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Contro l N mber: 49494

Item Number: 467

Addendum StartPage: 0

SOAH DOCKET NO. 473-19-4421 r.,',7r, r- 'ED PUC DOCKET NO. 49494

emtn LIJ:,- Cs r) —5 P'.1 2: 22

APPLICATION OF AEP TEXAS FOR § BEFOR Tfi-w STATE OFFI-CE AUTHORITY TO CHANGE RATES § ._,,

§ ADMINISTRATIVË 'HEARINGS

OFFICE OF PUBLIC UTILITY COUNSEL'S POST-HEARING INITIAL BRIEF

(REDACTED)

Lori Cobos Chief Executive & Public Counsel State Bar No. 24042276

Cassandra Quinn Senior Assistant Public Counsel State Bar No. 24053435 Harley Martin Assistant Public Counsel State Bar No. 24068879

OFFICE OF PUBLIC UTILITY COUNSEL 1701 N. Congress, Suite 9-180 P.O. Box 12397 Austin, Texas 78711-2397 512-936-7500 (Telephone) 512-936-7525 (Facsimile)

September 5, 2019

TABLE OF CONTENTS

I. Introduction/Summary [Preliminary Order (PO) Issues 5, 6, and 7] 1

II. Consolidation of Rates/Divisions [PO Issues 1, 2, 3, 4] 2

B. Is the Proposal reasonable and appropriate 2

III. Rate Base [PO Issues 8, 9, 14, 15, 16, 17, 19, 20, 21, 22, 23] 3

D. Accumulated Deferred Federal Income Tax [PO Issue 21] 3

F. Capitalized Annual Incentive Compensation 3

G. Capitalized Long-Term Incentive Compensation 3 1. The Commission's longstanding precedent holds that financially based

incentive compensation is not recoverable from ratepayers, and there is no reasonable basis for reversing this precedent 4

2. The Commission's established precedent applies to all financially based incentive compensation capitalized since the Company's last rate case 6

H. Capitalized Non-Qualified Pension Plan 9

V. Rate of Return [PO Issues 8, 9, 11, 12, 13] 10

A. Return on Equity [PO Issue 12] 10 1. Current Market Environment 11 2. Discounted Cash Flow Analysis 12 3. Risk Premium Analysis 14 4. Capital Asset Pricing Model 17

B. Cost of Debt [PO Issue 12] 18

C. Capital Structure [PO Issue 11] 18

D. Overall Rate of Return [PO Issue 12] 20

VI. Operating and Maintenance Expenses [PO Issues 4, 5, 25, 26, 27, 31, 32, 34, 35, 39, 41, 44, 45] 20

A. Transmission and Distribution O&M Expenses [PO Issue 25] 21 3. Distribution Vegetation Management Expense [PO Issue 27] 21

B. Labor Expenses 24 1. Incentive Compensation 24

a. Short-Term Incentive Compensation 24 b. Long-Term Incentive Compensation 27

2. Executive Employee Related Expenses (non-qualified pension plans) 29 3. Payroll Adjustments 31

C. Depreciation and Amortization Expense [PO Issue 31] 33 1. Advanced Metering Infrastructure ("AMI") Meters and Communications

Equipment 33

i

E. Self-Insurance Reserve Expense [PO Issues 20 and 39] 37

I. Rate-Case Expenses from previous proceedings 40

X. Functionalization and Cost Allocation [PO Issues 8, 9, 49, 50, 52] 43

A. Functionalization 43 1. Uncollectible Accounts Expenses Should be Functionalized to

Distribution, not Customer Service 43 2. Labor Costs in FERC Account 907 44

B. Class Allocation 44 1. Class Allocation of Transmission Costs 44

a. Hourly versus 15-minute interval data 44 2. Distribution Demand Cost Allocation (12 NCP versus 1 NCP) 45 5. Other cost allocation issues [PO Issue 52] 47

a. FERC Account 581 (Load Dispatching) 48 b. FERC Account 593 (Vegetation Management) 48 c. FERC Account 902 (Meter Reading) 49 d. Major Account Representatives 50

XII. Riders [PO Issues 8, 9, 49, 58, 59] 51

A. ITR Rider (related to TCJA) 51 1. Carrying Charges 53 2. One-Time Refund of Overcharges 54 3. Separate ITR Riders for Central and North Divisions 55

XV. Conclusion 56

CERTIFICATE OF SERVICE 57

11

SOAH DOCKET NO. 473-19-4421 PUC DOCKET NO. 49494

APPLICATION OF AEP TEXAS FOR § BEFORE THE STATE OFFICE AUTHORITY TO CHANGE RATES § OF

§ ADMINISTRATIVE HEARINGS

OFFICE OF PUBLIC UTILITY COUNSEL'S POST-HEARING INITIAL BRIEF

TO THE HONORABLE ADMINISTRATIVE LAW JUDGES:

The Office of Public Utility Counsel ("OPUC"), representing the interests of residential

and small commercial consumers in Texas, respectfully submits this initial post-hearing brief and

shows the following:1

I. Introduction/Summary [Preliminary Order (PO) Issues 5, 6, and 7]

This case is the first comprehensive base-rate proceeding for AEP Texas Inc. ("AEP

Texas" or the "Company") in 12 years. The Company made this filing pursuant to the rate-case-

review schedule established by the Public Utility Commission of Texas ("Commission") in 2018.2

The Commission adopted the schedule to implement Senate Bill 735 that was passed by the Texas

Legislature in 2017, which addressed the significant length of time between comprehensive rate

cases for electric utilities operating in the Electric Reliability Council of Texas ("ERCOT")

region.3 Prior to the adoption of the schedule, electric utilities generally controlled the timing of

their rate applications and could choose to file an application only when it was advantageous for

the utility. However, a regular, comprehensive review of an electric utility's rates is necessary to

ensure that the utility's rates remain just and reasonable. This case is an opportunity for such a

review.

1 OPUC' s initial brief follows the approved briefmg outline, but omits issues that OPUC does not address in its initial brief. OPUC reserves the right to address in its reply brief any issue raised by the parties in their initial briefs.

2 See 16 Tex. Admin. Code ("TAC") § 25.247(c)(2)(B).

3 Rulemaking Proceeding to Establish Filing Schedules for Investor-Owned Electric Utilities Operating Solely Inside ERCOT, Project No. 47545, Order Adopting New 25.247 (Apr. 16, 2018) (implementing Tex. S.B. 735, 85th Leg., R.S. (2017)).

1

In addition, this rate case is the first rate case filed by AEP Texas since the merger of its

predecessor companies, AEP Texas Central Company ("AEP TCC") and AEP Texas North

Company ("AEP TNC") in 2016.4 After the merger, the former AEP TCC operations (now the

Central Division) and former AEP TNC operations (now the North Division) remained separate,

with separate rates, riders and tariffs. The then-existing AEP TCC and AEP TNC base rates that

had been set in 2006 did not change and remained in effect for customers taking service within the

Company's two divisions. In this case, AEP Texas proposes to consolidate rates for its Central

and North Divisions for the first time. As discussed below, OPUC generally supports

consolidation of rates for the two divisions, with a few exceptions.

OPUC recommends several adjustments to the Company's requested cost of service in this

case. Ultimately, AEP Texas bears the burden of proving that the rate change it has requested is

just and reasonable,5 and the Company should be held to that burden.

II. Consolidation of Rates/Divisions [PO Issues 1, 2, 3, 4]

B. Is the Proposal reasonable and appropriate?

OPUC generally supports AEP Texas's proposal to consolidate the rates of its North and

Central Divisions. These divisions correspond to the former AEP TNC and AEP TCC,

respectively. Consolidation has been envisioned since the Commission approved the merger of

AEP TNC and AEP TCC in 2016,6 and the Company is currently being run as a single system.7

Consequently, the Company's base rates should generally be calculated for the system as a whole.

Nevertheless, OPUC recommends two exceptions to consolidation: (1) costs associated

with previous commitments made on behalf of a single division, including the stranded costs and

nuclear decommissioning costs that apply only to the Central Division and the Hurricane Harvey

costs that apply only to the Central Division; and (2) the Company's proposed Income Tax Refund

("ITR") rider.8 The Company is proposing that costs associated with previous commitments on

4 Application of AEP Texas Central Company, AEP Texas North Company, and AEP Utilities, Inc. for Approval of Merger, Docket No. 46050, Order (Dec. 12, 2016).

5 PURA § 36.006.

6 Docket No. 46050, Order.

7 OPUC Ex. 5 (Marcus Direct) at 22.

8 Id

2

behalf of a single division remain separate, but has proposed a consolidated ITR rider. The basis

for OPUC' s recommendation to implement separate ITR riders for the Company's divisions is

described in Section XII.A. below. With these exceptions, OPUC believes that consolidation of

the rates for the North and Central Divisions is reasonable and appropriate.

III. Rate Base [PO Issues 8, 9, 14, 15, 16, 17, 19, 20, 21, 22, 231

OPUC recommends reductions to AEP Texas's requested rate base for capitalized short-

term and long-term incentive ("STI" and "LTI," respectively) compensation tied to financial

measures, and capitalized supplemental executive retirement plan ("SERP") costs. These

adjustments are discussed in the following sections.

D. Accumulated Deferred Federal Income Tax [PO Issue 211

To properly reflect OPUC' s recommended reductions to rate base, an adjustment must also

be made to the accumulated deferred federal income taxes ("ADFIT") associated with these

specific reduction amounts.9 While AEP Texas disagrees with OPUC' s specific reductions to rate

base, it agrees that if the adjustments are made, then the corresponding ADFIT amounts should be

adjusted to reflect the reductions.1° OPUC witness Ms. Constance Cannady calculated ADFIT

adjustments for the Central and North Divisions in Schedules CTC-5A and CTC-5B to her direct

testimony.

F. Capitalized Annual Incentive Compensationn G. Capitalized Long-Term Incentive Compensation

OPUC recommends reductions to AEP Texas's requested cost of service to remove

financially based STI and LTI compensation costs that have been capitalized (discussed in this

section) and expensed (discussed in Section VI.B.1. below). The basis for OPUC's

recommendation to remove the amounts that have been capitalized is the same for both STI and

LTI compensation, so OPUC addresses these items together in this section.

9 OPUC Ex. 1 (Cannady Direct) at 31.

10 AEP Texas Ex. 40 (Hamlett Rebuttal) at 50-51.

11 In this brief, OPUC refers to AEP Texas's annual incentive compensation as short-term incentive compensation or STI compensation.

3

1. The Commission's longstanding precedent holds that financially based incentive compensation is not recoverable from ratepayers, and there is no reasonable basis for reversing this precedent.

The Commission's longstanding precedent is that a utility may recover incentive

compensation that is tied to achieving operational measures, but not financial measures.12

Operational measures are those designed to encourage a utility's employees to meet goals and

standards relating to the efficient operation of the utility, which is a benefit to shareholders and

ratepayers alike, while financial measures are those designed to encourage employees to achieve

financial targets, a benefit primarily to shareholders.13 The Commission's precedent on this issue

extends back to at least 200514 and is rooted in the Commission's cost-of-service rule, which only

allows utilities to recover expenses that are "reasonable and necessary to provide service to the

public."15 The Commission has repeatedly concluded that "[i]ncentive compensation that is based

on financial measures is of more immediate and predominant benefit to shareholders, whereas

incentive compensation based on operational measures is of more immediate and predominant

benefit to ratepayers."16 Thus, "[i]ncentives to achieve operational measures are necessary and

reasonable to provide utility services but those to achieve financial measures are not."17 As such,

financially based incentive compensation is not recoverable from ratepayers.

The Company acknowledges the Commission's longstanding precedent and does not deny

that its requested cost of service includes incentive compensation that is financially based.18

Instead, the Company contends that the Commission should reconsider its "policy."19 AEP Texas

12 Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at Finding of Fact ("FOF") Nos. 164-70 (Aug. 15, 2005); see also Application of Entergy Texas, Inc. for Rate Case Expenses Pertaining to PUC Docket No. 39896, Docket No. 40295, Order at 2 (May 21, 2013) ("The Commission has repeatedly ruled that a utility cannot recover the cost of fmancially-based incentive compensation because fmancial measures are of more immediate benefit to shareholders and fmancial measures are not necessary or reasonable to provide utility services.").

13 Application of Southwestern Electric Power Company for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 40443, Order on Rehearing at FOF Nos. 216-17 (May 6, 2014).

14 Docket No. 28840, Order at FOF Nos. 164-70.

15 16 TAC § 25.231(b).

16 See, e.g., Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment, Docket No. 39896, Order on Rehearing at FOF No. 129 (Nov. 2, 2012).

17 Id at FOF No. 130.

18 AEP Texas Ex. 38 (Talavera Rebuttal) at 2-3; AEP Texas Ex. 40 (Hamlett Rebuttal) at 46, 55.

19 AEP Texas Ex. 38 (Talavera Rebuttal) at 2-3.

4

uses the word "policy" to describe the Commission's precedent because it contends that nothing

in PURA requires the disallowance of a portion of its employee compensation as long as the

compensation is reasonable and necessary.2° However, while PURA § 36.051 only refers to

recovery of "reasonable and necessary operating expenses," the Commission's rule implementing

the statute requires that the expenses be "reasonable and necessary to provide service to the

public."21 The Commission has repeatedly concluded that financially based incentive

compensation does not meet this standard. Thus, the Commission's precedent is not simply a

"policy" decision, but rather is rooted in PURA and the Commission's rules and cannot be

disregarded.

In support of its proposal to reverse the Commission's established precedent, AEP Texas

notes that, during the recently concluded legislative session, the Texas Legislature enacted a new

statute that establishes a presumption of reasonableness for employee compensation and benefits

expenses for gas utilities if the expenses are consistent with market compensation studies

conducted within the three-year period before the gas utility's rate case.22 The Company asserts

that the new statute "demonstrates the Legislature's view that the recoverability of utility employee

compensation should be judged by its consistency with market compensation studies."23 However,

AEP Texas's reliance on this legislation is misplaced. As the Company acknowledges, the

legislation applies only to ratemaking proceedings for gas utilities, not electric utilities.24 As the

Texas Supreme Court has stated, "A statute's silence can be significant. When the Legislature

includes a right or remedy in one part of a code but omits it in another, that may be precisely what

the Legislature intended."25 This insight is particularly relevant here because during the same

legislative session, the Legislature considered, but did not adopt, legislation that would have

created a similar presumption for electric utilities.26 The Legislature is presumed to enact statutes

20 Id at 3.

21 16 TAC § 25.231(b).

22 AEP Texas Ex. 38 (Talavera Rebuttal) at 5.

23 Id

24 Id

25 PPG Indus., Inc. v. JMB/Houston Centers Partners Ltd P 'ship, 146 S.W.3d 79, 84 (Tex. 2004).

26 AEP Texas Ex. 38 (Talavera Rebuttal) at 5.

5

with complete knowledge of existing law.27 If the Legislature had intended to reverse Commission

precedent and create a presumption of reasonableness for electric utilities, it could have done so,

but did not do so. Accordingly, the newly enacted legislation for gas utilities does not provide a

basis for reversing the Commission's longstanding precedent that financially based incentive

compensation is not recoverable from an electric utility's ratepayers.

