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

5514728

THIRD COURT OF APPEALS

AUSTIN, TEXAS

6/2/2015 3:48:59 PM

JEFFREY D. KYLE

CLERK

No. 03-14-00735-CV

IN THE FILED IN

3rd COURT OF APPEALS

THIRD COURT OF APPEALS AUSTIN, TEXAS

AT AUSTIN, TEXAS 6/2/2015 3:48:59 PM

JEFFREY D. KYLE

Entergy Texas, Inc., et al., Clerk

Appellants

v.

Public Utility Commission of Texas, et al.,

Appellees

Appeal from the 353rd Judicial District Court, Travis County, Texas

The Honorable John K. Dietz, Judge Presiding

________________________________________________________________

ENTERGY TEXAS, INC.’S REPLY BRIEF

_________________________________________________________________

John F. Williams

State Bar No. 21554100

jwilliams@dwmrlaw.com

Marnie A. McCormick

State Bar No. 00794264

mmccormick@dwmrlaw.com

DUGGINS WREN MANN & ROMERO, LLP

600 Congress Ave., Ste. 1900 (78701)

P. O. Box 1149

Austin, Texas 78767-1149

(512) 744-9300

(512) 744-9399 fax

ATTORNEYS FOR APPELLANT

ENTERGY TEXAS, INC.

June 2015

ORAL ARGUMENT REQUESTED

TABLE OF CONTENTS

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

INDEX OF AUTHORITIES..................................................................................... ii

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

I.  There is no evidence or legal justification for the Commission’s

disallowance of over $11 million associated with ETI’s unrecovered

Hurricane Rita reconstruction costs.................................................................1

A.  Nothing in PURA required the Commission to address

amortization of the regulatory asset in Docket No. 37744. ..................1

B.  There is no evidence that anyone intended ETI to begin

amortizing the regulatory asset upon the settlement of Docket

No. 37744. .............................................................................................3

II.  The Commission’s refusal to make any adjustment to ETI’s test-year

level of purchased capacity expense is arbitrary and capricious and

unsupported by substantial evidence. ..............................................................7

A.  The Commission misapplied the standard for adjustments to

test-year expenses. .................................................................................8

B.  The Commission’s refusal to make any adjustment to test-year

levels of capacity costs is not supported by substantial

evidence. ..............................................................................................11

III.  The Commission’s decision to set ETI’s transmission equalization

expense at the test-year level is unsupported by substantial evidence. .........16

CONCLUSION AND PRAYER .............................................................................18

CERTIFICATE OF COMPLIANCE .......................................................................19

CERTIFICATE OF SERVICE ................................................................................20

APPENDIX ..............................................................................................................22

i

INDEX OF AUTHORITIES

Cases

AEP Texas Central Co. v. Public Util. Comm’n of Tex.,

286 S.W.3d 450 (Tex. App. – Corpus Christi 2008, pet. denied) .........................4

Bowden v. Phillips Petroleum Co.,

247 S.W.3d 690 (Tex. 2008) ..................................................................................8

City of El Paso v. Public Util. Comm’n of Tex.,

883 S.W.2d 179 (Tex. 1994) ..................................................................................9

Commint Technical Services, Inc. v. Quickel,

314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ........................4

Freedom Communications, Inc. v. Coronado,

372 S.W.3d 621 (Tex. 2012) ..................................................................................5

Hawkins v. Texas Co.,

209 S.W.2d 338 (Tex. 1948) ................................................................................18

Hendee v. Dewhurst,

228 S.W.3d 354 (Tex. App. -- Austin 2007, pet. denied) ......................................5

Katy Intern., Inc. v. Jinchun Jiang,

451 S.W.3d 74 (Tex. App. – Houston [14th Dist.] 2014, pet. requested) .............5

Office of Pub. Util. Counsel v. Public Util. Comm'n,

878 S.W.2d 598 (Tex. 1994) ..................................................................................5

Office of Pub. Util. Counsel v. Texas-New Mexico Power Co.,

344 S.W.3d 446 (Tex. App. – Austin 2011, pet. denied) ......................................4

Railroad Comm’n of Tex. v. High Plains Natural Gas Co.,

628 S.W.2d 753 (Tex. 1981) .................................................................................9

State of Texas’ Agencies & Institutions of Higher Learning v.

Public Util. Comm’n of Tex.,

450 S.W.3d 615 (Tex. App. – Austin 2014, pet. requested) .................................4

Suburban Util. Corp. v. Public Util. Comm’n of Tex.,

652 S.W.2d 358 (Tex. 1983) ....................................................................... 8, 9, 16

Texas Utils. Elec. Co. v. Public Util. Comm’n,

881 S.W.2d 387 (Tex. App. – Austin 1994),

rev’d on other grounds, 935 S.W.2d 109 (Tex. 1996) .................................. 15, 18

ii

Vickers v. State,

No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11

(Tex. App. – Texarkana Apr. 27, 2015, no pet. h.) ................................................5

Woods v. William M. Mercer, Inc.,

769 S.W.2d 515 (Tex. 1988) ..................................................................................4

Statutes

Tex. Gov’t Code Ann. § 2001.174...................................................................... 8, 18

Tex. Util. Code Ann. § 11.001, et seq. ......................................................................1

Tex. Util. Code Ann. § 11.002 .................................................................................10

Tex. Util. Code Ann. § 36.051 ...................................................................................9

Tex. Util. Code Ann. § 39.459 ...............................................................................2, 3

Tex. Util. Code Ann. § 39.462 ...............................................................................2, 3

Rules

16 Tex. Admin. Code § 25.231 ........................................................................... 9, 10

Tex. R. Civ. P. 94 .......................................................................................................4

Tex. R. Evid. 201 .......................................................................................................5

Administrative Cases

Application of Entergy Gulf States, Inc. for Determination of

Hurricane Reconstruction Costs, Docket No. 32907.............................................7

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

Reconcile Fuel Costs, Docket No. 37744 .........................................................5, 6

iii

Appellant Entergy Texas, Inc. (“ETI”) respectfully submits this reply to the

appellees’ briefs of the Public Utility Commission of Texas (“the Commission” or

“PUCT”) and Texas Industrial Energy Consumers (“TIEC”).

ARGUMENT AND AUTHORITIES

I. There is no evidence or legal justification for the Commission’s

disallowance of over $11 million associated with ETI’s unrecovered

Hurricane Rita reconstruction costs.

ETI challenges the Commission’s decision to allow it to amortize only $15

million of its Hurricane Rita regulatory asset. That is about $11 million less than

ETI proved it is entitled to but has not recovered. The Commission, the only party

to address this issue in its response brief, does not present any persuasive argument

for upholding its decision.

A. Nothing in PURA1 required the Commission to address

amortization of the regulatory asset in Docket No. 37744.

One of the rationales the Commission gave in support of its decision was its

view that PURA section 39.459(c) required ETI’s unrecovered Hurricane Rita

reconstruction costs to be addressed in a previous case, Docket No. 37744.2 As

explained in ETI’s appellant’s brief, section 39.459(c) does not apply to the

situation at hand. That provision addresses what should happen when a utility

securitizes hurricane reconstruction costs and then recovers them a second time

1

See Tex. Util. Code Ann. § 11.001, et seq. (“Public Utility Regulatory Act” or “PURA”).

2

AR Part I, Binder 5, Item 185 (Proposal for Decision at 15 & 21-22); AR Part I, Binder 7, Item

244 (Order on Rehearing at 1).

1

from an insurance company. See Tex. Util. Code Ann. § 39.459(c). Here, neither

of those things happened. A different statute, PURA section 39.462(a), applies in

this situation. That provision authorizes a utility to seek unrecovered hurricane

reconstruction costs “in its next base rate proceeding or through any other

proceeding authorized by Subchapter C, Chapter 36.” Id. § 39.462(a) (emphasis

added). It is undisputed that this case is authorized by Chapter 36.

The Commission now tacitly acknowledges that section 39.462(a) applies,

but still argues that the issue was statutorily required to be addressed in Docket No.

37744.3 The Commission contends that even under section 39.462(a), it was

required to address the issue in Docket No. 37744 because that was the “next”

base-rate proceeding after ETI knew it would not receive the anticipated insurance

proceeds.4 That statute says no such thing. Indeed, section 39.462(a) broadly

authorizes the Commission to address the issue in “any” proceeding authorized by

Chapter 36. This reflects the legislature’s understanding of the fact that it is often

difficult or impossible for a utility to know when multiple, large insurance claims

or government grants will be paid in full. Under the plain language of PURA

section 39.462(a), the Commission had authority to address the issue in this case.

Moreover, the Commission is flat wrong that Docket No. 37744 was the first

base rate case after ETI “knew” what insurance proceeds it would recover. It is

3

PUCT’s Appellee’s Brief at 16-17.

4

See id. at 18.

2

true that ETI had not recovered these insurance proceeds when it initiated Docket

No. 37744. But it is undisputed that ETI ended up receiving another $5 million in

insurance proceeds after Docket No. 37744, and ETI adjusted its regulatory asset

to account for this fact.5 Even under the Commission’s erroneous interpretation

of PURA sections 39.459(c) and 39.462(a), then, the Commission was not limited

to addressing the issue of hurricane reconstruction costs in Docket No. 37744.

B. There is no evidence that anyone intended ETI to begin

amortizing the regulatory asset upon the settlement of

Docket No. 37744.

The second rationale the Commission gave for its order was its conclusion

that ETI did not disprove that the issue was resolved in Docket No. 37744.6 That

was not, however, ETI’s burden. ETI affirmatively established that it had not yet

included the unrecovered insurance proceeds in its rate base, or begun recovering

them, when it filed this case.7 Intervening parties responded by arguing that ETI

should already have either written off or begun amortizing the Hurricane Rita

regulatory asset upon the conclusion of Docket No. 37744.8 In other words,

intervenors argued that Docket No. 37744 barred ETI from seeking permission to

amortize the full amount of the asset in this rate case. Intervenors, not ETI, bore

5

AR Part II, Binder 37, ETI Exh. 46 (Considine Rebuttal at 18 of 55).

6

AR Part I, Binder 5, Item 185 (Proposal for Decision at 22); AR Part I, Binder 7, Item 244

(Order on Rehearing at 1).

7

AR Part II, Binder 32, ETI Exh. 8 (Considine Direct at 20).

8

E.g., AR Part II, Binder 40, Staff Exh. 1 (Givens Direct at 32-35); AR Part II, Binder 8, Cities

Exh. 2 (Garrett Direct at 11).

3

the burden of proof on this affirmative defense. E.g., Tex. R. Civ. P. 94; Woods v.

William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex. 1988); Commint Technical

Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex. App. – Houston [14th Dist.]

2010, no pet.).

Regardless of who bore the burden of proof, the Commission is bound to

interpret a settlement and an order adopting it in accordance with the rules of

contract interpretation. See AEP Texas Central Co. v. Public Util. Comm’n of Tex.,

286 S.W.3d 450, 464 (Tex. App. – Corpus Christi 2008, pet. denied). The

Commission cannot use the opportunity to interpret its prior order as a means to

amend it. E.g., Office of Public Util. Counsel v. Texas-New Mexico Power Co.,

344 S.W.3d 446, 452 (Tex. App. – Austin 2011, pet. denied). Under the rules of

contract interpretation, the primary duty of the Commission is to determine and

give effect to the parties’ intentions as expressed in the document. AEP Tex. Cent.

Co., 286 S.W.3d at 464.

The Docket No. 37744 order does not say anything about the Hurricane Rita

regulatory asset, and the Commission does not pretend that it does. Nor does the

Commission dispute that a utility must have a regulator’s authority to begin

recovering a regulatory asset. See, e.g., State of Texas’ Agencies & Institutions of

Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App.

– Austin 2014, pet. requested) (recovery of regulatory asset is two-step process, the

4

second step being the authorization of a recovery mechanism). The Commission

nevertheless argues that the amortization of the Hurricane Rita regulatory asset

should have been “considered” approved in Docket No. 37744 because the order in

that case was “ambiguous,” and there is substantial evidence that no one in that

case disputed that ETI should get to recover the regulatory asset.

The Commission is correct that there is evidence in this case that no one in

Docket No. 37744 contested ETI’s right to recover the Hurricane Rita regulatory

asset at some point in time. However, there was a dispute in Docket No. 37744

about when and how ETI could recover the regulatory asset. Cities’ witness Jacob

Pous testified in Docket No. 37744 that ETI should not be able to amortize the

regulatory asset over a five-year period, and should credit the amount to its storm

reserve instead.9 No witness in this case testified about, much less controverted,

that fact. In short, no witness to this case said the parties to Docket No. 37744

agreed that ETI should begin amortizing the regulatory asset when the case was

9

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

Docket No. 37744 (Pous Direct at 113). A certified copy of Mr. Pous’s testimony is attached to

this brief at Appendix A. ETI does not present this document in support of the truth of its

content. ETI presents the document only to establish that it was filed, and the nature of the

matter the witness discussed, in the prior docket. This document was filed with the Commission,

a state agency. It is publicly available, and its authenticity is readily verifiable. This Court can,

therefore, take judicial notice of the document for the limited purpose ETI presents it. Tex. R.

Evid. 201(b); Freedom Communications, Inc. v. Coronado, 372 S.W.3d 621, 623 (Tex. 2012);

Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d 598, 600 (Tex. 1994); Vickers

v. State, No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11 (Tex. App. – Texarkana Apr. 27,

2015, no pet. h.); Katy Intern., Inc. v. Jinchun Jiang, 451 S.W.3d 74, 94 n.20 (Tex. App. –

Houston [14th Dist.] 2014, pet. requested); Hendee v. Dewhurst, 228 S.W.3d 354, 377 n.30 (Tex.

App. -- Austin 2007, pet. denied).

5

settled. Nevertheless, the Commission concluded in this case that ETI should have

done that. There is no testimony supporting the Commission’s conclusion.

The only evidence in this case of what the parties intended when they settled

Docket No. 37744 is the settlement agreement itself. Though the settlement

agreement expressly mentioned several issues in the case, it said nothing about

ETI’s request to amortize the Hurricane Rita regulatory asset. The agreement

certainly gave no indication that the parties intended ETI to begin recovering the

regulatory asset immediately. The agreement did, however, say, “[e]xcept to the

extent that the Stipulation expressly governs a Signatory’s rights and obligations

for future periods, this Stipulation shall not be binding or precedential upon a

Signatory outside this docket, and Signatories retain their rights to pursue relief to

which they may be entitled in other proceedings.”10

Despite that language in the agreement, the Commission maintains that the

Mother Hubbard clause in the order adopting the settlement supports its decision in

this case.11 The order says that “any … requests for general or specific relief, if not

expressly granted in this order, are hereby denied.”12 It is undisputed that neither

10

Id. (Aug. 6, 2010 Stipulation and Settlement Agreement at 12) (emphasis added).

