PUC DOCKET NO. PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY

Transcription

1 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF PAUL CHODAK FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

2 TESTIMONY INDEX SECTION PAGE I. INTRODUCTION...1 II. PURPOSE OF TESTIMONY... III. BACKGROUND OF THE WIND CATCHER ENERGY CONNECTION PROJECT... IV. CUSTOMER BENEFITS... V. TIMELY APPROVAL OF THE PROJECT... VI. CONCLUSION...1 DIRECT TESTIMONY i PAUL CHODAK

3 I. INTRODUCTION Q. PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS. A. My name is Paul Chodak. I am Executive Vice President- Utilities for American Electric Power Company Inc. (AEP or Company). My business address is 1 Riverside Plaza, Columbus, Ohio 1. Q. WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL BACKGROUND? A. I received a Doctorate Degree in nuclear engineering from Massachusetts Institute of Technology in 1. I received a Master s Degree in civil engineering from Virginia Polytechnic Institute and State University, and a Bachelor of Science Degree in chemical engineering with honors from Worchester Polytechnic Institute. Prior to joining American Electric Power Service Corporation (AEPSC), I was a Staff Scientist at Los Alamos National Laboratory conducting research on technology and policy issues surrounding nuclear power and proliferation risks. I served more than seven years as a U.S. Naval officer and completed both chief engineer and submarine officer qualifications. I joined AEPSC in 001 as a Senior Project Manager. In 00, I was named Director - Regional Engineering for Regulated Generation, working with the team providing engineering support to many of AEP s plants. I was named Managing Director - Corporate Technology Development in 00, and was part of a team that evaluated existing pollution control technologies, and the application of those technologies in meeting new and evolving environmental compliance requirements. DIRECT TESTIMONY 1 PAUL CHODAK

4 In 00, I helped implement AEP s system-wide environmental compliance plan as Director - Environmental Programs. In early 00, I was named Director - New Generation, responsible for the installation of several natural gas simple- and combined-cycle plants. During my tenure as Director - New Generation, I directed the team that successfully commissioned the first two units at Southwestern Electric Power Company s (SWEPCO) Harry D. Mattison Plant. I was also responsible for SWEPCO s J. Lamar Stall (Stall) project. In July 00, I was named President and Chief Operating Officer of SWEPCO. I became President and Chief Operating Officer of Indiana Michigan Power, an operating company subsidiary of AEP, on July 1, 0. On January 1, 01 I was named to my current role as Executive Vice President Utilities for AEP. Q. WHAT ARE YOUR CURRENT RESPONSIBILITIES? A. As the Executive Vice President Utilities, I oversee the activities of all AEP utility operating companies. I am responsible for AEP s regulated utility operations, including SWEPCO and Public Service Company of Oklahoma (PSO) (together the Companies), as they focus on serving customers with reliable, affordable and cleaner energy solutions. Q. HAVE YOU APPEARED AS A WITNESS BEFORE ANY REGULATORY COMMISSIONS? A. Yes, I have testified or submitted testimony with regulatory commissions on behalf of various AEP operating companies in Texas, Louisiana, Arkansas, Indiana, Michigan, Virginia, and West Virginia. DIRECT TESTIMONY PAUL CHODAK

5 II. PURPOSE OF TESTIMONY Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? A. My testimony: 1) provides the background of the Wind Catcher Facility (Wind Facility), including the proposed Generation Tie (Gen-Tie) line (collectively referred to as the Wind Catcher Energy Connection Project or Project); ) explains the opportunity to save customers approximately $. billion in net present value dollars over the life of the Project; ) addresses the need for approval consistent with the requested regulatory time-line and treatment in all four jurisdictions; and ) explains how the Project customers requests for clean low-cost energy to its customers. Q. WHY ARE SWEPCO AND PSO PROPOSING THE WIND CATCHER ENERGY CONNECTION PROJECT AT THIS TIME? A. In late 01, AEP had discussions with Invenergy related to a potential large scale wind project in the Oklahoma Panhandle. These discussions ultimately led to the execution of a Joint Development Agreement related to the Project on November 0, 01. Initial siting feasibility analysis was completed in December of 01 and in January of 01 AEP engaged The Brattle Group to study the potential benefits of this Project. We recognized that delivering a large quantity of energy from the Oklahoma Panhandle over the existing transmission system was not possible, so we investigated the benefits of a dedicated generation tie-line that could deliver this low-cost power from the Oklahoma Panhandle directly to the AEP load zone. After evaluating the potential benefits of this Project, AEP undertook a significant modeling analysis to more precisely quantify the value of the Project to our customers over the life of the Project. Additionally, contracts were negotiated for the DIRECT TESTIMONY PAUL CHODAK

6 development of the Wind Facility and the construction of the Gen-Tie in order to include refined estimates of the project cost in the overall analysis of the project net benefits. Given the late contact with Invenergy, we rapidly evaluated and developed this Project so that customers could benefit from the full value of the Production Tax Credit (PTC). The manageable but tight construction schedule for the Project requires expedited consideration of this filing no later than April 0, 01 in order to preserve the maximum PTC savings for our customers. By harnessing this high-quality wind resource and leveraging the extension of the federal PTCs, the Companies have an opportunity to lock-in over eight million low-cost megawatt-hours (MWh) per year of energy for their customers over the -year Project life. The delivery of this low-cost energy into the Companies SPP zone also creates additional significant savings for SWEPCO customers, PSO customers and other SPP customers by lowering the zonal energy price. Q. HOW DOES THIS WIND RESOURCE COMPARE WITH TRADITIONAL GENERATION SOURCES? A. The power grid requires both energy and capacity resources to meet customers demand hours per day, days per year. Energy is generated to meet the moment to moment demand of customers while capacity provides the assurance that power will be available whenever customers need it. Traditional generation resources generate energy in balance with customer demand they are dispatchable. That is to say, with the exception of unforeseen outages, it is possible to assure they will be available to generate energy whenever customers need it. In short, traditional generation resources provide both capacity and energy. By contrast, wind is DIRECT TESTIMONY PAUL CHODAK

7 primarily an energy-only resource. We cannot control when the wind will blow so we cannot be assured wind energy can be generated whenever customers demand it. Wind generation does not share the same dispatchability as traditional generation resources. The Companies are bringing the Project forward for approval because the wind energy it provides will cost less than the market price of energy and will lower customers bills. The Project will lock in approximately. million low-cost MWh per year for years. It will lower our customers overall rates from day one while also hedging against increases in future fuel and power costs III. BACKGROUND OF THE WIND CATCHER ENERGY CONNECTION PROJECT Q. PLEASE PROVIDE A BRIEF SUMMARY OF THE WIND FACILITY. A. Located within a region with some of the best wind resources in North America, the Companies Wind Facility was first conceptualized as an opportunity to capitalize on the robust wind profiles in the Oklahoma Panhandle while also realizing the significant cost savings offered by the extended (and expiring) PTCs. However, a substantial generation tie line must also be constructed in order to consistently deliver the power from that remote location to our customers. Absent an approximately 0- to 0-mile long Gen-Tie line, our customers would not be able to maximize the value of this low-cost energy. Fortunately, the Companies are able to leverage AEP s unique kv transmission experience to cost effectively bring this energy to our customers. The Project is uniquely situated to unlock the full value of Oklahoma s wind by delivering this great resource directly to our load. With an increasing penetration DIRECT TESTIMONY PAUL CHODAK

8 of wind in the Southwest Power Pool (SPP) regional transmission organization footprint, and the expectation for additional congestion in the region, the Companies undertook a process to evaluate the possibility of directly connecting this wind resource to our load, thereby bypassing congestion on the grid. AEP s team of engineers and construction professionals, in coordination with the Quanta Services team, developed the Gen-Tie as a feasible and cost-effective delivery solution. The Companies have entered into a Membership Interests Purchase Agreement (MIPA) with Invenergy to construct and purchase the Wind Facility in the Oklahoma Panhandle, subject to regulatory approvals and other conditions. In connection with the Wind Facility, the Companies will develop an approximately 0- to 0-mile Gen-Tie line to avoid congestion and enable the delivery of the Wind Facility energy to our customer load zone in Tulsa. The Wind Facility and Gen-Tie are proposed to be owned 0 percent by SWEPCO and 0 percent by PSO. Q. PLEASE DESCRIBE THE WIND FACILITY. A. The Wind Facility would provide over eight million MWh to the AEP load zone annually and consists of approximately 00,000 acres in Texas and Cimarron Counties in the Oklahoma Panhandle under lease to Invenergy for wind energy development. Invenergy started construction in 01 and has targeted completion in the third quarter of 00, which will enable customers to benefit from 0% of the PTC value. The Wind Facility includes 00 General Electric. MW wind turbine generators. The facility will be built in Oklahoma and significant portions of the equipment will be manufactured in Arkansas, Texas and Louisiana. Company witness Michael L. Bright provides further details of the Wind Facility. DIRECT TESTIMONY PAUL CHODAK

9 Q. PLEASE DESCRIBE THE GEN-TIE. A. The approximately 0- to 0-mile Gen-Tie will traverse Oklahoma and will deliver the wind-generated power via a radial, single circuit kv generation tie line that provides an interconnection for the Wind Facility into the existing system at the PSO Tulsa North kv Substation via a proposed Tulsa North kv generation substation. The proposed substation will transform the power from kv to kv. Company witness Robert W. Bradish provides additional details regarding the proposed Gen-Tie. Q. HOW WAS THE OWNERSHIP SPLIT BETWEEN PSO AND SWEPCO FOR THE PROJECT DETERMINED? A. The ownership split between SWEPCO and PSO was generally determined based upon the relative planned future additions of wind generation from the Companies long-range plans. Additionally, the ownership split of 0% for SWEPCO and 0% for PSO results in both companies providing approximately -0% of their energy from renewable resources once the Project is included in each Company s resource mix IV. CUSTOMER BENEFITS Q. WHAT ARE THE EXPECTED CUSTOMER BENEFITS OVER THE LIFE OF THE PROJECT? A. The Project is expected to provide savings of approximately $. billion, net of cost and in net present value dollars, as compared to relying on market energy. The combination of the Panhandle wind plus the Gen-Tie provides customers with an DIRECT TESTIMONY PAUL CHODAK

10 additional approximately $1.1 billion in savings relative to other similar wind generation options. See Company witness Pearce Exhibits KDP-1 and KDP- for additional detail on the specific SWEPCO customer benefits. In 01, the project will deliver energy to our customers at an average cost of $0/MWh as compared to a market price of $/MWh. This will result in lower costs to customers from day 1. Furthermore, this will lower the AEP load zone Locational Marginal Price (LMP) which will benefit non-aep customers as well. The Project is able to produce power with an average price of approximately $/MWh in constant 01 dollars over a -year period. This represents the total cost of the Project (Wind Facility and Gen-Tie). Company Witness Pearce describes the levelized cost of the Wind Facilities in his testimony. Along with the rate treatment described by Company witness John O. Aaron, the Project will mitigate future fuel and energy cost escalation and provide more stable and predictable rates for our customers for years. Q. HOW WERE THESE PROJECTED BENEFITS DETERMINED? A. As further discussed in the testimonies of Company witnesses Karl R. Bletzacker, Kelly D. Pearce and Johannes P. Pfeifenberger, the Companies went through a robust modeling analysis, consistent with standard regulatory practices, to confirm that the Project would provide the above-stated customer benefits when compared to alternative market offers or a generic wind case. Q. WILL THERE BE NET SAVINGS TO CUSTOMERS OVER THE LIFE OF THE PROJECT? DIRECT TESTIMONY PAUL CHODAK

11 A. Yes. The Project is expected to result in a net bill reduction in the initial year that the facility provides service to our customers and the Project is expected to result in net savings of over $ billion (in nominal dollars) to both SWEPCO and PSO customers over the life of the Project. Q. ARE THERE OTHER WAYS THE PROJECT PROVIDES BENEFITS TO CUSTOMERS? A. Yes. We constantly focus on economic development in the states and communities we serve. One of the ways we assist in economic development is working to retain existing customers and attract new customers. We have heard from current and potential customers an increasing interest in low-cost energy to meet their sustainability goals. In fact, many local, regional, national, and international companies have sustainability goals of which renewable energy is a key component. For example, United Parcel Service recently announced its commitment to obtain % of its electricity from renewable resources by 0. Other customers that have indicated a similar desire for increased renewable energy content include: Wal-Mart, Tysons, and the University of Arkansas. While these companies likely achieve their overall sustainability goals in different ways, the Project, which significantly increases renewable energy and lowers customers overall cost, will certainly be viewed favorably by sustainability-driven companies, as well as those focused on securing more-economic power supplies. In order to make our service territories more attractive to new economic development, it is important that we increase the amount of energy that we produce from renewable resources while at the same time remain focused on the cost of DIRECT TESTIMONY PAUL CHODAK

12 providing service to our customers. The Wind Catcher Energy Connection Project provides a great opportunity to do just that. This Project presents a rare opportunity to invest in clean energy while lowering costs to our customers. It makes our communities more attractive to companies with sustainability goals like those described above as well as those looking for more-economic energy supplies V. TIMELY APPROVAL OF THE PROJECT Q. WHAT APPROVAL IS THE COMPANY SEEKING IN THIS FILING? A. As stated in the direct testimony of Company witness Venita McCellon-Allen, the Company is seeking CCN authorization for this facility and approval of cost recovery no later than April 0, 01. Specifically, the Company is seeking approval for the inclusion of the costs and benefits of the Project as an eligible fuel expense as an interim recovery mechanism until the Company is able to add the Project to base rates. Absent strong regulatory support, the large size and unique nature of this Project would represent significant financial risk to SWEPCO. The support of the Public Utility Commission of Texas is necessary to allow the Company to move forward with the project and bring to its customers the significant benefits of the Project. Q. ARE THERE ANY OTHER STATE REGULATORY APPROVALS THAT ARE REQUIRED FOR THE COMPANIES TO MOVE FORWARD WITH THIS PROJECT? A. Yes. In addition to this request, the Companies are also seeking similar regulatory approvals from the Arkansas Public Service Commission, the Louisiana Public DIRECT TESTIMONY PAUL CHODAK

13 Service Commission and the Oklahoma Corporation Commission. In order for the Companies to make this investment of approximately $. billion, it is necessary that support for the recovery of the costs associated with this Project is received from each of these other state regulatory commissions before the Companies can proceed with significant investments in the Project. Q. WHY IS THE TIMING OF THE APPROVAL OF THE PROJECT CRITICAL? A. In December 01, the federal PTC extension included a phase-out over a four-year period starting at the end of year 01. The customer benefits of this Project are significantly impacted by the value that the PTCs provide. In order to claim 0% of the PTC value, an eligible project must have commenced construction prior to January 1, 01, and show continuous progress toward completion and to enable commercial operation prior to January 1, 01. Invenergy has taken and is taking the necessary steps to secure the commencement and continuing progress of construction at the Wind Facility to receive the 0% PTC. In order to enable commercial operation of the Project prior to January 1, 01, significant investments in the Project will need to be incurred beginning in mid-01. The Companies are committed to preserve the eligibility of the Project for full PTC s through mid-01. However, the Companies cannot commit to the significant investments beyond that time unless the requested commission approvals, including assurance of cost recovery, are received consistent with the timeline proposed by the Companies in the various filings I have described. Without timely approval, the Companies will not be able to move forward with this Project. The Companies recognize that the requested timeline for approvals is tight and we want to partner with our state commissions to DIRECT TESTIMONY PAUL CHODAK

14 take advantage of this time-sensitive opportunity to bring these substantial savings to our customers. VI. CONCLUSION Q. PLEASE SUMMARIZE WHY THE COMMISSION SHOULD APPROVE SWEPCO S REQUEST. A. The Project will lower overall costs to customers, continue the Company s strategy of diversifying its generation mix, serve the renewable goals of the Company s customers and make our communities more attractive for economic development. Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes, it does. DIRECT TESTIMONY 1 PAUL CHODAK

15 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF VENITA McCELLON-ALLEN FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

16 TESTIMONY INDEX SECTION PAGE I. INTRODUCTION... 1 II. PURPOSE OF TESTIMONY... III. DESCRIPTION OF THE PROJECT... IV. CUSTOMER BENEFITS OF THE PROJECT... 1 V. CRITERIA FOR CCN APPROVAL... 1 VI. PUBLIC INTEREST STANDARD... 1 VII. PROPOSED RATE TREATMENT OF PROJECT COSTS AND BENEFITS... 1 VIII. REQUEST FOR EXPEDITIOUS DECISION... IX. CONCLUSION... DIRECT TESTIMONY i VENITA MCCELLON-ALLEN

17 I. INTRODUCTION Q. PLEASE STATE YOUR NAME, POSITION, AND BUSINESS ADDRESS. A. My name is Venita McCellon-Allen, and my position is President and Chief Operating Officer (COO) for Southwestern Electric Power Company (SWEPCO or Company). My business address is Travis Street, Shreveport, Louisiana. Q. WHAT ARE YOUR PRINCIPAL AREAS OF RESPONSIBILITY WITH SWEPCO? A. I am responsible for the safe delivery of reliable electric energy and quality service for SWEPCO customers. This includes oversight of the following SWEPCO functions in Texas, Arkansas and Louisiana: Distribution; Customer service; Regulatory and statutory compliance; Community and economic development; and SWEPCO financial performance and health. In addition, I provide strategic coordination of transmission and generation operations as these affect SWEPCO s financial health and day-to-day operations. In fulfilling these roles, I coordinate with American Electric Power Service Corporation (AEPSC) departments and leaders responsible for supporting SWEPCO. I represent SWEPCO as it interacts with other operating units within the American Electric Power Company, Inc. (AEP) system. Q. WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL BACKGROUND? DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

18 A. I received a bachelor s degree in journalism from Texas A&M University in 1. I also graduated from the University of Chicago Executive Development Program and the Young Manager s Program at the University of Virginia Darden School of Business. In 1, I joined SWEPCO, then a Central and South West Corporation (CSW) subsidiary. I held various operational and customer service roles, and in 1 I was named SWEPCO s Central Division Manager in Texarkana, Texas. In 1, I became Vice President Corporate Services for CSW and held various executive positions with CSW. In 1, I was named Senior Vice President for both Customer Relations and Corporate Development for CSW. In September 000, I joined Baylor Health Care System (BHCS) as Senior Vice President Human Resources. At that time, BHCS was an integrated health care delivery network with 1,000 employees and about $ billion in annual revenues. In 00, I returned to the electric utility industry and was named Senior Vice President Shared Services for AEP. In that position, I was responsible for information technology, telecommunications, human resources, procurement and supply chain services, and enterprise security. In September 00, I was named President and COO of SWEPCO. In 00, I was named Executive Vice President for AEP Utilities West, with oversight of SWEPCO, Public Service Company of Oklahoma (PSO) and what is now AEP Texas. In 00, I became Executive Vice President for AEP Utilities East, with responsibilities for AEP operating companies in Indiana, Kentucky, Michigan, Ohio, DIRECT TESTIMONY VENITA MCCELLON-ALLEN

19 Tennessee, Virginia and West Virginia. In 0, I returned to SWEPCO as President and COO, with the additional responsibility for leadership support for AEP Texas. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE ANY REGULATORY COMMISSION? A. Yes. I have testified before the Public Utility Commission of Texas (PUC or Commission) in Docket No., an application for authority to change rates, and in Docket No. 0, a request for authority to change rates and reconcile fuel costs. I also testified in Docket No. 1, a request to amend SWEPCO s Certificate of Convenience and Necessity (CCN) for the construction of the John W. Turk, Jr. Power Plant (Turk). In addition, I have testified before the Louisiana Public Service Commission (LPSC) in Docket No. U-0, which was consolidated into Docket No. U-, Sub-docket B in support of the CCNs required to construct the Stall Unit at Arsenal Hill and Turk, respectively. I have also testified before the Arkansas Public Service Commission (APSC) in Docket No. 0-1-U supporting a Certificate of Environmental Compatibility and Public Need (CECPN) for the Turk Plant. I testified in APSC Docket 1-00-U, a request for a declaratory order for the installation of environmental controls at SWEPCO s Flint Creek Plant. DIRECT TESTIMONY VENITA MCCELLON-ALLEN