2. The Commission's established precedent applies to all financially based incentive compensation capitalized since the Company's last rate case.

As discussed in Section VI.B.1 . below, AEP Texas's requested operations and maintenance

("O&M") expense amounts for STI and LTI compensation should be reduced to remove the

portions tied to financial measures. However, removing the O&M expense amounts does not fully

eliminate financially based incentive compensation from the Company's cost of service. For

certain types of expenditures, particularly those related to employee compensation, some portion

of the expenditures may be charged to an expense account and some portion of the expenditures

may be capitalized if the employee's activity is related to a capital project or capitalized

overhead.28 Expensed costs that meet PURA's standards are included in a company's operating

expenses, while capitalized costs that meet PURA' s standards are included in rate base as invested

capita1.29 As with any employee expense disallowance, if any portion of the total expenditure is

capitalized, then that capitalized amount should also be disallowed. The underlying basis for a

disallowance would apply to the total expenditure, not just the expense amount. Therefore, any

incentive compensation that has been capitalized that was awarded on the basis of financial metrics

should be removed from the Company's invested capital balances in this proceeding.

The Commission expressly reached this conclusion regarding capitalized incentive

compensation in Entergy Texas, Inc.'s ("ETI") rate case in 2012.3° In that rate case, consistent

with prior precedent, the Commission agreed with the ALJs that ETI should not recover financially

based incentive compensation, and therefore, the portion of financially based incentive

compensation that was capitalized should be removed from rate base.31 In applying this holding,

27 Acker v. Texas Water Comm'n, 790 S.W.2d 299, 301 (Tex.1990).

28 OPUC Ex. 1 (Cannady Direct) at 11.

29 Id

" Docket No. 39896, Order on Rehearing at 5 & FOF Nos. 60-63.

31 Id at 5.

6

the Commission disallowed all financially based incentive compensation that had been capitalized

during the period from the end of ETI' s prior test year to the commencement of ETI' s then-current

test year.32

AEP Texas acknowledges that the Commission's precedent includes the disallowance of

financially based incentive compensation that has been capitalized by a utility.33 As discussed

above, the Company's primary position is that the Commission should reverse its precedent.

However, alternatively, if the Commission does not reverse its precedent, AEP Texas asserts that

two time constraints should be applied to the disallowance of capitalized financially based

incentive compensation. First, because the Commission first applied its policy on financially based

incentive compensation to capitalized amounts in November 2012 in ETI' s rate case in Docket

No. 39896, the Company contends that the disallowance of the capitalized amounts should only

extend back to that date.34 Second, as described further in Section VI.B.1. below, the Commission

considered an incentive compensation plan in Southwestern Public Service Company's ("SPS")

rate case in Docket No. 43695 that included an earnings-per-share "funding trigger" and concluded

that a portion of the utility's incentive compensation should be disallowed because the funding

trigger was financially based.35 Based on this prior Commission decision, AEP Texas states that

if the Commission disallows capitalized incentive compensation due to the Company's funding

trigger, then it should do so only back to February 2016 when the Commission issued the final

order in Docket No. 43695.36

However, the Company' s proposed time constraints are not consistent with Commission

precedent and should not be applied in this case. If the Commission had intended to apply its

precedent to capitalized financially based incentive compensation amounts solely on a prospective

basis, it would have done so in the prior rate cases where it addressed this issue, but the

Commission did not do so. For instance, in ETI's rate case in Docket No. 39896, the Commission

removed financially based incentive compensation that had been capitalized since the utility's last

32 Id. at FOF No. 63.

33 AEP Texas Ex. 40 (Hamlett Rebuttal) at 46.

34 AEP Texas Ex. 38 (Talavera Rebuttal) at 9.

35 Application of Southwestern Public Service Co. for Authority to Change Rates, Docket No. 43695, Order on Rehearing at FOF No. 314 (Feb. 23, 2016).

36 AEP Texas Ex. 38 (Talavera Rebuttal) at 9-10.

7

rate case.37 If the Commission had intended to change its practice on a going forward basis, it

would not have made any reduction to the utility's rate base in that proceeding because all of the

disallowed amounts were capitalized prior to the Commission's order in that rate case. Since that

rate case, the Commission has consistently removed capitalized financially based incentive

compensation that is included in rate base after the utility's last rate case.38 This practice is also

appropriate because all rate base additions since the Company's last rate case are subject to review

in a comprehensive base-rate proceeding, such as this one. This rate case is the Commission's

first opportunity to consider the prudence of AEP Texas's rate base additions since the last rate

cases for its predecessor companies in 2006, and only those additions that comply with the

Commission's established precedent should be included in the Company's rate base.

Moreover, the Company's requested time constraints are based on a misconception of the

Commission's recent decisions on financially based incentive compensation. AEP Texas

characterizes the Commission's conclusions in Docket Nos. 39896 and 43695 as changes in

Commission policy.39 However, the Commission simply applied its existing precedent, which was

articulated as early as 2005, to the facts in those rate cases. In particular, Docket Nos. 39896 and

43695 appear to be the first rate cases where the issues of capitalized financially based incentive

compensation and funding triggers, respectively, were litigated by the parties and addressed by the

Commission. The Commission's decisions in the rate cases did not overturn any prior Commission

precedent on capitalized financially based incentive compensation, but rather, applied the

Commission's existing precedent to the facts in those cases. Further, as stated above, the

Commission's precedent is based on its cost-of-service rule, which limits recovery of expenses to

those that are "reasonable and necessary to provide service to the public."49 The Commission

should not approve the recovery of financially based incentive compensation amounts in this

proceeding that do not comply with its cost-of-service rule requirements.

37 Docket No. 39896, Order on Rehearing at FOF No. 63.

38 See, e.g., Application of Southwestern Electric Power Company for Authority to Change Rates, Docket No. 46449, Order on Rehearing at FOF Nos. 132-33 (Mar. 19, 2019).

39 AEP Texas Ex. 38 (Talavera Rebuttal) at 3.

16 TAC § 25.231(b).

8

Accordingly, consistent with the Commission's rules and established precedent, all

financially based incentive compensation that has been capitalized since the Company's last rate

case should be removed from rate base.

H. Capitalized Non-Qualified Pension Plan

As discussed in Section VI.B.2. below, OPUC recommends that AEP Texas's requested

O&M expenses be reduced to remove all SERP-related costs, because the recovery of such costs

is not consistent with Commission precedent.41 However, similar to OPUC's recommended

adjustment to capitalized financially based incentive compensation, it is not sufficient to simply

remove the expense amount. Any capitalized SERP amounts must also be removed. The

Commission has expressly recognized that capitalized SERP costs should be removed from rate

base.42 In such cases, the Commission has removed all SERP costs that were capitalized after the

utility's last base rate case.43 Accordingly, OPUC believes that Commission Staff witness Ms.

Anna Givens's recommendation to remove capitalized SERP expenses since the Company's last

base rate case in 2006 is reasonable and consistent with Commission precedent.44

AEP Texas does not dispute that its requested cost of service includes capitalized SERP

costs.45 The Company's primary contention is that the Commission should change its precedent.

However, as discussed in Section VI.B.2. below, the Company's arguments on this issue have

previously been rejected and should similarly be rejected in this case. Alternatively, the Company

asserts that it is not reasonable to disallow SERP costs from rate base all the way back to June

2006.46 Instead, AEP Texas witness Mr. Randall W. Hamlett states that any adjustment should be

made on a going forward basis, or alternatively, should only be made back to "the date the

Commission's policy changed," which he states was in SWEPCO's rate case in Docket No.

40443.47

41 A SERP is a type of non-qualified pension plan. OPUC Ex. 1 (Cannady Direct) at 52.

42 Docket No. 46449, Order on Rehearing at FOF Nos. 128-31. 43 Id at FOF No. 128.

44 See Commission Staff Ex. 2 (Givens Direct) at 39-40.

45 AEP Texas Ex. 40 (Hamlett Rebuttal) at 41. 46 Id at 43.

47 Id

9

However, as with the capitalized financially based incentive compensation discussed

above, the Commission should reject the application of such time constraints in this case. First,

the proposed time constraints are not consistent with Commission precedent. As with capitalized

financially based incentive compensation, when the Commission has removed capitalized SERP

costs, it has removed all SERP amounts that were capitalized since the utility's last rate case.48

This practice is appropriate because all rate base additions since the Company's last rate case are

subject to review in a comprehensive base-rate proceeding, such as this one. Further, the removal

of capitalized SERP costs was not due to a change in Commission policy, but rather, the

Commission's application of its existing precedent to the specific facts presented in the case. As

discussed in Section VI.B.2., which addresses the Company's expensed SERP costs, the

Commission's precedent is based on its cost-of-service rule requirement that allowed expenses

include only those that are "reasonable and necessary to provide service to the public."49 The

Commission has concluded that capitalized SERP costs do not meet this standard. The

Commission should not approve the recovery of capitalized SERP costs in this proceeding that do

not comply with its cost-of-service rule. Accordingly, consistent with the Commission's rules and

established precedent, all SERP costs that have been capitalized since the Company's last rate case

should be removed from rate base.

V. Rate of Return [PO Issues 8, 9, 11, 12, 13]

OPUC recommends an overall rate of return of 6.17% based on a 9.00% return on equity

("ROE"), 4.28% cost of debt, and capital structure of 60% long-term debt and 40% equity.5°

A. Return on Equity [PO Issue 121

OPUC witness Ms. Anjuli Winker recommended an ROE of 9.00% that is derived from

three models commonly used to estimate a utility's cost of equity: (1) the constant-growth

Discounted Cash Flow ("DCF") model, (2) the Bond Yield Plus Risk Premium model, and (3) the

Capital Asset Pricing Model ("CAPM").51 Ms. Winker relied on the first two models to reach her

" See, e.g., Docket No. 46449, Order on Rehearing at FOF Nos. 128-29.

' 16 TAC § 25.231(b).

" OPUC Ex. 3 (Winker Direct) at 4.

51 Id

10

recommended ROE range.52 Ms. Winker's CAPM results were not directly incorporated into her

final ROE recommendation, but instead served as a qualitative check on the results of the other

two models, showing that a reduced ROE for AEP Texas is appropriate given the continued low

interest rate environment.53 OPUC' s recommended 9.00% ROE also includes Ms. Winker's

consideration of AEP Texas's low business risk as a transmission and distribution utility ("TDU")

operating in Texas.54 The results of her analyses are summarized in the following table:55

Methodology Range Point Estimate

Discounted Cash Flow 6.73%-9.57% 9.10%

Bond Yield Plus Risk Premium 8.94%-9.04% 8.99%

Recommendation 8.90%-9.10% 9.00%

OPUC's recommended 9.00% ROE should be adopted because it is reasonably sufficient to

support the Company's financial health, maintain and support its corporate credit rating, and

enable it to continue to attract invested capital. In support of OPUC's recommendation, below is

a discussion of the current market environment's impact on Ms. Winker's ROE analysis, and the

results of each model that she used to determine the recommended ROE.

1. Current Market Environment

OPUC' s recommended ROE takes into consideration the current low-interest market

environment in which AEP Texas operates. As discussed in Ms. Winker's testimony, while the

federal funds rate was increased in 2017 and 2018, the Federal Open Market Committee

("FOMC") issued a statement on June 19, 2019 announcing its decision to maintain the target

range for the federal funds rate at 2-1/4 to 2-1/2%.56 Moreover, on July 31, 2019, the FOMC

actually reduced the federal funds rate by a quarter percentage point.57 Thus, it appears that interest

" Id at 37-38.

53 Id

54 Id.

55 Id.

56 Id

57 AEP Texas Ex. 42 (Hevert Rebuttal) at 23.

11

rates will continue to remain at low levels for the foreseeable future, and AEP Texas's authorized

cost of equity should reflect this market expectation.

AEP Texas's current corporate credit ratings are considered investment grade by Standard

& Poor's ("S&P") and Moody's Investors Service ("Moody' s").58 Investment grade credit ratings

indicate that the Company has access to capital markets on reasonable terms, has demonstrated the

capacity and capability to meet its financial obligations, and has a stable or low risk of credit

default.59 In particular, S&P Ratings Direct reported that a key strength for AEP Texas is that the

Company is a fully regulated, low-risk electric TDU with a generally stable regulatory framework

in Texas, which S&P Ratings Direct described as "credit supportive."69 Likewise, Moody's

reported that AEP Texas's credit rating reflects

61

2. Discounted Cash Flow Analysis

The DCF model is based on the premise that the current price of a share of stock is equal

to the present value of all future cash flows (i.e., future dividends). The rate at which investors

discount the future dividends represents the riskiness of the future cash flows (i.e., the required

return).62 The DCF analysis looks at three factors: a current stock price, an expected dividend, and

an expected growth rate in dividends.63

Ms. Winker used a constant-growth DCF model, which assumes that dividends grow at a

constant rate.64 Her model incorporates two estimated dividend yields for the proxy group. Ms.

Winker's first estimate of 3.51% used the average high and average low stock prices reported in

the issues of Value Line published on April 26, May 17, and June 14, 2019.65 Ms. Winker's second

58 OPUC Ex. 3 (Winker Direct) at 15. 59 Id

60 Id (citing S&P Global Ratings, Rating Direct, AEP Texas Inc. (Mar. 26, 2019)).

61 Id. (citing Moody's Investors Services, Credit Opinion, AEP Texas Inc. (Sept. 20, 2018) (Confidential)).

62 Id at 20-21.

63 Id at Appendix.

64 Id at 22.

65 Id

12

estimate of 3.34% averaged Value Line's 2019 high and low stock prices with the June 14, 2019

closing stock prices reported by Yahoo Finance.66 Ms. Winker's dividend yield calculation is

consistent with the industry average yields of 3.4%, 3.3%, and 3.3% reported by Value Line on

April 26, May 17, and June 14, 2019, respectively.67

In addition to estimated dividend yields for the proxy group, the DCF model also requires

an estimate of the dividend growth rate expected by investors. The development of the expected

dividend growth rate is the most controversial component of the DCF model, and experts can

reasonably disagree about the importance of various growth rate measures. OPUC recommends

considering the sustainable retained earnings growth rate (i.e., BR growth rate) when estimating a

long-term dividend growth rate.68 Earnings retention rates are the primary source of book value

growth, and book value growth, in turn, is the primary source of sustainable dividend growth. This

is due to the fact that earnings that are not paid out as dividends are reinvested by the utility.69 As

additional plant is funded by retained earnings, the utility is allowed to earn its authorized rate of

return on the additional plant in rate base, which leads to future growth in earnings and dividends."

The BR growth rate helps gauge whether investors' current long-term dividend growth rates can

be sustained in future periods.71 In addition to the BR growth rate, Ms. Winker also considered

Value Line's historical 5-year and 10-year growth in earnings, dividends and book value for the

proxy group as well as Value Line's 5-year projected growth in earnings, dividends and book

value.72

In contrast, AEP Texas witness Mr. Robert Hevert relied entirely on analyst estimates of

projected earnings growth in developing the dividend growth component of his DCF model."