11

PUCT’s Appellee’s Brief at 21.

12

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

Docket No. 37744 (Dec. 13, 2010, Order at ¶ 15). Public filings in Commission dockets may be

accessed at the Commission’s interchange:

http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp

The “Control Number” for each case is its docket number.

6

the settlement agreement nor the order expressly granted ETI the authority to begin

amortizing the Hurricane Rita regulatory asset.13

In light of this language in the Docket No. 37744 order and the fact that

recovery of a regulatory asset requires express agency approval, it would have

been unreasonable for ETI to begin amortizing the asset upon the conclusion of

Docket No. 37744. The factual basis for the Commission’s contrary conclusion in

this case is not supported by substantial evidence. And there is no legal

justification – articulated in the Commission’s order or not – supporting what the

Commission did here. Because there is no evidence or law supporting the

Commission’s decision, it is not entitled to any deference and should be reversed.

II. The Commission’s refusal to make any adjustment to ETI’s test-year

level of purchased capacity expense is arbitrary and capricious and

unsupported by substantial evidence.

In its initial brief, ETI challenged the Commission’s refusal to include in

rates any of the increase in purchased capacity expense ETI proved it would incur

by the time rates went into effect. Neither the Commission nor TIEC presents any

13

The Attorney General makes a cryptic argument on page 21 of its brief, suggesting that ETI

cannot logically argue that “only one part of its request could have been approved” in Docket

No. 37744. See PUCT’s Appellee’s Brief at 21. ETI does not contend that the Commission

approved anything regarding the Hurricane Rita regulatory asset in Docket No. 37744. The

Commission approved ETI’s creation of the regulatory asset in Docket No. 32907 when it

recognized ETI’s future right to true-up its anticipated insurance recovery. See Application of

Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No.

32907 (Dec. 1, 2006, Order at FOF 28). ETI sought approval of a recovery mechanism in

Docket No. 37744. ETI’s point here is that the Commission did not even mention the Hurricane

Rita regulatory asset, much less approve an amortization schedule for the asset, in its Docket No.

37744 order.

7

logical basis upon which to disallow the entire $30 million increase in expenses at

issue.

A. The Commission misapplied the standard for adjustments

to test-year expenses.

The Commission took the view that only ETI’s test-year level of purchased

capacity expense should be included in rates because acknowledging known and

measurable changes to test-year data is an “exception.”14 ETI challenged that view

as contrary to PURA and judicial precedent.

In response, the Commission and TIEC point out that the Commission may

exercise “discretion” in determining what changes to make to test-year levels of

expense. That does not mean, however, that the Commission has carte blanche to

do whatever it wants. Even when it exercises discretion, the Commission must

adhere to some guiding principles. See, e.g., Tex. Gov’t Code Ann. § 2001.174(2)

(agency order reversible for abuse of discretion); Bowden v. Phillips Petroleum

Co., 247 S.W.3d 690, 696 (Tex. 2008) (failure to adhere to any guiding principles

constitutes abuse of discretion).

One of those principles is that rates are set prospectively. E.g., Suburban

Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex. 1983).

Another is that a utility is entitled to a reasonable opportunity to recover all of the

14

AR Part I, Binder 7, Item 244 (Order on Rehearing at 1); AR Part I, Binder 5, Item 185

(Proposal for Decision at 108).

8

reasonable and necessary expenses it incurs when the rates are in effect. See Tex.

Util. Code Ann. § 36.051; Railroad Comm’n of Tex. v. High Plains Natural Gas

Co., 628 S.W.2d 753 (Tex. 1981). PURA provides no support for giving test-year

data more weight than rate-year data in the process of setting rates. PURA does

not even impose the test-year construct – that is a Commission-made ratemaking

convention. Compare Tex. Util. Code Ann. § 36.051 with 16 Tex. Admin. Code

§ 25.231(a). And the Texas Supreme Court has acknowledged that the goal of the

process is to make the test-year data as representative as possible of the cost

situation that is apt to prevail in the future, not the past. City of El Paso v. Public

Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994). Costs that can be

anticipated with reasonable (not absolute) certainty should be included. See

Suburban Util. Corp., 652 S.W.2d at 362.

TIEC and the Commission acknowledge this is the standard. But they argue

the Commission’s order should be upheld because ETI could not predict its rate-

year costs with surgical precision. That cannot be a basis upon which to disallow

the entire adjustment. Without a crystal ball, it is impossible to know future costs

to the dollar. The Commission may not disregard compelling evidence of

substantial increases to test-year levels of expense simply because there may be

some level of uncertainty at the margin.

9

TIEC argues that projections of future expenses should be treated as

inherently suspect because there is a risk the projections will end up being too

high. TIEC fails to note that placing undue emphasis on test-year data imposes the

opposite risk – that rates will end up being too low. The Commission is charged

with setting rates that are just and reasonable for both consumers and utilities.

Tex. Util. Code Ann. § 11.002(a).

Contrary to TIEC’s assertions, ETI does not, in this appeal, seek to overturn

the Commission’s test-year approach to ratemaking. See 16 Tex. Admin. Code

§ 25.231(a). ETI simply seeks to hold the Commission to PURA’s basic guarantee

to utilities. To give effect to that guarantee, historical test-year data can only be

the starting place for setting rates. Because rates are set on a prospective basis,

evidence of known and measurable changes to test-year data must be given at least

equal weight to the test-year data itself. It cannot logically be treated with

suspicion or as an “exception” that is subject to a heightened proof requirement.

The Commission itself acknowledges this principle in other contexts. The

Commission made adjustments to other categories of ETI’s test-year expense, even

though those adjustments were based upon projections and estimates.15 If the

Commission is to allow post-test-year changes based upon projections in one

15

E.g., AR Part I, Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-

64 (payroll adjustments), & 182-86 (ad valorem tax rate update)).

10

situation, it must allow them in another. It is an abuse of discretion to apply

different standards in materially analogous circumstances.

B. The Commission’s refusal to make any adjustment to test-

year levels of capacity costs is not supported by substantial

evidence.

ETI showed that during the time rates would be in effect, it would incur over

$38 million annually above its test-year level of purchased capacity expense. ETI

showed that by procuring these third-party resources, it would save about $8

million annually in payments related to Entergy system resources. Accordingly,

ETI requested the Commission to include the net $30 million increase over its test-

year levels of purchased capacity expense in rates.

The Commission and TIEC argue the Commission was justified in denying

this request for several reasons. First, the Commission says ETI merely “believes”

its contracts will be in place during the rate year.16 But ETI proved that all the

third-party capacity contracts were executed before the hearing.17 Indeed, one of

them went into effect during the test year,18 and another went into effect five

months after the test-year end and several months before the hearing in this case.19

16

See PUCT’s Appellee’s Brief at 33.

17

E.g., AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (Frontier contract); AR Part

II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (SRMPA contract); AR Part II, Binder 35,

ETI Exh. 34 (Cooper Direct at 16 of 25) (regarding Calpine contract).

18

AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (regarding Frontier contract).

19

AR Part II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (regarding SRMPA contract).

11

The Commission and TIEC also argue that ETI simply “assumed” it would

have to pay for all the third-party resources it had contracted for. That is

affirmatively debunked by the record. ETI’s expectation that any adjustments for

poor performance under the Frontier contract would be minor was based upon its

past experience with the Frontier resource.20 ETI also proved that its agreement

with SRMPA was for “system capacity.”21 Even if one of SRMPA’s resources

were to falter, there is no evidence supporting the conclusion that SRMPA’s entire

system might become unavailable. ETI further proved that it had experience with

the Calpine resource, and that price deviations under that contract were “very, very

small” in ETI’s experience.22 ETI took its historical experience into account when

projecting future costs, and did not blindly assume what they would be under these

contracts.

The Commission and TIEC also contend that there are multiple “offsets”

that would negate any additional expense ETI will incur under the new third-party

purchased capacity contracts. As ETI pointed out in its appellant’s brief, none of

these offsets justifies a complete disallowance of ETI’s entire capital outlay for the

contracts at issue.

20

AR Part IV, Binder 43, Vol. F (4/26/12 Tr. at 705).

21

AR Part II, Binder 31, ETI Exh. 3A (SRMPA Power Contract) [Highly Sensitive].

22

AR Part IV, Binder 42, Vol. L (5/3/12 Tr. at 1942).

12

Both the Commission and TIEC contend that future load growth may offset

some of ETI’s increased purchased capacity expense. Even if the Commission

could properly consider future load growth in setting base rates, ETI made the

additional third-party capacity purchases to serve existing load,23 and existing

customers would recoup substantial savings from increased efficiencies and fuel

savings that would result from the purchases.24 Moreover, intervenors’ load

growth projections would not fully materialize until the rate year,25 but ETI began

incurring the additional purchased capacity costs during and shortly after the test

year. The prospect of load growth in ETI’s service area cannot logically offset the

immediate increase in purchased capacity expense at issue.

The Commission and TIEC also attempt to cast doubt upon ETI’s evidence

about how much the increased third-party capacity purchases enable ETI to avoid

in MSS-1 costs.26 But TIEC’s own witness admitted the inverse relationship

between the two categories of cost.27 Indeed, the record establishes that MSS-1

costs reached test-year lows during the last two months of the test year, when the

23

AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 5-7); see also AR Part II, Binder 37

(ETI Exh. 57, May Rebuttal at 13-15).

24

AR Part II, Binder 35 (ETI Exh. 34, Cooper Direct at 24 of 25).

25

AR Part IV, Binder 43, Vol. J (5/1/12 Tr. at 1299-1300) [Highly Sensitive].

26

As explained in ETI’s appellant’s brief, Schedule MSS-1 to the Entergy System Agreement

requires the various Entergy operating companies to make and receive payments according to

their relative share of total system capacity. See AR Part II, Binder 37, ETI Exh. 47 (Cooper

Rebuttal at 5-6).

27

AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 22, Table 1).

13

Frontier contract was stepped up.28 And another intervenor, Cities, adopted ETI’s

calculation of rate-year MSS-1 costs.29

Finally, the MSS-430 calculation is not a basis upon which to disallow all of

ETI’s increased third-party purchased capacity costs. The Commission itself

acknowledged that, save for costs associated with ETI’s contract with its Arkansas

affiliate, MSS-4 costs would remain “fairly stable” from the test year to the rate

year.31 Regarding the Arkansas contract (referred to by the parties as the Entergy

Arkansas, “EAI” or “EA” “WBL” contract), Cities’ and TIEC’s proposed

adjustments are not reasonably supported by the record. The evidence shows that

although the contract expired after the test year, ETI had extended the contract by

the time the hearing took place.32 Additionally, it is not reasonable to conclude

that if the Arkansas contract were not in place, ETI would not replace it with

another resource, since it is undisputed that ETI needed the capacity.33

In a nutshell, the Commission and TIEC argue that because there is “some

uncertainty” in these projections, it was inappropriate to make any adjustment. But

28

See AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct Attachment KJN-3 at 2) [Highly

Sensitive].

29

AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct at 17 [Highly Sensitive]).

30

As explained in ETI’s initial brief, Schedule MSS-4 to the Entergy System Agreement

contains a formula that sets the price of power purchased from specific units owned by other

Entergy operating companies. See AR Part II, Binder 36, ETI Exh. 39 (Cicio Direct at 24-26).

31

AR Part I, Binder 5, Item 185 (Proposal for Decision at 100); AR Part I, Binder 7, Item 244

(Order on Rehearing at 1).

32

AR Part IV, Binder 43, Vol. E (4/26/12 Tr. at 687-88 [Confidential]) .

33

See AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 15-16 of 21).

14

this Court long ago rejected the notion that when some of a utility’s proposal is

challenged, the entire proposal must be rejected unless the utility itself quantifies

the challenged piece. See Texas Utils. Elec. Co. v. Public Util. Comm’n, 881

S.W.2d 387, 404 (Tex. App. – Austin 1994), rev’d on other grounds, 935 S.W.2d

109 (Tex. 1996). This Court recognized that when the evidence conflicts about

how much of a proposal to include, it is the Commission’s job to sift through the

evidence and make the call. The Commission may not just throw its hands in the

air and refuse to address the issue simply because the utility’s evidence is contested

or because the issues are complex. See id. at 404-05.

TIEC cites the testimony of witnesses who recommended that the

Commission adopt a level of purchased capacity expense below the test-year level,

and suggests this testimony alone supports the Commission’s decision.34 But each

piece of testimony TIEC cites is based upon multiple “offsets” to ETI’s increased

level of expense. Each of these proposed offsets are flawed, as explained in ETI’s

appellant’s brief and above. Moreover, even assuming arguendo one of the offsets

were sustainable, no single offset justifies the entire disallowance. For both these

reasons, it is not reasonable to conclude from the evidence in this record that none

of ETI’s $30 million increase in third-party capacity costs were known and

measurable. The Commission did not even suggest that any single finding justifies

34

See TIEC’s Appellee’s Brief at 33.

15

the entire disallowance, or how much of the disallowance is attributed to each of its

findings. Therefore, if this Court determines that any of the Commission’s

findings are unsupported by substantial evidence, it must reverse the whole

disallowance and remand to the Commission for further consideration.

III. The Commission’s decision to set ETI’s transmission equalization

expense at the test-year level is unsupported by substantial evidence.

ETI challenges the Commission’s decision to set ETI’s MSS-2 (that is,

transmission equalization) expense at the test-year level for two reasons. First, the

Commission misapplied the “known and measurable” ratemaking standard, as it

did in setting ETI’s purchased capacity costs. Second, the Commission’s decision

is not supported by substantial evidence. The Commission and TIEC filed

responses. They devote their entire argument on this issue to attacking ETI’s

evidence supporting its request to include its rate-year level, rather than test-year

level, of MSS-2 expense in rates.

The issue before the Court, however, is whether there is substantial evidence

supporting the Commission’s conclusion that the test-year MSS-2 expense was the

level the utility “anticipated with reasonable certainty.” Suburban Util. Corp., 652

S.W.2d at 362. Clearly, this is not the case; there is no evidence that the test year

level allowed by the Commission is adequate or representative of the expense the

utility will incur when rates are in effect. All the evidence is to the contrary.