20 II. PURPOSE OF TESTIMONY Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? A. My testimony supports the Company s application for CCN authorization and related relief for the Wind Catcher Energy Connection Project (Wind Catcher or Project). The Project is the combination of the Wind Catcher Facility (Wind Facility) and the associated Wind Catcher Generation Tie Line (Gen-Tie). The remaining sections of my testimony are as follows: Section III - Describes the Project and proposed transactions between SWEPCO, PSO, Invenergy and Quanta; Section IV - Discusses the benefits of Project to SWEPCO customers; Section V - Describes the basis for amendment of SWEPCO s CCN under PURA.0; Section VI - Shows that the Project is in the public interest under PURA 1.1, to the extent that provision applies; Section VII - Requests approval of SWEPCO s proposed finding that special circumstances exist, as contemplated under 1 TAC.(a)(), to allow this cost as an eligible fuel expense to the benefit of the Company s customers until such time as this Project is included in SWEPCO s base rates; and Section VIII - Explains the Company s request and need for expeditious Commission approval of its Application. Q. PLEASE SUMMARIZE THE BENEFITS OF THE PROJECT. A. The Project is situated to support SWEPCO s long-term commitment to affordable rates, fuel diversity and environmental responsibility. Specifically, the Project will: Create significant and immediate economic benefits with the delivery of clean, low-cost energy previously not available to SWEPCO customers, resulting in estimated customer savings (NPV, SWEPCO total company) of approximately $1. billion. Significantly mitigate the risks and costs associated with grid congestion and curtailment; and DIRECT TESTIMONY VENITA MCCELLON-ALLEN

21 Provide customer value through delivery of 0% of available Production Tax Credits (PTCs) associated with the Wind Facility. Q. HOW MUCH WILL THE PROJECT COST? A. The Project costs, including AFUDC, are set out in the following table: SWEPCO (billions) TOTAL (billions) WIND FACILITY $.01 $.0 GEN-TIE $1.1 $1. PROJECT (BOTH) $.1 $ SWEPCO s Texas retail jurisdiction share of the estimated total Project cost (including AFUDC) is $1.0 billion Q. PLEASE DISCUSS THE SPECIFIC RELIEF SWEPCO IS SEEKING IN ORDER TO ACHIEVE THE CUSTOMER SAVINGS ASSOCIATED WITH THE PROJECT. A. SWEPCO specifically requests that the Commission: Amend SWEPCO s CCN and authorize acquisition of the Wind Facility and construction of the associated Gen-Tie pursuant to PURA.0; Find that a good cause exception to 1 TAC. is warranted to allow SWEPCO to pass the project revenue requirement and PTCs to customers through fuel expense until the Project is included in SWEPCO s base rates; If the Commission determines PURA 1.1 is applicable, find that SWEPCO s purchase of the Wind Facility is in the public interest under that provision; Approve SWEPCO s request to include any PTCs deferred for ratemaking purposes in a regulatory liability that is included in rate base or earns interest at the Company s pre-tax Weighted Average Cost of Capital (WACC) from the commercial operation date of the Project and thereafter as discussed by SWEPCO witness John O. Aaron; DIRECT TESTIMONY VENITA MCCELLON-ALLEN

22 Approve SWEPCO s request to include any unrealized PTCs in a deferred tax asset included in rate base in the event the PTCs cannot be fully utilized in a given year(s) as discussed by SWEPCO witness Aaron; Approve the requested depreciation rates for the Wind Facility and associated Gen-Tie; and Issue a final order by April 0, 01 to enable the commercial operation of the Wind Facility and associated Gen-Tie prior to January 1, 01. Q. PLEASE IDENTIFY THE WITNESSES WHO WILL BE SPONSORING TESTIMONY. A. In addition to myself, the following witnesses support SWEPCO s request in this proceeding: 1 Witness Paul Chodak Michael L. Bright Jay F. Godfrey Robert W. Bradish Brian D. Weber Kelly D. Pearce Johannes P. Pfeifenberger Karl R. Bletzacker Renee V. Hawkins John O. Aaron Testimony Summary Overall Policy Wind Facility Membership Interests Purchase Agreement (MIPA) Gen-Tie Line Engineering, Procurement, and Construction Contract for the Gen-Tie Project Economics Modeling Fundamentals Forecast Financing Customer Impacts III. DESCRIPTION OF THE PROJECT Q. PLEASE DESCRIBE THE PROJECT. A. As noted above, the Project includes two components, the Wind Facility and the Gen-Tie, which will ensure maximum savings to customers by delivering the energy DIRECT TESTIMONY VENITA MCCELLON-ALLEN

23 produced by the Wind Facility directly to the AEP Load Zone, as discussed by Company witnesses Robert W. Bradish and Kelly D. Pearce. The Wind Facility will provide 1,00 megawatts (MW) of delivered wind energy (,000 MW nameplate) and consists of 00 GE. MW wind turbines located on more than 00,000 acres in Texas and Cimarron Counties in the Oklahoma Panhandle. The acreage is under lease or to be leased to Invenergy for wind energy development. The site is one of the best wind resources in North America, supporting an expected net capacity factor of up to 1%. SWEPCO s 0% ownership share equates to 1,0 MW delivered into the AEP Zone and, at the projected capacity factor of 1%, SWEPCO s share of the energy produced would be approximately.1 million MWh annually. Invenergy started construction in 01, has continuously maintained construction, and has targeted completion in the third quarter of 00, providing eligibility for 0% of the PTCs available for the facility, as discussed in more detail below. Q. PLEASE DESCRIBE THE TRANSACTION WITH INVENERGY TO ACQUIRE THE WIND FACILITY. A. On July, 01, SWEPCO, along with PSO (collectively, the Companies) entered into the MIPA with States Edge Wind Holdings I LLC to acquire, subject to regulatory approvals and other conditions, States Edge Wind I LLC, an Invenergy single-purpose subsidiary that will own all of the rights and assets associated with the Wind Facility. The MIPA is structured as a turn-key, fixed-price arrangement whereby Invenergy manages all phases of construction and delivers the Wind Facility at DIRECT TESTIMONY VENITA MCCELLON-ALLEN

24 completion to SWEPCO and PSO. Under this arrangement, Invenergy also pays all construction financing costs, which are included in the purchase price. As stated in the MIPA, the purchase price for the Wind Facility is $. billion or approximately $1,/kW. The total estimated cost of the Wind Facility including the MIPA purchase price plus other cost components described by SWEPCO witness Michael L. Bright is $.0 billion. SWEPCO s 0% share is approximately $.01 billion. The MIPA with Invenergy is described in more detail in the testimony of Company witness Jay F. Godfrey. Q. WHAT IS THE OTHER MAJOR COMPONENT OF THE PROJECT? A. In addition to the Wind Facility, the Gen-Tie is an essential part of the Project that ensures SWEPCO customers receive the maximum savings associated with the Wind Facility energy. The Gen-Tie is expected to be an Extra-High Voltage (EHV) -kv line running approximately 0 to 0 miles through Oklahoma from the Wind Facility to the AEP Load Zone in Tulsa. The Gen-Tie provides value to SWEPCO customers by: Ensuring dependable delivery of the low-cost energy; Reducing congestion costs and wind generation curtailment that otherwise would be imposed in the area; and Reducing the AEP Zone energy cost for SWEPCO s load. Q. WHY IS THE DIRECT GEN-TIE CRITICAL TO THE PROJECT? A. As discussed by Company witness Bradish, the dedicated Gen-Tie is needed to reduce congestion and curtailment, to ensure SWEPCO customers receive the maximum tax and energy benefits of the Wind Facility generation. As discussed by Company witness Brian D. Weber, the Company has entered into a fixed-price DIRECT TESTIMONY VENITA MCCELLON-ALLEN

25 contract with Quanta Services (Quanta), a Houston company, for engineering, procurement and construction services (EPC) for the Gen-Tie. The dedicated Gen-Tie, together with the power supply provided by the Wind Facility, will provide a long-term, low-cost energy supply for SWEPCO customers. The Gen-Tie enables SWEPCO to procure renewable wind energy from the Wind Facility at a cost significantly less than current wholesale energy prices, providing significant savings for customers over the life of the Wind Facility. The customer savings are more fully described in the testimony of Company witness Pearce. While some of the best wind resources are located in the Oklahoma Panhandle, Southwest Power Pool (SPP) lacks sufficient transmission resources to deliver that energy to the major load centers. The Gen-Tie will allow customers to fully realize the benefits of superior wind energy with significantly reduced congestion and curtailments relative to what otherwise would be experienced. Q. PLEASE DISCUSS THE QUANTA SERVICES CONTRACT. A. As discussed by SWEPCO witness Weber, on July, 01, the Companies entered into a fixed-price contract with Quanta to engineer, procure and construct the Gen- Tie. The EPC contract with Quanta will mitigate substantial project risks by including only limited contractual pricing reopeners. The contract contains a liquidated damages schedule, warranties, and letters of credit to protect SWEPCO s interest and is expected to result in a reasonable construction cost for the Gen-Tie. Quanta is a recognized industry leader in providing a full suite of transmission EPC services. Quanta specializes in EPC services for high-voltage transmission lines, has significant resources in the Project s region, long-standing relationships DIRECT TESTIMONY VENITA MCCELLON-ALLEN

26 with transmission materials and equipment suppliers, and has worked with AEPSC and its affiliates on major transmission projects throughout the country. Q. HOW WILL THE BENEFITS AND COSTS OF THE PROJECT BE DIVIDED BETWEEN SWEPCO AND PSO? A. Consistent with the ownership shares, SWEPCO and PSO will share both the benefits and costs of the Project at 0% and 0%, respectively. As discussed by Mr. Pearce, the Project is expected to produce approximately. million MWh and SWEPCO s ownership share would be approximately.1 million MWh. As previously discussed, SWEPCO s 0% share of capital costs for the Wind Facility and associated Gen-Tie (including AFUDC) will be roughly $.1 billion. SWEPCO s responsibility for all operation and maintenance costs will likewise be 0% and SWEPCO will share in all savings (fuel, off-system sales, etc.) at that level. Q. DID SWEPCO ISSUE A FORMAL REQUEST FOR PROPOSAL (RFP) RESULTING IN THE SELECTION OF THE PROJECT? A. No. As explained below, the Project originated when Invenergy approached SWEPCO s parent company, AEP, to discuss potential options to develop a wind resource at its States Edge site in Oklahoma. Because of the time-sensitive nature of the customer benefits and because of the public policy opportunities available, SWEPCO elected to advance this filing based on recent market experience within AEP. Q. WHAT RECENT EXPERIENCE DO YOU REFERENCE? A. On August, 01, SWEPCO issued an RFP to evaluate the purchase of wind assets in SPP. As a result of the RFP, SWEPCO received numerous bids. The number of DIRECT TESTIMONY VENITA MCCELLON-ALLEN

27 bidders, along with the indicative pricing of the bids, caused SWEPCO to reassess potential opportunities to significantly reduce the cost of serving customers through more wind development. Q. WAS SWEPCO S RFP THE ONLY RFP ISSUED BY AN AEP AFFILIATE DURING THIS TIMEFRAME? A. No. At roughly the same time PSO issued an RFP to purchase wind energy under a Purchased Power Agreement (PPA). Q. PLEASE FURTHER DESCRIBE THE RESULTS OF SWEPCO s AUGUST 01 RFP. A. The results of the RFP demonstrated how significantly the economics of SPP wind generation had shifted to create opportunities to decrease SWEPCO s average production cost. Q. TO WHAT DO YOU ATTRIBUTE THIS SHIFT IN THE MARKET? A. On December 1, 01, President Obama signed the Protecting Americans from Tax Hikes Act of 01 (Act). The Act extended the PTCs available for wind production through 00. However, the Act also included a step-down in the amount of credit available depending on the timing of construction and project in-service date. This step-down in the PTC, along with the pertinent dates, is referenced elsewhere in this testimony and further discussed by Company witness Paul Chodak. Q. HOW DID WIND DEVELOPERS RESPOND TO THE ACT? A. The step-down of the PTC created a hard deadline for wind project developers. The wind PTC, which was originally enacted by Congress in 1, had been renewed and expanded several times, which suggested there might be further renewals and DIRECT TESTIMONY VENITA MCCELLON-ALLEN

28 Q. A. Q. A. extensions. However, when the Act established the step-down schedule, developers were incentivized to take action. Developers started construction at sites prior to January 1, 01 to ensure their projects would be eligible for the full value of the PTC. Pricing became more competitive. Developers that had held leases for some future option began to aggressively market projects. HOW DID THE STEP-DOWN OF THE PTC AFFECT SWEPCO s PLANS? As noted above, Invenergy reached out to representatives at SWEPCO s parent company, AEP, to market the value of leases at its expansive States Edge site in Oklahoma. Exploratory discussions led to an understanding of the customer value to be gained by accelerating renewable purchases contemplated in SWEPCO s recent integrated resource plan (IRP) filings. Acceleration allows SWEPCO to secure the full value of the expiring PTCs for customers. The full PTC value for the total Project is estimated to provide $. billion of savings to SWEPCO and PSO customers. HOW DID THE PROJECT PROCEED? Because of the time sensitivity, SWEPCO and Invenergy worked diligently to negotiate a deal in a timeframe that would allow the Company to take full advantage of the expiring PTC. Invenergy performed Project construction to demonstrate its compliance with the January 1, 01 PTC deadline and filed an SPP generation interconnect request in late 01. Contract negotiations occurred concurrently with AEP s internal customer benefit modeling. It would not have been possible to add the incremental time necessary to conduct an RFP and still bring the full value of such a project to SWEPCO s customers. DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

29 To achieve a schedule that would allow it maximize the value of the PTCs for customers, SWEPCO filed for approval of a waiver from requirements under the LPSC s 00 Market Based Mechanism Order. This waiver was approved July, 01, allowing the Project to proceed to this filing. Q. HOW DID THE SWEPCO AND PSO RFP S AFFECT THE PROJECT? A. During review of the RFP responses, SWEPCO gained a view into the SPP wind market. We were able to use these market comparisons, gained through a formal RFP process, to assess the value of the Project IV. CUSTOMER BENEFITS OF THE PROJECT Q. WHAT BENEFITS DOES SWEPCO EXPECT THE PROJECT TO PROVIDE TO CUSTOMERS? A. While the capacity contribution from the Project is expected to be modest, the Project will provide a significant volume of low-cost energy. The addition of the Wind Facility to SWEPCO s generation portfolio will have a positive economic impact on customers energy costs. Advances in wind turbine manufacturing have reduced both installed and ongoing costs. This cost reduction, in conjunction with the federal PTC, has positioned wind resources to be an economical source of energy for customers. In addition, high-quality wind resources will allow it to generate at an expected 1% capacity factor, with no associated fuel costs. As shown in the following table and discussed by Company witnesses Pearce and Johannes P. Pfeifenberger in more detail, the Project produces a forecasted $1. DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

30 to $. billion of net present value savings for customers using the range of gas price assumptions supported by Company witness Karl R. Bletzacker. Table 1 Total SWEPCO Net Present Value of Project Benefits ($ millions) Costs and Benefits 01 0 NPV of Savings/Costs Compared to Base Case Generic Wind Avoided Cost Savings (Benefits) Revenue Requirement of Wind Facility and Gen-Tie net of PTCs Net Customer Savings (Benefits) ($,) ($,) $,0 $1, ($1,) ($) Q. PLEASE EXPLAIN THE BASIS FOR THESE BENEFITS CALCULATIONS. A. Table 1 contains comparisons between the Project and two alternatives. The scenario referred to as Base Case assumes that the Company does not benefit from any additional low-cost wind generation and alternatively purchases its energy supply from SPP Integrated Market resources. The second scenario referred to as Generic Wind assumes the purchase of 1,00 MW of wind generation resources without the advantages of mitigated congestion and curtailment risk provided by the Gen-Tie in the Project. Since building 1,00 MW of wind in a single location is not practical without the Gen-Tie due to transmission constraints, the Company looked to the SPP s interconnection queue for planned wind additions throughout the region and selected several delivery points in Oklahoma, Kansas, Texas, Nebraska and Missouri. The difference in the DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

31 economics between the Project and the Generic Wind option represents the value to customer of the dedicated Gen-Tie. Q. HOW WILL THE PROJECT ACHIEVE FULL REALIZATION OF THE PTC? A. The PTC is a tax credit against Federal Income Taxes based on every kilowatt-hour (kwh) of energy that is produced by a wind generator over the first years of operation. The credit is based on an annual inflation-adjusted value that is currently set at $0.0 (01) per kilowatt-hour. 1 This amount equates to $ per 1 megawatt-hour (MWh). The PTC was extended by the Protecting Americans from Tax Hikes Act of 01 for projects beginning construction before January 1, 01. For projects beginning construction in 01 and prior to 00, the PTC is stepped down as shown below in Table. Table Start of Construction PTC% Before 1/1/01 0% During 01 0% During 01 0% During 01 0% After 1/1/01 0% IRS Notices with respect to the PTC establish a requirement that construction of a significant nature must be continuous from the beginning of construction until the project is placed in service. Completion of construction is planned for 00, and in 1 IRS Notice 01- DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

32 order to meet that goal SWEPCO requests expeditious consideration of this filing by the Commission, as referenced above and discussed in more detail below. Q. HAS SWEPCO INDEPENDENTLY VERIFIED INVENERGY S ASSESSMENT OF THE WIND FACILITY? A. Yes. As discussed by Company witness Godfrey, on behalf of SWEPCO and PSO, AEPSC retained Simon Wind to review the Wind Facility and to independently review Invenergy s assessment of the wind resource and forecasted annual net generation V. CRITERIA FOR CCN APPROVAL Q. WHAT CCN AUTHORIZATION IS SWEPCO REQUESTING IN THIS CASE? A. Pursuant to PURA.0 and 1 TAC.1(b)(), SWEPCO is requesting CCN authorization to acquire a 0% interest in the Project, as described in my testimony above. SWEPCO is requesting CCN authorization from the Commission for the entire generation project, including the dedicated Gen-Tie. Q. WHAT CCN REGULATORY STANDARDS AND CRITERIA ARE ADDRESSED BY THE COMPANY S APPLICATION? A. An application for a generation CCN must comply with the requirements in PURA.0. That section states the Commission may approve an application if it finds the certificate to be necessary for the service, accommodation, convenience, or safety of the public. It requires the Commission consider the following criteria: adequacy of existing service; need for additional service; effect of granting the CCN on the recipient and any electric utility serving the proximate area; and other factors such as DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

33 community values, recreational and park areas, historical and aesthetic values, environmental integrity, the probable improvement of service or lowering of cost to consumers, and the effect of granting the CCN on the state s ability to meet the renewable generating capacity goal. Because the Project is located in Oklahoma, the site-specific factors identified above are not relevant to the Commission s decision regarding the Company s request. In a previous CCN proceeding, the Commission found that a generation facility located outside of Texas would have no effect on site-specific factors such as community values, recreational and park areas, historical and aesthetic values, environmental integrity, and the impact on other utilities serving Texas. Q. IS THE PROJECT NECESSARY FOR THE SERVICE, ACCOMMODATION, CONVENIENCE, OR SAFETY OF THE PUBLIC IN TEXAS? A. Yes. Granting a CCN for the Project would serve the public convenience and necessity by enhancing the Company s ability to provide low-cost energy to its customers. The Project would produce energy at lower than avoided cost as demonstrated by Company witnesses Pearce and Pfeifenberger. The addition of this Project to SWEPCO s generation supply, considering the expected reduction in energy costs and the PTC, would save SWEPCO customers an estimated $1. billion and would reduce customer rates by an estimated % in the first year of commercial operation, as explained by Company witness Aaron. This low-cost energy and the associated customer benefits justify the addition of this resource to SWEPCO s Application of Southwestern Electric Power Company for Certificate of Convenience and Necessity Authorization for a Coal-Fired Power Plant in Arkansas, Docket No. 1, Order at Findings of Fact Nos.,,, 0, and 1 (Aug. 1, 00). DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

