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

ACCEPTED

03-14-00735-CV

5514413

THIRD COURT OF APPEALS

AUSTIN, TEXAS

6/2/2015 3:37:34 PM

JEFFREY D. KYLE

CLERK

NO. 03-14-00735-CV

IN THE FILED IN

TEXAS COURT OF APPEALS 3rd COURT OF APPEALS

AUSTIN, TEXAS

THIRD COURT OF APPEALS DISTRICT

6/2/2015 3:37:34 PM

AT AUSTIN JEFFREY D. KYLE

Clerk

ENTERGY TEXAS, INC., ET AL.,

APPELLANTS,

V.

PUBLIC UTILITY COMMISSION OF TEXAS, ET AL.,

APPELLEES

ON APPEAL FROM THE FINAL JUDGMENT

IN CAUSE NO. D-1-GN-13-000121 (CONSOLIDATED),

353RD JUDICIAL DISTRICT COURT,

TRAVIS COUNTY, TEXAS,

HONORABLE JOHN K. DIETZ, JUDGE PRESIDING

APPELLANT’S REPLY BRIEF AND APPENDIX OF

THE OFFICE OF PUBLIC UTILITY COUNSEL

OFFICE OF PUBLIC UTILITY COUNSEL

Tonya Baer

Public Counsel

State Bar No. 24026771

Sara J. Ferris

Senior Assistant Public Counsel

State Bar No. 50511915

P.O. Box 12397

Austin, Texas 78711-2397

512/936-7500

512/936-7525 (Fax)

Sara.Ferris@opuc.texas.gov

ORAL ARGUMENT REQUESTED

June 2, 2015

TABLE OF CONTENTS

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

INDEX OF AUTHORITIES ..................................................................................................... iv

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

A. Standards of Review .......................................................................................................... 1

B. Either the Commission weighed the evidence and concluded that it

was not sufficient to allow a determination as to what portion of the

storm expenses were due to the negligent state of the Company’s

system, or the Commission did not weigh the evidence and decided not

to address the issue based upon the irrelevant factor of the passage of

time. Either way, the Commission committed reversible error by

failing to hold ETI to its burden of proof under PURA § 36.006 and

allowing one hundred percent of the $13,014,379 1997 storm restoration

expenses to be included in the storm reserve and reflected in rates. .................. 4

C. Indisputably, the issue of determining what amount of 1997 storm

restoration expenses was prudent, appropriate, and includable in the

storm reserve and rates was an issue to be decided in Docket No.

39896. That fact does not render the Commission’s Orders in Docket

Nos. 18249 and 16705 irrelevant or properly disregarded........................................ 8

D. The Commission inappropriately focused on only one aspect of the

prudence question and ignored the genesis of the expenses. ................................. 11

E. The 60-basis-point reduction to the Company’s return on equity

assessed in Docket No. 18249 was not intended to be in lieu of

identifying and accounting for the portion of the cost of cleaning up

and repairing the damage caused by the Company’s imprudent

vegetation management. The Commission acted arbitrarily and

capriciously by considering this irrelevant factor and including the

entirety of the $13,014,379 in ETI’s storm reserve reflected in rates. .................... 13

F. The Commission erred in approving the recovery of imprudent costs. ............... 16

i

G. Some of ETI’s storm costs were “reasonably anticipated,” and it was

reversible error for the Commission to fail to consider this statutorily

required criterion. The Commission’s Order violates PURA § 36.064

and is the result of the Commission acting arbitrarily and through

unlawful procedure. ........................................................................................................ 20

H. ETI’s 420-page spreadsheet was properly excluded from the

evidentiary record. (Response to ETI’s Conditional Cross-Point). ................... 25

PRAYER ....................................................................................................................................... 29

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

CERTIFICATE OF SERVICE ................................................................................................ 30

APPENDIX

1. PURA, Chapter 36, Subchapters A and B

2. APA, Tex. Gov’t Code § 2001.174

3. PUC Substantive Rule on Cost of Service-Allowable Expenses:

16 Tex. Admin. Code § 25.231(b)

4. PUC Docket No. 18249, Order on Rehearing

5. Excerpts from PUC Docket No. 16705, Second Order on

Rehearing

6. PUC Docket No. 39896, Hearing on the Merits Transcript:

Excerpts of Direct and Cross-Examination of ETI Witness

Shawn Corkran

7. PUC Docket No. 39896 Hearing on the Merits Transcript:

Excerpts re. Optional Completeness

8. Tex. Health Facilities Comm’n v. Charter Medical-Dallas, 665 S.W.2d

446 (Tex. 1984)

9. City of El Paso v. Public Util. Comm’n, 839 S.W.2d 895 (Tex. App.—

Austin 1992) aff’d in part, rev’d in part on other grounds, 883 S.W.2d

179 (Tex. 1994).

ii

10. City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179 (Tex. 1994)

11. Helena Chemical Co. v. Wilkins, 47 S.W.3d 486 (Tex. 2001)

12. Texas Utilities Electric Company v. Public Utility Commission,

881 S.W.2d 387 (Tex. App. – Austin 1994) aff’d in part, rev’d in part

on other grounds, 935 S.W.2d 109 (Tex. 1997)

13. Gilmore v. State, 744 S.W.2d 630 (Tex. App.—Dallas 1987, pet. ref’d)

14. Crosby v. Minyard Food Stores, 122 S.W.3d 899 (Tex. App. – Dallas

2003, no pet.)

iii

INDEX OF AUTHORITIES

CASES

City of El Paso v. Public Util. Commission,

839 S.W.2d 895 (Tex. App.—Austin 1992) aff’d in part, rev’d in

part on other grounds, 883 S.W.2d 179 (Tex. 1994). ........................................... 17, 18

City of El Paso v. Public Util. Commission,

883 S.W.2d 179 (Tex. 1994). ................................................................................ 3, 23

Crosby v. Minyard Food Stores,

122 S.W.3d 899 (Tex. App.—Dallas 2003, no pet.) .............................. 27-28, 28

Entergy Gulf States, Inc. v. Public Utility Commission,

112 S.W.3d 208 (Tex. App.—Austin 2003, pet. denied). ................................. 17

Finder v. Texas Medical Board,

2010 WL 4670510 (Tex. App.—Austin, pet denied) ........................................ 23

General Motors Corp. v. Bray,

243 S.W.3d 678 (Tex. App.—Austin 2007, no pet.) ................................... 23-24

Gilmore v. State,

744 S.W.2d 630 (Tex. App.—Dallas 1987, pet. ref’d.) ......................... 25, 26, 27

Helena Chem. Co. v. Wilkins,

47 S.W.3d 486 (Tex. 2001). ...................................................................................... 15

Mentis v. Barnard,

870 S.W.2d 14 (Tex. 1994) ....................................................................................... 25

Office of Public Utility Counsel v. Public Utility Commission,

185 S.W.3d 555 (Tex. App.—Austin 2006, pet. denied) .................................. 25

Public Utility Commission v. Gulf States Utilities,

809 S.W.2d 201 (Tex. 1991). ................................................................................ 3, 24

iv

Roman v. State,

503 S.W.2d 252 (Tex. Crim. App. 1974) .............................................................. 27

Texas Health Facilities Comm’n v. Charter Medical-Dallas,

665 S.W.2d 446, 452 (Tex. 1984). ............................................................ 1-2, 22, 23

Texas Utilities Electric Company v. Public Utility Commission,

881 S.W.2d 387 (Tex. App.—Austin 1994) aff’d in part, rev’d in part

on other grounds, 935 S.W.2d 109 (Tex. 1997). ............................................ 17, 18, 19

ADMINISTRATIVE PROCEEDINGS

Application of Entergy Texas for Approval of its Transition to Competition Plan and

the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs,

Docket No. 16705, Second Order on Rehearing

(Oct. 14, 1998). ........................................................................................ 8, 9, 10, 14, 16

Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket No. 16705),

Docket No. 18249, Order on Rehearing

(Apr. 22, 1998). ........................................................ 4-5, 6, 8, 9, 10, 13, 14, 19, 20, 21

TEXAS STATUTES

TEX. GOV’T CODE § 311.021 (2), (3) ..................................................................................... 1, 15

Administrative Procedure Act, APA, TEX. GOV’T CODE ANN. §§ 2001.001-.902 ................. 1

APA § 2001.141(b) ................................................................................................................... 23

APA § 2001.141(d) ................................................................................................................... 23

APA § 2001.174......................................................................................................................... 1, 3

APA § 2001.174(2) ...................................................................................................................... 1

APA § 2001.174(2)(A),(B),(D),(E) AND (F) ................................................................. 23, 25

APA § 2001.174(2)(C) ............................................................................................. 13-14, 15, 27

Public Utility Regulatory Act PURA, TEX. UTIL. CODE §§ 11.001-66.017 ............................. 2

PURA § 36.006 .................................................................................................. 4, 5, 7, 12, 16-17

PURA § 36.051...........................................................................................................15, 16-17, 19

v

PURA § 36.052 ........................................................................................................................... 15

PURA § 36.062 ..................................................................................................................... 13, 15

PURA § 36.064............................................................................................ 15, 16-17, 19, 20, 23

PURA § 36.064(a) .............................................................................................................. 20-21

PURA § 36.064(c) .....................................................................................................................16

TEXAS RULES OF COURT

Tex. R. Civ. P. 197.3 ................................................................................................................. 25

Tex. R. Evid. 107 ...................................................................................................................... 26

PUBLIC UTILITY COMMISSION OF TEXAS RULES

16 Tex. Admin. Code § 22.202(c) ........................................................................................ 26

16 Tex. Admin. Code § 22.207 ............................................................................................. 26

16 Tex. Admin. Code § 25.231(b)(1)(G)........................................................................ 21, 23

16 Tex. Admin. Code § 25.231(b)(2)(J).......................................................................... 15, 19

vi

REPLY BRIEF OF APPELLANT,

OFFICE OF PUBLIC UTILITY COUNSEL

TO THE HONORABLE THIRD COURT OF APPEALS:

The Office of Public Utility Counsel (OPUC), Appellant, submits this reply

to the briefs of the Public Utility Commission (Commission or PUC), and Entergy

Texas, Inc. (ETI).

ARGUMENT AND AUTHORITIES

A. Standards of Review

Several standards of review are implicated by the Commission’s Order and

each, standing on its own, provides a sufficient basis for reversal. Contrary to the

PUC’s and ETI’s focus on the substantial evidence standard, the Commission’s

Order is subject to reversal under additional standards of review listed under

Section 2001.174 of the Administrative Procedure Act.1 The six standards of

review listed in Subsection 2001.174(2) offer independent grounds for reversal as

evidenced by the use of the word “or” in the subsection. Texas law is clear that

these standards of review are separate and distinct. For instance, the Supreme

Court has expressly stated that “instances may arise in which the agency’s action

is supported by substantial evidence, but is arbitrary and capricious nonetheless”

and that the Legislature intended to “distinguish between agency action that is

1

Administrative Procedure Act (APA), Tex. Gov’t Code §§ 2001.001-.902.

1

not supported by substantial evidence and agency action that is arbitrary and

capricious.” Texas Health Facilities Comm’n v. Charter Medical-Dallas, 665 S.W.2d 446,

452 (Tex. 1984).

In addition to the substantial evidence standard, and the arbitrary and

capricious standard acknowledged by the Commission as having been invoked in

this appeal, Appellant OPUC’s substantial rights have been prejudiced because the

administrative findings, inferences, conclusions, or decisions violate statutory

provisions, are made through unlawful procedure, and are affected by other error

of law.2 The Commission has violated PURA and the APA by failing to consider

and set forth findings on statutory criteria for the inclusion of storm costs in the

self-insurance reserve and rates.3 The Commission also committed reversible error

in making its decision through unlawful procedure by failing to include underlying

findings of fact in support of statutorily required criteria.4 Additionally, the

Commission’s Order is affected by other error of law in that it failed to give effect

to the plain, unambiguous language of the Commission’s rules.

The arbitrary and capricious standard applies as well; however, in its

Appellee’s brief, the Commission improperly mixes the arbitrary and capricious

2

APA § 2001.174(2)(A)(D)(E) and (F). APA Section 2001.174 is submitted as Appendix 2.

3

Public Utility Regulatory Act, PURA, TEX. UTIL. CODE ANN. §§ 11.001-66.017. PURA Chapter 36,

Subchapters A and B are submitted as Appendix 1.

4

OPUC also notes that this standard of review is applicable to ETI’s “conditional cross point”

because ETI’s challenge is procedural in nature, i.e., the exclusion from evidence of an exhibit.

2

standard with the substantial evidence standard of review. The Commission

contends that under the arbitrary and capricious standard, “Courts must uphold a

Commission decision if ‘some reasonable basis exists in the record for the action

taken by the agency.’”5 However, the quoted language from City of El Paso comes

from the Court’s discussion of the substantial evidence standard, not the arbitrary

and capricious standard of review. OPUC’s Appellant brief includes a discussion

on pages 37-39 as to how the Commission’s Order was arbitrary and capricious or

resulting from an abuse of discretion in three of the four ways possible under the

arbitrary and capricious standard of review.6 Under the standards articulated in

APA § 2001.174, the Commission’s Order should be reversed and the case

remanded for determination based upon the existing evidentiary record to

determine rates consistent with the Court’s decision.

5

PUC’s Brief of Appellee at 11, quoting City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179, 186

(Tex. 1994) (City of El Paso is submitted as Appendix 10).

6

An administrative agency’s decision is arbitrary or results from an abuse of discretion if the

agency: (1) failed to consider a factor the legislature directs it to consider; (2) considers an

irrelevant factor; or (3) weighs only relevant factors that the legislature directs it to consider but

still reaches a completely unreasonable result. City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179,

184 (Tex. 1994). Also, when an agency fails to “follow the clear, unambiguous language of its

own regulation,” it acts arbitrarily and capriciously. Public Util. Comm’n v. Gulf States Utilities, 809

S.W.2d 201, 207 (Tex. 1991).

3

B. Either the Commission weighed the evidence and concluded that it was

not sufficient to allow a determination as to what portion of the storm

expenses were due to the negligent state of the Company’s system, or the

Commission did not weigh the evidence and decided not to address the

issue based upon the irrelevant factor of the passage of time. Either way,

the Commission committed reversible error by failing to hold ETI to its

burden of proof under PURA § 36.006 and allowing one hundred percent

of the $13,014,379 1997 storm restoration expenses to be included in the

storm reserve and reflected in rates.

In their respective Appellee’s briefs, ETI and the PUC focus on the evidence

presented in the Commission proceeding related to the processes ETI went

through in repairing damage and restoring service following the 1997 ice storm.

