Rebuttal Testimony and Exhibits of Steven H. Ferguson, William E ...

WILLIAM C. PORTH
ATTORNEY AT LAW
ROBINSON
&McELWEE
P.O. BOX 1791
CHARLESTON, WV 25326
DIRECT DIAL: (304) 347-8340
E-MAIL: wce@,ramlaw.com
attorneys at law
November 22,201 0
BY HAND DELIVERY
Mrs. Sandra Squire
Executive Secretary
West Virginia Public Service Commission
201 Brooks Street
Charleston, WV 25301
Re:
Appalachian Power Company and
Wheeling Power Company
Case No, 10-0699-E-42T
Dear Mrs. Squire:
I am enclosing herewith on behalf of Appalachian Power Company and Wheeling Power
Company (“the Companies”) in the above-referenced proceeding the original and twelve (1 2) copies
of their rebuttal testimony.
WCP:tlw
Enclosures
cc: Service List
William C. Porth
(W.Va. State Bar #2943)
Counsel for Appalachian Power Company
and Wheeling Power Company
400 FIFTH THIRD CENTER 700 VIRGINIA.STREET, EAST CHARLESTON, WV 25301 (304) 344-5800
140 WEST MAIN STREET SUITE 300 CLARKSBURG, WV 26302 (304) 622-5022
www.ramlaw.com
{R05450 10. I}

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PUBLIC SERVICE COMM
F WEST VIRGINIA
.
REBUTTAL TE
NY AND EXHIBITS

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
STEVEN H. FERGUSON
n
1

SHF REBUTTAL EXHIBIT NO. 1
REBUTTAL TESTIMONY OF
STEVEN H. FERGUSON
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q. PLEASE STATE YOUR NAME.
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My name is Steven H. Ferguson.
ARE YOU THE SAME STEVEN H. FERGUSON WHO PRESENTED DIRECT
TESTIMONY IN THIS CASE
Yes, I am.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
The purpose of my rebuttal testimony is: 1) to discuss issues raised in the testimony of
CAD witness Alexander; 2) to propose the transfer of the Regional Transmission
Enhancement Plan (“RTEP”) charges to the Companies’ 2011 ENEC proceeding; 3) to
respond to the testimony of Staff witness Sprinkle on the amortization of the 2009 winter
storm expense; and 4) to address the tariff liability limitation provisions discussed in
Staff witness Melton’s testimony.
MS. ALEXANDER STATES THAT SOME OF THE COMPANIES’ POLICIES
AND PRACTICES RELATED TO LOW INCOME CUSTOMERS MAY NOT BE
IN COMPLIANCE WITH THE COMMISSION’S ELECTRIC RULES. IS SHE
CORRECT
No. I am not aware of any non-compliance with the Commission’s rules. The
Companies’ policies and practices are within the bounds of current law, Commission
regulations and practices, and the terms and conditions for electric service contained in
the Companies’ tariffs. While I certainly understand Ms. Alexander’s concerns about the
potential impact of a rate increase on the Companies’ low income residential customers, I
22 want to assure the Commission and other interested parties that our customers’ well-

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being is very important to us. Every day our customer service personnel work with low-
income customers to assist them with their service and payment issues, to help develop
payment plans to meet their individual needs where feasible, and to provide guidance
about possible financial assistance that may be available from federal, state and/or
community-based programs. Furthermore, all customers have the option of speaking
with a customer service supervisor in order to try to resolve any difficult or unusual
customer issues.
Q. DOES MS. ALEXANDER IDENTIFY SPECIFIC POLICIES OF THE
COMPANIES WHICH SHE REGARDS AS POSSIBLY NON-COMPLIANT
A. At page 36 of her direct testimony, she states:
It is my opinion that the Companies’ practices in implementing the
installment plan policies of the Commission’s regulations are at best
questionable and possible [sic] not in compliance. The Commission’s
regulations clearly require that customers who have received a
disconnection notice must be offered the opportunity to enter into a
‘reasonable payment plan.’
As previously stated, the Companies’ policies and practices, including those related to
installment plans, are in full compliance with the Commission’s regulations. After
customers have received a disconnection notice, they are given an opportunity to speak
with representatives of the Companies and work with them to prevent a disconnection of
service. As per the Companies’ existing credit and collections policies, an electronic file
is created three days prior to the scheduled termination of service to residential customers
who have been issued a disconnection notice. This file is sent to representatives in the
Direct Collections department, who then attempt to call the customers and advise them of
the impending disconnection due to nonpayment. The representatives are authorized to
discuss the payment plan options with the customer. Based on these conversations, the

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customer’s current circumstances, and past payment history, agreement may be reached
with the customer to establish a payment plan.
In addition, once customers receive a disconnection notice, they may call the
Companies’ Customer Solution Center and seek additional information. The Customer
Solution Center representatives are trained to assist customers, including informing
residential customers of available emergency assistance agencies, advising customers of
authorized payment agencies near their homes or businesses, and advising customers of
available payment options. If a customer who has received a disconnection notice still
has not spoken to either a Direct Collections or Customer Solution Center representative
after contact attempts have been made, a field representative will visit the customer
location to make personal contact and notify the customer of the impending
disconnection. During either contact with the Customer Solution Center or personal
contact with the field representative, personnel of the Companies have discretion to
forestall disconnection if they find extenuating circumstances, including but not limited
to medical conditions, life support equipment, elderly, handicapped, or infirm customers,
or the recent birth or death of a family member.
HAVE THE COMPANIES’ CREDIT AND COLLECTION POLICIES BEEN
MADE AVAILABLE TO THE PARTIES DURING THIS PROCEEDING
Yes. During the discovery phase of this case, the Companies submitted copies of their
credit and collection polices in response to Question B-25 of the CAD’S first set of
discovery requests.
MS. ALEXANDER RECOMMENDS THAT THE COMMISSION REJECT THE
COMPANIES’ PROPOSAL TO ALLOW REMOTE DISCONNECTION OF

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SERVICE TO RESIDENTIAL CUSTOMERS FOR NON-PAYMENT. DO YOU
AGREE
No, I do not agree. Ms. Alexander’s recommendation appears to be based on her
concerns that the number of disconnections will increase and that the standard practice of
attempting to contact customers prior to disconnection will be eliminated. The
Companies do not disconnect service to all accounts that receive a disconnection notice.
Many customers are paying their electric bills or cooperating with the Companies on
payment arrangements once a disconnection notice is received but prior to a physical
disconnection. Even with the technology and the authority to remotely disconnect
customers, the Companies will continue to follow their credit and collection policies that
specify the processes by which we work with OUT customers prior to any disconnection.
Although there are other values associated with the ability to remotely connect and
disconnect services, the greatest value of a remote disconnection option is to promote
safety. It is a sad reality that a small minority of customers will resort to violence and
threats of violence, sometimes even involving firearms, when confronting utility field
service personnel carrying out disconnection work orders. A remote disconnection
option offers tremendous potential for resolving such situations without risk of injury to
the Companies’ employees and risk of criminal liability for the belligerent customers.
MS. ALEXANDER ALSO RECOMMENDS THAT THE COMPANIES
INTERNALLY TRACK AND EVALUATE THE ABILITY OF LOWER INCOME
CUSTOMERS TO OBTAIN AND MAINTAIN ELECTRIC SERVICE. IS THAT
A WORKABLE RECOMMENDATION
Although I understand and appreciate Ms. Alexander’s suggestions, the Companies are
obligated by law to serve all customers within their territories who request electric

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service, regardless of income levels. The Companies do not have this kind of customer
demographic information as it is not necessary for the Companies to fulfill their legal
obligation to provide electrical service in a safe and efficient manner to its customers.
The Companies suggest that government agencies, such as the West Virginia Department
of Health and Human Resources (“WV DHHR”), are in a better position to track and
monitor this type of data. The WV DHHR currently provides comprehensive
coordination of assistance benefits to troubled customers and possesses the necessary
expertise to collect, evaluate, and safeguard pertinent information as it relates to low
income customers. Furthermore, the Companies would need to incur significant
additional costs to implement new systems, databases, and processes, in order to
implement Ms. Alexander’s recommendation, which costs in turn would have the effect
of increasing customer rates to recover this incremental costs.
PLEASE DISCUSS MS. ALEXANDER’S RECOMMENDATIONS THAT THE
COMPANIES ELIMINATE THE REQUIREMENT THAT BUDGET PAYMENT
PLANS BE LIMITED TO CUSTOMERS WITH NO ARREARS BALANCE AND
THAT THE COMPANIES CHANGE THE POLICY THAT AUTOMATICALLY
TERMINATES A BUDGET PAYMENT PLAN IF A CUSTOMER MISSES A
PAYMENT.
The Companies do not agree that the terms and conditions of its existing budget payment
plans need to be modified to accommodate payment-troubled customers. These
customers, which include customers with arrear balances, have other payment
arrangement options. As discussed later in my testimony, allowing customers to get too
far behind on their payments may actually lead them to give up when such arrears
become overwhelming. Commission rules with respect to the granting and renegotiating

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of deferred payment plans provide adequate flexibility for adjusting terms to a customer’s
means and ability to pay, and thus avoiding termination of service where there is a
reasonable prospect of payment. While every reasonable effort is made to assist a
delinquent customer to achieve a current actual usage or current budgeted usage payment
status in three months or less, payment plan durations often extend beyond that period,
based upon a customer’s ability to pay and expected future usage.
PLEASE DISCUSS MS. ALEXANDER’S RECOMMENDATIONS THAT THE
COMPANIES CHANGE THEIR POLICIES WITH REGARD TO
NOTIFICATION OF INSTALLMENT PAYMENT PLAN AVAILABILITY AND
TO MAKE THE “ENHANCED PAYMENT PLAN’’ IMPLEMENTED LAST
WINTER AVAILABLE ON A PERMANENT BASIS.
The Companies’ customers receive a message about budget billing plans directly on their
monthly electric bills. They can also review this information on the Companies’
website’. In addition, customers can call and speak with Customers Solution Center
employees to discuss these payment plans.
The Enhanced Payment Plan option was offered during the winter of 2009/2010
because of periods of prolonged cold temperatures. If there are abnormal or emergency
circumstances in the future, the Companies may consider implementing another
Enhanced Payment Plan, but we have discovered that offering this type of plan
sometimes actually impedes customers’ ability to get current on their bills. On an
ordinary day-to-day basis, however, the Companies regard their current bill payment
plans as effectively serving their customers by giving them payment options that they are
fiee to choose at any time during the course of the year. In addition, the Companies
“Level Your Payments”: httDs://www.appalachianpower.com/account/bills/maa~e/LevelPavments.as~x

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exercise discretion to negotiate initial payment amounts and/or the number of payments
on installment payment plans in response to individual customer circumstances.
PLEASE DISCUSS MS. ALEXANDER’S RECOMMENDATION THAT THE
COMPANIES TAKE ACTIONS TO INCREASE THE PENETRATION AND
ENROLLMENT OF THE STATUTORY 20% DISCOUNT PROGRAM.
The Companies believe their efforts to inform customers of assistance sources, in
conjunction with those made by local agencies, to be reasonable and sufficient to meet
customer needs. The Companies currently reach out to and assist payment-troubled
customers in determining what additional payment funds may be available. The
Companies maintain a database of all known sources of bill pay assistance for each
operating area. This database is accessible to all customer contact representatives for
customer referral. In addition, bill messages and inserts, as well as the Companies’
website, encourage customers with bill pay issues to contact the Companies’ Customer
Solution Centers, where customer contact representatives are available 24 hours a day
and are trained to offer information concerning bill pay assistance to all customers who
make contact and indicate an inability to pay.
The WV DHHR provides applications for the statutory 20% discount program to
customers with qualifying criteria, who may or may not be elderly customers, and mails
20% discount applications to all known eligible West Virginia residents. The Companies
facilitate enrollment by processing applications promptly. The vast majority of
applications are received in completed form and processed prior to the beginning of each
annual discount period. In the event an application is not accepted, the Companies return
the application to the customer with instructions on how to correct errors and re-apply. In
addition, customer contact representatives are trained to offer information about this

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program and to instruct customers on how to submit applications. The 20% discount
program is governed by W.Va. Code $$24-2A-1 et seq. Expansion of benefits or
eligibility requirements under this program would require a change in the law. Any
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interested party might advocate a change in the law, but a regulator should not ask a
public utility to advocate any particular position.
PLEASE DISCUSS MS. ALEXANDER’S RECOMMENDATION THAT THE
COMPANIES IMPLEMENT A PILOT PROGRAM THAT WOULD EXEMPT
KNOWN LOW INCOME CUSTOMERS FROM THE REQUIREMENT TO PAY
A SECURITY DEPOSIT AS A CONDITION OF SERVICE AND TO EXEMPT
SUCH CUSTOMERS FROM THE PAYMENT OF LATE FEES.
The Commission’s rules authorize and establish provisions respecting customer deposits.
The purpose of deposits is to offer utilities and all of their customers some protection
against excessive levels of charge-offs caused by non-paying customers. Deposits
applied to defaulted account balances reduce the Companies’ uncollectible accounts
expenses, the costs of which ultimately impact all ratepayers. Existing Commission rules
limit a residential deposit to one average monthly bill, while a utility’s practical exposure
for non-payment prior to permitted disconnection is more than two months. The
Commission’s rules also require that deposits be fully refunded (with interest) to
customers who make timely payments for twelve consecutive months, including those
who enter into annualized payment plans. Late charges are applied to accounts that are
paid past the due date. This fee is necessary to reimburse the Companies for some
portion of the direct expense associated with receiving late payments, such as rebilling
and processing. Late fees can also be an incentive for customers to pay their bills on time.
Both of Ms. Alexander’s proposals would require the Companies to obtain and maintain

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customer demographic information that is not necessary for the Companies to fulfill their
legal obligation to provide electric service in a safe and efficient manner to their
customers and would impose additional costs for implementation of the proposed
program and for dealing with any increased uncollectibles which they might cause.
MS. ALEXANDER AND MR. HARRIS RECOMMEND A RATEPAYER-
FUNDED LOW INCOME BILL PAYMENT ASSISTANCE DISCOUNT
PROGRAM. ARE THE COMPANIES OPEN TO SUCH A PROGRAM
The Companies are certainly willing to explore the idea. Mr. Harris further recommends
that the Commission provide guidance in this matter and, if it deems such a program
acceptable, to establish a task force for the purpose of proposing a revenue-neutral tariff
offering to implement such a program. The Companies share the concerns of low income
customers and are willing to work with other interested parties to address some form of
ratepayer-funded discount program, provided such a program is not unlawfully
discriminatory, the Companies are able to recover their costs associated with
implementing and maintaining the program, and the cost burden which the program
imposes on the Companies’ customers is not unreasonable.
PLEASE DISCUSS THE COMPANIES’ POSITION ON THE HANDLING OF
THE REGIONAL TRANSMISSION ENHANCEMENT PLAN CHARGES.
Included in the Companies’ Statement G adjustments filed on May 14,2010, Adjustment
No. 16-PE, Transmission & Distribution Expense, increased the PJM Regional
Transmission Enhancement Plan charges by $9,43 1,s 10. After consideration of the
matter, the Companies propose that these charges should be part of the ENEC
proceeding.
WHY ARE THE COMPANIES MAKING THIS PROPOSAL

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Over time there have been a number of changes in the components reflected in the
ENEC. In 1992, the Commission included the costs associated with the AEP
Transmission Equalization Agreement in the ENEC; later other items such as emission
allowances were included. Since 2004, when AEP became a member of the PJM
Regional Transmission Organization, a number of new accounts have been created to
better identify the charges associated with PJM transmission charges. When the account
was created to reflect the RTEP charges, it was inadvertently overlooked and not
included as part of the ENEC. After filing the instant rate case, the Companies
recognized that these charges were more appropriately included in the ENEC. They are
now proposing to move the RTEP charges from this case and, if that arrangement is
acceptable, will report the 2010 balance in the Companies’ 2011 ENEC filing to be made
by March 1,2011. Because these charges have not been included in rates before, the
Companies will also move the balances through December 2009 into the ENEC.
WHAT POSITION DO THE COMPANIES TAKE IF THE COMMISSION
DECIDES THAT THE RTEP CHARGES SHOULD NOT BE HANDLED IN THE
ENEC
In that event, the Companies continue to support Adjustment No. 16-PE.
DO YOU HAVE ANY COMMENTS ON THE TESTIMONY OF STAFF
WITNESS SPRINKLE REGARDING THE AMORTIZATION OF THE LARGE
EXPENSE CAUSED BY THE SEVERE STORMS OF DECEMBER, 2009
Yes. Company witness Brubaker addresses in his rebuttal testimony two aspects of the
subject, providing an update of the precise amount of incremental storm damage expense
and responding to Mr. Sprinkle’s mistaken suggestion that APCo could have capitalized
more of that expense than it did. I wish to respond to Mr. Sprinkle’s recommendation as

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to the length of amortization of this expense and his opposition to APCo being allowed to
earn a return on the unamortized balance of the expense. The Companies have proposed
the precise treatment which this Commission accorded Allegheny Power in 1994 in
connection with a comparable major storm expense. In that case, as Company witness
Patton noted in his direct testimony, the Commission rejected a proposed ten-year
amortization and decided to approve a five-year amortization. If the Commission were
inclined to consider the ten-year amortization proposed by Mr. Sprinkle, it should only do
so in conjunction with the authorization for APCo to earn a return on the unamortized
balance. It is Companies’ position that any extended period of time to carry such a
burden should allow for a return component and that the Commission should approve the
Companies’ five-year amortization proposal.
STAFF WITNESS EARL MELTON ADDRESSED IN HIS DIRECT TESTIMONY
THE COMPANIES’ REQUEST TO ADD REFERENCES TO THEFT OF
COMPANY PROPERTY AND VOLTAGE VARIANCES TO THEIR CURRENT
TARIFF LIMITATION OF LIABILITY LANGUAGE. ARE MR. MELTON’S
CONCERNS WARRANTED
No. It is important for the Companies to define the basic limits of their liability in their
tariffs because, for the vast majority of their customers, there is no separate contract in
which this issue could be addressed. Without such a clear limitation, the Companies
could be exposed to unjustified litigation for a vast array of consequential damages
arising from incidents which are outside their control and with respect to which they have
not been negligent. The two modifications proposed by the Companies are intended
simply to add specificity with respect to two aspects of the limitation language. The first
change is to clarify that the limitation applies not only to interruptions of service but also

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to service that is outside of normal voltage specifications. The second change is to add to
the enumeration of the causative forces outside of the Companies’ control the theft of
their equipment.
Contrary to Mr. Melton’s concerns, the requested changes would not allow the
Companies to unreasonably delay fixing a known problem or engage in unreasonable
practices regarding abnormal voltages. The Companies maintain reliability and voltage
standards which are already monitored by the Commission and which, incidentally, are in
the process of being updated with the collaboration of the Staff and other stakeholders.
The limitation of liability language has no effect on the Companies’ commitment to
reliability and safety or the Commission’s jurisdiction to ensure that they live up to that
commitment.
DOES THE LIMITATION OF LIABILITY LANGUAGE HELP THE
COMPANIES DEFEND AGAINST UNJUSTIFIED CLAIMS IN LITIGATION
Yes. The Companies have long relied on the tariffs’ limitation of liability language to
reduce exposure to unjustified claims for damages that are beyond the Companies’
control and would often be covered by standard homeowner or other insurance policies.
West Virginia courts have regularly recognized this limitation. The result has been to
avoid expenses that would otherwise add to the Companies’ cost of service.
WOULD A CURTAILMENT OF THE LIMITATION OF LIABILITY
LANGUAGE ENHANCE RELIABILITY OF SERVICE
Absolutely not. The Companies’ commitments to reliability and good service are
unaffected by the limitation of liability language. A curtailment of the limitation of
liability language would simply drive up the Companies’ cost of service by increasing

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1 litigation costs and exposure to damage awards and by effectively turning the
2 Companies’ into uncompensated insurers of last resort.
3 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
4 A. Yes.

1
OF
WILLIAM E. AVERA
i
J

WEA Rebuttal Exhibit No. 1
PUBLIC SERVICE COMMISSION
OF WEST VIFUGINIA
CHARLESTON
Case No. 10-0699-E-42T
APPALACHIAN POWER COMPANY and
WHEELING POWER COMPANY
Rule 42T tariff filing to increase
rates and charges
REBUTTAL TESTIMONY
OF
WILLIAM E. AVERA
ON BEHALF
OF
APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
November 24,20 10
(R0544224.1)

WEA Rebuttal Exhibit No. 1
Page 2 of 55
REBUTTAL TESTIMONY OF
WILLIAM E. AVERA
TABLE OF CONTENTS
I.
11.
111.
IV.
V.
VI.
VII.
VIII.
Ix.
PROXY GROUP REVENUE TEST IS UNSUPPORTED .........................................5
NO BASIS TO DISREGARD NON-UTILITY PROXY GROUP ........................ ..... 10
STAFF AND WVEUG DCF RESULTS FAIL TO REFLECT INVESTORS’
EXPECTATIONS. .. ... . . . . . .. .. ... . .. .. .. ... . ... . . . . . .. ... ... . . . . . . . . .. ... . . . . ... .. ... . 19
DOWNWARD BIAS IN SUSTAINABLE DCF GROWTH RATES ........................ 26
STOCK PRICE GROWTH IS CONSISTENT WITH INVESTORS’ VIEWS .......... 28
ILLOGICAL DATA UNDERLYING STAFF AND WVEUG CAPM
ANALYSES ............................ .......... .......................................................................... 31
EXPECTED EARNINGS METHOD IS AN ACCEPTED APPROACH .................. 43
NO BASIS TO IGNORE FLOTATION COSTS ................................................. .. ..... 50
END RESULT TEST ................................................................................................... 54
WEA Rebuttal Exhibit No. 2 ................ Short DCF Analysis - Revised Growth Rate Screen
WEA Rebuttal Exhibit No. 3 . .,. ,. . Baudino DCF Analysis - Revised Growth Rate Screen
WEA Rebuttal Exhibit No. 4 ...... Baudino CAPM Analysis - Revised Market Growth Rate
WEA Rebuttal Exhibit No. 5 .................................................... Expected Earnings Approach
WEA Rebuttal Exhibit No. 6 .......................................................................... Allowed ROES

WEA Rebuttal Exhibit No. 1
Page 3 of 55
REBUTTAL TESTIMONY OF
WILLIAM E. AVERA
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
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PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is William E. Avera, and my business address is 3907 Red River,
Austin, Texas, 78751.
BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY
I am the President of FINCAP, Inc., a firm providing financial, economic, and
policy consulting services to business and government.
DID YOU PROVIDE DIRECT TESTIMONY IN THIS PROCEEDING
Yes. My direct testimony presented my independent assessment of the fair rate of
return on equity for the jurisdictional electric utility operations of Appalachian
Power Company (“APCo”) and Wheeling Power Company (“WPCo”)
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(collectively the “Companies”).
This rebuttal testimony will use the same
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capitalized terms used in my direct testimony.
‘WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
My testimony addresses the testimony of Randall R. Short, submitted on behalf of
the Staff of the WVPSC and Richard A. Baudino, on behalf of the West Virginia
Energy Users Group (“WVEUG”), concerning a fair ROE to apply to the rate
base of the Companies.
PLEASE SUMMARIZE THE PRINCIPAL CONCLUSIONS OF YOUR
REBUTTAL TESTIMONY.
My rebuttal testimony demonstrates that:
0 Cost of equity estimates for the Non- Utility Proxy Group provide an

WEA Rebuttal Exhibit No. 1
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important benchmark that is consistent with financial theory, how
real-world investors operate, and the guidelines underlying a fair
ROE;
The expected earnings approach is entirely consistent with the
regulatory and economic principles advanced in the testimony of Mr.
Short and Mr. Baudino witnesses and represents an “apples to
apples” comparison with the allowed ROE;
The recommendations of Mr. Short and Mr. Baudino are woefully
inadequate to compensate investors in the Companies when evaluated
against the results of the expected earnings approach for the proxy
utilities;
Allowed ROES also demonstrate that Mr. Short’s and Mr. Baudino ’s
recommendations are too low to be credible;
Ifthe utility is unable to offer a return similar to that availableporn
other opportunities of comparable risk, investors will become
unwilling to supply the capital on reasonable terms, and investors will
be denied an opportunity to earn their opportunity cost of capital;
Because historical and dividend growth rates are not representative of
investors ’future expectations, projected earnings growth rates provide
a superior basis to apply the DCF model; and,
The failure of Mr. Short and Mr. Baudino to consider the impact of
flotation costs contradicts the findings of the financial literature and
the economic requirements underlying a fair rate of return on equity.
With respect to their analyses, I concluded that:
Mr. Short and Mr. Baudino failed to adequately evaluate the
reasonableness of their individual cost of equity estimates, and there is
no economic basis for the method used by Mr. Baudino to screen his
analyses for outliers;
Excluding illogical values fiom Mr. Short’s and Mr. Baudino ’s DCF
analyses resulted in average cost of equity estimates of 10.88percent
and 10.64 percent, respectively;
Growth in stock price is consistent with the assumptions underlying
the DCF method and investors’ expectations, and provides a logical
alternative to the downward bias of the distorted analyses presented
by Mr. Short and Mr. Baudino;
Historical CAPM applications are inconsistent with the underlying
assumptions of this approach andproduce cost of equity estimates that
are far below investors’ required return;
while Mr. Baudino granted that investors are more likely to focus on

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earnings growth when analyzing their expected rate of return for nonutility
companies, his forward-looking application of the CAPM model
was inconsistent with this observation; and,
Correcting this bias results in implied CAPM cost of equity estimates
for Mr. Baudino ’s proxy group of 10.70 percent and 10.98 percent.
My rebuttal testimony also demonstrates that Mr. Short’s and Mr. Baudino’s
criticisms of my alternative applications and conclusions are misguided and
should be rejected. There is nothing in the testimony of Mr. Short or Mr. Baudino
that would cause me to revise my recommended ROE range of 10.6 percent to
12.6 percent, or 10.75 percent to 12.75 percent after incorporating a minimum
adjustment to account for the impact of common equity flotation costs.
I. PROXY GROUP REVENUE TEST IS UNSUPPORTED
12 Q.
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DO YOU AGREE WITH MR. BAUDINO AND MR. SHORT THAT THE
SOURCE OF A UTILITY’S REVENUES IS A VALID CRITERION IN
SELECTING A PROXY GROUP FOR THE COMPANIES
No. Mr. Baudino selected proxy companies with at least 50 percent of their
revenues fiom electric operations, while Mr. Short argued for the elimination of
companies if less than 70 percent of total revenues were attributable to electric
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utility service.’
However, both witnesses failed to demonstrate how this
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subjective criterion translates into differences in the investment risks perceived by
investors. Any comparison of objective indicators demonstrates that investment
risks for the firms in my proxy groups are relatively homogeneous and
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comparable to the Companies.
Moreover, there are significant errors and
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inconsistencies associated with the approach adopted by Mr. Baudino and Mr.
Short that justify rejecting their proposed proxy group criteria.
Baudino Direct at 14; Short Direct at 23.

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DID MR. BAUDINO OR MR. SHORT DEMONSTRATE A NEXUS
BETWEEN THEIR SUBJECTIVE REVENUE CRITERION AND
OBJECTIVE MEASURES OF INVESTMENT RISK
No. Under the regulatory standards established by Hope2 and BZueJeZd, the
salient criterion in establishing a meaningful proxy group to estimate investors’
required return is relative risk, not the source of the revenue stream. Mr. Baudino
and Mr. Short presented no evidence to demonstrate a connection between the
subjective revenue criterion that they employed and the views of real-world
investors in the capital markets.
Moreover, the comfort that Mr. Baudino and Mr. Short take in limiting
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their proxy groups is misplaced.
Due to differences in business segment
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definition and reporting between utilities, it is often impossible to accurately
apportion financial measures, such as total revenues, between utility segments
(e.g. , electric and natural gas) or regulated and non-regulated sources. As a result,
even if one were to ignore the fact that there is no clear link between the source of
a utility’s revenues and investors’ risk perceptions, it is generally not possible to
accurately and consistently apply revenue-based criteria. In fact, other regulators
have rebuffed these notions, with FERC rejecting attempts to restrict a proxy
group to companies based on sources of revenues. As FERC concluded:
This is inconsistent with Commission precedent in which we have
rejected proposals to restrict proxy groups based on narrow
company attributes
Similarly, FERC has specifically rejected arguments analogous to those of Mr.
Short (p. 44) and Mr. Baudino (p. 14) that utilities “should be excluded fiom the
Fed. Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591 (1944).
BlueJield Water Works & Improvement Co. v. Pub. Serv. Comm’n, 262 U.S. 679 (1923).
Pepco Holdings, Inc., 124 FERC 7 6 1,176 at P 1 18 (2008) (footnote omitted).

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proxy group given the risk factors associated with its unregulated, non-utility
business operation^."^
DOES OBJECTIVE EVIDENCE CONFIRM THAT THESE SUBJECTIVE
CRITERIA ARE NOT SYNONYMOUS WITH COMPARABLE RISK IN
THE MINDS OF INVESTORS
6 A.
Yes.
Bond ratings are perhaps the most objective guide to utilities’ overall
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investment risks and they are widely cited in the investment community and
referenced by investors. While the bond rating agencies are primarily focused on
the risk of default associated with the firm’s debt securities, bond ratings and the
risks of common stock are closely related. As noted in Regulatory Finance:
Utilities’ Cost of Capital:
Concrete evidence supporting the relationship between bond
ratings and the quality of a security is abundant. ... The strong
association between bond ratings and equity risk premiums is well
documented in a study by Brigham and Shome (1 982)!
Indeed, Mr. Short (Appendix D) also reviewed the bond ratings of the companies
in his proxy group. Mr. Baudino (p. 12) testified that bond ratings are based on
“detailed analyses of factors that contribute to the risks of a particular investment”
and “quantify the total risk of a company.”
As shown on Mr. Short’s Appendix D, 23 utilities were identified as
21
having electric revenues below his 70 percent threshold.
Apart from two
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companies that were not rated, all of these utilities are shown to have an S&P
bond rating equal to or stronger than the criterion used to establish Mr. Short’s
proxy group. Similarly, while Sempra Energy’s electric revenues fell below Mr.
Baudino’s 50 percent cutoff, its bond rating reflects a comparable level of risk
Bangor Hydro-Elec. Co., 1 17 FERC 1 6 1,129 at PP 19,26 (2006).
Morin, Roger A., “Regulatory Finance: Utilities’ Cost of Capital,” Public Uti& Reports (1 994) at 8 1.

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WHAT DO YOU CONCLUDE FROM THIS REVIEW OF INDEPENDENT,
OBJECTIVE RISK FACTORS USED BY THE INVESTMENT
COMMUNITY
Considering that credit ratings provide one of the most widely referenced
benchmarks for investment risks, a comparison of this objective indicator
demonstrates that the range of risks for the companies eliminated under the
subjective revenue criterion proposed by Mr. Baudino and Mr. Short are either
less than or entirely comparable to those of the other firms in my Utility Proxy
Group. Contrary to the allegations of Mr. Baudino and Mr. Short, comparisons of
this objective, published indicator that incorporates consideration of a broad
spectrum of risks confirms that there is no link between the subjective tests they
applied to define their proxy groups and the risk perceptions of investors. In other
words, there is no factual basis to distinguish between the risks that investors
associate with the companies that Mr. Baudino and Mr. Short would eliminate
under their subjective revenue criteria and those included in their proxy groups.
ARE THERE OTHER INCONSISTENCIES ASSOCIATED WITH THE
REVENUE TESTS PROPOSED BY MR. BAUDINO AND MR. SHORT
Yes. While Mr. Baudino and Mr. Short screened all electric and combination
electric and gas utilities followed by Value Line, their revenue tests were based
solely on electric revenues and ignored the impact of gas utility operations. For
example, despite the fact that SCANA Corporation reported in its 2009 Form 10-
K report that electric and gas utility operations contributed 73 percent of
consolidated revenues, Mr. Short would exclude this firm under his revenue test.
Similarly, while Mr. Baudino excluded Sempra Energy from the proxy group, the
electric and gas utility segments posted 2009 revenues equal to 77 percent of the

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total consolidated revenues.’ Meanwhile, Wisconsin Energy Corporation reported
in its 2009 Form 1 O-K Report (p. 109) that its regulated utility segment accounted
for approximately 99.7 percent of total revenues. Considering the similarities in
the regulatory and business environments for regulated electric and gas utility
operations, the failure of Mr. Baudino and Mr. Short to incorporate gas utility
revenues in implementing their tests makes no sense.
The subjective nature of the revenue criteria proposed by Mr. Baudino and
Mr. Short is further illustrated by the wide disparity between the thresholds
imposed by these respective witnesses. Apart from the absence of any objective
evidence to link revenues with investors’ risk perceptions, the fact that one
witness would impose a 50 percent electric revenue criterion (Mr. Baudino) while
the other would set the bar at 70 percent (Mr. Short) reveals the lack of any
underlying basis for their arbitrary tests.
ARE THERE OTHER PROBLEMS ASSOCIATED WITH THE DATA
USED BY MR. SHORT TO SCREEN HIS PROXY GROUP
Yes. While Mr. Short applied screens based on bond ratings reported by AUS
Utility Reports, these reflect senior debt ratings, not the corporate, or issuer, credit
rating for the utility as a whole. Because equity investors are focused on the
overall investment risks of the fm, and not those attributable to a specific debt
issue, the appropriate indicia is the corporate credit rating.
For example, while Mr. Short includes UniSource Energy Corporation
(“UniSource”) in his proxy groups based on an S&P bond rating of “BBB+”, the
corporate credit rating corresponding to UniSource is “BB+”.8 This rating falls
below the ladder of investment grade ratings and places UniSource in the same
’ Sempra Energy, 2009 Annual Report at Note 18.
Standard & Poor’s Corporation, “Tucson Electric Power Co.,” RatingsDirect (Dec. 22,2009). S&P’s
ratings, including those relied on by Mr. Short, reflect its assessment of Unisource’s primary subsidiary.

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category as speculative, or “junk” investments. As S&P informed investors,
UniSource’s finances and risks reflect “the continuing effect of a series of losses
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and near bankruptcy two decades ago.”’
A junk bond rating does not reflect
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comparable risks to the Companies and the financial and operating challenges that
typically accompany a speculative grade rating color the data used to estimate the
cost of equity and seriously compromise the resulting estimates.
ARE THERE OTHER INACCURACIES REFLECTED IN THE BOND
RATINGS RELIED ON BY MR. SHORT
Yes. Mr. Short excluded Edison International from his proxy group based on his
understanding that S&P does not report credit ratings for this utility.” In fact,
S&P has assigned Edison International a corporate credit rating of “BBB-”, while
its principal utility subsidiary - Southern California Edison Company - is rated at
“BBB+”.ll Because these ratings are comparable to APCo’s “BBB” rating, Mr.
Short should have included Edison International in his proxy group.
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11. NO BASIS TO DISREGARD NON-UTILITY PROXY GROUP
IS THERE ANY BASIS TO IGNORE REQUIRED RETURNS FOR NON-
UTILITY COMPANIES
No. The implication that an estimate of the required return for firms in the
competitive sector of the economy is not useful in determining the appropriate
return to be allowed for rate-setting purposes is wrong. In fact, returns in the
competitive sector of the economy form the very underpinning for utility ROES
because regulation purports to serve as a substitute for the actions of competitive
markets. The Supreme Court has recognized that it is the degree of risk, not the
’ Id.
lo Short Direct at Appendix D.
* Standard & Poor’s Corporation, “Edison International,” RatingsDirect (Jul. 29,201 0).

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nature of the business, which is relevant in evaluating an allowed ROE for a
utility.12
Consistent with this view, Mr. Baudino noted (pp. 9-10) that the notion of
“opportunity cost” underlies the Supreme Court’s economic standards, and that:
One measures the opportunity cost of an investment equal to what
one would have obtained in the next best alternative. ... That
alternative could have been another utility stock, a utility bond, a
mutual fund, a money market fund, or any other number of
investment vehicles. (emphasis added)
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Similarly, Mr. Short recognized that allowed returns to utility stockholders should
be “commensurate with the returns earned by other firms with corresponding
risks,” and that investors consider “the returns being earned on other types of
investments” when evaluating their required return for utility stocks. l3
As Mr. Baudino correctly observed (p. lo), “The key determinant in
deciding whether to invest, however, is based on comparative levels of risk,” and
he concluded, “[Tlhe task for the rate of return analyst is to estimate a return that
is equal to the return being offered by other risk-comparable firms.” In other
words, Mr. Baudino granted that investors gauge their required returns from
utilities against those available from non-utility firms of comparable risk. My
reference to a comparable-risk Non-Utility Proxy Group is entirely consistent
with the guidance of the Supreme Court and the principles outlined in Mr.
Baudino’s and Mr. Short’s own testimony and sources.
DO UTILITIES HAVE TO COMPETE WITH NON-REGULATED FIRMS
FOR CAPITAL
Most certainly. The cost of capital is an opportunity cost based on the returns that
investors could realize by putting their money in other alternatives, which
l2 Fed. Power Comm‘n v. Hope Natural Gas Co., 320 U.S. 591 (1944).
l3 Short Direct at 8-9.

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according to Mr. Baudino include mutual funds and any number of other
alternatives available in the stock, bond or money markets. Clearly the total
capital invested in utility stocks is only the tip of the iceberg of total common
stock investment and there are a plethora of “other firms with corresponding risk”
available to investors beyond those in the utility industry.
DO MR. BAUDINO OR MR. SHORT RAISE ANY MEANINGFUL
CRITICISMS REGARDING THE USE OF YOUR NON-UTILITY PROXY
GROUP
No. Mr. Short presented no evidence to rebut the results for my Non-Utility
Proxy Group. Meanwhile, Mr. Baudino simply observed that there are differences
in the degree of regulation and the types of operations between my Non-Utility
Proxy Group and utilities. These sweeping generalizations are a straw man that
avoids the only question that matters; namely, what do objective measures tell us
about investors’ perceptions of relative risk
My direct testimony did not contend that the operations of the companies
in the Non-Utility Proxy Group are comparable to those of electric utilities.
Clearly, operating a worldwide enterprise in the restaurant, beverage, computer
software, retail, or transportation industry involves unique circumstances that are
as distinct from one another as they are from an electric or gas utility, But as the
Mr. Short and Mr. Baudino recognized, investors consider the expected returns
available from all these opportunities in evaluating where to commit their scarce
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capital.
So long as the risks associated with my Non-Utility Group are
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comparable to the Companies and other utilities - and my direct testimony
demonstrates conclusively that this is the case - the resulting DCF estimates
provide a meaningful benchmark for the cost of equity.

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My Non-Utility Proxy Group is comprised of 59 of the best-known and
most stable corporations in America and has risk measures that are comparable to,
or less than the proxy group of utilities referenced in my analyses. While these
companies do not have the regulatory protections that utilities have, neither do
they bear the burdens of losing control over their prices, undertaking the
obligation to serve, and having to invest in infrastructure even in unfavorable
market conditions. The Companies can’t relocate their service territories to an
area with a more attractive business climate or higher prospects for economic
growth, or abandon customers when turmoil roils energy or capital markets.
Consider Mr. Baudino’s statement that utilities “have protected markets . . .
enjoy full recovery of prudently incurred costs, and may increase their rates to
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cover increases in
Based on this, Mr. Baudino summarily concluded,
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“Obviously, the non-utility companies have higher overall risk structures.” In
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fact, however, investors are quite aware that utilities are
guaranteed recovery
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of prudent costs and that there are many instances in which utilities are unable to
increase rates to fully recoup reasonable and necessary costs, resulting in an
inability to earn the allowed rate of return on invested capital. The simple
observation that a firm operates in non-utility businesses says nothing at all about
the overall investment risks perceived by investors, which is the very basis for a
fair rate of return.
For example, consider (1) an electric utility such as UniSource with frozen
rates, a debt-to-capital ratio of 73 percent, and a junk bond credit rating, versus
(2) Wal-Mart Stores, Inc. (“Wal-Mart”), which faces competition on numerous
fronts. Despite its lack of a regulated monopoly, with a double-A bond rating, the
highest Value Line Safety Rank, and a beta that is comparable to the average for
l4 Baudino Direct at 32.

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my proxy group, the investment community would undoubtedly regard Wal-Mart
as a less risky alternative to UniSource, one of the utilities included in Mr. Short’s
proxy group.
DID MR. BAUDINO PRESENT ANY OBJECTIVE EVIDENCE TO
SUPPORT HIS CONTENTION THAT YOUR NON-UTILITY PROXY
GROUP IS RISKIER THAN THE COMPANIES OR YOUR PROXY
GROUP OF ELECTRIC UTILITIES
No. Apart from sweeping generalizations about the risk differences between
regulated and non-regulated companies, Mr. Baudino provided no support
whatsoever for his contention. In fact, the objective risk measures specifically
cited by Mr, Baudino as being relevant indicia of overall investment risks
contradict his generalizations. As noted earlier, Mr. Baudino testified that bond
ratings reflect a detailed and comprehensive analysis of the key factors
contributing to a firm’s overall investment risk, concluding (p. 12), “bond ratings
are tools that investors use to assess the risk comparability of firms.” But when it
came time to take an objective look at the risks of my Non-Utility Proxy Group,
bond ratings were one of the many unbiased implements that Mr. Baudino left
unused in his toolbox.
Contradicting Mr. Baudino’s unsupported assertion (p. 32) that the
companies in my Non-Utility Proxy Group “have higher overall risk structures,”
my direct testimony noted that the average corporate credit rating for the Non-
Utility Proxy Group of “A” is higher than the “BBB” average for the Utility
Proxy Group and APCo. This comparison is reinforced by the fact that S&P
ceased publishing separate ratings guidelines for regulated utilities in 2007, and
25 now applies the same matrix of business and financial risks used to evaluate non-

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regulated companies. As S&P concluded, “This is designed to present our rating
conclusions in a clear and standardized manner across all corporate sector^."'^
Similarly, the Safety Rank, which ranges from “1” (Safest) to “5”
(Riskiest), is Value Line’s primary risk indicator, and is intended to capture the
total risk of a stock, including elements of stock price stability and financial
strength. Given that Value Line is a widely available source of investment
advisory information, its Safety Rank provides usekl guidance regarding the risk
perceptions of investors. As discussed in my direct testimony,16 all of the firms in
my Non-Utility Proxy Group have a Safety Rank of “l”, which classifies them
among the least risky stocks covered by Value Line. Meanwhile, the average
Safety Rank for the firms in my Utility Proxy Group is “2”. In other words,
according to the key Value Line risk indicator, which Mr. Baudino described as “a
measure of total risk,”17 my Non-Utility Proxy Group is less risky in the minds of
investors. Similarly, the average beta value of 0.75 for the Non-Utility Proxy
Group is essentially identical to the 0.73 average for the Utility Proxy Group and
generally indicates comparable risk. In fact, the review of objective indicators of
investment risk presented in my direct testimony (Table WEA-3), which consider
the impact of competition and market share, demonstrated that, if anything, the
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risky in the minds of
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investors than the Companies or the common stocks of the proxy group of
utilities.
l5 Standard & Poor’s Corporation, ‘W.S. Utilities Ratings Analysis Now Portrayed In The S&P Corporate
Ratings Matrix,” RatingsDirect (Nov. 30, 2007).
Avera Direct at Table WEA-3.
l7 Baudino Direct at 24.

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Q. DOES THE FACT THAT UTILITIES ARE REGULATED SOMEHOW
INVALIDATE THE COMPARISON OF OBJECTIVE RISK INDICATORS
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DEVELOPED IN YOUR DIRECT TESTIMONY
Absolutely not. While I don’t disagree with Mr. Baudino that utilities operate
under a regulatory regime that differs from firms in the competitive sector, any
risk-reducing benefit of regulation is already incorporated in the overall indicators
of investment risk discussed above and presented in my direct testimony. The
impact of regulation on a utility’s investment risks is considered by credit rating
agencies, such as S&P, when establishing corporate credit ratings. As a result, the
impact of regulatory differences on investment risk is accounted for in the
published risk indicators relied on by investors and cited in my direct testimony.
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Q. DO YOU AGREE WITH MR. BAUDINO’S CONCLUSIONS (P. 33)
REGARDING THE IMPLICATIONS OF RELATIVE DCF ESTIMATES
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A.
No. The relevant exercise in evaluating a fair ROE for the Companies is to
employ objective evidence, such as credit ratings, to detennine alternative
investments of comparable risk and then apply accepted quantitative methods to
estimate the cost of equity. Mr. Baudino turns this process on its head, claiming
instead that because the DCF results for the Non-Utility Proxy Group are higher
than the results for the Utility Proxy Group, this somehow “tells the whole story.”
Mi. Baudino is misguided.
An example from the utility industry demonstrates the fallacy of Mr.
Baudino’s position. Consider ALLETE, Inc. (“ALLETE”), with a projected EPS
growth rate fiom Value Line of 1.00 percent,” and Wisconsin Energy Corporation
(“WEC”), with an expected EPS growth rate of 9.5 percent.” Combining these
growth rates with Mr. Baudino’s dividend yields results in cost of equity estimates
* Baudino Direct at Exhibit RAB-4, p. 1.
l9 Id.

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for ALLETE and WEC of 5.92 percent and 12.47 percent, respectively.20 Based
on Mr. Baudino’s paradigm, we would expect that the risks associated with WEC
would be dramatically higher than those for ALLETE. In fact, this is not the case
at all. Mr. Short’s Appendix D reports an S&P credit rating for WEC of “A-”,
which is identical to the rating shown there for ALLETE.
In fact, it is precisely because of this wide potential variation in DCF
estimates that it is imperative to examine the results for alternatives of comparable
risk, including the Non-Utility Proxy Group. The fact that the DCF estimates for
the Non-Utility Proxy Group are significantly higher than Mr. Baudino’s and Mr.
Short’s ROE recommendations for the Companies provides additional evidence
that their recommended ROES are inadequate to attract capital.
WOULD IT BE CONSISTENT WITH THE BLUEFIELD AND HOPE
CASES TO DISREGARD REQUIRED RETURNS FOR NON-UTILITY
COMPANIES
No. The Bluefield case refers to “business undertakings attended with comparable
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risks and uncertainties.”
It does not restrict consideration to other utilities.
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Similarly, the Hope case states:
By that standard the return to the equity owner should be
commensurate with returns on investments in other enterprises
having corresponding risks.
As in the Bluefield decision, there is nothing to restrict “other enterprises” solely
to the utility industry.
Indeed, in teaching regulatory policy I usually observe that in the early
applications of the comparable earnings approach, utilities were explicitly
eliminated due to a concern about circularity. In other words, soon after the Hope
2o As reflected on Mr. Baudino’s Exhibit RAB-3, the average dividend yield for ALLETE was 4.92
percent, versus 2.97 percent for WEC.

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decision regulatory commissions did not want to get involved in circular logic by
looking to the returns of utilities that were established by the same or similar
regulatory commissions in the same geographic region. To avoid circularity,
regulators looked instead to the returns of non-utility companies.
Q. DOES CONSIDERATION OF THE RESULTS FOR THE NON-UTILITY
PROXY GROUP MAKE THE ESTIMATION OF THE COST OF EQUITY
USING THE DCF MODEL MORE RELIABLE
A. Yes. The estimates of growth from the DCF model depend on analysts’ forecasts.
It is possible for utility growth rates to be distorted by historical trends in the
industry (e.g., changes in payout ratios) or the industry falling into favor or
disfavor by analysts. The result of such distortions would be to bias the DCF
estimates for utilities. For example, Value Line recently observed that near-term
growth rates understate the longer-term expectations for gas utilities:
Natural Gas Utility stocks have fallen near the bottom of our
Industry spectrum for Timeliness. Accordingly, short-term
investors would probably do best to find a group with better
prospects over the coming six to 12 months. Longer-term, we
expect these businesses to rebound. An improved economic
environment, coupled with stronger pricing, should boost results
across this sector over the coming years.21
Because the Non-Utility Proxy Group includes low risk companies from many
industries, it diversifies away any distortion that may be caused by the ebb and
flow of enthusiasm for a particular sector.
21 The Value Line Investment Survey at 445 (Mar. 12,2010).

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111. STAFF AND WVEUG DCF RESULTS FAIL TO REFLECT
INVESTORS’ EXPECTATIONS
WHAT ARE THE FUNDAMENTAL DIFFERENCES BETWEEN YOUR
DCF ANALYSIS AND THAT OF MR. SHORT
There are four key distinctions between my DCF analysis and that of Mr. Short:
1) whereas Mr. Short incorporates historical results as being indicative of what
investors expect, my analysis focuses directly on forward-looking data; 2) Mr.
Short discounts reliance on analysts’ growth forecasts in earnings per share
(“EPS”) as somehow biased, while my application of the DCF model recognizes
that it is investors’ perceptions and expectations that must be considered in
applying the DCF model; 3) rather than looking to the capital markets for
guidance as to investors’ forward-looking expectations, Mr. Short applies the DCF
model based on his own personal views; and, 4) whereas my analysis explicitly
excludes data that result in illogical cost of equity estimates, Mr. Short essentially
assumes that any resulting bias will be eliminated through averaging.
DO YOU BELIEVE THAT THE RESULTS OF MR. SHORT’S DCF
ANALYSIS MIRROR INVESTORS’ LONG-TERM EXPECTATIONS IN
THE CAPITAL MARKETS
No. There is every indication that his DCF results are biased downward and fail
to reflect investors’ required rate of return. As I explained in my direct testimony,
historical growth rates (such as those referenced by Mr. Short to apply the DCF
model) are colored by the structural changes and numerous challenges faced in
the utility industry. Moreover, given recent financial trends in the utility industry
and the importance of earnings in determining future cash flows and stock prices,
growth rates in dividends per share (“DPS”) and book value per share (C‘BVPS”)
are not likely to be indicative of investors’ long-term expectations. As a result,

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DCF estimates based on these growth rates do not capture investors’ required rate
of return for the industry.
Consider Mr. Short’s reference to historical growth rates, for example. If
past trends in EPS, DPS, and BVPS are to be representative of investors’
expectations for the future, then the historical conditions giving rise to these
growth rates should be expected to continue. That is clearly not the case for
utilities, where structural and industry changes have led to declining dividends,
earnings pressure, and, in many cases, significant write-offs. As Mr. Short noted
(p. 27-28), the growth rate variable in the DCF model reflects investors’ expected
rate of growth into the future. While past conditions for utilities serve to distort
historical growth measures, they are not representative of long-term expectations
for the electric utility industry. Moreover, to the extent historical trends for
electric utilities are meaningful, they are also captured in projected growth rates,
such as those published by Value Line, IBES, and Zacks because securities
analysts also routinely examine and assess the impact and continued relevance (if
any) of historical trends.
DID MR. BAUDINO ALSO RECOGNIZE THE PITFALLS ASSOCIATED
WITH HISTORICAL GROWTH RATES
Yes. Mr. Baudino noted (p. 13) that “the relevant time frame is prospective rather
than retrospective,” and that (p. 18) historical growth rates “may not accurately
represent investors’ expectations.” Mr. Baudino concluded that analysts’ forecasts
“provide better proxies for the expected growth components in the DCF model
than historical growth rates.”

~
WEA Rebuttal Exhibit No. 1
Page 21 of 55
IS THE DOWNWARD BIAS INHERENT IN HISTOFUCAL GROWTH
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MEASURES FOR ELECTRIC UTILITIES EVIDENT IN MR. SHORT’S
DCF ANALYSES
Yes, it is. For example, consider the historical growth measures displayed on Mr.
Short’s Schedule 3: one-quarter of the individual historical growth rates reported
by Mr. Short for the companies in his proxy group were zero or negative, with
one-half being 2.0 percent or less. Mr. Baudino correctly noted that negative
growth rates make no sense and should be ignored “because they are inconsistent
with the assumption of constant positive growth in the DCF formula.”22
Combining a growth rate of 2.0 percent with Mr. Short’s dividend yield of 4.74
percent implies a DCF cost of equity of approximately 6.7 percent. This implied
cost of equity is less than 100 basis points above his 5.9 percent cost rate on the
Companies’ long-term debt3 Clearly, the risks associated with an investment in
public utility common stocks substantially exceed those of long-term bonds. As
Mr. Baudino noted:
With respect to growth rates near zero, it is reasonable to conclude
that investors expect positive long-term earnings and dividend
growth over time. Including growth rates of 1% or less may
understate expected growth for the comparison
As a result, Mr. Short’s historical growth measures result in a built-in downward
bias to his DCF conclusions, which provide no meaningful information regarding
the expectations and requirements of investors.
22 Baudino Direct at 19.
23 Short Direct at Schedule 6.
24 Baudino Direct at 20.

WEA Rebuttal Exhibit No. 1
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DID MR. SHORT MAKE ANY EFFORT TO TEST THE
REASONABLENESS OF THE INDIVIDUAL GROWTH ESTIMATES HE
RELIED ON TO APPLY THE CONSTANT GROWTH DCF MODEL
Quite the opposite. As Mr. Short candidly recognized:
It is important to note that I did incorporate negative growth rates
of individual companies in calculating the average historical
growth rates as well as individual growth rates that are not
sustainable and probably overstated due to timing. ... The
inclusion of these individual growth rates in calculating the
average did affect the overall average growth estimate ... 25
In other words, Mr. Short simply calculated the average of the individual growth
rates with no consideration for the reasonableness of the underlying data. In fact,
many of the DCF cost of equity estimates implied by Mr. Short’s application of
this method make no economic sense.
For example, consider the 5-year historical EPS growth rates included in
Mr. Short’s evaluation. As shown on his Schedule 3, the individual values for the
firms in his proxy group ranged from -7.5 percent to 14.0 percent. Combining
these growth rates referenced by Mr. Short with his average dividend yield
suggests a DCF cost of equity range of -2.8 percent to 18.7 percent. Clearly,
DCF estimates that imply a cost of equity that are negative or approaching 20
percent violate economic logic and do not represent an informed evaluation of
investors’ expectations. Moreover, reliance on the average of a series of illogical
values does not correct for the inability of individual cost of equity estimates to
24 pass fundamental tests of economic logic.
25 Short Direct at 3 1-32.

WEA Rebuttal Exhibit No. 1
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DO YOU AGREE WITH MR. BAUDINO (P. 35) THAT YOU “ERRED” BY
IGNORING VALUE LINE’S DPS GROWTH PROJECTIONS IN YOUR
APPLICATION OF THE DCF MODEL
No. As I explained in my direct testimony, specific trends in dividend policies for
utilities and evidence from the investment community fully support my
conclusion that earnings growth projections are likely to provide a superior guide
to investors’ expectations. Indeed, while Mr. Baudino suggests (p. 36) that DPS
growth “must be considered,” his own review of this information confirms my
decision to exclude it. As shown on page 1 of Mr. Baudino’s Exhibit RAB-4, the
DPS growth rates for the fms in his proxy group ranged from zero to 13.0
percent. Even after Mr. Baudino excluded certain high and low values, Value
Line’s DPS growth rates for his proxy firms result in an average DCF cost of
equity estimate of 8.33 percent, which falls far below his already downwardbiased
9.5 percent ROE recommendation.
Moreover, I disagree with Mr. Baudino’s assertion (p. 35) that because
Value Line’s projected DPS growth rates “are widely available to investors,” they
can “reasonably be assumed to influence their expectation with respect to
growth.”26 Value Line also publishes a wide variety of other financial
information, including growth rates in revenues and cash flows, but simply
because a particular statistic is included in Value Line’s report does not mean that
investors would rely on it to determine their growth expectations. Indeed, Value
Line makes a number of historical growth rates available to investors, including
historical growth in DPS, which Mr. Baudino nevertheless recognized as
implausible.
26 Mr. Short makes a similar assertion at page 48 of his direct testimony.

