

The Attorney General and TIEC assert that the Commission instead

determined that all of ETI’s base-rate production costs will in fact be recovered

through the CGS program that was ultimately adopted.4 The agency said no such

thing. The Commission did not reach that question because, again, the

Commission said the statute does not entitle ETI to recover that type of cost at all.

TIEC champions the factual theory anyway, presumably because it was

TIEC’s principal argument to the agency. TIEC actually agreed that, “[i]f … the

Commission determines that there are unrecovered costs, then Entergy is entitled

4 PUCT’s Brief at 15; TIEC’s Brief at 6-10, 14, 22-23, & 35-37.

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under the statute to recover any such costs.”5 To TIEC, the dispute should not be

about the scope of the statutory entitlement – it should be about whether ETI

would actually recover all of its costs.6

The Commission disagreed with TIEC about that. After the parties tried

unsuccessfully to settle remaining issues, the Commission conducted a hearing to

consider “the remaining contested threshold issue – what types of costs will be

considered unrecovered for purposes of PURA 39.452(b)….”7 Though the issue is

one of law, the parties submitted testimony on the proper interpretation of the

statute to aid the Commission in its determination.8 After the hearing, the

Commission issued an interim order “making its determination of the definition of

unrecovered costs.”9 The Commission said:

[T]he proper interpretation of “costs unrecovered as a result of implementation of the CGS program tariff” is costs to implement and administer the CGS program tariff. Such unrecovered costs do not include lost revenues, embedded generation costs, or any other types of costs. The Commission reverses the proposal for decision on this issue.[10]

In its final order, the Commission acknowledged its interim ruling that:

5 AR Part I, Binder 1, Item 22 (TIEC’s Nov. 1, 2011, List of Unsettled Issues and Request for Procedural Schedule at 3). 6 Id. at 4 n.3. 7 AR Part I, Binder 2, Item 119 (Final Order at 3 (emphasis added), 7, & FOF 20); see also AR Part I, Binder 1, Item 77 (Interim Order at 1 & 5). 8 E.g., AR Part II, Binder 3, ETI Exh. 91 (Supp. Direct Testimony of P. May at 5-6 of 23); AR Part II, Binder 4, TIEC Exh. 15 (Supp. Direct Testimony of J. Pollock at 14). 9 AR Part I, Binder 1, Item 77 (Interim Order at 6) (emphasis added). 10 Id.

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the types of costs that will be considered ETI’s unrecovered costs for purposes of PURA § 39.452(b) are those costs necessary to implement and administer the CGS program and are not to be defined to include lost revenues, embedded generation costs, or any other types of costs.[11]

The Commission held fast to its previous interpretation of the statute:

The Commission … finds that unrecovered costs are only those costs necessary to implement and administer the CGS program and are not to be defined to include lost revenues, embedded generation costs, or any other types of costs.[12]

***

2. PURA § 39.452(b) does not allow for the recovery of lost revenue or embedded generation costs.[13]

A review of the whole order reveals that it is TIEC, not ETI, that is

“plucking” isolated words out of context.14 It is abundantly clear throughout the

order that the Commission’s decision was premised not upon a factual

determination about the extent to which ETI might not recover base-rate costs, but

upon a legal conclusion about the scope of costs recoverable under the CGS

statute.15

For that reason, the order cannot be affirmed on TIEC’s factual theory. This

Court has repeatedly recognized that an agency order can be upheld on any legal

basis shown in the record, but it may not be sustained on an unarticulated factual

11 AR Part I, Binder 2, Item 119 (Final Order at FOF 20) (emphasis added). 12 Id. at 6. 13 Id. at COL 2. 14 See TIEC’s Brief at 36. 15 AR Part I, Binder 2, Item 119 (Final Order at 6, 7-8, 11, FOFs 49-51, COL 2).

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theory. See Continental Imports, Ltd. v. Brunke, No. 03-10-00719-CV, 2011 WL

6938489 *5 (Tex. App. – Austin Dec. 30, 2011, pet. denied) (not designated for

publication) (citations omitted).

B. The Commission’s error is not harmless.

Though the Commission did not decide any factual dispute about

unrecovered costs, and though the Attorney General recognizes that this case

presents a legal question of statutory interpretation,16 the Attorney General now

advances a “no harm, no foul” theory. That is, the Attorney General contends that

ETI is not “aggrieved” by any error in the Commission’s statutory interpretation

because ETI will in fact recover all its costs.17 The order cannot be sustained on

this basis.

The rule that only a party “aggrieved” by an agency order may challenge it

is the same as the rule that only a plaintiff with a “justiciable interest” may file a

lawsuit. Hooks v. Texas Dep’t of Water Resources, 611 S.W.2d 417, 419 (Tex.

1981); CenterPoint Energy Entex v. Railroad Comm’n of Tex., 213 S.W.3d 364,

368 (Tex. App. – Austin 2006, no pet.). This Court must review the pleadings in

favor of ETI, and if necessary, the record to determine if “any” evidence supports

standing. See Texas Ass'n of Business v. Texas Air Control Bd., 852 S.W.2d 440,

446 (Tex. 1993).

16 PUCT’s Brief at 17.

17 Id. at 12 & 22-29.

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ETI undeniably pled that it is aggrieved by the agency’s order because the

order deprives ETI of dollars it is entitled to recover under the CGS statute.18 No

one disputed that ETI made this allegation in district court.

Moreover, there is abundant evidence in the record showing that the

Commission’s order deprives ETI of an opportunity to recover all of its costs. The

CGS program was ultimately designed such that participating CGS customers

would bear the costs of the energy and capacity that they contract for under the

CGS program. But the program does not, even as redesigned through negotiations,

impose upon participating customers all the costs they would have borne under the

bundled rates that were set through the traditional ratemaking process.

Under the traditional regulatory scheme, ETI must arrange generation

resources to serve all of its customers. ETI’s generation portfolio consists of many

types of resources. Those include power plants owned and operated by ETI and its

affiliates, short-term purchased capacity contracts, and long-term purchased

capacity contracts. ETI makes commitments and incurs costs to serve all its

customers, including the LIPS class, not knowing which of them might ultimately

migrate to the CGS program, or for how long. The Commission determined in

18 See CR 5.

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Docket No. 37744 and subsequent rate cases19 which of those costs ETI reasonably

and necessarily incurred, and set base rates to recover those costs.20

When a LIPS customer migrates to the CGS program, the customer will

receive a credit for the embedded production costs the customer would have paid

under ETI’s base rates.21 The credit is some $6.50/kW/month.22 But ETI is still at

risk of having to pay these costs.

Several ETI witnesses explained that the Entergy system must continue to

plan for and acquire short-, limited-, and long-term resources to reliably serve all

its Texas customers, including LIPS customers who may or may not choose to

participate in the CGS program.23 These witnesses acknowledged that the CGS

program may help ETI avoid acquiring some capacity in the future.24 However,

the program has a limited ability to relieve ETI of its planning obligations because

19 The Commission has reset ETI’s bundled rates twice since the Commission adjudicated Docket No. 37744. See Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment, Docket No. 39896; Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 41791. 20 See Supplemental Administrative Record (“Supp. AR”) Part I, Binder 2, Item 53 (Docket No. 37744 Order at FOFs 35 & 40, COLs 7, 9, & 12). 21 AR Part II, Binder 3, ETI Exh. 91 (Supp. Direct Testimony of P. May at 8-9 of 23); AR Part II, Binder 3, ETI Exh. 101 (Supp. Direct Testimony of D. Roach at 6 of 23). 22 AR Part I, Binder 2, Item 119 (Final Order at FOF 53(A)). This credit is subject to adjustment in future rate cases. Id. at FOF 41(C)(4). 23 AR Part II, Binder 3, ETI Exh. 91 (Supp. Direct Testimony of P. May at 4 of 23); AR Part II, Binder 3, ETI Exh. 95 (Supp. Rebuttal Testimony of S. Dingle at 7-8 of 26); AR Part II, Binder 3, ETI Exh. 101 (Supp. Direct Testimony of D. Roach at 7 of 23). 24 AR Part II, Binder 3, ETI Exh. 92 (Supp. Rebuttal Testimony of P. May at 27 of 30); AR Part II, Binder 3, ETI Exh. 95 (Supp. Rebuttal Testimony of S. Dingle at 8 of 26); AR Part II, Binder 3, ETI Exh. 101 (Supp. Direct Testimony of D. Roach at 7 of 23).

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of the short-term nature and other characteristics of CGS contracts.25 As ETI

witness Stephen Dingle testified:

The program … will not provide long-term resources to meet projected resource needs. The limited term nature of the proposed agreements, coupled with the uncertainty regarding the future continuation of the program, do not provide sufficient assurance that CGS resources will be available to meet ETI’s long-term resource needs. Furthermore, the program does not relieve ETI of its obligation to serve CGS customers in the event that providers withdraw or fail to renew under the program. Ultimately, the CGS program is at best a limited-term alternative that could defer or displace short- and limited-term PPAs [purchased power agreements], but it in no way can be considered a long-term resource option or affect ETI’s long-term acquisition strategy.[26]

Moreover, the CGS program in no way avoids embedded capacity costs that the

Company has already incurred, especially for existing power plants and long-term

purchased capacity contracts.27 Nor does the program enable ETI to recover a

return on investments it has already made to serve customers.28

This evidence was presented after the parties proposed that CGS suppliers

would provide service that Entergy could treat as “firm” capacity.29 The Attorney

General ignores it. Instead, the Attorney General points to testimony from other

25 AR Part II, Binder 3, ETI Exh. 92 (Supp. Rebuttal Testimony of P. May at 28 of 30); see also id. at 16 of 23; AR Part II, Binder 3, ETI Exh. 93 (Supp. Direct Testimony of A. O’Brien at 3 & 8 of 11); AR Part II, Binder 3, ETI Exh. 94 (Supp. Rebuttal Testimony of A. O’Brien at 2 of 7). 26 AR Part II, Binder 3, ETI Exh. 95 (Supp. Rebuttal Testimony of S. Dingle at 8 of 26). 27 See AR Part II, Binder 3, ETI Exh. 92 (Supp. Rebuttal Testimony of P. May at 28 of 30); AR Part II, Binder 3, ETI Exh. 95 (Supp. Rebuttal Testimony of S. Dingle at 12 of 26 & Exh. JSD- R-1, Pollock Depo. at 73-74); AR Part III, Vol. B (Transcript of Hearing on the Merits at 180- 82). 28 AR Part II, Binder 3, ETI Exh. 92 (Supp. Rebuttal Testimony of P. May at 29 of 30). 29 See, e.g., AR Part II, Binder 3, ETI Exh. 91 (Supp. Direct Testimony of P. May at 3 of 23).

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parties that, at best, suggests ETI may be able to avoid or mitigate some its base-

rate costs as customers migrate to the CGS program.30 ETI disputed the validity of

some of its opponents’ theories, and disputed the extent to which it could avoid

embedded production costs under others.31 ETI acknowledged that CGS customers

will pay a $1.10/kW fee that may offset some of the actual, embedded production

cost that CGS customers avoid by participating in the program.32 But even

considering the costs the Company may reasonably be able to avoid or mitigate,

about $3.50/kW/month of the Company’s embedded production costs will still be

unrecovered.33 The Court should not be misled into thinking that the CGS

program, even as ultimately designed, ensures that ETI will not have unrecovered

costs.

Nor would the CGS program that ETI proposed allow it to recover costs that

it does not actually incur. The CGSUSC rider contained true-up provisions that

would have ensured recovery only of actual, not hypothetical, costs.34 ETI did not

30 See, e.g., PUCT’s Brief at 24 & 26-28. 31 AR Part II, Binder 3, ETI Exh. 91 (Supp. Direct Testimony of P. May at 11-16 of 23); AR Part II, Binder 3, ETI Exh. 92 (Supp. Rebuttal Testimony of P. May at 7-18 of 30); AR Part II, Binder 3, ETI Exh. 95 (Supp. Rebuttal Testimony of S. Dingle at 5-26 of 26); AR Part II, Binder 3, ETI Exh. 93 (Supp. Direct Testimony of A. O’Brien at 4-8 of 11); AR Part II, Binder 3, ETI Exh. 94 (Supp. Rebuttal Testimony of A. O’Brien at 1-5 of 7); AR Part II, Binder 3, ETI Exh. 101 (Supp. Direct Testimony of D. Roach at 6-7 of 23). 32 AR Part II, Binder 3, ETI Exh. 92 (Supp. Rebuttal Testimony of P. May at 26 of 30). 33 AR Part II, Binder 3, ETI Exh. 91 (Supp. Direct Testimony of P. May at 17 of 23 & Exh. PRM-4). 34 See Supp. AR Part I, Binder 2, Item 36 (Docket No. 37744 Proposal for Decision at 18 & 21); Supp. AR Part II, Binder 3, ETI Exh. 9 (Direct Testimony of P. May, Exh. PRM-1); AR Part II, Binder 5, OOP-1.

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propose a program that would put the Company in a better position than it would

have been under traditional regulation. ETI simply sought to ensure that it would

not be in a worse position as a result of the program.35 That is, after all, what the

legislature mandated when it said CGS rates must be set to allow ETI to recover

“any costs unrecovered as a result of the implementation of the [CGS] tariff.” The

Commission’s erroneous interpretation of this mandate is not harmless – it

deprives ETI of any opportunity to recover costs that will effectively be “stranded”

as a result of the CGS program.

The Attorney General essentially invites this Court to find, based on

conflicting evidence, that ETI is not harmed by the Commission’s decision. But

this Court cannot make original findings of fact. E.g., Texas Nat’l Bank v. Karnes,

717 S.W.2d 901, 903 (Tex. 1986). Moreover, at this juncture, resolving this case

based on conflicting evidence would deprive ETI of its substantive right to

findings on fact issues upon which the agency decision rests. See Tex. Gov’t Code

Ann. § 2001.141. If the Commission indeed disposed of the case on TIEC’s

factual theory, the Commission was required to say so, and harmed ETI by failing

to do that.

35 AR Part II, Binder 3, ETI Exh. 92 (Supp. Rebuttal Testimony of P. May at 28 of 30).

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C. The 2011 CenterPoint case does not support the Commission’s interpretation of the CGS statute.

1. The statute at issue in CenterPoint authorized recovery of very specific costs; the CGS statute is not so limited.

The Commission based its interpretation of the CGS statute on this Court’s

decision in CenterPoint Energy Houston Elec., LLC v. Public Util. Comm'n of

Tex., 354 S.W.3d 899 (Tex. App. – Austin 2011, no pet.). As ETI explained in its

initial brief, that opinion does not concern the CGS statute. It concerns the Energy

Efficiency Cost Recovery Factor (“EECRF”) statute, which by its very terms,

authorizes a utility to recover only costs made for the specific purpose of satisfying

the goal of an energy efficiency program. See Tex. Util. Code Ann. §

39.905(b)(1). The EECRF statute does not authorize the recovery of other costs,

like those that “result from” the implementation of an energy efficiency program.

Id. That is why this Court held that the EECRF statute does not authorize a utility

to recover lost revenues that were intended to pay for something other than the

utility’s costs of implementing an energy efficiency program. CenterPoint Energy

Houston Elec., LLC, 354 S.W.3d at 904. Though the Court made observations

about other PURA provisions as well, it did not mention the CGS statute.

Moreover, none of those observations were essential to the Court’s interpretation

of the EECRF statute. Because the statute at issue in the 2011 CenterPoint case

14

and the one at issue here are materially different, appellees’ reliance upon the case

is misplaced.

2. Here, ETI seeks to recover the very type of costs the CGS statute authorizes it to recover.

In an attempt to make this case sound like CenterPoint, or perhaps because

they recognize that the legislature clearly intended ETI to recover all the costs that

will otherwise be unrecovered as a result of implementing the program, appellees

focus their efforts on arguing that ETI is seeking something other than “costs.”

They argue that because the word “revenue” appears in the proposed CGSUSC

rider, ETI is seeking to get (and presumably keep) money that it will not have to

pay out for any expense. That is not true. ETI has throughout this case sought to

recover the money the Commission authorized it to recover via test-year

ratemaking, because that was the amount of money the Commission determined is

necessary to pay ETI’s costs, and because the legislature entitled ETI to recover

that money in the CGS statute.

Appellees’ repeated suggestion that there is some significance to the way

ETI has characterized these amounts is without merit. It is true that ETI has

characterized this money as both “revenues” and “costs” in this case. But that is

not to “escape” this Court’s ruling in CenterPoint.36 ETI simply recognizes the

fundamental ratemaking principle that base rate costs are a utility’s revenue

36 See PUCT’s Brief at 21.

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requirement. They are flip sides of the same coin. Texas courts, including this

one, understand this concept. See, e.g., City of El Paso v. Public Util. Comm’n of

Tex., 883 S.W.2d 179, 187 (Tex. 1994) (ratemaking formula determines “revenue

requirement”); Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d

358, 362 (Tex. 1983) (ratemaking formula determines “cost of service”); City of

Dallas v. Railroad Comm’n of Tex., No. 03-06-00580-CV, 2008 WL 4823225 *1

(Tex. App. – Austin Nov. 6, 2008, no pet.) (not designated for publication) (using

“revenue requirement” and “cost of service” to describe the same thing). Even the

Attorney General acknowledges the logical link between “revenues” and “costs” in

test-year ratemaking.37

Appellees’ witnesses acknowledged that, putting semantics aside, what ETI

is seeking is a measure of expenses it will not recover as a result of implementation

of the program. OPUC witness Clarence Johnson testified that the costs at issue

are the embedded test-year production costs upon which base rates were

established in Docket No. 37744.38 He confirmed that fact again on cross-

examination:

Q. And the costs that may go unrecovered due to the CGTS [CGS]

program, they are reflected as part of the overall embedded costs in the test-year—right—that the rates are set on?

37 Id. at 36.

38 See Supp. AR Part II, Binder 4, OPUC Exh. 1 (Johnson Direct at 88).

16

A. There were costs allocated to the CGS customers and to their class. So in that sense, yes.39

TIEC witness Jeffry Pollock agreed on cross-examination that the Company’s

proposed rider would account for migrating customers’ share of the Company’s

embedded fixed production costs:

Q. And do you agree that if a LIPS customer decides to switch to CGS service that ETI will not collect the fixed production cost included in the LIPS rate from that customer?

A. I think the fact that the customer has switched [to CGS] and the Company is not collecting the same revenue certainly creates the potential that some costs would be uncollected...— unrecovered… unless there are some additional benefits to offset those unrecovered costs. That’s correct.40

Staff witness Stephen Mendoza confirmed on cross-examination that lost revenues

could be a measure of unrecovered costs.41 In any event, testimony on this point is

immaterial. What constitutes “costs” under the CGS statute is a question of law,

and no number of witnesses testifying that costs are not really costs can make it

true.

The Commission repeatedly suggests that ETI’s proposed rider would enable

it to recover amounts not contemplated by the test-year calculation, so ETI must

39 See Supp. AR Part IV, Vol. E (Docket No. 37744 7/20/2010 Transcript of Hearing on the Merits at 350-51). 40 See id. at 261-62; see also Supp. AR Part IV, Vol. D (Docket No. 37744 7/16/2010 Transcript of Hearing on Merits at 154-57 & 161-62). 41 Supp. AR Part IV, Vol. E (Docket No. 37744 7/20/2010 Transcript of Hearing on the Merits at 356).

17

not be seeking “costs.”42 As noted above, the rider contained a true-up provision

that would ensure ETI recovered only amounts it actually paid, not hypothetical

costs. Moreover, this argument concerns the extent to which ETI may have

unrecovered costs, not whether the CGS statute entitles ETI to recover them. That

ETI might get limited relief in a narrow, hypothetical situation (i.e., if a new LIPS

customer joins and participates in the CGS program) does not address or excuse

the Commission’s broad error in denying ETI a mechanism for full relief.

D. The principle of cost-causation does not justify the Commission’s disregard of language in the CGS statute.

OPUC, representing residential and small business customers, argues the

Commission’s order must be sustained because charging unrecovered base-rate

costs to customers who “indisputably” did not cause them (i.e., customers

ineligible for the CGS program) would be unfair and contravene traditional

ratemaking concepts embodied in PURA.43 The Commission echoes this

argument.44 This is no justification for upholding the Commission’s decision.

1. This issue is a red herring.

ETI’s challenge to the Commission’s order does not hinge on charging

“unrecovered costs” to one group of customers versus another. ETI expressed

opinions about which customers may be required to pay “unrecovered costs,” but

42 PUCT’s Brief at 24 & 33. 43 OPUC’s Brief at 6. 44 PUCT’s Brief at 16, 33, 35, & 41.

18

largely left the issue to the parties who represent the customer groups to resolve.

ETI did not join in or oppose the other parties’ stipulation on the subject.45

Ultimately, the Commission did not decide which customers should pay

unrecovered embedded production costs because the Commission determined they

are not recoverable from anyone.46 The effect of that decision is to impose the

costs on ETI. That result is what ETI disagrees with, because it violates the CGS

statute. Appellees tilt at windmills by arguing about which customers should or

must pay unrecovered costs, or whether ETI is somehow barred from taking a

position on the issue.47 The issue here is whether ETI, rather than customers, may

be forced to bear the costs.

45 AR Part I, Binder 1, Item 67 (Apr. 13, 2012, Stipulation). 46 Contrary to the Commission’s Statement of Facts, nowhere in the Commission’s order is there any hint that the agency rejected the proposed CGSUSC rider based upon principles of equity or any PURA provision other than the CGS statute itself. Indeed, the Attorney General does not cite the Commission’s order as support for that statement. Instead, the Attorney General cites the ALJ’s proposal for decision. See PUCT Brief at 6. It is true that the ALJ expressed a belief that it would be inequitable to shift unrecovered LIPS-class, base-rate costs to other customer classes through the CGSUSC rider. Supp. AR Part I, Binder 2, Item 36 (Docket No. 37744 Proposal for Decision at 24). That belief, coupled with the ALJ’s recognition that ETI will have unrecovered base rate costs that the CGS statute effectively precludes assigning to LIPS customers or ETI itself, is the reason the ALJ recommended that the CGS program not be adopted at all. Id. The Commission, however, did not adopt that recommendation. The Commission expressly reversed it, concluding that the costs are not recoverable and ordering ETI to implement the CGS program anyway. AR Part I, Binder 2, Item 119 (Final Order at 8). 47 OPUC begins its brief by arguing that ETI, by failing to oppose a stipulation among other parties to the case, “waived” its right to argue that customers ineligible for the CGS program may be required to pay “unrecovered costs.” OPUC’s Brief at 2-3. The Commission expressly found that ETI did not waive its right to appeal unsettled issues, and reserved its rights under applicable state and federal law. AR Part I, Binder 2, Item 119 (Final Order at FOF 55).

19

2. Though it may not be clear which customers should pay “unrecovered costs,” it is clear that ETI may not be required to absorb them.

It is true that the CGS statute does not expressly state which customer

groups should pay ETI’s unrecovered costs. But there can be no reasonable

disagreement that ETI gets to recover its costs from someone. And appellees

ignore that, to the extent there is inequity built into the CGS program, the

legislature – not ETI – has required this result. Just as the legislature had the

power to enact the general prohibition on preferential rates in PURA,48 it had the

power to enact an exception to that prohibition. There is no way to implement a

program in conformity with the terms of the CGS statute without, in some manner,

creating a preferential rate or assigning costs to customers that may not cause

them.

3. The Commission’s brief casts doubt upon whether it would be patently unfair to allocate “unrecovered costs” to ineligible customers.

OPUC argues it is unfair to allocate to customers who are ineligible for the

CGS program costs that would have been paid by LIPS customers under base

rates.49 The Attorney General, too, argues that it would be “absurd,” indeed

“anticompetitive,” to saddle ineligible customers with these costs.50 Implicit in

48 See Tex. Util. Code Ann. § 36.003. 49 OPUC’s Brief at 6. 50 E.g., PUCT’s Brief at 16, 35, & 39.

20

these arguments is the assumption that LIPS customers, not others, caused these

costs.

It is strange, then, that the Attorney General elsewhere questions whether

base rate costs allocated to LIPS customers in traditional rate cases were actually

caused by LIPS customers. The Attorney General notes that test-year expenses are

allocated to customer classes based on several factors, only one of which is the

principle of “cost causation.”51

First, regardless of whether the costs were “caused” by LIPS customers, the

costs were nevertheless allocated to LIPS customers in ETI’s rate cases. They are

the costs LIPS customers avoid by migrating to the program52 and, therefore, the

costs ETI is at risk of not recovering. ETI is entitled to recover them under the

CGS statute.

Second, the Attorney General’s insistence that LIPS customers do not

necessarily cause these costs defeats its own argument that it is unfair to charge

them to other customers. If the costs at issue were not necessarily caused by the

LIPS class, then how can the Attorney General logically argue it violates the

principle of cost causation to assign them to other customer classes? That makes

no sense. Someone caused the costs, because the Commission has determined in

rate cases that ETI reasonably and necessarily incurred them to serve customers.

51 Id. at 36-38.

52 AR Part I, Binder 2, Item 119 (Final Order at FOF 41(C)(2)-(4)).

21

4. If the statute inescapably dictates an unpalatably unfair result, the solution was to decline to adopt the program.

If the CGS program cannot fairly be implemented with full adherence to

statutory parameters, then the Commission could and should have declined to

adopt a CGS program. PURA expressly authorizes the Commission to take that

route. Tex. Util. Code Ann. § 39.452(b). The Commission may not instead ignore

the language of the statute to create a program that it perceives to be better (but

detrimental to ETI). The legislature clearly said ETI gets to recover its costs, and

the Commission cannot ignore that mandate simply because it believes the

mandate was “absurd” or difficult to comply with.

E. Other traditional ratemaking principles do not trump the plain language of the CGS statute.

1. The CGS statute is an exception to the traditional regulatory scheme.

OPUC ignores that the legislature, in enacting the CGS statute, created an

exception to the traditional regulatory scheme. A specific statutory provision

prevails as an exception over a conflicting general provision. E.g., Jackson v. State

Office of Administrative Hearings, 351 S.W.3d 290, 297 (Tex. 2011). Moreover,

“if statutes are irreconcilable, the statute latest in date of enactment prevails.”

Jackson, 351 S.W.3d at 297. The CGS statute is irreconcilable with traditional

22

ratemaking principles in several respects. Because it is more specific and more

recently enacted, it controls in these respects.

OPUC argues that a statutory exception to a general rule must be “strictly”

or “narrowly” construed.53 Courts have construed certain statutory “exceptions”

narrowly, but only when the language of those statutes – or some other legal

provision – has required it. Again, the principle rule of statutory construction is to

give effect to the legislature’s expression of its intent through the words it enacted.

No rule of statutory construction is paramount to that one.

2. PURA 11.002 does not shed any light on the proper interpretation of the CGS statute.

OPUC nevertheless argues that PURA section 11.002, assuring rates that are

reasonable to both customers and utilities, supports the Commission’s decision.54

See Tex. Util. Code Ann. § 11.002(a). OPUC ignores that the outcome here is not

fair to the utility, which is mandated to propose this program and statutorily

entitled to recover costs unrecovered as a result of it. PURA section 11.002

weighs against the Commission’s decision as much as it supports it.

53 OPUC’s Brief at 7.

54 Id.

23

3. The concept of “regulatory lag” does not absolve the Commission of its duty to follow the plain language of the statute.

OPUC says the “harm” from the Commission’s decision can be ameliorated

in ETI’s next rate case.55 This statement ignores not only the effects of regulatory

lag, but also the language in the CGS statute requiring that CGS rates be set “in the

proceeding in which the [CGS] tariff is adopted.” See Tex. Util. Code Ann.

§ 39.452(b).

OPUC begrudgingly acknowledges this problem, and says ETI could have

avoided it by requesting an adjustment to test-year billing determinants in its last

rate case.56 But as the Commission found and no one disputes, it is not possible to

know the full effects of the CGS program until customers sign up and start taking

service.57

OPUC ultimately argues that it is perfectly reasonable to saddle ETI with

losses that occur during the regulatory lag period, because that is a known risk

borne by utilities subject to traditional ratemaking.58 But again, the legislature in

the CGS statute crafted an exception to traditional ratemaking, and entitled ETI to

its otherwise unrecovered costs. This entitlement to full cost recovery is

necessarily an exception to the risk of regulatory lag.

55 Id. at 13. 56 Id. at 14. 57 AR Part I, Binder 2, Item 119 (Final Order at FOF 57(E)). 58 OPUC’s Brief at 15 & 18.

24

This statutory entitlement is also why the High Plains case is especially

relevant. That case confirms that a ratemaking agency must give a utility an

opportunity to recover 100% of its reasonably incurred costs. Railroad Comm’n of

Tex. v. High Plains Natural Gas Co., 628 S.W.2d 753 (Tex. 1981). In the same

way the Railroad Commission did in High Plains, the Commission here has

eliminated the opportunity to recover a portion of the reasonable and necessary

costs the utility will incur. OPUC and the Commission point out that PURA

contains a prohibition on the use of some automatic adjustment clauses, while the

Gas Utility Regulatory Act (“GURA”) administered by the Railroad Commission

does not.59 See Tex. Util. Code Ann. § 36.201. That fact is irrelevant because it

was not a basis of the Court’s decision in High Plains. The decision was based

upon a GURA section that has a materially identical counterpart in PURA section

36.051. See High Plains, 628 S.W.2d at 753. Both provisions require the agencies

to afford utilities a reasonable opportunity to recover their costs. The Commission

did not do that here.

4. The reference to discount rates in the CGS statute supports ETI’s argument.

OPUC and the Commission contend the legislature’s reference to PURA

section 36.007 in the CGS statute does not support ETI’s argument. First, ETI’s

argument is based upon the legislature’s mandate that ETI recover its unrecovered

59 Id. at 26; PUCT’s Brief at 43.

25

costs. The reference to section 36.007 simply supports that mandate, by allowing

costs avoided by CGS customers to be allocated to other customers. See Tex. Util.

Code Ann. § 36.007(d).

Second, appellees stretch to come up with another meaning for the reference.

They contend it harks to other aspects of PURA section 36.007, which contemplate

that discounted rates may not be less than a utility’s marginal costs. They contend

the legislature, by referring to section 36.007, simply meant that CGS rates can be

less than a utility’s marginal costs, to enable CGS customers to negotiate their own

deals. Either way, OPUC and the Commission argue, ETI may be forced to absorb

the costs it incurs to serve customers that migrate to the CGS program.

These musings are not supported by the language of the CGS statute. It does

not refer to one particular aspect of PURA section 36.007. It renders the whole of

section 36.007 inapplicable, and in the same sentence says ETI gets to recover any

unrecovered costs. The whole sentence reads:

The tariffs subject to this subsection may not be considered to offer a discounted rate or rates under Section 36.007, and the utility’s rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a result of the implementation of the tariff.

Id. § 39.452(b). The legislature obviously meant to remove the CGS program from

all the limitations of the discount rate statute, including the prohibition on

recovering discounts from other customers.

26

III. The Commission’s decision not to allow ETI to recover all of its costs of implementing the CGS tariff is reversible because it, too, contradicts the plain language of the statute.

The Commission and TIEC contend that the CGS statute does not authorize

ETI to recover the costs of developing the CGS program because they are just a

“cost of doing business.”60 But development of a CGS program is not a cost of

doing business under traditional rate regulation. The legislature mandated ETI to

design this program, and authorized ETI to recover all the costs that result from

implementing it.

Appellees also argue that adopting a rider that allows ETI to recover costs

incurred before the program goes live would enable ETI to over-recover the costs,

because some early costs were included in base rates.61 But ETI recognized this

issue and proposed to credit any of these costs that were included in base rates, so

the costs will not be recovered twice.62

The Commission says it refused to do that because it would constitute

improper retroactive ratemaking.63 The rule against retroactive ratemaking

prohibits a utility commission from making a retrospective inquiry to determine

whether a prior rate was reasonable and imposing a surcharge when rates were too

low or a refund when rates were too high. State v. Public Util. Comm’n, 883 60 PUCT’s Brief at 46; TIEC’s Brief at 39. 61 PUCT’s Brief at 46; TIEC’s Brief at 40. 62 AR Part II, Binder 3, ETI Exh. 101 (Supp. Direct Testimony of D. Roach at 15); AR Part II, Binder 3, ETI Exh. 103 (Supp. Rebuttal of D. Roach at 3). 63 PUCT’s Brief at 47.

27

S.W.2d 190, 199 (Tex. 1994). The rule requires only that the Commission and

courts abide by an administrative determination that a particular rate is just and

reasonable. Office of Public Util. Counsel v. Texas-New Mexico Power Co., 344

S.W.3d 446, 453 (Tex. App. – Austin 2011, pet. denied). ETI’s request, which it

made when it first proposed the CGS program in Docket No. 37744, and before the

costs at issue were even incurred, does not implicate a “prior rate.” The

Commission itself has recognized – and this Court has affirmed – that authorizing

recovery of costs in an analogous circumstance does not constitute retroactive

ratemaking. Office of Public Util. Counsel, 344 S.W.3d at 454. Indeed, the tariff

adopted in this case contemplates a future recovery of past expenses, as it

authorizes ETI to accrue implementation costs but wait 6 months to file the CGSC

rider.64 This is no basis upon which to sustain the Commission’s misapplication of

the CGS statute.

IV. The Commission’s decision not to allow ETI to recover interest on its unrecovered costs is reversible because the CGS statute entitles ETI to all of its unrecovered costs.

Because the CGS statute entitles ETI to recover all of its costs that are

unrecovered as a result of implementation of the CGS program, ETI is entitled to

recover interest on the balance of those costs until they are recovered. The

Commission offers several purported justifications for denying ETI that interest.

64 AR Part I, Binder 2, Item 119 (Final Order at FOFs 54(A), 57(A) & (E)).

28

First, the Commission says the unrecovered balance is “relatively small” and

will be recouped “quickly” so should be treated consistently with rate case

expenses, upon which the Commission has not historically allowed interest to

accrue.65 The Commission’s historical treatment of rate case expenses is not

persuasive in this context. The Commission may award rate case expenses. See

Tex. Util. Code Ann. § 36.061(b). But the CGS statute does not give the

Commission any discretion not to allow ETI’s unrecovered costs. And the statute

does not say ETI may recover only its “sizable” or “significant” costs – it says

“any” of its costs. Id. § 39.452(b).

Second, the Commission argues that ETI is not entitled to earn interest on

unrecovered expenses under the traditional ratemaking construct.66 As explained

above, the CGS statute is a marked departure from that construct. In traditional

ratemaking, a utility bears some risk that its rates will not cover its actual expenses.

The CGS statute, in contrast, says ETI gets to recover costs that are unrecovered as

a result of the implementation of the CGS program.

When PURA entitles a utility to recover its costs dollar for dollar, PURA

impliedly requires the Commission to award interest on those costs until they are

recovered. CenterPoint Energy, Inc. v. Public Util. Comm’n of Tex., 143 S.W.3d

81, 84 (Tex. 2004). The Commission misstates the basis of the Texas Supreme

65 PUCT’s Brief at 48.

66 Id. at 49.

29

Court’s holding in CenterPoint Energy, Inc. The Court reversed the Commission’s

refusal to allow utilities to accrue interest on stranded cost balances for the whole

time they were on the books. The Court expressly said that was error because

requiring a utility to wait two or three years before interest began would contradict

the utility’s statutory entitlement to recover of all its stranded costs. Id. at 84. The

Court so held even though PURA did not expressly authorize utilities to earn

interest on their unrecovered stranded costs.

The same is true here. The CGS statute does not expressly authorize ETI to

accrue interest on its unrecovered cost balance. But because the statute entitles

ETI to all of its unrecovered costs, ETI will not be made whole unless it is able to

accrue interest while the balances are unrecovered.

CONCLUSION AND PRAYER

For all these reasons, Entergy Texas, Inc. respectfully requests that the Court

reverse the district court’s judgment insofar as it upholds the Commission’s

decision in the respects discussed above. ETI requests that this Court remand the

case to the Commission for further proceedings consistent with the Court’s

decision. Finally, ETI requests its costs of court and any other relief to which it

may show itself justly entitled.

30

Respectfully submitted,

DUGGINS WREN MANN & ROMERO, LLP

By: /s/ Marnie A. McCormick John F. Williams State Bar No. 21554100 jwilliams@dwmrlaw.com Marnie A. McCormick State Bar No. 00794264 mmccormick@dwmrlaw.com P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax

ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC.

CERTIFICATE OF COMPLIANCE

I certify that this document contains 7,460 words in the portions of the document that are subject to the word limits of Texas Rule of Appellate Procedure 9.4(i), as measured by the undersigned’s word-processing software.

/s/ Marnie A. McCormick Marnie A. McCormick

31

CERTIFICATE OF SERVICE

As required by Texas Rule of Appellate Procedure 9.5, I certify that on the 5th day of March, 2015, the foregoing document was electronically filed with the Clerk of the Court using the electronic case filing system of the Court, and that a true and correct copy was served on the following lead counsel for all parties listed below via electronic service:

Elizabeth R. B. Sterling Megan M. Neal Environmental Protection Division Office of the Attorney General P.O. Box 12548 Austin, TX 78711-2548 Counsel for the Public Utility Commission of Texas

Rex VanMiddlesworth Benjamin Hallmark Thompson & Knight LLP 98 San Jacinto Blvd., Ste. 1900 Austin, TX 78701 Counsel for Texas Industrial Energy Consumers

Sara J. Ferris Office of Public Utility Counsel 1701 N. Congress Ave., Ste. 9-180 P.O. Box 12397 Austin, TX 78711-2397 Counsel for Office of Public Utility Counsel

/s/ Marnie A. McCormick Marnie A. McCormick

PUC DOCKET NO. 37744 .. ;.

SOAH DOCKET NO. 473-10-1962-

b • C"^

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION INC. FOR AUTHORITY TO CHANGE § RATES AND RECONCILE FUEL § OF TEXAS COSTS §

ORDER

This Order addresses the application of Entergy Texas, Inc. (ETI) for authority to change rates and reconcile fuel costs. ETI, Commission Staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by ETI (Cities),' Texas Industrial Energy Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and Sam's East, Inc. (collectively Wal-Mart), through their duly authorized representatives entered

into and filed a stipulation and settlement agreement that resolves all of the issues in this proceeding except the issues related to ETI's proposal for competitive generation service. Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education ( State Agencies) did not join but do not oppose the stipulation.

The Commission severed the competitive generation service issues into Docket No. 389512 in Order No. 14.

The Commission adopts the following findings of fact and conclusions of law:

1 Steering Committee of Cities is comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.

2 Application of Entergy Texas, Inc. for Approval of Competitive Generation Service Tariff (Issues Severed From Docket No. 37744), Docket No. 38951.

iq

PUC Docket No. 37744 Order Page 2 of 15 SOAH Docket No. XXX-XX-XXXX

1. Findings of Fact

Procedural Histo 1. On December 30, 2009, ETI filed an application requesting approval of (1) base rate tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million, which includes a total non-fuel retail revenue requirement of $838.3 million (base rate revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI's application; (3) a request for final reconciliation of ETI's fuel and purchased power costs for the reconciliation period from April 1, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI's application.

2. The 12-month test year employed in ETI's filing ended on June 30, 2009.

3. ETI provided notice by publication for four consecutive weeks before the effective date

of the proposed rate change in newspapers having general circulation in each county of

ETI's Texas service territory. ETI also mailed notice of its proposed rate change to all of its customers. Additionally, ETI timely served notice of its statement of intent to change

rates on all municipalities retaining original jurisdiction over its rates and services. ETI

also published one-time supplemental notice by publication in newspapers and by bill insert.

4. The following parties were granted intervenor status in this docket: OPUC, Cities, Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart. Commission Staff was also a participant in this docket.

5. On January 4, 2010, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing.

6. On February 19, 2010, the ALJs issued Order No. 3, which approved an agreement between ETI, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to (1) establish an interim rate increase of $17.5 million annually above ETI's then-existing base rates commencing with service rendered on and after May 1, 2010 subject to true-up and refund for service rendered prior to September 13, 2010 to the extent final

PUC Docket No. 37744 Order Page 3 of 15 SOAH Docket No. XXX-XX-XXXX

overall rates established by the Commission amounted to less than a $17.5 million rate increase; (2) extend the jurisdictional deadline by which the Commission must issue a final order on the Company's rate request from July 5, 2010 to November 1, 2010; (3) establish a September 13, 2010 effective date for rates such that, notwithstanding the extension of the jurisdictional deadline, the final overall rates established by the Commission would relate back to service rendered on and after September 13, 2010; (4) require ETI to publish supplemental notice, once in newspapers and by a bill insert, setting forth the effect of its proposed rate change in terms of the percentage increase in non-fuel revenues; and (5) establish a procedural schedule and discovery deadlines for this proceeding. Order No. 3 also granted Mr. Kurt Boehm's motion for admission pro hac vice as counsel for Kroger and ETI's February 3 and February 11, 2010 petitions for review of cities' ordinances and motions to consolidate with respect to the rate decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond, Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta, Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty, Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village, Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission, Trinity, and Woodville.

7. On June 14, 2010, the ALJs issued Order No. 6 granting Staff's June 1, 2010 motion and severing rate case expense issues to Docket No. 38346.3 Through Order No. 6, the ALJs also granted ETI's March 12, April 29, and May 17 petitions for review and motions to consolidate with respect to the rate decisions adopted by the Cities of Anahuac,

Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest,

Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard, Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and Woodloch.

3 Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 37744, Docket No. 38346.

PUC Docket No. 37744 Order Page 4 of 15 SOAH Docket No. XXX-XX-XXXX

8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in order to facilitate settlement negotiations. The hearing was again convened on July 15, 2010, at which time the signatories announced their intent to continue settlement discussions to resolve all issues related to the Company's application with the exception of those related to ETI's proposal for competitive generation service (CGS) and associated riders.

9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding issues regarding the Company's application with the exception of those related to ETI's CGS proposal. Under the stipulation, ETI will be allowed to implement base rate tariffs

and riders designed to collect an overall revenue requirement of $1,614.9 million,4 which includes a total non-fuel retail revenue requirement of $694.9 million (base rate revenues of $599 million plus revenue from riders of $95.9 million). The signatories also submitted, on August 6, 2010, an agreed motion to revise interim rates and to consolidate the severed rate-case expense docket. The interim rates requested in the agreed motion mirrored the final rates proposed for Commission approval in the stipulation. The agreed motion further requested that the ALJs consolidate with the instant proceeding Docket No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the parties' pre-filed exhibits into evidence.

10. On July 16 and July 20, 2010, the ALJs held the hearing on the merits with respect to ETI's CGS proposal.

11. On August 9, 2010, the ALJs issued Order No. 12, granting approval of revised interim rates for usage on and after August 15, 2010.

12. On October 5, 2010, the ALJs issued a proposal for decision regarding issues related to ETI's CGS proposal.

13. On October 5, 2010, the ALJs issued Order No. 13, ordering the consolidation of Docket No. 38346, related to severed rate-case expense issues, into the instant proceeding,

4 This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices, the overall revenue requirement figure would be $1,504.0 million.

PUC Docket No. 37744 Order Page 5 of 15 SOAH Docket No. XXX-XX-XXXX

admitting evidence, and returning this docket to the Commission consistent with the agreed motion filed on August 6, 2010.

14. The Commission considered this Docket at the November 10, 2010 and December 1, 2010 open meetings.

15. On November 30, 2010 ETI filed an unopposed motion to sever the competitive CGS issues from the settled issues in this docket. The Commission granted the motion at the December 1, 2010 open meeting and the Commission's decision was memorialized in Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket No. 38951 in Order No. 14.

Description of the stipulation and Settlement Agreement 16. The signatories to the settlement stipulated that ETI should be allowed to implement an initial overall increase in base-rate revenues of $59 million for usage on and after

August 15, 2010. The signatories further stipulated that they would request approval of interim rates by the ALJs presiding or by the Commission, as necessary, to ensure timely implementation of this initial rate increase. The signatories further stipulated that ETI should be allowed to implement an additional overall increase in base-rate revenues of $9 million on an annualized basis effective for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month of May.

17. The signatories agreed that ETI's authorized return on equity shall be 10.125% and its weighted average cost of capital shall be 8.5209%.

18. The signatories stipulated that the amount of rate increase authorized under finding of fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and that this amount constitutes the full and final recovery of all rate-case expenses relating to Docket No. 37744.

19. The signatories stipulated to the amount of transmission and distribution invested capital by function as of June 30, 2009 as set out in attachment 1 to the stipulation.

PUC Docket No. 37744 Order Page 6 of 15 SOAH Docket No. XXX-XX-XXXX

20. The signatories stipulated that the Company's proposed purchased-power recovery rider will not be approved in this docket, and purchased capacity costs will be included in base rates.

21. The signatories stipulated that the Company's proposed transmission cost recovery factor (TCRF) will not be approved in this docket. The signatories stipulated to the baseline values as shown in attachment 2 to the stipulation to be used in the Company's request, if any, for a TCRF in a separate proceeding.

22. The signatories agreed that ETI's proposed cost-of-service adjustment rider and formula rate plan will not be approved in this docket.

23. The signatories stipulated that the Company's proposed renewable-energy-credit rider

will not be approved in this docket, and the Company's renewable-energy-credit costs shall be recovered in base rates. The signatories further stipulated that a transmission customer that opts out pursuant to P.U.C. SUBST. R. 25.173(j) shall receive a credit that

offsets the amount of renewable-energy-credit costs that are recovered in base rates from the transmission customer.

24. The signatories agreed that ETI's proposed remote-communications-link rider should be approved as filed by the Company.

25. The signatories agreed that ETI's proposed market-valued-energy-reduction service rider will not be approved in this docket.

26. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this docket:

a. Rate Schedule IS. Rate Schedule IS will be opened to new business. In the Company's next base-rate case, the amount of interruptible credits recoverable from Texas retail customers shall be limited to an increase of $1 million more than the amount requested in this docket (or a total of $6.8 million); provided, however, that in the next rate case, the Company may request an exception to this limitation upon a showing that the test-year credit amount in excess of the $6.8 million cap is both cost effective and necessary to meet the Company's generation reserve margin requirement. The signatories further agreed that the

PUC Docket No. 37744 Order Page 7 of 15 SOAH Docket No. XXX-XX-XXXX

Company will not offer additional interruptible service if the availability of total interruptible service supplied by the Company under all interruptible service riders exceeds 5% of the projected aggregate Company peak demand unless the additional level of interruptible service offered in excess of the 5% cap is both cost effective and necessary to meet the Company's generation reserve margin requirement. To the extent that the credit amount or participation level exceeds the limitations described in this paragraph and the Company includes test-year credits over the $6.8 million credit-amount cap or additional participation in excess of the 5% participation-level cap in its next rate case, the Company shall have the burden to prove whether those test-year credits or participation levels meet the standards established in this paragraph for inclusion in the test year. The standards in this paragraph are in addition to any requirements in PURA for inclusion of costs in rates. The signatories further agreed to the Schedule IS revisions shown on attachment 3 to the stipulation.

b. Rate Schedule IHE. The signatories agreed that no change shall be made to rate schedule IHE in this docket.

c. Lighting Class Rates. The signatories stipulated that the language under the paragraph relating to rate group C in rate schedule SHL will be revised to reflect that, where the Company agrees to install facilities other than its standard street light fixture and lamp as provided under Rate Group A, a lump sum payment will be required, based upon the installed cost of all facilities excluding the cost of the standard street light fixture and lamp, and the customer will be billed under rate group A.

e. Electric Extension Policy. The signatories agreed to the line-extension terms and conditions as reflected in attachment 4 to the stipulation.

f. Life-of-Contract Demand Ratchet. The signatories agreed that the life-of-contract demand ratchet provision in rate schedules Large Industrial Power Service, Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of

PUC Docket No. 37744 Order Page 8 of 15 SOAH Docket No. XXX-XX-XXXX

Day shall be excluded from rate schedules in ETI's next rate case. The

signatories further stipulated that the foregoing rate schedules will be revised so that the life-of-contract demand ratchet provision shall not be applicable to new customers and shall not exceed the level in effect on August 15, 2010 for existing

customers.

g. Residential Customer Charge. The signatories agreed that the residential customer charge shall be increased to $5.00.

h. Non-Sufficient Funds Char^e. The signatories agreed that the non-sufficient

funds charge shall be increased to $15.00.

27. The signatories agreed to the class cost allocation set forth in attachment 5 to the stipulation.

28. The signatories stipulated that the appropriate allocation between ETI's wholesale and retail jurisdictions of baseline values and costs to be included in a TCRF is to be addressed in the proceeding, if any, in which ETI seeks approval of a TCRF.

29. The signatories stipulated that no party waives its right to address in any subsequent proceeding the appropriate treatment for Texas retail ratemaking purposes of power sales between ETI and Entergy Gulf States Louisiana, L.L.C.

30. The signatories reached the following specific agreements regarding fuel-related issues as part of the overall resolution of this docket:

a. Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of $3.25 million not associated with any particular issue raised by the signatories. The disallowance will be allocated pro rata with interest over each month of the reconciliation period and reflected in the refund in Docket No. 38403.5 The

signatories stipulated that the Company's fuel costs shall be finally reconciled for the reconciliation period of April 1, 2007 through June 30, 2009.

b. Rider IPCR. The signatories agreed that ETI's eligible Rider IPCR costs for the

5 Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund,. Docket No. 38403, Order (Sept. 16, 2010).

PUC Docket No. 37744 Order Page 9 of 15 SOAH Docket No. XXX-XX-XXXX

period April 1, 2007 through the date the rider terminated shall be finally reconciled with a disallowance of $300,000. The signatories further agreed that the under-recovered balance of Rider IPCR costs shall be booked as fuel expense in the month in which the Commission issues an order adopting the stipulation; provided, however, that the under-recovered balance shall be allocated to customer classes using A&E4CP.

c. Rough Production Cost Equalization (RPCE) Payments. The signatories agreed that ETI will credit an additional $18.6 million to Texas fuel-factor customers, which the signatories stipulated represents the remaining portion of RPCE payments ETI received in 2007 that were at issue in Docket No. 35269.6 The RPCE credit shall be allocated to rate classes based on loss-adjusted kilowatt hours at plant for calendar year 2006. For customers in the Large Industrial Power Service rate class, the credit will be refunded based on the customer's

actual kWh usage during the billing months of January 2006 through December 2006. Upon issuance of a final order approving the stipulation, the RPCEs shall be credited to customers as a separate one-month bill credit in the same form as the RPCEA Rider last approved in Docket No. 38098.7 ETI agreed that it will terminate all appeals related to Docket No. 35269.

31. The signatories agreed that ETI will continue its accrual of storm-cost reserves at the level of $3.65 million annually and that this amount shall be subsumed in the base-rate revenue increase described in finding of fact 16 above.

32. The signatories agreed that ETI shall maintain River Bend depreciation rates at current

levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at $2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of

6 Compliance Filing of Entergy Texas, Inc. Regarding Jurisdictional Allocation of 2007 System Agreement Payments, Docket No. 35269, Order (Jan. 7, 2009).

7 Application of Entergy Texas, Inc. for Authority to Implement New RPCEA Rate, Docket No. 38098, Order (July 1, 2010).

PUC Docket No. 37744 Order Page 10 of 15 SOAH Docket No. XXX-XX-XXXX

1.71%, resulting in an overall escalation rate of 3.62%, and net investment yields as

follows:

Nuclear-Decommissioning-Trust Projected Returns Tax- ualified Non-Tax-Qualified Investments Investment

2010 5.475% 5.057% 2011 5.837% 5.236% 2012 6.306% 5.567% 2013 6.304% 5.607% 2014 6.481% 5.896% 2015 6.493% 5.909% 2016 6.412% 5.826% 2017 6.412% 5.830% 2018 6.364% 5.790% 2019 6.316% 5.748% 2020 6.268% 5.712% 2021 6.220% 5.670% 2022 2.503% 5.458% 2023 5.817% 5.055% 2024 5.382% 4.628% 2025 5.036% 4.516% 2026-2034 4.920% 4.409%

33. The signatories stipulated that the Company's depreciation rates for non-River Bend production plant, transmission, distribution, and general plant will remain at current levels and the Company will maintain its accounting records on a prospective basis for purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage,

and cost of removal by FERC account.

Consistency of the AQreement with PURA and the Commission Requirements

34. Considered in light of (1) the pre-filed testimony by the parties entered into evidence and (2) the additional evidence and testimony admitted during the course of the hearing on the merits on the Company's application, the stipulation is the result of compromise from each signatory, and these efforts, as well as the overall result of the stipulation viewed in light of the record evidence as a whole, support the reasonableness and benefits of the

terms of the stipulation.

PUC Docket No. 37744 Order Page 11 of 15 SOAH Docket No. XXX-XX-XXXX

35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and conditions resulting from the stipulation are just and reasonable and consistent with the public interest.

36. The total level of the Texas retail revenue requirement contemplated by the stipulation will allow ETI the opportunity to earn a reasonable return over and above its reasonable and necessary operating expense.

37. The stipulated revenue requirement is consistent with applicable provisions of PURA chapter 36 and the Commission's rules.

38. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable and necessary for each class of affiliate costs presented in ETI's application.

39. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to ETI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or divisions, or a non-affiliated person within the same market area or having the same market conditions.

40. The retail revenue requirement in the stipulation does not include any expenses prohibited from recovery under PURA.

41. A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ETI should be adopted consistent with the stipulation.

42. The agreed rate-design provisions and terms and conditions of service included in the stipulation are just and reasonable.

43. The treatment of rate-case expenses described in the stipulation is reasonable.

44. The Company's proposed remote-communications-link rider as filed by the Company is reasonable.

45. The depreciation rates agreed to in the stipulation are just and reasonable.

PUC Docket No. 37744 Order Page 12 of 15 SOAH Docket No. XXX-XX-XXXX

46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production assets based on the factors agreed to in the stipulation is reasonable.

47. A $3.65 million annual storm cost accrual is reasonable.

48. The class allocation methodologies described in the stipulation are just and reasonable.

49. The fuel and IPCR-related provisions of the stipulation are reasonable.

H. Conclusions of Law 1. ETI is a public utility as that term is defined in PURA § 11.004(1) and an electric utility as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.001-.111, 36.203, 39.452, and 39.455.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEx. Gov'T CODE ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA, the Texas Administrative Procedure Act,g and Commission rules.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.

R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6. This docket contains no remaining contested issues of fact or law.

7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it addresses; results in just and reasonable rates, terms, and conditions; is supported by a preponderance of the credible evidence in the record; is consistent with the relevant provisions of PURA; and is consistent with the public interest.

8. ETI has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider IPCR.

8 TEX. Gov'T CODE ANN. Chapter 2001 (Vernon 2007 and Supp. 2009).

PUC Docket No. 37744 Order Page 13 of 15 SOAH Docket No. XXX-XX-XXXX

9. The revenue requirement, cost allocation, revenue distribution, and rate design implementing the stipulation result in rates that are just and reasonable, comply with the ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or prejudicial.

10. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement in PURA § 36.053(a) that electric utility rates be based on the original cost, less depreciation, of property used by and useful to the utility in providing service.

11. ETI has met its burden of proof in demonstrating that it is entitled to the level of retail base rate and rider revenue set out in the stipulation.

12. ETI has met its burden of proof in demonstrating that the rates resulting from the stipulation are just and reasonable, and consistent with PURA.

III. Ordering Paragraphs 1. ETI's application seeking authority to change its rates; reconcile its fuel and purchased power costs for the Reconciliation Period from April 1, 2007 to June 30, 2009; and for other related relief is approved consistent with the above findings of fact and conclusions of law.

2. Rates, terms, and conditions consistent with the stipulation are approved.

3. The tariffs and riders consistent with the stipulation are approved for the initial and second step rate increases.

4. ETI's request for waivers of RFP instructions (RFP Schedule V) is granted.

5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating Station consistent with the terms of this Order.

6. Neither the stipulation and settlement agreement nor this Order constitutes the Commission's agreement with, or consent to, the manner in which ETI, or any entity affiliated with ETI, has interacted with any decommissioning trust to which ETI or its ratepayers have made contributions or provided funds. Furthermore, this Order in no

Order Page 14 of 15 PUC Docket No. 37744 SOAH Docket No. XXX-XX-XXXX

way constitutes a waiver or release of any conduct, whether or not such conduct occurred before the date of this Order, that may constitute a violation of any provision of state law, including, without limitation, the rules and regulations of this Commission relating to nuclear decommissioning trust funds; or prevents the Staff of the Commission from opening an investigation and taking enforcement action relating to violations of such

rules and regulations.

7. Nothing contained in this Order constitutes the consent or approval, explicit or implied, of any modification, amendment or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station. Without

limiting the foregoing, nothing contained in this Order shall constitute the consent or approval of any modification, amendment, or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station, which is made to address any concerns raised by the NRC in its Request for Additional Information regarding the River Bend Station dated March 11, 2010.

8. The Rider IPCR costs and eligible fuel costs requested by ETI are, consistent with this Order, reconciled through June 30, 2009, and are approved consistent with the

stipulation.

9. ETI shall adjust its fuel over/under recovery balance consistent with the findings in this

Order.

10. ETI shall file an RPCEA Rider consistent with the above findings of fact and conclusions of law to be effective with the first billing cycle of the billing month immediately following the effective date of this Order..

11. Because the final approved rates are equal to or higher than the interim rates adopted in Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary.

12. The interim rates approved in Order No. 12 are herby approved for the initial step rate increase contemplated by the stipulation, and ETI shall implement the second step rates for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month

of May.

PUC Docket No. 37744 Order Page 15 of 15 SOAH Docket No. XXX-XX-XXXX

13. Within 30 days of the date of this Order, ETI shall file a clean copy of all of the tariffs and schedules approved in this docket and a clean copy of the attachments to the stipulation.

14. The entry of this Order consistent with the stipulation does not indicate the Commission's endorsement of any principle or method that may underlie the stipulation. Neither should entry of this Order be regarded as a precedent as to the appropriateness of any principle or methodology underlying the stipulation.

15. All other motions, requests for entry of specific findings of fact, conclusions of law, and ordering paragraphs, and any other requests for general or specific relief, if not expressly granted in this order, are hereby denied.

SIGNED AT AUSTIN, TEXAS the ^C> I day of December 2010

PUBLIC UTILITY COMMISSION OF TEXAS

d ^ BA . SMITHERMAN, CHAIRMAN

DONNA L. NELSON, COMMISSIONER

y:\cadm\orders\final\37000\37744fo.docx

State Office of Administrative Hearings

Cathleen Parsley Chief Administrative Law Judge

October 4, 201 0

TO: Stephen Journeay, Director Courier Pick-up Commission Advising and Docket Management William B. Travis State Office Building 1701 N. Congress, 7th Floor Austin, Texas 78701

RE: SOAH Docket No. XXX-XX-XXXX PUC Docket No. 37744

Application of Entergy Texas, Inc. for Authority to Change Rates and to Reconcile Fuel Costs

Enclosed are two copies of the Proposal for Decision (PFD) in the above-referenced case.

Please file-stamp and return a copy to the State Office of Administrative Hearings for our records. By copy of this letter, the parties to this proceeding are being served with the PFD.

Please place this case on an open meeting agenda for the Commissioners' consideration. The deadline by which a final order must be issued in this case is. November 1, 2010. It is my understanding that you will be notifying me and the parties of the open meeting date, as well as the deadlines for filing exceptions to the PFD, replies to the exceptions, and requests for oral argument.

Sincerely,

~---

Travis Vickery Administrative Law Judge

Enclosure xc: All Parties ofRecord

300 West 15 th Street Suite 502 Austin, Texas 78701/ P.O. Box 13025 Austin, Texas 78711-3025 512.475.4993 (Main) 512.475.3445 (Docketing) 512.475.4994 (Fax)

www.soah.state.tx.us

SOAR DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 37744

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES AND TO RECONCILE FUEL § OF COSTS § § ADMINISTRATIVE HEARINGS

TABLE OF CONTENTS

I. INTRODUCTION 1

II. PROCEDURAL HISTORY 1

III. SUMMARY 2

IV. BACKGROUND 3

A. The CGS Legislation 3

B. The Company's CGS Proposal 5

1. The CGS Tariff 6 2. The CGSC Rider 7 3. The CGSUSC Rider 7 4. The System Agreement 7

V. ARGUMENT AND ANALySIS 9

A. The CGS Tariff 9

1. Eligible Customers 9 2. Eligible Suppliers 12

a. Expanding the Supply to Include IPPs 13 b. Expanding the Supply to Include Cottonwood 15 c. Expanding the Supply to Include Out-of-State QFs 15

B. Cost Recovery Riders 17

1. CGSC Rider 18 2. CGSUSC Rider 21

8. Cost Estimates 24

SOAR DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE 2 PUC DOCKET NO. 37744

b. Annual True-ups Should Account for Load Growth 26 c. Potential Benefits of the CGS Program 30

i. Capacity Savings 30 ii. Potential Average Fuel Cost Savings 37

C. ETI May Recover its Costs Through a Rider 38

D. The UBserved Energy Rate 39

VI. CONCLUSION 41

VII. PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW 42

A. Findings of Fact on ETl's CGS Proposal 42

B. Conclusions of Law on ETl's CGS Proposal. 44

ATTACHMENT A

SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 37744

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES AND TO RECONCILE FUEL § OF COSTS § § ADMINISTRATIVE HEARINGS

PROPOSAL FOR DECISION

I. INTRODUCTION

On December 30, 2009, Entergy Texas, Inc. (ETl or Company) filed its application for authority to change rates and reconcile fuel costs (Application). On July 13, 2010, the parties appeared for the hearing on the merits. At the beginning of the hearing, the parties informed the Administrative Law Judges (ALJs) that they were engaged in settlement negotiations. On July 15, 2010, the parties advised the ALJs that there was a settlement in principle on all issues in the case except for ETl's Competitive Generation Service (CGS) proposal. Concurrent with this Proposal for Decision (PFD) the AU is forwarding to the Commission the parties' Stipulation and Settlement Agreement and Proposed Final Order filed on August 6, 2010. The ALJ recommends that the Commission reject ETl's CGS proposal. However, the Commission may disagree. As a result, the ALJ provides a full discussion of the parties' arguments.

II. PROCEDURAL HISTORY

On July 16 and July 20, 2010, the parties attended a limited hearing on the merits for issues solely related to CGS. 1 ALJ Travis Vickery presided and drafted this PFD. The following parties attended the hearing on the merits and submitted post-hearing briefing: ETl, Staff of the Public Utility Commission of Texas (PUC or Commission), Office of Public Utility Counsel of Texas (OPUC), State of Texas' Agencies and Institutions of Higher Education (State), Cottonwood Energy Company, L.P. (Cottonwood), and Texas Industrial Energy Consumers

I In the interests ofjudicial economy, the AU has borrowed liberally from the parties' briefing.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 2 PUC DOCKET NO. 37744

(TIEC),z The parties submitted post-hearing briefing and the record closed on August 26, 2010. Other procedural matters are dealt with in the proposed Findings of Fact and Conclusions of Law. 3

III. SUMMARY

All parties that participated in the hearing, except TIEC and Cottonwood, oppose ETI's CGS proposal, including Staff (referred to generally as opponents). In general, the opponents argue that the Company's proposed CGS tariff runs contrary to legislative intent and sound economic and public policy. These parties, however, also make arguments in the alternative. Cottonwood argues only that independent power producers (IPPs) be included as eligible suppliers. TIEC argues that the program should be approved with certain modifications.