16

As ETI noted in its initial brief, no witness testified that the test-year level of

expense was a fair or reasonable representation of what ETI would incur under

Schedule MSS-2 when these rates would be in effect. Though they proposed

different levels of increase, every witness testifying on this issue – including ETI’s,

TIEC’s, and Cities’ – recognized that the test-year amount of MSS-2 expense was

too small and should be updated based on more recent, actual payment

information. 35 Moreover, ETI established that the actual, historical level of MSS-2

expense it incurred, in every month from the end of the test year to the time of the

hearing, pointed to a substantially increasing, known and measurable level of

expense. 36 TIEC now wholly ignores its own witness’s testimony on this issue,

choosing instead to focus exclusively on its criticisms of ETI’s evidence. Even

assuming arguendo that there is reasonable disagreement about ETI’s proposed

rate-year level of MSS-2 expense, the record conclusively establishes that the test-

year level is not adequate. In this circumstance, the Commission may not blindly

adhere to its test-year convention. There is literally no evidence to support the

Commission’s decision.

The Commission is bound to consider all the record evidence and reach a

conclusion that is reasonably supported by it. See Hawkins v. Texas Co., 209

35

AR Part IV, Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Part IV, Binder 43, Vol. F (4/27/12

Tr. at 738, 760, 763, 780, & 783-84); AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 32-

33); AR Part II, Binder 8, Cities Exh. 4B (Goins Direct, Errata No. 3 at 9 [Highly Sensitive]);

AR Part II, Binder 8, Cities Exh. 4 (Goins Direct at 22).

36

AR Part II, Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI-5-1).

17

S.W.2d 338, 339-40 (Tex. 1948); Texas Utils. Elec. Co., 881 S.W.2d at 404. The

APA confirms this principle, requiring a court to reverse the agency if its decision

is “not reasonably supported by substantial evidence considering the reliable and

probative evidence in the record as a whole.” Tex. Gov’t Code Ann.

§ 2001.174(2)(E) (emphasis added). Because the Commission’s decision is not

supported by any evidence, much less reasonably supported by the evidence, the

Court must reverse it.

CONCLUSION AND PRAYER

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

reverse the district court’s judgment insofar as it affirms the Public Utility

Commission’s order in the respects discussed above. ETI requests the Court

remand the case to the Commission for further proceedings consistent with the

Court’s decision. Entergy Texas, Inc. further requests its costs of court and any

other relief to which it may show itself justly entitled.

18

Respectfully submitted,

/s/ Marnie A. McCormick

John F. Williams

State Bar No. 21554100

Marnie A. McCormick

State Bar No. 00794264

mmccormick@dwmrlaw.com

DUGGINS WREN MANN & ROMERO, LLP

P. O. Box 1149

Austin, Texas 78767-1149

(512) 744-9300

(512) 744-9399 fax

ATTORNEYS FOR APPELLANT

ENTERGY TEXAS, INC.

CERTIFICATE OF COMPLIANCE

I certify that this document contains 4,727 words in the portions of the

document that are subject to the word limits of Texas Rule of Appellate Procedure

9.4(i), as measured by the undersigned’s word-processing software.

/s/ Marnie A. McCormick

Marnie A. McCormick

19

CERTIFICATE OF SERVICE

The undersigned counsel certifies that the foregoing document was

electronically filed with the Clerk of the Court using the electronic case filing

system of the Court, and that a true and correct copy was served on the following

lead counsel for all parties via electronic service on the 2nd day of June, 2015:

Elizabeth R. B. Sterling

Environmental Protection Division

Office of the Attorney General

P. O. Box 12548 (MC 066)

Austin TX 78711-2548

Counsel for Appellee Public Utility Commission of Texas

Rex D. VanMiddlesworth

Benjamin Hallmark

Thompson Knight LLP

98 San Jacinto Blvd., Ste. 1900

Austin TX 78701

Counsel for Intervenor Texas Industrial Energy Consumers

Susan M. Kelley (retired)37

Administrative Law Division

Office of the Attorney General

P. O. Box 12548

Austin TX 78711-2548

Counsel for Intervenor State Agencies

Sara Ferris

Office of Public Utility Counsel

1701 N. Congress Ave., Ste. 9-180

P. O. Box 12397

Austin TX 78711-2397

Counsel for Intervenor Office of Public Utility Counsel

37

State Agencies have not yet appeared or designated a new lead counsel in this appeal.

20

Daniel J. Lawton

LAWTON LAW FIRM PC

12600 Hill Country Blvd., Ste. R-275

Austin TX 78738

Counsel for Cities of Anahuac, et al.

/s/ Marnie A. McCormick

Marnie A. McCormick

21

APPENDIX

A. Certified copy of Direct Testimony of J. Pous in PUCT Docket No. 37744

22

APPENDIX A

SOAH DOCKET NO. XXX-XX-XXXX

PUC DOCKET NO. 37744

'I II

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE

INC. FOR AUTHORITY TO CHANGE § OF

RATES AND RECONCILE FUEL COSTS § ADMINISTRATIVE HEARINGS

Ii

DIRECT TESTIMONY AND EXIDBITS

OF

JACOBPOUS

ON BEHALF OF

I

CERTAIN CITIES SERVED BY ENTERGY TEXAS, INC.

CBRTIPIBD TO BS ATRUE AND CORRSCT

COPY OF THE OIUOINAL ON FH..E WITH THE

PUBLIC UTILITY COMMISSION OF TEXAS

JUNE9,2010

c~~'~.

:*t:3';•

Diversified Utility Consultants Inc.

1912 West Anderson Lane, Suite 202

Austin, TX 78757

Record copY

·-

UL \ 3 'l.0\6

Cities Exhibit , 'K.'f

·-·

,I '

TABLE OF CONTENTS

SECTION I: INTRODUCTION .................................................................................................... 1

SECTION II: DEPRECIATION ..................................................................................................... 7

1. General ........................................................................................................................................ 7

2. Production Life ........................................................................................................................... 11

A. General ................................................................................................................................... 11

B. Basis for Retirement Dates ..................................................................................................... 14

C. Recommendation .................................................................................................................... 21

3. Production Interim Retirements .................................................................................................. 22

4. Production Net Salvage ............................................................................................................... 26

5. Mass Property Life .................................................................................................................. 38

A. Introduction ........................................................................................................................... 38

B. Account Specific Adjustments .............................................................................................. 43

6. Mass Property Net Salvage ......................................................................................................... 71

7. ELG vs. ALG Calculation Procedure ......................................................................................... 76

8. Remaining Life Method .............................................................................................................. 86

SECTION III: FULLY ACCRUED DEPRECIATION ................................................................. 89

SECTION IV: SGSF CAPITAL RECOVERY .............................................................................. 93

SECTIONV: STORM INSURANCE RESERVE ...................................................................... 102

1. General .................................................................................................................................... I 02

2. Storm Reserve Deficit ............................................................................................................. 105

3. Target Reserve ........................................................................................................................ 114

4. Annual Expected Losses ......................................................................................................... 117

I 5. Minimum Storm Reserve Threshold ....................................................................................... 120

SECTION VI: CASH WORKING CAPITAL ................................................................................. 123

I I

1. Introduction ............................................................................................................................. 123

2. General .................................................................................................................................... 125

3. Revenue Lag ............................................................................................................................. 127

A. Meter Reading To Billing ................................................................................................... 127

B. Billing-To-Payment Revenue Lag ...................................................................................... 130

C. Customer Float .................................................................................................................... 135

4. Expense Leads .......................................................................................................................... 136

A. Payroll .................................................................................................................................. 136

B. FAS 106 .............................................................................................................................. 139

C. Entergy Services Inc. ("ESI") Expense Lead ..................................................................... 141

D. Other O&M Expense Lead ................................................................................................. 142

SECTION VII: RIVER BEND DECOMMISSIONING REVENUE REQUIREMENT .............. 144

SECTION VIII: RIVER BEND DEPRECIATION RATES ........................................................... 149

2

ACRONYMS:

2008 Study 2008 Gannett Fleming Depreciation Study

AICPA American Institute of Certified Public Accountants

ALG Average Life Group

APFD Accumulated Provision for Depreciation

ASL Average Service Life

CIS Consumer Information Systems

Company Entergy Texas, Inc.

Commission Public Utility Commission of Texas

CPI Consumer Price Index

ewe Cash Working Capital

DUCI Diversified Utility Consultants, Inc

EIA U.S. Energy Information Administration

EAi Entergy Arkansas, Inc.

EGSL Entergy Gulf States Louisiana

ELG Equal Life Group

ESI Entergy Services, Inc.

ETI Entergy Texas, Inc.

FERC Federal Energy Regulatory Commission

FPL Florida Power & Light Company

FPSC Florida Public Service Commission

MPSC Michigan Public Service Commission

NARUC National Association of Regulatory Utility Commissioners

NIMB "not in my backyard" syndrome

NPC Nevada Power Company

NPSC Nevada Public Service Commission

NRC Nuclear Regulatory Commission

O&M Operation & Maintenance

occ Oklahoma Corporation Commission

OLT Observed Life Table

PSO Public Service of Oklahoma

PUC Public Utility Commission of Texas

RCT Railroad Commission of Texas

1

Reserve Accumulated Provision for Depreciation

SGSF Spindletop Gas Storage Facility

SGT Sabine Gas Transportation Company

SRP Strategic Resource Plan

SWEPCO Southwest Electric Power Company

USOA FERC Uniform System of Accounts

2

Docket No. 37744

APPLICATION OF ENTERGY TEXAS § BEFORE THE

INC. FOR AUTHORITY TO CHANGE § PUBLIC UTILITY

RATES & RECONCILE FUEL COSTS § COMMISSION OF TEXAS

SECTION I: INTRODUCTION

1 Q. PLEASE STATE YOUR NAME AND BUSINESS?

2 A. My name is Jacob Pous and my business address is 1912 W. Anderson Lane, Suite 202,

3 Austin, Texas 78757.

4

5 Q. WHAT IS YOUR OCCUPATION?

6 A. I am a principal in the firm of Diversified Utility Consultants, Inc. ("DUCI"). A copy of

7 my qualifications appears as Appendix A.

8

9 Q. HAVE YOU PREVIOUSLY TESTIFIED IN PUBLIC UTILITY PROCEEDINGS?

10 A. Yes. Appendix A also includes a list of proceedings in which I have previously presented

11 testimony. In addition, I have been involved in numerous utility rate proceedings that

12 resulted in settlements before testimony was filed. In total, I have participated in well

13 over 400 utility rate proceedings in the United States and Canada.

14

15 Q. WHAT IS YOUR PROFESSIONAL BACKGROUND?

16 A. I am a registered professional engineer. I am registered to practice as a Professional

17 Engineer in the State of Texas, as well as numerous other states.

18

19 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?

20 A. I am testifying on behalf of the cities of Anahuac, Beaumont, Bridge City, Cleveland,

21 Conroe, Houston, Huntsville, Montgomery, Navasota, Oak Ridge North, Pine Forest,

22 Pinehurst, Port Arthur, Port Neches, Groves, Nederland, Orange, Rose City, Shenandoah,

I 1

I

1 Silsbee, Sour Lake, Splendora, Vidor, and West Orange ("Cities") served by the Entergy

2 Texas, Inc. ("Company" or "ETI").

3

4 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

5 A. The purpose of my testimony is to address certain adjustments that are required to ETI's

6 requested rate increase filed before the Public Utility Commission of Texas

7 ("Commission" or "PUC"). I have provided Cities' witness Mr. Garrett with my

8 recommendations in order that they will be incorporated into the Cities' total revenue

9 requirement presentation.

10

11 Q. PLEASE BRIEFLY SUMMARIZE YOUR TESTIMONY.

12 A. The following is a brief summary of each of the major areas I address herein.

13

14 • Production Plant Life Spans. The Company proposes to retire almost all of its

15 gas-fired generation on June 30, 2025, for purposes of calculating depreciation

16 rates in this case as set forth in the 2008 Gannett Fleming depreciation study

17 ("2008 Study"). The proposed retirement year is earlier than and inconsistent with

18 the Company's internal planning for system resources. The Company's proposed

19 depreciation life spans assumes a retirement date that is also artificially short in

20 comparison to the life expectancy by the industry as well as the Company's own

21 resource planning division. I recommend establishing minimum life spans for the

22 Company's gas-fired generating facilities at the later of the year 2029 or when

23 such units reach 65 years of age. The standalone impact of this recommendation is

24 a reduction in depreciation expense of $11. 7 million based on plant in service as

25 of December 31, 2008.

26

27 • Interim Retirements. In spite of this Commission's previous rulings and

28 precedent regarding exclusion of interim retirements in the calculation of

29 production plant depreciation rates, the Company still proposes interim

30 retirements in its calculation. The Company's witness, Mr. Spanos attempts to

31 distinguish the Commission precedent by relying on an incorrect premise that the

32 Company's interim retirement analysis is based on a historical perspective, and

33 the Commission's precedent is applicable to a future perspective. This is a

34 distinction without a difference, because the Company applies the result of its

35 historical calculations to projected future results. Therefore, the Company's

36 witness's attempt to distinguish the Company's request from previous

37 Commission decisions is incorrect. The impact of upholding the Commission's

38 long standing precedent against interim retirements results in an approximate $4.6

39 million reduction in depreciation expense based on plant as of December 31,

40 2008.

2

1

2 • Production Plant Net Salvage. The Company proposes negative net salvage

3 values ranging from a negative 15% to a negative 32% for its gas and coal-fired

4 generations. The Company's coal-fired proposal isbased on an undocumented,

5 unsupported and inappropriate regression analysis associated with a database for

6 which the Company's depreciation witness has no first-hand knowledge. The

7 Company does not have a regression or any mathematical model to estimate net

8 salvage for gas-fired generation, but rather assumes it is approximately 80% of

9 the coal-fired value. Therefore, assuming the 80% factor to be correct, any

10 inaccuracies in the coal regression analysis would carry over to the Company's

11 projected net salvage for gas-fired generation. As a second step to the Company's

12 unsupported net salvage analysis, Mr. Spanos escalates the estimated demolition

13 costs as of the end of 2008 into the future for as many as 35 years and

14 recommends s that current customers pay with current dollars for future inflated

15 costs. These aspects of the Company's analysis are neither credible nor

16 reasonable. Therefore, in consideration of significant increases in scrap metal

17 prices that have occurred in the last 5 years and the potential sale of used

18 equipment, a zero (0) level of net salvage for production plant is recommended.

19 On a standalone basis this recommendation results in a reduction of

20 approximately $11. 7 million in depreciation expense based on plant as of

21 December 31, 2008.

22

23 • Mass Propertv Life Analysis. There are numerous problems with the Company's

24 proposed life-curve combination for the various mass property accounts

25 (transmission, distribution and general plant). First and foremost, the Company's

26 life analysis includes the impact of hurricane activity as typical, ongoing events.

27 This has resulted in certain accounts having life expectations shorter than

28 basically all other utilities in the industry. In addition, the Company's consultant

29 recognizes that there is a "significant portion" of the survivor curve to which the

30 curve-fitting process should be geared; however he has failed to properly

31 implement such criteria. Finally, the Company has failed to provide reasonable or

32 adequate support for its various positions. Modifications to 16 of the Company's

33 proposals results in a standalone impact of a $11.1 million reduction to annual

34 depreciation expense based on plant as of December 31, 2008.

