American Electric Power 801 Pennsylvania Avenue N.W. Suite 320 Washington, DC 20004 AEP.com

April 7, 2010

Monique Rowtham-Kennedy Monique Rowtham-Kennedy Senior Counsel Regulatory Services Senior Counsel - Regulatory Services (202) 383-3436 (202) 383-3436 (202) 383-3459 (F) (202) 383-3459 (F)

Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E., Room 1A Washington, D.C. 20426

Re: American Electric Power Service Corporation, FERC Docket No. ER08-1329

Dear Secretary Bose:

Pursuant to Rule 602 of the Federal Energy Regulatory Commissions (the Commission) Rules of Practice and Procedure, 18 C.F.R.385.602 (2008), American Electric Power Service Corporation (AEPSC) on behalf of its affiliates, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, and Wheeling Power Company (collectively AEP or the AEP East Companies), and on behalf of Blue Ridge Power Agency, Craig-Botetourt Electric Cooperative, The Musser Companies (Black Diamond Power Co., Elk Power Co., and Union Power Co,), Indiana Municipal Power Agency, City of Dowagiac, Michigan, American Municipal Power-Ohio, Inc, The AEP Intervenor Group1, Wabash Valley Power Association, Inc., Buckeye Power, Inc. and Indiana and Michigan Municipal Distributors Association (collectively, the Joint Intervenors), (individually, a Settling Party, and, collectively, the Settling Parties) submit an original and fourteen copies of an Offer of Settlement intended to resolve without need for evidentiary procedures all issues set for hearing in the

1 The AEP Intervenor Group consists of large industrial customers that take service from one or more AEP East Operating Companies.

Kimberly D. Bose, Secretary April 7, 2010 Page 2 of 3

captioned proceedings. In addition, this Settlement is supported or not opposed by all parties who have intervened in this proceeding2.

This Offer of Settlement includes the following documents:

1. Explanatory Statement (Appendix A); 2. Settlement Agreement (Appendix B), and several attachments described

below;

3. Draft Order Approving Settlement Agreement (Appendix C), and 4. Service List (Appendix D).

The attachments to the Settlement Agreement, Appendix B, include the following:

1. Attachment A, Cost of Service and Formula Rate Settlement Principles; 2. Attachment B-1, Revised Tariff language (Blacklined); 3. Attachment B-2, Revised Tariff language (Clean); 4. Attachment C, Interest Calculation Examples Pursuant to 18 C.F.R.

35.19a.; and

7. Attachment D, Populated Formula Rate Template for Rates Effective July 1, 2009.

8. Attachment E, Allowable PBOP Expense Formula

All parties in this proceeding and the Commissions Trial Staff have had the opportunity to review and comment on the Offer of Settlement, and no party has objected to its provisions. The Settling Parties expect this Offer of Settlement to be unopposed. PJM Interconnection , LLC (PJM) has represented to AEP that, if the Commission approves the Offer of Settlement, PJM will file conformed tariff sheets implementing the settlements terms.

AEP requests that the appropriate number of copies of this filing be transmitted to

Presiding Administrative Law Judge Karen Johnson in accordance with Commission Rule 602(b)(2)(i). In accordance with Rule 602(d), copies of this filing have been

2 In addition to the Settling Parties, these include the Maryland Office of People's Counsel, Office of the Attorney General of the Commonwealth of Virginia Division of Consumer Counsel, North Carolina Electric Membership Corporation, Kentucky Public Service Commission, Old Dominion Electric Cooperative, Public Service Commission of Maryland, PJM Interconnection, LLC, Dominion Resources Services, Inc., PJM Commercial and Industrial End Users, Steel Dynamics, Inc, PHI Companies, PPL Electric Utilities Corporation, FirstEnergy Companies, Ameren Services Company (Ameren), PSEG Companies, Hoosier Energy Rural Electric Cooperative, Inc., Exelon Corporation, and Consumers Energy Company

Appendix A EXPLANATORY STATEMENT

UNITED STATES OF AMERICA

BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

American Electric Power Service ) Docket No. ER08-1329-000 Corporation )

EXPLANATORY STATEMENT IN SUPPORT OF SETTLEMENT AGREEMENT

Pursuant to Rule 602 of the Commissions Rules of Practice and Procedure, 18

C.F.R. 385.602 (2008), American Electric Power Service Corporation (AEPSC), on

behalf of Appalachian Power Company, Columbus Southern Power Company, Indiana

Michigan Power Company, Kentucky Power Company, Kingsport Power Company,

Ohio Power Company, and Wheeling Power Company (collectively AEP or the AEP

East Companies) and certain parties to these Proceedings1, (individually, Settling

Party, and together, Settling Parties) submit this Explanatory Statement in support of

the concurrently filed Settlement Agreement, which is intended to resolve all issues in

this proceeding. In addition, this Settlement is supported or not opposed by all parties

who have intervened in this proceeding2.

1 The Settling Parties include: Blue Ridge Power Agency, Craig-Botetourt Electric Cooperative, The Musser Companies (Black Diamond Power Co., Elk Power Co., and Union Power Co,), Indiana Municipal Power Agency, City of Dowagiac, Michigan, American Municipal Power, Inc, The AEP Intervenor Group1, Wabash Valley Power Association,Inc., Buckeye Power, Inc. and Indiana and Michigan Municipal Distributors Association (collectively, the Joint Intervenors), 2 In addition to the Settling Parties, these include the Maryland Office of People's Counsel, Office of the Attorney General of the Commonwealth of Virginia Division of Consumer Counsel, North Carolina Electric Membership Corporation, Kentucky Public Service Commission, Old Dominion Electric Cooperative, Public Service Commission of Maryland, PJM Interconnection, LLC, Dominion Resources Services, Inc., PJM Commercial and Industrial End Users, PHI Companies, PPL Electric Utilities Corporation, FirstEnergy Companies, Ameren Services Company (Ameren), PSEG Companies, Hoosier Energy Rural Electric Cooperative, Inc., Exelon Corporation, and Consumers Energy Company .

1

I. INTRODUCTION

The AEP East Companies are operating companies of the American Electric

Power System providing electric service to customers at retail and wholesale in parts of

Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia, and West Virginia. AEPSC is

a company that provides professional and business services to the AEP East Companies.

The AEP East Companies are members of the PJM Interconnection, LLC (PJM), a

Commission-approved regional transmission organization (RTO) which, among other

things, offers transmission service on a regional basis pursuant to an Open Access

Transmission Tariff (OATT).

Transmission rates in PJM are currently zonal in nature (except for certain high-

voltage facilities constructed pursuant to the PJM regional transmission expansion plan

(RTEP), the costs of which are allocated to more than one PJM zone). In general,

customers within a particular rate zone, corresponding generally to the system of a

transmission-owning member of PJM, pay a rate for network integration transmission

service (NITS) that reflects the cost of service of the zonal transmission facilities. AEP

recovers its annual transmission cost of service (TCOS) for the AEP East Companies

zone of PJM (AEP Zone) through charges assessed by PJM pursuant to Attachment

H-14 of the PJM OATT. The transmission-owning members of PJM retain the right to

make filings under Section 205 of the Federal Power Act, 16 U.S.C. 824, et seq., to

change the rate for service in their zones. Historically within PJM, AEPs transmission

revenue requirements and the resulting unit charges have been stated rather than

formulaic. Under a stated rate approach, AEPs transmission revenue requirement and

2

unit charges for service to load within the pricing zone change only as the result of a

Federal Power Act (FPA) Section 205 or Section 206 rate filing.

On July 31, 2008, AEP filed with the Commission an application to increase its

zonal transmission rates under the PJM OATT and to convert its stated zonal rates into

formula rates. Formula rates allow cost-based rates, with certain exceptions, to be

adjusted annually to reflect changes in the TCOS and other factors underlying such rates.

AEP sought an effective date of October 1, 2008. The proposed formula rate included

Formula Rate Implementation Protocols and a Blank Formula Rate Template to be

populated annually with cost of service data to calculate the Annual Transmission

Revenue Requirement (ATRR) supporting the charges in effect during each Rate Year.

The ATRR calculated by application of the formula rate encompasses the TCOS both for

facilities owned by the AEP East Companies that were constructed pursuant to the PJM

RTEP and for facilities that predate or are outside the scope of the RTEP process. The

formula rate provides a means for separately evaluating the revenue requirement for AEP

Zone (NITS) and regional (RTEP) facilities that are allocated by PJM to transmission

customers outside the AEP Zone.

AEPs filing included a Completed Formula Rate Template that would establish

AEPs proposed ATRR for a shortened initial period3. The completed template

applicable to the initial period then would be followed by annual updates effective from

July 1 each year through June 30 of the following year (Rate Year). The ATRR will

include certain projected cost data, and will be trued-up annually to reflect actual costs

3 The initial period as proposed was to have been October 1, 2008 through June 30, 2009, but was shortened by imposition of a five-month suspension of the effective date to run from March 1, 2009 through June 30, 2009. The first annual update was implemented as of July 1, 2009, pursuant to the as-filed formula rate, subject to refund.