34 generation supply portfolio. Furthermore, as a renewable resource, wind generation incurs no fuel costs, produces no emissions, and enables the Company to provide its customers with additional options to satisfy their long-term renewable energy goals. Q. IS THE PROJECT PREMISED ON THE INADEQUACY OF EXISTING SERVICE OR THE NEED FOR ADDITIONAL SERVICE? A. No. As described below, SWEPCO does not view this resource as fulfilling a need for additional generating capacity, although it does defer the in-service date of future capacity additions during the planning period. The Company s existing level of capacity remains adequate at this time to serve its customers. However, the additional service provided by the Project is necessary to reduce costs to customers, as I have discussed. Q. WOULD GRANTING THE CCN AFFECT THE ABILITY OF THE STATE TO MEET THE RENEWABLE ENERGY GOAL SET OUT IN PURA? A. No. It is my understanding that the State has exceeded the renewable energy goal set out in PURA.0(a). Q. WOULD THE GRANTING OF THIS CCN BY THE COMMISSION HAVE A NEGATIVE EFFECT ON SWEPCO? A. No. From an operational perspective, this Project would enhance the Company s ability to provide low-cost energy to its customers, as described above and explained in more detail by Company witnesses Pearce and Pfeifenberger. Furthermore, the Company has a plan in place to ensure reliable ongoing operation and maintenance of the facility at a reasonable cost, as described by Company witness Bright. Although the Project would be a significant investment for SWEPCO, the proposed rate DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

35 treatment discussed later in my testimony will mitigate any negative impact on the Company s financial standing from those investments. In addition, as detailed by Company witness Renee V. Hawkins, SWEPCO s parent company, AEP, will provide necessary equity to SWEPCO to maintain its capital structure and support its current Moody s Baa credit rating. Thus, the effect of granting the CCN would be positive for the Company and for its customers VI. PUBLIC INTEREST STANDARD Q. IS A PUBLIC INTEREST FINDING REQUIRED UNDER PURA 1.1 FOR SWEPCO S PROPOSED ACQUISITION OF THE PROJECT? A. The Company s position is that such a finding is not required. Section 1.1 requires Commission review of any transaction in which a utility intends to sell, acquire, or lease a plant as an operating unit or system in this state for a total consideration of more than $ million. The Project will be located in Oklahoma, so it is does not appear to be an operating unit or system in this state. However, in an abundance of caution, SWEPCO requests a public interest finding under PURA 1.1 if such a finding is required. Q. IS THE PROPOSED ACQUISITION CONSISTENT WITH PURA SECTION 1.1? A. Yes. Under 1.1, the Commission considers: (1) the reasonable value of the property, facilities, or securities to be acquired, disposed of, merged, transferred, or consolidated; () whether the transaction will: DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

36 (a) adversely affect the health or safety of customers or employees; (b) result in the transfer of jobs of citizens of the state to workers domiciled outside this state; or (c) result in the decline of service; () whether the public utility will receive consideration equal to the reasonable value of the assets when it sells, leases, or transfers the assets; and () whether the transaction is in the public interest. Q. WHY IS SWEPCO S ACQUISITION OF AN INTEREST IN THE PROJECT IN THE PUBLIC INTEREST? A. As discussed above, the proposed acquisition will produce significant and immediate cost savings for SWEPCO customers by locking in a long-term, low-cost power supply with direct delivery to the AEP Zone in SPP. As a result, it is in the public interest. Q. WILL THE PROPOSED ACQUISITION ADVERSELY AFFECT THE HEALTH OR SAFETY OF CUSTOMERS OR EMPLOYEES, RESULT IN THE TRANSFER OF JOBS FROM TEXAS, OR RESULT IN A DECLINE IN SERVICE? A. No. The acquisition will have no effect on the health or safety of customers or employees and will not result in the transfer of jobs from Texas. With regard to its effect on service, the addition of this resource is expected to result in lower overall costs for customers. Q. IS SWEPCO PAYING A REASONABLE VALUE FOR THE PROJECT? A. Yes. The Companies have diligently negotiated with Invenergy and Quanta to arrive at terms for the MIPA and Gen-Tie EPC contract, respectively, that provide reasonable pricing, performance assurance, and risk mitigation to protect SWEPCO customers. The pricing achieved through such negotiations represents the vast DIRECT TESTIMONY 0 VENITA MCCELLON-ALLEN

37 1 majority of the costs considered in the economic evaluation of the Project. As discussed by Company witness Pearce, that economic evaluation indicates the Project is expected to provide SWEPCO s customers savings over its -year life of approximately $1. billion (NPV). Moreover, to ensure the economics of the Project are robust, the Company modeled the impacts on the Project of both low and high natural gas price forecasts. As Mr. Pearce explains, under the low natural gas price scenario, the Project provides net benefits to SWEPCO s customers of $1. billion (NPV) in 00 dollars over the -year life. Under the high gas price scenario, the Project provides net benefits to SWEPCO customers of approximately $. billion (NPV). Accordingly, at the prices achieved through arms-length negotiations with two sophisticated industry-leading third parties, the Project remains highly economic across a wide range of natural gas prices VII. PROPOSED RATE TREATMENT OF PROJECT COSTS AND BENEFITS Q. PLEASE DISCUSS SWEPCO S REQUEST FOR A FINDING THAT SPECIAL CIRCUMSTANCES EXIST TO ALLOW SWEPCO TO TREAT THE PROJECT REVENUE REQUIREMENT AND PTC S AS ELIGIBLE FUEL EXPENSE UNTIL SUCH TIME AS THIS PROJECT IS INCLUDED IN SWEPCO S BASE RATES. A. Given the substantial investment required and because the benefit of this Project is a direct reduction to customers energy costs realized on a timely basis through SWEPCO s fuel factor, SWEPCO proposes to treat the revenue requirement associated with the return of and on the investment, the asset s operation and maintenance expenses, and all related taxes as eligible fuel expense, and to credit DIRECT TESTIMONY 1 VENITA MCCELLON-ALLEN

38 federal PTC revenues against fuel expense until such time as this Project is included in SWEPCO s base rates. The Project, which is expected to produce more than eight million MWh annually, would immediately displace higher-cost energy to serve SWEPCO s customers. These benefits and the ongoing depreciation of the asset should be promptly passed through to customers through the Company s fuel clause. When a utility adds a generating facility, it is typically because the utility is experiencing strong load growth and needs the additional capacity provided by the new generating facility. Under such circumstances, the utility may be able to depend on revenues from that load growth to help mitigate the lost revenues between the date of commercial operation and inclusion in rate base. This case is different, in that the Project is being built to provide economic benefits to customers, not to serve growing load. It is in the public interest to provide customers timely access to these savings. Moreover, the revenue requirement from the addition of the Project to the Company s rate base will be more than offset by the Project s energy savings (through the displacement of higher cost energy) and value associated with the federal PTC. The expected result of these offsetting factors is a net reduction to the Company s cost of service such that a typical 1,000 kwh/month Texas customer would see a net decrease of approximately 1% to their bill in the first year of operations. For all of these reasons, special circumstances exist, as contemplated under 1 TAC.(a)(), to allow this cost as an eligible fuel expense to the benefit of the Company s customers until such time as this Project is included in SWEPCO s base rates. DIRECT TESTIMONY VENITA MCCELLON-ALLEN

39 Q. WHAT FACTOR IDENTIFIED IN THE COMMISSION S FUEL RULE SPECIAL CIRCUMSTANCES PROVISION IS PARTICULARLY APPLICABLE TO THIS CASE? A. The rule identified above states that an electric utility may recover as eligible fuel expense an expense otherwise excluded by the rule if the otherwise ineligible fuel expense is reasonably expected to result in lower fuel expenses than would otherwise be the case, and that such benefits expected to be received by ratepayers exceed the costs that ratepayers otherwise would reasonably expect to pay. As discussed in this and SWEPCO s other testimonies, this is the case for the Project for which SWEPCO seeks certification. Q. IS THERE ANOTHER REASON FOR GRANTING THE PROPOSED RATE TREATMENT? A. Yes. SWEPCO is incurring this cost with the express intent of producing immediate energy and fuel cost savings for its customers. At around the same time as the Company s request in this proceeding is being decided, the Commission will be 1 concluding a comprehensive review of SWEPCO s cost of service. Inclusion of this low-cost energy producing asset as an eligible fuel expense would make cost recovery consistent with the manner and timing in which customers receive the benefits of the Project. Because SWEPCO s customers would receive the benefit of these savings as they occur, it is reasonable that they would bear the costs of producing them at the same time. Application of Southwestern Electric Power Company for Authority to Change Rates, Docket No.. DIRECT TESTIMONY VENITA MCCELLON-ALLEN

40 Q. CAN THE COMMISSION INCENTIVIZE UTILIZATION OF RENEWABLES BY APPROVAL OF THIS COST RECOVERY PROPOSAL? A. Yes. PURA.0 authorizes the Commission to incentivize a utility s use of renewable resources in establishing the utility s rates. Q. PLEASE DISCUSS SWEPCO S REQUEST REGARDING TREATMENT OF PRODUCTION TAX CREDITS. A. As discussed by Company witnesses Aaron and Pearce, SWEPCO proposes to use the federal PTCs received by virtue of the Wind Facility as an additional benefit to offset the Project s revenue requirement. Because of the revenue requirement increase expected in year when the PTC expires, SWEPCO proposes to defer a portion of the PTCs earned as a regulatory liability to offset the revenue requirement in years through 1 (01-0). This deferral mechanism and subsequent revenue requirement reduction would reduce the impact to the customer when compared to the traditional treatment of reflecting the tax credits when earned. Q. PLEASE DISCUSS THE REQUESTED DEPRECIATION RATES FOR THE WIND FACILITY AND ASSOCIATED GEN-TIE. A. As discussed by Company witnesses Bright, Bradish, and Aaron, SWEPCO requests depreciation rates for the Wind Facility reflecting a life of years, and 0 years for the Gen-Tie. SWEPCO does not currently have a wind farm and therefore does not have an applicable rate to apply. As for the Gen-Tie, Mr. Bradish s testimony sets forth the reasons why 0 years accurately reflects the expected life of the asset. DIRECT TESTIMONY VENITA MCCELLON-ALLEN

41 Q. IN ADDITION TO THE ECONOMIC ENERGY IT WOULD PRODUCE THROUGHOUT ITS LIFE, WHAT OTHER BENEFIT WOULD BE DERIVED FROM THIS ASSET? A. This wind generating station would produce one Renewable Energy Credit (REC) for each MWh of energy it generates. The RECs would be the property of the Company. If the Commission were to grant SWEPCO timely cost recovery of its investment in the Project as an element of fuel expense, as proposed above, SWEPCO intends to propose the creation of a new tariff schedule through which customers could purchase the RECs created by this asset. This would have the dual benefit of giving SWEPCO s customers a choice by which to meet their own renewable energy goals, and producing revenue that would further reduce costs for all customers VIII. REQUEST FOR EXPEDITIOUS DECISION Q. WHY DOES SWEPCO REQUEST AN EXPEDITIOUS DECISION IN THIS PROCEEDING? A. In order to ensure that the Project receives the full benefit of federal PTCs by meeting the IRS safe harbor provision related to continuous construction, it is necessary to move forward to meet the completion deadline discussed earlier in my testimony. The IRS requirements for PTC eligibility are discussed further by SWEPCO witness Godfrey. As a result, SWEPCO requests that the Commission decide this case by the end of April 01, nine months after it is filed. DIRECT TESTIMONY VENITA MCCELLON-ALLEN

42 IX. CONCLUSION Q. PLEASE SUMMARIZE WHY THE COMMISSION SHOULD APPROVE SWEPCO S ACQUISITION OF AN INTEREST IN THE PROJECT AND PROPOSED RATE TREATMENTS. A. From the outset of commercial operation, the Project will immediately lower the overall cost to serve customers, lower customers bills in the first year of commercial operation, continue SWEPCO s strategy of diversifying its generation mix, and serve the renewable goals of the Company s customers. For the reasons explained above, the Company s application satisfies the requirements of PURA 1.1 and.0. Because the Project will require a substantial investment, directly reduce customers energy costs, and result in a net decrease to customers bills in the first year of commercial operation, good cause exists for an exception under 1 TAC.(a)() to recognize the revenue requirement for the Project as an element of eligible fuel expense to the benefit of the Company s customers until such time as this Project is included in SWEPCO s base rates. Q. DOES THIS COMPLETE YOUR TESTIMONY? A. Yes. Thank you. DIRECT TESTIMONY VENITA MCCELLON-ALLEN

43 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF ROBERT W. BRADISH FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

44 TESTIMONY INDEX SECTION PAGE I. INTRODUCTION...1 II. OVERVIEW OF THE PROPOSED GEN-TIE FACILITIES... III. GEN-TIE CONSIDERATIONS... IV. GEN-TIE DEPRECIABLE LIFE...1 V. OVERVIEW OF SPP GENERATOR INTERCONNECTION REQUEST...0 VI. CONCLUSION... EXHIBITS EXHIBIT EXHIBIT RWB-1 DESCRIPTION Overview map of the Wind Catcher Energy Connection Project DIRECT TESTIMONY i ROBERT W. BRADISH

45 I. INTRODUCTION Q. PLEASE STATE YOUR NAME, BUSINESS AFFILIATION AND ADDRESS. A. My name is Robert W. Bradish. I am employed by American Electric Power Service Corporation (AEPSC), one of several subsidiaries of American Electric Power Company, Inc. (AEP). I am currently Vice President - Grid Development for AEPSC. My business address is 00 Smiths Mill Road, New Albany, Ohio 0. Q. PLEASE PROVIDE AN OVERVIEW OF YOUR EDUCATIONAL BACKGROUND, PROFESSIONAL QUALIFICATIONS AND BUSINESS EXPERIENCE. A. I received a Bachelor of Science Electrical Engineering degree in May 1, and a Master of Science Electrical Engineering degree in December 1, both from Clarkson University. I also received a Master of Business Administration degree from The Ohio State University in May 001. I was employed by AEPSC in 1 as an assistant engineer and progressed through several engineering grades to the senior engineer level. In 001, I was promoted to Manager Power and Transmission Market Analysis. In 00, I became Director of the same group. In 00, I was promoted to Vice President Transmission and Market Analysis. From 00 to 0, I was Vice President Market Operations in AEPSC s Commercial Operations group. In May 0, I assumed the position of Managing Director, Transmission Planning and Business Development, where I was responsible for transmission planning and the origination, evaluation, and execution of strategic transmission investment opportunities in support of AEP s transmission business strategy. In January 01, I assumed my current position. I am also president of Pioneer CAUSE NO. PUD 00XXX DIRECT TESTIMONY 1 ROBERT W. BRADISH

46 Transmission, LLC, a joint venture transmission company formed by AEP and Duke Energy. Q. WHAT ARE YOUR PRIMARY AREAS OF RESPONSIBILITY? A. As Vice President - Grid Development, I am responsible for AEP transmission system planning, which includes organizing and managing all activities related to assessing the adequacy of AEP's transmission network to meet the needs of its customers in a reliable, cost-effective and environmentally-compatible manner. I oversee the real-time operation of AEP s transmission assets in compliance with all applicable safety and reliability standards, contractual and tariff obligations and all federal, state and local regulations and laws. Finally, I am responsible for the advanced technical/analytical studies in support of planning, engineering, design and operation of the AEP transmission system, and for managing/coordinating the Transmission Technology/Research and Development Program. In this filing, I present the interests of Southwestern Electric Power Company (SWEPCO or Company) and Public Service Company of Oklahoma (PSO) (together, the Companies), in regard to the Companies proposal to build certain generation tie-line facilities in the state of Oklahoma. Q. HAVE YOU PREVIOUSLY TESTIFIED IN ANY REGULATORY PROCEEDINGS? A. Yes, I have testified before the Arkansas, Oklahoma, Indiana, Kentucky, Michigan, Ohio and Virginia state regulatory commissions. DIRECT TESTIMONY ROBERT W. BRADISH

47 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? A. The purpose of my testimony is to support the Company s application with respect to the Wind Catcher Generation Tie (Gen-Tie) line, which in conjunction with the Wind Catcher Facility (Wind Facility) forms the Wind Catcher Energy Connection Project (Project). The Companies propose to construct, own and operate an approximately 0- to 0-mile kv Gen-Tie line to interconnect the Wind Facility to the AEP SPP load zone in Tulsa. Specifically, the Gen-Tie line will interconnect the Wind Facility, via two proposed generation substations, to PSO s existing Tulsa North kv Substation located in Tulsa County, Oklahoma. For the purposes of my testimony, I will refer to the approximately 0- to 0-mile kv generation-tie line, the proposed Western kv Generation Substation, and the proposed Tulsa North kv Generation Substation, as the Gen-Tie. In my testimony I will: Provide an overview of the Gen-Tie; Describe the benefits of dedicated deliverability that are provided by the Gen-Tie and the selection process for the chosen design, including alternatives considered; Explain why a kv line is the best option based upon the required performance characteristics, including power transfer capability and overall cost-effectiveness, to interconnect the output of the Wind Facility; Address the useful design life of the Gen-Tie and the expectation for utilization of the Gen-Tie in the future; and Finally, I describe the Southwest Power Pool (SPP), the Regional Transmission Organization (RTO), requirements for Generation Interconnection Requests as outlined in the SPP Open Access Transmission Tariff, including the potential impacts of these wind generation facilities on the existing transmission system. DIRECT TESTIMONY ROBERT W. BRADISH

48 Q. WILL YOU BE SPONSORING ANY EXHIBITS? A. Yes. I will sponsor EXHIBIT RWB-1 - An overview map of the Wind Catcher Energy Connection Project II. OVERVIEW OF THE PROPOSED GEN-TIE FACILITIES Q. PLEASE PROVIDE AN OVERVIEW OF THE GEN-TIE. A. As depicted in EXHIBIT RWB-1, the Gen-Tie will interconnect wind-generated power via a radial, single-circuit kv generation tie line from the Wind Facility into the existing transmission system at the existing PSO Tulsa North kv Substation. The Gen-Tie consists of the proposed kv to kv generation substation, referred herein as the Western kv Generation Substation, the proposed 0- to 0-mile kv line, and the proposed kv to kv substation, referred herein as the Tulsa North kv Generation Substation. The Gen-Tie has a projected completion date in 00. The Gen-Tie will be constructed via a fixed-price Engineer, Procure, Construct (EPC) contractual arrangement with a subsidiary of Quanta Services, which is further described in the direct testimony of Company witness Brian D. Weber. The Western kv Generation Substation, located near the Wind Facility at the western endpoint of the Gen-Tie line, will serve as the aggregation point for the collector substations from the Wind Facility. The kv Gen-Tie line interconnects at the Western kv Generation Substation and traverses approximately 0 to 0 miles across Oklahoma to interconnect at the proposed Tulsa North kv Generation Substation at the eastern endpoint of the Gen-Tie line, located near PSO s DIRECT TESTIMONY ROBERT W. BRADISH

49 existing Tulsa North kv Substation. The proposed Tulsa North kv Generation Substation will transform the wind power from kv to kv for interconnection to the existing PSO Tulsa North kv Substation. Q. WHY WAS THE TULSA NORTH SUBSTATION CHOSEN AS THE INTERCONNECTION POINT? A. The Tulsa North Substation allows delivery into the AEP load zone in a cost-effective fashion, which is expected to require relatively few network upgrades for an interconnection of this size. This interconnection point provides the most benefits to customers, net of costs, as compared to alternative interconnection points in the AEP zone. Q. COULD THE WIND FACILITY HAVE BEEN DIRECTLY INTERCONNECTED TO THE SPP SYSTEM IN THE OKLAHOMA PANHANDLE? A. No, the Wind Farm could not have been interconnected directly to the SPP system in the Oklahoma Panhandle without a significant investment in upgrades or additions to the local transmission infrastructure. In addition, significant grid congestion would be expected with a direct interconnection even with these investments. Q. IS THIS CONSISTENT IN OTHER AREAS OF HIGH-VALUE WIND IN THE SPP? A. Yes, the transmission system in the high-value wind areas of the SPP is typically located in areas where the local transmission system would need significant upgrades to allow for large additional interconnections as well as transmission to export out of the local area. DIRECT TESTIMONY ROBERT W. BRADISH