35

I 36

37

• Mass Property Net Salvage. The Company's analysis relies only on the most

recent 5 years of data. This compares to a 16-year database employed by the same

consultant in the current El Paso Electric Company case before this Commission.

l 38

39

40

Without any indication in the testimony, depreciation study or workpapers, is the

fact that the limited five years of data is not even maintained by account, yet it is

I 41

42

presented by account based on an initially unidentified data manipulation.

Another fatal flaw in the Company's proposals is that there are the effects of

several major hurricanes reflected in the 5-year historical database. Thus, the data

43

! 44

45

46

relied upon by the Company to propose net salvage parameters are significantly

skewed to more negative levels than would reasonably be expected. Given the

significant problems with the Company's presentation and database in this case,

I 3

I

1 retaining the existing levels of net salvage by account is recommended. On a

2 standalone basis this recommendation results in a $10.6 million reduction in

3 annual depreciation expense based on plant in service as of December 31, 2008.

4

5 • Calculation Procedure. The Company proposes to use the Equal Life Group

6 ("ELG") calculation procedure. The ELG procedure is not a conservative capital

7 recovery method and in fact represents an accelerated procedure when compared

8 to the industry standard Average Life Group ("ALO") calculation procedure. The

9 ELG procedure is inaccurate in all instances, except in the improbable scenario

10 that future annual retirements for up to 100 years into the future can be precisely

11 estimated. In reality, ETI cannot predict future annual retirement levels with any

12 degree of accuracy, even for as little as a 5-year period. Relying on the ALO

13 procedure, a straight line, non-accelerated procedure, results in a standalone

14 reduction to annual depreciation expense of $19.3 million based on plant as of

15 December 31, 2009.

16

17 • Combined Impact of Depreciation Adjustments. The combined impact of the

18 various depreciation adjustments is not simply the summation of the individual

19 standalone impacts. If life, net salvage, or calculation procedure proposals are

20 modified within the same account, they are interactive with each other. As set

21 forth on Schedule (JP-1 ), the combined impact of the various adjustments results

22 in a $57 million reduction in depreciation expense based on plant in service as of

23 December 31, 2008.

24

25 • Fully Accrued Depreciation. The Company admits that it unilaterally changed

26 the Commission approved depreciation rates when it ceased booking depreciation

27 expense for three accounts. The Company does not have the authority to

28 unilaterally change a depreciation rate previously approved by the Commission.

29 Reversal of the Company's inappropriate actions results in a $6.2 million decrease

30 in rate base and a $1.5 million credit amortization expense associated with a four-

31 year amortization period.

32

33 • Spindletop Gas Storage Facilitv l"SGSF"). Since the Company's last fully

34 litigated rate proceeding, the Company has exercised an option to purchase the

35 SGSF facilities for $1. Due to the unique situation of ownership, operation and

36 cost recovery, customers have significantly overpaid depreciation expense and are

37 now entitled to appropriate net salvage treatment and correction of the

38 intergenerational inequity that has transpired. Amortizing the excess depreciation

39 reserve over a 4-year period and recognition of Company-established net salvage

40 expectations results in a $5.5 million reduction to revenue requirements

41 associated with this unique investment. However, given Cities' witness Mr.

42 Nalepa's recommendation relating to the SGSF, only $1.2 million of my

43 recommendation associated with the recognition of net salvage is required, when

44 Mr. Nalepa's position is adopted.

45

4

1 • Storm Insurance Reserve. The Company has overstated revenue requirements in

2 the calculation of its insurance reserve request. The Company performs a flawed

3 Monte Carlo simulation. The Company has skewed its results to the high side

4 based on the inclusion of inappropriate costs and charges to the insurance reserve.

5 ETI also inappropriately attempts to segregate certain hurricane securitization cost

6 from the reserve. Removing certain inappropriate charges to the Company's

7 insurance reserve and performing a more realistic projection of future storm cost

8 accruals results in a $7. 7 million reduction to the Company's storm reserve annual

9 accrual and a $45.9 million reduction to rate base. In addition, I recommend an

IO increase in the current $50,000 storm insurance threshold limit to $500,000.

11

12 • Cash Working Capital ("CWC"). The Company overstates and incorrectly

13 calculates the Company's CWC requirements. In particular, the Company relies

14 on an inconsistent implementation of service period between revenues and

15 expenses. There are numerous other flaws associated with the Company's

16 approach to CWC that require correction. Based on my various recommendations,

17 the standalone impact of the corrected lead-lag analysis for the measurement of

18 ewe requirements would result in an incremental $43.7 million reduction to rate

19 base and an approximate corresponding $5. 7 million reduction to revenue

20 requirements.

21

22 • River Bend Decommissioning. The Company seeks approval from this

23 Commission for its proposed level of decommissioning expense associated with

24 the River Bend plant that is now owned by ETI's Louisiana affiliate Entergy Gulf

25 States Louisiana ("EGSL"). Cities' witness Mr. Brazell testifies that the

26 Commission does not have the authority to set a decommissioning revenue

27 requirement for River Bend given EGSL' s ownership of the plant. The

28 Company's proposal is based on a 40-year life span for River Bend, rather than

29 the more appropriate and realistic 60-year life expectancy. Therefore, if the

30 Commission were to determine the proper decommissioning revenue requirement

31 for Texas retail customers, I recommend that a 60-year life span be employed. In

32 addition, the beginning balances in the decommissioning funds are understated in

33 the Company's presentation and would need to be corrected. The standalone

34 impact of these adjustments eliminates the need for Texas retail customers to

35 contribute any additional amounts to the decommissioning trust funds. Therefore,

l 36

37

my recommendation results in a $2.8 million reduction to proposed annual

decommissioning revenue requirements.

38

39 • River Bend Depreciation. Cities' witness Mr. Brazell presents the position that

40 the Commission does not have the authority to set depreciation rates for River

41 Bend. However, the Company has requested that the Commission do just that.

42 Unfortunately, the Company's presentation reflects a 40-year service life for

43 River Bend. It should be noted that the Company relies on a 60-year life for

44 River Bend in the Louisiana jurisdiction and agreed to a 60-year life in Docket

45 No. 34800, a settled proceeding. While the Company has not yet received

46 permission from the Nuclear Regulatory Commission (''NRC") for such license

5

1 extension, it must be noted that not a single license application for the 20-year life

2 extension has been denied by the NRC. Therefore, if the Commission does elect

3 to establish a depreciation rate for River Bend, it should do so based on the 20-

4 year life extension and with no interim retirements reflected therein.

5

6 Q. IS THERE A CONCERN THAT NEEDS TO BE ADDRESSED AT THE

7 BEGINNING OF YOUR TESTIMONY?

8 A. Yes, in the area of depreciation and capital recovery a utility can present aggressive,

9 middle of the road, or conservative parameters given the subjectivity required in

10 performing any future depreciation or capital recovery estimate. After review of the

11 Company's depreciation presentation, it is clear that the Company's position in this case

12 is one of the most aggressive presentations realistically possible. The Company's

13 approach results in an extremely excessive level of depreciation expense, rapid return of

14 capital investment to shareholders, which in my estimation, is unreasonable and an

15 unnecessary burden for current customers.

16

17 Q. DO THE PROPOSED DEPRECIATION PARAMETERS CONTINUE THE

18 CORPORATE PLAN THAT PUSHES AGGRESSIVE DEPRECIATION

19 PRACTICES?

20 A. Yes. While utilities have become more sophisticated in the last several decades when it

21 comes to spelling out their corporate plans, this Company continues its predecessor's

22 Corporate Plan, which under the heading of Long-Range Corporate Objectives, stated the

23 following: "Push accounting/depreciation judgments aggressively where possible." 1

24 (Emphasis added).

25

26 Q. CAN YOU PROVIDE SPECIFIC EXAMPLES THAT DEMONSTRATE ETl'S

27 CONTINUATION OF THE PREVIOUSLY STATED AGGRESSIVE

28 DEPRECIATION PRACTICES?

29 A. Yes. First and foremost is the Company's decision to utilize the ELG calculation

30 procedure. Reliance on the ELG procedure in light of identifiable "anomalies" that result

31 from the analyses of the underlying data is flawed and can no longer be relied upon to

1

Gulf States Utilities Corporate Plan 1980-1984 item l(c).

6

I predict with some degree of certainty how mortality patterns might look in the future.

2 The anomalies in the analyses are due, at least in part, to problems with the data,

3 including potential problems associated with the jurisdictional separation of ETI and

4 EGSL. Indeed, the combination of the underlying data problems with the fact that the

5 ELG procedure is the most accelerated book depreciation calculation procedure that can

6 be proposed in a rate proceeding, can only result in a magnified distortion of the capital

7 recovery process compared to the industry standard ALG calculation procedure.

8

9 Next, in the area of production plant net salvage, Mr. Spanos not only relied upon an

I0 unsubstantiated regression analysis that produces excessively negative values, but then

11 proposed a unique escalation calculation. The Company, through Mr. Spanos' testimony,

12 proposes to charge current customers, who would have to pay with current dollars, for

13 costs that have been escalated, without discounting costs back to the present, for as many

14 as 35 years into the future. Such approach is illogical and unrealistic.

15

16 While there are other actions taken by Mr. Spanos that further push his and the

17 Company's aggressive depreciation goals, the above examples more than establish the

18 nature of the Company's presentation.

19 SECTION II: DEPRECIATION

20 1. General

21

I 22

23

Q.

A.

WHAT IS DEPRECIATION?

There are two commonly cited definitions of depreciation. The first comes from the

I 24

25

Federal Energy Regulatory Commission's ("FERC") Uniform System of Accounts

("USOA"): 2

l 26 'Depreciation', as applied to depreciable plant, means the loss in service

27 value not restored by current maintenance, incurred in connection with

I 28 the consumption or prospective retirement of electric plant in the course

2

Title 18 Code of Federal Regulations Part 101.

7

1 of service from causes which are known to be in current operation and

2 against which the utility is not protected by insurance. Among the causes

3 to be given consideration are wear and tear, decay, action of the

4 elements, inadequacy, obsolescence, changes in the art, changes in

5 demand and requirements of public authorities.

6 The second definition, from the American Institute of Certified Public Accountants

7 ("AICPA"), is similar:

8 Depreciation accounting is a system of accounting which aims to

9 distribute the cost or other basic value of tangible capital assets, less

10 salvage (if any) over the estimated useful life of the unit (which may be a

11 group of assets) in a systematic and rational manner. It is a process of

12 a/location, not of valuation. Depreciation for the year is a portion of the

13 total charge under such a system that is allocated to the year. Although

14 the allocation may properly take into account occurrences during the

15 year, it is not intended to be a measurement of the effect of all such

16 occurrences.

17 Q. WHAT ARE THE TWO GENERAL FORMULAS USED IN DETE RMINING

18 DEPRECIATION RATES?

19 A. The whole life and the remaining life technique are the most commonly used formulas.

20 The whole life technique is as follows: 3

Depreciation Rate (%) = [ Original Cost - Net Salvage

Average Service Life

Original Cost

J

21 The remaining life technique for calculating depreciation rates is as follows:

22

~ J

Original Cost - Reserve - Net Salvage

Depreoiation Rate (%) [ Remaining Life

Original Cost

3

A theoretical depreciation reserve calculation is developed and compared to the actual accumulated provision

for depreciation in conjunction with the whole life technique. If the differential is significant, an

amortization of the differential for some period of time may be recommended.

8

1 The two formulas should equal each other when the difference between the theoretical

2 reserve and the actual Accumulated Provision for Depreciation ("APFD" or "reserve")

3 are recovered over the remaining life of the investment under the whole life formula.

4

5 Q. ARE THERE ADDITIONAL CONSIDERATIONS IN DEPRECIATION BEYOND

6 THE DEFINITIONS?

7 A. Yes. The definitions provide only a general outline of the overall utility depreciation

8 concept. In order to arrive at a depreciation-related revenue requirement in a rate

9 proceeding, a depreciation system must be established.

10

11 Q. WHAT IS A DEPRECIATION SYSTEM?

12 A. A depreciation system constitutes the method, procedure, and technique employed in the

13 development of depreciation rates.

14

15 Q. BRIEFLY DESCRIBE WHAT IS MEANT BY "METHOD".

16 A. Method identifies whether a straight-line, liberalized, compound interest, or other type of

17 calculation is being performed. The straight-line method is normally employed for utility

18 depreciation proceedings.

19

20 Q. BRIEFLY DESCRIBE WHAT IS MEANT BY "PROCEDURE".

21 A. Procedure identifies a calculation approach or grouping. For example, procedures can

22 reflect the grouping of only a single item, items by vintage (year of addition), items by

23 broad group or total grouping, and equal life groupings. The vast majority of utilities and

I 24

25

regulatory authorities use the ALG procedure.

I 26

27

Q.

A.

PLEASE BRIEFLY DESCRIBE WHAT IS MEANT BY "TECHNIQUES".

There are two main categories of techniques with various sub-groupings: the whole life

I 28

29

technique and the remaining life technique. The whole life technique simply reflects

calculation of a depreciation rate based on the whole life (e.g., a ten-year life would

I 30

31

imply a ten percent depreciation rate over the life of a plant). The remaining life

technique recognizes that depreciation is a forecast or estimation process that is never

9

1 precisely accurate and requires true-ups in order to recover only 100% of what a utility is

2 entitled to over the entire life of the investment. Therefore, as time passes, the remaining

3 life technique attempts to recover the remaining unrecovered balance over the remaining

4 life or other period. Most utilities rely on a remaining life technique in utility rate matters.

5

6 Q. DO THE METHODS, PROCEDURES, AND TECHNIQUES INTERACT WITH

7 ONE ANOTHER?

8 A. Yes. Different depreciation rates will result depending on what combination of method,

9 procedure and technique is employed. Differences will occur even when beginning with

10 the same average service life and net salvage values.

11

12 Q. WHAT IS NET SALVAGE?

13 A. Net salvage is the value obtained from retired property (the gross salvage) less the cost of

14 removal. Net salvage can be either positive in cases where gross salvage exceeds cost of

15 removal, or negative in cases where cost of removal is greater than gross salvage.