Their arguments focus on the “substantial evidence” supporting the Commission’s

decision to include one hundred percent of the 1997 storm restoration expenses

into the storm reserve reflected in rates, and assert that OPUC seeks to have the

Court reweigh the evidence to reach a different result. Their contention misses

the mark. The weighing of the evidence was indisputably done during the

contested case by the Commission and the Administrative Law Judges (ALJs) who

authored the Proposal for Decision (PFD) adopted by the Commission. The result

of their weighing of the evidence on the issue of what costs were caused by ETI’s

negligent, imprudent or deficient quality of service,7 is encapsulated in the

7

The service quality deficiencies related to the costs at issue in this appeal included inadequate

distribution maintenance policies, inadequate vegetation management practices, distribution

poles in poor condition or in need of comprehensive vegetation clearing, and inadequate pole

inspection and repair work cycles. See Docket No. 18249, Entergy Gulf States, Inc. Service Quality

Issues (Severed from Docket No. 16705), Order on Rehearing at 8-19 (Apr. 22, 1998); OPUC’s

4

Commission-adopted PFD’s statement that, “[i]t is not feasible to accurately

determine now what portion of ice storm damage that occurred 15 years ago was

caused by preventative maintenance issues.”8 With this statement, the

Commission, through its adopted PFD, acknowledged the issue of what part of the

storm damage was caused by ETI, not solely by an Act of God, and not caused by

ratepayers. With this statement, the Commission also concluded its weighing of

evidence on the issue, and found that with the evidence presented, it was not

“feasible” to determine what portion was caused by the negligent state of the

Company’s preventative maintenance, including vegetation management.

Upon arriving at this conclusion, after having weighed the evidence on the

issue, the Commission had to then decide what to do with the proposed

$13,014,379 in 1997 ice storm costs. The Commission had several options, but one

option it did not legally have was to allow the inclusion of the entire requested

$13,014,379 in the storm reserve reflected in rates. When faced with no feasible

way of determining what part was due to the Company’s action or inaction, the

Commission had a duty under PURA § 36.006 to disallow the expenses. ETI had

the burden of proof on the issue and the Commission expressly stated that it could

not determine what portion was caused by the Company’s “preventative

Appellant’s Brief at 5-7 (Submitted as Appendix 5).

8

AR, Binder 5, Item No. 185, PFD at 56.

5

maintenance issues” that the Commission earlier had found to be a “major factor”

in the outages and to have “greatly exacerbated” the extent of the damage.9 If the

evidence cannot be shown to support the Company’s case, ETI fails to meet its

burden of proof necessary to include the entirety of the 1997 storm expenses. The

Commission committed reversible error by approving the inclusion of one

hundred percent of the 1997 storm costs.

Alternatively, if the quoted passage from the Commission-adopted PFD is

not a determination based upon the weight of the evidence, then it should be

interpreted as discussed in OPUC’s Appellant’s Brief10 as a refusal, based on an

irrelevant factor - the passage of time, to hold ETI to its burden to prove that

either one hundred percent of the costs would have been incurred, regardless of

the state of the Company’s system at the time of the storm, or provide evidence on

what portion should be disallowed. Contrary to the PUC’s implied argument,

OPUC does not argue that the Company was required to break out, line by line,

each imprudent cost. Rather, as noted in OPUC’s Appellant’s Brief, there were a

variety of ways available to the Company in which to propose an appropriate

division between the costs that would have occurred regardless of the state of its

9

Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket No. 16705), Docket No. 18249, Order

on Rehearing at 18-19 and 47, FoF No. 97 (Apr. 22, 1998) (Submitted as Appendix 4)

(Hereinafter, “Docket No. 18249 Order on Rehearing”).

10

OPUC’s Appellant’s Brief at 25-27, 31-32, 38.

6

system, and what was actually incurred. The Company did not, and it was error to

allow the entirety of the $13,014,379 in the storm reserve and rates. Likewise,

OPUC does not contend that the Company had to disallow all or require a line by

line accounting. Instead, as discussed in OPUC’s Appellant’s Brief,11 if the

Commission wished to grant the inclusion of the prudent portion of the costs, the

Commission had multiple options available to it, including but not limited to

using a third party review and basing a disallowance on the third party report, or

remanding the case back to SOAH for further evidence in a supplemental hearing

phase. However, the one option not legally available to the Commission was the

path the Commission chose to take. If, as argued in the PUC’s Appellee’s Brief,

the Commission did weigh the evidence, it concluded that there was not sufficient

evidence to allow a determination as to what portion of the storm expenses were

due to the negligent state of the Company’s system. On the other hand, if the

Commission did not weigh the evidence and refused to address the issue based

upon the passage of time, Commission considered an irrelevant factor. Either way,

the Commission committed reversible error by failing to hold ETI to its burden of

proof under PURA § 36.006 by including unreasonable, unnecessary and

imprudent costs in the storm reserve reflected in rates.

11

Id. at 18-19.

7

C. Indisputably, the issue of determining what amount of 1997 storm

restoration expenses was prudent, appropriate, and includable in the

storm reserve and rates was an issue to be decided in Docket No. 39896.

That fact does not render the Commission’s Orders in Docket Nos. 18249

and 16705 irrelevant or properly disregarded.

At various points in their respective briefs, Appellees ETI and PUC allege

that OPUC contends that the prudence of these storm restoration expenses was

decided in Docket No. 18249. The Appellees’ briefs minimized what the

Commission stated in Docket No. 18249; however, the Commission in its Order in

that docket does not mince words. The Commission expressly stated that a

“major cause of the outages during the storm” were trees overhanging wires.12 The

Commission also stated “[t]ree limbs in ROW overhanging distribution lines pose

a threat to system reliability, and are largely within EGS’ control.”13 The

Commission continued and stated that the “Company’s failure to clear the limbs

before the storm was a major factor in the number and duration of outages

experienced by customers” and that “vegetation management failures greatly

aggravated the situation.”14 The Commission wasn’t done discussing how ETI’s

negligent or poor quality of service impacted the extent of the storm damage. The

Commission found that the “impact of the January 1997 ice storm was greatly

exacerbated by the Company’s failure to maintain its ROW clear of excessive

12

Docket No. 18249 Order on Rehearing at 18-19.

13

Id. at 18-19 (emphasis added). “EGS” is Entergy Gulf States, Inc., the predecessor to ETI and

was the name the Company operated under during Docket Nos. 16705 and 18249.

14

Id. at 18-19 (emphasis added).

8

vegetation.”15 These statements very clearly address the cause of a portion of the

damages which ETI was obligated to repair and restore. ETI presented testimony

through its witness Shawn Corkran on the processes ETI used in repairing and

restoring the system. While the issue of the prudence of the $13,014,379 in

restoration costs and the question of their inclusion in the storm reserve was not at

issue in Docket No. 18249, the Commission did make a determination that impacts

the prudence review of those costs in this case; the Commission in Docket

No. 39896 was not free to disregard the finding in its prior order that a portion of

the storm damage for which the restoration expenses were incurred was caused by

the Company’s unacceptable actions or inactions. Likewise, once the Commission

made its findings that the Company was responsible for greatly exacerbating the

damage, ETI knew or should have known that it must address the issue when

presenting its storm restoration costs for inclusion in the storm reserve and rates.

The Commission’s Order in Docket No. 16705 also made it clear that the

issue of what amount of 1997 storm restoration costs are properly includable in the

storm reserve and reflected in rates remained in Docket No. 16705 and was not

severed into the separate quality of service docket, Docket No. 18249. The final

order (Second Order on Rehearing) in Docket No. 16705 very plainly shows that

the Commission considered the Company’s proposal to include a post-test-year

15

Id. at FoF No. 97.

9

adjustment for the January 1997 ice storm expenses. The Docket No. 16705 final

order, which was issued after Docket No. 18249’s final order, stated in pertinent

part in Finding of Fact No. 147 that, “EGS did not prove a reasonable post-test

year level for its existing reserve fund or that the amount expended in 1997 to

reduce the fund was prudent or appropriate.”16 The Commission continued and

expressed its intent for the issue to be addressed in the Company’s next rate case:

“Reserve fund levels following the test year in this case can be addressed in EGS’

November 1998 rate filing when all parties will have the opportunity to evaluate

the reasonableness of changes to the reserve fund.” Clearly, the Commission’s

Docket No. 16705 final order anticipated that the issue of what amount of 1997 ice

storm costs was prudent and appropriate and includable in the storm reserve fund

would be addressed in the next rate case. Docket No. 39896 was the next fully

litigated rate case and the first opportunity to give effect to Docket No. 16705’s

expectation and address the prudence of including the 1997 storm costs in the

Company’s storm reserve reflected in rates. On this issue, the parties in Docket

No. 39896 effectively stood in the same position as if it was November 1998, and it

was error for the Commission to treat the issue, and the parties, as if it were

otherwise.

16

Application of Entergy Texas for Approval of its Transition to Competition Plan and the Tariffs Implementing

the Plan, and for the Authority to Reconcile Fuel Costs, Docket No. 16705, Second Order on Rehearing

(Oct. 14, 1998) (An excerpt of this order is submitted as Appendix 5).

10

D. The Commission inappropriately focused on only one aspect of the

prudence question and ignored the genesis of the expenses.

ETI did not address the issue of what amount of 1997 ice storm costs was

prudent and appropriate and includable in the storm reserve fund, despite the

Commission’s prior findings that the Company caused much of the damage.

Instead, ETI presented its case on the 1997 storm restoration costs as if the damage

and the resulting restoration costs were incurred in a business as usual manner.

ETI presented testimony on its storm preparation and processes in general to

support its requested storm costs for the entire period of 1996-2011, including

testimony about practices that were put into place in 1998 and thereafter; ETI also

offered the rebuttal testimony of Shawn Corkran to specifically address how the

1997 ice storm restoration process was carried out, including what damage was

repaired and restored. However, none of this evidence went to the issue of what

amount of the damage and resulting costs were due to the “preventative

maintenance” issues or negligent state of the Company’s system.17

17

The PUC asserts on pages 27-29 of its Appellee’s Brief that substantial evidence supports the

inclusion of the expenses. However, the evidence cited by the PUC goes to the undisputed fact

that once the system was damaged and down, it needed to be restored and repaired. OPUC does

not dispute that the clean-up process was done properly; however, it is not the sole issue to be

considered when determining what amount of the 1997 ice storm restoration costs are

includable in the storm reserve and rates. Nor can the evidence cited by the PUC in its brief be

construed to be evidence on the question at issue, given Mr. Corkran’s statement that he was

unaware of any attempt by the Company to identify or quantify the portion of damage and

expenses related to the poor vegetation management. AR, Binder 43, Vol. D, Transcript at

579:15-19. The transcript of Mr. Corkran’s cross-examination is submitted as Appendix 6.

11

Proof that ETI did not present evidence on the issue is found in the

admission by ETI’s expert witness, Shawn Corkran during cross-examination

during the hearing on the merits in Docket No. 39896. Asked if the Company had

identified or quantified the level of expenses attributable to ETI’s negligence, Mr.

Corkran stated that he is not aware of any attempt by the Company to try and

quantify which costs or how much were attributable to the Company’s poor

vegetation management.18 Under PURA § 36.006, the Company holds the burden

of proof and it was error for the Commission to include the entirety of the

$13,014,379 in 1997 Storm Restoration costs in the storm reserve based upon the

existing evidentiary record. It was not feasible, based upon the case presented by

the Company, to determine what portion of the $13,014,379 was due to the

exacerbated level of damage and what portion would have been incurred

regardless. The Company failed to carry its burden of proof that would allow the

Commission to legally find that the entire amount is properly included in the

storm reserves and rates.

18

AR, Binder 53, Vol. D, Transcript at 579:15-19.

12

E. The 60-basis-point reduction to the Company’s return on equity assessed

in Docket No. 18249 was not intended to be in lieu of identifying and

accounting for the portion of the cost of cleaning up and repairing the

damage caused by the Company’s imprudent vegetation management. The

Commission acted arbitrarily and capriciously by considering this

irrelevant factor and including the entirety of the $13,014,379 in ETI’s

storm reserve reflected in rates.

As noted in OPUC’s Appellant’s brief, the Commission imposed a 60-basis-

point reduction in Docket No. 18249 pursuant to PURA § 36.062 expressly

intended to reflect the poor level of service provided by the Company, to

incentivize the Company to improve its service quality, and to provide the

ratepayers a remedy for such things as billing rate error and call center response

time.19 As acknowledged by ETI during the hearing on the merits in Docket No.

39896, the 60 basis point reduction levied in Docket No. 18249 was used by the

Commission as part of an incentive plan created to help the Company achieve

much needed service quality improvements.20

Moreover, the Company’s quality of service was a statutorily required

consideration under PURA § 36.062 when determining the Company’s return on

equity (ROE). The 60-basis-point reduction was more of a penalty in nature and

was not intended to be a cure-all for the attendant impacts of the poor service.

19

See Docket No. 18249 Order on Rehearing at 1-2; See also Id. at 28-29, 35 and Ordering

Paragraph 8.

20

AR, Vol. D, Transcript at 570:22-572:2; See Docket No. 18249 Order on Rehearing at 28 and

28-31. The plan also allowed the Company the opportunity to “earn back” some of its basis point

reduction going forward, if it met certain specific performance targets. Id. at 29.

13

Specifically, contrary to the statement on page 57 of the Commission-adopted PFD

and the Appellees’ argument, the 60 basis point reduction was not intended as a

remedy in whole or in part for the extra restoration costs the Company expended

in cleaning up the exacerbated damage caused by the imprudent state of its

system.

First, the issue of the recovery of the 1997 storm restoration costs through

the storm reserve was not one of the issued severed out of Docket No. 16705 into

Docket No. 18249.21 Therefore, the issue was not before the Commission at the

time it assessed the 60 basis point penalty. Second, the Order in Docket No. 16705

was issued six months after the Order in Docket 18249 in which the Commission

ordered the 60-basis-point reduction. The Commission was clearly aware of its

own order reducing the Company’s ROE and yet, the above-quoted Finding of

Fact No. 147 from the later order clearly indicates that the Commission anticipated

that the prudence, propriety and reasonableness of the 1997 storm costs and their

inclusion in the storm reserve would be litigated in a future rate case. The

Commission would not have made such a finding if it considered any imprudence

to have been remedied by the 60-basis-point reduction.

The PUC and ETI seem to be arguing that the 60-basis-point reduction

21

Id. at 2-3.

14

trumps the regulatory and statutory requirements that storm costs included in the

plan be “reasonable and necessary” and “not reasonably anticipated.”22 Such an

argument is without merit and contrary to law. Reducing the Company’s ROE

under PURA § 36.062 does not absolve the Company or the Commission from

PURA’s requirements that imprudent costs not be charged to ratepayers. Nor

does the reduction to the ROE convert unreasonable costs into reasonable costs,

and anticipated costs into unanticipated costs. The requirement in

PURA § 36.062 that the Commission address the Company’s service quality when

setting its ROE does not negate the statutory requirement that only reasonable

and necessary expenses be charged to ratepayers under PURA § 36.051 and

36.064.23 Courts “should not give one provision a meaning out of harmony or

inconsistent with other provisions, although it might be susceptible to such a

construction standing alone.”24 Courts must “presume that the Legislature

intends an entire statute to be effective and that a just and reasonable result is

intended.”25

Although PURA § 36.052 authorizes the Commission to take the quality

of a utility's services into account in establishing a reasonable return, the

22

PURA §§ 36.051 and 36.064; 16 Tex. Admin. Code § 25.231(b)(2)(J). Rule 25.231(b) is

submitted as Appendix 3.

23

See 16 Tex. Admin. Code § 25.231(b)(2)(J).

24

Helena Chem. Co. v. Wilkins, 47 S.W.3d 486, 493 (Tex. 2001) (Submitted as Appendix 11).

25

Id. citing Tex. Gov't Code § 311.021(2), (3).

