IN THE UNITED STATES OF AMERICA BEFORE THE FEDERAL by law23631

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									                                                         Exhibit AEP-2


                 IN THE UNITED STATES OF AMERICA
                            BEFORE THE
             FEDERAL ENERGY REGULATORY COMMISSION

The New PJM Companies, et al.   :   Docket Nos. ER03-262-000, et al.


                  PREPARED DIRECT TESTIMONY OF
                         SUSAN TOMASKY
                                AND
                          J. CRAIG BAKER
                           ON BEHALF OF
               THE AMERICAN ELECTRIC POWER SYSTEM




                                                    September 23, 2003
                                                                               Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1                                    I. INTRODUCTION

 2   Q.     Please state your names, titles and business addresses.

 3   A.     Susan Tomasky, Executive Vice President, Policy, Finance and Strategic Planning

 4          for American Electric Power Service Corporation (“AEPSC”) and J. Craig Baker,

 5          Senior Vice President- Regulation and Public Policy for American Electric Power

 6          Service Corporation (“AEPSC”). Our business address is 1 Riverside Plaza,

 7          Columbus, Ohio 43215.

 8   Q.     Would you please describe your educational and employment background?

 9   A.     Our backgrounds are set forth on attached Exhibit AEP-3.

10                              II. PURPOSE OF TESTIMONY

11   Q.     What is the purpose of your testimony?

12   A.     In compliance with the Commission’s September 12, 2003 Order Announcing

13          Inquiry Into Midwest ISO-PJM RTO Issues, our testimony addresses the

14          impediments to AEP’s planned participation in PJM Interconnection, L.L.C. -- a

15          Commission-approved RTO; AEP’s vigorous and continuing efforts, since at

16          least 1999, to participate in an RTO; the fluid regulatory landscape that has

17          affected those efforts; the current situation, including impediments to AEP’s

18          prompt fulfillment of its plan to join PJM and details of a proposal for a

19          collaborative solution to the current impasse. We will also address a proposal for




                                                 2
                                                                               Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

1           another purported solution to the impasse – splitting the AEP East transmission

2           zone – and explain how such a solution is unreasonable and counterproductive.

3                                   III. THE AEP SYSTEM

4           A.     Description of the AEP System

5    Q.     Please describe the AEP System.

6    A.     AEP is a multistate electric utility holding company system providing service to

7           more than 5 million customers in parts of eleven states – Indiana, Michigan, Ohio,

8           Kentucky, Tennessee, Virginia, West Virginia, Texas, Oklahoma, Arkansas and

9           Louisiana.

10                 AEP owns and operates an extensive interstate transmission system which

11          it uses to serve its customers and to provide open-access transmission pursuant to

12          the Commission’s Order No. 888. The AEP transmission system is operated as a

13          single system, and, pursuant to clear FERC precedent, AEP offers open access

14          transmission service across its entire system, without regard to operating company

15          or state boundaries.

16                 Attached as an Exhibit AEP-4 is a map showing AEP’s east zone

17          transmission facilities and surrounding facilities.     The Exhibit graphically

18          illustrates the scope, strength and geographical location of the AEP transmission

19          system, which is the focal point of these proceedings. This exhibit shows AEP’s

20          765kV transmission network in dark green color. As can be seen, this network



                                                3
                                                                                   Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                             PREPARED DIRECT TESTIMONY OF
                                    SUSAN TOMASKY
                                           AND
                                     J. CRAIG BAKER

 1          spans from the Indiana/Illinois border to the Ohio/Pennsylvania border and from

 2          Michigan to the Virginia/Carolina border.

 3   Q.     In what region of the country is AEP located?

 4   A.     Not including our western properties, which are not directly at issue in this

 5          Inquiry, the AEP system is located in the Midwest, South and East.

 6   Q.     Why is the previous answer important?

 7   A.     It is important to dispel the myth, that has been repeated so often that it is taken as

 8          fact, that AEP is located only in the “Midwest”. It has been stated in many

 9          Commission orders and elsewhere many times that “There should only be one

10          RTO in the Midwest”. The fact is that approximately 36 percent of AEP’s load

11          in its eastern zone is located in the states of Kentucky, Virginia, West Virginia

12          and Tennessee. Many a Kentucky colonel, Virginia squire, Tennessee volunteer

13          and West Virginia mountaineer would be surprised to learn they are

14          Midwesterners.     AEP generation supplies load in the Midwest (ECAR and

15          MAIN), but it also supplies load in the east, Mid Atlantic, the Carolinas, TVA and

16          beyond. AEP has no single natural market unless it is with all 18 control areas

17          with which we are interconnected.

18                 Much of the litigation that has attended AEP’s RTO efforts is based on the

19          idea that AEP, being a “Midwestern” utility, chose the wrong RTO when it chose

20          PJM. AEP’s choices have been portrayed as presenting barriers to transactions in



                                                  4
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          the “Midwest” or “the region”. Indeed, Virginia Power, which serves side by side

 2          with AEP’s Appalachian Power in Virginia was not named in this inquiry because

 3          “ it is not in the Midwest”. But if AEP had opted to join the Midwest ISO instead

 4          of PJM, the resulting “seams” and “pancakes” between it and PJM and between it

 5          and parts of Virginia, West Virginia and the Carolinas presumably could be

 6          portrayed as protectionist measures, just as those resulting from AEP’s PJM

 7          choice have been portrayed by stakeholders to AEP’s north and west.

 8                 It has been suggested that a reason that AEP should be in the MISO

 9          instead of PJM is that it is more heavily connected with the MISO. When the

10          Commission rejected the Alliance proposal, one reason was that the Alliance

11          Companies were heavily interconnected with the MISO. Now the difference

12          between AEP’s interconnections with MISO and PJM is largely driven by the

13          RTO choices made by Consumers Energy, NIPSCO and FirstEnergy. It would be

14          equally appropriate to conclude that those companies made the “wrong” RTO

15          choices based on strength of interconnections than to conclude that AEP made the

16          “wrong” choice.

17                 AEP believes that it is time to put the rhetoric aside and recognize that

18          AEP is a large system located centrally vis-à-vis different geographic and trading

19          regions, that properly designed transmission charges are not “barriers” or

20          “tollgates” but are legitimate transportation costs present in many industries, and



                                                 5
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                             PREPARED DIRECT TESTIMONY OF
                                    SUSAN TOMASKY
                                           AND
                                     J. CRAIG BAKER

 1          that seams between RTOs are inevitable, and can be adequately managed with

 2          close coordination and standardized rules and protocols.