Although the ALJ offers a discussion of the major Issues raised by the parties, he recommends rejection ofETI's CGS proposal. ETI, as a regulated member ofa multi-state set of related utilities, is limited in its ability to propose a CGS program that offers somewhat competitive choice to a limited class of customers. The ALJ finds that ETI's CGS proposal reflects a good faith attempt to navigate the conflicting interplay of its status within the Entergy system, principles of traditional ratemaking, and the competitive goals of the CGS legislation. The ALJ's primary reasons for recommending rejection of the proposal echoes the opponents' arguments: the anticipated costs are not ascertainable until the program has been implemented; and these potentially substantial costs are shifted to parties who may chose not to, or are not eligible to, participate in the program.

Although ETI is a necessary third party to any transaction between a CGS supplier and customer, it has attempted to render itself neutral by adopting a pass-through rate for supplier and customer. The fundamental problem is, for every customer that migrates to the program, ETI loses a customer that contributes to the recovery of its embedded production costs. As

2 The following parties intervened or participated in this docket: Staff, OPUC, the State, Cities, Cottonwood, TIEC, Kroger Co., and Wal-Mart Stores Texas, LLC and Sam's East, Inc. (Wal-Mart).

3 Although a number of parties proposed Findings of Fact and Conclusions of Law, the ALJ adopted Staffs with limited modifications.

SOAR DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 3 PUC DOCKET NO. 37744

explained below, the CGS legislation makes clear ETl is not to bear any costs as a result of the implementation of the program. As a result, ETl's proposal shifts the bulk of these unrecovered costs to all non-participating customers. This cost-shifting violates the basic principal of cost- causation. Although the parties offered some discussion of legislative intent, the ALJ is not convinced that this cost-shifting was intended by the Legislature. It is clear, however, that the drafters sought to create a program that offers competitive choice to certain ETl customers. Although the ALJ recommends rejection, he also understands the Commission may find, as a matter of policy, that the Legislature's intent to develop a competitive set of suppliers overrides the principal of cost-causation.

IV. BACKGROUND

A. The CGS Legislation

The Company's proposed CGS program in this proceeding is the product of legislation first enacted in 2005 as House Bill 1567. 4 The bill addressed a number of issues related to the timing of rate cases and cost recovery during Entergy Gulf States, Inc.'s (EGSI) efforts to transition to retail open access. The legislation authorized EGSI to file a rate proceeding with an effective date no earlier than June 30, 2008, and stipulated that as a part of that rate proceeding:

[t]he utility shall propose a competitive generation tariff to allow eligible customers the ability to contract for competitive generation. The commission shall approve, reject, or modify the proposed tariff The tariffs subject to this subsection may not be considered to offer a discounted rate or rates under Section 36.007, and the utility's rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a result of the implementation of the tariffS

4 Public Utility Regulatory Act, TEX. UIIL. CODE ANN., §§ 39.451 - 39.463 (Vernon 1998 & Supp. 2005)

(PURA 2005).

5 PURA 2005 at § 39.452(b).

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To comply with HB 1567, EGSI submitted a CGS proposal as part of its application in Docket No. 34800. 6 In that proposal, CGS customers were to be treated as wholesale transmission customers so they could seek competitive wholesale generation supply on the same tenns as other wholesale market participants. The Commission approved a settlement of that proceeding whereby the Company's CGS proposal was severed into a separate proceeding, 7 Docket No. 36713. 8

Soon after the resolution of Docket No. 34800 and initiation of Docket No. 36713, the Texas Legislature enacted House Bill 1492, which, among other things, altered the Company's obligations with regard to the transition to retail open access and significantly amended the provisions of PURA § 39.452(b) that addressed the requirements of a proposed competitive generation tariff, which now reads:

An electric utility subject to this subchapter shall propose a competItIve generation tariff to allow eligible customers the ability to contract for competitive generation. The commission shall approve, reject, or modify the proposed tariff not later than September 1,2010. The tariffs subject to this subsection may not be considered to offer a discounted rate or rates under Section 36.007, and the utility's rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a result of the implementation of the tariff. The commission shall ensure that a competitive generation tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers that choose not to take advantage of competitive generation. Pursuant to the competitive generation tariff, an electric utility subject to this subsection shall purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer. An electric utility subject to this subsection shall provide and price retail transmission service, including necessary ancillary services, to retail customers who choose to take advantage of the competitive generation tariff at a rate that is unbundled from the utility's cost of service. Such customers shall not be considered wholesale transmission customers. Notwithstanding any other provision of this chapter, the commission may not issue a decision relating to a competitive generation tariff

6 Application of Entergy Gulf States, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 34800 (Mar. 16,2009).

7 Id., Final Order at FoF 32, Ordering Paragraph No.5. 8 Application of Entergy Texas, Inc. for Approval of Competitive Generation Services Tariff, Docket No. 36713 (pending). Other than the Control Number Request filed on February 18, 2009, no other documents have been filed in Docket No. 36713.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGES PUC DOCKET NO. 37744

that is contrary to an applicable decision, rule, or policy statement of a federal

9

regulatory agency havingjurisdiction.

A comparison ofthe two statutes reveals that the amended PURA § 39.452(b) retains key components of the prior statute, as shown below:

• The Company shall propose a CGS program;

• The CGS program shall be available only to "eligible customers";

• The Commission may approve, reject, or modify the proposal;

• The tariff shall not constitute a discount rate under PURA § 36.007; and

• The rates shall be set in the proceeding in which the CGS tariff is adopted to recover any unrecovered costs resulting from implementation.

The new statute also adds several new provisions, summarized as follows:

• The tariff shall not result in harm to "manufacturers" that choose not to participate in the CGS program;

• The Company must purchase the energy selected by the CGS customer;

• The CGS customer shall not be considered a wholesale transmission customer; rather, the Company must provide the purchased energy through unbundled retail transmission service; and

• The Commission's decision regarding the Company's proposal must not be contrary to a decision, rule, or policy statement of the Federal Energy Regulatory Commission (FERC).

B. The Company's CGS Proposal

Pursuant to PURA § 39.452, ETl proposed a CGS tariff as part of its Application. The Company's CGS proposal consists of a CGS Tariff, a CGS Cost Rider (CGSC) and a CGS Unrecovered Service Cost Rider (CGSUSC). In its initial brief, ETl provided a diagram to illustrate the mechanics of the tariff and how costs are handled under the Company's proposed

9 PURA § 39.452(b).

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COS program. For the benefit of the Commission, the diagram is attached to the PFD as Attachment A.

1. The CGS Tariff

ETl's proposed COS tariff provides eligible customers with the opportunity to have ETl purchase competitive generation selected by the COS customer and provide the selected generation at retail to the COS customer. Under the proposal, the eligible customers are Large Industrial Power Service (LIPS) and LIPS Time-of-Day rate schedule customers. A cas customer would have the ability to contract with a participating COS supplier (an eligible QF located in ETl's service territory) that puts energy to ETl for a set amount of load at an agreed upon price. The cas customer must designate what portion of its load will be served by its cas supplier under the COS tariff and what portion will be served under the applicable LIPS tariff rate.

So long as the COS supplier provides the energy contracted by the cas buyer, ETI will continue to purchase energy from the QF at the avoided cost rate and the COS customer will pay ETl the avoided cost rate for the level contracted for in place of all generation related components that would otherwise be billed under the LIPS tariff. A cas customer and a QF supplier are free to contract, without ETl's participation, for a price other than avoided cost, in which case, the costs above or below the avoided costs would be accounted for in payments between the COS customer and COS supplier, or vice versa, as prescribed by the contract. 10

ETl explains that the COS customer could avoid costs it would otherwise incur under the Company's fixed fuel factor, along with the portion of the Company's retail rates that represent embedded production costs. Transmission service associated with the delivery of power would be provided at an unbundled retail rate. In the event the QF with whom the COS customer has contracted fails to deliver the contracted-for power, the Company would provide service at an "Unserved Energy" rate. The initial period of implementation would be one-year, beginning in January 2011, followed by a Company report to the Commission. ETl anticipates possible

10 ETI Ex. 3 at ETI Rate Schedule LQF; ETI Ex. 9 at 9-10, Ex. PRM-l; ETI Ex. 52 at 34-36.

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unforeseen issues that may require modification or supplementation of the CGS program's tenns or reconsideration of the program altogether. 11

2. The CGSC Rider

The CGSC rider is designed to recover costs related to the start-up and ongomg operations incurred to implement the CGS. Costs will be based on estimates and ETI proposes they be trued-up on an annual basis to match what the Company has actually incurred as a result of the program. As proposed, the costs would be recovered from all CGS eligible customers

12

(LIPS) through Rider CGSC regardless of whether they actually take the CGS service.

3. The CGSUSC Rider

ETI proposes the CGSUSC rider to recover avoided embedded generation costs that would have been allocated to LIPS customers under ETI's retail base rates, had those customers not elected to participate in CGS. Rider CGSUSC is designed to recover the difference between what would have been billed by ETI under traditional LIPS service and what is billed under the combined CGS tariff and modified LIPS service. Rider CGSUSC would recover embedded generation costs and ',Uly other related base rate costs and would apply to all non-participating customers across all classes, including LIPS customers not participating in the CGS program, through a rider that will be trued-up against the actual avoided embedded generation costs and reset on an annual basis. 13

4. The System Agreement

ETI developed its CGS proposal under constraints associated with its relation to the Entergy System (System), the Entergy Operating Committee, and the Entergy System Agreement (System Agreement). The System Agreement is a PERC-approved tariff governing

II PURA § 39.452(b); ETI Ex. 52 at 37; ETI Ex. 9 at 15,22-24, Ex. PRM-l; ETI Ex. 52 at 44-46. 12 ETI Ex. 9 at 14, 19,20, Ex. PRM-l. 13 ETI Ex. 9 at 14-15, 21-22, Ex. PRM-l; Tr. at 348, 356

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the manner in which the Entergy System is operated and resources are selected for serving the energy and capacity needs of the six Entergy Operating Companies. The Entergy Operating Committee is the entity charged by the FERC with administering the Entergy System Agreement. The System Agreement vests the Operating Committee with the discretion to allocate QF put energy among the Operating Companies. The Operating Committee has , exercised that discretion and determined that QF put should be allocated to the host Operating Company. 14

The Supreme Court has held that matters delegated to the Entergy Operating Committee as part of its duty to administer the System Agreement are matters of exclusive FERC jurisdiction. IS PURA § 39.452(b) explicitly prohibits the Commission from issuing a decision addressing the Company's CGS program "that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.,,16 The System Agreement constitutes an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction, within the meaning of that provision. Because the System Agreement prohibits a single Operating Company, such as ETI, from unilaterally selecting and purchasing a resource to supply its energy needs, ETI posits that the CGS program cannot: (1) result in the purchase of resources other than those that would have been selected and purchased pursuant to the System Agreement; or (2) require a different economic dispatch of resources or allocation of power and associated costs among the Operating Companies than would occur pursuant to the System Agreement. 17

ETI generally asserts that its CGS proposal complies with the statute by making QF put to the Entergy System from ETl's service territory available to participating customers at the avoided cost rate paid to QFs for that energy. Limiting the available CGS resources to such QF put avoids interference with the System Agreement because these Texas QF resources have

14 ETl Ex. 9 at 12-13, Ex. JPH-R-2. 15. Entergy Louisiana, Inc. v. Louisiana Pub. Servo Comm'n, 539 U.S. 39,49-50 (2003). 16 PURA § 39.452(b). 17 ETl Ex. 5 at 41-42; ETI Ex. 52 at 34.

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already been assigned to the Texas jurisdiction by the Operating Committee,IS to comply with the requirement of the Public Utility Regulatory Policies Act (PURPA) that a utility purchase the energy that is put to it by QFs. Thus, the Company contends that it designed the CGS proposal

9

consistent with the System Agreement. This contention has been acknowledged by Staff.I

v. ARGUMENT AND ANALYSIS

A. The CGS Tariff

1. Eligible Customers

Participation in the CGS tariff is limited to LIPS customers. The parties, however, disagree over the definition of "eligible customers" under PURA § 39.452(b). Cities and the State propose expanding the program to include additional and perhaps all customer classes. ETI counters that the limitation to LIPS is supported by the statute and practical constraints on the makeup of a customer class. Although the ALJ ultimately recommends rejection of ETl's CGS proposal, in the event the Commission approves the tariff, the limitation to LIPS customers is acceptable for initial implementation of the program. 20

ETI argues that the term "eligible" naturally implies a limitation on customer class and that the provision is not explicit as to the parameters of eligibility. However, based on the background and context ofPURA § 39.452(b), ETI argues that the term "manufacturers" should be viewed as a reference to large manufacturing concerns such as industrial customers. 21 ETI also argues that the limitation to LIPS was based on a number of practical factors, including:

18 ETI Ex. 73 at 13, Ex. JPH-R-2. 19 ETI Ex. 52 at 43-44; Staff Ex. 3 at 6-7. 20 State Ex. 1 at 36-39; Cities Ex. 6 at 57; Cities Initial Brief at 8-9. 21 State v. Hodges, 92 S.W.3d 489, 494 (Tex. 2002) (even where statute is clear and unambiguous, courts may consider the statute's objectives and the consequences of a particular construction).

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• presumed technical expertise of LIPS customers to enter into sophisticated contractual arrangements with Texas QFs;

• the need for interval data recorder meters and backup meters to measure consumption, which LIPS customers have already installed;

• the increased start-up and ongoing administrative costs that would be passed on to non-participating customers if the CGS program were opened up to a larger pool of potential participants; and

• in terms of demand, the minimum block needed to attract suppliers would be 5 MW. 22

According to ETI, limiting the pool of eligible customers to those most likely to participate necessarily limits the amount of the Company's unrecovered costs. Based on ETl's proposal, a limited pool of eligible customers also results in allocating unrecovered costs across a larger pool of non-participants. This will mitigate the potential impact on all customers, including, as required by the statute, non-participating manufacturers. On the flipside, ETI argues that expanding the pool of eligible customers would increase start-up and implementation costs, spread over a smaller pool of non-participants -- something Cities concedes. 23 According to established rate setting principles, ETI argues those increased costs should be borne by the larger pool of eligible customers. ETI notes, however, there is little to no likelihood, and no evidence that Cities' proposed expanded customer class would actually participate in the program. Finally, under the current proposal, any increase in the amount of unrecovered costs would also be borne by non-participants, including manufacturers.

Although the State's witness also testified that the customer class should be expanded, Cities framed strong arguments that the LIPS limitation should be rejected. Cities propose that the program be available to any customer who has the demand and resources to contract for CGS. Cities acknowledges not every customer will possess the means to contract for or accept such service. Nevertheless, Cities contend that ETl's limit to the LIPS class is too narrow.

22 ETI Ex. 9 at 10-11; Tr. at 253. 23 Cities Initial Brief at 8-9.

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First, Cities argue that LIPS class customers do not possess a monopoly of sophistication to contract for CGS service. Where demand is concerned, Cities note that some non-LIPS customers' combined demand may exceed 5 MW, in addition to the fact that some suppliers may be willing to contract for less than 5 MW. As for interval data recording meters, Cities argue that some customers' demand is constant, such as the City of Beaumont, which has some 10,000 street lights for which billing is unmetered. Although Cities provided no record cites for these propositions, its main point is that certain customers outside the LIPS class may be in a position to contract for and benefit from the CGS program. Finally, with regard to increased startup and administration costs associated with an expanded customer class, Cities proposes that only participants be responsible for cost recovery on a kWh basis.

Staffs position is that, while the term "eligible" is a limitation on the customer class, the provision's reference to "manufacturers" does not mandate the program's limitation to LIPS customers. Not all LIPS customers are manufacturers and some manufacturers may be members of commercial classes. 24 Nevertheless, Staff also acknowledges there may be other issues which justify ETI's limitation to customers in the LIPS class.

The ALl agrees with ETI and Staff that the term "eligible" in PURA § 39.452(b) implies ETI should limit participation in the program to certain customers. Although the provision does not define the terms of eligibility, the reference to "manufacturers" suggests that the program should be extended to ETI's larger customers, but as noted by Cities, Staff, and other opponents, the LIPS class is not a perfect fit for all of ETI's customers engaged in manufacturing. Nevertheless, the ALl finds that ETI has articulated a reasonable and practical limit on the CGS eligible customer class for the implementation of the program. Based on the uncertain nature of ETI's cost estimates and unknown levels of participation, there are too many unexplored variables involved in expanding the customer class beyond LIPS customers at this time. In the event the Commission approves the CGS proposal, the ALl recommends eligible customers be limited to the LIPS class, leaving open the possibility for further expansion as the program develops.

24 Cities share this view.

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2. Eligible Suppliers

As proposed by ETI, eligible suppliers for the CGS program are limited to fourteen QFs within ETl's service territory.25 These QFs are facilities that generate power for their own use, and then sell their excess power to ETI. ETI is required by federal law to purchase that excess power regardless of the CGS program. 26 ETI claims that QF suppliers within its own service area are the only source of power it could incorporate into the CGS program without running afoul of the System Agreement, because energy put by QFs located in ETl's service territory is allocated to ETI through the System Agreement, so that dedicating that energy to CGS supply does not upset the allocation of energy or costs among the Entergy Operating Companies. 27 ETI also describes QF put as a viable supply option for the CGS program because the delivery of that energy can be controlled by the CGS customer and the QF.

Cities and other intervenors generally argue that the limitation on eligible suppliers does not do enough to bring competition to the market. TlEC witness Jeffry Pollock echoed this concern when he testified that there is simply not enough capacity available in ETl's plan to allow for true competition. 28 Aside from the limited number of QFs eligible to participate, competition is further limited because QFs must first meet their own power needs before they put to ETI. 29 And Cities argue that even if IPPs currently dedicated to serving ETI are added to the supply, there is still too little competition, because that power is already under contract by ETI or is required to be purchased by ETI.

ETI responds, and the ALJ agrees, that PURA § 39.452(b) does not require ETI to develop a CGS program that mimics an open market. That would be impossible. ETI is a regulated entity and part of a multi-state utility system, whose available resources and resource and cost allocations are governed by the Operating Committee as sanctioned by the FERC. It is

25 TIEC Ex. 1 at 14. 26 Tr. at 51,67-68. 27 ETI Ex. 73 at 11-12. 28 TIEC Ex. 1 at 38. 29 TIEC Ex. 1 at 67-68.

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a reality that ETI has very limited resource options available for customer choice through the CGS program. Instead, the CGS program is intended to give eligible customers a supply alternative to ETI's generation. It is not intended to be retail open access, and the amendments to the CGS provision in the 2009 legislation law make it clear that the program should not make the CGS customer a wholesale market participant.

a. Expanding the Supply to Include IPPs

TIEC proposes that CGS suppliers be expanded to include IPPs currently dedicated to serving ETI. ETI argues, however, that while this proposal would avoid interference with the resource allocation principles of the System Agreement, it still runs afoul of the economic dispatch requirements of the System Agreement. ETI points out that the System Agreement dictates the dispatch of System resources using the lowest cost resources capable of reliably serving load for the System as a whole and without regard to which Operating Company owns or controls the resource. The System Agreement does not permit the dispatch of certain resources out of order for the benefit of a single Operating Company or customers in a particular jurisdiction.30

ETI argues that including IPP suppliers would be detrimental to CGS customers because they have no control over the delivery of energy from IPPs. Because System economics dictate the scheduling of energy from IPPs, System needs may not align with the needs CGS customers in any given hour. Under these circumstances, the System's economic dispatch decisions for IPPs would prevail and CGS customers would incur significant Unserved Energy costs when IPP resources selected by a CGS customer are not included in economic dispatch for a period of 3 time. ! Cities made the same argument in briefing, also noting "CGS must be limited to power that is already allocated to ETI under the terms of the System Agreement.,,32 The ALJ agrees with ETI that using QF put allows the CGS customer and QF to agree on delivery terms that

30 ETI Ex. 41 at 9-10. 31 ETI Ex. 73 at 11-16. 32 ETI Ex. 73 at 11-12.

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meet the needs of the COS customer in a manner that will not be superseded by the System Agreement.33

Cities are also concerned that if IPPs are included, COS customers would skim the lowest cost resources away from captive retail customers. 34 As a result, Cities propose that supply options be expanded to IPPs and QFs not currently under capacity contracts with ETI. Cities point out that, at most, the Company only has capacity contracts with two-fifths of the IPPs in its service territory.35

There is insufficient evidence, however, to determine what the impact of including IPPs in the COS power supply would be. IPPs could presumably be a source of firm power under the program, which would allow the Company to eliminate the costs it would have incurred to provide firm power to its COS customers rather than simply passing those costs on to ineligible customers. On the other hand, the Company claims that its System Agreement precludes it from including IPPs in its pool of eligible suppliers,36 and including IPPs could raise fuel costs for other customers because COS customers could effectively skim the lower-priced fuel out of ETI's supply.37 OPUC witness Clarence Johnson pointed out that the impact of including IPPs as eligible suppliers may be to increase purchased power costs for non-COS customers. 38 To the extent that including IPPs in the COS power supply would harm non-participating customers, Cities opposes such a modification to the CGS tariff. If, however, the CGSUSC rider were either rejected or modified so that it does not shift unrecovered costs to ineligible customers and other protections were put in place, Cities would recommend including IPPs as a way to make the COS program truly competitive. As explained below, however, if such costs are recovered from COS participants, there is little conceivable incentive for participation in the program. The ALJ concludes that expanding the pool of suppliers to IPPs and QFs not currently under capacity

33 !d. 34 Tr. at 129-130. 35 Tr. at 54. 36 ETI Ex. 52 at 36, note 4. 37 Tr. at 129. 38 OPC Ex. 4 at 10, Ex. CJ-Reb-2.

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contracts with ETI, should be avoided as it would likely result in higher purchased power and fuel costs for non-participating customers.

b. Expanding the Supply to Include Cottonwood

Cottonwood seeks to participate in the CGS program as a supplier. Cottonwood argues that it is on equal footing with QFs. ETl argues, however, that PURPA only requires the Company to purchase QF put, not that of an independent generator like Cottonwood. Cottonwood also argues that ETl would not actually purchase QF put for CGS customers. ETl and the ALl disagree. PURA § 39.452(b) states: "pursuant to the competitive generation tariff, an electric utility subject to this subsection shall purchase competitive generation service ... ,,39 Finally, Cottonwood suggests that the System Agreement be amended to permit Cottonwood to participate in the CGS program. As noted by ETl, this would interfere with the FERC-approved System Agreement, which is specifically prohibited by PURA § 39.452(b). The ALl concludes that Cottonwood's proposal to be included as an eligible CGS supplier should be denied.

c. Expanding the Supply to Include Out-of-State QFs

TIEC proposes to expand the CGS supply pool by including QFs located elsewhere on the Entergy System. Under that proposal, a CGS customer in Texas would be permitted to contract for energy supply from a QF in Louisiana. ETI opposes this proposal, arguing that it would upset energy allocation under the System Agreement because it would require allocation of energy put by a Louisiana QF to ETl. ETl argues that the Operating Committee has already exercised its discretion on this issue and determined that QF put is to be allocated to the host Operating Company.40 ETI notes that the Operating Committee has never allocated QF put from one Operating Company's service area to an Operating Company in another jurisdiction. 41 ETl argues that implementation of the CGS program does not justifies such a change. The ALl agrees.

39 PURA § 39.452(b). 40 ETI Ex. 73 at 12-13, Ex. IPH-R-2. 41 Tr. at 89.

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As explained above, the Operating Committee is charged by the FERC with administering the System Agreement, which vests the Operating Committee with the discretion to allocate QF put energy among the Operating Companies. The Supreme Court has held that matters delegated to the Operating Committee as part of its duties to administer the System Agreement are matters of exclusive FERC jurisdiction.42 As a result, there is no basis for a state regulator to direct how QF put should be allocated among the Entergy Operating Companies.

ETl argues that even TIEC's expert witness Jeffry Pollock acknowledged that the reallocation of lower-cost QF put from Louisiana customers to Texas customers could raise costs to Louisiana customers to benefit Texas CGS customers. 43 ETl witness John Hurstell testified that expanding the pool of CGS energy suppliers as proposed by TIEC requires abandonment of the System Agreement to allocate out-of-state QF pUt,44 The ALJ agrees with ETl that, even if TIEC's proposal did not violate the System Agreement, it makes little sense for the Operating Committee to reallocate QF put for the sole purpose of expanding the CGS supply pool for the benefit of a small number of Texas industrial customers and the detriment of customers in other Entergy System jurisdictions. Finally, ETl questions whether the Commission could even enforce such an obligation.

Cities note that including QFs outside of ETl's servIce area may benefit eligible customers by increasing the diversity of available power and providing a more competitive market,45 Cities, however, only supports the inclusion of QFs outside ETl's service area, if it would not increase costs to non-participating customers. This is not likely under the CGS program, because supply options are still limited to QFs, which have discretion to put energy to ETl. As explained below, ETl's current proposal contemplates no system capacity cost savings, because it considers QF put as non-firm and must plan its resources as if the CGS customer

46

remains a normal LIPS customer. Cities and OPUC argue that any additional QF put may

42 Entergy Louisiana, Inc. v. Louisiana Pub. Servo Comm'n, 539 U.S. 39, 49-50 (2003). 43 Tr. at 313. 44 ETI Ex. 73 at 13. 45 TIEe Ex. 1 at 41. 46 Tr. 50-51.

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expose non-participating customers to additional unrecovered costs under the CGSUSC rider. 47 As a result, Cities and OPUC do not support TIEC's proposal, unless the CGSUSC rider is rejected or modified to avoid shifting unrecovered costs to non-participating customers.

B. Cost Recovery Riders

ETI's two cost-recovery riders are based on forecasted data, in amounts unspecified at hearing, and to be updated through an annual true-up proceeding. Opponents of the program focus on the prospective nature of these riders and ETI's inability to provide accurate or final cost figures. They argue that both riders should be rejected as piecemeal, premature, and not based on costs that are known and measurable. Opponents propose that any costs may be captured in a subsequent proceeding based on a historical test year once they are known and

48

measurable. They argue that allowable expenses are limited under PUC SUBST. R. 25.231(b) to expenses that are reasonable and necessary to provide service.

ETI argues that the opponents' proposals to defer recovery of costs do not comply with PURA § 39.452(b)'s directive that rates be set in this proceeding to recover ETI's unrecovered costs as a result of the CGS tariff. ETI also argues that deferral of cost recovery does not constitute rate setting under Texas Supreme Court precedent. ETI points out that the Texas Supreme Court specifically rejected claims that deferred accounting should be considered as the setting of rates. The court ruled that deferral of costs was no more than setting aside the costs, so that a rate for their recovery could be considered in a future proceeding. 49

Under normal rate-making standards, the ALI would be inclined to agree with the opponents. However, the plain language of PURA § 39.452(b) requires that "the utility's rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a result of the implementation of the tariff," and the CGS tariff "may not be considered to offer a

47 OPC Ex. 4 at 10. 48 TIEC Ex. 1 at 10.

49 State v. Public Utility Comm 'n, 883 S.W.2d 190, 197-198 (Tex. 1994). ETI notes that TIEC witness Pollock was unaware of this decision in making his recommendations. Tr. at 264.

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discounted rate or rates under Section 36.007.,,50 Unfortunately, ETI was unable to provide fixed cost figures upon which to base its riders, but this is due primarily to the unknown level of participation. s1 And this does not mean ETI failed to establish it will incur costs as a result ofthe program - it has. The ALJ finds that the CGS legislation requires that the rate set in this matter include the recovery of any cost ETI reasonably anticipates incurring as a result of the CGS program, based on the Company's estimates, to be trued-up with actual costs in one year. However, opponents ofETl's proposal are correct that there may be benefits to non-participating customers or reduced costs to ETI, that should also be accounted for at the annual true-up contemplated by both cost-recovery riders.

1. CGSC Rider

Rider CGSC is designed to recover costs related to implementation and administration costs incurred to support the CGS program. These costs would be recovered from all CGS eligible (LIPS) customers through Rider CGSC, regardless of whether they actually take the CGS service. Because the costs are currently estimated, the CGSC Rider is set for an annual true-up to costs actually incurred. 52

While no party argues that ETI should not be able to recover its startup and administration costs, the parties disagree with the timing and specifics of ETl's proposed CGSC Rider. Opponents argue PURA § 36.003 requires an electric utility's rates to be just and reasonable and that the utility has the burden to show its rate change is just and reasonable. These parties contend that ETI failed to meet that burden, because it provided insufficient evidence of specific costs, opting instead for estimates. In other words there are currently no costs upon which to base a rate and State witness Pevoto testified that estimates should not be used to establish rates in this proceeding. 53 As a result, the parties argue that Rider CGSC is premature and should be delayed until specific figures are available.

50 PURA § 39.452(b). 51 ETI Ex. 9 at PRM-1 at 7; Tr. at 20, 161, 175. 52 ETl Ex. 9 at 14,20. 53 State Ex. 1 at 41-42.

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ETI argues that the text ofPURA § 39.452(b) requires a non-discounted rate be set in the same proceeding as the program's implementation:

The tariffs subject to this subsection may not be considered to offer a discounted rate or rates under Section 36.007, and the utility's rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a

54

result of the implementation of the tariff.

The ALl agrees that the clear language ofPURA § 39.452(b) requires that ETI recover all CGS program start-up and administrative costs through tariffs established in this proceeding and to do otherwise would result in a prohibited discount rate. The ALl notes that fuel reconciliations occur with regularity at the Commission and are analogous to the Company's proposed true-up mechanism for the cas program.55 The ALl recommends that ETI recover in this proceeding, its estimated startup and administrative costs through Rider casc, to be trued-up with actual costs in one year.

TIEC and Staff also seek to limit the application of Rider casc to customers that elect to participate in the CGS program. 56 This argument has merit, because there is no discemable benefit to the LIPS class customers who do not participate in the CGS program. As noted by Staff witness Stephen Mendoza, the rider "would seem to go against a cost causation principle whereby costs are allocated to those customers who cause the costs to be incurred.,,57

There is also the possibility that non-participating LIPS class manufacturers would suffer a competitive disadvantage. PURA § 39.452(b) specifically requires that:

The commission shall ensure that a competitive generation tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers that choose not to take advantage of competitive generation.58

54 PURA § 39.452(b). 55 ETl Ex. 76 at 32. 56 Staff Ex. 3 at 12-13; TlEC Ex. 1 at 46-47. 57 Staff Ex. 3 at 12. 58 PURA § 39.452(b).

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Although the recovery of CGS startup and administration costs may not affect the sustainability of non-participating manufacturers, it may affect their competitiveness relative to CGS participants, because non-participant manufacturers under the LIPS tariff will contribute to cost recovery while not receiving the benefits of the program. ETI witness Phillip May justified recovering these costs from LIPS class customers who decide not to participate because "those customers have the opportunity to sign up for and benefit from the CGS program."S9 But this argument ignores the plain language of PURA § 39.452(b) that prohibits competitive disadvantage to those manufacturers who elect not to participate. The parameters of competitive harm, however, were not spelled-out in the provision, nor is there specific evidence in the record of such harm.

ETI also points out that limiting Rider CGSC to participants may result in the Company incurring the costs of implementation. ETI witness May testified that, because there is a possibility that no customers will participate, the Company would be unable to recover its start- up and administrative costs if the rider is limited to CGS participants. 6o

This raises a potential conflict brought about by the language ofPURA § 39.452(b), and another reason the ALJ recommends against implementation of the program. Nevertheless, if PURA § 39.452(b) is to be read in a manner to avoid conflict, the ALJ recommends that ETI has proposed a reasonable compromise. The ALJ agrees that requiring any non-participant in the CGS program to share in its costs violates the principle of cost causation. Yet, even Staff agrees that PURA § 39.452(b) states the CGS tariffs "may not be considered to offer a discount rate or rates under Section 36.007." PURA § 36.007(d) reads:

Notwithstanding any other provision of this title, the commission shall ensure that the electric utility's allocable costs of serving customers paying discounted rates under this section are not borne by the utility's other customers.

As a result, Staff acknowledges the prohibition against "other customers" bearing the costs of a discounted rate appears not to apply here. Assuming this is the legislature's intent, ETI could

59 ETI Ex. 9 at 19,20. 60 ETI Ex. 76 at 32-33.

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charge other ratepayers its unrecovered CGS program costs, despite the principal of cost- causation.

Second, based on the record, the extent of competitive harm non-participant manufacturers would suffer is unclear. What is clear, however, is that if Rider- CGSC applies only to participants and no entities participate, the Company would be left with unrecovered startup costs, a result expressly prohibited by PURA § 39.452(b). If the Commission approves ETI's proposal, the ALl supports limiting Rider CGSC to CGS participants. However, to address ETI's legitimate concern over the potential of being left with the costs, the ALl recommends that Rider CGSC initially be implemented as proposed by ETI. However, once the program has participants, all costs should be shifted to those participants immediately or at the annual true-up. A refund could be issued to non-participants concurrent with the cost reallocation. The ALl understands that this issue has not been fully explored, but ETI indicated in briefing that it is open to suggestions.

2. CGSUSC Rider

Rider CGSUSC provides for the Company's recovery from non-participating customers of the embedded generation costs that it will lose from customers that elect to participate in the CGS program. It is intended to recover embedded generation costs and any other related base rate costs and would apply to all non-participating customers across all classes, including LIPS customers not participating in the CGS program. 61 As with Rider CGSC, the Company proposes an annual true-up of estimated unrecovered costs to the costs actually unrecovered. 62 ETI notes the annual true-up will also provide an opportunity to consider potential adjustments in light of the level of participation in CGS and its impact on other classes. 63

61 ETI Ex. 9 at 14, 15,21. 62 ETI Ex. 9 at 21-22. 63 ETI Ex. 9 at 23-24. While the Company has not proposed a cap on the level of CGS participation, it recognized that this is a means oflimiting the exposure of non-participating classes to unrecovered costs. Tr. at 182.

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A number of parties argue that ETl is not entitled to recover embedded generation costs or other base rate costs at all. These parties contend that ETl is essentially seeking to recover lost revenues, not costs. Parties opposed to the rider argue no rate should be set in this case to account for unrecovered costs. Instead, such unrecovered costs should be recovered from increased revenues from load growth, or from other savings that may be associated with the CGS program.

ETl argues these positions should be rejected because they are at odds with the requirements of the governing statute and with fundamental rate setting principles. As argued by ETI the "unrecovered costs" referenced in PURA § 39.452(b) and the "lost revenue" that ETI has calculated as the measure of the unrecovered costs are one and the same in the ratesetting context. ETl points out that OPUC witness Johnson acknowledged in his direct testimony that "[r]evenues are intended to equal embedded cost of service for the adjusted test year.,,64 TIEC witness Pollock also agreed at hearing the Company's unrecovered revenues calculation would account for the migrating customers' share of the Company's embedded fixed production costS. 65

The ALJ agrees with ETl that PURA § 39.452(b) requires that "the utility's rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a result of the implementation of the tariff," and that the CGS legislation specifically authorizes the Company to recover any unrecovered costs as "a result of' implementation of the CGS program. 66 ETI is entitled to collect unrecovered embedded generation costs and any other related base rate costs as a result of customer migration to the CGS program.

The ALJ agrees that ETI's revenue requirement is based on and designed to recover such costs. With every customer that migrates to the CGS program, ETl loses a customer and suffers "load loss." That is, the pool of customers contributing to the recovery of ETl's embedded

64 Tr. at 350-351. 6S Tr. at 261-262,356. 66 ETI Ex. 76 at 28-29.

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generation costs shrinks with each new COS participant. Load loss is detrimental to the Company in the opposite manner that load growth benefits the Company. Additional customers mean the base rate quantum is spread over a larger pool. Furthermore, the same parties who oppose Rider CGSUSC also contend ETl should offset the rider with load growth. Under normal circumstances, the ALJ would agree with those parties opposed to COSUSC, because ETl is only entitled to seek, but is not guaranteed a set return on its investment. However, PURA § 39.452(b) mandates ETI recover "any" of its unrecovered costs as a result of the implementation of the program. Opponents of Rider COSUSC have failed to identify any caveats to this expansive language. As a result, the ALJ concludes that ETl is entitled to recover the unrecovered embedded generation costs and any related base rate costs as a result of customer migration to the COS program. As discussed below, however, that recovery should be offset against load growth and any identifiable capacity savings at the annual true-up.

The most troubling aspect of Rider COSUSC is that it recovers the unrecovered costs from all non-participating ratepayers. As with the arguments for and against Rider CGSC, Staff and a number of intervenors argue Rider COSUSC should be rejected because it is inconsistent with the principal of cost-causation. Although the migrating COS customers cause the costs to be incurred, Rider COSUSC recovers ETl's unrecovered embedded generation costs from all other ratepayers, including non-LIPS class customers who are not eligible to participate in the COS program. 67

Furthermore, having non-COS participants pay for costs related to the COS program may contradict the statutory requirement that the COS tariff not harm the "sustainability or competitiveness of manufacturers that choose not to take advantage of competitive generation" although there is no evidence on whether this might occur. 68 All of the arguments regarding Rider CGSC's potential competitive harm to non-participating manufacturers apply with greater force to Rider COSUSC. Not all manufacturing customers fall within the LIPS class. Due to the

67 Staff Ex. 3 at 12. 68 PURA § 39.452(b).

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cost-shifting nature of this rider, all such manufacturers will be saddled with BTl's unrecovered embedded generation costs, which may be as high as 75 million dollars. 69

As with Rider CGSC, Staff acknowledges PURA § 39.452(b) permits BTl to recover "any" of its unrecovered costs and the CGS rate is not to be considered a discount rate under PURA § 36.007. As a result, the prohibition against allocating costs to "other ratepayers" under PURA § 36.007 does not apply. However, Staff disagrees with BTl's conclusion that PURA § 39.452(b) mandates these costs be recovered only from non-CGS participants. Staff argues that nothing in PURA § 39.452(b), prevents BTl from charging the CGS participants its unrecovered costs. While the AU agrees with Staff, a primary point ofBTI's CGS program is to remove itself from the market exchange between CGS customer and the QF supplier. Recovering unrecovered capacity/base rate costs from the migrating customer runs counter to this purpose. Although, the AU agrees with BTl that recovering these costs from CGS participants would make the CGS program economically unattractive, PURA § 39.452(b) does not mandate that such unrecovered costs be recovered from non-participating customers. 70 There is no easy resolution to this issue. Although the ALI provides further analysis below, Rider CGSUSC is a primary reason that he recommends the proposal be denied, because it runs contrary to the fundamental ratemaking principle of cost causation and may harm the competitiveness of non-participating manufacturers.

a. Cost Estimates

One of the greatest concerns stated by opponents is that the amount of potentially unrecovered costs is unknown. BTl estimates that if all LIPS class customer were to contract for an alternative QF supply for 100 percent of their load, BTl could potentially realize 75.2 million dollars in avoided embedded generation costs for the eligible CGS load. Company witness May testified that the Company already knows the unit cost of embedded generation that would be avoided. The only question is what the level of participation will be. ETl cannot predict

69 PURA § 39.452(b)'s competitive language only applies to manufacturers who elect not to participate.

The AU acknowledges that non-LIPS class customers cannot participate.

70 ETI Ex. 76 at 32-33.

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whether 5 percent or 100 percent of ETl's LIPS customers will participate in the program. Without knowing the level of participation there is no way to know the extent of costs. 71

TIEC witness Pollock also offered an estimate of ETl's potential unrecovered embedded generation and purchased power capacity costs. 72 He estimated the amount is approximately 15 million dollars at ETl's proposed revenues and 12 million dollars with TIEC's proposed adjustments to ETl's purchased power capacity costs (discussed below). However, Mr. Pollock admitted these figures were based on 200 megawatts of participation, which was "pulled out of thin air.,,73 The uncertainty associated with these figures is that the number of LIPS-class customers who will participate in the CGS program is unknown.

Because PURA § 36.003 requires that an electric utility's rates be just and reasonable, the electric utility proposing a rate change has the burden of proof on that issue. Given that the potential costs of the CGS program are unknown and could be very substantial, opponents argue that ETl has failed to show that Rider CGSUSC would result in just and reasonable rates. ETI points out that the unrecovered costs will ultimately be trued-up. Opponents respond that the true-up will not occur until a year after the implementation of the program, resulting in ratepayers being charged as much as 75 million dollars for the first year of the program. 74 They argue it is unreasonable for ratepayers to be charged a large, unsupported amount, especially when they do not cause ETl to incur these costs or benefit from the CGS program.

The ALJ agrees. The shifting of such unrecovered costs to rate-payers who do not cause their lack of recovery and the uncertainty associated with the ultimate amount to be charged other classes is another major reason for the ALl's recommended rejection of this program. This is not, however, a criticism of ETI. ETl was given the difficult task of developing a semicompetitive program for a limited number of customers, using its own distribution system and in spite of its limitations as a regulated entity and member of an integrated multi-state utility

71 ETI Ex. 9 at 14; Tr. at 157, 158, 162-163. 72 TIEe Ex. 1 at 51-52 and Ex. JP-16. 73 Tr. at 249. 74 Tr. at 11, 14.

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system, whose cost and resource allocations are largely controlled by the Operating Committee consistent with the System Agreement. The Company notes that while the portion of embedded generation costs subject to loss under the CGS program is known with certainty, the volume of load associated with those unrecovered costs will only be known once the program begins and participation levels are known. 7S All of these restrictions contributed to ETl's difficulty in developing exact cost figures.

The AU finds that ETl has made a good faith effort to determine the unit cost of unrecovered embedded generation, but simply cannot predict the level of participation. In so doing, ETl has given the Commission a worst-case scenario of 75 million dollars in unrecovered costs if every eligible customer participates. Because a rate must be set in this proceeding, if the Commission approves ETl's CGS program, the ALJ recommends the rate be set based on ETl's projections until the first annual true-up period, after which ETl may use known and measurable costs to set rates in the future, taking into account load growth and other potential benefits of the program as discussed below.

b. Annual True-ups Should Account for Load Growth

Staff and opponents of Rider CGSUSC argue it is deficient because it fails to account for load growth, which could mitigate ETl's unrecovered generation-related costS. 76 TIEC witness Pollock explained that as load grows:

each additional unit of energy sold will provide a contribution to all fixed costs including embedded generation costs [and that] any reduction in embedded generation cost recovery attributable to the CGS program [will] be more than offset by increased revenues due to load growth. 77

Although it remains to be see~ whether the reduction in cost recovery will be completely offset by load growth, it should nevertheless be accounted for. The potential amount of unrecovered costs is substantial and ETl seeks to recover these costs from ratepayers who don't cause them

75 Tr. at 162. 76 Tr. at 372. 77 TIEe Ex. 1 at 50.

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and are unlikely to benefit from the CGS program. As a result, opponents argue that any potential cost mitigation should be accounted for in designing Rider CGSUSC. The ALl agrees, and notes that at a minimum, load growth should be explored in the annual true-ups ofthe rider.

ETI points out that the unrecovered costs at issue here are the embedded test year production costs upon which the Company's base rates are being established. ETI explains that incremental changes in future costs and revenues do not play into the determination of how such costs are recovered. 78 Instead, rates are set in the first instance to recover the historical cost of service. Incremental future changes in revenue from load growth or future cost savings are devoted to covering incremental future cost increases and to ensuring that shareholders still have an opportunity to earn a fair return despite these future increases. 79 The Company argues that its approach to unrecovered costs honors these fundamental rate setting principles: it preserves the Company's opportunity to recover the existing embedded costs that its rates are set to recover, while the other parties' use of load growth and alleged future cost savings violates these principles.

ETI also notes that the Commission has previously recognized that load growth adjustments such as those suggested by opponents are inappropriate. Staff witness Mendoza, for example, acknowledged the Commission's rejection of a base revenue/load growth adjustment in adopting its rule implementing the transmission cost recovery legislation codified in PURA § 36.209. The Commission found that it was "not necessary or appropriate" to "account for growth in overall revenue as a means to reduce the transmission costs eligible for recovery.... ,,80 The Commission found that such an adjustment would discourage utility investment and that the impact of such load growth was more properly considered within the context of a future general rate setting proceeding. 8 !

78 Tr. at 356. 79 Tr. at 351-352.

80 Tr. at 358. Project No. 33253, Rulemaking Relating to Transmission Cost Recovery Factor for Non-

ERCOT Utilities, Final Order at 14 (Dec. 14,2007).

, 81 Id.

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The ALJ agrees with ETl's characterization of the traditional function of load growth in the period between rate cases. However, Rider CGSUSC recovers ETl's unrecovered base rate costs as a result of load loss from all ratepayers who are not beneficiaries of the CGS program. This violates the principal of cost causation. As a result, the ALJ recommends that load growth should be accounted for to the extent that non-participating ratepayers are subsidizing CGS program participants.

ETl also argues that its costs are likely to increase cancelling out any load growth. ETl claims that recent increases in non-fuel operating and maintenance costs have outpaced, and future forecast increases will continue to outpace, the Company's forecasted load growth due to a number of factors. Company witness May explained that distribution costs, transmission costs, and generation costs have all increased at a greater rate than the increase in the Consumer Price Index. ETI also argues that regulators' push for increased energy efficiency has reduced the rate of load growth increase. Increasing utility reliance on the maturing wholesale markets has changed the traditional model of cost recovery to one where increased purchased capacity expense must be captured through frequent rate case filings. 82 As a result, ETl claims that load growth cannot account for additional costs in the way it has in the past. Opponents generally argue that ETl's assumptions regarding its future costs lack evidentiary support or are unreliable. The ALI finds that even if ETI is correct, cost increases affecting load growth is an issue that can be addressed during the annual true-up proceeding.

ETl also cited the Commission's transmission cost recovery factor (TCRF) rule for utilities outside of the Electric Reliability Council of Texas (ERCOT) as support for not using potential load growth in designing Rider CGSUSC. 83 Staff argues, however, that the rule accounts for load growth, and protects ratepayers, because it requires the refund of any overrecovery as a result of load growth, but prohibits the surcharge of any under-recovery.84 In its

82 ETI Ex. 76 at16; 202-205; Tr. at 192,201-206. 83 Tr. at 357-360. 84 Tr. at 357-360; P.D.C. Subst. R. 25.239(f). See also P.U.C. SUBST. R. 25.239(d) (setting the denominator for the TCRF -BD - as "each customer class's annual billing determinant (kilowatt-hour, kilowatt, or kilovolt-ampere) for the previous calendar year").

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order approving the rule, the Commission recognized the "proposed calculation properly accounts for load growth for the purposes of the TCRF.,,85 The Commission concluded:

it is not necessary or appropriate to require that the calculation of the TCRF account for growth in overall revenue as a means to reduce the amount of transmission costs eligible for recovery through the TCRF. To do so would undermine the underlying purpose of HB 989 to encourage timely investment in non-ERCOT transmission infrastructure. 86

Staff also notes that in the non-ERCOT TCRF rulemaking the Commission noted that nontransmission costs could grow faster than the increased revenues resulting from the TCRF, which was also an implicit recognition that the opposite could be true.

According to Staff, the TCRF rule is designed to encourage investment in non-ERCOT transmission infrastructure. The CGS program, however, should be designed neither to encourage nor discourage participation. Instead, Staff argues the program should be cost-based to the extent possible and contends that PURA § 39.452(b) expresses a policy against crosssubsidization by prohibiting implementation in a manner that "harms the sustainability or competitiveness of manufacturers that choose not to take advantage of competitive generation." In light of this legislative policy and the limited scope of eligible customers, inaccuracies in the allocation of costs should be resolved in favor of over-allocating costs to the program rather than under-allocating costs to the program. Thus, Staff argues that accounting for load growth in the CGS program is appropriate.

ETI argues that if the Legislature had intended to include a load growth adjustment as part of a mechanism for cost recovery, it would have done so. ETI notes that in the same bill that first addressed the CGS program, the Legislature explicitly included a load growth adjustment in the context of the Incremental Purchased Capacity Rider:

85 Project No. 33253, Order Adopting New § 25.39 as Approved at the December 7,2007 Open Meeting (December 14,2007) at 14.

86 Project No. 33253, Order Adopting New §25.39 as Approved at the December 7, 2007 Open Meeting (December 14, 2007) at 14.

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An electric utility subject to this subchapter is entitled to recover, through a rate rider mechanism, reasonable and necessary costs of incremental resources required to meet load requirements to the extent those costs result in the utility expending more for capacity costs under purchase power agreements than were

87

included in the utility's last base rate case, adjustedfor load growth.

ETI argues the express inclusion of a load growth adjustment in this provision indicates legislative intent to exclude it where not made explicit, as in PURA § 39.452(b).

The ALJ disagrees. As Staff notes, PURA § 39.455 concerns the recovery of incremental costs and the express recognition of incremental load (load growth) is logical in that context. PURA § 39.455 specifically references "necessary costs of incremental resources required to meet load requirements to the extent those costs result in the utility expending more for capacity costs under purchase power agreements than were included in the utility's last base rate case ... ,,88 In contrast, PURA § 39.452(b) lacks specificity about such cost recovery, using only the term "any" in reference to costs. If the vague term "any" is broad enough to include unrecovered base rate costs, as argued by ETI, then the ALJ finds that it should also be read as inclusive of traditional offsets to those costs, such as load growth.

c. Potential Benefits of the CGS Program

i. Capacity Savings

Opponents of the CGS program argue that ETI failed to identify a number of potential benefits for non-participating customers. TlEC provided substantial briefing on this issue and the ALI's analysis focuses on its arguments among opponents. TIEC points out that the Commission has long recognized that QF power may be used to avoid a utility's capacity and energy costs. In Docket No. 5994, for example, the Commission held:

It is generally recognized that QF power may be used for two purposes. The first purpose, which is the primary thrust of Section 201 of PURPA, is the displacement of a utility's fuel with that of QFs to achieve a more efficient use of

87 PURA § 39.455 (emphasis added). 88 PURA § 39.455.

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natural resources. The second purpose is the substitution of QF generating plant for utility-constructed generating plant. That is, rather than constructing generating plant to serve its system demand, the utility should utilize, where practical, the generating plant of QFs. 89

TIEC argues the Commission's rules establish how avoided costs for QF capacity and energy should be addressed,90 and that the Commission has addressed how avoided costs may be determined for firm and as-available QF power and what constitutes firm or non-firm QF power. 91

First, TIEC argues that the CGS program would reduce ETI's capacity costs. It is undisputed that ETI is a capacity short company that pays capacity costs each month for purchased power and for its share of Entergy System capacity reserves. 92 According to ETI, purchased capacity costs, including capacity costs from its affiliates, were a significant component of the Company's cost of service and constituted 34 percent of the company's non- fuel revenue requirement.93 Even though ETI recently entered into several purchased power contracts, ETI's capacity deficit is expected to worsen over time and its load is growing at an

94

estimated average rate of 1.8 percent. As a result, TIEC urges the Commission to deem CGS power as a firm source of generation, with the added benefit of reduced capacity costs for all of ETI's customers.

89 Petition of Inquiry into the Rates Paid by Houston Lighting and Power Company to Qualifying Facilities for the Purchase of Non-Firm Energy, Docket No. 5994, 12 Tex. P.U.c. Bull. 795 (Oct. 6, 1986), 1986 WL 380068, *4.

90 P.U.C. SuaST. R. 25.242 (establishing rules for calculating avoided energy and capacity costs for fIrm and non-fIrm QF power).

91 P.U.C. SuaST. Rs. 25.242(c)(5), 25.242(g), 25.242(i); see also Complaint of JD Wind 1, LLC, et. ai, Against Southwestern Public Service Company, Docket No. 34442, Proposal for Decision (Mar. 25, 2009) and Order (May 1, 2009).

92 Tr. at 103, 173; ETI Ex. 52 at 26-28. 93 ETI Ex. 9 at 28.

94 Tr. at 109, 246; TIEC Ex. 12. See Application of Entergy Texas, Inc. for Approval of Power Cost Recovery Factor, Docket No. 37482 (seeking recovery of Entergy Arkansas Inc. Wholesale Baseload purchased power contract); see also OPC Ex. 1 at 91; and ETI Ex. 76 at 25 (seeking recovery for the Frontier purchased power contract).

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TIEC makes a valid point. LIPS customers account for 23 percent of ETl's total demand. 95 If demand-related costs could be reduced by moving firm LIPS customers to CGS load, the CGS program could possibly benefit all of ETl's customers through reduced MSS-l costs and reduced capacity ETl currently procures in the market to serve LIPS customers. To recognize these savings, however, ETl would have to treat the QF put as firm load - which it cannot. TIEC proposes a number of different ideas for achieving this. TIEC proposes that the Operating Company could recognize participating QFs as IPPs and enter into negotiated rates with the QFS. 96 Capacity cost savings would result from a firm capacity contract with each QF,

97

as demonstrated by EGSl's contract with Calpine's Carville facility, a QF located in Louisiana. However, the Commission does not have the authority to compel the Operating Committee to do so and ETI is subject to the Operating Committee's decisions on this issue.

TIEC also argues that a specific contract with ETl is not a pre-condition to treating QF power as capacity. TIEC posits the Commission could order ETl to recognize the capacity cost savings resulting from a QF contract with a CGS customer. TIEC contends that FERC precedent and the System Agreement explicitly recognize that, if a state commission determines that capacity costs can be avoided by QF purchases, that determination will affect the amount of capacity deemed available for the operating company and will impact MSS-l reserve equalization payments under the System Agreement. 98 ETI and Staff respond that this authority does not apply to QF put from CGS suppliers, because it would not be within the utility's control. As a result, ETI cannot recognize the capacity benefits of QF put. 99

TIEC claims there must be some avoided capacity costs by taking a steady stream of QF power. There is Commission authority for such recognition and the FERC has held that "[s]tate commission avoided cost determinations should be recognized for intra-system billing purposes

95 ETI Ex. 9 at 13. 96 Tr. at 88. 97 Tr. at 298; TIEC Ex. 11 at TIEC 9-9 EC1209. 98 Tr. at 86; TIEC Ex. 9, Entergy System Agreement at Section 10.02(f) and 2.12; State ofArk. v Middle South Servs., Inc., 34 FERC ~ 61342,61639, Opinion No. 246-A (March 17, 1986) (affrrming Opinion No. 246, 33 FERC ~ 61408 (Dec. 23, 1985).

99 Tr. at 87.

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under the System Agreement.,,100 TIEC argues that ETI could recognize a negotiated contract or rate with a QF, or the Commission could simply order ETI to recognize avoided capacity costs from the CGS program. According to TIEC, the Commission has the jurisdictional authority to determine whether the power put to ETI by a QF as a result of a CGS customer's contract with the QF results in firm capacity, 101 is evidence of the utility's legally enforceable obligation to take that power,102 and creates avoided costs associated with the power. 103

TIEC acknowledges, however, that Commission rules differentiate capacity and energy benefits provided by QFs based on whether the power is firm or non-firm. In Docket No. 5994, the Commission determined that "[t]he difference between firm and nonfirm primarily is the existence or non-existence of a legally enforceable obligation on the behalf of the QF to provide power.,,104 P.u.e. SUB ST. R. 25.242(c)(5) explicitly defines "Firm Power" from a QF as power "[f]rom a qualifying facility ... that is available pursuant to a legally enforceable obligation for scheduled availability over a specified term.,,105 TIEC argues that notice to ETI of a contract between a QF and a CGS customer would create such a legally enforceable obligation. l06 According to TIEC, courts have held that a legally enforceable obligation need not be a contract

100 Opinion No. 246, 33 FERC ~ 61408 (Dec. 23, 1985); Houston Lighting and Power Company, Docket No. 10832,20 Tex. P.U.C. Bull. 312 (Jun. 9, 1994) (addressing avoided costs for a utility that received fIrm energy and capacity from a QF).

101 p.u.c. SUBST. R. 25.242(c)(5) (defIning "fIrm power" from QFs) and P.U.C. SUBST. R. 25.242(c)(5)

(describing factors considered in determining quality offrrmness ofQF power).

102 Power Resources Group, Inc. v. Pub. Uti!. Comm 'n o/Tex., 422 F.3d 231 (5th Cir. 2005) (holding that the Commission had authority under P.U.c. SUBST. R. 25.242(£)(1)(B) to determine whether QF put power to utility resulted in a legally enforceable obligation); see also Pub. Servo Co. of Ok. V. State Ok. Corp. Comm 'n, 115 P.3d 861,872 (Jun. 2005) (citing Metropolitan Edison Co., 72 FERC 61,015, 61, 050, 1995 WL 397198 (1995)) ("It is up to the States, not [FERC], to determine the specifIc parameters of individual QF power arrangements, including the date at which a legally enforceable obligation is incurred under State law.").

103 See et. aI., 16 U.S.C. § 824a-3(f); FERC V. Miss., 456 U.S. 742 (1982); 18 C.F.R. 292.401(a); Petition of Inquiry into the Rates Paid by Houston Lighting and Power Company to Qualifying Facilities for the Purchase of Non-Firm Energy, Docket No. 5994, 12 Tex. P.U.C. Bull. 795 (Oct. 6, 1986), 1986 WL 380068, *4.

104 Petition of Inquiry into the Rates Paid by Houston Lighting and Power Company to Qualifying Facilities for the Purchase of Non-Firm Energy, Docket No. 5994, 12 Tex. P.U.c. Bull. 795 (Oct. 6, 1986), 1986 WL 380068, *5 (holding that the "difference between fIrm and nonfrrm primarily is the existence or non-existence ofa legally enforceable obligation on the behalf of the QF to provide power.")

lOS P.U.c. SUBST. R. 25.242(c)(5). 106 P.U.C. SUBST. Rs. 25.242(c)(5), 25.242(£)(1)(B).

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for power between a utility and QF,107 and the Commission recognizes that when a QF and a utility enter into a contract for the transfer of power, "the law will impose a legally enforceable

.

obligation on the utility if the parties are unable to agree on contractual terms.,,108 Under the Commission's rules and precedent, a legally enforceable obligation of an electric utility to take energy and capacity from a QF arises when the QF notifies the utility that it will deliver firm power within 90 days.109

TIEC concludes that if a legally enforceable obligation for firm power exists, then BTl must recognize avoided capacity costs associated with CGS QF pUt. IIO Specifically, P.U.C. SUBST. R. 25.242(c)(13) outlines numerous factors to determine the "degree to which capacity offered by the qualifying facility is an equivalent quality substitute for firm purchased power or an electric utility's own generation." The factors include:

reliability of generation and interconnection; forced outage rate; availability during peak periods; the terms of any contract or other legally enforceable obligation, including, but not limited to, the duration of the obligation, performance guarantees, termination notice requirements, sanctions for noncompliance; maintenance scheduling; availability for system emergencies, including the ability to separate the qualifying facility's load from its generation; the individual and aggregate value of energy and capacity from qualifying facilities on the utility's system; other dispatch characteristics; reliability of primary and secondary fuel supplies used by the qualifying facility; and impact on utility system stability. III

TIEC proposes that these factors would be examined in a proceeding to determine CGS program unrecovered costs, presumably in a true-up proceeding.

107 Pub. Servo Co. of Ok. V. State Ok. Corp. Comm'n, 115 P.3d 861,872 (Jun. 2005) (citing Metropolitan Edison Co., 72 FERC 61,015, 61, 050, 1995 WL 397198 (1995» ("It is up to the States, not [FERC], to determine the specific parameters of individual QF power arrangements, including the date at which a legally enforceable obligation is incurred under State law.").

108 Complaint of JD Wind 1, LLC, et. ai, Against Southwestern Public Service Company, Docket No. 34442, Proposal for Decision at 6 (Mar. 25, 2009), Order (May 1, 2009).

109 Docket No. 34442, Proposal for Decision at 9 (referring to p.u.C. SUBST. R. 25.242(f)(1)(B». 110 Docket No. 34442, Proposal for Decision at 10. III P.U.C. SUBST. R. 25.242(c)(13).

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Finally, TIEC argues that the cas program would result in reduced operational costs for ETI due to decreased volatility in QF put power. TIEC argues that ETI would experience operational savings due to a flatter round-the-clock load shape. As a result, ETI could eliminate a sporadic PURPA put pattern and would not have to swing generation associated with QFs as much. TIEC argues that this would reduce the amount of capacity needed to maintain reliable service. I 12

The obvious problem with TIEC's arguments is that they are premature. For instance, there is no evidence on any of the factors to determine whether OF put is firm because the program has yet to be approved, implemented, or subscribed to. Until that happens there are no contracts to be examined, nor capacity savings to be explored. In short, the record did not indicate whether there would actually be any capacity benefit. I 13 Mr. Pollock admitted that QF put does not count as capacity in ETl's resource planning, that such savings are only a potential benefit, and that there has been no specific quantification of potential savings from reduced capacity costS.11 4 As for operational costs, there is no evidence on load shape or decreased volatility in QF put power.

Furthermore, as argued by Staff and ETI, Mr. Pollock acknowledged that QF put is a non-finn source of energy. 115 He also acknowledged that his theory of capacity savings was dependent on an assumption that the QF put from which cas customers will be supplied is treated as a firm resource. 116 Both Staff and ETI argue that QF put cannot be treated a finn supply. First, with regards to any contract between a cas supplier and customer, the Company would be a third party to the contract with no rights whatsoever stemming from that contract. The fact that a cas customer might contract with a cas supplier for a "firm" supply of power, does not change the fact that ETI would have no control over the power put by the QF to ETI -- that power would still be non-firm to ETI. Second, the contract between the cas supplier and

112 Tr. at 252, 330. 113 Staff Ex. 3 at 11. 114 Tr. at 251,291-292,315. 115 Tr. at 284. 116 Tr. at 315.

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customer would simply be a financial transaction, and have no impact on the necessities of ETI' s resource planning. The Company's obligation to provide continuous, reliable service to all of its customers, including those that migrate to CGS, would remain unchanged; CGS customers must receive firm service and ETI cannot plan its system any differently regardless of customer type. 117 As a result, Staff and ETI argue that capacity cost savings are unlikely.

Staff and ETI also argue that TIEC's reliance on P.D.C. SUB ST. R. 25.242's definition of "firm power" is misplaced. The definition of "firm power" in the rule states: "from a qualifying facility, power or power-producing capacity that is available pursuant to a legally enforceable obligation for scheduled availability over a specified term.,,118 Again, the contract between the QF and the CGS customer is irrelevant. The purpose of the rule is "to regulate arrangements between qualifying facilities, retail electric providers with the price to beat obligation (PTB REPs), and electric utilities.,,119 The rule only applies to "all PTB REPs and to all electric utilities.,,120 A CGS customer is not one of these entities, and is not subject to the rule even ifit enters into a contract with a QF subject to the rule. The ALJ agrees with Staff and ETI. A contract between a CGS customer and a QF is not subject to the rule and cannot serve as the basis for finding a "legally enforceable obligation" between the QF and ETI to satisfy the definition of "firm power."