16

17 Q. HOW DOES NET SALVAGE IMPACT THE CALCULATION OF

18 DEPRECIATION?

19 A. The intent of the depreciation process is to allow the Company to recover 100% of

20 investment less net salvage. Therefore, if net salvage is a positive 10%, then the utility

21 should only recover 90% of its investment through annual depreciation charges, under the

22 theory that it will recover the remaining 10% through net salvage at the time the asset

23 retires (e.g., 90% + 10% = 100%). Alternatively, if net salvage is a negative 10%, then

24 the utility should be allowed to recover 110% of its investment through annual

25 depreciation charges so that the negative 10% net salvage that is expected to occur at the

26 end of the property's life will still leave the utility whole (e.g., 110% - 10% = 100%).

27

28 Q. WHAT ARE THE KEY ELEMENTS OF THE DEPRECIATION FORMULA AT

29 ISSUE IN TIDS PROCEEDING?

30 A. All parameters in the previously noted formula are at issue. The establishment of life and

31 net salvage parameters are a function of the analyses performed, the interpretation of the

10

1 data, the judgment and experience of the analys~ and other relevant information. In

2 addition, the remaining life calculation is at issue given that Mr. Spanos of Gannett

3 Fleming performs a different remaining life calculation than every other utility that does

4 not retain Gannett Fleming that I have dealt with over the past 37 years, including this

5 Company. This remaining life calculation produces theoretically impossible results.

6 Finally, the calculation procedure is a major issue in this case, as ETI does not rely on the

7 industry standard ALG procedure.

8 2. Production Life

9 A. General

10

11 Q. WHAT IS THE ISSUE IN TlllS PORTION OF YOUR TESTIMONY?

12 A. This portion of my testimony addresses the appropriate life spans for the Company's

13 various generating units. In particular, I will address what appears to be a practice of

14 understating the life span for generating units. I recommend longer life spans for the

15 Company's gas-fired generating units.

16

17 Q. WHAT IS A LIFE SPAN FOR A GENERATING UNIT?

18 A. A life span for a generating unit sets the period during which it is expected to be in

19 service prior to being retired. For example, if a generating unit was placed into service on

20 January 1, 1980 and had a 60-year estimated life span it would have a projected

21 retirement date of December 31, 2040. It should be noted that a generating unit that is

22 placed in peaking or standby service is still in service and not retired.

I 23

24 Q. PLEASE EXPLAIN THE SIGNIFICANCE OF SETTING AN APPROPRIATE

~ 25 LIFESPAN.

26 A. In determining the depreciation rate, and thus depreciation expense for a generating unit,

I 27 it is necessary to establish the period over which customers are expected to receive

28 benefits and in return pay for such benefits. This process complies with the standard

f 29 regulatory "matching principle." As previously noted, the depreciation formula includes

I 11

I

1 the original cost less net salvage less the APFD, all divided by the remaining life. Thus, if

2 the life spans, and the related remaining life, are set at too short a period, current

3 customers overpay and vice versa. Failure to set a proper estimated retirement date for a

4 generating unit creates intergenerational inequities and fails to comply with the

5 "matching principle" of ratemaking.

6

7 Q. ARE THE RETIREMENT DATES FOR GENERATING UNITS KNOWN WITH

8 CERTAINTY?

9 A. Not for most units. Even for nuclear units that must operate within the period of a license

10 granted by the NRC, we now know that the initial estimate of a 40-year life span has been

11 or will be expanded to 60-years. Indeed, in ETI's last case, Docket No. 34800, the life

12 span for River Bend was extended for ratemaking purposes to 60 years. 4

13

14 Q. WHEN SETTING THE LIFE SPAN FOR A GENERATING UNIT, IS IT

15 APPROPRIATE TO LIMIT THE TIME FRAME TO THE INITIAL ESTIMATED

16 PERIOD CORRESPONDING TO WHEN MAJOR CAPITAL ADDITIONS MAY

17 BE REQUIRED IN ORDER TO KEEP THE UNIT IN SERVICE?

18 A. No, even though ETI and its depreciation consultant, Mr. Spanos, attempt to rely on such

19 a concept to artificially limit the current estimate of life span for units. Indeed, it is

20 questionable whether even the Company really believes such less than credible argument

21 given the sizeable capital additions it had to make in the early stages of service life for its

22 gas fired units. 5 In recognition of these sizeable capital additions that were necessary to

23 keep the units operating, ETI did not attempt to limit the life spans in its earlier

24 depreciation studies to the date of the expected capital additions.

4

PUC Docket No. 34800 Final Order FOF 34.

s Exhibit JJS-1pages209-252.

12

1 Q. WHY IS IT INAPPROPRIATE TO ARTIFICIALLY LIMIT THE LIFE SPAN OF

2 A GENERATING UNIT BASED ON UNCERTAINTY AS TO WHETHER

3 FUTURE CAPITAL ADDITIONS WILL BE MADE?

4 A. It is inappropriate to implement such depreciation judgment because it assumes that

5 utilities will act differently in the future than they have acted in the past without the

6 benefit of specific factors that would warrant such a change. Generating units are very

7 capital-intensive items. Economic theory recognizes that it is normally expected that

8 capital expenditures and normal maintenance expense will not only be made, but

9 encouraged as necessary, to keep a large capital intensive facility in operation for as long

10 as economically practical. This has been the Company's practice as it applies to actual

11 operation of its units.

12

13 An analogy would be associated with the purchase of a home. A new home can easily be

14 expected to last well over 50 years. However, a major capital expenditure for a new roof

15 may be required after 15 to 20 years. No reasonable person would set the life expectancy

16 of the house at 20 years because the decision has not been made regarding an expected

17 major expenditure 20 years in the future. The same can be said about limiting the

18 expected initial life expectancy of a house to even 30 or 40 years when the second

19 replacement of a roof can be expected. The issue becomes at what point would one

20 expect external forces such as a change in character of the neighborhood or other events

21 to change, for it to warrant the abandonment of the house. As long as the best use of the

22 house is as a dwelling and it is economically cost effective to make repairs and

23 replacements, the initial life should not be set artificially short due to potential

24 uncertainties surrounding future major capital additions.

I 25

I 26

27

Q. DOES THE COMPANY'S PRODUCTION PLANT DEPRECIATION EXPENSE

REPRESENT A SIGNIFICANT REVENUE REQUIREMENT?

I 28

29

A. Yes. The Company's 2008 Study identifies over $783 million of investment and proposes

$28.4 million in depreciation expense for annual Steam Production plant (Accounts 310-

316). 6 This level of depreciation expense is unnecessary and only arises as a result of the

l 30

6

2008 Study at Exhibit JJS-1 page 52.

I 13

I Company's witness's aggressive "depreciation judgment" for reflecting life spans,

2 corresponding interim retirements, and net salvage values.

3 B. Basis for Retirement Dates

4

5 Q. WHAT TESTIMONY DID THE COMPANY SPECIFICALLY PROVIDE IN

6 SUPPORT OF THE PROPOSED LIFE SPANS FOR ITS VARIOUS

7 GENERATING UNITS?

8 A. The Company provided the testimony of Mr. Spanos. The entire basis for this significant

9 parameter is set forth at pages 19 and 20 of Mr. Spanos' direct testimony where he states:

10

11 The bases for the probable retirement years are life spans for each facility

12 that are based on judgment and incorporate consideration of the age, use.

13 size. nature of construction. management outlook, and typical life spans

14 experienced and used by other electric utilities for similar facilities. Many

15 of the life spans result in probable retirement years that are many years in

16 the future, but included as part of ETI' s resource plan. As a result, the

17 retirements of these facilities are not yet subject to specific management

18 plans. At the appropriate time, detailed studies of the economics of

19 rehabilitation and continued use or retirement of the facility will be

20 performed and the results incorporated in the estimation of the facility's

21 life span. (Emphasis added).

22

23 Q. DID THE COMPANY ADD ANY ADDITIONAL INFORMATION REGARDING

24 THE BASIS FOR THE LIFE SPANS OF ITS UNITS IN THE 2008

25 DEPRECIATION STUDY?

26 A. While the 2008 Study added the following statements, such verbiage fails to provide any

27 additional meaningful basis for the Company's proposed life spans:

28

29 The life span estimates for power generating stations were the result of

30 considering experienced life spans of similar generating units, the age of

31 surviving units, general operating characteristics of the units, major

32 refurbishing, and discussion with management personnel concerning the

33 probable long-term outlook for the units. Final decisions as to date of

34 retirement will be determined by management on a unit by unit basis. 7

35 (Emphasis added).

7

2008 Study at Exhibit JJS-1 page 35.

14

1 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY

2 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE

3 LIFE SPANS FOR ITS GENERATING UNITS REFLECTING

4 "CONSIDERATION OF THE AGE" OR "USE, SIZE, NATURE OF

5 CONSTRUCTION" OF ITS UNITS?

6 A. The Company has provided no information that would support its proposal for a life span

7 as short as 46 years for Sabine 5. In fact, Sabine Units 1 and 2, which are much smaller

8 and dispatched less than Sabine 5, have already reached ages in excess of 46 years. Thus,

9 judgment in conjunction with consideration of age or physical characteristics of the units

10 should have caused the Company to propose longer life spans than it has.

11

12 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY

13 PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE

14 LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "MANAGEMENT

15 OUTLOOK"?

16 A. The Company has provided no information that would support its proposals. In fact, the

17 timing horizon of the Company's Strategic Resource Plan ("SRP") is through 2028. 8 The

18 SRP planning horizon exceeds the retirement dates for all of the Company's gas-fired

19 units, yet such plan relies on the continued operation of all such units to meet future

20 loads. Thus, even the Company's current management "outlook" refutes the judgment

21 employed by Mr. Spanos in the 2008 Study.

22

23 Q. WHAT SPECIFIC ITEM OF INFORMATION HAS THE COMPANY

I 24

25

PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE

LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "TYPICAL LIFE

~

26 SPANS EXPERIENCED AND USED BY OTHER UTILITIES OF SIMILAR

27 FACILITIES"?

I 28

29

A. The Company has provided no information. However, through discovery, it was

determined that Gannett Fleming has supported a range of life spans for gas-fired units

I 30 that is so wide that it would allow for a selection of about any value, even ones

8

Response to Rose City 1-36 Attachments.

15

l approaching 70 years. I submit that Gannett Fleming's life span range for gas-fired units

2 is so large that it defies any credibility that might have been assigned to it in the

3 "judgmental" process claimed by Mr. Spanos.

4

5 Q. DOES MR. SPANOS' TESTIMONY PROVIDE SUFFICIENT EXPLANATION

6 AND JUSTIFICATION TO SUPPORT THE COMPANY'S PROPOSED LIFE

7 SPANS FOR ITS GENERATING FACILITIES?

8 A. No.

9

10 Q. DID THE COMPANY PROVIDE ANY ADDITIONAL INFORMATION JN

11 RESPONSE TO DISCOVERY?

12 A. Yes. Mr. Spanos provided his site visit notes that reference limited additional information

13 such as:

14

15 • System maintenance good;

16 • Control upgrades;

17 • Monthly vibration program, performance tests; and

18 • Boiler exam and maintenance every year. 9

19

20 Q. DO THESE ADDITIONAL STATEMENTS CONTAINED IN MR. SPANOS' SITE

21 VISIT NOTES PROVIDE SUFFICIENT SUPPORT FOR THE COMPANY'S

22 LIFE SPAN PROPOSALS?

23 A. No. These statements represent the type of statements one would expect relating to a

24 dynamic situation requiring decisions whether to retire units or continue to expend funds

25 to permit continued operation. In fact, it is quite clear from these comments and other

26 information in the 2008 Study that the Company has historically decided, and currently is

27 deciding, to make necessary capital expenditures to keep its units in operation long after

28 the claimed initial design life. The Company has faced the decision whether to retire

29 these units or spend funds to keep them in operating condition beyond initial expectations

30 and in each instance has decided that it is economically appropriate and efficient to do

31 what all other utilities have been doing: maximize the life of a capital-intensive asset.

9

Response to Rose City 1-15 Attachment.

16

1 There is more support for longer life spans in Mr. Spanos' notes than there is for the

2 artificially short life spans being proposed.

3

4 Q. DID MR. SPANOS PROVIDE ANY ADDITIONAL INFORMATION

5 REGARDING ms PROPOSED LIFE SPANS DURING ms DEPOSITION?

6 A. Yes. Mr. Spanos stated that the life spans corresponded with the best estimate of the

7 likelihood of assets being either taken out of service (i.e. retired), or the date of expected

8 major capital additions in the future made to change the functionality of the asset. 10 He

9 also admits that the proposed retirement in his study does not necessarily relate to when

10 the units would be shut down. 11 These two statements taken together default to a position

11 that the probable retirement dates in Mr. Spanos' study are the unsubstantiated date Mr.

12 Spanos assumes the Company may make major capital additions to change the

13 functionality of the units.

14

15 Q. IS THERE ANYTHING IN THE USOA THAT DEFINES OR TIES THE

16 SERVICE PERIOD FOR A GENERATING UNIT TO AN ASSUMED DATE

17 WHEN A UTILITY MIGHT MAKE A MAJOR CAPITAL ADDITION THAT

18 CHANGES THE FUNCTIONALITY OF AN ASSET?

19 A. Absolutely not.

20

21 Q. DID MR. SPANOS OR THE COMPANY PROVIDE A SINGLE DOCUMENT

22 THAT DEMONSTRATES THE PROPOSED RETIREMENT DATES ARE THE

23 COMPANY'S BEST ESTIMATE OF WHEN A UNIT WILL RETIRE?

I 24

25

A. No. In fact, as previously discussed, the documents presented by the Company now

demonstrate that assumed retirements prior to 2029 are not the current best estimate of

~ 26 the Company.

~

I 10

Deposition of Mr. Spanos on April 20, 2010 at TR 39.

Id.

I

II

17

!

1 Q. DID MR. SPANOS PROVIDE A SINGLE DOCUMENT OR ITEM OF

2 EVIDENCE THAT IT IS APPROPRIATE TO TIE THE PROPOSED

3 RETIREMENT DATE TO A CONCEPT OF WHEN MAJOR CAPITAL

4 EXPENDITURES MIGHT OCCUR?

5 A. No, Mr. Spanos' concept is a backdoor approach to recognizing interim additions,

6 something the PUC and other regulators do not permit.

7

8 Q. WHAT ARE INTERIM ADDITIONS?

9 A. Interim additions are theoretical future dollars of investment or capital additions in plant

10 to be added to existing facility of the Company. Such additions are not the dollars of

11 investment currently in service. Rather, they are .estimated dollars for replacement of

12 certain existing facilities or for additions of new facilities to an existing generating

13 facility in the future.

14

15 Q. ARE INTERIM ADDITIONS APPROPRIATE FOR DEPRECIATION

16 PURPOSES?

17 A. No. Interim additions are inappropriate since they reflect the estimation of potential

18 additions to plant-in-service that currently do not exist and are not used and useful in

19 providing service. Interim additions may never actually occur or may occur at a much

20 different date or amount than initially assumed.