 3   Q.     What are the impediments to AEP’s participation in PJM?

 4   A.     The most obvious impediments are the Kentucky Public Service Commission’s

 5          initial disapproval of AEP operating company Kentucky Power Company’s

 6          application for approval to participate in PJM, and the Virginia law prohibiting

 7          any Virginia utility from participating in any RTO until July, 2004, and thereafter

 8          only with the Virginia Commission’s approval. Underlying those two state

 9          actions, we believe, are basic differences in regulatory philosophy between those

10          states and this Commission, which we will discuss below. Certain other state

11          actions involve a degree of uncertainty regarding the timing and nature of AEP’s

12          participation.

13                 Another impediment involves conditions imposed by the Commission in

14          connection with its approval of AEP’s, Commonwealth Edison’s and Dayton

15          Power and Light’s (“the New PJM Companies”) RTO choices. Certain of those

16          conditions are beyond the New PJM Companies’ ability to fulfill, and, in fact are

17          dependent upon approval by parties who actively oppose the New PJM

18          Companies’ choices. Finally, the August 2003 electricity blackout has caused the

19          industry, including PJM, to pause and to currently channel resources toward




                                                 6
                                                                                 Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                             PREPARED DIRECT TESTIMONY OF
                                    SUSAN TOMASKY
                                           AND
                                     J. CRAIG BAKER

 1          evaluation of the reliability aspects of proposed actions. This, in turn, has delayed

 2          somewhat PJM’s west expansion.

 3                           IV.    AEP’s RTO PARTICIPATION EFFORTS

 4   Q.     Please describe AEP’s RTO participation efforts.

 5   A.     Since at least September, 1999, AEP has been continuously and conscientiously

 6          pursuing membership in an RTO. It has incurred or committed to approximately

 7          50 million dollars in costs and many hours of its officers’ and employees’ time in

 8          this endeavor.

 9                 Also, since 2000, as a result of a merger condition, many of the RTO

10          functions are in the hands of independent third parties. Access to AEP’s east zone

11          transmission facilities and calculation of available transmission capability

12          (“ATC”) has been in the hands of Southwest Power Pool, an independent party,

13          and AEP has had its own market monitor. Since February, 2003 PJM has been

14          AEP’s Reliability Coordinator.

15                 In 1999, along with eight other transmission-owning utilities, AEP sought

16          approval from the Commission of the Alliance RTO, which by several measures

17          would have been the largest RTO in existence and the first to be formed as an

18          independent transmission company (“ITC”). In a series of orders issued in 2000

19          and 2001, the Commission substantially approved the proposed Alliance RTO,

20          including its scope and configuration. In good faith reliance on those approvals,



                                                 7
                                                                               Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          AEP and the other Alliance Companies continued development of the Alliance

 2          RTO at a cost of more than 90 million dollars. National Grid Company, an

 3          experienced independent transmission operator, proposed to manage the new

 4          RTO.

 5                 The Alliance Companies had also negotiated a settlement that, among

 6          other things, would establish a single, non-pancaked rate across the combined

 7          Alliance-Midwest Independent System Operator (“MISO”) Super Region. The

 8          rate solution also provided for a transitional lost-revenue recovery mechanism.

 9          On May 8, 2001, the Commission unanimously accepted the so-called Illinois

10          Power settlement, with some modifications, finding it to be “the basis for an

11          expanded market and a sounder, seamless and more reliable electric grid in the

12          Midwest”.

13                 The Alliance RTO was planning on a February 2002 operation date when,

14          on December 20, 2001, the Commission abruptly changed course and found that

15          the Alliance RTO, as proposed, failed to meet FERC’s requirements for scope and

16          regional configuration. The Commission made this finding despite three earlier

17          specific findings that the Alliance complied with that requirement and despite the

18          fact that the Alliance at the time was larger than any RTO under development. By

19          this action, the Commission also repudiated the Illinois Power settlement it had

20          approved just months earlier.



                                                8
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1                 In the Commission’s December 20 ruling, it said:

 2                 While we cannot approve Alliance RTO as a stand-alone RTO, we
 3                 are confident that it can be a successful Transco under the Midwest
 4                 ISO’s Appendix I. Therefore, we direct Alliance Companies to
 5                 explore how their business plan (including National Grid) can be
 6                 accommodated within the Midwest ISO, e.g., via Appendix I, in
 7                 doing so, we are mindful of the benefits that for-profit transcos can
 8                 provide. (footnotes omitted).
 9
10                 In accordance with the Commission’s direction, AEP and the other

11          Alliance Companies spent the next several weeks in negotiations with the MISO,

12          exploring how the Alliance business plan could be incorporated into the MISO.

13          In fact, an agreement in principle on such a plan was reached with MISO’s

14          management, but management’s approval of the agreement was withdrawn after

15          consultation with a select group of MISO stakeholders, which included, among

16          others, representatives of other transmission-owning utilities and energy market

17          participants. Faced with such an intractable position, and concerned with the

18          independence of the MISO, the Alliance Companies sought guidance from the

19          Commission in the form of a request for a declaratory order. The request sought

20          to clarify the parameters under which the Alliance could participate as an ITC

21          under the MISO, while at the same time retaining the viability of its business plan,

22          as envisioned by the Commission’s December 20, 2001 Order.




                                                 9
                                                                                 Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1                 On April 26, 2002, the Commission issued an Order on Petition for

 2          Declaratory Order which granted in part, and denied in part, the declarations

 3          sought by the Alliance Companies. The Commission also pointed out that:

 4                 Importantly, the guidance provided herein regarding the rate
 5                 design and delegation of functions is intended, however, to be
 6                 applicable to [the Alliance Companies] regardless of whether they
 7                 join PJM, Midwest ISO or another RTO.”
 8
 9                 The Order went on to require the Alliance Companies to make a

10          compliance filing within 30 days. The filing “must detail which RTO Petitioners

11          plan to join and whether such participation will be collective or individual.”

12                 Thus, the Commission’s April 26, 2002 Order implicitly recognized that

13          its failure to grant, in full, the relief sought by the Alliance Companies could

14          result in the Alliance participants reevaluating their plans for RTO participation.