15

provision should not be interpreted to negate the requirements of PURA §§ 36.051

and 36.064(c) that only reasonable and necessary expenses are permitted for

recovery through rates. In other words, a penalty imposed upon a utility's

authorized return for poor service quality should not be viewed as a license to

permit the utility to now charge customers for the portion of the damages

resulting from the Company's poor service quality.26 The end result of the

Commission's decision is that unreasonable and unnecessary expenses are being

charged to customers through the storm reserve and rates. The Commission’s

Order violates PURA, is arbitrary and capricious and is affected by other error of

law.

F. The Commission erred in approving the recovery of imprudent costs.

The PUC in its Appellee’s Brief asserts that a utility is not obligated to carve

out imprudence from its request, and specifically, that ETI was not obligated to

identify the portion of its requested storm expenses that were due to the

exacerbated damage caused by its imprudent system management. These

contentions are incorrect. First, it is indisputably the Company’s burden to prove

each element of its case, including the reasonableness and necessity of including

26

Application of Entergy Texas for Approval of its Transition to Competition Plan and the Tariff Implementing

the Plan, and for the Authority to Reconcile Fuel Costs, Docket No. 16705, Second Order on Rehearing at

FoF No. 147.

16

restoration costs into the storm reserve.27 Imprudent costs are neither reasonable

nor necessary; imprudently incurred costs may not be recovered in the utility’s

base rates.28 Moreover, prudence is a statutorily required criterion.29 The utility

bears the burden of proving the prudence of costs it seeks to recover, and if some

but not all of the requested costs are imprudent, the imprudent costs must be

removed either by separating them out, adopting another reasonable method to

account for the imprudence, or disallowing the intermingled requested costs.30 In

the 1992 City of El Paso decision, the court addressed a case in which imprudence

had been found. The court stated that the Commission should “generally disallow

project costs to the extent of the imprudence.”31 The court continued, stating that

a “determination that an expenditure is imprudent carries the legal consequence of

its exclusion from rate base” and that prudence question “embodies one of the

27

PURA §§ 36.006, 36.051 and 36.064.

28

See Entergy Gulf States, Inc. v. Public Utility Commission, 112 S.W.3d 208, 214 (Tex. App.—Austin

2003, pet. denied) (“[I]n order to raise the price of its product, the utility must . . . bear the

burden of proving that each dollar of cost incurred was reasonably and prudently invested.”).

29

See Texas Utilities Electric Company v. Public Utility Commission, 881 S.W.2d 387, 406 (Tex. App.—

Austin 1994) aff’d in part, rev’d in part on other grounds, 935 S.W.2d 109 (Tex. 1997) (Imprudence

finding “must be supported by underlying findings because it embodies one of the criteria the

Commission must consider in deciding whether to include the particular expenditure in rate base.”)

(emphasis added).

30

Adopting another reasonable method to account for the imprudent costs intermingled with

prudent costs is precisely what the Commission did in the case underlying Texas Utilities Electric

Company v. Public Utility Commission, 881 S.W.2d 387.

31

City of El Paso v Public Utility Commission, 839 S.W.2d 895, 908 (Tex. App.—Austin 1992) aff’d in

part, rev’d in part on other grounds, 883 S.W.2d 179 (Tex. 1994) (Submitted as Appendix 9).

17

criteria the PUC must consider.”32 The City of El Paso case was relied upon by the

court in Texas Utilities Electric Company which dealt with a nuclear power plant. In

Texas Utilities Electric Company, the Texas Third Court of Appeals found that, where

a portion of the utility’s $537.90 million in costs for the Comanche Peak nuclear

project were imprudently incurred, the Commission acted properly in disallowing

some but not all of the costs due to imprudence.33 In the originating Commission

docket, the utility had argued that all of its Comanche Peak costs were prudently

incurred, while intervening parties had argued that the costs should be disallowed

entirely, line by line.34 The Commission had then brought in a third party to

evaluate the prudence of the costs. The court rejected the contention that if the

Commission were to disallow some but not all of the costs, it must require a

detailed breakdown. Instead of doing so, based upon the third party

recommendation, the Commission disallowed part of the costs because they were

imprudent but allowed other costs.35 In particular, the Commission made a $90.5

million disallowance for the response team, a $79.9 million disallowance related to

the corrective action program, plus other disallowances due to delays in licensing,

32

Id.

33

Texas Utilities Electric Company v. Public Utility Commission, 881 S.W.2d 387, 405-406 (Tex. App.—

Austin 1994) aff’d in part, rev’d in part on other grounds, 935 S.W.2d 109 (Tex. 1997) (Submitted as

Appendix 12).

34

Id. at 404.

35

Id. at 403-406.

18

including 54.1 million for “time-driven” indirect costs and $167.3 million in

AFUDC.36 The Austin court reviewed the Commission’s decision to reject an all-

or-nothing approach and disallow the imprudent portion of expenses as just

described; the Court stated that “it is the Commission that is charged with sifting

through the evidence and deciding whether imprudent conduct caused certain

expenditures.”37 While recognizing the Commission’s role in weighing evidence

(and recognizing the need to determine whether imprudent conduct caused

certain expenditures), nowhere in the Texas Utilities Electric Company case does the

court hold that the Commission may allow unreasonable or imprudently incurred

expenses to be included in rates in contravention of PURA §§ 36.051 and 36.064,

and the PUC’s substantive rule, 16 Tex. Admin. Code § 25.231(b)(2)(J), based on

the inability to segregate imprudent costs.

As discussed on pages 17-20 of OPUC’s Appellant’s Brief, the instant case is

distinguishable from Texas Utilities Electric Company because it was already

established as a matter of fact that imprudent conduct caused much of the storm

damage. Finding of Fact 97 from PUC Docket No. 18249 provided the

Commission with the starting point in its decision-making process, and it was the

Commission’s job at that point to either deny ETI’s requested 1997 storm expenses

36

Id. at 404-405. In total, the Commission disallowed $316.5 million as imprudent expenses. Id.

at 405-406 n. 34.

37

Id. at 404.

19

in their entirety, determine what portion was imprudently caused by the

exacerbated damages (by a variety of possible methods, or find that one hundred

percent of the expenses would have been incurred, regardless of the imprudent

system management and exacerbated level of damage.38 The Commission instead

chose to focus solely on the prudence of how the storm restoration was carried out

and erroneously failed to take any reasonable approach to considering what

expenses were related to the exacerbated damages. Consequently, the imprudent

costs became part of the approved rates through their inclusion in the storm

reserve.

G. Some of ETI’s storm costs were “reasonably anticipated,” and it was

reversible error for the Commission to fail to consider this statutorily

required criterion. The Commission’s Order violates PURA § 36.064 and is

the result of the Commission acting arbitrarily and through unlawful

procedure.

PURA Section 36.064 allows storm costs to be included in a self-insurance

plan to the extent they are “not reasonably anticipated.” PURA Subsection

36.064(a) states that, an electric utility “may self-insure all or part of the utility's

potential liability or catastrophic property loss, including windstorm, fire, and

explosion losses, that could not have been reasonably anticipated and included

under operating and maintenance expenses.”39 In a prior Commission Order in

38

Docket No. 18249 Order on Rehearing at 47, FoF No. 97.

39

The Commission’s substantive rule on self-insurance plans, 16 Tex. Admin. Code

§ 25.231(b)(1)(G), states in pertinent part: “The reserve accounts are to be charged with

20

Docket No. 18249, the Commission found that the damage resulting from the 1997

ice storm was much greater than it would otherwise have been due to the

Company’s imprudent vegetation management. Vegetation management is a

program designed to keep the rights of way surrounding power lines clear; the

very purpose of vegetation management is to anticipate and prevent or mitigate

storm damage and outages in bad weather.40 The Commission’s Order in Docket

No. 39896 fails to demonstrate that the Commission considered the imprudent

genesis of the storm damage and the fact that much of the damage and

corresponding expenses were reasonably anticipated and preventable.

Both the PUC and ETI defend the Commission’s order by claiming that the

“not reasonably anticipated” requirement for inclusion of storm costs in the self-

insurance reserve and rates was considered by the Commission either because the

PFD mentioned a witness’s discussion of the severity of the storm or because a

single Q&A that appeared in another witness’s rebuttal testimony said so (despite

not being cited in the PFD or Order). Neither contention even if read in the best

light would be sufficient. The “not reasonably anticipated” requirement is a

statutorily required consideration that requires support by underlying findings of

property and liability losses which occur, and which could not have been reasonably anticipated

and included in operating and maintenance expenses, and are not paid or reimbursed by

commercial insurance.”

40

Docket No. 18249 Order on Rehearing at 14.

21

fact in order to show that the Commission properly gave consideration to the

statutorily required criterion.41 It is not enough to merely infer consideration

through other findings of fact or statements; clear, specific findings are required in

order to prove that the Commission fulfilled its duty under the statute.42 The

Court in Charter Medical explained that underlying findings of fact have

“substantial statutory purpose” and serve to “restrain any disposition on the part

of the agency to grant [a certificate] without a full consideration of the evidence

and a serious appraisal of the facts.”43 Such findings of fact also serve to inform the

parties and the courts of the basis for the agency's decision so that the parties may

intelligently prepare an appeal and so that the courts may properly exercise their

function of review.44

The Commission’s Order fails to show the statutorily required

consideration that storm costs included in the self-insurance plan only be those

“that could not have been reasonably anticipated,” and further fails to provide

underlying findings, either in the findings of fact or in the body of the Order, that

constitute material basic facts that relate to the statutory finding of “not

reasonably anticipated.” The failure to include underlying findings of fact to

41

See Texas Health Facilities Comm’n v. Charter Medical-Dallas, 665 S.W.2d at 451-452 (Submitted as

Appendix 8).

42

Id.

43

Id. at 452.

44

Id.

22

support the “not reasonably anticipated” finding violates APA § 2001.141(d), but is

also procedural and a violation of APA § 2001.174(2)(C). Texas courts will reverse

an agency order when underlying fact findings are legally insufficient.45

Additionally, the omission of an ultimate finding (or statutorily required criteria)

when underlying findings are absent violates PURA § 36.064, APA § 2001.141(b), is

arbitrary and capricious, and the resulting order is made through unlawful

procedure. An expressly stated factor in determining whether the agency’s

decision is arbitrary or results from an abuse of discretion is whether the agency

“failed to consider a factor the Legislature directs it to consider.”46

Finally, the Commission’s own regulation, 16 Tex. Admin. Code

§ 25.231(b)(1)(G), requires that only those property and liability losses which

could not have been reasonably anticipated may be included in the self-insurance

plan. Failing to give effect to its own unambiguous regulation is reversible as

other error of law and is also arbitrary and capricious. This Court has stated that

an agency decision is arbitrary when its final order “fails to demonstrate a

connection between the agency decision and the factors that are made relevant to

45

See Texas Health Facilities Comm’n v. Presbyterian Hospital North, 690 S.W.2d 564, 566 (Tex. 1985);

See also Finder v. Texas Medical Bd., 2010 WL 4670510 *6 (Tex. App.—Austin, pet. denied) (“The

findings of fact in Dr. Finder's case do not require the inferential leap necessary in Presbyterian

Hospital.”).

46

City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179, 184 (Tex. 1994).

23

that decision by the applicable statutes and regulations.”47 More directly, our

Supreme Court has stated that “if the Commission has failed to follow the clear,

unambiguous language of its own regulation, we must reverse its action as

arbitrary and capricious.”48

Pages 20-22 of OPUC’s Appellant’s brief discusses why costs related to the

1997 ice storm were in fact reasonably anticipated, including that much of the

damage was found by the Commission to have been caused by imprudent

vegetation management. As noted in OPUC’s Appellant’s brief, the very purpose

of vegetation management requirements is to prevent or mitigate foreseeable

damage after storms due to vegetation in the rights of way coming into contact

with conductors and wires, causing wire breakage or ground faults. The Order is

legally deficient to support the inclusion of the entirety of 1997 ice storm costs in

the storm reserve as “not reasonably anticipated” costs; to the contrary, the record

shows that the 1997 storm costs were in fact reasonably anticipated. It was

reversible error to include these costs in the storm reserve and rates.

47

General Motors Corp. v. Bray, 243 S.W.3d 678, 684 (Tex. App.—Austin 2007, no pet.)

48

Public Util. Comm’n v. Gulf States Utilities, 809 S.W.2d 201, 207 (Tex. 1991).

24

H. ETI’s 420-page spreadsheet was properly excluded from the evidentiary

record. (Response to ETI’s Conditional Cross-Point)

ETI offers as a conditional cross-point that the Commission erred by

excluding from evidence a 420-page spreadsheet ETI produced in discovery. ETI’s

complaint is procedural in nature and falls under the “made through unlawful

procedure” standard of review.49 ETI’s conditional cross-point is meritless. First,

the excluded spreadsheet was not controlling on a material issue but was instead

merely cumulative and thus, its exclusion from evidence, if error, was harmless and

does not warrant reversal under APA § 2001.174(2)(c).50 Here, the spreadsheet

only shows that expenditures were made. Five pages are in evidence as part of

OPUC’s Exhibit No. 6; these pages show the nature of the information provided

and, because the accounting itself is not challenged, the remaining 415 pages are

unnecessary to the rendition of a proper order.51

ETI contends it was error to deny the admission the 420-page spreadsheet

on the basis that ETI failed to reserve its right to exercise optional completeness.52

ETI attempts to support its contention by citing to Gilmore v. State, which was a

49

APA § 2001.174(2)(c).

50

Mentis v. Barnard, 870 S.W.2d 14, 16 (Tex. 1994); Office of Public Utility Counsel v. Public Utility

Comm’n, 185 S.W.3d 555, 576-77 (Tex. App.—Austin 2006, pet. denied).

51

ETI also presented rebuttal testimony explaining the processes it went through in the storm

restoration.

52

It appears from ETI’s pleadings that it does not contest the validity of the other basis for the

ALJ’s ruling which was that the document violates Tex. R. Civ. P. 197.3. See AR, Binder 43, Vol.

K, Transcript at 1705-1706.

25

criminal case wherein the Dallas Court of Appeals held that a party does not have

to exercise optional completeness at the time the document being “completed” is

admitted; a party can wait until “cross-examination, or during the development of

[its] own case.”53 However, there is a difference between having the right to

exercise optional completeness later in the proceeding rather than

contemporaneously with the document being completed, and failing to reserve the

right to do so later. The “permissive grant” language quoted by ETI deals with the

fact that Appellant in Gilmore had argued that the language of Rule 107 of the Texas

Rules of Evidence required the court to admit the complete document

immediately.54

SOAH ALJs have been charged with the duty to conduct the contested case

hearing on the merits when referred from the Commission.55 When the SOAH

ALJ acts as the presiding officer, he has “broad discretion in conducting the course,

conduct, and scope of the hearing,” including the power to “rule upon the

admissibility of evidence and amendments to pleadings.”56 When conducting

hearings referred from the Commission, it is the established practice that parties

are required to reserve the right of optional completeness if not exercising it

53

Gilmore v. State, 744 S.W.2d 630, 631(Tex. App.- Dallas 1987, pet. ref’d) (Submitted as Appendix

13).

54

Id.