21

22 Q. IN THE RATEMAKING PROCESS, ARE INTERIM ADDITIONS EVER

23 APPROPRIATE FOR DEPRECIATION PURPOSES?

24 A. No. Interim additions are appropriate only after they occur. Once such expenditures

25 occur, and the plant becomes used and useful in providing service, it is appropriate to

26 incorporate the plant investment into a depreciation study. Under this approach, the

27 Company is not deprived of a return of its investments associated with interim additions.

28 Moreover, customers are not inappropriately charged for unknown plant that is not used

29 and useful in providing service to them at the time the depreciation rates are developed.

18

1 Q. WHAT SOURCE SUPPORTS YOUR POSITION THAT ESTIMATED INTERIM

2 ADDITIONS SHOULD NOT BE REFLECTED IN THE DEPRECIATION

3 CALCULATION?

4 A. The National Association of Regulatory Utility Commissioners (''NARUC") 1968

5 publication entitled Public Utility Depreciation Practices describes, on pages 133 and

6 134, how interim additions are treated. It states the following:

7 Appropriate computations must be made for such interim retirements, but

8 interim additions are not considered in the depreciation computation until

9 they are actually made.

10 It is possible to estimate the probable future retirements and additions to a

11 particular piece ofproperty and thus arrive at a single depreciation rate

12 applicable over the entire life of the property. This is an unsatisfactory

13 practice inasmuch as considerable speculations would be required to

14 make such an estimate on future additions. In any event. this is not

15 necessary inasmuch as the depreciation accrual can be adjusted in future

16 years as additions are made. (Emphasis added).

17

18 The 1996 NARUC depreciation publication reaffirms this concept. 12

19

20 Q. HAS THE FERC RENDERED A DECISION ON THE CONCEPT OF

21 INTERIM ADDITIONS?

22 A. Yes. The FERC reviewed and ruled on this issue in its Opinion No. 165, a

23 Commonwealth Edison Company case. 13 In that case, Commonwealth Edison had

24 proposed taking into account budgeted future interim additions and stated that without the

25 inclusion of the budgeted interim additions, there would be a violation of the matching

I 26

27

principle (i.e. revenues collected corresponding to the expenses incurred). In Opinion

No. 165, the FERC clearly rejected recognition of interim additions:

I 28

29

... we reject its [Edison 'sj claim that this will leave some costs

unrecovered after the plant is retired. Such a result might occur if

30 Commonwealth would fail to adjust its depreciation rates from time to

I 31

32

time, taking into account up-to-date information on changes in plant

balances, estimated remaining life, salvage and removal cost experience,

33 and accumulated provision for depreciation to date. However,

I 12

Page 142 states" ... interim additions are not considered in the depreciation base or rate until they occur."

13

23 FERC paragraph 61,219 (1983)

19

1 Commonwealth not only is free to make such adjustments to its

2 depreciation rates, but is obligated to do so to assure that as near as

3 possible the service value of electric plant is fully recovered during its

4 useful life. For all these reasons, we find no basis to approve

5 Commonwealth's depreciation methodology. 14

6

7 Q. IS THERE A NEED TO SPECULATE ON THE COMPANY'S FUTURE

8 INTERIM ADDITIONS?

9 A. No. The Company will have the opportunity to recover actual additions to plant from

10 customers once they occur.

11

12 Q. ARE OTHER UTILITIES FACED WITH THE SAME CONCERNS RELATING

13 TO THE DECISION TO REPAIR OR REPLACE WORN OR BROKEN

14 COMPONENTS VERSUS RETIRE A UNIT?

15 A. Yes, and the trend in the industry has been to project even longer life spans. In fact, in a

16 recent case here in Texas, Southwest Electric Power Company ("SWEPCO") filed for life

17 spans longer than ETI has for comparable units. 15 A listing of comparable size and age of

18 generating units between SWEPCO and ETI, along with the life spans filed by both

19 utilities is set forth in the table below:

20

21 COMPARABLE UNITS

Size Year Life Size Year Life

ETIUnit (MW) Installed Span SWEPCOUnit <MW) Installed Span

Lewis Creek # 1 271 1970 55 Wilks #2 357 1970 65

Lewis Creek #2 271 1971 54 Wilks #3 358 1971 65

Sabine #1 240 1962 63 Wilks #1 175 1964 65

Sabine #2 240 1963 62 Willes #1 175 1964 65

Sabine #3 473 1967 58 Willes #2 357 1970 65

Sabine #4 592 1974 51 KnoxLee#5 344 1974 65

Sabine #5 507 1977 46 KnoxLee#5 344 1974 65

14

23 FERC at page 61,469.

15

PUC Docket No. 37364, Exhibit DAD-I page 25.

20

1 C. Recommendation

2

3 Q. DO YOU BELIEVE THE COMPANY'S PROPOSED RETIREMENT DATES

4 FOR GENERATING UNITS ARE APPROPRIATE FOR DEPRECIATION

5 PURPOSES?

6 A. No. The Company's proposed life span for its gas-fired generating units assumes a 2025

7 retirement date. The Company's most recent SRP clearly dispels the credibility of that

8 date. Moreover, the Company has not shown why it cannot obtain life spans for its units

9 comparable to what other utilities have already achieved or are now projecting.

10

11 Finally, there is no credible basis for the Company to propose that the largest two gas-

12 fired units, Sabine Units 4 and 5, will only be able to achieve life spans of 51 and 46

13 years, respectively, while its two smallest and oldest units, Sabine Units 1 and 2, are

14 projected in the 2008 Study to achieve life spans of 63 and 62 years, respective. 16 These

15 life span estimates are extended at least to 67 and 68 years, respectively in the most

16 current SRP. The Company's production life span proposals are neither logical nor

17 credible.

18

19 Q. IS THERE ANY DOUBT THAT GAS-FIRED STEAM GENERATING UNITS

20 CAN LAST AS LONG AS 65 YEARS OR LONGER?

21 A. No. First, ETI now recognizes that Sabine Unit 1 will operate for at least that length of

22 time. 17 In addition, Mr. Spanos supports life spans for gas-fired units of up to 67 years for

23 Entergy Arkansas, Inc. ("EAi"), ETl's sister utility in Arkansas. 18 Moreover, the U.S.

24 Energy Information Administration ("EIA") maintains a database of operating generating

25 units in service through 2008. That database identifies over 500 natural gas-fired units

~ 26 that had already reached 46 years of age (the short life span proposed for Sabine 5) by the

27 end of2008, with almost 30 of those units exceeding 200 MW in size. 19

I

I 16

17

18

Exhibit JJS-1page36.

Response to Rose City 1-36.

Response to Rose City 1-3, 2008 Study for EAi at page 11-27.

19

EIA FORM 860, file Gen YOS.

I 21

I

1 Q. WHAT DO YOU RECOMMEND?

2 A. Given the industry, even here in Texas, is moving to a minimum of 60 years for coal-

3 fired generation and 60 plus years for gas-fired generation, I recommend a life span for

4 all gas-fired units corresponding to the year 2029 for those units that will exceed 65 year

5 life spans by that time, and a life span of 65 years for the remaining units. The year 2029

6 corresponds to the earliest year subsequent to the Company's current planning horizon in

7 its SRP.

8 3. Production Interim Retirements

9

10 Q. WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?

11 A. This portion of my testimony addresses the Company's request for interim retirements

12 and the corresponding impact on the life span for production plant.

13

14 Q. WHAT ARE INTERIM RETIREMENTS?

15 A. Interim retirements have been characterized as a fine-tuning adjustment to the life-span

16 analysis. The life-span method is used in estimating the retirement date for any large unit

17 of property such as an entire generating facility to recognize that through the course of its

18 60-year life span, several components of that generating facility will be changed. The

19 theory behind interim retirement rates is that even though a large unit of property, such as

20 a generating facility might retire in 60 years, in the interim period many components have

21 to be replaced in order to maintain the overall generating facility in operating condition.

22 An analogy to this would be a car, which might be anticipated to have a service life of 10

23 years. During the 10-year life of the car, the owner might have to replace the battery,

24 tires, alternator and other components in order to maintain the automobile in a safe and

25 operable condition. Therefore, even though the automobile may have a 10-year life span,

26 a 9.8-year average service life ("ASL") for the automobile and its components would

27 result due to the averaging of the automobile's life span with the average of the

28 individual components. In other words, the interim retirement rate would be a fine-

29 tuning factor used to reduce the service life from 10 years to a 9.8 year ASL.

22

1 Q. HAS THE COMPANY INCORPORATED THE IMPACT OF INTERIM

2 RETIREMENTS IN ITS DEPRECIATION ANALYSIS?

3 A. Yes. 20

4

5 Q. HAS THE COMMISSION PREVIOUSLY REJECTED THE INCLUSION OF

6 INTERIM RETIREMENTS IN THE CALCULATION OF PRODUCTION PLANT

7 DEPRECIATION RATES?

8 A. Yes. The Commission has specifically and consistently excluded interim retirements

9 from prior production-plant depreciation-rate calculations in fully litigated rate cases. In

10 Docket Nos. 14965 and 16705, the most recent fully litigated major electric base rate

11 cases where interim retirements were an issue, the Commission once again reaffirmed its

12 position and rejected the inclusion of interim retirements from the depreciation rate

13 calculation for production plant. In Docket No. 14965 the Commission stated " ...

14 forecasted interim additions and retirements and net salvage increases to plant in service

15 are not known and measurable changes to test-year invested capital."21 (Emphasis

16 added). In Docket No. 16705 the Commission denied the impact or recognition of all

17 interim retirements and additions beyond the end of the test year. 22 The Commission has

18 also denied the inclusion of interim retirements in cases where I also recommended their

19 inclusion.

20

21 Q. WAS MR. SPANOS AWARE OF COMMISSION PRECEDENT WHEN HE

22 PROPOSED THE INCLUSION OF INTERIM RETIREMENTS?

23 A. Yes. However, he believed that the precedent dealt with future interim retirements, not

24 historical interim retirements. 23 While his analysis of interim retirements was based on

I 25 historical data, the results were applied to future remaining lives because Mr. Spanos

26 thinks "that is a good indicator of what is going to happen into the future for interim

~ 27 retirement purposes."24 Mr. Spanos' approach is no different than the practices of other

28 utilities where the Commission rejected the use of interim retirements. In fact, Mr.

~

20

Direct Testimony of Mr. Spanos at page 18.

I 21

22

23

Docket No. 14965 FOF 94.

Final Order Docket No. 16705 at FOF 186.

Deposition of Mr. Spanos on March 25, 2010 at TR 93-94.

24

I Deposition of Mr. Spanos on April 20, 2010 at TR 95-96.

23

I

l Spanos could not identify any docket where this Commission had allowed interim

2 retirements as he would characterize them. 25

3

4 Q. IF THE COMl\flSSION WERE INCLINED TO REVERSE ITS PRECEDENT ON

5 TIDS ISSUE IN Tms CASE, DO YOU BELIEVE THE ANALYSIS PRESENTED

6 BY THE COMPANY IS APPROPRIATE?

7 A. No.

8

9 Q. WHAT DOES THE COMPANY PROPOSE FOR INTERIM RETIREMENTS?

10 A. The Company proposes to implement a calculation procedure for interim retirements

11 based on a truncated interim retirement survivor curve. 26

12

13 Q. PLEASE EXPLAIN THE PROBLEMS WITH THE COMPANY'S PROPOSED

14 METHOD.

15 A. The Company's approach relies on an actuarial analysis of the historical data for the

16 investment in Accounts 311 through 316.27 Actuarial analyses are normally performed on

17 more homogenous-type investments. The types of investments booked in the major steam

18 production plant accounts are non-homogeneous and do not reasonably lend themselves

19 to actuarial analyses. In other words, the retirement forces experienced by boiler tubes

20 booked in Account 312 may be noticeably different than those affecting the lighting

21 system, also booked in Account 312. Moreover, the retirement of individual units of

22 property in Account 312 can vary significantly. Therefore, Mr. Spanos' reliance on an

23 inappropriate method, which in turn relies on non-homogenous data to "guess" at a 55-R2

24 life-curve combination for the largest production plant account, is inappropriate. I use the

25 term "guess" given the fact that Mr. Spanos analysis yielded a survivor curve that only

26 declined by 12 percentage points out of 100 percentage points for a full curve. He simply

27 "guesses" or forces a result for the remaining 88%. Moreover, his "guess" at the 12%

28 decline in the observed life table ("OLT") was not good or reasonable. 28 If the

25

Id., at TR 96.

26

Exhibit JJS-1, pages 209-254.

27

Id., at pages 56-80.

28

OLT reflects the actual retirement pattern exhibited over a given period.

24

1 Commission were inclined to change its precedent on this matter, "guessed" at or forced

2 results cannot be accepted as a valid basis for the inclusion of the impact of interim

3 retirements.

4

5 Another consideration relating to Mr. Spanos' proposal in this case is his constant

6 practice of relying on industry data. With this in mind, it is worth noting that Mr. Spanos

7 proposed much longer ASLs for the same accounts in his current El Paso Electric

8 testimony before the Commission, as shown in the table below.

9

10 COMPARISON OF INTERIM RETIREMENT CURVES

Increase to EPE

Account ETI EPE Years %

311 65-R2 100-Sl.5 35 54%

312 55-R2 80-82.5 25 45%

314 50-82.5 75-R4 25 50%

315 50-S0.5 65-Sl.5 15 30%

316 50-Rl.5 60-R3 10 20%

11 Moreover, it must be noted that Mr. Spanos had basically the same level of utility

12 specific OLT data with which to work with in both cases. Therefore, it appears that the

13 difference between the two contemporaneous studies both filed at the same time before

14 this Commission is the depreciation policy in place for ETI. Finally, it is worth noting

15 that the Florida Public Service Commission ("FPSC") this year denied the method of

16 calculating interim retirement employed by Gannett Fleming recognizing many of the

17 problems noted above. 29

I 18

19 Q. WHAT DO YOU RECOMMEND?

I 20

21

A. Given that this Commission has consistently denied the recognition and inclusion of

interim retirements for production-plant deprecation rates in prior proceedings, I

I 22

23

recommend that the Commission precedent on this matter be recognized for ratemaking

purposes in this proceeding and the impact of interim retirements be eliminated from the

I 24 Company's proposed depreciation calculation.

29

I FPSC Docket No. 080677-EI Order at pages 30-32.

25

I

1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?

2 A. The total standalone impact of the elimination of the proposed interim retirements from

3 production plant depreciation rates results in a reduction to the Company's requested

4 depreciation expense by $4,608,437 based on plant as of December 31, 2008.