15          The Commission’s order also indicated the possibility that one or more of the

16          Alliance Companies might join PJM.

17                 The Commission’s April 26 Order substantially altered the functions and

18          responsibilities that could be undertaken by the Alliance, leaving AEP with

19          serious concerns regarding the Alliance’s ability to develop, operate and maintain

20          a viable, for-profit business, able to attract new transmission investment. Under

21          the circumstances, AEP decided to pursue other alternatives for RTO

22          participation. On May 7, 2002, AEP signed a memorandum of understanding

23          (“MOU”) with PJM. AEP and the other former Alliance Companies notified the


                                                 10
                                                                                   Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          Commission of their RTO choices. At the Commission’s public meeting on June

 2          6, 2002, Chairman Wood indicated some concern with the Illinois Companies and

 3          FirstEnergy’s choices (PJM and MISO, respectively) but said:

 4                 As to the rest of the choices, [including AEP’s] I don’t have
 5                 anything and I don’t anticipate having anything that I
 6                 would bring up about those choices.
 7
 8                 The Commission issued an order on July 31, 2002, accepting the former

 9          Alliance Companies’ RTO choices including AEP’s choice to participate in PJM,

10          subject to the following conditions: (1) development of a single joint market

11          between PJM and MISO by October 2004; (2) participation by National Grid

12          USA in both PJM and MISO; (3) pro-forma agreements in MISO’s and PJM’s

13          tariffs providing for participation by ITCs; (4) filing of an ITC agreement among

14          PJM, National Grid, AEP, and other new PJM Companies; (5) approval of PJM’s

15          and MISO’s Reliability Plan by the North American Electric Reliability Council

16          (“NERC”); (6) development of a solution for “through-and-out” rates between

17          PJM and MISO; (7) filing of a solution to hold Michigan and Wisconsin harmless

18          from the effect of loop flows and congestion resulting from the proposed

19          configuration; (8) filing of a PJM, MISO, and National Grid USA Implementation

20          Plan and frequent progress reports; and (9) participation of FERC Staff in the

21          process.




                                                11
                                                                              Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                             PREPARED DIRECT TESTIMONY OF
                                    SUSAN TOMASKY
                                           AND
                                     J. CRAIG BAKER

 1                 On September 30, 2002, AEP signed an Implementation Agreement

 2          authorizing PJM to proceed with activities necessary to assume functional control

 3          of AEP’s East Zone transmission facilities and to integrate AEP into PJM’s

 4          energy and ancillary service markets. The Implementation Agreement committed

 5          AEP to spend about $13 million, and if AEP ultimately does not join PJM,

 6          commits AEP to reimburse PJM for capital expenditures of about $23 million.

 7          AEP and PJM teams then began a series of meetings to iron out the details of

 8          AEP’s participation, including the negotiation of documents necessary for such

 9          participation.

10   Q.     Why would AEP sign such an agreement if it had concerns about its ability to

11          meet the Commission’s conditions?

12   A.     AEP had little choice. AEP was under pressure to join an RTO, and PJM, in light

13          of the fluid regulatory situation, understandably wanted to recover its costs

14          regardless of future developments. PJM and MISO, at the time, indicated that

15          development of the joint and common market could be done expeditiously, and

16          the Illinois Power settlement provided a roadmap for the elimination of out and

17          through rates. But at the time, AEP did not fully appreciate the lengths that

18          certain MISO stakeholders would go to to frustrate AEP’s plans to join PJM, or

19          the resistance we would encounter to revenue neutrality mechanisms.

20   Q.     Please continue.



                                                12
                                                                                 Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1   A.     On December 9, 2002, AEP signed an amended PJM West Transmission Owners’

 2          Agreement (“WTOA”) under which AEP agreed to transfer functional control of

 3          its East Zone facilities to PJM, subject to the receipt of necessary regulatory

 4          approvals. On December 11, 2002, AEP, PJM, Commonwealth Edison, and

 5          Dayton Power and Light filed an application in this Docket for approval of

 6          various documents necessary for the new PJM Companies to participate in PJM.

 7                 On December 19, 2002, AEP filed applications with the Indiana

 8          Regulatory Utility Commission, the Kentucky Public Service Commission, the

 9          Public Utilities Commission of Ohio, and the Virginia State Corporation

10          Commission seeking the state commissions’ authority, to the extent necessary, for

11          the proposed transfer of functional control of transmission facilities to PJM.

12                 The application in this Docket and the various state applications indicated

13          AEP’s plan to join PJM in two steps. On “Day One,” AEP would transfer

14          functional control of its transmission facilities and provision of open access

15          transmission service to PJM, and on “Day Two,” AEP would become fully

16          integrated into PJM’s energy and ancillary services markets.         Day One was

17          initially expected to occur on February 1, 2003, and Day Two on May 1, 2003.

18          However, AEP’s participation in PJM has been delayed by legal and regulatory

19          considerations. Those legal and regulatory considerations are described in detail

20          in a Report on Compliance with Transmission-related Merger Conditions filed



                                                 13
                                                                                   Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          with the Commission by AEP on February 28, 2003, in FERC Docket No. EC98-

 2          40-000. The Report indicated that:

 3                 . . . AEP worked diligently to achieve, and believed until very
 4                 recently, that AEP’s acceptance into [PJM] [was] imminent.
 5                 However, recent actions by several of AEP’s states suggests those
 6                 states will not grant requested permission of AEP’s plan to
 7                 participate in an RTO until FERC and the states can resolve their
 8                 differences about RTOs. These concerns center in part on the
 9                 [FERC’s] Standard Market Design (SMD) proposals, which were
10                 advanced in 2002, and would fundamentally affect both the
11                 structure of power markets and the division between federal and
12                 state jurisdiction over integrated utilities. Most significantly, on
13                 February 25, 2003, the Virginia General Assembly approved
14                 legislation that prohibits any firm that is a public utility in Virginia
15                 from transferring ownership or control of, or operational
16                 responsibility over, any transmission system to “any person”
17                 before July 1, 2004, and thereafter without approval of the Virginia
18                 State Corporation Commission (VSCC).
19
20                 At this point, AEP continues to pursue RTO membership, but is
21                 faced with the above-described federal and state issues. Until the
22                 Commission and the states can resolve the differences between
23                 them, AEP is reluctant to go further, and the [FERC] should not
24                 expect it to attempt to do so.
25
26                 AEP urged the Commission and states to engage in a dialogue to resolve

27          such conflicts but indicated that in the absence of a resolution, the Commission

28          has authority under Section 205 of the Public Utility Regulatory Policies Act of

29          1978 (PURPA), in some circumstances, to exempt electric utilities from any state

30          rule or regulation which prohibits the voluntary coordination of electric utilities,

31          including any agreement for central dispatch, if the Commission determines that

32          such voluntary coordination is designed to obtain economical utilization of


                                                 14
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          facilities and resources in any area. AEP indicated that it would be reluctant to

 2          see the Commission invoke this remedy and presumed the Commission would

 3          also view reconciliation as a much better outcome than compulsion.