50 Q. HOW WILL THE GEN-TIE BENEFIT THE COMPANIES CUSTOMERS? A. The Gen-Tie enables the Companies to procure higher capacity factor renewable wind energy from the Wind Facility at a cost significantly less than wholesale energy prices, providing significant savings for their respective customers over the life of the Project. The customer savings afforded by the Project are more fully described in the testimony of Company witness Kelly D. Pearce. The Oklahoma Panhandle has some of the best wind resources in the country, but lacks sufficient transmission facilities to deliver that wind energy to major load centers. The Gen-Tie will allow the Companies respective customers in the AEP load zone to fully realize the benefits of those wind energy resources delivered directly to the Tulsa area without incurring curtailments. Q. WHAT IS GRID CONGESTION AND WHERE DOES IT EXIST IN SPP? A. Generation resources are dispatched in the market based on their economic merit subject to transmission constraints. When the grid experiences transmission congestion, more expensive generation is dispatched in lieu of the most economical resources, which are curtailed to prevent overloading the transmission grid. Accordingly, congestion results in additional cost to the Companies customers and also drives the locational marginal prices (LMPs) of energy in the marketplace. SPP published a study in December 01 that identified Frequently Constrained Areas (FCAs). These are areas in the SPP marketplace that experience 1 frequent transmission congestion. From June 01 through May 01, the Woodward, Oklahoma area and the Texas Panhandle were the most constrained DIRECT TESTIMONY ROBERT W. BRADISH

51 areas. I discuss historic congestion and LMPs across SPP in more detail later in my testimony. The congestion-related and various other costs and benefits associated with the project are more fully described in the testimony of Company witness Johannes P. Pfeifenberger and quantified in the testimony of Company witness Pearce III. GEN-TIE CONSIDERATIONS Q. WHAT ARE THE PROPOSED GEN-TIE FACILITIES TO BE JOINTLY OWNED BY THE COMPANIES? A. As mentioned above, three primary facilities will be constructed to efficiently interconnect the Wind Facility power. The Gen-Tie facilities are comprised of: (1) a / kv Western kv Generation Substation, () an approximately 0- to 0-mile, single-circuit kv lines, and () a / kv Tulsa North kv Generation Substation. Additionally, two fiber optic repeater stations, spaced approximately miles apart, will be necessary to assure consistent communications for the safe operation of the facilities. The Western kv Generation Substation will be constructed as a / kv station with three single-phase / kv, 0MVA autotransformers with a single-phase switchable spare, three sets of kv 00 MVAR shunt reactor banks with two single-phase switchable shunt reactor spares, a four-rung kv breaker and a half station layout with six line positions and one future line position, and three sets of 0 MVAR capacitor banks on each of the two main buses. DIRECT TESTIMONY ROBERT W. BRADISH

52 The kv Gen-Tie consists of approximately 0 to 0 miles of kv, single-circuit, three-phase lattice tower structures on 00-foot wide rights-of-way. Each phase will consist of six conductors arranged in a hexagon design, which helps to reduce corona and audible noise. Dual fiber optic shield wires are utilized to provide redundant, end-to-end communications for the protection and control equipment, in addition to lightning protection. All installed equipment will meet current AEP transmission design standards. The Tulsa North kv Generation Substation will be constructed as a / kv station with three single-phase / kv 0MVA autotransformers with a single-phase switchable spare, and three sets of kv 00 MVAR shunt reactor banks with one single-phase switchable shunt reactor spare. This substation will include the installation of six kv 0 MVAR capacitor banks. Q. WHY WAS KV SELECTED FOR THE GEN-TIE LINE FACILITIES? A. The kv Gen-Tie line was selected for the Project because it was the least expensive and most efficient solution to interconnect and transfer the wind energy from the proposed Western kv Generation Substation to the proposed Tulsa North kv Generation Substation, on a dollar per delivered MW basis. It also has expansion capability for future generation and future connection into the SPP kv system, which I discuss later in my testimony. The kv technology selected for application in this Project represents the highest voltage class in commercial operation in North America and provides the greatest transmission capacity and operating flexibility, with minimal losses in the delivery of energy. DIRECT TESTIMONY ROBERT W. BRADISH

53 Q. DID THE COMPANIES CONSIDER ANY ALTERNATIVE VOLTAGES TO KV FOR THE GEN-TIE FACILITIES? A. Yes. The Companies considered constructing the proposed Gen-Tie using AEP s BOLD TM double-circuit kv line design, given this technology s ability to transfer significant amounts of power over long distances. In fact, the Companies requested their selected contractor, Quanta Services, to provide firm construction bids for both the BOLD TM double-circuit kv line design and the kv line design to make an appropriate cost comparison. The capital cost comparison for these options is discussed in greater detail in the testimony of Company witness Weber. A significant cost driver for the BOLD TM kv double-circuit solution is the requirement for the installation of dynamic reactive devices (Static VAR Compensators and Synchronous Condensers) at new incremental substations, which would be located approximately one-third of the length of the line, as measured from each endpoint. The addition of the dynamic reactive devices to the BOLD TM kv project scope would add an additional $00 million of project cost over the bid price received from Quanta Services. Furthermore, the dynamic reactive devices require high annual maintenance cost and total replacement every 1 to 0 years for these devices, further adding to the BOLD TM option s lifecycle cost in this particular application. The kv solution allows these dynamic devices to be excluded from the project scope. Using kv instead of BOLD TM kv also eliminates the need to curtail the output of the Wind Facility when a dynamic reactive device is taken out-of-service for its annual maintenance or an equipment failure. DIRECT TESTIMONY ROBERT W. BRADISH

54 Q. DID THE COMPANIES CONSIDER THE USE OF A DIRECT CURRENT (DC) GEN-TIE LINE? A. Yes. The Companies also evaluated a DC generation-tie line for the Project. However, this alternative was ultimately rejected due to the higher projected cost, reduced operational performance and more limited flexibility when compared to the kv line or the AEP BOLD TM kv double-circuit line alternatives discussed above. From a cost perspective, a major component of a DC line is in the required converter stations located at each end of the DC line, which require both significant upfront capital expenditures and costly ongoing operations and maintenance expenditures. DC lines are typically found to be economical solutions over very long distances. Examples include the Pacific DC Intertie from California to Washington (approximately 0 miles), the Intermountain DC tie from Utah to California (approximately 0 miles), and the two North Dakota to Minnesota DC lines (approximately 0 miles each). The proposed Gen-Tie line at 0 to 0 miles is well within the power transfer capability of AC lines. Q. PLEASE DESCRIBE THE INHERENT ADVANTAGES OF A KV GEN-TIE LINE. A. AEP optimized the selected Gen-Tie design to most cost-effectively interconnect the Wind Facility s low-cost wind energy from the proposed Western kv Generation Substation to the existing Tulsa North kv Substation. The kv design is the best option for several reasons. First, the higher operating voltage and resulting increased thermal capacity of kv offer an added advantage of markedly improved efficiency relative to kv. DIRECT TESTIMONY ROBERT W. BRADISH

55 The kv line incurs only about one-quarter of the power losses of the AEP BOLD TM kv double-circuit alternative, both carrying the same amount of power. For this Project, the overall energy loss for the kv line is approximately 0 MW versus approximately 1 MW of losses for the AEP BOLD TM kv double-circuit line. To illustrate this point, consider the additional wind turbines that would be needed to deliver the incremental 1 MW of wind energy (1 MW less 0 MW), in order to compensate for the additional energy losses on the BOLD TM kv line alternative. At an installed cost of $1, per kw for the Wind Facility, as supported by Company witness Jay F. Godfrey, 1 MW of additional wind turbines would cost an additional $1 million. Given the capital cost differences described above (and also discussed in Company witness Weber s testimony) and the impact of additional energy losses for the equivalent energy delivery, the cost of the kv line was estimated to be approximately 1 percent less expensive than the AEP BOLD TM double-circuit kv line. Second, a single kv generation tie-line can carry substantially more power than a similarly situated kv line. To assess the load-carrying ability, or loadability, of a high-voltage line, engineers commonly use the concept of Surge Impedance Loading (SIL). SIL, a loading level at which the line attains reactive power self-sufficiency, is a convenient yardstick for measuring relative loadabilities of long lines operating at different nominal voltages. A single kv, six-conductor bundled line has an approximate SIL = MW for a line of the Gen-Tie s length. In comparison, it would require six, single-circuit traditional kv lines built with DIRECT TESTIMONY ROBERT W. BRADISH

56 bundled conductors (SIL = 0 MW for each kv line), or three double-circuit traditional kv lines, to achieve the same loadability. Using the AEP BOLD TM kv technology (SIL = MW), it will take four single-circuits or two, doublecircuits to achieve the same loadability. kv also efficiently uses rights-of-way requiring less land to deliver the equivalent amount of power compared to traditional kv options. When comparing the impacts of kv and kv constructions, the former clearly has numerous advantages. The rights-of-way requirements for kv construction (00 feet for six single-circuits or 0 feet for three double-circuits) are much higher than for a single kv circuit (00 feet) to move the equivalent amount of power (see Diagram 1 below). With fewer lines and less rights-of-way necessary, the reduced impact of kv line on the landscape is significant. Moreover, a typical double-circuit kv structure is actually taller (about feet) than a kv tower (about feet). Diagram 1 Relative ROW Requirements of kv and kv 1 DIRECT TESTIMONY 1 ROBERT W. BRADISH

57 Q. HOW WILL THE DESIGN OF THE KV GEN-TIE LINE AND THE PROPOSED SUBSTATIONS IMPACT ITS RELIABILITY? A. The kv Gen-Tie line design presents advantages regarding the probability of occurrence of phase-to-phase faults or phase-to-phase faults that evolve into three-phase faults. This, in part, is due to the physical separation among phases. The probability of a phase-to-phase fault is rather small for kv. Momentary and Sustained Outage Attributes for the AEP kv events classified by fault type over a -year period are shown in Table 1 below, which indicates there were no momentary phase-to-phase faults or three-phase faults incurred during the period. There were four sustained phase-to-phase type faults with two being the result of tornados destroying structures. Table 1: Momentary and Sustained Outage Attributes for AEP kv events classified by fault type yr total Momentary Total No Fault 1 0 P-G P-P-G 0 P-P-P-G 0 Unknown 1 1 Sustained Total No Fault 1 1 P-G P-P 1 1 P-P-G 1 1 P-P-P-G 1 1 Grand Total 0 The P-P-P-G sustained faults were the result of tornados P = Phase; G = Ground Since the remaining momentary faults were single line-to-ground faults, the Gen-Tie is being designed with single-phase switching so that only one phase will be DIRECT TESTIMONY 1 ROBERT W. BRADISH

58 opened to clear a single line-to-ground fault while the other two phases remain closed, allowing for the power transfer to continue during the disturbance on the faulted phase. AEP has successfully used single-phase switching for two shorter kv lines in its eastern footprint for the past years, and it will be implemented for the Gen-Tie based on the results of a detailed study. Additionally, providing further assurance of availability, the Gen-Tie project scope includes a spare switchable 0 MVA / kv single-phase autotransformer and single-phase switchable spare kv 0 MVAR shunt reactor for each of the Western kv Generation and Tulsa North generation substations. Q. PLEASE DESCRIBE THE MAINTENANCE REQUIREMENTS FOR THE KV GEN-TIE FACILITIES. A. The Gen-Tie facilities will be maintained in accordance with AEP s standards for kv transmission lines. Maintenance activities for the Gen-Tie facilities include bi-annual air patrols, comprehensive inspection of the steel structures every 1 years, forestry clearing and spraying every four years, as well as certain preventative maintenance costs for the proposed Western kv Generation Substation and the Tulsa North kv Generation Substation. Estimates for all operating and maintenance activities were included in the cost modeling, as described by Company witness Pearce. DIRECT TESTIMONY 1 ROBERT W. BRADISH

59 IV. GEN-TIE DEPRECIABLE LIFE Q. WHAT IS THE USEFUL DESIGN LIFE AND APPROPRIATE DEPRECIABLE LIFE OF THE GEN-TIE? A. The useful design life of the Gen-Tie is approximately 0 years or more. As more thoroughly discussed later in my testimony, the Gen-Tie is expected to be an extremely useful asset well beyond the -year expected life of the Wind Facility. As such, the Companies propose a depreciable life of 0 years for the Gen-Tie. Q. BASED ON YOUR EXPERIENCE WITH THE AEP TRANSMISSION NETWORK IN GENERAL AND THE KV NETWORK SPECIFICALLY, HOW MIGHT THE GEN-TIE BE UTILIZED IN THE FUTURE AFTER THE INITIAL USEFUL LIFE OF THE WIND FACILITY EXPIRES? A. Based on my experience, it is my expectation that the Gen-Tie will remain a tremendously useful asset after the original -year life of the Wind Facility has initially expired. Even absent any renewal and re-powering of the Wind Facility, one potential and obvious use of the Gen-Tie would be to interconnect other existing, re-powered or new wind facilities located in this wind-resource rich region of SPP. This point is more thoroughly discussed in my testimony below. Alternatively, network integration of the Gen-Tie into the then-existing SPP system would be a second potential avenue for future use. Either of these potential options would require a non-discriminatory review of the cost recovery according to the SPP Tariff and it is expected any future revenue derived from such usage would benefit the Companies customers. DIRECT TESTIMONY 1 ROBERT W. BRADISH

60 The SPP system is experiencing a dynamic business environment as it expands its footprint and wind generation resources located in the SPP footprint are developed and other generation resources are retired. The U.S. Department of Energy estimates that wind penetration will continue to grow in the United States from five percent of electricity demand today to percent by 00. With a continuing desire for renewable resources by major corporations and the continued improvement in the cost competitiveness of wind and solar resources, these changes will drive a significant transformation in the resource mix within SPP. Fortunately, for load serving entities in SPP, some of the best wind resources in the country are located within the SPP footprint. However, these wind resources are primarily located in the western area of SPP while many of the major load centers are located in the eastern area of SPP. Figure below, extracted from the 01 SPP State of the Market Report, highlights the locations of high potential for wind development in the SPP footprint. The SPP footprint, outlined in black, includes the addition of the Integrated System in October 01. DIRECT TESTIMONY 1 ROBERT W. BRADISH

61 Figure Annual Average Wind Speed in US SPP, in its Definitive Interconnection System Impact Study Report dated February, 01, proposed a mile long kv line from TUCO Substation to the Seminole Substation in order to meet future potential wind integration needs. The primary driver for that proposed line is the expected demand for additional wind generation and the need to move the wind resource from west to east across the SPP footprint. While the need for the TUCO to Seminole line is beyond the current ten-year planning horizon, it clearly shows the value of strengthening the west to east capability of the SPP transmission grid. The Gen-Tie line will act as a catalyst to the DIRECT TESTIMONY 1 ROBERT W. BRADISH

62 creation of a kv wind superhighway system in Oklahoma much like the evolution of the kv network in the eastern part of AEP s transmission system. Q. WILL ADDITIONAL TRANSMISSION CONSTRUCTION IN THE SPP REDUCE THE PROSPECTIVE USEFULNESS OF THE GEN-TIE? A. No. In fact, as stated above, the Gen-Tie could serve as a platform for the complementary construction of EHV transmission in SPP, such as kv, that would further integrate the SPP marketplace. Q. IN ADDITION TO POTENTIAL NETWORK INTEGRATION, WHAT OTHER POSSIBLE USES ARE THERE FOR THE GEN-TIE FACILITIES? A. The proposed Gen-Tie line will traverse through areas where renewable energy is currently being interconnected and is constrained. To illustrate the impact of these constraints, Figure below, extracted from the 01 SPP State of the Market Report, depicts the average Marginal Congestion Component (MCC) of Locational Marginal Prices (LMPs) by settlement location for the Day-Ahead Market in SPP. The lowest MCCs occur in the Oklahoma and Texas Panhandles, at -$/MWh, and the highest MCCs lie in the Woodward, Oklahoma area at $1/MWh. The Woodward area congestion indicated by the red highlight in Oklahoma in Figure -- creates a west / east split in LMPs. The proposed Gen-Tie line would enable the movement of low cost wind energy from western Oklahoma in its panhandle through the Woodward constraint, and deliver such energy at a low LMP to the eastern load centers in the SPP. DIRECT TESTIMONY 1 ROBERT W. BRADISH

63 Figure 01 SPP Average Marginal Congestion In addition, it has been AEP s experience that Independent Power Producers (IPPs) manage their positions in the generation interconnection queues in a way that minimizes their exposure to potential transmission costs, so that their project has a competitive advantage over other projects. The optimization of the queue position requires the IPP to understand both the timing and location for their project. As new transmission capacity is announced, IPP developers will place their projects into the queue in an attempt to capture as much of the incremental capacity as possible, thereby reducing the overall project cost by minimizing the transmission cost. The DIRECT TESTIMONY 1 ROBERT W. BRADISH

64 retirement of the original Wind Facility at the end of its expected -year life would clearly signal the availability of new transmission capacity. As such, there will be opportunities for the Companies, or other utilities, to access new renewable resources in a highly-efficient manner over the remaining life of the Gen-Tie, with appropriate consideration of cost recovery for performance of such services. Given the potential that the Gen-Tie may eventually become part of the interconnected network in SPP, which would thereby require an appropriate examination of cost allocation at that time to the further benefit of the Companies customers, the correct approach to depreciation is to utilize the same depreciation schedules that are more reflective of this type of asset used elsewhere on the system. For the Gen-Tie, the proposed depreciable life is 0 years V. OVERVIEW OF SPP GENERATOR INTERCONNECTION REQUEST Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY? A. In this section of my testimony, I explain SPP s requirements for generation interconnection. Q. DOES SPP NEED TO APPROVE THE GEN-TIE LINE? A. No. The SPP Tariff only governs the studies used to determine the impact of adding a generation facility to the proposed point of interconnection so that the transmission system improvements (System Upgrades) required for and to accommodate the interconnection can be identified. DIRECT TESTIMONY 0 ROBERT W. BRADISH

65 Q. PLEASE EXPLAIN THE SPP GENERATION INTERCONNECTION PROCESS. A. SPP Tariff Attachment V contains Generation Interconnection Procedures (GIP) all large generation projects must utilize to interconnect to the SPP regional transmission system. The process begins when a generation developer (Generator) submits an Interconnection Request (Request) to SPP after which the Generator is expected to enter into an agreement under which SPP will complete a Definitive Interconnection System Impact Study (Impact Study). SPP collects generation interconnection requests over a 0-day time window and studies them together in the Impact Study. This is referred to as a cluster study. At the close of the window, SPP begins the first iteration of the Impact Study. SPP will then issue an initial Impact Study report that identifies the impact of the various proposed Requests on the SPP Transmission System. The Impact Study report includes an estimate of the cost of the System Upgrades. Each Generator has the option to continue in the study or drop out if the upgrade cost is too high. If any Requests are withdrawn, SPP must conduct another iteration of the Impact Study. This iterative process continues until all Generators remaining in the Impact Study accept the study results and no further Requests are withdrawn. I also should note that the Impact Study results can also include impacts on neighboring transmission owners due to one or more Requests. These would typically show up as a shared responsibility for upgrades assigned to the Generator(s). Upon completion of the Impact Study, SPP will complete an Interconnection Facilities Study (Facility Study) for each Request. The Facility Study specifies and estimates the cost of the facilities required to connect the generating facility to the DIRECT TESTIMONY 1 ROBERT W. BRADISH