55

16 Tex. Admin. Code § 22.207.

56

16 Tex. Admin. § 22.202(c).

26

contemporaneously with the admission of the document being completed. In the

case below, Docket No. 39896, ETI itself “reserved” optional completeness nine

times over the course of the hearing on the merits and exercised that right once.57

Notably, seven of the times the Company reserved optional completeness for later

admission occurred prior to the ALJ’s ruling on the spreadsheet. ETI knew what

was required to exercise optional completeness in a PUC case at SOAH and

cannot properly complain now that the spreadsheet’s exclusion from evidence was

error.

Further, the purpose behind optional completeness would not apply to the

spreadsheet and OPUC Exhibit No. 6. The purpose behind the rule of optional

completeness is “to reduce the possibility of the fact finder receiving a false

impression from hearing the evidence of only a part of a writing.”58 There are two

threshold requirements to invoke the rule of optional completeness: (1) an

incomplete statement was introduced into evidence, and (2) the party offering the

57

ETI reserved optional completeness on the following exhibits: Cities Exhibit No. 7

(Transcript (Tr.) at 69, ll. 1-2); TIEC Exhibit No. 9 (Tr. at 183, ll. 17-21); OPUC Exhibit No. 10

(Tr. at 282, l. 21-283, l. 1); Cities Exhibit No. 41 (Tr. at 968, ll.14-17); Cities Exhibit No. 43A (Tr.

at 1456, ll. 4-5 and 15-20); Cities Exhibit No. 43B (Tr. at 1456, l. 21-1457, l.4); Cities Exhibit No.

48 (Tr. at 2082, ll. 19-22); and OPUC Exhibit No. 35 (Tr. at 2095, ll. 1-25). ETI exercised its

reserved right to optional completeness as ETI Exhibit No. 98 (Tr. at 1505, l. 16- 1507, l. 15).

Cities also reserved optional completeness on one ETI Exhibit (ETI Exhibit No. 83, Tr. at 1190, l.

22-1191, l. 5) and exercised that reservation as Cities Exhibit No. 49 (Tr. at 1686, l. 15-1687, l. 7).

These transcripts are found in the Administrative Record in Binder 43, Volumes B, C, F, G, I, K,

and M, and the cited excerpts are submitted here as Appendix 7.

58

Gilmore v. State, 744 S.W.2d at 631; See Roman v. State, 503 S.W.2d 252, 253 (Tex. Crim. App.

1974).

27

remainder must show that the remainder is on the same matter and “is necessary

to fully understand or explain the matter.”59 In Crosby v. Minyard Foods, the Dallas

Court of Appeals found that the Defendant, Minyard Food Stores, may have

satisfied the first requirement but failed to meet the second. The court concluded

that, “Minyard clearly failed to meet the second requirement. . . . Minyard has

made no attempt to show how Rayshell's testimony could have confused or misled

the jury regarding the contents of Kern's affidavit or its meaning. . . . [T]he trial

court erred in admitting the document.”60 Like in Crosby, admitting the remainder

of the writing (here, the spreadsheet) would not serve to correct any false

impression or otherwise add to the Commission’s understanding. The five-page

excerpt was included as part of OPUC’s testimony to illustrate the naked

granularity of the data. Five pages of line-by-line accounting entries paint the

picture with sufficient clarity. Since the accuracy of the entries was not in

dispute, “completing” the spreadsheet with the remaining 415 pages would not

serve the purpose for which the optional completeness rule was intended to

address.

59

Crosby v. Minyard Food Stores, 122 S.W.3d 899, 903 (Tex. App.—Dallas 2003, no pet.) (Submitted

as Appendix 14).

60

Id.

28

PRAYER

For the reasons stated in this brief and in OPUC’s Appellant’s Brief, the

Office of Public Utility Counsel respectfully prays that the Court reverse the

district court’s judgment insofar as it upholds the Commission’s decision in the

respects discussed above. OPUC further prays that the Court remand the case to

the Commission for further proceedings, based upon the existing evidentiary

record, to determine rates consistent with the Court’s decision. Finally, OPUC

respectfully prays that this Court grant the OPUC such other and further relief to

which it may be justly entitled.

Respectfully submitted,

Tonya Baer

Public Counsel

State Bar No. 24026771

/s/ Sara J. Ferris___________________________

Sara J. Ferris

Senior Assistant Public Counsel

State Bar No. 50511915

OFFICE OF PUBLIC UTILITY COUNSEL

1701 N. Congress Avenue, Suite 9-180

P.O. Box 12397, Capitol Station

Austin, Texas 78711-2397

512/936-7500 (Telephone)

512/936-7525 (Facsimile)

29

CERTIFICATE OF COMPLIANCE

I certify that the Appellant’s Reply Brief of the Office of Public Utility

Counsel contains 5,805 words, as measured by the undersigned counsel’s word-

processing software, and therefore complies with the word limit found in Tex. R.

App. P. 9.4(i)(2)(B).

__ /s/ Sara J. Ferris_________________

Sara J. Ferris

CERTIFICATE OF SERVICE

I certify that the Appellant’s Reply Brief and Appendix of the Office of

Public Utility Counsel 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 of

the Appellant’s Reply Brief and Appendix of the Office of Public Utility Counsel

was served upon counsel for each party of record, listed below, by electronic

service or 1st Class U.S. Mail, on this 2nd day of June, 2015.

ENTERGY TEXAS, INC. CITIES OF ANAHUAC,

Marnie A. McCormick BEAUMONT, ET. AL

John F. Williams Daniel J. Lawton

Duggins, Wren, Mann & Romero, LLP Lawton Law Firm PC

P.O. Box 1149 12600 Hill Country Blvd, Suite R275

Austin, Texas 78767-1149 Austin, Texas 78738

(512) 744-9300 (512) 322-0019

mmcormick@dwmrlaw.com dlawton@ecpi.com

jwilliams@dwmrlaw.com

30

PUBLIC UTILITY COMMISSION TEXAS INDUSTRIAL ENERGY

OF TEXAS CONSUMERS

Elizabeth R. B. Sterling Rex VanMiddlesworth

Assistant Attorney General Benjamin Hallmark

Environmental Protection Division Thompson Knight LLP

Office of the Attorney General 98 San Jacinto Blvd, Suite 1900

P. O. Box 12548, Capitol Station Austin, Texas 78701

Austin, Texas 78711-2548 (512) 320-9200

(512) 475-4152 rex.vanm@tklaw.com

elizabeth.sterling@texasattorneygeneral.gov benjamin.hallmark@tklaw.com

STATE AGENCIES OF TEXAS

Katherine H. Farrell

Assistant Attorney General

Admin Law Div. – Energy Rates Section

Office of the Attorney General

P. O. Box 12548

Austin, Texas 78711-2548

(512) 475-4173

katherine.farrell@texasattorneygeneral.gov

_ /s/ Sara J. Ferris_________________

Sara J. Ferris

31

Appendix to the Appellant's Reply Brief

of the Office of Public Utility Counsel

l. PURA, Chapter 36, Subchapters A and B

2. APA, Tex. Gov't Code§ 2001.174

3. PUC Substantive Rule on Cost of Service~Allowable Expenses:

16 Tex. Admin. Code§ 25.231(b)

4. PUC Docket No. 18249, Order on Rehearing

5. Excerpts from PUC Docket No. 16705, Second Order on

Rehearing

6. PUC Docket No. 39896, Hearing on the Merits Transcript:

Excerpts of Direct and Cross~ Examination of ETI Witness

Shawn Corkran

7. PUC Docket No. 39896 Hearing on the Merits Transcript:

Excerpts re. Optional Completeness

8. Tex. Health Facilities Comm'n v. Charter Medical~Dallas, 665 S.W.2d

446 (Tex. 1984)

9. City ofEl Paso v. Public Util. Comm'n, 839 S.W.2d 895 (Tex. App.-

Austin 1992) aff'd in part, rev'd in part on other grounds, 883 S.W.2d

179 (Tex.1994).

10. City of El Paso v. Public Util. Comm'n, 883 S.W.2d 179 (Tex. 1994)

11. Helena Chemical Co. v. Wilkins, 47 S.W.3d 486 (Tex. 2001)

12. Texas Utilities Electric Company v. Public Utility Commission,

881 S.W.2d 387 (Tex. App.- Austin 1994) aff'd in part, rev'd in part

on other grounds, 935 S.W.2d 109 (Tex. 1997)

13. Gilmorev. State, 744 S.W.2d 630 (Tex. App.-Dallas 1987, pet. ref'd)

14. Crosby v. Minyard Food Stores, 122 S.W.3d 899 (Tex. App.- Dallas

2003, no pet.)

Appendix 1

PURA, Chapter 36, Subchapters A and B

PUBLIC UTILITY REGULATORY ACT

Title II, Texas Utilities Code

(As Amended)

Effective as of September 1, 2013

PUBLIC UTILITY COMMISSION

OF TEXAS

FOREWORD

The Public Utility Code was enacted by Acts 1997, 75th Leg., R.S., ch. 166, § 1 as a new

and separate code effective September 1, 2007. Title 2 of the code is properly cited as the Public

Utility Regulatory Act.

This edition of the Public Utility Regulatory Act contains amendments adopted through

the 83rd Legislature, Third Called Session.

In general, the effect of amendments has been clear and the resulting text changes were

straightforward and did not require any editorial discretion. Except as explained below, editorial

discretion was exercised in reconciling multiple amendments to the same section. In the majority

of these cases, there was no irreconcilable conflict and all of the amendments could be given

effect. In some cases, an act expressly amended a provision as added or amended by another act.

In the few cases where an irreconcilable conflict was found, the act with the later date of

enactment was given effect, with the other provisions italicized below. In addition, a note

explaining the conflict is provided following the section annotation.

The annotations following each section have two components. The first annotation

shows the derivation of the section, either citing to the Public Utility Regulatory Act of 1995

(V.A.C.S. Art. 1446c-O), Acts 1997, ch. 166, or showing the section as added to the code and

citing the relevant act. The second component identifies subsequent amendments, cites the

amending act (and originating bill), provides a brief summary of each of the amendments, and,

where appropriate, provides a reference to related provisions or material.

This publication is maintained by the Commission Advising and Docket Management

Division of the Public Utility Commission of Texas. Suggestions or corrections may be

submitted to that division.

CHAPTER 36. RATES

SUBCHAPTER A. GENERAL PROVISIONS

Sec. 36.001. AUTHORIZATION TO ESTABLISH AND REGULATE RATES.

(a) The regulatory authority may establish and regulate rates of an electric utility and may adopt

rules for determining:

( 1) the classification of customers and services; and

(2) the applicability of rates.

(b) A rule or order of the regulatory authority may not conflict with a ruling of a federal regulatory

body.

(V.A.C.S. art. 1446c-0, Sec. 2.201.)

Sec. 36.002. COMPLIANCE WITH TITLE.

An electric utility may not charge or receive a rate for utility service except as provided by this title.

(V.A.C.S. art. 1446c-O, Sec. 2.153 (part).)

Sec. 36.003. JUST AND REASONABLE RATES.

(a) The regulatory authority shall ensure that each rate an electric utility or two or more electric

utilities jointly make, demand, or receive is just and reasonable.

(b) A rate may not be unreasonably preferential, prejudicial, or discriminatory but must be sufficient,

equitable, and consistent in application to each class of consumer.

(c) An electric utility may not:

(1) grant an unreasonable preference or advantage concerning rates to a person in a

classification;

(2) subject a person in a classification to an unreasonable prejudice or disadvantage concerning

rates; or

(3) establish or maintain an unreasonable difference concerning rates between localities or

between classes of service.

(d) In establishing an electric utility's rates, the commission may treat as a single class two or more

municipalities that an electric utility serves if the commission considers that treatment to be appropriate.

(e) A charge to an individual customer for retail or wholesale electric service that is less than the

rate approved by the regulatory authority does not constitute an impermissible difference, preference, or

advantage.

(V.A.C.S. art. 1446c-0, Sees. 2.202, 2.214 (part).)

Sec. 36.004. EQUALITY OF RATES AND SERVICES.

(a) An electric utility may not directly or indirectly charge, demand, or receive from a person a

greater or lesser compensation for a service provided or to be provided by the utility than the

compensation prescribed by the applicable tariff filed under Section 32.101.

(b) A person may not knowingly receive or accept a service from an electric utility for a

compensation greater or less than the compensation prescribed by the tariff.

(c) Notwithstanding Subsections (a) and (b), an electric utility may charge an individual customer

for wholesale or retail electric service in accordance with Section 36.007.

79

(d) This title does not prevent a cooperative corporation from returning to its members net earnings

resulting from its operations in proportion to the members' purchases from or through the corporation.

(V.A.C.S. art. 1446c-O, Sees. 2.215(a), (b).)

Sec. 36.005. RATES FOR AREA NOT IN MUNICIPALITY.

Without the approval of the commission, an electric utility's rates for an area not in a municipality

may not exceed 115 percent of the average of all rates for similar services for all municipalities served by

the same utility in the same county as that area.

(V.A.C.S. art. 1446c-O, Sec. 2.213.)

Sec. 36.006. BURDEN OF PROOF ..

In a proceeding involving a proposed rate change, the electric utility has the burden of proving that:

(1) the rate change is just and reasonable, if the utility proposes the change; or

(2) an existing rate is just and reasonable, if the proposal is to reduce the rate.

(V.A.C.S. art. 1446c-O, Sec. 2.204.)

Sec. 36.007. DISCOUNTED WHOLESALE OR RETAIL RATES.

(a) On application by an electric utility, a regulatory authority may approve wholesale or retail

tariffs or contracts containing charges that are less than rates approved by the regulatory authority but not

less than the utility's marginal cost. The charges must be in accordance with the principles of this title

and may not be unreasonably preferential, prejudicial, discriminatory, predatory, or anticompetitive.

(b) The method for computing the marginal cost of the electric utility consists of energy and capacity

components. The energy component includes variable operation and maintenance expense and marginal

fuel or the energy component of purchased power. The capacity component is based on the annual

economic value of deferring, accelerating, or avoiding the next increment of needed capacity, without

regard to whether the capacity is purchased or built.

(c) The commission shall ensure that the method for determining marginal cost is consistently

applied among utilities but may recognize the individual load and resource requirements of the electric

utility.

(d) 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.

(V.A.C.S. art. 1446c-O, Sees. 2.001(b), (c), (d) (part), 2.052(b), (c).)

Sec. 36.008. STATE TRANSMISSION SYSTEM.

In establishing rates for an electric utility, the commission may review the state's transmission system

and make recommendations to the utility on the need to build new power lines, upgrade power lines, and

make other necessary improvements and additions.

(V.A.C.S. art. 1446c-O, Sec. 2.051(w) (part).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7), § 23.)

Sec. 36.009. BILLING DEMAND FOR CERTAIN UTILITY CUSTOMERS.

Notwithstanding any other provision of this code, the commission by rule shall require a transmission

and distribution utility to:

(1) waive the application of demand ratchet provisions for each nonresidential secondary service

customer that has a maximum load factor equal to or below a factor set by commission rule;

(2) implement procedures to verify annually whether each nonresidential secondary service

customer has a maximum load factor that qualifies the customer for the waiver described by

Subdivision (1);

80

(3) specify in the utility's tariff whether the utility's nonresidential secondary service customers

that qualify for the waiver described by Subdivision ( 1) are to be billed for distribution service

charges on the basis of:

(A) kilowatts;

(B) kilowatt-hours; or

(C) kilovolt-amperes; and

(4) modify the utility's tariff in the utility's next base rate case to implement the waiver described

by Subdivision (1) and make the specification required by Subdivision (3).