 4                 On April 1, 2003, the Commission issued an order conditionally accepting

 5          the documents submitted in the New PJM’s December 11, 2002 filing in this

 6          Docket and approving, under Section 203 of the Federal Power Act, AEP’s and

 7          Commonwealth Edison’s transfer of functional control of jurisdictional facilities

 8          to PJM.

 9                 The Commission required certain rate issues to be set for hearing and

10          directed the companies to file information required by FERC’s regulations. The

11          New PJM Companies made a compliance filing, as ordered, on May 1, 2003.

12                 Meanwhile, AEP and the other New PJM Companies did what they could

13          to attempt to fulfill the Commission’s July 31, 2002 conditions, keeping in mind

14          that many of those conditions were beyond the Companies’ control.

15   Q.     Which of the conditions were beyond the New PJM Companies’ control?

16   A.     Practically none of the conditions was solely within the New PJM Companies’

17          ability to fulfill, but some proved more problematic than others.

18                 The reliability condition depended on development of a Reliability Plan by

19          MISO and PJM, and its approval by the North American Electric Reliability

20          Council (“NERC”), where the New PJM Companies were only three voices out of



                                                15
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                            PREPARED DIRECT TESTIMONY OF
                                   SUSAN TOMASKY
                                          AND
                                    J. CRAIG BAKER

 1          many.    The latest version of plan was ultimately approved by the NERC

 2          Operating Committee on June 6, 2003.

 3                  The Michigan Wisconsin hold-harmless condition has proved particularly

 4          problematic.    We first tried informal negotiations, and when those were

 5          unsuccessful, held several meetings before a Settlement Judge, the Honorable

 6          Judith Dowd. At one point, the parties submitted questions to the Commission

 7          seeking more clarity on the meaning and scope of the hold harmless requirement.

 8          The Commission provided the clarification which the New PJM Companies

 9          believe was very helpful, but after more meetings, settlement proved

10          unsuccessful.

11   Q.     What, in your opinion has been the impediment to a settlement of this issue?

12   A.     There are two basic aspects to the “hold harmless” issue -- operational aspects and

13          financial aspects. The operational aspects are in the hands of the two RTOs, and

14          we believe they have done an outstanding job of addressing them, in their draft

15          Joint Operating Agreement in which MISO and PJM have developed state-of-the-

16          art procedures for coordinating loop flow and congestion issues between RTOs.

17                  The alleged financial effects are another matter.        The two RTOs,

18          appropriately, see any financial compensation as beyond their responsibilities.

19          The New PJM Companies believe there will be no significant net financial effects

20          on Michigan and Wisconsin utilities that will not be obviated by the Joint



                                                16
                                                                                 Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          Operating Agreement Plan. The Michigan and Wisconsin stakeholders disagree.

 2          Since many of these parties do not want the New PJM Companies to join PJM,

 3          they have no incentive to cooperate in a resolution of any of the conditions and

 4          every incentive to frustrate such a resolution. Therein lies the basic problem.

 5   Q.     What other condition has proved an impediment?

 6   A.     The Federal Power Act Section 206 proceeding on MISO and PJM through-and-

 7          out rates has provided the largest impediment. As with the “hold-harmless”

 8          condition, the affected parties first pursued negotiations. After those proved

 9          unsuccessful, a hearing was held before Administrative Law Judge Grossman. In

10          his initial decision, Judge Grossman stated that he did not have precedential

11          authority to order the elimination of MISO’s and PJM’s through-and-out rates.

12          He went on to say that if the Commission were nevertheless to conclude, on

13          policy grounds, that such rates should be eliminated, he would recommend the

14          adoption of a transitional revenue neutrality mechanism such as a “Seams

15          Elimination Charge/Cost Adjustment/Assignment” (“SECA”) of which two

16          versions had been proposed by parties to the proceeding.

17                 On July 23, 2003, the Commission issued an order reversing Judge

18          Grossman, and ordering the elimination of MISO’s and PJM’s through-and-out

19          rates for transactions in their combined territories. Significantly, the Commission

20          also rejected Judge Grossman’s recommendation that such rates be replaced with



                                                 17
                                                                                 Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                            PREPARED DIRECT TESTIMONY OF
                                   SUSAN TOMASKY
                                          AND
                                    J. CRAIG BAKER

 1          a SECA. Instead, the Commission allowed parties to propose a SECA or similar

 2          mechanism in a proceeding under Section 205 of the Federal Power Act. In

 3          addition, the Commission required AEP and other transmission owners to show

 4          cause why their individual company through-and-out rates should not be

 5          eliminated for transactions within the combined MISO/PJM area. As in the case

 6          of the RTO’s rates, the Commission allowed AEP and the other affected

 7          companies to propose a SECA or similar mechanism under FPA Section 205.

 8                 As AEP pointed out in its August 15, 2003 response to the Commission’s

 9          “show cause” order, that order threatens AEP’s shareholders and native load

10          customers with a loss of about $150 million dollars annually, with only an

11          uncertain prospect of replacing all or part of those dollars.

12                 We believe that order to be of questionable legality, for reasons spelled

13          out in our August 15 response, but, more important, the order threatens a

14          fundamental business interest of AEP – preservation of the value of its

15          transmission assets – as explained by Dr. Draper in his testimony.

16                 The order also had the effect of disrupting negotiations between the New

17          PJM Companies and the PJM “classic” transmission owners on lost revenue

18          recovery issues associated with intra-PJM transactions.          All in all, the

19          Commission’s July 23 Order represents a major impediment to RTO expansion.




                                                  18
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                             PREPARED DIRECT TESTIMONY OF
                                    SUSAN TOMASKY
                                           AND
                                     J. CRAIG BAKER

 1                          V. STATUS OF STATE PROCEEDINGS

 2   Q.      What is the status of the various state proceedings where AEP has sought

 3           approval of its PJM participation?

 4   A.      The status in each of the states is as follows:

 5           Virginia

 6           On December 19, 2002, AEP filed with the VSCC a request for permission to

 7           transfer functional control of transmission facilities to PJM.     No procedural

 8           schedule has been established with respect to AEP’s application.

 9           Kentucky

10           On December 19, 2002, AEP filed an application for approval by the Kentucky

11           Public Service Commission (“KPSC”) for approval to transfer functional control

12           of transmission facilities to PJM. On July 17, 2003, the KPSC issued an order

13           denying AEP’s application. The KPSC found that AEP had not shown that the

14           benefits of AEP’s participation outweighed the costs. Although the evidence

15           showed net benefits for AEP East as a whole, the KPSC cited the lack of an

16           analysis specific to AEP operating company Kentucky Power. On August 25,

17           2003, the KPSC granted AEP’s request for rehearing allowing the Company to

18           submit a Kentucky-specific analysis. AEP expects to file such an analysis by

19           December 2003, after which additional hearings will be held.

20        Indiana



                                                   19
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          On December 19, 2002, AEP filed with the Indiana Utility Regulatory

 2          Commission (“IURC”) an application for approval of AEP’s participation in PJM.

 3          Hearings were held, and on September 10, 2003, the IURC issued an order

 4          conditionally approving AEP’s application. Since many of the IURC’s conditions

 5          are beyond AEP’s ability to control (e.g., that there be a single dispatch for both

 6          PJM and MISO), AEP does not, at this time, have authorization from the IURC to

 7          transfer functional control of transmission assets to PJM, and is evaluating

 8          whether to request reconsideration.