3

and other relevant factors. Amounts over-collected or under-collected then would be

refunded or charged to customers, with interest.

Motions to intervene in this proceedings were filed by Blue Ridge Power Agency,

Craig-Botetourt Electric Cooperative, The Musser Companies (Black Diamond Power

Co., Elk Power Co., and Union Power Co.), Indiana Municipal Power Agency, City of

Dowagiac, Michigan, Old Dominion Electric Cooperative, American Municipal Power,

Inc.4, The AEP Intervenor Group5, Wabash Valley Power Association, Inc., Buckeye

Power, Inc., and Indiana Michigan Municipal Distributors Association ( collectively, the

Joint Intervenors), the Maryland Office of People's Counsel (MOPC), Office of the

Attorney General of the Commonwealth of Virginia Division of Consumer Counsel

(Virginia Consumer Counsel), North Carolina Electric Membership Corporation

(NCEMC), Kentucky Public Service Commission, Public Service Commission of

Maryland, PJM Interconnection, LLC (PJM), Dominion Resources Services, Inc.

(Dominion Services), PJM Commercial and Industrial End Users, PHI Companies

(PHI), PPL Electric Utilities Corporation (PPL), FirstEnergy Companies

(FirstEnergy), Ameren Services Company (Ameren), PSEG Companies (PSEG),

Hoosier Energy Rural Electric Cooperative, Inc. (Hoosier), Exelon Corporation

(Exelon), and Consumers Energy Company (Consumers).

Protests of AEPs filing were submitted by the Joint Intervenors, MOPC and the

Virginia Consumer Counsel. AEP filed an answer to the protests. On September 30,

2008, the Commission issued an order accepting AEPs proposed formula rates for filing,

4 American Municipal Power, Inc. previously was known as American Municipal Power-Ohio, Inc. (or AMP-Ohio). The change in name was made effective on July 1, 2009. 5 The AEP Intervenor Group consists of large industrial customers that take service from one or more AEP East Operating Companies.

4

subject to certain modifications to be made in a compliance filing and after hearing. In

doing so, the Commission suspended the proposed formula rates for five months, making

them effective, as modified, on March 1, 2009, subject to refund, set the proposed rates

for hearing, and established settlement judge procedures. Order Accepting and

Suspending Revised Tariff Sheets and Establishing Hearing and Settlement Judge

Procedures, 124 FERC 61,306 (2008). On October 30, 2008, AEP submitted a

compliance filing in which, among other things, AEP proposed amendments to sections

3(d) and 3(e) of the Formula Rate Protocols to remove language that could be interpreted

as limiting rights of parties under section 206 of the Federal Power Act.

On February 5, 2009, in response to a request by Commission staff, AEP filed an

amendment to its compliance filing in which additional changes to section 3(d) of the

Formula Rate Protocols were proposed to further clarify that the customer protocols do

not limit a customers or the Commissions rights with respect to challenges to the inputs

into the formula rate. On March 13, 2009, the Commission accepted AEPs compliance

filing. See Letter Order issued March 13, 2009 in Docket Nos. ER08-1329-002 and

ER08-1329-003.

The Honorable Karen Johnson was appointed Settlement Judge. Judge Johnson

convened the first settlement conference on October 21, 2008. Settlement discussions

continued since then, and included informal information gathering and numerous

conferences, meetings and telephone conversations. The Commissions Trial Staff

participated actively in the discussions. Judge Johnson submitted periodic reports to the

Commission on the progress of the settlement discussions.

5

Ultimately, the settlement discussions culminated in the Settlement Agreement

being filed herewith. The Settling Parties are AEP and the Joint Intervenors. MOPC and

Virginia Consumer Counsel have indicated by their signature on the Settlement

Agreement that, while they are not Settling Parties, they will not contest the settlement.

Thus, all of the entities that protested AEPs rate filing are either Settling Parties or have

indicated in writing that they will not contest the Settlement Agreement. The only

entities that are not Settling Parties and have not indicated by their signature on the

Settlement Agreement that they do not object to the Settlement Agreement are the

Commission Trial Staff and various other intervenors, including several other PJM

transmission-owning utilities who had intervened in the proceeding but had not filed

protests. AEP has canvassed all of the intervenors who elected not to sign the Settlement

Agreement andotests. AEP has canvassed all of the intervenors who elected not to join in

the Settlement and understands that they either support or do not oppose the Settlement

Agreement.

II. SUMMARY OF SETTLEMENT AGREEMENT

The substantive terms of the Settlement Agreement are set forth in five

Attachments to the Settlement Agreement, as follows:

A. Cost of Service and Formula Rate Settlement Principles;

B. Revised tariff language, in Blacklined (B-1) and Clean (B-2) format, that

will be incorporated in the PJM OATT;

C. Interest Calculation Examples Pursuant to 18 C.F.R. 35.19a;

D. Populated Formula Rate Template for Rates Effective July 1, 2009; and

E. Allowable PBOP Expense Formula.

6

The following is a summary of each of the Attachments:

A. Cost-of-Service and Formula Rate Settlement Principles

The Cost-of-Service and Formula Rate Settlement Principles (Attachment A to

the Settlement Agreement) set forth agreed-upon methods for determining certain

specified elements of the ATRR6. The principles cover a variety of TCOS elements and

related matters, including retail vs. wholesale ratemaking practices, costs of transmission

studies, rate base, expenses, capital structure, costs of capital, return on common equity,

cost allocator factors, and formula rate implementation.

Significant provisions in Attachment A include agreements regarding return on

equity, capital structure, cost of capital, and interest rate derivative hedging on long term

debt (collectively Cost of Capital), treatment of Post Retirement Benefits Other Than

Pensions (PBOP) expenses and transmission depreciation rates.

1. Cost of Capital. The agreements on Cost of Capital are set forth in

Section I. D. of Attachment A. The agreed-upon cost of common equity to be used in the

formula rate is 10.99%, plus a 50 basis point adder for AEPs continuing participation in

the PJM RTO, resulting in an 11.49% total ROE. The Settlement Agreement also limits

the amount of any incentive ROE that AEP may seek for a period of 36 months from the

effective date of the Settlement. That limitation is 125 basis points above the Base ROE.

This limits to 12.74% the ROE that AEP may request for any project as to which AEP

seeks an incentive ROE. For the period between March 1, 2009 and December 31, 2011,

specified maximum percentages (Equity Caps) will apply to the amounts of common

6 As filed, the rate formula contained initial inputs for the charges that, pursuant to the Commissions September 30 Order, became effective March 1, 2009, subject to refund, and remained in effect until June 30, 2009. AEP has posted its first annual update of the inputs to the formula rate, which went into effect on July 1, 2009 and will remain in effect until June 30, 2010, subject to true-up as described in the formula.

7

equity in AEPs capital structure that AEP can use in determining the after-tax weighted

average cost-of-equity for purposes of the formula rate (regardless of the actual

percentage of equity). The Equity Caps are: 55% for Ohio Power Company, 51% for

Columbus Southern Power, and 50% for Appalachian Power, Indiana Michigan Power,

and Kentucky Power. The Equity Caps will be implemented only in TCOS calculations

pursuant to provisions governing the annual reconciliation between projected and actual

costs (true-up provisions) of the Formula Rate (that is, the Equity Caps will not apply

in the Annual Updates except for the portion of the update that trues-up the prior-year

cost of service). Further, if the amount of common equity in the actual capitalization of

any AEP East Company subject to an Equity Cap exceeds the Equity Cap, the amount of

common equity exceeding the cap will be assigned the same cost rate as long-term debt.

Finally, there is an agreed-upon limitation on the amount of gains or losses from certain

eligible interest rate hedging in which AEP may engage that is includible in the cost of

debt. Those gains or losses may not exceed an amount that is equal to five (5) basis

points in the weighted average cost of capital.

2. PBOP Expenses. The treatment of PBOP Expenses is addressed in

Section I.C.6 of Attachment A. The Settling Parties have agreed upon a specified amount

of PBOP expenses ($48.1 million) that will be allocable to the TCOS based on a labor

expense allocator. The Settling Parties also have agreed to a process, which is set forth in

Attachment F, for changing that amount in the event that AEP either over-recovers or

under-recovers such expenses on a cumulative basis from and after the effective date of

the Settlement. Any change in the stated PBOP expense amount that is required by the

agreed-upon process must be filed with the Commission under Section 205 before it can

8

become effective in the formula rate. The Settlement provides that the methodology for

determining whether a change in the stated PBOP expense is required (because the

amount of over- or under-recovery exceeds a specified threshold) is subject to the

Mobile-Sierra public interest standard.

3. Depreciation Rates. Depreciation rates are addressed in Section

I.C.5 of Attachment A. The Settling Parties have agreed that the formula rate would use

AEPs composite depreciation rates which are based on state commission-approved and

FERC-approved depreciation rates. Attachments B-1 and B-2 contain a summary of

AEPs state approved depreciation rates for transmission plant. AEP will make a section

205 filing at FERC to seek changes to its composite depreciation rate methodology or to

reflect in the formula rate calculations any change in state-approved or FERC-approved

depreciation rates.