(Added by Acts 2011, 82nd Leg., R.S., ch. 150 (HB 1064), § 1.)

SUBCHAPTER B. COMPUTATION OF RATES

Sec. 36.051. ESTABLISHING OVERALL REVENUES.

In establishing an electric utility's rates, the regulatory authority shall establish the utility's overall

revenues at an amount that will permit the utility a reasonable opportunity to earn a reasonable return on

the utility's invested capital used and useful in providing service to the public in excess of the utility's

reasonable and necessary operating expenses.

(V.A.C.S. art. 1446c-O, Sec. 2.203(a).)

Sec. 36.052. ESTABLISHING REASONABLE RETURN.

In establishing a reasonable return on invested capital, the regulatory authority shall consider

applicable factors, including:

(1) the efforts and achievements ofthe utility in conserving resources;

(2) the quality of the utility's services;

(3) the efficiency of the utility's operations; and

(4) the quality of the utility's management.

(V.A.C.S. art. 1446c-0, Sec. 2.203(b).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7), § 24 (repealed

former subd. (1) and renumbered former subds. (2) to (5) as subds. (1) to (4)).)

Sec. 36.053. COMPONENTS OF INVESTED CAPITAL.

(a) Electric utility rates shall be based on the original cost, less depreciation, of property used by and

useful to the utility in providing service.

(b) The original cost of property shall be determined at the time the property is dedicated to public

use, whether by the utility that is the present owner or by a predecessor.

(c) In this section, the term "original cost" means the actual money cost or the actual money value of

consideration paid other than money. ·

(d) If the commission issues a certificate of convenience and necessity or, acting under Section

39.203(e), orders an electric utility or a transmission and distribution utility to construct or enlarge

transmission or transmission-related facilities to facilitate meeting the goal for generating capacity from

renewable energy technologies under Section 39.904(a), the commission shall find that the facilities are

used and useful to the utility in providing service for purposes of this section and are prudent and

includable in the rate base, regardless of the extent ofthe utility's actual use ofthe facilities.

(V.A.C.S. art. 1446c-O, Sees. 2.206(a) (part), (c).) (Amended by Acts 2005, 79th Leg., 1st C.S., ch. 1 (SB 20),

§ 1 (added subsec. (d)).)

81

Sec. 36.054. CONSTRUCTION WORK IN PROGRESS.

(a) Construction work in progress, at cost as recorded on the electric utility's books, may be included

in the utility's rate base. The inclusion of construction work in progress is an exceptional form of rate

relief that the regulatory authority may grant only if the utility demonstrates that inclusion is necessary to

the utility's financial integrity.

(b) Construction work in progress may not be included in the rate base for a major project under

construction to the extent that the project has been inefficiently or imprudently planned or managed.

(V.A.C.S. art. 1446c-0, Sees. 2.206(a) (part), (b).)

Sec. 36.055. SEPARATIONS AND ALLOCATIONS.

Costs of facilities, revenues, expenses, taxes, and reserves shall be separated or allocated as

prescribed by the regulatory authority.

(V.A.C.S. art. 1446c-O, Sec. 2.207.)

Sec. 36.056. DEPRECIATION, AMORTIZATION, AND DEPLETION.

(a) The commission shall establish proper and adequate rates and methods of depreciation,

amortization, or depletion for each class of property of an electric or municipally owned utility.

(b) The rates and methods established under this section and the depreciation account required by

Section 32.102 shall be used uniformly and consistently throughout rate-setting and appeal proceedings.

(V.A.C.S. art. 1446c-O, Sees. 2.15l(a) (part), (d).)

Sec. 36.057. NET INCOME; DETERMINATION OF REVENUES AND EXPENSES.

(a) An electric utility's net income is the total revenues of the utility less all reasonable and

necessary expenses as determined by the regulatory authority.

(b) The regulatory authority shall determine revenues and expenses in a manner consistent with this

subchapter.

(c) The regulatory authority may adopt reasonable rules with respect to whether an expense is

allowed for ratemaking purposes.

(V.A.C.S. art. 1446c-O, Sees. 2.208(a), (e).)

Sec. 36.058. CONSIDERATION OF PAYMENT TO AFFILIATE.

(a) Except as provided by Subsection (b), the regulatory authority may not allow as capital cost or as

expense a payment to an affiliate for:

(1) the cost of a service, property, right, or other item; or

(2) interest expense.

(b) The regulatory authority may allow a payment described by Subsection (a) only to the extent that

the regulatory authority finds the payment is reasonable and necessary for each item or class of items as

determined by the commission.

(c) A finding under Subsection (b) must include:

(1) a specific finding of the reasonableness and necessity of each item or class of items allowed;

and

(2) a finding that the price to the electric utility is not higher than the prices charged by the

supplying affiliate for the same item or class of items to:

(A) its other affiliates or divisions; or

(B) a nonaffiliated person within the same market area or having the same market conditions.

82

(d) In making a finding regarding an affiliate transaction, the regulatory authority shall:

(1) determine the extent to which the conditions and circumstances of that transaction are

reasonably comparable relative to quantity, terms, date of contract, and place of delivery; and

(2) allow for appropriate differences based on that determination.

(e) This section does not require a finding to be made before payments made by an electric utility to

an affiliate are included in the utility's charges to consumers if there is a mechanism for making the

charges subject to refund pending the making of the finding.

(f) If the regulatory authority finds that an affiliate expense for the test period is unreasonable, the

regulatory authority shall:

( 1) determine the reasonable level of the expense; and

(2) include that expense in determining the electric utility's cost of service.

(V.A.C.S. art. I446c-O, Sec. 2.208(b).) (Amended by Acts I999, 76th Leg., R.S., ch. 405 (SB 7), § 25 (amended

subsec. (d)); Acts 2005, 79th Leg., R.S., ch. 4I3 (SB I668), § I (amended subd. (c)(2)).)

Sec. 36.059. TREATMENT OF CERTAIN TAX BENEFITS.

(a) In determining the allocation of tax savings derived from liberalized depreciation and

amortization, the investment tax credit, and the application of similar methods, the regulatory authority

shall:

(1) balance equitably the interests of present and future customers; and

(2) apportion accordingly the benefits between consumers and the electric or municipally owned

utility.

(b) If an electric utility or a municipally owned utility retains a portion of the investment tax credit,

that portion shall be deducted from the original cost of the facilities or other addition to the rate base to

which the credit applied to the extent allowed by the Internal Revenue Code.

(V.A.C.S. art. l446c-O, Sees. 2.I5I(c), (d).)

Sec. 36.060. CONSOLIDATED INCOME TAX RETURNS.

(a) If an expense is allowed to be included in utility rates or an investment is included in the utility

rate base, the related income tax benefit must be included in the computation of income tax expense to

reduce the rates. If an expense is not allowed to be included in utility rates or an investment is not

included in the utility rate base, the related income tax benefit may not be included in the computation of

income tax expense to reduce the rates. The income tax expense shall be computed using the statutory

income tax rates.

(b) The amount of income tax that a consolidated group of which an electric utility is a member

saves, because the consolidated return eliminates the intercompany profit on purchases by the utility from

an affiliate, shall be applied to reduce the cost of the property or service purchased from the affiliate.

(c) The investment tax credit allowed against federal income taxes, to the extent retained by the

electric utility, shall be applied as a reduction in the rate-based contribution of the assets to which the

credit applies, to the extent and at the rate allowed by the Internal Revenue Code.

(V.A.C.S. art. I446c-O, Sec. 2.208(c).) (Amended by Acts 2013, 83rd Leg., R.S., ch. 787 (SB I364), § I

(amended subsec. (a)).)

Sec. 36.061. ALLOWANCE OF CERTAIN EXPENSES.

(a) The regulatory authority may not allow as a cost or expense for ratemaking purposes:

(1) an expenditure for legislative advocacy; or

83

(2) an expenditure described by Section 32.104 that the regulatory authority determines to be not

in the public interest.

(b) The regulatory authority may allow as a cost or expense:

(l) reasonable charitable or civic contributions not to exceed the amount approved by the

regulatory authority; and

(2) reasonable costs of participating in a proceeding under this title not to exceed the amount

approved by the regulatory authority.

(c) An electric utility located in a portion ofthis state not subject to retail competition may establish

a bill payment assistance program for a customer who is a military veteran who a medical doctor certifies

has a significantly decreased ability to regulate the individual's body temperature because of severe burns

received in combat. A regulatory authority shall allow as a cost or expense a cost or expense of the bill

payment assistance program. The electric utility is entitled to:

(1) fully recover all costs and expenses related to the bill payment assistance program;

(2) defer each cost or expense related to the bill payment assistance program not explicitly

included in base rates; and

(3) apply carrying charges at the utility's weighted average cost of capital to the extent related to

the bill payment assistance program.

(V.A.C.S. art. 1446c-0, Sees. 2.152(b), (c), (d), (e).) (Amended by Acts 2013, 83rd Leg., R.S., ch. 597 (SB 981),

§ 1 (added subsec. (c)).)

Sec. 36.062. CONSIDERATION OF CERTAIN EXPENSES.

The regulatory authority may not consider for ratemaking purposes:

(1) an expenditure for legislative advocacy, made directly or indirectly, including legislative

advocacy expenses included in trade association dues;

(2) a payment made to cover costs of an accident, equipment failure, or negligence at a utility

facility owned by a person or governmental entity not selling power in this state, other than a payment

made under an insurance or risk-sharing arrangement executed before the date of loss;

(3) an expenditure for costs of processing a refund or credit under Section 36.11 0; or

(4) any other expenditure, including an executive salary, advertising expense, legal expense, or

civil penalty or fine, the regulatory authority finds to be unreasonable, unnecessary, or not in the

public interest.

(V.A.C.S. art. 1446c-O, Sec. 2.208(d).)

Sec. 36.063. CONSIDERATION OF PROFIT OR LOSS FROM SALE OR LEASE OF

MERCHANDISE.

In establishing an electric or municipally owned utility's rates, the regulatory authority may not

consider any profit or loss that results from the sale or lease of merchandise, including appliances,

fixtures, or equipment, to the extent that merchandise is not integral to providing utility service.

(V.A.C.S. art. 1446c-O, Sees. 2.151(b) (part), (d).)

Sec. 36.064. SELF-INSURANCE.

(a) An electric utility may self-insure all or part of the utility's potential liability or catastrophic

property loss, including windstorm, fire, and explosion losses, that could not have been reasonably

anticipated and included under operating and maintenance expenses.

(b) The commission shall approve a self-insurance plan under this section if the commission finds

that:

84

(1) the coverage is in the public interest;

(2) the plan, considering all costs, is a lower cost alternative to purchasing commercial

insurance; and

(3) ratepayers will receive the benefits of the savings.

(c) In computing an electric utility's reasonable and necessary expenses under this subchapter, the

regulatory authority, to the extent the regulatory authority finds is in the public interest, shall allow as a

necessary expense the money credited to a reserve account for self-insurance. The regulatory authority

shall determine reasonableness under this subsection:

(1) from information provided at the time the self-insurance plan and reserve account are

established; and

(2) on the filing of a rate case by an electric utility that has a reserve account.

(d) After a reserve account for self-insurance is established, the regulatory authority shall:

(1) determine whether the reserve account has a surplus or shortage under Subsection (e); and

(2) subtract any surplus from or add any shortage to the utility's rate base.

(e) A surplus in the reserve account exists if the charges against the account are less than the money

credited to the account. A shortage in the reserve account exists if the charges against the account are

greater than the money credited to the account.

(f) The allowance for self-insurance under this title for ratemaking purposes is not applicable to

nuclear plant investment.

(g) The commission shall adopt rules governing self-insurance under this section.

(V.A.C.S. art. 1446c-O, Sec. 2.210.)

Sec. 36.065. PENSION AND OTHER POSTEMPLOYMENT BENEFITS.

(a) The regulatory authority shall include in the rates of an electric utility expenses for pension and

other postemployment benefits, as determined by actuarial or other similar studies in accordance with

generally accepted accounting principles, in an amount the regulatory authority finds reasonable.

Expenses for pension and other postemployment benefits include, in an amount found reasonable by the

regulatory authority, the benefits attributable to the service of employees who were employed by the

predecessor integrated electric utility of an electric utility before the utility's unbundling under Chapter

39 irrespective of the business activity performed by the employee or the affiliate to which the employee

was transferred on or after the unbundling.

(b) Effective January 1, 2005, an electric utility may establish one or more reserve accounts for

expenses for pension and other postemployment benefits. An electric utility shall periodically record in

the reserve account any difference between:

(1) the annual amount of pension and other postemployment benefits approved as an operating

expense in the electric utility's last general rate proceeding or, if that amount cannot be determined

from the regulatory authority's order, the amount recorded for pension and other postemployment

benefits under generally accepted accounting principles during the first year that rates from the

electric utility's last general rate proceeding are in effect; and

(2) the annual amount of pension and other postemployment benefits as determined by actuarial

or other similar studies that are chargeable to the electric utility's operating expense.

(c) A surplus in the reserve account exists if the amount of pension and other postemployment

benefits under Subsection (b )(1) is greater than the amount determined under Subsection (b )(2). A

shortage in the reserve account exists if the amount of pension and other postemployment benefits under

Subsection (b )(1) is less than the amount determined under Subsection (b )(2).

85

(d) If a reserve account for pension and other postemployment benefits is established, the regulatory

authority at a subsequent general rate proceeding shall:

(1) review the amounts recorded to the reserve account to determine whether the amounts are

reasonable expenses;

(2) determine whether the reserve account has a surplus or shortage under Subsection (c); and

(3) subtract any surplus from or add any shortage to the electric utility's rate base with the

surplus or shortage amortized over a reasonable time.

(Added by Acts 2005, 79th Leg., R.S., ch. 385 (SB 1447), § 1.)

SUBCHAPTER C. GENERAL PROCEDURES FOR RATE CHANGES

PROPOSED BY UTILITY

Sec. 36.101. DEFINITION.

In this subchapter, "major change" means an increase in rates that would increase the aggregate

revenues of the applicant more than the greater of $100,000 or 2-112 percent. The term does not include

an increase in rates that the regulatory authority allows to go into effect or the electric utility makes under

an order of the regulatory authority after hearings held with public notice.

(V.A.C.S. art. 1446c-O, Sec. 2.212(b) (part).)

Sec. 36.102. STATEMENT OF INTENT TO CHANGE RATES.

(a) Except as provided by Section 33.024, an electric utility may not change its rates unless the

utility files a statement of its intent with the regulatory authority that has original jurisdiction over those

rates at least 35 days before the effective date of the proposed change.

(b) The electric utility shall also mail or deliver a copy of the statement of intent to the appropriate

officer of each affected municipality.

(c) The statement of intent must include:

(1) proposed revisions oftariffs; and

(2) a detailed statement of:

(A) each proposed change;

(B) the effect the proposed change is expected to have on the revenues of the utility;

(C) each class and number of utility consumers affected; and

(D) any other information required by the regulatory authority's rules.