 9        Ohio

10          On December 19, 2002, AEP filed with the Public Utilities Commission of Ohio

11          (“PUCO”) a request for approval of AEP’s participation in PJM as part of an

12          amended Independent Transmission Plan (“ITP”). On February 20, 2003, the

13          PUCO issued an entry which states, in relevant part, that in light of the “many

14          unresolved issues regarding the formation, approval and operation of PJM and

15          other transmission organizations at state and federal levels,” “there are too many

16          unresolved issues beyond the [Ohio] Commission’s jurisdiction for the

17          Commission to have a meaningful review of [Ohio] Utilities’ ITPs at this time.”

18   Q.      What do you believe are the state concerns that led to the Kentucky initial

19          disapproval and Virginia legislation?




                                                  20
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1   A.     The states, of course, can speak for themselves, but based on their orders and

 2          public statements, it is apparent that there exists an overall difference in

 3          regulatory philosophy between these state regulators and this Commission

 4          regarding the structure of the electricity industry. This Commission, of course, has

 5          a vision of the future of the industry described in its Standard Market Design

 6          Notice of Proposed Rulemaking (“SMD NOPR”), as modified somewhat by its

 7          subsequent White Paper.

 8                 Kentucky clearly stated its position on this vision in its Comments filed in

 9          the SMD NOPR on November 15, 2002:

10                         The Commonwealth of Kentucky has the lowest
11                         average electricity costs in the nation. In addition, our
12                         electricity service is highly reliable. FERC seeks to
13                         force fundamental changes to the way Kentucky’s
14                         utilities operate without any probative evidence that
15                         there is a need for such changes, and without any
16                         showing that customers served by these utilities will see
17                         significant benefit from them. Such dramatic changes
18                         are certain to undercut the very foundation of the
19                         reliable and low-cost electricity service that Kentucky
20                         customers enjoy.
21
22
23                 In its SMD Comments, the Virginia State Corporation Commission
24   concluded:
25
26                         [T]hat both in concept and execution, the proposed
27                         rules are fundamentally flawed, and should be
28                         withdrawn by the Commission in favor of a thorough
29                         examination of the critical issues encompassed by them.
30                         Such a review should fully consider state and federal
31                         jurisdictional questions, as well as the costs and


                                                21
                                                                               Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1                        benefits associated with implementing the sweeping
 2                        imposition of federal control over the nation’s
 3                        electricity system envisioned in this rulemaking.
 4
 5   Q.     What are the Kentucky Commission’s specific concerns about AEP’s planned

 6          participation in PJM?

 7   A.     Based on the KPSC’s order rejecting AEP’s application, its concerns center

 8          around the following issues:

 9             1. Costs and cost/benefit

10          The KPSC noted, at page 17 of its order:

11                     The record shows that Kentucky Power will incur $3
12                     million per year in administrative costs as a result of AEP-
13                     East joining PJM. This can be viewed as a minimum cost
14                     level that is likely to increase over time as FERC assigns
15                     additional functions and responsibilities to RTOs, or as
16                     PJM elects to take on additional functions and
17                     responsibilities. Moreover, FERC has conducted no review
18                     to determine the reasonableness of RTO costs incurred by
19                     AEP or PJM. (emphasis in original).
20
21          The KPSC focused more specifically on costs associated with the markets to be

22          administered by PJM:

23                 Additionally, a portion of the PJM administrative costs pays for its
24                 day-ahead and real-time markets, as well as the PJM congestion
25                 management system. Although these services may benefit PJM’s
26                 multi-state wholesale market, they bring no discernible benefits to
27                 Kentucky Power’s retail customers. Such benefits to the PJM’s
28                 multi-state wholesale market will not be realized by Kentucky
29                 Power’s retail customers since they receive bundled service and
30                 Kentucky Power meets its load with generation that it owns or
31                 purchases under bilateral contracts, except for a few hours each
32                 year during peak periods.


                                               22
                                                                                   Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                             PREPARED DIRECT TESTIMONY OF
                                    SUSAN TOMASKY
                                           AND
                                     J. CRAIG BAKER

 1
 2                                           *** *** ***
 3                   Simply creating a larger wholesale market that extends from the
 4                   Midwest region to the mid-Atlantic region will not bring cheaper
 5                   power to Kentucky. As Kentucky Power’s base load generation is
 6                   at or near the lowest cost of generation in both AEP-East and PJM,
 7                   being part of the PJM market will bring no quantifiable benefit to
 8                   Kentucky Power.
 9
10            The KPSC also expressed concern about the potential for unhedged congestion

11            costs under LMP.

12               2. Loss of jurisdiction and control

13            In its SMD NOPR Comments, the KPSC noted its concern that FERC’s

14   preemption of state jurisdiction would hinder each state’s ability to protect its own

15   electricity customers. In its order denying AEP’s RTO application, the Commission

16   stated

17                   In more general terms, we must also express herein our grave
18                   concern at the prospect of surrendering even a portion of our
19                   authority to protect Kentucky Power’s customers. Experience over
20                   the past few years has taught us that the transfer of control of a
21                   utility’s transmission system is to be approached most cautiously.
22                   FERC policies now encourage entities outside Kentucky to
23                   exercise authority over resource adequacy, transmission rights,
24                   transmission planning, and cost allocation of transmission
25                   upgrades. Since these are all issues that have traditionally been
26                   subject to state jurisdiction, we must look very carefully at any
27                   petition of a Kentucky utility for authority to place its transmission
28                   system under an RTO that is not subject to the jurisdiction of this
29                   Commission.
30
31            Finally, the KPSC expressed concern with federal rules that preclude utilities

32   from providing transmission curtailment priority to native load customers.