66 host transmission owner s transmission system along with the cost of any upgrades on neighboring transmission owners. After receiving the Facility Study, the Generator commences negotiating a Generator Interconnection Agreement (GIA) with SPP and the host transmission owner. If upgrades are required on the transmission system of others, the Generator must also enter into an agreement with each affected transmission owner. Upon execution of any of those applicable agreements and the GIA, SPP files the agreements with FERC and the host and any impacted transmission owners commence their respective obligations under the terms of the agreements to effect the connection and energization of the generation facility. Q. WHAT STAGE IS THE WIND FACILITY IN THE GENERATOR INTERCONNECTION PROCESS? A. The request for the Wind Facility had been submitted to SPP by Invenergy. The cluster window has since closed and SPP is beginning the Impact Study process. The final Impact Study results should be available within 1 to 1 months. The Facility Study results should be ready about six months after the Impact Study is completed. Q. IN ADVANCE OF THE SPP FACILITY STUDY RESULTS, HAVE THE COMPANIES ANALYZED THE POTENTIAL TRANSMISSION SYSTEM IMPACTS AND ESTIMATED ANY NECESSARY TRANSMISSION UPGRADES TO INTERCONNECT THE WIND FACILITY? A. Yes. Given that the Wind Facility, via the Gen-Tie, will directly connect to the PSO transmission system at PSO s existing Tulsa North kv Substation, the Companies are well-positioned to analyze the impact to PSO s transmission system and the DIRECT TESTIMONY ROBERT W. BRADISH

67 surrounding transmission systems in the Tulsa area and estimate the cost for required upgrades. In total, the Companies project the need for network upgrades of approximately $0 million. These network upgrade costs are included in the total project cost estimate for the Project. Ultimately, the results of SPP s Facility Study will determine the final scope of any necessary upgrades to the PSO and any neighboring utility transmission systems in Tulsa or neighboring regions VI. CONCLUSION Q. PLEASE SUMMARIZE YOUR RECOMMENDATION AS DESCRIBED IN YOUR DIRECT TESTIMONY. A. In summary, I recommend the Commission approve the Company s application regarding the proposed Gen-Tie, which is necessary to interconnect the Wind Facility with the grid at PSO s Tulsa North kv Substation. The Gen-Tie, as proposed in my testimony, was evaluated against other options and has proved to be the most economic means for interconnecting the Wind Facility. Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes, it does. DIRECT TESTIMONY ROBERT W. BRADISH

68 EXHIBIT RWB-1 Page 1 of 1 WIND CATCHER ENERGY CONNECTION PROJECT PROJECT MAP KANSAS MISSOURI Route to be determined for dedicated line CIMARRON COUNTY TEXAS COUNTY to connect the two future substations. The line route is currently under development and study segments will be presented for public input in the fall of 01. CLARENDON OKLAHOMA TULSA FAYETTEVILLE LAWTON ARKANSAS LEGEND Wind Catcher Facility Future Substation TEXAS PSO Service Territory LONGVIEW SHREVEPORT SWEPCO Service Territory LOUISIANA Wind Catcher kv Line N

69 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF BRIAN D. WEBER FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

70 TESTIMONY INDEX SECTION PAGE I. INTRODUCTION... 1 II. OVERVIEW OF THE GEN-TIE SCOPE OF WORK AND COST ESTIMATE... III. GEN-TIE FIXED-PRICE EPC CONTRACT... IV. LAND, PERMITTING, AND ROW ACQUISITION... 1 V. CONCLUSION... 1 EXHIBITS EXHIBIT EXHIBIT BDW-1 DESCRIPTION Summary of the contract between Quanta Electric Power Construction, LLC and AEPSC, on behalf of SWEPCO and PSO EXHIBIT BDW- CONFIDENTIAL HIGHLY SENSITIVE AND VOLUMINOUS EPC between Quanta Electric Power Construction, LLC and AEPSC, on behalf of SWEPCO and PSO DIRECT TESTIMONY i BRIAN D. WEBER

71 I. INTRODUCTION Q. PLEASE STATE YOUR NAME, BUSINESS AFFILIATION AND ADDRESS. A. My name is Brian D. Weber. I am employed by American Electric Power Service Corporation (AEPSC), one of several subsidiaries of American Electric Power Company, Inc. (AEP). I am currently Managing Director, Transmission Business Development for AEPSC. My business address is 1 Riverside Plaza, Columbus, Ohio 1. Q. PLEASE PROVIDE AN OVERVIEW OF YOUR EDUCATIONAL BACKGROUND, PROFESSIONAL QUALIFICATIONS AND BUSINESS EXPERIENCE. A. I graduated from Iowa State University in Ames, Iowa in 000, where I received a Bachelor s of Science Degree in Civil Engineering, and from the University of Iowa in Iowa City, Iowa in 00, where I received a Master s Degree in Business Administration. I also hold a certification as a licensed Professional Engineer in the State of Iowa. From 000 to 00, I was employed by MidAmerican Energy Company (MEC) in Des Moines, Iowa in progressive roles in engineering and project management culminating in a position as Senior Engineer. In 00, I was promoted to Investment Portfolio Manager, Delivery Services where I was responsible for capital budget allocation for MEC s Delivery Services business unit. In 00, I transferred to PacifiCorp, an affiliate of MEC, and assumed the role of Manager, Transmission Strategy and Policy where I was responsible for transmission DIRECT TESTIMONY 1 BRIAN D. WEBER

72 ratemaking, policy, business strategy, and economic planning. In 00, I was promoted to Berkshire Hathaway Energy Company with roles of progressive responsibility culminating in my final position as Vice President, Commercial and Regulatory for BHE U.S. Transmission (a subsidiary of Berkshire Hathaway Energy Company) with responsibility for business management of transmission joint ventures, policy, finance, regulation and business development. In September 01, I assumed my current position as Managing Director, Transmission Business Development for AEPSC. In October 01, I also assumed the role of President, BOLD TM Transmission, LLC, a wholly-owned subsidiary of AEP. In addition, I have previously held officer positions in multiple joint ventures, including as Vice President of Electric Transmission America, LLC a joint venture between subsidiaries of AEP Transmission Holding Company, LLC and BHE U.S. Transmission, and have served on various transmission project company boards. Q. WHAT ARE YOUR PRIMARY AREAS OF RESPONSIBILITY? A. As Managing Director, Transmission Business Development, I am responsible for development of transmission projects under the competitive framework established under the Federal Energy Regulatory Commission s (FERC) Order No. 00 both inside and outside the service territories of AEP s affiliated regulated utilities. I am also responsible for leading the development of transmission project opportunities outside AEP s affiliated utilities service territories or not directly driven by an existing transmission tariff obligation. I also have overall responsibility for BOLD TM Transmission, LLC, a company that has developed patented technology for high voltage compact line designs. In this filing, I present the interests of Southwestern DIRECT TESTIMONY BRIAN D. WEBER

73 Electric Power Company (SWEPCO or Company) and Public Service Company of Oklahoma (PSO) (together, the Companies), in regard to the Companies proposal to build certain generation tie-line facilities in the state of Oklahoma. Q. HAVE YOU PREVIOUSLY TESTIFIED IN ANY REGULATORY PROCEEDINGS? A. Yes. I have testified before the Iowa Utilities Board in Docket Nos. E-1, E-1, E-1, E-1 and E-1. I have also testified before the FERC in Docket No. ER1-. Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? A. The purpose of my testimony is to support the Company s application with respect to the Wind Catcher Generation Tie (Gen-Tie) line, which in conjunction with the Wind Catcher Facility (Wind Facility), forms the Wind Catcher Energy Connection Project (Project). The Companies propose to construct, own and operate an approximately 0- to 0-mile kv Gen-Tie line to interconnect the Wind Facility energy to the AEP load zone in Tulsa. Specifically, the Gen-Tie line will interconnect the Wind Facility, via two proposed substations, to PSO s existing Tulsa North kv Substation located in Tulsa County, Oklahoma. For the purposes of my testimony, I will refer to the approximately 0- to 0-mile kv generation-tie line, the proposed Western kv Generation Substation, and the proposed Tulsa North kv Generation Substation, as the Gen-Tie. In my testimony, I will: Provide an overview of the components of the Gen-Tie and an overview of the construction activities, costs and schedule for the Gen-Tie; Describe the qualifications and capabilities of the selected contractor, Quanta Electric Power Construction, LLC, a wholly-owned subsidiary of Quanta DIRECT TESTIMONY BRIAN D. WEBER

74 1 1 Services, Inc. (Quanta or the Contractor), to engineer, procure and construct (EPC) the Gen-Tie under a fixed price contract (the EPC Contract); Provide a description of the EPC Contract s scope of work, construction schedule, performance measurements, costs, and other important terms and conditions included in the construction contract; and Finally, provide an overview of the siting, routing, permitting and other activities for the Gen-Tie. Q. WILL YOU BE SPONSORING ANY EXHIBITS? A. Yes. I am sponsoring two Exhibits: EXHIBIT BDW-1 is a summary of the EPC Contract s key terms. EXHIBIT BDW- is the Confidential Highly Sensitive EPC between Quanta Electric Power Construction, LLC and AEPSC, on behalf of SWEPCO and PSO II. OVERVIEW OF THE GEN-TIE SCOPE OF WORK AND COST ESTIMATE Q. WHAT IS THE SCOPE OF WORK FOR THE GEN-TIE? A. At a high-level, the Gen-Tie scope of work consists of two proposed / kv substations, two fiber-optic repeater sites, and approximately 0 to 0 miles of single-circuit kv generation tie-line. The westernmost substation, referred herein as the Western kv Generation Substation, will be located in the Oklahoma Panhandle at the Wind Facility site. The Western kv Generation Substation will be designed to accommodate six kv line positions and a single kv line position. The Western kv Generation Substation will require a phased construction approach to allow for the kv portion of the substation to operate independently of the kv portion of the substation by October 1, 01. The planned phased construction will allow commissioning for the Wind Facility to begin in advance of the Gen-Tie s DIRECT TESTIMONY BRIAN D. WEBER

75 completion. The Contractor s responsibility for physical construction will cease at the kv take-off structures facing the Wind Facility. The wind farm constructor, Invenergy Wind Development North America, LLC, will be responsible for the design, procurement and installation of the Wind Facility s kv collector system. The easternmost substation, referred to herein as the Tulsa North kv Generation Substation, is anticipated to be near or adjacent to the existing PSO Tulsa North facilities in Tulsa County, Oklahoma. The Tulsa North kv Generation Substation will be designed to step down the voltage of the incoming kv generation tie-line to kv for interconnection with the existing PSO Tulsa North facilities. The Contractor s responsibility for physical construction will cease at the Tulsa North kv Generation Substation s kv take-off structure facing the existing PSO Tulsa North kv Substation. Q. WHAT IS THE TOTAL CAPITAL COST ESTIMATE FOR THE GEN-TIE SCOPE OF WORK DESCRIBED ABOVE? A. The total estimated capital cost for the Gen-Tie, is $1. billion inclusive of $1 million for Allowance for Funds Used during Construction (AFUDC) III. GEN-TIE FIXED-PRICE EPC CONTRACT Q. DESCRIBE THE CAPABILITIES OF QUANTA. A. Quanta is a leading transmission construction contractor specializing in designing, building and maintaining transmission systems of all lengths and configurations across the voltage spectrum. With over,000 workers, Quanta is the largest specialty contractor in North America. Quanta has a family of construction DIRECT TESTIMONY BRIAN D. WEBER

76 subsidiaries that it calls upon to deliver end-to-end infrastructure solutions on a self-perform basis, more than half of them serving the electric industry. With over $. billion in revenues (01), a senior secured revolving credit facility of $1.1 billion and aggregate bonding capacity greater than $.0 billion, Quanta is a substantial, publicly-traded (NYSE: PWR, S&P 00 Index) entity with the financial wherewithal to take on a project of the scale of Gen-Tie. As it relates to the Gen-Tie scope of work, Quanta has decades of experience to draw upon in completing the Gen-Tie, as well as experience specifically tailored to the Gen-Tie. Quanta has completed more than,000 miles of extra high voltage transmission over the last 0 years, and designed and built over 00 substations in the last two decades. Specifically for AEP, Quanta has built over 00 transmission and substation projects since the s. During that time, Quanta has completed a variety of landmark projects for AEP, including the Wyoming-Jacksons Ferry kv project and the Lower Rio Grande Valley energized kv reconductor project. Lastly, Quanta is fully informed of AEP s EPC design standards for transmission and substations, and has long-standing relationships with AEP s preferred suppliers. Q. WHAT OTHER ITEMS DIFFERENTIATE QUANTA? A. Quanta has extensive working knowledge of AEP s systems and protocols and has industry-leading experience with grid requirements at voltage levels up to the kv threshold required for this Project. Further, in the onset of AEP s analysis, and as further described in the testimony of Company witness Robert W. Bradish, kv BOLD TM was a potential alternative technology to the kv technology with the potential to interconnect the Wind Facility output to the Tulsa North facilities. Quanta DIRECT TESTIMONY BRIAN D. WEBER

77 is the only contractor with experience with both BOLD TM construction using lattice kv towers and kv construction, and thus provided a strong foundation for assisting AEP with development of best practices for both options. In order to ensure competitive and accurate pricing for kv and kv BOLD TM alternatives, Quanta was asked to provide firm pricing for both kv and kv configurations. Q. EXPLAIN THE NATURE OF THE EPC CONTRACT AND DESCRIBE THE ACTIVITIES THAT ARE INCLUDED. A. The EPC Contract is a fixed-price contract where all engineering, procurement and construction is covered under the scope with one counter-party, which for the scope of work necessary to construct the Gen-Tie, is Quanta. A summary of the key terms of the EPC Contract is included as EXHIBIT BDW-1 to my testimony. Additionally, EXHIBIT BDW- is the Confidential Highly Sensitive and Voluminous EPC contract between Quanta Electric Power Construction, LLC and AEPSC, on behalf of SWEPCO and PSO. The Contractor, with minimal exceptions, is responsible for line routing, siting, permitting, easement acquisition, surveying, engineering design, procurement, construction, testing, and commissioning to established AEP standards and project-specific design criteria for the entire Gen-Tie scope described previously. Contract completion is ensured utilizing backstop letters of credit with accredited financial institutions, a parental guaranty from Quanta Services, and liquidated damages for delays in reaching the guaranteed completion date. Q. WHAT WAS THE FIRM PRICE FOR KV PROVIDED BY QUANTA, AND HOW DOES IT COMPARE TO QUANTA S BOLD TM KV PRICING? DIRECT TESTIMONY BRIAN D. WEBER

78 A. For the scope of the kv work, Quanta has agreed to payment terms totaling $1.1 billion, inclusive of taxes, insurance, and required credit support (the Contract Price). In comparison, the kv BOLD TM option that was evaluated by the Companies and further discussed in the testimony of Company witness Bradish, was priced by Quanta at $1.00 billion (not inclusive of taxes, insurance, required credit support or the additional scope needed such as dynamic reactive devices which are typically installed directly by the manufacturer). The dynamic reactive devices required for the kv BOLD TM option were estimated to cost an approximately $00 million, based upon budgetary quotes from suppliers. In total, the kv BOLD TM estimated capital costs were greater than the kv alternative for the specific application of the Gen-Tie. This capital cost differential, coupled with the additional electrical losses further described in the testimony of Company witness Bradish, made kv the lowest-cost option. Q. PLEASE EXPLAIN WHY THE EPC CONTRACT IS FAVORABLE TO CUSTOMERS. A. Constructing a 0- to 0-mile kv line in less than two years with a guaranteed completion date backed by meaningful financial assurances is a significant undertaking. Quanta has the most kv experience in the country and has the unique ability to draw on multiple subsidiary companies to provide the necessary labor to construct the Gen-Tie by the guaranteed completion date in 00. Also, as previously discussed in my testimony, Quanta has the requisite financial standing to undertake the Gen-Tie project and the ability to provide sufficient financial assurances to the Companies, as evidenced by the letter of credit and parental DIRECT TESTIMONY BRIAN D. WEBER

79 guaranty provided for in the EPC Contract. Additionally, the cost estimate for the Gen-Tie is comparable to other kv projects, which did not have accelerated schedule requirements or the comprehensive wrap that the EPC Contract provides. In comparison to recent large-scale projects that were competitively bid through the more traditional procurement process, the EPC Contract provides for more certainty and lower costs. Q. WHY WAS THE EPC APPROACH USED FOR THE GEN-TIE? A. The EPC approach provides significant value to customers because it allows the Contractor to efficiently manage design, construction and procurement activities together. This approach reduces inefficiencies and the potential for disputes arising from delays or impacts from interrelated work streams, which may result in future cost increases. Examples of these interrelated work streams include items such as material deliveries and access to rights-of-way (ROW). This approach also reduces the potential that future warranty claims would be clouded by questions regarding installation practices or treatment of the materials during the construction phase because all warranties are provided by the same entity providing construction services. Q. WHAT RESPONSIBILITIES ARE NOT COVERED UNDER THE SCOPE OF THE EPC CONTRACT? A. Beyond the typical design reviews and construction monitoring completed for EPC contracts, AEPSC on behalf of the Companies has retained the obligation to approve the final route, make final payments to landowners for property rights, prosecute any eminent domain proceedings (to the extent necessary), obtain final permits pertaining DIRECT TESTIMONY BRIAN D. WEBER

80 to specific protected species, make any payments to agencies or third parties required by permits, make payments for mitigation of hazardous or cultural conditions discovered or induced voltage mitigation (if any), telecommunications support, and to provide AEP s proprietary kv lattice tower family design for use on the Gen-Tie. Q. PLEASE DESCRIBE ANY EXPECTED GEN-TIE COSTS THAT ARE NOT INCLUDED IN THE FIXED-PRICE CONTRACT WITH QUANTA. A. Additional estimated costs include obtaining land rights, including the costs of any necessary eminent domain proceedings, of $0 million, internal labor and overheads associated with project oversight at $ million, an allowance for potential variable costs for known and unknown risks of $ million, and AFUDC of $1 million. These items, when added to the Quanta EPC Contract price, result in the total project cost of $1. billion referenced earlier in my testimony. Q. HOW DOES THE COMPANY PLAN TO MONITOR PROGRESS AND QUALITY MATTERS DURING CONSTRUCTION? A. AEPSC will have a dedicated team of professionals assigned to the Gen-Tie to provide oversight of the work. The project team will be comprised of specialists in project management, project controls, scheduling, construction management, engineering (transmission and substation line design, civil, protection & control, and telecommunication), ROW, siting, project outreach, and environmental and permitting. Progress and quality will be verified through design reviews for contract compliance, scope conformance, and design integrity. On-site field observations control quality utilizing construction hold points, regular inspections, environmental compliance, safety observations, and commissioning plan approval processes. DIRECT TESTIMONY BRIAN D. WEBER

81 Additionally, there are multiple reporting requirements and invoice verification procedures in place to monitor project progress and conformance to schedule and cost controls. These requirements include but are not limited to, scheduled periodic reviews of work plans, contractor and owner deliverables, schedule performance reporting, schedule status reviews ROW progress reporting, material expediting reporting, cost summary and variance reporting, risk register tracking, and cost forecasting. Q. WHAT WORK IS CURRENTLY UNDERWAY UNDER THE EPC CONTRACT? A. In order to ensure a final completion date before December 1, 00, which aligns with the Internal Revenue Service safe harbor date for the wind production tax credit, the Contractor is operating under eight limited notices to proceed (LNTPs). An LNTP is a contractually-defined term in the EPC Contract. An LNTP requires the Contractor, upon notice from the Companies, to proceed with a specified scope of work on a pre-determined date, but does not authorize full release of the work under the EPC Contract. The first eight LNTPs under the Contract cover work through August, 01. The scope of work under these LNTPs includes certain routing, ROW acquisition, siting, permitting, outreach, and engineering work for the Western kv Generation Substation, Tulsa North kv Generation Substation and the Gen-Tie kv line. Q. WHAT IS THE COST OF THIS WORK CURRENTLY UNDERWAY? A. The cost of the work conducted under the first eight LNTPs, if fully completed, totals approximately $ million. As mentioned previously, this work is required to maintain a construction schedule that meets future key construction schedule dates, DIRECT TESTIMONY BRIAN D. WEBER