At this point, the ALJ agrees with Staff and ETI that the Company cannot, nor should the Commission treat, CGS QF put as firm capacity. However, as noted by Mr. Pollock, because a CGS customer will need firm, reliable service, it is reasonable to anticipate they will enter into contracts with QF suppliers for firm round-the-clock power. As a result, the ALJ anticipates (as do most intervenors) that ETI's purchased capacity and MSS-l needs will drop in some proportion to the number of LIPS customers who migrate to the CGS program. If all non- participating ETI customers are to make up for ETI's resulting load loss, then they should also realize the benefit of any capacity savings. If the Commission approves the CGS program, the

117 Tr. at 52, 124, 125, 136-137. 118 P.U.C. SUBST. R. 25.242(c)(5). 119 P .U.c. SUBST. R. 25.242(a).

120 P.U.C. SUBST. R. 25.242(b).

SOAR DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 37 PUC DOCKET NO. 37744

ALJ recommends that the issue of capacity savings be fully explored in the annual true-up proceeding, where evidence can be taken on the factors identified above, and on the existence and extent of such benefits.

ii. Potential Average Fuel Cost Savings

Opponents also argue that the CGS program has the potential to lower average fuel costs for non-CGS participants. ETl's proposal contemplates that CGS customers will move off the fuel factor and instead pay energy costs at the avoided cost rate. ETl's firm customers (LIPS, residential, commercial) are on ETl's fuel factor and pay average fuel costs, as opposed to avoided fuel costs. During the reconciliation period, ETl's avoided costs of QF energy were higher than its average costs of energy. As a result, these parties contend that if firm LIPS load had moved to the CGS tariff during the reconciliation period, average fuel costs would have lowered for non-CGS participants. 121

ETI argues that avoided fuel costs could actually be lower than average fuel costs, but no party other than TIEC provided analysis of this likelihood. In fact, both Cities witness Karl Nalepa and ETI witness John Hurstell confirmed that, when avoided costs are higher than average costs, non-CGS customers would experience lower average fuel costs; and that they had conducted no analysis comparing ETl's average and avoided fuel costs. I22 While there could be certain times when avoided fuel costs are lower than average fuel costs, TlEC argues that increases in gas prices make this scenario less likely. 123

121 Tr. at 229-230,311. See P.D.C. SUBST. R. 25.242(c)(1) (defIning "avoided costs" as "[t]he incremental costs to a PTB REP, or electric utility of electric energy, which but for the purchase from the qualifying facility or qualify facilities, such PTB REP or electric utility would generate itself or purchase from another source") and TlEC Ex. 6 (describing the methodology for calculating ETI's avoided energy costs from QF puts under Schedule LQF); see also Tr. at 78 (describing average energy costs as the total amount of energy sources on the system divided by total energy).

122 Tr. at 115,229,231. TlEC Ex. 14. 123 TIEC Ex. 2 at 57-59.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 38 PUC DOCKET NO. 37744

124 Staff notes that these purported benefits have yet to be quantified. Staff is also concerned that because potential unrecovered generation costs could be substantial, any benefits would probably be inadequate to offset those costs. Staff is correct that it is premature to attempt to weigh the relative value of such benefits - there is no evidence on the matter. Nevertheless, in the event the Commission approves ETI's CGS proposal, the ALl recommends that a review of average fuel cost saving should at least be included in the annual true-up proceeding.

c. ETI May Recover its Costs Through a Rider

Cities argue that PURA § 39.452(b) limits ETI's recovery of unrecovered costs to program implementation and administration costs (CGSC costs) and prohibits recovery of unrecovered costs through a rider. Cities cite to the legislative history of PURA § 39.452(b), specifically the Bill Analysis filed with the House Committee Substitute to House Bill 1567, to support both arguments. 125 The portion of the Bill Analysis Cities rely on states:

At the time the utility files a rate proceeding, a competitive generation tariff must be proposed that the PUC shall approve, reject or modify. Any tariff that is approved cannot be considered as a discounted rate and the utility's rates shall be set in this proceeding to recover any costs associated with the tariff. When the utility files a rate proceeding, they cannot request approval of both a rate change and a rate rider mechanism.

The ALJ rejects the idea that ETI is limited to recovering CGSC costs. The language of PURA § 39.452(b) imposes no such restrictions, and clearly states ETI is entitled "to recover any costs unrecovered as a result of the implementation of the tariff."

Staff and ETl also disagree with Cities' interpretation ofPURA 39.452(b) stating that the CGS tariffs "may not be considered to offer a discounted rates or rates under Section 36.007." Cities argue that the reference to PURA § 36.007 means that ETl must recover its cost of providing service to CGS customers since to recover less than its cost would mean that it would

124 Tr. at 251. 125 Cities Initial Brief at 13.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 39 PUC DOCKET NO. 37744

be offering a discounted rate. 126 The Cities argue further that because PURA § 36.007 requires ETI to recover its costs, it cannot reallocate those costs to other customers of the utility. Cities do not explain why a statutory requirement that ETI recover its costs means that it is prohibited from recovering those costs from other ratepayers.

Staff argues that Section 39.452(b)'s reference to Section 36.007 means the prohibition against recovering costs associated with a discounted rate from other ratepayers does not apply to the CGS tariff and that therefore ETI can recover its unrecovered costs from other ratepayers so . . approves such a recovery. 127 1ong as th e CommlSSlon

Finally, Staff notes that Cities' argument that PURA § 39.452(b) only allows ETl to recover its unrecovered costs through base rates, raises another issue. Both riders include an annual true-up mechanism, which Staff is concerned may be retroactive ratemaking not 128 authorized by PURA. The Commission is currently considering a proposed rule under which utilities may reconcile their distribution costs of service. 129 As a result, Staff requests that the Commission consider resolving the retroactive ratemaking issue consistently in this docket and that rulemaking.

D. The Unserved Energy Rate

ETI proposes that in instances where the QF is either unable or chooses not to put energy to ETI, the CGS customer will take energy from ETI at the Unserved Energy rate. The proposed Unserved Energy rate is based on a fixed heat rate and objective market gas prices. ETl argues that this approach gives the CGS customer certainty as to pricing so it can either contract for such risk with the QF or hedge that risk. ETl also asserts that the rate involves a sufficiently

126 Cities Initial Brief at 15-16. 127 Staff's Initial Brief at 4.

128 See Project No. 38298, Initial Comments of the Steering Committee of Cities Served by Dncor (July 26,2010), at 16.

129 Rulemaking Related to Recovery by Electric Utilities ofDistribution Costs, Project No. 38298, Proposal for Publication of New § 25.43 as Approved at the June 11,2010 Open Meeting (June 14,2010) at Section (d).

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 40 PUC DOCKET NO. 37744

high heat rate to incent against using Unserved Energy as a primary supply option, or to dissuade the QF from sales other than to the CGS customer when it is more profitable to do SO.130

TIEC argues that the Company's Unserved Energy rate should be replaced by Standby and Maintenance Service (SMS), currently available under ETI's SMS tariff. TIEC contends that SMS and CGS customers are indistinguishable. l3l ETI first responds that this claim is based on the false assumption that the Company is being supplied firm energy and capacity directly from the QF. As explained above, CGS QF put cannot be considered firm energy. ETI also argues that TIEC's proposal fails to recognize substantive differences between SMS and the role of the Unserved Energy rate. The Unserved Energy rate is not designed to function as back-up power as with customers that contract with ETI under SMS. Customers under the SMS tariff own their own generation, contract for SMS capacity, and in turn may rely on that capacity and purchase energy when their own generation becomes unavailable. 132 SMS customers may not resell any power taken under the SMS tariff. Furthermore, unlike the SMS tariff, there is no requirement that CGS customers own their own generation, and many will not. 133 Consequently, many potential CGS customers would not be eligible to participate in the CGS tariff if the SMS tariff were read into the CGS requirements. CGS and SMS customers are not indistinguishable.

Next, ETI argues that the energy rate charged to CGS customers and under the SMS tariff is based on the avoided costs determined after the fact for SMS. 134 ETI explains that, if the SMS rate were the recourse rate under CGS, the CGS customer would have no certainty before the fact of its risk exposure for a failure of the QF to put energy to ETI. This would complicate the CGS customers' ability to mitigate that risk. That said, there is little risk to address because the energy rates are effectively the same for CGS service and SMS. TIEC's proposal seriously undermines its assertions that CGS customers and QFs could effectively firm up QF put energy

130 ETI Ex. 52 at 45-46. 131 TIEC Ex. 1 at 44. 132 Tr. at 124; ETI Ex. 73 at 17. 133 ETI Ex. 73 at 17-18. 134 The SMS tariff provides for an avoided cost rate plus an adder.

SOAR DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 41 PUC DOCKET NO. 37744

with contracts that assure delivery and energy. There is little incentive for a CGS customer to pay a premium for delivery assurance if the customer will pay approximately the same energy rate for CGS supply as it would pay for the energy that the Company provides when that customer's QF supply option is unavailable. The CGS customer would be relatively indifferent to the source of energy supply. TIEC's proposal for replacing Unserved Energy with the SMS rate is flawed as it does nothing more than offer the CGS customer neutral pricing options in lieu of alternative supply options.

TIEC and OPUC expressed the concern that the Unserved Energy rate will allow the Company to realize additional profit. 135 ETI responds that any revenues obtained through application of the Company's Unserved Energy component will be returned to all customers through the Company's fixed fuel factor (including LIPS customers as to the portion of load not designated for CGS service) as a credit to the fuel balance. 136

Finally, ETI argues that under TlEC's proposal, QF put would be deemed avoided capacity for MSS-I purposes, purchased by ETI at its avoided capacity costs, and then purchased from ETI by CGS customers at avoided energy costs. In other words, the QF put would be recognized as avoided capacity when doing so would result in MSS-l savings, but then priced as avoided energy when it comes time for CGS customers to purchase such put from ETI. The ALJ agrees that TIEC's proposal on Unserved Energy should be rejected.

VI. CONCLUSION

PURA § 39.452(b) authorizes the Commission to accept, reject, or modify the Company's proposed CGS tariff. The ALJ finds that ETl's proposal represents a good faith effort to develop a CGS program that does not violate the System Agreement and yet complies with PURA § 39.452(b). The ALJ recommends the Commission reject the proposal, however, because it shifts a significant cost burden to ratepayers who either cannot or elect not to participate. The Legislature made clear in PURA § 39.452(b) that the Company will not be

135 TlEC Ex. 1 at 45; OPUC Ex. 1 at 87. 136 ETI Ex. 73 at 19; Tr. at 199.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 42 PUC DOCKET NO. 37744

responsible for any unrecovered costS.1 3? Furthermore, the costs cannot be accurately quantified until the program has been implemented and the number of participants known - thus necessitating two cost-recovery riders and an annual true-up. ETl recognizes the policy implications of such cost-shifting and made this appeal to the Commission:

ETI realizes that the cost shifting associated with the CGS program raises important policy concerns. If such concerns cause the Commission to conclude that the CGS program as proposed should not be adopted, the proper course of action is to reject the program as allowed by the statute, rather than modify the program in a way that would require shareholders to fund unrecovered costs. 138

The ALJ agrees and recommends that ETl's proposed CGS program be rejected. The proposed Findings of Fact and Conclusions of Law are limited to the CGS issue as the parties have already provided the remaining proposed findings and conclusions in the Stipulation and Settlement Agreement and Proposed Final Order.

VII. PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW

A. Findings of Fact on ETl's CGS Proposal

1. As part of its application, ETl proposed a Competitive Generation Service (CGS)

pursuant to Public Utility Regulatory Act, TEX. UTIL. CODE ANN. (PURA) § 39.452(b).

2. On July 16, 2010 and July 20, 2010, a SOAR Administrative Law Judge held a hearing on the merits on ETl's CGS Proposal.

3. ETl's proposed CGS tariff provides eligible customers with the opportunity to have ETI purchase competitive generation selected by the CGS customer and provide the selected generation at retail to the CGS customer.

4. The eligible customers are Large Industrial Power Service (LIPS) customers under the proposal.

5. Under the proposed tariff, a CGS customer would have the ability to contract with a participating CGS supplier, an eligible Qualifying Facility (QF), that puts energy to ETl for a set amount of load at an agreed upon price.

137 PURA § 39.452(b).

138 ETl Initial Brief at 9.

SOAR DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 43 PUC DOCKET NO. 37744

6. The CGS customer must designate what portion of its load will be served by its CGS supplier under the CGS tariff and what portion will be served under the applicable LIPS tariff rate.

7. So long as the CGS supplier provides the energy contracted for by the CGS buyer, BTl will continue to purchase energy from the QF at the avoided cost rate and the CGS customer will pay BTl the avoided cost rate for the level contracted for in place of all generation relate~ components that would otherwise be billed under the LIPS tariff.

8. A CGS customer and a QF supplier are free to contract, without ETl's participation, for a price other than avoided costs, in which case, the costs above or below the avoided costs would be accounted for in payments between the CGS customer and CGS supplier, as prescribed by the contract.

9. The proposed tariff would consist of a schedule describing the provisions of the program (Schedule CGS) along with two cost recovery riders associated with the proposed program: the Competitive Generation Service Cost rider (Rider CGSC) and the Competitive Generation Service Unrecovered Service Cost rider (Rider CGSUSC).

10. Rider CGSC is designed to recover costs related to implementation and operating costs incurred to support the CGS program. These costs would be recovered from all CGS eligible customers (LIPS) customers through Rider CGSC regardless of whether they actually take the CGS service.

11. Rider CGSC would recover ETl's initial and ongoing program costs from ratepayers who would not cause those costs to be incurred.

12. Rider CGSC would recover costs from ratepayers who do not participate in the CGS program.

13. The amount of implementation and operating costs incurred to support the CGS program to be recovered through Rider CGSC cannot be ascertained until after the program is implemented and CGS customers participate.

14. Rider CGSUSC is designed to recover the difference between what would have been billed by BTl under traditional LIPS service and what is billed under the combined CGS tariff and modified LIPS service.

15. The amount of unrecovered embedded generation costs and any other related base rate costs to be recovered under Rider CGSUSC cannot be ascertained until after the program is implemented and CGS customers participate in the program.

16. Rider CGSUSC would recover embedded generation costs and any other related base. rate costs and would apply to all non-participating customers across all classes, including LIPS customers not participating in the CGS program.

SOAR DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 44 PUC DOCKET NO. 37744

17. Rider CGSUSC would recover ETl's unrecovered embedded generation costs from ratepayers who would not cause those costs to be incurred.

18. Rider CGSUSC would recover costs from ratepayers who do not participate in the CGS program.

19. Rider CGSC and Rider CGSUSC may harm the competitiveness of manufacturers that choose not to take advantage of competitive generation.

20. The power put to ETl would have no effect on ETl's generation resource planning because the energy put to ETl by a QF is a non-firm resource.

21. There has not been a quantification of the alleged benefits to non-CGS customers that would result from potential capacity savings, reduced average fuel costs, and additional revenues from the Unserved Energy Rate.

22. Rider CGSUSC is deficient because it does not account for potential load growth. Load growth should be accounted for because load growth could mitigate ETl's unrecovered generation related costs.

B. Conclusions of Law on ETl's CGS Proposal

1. PURA § 39.452(b) permits ETl to charge its unrecovered initial and ongoing program costs and generation related costs to customers who do not participate in the CGS program.

2. ETl cannot be required to absorb its unrecovered costs under PURA § 39.452(b).

3. PURA § 39.452(b) does not prohibit ETl from charging CGS participants its unrecovered costs.

4. PURA § 39.452(b) requires that the Commission "approve, reject, or modify" the CGS tariff proposed by BTL

5. PURA § 39.452(b) permits ETl to account for load growth in the design of the CGS tariff.

6. ETl has not met its burden of proof to establish a rate regarding the unrecovered cost of implementing the CGS program.

7. The term "eligible customer" in PURA § 39.452(b) does not mandate that the CGS program be only available to LIPS class customers.

8. P.U.C. SUBST. R. 25.239 accounts for load growth.

SOAR DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 45 PUC DOCKET NO. 37744

9. Neither a CGS customer nor a contract between a CGS customer and a QF is subject to P.D.C. SUB ST. R. 25.242(c)(5).

10. ETl's CGS proposal is rejected.

SIGNED October 4, 2010.

_.~

~RY----ADMINISTRATIVE LAW JUDGE STATE OFFICE OF ADMINISTRATIVE HEARINGS

ATTACHMENT A

Financi~ Contract specifyine a level putto ETI Hourly Avoided Allocation of Cost Sche dule Texas QF put LQF (non-firm)

CGS Tariff I

I

(firm) I (enerev at I I \ avoided co I \ pricine) I I \ I \

.. ~ I ...

\ ~

------> Unserved energy rate if OF does not put to System (any revenues go to non-CGS customers as credit to fuel expense) Startup and ongoing costs (CGSC rider)

----> Unrecovered embedded generation costs (CGSUSC rider)

.e_ SOAH Docket No. XXX-XX-XXXX PUC Docket No. 37744 ETI Exhibit No. 9

DOCKET N O . - - - -

APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS §

DIRECT TESTIMONY

OF

( PHILLIP R. MAY

ON BEHALF OF

ENTERGY TEXAS, INC.

DECEMBER 2009

2009 ETI Rate Case 3-249

Exhibit PRM-1 ( 2009 TX Rate Case Page 1of7

SECTION Ill RATE SCHEDULES Page 42.1

ENTERGY TEXAS, INC. Sheet No.: 107 Electric Service Effective Date: Proposed Revision: 0 Supersedes: New Schedule RIDER SCHEDULE CGS Schedule Consists of: One Sheet

COMPETITIVE GENERATION SERVICE

I. AVAILABILITY

Pursuant to PURA Section 39.452(b), this competitive generation tariff allows eligible Entergy Texas, Inc. ("ETI" or "Company") customers the ability to contract for competitive generation. This Rider will be available to Rate Schedules Large Industrial Power Service ("LIPS") and Large Industrial Power Service - Time of Day ("LIPS-TOD") firm customer load.

II. APPLICABILITY

Customers receiving service under Rate Schedules LIPS and LIPS-TOD may contract with N Qualifying Facilities ("QF(sn that are able to put energy to ETI for the provision of energy to serve all or part of the Customer's generation requirements. Such customers will pay only CGS charges on Schedule LIPS or Schedule LIPS-TOD (Net Monthly Bill, Column B)

( plus applicable adjustments for the load served on CGS. Eligible Customers who elect to serve a portion of their load with CGS are CGS Customers.

Ill. REQUIREMENTS

A. Any Customer applying for CGS must receive service under one of the Rate Schedules listed in § II above. Only the service provided under such Schedules is eligible for CGS. B. A LIPS customer participating in the CGS program as a QF at one account location may not also participate as a CGS customer at that same account location. C. CGS Customers must inform the Company at the time of sign-up of their MW block commitment for CGS for the initial term. CGS Customers may change that commitment with their next term of service. D. Any Customer accepted for CGS service must be billed on a calendar month basis. E. CGS service may only begin after technical and contractual requirements are met (amended contract with the utility and back up metering/telemetry in place). F. Standby and Maintenance Service ("SMS") is not available to CGS Customers.

IV. INITIAL TERM

The initial term will begin January 1, 2011 and be effective for one year. CGS Customers must notify ETI in writing a minimum of 60 days before beginning CGS and must have all contractual and technical requirements completed prior to taking CGS. CGS Customers may start service anytime after January 1, 2011 but must commit to a full one year period from their beginning date. CGS may then be renewed on an annual basis with the minimum 60 day notification period. After the initial term, ETI will provide a report to the Public Utility Commission of Texas identifying the successes as well as issues raised by

(Continued on reverse side)

2009 ETI Rate Case 3-333

Exhibit PRM-1 2009 TX Rate Case Page 2 of7

Page42.2 CGS. The report will also identify any changes that should be considered as a result of the first year of implementation and may result in changes to this Rider. CGS Customers assume the risk that changes to this Rider may affect the economics of any contract between a CGS Customer and a QF.

V. RETURN TO BUNDLED SERVICE

CGS Customers may choose to withdraw from their one year commitment to CGS at anytime during that year but must give a 60 day written notice prior to returning to bundled service. A CGS Customer choosing to withdraw may not return to CGS for at least 12 months from the time the withdrawal is effective.

N

VI. NET MONTHLY BILL

CGS customers will be billed for CGS pursuant to § II. In addition to these charges CGS Customers will also be billed the Company's Hourly Avoided Cost calculated pursuant to Attachment A of Rate Schedule LQF paid to the QF(s) to provide the CGS Customer's energy. Should any hourly deficiencies occur between the Customer's committed CGS load and the QF generation delivery within that hour, CGS Customers will be billed for "Unserved CGS Energy'' and be charged using the formula below:

Gas price based on a 13,000 Btu/kWh heat rate (on-peak) and 10,000 Btu/kWh heat rate (off-peak) applied to a gas price pursuant to the Houston Ship Channel Gas Daily Average (HSCGDA) plus a delivery adder based on Entergy's historical average cost per MMBtu of gas delivered to ETl's Lewis Creek and Sabine plants for the preceding 24 months ending October 31. The delivery adder will be updated annually. On-peak and off-peak are as defined by Platt's Megwatt Daily.

IX. METERING

Interval data recording (IDR) meters and telemetry are required for billing CGS accounts. Back up meters, the incremental cost of which will be paid by the Customer, are also required. The CGS Customer will be responsible for the cost of telephone service and maintaining any required telephone equipment for the IDR. Alternatively, and at ETl's discretion, such telemetry communications service required for billing may be provided to the CGS Customer in accordance with ETI Rider Schedule RCL (Remote Communications Link Rider). Meter errors will be resolved in accordance with the PUCT Substantive Rules.

RIDER SCHEDULE CGS

2009 ETI Rate Case 3-334

Exhibit PRM-1 ( 2009 TX Rate Case Page 3of 7

SECTION Ill RATE SCHEDULES Page 43.1

ENTERGY TEXAS, INC. Sheet No.: 108 Electric Service Effective Date: Proposed Revision: 0 Supersedes: New Schedule RIDER SCHEDULE CGSC Schedule Consists of: One Sheet Plus Attachment A

COMPETITIVE GENERATION SERVICE COST RIDER

I. APPLICATION

This Competitive Generation Service Cost Rider (•Rider CGSC" or the •Rider") is applicable under the regular terms and conditions of Entergy Texas, Inc. rcompany") to all electric service billed under the Company's Rate schedules LIPS and LIPS-TOD subject to the jurisdiction of the Public Utility Commission of Texas (·Pucr).

II. PURPOSE

The purpose of the Rate in § Ill below is to recover the costs incurred by the Company resulting from the development and ongoing operation of the Competitive Generation Service program that PURA§ 39.452(b) requires the Company to implement.

N

( Ill. RATE

All electric service accounts billed in accordance with Company's LIPS and LIPS-TOD Rate Schedules will be billed the Rider CGSC Rate per kWh shown on Attachment A for recovery of the Competitive Generation Service program costs.

IV. RECOVERY PERIOD

This Rider will be billed initially beginning with the Effective Date of the Competitive Generation Service program and will remain in effect until termination of the program. The redetermined rate described in § V. below shall become effective for bills rendered on and after the first billing cycle of the January immediately following the filing year and shall then remain in effect for a twelve (12) month billing period, unless otherwise terminated or superseded.

V. TRUE-UP PROVISION

This Rate will be adjusted annually as shown on Attachment A to reflect actual costs incurred in the development and ongoing administration of the Competitive Generation Service program. On or before October 1st of each year the Company shall file with the PUCT a revision of this rate that incorporates the current estimate of program operation costs for the next calendar year and a true-up calculation that recognizes the difference between actual expenses and recovery under this rider for the prior calendar year. Interest shall be calculated monthly on the cumulative over/under recovery balance at the rate established annually by the PUCT for overbilling and certain underbilling in the P.U.C. Suesr. R. 25.28(c) and (d). Interest shall be calculated based on the principles set out in the P.U.C. SUBST. R. 25.236(e)(1 ).

2009 ETI Rate Case 3-335

Exhibit PRM-1 2009 TX Rate Case Page 4 of7

Page43.2 ATTACHMENT A ENTERGY TEXAS, INC.

COMPETITIVE GENERATION SERVICE COST RIDER SCHEDULE CGSC

The Rider CGSC rate will be adjusted annually as follows:

LINE DESCRIPTION ADJUSTED NO AMOUNT

N

1. Estimated Program Operation Costs for Following Calendar $940,500 Year 2. Plus: Difference Between Actual Program Operation Costs and Recovery Under Rider CGSC for Prior Year (True-Up) with Cumulative Interest $0 3. Sum of Estimated Program Costs and True-Up (L1 + L2) $940,500 4. LIPS class kWh for Prior Year 4,885,025,000

5. Rider Schedule CGSC Rate for Following Calendar Year (L3 $0.000193 I L4)

2009 ETI Rate Case 3-336

Exhibit PRM-1 ( 2009 TX Rate Case Page 5of 7

SECTION Ill RATE SCHEDULES Page44.1

ENTERGY TEXAS, INC. Sheet No.: 109 Electric Service Effective Date: Proposed Revision: O Supersedes: New Schedule RIDER SCHEDULE CGSUSC Schedule Consis~ of: One Sheet Plus Attachment A

COMPETITIVE GENERATION SERVICE UN RECOVERED SERVICE COST RIDER

I. PURPOSE

This Competitive Generation Service Unrecovered Service Cost Rider rRider CGSUSC" or "Rider") defines the procedure by which Entergy Texas, Inc. ("Company") shall implement and adjust rates for recovery of lost base rate revenue resulting from customers participating in the Company's Competitive Generation Service ("CGS Program"). The purpose of this Rider is to provide a mechanism for recovery of such lost base rate revenues that were included in the Company's last general rate case proceeding before the Public Utility Commission of Texas ("PUCr).

N

II. APPLICABILITY

This Rider is applicable under the regular terms and conditions of the Company to all electric service billed under the Company's rate schedules subject to the jurisdiction of the PUCT, with the exception of service billed under the CGS Program provisions of Rate Schedules LIPS and UPS-TOD.

Ill. RATE PROCEDURE

The rates shown on Attachment A to this Rider shall be updated annually on or before October 1st to reflect the estimated lost base rate revenue for (1) customers and load participating in the Company's CGS Program in the upcoming calendar year and (2) a true-up calculation for the twelve (12) billing months ending with December 31st of the prior year. The estimate of the tost base rate revenue for the upcoming calendar year will be based on the usage history for the known participants at the time of filing. The Company will calculate the base rate charges that would apply under the standard rates for the annual usage of customers participating in the CGS Program. This standard rate amount will be compared to the rate revenue calculated under the applicable CGS Program rates actually in effect for the Program participants. The difference between these two amounts is the CGS Program's annual estimated lost base rate revenue.

The true-up calculation is the difference between the calculated standard (non-CGS Program) rate charges for actual usage in the CGS Program and the actual CGS Program rate revenue for all participants in the twelve {12) billing months ending with December 31stof the prior year, plus interest calculated monthly on accrued true-up balances using the rate established annually by the PUCT for overbilling and certain underbilling in the P.U.C. Suesr. R. 25.28(c) and (d). Interest shall be calculated based on the principles set out in the P.U.C. Suesr. R. 25.236(e){1 ). The sum of the upcoming year estimate and the true-up calculation is the amount allocated to the rate classes using the Production Demand Allocation Factors from the most recent base-rate case adjusted to remove CGS Program load and energy. The resulting rate class allocations of lost base rate revenue will be used to calculate rate class charges using the

(Continued on reverse side)

2009 ETI Rate Case 3-337

Exhibit PRM-1 2009 TX Rate Case Page 6 of7

Page44.2 Company's best estimate of Mure billing determinants as adjusted to remove expected CGS Program load and energy.

The initial Rider CGSUSC Rate Adjustments shall become effective with the first (1st) billing cycle of the month following the date of the PUCT order approving this Rider CGSUSC if such order is received by the fifth (5th) day of the month, otherwise, the initial Rider CGSUSC Rate Adjustments shall become effective with the first (1st) billing cycle of the second (2nd) subsequent month after the date of the PUCT order approving this Rider CGSUSC and shall remain in effect until superseded. The redetermined rate as described earlier in this§ V shall be effective for bills rendered on and after the first (1st) billing cycle of July of the filing year and shall then remain in effect for a twelve (12) month billing period, unless otherwise terminated or superseded.

N

IV. INTERIM ADJUSTMENT

Should a change in the level of estimated Unrecovered Service Cost exceed $2 million, greater or less than, the estimate included in the most recently filed determination under this CGSUSC Rider, then either the PUCT staff or the Company may propose an interim revision to the then currently effective CGSUSC rate.

V. TERM

This Rider shall be billed beginning with the Effective Date of the Competitive Generation Service program and shall remain in effect until termination of the program.

RIDER SCHEDULE CGSUSC

2009 ETI Rate Case 3-338

Exhibit PRM-1 ( 2009 TX Rate Case Page 7 of7

Page44.3 ATIACHMENTA ENTERGY TEXAS, INC.

COMPETITIVE GENERATION SERVICE UNRECOVERED SERVICE COST RIDER SCHEDULE CGSUSC

Net Monthly Rate

The following Rate Adjustments will be added to the rates set out in the Net Monthly Bill for electric service billed under applicable retail rate and rider schedules* on file with the Public Utility Commission of Texas. The Rate Adjustments shall be effective for bills rendered on and after the first billing cycle of the January immediately following the filing year.

*Excluded Schedules: CGS Program applications of, LIPS and LIPS-TOD, and EAPS, LQF, N SMS, and SQF.

Rate Class Rate Schedule Rate Adjustment

Residential RS, RS-TOD x.xxxxx $/kWh Small General Service SGS, UMS, TSS x.xxxxx $/kWh General Service GS, GS-TOD, x.xxxxx $/kWh Large General Service LGS, LGS-TOD x.xxxxx $/kWh Large Industrial Power Service LIPS, LIPS-TOD x.xxxxx $/kW ( Lighting SHL,LS-E,ALS,RLU x.xxxxx $/kWh

2009 ETI Rate Case 3-339

This page has been intentionally.left blank.

2009 ETI Rate Case 3-340

SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 37744

APPLICATION OF ENTERGY, ) STATE OFFICE OF TEXAS, INC. FOR AUTHORITY ) TO CHANGE RATES AND TO ) RECONCILE FUEL COSTS )ADMINISTRATIVE HEARINGS

HEARING ON THE MERITS

FRIDAY, JULY 16, 2010

BE IT REMEMBERED THAT at 10:09 a.m., on Friday, the 16th day of July 2010, the above-entitled matter came on for hearing at the State Office of Administrative Hearings, William P. Clements, Jr., Building, 300 West 15th Street, Room 404, Austin, Texas, before TRAVIS VICKERY, Administrative Law

Judge, and the following proceedings were reported by Lou Ray and Lorrie Schnoor, Certified Shorthand Reporters of:

Volume 3 Pages 15 - 216

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1 also includes not just your testimony but also your

2 exhibits to your direct testimony? 3 A Yes. 4 Q And for Exhibit 76, it includes not just your 5 rebuttal testimony but also workpapers to your 6 rebuttal testimony. Is that correct? 7 A Yes.

8 Q I noticed that in your direct testimony, 9 there's some errata included within your Exhibit 9.

10 A Correct.

11 Q Do you recognize that? 12 A Yes.

13 Q If do you have any other changes or 14 corrections to any of these three exhibits? 15 A I do not.

16 Q And if I were to ask you the same questions 17 today on the stand that are included within the 18 written testimony, would your answers be the same?

19 A They would be the same with the one caveat 20 that the $75 million associated with the LIPS rate 21 will likely change if there ultimately is a 22 settlement. 23 Q Thank you. 24 MS. KELLEY: If what? I didn't hear 25 that.

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1 WITNESS MAY: I'm sorry? 2 MS. KELLEY: I didn't hear the last part 3 of your testimony. 4 WITNESS MAY: We had identified 5 $75 million of potential unrecovered costs for the 6 entire LIPS class. That amount would be affected with 7 the potential settlement. 8 MR. NEINAST: At this time, Your Honor, 9 the company would offer into evidence ETI Exhibits 10 No. 9, 76, and 76A. 11 JUDGE VICKERY: Any objections? 12 (No response) 13 JUDGE VICKERY: ETI Exhibit 9, 76, and 14 76A are admitted. 15 (Exhibit ETI Nos. 9, 76 and 76A admitted) 16 MR. NEINAST: And at this time, Your 17 Honor, the Company would tender Mr. May for 18 cross-examination. 19 JUDGE VICKERY: Let's go off the record 20 for just one second. 21 (Discussion off the record) 22 JUDGE VICKERY: Let's go back on the 23 record. 24 Mr. Mack? 25 MR. MACK: Thank you.

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1 CROSS-EXAMINATION

2 BY MR. MACK:

3 Q How are you doing, Mr. May?

4 A Doing good.

5 Q Good. Could you tell me what an interval

6 data recording meter is?

7 A It's a meter that records the actual usage by

8 a customer and frequent intervals, perhaps as frequent

9 as you want, 15-minute intervals, that sort of thing,

10 so it provides for an average month. Instead of just

11 cumulative consumption, it would provide that actual

12 consumption on a 15-minute basis.

13 Q And you claim that those would be necessary

14 for a CGS customer. Is that right?

15 A Correct.

16 Q And why is that?

17 A So that you can match up what the actual QF

18 Put is to what the consumption is at that CGS

19 customer. And so that -- make sure that the unserved

20 energy that Mr. Hurstell was talking about, that would

21 provide whether or not there was a need to provide the

22 gap, if you will, with unserved energy.

23 Q Okay. And is that kilowatts, or kilowatt

24 hours?

25 A It would be kilowatts per hour. Probably

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1 match it up on an hourly basis.

2 Q Okay. And if there were a customer that had

3 a permanent and steady load, would they still need one

4 of these meters?

5 A Absolutely.

6 Q And why is that?

7 A Because I don't think there is a permanent

8 steady load. That load would fluctuate, and we would

9 need to make sure we know exactly what that load is

10 and can match it up on an hour-by-hour basis with that

11 QF Put.

12 Q Okay.

13 MR. MACK: And I pass the witness.

14 JUDGE VICKERY: The State?

15 CROSS-EXAMINATION

16 BY MS. KELLEY:

17 Q Yes, I have a few questions, Mr. May.

18 A All right.

19 Q Since this legislation was being considered

20 sometime, I would imagine, before the last legislative

21 session up until today, what discussions has the

22 company had with any of its LIPS customers to gauge

23 the level of interest in the CGS program?

24 A What discussion have we had with our LIPS

25 customers?

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1 Q Right.

2 A We had a couple of discussions, and I won't

3 be able to recall all the details. There were -- I

4 believe there were at least two.

5 The one that I am thinking of

6 specifically here, where we talked about some of the

7 issues associated, that was about a year ago. It was

8 after the legislative session. We talked about some

9 of the provisions of the CGS within the law. We

10 described what we saw as some of the challenges of

11 making sure that the CGS complied with the system

12 agreement. And as a matter of fact, in that meeting,

13 one of those LIPS customers suggested using QF as a

14 means for getting around that.

15 Q As a percentage of your LIPS customers, did

16 you have you come away from any of these

17 discussions with a feel for what the level of

18 participation would be?

19 A No. And having that discussion, I think

20 there was indication of interest, but, you know, it's

21 one of those things where it's all in the details and

22 relevant marketing conditions at the time and so

23 forth. So I could not tell you how -- which customers

24 and how many and how much would be interested in

25 actually partaking in the CGS.

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1 Q Okay. Just no idea if it would be 5 percent

2 of your customers or 100 percent of your customers?

3 A Have no way of estimating it.

4 Q Okay. If you could turn to Page 15 of

5 your -- oh, 19 of your testimony --

6 A Direct?

7 Q -- sir, and you talk about the CGSC Rider and

8 what the company estimates for startup and ongoing

9 costs.

10 A Yes, ma'am.

11 Q And I notice on Lines No. 15 and 16, you talk

12 about that the precise level of ongoing cost in each

13 of these areas would be dependent upon level of

14 participation. Correct?

15 A Yes, ma'am.

16 Q But what did -- what level of participation

17 did you use to come up with the estimates for the

18 kick-off costs and the yearly cost?

19 A I think what we talked about is a level that

20 was well below the entirety of the LIPS class but at a

21 level that could be managed with sort of an

22 out-of-the-process process. We have a billing process

23 that is fairly automated. What we would plan to do

24 with this would be to do these by hand, so to speak,

25 and it was our view that we could manage a significant

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1 participation in this with these two-and-a-half 2 full-time customers on an ongoing basis. So a 3 significant portion of the customers could be managed 4 with that. 5 Q Okay. But you must have had some starting 6 estimate. I think I heard you say you were trying to 7 come up with a ballpark or there must -- it's not

8 plucked out of thin air. You grant me that, don't 9 you? 10 A I'm sorry. I didn't hear all that. 11 Q The $610,000 figure and then the 330 12 A Yes, ma'am.

13 Q -- that's not just plucked out of thin air. 14 Correct? 15 A No, ma'am. 16 Q Okay. So what -- I think I heard you say 17 that there was some assumption about the level of 18 participation there would be, and I'd ask you to kind 19 of give me a ballpark there.

20 A Yes. And let me make clear, I don't think we 21 had any assumption of what the actually participation 22 would be. What we were doing was trying to design a 23 system in which we would have the capacity to deal 24 with a significant portion of the LIPS customers 25 participating.

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1 Q And what do you consider to be a significant 2 portion to be? 3 A More than half. 4 Q Okay. I think a moment ago, you qualified 5 the figure of -- that appears on Page 14, the 6 75.2 million? 7 A Yes, ma'am.

8 Q You said that the -- a settlement would 9 impact that? 10 A Yes, ma'am. 11 Q How do you anticipate it would impact it? 12 A I can't estimate that with any certainty at 13 this time, but it would be a smaller number than 14 that 15 Q Okay.

16 A -- were the settlement to be adopted. 17 Q Okay. 18 MS. KELLEY: I don't have any further 19 questions. 20 JUDGE VICKERY: Ms. Griffiths? 21 MS. GRIFFITHS: Oh, Ms. Magruder is no 22 longer there. 23 JUDGE VICKERY: Yeah. 24 25

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1 CROSS-EXAMINATION

2 BY MS. GRIFFITHS:

3 Q Okay. Mr. May, the $75.2 million figure on

4 Page 14 of your testimony, that is based on the

5 coincident peak demand of the LIPS accounts for the

6 test year ending June 30th, 2009. Is that correct?

7 A I think it's actually billing determinants,

B is what that's based upon.

9 Q Okay. Could you take a look at your

10 testimony starting on Page 13 and then looking at that

11 next Q and A on Page 14?

12 A (Witness complying.)

13 Q And you estimate that the coincident peak

14 demand of the LIPS class is approximately

15 651 megawatts. Correct?

16 A Yes.

17 Q All right. You don't anticipate that all

18 651 megawatts would move to the CGS load, do you?

19 A I don't have a way to estimate how much

20 would.

21 Q So the answer is no? 22 A I have no way of estimating it.

23 Q And the generation portion of the LIPS

24 revenue requirement you state is 75.2 million. That

25 is the entire -- based on the entire LIPS billing

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1 determinants. Correct? 2 A Yes, ma'am. We know with certainty what the 3 actual unit cost of the difference between LIPS and 4 CGS is. We just don't know what volume to apply to 5 that. We'll know that through participation in the 6 program. 7 Q All right. So you don't know those costs 8 now, and you can't measure -- 9 A No. 10 Q them at this point? 11 A We know those costs with certainty. We don't 12 know what the volume would be applied to those costs. 13 Q Okay. If you could turn to your exhibits 14 that contain the competitive generation services 15 unrecovered service cost rider. 16 A Yes, ma'am. 17 Q And that is I'm referring you to Page 7. 18 Correct -- or I'm sorry to Page 7. And I think the 19 Bates number at the bottom is 3-339? 20 A Yes, ma'am. 21 Q All right. You're not actually proposing any 22 rate adjustment specifically in this tariff, are you? 23 A No. There's no volume that is estimated at 24 this time to apply to that tariff, so there is no 25 number in there.

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SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 37744

APPLICATION OF ENTERGY, ) STATE OFFICE OF TEXAS, INC. FOR AUTHORITY )

I • TO CHANGE RATES AND TO ) ~· 'ti RECONCILE FUEL COSTS )ADMINISTRATIVE HEARINGS

HEARING ON THE MERITS TUESDAY, JULY 20, 2010

BE IT REMEMBERED THAT at 9:16 a.m., on Tuesday, the 20th day of July 2010, the above-entitled matter came on for hearing at the State Off ice of

Administrative Hearings, William P. Clements, Jr., Building, 300 West 15th Street, Room 404, Austin,

Texas, before TRAVIS VICKERY, Administrative Law Judge, and the following proceedings were reported by Lou Ray and Leanna Lynch, Certified Shorthand Reporters of:

Volume 4 Pages 217 - 379

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1 right? 2 A Yes. 3 Q All right. And so you propose that the 4 unserved energy rate be provided in the same manner as 5 stand-by service is provided to customers who own 6 their own generation. Is that right? 7 A Right. Given that they're essentially the 8 same type of service, I didn't feel that there was a 9 need to discriminate against the CGS customer. 10 Q And that's rate schedule SMS. Correct? 11 A Yes. 12 Q That's a cost-based rate. Would you agree? 13 A It's more or less a cost-based rate, yes. 14 Q And that SMS rate includes a demand charge. 15 Right? 16 A Yes. 17 Q And just to clarify, you're agreeing that if 18 the SMS rate is utilized for unserved energy, that CGS 19 customers would indeed pay that demand charge as well? 20 A Yes, they would. 21 Q Are you familiar with fuel cost recovery in 22 Texas, sir? 23 A Yes. 24 Q Earlier I believe you heard some questions of 25 Mr. Nalepa about whether or not the avoided costs that

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1 a CGS customer might pay would be above or below the 2 average cost to customers -- 3 A Yes. 4 Q -- non-CGS customers? 5 A I heard the questions, yes. 6 Q And do you know whether the effects of 7 whether or not the avoided cost that is above or below 8 the average fuel cost charge to CGS customers will 9 flow through the fuel rate? 10 A Well, the costs that the CGS customers are

11 charged might not be reflected in the fuel rate, but 12 to the extent that the CGS customer is taking 24/7

13 power off of the system -- and that's basically taking 14 it away from Entergy Texas generation purchased power 15 supply -- that will have an effect on the cost flowed 16 through the Texas fuel factor.

17 Q Right . Let's talk a little bit about cost 18 recovery. Do you agree that ETI will in fact incur 19 costs to set up and administer the CGS program?

20 A Yes. 21 Q And do you agree that if a LIPS customer 22 decides to switch to CGS service that ETI will not 23 collect the fixed production cost included in the LIPS 24 rate from that customer?

25 A I think the fact that the customer has

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1 switched and the Company is not collecting the same 2 revenue certainly creates the potential that some 3 costs would be uncollected 4 Q All right. 5 A -- unrecovered. 6 Q And that cost will go unrecovered unless 7 there is some additional revenues to -- 8 A Exactly, unless there are some additional 9 benefits to offset those unrecovered costs . That's 10 correct. 11 Q I think earlier in your testimony in this 12 section you quote the statute, 39.452(b) at Page 36. 13 Let me know when you're there. 14 MS. GRIFFITHS: What page are you on? 15 MR. BREEDVELD: Page 36. 16 MS. FERRIS: Is that of his direct? 17 MR. BREEDVELD: Yes, I'm sorry, direct 18 testimony. 19 Q (BY MR. BREEDVELD) Okay. About a third of 20 the way down, sir, do you see where the statute says 21 that the utility's rates shall be set in this 22 proceeding in which the tariff is adopted to recover 23 any costs that are unrecovered as a result of the 24 implementation tariff? 25 A Yes, it states that.

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1 A Based on the adjusted test-year, yes. 2 Q And the rate-setting process that we are 3 describing does not concern itself about what may 4 occur after rates are set. Right? At least at that 5 time? 6 A That's correct. The assumption is that~

7 reasonable revenue level has been set prospectively a and that the conditions may change up or down, and it

9 may be different in the future.

10 Q And you agree that when you set rates, the 11 company should have the opportunity to recover the 12 revenue requirement that those rates are based on. 13 Right? 14 A The cost of service rates are set at a level 15 that the commission has determined will produce a 16 reasonable opportunity to recover cost. Whether or 17 not it does or does not is within the range of 18 conditions that may exist in the future and, of 19 course, the company can always file another case if,

20 in fact, revenues no longer cover cost. 21 Q I think we are not disagreeing. I think I 22 said you would agree that the company should have the 23 opportunity to recover the revenue requirement or the 24 cost that rates are based on. Right? 25 A What I said is the commission determined when

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1 it set the rates in the rate case, that would provide 2 a reasonable opportunity to recover cost of service.

3 Q And the CGS program should not impede that 4 opportunity to recover those costs as established in

5 that adjusted test-year. Correct? 6 A I would say in an ideal world, yes, that's 7 correct. 8 Q And the costs that may go unrecovered due to 9 the CGS program, they are reflected as part of the

10 overall embedded costs in the test-year -- right -- 11 that the rates are set on? 12 A There were costs allocated to the CGS 13 customers and to their class. So in that sense, yes. 14 After the rates are set, there really is no attempt to 15 track particular components to particular -- 16 particular cost components to particular customers. 17 Q But those costs are not incremental costs by 18 any means. Right? Costs that are -- for example, the 19 LIPS embedded cost of service in the test-year has 20 nothing to do with incremental cost that may be 21 incurred after the rates are set. Right? They are 22 costs that are in the test-year -- embedded historical 23 costs. Right? 24 A Embedded costs for allocated LIPS, they were 25 part of the overall cost of service that the

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1 commission approves in the rate case. 2 Q If you set aside the CGS program for a 3 minute, once rates are set, typically revenues can 4 change, the cost can change as well. Correct? s A That's correct. 6 Q And if you set aside the CGS program for a 7 minute, if the company had increased revenues, those 8 increased revenues could be applied to off set or 9 recover increased cost. They are not reflected in the 10 test-year. Right? 11 A Yes, that's possible. I mean -- 12 Q That's typically how a rate setting has 13 worked -- base rate setting has worked at the 14 commission . Right?

15 A Well, the revenues are not normally dedicated 16 to particular uses, but certainly as costs increase, 17 the company will use the revenues to cover changes and 18 conditions that occur after the test-year.

19 Q So you are asking that the revenues -- the 20 sales growth revenues, any of the company realizes, be 21 dedicated to off set embedded costs that are in the 22 historical test-year -- right -- that may be foregone 23 because of the CGS program? 24 A Yes, that's correct. 25 Q And to the extent you do that -- to the

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1 extent there is revenue growth, it won't be available 2 to cover other cost increases that may occur after the 3 rates are set. Correct? 4 A That's possible. It could -- as I said, it 5 could affect the extent to which the company may 6 accelerate its need for a rate case in the future. 7 MR. WILLIAMS: Your Honor, I'll pass the 8 witness. 9 JUDGE VICKERY: Ms. Ferris? 10 MS. FERRIS: It's my witness, Your 11 Honor. 12 JUDGE VICKERY: I'm sorry? 13 MS. FERRIS: Has everyone had an 14 opportunity to cross? 15 JUDGE VICKERY: Yes. 16 MS. FERRIS: One minute, Your Honor. No 17 questions, Your Honor. 18 JUDGE VICKERY: Thank you, Mr . Johnson. 19 Mr. Foley. 20 MR. FOLEY: Staff calls Stephen Mendoza. 21 (Exhibit Staff Exhibit No. 3 marked) 22 JUDGE VICKERY: Mr. Mendoza, raise your 23 right hand, please. 24 (Witness sworn) 25 JUDGE VICKERY: Mr. Foley, whenever you

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1 are ready. 2 PRESENTATION ON BEHALF OF PUBLIC UTILITY COMMISSION 3 STEPHEN J. MENDOZA, 4 having been first duly sworn, testified as follows: 5 DIRECT EXAMINATION 6 BY MR. FOLEY: 7 Q Mr. Mendoza, you should have what's been 8 marked as Staff's Exhibit No. 3 in front of you. 9 A Yes, I do. 10 Q Could you identify that exhibit. 11 A It's my direct testimony in this docket. 12 Q Was this testimony prepared under your direct 13 supervision and control? 14 A Yes, it was. 15 Q If I were to ask you the same questions 16 today, would your answers be the same? 17 A Yes, they would. 18 MR. FOLEY: Staff offers Mr. Mendoza for 19 cross-examination. 20 JUDGE VICKERY: Thank you, Mr. Foley. 21 Cities? No questions? 22 Ms. Kelley? 23 MS. KELLEY: No questions. 24 JUDGE VICKERY: Kroger? 25 MR. BOEHM: No questions.

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1 JUDGE VICKERY: Mr. Griffiths? 2 MS. GRIFFITHS: No questions. 3 JUDGE VICKERY: Ms. Ferris? 4 MS. FERRIS: No questions, Your Honor.

5 JUDGE VICKERY: ET!? 6 MR. WILLIAMS: Thank you, Your Honor. 7 CROSS-EXAMINATION 8 BY MR. WILLIAMS:

9 Q Hi Mr. Mendoza. 10 A Hi. 11 Q Under the CGS program, as you understand it, 12 Mr. Mendoza, the company buys from QFs that avoided 13 cost. Right? 14 A Yes, sir, that's correct. 15 Q So long as QF put is made available, the 16 company collects no more from CGS customers in that 17 same avoided cost. Right?

18 A Yes, sir, that's correct.

19 Q So there is nothing in it for the company 20 regarding the purchase of avoided cost -- right -- in 21 terms of prof it or margin? 22 A It's a simple pass-through as I understand 23 it. 24 THE REPORTER: Can you speak up, please. 25 WITNESS MENDOZA: Yes.

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1 THE REPORTER: I didn't get your last 2 answer.

3 A It's a simple pass-through. 4 Q (BY MR. WILLIAMS) And you also understand, s do you not, that if the QF put is not available, if 6 the company has to provide what's called unserved 7 energy, then under that tariff, the customers get any 8 margins from those sales -- float through them through 9 the fuel clause . Do you understand that as well? 10 A Yes, sir. 11 Q So again, there is no opportunity for the 12 company to make a prof it or a windfall off that aspect 13 of the program either . Right? 14 A Not the way I understand it, no. 15 Q Is part of your recommendation that the 16 commission consider getting -- taking base rate 17 revenues associated with load growth to recoup 18 unrecovered cost associated with the CGS program. Is 19 that right?

20 A Yes, sir, that's correct. 21 Q More generally, is it Staff's position that 22 the proposed CGS program should be rejected because 23 it's not consistent with traditional rate-making 24 principles. Is that sort of a summary of your 25 concern?

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1 A That could be one way to look at it.

2 Q And as we talked about with Mr. Johnson, both 3 principles include that rates are supposed to be 4 designed to recover adjusted test-year cost. Right?

5 A Under a rate case?

6 Q Yes .

7 A Yes, that's correct.

8 Q And traditional rate setting does not concern 9 itself with incremental costs from revenues that occur 10 after the period addressed in the rate case. Right?

11 A For base rates?

12 Q Yes, sir. 13 A For base rates, yes.

14 Q And it would be completely improper here if 15 you would have not, for example, set rates at a level

16 below that is shown by the test-year in the hope that 17 some later incremental revenue might make up the

18 difference. That would not happen in a base rate 19 setting case at the PUC, would it?

20 A You are speaking specifically to base 21 rates

22 Q Yes, sir.

23 A - - below the revenue requirement. Is that 24 what you are saying?

25 Q Yes, sir.

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1 A Yes, that's correct. 2 Q The commission has considered proposals to 3 offset costs with load growth in other contexts, has 4 it not? 5 A By "other contexts," you mean other riders? 6 Q Are you familiar with the commission's order 7 adopting the TCRF rule? 8 A Somewhat, yes. 9 Q And that was the rule that allows the 10 company -- the utility outside ERCOT to recover 11 transmission investment and certain other costs 12 right on an annual basis? 13 A On an incremental basis, yes, that's right. 14 Q Is it right that the -- there were proposals 15 in that rulemaking to offset the company's recovery by

16 looking at general growth and base rate revenues? 17 A Yes. 18 Q And the commission rejected that proposal. 19 Right?

20 A I am going to have to take your word for 21 that. I don't know for sure. 22 MR. WILLIAMS: May I approach the 23 witness, Your Honor? 24 JUDGE VICKERY: Yes. If you could hold 25 off on any questions until Mr. Foley has had an

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PUC DOCKET NO. 38951

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMM16SSI^I INC. FOR APPROVAL OF § r, COMPETITIVE GENERATION § OF TEXAS =^-- SERVICE TARIFF (ISSUES SEVERED § r^ ..w f_^+ ^.3 FROM DOCKET NO. 37744) § ^^^•^ ^ y^ 1 '^

r c^^ rrt, _^, ^c t° rJ INTERIM ORDER

1. Introduction This interim order addresses the Commission's decision regarding three threshold issues surrounding Entergy Texas, Inc.'s ( ETI's) proposed competitive generation service (CGS). The

Commission makes its determination on these three threshold issues so the parties can move forward with the remaining issues that parties have characterized as being contingent on Commission decisions on the threshold issues: ( 1) what types of costs that will be considered unrecovered for purposes of PURA § 39.452(b); ( 2) what types of ETI customers will be eligible

for participation in the CGS program; and (3) which ETI customers will be responsible for paying the unrecovered costs.

ETI, Commission Staff, Office of Public Utility Counsel, Texas Industrial Energy Consumers, State Agencies, Kroger Co., Cities,' Wal-Mart Stores Texas, LLC and Sam's East, Inc. participated in this docket.

II. Procedural History ETI submitted its proposed CGS tariff and related riders in Docket No. 37744, its last rate case.2 In that rate case, the parties settled on all issues except for ETI's CGS proposal. After a hearing on the CGS proposal and the associated riders, the administrative law judge (ALJ)

I The cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.

zApplication of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Corrected Application (Feb. 23, 2010).

e^ l

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PUC Docket No. 38951 Interim Order Page 2 of 17

forwarded the parties' stipulation and settlement agreement and the proposal for decision to the Commission for consideration.

The Commission considered the settlement and the proposal for decision at the November 10 and December 1, 2010 open meetings. The Commission adopted the settlement for the rate case issues and severed the CGS issues into this docket, including the record in Docket No. 37744.3

At the December 1, 2010 open meeting, the Commission requested the parties to enter into negotiations and work to come to agreement on as many of the undetermined CGS program issues as possible, and then bring the issues for which an agreement could not be reached back to the Commission for consideration. Status reports were filed on January 13 and 28, February 18, March 11, and April 8, 2011. These reports indicated that parties continued to negotiate and that they were working to narrow the contested issues.

On September 8, 2011, State Agencies, Cities, OPUC, Kroger, and Wal-Mart jointly filed a motion requesting a decision on the proposal for decision in this docket. TIEC and Commission Staff filed responses to the joint motion and generally opposed the motion. At the September 29, 2011 open meeting, the Commissioners considered the motions and issued an order requiring the parties to file pleadings identifying the CGS tariff issues that have been settled on by the parties and identifying the issues for which a settlement could not be reached. The parties were also permitted to identify issues that are contingent upon the Commission's determination of the unsettled issues.

On November 1, 2011, several parties4 filed an agreed list of settled issues. However, the parties did not agree on a recommendation as to how the unsettled issues and issues that are contingent on the Commission's determination of unsettled issues should be addressed and resolved by the Commission. Therefore, TIEC also separately filed a list of unsettled issues and request for procedural schedule. TIEC also requested that the Commission receive additional evidence in order to resolve the unrecovered costs issue because ETI's proposal in Docket No. 37744 was based on ETI's proposal for an energy-only program, not an energy and

3 Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Order No. 14 Memorializing Decision Granting Motion to Sever ( Dec. 3, 2010).

' Cities, Entergy, OPUC, Commission Staff, State Agencies, and Wal-Mart/Sam's East. Kroger Company did not oppose the agreed settled issues and Cottonwood Energy has not participated in the discussions.

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PUC Docket No. 38951 Interim Order Page 3 of 17

capacity-based program. T1EC reported that during the time period when the parties were negotiating the Entergy Operating Committee had agreed that CGS power from qualifying facilities in the ETI service territory could provide firm generation. 5

At the December 8 and December 15, 2011 open meetings, the Commission decided that the parties should submit stipulated facts, the Commission would re-open the record to admit additional evidence, and then the Commission would make a decision on the unsettled issues. After that, the Commission planned to issue an interim order reflecting the decisions on the unsettled, threshold issues.

On January 20, 2012, the parties submitted agreed settlement terms and stipulated facts.

The parties reached agreement in principle on a number of discrete items within the overall framework of the CGS program and tariffs. Many of the items are simply elements of larger program issues that retain one or more as yet unsettled aspects essential to final resolution of that program issue. Items as to which agreement in principle exists are "subject to satisfactory resolution of unsettled issues. ,6

On January 26, 2012, ETI submitted supplemental direct testimony. On February 10, 2012, the intervenors submitted supplemental direct testimony and on February 25, 2012, ETI and intervenors submitted rebuttal and cross rebuttal testimony. The parties submitted statements of position and pre-hearing briefs on March 26, 2012.

On April 13, 2012, the parties submitted an unopposed stipulation on the threshold issue regarding customers responsible for paying unrecovered costs. The parties, except ETI, agreed that CGS customers would be the only ETI customers responsible for unrecovered costs of the CGS program. ETI did not join or oppose this stipulation.7 On April 18, 2012, the parties submitted a third stipulation on customer eligibility stating that LIPS customers would be the CGS-eligible customers, with certain limitations on the LIPS customers' participation and other program minimums and caps.8

5 TIEC's Response to Joint Motion for Decision on Proposal for Decision at 4 (Sep. 15, 2011). 6 CGS Stipulated Matters and Stipulated Facts (Jan. 20, 2012).

Unopposed Stipulation on Unresolved Issue No. 3 (Apr. 13, 2012). Stipulation on Unresolved Issue No. 2 (Apr. 18, 2012).

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PUC Docket No. 38951 Interim Order Page 4 of 17

The Commission held a hearing on the remaining contested threshold issue on April 19, 2012.

III. Discussion PURA9 § 39.452(b) requires ETI to propose a CGS tariff that would require ETI to purchase CGS, selected by the CGS customer, and provide the generation at retail to the customer. ETI is required to provide and price retail transmission service, including necessary ancillary services, to retail customers who choose to take advantage of the competitive generation tariff at a rate that is unbundled from the utility's cost of service. Competitive generation customers are not to be considered wholesale transmission customers. The statute required the Commission to approve, reject, or modify the proposed tariff not later than September 1, 2010. The CGS tariff may not be considered to offer a discounted rate or rates under Section 36.007, and ETI's rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a result of the implementation of the tariff. The statute requires the Commission to ensure that a competitive generation tariff not be implemented in a manner that harms the sustainability or competitiveness of manufacturers that choose not to take advantage of competitive generation. PURA § 39.452(b) also prohibits the Commission from issuing a decision relating to the competitive generation tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.

The Commission finds that the three stipulation-and-settlement agreements are reasonable and adopts them to the extent they do not conflict with other Commission determinations in this docket.

Adoption of the three stipulation-and-settlement agreements leaves one threshold issue remaining: the types of costs that will be considered ETI's unrecovered costs for purposes of PURA § 39.452(b). The Commission finds that unrecovered costs are only those costs necessary to implement and administer the CGS program and are not to be defined to include lost revenues, embedded generation costs, or any other types of costs.

' Public Utility Regulatory Act (PURA), TEX. UTIL. CODE ANN. §§ 11.001-66.017 (Vernon 2007 & Supp.

2011).

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PUC Docket No. 38951 Interim Order Page 5 of 17

A. Eligible Customers Stipulation The Commission adopts the stipulation and settlement regarding eligible customers and finds that LIPS customers are the ETI customers that will be eligible to participate in the CGS program (with further Iimitations as set forth in the parties' stipulation on this issue).10

B. Customers Responsible for Paying Unrecovered Costs Stipulation The Commission also adopts the stipulation and settlement regarding determining which customers will be responsible for paying the unrecovered costs referenced in PURA § 39.452(b). To the extent there are costs unrecovered as a result of implementation of

the CGS program tariff, those costs will be borne solely by customers taking service under the CGS tarif£ "

C. January 20, 2012 CGS Stipulated Matters and Stipulated Facts The Commission adopts the stipulated facts submitted by the parties on January 20, 2012 regarding ETI's capacity deficit and the program cap and notes that the items that are a part of the "agreed settlement terms" regarding eligible CGS suppliers, amount of CGS capacity, the CGS customer unbundled rate, the CGS energy payment, the CGS customer fixed-cost contribution, the CGS customer unserved energy rate, and the recognition of CGS supply as firm capacity are items for which there is only an agreement in principle that are subject to satisfactory resolution of unsettled issues.12

D. Unrecovered Costs The remaining threshold issue, the meaning of "costs unrecovered as a result of implementation of the CGS program tariff," as used in PURA § 39.452(b), was the subject of the April 19, 2012 hearing. In the proposal for decision, the ALJ found that ETI is entitled to collect unrecovered embedded generation costs and any other related base rate costs as a result of customer migration to the CGS program.13

'o Stipulation on Unresolved Issue No. 2 (Apr. 18, 2012).

" Unopposed Stipulation on Unresolved Issue No. 3 (Apr. 13, 2012). 'Z CGS Stipulated Matters and Stipulated Facts at 1(Jan. 20, 2012).

" Proposal for Decision at 22 (Oct. 5, 2010).

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PUC Docket No. 38951 Interim Order Page 6 of 17

ETI argued that unrecovered costs should be defined as the embedded production costs and any other related base rate costs that would have been recovered through traditional rates charged to CGS customers that will no longer be recovered due to the CGS program.14 TIEC took the position that unrecovered costs should not include ETI's hypothetical lost revenues and that the costs that could be unrecovered as a result of implementation of the tariff should include the expenditures actually incurred by ETI to implement and maintain the CGS program.ts Cities and OPUC agreed with TIEC that unrecovered costs are not the same thing as unrecovered revenues. 16 Cities also noted that it would be unreasonable to allow ETI to continue to incur costs for a customer the utility no longer plans to serve. 17

In making its determination of the definition of unrecovered costs, the Commission follows the precedent set in CenterPoint Energy Houston Electric, LLC v. Pub. Util. Comm 'n, 354 S.W.3d 899 (Tex. App-Austin, 2011 no pet.) where the Third Court of Appeals found that because the language of PURA § 39.905 did not specifically provide for recovery of "lost revenues" and that in at least two other provisions of PURA 18 the legislature expressly distinguishes "costs" from "revenues," the term "costs," as used by the legislature in PURA § 39.905, is not intended to include lost revenues.19 Like PURA § 39.905, PURA § 39.452(b) only provides for "costs unrecovered as a result of implementation of the tariff' and does not specifically provide for the utility to recover lost revenues or any other type of costs.

Based on the evidence and testimony, the Commission finds that the proper interpretation of "costs unrecovered as a result of implementation of the CGS program tariff' is costs to implement and administer the CGS program tariff. Such unrecovered costs do not include lost revenues, embedded generation costs, or any other types of costs. The Commission reverses the proposal for decision on this issue.

14 Supplemental Direct Testimony, Exhibits, and Workpapers of Phillip R. May, ETI Ex. 91 at 6. " s Supplemental Direct Testimony of Jeffry Pollock, TIEC Ex. 15 at 14-15. "' Supplemental Direct Testimony of Karl Nalepa, Cities Ex. 6C at 7 and Supplemental Cross Rebuttal Testimony of Clarence Johnson, OPUC Ex. 8 at 6.

" Supplemental Direct Testimony of Karl Nalepa, Cities Ex. 6C at 7-8. 18 PURA § 55.024(b) and PURA § 56.025(e). 19 CenterPoint Energy Houston Electric, LLC v. Pub. Util. Comm'n, 354 S.W.3d 899, 903-904 (Tex.Civ.App-Austin, 2011)

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PUC Docket No. 38951 Interim Order Page 7 of 17

The Commission issues this interim order so that the parties may work to reach an agreement on the components of the CGS program tariff that are contingent on the Commission's decision on the threshold issues.

IV. Conclusion The Commission adopts each of the three stipulation-and-settlement agreements and finds that unrecovered costs for the CGS program are those needed to implement and administer the CGS program and are not lost revenues, embedded generation costs, or any other types of costs.