                                                  23
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                              PREPARED DIRECT TESTIMONY OF
                                     SUSAN TOMASKY
                                            AND
                                      J. CRAIG BAKER

 1                  3. Diversion of Low Cost Power
 2
 3           The Commission expressed a concern that, although not currently required by

 4   PJM rules, PJM could, in the future:

 5                        [R]evise its rules to require all member generation to be
 6                        sold into PJM. In such an eventuality, Kentucky Power’s
 7                        customers would be required to pay the average rate for
 8                        power sold in the PJM market. Since the cost of generation
 9                        for the existing PJM members is significantly higher than
10                        the cost for Kentucky Power, the financial impact would be
11                        devastating and severely hamper future economic
12                        development efforts in eastern Kentucky. (emphasis in
13                        original).
14
15   We also believe that these concerns, in some degree contributed to the Virginia

16   legislation.

17   Q.      What other state regulatory uncertainties exist?

18   A.      There are regulatory uncertainties even in states which support our PJM choice.

19           Although Indiana has approved our application to participate in PJM, it has

20           attached conditions that are beyond our control. Ohio has held our filing in

21           abeyance, pending resolution of “unresolved issues . . . at state and federal

22           levels.”

23                                 VI. SPLIT SYSTEM PROPOSAL

24   Q.      It has been suggested by the Commission Staff that a way to expedite AEP’s

25           participation would be to split the AEP east transmission zone between states that




                                                  24
                                                                                    Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          have approved or do not object and those that have not yet approved AEP’s

 2          joining PJM. Would you please address this scenario?

 3   A.     Yes. The split system scenario is a very bad idea. Although perhaps technically

 4          feasible, it would increase AEP’s costs, and raise a host of complex contractual,

 5          legal, regulatory and operational issues that totally negate the idea that such a

 6          scenario represents an expeditious solution to accomplishing PJM expansion.

 7          Further, the split system scenario runs contrary to the integrated nature of the AEP

 8          transmission system, which Dr. Draper identifies as a fundamental business

 9          interest for AEP.

10                 AEP addressed the split system scenario in detail in responses to staff data

11          requests filed in this docket on June 25, 2003. A copy of those responses and

12          accompanying transmittal letter is attached hereto as Exhibit AEP-4. I would

13          summarize AEP’s responses as follows:

14                 1)           Integrated planning and operation are fundamental to the AEP

15                              transmission system, and have resulted in AEP being a very low

16                              cost electric provider;

17                 2)           Holding company systems are required to provide system-wide

18                              transmission service under a single tariff. Splitting the system for

19                              RTO purposes would result in two tariffs;




                                                    25
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                          PREPARED DIRECT TESTIMONY OF
                                 SUSAN TOMASKY
                                        AND
                                  J. CRAIG BAKER

 1                 3)      Splitting the system would result in the loss of economies and

 2                         efficiencies of integrated planning and operation;

 3                 4)      Splitting the system would run counter to the whole movement

 4                         toward regionalization of tariff and reliability functions under

 5                         Order No. 2000;

 6                 5)      Splitting operating companies by state (e.g., Appalachian Power,

 7                         which operates both in Virginia and West Virginia), if required,

 8                         would create operational barriers where none exist today;

 9                 6)      The scenario presents complicated tariff administration questions

10                         regarding pricing and transaction protocols;

11                 7)      Creating non-pancaked rates for a split system would create lost

12                         revenue and cost allocation issues among the operating

13                         companies;

14                 8)      Unlike RTO creation, which reduces seams, and leaves only

15                         inter-RTO seams, splitting the system would create seams where

16                         none existed before;

17                 9)      Changes to AEP’s pool agreements may be required. Past efforts

18                         at changing the agreements have resulted in complex, costly and

19                         time-consuming FERC proceedings;




                                              26
                                                                                  Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                            PREPARED DIRECT TESTIMONY OF
                                   SUSAN TOMASKY
                                          AND
                                    J. CRAIG BAKER

1                10)         A new control area around the non-transferred facilities would

2                            have to be set up, requiring new facilities and personnel costs;

 3               11)         Congestion management would become significantly more

 4                           difficult than it is today.

 5   Q.     Is the foregoing discussion inconsistent with PJM’s position described in its

 6          responses to the Staff data requests?

 7   A.     No, it is not. PJM simply was addressing the Staff’s questions from a much

 8          narrower perspective. PJM took great pains to point out that it “is focusing on the

 9          technical and operational aspects of the alternative scenarios”, and stated that:

10                     Equally, important, PJM has not attempted to evaluate or
11                     address for purposes of these responses potential federal or
12                     state legal or regulatory concerns or issues that might arise
13                     about dividing AEP-East’s facilities as discussed in these
14                     responses. PJM notes that implementation of any of the
15                     above scenarios may require further discussions with
16                     federal and state regulators,
17
18                 AEP does not dispute that the split system scenario may be technically

19          feasible, but AEP, must, as well consider the regulatory, contractual, legal and

20          other considerations that are beyond the scope of PJM’s responses. If a split

21          system proposal is imposed on the non-consenting states, these issues are likely to

22          arise, negating any prospect for an expeditious resolution. In addition, we would

23          offer the following observations on PJM’s responses to the Staff data requests.




                                                    27
                                                                                    Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                            PREPARED DIRECT TESTIMONY OF
                                   SUSAN TOMASKY
                                          AND
                                    J. CRAIG BAKER

 1                   I also note that PJM’s responses say that transferring all of AEP’s east

 2          zone to PJM will produce optimum benefits because of the additional resources

 3          and number and diversity of economic dispatch solutions.             The new smaller

 4          control areas would thus be sub-optimal.

 5   Q.     Doesn’t AEP’s corporate separation proposal approved by the Commission in

 6          2002 show that AEP can, in fact, split its system?

 7   A.     No. First, AEP’s corporate separation proposal involved the separation of

 8          generating assets, not AEP’s integrated transmission system. The corporate

 9          separation proposal, unlike the split system scenario would have retained

10          operating company boundaries, a single transmission tariff and a single control

11          area with adequate reserves in each of the control zones. Second, as discussed

12          above, AEP never said it cannot split its system. Technically it may be feasible.

13          What we have said, is that such a split raises numerous technical, legal,

14          contractual, political and regulatory complications, which would be costly and

15          difficult to resolve, and in addition, will result in the incurrence of additional

16          costs.

17                   While we eventually obtained Commission approval of our corporate

18          separation proposal, it took substantial time and resources to resolve concerns

19          voiced by our state commissions and other stakeholders.             We had to make




                                                  28
                                                                                 Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                             PREPARED DIRECT TESTIMONY OF
                                    SUSAN TOMASKY
                                           AND
                                     J. CRAIG BAKER

 1          numerous concessions, such as extensions of rate freezes, to obtain buy-in from

 2          affected parties.

 3                 The separation of the transmission system is more fundamental than

 4          AEP’s corporate separation proposal and would result in significantly more

 5          controversy and litigation.