(V.A.C.S. art. 1446c-O, Sec. 2.212(a) (part).)

Sec. 36.103. NOTICE OF INTENT TO CHANGE RATES.

(a) The electric utility shall:

(1) publish, in conspicuous form and place, notice to the public of the proposed change once

each week for four successive weeks before the effective date of the proposed change in a newspaper

having general circulation in each county containing territory affected by the proposed change; and

(2) mail notice of the proposed change to any other affected person as required by the regulatory

authority's rules.

(b) The regulatory authority may waive the publication of notice requirement prescribed by

Subsection (a) in a proceeding that involves only a rate reduction for each affected ratepayer. The

applicant shall give notice of the proposed rate change by mail to each affected utility customer.

86

Appendix2

APA, Tex. Gov't Code§ 2001.174

west law.

V.T.C.A., Government Code§ 2001.174 Page 1

c

Effective:[See Text Amendments]

Vernon's Texas Statutes and Codes Annotated Currentness

Government Code (Refs & Annos)

Title 10. General Government (Refs & Annos)

Subtitle A. Administrative Procedure and Practice

"!51 Chapter 2001. Administrative Procedure (Refs & Annos)

"!51 Subchapter G. Contested Cases: Judicial Review

-+-+ § 2001.174. Review Under Substantial Evidence Rule or Undefined Scope of Review

If the law authorizes review of a decision in a contested case under the substantial evidence rule or if the law

does not define the scope of judicial review, a court may not substitute its judgment for the judgment of the state

agency on the weight of the evidence on questions committed to agency discretion but:

(1) may affirm the agency decision in whole or in part; and

(2) shall reverse or remand the case for further proceedings if substantial rights of the appellant have been pre-

judiced because the administrative findings, inferences, conclusions, or decisions are:

(A) in violation of a constitutional or statutory provision;

(B) in excess of the agency's statutory authority;

(C) made through unlawful procedure;

(D) affected by other error of law;

(E) not reasonably supported by substantial evidence considering the reliable and probative evidence in the

record as a whole; or

(F) arbitrary or capricious or characterized by abuse of discretion or clearly unwarranted exercise of discre-

tion.

CREDIT(S)

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.

V.T.C.A., Government Code§ 2001.174 Page 2

Added by Acts 1993, 73rd Leg., ch. 268, § 1, eff. Sept. 1, 1993.

HISTORICAL AND STATUTORY NOTES

2008 Main Volume

Prior Laws:

Acts 1975, 64th Leg., p. 136, ch. 61.

Vernon's Ann.Civ.St. art. 6252-13a, § 19(e).

CROSS REFERENCES

Groundwater management trial of suit, see V.T.C.A., Water Code§ 36.253.

LAW REVIEW COMMENT ARIES

Administrative law 2004 update and analysis. Ron Beal, 57 Baylor L.Rev. 359 (Spring 2005).

Due process and local administrative hearings regulating public nuisances: Analysis and reform. Alex Cameron,

43 St. Mary's L..T. 619 (2012).

Mixing oil and gas with Texas water law. Edmond R. McCarthy, 44 Tex. Tech L. Rev. 883 (2012).

A shift in power: Why increased urban drilling necessitates a change in regulatory authority. Riley W. Vanham,

43 St. Mary's L.J. 229 (Nov. 2011).

LIBRARY REFERENCES

2008 Main Volume

Administrative Law and Procedure~ 763, 791.

Westlaw Topic No. 15A.

C.J.S. Public Administrative Law and Procedure§§ 213, 394, 418 to 420, 433 to 435, 444 to 450.

RESEARCH REFERENCES

2015 Electronic Update

ALR Library

80 ALR 6th 1, Special Commentary: Recovery of "Stranded Costs" by Utilities.

30 ALR 6th 483, Validity, Construction, and Application of State Statutes Providing for Revocation of Driver's

License for Failure to Pay Child Support.

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.

Appendix3

PUC Substantive Rule on Cost of Service,

Allowable Expenses:

16 Tex. Admin. Code§ 25.23l(b)

16 TAC § 25.231 Page 1

Tex. Admin. Code tit. 16, § 25.231

c plant used by and useful to the electric utility

in providing such service to the public.

Payments to affiliated interests for costs of

Texas Administrative Code Cunentness

service, or any property, right or thing, or for

Title 16. Economic Regulation

interest expense shall not be allowed as an

Part 2. Public Utility Commission of Texas

expense for cost of service except as pro-

Chapter 25. Substantive Rules Applicable to

vided in the Public Utility Regulatory Act §

Electric Service Providers

36.058.

Subchapter J. Costs, Rates and Tariffs

"~!! Division 1. Retail Rates

-+-+ § 25.231. Cost of Service (B) Depreciation expense based on original

cost and computed on a straight line basis as

approved by the commission. Other methods

(a) Components of cost of service. Except as provided

of depreciation may be used when it is de-

for in subsection (c)(2) of this section, relating to

termined that such depreciation methodology

invested capital; rate base, and § 23.23(b) of this title,

is a more equitable means of recovering the

(relating to Rate Design), rates are to be based upon an

cost of the plant.

electric utility's cost of rendering service to the public

during a historical test year, adjusted for known and

measurable changes. The two components of cost of (C) Assessments and taxes other than income

service are allowable expenses and return on invested taxes.

capital.

(D) Federal income taxes on a normalized

(b) Allowable expenses. Only those expenses which basis. Federal income taxes shall be com-

are reasonable and necessary to provide service to the puted according to the provisions of the

public shall be included in allowable expenses. In Public Utility Regulatory Act§ 36.060.

computing an electric utility's allowable expenses,

only the electric utility's historical test year expenses (E) Advertising, contributions and donations.

as adjusted for known and measurable changes will be The actual expenditures for ordinary adver-

considered, except as provided for in any section of tising, contributions, and donations may be

these rules dealing with fuel expenses. allowed as a cost of service provided that the

total sum of all such items allowed in the cost

(1) Components of allowable expenses. Allowa- of service shall not exceed three-tenths of

ble expenses, to the extent they are reasonable and 1.0% (0.3%) of the gross receipts of the

necessary, and subject to this section, may in- electric utility for services rendered to the

clude, but are not limited to the following general public. The following expenses shall be in-

categories: cluded in the calculation of the three-tenths

of 1.0% (0.3%) maximum:

(A) Operations and maintenance expense

incurred in furnishing normal electric utility (i) funds expended advertising methods

service and in maintaining electric utility of conserving energy;

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.

16 TAC § 25.231 Page2

Tex. Admin. Code tit. 16, § 25.231

the preceding sentence shall be ex-

(ii) funds expended advertising methods pressly included in the cost of service

by which the consumer can effect a established by the commission's order.

savings in total electric utility bills;

(ii) In the event that an electric utility

(iii) funds expended advertising methods implements an interim rate increase in-

'

to shift usage off of system peak; and eluding an increase filed under bond, an

incremental change in decommissioning

funding shall be included in the increase.

(iv) funds expended promoting renewa-

ble energy.

(iii) An electric utility's decommission-

ing fund and trust balances will be re-

(F) Nuclear decommissioning expense. The

viewed in general rate cases. In the event

following restrictions shall apply to the in-

that an electric utility does not have a

clusion of nuclear decommissioning costs

rate case within a five-year period, the

that are placed in an electric utility's cost of

commission, on its own motion or on the

service.

motion of the commission's Office of

Regulatory Affairs, the Office of Public

(i) An electric utility owning or leasing

Utility Counsel, or any affected person,

an interest in a nuclear-fueled generating

may initiate a proceeding to review the

unit shall include its cost of nuclear de-

electric utility's decommissioning cost

commissioning in its cost of service.

study and plan, and the balance of the

Funds collected from ratepayers for de-

trust.

commissioning shall be deposited

monthly in irrevocable trusts external to

(iv) An electric utility shall perform, or

the electric utility, in accordance with §

cause to be performed, a study of the

25.301 of this title (relating to Nuclear

decommissioning costs of each nuclear

Decommissioning Trusts). All funds

generating unit that it owns or in which it

held in short-term investments must bear

leases an interest. A study or a redeter-

interest. The level of the annual cost of

mination of the previous study shall be

decommissioning for ratemaking pur-

performed at least every five years. The

poses will be determined in each rate

study or redetermination should consider

case based on an allowance for contin-

the most current information reasonably

gencies of I 0% of the cost of decom-

available on the cost of decommission-

missioning, the most current information

ing. A copy of the study or redetermina-

reasonably available regarding the cost

tion shall be filed with the commission

of decommissioning, the balance of

and copies provided to the commission's

funds in the decommissioning trust, an-

Office of Regulatory Affairs and the

ticipated escalation rates, the anticipated

Office of Public Utility Counsel. An

return on the funds in the decommis-

electric utility's most recent decommis-

sioning trust, and other relevant factors.

sioning study or redeterminations shall

The annual amount for the cost of de-

be filed with the commission within 30

commissioning determined pursuant to

days of the effective date ofthis subsec-

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.

16 TAC § 25.231 Page 3

Tex. Admin. Code tit. 16, § 25.231

tion. The five year requirement for a new

study or redetermination shall begin (i) OPEB expense shall be included in an

from the date of the last study or rede- electric utility's cost of service for rate-

termination. making purposes based on actual pay-

ments made.

(G) Accruals credited to reserve accounts for

self-insurance under a plan requested by an (ii) An electric utility may request a

electric utility and approved by the commis- one-time conversion to inclusion of

sion. The commission shall consider ap- current OPEB expense in cost of service

proval of a self insurance plan in a rate case for ratemaking purposes on an accrual

in which expenses or rate base treatment are basis in accordance with generally ac-

requested for a such a plan. For the purposes cepted accounting principles (GAAP).

of this section, a self insurance plan is a plan Rate recognition ofOPEB expense on an

providing for accruals to be credited to re- accrual basis shall be made only in the

serve accounts. The reserve accounts are to context of a full rate case.

be charged with property and liability losses

which occur, and which could not have been

(iii) An electric utility shall not be al-

reasonably anticipated and included in oper-

lowed to recover current OPEB expense

ating and maintenance expenses, and are not

on an accrual basis until GAAP requires

paid or reimbursed by commercial insurance.

that electric utility to report OPEB ex-

The commission will approve a self insur-

pense on an accrual basis.

ance plan to the extent it fmds it to be in the

public interest. In order to establish that the

(iv) For ratemaking purposes, the tran-

plan is in the public interest, the electric util-

sition obligation shall be amortized over

ity must present a cost benefit analysis per-

20 years.

formed by a qualified independent insurance

consultant who demonstrates that, with con-

sideration of all costs, self-insurance is a (v) OPEB amounts included in rates

lower-cost alternative than commercial in- shall be placed in an irrevocable external

surance and the ratepayers will receive the trust fund dedicated to the payment of

benefits of the self insurance plan. The cost OPEB expenses. The trust shall be es-

benefit analysis shall present a detailed tablished no later than six months after

analysis ofthe appropriate limits of self in- the order establishing the OPEB expense

surance, an analysis of the appropriate annual amount included in rates. The electric

accruals to build a reserve account for self utility shall make deposits to the fund at

insurance, and the level at which further ac- least once per year. Deposits on the fund

cruals should be decreased or terminated. shall include, in addition to the amount

included in rates, an amount equal to

fund earnings that would have accrued if

(H) Postretirement benefits other than pen-

deposits had been made monthly. The

sions (known in the electric utility industry as

funding requirement can be met with

"OPEB"). For ratemaking purposes, expense

deposits made in advance of the recog-

associated postretirement benefits other than

nition of the expense for ratemaking

pensions (OPEB) shall be treated as follows:

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.

16 TAC § 25.231 Page4

Tex. Admin. Code tit. 16, § 25.231

purposes. The electric utility shall, to the bership in social, recreational, fraternal, or

extent permitted by the Internal Revenue religious clubs or organizations;

Code, establish a postretirement benefit

plan that allows for current federal in- (F) funds promoting increased consumption

come tax deductions for contributions of electricity;

and allows earnings on the trust funds to

accumulate tax free.

(G) additional funds expended to mail any

parcel or letter containing any of the items

(vi) When an electric utility terminates mentioned in subparagraphs (A)-(F) ofthis

an OPEB trust fund established pursuant paragraph;

to clause (v) of this subparagraph, it

shall notify the commission in writing. If

(H) payments, except those made under an

excess assets remain after the OPEB

insurance or risk-sharing arrangement exe-

trust fund is terminated and all trust re-

cuted before the date of the loss, made to

lated liabilities are satisfied, the electric

cover costs of an accident, equipment failure,

utility shall file, for commission ap-

or negligence at an electric utility facility

proval, a proposed plan for the distribu-

owned by a person or governmental body not

tion of the excess assets. The electric

selling power within the State of Texas;

utility shall not distribute any excess

assets until the commission approves the

(I) costs, including, but not limited to, inter-

disbursement plan.

est expense, of processing a refund or credit

of sums collected in excess of the rate finally

(2) Expenses not allowed. The following ex-

ordered by the commission in a case where

penses shall never be allowed as a component of

the electric utility has put bonded rates into

cost of service:

effect, or when the electric utility has other-

wise been ordered to make refunds;

(A) legislative advocacy expenses, whether

made directly or indirectly, including, but not

(J) any expenditure found by the commission

limited to, legislative advocacy expenses in-

to be unreasonable, unnecessary, or not in the

cluded in professional or trade association

public interest, including but not limited to

dues;

executive salaries, advertising expenses, le-

gal expenses, penalties and interest on

(B) funds expended in support of political overdue taxes, criminal penalties or fmes,

candidates; and civil penalties or fmes.

(C) funds expended in support of any politi- (c) Return on invested capital. The return on invested

cal movement; capital is the rate of return times invested capital.

(D) funds expended promoting political or (1) Rate of return. The commission shall allow

religious causes; each electric utility a reasonable opportunity to

earn a reasonable rate of return, which is ex-

(E) funds expended in support of or mem- pressed as a percentage of invested capital, and

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.

Appendix4

PUC Docket No. 18249, Order on Rehearing

I ' "• .. ~-

PUC DOCKET NO. 18249

ENTERGY GULF STATES, INC. §

SERVICE QUALITY ISSUES §

(SEVERED FROM DOCKET NO. 16705) § OF TEXAS

ORDER ON REHEARING

This Order addresses electric service quality issues relating to Entergy Gulf

States, Inc. (EGS or the Company). The Commission concludes that the quality of EGS'

electric service to its customers in Texas has been less than adequate, specifically sin9e

Entergy Corporation acquired Gulf States Utilities, Inc., in 1993. The record evidence

reveals a lack of effective and prudent maintenance policies, uneven spending in the area

of operations and maintenance (O&M), cuts in experienced personnel, and consequent

deterioration in the quality of service. The management of EGS is structured in a way

that fails to link resource availability with appropriate performance accountability.

The Commission further concludes that the difficulties EGS has experienced with

its quality of service are not simply "customer perception" problems, as claimed by the

Company. 1 The problems are real and must be addressed by the Company in a timely

and serious manner. To motivate the Company to revise its current approach and

promote long-term commitment toward service quality and reliability, the Commission

orders a two-part solution designed both to deal with past problems and implement

remedies for the future. First, the Company's authorized return on equity (ROE) that

otherwise would be adopted in Docket No. 16705 2 will be reduced by 60-basis points and

initially refunded to distribution-level customers. Second, going forward, the Company

1

EGS Initial Brief (IB) at 4 (Dec. 2, 1997); see also, Tr. at 231.