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Page 24 of 55
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DO MR. BAUDINO’S PROJECTED DPS GROWTH RATES HAVE
SIMILAR PROBLEMS
Yes. As shown on page 1 of Mr. Baudino’s Exhibit RAB-4, DPS growth rates for
four of the firms in his reference group were equal to 1.0 percent or less, and his
average dividend growth rate of 4.8 percent was over 133 basis points below the
growth rate indicated from his review of analysts’ earnings growth projections.
This mirrors the trend towards a more conservative payout ratio for electric
utilities and the need to conserve financial resources to provide a hedge against
heightened uncertainties. However, while utilities have significantly altered their
dividend policies in response to more accentuated business risks in the industry,
this is not necessarily indicative of investors’ long-term growth expectations. In
fact, as discussed in my direct testimony and earlier in my rebuttal testimony in
response to Mr. Short, growth in earnings is far more likely to provide a
meaningful guideline to investors’ growth rate expectations.
DO YOU AGREE THAT THE SCREENING CRITERIA MR. BAUDINO
APPLIED RESULTED IN A REASONABLE GROWTH ESTIMATE
No. While I certainly agree that it is appropriate to evaluate the reasonableness of
inputs to the DCF model, I take issue with the specific criteria applied by Mr.
Baudino. After a review of the individual growth rates for the companies in his
reference group, Mr. Baudino speculated (p. 20) that no growth rate of 10 percent
or above is reasonable. Mr. Baudino’s “Method 3” results omitted all double-digit
growth rates, as well as those of 1 .O percent or less.
But the growth expectations relevant to the DCF model are those of
investors, not his personal assessment, and he has presented no meaningful
evidence to support his claim that the growth expectations that investors build into
current stock prices could never reach or exceed 10 percent. Moreover, while I

WEA Rebuttal Exhibit No. 1
Page 25 of 55
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agree with Mr. Baudino that growth rates of 1.0 percent or less cannot be
considered reasonable, his criterion retains numerous other low-end growth
estimates that produce illogical cost of equity estimates. For example, in his
“Method 3’’ analysis, Mr. Baudino retained Value Line’s 1.5 percent projected
DPS growth rates for ALLETE and SCANA Corp. But adding the 4.9 percent
dividend yield for these two firms (Exhibit R4B-3) to these growth rates results
in implied cost of equity estimates of 6.4 percent, which is not significantly above
the yield on triple-B public utility bonds and falls far below a meaningful estimate
of investors’ required return for an electric utility.
HAVE OTHER REGULATORS APPROVED DCF ESTIMATES BASED
ON DOUBLE-DIGIT GROWTH RATES
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A. Yes. For example, the FERC approved an ROE zone of reasonableness of 9.21
percent to 15.96 percent for the utility participants in the Midwest Independent
Transmission System Operator, Inc., with the high-end of the DCF range being
based on a growth rate of 11.00 per~ent.2~ Similarly, in 2009 FERC approved an
ROE based on DCF cost of equity estimates for a proxy group of fifteen
companies that incorporated twelve individual growth rates ranging from 8.0
percent to 11.5 percent’ These authorized DCF results contradict Mr. Baudino’s
suggestion that double-digit growth rates are per se illogical.
Q. WHAT, THEN, IS A MORE REASONABLE EVALUATION OF MR.
SHORT’S AND MR. BAUDINO’S DCF RESULTS
A. I revised Mr. Short’s and Mr. Baudino’s DCF methods to reflect an evaluation of
outliers that is consistent with the approach commonly employed by FERC9 As
27 Midwest Independent Transmission System Operator, Inc., 99 FERC 7 63,011 at Appendix A (2002).
28 Pioneer Transmission, LLC, 126 FERC 7 6 1,281 (2009).
29 This approach is explained in detail in my direct testimony. Exhibit WEA No. 1 at 40-43. Mr. Short
also recognized that it is appropriate to consider interest rate forecasts in developing current cost of equity
estimates. Short Direct at 38.

WEA Rebuttal Exhibit No. 1
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shown on page 1 of WEA Rebuttal Exhibit No. 2, eliminating illogical low and
high-end outliers from Mr. Short’s DCF analysis resulted in an average cost of
equity of 10.88 percent. Revising Mr. Baudino’s DCF method (WEA Rebuttal
Exhibit No. 3) resulted in a DCF cost of equity based on projected dividend
growth of 10.55 percent, and an average and midpoint cost of equity of 10.64
percent. I offer the foregoing modifications, not as a substitute for my own DCF
analysis, but as a more reasonable modification of Mr. Short’s and Mr. Baudino’s
DCF analyses.
IV.
DOWNWARD BIAS IN SUSTAINABLE DCF GROWTH RATES
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IS THERE A DOWNWARD BIAS INHERENT IN MR. BAUDINO’S AND
MR. SHORT’S APPLICATION OF THE DCF MODEL BASED ON THE
INTERNAL, “BR” GROWTH RATE
Yes. Mr. Baudino and Mr. Short based their calculations of the internal, “br+sv”
retention growth rate on data fiom Value Line, which reports end-of-period
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results’
If the rate of return, or ‘P’ component of the “br+sv” growth rate, is
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based on end-of-year book values, such as those reported by Value Line, it will
understate actual returns because of growth in common equity over the year. This
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downward bias, which has been recognized by regulators;’
table below.
is illustrated in the
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Consider a hypothetical firm that begins the year with a net book value of
common equity of $100. During the year the firm earns $15 and pays out $5 in
dividends, with the ending net book value being $110. Using the year-end book
value of $110 to calculate the rate of return produces an “r” of 13.6 percent. As
30 While Mr. Baudino calculated sustainable, “br” growth rates for the fms in his proxy group, his DCF
analysis ignored these data.
31 See, e.g., Southern California Edison Company, Opinion No. 445 (Jul. 26,2000), 92 FERC fi 6 1,070.

WEA Rebuttal Exhibit No. 1
Page 27 of 55
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the FERC has recognized, however, this year-end return “must be adjusted by the
2
growth in common equity for the period to derive an average yearly
In
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the example below, this can be accomplished by using the average net book value
over the year ($105) to compute the rate of return, which results in a value for “i’
of 14.3 percent. Use of the average rate of return over the year is consistent with
the theory of this approach to estimating investors’ growth expectations, and as
illustrated below, it can have a significant impact on the calculated retention
growth rate:
Beginning Net Book Value
Earnings
Dividends
Retained Earnings
Ending Net Book Value
“b x r” Growth End-of Year
Earnings $ 15
Book Value $110
“r” 1,3.6%
“b” 66.7%
“b x r” Growth 9.1%
$100
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10
$110
Average
$ 15
$105
14.3%
66.7%
9.5%
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Because Mr. Baudino and Mr. Short did not adjust to account for this reality in
their analyses, the “internal” growth rates that they considered are downwardbiased.
ARE THERE ANY OTHER CONSIDERATIONS THAT LEAD TO A
DOWNWARD BIAS IN MR. BAUDINO’S CALCULATION OF
INTERNAL, “BR” GROWTH
Mr. Baudino ignored the impact of additional issuances of common stock in his
analysis of the sustainable growth rate. As Mr. Short recognized (p. 30-3 l), under
DCF theory, the “sv” factor is a component designed to capture the impact on

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growth of issuing new common stock at a price above, or below, book value. As
noted by Myron J. Gordon in his 1974 study:
When a new issue is sold at a price per share P = E, the equity of
the new shareholders in the firm is equal to the funds they
contribute, and the equity of the existing shareholders is not
changed. However, if P > E, part of the funds raised accrues to the
existing shareholders. Specifically.. . [VI is the fraction of the funds
raised by the sale of stock that increases the book value of the
existing shareholders' common equity. Also, "v" is the fraction of
earnings and dividends generated by the new funds that accrues to
the existing shareholder^.^^
In other words, the "sv" factor recognizes that, when new stock is sold at a price
above (below) book value, existing shareholders experience equity accretion
(dilution). In the case of equity accretion, the increment of proceeds above book
value (P > E in Professor Gordon's example) leads to higher growth because it
increases the book value of the existing shareholders' equity. In short, the "sv"
component is entirely consistent with DCF theory, and the fact that Mr. Baudino
failed to consider the incremental impact on growth results is another downward
bias to his "internal" growth rates.
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A.
V. STOCK PRICE GROWTH IS CONSISTENT WITH INVESTORS'
VIEWS
DID MR. SHORT PRESENT ANY EVIDENCE THAT UNDERMINES
YOUR REFERENCE TO STOCK PRICE GROWTH IN APPLYING THE
DCF MODEL
No. As indicated in my direct testimony,34 I also examined expected growth in
each utility's stock price based on Value Line's projections. Mr. Short did not
33 Gordon, Myron J., "The Cost of Capital to a Public Utility," MSU Public Utilities Studies (1974), at 3 1-
32.
34 Avera Direct at 38-39.

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specifically take issue with my reference to trends in stock price as a guide to
investors’ growth expectations.
In fact, the DCF model assumes that investors expect to receive a portion
of their total return in the form of current dividends and the remainder through
price appreciation over their holding period. Expected growth in stock price is a
central question posed by most investors when evaluating common stocks, and
projected stock prices from investment advisory services such as Value Line are
widely reported and available to investors. In other words, projected growth in
stock price is directly relevant to an analysis of the fkture cash flows that
investors expect to receive when they purchase common stocks and is entirely
consistent with the underlying basis of the DCF model.
Under the assumptions required to derive the constant growth form of the
DCF model, stock price, earnings, dividends, and book value are all expected to
grow at the same rate. Dr. Myron Gordon noted in his seminal article, The Cost of
Capital to a Public Utility (1974), that growth in stock price could serve as
another guide to investors’ growth expectations in the constant growth DCF
model, observing that, “Earnings and price are expected to grow at the same rate.
. . . [Tlhe rate of growth in the price of a stock . . . will respond to all of the factors
mentioned above and, in addition, to the yield investors require on the share.’’35
Similarly, The Cost of Capital -A Practitioner B Guide, published by the Society
of Utility and Regulatory Financial Analysts, observed that under the assumptions
of the DCF model, “The stock price grows proportionally to the growth rate.”36
My reference to expected growth in common stock prices is entirely consistent
with this paradigm.
35 Gordon, Myron J., “The Cost of Equity to a Public Utility,” MSU Public Utilities Studies (1974) at 27 &
90.
36 Parcell, David C., “The Cost of Capital - A Practitioner’s Guide,” Society of Utility and Regulatory
Financial Analysts (1997).

WEA Rebuttal Exhibit No. 1
Page 30 of 55
1 Q. DID MR. BAUDINO PROVIDE A LOGICAL RATIONALE FOR
2 IGNORING EXPECTATIONS FOR STOCK PRICE APPRECIATION
3 A. No. Mr. Baudino wrongly argues that looking to the cash flows that an investor
4 may expect to receive through appreciation in share price is “inconsistent with the
5
principle embodied in the DCF
Mr. Baudino incorrectly asserts that the
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only appropriate cash flows to consider in applying the DCF model “are based on
earnings and dividends, not on a forecast of what a company’s stock price might
be in a few years.”3s
As discussed above, however, the expectation for capital gains associated
with share price appreciation is entirely consistent with the underpinnings of the
DCF model. Of course, one need only listen in on Bloomberg or any one of a
host of business programs to recognize that expectations for share price
appreciation are highly relevant to investors’ expectations regarding returns. In
fact, Mr. Baudino’s argument on page 33-34 that stock prices are not relevant cash
15 flows to consider in the DCF model is contradicted by his own testimony:
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The basic DCF approach is rooted in valuation theory. It is based
on the premise that the value of a financial asset is determined by
its ability to generate future net cash flows. In the case of a
common stock, those future cash flows take the form of dividends
and appreciation in st~ckprice.~~
PLEASE COMMENT ON MR. BAUDINO’S OBSERVATION (P. 33) THAT
STOCK PRICES ARE “INFLUENCED BY THE VICISSITUDES OF THE
23 MARKET.”
24 A.
25
I agree that stock price projections do respond to changes in expectations
regarding the outlook for the economy, capital market conditions, firm-specific
37 Baudino Direct at 33.
38 zd.
39 Id. at 12 (emphasis added).

WEA Rebuttal Exhibit No. I
Page 3 1 of 55
factors, and a host of other considerations relevant to investors. In fact, the notion
that stock prices capture all relevant information available to investors is the
bedrock of modern capital market theory. But the fact that projections for share
price appreciation change in response to economic and market cycles does not
impugn the usefulness of price growth to serve as a gauge of investors’ future
expectations when they purchase common stock.
VI.
ILLOGICAL DATA UNDERLYING STAFF AND WVEUG CAPM
ANALYSES
7 Q. WHAT IS THE FUNDAMENTAL PROBLEM ASSOCIATED WITH MR.
8 SHORT’S APPROACH TO APPLYING THE CAPM
9 A.
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Like the DCF model, the CAPM is an ex-ante, or forward-looking model based
on expectations of the future. As a result, in order to produce a meaningful
estimate of investors’ required rate of return, the CAPM must be applied using
data that reflect the expectations of actual investors in the market. However, Mr.
Short’s application of the CAPM method was based entirely on historical - not
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projected - rates of return.
expectations:
Morningstar recognized the primacy of current
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The cost of capital is always an expectational or forward-looking
concept. While the past performance of an investment and other
historical information can be good guides and are often used to
estimate the required rate of return on capital, the expectations of
future events are the only factors that actually determine cost of
capital’
Because he failed to look directly at the returns investors are currently requiring
in the capital markets, Mr. Short’s CAPM estimate significantly understates
investors’ required rate of return.
40 Morningstar, Ibbotson SBBI, 2008 Valuation Yearbook at 23.

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IS THERE GOOD REASON TO ENTIRELY DISREGARD THE RESULTS
OF HISTORICAL CAPM ANALYSES SUCH AS THOSE PRESENTED BY
MR. SHORT AND MR. BAUDINO
Yes. Applying the CAPM is complicated by the impact of the recent capital
market turmoil and recession on investors’ risk perceptions and required returns.
The CAPM cost of common equity estimate is calibrated from investors’ required
risk premium between Treasury bonds and common stocks. In response to
heightened uncertainties, investors sought a safe haven in U.S. government bonds
and this “flight to safety’’ pushed Treasury yields significantly lower while yield
spreads for corporate debt widened. This distortion not only impacts the absolute
level of the CAPM cost of equity estimate, but it affects estimated risk premiums.
Economic logic would suggest that investors’ required risk premium for common
stocks over Treasury bonds has also increased.
Meanwhile, Mr. Short’s and Mr. Baudino’s backward-looking approach
incorrectly assumes that investors’ assessment of the relative risk differences, and
their required risk premium, between Treasury bonds and common stocks is
constant and equal to some historical average. At no time in recent history has the
fallacy of this assumption been demonstrated more concretely. This incongruity
between investors’ current expectations and requirements and historical risk
premiums is particularly relevant during periods of heightened uncertainty and
rapidly changing capital market conditions, such as those experienced recently.
Mr. Baudino noted (p. 5) that world financial markets “experienced
tumultuous changes and volatility not seen since the Great Depression.” But the
impact of these changes on investors’ sensitivity to risk is not reflected in
backward-looking, historical risk premiums. As a result, there is every indication
that the historical CAPM approach fails to fully reflect the risk perceptions of

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real-world investors in today’s capital markets, which would violate the standards
underlying a fair rate of return by failing to provide an opportunity to earn a
return commensurate with other investments of comparable risk. As the Staff of
the Florida Public Service Commission recently acknowledged:
[Rlecognizing the impact the Federal Government’s unprecedented
intervention in the capital markets has had on the yields on longterm
Treasury bonds, staff believes models that relate the investorrequired
return on equity to the yield on government securities,
such as the CAPM approach, produce less reliable estimates of the
ROE at this time.4l
Similarly, FERC has previously rejected CAPM methodologies based on
historical data because whatever historical relationships existed between debt and
equity securities may no longer hold2
DO MR. SHORT’S HISTORICAL CAPM RESULTS MAKE ECONOMIC
SENSE
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No.
The results of Mr. Short’s application of the CAPM - which ranged from
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5.02 percent to 6.86 percent - are not even remotely plausible. The bottom end of
Mr. Short’s CAPM range implies that investors would be willing to invest in
utility common stocks at an expected return that falls below what they could earn
on senior long-term bonds. Meanwhile, the top end of Mr. Short’s CAPM range
is barely 100 basis points above his recommended cost of long-term debt for the
Companies. As FERC concluded, it is reasonable to exclude any ROE estimate
that “fails to exceed the average bond yield by about 100 basis points or
41 Sta~Recommendationfor Docket No. 080677-El - Petitionfor increase in rates by Florida Power &
Light Company, at p. 280 (Dec. 23,2009).
42 See, e.g., Orange & Rockland Utils., Inc., 40 F.E.R.C. P63,053, at pp. 65,208 -09 (1987), affd, Opinion
No. 314,44 F.E.R.C. P61,253 at 65,208.
43 Southern Calfornia Edison Co., 13 1 FERC 7 6 1 , 020 at P 55 (201 0).

WEA Rebuttal Exhibit No. 1
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DID MR. BAUDINO RECOGNIZE THE INHERENT FLAWS IN
HISTORICAL CAPM RESULTS
Yes. As Mr. Baudino noted:
There is no real support for the proposition that an unchanging,
mechanically applied historical risk premium is representative of
current investor expectations and return requirements4
Mr. Baudino based his ROE recommendation solely on cost of equity estimates
implied by his application of the DCF model and ignored his CAPM results
entirely.45 The Commission should ignore both Mr. Baudino’s and Mr. Short’s
CAPM results.
WERE MR. BAUDINO AND MR. SHORT JUSTIFIED IN RELYING ON
GEOMETRIC MEANS AS A MEASURE OF AVERAGE RATE OF
RETURN WHEN APPLYING THE HISTORICAL CAPM
No. While both the arithmetic and geometric means are legitimate measures of
average return, they provide different information. Each may be used correctly, or
misused, depending upon the inferences being drawn fiom the numbers. The
geometric mean of a series of returns measures the constant rate of return that
would yield the same change in the value of an investment over time. The
arithmetic mean measures what the expected return would have to be each period
to achieve the realized change in value over time.
In estimating the cost of equity, the goal is to replicate what investors
expect going forward, not to measure the average performance of an investment
over an assumed holding period. When referencing realized rates of return in the
past, investors consider the equity risk premiums in each year independently, with
44 Baudino Direct at 26.
45 Id. at 3.

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the arithmetic average of these annual results providing the best estimate of what
investors might expect in future periods. New Regulatory Finance had this to say:
One major issue relating to the use of realized returns when
estimating the market risk premium from historical return data is
whether to use the ordinary average (arithmetic mean) or the
geometric mean return. Because valuation is fonvard-looking,’ the
appropriate average is the one that most accurately approximates
the expected future rate of return. The best estimate of expected
returns over a given future holding period is the arithmetic
average. ... Only arithmetic means are correct for forecasting
purposes and for estimating the cost of capital.46
Similarly, ‘Morningstar concluded that:
For use as the expected equity risk premium in either the CAPM or
the building block approach, the arithmetic mean or the simple
difference of the arithmetic means of stock market returns and
riskless rates is the relevant number. ... The geometric average is
more appropriate for reporting past performance, since it
represents the compound average return.47
I certainly agree that both geometric and arithmetic means are useful,
since my Ph.D. dissertation was on the usefulness of the geometric mean:*
the issue is not whether both measures can be useful; it is which one best fits the
use for a forward-looking CAPM in this case. One does not have to get deeply
into finance theory to see why the arithmetic mean is more consistent with the
facts of this case. The Commission is not setting a constant return that the
Companies are guaranteed to earn over a long period. Rather, the exercise is to
set an expected return based on current market data. In the real world, the
Companies’ yearly return will be volatile, depending on a variety of economic and
industry factors, and investors do not expect to earn the same return each year.
But
46 Morin, Roger A., “New Regulatory Finance,” Public Utilities Reports, Inc. at 156 (2006), (emphasis
added).
47 Morningstar, Ibbotson SBBI 2008 Valuation Yearbook at 77.
48 William E. Avera, The Geometric Mean Strategy as a Theory of Multiperiod Portfolio Choice (1972).

WEA Rebuttal Exhibit No. 1
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The usefulness of the arithmetic mean for making fonvard-looking estimates was
confirmed in Quantitative Investment Analysis (2007), one of the textbooks
included in the study curriculum for the Chartered Financial Analyst designation,
which concluded that the arithmetic mean is the appropriate measure when
calculating an expected equity risk premium in a fonvard-looking context’ Just
as importantly, by relying directly on expectations and estimates of investors’
required rate of return, as incorporated in the CAPM analysis presented in my
direct testimony, there is no need to debate the merits of geometric versus
arithmetic means, because neither is required to apply this forward-looking
approach.
WHAT DOES THIS IMPLY WITH RESPECT TO MR. BAUDINO’S AND
MR. SHORT’S CAPM ANALYSES
For a variable series, such as stock returns, the geometric average will always be
less than the arithmetic average. Accordingly, Mr. Baudino’s and Mr. Short’s
reliance on geometric average rates of return is yet another element of built-in
downward bias.
DO THE ARITHMETIC MEAN RISK PREMIUMS THAT MR. SHORT
AND MR. BAUDINO REPORT FROM IBBOTSON’S STUDIES OF
HISTORICAL DATA COMPORT WITH WHAT ARE RECOMMENDED
BY THIS PUBLICATION
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A.
No.
For purposes of estimating the cost of capital, Morningstar (formerly
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Ibbotson Associates) reports an historical arithmetic mean risk premium for the
S&P 500 over the period 1926 through 2009 of 6.7 per~ent.~’ Meanwhile, Mr.
Short (Schedule 5) and Mr. Baudino (Exhibit RAJ3-6) cited arithmetic mean risk
49 DeFusco, Richard A., Dennis W. McLeavey, Jerald E. Pinto, and David E. Runkle, Quantitative
Investment Analysis, John Wiley & Sons, Inc. (2007) at 128.
50 Morningstar, 2010 Ibbotson SBBI Valuation Yearbook, at Appendix C, Table C-1.

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premiums over long-term government bonds of 6.00 percent and 6.6 percent,
respectively. As a result, their equity risk premiums fall below what Morningstar
calculates, and the CAPM cost of equity estimates developed by Mr. Short and
Mr. Baudino are understated.
DO THE SHORT-TERM TREASURY BILL RATES REFERENCED BY
MR. BAUDINO (PP. 26-27) AND MR. SHORT (P. 37) PROVIDE AN
APPROPRIATE BASIS TO ESTIMATE THE COST OF EQUITY USING
THE CAPM
No. Unlike debt instruments, common equity is a perpetuity and as a result, any
application of the CAPM to estimate the return that investors require must be
predicated on their expectations for the stock’s long-term risks and prospects.
This does not mean that every investor will buy and hold a particular common
stock into perpetuity. Rather, it recognizes that even an investor with a relatively
short holding period will consider the long-term, because of its influence on the
price that he or she ultimately receives from the stock when it is sold. This is also
the basic assumption underpinning the DCF model, which in theory considers the
present value of all fbture dividends expected to be received from a share of
stock.
In evaluating the risks and prospects for an investment in utility common
stock, investors do not restrict their analysis to conditions “expected to prevail
during the period that the pending rate order is expected to be in force.”51 Rather,
even an investor with a relatively short holding period will consider the longterm,
because of its influence on the price that will ultimately be received for the
stock. If Mr. Short were correct, then there would be no need to consider longterm
growth expectations in applying the DCF model. Of course, while any given
51 Short Direct at 37.

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rate order may be in force for a relatively short-term period, investors look well
beyond this horizon in evaluating their required return for a utility’s common
stock.
Shannon P. Pratt, a leading authority in business valuation and cost of
capital, recognized that the cost of equity is a long-term cost of capital and that
the appropriate instrument to use in applying the CAPM is a long-term bond:
The consensus of financial analysts today is to use the 20-year U.S.
Treasury yield to maturity as of the effective data of valuation for
the following reasons:
0 It most closely matches the often-assumed perpetual lifetime
horizon of an equity investment.
0
0
0
The longest-term yields to maturity fluctuate considerably less
that short-term rates and thus are less likely to introduce
unwarranted short-term distortions into the actual cost of
capital.
People generally are willing to recognize and accept the fact
that the maturity risk is impounded into this base, or otherwise
risk-free rate.
It matches the longest-term bond over which the equity risk
premium in measured in the Ibbotson Associates data series.52
Similarly, in applying the CAPM, Ibbotson Associates recognized that the cost of
equity is a long-term cost of capital and the appropriate interest rate to use is a
long-term bond yield:
The horizon of the chosen Treasury security should match the
horizon of whatever is being valued. ... Note that the horizon is a
function of the investment, not the investor. If an investor plans to
hold a stock in a company for only five years, the yield on a fiveyear
Treasury note would not be appropriate since the company
will continue to exist beyond those five years.53
52 Pratt, Shannon P., Cost of Capital, Estimation and Applications at 60 (1998).
53 Ibbotson Associates, 2003 Yearbook (Valuation Edition) at 53.

WEA Rebuttal Exhibit No. 1
Page 39 of 55
Accordingly, proper application of the CAPM should focus on long-term
government bonds and analyses based on 5-year Treasury notes (Mr. Baudino)
and short-term Treasury bills (Mr. Short) should be rejected.
Q. ARE THE SELECTED ARTICLES REFERENCED BY MR. SHORT
REPRESENTATIVE OF INVESTORS’ EXPECTATIONS
A.
No. The conclusions of the publications referenced by Mr. Short do not make
economic sense. For example, the average risk premium for the Journal of
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Porvolio Management article described by Mr. Short (p. 36) is 3.5 percent.
Multiplying a market equity risk premium of 3.5 percent by Mr. Short’s beta of
0.67 for his proxy group, and combining the resulting 2.35 percent risk premium
with his 3.36 percent risk-free rate based on long-term Treasury bonds, results in
an indicated cost of equity of approximately 5.71 percent. This is below the
yields available on long-term bonds and, by any objective measure, such results
fall woefully short of required returns from an investment in common equity.
Moreover, even if historical studies were relevant in this context, there are
other such studies of equity risk premiums published in academic journals that
imply required rates of return considerably in excess of those selected by Mr.
Short. For example, a study of equity risk premiums over the period 1889
through 2000 reported in the Financial Analysts ’Journal directly contradicted Mr.
Short’s view that investors are likely to anticipate sharp declines in the equity risk
premium for US. stocks:
Over the long term, the equity risk premium is likely to be similar
to what it has been in the past and returns to investment in equity
will continue to substantially dominate returns to investments in T-
bills for investors with a long planning horizon.54
54 Mehra, Ranjnish, “The Equity Premium: Why Is It a Puzzle,” Financial Analysts ’ Journal
(Januarymebruary 2003).

WEA Rebuttal Exhibit No. 1
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Similarly, based on a study of ex-ante expected returns for a sample of S&P 500
firms over the 1983-1998 period, a 2003 article in Financial Management found
an expected market risk premium of 7.2 percent.55
MR. SHORT (PP. 48-49) AND MR. BAUDINO (P. 38) POINT OUT THAT
YOU HAVE PREVIOUSLY APPLIED THE CAPM USING HISTORICAL
DATA. IS THERE ANY INCONSISTENCY IN YOUR POSITION
None whatsoever. As I observed in prior testimony before this Commission in
Allegheny Power Case No. 06-0960-E-42T
[I]n order to accurately estimate required returns the CAPM must
be applied using data that reflects the expectations of actual
investors. While reference to historical data represents one way to
apply the CAPM, these realized rates of return reflect, at best, an
indirect estimate of investors’ current requirements. As a result,
fonvard-looking applications of the CAPM that look directly at
investors’ expectations in the capital markets are apt to provide a
more meaningful guide to investors’ required rate of return.56
In other words, my position has been, and continues to be, that the only
appropriate application of the CAPM is one based on the forward-looking
expectations of investors. As I recognized, while historical data are sometimes
referenced as a proxy for investors’ expectations, they are a poor substitute for the
forward-looking approach presented in my direct testimony. As noted earlier, Mr.
Baudino (p. 26) came to the very same conclusion.
55 Harris, R.S., Marston, F. C., Mishra, D. R., and O’Brian, T. J., “EX Ante Cost of Equity Estimates of
S&P 500 Firms: The Choice Between Global and Domestic CAPM,” Financial Management (Autumn
2003) at Table I.
56 Case No. 06-0960-E-42TY Avera Direct at 43.

WEA Rebuttal Exhibit No. 1
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IS THERE ANY MERIT TO MR. BAUDINO’S ARGUMENT (P. 38) THAT
YOUR ANALYSIS OF THE MARKET RATE OF RETURN SHOULD NOT
HAVE BEEN LIMITED SOLELY TO THE DIVIDEND PAYING FIRMS IN
THE S&P 500
No. As Mr. Baudino recognized (p. 13)’ under the constant growth form of the
DCF model, investors’ required rate of return is computed as the sum of the
dividend yield over the coming year plus investors’ long-term growth
expectations. Because the dividend yield is a key component in applying the DCF
model, its usefulness is hampered for firms that do not pay common dividends.
Accordingly, my DCF analysis of the market rate of return properly focused on
the dividend paying fms included in the S&P 500.
Meanwhile, Mr. Baudino (p. 25) predicated his DCF analysis of the
market rate of return on the companies included in the Expanded Edition of Value
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Of these approximately 6,700 companies, only 1,500 pay common
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dividends.
In other words, more than three-quarters of the companies that
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underpin Mr. Baudino’s DCF analysis do not have the data necessary to
implement this approach. Further, many of these firms are extremely small and
lack a meaningful operating history.57 As a result, there is also greater uncertainty
associated with estimating the future growth expectations that are central to the
20
application of the DCF method.
Taken together, these factors impugn the
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reliability of Mr. Baudino’s market risk premium and confirm my decision to
restrict my analysis to the established, dividend paying firms in the S&P 500.
57 Over one-half of the fms included in Mr. Baudino’s CAPM analysis have a market capitalization of
less than $400 million.

~~
WEA Rebuttal Exhibit No. 1
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WHAT OTHER PROBLEMS ARE ASSOCIATED WITH MR. BAUDINO’S
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MARKET RATE OF RETURN BASED ON VALUE LINE DATA
As detailed in my direct testimony and explained earlier here, expected growth in
earnings is far more likely to be representative of investors’ forward-looking
expectations. Mr. Baudino apparently agrees, noting, “earnings growth is the
primary factor considered by investor^."^^ Mr. Baudino confirmed that investors’
focus on earnings was especially pronounced for the non-regulated firms covered
by Value Line:
[I]t is not surprising that earnings and cash flow are considered
more important than book value and dividends, particularly for
non-utility companies that may not pay out much in the way of
dividends.
But despite this admission and the facts that 1) over three-quarters of the
companies underlying his CAPM analysis do not even pay common dividends,
and 2) Mr. Baudino ignored book value in applying the DCF method to his group
of electric utilities, he nevertheless included dividend and book value growth rates
in the DCF analysis he employed to estimate the expected market rate of return.
This had the effect of understating his resulting CAPM cost of equity
estimates. As shown on page 1 of WEA Rebuttal Exhibit No. 4, correcting Mr.
Baudino’s CAPM analysis to remove dividend and book value growth resulted in
an estimated cost of equity for his group of utilities of 10.70 percent. Meanwhile,
as shown on page 2 of WEA Rebuttal Exhibit No. 4, restricting Mr. Baudino’s
analysis to the approximately 1,700 larger firms in Value Line’s Standard Edition
would result in an implied cost of equity of 10.98 percent.
58 Baudino Direct at 35.
59 Baudino Direct at 35-36.

WEA Rebuttal Exhibit No. 1
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VII.
EXPECTED EARNINGS METHOD IS AN ACCEPTED
APPROACH
Q*
DO YOU AGREE WITH THE DECISION OF MR. SHORT AND MR.
BAUDINO NOT TO CONSIDER THE RESULTS OF THE EXPECTED
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EARNINGS APPROACH
No. Mr. Short and Mr. Baudino cited the standards underlying a fair ROE
stemming from the Supreme Court decisions in Bluefield and Hope. The
expected earnings approach applied in my direct testimony is predicated on the
comparable earnings test, which developed as a direct result of these cases.
DOES THIS METHOD REPRESENT AVALID ROE BENCHMARK
Absolutely. From my understanding as a regulatory economist, not as a legal
interpretation, the Bluefield and Hope cases required that a utility be allowed an
opportunity to earn the same return as companies of comparable risk. That is, the
Supreme Court recognized that a utility must compete with other companies -
including non-utilities - for capital.
WHAT ECONOMIC PREMISE UNDERLIES THE EXPECTED
EARNINGS APPROACH
The simple but powerful concept underlying the expected earnings approach is
that investors compare each investment alternative with the next best opportunity.
As Mr. Baudino recognized (p. lo), economists refer to the returns that an
investor must forgo by not being invested in the next best alternative as
“opportunity costs”.
WHAT ARE THE IMPLICATIONS OF SETTING AN ALLOWED ROE
BELOW THE RETURNS AVAILABLE FROM OTHER INVESTMENTS
OF COMPARABLE RISK
If the utility is unable to offer a return similar to that available from other
opportunities of comparable risk, investors will become unwilling to supply the

WEA Rebuttal Exhibit No. 1
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capital on reasonable terms. For existing investors, denying the utility an
opportunity to earn what is available from other similar risk alternatives prevents
them fiom earning their opportunity cost of capital. In this situation the regulator
is effectively taking the value of investors’ capital without adequate
compensation.
HOW IS THE COMPARISON OF OPPORTUNITY COSTS TYPICALLY
IMPLEMENTED
The traditional comparable earnings test identifies a group of companies that are
believed to be comparable in risk to the utility. The actual earnings of those
companies on the book value of their investment are then compared to the
allowed return of the utility. While the traditional comparable earnings test is
implemented using historical data taken from the accounting records, it is also
common to use projections of returns on book investment, such as those published
by recognized investment advisory publications (e.g., Value Line). Because these
returns on book value equity are analogous to the allowed return on a utility’s rate
base, this measure of opportunity costs results in a direct, “apples to apples”
comparison.
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Q. IS THE TRADITIONAL COMPARABLE EARNINGS METHOD AN
ACCEPTED APPROACH TO DETERMINING A FAIR RATE OF
RETURN ON EQUITY
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A.
Yes.
In fact, a textbook prepared for the Society of Utility and Regulatory
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Analysts labels the comparable earnings approach the “granddaddy of cost of
equity methods” and notes that it is based on the opportunity cost concept and is
consistent with both sound regulatory economics and the legal standards set forth
in the landmark Bluefield and Hope cases.6o I have used the comparable earnings
6o Parcell, David C., The Cost of Capital-a Practitioner’s Guide ( 1 997).

WEA Rebuttal Exhibit No. 1
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approach in my consulting, teaching, and testimony for 35 years, and it has been
widely referenced in regulatory decision-making.61 Mr. Short’s own sources
confrm that the comparable earnings method is widely referenced by regulatory
agencies throughout the U.S. and Canada. As shown on Appendix B to Mr.
Short’s testimony, the comparable earnings approach was identified as a favored
method in determining the allowed ROE for 24 of the agencies surveyed in
NARUC’s compilation of regulatory policy.
DO YOU AGREE WITH MR. BAUDINO (P. 39) AND MR. SHORT (P. 50)
THAT IT IS NECESSARY TO EXAMINE MARKET-TO-BOOK RATIOS
IN APPLYING THE EXPECTED EARNINGS APPROACH
No. Traditional applications of the expected earnings approach do not involve a
market-to-book adjustment. I have never made a market-to-book adjustment, nor
is such an adjustment recommended in recognized texts such as New Regulatory
Finance. 62
IS THERE A CLEAR LINK BETWEEN MARKET-TO-BOOK RATIOS
FOR ELECTRIC UTILITIES AND ALLOWED RATES OF RETURN
No. Underlying Mr. Baudino’s and Mr. Short’s criticism is the supposition that
regulators should set a required rate of return to produce a market-to-book value
of approximately 1 .O.
noted that:
This is fallacious. For example, New Regulatory Finance
The stock price is set by the market, not by regulators. The MA3
ratio is the end result of regulation, and not its starting point. The
view that regulation should set an allowed rate of return so as to
produce a M/l3 of 1 .O, presumes that investors are irrational. They
61 For example, a NARUC survey reported that 19 regulatory jurisdictions cited the comparable earnings
test as a primary method favored in determining the allowed rate of return. “Utility Regulatory Policy in
the U.S. and Canada, 1995-1996,” National Association of Regulatory Utility Commissioners (December
1996). In my experience, while a few Commissions have explicitly rejected comparable earnings, most
regard it as a useful tool.
62 Morin, Roger A,, “New Regulatory Finance,” Public Utilities Reports, Inc. (2006).

~ ~
1’
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WEA Rebuttal Exhibit No. 1
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commit capital to a utility with a M/B in excess of 1.0, knowing
full well that they will be inflicted a capital loss by regulators.
This is certainly not a realistic or accurate view of reg~lation.6~
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With market-to-book ratios for most electric utilities above 1 .O, Mr. Baudino and
Mr. Short are suggesting that, unless book value grows rapidly, regulators should
establish equity returns that will cause share prices to fall. Given the regulatory
imperative of preserving a utility’s ability to attract capital, this would be a truly
perverse result.
Q. IS THERE ANYTHING UNUSUAL ABOUT A STOCK PRICE
EXCEEDING BOOK VALUE
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A.
No. In fact the majority of stocks currently sell substantially above book value.
For example, Value Line reports that, even after the unprecedented decline
recently experienced in stock market prices, roughly 1,400 of the approximately
1,700 stocks followed in its Standard Edition (including utilities and other
industries) sell for prices in excess of book value.64 Moreover, regulators
previously recognized the fallacy of relying on market-to-book ratios in
evaluating cost of equity estimates. For example, the Presiding Judge in Orange
& Rockland concluded, and the FERC affirmed that:
The presumption that a market-to-book ratio greater than 1.0 will
destroy the efficacy of the DCF formula disregards the realities of
the market place principally because the market-to-book ratio is
rarely equal to 1 .o
The Initial Decision found that there was no support in FERC precedent for the
use of market-to-book ratios to adjust market derived cost of equity estimates
based on the DCF model and concluded that such arguments were to be treated as
“academic rhetoric” unworthy of consideration.
63 Id. at 376.
64 www.valueline.com (retrieved Nov. 19,2010).
65 Orange & Rockland Utilities, Znc., Initial Decision, 40 FERC 7 63,053, 1987 WL 118,352 (F.E.R.C.).

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WHAT ROE IS IMPLIED BY THE RESULTS OF THE EXPECTED
EARNINGS APPROACH
The results of the expected earnings approach for the groups of electric utilities
referenced by Mr. Short and Mr. Baudino are presented in WEA Rebuttal Exhibit
No. 5. As shown there, this method results in an implied cost of equity for Mr.
Short’s proxy group of 10.7 percent (page l), while the resulting ROE for Mr.
Baudino’s proxy group is 11 .O percent (page 2).
It is a very simple, conceptual principle that when evaluating two
investments of comparable risk, investors will choose the alternative with the
higher expected return. If the Companies are only allowed the opportunity to earn
a return on the book value of their equity investment in the range of 9.0 percent to
9.5 percent, as recommended by Mr. Short and Mr. Baudino, while the
comparable-risk utilities in these proxy groups are expected to earn averages of
10.7 percent and 11.0 percent, respectively, the implications are clear - the
Companies’ investors will be denied the ability to earn their opportunity cost.
Moreover, regulators do not set the returns that investors earn in the
capital markets - they can only establish the allowed return on the value of a
utility’s investment, as reflected on its accounting records. As a result, the
expected earnings approach provides a direct guide to ensure that the allowed
ROE is similar to what other utilities of comparable risk will earn on invested
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capital.
This opportunity cost test does not require theoretical models to
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indirectly infer investors’ perceptions from stock prices or other market data. As
long as the proxy companies are similar in risk, their expected earned returns on
invested capital provide a direct benchmark for investors’ opportunity costs that is
independent of fluctuating stock prices, market-to-book ratios, debates over DCF

WEA Rebuttal Exhibit No. 1
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growth rates, or the limitations inherent in any theoretical model of investor
behavior.
WHAT WOULD BE THE EFFECT OF AUTHORIZING A BOOK RETURN
FOR THE COMPANIES THAT IS SO FAR BELOW THE AVERAGE
EARNINGS OF THE PROXY UTILITIES
Plain and simple, the Companies will find it difficult to compete for investors’
capital and they would not be earning up to the Bluefield standard of comparable
earnings:
A public utility is entitled to such rates as will permit it to earn on
the value of the property which it employs for the convenience of
the public equal to that generally being made at the same time and
in the same general part of the country on investments in other
business undertakings which are attended by corresponding risks
and uncertainties.66
MR. BAUDINO IMPLIES (P. 39) THAT A METHODOLOGY MUST BE
“MARKET-BASED” TO BE USEFUL IN EVALUATING INVESTORS’
OPPORTUNITY COSTS. DO YOU AGREE
No. While I agree that market-based models are certainly important tools in
estimating investors’ required rate of return, this in no way invalidates the
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usefulness of the expected earnings approach.
In fact, this is one of its
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advantages. Perhaps the most ardent proponent of earned returns as a benchmark
for fair ROE is David C. Parcell, who frequently appears as a witness for
regulatory agencies and other intervenors. Mr. Parcell literally “wrote the book”
for the Society of Utility and Regulatory Financial Analysts, referring to the
comparable earnings approach as the “granddaddy” of cost of equity rneth0ds.6~
He also points out that the amount of subjective judgment required to implement
66 Bluefield Water Work h Improvement Co. v. Pub. Sen. Comm’n, 262 U.S. 679 (1923).
67 Parcell, David C., The Cost of Capital - A Practitioner’s Guide (1 997) at 7- 1.

WEA Rebuttal Exhibit No. 1
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1 this method is “minimal”, particularly when compared to the DCF and CAPM
2 methods, and notes that the comparable earnings test method is “easily
3 understood” and firmly anchored in the regulatory tradition of the BZueJieZd and
4 Hope cases.68 As discussed above, it is consistent with economic logic that, when
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choosing between two opportunities of comparable risk, investors will select the
investment with the higher expected return.
WHAT OTHER EVIDENCE INDICATES THAT THE
RECOMMENDATIONS OF MR. SHORT AND MR. BAUDINO ARE
INSUFFICIENT TO MEET REGULATORY STANDARDS
Reference to allowed rates of return for other utilities provides an alternative
guideline that can be used to assess the extent to which the 9.0 percent and 9.5
percent ROE recommendations of Mr. Short and Mr. Baudino are comparable and
sufficient. As shown on page 1 of WEA Rebuttal Exhibit No. 6, data from AIS
Monthly ReDort indicates that the average authorized ROEs for the firms in Mr.
15
Short’s proxy group is 10.78 percent.
Page 2 of that exhibit presents the
16
17
18
19
20
21
authorized ROEs for the firms in Mr. Baudino’s proxy group, which average
10.57 percent. These authorized returns exceed the ROE recommendations of Mr.
Short and Mr. Baudino by a wide margin. It is unreasonable to suppose that
investors would be attracted by their ROE recommendations for the Companies,
which fall significantly below the allowed returns for other utilities they consider
to be comparable.
68 ~ d. at 7-3.

VIII. NO BASIS TO IGNORE FLOTATION COSTS
WEA Rebuttal Exhibit No. 1
Page 50 of 55
1 Q*
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3
4 A.
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21
22
23
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25
PLEASE RESPOND TO THE ARGUMENT THAT THERE IS NO BASIS
TO CONSIDER THE IMPACT OF FLOTATION COSTS IN
ESTABLISHING THE COMPANIES’ ROE.
The need for a flotation cost adjustment to compensate for past equity issues has
been recognized in the financial literature. In a Public Utilities Fortnightly
article, for example, Brigham, Abenvald, and Gapenski demonstrated that, even if
no further stock issues are contemplated, a flotation cost adjustment in all future
years is required to keep shareholders whole, and that the flotation cost
adjustment must consider total equity, including retained earnings.69 Similarly,
New Regulatory Finance contains the following discussion:
Another controversy is whether the flotation cost allowance should
still be applied when the utility is not contemplating an imminent
common stock issue. Some argue that flotation costs are real and
should be recognized in calculating the fair rate of return on equity,
but only at the time when the expenses are incurred. In other
words, the flotation cost allowance should not continue
indefinitely, but should be made in the year in which the sale of
securities occurs, with no need for continuing compensation in
future years. This argument implies that the company has already
been compensated for these costs andor the initial contributed
capital was obtained freely, devoid of any flotation costs, which is
an unlikely assumption, and certainly not applicable to most
utilities. ... The flotation cost adjustment cannot be strictly
fonvard-looking unless all ast flotation costs associated with past
issues have been recovered. 70
69 Brigham, E.F., Abenvald, D.A., and Gapenski, L.C., “Common Equity Flotation Costs and Rate
Making,” Public Utilities Fortnightly, May, 2, 1985.
70 Morin, Roger A., “New Regulatory Finance,” Public Utilities Reports, Inc. at 335 (2006).

WEA Rebuttal Exhibit No. 1
Page 51 of 55
1 Q*
2
3
CAN YOU PROVIDE A SIMPLE NUMERICAL EXAMPLE
ILLUSTRATING WHY A FLOTATION COST ADJUSTMENT IS
NECESSARY TO ACCOUNT FOR PAST FLOTATION COSTS
4 A.
Yes.
The following example demonstrates that investors will not have the
5
6
7
8
9
10
11
12
13
14
15
16
opportunity to earn their required rate of return (i. e., dividend yield plus expected
growth) unless an allowance for past flotation costs is included in the allowed rate
of return on equity. Assume a utility sells $10 worth of common stock at the
beginning of year 1. If the utility incurs flotation costs of $0.48 (5 percent of the
net proceeds), then only $9.52 is available to invest in rate base. Assume that
common shareholders’ required rate of return is 11.5 percent, the expected
dividend in year 1 is $0.50 (i.e., a dividend yield of 5 percent), and that growth is
expected to be 6.5 percent annually. As developed below, if the allowed rate of
return on common equity is only equal to the utility’s 11.5 percent “bare bones”
cost of equity, common stockholders will not earn their required rate of return on
their $10 investment, since growth will really only be 6.25 percent, instead of 6.5
percent:
Common Retained Total Market MIB Allowed Earnings Dividends Payout
Year Stock Earnings Equity Price Ratio ROE Per Share Per Share Ratio
1 $ 9.52 $ - $ 9.52 $10.00 1.050 11.50% $ 1.09 $ 0.50 45.7%
2 $ 9.52 $ 0.59 $10.11 $10.62 1.050 11.50% $ 1.16 $ 0.53 45.7%
3 $ 9.52 $ 0.63 $10.75 $11.29 1.050 11.50% $ 1.24 $ 0.56 45.7%
Growth 6.25% 6.25% 6.25% 6.25%
17
18
19
20
21
The reason that investors never really earn 11.5 percent on their investment in the
above example is that the $0.48 in flotation costs initially incurred to raise the
common stock is not treated like debt issuance costs (Le., amortized into interest
expense and therefore increasing the embedded cost of debt), nor is it included as
an asset in rate base.

WEA Rebuttal Exhibit No. 1
Page 52 of 55
1 Q*
2
3
4 A.
5
6
7
8
9
10
11
CAN YOU ILLUSTRATE HOW THE FLOTATION COST ADJUSTMENT
ALLOWS INVESTORS TO BE FULLY COMPENSATED FOR THE
IMPACT OF PAST ISSUANCE COSTS
Yes. As discussed in my direct testimony, one method for calculating the flotation
cost adjustment is to multiply the dividend yield by a flotation cost percentage.
Thus, with a 5 percent dividend yield and a 5 percent flotation cost percentage,
the flotation cost adjustment in the above example would be approximately 25
basis points. As shown below, by allowing a rate of return on common equity of
11.75 percent (an 11.5 percent cost of equity plus a 25 basis point flotation cost
adjustment), investors earn their 11.5 percent required rate of return, since actual
growth is now equal to 6.5 percent:
Common Retained Total Market MIB Allowed Earnings Dividends Payout
Year Stock Earnings Equity Price Ratio ROE Per Share Per Share Ratio
1 $ 9.52 $ - $ 9.52 $10.00 1.050 11.75% $ 1.12 $ 0.50 44.7%
2 $ 9.52 $ 0.62 $10.14 $10.65 1.050 11.75% $ 1.19 $ 0.53 44.7%
3 $ 9.52 $ 0.66 $10.80 $11.34 1.050 11.75% $ 1.27 $ 0.57 44.7%
Growth 6.50% 6.50% 6.50% 6.50%
12
13
14
15
16 Q.
17
18 A.
19
20
21
22
The only way for investors to be fully compensated for issuance costs is to
include an ongoing adjustment to account for past flotation costs when setting the
return on common equity. This is the case regardless of whether or not the utility
is expected to issue additional shares of common stock in the future.
PLEASE RESPOND TO MR. BAUDINO’S AND MR. SHORT’S SPECIFIC
CRITICISMS OF YOUR FLOTATION COST ADJUSTMENT.
The need to consider past flotation costs has been recognized in the financial
literature, including sources that Mr. Baudino and Mr. Short relied on in their
testimony. First, with respect to Mr. Baudino’s contention (p. 39) that flotation
costs “are already accounted for in current stock prices,” New Regulatory Finance
has this to say:

1
2
3
4
5
6
7
8
9
10
11
WEA Rebuttal Exhibit No. 1
Page 53 of 55
A third controversy centers around the argument that the omission
of flotation cost is justified on the grounds that, in an efficient
market, the stock price already reflects any accretion or dilution
resulting from new issuances of securities and that a flotation cost
adjustment results in a double counting effect. The simple fact of
the matter is that whatever stock price is set by the market, the
company issuing stock will always net an amount less than the
stock price due to the presence of intermediation and flotation
costs. As a result, the company must earn slightly more on its
reduced rate base in order to produce a return equal to that required
by shareholder^.^^
.,
12 Similarly, Ibbotson Associates concluded that:
13
14
15
16
17
18 Q.
19
20
21
22 A.
23
24
25
26
27
28
29
30
Although the cost of capital estimation techniques set forth later in
this book are applicable to rate setting, certain adjustments may be
necessary. One such adjustment is for flotation costs (amounts that
must be paid to underwriters by the issuer to attract and retain
capital).72
PLEASE RESPOND TO MR. SHORT’S CONTENTION (P. 45) THAT A
FLOTATION COST ALLOWANCE IS UNNECESSARY BECAUSE THE
MARKET-TO-BOOK RATIO FOR ELECTRIC UTILITIES IS GREATER
THAN 1.0
Whether the market-to-book ratio is greater than, or less than, 1.0 says nothing
about the need to recognize the impact of legitimate costs of issuing common
stock when establishing a fair rate of return. Investors determine the price they
are willing to pay for a share of common stock based on their assessment of
expected cash flows and relative risks.
While I don’t dispute Mr. Short’s
observation that sales of stock at a price that exceeds book value will cause the
book value per share of existing shareholders to grow, this doesn’t change the fact
that investors must be granted an opportunity to earn their required rate of return
on all invested capital, including that portion paid out as issuance expenses. As I
71 Morh, Roger A,, “New Regulatory Finance,” Public Utilities Reports, Inc. at 334-335 (2006). Mr. Short
cited Dr. Morh’s previous edition of this book on page 23 of his testimony.
72 Ibbotson Associates, Stocks, Bonds, Bills, and Inflation, Valuation Edition, 2006 Yearbook, at 35.

WEA Rebuttal Exhibit No. 1
Page 54 of 55
1
2
3 Q*
4
5
6 A.
7
8
9
10
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12
13
14
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17
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21
demonstrated in the example above, this can only occur if an upward adjustment
to the ROE is made to account for flotation costs.
-.
IX. END RESULT TEST
DOES THE COVERAGE RATIO CALCULATION PRESENTED BY MR.
SHORT (P. 41) PROVE THAT HIS RECOMMENDED ROE IS
REASONABLE
No. The coverage ratio developed by Mr. Short is only one isolated financial
statistic. In and of itself, this one ratio falls far short of what is necessary to, in
Mr. Short’s words, “indicate an adequate and fair recommendation.” In fact, the
investment community has largely shifted away from coverage ratios to other
measures of cash flow adequacy in their evaluation of a utility’s risks, and S&P
and Moody’s no longer publish a target ratio for EBIT interest coverage. More
importantly, however, a single financial statistic has little bearing on the overall
risk profile of the utility, which is based on investors’ assessment of a broad range
of qualitative and quantitative factors. As S&P made clear, “our assessment of
financial risk is not as simplistic as looking at a few ratios.’’73
Moreover, Mr. Short’s coverage calculation rests on the assumption that
the Companies will actually earn their allowed rate of return - an assumption that
history has proven to be 0ptimistic.7~ Investors are concerned with what they can
expect in the future, not what they might expect in theory if a historical test year
were to repeat. To be fair to investors and to benefit customers, a regulated utility
must have an opportunity to actually earn a return that will maintain financial
73 Standard & Poor’s Corporation, “Criteria Methodology: Business RiskPinancial Risk Matrix
Expanded,” RatingsDirect (May 27,2009).
74 For example, S&P reported to investors that APCo’s return on common equity averaged 5.98 percent
over the last three years. Standard & Poor’s Corporation, www.globalcreditportal.com/ratingsdirect
(retrieved Nov. 20, 2010).

WEA Rebuttal Exhibit No. 1
Page 55 of 55
1
2
3
4
integrity, facilitate capital attraction, and compensate for risk. In other words, it is
the end result likely to prevail when rates are in effect that determines whether or
not the Hope and Bluefield standards are met.75 S&P observed that its risk
analysis focuses on the utility’s ability to consistently a reasonable return:
Notably, the analysis does not revolve around “authorized” returns,
but rather on actual earned returns. We note the many examples of
utilities with healthy authorized returns that, we believe, have no
meaninghl expectation of actually earning that return because of
rate case lag, expense disallowances, et^.^^
10
11
12
13
14
15
16
17
18
19 Q.
20 A.
Similarly, Moody’s concluded, “we evaluate the framework and mechanisms that
allow a utility to recover its costs and investments and earn allowed returns. We
are less concerned with the official allowed return on equity, instead focusing on
the earned returns and cash
Mr. Short’s single coverage statistic is
unlikely to convince real-world investors that an ROE of 9.0 percent is “adequate
and fair.” In fact, when evaluated against expected and allowed ROES for his own
proxy companies, which averaged 10.7 and 10.8 percent, re~pectively,~~ there is
every indication that Mr. Short’s recommended ROE falls far below a reasonable
range.
DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
Yes.
75 See Hope at p. 605, as cited in Verizon Communications, Inc. et al. v. Federal Communications
Commission, et al., 535 U.S.-(2002) slip op. atpp. 11-12
76 Standard & Poor’s Corporation, “Assessing U.S. Utility Regulatory Environments,” RatingsDirect (Nov.
7,2008).
77 Moody’s Investors Service, “Electric Utilities Face Challenges Beyond Near-Tern,’’ Industry Outlook
#an. 2010).
WEA Rebuttal Exhibit Nos. 5 and 6 at p. 1.

SHORT DCF ANALYSIS
REVISED GROWTH RATE SCREEN
WEA Rebuttal Exhibit No. 2
Page 1 of 2
Projected Growth Rates
Cost of Equity Estimates
Historic Growth Rates
COMPANY
ALE
LNT
AEP
CNL
EDE
ETR
HE
IDA
PCG
PNW
PGN
UNS
XEL
AVERAGES
AVERAGE OF RESULTS
Value Line Five Year
Zacks
Projected Projected Projected
- EPS
11.33% 8.83%
11.46% 14.36% 9.46%
8.10%
13.07%
13.86%
10.95% 10.45% I 8.95%
16.83%
8.85%
10.11%
11.16%
9.16%
18.70%
10.00%
I 9.00% I 9.10%
11.69%
1 10.40% I 1 11.04% I
Sustainable
Growth
"br '' + "sv "
-
7.85%
10.02%
9.81%
8.82%
9.03%
10.02%
9.33%
8.15%
10.68%
8.72%
8.58%
9.75%
9.09%
9.33%
Value Line Five Year
Historical
- EPS - DPS Bvps
18.83% NMF 8.33%
13.46% 1 4.96% 1 7.96%
14.45% 16.45% 1 7.45%
-2.17% 1 5.33% 6.33%
NMF
1.20%
9.16%
-~-""-,-
7.66% 7.66%
16.20% 10.20%
12.50% [ 5.50% 1 8.5oyo
14.22%
!
13.94%
I 12.77% I
10.14%
Source: Short Direct at Schedule 3 and Schedule 4; WEA Exhibit No. 1 at pp. 40-4. Averages exclude highlighted values.

SHORT DCF ANALYSIS
REVISED GROWTH-RATE SCREEN
WEA Rebuttal Exhibit No. 2
Page 2 of 2
P m
Growth Rates
~ ~~
Historic Growth Rates
COMPANY
ALE
LNT
AEP
CNL
EDE
ETR
HE
IDA
PCG
PNW
PGN
UNS
XEL
AVERAGES
Dividend
Yield
4.83%
4.46%
5.10%
3.57%
6.36%
4.45%
5.33%
3.35%
4.11%
5.16%
5.66%
4.70%
4.50%
Value Line Five Year
Projected
8.50% 7.00%
1.00% 1 1.50%
6.50% 6.00%
1.00%
2.50% 5.00%
6.00% 6.00%
*-. _.-
1.50% 72.00%
1.00% 1 2.50%
12.00% 5.00%
3.50% 4.50%
I
7.00% 5.06%
6.03%
I YahooFin.
Projected
Zack's
Projected
- EPS
4.00%
5.00%
4.00%
7.00%
0.00%
3.00%
9.50%
4.70%
6.80%
6.80%
4.00%
5.00%
5.70%
5.68%
;,stainable
Growth
"br" + "sun
3.02%
5.56%
4.71%
5.25%
2.66%
5.56%
4.00%
4.80%
6.57%
3.56%
2.92%
5.06%
4.58%
4.60%
Value Line Five Year
Historical
- EPS - DPS BVPS
14.00% NMF 3.50%
9.00% 0.50% 1 3.50%
2.00% -2.50% 1 5.00%
3.00% I 0.00% 1 10.00%
0.50% 1 0.00% I 1.00%
-___--~
NMF na 14.00%
4.00% IXiG-
-3.50% 1 11.50% 5.50%
8.00% [ 1.00% 1 4.00%
9.90% 9.17% 5.60%
8.22%
Source: Short Direct at Schedule 3 and Schedule 4. Averages exclude highlighted values.