B. Revised Tariff Sheets

Resolution of the issues as set forth in Attachment A requires certain changes to

the tariff sheets for transmission services for the AEP Zone. Attachments B-1 and B-2

provide tariff language, including the Formula Rate Implementation Protocols, that the

Settling Parties have agreed is necessary to implement the Settlement Agreement.

Accordingly, these attachments will be incorporated in the PJM OATT following

Commission approval of the Settlement Agreement.

Among other changes, the revised Formula Rate Implementation Protocols

provide more time than originally proposed for customers to submit information requests

and raise challenges to the Annual Updates. The Formula Rate Implementation Protocols

provide that, except as expressly provided, nothing in the formula rate limits any

9

interested partys rights to make a filing under Section 205, 206 or 306 of the Federal

Power Act.

C. Revised Formula Rate Template

The Blank Formula Rate Template ,which is included in Attachments B-1 and B-

2, has been revised from that accepted by the Commission in its September 30, 2008 and

March 13, 2009 Orders to reflect the Cost-of-Service and Formula Rate Settlement

Principles set forth in Attachment A.

D. Interest Calculation Examples

The Settlement Agreement provides that the True-Up adjustments for AEP

revenue requirements will be rolled forward to be refunded or collected during the next

Rate Year. The Interest Calculation Examples contained in Attachment C to the

Settlement Agreement illustrate how interest on refunds or additional charges will be

computed in each case, consistent with using an amortization methodology with interest

rates derived from provisions of 18 C.F.R. 35.19a.

E. Populated Formula Rate Template for Rates Effective July 1, 2009

Resolution of the issues as set forth in Attachment A requires changes to the

populated Formula Rate Template for rates effective July 1, 2009 through June 30, 2010

(posted in May 2009). Attachment D to Appendix B consists of the agreed-upon

populated Formula Rate Template, which calculates the ATRR for the Rate Year

beginning July 1, 2009 and ending June 30, 2010 based on the settlement methodology.

AEP will submit a Motion to expedite implementation of the revised rates resulting from

the revised populated template effective January 1, 2010. If approved, this change in

10

going forward invoicing will reduce the collections, and subsequent refunds due, for the

last six months of the Rate Year.

III. PROCEDURAL ASPECTS OF SETTLEMENT AGREEMENT

The remaining provisions of the Settlement Agreement address procedural aspects

of the Settlement Agreement including implementation, non-severability, rights reserved,

waiver and amendment, and the scope of review. Specifically, with specified exceptions,

the standard of review for modifications to the Settlement Agreement (including changes

to the formula rate and values used in computing the formula rate) that are proposed by

any Settling Party will be the just and reasonable standard under FPA 205/206.

Certain specific provisions are subject to a more stringent standard for unilateral

modification requests: viz., the public interest standard adopted in the Sierra-Mobile

line of cases. Provisions as to which a unilateral request for modification would require a

public interest showing are: (i) the methodology set forth in Attachment A, section

I.C.6, for determining whether AEP is required to file a change to the PBOP expense

allowance; (ii) the duration and amount of the Equity Caps established pursuant to

Attachment A, paragraph I.D.2.c; (iii) the duration and amount of the limitation, set forth

in Attachment A, paragraph I.D.1.a, on the amount of any incentive return on common

equity AEP may request; and (iv) the limitation on the amount of eligible hedging gains

and losses AEP may reflect in the cost of long-term debt. The standard of review for

modifications to the Settlement Agreement proposed by any non-party to the Settlement

Agreement and the Commission acting sua sponte, after it is approved by the

Commission, will be the most stringent standard permitted by law.

IV. RESPONSES TO REQUIRED QUESTIONS

11

By order dated October 23, 2003, the Chief Administrative Law Judge requires

that five questions be answered as part of every Explanatory Statement submitted in

support of a proposed settlement. The questions and specific responses thereto applicable

to this Settlement Agreement are as follows:

1. What are the issues underlying the settlement and what are the major implications?

The issues raised in this proceeding that underlie the Settlement Agreement are:

What should be the appropriate Formula Rate Template to determine annual transmission

revenue requirements at each annual Update, and what just and reasonable provisions and

protocols should the formula rate contain?

2. Whether any of the issues raise policy implications.

The resolution of the underlying issues does not raise any policy implications.

3. Whether other pending cases may be affected.

The Settlement Agreement addresses the specific transmission service formula

rates at issue in this proceeding. No other pending cases are affected.

4. Whether the settlement involves issues of first impression, or if there are any previous reversals on the issues involved?

There are no issues of first impression presented in this proceeding or resolved

by the Settlement Agreement. There are no previous reversals with respect to the

transmission formula rates at issue in this proceeding.

5. Whether the proceeding is subject to the just and reasonable standard or whether there is Mobile-Sierra language making it the standard, i.e., the applicable standards of review.

This proceeding on AEPs rate filing is subject to the just and reasonable

standard. Section 6.7 of the Settlement Agreement states that, except as specified, a

unilateral request by a Settling Party to modify any provision of the Settlement

12

Appendix B SETTLEMENT AGREEMENT

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

American Electric Power Service ) Docket No. ER08-1329-000 Corporation )

SETTLEMENT AGREEMENT

Pursuant to Rule 602 of the Rules of Practice and Procedure of the Federal Energy

Regulatory Commission (Commission), 18 C.F.R. 385.602 (2008), American Electric

Power Service Corporation (AEPSC), on behalf of Appalachian Power Company,

Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky

Power Company, Kingsport Power Company, Ohio Power Company, and Wheeling

Power Company (collectively AEP or the AEP East Companies) and certain

entities1 that have intervened in this proceeding as indicated below (individually,

Settling Party and together, Settling Parties) submit this Settlement Agreement to

resolve all issues between and among them in this docket. In addition, this Settlement is

supported or not opposed by all parties who have intervened in this proceeding2.

1 Blue Ridge Power Agency, Craig-Botetourt Electric Cooperative, The Musser Companies (Black Diamond Power Co., Elk Power Co., and Union Power Co,), Indiana Municipal Power Agency, City of Dowagiac, Michigan, American Municipal Power-Ohio, Inc, The AEP Intervenor Group1, Wabash Valley Power Association, Inc., Buckeye Power, Inc. and Indiana and Michigan Municipal Distributors Association (collectively, the Joint Intervenors)2 In addition to the Settling Parties, these include the Maryland Office of People's Counsel, Office of the Attorney General of the Commonwealth of Virginia Division of Consumer Counsel, North Carolina Electric Membership Corporation, Kentucky Public Service Commission, Old Dominion Electric Cooperative, Public Service Commission of Maryland, PJM Interconnection, LLC, Dominion Resources Services, Inc., PJM Commercial and Industrial End Users, Steel Dynamics, Inc., PHI Companies, PPL Electric Utilities Corporation, FirstEnergy Companies, Ameren Services Company, PSEG Companies, Hoosier Energy Rural Electric Cooperative, Inc., Exelon Corporation, and Consumers Energy Company .

1

ARTICLE I INTRODUCTION

The AEP East Companies are operating companies of the American Electric

Power System providing electric service to customers at retail and wholesale in parts of

Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia, and West Virginia. AEPSC is

a company that provides professional and business services to the AEP East Companies.

The AEP East Companies are members of the PJM Interconnection, LLC (PJM), a

Commission-approved regional transmission organization (RTO) which, among other

things, offers transmission service on a regional basis pursuant to an Open Access

Transmission Tariff (OATT). Transmission rates in PJM currently are zonal in nature,

for transmission facilities planned before the introduction of the PJM regional

transmission expansion planning (RTEP) process, i.e., customers within a particular

rate zone, corresponding generally to the system of a transmission-owning member of

PJM, pay a rate for network integration transmission service (NITS) that reflects the

costs of pre-RTEP transmission facilities, as well as the costs of new transmission

facilities that are allocated on a zonal basis. The annual revenue requirement for

transmission facilities in the AEP East Companies zone of PJM (AEP Zone) is

collected by PJM through charges assessed under Attachment H-14 of the PJM OATT.

The transmission-owning members of PJM retain the right to make filings under Section

205 of the Federal Power Act, 16 U.S.C. 824, et seq., to change the rates for service in

their respective zones.

Historically within PJM, AEPs annual transmission revenue requirement

(ATRR) and the associated unit charges for service to load within the pricing zone have

2

been stated rather than formulaic. Under a stated rate approach, AEPs ATRR and unit

charges for service may be changed only through a Federal Power Act (FPA) Section

205 or Section 206 rate filing.