2

Application of Entergy Texas for Approval of Its Transition to Competition Plan and the Tariffs

Implementing the Plan, and for the Auth~rity to Reconcile Fuel Costs, to Set Revised Fuel Costs, to Set

Revised Fuel Factors, and to Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705

(pending).

PUC DOCKET NO. 18249 ORDER ON REHEARING Page2

will have an opportunity to earn back a portion of the ROE reduction, depending on

whether its service quality meets specified benchmarks. These benchmarks will establish

service reliability standards (outage frequency and duration) and customer service

standards (billing errors, call-center performance, service installation, line extension, and

street light replacement). The margin achieved above the benchmarks will reflect the

level of improvement (or, if below, a lack thereof) and will be used to determine whether

the Company is entitled to recoup a portion of the ROE reduction.

I. Procedural History

EGS filed its transition/rate case in Docket No. 16705 on November 27, 1996.

The Commission referred the case to the State Office of Administrative Hearings

(SOAH) on December 5, 1996. On January 24, 1997, the Commission issued a

preliminary order in Docket No. 16705 directing parties, among other things, to "address

specific service quality standards that will apply after the transition [proposed by EGS]."3

On March 7, 1997, the Commission issued a supplemental preliminary order in

Docket No. 16705 that dealt specifically with service quality issues. This order required

that Docket No. 16705 address, in addition to others, the following issues: (1) Does EGS

have an effective and prudent management policy in place that devotes sufficient

resources to ensure adequate and reliable service to its ratepayers? (2) Are there patterns

of variable service quality in EGS' service territory, and if so, what is the cause and

potential resolution of these variations? and (3) What procedures can and should the

Commission implement to monitor service quality on EGS' system, and to respond to

situations in which EGS' service quality falls below the service quality benchmark

levels?

3

Preliminary Order at 12 (January 24, 1997).

PUC DOCKET NO. 18249 ORDER ON REHEARING Page3

Proceeding with EGS' rate case, SOAH established a four-phased hearing

schedule to address the numerous transition and rate issues in Docket No. 16705. The

service quality issues were to be dealt with in the "Competitive Issues" phase, scheduled

to begin in early November 1997.

After EGS and interested parties had filed written testimony and exhibits, 4 but

before the Competitive Issues phase commenced at SOAH, the Commission determined

that it would itselfhear and resolve the service quality issues. Accordingly, on November

4, 1997, the Commission issued an order severing the pending service quality issues from

Docket No. 16705, establishing Docket No. 18249 to deal with those issues, and

establishing procedures by which the Commission would hear and rule on the case.

The Commission convened a hearing on the merits of EGS' service quality on

November 20 and 21, 1997. Chairman Pat Wood and Commissioner Judy Walsh

presided over the hearing. The participating parties included the Company, the Cities, the

High Load Factor Commercial Customer Group (HLFCCG), and the General Counsel, all

of whom presented their direct cases and conducted cross-examinations. Chairman Wood

and Commissioner Walsh also directed questions to the witnesses. Observers from the

Office of Public Utility Counsel (OPUC) and the Attorney General's Office attended the

hearing. The active parties filed initial and reply briefs on December 2 and 9, 1997,

respectively. OPUC filed a statement on December 2, 1997, supporting the briefs of the

Cities and HLFCCG, and the Attorney General's Office filed a statement on December 9,

1997, in support of the same briefs.

The Commission issued the final order in this docket on February 13, 1998. On

March 5, 1998, EGS and General Counsel filed motions for rehearing. The replies to the

motions were due on March 16, 1998, but based on parties' request, the Commission

4

Some of the testimony, particularly from the Company's witnesses, was originally pre-filed for the

Revenue Requirement phase.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page4

granted an extension for filing of replies until March 25, 1998. On March 19, 1998, the

Commission ratified the extension of deadline to file replies and also extended until May

14, 1998, the time to rule on the motions for rehearing pursuant to Gov'T CODE

2001.146(e).

On March 25, 1998, the parties filed a joint reply to motions for rehearing and

motion for entry of order consistent with the parties' stipulation and agreement (the

Stipulation). General Counsel, EGS, OPUC, and lll.-FCCG signed the Stipulation. At

the April 1, 1998 open meeting, the Commission granted rehearing and approved the

Stipulation. The provisions of the Stipulation are reflected in this Order.

II. Background

Entergy Gulf States, Inc., is a public utility subject to the jurisdiction of this

Commission in accordance with Public Utility Regulatory Act (PURA) §§ 14.001,

31.001, 32.001, 33.122, and 36.001 through 36.156. 5 EGS is a wholly-owned subsidiary

of Entergy Corporation (Entergy), a holding company incorporated in Delaware and

registered with the federal Securities and Exchange Commission in accordance with the

Public Utility Holding Company Act. Entergy acquired Gulf States Utilities, Inc., to

create EGS, effective on December 31, 1993. 6

EGS operates in Louisiana and Texas, and is affiliated through its holding

company with investor-owned electric utilities located in Louisiana, Mississippi, and

5

Public Utility Regulatory Act, TEX. UTIL. CODE ANN. 11.001-63.063 (Vernon 1998).

6

Application of Entergy Corporation and Gulf States Utilities Company for Sale, Transfer, or Merger,

Docket No. 11292 (Mar. 25, 1994).

PUC DOCKET NO. 18249 ORDER ON REHEARING PageS

7

Arkansas. The EGS service territory in Texas is located in the southeastern part of the

state, and contains industrialized areas in the vicinity of Beaumont and Port Arthur, as

well as a coastal zone. The differing geographic and climatic characteristics of the

Company's service territory have led to the creation of three distinct sectors: Western I

(suburban with dense trees), Western II (rural with fewer trees), and Gulf (both rural and

urban).

Entergy's headquarters is in New Orleans; EGS' principal office in Texas is

located in Beaumont. In Texas, the Company serves approximately 318,279 customers8

9

and has 11,472 miles of distribution lines. There are 394,865 poles in its system, with

431 feeders. 10 The transmission system--built as early as 1924, with approximately half

of the lines added in the 1950's and 1960's and only 12 percent of lines built or

rehabilitated after 1977--has shown generally good performance. ll This Order is

concerned predominantly with the state of the Company's distribution system.

lll. Discussion and Analysis of Issues

A. General Concept of Reliability

Electricity plays a vital role in our lives. Most, if not all, aspects of our society,

including industrial production, commerce, and individual lifestyles, are built around a

reliable and adequate supply of electrical energy. People have come to depend on

7

Entergy Arkansas (including the Arklahoma Corporation), Inc., Entergy Louisiana, Inc., Entergy

Mississippi, Inc., and Entergy New Orleans, Inc. These companies, together with EGS, form the

"Operating Companies."

8

Ice Storm '97 Field Investigations, Project No. 16301, at V-25 (June 24, 1997).

9

General Counsel Ex. 5, Burrows Direct Testimony at 33, Attachment JDB-2.

10

General Counsel Ex. 24.

11

General Counsel Ex. 1, Ethridge Direct Testimony at 6.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page6

el<~ctricity being available when they need it. In fact, for most customers, delivery of

electrical power and reliability of its delivery have become two inseparable expectations.

Electric utilities generally recognize and accept this dependence and have responded to it

by constructing and operating generation and delivery systems of superior reliability. 12

State law formalizes the utilities' obligation to provide reliable service in PURA

§ 37.151. Reliability, however, is not a static concept. As customer bases grow and

systems age, utilities face new challenges that must be acknowledged and resolved to

maintain reliable service.

In addition to sufficient generating capacity, transmission and distribution

facilities are built so that a specified degree of reliability is achieved. The goal is to

provide required amounts of energy with no, or few, interruptions, while maintaining a

reasonable cost of the overall system. Smooth and continuous interaction of the various

elements of the electrical system results in reliable performance of the overall system.

For consumers, this reliability is reflected in uninterrupted power supply, the degree of

which may be measured by the frequency, duration, and magnitude of adverse effects on

consumer service.

B. Legal Standards

PURA imposes various obligations on utilities and the Co:mrtlission regarding the

provision of electric service to Texas consumers. Specifically, PURA § 37.151 requires

that a regulated utility provide continuous and adequate service in its certificated service

territory. PURA § 38.001 directs utilities to furnish service, instrumentalities, and

facilities that are safe, adequate, efficient, and reasonable. Parallel responsibilities rest

with the Commission. In accordance with PURA § 36.052(3), the Commission must

consider the quality of a utility's services in establishing a reasonable return on invested

12

NORTH AMERICAN ELECTRIC RELIABILI1Y COUNCIL, RELIABILITY CONCEPTS 1-2 (Feb. 1985).

PUC DOCKET NO. 18249 ORDER ON REHEARING Page7

13

capital. This same section of PURA directs the Commission to consider the quality of

the utility's management and the efficiency of its operations when establishing a

reasonable return. Moreover, PURA § 38.071 authorizes the Commission to order an

electric utility to provide "specified" improvements in its service.

C. Analysis of Issues

The Commission's analysis of the issues in this case is divided into five general

topics: (1) physical facil,ities, maintenance, and monitoring; (2) vegetation management;

(3) emergency preparedness, response, outage restoration, and treatment of storm data;

(4) personnel levels, management practices, and spending levels; and (5) pockets of

unreliable service and overall customer service. The following narrative lays out

essential points of the relevant issues; with additional, specific information contained in

the Findings of Fact in Section IV.

1. Physical Facilities, Maintenance, and Monitoring

a. Condition of Poles

As stated above, EGS' transmission system does not pose serious concerns since

it has performed adequately over the last few years, during which only a minimal number

of transmission-related outages or circuit-breaker operations occurred. EGS' inspection

and treatment programs relating to its transmission system seem to be working

13

There are several precedent cases in which the Commission reduced ROE to address inadequate quality

of service. See, e.g., Application of General Telephone Company of the Southwest for Authority to

Increase Rates, Docket No. 3094, Final Order, 6 P.U.C. BULL. 92, 123 (Aug. 8, 1980) (imposing penalty

on company for inadequate service quality); Application of General Telephone Company of the Southwest

for Authority to Increase Rates, Docket No. 3690, Final Order, 7 P.U.C. BULL. 11, 39 (June 18, 1981)

(sustaining penalty due to persistence of poor service); Application of General Telephone Company of the

Southwest for Authority to Increase Rates, Docket No. 4132, Final Order, 7 P.U.C. BULL. 646, 648 (Jan.

14, 1982) (lifting penalty after service was shown to improve for a sufficient period of time); Application

ofHouston Lighting and Power Company, Docket No. 4540, Final Order, 8 P.U.C. BULL 75 (Dec. 6, 1982)

(reducing company's ROE because of service quality and reliability concerns).

PUC DOCKET NO. 18249 ORDER ON REHEARING PageS

satisfactorily, with transmission line rights-of-way (ROW) appearing generally clear. 14

For these reasons, the Commission concludes that the physical state of the Company's

transmission system is adequate. The remainder of this Order will address the

Company's distribution system and related services.

Primary evidence for the condition of EGS' distribution system, including wires,

poles, pole appurtenances, and transformers, comes from the Osmose Wood Preserving

Company (Osmose) inspections conducted in 1995 and 1996, a report filed by Drash

Consulting Engineering, Inc. (Drash), and limited Staff surveys. 15 In general, most of the

poles in the Texas portion of the Company's distribution system are in good condition.

There are, however, numerous poles with physical deficiencies or in need of extensive

and comprehensive vegetation clearing. 16

The Osmose inspectors, contracted by EGS in 1995 and 1996, examined

approximat~ly 37,000, or 10 percent, of the poles and crossarms and found that on

17

average 17.9 percent of poles in eight different areas showed structural decay. The

actual percentages, however, varied greatly, with one area having more than 37 percent of

the poles with some decay, a condition clearly impermissible for any transmission and

distributi~n (T&D) system. 18 While the Osmose inspections were not random, and in

fact, as the Company asserts, focused on particularly troubled spots, the results show that

there are many poles in unsatisfactory condition.

14

General Counsel Ex. 1, Ethridge Direct Testimony at 6-8, 41-43.

15

General Counsel Ex. 1, Ethridge Direct Testimony at 15; General Counsel Ex. 4; General Counsel Ex. 5,

Burrows Direct Testimony, Attachment JDB-3.

16

/d. at 5.

17

General Counsel Ex. 5, Burrows Direct Testimony at 17.

18

Id, Appendix Workpapers at 2.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page9

The purpose of the Drash report, contracted for by the Commission, was to collect

data regarding the condition of EGS' overhead distribution system. The survey was

based on a sample of33 uniformly distributed substations from the Texas portion of EGS

distribution system. 19 The Drash inspectors examined 582 poles on various feeders

originating at these su'Qstations. 20 The Drash survey found 59 poles with structural

deficiencies and 72 poles with ROW encroachments? 1 During the hearing, EGS raised

questions about the accuracy and statistical reliability of the Drash report. The

Commission concludes that the Drash study lacked specific evaluation criteria and

necessary randomness to draw conclusions about the entire EGS Texas system. The

Commission, however, does not reject the Drash report, as requested by the Company;22

rather, the Commission relies on the report to the extent that its findings have been

confirmed by the Osmose inspections and Staff surveys. Considered together, the

collected data persuasively indicate that numerous poles show decay, are in need of repair

or replacement, and that vegetation growth poses a serious problem on some ROW.

b. Pole Inspection Program

The Company conceded that it does not have a traditional pole inspection

progr~ in place.23 Since the Osmose inspections in 1996, there have been no pole or

crossarm inspections on Texas territory. 24 Post-merger, EGS reduced the number of

inspections; for example, in 1995, 29,294 poles and 43,941 crossarms were inspected, but

25

in 1996, only 7,939 poles and 11,908 crossarms underwent inspections. The Company

19

Id. at 19.

20

ld. at 20.

21

Id. at 21-22.

22

Tr. at 552-60, 606-15.

23

Tr. at 176,751-52.

24

Tr. at 170, 177-78.

25

General Counsel Ex. 19 at Bates Stamp 0194741.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 10

is now planning to hire Osmose to carry out a ten-year inspection program that will cover

the entire system (35,000 poles inspected annually). 26 Evidence presented in the case

makes it clear that EGS' pole inspection and repair work cycles have not been sufficiently

rigorous, continuous, or frequent to maintain all of its facilities in the condition required

to meet its reliability and service obligations under PURA.

c. Maintenance Practices

A review of maintenance records shows that line maintenance and vegetation

control are reactive in nature;27 there is a lack of written, specific, and preventive

maintenance policies;28 and priority is given to capital additions to the detriment of

adequate maintenance practices. 29 For example, total line-miles actively maintained by

the Company's employees dropped 30 percent from 1994 to 1996?0 The Company's

internal risk assessment study points to an absence of a strategic plan, and consequent

inadequacies in resource sharing and work planning. 31 Based on the evidence, the

Commission concludes that EGS has failed to establish and carry out distribution

maintenance policies in a manner sufficient to ensure adequate and reliable delivery of

electric service.

d. Data Collection

The Company presented a variety of data to support its claim of good

performance; however, the accuracy of its data collection practices came under a great

deal of scrutiny during the hearing, bringing into question the ability of the Company to

26

Tr. at 751-52.