BAUDINO DCF ANALYSIS
REVISED GROWTH RATE SCREEN
WEA Rebuttal Exhibit No. 3
Page 1 of 2
Value Line Value Line Zack's First Call Average of
Dividend Gr. Earnines Gr. EarninP Gr. Earnine Gr. All Gr. Rates
Method 1:
Dividend Yield
Growth Rate
Expected Div. Yield
DCF Return on Equity
Midpoint of Results
4.42% 4.78% 4.84% 4.80% 4.71%
6.00% 5.25% 5.74% 6.18% 5.79%
4.55% 4.90% 4.98% 4.95% 4.85%
10.55% 10.15% 10.72% 11.13% 10.64%
10.64'/0
Source: Exhibit IWB-4, WEA Exhibit No. 1 at pp. 40-43.

BAUDINO DCF ANALYSIS
REVISED GROWTH RATE SCREEN
WEA Rebuttal Exhibit No. 3
Page 2 of 2
Comuanv
1 ALLETE
2 Alliant Energy
3 American Elec Pwr
4 Edison International
5 Entergy Corp.
6 OGE Energy Corp.
7 PG&E Corp.
8 Portland General Elec.
9 Progress Energy
10 P S Enterprise Group
11 SCANA Corp.
12 UIL Holdings
13 Westar Energy
14 Wisconsin Energy
Dividend
Yield
4.92%
4.62%
4.89%
3.75%
4.34%
3.73%
4.16%
5.28%
6.02%
4.25%
4.93%
6.43%
5.30%
2.97%
Growth Rates
Cost of Equity Estimates
Value Line Value Line Zacks First Call Value Line Value Line Zacks First Call
Dividend Gr. Earnings Gr. Earning Gr. Dividend Gr. Earnings Gr. Earning Gr. Earning Gr.
I 1.50% I 1.00% I 4.00% 6.50% I 6.46% I 5.94% I 9.02% 11.58%
5.50% 7.00% 5.00% 9.90%
2.50% I 3.00% I 4.33% 4.30%
L
3.50% I -1.00%
6.50% 4.50%
I
3.00% 2.22% I
3.00% 5.14%
4.00% I 2.00% I -0.33% I 2.00%
3.50% 7.50% 8.00% 9.28%
13.00% 9.50% 8.67% 9.53%
10.25% 11.78% 9.74% 14.75%
I 7.45% I 7.96% I 9.33% 9.30%
7.32% 2.73% 6.81% 6.01% I
10.98% 8.94% 7.41% 9.59%
7.05%
8.34%
9.63% 10.14% 9.76%
6.47% 8.52% 9.31% 9.95%
6.43% 9.53% 9.53% 10.43%
8.89% 13.00% 13.51 yo 14.83%
16.16% 12.61% 11.77% 12.64%
6.29% I 3.91% I 6.29% I
Source: Baudino Direct at Exhibit RAB-3 and Exhibit RAB-4.

BAUDINO CAPM ANALYSIS
REVISED MARKET GROWTH RATE
WEA Rebuttal Exhibit No. 4
Page 1 of 2
Market Required Return Estimate
Expected Dividend Yield
Expected Earnings Growth
Required Return
Risk-free Rate of Return, 20-Year Treasury Bond
Average of Last Six Months
Risk Premium
Comparison Group Beta
Comparison Group Risk Premium
Risk-free Rate of Return, 20-Year Treasury Bond
Average of Last Six Months
Value Line
0.65%
12.96%
13.61%
3.90%
9.71%
0.70
6.80%
3.90%
CAPM Return on Equity
10.70%
Source: www.valueline.com (retrieved Nov. 18,2010); Exhibit RAB-5.

BAUDINO CAPM ANALYSIS
VALUE LINE STANDARD EDITION
WEA Rebuttal Exhibit No. 4
Page 2 of 2
Market Required Return Estimate
Expected Dividend Yield
Expected Earnings Growth
Required Return
Risk-free Rate of Return, 20-Year Treasury Bond
Average of Last Six Months
Risk Premium
Comparison Group Beta
Comparison Group Risk Premium
Risk-free Rate of Return, 20-Year Treasury Bond
Average of Last Six Months
Value Line
1.34%
12.68%
14.02%
3.90%
10.12%
0.70
7.08%
3.90%
CAPM Return on Equity
10.98°/o
Source: www.vaIueIine.com (retrieved Nov. 18,2010); Exhibit RAB-5.

EXPECTED EARNINGS APPROACH
SHORT PROXY GROUP
WEA Rebuttal No. 5
Page 1 of 2
Company
(a)
Expected Return
on Common Eauitv
(a)
Adjustment
Factor
(b)
Adjusted Return
on Common Eauity
1
2
3
4
5
6
7
8
9
10
11
12
13
ALLETE
Alliant Energy
American Electric Power
Cleco Corp.
Empire District Electric
Entergy Corp.
Hawaiian Electric
IDACORP, Inc.
PG&E Corp.
Pinnacle West Capital
Progress Energy
UniSource Energy
Xcel Energy
8.5%
11.5%
10.0%
10.5%
10.5%
13.5%
10.5%
8.5%
12.0%
9.0%
10.0%
12.5%
10.0%
1.0217
1.0261
1.0279
1.0425
1.0200
1.0182
1.0212
1.0306
1.0401
1.0348
1.0197
1.0286
1.0307
8.7%
11.8%
10.3%
10.9%
10.7%
13.7%
10.7%
8.8%
12.5%
9.3%
10.2%
12.9%
10.3%
Average
10.7%
The Value Line Investment Survey (Aug. 27, Sep. 24, & Nov. 5,2010).
(4 x (b).

EXPECTED EARNINGS APPROACH
WEA Rebuttal No. 5
Page 2 of 2
BAUDINO PROXY GROUP
Comuanv
(a)
Expected Return
on Common Eauitv
(a)
Adjustment
Factor
(b>
Adjusted Return
on Common Equity
1 ALLETE
2 AlliantEnergy
3 American Electric Power
4 Edison International
5 Entergy Corp.
6 OGE Energy Corp.
7 PG&ECorp.
8 Portland General Elec.
9 Progress Energy
10 P S Enterprise Group
11 SCANA Corp.
12 UIL Holdings
13 Westar Energy
14 Wisconsin Energy
8.5%
11.5%
10.0%
8.5%
13.5%
11.5%
12.0%
8.5%
10.0%
13.0%
10.0%
10.5%
8.5%
13.0%
1.0217
1.0261
1.0279
1.0268
1.0182
1.0489
1.0401
1.0327
1.0197
1.0394
1.0419
1.0186
1.0281
1.0307
8.7%
11.8%
10.3%
8.7%
13.7%
12.1%
12.5%
8.8%
10.2%
13.5%
10.4%
10.7%
8.7%
13.4%
Average
11.0%
(a) The Value Line Investment Survey (Aug. 27, Sep. 24, & Nov. 5,2010).
(b) (a)x(b)*

ALLOWED ROE
SHORT PROXY GROUP
WEA Rebuttal Exhibit No. 6
Page 1 of 2
Company
ALLETE
Alliant Energy
American Electric Power
Cleco Corp.
Empire District Electric
Entergy Corp.
Hawaiian Electric
IDACORP, Inc.
PG&E Corp.
10 Pinnacle West Capital
11 Progress Energy
12 UniSource Energy
13 XcelEnergy
Average
Allowed Return
on Common Ea_uity
1 0.74%
10.41%
10.66%
10.70%
1 0.80 Yo
10.80%
10.82%
10.18%
11.35%
11.00%
12.00%
10.00%
10.72%
10.78%
Source: AUS Monthly Report (Aug. 2010).

ALLOWED ROE
WEA Rebuttal Exhibit No. 6
Page 2 of 2
Company
ALLETE
Alliant Energy
American Electric Power
Edison International
Entergy Corp.
OGE Energy Corp.
PG&E Corp.
Portland General Elec.
Progress Energy
10 P S Enterprise Group
11 SCANA Corp.
12 UIL Holdings.
13 Westar Energy
14 Wisconsin Energy
Average
Allowed Return
on Common Eauity
10.74%
10.41%
10.66%
10.66%
10.80%
10.13%
11 .%Yo
10.80%
12.00%
10.30%
10.67%
8.75%
10.20%
10.55%
10.57%
Source: AUS Monthly Report (Aug. 2010).

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
MARC D. REITTER

MDR Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
MARC D. REITTER
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q. PLEASE STATE YOUR NAME.
2 A. My name is Marc D. Reitter.
3 Q. ARE YOU THE SAME MARC D. REITTER WHO FILED DIRECT
4 TESTIMONY IN THIS CASE
5 A. Yes.
6 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
7 A. The purpose of my rebuttal testimony is to respond to Staff witness Short’s
8 recommendations related to capital structure and the associated financing costs of
9 both short-term and long-term debt. I will also respond to Mr. Short’s proposal
10 that Virginia’s accounts receivable factoring be included as short-term debt.
11 Q. DO YOU AGREE WITH THE DEBT AND EQUITY BALANCES MR.
12 SHORT USES FOR RATEMAKING PURPOSES
13 A. No. While I do not disagree with his timeline, I do disagree with his approach for
14 arriving at the balances of short-term debt, long-term debt, and common equity.
15 Mr. Short uses an average of the quarter-end capital balances for the four quarters
16 from October 1,2009 through September 30,2010. The more appropriate way to
17 develop the capital structure for Appalachian Power Company (APCo) and
18 Wheeling Power Company (WPCo) (collectively the Companies) is to use a 13-
19 month average of the month-end balances for short-term debt, long-term debt, and
20 common equity, which is similar to the method the Commission uses to determine

Page 2 of 4
rate base. Furthermore, using a 13-month average of the month end balances for
the Companies’ sources of capital illustrates a more precise view of the
Companies’ financing activities compared to using a four quarter average of the
quarter end balances as Mr. Short proposed.
5 Q*
6
7
8 A.
9
10
11
12
13 Q.
14
15
16
17 A.
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19
20
21
22
WHAT IS THE RESULTING CAPITAL STRUCTURE AND COST OF
CAPITAL USING A 13-MONTH AVERAGE ENDING SEPTEMBER 30,
2010
Using a 13-month average for the capital balances for the Companies results in a
weighted average cost of capital of 8.150 percent. MDR Rebuttal Exhibit 2
shows the development of the WACC rate and the corresponding cost of both
short-term debt and long-term debt as well as the cost of equity, as provided by
witness Avera.
BEFORE YOU DISCUSS MR. SHORT’S POSITION AND APCO’S
ACCOUNTS RECEIVABLE FACTORING, CAN YOU BRIEFLY
SUMMARIZE AEP’S ACCOUNTS RECEIVABLE FACTORING
PROGRAM
Yes. AEP Credit, Inc. (AEP Credit), a wholly owned subsidiary of American
Electric Power Company, Inc. (AEP), was formed for the single purpose of
purchasing accounts receivables at a discount and financing these purchases at an
approved debt-equity ratio. Each company selling its receivables to AEP Credit
has executed a “Purchase Agreement” and an “Agency Agreement” which
outlines how the basic transactions take place.

Page 3 of 4
1
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5 Q*
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7 A.
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11 Q.
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15 A.
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Except for APCo - West Virginia, WPCo and the AEP operating companies in
Texas, electric receivables are sold to and owned by bank sponsored conduits.
AEP Credit’s credit rating of AA allows for low-cost financing that results in
substantial savings.
DOES APCO SELL ITS WEST VIRGINIA RECEIVABLES TO AEP
CREDIT
No. WPCo and APCO’S West Virginia jurisdiction do not participate in the
accounts receivable factoring program with AEP Credit. The Companies sought
regulatory permission to participate, but on March 5,2003 in Case No. 00-0754-
E-PC, the Commission declined to grant that permission.
DO YOU AGREE WITH MR. SHORT’S ARGUMENT THAT AN
ADJUSTMENT SHOULD BE MADE TO APCO’S SHORT-TERM DEBT
BALANCES TO REFLECT THE SELLING OF APCO’S VIRGINIA
JURISDITION ELECTRIC RECEIVABLES TO AEP CREDIT
No. The inclusion of the APCo Virginia jurisdiction electric receivables in
calculating capital structure and cost of capital for setting West Virginia rates is
inappropriate. Virginia receivables factoring is a true sale of the accounts
receivables and is not an accounts receivable financing facility. Therefore, it
would be inappropriate to include the Virginia receivables in the Companies’
short-term debt balances. APCo is selling its Virginia accounts receivable; there
is no borrowing obligation between the seller and buyer. Further, should APCo
have to unwind its account receivable factoring program within its Virginia

Page 4 of 4
jurisdiction, a capital contribution to equity from AEP may be required to manage
2
3 Q*
4
5 A.
6
7
8 Q*
9 A.
the short-term working capital needs and capitalization ratios of APCo.
IS THE VIRGINIA ACCOUNTS RECEIVABLE FACTORING A
FINANCING FACILITY
No. In accounts receivable financing facilities the lender does not purchase the
accounts receivable balance but lends against the balance, securing the loan with
the asset. This is not the case for APCo and AEP.
DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
Yes.

MDR Rebuttal Exhibit 2
APPALACHIAN POWER COMPANY & WHEELING POWER COMPANY
WEST VIRGINIA RETAIL JURISDICTION
CAPITAL STRUCTURE AND COST OF CAPITAL
13 MONTH AVERAGE - 0913012009 TO 0913012010
Amount
Outstanding
Percent
($000) %
Cost Rate
%
Weighted
Return
Component
%
Long-term Debt
$ 3,535,345 53.041%
5.968
3.166
Short-term Debt
$ 297,339 4.461 %
0.250
0.01 1
Total Debt
$ 3,832,684
3.177
Preferred Stock (a)
$ 18,510 (a) 0.278%
4.35
0.012
Common Stock
$ 2,814,151 42.221%
11.75
4.961
Total
$ 6,665,345 100%
Overall Cost of Capital
8.150
(a) Incl. prem. On Preferred Stock of
$ 761

~ REBUTTAL
APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
TESTIMONY ~~
OF
JAY JOYCE

JJ Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
JAY JOYCE
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q*
2 A.
3 Q*
4
5 A.
6 Q*
7 A.
8
9
10
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13
14
PLEASE STATE YOUR NAME.
My name is Jay Joyce.
ARE YOU THE SAME JAY JOYCE WHO PRESENTED DIRECT
TESTIMONY IN THIS CASE
Yes, I am.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
I am responding to several adjustments to the Companies’ cash working capital
(“CWC”) allowance and rate base that have been proposed by Staff witness
Thomas D. Sprinkle and Consumer Advocate Division (“CAD”) witness Deanna
Lynne White. Mr. Sprinkle and Ms. White adopted virtually identical positions
regarding CWC, and both address the following three CWC issues:
1. “Cash”-basis CWC study
2. Property tax lead days
3. Average bank balances
“CASH”-BASIS CWC STUDY
15 Q ARE THERE FLAWS IN THE STAFF’S AND THE CAD’S PROPOSALS
16 TO CONVERT THE COMPANIES’ CWC REQUIREMENTS TO A
17 “CASH BASIS”

Page 2 of 7
1 A.
Yes.
The most significant flaw is that Mr. Sprinkle’s and Ms. White’s
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calculations consider only a portion of the Companies’ costs of service and
resulting revenues. By removing certain expenses for depreciation and equity
return and an equal amount of revenues from their analyses, they omit a
significant portion of the Companies’ CWC requirement from their calculations.
HOW WERE THE LEAD DAYS FOR DEPRECIATION AND EQUITY
RETURN CALCULATED IN YOUR CWC STUDIES
The lead days for depreciation expense are zero because the net plant component
of rate base is reduced simultaneously with the recording of depreciation expense.
Thus, there is no delay between when the expense is recorded and when the
expense is used to reduce rate base. This reduction in the plant component of rate
base is recorded as if that these amounts were collected simultaneously from
customers. However, like all other components of revenues, APCo does not
collect those revenues on average until 35.38 days after recording the depreciation
expense and WPCo does not collect them until 37.67 days after recording the
depreciation expense.
With respect to the equity return element of cost of service, preferred
dividends are paid at the end of the quarter. This results in an average payment
lead of 45.75 days (366/4 = 91.50/2 = 45.75). There are no lead days associated
with common equity as those funds become the property of the common
shareholders (through retained earnings) at the time service is provided and
represent capital reinvested in the business until those shareholders elect to
withdraw it. Net income available to common shareholders is effectively “paid”

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7 A.
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to such shareholders each day and “reinvested” each day unless retained by them
as common dividends are paid.
DO YOU AGREE WITH MR. SPRINKLE AND MS. WHITE THAT IT IS
AN ERROR TO INCLUDE REVENUES RELATED TO “NON-CASH”
ITEMS SUCH AS DEPRECIATION AND EQUITY RETURN
COMPONENTS IN THE CWC STUDY
Not at all. In fact, it is an error to exclude these components of revenue. The
Companies have working capital requirements for the total amount of revenue
billed to customers until payment for that total amount billed is received by the
Companies. Failure to include the depreciation and equity return components of
revenue in measuring working capital incorrectly assumes that the Companies
collect this portion of revenues on the same day service is provided even though
the revenue is not recovered on average for 35.38 days for APCo or 37.67 days
14
for WPCo-a
fact not contested as to the remainder of the Companies’ revenue.
PROPERTY TAX LEAD DAYS
15 Q.
16
17
18
19
MR. SPRINKLE AND MS. WHITE RECOMMEND INCREASING THE
PAYMENT LEAD FOR PROPERTY TAXES FROM AN ACTUAL
RANGE OF -27.66 TO 30.61 LEAD DAYS TO A HYPOTHETICAL
RANGE OF 426 TO 870.46 LEAD DAYS. DO YOU AGREE WITH THEIR
PROPOSED ADJUSTMENTS

Page 4 of 7
1
2
3
A. No. They fail to match the service period of the expense to the service period
over which electricity is delivered to customers and the resulting revenue is
recovered.
4
5
6
7
8
9
Q.
A.
WHY IS IT IMPORTANT TO MATCH EXPENSES AND REVENUES
The service period measures the time span over which services are provided. The
critical feature of this measure is that it establishes the 'lcommon point" fiom
which the timing difference between cost incurrence and revenue recovery is
measured. Costs are not incurred until they are accrued, and the costs are not
reflected in the Companies' books or revenue requirements until that time.
10 Q.
11
12 A.
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HOW IS THIS MATCHING PRINCIPLE APPLIED TO WEST VIRGINIA
PROPERTY TAXES
The Staff and the CAD erroneously assume that the assessment date is the
appropriate date to begin measuring expense lead days for property taxes even
though none of the corresponding taxes are accrued or reflected on the
Companies' books until much later. The Staff/CAD proposal fails to match the
period over which the tax expense is incurred and paid to the period that the same
tax expense is recovered from the Companies' customers. As explained in the
rebuttal testimony of Company witness Mark A. Pyle, the Companies are
accruing and expensing the property tax during the same period that payments are
made; therefore, a portion of the tax payment is made in advance and a portion is
made in arrears. I have properly reflected this timing difference in my CWC
studies for the Companies.

Page 5 of 7
AVERAGE BANK BALANCES
WHY IS IT NECESSARY TO ACCOUNT FOR AVERAGE BANK
2
3 A.
4
BALANCES IN CWC
Because the Companies’ CWC studies have reflected check float as a reduction of
cash working capital, the actual bank cash balances must be included in CWC in
5
order to recognize the financing costs associated with this asset.
Since the
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9 Q*
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11 A.
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16 Q.
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18 A.
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20
Companies cannot control when checks will clear through the banking system,
and given the various minimum balance requirements imposed by banks, the
Companies must maintain certain levels of available cash in their bank accounts.
ARE THESE INVESTMENTS IN BANK BALANCES PROVIDED BY
RATEPAYERS OR INVESTORS
These investments are provided by investors. This is evident because all of the
funds supplied by ratepayers (either through revenues or contributions-in-aid-ofconstruction)
are already spoken for or otherwise deducted in development of the
Companies’ cost of service. There is simply no other possible source for the bank
balances other than the investors.
WHY DID STAFF AND CAD EXCLUDE THESE AMOUNTS FROM THE
CWC REQUIREMENTS
Neither Staff nor CAD provides any ratemaking rationale for excluding average
bank balances. The exclusion of these average bank balances by the Staff and the
CAD appears to be based on the unsubstantiated belief that these amounts
21
somehow constitute ratepayer-supplied hds.
This reflects a significant
22
misunderstanding of the purpose of CWC studies to measure cash working

Page 6 of 7
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10 Q.
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12 A.
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18 A.
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capital. A CWC study should identify all of a utility’s requirements for capital
that have not otherwise been included as separate rate base components (e.g.,
plant and inventories) and to identify any cost-free or non-investor-supplied
sources of capital that have not been included as separate rate base components
(e.g., accumulated depreciation and accumulated deferred income taxes) or
included in the capital structure. The net result of this process will produce an
amount of net funds required of investors to be included in rate base or net funds
available from non-investors to support plant and other rate base components to
be deducted from rate base.
DO MOST COMMISSIONS INCLUDE AVERAGE BANK BALANCES IN
WORKING CAPITAL
Yes. Based on my experience, every Commission has approved the request for
average bank balances, including the request by APCo in Virginia. Specifically,
when I have presented the issue to regulatory commissions in Texas, Oklahoma,
and Arkansas, those commissions have approved bank balances.
ARE YOU AWARE OF ANY REGULATORY BODIES THAT ACTUALLY
REOUIRE THE INCLUSION OF AVERAGE BANK BALANCES IN CWC
Yes. Although most commission do not have such detailed rules, the Public Utility
Commission of Texas (“PUCT”) has substantive rules that govern the filing of rate
cases and detail the components required in a utility’s cost of service. PUCT
Substantive Rule 25.231 (c)(2)(B)(iii)(IV)(e) states that “For electric utilities the
balance of cash and working funds included in the working cash allowance

Page 7 of 7
1
2
calculation shall consist of the average daily bank balances of all non-interest
bearing demand deposits and working cash funds.”
3 Q. WHAT IS THE QUANTITATIVE EFFECT OF REJECTING THE
4 STAFFKAD ADJUSTMENTS WHICH YOU HAVE SHOWN TO BE
5 ERRONEOUS
6 A.
7
8
9
10
11 Q.
12
13 A.
14
15
16
17
18 Q.
19 A.
The erroneous conversion to “cash basis” reduces CWC by approximately $20.4
million; the erroneous treatment of property taxes further reduces CWC by $42.7
million’; and the exclusion of average bank balances reduces CWC by an
additional $400,000. In total, this equates to an understatement of CWC by $63.5
million.
SHOULD THE COMMISSION ADOPT YOUR cwc
RECOMMENDATION
Yes. The CWC studies that I have conducted are reasonable and accurately
reflect the actual operations of the Companies. Moreover, my CWC studies
reflect relevant methodologies applied in a logical and consistent manner.
Accordingly, the results of my CWC studies should be adopted by the
Commission to calculate the Companies’ CWC requirements.
DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
Yes.
$42.7 million is Staffs recommended reduction; the CAD’S CWC reduction is lower, but the CAD claims
1
that their reduction is understated (White Direct at 14) thereby implying that they would endorse a higher
reduction similar to Staffs.

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
ANDREW R. CARLIN

ARC Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF ANDREW R. CARLIN
ON BEHALF OF
APPALACHIAN POWER COMPANY
AND
WHEELING POWER COMPANY
1 Q*
2 A.
3 Q*
4
5 A.
6 Q*
7 A.
8
9
10
11
12
13
14
15
16 Q.
17 A.
PLEASE STATE YOUR NAME
My name is Andrew R. Carlin.
ARE YOU THE SAME ANDREW R. CARLIN WHO PRESENTED DIRECT
TESTIMONY IN THIS CASE
Yes.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
I will address various adjustments recommended in the direct testimony of Staff
witness Thomas D. Sprinkle and Consumer Advocate Division (“CAD’) witness
Ralph C. Smith with respect to various compensation and benefit expenses included
in the Companies’ filing. I will show that the Companies’ expenses are reasonable
and prudent components of a market competitive total compensation program. For
the larger expenses, I will show that disallowance of these expenses would likely lead
to less efficient provision of electric utility service and increased costs for customers
over time. I will also point out several public policy concerns raised by the proposed
adjustments.
ARE YOU SPONSORING ANY EXHIBITS
Yes. I am sponsoring the following exhibits:
18
19
0
0
ARC Rebuttal Exhibit No. 2 Hourly Market Analysis
ARC Rebuttal Exhibit No. 3 Annual Incentive Payout History and

ARC Rebuttal Exhibit No. 1
Page 2 of 19
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Q*
A.
Q*
A.
Q*
A.
ARC Rebuttal Exhibit No. 4 Clark Consulting 2009 Executive Benefits
Survey
WHAT ADJUSTMENTS HAVE BEEN PROPOSED WITH RESPECT TO
THE COMPANIES’ REQUESTED LEVEL OF ANNUAL INCENTIVE
COMPENSATION EXPENSE
Staff witness Sprinkle proposes removal of all incentive expense, while CAD witness
Smith proposes removal of 50% of annual incentive expense.
DO YOU AGREE WITH EITHER OF THESE RECOMMENDATIONS
No.
IS THE TOTAL COMPENSATION OPPORTUNITY PROVIDED TO
EMPLOYEES BY AEP AND THE COMPANIES MARKET COMPETITIVE
Yes. In my direct testimony I showed that the total compensation for AEP’s executive
officers was market competitive (p. 5). Both 2009 and 2010 market compensation
analyses showed that AEP’s total Compensation for approximately 50 management
positions was also within the market competitive range but currently approximately
one (1) percent below market median in aggregate. Furthermore, total compensation
for hourly positions is also market competitive but approximately 4.5% below market
median on average relative to both east region specific comparable companies and all
comparable companies (see ARC Rebuttal Exhibit No. 2, Hourly Market Analysis).
In fact, no concerns have been raised by any party in this case with respect to the
market competitiveness of the Companies’ base pay or total compensation levels.
This is presumably because these levels are generally market competitive, if not
slightly below the midpoint of the market competitive range overall.

ARC Rebuttal Exhibit No. 1
Page 3 of 19
1 Q*
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I O
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WHAT ARE THE PUBLIC POLICY CONCERNS WITH RESPECT TO
REDUCING OR ELIMINATING THE COMPANIES’ INCENTIVE
COMPENSATION FROM ITS COST OF SERVICE FOR RATEMAKING
PURPOSES
If the Commission agrees that the Companies’ total compensation is market
competitive, which has not been challenged in this case, it would presumably allow
hll cost recovery’ of this level of compensation without question if it were provided
entirely in the form of base pay. However, if the Staff or the CAD recommendation is
adopted, then cost recovery for a portion of this same level of compensation would be
denied solely because it is provided in the form of incentive compensation. The
obvious signal which this would send to the Companies is that they should convert
some or all of their incentive compensation to base pay in order to provide market
competitive wages and achieve cost recovery in future rate cases. The Companies
could not eliminate incentive compensation without such an offsetting increase in
base pay because they could not hope to compete successfully for appropriately
skilled and experienced personnel without a market competitive total compensation
package. However, converting incentive compensation to base pay would likely lead
to the gradual erosion of the efficiencies and productivity gains mentioned by Staff
witness Sprinkle (see Direct Testimony of Thomas D. Sprinkle, page 11, lines 22-23).
The loss of these efficiency and productivity gains, as well as the many other benefits
which incentive compensation provides to ratepayers, employees, and shareholders,
would likely lead to increased expenses in other categories and eventually to higher
rates. Because of this long-term adverse impact on rates, I submit that the proposed

ARC Rebuttal Exhibit No.1
Page 4 of 19
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reduction or elimination of rate recovery for incentive compensation should raise a
public policy concern for the Commission.
WHAT JUSTIFICATION WAS CITED BY STAFF FOR DISALLOWING 2
ALL ANNUAL INCENTIVE EXPENSE
Staff witness Sprinkle states that “stockholders of the Companies should absorb the
cost of employee incentive bonuses, not ratepayers.” He goes on to argue that such
“costs will not continue in the future unless management continues to maximize
profits through efficiencies and increased productivity. We would expect future cost
reductions or net income improvements to accompany future bonuses.” This attitude
ignores the critical importance of annual incentive compensation as a component of
the Companies’ market competitive total compensation program as well as the cost
and service quality benefits that incentive compensation provides to customers. As
shown in my direct testimony with respect to executive officers, on page 4 on lines
16-19 for approximately 50 management positions and ARC Rebuttal Exhibit No. 2
with respect to hourly positions, the overall value of the Companies’ total
compensation program would fall well below market competitive levels if annual
incentive compensation was eliminated without an offsetting increase in base pay.
Without a market-competitive total compensation program, the Companies would not
be competitive in attracting and retaining the qualified and appropriately experienced
employees they need to efficiently and effectively operate the Companies’ business.
If the Companies’ compensation programs were allowed to fall significantly below a
market competitive level, then I would expect increased and possibly substantial
23
turnover in many types of positions.
This would result in less efficiency and

ARC Rebuttal Exhibit No. 1
Page 5 of 19
1
2
3
4
productivity at all levels, increased hiring expense, declining performance and an
overall increase in expense that would ultimately result in increased customer rates.
Furthermore, it is an unrealistic assessment of AEP’s and the Companies’ past
and future performance to suggest that management has or can provide incentive
compensation to employees by sharing the value derived from an endless series of
efficiency and productivity gains. Most, if not all, such gains have already occurred,
have already reduced the Companies’ cost of service, and either have been or will be
used entirely to benefit customers through lower rates. Having recently substantially
reduced employment levels in the Companies’ workforce without reducing the
I O
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amount of work that needs to be completed, the potential for future significant
efficiency and productivity gains is remote. Furthermore, the Staff has already
proposed reducing the Companies’ payroll expense in cost of service for ratemaking
purposes, which would give ratepayers the entire expense benefit of the workforce
reduction. Therefore, if all efficiency and productivity gains from prior years and the
gains from the workforce initiative are used for the benefit of ratepayers, no funds
from these gains will be available to shareholders or to fund annual incentive
Compensation. However, because annual incentive compensation is a component of
the Companies’ market competitive total compensation program, providing it only
when efficiency and productivity gains are realized would leave the Companies’
compensation substantially below market and lead to the many ill effects discussed
above.
AEP and the Human Resources Committee of AEP’s Board of Directors (“HR
Committee”) strive to provide an attainable incentive compensation opportunity

ARC Rebuttal Exhibit No. 1
Page 6 of 19
during periods of both strong and weak financial and economic conditions, subject, of
course, to affordability and the need to balance the Companies’ commitments to other
stakeholders. The HR Committee, in consultation with senior AEP management,
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Q.
does this by setting funding targets that are aggressive while still being realistic and
achievable. Because of this, Mr. Sprinkle’s expectation that future cost reductions or
net income improvements will accompany future bonuses is not necessarily true,
particularly during extended periods of economic downturn, such as we are currently
experiencing.
Mr. Sprinkle further asserts that eliminating all annual incentive Compensation
expense from rates “is the proper rate making treatment, since these bonuses clearly
reflect rewards to employees for stockholders benefits achieved, not ratepayer
benefits.” This statement inaccurately characterizes the Companies’ annual incentive
compensation payments as “bonuses” above and beyond market competitive
compensation, whereas they are in fact a critical component of a market competitive
total compensation package. This statement also ignores the many direct and indirect
benefits that the Companies’ incentive compensation provides to ratepayers, not the
least of which is strongly encouraging all employees to maintain financial discipline
and conserve resources, which directly benefits customers by keeping rates low.
STAFF WITNESS SPRINKLE AND CAD WITNESS SMITH ARGUE THAT
ALL OR FIFTY PERCENT OF ANNUAL INCENTIVE COMPENSATION
SHOULD BE EXCLUDED FROM THE COMPANIES’ COST OF SERVICE
DUE TO THE COUNTRY’S PROTRACTED ECONOMIC TURMOIL AND

Y
ARC Rebuttal Exhibit No. 1
Page 7 of 19
1
WEAKENED ECONOMY.
IS THIS AN APPROPRIATE REASON FOR
2
3 A.
4
5
ADOPTING THE PROPOSED EXCLUSION
Although AEP and the Companies understand the extremely difficult situation the
economy has created for many ratepayers and the fbrther burden posed by rate
increases, this is not an appropriate reason for excluding some or all annual incentive
6
compensation from the Companies’ cost of service.
Although the number of
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ratepayers in economic distress has increased, a significant portion of ratepayers are in
economic distress at any given time, so this is neither a new nor temporary issue.
Moreover, even if some or all annual incentive compensation could be excluded from
the Companies’ cost of service without leading to other countervailing cost increases,
the effect would be to lower rates for all ratepayers, not just those in economic
distress.
Mr. Sprinkle and Mr. Smith inaccurately characterize the Companies’ annual
incentive expense as “additional bonuses” or a “discretionary cost.’’ To the contrary,
the amount requested is the target amount which the Companies need to pay on
average to provide market competitive total compensation to the employees who
serve their customers’ needs. Thus, it is not a bonus on top of an already market
competitive total compensation program. While the amount of annual incentive
compensation paid in any one year is controlled and determined by senior
management and the HR Committee, its expected value, in a statistical sense, could
not be reduced or eliminated without either offsetting this compensation with
additional base pay or suffering the ill effects of below market compensation.

ARC Rebuttal Exhibit No. 1
Page 8 of 19
WHAT ASSURANCE IS THERE THAT THE COMPANIES WILL PAY THE
2
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REQUESTED LEVEL OF ANNUAL INCENTIVE COMPENSATION OR
OTHER COMPENSATION OF EQUAL VALUE IN FUTURE YEARS
The target level of annual incentive expense is substantially less than the long-term
average of the amounts paid to employees over the last six years and less than the
amount paid for all but one of these six years. See ARC Rebuttal Exhibit No. 3.
Also, as previously shown, the overall value of Companies’ total compensation
program would fall well below market competitive levels if annual incentive
compensation was eliminated without an offsetting increase in base pay.
WHAT OTHER JUSTIFICATION WAS CITED FOR REDUCING THE
AMOUNT OF INCENTIVE EXPENSE INCLUDED IN RATES
CAD witness Smith makes the following statement:
In general, incentive compensation programs can provide benefit to
both shareholders and ratepayers. The removal of 50 percent of the
incentive Compensation expense, in essence, provides an equal
sharing of such costs, and therefore provides an appropriate
balance between the benefits attained by both shareholders and
ratepayers.
However, the Companies’ purpose is to provide benefits to both shareholders and
ratepayers, so annual incentive expense is no different from other expenses in this
regard. The Companies’ annual incentive compensation program and overall expense
has been shown to be a reasonable, appropriate and prudent cost of doing business.
Given this, the primary direct impact of “sharing” the expense of annual incentive
compensation between shareholders and ratepayers would be to reduce the

ARC Rebuttal Exhibit No. 1
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Companies’ rates at the expense of disallowing necessary and reasonable costs of
doing business.
WOULD THE COMPANIES BE FINANCIALLY HARMED IF THE
COMMISSION ADOPTED THE STAFF’S OR THE CAD’S PROPOSAL ON
INCENTIVE COMPENSATION
6 A.
Yes.
The annual incentive program is necessary because the Companies’ total
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compensation program would not be market competitive if it was eliminated without
providing an approximately equal and compensating increase in base pay. Therefore,
the Companies would be financially harmed by the elimination of the Companies’
incentive compensation expense from its cost of service for ratemaking purposes
because it would not be recovering the reasonable and prudent cost of providing
market competitive compensation.
HOW HAS THIS COMMISSION ADDRESSED INCENTIVE
COMPENSATION IN A RECENT RATE CASE DECISION
As CAD witness Smith points out, in a 2009 Hope Gas case the Commission allowed
incentive Compensation for direct employees of the utility but disallowed the affiliate
service company charges for 50% of the incentive compensation for senior
management. The Hope Gas order, therefore, disallowed only 50% of the service
company affiliate incentive expense that is attributable to incentive compensation for
senior management. By contrast, CAD witness Smith and Staff witness Sprinkle have
recommended disallowing either 50% or 100% of both AEP Service Corporation’s
and the Companies’ incentive expense for senior management and all other

ARC Rebuttal Exhibit No. 1
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employees. This would exclude substantially more expenses than were excluded by
the Hope Gas order.
WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE CAD
AND STAFF PROPOSALS ON ANNUAL INCENTIVE COMPENSATION
I recommend that the Commission reject those proposals and approve the Companies’
request to include the target value of annual incentive compensation in their cost of
service for ratemaking purposes. The Commission should also include the savings
plan expenses associated with this incentive compensation in the Companies’ cost of
service for ratemaking purposes.
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However, should the Commission decide to follow the methodology it used in
its order cited above (November 30, 2009 order in the Dominion Hope Gas Case),
then 50% of target annual incentive compensation for senior management would be
excluded. Based on the information for the officer group provided in the response to
data request CAD E-127, the West Virginia jurisdictional portion of the target 2010
annual incentive expense for APCo, WPCo and applicable AEPSC officers was
$546,952. Therefore, the applicable reduction would be 50% of this amount or
$273,476, rather than the $1,955,000 reduction recommended by Mr. Smith.
DO YOU AGREE WITH THE STAFF AND CAD RECOMMENDATIONS TO
EXCLUDE SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN (SEW)
EXPENSE FROM COST OF SERVICE
I do not agree that SEW Expense should be removed for ratemaking purposes. Staff
witness Sprinkle (page 12, lines 15-19) inaccurately characterizes SEW as “bonus
related expenses” rather than as a retirement benefit (page 12, lines 15-19). Both

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CAD and Staff witnesses suggest that SERP is an unnecessary cost for the provision
of electric utility service and, therefore, a discretionary cost that should be borne by
shareholders. This view is incorrect on many levels. First, SERP is an important and
highly prevalent component of a market competitive total rewards package. ARC
Rebuttal Exhibit No. 4 -Clark Consulting 2009 Executive Benefits Survey (p. 6 and
25) shows that SEWS are highly prevalent (67% of companies included in this survey
provide SEWS). The HR Committee of AEP’s Board of Directors, which represents
shareholders, is just as concerned with corporate expenses as ratepayers and shares
many of the public’s concerns with unreasonable and excessive executive
compensation and benefits. The HR Committee members would not provide SEW
benefits that they believe to be unreasonable or excessive.
Because SERP benefits are an important component of the Companies’ market
competitive total rewards program, the Companies could not eliminate them without
providing other compensation or benefits of equal value to employees or eroding the
overall competitiveness of the Companies’ total rewards program. Therefore, SEW
benefits, or some other form of compensation or benefits of equal value, are necessary
to the provision of utility service and are not discretionary. While employees are not
likely to accept or leave a job solely based on the provision of SEW benefits, they
will certainly be attracted elsewhere by a better overall total rewards package.
Staff witness Sprinkle and CAD witness Smith argue that SERP Benefits are
excessive because they provide benefits above the level normally offered to other
AEP employees or an additional benefit that other employees do not receive.
However, the benefit formula that will be provided going forward in AEP’s SEW

ARC Rebuttal Exhibit No. 1
Page 12 of 19
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plan is nearly identical to that provided in the qualified pension plan in which all fulltime
employees participate, except that the tax limits imposed on qualified ERISA
pension plans do not apply. Qualified plan tax limits cap the amount of retirement
benefits that are subsidized with favorable corporate tax treatment, the purpose and
result of which is to increase government tax revenue. These qualified plan tax limits
are not a limit on or statement about the amount or number of retirement benefits that
companies can or should provide. Therefore, by recommending the elimination of all
SEW expense from the cost of service for ratemaking purposes, the Staff and CAD
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witnesses are suggesting that higher paid employees should not receive retirement
benefits based on the same formula as other employees, in essence capping the
formula to provide the same capped retirement benefit to all higher paid employees.
They are also arbitrarily choosing the qualified plan tax limits as the demarcation
point for what they consider to be reasonable and appropriate retirement benefits
without providing any rationale for this arbitrary limit. Moreover, while I agree to an
adjustment for the SEW credit in this instance, I do not generally believe an
adjustment to reduce or eliminate AEP’s supplemental benefit plan expense from
rates would be appropriate.
DO YOU AGREE WITH THE STAFF AND CAD RECOMMENDATIONS TO
EXCLUDE LONG-TERM INCENTIVE EXPENSE FROM THE
COMPANIES’ COST OF SERVICE
No. The amount of long-term incentive compensation the Companies included in
their cost of service is less than the target amount, even though the target amount of
long-term compensation is the amount needed to provide a market competitive total

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compensation opportunity to employees on average. Therefore, it is part of the
Companies’ market competitive total compensation package and is not a bonus on top
of an already market competitive total compensation program, as is asserted by both
Staff witness Sprinkle and CAD witness Smith.
Mr. Smith’s recommendation to exclude long-term incentive Compensation
expense is based on his view that ratepayers “should not be required to pay executive
compensation that is based on the performance of the company’s (or its parent
Company’s) stock price.” He views such compensation as a way for shareholders to
induce company employees to work to promote shareholder interests at the expense of
ratepayer interests. This view is based on a false dichotomy that ignores the
encouragement that long-term incentive compensation provides to participants to
work in both shareholder and ratepayer interests. CAD witness Smith does not
provide any explanation of, or allow for any exceptions with respect to, his view.
This is indicative of the extreme nature of his view. While long-term incentive
awards predicated on extremely high or uncapped earnings targets could put
shareholder and ratepayer interests at odds, AEP’s long-term incentive compensation
is predicated on achieving earnings targets that are similar to the Companies’
authorized rate of return. In any event, the Companies have not requested inclusion of
any long-term incentive expense above the target level in their cost of service.
Furthermore, AEP’s long-term incentive targets are set to motivate but to be
achievable. Therefore, ratepayers are not being asked to pay for long-term incentive
expense attributable to a rate of return or stock price performance above what could

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reasonably be expected based on the average rate of return allowed in all of AEP’s
jurisdictions.
Moreover, contrary ‘to Mr. Smith’s assertion, the Companies’ performance
unit program and older restricted stock unit awards, which constitute a large majority
of the Companies’ long-term incentive expense, have always been expensed as
liability awards, rather than treated as equity awards under SFAS 123R and previous
equity award accounting standards. Consequently, Mr. Smith’s argument (that the
accounting change requiring expensing of equity awards does not provide a reason to
shift the expense of these awards from shareholders to ratepayers) is not applicable to
the Companies’ long-term incentive awards.
Mr. Sprinkle suggests that the expense of long-term incentive compensation, if
continued, should be absorbed by shareholders “during this huge national economic
downturn,” but he provides no rationale for why this is a valid determinant, what
gauge of economic conditions might be a fair barometer for measuring this, or what
level of economic prosperity would trigger the end of such shareholder absorption.
Q. WHY SHOULD LONG-TERM INCENTIVE EXPENSE BE INCLUDED IN
THE COMPANIES’ COST OF SERVICE FOR RATEMAKING PURPOSES
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A.
AEP provides long-term incentive compensation as part of a market competitive total
compensation program just as it does with annual incentive compensation. AEP’s
long-term incentive compensation is intended, as the name implies, to encourage
participants to consider the long-term impact of their decisions on AEP and all of its
stakeholders, which include both the Companies’ shareholders and ratepayers. AEP’ s
long-term incentive program also serves as a way of rewarding employees in AEP’s

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currency for extraordinary performance that often has significant benefits to
ratepayers, such as by designing new equipment and procedures in house, and thus
avoiding the cost of much more expensive outside contractors and consultants.
Again, without a market competitive total compensation program that includes
either long-term incentive compensation or some other form of compensation of equal
value, AEP cannot hope to successfully compete for appropriately skilled and
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experienced personnel.
Therefore, as previously shown, providing market
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competitive total compensation to employees at all levels of the organization is a
necessary cost of providing utility service. This is particularly true at leadership
levels where management continuity can be critical. Simply put, no company of
AEP’s size and complexity can hction effectively without highly skilled people to
lead it. Economies of scale make AEP and most other companies of its size and
complexity more efficient than companies of smaller scale. While it might be possible
to break up AEP into many smaller companies with lower level leadership roles for
which long-term incentive compensation is less prevalent, this would likely result in a
reduction in economies of scale and, ultimately, higher rates. Therefore, ratepayers
are better off maintaining AEP’s current structure, which requires a substantial
number of positions for which long-term incentive compensation is a highly prevalent
and substantial component of a market competitive compensation program.
WHAT OTHER JUSTIFICATION WAS CITED FOR EXCLUDING ALL
LONG-TERM INCENTIVE EXPENSE FROM THE COMPANIES COST OF
SERVICE FOR RATEMAKING PURPOSES

ARC Rebuttal Exhibit No. 1
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CAD witness Smith states that stock based compensation expense “should be
removed because the expense is not needed for the provision of utility service.”
However, as previously stated, AEP provides long-term incentive compensation as
part of a market competitive total compensation program just as it does with annual
incentive compensation. Therefore, the company cannot simply eliminate it without
providing an offsetting increase in some other form of compensation or it will suffer
the ills and increased overall costs incurred by companies that do not provide market
competitive compensation.
HOW HAS THE WEST VIRGINIA COMMISSION ADDRESSED LONG-
TERM INCENTIVE COMPENSATION IN A RECENT RATE CASE
DECISION
CAD witness Smith cites the same text from the Commission’s Dominion Hope Gas
case for long-term incentive compensation as he did for annual incentive
compensation, which allowed incentive compensation for direct employees of the
utility but disallowed 50% of the affiliate service company charges for incentive
compensation for senior management.
WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE CAD
AND STAFF PROPOSALS ON LONG-TERM INCENTIVE
COMPENSATION
I recommend that the Commission reject those proposals and include all long-term
incentive compensation in the cost of service for ratemaking purposes. However, if
the Commission wishes to exclude executive long-term incentive expense from rates,
it should not exclude all long-term incentive compensation, because this type of

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compensation is provided to many employees other than executives, There are
currently 15 executive officers of AEP or public subsidiaries of AEP, such as the
Companies, which is approximately 2% of the population that receives long-term
incentive awards. The value of long-term incentive awards granted to these executive
officers is approximately 40% of the amount granted to employees overall.
Therefore, if the Commission wishes to reduce the amount of long-term incentive
compensation included in rates by the amount granted to executives, I recommend a
20% reduction of the expense requested by the Companies’ which reflects 50% of the
40% portion granted to executive officers. This would reduce Smith’s adjustment
from $2,527,105 to $505,421.
DO YOU AGREE WITH CAD WITNESS SMITH’S RECOMMENDATION
TO EXCLUDE OTHER EXECUTIVE COMPENSATION FROM THE
COMPANIES’ COST OF SERVICE
While I’m sensitive to concerns and public perceptions regarding perquisites expense
in general and personal use of corporate aircraft in particular, I do not agree that all of
these costs should be removed from the Companies’ cost of service, Mr, Smith again
argues that these costs should be removed from the Companies’ cost of service
“because none of these items are necessary for the provision of safe and reliable gas
[sic] service to APCo/WPCo’s ratepayers.” To the contrary, most of these costs
necessary for the provision of the Companies’ utility service for the same reasons I
noted above with respect to Supplemental Executive Retirement Expense and they
should be included in the Companies’ cost of service.

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The expenses that Mr. Smith includes in his recommended adjustment were
derived from information provided in AEP’s annual proxy report in accordance with
Security and Exchange Commission reporting requirements. In many cases, these
requirements differ from generally accepted accounting principles (GAAP), the
Internal Revenue Code, or both. Therefore, the amounts Mr. Smith is recommending
be removed from the cost of service are calculated on a basis that is different, in some
cases, from generally accepted accounting principles or the Internal Revenue Code, if
there is a direct accounting expense attributable to them at all. For example, the
Wellness incentive program is a cost absorbed by AEP’s medical trust, not AEP or
the Companies.
In addition to the reasons given in my decision of SEW expense above, it is
inappropriate to single out retirement savings plan matching contributions,
supplemental retirement savings plan matching contributions, health and wellness
program incentives and relocation payments for senior executives because no
objection has been made to these items being a reasonable and appropriate cost for
employees in general. All employees are eligible to participate in retirement savings
plan matching contributions, and health and wellness program incentives. Employees
who are asked to relocate are also generally offered relocation benefits. Currently,
531 AEP employees are eligible to participate in the supplemental retirement savings
plan and thereby receive matching contributions in this plan, which shows that this
program is an important part of AEP’s market competitive total rewards program for a
broad group of employees, not just the five proxy officers. In addition, a majority of

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companies similar to AEP provide such matching contributions through similar plans
(see EXHIBIT ARC-5 Clark Consulting Executive Benefits Survey, p. 10).
AEP provides personal use of corporate aircraft to Mr. Morris and, in a few
instances, to other executives, because the HR Committee believes that the enhanced
security, travel flexibility and reduced travel time that corporate aircraft provide, for
both business and personal travel, benefit AEP and, by extension, all of its
stakeholders. Mr. Morris negotiated the use of corporate aircraft for personal travel as
part of his employment agreement. However, the HR Committee has offset Mr.
Morris’ s compensation opportunity by an amount approximating the incremental cost
of his personal use of corporate aircraft above that of other CEOs in AEP’s
Compensation Peer Group (see my Direct Testimony ARC Exhibit No. 2, page 46,
paragraph 1). Therefore, this cost is clearly a component of his market competitive
13 total compensation package and ratepayers receive an offsetting benefit to this cost in
14 the form of offsetting reductions in his other compensation.
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For the reasons cited above, I recommend that retirement savings plan
matching contributions, supplemental retirement savings plan matching contributions,
health and wellness program incentives, relocation payments and personal use of
corporate aircraft continue to be included in the Companies’ cost of service for rate-
19 making purposes.
20 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
21 A. Yes, it does.

~ .----
ARC Rebuttal Exhibit No. 2, Page I of 2
@
Hourly Market Analysis
AEP’s hourly rates for key benchmark Utility Group and Power Generation positions
continue below market as a result of the 2009 pay freeze, and are only slightly better
in total cash compensation relative to all comparable companies for the East portion
of the AEP System
vs. All Comparable Companies
-. -
Above the competitive range (+/- 5%)
Below the competitive range (+/- 5%)
E

ARC Rebuttal Exhibit No. 2, Page 2 of 2
Hourly Market Analysis
When measured against region specific comparable companies, AEP’s hourly rates
for key benchmark Utility Group and Power Generation positions are also below
market on base pay, but more competitive on a total cash compensation basis for
the East portion of the AEP system
vs. East Region Comparable Companies
Above the competitive range (+/- 5%)
Below the competitive range (+/- 5%)

ARC Rebuttal Exhibit No. 3, Page I of 1
Annual Incentive Award History
Overall Non- Overall Executive
Executive Score as a Score as a Percent of
Year
Percent of Target
Target
2005
163.7% I 179.4%
2006 184.9% I 151.6%
2007 156.0% 134.4%
2008 136.2% 120.5%
2009 23.1 % 0.0%
2010 est. 100.0% 100.0%
6 Year Average
127.3% 114.3%
Amount Requested in Rates 100.0% 100.0%
Delta
27.3% 14.3%
1

presented by
\
\

ARC Rebuttal Exhibit No. 4
The Survey moved from an annual to a biennial survey in 2005. Therefore, this edition of the Survey
does not contain specific information for 2006 or 2008,
While comparisons in this report are often made between the 2009 Executive Benefits Survey and
prior years' surveys, care should be taken not to infer trend data based solely on such comparisons,
as participating companies vary each year. Nevertheless, in general analysis, significant percentage
changes might be indicative of changing corporate practices.
Unless specifically noted otherwise, the percentage breakdowns of responses to a given question are
net of "no response"; that is, they are derived only from the subset of valid responses.

