500 LEE STREET EAST * SUITE 1600 * PO. BOX 553 *CHARLESTON. WEST VIRGINIA 25322 *TELEPHONE: 304-340. ID00 * TELECOPIER 304.340- t I 30 wMjo<iuo"&el lpm

Direct Telephone: (304) 340-1251 Direct Telecopier: (304) 340-1080 E-mail: ccallas@,iacksonkellv.com

December 23,2015

VIA HAND DELIVERY

Ingrid Ferrell, Executive Secretary Public Service Commission of WV 201 Brooks Street ~~

Charleston, West Virginia 25323

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~,

Re: West Virginia-American Water Company PSC Case No. 15-0674-WS-D

Dear Ms. Ferrell:

Enclosed are an original and twelve copies of West Virginia-American Water Company's Reply Brief.

Please file this brief and circulate the additional copies to the appropriate parties at the Commission. Please also date stamp the extra copy provided and retum it with our messenger. As always, we appreciate your assistance.

Sincegly yours, lm. Christopher L. Callas

CLC/mrv Enclosures C: Tom White (w/enc.)

David A. Sade (w/enc.) Andrew T. Gunnoe (w/enc) Paul R. Sheridan (w/enc.) Paul D. Ellis (w/enc)

Lee F. Feinberg (w/enc.) Susan J. Riggs (w/enc.) Derrick Price Williamson and

Barry A. Naum (wlenc.) Mandi Kay Carter (w/enc)

482 1-964723252.~1

PUBLIC SERVICE COMMISSION OF WEST VIRGINIA

CHARLESTON

CASE NO. 15-0674-WS-D

WEST VIRGINIA-AMERICAN WATER COMPANY

Application for Change in Depreciation Rates pursuant to Procedural Rule 20

WEST VIRGINIA-AMERICAN WATER COMPANY’S REPLY BRIEF

West Virginia-American Water Company replies to the Staff, CAD, and WVEUG briefs.

The CAD recommendation to eliminate all net salvage from depreciation rates was rejected

earlier this year, when Mr. Majoros presented the same arguments in the APCo depreciation

case. One way or another, every argument CAD makes (and WVEUG uncritically supports)

comes back to this “no net salvage” position. The CAD and WVEUG also fail to demonstrate

that non-compliance with portions of the 1998 order harmed customers.

The Staff position, which differs from the Company’s only in the net salvage estimates

for certain plant accounts, has two important flaws. First, Staffs recommended net salvage rates

for those accounts, which merely hold over 1998 accrual rates, are an outdated, unreliable basis

for going-forward depreciation rates. Second, Staffs carried-forward 1998 accrual rates were

premised on the view that absent actual removal of facilities from the ground, there are no costs

to remove at all - a position Mr. deGruyter conceded is inaccurate.

For these reasons and those presented in the Company’s initial brief, the Commission

should adopt the Company’s proposed accrual rates.

A. CAD/WVEUG - Adopt Whole Life; Remove All Net Salvage from Accrual Rates

CAD dislikes remaining life-based depreciation rates, for the central reason that they

include a net salvage component. CAD’s opposition to any net salvage component, which runs

throughout the CAD brief, is the same opposition the Commission dismissed in the 2014 APCo

RC Order - a directly relevant ruling CAD avoids entirely.

Examples abound in the CAD brief. CAD’s clear preference is for whole life-based

rates, apparently because that technique excludes of any net salvage component: “The whole life

method is a less complicated and more transparent method. Remaining life is not.” CAD Ex.

MJM-D at 8. Mr. Majoros addressed this complexity: “The remaining life technique is sensitive

to changes in the depreciation reserve; depreciation life changes retirement levels and net salvage

entries.”’ Id. CAD also assails the remaining life technique because it incorporates estimates of

future net salvage, which necessarily are not “known and measurable.” CAD Br. at 2. CAD

claims its depreciation rate proposal is superior to the others, because its proposal is the only one

that does not incorporate net salvage estimates:

Following long-standing regulatory practice that ratepayers pay only those expenses that are known and measurable, CAD did not include these estimated and unknown costs in its proposed depreciation rates.

Id. (emphasis in original). CAD boasted that only its proposal allows for utility recovery of the

original cost of plant in service and no more; all other proposals “are designed to recover much

more than the original cost of UPIS” precisely because they incorporate net salvage. Id.

Although CAD later suggested that the alleged unreliability of the Company’s retirement data is

This is the correct quote from Mr. Majoros’s testimony. CAD omitted the mention of “retirement 1

levels” in its quote. CAD Br. at 7.