82 supporting the final guaranteed completion date of December 1, 00. Of the $ million, the Companies have agreed to pay up to $0 million of these costs, with the contractor covering the remainder. Upon the issuance of LNTP #, the remaining unpaid portion of the previous LNTP s (totaling approximately $ million) would also be required to be paid by the Companies. Q. WHAT ARE THE COSTS OF LNTP #, WHEN IS IT REQUIRED TO BE ISSUED, AND WHAT DOES THE WORK UNDER LNTP # CONSIST OF? A. The cost of the work under LNTP # is approximately $1. million. LNTP # is required to be issued on August, 01 to maintain the guaranteed completion date of December 1, 00, and covers work to be completed through December 1, 01. If the Companies issue LNTP #, the remaining amounts under the previous eight LNTPs are also payable to the Contractor. Q. WHY WAS THE EPC CONTRACT STRUCTURED WITH LNTPs? A. The EPC Contract was structured to operate under LNTPs to allow essential work on the Gen-Tie to proceed forward while the necessary regulatory approvals are obtained by the Companies, thereby maintaining a guaranteed completion date of December 1, 00, as further discussed in the testimony of Company witness Paul Chodak. Q. WHAT ARE OTHER KEY MILESTONES IN THE EPC CONTRACT? A. The EPC Contract also has the following key milestones including: 1//01 - Final Route selection /1/01 - Mechanical Completion of kv Subsystem 1/1/00 - Project Substantial Completion 1/1/00 - Guaranteed Completion Date DIRECT TESTIMONY 1 BRIAN D. WEBER

83 1 1 1 Q. WHAT ASSURANCES ARE IN THE EPC CONTRACT TO ENSURE THE GEN-TIE IS PLACED IN SERVICE BY THE GUARANTEED COMPLETION DATE? A. The EPC Contract requires delay liquidated damages payments consisting of $00,000 per day for each day where the substantial completion of the Gen-Tie exceeds the guaranteed completion date of December 1, 00. Liquidated damages, in aggregate, are capped at 1% of the Contract Price. These delay liquidated damages provide additional certainty that the Gen-Tie line will be placed into service by the guaranteed completion date so that the full value of wind production tax credits can be maximized for customers. Q. WHAT ADDITIONAL ASSURANCES DOES THE EPC CONTRACT PROVIDE FOR CUSTOMERS AFTER THE GEN-TIE IS CONSTRUCTED? A. The EPC Contract contains a warranty of three years after completion on all installed equipment IV. LAND, PERMITTING, AND ROW ACQUISITION Q. PLEASE PROVIDE AN OVERVIEW OF THE SITING AND ROUTING REQUIREMENTS AND ACTIVITIES FOR THE GEN-TIE. A. Oklahoma does not have a specific siting process or siting application requirement for overall approval of the route alignment for the Gen-Tie. However, individual state and federal agencies will require permits and/or consultations to ultimately initiate construction activities. DIRECT TESTIMONY 1 BRIAN D. WEBER

84 AEPSC s siting process involves iterative phases of data collection, route development and refinement, agency coordination, public outreach, and comparative analysis to identify a final route for the Gen-Tie. The process begins with the collection of a broad range of geographic information from federal, state, and local sources from which a constraint map of the Gen-Tie area is compiled. An interdisciplinary team of engineers, scientists, and planners then develops a network of potential alignments for the Gen-Tie and conducts more detailed investigations into the site-specific considerations of each of the alignments from aerial photography, field reviews, and comparative analysis. A revised network of potential alignments is then shared with public officials, regulatory agencies, and the general public for input and comment. The interdisciplinary team then compiles all of the input received and through further analysis and comparison identifies a final Proposed Route that best minimizes the overall impacts of the line on natural resources, cultural resources, and area land uses, while avoiding non-standard design requirements and circuitous routes. The Contractor will follow the siting process established by AEPSC. Q. PLEASE PROVIDE AN OVERVIEW OF THE PERMITTING REQUIREMENTS AND ACTIVITIES FOR THE GEN-TIE. A. As described above, the Contractor, with the involvement of AEPSC personnel, will coordinate with state and federal agencies as well as local officials during the siting process to gather information to support the identification of a route for the Gen-Tie. The Contractor has the responsibility to obtain all permits with the exception of permits, if any, needed for National Environmental Policy Act compliance and DIRECT TESTIMONY 1 BRIAN D. WEBER

85 permits needed, if any, to address concerns with species such as the American Burying Beetle and the Lesser Prairie Chicken. Once the route is identified, the Contractor and AEPSC will then work with those regulatory agencies to obtain all the required federal, state and local permits and approvals necessary for construction of the Gen-Tie. Specific permitting requirements can vary based on geographic location of the project, land use, environmental or historic features identified along the route, and local regulatory requirements for construction operations. The Gen-Tie will likely require permits from: the US Army Corp of Engineers, for water and wetland impacts; Oklahoma Department of Environmental Quality (ODEQ), for water quality and storm water permits; and the U.S. Fish and Wildlife Service, for sensitive species and habitat consultations. Depending on the route identified, additional permits and/or consultation may be required from the U.S. Environmental Protection Agency, U.S. Bureau of Indian Affairs, Oklahoma State Historic Preservation Office, and potentially tribal, county, and municipal governments to construct the project. These requirements can only be identified as the route is identified. Q. PLEASE PROVIDE AN OVERVIEW OF THE LAND RIGHTS ACQUISITION REQUIREMENTS AND ACTIVITIES FOR THE GEN-TIE. A. The Contractor will follow the land right acquisition processes followed by AEPSC. AEPSC works with landowners at each step in the process. AEPSC attempts to balance landowner concerns and preferences with the need for cost-effective electric infrastructure when locating ROW. AEPSC discusses with property owners easement rights and project specifics, including: DIRECT TESTIMONY 1 BRIAN D. WEBER

86 The length and width of the ROW The number and placement of structures The height and design of the structures Voltage of the power line Clearing and construction practices ROW access Project schedule Post-construction maintenance Vegetation maintenance practices AEPSC also pays for justified crop damage and/or physical damage to property resulting from the construction and/or maintenance of the transmission line. AEPSC typically acquires necessary easements through negotiations and by working with landowners, as long as practical, to reach a voluntary agreement. It is only when a voluntary agreement cannot be reached, and other viable alternatives do not exist, that the final option of exercising the right of eminent domain is pursued. Q. ARE ANY OTHER AUTHORIZATIONS NEEDED PRIOR TO CONSTRUCTING THE GEN-TIE? A. Any necessary construction-related authorizations that are typically administrative in nature will occur between the time local land use permits are acquired and when construction begins. These authorizations may include building permits, permits for road crossings and road occupancy, and any bridge, railroad or highway crossings. These permits are the responsibility of the Contractor to obtain. DIRECT TESTIMONY 1 BRIAN D. WEBER

87 V. CONCLUSION Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes, it does. DIRECT TESTIMONY 1 BRIAN D. WEBER

88 EXHIBIT BDW-1 Page 1 of Project Timing Contract Price Payment Obligations Guarantee Credit Support The deadline for the Owner s Final Route Selection is 1//1 and full performance of the Work shall commence no later than 1/1/1 (the NTP Deadline). The guaranteed completion date of the project is 1/1/0. The Contract Price will be provided for in the final Contract Letter, will be adjusted as necessary for Change Orders, and is calculated based on a mutual assumption that the total mileage of the Final Route is 0 miles. The Contract Price may be adjusted based on the actual mileage of the Final Route as well as any executed Change Orders during the pendency of the Project. Each Owner is severally, not jointly, liable for the Contract payments. AEPSC will act on behalf of the Owner for receiving the Applications for Payment and making each payment to the Contractor. Quanta Services, Inc. will provide a guarantee for the Contractor s obligations under the Contract. The guarantee is limited to 0% of the Contract Price for all claims except gross negligence, willful misconduct, and/or fraud, which are limited to 0% of the Contract Price. The Contractor will provide a letter of credit to the Owner for one hundred million dollars ($0,000,000) that will remain in effect until the primary warranty period has expired (as described below in Warranty section). Project Schedule Changes in Work The Contractor shall develop and maintain the Project Schedule, which shall be accessible by the Owner at all times. Updates will be provided to the Owner every weeks. The Owner can initiate a Change Order by issuing the request to the Contractor. The Contractor then provides a statement of the proposed change s impact to the Scope of Work, Contract Price, Guaranteed Completion Dates, Key Project Dates and/or Project Schedule. If the parties agree, they will execute a Change Order. Contractor can initiate a Change Order upon an occurrence of certain events by issuing a request to the Owner along with a statement of impact and reason for change. If parties agree, they will execute a Change Order. Without the notice by Contractor, the Owner is not obligated to pay the Contractor additional compensation for any changes. Contractor can request a fixed-price, lump-sum increase in the Contract Price due to a Change Order. If the parties cannot agree on the changes or the Contractor s payments for the changes, the Owner may issue a unilateral Change Order and require the Contractor to begin the change work either (i) on a cost-plus basis, or (ii) in accordance with the outcome of a dispute resolution procedure (described below in Dispute Resolution section). AEPSC s Duties Under the Contract as Owner s Agent AEPSC will serve as the Owner s Agent for all purposes of the Contract including (i) waiver and amendment of Owner s rights and duties, (ii) issuance and receipt of Notices, (iii) resolution of any dispute, (iv) negotiation of accounting matters, and (v) completion of all things concerning Owner in the Contract.

89 EXHIBIT BDW-1 Page of Specific Owner Obligations Taxes Indemnification In addition to other obligations in the Contract, the Owner is specifically obligated to: (i) achieve the Owner milestones set out in the Scope of Work, (ii) perform all tasks required of it concerning access to the Site, availability of the Site, and real property rights of the Site, (iii) obtain and maintain Owner permits, (iv) provide adequate personnel, (v) comply with all manuals, (vi) pay for Critical Components, (vii) provide Project Outreach, and (viii) provide assistance to Contractor concerning outages. The Contract Price includes and the Contractor is responsible for paying all taxes based upon compensation paid to persons for performance of the Work. The Owner will indemnify the Contractor related to any sales and use tax exemptions. The Contractor shall indemnify the Owner for all claims arising out of the Contract except for those claims arising from Owner s negligence or breach of the contract by either Owner. The Owner has the right to select its own counsel separate from the Contractor and at the Contractor s expense. The Contractor is liable for reasonable attorneys fees and costs for enforcement of the Contract s indemnification obligations. Limitations of Liability Neither the Contractor nor the Owner will be liable to the other party for consequential damages for any claim arising from the Contract. The aggregate liability of the Contractor for any claim by the Owner shall not exceed: (i) the total adjusted Contract Price for claims prior to Substantial Completion, (ii) 0% of adjusted Contract Price for claims after Substantial Completion concerning the Contractor s obligations for Chronic Failures, and (iii) % of the adjusted Contract Price for claims after Substantial Completion concerning the Contractor s other obligations under the Contract. These limitations of liability do not apply to claims for indemnification, patent and copyright infringement, compliance with Applicable Laws, liquidated damages, or claims arising from the Contractor s gross negligence, willful or intentional failure to perform, or fraud. Liens The Contractor shall not permit liens to attach to the Work, the Project, or the Site, except for liens arising from Owner s failure to pay Contractor an undisputed payment or liens for which the Contractor promptly obtains acceptable security. The Owner can seek lien waivers from the Contractor prior to each Contract payment. Delay Damages The Contractor will pay Delay Damages for each Day after the Guaranteed Completion Date until substantial completion is achieved. The Contractor will pay Delay Damages for each Day after /1/1 until the Western kv Generation Substation is achieved. Delay damages will not exceed a percentage of the Contract Price.

90 EXHIBIT BDW-1 Page of Warranty The Contractor warrants that (i) the Work is completed in a good and workmanlike manner and in compliance with all applicable laws, and (ii) all Equipment is new, free of defects and liens, and complies with all Applicable Laws. As to the Western kv Generation Substation, the primary warranty period is for years following completion of the station. For the rest of the Project, the primary warranty period is for years following the Project Substantial Completion date. The Contractor additionally warrants that (i) it will cooperate with the Owner concerning of any general site condition hazards, (ii) its performance of the Work will not infringe upon or violate any intellectual property rights, and (iii) it has obtained agreements from all necessary parties concerning intellectual property. Risk of Loss Except for the Western kv Generation Substation, the Contractor has the risk of loss with respect to the Work and Project until Project Substantial Completion. The risk of loss will transfer to the Owner upon acceptance of completion certificate. Owner shall take possession of the Western kv Generation Substation upon Western kv Generation Substation Mechanical Completion, and all care, custody, control, risk of loss and title with respect to the Western kv Generation Substation shall transfer to Owner at such time. Insurance Suspension of Work The Contractor shall maintain the following insurance: (i) workers compensation insurance, (ii) employer s liability with $1,000,000 coverage; (iii) automobile insurance with $,000,000 coverage, (iv) CGL with coverage of $,000,000 per occurrence, (v) environmental/pollution insurance with coverage of $,000,000 per occurrence, (vi) umbrella/excess coverage of $0,000,000 per occurrence and $0,000,000 aggregate, and (vii) other specific coverage if the work involves aircraft, cyber/tech exposure, design and engineering, or marine vessels. The Owner can suspend the Work, or any part thereof, with days notice to the Contractor. The Notice must set for an estimate for the duration of the suspension. The Owner must pay the Contractor for Work completed prior to time of suspension as well as for costs incurred as a result of the suspension. If any single suspension exceeds 0 days or if the aggregate suspensions exceed days, the Contractor can proceed to issue a Change Order request to the Owner. Failing execution of a Change Order, either party may terminate the Contract, which will be deemed a termination for the Owner s convenience (as described below in Termination section). Dispute Resolution If the parties cannot resolve a dispute among themselves, either party will have the right to escalate the dispute to be heard by project management. Management representatives will meet to exchange relevant information and attempt to resolve the dispute. If project management cannot resolve the dispute, either party has the right to escalate the dispute to be heard by senior management. If the dispute is one that jeopardizes the continued progress of the Work, the parties can negotiate to appoint a Project Neutral to determine the dispute. Any written decision issued by the Project Neutral is final, binding, and non-appealable unless based on fraud, bias or that the Project Neutral exceeded its scope. If the parties failed to resolve the dispute through their own discussions, project management discussions, and senior management discusses and the parties cannot agree to a Project Neutral, then either party can submit the dispute to binding arbitration.

91 EXHIBIT BDW-1 Page of Termination The bases for termination of the Contract are: (i) filing of a petition for bankruptcy by either party or either party s creditors file an involuntary petition in bankruptcy, (ii) the Contractor fails to provide or fails to comply with a written recovery plan for delay, and (iii) either party commits a material breach of the Contract that remains unremedied for 0 days. The Owner can also terminate the Contract for its convenience. If terminated after the NTP Deadline, the Contractor shall receive payment for all Work satisfactorily performed up to the date of termination.

92 EXHBIT BDW- This Exhibit is voluminous and HIGHLY SENSITIVE under the terms of the Protective Order. The information is available for review at the Austin offices of American Electric Power Company (AEP), 00 West 1th Street, Suite, Austin, Texas, (1) 1-, during normal business hours, by parties to this case who have agreed to be bound by the Protective Order.

93 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF KELLY D. PEARCE FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

94 SECTION TESTIMONY INDEX PAGE I. INTRODUCTION... II. PURPOSE OF TESTIMONY... III. ECONOMIC BENEFIT... IV. METHODOLOGY FOR DETERMINING BENEFITS... V. ESTIMATED COSTS OF THE PROJECT... VI. NATURAL GAS PRICE IMPACTS ON THE ECONOMIC RESULTS... 1 VII. GENERIC WIND ALTERNATIVE... 1 VIII. ENERGY SOURCES AND USES... 1 IX. SHAPING OF PTCS... 1 X. JURISDICTIONAL NET BENEFITS AND REVENUE REQUIREMENT... 0 XI. CONCLUSION... 1 EXHIBITS EXHIBIT EXHIBIT KDP-1 EXHIBIT KDP- EXHIBIT KDP- EXHIBIT KDP- EXHIBIT KDP- EXHIBIT KDP- DESCRIPTION Forecasted Costs and Benefits of the Project Costs and Benefits of the Project using low and high natural gas assumptions Costs and Benefits of the Project versus a Generic Wind Case Sources and Uses of Energy Project PTCs Shaping Project Benefits with Shaping of PTCs DIRECT TESTIMONY 1 KELLY D. PEARCE

95 I. INTRODUCTION Q. PLEASE STATE YOUR NAME, BUSINESS ADDRESS AND POSITION. A. My name is Kelly D. Pearce. My business address is 1 Riverside Plaza, Columbus, Ohio 1. I am employed as Director - Contracts and Analysis for American Electric Power Service Corporation (AEPSC), a wholly-owned subsidiary of American Electric Power Company, Inc. (AEP). AEP is the parent company of Southwestern Electric Power Company (SWEPCO or the Company). Q. PLEASE BRIEFLY DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL BACKGROUND. A. I received a Bachelor of Science degree in Mechanical Engineering from Oklahoma State University in 1. I received Master of Science and Doctor of Philosophy degrees in Nuclear Engineering from the University of Michigan in 1 and, respectively. I received a Master of Science in Industrial Administration degree from Carnegie Mellon University in 1. From 1 to 1, I worked for a subsidiary of Olin Corporation. From to 1, I worked for the United States Department of Energy within the Office of Fossil Energy. My responsibilities included serving as a Contracting Officer s Representative in the oversight and administration of government-funded research of advanced generation and environmental remediation technologies and projects. I also supported strategic studies for deployment and commercialization of these technologies, as well as administration and support of government research and development solicitations. DIRECT TESTIMONY KELLY D. PEARCE

96 In 1, I joined AEPSC as a Rate Consultant I in the Regulatory Services department. In 001, I was promoted to Senior Regulatory Consultant. My responsibilities included preparation of class cost-of-service studies and rate design for AEP operating companies and the preparation of special contracts and regulated pricing for retail customers. In 00, I transferred to Commercial Operations within AEPSC as Manager of Cost Recovery Analysis. In 00, I was promoted to Director of Commercial Analysis. During this period, I was responsible for analyzing the financial impacts of Commercial Operations-related activities. I also supported settlement of AEP s generation pooling agreements among AEP s operating companies. In 0, I transferred to Regulatory Services in my current position. I am a registered Professional Engineer in Ohio and West Virginia. Q. WHAT ARE YOUR CURRENT RESPONSIBILITIES? A. My group is responsible for performing financial and other analyses concerning AEP s generation resources and load obligations; settlement support for AEP s operating companies, including that associated with certain affiliate agreements and 1 the Southwest Power Pool (SPP) and PJM, L.L.C. (PJM) 1 regional transmission organizations; and regulatory support in areas that relate to commercial operations. In addition, my group is responsible for AEP s wholesale formula rate agreements. Q. HAVE YOU APPEARED AS A WITNESS BEFORE ANY REGULATORY COMMISSIONS? A. Yes. I submitted testimony and testified before the Public Utilities Commission of Ohio in Case Nos. --EL-SSO et al., --EL-UNC and 1-1-EL-RDR 1 The PJM acronym was originally derived from Pennsylvania, New Jersey and Maryland. DIRECT TESTIMONY KELLY D. PEARCE

97 et al. on behalf of AEP Ohio. I submitted testimony to the Virginia State Corporation Commission (VSCC) in Case Nos. PUE and PUE and submitted testimony and testified before the VSCC in Case No. PUE I testified before the Indiana Utility Regulatory Commission in Cause No. and the Kentucky Public Service Commission in Case No I also submitted testimony to the Federal Energy Regulatory Commission in Docket No. ER My testimony in all of these proceedings was on behalf of operating companies that are affiliates of SWEPCO II. PURPOSE OF TESTIMONY Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? A. My testimony quantifies the benefits of SWEPCO s proposal to acquire a seventy-percent (0%) share of the Wind Catcher Facility (Wind Facility) and to construct the Wind Catcher Generation Tie Line (Gen-Tie Line), which together forms the Wind Catcher Energy Connection Project (Project) that is forecasted to provide SWEPCO s customers a savings over the -year project life of approximately $1. billion in discounted or net present value (NPV) dollars. Consistent with the in-service date of the Project, all NPV values I reference are expressed in 00 dollars. Approximately $0 million of this savings is forecasted to flow to Texas retail customers. Public Service Company of Oklahoma (PSO), a SWEPCO affiliate, will own the remaining 0% of the Project. DIRECT TESTIMONY KELLY D. PEARCE