ARC Rebuttal Exhibit No. 4
Dear Colleague:
Clark Consulting IS pleased to present the findings from the fotirteenth edition of Executive
Reliefits - il Survey of Current E ed, which reports on issues and trends involving executive
benefit plans. The results reflect data compiled from over 11 Or; of Fortrrne f 000 companies.
Since Clark Consulting last conducted this survey in 2007, the United States has espcricnced
cstraordinary devclopmcnts in the financial markets ss wcEl ,IS the broader cconomy.
We are experiencing the consequences of one of the longest and deepest contractions since
the Great Depression. Unemployment more than doubled to over 10% and continues to be
a concern. After peaking in October 2007, rhe Dow Jones Industrial Avcrage dropped to just
above 6,500 points by March 2009, and as of this writing has recovered to about 10,000 points.
Although there have been encouraging signs recently, we still await broad consensus on the
timing of a sustained recovery impacting all sectors of the economy.
In the midst of these challenges, as well as concerns about potential legislation and public
sentiment, employers naturally remain uncertain about their approach toward executive
compensation.
But when we look ahead beyond the current turbulence, the fundamentals remain unchanged.
The companies that will emerge strongest from this recession are those that have the strongest
leadership and teams. They are the companies best positioned to fully realize the opportunities
offered by an economic recovery. In this context, it is crucial for employers to constantly recruit,
reward and retain talented executives.
The results of our 2009 survey reflect employers’ current concerns while showing that
employers rccognizc the value of a well-designed, market-driven cxecutivc bcncfits plan that is
adequately funded.
I invite you to review the 2009 results of Clark Consulting’s Executrve Reizefits - A Survey of
Current Trends. Having a comprehcnsivc executive compcnsation and bcncfits stratcgy has
never been more important ... or more challenging!
Sincerely,
Kurt Laning
President, Clark Consulting

Table of Contents
ARC Rebuttal Exhibit No. 4
In trod uction
Purpose of the Survey , . , , , . . * . , . , . . . . . ,, , , . . . . , , , . I I I t 5
Impact of Legislation , , , , , , . ,,, . , . . . . ,.. , , , ,.. . . . , , , . ,.. .5
Executive Summary., , , , , , , , , , , , , , . ,
,. ,, . , , , . ,. . . . , , , , ,. . I
Nonqualified Deferred Compensation (NQDC) Plans
Plan Prevalence. .,.#.*.. ...... t , . . * . . . . I . .
Eligibility.. , , , , , .. .. . , . . . ,.. I . . , , ..-,.. .. . . . , , . I .. . . . . ,.. . I . , . . . . ,.. .8
Deferrable Compensation .... , . , . . . ., , , . . I ... . . . . , . . ,., . . , . , , . , ., . . I . 9
Matching Contributions . . . I . ,., , , .... I I .. I . . . . , , , , . , , . . I , , , , I I -10
Types of Matchlng Contributions.. . . ..... , , , . . . . . . . . . ,.. . , ,. . . , . .. . . -11
Vesting. ,.,, ,.,., ,. , , , , .,, , . , , . . , , . . , , , , ... ., I + ,, ,.....,, , . . I . . I I I . , . . I 11
Payment of Benefits, , ,., . . , . . , , .. *. . . . I , , , , , , e , , . , , I . . , , , I . , , . , . . .12
, ,., . . I I
Payment Options ., , ,, , .., , ., . . ,..
, , , I , , , , , ,, . . . . . , . . , . , ,. . , ... , -13
Change in Distribution Election ,.. . ... , , ... , , , , , , I . I I I < . , ., . , , . , , . . , , . , . , , . . . 14
ayment of Distributions in Employer Stock,. . I I , , , I , ,, , s , . . I ,,. I . . I I . . ,..., .15
erest Crediting Rates on Deferrals ... . ,.... I .. , , , , , I I I ,,.. . . ,.., . . . I I . . . , I . . . .16
NQDC Plan Informal Funding. , , ,. ,., . . , .., , , . , , , , , , . I , , , ,, , . . , , , . . , , , , , .17
Funding Vehicles , , . ,, , . ., ,.. . . , , , I ,., , , , , . . I . ., . , . . . , I . . , . . ....18
LI,, . ,, , , ,.,,, , , * , , , , , , , . ,, . . , , , , ,,* ,,I.,, , , , , . . , , , , , . . I I I .,, . . I I .19
d Alternatives. . . . I . . . . . I I . I . ., I . . ,.. , ,, , . I ,.. , , , . , I I . I . . , I . . . .., . . . . . -20
.,.I.,...,.,,,I. 6 ...,II.,....,.I.,,......,.I,....,.,... .. I..., . ... 20
a
ration,, . , , . , .,
, ,,,. ,,,,..,,.,,,,, ,,. , , . . , . . . , . . , , , .21
Supplemental Executive Retirement Plans (SERPs)
Plan Prevalence,, , , . , , , . , , , . . , . , , , , . . , , , , , , . . , .. , , , .. , , , . . , , . , , , . . , . a a ,.., , I I ,,., . . a ,23
Eligibility,, , , , , , , , , , , . , , . . , , . . , , , , , . , , , , , , . , . ,,, . . , , , . I ,II.., , , , , , .,., ,,,. . , , . . , , ,24
Reasons for Implementing a SERP. . , I , , , , , , , , , , , , I , , , , , a , , I , , , , . . I I I , , , , I ,,. , , I I I ,25
SERP Benefit Formulas., , , , , , , , , . , , , . . , , , , , , . . , , , , , , . , , , , , , , , , , I . , , * . . . , , , . , . . , -26
SERP Benefit Offsets., , , . , , . . , . , . , . , , , . , , ,., , , . , , , , , , . . , , , , , , , , , a I I , I , , , I. a , , , I . I .27
SERPVesting , , , .. , , . , , , . . , , , , , , . . . , , , , , , , , , . , , , . , , , , , , , , , , , , , , , . , , , , . . . , ,,,, I. .28
SERP Benefit Payment Triggers,, , ,. . , ., , , I . . ,, , , , , , I I I , , , , , , I I I , , , , ,. I I I , , . . I I I I ,,, . I I I .28
Payment Options . . , , . , , , , , , , , , , , , , . . , , , , , , , , . , , , , , , , , , , , , , , , , , , , , , , , . , , , , . , , a , . , , . . . .29
Informal SERP Funding, , , , . , . , , , , . I , , , ,',, . ,,, , , , , ,,. ,, , . . . , , , , , , . , . a , . , . , . . , , , , . I . ,30
Types of Informal Funding Vehicles. , , I , , , , I , , , . , , , , , , , , . , , , , , , I I , , $ , , . . I . , , , I I I . , I , , . I . I -31
Rabbi Trusts and Alternatives. , , ,, , , , . , , , , . , , , I , , , , , , , . . , , , , , , , , , , , , , I I I , , , , , , , I . , , I , , I I I .32
SERP Administration. , , , , . I , . , , . . , , , , , . . , , , , , , , , , , , a , , . . , , , , , , , , a a , . , , . . . a I . , I , .33
6
-Term Disability Benefits , , . , , , , , , , ,.,, . . , , , , , , I . , , . ., , . ,,., a m , .35
bility Benefits Formulas , , ,,, , , , . , , , , , , . , , , , , , , , a a ,., . . , . . . , ,. . . I I -36
Executive Perquisites ,. , , . , , , , , . , , . , , , . , , , , , , , , , , , . . , , , . , , I . , . , , , I , . , . , , ,. , , . . , . I -37
Survey Methodology & Respondent Distribution
Survey Methodology. , , , , , , , , , , , , , , , , , , ,,.,, , , I, ,, , , , , , , , , I , , , , , I I I I , . I I . I . I
I
Respondent Distribution I . . ,. . . I. a ,,, , , , ,,, , , , . I I . ,,,.. . . , . . . , .
Survey Respondents
I I I .39
a .39

Rebuttal Exhibit No. 4
/
I ~~~~~ uction
The 2009 edition of Executive Benefits
- A Survey of Current Trends (the Survey)
is the fourteenth survey on executive benefits
conducted by Clark Consulting. The goal
of the Survey is to identify how corporate America
is providing certain nonqualified retirement and
welfare benefits to its executives. The Survey
focuses on two main types of nonqualified
retirement plans - Nonqualified Deferred
Compensation (NQDC) plans and Supplemental
Executive Retirement Plans (SERPs) - and also touches
upon supplemental long-term disability benefits and other
executive perks.
\

ARC Rebuttal Exhibit No. 4
PURPOSE OF THE SURVEY
The 2009 edition of Executive Benefits -A Survey of Current Trends (the
Survey) is the fourteenth survey on executive benefits conducted by Clark
Consulting. The goal of the Survey is to identify how corporate America is
providing certain nonqualified retirement and welfare benefits to its executives
and how these plans are structured, funded, secured and administered. The
Survey focuses on the two main types of nonqualified retirement plans:
Nonqualified Deferred Compensation (NQDC) plans (Le*, voluntary deferral plans)
and Supplemental Executive Retirement Plans (SERPs). Supplemental long-term
disability benefits and other executive perquisites are also reviewed. The Survey
moved from an annual to a biennial survey in 2005 and therefore does not include
specific information for 2006 or 2008.
IMPACT OF LEGISLATION
In October 2004, the American Jobs Act was passed, creating a new Internal
Revenue Code section (409A) that governs nonqualified deferred compensation
plans for amounts deferred after December 31,2004.
The legislation codifies some specific rules for the design and operation of
these plans. For example, plans may allow payment of benefits only following
certain permissible distribution events, and the plans must follow restrictions on
both the timing of deferral elections and changes to distribution elections, The
legislation also prohibits plan provisions that accelerate benefit payments, such as
withdrawal provisions (haircuts).
As a result of the requirements in the legislation, the design of SERPs and NQDC
plans changed as plan sponsors revised their arrangements to comply with the
new statute and related regulations,
Accordingly, the statistics and trends contained in our current survey represent
the third occasion that responses may reflect changes to the nonqualified plans
due to this legislation.
INTRODUCTION

ARC Rebuttal Exhibit No. 4
EXECUTIVE SUMMARY
Developments in the employment landscape over the past 25 years or so
have increasingly changed the retirement planning outlook for employers and
employees. Responsibilities for retirement saving have shifted, and legislative
limitations have evolved.
Restrictions on the amounts executives can contribute and receive in qualified
benefit plans have led companies to supplement retirement benefits by
implementing nonqualified benefit plans for their executives.
Nonqualified retirement plans such as NQDC plans and SERPs are now integral
parts of an executive’s overall financial portfolio - and are therefore powerful tools
to help companies recruit, reward and retain talent.
The 2009 Executive Benefits Survey’s key statistics and trends follow:
Plan Prevalence
u Although NQDC plan prevalence has decreased since 2007 (95%), it remains
high - 85% of responding companies report having NQDC plans.
* 67% of responding companies report having SERPs, similar to the prevalence
in 2007.
Plan Funding
0
71% of respondents report informally funding their NQDC plans, up from 62%
in 2007 and at the highest level since 2001, This stands in interesting contrast
to the apparent decrease in plan prevalence over the same period.
- 39% of 2009 respondents report informally funding their SERPs, vs,
48% in 2007,
0 61% of respondents funding their NQDC plans and 68% of those funding their
SERPs use Corporate-Owned or Trust-Owned Life Insurance (COLVTOLI).
Plan Administration
6 The percentage of respondents exclusively administering their NQDC
plans in-house has dropped from 15% in 2007 to 3% in 2009, This has
been accompanied by corresponding increases in prevalence of third-party
administered and combination (in-house and third-party) administered plans,
n
32% of respondents sponsoring SERPs administer their plans in-house,
slightly higher than in 2007 (30%) but lower than the levels seen in
2001 (48%).
2089 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

D
or purposes of this Survey, a Nonqualified
eferred Compensation (NQDC) plan is defined as a
nqualified retirement plan under which a participant
voluntarily elects to defer some portion of his or her salary,
short-term incentives or other compensation. A typical
NQDC plan allows a participant to elect to defer a portion
of his or her salary and/or bonus until a future date, such
as retirement or termination of employment.
Generally, deferrals will be credited to an account, and
interest or some other type of credit will be applied to that
account on a periodic basis. At the appropriate time, the
balance of the account will be distributed to the participant,
either in a lump sum or over time. The NQDC plan may
include an employer contribution,

ARC Rebuttal Exhibit No. 4
/
PLAN PREVALENCE
As the chart below shows, 85% of the respondents to the 2009 Survey questionnaire
(Respondents) offer some type of NQDC plan in 2009, representing a drop to levels last
seen in 2001 -2002 but still reflecting widespread prevalence of the plans.
Comment: The drop since 2007 might be a reaction to current market and economic
conditions.
Of those Respondents offering an NQDC plan in 2009, 65% also maintain a SERP for the
benefit of executives.
100%
90%
%o%
7@h
60%
50%
40%
30%
20%
10%
PREVALENCE OF NQDC PLANS
\
0% 2001 2002 2003 2004 2005 2007 2009
Have an NOD( Plan Currenlly Considering H Not Currently Considering
I
NQDC PLAN PREVALENCE (2009)
Up to $2.5 Billion Above $2.5 Billion All Financial All Surveyed
in Annual Revenue in Annual Revenue Institutions Companies
88% 84% 82% 85%
i
Base: Survey Respondents.
NONQUALIFIED DEFERRED COMPENSATION (NQDC) PLANS

ARC Rebuttal Exhibit No. 4
E LIG I BI LlTY
NQDC plans have typically been designed to cover executives from the board of directors
to vice presidents and highly compensated sales personnel, However, since the Omnibus
Budget Reconciliation Act of 1993 lowered the limit on compensation for qualified pension.
calculations to $1 50,000 (currently indexed to $245,000 in 2009) while the limit on annual
contributions to 401(k) plans is currently at $1 6,500, some companies have responded
by offering NQDC plans to middle management personnel. The following chart shows the
percentage of Respondents that offer NQDC plans by specific position levels. 90% of
Respondents with NQDC plans determine eligibility entirely or in part by position level.
NQDC PLAN ELIGIBILITY BY POSITION LEVEL (2009)
Presidents and Chief Executive Officers
Board of Directors
Executive and Senior Vice Presidents
Vice Presidents
Division or Unit Managers
Highly Compensated Sales Personnel
Other
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Base: Respondents determining NQDC plan eligibility by position level.
2009 RESULTS EXECUTIVE BENEFITS ASurveyof Current Trends

ARC Rebuttal Exhibit No. 4
/
Of the Respondents with NQDC plans, 64% determine eligibility at least in part by
using base salary compensation level as a criterion (compared with 47% who use total
compensation). 10% of Respondents who use base salary to determine eligibility allow
participants with compensation below $1 00,000 to participate in their plans, while 2% of
those who base eligibility on total compensation permit participation by individuals earning
less than $100,000.
NQDC PLAN ELIGIBILITY BY BASE SALARY COMPENSATION LEVELS
\
2007 2009
H S150,OOO ond higher
a s125,ooo to s1s0,000
D SlO0,OOO io Sl25,OOO
Under SlO0,OOO
Olher
Base: Respondents determining NQDC plan eligibility by base salary level.
In 2007, 43% of Respondents based their NQDC plan eligibility on base salaries of
$1 25,000 and above. By 2009, this percentage increases to 52%.
D E F E R R A B LE C 0 M P E N SAT1 0 N
Deferrable compensation is broken down into several categories, which include base salary,
short-term incentives, long-term incentives, director’s feedretainers and restricted stock,
I TYPES OF DEFERRABLE COMPENSATION ALLOWED (2009)
’ ._ - __^I-
Base Salary
Short-Term Incentives
Long-Term Incentives - Cash
Other Compensation
Director’s FeeslRetainers
Restricted Stock
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
NONQUALlFlED DEFERRED COMPENSATION (NQDC) PLANS

ARC Rebuttal Exhibit No. 4
The percentage of Respondents allowing deferral of compensation did not change much
since 2007 for the top three categories (base salary, short-term incentives and director's
fees/retainers). Those allowing deferral of long-term incentives - cash did increase, from
35% in 2007 to 43% in 2009.
24% of Respondents allow 100% of salary to be deferred, and approximately 16% only
permit deferrals of up to 50% of salary. For short-term incentive compensation, most
companies (66%) allow a deferral of up to 100%. Permissible deferrals of director's
feedretainers range from less than 50% to 1 OO%, with a substantial majority (86%)
of Respondents allowing up to 100% of director's feedretainers to be deferred, Of
Respondents allowing deferral of long-term compensation in cash, the majority (68%) permit
up to 100% of awards to be deferred.
M ATC H I N G C 0 NT R I B UT I 0 N S
Generally, the purpose of an NQDC plan is to allow executives to defer receipt of, and
therefore defer current taxation on, personal income. However, a number of plans also
provide a matching contribution by the employer. The percentage of Respondents providing
corporate matching contrrbutions to NQDC plans rose steadily from 38% in 2004 to 56%
in 2007, and remained almost unchanged in 2009. In total, 55% of Respondents in 2009
with NQDC plans make corporate matching contributions (compared with 94% of 2009
Respondents making corporate matching contributions to their 401 (k) plan),
Comment: The increase from 2004 to 2007 coincided with a time of growth for the US.
economy, when rewarding and retaining top executives would have been a major focus for
companies, 2009 results might be attributed to companies avoiding a knee-jerk pullback of
benefits, In addition, with deferral amounts expected to be lower, the corporate match would
also be lower, thus cushioning the impact.
1 00%
90%
80%
70%
60%
50%
40%
30%
20%
\
CORPORATE MATCHING CONTRIBUTIONS IN NQDC PLANS 1
10%
0%
2001 2002 2003 2004 2005 2007
2009
Match
H No Match
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
2039 RESULTS EXECUTIVE BENEFITS ASurveyof Current Trends

ARC Rebuttal Exhibit No. 4
TYPES OF MATCHING CONTRIBUTIONS
Respondents use various types of matching contribution formulas, including 401 (k) plan
restoration matches, percent of employee contributions, pay level based and company
performance based.
I
MATCHING CONTRlBUTfON FORMULAS USED IN NQDC PLANS (2009)
6% 3%
ph , ut3
**%YAY
w
401(k) Rertorafion Matth/Replores 401 (k)
m Percent of Employee Contribution
\ Tied to Compony Performonre
Jti Based on Pay level
L ',
Base: Respondents making corporate matching contributions to NQDC plans.
A majority (710/0) of organizations have structured their matching formulas to be similar to
401(k) plans (e,g., 50 cents to $1 on the dollar, up to a maximum dollar limit). For those plans
providing a 401 (k) restoration match, 49% responded that the match could be up to the
qualified plan limit. For those plans offering a matching contribution based on a percentage of
employee contribution, the match ranges from 50% to 100% of employee contribution, capped
at between 3% and 6% of compensation.
VESTING
Vesting requirements are commonly used as a retention tool, Approximately 44% of
Respondents indicate that their NQDC plan contains some type of vesting requirements for
company contributions, matching contributions, bonus interest or restricted stock - about the
same as 2007 levels (429'0)~
I VESTING REQUIREMENTS (2009)
i . "
i
Percentage of Respondents applying vesting requirement to:
Vcsring Company Matching Bonus Restricted
Reouiremenr Contributions Contrihutions Interest Stock
Years of Service 50% 78%
- 3% 9%
Years in Plan 50% 50% 25% 25%
Performance -
Goals
Base: Respondents imposing some type of vestlng requirement on thelr NQDC plan.
NONQUALIFIED DEFERRED COMPENSATION (NQDC) PLANS

ARC Rebuttal Exhibit No. 4
PAYMENT OF BENEFITS
Respondents were asked to specify the criteria for determining when a participant
becomes eligible to receive a benefit under the NQDC plan. All Respondents (1 00%) report
"separation from service" as an event that may trigger a benefit distribution.
Comment: Interestingly, 56% of Respondents do not distinguish between separation
from service due to "retirement" (Le., satisfying an age or years of service requirement) vs.
termination - up from 44% in 2007. 65% recognize "change of control" as a trigger for
payment, again up from 59% in 2007. These might reflect a recognition of the increased
likelihood of mergers, takeovers and job reductions in the current market.
Comment: 75% also allow distribution at a specified time (up from 62% in 2005),
possibly an attempt by employers to allow their employees some flexibility in light of certain
restrictions on distributions imposed by Internal Revenue Code section 409A rules.
61010 of Respondents state that their plan contains a special financial hardship
provision. This provision typically allows early withdrawal in the case of an
unforeseeable financial emergency.
I
CRITERIA FOR DISTRIBUTIONS (2009)
I
Change of Control
Separation from Service 100%
1
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

ARC Rebuttal Exhibit No. 4
PAYMENT OPTIONS
Normally, plan participants choose payment options based on their personal goals and
needs. 99% of Respondents offer a lump sum payment at the option of the executive. Of
Respondents that allow a form of distribution other than a lump sum, the most common
option reported is a term of between 5 and 20 years, selected by the participant.
PAYMENT OPTIONS IN NQDC PLANS (2009)
Annuities
Annual Payments j 1-4~
996
I f
15 30%
20
t i
Other b19* 1
Monthly Peyments 60 10%
120 'd 1 '
1106
i
i
is0 m8%
240 h5sb j ,
Other 10% 1
,
i
0% 10% 20% 30% 40% 50% 60% 70% 8oX 90% 100%
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
NONQUALIFIED DEFERRED COMPENSATION (NQDC) PLANS

I -
ARC Rebuttal Exhibit No. 4
CHANGE IN DISTRIBUTION ELECTION
The following chart shows the prevalence of the plan provislon that allows a participant to
make a change in his or her distribution election.
CHANGE IN DISTRIBUTION ELECTION (2009)
t
’
No Subsequent Change Permitted
Change Permitted Only Before Qualifying for Retirement
0 Change Permitied Only After Qualifying for Retirement
Change Permitted Before and After Qualifying for Retirement
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
- - ”
--
AMONG RESPONDENTS PERMITTING CHANGES - ._ i
After Qualifying for Retirement
Before Qualifying for Retirement
2009 RESULTS EXECUTIVE BENEFITS A Survey of CurrentTrends

ARC Rebuttal Exhibit No. 4
PAYMENT OF D STRIBUTIONS IN EMPLOYER STOCK
27% of 2009 Respondents pay all or some portion of distributions in the form of company
stock, 7% higher than in 2007.
PAY DISTRIBUTIONS IN COMPANY STOCK
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0% -
2001
2002
2003 2004 200s 2007 2009
Yes
H No
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
NONOUALIFIED DEFERRED COMPENSATION (NQDC) PLANS

ARC Rebuttal Exhibit No. 4
INTEREST CREDITING RATES ON DEFERRALS
The rate at which interest is credited to the accounts of NQDC plan participants varies
widely. 63% of Respondents with NQDC plans niirror the returns of a particular stock index
or the investment options in their 401 (k) plan, a steady rise since 2002. Once retirement
payments begin, the crediting rate applied to undistributed funds typically remains the same
as the pre-retirement rate (as is the case for 93% of 2009 Respondents).
Trends in the usage of various crediting rates are illustrated below.
INTEREST CREDlTtNG RATES
I
65%, 63
I
60% j
55%
!
” _
__
. __“ -
Treasury Note Prime Rate Fixed Rate Moody’s 401 (k)/ Company Corporate Other
Bil Corporate Bond Stock index Stock Borrowing
Index Rate
2001 2002 2003 2004 2005 2007 e’ 2009
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
The chart on the following page shows how often Respondents credit participants’ account
balances. The increase in daily crediting since 2001 has come mainly at the expense of
monthly and annual crediting.
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

I "
-I
ARC Rebuttal Exhibit No. 4
FREQUENCY OF CREDITING
1 oo&
90 9;
806
70%
60%
50%
40x
30 9;,
20%
10%
0%
2001 2002 2003 2004 2005 2007 2009
g Daily Monthly Quarterly Annually I Other
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
NQDC PLAN INFORMAL FUNDING
71% of NQDC plans in 2009 are informally funded, up from 62% in 2007, 5% of 2009
Respondents are considering informal funding within the next 12 to 24 months.
c
I
N INFORMAL FUNDING
2001 2002 2003 2004 2005 2007 2009
informally Funded Considering Unfunded/Unrpecified
I
NQDC PLAN INFORMAL FUNDING (2009)
^- ^ x .
-.-
Up to $2.5 Billion Above $2.5 Billion All Financial All Surveyed
in Annual Revenue in Annual Revenue Institutions Companies
80% 66O/o 78% 71 Yo
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
NONQUALlFlED DEFERRED COMPENSATION (NQDC) PLANS

ARC Rebuttal Exhibit No. 4
TYPES OF INFORMAL FUNDING VEHICLES
Over the years, a variety of funding vehicles have been used to informally fund NQDC plans.
Although the prevalence of Corporate-Owned and Trust-Owned Life Insurance (COLIITOLI)
dropped to 61% in 2009 (from 72% in 2007), it is still the most commonly used vehicle,
followed by mutual funds (45%).
I
TYPES OF NQDC PLAN FUNDING VEHICLES
7596 72
70
70% \
6565
65
r
% -mi
60% 1
55% 50% I
45% j
40% 1
35% 1
30% I
25% 1 23
20% I" II
15% i
1O%i .
5%
3-2
0%
Bonds or Company COll/lOU Corpornle Mutual Mnnaged Other
Bond Funds Stock Assets Funds Portfolio
1001 2002 2003 zoo4 ZOOS 2007 2009
S INFORMAL FUNDING VEHICLE DC PLANS (2009)
Up to $2.5 Billion Above $2.5 Billion All Financial All Surveyed
in Annual Revenue in Annual Revenue Institutions Companies
53% 699'0 50% 6 1 Yo
Base: Respondents informally funding or considering funding their NQDC plan.
2009 RESULTS EXECUTIVE BENEFITS A Survey of CurrentTrends

ARC Rebuttal Exhibit No. 4
TYPES OF COLI/TOLI
Respondents that informally fund their plans with COLllTOLl were asked the type
of product being used. 33% use whole Iife/universal life insurance, down from 42%
in 2007. 67% use variable life insurance, up from 58% two years ago.
Whole Iife/universal life premium payments are invested in the general assets of the
insurance company, while variable life premium payments are invested in a separate account
held outside the general assets of the insurance company.
100%
TYPES OF COLl/TOLI
\
90%
80%
70%
60%
50%
40%
30%
20%
1 oq
0% - -
2001
Variable Life
2002 2003
2004 2005 2007 2009
I Whole life / Universal life
Base: Respondents informally funding their NQDC plan with COLI/TOLI.
NONClUALlFlED DEFERRED COMPENSATION (NQDC) PLANS

ARC Rebuttal Exhibit No. 4
RABBI TRUSTS AND ALTERNATIVES
80% of 2009 Respondents use some device to protect NQDC plan participants, up 10%
from 200%
The most prevalent arrangement for the past several years and in 2009 is the Rabbi Trust,
which may offer the participant protection, short of the company's bankruptcy or insolvency,
that the assets will only be used for the payment of the intended benefits
Comment: The overall increase in protective arrangements since 2007 might be driven by
rising concerns among participants about potential change of heart or change of control in
an uncertain economy.
100%
95%
90%
85%
80%
75%
70%
65%
60%
55%
50%
45%
40%
35%
30%
25%
20%
15%
10%
5%
0%
' Funded/Unfunded ' Springing Rabbi Split Dollar Rabbiculur Employer Secular Other
Rabbi Trust Trust Trust Trust
2001 2002 2003 W 2004 W 2005 I2007 2009
Base: Respondents using some device to protect NQDC plan participants.
PARTlCl PATION
On average, 46% of eligible participants in NQDC plans offered by Respondents choose
to participate in the plan. In the NQDC plans that are funded, participation is slightly higher
(48%) and in the NQDC plans that are "secured," participation is 47%.
! PARTICIPATION LEVEL (2009)
"Secured" NQDC Plans
I
Fuiicled XQDC Plans
A11 NQDC Plans
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Partitipote
Do Not Participate
Base: Respondents sponsoring or considering sponsoring an NQDC plan.
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

I .~
ARC Rebuttal Exhibit No. 4
The following chart shows the parkipation levels in NQDC plans that use various popular
crediting rates.
NQDC PARTICIPATION LEVEL BY TYPE OF CREDITING RATE (2009)
Fixed Rate
140ody's Corporate Gond Index Rate 55%
Ten-Year Treasury Note
Same as 401(k)
S&P 500 Composite Index
Prime Rate 1-41 %
1
\ a
Company Stock I '
I ,
$ 1
OS& 10~620% 30% 4 0 ~ 50% 60% 70% 80% 90% 100%
Base: Respondents sponsoring or considering sponsoring an NQDC plan. \
NQDC PLAN ADMINISTRATION
The percentage of Respondents exclusively administering their NQDC plans in-house has
decreased steadily - from 24% in 2001 to 3% in 2009, This has been accompanied by
corresponding increases in the prevalence of third-party administered and combination
(in-house and third-party) administered plans.
Comment: In particular, the sharp drop in in-house administered plans from 2005 (19%) to
2009 (3%) may reflect a need for more sophisticated administration and greater capabilities
in light of the need to satisfy the requirements of Internal Revenue Code section 409A.
" - >
i NQDC PLAN ADMINISTRATION - 1
10096
90%
80%
7oYY
60%
50%
40%
30%
20%
10%
0%
2001 2002 2003 2004 2005 2007 2009
In.House Third-Partv Combination Other
*Of which 45% are administered by the same provider as the 401 (k) plan and 55% are
administered by another provider.
Base: Respondents informally funding or considering funding thelr NQDC plan.
NONQUALIFIED DEFERRED COMPENSATION (NQDC) PLANS

,/‘
J’
, I
ARC Rebuttal Exhibit No. 4
i
Supplemental Execu
For purposes of this Survey, a Supplemental
Executive Retirement Plan (SERP) is a nonqualified
retirement plan under which the employer provides an
additional retirement benefit to the employee.
A SERP may be characterized as either a nonqualified defined
contribution plan or a nonqualified defined benefit plan. Often,
a SERP is tied in some fashion to the benefits provided under
the employer’s qualified retirement plans.
The primary reason for adopting a SERP continues to be the
Omnibus Budget Reconciliation Act of 1993, which lowered the
limit on compensation used for qualified pension calculations
to $150,000 (currently indexed to $245,000 in 2009)
(Internal Revenue Code §401(a)(l7)).

ARC Rebuttal Exhibit No. 4
I
f
PLAN PREVALENCE
As in 2007, 67% of Respondents have adopted a SERP to provide benefits to executives in
excess of amounts limited by qualified plan restrictions.
i
This represents a drop from the levels seen in 2001 and 2002 (2004 appears to be a data
anomaly).
Of the 2009 Respondents who sponsor or are considering sponsoring SERPs, 77% indicate
that the most recent SERP is a defined benefit plan (previous editians of the survey did not
draw this distinction).
1 m%
90%
80%
703h
60%
50%
40%
30%
20%
10%
SERP PREVALENCE
‘1
.3
0% 2001 2002 2003 2004 2005 2007 2009
Have a SERP Currently Considering I Not Currently Considering
- -
I
SERP PREVALENCE (2009) !
Up to $2.5 Billion Above $2.5 Billion All Financial All Surveyed
in Annual Revenue in Annual Revenue Institutions Companies
-
57% 66% 89% 67%
Base: Survey Respondents.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS (SERPs)

ARC Rebuttal Exhibit No. 4
E LIG I6 I LlTY
The following chart displays SERP eligibility among Respondents based on specific
position levels.
SERP ELIGIBILITY BY POSITION LEVEL (2009)
Presidents and Chief Executive Officers 839;
Board of Directors
Executive Vice Presidents
Senior Vice Presidents ' 63%
Vice Presidents
Division or Unit Managers
Highly Compensated Sales Personnel
I
Other
0% loo/, 20% 30% 40., 50% 6096 70% 80~" 90% 100%
Base: Respondents determining SERP eligibility by position level.
I
57% of Respondents who use base salary to determine SERP eligibility require a
minimum of $1 50,000 in base salary. 72% of Respondents who use total compensation
to determine SERP eligibility require a minimum of $1 50,000 in total compensation.
I
"- - _ -
SERP ELIGIBILITY BY BASE SALARY COMPENSATION LEVEL (2009)
" I
2007 2009
I $150,000 and higher
rn s12s,000 to s1s0.000
SlO0,OOO to sl25,OOO
Under Sl00,OOO
Other
Base: Respondents determining SERP eligibility by base salary level.
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

ARC Rebuttal Exhibit No. 4
REASONS FOR IMPLEMENTING A SERP
The predominant reasons for establishing a SERP are to:
* Replace benefits lost by the Section 401 (a)( 17) limit ($245,000 salary cap in 2009).
Replace benefits lost by Section 41 5 limits.
Replace benefits lost by other tax code limitations.
* Provide additional incentives for high-level executives to join company.
* Provide executives with retention incentives (golden handcuffs).
Provide targeted retirement compensatlon.
* Provide retirement benefits that are higher than those under the qualified plan.
The following chart quantifies Respondents’ reasons for implementlng a SERP.
r
i
REASONS FOR IMPLEMENTING A SERP (2009)
Replace Benefits Lost by
401(a)( 17) Limit
Replace Benefits Lost by 415 Limits
Replace Benefits Lost by
Other Tax Code Limitations
Provide Additional Recruitment
Incentives
Provide Retention Incentives
Provide Targeted Retlrement 5324
Compensation .
Provide Higher Retirement Benefits
Than Under Qualified Plan
I
0 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Base: Respondents sponsoring or considering sponsoring a SERP.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS (SERPs)

ARC Rebuttal Exhibit No. 4
For 42% of Respondents who offer a SERP, the primary purpose is to restore benefits
limited by legislation. And for 26%, the main reason IS to provide incentives for recruitment
and retention of key executives. Since 2001, there appears to be growing emphasis on the
use of SERPs as a recruitment and retention tool.
PRIMARY REASON FOR IMPLEMENTING A SERP
2001 2002 2003 2004 2005 2007 2009
Restore Benefits limited by Legislation
Provide Incentives for Recruitment/Retention
Provide Higher Level of Benefits
R Provide Targeted Retirement Compensation
Other
Base: Respondents sponsoring or considering sponsoring a SERP.
SERP BENEFIT FORMULAS
SERP benefit formulas vary substantially among Respondents, Many Respondents use some
percentage of final compensation to calculate benefits or a percentage of compensation plus
benefits.
d
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

I" -
ARC Rebuttal Exhibit No. 4
SERP BENEFIT OFFSETS
Some Respondents also offset (reduce) SERP benefits based on amounts received
from Social Security, qualified retirement plans and matching contributions to 401 (k)
and NQDC plans.
The top offsets for defined benefit SERPs are qualified plan benefits ather than 401(k)
match (83% of Respondents with defined benefit SERP) and Social Security income (58%).
For defined contribution SERPs, the top offsets are 401(k) company match (63% of
Respondents with defined contribution SERP) and qualified plan benefits other than 401 (k)
match (5Oo/o).
SERP OFFSETS (2009)
-
10%
Social Security 58%
j ~
63%
18%
. .._ .. ... .,._. . .. , ..,.. . ., ..,., ,. . . ., , . . . . . . . . .!
Company Match to Other 1, 3%
Nonqualified Plans I20%
Company Match to 401(k)
,-,"
jo/, 18%
Former Employer Qualified Plan
Income .- ._-
i 0%
Disability Payments 8%
Other b-13%
;o% I
I 1 I ! 1
0% 10.h 20% 30% 40% 50% 60% 70% 80% 90% 100%
Defined Contribution
Defined Benefit
Base: Respondents sponsoring or considering sponsoring a SERP with benefit offsets.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS (SERPs)

~
ARC Rebuttal Exhibit No. 4
SERP VESTING
94% of Respondents have imposed a vesting schedule on SERP distributions. The following
chart shows the prevalence of the types of vesting schedules used.
SERP VESTING SCHEDULES USED (2009)
Cliff Vesting at Retirement
Cliff Vesting at Specified
Agenears of Service
Graduated Vesting
30~0
I t
Same as Qualified Plan 32\
Years of Participation in Plan
Other 11%
k - . 1 8 -
0% 10% 20% 30% 40% 50% 60% 70% e
Base: Respondents imposing a vesting schedule on SERP distributions.
I
., . .
% 1r 1%
65Yo of Respondents imposing a SERP vesting schedule indicated that vesting was
accelerated by a change of control of the company Death (67%) and disability (59%) are the
other triggers considered for accelerated vesting.
SERP BENEFIT PAYMENT TRIGGERS
The following chart displays the prevalence of qualifying events among Respondents that
would trigger SERP payments to a participant or his or her beneficiary. 54% of Respondents
indicated that the plan allows for payment to a beneficiary other than the executive's spouse
(e,g., a trust) in the event of the executive's death.
1
TRIGGERS FOR PAYMENT OF SERP BENEFIT (2009)
" "
I
t
Normal Retirement
Early Retirement
Late Retirement
Death
Disability 2 ,
Change of Control
Termination
1 1
. ( a
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Base: Respondents sponsoring or considering sponsoring a SERP.
1
I
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

ARC Rebuttal Exhibit No. 4 1
i
PAYMENT OPTIONS
For Respondents with defined benefit SERPs, 85% indicate that the SERP benefit is
adjusted for early retirement. 47% indicate that the payment options under their SERP are
the same as under their qualified pension plan. The top payout options offered are single life
annuity (52%), joint and survivor annuity (50%) and lump sum (50°/o).
For Respondents with defined contribution SERPs, the vast majority (8la/o) offer the lump
sum payout option.
1 PAYMENT OPTIONS - DEFINED BENEFIT/DEFINED CONTRIBUTION (2009)
1
I 1
i
\
\,
\
\
Joint and Survivor Annuity
Single Life Annuity
I > ) I
-'p i ~
\ - "-
1 50%
< i--, '
52% I 1
I
I
I
I 1 1
2 !
Lump Sum 81% 1
"- " I
I
I
Term Certain Over Specific
i
I 1 I
t l l i :
J j ,
I !
Annual Installments ! I I
i
/ I :
Monthly Installments , I
i
I
0% 10% 20% 300h 40% 50% 60% 70% 80% 90% 100%
Defined Benefit
Defined Contribution
Base: Respondents sponsoring or considering sponsoring a SERP.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS (SERPs)

ARC Rebuttal Exhibit No. 4
INFORMAL SERP FUNDING
39% of 2009 Respondents are informally funding their SERP, the lowest level since 2001,
6% of Respondents are considering informal funding within the next 12 months.
INFORMAL SERP FUNDING
U
2001
2002 2003 2004 2005 2007 2009
Informally Funded Considering Unfunded/Unspecified
I
1
INFORMAL SERP FUNDING (2009)
._" I " ^ ^ - I-
I
i
Up to $2.5 Billion Above $2.5 Billion All Financial All Surveyed
in Annual Revenue in Annual Revenue Institutions Companies
73%
36% 43% 39%
111_
Base: Respondents sponsoring or considering sponsoring a SERP.
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

__I
ARC Rebuttal Exhibit No. 4
TYPES OF INFORMAL FUNDING VEHICLES
Of the 2009 Respondents that informally fund their SERP, 68% use COLI/TOLI, down
from 2007. This seems to mirror the trend observed in the informal fundtng of NODC plans;
however, COLVTOLi is still by far the most commonly used vehicle.
-
I
75%
7096
65%
60%
55%
50%
450
40%
35%
30a
25%
20/0
15%
10%
5%
0%
t i
.... ~ _.._....... ..........................
__-. ._...-. l.l
L-" .^ ^...... ... .....
....._-___ll-"l..."-l
..... .
I ^, . . "
I rn io
I
TYPES OF SERP FUNDING VEHICLES
It3 ................................................................................................
1 ..... . _ ........... ...... __ ......................
I _..__ ................ ..................
11 I
I COLI/ Corporate Mutual Managed Other
Bonds or
Company
Bond Funds Stock TO11 Assets Funds
Portfolio
2001 2002 2003 2004 2005 2007 R 2009
I
COLl/TOLI AS INFORMAL FUNDING VEHICLE FOR SERP (2009)
Up to $2.5 Billion Above $2.5 Billion All Financial All Surveyed
in Annual Revenue in Annual Revenue Institutions
Companies
71 Yo 63% 100% 68%
Base: Respondents informally funding or considering funding their SERP.
SUPPLEMENTAL EXECUTIVE RETI REM ENT PLANS (SERPs)

,.-l.".,l ..
ARC Rebuttal Exhibit No. 4
Of those Respondents that use COLVTOLI, 46@/0 use variable life insurance and 54% use
whole lifehniversal life insurance.
TYPES OF COLIITOLI
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
" /"
2001 2002 2003 2004 2005 2007
H Voriabie Life
W Whale life/Universal life
2009
Base: Respondents informally funding their SERP with COLI/TOLI.
RABBI TRUSTS AND ALTERNATIVES
75% of Respondents use some device to protect SERP participants, up 5% from 2007,
The most prevalent arrangement for the past several years and in 2009 is the Rabbi Trust,
which may provide protection in the event of a change of control or change of heart.
Comment: As in the case of NQDC plans, the overall increase in protective arrangements
since 2007 might reflect rising concerns among participants about an uncertain economy,
100%
95%
90%
85%
80%
75%
70%
65%
60%
55%
50%
45%
40%
35%
30%
25 %
20%
15%
10%
5%
0%
lll_._____."
........."._..__-
__" I..,._ "I ....... I.x ....
. "........ ................ "l_., ..... .................. ................... .- .................
_I_."___I__.__.____. I ." "." .... _I_.I___ . I_ ... ^.I__ ._.
______ _^I__
. .. ," ...................""....-..........-...I....... ......... "....... "...... ,l-"ll..
___._._I. . . ..._ ._.l.__l .-....-..I . _..- I -.11-
I.-_..
I
.. .................. .................. ... I .......^............ . ............. .- .................
. . _. . ... ...-I.
. ..... l",_ ................................ ...I................... I..I . .. ._.l_l_l .......... ...........
..I. ................................................
_.._.._.I ...... ^I.I I". .
2003 2004 2005 I2007 $3 2009
Base: Respondents using some device to protect SERP participants.
2009 RESULTS EXECUTIVE BENEFITS A Survey of CurrentTrends

ARC Rebuttal Exhibit No. 4
S E R P AD M I N I STRATI 0 N
As with NQDC plans, the percentage of Respondents exclusively administering their SERPs
in-house has decreased steadily - from 48% in 2001 to 32% in 2009. This has been
accompanied by corresponding' increases in the prevalence of third-party adniinistered and
combination (in-house and third-party) administered plans.
i
i
Comment: In particular, the drop in in-house administered plans from 2005 (44%) to 2009
(32%) may reflect a need for more sophisticated administration and greater capabilities in
light of the need to satisfy the requirements of Internal Revenue Code section 409A.
1
SER P ADMl N ISTRATION
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0 %
2001 2002 2003 2004 2005 2007 2009
InHouse Third-party tombination Other
* Of which 42010 are administered by the same provider as the 401 (k) plan and 58% are
administered by another provider.
Base: Respondents informally funding or considering funding their SERP.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS (SERF'S)

"
,/"
qKC Rebuttal Exhibit No. 4
/'
,/
//
/
i
Many companies continue to offer their executives supplemental
executive benefits. These benefits help employers to attract and
retain key executives and include:
Supplemental portable long-term disability (LTD)
policies and/or significantly higher individual
LTD coverages.
Supplemental life insurance, split dollar life
insurance.
Other perks and special benefits, such as
financial planning and tax preparation.

ARC Rebuttal Exhibit No. 4
SU PPLEM ENTAL LONG-TERM DI SABl LlTY BEN E FITS
40% of Respondents offer supplemental disability plans to executives, down from 81% in
2005 and 56% in 2007.
SUPPLEMENTAL LONG-TERM DISABILITY BENEFITS PREVALENCE
U%
2001 2002 2003 2004 2005 2007 2009
W Offered
W Not Offered
Base: Survey Respondents.
OTHER EXECUTIVE BENEFITS

ARC Rebuttal Exhibit No. 4
SU PPLE M ENTAL D I SAB I LlTY B E N E FITS FORM U LAS
Typically, either a percentage of salary or a percentage of total compensation is used
as the benefit formula to calculate supplemental disability benefits. 42% of Respondents
use a percentage of salary, while 37% use a percentage of total compensation (up from
30% in 2007), apparently indicating a greater shift toward using total compensation as the
basis since 2005.
S U P P L E M E N TA L D I SA B I LI TY BEN E F ITS FOR M U LAS
1 OOYO
90%
80a
70%
60%
50%
40%
30%
20%
10%
0%
2001 2002 2003 2004 2005 2007 2009
Pertentoge of Salary Percentage of Total Compensation Other
Base: Respondents sponsoring or considering sponsoring a supplemental long-term
disability plan.
For Respondents that base their formula on a percentage of salary, percentages ranged from
50% to 100%. For formulas based on a percentage of total compensation, percentages
ranged from 60% to 80%. Maximum monthly benefit ranged from $2,750 to unlimited.
58% of Respondents that provide supplemental disability benefits pay 100% of the
premiums (vs. 47% in 2007), the first time this percentage has risen since 2002.
I
PERCENTAGE OF PREMIUMS PAID BY COMPANY
I
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
2001 2002 2003 2004 2005 2007 2009
100% 50% 0% E Other
Base: Respondents Sponsoring or considering sponsoring a supplemental long-term
disability plan.
2009 RESULTS EXECUTIVE BENEFITS ASorveyof Current Trends

ARC Rebuttal Exhibit No. 4
EXECUTIVE PERQUISITES
97% of Respondents make at least one of the following perquisites available to their
executives.
Corporate Financial Planning
Financial Planning
Supplemental Life Insurance
CarlCar Allowance -
Split-Dollar Life Insurance
EXECUTIVE PERQUISITES (2009)
I
l l
I
I
4ox 1
I
I
91%
)
Tax Preparation
L
Cellular PhonePDA
' 1 ,
i
Long-Term Care Insurance
Country Club Membership
Company AirplanesHelicopters
LunchDining Club Membership
HealtWFitness Club Membership
Drivers or Chauffeurs
Annual Physical Exam
Other (Various)
Base: Survey Respondents.
0% 10% 20% 30% 40% 50%
60%
70% 80% 90% 100%
OTHER EXECUTIVE BENEFITS

,/"
,/"
,/+
ARC Rebuttal Exhibit No. 4
,/'
.i'
~ ~ ~ & Respondent ~ d Distribution ~ l ~ ~ y
\

ARC Rebuttal Exhibit No. 4
SU RVEY M ETH OD0 LOGY
The Survey is based on the 2009 Survey questionnaire, which was sent to fortune 1000
companies. Over 1 1 O/o of the fortune 7000 companies completed and returned their
questionnaires to Clark Consulting. The information contained in the returned questionnaires
was entered into a database by an outside database management firm and analyzed by Clark
Consulting's professional staff.
The 27-page questionnaire contained approximately 80 questions, each of which required a
respondent io provide multiple items of information about their nonqualified retirement and
welfare plans.
RESPONDENT DISTRIBUTION
Respondents are located throughout the country and represent a wide variety of industries.
The largest proportion of Respondents (36O/o) have their corparate offices in the South,
followed by the Midwest at 34%. The map below provides a pictorial breakdown of the
geographic locations of the Respondents.
REGIONAL BREAKDOWN (2009)
\
OTHER EXECUTIVE BENEFITS

ARC Rebuttal Exhibit No. 4
Respondents have been placed into 16 general industry categories. The largest
number of Respondents (25%) are in the manufacturing industry. A breakdown by industry is
shown below.
INDUSTRY BREAKDOWN (2009)
1 2%
..
4% 5%
11%
Retail
e Diversified Services
Tronsporlalion
Wholesale/Distribution
P Insurance
@ Technology
e Energy
Communication
J* Healthcare
0 Construdion/Reol Estate
0 Restaurants
BO,
Entertainment
Other
20Q9 RESULTS
EXECUTIVE BENEFITS A Survey of Current Trends

f'*
.,

ARC Rebuttal Exhibit No. 4
2009 SURVEY RESPONDENTS
Aaron’s, Inc.
Abercrombie & Fitch
Affiliated Computer Services, Inc.
Aleris International, Inc.
Alexander 8. Baldwin, Inc.
Allegheny Energy, Inc.
Allstate Insurance Company
American Electric Power Co., Inc.
Apria Healthcare Group, Inc.
Avery Dennison Corporation
Barnes & Noble, Inc.
Becton, Dickinson and Company
Big Lots Stores, Inc.
Black & Decker
Bob Evans Farms, Inc.
Carlisle Companies, Incorporated
Centene Corporation
CF Industries, Inc.
Chiquita Brands International, Inc.
CHS Inc.
CIGNA Corporation
Cisco Systems, Inc.
Collective Brands, Inc.
Consolidated Edison, Inc,
Cracker Barrel Old Country Store, Inc.
CSX Corporation
Danaher Corporation
Delta Airlines, Inc,
Duke Energy Corporation
Dynegy Inc,
The E,W. Scripps Company
El Paso Corporation
Emerson Electric Co.
Energy Future Holdings
Entergy Corporation
EOG Resources, Inc.
Equifax, Inc.
FirstEnergy Corporation
Fiserv, Inc.
FM Global
Gannett Company, Inc.
Genworth Financial, Inc.
Georgia Gulf Corporation
The Goodyear Tire & Rubber Company
Greif, Inc.
Halliburton Company
Hanesbrands Inc.
The Hartford Financial Services Group, Inc.
Hayes Lemmerz International, Inc.
Herman Miller, Inc.
Host Hotels & Resorts, Inc.
Humana, Inc.
lngram Micro Inc.
Jack in the Box Inc.
K. Hovnanian Companies
Kelly Services, Inc.
La-Z-Boy, Inc.
Lennox International, Inc.
Louisiana-Pacific Corporation
Marriott Internatjonal, Inc.
Massachusetts Mutual Life Insurance Company
Medical Mutual of Ohio
MetroPCS Communications, Inc.
Mirant Corporation
The Mosaic Company
Mueller Water Products, Inc,
Nalco Company
Nash Finch Company
I
I I
, .
SURVEY RESPONDENTS

ARC Rebuttal Exhibit No. 4
National Semiconductor Corporation
NCR Corporation
Nicor Inc.
The Northwestern Mutual Life Insurance
Company
Occidental Petroleum Corporation
Olin Corporation
O’Reilly Automotive, Inc.
Owens & Minor, Inc.
The Pantry, Inc
PC Connection, Inc.
The PNC Financial Services Group, Inc.
PNM Resources, Inc.
Progress Energy
Protective Life Corporation
Qualcomm Incorporated
Raytheon Company
Southwest Gas Corporation
Thrivent Financial for Lutherans
Toys “R Us, Inc.
Tupperware Brands Corporation
Tyson Foods, Inc.
Unified Grocers, Inc.
Union Pacific Railroad Company
United States Steel Corporation
The Valspar Corporation
Vectren Corporation
Visteon Corporation
Waste Management, Inc.
Wells’ Dairy, Inc.
The Western Union Company
Worthington Industries, Inc.
Did Not Provide Company Name (1 0)
The Ryland Group, Inc.
SAlC
Scripps Networks
Securian Financial Group, Inc-
Service Corporation International
Sonic Automotive, Inc.
2009 RESULTS EXECUTIVE BENEFITS A Survey of Current Trends

ARC Rebuttal Exhibit No. 4
Founded in 1967, Clark Consulting specializes in providing consulting
services for the design and administration of compensation and benefit
programs for executives, directors and employees. Based on long-term
relationships with the nation's top insurance carriers and fund companies,
we offer a full array of financial products that help companies manage
their benefit liabilities while enhancing shareholder value,
With offices nationwide, Clark Consulting provides the tools and
strategies to help attract, retain, motivate and reward the entrepreneurs,
managers and leaders who guide institutions toward exceptional
performance.
Q 2009 Clark Consulting
For additional copies, please contact Clark Consulting
www.clarkccsnsuiting.com/execbenefitssurvey
or download the Survey in PDF format from

CLARK
www,clarkconsulting.com
\

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
JEFFREY L. BRUBAKER

JLB Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
JEFFREY L. BRUBAKER
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q. PLEASE STATE YOUR NAME.
2 A. My name is Jeffrey L. Brubaker.
3 Q. ARE YOU THE SAME JEFFREY L. BRUBAKER WHO PRESENTED
4 DIRECT TESTIMONY IN THIS CASE
5 A. Yes.
6 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
7 A. I will rebut various recommendations and adjustments presented in the testimony
8 of Staff witness Sprinkle and Consumer Advocate Division (CAD) witnesses
9 Smith and White, as follows:
IO 1. Accumulated Depreciation - page 2
11 2. Amortization of Severance Costs - page 10
12 3. Payroll and Other Benefits - page 13
13 4. Storm Damages - page 14
14 5. Utility Plant Held for Future Use - page 15
15 I will also discuss, starting on page 16 of my rebuttal testimony, an
16 understatement in the Companies’ per books West Virginia jurisdictional CWIP
17 balance included in rate base which resulted in an understatement of the
18 Companies’ revenue requirement.

Page 2 of 18
1
2 Q*
3
4
5
6
7
8 A.
9
10
11
12
13
14 Q.
15
16
17 A.
18
19
20
21
22 Q.
23
ACCUMULATED DEPRECIATION
PLEASE RESPOND TO THE STAFF’S AND THE CAD’S REJECTION
OF THE COMPANIES’ $26,482,020 ACCUMULATED DEPRECIATION
ADJUSTMENT THAT RESTATES TOTAL COMPANY ACCUMULATED
DEPRECIATION FROM VALUES BASED ON COMPOSITE
DEPRECIATION RATES TO VALUES BASED ON THIS
COMMISSION’S APPROVED DEPRECIATION RATES.
The Staff and the CAD do not accept the Companies’ adjustments to accumulated
depreciation, apparently based upon their mistaken belief that the Companies
never implemented the annual depreciation rates approved in Case No. 05-1278-
E-PC-PW-42T and are now trying to retroactively adjust for this failure. The
Companies’ proposed adjustment is simply to reflect the proper allocation of
APCo’s total company accumulated depreciation to the WV Retail jurisdiction.
DID THE COMPANIES IMPLEMENT THE ANNUAL DEPRECIATION
RATES THAT WERE APPROVED BY THIS COMMISSION IN CASE
NO. 05-1278-E-PC-PW-42T
Yes. In the case of APCo, which is a multi-jurisdictional utility, it implemented
the approved annual depreciation rates effective July 1, 2006 for the WV portion
of its depreciable assets through the use of composite or weighted average
depreciation rates which reflect the current approved WV, VA, and FERC
depreciation rates.
IS THE COMMISSION ALREADY AWARE THAT APCO USES
COMPOSITE DEPRECIATION RATES

Page 3 of 18
1
2
3
4
5
6
7
A. Yes. The Final Order issued by the Commission on December 14, 1992 in Case
No. 91-1037-E-D ordered ''. . . that Appalachian Power Company be authorized to
use composite depreciation accrual rates for recording book depreciation expenses
for accounting purposes, as requested in TEM Exhibit No. 1, pages 2,4 and 5 and
that, concurrently therewith, Appalachian Power Company also maintain separate
and complete records with respect to the depreciation rates approved in each of its
retail jurisdictions."
8
9
Q.
WHAT WAS THE EFFECTIVE DATE OF THE DEPRECIATION RATES
APPROVED IN THE FINAL ORDER IN CASE NO. 91-1037-E-D
10
11
12
13
A. The depreciation rates authorized in the Final Order in Case No. 91-1037-E-D
were ordered to become effective on the first day of the month immediately
following the effective date of base rates approved in Appalachian Power
Company's next general rate proceeding.
14
15
Q.
WERE THERE ANY ORDERS SUBSEQUENT TO THE FINAL ORDER
IN CASE NO. 91-1037-E-D THAT CHANGED DEPRECIATION RATES
16
A. Yes, the Commission has issued two subsequent orders that changed APCo's
17
depreciation rates.
On March 29, 1994, the Commission found that it is
18
19
20
21
22
reasonable to conclude, and directed that, the depreciation rates set forth in the
recommended decision in Case No. 91 -1037-E-D become effective November 1,
1995. On July 26, 2006, in Case No. 05-1278-E-PC-PW-42T, the Commission
approved a Joint Stipulation and Agreement for Settlement that included revised
depreciation rates for APCo effective July 1, 2006. In each instance, APCo

Page 4 of 18
1
2
3 Q-
4
5 A.
6
modified its composite depreciation rates to reflect the rates approved by the
Commission.
WHY DOES APCO USE COMPOSITE OR WEIGHTED AVERAGE
DEPRECIATION RATES
Prior to 1993, APCo’s approved depreciation rates were the same in each of its
jurisdictions and thus there was no need to calculate a weighted average
7
composite depreciation rate.
Effective January 1, 1993, the VA SCC approved
8
9
10
11
12
13
14
15 Q.
16
17
18
19 A.
20
21 Q.
22
23
new depreciation rates for APCo that were different from those approved at that
time by APCo’s other regulatory commissions. At that time, APCo began using
weighted average or composite annual depreciation rates reflecting the different
rates in effect in its respective jurisdictions. As discussed above, this Commission
approved new depreciation rates effective November 1, 1995 and July 1, 2006
that also changed the composite annual depreciation rates based upon the different
annual depreciation rates in each of APCo’s jurisdictions.
DOES APCO’S ACCUMULATED DEPRECIATION RECORDED ON ITS
BOOKS AS OF DECEMBER 31,2008 (THE BEGINNING OF THE TEST
YEAR) REFLECT ONLY WEST VIRGINIA APPROVED ANNUAL
DEPRECIATION RATES
No. APCo’s accumulated depreciation reflects a composite or blend of the annual
depreciation rates approved by this Commission, the VA SCC, and the FERC.
GIVEN THAT APCO’S ACCUMULATED DEPRECIATION BALANCE
AS OF DECEMBER 31, 2008 IS BASED UPON A COMPOSITE OF
ANNUAL DEPRECIATION RATES APPROVED BY THE VARIOUS

Page 5 of 18
1 COMMISSIONS, IS IT NECESSARY TO MAKE AN ADJUSTMENT TO
2 THE TOTAL COMPANY BALANCES OF ACCUMULATED
3 DEPRECIATION RECORDED ON THE BOOKS AS OF DECEMBER 31,
4 2008
5 A. No. The total company accumulated depreciation balances on the books are
6 correct. APCo is not proposing to change the total company accumulated
7 depreciation balances on the books, but is simply recognizing the amount of
8 accumulated depreciation properly allocated to the WV jurisdiction per this
9 Commission’s orders.
10 Q. WHY IS IT APPROPRIATE TO MAKE AN ADJUSTMENT TO
11 ACCUMULATED DEPRECIATION FOR THE WV RETAIL
12 JURISDICTION
13 A. As previously discussed, annual depreciation expense, and thus accumulated
14 depreciation, are calculated using weighted average or composite rates. The per
15 books conventional cost of service allocation of accumulated depreciation to the
16 WV retail jurisdiction does not recognize the different depreciation rates in effect
17 for the various jurisdictions beginning in 1993 and simply allocates a WV share
18 of the total company accumulated depreciation using a current allocation factor.
19
20
1
In order to properly determine the WV accumulated depreciation balance, it is
necessary to recalculate the total company accumulated depreciation balance
21 using only depreciation rates approved by this Commission before applying the
22 current allocation factor.

Page 6 of 18
1 Q*
2
3
DID APCO MAKE AN ADJUSTMENT IN THIS CASE TO THE WV
RETAIL JURISDICTIONAL ALLOCATED ACCUMULATED
DEPRECIATION
4 A.
Yes.
APCo recalculated the WV retail jurisdictional allocated accumulated
5
6
7
8
9
10
11 Q.
12
13
14 A.
15
16
17
18 Q.
19
20
21 A.
22
23
depreciation for the period January 1, 1993 through December 31, 2008 to
recognize the difference in depreciation between using composite rates and using
only the rates approved by this Commission. Since APCo’s annual depreciation
rates approved by this Commission were generally lower than the composite rates,
the result is a decrease in the WV Retail jurisdictional accumulated depreciation,
which increases the WV Retail jurisdictional total rate base.
IS THIS THE FIRST TIME THAT APCO HAS PROPOSED AN
ADJUSTMENT TO THE WV RETAIL JURISDICTIONAL ALLOCATED
ACCUMULATED DEPRECIATION
No. This is not a new adjustment proposed for the first time in this case. APCo
has made similar adjustments in previous cases filed with this Commission
subsequent to Case No. 91-1037-E-D to reflect the proper allocation of total
company accumulated depreciation to the WV Retail jurisdiction.
DOES APCO MAKE A COMPARABLE ADJUSTMENT TO VA RETAIL
JURISDICTIONAL ALLOCATED ACCUMULATED DEPRECIATION
WHEN FILING WITH THE VA SCC
Yes, APCo makes a comparable adjustment when it files with the VA SCC.
However, APCo’s annual depreciation rates approved by the VA SCC were
generally higher than the composite depreciation rates, which results in an

Page 7 of 18
1
2
3 Q*
4
5
6
7
8 A.
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adjustment to increase the VA Retail jurisdictional accumulated depreciation,
thereby reducing rate base.
WHAT IS THE RESULT OF THE STAFF’S AND CAD’S
RECOMMENDED ELIMINATION OF THE COMPANIES’ PROPOSED
ADJUSTMENT TO ACCUMULATED DEPRECIATION TO RESTATE
APCO’S TOTAL COMPANY VALUES TO THE JURISDICTIONAL
VALUES
Eliminating the proposed adjustment to accumulated depreciation results in a
mismatch between the WV jurisdictional depreciation expense reflected in rates
and the WV jurisdictional accumulated depreciation balance. Without making
this adjustment to accumulated depreciation, the WV jurisdictional depreciation
expense has reflected, and will continue to reflect, the lower depreciation rates
approved by this Commission while the accumulated depreciation gives WV
jurisdictional customers the benefit of higher depreciation expense reflected in
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rates charged to non-WV jurisdictional customers.
This higher depreciation
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expense is not reflected in the WV cost of service and therefore it should not be
included in the accumulated depreciation balance.
CAN YOU GIVE A SIMPLE EXAMPLE TO ILLUSTRATE THE
ADJUSTMENT TO RECOGNIZE THE DIFFERENT ANNUAL
DEPRECIATION RATES
21 A.
Yes.
Below is a hypothetical example to illustrate the differences between
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jurisdictions, while at the same time showing that the difference between
jurisdictions nets to zero on a total company basis.