Contrary to Mr. Hevert's approach, when estimating expected dividend growth rates for the proxy

group, it is appropriate to consider historical growth rates, as past performance is often an

66 Id

67 OPUC Ex. 4 (Workpapers to Winker Direct) at 80-82.

68 OPUC Ex. 3 (Winker Direct) at 24.

69 Id. at 21. 70 Id

71 Id

72 Id at 27.

73 AEP Texas Ex. 6 (Hevert Direct) at 57.

13

indication of future performance in a regulated industry like the electric utility industry.74 The

regulatory process results in fewer fluctuations and more stable revenues and earnings for electric

utilities, and as a result, investors attach more significance to the past financial results of these

utilities than for other sectors of the economy.75 Investors do not rely exclusively on a single factor

in making their investment decisions due to the abundance of information available to assist with

the evaluation of stocks. Earnings forecasts are only one of the many statistics they use for making

investment decisions.76 It is neither realistic nor logical to maintain that investors only consider

projected (estimated) data to the exclusion of historic (actual) data because data on historical

growth rates is readily available to investors.

Ms. Winker's review of the proxy group's historical and projected growth rates resulted in

a reasonable growth rate expectation of 3.38% to 6.06%.77 This range incorporates:

• A 2020 BR growth rate calculated by Ms. Winker;

• A 5-year projected BR growth rate;

• Value Line's 5-year and 10-year historical dividend, earnings, and book value

growth; and

• Value Line's 5-year projected dividend, earnings, and book value growth.78

OPUC' s DCF model analysis results in an overall recommended DCF range of 6.73% to 9.57%.79

3. Risk Premium Analysis

The second analysis performed by Ms. Winker estimated AEP Texas's cost of equity using

a bond yield plus risk premium mode1.8° This model is based on the premise that it is riskier to

invest in a company's equity (stocks) than to invest in its debt (bonds).81 As such, this model

calculates a risk premium, which is the additional amount an investor requires as compensation

' OPUC Ex. 3 (Winker Direct) at 25. 75 Id.

76 Id

77 Id at 27. 78 Id at 30-31 and Atts. AW-1 and AW-2. 79 Id. at 27. 80 Id at 30. 81 Id.

14

for assuming the risk of investing in stocks rather than bonds.82 Thus, as the cost of a company's

debt increases, so does the risk premium.83

Ms. Winker began with the data that Mr. Hevert gathered from SNL Financial to calculate

an annual average authorized ROE for regulated electric utility companies." However, instead of

using the average 30-year Treasury yields (including a 200-day lag period) and projected near-

term and long-term 30-year Treasury yields, Ms. Winker used Moody's Average Public Utility

Bond Yields as reported in Mergent Bond Records.85 Public utility bonds are issued in the industry

in which AEP Texas operates; therefore, the bonds provide a more comparable and reasonable

estimate of investor risk premium expectations than 30-year historical and projected Treasury

yields.86

Next, Ms. Winker calculated the difference between the SNL Financial annual average

authorized ROEs from January 2000 to March 2019 and Moody's Average Public Utility Bond

Yields for the same period.87 Using this shorter and more current 18-year time period effectively

captures the trend in authorized ROEs, while remaining long enough to encompass the last two

recessions and the last two periods of economic growth.88 The average risk premium during this

18-year period was 4.67%.89

Finally, Ms. Winker added her risk premium of 4.67% to the average Moody's utility bond

yields, for the same time period, of 4.7% to reach an ROE of 9.04%.9° She also added her risk

premium to the 4.25% Moody's BBB utility bond yield reported on June 14, 2019 to reach an ROE

of 8.94%. Using the resulting ROEs as the upper and lower bounds, Ms. Winker's bond yield plus

risk premium model results in a recommended ROE range of 8.94% to 9.04%.91

82 Id 83 Id

84 Id at 30-31.

85 Id at 31. 86 Id

' Id at 31 and Att. AW-3.

88 Id at 32.

89 Id 90 Id 91 Id

15

AEP Texas witness Mr. Hevert also utilized a bond yield plus risk premium model.

However, Mr. Hevert's analysis has several conceptual problems that result in an inflated risk

premium.92 Mr. Hevert based his analysis on electric utility rate proceedings conducted between

January 1, 1980 and March 15, 2019, which had an average risk premium of 4.67%.93 This amount

is the same risk premium calculated by Ms. Winker with the shorter time period. However,

because Mr. Hevert believed that his calculated risk premium would understate the cost of equity,

he made an upward adjustment of 1.45% to 2.23%, which he states accounts for the inverse

relationship between interest rates and risk premiums.94 The adjustment results in IVIr. Hevert's

recommended ROE range moving upward from an unadjusted 7.70% - 8.72% to 9.93% - 10.17%.95

However, Mr. Hevert's adjustment to account for the inverse relationship between interest rates

and risk premiums was redundant and inflates his results. The 39 years of historical data that Mr.

Hevert used to calculate his risk premium reaches back to 1980 and incorporates various periods

of very high, medium and very low interest rates. Mr. Hevert' s 39-year time period makes it

unnecessary to upwardly adjust his risk premium, because it already incorporates the tendency of

an inverse relationship between interest rates and risk premiums.96

Further, Mr. Hevert's upward adjustment to his 4.67% basic risk premium also does not

recognize that investor-expected risk premiums do not remain constant over time. As noted by

Texas Industrial Energy Consumers ("TIEC") witness Mr. Michael P. Gorman, academic studies

have shown that the relationship between interest rates and risk premiums is influenced by changes

in perception of the risk of bond investments relative to equity investments, and not simply to

changes in interest rates.97 For these reasons, Mr. Hevert's bond yield plus risk premium analysis

should not be considered by the Commission in establishing AEP Texas's cost of equity and the

Commission should instead rely on OPUC and the other intervenors' risk premium analyses for

estimating the Company's cost of equity.

92 Id. at 33-34.

93 AEP Ex. 6 (Hevert Direct) at 68.

94 OPUC Ex. 3 (Winker Direct) at 33; AEP Ex. 6 (Hevert Direct) at 68.

95 OPUC Ex. 3 (Winker Direct) at 33; AEP Ex. 6 (Hevert Direct) at Exh. RBH-5.

96 OPUC Ex. 3 (Winker Direct) at 34.

97 TIEC Ex. 3 (Gorman Direct) at 85-86.

16

4. Capital Asset Pricing Model

OPUC' s third method of estimating the cost of equity for AEP Texas uses the capital asset

pricing model ("CAPM"), which is a model that describes the relationship between risk and

expected return that is used when pricing a security.98 This model is used by Ms. Winker as a

qualitative check and confirms that a reduced ROE for AEP Texas is appropriate given the

continued low interest rate environment.99 Under the CAPM, the cost of equity is estimated as the

sum of the interest rate on a risk-free security plus a market risk premium.m° The yield on long-

term U.S. Treasury bonds is typically used as the risk-free rate, and the market risk premium

represents the investor-expected incentive for holding the stock instead of a risk-free security. Ms.

Winker's CAPM produced an ROE of 8.49%.1°1

Mr. Hevert's CAPM analyses resulted in an ROE range of 8.17% to 12.73%102 but his

CAPM analysis is flawed and should not be given any weight. Mr. Hevert's analysis uses two

market risk premiums that were derived by conducting a DCF analysis for the S&P 500. However,

Mr. Hevert's DCF model for the S&P 500 uses sustainable market growth rates that are too high

to be a rational outlook for sustainable long-term market growth, especially when compared to

historic returns of the market.1°3 Specifically, Mr. Hevert uses sustainable market growth rates of

approximately 11.67% and 14.51%.104 For comparison, Duff & Phelps estimates the actual capital

appreciation for the S&P 500 over the period 1926 through 2018 to have been 5.8% to 7.7%.105

Mr. Hevert's growth rates are also more than two times the U.S. GDP long-term growth outlook

of 4.10%.1°6 Current projected U.S. GDP growth is closer to the 4.0% to 4.5% range.1°7 Because

Mr. Hevert relies on unreasonably high market growth rates when calculating his estimated market

" OPUC Ex. 3 (Winker Direct) at 34.

99 Id. at 36-37.

1' Id at 36. 101 Id

102 AEP Texas Ex. 6 (Hevert Direct) at 9. 103 TIEC Ex. 3 (Gorman Direct) at 78.

1°4 Id.

105 Id. at 79.

106 Id. at 78.

107 Id at 79.

1 7

DCF returns for his CAPM analysis, it produces inflated and unreliable results. Therefore, Mr.

Hevert's CAPM results should not be considered by the Commission in establishing AEP Texas's

cost of equity.

B. Cost of Debt [PO Issue 12]

OPUC witness Ms. Winker did not recommend adjusting AEP Texas's requested long-

term cost of debt of 4.28%.1"

C. Capital Structure [PO Issue 11]

AEP Texas's current Commission-authorized capital structure is 60% debt and 40%

equity.109 In this proceeding, the Company is requesting to increase the amount of equity in its

capital structure by moving to a 55% debt and 45% equity capital structure. As discussed below,

OPUC recommends retaining AEP Texas's current Commission-authorized capital structure of

60% debt and 40% equity.110

The Commission's basis for authorizing a 60% debt and 40% equity capital structure

continues to apply today. The Commission initially set a 60/40 debt-to-equity capital structure for

TDUs in Docket No. 22344, the "generic" docket for TDUs that addressed unbundling of

integrated electric utilities.' The Commission concluded that a 60/40 debt-to-equity capital

structure was appropriate for TDUs, because it found that "favorable market and regulatory

conditions in Texas should result in a lower business risk to Texas TDUs."112 In particular, the

Commission pointed to: (1) complete separation of generation and transmission and distribution

functions, thus virtual elimination of commodity risk; (2) a requirement that retail electric

providers ("REPs") be the point of sales for retail customers; (3) Commission rules to minimize

the impact REP defaults; and (4) existence of the transmission cost recovery factor ("TCRF")

108 OPUC Ex. 3 (Winker Direct) at 44.

1' This capital structure was approved in the last base rate cases for AEP Texas's predecessor companies, AEP TCC and AEP TNC. See Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on Rehearing at FOF Nos. 60-62 (Mar. 4, 2008); Application of AEP Texas North Company for Authority to Change Rates, Docket No. 33310, Order at FOF No. 32 (May 29, 2007).

110 OPUC Ex. 3 (Winker Direct) at 43.

111 Generic Issues Associated with Applications for Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22344, Order No. 42 at 8-11 (Dec. 18, 2000).

112 Id at 10.

18

process "to ensure speedy recovery of transmission expenditures."113 In AEP TCC's most recent

rate case in Docket No. 33309, the Company's capital structure was litigated, and the Commission

retained the 60/40 debt-to-equity capital structure. The Commission concluded that a 60/40 debt-

to-equity capital structure was appropriate for the purpose of setting rates and was consistent with

existing Commission precedent for TDUs and then-current credit rating agency expectations.114

In this proceeding, the Company has failed to demonstrate a need for a larger percentage

of equity in its capital structure. The same factors that the Commission identified in the generic

docket continue to apply to TDUs operating in Texas. TDUs in Texas continue to operate in a

lower business risk environment, which justifies a 60/40 debt-to-equity capital structure.

Moreover, the Commission has adopted additional regulatory mechanisms that further reduce the

risk of regulatory lag that were not available at the time of AEP TCC's and AEP TNC's last rate

cases. These mechanisms include the distribution cost recovery factor ("DCRF"), which was

implemented in 2011,115 and an amendment to the Commission's rules to allow interim updates to

recover transmission investment twice per year instead of once.116 The credit rating agencies

recognize the impact of these interim mechanisms on capital structure. For example, on February

27, 2019, Moody's reported in its credit opinion for AEP that for AEP Texas, the Commission's

regulation of TDUs is viewed as

'117

Given these factors, the Company has not shown that changed circumstances justify

increasing the equity portion of its capital structure. The credit rating agencies continue to view

1" Id

114 Docket No. 33309, Order on Rehearing at FOF Nos. 60-62.

115 Rulemaking Related to Periodic Rate Adjustments, Project No. 39465, Order Adopting New §25.243 as Approved at the September 15, 2011 Open Meeting (Sept. 22, 2011).

116 Rulemaking Proceeding to Amend Subst. R. 25.192(g), Relating to Transmission Service Rates, Project No. 37519, Order Adopting Amendment to §25.192 as Approved at the July 20, 2010 Open Meeting (Aug. 5, 2010).

117 OPUC Ex. 4A (Winker Confidential Workpapers) at 81 (Moody's Investor Service, Credit Opinion, American Electric Power Company, Inc. (Feb. 27, 2019) (Confidential)).

19

TDUs as low risk and regulated in a credit supportive environment, and a 60/40 debt-to-equity

capital structure reflects a reasonably prudent balance sheet during this period of relatively low-

cost debt.118 If the Company's capital structure is weighted more heavily in higher-cost common

equity than is necessary to attract financial capital, the Company's revenue requirement and rates

charged to customers would be unjustly inflated."9 Accordingly, OPUC recommends that the

Commission retain the Company's existing authorized capital structure of 60% debt and 40%

equity.

D. Overall Rate of Return [PO Issue 12]

OPUC recommends an overall rate of return of 6.17%. This recommendation is calculated

by incorporating Ms. Winker's recommended ROE of 9.00%, long-term cost of debt of 4.28%,

and capital structure of 60% debt and 40% equity, as shown in the following table:12°

% of

Capitalization Cost

Weighted Cost

Long-Term Debt 60% 4.28% 2.57% Common Equity 40% 9.00% 3.60%

TOTAL

6.17%

OPUC' s recommendation is an appropriate and reasonable overall rate of return for AEP Texas

that allows the Company a reasonable opportunity to earn a reasonable return on its invested capital

used and useful in providing service to the public in excess of its reasonable and necessary

operating expenses:21 For these reasons, the Commission should adopt an overall rate of return

for AEP Texas of 6.17%.

VI. Operating and Maintenance Expenses [PO Issues 4, 5, 25, 26, 27, 31, 32, 34, 35, 39, 41, 44, 45]

In this section, OPUC recommends adjustments to AEP Texas's requested O&M expenses

for distribution vegetation management, financially based incentive compensation, SERP costs, an

adjustment to the Company's payroll, depreciation of Advanced Metering Infrastructure ("AMI")

118 OPUC Ex. 3 (Winker Direct) at 41.

"9 Id

120 Id. at 44.

121 See PURA § 36.051.

20

meters and communications equipment, self-insurance reserve, and rate case expenses for

proceedings prior to this rate case. For the reasons discussed below, OPUC requests that its

adjustments be adopted.

A. Transmission and Distribution O&M Expenses [PO Issue 25]

3. Distribution Vegetation Management Expense [PO Issue 27]

During the test year, AEP Texas incurred $9.47 million in distribution vegetation

management expenses. However, in this case, the Company proposes to increase this amount by

$5 million, for a total annual expense of $14.47 million.122 As discussed below, OPUC

recommends a more moderate increase over the test-year amount, for a total annual expense of

$10.5 million.