On July 31, 2008, AEP filed with the Commission an application to increase its

zonal transmission rates under the PJM OATT and to convert its stated zonal rates into

formula rates. Formula rates allow cost-based rates, with certain exceptions, to be

adjusted annually to reflect changes in various factors that affect the transmission cost of

service (TCOS) (e.g., changes in the amount of transmission Plant in Service,

transmission-related expenses, allocation factors, loads, etc.). The proposed formula rate

included Formula Rate Implementation Protocols and a Blank Formula Rate Template to

be populated annually with cost-of-service data to calculate the ATRR supporting the

charges in effect during each Rate Year. AEP requested an effective date of October 1,

2008 for its proposed formula rate and the associated revised charges for transmission

service.

The ATRR calculated by AEPs formula rate encompasses the cost-of-service for

AEP Zone transmission facilities built pursuant to PJMs Regional Transmission

Expansion Plan (RTEP) as well as facilities constructed by AEP before it joined PJM

and became subject to the RTEP. It does so by separately establishing (i) the Network

Integration Transmission Service (NITS) ATRR for the AEP Zone, and (ii) AEPs

costs for regional (RTEP) facilities allocated by PJM to customers outside the AEP Zone.

AEPs filing included a Completed Formula Rate Template containing AEPs proposed

ATRR for a shortened initial period ending on June 30, 20093. That initial set of rates

3 The initial period as proposed by AEP was to have been October 1, 2008 through June 30, 2009. The initial period was shortened further due to a five-month suspension of the effective date. As a result, the

3

would be superseded by annually updated rates that would be effective from July 1 each

year through June 30 of the following year (the Rate Year).. The formula rate relies on

prior year (historic) cost data as well as certain forecasted values in order to calculate a

projected ATRR. That ATRR forms the basis for the rates for service in effect during

the associated Rate Year. When the next annual update is performed, a new projected

ATRR and associated rates will be calculated. In addition, the ATRR billed during the

prior calendar year period will be trued-up based on actual costs in that year. Amounts

charged to customers in excess of the charges that would result from the trued up

ATRR will be refunded to customers (with interest generally consistent with Section

35.19a of the Commission regulations) over the following Rate Year; likewise, any

shortfalls between the charges assessed and the charges that would result from the trued

up ATRR will be recovered from customers (also with like interest) over the following

Rate Year.

Motions to intervene in this proceedings were filed by the following entities: Blue

Ridge Power Agency; Craig-Botetourt Electric Cooperative; The Musser Companies

(Black Diamond Power Co., Elk Power Co., and Union Power Co.); Indiana Municipal

Power Agency; City of Dowagiac, Michigan; Old Dominion Electric Cooperative;

American Municipal Power, Inc.4; The AEP Intervenor Group5; Wabash Valley Power

Association, Inc., Buckeye Power, Inc., and Indiana Michigan Municipal Distributors

Association (the foregoing intervenors being referred to collectively as the Joint

initial rates were in effect from March 1, 2009 through June 30, 2009. The first annual update was implemented through rates made effective on July 1, 2009 (subject to refund) pursuant to the as-filed formula rate. 4 American Municipal Power, Inc. previously was known as American Municipal Power-Ohio, Inc. The change in names became effective on July 1, 2009. 5 The AEP Intervenor Group consists of large industrial customers that take service from one or more AEP East Operating Companies.

4

Intervenors); the Maryland Office of People's Counsel (MOPC); Office of the

Attorney General of the Commonwealth of Virginia, Division of Consumer Counsel

(Virginia Consumer Counsel); North Carolina Electric Membership Corporation;

Kentucky Public Service Commission; Public Service Commission of Maryland; PJM

Interconnection LLC; Dominion Resources Services, Inc.; PJM Commercial and

Industrial End Users; PHI Companies; PPL Electric Utilities Corporation; Steel

Dynamics, Inc.; FirstEnergy Companies; Ameren Services Company; PSEG Companies;

Hoosier Energy Rural Electric Cooperative, Inc.; Exelon Corporation; and Consumers

Energy Company.

Joint Intervenors, MOPC and the Virginia Consumer Counsel protested AEPs

filing, and AEP answered their protests. On September 30, 2008, the Commission issued

an order accepting AEPs proposed formula rates for filing, subject to certain

modifications to be made by AEP through a compliance filing and subject to hearing.

The Commission suspended the proposed formula rates for five months, making them

effective (subject to refund), as modified, on March 1, 2009. The Commission set the

proposed rates for hearing and established settlement judge procedures. Order Accepting

and Suspending Revised Tariff Sheets and Establishing Hearing and Settlement Judge

Procedures, 124 FERC 61,306 (2008). On October 30, 2008, AEP submitted a

compliance filing in which, among other things, AEP proposed amendments to sections

3(d) and 3(e) of the customer protocols to remove language that could be interpreted as

limiting rights of parties under section 206 of the Federal Power Act.

On February 5, 2009, in response to a request by Commission staff, AEP filed an

amendment to its compliance filing in which additional changes to section 3(d) of the

5

customer protocols were proposed to further clarify that the customer protocols do not

limit a customers or the Commissions rights with respect to challenges to the inputs into

the formula rate. On March 13, 2009, the Commission issued an order accepting AEPs

compliance filing. See Letter Order issued on March 13, 2009 in Docket Nos. ER08-

1329-002 and ER08-1329-003.

The Honorable Karen Johnson was appointed Settlement Judge. Judge Johnson

convened the first settlement conference on October 21, 2008, and settlement

negotiations (including informal information gathering and numerous conferences,

meetings and telephone conversations) continued since then. The Commissions Trial

Staff participated actively in the discussions. Judge Johnson submitted periodic reports

to the Commission on the progress of the settlement discussions. Ultimately, the

settlement discussions produced this Settlement Agreement.

ARTICLE II SCOPE OF SETTLEMENT AGREEMENT

The Settling Parties hereby settle and resolve all issues between them arising from

AEPs submittals in Docket No. ER08-1329-000, on the terms set forth in the following

Article III and Attachments A, B, C, D, and E.. Attachments A, B, C, D and E are

incorporated by reference in and made a part of this Settlement Agreement, and all

references herein to the Settlement Agreement shall be deemed to encompass the listed

Attachments.

ARTICLE III TERMS OF THE SETTLEMENT AGREEMENT

6

3.1 The Cost of Service and Formula Rate Settlement Principles set forth in

Attachment A6 describe the agreement of the Settling Parties regarding changes to the

formula rate to be incorporated in PJM OATT Attachment H-14, Annual Transmission

Revenue Requirement for Network Integration Transmission Service; Attachment H-

14A, Formula Rate Implementation Protocols, Attachment H-14B, Formula Rate

Template, Schedule 1A, Transmission Owner Scheduling, System Control and Dispatch

Service, Schedule 7, Long-Term and Short-term Firm Point-to-Point Transmission

Service, and Schedule 8, Non-Firm Point-to-Point Transmission Service .

3.2 Revised tariff provisions for Attachment H-14A (Formula Rate

Implementation Protocols), Attachment H-14B (Formula Rate Template), Schedule 1A

(Transmission Owner Scheduling, System Control and Dispatch Service), Schedule 7

(Long-Term and Short-term Firm Point-to-Point Transmission Service), and Schedule 8

(Non-Firm Point-to-Point Transmission Service) are as set forth in Attachments B-1

(Blacklined) and B-2 (Clean) to this Settlement Agreement. The provisions submitted

herewith shall be substituted for the tariff pages accepted for filing, subject to refund, in

the Commissions September 30, 2008 and March 13, 2009 orders in this Docket. The

Settling Parties request that the Commission accept the tariff pages set forth in

Attachment B for filing without suspension, investigation, change or condition, and

further that, in connection with such acceptance, PJM be directed to file conforming

changes in the form of revised sheets for the PJM OATT, which tariff changes shall

remain in effect until changed as allowed in this Settlement Agreement. Attachments B-1

and B-2 to this Settlement Agreement also contain copies of the formula rate template

6 The Cost of Service and Formula Rate Settlement are included in PJM OATT Attachment H-14A as Appendix A.

7

and indicates changes made to the formula template as a result of this Settlement

Agreement.

3.3 Interest paid for refunds or surcharges made pursuant to the

formula rate will be calculated as set forth in Attachment C - Interest Calculation

Examples Pursuant to 18 C.F.R. 35.19a.

3.4 The ATRR for the period beginning July 1, 2009 and ending June

30, 2010, shall be as calculated in accordance with the revised Formula Rate Template

attached hereto as Attachment D Populated Formula Rate Template for Rates Effective

July 1, 2009, and shall form the basis for the determination of charges to customers

pursuant to the procedures set forth below.

3.5 Attachment E Allowable PBOP Expense Formula sets forth the

agreed upon specified amount of PBOP expenses ($48.1 million) that will be allocable to

the TCOS based on a labor expense allocator. Attachment F also provides a process for

changing that amount in the event that AEP either over-recovers or under-recovers such

expenses on a cumulative basis from and after the effective date of the Settlement

methodology.

3.6 A, Summary of State-Approved Transmission Depreciation Rates

supporting the composite depreciation rates (which are derived from state approved and

FERC-approved depreciation rates) found in AEPs FERC Form 1 is included in

Attachments B-1 and B-2. AEP will make a Section 205 filing at FERC to seek to

change its composite depreciation rate methodology or to reflect in the formula rate

calculation any change in state approved or FERC approved depreciation rates.