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the reason the Company’s net salvage estimates are “neither known nor measureable” (id. at 3),

estimating future net salvage is a part of every remaining life-based depreciation study.

In other words, estimating future net salvage is not unique to Mr. Spanos’s work in this

case. As the Commission may recall, the amount (but not the concept) of future net salvage for

steam plant was the central depreciation debate in APCo’s last case. See generally 2014 APCo

RC Order at 80-88 (approving Staff-recommended depreciation rates, which contained

“significant amounts of negative net salvage” (p. 86)). So, the CAD position here should be no

surprise; opposing the allegedly speculative nature of negative net salvage was the basis for

CAD’s opposition to APCo’s depreciation rates, too, as CAD’s briefing in that docket shows2

This CAD position, which had nothing to do with the unreliability of historic removal

costs alleged here, was roundly rejected in &:

The Commission has historically included some amount for projected cost of removal and projected salvage value in the development of depreciation rates. We do so when the projected cost of removal and salvage is reasonable and supported by substantial evidence.

2014 APCo RC Order at 85. Because Mr. Majoros “opposed the use of any negative net salvage

in depreciation rates,” the Commission was unable to “find the CAD recommendation to be

reasonable.” Id. There is no sound reason for a different outcome h e x 3

“[Tlhe problem with all this is that cost of removal and negative net salvage is almost entirely speculative.” Consequently, CAD argued that APCo’s estimation of net salvage value was nothing more than “monetizing assumptions about future cost of removal.” CAD Initial Brief dated March 6, 2015 in 2014 APCo ratddepreciation case, Case Nos. 14-1 151-E-D and 14-1 152-E-42T, at pages 56,57.

2

Given CAD’s strong opposition, in this and other cases, to net salvage in depreciation rates, its alternative recommendation (CAD Br. at 3-4) for three years of whole life rates, combined with going- forward recording of net salvage, to be followed by consideration of a return to remaining life-based rates, is conceptually inconsistent. It also ignores the fact that remaining-life rates developed then would still incorporate the future estimation aspects CAD obviously does not support.

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3

Perhaps sensing the Commission might apply its “historic” approach, CAD tried to hedge

its bets, arguing that the 50/50 allocation also compromised the actual Company-specific data

needed to estimate future net salvage accruals. Although WVEUG makes no mention of it, this

rationale is sprinkled throughout the CAD brief! CAD Br. at 10, 12. But this argument is

flawed, too, from ratemaking and practical perspectives.

First, CAD has not shown that estimates of future net salvage must be based on actual

historical experience for the same plant. If this were so, then APCo could not have incorporated

net salvage into its steam production plant accruals because it would have lacked adequate and

relevant historical data; we h o w , however, that this deficiency did not keep the Commission

from incorporating a net salvage component in APCo’s relevant plant accounts. Moreover,

CAD’s approach to net salvage estimation would put a premium on historic dollar costs for

removal (“COR”), when parameters such as the utility’s removal approach and, as here, the

proportion between installation and removal costs, are much more reliable predictors for future

net salvage expense than aged dollar amounts. CAD has not shown that Mr. Spanos’s

assessment of typical water utility removal allocations is an unreliable approach - it certainly

will reduce dramatically the COR previously booked under the 50/50 allocation method.

From a practical perspective, CAD’s position necessitates exactly what it knows the

Company is unlikely to generate: actual, detailed cost information by work order, accurately

segregating line replacement jobs into defined, accurate “cost of removal” and plant investment

amounts. Because line replacement jobs are “of a piece,” it is difficult to assess with certainty,

for instance, the paving removal and new paving expense that should be assigned to removal,

and the portion properly assigned to investment - both are indisputably necessary (which is

Staff also argues that the 50150 allocation impairs the Commission’s ability to track the accuracy of the Company’s allocations to cost of removal or to establish appropriate accruals now. Staff presented no evidentiary support for this view, however. Staff Br. at 4.

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likely to be the origin of the 50/50 allocation in the first place). Another example is the labor

time associated with opening and closing the ground, and work efforts during which both

removal and installation tasks are occurring simultaneously. The difficulty and burden in

segregating these costs is obvious; the just-as-obvious solution is to use an allocation for

common jobs. When asked what the industry standard was, MI. Spanos spoke of allocation

percentages; the same was true for other American Water subsidiaries, Mr. McIntyre said. Tr. at

82-83, 93-99 (Spanos) and 171 (McIntyre). CAD’s demand for actual historic data appears

designed to render the Company unable to benefit from a net salvage component in its

depreciation rates.