In recent years, aside from 2016, AEP Texas's vegetation management expense has trended

upward as shown in the following table:123

AEP Texas Annual Distribution Vegetation Management Expense

AEP Texas 2013. 2012 2033 2014 2015 2016 2017 2018

Central 2,744 2,720 3,850 6,815 5,763 4,989 8,858 7,808

North 535 920 1,303 2,952 2,717 1,136 1,656 1,658

Total 3,279 3,640 5,153 9,767 8,840 6,125 10,514 9,466

Despite the recent increased spending, AEP Texas has not demonstrated that the $14.47 million

expense amount that it is requesting in this case is reasonable and necessary.124 The Company's

requested expense is 53% higher than the test year, and 38% more than 2017, when AEP Texas

incurred its highest vegetation management expenses.

To determine whether there is a significant problem warranting extra spending by the

Company, OPUC witness Mr. William P. Marcus began by comparing the reliability of AEP Texas

with its affiliated utility in the same geographic region, Southwestern Electric Power Company

("SWEPCO"). To compare the two utilities, Mr. Marcus assessed their System Average

Interruption Duration Index ("SAIDI"), which measures the average outage duration in minutes

122 AEP Texas Ex. 9 (Coad Direct) at 23; OPUC Ex. 5 (Marcus Direct) at 7.

123 OPUC Ex. 5 (Marcus Direct) at 11, Table 2.

124 See PURA § 36.051.

21

for each customer served per year, and System Average Interruption Frequency Index ("SAIFI"),

which measures the average number of outages per customer per year.125 Lower SAIDI and SAIFI

numbers indicate greater reliability.

Mr. Marcus found that between 2011 and 2018, AEP Texas performed more reliably than

SWEPCO with respect to SAIDI caused by vegetation, namely trees and vines.126 For areas

serviced by AEP Texas, the percentage of SAIDI caused by vegetation was lower than the

percentage in SWEPCO's territories.127 Unlike SWEPCO, equipment failure was a larger

percentage cause of SAIDI for AEP Texas than vegetation-related outages.128 Comparing SAIFI

for the two companies also shows greater reliability from AEP Texas. Between 2014 and 2018,

each of SWEPCO's service areas—Texas, Arkansas, and Louisiana—had at least twice as many

vegetation-based outages as AEP Texas.129 The comparison shows that the impact of vegetation

on system reliability was a much greater issue for SWEPCO than for AEP Texas.

Moreover, at both its current expense level and in prior years, the Company has adequately

conducted its tree trimming activities with no adverse effect on reliability. AEP Texas witness

Mr. Thomas Coad reports that power is available to the Company's distribution customers 99.97%

of the time.130 These same AEP Texas customers, on average, experience just over one service

outage per year.131 Thus, given AEP Texas's current reliability, there does not appear to be a

justification for a substantial increase in spending over its test year amounts.

AEP Texas also has not demonstrated that the extra $5 million would be used effectively

for vegetation management. While the number of trees trimmed and removed per thousand dollars

spent was relatively stable through 2016, tree trimmings and removals declined in 2017 and

2018.132 Notably, AEP Texas anticipates spending 38% more on vegetation management than it

125 OPUC Ex. 5 (Marcus Direct) at 7.

126 Id at 9.

127 M.

128 Id

129 Id at 10, Table 1.

130 AEP Texas Ex. 9 (Coad Direct) at 17.

131 Id

132 Id at 12, Table 3.

22

did in 2017, but the Company expects to trim and remove only 10.5% more trees with its extra $5

million budget.133

Additionally, AEP Texas has failed to show that its proposed $5 million increase is a

known and measurable change to its test year expenses.134 The Company has not budgeted for the

increase and is instead projecting lower spending on vegetation management within two years of

the requested increase.135 Given the reduced spending forecasted in 2021, a $5 million annual

increase is not a known and measurable adjustment to the test year vegetation management

expense. While it is understandable that the Company would not budget for the $5 million in 2019,

some movement in that direction would be expected in 2020-21, not a decline in spending in

2021.136

In rebuttal, AEP Texas counters that the increased expense budget is necessary because it

lends support to the Company's goals to modernize the grid and replace infrastructure.137

However, AEP Texas concedes that tree-related reliability is not an urgent need and that the

increase in vegetation management would not ensure improved reliability metrics aside from those

customers on targeted distribution circuits.138

For the reasons discussed above, the Company has failed to demonstrate that an additional

$5 million in vegetation management expense is reasonable and necessary. Instead, OPUC

recommends that the Company be authorized an increase of $1,048,000 over test year levels (i.e.,

$10,514,000) for distribution vegetation management, which is the maximum amount that the

Company has spent in any one year within the last five years. This expense amount also generally

comports with the moderate increase to vegetation management spending projected in the

Company's budget for 2020.139

1" Id. at 12.

134 See 16 TAC § 25.231(b).

135 OPUC Ex. 5 (Marcus Direct) at 12-13.

136 Id at 13. 137 AEP Texas Ex. 45 (Coad Rebuttal) at 12.

138 Id at 9, 12.

139 Id at 14.

23

B. Labor Expenses

In this section, OPUC addresses three recommended adjustments to the Company's

requested labor expenses: (1) disallowance of financially based STI and LTI compensation;

(2) disallowance of SERP costs; and (3) reduction of the Company's proposed payroll adjustment

for salary increases from 3.5% to 3.0%.

1. Incentive Compensation

OPUC recommends adjusting AEP Texas's requested expenses for STI and LTI

compensation to remove all costs associated with financially based performance goals. As

discussed in Section III.F.&G. above, the Commission's precedent is well-established that

incentive compensation based on financial performance measures should not be included in

rates.140 AEP Texas does not dispute that its application includes amounts for financially based

incentive compensation.141 Therefore, the Commission should determine which portions of the

Company's STI and LTI compensation plans are financially based and must be disallowed.

a. Short-Term Incentive Compensation

STI compensation is a component of an employee's total compensation that is generally

intended to motivate the employee to achieve or exceed goals set by the Company.142 AEP Texas

has STI compensation plans that award short-term incentives to employees at AEP Texas and AEP

Service Company ("AEPSC").143 Under the STI compensation plans, the payment of incentives

is first conditioned on the parent company, American Electric Power Company ("AEP"), meeting

an established threshold for its earnings per share.144 If the earnings-per-share threshold is not met

by AEP, then the plan is not funded. If the earnings-per-share threshold or "funding trigger" is

met by AEP, then the payment of incentives is further dependent on whether employees satisfy

goals that are specific to separately identified types of operations within the Company.145 In this

140 For a discussion of the Commission's precedent and why it should not be reversed in the proceeding, please see Section III.F.&G. above.

141 AEP Texas Ex. 40 (Hamlett Rebuttal) at 46, 55. 142 OPUC Ex. 1 (Cannady Direct) at 36.

143 Id. at 36-37 & Att. M (AEP Texas Response to OPUC RFI No. 1-14). 144 Id at 37.

145 Id

24

case, AEP Texas proposes to include $6,053,774 of STI compensation for AEP Texas

employees146 and $5,078,095 for AEPSC employees who provide services to AEP Texas.147

However, a portion of this compensation is awarded based on financial measures, and therefore,

is not recoverable from the Company's ratepayers.

To remove the financially based portion of the STI compensation, the impact of AEP

Texas's earnings-per-share funding trigger must first be considered. The Commission has

addressed STI compensation plans with earnings-per-share funding triggers in two recent rate

cases.148 First, in SPS's rate case in Docket No. 43695, the Commission concluded that such a

funding trigger is financially based. In that case, SPS's entire STI compensation plan was subject

to the funding trigger. Nevertheless, instead of disallowing all of the utility's STI compensation

plan costs because the plan included a financially based funding trigger, the Commission adopted

OPUC's alternative approach to disallow 50% of the total STI compensation expense, which

represented a 50/50 sharing between ratepayers and shareholders.149 The Commission considered

a similar STI compensation plan in SWEPCO's rate case in Docket No. 46449. SWEPCO's STI

compensation plan also included an earnings-per-share funding trigger, but it only applied to 75%

of the plan. In that case, the Commission again concluded that such a funding trigger was

financially based. To calculate the disallowance related to the funding trigger, the Commission

subtracted 50% of the 75% share of the plan subject to the trigger (i.e., 37.5%).150

In AEP Texas's case, 70% of the Company's STI compensation plan is dependent on

achieving earning-per-share targets.151 Given the Commission precedent described above, the first

step to remove the financially based portion of the Company's request is to subtract 50% of the

70% share of the plan subject to the financially based funding trigger (i.e., 35%). OPUC witness

Ms. Cannady used this methodology as the starting point for her calculations.

146 AEP Texas. Ex. 22 (Carlin Direct) at 37.

147 AEP Texas. Ex. 18 (Frantz Direct) at Exhibit BJF-4, page 3.

148 Docket No. 46449, Order on Rehearing at FOF Nos. 194-98; Docket No. 43695, Order on Rehearing at 5-6 & FOF Nos. 83A-85A.

149 Docket No. 43695, Order on Rehearing at 6 & FOF No. 85A; see also Docket No. 43695, PFD at 91 (Oct. 12, 2015).

'5° Docket No. 46449, Order on Rehearing at FOF No. 198; see also Docket No. 46449, PFD at 240-41 (Sept. 22, 2017).

151 OPUC Ex. 1 (Cannady Direct) at 38.

25

Once the effect of the financially based funding trigger is removed, the next step is to

consider whether the specific employee and workgroup performance goals are operational

measures or financial measures. To determine which performance goals are tied to financial

measures requires a review of the components of the Company's STI compensation plan. AEP

Texas's response to Cities RFI No. 6-30 provided the 2018 incentive plans and metrics.152 There

are five plans within the STI compensation plan: distribution plan, support plan, generation plan,

transmission plan, and customer plan.153 These plans are then divided into certain metrics with

percentages assigned to each metric. For example, the distribution plan for 2018 was divided into

the categories of company earnings, expense containment, customer service, safety, and other.154

Within these categories there are various metrics, such as Business Unit or Operating Company

Net Income/Earnings, which is under the "company earnings" category and comprises 10% of the

distribution plan!' This particular goal is tied to financial measures and is the type of

performance goal for which costs should be removed from the Company's cost-of-service. Based

on Ms. Cannady's review of the performance goals for AEP Texas, she recommended the

following disallowances for STI compensation awarded based on financial metrics:156

Table 3: Additional STI Percentage Awards Based on Financial Metrics

Percentage Based on Financial Metric STI Plan Type Description of Metric

10% Distribution Plan Business Unit or Op. Co. Net Income/Earnings

10% Distribution Plan Economic Development: Op. Co. Net Revenue

9.387% Exec./Support Plan AEP Operating Earnings-per-Share

9.53% Exec./Support Plan Business Unit or Op Co. Net Income/Earnings

5% Generation Plan Regulatory Cost Recovery

20% Transmission Plan Business Unit or Op. Co. Net Income/Earnings

15% Transmission Plan Transmission Business Expansion, Cap. Investment

5% Chief Customer Officer Economic Development: Op. Co. Net Revenue

152 Id. at Att. P, Bates p. 221.

153 Id. For each table, the specific plan is identified in the upper left-hand corner.

154 Id at Att. P, Bates pp. 223-25 (AEP Texas Response to Cities 6-30, Att. 1 at pp. 43-45). The categories are listed in the top row of the table.

155 Id

156 Id at 46, Table 3.

26

As shown in Schedules CTC-7A and CTC-7B of Ms. Cannady's testimony, she removed the

amounts tied to these metrics from the 30% portion of the STI compensation plan that was not

subject to the funding trigger.

In addition, in adjusting AEP Texas's STI compensation, Ms. Cannady used the per books

expense. As she noted, the targeted amounts for the Chief Customer Officer ("CCO") plan for

both the Central and North Division employees and the Transmission Plan for North Division

employees were greater than the per books expense, because AEP Texas increased the amounts

over per book to meet 100% of the target awards.157 This adjustment is inappropriate because AEP

Texas's proposal requests that ratepayers pay for STI compensation that the Company did not

award since the performance measures were not met by the employees. Accordingly, Ms.

Cannady's use of the per books amounts is the correct approach. On a consolidated basis, Ms.

Cannady recommends an STI compensation expense of $3,142,493 for retail and an STI

compensation expense of $373,508 for transmission. This recommended STI compensation

expense represents approximately 58.1% of the Company's requested $6,053,774 STI

compensation expense for AEP Texas.

OPUC also recommends similar adjustments for the AEPSC STI compensation expense.

These employees are likely under the Executive/Support Plan, so Ms. Cannady based her

disallowances on those metrics. As shown in Schedule CTC-7C of her testimony, she first split

the portion of the plan that was subject to the funding trigger 50/50 between customers and the

Company. She then removed the same 19.4% for financially based metrics that she removed from

the Executive/Support plan as noted above for the divisional STI compensation computations.158

Based on these adjustments, her recommended reduction to the AEP Texas combined amount of

AEPSC STI compensation expense is $1,917,588 as shown on Schedule CTC-7C.159

b. Long-Term Incentive Compensation

AEP Texas has two types of LTI compensation, a performance-based plan and a restricted

stock plan. AEP Texas is requesting performance-based LTI compensation for its AEP Texas

'' Id. at 47.

158 OPUC Ex. 1 (Cannady Direct) at 48.

159 Id.

27

employees of $414,002 and for AEPSC employees of $1,836,460.160 The Company's per books

restricted stock expense is $132,429 for AEP Texas employees and $644,538 for AEPSC

employees!61 Therefore, AEP Texas's proposed total LTI compensation-related O&M expense

is $3,027,429. As discussed below, OPUC recommends the disallowance of all performance-

based LTI compensation awarded to AEP Texas and AEPSC employees and all restricted stock

awarded to AEPSC employees.

As to the performance-based plan, AEP Texas witness Mr. Andrew Carlin indicates that

the Company provides performance units, which are generally similar in value to shares of AEP

common stock, except that participants must generally continue their AEP employment over a

three-year period to earn a payout and the number of performance units that participants ultimately

earn is tied to AEP's long-term performance. Based on Mr. Carlin's description, the payout of the

performance units is tied to the interests and financial success of AEP and its shareholders, which

indicates that the payout is based on achieving financial measures, not operational measures. The

Commission reached this same conclusion regarding performance units in a previous rate case for

SWEPCO, which is an affiliate of AEP Texas. In that rate case, the Commission concluded that

long-term incentive awards in the form of performance units relate to financial measures and

should be disallowed!62 Consistent with this Commission precedent, AEP Texas's request to

recover the costs for the portion of its LTI compensation plan comprised of performance units

should be rejected and these costs should be disallowed.

As to the restricted stock plan, OPUC recommends that the Commission disallow the

portion of the plan for restricted stock awarded to AEPSC employees. While the Commission

previously found that SWEPCO's restricted stock plan was not financially based and was

allowable in rates, the Commission's finding did not address whether the restricted stock awards

for AEPSC were necessary to provide reasonable and reliable service in Texas, or necessary to

attract and retain employees!' OPUC believes that distinguishing between AEP Texas employees

and AEPSC employees is appropriate in this context. AEPSC employees are charged with

160 Id at 49-50.

161 M. at 50.

162 Application of Southwestern Electric Power Company for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 40443, Order on Rehearing at FOF Nos. 219-20.