V. Findings of Fact

Procedural History I. As part of its application in Docket No. 37744, Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, ETI proposed a competitive generation service (CGS) program pursuant to Public Utility Regulatory Act. Tex. Util. Code Ann. (PURA) § 39.452(b).

2. On July 16, 2010 and July 20, 2010, a State Office of Administrative Hearings administrative law judge held a hearing on the merits on ETI's CGS proposal.

3. A proposal for decision was issued on November 1, 2010. The ALJ ultimately recommended that the CGS proposal be rejected.

4. The Commission considered the proposal for decision at the November 10 and December 1, 2010 open meetings as part of Docket No. 37744. At the December 1, 2010 open meeting, the Commission adopted the settlement for the rate case issues and severed the CGS proposal into this Docket. The Commission requested that the parties enter into negotiations and work to come to agreement on as many of the undetermined issues as possible, and then bring the issues for which an agreement could not be reached back to the Commission for consideration.

5. Order No. I was issued on December 3, 2010 severing the CGS issues into this docket, including the record in Docket No. 37744.

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PUC Docket No. 38951 Interim Order Page 8 of 17

6. Sabine Cogen, LP filed a motion to intervene in this docket on December 23, 2010. ETI

tiled an objection to Sabine Cogen, LP's motion to intervene on December 30, 2010. Sabine Cogen, LP's motion to intervene was denied in Order No. 3 on January 12, 2011.

7. ETI, Commission Staff, Office of Public Utility Counsel, Texas Industrial Energy Consumers, State Agencies, Kroger Co., Cities,20 Wal-Mart Stores Texas, LLC and Sam's East, Inc., and Cottonwood Energy are parties to this proceeding.

8. On January 11, 2011, the Commission ALJ issued Order No. 2 requiring ETI to either provide an update on the status of settlement discussions or to propose a schedule, agreed to by all parties, for finalizing the outstanding issues.

9. The parties filed status reports on January 13 and 28, February 18, March 11, and April 8, 2011. These reports indicated that parties continued to negotiate and that they thought that they could narrow the issues.

10. On September 8, 2011, State Agencies, Cities, OPUC, Kroger, and Wal-Mart jointly filed a motion requesting a decision on the proposal for decision in this docket. TIEC and Commission Staff filed responses to the joint motion and generally opposed the motion. At the September 29, 2011 open meeting, the Commissioners considered the motions and issued an order requiring the parties to file pleadings identifying the CGS tariff issues that have been settled on by the parties and identifying the issues for which a settlement could not be reached. The parties were also permitted to identify issues that are contingent upon the Commission's determination of the unsettled issues.

11. On November 1, several parties filed an agreed list of settled issues. TIEC also separately filed a list of unsettled issues and request for procedural schedule. TIEC also requested that the Commission receive additional evidence in order to resolve the unrecovered costs issues because ETI's proposal in Docket No. 37744 was based on ETI's proposal for an energy-only program, not an energy and capacity-based program. The circumstances had changed primarily due to the agreement of the Entergy Operating to treat CGS power from qualifying facilities in the ETI service territory as firm

20 The cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.

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PUC Docket No. 38951 Interim Order Page 9 of 17

generation. The remainder of the parties tiled a joint agreed list of unsettled issues and issues contingent on a Commission determination of unsettled issues.

12. At the December 8 and December 15, 2011 open meetings, the Commissioners decided that the parties should submit stipulated facts, the Commission would re-open the record to admit additional evidence as requested by TIEC, and then the Commission would make a decision on the three threshold unsettled issues in an interim order.

13. On December 18, 2011, Order No. 4 was issued establishing a procedural schedule.

14. On January 20, 2012, the parties submitted agreed settlement terms and stipulated facts.

The parties reached agreement in principle on a number of discrete items within the overall framework of the CGS program and tariffs. Many of the items are simply elements of larger program issues that retain one or more as yet unsettled aspects essential to final resolution of that program issue. Items as to which agreement in principle exists are "subject to satisfactory resolution of unsettled issues."

15. On January 24, 2012, Order No. 5 was issued clarifying the number of copies of testimony that were to be filed by the parties.

16. On January 26, 2012, ETI submitted supplemental direct testimony. On February 10, 2012, the intervenors submitted supplemental direct testimony and on February 25, 2012, ETI and intervenors submitted rebuttal and cross rebuttal testimony. The parties submitted statements of position and pre-hearing briefs on March 26, 2012.

17. Order No. 6 was issued on February 1, 2012 setting April 19, 2012 as the date for the hearing.

18. On April 13, 2012, the parties filed an unopposed stipulation that to the extent there are costs unrecovered as a result of the implementation of a CGS tariff, those costs should be borne solely by customers taking service under the CGS tariff. ETI did not join but did not oppose the stipulation.

19. On April 18, 2012, the parties filed an unopposed stipulation regarding customer eligibility. LIPS customers will be eligible to participate in ETI's CGS program (with further limitations as set forth in the stipulation on this issue).

20. The Commission held the hearing on the merits on April 19, 2012.

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PUC Docket No. 38951 Interim Order Page 10 of 17

Elizible customers stipulation 21. The parties agreed that only customers eligible to take service under ETI's Large Industrial Power Service ( LIPS) are eligible customers for the CGS program.

22. The parties agreed that only LIPS firm load will be eligible to participate in the CGS program.

23. The parties agreed that LIPS customers with interruptible service (IS) or standby and maintenance service (SMS) load are not precluded from participating in the CGS program, but this participation is limited to their firm LIPS load. To the extent that customers with IS load participate in the CGS program, they must comply with the terms of the IS tariffs regarding minimum LIPS load. Only the portion of the customer's LIPS load that is in excess of the firm contract power minimum requirement under section 1 of Schedule IS is eligible for the CGS program.

24. The parties agreed that to the extent there are increased administration costs associated with billing a customer that has CGS and IS or SMS load, the CGS customer will bear the costs.

25. The parties agreed that there will be a 115 MW cap on the CGS program.

26. The parties agreed that there will be a 5 MW minimum on CGS customer load.

27. The parties agreed that there will be no aggregation of CGS customer load to meet the 5 MW minimum on CGS customer load.

28. The parties agreed that there will be a cap of 10 CGS purchase agreements.

Customers responsible for Paying unrecovered costs stipulation

29. The parties, except ETI, agreed that to the extent there are costs unrecovered as a result of the implementation of a CGS tariff, those costs should be borne solely by customers taking service under the CGS tariff, i.e., CGS customers. ETI did not oppose this stipulation.

January 20, 2012 CGS Stipulated Matters and Stipulated Facts

30. In the CGS stipulated matters and stipulated facts filed on January 20, 2012, the parties stated they had reached an agreement in principle on a number of discrete items within

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PUC Docket No. 38951 Interim Order Page 11 of 17

the overall framework of the CGS program and tariffs, which were listed in Section I. A-G of the stipulation. However, many of those items are simply elements of larger program issues that retain one or more as yet unsettled aspects essential to final resolution of that program issue. Items as to which agreement in principle exists, subject to satisfactory resolution of unsettled issues, include the following:

A. Eligible CGS suppliers

1. Eligible CGS suppliers will be limited to qualifying facilities that are or will be directly connected to ETI. Any expansion of eligible CGS suppliers would require initiation of new Commission proceedings.

B. Amount of CGS capacity

1. A CGS customer will specify the amount of its load to be served by a specified CGS supplier.

2. The specified CGS supplier will enter into a contract with Entergy Services, Inc., on behalf of ETI, or directly with ETI, for the purpose of becoming an Entergy system network resource. The agreement between the CGS supplier and Entergy Services, Inc. or ETI shall include a contract for the purchase of capacity and energy (CGS purchase agreement). Per determination of the Entergy Operating Committee, the capacity and energy contracted for under the CGS purchase agreements shall be allocated

solely to ETI.

3. The level of capacity contracted for under the CGS purchase agreement (CGS contract capacity) will be the same level of capacity contracted for in a separate but related contract between the CGS supplier and the CGS customer.

4. The monthly CGS supplied capacity shall be calculated monthly based on the on-peak energy deliveries of CGS-supplied energy from the CGS supplier. The

monthly CGS supplied capacity shall be the lesser of the CGS contract capacity and the result of the following calculation-on a rolling 12-month basis (using a cumulative basis during the first 11 months), the sum of the CGS-supplied energy delivered by the CGS supplier during on-peak hours, divided by the number of on-peak hours during the same time period, divided by 0.8. On-peak hours are defined as the hours ending 7:00 am

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PUC Docket No. 38951 Interim Order Page 12 of 17

through 10:00 pm Monday through Saturday, excluding North American Electric

Reliability Corporation holidays.

C. CGS-customer unbundled rate

1. CGS customers are limited to, and will remain, ETI retail customers.

2. ETI will not make a capacity payment to the CGS supplier, and the CGS customer will not pay ETI the embedded production cost in the firm rate schedule under which the customer would otherwise be eligible to receive service.

3. The price for retail delivery service, including necessary ancillary services, to retail customers who choose to take advantage of the competitive generation tariff will be a rate that is unbundled from ETI's cost of service and that will be determined by a credit to the CGS customer's bill based on the unbundled production costs associated with the otherwise applicable firm rate.

4. The unbundled, embedded production cost for a LIPS customer based on current rates is $6.84 per kW per month. The CGS credit is subject to review and modification in subsequent rate cases. If the clause "less any corresponding concurrent reduction in energy purchased by the CGS customer" referenced in section F.1 below is adopted, then certain parties may recommend a further adjustment to the LIPS embedded production cost specified in this paragraph C.4.

5. With the exception of the capacity credit and fixed fuel factor, a CGS customer will pay ETI a retail rate that includes all other charges the customer would pay as a firm customer (for example Rider TTC, HRC, SRC, SRO, and IFF charges, if applicable).

D. CGS energy payment

l. CGS customers will pay fuel costs based on avoided cost for CGS-supplied energy. Specifically, ETI will purchase hourly CGS energy supplied by the CGS supplier from the CGS contract capacity at the system hourly avoided-energycost as determined under Rate Schedule LQF. ETI will charge the CGS customer at the same rate for that hourly CGS-supplied energy not to exceed the energy requirement of the CGS customer.

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Interim Order Page 13 of 17 PUC Docket No. 38951

E. CGS customer fixed-cost contribution

l. The level of compensation to ETI from CGS customers for CGS service

will include a monthly fixed charge called a fixed-cost contribution.

2. The fixed-cost contribution will be $1.10 per kW of CGS load per month.

3. Revenues from the fixed-cost contribution will reduce any otherwise

unrecovered costs associated with the program.

F. CGS customer unserved energy rate

l. If, in any hour in a delivery month, there is hourly CGS unserved energy, the CGS customer will take service from ETI under the CGS unserved energy rate. Hourly CGS unserved energy is the difference in any given hour between the amount of energy corresponding to the full amount of CGS contract capacity and the amount of energy actually supplied to ETI from the CGS contract capacity by the CGS supplier in such hour, not to exceed the energy requirement of the CGS customer. The parties have not agreed whether the following clause should be added to this last sentence: "less any corresponding concurrent reduction in energy purchased by the CGS customer."

2. The structure of the CGS unserved energy tariffed rate will include an agreed energy charge and agreed O&M adder. The monthly CGS unserved energy charge will be the sum of (a) the hourly CGS unserved energy for the month times 105% of the system hourly avoided energy cost as determined under Rate Schedule LQF and (b) the hourly CGS unserved energy for the month times specified variable O&M charges

specified immediately below in paragraph 3.

3. The specified variable O&M charges for the CGS unserved energy rate are as follows:

Delivery Voltage On-Peak Per kWh Off-Peak Per kWh

Distribution (less than 69kV) $0.03555 0.00540

Transmission (69kV and $0.02451 0.00222

greater)

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PUC Docket No. 38951 Interim Order Page 14 of 17

4. On-peak and off-peak hours for the CGS unserved energy rate are as follows:

a. Summer: On-peak hours are 1:00 pm to 9:00 pm Monday through Friday of each week beginning on May 15 and continuing through October 15 of each year except that Memorial Day, Labor Day and Independence Day (July 4 or the nearest weekday if July 4 is on a weekend) are not on-peak.

b. Winter: On-peak hours for each week of Monday through Friday beginning October 16 and continuing through May 14 of each year are 6:00 am to 10:00 am and 6:00 pm to 10:00 pm, except that Thanksgiving Day, Christmas Day, and New Year's Day (or the nearest weekday if the holiday should fall on a weekend) are not on-peak.

c. Off-peak hours are all hours of the year not specified as on-peak hours. With the approval of the Commission, ETI may at its sole discretion change on-peak hours and season from time to time.

5. Revenues from the CGS unserved energy rate derived from the variable O&M charges will go towards offsetting any unrecovered costs as a result of the implementation of the CGS tariff.

6. Revenues from the CGS unserved energy rate derived from 105% of the system hourly avoided energy charges will go towards offsetting ETI's eligible fuel costs.

G. Recognition of CGS supply as firm capacity. Progress has been made on resolving issues regarding the recognition of CGS capacity as firm capacity, but final resolution of these issues, including the following, is contingent on the Entergy Operating Committee's approval as well as a final resolution of all issues.

1. The Entergy Operating Committee has established certain conditions that must be met before it will recognize a CGS purchase agreement as "capability" for the Entergy System, for purposes of determining reserve equalization payments or receipts. The parties are continuing to discuss the conditions established by the Operating Committee.

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PUC Docket No. 38951 Interim Order Page 15 of 17

2. The capacity product from CGS purchase agreements will be a 24/7 unit-contingent product.

3. The delivery term of CGS purchase agreements may be from one year to

five years, and must be a whole number of years.

4. The contract capacity will be a fixed capacity amount throughout any

successive 12-month period during the contract term.

5. The parties have tentatively agreed to a number of concepts for firming up CGS capacity that would be reflected in a form contract for use in implementing the CGS program. The parties will continue to negotiate other concepts and terms for inclusion in

a form supply contract.

31. The parties stipulated that the Strategic Resource Plan (SRP) for the Entergy system (of which ETI is a part) projects a continuing need for additional capacity for ETI and the Entergy system through 2017. Entergy's and ETI's resource needs are subject to change at any time based on actual experience related to operational conditions, resource offers and solicitations, and other events that affect resource needs.

32. The parties stipulated that based on an assessment of load requirements and generating capability, the SRP projects that ETI has an incremental net resource deficiency of

260 MW in 2012 and 504 MW in 2013.

33. The parties stipulated that the Entergy system-wide planning process is conducted pursuant to the requirements of the Entergy system agreement and is designed to result in a portfolio of resources that differ by term and source. The Entergy system agreement states that the objective of this process is to ensure cost-effective, reliable levels of

service.

34. The parties stipulated that CGS purchase agreements are resources that will be included in the Entergy System's portfolio of supply resources, consistent with the terms and conditions related to the delivery requirements of those purchase agreements (e.g., degree

of dispatchability, term, degree of firmness).

35. The parties stipulated that it is reasonable at the outset of the CGS program to establish a cap on the amount of load that may subscribe to CGS service.

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PUC Docket No. 38951 Interim Order Page 16 of 17

36. The parties stipulated that the range of the cap should be between 80 MW and 150 MW.

Unrecovered costs

37. It is reasonable to adopt the three unopposed stipulation-and-settlement agreements regarding customer eligibility for the CGS program; the customers responsible for paying for unrecovered costs; the capacity deficit; and the program cap.

38. PURA § 39.452(b) provides for the utility to be able to recover any costs unrecovered as a result of the implementation of the tariff.

39. In CenterPoint, the Third Court of Appeals found that because the language of PURA § 39.905 did not specifically provide for recovery of "lost revenues" and that in at least two other provisions of PURA the legislature expressly distinguishes "costs" from "revenues," the term "costs," as used by the legislature in PURA § 39.905, is not intended to include lost revenues. Like PURA § 39.905, PURA § 39.452(b) only provides for "costs unrecovered as a result of implementation of the tariff" and does not specifically provide for the utility to recover lost revenues or any other type of costs.

40. The Commission finds that the costs that will be unrecovered as a result of the implementation of the CGS program tariff are the costs to implement and administer the CGS program tariff.

VI. Conclusions of Law l. The Commission has jurisdiction and authority over this proceeding pursuant to PURA §§ 14.001 and 39.452(b).

2. PURA § 39.452(b) does not allow for the recovery of lost revenue or embedded generation costs.

VII. Ordering Paragraphs l. The Commission adopts each of the three stipulation-and-settlement agreements filed on January 20, 2012, April 30, 2012, and April 18, 2012.

2. The parties shall work to reach an agreement on the issues that are considered contingent on the Commission's decision on the threshold issues.

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PUC Docket No. 38951 Interim Order Page 17 of 17

3. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general or specific relief, if not expressly granted, are denied.

SIGNED AT AUSTIN, TEXAS the / #-- j WL-"

day of-114ay2012

PUBLIC UTILITY COMMISSION OF TEXAS

DONNA L. NELSON, CHAIRMAN

KENNETH W. AND , JR., COMMISSIONER

ROLANDO PABLOS, COMMISSIONER

y \cadm\orders\mterim\38000\38951 interim order.docx

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PUC DOCKET NO. 38951 t'

FEB P H 2' 1 ^ APPLICATION OF ENTERGY TEXAS, § ^ INC. FOR APPROVAL OF § PUBLIC UTILITY COMMI$$ION ^.^.,,, COMPETITIVE GENERATION § OF TEXAS SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) §

OFFER OF PROOF

On February 6, 2013, Order No. 11 was issued granting the Motion to Strike that was

filed by Citiesl on January 25, 2013. Pursuant to P.U.C. PROC. R. 22.227, Entergy Texas, Inc.

makes an offer of proof with regard to the supplemental direct testimony and exhibits of

Company witness Dennis R. Roach that were struck in Order No. 11. Attached to this pleading

is a complete copy of Mr. Roach's supplemental direct testimony and exhibits including the

portions struck under Order No. 11.

' The Cities are comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville. Montogomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City. Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.

1i 0^

Respectfully submitted,

Steven H. Neinast ENTERGY SERVICES, INC. 919 Congress Avenue, Suite 840 Austin, Texas 78701 (512) 487-3957 telephone (512) 487-3958 facsimile

John F. Williams Everett Britt DUGGINS WREN MANN & ROMERO, LLP P.O. Box 1149 Austin, Texas 78767 512-744-9300 512-744-9399 (fax)

By: Z '

Steven H. 1N State Bar N 14880700

CERTIFICATE OF SERVICE

I hereby certify that a true and correct copy of the foregoing document was served on all

parties of record via U.S. first-class mail, hand delivery, overnight delivery, or facsimile

transmission on this l lt" day of February 2013.

2 .12-

Docket No. 38951 Entergy CGS Tariff ETI OFFER OF PROOF NO. 1 ([KLELW'556' 53 of 86 'RFNHW1R 3DJHRI

SECTION III RATE SCHEDULES Page __.1

ENTERGY TEXAS, INC. Sheet No.: 109 Electric Service Effective Date: Proposed Revision: 0 Supersedes: New Schedule RIDER SCHEDULE CGSUSC Schedule Consists of: Two Sheets Plus Attachments A and B

COMPETITIVE GENERATION SERVICE UNRECOVERED SERVICE COST RIDER

I. PURPOSE

This Competitive Generation Service Unrecovered Service Cost Rider (“Rider CGSUSC” or “Rider”) defines the procedure by which Entergy Texas, Inc. (“Company”) shall implement and adjust rates for recovery of Unrecovered Service Cost resulting from customers participating in the Company’s Competitive Generation Service (“CGS

N

Program”). The purpose of this Rider is to provide a mechanism for recovery of such Unrecovered Service Costs that were included in the Company’s last general rate case proceeding before the Public Utility Commission of Texas (”PUCT”).

II. APPLICABILITY

This Rider is applicable under the regular terms and conditions of the Company to all electric service billed under the Company’s rate schedules subject to the jurisdiction of the PUCT, with the exception of service billed under the Competitive Generation Service Rider (“Rider CGS”).

III. RATE

All electric service accounts with the exception of service billed under Rider CGS will be billed the Rider CGSUSC rates shown on Attachment A, as determined by application of Attachment B.

IV. RECOVERY PERIOD

This Rider is effective with the first billing cycle of ______, 201_ following the PUCT’s approval of the initial rate to be charged under Rider CGSUSC. ETI will file a request for PUCT approval of the initial rate no earlier than six (6) months after the PUCT’s approval of the CGS Program. This Rider will remain in effect until termination of the CGS Program and recovery of any remaining Unrecovered Service Cost. The redetermined rates described in § V below shall become effective for bills rendered on and after the first billing cycle of ______ immediately following the filing year and shall remain in effect for a twelve (12) month billing period, unless otherwise terminated or superseded.

V. TRUE-UP PROVISION

The rates shown on Attachment A will be adjusted annually as shown on Attachment B to reflect the actual Unrecovered Service Cost incurred due to the CGS Program. On or before _________ 1st of each year the Company shall file with the PUCT a revision of this Rider that incorporates the actual Unrecovered Service Cost for the twelve (12) months ending with _______ (“Test Period”) less any recovery under this Rider during the Test Period plus or minus any prior Cumulative Over/Under Recovery plus interest. Cumulative Over/Under Recovery for the Test Period is defined as the prior period Cumulative Over/Under Recovery plus the difference between Unrecovered Service Cost

(Continued on reverse side)

Docket No. 38951 Entergy CGS Tariff ETI OFFER OF PROOF NO. 1 ([KLELW'556' 54 of 86 'RFNHW1R 3DJHRI

Page __.2

incurred and revenues received from this Rider during the Test Period. Interest shall be calculated monthly on the Cumulative Over/Under Recovery balance at the rate established annually by the PUCT for overbilling and certain underbilling in the P.U.C. SUBST. R. 25.28(c) and (d). Interest shall be calculated based on the principles set out in the P.U.C. SUBST. R. 25.236(e)(1). The Rider CGSUSC Recovery Amount shall be the sum of the Cumulative Over/Under Recovery for the Test Period plus interest less any CGSUSC Offsets as described in § VI below and in Attachment B. The Rider CGSUSC Recovery Amount shall be allocated to the rate classes using the Production Demand Allocation Factors from the most recent base-rate case adjusted to remove CGS Program load and energy. The resulting rate class allocations of the Rider CGSUSC Recovery Amount will be divided by the rate class billing determinants for the Test Period, as adjusted to remove expected CGS Program load and energy, to determine Rider CGSUSC rate class charges.

VI. CGSUSC OFFSETS

CGSUSC Offsets are defined as 1) the $/kW reduction in ETI’s obligations under Entergy System Agreement Service Schedule MSS-1 associated with ETI’s acquisition of CGS Supplied Capacity (as defined by Rider CGS), which will be calculated pursuant to Attachment B; and 2) the revenues received from the Fixed Cost Contribution Fee (as defined by Rider CGS) for the Test Period. N

VII. INTERIM ADJUSTMENT

Should a change in the level of estimated Rider CGSUSC Recovery Amount exceed $2 million, greater or less than, the estimate included in the most recently filed determination under this CGSUSC Rider, then the Company may propose an interim revision to the then currently effective CGSUSC rate.

VIII.STAFF AND COMMISSION REVIEW

Staff shall, and any affected person may, review the ETI filed Rider CGSUSC rate to verify that the formula in Attachment B has been correctly applied and shall notify the Company of any necessary corrections within sixty days. After completion of this review of the rate calculation, the Company shall make appropriate changes to correct undisputed errors identified in the review process. Any disputed issues arising out of this review process are to be resolved by the PUCT after notice and hearing.

RIDER SCHEDULE CGSUSC

Docket No. 38951 Entergy CGS Tariff ETI OFFER OF PROOF NO. 1 ([KLELW'556' 55 of 86 'RFNHW1R 3DJHRI

Page ___.3

ATTACHMENT A ENTERGY TEXAS, INC.

COMPETITIVE GENERATION SERVICE UNRECOVERED SERVICE COST RIDER SCHEDULE CGSUSC

Net Monthly Rate

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The following Rate Adjustments, as determined by Attachment B, will be added to the rates set out in the Net Monthly Bill for electric service billed under applicable retail rate and rider schedules* on file with the Public Utility Commission of Texas. The Rate Adjustments shall be effective for bills rendered on and after the first billing cycle of the January immediately following the filing year.

*Excluded Schedules: CGS Program applications of, LIPS and LIPS-TOD, and EAPS, LQF, SMS, and SQF.

Rate Class Rate Schedule Rate Adjustment

Residential RS, RS-TOD 0.000202 $/kWh Small General Service SGS, UMS, TSS 0.000180 $/kWh General Service GS, GS-TOD, 0.041553 $/kW Large General Service LGS, LGS-TOD 0.055556 $/kW Large Industrial Power Service LIPS, LIPS-TOD 0.050944 $/kW Lighting SHL, LS-E, ALS, RLU 0.000095 $/kWh

Values above are for illustrative purposes only.

Docket No. 38951 Entergy CGS Tariff ETI OFFER OF PROOF NO. 1 ([KLELW'556' 56 of 86 'RFNHW1R 3DJHRI

Page __.4

ATTACHMENT B ENTERGY TEXAS, INC.

COMPETITIVE GENERATION SERVICE UNRECOVERED SERVICE COST RIDER SCHEDULE CGSUSC Test Period Twelve Months Ending ____, 201_

Class Allocation & Rate Development

Line (A) (B) (C) (D) (E) No. Class Rider Class Billing CGSUSC Rate Class Allocation Recovery Determinants Rate % (1) Amount ($) (MWh or kW) (4)

(2) (3)

1 Residential 47.8200% 1,081,689 5,363,885 0.000202 $/kWh 2 Small General Service 2.3436% 53,012 294,185 0.000180 $/kWh 3 General Service 20.7885% 470,236 11,316,623 0.041553 $/kW

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4 Large General Service 7.2612% 164,248 2,956,460 0.055556 $/kW 5 Large Industrial Power Service 21.4744% 485,751 9,535,012 0.050944 $/kW 6 Lighting 0.3123% 7,064 74,156 0.000095 $/kWh 7 Total ETI Retail 100.000% 2,262,000

Notes:

(1) Most recently approved Rate Class Production Demand Allocation Factor, as adjusted to remove service under the CGS Program; or, if no such factor has been approved within five years, the factor used in ETI’s cost of service study in its most recent general rate case.

(2) Attachment B, Page ___.5, Line 8 * Class Allocation % (B).

(3) The Class Billing Determinant (MWh or kW) for the year ending ________, 20__, as adjusted to remove service under the CGS Program.

(4) Class Rider Recovery Amount (C) / Class Billing Determinant (D)

Values above are for illustrative purposes only.

RIDER SCHEDULE CGSUSC

Docket No. 38951 Entergy CGS Tariff ETI OFFER OF PROOF NO. 1 ([KLELW'556' 57 of 86 'RFNHW1R 3DJHRI

Page ___.5

ATTACHMENT B ENTERGY TEXAS, INC.

COMPETITIVE GENERATION SERVICE UNRECOVERED SERVICE COST RIDER SCHEDULE CGSUSC Test Period Twelve Months Ending ____, 201_

The Rider CGSUSC rate will be adjusted annually as follows:

LINE ADJUSTED DESCRIPTION NO AMOUNT

1. Prior Period Cumulative Over/Under Recovery (A) $0

2. Unrecovered Service Costs for Test Period (B) $4,000,000 N

3. Rider CGSUSC Revenues for Test Period $0

4. Test Period Cumulative Over/Under (L1 + L2 – L3) $4,000,000

5. Cumulative Interest (C) $40,000

6. Reserve Equalization Impact (D) $1,250,000

7. Rider CGS Fixed Cost Contribution Fee (E) $528,000

8. Rider CGSUSC Recovery Amount (L4 + L5 – L6 – L7) $2,262,000

Notes:

(A) Test Period Cumulative Over/Under Recovery from prior period filing of Rider CGSUSC.

(B) Embedded cost of generation from last ETI rate case for the CGS eligible class of customers stated on a $/kW/month basis times the Monthly CGS Supplied Capacity (kW) provided each month under Rider CGS.

(C) See workpaper. (D) Reserve Equalization Impact = [CGS MW – (CGS MW * ETI responsibility ratio)] * cost rate $/MW for each month. a. CGS MW is Monthly CGS Supplied Capacity provided each month under Rider CGS.

b. ETI responsibility ratio and weighted average cost rate per MSS-1 calculation for that month during the Test Period.

(E) Rider CGS Fixed Cost Contribution Fee revenues received during Test Period.

Values above are for illustrative purposes only.

^ra PUC DOCKET NO. 38951 ^fl f^ jUL 1 PH 3: ^ ^

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION INC. FOR APPROVAL OF § COMPETITIVE GENERATION § OF TEXAS SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) §

ORDER

1. Introduction This order addresses Entergy Texas, Inc.'s (ETI's) application for a competitive generation service (CGS) under PURA § 39.452(b). The Commission approves ETI's CGS rider and competitive generation service cost (CGSC) rider as set out in this order.

This order incorporates the Commission's interim order issued in this docket on June 12, 2012 and the Commission's rulings adopting in part and rejecting in part the stipulation and settlement agreement filed by ETI, Texas Industrial Energy Consumers (TIEC), and Commission Staff on May 17, 2013. The interim order addressed the Commission's decision regarding three threshold issues surrounding ETI's CGS program. The May 17 settlement, as adopted in part and rejected in part, resolves all other contested issues in this docket.

II. Procedural History ETI submitted its proposed CGS tariff and related riders in Docket No. 37744, its last rate case.' In that rate case, the parties settled on all issues except for ETI's CGS proposal. After a hearing on the CGS proposal and the associated riders, the administrative law judge (ALJ) forwarded the parties' stipulation and settlement agreement and the proposal for decision to the Commission for consideration.

I Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Corrected Application (Feb. 23, 2010).

o^

PUC Docket No. 38951 Order Page 2 of 27

The Commission considered the settlement and the proposal for decision at the November 10 and December 1, 2010 open meetings. The Commission adopted the settlement for the rate case issues and severed the CGS issues into this docket, including the record in Docket No. 37744.2

At the December 1, 2010 open meeting, the Commission requested the parties to enter into negotiations and work to come to agreement on as many of the undetermined CGS program issues as possible, and then bring the issues for which an agreement could not be reached back to the Commission for consideration. Status reports were filed on January 13 and 28, February 18, March 11, and April 8, 2011. These reports indicated that parties continued to negotiate and that they were working to narrow the contested issues.

On September 8, 2011, State Agencies, Cities, OPUC, Kroger, and Wal-Mart jointly filed a motion requesting a decision on the proposal for decision in this docket. TIEC and Commission Staff filed responses to the joint motion and generally opposed the motion. At its September 29, 2011 open meeting, the Commissioners considered the motions and issued an order requiring the parties to file pleadings identifying the CGS tariff issues that have been settled on by the parties and identifying the issues for which a settlement could not be reached. The parties were also permitted to identify issues that are contingent upon the Commission's determination of the unsettled issues.

On November 1, 2011, several parties3 filed an agreed list of settled issues. However, the parties did not agree on a recommendation as to how the unsettled issues and issues that are contingent on the Commission's determination of unsettled issues should be addressed and resolved by the Commission. Therefore, TIEC also separately filed a list of unsettled issues and request for procedural schedule. TIEC also requested that the Commission receive additional

evidence in order to resolve the unrecovered costs issue because ETI's proposal in Docket No. 37744 was based on ETI's proposal for an energy-only program, not an energy and capacity-based program. TIEC reported that during the time period when the parties were

2 Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Order No. 14 Memorializing Decision Granting Motion to Sever (Dec. 3, 2010).

3 Cities, Entergy, OPUC, Commission Staff, State Agencies, and Wal-Mart/Sam's East. Kroger Company did not oppose the agreed settled issues and Cottonwood Energy has not participated in the discussions.

PUC Docket No. 38951 Order Page 3 of 27

negotiating, the Entergy Operating Committee had agreed that CGS power from qualifying facilities in the ETI service territory could provide firm generation.4

At the December 8 and December 15, 2011 open meetings, the Commission decided that the parties should submit stipulated facts, the Commission would re-open the record to admit additional evidence, and then the Commission would make a decision on the unsettled issues. After that, the Commission planned to issue an interim order reflecting the decisions on the unsettled, threshold issues.

On January 20, 2012, the parties submitted agreed settlement terms and stipulated facts.

The parties reached agreement in principle on a number of discrete items within the overall framework of the CGS program and tariffs. Many of the items were simply elements of larger program issues that retained, at that time, one or more unsettled aspects essential to final resolution of that program issue. Items as to which there was agreement in principle were "subject to satisfactory resolution of unsettled issues."5

On January 26, 2012, ETI submitted supplemental direct testimony. On February 10, 2012, the intervenors submitted supplemental direct testimony and on February 25, 2012, ETI and intervenors submitted rebuttal and cross rebuttal testimony. The parties submitted statements of position and pre-hearing briefs on March 26, 2012.

On April 13, 2012, the parties submitted an unopposed stipulation on the threshold issue regarding customers responsible for paying unrecovered costs. The parties, except ETI, agreed that CGS customers would be the only ETI customers responsible for unrecovered costs of the CGS program. ETI did not join or oppose this stipulation.6 On April 18, 2012, the parties submitted a third stipulation on customer eligibility stating that large industrial power service (LIPS) customers would be the CGS-eligible customers, with certain limitations on the LIPS customers' participation and other program minimums and caps.7

The Commission held a hearing on the remaining contested threshold issue-what types of costs will be considered unrecovered for purposes of PURA § 39.452(b)-on April 19, 2012.

4 TIEC's Response to Joint Motion for Decision on Proposal for Decision at 4 (Sep. 15, 2011). 5 CGS Stipulated Matters and Stipulated Facts (Jan. 20, 2012). 6 Unopposed Stipulation on Unresolved Issue No. 3 (Apr. 13, 2012).

7 Stipulation on Unresolved Issue No. 2 (Apr. 18, 2012).

PUC Docket No. 38951 Order Page 4 of 27

An interim order was issued on June 12, 2012. It was expected that the parties would reach agreement on the remaining issues.

On November 27, 2012, TIEC filed a motion to adopt a CGS program and submitted proposed CGS riders for approval. TIEC and ETI had not been able to resolve certain issues related to the CGS tariffs and TIEC stated that continued negotiations would only result in further delay of the implementation of the CGS program.8 Commission Staff requested that the parties be required to submit a procedural schedule to govern the handling of the docket.9 ETI submitted its own version of the CGS tariffs for approval and proposed procedures to lead to final disposition of this docket. 10

The Commission ALJ issued Order No. 10 adopting a procedural schedule that required the parties to indicate by February 8, 2013 whether a hearing was necessary. TIEC filed a letter stating that no party intended to file a request for a live hearing to cross-examine witnesses on the remaining contested issues.ll Cities, OPUC, ETI, TIEC, and Commission Staff filed briefs on March 1, 2013 and reply briefs on March 20, 2013. At the April 25, 2013 open meeting, the parties gave oral argument and the Commissioners discussed the Entergy Operating Committee review of the capacity component of the CGS program and the proposed MISO regulatory change provision. The Commission deferred its ultimate decision on all of the issues to the May 9, 2013 open meeting.

On May 8, 2013, TIEC filed a letter stating that TIEC and ETI had reached a preliminary agreement on the remaining disputed issues, but that the other parties had not had an opportunity to review the agreement. 12 At the May 9 open meeting, the Commission deferred consideration of the docket until the May 23, 2013 open meeting.

ETI filed a stipulation and settlement agreement on May 17, 2013 that addressed each of the disputed issues that remained in this case. ETI, TIEC, and Commission Staff signed the

8 TIEC's Motion to Adopt a Competitive Generation Services Program (Nov. 27, 2012). 9 Commission Staff's Response to TIEC's Motion to Adopt a Competitive Generation Services Program (Dec 4, 2012).

10 Entergy's Response to TIEC's Motion to Adopt Competitive Generation Services Program and Motion for Adoption of Competitive Generation Services Tariffs at 1-2 (Dec. 4, 2012).

11 Letter from TIEC (Feb. 8, 2013). 12 Letter from TIEC (May 8, 2013).

PUC Docket No. 38951 Order Page 5 of 27

stipulation. The stipulation and settlement agreement included agreement on all of the issues regarding the CGS rider, i.e., how the CGS program would work, but delayed approval of the competitive generation service cost (CGSC) rider, which is the rider that will include

implementation and administration costs for the CGS program, for a later date.

Specifically, the signatories to the settlement agreed that the CGSC rider would not be proposed for approval, but would be filed with the Commission no earlier than six months after the CGS rider becomes effective. The parties also stipulated to five issues that would be addressed in the CGSC rider docket. ETI noted that Commission Staff supports the stipulation, but did not take a position relating to the deferral of the consideration of issues regarding the CGSC rider.13 OPUC, joined by Kroger Company, Wal-Mart Stores, LLC, and Sam's East, Inc.

filed a statement of opposition to the stipulation stating that their opposition was limited to Section II.B. of the stipulation, which allows the delay of the resolution of the CGSC rider issues.14 Cities filed a letter on May 21 stating that it supports the resolution of the issues in the stipulation, but that they also support resolving all issues at this time in order to conserve judicial resources and provide certainty to parties in future cases.15 TIEC filed a response to the opposition16 and OPUC, Kroger, Wal-Mart, and Sam's East filed a reply to TIEC's response. 17

The Commission considered this docket again on the merits at the May 23, 2013 open meeting. The Commission adopts the May 17, 2013 stipulation and settlement agreement in part, but rejects the deferral of approval of the CGSC rider set out in section II.B.2. of the stipulation. The Commission adopts the stipulation and settlement agreement as it pertains to the

CGS rider, and makes findings on the outstanding issues related to the CGSC rider.

13 Stipulation and Settlement Agreement (May 17, 2013).

14 Joint Statement of Position (May 17, 2013). 15 Cities' Letter Addressing the Settlement Reached by Entergy and TIEC (May 21, 2013). 16 TIEC's Response to OPUC's Statement of Opposition (May 21, 2013). 17 Joint Reply to TIEC's Response to the Joint Statement of Opposition (May 22, 2013).

PUC Docket No. 38951 Order Page 6 of 27

III. Discussion PURA18 § 39.452(b) requires ETI to propose a CGS tariff that would require ETI to purchase CGS, selected by the CGS customer, and provide the generation at retail to the customer. ETI is required to provide and price retail transmission service, including necessary

ancillary services, to retail customers who choose to take advantage of the competitive generation tariff at a rate that is unbundled from the utility's cost of service. Competitive generation customers are not to be considered wholesale transmission customers. The statute required the Commission to approve, reject, or modify the proposed tariff not later than September 1, 2010. The CGS tariff may not be considered to offer a discounted rate or rates under Section 36.007, and ETI's rates shall be set, in the proceeding in which the tariff is adopted, to recover any costs unrecovered as a result of the implementation of the tariff. The statute requires the Commission to ensure that a competitive generation tariff not be implemented in a manner that harms the sustainability or competitiveness of manufacturers that choose not to take advantage of competitive generation. PURA § 39.452(b) also prohibits the Commission from issuing a decision relating to the competitive generation tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.

The Commission finds that the three stipulation and settlement agreements submitted by the parties in January and April 2012 are reasonable and adopts them to the extent they do not conflict with other Commission determinations in this docket.

The Commission also finds that unrecovered costs are only those costs necessary to implement and administer the CGS program and are not to be defined to include lost revenues, embedded generation costs, or any other types of costs.

Finally, the Commission finds that the May 17, 2013 stipulation with regard to the CGS

rider is reasonable and adopts that portion of the stipulation. The Commission declines to adopt the stipulation regarding the CGSC rider, and finds that the issues regarding the CGSC rider should not be deferred and that the CGSC rider should not include costs prior to implementation of the CGS program; LIPS and LIPS time-of-day customers should be responsible for the CGSC

18 Public Utility Regulatory Act (PURA), TEx. UTIL. CODE ANN. §§ 11.001-66.017 (Vernon 2007 & Supp.

2011).

PUC Docket No. 38951 Order Page 7 of 27

rider costs if the CGS program is unsubscribed; ETI should not recover interest on any unrecovered balance of the CGSC rider; and the CGSC rider costs should not be offset to account for the CGS costs included in ETI's base rates.

A. Unrecovered Costs As explained in the interim order, the meaning of "costs unrecovered as a result of implementation of the CGS program tariff," as used in PURA § 39.452(b), was the subject of the April 19, 2012 hearing. In the proposal for decision, the ALJ found that ETI is entitled to collect unrecovered embedded generation costs and any other related base rate costs as a result of customer migration to the CGS program.t9

ETI argued that unrecovered costs should be defined as the embedded production costs and any other related base rate costs that would have been recovered through traditional rates charged to CGS customers that will no longer be recovered due to the CGS program. 2' TIEC took the position that unrecovered costs should not include ETI's hypothetical lost revenues and that the costs that could be unrecovered as a result of implementation of the tariff should include the expenditures actually incurred by ETI to implement and maintain the CGS program.21 Cities and OPUC agreed with TIEC that unrecovered costs are not the same thing as unrecovered revenues.22 Cities also noted that it would be unreasonable to allow ETI to continue to incur costs for a customer the utility no longer plans to serve.23

In making its determination of the definition of unrecovered costs, the Commission follows the precedent set in CenterPoint Energy Houston Electric, LLC v. Pub. Util. Comm 'n, 354 S.W.3d 899 (Tex. App-Austin, 2011 no pet.) where the Third Court of Appeals found that because the language of PURA § 39.905 did not specifically provide for recovery of "lost revenues" and that in at least two other provisions of PURA24 the legislature expressly

19 Proposal for Decision at 22 (Oct. 5, 2010). 20 Supplemental Direct Testimony, Exhibits, and Workpapers of Phillip R. May, ETI Ex. 91 at 6. 2 1 Supplemental Direct Testimony of Jeffry Pollock, TIEC Ex. 15 at 14-15. 22 Supplemental Direct Testimony of Karl Nalepa, Cities Ex. 6C at 7 and Supplemental Cross Rebuttal Testimony of Clarence Johnson, OPUC Ex. 8 at 6.

23 Supplemental Direct Testimony of Karl Nalepa, Cities Ex. 6C at 7-8.

24 PURA § 55.024(b) and PURA § 56.025(e).

PUC Docket No. 38951 Order Page 8 of 27

distinguishes "costs" from "revenues," the term "costs," as used by the legislature in PURA § 39.905, is not intended to include lost revenues.25 Like PURA § 39.905, PURA § 39.452(b) only provides for "costs unrecovered as a result of implementation of the

tariff' and does not specifically provide for the utility to recover lost revenues or any other type of costs.

Based on the evidence and testimony, the Commission finds that the proper interpretation of "costs unrecovered as a result of implementation of the CGS program tariff' is costs to implement and administer the CGS program tariff. Such unrecovered costs do not include lost revenues, embedded generation costs, or any other types of costs. The Commission reverses the proposal for decision on this issue.

B. May 17, 2013 Stipulation and Settlement Agreement The Commission adopts the May 17, 2013 stipulation and settlement agreement in part, and rejects the settlement in part.

Under the terms of the stipulation, the parties agreed on issues relating to a CGS credit amount, a fixed cost contribution fee, unserved energy, a termination payment, a force majeure clause, the Entergy Operating Committee, and MISO. Those issues are covered under findings of fact 53A-H. Under the stipulation, decisions regarding the CGS cost rider were to be deferred until no earlier than six months after the CGS rider became effective. The Commission adopts the stipulation except for the portion of the stipulation that would defer decisions regarding the CGS cost rider. The Commission elects to make those decisions now rather than deferring them, and no party at the open meeting objected to this proposal.

C. CGSC rider 1. Retroactive Recovery of Historical Costs

ETI proposed to recover the costs it incurred since November 10, 2010 related to the CGS program.26 TIEC's version of the CGSC rider would permit ETI to be able to recover the incremental, reasonable, and necessary CGS program implementation and administration costs

25 CenterPoint Energy Houston Electric, LLC v. Pub. Util. Comm 'n, 354 S.W.3d 899, 903-904 (Tex.Civ.App-Austin, 2011)

26 ETI's redlined tariff version Exhibit DRR-SD-6 at 1, Section II Purpose.

PUC Docket No. 38951 Order Page 9 of 27

incurred by ETI following the approval of the CGS program pursuant to PURA § 39.452(b).27 Commission Staff did not support allowing ETI to recover costs in excess of the amounts already in base rates until the CGS program is actually implemented and the implementation costs associated with the eventual design of the CGS program are actually incurred.28 The Commission finds that ETI should not be able to recover any costs via the CGSC rider until the CGS program is implemented.

2. Cost Recovery if the CGS program is unsubscribed

ETI proposed that if the CGS program is unsubscribed, the CGSC rider rate would apply to the classes that are eligible to participate in the program.29 Commission Staff agreed with ETI and noted that even if the costs incurred to implement the program are de minimis because there are no subscribers, ETI would still be entitled to recover those costs under PURA § 39.452(b).3o OPUC agreed with ETI and Commission Staff.31 TIEC urged the Commission to defer this issue until the facts are not speculative in order to balance the twin charges of the statute of allowing ETI to recover any costs that are unrecovered as a result of the implementation of the tariff and ensuring that the tariff is not implemented in a manner that harms the sustainability or competitiveness of manufacturers that choose not to take advantage of the CGS program.32

The Commission finds that ETI should be allowed to recover CGSC rider costs in the event that there are no subscribers to the CGS program, because PURA § 39.452(b) entitles ETI to recover those costs. The Commission finds that those costs should be borne by the customer class that the program was designed to benefit-the LIPS and LIPS-TOD customers-the customers that are eligible to participate in the program. The Commission adopts the language proposed by ETI on this issue in Section III of the redlined tariff.

27 TIEC's Initial Brief at 21-24. 28 Commission Staff's Initial Brief at 6-7 (March 1, 2013). 29 ETI's redlined tariff version Exhibit DRR-SD-6 at 1, Section III Rate. 3 0 Commission Staff s Initial Brief at 7 (March 1, 2013).

31 OPUC's Reply Brief at 12 (March 20, 2013). 32 TIEC's Initial Brief at 24-25 (March 1, 2013).

PUC Docket No. 38951 Order Page 10 of 27

3. Interest

Citing PURA § 39.452(b), that ETI should be allowed to recover any costs unrecovered as a result of implementing the tariff, ETI requested recovery of interest on the unrecovered balance of the CGSC rider charges.33 TIEC noted that the CGSC rider would be periodically adjusted to reflect ETI's actually incurred costs, so there would be no need for ETI to accrue interest on any unrecovered balance.

The Commission finds that not allowing interest would be consistent with the treatment of rate-case expenses, which are typically amortized over a three-year period without a return on the unamortized balance.34 ETI should not be permitted to recover interest on the unrecovered balance of the CGSC rider charges.

4. CGSC rider costs recovered in rate-base offset

OPUC argued that the interim order is clear that the costs to implement the CGS program are to be borne only by CGS customers. However, $299,372 was included in ETI's base rates for costs related to the CGS program and will be paid by all retail customer classes. OPUC recommended that the same amount that is being recovered from all retail customers in base rates for CGS costs be recovered solely through the CGSC rider. Since the LIPS class is being charged $49,192 per year in base rates, OPUC recommended that the CGS rider should be reduced by $49,192 to prevent double-recovery and that the remainder that is being recovered in retail base rates, $249,960, should be refunded directly to each class in the amount allocated in base rates.35

TIEC took the position that OPUC was attempting make a collateral attack on the Commission's order in ETI's rate case. Furthermore, TIEC argues that ETI should not be required to conduct OPUC's proposed "offset" for the same reason that ETI should not be

permitted to include costs incurred since November 2010-the costs are not costs to implement the CGS program.36

33 ETI's Initial Brief at 24 (March 1, 2013). 34 TIEC's Initial Brief at 25 (March 1, 2013). 35 OPUC's Initial Brief at 3-7 (March 1, 2013).

36 TIEC's Reply Brief at 17-18 (March 20, 2013).

PUC Docket No. 38951 Order Page 11 of 27

ETI proposed to credit the CGSC rider with $299,372 to recognize amounts that were used in setting ETI's current base rates. This amount represents the amount of CGS-related costs that ETI is already recovering in base rates pursuant to the Commission's order in ETI's mostrecent rate case, Docket No. 39896.37

The Commission agrees with TIEC on this issue and goes further to state that to permit an offset to the CGSC rider for amounts already included in rates may be retroactive ratemaking.

5. Amount to be recovered in the CGSC rider

The Commission does not reach the issue of the amount to be recovered for the implementation and administration costs at this time because the amount cannot be known until ETI actually implements the program.

IV. Conclusion The Commission adopts each of the stipulation and settlement agreements except for section II.B.2 of the May 17, 2013 stipulation, and finds that unrecovered costs for the CGS program are those needed to implement and administer the CGS program and are not lost revenues, embedded generation costs, or any other types of costs. The Commission finds that ETI should not be able to recover any costs via the CGSC rider until the CGS program is implemented, that ETI should be allowed to recovery CGSC rider costs in the event that there are no subscribers to the CGS program, that ETI should not be permitted to recover interest on the unrecovered balance of the CGSC rider charges, and that ETI should not be required to conduct OPUC's proposed "offset."

37 Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment, Docket No. 39896, Order (Sept. 14, 2012).

PUC Docket No. 38951 Order Page 12 of 27

V. Findings of Fact

Procedural History 1. As part of its application in Docket No. 37744, Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, ETI proposed a competitive generation service ( CGS) program pursuant to Public Utility Regulatory Act. Tex. Util. Code Ann. (PURA) § 39.452(b).

2. On July 16, 2010 and July 20, 2010, a State Office of Administrative Hearings administrative law judge held a hearing on the merits on ETI's CGS proposal.

3. A proposal for decision was issued on November 1, 2010. The ALJ ultimately recommended that the CGS proposal be rejected.

4. The Commission considered the proposal for decision at the November 10 and December 1, 2010 open meetings as part of docket No. 37744. At the December 1, 2010 open meeting, the Commission adopted the settlement for the rate case issues and severed the CGS proposal into this Docket. The Commission requested that the parties enter into negotiations and work to come to agreement on as many of the undetermined issues as possible, and then bring the issues for which an agreement could not be reached back to the Commission for consideration.

5. Order No. 1 was issued on December 3, 2010 severing the CGS issues into this docket, including the record in Docket No. 37744.

6. Sabine Cogen, LP filed a motion to intervene in this docket on December 23, 2010. ETI filed an objection to Sabine Cogen, LP's motion to intervene on December 30, 2010. Sabine Cogen, LP's motion to intervene was denied in Order No. 3 on January 12, 2011.

7. ETI, Commission Staff, Office of Public Utility Counsel, Texas Industrial Energy Consumers, State Agencies, Kroger Co., Cities,38 Wal-Mart Stores Texas, LLC and Sam's East, Inc., and Cottonwood Energy are parties to this proceeding.

38 The cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.

PUC Docket No. 38951 Order Page 13 of 27

8. On January 11, 2011, the Commission AU issued Order No. 2 requiring ETI to either

provide an update on the status of settlement discussions or to propose a schedule, agreed to by all parties, for finalizing the outstanding issues.

9. The parties filed status reports on January 13 and 28, February 18, March 11, and April 8, 2011. These reports indicated that parties continued to negotiate and that they thought that they could narrow the issues.

10. On September 8, 2011, State Agencies, Cities, OPUC, Kroger, and Wal-Mart jointly filed a motion requesting a decision on the proposal for decision in this docket. TIEC and Commission Staff filed responses to the joint motion and generally opposed the motion. At the September 29, 2011 open meeting, the Commissioners considered the motions and issued an order requiring the parties to file pleadings identifying the CGS tariff issues that have been settled on by the parties and identifying the issues for which a settlement could not be reached. The parties were also permitted to identify issues that are contingent upon the Commission's determination of the unsettled issues.

11. On November 1, several parties filed an agreed list of settled issues. TIEC also separately filed a list of unsettled issues and request for procedural schedule. TIEC also requested that the Commission receive additional evidence in order to resolve the unrecovered costs issues because ETI's proposal in Docket No. 37744 was based on ETI's proposal for an energy-only program, not an energy and capacity-based program. The circumstances had changed primarily due to the agreement of the Entergy Operating Committee to treat CGS power from qualifying facilities in the ETI service territory as firm generation. The remainder of the parties filed a joint agreed list of unsettled issues and issues contingent on a Commission determination of unsettled issues.

12. At the December 8 and December 15, 2011 open meetings, the Commissioners decided that the parties should submit stipulated facts, the Commission would re-open the record to admit additional evidence as requested by TIEC, and then the Commission would make a decision on the three threshold unsettled issues in an interim order.

13. On December 18, 2011, Order No. 4 was issued establishing a procedural schedule.

PUC Docket No. 38951 Order Page 14 of 27

14. On January 20, 2012, the parties submitted agreed settlement terms and stipulated facts.

The parties reached agreement in principle on a number of discrete items within the overall framework of the CGS program and tariffs. Many of the items were simply elements of larger program issues that retain one or more as yet unsettled aspects essential to final resolution of that program issue. Items as to which agreement in principle existed were "subject to satisfactory resolution of unsettled issues."

15. On January 24, 2012, Order No. 5 was issued clarifying the number of copies of testimony that were to be filed by the parties.

16. On January 26, 2012, ETI submitted supplemental direct testimony. On February 10, 2012, the intervenors submitted supplemental direct testimony and on February 25, 2012, ETI and intervenors submitted rebuttal and cross rebuttal testimony. The parties submitted statements of position and pre-hearing briefs on March 26, 2012.

17. Order No. 6 was issued on February 1, 2012 setting April 19, 2012 as the date for the hearing.

18. On April 13, 2012, the parties filed an unopposed stipulation that to the extent there are costs unrecovered as a result of the implementation of a CGS tariff, those costs should be borne solely by customers taking service under the CGS tariff. ETI did not join but did not oppose the stipulation.

19. On April 18, 2012, the parties filed an unopposed stipulation regarding customer eligibility. LIPS customers will be eligible to participate in ETI's CGS program (with further limitations as set forth in the stipulation on this issue).

20. The Commission held the hearing on the merits on April 19, 2012, and issued an interim order on June 12, 2012 that adopted the unopposed issues and ruled that the types of costs that will be considered ETI's unrecovered costs for purposes of PURA § 39.452(b) are

those costs necessary to implement and administer the CGS program and are not to be defined to include lost revenues, embedded generation costs, or any other types of costs.

21. Subsequent to the interim order, the parties continued discussions regarding how to develop a CGS tariff (or tariffs) that would conform to the interim order rulings and resolve other remaining contested issues.

PUC Docket No. 38951 Order Page 15 of 27

22. On November 27, 2012, TIEC filed a motion to adopt a competitive generation services program that included its proposed Rider Schedule CGS and Rider Schedule CGSC, the latter of which addressed ETI's recovery of its costs of implementing and administering the CGS program. TIEC's motion also addressed a number of issues that the parties had not been able to resolve, and asked that the Commission rule in TIEC's favor on those remaining contested issues.

23. On December 4, 2012, ETI filed a response to TIEC's November 27 motion. ETI's response addressed the same contested issues raised by TIEC and asked the Commission to rule in favor of ETI's position. ETI's response also included its own versions of the CGS and CGSC riders (based on its positions on the contested issues), plus a redlined version of both riders that compared TIEC's versions to ETI's versions.

24. On January 7, 2013, in response to a motion filed by TIEC, the Commission issued a procedural schedule that required parties to file supplemental testimony in support of their positions later in January and early February, and that parties were to indicate, on February 8, 2013, whether a hearing was necessary. Interested parties filed supplemental testimony in accordance with that schedule, and no party requested an evidentiary hearing.

25. On February 19, 2013, the Commission issued an agreed briefing schedule which called for parties to file a joint motion to stipulate testimony and RFIs into the record on February 25, and for parties to file initial and reply briefs on March 1 and 20, respectively, which briefs were filed by ETI, TIEC, Staff, OPUC, and Cities.

26. On May 8, 2013, TIEC filed a letter stating that TIEC and ETI had reached a preliminary agreement on the remaining disputed issues and asked that this matter be deferred to the next open meeting. All parties indicated their agreement with the deferral. The Commission deferred consideration until the May 23, 2013 open meeting.

27. On May 17, 2013, ETI filed a stipulation and settlement agreement, which was supported by TIEC and Staff, but with Staff taking no position on Sections II.B.1 and 2 of that settlement.

PUC Docket No. 38951 Order Page 16 of 27

28. On May 17, 2013, OPUC, Kroger, and Wal-Mart filed a Joint Statement of Opposition to

the May 17 settlement. Their opposition was limited to Section II.B. of that settlement and pertained to the proposed delay in deciding certain issues before the Commission, including which customer classes should pay for costs recovered through the CGSC rider in the event there are no CGS program subscribers, and the treatment of CGS project code costs "embedded" in ETI's base rates in accordance with the Commission's order in Docket No. 39896.

29. TIEC filed a response to the Joint Statement of Opposition on May 21, 2013.

30. OPUC, Kroger and Wal-Mart filed a joint reply to TIEC's response on May 22, 2013.

31. The Commission considered this matter at its May 23, 2013 open meeting, at which it voted to accept in part and reject in part the May 17 settlement.

Elisible customers stipulation 32. The parties agreed that only customers eligible to take service under ETI's Large Industrial Power Service (LIPS) are eligible customers for the CGS program.

33. The parties agreed that only LIPS firm load will be eligible to participate in the CGS program.

34. The parties agreed that LIPS customers with interruptible service (IS) or standby and maintenance service (SMS) load are not precluded from participating in the CGS program, but this participation is limited to their firm LIPS load. To the extent that customers with IS load participate in the CGS program, they must comply with the terms of the IS tariffs regarding minimum LIPS load. Only the portion of the customer's LIPS load that is in excess of the firm contract power minimum requirement under section 1 of Schedule IS is eligible for the CGS program.

35. The parties agreed that to the extent there are increased administration costs associated with billing a customer that has CGS and IS or SMS load, the CGS customer will bear the costs.

36. The parties agreed that there will be a 115 MW cap on the CGS program.

37. The parties agreed that there will be a 5 MW minimum on CGS customer load.

PUC Docket No. 38951 Order Page 17 of 27

38. The parties agreed that there will be no aggregation of CGS customer load to meet the

5 MW minimum on CGS customer load.

39. The parties agreed that there will be a cap of 10 CGS purchase agreements.

Customers responsible for nayinQ unrecovered costs stipulation

40. The parties, except ETI, agreed that to the extent there are costs unrecovered as a result of the implementation of a CGS tariff, those costs should be borne solely by customers taking service under the CGS tariff, i.e., CGS customers. ETI did not oppose this stipulation.

January 20, 2012 CGS Stipulated Matters and Stipulated Facts

41. In the CGS stipulated matters and stipulated facts filed on January 20, 2012, the parties stated they had reached an agreement in principle on a number of discrete items within the overall framework of the CGS program and tariffs, which were listed in Section I. A-G of the stipulation. However, many of those items were simply elements of larger program issues that retained one or more unsettled aspects essential to final resolution of that program issue. Items as to which agreement in principle existed, subject to satisfactory resolution of unsettled issues, included the following:

A. Eligible CGS suppliers

1. Eligible CGS suppliers will be limited to qualifying facilities that are or will be directly connected to ETI. Any expansion of eligible CGS suppliers would require initiation of new Commission proceedings.

B. Amount of CGS capacity

1. A CGS customer will specify the amount of its load to be served by a specified CGS supplier.

2. The specified CGS supplier will enter into a contract with Entergy Services, Inc., on behalf of ETI, or directly with ETI, for the purpose of becoming an Entergy system network resource. The agreement between the CGS supplier and Entergy Services, Inc. or ETI shall include a contract for the purchase of capacity and energy (CGS purchase agreement). Per determination of the Entergy Operating Committee, the

PUC Docket No. 38951 Order Page 18 of 27

capacity and energy contracted for under the CGS purchase agreements shall be allocated

solely to ETI.

3. The level of capacity contracted for under the CGS purchase agreement (CGS contract capacity) will be the same level of capacity contracted for in a separate but related contract between the CGS supplier and the CGS customer.

4. The monthly CGS supplied capacity shall be calculated monthly based on the on-peak energy deliveries of CGS-supplied energy from the CGS supplier. The monthly CGS supplied capacity shall be the lesser of the CGS contract capacity and the result of the following calculation-on a rolling 12-month basis (using a cumulative basis during the first 11 months), the sum of the CGS-supplied energy delivered by the CGS supplier during on-peak hours, divided by the number of on-peak hours during the same time period, divided by 0.8. On-peak hours are defined as the hours ending 7:00 am through 10:00 pm Monday through Saturday, excluding North American Electric Reliability Corporation holidays.

C. CGS-customer unbundled rate

1. CGS customers are limited to, and will remain, ETI retail customers.

2. ETI will not make a capacity payment to the CGS supplier, and the CGS customer will not pay ETI the embedded production cost in the firm rate schedule under which the customer would otherwise be eligible to receive service.

3. The price for retail delivery service, including necessary ancillary services, to retail customers who choose to take advantage of the competitive generation tariff will be a rate that is unbundled from ETI's cost of service and that will be determined by a credit to the CGS customer's bill based on the unbundled production costs associated with the otherwise applicable firm rate.

4. The unbundled, embedded production cost for a LIPS customer based on current rates is $6.84 per kW per month.39 The CGS credit is subject to review and modification in subsequent rate cases. If the clause "less any corresponding concurrent

39 The parties subsequently agreed to set this amount at $6.50 per kW per month until rates are changed in ETI's next base rate case (that is, the next base rate case after May 16, 2013). Finding of Fact No. 53A.

PUC Docket No. 38951 Order Page 19 of 27

reduction in energy purchased by the CGS customer" referenced in section F.1 below is

adopted, then certain parties may recommend a further adjustment to the LIPS embedded

production cost specified in this paragraph C.4.

5. With the exception of the capacity credit and fixed fuel factor, a CGS customer will pay ETI a retail rate that includes all other charges the customer would pay as a firm customer (for example Rider TTC, HRC, SRC, SRO, and IFF charges, if applicable).

D. CGS energy payment

1. CGS customers will pay fuel costs based on avoided cost for CGS-supplied energy. Specifically, ETI will purchase hourly CGS energy supplied by the CGS supplier from the CGS contract capacity at the system hourly avoided-energycost as determined under Rate Schedule LQF. ETI will charge the CGS customer at the same rate for that hourly CGS-supplied energy not to exceed the energy requirement of the CGS customer.

E. CGS customer fixed-cost contribution

1. The level of compensation to ETI from CGS customers for CGS service will include a monthly fixed charge called a fixed-cost contribution.

2. The fixed-cost contribution will be $1.10 per kW of CGS load per month.

3. Revenues from the fixed-cost contribution will reduce any otherwise unrecovered costs associated with the program.

F. CGS customer unserved energy rate

1. If, in any hour in a delivery month, there is hourly CGS unserved energy, the CGS customer will take service from ETI under the CGS unserved energy rate. Hourly CGS unserved energy is the difference in any given hour between the amount of energy corresponding to the full amount of CGS contract capacity and the amount of energy actually supplied to ETI from the CGS contract capacity by the CGS supplier in such hour, not to exceed the energy requirement of the CGS customer. The parties have

PUC Docket No. 38951 Order Page 20 of 27

not agreed whether the following clause should be added to this last sentence: "less any corresponding concurrent reduction in energy purchased by the CGS customer."40

2. The structure of the CGS unserved energy tariffed rate will include an agreed energy charge and agreed O&M adder. The monthly CGS unserved energy charge will be the sum of (a) the hourly CGS unserved energy for the month times 105% of the system hourly avoided energy cost as determined under Rate Schedule LQF and (b) the hourly CGS unserved energy for the month times specified variable O&M charges specified immediately below in paragraph 3.