CAD’s final argument, like many other statements of its brief, was based on inaccurate

information. CAD asserted that Mountaineer Gas Company, in its recent depreciation case,

“asked for the very same depreciation method that CAD is recommending: straight line whole

life depreciation.” CAD provides no citation to support this, and there is none. Nowhere in

Mountaineer’s depreciation study, its expert’s supporting testimony, or the stipulated settlement

of its depreciation and rate cases is this notion advanced commented on.’ In fact, CAD’s

assertion is undercut in the very next sentence of its brief: “Mountaineer asked for a small

amount of net salvage in their depreciation rates.” Id.

See docket in Case No. 15-0048-G-D, including initial filing of January 20, 2015 at 1; direct testimony of Dale L. Parris filed February 20, 2015 at 4; and Commission Order approving joint stipulation entered on October 13, 2015. Due to limitations in historic plant data, Ms. Parris used a combination of average remaining life analysis, straight line methods, and industry comparisons. Although Ms. Parris did not incorporate net salvage information to devetop accrual rates, it was because she determined they would not have a material impact on her recommendations - not because she advocated for and used an approach (whole life) that does not consider net salvage in its calculation.

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B. The 50/50 Allocation Did Not Harm Customers.

CAD repeatedly asserts that the Company’s re-implementation of the 50/50 allocation

ratio in 2001 harmed its customers. But there is no evidence to support this view. Perhaps this is

why CAD believes the “greatest harm” arising from this re-implementation is “the most

obvious” - that the Company “willfully ignored a Commission order.” CAD Br. at 22. CAD’s

other claims of harm are just as nebulous. CAD contends that by re-implementing the 50/50

allocation:

Customers “lost the benefit of their negotiated settlement” in the 1998 depreciation case (id. at 4-5).

The Company caused a “material effect” on the calculation of UPIS [utility plant in service] and the depreciation reserve by obscuring “the true cost of UPIS” and the depreciation expense paid by customers, and by distorting “the ratio of net plant to both accumulated depreciation and original cost of UPIS.” CAD conceded, however, that these changes did not affect the Company’s net plant balance (id. at 11); CAD’s Table 2, where the $47 million “regulatory asset” was added to the UPIS and depreciation reserve balances, proved the absence of an adverse rate base impact (id. at 12):

A “lack of transparency” was created, because the Company’s financial statements do not separately state the levels of UPIS and accrued depreciation, and thus a “ratepayer or Commission member” reviewing those financial statements might be misled (id. at 21)?

CAD is unable to identify an adverse customer impact arising from these outcomes, much

less quantify one. Moreover, the “lack of transparency” argument is as misleading as it is far-

fetched. Under GAAP, the Company’s audited financial statements’ do not separately identify

CAD also pointed out that making this change changed the “depreciation reserve ratio” to 20.3% 6

from 14.6%. Id. at 13. Again, though, CAD does not explain how this has harmed customers.

For reasons that are unclear, CAD also believes that the Company’s alleged lack of transparency 7

here has also “create[d] a credibility issue” for the Commission and ratepayers.

CAD’s suggestion that the Commission looks only to the Company’s GAAP financial statements to evaluate the Company’s financial condition is rather rich, given that CAD routinely disparages the value of GAAP financial performance in evaluating the Company’s achieved ROE.

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6

the original cost of all utility plant and the accumulated depreciation on that plant; rather, only

the net amount is stated. Instead, the Company’s Rule 42 presentations, its quarterly financial

reports, and its depreciation filings are the sources the Commission and stakeholders use to make

those evaluations?

The closest CAD gets to asserting an actual ratepayer impact is stated (but then not

explained) on page 10, where CAD stated that re-implementation of the 50/50 allocation

“artificially increases depreciation rates under the Remaining Life method.” Id. at 10. Although

the Company disputes the “artificial” characterization, there is a hint of accuracy here, but not in

the way CAD intended. Analyzing the potential for impact is a much more involved exercise,

and one that CAD did not undertake. To prove there has been no adverse impact on the

Company’s customers, we will do so here.

It is reasonable to expect that if a depreciation case had been filed soon after the 50150

allocation was re-implemented (say in 2002), and if the 50/50 allocation had been discontinued

soon afterward (for example, in favor of a lower allocation ratio, or the method used between

1999 and 2001), then amounts booked to cost of removal would have been reduced, and amounts

booked to UPIS would have increased, all else equal and constant. Yet over the next decade or

more, we know “all eke” would have been neither “equal” nor “constant”:

The company’s line replacement efforts would still have grown between 2002 through 2015, resulting in higher investment in UPIS and higher levels of retirements overall.