98 Specifically, my testimony: 1) identifies the economic benefits to SWEPCO customers if the application is approved consistent with the Company s request in order to take full advantage of the federal Production Tax Credits (PTCs); ) provides a detailed description of the methodology used to forecast the economic benefits; ) demonstrates that the Project is beneficial compared to either a base case alternative or procuring an equivalent 0 MW of generic wind resources through purchase power agreements (Generic Wind case); and ) forecasts the total Company revenue requirement and customer savings. III. ECONOMIC BENEFIT Q. WHAT ARE THE FORECASTED BENEFITS AND PROJECTED COSTS OF THE PROJECT? A. EXHIBIT KDP-1 contains the forecasted benefits, projected costs and resulting net customer savings of the Project. These results are summarized in Table I. TABLE I Total SWEPCO Net Benefits of Project Company Costs and Benefits 1. Avoided Costs Benefits (Exhibit KDP-1 Ln1+Ln+Ln). Revenue Requirement of Wind Facility and Gen-Tie Line (Cost) (Exhibit KDP-1 Ln + Ln). PTCs including tax gross-up (Exhibit KDP-1 Ln) SWEPCO Savings and Costs Total 01-0 (NPV $Millions) $, ($,0) $1, 1. Net Customer Benefits $1, DIRECT TESTIMONY KELLY D. PEARCE

99 Q. PLEASE EXPLAIN THE COMPONENTS OF TABLE I. A. Line 1 is the forecasted avoided costs, which is the savings in fuel, purchased power, and other variable costs, plus the Wind Facility capacity value, less the incremental costs of congestion and Off-System Sales (OSS) revenue net of retained margins. Line shows the projected revenue requirement of the Project. Line shows the forecasted value of the PTCs, including the tax gross-up. Line, the net of lines 1, and, shows a substantial savings for SWEPCO s customers over the life of the Project. Q. HOW DOES THE PROJECT ALIGN WITH THE COMPANY S MOST RECENT INTEGRATED RESOURCE PLAN (IRP)? A. SWEPCO s most recent IRP, filed with the Arkansas Public Service Commission in December 01, included additional wind resources of 00 MW nameplate capacity in 01 and incremental additions of wind resources beginning in 0 and increasing to a total of 1,00 MW by 0. The IRP also included the addition of a MW Natural Gas Combined Cycle (NGCC) unit in 0. It is important to note that the 01 IRP assumed PTCs would expire at the end of 01, which is no longer the case. Consequently, this Project effectively accelerates the IRP results related to additional wind resources to capture the PTC s value. This acceleration also allows 1 SWEPCO to delay the cost of adding the NGCC. The benefits of the acceleration 0 1 are the large energy savings, which when coupled with the PTCs and delay in adding additional generation, creates a unique opportunity for SWEPCO s customers to save up to approximately two billion dollars, as shown in EXHIBIT KDP-1. DIRECT TESTIMONY KELLY D. PEARCE

100 Q. DID YOU COMPARE THE PROJECT AGAINST THIS 01 IRP? A. No. As stated, the 01 IRP assumed the expiration of the PTCs, so a new updated baseline case, which I will describe, was developed for the -year life of the Wind Facility (compared to the shorter-term IRP) for determining the economics of the Project IV. METHODOLOGY FOR DETERMINING BENEFITS Q. PLEASE EXPLAIN THE METHODOLOGY USED TO DETERMINE THE ADJUSTED PRODUCTION COST (APC) SAVINGS PROVIDED IN EXHIBIT KDP-1. A. To determine the net benefits of the Project, the Company developed both a baseline scenario (Base Case), which assumed no new wind resource additions for SWEPCO, and a change-case scenario that included the Project (Project Case), and then compared the difference or delta between these two cases for the period modeled, 01 to 0. Consistent with the 01 IRP, NGCC units were assumed as additions to SWEPCO s resources in both the Base Case and Project Case as needed throughout the period to maintain a 1% capacity reserve margin as required by SPP. The forecasted total variable costs used to determine the APC savings are based on a MWh generation forecast for each SWEPCO generation unit determined utilizing the simulation model PLEXOS, a widely-accepted model that AEP uses to forecast its operating companies production costs. The PLEXOS model utilizes a forecast for each unit s cost of energy (e.g., fuel, fuel handling, variable operations and maintenance, consumable costs and emission allowance costs), scheduled DIRECT TESTIMONY KELLY D. PEARCE

101 maintenance outages, and forced outages, along with forecasted market prices of energy to determine forecasted generation output, costs, and revenues. The model compares the total hourly energy output of SWEPCO s generation resources against the hourly internal load energy requirement of SWEPCO. To the extent that the resources exceed the load, the model determines the surplus generation sold at the hourly generation price. To the extent that the load exceeds the resources, the model determines the deficit purchase at the market load price. Consequently, the APC includes the cost of production less the cost of purchases, plus the revenues from additional OSS less the OSS margins retained by SWEPCO. The benefits also include the Project s capacity value, which is determined outside of PLEXOS. Q. DID YOU MAKE ANY ADDITIONAL MODIFICATIONS IN DEVELOPING THESE RESULTS? A. Yes. Under normal IRP or incremental resource addition modeling, the Company has not historically modeled the impact that a new resource itself has on market prices of energy. The reasons for this are twofold. First, new generation is typically being sized to meet forecasted load growth and generation retirements, and additional OSS and purchases are secondary to the overall economics. Secondly, the generation resource additions are typically small relative to the size of the regional transmission organization (RTO), in this case, SPP. As such, the change in SPP market prices can reasonably be assumed to be negligible. However, due to the amount of energy, particularly when at full output, which will be produced by the Project in comparison to the AEP SPP zonal market, the DIRECT TESTIMONY KELLY D. PEARCE

102 Company included a forecast of the impact that the Project itself will have on SPP market energy prices. Q. PLEASE EXPLAIN HOW THIS WAS ACCOMPLISHED. A. The Company enlisted the aid of The Brattle Group (Brattle) to support modeling of the entire SPP RTO. As described by Company witness Johannes P. Pfeifenberger of Brattle, the entire SPP RTO and its neighboring systems were modeled for two representative years, 00 and 0, to forecast the impacts that the 0 MW Project would have on SPP hourly market energy prices including the impact on the total locational marginal prices (LMPs) and the congestion and loss components of those prices. The PROMOD model was utilized for these simulations to perform a transmission-constrained economic dispatch including all SPP region resources and loads. As a result, the simulation determines the hourly LMPs for both generation and load based on the incremental energy cost of the last MWhs produced and the congestion-related cost resulting from any transmission capacity limitations. This method provides a good forecast of the impacts that the Project will have on SPP LMPs, including the LMPs specific to SWEPCO s load. Q. HOW WERE THE PROMOD RESULTS INCORPORATED INTO PLEXOS? A. To complete the modeling for all years of the Project s life, the Company utilized the long-term SPP market energy prices prepared by the AEP Fundamentals groups as supported by Company witness Karl Bletzacker. The year-over-year percentage changes in these forecasted market energy prices were used to develop the entire data set of prices for 01 through 0. This process is supported by Company witness Pfeifenberger. These market prices were then input into PLEXOS. DIRECT TESTIMONY KELLY D. PEARCE

103 Q. DOES INCLUSION OF THE IMPACT THAT THE PROJECT HAS ON MARKET PRICES ADD FURTHER CONFIDENCE IN THE RESULTS? A. Yes. The analysis demonstrates that the Project is beneficial to SWEPCO s customers when considering the impact that the Project itself has on market prices and congestion. Q. HOW WERE OSS MARGINS TREATED? A. As previously mentioned, the Company employed the currently authorized OSS sharing mechanism, which flows 0% of margins through to customers. The APC includes the benefits of these incremental OSS margins. Q. HOW WAS THE VALUE OF CAPACITY DETERMINED? A. The Company forecasted the incremental value of the capacity of the Project. Based on the SPP-required 1% reserve margin, the Company has estimated the avoided capacity cost savings of deferring certain future capacity investments. Based on the Project Case, SWEPCO will be able to defer the investment in a NGCC unit from 0 to 0 and avoid entirely the addition of a second NGCC unit in 0 through the end of the period modeled, 0. Based on these projections, the value of the Project capacity, as shown in EXHIBIT KDP-1, is $ million on an NPV basis. This includes the cost savings for the years in which the NGCC capacity investment is able to be delayed, including the carrying costs and Operations and Maintenance (O&M) savings. Q. ARE THERE ANY OTHER WAYS IN WHICH THE AVOIDED CAPACITY VALUE COULD BE DETERMINED? DIRECT TESTIMONY KELLY D. PEARCE

104 A. Yes. The Company also evaluated the value of the avoided capacity based on the AEP Fundamentals group forecast of SPP capacity costs, as supported by Company witness Bletzacker. In order to be conservative, the Company assumed a zero value of the incremental capacity from the Project until 0, which is the first year in which SWEPCO has a forecasted need for additional capacity. Beginning in 0, 1% of the Project delivered capacity was assumed as the SPP capacity credit for the Wind Facility, which results in 1. MW. This is equal to 1% multiplied by SWEPCO s Project ownership share of 1,0 MW. In this case, the Wind Facility provides economic value to SWEPCO of $1 Million in NPV from 0 through 0. This is the fundamental value of capacity in the SPP market, whether as an avoided cost savings or surplus sale. However, the Company did not assume any incremental capacity value from the Project until it is forecasted to have a capacity need without the Project. Any ability SWEPCO may have to monetize the capacity prior to 0 will add additional value to this forecast V. ESTIMATED COSTS OF THE PROJECT Q. WHAT ARE THE ESTIMATED COSTS OF THE PROJECT? A. The revenue requirements of the Wind Facility and the Gen-Tie Line consist of financing cost, depreciation, O&M expense and other expenses net of the PTC. The costs of the Wind Facility are supported by Company witnesses Jay F. Godfrey and Michael L. Bright. The capital investment and ongoing expense of the Gen-Tie Line are supported by Company witnesses Brian D. Weber and Robert W. Bradish. These 1,00 MW total Wind Project multiplied by SWEPCO s 0% ownership share. DIRECT TESTIMONY KELLY D. PEARCE

105 Q costs were modeled in typical cost-of-service fashion for the -year assumed life of the Wind Facility. PLEASE DESCRIBE THE PTCS A. The PTCs are an inflation-adjusted per-kwh federal tax credit for electricity generated by qualified energy resources. The PTCs are available for years from the date the resource is placed in service. As stated by Company witnesses Paul Chodak and Venita McCellon-Allen, resource eligibility is being stepped down and will no longer be available at the 0% level under the safe harbor provision for facilities that do not achieve commercial operation by the end of 00. Q. WHAT IS THE LEVELIZED COST OF POWER FROM THE WIND FACILITY WHEN THE PTCS ARE CONSIDERED? A. The Project Wind Facility is forecasted to produce power at a levelized cost of $1.0/MWh including the cost of the Wind Facility net of the value of the PTCs. Q. WHAT WAS THE ASSUMED COST OF CAPITAL ASSOCIATED WITH THE PROJECT? A. The total cost of capital of the Project is based on a composite of SWEPCO s three state retail jurisdictions and its wholesale generation agreements including interest expense, Return on Equity (ROE), and capital structure. For the Texas portion, an ROE of %, consistent with SWEPCO s proposal in its recent base rate case in Docket No., was assumed. This is not to infer that the Company is making any assumption about the Commission s decision in that case, but is simply a proxy as a modeling assumption. This ROE was utilized for modeling purposes for 01 and DIRECT TESTIMONY 1 KELLY D. PEARCE

106 For years 0 to 0, a forecasted ROE of.% was assumed as supported by Company witness Renee V. Hawkins. Q. WHAT DEPRECIABLE LIVES WERE ASSUMED FOR THE WIND FACILITY AND THE GEN-TIE LINE? A. The Wind Facility was modeled using a -year depreciable life consistent with existing wind projects, as supported by Company witness Bright. The Gen-Tie Line was modeled using a 0-year service life as supported by Company witness Bradish. Q. WHAT WOULD THE OVERALL PROJECT ECONOMICS LOOK LIKE IF A -YEAR SERVICE LIFE WAS ASSUMED FOR THE GEN-TIE LINE? A. If the Gen-Tie Line is depreciated at the same -year rate as the Wind Facility, the total costs of the Gen-Tie Line would increase by approximately $ Million on an NPV basis and the total net benefit of the Project would be reduced from approximately $1. billion to $1. billion VI. NATURAL GAS PRICE IMPACTS ON THE ECONOMIC RESULTS Q. DID THE COMPANY PERFORM ANY SENSITIVITY STUDIES WITH REGARD TO NATURAL GAS PRICES? A. Yes. In addition to the AEP Fundamentals group base forecast of future natural gas prices, the Company also modeled the impacts on the Project of both low and high natural gas price forecasts, as supported by Company witness Bletzacker. The results of these cases are provided in EXHIBIT KDP-. These natural gas prices were utilized in the 00 and 0 PROMOD models to determine the SPP energy market prices that were then interpolated and extrapolated for all years of the study and input DIRECT TESTIMONY 1 KELLY D. PEARCE

107 into the PLEXOS model. The lower natural gas price forecast reduces the net benefit of the Project by approximately 1%. At this level, the Project provides net benefits to SWEPCO s customers of $1. billion on an NPV basis in 00 dollars over the -year Project life. Alternatively, in the high gas price scenario, benefits are increased 1%, and are approximately $. billion on an NPV basis over the Project life VII. GENERIC WIND ALTERNATIVE Q. DID THE COMPANY COMPARE THE PROJECT WITH ANY OTHER WIND RESOURCE ALTERNATIVES? A. Yes. The Company considered the feasibility and economics of attempting to capture the benefits of the PTCs on the same scale as the Project, without the Gen-Tie Line. To compare this generic wind case (Generic Wind Case) with the Project, the Company modeled 1,00 MW of wind resources with SWEPCO receiving the same 0% allocation of the output. However, the congestion created by adding 1,00 MW of wind in the same area of the Oklahoma Panhandle as the Project, but without the Gen-Tie Line, is not realistic given the expected magnitude of congestion that would be created. Therefore, the Company modeled the Generic Wind case as being distributed and sourced from several delivery points in western Oklahoma, Kansas, Texas, Nebraska and Missouri. For the PROMOD cases used to determine LMP price impacts,,0 GWhs of annual output were modeled based on data from the National Renewable Energy Laboratory. For the PLEXOS modeling, which determines the value of the wind resources, the output was increased to,1 GWhs DIRECT TESTIMONY 1 KELLY D. PEARCE

108 of annual output, as described by Company witness Pfeifenberger. The Project s forecasted average annual output is, GWhs delivered to PSO s existing Tulsa North kv substation after reducing for Gen-Tie losses. Q. WHAT ENERGY PRICE WAS USED FOR THE GENERIC WIND CASE? A. The Company assumed a year one purchase price of $1./MWh with an annual escalation of.%. This price assumes that the PTCs can be captured before their expiration. This price is based on reported estimates from the U.S. Energy Information Agency s 01 Annual Energy Outlook, as discussed by Company witness Pfeifenberger. The Company also assumed and included $0 million of contingency cost. Q. WHAT ARE THE RESULTS OF THE GENERIC WIND CASE COMPARED TO THE PROJECT WHEN ALL COSTS ARE CONSIDERED? A. EXHIBIT KDP- shows the savings and costs of the Project Case less the Generic Wind Case. As shown in EXHIBIT KDP-, the Project is expected to produce approximately $ million more in customer savings than the Generic Wind Case would relative to the Baseline Case. As indicated, the Generic Wind Case provides some of the same benefits as the Project and avoids the cost of the Gen-Tie Line. However, the Generic Wind Case APC also includes the purchase costs of the Generic Wind and therefore has a higher APC than the Project APC. In addition, without the Gen-Tie Line, the Generic Wind Case creates significant congestion in SPP compared to the Project, even when attempting to mitigate this congestion by dispersing the resources. Furthermore, the Generic Wind Case will be subject to curtailments by SPP, as discussed by Company witness Pfeifenberger. DIRECT TESTIMONY 1 KELLY D. PEARCE

109 Q. IN THE GENERIC WIND CASE, WOULD POTENTIAL FUTURE TRANSMISSION PROJECTS MITIGATE THE CONGESTION AND CURTAILMENT COSTS? A. Under the Generic Wind Case, to what extent the congestion is mitigated is uncertain and at best would take several years. In SPP, wind projects are studied such that only the cluster in an area under study is dispatched to full output while other remote wind is only dispatched at 0% of nameplate output during the interconnection process. Also, existing generation is scaled below capacity to balance the supply and demand in the models. This results in masking of congestion, which only becomes visible in a market efficiency analysis or real-time. Typically, it may take the RTO five to eight years to address real-time congestion based on the analysis cycle, siting, permitting and construction lead time associated with major transmission projects. Under the Generic Wind Case, even when SPP adds more transmission projects to address capacity constraints, more generation capacity may also be added as well, which will in turn create additional congestion. As a result, this cycle of congestion may continue indefinitely. Even more importantly, the cost of any additional transmission capacity that SPP constructs to relieve congestion in the future will be allocated to the beneficiaries. If the AEP zone is procuring wind generically across SPP, then the AEP zone will also be responsible for a large portion of the transmission costs, whether or not congestion associated with the Generic Wind is actually relieved. Alternatively, the Project will provide delivery of wind power from the high wind DIRECT TESTIMONY 1 KELLY D. PEARCE

110 resource area of the Oklahoma Panhandle all the way to the Tulsa North kv substation with no congestion in-between due to the dedicated Gen-Tie Line VIII. ENERGY SOURCES AND USES Q. PLEASE PROVIDE MORE DETAIL ON HOW THE PROJECT IMPACTS SWEPCO S SOURCES AND USES OF ENERGY. A. A breakdown of the energy changes between the Baseline Case and the Project is shown in EXHIBIT KDP-. These changes show the drivers of the APC savings described earlier. A portion of the benefit comes from the avoided cost of fuel and other variable costs from SWEPCO s units. In addition, a large portion of the Project s value comes from the fact that the large amount of low-cost energy produced by the Project to serve customers loads will also result in sales of additional MWhs of economic energy from SWEPCO s other units as OSS. The costs of these sales are then paid, not by SWEPCO s customers, but from the proceeds of the sale itself, and SWEPCO will pass through 0% of the margin from the incremental OSS to its customers. Additional benefit comes from the purchases that SWEPCO is able to avoid making to serve its customers as a result of the Project. Q. WHAT ARE THE FORECASTED IMPACTS ON THE DISPATCH OF SWEPCO S OTHER GENERATION UNITS? A. SWEPCO s existing generation units are impacted very little from the addition of the Project. As shown in EXHIBIT KDP-, SWEPCO s existing units are forecasted to have a 0.% reduction in total MWh output over the period. A large part of the fuel and other variable production cost savings is forecasted to come from the modeled DIRECT TESTIMONY 1 KELLY D. PEARCE

111 new NGCC units, which will produce less energy in part since they will be able to be delayed. Including both the impacts on the other generation units and the addition of the Project, SWEPCO is forecasted to see its energy production increase by approximately thousand GWhs over the -year period, which is an increase on average of approximately,00 GWhs per year IX. SHAPING OF PTCS Q. WHAT HAPPENS WHEN THE PTCS EXPIRE AFTER THE FIRST YEARS OF THE PROJECT? A. As shown in EXHIBIT KDP-1, the value of the PTCs grows over time, as do the customer benefits, until their expiration after 00. While benefits continue beyond 00, there is a significant drop in benefits in 01 as a result of the PTCs expiration that would lead to a significant one-time increase in the Project s year-over-year revenue requirement, which up to that point would be declining each year. Q. IS THE COMPANY PROPOSING ANYTHING TO MITIGATE THIS IMPACT OF PTCS EXPIRATION? A. Yes. The Company is proposing to defer, for rate-making purposes, some of the value of the PTCs beginning in 0 through 00. This would be accomplished, with Commission approval, by establishing a regulatory liability, and then returning this value to customers beginning in 01 until the entire liability has all been returned in the form of credits to customers. The result of this shaping is that the revenue requirement does not result in a large decrease from 01 to 00 followed by a large increase in 01. DIRECT TESTIMONY 1 KELLY D. PEARCE