8

3.7 As soon as practicable after the filing of this Settlement

Agreement, the Settling Parties shall file a joint motion seeking the Commissions

permission for AEP to place the settlement rates in effect pending approval of the

Settlement Agreement. The Settling Parties shall state in such joint motion that AEP

should be allowed to recoup, with interest, any amounts foregone by AEP pursuant to

such motion if the Settlement Agreement fails to become effective. Failure or refusal of

the Commission to grant such motion shall not affect any Settling Partys rights or

obligations under the Settlement Agreement.

ARTICLE IV IMPLEMENTATION

4.1 This Settlement Agreement shall be binding as among the Settling Parties

upon the execution hereof. The revised tariff sheets and other provisions set forth in the

Attachments hereto shall become effective on the date the Commission specifies as the

effective date for the agreed-upon rates and charges in its order approving or accepting

the Settlement Agreement. The Settling Parties shall request that the Commission permit

the agreed-upon rates and charges become effective as of March 1, 2009.

4.2 For the purpose of this Settlement Agreement, a Commission order shall be

deemed to be final as of the date all rehearing requests have been denied or, if

rehearing is not applied for, the date on which the right to seek rehearing expires.

4.3 This Settlement Agreement shall be null and void and shall not become

effective unless: (i) the Commission approves it without condition or modification as a

complete settlement of the issues described herein, or (ii) the Settling Parties are willing

to accept all such conditions and modifications as the Commission may require. Any

Settling Party that does not notify the other Settling Parties, within 15 days of a

9

Commission order imposing any condition or modification to the Settlement Agreement,

that it may or will seek rehearing or reconsideration of the order shall be deemed to have

waived all objections thereto.

ARTICLE V NON-SEVERABILITY

This Settlement Agreement and its Attachments establish rights and obligations

that are interrelated and interdependent. No Settling Party shall be deemed to have

agreed to any term of the Settlement Agreement in isolation from any other term. For

these reasons, the provisions of this Settlement Agreement are not severable.

ARTICLE VI RESERVATIONS

6.1 The provisions of this Settlement Agreement are intended to govern only

the specific matters addressed herein. No Settling Party waives any claim or right that it

may have with respect to matters not addressed in this Settlement Agreement.

6.2 No Settling Party shall be bound or prejudiced by this Settlement

Agreement unless it is approved and made effective pursuant to its terms.

6.3 Nothing in this Settlement Agreement shall constitute an admission by any

Settling Party of the correctness or applicability of any claim, defense, rule, or

interpretation of law, allegation of fact, principle, or method of ratemaking or cost-of-

service determination. The Settlement Agreement is made upon the explicit

understanding that it constitutes a negotiated agreement with respect to the rates, terms,

and conditions at issue in these proceedings. The Settling Parties shall not be deemed to

have conceded the applicability of any principle, or any method of ratemaking or cost-of-

service determination, rate design or rate schedule, or terms and conditions of service; or

10

the application of any rule or interpretation of law that may underlie, or be thought to

underlie, this Settlement Agreement. The Cost of Service and Formula Rate Settlement

Principles contained in Attachment A are principles that the Settling Parties shall be

deemed to have accepted solely for purposes of resolving the issues in this docket, and

their inclusion as part of this Settlement Agreement shall not (i) constitute an admission

by any Settling Party of the correctness of any principle therein, or (ii) establish any

precedent binding on a Settling Party in any other proceeding. In any further negotiation

or proceedings whatsoever (other than a proceeding involving the honoring, enforcement

or construction hereof, as applicable as set forth herein), the Settling Parties shall not be

bound or prejudiced by this Settlement Agreement.

6.4 The Commissions approval of this Settlement Agreement shall not

constitute approval of, or precedent regarding, any principle or issue in this proceeding.

Nothing herein shall be deemed to constitute or establish a settled practice as the Court

interpreted that term in Public Service Commn of New York v. FERC, 642 F.2d 1335

(D.C. Cir. 1980).

6.5 This Settlement Agreement is expressly contingent upon the following

further conditions: (i) all Settling Parties shall provide reasonable cooperation in seeking

the Commissions acceptance and approval hereof; (ii) no Settling Party shall seek or

request additional terms or conditions of settlement beyond those contained herein; and

(iii) the Commission approves or accepts this Settlement Agreement without

modification. If the Commission requires any modification(s) of this Settlement

Agreement and if such modification(s) is (are) not fulfilled, then: (i) this Settlement

Agreement shall not be binding on any Settling Party; (ii) the Settling Parties shall not be

11

obligated to negotiate further, other than to discuss in good faith whether the

modification(s) required by the Commission is (are) acceptable to them; (iii) all Settling

Parties shall be deemed to have reserved all of their respective rights and remedies with

respect to the issues in this proceeding; and (iv) this Settlement Agreement shall not be

part of the record in any subsequent proceedings, and all discussions and negotiations

related hereto shall be privileged.

6.6 The titles and headings of the various articles of this Settlement Agreement:

(i) are for reference and convenience purposes only; (ii) are not to be construed or taken

into account in interpreting the Settlement Agreement; and (iii) do not qualify, modify, or

explain the effects of the Settlement Agreement.

6.7 This Settlement Agreement may be amended only by a written instrument

duly executed by all Settling Parties. The standard of review for any modification to this

Settlement Agreement sought by a Settling Party that is not agreed to by all other Settling

Parties shall be the just and reasonable standard. A Settling Party or Settling Parties

seeking to modify the Formula Rate in any respect shall bear the applicable burden under

the FPA. Notwithstanding the foregoing, the public interest standard described in the

Mobile-Sierra line of decisions shall apply to any modification of the following

provisions that may be sought by a Settling Party and that is not agreed to by all Settling

Parties: (i) the methodology set forth in Attachment A, section I.C.6, for determining

whether AEP is required to file a change to the PBOP expense allowance; (ii) the

duration and amount of the Equity Caps established pursuant to Attachment A, paragraph

I.D.2.c; (iii) the duration and amount of the limitation, set forth in Attachment A,

paragraph I.D.1.a, on the amount of any incentive return on common equity AEP may

12

request; and (iv) the limitation on the amount of hedging gains and losses AEP may

reflect in the cost of long-term debt.

6.8 The standard of review for any modifications to this Settlement Agreement

requested by an intervenor or other interested entity that is not a Settling Party or that is

sought in a proceeding initiated by the Commission acting sua sponte will be the most

stringent standard permissible under applicable law. For purposes of the application of

sections 6.7 and 6.8, all parties who have formally represented in writing, by their

respective authorized representative, that they did not object to the Agreement shall be

treated as Settling Parties.

6.9 This Settlement Agreement is submitted pursuant to Rule 602 of the

Commissions Rules of Practice and Procedure, 18 C.F.R. 385.602 (2008). Unless and

until the Settlement Agreement becomes effective pursuant to its terms, the Settlement

Agreement shall be privileged and of no effect and shall not be admissible in evidence or

in any way described or discussed in any proceeding before any court or regulatory body

(except in comments on the Settlement Agreement in this proceeding).

13

Indiana Municipal Power Agency, City of Dowagiac, Michigan

Cynthia S. Bogorad

Stephen C. Pearson

Spiegel & McDiannid LLP

1333 New Hampshire Avenue, NW

Washington, DC 20036

Attorneys for Indiana Municipal Power Agency and Dowagiac, Michigan

American Municipal Power-Ohio, Inc,

Gary 1. Newell Thompson Coburn LLP Suite 600 1909 K St., NW Washington, DC 20006-1167 (202) 585-6900 E-Mail: gnewell@thompsoncoburn.com

Counsel for American Municipal Power

By:=F-+ _______--."---""''_+_ Robert A. Weishaar, Jr. Dennis P. Jamouneau McNees Wallace & Nunck LLC 777 North Capitol Street, NE Suite 401 Washington, DC 20002-4292

Counsel to AEP Intervenor Group

15

mailto:gnewell@thompsoncoburn.com

16

Wabash Valley Power Association, Inc.

By: ____________________________Jeremy L. FettyPARR RICHEY OBREMSKEY FRANDSEN & PATTERSON LLPPhone: (317)269-2509; (765) 482-0110Facsimile: (765) 483-3444www.parrlaw.com

Attorney for Wabash Valley Power Association, Inc,

Buckeye Power, Inc.