The Company’s implementation of SFAS 143 would have still resulted in a reclass of negative net salvage previously included in accumulated depreciation, which added millions of dollars to the cost of removal account - only a portion of which related to the 50/50 allocation. CAD Cross Ex. 1 at CAD DEP 1-020; Tr. at 49-50 (Spanos).

To dispel concerns about the inability to separate UPIS and the depreciation reserve from the Company’s financial statements, CAD should realize that the Company’s annual reports (page 505) show annual changes to depreciation reserve levels.

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The Company would still have booked cost of removal (i) for other utility accounts to which the 50/50 allocation had not applied, (ii) to other retirement costs within those same accounts that did not arise from the Company’s small main replacement program, and (iii) as permissible direct charges “clearly attributable to the retirement of utility plant” in accordance with the Uniform System of Accounts (see 1998 stipulation language at CAD Ex. MJM-I).

The Company’s removal costs would still have exceeded the original cost of the plant being retired, and the impact of this excess would likewise have grown with increased annual infrastructure replacement and time.

All of these subsequent realities would have increased cost of removal, without regard to the

50/50 allocation.’o They help to explain what Mr. Spanos said at hearing: use of the 50/50

allocation resulted in only a part of the existing COR balance (Tr. at 27-28), and consequently

only a part of the $47 million “regulatory asset” as well.

In short, the COR account balance would have grown on its own, even if the 50/50

allocation had been corrected in 2002. Assuming periodic depreciation cases, two things could

have happened. First, the Commission could have established depreciation rates with negative

net salvage components sufficient to reduce or eliminate the insufficiency between incurred costs

of removal and amounts collected to cover that cost in depreciation rates (which, after all, this

insufficiency is what the $47 million represents). This approach would have reduced the

regulatory asset, but would have increased depreciation rates, requiring customers to pay more.

The second outcome is the converse: Commission-established depreciation rates would have

continued to be insufficient to recover costs of removal (both incurred previously and going-

forward), keeping customer rates lower but allowing the insufficiency of COR recovery to grow

- only to show up as an even higher amount of unrecovered removal costs in subsequent

lo These observations also undermine Staffs simplistic view that increasing COR percentages necessarily denote that the Company’s proposed costs of removal (or more specifically, its negative net salvage percentages) are “excessive.” Staff Br. at 2; Staff Ex. EFG-D at 4.

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depreciation cases, where this choice would continue to present itself until addressed through

higher depreciation accruals to account for past and future COR recovery.

Thus, if the 50/50 allocation had been discontinued in 2003, either depreciation rates (and

customer rates) would have gone up, or they would have stayed flat and kicked the COR can

down the road until dealt with through an even larger increase in a subsequent depreciation case.

Somewhere along the way, addressing the unrecovered COR would have caused depreciation

accruals and customer rates to increase. CAD cannot say, then - and certainly cannot prove -

that re-implementation of the 50/50 allocation in 2001, combined with the absence of

depreciation cases since 1998, visited any harm on customers during that period. Directionally,

the opposite is much more probable: these “non-compliance” factors made depreciation-related

customer rates Cess than they otherwise would have been during this period. Of course, CAD did

not conduct this analysis or, if it did, chose not to present it. It has proven no harm to customers

arising from the 50/50 allocation or the delay in filing a depreciation case. Neither did WVEUG,

whose advocacy on this point was inflammatory and incorrect.”

But there is a second crucial aspect of this analysis that CAD and WVEUG neither

addressed in their initial briefs nor challenged at hearing: the rate base impact of removing COR

from depreciation rates. As Mr. Spanos explained in rebuttal:

[I]f Mr. Majoros believes that the allocation to cost of removal was too high, then the $46.9 million regulatory asset he proposes to remove must instead be recorded as an installation cost of new investment - that is, included in rate base.

Co. Ex. JJS-R at 5. This dynamic arose over and again at hearing, and the Company addressed it

in detail in its initial brief. Co. Brief at 17-18; Tr. at 41-42, 50, 69 (Spanos). If allocations to

WVEUG asserted that re-implementing the 50/50 allocation “increased rates from ratepayers throughout a 15-year period beginning in 2000” (WVEUG Br. at 4) and urged the Commission not to allow the Company to retain what should have been a customer benefit from the 1998 case (id. at 5). There is no evidence to support these assertions, and WVEUG cited none.

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cost of removal were lower, then net plant in service would be higher, and in subsequent rate

cases the net plant balance on which investors earn a return” would have been higher - meaning

higher customer rates, all else equal. To use the previous example, if CAD’S current opposition

to including net salvage in depreciation rates had been applied in 2002 and perpetuated in later

depreciation case orders, then the Company’s insufficiency in COR collection would be much

higher, and rate base would be higher as well.