Page 8 of 18
Jurisdiction Annual Dep Rate Allocation Factor Composite Dep Rate
WV 2.00% 0.43 0.860%
All others 2.50% 0.57 1.425%
Total 2.285%
Assuming you have a $1 million depreciable asset balance and using the
depreciation rate fiom the above example, the utility would record annual
depreciation expense of $22,850 ($1 million times 2.285%) and credit
accumulated deprecation for $22,850. For cost of service purposes, $9,825 (43%
of $22,850) of accumulated depreciation would initially be allocated to the WV
jurisdiction.
However, the proper amount of accumulated depreciation that
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should be assigned to the WV jurisdiction is $8,600 ($1 million times 2% annual
WV depreciation rate times the WV allocation factor of 0.43). Thus, in this
hypothetical example, the WV jurisdiction allocated per books cost of service
accumulated depreciation is overstated by $1,225 ($9,825 less $8,600) because
the total company accumulated depreciation is based upon the higher composite
annual depreciation rate. Therefore, the WV retail allocated per book share of
accumulated depreciation is too high and must be reduced (which increases rate
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base) by $1,225.
Conversely, the other jurisdictions’ allocated share of
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accumulated depreciation is too low and must be increased.
DOES THE COMPANIES’ ADJUSTMENT TO WV RETAIL
JURISDICTIONAL ALLOCATED ACCUMULATED DEPRECIATION
CONSTITUTE RETROACTIVE RATEMAKING
Absolutely not. The Staff and the CAD imply that APCo did not implement the
rates approved by the PSC of WV effective July 1, 2006. They also indicate that

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they believe this adjustment is an attempt to implement these rates after the fact.
Both of these assumptions are incorrect. APCo has implemented the depreciation
rates approved by this Commission, through the composite depreciation rates
effective November 1, 1995 and July 1, 2006. The adjustment proposed by the
Companies is needed to properly state the WV share of accumulated depreciation
in accordance with the past Commission decision which mandated jurisdictional
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depreciation records.
APCo has maintained WV jurisdictional depreciation
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records as ordered and the proposed adjustment simply reflects the correct
allocation of the total company accumulated depreciation to the WV retail
jurisdiction from those jurisdictional records. This adjustment does not constitute
retroactive ratemaking.
PLEASE SUMMARIZE YOUR REBUTTAL TESTIMONY ON THE USE
OF THE COMMISSION APPROVED DEPRECIATION RATES.
As ordered by this Commission, APCo has consistently maintained records to
track the effect of the difference in the WV approved depreciation rates and the
composite depreciation rates used on its books since January 1, 1993 and has
reflected from its records the appropriate values at the going-level in this filing.
Disallowing these adjustments would erroneously reflect composite depreciation
in the accumulated provision for depreciation balance included in rate base rather
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than the WV-approved depreciation.
This would erroneously remove more
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depreciation expense from rate base than this Commission actually approved and
included in APCo’s rates, and, consequently, would understate APCo’s WV rate
base and its return.

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AMORTIZATION OF SEVERANCE COSTS
DO YOU AGREE WITH THE CAD’S PROPOSED ADJUSTMENT TO
AMORTIZE SEVERANCE COSTS OVER FOUR YEARS
I agree that a four-year amortization of severance costs is reasonable, but I do not
agree with the amount of severance costs calculated by the CAD to be amortized
over four years.
WHAT IS THE BASIS OF YOUR DISAGREEMENT
First, the CAD failed to include the total severance costs that the Companies
provided in a data response and which the CAD referenced in its workpapers.
Secondly, the CAD incorrectly allocated a portion of the severance costs to non-
O&M accounts, thereby understating the amount to be amortized.
PLEASE ELABORATE ON THOSE ERRORS IN THE CAD’S
CALCULATIONS.
CAD witness White’s Exhibit DLW-3 includes the following amounts for
severance and FICA for APCo and WPCo employees as the basis for the CAD’S
proposed adjustment:
APCo WPCO Total
Severance $3 1,512,624 $666,766 $32,179,390
FICA 1,812,882 39,804 1,852,686
Total $33,325,506 $706,570 $34,032,076
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The exhibit also indicates that the source of the data was from the Companies’
response to CAD data request E-149. The Companies’ response to CAD data
request E-149 segregates the total severance costs between voluntary and

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involuntary severances. The CAD only included the voluntary severance and
related FICA amounts but did not include the involuntary severance and FICA
amounts.
DO YOU AGREE WITH CAD WITNESS WHITE’S EXCLUSION OF
INVOLUNTARY SEVERANCE EXPENSE
No. The involuntary severance expenses were an integral part of the overall
severance program and should not be treated any differently than the voluntary
severance expenses. The involuntary severance expenses also contributed to the
payroll savings discussed in CAD witness White’s testimony.
WHAT AMOUNT OF INVOLUNTARY SEVERANCE EXPENSE WAS
EXCLUDED FROM CAD WITNESS WHITE’S PROPOSED SEVERANCE
AMORTIZATION
APCo had $1,191,294 in involuntary severance expense and $57,951 in related
FICA expense, for a total of $1,249,245 related to involuntary severance
expenses. WPCo did not have any involuntary severance expense.
IS IT APPROPRIATE, AS CAD WITNESS WHITE SUGGESTS, TO
ALLOCATE A PORTION OF THE SEVERANCE COSTS TO CAPITAL
No, All severance costs were expensed by the Companies and therefore it is
inappropriate for the CAD to allocate a portion of the severance costs to capital.
WHY DID THE COMPANIES EXPENSE ALL SEVERANCE COSTS
The Companies expensed all severance costs in compliance with Statement of
Financial Accounting Standards (SFAS) No. 88 “Employers’ Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for

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Termination Benefits” (now known as Financial Accounting Standards Board’s
Accounting Standards Codification (FASB ASC) 712-10). SFAS No. 88 requires
that, when an employer offers special termination benefits to employees (which
include lump-sum payments), it must recognize a loss when it is probable that
employees will be entitled to benefits and the amount can be reasonably
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estimated.
capitalized.
Thus, SFAS No. 88 does not allow termination benefits to be
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DO YOU AGREE WITH THE CAD’S DEDUCTION FOR SEVERANCE
OF $337,671 RELATED TO THE AMOUNTS RECORDED IN THE TEST
YEAR
No. Although I accept the total company severance costs recorded in the test year
of $337,671, the CAD did not jurisdictionalize this amount in its proposed
adjustment. I therefore cannot agree with the amount of the CAD’S adjustment.
WHAT IS THE APPROPRIATE AMOUNT OF SEVERANCE COSTS
THAT SHOULD BE AMORTIZED OVER FOUR YEARS
The appropriate amount of severance costs related to APCo and WPCo employees
to be amortized over four years is $15,580,390 on a WV jurisdictional basis. This
amount includes both voluntary and involuntary severance amounts, recognizes
that 100% of the severance costs were expensed, and allocates a portion of the test
year severance expense to the WV jurisdiction as shown below:
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Page 13 of 18
APCo WPCO Total
Voluntary severance
Involuntary severance
Voluntary FICA
Involuntary FICA
Total severance
Less test year severance
Net severance
WV allocation factor
WV Retail severance
$3 1,5 12,624 $666,766 $32,179,390
1,191,294 0 1,19 1,294
1,812,882 39,804 1,852,686
57.95 1 - 0 57.95 1
34,574,751 706,570 35,281,321
337,671 - 0 337.671
$34,237,080 $706,570 $34,943,650
0.434436 - 1 .o
$14.873.820 $706.57Q $15.580.390
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Q.
WHAT WOULD BE THE ANNUAL AMORTIZATION OF $15,580,390
OVER A FOUR YEAR PERIOD
The annual amortization of the $15,580,390 over four years is $3,895,097.
PAYROLL AND OTHER BENEFITS
DO YOU AGREE WITH THE CAD’S AND THE STAFF’S PROPOSED
ADJUSTMENTS TO REDUCE APCO’S AND WPCO’S LABOR EXPENSE
AND EMPLOYEE BENEFITS TO RECOGNIZE THE COMPANIES’
WORKFORCE REDUCTIONS
9
A.
Generally yes.
Both the CAD and the Staff proposed to reduce the WV
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jurisdictional labor, employee savings plan expenses, and related FICA and
Medicare taxes as a result of the reduction in APCo and WPCo employees since
the end of the test year. The CAD and the Staff also proposed adjustments to
reduce the WV jurisdictional group insurances (medical, dental, life, and long-

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term disability) related to the reduction in APCo and WPCo employees. I agree
with these proposed adjustments only to the extent that the Companies are also
permitted to recover in rates the proper amount of related severance costs that I
discussed previously in my rebuttal testimony.
DO YOU AGREE WITH THE STAFF’S PROPOSED ADJUSTMENT TO
REDUCE LABOR BILLINGS FROM AEP AFFILIATES DUE TO
WORKFORCE REDUCTIONS
No. The Staff proposed an additional adjustment to reduce the labor billings from
AEP affiliates (primarily AEPSC) to APCo and WPCo. I cannot agree with this
adjustment because the Staff did not propose to allow the Companies to recover
their WV jurisdictional share of the related severance costs billed from AEPSC of
approximately $9.4 million, which amortized over four years is approximately
$2.35 million per year.
STORM DAMAGES
DO YOU HAVE ANY COMMENTS RELATED TO THE STAFF’S
PROPOSED ADJUSTMENTS RELATED TO STORM DAMAGES
Yes. In addition to the comments in the rebuttal testimony of Company witness
Ferguson related to Staffs recommended denial of APCo’s proposal to earn a
return on its rate base for the average deferred storm damage expenses, I would
like to make the following clarification about capitalization and O&M. In the
Staffs argument to deny APCo’s proposal to earn a return on its rate base for the
average deferred storm expenses, Staff implied that APCo could have decided to
capitalize a large portion of these costs. Staff is apparently unaware that APCo

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capitalized approximately $9.6 million of incremental storm costs in the test year
related to the December 18,2009 storm in addition to the $22.8 million of
incremental O&M expenses recorded in the test year for the same storm. APCo
does not have the option to “decide” what amount of storm damages are
capitalized versus expensed. The amounts of storm damages capitalized or
expensed must be based upon the nature of the work performed,
DO YOU HAVE ANY UPDATES TO THE AMOUNT OF STORM
DAMAGES REQUESTED TO BE RECOVERED IN THIS PROCEEDING
Yes. The incremental O&M storm damages of $22.8 million recorded in the test
year and requested to be recovered in this proceeding relate to a storm that
occurred on December 18,2009 and included some estimates of costs. Based
upon the invoices received through September 30,2010, the actual amount of
incremental O&M storm damages related to the December 18,2009 storm is
$1 8,282,658. Therefore, APCo’s proposed adjustment to recover and amortize
the incremental storm damage expenses over five years should be revised to
$3,656,532 ($18,282,658 / 5 years) instead of the $4,566,501 included in the
17 Companies’ original filing.
18 UTILITY PLANT HELD FOR FUTURE USE
19 Q. DO YOU AGREE WITH THE CAD’S ADJUSTMENT TO REMOVE
20 $1,868,248 OF UTILITY PLANT HELD FOR FUTURE USE FROM RATE
21 BASE
22 A. No. The CAD proposes to remove from rate base $1,868,248 of Utility Plant
23 Held for Future Use recorded in FERC Account 105 because the CAD claims that

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the majority of the property in this account is not serving customers and will not
serve them in the foreseeable future. First of all, it is incorrect to remove any
amounts in FERC Account 105 from rate base on the basis that the property is not
currently serving customers. If the property were currently serving customers, by
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definition it would not be recorded in FERC Account 105.
To wait until
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construction is imminent before acquiring property could result in the needed
property being obtainable only at a much higher cost. Secondly, in response to
the CAD’S discovery request B-41, the Companies provided additional
information related to the property included in Account 105, including the plans
for properties owned by APCo. The assets recorded in Utility Plant Held for
Future Use were purchased prudently with the vision and forethought that they
would be used for such purposes as future station sites and rights-of-way.
Utilities that are discouraged by rate base disallowance from prudently acquiring
property for future use will likely find themselves having to pursue expensive and
time consuming legal procedures to acquire the needed property and/or having to
pay much higher purchase prices when these sites must be acquired in the future.
The amount of the Companies’ investment in future project sites is modest and
should be allowed by the Commission.
CWIP BALANCES
DO YOU HAVE ANY COMMENTS CONCERNING THE COMPANIES’
ENVIRONMENTAL CWIP BALANCE IN RATE BASE
Yes. I will discuss an error in the balance of CWIP in APCo’s rate base.
PLEASE DESCRIBE THIS ERROR.

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There is an understatement in APCo’s CWIP balance in rate base because some
projects related to the installation of pollution control equipment at APCo’s Amos
Units 1 & 2 were not coded as environmental work orders, although they should
have been. The CWIP balance in rate base was developed through a query of
work orders identified as environmental in APCo’s property accounting system.
Thus the projects not coded as environmental were not included in the CWIP
balance included in APCo’s rate base.
HOW WAS THIS ERROR DISCOVERED
In the Rule 42 filing, Company witness Fawcett made a going-level adjustment to
reduce the balance of environmental CWIP by the value of the work orders for
projects at Amos Unit 1&2 that are being recovered through a separate
construction surcharge. During the recent Staff audit, the Staff made several
inquiries related to CWIP. One of these was to confirm that the work orders used
by Mr, Fawcett as the basis of his construction surcharge adjustment had in fact
been included in CWIP balances used in the jurisdictional cost of service. In
comparing the work orders included in environmental CWIP and in Mr. Fawcett’s
adjustment, the Companies discovered that some of the work orders included in
the adjustment had not been included in the CWIP balance in rate base because of
the previously mentioned coding error.
WHAT IS THE IMPACT OF THIS UNDERSTATEMENT
The West Virginia jurisdictional rate base is understated by $53.8 million and the
related revenue requirement is understated by approximately $6.2 million as
shown on JLB Rebuttal Exhibit No. 2.

Page 18 of 18
1 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
2 A. Yes.

JLB Rebuttal Exhibit No. 2
Y/Us from Construction Surcharae Adlustment
W/O Balance In
Surcharge
bdlustment
W/O Balance In
Environmental
cwlp
Difference
mated AFUDC
40817441 AM12 AFUDC REVERSAL
Xi 16981 0 AMOS 1 & 2-FDG-ET & ES
Xi 169820 AMOS 1 & 2-FDG-BS
Xi 170340 AMOS 1 & 2-FGD-ET & ES
Xi 170341 AMOS 1 & 2-FGD-BS
XI 170342 AMOS 1 & 2-FGD-F & H
X1 170343 AMOS 1 & 2-FGD-OUTSIDE SERVICE
Xi 170344 AMOS 1 & 2-FGD-NE
Xi 171900 1171 90 AM 1 &2 BALANCED DRAFT C
X1171910 AM 1842 BOILER MODIFICATIONS
Xi 171 920 11 71 92 AM I &2 CONTROLS MODERN1
Xi 171 930 11 71 93 AM 1 &2 SO3 MITIGATION S
Xi 1771 10 AM2 NOSE Pre-outage Boiler Mod
(1,116,530)
26,237,734
2,198,361
1,487,183
137,001,700
159,292,201
70,431,461
32,437,870
6,292,359
16,126,234
8,493
26,237,734
2,198,361
1,487,183
137,001,700
159,292,201
8,493
(1,116,530) (1 ,I 16,530)
26,237,734
2,198,361
(26,237,734)
(2,198,361)
70,431,461 1,559,069
32,437,870 501,033
6,292,359 100,400
16,126,234 627,737
69
Total
1,671,778
Total CWlP Understatement
$ 124,171,395
Case Demand Allocator 42.79910% 47.5096% Note 1
Addition CWlP Alllocated to WV $ 53,144,240 794,255
81.5370% Note 2
Related AFUDC 647,612
Total WV Ratebase Understatement $ 53,791,051
Tax Effected Return on Ratebase 11.5797%
Incremental Revenue Requirement $ 6,-
Jax Effected Return on Ratebase
Interest Return
Equity Return
Total After Tax/ Before Tax Return
After Tax Rate Conversion Factor Before-Tax Rate
3.2610% 1 .ooooo 3.2610%
5.0220% 1.65645 8.3187%
8.2830% 11.5797%
.w
The sum of the demand allocators for VA. The AFUDC Included in the company total was partially allocated to VA. This amount
is then properly reallocated to WV.
w
The WV portion of the AFUDC Demand Reallocator which represents the WV portion of the non-VA jurisdictions on APCo's Statement E.

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REB-UTTAL TESTIMONY
OF
MARK A. PYLE
J

MAP Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
MARK A. PYLE
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
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PLEASE STATE YOUR NAME.
My name is Mark A. Pyle.
ARE YOU THE SAME MARK A. PYLE WHO FILED DIRECT TESTIMONY
IN THIS CASE
Yes.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
The purpose of my testimony is to rebut the testimony of Staff witnesses Edwin L.
Oxley and Thomas D. Sprinkle and Consumer Advocate Division (CAD) witness
Ralph C. Smith regarding consolidated tax savings, effective tax rate used in cost of
service computation, and accumulated deferred federal income tax on prepaid pension
adjustments. Company witness Robert W. Hriszko, an outside expert on technical tax
matters and tax matters arising in the ratemaking process, will also provide rebuttal
testimony on why consolidated tax savings adjustments should not be made in the
determination of utility cost of service and the appropriate deferred income tax
treatment for APCo’s change in tax accounting method. In addition, I will explain the
tax accounting timetable related to West Virginia property taxes that supports
testimony by Company witness Jay Joyce.
IS IT APPROPRIATE TO INCLUDE AN EXPANDED CONSOLIDATED
INCOME TAX SAVINGS ADJUSTMENT IN THIS PROCEEDING
No. As I explained in my direct testimony, the appropriate method of determining
{R0543949.1}

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income tax expense is to apply the same approach the Commission used in APCo’s
last fully litigated base rate case in 1991, recognizing that “losses of other companies
besides the parent company should not be included in the consolidated tax saving.”
Reaching beyond the application of the parent company loss adjustment is nothing but
a mechanism to indirectly reduce the authorized rate of return to shareholders.
DO YOU AGREE WITH MR. SPRINKLE’S OR MR. SMITH’S FEDERAL
INCOME TAX (“FIT”) COMPUTATION USED IN COMPUTING COST OF
SERVICE
No. Mr. Sprinkle employs an expanded consolidated tax savings (“CTS”)
methodology to arrive at an effective tax rate of 16.82%. The rate was developed by
Mr. Oxley in his Exhibit ELO-1. Mr. Smith, in his Exhibit LA-1, Schedule C-24,
page 1 of 1, computed a tax rate of 26.99%. As I indicated in my direct testimony, at
page 13, utilization of the expanded CTS methodology is not appropriate in this case.
The 35% statutory rate is the tax that APCo and WPCo will owe on a separate
company basis and is the appropriate rate to use in this computation.
IF THE COMMISSION ADOPTS THE STAFF’S AND THE CAD’S CTS FIT
RATE METHODOLOGY, WHAT FIT RATE WOULD YOU USE
If the Commission accepts the Staff and the CAD methodology, I recommend using a
rate of 26.03%, as shown in MAP Rebuttal Exhibit No. 2. The 16.82% rate proposed
by the Staff significantly underestimates the tax rate that will be applicable when rates
are expected to go into effect. Mr. Smith shows a slightly higher 26.99% rate because
(R0543949.1)

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he uses the five year average from 2004 through 2008, which would also be an
acceptable rate to use.
WHY DO YOU DISAGREE WITH MR. OXLEY’S FEDERAL INCOME TAX
RATE COMPUTATION
Mr. Oxley developed a five year average of the effective tax rates from the period
2005-2009 to arrive at his rate of 16.82%. The effective tax rate in this instance is a
percentage derived by dividing the net tax paid by the consolidated group by the
aggregate taxable income of companies with taxable income. Even if the Commission
adopts the five-year average approach advocated by Mr. Oxley, it should not adopt his
computation of the effective tax rate at 16.82%. That rate is artificially low; the
computation of the 2009 consolidated taxable income used in his analysis is not
appropriate without adjustments for significant one-time transactions that will not
repeat in the future.
WHAT IS MR. OXLEY’S EFFECTIVE FIT RATE COMPUTATION
INTENDED TO REPRESENT
It is my understanding that Mr. Oxley’s computation is intended to develop an
effective FIT rate that is based on historical rates; to take into consideration
consolidated tax savings from all taxable loss subsidiaries; and to be representative of
an applicable effective FIT rate when the new base rates to be set by the Commission
go into effect.
{ R0543949.1}

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WHAT’S WRONG WITH MR. OXLEY’S COMPUTATION
In order for the effective FIT rate to appropriately represent historic and future FIT
rates, taxable income should be adjusted for significant one-time adjustments
impacting consolidated taxable income. For example, in my direct testimony, I made
an adjustment to the 2004 consolidated taxable income related to a significant tax loss
that AEP incurred involving the disposition of a generation facility in the United
Kingdom. The CAD accepted this adjustment in the development of their effective
FIT rate. In 2009, the change in tax accounting method adopted by APCo related to
units of generation property resulted in a similar significant consolidated tax
deduction that will not be repeated when new rates are expected to go into effect.
During Staffs audit, the Companies identified for the Staff the one-time deduction of
$1.18 billion in the 2009 AEP consolidated income tax return. This one-time
adjustment was the primary driver of the negative 27.77% effective FIT rate for 2009
in Mr. Oxley’s Exhibit ELO-1. The unadjusted 2009 effective FIT rate is not
indicative of prior operating results nor does it produce a result reflective of what can
be expected when the new base rates set in this proceeding go into effect.
HOW WOULD YOU CORRECT MR. OXLEY’S EFFECTIVE FIT RATE
COMPUTATION
As shown in MAP Rebuttal Exhibit No. 2, I adjusted the 2009 taxable income to
remove the $1.18 billion, one-time effect of the change in tax accounting method. In
addition, I corrected Mr. Oxley’s numbers by adjusting taxable income for accelerated
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depreciation for all companies, not just the operating companies, and recomputed the
2005 through 2009 average effective FIT rate, which proved to be 26.03%.
ARE THERE OTHER REASONS WHY YOU ADJUSTED THE 2009
CONSOLIDATED FIT COMPUTATION FOR THE ONE-TIME CHANGE IN
ACCOUNTING METHOD
Yes. The Accumulated Deferred FIT (“ADFIT”) liability related to the one-time
change in accounting method was included as a reduction in rate base. It would be
irrational to include such a significant item in the 2009 computation of the effective
FIT rate for computing cost of service when the impact fi-om that one year alone,
compared with the other four years in the average computation, drives the average to
an unreasonable low percentage. The fact that the ADFIT related to this one-time tax
deduction (calculated using the statutory income tax rate of 35%) was included as a
significant reduction to rate base as well as used by the Staff to reduce the effective
income tax rate has a double negative impact on the Company.
DOES THE RECOMMENDED CHANGE IN MR. OXLEY’S EFFECTIVE FIT
RATE COMPUTATION IMPACT THE GROSS REVENUE CONVERSION
FACTOR
Yes. For consistency, the federal statutory 35% income tax rate should be used in the
gross revenue conversion factor. However, if the Commission adopts the Staffs CTS
methodology, the gross revenue conversion factor shown on Mr. Sprinkle’s Exhibit
TDS-1 , Schedule 1 , page 2 of 2, should at least be adjusted to reflect the increase in
the effective FIT rate from 16.82% to 26.03%.
(R0543949.1)

Page 6 of 9
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DID THE STAFF AND CAD MAKE AN ADJUSTMENT RELATED TO THE
PREPAID PENSION ASSET INCLUDED IN THE COMPANIES’ RATE
BASE
Yes. Company witness McCoy is rebutting the Staffs proposed removal of the
prepaid pension asset from rate base.
ARE THERE ACCUMULATED DEFERRED FEDERAL INCOME TAXES
(“ADFIT”) RELATED TO THE PREPAID PENSION ASSET
Yes. There is combined ADFIT liability of $22,815,538 related to the combined
$65,187,25 1 prepaid pension asset included in rate base in the Companies’ filing.
WAS THE ADFIT RELATED TO THE PREPAID PENSION ADJUSTMENT
PROPOSED BY THE STAFF AND THE CAD REMOVED FROM THE RATE
BASE DETERMINATION
No. Neither the Staff nor the CAD removed the ADFIT related to the proposed
prepaid pension rate base reduction.
WAS ANY REASON PROVIDED BY THE STAFF OR THE CAD FOR
CONTINUING TO REDUCE RATE BASE FOR THE ADFIT RELATED TO
PREPAID PENSIONS
The Staff offered no explanation at all. CAD witness Smith cited a November 25,
2009 Commission Order, Case No. 08-1783G-42T (Hope Gas) in which the
Commission rejected Hope’s request to remove the ADFIT associated with pensions.
From the tone of Mr. Smith’s testimony, he seemed perplexed by the Commission’s
order when he stated, “Normally, I would recommend that ADFIT rate base treatment
{R0543949.1}

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21
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24
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Q.
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Q*
A.
follow the rate base treatment of the related asset (or liability).” As explained by
Company witness McCoy, the facts in the Hope Gas case are very different from the
facts in the instant case.
ON WHAT BASIS DID THE COMMISSION REJECT REMOVAL OF THE
PREPAID PENSION RELATED ADFIT FROM RATE BASE IN THE HOPE
GAS CASE
The Commission seemed to focus its discussion around Hope’s assertion that the
ADFIT would not exist if the pension expenses were on a cash basis. It stated in its
order:
We agree that there would not be a future accumulation of
deferred income taxes once there is a cash basis for pension
expenses as we are adopting this Order. However, Hope would
have us disregard ADITs that have accumulated in the past. This
would be the equivalent of saying that if we would stop allowing
depreciation expense on fully depreciated property, the
accumulated depreciation reserves would disappear and should no
longer be used as a rate base reduction. The Commission will not
adopt Hope’s proposed rate base adjustment to eliminate pension
ADITs.
IS THAT ANALYSIS APPLICABLE TO THE COMPANIES’
CIRCUMSTANCES
No. Again, as explained by Company witness McCoy, the facts in this case are very
different from those in the Hope Gas case. APCo and WPCo each have an asset on
their books for prepaid pensions, in the amounts of $58,443,093 and $6,744,158,
respectively. The Companies requested that these assets be included in rate base in
order for the Companies to earn a return on that investment for their employees. The
Companies claimed a tax deduction when the amounts were paid, whereas in the
(R0543949.1)

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fbture the prepayment will be expensed for accounting purposes. The difference in
timing of the deduction between tax and accounting gives rise to the ADFIT liability.
The Companies included that ADFIT liability as an offset to rate base to give effect to
the tax benefit already received on the prepayment. The Companies asked for a net
rate base asset of $42,371,713. The Staff and CAD are proposing to remove the
$65,187,25 1 prepaid pension assets from rate base but not to remove the related
ADFIT. As explained above, there is a direct link between the pension asset and the
related ADFIT that should not be broken. If the Commission elects to exclude the
prepaid pension asset from rate base, it is only consistent and appropriate that the
related ADFIT also be removed as a rate base reduction.
CAN YOU EXPLAIN THE PROCESS TIMETABLE IN WHICH WEST
VIRGINIA ASSESSES AND COLLECTS PROPERTY TAXES FOR A
PUBLIC UTILITY COMPANY
Yes For ease of explaining the timetable, I will use December 31,2009 as the starting
point. The assessment date for public service company property in this instance
would be December 31,2009, according to $ 11-6-1 (e) of the West Virginia Code.
The utility files its property tax return in May, 2010 to list its property holdings as of
December 31,2009. The tax lien would then attach on December 31,2010, the year
following the assessment, according to $1 1-6-23(b) of the West Virginia Code, after
the property tax valuations have been determined. The actual property tax liability is
not known until the property tax rates are determined and the bills are received, in
July 2011. The property tax payments are made in two installments; the first being in
{R0543949.1]

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19
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21 A.
August, 2011 and the second being made in February, 2012 in order to meet the due
dates of September 1,2011 and March 1,2012, respectively.
WHAT IS THE COMPANIES TAX ACCOUNTING FOR WEST VIRGINIA
PROPERTY TAXES
Continuing with the example dates above, the Companies would not record any
entries on its ledgers until December 31 , 2010 when the lien attaches. At that time, a
deferred tax asset is debited and accrued tax payable is credited for the amount of the
estimated tax. These accounts are adjusted as the valuations and tax rates become
known. The deferred tax asset is amortized ratably to book expense from July 2011
through June 2012. The accrued taxes payable account is debited when the cash
payments are made in August 2011 and February 2012.
DO YOU HAVE AN EXAMPLE WHICH SHOWS THE TIMELINE FOR
WEST VIRGINIA PROPERTY TAX ACCOUNTING USING YOUR
EXAMPLE ASSESSMENT DATE OF DECEMBER 31,2009
Yes. See MAP Rebuttal Exhibit No. 3 for a visual example of the timetable and MAP
Rebuttal Exhibit No. 4 for the applicable West Virginia Property Tax Code sections.
This exhibit demonstrates that property taxes expensed during the period June 2011
through July 2012 are paid in two installments on or prior to September 1 , 2011 and
March 1,2012.
DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
Yes.
IR0543949.1)

AMERICAN ELECTRIC POWER COMPANY
COMPUTATION OF EFFECTIVE F.I.T. RATE
FOR YEARS 2005 THRU 2009
MAP Rebuttal Exhibit No. 2
Page 1 of 11
2005 2006 2007 2008 2009
1 5YearAve 1
AEP System Adjusted Taxable Income cLoss>
AEP Companies With Positive Adjusted Taxable income
AEP Companies Having Tax Losses
1,048,768,758 1,035,751,327 1,373.223,627 1,034,389,779 61 0,479,747
1,278,570,329 1,443,631,787 1,567,155,836 1,327,876,159 1,159,667,712
(229,801,571) (407,880,460) (193,932,209) (293,486,380) (549.187.965)
F.I.T. - Companies with Positive Income
F.I.T. - AEP Consolidated
Theoretical Tax Savings
Effective Federal Taxes Savings Paid Rate
35% -- - 447.499.615 ,
505.271.125 548.504.543 464,756,656 405,883,699
35% 367,069,065 362,512.964 480.628.269 362,036,423 213,667,911
60,430,550 142.758.161 67,878,274 102,720,233 192.215.788
28.71% 25.11% 30.67% 27.26% 16.42%
Simple Effective FIT Paid Rate - 5 Year Average
26.03%

AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE INCOME
FOR THE rAx YEAR ENDED 2006
MAP Rebuttal Exhibit No. 2
Page 2 of 11
I
Taxable Income c hse
2006 ADJUSTMENTS Adjusted
Tax Return Accelerakd Repairs Charitable Taxable
AS Filed DepreclaBon Deduction Contrlbutlons Income
POSITIVE
TAXABLE
INCOMES
TAXABLE
LOSSES
AEP Company
AEP Desert Sky GP
AEP Coal, Inc.
AEP Communications Inc.
AEP Credit Inc.
AEP Delaware investment Company
AEP Delaware Investment Company II
AEP Delaware Investment Company Ill
AEP Energy Partners, Inc.
AEP Energy Services Gas Holdings
AEP Energy Services Investments
AEP Energy Services Ventures II
AEP Energy Services Ventures 111
AEP Energy Services Ventures
AEP Energy Services
AEP Fiber Venture Inc.
AEP Generating Company
AEP Indiana Michigan Transmission
AEP Investments
AEP Power Marketing
AEP Pro Sew
AEP Resource Services, LLC
AEP Resources
AEP Retail Energy
AEP Southwestern Transmission
AEP T&D Services
AEP West Vlrginia Coal
AEP Service Corporation
Appalachlan Power Co.
Ash Creek Mining Company
Blackhawk Coal Company
C3 Communications
Cedar Coal Company
AEP Utilities, Inc. (fonerly CSW Corp.)
Central Appalachian Coal Company
Central Coal Company
Central Ohio Coal Company
AEP Texas Central Company(CPL)
Colomet, Inc.
Columbus Southern Power Company
Conesviie Coal Preparation Company
CSW Development I
CSW Eastex GP II
CSW Eastex LP I
CSW Eastex LP ii
CSW Energy, Inc.
AEP Wind GP, LLC
CSW Energy Services
CSW Fort Lupton
CSW Frontera GP il
CSW Frontera LP I1
CSW International; Inc
CSW international Two
CSW International Three
CSW Leasing, Inc.
CSW Mulberry, inc.
CSW Mulberry ii
CSW Orange
CSW Orange 11
CSW Power Marketing
Central and South West Services, inc.
CSW Services International
CSW Sweeny GP i
CSWSweeny GP II
csw sweeny LP I
csw sweeny LP II
DECCO
Enershop
Houston Pipeline Company
HPL Holdings, Inc.
HPL Resources
HPL Storage
Indiana Michigan Power Company
Industry and Energy Associates LLC
Kentucky Power Company
Kingsport Power Company
Latin American Energy Holdings, Inc.
Louisiana intrastate Gas Company, LLC
LIG, Inc.
LIG Chemical Company
LIG Liquids Company
LIG Pipeline Company
Newgulf Power Venture, inc.
Noah I Power GP
Ohio Power Company
(1 2,538.71 3)
(149,435)
(237,418)
(3,651,839)
5,779,770
(6,945,901)
(1,118,858)
(641,289)
120,960,342
(3,267)
(30,549)
(2,177)
(31,745)
135,480,059
5,408,135
23,277,414
71,525,167
34,238,158
2,157,273
(32,313,649)
1,568,891
(64,084,833)
(25,329,061)
1,248,095
(74,418)
1,117,842
16,918,820
186,002
81,270
268,505,154
1,389,370
162,823,092
164,270
193,592
(20,716,081)
(277.069)
1,632.588
(402,626)
(878,774)
(801,120)
(192)
483,442
(10,641)
129,966
813,384
5,943,113
(1)
(24,153,030)
(2,283,318)
207,886,452
11,852,070
2,754,151
(7.651)
(1,175)
268,730,414
340.417
(166.048)
(44,205)
37,683
171,016
19,252,875
(8,470,784)
281,692
(48,479,209)
8,058,169
13,763,155
250,455
(3,834,126)
(302,543)
33,268,739
(61,515)
111,864
2,213
(8,420,881)
69,342,005
6,276,160
246,475
56,434,253
(1 2,879,130)
(149,435)
(71,370)
(3,607,634)
5,779,770
(6,945,901)
(1,118,658)
(641,289)
120,922,659
(3,267)
(30,549)
(28177)
(31,745)
135,309,043
5,408,135
4,024,539
79,995,951
34,238,158
1,875,581
18,165,560
1,536,891
(92,143,002)
(39,092,218)
1,248,095
(74,418)
1,117.842
16,666,185
186,002
81,270
272,339,280
1,691,913
129,534,353
225,785
193,592
(20,827,945)
(277.069)
1,630,375
(402,828)
(876,774)
(801,120)
(192)
483,442
(10,641)
129,966
813,384
5,943,113
(1)
(1 5,732,149)
(2,283,318)
138,544,447
5,575,910
2,507,676
(7,651)
(1 I 175)
212,296,161
5,779,770
120,922,659
c
135,309,043
5,408,135
4,024,539
79,995,951
34,238.158
1,875,581
16,185,330
1,566,891
1,248,095
1.1 17,842
16,666,185
188,002
81,270
272,339.280
1,691,913
129,534,353
225,785
193,592
1,630,375
483,442
129,956
813,384
5,943,113
136,544,447
5,575,910
2,507,678
212,296,161
(1 2,879,130)
(149,435)
(71,370)
(3,607,634)
(6,945,901)
(1 ,118,658)
(641,289)
(3.267)
(30,549)
(2,177)
(31,745)
(92,143,002)
(39,092,216)
(74,418)
(20,827,945)
(277,069)
(402,626)
(876,774)
(801,120)
(192)
(10,641)
(1)
(1 5,732,149)
(2,283,318)
(7.651)
(1,175)

AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE INCOME
FOR THE TAX YEAR ENDED 2005
MAP Rebuttal Exhibit No. 2
Page 3 of 11
I
Taxable Income
I
200s
Tax Return
As Filed
ADJUSTMENTS
Accelerated Repairs Charitable
DepreclaUon Deduction Contributions
Adjusted
Taxable
Income
POSITIVE
TAXABLE
INCOMES
TAXABLE
LOSSES
Public Service Company of Oklahoma
REP Holdco. Inc.
Simco
Snowcap Coal Company
Southern Appalachian Coal Company
Southern Ohio Coal Company
Southwestern Electric Power Corporation
Tuscaloosa Pipeline Company
United Sciences Testing, inc
AEP Texas North Company (WTU)
West Virginia Power Company
Windsor Coal Company
Wheeling Power Company
(36,301,988)
98,497
(219,177)
57,121
95,050,050
1,204,498
50,974,550
1,124,646
(4,724,636)
51,599
(6,410)
52,098,568
30,730
13,585,932
667,262
(31,577,352)
46,898
(212,767)
57,121
42,951,482
1,173.768
37,388,618
457,384
46,898
57,121
42,951.482
1,173,768
37,388,618
457,384
(31,577,352)
(212,767)
Taxable Income
1,248 549,663 193 780.905 1.048 768.758
1,278,570,329
(229,801,571)

AMERICAN ELECTRIC POWER COMPANY
FEDERALTAXABLE INCOME
FOR THE TAX YEAR ENDED 2006
MAP Rebuttal Exhibit No. 2
Page4of11
I
2006 ADJUSTMENTS Adjusted
Tax Return Accelerated Repairs Charitable Taxable
Taxable Income As Filed Depreclalion Deduction Contributions Income
AEP Company
AEP Desert Sky GP
AEP Coal, Inc.
AEP Communications Inc.
AEP Credit Inc.
AEP Delaware Investment Company
AEP Delaware Investment Company Ii
AEP Delaware Investment Company Ill
AEP Energy Partners, Inc.
AEP Energy Services Gas Holdings
AEP Energy Services investments
AEP Energy Services Ventures I1
AEP Energy Services Ventures 111
AEP Energy Services Ventures
AEP Energy Services
AEP Fiber Venture Inc.
AEP Generating Company
AEP Indiana Michigan Transmission
AEP Investments
AEP Power Marketing
AEP Pro Sew
AEP Resource Services, LLC
AEP Resources
AEP Retail Energy
AEP Southwestern Transmission
AEP T8D Services
AEP West Wrginia Coal
AEP Service Corporation
Appalachlan Power Co.
Ash Creek Mining Company
Blaclhawk Coal Company
C3 Communications
Cedar Coal Company
AEP Utilities, Inc. (formerly CSW Cop.)
Central Appalachian Coal Company
Central Coal Company
Central Ohio Coal Company
AEP Texas Central Company(CPL)
Colomet, Inc.
Columbus Southern Power Company
Conesvlie Coal Preparation Company
CSW Development I
CSW Eastex GP II
CSW Eastex LP I
CSW Eastex LP iI
CSW Energy, Inc.
AEP Wlnd GP, LLC
CSW Energy Services
CSW Fort Lupton
CSW Frontera GP II
CSW Frontera LP II
CSW International, Inc
CSW International Two
CSW International Three
CSW Leasing, Inc.
CSW Mulberry. Inc.
CSW Muibeny I1
CSW Orange
CSW Orange II
CSW Power Marketing
Central and South West Services, Inc.
CSW Services International
CSW Sweeny GP I
CSW Sweeny GP II
CSW Sweeny LP I
CSW Sweeny LP Ii
DECCO
Enershop
Houston Pipeline Company
HPL Holdings, Inc.
HPL Resources
HPL Storage
indiana Michigan Power Company
Industry and Energy Associates LLC
Kentucb Power Company
Kingsport Power Company
Latin American Energy Holdings, Inc.
Louisiana Intrastate Gas Company, LLC
LIG, Inc.
LiG Chemical Company
LIG Liquids Company
LIG Pipeline Company
Newguif Power Venture, Inc.
Noah I Power GP
Ohio Power Company
I
(2,327,604)
(52,198)
(3,580.962)
(2,822,498)
6,318,977
35,492,264
6,156,725
5,446,104
6,175,521
(43,206,017)
2,680,212
21,269,696
33,004,047
(2,317,831)
1,539,340
(278,811,329)
484,505
795,740
6,988,415
217,338,484
534,704
1,328
1,302,846
6,204,715
(303,OW
(160,211)
17,985,698
61,837
318,942,506
302,941
(7,835,931)
(149,300)
177,458
(451,671)
(282,594)
930,183
(16,559)
114,051
481,245
2,793,552
(20,092,351)
166,252,524
34,659,105
3,746,281
(1.W
388,538,433
396,416
(120,217)
324,991
18,494,136
(5,789,643)
276,135
46,253,654
5380,949
1,809,759
250,880
(13,287,341)
(258,332)
28,349,163
(16,862)
107.830
2,538
70,818,868
6,295,456
285.226
56,581,139
(2,724,022)
(52,198)
(3,460,745)
(2,822,498)
6,318,977
35,492,264
6,156,725
5,446,104
6,175,521
(43,531,008)
2,680,212
2,775,560
38,793,890
(2,317,831)
1,263,205
(323,064,983)
484,505
795,740
1,607,466
215,528,725
534,704
1,328
1,302,846
5,953,835
(303,056)
(16021 1)
37,273,039
320,169
290,593,343
321,823
(7,943,761)
(149,300)
174,920
(451,671)
(282,594)
930,183
(16,559)
114,051
481,245
2,793,552
(20,092,351)
95,433,636
28,363649
3,461,035
(1,844)
331,957,294
POSITIVE
TAXABLE
INCOMES
6,318,977
35,492,264
6,156,725
5,446,104
6,175,521
2,680,212
2,775,560
38,793,890
1,263,205
484,505
795,740
1,607,466
215,528,725
534,704
1,328
1,302,848
5,953,835
31,273,039
320,189
290,593,343
321,823
174,920
930,163
114,051
481,245
2,793,552
95,433,636
28,363,649
3,461,035
331,957,294
TAXABLE
LOSSES
(2,724,022)
(52,198)
(3,460,745)
(2,822,498)
(43,531,008)
(2,317,831)
(323,064,963)
(303,056)
(180,211)
(7,943,761)
(149,300)
(451,671)
(282,594)
(16,559)
(20,092,351)

AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE INCOME
FOR THE TAX YEAR ENDED 2006
MAP Rebuttal Exhibit No. 2
Page5of11
1
Taxable Income

AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE INCOME
FOR THE TAX YEAR ENDED 2007
MAP Rebuttal Exhibit No. 2
Page6of 11
I
Taxable Income 1
2007 ADJUSTMENTS Adjusted
Tax Return Accelerated Repairs Charitable Taxable
As Filed Depreciation Deduction Contributions Income
POSITIVE
TAXABLE
INCOMES
TAXABLE
LOSSES
AEP Company
AEP Desed Sky GP
AEP Coal, Inc.
AEP Communications inc.
AEP Credit Inc.
AEP Delaware Investment Company
AEP Delaware Investment Company II
AEP Delaware Investment Company ill
AEP Energy Partners, Inc.
AEP Energy Services Gas Holdings
AEP Energy Services Investments
AEP Energy Services Ventures II
AEP Energy Services Ventures Iii
AEP Energy Services Ventures
AEP Energy Services
AEP Fiber Venture Inc.
AEP Generating Company
AEP lndiana Michigan Transmission
AEP Investments
AEP Power Marketing
AEP Pro Sen/
AEP Resource Services. LLC
AEP Resources
AEP Retail Energy
AEP Southwestern Transmission
AEP T&D Services
AEP West Vlrginia Coal
AEP Service Corporation
Appalachian Power Co.
Ash Creek Mining Company
Blackhawk Coal Company
C3 Communications
Cedar Coal Company
AEP Utilities, Inc. (formerly CSW Cop.)
Central Appalachian Coal Company
Central Coal Company
Central Ohio Coal Company
AEP Texas Central Company(CPL)
Coiomet, Inc.
Columbus Southern Power Company
Conesvlie Coal Preparation Company
CSW Development I
CSW Eastex GP II
CSW Eastex LP i
CSW Eastex LP II
CSW Energy, Inc.
AEP Wind GP, LLC
CSW Energy Services
CSW Fort Lupton
CSW Frontera GP Ii
CSW Frontera LP ii
CSW International, Inc
CSW lntemational Two
CSW International Three
CSW Leasing, Inc.
CSW Mulbeny, inc.
CSW Mulbeny Ii
CSW Orange
CSW Orange II
CSW Power Marketing
Central and South West Services, Inc.
CSW Services International
CSW Sweeny GP I
CSW Sweeny GP II
CSW Sweeny LP I
csw sweeny LP iI
DECCO
Enershop
Houston Pipeline Company
HPL Holdings, inc.
HPL Resources
HPL Storage
indiana Michigan Power Company
Industry and Energy Associates LLC
Kentucky Power Company
Kingsport Power Company
Latin American Energy Holdings, Inc.
Louisiana Intrastate Gas Company, LLC
LiG, inc.
LiG Chemical Company
LIG Liquids Company
LIG Pipeline Company
Newgulf Power Venture, Inc.
Noah I Power GP
Ohio Power Company
(4,532,149)
115,938
2,641,365
(1,517,856)
12,028,811
1,497,362
257,016
8,072,476
(2,273,809)
13,869,634
(60,269,156)
268,899
22,053,057
11,091,663
26,952,567
1,149,085
38,723,978
(1,582,628)
906,152
50,074,210
65,087,815
335,347
286,889
(6,307,109)
377,591
89.461
74,356,856
I. 136,575
443,700,164
72,619
(1 4,997,754)
35,705
(2,498,672)
(2,599,550)
677,900
1,613,053
33,641
787,271
75,252,378
(4,453,125)
156,879.950
26,773,624
3,646,617
447,120,206
361,729
(104,507)
(1,591,079)
249,064
10,513,537
(3,920,407)
278,444
(6,888,614)
4,686
5,078,658
(44,032,882)
251,417
(29,244,908)
(218,601)
21,233,671
38,040
866.269
2,538
26,008,558
3,531,274
45,443
34,488,569
(4.893.878)
115,938
2,745,872
(1,517,856)
12,028,811
1,497,362
257,016
8,072,476
(682,730)
13,669,634
(60,518,220)
268,899
11,539,520
15,012,070
26,952,567
870.641
45,612,792
(1,587,314)
906,152
44,995,552
109,120,697
335,347
288,889
(6,558,526)
377,591
89,461
103,601,764
1,355,176
422,466,493
34,579
(1 5,864,023)
35,705
(2,501,210)
(2,599,550)
677,900
1,613,053
33,641
787,271
75,252.378
(4,453,125)
130,871,392
23,242,350
3,603,174
412,631,637
115,938
2,745.872
12,028,811
1,497,362
257,015
8,072,476
13,869,634
268,899
1 1,539,520
15,012,070
26,952,567
870,641
45,612,792
906,152
44995,552
109,120,697
335,347
288,889
377,591
89,461
103,601,764
1,355,176
422,466,493
34,579
35,705
677,900
1,613,053
33,641
787.271
75,252,378
130,871,392
23,242,350
3,603,174
412,631,637
(4,893,878)
(1,517,856)
(682,730)
(60,518,220)
(1,587,314)
(6,558,526)
(15,864,023)
(2,501,210)
(2,599,550)
(4,453,125)

AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE INCOME
FORTHE TAXYEAR ENDED 2007
MAP Rebuttal Exhibit No. 2
Page 7 of 11
2007 ADJUSTMENTS Adjusted POSITIVE
Tax Return Accelerated RepalK Charitable Taxable TAXABLE TAXABLE
Taxable Income CLosSz AS Filed Depreciation Deduction Contributions Income INCOMES LOSSES
I 1
Public Service Company of Oklahoma
REP Holdco, inc.
Simco
Snowcap Coal Company
Southern Appalachian Coal Company
Southern Ohio Coal Company
Southwestern Electric Power Corporation
Tuscaloosa Pipeline Company
United Sciences Testmg, Inc.
AEP Texas North Company (WU)
West Virginia Power Company
Windsor Coal Company
Wheeling Power Company
(1 30,454,535)
76,159
(727.083)
102,210
44,761.770
1,431,097
64,329,880
28,993,948
(38,425,841)
34,445,724
89,928
8,825,306
342,070
(92,028.694)
76,159
(727,083)
102,210
10,316,046
1,341,169
55,504,574
26,651,875
76,159
102,210
10,316,045
1,341,169
55,504,574
28,651,878
(92,028,694)
(727,083)
Taxable Income
1,395451.513 22 227.886 1.373 223,627
1,567.155836 (193,932.209k

AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE INCOME
FOR THE TAX YEAR ENDED 2008
MAP Rebuttal Exhibit No. 2
Page i3 of 11
I
Taxable Income

1034,389.779
AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE !NCOME
FOR THE TAX YEAR ENDED 2008
MAP Rebuttal Exhibit No. 2
Page 9 of 11
I
Taxable Income

AMERICAN ELECTRIC POWER COMPANY
FEDERAL TAXABLE INCOME
FOR THE TAX YEAR ENDED 2009
MAP Rebuttal Exhibit No. 2
Page 10 of 11
I Taxable Income

~ -
AMERICAN ELECTRIC POWER COMPANY
FEDERALTAXABLE INCOME
FOR THE TAX YEAR ENDED 2009
MAP Rebuttal Exhibit No. 2
Page 11 of 11
1
Taxable Income

MAP Rebuttal Exhibit No. 3
Page 1 of 1
West Virginia Public Service Company
Property Tax Timetable Example
I I I I I I
I I I I
Assessment Date Return filed Tax Values Lien Attaches Tax Expense 1st Half
I
Determined Liability Recorded Amortization Payment Due
Starts
I
I
I
2nd Half
Payment Due
Tax Expense
Amortization
Ends
Property Taxes Expensed
SUMMARY
Assessment
Date
12/31/2009
Return Filed
5/1/2010
Lien Attach
Accrual Dates
Date Deferral Made (Book Expense)
Payment Dates
12/31/2010 12/31/2010 07/1/2011 thru 06/30/2012 9/1/2011
3/1/2012
DR: 186 DR: 408 DR: 236 DR: 236
CR: 236 CR: 186 CR: Cash CR: Cash

~ prlvate
West Virginia Public Service Company
West Virginia Property Tax Code
MAP Rebuttal Exhibit No. 4
Page 1 of 1
ARTICLE 6.ASSESSMENT OF PUBLIC SEMCE BUSINESSES.
§*I-6-1, Retiirtis of propertyto Board of (~bllc works.
(a) On or before the first day of May in each year a return in writing shall be filed with the board of public works: (1) By
the owner or operator of every railroad, wholly or In part, withln this state; (2) by the owner or operator of every railroad
bridge upon which a separate toll or fare is charged; (3) by the owner or operator of every car or line of cars used upon
any railroad within the state for transportation or accommodation offreight or passengers, other than the owners or
operators as may own or operate a railroad within the state; (41 by the owner or operator of every express company or
express line, wholly or in part, within this state, used for the transportation by steam or otherwise offreight and other
articles of commerce; (5) by the owner or operator of evely pipellne, wholly or in part, within this state, used for the
transportatlon of oil or gas or water, whether the oil or gas or water be owned by the owner or operator or not, or for the
transmlsslon of electrical or other power, or the transmisslon of steam or heat and power or of articles by pneumatic or
other power; (e) by the owner or operator of every telegraph or telephone line, wholly or in part, within this state, except
lines not operated for compensatlon; (71 by the owner and operator of every gas company and electric lighting
i companyfurnlshing gas or electrlcity for lighting, heating or power purposes; (8) by the owner or operator of
: hydroelectric companies for the generation and transmission of light, heat or power; (9) by the owner or operator of
b water companles furnishing or distributing water; and (10) by the owner or operator of all other public service
, corporations or persons engaged in public service business whose property is located, wholly or in part, within this
1 state.
(e) The return required by this section of every owner or operator shall cover the year ending on the thirty-first day of
December, next preceding, and shall be made on forms prescribed by the board of public works, which board is
'
hereby invested with full power and authority and it is hereby made its duty to prescribe the forms as will require from
any owner or operator hereln mentioned information as in the judgment ofthe board may be of use to it In determining
' the true and actual value ofthe properties ofthe owners or operators.
$1 14-23. Lien oftaxes; notice; collectioii by suit.
(a)The amount oftaxes and levies assessed under this article shall constltute a debt due the state, county, district or
municipal corporation entitled thereto, and shaii be a lien on all property and assets ofthe taxpayer within the State.
i
(b) The lien shall attach December 31, following the commencement ofthe assessment year, and shall be prior to all
other ilens and charges.