By:____________________________Peter C. Lesch, Esq.Thompson Hine LLP1920 N Street, N.W.Suite 800Washington, D.C. 20036-1600(202) 263-4175

Attorney for Buckeye Power, Inc

Indiana and Michigan Municipal Distributors Association on behalf of:,Town of Avilla, City of Bluffton, City of Dowagiac, City of Garrett, City of Mishawaka,Town of New Carlisle, City of Niles, Village of Paw Paw, City of South Haven,City of Sturgis, Town of Warren

By:_____________________________Tatjana M. ShonkwilerDuncan, Weinberg, Genzer & Pembroke, P.C.1615 M Street, N.W., Suite 800Washington, D.C. 20036(202) 467-6370(202) 467-6379 (Fax)tms@dwgp.com

North Carolina Electric Membership Corporation

Sean T. BeenyDenise C. GouletMiller, Balis & O'Neil, P.C.Twelfth Floor1015 Fifteenth Street, N.W.Washington, D.C.20005(202) 296-2960

Richard FeathersNorth Carolina Electric Membership Corporation3400 Sumner BoulevardRaleigh, North Carolina 27616(er9) 872-0800

Attomeys forNorth Carolina Electric Membership Corporation

Office of the Attorney General of Virginia Division of Consumer Counsel

Kenneth T. Cuccinelli, IIAttorney GeneralWesley G. Russell, Jr.Deputy Attorney GeneralC. Meade Browder, Jr.Senior Assistant Attorney General

COMMONWEALTH OF VIRGINIAOFFICE OF THE ATTORNEY GENERAL900 East Main StreetRichmond, Virginia 23219Telephone: (804) 786-2071Facsimile: (804) 37 l -2086

By:

18

Attachment A to Appendix B Cost of Service and Formula Rate Settlement Principles

ATTACHMENT A to APPENDIX B

Cost of Service and Formula Rate Settlement Principles

American Electric Power Service Corporation Docket No. ER08-1329

Transmission Formula Rate Settlement

For Appalachian Power Company, Columbus Southern Power Company, Indiana

Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, and Wheeling Power Company

(collectively AEP or the AEP East Companies)

The following Cost of Service and Formula Rate Settlement Principles are a part of the Settlement Agreement being filed April 7, 2010 in Docket No. ER08-1329 (the Settlement):

I. Transmission Formula Rate Design.

A. Retail versus Wholesale Ratemaking Practices.

1. Differing practices among retail and wholesale regulatory jurisdictions - Costs that are not recoverable pursuant to FERC accounting and/or ratemaking practices may not be recovered by the AEP East companies through its FERC transmission formula rate.

2. Adjustments to the AEP cost of service formula rate templates - AEP shall take steps to have PJM include in the rate template used to calculate charges to transmission customers all of the adjustments, modifications, and corrections identified in the new formula rate templates included with this Statement of Settlement Principles.

3. Costs of transmission studies

a. All costs of transmission studies (e.g., studies of requested new or modified delivery or interconnection points, System Impact Studies and Facilities Studies) associated with service to affiliated (e.g., AEP East companies) and non-

1

affiliated customers shall be allocated and charged to customers on a comparable and consistent basis.

b. Currently, the costs of transmission studies are directly assigned or charged to the requesting entity (including the AEP East companies) seeking the service. The costs of such studies shall be accounted for in one of the following ways:

i The study costs are not included in the formula rate, expressly or otherwise; or

ii If the costs are included in the formula rate but also are directly assigned to the entity requesting the study, then the formula rate also will include a revenue credit equal to the amount of study costs that are directly assignable to the requesting entity. Such revenue credit shall be reflected in the formula rate regardless of the specific accounting applied to the costs and revenues.

iii Study costs that are not directly assigned to the requesting entity may be treated as a system-wide cost in applying the formula rate, but only if that treatment is applied to all such study costs incurred for any requesting entity.

c. Transmission service base rate charges under the formula shall be calculated in a manner that allocates the costs of transmission studies to, and recovers those costs from, customers (including the AEP East companies themselves) on a comparable basis, without regard to whether the costs of those studies are directly assigned or rolled-in, and without regard to whether any particular studies are performed for affiliated or non-affiliated customers.

d. AEP will correct its books of account to remove from transmission investment the estimated costs of distribution-related studies that were inadvertently recorded as transmission overheads. The effect of this correction will be to reduce the transmission Rate Base used in formula rate calculations. This correction will be reflected in the 2009 end-of-year Transmission Plant In Service (TPIS) balance. In the 2010 Annual Update trueing up 2009 costs,

2

the beginning-of-year 2009 TPIS balances shall be reduced by the same amount.

B. Rate Base

1. The transmission Rate Base used in the annual update shall be based upon the end-of-year net transmission plant balance from the prior calendar year FERC Form 1 (FF1). The true-up of the formula rate, however, shall utilize a Transmission Rate Base that incorporates the arithmetic average of the most recent actual values for beginning-of-year and end-of-year net transmission plant (that is, the average of beginning and end of calendar year balances for plant in service and accumulated depreciation).

a. The revenue requirements billed each July and running through June of the next year (except the first Rate Year which starts in March of 2009) will be based on a test-year-end rate base style annual transmission revenue requirement (ATRR) calculation. This means there will be two sets of revenue requirements billed during 2009. The first set applies to the period from March through June, and is based on 2007 calendar year expenses and calendar year end rate base derived from the FF1 plus the projected 2008 calendar year plant-in-service additions. The second set was posted in May 2009, and applies from July 1, 2009 through June 30, 2010. Those revenue requirements will be based on the expenses and year-end TPIS balances obtained from the 2008 FF1 plus projected 2009 calendar year TPIS additions.

b. In 2010, the estimated ATRR that was effective during 2009 will be reconciled (trued-up) with an ATRR that is calculated based on actual 2009 calendar year expenses and the arithmetic average of the beginning-of-year and end-of-year balances for TPIS and accumulated depreciation. The actual 2009 ATRR to be used for such reconciliation will be posted or otherwise provided to customers in May 2010 at the same time that the estimated ATRR to be used for billing purposes during the second half of 2010 is posted or otherwise provided to customers.

c. For the true-up of prior year charges, AEP East Companies will calculate the difference between the estimated ATRR for the prior calendar year that was used for billing purposes and the actual ATRR for that prior calendar year, calculated as described in paragraph B.1.b. above. The

3

difference between the two values (plus interest) shall be reflected as an addition to or offset against billed charges for transmission service beginning on July 1st of the current year. The interest rate will be calculated as per section 35.19a of the Commissions regulations.

d. The sequence outlined in paragraphs B.1.a, B.1.b and B.1.c above will be repeated each year.

2. Cash working capital for each AEP East operating company will be calculated as 1/8 of transmission-related O&M expense not including any portion of A&G expense allocated to transmission. (For example, using the historic formula from the template, the cash working capital reference on line 232 in the original filing which referenced (1/8 * ln 275) is now line 236 in the updated template and is changed to be (1/8 * ln 256.)

3. AEP shall change the line item description "Regulatory Assets Approved for Recovery in Ratebase" in Worksheet A for each operating company to "Regulatory Assets and Regulatory Liabilities Approved for Recovery in Ratebase." In addition, a note will be added stating that Regulatory Assets and Liabilities may be included in the formula rate calculations only if approved by the Commission in a proceeding pursuant to Section 205 or Section 206 of the Federal Power Act (FPA).

4. If AEP includes plant held for future use in the formula rate ATRR calculation, then it also shall reflect any gains or losses on sales of such property in the ATRR calculation. Accordingly, AEP will modify the formula rate to include any amounts recorded in FERC Accounts 411.6 and 411.7 in the ATRR, and will prepare and include in its annual update filing a new Worksheet N, which shows the impact (net of income taxes) on the ATRR resulting from gains and losses on sales of plant held for future use.

5. AEP will provide as a part of its informational filing each May/June detail regarding ADIT balances for the historical year that is no less detailed, and selectively more detailed as described in this section, than what is included in Period I Statement AF (Accts. 281, 282, and 283) and Statement AG (Acct. 190) for each AEP operating company. In consideration of that commitment, the intervenors that are Settling Parties will not challenge the ADIT balances reflected in the Companys July 31, 2008 filing. In addition, AEPs information on ADIT will distinguish between utility and non-utility ADIT in order to ensure compliance with Section I.D.2.c.i. below.

4

6. AEP will be permitted to include in Rate Base in the formula rate the transmission portion of AEPs FAS 87 cash investment in Pre-Paid Pension cost recorded in FERC Account 165. If AEP elects to include such costs in Rate Base, it will use a labor expense allocation factor to allocate the total company amount to the TCOS.

7. In consideration of the agreements reached herein, AEP will remove the lines in the Formula Rate templates relating to CWIP. AEP retains the right to make a future filing(s) under section 205 of the Federal Power ACT for current recovery for CWIP.

C. Expenses

1. The formula rate shall allocate property tax expense based on the methodology of Worksheet Sheet H using the as-filed net plant cost allocation methodology.

2. The formula rate shall reflect the applicable state and federal statutory tax rates in effect during the period the calculated estimated unit charges are applicable. If statutory tax rates change during such period, the effective tax rates used in the formula shall be weighted by the number of days the pre-change rate and the post-change rate each is in effect (e.g., if a 40% rate is in effect nine months and a 32% rate is in effect 3 months, the weighted rate for the 12-month period would be 38%, which reflects 40% x 0.75 + 32% x 0.25 = 38%).