Concluding this analysis requires the Commission to determine whether the Company’s

proposed depreciation rates are being used to recover depreciation expense arising from its use of

the 50/50 allocation. Stated differently, do Mr. Spanos’s estimated net salvage percentages

incorporate unrecovered incremental cost of removal arising from the use of that allocation? The

answer is no, as Mr. Spanos explained. Although CAD and WVEUG ducked this issue in their

briefs, the Company addressed it head on:

Commissioner McCabe questioned Mr. Spanos at length on the potential for customer impact. Mr. Spanos again confirmed that whether the cost was allocated to plant in service or to cost of removal, there is no impact because the net effect on rate base is zero. Because his estimated net salvage percentages are lower than the Company’s data showed - and even controlling for the 50/50 allocation still produced a very high net salvage percentage -the allocation issue itself did not cause a cost of removal change in percentage in the study. “[Tlhe Company is going to get their fair recovery, [that] ratepayers have not paid more than they should have, will not pay more going forward by doing it this way His changes ensured that “there has been no harm to the ratepayer so far and going forward.”

l 2 This may sound contrary to the observation, supported by CAD, that moving replacement costs from cost of removal to UPIS has no net impact on the plant balance. This is true, but in evaluating the rate impact of this movement, it tells only part of the story. Lower COR and higher UPIS means the Company’s “return of’ its investment through depreciation expense is the same, because the increased investment would be offset by an increase in accumulated depreciation. However, a higher net plant balance arising from a greater share of these costs being allocated to new capital investment would cause the Company’s “return on” investment to be higher, because the investment base is greater each time rate base is established in a rate case.

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Co. Br. at 17 (internal citations omitted). Mr. Spanos explained that in estimating the net salvage

percentages for the accounts affected by the 50150 allocation, he discounted the actual recorded

COR percentage (for mains, 391 percent) to reflect the use of a 20% allocation to COR more

consistent with other utilities, and still generated a COR component that was 194 percent of the

dollars being retired. Co. Ex. JJS-R at 11. Consequently, in a second step Mr. Spanos reduced

the COR component again, to negative 50 percent, to reflect a more reasonable COR allocation

going forward, too. Tr. at 83. These discounts, which are incorporated in Mr. Spanos’s accrual

rates for the relevant accounts, were designed to avoid recovering any 50150 allocation-generated

amounts in depreciation rates. Id. at 84. No other party presented evidence to undermine Mr.

Spanos’s calculation method or its efficacy in removing the impacts of the 50/50 allocation from

depreciation rates.

It is one thing for CAD and WVEUG to assert the Company’s non-compliance with the

1998 order “harmed customers”; it is quite another thing to demonstrate it. Their decision to

avoid a meaningful analysis of the situation proves nothing. And CAD and WVEUG never

attempted to show that the blunt instrument they offer as a remedy - a return to whole life rates

with no negative salvage, producing millions less in depreciation expense each year - is

commensurate with the harm (in this case, non-existent harm) they allege customers have

suffered.

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C. Staff‘s Accrual Rates are Outdated, Unreliable, and Contradict Staff’s Own Evidence.

Staff contends that Mr. deGruyter’s rejection of certain net salvage percentages (those

higher than calculated in 1998), and his replacement of those percentages with those used in

1998, are justified because the Company’s practice of leaving retired pipes in the ground has not

changed since then. Staff Br. at 7-9. Although this was Staffs sole rationale Staff for this

position, in its brief Staff explicitly relies on the 1998 testimony of a now-departed analyst.

In 1998, David Wansley observed that the Company does not typically remove retired

pipe from the ground, and also opined that in those situations, there are no other costs related to

the retirement that may be capitalized. Mr. Wansley asserted that since the Company does not

remove all of its plant from the ground in every instance, “there is no direct cost associated with

the removal of plant that is abandoned in place.” Summarizing Staffs position, Mr. Wansley

presented this doctrinaire principle:

Absent an actual removal of old plant we do not agree with the company’s proposal to assume that a portion of the costs that might be related to disconnecting old taps and retapping the new line should be accounted for as “cost of removal.”

Staff Br. at 9, quoting Wansley prefiled testimony (Attachment 2) at 3. By embracing the

uniformity of Staff views between 1998 and now, Staff also adopted Mr. Wansley’s view that

removal of retired facilities from the ground is the governing prerequisite for any costs - no

matter for what - to be accounted for as cost of removal.