163 OPUC Ex. 1 (Cannady Direct) at 51 (citing Docket No. 46449, Order on Rehearing at FOF No. 199).

28

providing service to multiple operating companies, and therefore, have performance goals that

may be very different from the goals of the local operating company, AEP Texas.164 These

employees also do not regularly interface with AEP Texas's customers. Therefore, AEP Texas

ratepayers should not be responsible for LTI compensation to AEPSC employees. This distinction

is also supported by a 2017 Railroad Commission of Texas determination that LTI compensation

should only be included for direct employees, and not those providing centralized services.165

In total, OPUC's recommended disallowances for the performance-based plan and

restricted stock plan result in a reduction to AEP Texas's proposed O&M expense of

$2,895,001.166 The recommended adjustment includes an adjustment to AEP Texas retail O&M

of $2,435,817 and an adjustment to AEP Texas transmission O&M of $459,184.

2. Executive Employee Related Expenses (non-qualified pension plans)

AEP Texas is requesting to recover SERP expenses of $257,682 incurred directly by the

Company for its Central and North Divisions and an additional $459,076 allocated to the

Company's divisions by AEPSC, for a total of $716,758.167 However, as discussed below, the

Company's request to recover these costs is contrary to Commission precedent and should be

denied. Accordingly, all SERP-related costs should be excluded from rates, including costs that

have been capitalized (as discussed in Section III.H. above) and costs that have been expensed. In

this section, OPUC addresses the SERP-related costs that the Company expensed.

The term SERP typically refers to a supplemental executive retirement plan that provides

the means by which a company's executive team and management can receive additional pension

benefits that would not otherwise be allowed under the defined pension plans available company-wide.168 These plans are established because a company has a limit as to how much retirement it

can provide and deduct for tax purposes under ERISA.169 Because pension benefits are tied to

compensation, highly paid employees will be awarded pension benefits that may be greater than

164 Id at 50.

1' Id at 51.

166 Id at 50.

167 Staff Ex. 2 (Givens Direct) at 24, Table AG-4.

168 OPUC Ex. 1 (Cannady Direct) at 51-52.

169 ERISA refers to the Employee Retirement Income Security Act of 1974.

29

the amounts deductible for income tax purposes. Therefore, companies establish an unfunded plan

for these additional executive benefits.

The Commission has historically disallowed SERP expenses. A utility may only recover

expenses that are "reasonable and necessary to provide service to the public."1" As with

financially based incentive compensation, as discussed above, the Commission has concluded that

SERP expenses do not meet this standard because these expenses predominantly benefit a utility's

shareholders rather than its customers. The Commission reached this conclusion in ETI' s rate case

in Docket No. 39896 in 2012, finding that:

140. ETI provides non-qualified supplemental executive retirement plans for highly compensated individuals such as key managerial employees and executives that, because of limitations imposed under the Internal Revenue Code, would otherwise not receive retirement benefits on their annual compensation over $245,000 per year.

141. ETI' s non-qualified supplemental executive retirement plans are discretionary costs designed to attract, retain, and reward highly compensated employees whose interests are more closely aligned with those of the shareholders than the customers.

142. ETI's non-qualified executive retirement benefits in the amount of $2,114,931 are not reasonable or necessary to provide utility service to the public, not in the public interest, and should not be included in ETI' s cost of service.171

The Commission recently reached the same conclusion in 2018 for SWEPCO, an affiliate of AEP

Texas.172

AEP Texas witness Mr. Hamlett acknowledges the Commission's precedent, but

nevertheless, asserts that SERP expenses should be recoverable.173 However, as support for his

position, Mr. Hamlett raises the same arguments that he previously raised in SWEPCO's last rate

case and that the Commission rejected.174 Specifically, he states that all retirement benefits are

deductible for tax purposes and that the Internal Revenue Code simply results in a timing

170 16 TAC § 25.231(b).

171 Docket No. 39896, Order on Rehearing at FOF Nos. 140-42.

172 Docket No. 46449, Order on Rehearing at FOF Nos. 203-04.

173 AEP Texas Ex. 40 (Hamlett Rebuttal) at 41.

174 See Docket No. 46449, PFD at 248.

30

difference for when they are deductible. Further, he contends that SERP is not an additional or

unreasonable benefit provided only to executives.175 However, as he discusses, the SERP only

applies to compensation levels that exceed the amount that can be deducted for tax purposes for

qualified pension plans, which is $280,000 in 2019.176 Thus, the SERP applies only to highly paid

employees making over $280,000. Moreover, Mr. Hamlett's arguments have already been rejected

by the Commission. As the proposal for decision ("PFD") in SWEPCO's last rate case stated:

SWEPCO contends that the line of decisions disallowing SERP expenses are based on a faulty understanding of the IRS Code, thereby leading the ALJs and Commission to believe that these SERP expenses are somehow extraordinary and unnecessary. On the contrary, the Commission disallowed SERP expenses in past cases not because of a misunderstanding of tax deduction timing differences in the IRS Code, but rather, because in the case of an executive making $270,000 and above, it is reasonable to expect shareholders, not ratepayers, to pay for SERP expenses.177

The basis for the Commission's precedent has not changed. Accordingly, the Company's request

to recover SERP expenses in this proceeding should be denied.

3. Payroll Adjustments

AEP Texas seeks a $5.6 million increase to its payroll expense to include a proposed pay

raise of 3.5% for the Company's direct employees and AEPSC's employees. For direct employees,

AEP Texas applied its proposed pay raise of 3.50% to annualized base payroll amounts from

December 2018 for its Central and North Divisions. For AEPSC employees, the Company

annualized base payroll from November 2018 and applied the 3.50% proposed raise.178 AEP

Texas's computations result in increases to O&M expense of $1,654,190 for its Central Division,

$300,270 for its North Division, and $3,656,917179 for AEPSC payroll charged to AEP Texas.189

However, as discussed below, the Company has failed to demonstrate the reasonableness of a 3.5%

175 AEP Texas Ex. 40 (Hamlett Rebuttal) at 42.

176 Id. at 41.

177 Docket No. 46449, PFD at 251.

178 OPUC Ex. 1 (Cannady Direct) at 33; see Attachment H, AEP Texas Response to OPUC RFI No.7-4.

179 OPUC witness Ms. Cannady's direct testimony contains a typographical error for the AEPSC payroll amount. The amount used in this brief is the amount identified by the Company. See AEP Texas Ex. 18 (Frantz Direct) at Exhibit BJF-4, page 1.

180 OPUC Ex. 1 (Cannady Direct) at 33 (citing AEP Texas Ex. 3 (Hamlett Direct) at Exhibit RWH-2); AEP Texas Ex. 18 (Frantz Direct) at Exhibit BJF-4, page 1).

31

pay raise. Based on the record evidence, OPUC recommends using a 3.0% increase instead of a

3.5% increase to compute the payroll adjustment.

Market information concerning 2019 wage increases supports a 3.0% increase, but not a

3.5% increase. As OPUC witness Ms. Cannady testified, a review of market information shows

that in 2019 salary raises for all employment sectors averaged right at 3%, with reported pay

increases ranging between 2.8% and 3.1%.181 Notably, the energy and utilities sector reported

lower wage growth in both the first and second quarter of 2019 than in the last quarter of 2018.182

In addition, the direct testimony of AEP Texas witness Mr. Carlin shows that, in the energy

services industry, 2019 salaries will rise 3% on average for non-exempt, exempt, and executive

employees.183 The use of a 3% wage increase is also supported by CenterPoint Energy Houston

Electric, LLC's pending rate case in Docket No. 49421, which requests a 3% wage increase for its

employees in 2019.184

In rebuttal, Mr. Carlin argues that AEP Texas's base wage increases are behind the industry

average due to a company-wide base wage freeze in 2009 in response to the Great Recession that

began in 2008.185 He asserts that AEP Texas's base wages should be allowed to catch up to

competitive wages.186 However, the Company has the burden of proof to show that its requested

payroll adjustment is reasonable and necessary to provide service to the public.187 While Table

ARC-1 in Mr. Carlin's direct testimony shows that wage increases for the period from 2009 to

2019 lag the industry average, he does not explain why the Company was more strongly impacted

by the Great Recession than other utilities in the industry. The table also uses the industry average,

so there will be some utilities with higher wage increases and some with lower wage increase.

Wage increases that are slightly behind the industry average are not inherently unreasonable. In

addition, Mr. Carlin's analysis may be impacted by the time period he selected, which begins with

181 OPUC Ex. 1 (Cannady Direct) at 34. 182 m

183 AEP Texas Ex. 22 (Carlin Direct) at 10.

184 OPUC Ex. 1 (Cannady Direct) at 34 (citing Application of CenterPoint Energy Houston Electric, LLC for Authority to Change Rates, Docket No. 49421, Application at Bates 1849 (pending)).

185 AEP Texas Ex. 51 (Carlin Rebuttal) at 3.

186 Id at 3-4.

187 PURA §§ 36.006, .051; 16 TAC § 25.231(b).

32

a salary freeze. Mr. Carlin's table does not extend further back than 2009, so it is not clear whether

the Company's wage increases lag the industry average over a longer period, such as since AEP

Texas's predecessor companies' last rate cases in 2006. Notably, using any period shorter than

the one selected by the Company would not show that the Company's wage increases lag the

industry average for non-exempt salaried and exempt employees, and any period from 2011

forward would not show a lag for executives.188 Accordingly, AEP Texas has failed to demonstrate

that it is reasonable and necessary to include a 3.5% wage increase in rates, rather than the expected

industry average of 3.0%.

To reflect a 3.0% increase rather than a 3.5% increase, OPUC witness Ms. Cannady

calculated a reduction of $217,860 to AEP Texas's proposed base payroll expense.189 As shown

in Schedule CTC-6 to her direct testimony, Ms. Cannady applied the industry-average 3% increase

to the Company's adjusted annualized base pay for the Central and North Divisions and AEPSC.

Schedule CTC-6A and Schedule CTC-6B provide calculations for the Central and North Divisions,

respectively, and Schedule CTC-6C provides the calculation for AEPSC. Ms. Cannady calculates

a $173,761 adjustment for AEP Texas retail distribution and a $44,100 adjustment for

transmission!"

C. Depreciation and Amortization Expense [PO Issue 31]

1. Advanced Metering Infrastructure ("AMI") Meters and Communications Equipment

In this case, AEP Texas has not proposed to update its depreciation rates for AMI meters

(Account 370.16) and AMI communications equipment (Account 397.16) (referred to collectively

as "AMI plant").191 The current depreciation rate for AEP Texas's AMI plant is 14.29% of gross

plant per year, which reflects a seven-year depreciable life. However, if that depreciation rate

remains in place, it will result in significant over-depreciation of the AMI plant by the next rate

case, which would result in an over-recovery by the Company of its costs for the AMI plant. As

188 AEP Texas Ex. 22 (Carlin Direct) at 10, Table 1.

1" See OPUC Ex. 1 (Cannady Direct) at Schedule CTC-6.

190 Id

191 AEP Ex. 16 (Cash Direct) at 11-14.

33

discussed below, OPUC recommends adjusting the depreciation rate to avoid this result and to

reflect that the AMI plant is expected to have a longer depreciable life than seven years.

As discussed by OPUC witness Mr. Marcus, leaving AEP Texas's current depreciation

rates in place for AMI plant will result in significant over-depreciation of the AMI plant by the

next rate case. The net book value of all of the AMI plant Company-wide was $47,825,741 at the

end of 2018.192 Using the existing depreciation rate, the amount of depreciation charged against

that plant is $31,695,905 per year.193 Therefore, the AMI plant will be fully depreciated in an

average of 1.51 years.194 AEP Texas is only required to file a base-rate proceeding every four

years under the Commission's rate review schedule.195 If the Company's position is adopted and

it files its next rate case in four years, the Company will collect $158.5 million in depreciation

expense for a beginning book value of $47.8 million.196 Collecting $158.5 million in depreciation

expense for $47.8 million of existing plant constitutes significant over-depreciation. Over-

depreciation, at best, creates generational inequities by making current ratepayers pay for more

depreciation than the plant requires.197 Even worse, AEP Texas could potentially stop depreciation

of the AMI plant and simply divert the unnecessary depreciation expense (after paying taxes) to

return on equity between rate cases.198 Therefore, the Commission should prevent over-

depreciation of the AMI plant and ensure that ratepayers do not overpay for the AMI plant.

Retaining a depreciable life of seven years for the AMI plant is also not justified given the

current service life expectations for the plant. As Mr. Marcus testified, AMI plant life is likely to

be longer than seven years.199 AEP Texas also confirmed that it does not expect to undertake a

mass replacement of AMI meters at the end of seven years.20° While a large number of the

192 OPUC Ex. 5 (Marcus Direct) at 15, Table 6. 193 Id.

194 Id. 195 16 TAC § 25.247(c).

196 As Mr. Marcus noted, these figures could change somewhat due to retirements and plant additions after January 1, 2019, but those costs are likely to be small relative to the gross plant installed before the end of 2018. OPUC Ex. 5 (Marcus Direct) at 16.

197 Id at 16-17.

198 Id at 17.

199 Id. at 18.

NCI Id at 18 & Exhibit WM-8 (AEP Texas Response to OPUC RFI No. 8-5).

34

Company's AMI meters have been replaced since their installation date, these meters have been

replaced under warranty.201 Moreover, in his rebuttal testimony, AEP Texas witness Mr. Jason

Cash agreed with intervenor witnesses that "the average service life for this type of equipment is

estimated to be 15 years based on the recommendations from the equipment manufacturers."202

He has also testified to that effect in Indiana and Michigan on behalf of Indiana Michigan Power

Company.203

Yet despite agreeing that AMI plant has a longer average service life than seven years, Mr.

Cash contends that the Company is bound to use that time period by Commission rule and order.

In particular, he cites the Commission's rule that applies to advanced metering system ("AMS")

surcharge proceedings, which states: "In the request for surcharge proceeding, an electric utility

may propose a surcharge methodology, but the commission prefers the stability of a levelized

amount, and an amortization period ranging from five to seven years, depending on the useful life

of the meter."204 Mr. Cash also cites the Commission's order in Docket No. 36928, which

approved a settlement authorizing the Company to implement an AMS surcharge based on a seven-

year depreciation period.205

However, the Commission is not required to retain the seven-year depreciable life for the

AMI plant in perpetuity. The Commission's rule quoted above applies to AMS surcharge

proceedings. This case is a base-rate proceeding in which AEP Texas is proposing to eliminate its

AMS surcharge and move all of its AMI plant costs into base rates.206 Therefore, Commission's

AMS surcharge rule does not apply. In addition, the Commission's order in the Company's

surcharge proceeding does not bind the Commission in this case. It is not uncommon for utilities

to update the service lives of plant items in subsequent proceedings based on the facts as they exist

at the time. For instance, in this case, the Company proposes to update several service lives since

201 Id. at 18 & Exhibit WM-9 (AEP Texas Response to OPUC RFI No. 8-2 (Confidential)).

202 AEP Texas Ex. 48 (Cash Rebuttal) at 6.

2°3 Id

2" Id at 5 (citing 16 TAC § 25.130(k)(3)).