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
ROBERT W. HRISZKO

RWH Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
ROBERT W. HRISZKO
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q. PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS.
2 A. My name is Robert W. Hriszko. I am a managing director in the firm of
3 PricewaterhouseCoopers LLP. My business address is One North Wacker Drive,
4 Chicago, IL 60606.
5 Q. WOULD YOU PLEASE DESCRIBE THE FIRM OF
6
7 A.
8
9
10
11
12
13
14 Q.
15
16
17 A.
18
19
20
PRICEWATERHOUSECOOPERS LLP ("PwC")
PwC is a firm of independent public accountants with officedaffiliates throughout
the United States and in many other countries. We have as clients a large number
of both publicly and privately owned companies. The firm performs audits of
financial statements, prepares and reviews income tax returns for all types of
businesses, and consults with businesses regarding financial, accounting and tax
matters. PwC audits a significant number of the electric, gas and
telecommunications companies in the United States.
WOULD YOU PLEASE DESCRIBE YOUR PROFESSIONAL
BACKGROUND AND QUALIFICATIONS TO TESTIFY AS AN EXPERT
IN THIS PROCEEDING
I am a graduate of St Mary's College in Winona, Minnesota, from which I
obtained a Bachelor of Arts degree in Accounting and Economics in 1964. I am
also a graduate of Northwestern University School of Law, from which I obtained
a Juris Doctor degree in 1967. I am a certified public accountant and an attorney
{ R054393 8.1 }

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Q.
A.
Q.
A.
Q*
in the State of Illinois and a member of the American Institute of Certified Public
Accountants, the Illinois CPA Society, and the Tax Committee of the American
Bar Association.
WHAT EXPERIENCE HAVE YOU PERSONALLY HAD IN THE
UTILITY FIELD
I have spent my entire career working with utility companies on industry issues.
After a 35-year career at Arthur Andersen LLP, I presently assist in directing the
PwC tax practice for the utility industry in the U.S. I have been with PwC for
eight years. I am also responsible for technical matters involving federal income
tax and related ratemaking issues and consult with utility companies throughout
the country on various tax issues and ratemaking issues.
HAVE YOU PREVIOUSLY TESTIFIED BEFORE REGULATORY
AGENCIES
Yes. I have testified before the Public Utility Commission of Texas, the Illinois
Commerce Commission, the Ohio Public Utility Commission, the Wisconsin
Public Utility Commission, the State Corporation Commission of the State of
Kansas, the Missouri Public Service Commission, and the U.S. Treasury
Department. My testimony has addressed the normalization requirements of the
Internal Revenue Code as applied to various factual settings and various other tax
issues in ratemaking proceedings. In addition to my personal testimony, I have
reviewed testimony prepared by my present and predecessor firms and/or their
clients on numerous occasions.
HAVE YOU PREVIOUSLY TESTIFIED IN THIS DOCKET
{R054393 8.1 }

Page 3 of 10
1 A.
2 Q*
3 A.
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11 A.
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21 Q.
22
No, I have not.
WHAT IS THE PURPOSE OF YOUR TESTIMONY
I am testifying on behalf of Appalachian Power Company ("APCo") and
Wheeling Power Company ("WPCo") (collectively "the Companies"),
subsidiaries of American Electric Power Company, Inc. ("AEP"). The purpose of
my testimony is to rebut certain aspects of the testimony of Staff witness Oxley
and of CAD witness Smith. Specifically, my testimony will address consolidated
tax adjustments ("CTAs") and deductions following APCo's change in method of
accounting for units of property.
PLEASE DESCRIBE THE CTA METHODOLOGY.
A CTA is an adjustment to the revenue requirement of a utility based upon its
membership in an affiliated group filing a consolidated income tax return in
which there are non-jurisdictional and/or non-regulated members that generate tax
losses. Under the CTA method, income tax benefits from losses of affiliated
corporations are used to reduce the tax costs of the utility. This method is to be
contrasted with the stand-alone method for determining income tax expense in the
ratemaking process. Under the stand-alone method, income tax expense and the
reserve for deferred income taxes are calculated based only on the revenue and
expedse, rate base, capital structure, and cost of capital elements included in the
determination of cost of service for the jurisdictional utility customers.
ARE THE COMPANIES PROPOSING USE OF THE STAND-ALONE
METHOD
{R0543938.1}

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A.
Q.
A.
No, they are not. The Companies are proposing, as described in the direct
testimony of Company witness Pyle, the parent company loss adjustment
('IPCLA'') method. The PCLA method proposed by Mr. Pyle takes into account an
adjustment to the revenue requirement of the utility based on the losses only of
the parent of the consolidated group, in this case AEP. This was the same method
utilized by the Company in its last base rate case filing (Case No. 05-1278-E-PC-
PW-42T). Until recently, this Commission has employed the PCLA method and
the Company has agreed to utilize it. However, recently, this Commission has
ordered that the CTA method be used in Case No, 06-0960-E-42T (Allegheny
Power), Case No. 08-0900-W-42T (West Virginia American Water Company),
and Case No. 08-1761-G-PC (Hope Gas). In this Docket, both Staff witness
Oxley and CAD witness Smith propose utilizing the CTA method.
IS THE CTA METHOD APPROPRIATE FOR CALCULATING COST OF
SERVICE FOR RATEMAKING PURPOSES
No, it is not. The CTA method is never appropriate for calculating cost of
service for ratemaking purposes because it is arbitrary, inequitable and violates
fundamental ratemaking principles. It bestows arbitrarily on the customers of the
jurisdictional utility a benefit created by the capital investments or expenditures of
the non-jurisdictional and/or non-regulated affiliates of the utility. The utility
customers have not put capital at risk, incurred operating losses, or met any of the
other tests that permit income tax benefits to be granted under the Internal
Revenue Code. Allocating income tax benefits to utility customers will not
encourage them to undertake any of the activities for which Congress enacted the
{ R0543938.1}

Page 5 of 10
1
incentive measures giving rise to the income tax benefits, such as investment in
assets eligible for accelerated depreciation, alternative energy property, and
research and development. Ratepayers have not funded these non-regulated
investments. Rather, they have merely paid for the costs of electric utility services
5
6
7
8
9
10
11 Q.
12
13 A.
14
provided by the utility and a reasonable rate of return. It is the shareholders who
have incurred the risk, made the investment, and borne the losses. To allocate the
tax benefits generated by those losses away from the shareholders who have borne
the losses is inequitable. Moreover, it violates the standard ratemaking principle
that cross-subsidization between utility and non-utility activities is strictly
prohibited.
CAN YOU PROVIDE AN ILLUSTRATION OF THE INEQUITIES
CAUSED BY THE CTA METHOD
Yes. Consider a utility company that decides that it would make reasonable
business sense to enter into a non-regulated business and obtains shareholder
15 approval to reorganize into a holding company structure. Following the
16 reorganization, both the utility itself as well as the new, non-regulated company
17 are wholly-owned subsidiaries of the new holding company. Assume that the
18 utility earns an amount of after-tax income that enables it to distribute a dividend
19 to its immediate shareholder, now the holding company. The holding company
20 then has a choice: it could distribute the amount as a dividend to its shareholders
21 or, instead, contribute that amount to its non-regulated subsidiary in accordance
22 with its business plan approved by the shareholders. If it does the latter and the
23 non-regulated subsidiary generates positive taxable income, the CTA
(R0543938.1)

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methodology will not impact the utility's rates. However, if the non-regulated
subsidiary incurs losses that generate tax benefits, under the CTA methodology
the utility's rates will reflect a sharing of the tax benefits of the non-regulated
subsidiary's losses, notwithstanding the fact that the jurisdictional economics for
the utility are unchanged. This is not appropriate ratemaking. Equity would
dictate that the shareholders who funded the investment that generated both the
losses and the tax benefits should not only bear the economic losses, but should
also garner the tax benefit generated by those losses. To have the shareholders
bear the burden of the losses but share the tax benefits emanating from those
losses would be both arbitrary and unfair.
WHAT IS THE IMPACT OF THE CTA METHODOLOGY ON THE
UTILITY'S AUTHORIZED RATE OF RETURN
Utilization of the CTA methodology results in an indirect reduction of the utility's
authorized rate of return. When an affiliate of the utility incurs a loss and a
portion of the tax benefit associated with that loss is used to reduce the utility's
current tax expense in cost of service under the CTA methodology, the resulting
rates are flawed in three ways. First, the rates set will not take into account the
entitlement of group members with losses to compensation for the use of those
losses from members with positive taxable income under a tax sharing agreement.
Second, as I already indicated, the rates will reflect tax benefits of losses from
affiliate investments that ratepayers never funded. Third, the rates set
prospectively will be based on the assumption that affiliates will continue to
sustain losses and share their tax benefits over the period the new rates are in
{R0543938.1}

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Q.
A.
Q.
A.
effect. If, during the period the new rates are in effect, the utility and previous loss
affiliates have positive taxable income, the consolidated group will owe the
government the same amount of tax as they would have owed if the affiliates had
filed separately. However, because rates were set using a methodology that
ignores the cost of tax sharing payments and takes into account tax benefits from
losses on investments that ratepayers never funded and projects them into future
periods, the authorized rate of return is impaired.
IS THE CTA METHODOLOGY COMMON AMONG STATE UTILITY
COMMISSIONS OR THE FERC
No, the CTA methodology is very uncommon. To my knowledge, only a handful
of states impose CTA’s.
ARE YOU AWARE OF RECENT REGULATORY ORDERS IN WHICH A
COMMISSION CONSIDERED AND REJECTED CHANGING ITS
POLICY TO IMPOSE A CTA
Yes. Both the Minnesota Public Utilities Commission, in Northern States Power
Company, Docket No. E-002/GR-05-1428 (September 1, 2006), and the New
Mexico Public Regulations Commission, in Public Service Company of New
Mexico, Case No. 07-00077-UT (April 25, 2008), have recently addressed the
19 issue of whether to implement a CTA and both unequivocally rejected
20 implementation of a CTA. More recently, the Washington Utilities and
21 Transportation Commission, in Washington Utilities and Transportation
22 Commission v. Avista Corporation, Case No. UE-080416, December 29, 2008,
{R0543938.1}

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A.
issued a final order approving and adopting a multi-party settlement stipulation
that addressed and squarely rejected implementing a CTA.
IF THE COMMISSION WERE TO ORDER THE CTA METHOD TO BE
USED BY THE COMPANIES IN THIS DOCKET, IS THE APPROACH
TAKEN BY THE STAFF CORRECT
No, it includes one significant error. The Staff has used a five-year average of
effective tax rates from the period 2005-2009 to arrive at an effective tax rate of
16.82 percent. This rate is as low as it is because the Staff did not eliminate from
the 2009 effective tax rate the effect of the cumulative catch-up adjustment for the
change in method of accounting that APCo obtained for that year to change its
method of accounting for units of property for its generation assets. The Staff
should have treated this as a going level adjustment to remove the impact of this
one-time, cumulative adjustment from the average effective tax rate calculation.
The impact of this error in the Staffs calculation was compounded by the
accumulated deferred income tax liability resulting from the cumulative
adjustment being utilized by the Staff to reduce rate base. By reducing rate base
and also including the adjustment in the calculation of the effective tax rate, the
Staff is double weighting its impact. This has a distorting effect on rates and
should be corrected by eliminating the cumulative catch-up adjustment from the
2009 effective tax rate used in arriving at the five-year average effective tax rate.
MAP Rebuttal Exhibit No. 2 properly reflects the adjustment to 2009 taxable
income to remove the one-time effect of the change of accounting method, thus
resulting in an average effective tax rate of 26.03 percent.
{R0543938.1}

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A.
Q.
A.
ARE YOU FAMILIAR WITH APCO's CHANGE OF METHOD OF
ACCOUNTING FOR GENERATION UNITS OF PROPERTY
Yes, I am.
IS IT PREFERABLE FOR THE STAFF TO PROPOSE TO FLOW
THROUGH TO CUSTOMERS THE FEDERAL INCOME TAX BENEFIT
OF THE 2009 AND FUTURE YEARS' DEDUCTIONS RESULTING
FROM APCO'S CHANGE OF ACCOUNTING METHOD
No, it is not. There are several reasons for normalizing, rather than flowing
through, each year's deduction associated with units of property. First, the
deduction is nothing more than an acceleration of the depreciation deduction that
had been previously taken by APCo when it followed its financial statement
treatment of units of property whereby it capitalized for tax purposes many
expenses that actually were deductible. The depreciation deductions that APCo
had been taking would have been subject to the normalization requirements of the
Internal Revenue Code. The acceleration of those deductions does not negate the
arguments in favor of normalization, even though technically it may eliminate the
application of the normalization requirements of the Internal Revenue Code.
Flow-through of the tax benefit of the annual repairs deduction is not preferable
because it benefits current ratepayers at the expense of future ratepayers when the
temporary differences reverse. In addition, in APCo's situation, it defeats the very
purpose for which the accounting method change was undertaken. APCo changed
its method of accounting as a strategic means to meet its cash flow needs. As Mr.
Pvle's direct testimonv states. the kev to APCo sustaining: the cash flow benefits
Y
{ R0543938.1}

Page 10 of 10
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3
of the accounting method change is derived from normalizing and recognizing the
deferred tax accounting in similar fashion to tax depreciation normalization. To
flow the tax benefit through to ratepayers would defeat APCo's strategic cash
4 flow objective.
5 Q. DOES THIS CONCLUDE YOUR TESTIMONY
6 A. Yes.
{ROS4393 8.1 }

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
JEFFREY D. LAFLEUR

JDL REBUTTAL EXHIBIT NO. 1
REBUTTAL TESTIMONY OF
JEFFERY D. LAFLEUR
ON BEHALF OF APPALACHIAN POWER COMPANY
AND WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION
OF WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q*
2 A.
3 Q*
4
5 A.
6 Q*
7 A.
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17 Q.
18 A.
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20
PLEASE STATE YOUR NAME.
My name is Jeffery D. LaFleur.
ARE YOU THE SAME JEFFERY D. LAFLEUR WHO PRESENTED
DIRECT TESTIMONY IN THIS CASE
Yes, I am.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
I present corrections to Table 3 of my Direct Testimony and to the Companies’
adjustment 14-PE. Additionally, my rebuttal testimony addresses CAD witness
Ralph C. Smith’s recommended adjustments to APCo’s operation and
maintenance (O&M) expenses associated with the flue gas desulfurization units
(FGDs or scrubbers) at Amos and Mountaineer, and the Mountaineer Carbon
Capture and Storage (CCS) Facility. I also address the CAD’S and the Staff’s
proposed disallowance of $1.484 million (WV jurisdictional) of the Companies’
requested inflation-adjustment for Generation O&M expense. Finally, I comment
on WVEUG witness Stephen J. Baron’s testimony regarding the Mountaineer
CCS facility.
ARE YOU SPONSOFUNG ANY REBUTTAL EXHIBITS
Yes. I am sponsoring the following exhibits:
0 JDL Rebuttal Exhibit No. 2 - Response to CAD Data Request E- 174
0 JDL Rebuttal Exhibit No. 3 - Response to CAD Data Request T-26

Page 2 of 6
1 Q.
PLEASE DISCUSS THE CORRECTIONS TO TABLE 3 OF YOUR
2 DIRECT TESTIMONY.
3 A.
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7
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10
Table 3 in my Direct Testimony contained an error in the average amount of
annual O&M shown in the line labeled, “Three-Year (2007-2009) Average:
Inflation Adjusted without FGD and CCS”. The incorrect average of
$190,194,526 is corrected in Table JDL-1 below to $190,070,03 1 (Line 21). This
revised 3-year average is also reflected in Table JDL-1 “Total 2007-2009 Average
Including Additions” (Line 31); the incorrect total of $2 19,712,067 in Table 3 of
my Direct Testimony is corrected to $219,587,572.
Table JDL - 1 Development of Inflation and O&M Adjustments
1
)
C CCS
11
24 I I
25 Additions On-Going Basis To Reflect FGD and CCS:
26 Amos FGD Operation & Maintenance Costs
27 Mountaineer FGD Operation & Maintenance Costs
28 Mountaineer CCS
29 I TOTAL Additions =
30
31 Total 2007-2009 Average Including Additions =
1
$219,587,572 I
1
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Page 3 of 6
PLEASE DISCUSS THE BASIS FOR THE COMPANIES’ CORRECTION
2 TO ADJUSTMENT 14-PE.
3 A. In the process of developing adjustment 14-PE, the Companies removed
4
$8,020,213 (total Company basis) in actual 2009 FGD and CCS expenses. Table
5 JDL-1 , Line No. 7 “FGD and CCS Costs Total” reflects the total company
6
amount of actual test year costs of $8,020,213 that was removed. However, the
7 Companies failed to remove this amount from the per books test year level of
8
9
expenses. This amount was then incorrectly included in the requested total
Companies’ adjustment 14-PE of $29,517,541. The corrected amount of the
10 requested adjustment is shown in Table JDL-1 , Line 29 of $21,497,328 (total
11
Company) or $9,200,641 (WV jurisdictional). Table JDL-1A provides a summary
12 of this correction.
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Table JDL - 1A Adjustment 14-PE Correction Summary
Total Company WV Jurisdictional
Incorrect Adjustment 14-PE $29,5 17,541 $12,633,2 12
2009 FGD & CCS Expenses (8,020,213) (3,432,571)
Corrected Adjustment 14-PE $21,497,328 $9,200,641
The intended purpose of adjustment 14-PE was to reflect an annual, going-level
of O&M expenses for these facilities. Such an adjustment is necessary because
there were either zero or less than a full year’s level of O&M expenses in the test
year for the facilities other than the Mountaineer FGD.
24 Q DOES THE CORRECTED ADJUSTMENT PROPERLY REFLECT AN
25
ANNUAL ON-GOING LEVEL OF EXPENSE FOR THESE FACILITIES

Page 4 of 6
1 A. Yes. As corrected, adjustment 14-PE, combined with test year actual costs,
2 reflects the appropriate level of annual O&M expense for these facilities. The
3 O&M expenses for 20 10 are at a going-level, based on year-to-date actual
4 expenses, as shown in Table JDL-2 (listing the in-service dates and O&M
5 expenses for FGDs at Amos Units 2 and 3 and for the FGD and CCS at
6 Mountaineer).’ I have also updated actual total Companies’ expenses through
7 October 2010 in Table JDL-2.
8
9 Table JDL-2 FGDs and CCS In Service Dates and Annual O&M Expenses
10 --
11 Q. ON WHAT BASIS DID THE CAD RECOMMEND THAT THESE O&M
12 EXPENSES BE EXCLUDED
13 A. CAD witness Smith argues that these expenses occurred outside of the test year
14
and are not known and measurable.
15 Q. DO YOU AGREE WITH MR. SMITH’S RECOMMENDATION
16 A. No. As presented in Table JDL-2, the FGD and CCS costs are effectively known
17
18
and measurable because actual costs have been recorded through October of 20 10.
As discussed in the response to data request CAD E-174 (JDL Rebuttal Exhibit
19 No. 2), the Companies’ adjustment is based on actual data and estimates and
I
During the discovery process, the Companies provided evidence of APCo’s actual O&M costs
incurred through July 2010.

Page 5 of 6
1
2
3
4
reflects a reasonable level of O&M expense. While the Companies continue to
believe that their corrected adjustment is appropriate, at a minimum consistency
would dictate that the CAD use the same methodology it used to recognize the
effect of the Companies’ downsizing in 2010, which was to annualize a known
5 level of 2010 costs.
6 Q.
7
8
9 A.
10
11
12
13
14
15
16
17
18
19 Q.
20
21
22 A.
23
24
DO YOU AGREE WITH THE CAD’S AND STAFF’S DISALLOWANCE
OF THE RECOGNITION OF INFLATION TO ADJUST 3-YEAR
AVERAGE O&M EXPENSES
No. Adjustment 13-PE for $1.5 million (WV jurisdictional) to recognize the
average inflation rate over 2007-2009 is appropriate to reflect the real cost of
goods and services in the power generation marketplace. In the absence of special
circumstances, averaging over a multi-year historical period (which includes the
test year) provides a more representative going-level of O&M expenses than
basing a request on a single year of cost data, since many power plant
maintenance activities such as major turbine and boiler outages occur on a
cyclical basis over several years. Not accounting for inflation in the ratemaking
process would have the same effect as disallowing ongoing prudently incurred
O&M costs.
DID THE COMPANIES PROVIDE THE CAD WITH A DETAILED
EXPLANATION OF THE DERIVATION AND BASIS FOR
ADJUSTMENT 13-PE
Yes. This justification was provided in response to CAD data requests E- 174 and
T-26, and is included in my Rebuttal Testimony as JDL Rebuttal Exhibits No. 2
and No. 3, respectively. The inflation calculations and source are based on US

Page 6 of 6
1
2
3 Q*
4
5 A.
6 Q*
7
8 A.
9
10
11
12
13
14
15
16 Q.
17 A.
Bureau of Labor Statistics indices for the electric power generation, transmission,
and distribution industry as presented in JDL Rebuttal Exhibit No. 3.
DO YOU AGREE WITH THE WVEUG’S RECOMMENDATION
RELATING TO THE MOUNTAINEER CCS FACILITY
No.
DOES THE MOUNTAINEER CCS FACILITY PROVIDE BENEFITS TO
WEST VIRGINIA AND ITS CITIZENS
Yes. Given the vital significance of coal to the West Virginia economy,
advancing carbon capture and storage is very important to the State, its citizens,
the Companies, and their customers. In fact, in 2009 the West Virginia
Legislature enacted Article 11 A of the West Virginia Code on Carbon Dioxide
Sequestration. Section 22- 11 A- 1 (b)( 1) of that statute contains the legislative
finding: “It is in the public interest to advance the implementation of carbon
dioxide capture and sequestration technologies into the state’s energy portfolio.. .
99
DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
Yes.

. .
I .:
5
JDL Rebuttal Exhibit No. 2
Page 1 of 2
APPALACHIA$I POWER COMPANY & WHEELING
POWER COMPANY
WEST VIR@IMA CASE NO, 10-0699-E-42T
SEVENTH REQUEST FOR INFORMATION CAD
Reauest E-174
Generation O&M Expenses, Refer tp Statement G-1 , Adjustments 13-PE and 14-PE.
a. Please explain fully and in detail the Companies’ rationale for adjusting test year generation
O&M expenses to reflect a three-year average of such costs,
b. Please explain fully and in d& how the labor and non-labor inflation adjustment factors
listed on lines 19 and 20 of page 1 a€ Statement 0-1, Adjustments 13:PE and 14-PE were derived.
Show detailed calculations.
I
c. Please explain Mly and in. detail how the forecasted mounts reflected Statement (3-1,
Adjustment 14-PE (pages 2-4) were;ddvd. Show detailed dculations.
d. Refer to Statement G-1, Adjustment 14-PE, page 2 of 4. Please indicate whether the
Companies’ have updated its forecasted mounts related to the Amos Plant FGD OtQM for the
period July 2010 through June 201.1;. If so, please provide the updated forecast electronically in
Excel with all formulas and calculations intact. If not, explain fully why not.
e. Refer to Statement G-1, Adjytment 14-PE, page 3 of 4. Please indicate whether the
Companies’ have updated its forecasted amounts related to the Mouitainecr Plant FGD O&M for
the period July 2010 though June 201 1, Ifso, please provide the updated forecast electrodcdy in
Excel with all formulas and calculations intact. If nat, explah MIy why not,
- 1
f. Refer to Statement 0-1, Adjustment 14-PE, page 4 of 4. Please indicate whether the
Companies’ have updated its forecasted amounts related to the Mountaineer Carbon Capture. If so,
please provide the updated forecast electronically in Excel with dl formulas and calculations intact,
If not, explain Wry why not.
g. Refer to the electronic ve~ion of Statement 0-1, Adjustment 14-PE, page 4 of 4.
SpecificalIy, referring to cell X-18, which shows the amount of $13,773,596, please explain fully
md in detail why the formula embdded in the refereaced cell does not reflect the removal of the
Cost Rehburmneftt for EfedSteam A Fuel in the amount of $579,775,
Response E- 174
I i
a. See the direct testimony of Companies witness LaFleur, page 9, line 3, through page 12,
line 22.
b,
4 :
Please refer to the Companies’ response to CAD 4 T-26.
c. The forecasted amounts shown in AdjusFent 14 PE (pages 2-3) were developed in the
summer of 2009 based upon actual expenditures at the Mountaineer FOD and other locations. The
Amos and Mountaineer plants evaluated these actual expenditures &d estimated O&M costs by
each month for their respdve FGD foperatiom, The Mountaineer CCS project team developed its
\ I ,
. ..
.

JDL Rebuttal Exhibit No 2
Page 2 of 2
APPALAC&,POWER COMPANY ~ZFEEL~G
POWER COMPANY
WEST VIRGINIA CASE NO, 10-0699-E42T
SEVENTH REQUEST FOR INFORMATION - CAD
estimates of O M casts for.the CCS (Adjustment 14 PE .(page 4))'based upon engineering
analysis. The estimates developed fQr the FGDs and the CCS for the period July 2009 through
June 2010 were used as the estimates for the July 2010 through June 2011 period.
d.-f. No updated forecast for the:July 2010 to June 2011 period has been done. A budget for
2011 is not expected to be available Until late this year. See the Company's response to item e.,
above.
g. The $579,775 amount was Wvertently shown on both the hard and electronic copies of
Statement 0-1, Adjustment 14-PE, page 4 of 4, It WBS not included in the amounts uied to
calculate Adjustment 14-PE. Conseq&ntly, it was not necessary for the formula embedded in cell
X.18 to remove that amount.
,
. .
. .
i :I
. ..
6 ;
. .
. I
';I :
, ,I
..

JDL Rebuttal Exhibit No. 3
Page 1 of 3
APPALACHIAN POWER COMPANY &
I
WHEELING POWR COMPANY 1
WEST VIRGINIA CASE NO, 10-0699-E-42T
FOURTH REQUEST FOR INFORMATION -
I
CAD
I
JhWt T-26 I 1
1
i
I
i
I
i
Please provide all studies, memoranda or other written documents refid upon by Mr. LaFleur to
cdculate the Labor and Non-Labor adjustment factors in Table 3 on Page 11 of his testimony.
I
Response T-26
Please see CAD 4 T-26, Attachment 1 for the escalation indexes used to convert 2007 budgeted
O&M costs to 2010 dollars in Table 3 of Mr LaFleur's testimony. The esdation rites used are
the US Bureau of Labor StatiSti~~ indices Electric Power Transmission, Distribution and
Generation Producer Price Index and the Utility Total Compensation Index found' on pages I and
2, respectively in the attachment.

Databases
FONT SIZE:
:3 @
'
US Bureau of Labor Statistics Indices
Industry: Electric power generation, transmirsbn, and distribution
nl.rq)r pKT3 [2008i
OutpVt ,
Options: From: .
T4:
p udegraphs .. .
Data ex~csu
an: December 8, 2009 (2:i9:12 PM)
Producer Price Index Industry Data .
Series Id: PCU2211-2211-
Industry: Electric power generation, trans~nlssion, and distribuiion
Product: Electric power generation, transmission, and distribution
Base Rate': 200312
Cahlations:
2007- Oct2008 (128.7) t Jan, 2007 (110.9) - 1
2008. Oct2008 (128.7) I Jan, 2008 (g23.6) - 1.
2008- W,2009 (128.7) I Jan, 2009 (129.7) - 1
Escalation Rates
10.1%
4.1%
4.8%

Page 2 of2
US Bureau of Labor Statistics indices
Industry: ud&b6 '
Series I+ ClU2O144OM)OooMll (B)
Not Seasonally Adjugted
compensatioli! Total compensation
ssctoc Private Industry .
periodicity: In&x number
Industryocc: Utilities
. . .
. , . ,
Escaiatlon
Calculations: Rates '
2007- ~tr3,2009 (I I 4 -2) I mi, 2007 (I a.sj I 8.17%
2008- .Qlr3.2009(I 11.2) I QW, 2008 (106.5) - 1 ' 4.4%
2000- Qtn,20~(111.2)1Qtr~,2009'(10Q.5) -1 I-#%
. .
c
3:
z
w

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
- - -~ REBU-T-TAL-TESTIMONY -
OF
JAMES D. FAWCETT
-

JDF Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
JAMES D. FAWCETT
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q*
2 A.
3 Q*
4
5 A.
6 Q*
7 A.
8
9
10
11
PLEASE STATE YOUR NAME.
My name is James D. Fawcett.
ARE YOU THE SAME JAMES D. FAWCETT WHO PRESENTED
DIRECT TESTIMONY IN THIS CASE
Yes.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
I will comment on and rebut various recommendations and adjustments presented
in the testimony of Staff witness Oxley and Consumer Advocate Division (CAD)
witness Smith as follows:
1. Amos Unit 2 and Unit 3 flue gas desulfurization units (FGDs or scrubbers)
-page 1
12
13
14
15
2.
3.
4.
Amos Unit 2 Reheater Replacement and Turbine Modification- page 3
Wheeling Network Improvements - page 4
Associated Business Development Net Margins - page 5
AMOS UNIT 2 AND UNIT 3 SCRUBBERS
16 Q.
17
18
19 A.
20
WHAT ARE THE STAFF AND CAD RECOMMENDATIONS
CONCERNING THE COMPANIES’ AMOS UNIT 2 AND UNIT 3 FGD
PROPOSALS
Staff witness Oxley in his testimony at page 7 states, “The Company has proposed
Units 2 and 3 costs be moved to base rates in this case, but to continue a
(R0543933.1)

Page 2 of 6
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2
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6 Q*
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8
9 A.
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14
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20
21
22
construction surcharge for Unit 1 into the future. Staff recommends the
Companies proposal be approved.” By recommending approval of the
Companies’ proposal, the Staff has accepted Terminal Treatment for these two
environmental projects. In contrast, CAD witness Smith disagrees that these
projects deserve Terminal Treatment.
DO YOU AGREE WITH THE CAD POSITION THAT THE
INVESTMENTS IN THE AMOS 2 AND AMOS 3 FGD SCRUBBERS DO
NOT DESERVE TERMINAL TREATMENT
No. Mr. Smith properly states on page 21, lines 4-6, of his testimony that the
Commission has approved Terminal Treatment for non-revenue producing and
non-expense reducing plant in the past. In my direct testimony, I identified the
Amos Unit 2 and 3 FGDs as environmental projects that do not produce revenue
or reduce expenses. The scrubbers do not generate any additional electricity that
can be sold to customers to produce additional revenues; in fact, they use quite a
lot of electricity for what is referred to as “parasitic” load to run all of the pumps,
stirring motors and other machinery that are needed for the FGDs operation. Nor
do the scrubbers reduce O&M expenses; to the contrary, the Amos Unit 2 and 3
FGDs add significant O&M expense. Because the Amos Unit 2 and 3 FGDs are
new pieces of equipment, separate from the generating plant, they have their own
maintenance costs. For example, parts wear out and need to be replaced and the
equipment has to be kept in working condition. Because the scrubbers are
operated separately f’rom the generating units themselves, they also have their
23 own operation costs associated with the employees who run the equipment. The

Page 3 of 6
1
2
3
4
5
6
7
8
9
10
11
Q.
A.
fact that APCo is earning a return on “Construction Work In Progress” (CWIP)
during the period the Amos Unit 2 and 3 FGDs are included in the Construction
Surcharge does not change the fact that the FGDs are non-revenue producing and
non-expense reducing investments that qualify for Terminal Treatment.
IF THE COMMISSION GRANTS TERMINAL TREATMENT FOR THE
AMOS UNIT 2 AND 3 FGDS, WILL THE CONSTRUCTION
SURCHARGE RELATED TO THESE PIECES OF EQUIPMENT
CONTINUE THROUGH JUNE 30,2011
Not under the Companies’ proposal. As I explained in my direct testimony, at
page 16, lines 12-17, the Construction Surcharge will continue to be collected
until such time as recovery of those costs is included in base rates.
12
13
14
15
AMOS UNIT 2 REHEATER REPLACEMENT AND TURBINE MODIFICATION
Q. ARE THE AMOS UNIT 2 REHEATER REPLACEMENT AND TURBINE
MODIFICATION PART OF THE OVERALL AMOS UNIT 2 FGD
PROJECT
16
17
18
19
20
21
22
A.
Yes. The Amos Unit 2 reheater replacement was part of the balanced draft
upgrade associated with the FGD Project. Due to the installation of its FGD,
Amos Unit 2 will be burning a higher sulfur coal. The new reheater will facilitate
the use of this higher sulfur coal and limit the amount of additional slag build up
associated with the burning of such coal. Consequently, the replacement was not
simply the installation of a new part, in place of a worn-out old part; it was an
integral element of a comprehensive environmental project.

Page 4 of 6
1
2
3
4
5
6 Q.
7
8
The installation of the upgraded turbine was also an integral part of the
Amos Unit 2 FGD retrofit. The turbine modification allows the unit to continue
producing at the generation output level at which it operated prior to installation
of the FGD equipment, and to produce the energy needed to meet the electrical
requirements of the FGD equipment.
OVER WHAT PERIOD OF TIME DID APCO INCUR COSTS FOR THE
AMOS UNIT 2 REHEATER REPLACEMENT AND TURBINE
MODIFICATION
v
9 A.
10
11
12
13
14
15
16 Q.
17
18 A.
19
20
21
APCo began incurring costs for the Amos Unit 2 reheater replacement and turbine
modification in 2006. By the time the Amos Unit 2 FGD went into service in
February 2010, APCo had spent $23.15 million and $7.4 million on the Amos
Unit 2 reheater replacement and turbine modification, respectively. I used these
actual Electric Plant In Service (EPIS) booked amounts, which were known at the
time of the Companies’ filing, in my adjustments shown on Statement G.
WHEELING NETWORK IMPROVEMENTS
WHAT ARE THE CAD AND STAFF POSITIONS ON THE WHEELING
NETWORK IMPROVEMENTS
The Staff and the CAD both recommend that any investment in the Wheeling
Network improvements, which are beyond the amounts included in the average
test year EPIS balances, not be considered when determining rate base because
they are not known and measurable.
22 Q. PLEASE EXPLAIN THE STATUS OF THE WHEELING NETWORK
23 IMPROVEMENTS.

Page 5 of 6
1
2
3
4
5
6
7
A. This project was completed just recently. The Companies included a
conservative adjustment in this case because of the amount of the
investment relative to Wheeling’s rate base and because the project was
on a fast track to completion. For the reasons I explain in my direct
testimony, page 15, lines 9-22, these investments meet the criteria for
Terminal Treatment.
ASSOCIATED BUSINESS DEVELOPMENT NET MARGINS
8
9
10
Q.
DO YOU AGREE WITH CAD WITNESS SMITH’S ADJUSTMENT TO
THE TEST YEAR ASSOCIATED BUSINESS DEVELOPMENT
MARGINS
11
12
13
14
A. No.
Q. YOU DO NOT ADDRESS ASSOCIATED BUSINESS DEVELOPMENT IN
YOUR DIRECT TESTIMONY. WHAT QUALIFICATIONS DO YOU
HAVE TO TESTIFY ON THIS SUBJECT
15
16
17
18
19
20
21
22
23
A.
Q.
A.
I was manager of Associated Business Development (“ABD’’) for the West
Virginia, Virginia, Tennessee, and Kentucky service areas of AEP from April
2001 to December 2008.
WHAT IS WRONG WITH MR. SMITH’S CALCULATIONS TO ADJUST
THE TEST YEAR ABD MARGINS
The Companies provided information to the CAD concerning ABD revenues and
expenses in their responses to CAD data requests E-10, and E-255. In the
response to E-1 0, the Companies did not pick up all revenues attributed to ABD
and therefore understated the margins for ABD in the test year. However, in their

Page 6 of 6
1
2
response to E-255, the Companies identified and corrected the errors in response
E-10. The Companies expressly noted in section c. of response E-255:
c. Note that 2009 revenue amounts and margins in the response to
CAD 13 E-255 Attachment 2 have been modified to $7.82 million
and $3.79. The 2009 ABD amounts are reflective of the situation
we face and expect to face in the foreseeable future.
Mr. Smith did not use the corrected information in his calculations; he used the
9
10
11
12
13
14 Q.
incorrect figure of $1,939,777 as the test year level of ABD margins. The correct
test year level of ABD margins provided in response E-255 is $3,787,414. This
amount is quite comparable to the five-year average of $3,670,955. If an
adjustment were made based on an average, it would actually increase the
Companies’ jurisdictional expense by $50,607.
DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
15 A. Yes.

~ -___
J
APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
--
-- - - __ __ _-_-- -
OF _ _-
HUGH E. MCCOY
- _- ___ -
_ -

HEM Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
HUGH E. MCCOY
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q. PLEASE STATE YOUR NAME, BUSINESS ADDRESS AND POSITION.
2 A. My name is Hugh E. McCoy. My business address is 1 Riverside Plaza,
3 Columbus, Ohio 43215. I am a Director of Accounting Policy and Research,for
4 the American Electric Power Service Corporation (AEPSC), a subsidiary of
5 American Electric Power Company, Inc. (AEP).
6 Q. WHAT ARE YOUR PRINCIPAL AREAS OF RESPONSIBILITY
7 A. I am responsible for performing accounting research, recommending accounting
8 policy and procedures, reporting on the financial effects of potential transactions,
9 and developing accounting instructions for certain non-routine transactions and
10 new accounting rules. In addition, I serve as AEP’s primary internal advisor with
11 regard to issues surrounding the accounting for employee benefits, including
12 pensions.
13 Q. WOULD YOU PLEASE REVIEW YOUR EDUCATIONAL
14 BACKGROUND AND PROFESSIONAL EXPERIENCE
15 A. Yes. I graduated magna cum laude from West Virginia University in 1977, with a
16 Bachelor of Science in Business Administration degree in Accounting.
17 From 1977 to 1981, I was employed by Peat, Marwick, Mitchell and Co.,
18 where I was promoted to Audit Supervising Senior. I have been a Certified
19 Public Accountant since 1979 and a member of the American Institute of
20 Certified Public Accountants since 1980.

Page 2 of 20
Since 1981, I have been employed by AEPSC. I served from 1981 to
early 1998 in Accounting Policy and Research, initially as a Treasury Staff
Accountant and beginning in 1989 as a Senior Treasury Staff Accountant. In
4
5
6
7
8
9 Q*
10
11 A.
12
13
14
15
16
17
18
19 Q.
20 A.
21
22
1998, I was promoted to Manager of Utility Ledgers for AEP’s operating
companies in Ohio. In 2000, I was promoted to Assistant Controller of Non-
Regulated Accounting. Following two years in that position and a one-year
rotational assignment to Corporate Finance, I returned to Accounting Policy and
Research in my current position in 2003.
HAVE YOU PREVIOUSLY FILED TESTIMONY BEFORE THIS OR
OTHER UTILITY COMMISSIONS
Yes, I have previously testified on retiree benefits accounting before the Public
Service Commission of West Virginia (Commission), the Indiana Utility
Regulatory Commission, the Public Service Commission of Kentucky, the
Louisiana Public Service Commission, the Michigan Public Service Commission,
the Public Utilities Commission of Ohio, the Oklahoma Corporation Commission,
the Tennessee Regulatory Authority, the Public Utility Commission of Texas, the
Virginia State Corporation Commission, and the Federal Energy Regulatory
Commission
WHAT IS THE PURPOSE OF YOUR TESTIMONY
I will present testimony on behalf of Appalachian Power Company (APCo) and
Wheeling Power Company (WPCo) (collectively the Companies) rebutting the
direct testimony of:

Page 3 of20
Staff witness Thomas D. Sprinkle with regard to inclusion of the
Companies’ prepaid pension asset in rate base and inclusion of the
Companies’ supplemental pension plan in pension cost.
Consumer Advocate Division (CAD) witness Ralph C. Smith with regard
to inclusion of the Companies’ prepaid pension asset in rate base,
inclusion of the Companies’ supplemental pension plan in pension cost,
and with regard to the amount of the Companies’ pension cost.
8 Q*
9 A.
10
11
12
13
14
WHAT EXHIBITS ARE YOU SPONSORING
I am sponsoring HEM Rebuttal Exhibit No. 2, which is my schedule of the effect
of additional pension contributions that were recorded as a prepaid pension asset
in reducing pension cost for the Companies’ customers. The amounts set forth on
that exhibit are total Company amounts before jurisdictional allocation. I am also
sponsoring HEM Rebuttal Exhibit No. 3, which is the final 2010 qualified pension
actuarial report dated September 2010.
15
16
17 Q.
18
19
20 A.
21
22
23 Q.
PREPAID PENSION ASSET
WHAT IS STAFF WITNESS SPRINKLE’S POSITION WITH REGARD
TO INCLUDING THE COMPANIES’ PREPAID PENSION ASSET IN
RATE BASE
Mr. Sprinkle recommends that the prepaid pension asset in the jurisdictional
amount of $65,187,25 1 be excluded from rate base based on the Commission’s
November 20,2009 order in Hope Gas’s Case No. 08-289-G-42T.
DOES CAD WITNESS SMITH MAKE THIS SAME ARGUMENT

Page 4 of 20
1 A.
2 Q*
3
4 A.
5
6
7
8
9 Q*
10
11 A.
12
13
14 Q.
15
16 A.
17
18
19
20
21
22
Yes, he does.
PLEASE REMIND US WHAT THE $65,187,251 PREPAID PENSION
ASSET REPRESENTS.
The $65,187,25 1 prepaid pension asset is the West Virginia jurisdictional amount,
on a thirteen-month average basis, of the Companies’ cumulative additional cash
pension contributions beyond the amount of the pension cost included in cost of
service. Most of the prepaid pension asset balance results from large pension
contributions made in 2005.
IS THE COMPANIES’ SITUATION COMPARABLE TO THAT OF HOPE
GAS
No. The Companies’ situation is quite different from the facts in the Hope Gas
case. The ratemaking treatment accorded Hope Gas should not be applied to the
Companies’ prepaid pension asset.
PLEASE DIFFERENTIATE BETWEEN THE SITUATIONS OF HOPE
GAS AND THE COMPANIES.
In Case No. 08-289-G-42T, Hope Gas was in the unusual situation of having a
union pension fund that was significantly overfunded and creating negative
pension cost (or pension income). However, neither the overfunded assets of the
union pension fund nor the resulting pension income were available to benefit
Hope Gas. The Commission decided in the Hope Gas case that the pension
income should be excluded from earnings and the overfimded net pension asset
should be excluded from rate base.

Page 5 of 20
1
2
3
4
5
6
7
8
9
10
11 Q.
12
13
14 A.
15
16
17
18
19 Q.
20 A.
21
22
23
The circumstances in the instant case are altogether different. The
Companies’ pension plan is not a union pension plan with its inherent additional
restrictions against employer access to significantly overfunded pension assets.
Moreover, the Companies’ pension plan is not overfunded at all but rather has a
significant funding shortfall. Further, the Companies’ pension plan has pension
cost instead of pension income. Finally, in the past when the Companies’ pension
plan created pension income for a few years, that pension income was available to
the Companies and properly offset other operating expenses to reduce cost of
service. Therefore, the pension cost and rate base decisions in the Hope Gas case
are not logically applicable to the Companies’ circumstances.
DOES MR. SMITH HAVE ADDITIONAL OBJECTIONS TO THE
INCLUSION OF THE COMPANIES’ PREPAID PENSION ASSET IN
RATE BASE
Yes. In addition to the Hope Gas decision that I have already addressed, Mr.
Smith has two objections to including the Companies’ prepaid pension asset in
rate base. The first is his argument that there is a pension liability instead of a
pension asset. Mr. Smith is incorrect, apparently as a result of a common
misconception about the term “pension asset.”
PLEASE EXPLAIN THAT MISCONCEPTION.
Pension accounting rules have two similar terms that have very different
meanings and very different proper accounting and ratemaking treatments but
which are often misconstrued to be equivalent. Those terms are “prepaid pension
asset” and “net pension asset.” Under the Financial Accounting Standards

Page 6 of 20
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Board’s (FASB) Statement of Financial Accounting Standards (FAS) No. 87,
Employers’ Accounting for Pensions, the cumulative amount of cash pension
contributions beyond the cumulative amount of periodic pension cost must be
recorded as a “prepaid pension asset.” This additional cash investment in the
pension plan beyond the amount of pension cost includable in cost of service
represents an investment that is necessary for utility service, that benefits
customers through reduced pension cost, and that should be included in rate base,
much like a cash investment in a substation. If instead the cumulative pension
cost exceeds cumulative pension contributions, the result under FAS 87 is an
accrued pension liability.
“Net pension asset,” however, is a funded status concept under FAS 158,
Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans. FAS 158 requires a once-per-year mark-to-market adjustment to the
balance sheet, but not to the income statement, to reflect the net funded status of
the pension plan. A “net pension asset” results when the fair market value of plan
assets exceeds the pension plan’s projected benefit obligation. A net pension
liability results when the plan is underfunded, or when the fair market value of
plan assets is less than the projected benefit obligation.
WHY DOES THE FAS 158 ADJUSTMENT NOT AFFECT THE INCOME
STATEMENT
The FASB provided the funded position mark-to-market adjustment to the
balance sheet under FAS 158 only to provide additional theoretical information to
financial analysts, but recognized that the income statement effect under FAS 87

Page 7 of 20
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was already the proper measure and timing of periodic pension cost. Since the
FAS 158 adjustment is a non-cash accrual mark-to-market adjustment, and since
FAS 87 produces the proper amount of pension cost as provided by generally
accepted accounting principles and is on an accrual accounting basis as required
by the Uniform System of Accounts adopted by the FERC and this Commission,
amounts under FAS 87 should be reflected for ratemaking purposes while
amounts under FAS 158 should not. Therefore, the FAS 87 “prepaid pension
asset” should be included for ratemaking purposes, but the FAS 158 “net pension
asset” or net pension liability should not be included for ratemaking purposes.
HAS THE REFERENCE SYSTEM FOR GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES BEEN MODIFIED RECENTLY
Yes, it has. However, throughout this testimony I continue to use the familiar
references such as FAS 87 because they are easier for most of us to remember.
Last year, the FASB reconfigured existing generally accepted accounting
principles into a single authoritative source called the FASB Accounting
Standards Codification (ASC). The ASC does not change existing generally
accepted accounting principles, but instead introduces a new structure organized
in a searchable on-line research system of topics and sections that is intended to
reduce the time and effort needed to research accounting rules. Although the
ASC does not change the substance of the existing rules, it does introduce a new
nomenclature to replace the old statement references. The FAS 87 pension rules
are now located in FASB ASC 715-30, and the FAS 158 defined benefit plans
rules are now located in FASB ASC 715-20.

Page 8 of 20
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IS IT POSSIBLE FOR AN EMPLOYER TO HAVE BOTH A FAS 87
PREPAID PENSION ASSET AND A FAS 158 NET PENSION LIABILITY
Yes. In fact, the Companies are in that very situation now. The FAS 87 prepaid
pension asset, or the amount of cumulative cash pension contributions beyond
cumulative pension cost, results mainly from making substantial contributions in
2005 in order to fully fund the pension obligation at that time. In 2005, APCo
contributed $127,787,891 and WPCo contributed $4,493,529. Subsequent to the
end of the test year, in 2010 the Companies made additional monthly
contributions that will total for all of 2010 $19,328,148 for APCo and $297,936
for WPCo. APCo also made an additional one-time contribution in September
2010 of $17,455,800.
The Companies' pension fund was fully funded following the 2005
contributions until the large investment market losses that occurred during the
2008 financial crisis. As a result, the pension plan currently is significantly
underfunded and has a FAS 158 net pension liability. The Companies resumed
pension contributions in January 2010.
Therefore, Mr. Smith is incorrect that the Companies' pension funding
shortfall means that there is no prepaid pension asset.
CAN YOU CONCEPTUALLY RECONCILE HOW AN ENTITY CAN
HAVE BOTH A PREPAID PENSION ASSET AND AN UNDERFUNDED
PENSION PLAN
Yes. The FAS 87 pension cost and prepaid pension asset rules provide incomesmoothing
deferrals of actuarial gains and losses so that unexpected changes are

Page 9 of 20
spread out over several years, thus reducing pension cost volatility. By contrast,
the FAS 158 funded position is a market value measure with no deferral or
smoothing. The difference between the two measures results from remaining
unamortized deferred losses that are smoothed under FAS 87 pension cost. If
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there were no further actuarial gains and losses going forward, the FAS 87 versus
FAS 158 difference would move toward zero over time.
WHAT IS MR. SMITH’S REMAINING OBJECTION TO INCLUDING
THE PREPAID PENSION ASSET IN RATE BASE
Mr. Smith claims that the prepaid pension asset has not reduced pension cost. His
assertion is absolutely incorrect. In fact, the additional pension contributions that
are recorded as a prepaid pension asset reduced pension cost that the Companies
are seeking to reflect in this case by nearly $15 million on a total Company basis.
PLEASE EXPLAIN HOW THE ADDITIONAL PENSION
CONTRIBUTIONS RECORDED AS A PREPAID PENSION ASSET
REDUCED PENSION COST.
The additional cash pension contributions that are recorded as a prepaid pension
asset benefit customers by reducing pension cost as a result of the investment
earnings on the additional fund assets. This has the effect of reducing fbture
pension cost under generally accepted accounting principles in an amount that
grows over time through compounding. As computed on HEM Rebuttal Exhibit
No. 2, the additional pension contributions recorded as a prepaid pension asset
reduced pension cost on a total Company basis by approximately $13,15 1,000 for
APCo and $679,000 for WPCo in 2009 and by approximately $14,203,000 for

Page 10 of 20
APCo and by $733,000 for WPCo in 2010. This is a total pension cost savings
for the Companies in 2010 of approximately $14,936,000. In other words, had
the Companies not made the additional pension contributions, the total amount of
2010 pension cost that the Companies would be seeking to reflect in the instant
case would be nearly $15 million higher, or $3 1,028,000 instead of $1 6,091,000.
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DO YOU HAVE ADDITIONAL COMMENTS ON MR. SMITH’S CLAIM
THAT PENSION COST FOR THE COMPANIES DID NOT DECLINE AS
A RESULT OF THE ADDITIONAL PENSION CONTRIBUTIONS
Yes. Mr. Smith’s testimony is inconsistent. In his testimony on prepaid pension
in rate base (pages 32 and 33), he asserts that the additional pension contributions
did not reduce pension cost because pension cost increased starting in 2009. He
makes this assertion even though he admits that the increase is “because of the
poor investment returns that occurred in the wake of the worldwide financial
crisis that began in 2008.” In sum, he acknowledges that another factor made it
difficult to see the savings from the additional contributions, but he still denies the
savings.
This is inconsistent with Mr. Smith’s testimony on pension expense, (page
73) in which he supports the Companies’ position when he states that “all other
things being equal, the better funded a pension plan is, the lower the pension
expense. This is because the larger expected return on plan assets serves to offset
pension expense in the pension expense equation.” As shown on HEM Rebuttal
Exhibit No. 2, the additional pension contributions reduced 2010 pension cost for
the Companies by nearly $15 million.

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MR. SMITH REFERRED TO THE EFFECT OF INVESTMENT LOSSES
DURING THE 2008 FINANCIAL CRISIS. HOW IS THIS EFFECT
REFLECTED IN THE COMPANIES’ PENSION COST
In accordance with FAS 87, the effect of investment gains or losses is deferred
and amortized to pension cost through a two-step process that phases in the effect
on pension cost over five years. First, investment return losses such as those from
2008 are added to the amortization base over a five-year period, such that 20
percent of the loss is included in amounts to be amortized over about ten years in
the first year following the loss, another 20 percent is added in the second year,
and so on, so that the effect of the amortized losses is twice as large in the second
subsequent year (2010 in this case), three times as large in the third subsequent
year, etc., than in the first subsequent year (2009). The resulting increased
pension cost in 2009,2010,201 1,2012, and 2013 all relates to the 2008
investment return loss.
Nevertheless, pension cost in each of these years and even in 2008 and
earlier years is significantly lower as a result of the additional pension
contributions recorded as a prepaid pension asset, as discussed earlier and as
shown on HEM Rebuttal Exhibit No. 2.
IF THE COMMISSION WERE TO DECIDE TO REMOVE THE
PREPAID PENSION ASSET FROM RATE BASE, ARE THERE
CORRESPONDING ADJUSTMENTS THAT ALSO SHOULD BE MADE
Yes, there are two. The first corresponding adjustment that should be made if the
Commission were to remove the prepaid pension asset from rate base is to remove

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the related deferred tax balance, also. Company witness Pyle addresses this issue
in his rebuttal testimony.
The other corresponding adjustment that should be made if the prepaid
pension asset is excluded from rate base is to remove from cost of service the
resulting pension cost savings from investment earnings on the additional
contributions. As shown on HEM Rebuttal Exhibit No. 2, the additional cash
pension contributions that are recorded as a prepaid pension asset reduced the
amount of pension cost that the Companies are seeking to reflect in the instant
case by nearly $15 million on a total Company basis. It would not be equitable to
include this pension cost savings for ratemaking purposes without also including
the cost of capital for the additional cash investment by including the prepaid
pension asset in rate base. If the companies are to be denied a return on this
additional cash investment, customers should not receive the resulting benefit of
reduced pension cost.
PENSION COST
WHAT DOES CAD WITNESS SMITH RECOMMEND WITH REGARD
TO PENSION COST
Mr. Smith recommends that pension cost be kept at the 2009 level and that the
cost of the supplemental pension plan that is included in pension cost be removed
from cost of service.
WHY DOES MR. SMITH PROPOSE TO REMOVE THE COST OF THE
SUPPLEMENTAL PENSION PLAN FROM COST OF SERVICE

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A. Mr. Smith claims that the Supplemental Employee Retirement Plan (SERP)
provides extra pension benefits to executives over and above the benefits of other
employees. Mr. Sprinkle makes the same argument.
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WHAT IS THE MAIN PURPOSE OF THE COMPANIES’
SUPPLEMENTAL PENSION PLAN
The main purpose of the Companies’ supplemental pension plan is to protect
higher paid employees from losing a portion of the pension benefits that the
Companies provide to all employees. The same pension benefit formula applies
to all employees regardless of pay level. Although some unaffiliated companies
may provide substantial extra benefits to executives through a SERP, the
Companies’ supplemental pension plan simply replaces the portion of pension
benefits that otherwise would be lost under the qualified plan ERISA funding
limits. So, the supplemental pension plan does not represent separate or extra
benefits for executives but rather avoids the loss of benefits available to all of the
Companies’ employees.
Mr. Smith makes this same error in referring on page 67 of his testimony
to the decision of the Arizona Commission, which disallowed additional
retirement benefits beyond those available to other employees. Again, in the
instant case the Companies’ situation is distinct from the Arizona circumstances
in that the purpose of the Companies’ SEW is not to provide additional benefits
but instead simply to replace benefits available to all employees that otherwise
would be lost.

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IF THE COMMISSION WERE TO DECIDE TO REMOVE SERP COST
FROM PENSION COST, IS MR. SMITH’S PROPOSED ADJUSTMENT
AMOUNT CORRECT
No. Mr. Smith proposes to remove a jurisdictional $3 13,046 from pension cost.
The correct adjustment to pension cost under his proposal is a credit or negative
cost of $294,532. Mr. Smith arrived at his $3 13,046 adjustment by mistakenly
adding the Companies’ jurisdictional test year SEW cost of $9,257 plus
jurisdictional AEPSC SEW cost allocated to the Companies of $303,789.
However, the AEPSC allocated amount was actually a credit rather than a cost.
Therefore, instead of adding to the Companies’ SERP cost, the AEPSC credit
more than offsets it, resulting in a net credit or negative cost of $294,532.
DID THE COMPANIES PROVIDE MR. SMITH WITH CORRECT
INFORMATION ABOUT THE AEPSC CREDIT
Yes. On pages 65 and 66 of his testimony Mr. Smith explains that the
Companies’ provided in discovery in response to CAD Question E-234 a schedule
showing that test year AEPSC SERP charges to the Companies were negative
amounts, or credits, which is correct. However, Mr. Smith then explains that he
thinks the negative amounts actually represent expenses instead of credits based
on positive SERP cost in the actuarial report. He is incorrect.
WHY WAS THE TEST YEAR AEPSC SEW COST THAT WAS
ALLOCATED TO THE COMPANIES A NEGATIVE AMOUNT, OR
CREDIT

Page 15 of 20
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AEPSC’s SEW cost includes two items, the first of which is the FAS 87 cost as
shown in the actuarial report, as noted by Mr. Smith. In addition, the AEPSC
SERP has a trust fund that does not qualify under accounting rules to be included
in FAS 87 cost. As a result, the effect of the SERP trust fund must be added to
FAS 87 SEW cost to arrive at total SERP cost for AEPSC. In the test year, the
funding portion had a credit from investment return that more than offset the FAS
87 SEW cost, resulting in an overall credit or negative expense for AEPSC’s
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SERP.
DOES ANOTHER WITNESS OF THE COMPANIES ALSO ADDRESS
THE APPROPRIATENESS OF INCLUDING THE SUPPLEMENTAL
PENSION PLAN COST IN THIS CASE
Yes, Company witness Carlin also addresses the SEW in his rebuttal testimony.
WHY DOES MR. SMITH RECOMMEND THAT PENSION COST BE
KEPT AT THE 2009 LEVEL INSTEAD OF USING 2010 PENSION COST
Mr. Smith states on page 70 of his testimony that 2009 pension cost and 2010
pension cost appear to be abnormally high and are not representative of normal
ongoing conditions. On pages 74 and 75, he recommends using 2009 pension
cost instead of 2010 pension cost while stating that “there are serious concerns
remaining regarding the 2009 test year amount of pension cost itself as being
abnormally high and perhaps is (sic) in need of a downward adjustment.” It is
illogical for Mr. Smith to claim that both 2009 pension cost and 2010 pension cost
are abnormally high and not representative of ongoing conditions and then to
recommend the use of 2009 pension cost.

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DOES MR. SMITH SUPPORT HIS CLAIM THAT 2009 AND 2010
PENSION COST ARE ABNORMALLY HIGH AND NOT
REPRESENTATIVE OF NORMAL ONGOING CONDITIONS
I did not find any evidentiary substantiation of that claim in Mr. Smith’s
testimony.
WHY DID THE COMPANIES’ PENSION COST INCREASE IN 2009 AND
2010
Pension cost increased in 2009 and 2010 as a result of the poor investment market
return during the financial crisis of 2008. As I discussed earlier in my rebuttal
testimony, the FAS 87 accounting rules defer and spread to future pension cost
the effects of actuarial losses such as the 2008 poor investment return.
Consequently, the effects of large fluctuations are smoothed instead of being
immediately and fully included in pension cost. This FAS 87 smoothing phases
in to the Companies’ pension cost the amortization of such losses so that the
negative effect of the 2008 investment return losses increases pension cost by a
greater amount during each year of the five-year phase-in period. Therefore, all
other things being equal, the 2008 losses will cause continuing pension cost
increases in 2009 through 2013 as the 2008 investment return losses are phased in
over five years and then amortized to pension cost over about ten years.
This same pension cost smoothing process, phasing in actuarial gains and
losses over five years and amortizing them over about ten years, has served to
decrease the Companies’ pension cost in the past. Mr. Smith points out that
pension cost over the past several years before 2009 was lower and that pension

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cost in 2002 and 2003 was negative. The negative pension cost in 2002 and 2003
resulted from large investment market gains during the late 1990s that were
smoothed under this same process.
ARE THE LOW PENSION COST AMOUNTS FROM SEVERAL YEARS
AGO INDICATIVE OF ONGOING COSTS IN THE FUTURE
No. The low pension cost several years ago reflected the deferral and
amortization smoothing of favorable investment returns from many years earlier.
The current balance of remaining unamortized actuarial gains and losses is
dominated by the large 2008 investment return losses, which were first amortized
to increase pension cost in 2009 and which will continue to increase pension cost
during the five-year phase-in period through 2013. It is important to note that the
2008 investment return losses that are increasing pension cost in 2009 through
2013 are not speculation but are the result of a past event that is known and
measurable. Since 2010 represents only the second post-2008 year of the fiveyear
phase-in period, it would be more proper to say that 2010 pension cost is
significantly below ongoing pension cost over the next few years, again based on
known and measurable events.
MR. SMITH POINTS OUT THAT THE JUNE 2010 QUALIFIED
PENSION ACTUARIAL REPORT THAT THE COMPANIES PROVIDED
IN DISCOVERY IN RESPONSE TO CAD QUESTION E-162 IS MARKED
ON THE COVER “DRAFT- INFORMATION PROVIDED IN REPORT
WILL NOT BE CONSIDERED FINAL UNTIL FUNDED TARGET
ATTAINMENT PERCENTAGE UNDER PPA IS REQUESTED AND

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CERTIFIED.” DOES THAT MEAN THAT THE PENSION COST
NUMBERS IN THE REPORT ARE TENTATIVE
No. The pension cost amounts included in the June 2010 actuarial report are final
amounts that have not changed. In addition to FAS 87 pension cost information
that is used to record pension cost on the Companies’ books, the 2010 qualified
pension actuarial report also addresses separate ERISA measures that cannot be
finalized until all Pension Protection Act measures are finalized later in the year.
Those measures, which are separate from the FAS 87 pension cost amounts, are
the reason that the earlier actuarial report was marked draft. The final 2010
qualified pension report, dated September 2010, is attached as HEM Rebuttal
Exhibit No. 3.
MR. SMITH CLAIMS THAT THE COMPANIES MADE NO PENSION
CONTRIBUTIONS DURING 2006 THROUGH 2009 EVEN THOUGH
SOME LEVEL OF PENSION COST WAS INCLUDED IN COST OF
SERVICE IN THE PRIOR RATE CASE. SHOULD THE COMPANIES
HAVE BEEN EXPECTED TO MAKE PENSION CONTRIBUTIONS IN
THOSE YEARS
No. Pension contributions in each year should not be expected to match the
pension cost level in the last rate case. Mr. Smith fails to recognize that the
Companies in 2005 made pension contributions of over $132 million, an amount
that would cover much more than four years (2005 through 2009) if such a
measure were appropriate. However, pension cost is determined under generally
accepted accounting principles, while required pension contributions are governed

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by ERISA, income tax law, and the Pension Protection Act. Accordingly, pension
cost and pension contributions rarely match.
Fortunately, FAS 87 automatically makes appropriate adjustment for the
difference between pension cost and pension contributions in a way that makes
both the Companies and their customers whole.
PLEASE EXPLAIN HOW BOTH THE COMPANIES AND THEIR
CUSTOMERS ARE MADE WHOLE UNDER THE COMPANIES’
PROPOSED RATEMAKING TREATMENT.
As I discussed earlier, under FAS 87 additional pension contributions beyond the
amount of pension cost are recorded as a prepaid pension asset, which is a cash
investment that, if significant, should be included in rate base; pension
contributions which are less than pension cost are recorded as an accrued pension
liability that, if significant, should be included as a rate base reduction. Thus, if a
utility makes pension contributions over time that are less than the amount of
pension cost included in cost of service, the extra cash not contributed to the
pension fund serves as a rate base reduction. In the opposite circumstances,
which match the Companies’ present situation, if a utility’s cash pension
contributions are more than the amount of pension cost, the additional cash
investment is added to rate base to cover the utility’s cost of capital for the
additional cash contribution. The beauty of this pension accounting treatment
under FAS 87 is that both the utility and its customers are treated equitably
without any need to keep special track of varying pension cost and pension
contributions over the years.