5 4. Production Net Salvage

6

7 Q. WHAT ISSUE DO YOU ADDRESS IN TIDS PORTION OF YOUR

8 TEST™ONY?

9 A. I address the Company's request for production net salvage. Specifically, the Company

10 requests net salvage for its various generating facilities ranging from a negative 15% to a

11 negative 32% for its various generating facilities. 30 In response to the Company's

12 proposal, I recommend a zero (0) level of net salvage, even though a more appropriate,

13 yet still conservative, level would be a positive 5% to 10%.

14

15 Q. WHAT DOLLAR IMPACT DOES THE COMPANY'S PROPOSAL HAVE ON

16 DEPRECIATION EXPENSE?

17 A. Based on plant in service as of December 31, 2008, the Company's net salvage request of

18 $190.7 million over the life of the investment produces approximately $11.6 million of

19 annual depreciation revenue requirements. 31

20

21 Q. WHAT IS THE COMPANY'S BASIS FOR ITS REQUEST OF NEGATIVE NET

22 SALVAGE?

23 A. Mr. Spanos states the following:

24

25 final net salvage of dismantling costs of steam production units was based

26 on common industry practices of linear regression analysis by Megawatts

27 (capacity). These analyses were performed as of 2008 and the overall

28 dismantling costs were projected to the date of removal. 32

30

Exhibit JJS-1, pages 51 and 52.

31

Exhibit JJS-1, pages 51 and 52, setting the net salvage percentage to zero {O).

32

Direct Testimony of Mr. Spanos at page 22.

26

1 In other words, the Company performed what it claims is a common industry practice of

2 performing linear regression analysis on some unidentified data set to arrive at an

3 unidentified regression equation, which can then be applied to the individual megawatt

4 size of the Company's generating units. Once a current cost value has been established

5 under this method, Mr. Spanos then escalated the costs into the future until the proposed

6 retirement date for the Company's various generating units.

7

8 Q. CAN YOU PROVIDE A SPECIFIC EXAMPLE OF WHAT THE COMPANY

9 PROPOSES?

10 A. Yes. Mr. Spanos claims his regression analysis yields a $40.61 per kW dismantlement

11 cost for the Big Cajun coal-fired generating unit. 33 He then applies that value to the 588

12 Mw size of the Big Cajun coal unit, which yields an estimated cost of $23,878,680 in

13 2008 dollars. Mr. Spanos then applied ETI's 42.5% ownership share of what he believed

14 was the Entergy ownership share of the Big Cajun unit, in an attempt to establish a

15 $10,148,439 cost applicable to ETI. Mr. Spanos inflated that 2008 cost figure at an

16 annual compounded rate of 3% for 3 5 years into the future, the assumed future retirement

17 date for the Big Cajun unit. The result is an estimated future dismantlement cost of

18 $28,536,311. 34 The future escalation of cost raised the requested cost level by multiplying

i 19 the current cost level by a factor of 2.814 (l.03<35 ».

20

21 Q. SETTING ASIDE FOR THE MOMENT THE REGRESSION AND ESCALATION

22 CONCEPTS EMPLOYED BY MR. SPANOS, IS ms CALCULATION

23 CORRECT?

No. For Big Cajun and Nelson 6, Mr. Spanos failed to reduce the stated MW size of the

I 24

25

A.

units for Entergy's ownership share. While Mr. Spanos did apply a 42.5% ownership

I 26

27

share allocation between ETI and Entergy Gulf States Louisiana ("EGSL"), he failed to

recognize that these are jointly owned units with other utilities. In particular, Cajun

l 28

29

Electric Power Company, Inc. owns 58% of the Big Cajun unit, while other utilities own

30% of Nelson 6. Therefore, Mr. Spanos' calculation overstates the dismantlement cost

I 33

Exhibit JJS-1page189, column (a).

34

$10,148,439 X l.03 3S = $28,536,31).

27

1 for these units even if one were to accept his linear regression and future cost escalation

2 approach.

3

4 Q. IS THE LINEAR REGRESSION ANALYSIS AS PROPOSED BY MR. SPANOS A

5 COMMON INDUSTRY PRACTICE AS CLAIMED?

6 A. No. In fact, when requested to provide support for such claim, all Mr. Spanos could state

7 was that it "is utilized by many utilities."35 Clearly, the claim is incorrect. Indeed, no

8 other use of the "common" industry approach was found in review of the recent

9 testimonies of Mr. Spanos.36

10

11 Q. WAS MR. SPANOS REQUESTED TO IDENTIFY OTHER UTILITIES WHERE

12 GANNETT FLEMING HAD EMPLOYED A METHOD OTHER THAN LINEAR

13 REGRESSION ANALYSIS FOR PRODUCTION PLANT NET SALVAGE

14 DURING THE PAST 3 YEARS?

15 A. Yes. Surprisingly, Mr. Spanos only identified two examples in response to this request

16 for information. 37 What is surprising about Mr. Spanos' response is that he currently has

17 a Gannett Fleming depreciation study on behalf of El Paso Electric before the

18 Commission in Docket No. 37690. In that depreciation study, Mr. Spanos did not employ

19 a linear regression analysis for production plant net salvage. In other words, two

20 contemporaneous depreciation studies performed on two different utilities both providing

21 service in Texas, both of which have been filed before this Commission, reflect

22 inconsistent application of what Mr. Spanos claims is a "common'' industry practice.

23

24 Q. DID MR. SPANOS IDENTIFY ms STANDARD FOR PRODUCTION PLANT

25 DISMANTLEMENT COSTS DURING A RECENT DEPOSITION?

26 A. Yes. In the El Paso Electric case noted above, Mr. Spanos stated during his deposition the

27 following regarding his standards for production plant terminal net salvage:

35

Response to Rose City 12-S(a).

36

Response to Rose City 1-3.

37

Response to Rose City 12-5(b).

28

1 I feel as though you need to incorporate a terminal net salvage component

2 or a -- what's called a decommissioning study to be incorporated into the

3 development.

4 However, if the company has not gone through the practice of getting the

5 estimate on that or does not have any determination of what their plans are

6 at final dismantlement, it's, in my opinion, not proper to build in a

7 terminal net salvage component without some sort of support.

8 The company [El Paso Electric] at this time hadn't had any plans, so

9 we've not included that. But there is going to be a major cost to dismantle

10 these facilities, and that needs to be built into rates for production facilities

11 as a full-service value of that facility.

12 But unless you have a specific plan or at least an idea of what's going to

13 happen, I don't think it is wise to build that into rates. But I think that's

14 something that's going to be a consideration here. 38 (Emphasis added.)

15

16 In other words, Mr. Spanos has established his standard for production plant terminal net

17 salvage in the El Paso Electric case, which is inconsistent within his proposal in this

18 proceeding. He admits that it is not proper to build in a terminal net salvage component

19 without some sort of support. Neither ETI nor El Paso Electric produced a

20 decommissioning cost estimate and neither have specific plans as to what would transpire

I 21 at the time of retirement.

22

23 Q. CAN MR. SPANOS CLAIM THAT HE DID NOT HAVE THE DATA

24 NECESSARY TO PERFORM THE "COMMON INDUSTRY PRACTICE OF

25 LINEAR REGRESSION ANALYSIS" IN THE EL PASO ELECTRIC CASE

26 THAT HE HAS PROPOSED IN TIDS CASE?

27 A. No. Mr. Spanos claims that his firm obtained this data in the early 1990s. Thus, Mr.

28 Spanos had the information available for his El Paso Electric study and testimony, yet

I 29 found it not wise to rely on it there, unlike his decision in this proceeding.

1

I

38

Deposition of Mr. Spanos on March 25, 2010 in Docket No. 37690 at page 86.

29

1 Q. SETTING ASIDE MR. SPANOS' FAILURE TO COMPLY WITH ms OWN

2 STANDARD AND ms INCONSISTENT TREATMENT BETWEEN EL PASO

3 ELECTRIC AND ETI, ARE THERE MAJOR PROBLEMS WITH THE

4 COMPANY'S PROPOSED REGRESSION ANALYSIS?

5 A. Yes. The Company's basis for its production net salvage has almost too many problems

6 to enumerate. However, the following are some of the major problems:

7

8 • No underlying data exists to support the claimed regression data points;

9 • No first-hand knowledge exists of where the data came from;

10 • Assumed future inflation rates are inconsistent with what the Company's rate

11 of return witness is proposing in this case;

12 • Proposing that current customers pay with current dollars for future inflated

13 costs while failing to discount such costs back to a present value level is

14 rmproper;

15 • Reliance on a false premise that the data points in the regression analysis

16 represent actual dismantlement costs of generating units over many years,

17 rather than being associated with dismantlement cost estimates for plants that

18 have not been dismantled is improper;

19 • Mathematical errors exist in the net salvage process; and

20 • Failure to recognize or understand the dramatic underlying differences

21 between assumed values or values within the regression database associated

22 with comparable sized units leads to flawed results in addition to the flawed

23 results generated by the flawed analysis.

24

25 Q. PLEASE DESCRIBE THE DATABASE RELIED UPON BY MR. SPANOS TO

26 DEVELOP ms REGRESSION ANALYSIS.

27 A. As set forth in the Company's response to Rose City 12-5, Mr. Spanos claims

28 approximately 60 data points associated with demolition costs for coal-fired generating

29 facilities. However, he does not have a single item of information associated with the

30 underlying data points. In other words, he cannot identify the units, stations, year in

31 which the dismantlement supposedly occurred, the process employed, the utility at issue

32 or anything else about the underlying data. Review of the data points indicates a mixture

33 of individual units with stations that are comprised of multiple units. The smallest data

34 point reflects 21 megawatts, while the largest data point reflects 3,145 megawatts. I am

35 unaware of any single generating unit that begins to reflect a size even approaching 3,000

36 MW.

30

1

2 Q. DO VALUES IN MR. SPANOS' REGRESSION DATA SET REPRESENT

3 UNREALISTIC RANGES?

4 A. Yes. For example, at the low end of the MW size range, Mr. Spanos identifies a 21 MW

5 and a 23 MW unit. The observed values for these two similarly sized coal units are a

6 $38.14 per kW dismantlement cost and a $119.22 per kW dismantlement cost,

7 respectively. This cost range represents in excess of a 3 to I variance from the low value

8 to the high value. Ranges of this magnitude for the same type and size units call into

I 9 question the validity of the data. However, Mr. Spanos does not have the underlying data

IO and cannot explain such variances.

11

12 Q. IS THE UNREALISTIC LEVEL OF VARIANCE LIMITED TO ONLY THE

13 SMALLEST SIZE UNITS?

14 A. No. For example, Mr. Spanos' database includes a 610 MW and a 630 MW unit with

15 corresponding estimated decommissioned costs of $8.96 per kW and $84.33 per kW,

16 respectively. Again, this range represents a differential in excess of 9 times from the low

17 value to the high value. Ranges of this magnitude for similar size and type units

18 demonstrate that Mr. Spanos' unsubstantiated database does not produce credible values.

19

20 Q. DOES THE FACT THAT MANY OF THE VALUES FALL WITHIN MORE

21 REALISTIC RANGES HELP JUSTIFY RELIANCE ON THE REGRESSION

22 ANALYSIS?

23 A. No. Without access to the underlying data, we do not know whether the majority of the

24 values in the more plentiful middle range are not a function of cost estimates from the

25 same cost estimator firm, thus further diminishing the credibility of the database.

~ 26

27 Q. YOU STATE THAT THESE VALUES ARE ESTIMATED VALUES, DOES MR.

! 28

29 A.

SPANOS AGREE WITH YOU?

No. During Mr. Spanos' deposition, he stated that he believed that the values reflected in

I 30 his database were for actual demolition activity, rather than estimated demolition cost

I 31

I

1 studies. 39 Mr. Spanos' understanding of the data is based on his undocumented

2 discussions with his predecessors at Gannett Fleming. 40

3

4 Q. IS MR. SPANOS CORRECT?

5 A. No. This is the first time I have heard Mr. Spanos claim that these were actual demolition

6 cost studies. For example, when Mr. Spanos relied on a regression analysis for his

7 proposed production plant net salvage proposal in a Nevada Power Company (''NPC")

8 case before the Nevada Public Service Commission (''NPSC"), he believed the values

9 were from estimated cost studies.41 In that case, Mr. Spanos also stated that the "data

10 [demolition cost information] were obtained from a survey conducted by the Property

11 Accounting and Valuation Committee of the Edison Electric Institute.''42 However, Mr.

12 Spanos' statements regarding these studies included discussion of different contingency

13 factors between studies. If the data represented actual completed demolition of power

14 plants, there would be no need for references to contingency factors. Contingency factors

15 are only applicable to future occurrences. The most troubling aspect of this situation is

16 that Mr. Spanos now claims he has even less of the limited data he had in the NPC case

17 associated with the old demolition cost estimates in this case.

18

19 Q. IS THERE YET ANOTHER PROBLEM WITH THE RELIANCE ON A 20-YEAR

20 OLD UNIDENTIFIED DATABASE?

21 A. Yes. Productivity rates and types of potential demolition activities have changed over

22 time. For example, there now exists a mechanical boom that can reach 300 ft high with

23 sheers on the end that can sever large beams of steel. This type of equipment has changed

24 the productivity levels reflected in whatever studies Mr. Spanos relied upon in

25 comparison to today's activity. In addition, Mr. Spanos' reliance on demolition cost

26 studies fails to recognize that many portions of units may be sold, which diminishes the

27 level of negative net salvage or, in fact, results in positive levels of.net salvage. Another

28 consideration that Mr. Spanos fails to take into account is the possibility of reuse of the

39

Deposition of Mr. Spanos on April 20, 2010 at TR 117.

40

Id.

41

NPSC Docket Nos. 03/1001-03/1002.

42

Rebuttal Testimony Mr. Spanos, page 16 in NPC Docket Nos. 03-1001/03-1002.

32

1 facilities by ETI. Most of the decommissioning studies in the late 80s and early 90s

2 reflect a substantial amount of dollars for site restoration. Such costs would be

3 inappropriate if a utility were to reuse the facility, as those costs would be associated with

4 the new installation. Simply put, multiple problems with the Company's production net

5 salvage analysis render it unreliable for any purpose in this proceeding.

6

7 Q. DOES MR. SPANOS FURTHER EMPLOY AN EXCESSIVE DEPRECIATION

8 CONCEPT IN ms PRODUCTION PLANT NET SALVAGE PROPOSAL?

9 A. Yes. After inconsistently relying on a linear regression analysis for his proposal in this

10 case and obtaining results that lack credibility, Mr. Spanos takes another major

11 inappropriate step. That step is to escalate the results of his regression analysis for net

12 salvage costs into the future until the projected date of retirement. Mr. Spanos relies on a

13 3% inflation factor, which he claims is representative of the Consumer Price Index

14 ("CPI") over the last 40-50 years. 43

15

16 Q. DID MR. SPANOS DISCOUNT THE FUTURE ESCALATED COST BACK TO

17 THE PRESENT PERIOD?

18 A. No. Mr. Spanos believes that the negative net salvage to be reflected in current rates must

19 include the cost to demolish a unit at the time of retirement. 44 In other words, Mr. Spanos

20 proposes to have current customers pay in current dollars for future costs that may have

21 been escalated as many as 3 5 years into the future.