3. The formula shall include only expenses that are directly related to or properly allocable to transmission service.

4. Expenses recorded in FERC Accounts 928 (Regulatory Commission Expense), 930.1 (Safety Related Advertising) and 930.2 (Miscellaneous General Expenses) that are not directly related to or properly allocable to transmission service will be removed from the TCOS. If AEP includes any expenses booked to these accounts in future ATRR updates, AEP must provide supporting information demonstrating that the underlying activities are directly related to providing transmission service.

5. AEPs Depreciation rates contained in the FF1 are composite rates based on state commission-approved and FERC-approved depreciation rates. Composite rates are determined by plant account for each operating company that has more than one jurisdiction that approves depreciation rates, based on jurisdictional plant allocation factors. Attachments B-1 and B-2 to the Settlement Agreement contain a summary of AEPs state commission-approved depreciation rates for transmission plant. AEP will make a Section 205 filing at FERC to seek to change its composite depreciation rate methodology or to reflect in the formula rate

5

calculations any change in state commission-approved or FERC- approved depreciation rates.

6. PBOP Expense

i. The formula rate shall include PBOP expense as illustrated in Worksheet O, which is included in Attachment F to the Settlement Agreement, and which will be included in the formula rate. Worksheet O provides that the PBOP allowance will be initially stated in the formula rate as $48.1 million for the AEP East system, with that amount to be shared by the seven (7) AEP companies in each formula rate update in proportion to their actual PBOP costs, including each companys share of PBOP costs billed to the AEP operating companies by AEP Service Company.

ii. As part of the annual update process, AEP will provide to

transmission customers, and include in its informational filing, an independently prepared actuarial report (Annual Actuarial Report) that includes a ten (10) year forecast of PBOP costs when that report becomes available. The Settling Parties anticipate that the Annual Actuarial Report normally will be received by the time the annual update is posted or otherwise provided to customers each year.

iii. During the annual update process conducted in 2013, and every

four years thereafter, Worksheet O will be used to determine whether, and if so by what amount, the PBOP allowance should be adjusted going forward for the next four years. If the Annual Actuarial Report produced for that year projects PBOP costs during the next four years, taken together with the then current cumulative PBOP cost/allowance position, will, absent a change in the PBOP allowance, cause the AEP Companies to over or under collect their cumulative PBOP costs by more than 20% of the projected next four year's total cost, the PBOP allowance shall be adjusted. In order to determine whether the AEP Companies' cumulative allowance of PBOP costs under the formula rate will result in a cumulative over or under-recovery of actual PBOP expenses exceeding 20% over the subsequent four year period, Worksheet O will be used to determine the following PBOB cost/allowance values:

(a) the level of cumulative over or under collections during the

period since the PBOP allowance was last set, including carrying costs based on the weighted average cost of capital ("WACC") each year from the Formula rate True-Up transmission cost-of-service ("TCOS") analyses;

6

(b) the cumulative net present value ("CNPV") of projected PBOP costs during the next four years, as estimated by the then current Actuarial Report, assuming a discount rate equal to the True-Up TCOS WACC for the prior calendar year ("Prior Year WACC"); and

(c) the CNPV of continued collections over the next four years based on the then effective PBOP allowance, assuming a discount rate equal to the Prior Year WACC.

If the absolute value of (a) + (b) - (c) exceeds 20% of (b), then the PBOP allowance used in the formula rate calculation shall be changed to the value that will cause the projected result of (a) + (b) - (c) to equal zero. If the projected over or under collection during the next four years, (a) + (b) - (c), will be less than 20% of (b), then the PBOP Allowance will continue in effect for the next four years at the then effective rate.

iv. If it is determined through the foregoing procedure that the AEP

Companies cumulative PBOP expense allowance will over-recover or under-recover actual PBOP expenses by more than 20% over the subsequent four-year period, AEP shall make a filing under FPA 205 to change the PBOP expense stated in the formula rate. No other changes to the formula rate may be included in that filing. Neither AEP nor any Settling Party may raise in connection with such filing any issue affecting the formula rate other than the level of allowable PBOP expense.

v. The foregoing procedure for required updating of the formula

rates stated PBOP expense amount shall not affect either: (i) AEPs right to make filings under FPA 205 to address aspects of the formula rate other than PBOP expense, or (ii) customers rights to make filings under FPA 206 to address aspects of the formula rate other than the PBOP expense.

D. Capital Structure, Cost of Capital and Return on Equity

1. Return on Equity

a. The Settlement shall establish on a non-precedential basis a base return on common equity (Base ROE) used in the OATT transmission formula rates applicable to the AEP East zone of 10.99%, plus a 50 basis point adder for continued RTO participation (for a total of 11.49% ROE).

b. The Settlement shall not establish a lower or upper end of the zone of reasonableness, but for a period of 36 months

7

from the effective date of the Settlement, AEP will limit any request for an incentive ROE pursuant to Order No. 679 and Order No. 679-A to not more than the total ROE plus 125 basis points (i.e., 12.74% total incentive ROE). Such incentive ROE must be within the then-applicable zone of reasonableness as determined in a Section 205 or 206 proceeding. Settling Parties reserve the right to protest any request by AEP for incentive rates including any request for an incentive ROE.

2. Capital Structure / Cost of Capital:

a. In the annual true-up calculations, AEP shall use the arithmetic average of the beginning-of-year and end-of-year balances of long-term debt and calendar year interest expenses. The balances of any fair value hedges on interest rate derivatives of long term debt shall not be included in the average.

b. In the estimated (projected) ATRR used for billing purposes, AEP shall use the most recent available FF1 actual end-of-year balances of outstanding long term debt (less the balance of any fair value interest rate hedges), preferred equity, and common equity. The estimated cost rate for long term debt for the Projected Rate Year shall reflect the prior calendar year actual cost of long term debt (including periodic expenses such as remarketing and letter of credit fees, and related amortizations, as applicable, of issuance/reacquisition cost and discount or premium amortizations, and the amortization of eligible net hedging costs) for debt outstanding during the full year and the annualized cost of any issuances that occur after January 1 of the prior calendar year for a full twelve months coupon interest expense.

c. Except as provided for below regarding interest rate hedge gains and losses, the cost rates for long-term debt shall include interest expense, and related periodic expenses (such as remarketing and letter of credit fees) as recorded in FERC Account 427 or 430, amortization of issuance costs (including insurance), and discounts as recorded in FERC Account 428, issuance premiums as recorded in FERC Account 429, and losses or gains on reacquired debt as recorded in FERC Accounts 428.1 or 429.1, respectively. The cost rates for preferred stock shall include the dividends.

8

The cost rates for long-term debt shall include amortization of gains and losses resulting from interest rate hedging recorded in FERC Account 427 provided that only the gains and losses on the effective portion of pre-issuance cash flow hedges on interest rate derivatives of long term debt are eligible to be included in interest expense in the annual true-up ATRR calculation. No gains/losses and related ADIT on fair value interest rate hedges, the ineffective portion of pre-issuance interest rate cash flow hedges, post-issuance cash flow hedges, and cash flow hedges of variable rate debt issuances may be included in the true-up ATRR. The realized hedge gain or loss on the effective portion of pre-issuance cash flow hedges shall be amortized over the life of the associated debt security or refunding debt security, as applicable. The amount of net hedging gain or loss included in the annual true -up calculations shall not cause the after-tax weighted average cost of capital to increase or decrease by more than five (5) basis points. To determine the includable amount of hedging net losses or net gains to establish the long term debt cost rate, AEP will multiply the total company average true-up dollar capitalization (long-term debt net of any fair value hedge balances, preferred stock and common equity) by 0.0005, and compare the result to the full eligible net hedging loss or gain amortization amounts. The unamortized balances of eligible hedge gains/losses and their related ADIT amounts (FERC Accounts 190,282, and 283) shall not flow through the formula rate. AEPs corporate accounting records shall clearly segregate eligible hedge gains/losses and related ADIT from ineligible hedge gains/losses and related ADIT. AEP shall provide on request during discovery periods provided for in this settlement, supporting hedge information including but not limited to copies of all eligible and ineligible hedge transaction internal authorization documents and company policies and procedures.

d. In applying the formula rate to determine charges for service rendered between March 1, 2009 and December 31, 2011, the amounts of common equity used in determining the weighted average cost of capital for the AEP East operating companies shall not exceed the following percentages of the total true-up capitalization (Equity Caps), regardless of the actual amounts of common equity capital outstanding:

9

Ohio Power Company 55%

Columbus Southern Power 51%

Appalachian Power Company 50%

Indiana Michigan Power Company

50%

Kentucky Power Company 50%

If the percentage of common equity in an operating companys capitalization exceeds the applicable Equity Cap, the amount of common equity exceeding the Equity Cap shall be assigned the same cost rate as long-term debt in the formula rate cost of capital calculations.

E. Revenue Credits-- The following principles shall be stated in the formula rate:

1. If the AEP East companies have any directly assigned transmission facilities, the revenue credits in the AEP East formula rate shall include all revenues associated with those directly assigned transmission facilities, irrespective of whether the loads of the customer are included in the formula rate divisor; provided, however, such addition to revenue credits shall not be reflected if the costs of such directly assigned transmission facilities are not included in the transmission plant balances on which the formula rate ATRR is based.