Page 20 of 20
1 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
2 A. Yes.

Effect of Additional Pension Contributions Recorded As Prepaid Pension Asset in Reducing Pension Cost
Total Company Amounts Before Jurisdictional Allocation
HEM Rebuttal Exhibit No. 2
Plan Investment Return Balance of
Contribution Rate Amount Plan Assets
Plan Investment Return Balance of
Contribution Rate Amount
Plan Assets
Prepaid Pension Balance from 2005 Contributions 127,787,891 129,298,224 4,493,529
6,674,930
2006 Return on 2005 Balance 8.50% 10,990,349 140,288,573 8.50% 567,369 7,242,299
2007 Return on 2006 Balance 8.50% 11,924,529 152,213,102 8.50% 615,595 7,857,894
2008 Return on 2007 Balance 8.00% 12,177,048 164,390,150 8.00% 628,632 8,486,526
2009 Return on 2008 Balance 8.00% 13,151,212 177,541,362 8.00% 678,922 9,165,448
2010 Return on 2009 Balance 8.00% 14,203,309 19 1,744,67 1 8.00% 733,236 9,898,684
Prepaid Pension Balance at December 2009
mirteen Month Average Balance 134,526,480
~~
6,674,930
6,744,158
Actual Pension Cost
Prepaid Contribution Savings Above
Pension Cost Without Contribution Savings
2009 2010
10,496,246 15,830,669
13,151,212 14,203,309
23,647,458 30,033,978
--
2009 2010
139,438 260,487
678,922 733,236
818,360 993,723
Note: This schedule computes the pension cost savings from the additional pension contributions that were recorded as prepaid pension asset based on additional trust fund investment earnings
following the large 2005 contributions.

American Electric Power System
Retirement Plan
Actuarial Valuation Report
Pension Cost for Fiscal Year Ending December 31,2010
Employer Contributions for Plan Year Beginning January I, 201 0
September 201 0
This report is confidential and intended solely for the information and benefit of the immediate recipient thereof. It may not be distributed to
a third party unless expressly allowed under the "Actuarial Certification, Reliances and Distribution" section herein.
TOWERS WATSON -

Table of Contents
Management Summary of Valuation Results ...................................................
Supplemental In formation ...................................................................................
Miscellaneous by Location .................................................................................
MS
SI
ML
TOWERS WATSON -

Management Summary of Valuation Results
Financial Results ............................................................................................. m5-1
FAS 87 Pension Cost and Funded Position ................................................... m5-2
Employer Contributions and EIUSA Funded Position . m5-5
Basis for Valuation .......................................................................................... m5-9
Actuarial CertiJication. Reliances and Distribution . m5-10
TOWERS WATSON .

MS- 1
Financial Results
This report summarizes financial results for American Electric Power System’s Retirement Plan based
on actuarial valuations for fiscal 2010 (fiscal year ending December 31,2010) and fiscal 2009 and for
plan year 20 10 (plan year beginning January 1,20 10) and plan year 2009.
Pension Cost
Amount
Funded Position
Projected benefit obligation [PBO]
Fair value of assets [FV]
Overfunded (underfunded) PBO
PBO funded percentage [FV + PBO]
Fiscal 2010
$ 132,598,976
January I, 2010
$ 4,499,732,489
3,403,606,388
(I,096,126,101)
75.6%
Fiscal 2009
$ 86,074,595
January Is 2009
$ 4,232,544,398
3,156,051 ,I 05
(1,076,493,288)
74.6%
Employer Contributions
Minimum funding requirement
Remaining cash requirement (assuming
sponsor uses available credit balance)
Maximum deductible contribution*
Plan Year 2010
239,570,523
0
2,407,429,808
Plan Year 2009
107,877,356
0
1,882,722,791
ERISA Funded Position
Funding target
Net actuarial value of assets
Funding shortfall/( excess assets)
Funding target attainment percentage for
participant funding notice
Actuarial value of assets
Actuarial value of assets as a percentage
of funding target
* Estimated amount, pending issuance of TreasuryhRS guidance.
3,999,133,748
3,201,584,739
797,549,009
80.1 %
3,731,427,671
93.3%
3,453,898,445
2,907,253,845
546,644,600
100.5%
3,471,656,216
100.5%
American Electric Power System Retirement Plan, September 2010
-
TOWERS WATSON 1/L/

MS-2
FAS 87 Pension Cost and Funded Position
The cost of the pension plan is determined in accordance with generally accepted accounting principles
in the U.S. (“U.S. GAAP”). The fiscal 2010 pension cost for the plan is $132,598,976, or 7.9% of
covered pay.
Under U.S. GAAP, the funded position (fair value of plan assets less the projected benefit obligation, or
“PBO”) of each pension plan at fiscal year-end is required to be reported as an asset (for overfunded
plans) or a liability (for underfunded plans). The PBO is the actuarial present value of benefits attributed
to service rendered prior to the measurement date, measured using expected hture pay increases for
pay-related plans. The plan’s overfunded (underfunded) PBO as of January 1 , 20 10, was
$(1,096,126,101), based on the fair value of plan assets of $3,403,606,388 and the PBO of
$4,499,732,489.
Fiscal year-end financial reporting and disclosures are prepared before detailed participant data and the
full valuation results are available. Therefore, the postretirement benefit asset (liability) at December 3 1 ,
2009, was derived from January 1 , 2009, valuation results. The fiscal year-end 20 10 financial reporting
information will be developed based on the results of the January 1 , 20 10, valuation, rolled forward to
the end of 2010 and adjusted for the year-end discount rate and asset values, as well as significant
changes in plan provisions and participant population.
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

Change in Pension Cost and Funded Position
MS-3
The pension cost increased from $86,074,595 in fiscal 2009 to $132,598,976 in fiscal 2010 and the
hnded position deteriorated slightly from $( 1,076,493,288) on January 1,2009, to $( 1,096,126,101) on
January 1 , 20 10, as set forth below:
Prior year
Change due to:
Pension Cost
Funded
Position
$ 86,074,595 $ (1,076,493,288)
b Expected based on prior valuation and
.
contributions
Unexpected noninvestment
(7,165,379) (29,981,976)
experience (16,004,325) 86,775,402
.
b Unexpected investment experience 51,821,078 166,103,182
Assumption changes 17,873,007 (242,529,421)
b Plan amendments 0 0
Current year $ 132,598,976 $ (1,096,126,101)
Significant reasons for these changes include the following:
The return on the fair value of plan assets since the prior measurement date was greater than
expected, which improved the funded position.
The return on the market-related value of plan assets, which reflects gradual recognition of asset
gains and losses over the past five years, was less than expected, which increased the pension cost.
The plan experienced demographic gains which reduced the pension cost and improved the funded
position.
The salary increase rate, termination rate, retirement rate and form of payment assumptions were
updated to reflect the results of AEP’s recent experience study. Also, the methodology used to value
disability benefits changed per PPA regulations and were subsequently adopted by AEP for
accounting purposes as well. These combined changes increased the pension cost and caused the
funded position to deteriorate.
The discount rate declined 40 basis points compared to the prior year which increased the pension
cost and caused the funded position to deteriorate.
American Electric Power System Retirement Plan, September 2010
TOWERS WATSON -

MS-4
History of Pension Cost and Funded Position
The following table shows the history of the plan’s pension cost and funded position.
Fiscal
year
History of Pension Cost and PBO Funded Percentage
--__-_- Pension cost - - - - - - -
Percent of Funded Discount
Amount covered pay position rate
201 0 $ 132,598,976 7.9% (1,096,126,101) 5.60%
2009
86,074,595
5.3 (1,076,493,288) 6.00
2008
41,836,053
2.7 334,31 6,983 6.00
2007 40,454,930 2.8 299,752,151 5.75
2006 61,344,648 4.4 (45,745,159) 5.50
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

MS-5
Employer Contributions and ERISA Funded Position
Under the Pension Protection Act of 2006 (PPA), the funded position is measured by comparing the net
actuarial value of assets (actuarial value of assets reduced by the plan’s credit balance) with the funding
target. The amount by which the funding target exceeds the net actuarial value of assets is the plan’s
funding shortfall. If the net actuarial value of assets exceeds the funding target, the difference is the
plan’s excess assets. The actuarial value of assets is an average of the fair market value over a sixmonth
period, adjusted for contributions, disbursements, and expected earnings. The funding target is
the present value of benefits accrued or earned as of the valuation date. The target normal cost is the
present value of benefits expected to be earned during the plan year plus the amount of plan-related
expenses expected to be paid from plan assets during the year. Plans that do not meet certain funded
status criteria are considered to be at-risk and are required to use specific actuarial assumptions, and in
some cases additional loads, that will generally increase the funding target and target normal cost.
The plan’s funding shortfall is $797,549,009 as of January 1,2010. The plan’s actuarial value of assets,
including the credit balance, is 93.3% of the funding target as of January 1 , 201 0. This percentage is
based on an actuarial value of assets of $3,731,427,671 and a funding target of $3,999,133,748.
The minimum funding requirement under PPA is generally equal to the target normal cost plus
amortization of the plan’s funding shortfall and any funding waivers. For overfunded plans, the
minimum finding requirement is reduced by the amount of the plan’s excess assets. The minimum
funding requirement for the 2010 plan year, before reflecting any credit balance elections, is
$239,570,523 (including a shortfall amortization charge of $107,110,851), or 14% of covered pay.
Plan sponsors that have in the past contributed more than the minimum may have a credit balance.
Sponsors can elect to apply the plan’s credit balance to offset the minimum funding requirement if
certain other requirements are met. If AEP elects to fully apply its available credit balance, the
remaining cash requirement is $0.
The maximum deductible contribution under PPA is generally equal to 150% of the funding target, plus
the target normal cost, plus an allowance for future pay or benefit increases, less the actuarial value of
assets. For plans that are not at-risk, the deductible limit will not be less than the unfunded funding
target plus the target normal cost, both determined as if the plan were at-risk. For all plans, the
deductible limit will not be less than the minimum funding requirement. Pending issuance of
TreasuryhRS guidance, the estimated maximum deductible contribution for the plan is $2,407,429,808.
American Electric Power System Retirement Plan, September 201 0
-
TOWERS WATSON ch/

MS-6
Change in Minimum Funding Requirement and Funding Shortfall
The minimum fbnding requirement increased fiom $107,877,356 for the 2009 plan year to $239,570,523
for the 20 10 plan year, and the funding shortfall increased fiom $546,644,600 on January 1 , 2009, to
$797,549,009 on January 1,2010, as set forth below:
Prior year
.
Change due to:
Expected based on prior valuation and
.
contributions
Unexpected noninvestment
experience
.
Unexpected investment experience
Assumption changes
t Plan amendments
Current year
Minimum
Funding
Funding
Requirement
Shortfall
$ 107,877,356 $ 546,664,600
6,364,764 (530,056,596)
(6,584,386) 34,262 ,O 14
0 222,64335 1
131,912,789 524,055,440
0 0
$ 239,570,523 $ 797,549,009
Significant reasons for these changes include the following:
t
.
t
.
The return on the actuarial value of assets, which reflects a gradual recognition of investment gains
and losses over the past six months since the prior valuation was less than expected, which increased
the finding shortfall.
The fbnded interest rate methodology was changed fiom using the yield curve published in
November 2008 (October 2008 yield curve) to the segment rates published in October 2009, which
increased both the minimum fbnding requirement and the hnding shortfall.
The salary increase rate, termination rate, retirement rate and form of payment assumptions were
updated to reflect the results of AEP’s recent experience study. Also, the methodology used to value
disability benefits changed per PPA regulations and were subsequently adopted by AEP for
accounting purposes as well. These combined changes increased both the minimum fbnding
requirements and fbnding shortfall.
The plan experienced demographic gains which reduced the minimum fbnding requirement.
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

MS-7
Employer Contributions and ERISA Funded Position
The following table shows the history of employer contributions and the funding range for the American
Electric Power System Retirement Plan, as well as the ERISA funded position.
History of Employer Contributions and ERISA Funded Position
and Current YeaPs Funding Range
----- Employer contributions - - - - -
AVA as a %
Percent of of funding
Plan Year
Amount covered pay target*
.
2010
Minimum** $ 0 0% 93.3%
t Maximumt 2,407,429,808 144.2
2009 462,500,000 27.7 100.5
2008 0 0 109.3
2007 0 0 104.2
2006 0 0 104.6
Effective
interest
rate*
6.56%
8.23
5.93
5.78
5.77
* Results prior to 2008 are based on the pian’s current liability.
** Remaining cash requirement assuming sponsor elects full use of available credit balance.
t Estimated amount, pending issuance of TreasuryliRS guidance.
Timing of Contributions
The minimum required contribution for the 2010 plan year is determined as of the plan’s valuation date
and must be partially satisfied in quarterly installments, with a final payment due on or before
September 15,2011. These requirements may be satisfied through contributions and or an election to
apply available credit balance. Any payment made on a date other than the valuation date is adjusted for
interest using the plan’s effective interest rate.
The minimum funding schedule, before reflecting any credit balance elections, is shown below:
April 15, 2010 $ 26,969,339
July 15, 2010 26,969,339
October 15,2010 26,969,339
January 15,2011 26,969,339
September 15,2011 151,663,184
If a plan has a hnding shortfall for the current plan year, quarterly contributions will be required in the
following plan year. Because the plan has a funding shortfall, quarterly contributions for the 2011 plan
year will be required but will not exceed $59,900,000 per payment, based on this year’s valuation
results.
TOWERS WATSON
American Electric Power System Retirement Plan, September 2010
-

MS-8
Benefit Limitations
Under PPA, a plan may become subject to various benefit limitations if its funded status falls below
certain thresholds. Plan amendments that increase benefits are prohibited if the effect of the amendment
would be to reduce the adjusted funding target attainment percentage (AFTAP) below 80%. Benefit
accruals must cease and shutdown benefits are prohibited if the AFTAP falls below 60%. To avoid these
benefit limitations, a plan sponsor may either contribute certain additional amounts for the current plan
year or provide security outside the plan.
Plans are prohibited from paying lump sums or other accelerated forms of distribution if the AFTAP is
below 60%, and only reduced amounts are allowed to be paid if the AFTAP is between 60% and 80%.
This limitation does not apply to mandatory lump sum cash-outs of $5,000 or less.
The AFTAP for AEP is 80.1% as of January 1,2010.
PBGC Reporting Requirements
Certain financial and actuarial information (ie., a “4010 filing”) is required to be provided to the PBGC
if the funding target attainment percentage (FTAP) for the year is less than 80% for any plan in the
contributing sponsor’s controlled group. However, this reporting requirement may be waived for
controlled groups with no more than $15 million in aggregate plan underfunding.
The FTAP for AEP is 80.1% as of January 1 , 2010. Since the FTAP is at least 80%, no 4010 filing will
be required for 2011.
-
TOWERS WATSON I/L/ American Electric Power System Retirement Plan, September 2010

MS-9
Basis for Valuation
Economic Assumptions
The discount rate for pension cost purposes lD the rate at which the pension obligations could be
effectively settled. This rate is developed from yields on available high-quality bonds and reflects the
plan's expected cash flows.
The assumed rate of return on assets, the cash balance interest crediting rate and salary increase rate
assumptions both reflect long-term expectations. The assumed rate of return on assets for pension cost
purposes is the weighted average of expected asset returns. The salary increase rate is based on current
expectations of future pay increases. The assumptions selected by American Electric Power for pension
cost purposes are:
December 31,2009 December 31,2008
Discount rate
5.60% 6.00%
Rate of return on assets 8.00% 8.00%
Cash balance interest
crediting rate
5.25% 5.25%
Salary increase rate
Rate vary by age
Rate vary by age
from 3.5% to 11 -5% from 5.0% to 115%
Assumptions used to determine statutory contribution limits must be reasonable taking into account the
experience of the plan and reasonable expectations. However, certain assumptions (such as interest and
mortality) are either prescribed by the IRS or are subject to IRS approval. The interest rates used to
determine the funding target and target normal cost are based on a high-quality corporate bond yield
curve. The assumptions for contribution purposes are:
Effective interest rate
Cash balance interest
crediting rate
Salary increase rate
January I, 2010 January I, 2009
6.56% 8.23%
Rate vary by age
from 3.5% to 11.5%
5.25% 5.50%
Rate vary by age from
5.0% to 11 3%
Demographic Assumptions
The cost of providing benefits takes into consideration demographic factors such as rates of retirement,
mortality and turnover. Demographic assumptions used in accounting and ERISA finding valuations
are summarized in the Supplemental Information section.
American Electric Power System Retirement Plan, September 2010
-
TOWERS WATSON

MS-10
Actuarial Certification, Reliances and Distribution
American Electric Power System (“AEP”) retained Towers Watson Pennsylvania Inc. (“Towers
Watson”), to perform valuations of its pension plans for the purpose of determining (1) the value of
benefit obligations and its pension cost in accordance with FASB ASC 715-30 (formerly FAS 87) and
(2) the minimum required and maximum tax-deductible contributions in accordance with ERISA and
allowed by the Internal Revenue Code. These valuations have been conducted in accordance with
generally accepted actuarial principles and practices.
The consulting actuaries are members of the Society of Actuaries and other professional actuarial
organizations and meet their “Qualification Standards for Actuaries Issuing Statements of Actuarial
Opinion in the United States” relating to pension plans.
In preparing the results presented in this report, we have relied upon information provided to us
regarding plan provisions, plan participants, and plan assets. We have reviewed this information for
overall reasonableness and consistency, but have neither audited nor independently verified this
information. The accuracy of the results presented in this report is dependent upon the accuracy and
completeness of the underlying information.
The actuarial assumptions and the accounting policies and methods employed in the development of the
pension.cost have been selected by the plan sponsor, with the concurrence of Towers Watson. FASB
ASC 715-30-35 requires that each significant assumption “individually represent the best estimate of a
particular future event.”
To the extent not prescribed by ERISA, the Internal Revenue Code and regulatory guidance from the
Treasury and the IRS , the fbnding methods (including asset valuation method, choice among prescribed
interest rates, and choice among prescribed mortality tables) employed in the development of the
contribution limits have been selected by the plan sponsor, with the concurrence of Towers Watson. To
the extent not prescribed by ERISA, the Internal Revenue Code and regulatory guidance fiom the
Treasury and the IRS, the actuarial assumptions employed in the development of the contribution limits
have been selected by Towers Watson, with the concurrence of the plan sponsor. Other than prescribed
assumptions, ERISA and the Internal Revenue Code require the use of assumptions each of which is
“reasonable (taking into account the experience of the plan and reasonable expectations), and which, in
combination, offer the actuary’s best estimate of anticipated experience under the plan.”
The results shown in this report have been developed based on actuarial assumptions that, to the extent
evaluated or selected by Towers Watson, are considered reasonable by us and within the “best-estimate
range” as described by the Actuarial Standards of Practice. Other actuarial assumptions could also be
considered to be reasonable and within the best-estimate range. Thus, reasonable results differing fiom
those presented in this report could have been developed by selecting different points within the bestestimate
ranges for various assumptions.
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

MS-11
The information contained in this report was prepared for the internal use of AEP and its auditors in
connection with our actuarial valuations of the pension plan. It is neither intended nor necessarily
suitable for other purposes. AEP may also distribute this actuarial valuation report to the appropriate
authorities who have the legal right to require AEP to provide them this report, in which case AEP will
use best efforts to notify Towers Watson in advance of this distribution. Further distribution to, or use
by, other parties of all or part of this report is expressly prohibited without Towers Watson’s prior
written consent.
Towers Watson
September 20 10
A
American Electric Power System Retirement Plan, September 2010
-
TOWERS WATSON

Supplemental In formation
Asset Values ......................................................................................................... -1
Basic Results for Pension Cost and Funded Position ..................................... 5i-2
Pension Cost ...................................................................................................... 5i-4
Present Value of Accumulated Plan Benefits for Plan Reporting ................. 51-5
Basic Results for Minimum Required Employer Contribution . 51-6
Minimum Required Employer Contribution .................................................... SI- 7
Basic Results for Maximum Deductible Employer Contribution ................... 51-8
Maximum Deductible Employer Contribution ................................................ 51-9
Funded Status for Benefit Limitations ........................................................... 51-1 0
Actuarial Assumptions and Methods .............................................................. 51-1 1
Participant Data .............................................................................................. 51-16
Plan Provisions .................................................................................................. -20
TOWERS WATSON
.

SI-1
Asset Values
Asset Values for Calculating
Pension Cost and Funded Position
Fair value (excludes
contributions receivable):
As of January 1,2009
Contributions
Disbursements
Investment return
.
AsofJanuary1,2010
Rate of return
Market-related value:
As of January 1,2009
.
As of January 1,2010
Rate of return
Asset Values for Calculating
Employer Contributions
Market value, including
contributions receivable:
.
As of January 1,2009
Contributions*
Disbursements
Investment return
.
As of January 1,2010
Rate of return
Actuarial value:
As of January 1,2009
.
As of January 1,2010
Rate of return
$ 3,156,051,105
0
(239,941,I
87)
487,496,470
$ 3,403,606,388
16.06%
$ 4,207,584,469
4,003,715,650
0.88%
$ 3,156,051,105
440,035,409
(239,941,I
87)
487,496,470
$ 3,843,641,797
16.06%
$ 3,471,656,216
3,731,427,671
1.78%
*Discounted to January 1, 201 0, using effective interest rate for plan year 2009.
American Electric Power System Retirement Plan, September 2010
TOWERS WATSON
-

SI-2
Basic Results for Pension Cost and Funded Position
Fiscal 2010 Fiscal 2009
Service Cost
Amount
I
$ 109,179,598 $ 102,723,635
a
Obligations
Accumulated
.
benefit obligation [ABO]:
Participants currently receiving
benefits
.
Deferred inactive participants
Active participants
Total AB0
Obligation due to future salary increases
Projected benefit obligation [PBO]
Assets
Fair value [FV]
Unamortized investment losses (gains)
Market-related value
Funded Position
Overfunded (underfunded) PBO
PBO funded percentage
Amounts Not Yet Recognized in
Net Periodic Cost
Net actuarial loss (gain)
Prior service cost (credit)
Transition obligation (asset)
Total
$ 1,959,944,060 $ 1,916,732,391
303,903,649 232,490,752
2,148,943,751 1,974,284,956
$ 4,412,791,460 $ 4,123,508,099
86,941,029 109,036,294
$ 4,499,732,489 $ 4,232,544,393
$ 3,403,606,388 $ 3,156,051,105
600,109,262 1,051,533,364
$ 4,003,715,650 $ 4,207,584,469
$ (1,096,126,101) $ (1,076,493,288)
75.6% 74.6%
$ 1,955,167,746 $ 2,021,497,870
10,245,330 10,356,988
0 0
$ 1,965,413,076 $ 2,031,854,858
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

SI-3
Key Economic Assumptions
Discount rate
Rate of return on assets
Cash balance interest crediting rate
Salary increase rate
Fiscal 2010 Fiscal 2009
Rates vary by age
from 3.5% to 11.5%
5.60% 6.00%
8.00% 8.00%
5.25% 5.25%
Rates vary by age
from 5.0% to 11.5%
The results above may differ from the amounts disclosed in AEP's 2009 financial statements because
disclosures are prepared before the corresponding valuation results are available.
American Electric Power System Retirement Plan, September 2010
-
TOWERS WATSON ch/

SI-4
Pension Cost
Pension Cost
Service cost
Interest cost
Expected return on assets
Amortization:
Transition obligation (asset)
.
Prior service cost (credit)
Net loss (gain)
Pension cost
Percent of covered pay
Per active participant
Fiscal 2010
$ 109,179,598
248,990,578
(312,808,907)
0
684,658
86,553,049
$ 132,598,976
7.9%
$ 6,346
Fiscal 2009
$ 102,723,635
248,651,629
(321,393,288)
0
I1 1,658
55,980,96 1
$ 86,074,595
5.3%
$ 4,192
Change in Pension Cost
Pension cost for fiscal 2009
Change from fiscal 2009 to fiscal 2010:
.
b Expected based on prior valuation
Loss (gain) from noninvestment experience
Loss (gain) from asset experience
.
b Assumption changes
Plan amendments
Pension cost for fiscal 2010
$ 86,074,595
(7,165,379)
(1 6,004,325)
51,821,078
17,873,007
0
$ 132,598,976
TOWERS WATSON -
American Electric Power System Retirement Plan, September 2010

SI-5
Present Value of Accumulated Plan Benefits for Plan Reporting
January I, 201 0 January I, 2009
Actuarial Present Value of
Accumulated Plan Benefits
Vested benefits:
b
b
b
Participants currently receiving benefits
Other participants
Total vested benefits
Nonvested benefits
Total accumulated benefits
Fair value of assets (including contributions
receivable)
Key Assumptions
Interest rate
Cash balance interest crediting rate
Average retirement age
Mortality
$ 1,655,388,995
1,833,477,815
$ 3,488,866,810
37,357,024
$ 3,526,223,834
3,866,106,388
8.00%
5.25%
61
2010 IRS AMT
$ 1,665,510,496
1,860,424,545
$ 3,525,935,041
45,840,797
$ 3,571,775,838
3,156,051,105
8.00%
5.50%
60
2009 IRS AMT
Change in Actuarial Present Value of
Accumulated Plan Benefits
Actuarial present value of accumulated plan
benefits as of January 1,2009
.
Change from 2009 to 2010:
Additional benefits accumulated (including the
.
effect of noninvestment experience)
Interest due to decrease in the discount period
Benefits paid
.
Assumption changes
Plan amendments
Actuarial present value of accumulated plan
benefits as of January 1,2010
$ 3,571,775,838
(I 9,157,046)
293,611,395
(239,941,I
87)
(80,065,166)
0
$ 3,526,223,834
American Electric Power System Retirement Plan, September 2010
TOWERS WATSON
-

~ 6.56%
SI-6
Basic Results for Minimum Required Employer Contribution
Normal Cost and Liabilities
Normal cost
Funding target [FT]:
t Participants currently receiving
benefits
.
Deferred inactive participants
Active participants
Total funding target
Assets
Market value
Unrecognized investment losses (gains)
Actuarial value [AVA]
Credit Balance
Funding standard carryover balance
Prefunding balance
Total credit balance [CB]
ERISA Funded Position
Net actuarial value of assets [AVA - CB]
Funding shortfall/(excess assets)
[FT - (AVA - CB)]
Assets, including credit balance, as a
percentage of funding target [AVA + FT]
Key Economic Assumptions
Effective interest rate
Cash balance interest crediting rate
Salary increase rate
January I, 2010
$ 132,459,672
!§ 1,836,183,930
248,566,060
1,914,383,758
$ 3,999,133,748
$ 3,843,641,797
(1 12,214,126)
$ 3,731,427,671
$ 529,842,932
0
$ 529,842,932
$ 3,201,584,739
797,549,009
93.3%
5.25%
Rates vary by age
from 3.5% to 11 5%
January I, 2009
$ 107,877,356
$ 1,629,202,107
171,496,932
1,653,199,406
$ 3,453,898,445
$ 3,156,051,105
31 5,605,111
$ 3,471,656,216
$ 564,402,37 1
0
$ 564,402,37 1
$ 2,907,253,845
546,644,600
100.5%
8.23%
5.50%
Rates vary by age
from 5.0% to I 1 5%
-
TOWERS WATSON t/L/ American Electric Power System Retirement Plan, September 2010

SI-7
Minimum Required Employer Contribution
January l9 2010
January I, 2009
Minimum Required Employer
Contribution
Target normal cost
Net shortfall amortization charge
Waiver amortization charge
Excess assets
Minimum funding requirement
Available credit balance
Remaining cash requirement (assuming
sponsor elects full use of available credit
balance)
Percent of covered pay
Per active participant
$ 132,459,672
107,110,851
0
0
$ 239,570,523
529,842,932
0
0.0%
$ 0
$ 107,877,356
0
0
$ 107,877,356
564,402,371
0
0.0%
0
Additional details regarding the calculation of the minimum required employer contribution may be
obtained from the Form 5500 Schedule SB filings and attachments.
Schedule of Minimum Funding
Requirements* Plan Year 2010 Plan Year 2009
April 15
$ 26,969,339 $ 24,272,405
July 15
October 15
26,969,339
26,969,339
24,272,405
24,272,405
January 15 (following) 26,969,339 24,272,405
September 15 (following) 151,663,184 17,977,458
Quarterly contributions for the 2011 plan year will not exceed $59,900,000 per payment, based on this
year’s valuation results.
* Before reflecting any credit balance elections for 2010 or 2009.
American Electric Power System Retirement Plan, September 201 0
-
TOWERS WATSON

~ ~ ~
SI-8
Basic Results for Maximum Deductible Employer Contribution
Normal Costs
Target normal cost
Target normal cost as if at-risk
(for plans not at-risk)
Liabilities
Funding target
Funding target reflecting future
pay/benefit increases
Funding target as if at-risk (for plans not
at-risk) .
Assets
Market value
Unrecognized investment losses (gains)
Actuarial value
Key Economic Assumptions
Effective interest rate
Cash balance interest crediting rate
Salary increase rate
January I, 2010
$ 132,459,672
N/A
$ 3,999,133,748
4,006,830,933
NIA
$ 3,843,641,797
(1 12,214,126)
$ 3,731,427,671
6.56%
5.25%
Rates vary by age
from 3.5% to 113%
January I, 2009
$ 107,877,356
N/A
$ 3,453,898,445
3,519,552,428
N/A
$ 3,156,051,105
31 5.605. 11
$ 3,471,656,216
8.23%
5.50%
Rates vary by age
from 5.0% to 115%
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

SI-9
Maximum Deductible Employer Contribution
January I, 2010
January I, 2009
Basic Funding Limit
Funding target
Target normal cost
Statutory cushion amount
Basic funding limit
At-Risk Funding Limit
Funding target as if at-risk
Target normal cost as if at-risk
At-risk funding limit (for plans not at-risk)
Maximum Deductible Employer
Contribution
Maximum funding limit
Actuarial value of assets
Preliminary maximum contribution
Minimum funding requirement
Maximum deductible contribution*
Percent of covered pay
Per active participant
$ 3,999,133,748
132,459,672
2,007,264,059
$ 6,138,857,479
NIA
NIA
NIA
$ 6,138,857,479
3,731,427,671
$ 2,407,429,808
239,570,523
2,407,429,808
144.2%
$ 115,216
$ 3,453,898,445
107,877,356
1,792,603,206
$ 5,354,379,007
NIA
NIA
NIA
$ 5,354,379,007
3,471,656,216
$ 1,882,722,791
107,877,356
1,882,722,791
116.0%
$ 91,693
*Estimated amount, pending issuance of TreasuryllRS guidance.
American Electric Power System Retirement Plan, September 201 0
TOWERS WATSON -

Funded Status for Benefit Limitations
Fiscal 2010
Fiscal 2009
Basic Results
Funding target disregarding at-risk
provisions
Actuarial value of assets
Credit balance
Annuity purchases for non-highly
compensated employees during
preceding two plan years
Funded Status
Adjusted funding target attainment
percentage
Key Economic Assumptions
Effective interest rate
$ 3,999,133,748
3,731,427,671
529,842,932
0
80.1 %
6.56%
$ 3,453,898,445
3,471,656,216
564,402,371
0
100.5%
8.23%
-
TOWERS WATSON ch/ American Electric Power System Retirement Plan, September 2010

SI-11
Actuarial Assumptions and Methods
Pension Cost
Contributions
Economic Assumptions
Discount rate
Return on assets
5.60%
8.00%
NIA
8.00%
Funding interest rate basis:
.
Applicable month (published)
Yield curve basis
Funding interest rates:
.
First segment rate
Second segment rate
. Third segment rate
. Effective interest rate
Annual rates of increase
. Total compensation
Age
< 26
26 - 30
31 -35
36 - 40
41 -45
46 - 49
> 51
NIA
NIA
N/A
N/A
NIA
NIA
Rate
11.50%
9.50%
7.50%
6.50%
5.00%
4.00%
3.50%
October 2009
Segment rates
4.92%
6.71 %
6.80%
6.56%
Rate
11.50%
9.50%
7.50%
6.50%
5.00%
4.00%
3.50%
Cash balance crediting rate
.
Lump sumlannuity conversion rate
Future Social Security wage bases
5.25%
6.50%
4.00%
5.25%
October 2009
Segment rates
4.00%
. Statutory limits on compensation and
benefits
3.00%
NIA
American Electric Power System Retirement Plan, September 2010
TOWERS WATSON
-

SI-12
Demographic Assumptions
Pension Cost
Contributions
Preretirement Healthy Mortality RP2000, projected to 2025 RP2000, projected to 2025
Postretirement Healthy
Mortality
Disabled Mortality
RP2000, projected to 201 7 RP2000, projected to 2017
RP2000 disabled retiree, no
projection
Post-I994 current liability
disabled
Lump Sum/Annuity Conversion
Applicable 41 7(e) IRS Mortality
Table
Applicable 417(e) IRS Mortality
Table
Termination
Rates varying by age and service:
Less than five
Age years of service
~ 2 5 8.00%
25-29 8.00%
30-34 8.00%
35-39 8.00%
40-49 8.00%
>49 8.00%
Five or more
years of service
8.00%
6.00%
5.00%
3.00%
2.50%
4.00%
Retirement
Rates varying by age; average retirement age 61 :
Age
Rate
55-57 7.00%
58-60 10.00%
61-63 25.00%
64-65 50.00%
66-69 25.00%
70+ 100.00%
Disability
Rates apply to employees not eligible to retire and vary by age and sex as
indicated by the following sample values:
Age
Male
Female
20 0.060% 0.090%
30 0.060% 0.090%
40 0.074% 0.110%
50 0.178% 0.267%
60 0.690% 1.035%
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

SI- 13
Form of payment
Percent married
Spouse ages
Valuation pay
40% lump sum; 60% annuity for retirement eligible East grandfathered
participants and 75% lump sum; 25% annuity for all other participants
(married participants are assumed to elect the 50% joint and survivor annuity
and unmarried participants are assumed to elect the single life annuity. No
other optional form of payment election is assumed).
80% of male participants; 70% of female participants.
Wives are assumed to be three years younger than husbands.
2010 Base Salary Pay (Grandfathered) - estimated as 2009 Base Pay
updated one year according to the salary increase assumption.
Administrative
expense
Actuarial Methods
Pension cost:
t Service cost and projected
benefit obligation
t Market-related value of assets
Contributions:
Funding target
Target normal cost
201 0 Expanded Pay (Cash Balance) - sum of the following
updated one year according to the salary increase assumption:
(i) 2009 base salary
(ii) A 15% increase for overtime eligible employees and a
target bonus percent increase for incentive-eligible employees.
Discount rate is net of expenses paid by the trust.
Projected unit credit.
The market value on the valuation date less the following
percentages of prior years' investment gains and losses:
-
-
-
-
American Electric Power System Retirement Plan, September 2010
-
80% of the prior year
60% of the second prior year
40% of the third prior year
20% of the fourth prior year.
The investment gain or loss is calculated each year by:
- Rolling forward the prior year's fair value of assets
with actual contributions, benefit payments and
expected return on investments using the long-term
yield assumption
- Comparing the actual fair value of assets to the
expected value calculated above.
Present value of accrued benefits.
Present value of accrued benefits expected to accrue during the
plan year plus plan related expenses expected to be paid from
the trust (based on actual trust expenses paid in previous year).
TOWERS WATSON

SI- 14
Actuarial value of assets
Benefits Not Valued
Average of the fair market value of assets on the valuation date
and the six immediately preceding months, adjusted for
contributions, benefivexpense payments and expected
investment returns. The average asset value must be within
10% of fair value, including contributing receivable. The method
of computing the actuarial value of assets complies with rules
governing the calculation of such values under PPA.
These rules produce smoothed values that reflect the underlying
market value of plan assets but fluctuate less than the market
value. As a result, the actuarial value of assets will be lower
than the market value in some years and greater in other years.
However, over the long term under PPAs smoothing rules, the
method has a bias to produce an actuarial value of assets that is
below the market value of assets.
All benefits were valued except:
- Any liabilities that may be reinstated in the event of
reemployment
- The alternate benefit formula for members who did not
elect to withdraw their contributions
- Any liabilities relating to member's unwithdrawn
contributions
- Liabilities related to special benefits as a result of
termination due to restructuring or downsizing.
Change in Assumptions and Methods Since Prior Valuation
Pension cost The discount rate was decreased from 6.00% to 5.60%.
The mortality table used to value the benefit obligations was
updated from the RP2000 with projections to 2016 for
annuitants and to 2024 for nonannuitants to RP2000 with
projections to 2017 for annuitants and to 2025 to nonannuitants.
The salary increase rate, terminate rate, retirement rate and
form of payment assumptions were updated to reflect the results
of AEP's recent experience study.
Participants on long-term disability are now valued by projecting
their benefit to Normal Retirement Date and valuing their
projected benefit as of the valuation date.
The probability of disablement is now explicitly valued (see
sample disability rates above).
-
TOWERS WATSON American Electric Power System Retirement Plan, September 2010

SI-15
Contributions
Data Sources
The funding interest rate methodology was changed from being
based on the full yield curve published in November 2008 to
being based on segment rates published in October 2009.
Assumed plan-related expenses of $14,593,879 were added to
the target normal cost.
The required mortality table used to value the funding target and
target normal cost was updated to include one additional year of
projected mortality improvements.
The salary increase rate, terminate rate, retirement rate and
form of payment assumptions were updated to reflect the results
of AEP’s recent experience study.
Participants on long-term disability are now valued by projecting
their benefit to Normal Retirement Date and valuing their
projected benefit as of the valuation date per final PPA
regulations.
The probability of disablement is now explicitly valued (see
sample disability rates above).
Towers Watson used participant and asset data as of January I, 2010, supplied by AEP. Data were
reviewed for reasonableness and consistency, but no audit was performed. Assumptions or
estimates were made by Towers Watson actuaries when data were not available. We are not aware
of any errors or omissions in the data that would have a significant effect on the results of our
ca Icu lat ion s.
American Electric Power System Retirement PlaT September 201 0
-
TOWERS WATSON ch/

Participant Data
Active
Number
Average age
Average past service
Average future service
. Total
. Average
Covered pay:
January I, 2010
20,895
46.6
17.3
10.6
$ 1,672,038,281
80,821
January I, 2009
20,533
47.1
18.2
9.8
$ 1,624,499,706
79,117
Deferred Inactive
Number
Average age
. Total
. Average
Annual benefits:
5,912
53.5
5,355
52.5
$ 50,810,684 $ 41 ,I 31,607
8,595 7,681
Currently Receiving Benefits
Number 15,126 15,047
Average age 74.0 73.7
Annual benefits:
.
Total
$ 203,109,656 $ 203,104,413
Average 13,428 13,498
Total Participants Included
in Valuation
Number
41,933 40,935
TOWERS WATSON
-
American Electric Power System Retirement Plan, September 201 0

SI-17
Analysis of Inactive Participant Data
Deferred Inactive
Age last birthday
Number
Annual benefit
Average annual
benefit
< 40
150 $
1,627,378
$ 10,849
40 - 44
306
1,976,531
6,459
45 - 49
1,016
6,750,025
6,644
50 - 54
1,722
13,413,043
7,789
55 - 59
1,598
14,652,207
9,169
60 - 64
1,026
1 1,510,154
11,218
> 64
94
881,346
9,376
Total
5,912 $
50,810,684
$ 8,595
Currently Receiving
Benefits
Age last birthday
< 55
55 - 59
60 - 64
65 - 69
70 - 74
75 - 79
Number
104 $
522
2,010
2,729
2,644
2,547
Annual benefit
444,288
6,465,789
36,310,753
33,534,998
35,182,836
36,589,219
Average annual
benefit
$ 4,272
12,387
18,065
11,288
13,307
14,366
> 79
4,570 54,581,773
11,943
Total 15,126 $ 203,109,656 $ 13,428
American Electric Power System Retirement Plan, September 2010
TOWERS WATSON -

SI-18
Active Participant Data by Age and Service
American Electric Power System Retirement Plan
201 0 Projected Pay
Age
Nearest
Birthday
0-24
25-29
30-34
35-39
40-44
45-49
50-54
55-59
60-64
65-69
Over 69
Total
Completed Years of Service
0 1-4 5-9 10-14 15-19 20-24 25-29 30-34 Over 35 Total
Number 525 10 535
Avg Pay
Number
Avg Pay
Number
Avg Pay
Number
Avg Pay
46,752
1,149
58,998
1,028
63,370
834
69,105
55,453
257
66,237
531
72,680
525
78,053
3
59,331
135
75,983
374
79,415
2
73,584
96
83,457
3
76,189
46,915
1,409
60,319
1,696
4,338
1,832
74,538
Number
652 423 338 501 297 9
2,220
Avg Pay
69,669 81,509 84,387 90,340 86,791 77,244
81,152
Number
483 380 333 437 925 797 78
3,433
Avg Pay
70,946 . 81,900 83,440 81,887 90,458 85,720 82,759
83,719
Number
Avg Pay
Number
Avg Pay
Number
Avg Pay
Number
Avg Pay
Number
328
76,057
217
75,982
91
74,715
9
68,141
5
304
82,468
183
84,039
121
88,681
36
80,298
4
228
84,611
143
84,878
72
79,260
14
84,556
3
345
84,704
208
79,586
81
76,033
18
84,214
2
660
84,510
387
85,280
194
80,318
22
85,457
4
1,208
93,958
652
90,796
250
86,443
26
97,749
3
1,228
88,286
965
92,328
286
89,934
16
94,145
37
86,201
649
90,381
709
96,881
60
91,067
2
4,338
87,463
3,404
88,283
1,804
89,245
201
87,540
23
Avg Pay
66,765 102,578 49,037 80,647 69,708 81,074
110,534 78,072
Number
Avg Pay
5,321
64,647
2,774
78,309
1,643
82,113
1,690
84,507
2,492
86,758
2,945
90,360
2,573
89,854
1,457
93,494
20,895
80,817
Average Age = 46.6 Average Service = 17.3
-
TOWERS WATSON 1/L/
American Electric Power System Retirement Plan, September 2010

SI-I9
Reconciliation of Participant Data
Included in January 1,2009
valuation
Change due to:
t New hire and rehire
t Nonvested termination
t Vested termination
t Retirement
t Disability*
F Death without beneficiary
t Death with beneficiary
t Cashout
F Miscellaneous
t Net change
Included in January 1,2010
valuation
Currently
Deferred receiving
Active inactive benefits Total
20,533 5,355 15,047 40,935
20,895 5,912 15,126 41,933
*Per final PPA regulations, LTD participants are now valued as deferred inactive participants by projecting their
benefit to Normal Retirement Date and valuing the projected benefit as of the valuation date.
American Electric Power System Retirement Plan, September 2010
-
TOWERS WATSON

SI-20
Plan Provisions for Participants Covered by the
Former East Retirement Plan
Effective Date
Recent Amendments
Covered Employees
Participation Date
May 1, 1955. Restated effective January 1, 1997.
Executed as of December 23,2009.
Employees become Members of the Plan on the first day of
the month following completion of one year of service.
Date of becoming a covered employee.
Definitions
Grandfathered Employee
If, on December 31, 2000, either:
H Participating in AEP Retirement Plan, or
H In one-year waiting period for AEP System Retirement
Plan participation.
Vesting Service
Accredited Service
Final Average Pay
Cash Balance Pay
Covered Compensation
Amount
Normal Retirement
Date (NRD)
A period of time from employment date to termination date
and, in general, includes periods of severance that are not in
excess of 12 months.
Elapsed time from date of hire (from benefit service start
date).
Average of the highest 36-consecutive months of base pay
out of the last 120 months of employment, subject to IRS
limits.
Pay received during the year, including base pay,
overtime, shift differential/Sunday premium pay and
incentive pay, subject to IRS limits.
The average of the Social Security taxable wage base during
the 35-year period including the year in which the participant
retires, dies, becomes disabled or otherwise terminates
employment. This monthly average is calculated to the next
lower or equal whole dollar amount and is then rounded to
nearest $50.
The first day of the calendar month whose first day is nearest
the later of the member's 6!jth birthday or the completion of
five years of Vesting Service.
TOWERS WATSON -
American Electric Power System Retirement Plan, September 2010

SI-21
Cash Balance Account
Cash Balance Benefit
Recordkeeping account to which annual interest credits and
annual compensation credits is credited. The cash balance
account is updated at the end of each plan year and is equal
to:
Cash Balance Account as of the
End of the Prior Plan Year
+
Interest Credits
+
Company Credits
Cash Balance Account converted to a monthly annuity.
Opening Balance
For those participating in or eligible for the AEP System
Retirement Plan on December 31, 2000, opening balance is
calculated as follows:
Present value of monthly normal retirement benefit
determined as of December 31,2000, and payable at age
65 (or current age if older)
- Present value determined based on 5.78% interest and
IRS regulated mortality (GAM83 Unisex) data for lump
sums (postretirement only)
Plus
Plus
Credit for early retirement subsidy for monthly payments
beginning at age 62 (or current age if older)
Transition credit based on age, service and pay received in
2000 (see “Company Credits” for credit percentages)
- Age and service based on completed whole years as of
December 31,2000.
For employees hired on or after January 1,2001, opening
balance is $0.
Interest Credits
Interest credits are applied to beginning of year account
balance on December 31 each year.
Based on the average 30-year Treasury Bond rate for
November of the previous year.
Minimum of 4%.
American Electric Power System Retirement Plan, September 2010
-
TOWERS WATSON

SI-22
Company Credits
Applied to account balance on December 31 or termination
date if earlier.
Amount is a percentage of eligible pay received during the
year, based on age plus years of Vesting Service (age and
service in completed whole years as of December 31).
Age Plus
Years of Service
Less than 30
30 - 39
40 - 49
50 - 59
60-69 '
70+
Annual
Company Credit
3.0%
3.5%
4.5%
5.5%
7.0%
8.5%
Monthly Grandfathered Sum of (1)+(2)+(3):
Benefit
(1) 1 .I% of Final Average Pay x Accredited Service up to 35
years
(2) 0.5% of Final Average Pay Less Covered Compensation x
Accredited Service up to 35 years
(3) 1.33% of Final Average Pay x Accredited Service between
35 and 45 years.
Service continues to accrue and Final Average Pay grows
through December 31,201 0.
Long-term Disability
and Paid Leaves
Unpaid Leave
Eligibility for Benefits
Normal Retirement
Compensation equal to base rate of pay as of disability date
Vesting service continues.
No compensation for annual compensation credit. Vesting
service continues.
All members at or after their Normal Retirement Date.
-
TOWERS WATSON cIL/
American Electric Power System Retirement Plan, September 2010

SI-23
Vested
Early Retirement
Disability
Surviving Spouse
Preretirement Death
All members who terminate employment after completion of
three years of Vesting Service, or upon death.
Any time after attainment of age 55 and completion of five
years of vesting.
All members who are unable to work at own occupation solely
because of sickness or injury for the first 24 months of
disability. After 24 months of disability, the participant is
eligible if unable to work at any gainful occupation for which
the participant may be able, or may reasonably become
qualified by education, training or experience, to perform.
The surviving spouse of a Grandfathered Member who retired
or is eligible to retire on Normal or Early Retirement and who
was married to that spouse for the year preceding
commencement and whose grandfathered benefit exceeds his
or her Cash Balance Benefit.
Beneficiary of deceased member
Monthly Benefits Paid Upon the Following Events
Normal Retirement
Early Retirement
For Grandfathered Employees, the better of the monthly
grandfathered benefit or the Cash Balance Benefit determined
as of Normal Retirement Date. For all other employees, the
Cash Balance Benefit determined as of Normal Retirement
Date.
For Grandfathered Employees, the better of:
(1) The monthly grandfathered retirement benefit reduced by
3% per year for each year commencement precedes age
62, and
(2) The Cash Balance Benefit determined as of the Early
Retirement Date.
For all other employees, the Cash Balance Benefit determined
as of the Early Retirement Date.
American Electric Power System Retirement Plan, September 201 0
-
TOWERS WATSON
t/c/

SI-24
Deferred Vested Retirement
The accrued Normal Retirement Benefit (better of Cash
Balance and Grandfathered Benefits, if eligible), payable at
Normal Retirement Date or actuarially reduced and payable at
any age.
Disability The greater of (1) or (2):
Preretirement Death Better of (1) or (2):
(1) Accrued Grandfathered Retirement Benefit reduced as in
the Early Retirement Benefit. If retirement occurs prior to
age 55, the benefit is further reduced actuarially from age
55. The Disability Retirement Benefit will reflect
Accredited Service that accrued (at most recent rate of
base earnings) to a member while receiving benefits
under the Company’s LTD plan.
(2) The Cash Balance Benefit with continued Company
Credits while disabled.
Benefit (1) applies for Grandfathered Employees only.
(1) The grandfathered monthly benefit as if the employee
commenced a 60% qualified joint and survivor benefit at
his earliest retirement date
(2) Annuity equivalent of Cash Balance account, or the cash
balance account.
Benefit (1) applies for a Grandfathered Employee whose
beneficiary is his or her spouse.
Surviving Spouse Benefits
A benefit payable for life equal to 30% of the single life annuity
payable to the grandfathered member. The spouse’s benefit is
actuarially reduced for each year by which the spouse is more
than ten years younger than the member. Payable to
Grandfathered Employees only.
TOWERS WATSON -
American Electric Power System Retirement Plan, September 2010

SI-25
Form of Payment
Grandfathered
Employees
Employees Hired on or
After January 1,2001
Form of Payment Conversion
for Non417(e) Covered
Conversions
Cash balance
Grandfathered benefit
The following are available for Grandfathered Employees for
both the Grandfathered Benefit and the Cash Balance Benefit:
W
W
Full lump sum payment.
Combination of partial lump sum (25%, 50% or 75% of
full lump sum) with remainder paid as a monthly benefit
(see below).
Monthly payment:
- Single life annuity.
- Optional joint annuities (spouse or other beneficiary).
- Available in 40%, 50%, 60%, 75%, 100%.
- Can elect pop-up and/or level income options.
- Automatic company-paid 30% surviving spouse
annuity included in Grandfathered Benefit annuity if
terminate on or after age 55 and married at least one
year. Cash Balance Benefit is actuarially reduced for
this feature.
The following are available for those hired on or after January
1 I 2001 :
Full lump sum payment.
Combination of partial lump sum (25%, 50% or 75% of
full lump sum) with remainder paid as a monthly benefit
(see below).
Monthly payment:
- Single life annuity.
- Joint annuities (spouse or other beneficiary).
- Available in 50%, 75%, 100%.
7.50% interest and the applicable 417(e) Mortality Table.
7.50% interest and the 1974 George B. Buck Mortality Table.
American Electric Power System Retirement Plan, September 2010
-
TOWERS WATSON

SI-26
Member Contributions
Prior to January 1, 1978, employee contributions were
required as a condition of Membership. In May and June of
1981, Members were permitted an election to withdraw those
contributions. Those who did not elect to withdraw have
retirement benefits based on a formula that differs from the
formulas previously described in this section. However, the
number of nonelecting Me-mbers is so small that special plan
provisions for that group have not been included in this
summary.
Benefits Not Valued
A small portion of the population made employee contributions to the plan. Because the
amount of these contributions is not material to the plan, they are not part of the valuation.
Participants who were employees of Columbus Southern Power (CSP) at the time AEP
acquired that company have a frozen benefit under the CSP benefit formula at December 31,
1986. Benefits for these participants are the greater of an all-service AEP benefit and a twopart
benefit consisting of the frozen CSP benefit plus an AEP benefit accrued from January 1,
1987. Because this applies to a small portion of the population and the CSP frozen benefit is
not often the greater benefit for these participants, this benefit is not valued.
Plan Status
Ongoing.
Future Plan Changes
No future plan changes were recognized in determining pension cost. Towers Watson is not
aware of any future plan changes that are required to be reflected.
Changes in Benefits Valued Since Prior Year
None.
TOWERS WATSON -
American Electric Power System Retirement Plan, September 2010

SI-27
Plan Provisions for Participants Covered by the
Former West Retirement Plan
Effective Date
Recent Amendments
Covered Employees
Participation Date
Definitions
Grandfathered Employee
Vesting Service
Credited Service
Final Average Pay
Cash Balance Pay
Normal Retirement
Date (NRD)
January 1940. Restated effective January 1 , 1997.
Executed as of December 13,2009.
All full-time employees of a Participating Company employed by
CSW before January 1, 2001 , and not covered by a union (that
has not bargained for coverage) or another pension plan provided
by AEP. Part-time employees of the Company had to work more
than 1,000 hours in the first anniversary year or subsequent
calendar years.
Date of becoming a covered employee.
Employees who were at least age 50 with ten years of vesting
service as of July 1, 1997.
All service from date of hire in completed years.
The aggregate of:
For the period prior to January 1, 1976:
(1) The number of full years in the last continuous period that
employee was a participant after June 30, 1970, plus
(2) Credited service under any prior plan if service extended to
July 1, 1970.
For the period beginning on or after January I, 1976, the number
of full years of service.
Highest average annual earnings (base pay only) during any 36
consecutive months in the 120 months before retirement. Any
changes in earnings within the last three months before retirement
will not be taken into account.
Pay received during the year, including base pay, overtime,
shift differentiaVSunday premium pay and incentive pay, subject
to IRS limits.
The first day of the calendar month on or following the
member's 6!jth birthday.
American Electric Power System Retirement Plan, September 201 0
-
TOWERS WATSON

Cash Balance Account
Cash Balance Benefit
Interest Credits
Recordkeeping account to which annual interest credits and
annual compensation credits are credited. The cash balance
account is updated at the end of each plan year and is equal to:
Cash Balance Account as of the
End of the Prior Plan Year
+
+
Interest Credits
Company Credits
Cash Balance Account converted to a monthly annuity.
Interest credits are applied to beginning of year account balance
on December 31 each year.
Based on the average 30-year Treasury Bond rate for November
of the previous year.
Minimum of 4%.
Company Credits
Applied to account balance on December 31 or date of
termination if earlier.
Amount is a percentage of eligible pay received during the year,
based on age plus years of Vesting Service (age and service in
completed whole years as of December 31).
Age Plus
Years of Service
Less than 30
30 - 39
40 - 49
50 - 59
60 - 69
70+
Annual
Company Credit
3.0%
3.5%
4.5%
5.5%
7.0%
8.5%
Monthly Grandfathered
Benefit
TOWERS WATSON -
Greater of (1) or (2) below with automatic cost of living
adjustments upon retirement:
(1) Basic benefit - An annual amount equal to:
The aggregate of a participant's (a) earned benefit (if any)
under any prior plan or acquired Company pension plan
under which no election was made to receive a paid-up
annuity; and (b) participant contributions without interest for
the period commencing on or after July 1 , 1970. For the
period after September 1 , 1980, participants will be deemed
to have made contributions at the rate of 2% annually of the
participant's annual rate of earnings as of January 1.
American Electric Power System Retirement Plan, September 2010