 6   Q.     Doesn’t AEP operate in three different control areas as a result of its merger with

 7          CSW?

 8   A.     Yes, but the merger represented the exact opposite of the “split system” scenario

 9          suggested here. The merger involved tying together two historically integrated

10          systems, one of which had years of experience with integrated operation in two

11          control areas (which are connected through DC ties, thereby simplifying

12          operational issues). The split system scenario, by contrast, would involve

13          separating a historically integrated system. It should also be added that the

14          merger presented numerous complications and some controversy regarding the

15          mechanics and pricing associated with transmission pricing among the three

16          control areas.

17                              VII. AEP’s PROPOSED SOLUTION

18   Q.     What solution does AEP recommend for resolution of the impediments to its RTO

19          participation discussed above?




                                                 29
                                                                                   Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1   A.     First and foremost, AEP urges that any solution come about as a result of a

 2          dialogue between and among federal and state regulators.         While AEP has

 3          acknowledged this Commission’s authority, if exercised properly, to impose a

 4          solution on the states, it has cautioned against such action. AEP indicated in its

 5          February 28, 2003 filing in Docket Nos. EC98-40-000, that it would be “reluctant

 6          to see the Commission invoke this remedy, and presumably the Commission

 7          would view reconciliation as a much better outcome than resorting to

 8          compulsion.”

 9             An imposed solution, in the long run, is unlikely to represent the most

10          desirable or expeditious remedy.         The controversy, litigation and ill will

11          engendered by such a solution would be detrimental to the affected regulators and

12          the utilities they regulate, for a number of years. An imposed solution would also

13          frustrate AEP’s attempts to recover RTO costs, and would compromise the

14          fundamental business interests identified in Dr. Draper’s testimony.

15             Any mutually-agreeable solution, of course, must entail compromise by the

16          regulators involved.

17             With those considerations in mind, AEP proposes, as a starting point for the

18          dialogue between and among state regulators the following solution in which AEP

19          would transfer functional control of its east zone transmission facilities to PJM,

20          but PJM’s functions would be limited to those required by Order No. 2000. In



                                                30
                                                                                 Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                            PREPARED DIRECT TESTIMONY OF
                                   SUSAN TOMASKY
                                          AND
                                    J. CRAIG BAKER

 1          other words, AEP would not become integrated into PJM’s voluntary markets.

 2          AEP could certainly participate in PJM markets on a bilateral basis, and PJM

 3          market participants could likewise trade with AEP on such a basis.

 4   Q.     Describe the functions that the RTO would and would not perform.

 5   A.     The RTO would perform many of its current functions, including:

 6          •   Independent functional control of AEP’s transmission system

 7          •   Independent tariff administration, with transmission service provided under

 8              PJM’s OATT

 9          •   Independent control of transmission access, including calculation of TTC and

10              ATC

11          •   Continuation of PJM as AEP’s Reliability Coordinator

12          •   Market monitoring by the PJM Market Monitor

13          •   Regional transmission planning pursuant to the PJM Regional Planning

14              Protocol

15          •   Seams coordination with the Midwest ISO pursuant to the PJM/MISO Joint

16              Operating Agreement

17          In addition, the proposal would include non-pancaked rates for service throughout

18   the combined PJM/Midwest ISO regions (with a transitional revenue- neutrality

19   mechanism and a long-term solution to the cost-shifting issue for the full footprint)

20          The RTO’s functions would not include:



                                                 31
                                                                               Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

1           •   Administration of day-ahead and real-time energy and ancillary service

2               markets

3           •   Centralized economic dispatch

4           •   Locational Marginal Price congestion management

5       Q. Do you believe such a solution would be acceptable to the state Commissions that

6           support or do not oppose AEP’s membership in PJM?

7       A. I cannot speak for those states. However, I note that the solution resembles an

8           alternative proposal put forward in a filing made in this docket on March 14, 2003

9           by the Public Utilities Commission of Ohio, the Michigan Public Service

10          Commission and the Pennsylvania Public Utilities Commission. In that pleading,

11          the Commissions said:

12                 Our first choice, and strong preference, is still to see AEP
13                 expeditiously join an established RTO. However, to postpone
14                 a direct jurisdictional conflict, and indeed in the hopes that
15                 such a conflict might be avoided altogether, the Joint Movants
16                 propose the following interim course of action:
17
18                 AEP should be required to immediately contract with an
19                 independent third party that has no economic interest in the
20                 wholesale generation market to operate AEP’s transmission
21                 system, in a manner that need not require any legal transfer of
22                 functional control or state approval. To be an acceptable
23                 candidate, this independent third party must either be an
24                 established RTO or have a binding contractual commitment to
25                 operate AEP’s transmission system with an established RTO in
26                 a manner consistent with the TransLink precedent discussed
27                 below. The most logical entity to assume this third party
28                 function is PJM Interconnection, L.L.C., which, in consultation
29                 with AEP and other applicants in “The New PJM” docket at


                                                32
                                                                                Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1                 ER03-262, have already expended many dollars and hours in
 2                 assessing each others’ transmission grids and in drafting the
 3                 agreements and operating protocols necessary for joint
 4                 operation.
 5
 6                                   *** *** ***

 7                 While this arrangement would not immediately create a
 8                 regional wholesale generation market, your Commission has
 9                 not required that all generation markets be operated by RTOs.
10                 Regional Transmission Organizations, 89 FERC ¶ 61,285. A
11                 primary purpose of the creation of independent regional
12                 transmission entities is to separate transmission service
13                 operations from generation to prevent vertically integrated
14                 public utilities from exercising preferential treatment of their
15                 own generation. Id. At 35-36.
16
17                 While the Joint Movants recognize that this proposal is not an
18                 end state and does not dispose of all issues, it will enable
19                 progress to be made. The necessary and critical step of
20                 transferring control of AEP’s grid to an independent third party
21                 operator under an established RTO assures non-discriminatory
22                 open-access to the transmission system and will enable
23                 regional interstate electric generation markets to develop.
24
25      Q. Would such a solution be acceptable to Kentucky and Virginia?

26      A. Again, I cannot speak for them, but I note that it addresses some of the major

27          concerns expressed by the Kentucky Commission in its order denying AEP’s

28          RTO application. In particular, it could save some of the considerable costs

29          associated with integration into PJM’s markets, and the KPSC’s perceived lack of

30          benefit to AEP of participation in such markets. It also would it would eliminate

31          AEP’s exposure to unhedged LMP congestion costs, another concern expressed

32          by Kentucky as well as during discussions leading to the Virginia legislation.