3. The specified variable O&M charges for the CGS unserved energy rate are as follows:

Delivery Voltage On-Peak Per kWh Off-Peak Per kWh

Distribution (less than 69kV) $0.03555 0.00540

Transmission (69kV and $0.02451 0.00222 greater)

4. On-peak and off-peak hours for the CGS unserved energy rate are as follows:

a. Summer: On-peak hours are 1:00 pm to 9:00 pm Monday through Friday of each week beginning on May 15 and continuing through October 15 of each year except that Memorial Day, Labor Day and Independence Day (July 4 or the nearest weekday if July 4 is on a weekend) are not on-peak.

b. Winter: On-peak hours for each week of Monday through Friday beginning October 16 and continuing through May 14 of each year are 6:00 am to 10:00 am and 6:00 pm to 10:00 pm, except that Thanksgiving Day, Christmas Day, and New Year's Day (or the nearest weekday if the holiday should fall on a weekend) are not on-peak.

40 The parties subsequently agreed that this quoted language would be added.

PUC Docket No. 38951 Order Page 21 of 27

c. Off-peak hours are all hours of the year not specified as on-peak hours. With the approval of the Commission, ETI may at its sole discretion change on-peak hours and season from time to time.

5. Revenues from the CGS unserved energy rate derived from the variable O&M charges will go towards offsetting any unrecovered costs as a result of the implementation of the CGS tariff.

6. Revenues from the CGS unserved energy rate derived from 105% of the system hourly avoided energy charges will go towards offsetting ETI's eligible fuel costs.

G. Recognition of CGS supply as firm capacity. Progress has been made on resolving issues regarding the recognition of CGS capacity as firm capacity, but final resolution of these issues, including the following, is contingent on the Entergy Operating Committee's approval as well as a final resolution of all issues.

1. The Entergy Operating Committee has established certain conditions that must be met before it will recognize a CGS purchase agreement as "capability" for the Entergy System, for purposes of determining reserve equalization payments or receipts. The parties are continuing to discuss the conditions established by the Operating Committee.

2. The capacity product from CGS purchase agreements will be a 24/7 unit-contingent product.

3. The delivery term of CGS purchase agreements may be from one year to five years, and must be a whole number of years.

4. The contract capacity will be a fixed capacity amount throughout any successive 12-month period during the contract term.

5. The parties have tentatively agreed to a number of concepts for firming up CGS capacity that would be reflected in a form contract for use in implementing the CGS program. The parties will continue to negotiate other concepts and terms for inclusion in a form supply contract.

42. The parties stipulated that the Strategic Resource Plan (SRP) for the Entergy system (of which ETI is a part) projects a continuing need for additional capacity for ETI and the

PUC Docket No. 38951 Order Page 22 of 27

Entergy system through 2017. Entergy's and ETI's resource needs are subject to change

at any time based on actual experience related to operational conditions, resource offers

and solicitations, and other events that affect resource needs.

43. The parties stipulated that based on an assessment of load requirements and generating capability, the SRP projects that ETI has an incremental net resource deficiency of 260 MW in 2012 and 504 MW in 2013.

44. The parties stipulated that the Entergy system-wide planning process is conducted pursuant to the requirements of the Entergy system agreement and is designed to result in a portfolio of resources that differ by term and source. The Entergy system agreement states that the objective of this process is to ensure cost-effective, reliable levels of service.

45. The parties stipulated that CGS purchase agreements are resources that will be included in the Entergy System's portfolio of supply resources, consistent with the terms and conditions related to the delivery requirements of those purchase agreements (e.g., degree of dispatchability, term, degree of firmness).

46. The parties stipulated that it is reasonable at the outset of the CGS program to establish a cap on the amount of load that may subscribe to CGS service.

47. The parties stipulated that the range of the cap should be between 80 MW and 150 MW.

48. It is reasonable to adopt the three unopposed 2012 stipulation and settlement agreements regarding customer eligibility for the CGS program; the customers responsible for paying for unrecovered costs; the capacity deficit; and the program cap.

Unrecovered costs

49. PURA § 39.452(b) provides for the utility to be able to recover any costs unrecovered as a result of the implementation of the tariff.

50. In CenterPoint, the Third Court of Appeals found that because the language of PURA § 39.905 did not specifically provide for recovery of "lost revenues" and that in at least two other provisions of PURA the legislature expressly distinguishes "costs" from "revenues," the term "costs," as used by the legislature in PURA § 39.905, is not intended to include lost revenues. Like PURA § 39.905, PURA § 39.452(b) only

PUC Docket No. 38951 Order Page 23 of 27

provides for "costs unrecovered as a result of implementation of the tariff' and does not

specifically provide for the utility to recover lost revenues or any other type of costs.

51. The Commission finds that the costs that will be unrecovered as a result of the implementation of the CGS program tariff are the costs to implement and administer the CGS program tariff.

The May 17, 2013 Stipulation and Settlement Agreement

52. The May 17 settlement addresses the remaining contested issues that were not resolved through the 2012 stipulation and settlement agreements and the interim order. The substantive provisions of the May 17 settlement address the CGS rider, the CGSC rider, and appeal rights.

53. Agreements as to CGS Rider:

A. CGS Credit: The parties agree to a CGS credit set at $6.50 per kW/month until rates are changed in ETI's next base rate case.

B. Unserved Energy: The parties agree to accept TIEC's proposed CGS rider tariff language in the Second Supplemental Direct Testimony of Jeffry Pollock, which will allow a CGS customer to attempt to decrease its load to match a decrease in deliveries by the CGS supplier and thereby avoid unserved energy charges to the extent the CGS customer's CGS load is reduced.

C. Termination Payment: The parties agree to remove ETI's proposed liquidated damages provisions from the CGS rider and deal with liquidated damages provisions in the supplier contract negotiations. The amount of liquidated damages, if any, received by ETI shall be used to offset any capacity costs incurred by ETI to replace the lost CGS supply.

D. The Tracking Certificate: The parties agree to remove ETI's proposed prioritization provisions in Section G(5) and H from the tracking certificate (leaving them to contract negotiations) and delete the provisions that would require the CGS customer to provide what TIEC deemed "competitively sensitive" information.

E. Force Majeure: The parties agree to remove TIEC's proposed force majeure provision.

PUC Docket No. 38951 Order Page 24 of 27

F. The Entergy Operating Committee: The parties agree to remove the following

ETI-proposed "reservation" provision from the CGS rider:

In addition, entering into new ETI-Supplier Contracts under the CGS Program (i.e., ETI-Supplier Contracts that have not already been entered into by ETI in response to CGS Service requests) at any given time must be consistent with the Entergy System's need for capacity. Capacity resources associated with the CGS Program will receive no preferential treatment, but will be considered as part of the Entergy System's planning process on the same basis as other potential capacity resources. Recognition of the capacity component of the CGS Program on an ongoing basis is contingent on periodic Entergy Operating Committee conclusion that ETI requires the capability that would be obtained through this program component.

ETI shall have the right by notice to the applicable customer, to deny or terminate a request for CGS Service at any time prior to entering into the ETI-Supplier Contract corresponding to such request if the limitations in the penultimate paragraph of § I above apply ...

The following clause in Rider CGS Section III.B.3 of ETI's proposed Rider CGS is modified as follows: Unless a CGS Service request is earlier denied or terminated according to tariff provisions (or provisions of law) applicable to the CGS Service ...

G. MISO: The parties agree that ETI's proposed RTO/MISO provision will stay in the CGS rider, but the phrase "it will be necessary or appropriate to include [MISO terms and conditions]" is changed to "it may be appropriate to include [MISO terms and conditions)."

H. $1.10 Fixed Cost Contribution Fee: The parties agree that this fee will not be applied as an offset to CGS administration and implementation costs.

54. Agreement as to CGSC Rider:

A. ETI has agreed that an application for the CGSC rider will be filed with the Commission no earlier than six months after the CGS rider becomes effective.

B. Section II.B.2. in the May 17, 2013 settlement was challenged by OPUC, Kroger, and Wal-Mart, with Cities also supporting resolution of the issues in Section II.B.2. now, rather than deferring them as proposed in the May 17, 2013 settlement.

PUC Docket No. 38951 Order Page 25 of 27

C. Other than Section II.B.2, no other sections of the May 17 settlement were opposed by OPUC, Kroger, Wal-Mart, or Cities, and were supported by ETI, TIEC, and Commission Staff. The Commission finds that those unopposed provisions in the May 17 settlement are reasonable and in the public interest.

D. The record from the current CGS docket (Docket No. 38951) and from Docket No. 37744 shall be incorporated into the record in the CGSC rider application docket.

E. All parties agree that only the variable O&M portion of the unserved energy rate should be used to offset the unrecovered implementation and administrative costs. Fuel- related revenues from the unserved energy rate will offset ETI's fuel balance, and not be used to offset unrecovered costs.

F. There will be no changes to ETI's current base rates as a result of this proceeding.

55. Agreement as to Appeal Rights: The parties agree that ETI is not waiving its right to appeal the Commission's final order to the courts on any issues that are not resolved by settlement in this docket. All parties reserve their rights under applicable state and federal law.

56. Proposed CGS Program Tariff: The proposed CGS program tariff (the CGS rider), which is attached to the May 17 settlement as Attachment 1, is agreed to by the parties and represents the CGS program as set out in the preceding Findings of Fact.

57. The Commission makes the following findings regarding the five issues within Section II.B.2. of the May 17 settlement:

A. The appropriate date upon which ETI is authorized to begin accruing CGS program implementation and administration costs is the date that the CGS Rider implemented.

B. In the event there are no subscribers to the CGS program, it is reasonable and appropriate for unrecovered implementation and administration costs accrued to the CGSC rider will be charged to the LIPS and LIPS-TOD customers, the customer class that the program was designed to benefit.

C. It is not appropriate for ETI to recover interest on the unrecovered balance of the CGSC rider charges.

PUC Docket No. 38951 Order Page 26 of 27

D. It is not appropriate for there to be an offset to the CGSC rider for amounts included in rates in Docket No. 39896.

E. The Commission declines to address at this time the amount to be recovered as implementation and administration costs because such amount is not known at this time.

V1. Conclusions of Law 1. The Commission has jurisdiction and authority over this proceeding pursuant to PURA §§ 14.001 and 39.452(b).

2. PURA § 39.452(b) does not allow for the recovery of lost revenue or embedded generation costs.

VII. Ordering Paragraphs 1. The Commission adopts each of the three stipulation and settlement agreements filed on January 20, 2012, April 30, 2012, and April 18, 2012.

2. The Commission adopts each of the provisions of the stipulation and settlement agreement filed on May 17, 2013, except for section II.B.2, pertaining to deferring decisions on issues related to (a) the date ETI uses to start accruing implementation costs, (b) whether rider CGSC will also recover interest on unrecovered costs, (c) whether any historical costs billed to the CGS project code that are currently in base rates should be removed from base rates, credited, and recovered through rider CGSC, and (d) who pays if there are no subscribers. Those issues are resolved as set forth in this order. Accordingly, the Commission adopts in part and rejects in part the May 17 settlement as set forth in this order.

3. The CGS rider, attached to the May 17 stipulation and settlement agreement, is approved as of the date of this order. ETI shall file a clean CGS rider tariff in this docket within 10 days of the date of this order.

4. In the event there are no subscribers to the CGS program, unrecovered implementation and administration costs accrued to the CGSC rider will be charged to the LIPS and LIPS-TOD customers, the customer class that the program was designed to benefit.

PUC Docket No. 38951 Order Page 27 of 27

5. ETI is not authorized to recover interest on the unrecovered balance of the CGSC rider charges.

6. There shall be no offset to the CGSC rider for amounts included in rates in Docket No. 39896.

7. The Commission declines to address at this time the amount to be recovered as implementation and administration costs because such amount is not known at this time.

8. The date upon which ETI is authorized to begin accruing CGS program implementation and administration costs is the date that the CGS Rider is implemented.

9. ETI shall not file an application for the CGSC rider earlier than six months after the CGS rider becomes effective. ETI shall file an application for the CGSC rider in accordance with the agreement approved by this order.

10. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general or specific relief, if not expressly granted, are denied.

SIGNED AT AUSTIN, TEXAS the g L day of July 2013

PUBLIC UTILITY COMMISSION OF TEXAS

DONNA L. NELSON, CHAIRMAN

NNETH W. ANDE ., COMMISSIONER

V

q:\cadm\orders\fmal\38000\38951 fo.docx

DOCKET NO. 38951 ` APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY CO^YIIVIIS(SIv INC. FOR APPROVAL OF § COMPETITIVE GENERATION SERVICE § TARIFF (ISSUES SEVERED FROM § DOCKET NO. 37744) OF TEXAS

TEXAS INDUSTRIAL ENERGY CONSUMERS' LIST OF UNSETTLED ISSUES AND REQUEST FOR PROCEDURAL SCHEDULE

Texas Industrial Energy Consumers (TIEC) submits the following list of unsettled issues and request for a procedural schedule.

1. PRELIMINARY ISSUES AND REQUEST FOR PROCEDURAL SCHEDULE

TIEC's list of unsettled issues in Section II below reflects the common language that has been agreed upon by the parties to identify the remaining unsettled CGS issues. The parties have worked in good faith to identify the remaining contested issues related to implementation of a CGS program. The parties were not able to agree on the procedures for resolving these contested issues, however, and thus are filing separate pleadings. While TIEC believes that it may be more expeditious for the Commission to take up all of the unresolved issues at once, TIEC is not opposed to the other parties' preference to have the Commission first address certain preliminary contested issues, if the Commission so desires. Preliminary issues could include the following:

A. Unrecovered Costs

In TIEC's view, this issue dwarfs all others and has been the primary impediment to a workable CGS program from the outset. The position of TIEC (and others) at the hearing in this matter during the summer of 2010 was that Entergy had not shown that there would be any unrecovered costs (other than potential administrative costs) as a result of the CGS program. Entergy, on the other hand, indicated that there would be a substantial amount of unrecovered costs, at one point asserting that it could be as much as $75 million. The potential magnitude of that issue is substantially reduced given the parties' progress on (1) a cap on the CGS program and (2) procedures to firm up the capacity provided by CGS suppliers so that it would be counted as firm capacity by the Entergy system. Nonetheless, the dispute remains concerning whether there would be any unrecovered costs and, if so, the amount.

2l AUS 647538.3

The CGS statute essentially provided that retail customers who choose to take CGS service would pay an unbundled rate for transmission and ancillary services, but would obtain their generation from a competitive source.' ETI would purchase electricity from the identified source and provide it to the CGS customer. TIEC's position has been that Entergy would be fully compensated for the unbundled transmission and ancillary services through the CGS rate, and Entergy would be fully compensated for the cost of the electricity by the CGS customer paying the full cost of the electricity bought on its behalf from the CGS supplier. Entergy's position, on the other hand, has been that it would suffer lost revenues that it would otherwise receive if the CGS customer were a full bundled customer, and that Entergy's other customers should be required to pay Entergy for those lost revenues.

If the Commission desires to resolve this issue as a preliminary matter, the Commission should receive limited additional evidence. The pre-filed testimony submitted in this case in late 2009 or early 2010 no longer accurately reflects the facts, and the Commission should base its decision on the actual facts as they exist today. Notably, the evidentiary record that was developed in Docket No. 37744 was based on ETI's proposal for an energy-only program, not an energy and capacity-based program as reflected in the parties' list of settled issues. TIEC does not anticipate that additional evidence would be lengthy, and it is possible that the parties could stipulate to key facts rather than submit testimony. In any case, the items on which the Commission would need evidence include the following:

• The Entergy Operating Committee's recognition that, assuming certain conditions are met, capacity provided by a CGS supplier could be counted as system capacity, thereby reducing Entergy's capacity requirements.

• The value of the capacity provided by the CGS supplier. • The fact that ETI's load growth since base rates were set is greater than the proposed capped amount of CGS load. As a result, the CGS program as capped would not result in any reduction in generation-related revenues for ETI, but would simply reduce the amount of ETI's load growth.

• Operational savings that would accrue to ETI's customers from firming up Qualified Facility (QF) energy puts by using them as a source of 24 by 7, base load capacity.

• What impact, if any, joining MISO would have on a CGS program.

'See PURA § 39.452(b).

2

AUS.647538.3

Key facts on the above issues are not in the record at this time, and TIEC submits that the Commission cannot make an informed decision in this case without them. Accordingly, TIEC would request an opportunity for the parties to submit record evidence on these issues in the form of stipulated facts, facts administratively noticed, or testimony on limited issues.

B. Responsibility for Paying any Unrecovered Costs

If the Commission determines that there are no unrecovered costs, then this is not an issue. If, however, the Commission determines that there are unrecovered costs, then Entergy is entitled under the statute to recover any such costs and the Commission would have to determine how any such costs will be recovered.

C. Eligible CGS Customers

There are issues about whether eligibility for CGS service should be limited to certain rate classes, as ETI proposed, or should be available to all customers who can meet the necessary metering requirements, including customers who may aggregate load.

The parties differ on the issue of whether the unsettled issues can be resolved based on briefing on the existing record or whether, in addition to briefing, it may be appropriate for the Commission to take administrative notice of certain facts and/or accept limited additional evidence relevant to the settled and unsettled issues. TIEC's position is that the Commission should establish a procedural schedule that would allow the Commission to take notice of facts and/or accept limited additional evidence relevant to the CGS issues, as well as briefing.

The need for a procedural schedule to address evidentiary issues should be apparent from the face of the parties' joint list of settled issues. The Commission is currently faced with a substantially different CGS proposal than was originally proposed by ETI almost two years ago in Docket No. 37744. Further, considerable time has passed since the close of the record in Docket No. 37744, and the evidence that was developed in that record is now stale (e.g., forecasted load growth since the test year). It is TIEC's position that the work and effort that the parties have put into developing a revised CGS proposal will result in a much better program than the one proposed by ETI in Docket No. 37744. Because the parties did not develop the evidence with the current proposal in mind, however, additional evidence is necessary to provide

3

AUS 647538.3 information to the Commission that it could not otherwise consider based on the existing

evidentiary record.

II. LIST OF UNSETTLED ISSUES

TIEC identifies specific unsettled issues, as follows:2

A. Unrecovered Costs3

B. Who are eligible CGS customers

C. Who is responsible for paying for any unrecovered costs

D. Unresolved issues related to recognition of CGS supply as firm capacity include4:

1) Terms and conditions necessary for the CGS program to comply with capacity planning and acquisition principles under the Entergy System Agreement

2) CGS Supply Contract minimum size

3) Whether CGS Customer aggregation should be permitted

4) Cost responsibility for transmission upgrades

5) Commercial CGS Supply Agreement terms and conditions

E. Cap on CGS load - the level of an overall cap on the amount of customer load that would be included in the CGS program (i.e., 80MW to 150MW)5

F. Appropriateness of using load growth as an offset to any unrecovered costs

G. Capacity value of the CGS capacity product

H. CGSC costs:

2 These descriptions are meant to be high level, and do not include all the component issues which affect the controversy surrounding these matters.

3 The parties disagree as to whether this issue is: "The definition and calculation of any unrecovered costs" or instead "the definition, existence, and calculation of any unrecovered costs." TIEC's position is that the latter description of the issue is appropriate.

4 ETI maintains that matters such as these listed in Section II A fall within the exclusive jurisdiction of the FERC. If ETI and the Parties can reach an agreed resolution of these issues, the jurisdictional question will be avoided.

5 ETI maintains that matters such as these fall within the exclusive jurisdiction of the FERC. If ETI and the Parties can reach an agreed resolution of these issues, the jurisdictional question will be avoided.

4

AUS 647538.3 1) Recovery of CGSC costs should there be no CGS participants

2) Determination of the appropriate starting date for incurring recoverable CGSC costs

3) Whether CGSC costs should earn carrying costs

1. Whether a form contract is required for the successful implementation of the CGS program

III. CONCLUSION

For the above reasons, TIEC requests that the Commission adopt a schedule to allow additional evidence and briefing on the unsettled issues.

Respectfully submitted, ANDREWS KURTH LLP

Rex D. VanMiddlesworth State Bar No. 20449400 Meghan Griffiths State Bar No. 24045983 111 Congress Avenue, Suite 1700 Austin, Texas 78701 (512) 320-9200 (512) 320-9292 Fax

ATTORNEYS FOR TEXAS INDUSTRIAL ENERGY CONSUMERS

CERTIFICATE OF SERVICE

I, Meghan Griffiths, Attorney for TIEC, hereby certify that a copy of the foregoing pleading was served on all parties of record in this proceeding on this 1 st day of November 2011 by hand-delivery, facsimile, electronic mail and/or FirstCla,4, U.S. Mail, Postage Prepaid.

5

AUS•647538.3

PUC DOCKET NO. 38951

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION INC. FOR APPROVAL OF § COMPETITIVE GENERATION § SERVICE TARIFF ( ISSUES SEVERED § FROM DOCKET NO. 37744) § OF TEXAS ..^t. .._.,.

UNOPPOSED STIPULATION ON UNRESOLVED ISSUE NO. 3?% ^ ,.

C, All Parties except Entergy Texas, Inc. (ETI) have reached an agreement on the^"e bf who is responsible for paying for any unrecovered costs. ETI does not join in this stipu^`'aAYn, ro but does not oppose the resolution proposed by the other Parties. The proposed resolution is tl*,

11

to the extent there are costs unrecovered as a result of the implementation of a CGS tariff, those costs should be borne soley by customers taking service under the CGS tariff.

The signatories request that the Commission resolve Issue No. 3 on the above basis and are authorized to represent that ETI does not oppose this request.

Staff of the Public Utility Commission of Texas, the Steering Committee of Cities Served by ETI, Kroger Company, Office of Public Utility Counsel, State of Texas' agencies and institutions of higher education through their duty authorized representatives, Texas Industrial Energy Consumers, and Wal-Mart Stores Texas, LLC and Sam's East, Inc.

CITIES OF ANAHUAC, BEAUMONT, BRIDGE CITY, CLEVELAND, CONROE, GROVES, HOUSTON, HUNTSVILLE, MONTGOMERY, NAVASOTA, NEDERLAND, OAK RIDGE NORTH, ORANGE, PINE FOREST, PINEHURST, PORT ARTHUR, PORT NECHES, ROSE CITY, SHENANDOAH, SILSBEE, SOUR LAKE, SPLENDORA, VIDOR, AND WEST ORANGE

By: Stephen Mac

Date: April 13, 2012

OFFICE OF PUBLIC UTILITY COUNSEL

By: Sara J. Ferris

Date: April 13, 2012

STAFF OF THE PUBLIC UTILITY COMMISSION OF TEXAS

By: Brennan Foley

Date: April 13, 2012

TEXAS INDUSTRIAL ENERGY CONSUMERS

By: Rex anM' lesworth Meghan Griffiths

Date: April 13, 2012

THE KROGER COMPANY

By.

Kurt J. Boehm

Date: April 13, 2012 --^

WAL^MART STO4S TEXAS, LLC AND SAM'S EAST, INC.

Rick D. Chamberlain

Date: April 13, 2012 /%^' _.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 91

DOCKET NO. 38951

APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR APPROVAL OF § COMPETITIVE GENERATION § PUBLIC UTILITY COMMISSION SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) § OF TEXAS

SUPPLEMENTAL DIRECT TESTIMONY

OF

PHILLIP R. MAY

ON BEHALF OF

ENTERGY TEXAS, INC.

JANUARY 26, 2012

38 r

-----~~------------------------------------------------~

ENTERGY TEXAS, INC.

SUPPLEMENTAL DIRECT TESTIMONY OF PHILLIP R. MAY DOCKET NO. 38951

TABLE OF CONTENTS

Page

I. Introduction and Qualifications 1

II. Purpose 1

Ill. CGS Unrecovered Costs (Definition and Calculation) 5 IV. Who Pays For CGS Unrecovered Costs 17

v. Who Is Eligible For CGS Service 19

VI. Conclusion 23

EXHIBITS

Exhibit PRM-1 LIPS Embedded Production Cost Docket No. 37744

Exhibit PRM-2 LIPS Embedded Production Cost Docket No. 39896

Exhibit PRM-3 MSS-1 Offset to CGS Unrecovered Costs

Exhibit PRM-4 Net CGS Unrecovered Costs

Entergy Texas, Inc. Page 1 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 I. INTRODUCTION AND QUALIFICATIONS

2 Q. PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS.

3 A My name is Phillip R. May. I am employed by Entergy Services, Inc.

4 ("ESI") as the Vice President, Regulatory Services. My business address

5 is 639 Loyola Avenue, New Orleans, Louisiana 70113.

6

7 Q. ON WHOSE BEHALF ARE YOU TESTIFYING?

8 A I am testifying on behalf of Entergy Texas, Inc. ("ETI" or the "Company").

9

10 Q. ARE YOU THE SAME PHILLIP MAY WHO FILED TESTIMONY IN THIS

11 PROCEEDING REGARDING THE COMPETITIVE GENERATION

12 SERVICE PROGRAM?

13 A Yes.

14

15 II. PURPOSE

16 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

17 A My testimony will address the three "threshold" issues 1 summarized as:

18 1) what is the definition and calculation of CGS unrecovered costs; 2) who

19 should pay for the CGS unrecovered costs; and 3) who is eligible for

20 participating in the CGS program.

These issues were identified in The Joint Parties List of Unsettled Issues and Issues Contingent on a Commission Determination of Unsettled Issues, filed in this docket on November 1, 2011. The Commission authorized submission of further evidence on these issues at its December 8, 2011 open meeting.

Entergy Texas, Inc. Page 2 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 Q. DO YOU SPONSOR ANY EXHIBITS IN THIS FILING?

2 A. Yes. I sponsor the exhibits listed in the Table of Contents to my

3 testimony.

4

5 Q. WILL ANY OTHER WITNESSES ADDRESS CGS ISSUES IN

6 SUPPLEMENTAL DIRECT TESTIMONY?

7 A. Company witness Andrew J. O'Brien with ESI's System Planning and

8 Operations group ("SPO") will provide testimony supporting certain of the

9 issues I address.

10

11 Q. WHAT IS YOUR UNDERSTANDING AS TO THE PURPOSE OF THE

12 CGSPROGRAM?

13 A. The CGS program, as provided for in its enabling legislation and as

14 currently being discussed by the parties to this proceeding, is intended to

15 provide a specific subset of customers ("CGS Customers") with the ability,

16 consistent with the requirements of federal law and FERC tariffs including

17 the Entergy System Agreement, to obtain generation service from an

18 alternative supplier. In order to accomplish this objective, to address the

19 Commission's concerns regarding cost shifting under the program, and to

20 address other significant limitations imposed by the legislation (including

21 the requirement that the CGS program not create a conflict with Federal

22 law), the parties to this proceeding have engaged in extensive

Entergy Texas, Inc. Page 3 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 negotiations and arrived at a tentative solution to at least some aspects of

2 the CGS program design.

3 Under this collaborative proposal, customers eligible for CGS

4 service will contract with a CGS Supplier, which must be a Qualified

5 Facility ("QF") as defined by Rate Schedule LQF in ETI's service territory,

6 for a negotiated level of CGS capacity ("Supplier-Customer Contract").

7 ETI will not be a party to this contract; however, the Supplier/OF ("CGS

8 Supplier"), based on the Supplier-Customer Contract, will then enter into a

9 CGS Purchase Agreement with the Company for the same level of

10 capacity as in the Supplier-Customer Contract. The capacity supplied by

11 the CGS Purchase Agreement will take the form of a 24/7 unit contingent

12 product. Upon fulfillment of other as-yet unresolved conditions in a

13 manner satisfactory to the Entergy Operating Committee, that committee

14 has agreed to recognize that the CGS Purchase Agreement can provide

15 firm capacity (or, in the terms of the Entergy System Agreement,

16 "capability") to the Entergy System. 2

17 ETI will not make a capacity payment directly to the CGS Supplier.

18 Instead, ETI will provide a credit to the CGS Customer equal to ETI's

2 The parties to the case, including ETI, have not reached agreement on all matters necessary to establishment of a CGS program that includes such a capacity product. Matters yet to be unresolved are listed in the "Agreed List of Unsettled Issues and Issues Contingent on a Commission Determination of Unsettled Issues" referenced earlier in this testimony. By providing this testimony, ETI does not in any manner waive its rights to fully contest and independently assert its rights regarding any and all matters that remain in dispute among the parties. ETI presents this testimony solely for the purpose of facilitating the Commission's resolution of the threshold issues listed above, which may facilitate further efforts by the parties to resolve remaining contested issues surrounding the design of the CGS program and tariffs.

Entergy Texas, Inc. Page 4 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 embedded production cost (measured in $/kW/month) for that customer

2 times the CGS Supplied Capacity (kW). Any compensation for the CGS

3 capacity to the CGS Supplier is paid by the CGS Customer pursuant to

4 the terms of a separate Supplier-Customer Contract. The tentative terms

5 and conditions I have laid out here, among others, are included in Section

6 I of the CGS Stipulated Matters and Stipulated Facts filed by the parties to

7 this proceeding on January 20, 2012.

8

9 Q. IS THE INTENT OF THE CGS PROGRAM TO CREATE A CAPACITY

10 MARKET FOR ETI?

11 A. No. The CGS program is not intended, or needed, as a means to fulfill

12 ETI's resource needs and the Company would resist any effort to place a

13 value on CGS capacity based on an alleged resource need for the

14 program. To the contrary, the CGS program, as I noted above, is

15 designed as a means whereby a limited class of eligible customers could

16 gain access to an alternative source of generation apart from that offered

17 by ETI.

18 The Entergy system has and will continue to plan for and acquire

19 short-term, limited-term and long-term resources needed by ETI to reliably

20 serve its Texas customers. However, if implemented properly and

21 consistent with applicable legal requirements, the CGS program could

22 provide a relatively modest amount of additional capacity for the Entergy

l

Entergy Texas, Inc. Page 5 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 System. As discussed below, however, this resource would come with

2 unique risks and limitations.

3

4 Ill. CGS UNRECOVERED COSTS (DEFINITION AND CALCULATION)

5 Q. PLEASE PROVIDE AN OVERALL DEFINITION OF UNRECOVERED

6 COSTS.

7 A. PURA § 39.452(b), which provides the statutory authority for the CGS

8 program, provides that "The tariffs subject to this subsection may not be

9 considered to offer a discounted rate or rates under Section 36.007, and

10 [ETI's] rates shall be set, in the proceeding in which the tariff is adopted, to

11 recover any costs unrecovered as a result of the implementation of the

12 tariff." The statute's definition of unrecovered costs is broad: "any costs

13 unrecovered as a result of the implementation of the tariff." There are two

14 categories of costs within this statutory provision: 1) implementation and

15 administration cost ("lA Cost") associated with this program - this would

16 include the cost of any billing systems, administration cost of the program

17 going forward, and any cost incurred to develop and implement the

18 program in the first instance; and 2) unrecovered costs ("Unrecovered

19 Costs") that results due to CGS Customers no longer taking firm service

20 from the Company. The lA Cost and its recovery is not one of the three

21 threshold issues and will not be addressed in this testimony.

22 Unrecovered Costs should be defined as the embedded production

23 costs and any other related base rate costs that would have been

Entergy Texas, Inc. Page 6 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 recovered through traditional rates charged to CGS Customers that will no

2 longer be recovered from the CGS Customers. These are costs that the

3 CGS Customers would have paid under their traditional rate schedules if

4 they had not switched to the CGS program. Because these customers

5 have switched to the CGS program, these embedded production costs

6 (less any potential offsets) would otherwise be unrecovered by ETI due to

7 implementation of the CGS program.

8

9 Q. IS THIS DEFINITION OF THE STARTING POINT FOR UNRECOVERED

10 COSTS CONSISTENT WITH THE ASSESSMENT OF UNRECOVERED

11 COSTS RECOGNIZED IN THE INITIAL EVIDENTIARY HEARING

12 REGARDING THE CGS PROGRAM?

13 A. Yes. In his Proposal For Decision, the ALJ reached the following

14 conclusion regarding the nature of unrecovered costs:

15 The ALJ agrees with ETI that PURA § 39.452(b) 16 requires that "the utility's rates shall be set, in the proceeding 17 in which the tariff is adopted, to recover any costs 18 unrecovered as a result of the implementation of the tariff," 19 and that the CGS legislation specifically authorized the 20 Company to recover any unrecovered costs as "a result of' 21 implementation of the CGS program. ETI is entitled to 22 collect unrecovered embedded generation costs and 23 any other related base rate costs as a result of customer 24 migration to the CGS program. 3

3 Docket No. 37744 (now severed into Docket No. 39851),Proposal for Decision ("PFD") at p. 22 (emphasis added).

q

Entergy Texas, Inc. Page 7 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 Although the ALJ believed that there might be offsets to these

2 unrecovered costs, he was clear in his recognition of embedded test year

3 generation costs as the starting point for the measurement of unrecovered

4 costs.

5

6 Q. WOULD IT BE APPROPRIATE TO ADOPT A DEFINITION OF

7 UNRECOVERED COSTS LIMITED TO WHAT YOU REFER TO ABOVE

8 AS THE lA COSTS?

9 A. No, it would not. When ETI's rates are set in a base rate proceeding, the

10 level of those rates is expressly determined so as to be sufficient to

11 recover the reasonable and necessary production-related costs (including

12 return on investment) that it incurred in a representative test year,

13 adjusted for known and measureable changes. Those rates are further

14 designed so that each of the Company's customers' rates contributes their

15 share of those costs, consistent with principles of cost causation. As the

16 ALJ stated, "the ALJ agrees that ETI's revenue requirement is based on

4

17 and designed to recover such [embedded production] costs."

18 When, for example, a Large Industrial Power Service ("LIPS")

19 customer shifts part of its load to CGS service, it avoids payment of the

20 share of ETI's embedded test year production costs allocated to it when

21 base rates were set, because that load is now served through the CGS

4 /d.

fo

Entergy Texas, Inc. Page 8 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 program. If ETI must absorb this loss, then it has failed to recover a part

2 of its production costs that its base rates were designed to recover. The

3 effect is the same as if the Commission had granted that particular

4 customer a discount rate for a portion of the service. As a general rule,

5 PURA requires that the utility, rather than its customers, absorb losses

6 associated with discount rates. 5 As quoted above, however, PURA §

7 39.452(b) is an exception to this rule, and expressly prohibits the CGS

8 program tariffs from being treated as offering a discount rate.

9 The Company does not support proposals that shift risks or losses

10 onto ETI. Any such proposal results in only a small group of customers

11 obtaining a benefit at the expense of the Company, which is nothing more

12 than a discount rate in disguise.

13

14 Q. HOW IS THE CGS RATE FOR CUSTOMERS STRUCTURED, BASED

15 ON THE CGS PROGRAM DESIGN DISCUSSED BY THE PARTIES

16 DURING THEIR SETTLEMENT NEGOTIATIONS?

17 A. The proposed CGS program provides a $/kW credit for the amount of

18 CGS capacity supplied by the CGS Customer. 6 The parties' January 20

19 Stipulation affirms (Stipulation I.C.3) that this $/kW credit should be based

20 on the embedded production cost from the most recent ETI general rate

5 PURA § 36.007.

6 This credit approach is different from the ETI proposal at the time of the initial CGS hearing to implement unbundled rates and is administratively more efficient. See Section I.C of the Stipulation of Facts and Other Matters filed January 20, 2012.

Entergy Texas, Inc. Page 9 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 case for the class of customers eligible to participate in the program. For

2 example, based on ETI's last full base rate case (Docket No. 37744), for

3 the LIPS rate class, this value is $6.84/kW as shown on Exhibit PRM-1.

4 Based on the Company's most recent filed base rate case in Docket No.

5 39896, again for the LIPS class, this value is $7.77/kW as shown on

6 Exhibit PRM-2. This $/kW credit recognizes that the CGS Customers will

7 be supplying a portion of their own production-related requirements via the

8 CGS supplied capacity and not receiving the generation supply associated

9 with ETI production costs for that amount of capacity supplied.

10

11 Q. CAN YOU FURTHER DISCUSS WHY EMBEDDED PRODUCTION COST

12 IS THE APPROPRIATE STARTING POINT FOR DETERMINING THE

13 CGS UNRECOVERED COSTS?

14 A. As I explained earlier, embedded production cost is the appropriate

15 starting point because that is the amount that the CGS Customer will

16 receive as a credit and will thereby avoid by taking some level of service

17 under the CGS program, instead of continuing to take that level of service

18 under its historical rate schedule. As described above, this credit is based

19 on the embedded production cost incurred to serve that customer, and

20 equates to the amount of contribution to fixed production costs previously

21 provided by the CGS Customers, and thus is the starting point for

22 calculating the CGS Unrecovered Costs.

Entergy Texas, Inc. Page 10 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 Q. ARE THERE ANY POTENTIAL OFFSETS TO THIS STARTING POINT

2 FOR DETERMINING UNRECOVERED COSTS?

3 A. Yes. The current CGS program proposal under discussion among the

4 parties is based upon energy supplied via a firm 24/7 product as described

5 earlier in my testimony, and by ETI witness O'Brien. The Entergy

6 Operating Committee has indicated that such a product may, under

7 appropriate conditions, be included in ETI's generating capability for

8 purposes of the Entergy System Agreement accounting and resource

9 planning. Provided that remaining outstanding issues regarding "firming

10 up" CGS capacity can be resolved in a manner that is consistent with the

11 Operating Committee parameters, the amount of capacity associated with

12 the CGS Supplier-Customer Contracts will - unlike the capacity

13 associated with the initial CGS proposal originally filed in Docket No.

14 37744 - be considered ETI capability in the determination of ETI's

15 payments pursuant to Entergy System Agreement Service Schedule

16 MSS-1 (Reserve Equalization). 7 The inclusion of CGS capacity in the

17 calculation of ETI's Schedule MSS-1 obligations is expected to reduce

7 MSS-1 obligations are calculated by comparing an Entergy Operating Company's ("OPCO's") owned or controlled capability to the amount of capability that an OPCO should own or control if it owned or controlled an amount of capability equal to its share of the System's load. A company that owns or controls less capability that it should be responsible for is known as a "short" company, and is required to compensate those OPCOs that are "long" for the use of the long Company's reserves. ETI is a short OPCO, which means that adding capability that the Operating Committee has determined to be eligible to ETI's total company capability will reduce ETI's MSS-1 payments.

Entergy Texas, Inc. Page 11 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 ETI's Schedule MSS-1 payments to the other OPCOs and, as such, will

2 reduce ETI's overall revenue requirement.

3

4 Q. HAVE YOU CALCULATED THE EFFECT OF CGS CAPACITY ON ETI'S

5 SCHEDULE MSS-1 PAYMENTS?

6 A. Yes. Exhibit PRM-3 shows the calculation of the effects of CGS capacity

7 on ETI's Schedule MSS-1 obligations, based on a recent Intra System Bill.

8 Under Schedule MSS-1, when capacity is added incrementally to the

9 system each OPCO is responsible for their responsibility ratio share of this

10 capacity. When an OPCO is adding capacity, in this case ETI adding

11 CGS capacity, the OPCO is comparatively longer and thus reduces its

12 Schedule MSS-1 obligation. In this example, the reduction amounts to

13 $3.097/kW/month and would be an offset to the CGS Unrecovered Costs

14 starting point ($6.84/kW/month under current rates) discussed above.

15

16 Q. ARE THERE ANY OTHER OFFSETS TO THIS UNRECOVERED COSTS

17 STARTING POINT?

18 A. Yes. Under the settlement terms tentatively agreed to by the parties,

19 other offsets would be the Fixed Cost Contribution Fee and the Unserved

20 Energy O&M adder charges set out in the parties' January 20 Stipulation

21 (Stipulations I.E.1-3, I.F.5). The Fixed Cost Contribution Fee is a fixed

22 $/kW fee per month that each CGS Customer will pay and for which the

23 revenues received by ETI will go to offset the CGS Unrecovered Costs.

Entergy Texas, Inc. Page 12 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 The Unserved Energy O&M adder is a fee the CGS Customers may or

2 may not pay depending on whether the CGS capacity was actually

3 supplied to ETI or not. Again, revenues received by ETI from this O&M

4 adder will go to offset the CGS Unrecovered Costs.

5

6 Q. OTHER PARTIES HAVE ARGUED THAT LOAD GROWTH SHOULD BE

7 AN OFFSET TO CGS UNRECOVERED COSTS. PLEASE COMMENT.

8 A It has been suggested previously that revenues associated with load

9 growth should be an offset to unrecovered costs. Such a suggestion is

10 inconsistent with the provision of the law that states: " ... and [ETI's] rates

11 shall be set, in the proceeding in which the tariff is adopted, to recover any

12 costs unrecovered as a result of the implementation of the tariff." This

13 language requires that the program be implemented within the base rate

14 case in which the tariff is developed, in order that the embedded costs that

15 are avoided by the CGS Customer would be readily identifiable. Load

16 growth is not a concept that can be appropriately applied within the

17 context that rates are set in Texas based upon an historical test year with

18 known and measureable costs. Load growth adjustments have gained

19 acceptance in Texas in some instances as a consideration in offsetting

20 incremental costs, and should not be used to offset the embedded costs

21 we are dealing with in this case.

22 Also, as referenced above, unrecovered costs are costs that would

23 have been recovered but for the CGS program or "as a result of the

Entergy Texas, Inc. Page 13 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 implementation of the tariff." Load growth is not dependent on the CGS

2 program and would have occurred regardless of the CGS program.

3 In addition, any potential offset associated with load growth would

4 have to be limited to load growth associated with the generation function.

5 Any load growth associated with the distribution function, for example,

6 would be earmarked for the Distribution Cost Recovery Factor ("DCRF") in

7 accordance with the rules adopted to implement the DCRF. I would add

8 that load growth in the DCRF example is used to offset incremental costs

9 incurred since the last base rate case, not to offset embedded cost.

10 Lastly, any load growth adjustment to the Unrecovered Costs would

11 also need to recognize that ETI's generation cost continues to increase.

12 More specifically, simply adjusting for the effect of load growth on ETI

13 revenues associated with the generation function would not recognize the

14 other effects on the generation function such as cost increases. The

15 result of such an approach would be that revenues that would otherwise

16 be available to offset increases in purchased power cost for customers,

17 would instead be dedicated to the CGS program. The result of dedicating

18 the growth in revenues to the CGS program would be the purchased

19 power costs to be recovered from all customers, save for those taking

20 CGS service, would increase. This inappropriate outcome further justifies

21 the conclusion that load growth, to the extent it is utilized, should only

22 offset incremental costs, and not embedded costs.

Entergy Texas, Inc. Page 14 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 Q. WHAT WAS THE COMPANY'S EARNED ROE IN ITS LAST EARNINGS

2 MONITORING REPORT?

3 A. The Earnings Monitoring Report for the calendar year 2010 showed the

4 Company's earned ROE was 7.22%, compared to an authorized return of

5 10.125%.

6

7 Q. HOW DOES THE COMPANY'S EARNED ROE RELATE TO A LOAD

8 GROWTH ADJUSTMENT?

9 A. If the Company is not earning its allowed ROE it should not be required to

10 make a load growth adjustment. Any load growth adjustment would

11 simply further reduce the earned ROE below the allowed level. An earned

12 ROE below the allowed ROE is an indication that the Company's cost has

13 increased at a higher rate than any load growth or increase in sales.

14

15 Q. IS THERE ANOTHER MORE EFFECTIVE APPROACH TO ADDRESS

16 THESE LOAD GROWTH AND COST INCREASE ISSUES?

17 A. Yes. In Project 39246, the Commission is considering the development of

18 a purchased power recovery ("PPR") rider applicable to ETI and other

19 Texas vertically integrated utilities. The PPR rider envisioned by ETI

20 recognizes the benefits of load growth because it reflects the total

21 revenues collected by the PPR rider. Thus, if revenues collected from the

22 PPR rider have increased due to increased sales, this increase would

23 automatically be reflected in updates to the PPR rider via the over( under)-

Entergy Texas, Inc. Page 15 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 recovery provision, thus reducing the amounts customers would otherwise

2 pay for purchased power costs.

3 In addition, ETI's envisioned PPR rider reflects the total purchased

4 power cost8 of the Company, thus it would automatically reflect any

5 fluctuations (up or down) caused by increases or decreases in any

6 purchased power cost component via the over(under)-recovery provision.

7 Due to the manner in which the PPR should function, if the

8 acquisition of CGS capacity truly reduces ETI purchases or reduces

9 MSS-1 payments made by ETI, these reductions would be reflected in the

10 actual cost collected through the PPR rider and would not need to be

11 separately identified and quantified. Likewise any debate on the value of

12 load growth or its quantification as an offset would no longer be necessary

13 because all increased revenues caused by the increased sales, whatever

14 their level, would be reflected in the over/under recovery provision of the

15 PPR rider. For example, if sales increased by 5% and the purchased

16 power cost decreased 3% in the same period, both of these effects would

17 be reflected as reductions in the PPR rider, thereby automatically

18 offsetting CGS Unrecovered Costs included in the PPR. This would

19 eliminate any need to debate the extent to which CGS Capacity provided

20 value that should offset CGS Unrecovered Costs, because any such value

8 The purchased power cost reflected in ETI's envisioned PPR rider would also include the cost associated with Entergy System Agreement Service Schedule MSS-1.

Entergy Texas, Inc. Page 16 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 would be captured in the PPR rider along with all other purchased power

2 cost.

3

4 Q. IS THERE ANY CAPACITY COST VALUE, OTHER THAN THAT

5 ASSOCIATED WITH SCHEDULE MSS-1, THAT CAN BE USED TO

6 OFFSET THE CGS UNRECOVERED COSTS?

7 A No. As demonstrated in the forgoing discussion, an offset is appropriate

8 only if the CGS program results in an actual reduction to ETI's revenue

9 requirement. Accordingly, there are no grounds for an additional offset

10 other than those previously discussed.

11 Further, as discussed by ETI witness O'Brien, many factors and

12 characteristics must be considered when valuing capacity costs, such as

13 the lack of flexibility, energy cost, firmness (unit contingent vs. system

14 contingent), term, size (level of MW), location and ability to reduce

15 operating constraints (reduction of QF put). A review of the characteristics

16 of the capacity that ETI will acquire as a result of the CGS program

17 indicates that the CGS capacity is not a product that would reasonably be

18 expected to have a high level of value.

(j

Entergy Texas, Inc. Page 17 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 Q. WHAT IS THE RESULTING NET CGS UNRECOVERED COSTS BASED

2 ON THE CGS UNRECOVERED COSTS STARTING POINT AND THE

3 OFFSETS YOU DISCUSS ABOVE?

4 A. Using the LIPS rate class as an example (and which ETI proposes should

5 comprise the CGS-eligible customers), Exhibit PRM-4 shows the

6 calculation of the net CGS Unrecovered Costs based on embedded cost

7 from Docket No. 37744 and ETI's filed case in Docket No. 39896 net of

8 the offsets I discussed above. The current net CGS Unrecovered Costs is

9 $2.643/kW/month based on current values from Docket No. 37744.

10 Based on the Company's filed case in Docket No. 39896 the CGS

11 Unrecovered Costs is $3.543/kW/month.

12

13 IV. WHO PAYS FOR CGS UNRECOVERED COSTS

14 Q, WHAT IS THE COMPANY'S PROPOSAL FOR WHO SHOULD PAY FOR

15 THE CGS UNRECOVERED COSTS?

16 A. The Company proposes that the CGS Unrecovered Costs should be

17 recovered from all non-CGS participating load. This is a slight

18 modification from the Company's direct case position in which the

19 Company was proposing that the CGS Unrecovered Costs should be

20 recovered from all non-CGS customers. 9 This modification recognizes

21 that there is a portion of a CGS Customer's load that is not supplied by the

9 See Docket No. 37744, Phillip R. May Direct Testimony filed on December 30, 2009, pages 14-15 and 21, (Bates No. 3-265-266 and 3-272); ETI's Initial Brief on Proposed CGS filed August 2, 2010, page 11; ETI's Reply Brief on CGS filed August 16, 2010, page 6.

Entergy Texas, Inc. Page 18 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 CGS program and for which the Company continues to supply generation.

2 This non-CGS participating load should be treated as any other customer

3 load for which ETI supplies generation resources.

4 As discussed by Company witness O'Brien in his supplemental

5 direct testimony, under appropriate conditions, CGS capacity can be

6 considered to be capability for ETI and the Entergy System. Therefore,

7 ETI's proposal for who should pay for Unrecovered Costs recognizes that

8 the proposed CGS firm capacity product is a generation resource, the cost

9 of which should be recovered from all customers.

10

11 a. WHY SHOULD A NEW CUSTOMER, WHO DID NOT EXIST PRIOR TO

12 THE CREATION OF THE CGS PROGRAM, HAVE TO PAY FOR

13 UNRECOVERED COSTS?

14 A. As stated above, the CGS capacity should be treated like any other supply

15 resource and be recovered from all customers whether new or existing.

16 Any other conclusion would imply that certain customer groups can select

17 specific ETI generation resources to satisfy their needs. For example, this

18 would imply that a new customer could elect to not pay for any River Bend

19 Station nuclear generation-related costs because the Company's

20 acquisition of power from the River Bend Station was made and approved

21 long before that customer became an ETI customer. Such a conclusion is

22 contrary to traditional ratemaking whereby customers' rates are based on

23 average cost pricing.

Entergy Texas, Inc. Page 19 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 Q. SHOULD THE LOADS OF NEW CUSTOMERS, WHO ARE ALSO CGS

2 CUSTOMERS, BE INCLUDED IN THE CALCULATION OF

3 UNRECOVERED COSTS?

4 A Yes. But for the CGS program, a new customer would contribute to the

5 Company's embedded production fixed cost based on current base rates.

6 However, because of the CGS program, the Company will not recover the

7 same level of fixed cost from the new customer had the CGS program not

8 been in effect.

9

10 V. WHO IS ELIGIBLE FOR CGS SERVICE

11 Q. WHAT IS THE COMPANY'S PROPOSAL FOR WHO SHOULD BE

12 ELIGIBLE FOR CGS SERVICE?

13 A The Company continues to propose that only the LIPS class of customers

14 be eligible for the CGS program. As stated in ETI's direct case, PURA

15 § 39.452(b) is not intended to extend a competitive generation tariff

16 offering to all customers. 10 The provision refers to "eligible customers"

17 rather than to "all customers." It is important to reiterate that the CGS

18 program is not a provision for retail customer choice, or for a retail pilot

19 project, as otherwise addressed in PURA Chapter 39. Given the

20 complexity of the CGS program, it is appropriate to set reasonable

10 See Docket No. 37744, Phillip R. May Direct Testimony filed on December 30, 2009, pages 10-12, (Bates No. 3-261-263).

Entergy Texas, Inc. Page 20 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 eligibility thresholds for CGS service. Moreover, the statutory language's

2 reference to protections for "manufacturers" who choose not to participate

3 in the program suggests an expectation that this is the type of customer

4 who otherwise will be participating. The Company continues to believe

5 that only large customers will have the size, sophistication, and capability

6 to make use of the CGS service. Second, LIPS customers already have

7 the interval data recorder ("lOR") metering in place that is technically

8 required for the program. Third, the administration and billing

9 requirements of the CGS program require a substantial amount of

10 additional systems work and on-going manual intervention from the

11 Company's Major Accounts Billing function. It cannot be easily or

12 inexpensively expanded past a relatively small number of CGS Customers

13 (customers/meters) without requiring a much larger system and personnel

14 investment. Potentials for expanding the program beyond the LIPS class

15 can be addressed in the annual reports to be filed by the Company but,

16 until it is shown that expansion beyond that class is workable and

17 appropriate, the eligible CGS Customers should be limited to the LIPS

18 class.

19

20 Q. COULD AGGREGATION ALLOW SMALLER CUSTOMERS TO QUALIFY

21 FOR THE CGS PROGRAM?

22 A. Theoretically, aggregation - by which I mean a group of customers

23 pooling their load for purposes of utilizing CGS service - could allow such

Entergy Texas, Inc. Page 21 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 customers to qualify. However, as stated in the Company's direct case

2 and above, the CGS program is not intended to be retail open access. 11

3 Implementing the CGS program with aggregation across all customer

4 classes, or even just some classes in addition to the LIPS class, is

5 tantamount to retail open access, as there would be no limit on the retail

6 customers then "eligible" to participate in the choice of an alternative to

7 service from ETI. 12 In addition, on a more practical note, aggregation of

8 accounts raises complicated customer accounting and billing provisions. 13

9 The Company's billing system would require major modification or

10 potential replacement in order to aggregate accounts depending on the

11 number of accounts under the CGS program. Employee training on

12 aggregation and the ultimate billing system will be required. The cost of

13 any new billing system would have to be recovered from customers like

14 any other implementation and administration cost for the CGS program.

15 Moreover, certain provisions of this CGS program may require notification

11 /d.

12 Parties have agreed that it is reasonable at the outset of the CGS program to establish a cap on the amount of load that may subscribe to CGS service. However, the parties have not reached agreement on the amount of a cap beyond a range from 80 MW to 150 MW. See Stipulation of Facts and Other Matters filed January 20, 2012 (Stipulation II.B. 1-2).

13 The Company is assuming that if aggregation were allowed, an aggregator would be required to facilitate aggregation. The CGS product is a 24/7 firm product that requires the CGS Supplier to acquire firm network service. Examples of the complications associated with aggregation include: 1) if a customer who is part of a CGS aggregated group closes business, does this result in the entire aggregated group's CGS contract being terminated because the firm network resources no longer matches the aggregated groups CGS capacity?; 2) how can, or should, customers be added to an aggregate group because this would then exceed the existing CGS capacity and contracted firm network transmission service?; 3) how can the requirement for IDR metering and backup metering for each CGS Customer at their cost be fulfilled in the context of aggregation?; and 4) how would all such CGS Customers be converted to calendar month billing?

Entergy Texas, Inc. Page 22 of23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 to each CGS Customer or CGS Supplier to cease CGS supply. Providing

2 this notice to a large number of customers for a single supply is

3 impractical and not feasible.

4

5 Q. ARE THERE ANY OTHER ISSUES RELATED TO ELIGIBILTY THAT

6 SHOULD BE ADDRESSED?

7 A. Yes. As discussed in Company witness O'Brien's supplemental direct

8 testimony, it is appropriate to limit the number of CGS Supplier-Customer

9 Contracts that can be in effect at any point in time, or to set a minimum

10 contract size for each CGS Supplier-Customer Contract. Lastly, as

11 discussed above and as described in the parties January 20 Stipulated

12 Matters and Stipulated Facts, this CGS program is extremely complicated.

13 The Company therefore proposes that customers currently on either the

14 Rider to Rate Schedule LIPS for Interruptible Service ("Schedule IS") or

15 Economic As-Available Power Service ("Schedule EAPS") should not be

16 allowed to participate in the CGS program to satisfy any portion of their

17 firm load at this time. Customers on Schedules IS and EAPS already

18 have their loads split between firm and other service. Adding a further

19 split of what was firm service between CGS and what then remains for

20 firm service is a further complexity in billing and administration of the CGS

21 program that should be considered at a future date, once the Company

22 and its customers have the opportunity to gain experience in the basics of

23 the CGS program. Again, the potential for expanding the CGS program to

Entergy Texas, Inc. Page 23 of 23 Supplemental Direct Testimony of Phillip R. May Docket No. 38951

1 the IS and EAPS customers can be addressed in the annual reports to be

2 filed by the Company.

3

4 VI. CONCLUSION

5 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT

6 TESTIMONY?

7 A. Yes, at this time.

Exhibit PRM-4 Docket No. 38951 Page 1 of 1

Entergy Texas, Inc.

Net CGS Unrecovered Costs Based on LIPS Class $/kW/month

Line Item Docket No. 37744 Docket No. 39896 Source

Unrecovered Costs Starting Point LIPS CGS Credit ( Embedded Gen Rev Req) 6.84 7.74 Exhibits PRM-1 and PRM-2

Offsets 2 ETI MSS-1 offset for CGS 3.097 3.097 Exhibit PRM-3 3 Fixed Cost Contribution Fee 1.10 1.10 Stipulated Facts 4 Unserved Energy O&M Adder (a) (a)

6 Net Unrecovered Costs (b) 2.643 3.543 Line 1 - Line 2 - Line 3

Notes (a) Unserved Energy O&M Adder offset is dependent on the actual amount of unserved energy supplied hourly.

The resulting dollar value will go to offset the otherwise net unrecovered cost.

(b) This Net Unrecovered Costs rate would be multiplied by any CGS Supplied Capacity and then reduced by any Unserved Energy O&M Adder dollars received to determine the Net Unrecovered Cost dollars for each month.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 92 DOCKET NO. 38951

APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR APPROVAL OF § COMPETITIVE GENERATION § PUBLIC UTILITY COMMISSION SERVICE TARIFF (ISSUES SEVERED§ FROM DOCKET NO. 37744) § OF TEXAS

SUPPLEMENTAL REBUTTAL TESTIMONY

OF

PHILLIP R. MAY

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FEBRUARY 24, 2012

ENTERGY TEXAS, INC.

SUPPLEMENTAL REBUTTAL TESTIMONY OF PHILLIP R. MAY DOCKET NO. 38951

TABLE OF CONTENTS

Page

I. Introduction and Qualifications 1

II. Purpose 1

Ill. Loss of Revenues Versus Unrecovered Embedded Generation Costs 2

IV. Load Growth as an Offset to Unrecovered Costs 7

v. Allocation of Unrecovered Costs 18

VI. Eligible Customers For CGS Service 20

VIII. Conclusion 30

J

EXHIBITS

Exhibit PRM-1R ETI's Response to OPUC RFI1-4

Exhibit PRM-2R ETI's Response to TIEC RFI 1-8

Exhibit PRM-3R TIEC's Response to ETI RFI 1-5

Entergy Texas, Inc. Page 1 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 I. INTRODUCTION AND QUALIFICATIONS

2 Q. PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS.

3 A. My name is Phillip R. May. I am employed by Entergy Services, Inc.

4 ("ESI") as the Vice President, Regulatory Services. My business address

5 is 639 Loyola Avenue, New Orleans, Louisiana 70113.

6

7 Q. DID YOU PREVIOUSLY FILE TESTIMONY ON BEHALF OF ENTERGY

8 TEXAS, INC. ("ETI" OR THE "COMPANY") IN THIS PROCEEDING?

9 A. Yes, I did.

10

11 II. PURPOSE

12 Q. WHAT IS THE PURPOSE OF YOUR SUPPLEMENTAL REBUTTAL

13 TESTIMONY?

14 A. I will address certain comments and recommendations made by 1) Cities

15 witness Karl J. Nalepa, 2) Texas Industrial Energy Consumers witness

16 Jeffry Pollock, 3) the Office of Public Utility Counsel ("OPUC") witness

17 Clarence Johnson, 4) The Kroger Co. witness Neal Townsend, and

18 5) Wai-Mart Stores Texas, LLC and Sam's East, Inc witness Steve W.

19 Chriss. 1

20 Specifically, the subjects I will address are:

21 • the erroneous claim that ETI is not seeking to recoup unrecovered

22 costs resulting from the CGS program.

1 The Staff and State did not file any further testimony on the three threshold issues.

Entergy Texas, Inc. Page 2 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 • why load growth is not an appropriate offset to unrecovered costs,

2 • ETI's perspective on the determination of which customers should be

3 allocated responsibility for payment of unrecovered costs, and

4 • why it is unreasonable to expand beyond the LIPS class the types of

5 customers eligible for CGS service,

6 7 Q. DO YOU SPONSOR ANY EXHIBITS IN THIS FILING?

8 A. Yes. I sponsor the exhibits listed in the Table of Contents to my

9 testimony.

10 11 Q. WILL ANY OTHER WITNESSES ADDRESS CGS ISSUES IN

12 SUPPLEMENTAL REBUTTAL TESTIMONY?

13 A. Company witnesses Andrew J. O'Brien and J. Stephen Dingle with ESI's

14 System Planning and Operations group ("SPO") will also provide

15 Supplemental Rebuttal Testimony on certain issues.

16

17 Ill. LOSS OF REVENUES VERSUS UNRECOVERED EMBEDDED 18 GENERATION COSTS

19 Q. PLEASE SUMMARIZE THE POSITION PARTIES HAVE TAKEN

20 REGARDING THE COMPANY'S DESCRIPTION OF ITS

21 UNRECOVERED COSTS.

Entergy Texas, Inc. Page 3 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 A. Mr. Nalepa and Mr. Pollock take the position that the Company is seeking

2 recovery of "lost revenues," and that lost revenues are not the same as

3 unrecovered costs.

4

5 Q. MR. POLLOCK (PP. 18-19) AND MR. NALEPA (P. 8) CLAIM THAT

6 COURT AND COMMISSION PRECEDENTS HAVE ALREADY

7 REJECTED THE COMPANY'S POSITION IN THIS CASE BY

8 CONCLUDING THAT UTILITIES ARE NOT ENTITLED UNDER PURA TO

9 RECOUP "LOST REVENUES." WHAT IS YOUR RESPONSE?

10 A. Mr. Nalepa does not provide any indication of what precedent he is

11 referencing, so I am not in a position to respond to his contention. Mr.

12 Pollock references several Commission proceedings dealing with the

13 promulgation of the Commission's energy efficiency rule, and a court case

14 reviewing certain aspects of that rule. Mr. Pollock contends that these

15 precedents establish a principle that references to recovery of costs in

16 PURA do not contemplate recovery of lost revenues.

17 Before I turn to rebuttal of Mr. Pollock's suggestion, I note that

18 neither the Commission Staff nor the SOAH ALJ who was the first

19 impartial judge of these issues had any trouble concluding that ETI's

20 proposal was for the recovery of unrecovered embedded production

21 costs. The Staff, which has not indicated any change in position at this

22 juncture, concluded: "[i]mplementing the CGS tariff... allows CGS

23 customers to avoid certain generation-related costs, and therefore PURA

Entergy Texas, Inc. Page 4 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 § 39.452(b) permits ETI to recover these unrecovered costs."2 Similarly,

2 the ALJ concluded: "ETI is entitled to collect unrecovered embedded

3 generation costs and any other related base rate costs as a result of

4 customer migration to the CGS program."3

5 As for Mr. Pollock's arguments in his Supplemental Direct

6 Testimony, I am not a lawyer and do not intend to debate the merit of

7 Mr. Pollock's testimony as legal analysis per se. His analysis, however, is

8 irrelevant and off base because the Company in this proceeding seeks

9 only its statutory right to recoup the fixed production costs that it fails to

10 recover when a customer chooses CGS service over firm LIPS service.

11 The Company's production costs to serve all of its customers are

12 determined in a base rate case based on a representative test year (most

13 recently in Docket No. 37744), and every customer's share of those costs

14 are likewise determined in that same case. The Company's production

15 costs for the LIPS customers in Docket No. 37744 is $6.84/kW-month.

16 When one of those customers moves to CGS service, the Company no

17 longer recovers that $6.84 unit production cost from that customer; in the

18 words of the CGS statute, that cost is "unrecovered." Mr. Pollock points to

19 the fact that ETI's proposed CGSUSC tariff uses the term "lost revenues"

20 rather than "unrecovered costs." This difference in terminology is of no

2 Docket No. 37744, Staff Reply to Exceptions at p. 3. . See also /d., Staff Initial Brief at p. 3 (" ... unrecovered costs are the costs that the Ll PS customers who elect to participate in the CGS program would avoid paying ETI.").

3 Docket No. 377 44, Proposal for Decision at p.22.

l

Entergy Texas, Inc. Page 5 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 moment, however, because in terms of test year rate-setting principles, a

2 utility's revenue requirement and its cost of serving its customers are one

3 and the same.