SI-29
(2) Minimum benefit:
1-2/3% of final average annual earnings less 50% of
participant's annual primary Social Security benefit times years of
credited service up to 30 years.
Minimum Benefits
Primary Social Security
Benefit
Long-term Disability
and Paid Leaves
Unpaid Leave
The benefit payable will never be less than the frozen accrued
benefit as of July 1 1997, under the prior plan.
The annual amount payable under the Social Security Act as
amended in effect at the employee's date of retirement. The date
as of which the amount is to be determined is:
(1) In the case of an employee (including deferred vested
employees) retiring on or after normal retirement date,
normal retirement date.
(2) In the case of an employee retiring prior to normal retirement
date, the later of employee's 62"' birthday or actual
retirement date.
Early retirees and deferred vested employees are assumed to
have no earnings after termination in determining the amount of
this benefit.
Compensation equal to the base rate of pay as of disability date. If a
participant became disabled prior to January 1, 2003, compensation
for the cash balance formula is equal to the greater of the
compensation for the calendar year before the disability and the year
in which the disability benefits began. For the grandfathered formula,
the final average pay will be determined as of the date on which the
participant became disabled. Vesting service continues.
No compensation for annual compensation credit. Vesting service
continues.
Eligibility for Benefits
Normal Retirement
Vested
All participants at or after their normal retirement date.
The participant's cash balance account is 100% vested when any
one of the following applies:
(1) Three years of vesting service
(2) Attainment of age 55 while an employee
(3) Death prior to termination
(4) Upon disability.
Early Retirement
American Electric Power System Retirement Plan, September 201 0
-
Any time after attainment of age 55 and completion of 15 years of
vesting service. ,
TOWERS WATSON

SI-30
Disability
Surviving Spouse
Preretirement Death
All participants who become permanently and totally disabled.
Permanent and total disability is determined by reference to the
LTD plan covering that participant.
The surviving spouse of a participant who retired or is eligible to
retire on normal or early retirement.
Beneficiary of participant who dies after becoming vested.
Monthly Benefits Paid Upon the Following Events
Normal Retirement
Early Retirement
Grandfathered employees must elect either the cash balance or
the grandfathered formula. For purposes of this valuation, the
employee is assumed to elect the formula with the higher
present value. Employees with a prior plan frozen benefit get
the better of the cash balance benefit and the prior plan frozen
benefit. For all other employees, the Cash Balance Benefit is
determined as of Normal Retirement Date.
Greater of (1) if applicable or (2):
(1) The grandfathered accrued benefit and the prior plan
frozen are payable subject to reduction according to the
following schedule if payments commence prior to the
normal retirement date.
Age at
Retirement
Percent of
Benefit Payable
64
63
62
61
60
59
58
57
56
55
100%
100%
100%
95%
90%
84%
78%
72 %
66%
60%
(2) The Cash Balance Benefit determined as of the Early
Retirement Date.
Deferred Vested Retirement Greater of (1) if applicable or (2):
TOWERS WATSON
-
(1) Grandfathered accrued benefit payable at age65, or if
earlier reduced 5% per year from age 65,6% per year from age
60 and 7.5% per year compounded from age 55.
(2) Vested cash balance account.
American Electric Power System Retirement Plan, September 20 10

SI-3 1
Disability Retirement
Preretirement Death
The greatest of grandfathered accrued benefit, if eligible, based
on projected service and frozen pay deferred to age 65, prior
plan frozen benefit if eligible and cash balance account with
continued pay credits.
If the beneficiary is the spouse and the participant is a
grandfathered/protected plan participant, then:
For an active participant who dies on or after 55Ih birthday
but before retirement, a monthly benefit equal to 50% of
the benefit accrued to the date of death without reduction
for early retirement is payable immediately as a life annuity
to a qualifying spouse.
For an active participant who dies after completing five or
more years of vesting service but before age 55, a
deferred monthly benefit equal to 50% of the benefit
accrued to the date of death reduced as for early
retirement is payable as a life annuity to a qualifying
spouse. Benefit commencement is deferred to when the
deceased participant would have attained age 55.
For a deferred vested participant who dies before benefits
commence, a monthly benefit equal to 50% of the deferred
vested benefit reduced for early commencement (as for
deferred vesteds) is payable as a life annuity to a
qualifying spouse. If death occurs before age 55, the
benefit to the spouse is deferred to when the deceased
participant would have attained age 55.
The spouse's benefit is actuarially reduced for each year by
which the spouse is more than five years younger than the
participant.
For all employees, the minimum benefit is the cash balance
account immediate annuity, which is also payable if the
beneficiary is not the participant's spouse.
Form of Payment
American Electric Power System Retirement Plan, September 2010
-
The following are available for those participants who did not
work an hour of service on or after January 1,2003:
W
Full lump sum payment.
Monthly payment:
- Single life annuity.
- 50% joint annuity (spouse or other beneficiary).
The following are available for those participants who work an
hour of service on or after January 1,2003:
W
Full lump sum payment.
Combination of partial lump sum (25%, 50% or 75% of full
TOWERS WATSON

Form of Payment Conversion
for Non417(e) Covered
Conversions
Cash balance
Grandfathered benefit
lump sum) with remainder paid as a monthly benefit (see
below).
H Monthly payment:
- Single life annuity.
- Joint annuities (spouse or other beneficiary).
- Available in 50%, 75%, 100%.
7.50% interest and the applicable IRS 41 7(e) Mortality Table.
7.50% interest and the 1951 Group Annuity Mortality Table.
Plan Status
Continuing accruals. All new entrants to plan are covered under former East plan provisions.
Future Plan Changes
No future plan changes were recognized in determining pension cost. Towers Watson is not
aware of any future plan changes that are required to be reflected.
Changes in Benefits Valued Since Prior Year
None.
TOWERS WATSON -
American Electric Power System Retirement Plan, September 2010

AMERICAN ELECTRIC POWER - QUALIFIED RETIREMENT PLAN
SUMMARY OF PLAN PARTICIPANTS FOR THE 2010 VALUATION
ML- 1
Location
Vested
Actives
Nan-Vested
Actives
roiai
Actives
Retirees
Receiving
BeneMs
Beneficiaries
Defemd
Vesfeds
Total
lnaciives
Tofal
Participants
AEP Energy Services, Inc.
AEP Pm Sew, Inc.
AEP T 8 D Services, LLC
American Electric Power Service Corporation
Appalachian Power Co - Distribution
Appalachian Power Co - Generation
Appalachian Power Co - Transmission
C3 Communications, Inc.
Cardinal Operating Company
AEP Texas Central Company - Distn'bution
AEP Texas Central Company - Generation
AEP Texas Central Company - Nudear
AEP Texas Central Company - Transmission
Columbus Southern Power Co - Distribution
Columbus Southern Power Co - Generation
Columbus Southern Power Co - Transmission
Coneaville Coal Preparation Company
Cook Coal Terminal
CSW Energy, Inc.
Elmwood
EnerShop Inc.
Indiana Michigan Power Co - Distribution
Indiana Michigan Power Co - Generation
Indiana Michigan Power Co - Nudear
Indiana Michigan Power Co -Transmission
Kentucky Power Co - Distribution
Kentucky Power Co - Generation
Kentucky Power Co - Transmission
Kingsport Power Co - Distribution
Kingsport Power Co - Transmission
AEP River Operations LLC
Ohio Power Co - Distribution
Ohio Power Co -Generation
Ohio Power Co - Transmission
Public Service Co of Oklahoma -Distribution
Public Service Co of Oklahoma - Generation
Public Service Co of Oklahoma - Transmission
Southwestem Electric Power Co - Distribution
Southwestern Electric Power Co - Generation
Southwestern Electric Power Co - Texas - Distribution
Southwestern Electric Power Co - Texas -Transmission
Southwestern Electric Power Co - Transmission
Ind Mich River Transp Lakin
AEP Tmas North Company - Distribution
AEP Texas North Company - Generation
AEP Texas North Company -Transmission
'&beeling Power Co - Distribution
Wheeling Power Co -Transmission
Cedar Coal Co
Central Coal Company
Central Ohio Coal
Southern Ohio Coal- Martinka
Southern Ohio Coal - Meigs
Windsor
Price River Coal
Houston Pipeline (HPL)
0
1
0
5,278
1,078
1,000
160
0
243
966
1
0
111
693
284
51
9
17
18
104
0
661
413
927
148
272
126
48
40
10
614
804
745
208
685
353
72
472
463
251
0
81
249
298
0
47
54
0
0
0
0
0
0
0
0
0
0
0
0
821
86
200
13
0
77
72
0
0
22
115
91
11
0
0
1
35
0
78
38
173
19
10
20
2
3
2
332
80
122
17
94
39
11
41
87
22
0
11
94
9
0
6
6
0
0
0
0
0
0
0
0
0
0
1
0
6,099
1,164
1,200
173
0
320
1,038
1
0
133
808
375
62
9
17
19
139
0
739
451
1,100
167
262
146
50
43
12
946
884
867
225
779
392
83
513
530
273
0
92
343
307
0
53
60
0
0
0
0
0
0
0
0
0
3
0
0
1897
1129
642
92
0
146
835
81
0
75
917
338
73
9
10
4
3
0
677
260
259
81
155
67
5
44
7
2
880
642
110
486
176
56
196
190
164
3
32
103
185
119
26
58
4
73
0
62
65
64
26
12
2
0
0
0
414
416
214
13
0
49
239
63
0
36
141
64
20
0
0
0
0
0
267
62
58
12
70
24
0
16
1
0
288
188
36
206
81
18
94
93
37
4
11
37
85
53
12
28
9
32
0
14
14
34
7
1
0
39
2
0
1,772
376
179
39
14
36
460
218
0
69
176
94
12
0
0
22
9
0
174
184
330
21
107
40
7
22
1
39
208
196
26
231
89
26
94
85
83
4
10
50
122
62
7
10
1
11
0
34
53
18
13
6
33
42
2
0
4,083
1,921
1,035
144
14
231
1,534
362
0
180
1,234
496
105
9
10
26
12
0
1,118
526
647
114
332
131
12
82
9
41
1,376
1,026
172
923
346
100
384
368
284
11
53
190
392
234
45
96
14
116
0
110
132
114
46
19
35
42
3
0
10,182
3,085
2,235
317
14
551
2,572
363
0
313
2,042
871
167
18
27
45
151
0
1,857
977
1,747
281
614
277
62
125
21
987
2,260
1.893
397
1,702
738
183
897
698
557
11
145
533
699
234
96
156
14
116
0
110
132
114
46
19
35
Total
18.055
2,840
20,895
11,545
3,581
5,912
21,038
41,933

AMERICAN ELECTRIC POWER - QUALIFIED RETIREMENT PLAN
FUNDED STATUS OF PRESENT VALUE OF ACCUMULATED P UN BENEFITS (FASB ASC 960) AS OF JANUARY 1,201 0
ML-2
Location
Present
value Of
Vested Beneflk
Plesent
Value of
Non-Vested Benetlts
Present Value of
Accumulated
Plan Benefits
Market Value
of Assets
Percent
Funded
AEP Energy Services, Inc.
AEP Pro Sew, Inc.
AEP T Bi D Services, LLC
American Electric Power Service Corporation
Appalachian Power Co - Distribution
Appalachian Power Co - Generation
Appalachian Power Co - Transmission
C3 Communications. Inc.
Cardinal Operating Company
AEP Texas Central Company - Distribution
AEP Texas Central Company - Generation
AEP Texas Central Company - Nudear
AEP Texas Central Company -Transmission
Columbus Southern Power Co - Distribution
Columbua Soulhem Power Co -Generation
Columbus Southem Power Co -Transmission
Conesviiie Coel Preparation Company
Cook Coal Terminal
csw Energy, Inc
Elmwood
EnerShop inc.
Indiana Michigan Power Co - Distribution
Indiana Michigan Power Co - Generation
Indiana Michigan Power Co - Nuclear
Indiana Michigan Power Co - Transmission
Kentucky Power Co - Distribution
Kentucky Power Co - Generation
Kentucky Power Co - Transmission
Kingsport Power Co - Distribution
Kingsport Power Co -Transmission
AEP River Operations LLC
Ohio Power Co - Distribution
Ohio Power Co - Generation
Ohio Power Co -Transmission
Public Service Co of Oklahoma - Distribution
Public Service Co of Oklahoma - Generation
Public Service Co of Oklahoma -Transmission
Southwestem Electric Power Co - Distribution
Southwestern Electric Power Co - Generation
Southwestern Electric Power Co - Texas - Distribution
Southwestem Electric Power Co - Texas - Transmission
Southwestem Electric Power Co - Transmission
Ind Mich RiverTransp Lakin
AEP Texas North Company - Distribution
AEP Texas Noah Company - Generation
AEP Texas North Company - Transmission
Wheeling Power Co - Distribution
Wheeling Power Co - Transmlssion
Cedar Coal Co
Central Coal Company
Central Ohio Coal
Southern Ohio Coal - Martinka
Southem Ohio Coal - Meigs
Windsor
Price River Coal
Houston Pipeline (HPL)
$1,118,569
807,957
0
958,493,453
245,443,954
196,870,249
33,617,210
387,174
52,520,415
226,430,050
17,290,155
0
26,077,955
175,005,494
81,228,078
18,212,288
3,091,254
2,528,668
2,787,386
1,582,162
0
138,192,578
78,145,586
131,671.292
27,520,095
52,010,856
24,167,558
5,374,488
9,699,575
2,478,884
11,862,496
177,720,840
170,361,356
40,720,534
136,960,458
62,614,749
18,268,533
80,860.500
79,304,097
45,245,892
437,930
12,480,546
21,327,105
54,785,015
20,297,634
8,010,190
12,274,161
863,592
2,674,194
0
7,030,625
5,207,251
7,481,967
2,535,763
322,067
865,934
$0
50
0
19,082,762
1,203,812
1,994,364
162,956
0
700,658
920,611
0
0
103,993
761,431
755,470
89,821
49,960
58,743
14,649
106,790
0
1209,385
883,654
1,678,322
212,703
333,973
111,223
398
82,102
18,998
1,038,875
481,882
1,205,838
78,412
761,760
532,756
146,970
434,339
697,892
246,435
0
102,398
710,708
317,399
0
60,827
4,107
0
0
0
0
0
0
0
0
0
$1,118,569
808,007
0
977,576,215
246,647,566
198,864,613
33,780,166
387,174
53,221,071
227,350,861
17,290,155
0
26,181,948
175,758,925
81,983,548
18,302,109
3,141,214
2,587,411
2,802,035
1,688,952
0
137,401,963
7 9,0 2 9,2 4 0
133,349,614
27,732,798
52,344,629
24,278,779
5,374,886
9,781,677
2,497,882
12,701,171
178202,722
171,567,194
40,798,946
137,722,218
63,147,505
16,415,503
81,294,839
80,001,989
45,492,327
437,930
12,582,944
22,037,813
55,102,4 14
20,297,634
8,071,017
12,278.268
863,592
2,674,194
0
7,030,825
5,207,251
7,481,967
2,535,763
322,067
865,934
$1,123.510
788,334
0
1,123,442,665
255,497,510
215,851,166
34,865,813
767,838
57,565,788
228,272,087
31,282,958
0
26,902,486
184331,822
85,252,815
19,396,548
3,159,934
2,644,554
2,869,090
2,041,083
0
140,947,342
85,582,629
163,765,060
29,228,720
54,843,665
27,122,361
6,606,749
9,965,631
2,352,936
16,532,332
180,097,794
200,520,506
43,172,123
141,018,339
69,037,995
15,850,803
88,885,822
86,593,197
48,198,477
450,272
14,609,991
28,038.433
57,798,280
22,784,349
8,749,507
12,955,540
962,333
2,770,429
0
8,823,035
6,402,827
9,709,573
3,272,405
403,684
2,497,868
100.4%
129.7%
0.0%
114.9%
103.6%
108.4%
102.6%
198.3%
108.2%
100.4%
180.9%
0.0%
102.8%
104.9%
104.0%
108.0%
100.6%
102.2%
106.0%
120.8%
0.0%
102.6%
108.3%
122.8%
105.4%
104.8%
111.7%
122.9%
101.9%
94.2%
130.2%
101.1%
116.9%
105.8%
102.4%
109.3%
96.6%
109.3%
108.2%
105.9%
102.8%
116.1%
127.2%
104.9%
112.3%
108.4%
105.5%
111.4%
103.6%
0.0%
122.6%
123.0%
129.8%
129.1%
125.3%
288.5%
Total
$3,488,866,810
$37,357,024
$3,526223,834
$3,866,106,388
109.6%

AMERICAN ELECTRIC POWER - QUALIFIED RETIREMENT PLAN
SUMMARY OF FASB ASC 71540 VALUATION RESULTS AS OF JANUARY I, 2010
ML-3
Locetion
Actives
Number of Participentb-
Debmd Benefcinhs
Vested 8 Retirees
Total
Valuation
Earnings
Service
cost
Accumulated
Benefit
Obligation
Pmjected
Benefit
Obligation
January I, 2010
Pm-Tar
AOCI
AEP Energy Services, Inc.
AEP Pro Sew, Inc.
AEP T & D Services, LLC
American Electric Power Service Corporation
Appalachian Power Co - Distribution
Appalachian Power Co - Generation
Appalachian Power Co -Transmission
C3 Communications, inc.
Cardinal Operating Company
AEP Texas Central Company - Distribution
AEP Texas Central Company - Generalion
AEP Texas Central Company - Nuclear
AEP Texas Central Company - Transmission
Columbus Southern Power Co - Distribution
Columbus Southem Power Co - Generation
Columbus Soulhem Power Co . Transmission
Conesville Coal Preparation Company
Cook Coal Tenninal
CSW Energy, Inc.
Elmwood
EnerShop Inc.
Indiana Michigan Power,Co - Distribution
Indiana Michigan Power Co - Generation
Indiana Michigan Power Co - Nuclear
Indiana Michigan Power Co - Transmission
Kentucky Power Co - Distribution
Kentucky Power Co - Generation
Kentucky Power Co - Transmission
Kjngsport Power Co - Distribution
Kingsport Power Co - Transmission
AEP River Operations LLC
Ohio Power Co - Distribution
Ohio Power Co - Generation
Ohio Power Co - Tranamisslon
Public Service Co of Oklahoma - Distribution
Public Service Co of Oklahoma - Generation
Public Service Co of Oklahoma - Transmission
Southwestern Electric Power Co - Distribution
Southwestem Electric Power Co - Generation
Southwestem Electric Power Co -Texas - Dislribution
Southwestern Electric Power Co - Texaa - Transmission
Southwestern Electric Power Co - Transmission
Ind Mich River Tranrp Lakin
AEP Texas North Company - Distribulion
AEP Texas North Company - Generation
AEP Texas Noflh Company - Transmission
Wheeling Power Co - Distribution
Wheeling Power Co - Transmission
Cedar Coal Co
Central Coal Company
Central Ohio Coal
Southem Ohlo Coal - Martinka
Southem Ohio Coal - Meigs
Windsor
Price River Coal
Houston Pipeline (HPL)
0
1
0
6,099
1,164
1,200
173
0
320
1,038
1
0
133
808
3 75
62
9
17
I9
139
0
739
451
1,100
167
282
146
50
43
12
946
884
867
225
779
392
83
513
530
273
0
92
343
307
0
53
60
0
0
0
0
0
0
0
0
0
39
2
0
I .772
376
179
39
14
36
460
218
0
69
176
94
12
0
0
22
9
0
174
184
330
21
107
40
7
22
1
39
208
196
26
231
89
26
94
85
83
4
10
50
I22
62
7
10
I
11
0
34
53
16
13
6
33
3
0
0
2,311
1,545
856
105
0
195
1,074
144
0
111
1,058
402
93
9
10
4
3
0
944
342
317
93
225
91
5
60
8
2
1,168
830
146
692
257
74
290
283
201
7
43
140
270
172
38
86
13
105
0
76
79
98
33
13
2
42
3
0
10,182
3,085
2,235
317
14
551
2,572
363
0
313
2,042
871
167
18
27
45
151
0
1,857
977
1,747
281
614
277
62
125
21
987
2,260
1,893
397
1,702
738
183
897
898
557
11
145
533
699
234
98
156
14
116
0
1 10
132
114
46
19
35
0
185,306
0
5541 18,394
86,586,206
92,953,401
13,617.826
0
24,681,392
75,006,363
65,464
0
10,127,727
55.1 61,997
28,914,482
4,686,461
768,159
1,487,732
2,453,406
6,113.426
0
53,980,943
36,633,942
105,143,007
12,861,450
21,247,046
11,591,038
3,937,347
3,059842
871,405
62,238,718
61,334,030
66,685,299
17,105,380
58,137.440
32,207,087
6,560,513
38,505,392
42,253,383
20,213.140
0
7,459,989
21,785,855
22,869,685
0
4,254,216
4,254,392
0
0
0
0
0
0
0
0
0
$0
16,249
0
36,357,027
5,814,612
6,145,039
948.221
0
1,629.988
4,907,333
1,200
0
645,610
3,524,042
1,983,834
309,632
55,022
90,725
121,804
338,431
0
3,635,792
2,567,060
6,934,330
866,516
1,481,760
801,532
266,325
204,149
56,236
3,377,371
4,070,933
4,438,752
1,150,919
3,549,403
2,065,766
420,990
2,499,821
2,766,233
1,295,473
0
475,539
1,243,743
1,570,410
0
268,865
282,811
0
0
0
0
0
0
0
0
0
$1,660,798
820.712
0
1,240,898,113
308,432,166
251,617,509
43,317,777
656,648
67,184,579
276,499,421
22,954,042
0
31,985,104
215,025,131
101,900,375
22,294,756
3,959,613
3,293,387
3,752,427
2,223,476
0
170,302,102
101,166,491
174,728,154
34,971,471
66,407,056
31,422,099
7,192,490
12,204,375
3,137,182
16,617,494
220,326,249
216,298,752
51,119,283
167,114,377
76,578,921
19,922,176
98,214,361
97,372,573
55,379,182
559.648
15,068,650
28,531,570
67,105,623
24,572,484
9,902,953
15,100,412
1,007,455
3,173,939
0
8,477,509
6,575,959
8,846,889
3,126,046
395,631
1,283,857
51,660,796
632,865
0
1,273,131,425
312,358,937
255,921,418
43,943,430
656,648
68,222,026
279,950,787
22,961,020
0
32,459,751
218,586,136
103,462,439
22,615,363
4,029,429
3,386,790
3,989,629
2,458,048
173,466,796 0
102,605,452
179,714,608
35,706,754
67,348,736
31,925,827
7,378,941
12,330,352
3,186,337
19,365,246
223,681,426
219,493,444
52,067,480
170,239,371
77,933,469
20,188,094
99,997,582
99,008,191
56,372,561
15,335,390 559,648
30,333.327
67,862,877
24,572,484
10,140,903
15,274,873
1,007,455
3,175,939
0
8,477,509
6,575,959
6,946,889
3,126,046
395,631
1,293,857
$707,286
(31,925)
(622)
492,064,811
145,883,236
105,189,108
16,587,086
894,759
28,309,104
126,990,098
23,345,176
93,090
15,062,243
123,167,032
51,842,062
12,855,178
1,505,613
1,450,884
4,258,371
526,310
161,813
76,715,400
37,838,838
52,918,549
13,540,670
25,606,101
10,693,701
1,908,792
6,159,133
1,457,526
4,660,965
115,836,937
111,370,158
23,085,988
82,459,046
33,163,215
10,185,895
49,261,468
43,684,139
25,961,083
941,135
6,601,154
9.845.690
35,683,925
19,503,673
5,118,867
8,453.040
809,796
3,878,212
3,979
(759,407)
1,262,523
(1,990,467)
74,936
359,750
(1,761,055)
Total
20,895
5,912
15,126
41,933 $1,672,038,281 $109,179.598 $4,412,791,460 $4,489,732,489
$1,965,413,075

AMERICAN ELECTRIC POWER- QUALIFIED RETIREMENT PLAN
7.010 NET PERIODIC PENSION COST
ML-4
Location
SeNb
COSt
Pmjeclad
Benefit
Obligation
Market-Related
Vatue
of Assets
Interest
cost
Expected
Return
on Assets
Amortization of
Initial TransZion
/Asset)/
Obligati'on
Amortization of
Piior
Service
cost
Amortization of
GainRoss
Amortization
Net
Petfodic
Pension
COSf
AEP Energy Services. inc.
AEP Pro Sew, Inc.
AEP T 8 D Services, LLC
American Eieclric Power Se'Nice Corporation
Appalachian Power Co Distribution
Appalachian Power Co - Generation
Appalachian Power Co -Transmission
C3 Communications, Inc.
Cardinal Operating Company
AEP Texas Central Company Distribution
AEP Texas Central Company Generation
AEP Texas Central Company Nuclear
AEP Texas Central Company - Transmission
Columbus Southem Power Co Distribution
Columbus Southem Power Co - Generalion
Columbus Southem Power Co -Transmission
Conesville Cod Preparation Company
Cook Coal Terminal
CSW Energy, inc.
Elmwuod
EnerShop Inc.
Indiana Michigan Power Co Distribution
Indiana Michigan Power Co Generation
Indiana Michigan Power Co Nudear
indiana Michigan Power Co - Transmission
Kentucky Power Co Distribution
Kentucky Power Co Generation
Kentucky Power Co - Transmission
Kingsport Power Co Distribution
Kingsport Power Co - Transmission
AEP River Operations LLC
Ohio Power Co Dishibution
Ohio Power Co Generation
Ohio Power Co - Transmission
Public Service Co of Oklahoma Distribution
Public Servics Co of Oklahoma Generation
Public Service Co of Oklahoma - Transmission
Southwestem Electtic Power Co Distribution
Southwestern Electric Power Co Generation
Southwestern Electric Power Co Texas Distribution
Southwestern Electric Power Co - Texas - Transmission
Southwestern Electric Power Co -Transmission
Ind Mich River Transp Lakin
AEP Texas North Company Distribution
AEP Texas North Company - Generatlon
AEP Texas North Company -Transmission
Wheeling Power Co Distribution
Wheeling Power Co - Transmission
Cedar Coal Co
Central Coal Company
Central Ohio Coal
Southem Ohio Coal Marlinka
Soulhem Ohio Coal - Meigs
Windsor
Prim River Coal
Houston Pipeline (HPL)
$0
16,249
0
36,357,027
5,814,612
6,145,039
948,221
0
1,629,988
4,9 0 7,3 3 3
1,200
0
645,610
3,524,042
1,983,834
309,632
55,022
90,725
121,804
338,431
0
3,635,792
2,567,060
6,934,330
866.516
1,481,760
801,532
266,325
204,149
56,236
3,377,371
4,070,933
4,438,752
1,150,919
3,549,403
2,065,766
420,990
2,499,821
2,766,233
1,295,473
0
475,539
1,243,743
1,570,410
0
268,965
282,811
0
0
0
0
0
0
0
0
0
$1,660,796
832,965
0
1,273,131,425
312,358,937
255,921,418
43.943.430
656,648
68,222,026
279,950,787
22,961,020
0
32,459,751
218,586,138
103,482,438
22,615,363
4,029,429
3,386,790
3,989,629
2,458,046
0
173,466,796
102,605,452
179,714,608
35,706,754
67,346,736
31,925,827
7,378.941
12,330,352
3.186,337
19,365,246
223,681,426
219,493,444
52,067,480
170,239,371
77,933,469
20,188,094
99,997382
99,006,191
56,372,561
559,648
15,335,390
30,333,327
67,862,877
24,572,484
10,140,903
15,274.873
1,007,455
3,173,939
0
8,477,509
6,575,959
8,946,889
3,126,046
395,631
1,293,857
$538,442
678,681
0
1,034,969,296
293,479,557
224,531,790
39,400,645
903,220
59,284,112
261,591,408
36,798,634
0
30,907,141
214,043,471
97,557,415
22,681,789
3,060,954
2,751,376
3,389,768
621,237
0
'157,411,958
91,718,477
143,306.610
32,069,142
61,632,062
30,340,448
5,992,345
11,358,604
2,588,501
5,223,370
206,584,137
162,418,820
47,090,277
162,301,469
72,331,678
18,015,466
91,025,968
92,037,309
52,158,889
529,662
13,690,380
23,503,444
64,908,345
26,801,587
10,053,426
14,986,875
1,122,088
3,258,899
0
15,765,890
9,116,416
18,352,638
5,430.91 5
466,147
2,938,282
$89,722
45,878
0
70,743,439
17,188,919
14,157,805
2,425,214
35,475
3,773.666
15,389,095
1,240,505
0
1,788,475
11,999,218
5,697,680
1,238,494
220,657
187.868
222,115
151,076
0
9,567,741
5,681,810
10,083,470
1,975,824
3,718,478
1,768,054
413,026
677,160
175,176
1,228,641
12,304,030
12,097,650
2,875,056
9,388,716
4,321,856
1,113,379
5,637,291
5,498.125
3,115,442
30,234
854,165
1,705,911
3,751,044
1,327,497
562,380
840,484
54,426
171,468
0
457,987
3 5 5,2 5 8
483.344
168,881
21,373
69,899
($42.068)
(53,025)
0
(80,861,792)
(22,929,455)
(17,542,590)
(3,078,358)
(70,568)
(4,631,847)
(20,438,045)
(2,875,064)
0
(2,414,764)
(16,723,142)
(7,622,127)
(1,772.120)
(239,151)
(214,964)
(264,841)
(48,537)
0
(12,298,541)
(7,165,933)
(11,196,495)
(2,505,551)
(4,816,292)
(2,370,489)
(468,180)
(887.444)
(202,239)
(408,100)
(16,140,347)
(14,252,163)
(3,679,147)
(12,680,557)
(5,651,264)
(1,407,542)
(7.1 11,826)
(7,190,843)
(4,075,156)
(41,382)
(1,089,625)
(1,838,316)
(5,071.1 IO)
(2,093,999)
(785,471)
(1,170,919)
(87,668)
(254,617)
0
(1,231,783)
(712,262)
(1,433,885)
(424,315)
(36,420)
(229,567)
$0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
$1,036
118
0
726,636
485,847
362,368
59,438
(4,656)
89.904
(1,147,758)
0
0
(110,544)
363,266
159,518
38,043
3,832
4,063
(12,014)
7,552
0
252,409
138,960
251,376
49,478
92,116
46,371
10,405
18.826
3,478
40,370
364,65 I
324,557
79,060
(636,333)
(243,479)
(65,508)
(311,735)
(281,516)
(153,170)
(2,417)
(42,692)
50,608
(225,262)
(157,041)
(32,421)
26,287
1,872
8,980
0
13,405
7,950
16,988
5,640
1,124
4,574
$31,946
16,022
0
24,488,877
6,008,272
4,922,688
845,259
12,631
1,312,261
5,384,897
441,659
0
624,368
4,204,538
1,990,501
435,010
77,507
65,145
76,741
47,281
0
3,336,661
1,973,632
3,458,838
686,825
1,295,463
614,098
141,935
237,176
61,290
372,493
4,302,547
4,221,990
1,001,526
3,274,581
1,499,062
388,321
1,923,469
1,904,399
1,084,335
10,765
294,979
583,466
1,305,353
472,656
195,082
293,815
19,379
81,051
0
163,066
126,490
172,095
60,130
7,610
24.888
$80.636
25,242
0
51,454,187
6,568,195
8,045,310
1,199,773
(27,118)
2,173,972
4,095,522
(1,191,700)
0
533,145
3,367,922
2,209,406
249,059
117,867
132,837
143.805
495,803
0
4,494,062
3,195,529
9,529,519
1,073,092
1,772,526
859,566
363,511
249,967
93,941
4,610,775
4,901.814
6,830,786
1,427,414
2,895,810
1,991,941
449,642
2,537,020
2,696,398
1,266,924
(2,800)
512,366
1,747,410
1,330,436
(450,887)
208,515
272.478
(11,991)
(13,118)
0
(597,325)
(222,564)
(761.458)
(189,664)
(6,313)
(130,206)
Total
$109,179,598 $4,498,732,489
$4,003,715,650 $248,990,578 ($312.808307)
$0
$684,658 $86,553,049
$132,598,976

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
LARRY C. FOUST
,

LCF Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
LARRY C. FOUST
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q*
2 A.
3 Q*
4
5 A.
6 Q*
7 A.
8
9
10
11
12
13
14
15
16
17 Q.
18
19 A.
20
PLEASE STATE YOUR NAME.
My name is Larry C. Foust.
ARE YOU THE SAME LARRY C. FOUST WHO PRESENTED DIRECT
TESTIMONY IN THIS PROCEEDING
Yes.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
I will address CAD witness Harris’ discussion of the Companies’ allocation of
certain expenses in the class cost of service study (CCOSS) and the
recommendation to present individual company data, instead of class data, for the
special contract customers of the Companies. I will also address Steel of West
Virginia witness Goins’ proposed change to the demand allocation factor in the
Companies’ CCOSS to exclude interruptible loads and CAD witness Smith’s and
Staff witness Sprinkle’s adjustments to the Companies’ proposed PJM
transmission expenses. Finally, I will respond to the rejection of the Companies’
proposed transmission tracker advocated by Staff witness Oxley, WVEUG
witness Baron, and CAD witness Harris.
PLEASE DESCRIBE THE CAD’S STATED CONCERNS ABOUT
CERTAIN ALLOCATORS IN THE COMPANIES’ CCOSS.
CAD witness Harris cited three areas of disagreement: the allocation of Customer
Records and Collection Expense (Account 903), the allocation of secondary

Page 2 of 6
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Q*
A.
Q*
A.
Q.
A.
distribution plant and expenses, and the allocation of rate case and regulatory
expense.
PLEASE COMMENT ON THE ALLOCATION OF ACCOUNT 903
EXPENSE.
As noted by Mr. Harris, the Companies did recognize an error in the allocation
factor used to allocate Account 903, However the effect of the correction on the
residential class is not $600,000, as stated by Mr. Harris. The effect is
approximately $20,000, as can be seen on LCF Rebuttal Exhibit No. 2.
PLEASE COMMENT ON THE ALLOCATION OF RATE CASE AND
REGULATORY EXPENSE.
Rate case and regulatory expenses are incurred by the Companies to prepare, file,
and litigate various regulatory proceedings. They include costs such as legal fees,
consultant fees, and filing fees. The basis for my allocation recommendation is
that those proceedings are decided by a Commission that balances the interests of
all customers. Therefore I chose to allocate those costs on the basis of customers.
While I recommend an allocation based on customers, CAD witness Harris argues
that rate case and regulatory expense should be allocated on a combination of
plant and revenues. That allocation method is not an unreasonable approach.
HOW DOES THE CAD PROPOSE TO ALLOCATE THE COST OF
SECONDARY VOLTAGE DISTRIBUTION FACILITIES
CAD witness Harris proposes to allocate secondary voltage lines and poles using
the coincident peak demand for tariff customers using electricitv at the secondarv

Page 3 of 6
voltage level and to allocate transformers using the non-coincident peak demands
by class for customers served at the secondary voltage levels.
Q.
A.
DO YOU AGREE WITH THAT METHODOLOGY
No. There are many circuits that make up the secondary voltage distribution
system. A circuit must be designed to carry the maximum load required by the
customers on that circuit, whenever it occurs. Those circuits have diverse usage
patterns. At the time of the coincident peak, each of those circuits may not be
peaking and therefore a coincident peak methodology is not appropriate to
allocate costs. The non-coincident peak demands by class for the entire
10
11
12
13
14
15
16
17
secondary distribution system are a better indicator than the coincident peak
demands, but they are still not the best indicators of usage on the individual
circuits. As Mr. Harris noted in his testimony, the maximum demand of individual
customers is also not a good indicator because of diversity. In my opinion the
best indicator lies somewhere between the non-coincident peak demands by class
for the entire secondary voltage distribution system and the maximum demands of
individual customers. That is why I chose an allocator that uses a combination of
the non-coincident peak demand by class and the maximum demands of
18 individual customers.
19 Q.
20
21
22
THE CAD RECOMMENDS THAT THE COMPANIES BE ORDERED TO
FILE ALL RELEVANT INFORMATION FOR EACH SPECIAL
CONTRACT CUSTOMER IN STATEMENT D AND THEIR CCOSS. DO
YOU THINK THAT IS APPROPRIATE

Page 4 of 6
1
2
3
A.
No. The Companies take seriously their obligation to protect individual customer
data. The Companies have presented the combined information for all special
contract customers as a group designated as Special Contracts in Statement D and
4
the CCOSS to allow analysis for the group as a whole.
Providing Statement D
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Q.
A.
on an individual customer basis would reveal sensitive rate structures and usage
specific to their contracts which I do not believe the customers would want to be
made public. Although the CCOSS does not contain information as detailed as
the Statement D, yearly load and revenue data is shown. However, the
Companies are willing to provide such individual customer information in the
CCOSS if confidentiality can be assured.
STEEL OF WEST VIRGINIA ASKS THE COMMISSION TO REQUIRE
THE COMPANIES TO EXCLUDE INTERRUPTIBLE DEMANDS IN
DEVELOPING DEMAND ALLOCATION FACTORS IN BASE RATE
AND ENEC CASES. DO YOU AGREE
No. While I recognize the arguments that Mi. Goins presents to exclude demands
from the demand allocation factor calculation, his proposal does not fully reflect
the proper treatment of interruptible loads. If one were to adopt Mr. Goins’s
theoretical approach and exclude the demands from the demand allocation factor
calculation, to be consistent one would also have to remove the energy from the
energy allocation factor. In other words, for cost of service purposes, the
interruptible sales would need to be treated similarly to off-system, or
22 opportunity, sales where no costs or revenue credits are allocated to the

Page 5 of 6
1
2
3 Q*
4
5 A.
6
7
8
9 Q*
10
11 A.
12
13
14
15
16 Q.
17
18
19 A.
20
21
22
23
interruptible service and the revenues associated with this service is allocated to
all other classes of customers as a revenue credit.
PLEASE DISCUSS THE STAFF AND CAD ADJUSTMENTS FOR PJM
ADMINISTRATIVE FEES.
Staff witness Sprinkle and CAD witness Smith reduced the Companies’
adjustment for PJM administrative fees by approximately $745,000 based upon an
analysis of the PJM administrative charges through September 2010. The
adjustment appears reasonable.
DO YOU HAVE COMMENTS REGARDING THE PJM TRANSMISSION
ENHANCEMENT CHARGES (RTEP)
Yes. These charges are similar to other PJM charges that currently are reflected
in the ENEC. As further discussed by Company witness Ferguson, the
Companies believe that the PJM RTEP charges are likewise more appropriately
included in the ENEC proceeding until such time the Commission approves a
separate transmission tracking mechanism.
DO YOU AGREE WITH THE STAFF, CAD, AND WVEUG
RECOMMENDATION THAT THE COMMISSION REJECT THE
PROPOSED TRANSMISSION TRACKER
No. While inclusion of the RTEP costs in the ENEC will alleviate some of the
concerns relating to transmission cost volatility, the Companies continue to
believe that it is appropriate to allow recovery of the FERC approved transmission
costs incurred to provide transmission service to their retail customers. Approval
of the Companies’ proposed transmission cost tracking mechanism will ensure

Page 6 of 6
1
2
that the amount of costs collected from West Virginia retail ratepayers will be no
more or less than the level of cost the Companies incur to provide retail
3 transmission service.
4 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
5 A. Yes.

LCF Rebuttal Exhibit Page 1 No. of 2
Appalachian Power CompanyMlheeling Power Company
Quantification of Account 903 class allocation factor change
ALLOCATOR
FUNCTiON
Total RS SGS MGS-SEC MGS-PRI MGS-SUB LGS-SEC LGS-PRi LGS.SUB LCP-SEC LCP-PRI LCP-SUB LCP-TRA
Updated Allocation Factors
CALL CENTER
CALL CENTER
BlLLiNG
BILLING
BILLING OTHER
BILLING OTHER
OTHER
OTHER
CUSTOMER
CUSTOMER
CUSTOMER
CUSTOMER
32.OM6W 1 00000000 0 64651669 0 09771559 0 03663317 0 00070667 0 00001041 000510666 000016626 000002062
326 942 437
000002693 000007763 000003610
106 6 089 145
000006491 000466176 000006715
450 1,299 605
0 00007271 0 00020969 0 00009776
665 1,976 920
0.00007277 0.00020902 0.00009774
132
0.00001091
43
0.00002584
160
0.00002908
274
0.00002911
DiR903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
PRODUCTION
BULKTRAN
SUBTRAN
DlSTPRl
OiSTSEC
ENERGY
CUSTOMER 1.00000000 0.66121061 0.07177566 0.02917233 0.00065139 0.00000763 0,00375106 0.00012217 0.00001536
0.00005342 0.00041900 0.00007174
TOTAL
1.00000000 0.68121061 0.07177566 0.02917233 0.00065139 0.00000783 0.00375106 0.00012217 0.00001536
0.00005342 0.00041900 0.00007174
0.00002142
0.00002142
Original Allocation Factors
CALL CENTER
CALL CENTER
BILLING
BILLING
BiLLlNG OTHER
BiLLlNG OTHER
OTHER
OTHER
CUSTOMER
CUSTOMER
CUSTOMER
CUSTOMER
30 1695% 1 00000000 0 64651680 0 09771564 0 03663316 0 00070667 0 00001040 000510659 000016626 000002060
652 1,663
000002693 000007779
216 16 179
0 00036491 0 00466206
663 2,469
0 00007278 0.00020991
1.238 3,573
000007274 000020994
673
0 00003606
290
0 00006715
1,156
0 00008766
1,663
0.00009771
263
0.00001066
66
0.00002564
345
0.00002910
495
0.00002906
DlR903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
PROOUCTiON
BULKTRAN
SUBTRAN
DlSTPRl
DISTSEC
ENERGY
CUSTOMER
TOTAL
1 .OOOOOOOO 0.66264210 0.07070543 0.02676199 0.00064912 0,00000755 0.00369514 0.00012036 0.00001509 0.00005263 0.00042764 0.00007062 0.00002106
1.00000000 0.66264210 0.07070543 0.02876198 0.00064912 0.00000755 0.00369514 0.00012036 0.00001509 0.00005263 0.00042764 0.00007062 0.00002108
Original Cost of Service
903 CLsiomer Records 8 Col ect on Exp
903 CLsiomer Records - Storm Damage
Updated Cost of Service
903 Customer Records & Collection Exp
903 Customer Records. Storm Damage
Change
TOTAL 14,152,646 12,491,698 1,000,663 407,347 9,187 107 52,297 1,704 214 745 6,052 1,000 296
TOTAL 6,399 5.646 452 184 4 0 24 1 0 0 3 0 0
TOTAL 14,152,645 12,471,838 1,015,630 412,671 9,219 106 53,066 1,729 217 756 5,930 1015 303
TOTAL 6,399 5,639 459 167 4 0 24 1 0 0 3 0 0
20.269 -15,154 -5.527 -32 1 -792 -26 -4 -11 122 -16 5

LCF Rebuttal Exhibit No. 2
Page 2 of 2
Appalach.an Poner CompanyNvnee lng Power Company
0,anI fcat on of AccoLnl903 class al.ocallon faclor change
ALLOCATOR
Updated Allocation Factors
CALL CENTER
CALL CENTER
BILLING
BILLING
BILLING OTHER
FUNCTION
CUSTOMER
CUSTOMER
CUSTOMER
CUSTOMER
IP-SEC IP-PRI IP-SUB IP-TRA sws SS-Sec SS-Pri OL SL sc
358 111,560
021517 0 06705674
1.402 103
24108 0 00001664
2.269 157
000001870 000008650 000003113 000001668 000755290 000255853 000021204 000024104 000001668
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
PRODUCTION
BULKTRAN
SUBTRAN
DlSTPRl
DISTSEC
ENERGY
CUSTOMER 0.00001376 0.00004893 0.00055278 0.00054216
0.00554790 0.00167929 0.00015577
0.00017716 0.00381048
TOTAL
0.00001378 0.00004893 0.00055278 0.00054216 0.00554790 0.00187020 0.00015577
0.00017716 0.00381048
Original Allocation Factors
CALL CENTER
CALL CENTER
BILLING
BILLING
BILLING OTHER
BILLING OTHER
OTHER
OTHER
CUSTOMER
CUSTOMER
CUSTOMER
DIR003
CUST-903
CUST-903
CUSTI903
CUST-903
CUST-903
CUST-903
CUST-903
CUST-903
PRODUCTION
BULKTRAN
SUBTRAN
DlSTPRl
DISTSEC
ENERGY
CUSTOMER
TOTAL
0.00001354 0.00004820 0.00057435 0.00056380
0.00001354 0.00004820 0.00057435 0.00056380
0.00546514 0.00185126
0.00546514 0.00185126
0.00015344
0.00015344
0.00017454 0.00396699
0.00017454 0.00396699
Original Cost of Service
903 CLslomer Records 8 Co. ecl on Exp
903 CJstomer Recoms - Storm Damage
102 682 8,129 7,979
0 0 4 4
77,347 26,201 2,172
35 12 1
0 2,470 56.144
0 1 25
Updated Cost of Service
933 CLstomer Records 8 Co lecl on Exp
903 Customer Records - Storm Damage
195 692 7,823 7,673
0 0 4 3
78.519 26,597 2,205
36 12 1
0 2,507 53,929
0 1 24
Cnange
-3 -10 305 306
-1,172 -397 -33
0 -37 2,218

APPALACHIAN POWER COMPANY
WHEELING POWER COMPANY
REBUTTAL TESTIMONY
OF
DAVID M. ROUSH

DMR Rebuttal Exhibit No. 1
REBUTTAL TESTIMONY OF
DAVID M. ROUSH
ON BEHALF OF APPALACHIAN POWER COMPANY AND
WHEELING POWER COMPANY
BEFORE THE PUBLIC SERVICE COMMISSION OF
WEST VIRGINIA IN CASE NO. 10-0699-E-42T
1 Q*
PLEASE STATE YOUR NAME, BUSINESS ADDRESS, AND POSITION.
2 A.
My name is David M. Roush.
My business address is 1 Riverside Plaza,
3
4
5
6
7 Q*
8
9 A.
10
11
12 Q.
13
14 A.
15
16
17
18
19
Columbus, Ohio 43215. I currently hold the position of Director - Regulated
Pricing and Analysis in the Regulatory Services Department of American Electric
Power Service Corporation (AEPSC), a subsidiary of American Electric Power
Company, Inc. (AEP).
WHAT ARE YOUR RESPONSIBILITIES AS DIRECTOR-REGULATED
PRICING AND ANALYSIS
My responsibilities include the oversight of the preparation of cost of service and
rate design analysis for the AEP System operating companies, and oversight of
the preparation of special contracts and pricing for customers.
PLEASE BRIEFLY DESCRIBE YOUR EDUCATIONAL AND BUSINESS
EXPERIENCE.
I graduated from The Ohio State University (OSU) in 1989 with a Bachelor of
Science degree in mathematics and a computer and information science minor. In
1999, I earned a Master of Business Administration degree from The University
of Dayton. I have completed both the EEI Electric Rate Fundamentals and
Advanced Courses. In 2003, I completed the AEP/OSU Strategic Leadership
Program. In 1989, I joined AEPSC as a Rate Assistant. Since that time I have

Page 2 of 6
1
2
3 Q*
4
5 A.
6
7
8
9 Q*
10 A.
11
12 Q.
13 A.
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15
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17
18 Q.
19
20 A.
21
22
23
progressed through various positions and was promoted to my current position of
Director-Regulated Pricing and Analysis in June 2010.
HAVE YOU PREVIOUSLY TESTIFIED BEFORE ANY REGULATORY
COMMISSIONS
Yes. I have submitted testimony before the Public Service Commission of West
Virginia (Commission), Indiana Utility Regulatory Commission, the Public
Service Commission of Kentucky, the Michigan Public Service Commission and
the Public Utilities Commission of Ohio.
DID YOU SUBMIT DIRECT TESTIMONY IN THIS PROCEEDING
No. However, due to the retirement of Company witness Dennis W. Bethel, I am
adopting his Direct Testimony and Exhibits as my own.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY
I will address CAD witness Harris’ rate design proposal for the residential tariff
(Schedule RS); West Virginia Energy Users Group (WVEUG) witness Baron’s,
Wal-Mart witness Chriss’ and Kroger witness Higgins’ rate design proposals for
the commercial and industrial tariffs (Schedules MGS, LGS, GS, LCP, IP and
LPS); and Steel of West Virginia witness Goins’ discussion of interruptible rates.
WHAT DOES MR. HARRIS RECOMMEND FOR THE RESIDENTIAL
(RS) RATE DESIGN
Mr. Harris proposes to eliminate the current declining block rate structure of the
residential tariff. The current structure includes a higher rate for the first 500
kWh consumed and a lower rate for all additional usage. Mr. Harris also proposes
a slightly higher customer charge.

Page 3 of 6
1
2
Q. DO YOU AGREE WITH MR. HARRIS’ RESIDENTIAL RATE DESIGN
RECOMMENDATIONS
3
4
5
6
7
8
9
10
11
12
13
14
15
16
A.
In concept, I do. To the extent possible, the residential rate should consist of a
full cost customer charge and a single full cost energy charge. However, one
must also evaluate the impacts which that rate design would have on various
residential customers. A comparison of the impacts under the Companies’ rate
design and Mr. Harris’ rate design is as follows:
% INCREASE USING % INCREASE USING
MONTHLY COMPANIES CAD
USAGE RATE DESIGN RATE DESIGN
(kW
100 16.4% 11.9%
250 16.7% 8.7%
500 16.9% 7.3%
1,000 17.0% 14.5%
2,000 17.1% 18.9%
4,000 17.1% 21.3%
As can be seen from this table, Mr. Harris’ rate design results in significant
variations in the bill impacts on customers. The higher percentage increase on
higher usage customers would seem to exacerbate CAD witness Alexander’s
concern that “poor and near-poor customers who use a higher than average
amount of electricity due to larger family sizes, poorly insulated dwellings,
medical need for electricity, etc. will see significantly higher bills that will
adversely impact their ability to obtain and maintain essential electricity service.”
One possible way to balance both interests and manage the impact during high
winter use months would be to eliminate the declining block only for the months
17 of May through November, and maintaining the declining block during the

Page 4 of 6
1
2
3 Q*
4
5
6
7 A.
8
9
10
11
12
13
14
15 Q.
16
17
18 A.
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20
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22
months of December through April when the 20% discount under the S.R.R.-R.S.
amendment applies.
PLEASE COMMENT ON THE CONCERNS OF WVEUG, WAL-MART,
AND KROGER ABOUT THE LEVEL OF FIXED COSTS INCLUDED IN
THE DEMAND CHARGES OF THE COMPANIES’ COMMERCIAL AND
INDUSTRIAL RATES.
In concept, I do not disagree with the objectives of these parties to include a high
percentage of fixed costs in demand charges, or charges equivalent to demand
charges, for rate schedules that include high load factor customers. However,
these objectives must be balanced against the principle of gradualism to ensure
that such a design does not create bill impact issues for lower load factor
customers. The appropriate percentage of fixed costs to achieve that balance is a
direct function of the class revenue level. The Companies’ proposed rate design
was intended to strike such a balance at the proposed revenue levels.
PLEASE COMMENT ON THE CONCERNS OF WVEUG, WAL-MART,
AND KROGER ABOUT THE COMPANIES’ PROPOSALS WITH
RESPECT TO SCHEDULES GS AND LPS.
I agree with Mr. Baron, Mr. Chriss, and Mr. Higgins that, whatever appropriate
percentage of fixed costs is included in demand charges, or charges equivalent to
demand charges, the same percentage should be reflected in the proposed
Schedules GS and LPS. This seemed to be a primary source of Mr. Higgins’
reluctance to implement Schedule GS even though he did not oppose a combined
23
Schedule GS in principle.
If Schedule GS is implemented on a voluntary,

Page 5 of 6
1
2
3
4
5
Q.
optional basis, as suggested by Mr. Higgins, then a migration adjustment must be
made in the rate design to recognize that customers would elect Schedule GS only
if their billing would be lower than under Schedules MGS or LGS. Such an
adjustment is unnecessary under the Companies’ proposal.
PLEASE COMMENT ON MR. GOINS’ RECOMMENDATION THAT
6
7
INTERRUPTIBLE CUSTOMERS SHOULD PAY NO
CHARGES
CAPACITY
8
9
10
11
12
13
14
15
16
17
A.
Mr. Goins makes a number of arguments concerning the treatment of interruptible
load. The crux of his arguments seems to be that a utility does not build or
acquire generating capacity to serve interruptible load and therefore interruptible
customers should not pay any capacity charges for their interruptible load. Of
course, if you took this concept to its extreme and posited a utility with only
interruptible load customers, that utility would be unable to build power plants or
enter into power supply contracts of any duration because it would have no
customers who would pay for the capacity needed to serve them. As a practical
matter, the Companies’ interruptible customer loads receive firm service for
thousands upon thousands of hours a year and only experience occasional
18
interruptions.
As reflected in the express terms of the Companies’ current
19
20
21
interruptible service agreements, it is entirely reasonable and appropriate to
expect interruptible customer loads to make some contribution to the recovery of
the fixed costs of providing the power on which they rely, albeit, a lesser
22
contribution than the contribution required of firm loads.
In any event,

Page 6 of 6
1
interruptible service is an important tool for utility peak management and resource
2 planning.
3 Q.
4
IN LIGHT OF THE RECOMMENDATIONS OF THE OTHER PARTIES
AS DISCUSSED ABOVE, HAVE THE COMPANIES’ RATE DESIGN
5 PROPOSALS CHANGED
6 A.
No. The Companies continue to support the rate design as filed.
7 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY
8 A. Yes.

PUBLIC SERVICE COMMISSION
OF WEST VIRGINIA
CHARLESTON
CASE NO. 10-0699-E-42T
APPALACHIAN POWER COMPANY and
WHEELING POWER COMPANY,
public utilities.
Joint Application for Rate Increases on Notice
with Proposed Effective Dates and Changes in
Tariff Provisions, Pursuant to W.Va. Code, §§24-2-4aY
and Approval of a Transmission Rate Adjustment Clause Rider
CERTIFICATE OF SERVICE
I, William C. Porth, counsel for Appalachian Power Company and Wheeling Power
Company, do hereby certify that true copies of the foregoing rebuttal testimonies were served
upon the following parties to this proceeding by hand delivery or first-class U.S. Mail this 24th
day of November, 201 0, addressed to the following:
Leslie J. Anderson, Esquire
Derrick P. Williamson, Esquire
Public Service Commission
Barry A. Naum, Esquire
201 Brooks Street
Spilman Thomas & Battle, PLLC
Charleston, West Virginia 25301 1100 Bent Creek Blvd., Suite 101
Counsel for Mechanicsburg, PA 17050
Stuff0 f West Virginia
Counsel for
Public Service Commission
West Virginia Energy Users Group
Jacqueline Lake Roberts, Esquire
David A. Sade, Esquire
Consumer Advocate Division
700 Union Building
723 Kanawha Blvd., East
Charleston, WV 25301
Counsel for
Consumer Advocate Division
Susan J. Riggs, Esquire
Spilman Thomas & Battle, PLLC
300 Kanawha Blvd., East
Charleston, WV 25301
Counsel for
West Virginia Energy Users Group
Kwt J. Boehm, Esquire
Thomas N. Hanna, Esquire
Boehm, Kurtz & Lowry 1206 Virginia St., E., Suite 201
36 East Seventh St., Suite 1510 Charleston, WV 25301
Cincinnati, OH 45202
Counsel for
Counsel for
The Kroger Company
The Kroger Company
IR0544946. I}

Damon E. Xenopoulos, Esquire
Brickfield, Burchette, Ritts
& Stone, PC
1025 Thomas Jefferson St., NW
8th Floor - West Tower
Washington, DC 20007
Counsel for
Steel of West Virginia, Inc.
John H. Shott, Esquire
621 Commerce Street
Bluefield, WV 24701
Counsel for South
Bluefield Neighborhood Association
Holly Rachel Smith, Esquire
Holly Rachel Smith, PLLC
Hitt Business Center
3803 Rectortown Road
Marshall, VA 201 15
Counsel for
Wal-Mart Stores East, LP
& Sam’s East, Inc.
Ralph Smith
Larkin & Associates
15728 Farmington Road
Livonia, MI 48154
Consultant for
Consumer Advocate Division
Stephen J. Baron
J. Kennedy & Associates, Inc.
570 Colonial Park Drive, Suite 305
Roswell, GA 30075
Consultant for
West Virginia Energy Users Group
James V. Kelsh, Esquire
Law Office of James V. Kelsh
300 Summers St., Suite 1230
P.O. Box 3713
Charleston, WV 25337
Counsel for
Steel of West Yirginia, Inc.
Tanya Hunt Handley, Esquire
MacCorkle, Lavender
& Sweeney, PLLC
300 Summers St., Suite 800
Charleston, WV 25301
Counsel for
Wal-Mart Stores East, LP
& Sam’s East, Inc.
Steve Chriss
Walmart
2001 S.E. loth Street
Bentonville, AR 727 16
Counsel for
Wal-Mart Stores East, LP
& Sam’s East, Inc.
Kevin Higgins
Energy Strategies, LLC
Parkside Towers
215 South State St., Suite 200
Salt Lake City, UT 841 11
Consultant for The Kroger Co.
Barbara Alexander
83 Wedgewood Drive
Winthrop, ME 04364
Consultant for
Consumer Advocate Division
William C. Porth (WV State Bar ID No. 2943)
{ R0544946.1}