205 Id (citing AEP Texas Central Company's and AEP Texas North Company's Request for Approval of Advanced Metering System (AMS) Deployment Plan and Request for AMS Surcharges, Docket No. 36928, Order (Dec. 17, 2009).

206 AEP Texas Ex. 2 (Strahler Direct) at 7.

35

the last rate cases for its predecessor companies.207 In fact, Mr. Cash states that if he did not

believe he was constrained by the Commission's rule and prior order, he would have performed

an analysis as part of his depreciation study and would have considered updating the depreciation

rates for the AMI plant accounts (Accounts 370.16 and 397.16).208

Therefore, a change to the depreciation rates is warranted given that a seven-year

depreciable life for the AMI plant results in significant over-depreciation, is not consistent with

the expected average service life for the plant, and is not required by Commission rule or order.

OPUC proposes depreciating the remaining net AMI plant in the Central and North Divisions'

Accounts 370.16 and 397.16 over five years (the period between rate cases plus one year), so that

existing plant is fully recovered but not significantly over-depreciated.209 This method is similar

to the remaining-life methods used on other depreciable plant, but with the pragmatic effect of

trying to prevent or reduce over-depreciation.21° As shown in Table 7 of OPUC witness Mr.

Marcus's direct testimony, using this approach results in depreciation rates of 4.39% for the

Central Division and 3.40% for the North Division for Account 370.16, and 6.55% for the Central

Division and 2.47% for the North Division for Account 397.16.211 The average depreciation rate

is 4.31%, but varies by type of AMI plant (meters or communications equipment) and by division.

The result is a reduction of depreciation expense of $22,130,857 from $31,695,905 to

$9,565,048.212

Commission Staff and Cities both propose a 15-year depreciable life for the AMI plant,

and a depreciation rate of 6.67%,213 which yields depreciation expense of $14,794,380,214 about

$5.2 million more than OPUC' s recommendation. While this rate reflects the expected life of AMI

207 AEP Texas Ex. 16 (Cash Direct) at Exhibit JAC-1, p. 21 (comparing depreciation expense using currently approved rates and depreciation study rates). Notably, only three accounts do not show different rates, two of which are the accounts for AMI meters (Account 370.16) and AMI communications equipment (Account 397.16).

208 AEP Texas Ex. 48 (Cash Rebuttal) at 8.

209 OPUC Ex. 5 (Marcus Direct) at 19.

21° Id.

2 11 OPUC Ex. 5 (Marcus Direct) at 19, Table 7. 212 Id.

213 Cities Ex. 5 (Hughes Direct) at 14-22; Commission Staff Ex. 4 (Tuvilla Direct) at 10-17.

214 A rate of 6.67% of gross plant of $221,804,795 (OPUC Ex. 5 (Marcus Direct) at 19, Table 7) yields $14,794,380 per year.

36

meters as estimated by AEP Texas witness Mr. Cash, it does not fully address the over-depreciation

issue, as their higher depreciation rate will collect more than the current net AMI plant before the

Company's next rate case.215 Thus, while Commission Staff and Cities' proposal is a significant

improvement over the Company's seven-year depreciable life, it does not do enough to minimize

over-depreciation. Accordingly, OPUC requests that its depreciation parameters be adopted.

E. Self-Insurance Reserve Expense [PO Issues 20, 39]

AEP Texas self-insures against storm-related property loss impacting its transmission and

distribution assets, rather than buying third-party commercial insurance. Under the Commission's

rules, annual accruals to the utility's self-insurance plan are credited to reserve accounts.216 The

annual accrual to the storm reserve is based on a reasonable amount to cover average annual storm

events.217 An additional amount may be included in rates to reach a reserve target balance for

unforeseeable catastrophic storm events that are greater than the annual average.218

In this proceeding, AEP Texas seeks: (1) to increase its authorized annual accrual for storm

losses from $1,300,000219 to $4,272,161, and (2) to increase its currently authorized maximum

reserve balance from $13,000,000 to $13,300,000.220 The requested annual accrual includes

average annual storm expenses of $2.35 million for the Central Division and $550,000 for the

North Division.221 In addition, to establish the new target reserve balance, the requested annual

accrual includes $472,161 for the Central Division and $900,000 for the North Division for each

of the next three years.222 As discussed below, OPUC recommends adjustments to both the annual

accruals for storm expenses and the target reserve balance.

215 Adding $31,695,905 in depreciation for 2019 plant before the rate case takes effect (from OPUC Ex. 5 (Marcus Direct) at 19, Table 7) and $14,794,380 for four years yields a depreciation recovery of $90,873,425 versus $47,825,241 in net plant (Id.).

216 16 TAC § 25.231(b)(1)(G).

217 OPUC Ex. 1 (Cannady Direct) at 54. 218 m

219 See Application of AEP Texas Central for Authority to Change Rates, Docket No. 33309, Order on Rehearing at Conclusion of Law ("COL") No. 28 (Mar. 4, 2008).

229 OPUC Ex. 1 (Cannady Direct) at 54.

221 Id

222 Id at 54-55.

37

OPUC first addresses its adjustment to the annual accruals for storm expenses. The

Company's recommended annualized storm damages of $2,350,000 for the Central Division are

significantly higher than its past average storm expenses.223 The Central Division averaged less

than $1.9 million in storm expenses over the past five years, and less than $1.6 million over the

past 10 years.224 The Company's requested amount is significantly impacted by AEP Texas

witness Mr. Gregory Wilson's inclusion of unusually high trended storm costs in 2008 of

$33,773,605. This amount exceeded any other year's qualified expenses by more than $25

million.225 Including this outlier in the average annual storm damages unreasonably inflates AEP

Texas's storm expenses. Instead, OPUC witness Ms. Cannady recommends using the average

storm damages from the last five years to provide a more accurate measure of the Company's

eligible annual storm expenses.226 This adjustment results in annual storm expense accruals of

$1,855,158 for the Central Division. As discussed in Ms. Cannady's testimony, OPUC does not

contest the Company's proposed annual storm expense accrual for the North Division.227

In rebuttal, AEP Texas witness Mr. Wilson disagrees with using a five-year average to

calculate annual storm damages for the Central Division.228 Mr. Wilson contends that it is

inconsistent with the 20-plus-year average historically used in insurance ratemaking and that

excluding the unusually high 2008 storm costs is contrary to the purpose of the self-insurance

reserve balance, which is to allow AEP Texas to accrue amounts that will cover unexpected storm

damages.229 However, a five-year average period is more reasonable in this case. With the

Commission's recent adoption of a rate review schedule for TDUs in ERCOT, the Company's cost

of service will be reviewed at least every four years.23° This regular review will allow for more

frequent adjustments to the Company's storm reserve accruals, to the extent necessary. A five-

year average period is more closely aligned with the four-year rate review schedule than a 20-year

223 Id. at 55.

224 See AEP Texas Ex. 4 (Wilson Direct) at Exhibit GSW-3a.

225 See OPUC Ex. 1 (Cannady Direct) at 54 (citing AEP Texas Ex. 4 (Wilson Direct) at Exhibit GSW-3a).

226 Id at 56. 227 Id

228 AEP Tex. Ex. 41 (Wilson Rebuttal) at 4-5.

229 Id

230 See PURA § 36.212(b)(1).

38

or more average period. In addition, for extraordinary storm damages, AEP Texas has the ability

to securitize its storm restoration costs,231 which the Company has recently done for its Hurricane

Harvey costs.232 Accordingly, OPUC's recommended five-year average period is reasonable and

should be adopted.

OPUC next addresses its adjustment to AEP Texas's request to increase its target reserve

balance. For the North Division, the Company's request for additional storm reserve beyond the

average annual storm-related expense of $550,000 that the Company requested should be denied.

The North Division experienced major storm damages in only three of the last 14 years, and only

one of the past five years.233 The average trended cost (2018 dollars) for the three major storms is

$2.73 million.234 AEP Texas requests $550,000 in annual storm expenses for the North Division,

which equates to $2.75 million for the next five years.235 Because the North Division had only

one major storm in the past five years, the annual storm expense should cover major storm losses

for this region.236

For the Central Division, OPUC does not challenge the total additional amount requested

by the Company to achieve its target reserve, but the Company should accrue its target reserve

over a 10-year period instead of the proposed three-year period.237 The time period for restoring

the target reserve must balance the interests of both customers and the utility. Using a three-year

time period, as proposed by the Company, is unnecessary and would fail to account for the

significant impact on customer rates. As stated above, under the Commission's rate review

schedule, AEP Texas must file a rate case at least every four years.238 To the extent that the target

reserve needs to be adjusted, it can be done in the Company's next rate case. In addition, the

Commission has supported longer accrual periods for target reserve balances, including a 20-year

231 PURA §§ 36.401-.403. 232 Application of AEP Texas Inc. for a Financing Order to Securitize System Restoration Costs, Docket No.

49308 (June 17, 2019).

233 OPUC Ex. 1 (Cannady Direct) at 56.

234 Id :

235 Id.

236 Id. (citing AEP Texas Ex. 4 (Wilson Direct) at Exhibit GSW-3b).

237 Id. 56-57.

238 See PURA § 36.212(b)(1).

39

period for ETI.239 Using a 10-year period for AEP Texas's Central Division results in an additional

annual accrual for the division of $141,648, instead of the Company's proposed $472,161.240

In total, OPUC's recommended adjustments to the storm reserve annual accruals result in

a $1,725,355 reduction to AEP Texas's proposal. This reduction is comprised of: (1) an annual

storm expense accrual of $1,855,158 for the Central Division, rather than the Company's requested

$2,350,000 (a difference of $494,842); (2) the removal of the Company's proposed additional

annual accrual of $900,000 for the North Division target balance; and (3) an additional annual

accrual of $141,648 for the Central Division target balance, rather than the Company's requested

$472,161 (a difference of $330,513).

I. Rate-Case Expenses from previous proceedings

AEP Texas's application requested to recover rate case expenses for this proceeding and

eight prior dockets.241 The Company estimates that its rate case expenses will be approximately

$6.3 million for this docket and approximately $1 million for the earlier cases.242 In SOAH Order

No. 2, the ALJs established a new docket (Docket No. 49556) to address rate case expenses, but

stated that the PFD in this proceeding would address which docket is appropriate to address the

method to recover the reasonable rate cases expenses incurred in the eight prior dockets.243

OPUC recommends that the Commission divide rate case expenses into two groups when

considering how these costs should be recovered.244 The first group includes large rate cases, like

base-rate proceedings and fuel reconciliation proceedings. For these cases, OPUC believes that

riders remain a reasonable means to recover costs.245 The second group includes more routine rate

cases, such as TCRFs and DCRFs. For these cases, OPUC believes that it is appropriate to

239 Docket No. 39896, Order at FOF No. 157.

240 OPUC Ex. 1 (Cannady Direct) at 57. 241 AEP Texas Ex. 2 (Strahler Direct) at 37. The prior proceedings are three base rate cases (Docket Nos.

28840, 33309, and 33310), a rate-case-expense proceeding (Docket No. 34301), an AMS reconciliation (Docket No. 40261), two DCRFs (Docket Nos. 47015 and 48222), and a system-restoration-costs proceeding (Docket No. 48577).

242 AEP Texas Ex. 2 (Strahler Direct) at 34, 38.

243 SOAH Order No. 2 at 6 (May 21, 2019).

244 OPUC Ex. 5 (Marcus Direct) at 20.

245 Similar treatment is provided for rate case expenses in Energy Efficiency Cost Recovery Factor ("EECRF") cases. 16 TAC § 25.182(d)(3).

40

normalize the rate case expenses using a historic average to develop a representative test year.246

These rate case expenses would no longer be recovered through riders, but instead would be part

of a utility's base rates as an O&M expense.247 This treatment is appropriate because rate case

expenses for routine rate cases are essentially O&M expenses.248 Utilities already recover certain

legal expenses as O&M expenses,249 and rate case expenses for routine cases can reasonably be

included as well.

OPUC excludes rate case expenses for base rate cases and fuel reconciliation cases for two

reasons. First, the majority of expenses for base rate cases are incurred after the test year, and

consequently, these costs will not be included in test-year costs.250 To include the costs of a

pending base rate case as a known and measurable expense requires estimating expenses after the

close of the evidence, or reviewing rate case expenses in a later proceeding.251 Second, base rate

cases and fuel reconciliation cases cover more issues of greater complexity—at a greater

expense—than limited proceedings like TCRF and DCRF cases.252 As a result, including base rate

case costs in test year expenses for recovery in rates would not represent test year expenses and

would distort the Company's revenue requirement.253

In rebuttal, the Company disagrees with OPUC' s approach to include a normalized amount

of rate case expenses in base rates. AEP Texas witness Ms. Leigh Anne Strahler states that the

Commission does not limit rate-case-expense recovery to comprehensive base rate cases.254 Ms.

Strahler adds that AMS Reconciliation, DCRF, and System Restoration proceedings are periodic

in nature, unevenly distributed through a range of years, and not necessarily indicative of future

246 OPUC Ex. 5 (Marcus Direct) at 20. 247 Id

248 Id

249 For example, in this case, AEP Texas is seeking to recover certain legal expenses in FERC Account 923 for outside services. AEP Ex. 33B (AEP Texas Central Division Schedules) at Sch. II-D-2.7; AEP Ex. 33C (AEP Texas North Division Schedules) at Sch. II-D-2.7.

250 Id

251 Id

252 Id at 20-21.

253 Id at 21.

254 AEP Texas Ex. 39 (Strahler Rebuttal) at 9.

41

proceedings.255 However, OPUC's proposed approach also does not limit rate-case-expense

recovery to comprehensive base rate cases. As described above, a representative amount would

be included in base rates for other types of proceedings. In addition, OPUC recognizes that rate

case expenses for routine cases will have some variation from year to year. However, that is the

case with many other types of O&M expenses. A utility's legal expenses that are unrelated to rate

cases will also vary from year to year, but the expenses are appropriately recovered through base

rates. To account for the possibility of variation, OPUC recommends that rate case expenses be

normalized, which is a common practice for other types of O&M expenses that vary from year to

year, such as vegetation management expenses. Accordingly, OPUC believes its approach is

consistent with how the Commission treats other types of O&M expenses and is a reasonable

method for recovery of routine rate cases expenses.