But Mr. Wansley’s view on this point contradicts the evidence in this docket, including

from Mr. deGruyter himself. Mr. Spanos testified without challenge that there are activities

associated with retirement of distribution lines, even when they are abandoned in place. ‘&If an

item is abandoned in place, that does not mean you have zero cost of removal.” Tr. at 39. These

include the cutting the pipe, plugging or “capping” it, installing bracing, and removing pavement

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and getting it out of the way to perform this work. Id. at 39, 69, 98 (Tomac); see also CAD

Cross Ex. 2 at PSC 3-001 (retirement activities in the abandonment situation include valving off

the lines, cutting and plugging with caps and installing concrete thrust blocks). Mr. deGruyter

agreed that in 1998 and today, these are distinct costs associated with the retirement of facilities

abandoned in place. Tr. at 128.

How can Staff contend that abandonments in place entail zero cost of removal, when Mr.

deGruyter acknowledged that the same costs of removal Mr. Tomac identified exist in the very

same situation? Faced with this fundamental inconsistency, the Commission should prefer the

more reasonable, common-sense approach advanced by Staff and Company witnesses alike:

these costs do exist in the abandonment context, and consequently should be accounted for in the

cost of removal component of depreciation rates. By recommending accrual rates incorporating

1998 COR allocations -which were premised on the exclusion of COR fiom depreciation rates

the affected accounts - Staff effectively proposes new depreciation rates that fail to account for

removal costs its own witness has acknowledged the Company incurs. This is reason enough to

prefer the Company’s depreciation rates for the affected accounts over Staff s.13

l3

of which arose in Staffs brief. Co. Br. at 13-15. These flaws require no repetition here. The Company’s initial brief provided three other flaws in the Staff reasoning on this issue, none

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D. Assertions Unrelated to Setting Depreciation Accrual Rates

As in the rate case, much of the depreciation case record was devoted to “red herring”

issues that have no impact on depreciation rates.

1.

The Company knows it failed to comply with two of the terms in a Commission-

approved settlement. Repetition of those failures in the opposing briefs, or the stridency

employed in repeating them, is no substitute for actually demonstrating that adverse customer

impacts occurred. Nor does such rhetoric convert an unexplained re-implementation of the 50/50

allocation in 2001 into an act of willful, intentional, deliberate disobedience - there is no

evidence of that, either. CAD Br. at 4; WVEUG Br. at 1. Finally, WVEUG’s appeal not to let

the Company “escape the consequences of its actions” is an empty slogan when, as hard as they

have tried, the other parties have yet to articulate any real adverse consequences.

Calls for the Company to be Punished

Likewise, alleging that the Company tried to hide its non-compliance is refuted by the

very first filings in the depreciation case, exactly where one would have expected to find it - in

the depreciation study and Mr. Spanos’s supporting direct testimony. Mr. Spanos not only

explained the unexpectedly large COR accruals; he also identified the cause (allocation factors

much higher than industry averages) and took steps to correct the problem, both as to existing

COR accruals and going forward. Co. Ex. JJS-D at QZS; Co. Ex. 1 (Study) at IV-4. CAD

immediately noticed; its investigation into asset removal costs and COR balances began with its

very first set of data requests, issued July 1, more than four months before it filed Mr. Majoros’s

te~timony.’~ See CAD Cross Ex. 1 at CAD DEP 1-030 and others. Although the Company

Staff investigated these areas, too. See CAD Cross Ex. 2 at PSC 3-001 (requests filed in early I4

September). WVEUG filed no discovery on depreciation issues.

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could have filed separate depreciation case testimony to explain what happened, the fact that it

did not do so does not establish a cover-up, as CAD, WVEUG, and Staff assert.”

Instead, the Company has acknowledged its failures, explained that their origins and

actors involved are no longer known to Company management, and promised to correct them

going forward. This is all that can reasonably be expected of the Company at this point, nearly

fifteen years after the non-compliance began. The Company has already received a “strong

message” (CAD Br. at 4) that non-compliance with Commission orders is a serious matter -

something no sophisticated utility really needs to be reminded. If customers had been harmed,

that might justify the outraged tone of the CAD and WVEUG briefs, but they were not. The

Company’s observation here is not offered as an excuse, or to evade responsibility. It is a fact

that should inform the Commission’s evaluation of the situation.

2. Capitalization Practices

CAD suggested that the Company’s “capitalization practices” - when it capitalizes labor

and related costs for main repairs and replacement, and when it expenses them - may have led to

high unaccounted for water levels (CAD Br. at 5 ) and even driven the growth of utility plant (id.

at 17). There is no connection between these suppositions and the Company’s depreciation

accrual rates, and CAD does not offer any.