2. All transmission services revenues not credited to customers in monthly PJM billings shall be included in the formula rate calculation as reductions to the ATRR. Such amounts shall include transmission revenues received from PJM or other PJM Transmission Owners where the associated loads are not in the AEP Zone divisor, unless the revenues are attributable to AEPs base transmission rate charges for Network Integration Transmission Service (Network Service) or long-term firm Point-to-Point Transmission Service.

F. Allocators.

1. The allocations of Administrative & General (A&G) expenses identified by three-digit FERC account in the Formula Rate Template and Worksheet F, Supporting Allocation of Specific O&M or A&G Expenses, may not be changed except through a filing under FPA 205 or 206. If AEP wishes to reflect new O&M or A&G expenses or accounts in future updates, it must include in such 205 filing: (i) a specification of the basis on which it proposes to allocate a portion of such costs as is properly assignable to wholesale transmission service, and (ii) documentation sufficient to demonstrate the reasonableness of its proposed allocation factor consistent with applicable Commission precedent.

10

2. AEP shall change the treatment of FERC Accounts 565 in the formula to clarify that no Account 565 costs other than inter-company charges that net out (such as lease arrangements and transmission equalization payments/receipts between operating companies) will be included in the TCOS, unless first approved by FERC following a separate FPA 205 filing by AEP.

II. Application of Interest Rate Calculation in True-Up

AEP shall include an interest rate worksheet as Attachment C to the Settlement Agreement specifying its procedure for applying interest to true-up over or under recoveries.

11

Attachment B-1 to Appendix B Revised Tariff Language (Blacklined)

PJM Interconnection, L.L.C. Second Revised Sheet No. 314C FERC Electric Tariff Superseding Substitute First Revised Sheet No. 314C Sixth Revised Volume No. 1 Superseding Original Sheet No. 314C

Issued By: Craig Glazer Effective: March 1, 2009 Vice President, Government Policy Issued On: October 30, 2008 April 7, 2010 Filed to comply with order of the Federal Energy Regulatory Commission pursuant to settlement in, Docket No. ER08-1329, issued September 30, 2008.

ATTACHMENT H-14A FORMULA RATE IMPLEMENTATION PROTOCOLS

Definitions Annual Transmission Revenue Requirements means the result produced by populating the Formula Rate Template with data as provided by the Formula Rate. Annual Update means the posting and informational filing submitted by AEP on or before May 25 of each year that sets forth the AEP Zonal Transmission Cost of Service (TCOS) for the subsequent Rate Year and which contains the True-Up calculation for the prior calendar year. Discovery Period means the period after each annual Publication Date to serve information requests on AEP as provided in Section 2b below. First Rate Year means the period of March 1, 2009 through June 30, 2009. Formal Challenge means a challenge to an Annual Update submitted to the Federal Energy Regulatory Commission (FERC) as provided in Section 3.a below. Formula Rate means these Formula Rate Implementation Protocols (to be included as Attachment H-14A of the PJM Interconnection, L.L.C. (PJM), FERC Electric Tariff (PJM Tariff)) and the Formula Rate Template. Formula Rate Template means the collection of formulae, and worksheets, unpopulated with any data, to be included as Attachment H-14B of the PJM Tariff. Interested Party means any person or entity having standing under Section 206 of the Federal Power Act (FPA) with respect to the Annual Update. Material Changes means (i) material changes in AEPs accounting policies and practices, (ii) changes in FERCs Uniform System of Accounts (USofA), (iii) changes in FERC Form No. 1 reporting requirements as applicable, or (iv) changes in the FERCs accounting policies and practices, which change causes a result under the Formula Rate different from the result under the Formula Rate as calculated without such change. Preliminary Challenge means a written challenge to the Annual Update submitted to AEP as provided in Section 2.a below. Protocols means these Formula Rate Implementation Protocols (to be included as Attachment H-14A of the PJM Tariff)

ER08-1329Attachment B-1

Page 1 of 65

PJM Interconnection, L.L.C. Second Revised Sheet No. 314C FERC Electric Tariff Superseding Substitute First Revised Sheet No. 314C Sixth Revised Volume No. 1 Superseding Original Sheet No. 314C

Issued By: Craig Glazer Effective: March 1, 2009 Vice President, Government Policy Issued On: October 30, 2008 April 7, 2010 Filed to comply with order of the Federal Energy Regulatory Commission pursuant to settlement in, Docket No. ER08-1329, issued September 30, 2008.

Section 1 Annual Updates

a. The Annual Transmission Revenue Requirements applicable under Attachment H-14B and the Network Integration Transmission Service and Point-to-Point rates derived therefrom shall be applicable to services on and after July 1 of a given calendar year through June 30 of the subsequent calendar year (the Rate Year).

b. On or before May 25 of each year, the AEP East Companies (AEP) shall

recalculate its Annual Transmission Revenue Requirements, producing the Annual Update for the upcoming Rate Year, and post such Annual Update on PJMs Internet website via a link to the Transmission Services page or a similar successor page. In addition, AEP shall submit such Annual Update as an informational filing with the FERC.

c. If the date for making the Annual Update posting/filing should fall on a

weekend or a holiday recognized by the FERC, then the posting/filing shall be due on the next business day.

d. The date on which the last of the events listed in Section 1.b or 1.c occurs

shall be that years Publication Date. e. Upon written request for a particular years Annual Update by any entity

having standing under section 206 of the Federal Power Act with respect to such Annual Update (collectively Interested Parties), AEP will promptly make available to such entity and/or a consultant designated by it, a workable Excel file containing that years Annual Update data.

f. The Annual Update for the Rate Year:

(i) shall, to the extent specified in the Formula Rate, be based upon the FERC Form No. 1 reports of the AEP East Companies for the most recent calendar year, and to the extent specified in the Formula Rate, be based upon the books and records of AEP consistent with FERC accounting policies;

ER08-1329Attachment B-1

Page 2 of 65

PJM Interconnection, L.L.C. First Revised Sheet No. 314C.01 FERC Electric Tariff Superseding Substitute Original Sheet No. 314C.01 Sixth Revised Volume No. 1

Issued By: Craig Glazer Effective: March 1, 2009 Vice President, Government Policy Issued On: October 30, 2008 April 7, 2010 Filed to comply with order of the Federal Energy Regulatory Commission pursuant to settlement in, Docket No. ER08-1329, issued September 30, 2008.

Publication Date means the date on which the Annual Update is posted under the provisions of Section 1.b below. Rate Year means the twelve consecutive month period that begins on July 1 and continues through June 30 of the subsequent calendar year except for the First Rate Year. Review Period means the period during which Interested Parties may review the calculations in the Annual Update as provided in Section 2.a below. Section 1 Annual Updates 1

a. Beginning March 1, 2009, the Annual Transmission Revenue Requirements applicable under Attachment H-14B and the Network Integration Transmission Service and Point-to-Point rates derived therefrom shall be applicable to services for the subsequent Rate Year.

b. On or before May 25 of each year, the AEP East Companies (AEP) shall

recalculate its Annual Transmission Revenue Requirements, producing the Annual Update for the upcoming Rate Year, and post such Annual Update on PJMs Internet website via a link to the Transmission Services page or a similar successor page (Publication Date). In addition, AEP shall submit such Annual Update as an informational filing with the FERC. AEP shall also send an e-mail or other similar electronic communication to all Interested Parties that have previously requested such notification through procedures to be established by AEP that informs the recipient that the Annual Update is available and that provides the Uniform Resource Locator or other similar identifying locator information from which the Annual Update can be obtained.

c. If the date for making the Annual Update posting/filing should fall on a

weekend or a holiday recognized by the FERC, then the posting/filing shall be due on the next business day.

d. The date on which the last of the events listed in Section 1.b or 1.c occurs

shall be that years Publication Date.

1 It is the intent of the Formula Rate, including the supporting explanations and allocations

described therein, that each input to the Formula Rate Template will be either taken directly from the FERC Form No. 1 or reconcilable to the FERC Form No. 1 by the application of clearly identified and supported information. Where the reconciliation is provided through a worksheet included in the filed Formula Rate Template, the inputs to the worksheet must meet this transparency standard, and doing so will satisfy this transparency requirement for the amounts that are output from the worksheet and input to the main body of the Formula Rate Template. Appendix A to these Protocols summarizes the Cost of Service and Formula Rate Settlement Principles further describing the intent of the Parties and the Formula Rate.

ER08-1329Attachment B-1

Page 3 of 65

PJM Interconnection, L.L.C. First Revised Sheet No. 314C.01 FERC Electric Tariff Superseding Substitute Original Sheet No. 314C.01 Sixth Revised Volume No. 1

Issued By: Craig Glazer Effective: March 1, 2009 Vice President, Government Policy Issued On: October 30, 2008 April 7, 2010 Filed to comply with order of the Federal Energy Regulatory Com