4 In the court of appeals case cited by Mr. Pollock, it appears that the

5 court determined that the utility could not recover lost revenues on top of

6 the energy efficiency program costs that were the focus on the statutory

7 provision governing energy efficiency cost recovery. 4 Here, by contrast,

8 ETI seeks only recovery of the production costs that a CGS customer

9 avoids paying when it takes CGS service.

10 In addition, the statute governing the CGS program is unique, and

11 distinct from the energy efficiency statute, in that it prescribes that ETI is

12 entitled to recoup costs that are unrecovered due to implementation of the

13 CGS program, and requires that the implementation of the program not be

14 treated as though a discount rate is being put in place. Under PURA

15 § 36.007, if a utility grants a discount rate, it must absorb the "allocable

16 cost of serving those customers ... " who receive the discount. If ETI

17 cannot recover the production costs avoided by the CGS customer, it will

18 absorb the portion of its production costs "allocable" to those customers,

19 just as is required when a utility provides a customer with a discount rate.

20 PURA § 39.452(b}, however, expressly prohibits the CGS program from

21 producing this result.

4 See PURA § 39.905.

Entergy Texas, Inc. Page 6 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Q. THROUGHOUT MR. POLLOCK'S DISCUSSION ON THIS TOPIC, HE

2 REFERS TO "HYPOTHETICAL" LOST REVENUES. IS THERE

3 ANYTHING HYPOTHETICAL ABOUT THE COMPANY'S

4 UNRECOVERED COSTS?

5 A. No. The Company's calculation of unrecovered costs is based on

6 embedded costs within the rate case establishing the CGS tariff as

7 prescribed by PURA § 39.452(b). The only unknown is whether any

8 customers will actually apply for CGS service. Hence, the Company has

9 developed a $/kW rate associated with its known embedded costs that

10 would be applied to actual CGS load as it occurs to determine the CGS

11 unrecovered costs. There is nothing hypothetical about this cost. The

12 same cannot be said for load growth, which may or may not occur in the

13 future.

14

15 Q. YOU MENTION LOAD GROWTH IN THE FUTURE. WHAT ABOUT

16 LOAD GROWTH SINCE THE LAST RATE CASE?

17 A. The Company has already filed a new rate case. Any growth in load since

18 rates were set in the last rate case (Docket No. 37744), along with any

19 growth in cost. will be taken up in the rate new case (Docket No. 39896).

Entergy Texas, Inc. Page 7 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 IV. LOAD GROWTH AS AN OFFSET TO UNRECOVERED COSTS

2 Q. PLEASE SUMMARIZE THE LOAD GROWTH PROPOSALS MADE BY

3 THE OTHER PARTIES.

4 A. Mr. Townsend recommends that unrecovered costs be reduced by any

5 increases in generation-related base rate revenues attributable to load

6 growth. 5 It appears that, under Mr. Townsend's approach, an allocation of

7 ETI's overall revenues from load growth would need to be made, yielding

8 the proportion of the growth reasonably attributable to the generation

9 function. Mr. Johnson recommends that unrecovered costs be offset by

10 production revenue growth for the LIPS class only. 6

11 Similar to Mr. Townsend, Mr. Nalepa states that load growth "from

12 existing production-related rates charged to incremental load" should form

13 the basis for ETI to recover the production costs previously paid by the

14 CGS customer? Mr. Chriss makes no recommendation regarding load

15 growth in Wai-Mart's February 10, 2012 direct testimony. Mr. Pollock

16 suggests that ETI has experienced load growth that exceeds unrecovered

17 costs and therefore there are no unrecovered costs. 8 For this discussion it

18 appears that Mr. Pollock is utilizing total company growth for the

5 Townsend Supplemental Direct Testimony, February 10, 2012, pages 81ines 19-21.

6 Johnson Supplemental Direct Testimony, February 10, 2012, page 15, lines 5-7.

7 Nalepa Supplemental Direct Testimony, February 10, 2012, page 8, line 22 to page 9, lines 1-2.

8 Pollock Supplemental Direct Testimony, February 10, 2012, pages 21-24.

\0

Entergy Texas, Inc. Page 8 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 generation function, rather than load growth solely from the LIPS class of

2 customers.

3

4 Q. ARE THERE COMMON FLAWS IN THE LOAD GROWTH

5 RECOMMENDATIONS OF THE INTERVENOR WITNESSES?

6 A. Yes, the intervenor witnesses uniformly ignore that ETI's unrecovered

7 costs (the embedded production costs associated with serving CGS

8 customers) are determined in a base rate case, using test year rate setting

9 principles, just like every other element of the Company non-fuel

10 production costs. The Commission does not consider incremental load

11 growth or other incremental cost or revenue changes outside the rate year

12 in establishing the rates that will recover ETI's fixed production costs for

13 any other component of those costs. There is no basis for taking a

14 contrary approach in determining recovery of the embedded production

15 costs associated with serving the CGS customers. PURA § 39.452(b)

16 confirms this view when it states that "the utility's rates shall be set, in the

17 proceeding in which the tariff is adopted, to recover any costs as a result

18 of the implementation of the tariff." The statute says nothing about

19 considering a load growth adjustment that is unknown and unmeasurable

20 as the Commission sets rates, in this case, to recover the production costs

21 incurred to serve CGS customers. Furthermore, even if the statute did

22 refer to load growth, changes in costs to serve customers, not just growth

23 in load, would also need to be considered.

Entergy Texas, Inc. Page 9 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Q. ARE THERE ADDITIONAL FUNDAMENTAL FLAWS IN INTERVENOR

2 WITNESS LOAD GROWTH ANALYSES?

3 Yes, the intervenor witnesses' load growth recommendations are

4 fundamentally flawed for additional reasons. All of these

5 recommendations assume, to one degree or another, that load growth

6 under base rates is to be devoted, in a preferential fashion, to subsidize

7 the CGS program. There is nothing in base ratesetting principles or in

8 PURA that supports this approach. Under PURA, absent special statutory

9 requirements to the contrary, base rates are to be set sufficient to

10 providing the utility with a reasonable opportunity to earn a reasonable

11 return over and above the recovery of its reasonable and necessary

12 operating expenses.

13 Once those base rates are set, they are left in place until such time

14 as they are changed again, on a prospective basis only. There is nothing

15 in this process that earmarks load growth for a special purpose, such as

16 subsidizing the CGS customers.

17 The Commission Staff has explicitly recognized this principle in this

18 case. In its Exceptions to the ALJ's Proposal for Decision, ETI explained

19 that devoting load growth to address unrecovered costs would prevent it

20 from using such growth to address costs of operations it actually

21 experienced while the rates were in effect. The Staff agreed, stating in its

22 Replies to Exceptions that:

\I-

Entergy Texas, Inc. Page 10 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 [l]oad growth could be accounted for in a manner that would 2 keep ETI's shareholders whole. The CGSUSC Rider [for 3 recovering unrecovered costs] could be designed in such a 4 manner that only the amount of load growth related revenue 5 in excess of the amount of load growth related revenue 6 equal to ETI's costs would go toward offsetting the 7 unrecovered costs non-CGS participants would have to pay. 9 8 9 Q. ARE YOU AWARE OF OTHER INSTANCES IN WHICH THE

10 COMMISSION HAS APPLIED TOTAL COMPANY OR GENERATION-

11 RELATED REVENUE GROWTH AS AN OFFSET TO EMBEDDED

12 HISTORICAL COSTS SUCH AS THE CGS CUSTOMER PRODUCTION

13 COSTS?

14 A. No. As discussed in my Supplemental Direct Testimony, load growth has

15 gained acceptance in Texas as a consideration in offsetting incremental

16 costs, as in the provision for periodic adjustments for incremental changes

17 in distribution investment, 10 but should not be used to provide a means for

18 the non-recovery of embedded costs without consideration of incremental

19 costs.

20 21 Q. IF ONE ASSUMED, PURELY FOR THE SAKE OF ARGUMENT, THAT A

22 GENERATION LOAD GROWTH ADJUSTMENT WERE APPROPRIATE

23 TO OFFSET UNRECOVERED COSTS, IS IT APPROPRIATE TO USE

9 Staff Reply to Exceptions at p. 4 (emphasis added).

10 PURA Sec. 36.21 O(a)(2).

\~

Entergy Texas, Inc. Page 11 of30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 GENERATION REVENUE LOAD GROWTH FROM ALL CUSTOMER

2 CLASSES?

3 A. No. If load growth from all customers classes associated with generation

4 revenues were used to offset the CGS unrecovered costs then: 1) this

5 load growth would not be available to offset incremental generation cost in

6 the context of the pending purchased power rulemaking; and 2) other

7 non-CGS classes of customers would be further subsidizing the CGS

8 program because load growth attributable to their classes would be used

9 to offset CGS unrecovered costs for a program that only benefits CGS

10 participants. Mr. Pollock's Exhibit JP-4 illustrates these problems. His

11 illustration shows that ETI' five-year projected load growth is 73.6 MW.

12 But the load growth that he calculates is necessary to offset unrecovered

13 costs (68.7 MW based on ETI's currently pending rate case) uses up

14 virtually all the ETI projected load growth.

15

16 Q. ON PAGE 16, MR. JOHNSON DISMISSES THE COMPANY'S USE OF

17 THE EARNINGS MONITORING REPORT ("EMR") EARNED RETURN

18 ON EQUITY ("ROE") AS AN INDICATION THAT LOAD GROWTH HAS

19 NOT OFFSET INCREASED COSTS. PLEASE COMMENT.

20 A. Mr. Johnson at first states that this report is not indicative because it does

21 not include the unrecovered costs of the CGS program (there are no CGS

22 participants currently). First, this statement is inaccurate. The EMR does

23 include the embedded production costs currently being used to satisfy

Entergy Texas, Inc. Page 12 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 customers who may opt for the CGS program. In addition, this statement

2 misses the Company's point. Regardless of the potential criticisms of a

3 particular EMR, it well illustrates the general concept that if the Company

4 is not earning its allowed ROE, then the Company's non-fuel cost must

5 have increased at a faster rate than load and its associated revenues

6 have grown. The other parties continue to focus on growth in revenues

7 but ignore the fact that the Company's cost is also increasing. For

8 example, Mr. Pollock's Exhibit JP-2 indicates that adjusted energy sales

9 have increased by 5.9% in the two years between the test year in ETI's

10 last rate case (the twelve months ending June 30, 2009) and the test year

11 in the currently pending rate case (the twelve months ending June 30,

12 2011). 11 ETI's non-fuel generation costs, however, have increased by

13 28.6% in the same time frame. Load growth cannot be claimed or utilized

14 to recover both incremental cost and embedded cost. 12 This would simply

15 be double counting load growth.

16 Lastly Mr. Johnson indicates that the EMR is a general diagnostic

17 tool and does not reflect all of the adjustments that would be made in the

18 context of a rate case. A general diagnostic tool is precisely how the

19 Company utilized this report. It provides a general indication that the

11 Pollock Exhibit JP-2, line 2, last column shows 5.9% increase in sales.

12 LIPS non-fuel generation revenue requirement of $65.251 million from Exhibit PRM-1, line 14 compared to $83.890 million from Exhibit PRM-2, line 3. Growth in cost for LIPS class stated as a percent is representative of growth in cost for the Company.

Entergy Texas, Inc. Page 13 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Company's revenues have not kept pace with its costs and, therefore,

2 earnings have been below the allowed ROE.

3

4 Q. ON PAGE 10-11, MR. JOHNSON DISCUSSES HIS VIEW OF THE

5 EFFECT OF THE CGS PROGRAM ON CUSTOMER CLASS

6 ALLOCATION IN SUCCEEDING RATE CASES, AND SUGGESTS THAT

7 ALLOCATION FACTORS FOR THE CLASS OF CUSTOMERS ELIGIBLE

8 FOR THE CGS PROGRAM WILL BE REDUCED, RESULTING IN

9 OTHER CLASSES BEARING A LARGER SHARE OF ETI'S FIXED

10 PRODUCTION COSTS. DO YOU AGREE?

11 A. No. In response to an RFI from OPUC, attached as Exhibit PRM-1 R, the

12 Company responded to essentially this same question. That response

13 reflects the Company's intention on how CGS load would be treated in a

14 future rate case proceeding.

15 Question: 16 Assuming that Mr. May's position is adopted with respect to 17 recovery of unrecovered costs, please explain how CGS 18 customers' billing determinants, demand and energy contributions 19 to class allocators, and revenues will be treated in future class cost 20 of service studies. 21 22 Response: 23 Assuming Mr. May's position is adopted, including fully 24 compensatory recovery of unrecovered costs by ETI, CGS 25 customers' demand and energy contributions to class allocators will 26 be included in future class cost of service studies as if the CGS 27 program did not exist. Revenues will be calculated by including the 28 CGS revenues and credits.

Entergy Texas, Inc. Page 14 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Therefore, allocation factors and the allocation of production cost will not

2 be affected by the CGS program,

3

4 a. ON PAGE 22, MR. POLLOCK DISCUSSES THE AMOUNT OF LOAD

5 GROWTH THE COMPANY HAS EXPERIENCED. DO YOU HAVE ANY

6 COMMENT?

7 A. Yes. Mr. Pollock asks the Commission to simply assume that the load

8 growth forecast by ETI will in fact come to pass, although it is plainly not a

9 known or measurable event at this point. Based on that speculative

10 assumption, he asks the Commission to decree for now and ever after that

11 ETI will have no unrecovered costs because load growth will outstrip

12 them. This is an unreasonable and unsupportable assumption, to say the

13 least, as Mr. Pollock's own exhibits demonstrate. The workpaper to Mr.

14 Pollock's Exhibit JP-2 shows the actual known and measurable growth in

15 ETI load over the period 1999 - 2009. Using that data, I have calculated

16 the increase from each year to the year 2009, along with the compound

17 annual growth for each year to 2009 as shown in Table 1 below.

\1

Entergy Texas, Inc. Page 15 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Table 1

Year Non- MW MW Retail GWh GWh

Coincident Increase CAGR Sales Increase CAGR

PeakMW to 2009 GWh to 2009

1999 3,205 41 0.13% 14,833 613 0.41%

2000 3,338 (92) (0.31 %) 15,325 121 0.09%

2001 3,143 103 0.40% 14,885 561 0.46%

2002 3,185 61 0.27% 14,987 459 0.43%

2003 3,248 (2) (0.01%) 15,366 80 0.09%

2004 3,512 (266) (1.56%) 16,026 (582) (0.74%)

2005 3,434 (188) (1.40%) 14,979 467 0.77%

2006 3,571 (325) (3.13%) 15,383 63 0.14%

2007 3,711 (465) (6.47%) 15,521 (75) (0.24%)

2008 3,176 70 2.20% 15,533 (87) (0.56%)

2009 3,246 0 n/a 15,446 0 n/a

2

3 This table clearly shows that load growth has been anything but

4 consistent for ETI and cannot be depended on to offset CGS unrecovered

5 costs as claimed by Mr. Pollock.

Entergy Texas, Inc. Page 16 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Q. ON PAGE 23, MR. POLLOCK DESCRIBES HIS BELIEF THAT

2 PROJECTED LOAD GROWTH MORE THAN OFFSETS ETI'S CLAIMED

3 "LOST REVENUES." PLEASE COMMENT.

4 A. Mr. Pollock simply assumes 150 MW of CGS customer load, then

5 estimates the unrecovered costs based on both values from Docket

6 No. 37744 and from Docket No. 39896 provided by the Company, then

7 backs into the amount of load growth that would be required to offset

8 these unrecovered costs based on the embedded production cost values

9 provided by the Company. This analysis exhibits several flaws. First, as

10 discussed above, Mr. Pollock's example greatly overstates the amount of

11 load growth that may reasonably be considered available to subsidize the

12 CGS program. A more reasonable allocation of load growth would be

13 based on the percentage of load growth attributable to the LIPS class that

14 should be determined to be the class eligible for the CGS program.

15 Second, Mr. Pollock's analysis fails to recognize the impact load

16 growth has on MSS-1 payments and ETI's capacity purchases. As ETI's

17 load increases, its responsibility ratio increases for MSS-1 purposes.

18 Therefore, ETI becomes a "shorter" company and, as a result, incurs

19 increased MSS-1 payments. In addition, ETI will incur incremental

20 capacity costs to serve this hypothesized load growth not currently

21 reflected in the embedded cost rate assumed by Mr. Pollock. Thus, Mr.

22 Polllock has overstated the effect load growth would have as an offset to

23 unrecovered costs.

Entergy Texas, Inc. Page 17 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Q. ON PAGE 20, MR. POLLOCK PROVIDES EXAMPLES OF SITUATIONS

2 WHERE HE HYPOTHESIZES THAT NEW LOAD ASSOCIATED WITH

3 CGS CUSTOMERS WOULD NOT RESULT IN UNRECOVEVRED

4 COSTS. PLEASE COMMENT.

5 A. As discussed above and in my Supplemental Direct Testimony, PURA

6 provides that "... [ETI's] rates shall be set, in the proceeding in which the

7 tariff is adopted, to recover any costs unrecovered as a result of the

8 implementation of the tariff." As discussed in my Supplemental Direct

9 Testimony, new load is subject to the same average cost pricing as

10 existing load. Accordingly, in the normal course of events, new loads

11 would pay their share of ETI's embedded production costs in the same

12 manner as existing customers. Mr. Pollock's position assuming that these

13 new customers would not have paid these costs absent the CGS program

14 would require: 1) a decision by the Commission to treat a portion of ETI's

15 new load differently from other new load not associated with the CGS

16 program; and 2) would require credible proof that absent the CGS

17 program, this load would never have been added to ETI's system. Absent

18 this proof, this load is like any other new or existing load subject to

19 average cost pricing. Like much of Mr. Pollock's presentation, his

20 scenarios are purely hypothetical and theoretical. The facts and

21 circumstances surrounding a new customer taking service from ETI, or an

22 existing customer expanding its load, cannot be judged until such an event

Entergy Texas, Inc. Page 18 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 occurs. Accordingly, these scenarios form no legitimate basis for making

2 a determination regarding the level of ETI's unrecovered costs.

3

4 V. ALLOCATION OF UNRECOVERED COSTS

5 Q. PLEASE SUMMARIZE THE PARTIES' POSITIONS REGARDING WHO

6 SHOULD PAY (OR BE ALLOCATED) THE CGS UNRECOVERED

7 COSTS.

8 A. Mr. Townsend recommends that: 1) unrecovered costs should be

9 recovered from CGS participants, and if that option is not viable; 2) the

10 CGS program should be rejected, and if that option is not selected;

11 3) ETI's proposal to spread these costs across all classes is the most

12 equitable (with certain modifications). 13 Mr. Johnson, Mr. Nalepa and Mr.

13 Chriss recommend that the unrecovered costs should be recovered from

14 the LIPS class of customers (both CGS participants and non-participants)

15 because only the LIPS customers have an effective ability to participate in

16 CGS and this is consistent with cost causation principles. 14 Mr. Pollock

17 recommends that unrecovered costs (if any) should be recovered from

18 CGS participants. 15 Mr. Pollock also suggests that if the unrecovered

13 Townsend Supplemental Direct Testimony, February 10, 2012, pages 3-4 and pages 7-8.

14 Johnson Supplemental Direct Testimony, page 6, line 16 to page 7, line 2. Nalepa Direct Testimony, February 10, 2012, page 17, lines 11-18. Chriss Direct Testimony, February 10, 2012, page 6, line 9-19, page 7, lines 13-22.

15 Pollock Supplemental Direct Testimony, February 10, 2012, page 38, lines 1-13.

Entergy Texas, Inc. Page 19 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 costs are substantial, there may be insufficient benefits to justify

2 implementing the CGS program. 16

3 4 Q. PLEASE COMMENT ON THESE PROPOSALS.

5 A. Ultimately the question of what class of customers should pay for

6 unrecovered costs is a policy decision to be made by the Commission.

7 One thing that is clear under PURA § 39.452(b) is that the Company is

8 allowed to recover its unrecovered costs: "[ETI's] rates shall be set, in the

9 proceeding in which the tariff is adopted, to recover any costs unrecovered

10 as a result of the implementation of the tariff." 17 The statute, however,

11 does not dictate a specific allocation of unrecovered costs among ETI's

12 customers. The Company would not oppose any reasoned allocation of

13 unrecovered costs to customer classes including CGS participants or CGS

14 eligible customers. That said, it should be understood that any allocation

15 of unrecovered costs will be temporary in nature. Ultimately, when ETI

16 files another base rate case, the effects of the CGS program would be

17 reflected in the allocation of cost responsibility similar to the way that the

18 Company now allocates the interruptible credit.

16 ld, page 38, lines 11-13.

17 PURA § 39.452(b).

Entergy Texas, Inc. Page 20 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Q. WHAT RESPONSE DO YOU HAVE TO MR. POLLOCK'S STATEMENT

2 THAT SHOULD THE UNRECOVERED COSTS BE SUBSTANTIAL

3 THERE WILL BE INSUFFICIENT BENEFITS TO JUSTIFY

4 IMPLEMENTING THE CGS PROGRAM?

5 A. There is no aspect of the CGS program, as described in PURA

6 § 39.452(b), hinting that unrecovered costs should be ignored in order to

7 heighten the chance of the program's success for those relatively few

8 customers positioned to take advantage of it. To accept Mr. Pollock's

9 implicit invitation to do so would be nothing less than creating an

10 impermissible discounted rate for CGS customers that is financed by the

11 Company's absorption of the embedded production costs incurred to

12 serve those customers. As stated in PURA § 39.452(b) and described in

13 my Supplemental Direct Testimony, the CGS program may not result in

14 the creation of such a discounted rate. The Company is allowed to

15 recover its unrecovered costs, and the CGS program is optional to

16 customers. Satisfaction of the statutory requirements applicable to the

17 CGS program, not guaranteed success for a select few customers, should

18 be the basis for evaluating the CGS program and tariffs.

19

20 VI. ELIGIBLE CUSTOMERS FOR CGS SERVICE

21 Q. PLEASE SUMMARIZE THE POSITIONS OF THE VARIOUS PARTIES

22 REGARDING WHAT CUSTOMERS SHOULD BE ELIGIBLE FOR CGS

23 SERVICE.

Entergy Texas, Inc. Page 21 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 A. Mr. Townsend states that Kroger agrees with the Company that

2 participation should be limited to the LIPS customers. 18 OPUC witness

3 Mr. Johnson and Cities witness Mr. Nalepa state they agree to limiting

4 CGS eligibility to the LIPS class and, to their knowledge, that LIPS

5 customers are the only class of customers actively pursuing CGS. 19

6 Mr. Chriss states that Wai-Mart does not support expanding the class of

7 eligible CGS customers beyond the LIPS class at this time. 20 Mr. Pollock

8 proposes that eligibility should be expanded to all customers having a

9 sufficient amount of 24n load. 21 Mr. Pollock also suggests that

10 aggregation of customer load should be allowed in order for smaller

11 customers to qualify for the CGS program?2 However, Mr. Pollock also

12 concludes that the minimum CGS contract size should be 5 MW. He

13 appears to make these recommendations without regard to whether such

14 customers have any interest in or ability to effectively participate in the

15 program. Notably, in response to an RFI from ETI, TIEC could not

16 produce a list of even just one of its members, or any other person, that

17 has expressed an interest or intent to participate in the CGS program. 23

18 Townsend Supplemental Direct Testimony, February 10, 2012, page 5, lines 8-18.

19 Johnson Supplemental Direct Testimony, February 10, 2012, page 17, lines 1-9. Nalepa Direct Testimony, February 10, 2012, page 17, lines 11-18.

2 ° Chriss Supplemental Direct Testimony, February 10, 2012, page 7, line 13-15. 21 Pollock Supplemental Direct Testimony, February 10, 2012, page 10, line 13-16, and page 40, lines.

22 /d, page10, lines 16-19, and page 41-42.

23 See Exhibit PRM-3R.

--------------------~-~-~---~ --- ----

Entergy Texas, Inc. Page 22 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Q. HOW DOES MR. POLLOCK'S RECOMMENDATION REGARDING THE

2 MINIMUM CGS SUPPLY CONTRACT SIZE AFFECT HIS OTHER

3 PROPOSALS REGARDING CUSTOMER ELIGIBILITY?

4 A The minimum demand for LIPS service is 2.5 MW. Therefore, under Mr.

5 Pollock's own proposals (absent aggregation), the CGS program would

6 still have to be limited to the LIPS class of customers. Aggregation is the

7 only proposal made by Mr. Pollock that expands the eligibility beyond the

8 LIPS class of customers.

9

10 Q. WHAT SUGGESTION DOES MR. POLLOCK MAKE REGARDING

11 AGGREGATION?

12 A. Mr. Pollock makes two suggestions: 1) aggregation is not tied to retail

13 competition; and 2) aggregation is not complicated. 24

14

15 Q. DO YOU HAVE ANY COMMENTS ON THESE TWO SUGGESTIONS?

16 A Yes. First, in attempting to support his claim that aggregation is not

17 complicated, Mr. Pollock uses an example that contradicts his argument

18 that aggregation is not a feature of retail competition. The only location

19 Mr. Pollock cites where aggregation was instituted to allow widespread

20 customer choice of alternative sources of electricity was in ERGOT.

21 There, of course, aggregation was expressly included as an element of

24 /d,pages 40-41.

Entergy Texas, Inc. Page 23 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 the introduction of retail competition. 25 PURA § 39.452(b) does not

2 impose retail open access on ETI and its customers. As discussed in my

3 Supplemental Direct Testimony, allowing aggregation of load to any

4 customer class is the equivalent to retail open access in that any customer

5 can choose to aggregate its load with another and thereby select to have

6 an alternative generation supplier. In connection with the passage of

7 Senate Bill 7, the Commission spent several years, in numerous projects

8 and workshops, working with ERCOT and numerous stakeholders to

9 develop and implement the rules and mechanisms whereby service to a

10 multitude of retail customers could be split between regulated

11 Transmission and Distribution service and unregulated generation service.

12 Similarly, ETI would need to be able to identify all the individual customers

13 who decided to take part in aggregation, account for changes in the

14 aggregate group, account for switches between aggregated and traditional

15 service, etc. This Commission is well aware of the difficulties associated

16 with implementing that type of program and, contrary to Mr. Pollock's

17 suggestion, it is certainly complicated and not inexpensive.

18

19 Q. ARE THERE ANY OTHER PROPOSALS FOR ELIGIBILITY MADE BY

20 MR. POLLOCK?

21 A. Yes, Mr. Pollock also suggests that customers on LIPS who are also on

22 Standby Maintenance Service (SMS) and Interruptible Service (IS) should

25 E.g, PURA § 39.353.

Entergy Texas, Inc. Page 24 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 be allowed to contract for CGS supply. A LIPS customer typically

2 designates part, but not all, of its load to be served under these separate

3 rate schedules. SMS is a service that a customer may call on to back up

4 its own co-generation supply under certain circumstances. IS is a rate

5 whereby a customer who agrees to allow its service to be curtailed under

6 certain circumstances receives a bill credit for the load devoted to IS.

7 8 Q. PLEASE RESPOND TO MR. POLLOCK'S CLAIM THAT CGS SERVICE

9 CAN READILY BE ADDED ON TOP OF CUSTOMERS ALREADY

10 RECEVING SERVICE UNDER THESE MULTIPLE RATES AND

11 SCHEDULES.

12 A. As discussed in my Supplemental Direct Testimony, this CGS program is

13 extremely complicated: it will be the single most complicated billing and

14 administration ever attempted on the Entergy system. Therefore, the

15 Company continues to propose that customers currently on either

16 Schedule IS or Economic As-Available Power Service (EAPS) should not

17 be allowed to participate in the CGS program to satisfy any portion of their

18 firm load at this time. Customers on Schedules IS and EAPS already

19 have their loads split between firm and other service. Adding a further

20 split of what was firm service between CGS and what then remains for

21 firm service is a further complexity in billing and administration of the CGS

22 program that may be considered at a future date, once the Company and

Jl

Entergy Texas, Inc. Page 25 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 its customers have the opportunity to gain experience in the basics of the

2 CGS program.

3 Moreover, as explained in the Company's response to TIEC RFI

4 1-8 (attached as Exhibit PRM-2R), this limit on customer eligibility should

5 likewise extend to LIPS customers who also receive service under the

6 SMS rate schedule. 26 In that RFI response, ETI further explained that the

7 Company has a concern that customers on Schedule SMS may be able to

8 manipulate their own generation to avoid unserved energy charges

9 associated with a third-party CGS supplier. For example, a customer on

10 SMS is receiving backup service for its own generation. It is possible that

11 customer could utilize this backup service for its generation to instead

12 backup generation from a third-party CGS supplier and thereby avoid

13 unserved energy changes. For these reasons, and because of the same

14 billing concerns applicable to EAPS and IS customers, the CGS tariff

15 should be limited at this time to LIPS customers only.

16

17 Q. DO YOU HAVE ANY FINAL COMMENT ON THE CUSTOMER

18 ELIGIBILITY ISSUE?

19 A. Yes. It makes little sense to extend eligibility for this type of experimental

20 program to customer groups or classes who have shown no interest in

21 participating. Even for the LIPS class of customers expanding CGS to IS,

26 SMS service is essentially backup service for a customer who serves its load from co-generation facilities.

Entergy Texas, Inc. Page 26 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 EAPS and other optional rates makes little since when, as discussed

2 above, these customers have exhibited no interest in the program.

3

4 VII. OTHER ISSUES

5 Q. MR. NALEPA AND MR. POLLOCK CLAIM THAT THE FIXED COST

6 CONTRIBUTION FEE OF $1.10/KW PAID BY CGS PARTICIPANTS

7 FULLY RECOVERS THE PRODUCTION COST INCURRED BY THE

8 COMPANY TO SERVE CGS CUSTOMERS. DO YOU AGREE?

9 A. No. The production cost incurred by the Company to serve existing

10 customers, who might migrate to CGS service, is its actual embedded

11 production cost determined in the rate case from which the CGS program

12 will be approved. That actual embedded production cost is the $6.84/kW

13 resulting from Docket No. 37744 described in my Supplemental Direct

14 Testimony and Exhibit PRM-1. The only offsets to this unrecovered

15 embedded production cost are the Fixed Cost Contribution Fee of

16 $1.1 0/kW and the MSS-1 impact associated with System Agreement

17 recognition of this capacity for MSS-1 purposes. There are no other actual

18 offsets to the unrecovered embedded production costs.

19 Both Mr. Nalepa and Mr. Pollock would like to now claim that the

20 $1.1 0/kW is associated with providing production service to CGS

21 participants, or in the terms of Mr. Pollock: backup service. This is not the

22 case. The Fixed Cost Contribution Fee has always been discussed as

23 simply a method to reduce any unrecovered costs by having the CGS

Entergy Texas, Inc. Page 27 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 participants pay a contribution to fixed cost. Characterizing this as

2 recovery of incremental production cost or backup service to serve CGS

3 load is simply wrong.

4

5 Q. WHAT IS YOUR RESPONSE TO MR. POLLOCK'S ARGUMENT THAT

6 THE MSS-1 OFFSET IS NOT AN APPROPRIATE MEANS OF PLACING

7 A MARKET VALUE ON CGS CAPACITY?

8 A. Mr. Pollock has completely missed the significance of the MSS-1 offset to

9 this case. The reduction in ETI's MSS-1 payment, which is associated

10 with equalizing reserves among the Entergy Operating Companies, is not

11 being used as a proxy value for the CGS capacity, as claimed by

12 Mr. Pollock. 27 The Company is simply recognizing that its MSS-1

13 payments (or cost) will be reduced by recognition of the CGS capacity,

14 and that this is the only known and measurable actual cost reduction

15 attributable to the CGS program available to offset the unrecovered costs.

16

17 Q. ON PAGE 28, MR. POLLOCK STATES THAT CGS CAPACITY IS AN

18 INCREMENTAL NEW RESOURCE. WHAT IMPACT DOES THIS HAVE

19 ON DETERMINATION OF UNRECOVERED COSTS?

20 A. As discussed by Company witness Dingle, CGS capacity may help the

21 Company avoid acquiring some capacity in the future, although the ability

22 of CGS capacity to create such a result is limited due to certain program

27 Pollock Supplemental Direct Testimony, page 28, lines 7-9.

Entergy Texas, Inc. Page 28 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 constraints such as the short-term nature of the CGS contract. However,

2 CGS capacity in no way avoids embedded capacity cost that the

3 Company has already incurred. Unrecovered embedded costs due to the

4 CGS program are none the less still unrecovered. This is the case

5 whether or not the CGS capacity allows the Company to avoid any future

6 capacity costs.

7

8 Q. ON PAGE 14, MR. NALEPA CLAIMS THAT THE COMPANY IS

9 BENEFITING BY THE CGS PROGRAM. DO YOU AGREE?

10 A. No. Mr. Nalepa claims that the Company will benefit from any MSS-1

11 savings due to the added CGS capacity for MSS-1 purposes. As

12 described in my Supplemental Direct Testimony and discussed above,

13 assuming the CGS capacity is firmed up, MSS-1 is being used to offset

14 the unrecovered costs; thus, the Company is not keeping these benefits.

15 Rather, the Company is giving these benefits to those customers who

16 have to pay the unrecovered costs. The Company is simply complying

17 with PURA in ensuring that it is no worse off due to implementation of the

18 CGS program.

19

20 Q. HOW CAN THE COMPANY END UP WORSE OFF DUE TO

21 IMPLEMENTATION OF THE CGS PROGRAM?

22 A. There are a number of ways. Examples include: 1) The Company's

23 current rates were designed in Docket No. 37744 to recover the

Entergy Texas, Inc. Page 29 of 30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 Company's embedded cost and provide for a reasonable return to

2 stockholders based on the existing customers. If those customers are

3 now provided an alternative supply, the Company no longer recovers the

4 cost of its existing facilities, nor does it recover a return on those

5 investments; 2) the Company would not be allowed to fully recover its

6 implementation and administration cost of the program; and 3) load growth

7 could be used as an offset to CGS unrecovered costs and in addition be

8 used as an offset to purchased power or production cost recovery in a

9 future ratemaking proceeding.

10

11 Q. DO YOU HAVE ANY OTHER GENERAL COMMENTS REGARDING THE

12 CGS PROGRAM?

13 A. Yes. As the Company transitions to MISO, the CGS program will need to

14 be redesigned for a number of reasons such as: 1) QF pricing under

15 MISO will change; 2) the capacity market under MISO will be more

16 transparent; 3) uncertainty of what the MISO capacity market will look like;

17 4) QFs will have different options under MISO; and 5) ETI's options will be

18 different under MISO. Based on these factors it can be anticipated that a

19 revision to the CGS program as currently envisioned will be required in

20 2013 as ETI and the other Entergy Operating Companies enter MISO.

Entergy Texas, Inc. Page 30 of30 Supplemental Rebuttal Testimony of Phillip R. May Docket No. 38951

1 VIII. CONCLUSION

2 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL REBUTTAL

3 TESTIMONY?

4 A. Yes, at this time.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 DOCKET NO. 38951

APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR APPROVAL OF § COMPETITIVE GENERATION § SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) §

SUPPLEMENTAL DIRECT TESTIMONY

OF

ANDREW J. O'BRIEN

ON BEHALF OF

ENTERGY TEXAS, INC.

JANUARY 26, 2012

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93

ENTERGY TEXAS, INC.

SUPPLEMENTAL DIRECT TESTIMONY OF ANDREW J. O'BRIEN DOCKET NO. 38951

TABLE OF CONTENTS

I. Introduction and Purpose of Testimony 1

II. Assessing the Value of CGS Capacity 4

Ill. Eligibility for Participation in the CGS Program 9

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 1 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 I. INTRODUCTION AND PURPOSE OF TESTIMONY

2 Q. PLEASE STATE YOUR NAME, BUSINESS ADDRESS, EMPLOYER AND

3 JOB TITLE.

4 A My name is Andrew J. O'Brien. My business address is Parkwood Two

5 Bldg., Suite 300, 10055 Grogan's Mill Road, The Woodlands, Texas

6 77380.

7

8 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

9 A I am employed as Manager, Power Marketing by Entergy Services, Inc.,

10 the service company affiliate providing engineering, planning, accounting,

11 technical, regulatory support and other services to Entergy Texas, Inc.

12 ("ETI" or the "Company") and the other Operating Companies of the

13 Entergy System. 1 Although each individual Operating Company owns its

14 generating resources and transmission assets, the Entergy System is

15 planned and operated as a single, integrated system pursuant to the terms

16 and conditions of the Entergy System Agreement. 2

The six Entergy Operating Companies are Entergy Arkansas, Inc. ("EAI"), Entergy Gulf States Louisiana, L.L.C. ("EGSL"), Entergy Louisiana, LLC ("ELL"), Entergy Mississippi, Inc. ("EMI"), Entergy Texas, Inc. ("ETI") and Entergy New Orleans, Inc. ("ENOl"). The electric generation and bulk transmission assets of these six Operating Companies are operated on a coordinated basis as a single electric system, referred to as the "Entergy System" or the "System."

2 The Entergy System Agreement is a FERC-approved rate schedule and contract entered into among ESI and the Operating Companies, which requires the Operating Companies to plan, construct and operate their electric generation and bulk transmission facilities as a single, integrated electric system. It is administered by the Entergy Operating Committee. EAI and EMI have provided notice to the other Operating Companies that they are terminating their participation in the System Agreement effective December 2013 and November 2015, respectively, or on such earlier dates as the FERC may permit.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 2 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 Q. PLEASE DESCRIBE YOUR BUSINESS EXPERIENCE AND

2 EDUCATION.

3 A. I have been employed by ESI since June, 2001. During my career, I have

4 held numerous positions, including my current leadership position, in the

5 areas of commercial negotiations, regulatory, generation dispatch

6 operations as well as resource and operations planning. In June, 2001, I

7 accepted a position as Next Day Scheduler in the power marketing

8 department of the Energy Management Organization ("EMO"). From 2003

9 to 2006, I worked as a Generation System Dispatcher and then as the Sr.

10 Lead Analyst in the Current Day Operations group. In 2007, I accepted

11 the role of Wholesale Executive in the Supply Procurement department

12 and was promoted in 2008 to Manager, Supply Procurement. In this role,

13 gained significant experience negotiating long-term resource

14 acquisitions, both asset purchases and purchase power agreements. In

15 2010, I accepted a position within the EMO as Manager, Operations

16 Support which is responsible for overseeing the development and

17 implementation of the next-day resource plan including generation

18 commitment and system load forecast. In September 2011, I assumed

19 the position of Manager, Power Marketing. I have a Masters Degree in

20 Business Administration from Texas A&M University and a Bachelor of

21 Science Degree in Psychology from Louisiana State University.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 3 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 Q. ON WHOSE BEHALF ARE YOU PROVIDING THIS TESTIMONY?

2 A. I am submitting this testimony to the Public Utility Commission ("PUCT" or

3 the "Commission") on behalf of ETI.

4

5 Q. HAVE YOU PREVIOUSLY FILED TESTIMONY IN THIS PROCEEDING?

6 A. No.

7

8 Q. WHAT IS THE PURPOSE OF YOUR SUPPLEMENTAL DIRECT

9 TESTIMONY?

10 A. I address two issues in support of Company witness Phillip R. May's

11 Supplemental Direct Testimony regarding the Competitive Generation

12 Service ("CGS") program that is at issue in this proceeding. First, I explain

13 that the value of capacity must consider many different factors related to

14 the characteristics of the capacity product at issue and the market

15 environment in which that capacity is being evaluated. As such, it is not

16 feasible to assign some independent arbitrary value to the capacity that

17 CGS Customers will use to supply their energy needs under the CGS

18 Program. I offer this explanation to support Company witness May's

19 discussion of ETI's position regarding the appropriate definition and

20 calculation of unrecovered costs. My explanation addresses the factors

21 that must be considered when valuing capacity, and concludes that the

22 characteristics of CGS capacity are associated with relatively low-value

23 products.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 4 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 also support Company witness May's testimony regarding

2 eligibility for participating in the CGS Program, explaining why important

3 operational concerns support the Company's position that the minimum

4 capacity supplied by a CGS Purchase Agreement should be 10 MW.

5

6 II. ASSESSING THE VALUE OF CGS CAPACITY

7 Q. WHAT IS YOUR UNDERSTANDING OF THE PURCHASED CAPACITY

8 PRODUCT THAT HAS BEEN PROPOSED AS AN ELEMENT OF THE

9 CGS PROGRAM?

10 A. My understanding is that the parties to this proceeding have been

11 engaged in negotiations for some time aimed at achieving a collaborative

12 resolution of a number of contested matters surrounding the design and

13 implementation of the CGS Program. As further discussed by Company

14 witness May, that negotiating process has resulted in a tentative proposal

15 that purchased power supplied by a third party to ETI under the CGS

16 Program may be counted as ETI's capacity (or, in the terminology of the

17 Entergy System Agreement, "capability") by the Entergy System. 3 I will

18 refer to this capacity product in my testimony as "CGS Capacity" and the

3 The parties to the case, including ETI, have not reached agreement on all matters necessary to establish a CGS program that includes such a capacity product. Matters yet to be resolved are listed in the "Agreed List of Unsettled Issues and Issues Contingent on a Commission Determination of Unsettled Issues" filed on November 1, 2011. By providing this testimony, ETI does not in any manner waive its rights to continue to fully contest any and all issues that remain disputed among the parties. ETI presents this testimony solely for the purpose of facilitating the Commission's resolution of the three threshold issues, which may facilitate further efforts by the parties to resolve remaining contested issues surrounding the design of the CGS program and tariffs.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 5 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 contracts under which this capacity is supplied to the Entergy System as

2 "CGS Purchase Agreement."

3 As currently contemplated, when the CGS program goes into effect,

4 the CGS Capacity would consist of an obligation on the part of the CGS

5 Supplier to deliver to ETI's transmission system a contractually-specified

6 amount of energy 24 hours per day, seven days per week ("24/7") on a

7 firm, unit-contingent basis. 4 ETI, however, will not make a capacity

8 payment to the CGS Supplier. Instead, ETI will pay the CGS Supplier for

9 the energy provided under the CGS Purchase Agreement at the avoided

10 cost rate established under ETI's rate schedule LQF. The CGS Supplier

11 would look to the CGS Customer, under a separate contract, for payment

12 for the capacity provided to ETI.

13

14 Q. CAN ETI UNAMBIGUOUSLY DETERMINE THE VALUE TO THE

15 ENTERGY SYSTEM OF THE CAPACITY ASSOCIATED WITH THE CGS

16 PROGRAM?

17 A. No. The value of any capacity purchase is a function of a number of

18 different factors, including, for example, the operational characteristics of

19 the capacity purchase, the location of that capacity, the term of the

20 agreement, and the availability of other market alternatives. Moreover, it

21 is difficult to assign discrete scores to these characteristics. I am not

4 "Unit Contingent" means that so long as the CGS Supplier's generating unit is physically capable of producing energy (or "available"), the CGS Supplier has the obligation to deliver the contractually-specified amount of energy.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 6 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 aware of any specific formula or algorithm that can take all of these factors

2 into consideration to produce a single meaningful point estimate of the

3 value of capacity. However, it is reasonable to consider how a specific

4 capacity product ranks on a sliding scale of more or less valuable

5 according to each of the relevant characteristics, consider all of the

6 characteristics collectively, and reach a conclusion about the relative value

7 of a specific capacity product.

8

9 Q. WOULD YOU PLEASE LIST SOME OF THESE CHARACTERISTICS,

10 AND EXPLAIN HOW THEY APPLY TO CGS CAPACITY?

11 A Yes. The following Table 1 lists and describes some of the prominent

12 characteristics that should be considered when evaluating capacity, and

13 indicates where CGS capacity lies on the spectrum of more to less

14 valuable.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 7 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

Table 1 Relative Valuation of CGS Ca(;!acit~ Relative Rank of CGS Ca(;!acit~ Characteristic Description Low ~-----------------------~High The ability of the System Operator to direct a unit to start or stop, or to move from one operating level to another. Generally, more flexibility means more Flexibility value. CGS Capacity is not ~ at all flexible-if a CGS Supplier's facility is physically capable, it must deliver and ETI must take energy up to the full Contract Capacity. The cost of the energy that is acquired when the Energy Cost contracted capacity is ~ called upon. Degree of reliability of supply (e.g., a unit contingent contract, which depends on the performance of a specific generator, is less valuable than a system contingent Firmness contract that relies on a ~ group of generators; similarly, contracts that have the first call on any energy from a generating unit are more valuable than contracts that have other assorted obligations). A longer-term product allows more certainty that Term other capacity needs will be ~ avoided. Generally, fewer, but larger contract blocks are easier Size to administer and manage ~ in system operations. Capacity that can alleviate congestion in a specific Location planning region is more ~ valuable.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 8 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

Relative Rank of CGS Ca~acit)£ Characteristic Description Low ~------------------------~High Capacity that can reduce the need for flexible Ability to reduce capacity on the System has System operating more value; CGS Capacity ../ constraints firms up QF put, which reduces the need for flexible capacity.

1 As can be seen from the preceding Table 1, a review of the characteristics

2 of the capacity that ETI will acquire as a result of the CGS program

3 indicates that the CGS Capacity is not a product that would reasonably be

4 expected to have a high level of value.

5

6 Q. FROM THE PERSPECTIVE OF ETI'S CUSTOMERS, IS THERE ANY

7 VALUE THAT CAN BE ASCRIBED TO CGS CAPACITY?

8 A. Yes. As discussed in more detail by Company witness May, the Entergy

9 Operating Committee has agreed to consider CGS Capacity as ETI

10 capability for purposes of determining ETI's payment obligations pursuant

11 to Service Schedule MSS-1 of the System Agreement, so long as CGS

12 Capacity meets certain conditions imposed by the Operating Company.

13 That treatment means that ETI's capacity costs will be decreased as a

14 result of the CGS program.

~~ ---~- - - - - - - - - - - - - - - - - - - - - - -Docket ---- No.

- 38951 -------.

Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 9 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 Ill. ELIGIBILITY FOR PARTICIPATION IN THE CGS PROGRAM

2 Q. WHAT ASPECT OF THE ISSUES REGARDING ELIGIBILITY TO

3 PARTICIPATE IN THE CGS PROGRAM DO YOU ADDRESS?

4 A. I discuss the issue of whether it would be advisable to allow CGS

5 Customers to contract with CGS Suppliers for very small amounts of

6 capacity, thus permitting an opportunity for an increased amount of very

7 small CGS Purchase Agreements.

8

9 Q. WHAT IS ETI'S POSITION ON THIS ISSUE?

10 A. ETI's position is that a CGS Customer should not be permitted to contract

11 with a CGS Supplier for a level of capacity less than 10 MW.

12 Furthermore, for the reasons explained by Company witness May,

13 customers should not be allowed to aggregate their load for purposes of

14 contracting for CGS supply. As a result of these conditions, eligibility to

15 participate in the CGS program would be limited to customers who can

16 individually contract for at least 10 MW of CGS Capacity.

17

18 Q. ARE THERE OPERATIONAL CONSIDERATIONS THAT SUPPORT THE

19 IMPOSITION OF A 10 MW FLOOR FOR PARTICIPATING

20 CUSTOMERS?

21 A. Yes. From an operational perspective, the key factor is not the size of the

22 contracts with CGS Suppliers, but is instead the number of CGS

23 Suppliers. From time to time, especially in emergency situations or in

ll

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 10 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 situations in which the transmission system operator calls for curtailments

2 to alleviate transmission constraints, the System's dispatchers must reach

3 out and provide instructions to each Purchased Power Agreement ("PPA")

4 counterparty. That process grows more difficult as the number of PPAs

5 increases. Currently, the parties to the CGS proceeding have reached a

6 tentative agreement in principle that the total amount of customer load

7 should be capped at somewhere between 80 and 150 MW, although there

8 is no specific agreement regarding the specific cap level within that range.

9 This cap, combined with a minimum size of 10 MW, would limit the

10 number of potential CGS Purchase Agreements to 8 to 15, a number that

11 should be able to be reasonably accommodated.

12 From an administrative and operational perspective, when

13 managing load on the System, the System dispatchers must undertake

14 the same procedures regardless of the size of the contract. Thus, for

15 example, the same notification procedures are used to pursue the

16 reduction of a 10 MW resource as are used for a 100 MW resource during

17 a low load event. The lower the MW limit for participation in the CGS

18 program, the more likely that the administrative burden exceeds the

19 benefit provided by the resource during emergencies such a low load

20 events. Further, the value of lower capacity level PPAs is less.

21 Continuing with the example of the management of low load events, in the

22 case of the 10 MW and 100 MW PPAs, when having to manage a low

23 load event, the ability to turn down 100 MW provides substantially greater

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 93 Entergy Texas, Inc. Page 11 of 11 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 value to the System than does the turning down of 10 MW. In general,

2 given the size of the load on the Entergy System, contracts as small as 10

3 MW simply do not provide the same capacity value as larger PPAs, and in

4 the absence of special programs, such as CGS, that are entered into for

5 specific reasons, the System would not generally contract for such small

6 amounts.

7

8 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

9 A. Yes, at this time.

/3

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 94 DOCKET NO. 38951

APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR APPROVAL OF § COMPETITIVE GENERATION § PUBLIC UTILITY COMMISSION SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) § OF TEXAS

SUPPLEMENTAL REBUTTAL TESTIMONY

OF

··--

ANDREW J. O'BRIEN h)

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1,, -·- en ~ ... ~ \ ,..,_, ,)

ON BEHALF OF .::::- T1 ·-o <: :::i: rn r:'? 0 ENTERGY TEXAS, INC.

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FEBRUARY 24, 2012

Entergy Texas, Inc. Page 1 of 7 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 Q. PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS.

2 A My name is Andrew J. O'Brien. My business address is Parkwood Two

3 Bldg., Suite 300, 10055 Grogan's Mill Road, The Woodlands, Texas

4 77380.

5

6 Q. DID YOU PREVIOUSLY FILE TESTIMONY ON BEHALF OF ENTERGY

7 TEXAS, INC. ("ETI" OR THE "COMPANY") IN THIS PROCEEDING?

8 A Yes, I did.

9

10 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?

11 A I will address certain comments and recommendations made by Texas

12 Industrial Energy Consumers witness Jeffry Pollock regarding my Direct

13 Testimony.

14

15 Q. MR. POLLOCK CONCLUDES THAT YOUR TESTIMONY SHOULD BE

16 GIVEN LITTLE WEIGHT BECAUSE YOU HAVE NOT COMPARED THE

17 VALUE OF CGS POWER (CAPACITY) TO ETI'S EXISTING

18 PURCHASE POWER CONTRACTS. 1 HOW DO YOU RESPOND?

19 A Nothing in my Direct Testimony required an analysis or comparison

20 between hypothetical CGS Purchase Agreements and ETI's actual PPAs.

21 Mr. Pollock's contention is inappropriate given that there are no CGS

1 Pollock Direct, p. 30, Ins. 8 - 10.

Entergy Texas, Inc. Page 2 of 7 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 Purchase Agreements. As noted in my Direct Testimony, there is no way

2 to unambiguously determine at this time the value to the Entergy System

3 of CGS Capacity to be acquired in the future. The value or price of

4 capacity is determined based on considerations and circumstances

5 existing at the time a decision is made to acquire capacity, as well as the

6 process employed, such as, for instance, a Request for Proposal, which

7 relies on competitive bidding. Additionally, unlike energy transactions,

8 there are no pre-existing capacity markets or indices to consult when

9 purchasing capacity. With that understanding, the point of my Direct

10 Testimony was simple; namely, that the value of purchased capacity is a

11 function of a number of different factors or attributes; that, as

12 contemplated, CGS Capacity ranks relatively low for five of seven major

13 attributes; and that, accordingly, CGS Capacity "is not a product that

14 would reasonably be expected to have a high level of value." 2

15 16 Q. MR. POLLOCK CONTENDS THAT A BASE-LOAD PRODUCT DOES

17 NOT NEED FLEXIBILITY. 3 DOES THAT UNDERMINE YOUR

18 CONCLUSION REGARDING THE LOW VALUE OF CGS CAPACITY?

19 A. No. While an inflexible product may be able to provide a base-load role,

20 flexibility is expected to add value to the resource, even if the resource

21 may also be used to provide a base-load role. Additionally,

2 Direct Testimony of Andrew J. O'Brien, p. 8, Ins 3- 4.

3 Pollock Direct at p. 3, Ins 2 - 3.

Entergy Texas, Inc. Page 3 of7 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 notwithstanding ETI's base-load deficit, ETI still places a value on flexible

2 capacity. The current 2011 Western Region RFP, which seeks to fill a

3 long-term capacity need for ETI, makes clear that flexibility is preferred:

4 Resources supplying flexibility offer benefits to Entergy 5 Texas and the Entergy System that resources with less 6 flexible or inflexible scheduling and dispatch capabilities 7 cannot provide. Bidders are advised that these benefits will 8 be captured quantitatively and qualitatively in the evaluation 9 of proposals and ... will result in, all else being equal, a 10 preference for Flexible Capacity over Baseload Capacity 11 resources. 4 12 13 Further, Mr. Pollock's observation regarding the ability of the Entergy

14 System Operator to order the CGS Supplier to curtail or not operate during

15 System emergencies misses the mark. 5 The referenced emergency

16 curtailment rights do not provide, and are notably different from, the right

17 and ability to adjust the output of a resource to respond to dynamic

18 changes in load, which is the valuable "flexibility" I discuss in my Direct

19 Testimony.

20

21 Q. MR. POLLOCK CONTENDS THAT THE PROSPECT OF PAYING

22 UNSERVED ENERGY FOR LACK OF PERFORMANCE SHOULD

23 ADDRESS ANY FIRMNESS CONCERNS ASSOCIATED WITH THE

4 2011 Western Region Request for Proposals for Long-Term Supply Side Resources, p. 7.

5 Pollock Direct, p. 31, Ins 6- 8.

Entergy Texas, Inc. Page 4 of 7 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 UNIT-CONTINGENT NATURE OF THE CGS PURCHASE

2 AGREEEMENT. 6 DO YOU AGREE?

3 A. No. CGS Suppliers must be Qualified Facilities ("QFs") connected to

4 the ETI System. My low ranking on "firmness" relates to the reality

5 that many factors affect the firmness of a resource. Among these

6 factors would be the number of units providing service. Most QFs

7 consists of a single generating unit, rather than a system or fleet of

8 generating resources. Regardless of economic motivation, the

9 reliability of supply, or firmness, is proportional to the number of units

10 providing service. It follows that a unit-contingent product is less firm

11 than a "system"-contingent product. As noted in my Direct

12 Testimony, the fact that a CGS (QF) Supplier has the primary

13 obligation to serve a host load further reduces the firmness of

14 supply.

15

16 Q. PLEASE COMMENT ON MR POLLOCK'S OBSERVATION WITH

17 REGARD TO HIS EXHIBIT JP-7 THAT ETI HAS ENTERED INTO

18 NUMEROUS UNIT CONTINGENT PURCHASED POWER

6 Pollock Direct, p. 31, Ins 9 - 16.

Entergy Texas, Inc. Page 5 of 7 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 AGREEMENTS, INCLUDING CONTRACTS WITH TERMS AS

2 SHORT AS ONE TO THREE YEARS. 7

3 A. All of the contracts listed in Exhibit JP-7 are distinguishable from the

4 contemplated CGS Purchase Agreements, and, as such, Exhibit

5 JP-7 actually makes the point made in my Direct Testimony. Each

6 of the contracts listed in the Exhibit provide one or more attributes

7 that will not be provided by a CGS Purchase Agreement. For

8 instance, certain of the contracts are for a level of capacity (MW)

9 greater than 150 MW. A number of the contracts provide flexibility.

10 Others provide a term longer than five years. Put another way,

11 unlike the contracts that would result from the CGS program, none of

12 the contracts listed in the Exhibit provide a low level of inflexible,

13 short-term capacity from a resource that Entergy does not control.

14

15 Q. MR. POLLOCK IS PROPOSING A LOWER LIMIT OF 5 MW

16 RATHER THAN THE 10 MW YOU PROPOSED. COULD YOU

17 CONSIDER SUPPORTING A 5 MW LIMIT? 8

18 A. Yes, my Direct Testimony was clear that the concern is not the size

19 of the contracts with CGS Suppliers, but is instead the number of

7 Pollock Direct, p. 32, lines 1 - 5.

8 Pollock Direct, pp. 32 and 43.

Entergy Texas, Inc. Page 6 of 7 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 CGS Suppliers. I should also add that the number of CGS contracts

2 is a concern. As noted in my Direct Testimony, the lower the floor

3 for participation, the greater the opportunity for more suppliers and

4 more contracts at a smaller capacity size, which, as noted in my

5 Direct Testimony, can raise cost-benefit concerns. In the event the

6 Commission determined to permit 5 MW contracts, ETI may seek a

7 limitation on the number of contracts, depending on the ultimate

8 level of participation. 9

9

10 Q. DOES THE FACT THAT ETI'S SERVICE AREA IS WITHIN THE

11 WOTAB PLANNING REGION, A CAPACITY-CONSTRAINED

12 REGION, CAUSE YOU TO RECONSIDER YOUR LOW

13 "LOCATION" RANKING FOR CGS CAPACITY. 10

14 A. No. My ranking attributes some value for "location" to CGS Capacity,

15 which reflects Mr. Pollock's observation that ETI is within WOTAB;

16 however, the relatively low ranking also reflects that all but one QF is

17 located outside of Entergy's Western Region (generally the region

18 within the ETI area that is west of the Trinity River), which has a

19 greater need for capacity than other areas within WOTAB.

9 Based on the contemplated cap of 150 MW for the CGS Program and ETI's recommended 10 MW lower contract limit, the maximum number of contracts would be 15. 10 Pollock Direct, p. 33, Ins 4-7.

Entergy Texas, Inc. Page 7 of 7 Supplemental Direct Testimony of Andrew J. O'Brien Docket No. 38951

1 Q. WOULD YOU PLEASE COMMENT ON THE ISSUE OF

2 AGGREGATION?

3 A. Mr. Pollock acknowledges that he has not conducted a study of the

4 operational, billing or customer support ramifications that might be

5 associated with aggregation. 11 Neither can ETI warrant that there

6 would be no difficulties, including those that might be prohibitive,

7 related to ETI's supply, planning and operational responsibilities,

8 were the CGS program to include aggregation. These

9 considerations suggest that any CGS program, if implemented,

10 should not include aggregation.

11

12 II. CONCLUSION

13 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL REBUTTAL

14 TESTIMONY?

15 A Yes, at this time.

11 Pollock deposition (February 22, 2012), p. 88.

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 95

DOCKET NO. 38951

APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR APPROVAL OF § COMPETITIVE GENERATION § PUBLIC UTILITY COMMISSION SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) § OF TEXAS

SUPPLEMENTAL REBUTTAL TESTIMONY

OF

J. STEPHEN DINGLE

ON BEHALF OF

ENTERGY TEXAS, INC.

FEBRUARY 24, 2012

ENTERGY TEXAS, INC.

SUPPLEMENTAL REBUTTAL TESTIMONY OF J. STEPHEN DINGLE DOCKET NO. 38951

TABLE OF CONTENTS

PAGE

I. INTRODUCTION AND PURPOSE 1

II. CGS CAPACITY AND ETI'S CAPACITY DEFICIT 5

Ill. THE VALUE OF CGS CAPACITY DOES NOT REDUCE EMBEDDED COSTS 11

IV. FLAWS IN MR. POLLOCK'S CALCULATION OF LOWER OPERATING COSTS 13

V. CONCLUSION 26

EXHIBITS p..~ JSD-~ Selected Excerpts from February 22, 2012 Deposition of Jeffry Pollock (Rough Transcript)

JSD-2 Cost-Benefit Analysis of Entergy and Cleco Power ~ Joining the SPP RTO, Prepared by Charles River Associates and Resero Consulting, September 30, 2010 JSD-3 Cost-Benefit Analysis of Entergy and Cleco Power ~ Joining the SPP RTO Addendum Study, prepared by Charles River Associates, December 8, 2010 JSD-4 Power Point Presentation re CODA: Results of the (\ Initial Analysis

Entergy Texas, Inc. Page 1 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 I. INTRODUCTION AND PURPOSE

2 Q. PLEASE STATE YOUR NAME AND CURRENT BUSINESS ADDRESS.

3 A My name is J. Stephen Dingle. My business address is Parkwood Two Building,

4 Suite 300, 10055 Grogan's Mill Road, The Woodlands, Texas 77380.

5

6 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

7 A I am the Lead Regulatory Strategist for the System Planning and Operations

8 ("SPO") 1 organization of Entergy Services, Inc. ("ESI"), 2 which is the service

9 company affiliate of Entergy Texas, Inc. ("ETI" or the "Company").

10

11 Q. PLEASE DESCRIBE YOUR DUTIES.

12 A As the Lead Regulatory Strategist, I am responsible for managing regulatory

13 issues related to the SPO arising before the Operating Companies' 3 retail

14 regulators and the Federal Energy Regulatory Commission ("FERC").

15 Regulatory issues include the application of regulatory policy, execution and the

16 administration of fuel and wholesale power purchases, the determination of

17 avoided costs, the acquisition of new generating resources, the operation of the

System Planning and Operations is a department within ESI tasked with {1) the procurement of fossil fuel and purchased power, (2) the dispatch of the resources of the Entergy Operating Companies, and (3) the planning and procuring of additional resources required to provide reliable and economic electric service to the Entergy Operating Companies' customers. SPO also is responsible for carrying out the directives of the Entergy Operating Committee and the daily administration of aspects of the Entergy System Agreement not related to transmission.

2 ESI is the service company affiliate of the Operating Companies, which provides engineering, planning, accounting, technical, regulatory, and other administrative support services to each of the Operating Companies.

3 In addition to ETI, the Operating Companies include Entergy Arkansas, Inc. ("EAI"); Entergy Gulf States Louisiana, L.L.C. ("EGSL"); Entergy Louisiana, LLC. ("ELL"), Entergy Mississippi, Inc. ("EMI"); and Entergy New Orleans, Inc. ("ENO"). EAI's and EMI's participation in the System Agreement will be terminated effective December 2013 and November 2015, respectively.

Entergy Texas, Inc. Page 2 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Entergy System Agreement4 , and the evaluation of and transition into the

2 Midwest Independent Transmission System Operator, Inc. ("MISO"). My duties

3 routinely require me to interpret and apply regulatory principles, as well as the

4 rules and regulations of the FERC and the Operating Companies' retail

5 regulators to issues facing the SPO organization, especially in matters related to

6 the acquisition of generating resources, wholesale power or fuel transactions,

7 and the application of various FERC and retail regulator-approved tariffs.

8

9 Q. PLEASE DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL

10 BACKGROUND.

11 A. I hold a Bachelor of Science degree, with majors in Economics and Government,

12 from The Florida State University and a Master of Business Administration

13 degree from the Mays School of Business at Texas A&M University.

14 My professional career began in 1980 when I joined Middle South

15 Services, Inc. (ESI's predecessor in name), as an Associate Econometrician in

16 the System Planning department. I remained in the System Planning

17 department, with positions of increasing responsibility, for about the next decade.

18 During my tenure in the System Planning department, I was responsible for

19 preparing forecasts of economic activity, fuel prices, energy consumption, and

20 peak load. I also was responsible for performing various economic analyses.

4 The Entergy System Agreement is an FERC-approved rate schedule and contract entered into among ESI and the Operating Companies, by which the Operating Companies plan, construct and operate their electric generation and bulk transmission facilities as a single, integrated electric system, referred to as the "Entergy System" or, simply, the "System." The System Agreement is administered by the Entergy Operating Committee.