CAD began its argument with the assertion that 62% of the Company’s plant is less than

fifteen years old. CAD Br. at 5. This calculation arises from a rudimentary error: assuming the

Company’s plant investments during that fifteen years, measured in dollars at the time they were

placed into service, also meamres that investment’s proportion to the Company’s overall

CAD Br. at 4,22-23; WVEUG Br. at 4; Staff Br. at 5-7. The parties do not acknowledge that on the April 30, 2015 filing date, the Commission had not yet consolidated the rate cases with the depreciation case. This happened later, and the Company had no reason to expect it would; the Commission did not consolidate recent rate/depreciation cases filed by APCo and Mountaineer.

IS

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physical plant. For whatever reason CAD saw the need to calculate this, the statement is wildly

misleading. Next CAD reaches into the rate case record to quote Mr. Fowler’s prefiled

testimony, ostensibly to support CAD’s assertion that the Company’s unaccounted-for water is

“more than 200% of the national average.”I6 But Mr. Fowler’s testimony did not concern high

UFW levels, and certainly did not address depreciation; instead, the context of his quoted rate

case testimony was the need for “a means of hnding critical infrastructure replacement needs,”

because in his view traditional funding mechanisms were not attracting enough capital for that

purpose.

More to the point, CAD did not point to any of its depreciation case testimony or cross-

examination to condemn the Company’s capitalization practices; even CADS rate case

testimony did not advance this argument. The only evidence criticizing the Company’s

capitalization methods was offered by ASWS in the rate case, in the form of Fred Stottlemyer’s

prefiled testimony. His opinions on capitalization were easily undermined on cross, where he

confessed to having no training in accounting, no familiarity with GAAP standards for

capitalizing assets, and no authoritative basis to questidn the Company’s capitalization practices

for main repairs and ~eplacements.” Like much of its brief, CAD’s advocacy here illustrates that

just saying it doesn’t make it so.

CAD also offered Mr. McIntyre’s rate case hearing testimony in asserting that gas

companies have a higher dollar threshold for capitalization - at $3,000 -than the Company. Mr.

Mr. Fowler did not say this in his prefiled testimony in Case No. 15-0676-W-42T or his 16

November 2,2015 oral testimony.

See Transcript of October 30,2015 hearing in CaseNo. 15-0674-W-42T, pages 163-164.

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Mclntyre did not say this, and the garbled transcription might at least have led CAD to question

its accuracy:”

Q. (by CAD counsel) And do you know whether this $1,500 rule, is the norm in the industry, or is that something that’s unique to American Water?

A. Every utility sets its practice, but I think it’s fairly normal. And if I recall, gas would be 34 for municipal operations, tracking of a utility asset billed at $3,000. . . ,

CAD was somehow able to interpret this gibberish, restating it like this: “For the gas companies,

according to Mr. McIntyre, the threshold for capitalizing repairs is $3,000.” CAD Br. at 17-18.

CAD concluded with the recommendation that a “higher capitalization threshold - as with the

natural gas companies - is warranted.” Id. at 18-19. Incidentally, by asserting that “[tlhe

Company threshold for capitalizing an expense is $1,400 dollars” (CAD Br. at 17), CAD

misstated this part of the record as well. The $1,500 (not $1,400) threshold applies to non-utility

property, not utility pipe replacement, as Mr. McIntyre noted. RC Tr. I at 150-151; see also

CAD Cross Ex. 5 (Redacted) at 1. Instead, the Company’s approach to capitalization for pipe is

a functional, common-sense one: if a leak can be fixed with a clamp, the repair is expensed; if

the repair requires installation of new pipe, the installation is capitalized, without regard to the

length or value of the new pipe installed. RC Tr. I at 147-149 (McIntyre)

The Commission should also observe that the conclusions CAD draws from this

discussion are also incorrect. First, to the extent CAD is concerned that the Company’s

capitalization practice is impairing investment in infrastructure to reduce UFW - certainly the

sense of CAD’S quote of Mr. Fowler’s testimony (CAD Br. at 5) - the converse is far more

’* See Transcript of October 27, 2015 bearing in Case No. 15-0674-W-42T (“RC Tr. I”), pages 65- 66 (emphasis added). For what it is worth, we believe Mr. McIntyre was referring to “GASB 34,” short for the Governmental Accounting Standards Board’s Statement 34 that governs the financial reporting of state and local governments, and not “gas would be 34” as CAD assumed.