To implement OPUC's approach in this proceeding, OPUC witness Mr. Marcus

recommends recovering the reasonable rate case expenses for the Company's prior base rate cases

and their associated rate-case-expense proceeding (Docket Nos. 28840, 33309, 33310, and 34301)

through riders, along with this rate case proceeding's expenses after the Commission reviews and

approves the amounts.256 In addition, he recommends including a normalized amount of rate case

expenses in AEP Texas's base rates in this proceeding based on a seven-year average of $78,627

for amounts incurred between 2012 and 2018 for routine cases, as follows:257

Table: Rate Case Expenses to Include in Account 928

40261 Advanced Meter Reconciliation 2012 $ 82,103

47015 DCRF 2017 $ 21,000

48222 DCRF 2018 $ 48,108

48577 System Restoration Costs 2018 $ 399,176

$ 550,387

7 year average $ 78,627

It is important to make this adjustment in this rate case proceeding, rather than deferring the

decision to the Company's severed rate-case-expense proceeding. If the Commission agrees with

2" Id. at 10.

256 OPUC Ex. 5 (Marcus Direct) at 21.

257 Id. (citing AEP Texas Ex. 39 (Strahler Direct) at Exhibit LAS-2).

42

OPUC' s approach, then base rates can be adjusted in this case. However, if the issue is decided

later in the severed rate-case-expense proceeding, there will not be an opportunity to reopen this

proceeding to adjust base rates. Accordingly, OPUC requests that its recommended approach be

adopted in this proceeding, which results in an increase to O&M expense of $78,627.

X. Functionalization and Cost Allocation [PO Issues 8, 9, 49, 50, 52]

A. Functionalization

OPUC generally believes that AEP Texas's functionalization of costs is reasonable. In

general, the Company's cost of service study comports with the Unbundled Cost of Service

principles set forth in Docket No. 22344 in Order No. 40.258 However, as discussed below, OPUC

identified two relatively small issues regarding functionalization. The Company agreed to make

both of OPUC's functionalization changes in its rebuttal testimony, so these changes appear to be

unopposed.

1. Uncollectible Accounts Expenses Should be Functionalized to Distribution, not Customer Service.

The Company functionalized uncollectible accounts expenses in FERC Account 904 to

Transmission and Distribution Customer Service ("TDCS"). However, the uncollectible accounts

expenses written off by AEP Texas are not the same types of uncollectible accounts expenses as

seen with the vertically integrated non-ERCOT utilities, based on bad debt of former customers of

the utility. In this case, $107,120 or over 92% of the uncollectible expenses written off by AEP

Texas in the test year are from Joint Use Agreements, which are payments that the Company

cannot collect from telecommunications companies for pole rentals and similar items.259 Because

the bulk of the uncollectible expenses are related to rentals by telecommunications companies,

OPUC recommends functionalizing these costs to the distribution function, rather than the TDCS

function, given that rent from electric properties, where telecommunications revenues are booked,

are functionalized to distribution. Any rent that the Company cannot collect should have the same

258 OPUC Ex. 5 (Marcus Direct) at 22.

259 OPUC Ex. 5 (Marcus Direct) at 23 and Exhibit WM-10.

43

functionalization.26° AEP Texas accepted OPUC's proposed functionalization in rebutta1,261 so

this adjustment appears to be unopposed and should be adopted.

2. Labor Costs in FERC Account 907

OPUC witness Mr. Marcus identified an issue with labor costs in FERC Account 907 (an

account functionalized to TDCS). These labor costs were used to functionalize certain

Administrative and General ("A&G") expenses and General Plant. In the Company's original

filing, labor costs exceeded the total costs ($1,537,695 in labor versus $610,877 in total cost),

because energy efficiency costs were removed from base rates but were not removed from labor

costs.262 In rebuttal testimony, AEP Texas witness Mr. John Aaron agreed to correct this error and

provided the appropriate labor figure to be used for FERC Account 907 ($386,992).263 The

Commission should adopt the Company's undisputed correction.

B. Class Allocation

1. Class Allocation of Transmission Costs

a. Hourly versus 15-minute interval data

AEP Texas allocates transmission costs to customer classes based on the average of four

coincident peak months in the summer ("4CP"). In its application, the Company based this 4CP

allocation on the demand measured over the peak hour. However, TIEC and Commission Staff

recommended changing the allocation from 4CP based on hourly demands to 4CP based on the

highest 15 minutes in each hour.264

While ERCOT uses a 15-minute demand to allocate costs to TDUs, OPUC believes that

using an hour interval is more reasonable. The example presented by TIEC witness Mr. Jeffry

Pollock, with loads varying by 50% within a single peak hour, is overstated. As OPUC witness

Mr. Marcus testified, review of load data for several electric utilities suggests that load typically

260 The costs should be allocated to customer classes by the plant in Accounts 364-365 (overhead poles and conductors), because the revenue from these rents is allocated in this way. Id at 24.

261 AEP Ex. 54 (Aaron Rebuttal) at 10.

262 OPUC Ex. 5 (Marcus Direct) at 24-25.

263 AEP Ex. 54 (Aaron Rebuttal) at 10.

264 TIEC Ex. 1 (Pollock Direct) at 22-25; Staff Ex. 8 (Narvaez Direct) at 22-25.

44

varies by a much smaller amount, such as by 1% to 2%.265 Aside from minor changes in air

conditioning use and the timing of when businesses randomly use equipment or shut down for the

day, the primary reason that load can vary over a short period of time is that certain very large,

sophisticated customers can reduce their loads for very short periods of time, such as on a 15-

minute basis on a summer afternoon with high electricity demand, and thereby reduce their

wholesale transmission costs over the entire year.266 This 15-minute reduction in load has little or

no impact on transmission planning, which is governed by forecasts and avoiding outages under

contingency conditions.267

Rather than significantly reducing costs, a 15-minute reduction in load effectively results

in cost-shifting from customers who have the capability to reduce their load for a few minutes

(typically, large commercial or industrial customers) to those customers who cannot reduce their

load or who might not have the capability to cost-effectively monitor the electricity system to

determine when to reduce their load (nearly all residential and small commercial customers).268

This point was recognized by the Commission's consultants in Project No. 47199 who suggested

that allocation of transmission costs on a 15-minute interval basis distorts competitive markets.269

Transmission cost shifting through short-term load reductions becomes more difficult when

measured on an hourly basis. Measuring 4CP based on hourly demands is also consistent with the

approach approved in the Company's last rate case. Therefore, OPUC recommends that AEP

Texas retain a 4CP allocation for transmission costs measured on an hourly basis, not a 15-minute

basis.

2. Distribution Demand Cost Allocation (12 NCP versus 1 NCP)

In its rate design schedules, AEP Texas based its distribution demand cost allocation on

the average of 12 months' class non-coincident peak ("12NCP") loads. This point was challenged

by TIEC, Federal Executive Agencies ("FEA"), and Commission Staff, who all recommended a

265 OPUC Ex. 7 (Marcus Cross-Rebuttal) at 5. 266 Id. at 5.

267 Id. at 5-6; see also Tr. at 476 (Marcus Cross) (Aug. 22, 2019).

268 Id. at 6.

269 Id. at 6 (citing Project No. 47199, "Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT" by William W. Hogan and Susan L. Pope, May 9, 2017, p. 76).

45

single class NCP ("1NCP") based on the maximum load in each class.27° The Company agreed

to change to 1CP in its rebuttal testimony .271 OPUC and Cities propose to retain 1 2NCP.272

The claim by TIEC, FEA, and Commission Staff that costs are caused by the single NCP

because the system must be sized to meet it is overstated. OPUC witness Mr. Marcus provided a

detailed discussion as to why the construction of a distribution system is far more complex than

an approximation based on 1NCP. As Mr. Marcus pointed out:

1 . Many individual components of the primary distribution system do not serve the load of a single class of customers and must be built for class-diversified loads.273

2. Even some components that serve one class of customers may peak at different times than the class peak.

3. Distribution system components are not necessarily sized to meet a single hour's peak load but must reflect duration of usage in some cases due to thermal limitations, and may also be designed to alleviate contingencies in the event of an outage of another system component regardless of whether the outage occurs at peak or not.274

4. A distribution system has more physical capacity to serve a winter peak load than a summer peak load, so a winter peak might not be as constraining.275

Thus, as Mr. Marcus summarized:

The Class NCP is not a prescription for how to plan, build, or size anything, contrary to the suggestions of its proponents in this case. The fact that a distribution system has the ability to reliably serve the load of each class at Class NCP says very little about how it is designed or built.276

In essence, 1NCP is an approximation, not necessarily unreasonable, but also not sacrosanct.

1 2NCP is a different approximation that considers additional complexities of distribution system

270 TIEC Ex. 1 (Pollock Direct) at 12-16; FEA Ex. 2 (Al-Jabir Direct) at 12-14; Staff Ex. 8 (Narvaez Direct) at 26-29.

271 AEP Texas Ex. 54 (Aaron Rebuttal) at 12-13.

272 OPUC Ex. 7 (Marcus Cross-Rebuttal) at 9-14; Cities Ex. 4B (Johnson Cross-Rebuttal) at 12-16.

273 OPUC Ex. 7 (Marcus Cross-Rebuttal) at 9.

274 Id at 10. 275 Id

276 Id at 11. Cities witness Mr. Johnson also generally agrees with these concerns. See Cities Ex. 4B (Johnson Cross-Rebuttal) at 15.

46

loading and capacity by removing the emphasis on a single hour. It also reflects that the

distribution system is constructed and operated to allow customers to consume year-round

electricity.277

Mr. Marcus's testimony also traced the chronology of the use of 12NCP for AEP Texas,

finding that the 12-month average of class NCP loads has been used for over two decades by AEP

Texas and its predecessors.278 This point is important because the Commission has found 12NCP

to be reasonable for a long period of time. The suggestion that 1NCP is the only reasonable method

is not consistent with the Commission's past findings.

Finally, the 1NCP method creates an anomaly in this specific case. The residential class

peak is in the month of January—in other words, residential customers are winter peaking

customers, not summer peaking customers. This factor is important because: (1) loads of other

customer rate classes are considerably lower in the winter than the summer (so facilities that are

far from the customer, like substations, have plenty of unused capacity from other customer classes

to meet the residential winter peak), and (2) transformers and wires have a greater carrying capacity

in the winter because it is colder.279 Therefore, using 1NCP with a winter NCP for the single

largest customer rate class is likely to overestimate the residential class's costs even if one were to

accept the 1NCP method.28°

OPUC therefore recommends that the 12NCP method be retained. If it is not retained, the

residential class peak should be based on the highest summer NCP of 3,489 MW, instead of the

winter NCP of 3,611 MW.

5. Other cost allocation issues [PO Issue 52]

In this section, OPUC addresses cost allocation of FERC Account 581 (Load Dispatching),

FERC Account 593 (Vegetation Management), FERC Account 902 (Meter Reading), and major

account representatives.

277 OPUC Ex. 7 (Marcus Cross-Rebuttal) at 12.

278 Id at 12-14.

279 Id. at 14-15.

289 Id at 15.

47

a. FERC Account 581 (Load Dispatching)

AEP Texas's application initially allocated FERC Account 581 (load dispatching) by the

total of all distribution plant.281 OPUC witness Mr. Marcus recommended using a primary

distribution demand allocation factor for distribution load dispatching costs instead, recognizing

that load dispatching affects substations and primary feeder lines, not transformers, secondary

lines, streetlights, and services.282 In his rebuttal testimony, AEP Texas witness Mr. Aaron did not

oppose OPUC's change and incorporated the change into the Company's rebuttal class cost of

service.283 FEA witness Mr. Ali Al-Jabir opposed this recommendation in cross-rebuttal because

the definition of Account 581 contained in the FERC uniform system of accounts does not

specifically limit the account to primary distribution.284 However, Mr. Al-Jabie s objection is

based on a lack of specificity in the definition, not on any operational issues. As a result, the

testimonies of Mr. Marcus and Mr. Aaron, who both agree on how the account is used in general

practice, should be given more weight. Accordingly, the Commission should adopt OPUC' s

recommendation on this issue.

b. FERC Account 593 (Vegetation Management)

In its cost of service study, the Company allocated all costs in FERC Account 593

(vegetation management) based on the composite allocation factor for poles and wires, which was

75.27% primary distribution and 24.73% secondary distribution.285 OPUC witness Mr. Marcus

testified in support of a lesser allocation to primary distribution based on three considerations.286

First, the clearance requirements for secondary distribution are less stringent than for primary

distribution, requiring less trimming all else being equal. Second, according to the Company, only

half of secondary lines require trimming independent of primary lines. Third, tree trimming is

focused on clearances from wires (which are only 16.32% related to secondary distribution), rather

than on the composite of poles and wires. Based on all of these considerations, but particularly

281 OPUC Ex. 5 (Marcus Direct) at 27. 282 m

283 AEP Texas Ex. 54 (Aaron Rebuttal) at 11.

284 FEA Ex. 3 (Al-Jabir Cross-Rebuttal) at 5-7.

285 OPUC Ex. 5 (Marcus Direct) at 27 (Calculated from Schedule Tab II-1 TOTAL COMPANY, spreadsheet rows 118-125).

286 Id at 27-28.

48

the fact that only half of secondary lines require independent trimming, Mr. Marcus recommended

an allocation reducing the total secondary line costs for vegetation management by half (12.365%

instead of 24.73%).

In rebuttal, AEP Texas witness Mr. Aaron did not oppose reducing the allocation of FERC

Account 593 to secondary distribution. However, he recommended an allocation by secondary

distribution wires only to account for Mr. Marcus's testimony that "tree contact with wires causes

the need for vegetation management, not the poles themselves."287 Mr. Aaron's approach results

in allocation of 83.68% to primary and 16.32% to secondary. In cross-rebuttal, FEA witness Mr.

Al-Jabir recommended the allocation that the Company initially proposed in its application,

claiming that Mr. Marcus did not consider tree removals and other factors that would support

allocating vegetation management based on the full 24.73% to secondary distribution. However,

OPUC submits that the Company's 16.32% functionalization of vegetation management for

secondary lines takes into account the Company's view of operational considerations. OPUC

supports the Company's recommendation as a reasonable compromise. OPUC further notes that

the Commission has previously approved using a lower allocation of vegetation management costs

to secondary lines in SPS's rate case in Docket No. 43695.288 Therefore, the Commission should

adopt the Company's recommendation in rebuttal of 83.68% primary distribution and 16.32%

secondary distribution for allocation of vegetation management costs in FERC Account 593.

c. FERC Account 902 (Meter Reading)

FERC Account 902 contains expenses for reading meters. Although the deployment of

AMI meters permits automatic meter reads and allowed AEP Texas to eliminate meter reading

personnel, the Company continues to record $438,735 in FERC Account 902.289 Cities witness

Mr. Clarence Johnson proposed to change the allocation factor for meter reading from the number

of customers to the capital cost of meters.290 In support of his position, Mr. Johnson cited an AEP

Texas RFI response indicating that the remaining manual meter reading was heavily associated

with large customers' IDR meters. Mr. Johnson's proposed allocation method is a compromise

287 AEP Texas Ex. 54 (Aaron Rebuttal) at 11-12.

288 Docket No. 43695, Order on Rehearing at FOFs 300-06.

289 Cities Ex. 4 (Johnson Direct) at 21.

2" Id. at 22.