27

General Counsel Ex. 4, Gonzalez Direst Testimony at 6-8, Drash Report at 45-46.

28

Tr. at 59; HLFCCG Ex. I, Patton Direct Testimony, Entergy Internal Audit and Risk Assessment.

29

General Counsel Ex. I, Ethridge Direct Testimony at 19-20; General Counsel Ex. 8; General Counsel

Ex. 19.

30

Tr. at 737.

31

General Counsel Ex. 30 at 2.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 11

monitor its performance fairly. The parties debated at length the merits and mechanics of

various system monitoring tools and reporting standards. These include: (1) System

Average Interruption Frequency Index (SAIFI), a measure of the number of interruptions

per year for the average customer;32 (2) System Average Interruption Duration Index

(SAIDI), a measure of the total interruption time experienced by the average customer; 33

(3) Customer Average Interruption Duration Index (CAIDI), defined as the ratio of

SAIDIISAIFI; 34 ( 4) Distribution Interruption System (DIS), a database to capture

reliability performance and indices for individual feeders; 35 (5) Average System

Availability Index (ASAI)/ 6 a measure of the total time of service availability to the

average customer; and (6) TACTICS, which captures data on every device ~own to the

transformer level to measure each device's operational performance and impact on

customers. 37 In addition, the Company utilizes a System Control and Data Acquisition

device (SCADA) to measure data for large interruptions such as feeder breaker outages/ 8

and the new Automatic Mapping and Facilities Management System (AMJFM),

developed in order to determine where an outage occurred and what device caused it,

which will be completed by the year 2000. 39

General Counsel, Cities, and HLFCCG argued that the number of customers

affected by outages and the duration of such outages are difficult to determine because

32

HLFCCG Ex. 1, Patton Direct Testimony at 9-12.

33

Id. at 10.

34 !d.

3S .

!d. at 11.

36

General Counsel Ex. 3, Eckhoff Direct Testimony at 20.

37

Tr. at 448-450.

38

Tr. at 238, 443.

39

Tr. at 429-30.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 12

EGS excluded relevant information between 1994 and 1996.4° For example, for the first

six months of 1996, the Company reported 35 to 40 percent fewer outages than were

reported on average during the first six months of the years 1991-94.41 In trying to

explain the discrepancies in the data, Company officials described changing data

collection standards applied to the various outage-causing events. At different times, the

Company excluded outages caused by equipment failures; outages affecting feeders with

fewer than 500 customers; storms, generation or transmission outages; or trees falling

into the ROW ("non-preventable" trees). 42 The Company data is generally confusing

and comparisons over a period of several years are difficult to make because of changing

standards; 43 in addition, the inaccuracies are further compounded because, for example,

outages on feeders with fewer than 500 customers can nevertheless result in very long

outage durations, especially when those feeders are energized last. 44

The evidence shows that Company linemen sometimes made subjective

determinations as to the cause, duration, or effect of an outage, thus causing the

Company's SAIFI and SAID! numbers to be unreliable. 45 The evidence also revealed

46

that most historically deficient feeders serve rural customers. This observation is

supported by EGS' testimony that it prioritizes restoration of feeders serving the greatest

numbers of customers, thus leaving those in lower-density areas (most likely rural) to

47

experience recurring and longer service reliability problems.

40

See HLFCCG Ex. 2, Entergy Southwest Reliability Report 1.994-1996; Tr. at 41-43.

41

HLFCCG Ex. 3 at slide 9.

42

Tr. at 41-44, 54, 62-66.

43

Id; HLFCCG Ex. 2 at Bates Stamp 0232514.

44

Tr. at 67.

45

Tr. at 47-48.

46

Tr. at 707, 821

47

The Rebuttal (redacted) Testimony of Dereck Hasbrouck on behalf of the Company contains this quote:

"One important fact to keep in mind when considering a customer or group of customers who consistently

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 13

General Counsel, Cities, and HLFCCG asserted that the Company has

manipulated information to show better performance. 48 A significant problem with the

Company's use of performance and reliability indices is that they reflect outage

frequency and duration on a system-wide rather than feeder-by-feeder basis which can

mask poor performance of individual.feeders. 49 For example, EGS reported a syst_em-

wide SAIDI of 133 minutes for 1996,50 but this measure failed to reveal that 83 feeders or

primary circuits experienced outage times in excess of 200 minutes. 51 The average

customer on these circuits experienced an outage duration of 3.3 hours. 52 More notably,

customers on feeder Tamina encountered 41.3 hours of outage time in one year. 53 It is

apparent that system-wide averages used by the Company cannot be relied on to disclose

many of the localized service difficulties.

The historic data presented by the Company is not accurate and consistent as the

Company itself admitted to not collecting all relevant data, 54 changing the standards for

55

data collection, and submitting inconsistent data for ASAI and SAIFI. Even the

receive less reliable service than the average customer is that there are geographic and environmental

conditions beyond the utility's control. These conditions, in combination with the construction cost

considerations may effectively limit the realistic reliability expectations for customers in certain areas. In

EGS Texas' service territory, the Bolivar Peninsula and Sabine Pass may be examples where these

constraints come into play." EGS Ex. II, Hasbrouck Rebuttal Testimony at 39.

48

Tr. at 278-79, General Counsel Ex. 3, Eckhoff Direct Testimony at 54.

49

General Counsel Ex. 3, Eckhoff Direct Testimony at I8, Appendix Hand I; Tr. at 4I-67; HLFCCG Ex.

I, Patton Direct Testimony at I2-I4.

50

General Counsel says SAIDI in 1996 was I57 m~utes. General Counsel Ex. 22; HLFCCG Ex. I,

Patton Direct Testimony at 13.

51

HLFCCG Ex. I, Patton Direct Testimony at Exhibit ADP-3.

52 /d.

53

General Counsel Ex. 3, Eckhoff Direct Testimony, Appendix H..

54

Tr. at 706.

55

General Counsel Ex. 3, Eckhoff Direct Testimony at 54.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 14

Company's internal audit revealed that reporting of outages has not been consistent. 56

EGS cannot correctly measure how many individual customers lose service because of an

outage affecting parts of a feeder. 57

The Commission concludes that the types of information monitoring and

reporting tools relied on by the Company are useful, but they must be employed

uniformly and consistently to be meaningful measures of service quality. The

Commission finds that the level of EGS' service quality and reliability, as documented

through the Company data, is unreliable because the data fail to record and report all

events accurately and consistently. Pockets of inadequate service are ignored by system-

wide measures, and such measures do not identify recurring individual-feeder problems.

2. Vegetation Management

Vegetation management is the catch-all description for programs involving the

removal of trees, bushes, or vines that overhang, grow into, or toward conductors strung

along the Company's ROW. The purpose of vegetation management is to ensure, to the

greatest extent possible, that vegetation in, or near, the ROW does not come into contact

with the conductors and thereby cause wire breakage or ground faults. 58 During the

hearing, Company witnesses referred to scheduled tree trimming, carried out on a three-

year cycle in urban. areas and a six-year cycle in rural areas. The evidence presented,

however, was not clear on whether EGS actually followed the stated cycles. 59

Nonetheless, the Company argued that its vegetation management has been adequate and

56

Cities Ex. I, Lawton Direct Testiniony at 12.

51

Tr. at 445-46.

58

Tr. at 176-178.

59

Tr. at 602, 728.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 15

consistent with industry practice. 60 In fact, EGS asserted that it had improved vegetation

management and introduced efficiencies when compared to the pre-merger period. 61

General Counsel, Cities, and HLFCCG presented extensive evidence to document

serious neglect of vegetation management and consequent heightened risk to the

distribution system. The majority of incidents included in the evidence involve three

types of vegetation-related damage: wires expanding down into vegetation due to

increased load or lack of under-clearance; overhanging limbs breaking or growing into

wires in non-inclement weather; and limbs or trees bending or breaking onto wires due to

wind, ice build-up, or other adverse weather conditions. These parties also argued that

the ROW surveyed were in need of extensive clearing and that vegetation encroachments

posed unacceptable risks. 62 Cities claimed that neglected vegetation management

multiplied the severity of the ice storm in January 1997. 63 The number and duration of

64

vegetation-caused service interruptions almost doubled in the last four years, and

65

vegetation-related SAIDI and SAIFI have worsened since the merger.

The author of a vegetation management study, commissioned by the Company,

observed that there were areas where maintenance clearing had been deferred until brush

reached the conductors. 66 The study proposed specific and comprehensive ways for

60

EGS Ex. 10, Ervin Rebuttal Testimony at 55, 59. EGS states that more than 80 percent of the

Company's vegetation management expenditures are allocated to trimming, which is above the industry

norm.

61

EGS Ex. 8, Ervin Supplemental Direct at 22.

62

General Counsel Ex. 4, Gonzalez Direct Testimony at 6-8; General Counsel Ex. I, Ethridge Direct

Testimony at 8-11.

63

Tr. at 305-08.

64

HLFCCG Ex. I, Patton Direct Testimony, Exhibits ADP-10, ADP-13 (illustrating values for system-

wide SAID! for Texas increased from 21.17 in 1994 to 40.36 in 1997, and SAIFI doubled, from .31 in

1994 to .63 in 1997).

65

General Counsel Ex. 37.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 16

ROW maintenance, but the Company presented no evidence that the study's findings had

been implemented. An e-mail sent in August of 1997 by an EGS network manager in

Beaumont identified trees touching· conductors as one of the preventable root causes of

several recent outages. 67

The Commission concludes that the level of the Company's vegetation

management is unacceptable and has significantly affected the reliability of the

distribution system in recent years. While such a deficiency may not in itself impact a

typical system severely, this deficiency is magnified when the inadequacy of the

infrastructure and the nature of the weather in the Company's service area are taken into

account. 68 The lack of preventive vegetation control efforts, by the Company and neglect

of regular vegetation clearing have led to the creation of unnecessary risks. The

Commission does not suggest that "ground-to-sky" tree trimming is necessary, but the

Company clearly has significant room for improvement. The recent hiring of 30 new

vegetation clearance crews, while welcome, confirms the existence of an unacceptable

backlog in vegetation control. 69 As will be discussed below, the Commission is also

concerned that managers in Texas have no clear line of authority or resources necessary

to implement effective vegetation management policies.

66

General Counsel Ex. 27, Environmental Consultants, Inc., Report on Distribution Line Clearance

Program (Jul. 1994) at 1-2-3.

67

HLFCCG Ex. 6.

68

Tr. at 308.

69

Tr. at 730-31, 787.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 17

3. Emergency Preparedness, Response, Outage Restoration, and Treatment of

Storm Data

a. January 1997 Ice Storm

In mid-January 1997, many parts of Texas experienced a severe ice storm;

70

disruptions of electric service were sustained by most utilities in the state. The impact

on EGS' territory was particularly hard. At one time, up to 120,000 of EGS' customers

were without power and it took seven days to complete the restoration process. 71

Utilizing help from other utilities and contract workers, EGS had more than 2,700

personnel working to restore service. 72 In assessing the Company's performance, EGS

officials compared it to that of other utilities and concluded that its efforts were not only

adequate, but even "very good.'m They blamed most of the damage on excessive ice.74

This view was not shared by the other parties. 75 HLFCCG played excerpts from

taped conversations conducted by the Company's dispatchers during the storm, which

highlighted insufficient numbers of personnel and initially inadequate efforts to repair the

damage.76 The Cities asserted that they had to use their own employees for repairs,

including the handling of live wires, 77 and that in some instances they were unable to

reach Company employees at a11. 78 One of the Cities' exhibits was a letter, dated August

70

General Counsel Ex. 2B, Hughes Workpapers, Ice Storm '97 Field Investigations Project 16301 at 11-1.

71

EGS Ex. 8, Ervin Supplemental Direct Testimony at 53.

72 Jd.

73

Jd. at 74.

74

Id. at 74-75.

15

Tr. at 379; Cities Ex. 1, Lawton Direct Testimony at 12.

76

Tr. at 87-92.

77

Tr. at 376.

78

Cities Ex. 2, Kimler Direct Testimony at 2.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 18

17, 1995, from several fire chiefs in EGS' service territory to the Company describing

various problems with emergency procedures, such as not being able to reach the

Company's 1-800 telephone number, and, apparently, this problem persisted. 79 Some

other cities' representatives testified, however, that the Company's restoration efforts

were good. 80 The significant disparities in the Company's response to the qamage caused

by the ice storm suggest a need for greater and clearer communication between the

Company and all cities, including development of contacts before an emergency occurs.

The Company has an emergency plan on file with the Commission; the plan

contains no obvious deficiencies. 81 As is industry practice, EGS also has agreements

with other utilities for emergency cooperation; those agreements, however, are not in

writing. 82

The January 1997 ice storm was certainly a severe storm that would have

adversely affected even the best-maintained distribution system. EGS' distribution

system, however, is not the best-maintained. A major cause of the outages during the

storm were broken or bowed ice-laden tree limbs overhanging the wires. Tree limbs in

ROW overhanging distribution lines pose a threat to system reliability, and are largely

within EGS' control. The Company's failure to clear the limbs before the storm was a

83

major factor in the number and duration of outages experienced by customers. While

Company's initial efforts to mobilize and deploy additional non-EGS personnel were

slow and cause concern, 84 vegetation management failures greatly aggravated the

79

Cities Ex. 2, Kimler Direct Testimony at 7.

80

Tr. at 377, 381, 391.

81

General Counsel Ex. 2, Hughes Direct Testimony at 21.

82

Tr. at 676-77.

83

General Counsel Ex. 2, Hughes Direct Testimony at 17.

84

Tr. at 379.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page 19

situation. The Company has experienced major storms in 1994, 1995, and 1997. 85 The

weather, however, cannot be an excuse for poor service. While the Commission does not

expect 100 percent reliability, the system must be built and maintained taking the local

geographic and weather conditions into account.

b. Treatment of Storm Data

The Commission has required utilities to report the causes of interruptions,

including the extreme storms. EGS, however, excludes outage duration and frequency

data from its SAIDI and SAIFI reports if the data are attributable to a "major storm."86

As defined currently by the Commission, major storms include situations in which there

is a loss of power to 10 percent or more of customers in a region over a 24-hour period

and full restoration is not achieved within 24 hours. 87 EGS' definition of a major storm

counts any event in which 10 percent or more of a region's customers are interrupted for

88

24 hours or more, and is similar to the Commission's definition.

HLFCCG argued that interruptions associated with major storms should be

included in the computation of reliability indices. HLFCCG maintains that the design

and maintenance of lines, and therefore their condition under the stress of severe weather,

is within the control of the utility. 89 Exclusion of major-storm interruptions from

reliability indices could encourage reduced preventive maintenance, including vegetation

90

management, and reductions in force needed for restoration efforts.

8S

Tr. at214, 377.

86

Tr. at 54.

87

EGS Ex. 10, Ervin Rebuttal Testimony at 30.

88 /d.

89

HLFCCG Ex. 1, Patton Direct Testimony at 14.

90

/d. at 15.

PUC DOCKET NO. 18249 ORDER ON REHEARING Page20

The Commission is reluctant to allow the Company to exclude major-storm data

from its overall reports because such reports may be incorrectly perceived as an

indication that overall serv

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