                                                33
                                                                                   Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                            PREPARED DIRECT TESTIMONY OF
                                   SUSAN TOMASKY
                                          AND
                                    J. CRAIG BAKER

 1   Q.     Would this mean that AEP’s surplus generation would not be available in PJM’s

 2          markets?

 3   A.     No. AEP would be free to transact bilaterally with PJM market participants and

 4          vice-versa. Further, the pancake elimination (with a contemporaneously effective

 5          substitute rate mechanisms) and seams mitigation measures would facilitate such

 6          commerce. The only difference is that AEP would not be integrated into PJM’s

 7          organized markets. Since participation in such markets is voluntary in any event,

 8          this should not pose a practical problem for PJM or its existing members.

 9   Q.     Would AEP’s proposal satisfy its merger condition?

10   A.     Yes. At the time that FERC issued the Merger Order and that AEP accepted the

11          conditions of the Order, the Commission had defined an RTO as having attributes

12          that meet the principles set forth in Order No. 2000. Under Order No. 2000,

13          RTOs must be independent from market participants; must have sufficient scope

14          and regional configuration; must have operational authority for all transmission

15          facilities under its participants’ control; and must have the authority for

16          maintaining reliability. In addition, RTOs must perform certain functions

17          described in Order No. 2000, including the administration of the transmission

18          tariff; congestion management; development of procedures to address parallel

19          path flow; and market monitoring.




                                                  34
                                                                              Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1                 The administration of energy markets, and LMP congestion management,

 2          although a feature of PJM and some other existing or proposed regional entities,

 3          was not an RTO requirement. It was not until the SMD NOPR, issued in 2001,

 4          that the Commission proposed to require market administration as an RTO

 5          function.

 6                 The RTO merger condition was imposed by the Commission to address

 7          the concern about the ability of the merged entity to exercise “transmission

 8          market power”, that is, the concern that the merged entity would use its

 9          combination of generation and transmission assets to “frustrate competitors’

10          access to relevant markets” (Merger Order, at 61,786). Independent functional

11          control of AEP’s transmission system and tariff administration, independent

12          market monitoring, and all of the other Order 2000 functionalities more than

13          sufficiently addresses this concern.

14                 With increased functionalities come increased costs. In AEP’s case, the

15          increase has been fivefold since we entered into the merger commitment - from

16          around $10 million for the Alliance – a transmission-only entity -- to around $50

17          million per year for PJM, with its additional functions.

18   Q.     Have other factors changed since the merger order?

19   A.     Yes.   Not only have the Commission’s preferred functionalities for RTOs

20          expanded to include market administration, as discussed above, but the physical



                                                   35
                                                                             Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                           PREPARED DIRECT TESTIMONY OF
                                  SUSAN TOMASKY
                                         AND
                                   J. CRAIG BAKER

 1          scope of RTOs and “super regions” has expanded significantly. The RTOs at the

 2          time (such as The New England and New York ISOs and PJM and the Midwest

 3          ISO as they then existed) were much smaller in scale than the expanded PJM that

 4          AEP plans to join.      Moreover, Order 2000 required rate pancaking to be

 5          eliminated within RTOs. Now, the Commission is requiring (at least in the

 6          present context) inter-RTO pancake elimination. The practical effect of such an

 7          expansion of has been to increase AEP’s exposure to lost revenues from $86

 8          million to $152 million. (the $86 million number represents the initial 5-member

 9          Alliance Company which had an agreed-upon revenue neutrality solution among

10          the members). I think it is safe to say that the notion of shipping power from

11          Nebraska to Philadelphia at a single rate would have been a startling concept at

12          the time of the merger order.

13                 As both the functional and physical scope of RTOs (and super regions) has

14          expanded, state resistance to such developments has grown. At the time of the

15          merger our eastern states were all either neutral or positive toward RTO

16          development.    No state protested FERC’s imposition of the RTO merger

17          condition. Since the Commission’s expansion of the RTO concept (as reflected in

18          the SMD NOPR), that situation has changed such that two of our eastern states

19          have reacted negatively.    In fact, State laws in Kentucky and Virginia were

20          changed to reflect the increased state concern. Kentucky law was amended to



                                               36
                                                                               Exhibit AEP-2

     Docket Nos. ER03-262-000, et al.

                            PREPARED DIRECT TESTIMONY OF
                                   SUSAN TOMASKY
                                          AND
                                    J. CRAIG BAKER

 1          require Public Service Commission approval of incumbent utilities’ RTO

 2          participation, and Virginia, which had in place a law requiring RTO participation

 3          to support customer choice legislation, passed the above-discussed legislation

 4          delaying such participation, and in a report to the Virginia legislature, the VSCC

 5          has asked for an additional delay.

 6                 So, joining an RTO now means a lot more than it did at the time of the

 7          merger order, and carries a much larger potential price tag. Clearly, joining PJM

 8          with reduced functionalities would satisfy the merger commitment, and has the

 9          potential to alleviate some state concerns.

10   Q.     Does this conclude your direct testimony?

11   A.     Yes, it does.




                                                 37
                                                                           Exhibit AEP-2

Docket Nos. ER03-262-000, et al.

                       PREPARED DIRECT TESTIMONY OF
                              SUSAN TOMASKY
                                     AND
                               J. CRAIG BAKER

                              AFFIDAVIT OF WITNESS

       I, the undersigned, being duly sworn, depose and say that the Prepared Direct

Testimony of Susan Tomasky served on behalf of The AEP Companies in this

proceeding is the testimony of the undersigned, and the exhibits sponsored by me to the

best of my knowledge, information and belief, are true, correct, accurate and complete,

and I hereby adopt said testimony as if given by me in formal hearing, under oath.




                                             Susan Tomasky

       SUBSCRIBED AND SWORN to before me, a Notary Public, in Franklin County,

Ohio on the 23rd day of September, 2003.




                                           38
                                                                           Exhibit AEP-2

Docket Nos. ER03-262-000, et al.

                       PREPARED DIRECT TESTIMONY OF
                              SUSAN TOMASKY
                                     AND
                               J. CRAIG BAKER

                              AFFIDAVIT OF WITNESS

       I, the undersigned, being duly sworn, depose and say that the Prepared Direct

Testimony of J. Craig Baker served on behalf of The AEP Companies in this proceeding

is the testimony of the undersigned, and the exhibits sponsored by me to the best of my

knowledge, information and belief, are true, correct, accurate and complete, and I hereby

adopt said testimony as if given by me in formal hearing, under oath.




                                             J. Craig Baker

       SUBSCRIBED AND SWORN to before me, a Notary Public, in Franklin County,

Ohio on the 23rd day of September, 2003.




                                           39

								
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