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likely. Expensing more investment under a CAD-recommended higher cost threshold for

capitalization (such as $3,000 for the gas companies?) would not allow the Company to recover

depreciation and a return on those investments. This would not only increase customer rates (at

least after the first rate case with this added expense in the test year), but disincentivize

otherwise-appropriate pipe replacement in the context of leak repair. It is hard to see how

customers would benefit from this arrangement. Also, CAD’s later charge that the Company is

incentivized by a return on invested capital to capitalize pipe replacement ignores the accepted

regulatory principle that customers should pay only for that portion of a capital asset’s useful life

from which they derive a benefit - not all of it in a single year. More than once in the rate case

hearing, Company witnesses explained the customer benefits of capitalization and how

expensing capital investments would harm customers; no recognition of those explanations

appears in the CAD brief.

The UFW and capitalization issues have no legitimate connection to setting depreciation

rates. Apart from exposing some questionable advocacy on CAD’s part, these issues deserve

little attention.

3.

At page 1 of its brief, CAD sought to convert the Company’s depreciation rate request,

which would generate an additional $3.9 million in depreciation expense based on the

Company’s HTY-based Rule 42 exhibit,lg into a request to recover “disputed depreciation

expenses of $251 million.” CAD Br. at 1. Not only does the $251 million request dwarf the

additional revenue requested in the rate case, CAD contended, it would also represent a $1,500

Misleading Representations of Depreciation Expense in Rates

l9 See Co. Ex. 1 in Case No. 15-0676-W-42T (HTY Rule 42 Exhibit) at Stmt. A, column 6. Note Staffs incorrect representation that the Company’s proposed depreciation rates would produce $6.6 million in revenue based on December 3 1,2014 plant balances. CAD Br. at 9.

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burden on every household the Company serves. Id. CAD returned to this rhetorical device

again and again. Id. at 2, 12, 14.

It is hard to imagine a more misleading comparison. For the Company’s biggest utility

accounts, recovery of depreciation expense will be measured in generations, not years. The

parties have agreed with Mr. Spanos’s average service life calculations, including 95 years for

mains. To encourage readers to confuse life-of-asset depreciation recovery with annual

depreciation expense is wrong, and unlike those who may learn about this case through media

coverage of CAD’S written advocacy, CAD knows better.

E. Conclusion and Request for Relief

The Company’s depreciation case presentation was straightforward and professional, and

not in the “state of disarray” CAD claimed. CAD Br. at 5 . Mr. Spanos’s depreciation study used

Commission-approved methods, including the incorporation of net salvage estimates using the

remaining life technique, to develop recommended depreciation accrual rates. Mr. Spanos

addressed the 50/50 allocation issue in a direct, effective way, developing reduced net salvage

estimates for the affected accounts that no party has challenged. He also used current, industry-

standard information in the net salvage estimation process, not the late-1990s retirement data

Staff proposed to use for selected accounts. And Mr. Spanos withstood cross-exmination

without incident, explaining the process to the Commission in some detail. There has been no

evidence to undermine his processes or results.

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The Company’s depreciation study and supporting testimony are sound and reliable. The

Company respectfully requests that the Commission adopt its recommendations as the basis for

new water and wastewater depreciation accrual rates.

WEST VIRGINIA-AMERICAN WATER COMPANY By Counsel

Christopher L. Callas, WV Bar ID 5991 JACKSON KELLY PLLC Post Office Box 553 Charleston, West Virginia 25322 Counsel for West Virginia-American Water Company

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CERTIFICATE OF SERVICE

I certify service of WEST VIRGINIA-AMERICAN WATER COMPANY’S REPLY

BRIEF on December 23,2015, by United States First Class Mail, postage prepaid, as addressed:

Tom White, Esq. Consumer Advocate Division 700 Union Building 723 Kanawha Boulevard, East Charleston, WV 25301

Andrew T. Gunnoe, Esq. P. 0. Box 3627 Charleston, WV 25336 Kanawha County Commission and

Regional Development Authoriy

David A. Sade, Esq. Public Service Commission of WV P. 0. Box 812 Charleston, WV 25323 PSC Staff

Paul D. Ellis, Esq. Mandi Kay Carter, Esq. 501 Virginia Street, East Charleston, WV 25301 City of Charleston

Paul R. Sheridan, Esq. 429 McKinley Ave. Charleston, WV 25314 Advocates for a Safe Water System

Derrick Price Williamson, Esq. Barry A. Naum, Esq. Spilman Thomas & Battle PLLC 1100 Bent Creek Blvd., Suite 101 Mechanicsburg, PA 17050 Wesi Virginia Energy Users Group

and S W A , Inc.

Lee F. Feinberg, Esq. Susan J. Riggs, Esq. Spilman Thomas & Battle, PLLC P. 0. Box 273 Charleston, WV 25321 West Virginia Energy Users Group

and SWVA, Inc. c a Christopher L. Callas

4851-0293-4060.v1