Entergy Texas, Inc. Page 3 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 In 1991, I joined the then newly-created Least Cost Planning Department

2 as the senior analyst responsible for developing and filing with retail regulators

3 Least Cost Integrated Resource Plans ("LCIRPs") for each of the Operating

4 Companies. While in the Least Cost Planning Department, I was responsible for

5 advising the System's senior management regarding the development and

6 implementation of LCIRP policies that would be consistent with Federal and local

7 initiatives advancing the public interest, advocating the System's position in

8 public rulemakings related to LCIRP initiatives, preparing LCIRP filings,

9 assessing demand-side management programs, and considering alternative

10 methods for meeting the Operating Companies' future resource needs.

11 In 1995, I joined EAI as the Regulatory Affairs Coordinator, with

12 responsibility for coordinating EAI's regulatory activities before the Arkansas

13 Public Service Commission ("APSC"). My primary responsibilities in that position

14 were to manage the day-to-day interactions between EAI and the APSC's

15 General Staff and advise EAI and ESI employees regarding compliance with the

16 Arkansas Commission's regulatory requirements. I was also responsible for

17 overseeing the preparation of EAI's filings with the APSC, coordinating EAI's

18 responses to discovery, and training EAI and ESI staff regarding APSC

19 regulatory requirements. In 1999, I returned to ESI as the Manager, Regulatory

20 Affairs for the SPO organization. I was promoted to my current position in early

21 2008.

Entergy Texas, Inc. Page 4 of26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 0. HAVE YOU PREVIOUSLY FILED TESTIMONY IN REGULATORY

2 PROCEEDINGS?

3 A Yes. I have testified before state retail regulatory authorities in Arkansas,

4 Louisiana, Mississippi, and Texas, as well as before the Council of the City of

5 New Orleans ("Council"). I have also provided affidavits in judicial proceedings in

6 Mississippi and Texas. My testimony has addressed matters related to

7 regulatory policy and rulemakings, tariff design and implementation, the

8 reasonableness and recovery of fuel and purchased power costs, integrated

9 resource planning, the acquisition of generating facilities, and the appropriate

10 protection of confidential information.

11

12 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?

13 A I rebut certain of the claims that Texas Industrial Energy Consumers ("TIEC")

14 witness Jeffry Pollock asserts in his February 10, 2012 testimony in this docket.

15 Specifically, I

16 • Discuss Mr. Pollock's flawed understanding of ETI's resource planning

17 and resource plans, ultimately explaining that the CGS program is at best

18 a limited-term alternative that could defer or displace short- and limited-

19 term Purchased Power Agreements ("PPA"), but it in no way can be

20 considered a long-term resource option or a program that affects ETI's

21 long-term acquisition strategy;

22 • Address Mr. Pollock's implied assertion that the CGS program will allow

23 ETI to avoid some level of embedded capacity cost, explaining that -

Entergy Texas, Inc. Page 5 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 consistent with Mr. May's testimony on this issue, any value that might

2 ultimately be attributed to CGS capability does not reduce or offset ETI's

3 embedded generation costs; and

4 • Demonstrate that Mr. Pollock's claim that the CGS program could result in

5 annual operating cost savings of $2 million is conceptually flawed, such

6 that it should be rejected.

7

8 II. CGS CAPACITY AND ETI'S CAPACITY DEFICIT

9 Q. WHAT IS YOUR UNDERSTANDING OF MR. POLLOCK'S CONTENTION WITH

10 RESPECT TO CGS CAPACITY AND ETI'S CAPACITY DEFICIT?

11 A. Mr. Pollock contends that CGS Capacity can reduce ETI's capacity deficit, and,

12 in particular, ETI's base-load capacity deficit. 5 He bases this conclusion on the

13 following provisions included in the tentative proposal under consideration by the

14 parties and described in the Supplemental Direct Testimony of Company

15 witnesses Phillip R. May and Andrew J. O'Brien:

16 • A CGS Supplier must enter into a contract ("CGS Purchase

17 Agreement") with ETI to provide CGS capacity on a 7X24 basis, except

18 when the supplier's resource is not physically available;

19 • The CGS Supplier must obtain the status of a network resource under

20 Entergy's OATT for the duration of the proposed CGS Purchase

21 Agreement (which must also correspond with the term of the contract

5 Pollock Direct at 13, 24-25.

Entergy Texas, Inc. Page 6 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 between the CGS Supplier and the CGS Customer ("Customer-

2 Supplier Contract"). 6

3 • If the above conditions are met, and all remaining issues are resolved,

4 the Entergy Operating Committee 7 has indicated that CGS Capacity

5 can be treated as capacity that is allocated to ETI.

6

7 Mr. Pollock implicitly concludes that because of these attributes - the 7X24

8 delivery obligation in particular - CGS Capacity should be considered a "base

9 load" resource for the Entergy System. He further notes that because the

10 Entergy System's 2009 Strategic Resource Plan ("SRP") Refresh reflects a

11 capacity deficit and, in particular, a base-load deficit of 969 MW for ETI, 8 CGS

12 Capacity "would provide the utility much needed base-load capacity" and "can

13 offset ETI's projected base-load capacity deficit." 9

6 Pollock Direct at 25. Mr. Pollock also states that the CGS supplier must achieve a minimum 80% capacity factor measured during on-peak hours. (Pollock, Page 12, line 11) Actually, as a 7X24 product, CGS Purchase Agreement requires the Supplier to provide energy at the contracted MW level every hour that the facility is available. Mr. Pollock reference is to the economic consequence associated with an increase in demand payment if the Supplier fails to provide energy at the contracted level during 80% of the on-peak hours. Mr. Pollock further states at Page 25, Footnote 9 that "several of ETI's Purchased Power Agreements obligate ETI (and not the seller) to obtain network transmission service. To clarify, there is no relevance to this observation, which speaks only to the process by which transmission service is obtained for a potential System resource. For instance, even under the proposed CGS program, ESI, on behalf of ETI, will be making application for network service for the CGS Purchase Agreement. The fact that ETI (or ESI, on behalf of ETI), takes responsibility for the application process does not change the requirement that the resource must be qualified as a network resource.

7 The Entergy Operating Committee is the entity responsible for administering the Entergy System Agreement, a FERC-filed rate schedule that governs the coordinated planning and operations of the Entergy System.

8 Note that the Entergy System prepared periodic updates of its SRP; subsequent SRPs will reflect a different base load deficit than that shown in the 2009 SRP Refresh as a result of changes in load growth or resource additions/retirements.

9 Pollock Direct, p. 13, Ins 1-8.

Entergy Texas, Inc. Page 7 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 a. ARE THERE FUNDAMENTAL RESOURCE PLANNING PRINCIPLES

2 RELEVANT TO THE EVALUATION OF MR. POLLOCK'S CLAIMS?

3 A. Yes. As an initial observation, it is somewhat irrelevant to discuss "ETI's base

4 load resource need" outside of the context of the System Agreement. The

5 System Agreement requires that all of the System's resources are planned

6 collectively for the mutual benefit of all of the System's load, and the allocation of

7 any new resources is a decision that is made after System-wide resource

8 acquisition issues are addressed. That said, the starting point for the System's

9 resource planning is its load forecast, meaning the demand (MW) and energy

10 (MWh) that the System's resources must serve over various planning horizons.

11 Based on that load forecast, the System then plans for the acquisition of

12 resources necessary to economically and reliably meet the load over the same

13 planning horizons.

14

15 Q. WHAT IS YOUR UNDERSTANDING OF WHETHER THE CGS PROGRAM

16 WILL AFFECT PLANS TO SERVE LOAD PARTICIPATING IN THE CGS

17 PROGRAM?

18 A. It is uncertain how a CGS customer's load will ultimately be treated for planning

19 purposes, or whether that treatment will change over time as ETI gains

20 experience with the program. Having said that, it is my understanding that, at

21 least initially, a customer's participation in the CGS program will not affect ETI's

22 plan to serve the portion of a customer's load associated with CGS Capacity

10

-- --- --~-~~-----~

Entergy Texas, Inc. Page 8 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 ("CGS Load"). 10 Through the CGS program, a customer's load will be served via

2 energy that flows through the meter, and as such will be included in the load that

3 ETI is obligated to serve.

4

5 a. WILL CGS CAPACITY REDUCE LONG TERM RESOURCE NEEDS?

6 A. No. The program, as it is currently defined, will not provide long-term resources

7 to meet projected resource needs. The limited term nature of the proposed

8 agreements, coupled with the uncertainty regarding the future continuation of the

9 program, do not provide sufficient assurance that CGS resources will be

10 available to meet Ell's long-term resource needs. Furthermore, the program

11 does not relieve ETI of its obligation to serve CGS customers in the event that

12 providers withdraw or fail to renew under the program. Ultimately, the CGS

13 program is at best a limited-term alternative that could defer or displace short-

14 and limited-term PPAs, but it in no way can be considered a long-term resource

15 option or affect ETI's long-term acquisition strategy.

16 Because of its characteristics, CGS Capacity could possibly defer or

17 displace the acquisition of new short- and limited-term Purchased Power

18 Agreements ("PPA") that ETI might otherwise acquire, but would not defer or

19 displace the acquisition of long-term capacity. Because ETI will continue to plan

20 to serve Customers' CGS load, while obtaining only short- and limited-term

10

Note, however, that Cities witness Karl J. Nalepa has suggested that the Commission should direct ETI not to plan to serve load served under the CGS tariff. Nalepa Direct at 8. ("ETI should not be permitted to claim that it will continue to include the CGS customer in its capacity planning process .... ) ETI cannot relieve itself of its obligation to serve, and my testimony does not address the changes that would occur within the resource planning process were the Commission to adopt Mr. Nalepa's recommendation and relieve ETI of its obligation to serve CGS load.

Entergy Texas, Inc. Page 9 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 resources associated with that load, ETI's long-term planning, including the

2 acquisition of long-term capacity, will not be affected by the CGS program.

3

4 Q. EVEN ASSUMING THAT A CGS PURCHASE AGREEMENT HAS BASE-LOAD

5 RESOURCE CHARACTERISTICS, IS IT CORRECT TO CONCLUDE THAT

6 CGS CAPACITY REDUCES ETI'S BASE LOAD DEFICIT?

7 A. Not necessarily. First, there is no reduction in the existing base-load capacity

8 deficit with respect to a CGS Purchase Agreement associated with new ETIIoad.

9 In that case, the CGS Capacity is added only for the purpose of serving the

10 additional load contractually associated with the CGS Capacity and, so, as

11 discussed above, there is no additional capacity available to reduce ETI's

12 base-load capacity deficit or any of ETI's capacity deficits for that matter.

13 Additionally, even though it will become a System capacity resource with

14 certain base-load characteristics, a CGS Purchase Agreement does not provide

15 capacity and associated energy to the System in the same way as other base-

16 load resources. A CGS Purchase Agreement is contractually linked to a specific

17 CGS Customer and has been acquired only because of the load of that

18 Customer. Moreover, the System can only rely on the CGS Supply as a firm

19 resource so long as that contractual relationship between the CGS Customer and

20 the CGS Supplier remains in place. This relationship creates additional

21 complexities within the resource planning process, because it adds additional

22 uncertainty to future supply and demand.

Entergy Texas, Inc. Page 10 of26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Q. HOW DO YOU RESPOND TO MR. POLLOCK'S CLAIM THAT CGS CAPACITY

2 REFLECTS A CAPACITY BENEFIT COMPARABLE TO $6.66 PER t<m-

3 MONTH?11

4 A. Mr. Pollock glosses over the fundamental interrelationship between capacity cost

5 and energy cost. It is difficult to consider one without the other. Typically,

6 resource planners are willing to pay high capacity costs for units that have a low

7 variable cost - so long as those units can be run in a base-load role - because

8 over the course of a year the high fixed cost can be spread over a large number

9 of MWh of generation, and the "all-in• cost, or the sum total of the amortized foced

10 cost and the variable (fuel) cost should be relatively low. On the other hand, all

11 things equal, planners are not willing to pay a high capital cost for a resource that

12 will be called on to run only a few hours a year. For example, a nuclear unit

13 tends to have a high capacity cost and a low c-=cost, while a peaker like a

14 combustion turbine typically has a low fixed capital cost and relatively high

15 energy cost. In fact, the Entergy System has recently purchased high-heat rate

16 peaking contracts for a capacity payment of less than $1/kW/month. CGS

17 capacity is a unique product - even though ETI will not pay the CGS Supplier

18 any direct capacity payment, ETI will pay the CGS Supplier its avoided energy

19 cost, which will never be as low as the cost of energy from the System's nuclear

20 units, and may at some times be equal to the cost of peaking energy. 12

11 Pollock Direct at 26-27.

12 Mr. Pollock also seems to suggest that there will be no energy costs to other customers, because the energy cost will be offset by an energy credit. That is an over-simplified argument that ignores the actual mechanics of the PUCT's fiXed fuel factor, fuel surcharge/refund, and fuel reconciliation processes.

- ---~~~~

Entergy Texas, Inc. Page 11 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Ill. THE VALUE OF CGS CAPACITY DOES NOT REDUCE EMBEDDED COSTS

2 Q. DOES MR. POLLOCK CLAIM THAT THE CGS CAPACITY DISPLACES ANY

3 OF ETI'S EXISTING RESOURCES?

4 A Mr. Pollock does not expressly make that claim; however, several of his

5 statements indicate his recognition that CGS Capacity would not displace any

6 existing resources. He states that "CGS can offset ETI's projected base-load

7 capacity deficit." 13 He also purports to explain "how the CGS program could

8 potentially offset the need for new base-load capacity." 14 In his discussion of

9 "other offsetting cost savings," he argues that the CGS program results in

10 capacity available to the Entergy System that "ETI will not have to procure," and,

11 in turn, ETI can "defer or displace additional generation capacity that would be

12 needed to maintain reliable service." 15 Additionally, as mentioned, Mr. Pollock

13 notes that the 2009 Entergy SRP Refresh reflects a deficit for ETI that is

14 substantially greater than the 150 MW maximum cap initially proposed for the

15 CGS program. Even assuming that the entire 150 MW was subscribed under the

16 CGS program, ETI would still have a capacity need greater than all of its existing

17 resources.

13 Pollock Direct at 13 (emphasis added).

14 Pollock Direct at 25 (emphasis added). The discussion of this issue in Mr. Pollock's deposition also indicates that the acquisition of CGS Capacity can only affect future resource decisions (the costs associated with those decisions) made after the acquisition of CGS capacity. Pollock Depo at 72-74.

15 Pollock Direct at 24 (emphasis added).

Entergy Texas, Inc. Page 12 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Q. WHAT IS THE IMPORTANCE OF MR. POLLOCK'S RECOGNITION THAT CGS

2 CAPACITY DOES NOT DISPLACE ETI'S EXISTING CAPACITY?

3 A. Company witness. May, in his Supplemental Direct Testimony (January 26,

4 2012), explained that ETI is seeking recovery of "unrecovered costs" which the

5 Company has defined as its embedded generation costs, 16 and that an offset to

6 these costs is appropriate only if the CGS program results in an actual reduction

7 to ETI's revenue requirement associated with those embedded costs. "17 The

8 embedded costs Mr. May addresses are those caused by ETI's existing

9 generation resources. The recognition that the CGS program will not result in the

10 displacement of existing resources is a tacit recognition that the program will not

11 reduce the Company's embedded costs left unrecovered by a customer's

12 participation in the program. As Mr. May notes, the only appropriate credits to

13 unrecovered costs are those associated with a reduction in the Company's

14 MSS-1 costs, the Fixed Cost contribution Fee, and the Unserved Energy O&M

15 adder charges.

16

17 Q. REGARDLESS OF THE VALUE ASSOCIATED WITH FIRMING UP CAPACITY,

18 IS IT APPROPRIATE TO USE THAT VALUE TO REDUCE EMBEDDED

19 CAPACITY COSTS?

20 A. No. To the extent that there is any intrinsic value to be gained by firming up the

21 QF puts (a claim that I rebut in the following section of my testimony), any such

22 value will be largely, if not exclusively, realized through lower fuel costs. Mr.

16 Direct Testimony of Phillip R. May ("May Direct") at 5-7.

17 May Direct at 16.

,---------------------------------------

Entergy Texas, Inc. Page 13 of 26 Supplemental Rebuttal Testimony of J. stephen Dingle Docket No. 38951

1 Pollock himself recognizes that this is the case, because he denominates his

2 additional savings in $/MWh, a measure associated with energy savings, and not

3 $/~,a measure associated with capacity savings. Moreover, when asked why

4 he presented the value of firming up capacity in $/MWh rather than $/kW, Mr.

5 Pollock replied "we're talking about operating cost savings, and so the most -

6 ,, and in this case trade benefits, most of which are production cost, most of which

7 is that is fue'- a~tEI, .~n~queutty, cuslQme~=a ·~.~m resei¥8 the ileA.efit aa a pa_as f\ 8 tlw~gh without the Reed tc credit cr offset ether ees4:" 18 9

10 IV. FLAWS IN MR. POLLOCK'S CALCULATION OF LOWER OPERATING COSTS

11 Q. DOES MR. POLLOCK CLAIM THAT THE CGS PROGRAM CAN OFFSET

12 SOME OF THE COSTS INCURRED TO PROVIDE FLEXIBLE CAPABILITY?

13 A. Yes. On page 36 of his Supplemental Direct testimony, Mr. Pollock asserts that:

14 Firming up 150 MW of QF Puts will reduce the costs associated 15 with flexible capacity [sic]. Based on a review of various studies 16 presented in recent filings, I believe $2 million per year would be a 17 conservative estimate of lower operating costs.

18 The calculations that Mr. Pollock used to derive this $2 million "conservative

19 estimate" was provided to the Company in a workpaper entitled "CGS Operating

20 Cost Benefits." I have reproduced Mr. Pollock's calculations from that workpaper

21 in the following Table 1, although I have also added row numbers and a brief

22 description of the rows:

18

Rough Draft of Telephonic Deposition of Jeffry Pollock, dated February 22, 2012 ("Pollock Depo") at 46. A copy of all of the citations that I reference from Mr. Pollock's deposition are attached as Exhibit JSD-1.

Entergy Texas, Inc. Page 14 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951 ""'"'--·----------..... -~-""TT"'----"""T"·--------···---"···-· -·····--........--, -~·---- "'' ·-··. -·-· ,., ____ .,__ ·- """""""! I

---··----~· ·--~. ..... - - - - - - - - - · - - - · •• - - - - - - - · - · ---· ---- • - - - - .... 1 Pollock's Work paper Calculation of CGS Operating Cost Benefits 1

. . ~in~~J~~:~~s~~~ -2~~~-($oo;; ~~~d-e~~~-- jso~6"t~~f~~~~~P~;~~~~~~:~s!~dy~-. ·-=1 -·-· ~-- ~;;~ij~~i~~&~~s ~~~es (MW!)J 2 ... --=] 97 '}~-~6.~{ \Line 1 1 Line 2 ·-

--~-4 ··)foDAFI~xible~a·p~ci_tyc~$ooqL_·_--·~·] _ $s,ooO.aa·~-6~~:99~ 2o~~--~-·---~------ _.§...__~r12.Q..1} Sal_e,s.J~L....... ·····-··----·-- 1_g,231..?..?.~·-· ···-···-··--··-------·-···-------' ___ 6 ____ Per Unit S~~~gs ($.~L-----·-·-"··- .......... ·---·-~0.42 Line 4 I ~~':!~.·-··-···-··· ____,_...j 7 Averag.=_5stima_!~.'!.~.~vings ··--·· $0.46 A~rage_of line!}~~-----1 1---8=---- 150 J:!r!'l CGS_@..~nths.t•.. ·----·------ _?..§~!!.POD .. .!50~-~?60*2 -·----·----·-·------.. -1 ___9__ ETI QF~_l,l_I~J?._4 ~O..!hS.) •..- - - - - - - · · ... 8,31~J!OO Actual qfp~!uqr 24_~_ont~C?5!.j Percent~ecte,~_., ___ - -.......,.... - - · ___ 31.6til'~•J!' ~!oe 9_

·=- --j _.!Q__ ····- 1

- __ ]~-- --~~-!~~:~:~-~~~!q}sq.r.v.tfJcqs·--=:-· .... ---·· -- · __!i~~·6f.~~ L.l~§!-7. ~. .~!ne 1iFi!!)~31 ......-.,...~ ....-........ ,_.. .,. .......~-· ....-~..- . --·--- __.. ,.....L -- .........- .........-.~·-·-··- ....._, ___J

1

2 Q. IS MR. POLLOCK'S $2 MILLION "CONSERVATIVE ESTIMATE OF THE

3 LOWER OPERATING COSTS" CREDIBLE?

4 A No. Mr. Pollock's calculation includes several significant errors. Mr. Pollock

5 claims to use two different studies as sources of the quantification of the value of

6 flexible capability: (1) the Cost-Benefit Analyses ("CBA") that Charles River

7 Associates ("CRA") developed to assess the potential benefits that might occur if

8 the Entergy Operating Companies were to join a Regional Transmission

9 Organization ("RTO") and (2) the modeling that Entergy Services prepared to

10 support discussions regarding the Commitment, Operations and Dispatch

11 Agreement ("CODA") that was, at one time, a potential successor arrangement to

12 the Entergy System Agreement. Mr. Pollock's analysis is based on a

13 fundamental misinterpretation of the methodology and results of both of those

14 studies, such that his estimates have no meaning whatsoever.

Entergy Texas, Inc. Page 15 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 That is not the only error that Mr. Pollock made in his analysis. Mr.

2 Pollock also calculated a value that he labeled "Percent Affected: which he

3 asserts represents the percentage of the QF puts that would be firmed up under

4 the CGS program. However, Mr. Pollock's calculation of Percent Affected

5 grossly overstates the amount of QF puts that would be firmed up as a

6 percentage of the total puts. Mr. Pollock then compounds the error by incorrectly

7 applying the "Percent Affected" to ETI's total annual sales to determine his

8 estimate of the potential operating benefit. I will discuss each error in tum.

9

10 Q. WHAT ARE THE CRA CBAs?

11 A. The CRA CBAs are a series of studies that evaluate the costs and benefits that

12 might inure to ratepayers if one or more of the Entergy Operating Companies

13 were to join one of two Regional Transmission Organizations ("RTO"): the

14 Southwest Power Pool ("SPP"), or the Midwest Independent Transmission

15 System Operator, Inc. ("MISO"). The initial report regarding the CBAs - "CBA of

16 Entergy and Cleco Power Joining the SPP RTO" - was released on September '3S"0 -1?. -1.

17 30, 2010. I have attached a copy of that report as Exhibit dSD•1. The Executive 1\ 18 Summary of that report provides a brief background regarding the study itself:

19 On June 24, 2009, the FERC and Entergy's retail regulators held a 20 technical conference in Charleston, South Carolina that was 21 attended by Entergy and many of the entities that purchase and/or 22 sell energy in the Entergy region. The FERC agreed to fund a Cost 23 Benefit Analysis ("CBA"} to study the costs and benefits of Entergy 24 and Cleco Power joining the SPP as full transmission-owning 25 members with their transmission facilities under SPP operational 26 control.

Entergy Texas, Inc. Page 16 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 The CBA was performed over a seven-month period, and included 2 an open and collaborative discussion with stakeholders of the study 3 framework, modeling approach, input assumptions, interim results, 4 and qualitative issues throughout this period. 19 Based on the 5 analysis performed, we conclude that Entergy and Cleco Power 6 joining the SPP RTO will yield significant economic benefits to the 7 collective SPP/Entergy region.

8

9 a. WHAT IS THE BASIC METHODOLOGICAL APPROACH UNDERLYING THE

10 CRA CBA ANALYSES?

11 A CRA collected data on all of the generating facilities and load serving entities

12 located within the Entergy/Cieco Power, SPP, and MISO footprints. 2 ° CRA then 13 incorporated this data, along with other data representing the entire eastern

14 interconnection, into the General Electric Multi-Area Production Simulation Model

15 ("GE MAPS") model. GE MAPS is a detailed economic dispatch and production

16 costing model that simulates the operation of the electric power system taking

17 into account transmission topology.

18 Each scenario involved the preparation of two different GE MAPS cases

19 over the 10 year period from 2013 to 2022:

20 1. Entergy and Cleco Power continue to operate as they do today

21 ("Status Quo Case"}, and

22 2. Entergy and Cleco Power join the SPP RTO ("Join SPP Case").

19 Mr. Pollock did not participate in any of these collaborative stakeholder activities. Pollock Depo at 36.

20 The "Entergy region" refers to the area within the Entergy transmission system footprint, and for purposes of this study includes Louisiana Generating and Louisiana Energy and Power Authority. The "Cieco region" refers to the area within the Cleco transmission system footprint as well as the Cleco Power load served by the Entergy transmission system, and for purposes of this study includes the City of Lafayette. The "SPP region" refers to the SPP transmission system footprint that is currently operating within the SPP Energy Imbalance Service market.

Entergy Texas, Inc. Page 17 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 CRA typically presented the results of each scenario as the ten-year net

2 present value ("NPV") difference in the trade benefits between the two cases.

3 CRA presented results for the Entergy, Cleco, and SPP regions separately, and

4 the Entergy region trade benefits included the Entergy Operating Companies and

5 other entities, including, for example, Louisiana Generating, Louisiana Energy

6 and Power Authority, and Arkansas Electric Cooperative Corporation, Inc. 21

7 Trade Benefits are comprised of the production costs produced by the GE MAPS

8 model for the generating units in the SPP, Cleco and Entergy regions (fuel,

9 variable O&M and emission costs) plus purchased power costs net of energy

10 sales revenue for each region and "lost" transmission revenue. Transmission

11 charges would not be assessed for transactions between SPP, Entergy and

12 Cleco in the Join SPP Case, yielding reduced or "lost" transmission revenue that

13 would have to be compensated for by increased charges to customers.

14

15 Q. DID CRA PERFORM MORE THAN ONE CBA?

16 A. Yes. After the initial CBA to evaluate the potential benefits to joining SPP was

17 begun, the alternative of joining the Midwest Independent System Operator, Inc.

18 ("MISO") became feasible. That alternative was added to the list of CBAs that

19 CRA was to prepare. Moreover, and more relevant to this proceeding, the

20 stakeholders requested that CRA perform a number of sensitivity and addendum

21 studies to evaluate the sensitivity of CRAs results to different sets of input

21 CRA Sept 10 CBA at 2. Mr. Pollock incorrectly assumed that the CBA results for "Entergy" applied just to the Operating Companies (See Pollock Depo at 35.) Mr. Pollock further admitted that his analysis would be wrong if he mistakenly assumed that the values that CRA reported under "Entergy" included more than just the Entergy Operating Companies (Pollock Depo at 36).

Entergy Texas, Inc. Page 18 of26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 assumptions or modeling approaches. The results of these sensitivity and

2 addendum studies were memorialized by CRA in a December 8, 2010 report

3 entitled "Cost-Benefit Analysis of Entergy and Cleco Power Joining the SPP "l~-R.~ 4 Addendum Study•. In that report, which is attached as Exhibit J&B-5", CRA

5 explained that:

6 During the course of the SPP-Entergy CBA, potentially important 7 parameters worthy of additional analysis were Identified by study 8 stakeholders, including seams charges and the treatment of 9 Entergy QFs. In response, CRA was engaged by Entergy to 10 perform an addendum study ("SPP-Entergy CBA Addendum"} to 11 analyze additional sensitivity cases using the models and input 12 assumptions developed under the SPP-Entergy CBA. This 13 addendum study was perfonned by CRA over a three-month 14 period, and included an open and collaborative discussion with 15 stakeholders of the sensitivity analyses to conduct, modeling 16 approach, input assumptions, and interim results throughout this 17 period.

18 *** 19 As trade benefrts are a key determinant in the overall benefits, the 20 impact on 2013 trade benefits resulting from alternative 21 assumptions in 2013 were the main focus of these addendum 22 studies.

23 The key sources of trade benefits between the Status Quo Case 24 and the Join SPP Case are the elimination of commitment and 25 dispatch seams charges, the elimination of IPP commitment 26 hurdles, and the treatment of QFs as firm resources. 22

27

22 CRA Addendum Study at 3-4.

l

Entergy Texas, Inc. Page 19 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Q. DID MR. POLLOCK USE ONE OF THESE SENSITIVITIES IN THE

2 PREPARATION OF HIS TESTIMONY?

3 A. Yes. He focused on the case in which CRA changed the Status Quo ("SQ") case

4 called "SQ2: Entergy QFs Firm." 23 Mr. Pollock has testified that he thought that

5 sensitivity "compared the benefits of firming up the QFs." 24 He further testified

6 that "the whole purpose of doing the sensitivity study was to measure the

7 benefits of firming up the QFs." 25 It is unclear how or why Mr. Pollock arrived at

8 that conclusion; CRA itself reported that the purpose of the CRA CBA was to test

9 the robustness of the finding that there was a potential economic benefit

10 associated with joining the SPP. 26 However, Mr. Pollock, who was not involved

11 in the preparation of the initial CBA or in any of the subsequent addendum or

12 sensitivity studies, misunderstood what that sensitivity was and how the results

13 could be interpreted.

14

15 Q. WHAT WAS THE SQ2: ENTERGY QFs FIRM STUDY INTENDED TO

16 ASSESS?

17 Q. CRA described the basis for this case by initially describing the treatment of QFs

18 in the initial SPP-Entergy CBA:

19 QF Treatment. As discussed in the SPP-Entergy CBA, upon joining 20 an SPP Day 2 RTO, FERC may rule, as it has in other Day 2 21 markets, that the Entergy OF put options no longer apply. If so, the 22 QFs would have to provide prior notice of self scheduled output to

23 Pollock Depo at 37.

24 Pollock Depo at 40.

25 Pollock Depo at 41.

26 CRA Addendum Study at 3-4.

Entergy Texas, Inc. Page 20 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 the RTO system operator. That is, the QFs would effectively 2 operate as IPPs, albeit with the added limitation of needing to serve 3 their host load. To model this, in the Status Quo Case, the Entergy 4 QFs were treated as "non-firm", meaning that the Entergy region is 5 committed day-ahead without QF energy considered. In the Join 6 SPP Case, the Entergy QFs were treated as "firm", meaning that 7 the QFs were treated as available for commitment. 27

8 CRA then described the SQ2: Entergy QFs Firm in Status Quo Case: "[t]his

9 sensitivity has QFs treated as firm in both the Status Quo Case and Join SPP

10 Case." 28 Thus, SQ2 cannot possibly have measured the difference between

11 treating QF puts as firm versus treating it as non-firm. The fact that the $50

12 million trade benefit value for Entergy was based on a comparison of two

13 scenarios that both treated QFs as firm can be confirmed by looking at Table 4

14 of the December 8 Report, which indicates that both the Status Quo (SQ) 2 case

15 and the Join SPP case assume that QFs are firm. 29 Mr. Pollock observed that "if

16 you're comparing the status quo case·and the SQ2, the analysis measures the

17 benefits of firming up the QFs" 30 However, the $50 million reported on Table 5 of

18 the CRA CBA - the $50 million that Mr. Pollock actually used - was not a

19 comparison of the initial status quo case and SQ2. It was instead a measure of

20 the effect of eliminating only the seams charge between the SPP and Entergy

21 regions, and as such cannot be said to determine the value of firming up the QF

22 put.

27 CBA Addendum Study at 7.

28 CBA Addendum Study at 9 (emphasis added).

29 CBA Addendum Study at 8.

30 Pollock Depo at 44.

---- ----------

Entergy Texas, Inc. Page21 of26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Q. DOES THE FACT THAT MR. POLLOCK MISINTERPRETED THE CRA CBA

2 ADDENDUM STUDY UNDERMINE HIS ANALYSIS?

3 A. Yes. In fact, Mr. Pollock himself recognized that fact:

4 4 Q (BY MR. WILLIAMS} My question is: If you 5 5 assume that the -- in both the status quo case and in 6 6 the join SPP case being compared by Charles River, the 7 7 Entergy QFs are firm, then your analysis is wrong? 8 8 MS. GRIFFITHS: Objection, form. 9 9 A If you're saying I compared the same 10 10 circumstances in both cases they're firm, then I picked 11 11 the wrong number. ~ 'fo.. 12 13 Q. YOU EXPLAINED ABOVE THAT THE SECOND BASIS FOR MR. POLLOCK'S

14 ESTIMATION OF THE BENEFIT OF FLEXIBLE CAPABILITY INVOLVED HIS

15 MISUSE OF INFORMATION ASSOCIATED WITH THE CODA. WHAT IS THE

16 CODA?

17 A. The CODA was a draft "Commitment, Operations, and Dispatch Agreemenr that

18 was drafted as a potential replacement for the Entergy System Agreement. It

19 was intended to be a coordinated operating agreement that all of the Operating

20 Companies, including Entergy Arkansas, Inc. and Entergy Mississippi, Inc. -

21 companies that have provided notice that they are terminating their participation

22 in the System Agreement - to remain in a coordinated pooling agreement. The

23 CODA was presented to each of the Operating Companies' retail regulators for

24 comment and review, and none of those retail regulators saw enough promise in

25 the CODA to proceed with further negotiations.

Entergy Texas, Inc. Page22 of26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Q. IS THERE ONE SALIENT FEATURE OF THE CODA THAT IS RELEVANT TO

2 THIS PROCEEDING?

3 A. Yes. One of the new and innovative features of the CODA was the introduction

4 of a "Flex exchange" that would equalize the cost of providing flexible capability

5 across all of the participating Operating Companies. The nature of the flex

6 exchange, and an indication of the amount of flex capability that would be

7 exchanged among the Companies, was described in a presentation made at a

8 PUCT-sponsored technical conference. Mr. Pollock attached a few pages of that

9 presentation to the workpapers to his testimony. I attach the entirety of that ~t> ..f-1{-

10 presentation to my testimony as Exhibit JS&+.

11

12 Q. DID MR. POLLOCK USE SOME INFORMATION FROM THAT PRESENTATION

13 TO DERIVE A VALUE USED IN THIS PROCEEDING?

14 A. He did. Mr. Pollock relied on page 13 (Summary of Differences Between ETI's 3S~-rt-lf'

15 costs under CODA versus the 5-1 scenario in 2014) of Exhibit dSB-4. In his

16 recent deposition, Mr. Pollock testified:

17 2 All right. So if you start with that [page 13 slide], you 18 3 look at the column called flex cost allocation 19 4 differences, I had to eyeball what that is. That 20 5 represents the additional flexible capacity costs or 21 6 basically energy costs that Entergy would incur because 22 7 of its flexible energy requirements a portion of which 23 8 is attributable to the PURPA puts. 31 24

31 Pollock Depo at 48 - 49.

q

Entergy Texas, Inc. Page23 of26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Q. DOES MR. POLLOCK'S APPROACH PRODUCE A MEANINGFUL RESULT?

2 A. No. The fundamental problem is that Mr. Pollock's starting point - the $40 million

3 that he eyeballs from the graph on page 13- is not a measure of the flexible

4 capability or energy costs that ETI would incur as a result of its flexible energy

5 requirements. Rather, the graph presents a comparison of the costs that ETI

6 might have incurred while operating in 2014 under the System Agreement

7 without EAI and the costs that ETI might have expected to incur under the CODA

8 with all six Operating Companies participating. The bar that he uses as the basis

9 for his $40 million number is labeled "Flex Cost Allocation Differences." I am

10 perplexed as to how Mr. Pollock could look at those descriptions, especially in

11 the overall context of this presentation, and reach the conclusion that the $40

12 million was some sort of estimate of the cost of flexibility.

13

14 Q. WHY DO YOU BELIEVE THAT THE CONTEXT OF THE PRESENTATION IS

15 IMPORTANT?

16 A. A review o!J. page 3 of the presentation (the entirety of which is attached at Exhibit ~1)-'YI.•,.

17 ~ may be helpful. A copy of that page follows:

Entergy Texas, Inc. Page 24 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

The main difference in this initial analysis between CODA and the System Agreement revolves around the allocation of flexible energy costs

• Flexible energy costs refer to the costs that correspond to the provision of flexibility for the System • Flexible energy costs are not unique to CODA-- they are as much a part of the System • Agreement as they are of CODA • CODA and the System Agreement allocate flexible energy costs very differently • The System Agreement allocates flexible energy costs regardless of an OPCO's "flex" position (i.e. if it has excess flexibility or is short flexibility)

• CODA allocates flexible energy costs based on an OPCO's flex position • The largest impact relates to different allocations of the flexible energy costs of legacy gas/oil units as the cost of these unit are usually much higher than newer gas and coal units-- i.e. $100/MWh versus $65-75/MWh • The following charts highlight how the CODA and System Agreement structures differ, using three portrayals that are indicative of circumstances faced by the OPCOs

Preliminary Results -- SubJect to Change Addtttonal Scenarios Contemplated

1 As is explained on that slide, the Operating Companies incur costs associated

2 with flexible operation under both the CODA and under the System Agreement.

3 However, one of the key differences between the CODA and the System

4 Agreement is how those costs are allocated. Slide 13 explains that under CODA,

5 ETI is allocated $40 million more in costs associated with flexibility than it is now

6 - in other words, under the current System Agreement regime, ETI is short on

7 flexibility but is not paying the other Operating Companies for that flexibility.

8

g a. DOES THE APPLICATION OF MR. POLLOCK'S APPROACH TO OTHER

10 OPERATING COMPANIES INDICATE THE FUNDAMENTAL FALLACY OF HIS

11 APPROACH?

Entergy Texas, Inc. Page25of26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 A. Yes. First, it is important to note that, as is the case in most forms of energy

2 exchanges, the Flex Exchange sums to zero. That is, the amount of energy that

3 is taken from the exchange exactly equals the amount of energy placed into the

4 exchange. 32 The application of Mr. Pollock's approach would thus suggest that

5 the value of flexible capability for the System is zero. Furthermore, page 14 of

6 the same presentation upon which Mr. Pollock relies indicates that EAI has a

7 negative $25 million Flex Cost Allocation Difference. The application of Mr.

8 Pollock's method for valuing flexible capability to EAI would indicate that there is

9 a negative value, or a cost, associated with firming up the QFs. That is a

10 nonsensical result. A valuation method that does not produce consistently

11 meaningful results across companies cannot be relied upon.

12

13 Q. ARE THERE OTHER FLAWS IN MR. POLLOCK'S CALCULATION?

14 A. Yes. The next error that I address is the "Percent Affected• calculation that Mr.

15 Pollock performs.

16

17 Q. HOW DOES MR. POLLOCK DESCRIBE THE "PERCENT AFFECTED•

18 NUMBER?

19 A. Mr. Pollock claims that the Percent Affected number is the percentage of ETI's

20 QF puts that would be eliminated as a result of the implementation of 150 MW of

21 CGS Capacity. 33

5J.

32 Mr. Pollock acknowledged this fact in his deposition. Pollock Depo at~ 33 Pollock Depo at 53.

\\

Entergy Texas, Inc. Page 26 of 26 Supplemental Rebuttal Testimony of J. Stephen Dingle Docket No. 38951

1 Q. IS MR. POLLOCK'S ASSERTION REASONABLE?

2 A No. Mr. Pollock reaches his 31.6% Percent Affected value by assuming that the

3 150 MW of QF capacity that participates in the CGS program operates at a 100%

4 load factor. 34 He then multiplies 150 MW by 8, 760 hours per year by two years,

5 which yields 2,628,000 MWh, which Mr. Pollock then claims is the amount of

6 energy that would be provided by 150 MW of CGS generation. He then divides

7 that 2.6 million MWh of generation into 8.2 million MWh, which is the actual

8 amount of energy that QFs put to ETI over a two year period, to arrive at 31.6%.

9 But, comparing one number (his assumed QF put) at an assumed 100%

10 load factor with another number that reflects the actual load factor of the QFs that

11 put to ETI, which is approximately 40%, is like comparing apples to oranges. A

12 more reasonable calculation would be to compare the 150 MW of QF capacity

13 that could potentially be firmed up via the CGS program to the 1 ,825 MW of

14 eligible QF suppliers shown in Mr. Pollock's Exhibit JP-1. That produces a

15 "Percent Affected," or percent of QF puts that would be potentially firmed up, at

16 less than 12%.

17

18 V. CONCLUSION

19 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL REBUTTAL TESTIMONY?

20 A Yes.

34 Which, as Mr. Pollock admitted in deposition, is an assumption inconsistent with the actual facts. Pollock Depo at 52-53.

JSD-R-1 Docket No. 389~ Page 1 of~ \1

1

Page 35 1 River analysis looked at? 2 A Well, it's -- the Charles River analysis looked 3 at the whole region, but then Entergy took that analysis 4 and did a second analysis that showed what the benefits s were for just the Entergy -- Entergy operating company. 6 Q Right. But you took that number from the 7 Charles River analysis. Right? 8 A I think that was the original source, but I'll 9 have to check it to make sure. 10 Q Well, let me ask you this. If, in fact, that 11 reference is from -- to Entergy is from the Charles 12 River addendum, that's -- refers to the entire Entergy 13 balancing authority. Correct? Not simply the Entergy 14 operating companies? 15 A Well, I don't recall. There were two studies. 16 The original study was based on the regions, and then I 17 think in the evaluation report that was filed by Entergy 18 at the Commission, they separated the analysis between 19 Entergy operating companies qnd the other regional 20 companies. 21 Q Well, let me -- let me ask you this. Is it 22 correct that if more than just the Entergy operating 23 companies are included in that number, that 24 so million-dollar number, or -- I'm sorry -- the sales 25 number in Row 1, your analysis would be incorrect, would Kennedy Reporting

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JSD-R-1 Docket No. 38951 Page2of~l~ Page 36 1 it not? 2 A Well, it -- it -- I mean, the so million could 3 be higher or lower. Just depends -- I mean, some of the 4 benefits went up when you only looked at Entergy only; S but, yeah, if it if, in fact, the so million is 6 region-wide, then I should have used the Entergy•s 7 operating company specific number, which is the number I 8 thought I used. 9 Q All right. 10 A I'll have to check it and let you know. 11 Q Did you have any involvement with the 12 development of the Charles River cost benefit analyses? 13 A I did not. 14 Q So you weren't -- you didn't participate in the 1S working group that put those together? 16 A No.

17 Q Did not attend the Entergy Regional State 18 Committee meetings where they reviewed that modeling and 19 set it up? 20 A No.

21 Q Have you reviewed the specific addendum study 22 that that so million-dollar number was based on? 23 A I've read through the study, yes. 24 Q All right. And so do you know what the 25 particular identifier of the study how it was Kennedy Reporting

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JSD-R·1 Docket No. 389~y Page 3 of~ ll.a

Page 37

1 identified or what it was called? Particular 2 sensitivity? 3 A I think it was called Cost Benefit Analysis of 4 Entergy and Cleco joining the SPP RTO Addendum Study. 5 It is December 8th, 2010. 6 Q And the particular aspect of the study that 7 resulted in the 50 million-dollar number for Entergy, a would that have been SQ2 Entergy QFs firm? 9 A Yes. 10 Q So you're aware that in this study, each of 11 these different sensitivities reflect different modeling 12 assumptions in the status quo case or in the case in 13 which a move to SPP is compared? 14 A Yes. 15 Q Do you have the December 8th addendum study in 16 front of you? 17 A No.

18 Q Can you get that? 19 MS. GRIFFITHS: I'd like a copy as well if 20 you're going to be going through it with Jeff. Can you 21 get me a copy? 22 A I don't know that I have it in front of me or 23 that I have immediately in front of me. 24 Q (BY MR. WILLIAMS) All right. I'll have to -- 25 I thought you would have that with you.

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JSD-R-1 Docket No. 389~y Page 4 of JiO lla

Page 40

1 $50 million is a comparison to the status quo. 2 Q Well, take a look at Page 7 of the Exhibit 2. 3 Do you see where it says 11 SQ2: Entergy QFs Firm in 4 Status Quo Case"? 5 A Yes. 6 Q And that says SQ2 -- in that sensitivity, it 7 says QFs are treated as firm in both the status quo case 8 and the join SPP case. Do you see that? 9 A Yes. 10 Q So SQ2 does not reflect the value of firming up 11 the QF capacity, does it? 12 A Okay. So the SQ is compared to status quo 13 wait a second. That's not right, then, because the 14 status quo case says nonfirm. So status quo in Table 4 15 says nonfirm. SQ2 shows firm. So that is comparing the 16 benefit of firming up the QFs. 17 I think there's something -- a problem 18 with the way that's being described. But if you go back 19 to Table 4 and you start with the status quo case, that 20 says "QFs nonfirm." SQ2 says "QFs firm." Therefore, it 21 reflects the benefits of firming up the QFs. 22 Q But that's not what it says on Page 7. It says 23 that "This sensitivity has QFs treated as firm in both 24 the status quo case and join SPP case." 25 A Well, that's not what Table 4 says.

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JSD-R·1 Docket No. 38951 Page5of~(p

Page 41 1 Q So you -- you think that Charles River got it 2 wrong in their description on Page 7? 3 A I think there could be a wrong description or a 4 misstatement on page -- on that page because the 5 chart -- I mean, the whole purpose of doing the

1

6 sensitivity study was to measure the benefits of firming '

7 up the QFs. In the status quo case, the QFs were not 8 firm. That's what Table 4 says. And we can read the 9 rest of the report. That's the context in which that 10 that sensitivity was done is what's the benefit of 11 firming up QFs. 12 Q Well, what Table 4 shows is it starts the 13 status quo case, then it does sensitivities. Right? 14 A Right. 15 Q SQ2 shows that the sensitivity is -- make the 16 QFs firm in the status quo case. SQ, status quo. 17 Correct? 18 A Status quo, Sensitivity 2, says -- 19 Q Firm Entergy QFs. 20 A -- makes it firm. 21 Q Right? 22 A Right. So -- 23 (Simultaneous discussion) 24 Q At the bottom, join SPP case 25 MS. GRIFFITHS: Let him finish Kennedy Reporting

JSD-R-1 Docket No. 38951 Page 6 of jt, ~ Page 44

1 QFs from nonfirm to firm. 2 Q But your -- the case you're comparing are the 3 status quo case and the join SPP case. Right? 4 A No. I'm comparing the status quo case where 5 QFs are nonfirm and SQ2 which the Entergy QFs are firm. 6 Q But Charles River was comparing the status quo 7 case with the join SPP case, was it not? 8 A Sure. 9 Q And Status Quo Case 2, which it was comparing 10 to the join SPP case, had the Entergy QFs firm. Right? 11 A Status Quo 2 has the QFs as firm, yes. 12 Q And you compare that to the join SPP case, at 13 the they it also has the QFs firm. And Page 7 14 explains it by saying only the seams charges are 15 different between the two cases. Isn't that not right? 16 A That's what it says. I understand that. 17 Q All right. But just so we can wrap this up, if 18 you assume that the QFs are firm in both the status quo 19 case and in the join SPP case being compared, then your 20 analysis would be wrong. Right? 21 A Well, the status quo case in Table 4 says QFs 22 are nonfirm. So if you're comparing the status quo case 23 and the SQ2, the analysis measures the benefits of 24 firming up the QFs. 25 Q Can you answer my question?

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JS.D- ~- ..1 \)oc.-~t~o. 3~Gj_ \)tt')e.... I ot \lD Page 45

1 A Yes. 2 MS. GRIFFITHS: Restate your question, 3 John. 4 Q (BY MR. WILLIAMS) My question is: If you 5 assume that the -- in both the status quo case and in 6 the join SPP case being compared by Charles River, the 7 Entergy QFs are firm, then your analysis is wrong?

8 MS. GRIFFITHS: Objection, form. 9 A If you're saying I compared the same 10 circumstances in both cases they're firm, then I picked 11 the wrong number. 12 Q (BY MR. WILLIAMS) Okay. You know, 13 Mr. Pollock, your interpretation or explanation of this 14 document, is that based just on looking at the face of 15 the document here this afternoon or do you have some 16 other information that leads you to that interpretation? 17 A I've read the reports. I've read the reports 18 when they were presented and read the reports when the 19 company filed its technical report -- technical 20 evaluation report with the Commission. 21 Q Okay. So it's strictly based on reading the 22 report? 23 A Yes. 24 Q Okay. Going on to Line 3 of Deposition Exhibit 25 1, there you calculate a dollar per megawatt hour per

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JSD-R-1 Docket No.j8951 Page7( J$\ /.Q Page 46

1 unit savings rate. Why is it appropriate to use a 2 calculated capacity benefit of firming up capacity on a 3 dollar per megawatt hour, not a dollar per kW basis? 4 A Since we're talking -- we're talking about 5 operating cost savings, and so the most -- and in this 6 case trade benefits, most of which are production cost, 7 most of which is that is fuel. 8 Q Okay. So these won't these will be 9 produce fuel cost savings mostly. Is that what you're 10 saying? 11 A I said that the lower operating cost associated 12 with reduced flexible capacity requirements; so, yes, 13 there would be changes in operating costs. It would be 14 benefits that customers would see immediately in terms 15 of lower fuel costs. 16 Q So these would not change the company's fixed 17 capacity cost? 18 A Over time, they could because the company says 19 it installs significant amount of flexible capacity in 20 part to the -- for the -- reflect the PURPA put. If you 21 had no PURPA puts, there would be less reserve margin 22 required; therefore, over time, there would be less 23 capacity cost. 24 Q But you haven't calculated that? You've 25 calculated essentially a benefit that flows through fuel Kennedy Reporting

JSD-R-1 Docket No.. )89~!.­ Page/'..of ~ 1 A

p.. \w Page 48 1 A Correct. That's the work paper. 2 All right. So if you start with that, you 3 look at the column called flex cost allocation 4 differences, I had to eyeball what that is. That 5 represents the additional flexible capacity costs or 6 basically energy costs that Entergy would incur because 7 of its flexible energy requirements, a portion of which 8 is attributable to the PURPA puts. 9 I estimated about 20 percent of the -- and 10 eyeballed the number there -- about 40 million-dollar 11 impact, so it doesn't -- it only counts the additional 12 flexible capacity or energy cost that ETI would incur 13 under the CODA and not the -- kind of didn't count any 14 of the flexible energy costs that ETI itself would 15 incur. This is additional cost that ETI would have to 16 purchase from the other company. I determined that 17 about 20 percent of that 40 million would be 18 attributable to the PURPA puts. That's how I got the 19 8 million. 20 Q How did you get 20 percent? 21 A I looked at the company's strategic resource 22 plan and looked at what the resource plan was saying 23 about variations in load in various different time 24 periods, and it cited two things. It cited the 25 variations due to load swings and also the variations Kennedy Reporting

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JSD-R-1 Docket No. 38951 Page/of '!I.

,o \Lt Page 49 1 due to the PURPA puts. If I looked at all four of the 2 scenarios, I looked at the variation in the PURPA puts 3 to the sum of the variation of the PURPA puts and load 4 swing, and you get a number ranging anywhere from the QF 5 puts ranging anywhere from 15 to over half of the load 6 swings. So I picked 20 percent. 7 Q Okay. Now, this analysis is based on 8 information related to what's called the CODA. Right? 9 A Yes. 10 Q What is the CODA? 11 A Commitment, operating and dispatch agreement, 12 which was one of the alternatives that Entergy was 13 considering as a successor to the current system 14 agreement. 15 Q And looking back at the work paper regarding 16 the summary of differences between ETI's costs under the 17 CODA versus the 5-1 scenario -- 18 A Yes. 19 Q -- are you saying the $40 million is the -- 20 well, explain to me again. What are you saying the 21 $40 million represents? 22 A If you look at the bar in the middle, it 23 says -- under -- where it says "Flex cost allocation 24 differences" and eyeball it, it looks like about -- the 25 size of the bar is about 40 million.

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J"<;.D-R,;j_ DoL-¥-2-* No. 3&q«?:L Va~e.. l\ of I{P Page 51

1 operating company either has to self-provide or obtain 2 from other operating companies so that it matches the 3 amount of flexible capacity that each company requires. 4 In this case, ETI would have to spend 5 about $40 million more than its existing flexible 6 capacity resources to meet its flexible capacity 7 requirements. 8 Q So you agree that this flex exchange was 9 intended to compensate the operating companies that 10 provide more than their proportioned share of flex -- 11 capability to the system? 12 A Yes, with the companies that need it more or 13 has less than their necessary share of flexible 14 resources. 15 Q Okay. And so is it correct that a fundamental 16 design principle for an exchange like this is that the 17 dollars in megawatts hours in the exchange sum to zero? 18 MS. GRIFFITHS: Objection, form. 19 A On a system-wide basis, yes, they would. 20 Q (BY MR. WILLIAMS) Okay. So that means some 21 operating companies would have negative values -- 22 right -- or payments associated with the flex exchange. 23 Right? 24 A Right. Works just like MSS-1. 25 Q And other companies would have negative

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JSD-R-1 Docket No. 38951 Page y5 of 1Z'l(.e \'V Page 52

1 values 2 A That's correct. 3 Q -- associated with firming up QF puts. Right? 4 A That's correct. 5 Q Take a look at Line 8 of Exhibit 1. 6 A Yes. 7 Q On there, you calculate 150 megawatts CGS, 24 8 months. Do you see that? 9 A Yes. 10 Q Is that by multiplying 150 megawatts by 8760 11 hours per year for two years? 12 A Yes. 13 Q So that would be a hundred percent load factor. 14 Correct? 15 A Yes. 16 Q But there's no customer generator that has a 17 hundred percent load factor. Right? 18 A Well, this is not measuring the customer 19 generator. It's measuring a CGS customer's supply. 20 Q Well, do they -- will they -- do you expect a 21 CGS customer or the CGS supplier to have a hundred 22 percent load factor for over 24 months? 23 A Probably not exactly a hundred percent load 24 factor, no. 25 Q Are you aware of any customer or supplier that Kennedy Reporting

JSD-R-1 Docket No. 389~~ Page ~of 1-5llt Page 53

1 has a hundred percent load factor now? 2 A No. 3 Q Line 10 has a -- the data is described as 4 percent affected. 5 A Yes. 6 Q And that's Line 8 divided by Line 9. Right? 7 A Yes. 8 Q What is -- what is that representing, the 9 percent affected number? 10 A If we had 150 megawatts of QF puts, that would 11 roughly be about 31.6 percent of all the QF puts that 12 Entergy Texas bought power from over that 24-month 13 period. 14 Q So you're saying that firming up 150 megawatts 15 of QF puts would alleviate the flexible capability needs 16 of a third of ETI's entire annual energy needs? 17 A No. It would eliminate about a third -- 18 31.6 percent of the PURPA put. 19 Q So why do you -- so why do you multiply the 20 percent affected by the total sales? 21 A So the average effect is 46 cents a megawatt 22 hour. It affects roughly 31.6 percent of the total 23 sales. So that's why the value is basically the 46 24 cents times 31.6 percent times ETI's sales. That gets 25 you to 2.3 million.

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\)tvj{_ l4 o.C. l i.Q Page 72

1 A The answer is whatever the power plant is still 2 providing service, it's providing service to somebody. 3 It's needed by somebody on the system. 4 Q So the CGS contract will not cause me to be 5 able to reduce those capacity costs associated with that 6 generating plant. Right?

7 A Not exactly on the day of the CGS contract; but 8 over time, it might.

9 Q Well, my hypothetical was year ten of a 40-year

10 power plant life. There's no CGS contract going to 11 cause me to shed those capacity costs. Right? 12 A I understand. 13 Q Was the answer 14 A The company is in a deficit, and so the company 15 needs additional capacity. It's that additional 16 capacity that would be avoided. 17 Q Okay. So we're not talking about historical 18 we'r~ not talking about avoiding historical embedded 19 capacity costs with CGS capacity. We're talking about 20 the ability to avoid potentially some capacity costs 21 that's incremental that results --

22 A Well, not entirely. No. Your example was for 23 power plants. And, you know, for power plants, you have 24 a need, and it would be an avoided -- it would be 25 avoiding another power plant coming in, which would

Kennedy Reporting

JSD-R-1 Docket No. 389~ Page~. ((p Page 73 1 raise rates for everybody. 2 Q Okay. And that's an incremental 3 A There could be -- there could be a purchased 4 power agreement that you would otherwise not extend 5 because you got this -- you've already met the supply 6 deficit with CGS supply. 7 Q Okay. Well, I bite. Let's go onto the 8 purchased power example. 9 If I have a purchased power contract 10 that's ten years -- has ten years to run on it when I 11 enter into a CGS contract, I'm not going to avoid any of 12 the capacity costs under that purchased power contract 13 because I entered into a CGS contract. Right? 14 A Not for that specific contract, no; but you 15 might not enter into a new contract, or you might 16 enter· -- exit a contract that existed at the time the 17 rates were set because you didn't need the capacity. 18 You didn't -- you decided not to extend the term. I 19 mean, that's why you enter into some short-term 20 contracts. 21 Q Yeah. And assuming you had the right to get 22 out of that contract? 23 A Oh, contracts have a specific term. Sometimes 24 there's one year. Sometimes it's three years. 25 Sometimes it's ten years. At the end of one year, three Kennedy Reporting

JSD·R-1 Docket No. :}8951 Page)'! of)'!, \\1 \\1 Page 74

1 years, ten years, you can deci~e to renew it or not. 2 It's not a question of breaking a contract. It's a 3 question of not renewing it. 4 Q Is it correct your view is that CGS capacity 5 should be viewed as base load? 6 A Sorry? Can you repeat it -- the question? 7 Q Is it your view that CGS capacity should be 8 viewed as base load capacity? 9 A Yes. 10 Q Is short-term base load capacity a common 11 product for ETI or -- I'm sorry -- for the Entergy 12 system? 13 MS. GRIFFITHS: Objection, form. 14 A I don't know what you mean by "common product." 1'5 I mean, the company has bought 24-7 products. That is a 16 base load product. I don't know how common that 17 practice is or if it's still -- still done. The company 18 enters into ETI enters into a three-year deal for 19 base load capacity from Arkansas. That's a -- that's a 20 short-term base load contract. 21 Q (BY MR. WILLIAMS) All right. Let me just wrap 22 this up. Let's talk about base load capacity. Is it 23 your opinion that CGS capacity can allow ETI to avoid 24 the cost of long-term base load capacity? 25 A What do you mean "long-term base load Kennedy Reporting

ll

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 101

Redacted Per Order No. 11

DOCKET NO. 38951

APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR APPROVAL OF § COMPETITIVE GENERATION § PUBLIC UTILITY COMMISSION SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) § OF TEXAS

SUPPLEMENTAL DIRECT TESTIMONY

OF

DENNIS R. ROACH

ON BEHALF OF

ENTERGY TEXAS, INC.

JANUARY 11, 2013

ENTERGY TEXAS, INC.

SUPPLEMENTAL DIRECT TESTIMONY OF DENNIS R. ROACH DOCKET NO. 38951

TABLE OF CONTENTS

Page

1. Introduction and Qualifications 1

II. Purpose 3

III. Non-Fuel Embedded Generation Cost Credit 7 IV. TIEC's Proposal to Avoid Unserved Energy Costs 10 V. TIEC's Proposed Rider CGSC Does Not Allow ETI to Recover Its CGS Implemenation and Administration Costs 13 VI. Fixed Cost Contribution Fee 18

VII. Rider CGS, Rider CGSC, 21 VIII. Conclusion 23

EXHIBITS

Exhibit DRR-SD-1 LIPS Non-Fuel Embedded Production Cost Docket No. 39896

Exhibit DRR-SD-2 ETI's Proposed Rider Schedule CGS

Exhibit DRR-SD-3 ETI's Proposed Rider Schedule CGSC

Exhibit DRR-SD-5 Redline Comparing ETI's Proposed Rider Schedule CGS to TIEC's Proposed Rider Schedule CGS Exhibit DRR-SD-6 Redline Comparing ETI's Proposed Rider Schedule CGSC to TIEC's Proposed Rider Schedule CGSC

Entergy Texas, Inc. Page 1 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 I. INTRODUCTION AND QUALIFICATIONS

2 Q. PLEASE STATE YOUR NAME, BUSINESS ADDRESS, EMPLOYER AND

3 JOB TITLE.

4 A. My name is Dennis R. Roach. My business address is 425 West Capitol,

5 Little Rock, Arkansas 72201. I am employed by Entergy Services, Inc.

6 (ESI)' as Manager Regulatory Strategy.

7

8 Q. ON WHOSE BEHALF ARE YOU SUBMITTING THIS TESTIMONY?

9 A. I am submitting this Supplemental Direct Testimony on behalf of Entergy

10 Texas, Inc. (ETI or the Company).

11

12 Q. PLEASE STATE YOUR EDUCATION, PROFESSIONAL AND WORK

13 EXPERIENCES.

14 A. I hold a Bachelor of Science degree, cum laude, with a major in

15 Mathematics, from Henderson State University and a Master of Arts

16 degree in Management from Webster University.

17 I have spent my entire professional career working for the Entergy

18 System. I began working for Arkansas Power & Light Company (AP&L),

19 Entergy Arkansas, Inc.'s (EAI's) predecessor, in 1981, in the Rate

20 Department as a rate analyst. I primarily worked on rate design, cost

21 analysis, and economic analysis associated with rates. From 1990 to

' ESI is a subsidiary of Entergy Corporation that provides technical and administrative services to all the Entergy Operating Companies.

Entergy Texas, Inc. Page 2 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 1993, I worked for AP&L as a senior analyst in the Rate Department and

2 then in the Market Support Department with additional responsibilities in

3 the areas of cost studies, rate design, and economic analysis.

4 In 1993, I joined ESI, working in the Pricing and Economic Analysis

5 Department as a senior analyst. During this time my duties included rate

6 design, demand side management analysis, cost analysis, special rate

7 contract analysis, and marketing program evaluations for each of the

8 Entergy Operating Companies.2

9 In 2002, I joined the Regulatory Strategy Department as Manager 10 Regulatory Strategy. In this job, I am responsible for assisting in the 11 overall coordination of regulatory issues among the Operating Companies.

12

13 Q. HAVE YOU PREVIOUSLY PROVIDED TESTIMONY BEFORE THE 14 PUCT?

15 A. No.

16

17 Q. WHY ARE YOU QUALIFIED TO PROVIDE THIS TESTIMONY?

18 A. I have worked closely on the development of the Competitive Generation

19 Services (CGS)-related riders that I sponsor through this testimony, and 20 have been involved in the negotiations with the Texas Industrial Energy

2 The Entergy Operating Companies are: ETI; EAI; Entergy Gulf States Louisiana, L.C.C.;

Entergy Louisiana, LLC; Entergy Mississippi, Inc.; and Entergy New Orleans, Inc.

^

Entergy Texas, Inc. Page 3 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 Consumers (TIEC) and the other parties throughout the development of

2 the CGS program.

3

4 II. PURPOSE

5 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

6 A. In this testimony, I:

7 • Address the non-fuel embedded generation cost portion of the

8 Large Industrial Power Service (LIPS) Rate Schedule as derived

9 from the current rates set in PUCT Docket No. 39896;

10 • Explain ETI's concerns with TIEC's proposal to allow a CGS

11 customer to decrease its load as that customer's CGS Supplier

12 decreases its supply, and thereby avoid Unserved Energy

13 charges;

14 • Address the flaws in TIEC's proposed schedule for recovery of

15 CGS-related administration and implementation costs; that is,

16 the Rider "CGSC";

17 • Address the Company's position on the role of the "Fixed Cost

18 Contribution Fee" in the CGS rider; and

19 • Sponsor the three CGS-related riders proposed by ETI in this

20 docket: Rider Schedules CGS, CGSC,

^

Entergy Texas, Inc. Page 4 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 Q. DO YOU SPONSOR ANY EXHIBITS IN THIS FILING?