22

23 Q. IS TIDS APPROPRIATE?

24 A. No.

I

~

I

l 43

Deposition of Mr. Spanos on April 20, 2010 at TR 125.

44

Id., at TR 124.

33

l Q. HAVE OTHER COMMISSIONS DENIED REQUESTS FOR INCLUSION OF

2 FUTURE INFLATION IN THE CALCULATION OF PRODUCTION-PLANT

3 NET SALVAGE?

4 A. Yes. Recently, the Oklahoma Corporation Commission ("OCC") denied the identical

5 request in a Public Service of Oklahoma ("PSO") case. 45 Another example is the NPSC

6 in consolidated Docket Nos. 91-5032 and 91-5055. In that case the NPSC stated the

7 following:

8

9 Since NPC has no terminal salvage and cost of removal experience for steam

10 and combustion turbine generating units, Mr. Ferguson [the utility

11 witness] relied on demolition studies of other utilities, adjusted for the

12 expected inflation between the study date and date of removal, in

13 determining his recommended rates ....

14

15 Mr. Pous criticized Mr. Ferguson for applying inflation to the cost of removal

16 or demolition studies without also taking into consideration other factors

17 such as the potential sale of production facilities or increased labor

18 productivity which might impact gross salvage or cost ofremoval....

19

20 Mr. Pous' arguments regarding the unreasonableness of Mr. Ferguson's

21 proposed net salvage factors for Steam Production Plant are persuasive. It

22 is apparent that Mr. Ferguson has selected only a limited number of

23 demolition studies and interpreted them in a manner to suwort his

24 position without adequately considering all factors involved. ... (Emphasis

25 added).

26

27 In another case, the Michigan Public Service Commission ("MPSC") in case No. U9493,

28 a Consumers Power Company case, stated the following regarding the incorporation of

29 future inflation in determining net salvage for production plant:

30

31 The Commission finds that Consumer's arguments must be rejected for

32 several reasons. First, contrary to Consumer's assertions, it is not clear

33 from the Commission's definitions of salvage value and cost of removal

34 that future inflation must be included in the net salvage used to calculate

35 depreciation rates. In fact, a review of those definitions reveals that they

36 are silent on that issue and make no provision for inclusion ofinflation....

37

38 Finally, the Commission also agrees with Staff and ABATE that it is

39 unreasonable to charge current ratepayers for future estimated costs of

40 removal that are escalated for inflation...Although magnifying the costs,

45

OCC Cause No. 200800144.

34

1 Consumer's did not consider future technological changes that might

2 reduce removal costs. For these reasons, the Commission finds that

3 Consumer's proposal is not in the public interest. Future inflation should

4 not be reflected in the terminal net salvage for steam production plant.

5 (Emphasis added).

6

7 The concept underlying net salvage for depreciation purposes is to estimate a reasonable

8 level of net salvage to include in current rates so that current customers will pay their fair

9 share of any such costs. To assume that inflation is the only factor that impacts future

10 cost of removal is simply wrong. Many areas of construction or demolition that entail

11 potentially large costs are subject to technological changes and process improvements.

12 For example, the demolition or toppling of large smoke stacks rather than taking such

13 structures down brick by brick is one improvement. Thus, Mr. Spanos' focus solely on

14 inflation distorts any credible results obtained from the analysis.

15

16 Q. IS THERE ANOTHER SIGNIFICANT REASON WHY INFLATION AS

17 PROPOSED BY THE COMPANY IS INAPPROPRIATE?

18 A. Yes. Current customers should pay their current cost in current dollars. Under ETI's

19 proposal, customers would be forced to pay for future costs established at a future dollar

20 level without any discounting back to current dollar levels. This is simply not a logical

21 conclusion and is not an accepted practice in utility ratemaking. For example, when

22 future inflation is taken into account in the establishment of external decommissioning

23 fund payments for nuclear plants, not only is an inflation or escalation rate included in the

24 overall calculation, but an earnings or discount rate is included as well. The earnings or

25 discount rate is included in order to recognize time value of money that occurs between a

26 dollar being spent or invested today and a dollar spent or invested at some point in the

I 27 future. ETI's total failure to recognize a discount rate is a fatal flaw in its proposal.

28

~ 29 Q. WHAT DO YOU RECOMMEND FOR PRODUCTION PLANT NET SALVAGE?

30 A. I recommend a zero (0)-level of net salvage for steam production plant as a conservative

I 31 position. The Commission may find it appropriate to adopt a positive 5% or greater level

32 of net salvage for steam generating facilities in recognition of: (1) the significant increase

I 33 in scrap metal prices that have occurred during the last 5-7 years due in part to the

34 significant growth by the economies of China and India; and/or (2) recognition of

35

l potential total sale of generating unit, or partial sale of used equipment as operable

2 equipment, rather than a sale as scrap value.

3

4 Q. DID MR. SPANOS CONSIDER THE POTENTIAL THAT A POSITIVE NET

5 SALVAGE COULD BE OBTAINED EVEN THROUGH A DEMOLITION

6 PROCESS?

7 A. No. Mr. Spanos stated that he "would be very surprised that there is much of a market for

8 someone to come in and buy it [a generating unit] for the scrap value and consider that to

9 be more than the cost they will have to dismantle it when they have eventually walked

10 away from that site.'.46

11

12 Q. ARE YOU AWARE OF A RECENT SITUATION WHERE A DEMOLITION

13 CONTRACTOR PAID TO TAKE DOWN A POWER PLANT?

14 A. Yes. Just last year the King Power Plant in Ft. Pierce, Florida was being demolished.

15 Even though the cost estimator developed a study that estimated a substantial cost to

16 demolish, the winning bid to demolish the plant was a negative $974,000. In other words,

17 a contract offered to lli!Y almost $1 million to get the salvageable equipment and scraps

18 material while demolishing the plant. The winning bid also included substantial costs for

19 the removal of asbestos at the old plant. 47

20

21 Q. COULD TIDS BE A SITUATION WHERE A CONTRACTOR WAS JUST OUT

22 OF LINE WITH ms ESTIMATE?

23 A. No. In fact, there were four bids where contractors were willing to lli!Y between $250,000

24 and $600,000 for the right to demolish the plant.48

25 Q. IS THERE AN AFTER MARKET FOR EQUIPMENT THAT WAS DESIGNED

26

27 A.

FOR OLDER POWER PLANTS?

Yes. For example, the city of Traverse, Michigan, recently retired the 1940s vintage

I

28 Bayside generating station. As part of the demolition, a sugar cane grower from Central

46

Deposition of Mr. Spanos on March 25, 2010 in PUCT Docket No. 37690 at TR 91.

47

Several conversations with Mr. John Tompeck, Capital Project Engineer for the Ft. Pierce Utilities Authority.

48

Several phone conversations with John Tompeck Project Engineer for the King Generation plant demolition

plant for the Ft. Pierce Utility Commission, Ft. Pierce, Florida.

36 I

I

1 America came, dismantled the boiler and other equipment, and shipped it to Central

2 America for on his sugar cane plantation.49 Moreover, when investor owned utilities

3 demolish power plants, usable items are sold or transferred rather than scrapped.

4

5 Q. ARE YOU AWARE OF OTHER EVIDENCE THAT EQUIPMENT AT

6 DEMOLISHED POWER PLANTS CAN AND HAVE BEEN SOLD RATHER

7 THAN CONSIDERED USABLE ONLY FOR SCRAP VALUE?

8 A. Yes. A presentation was made at a decommissioning conference regarding Florida

9 Power & Light Company's ("FPL") Palatka decommissioning project. One of the slides

10 in that presentation clearly notes under the heading Salvage/Sale that the

11 turbine/generator for Unit 1 at that station was sold.so 1bis fact was confirmed by FPL's

12 decommissioning documents. In spite of an active "after market" for power plant

13 equipment, when it comes to presenting a proposal, Mr. Spanos believes that selling

14 pieces of equipment is unlikely because there are so many requirements as to perfectly

15 matching equipment.st In contrast to this false assumption, he is more than willing to

16 offer negative 15% to 32% values without any underlying support.

17

18 Q. HOW HAVE THE ECONOMIES OF CHINA AND INDIA IMPACTED

19 DEMOLITION COST ESTIMATES?

20 A. The dramatic expansion of these economies has resulted in substantial upward pressure

21 on scrap metal prices. Prices for scrap copper are now over $3.00 per pound, while in the

22 early 2000s the price was more in the $0.40 price per pound range. Indeed, ETI admits

23 that it obtained $0.5039 per pound for scrap iron in 2008 while it was only able to obtain

24 $0.0621 per pound back in 2003.s2 Since the demolition of a power plant produces large

25 quantities of copper, steel and other metals, the gross salvage associated with the sale of

26 scrap metal can exceed the cost of demolition.

49

Web article at http://www.tclp.org/news_details.php?id=l22, and discussions with Traverse City electric

department personnel.

so Response to AXM 6-93 in PUCT Docket No. 35763.

51

Deposition of Mr. Spanos on March25, 2010 at TR 89.

52

Response to Rose City 1-34.

37

1 Q. WHAT IS THE IMPACT OF YOUR RECOMMENDATION?

2 A. On a standalone basis my recommendation results in an $11. 7 million reduction in annual

3 depreciation expense based on plant as of December 31, 2008.

4 5. Mass Property Life

5 A. Introduction

6 Q. WHAT IS THE PURPOSE OF THE LIFE PORTION OF A DEPRECIATION

7 ANALYSIS?

8 A. The purpose of a life analysis is to determine the "average service life" or ASL, the

9 dispersion pattern and remaining life for each account or subaccount. This information is

10 necessary to properly perform the depreciation calculation. A longer ASL results in a

11 longer remaining life and therefore a lower depreciation expense. Alternatively, a shorter

12 ASL will reduce the remaining life and increase depreciation expense. The dispersion

13 pattern is also important, as it is critical in the overall selection process of the best fitting

14 results. The same ASL with different Iowa Survivor Curves also results in different

15 remaining lives, due to the remaining expected pattern of retirements.

16

17 Q. WHAT ARE THE MAIN TOOLS UTILIZED IN PERFORMING LIFE

18 ANALYSIS?

19 A. Life analysis is normally performed by actuarial or semi-actuarial analyses. Actuarial

20 analyses rely on aged data. In other words, when an item of property is retired, the age at

21 retirement is known. 1bis is the type of analysis performed by insurance companies

22 when developing life tables in order to establish premiums. Semi-actuarial analyses are

23 performed in instances in which the age of retired plant is not known.

24

25 Q. PLEASE PROVIDE MORE INFORMATION REGARDING HOW A

26 DEPRECIATION ANALYST PERFORMS SUCH A LIFE ANALYSIS THAT

27 RELIES ON AN ACTUARIAL APPROACH.

28 A. Aged data is gathered and analyzed. Aged data means that when an asset retires in 2008

29 we know that it originally went in service in 1968, and was 40 years old at the time of

30 retirement. When all the aged data in a group is statistically analyzed by actuarial

38

1 techniques a resulting Observed Life Table or OLT is developed that depicts the rate of

2 retirement over the life of the group. The OLT starts at 100% surviving and declines

3 from there as each year of age is obtained and retirements occur. Naturally, not all units

4 retire at once; instead, the retirement dates are dispersed through time, creating a

5 "dispersion pattern." In order to permit testing and smoothing of the results some

6 standard or index must be used. The principal tool that a depreciation analyst uses for

7 this aspect of the study is a set of "survivor curves." The industry standard and most

8 extensively used curves are called the Iowa Survivor Curves. The name is derived from

9 the fact that they were developed at Iowa State College in the 1930s.

IO

11 Often, the historical data base analyzed does not yield a complete OLT, one that fully

12 declines to 0% surviving. This means that the data set will produce an incomplete OLT

13 or a "stub curve." Also, the limited data base may include atypical or abnormal events

14 not reasonably anticipated to occur again during the remaining life at the same levels

15 reflected in the historical data.

16

17 The Iowa Survivor Curves are based on empirical studies of retirement "behavior" of

18 physical property. They are designed to predict the retirement patterns of the property

19 under study based on detailed past observations. The Iowa Survivor Curves make the

20 calculation of the ASL far more manageable and comparable; instead of making and

21 weighting a myriad of individual calculations that include each data point in the universe,

22 the analyst measures the area below the curve and uses an established equation or

23 standard curve to "solve" for the ASL. And, even ifthe data set is incomplete-which is

24 often the case -by properly choosing a closely fitting curve to the known data, the

25 analyst can better predict the behavior of the entire universe and calculate the ASL with

26 reasonable statistical accuracy, if a meaningful "stub curve" exists. The results of any

27 estimation are more reliable if 70% of an OLT is known and only 30% must be assumed,

28 than if only 10% of the OLT is known and 90% must be assumed.

29

30 Not surprisingly, choosing the survivor curve that provides the best fit to the data is

31 critical to the accuracy of the analysis. When fitting the curves to the OLT the analyst

32 must bear in mind that some data points-those that occur on the points of the graph that

39

1 reflect the most significant level of plant exposed to retirement events-- are more

2 important to the determination of the ASL and dispersion pattern than others. Further,

3 the analyst cannot use the curves in isolation of other considerations. The analyst must

4 incorporate such things as knowledge of the nature of the property being studied, an

5 understanding of the causes of unusual events, recognition of changes or trends, and

6 judgment when using the curves. Also, the nature of survivor curves limits their

7 usefulness. For instance, they are best suited to studies of homogeneous items that,

8 because of their physical similarity and common exposure to retirement forces, can be

9 expected to share common retirement characteristics. (By analogy: When an insurance

10 actuary performs a mortality/longevity study for life insurance purposes, the actuary does

11 not combine people and horses in the universe of data.) It is for that reason that I

12 criticized ETI's analyst for inappropriately applying the Iowa Survivor Curves to interim

13 retirements for generation plant. The items of generation plant involved in interim

14 retirements frequently are far from homogeneous.

15

16 Q. HAVE YOU REVIEWED THE COMPANY'S MASS PROPERTY LIFE

17 ANALYSES?

18 A. Yes, I have reviewed the Company's mass property life analyses. The main problem

19 with the analyses is that Mr. Spanos proposes ASLs with corresponding Iowa Survivor

20 Curves that are not the best fit

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