49

that reduces the heavy allocation of meter reading costs to the residential class. OPUC supports

this change, and AEP Texas witness Mr. Aaron did not oppose this proposal in rebutta1.291 Since

there is no opposition, the Commission should adopt this proposal.

d. Major Account Representatives

OPUC witness Mr. Marcus and Cities witness Mr. Johnson both identified a problem with

the Company's initial proposal for allocating costs for Major Account Representatives (which are

personnel who serve large customers and national chain accounts).292 In its application, the

Company allocated these costs, which are largely part of TDCS costs, by the number of customers,

which heavily allocates costs to residential and secondary general service customers under 10 kW

who do not receive these services. OPUC and Cities recommend that costs for major account

representatives be allocated to the customers who benefit from their services. This

recommendation is consistent with Commission precedent in several recent base rate cases,

including Dockets Nos. 39896 (ETI' s rate case), 43695 (SPS's rate case), and 46449 (SWEPCO's

rate case).293 In AEP Texas witness Mr. Aaron's rebuttal testimony, he stated that in light of the

Commission's precedent, the Company does not oppose the allocation of the expensed costs of

major account representatives in FERC Accounts 903, 907, and 908 to the large secondary,

primary, and transmission customer classes and not to the residential, small secondary, and lighting

classes.294

TIEC witness Mr. Pollock filed cross-rebuttal testimony opposing this position, stating that

the residential class should pay for economic development costs, and secondary customers under

10 kW and lighting customers should be assigned a full share of these costs based on the number

of customers.295 Mr. Pollock's recommendation was that the Commission should reject proposals

to change the allocation of major account representatives and continue to allocate these costs based

on the number of customers for all classes, including residential. As noted above, the Commission

291 AEP Texas Ex. 54 (Aaron Rebuttal) at 12.

292 OPUC Ex. 5 (Marcus Direct) at 29-30; Cities Ex. 4 (Johnson Direct) at 17-21.

293 Docket No. 46449, Order on Rehearing at FOF Nos. 294-302; Docket No. 43695, Order on Rehearing at FOF No. 314; Docket No. 39896, Order on Rehearing at 8 and FOF No. 164A.

294 AEP Texas Ex. 54 (Aaron Rebuttal) at 9.

295 TIEC Ex. 2 (Pollock Cross-Rebuttal) at 8-11.

50

precedent does not support Mr. Pollock's recommendation, and the Commission should reject

TIEC' s position.

OPUC notes that there is one difference between the supporters of this recommended

change. Cities witness Mr. Johnson and AEP Texas witness Mr. Aaron propose to allocate the

cost of major account representatives based on all customers in excess of 10 kW in size. OPUC

proposes to allocate this cost on a weighted basis (with a 0.1 weighting to secondary customers

over 10 kW without IDR meters and a full weighting for secondary customers with IDR meters

and primary and transmission customers). OPUC' s proposed weighting reflects that the majority

of secondary customers over 10 kW without IDR meters are relatively small customers and would

not receive the services provided by these representatives. While OPUC believes that its position

is more reasonable than the Cities' and AEP Texas's position, OPUC believes that the Commission

should remove the burden of these costs from residential and small commercial customers

consistent with its established precedent.

XII. Riders [PO Issues 8, 9, 49, 58, 59]

A. ITR Rider (related to TCJA)

AEP Texas is proposing to create an Income Tax Refund ("ITR") rider to return certain

amounts to customers due to the enactment of the Tax Cuts and Jobs Act of 2017 ("TCJA"). The

most important impacts of the TCJA on Texas utilities are that the utility: (1) must include a 21%

tax rate in the development of rates, (2) refund the difference between the 35% tax rate and 21%

tax rate that was or will be collected from the utility's ratepayers from January 2018 until rates are

changed, and (3) refund the excess deferred federal income taxes ("EDFIT") that were originally

paid by ratepayers at the 35% corporate income tax rate over some period ordered by regulators.296

In response to the passage of the TCJA, the Commission ordered utilities to record as a regulatory

liability beginning on January 25, 2018 the following: (1) the difference between the revenues

collected under existing rates and the revenues that would have been collected had the existing

296 OPUC Ex. 1 (Cannady Direct) at 58.

51

rates been set using the recently approved federal income tax rates; and (2) the balance of ADFIT

that now exists because of the decrease in the federal income tax rate from 35% to 21%.297

AEP Texas reflected the new 21% federal income tax rate for its retail rates through its

DCRF effective September 1, 2018 and for its transmission rates through its TCRF effective July

1, 2018.298 Given these effective dates, to comply with the Commission's first directive, AEP

Texas had to record a regulatory liability of the overcharges to ratepayers from January 25, 2018

through August 31, 2018 for retail ratepayers and from January 25, 2018 through June 30, 2018

for transmission ratepayers.299 With respect to the Commission's second directive, the Company

has calculated the EDFIT resulting from the change in tax rate and proposes to return the portion

characterized under IRS normalization rules as "protected" through base rates and the portion

characterized as "unprotected" through the ITR rider. The unprotected amount includes an amount

of EDFIT that was originally classified as protected, but that the Company reclassified as

unprotected because the refund period specified under the IRS's normalization rules has already

passed.

Thus, the Company must refund three categories of costs: (1) the overcharges that occurred

before rates could be changed to implement the TCJA's lower tax rate; (2) the unprotected EDFIT,

and (3) the portion of protected EDFIT that the Company reclassified as unprotected EDFIT. The

Company proposes a one-time refund for its transmission ratepayers and a refund through the ITR

rider over a four-year amortization period for its retail ratepayers. As discussed below, OPUC

recommends three adjustments to the Company's proposal: (1) the overcharges and reclassified

protected EDFIT should include carrying costs calculated using the Company's weighted average

cost of capital ("WACC"); (2) the overcharges for retail ratepayers should be provided in a one-

time refund rather than including them in the ITR rider with a four-year amortization period; and

(3) separate ITR riders should be established for the Company's North and Central Divisions.

292 Proceeding to Investigate and Address the Effects of Tax Cuts and Jobs Act of 2017 on the Rates of Texas Investor-Owned Utility Companies, Project No. 47945, Amended Order Related to Change in Federal Income Tax Rates (Feb. 15, 2018).

298 OPUC Ex. 1 (Cannady Direct) at 59.

299 Id. at 59-60.

52

1. Carrying Charges

In calculating the overcharges and reclassified protected EDFIT amounts, the Company

failed to include carrying charges. As discussed by OPUC witness Ms. Cannady, carrying charges

should be included on the overcharges and reclassified protected EDFIT commensurate with the

carrying charge that AEP Texas has proposed for the unprotected balances, which is the

Company's rate of return or WACC.30° The carrying charges should continue to accrue until the

balances have been completely refunded to customers. For the period prior to the effective date

of rates in this proceeding, OPUC recommends using the WACC approved in Docket No. 48577,

which addressed AEP Texas's system restoration costs. The WACC in that case was calculated

both with and without the impact of the TCJA's reduction in tax rates.301 For the period starting

with the effective date of rates in this proceeding, OPUC recommends using the WACC approved

in this proceeding.

In rebuttal, AEP Texas agreed that it is reasonable to include carrying charges, but

disagreed with using the Company's WACC to calculate the charges.302 Instead, AEP Texas

witness Mr. Hamlett contends that the Commission should apply the interest rate established in 16

TAC § 25.28(c), which addresses customer bill adjustments for overbillings.303 The approved

interest rate for overbillings is currently 1.99%.304 Mr. Hamlett contends that this rate is

appropriate for the required refunds because he characterizes them as "an overbilling issue."305

However, the plain language of the Commission's rule makes clear that it does not apply to these

circumstances. The Commission's rule states that "[i]f charges are found to be higher than

authorized in the utility's tariffs, then the customer's bill shall be corrected."306 No party is

contending that AEP Texas failed to charge its tariffed rates. Thus, the rule does not apply.

300 Id. at 62-64.

301 Application of AEP Texas, Inc. for Determination of System Restoration Costs, Docket No. 48577, Order at FOF Nos. 33, 36-38 (Feb. 28, 2019).

302 AEP Texas Ex. 40 (Hamlett Rebuttal) at 74-75.

3°3 Id.

304 See Interest Rates Set Under Texas Utilities Code §183.003 and Set for Overcharges and Undercharges under 16 Texas Administrative Code 025.28, 25.480, and 26.27, Docket No. 45319, Order (Dec. 4, 2018).

305 AEP Texas Ex. 40 (Hamlett Rebuttal) at 75.

306 16 TAC § 25.28(c).

53

In addition, applying the Commission's interest rate for overbillings would be inconsistent

with how AEP Texas proposes to treat the unprotected EDFIT, which would accrue interest at the

Company's WACC. Applying the Commission's interest rate for overbillings would also be

inconsistent with the carrying charges that other utilities are applying to their EDFIT.307 A utility's

WACC is also used to calculate carrying costs in other circumstances, such as the calculation of

system restoration costs.308 Accordingly, OPUC requests that the overcharges and reclassified

protected EDFIT amounts include carrying costs calculated using the Company's WACC.

2. One-Time Refund of Overcharges

Rather than including the overcharges for retail ratepayers in the ITR rider with a four-year

amortization period, OPUC recommends that the overcharges be refunded (including carrying

charges) through a one-time refund. AEP Texas is proposing a one-time refund of the overcharges

to transmission ratepayers, and the same treatment should also be applied to retail ratepayers.309

The overcharge amounts accrued over a short period of time (approximately seven months), and

the refund to ratepayers should not be delayed. This treatment is also consistent with how Oncor

agreed to return the overcharge amounts resulting from the TCJA's change in tax rate.310

AEP Texas has calculated retail overcharges, without carrying charges, of $9,293,055 for

the Central Division ratepayers and $2,372,460 for the North Division ratepayers. OPUC's

recommended one-time refund of overcharges, with carrying charges, would be $10,628,565 for

the Central Division ratepayers and $2,714,862 for the North Division ratepayers.3" OPUC

requests that these amounts be refunded during the first month that rates from this proceeding are

effective.

307 See, e.g., Entergy Texas, Inc. 's Statement of Intent and Application for Authority to Change Rates, Docket No. 48371, Order at FOF No. 73 (Dec. 20, 2018); Application of Oncor Electric Delivery Company LLC for Authority to Decrease Rates Based on the Tax Cuts and Jobs Act of 2017, Docket No. 48325, Order at FOF No. 32 (Apr. 4, 2019).

308 PURA § 36.402(b).

309 OPUC Ex. 1 (Cannady Direct) at 64-65.

310 See, e.g., Docket No. 48325, Order at FOF No. 34.

311 OPUC Ex. 1 (Cannady Direct) at 65.

54

3. Separate ITR Riders for Central and North Divisions

OPUC recommends that AEP Texas provide separate ITR riders for its Central and North

Divisions. The Company's justification for proposing a single, Company-wide ITR rider is that

AEP Texas has been consistent and consolidated all tax reform items.312 However, while OPUC

generally supports consolidated rates for the Company, the ITR rider should be implemented

separately for the Company's Central and North Divisions for two reasons.

First, the EDFIT balances result from the difference between the ADFIT computed using

the 35% federal income tax rate adopted in 1986 and the re-computation of ADFIT using the 21%

tax rate adopted with the passage of the TCJA. Because each of AEP Texas's divisional operations

historically and currently have separately computed customer rates, the EDFIT balances now owed

to customers should also be determined separately for each division.313 Unlike the request to

consolidate rates for the provision of electric service going forward, the refund of EDFIT is due to

historical rates already charged and should not be consolidated in this case.

Second, the EDFIT balances for the Central Division have been offset by approximately

$63.5 million for its Hurricane Harvey restoration costs.314 Including the EDFIT balances net of

the $63.5 million in the combined ITR rider balances effectively pushes Hurricane Harvey

restoration costs onto the North Division customers. OPUC witness Ms. Cannady confirms this

effect by comparing the proposed combined refund with the refunds that would occur if the refunds

were calculated separately.315 As she states in her direct testimony, under the Company's proposal

to provide a combined refund for both divisions, the average refund for all customers is 3.35% of

customer billings. However, if this percentage is calculated separately for the Central Division

customers, including the reduction in the EDFIT balance for the Hurricane Harvey restoration

costs, the average refund for Central Division customers would be 2.72% of customer billings. In

contrast, if the percentage is calculated separately for the North Division customers, the average

refund for the North Division customers would be 5.83% of customer billings. Therefore,

312 AEP Texas Ex. 40 (Hamlett Rebuttal) at 78.

313 OPUC Ex. 1 (Cannady Direct) at 66.

314 Id at 66-67 (citing Application of AEP Texas, Inc. for Determination of System Restoration Costs, Docket No. 48577, Order at FOF No. 52 (Feb. 28, 2019)).

315 Id at 67-68.

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combining the adjusted EDFIT balances for the two divisions effectively places some of the

responsibility for Hurricane Harvey restoration costs on North Division customers by lowering

their EDFIT refunds. This proposed combination is also contrary to the Commission's order in

Docket No. 48577, which provides that the Hurricane Harvey restoration costs be charged only to

Central Division customers.316

In rebuttal, AEP Texas witness Ms. Strahler notes that the Company has long been operated

and managed as a single enterprise and that she believes that on balance the Company's proposal

for a single ITR rider is reasonable.317 However, the EDFIT balances and Hurricane Harvey

restoration costs predate the consolidation of rates for the Central and North Divisions, which is at

issue in this proceeding. As discussed above, the ITR rider is intended to refund amounts included

in historical rates. Thus, despite the operation of the Company as a single enterprise, the amounts

at issue are tied to the Company's separate divisions. Ms. Strahler noted that there is no

Commission or statutory requirement to maintain separate refunds for the Company's Central and

North Divisions,318 but there is also no requirement that the refunds be consolidated. Given the

reasons discussed above, OPUC believes that the EDFIT balances are more appropriately refunded

through separate ITR riders for the Company's Central and North Divisions.

XV. Conclusion

For the reasons stated herein and discussed in the testimonies of its witnesses, OPUC

respectfully requests that the SOAH Ails adopt and incorporate OPUC's recommendations into

the PFD in this proceeding. OPUC further asks to be granted any other relief to which it may be

entitled.

316 Docket No. 48577, Order at FOF No. 4.

317 AEP Ex. 39 (Strahler Rebuttal) at 13.

318 Id.

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Respectfully submitted,

Lori Cobos Chief Executive & Public Counsel State Bar No. 24042276

Cassandra Quinn Senior Assistant Public Counsel State Bar No. 24053435 Harley Martin Assistant Public Counsel State Bar No. 24068879

OFFICE OF PUBLIC UTILITY COUNSEL 1701 N. Congress Avenue, Suite 9-180 P.O. Box 12397 Austin, Texas 78711-2397 512/936-7500 (Telephone) 512/936-7525 (Facsimile) cassandra.quinn@opuc.texas.gov harley.martin@opuc.texas.gov opuc_eservice@opuc.texas.gov (Service)

CERTIFICATE OF SERVICE

I hereby certify that a copy of the foregoing document was served on all parties of record in this proceeding on this 5th day of September 2019 by facsimile, electronic mail, and/or first class, U.S. Mail.

Cassandra Quinn

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