2 A. Yes. I sponsor the exhibits listed in the Table of Contents to my

3 testimony.

4

5 Q. WILL ANY OTHER WITNESSES ADDRESS CGS ISSUES IN

6 SUPPLEMENTAL DIRECT TESTIMONY?

7 A. Company witness J. Steven Dingle with ESI's System Planning and

8 Operations group (SPO) will provide testimony supporting certain of the

9 issues I address, as well as additional matters that remain unresolved in

10 this docket. Specifically, Mr. Dingle also addresses the 24/7 firm nature of

11 the CGS product and how that affects the Unserved Energy rate, which I

12 also address in part. In addition, Mr. Dingle addresses issues regarding

13 the Entergy System Agreement and the Entergy Operating Committee's

14 role and authority under that agreement; how the CGS program could be

15 affected by ETI's integration into the Midwest Transmission System

16 Operator; termination payments should the CGS Supplier or CGS

17 Customer default in their obligations to provide CGS supply for the entire

18 contracted period; the process for initiating CGS service; and TIEC's

19 proposed "force majeure" provision for the CGS Purchase Agreement.

20

21 Q. WHAT IS YOUR UNDERSTANDING AS TO THE PURPOSE OF THE

22 CGS PROGRAM?

Entergy Texas, Inc. Page 5 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 A. The tentative terms and conditions that address how the CGS program

2 would work are included in Section I of the CGS Stipulated Matters and

3 Stipulated Facts filed by the parties to this proceeding on January 20,

4 2012. In this answer, I will explain the primary (but not all) provisions of

5 the program as laid out in those stipulations.

6 The CGS program, in accordance with PURA § 39.452 and as

7 proposed to be structured by the parties, is intended to provide a specific

8 subset of customers (CGS Customers) within ETI's Large Industrial Power

9 Service (LIPS) Rate Schedule class with the ability, consistent with the

10 requirements of federal law and FERC tariffs including the Entergy System

11 Agreement, to obtain generation service from an alternative supplier. In

12 order to accomplish this objective, to address the Commission's concerns

13 regarding cost shifting under the program, and to address other significant

14 limitations imposed by the legislation (including the requirement that the

15 CGS program not create a conflict with Federal law), the parties to this

16 proceeding have engaged in extensive negotiations and arrived at a

17 tentative solution to at least some aspects of the CGS program design.

18 Under this collaborative proposal, customers eligible for CGS

19 service will contract with a CGS Supplier, which must be a Qualified

20 Facility ("QF") as defined by Rate Schedule LQF that is or will be

21 interconnected to ETI, for a negotiated level of CGS capacity 22 (Supplier-Customer Contract). ETI will not be a party to this contract; 23 however, the Supplier/QF ("CGS Supplier"), based on the

9^

Entergy Texas, Inc. Page 6 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 Supplier-Customer Contract, will then enter into a CGS Purchase

2 Agreement with the Company for the same level of capacity as in the

3 Supplier-Customer Contract. As further discussed in Mr. Dingle's

4 Supplemental Direct Testimony, the capacity supplied by the CGS

5 Purchase Agreement will take the form of a 24/7 unit contingent product.

6 Mr. Dingle also explains, upon fulfillment of other conditions addressed in

7 his testimony in a manner satisfactory to the Entergy Operating

8 Committee, that Committee has agreed to recognize that the CGS

9 Purchase Agreement can provide firm capacity (or, in the terms of the

10 Entergy System Agreement, " capability") to the Entergy System.3

11 ETI will not make a capacity payment directly to the CGS Supplier.

12 Instead, ETI will provide a credit to the CGS Customer equal to ETI's

13 non-fuel embedded generation cost (measured in $/kW/month) for that

14 customer times the CGS Supplied Capacity (kW). Any compensation for

15 the CGS capacity to the CGS Supplier is paid by the CGS Customer

16 pursuant to the terms of a separate Supplier-Customer Contract.

17

18 Q. IS THE INTENT OF THE CGS PROGRAM TO CREATE A CAPACITY

19 MARKET FOR ETI?

3 By providing this testimony, ETI does not in any manner waive its rights to fully contest and independently assert its rights regarding any and all matters that remain in dispute among the parties. ETI presents this testimony solely for the purpose of facilitating the Commission's resolution of the issues listed above.

Entergy Texas, Inc. Page 7 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 A. No. As explained by Mr. Dingle, the CGS program is not intended, or

2 needed, as a means to fulfill ETI's resource needs and the Company

3 would oppose any effort to place a value on CGS capacity based on an

4 alleged resource need for the program. To the contrary, the CGS 5 program, as I noted above, is designed as a means whereby a limited

6 class of eligible customers could gain access to an alternative source of

7 generation apart from that offered by ETI.

8 The Entergy system has planned for and acquired, and will

9 continue to plan for and acquire, short-term, limited-term and long-term

10 resources needed by ETI to reliably serve its Texas customers. However,

11 if implemented properly and consistent with applicable legal requirements,

12 the CGS program could provide a modest amount of additional capacity

13 for the Entergy System. As discussed below and in Mr. Dingle's 14 testimony, however, this resource would come with limitations.

15

16 III. NON-FUEL EMBEDDED GENERATION COST CREDIT 17 Q. WHAT IS THE LEVEL OF THE LIPS NON-FUEL EMBEDDED

18 GENERATION COSTS THAT WILL BE CREDITED TO CGS 19 CUSTOMERS AS PART OF THE CGS PROGRAM?

20 A. The LIPS non-fuel embedded generation costs derived from the rates

21 recently set by the Commission in ETI's most recent base rate Docket

22 No. 39896 is $6.33 per kW per month. The order approving new rates in

23 Docket No. 39896 became final in mid-December 2012 and the new rates

^^

Entergy Texas, Inc. Page 8 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 relate back to service rendered on and after June 30, 2012. As a result,

2 the LIPS non-fuel embedded generation costs figure that has been

3 addressed in prior filings in this docket should be changed from the $6.84

4 per kW per month that resulted from the prior rates approved in ETI

5 Docket No. 37744 to the $6.33 per kW per month derived from the more

6 recent Docket No. 39896. A schedule showing how the $6.33 per kW per

7 month non-fuel embedded cost figure is derived is attached as my Exhibit

8 DRR-SD-1. The $6.84 per kW value resulting from Docket No. 37744,

9 and agreed to by all parties to this docket, was developed by taking the

10 LIPS class non-fuel embedded production cost from the Company's

11 rebuttal cost of service and scaling this value down based on the

12 difference between the LIPS non-fuel total revenue requirement resulting

13 from the settlement in Docket No. 37744 and the LIPS non-fuel total

14 revenue requirement from the Company's rebuttal cost of service. The

15 resulting scaled value was then divided by the LIPS billing demand to

16 develop the LIPS non-fuel embedded production cost on a $/kW basis.

17 This scaling was necessary because the settlement from Docket No.

18 37744 did not identify the functional revenue requirement by rate class. A

19 similar situation exists now as a result of ETI's most recent base rate case

20 (Docket No. 39896) because the Staff's cost of service number running

21 model from Docket No. 38986 also does not identify the functional

22 revenue requirement by rate class. As shown on my attached Exhibit 23 DRR-SD-1, and its supporting work papers, a similar process was used to

Entergy Texas, Inc. Page 9 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 develop the non-fuel embedded production cost for the LIPS class for

2 Docket No. 38986. This change to $6.33 per kW per month should be

3 made in Section VI.B. of Schedule CGS, which is Exhibit DRR-SD-2 to my

4 testimony. As currently written, that section acknowledges that the

5 $6.84 figure should be updated to the current applicable non-fuel

6 embedded generation cost figure.

7

8 Q. BY AGREEING THAT $6.33 PER KW PER MONTH SHOULD BE

9 CREDITED TO CGS CUSTOMERS, IS ETI MAKING ANY CONCESSION

10 REGARDING THE DETERMINATION OF THE COMPANY'S 11 "UNRECOVERED COSTS" RESULTING FROM THE CGS PROGRAM?

12 A. No. The Interim Order issued by the Commission in this Docket

13 No. 38951 on June 12, 2012 concluded, on an interim basis, that the

14 non-fuel embedded generation costs avoided by the CGS customer are

15 not included within the meaning of the phrase " unrecovered costs" to the

16 Company as that phrase is used in PURA § 39.452(b). I understand that

17 that is the Commission's interim ruling, and my testimony here is limited to

18 identifying the level of the LIPS credit that would be provided to the CGS

19 Customers under the CGS rider. By providing this testimony, ETI is not

20 waiving its right to contest the Commission's ruling as to what is and what

21 is not an " unrecovered cost" under PURA § 39.452(b).

l,Q,

Entergy Texas, Inc. Page 10 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 IV. TIEC'S PROPOSAL TO AVOID UNSERVED ENERGY COSTS 2 Q. PLEASE SUMMARIZE THE NATURE AND OBJECTIVES OF THE

3 UNSERVED ENERGY RATE INCLUDED IN THE CGS PROGRAM.

4 A. The unserved energy rate is covered in Section VII of the CGS rider, and

5 is included in both the Company's (Exhibit No. DRR-SD-2) and TIEC's

6 proposed riders. ETI charges the CGS Customer under this rate when the

7 CGS Supplier fails to provide the contracted CGS capacity that is intended

8 to be made available on a 24/7 basis to serve the CGS Customers.

9 Charging the unserved energy rate allows ETI to recover the costs of

10 continuing to serve the CGS Customer when the CGS Supplier fails to

11 deliver. By implementing an Unserved Energy rate, other customers are

12 protected because they are not then burdened with bearing the cost of the

13 energy that ETI must provide to make up for the lack of CGS supply. This

14 is also why the revenues from the Unserved Energy are credited to ETI's

15 fuel balance-to ensure that other customers are not being harmed when

16 a CGS Supplier fails to deliver its contracted supply.

17

18 Q. PLEASE EXPLAIN THE SECOND ISSUE THAT YOU ADDRESS: TIEC'S

19 PROPOSAL TO ALLOW A CGS CUSTOMER TO REDUCE ITS LOAD

20 TO MATCH A DECREASE IN DELIVERIES BY THE CGS SUPPLIER,

21 AND THEREBY AVOID UNSERVED ENERGY CHARGES.

22 A. TIEC's proposed CGS rider, at the end of the first sentence in Section VII, 23 "Unserved Energy," includes the words: "less any corresponding

to

Entergy Texas, Inc. Page 11 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 reduction in the CGS Customer's electricity usage." I understand this

2 phrase to mean that a CGS Customer would be allowed to reduce its load

3 to match a corresponding reduction in its CGS Supplier's deliveries to ETI,

4 and thereby potentially avoid unserved energy charges. ETI does noi 5 agree with TIEC's proposal to allow the CGS Customer to avoid unserved

6 energy payments in this manner. Company witness Dingle addresses 7 certain aspects of this issue in support of ETI's position.

8 In addition to Mr. Dingle's points, this proposal by TIEC is

9 unworkable for a number of reasons related to metering and tracking. If 10 TIEC's proposal were adopted:

11 (1) ETI has no way to know that a reduction in a Customer's load is 12 for economic reasons, rather than because of a reduction in the

13 Customer's CGS Supplier's supply;

14 (2) Entergy's System Operations Center real-time system does not 15 meter customers' consumption (CGS or otherwise). Because there is no 16 real-time data as to both the CGS Customers and CGS Suppliers, there is 17 not a reliable method for a CGS Supplier to notify its CGS Customer(s) 18 that it is reducing its supply;

19 (3) In the situation of one CGS Supplier serving multiple CGS 20 Customers, when the CGS Supplier reduces its supply, there is no method 21 for prioritizing the reduction to the multiple Customers, and therefore no 22 method for determining which CGS Customer should avoid unserved 23 energy charges or the level of required reduction; and

i^

Entergy Texas, Inc. Page 12 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 (4) In the reverse situation-one CGS Customer with multiple CGS

2 Suppliers-all hierarchy rules as to CGS and non-CGS supplies from the

3 Supplier are set by the Supplier, and ETI has no way of knowing how to

4 allocate the reduction in the Customer's load to multiple CGS Suppliers.

5 As a consequence of these various uncertainties, there is no way to

6 reliably match a CGS supply reduction to a CGS customer load reduction.

7 In addition to the metering and tracking-related implications that I

8 just described, Mr. Dingle also notes that the CGS program is intended to

9 result in a 24/7 firm product, and the 80% capacity factor built in to the

10 CGS program is intended to cover potential unavoidable reductions in

11 CGS Supplier deliveries to ETI. If the CGS Customer is also allowed to

12 reduce its load to offset any reduction in CGS supply, the "firmness" of the

13 CGS program, and the very basis for treating the CGS Supplier's

14 deliveries as firm capacity, is compromised. If the CGS program in fact

15 results in a non-firm capacity product from a CGS Supplier, then the

16 Entergy Operating Committee may well determine that it cannot treat that

17 CGS Supplier's CGS capacity as firm and will thereby need to plan to

18 serve that Supplier's CGS Customer(s) with Entergy System capacity,

19 rather than CGS capacity, thus nullifying the core intent of the program as

20 to that Supplier and its CGS Customers.

21 As noted, ETI must stand ready to serve the CGS Customer

22 regardless of what the CGS Supplier delivers to ETI. The solution to

23 TIEC's issue is for the CGS Customer and its CGS Supplier to agree to

I„-5-

Entergy Texas, Inc. Page 13 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 provisions in their separate contract that would account for the Supplier

2 reducing its deliveries. The Commission should reject TIEC's unworkable

3 proposal to allow a CGS customer to match a reduction in CGS supply to

4 a corresponding reduction in the Customer's load

5

6 V. TIEC'S PROPOSED RIDER CGSC DOES NOT ALLOW ETI TO 7 RECOVER ITS CGS IMPLEMENATION AND ADMINISTRATION COSTS 8 Q. PLEASE ADDRESS ETI'S CONCERNS WITH TIEC'S PROPOSED

9 RIDER SCHEDULE CGSC.

10 A. Rider CGSC establishes the formula and method by which ETI would

11 recover its costs of implementing and administering the CGS program.

12 TIEC's version and ETI's version of Rider CGSC are very different. ETI's

13 version is attached as my Exhibit DRR-SD-3. TIEC's version is attached

14 to its November 27, 2012 Motion filed in this docket.

15 TIEC's Rider CGSC fails to carry out the requirement of PURA

16 § 39.452(b) that ETI incur no "unrecovered costs" in connection with the

17 CGS program. TIEC's proposal erroneously:

18 • eliminates virtually all recovery of implementation costs prior to the 19 date the Commission approves the program (save for a small 20 amount included in ETI's most recently established base rates) 21 (TIEC CGSC Rider Sections II, IV, and V); 22 • makes no provision for ETI recovery of implementation costs to the 23 extent there are no CGS subscribers;

/I/

Entergy Texas, Inc. Page 14 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 • makes no provision for recovery of interest to address the time 2 value of money in connection with delay in cost recovery under the 3 rider; 4 • applies revenues from the Unserved Energy rate, without 5 reservation, to reduce the recovery of implementation and 6 administrative costs (TIEC Rider CGSC, Attachment A). The 7 parties have previously agreed that revenues only from the variable 8 O&M portion of the Unserved Energy rate are to be used to reduce 9 unrecovered costs. The parties have further previously agreed that 10 other revenues from the Unserved Energy rate are to be used to 11 reduce reconcilable fuel costs; 12 • applies revenues from the Fixed Cost Contribution Fee to offset 13 and reduce the recovery of CGS program implementation and 14 administrative costs. (TIEC Rider CGSC, Attachment A). 15 16 Q. WHAT IS ETI'S POSITION WITH REGARD TO CGSC COSTS 17 INCURRED PRIOR TO THE DATE THE COMMISSION APPROVES THE 18 CGS PROGRAM? 19 A. For purposes of the current CGS proposal, ETI has been incurring costs to 20 implement this CGS program since 2009 when it proposed the basis for 21 the current CGS proposal in its base rate case filing in Docket No. 37744. 22 The current Docket No. 38951 was severed from Docket No. 37744 and 23 has proceeded since then to result in the CGS riders now at issue before 24 the Commission. ETI will continue to incur those implementation costs 25 until the program commences, and then will incur costs to 26 administer/operate the program once the Commission issues its order

27 directing ETI to proceed with the program. ETI should recover these

(?

Entergy Texas, Inc. Page 15 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 costs-including historical, current, and future implementation costs-as

2 well as administering the CGS program once it is approved.

3 Specifically, ETI proposes that its initial annual program

4 implementation and operation costs be established at a level of $940,500,

5 as addressed in Company witness Phillip May's testimony filed in ETI

6 Docket No. 37744 filed on December 30, 2009, Exhibit PRM-1. However,

7 to show the Rider CGSC calculation for illustrative purposes, ETI is

8 deducting $310,746 from the $940,500. This illustration is shown on

9 Attachment A to Rider CGSC (Exhibit DRR-SD-3). The $310,746 is the

10 amount of affiliate-related costs charged to the CGS Project Code during

11 the Docket No. 39896 test year, and now included in ETI's current base

12 rates as a result of the Commission's order in that case. Thus, ETI is not

13 double recovering these CGSC-related costs through both current base

14 rates and ETI's proposed Rider CGSC. As also shown on 15 Exhibit DRR-SD-3, ETI has also deducted an assumed (for illustrative

16 purposes) $20,000 attributable to the "Rider CGSC Unserved Energy

17 Variable O&M Charge," for a total Rider CGSC Recovery Amount of

18 $619,254. To derive the Rider CGSC rate for the following year, the

19 CGSC Recovery Amount would be divided by the CGS or LIPS class kW

20 for the prior year. This initial Rider CGSC rate would be proposed some

21 months after the Commission approves a CGS Program, but ETI cannot

22 identify precisely when that filing would be made until it has a Commission

23 order in hand.

Entergy Texas, Inc. Page 16 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 Q. WHAT IS ETI'S POSITION WITH REGARD TO TIEC'S "INCREMENTAL"

2 COST RECOVERY PROPOSAL?

3 A. In Section II of its version of the CGSC rider, TIEC defines "incremental"

4 costs as reasonable and necessary costs incurred by ETI "following" the

5 Commission's approval of the CGS Program. Through this definition, 6 TIEC is proposing that ETI not recover any of its implementation costs

7 incurred prior to the date the Commission approves the CGS Program.

8 ETI disagrees with that position because it would result in ETI not

9 recovering those unrecovered costs, contrary to PURA § 39.452.

10

11 Q. SHOULD RIDER CGSC ACCOUNT FOR A POTENTIAL SITUATION IN 12 WHICH THERE ARE NO CGS SUBSCRIBERS?

13 A. Yes. TIEC's proposed Rider CGSC does not account for this potential 14 situation. In that situation, ETI will, nevertheless, have incurred costs to

15 implement the program even if no Customers subscribe. These would be

16 "unrecovered" implementation and administrative costs, which ETI is

17 entitled to recover in accordance with PURA § 39.452, as is provided for in

18 ETI's proposed Rider CGSC. ETI's proposal is that, if there are no CGS

19 subscribers, these costs would be recovered from all customers taking 20 service under Rate Schedules LIPS and LIPS Time-of-Day.

i^

Entergy Texas, Inc. Page 17 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 Q. SHOULD ETI RECOVER INTEREST ON THE FUNDS ITS EXPENDS TO

2 IMPLEMENT AND ADMINISTER THE CGS PROGROM PRIOR TO

3 RECOVERING THOSE COSTS THROUGH RIDER CGSC?

4 A. Yes. As noted above, there is a time value of money associated with

5 ETI's expenditures between the time those expenditures are made and

6 when they are actually recovered through Rider CGSC. ETI's proposed

7 Rider CGSC, therefore, includes a cumulative interest line item to account

8 for this value.4

9

10 Q. SHOULD ALL REVENUES RECEIVED BY ETI UNDER THE UNSERVED

11 ENERGY RATE PROVISION BE USED TO REDUCE THE RIDER CGSC 12 COSTS?

13 A. No. The parties have agreed that the structure of the rate for Unserved

14 Energy will include an agreed energy charge and an agreed Operation

15 and Maintenance (O&M) adder. The monthly CGS Unserved Energy 16 charge will be the sum of (a) hourly Unserved Energy times 105% of the 17 system hourly avoided energy costs for ETI for the current month and 18 (b) the hourly CGS Unserved Energy times specified variable O&M 19 charges. This agreement is memorialized in both the "Agreed List of 20 Settled Issues" filed in Docket No. 38951 on November 1, 2011 at page 2, 21 Paragraph C. and in the "CGS Stipulated Matters and Stipulated Facts"

° TIEC deleted any reference to interest in the body of Rider CGSC, though it did leave a reference to "cumulative interest" in Attachment A to its proposed rider. Thus, the intent regarding the treatment of interest is not clear.

Entergy Texas, Inc. Page 18 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 filed in this docket on January 20, 2012 at pages 2-3. The document

2 provides that revenues from the variable O&M portion of the Unserved

3 Energy rate will be used to offset unrecovered costs.5 But that stipulation

4 also provides that the revenues from the portion of the rate that is based

5 on system avoided energy charges will go towards offsetting ETI's eligible

6 fuel costs.6 Thus, to maintain consistency with the parties' agreement, not

7 all revenues from the Unserved Energy rate are used to offset the CGSC

8 costs-only revenues the variable O&M charges are used for that

9 purpose, and is necessary to help prevent other non-participating

10 customers from subsidizing the CGS Program.

11

12 VI. FIXED COST CONTRIBUTION FEE 13 Q. WHAT IS THE "FIXED COST CONTRIBUTION FEE"?

14 A. This fee is a fixed dollar per kW charge paid on a monthly basis to ETI by

15 a CGS customer as part of the compensation ETI receives to provide CGS

16 service. This fee is referenced in Section VI of the CGS rider proposed by

17 both TIEC and ETI.

This may be a typographical error. It is possible that TIEC intended to reference variable O&M revenue only from the unserved energy rate as being used to reduce the unrecovered implementation and administrative costs. See "CGS Stipulated Matters and Stipulated Facts" at page 3, Item F.5.

6 See CGS Stipulated Matters and Stipulated Facts at page. 3, Item and F.6. To reduce remaining controversy among the parties, ETI has conformed its rider to TIEC's proposal to use the variable O&M revenue to offset CGS implementation and administration costs.

Entergy Texas, Inc. Page 19 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 Q. WHAT IS TIEC'S PROPOSAL REGARDING THE USE OF THE FIXED

2 CONTRIBUTION FEE?

3 A. In Section VI.A. of its proposed CGS rider, TIEC proposes that "Revenues

4 received from this fee will reduce ETI's Rate Schedule CGSC charges."

5

6 Q. WHY SHOULD THE $1.10 per kW FIXED COST CONTRIBUTION FEE

7 NOT BE USED TO REDUCE RIDER CGSC COSTS?

8 A. As recognized by TIEC, the Office of Public Utility Counsel (OPUC), and

9 the Cities in this docket, the $1.10 per kW Fixed Cost Contribution Fee is

10 intended to compensate ETI for standing ready to serve the CGS

11 Customer.' This $1.10 fee was intended to offset unrecovered production

12 costs, not unrecovered implementation and administration costs. This 13 point is addressed in the "Agreed List of Settled Issues" filed in this docket

' The citations to TIEC's OPUC's, and the Cities' testimony on this point are: Direct Testimony of TIEC witness Jeffry Pollock at page 16, lines 3-11: "The costs of backup power will be paid for by CGS Customers through the Unserved Energy Rate and a Fixed Cost Contribution Fee referenced in the Stipulation. Unserved Energy will be priced at 105% of avoided energy cost plus an O&M Adder. This is similar to how ETI currently prices backup power in Schedule SMS. In addition, the CGS Customer will be required to pay a Fixed Cost Contribution Fee of $1.10 per kW-Month of CGS Contract Capacity. The Unserved Energy pricing mechanism ensures that CGS Customers pay all of the incremental variable costs associated with back-up power plus a contribution to generation fixed costs." (Feb. 10, 2012) Supplemental Rebuttal Testimony of TIEC witness Jeffry Pollock at page 12, lines 7-9: "ETI will incur production costs (capacity, O&M, fuel) only to provide backup power, which is covered through the Unserved Energy rate and the Fixed." (Feb. 24, 2012). Supplemental Direct Testimony of OPUC witness Clarence Johnson at page 11, lines 16-18: "ETI must maintain generating capacity to serve CGS load when the associated cogeneration is not providing output. The CGS customers pay a$1:10 per month fixed charge in recognition of that fact." (Feb. 10, 2012). Supplemental Direct Testimony of Cities witness Karl Nalepa at page 10, lines 14-17: "Over time, the only production costs that would be incurred by ETI for providing firm production service to CGS customers should be recovered through the CGS fixed cost contribution and revenues generated from the variable O&M unserved energy rate. If not, the fixed cost contribution and unserved energy rate should be adjusted so that the CGS customer is responsible for any production costs that it causes to be incurred." (Feb. 10, 2012).

^^

Entergy Texas, Inc. Page 20 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 on November 1, 2011, which, at page 3, Section G, states: "Certain

2 revenues from the Unserved Energy Rate, and all revenues from the

3 Fixed Cost Contribution, will be applied as an offset to any production

4 costs unrecovered as a result of the implementation of the CGS tariff."

5 (Emphasis added.) ETI's position on this point is further bolstered by

-6 Cities acknowledgment that the Fixed Cost Contribution Fee was intended

7 to offset embedded production costs: "Even though ETI alleges that the

8 unrecovered costs would be the full amount of LIPS production cost

9 revenues of $6.84/kW/month, ETI would reduce (or offset) that amount by

10 the fixed cost contribution fee and the variable O&M unserved energy

11 revenues."8 Thus, the $1.10 charge was intended to offset "production"

12 costs, not the implementation and administration costs covered by Rider

13 CGSC. As indicated by TIEC, OPUC, and the Cities, the $1.10 charge is

14 necessary to compensate ETI for standing ready to serve the CGS

15 Customers and, therefore, should be retained by ETI rather than being

16 credited back to the customers who paid that monthly charge. The $1.10

17 charge cannot be used to recover both implementation costs and also

18 compensate ETI for standing ready to serve CGS customers.

8 Karl Nalepa Supplemental Direct Testimony at page 11, lines 19-22 (Feb. 10, 2012)

( Emphasis added).

^j

Entergy Texas, Inc. Page 21 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

1 VII. RIDER CGS, RIDER CGSC, 2 Q. DO YOU SPONSOR THE RIDERS CGS, CGSC,

3 ATTACHED AS EXHIBITS TO YOUR TESTIMONY?

4 A. Yes. I sponsor those three Riders, as well as the appendices and

5 attachments to those Riders.

6

7 Q. PLEASE BRIEFLY DESCRIBE EACH OF THESE RIDERS.

8 A. Rider CGS is the schedule that sets out the CGS program. It is attached

9 as my Exhibit DRR-SD-2. Rider CGS addresses: the availability of CGS 10 service; who is eligible for this service; how CGS service is initiated;

11 tracking certifications; termination events and rights; billing; unserved 12 energy; metering; and reporting requirements. Rider CGS also includes 13 an "Appendix A," which sets out the general terms and conditions that 14 would apply to an ETI-Supplier Contract. ETI had intended that a form of 15 the ETI-Supplier Contract would have been developed and filed with these 16 Riders, but ETI and TIEC were unable to agree to such a form contract. 17 I have generally described Rider CGSC above. This Rider, 18 attached as Exhibit DRR-SD-3, sets out the recovery of ETI's CGS 19 implementation and administration costs. This Rider includes an 20 "Attachment A" that sets out the proposed CGSC rate for illustrative 21 purposes. The Company's intention would be to file a revised Rider 22 CGSC when the costs of developing and administering the ultimate CGS 23 program are known.

-^ Y

Entergy Texas, Inc. Page 22 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

I

2

3

4

5

6

7

8

9

10

11

12

13 Q. DO YOU SPONSOR ANY OTHER EXHIBITS?

14 A. Yes. For illustrative purposes, I have included two additional exhibits.

15 Exhibit DRR-SD-5 is a redline comparison of ETI's proposed Rider CGS to

16 TIEC's proposed Rider CGS filed with its November 27 motion.

17 Exhibit DRR-SD-6 is a redline comparison of ETI's proposed Rider CGSC

18 to TIEC's proposed Rider CGSC. These two exhibits are presented to

19 better assist the Commission in understanding, and seeing, the

20 differences between ETI's and TIEC's respective proposals for these two

21 Riders.

as

Entergy Texas, Inc. Page 23 of 23 Supplemental Direct Testimony of Dennis R. Roach Docket No. 38951

VIII. CONCLUSION 2 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT

3 TESTIMONY?

4 A. Yes, at this time.

a^X

Docket No. 38951 Entergy CGS Tariff ETI EXHIBIT NO. 103

DOCKET NO:: :3$951" 5 r `

2013 FEB -I PM 2: 53 APPLICATION OF ENTERGY BEFORE THE TEXAS, INC. FOR APPROVAL OF COMPETITIVE GENERATION § PUBLIC UTILITY COMMISSION SERVICE TARIFF (ISSUES SEVERED § FROM DOCKET NO. 37744) § OF TEXAS

SUPPLEMENTAL REBUTTAL TESTIMONY

OF

DENNIS R. ROACH

ON BEHALF OF

ENTERGY TEXAS, INC.

FEBRUARY 1, 2013

/7 i

ENTERGY TEXAS, INC.

SUPPLEMENTAL REBUTTAL TESTIMONY OF DENNIS R. ROACH DOCKET NO. 38951

TABLE OF CONTENTS

Page

1. Introduction 1

II. Response to TIEC 1

III. Response to Staff 11

IV. Response to OPUC 12

V. Response To WAL-MART/SAM'S CLUB 17

VI. Conclusion 17

EXHIBITS

Exhibit DRR-SR-1 TIEC Response to ETI RFI's

Exhibit DRR-SR-2 ETI Response to TIEC RFI 4-4 Subpart (a)

Page 1 of 17 Entergy Texas, Inc. Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 I. INTRODUCTION

2 Q. PLEASE STATE YOUR NAME, BUSINESS ADDRESS, EMPLOYER AND

3 JOB TITLE.

4 A. My name is Dennis R. Roach. My business address is 425 West Capitol,

5 Little Rock, Arkansas 72201. I am employed by Entergy Services, Inc.

6 (ESI)' as Manager Regulatory Strategy.

7

8 Q. ARE YOU THE DENNIS ROACH WHO FILED SUPPLEMENTAL DIRECT

9 TESTIMONY IN THIS DOCKET ON JANUARY 11, 2013?

10 A. Yes.

11

12 II. RESPONSE TO TIEC

13 Q. ON PAGE 9 OF HIS SECOND SUPPLEMENTAL DIRECT TESTIMONY,

14 TIEC WITNESS JEFFRY POLLOCK STATES THAT "TIEC'S PROPOSED

15 [CGS] TARIFF COMPORTS WITH THE PARAMETERS OF THE CGS

16 PROGRAM AS DISCUSSED IN THE PRIOR STIPULATIONS AND IN

17 THE INTERIM ORDER, AND IT PROVIDES A WORKABLE PROCESS

18 FOR INITIATING CGS SERVICE." HOW DO YOU RESPOND?

19 A. While I agree that ETI and TIEC (along with the Staff and other parties)

20 have made significant progress in resolving many contentious and

21 complex issues, TIEC's version of Rider CGS does not comply with the

' ESI is a subsidiary of Entergy Corporation that provides technical and administrative services to all the Entergy Operating Companies.

Entergy Texas, Inc. Page 2 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 final sentence in PURA § 39.452(b) because it would be contrary to "an

2 applicable decision, rule or policy statement of a federal regulatory

3 authority having jurisdiction" (that is, the Federal Energy Regulatory

4 Commission) as discussed by Company witness Dingle. In addition,

5 TIEC's version of Rider CGS should be rejected for the reasons discussed

6 in Mr. Dingle's Supplemental Direct and Second Supplemental Rebuttal

7 Testimony, as well as my Supplemental Direct and this Supplemental

8 Rebuttal Testimony.

9

10 Q. ON PAGES 25-26 OF HIS SECOND SUPPLEMENTAL DIRECT

11 TESTIMONY, MR. POLLOCK ASSERTS THAT THE RIDER CGSC

12 (IMPLEMENTATION AND ONGOING ADMINISTRATION COSTS)

13 SHOULD APPLY TO COSTS INCURRED ONLY AFTER THAT RIDER IS

14 APPROVED AND THAT ETI IS ALREADY RECOVERING LEGAL AND

15 REGULATORY COSTS RELATED TO THE CGS PROGRAM THROUGH

16 ETI'S BASE RATES. HOW DO YOU RESPOND?

17 A. ETI is and has been incurring costs to implement the CGS Program since

18 prior to November 10, 2010, which is the date the PUCT severed the CGS

19 Program from Docket No. 37744 to establish this docket. ETI, however, is

20 requesting recovery of its implementation costs only from that November

21 10, 2010 date forward. There is no way that ETI could put the CGS

22 Program into effect without incurring these implementation costs: we

23 would not have a proposed tariff, much less completed all of the drafts,

Entergy Texas, Inc. Page 3 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 analyses, and discussions necessary to work through the myriad complex

2 issues that have brought us just to this point. In addition, TIEC's assumed

3 recovery via base rates in Docket No. 39896 did not begin until June

4 2012, which is long after costs started being incurred. There is no doubt

5 that, under TIEC's approach, these implementation costs would go

6 "unrecovered" if ETI were not allowed to collect them. My understanding

7 is that the PUCT has concluded, on an interim basis, that "unrecovered

8 costs" are the "costs to implement and administer the CGS program tariff."

9 (Interim Order at page 6.) TIEC's approach would allow only recovery of

10 the costs of administering the tariff.

11 As to Mr. Pollock's second point, yes, there is an amount

12 attributable to ETI's work on the CGS Program that was used to set

13 current base rates. But ETI is proposing, in its Rider CGSC, to credit the

14 amount used to set current retail base rates ($299,372)2 to the ultimate

15 Rider CGSC rate. For a further discussion about what was included in the

16 setting of base rates and if it is determined that something else should be

17 done, how to avoid rate class subsidy issues, please refer to Section IV of

18 this testimony below where I respond to OPUC's testimony on this issue.

19

2 ETI's Rider CGSC should have only credited the retail portion included in base rates of $299,372 because that is the level authorized for recovery in current retail rates and not the full $310,746. The difference between the two figures is the amount allocated to the wholesale class.

);5

Entergy Texas, Inc. Page 4 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 Q. ON PAGE 26, MR. POLLOCK CONTENDS THAT THE $1.10 FIXED

2 COST CONTRIBUTION FEE SHOULD BE USED TO REDUCE THE

3 "UNRECOVERED COSTS," THAT IS, THE COSTS TO BE COLLECTED

4 THROUGH RIDER CGSC. DO YOU AGREE?

5 A. No. I addressed this point in some detail in my Supplemental Direct

6 Testimony. Mr. Pollock is correct if the PUCT had concluded that

7 "unrecovered costs" included ETI's unrecovered embedded production

8 costs, but it did not. The fixed cost contribution fee is necessary for ETI

9 standing ready to provide service to the CGS Customer regardless of

10 whether the Customer's CGS Supplier delivers its contracted supply to

11 ETI. ETI should be allowed to retain this fee in order to at least contribute

12 to, if not cover, the incremental cost incurred by the Company to stand by

13 to serve this load. Staff witness Mendoza came to this same conclusion in

14 his January 25, 2013 testimony by referring to the Agreed List of Settled

15 Issues that state that the Fixed Cost Contribution Fee "will be applied to

16 offset any production costs unrecovered as a result of the implementation

17 of the CGS tariff."3

18

19 Q. ON PAGE 27, MR. POLLOCK STATES THAT IT IS PREMATURE TO

20 ADDESS HOW ETI WOULD RECOVER ITS RIDER CGSC COSTS IF

21 THERE ARE NO CGS CUSTOMERS. HE STATES THAT IT WOULD BE

22 SPECULATIVE TO ASSERT THAT THERE WOULD BE ZERO

3 Docket No. 38951, Mendoza Direct Testimony at 11.

(-Lo

Entergy Texas, Inc. Page 5 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 PARTICIPATION AND, EVEN IF THERE WERE NO PARTICIPANTS,

2 THE COSTS WOULD BE DI MINIMIS. HOW DO YOU RESPOND?

3 A. This is another situation in which TIEC is attempting to put off an important

4 and real issue, and thereby place at risk ETI's ability to recover these

5 costs. Once again, TIEC has responded to an ETI request for information

6 that it does not keep records of which of its members have even

7 expressed an interest in the CGS Program-TIEC cannot name even one

8 of its members (also ETI customers and/or Qualifying Facilities "QFs")

9 who are interested. My attached Exhibit DRR-SR-1 is a copy of TIEC's

10 responses on this point. Staff witness Mendoza has agreed with ETI's

11 proposal and that "In the event no customers subscribe to the CGS

12 program, any unrecovered costs should be borne by the customer class it

13 was designed to potentially benefit."4 Further, the costs incurred by ETI to

14 implement the CGS Program to date are $945,100 for the period

15 December 2010 through November 2012, which the Company reported to

16 TIEC in response to TIEC 4-4 subpart (a). This response is attached as

17 my Exhibit DRR-SR-2. This value is certainly not di minimis. There is no

18 valid reason to not address this issue now as an important component of

19 the CGS Program.

20

4 Id. at 9.

Entergy Texas, Inc. Page 6 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 Q. ON THE SAME PAGE, MR. POLLOCK ALSO ASSERTS THAT ETI

2 SHOULD NOT ACCRUE INTEREST ON THE UNRECOVERED

3 BALANCE OF THE RIDER CGSC CHARGES. DO YOU AGREE?

4 A. No. Mr. Pollock analogizes this requested interest recovery to what he

5 refers to as the typical practice regarding rate case expenses. This is not

6 a "typical" case; it is instead a case subject to a specific statutory provision

7 that applies only to a CGS Program for ETI. Rider CGSC would recover

8 the costs that ETI incurs to implement and administer the CGS Program,

9 which the PUCT has ruled, on an interim basis, that ETI is entitled to

10 recover. There is a time value of money associated with the unrecovered

11 balance of CGSC costs, due to the delay in their recovery, which is

12 addressed by allowing ETI to recover interest on this unrecovered

13 balance. Otherwise, ETI will not be recovering the full amount of these

14 unrecovered costs.

15

16 Q. ON PAGE 15 AND PRIMARILY PAGES 27 THROUGH 29, MR.

17 POLLOCK ARGUES THAT THE PROVISION ADDRESSING

18 "UNSERVED ENERGY" SHOULD INCLUDE A PROVISION THAT

19 ALLOWS A CGS CUSTOMER TO REDUCE ITS LOAD TO MATCH A

20 REDUCTION IN CGS SUPPLIERS TO ETI BY THE CGS SUPPLIER. DO

21 YOU AGREE?

22 A. No. Mr. Pollock asserts a number of points in an attempt to support

23 TIEC's request to include this " reduce load to match reduced supplies"

Entergy Texas, Inc. Page 7 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 provision. I also addressed this at some length in my Supplemental Direct

2 Testimony, as did Mr. Dingle. The fundamental bottom line is that TIEC's

3 proposal ignores the 24/7 Unit Contingent nature of the CGS product, to

4 which TIEC has agreed.

5 In addition, as described in Mr. Dingle's Second Supplemental

6 Rebuttal Testimony, the Entergy system would purchase the CGS Supply

7 to satisfy system load. There is no direct link between the CGS Supply

8 and the CGS Customer load as implied by TIEC. TIEC attempts to make

9 this connection between CGS Supply and the CGS Customer in order to

10 equate the simultaneous reduction in CGS Supply and CGS Customer

11 load to the simultaneous reduction in host load and host generation

12 associated with the provision of standby service to customer host

13 generation. These two situations are drastically different as I explain

14 below.

15 Under Standby service for host generation, Entergy (and ETI) is not

16 purchasing the host generation, rather it is satisfying host load and any

17 excess in generation may or may not be "put" to the Company in the form

18 of a QF put. The simultaneous reduction in load and generation happens

19 with a singular customer at a single location, and the Company in all

20 likelihood does not even know, or need to know, that this has occurred.

21 On the other hand, for the CGS Program, the CGS Supplier must have

22 obtained firm transmission service, committed to supply a 24/7 unit

23 contingent product to the Entergy transmission grid as described by Mr.

q

Entergy Texas, Inc. Page 8 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 Dingle, and agreed that CGS Supply is being provided to serve the

2 Entergy System load, rather than a specific CGS Customer. If this CGS

3 Supply is suddenly no longer available, Entergy and its other customers

4 will incur a cost to 1) replace this energy source and 2) plan for and

5 provide standby service whether or not a customer's load (CGS or

6 otherwise) coincidentally is reduced.

7

8 Q ON PAGE 28, MR. POLLOCK SUGGESTS THAT THE CGS CUSTOMER

9 WILL HAVE INTERVAL DATA RECORDING METERING IN PLACE SO

10 ETI SHOULD BE ABLE TO TELL WHEN THE CUSTOMER IS

11 REDUCING LOAD IN ORDER TO MATCH THE CGS SUPPLY

12 REDUCTION. DOES THIS STATEMENT FULLY ADDRESS THE

13 BILLING ISSUES ASSOCIATED WITH TIEC'S PROPOSAL?

14 A. No. This statement makes a rather broad conclusion about "matching"

15 that does not address the events that are likely to occur in the real world

16 but instead raises numerous unanswered questions. First, what is the

17 Company supposed to consider for billing if the MW's do not match?

18 Meaning, what if the CGS Supply was reduced by 1,500 kW between two

19 30 minute intervals, but the CGS Customer's load only reduced by 1,000

20 kW. Is the Company to assume that the supply reduction and load

21 reduction have "matched" or is the Company supposed to bill unserved

22 energy for the difference between 1,500 and 1,000?

lC)

Entergy Texas, Inc. Page 9 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 Second, what is the Company supposed to consider for billing if the

2 timing doesn't match? If the CGS supply was reduced in one interval but

3 the reduction in CGS Customer load did not occur until two hours later,

4 what is the Company to assume for billing unserved energy under TIEC's

5 proposal? Is the Company supposed to bill unserved energy for the

6 intervening two hours?

7 Third, what is the Company to assume if either the supply reduction

8 or the load reduction is not constant or consistent across intervals? For

9 example, is the Company to charge for unserved energy if the load

10 reduction is a constant 5,000 kW across all hours but the supply reduction

11 is 5,000 kW for half of the hours but 5,100 kW for the other half of the

12 hours.

13 Fourth, the CGS Program is further complicated by the potential for

14 a CGS Supplier to enter into CGS agreements with multiple CGS

15 Customers. As discussed in my Supplemental Direct Testimony in the

16 situation of one CGS Supplier has entered into a CGS agreement with

17 multiple CGS Customers, when the CGS Supplier reduces its supply,

18 there is no method for prioritizing the reduction to the multiple Customers,

19 and therefore no method for determining which CGS Customer should

20 avoid unserved energy charges or the level of required reduction. For

21 example, if the CGS Supply was reduced by 10,000 kW and CGS

22 Customer-1 reduced its load by 4,500 kW and CGS Customer-2 reduced

Entergy Texas, Inc. Page 10 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 its load 3,000 kW, the Company does not know which CGS Customer(s) is

2 supposed to billed unserved energy and in what quantities.

3 Fifth, the Company has no way to determine whether a CGS

4 Customer's reduction in load truly had to do with a reduction in CGS

5 Supply or a reduction in load for economic reasons. For example, assume

6 again as in my fourth point immediately above that a single CGS Supplier

7 that has contracted with two separate CGS Suppliers. Assume the CGS

8 Customer-2 reduction in load was for economic reasons associated with

9 the sale of its own product. Further assume that the CGS Supplier

10 actually never requested CGS Customer-2 to reduce its load, but instead

11 requested that CGS-Customer-1 undertake the full reduction. Under this

12 set of assumptions, CGS Customer-1 should pay unserved energy for the

13 full difference between 10,000 kW and 4,500 kW. From ETI's billing

14 perspective, however, the Company has the exact same metering data

15 under both scenarios (fourth point versus this fifth point) but has no way to

16 discern that difference.

17 Finally, these issues are not mutually exclusive. For example, the

18 circumstance could be similar to the fifth point above, while at the same

19 time, the timing of the reductions does not match (second point above)

20 and the kW values do not match (first point above).

21

t-Z^

Entergy Texas, Inc. Page 11 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 III. RESPONSE TO STAFF

2 Q. ON PAGE 6 OF HIS DIRECT TESTIMONY, STAFF WITNESS STEPHEN

3 J. MENDOSA STATES THAT THE CGS PROGRAM HAS NOT YET

4 BEEN IMPLEMENTED AND THEREFORE, ETI SHOULD NOT BE

5 ALLOWED TO RETROACTIVELY RECOVER ANY COSTS

6 ASSOCIATED WITH THE IMPLEMENTATION OF THE CGS PROGRAM.

7 ON A RELATED POINT, ON PAGE 7, MR. MENDOZA STATES THAT

8 ETI SHOULD NOT BE ALLOWED TO RETROACTIVELY RECOVER

9 COSTS ABOVE THE LEVEL CURRENTLY REFLECTED IN BASE

10 RATES. IS THE RECOVERY OF CGS COSTS SUBJECT TO

11 TRADITIONAL TEST YEAR RATE MAKING?

12 A. No. The recovery of CGS implementation cost is subject to the specific

13 provisions in PURA §39.452(b), which states in part:

14 The tariffs subject to this subsection may not be considered 15 to offer a discounted rate or rates under Section 36.007, and 16 [ETI's] rates shall be set, in the proceeding in which the tariff 17 is adopted, to recover any costs unrecovered as a result of 18 the implementation of the tariff. 19 20 A common definition of the word " implement" is to "CARRY OUT,

21 ACCOMPLISH; esp : to give practical effect to and ensure actual

22 fulfillment by concrete measures...."5 Substituting the definitional phrase

23 into the statutory word "implementation" results in: "...to recover any costs

24 unrecovered as a result of giving practical effect to and ensuring actual

25 fulfillment by concrete measures of the tariff." ETI cannot give "practical

5 MERRIAM-WEBSTER'S COLLEGIATE DICTIONARY 582 (101h ed. 2002).

Entergy Texas, Inc. Page 12 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 effect to and ensure actual fulfillment by concrete measures" (or "carry

2 out" or "accomplish") the CGS tariff without undertaking all of the work that

3 has gone into this docket. Thus, ETI is incurring, and has incurred, costs

4 to implement the CGS tariff; by statute, it is entitled to recover those costs.

5 Further, there is no timeframe qualifier on this provision. The

6 Company is allowed to recover any costs unrecovered as a result of the

7 implementation of the CGS tariff no matter when those costs are incurred;

8 there is, therefore, no consideration, much less prohibition, against

9 recovering costs incurred back to November 10, 2010.

10

11 Q. ON PAGE 8, STAFF WITNESS MENDOZA STATES THE AMOUNT

12 CURRENTLY RECOVERED IN BASE RATES ASSOCIATED WITH THE

13 CGS PROGRAM GOES AGAINST COST CAUSATION PRINCIPLES

14 WHEREBY COSTS ARE ALLOCATED TO THOSE CUSTOMERS

15 CAUSING THE COST TO BE INCURRED. PLEASE COMMENT.

16 A. The Office of Public Utility Counsel ("OPUC") makes a similar argument. I

17 will address the topic of the amount included in base rates and cost

18 causation among classes in Section IV of this testimony below.

19

20 IV. RESPONSE TO OPUC

21 Q. STARTING ON PAGE 8, OPUC WITNESS NATHAN A. BENEDICT

22 STATES A CONCERN THAT NON-CGS PARTICIPATING RATE

23 CLASSES ARE PAYING FOR CGS IMPLEMENTATION COSTS VIA

Entergy Texas, Inc. Page 13 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 BASE RATES. ON PAGES 8 THROUGH 10, MR. BENEDICT STATES

2 THAT ETI'S RECOVERY VIA BASE RATES AND SUBSEQUENT

3 CREDIT VIA RIDER CGSC CREATES CLASS SUBSIDIES. ARE THERE

4 CGS COSTS REFLECTED IN ALL CUSTOMER CLASSES?

5 A. Yes. As stated in ETI's response to OPUC RFI 2-1 and RFI 2-2, the

6 $299,372 represents the amount of CGS costs used to set current retail

7 base rates and that has been allocated to all retail rate classes.

8

9 Q. WHAT IS THE MAGNITUDE OF THE AMOUNTS BEING BILLED

10 CUSTOMERS FOR CGS IMPLEMENTATION COSTS CURRENTLY IN

11 BASE RATES?

12 A. Using the residential rate class as an example, a typical residential

13 customer using 1,000 kWh per month would be paying less than

14 $0.03/month.6

15

16 Q. ON PAGES 5 AND 8, OPUC WITNESS BENEDICT SUGGESTS THAT A

17 ONCE-ANNUAL REFUND IS THE OPTIMAL SOLUTION TO CREDIT

18 CUSTOMER CLASSES FOR THE AMOUNT BEING BILLED IN BASE

19 RATES. DO YOU AGREE?

20 A. No. At the outset, in Docket No. 39896, the Commission authorized ETI to

21 recover, through base rates, the charges to the Company's project code

6 Residential $159,946 shown on the Company's response to OPUC RFI 2-2 divided by Residential 5,577,331,000 kWh (Docket No. 38986, Staff Cost of service number running model, Schedule Q-7) times 1,000 kWh/month equals approximately $0.029/month.

Entergy Texas, Inc. Page 14 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 established to capture CGS-related costs. OPC's proposal would

2 circumvent that ruling by requiring a refund of those base rate charges to

3 all but the LIPS class. Further, the class-based figures cited by Mr.

4 Benedict in his testimony (which were provided to OPUC through the

5 Company's response to OPUC RFI 2-2) were based on ETI's cost of

6 service model, which is an approximation of the Staff's number running

7 model. But Staff's number running model does not provide the detail or

8 functionality to segregate the CGS-related charges by customer class, and

9 a number of different allocation factors were used to allocate the CGS

10 project code costs in Docket No. 39896. Therefore, there is an

11 unavoidable imprecision in those figures.

12 However, if the PUCT wants to attempt to remove customer class

13 subsidies ( both inter and intra class), even given the imprecision

14 described above for this portion of the Rider CGSC charge, then the

15 appropriate method to address these class subsidies would be to have a

16 separate rider that would essentially negate the amount included in base

17 rates for CGS service, but also implement a mechanism to ensure that ETI

18 then recovers this full amount via Rider CGSC. The rate for this credit

19 rider would be developed by rate class using the rate class dollar amounts

20 referenced in ETI's response to OPUC RFI 2-2 and included in the table

21 on page 8 of Mr. Benedict's testimony divided by the billing determinants

22 used to set rates in Docket No. 39896. The table below shows this credit

23 rate to remove the CGS billing via base rates going forward. This rate

^('0

Entergy Texas, Inc. Page 15 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 could go into effect when the CGS Program is approved, and specifically,

2 when Rider CGSC is approved and in effect, and would continue as long

3 as base rates from Docket No. 39896 are in effect.

4 Table 1

Rate Class CGS $ kWh Credit Rate

in Base Rates in Base Rates $/kWh

Residential 159,946 5,577,331,000 0.000029

Small General Service 9,954 310,769,000 0.000032

General Service 55,140 3,253,695,000 0.000017

Large General Service 17,988 1,520,082,000 0.000012

Large Industrial Power

Service 49,192 5,301,215,000 0.000009

Lighting 7,153 77,279,359 0.000093

Total Retail 299,372

5

6 Q. IF THIS CREDIT RIDER APPROACH IS TAKEN, WHAT OTHER

7 CHANGES ARE REQUIRED?

8 A. The Rider CGSC filed by the Company would need to have the $310,746

9 credit currently reflected in this rider removed because customers would

10 effectively be receiving this credit via the credit rider.' But as stated

11 above, the Rider CGSC rate would then need to ensure that the full

12 amount of implementation costs, including the $299,372, is recovered so

' Again, ETI's Rider CGSC should have only credited the retail portion included in base rates of $299,372 because that is the level reflected in current retail rates and not the full $310,746.

iI

Entergy Texas, Inc. Page 16 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 that ETI does not forego this recovery already authorized in Docket No.

2 39896.

3

4 Q. WHY IS THE USE OF A CREDIT RIDER PREFERRED TO OPUC'S

5 PROPOSAL?

6 A. Again, if the PUCT concludes that an attempt to remove class subsidies

7 should be made, there are a number of reasons. First, the credit rider

8 truly is the simplest approach in that this credit rider simply removes what

9 is included in base rates and it stays in effect as long as rates from Docket

10 No. 39896 are in effect. Second, this approach treats all rate classes the

11 same. Third, this also simplifies Rider CGSC to just recover the CGS

12 implementation and administration costs and not deal with either prior

13 periods or on-going credit amounts. Fourth, this proposal accurately

14 removes any perceived customer subsidy in that the base rate charge is

15 effectively removed. Fifth, this proposal not only removes any perceived

16 inter-class subsidies but it also removes any intra-class subsidy. By giving

17 the LIPS class a credit just like other classes and then charging the CGS

18 participants the Rider CGSC costs, intra-class subsidies within the LIPS

19 rate class are removed. In comparison, OPUC's proposal is overly

20 complicated by once-annual refunds and continues to have an intra-class

21 subsidy within the LIPS rate class.

22

^4

Entergy Texas, Inc. Page 17 of 17 Supplemental Rebuttal Testimony of Dennis R. Roach Docket No. 38951

1 V. RESPONSE TO WAL-MART/SAM'S CLUB

2 Q. STEVEN CHRISS, FILING TESTIMONY ON BEHALF OF WAL-

3 MART/SAM'S CLUB, RECOMMENDS THAT THE COMMISSION

4 REJECT ETI'S RIDER CGSUSC AND LIMIT THE COLLECTION OF

5 UNRECOVERED COSTS TO THE CUSTOMERS TAKING SERVICE

6 UNDER THE RIDER CGS. HOW DO YOU RESPOND?

7 A. First, I note that Cities filed a Motion to Strike the Rider CGSUSC

8 references and discussion in my Supplemental Direct, as well as striking

9 Rider CGSUSC attached as an exhibit to that testimony. The Company

10 has filed a response in opposition to Cities' Motion to Strike. As discussed

11 in the Company's response to Cities, Rider CGSUSC (and references to

12 that Rider in my Supplemental Direct Testimony) should not be struck

13 because that proposed Rider CGSUSC and referenced passages in

14 testimony are presented to establish a complete evidentiary record on the

15 issue of what are unrecovered costs, and ETI's consistent position is that

16 it is a Commission policy call as to which customers are responsible for

17 reimbursing ETI for its unrecovered costs.

18

19 VI. CONCLUSION

20 Q. DOES THIS CONCLUDE YOUR SUPPLEMENTAL REBUTTAL

21 TESTIMONY?

22 A. Yes, at this time.

V^A

PUC DOCKET NO. 38951

APPLICATION OF ENTERGY ) PUBLIC UTILITY COMMISSION TEXAS, INC. FOR APPROVAL ) OF COMPETITIVE SERVICE ) TARIFF (ISSUES SEVERED ) FROM DOCKET NO. 37744) ) OF TEXAS

HEARING ON THE MERITS

Thursday, April 19, 2012

BE IT REMEMBERED THAT at 9:11 a.m., on

Thursday, the 19th day of April 2012, the above-entitled

matter came on for hearing at the Public Utility

Commission of Texas, William B. Travis Building, 1701

North Congress Avenue, Commissioners' Hearing Room,

Austin, Texas, before DONNA NELSON, CHAIRMAN; KENNETH

ANDERSON AND ROLANDO PABLOS, COMMISSIONERS, IRENE

MONTELONGO AND ANDREW KANG, Administrative Law Judges,

and the following proceedings were reported by Evelyn

Coder, Certified Shorthand Reporter.

Volume 2 Pages 37 - 212

Page 180

1 any of the company's capacity costs for the generatiort 2 it owns. Correct? 3 A (Pollock) The company is going to know pretty 4 far in advance, before the signing of the contract, that 5 there's a good -- at least the likelihood that there's a 6 resource out there, and I don't think that's going to go 7 totally unnoticed in the planning process. 8 I mean, the company executes year, 9 two-year, three-year extensions of existing contracts 10 that they might not otherwise have to do if they know 11 that they're close to getting a CGS resource in place, 12 within the time window, which requires that the 13 contract, I think, has to be in place by at least April 14 or before the summer. So that gives the company plenty 15 of -- and you're going to know in advance that customers 16 are going through this process, so it's not going to be 17 a total unknown. 18 Q Well, that's not my question. My question is, 19 the company has capacity costs that it incurs on its 20 power plants like River Bend. 21 A (Pollock) Yes. 22 Q And the fact that it enters into a CGS contract 23 for a couple of years will have no tendency to reduce 24 the capacity costs its paying for River Bend at all. 25 Right?

KENNEDY REPORTING SERVICE, INC.

512.474.2233

Page 181

1 A (Pollock) It's not intended to. As I said, 2 the CGS program right now would replace a limited-term, 3 PPA, purchased power agreement. So, yeah, it could 4 certainly def er an extension or brand new PPA from being 5 entered into, and that's really the point. 6 Q But if the contract is for, say, three years, 7 and no longer than five years, it's not going to cause 8 the company to alter any of its obligations that are 9 long-term contracts. Correct? They would be the same? 10 A (Pollock) No, but on the margins, when the 11 company, you know, enters into numerous limited-term 12 agreements, as they've had, it's going to affect those 13 agreements. 14 I mean, you know, let's not put, you know, 15 CGS as trying to replace a 30- or 40-year resource. You 16 know, maybe it eventually will do that, but for the 17 short run, as long as the company is relying on these 18 limited-term purchases, that's where we can defer -- and 19 those purchases -- those costs, as Mr. May points out, 20 keep going up, that's where we can do some good and help 21 out the customers. 22 Q But it would simply be a matter, though, of 23 what -- if you have a short-term CGS contract, what it 24 can displace will depend on what the company has in its 25 portfolio at the time the CGS contract is entered into.

KENNEDY REPORTING SERVICE, INC.

512.474.2233

Page 182

1 Right? 2 A (Pollock) Sure; sure, it does. 3 Q We don't know what that will be at this point? 4 A (Pollock) You know what your portfolio is. 5 You know for all the limited-term contracts. You have a 6 start date, an end date. The question is, is there 7 going to be an extension if we need it or not, and 8 that's where you could potentially affect the process. 9 Q But we don't know when the CGS contract will be 10 entered into? 11 A (Pollock) We don't. 12 Q Okay. Is it your contention or TIEC's 13 contention that any amount of unrecovered costs, no 14 matter how small, will undermine the program? 15 A (Pollock) I think to the extent that a CGS 16 customer is going to incur some unrecovered costs -- and 17 that's an issue. I can't say how much of unrecovered 18 costs would either dissuade that customer from not 19 entering a CGS contract or not because I'm not in a 20 position to know that. 21 But I think the more pressure you put and 22 the more hurdles you put on the program like that, I 23 think less likely the program will work. Maybe it will 24 work for some customers but not as many customers as 25 would otherwise be the case.

KENNEDY REPORTING SERVICE, INC.

512.474.2233

SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 37744

APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY TO § CHANGE RATES AND RECONCILE § FUEL COSTS § OF TEXAS

DIRECT TESTIMONY

OF

CLARENCE JOHNSON

ON BEHALF OF THE

OFFICE OF PUBLIC UTILITY COUNSEL

REDACTED

June 9, 2010

1 A. Yes. The CGS-USC rider will allow the company to flow through unrecovered

2 embedded cost to other customer classes. The unrecovered costs are defined as the

3 difference between the revenue paid as a CGS customer and the revenues which would

4 have been collected by ETI ifthe CGS customer had remained a standard LIPS customer.

5 If all LIPS customers opted for CGS service, the unrecovered costs would be $57.5

6 million. 87 Furthermore, the "lost revenue method" used in the CGS-USC tariff may not

7 be equivalent to "unrecovered costs," which is the term used in the statute.

8 Q. WHY IS "LOST REVENUE" DIFFERENT FROM "UNRECOVERED COST?"

9 A. Revenues are intended to equal embedded cost of service for the adjusted test-year.

10 However, revenues may depart from costs, either higher or lower, as the time frame

11 advances further from the test-year. Moreover, the loss of individual customers'

12 revenues does not mean that the underlying costs are ''unrecovered." For instance, the

13 generating capacity which served the departing customers can be redirected to other

14 revenue producing uses, such as selling power into the wholesale market.

15 Q. CAN YOU FORESEE ANY CIRCUMSTANCES WHERE RE-ENTRY OF

16 FORMER CGS CUSTOMERS IMPOSES UNFAIR IMPACTS ON NON-

17 PARTICIPATING CUSTOMERS?

18 A. Yes. Bundled utility pricing tends to be more stable and less volatile than market pricing

19 because rates are based upon average costs ~stead of marginal costs. Customers will be

20 attracted to CGS service when market prices are lower than the utility's average costs.

87

May Direct Testimony at 14.

Redacted Direct Testimony of Clarence Johnson On Behalf of the Office of Public Utility Counsel SOAH Docket No. XXX-XX-XXXX; PUC Docket No. 37744 Page 88 of 115

TIEC EXHIBIT NO. 15

PUC DOCKET NO. 38951

APPLICATION OF ENTERGY § TEXAS, INC. FOR APPROVAL OF § PUBLIC UTILITY COMPETITIVE GENERATION § SERVICE TARIFF (ISSUES § COMMISSION OF TEXAS SEVERED FROM DOCKET NO. § 37744) §

Supplemental Direct Testimony and Exhibits

of

JEFFRY POLLOCK

On Behalf of

Texas Industrial Energy Consumers

February, 2012

iy j. POLLOCK

4

........................................................:.......................................................

u ' t3 & A °`#

Jeffry Pollock Supplemental Direct Page 14

3. UNRECOVERED COSTS FROM THE CGS PROGRAM

1 Q WHY IS THE ISSUE OF THE DEFINITION OF "UNRECOVERED COSTS" BEING 2 ADDRESSED IN THIS PROCEEDING? 3 A PURA § 39.452(b) provides that ETI's rates "shall be set, in the proceeding in which 4 the tariff is adopted, to recover any costs unrecovered as a result of the 5 implementation of the tariff." ETI and TIEC do not agree about what "costs" this 6 refers to. Just as ETI and other utilities unsuccessfully argued with respect to energy 7 efficiency program costs, ETI claims the reference to "costs" would allow it to recover 8 not just its actual expenditures in implementing a CGS Program but also hypothetical 9 lost revenues ETI may have received if all CGS Customers paid ETI's full firm rate 10 instead. ETI's proposed Rider CGSUSC clearly states that it "defines the procedure 11 by which Entergy Texas, Inc. ('Company') shall implement and adjust rates for 12 recovery of lost base rate revenue resulting from customers participating in the 13 Company's Competitive Generation Service ('CGS Program')."' (emphasis added)

14 Definition of Unrecovered Costs 15 Q HOW SHOULD UNRECOVERED COSTS BE DEFINED? 16 A Unrecovered costs should not include ETI's hypothetical lost revenues. If a CGS 17 tariff is adopted, the costs that could be unrecovered as a result of implementation of 18 the tariff should include the expenditures actually incurred by ETI to implement and

1 Docket No. 37744, ETI Ex. 9 at Exhibit PRM-1.

3. Unrecovered Costs From the CGS Program J.POLLOCK INCORPORATED