112 Q. DOES THE COMPANY HAVE A PROPOSAL FOR HOW TO ACCOMPLISH THIS MITIGATION? A. Yes. There is no one right way to perform this shaping and it is also dependent upon the rate-making treatment of the PTC. For example, the amount of PTCs value deferred for rate-making purposes in order to shape the revenue requirement is dependent upon whether the regulatory liability is provided as a credit to rate base, which in turn also determines whether and by how much the regulatory liability accrues interest. However, the Company is providing a proposal it believes is reasonable and appropriate. The amount of PTCs value that would be deferred is shown in Table II. TABLE II Proposed Deferral of PTCs Year Proposed PTCs Value Deferred - Percent of Annual Amount Received Forecasted PTCs Value Deferred (Nominal Millions) Forecasted Aggregate PTCs Value Deferred Including Interest (Nominal Millions) % $0.0 $ % $.1 $ % $. $. 0 1.% $. $ % $. $.1 0.0% $1. $1. 0.0% $. $. 00.0% $. $. Q. HOW WILL SWEPCO RETURN THE DEFERRED PTCS VALUE TO CUSTOMERS? DIRECT TESTIMONY 1 KELLY D. PEARCE

113 A. Beginning in 01, when the PTCs expire, SWEPCO will flow the value of the deferred PTCs back to its customers. The amounts flowed through to customers will be based on a percentage of the aggregated amount at the end of the prior year as shown in Table III. TABLE III - Proposed Schedule for the Return of the Deferred PTCs and End of Year (EOY) Balances Year Proposed PTCs Value Returned - Percent of Prior Year End Balance Forecasted PTCs Value Returned (Nominal Millions) Forecasted Deferred PTCs EOY Balance Including Interest (Nominal Millions) 1 01.% $.1 $ % $. $. 0.% $1. $1. 0.% $. $1. 0.% $. $. 0.1% $.0 $.0 0.% $. $1.1 0 Remaining Balance $1. $0.0 Shown in EXHIBIT KDP- is a graphical representation of the total revenue requirement for the Project with and without the proposed shaping. The levelized costs are also shown for comparison. EXHIBIT KDP- is a modified version of EXHIBIT KDP-1 that shows the impacts of applying this PTCs value shaping. Note that the Project NPV in both cases is the same X. JURISDICTIONAL NET BENEFITS AND REVENUE REQUIREMENT Q. HAVE YOU FORECASTED THE PORTION OF THE COSTS AND BENEFITS THAT WILL BE ALLOCATED TO SWEPCO S TEXAS RETAIL CUSTOMERS? DIRECT TESTIMONY 0 KELLY D. PEARCE

114 A. Yes. I used forecasted jurisdictional allocation factors to allocate a portion of the Project costs, revenues and savings across the SWEPCO jurisdictions to identify the amount of the net benefit that each jurisdiction would receive. Based on this allocation, SWEPCO s Texas retail customers are forecasted to receive a net benefit of approximately $0 Million over the -year life of the Project. Q. ARE THESE COSTS BEING UTILIZED TO DEVELOP THE JURISDICTIONAL REVENUE REQUIREMENT FOR THE PROJECT? A. Yes. Company witness John Aaron utilized the same forecasted costs as contained herein on a jurisdictional-specific basis and presents the revenue requirement conversion into SWEPCO-Texas retail rates XI. CONCLUSION Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes, it does. DIRECT TESTIMONY 1 KELLY D. PEARCE

115 FORECASTED SWEPCO SHARE OF PROJECT COSTS AND BENEFITS COMPARED TO BASELINE CASE $ in Millions (Nominal unless otherwise indicated) Exhibit KDP-1 Page 1 of 1 Project Less Baseline Case Year 00 NPV Total Nominal Adjusted Production Cost Savings $,00 $, $ $ $1 $ $ $ $1. Congestion and Loss Cost ($) ($1) ($) ($) ($) ($) ($) ($) ($). Capacity Value $ $ $0 $0 $0 $0 $0 $1 $1.Wind Facility Revenue Requirement ($,) ($,) ($) ($) ($) ($) ($) ($1) ($). Production Tax Credits $1, $, $ $ $ $ $ $0 $. Gen-Tie Line Revenue Requirement ($1,1) ($,1) ($) ($1) ($1) ($) ($1) ($1) ($). Total Benefits/(Cost) $1, $,0 $1 $ $0 $1 $1 $1 $0 Project Less Baseline Case Year Adjusted Production Cost Savings $ $ $ $0 $ $ $ $0 $. Congestion and Loss Cost ($1) ($) ($) ($) ($1) ($) ($) ($) ($). Capacity Value $1 $1 $1 $1 $1 ($) ($) ($) ($).Wind Facility Revenue Requirement ($1) ($) ($0) ($) ($0) ($) ($0) ($1) ($). Production Tax Credits $1 $ $0 $0 $0 $0 $0 $0 $0. Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($). Total Benefits/(Cost) $ $1 $ $1 $1 $ $1 $1 $1 Project Less Baseline Case Year Adjusted Production Cost Savings $ $ $0 $1 $ $ $ $ $. Congestion and Loss Cost ($) ($) ($) ($) ($) ($0) ($0) ($1) ($). Capacity Value ($) $ $ $ $ $ $ $ $.Wind Facility Revenue Requirement ($0) ($00) ($1) ($) ($1) ($1) ($1) ($1) ($1). Production Tax Credits $0 $0 $0 $0 $0 $0 $0 $0 $0. Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($). Total Benefits/(Cost) $1 $ $0 $ $ $ $0 $0 $

116 FORECASTED SWEPCO SHARE OF PROJECT COSTS AND BENEFITS COMPARED TO BASELINE CASE WITH LOW NATURAL GAS SCENARIO $ in Millions (Nominal unless otherwise indicated) Exhibit KDP- Page 1 of Project Less Baseline Case with Low Natural Gas Scenario Year 00 NPV Total Nominal Adjusted Production Cost Savings $, $, $ $ $0 $1 $ $ $0. Congestion and Loss Cost ($1) ($) ($) ($) ($) ($) ($) ($) ($). Capacity Value $ $ $0 $0 $0 $0 $0 $1 $1.Wind Facility Revenue Requirement ($,) ($,) ($) ($) ($) ($) ($) ($1) ($). Production Tax Credits $1, $, $ $ $ $ $ $0 $. Gen-Tie Line Revenue Requirement ($1,1) ($,1) ($) ($1) ($1) ($) ($1) ($1) ($). Total Benefits/(Cost) $1, $,1 $ $ $ $0 $ $1 $ Project Less Baseline Case with Low Natural Gas Scenario Year Adjusted Production Cost Savings $ $ $ $ $ $ $1 $ $. Congestion and Loss Cost ($1) ($) ($) ($) ($0) ($1) ($) ($) ($). Capacity Value $1 $1 $1 $1 $1 ($) ($) ($) ($).Wind Facility Revenue Requirement ($1) ($) ($0) ($) ($0) ($) ($0) ($1) ($). Production Tax Credits $1 $ $0 $0 $0 $0 $0 $0 $0. Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($). Total Benefits/(Cost) $ $ $1 $ $ $1 $ $ $ Project Less Baseline Case with Low Natural Gas Scenario Year Adjusted Production Cost Savings $ $ $1 $ $0 $ $0 $1 $. Congestion and Loss Cost ($) ($) ($) ($) ($) ($0) ($1) ($1) ($). Capacity Value ($) $ $ $ $ $ $ $ $.Wind Facility Revenue Requirement ($0) ($00) ($1) ($) ($1) ($1) ($1) ($1) ($1). Production Tax Credits $0 $0 $0 $0 $0 $0 $0 $0 $0. Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($). Total Benefits/(Cost) $1 $1 $1 $1 $ $ $0 $ $

117 FORECASTED SWEPCO SHARE OF PROJECT COSTS AND BENEFITS COMPARED TO BASELINE CASE WITH HIGH NATURAL GAS SCENARIO $ in Millions (Nominal unless otherwise indicated) Exhibit KDP- Page of Project Less Baseline Case with High Natural Gas Scenario Year 00 NPV Total Nominal Adjusted Production Cost Savings $, $, $ $ $ $0 $1 $ $. Congestion and Loss Cost ($) ($1,) ($) ($) ($) ($) ($) ($1) ($). Capacity Value $ $ $0 $0 $0 $0 $0 $1 $1.Wind Facility Revenue Requirement ($,) ($,) ($) ($) ($) ($) ($) ($1) ($). Production Tax Credits $1, $, $ $ $ $ $ $0 $. Gen-Tie Line Revenue Requirement ($1,1) ($,1) ($) ($1) ($1) ($) ($1) ($1) ($). Total Benefits/(Cost) $, $, $ $ $ $ $1 $ $ Project Less Baseline Case with High Natural Gas Scenario Year Adjusted Production Cost Savings $0 $0 $ $1 $ $ $ $ $1. Congestion and Loss Cost ($) ($) ($1) ($) ($) ($) ($0) ($1) ($). Capacity Value $1 $1 $1 $1 $1 ($) ($) ($) ($).Wind Facility Revenue Requirement ($1) ($) ($0) ($) ($0) ($) ($0) ($1) ($). Production Tax Credits $1 $ $0 $0 $0 $0 $0 $0 $0. Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($). Total Benefits/(Cost) $1 $0 $1 $ $1 $ $ $0 $1 Project Less Baseline Case with High Natural Gas Scenario Year Adjusted Production Cost Savings $0 $ $ $1 $ $1 $0 $1 $. Congestion and Loss Cost ($) ($) ($) ($) ($) ($) ($) ($) ($0). Capacity Value ($) $ $ $ $ $ $ $ $.Wind Facility Revenue Requirement ($0) ($00) ($1) ($) ($1) ($1) ($1) ($1) ($1). Production Tax Credits $0 $0 $0 $0 $0 $0 $0 $0 $0. Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($). Total Benefits/(Cost) $ $0 $ $0 $1 $ $ $1 $

118 FORECASTED SWEPCO SHARE OF PROJECT COSTS AND BENEFITS COMPARED TO GENERIC WIND CASE $ in Millions (Nominal unless otherwise indicated) Exhibit KDP- Page 1 of 1 Project Less Generic Wind Year 00 NPV Total Nominal Adjusted Production Cost Savings $1, $, $ $1 $1 $ $1 $1 $1 Congestion and Loss Cost $ $1,1 $ $ $ $ $ $ $0 Curtailment Costs $ $0 $ $ $ $ $ $1 $1 Wind Facility Revenue Requirement ($,) ($,) ($) ($) ($) ($) ($) ($) ($) Production Tax Credits $1, $, $ $ $ $ $ $0 $ Gen-Tie Line Revenue Requirement ($1,1) ($,1) ($) ($1) ($1) ($) ($1) ($1) ($) Total Benefits/(Cost) $ $1,1 $ $1 $ $0 $ $1 $1 Project Less Generic Wind Year Adjusted Production Cost Savings $1 $ $1 $ $1 $ $1 $1 $1 Congestion and Loss Cost $ $ $ $ $1 $ $1 $ $ Curtailment Costs $1 $1 $1 $1 $1 $1 $1 $1 $1 Wind Facility Revenue Requirement ($) ($) ($) ($) ($) ($1) ($1) ($0) ($0) Production Tax Credits $1 $ $0 $0 $0 $0 $0 $0 $0 Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($) Total Benefits/(Cost) $1 $1 $0 ($) ($) ($) ($1) ($1) ($) Project Less Generic Wind Year Adjusted Production Cost Savings $1 $ $1 $1 $0 $0 $1 $1 $0 Congestion and Loss Cost $ $ $ $0 $ $ $ $ $ Curtailment Costs $0 $0 $0 $1 $1 $ $ $ $ Wind Facility Revenue Requirement ($1) ($1) ($) ($1) ($) ($1) ($1) ($1) ($1) Production Tax Credits $0 $0 $0 $0 $0 $0 $0 $0 $0 Gen-Tie Line Revenue Requirement ($) ($1) ($) ($) ($) ($) ($0) ($) ($) Total Benefits/(Cost) $ $ $ $ $ $ $ $ $

119 Exhibit KDP- Page 1 of 1 FORECASTED SWEPCO SOURCES AND USES OF ENERGY GWH CHANGE OF PROJECT CASE COMPARED TO BASELINE CASE SOURCES OF ENERGY TOTAL GWhs 01-0 BASELINE CASE (1) PROJECT CASE () CHANGE () = () - (1) PERCENT CHANGE () = () / (1) Coal/Lignite 0, 0,0 (,0) -0.% CC Existing 0,0, (,0) -.1% CT () -.% Gas Steam,0, () -1.1% SUBTOTAL EXISTING FOSSIL 1,1, (,01) -0.% Wind and Solar PPA Purchases 1, 1, 0 0.0% Sundance,, 0 0.0% Wind Catcher 0 1, 1, - CC New,1,0 (0,1) -.% TOTAL GEN RESOURCES,,, 0.% Market Purchases,0 1, (,1) -.% TOTAL SOURCES, 1,, 1.% USES OF ENERGY TOTAL GWhs 01-0 BASELINE CASE (1) PROJECT CASE () CHANGE () = () - (1) PERCENT CHANGE () = () / (1) Internal Load,, 0 0.0% Market Sales,0 1,, 1.1% TOTAL USES, 1,, 1.%

120 Wind Catcher Energy Connection Project - Effect of PTCs Shaping Exhibit KDP- Page 1 of 1 Annual Revenue Requirement of Wind Facility & Gen-Tie Line ($ Millions) $00 $0 $00 $0 $00 $ $0 $0 $ Year Wind Farm and Gen-Tie Unshaped Cost Shaped Cost Levelized Cost

121 FORECASTED SWEPCO SHARE OF PROJECT PROJECT BENEFITS WITH SHAPING OF PTCS $ in Millions (Nominal unless otherwise indicated) Exhibit KDP- Page 1 of 1 Project Less Baseline Case with Shaped PTC Value Year 00 NPV Total Nominal Total Benefits/(Cost) * $1, $,1 $ $ $ $0 $ $1 $ Less PTCs Earned * $1, $, $ $ $ $ $ $0 $ Subtotal without PTCs $ $1,1 ($) ($0) ($1) ($1) ($1) ($) ($) Shaped PTCs Passed Through $1, $, $ $ $ $ $ $ $ Total Benefits with Shaped PTCs $1, $, $ $ $ $ $ $1 $1 Project Less Baseline Case with Shaped PTC Value Year Total Benefits/(Cost) * $1 $ $ $ $ $ $1 $1 $ Less PTCs Earned * $1 $ $0 $0 $0 $0 $0 $0 $0 Subtotal without PTCs ($1) ($) $ $ $ $ $1 $1 $ Shaped PTCs Passed Through $ $1 $1 $1 $1 $ $ $ $ Total Benefits with Shaped PTCs $1 $ $0 $1 $ $1 $1 $1 $1 Project Less Baseline Case with Shaped PTC Value Year Total Benefits/(Cost) * $1 $1 $ $ $ $ $ $ $0 Less PTCs Earned * $0 $0 $0 $0 $0 $0 $0 $0 $0 Subtotal without PTCs $1 $1 $ $ $ $ $ $ $0 Shaped PTCs Passed Through $ $1 $0 $0 $0 $0 $0 $0 $0 Total Benefits with Shaped PTCs $ $ $ $ $ $ $ $ $0 *From Exhibit KDP-1

122 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF JOHANNES P. PFEIFENBERGER FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

123 TESTIMONY INDEX SECTION PAGE I. INTRODUCTION AND SUMMARY... 1 II. CASE DEVELOPMENT BACKGROUND... III. SIMULATION TOOLS & KEY ASSUMPTIONS... IV. BENEFIT METRICS AND METHODOLOGY... 1 V. ESTIMATING PRICES OF GENERIC WIND PROCUREMENT... QUALIFICATIONS OF JOHANNES P. PFEIFENBERGER PROMOD ASSUMPTIONS & BENEFITS EXTRAPOLATION DETAILS (Exhibit JPP-1) (Exhibit JPP-) DIRECT TESTIMONY i JOHANNES P. PFEIFENBERGER

124 I. INTRODUCTION AND SUMMARY Q. PLEASE STATE YOUR NAME, TITLE, EMPLOYER, AND BUSINESS ADDRESS. A. My name is Johannes P. Pfeifenberger. I am a Principal at the Brattle Group, and I am based in the company s Boston office. My business address is One Beacon Street, Suite 00, Boston MA 0. Q, ON WHOSE BEHALF ARE YOU TESTIFYING? A. I am testifying on behalf of the Public Service Company of Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO). Both PSO and SWEPCO are operating companies of American Electric Power (AEP), jointly the three are the Companies Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? A. My testimony explains the analytical framework and description of the benefits metrics that the Companies used for modeling and analyzing the proposed Wind Catcher Energy Connection Project (Project), which includes the Wind Catcher facility and the Wind Catcher Generation Tie Line. The testimony describes in detail the cases modeled, why each case was selected, and the key assumptions used in the PROMOD simulations. I describe the PROMOD tool, how PROMOD simulation results were transferred for use in the Companies PLEXOS simulation, and why both modeling tools were used in supporting the Companies analysis, including the differences between the two models and how the two models work together. My testimony then describes the methodology used for the Companies benefit calculations based on the PROMOD and PLEXOS DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

125 simulation results. Finally, I present pricing estimates of power purchase agreements for generic new wind resources in Southwest Power Pool (SPP) regional transmission organization footprint Q. PLEASE DESCRIBE YOUR BACKGROUND, EDUCATION, AND PROFESSIONAL EXPERIENCE AS THEY RELATE TO THIS DIRECT TESTIMONY. A. I am an economist with a background in power engineering and over twenty-five years of work experience in the areas of regulated industries, energy policy, and finance. I received a M.A. in Economics and Finance from Brandeis University and a M.S. in Electrical Engineering with a specialization in Power Engineering and Energy Economics from the University of Technology, Vienna, Austria. I am the author and co-author of numerous articles, reports, and presentations on subject areas related to the economic benefits of transmission investment, planning, market design, and cost allocation. For example, I prepared (with colleagues) the report entitled The Benefits of Electric Transmission: Identifying and Analyzing the Value of Investments that documents the wide range of benefits that can be provided by transmission investments and how these benefits are assessed by the various transmission planning organizations. I have filed testimony before the Federal Energy Regulatory Commission ( FERC or Commission ) on a range of subject areas, including the economic benefits of transmission and renewable generation investments by both vertically-integrated and independent transmission companies. For example, I previously submitted testimony regarding the value of the Path 1 Upgrade in Docket Nos. ER1- and ER1-1, and provided testimony on behalf of ITC Holdings Corp. in Docket Nos. EC and DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

126 EL regarding the potential benefits of strategic transmission projects. I have also provided testimony (with my colleague Samuel Newell) on behalf of RITELine Transmission Development, LLC in Docket No. ER-0 regarding the congestion reduction and related economic and renewable integration benefits associated with the RITELine transmission project spanning from western Illinois to the Indiana-Ohio border within the ComEd and American Electric Power (AEP) zones of PJM Interconnection, L.L.C. I similarly provided testimony (with my colleague Samuel Newell) on behalf of the Atlantic Wind Connection Companies in Docket No. EL-1 regarding the renewable integration, reliability, operational, congestion relief, and other benefits of the Atlantic Wind Connection Project, a proposed offshore high-voltage transmission backbone along the Mid-Atlantic coast to interconnect up to,000 MW of offshore wind generation. In addition, I filed (co-authored with colleagues) comments in response to three Commission notices on regional transmission planning and cost allocation, in Docket Nos. AD1-1, AD0-, and RM-. Further, on behalf of various clients, I have submitted testimonies on transmission tariff design, the costs and benefits of alternative transmission access charge methodologies, and regional transmission organization ( RTO ) scope and configuration issues. I also filed testimony on transmission benefits before a number of state commissions, including in Arkansas, Texas, Louisiana, Mississippi, Wisconsin, and Arizona. For example, I submitted testimony in Wisconsin on behalf of American Transmission Company LLC and ATC Management Inc. in Docket No. 1-CE-1 discussing the economic benefits of the Paddock-Rockdale Transmission Project. DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

127 Exhibit JPP-1 to my testimony contains a more complete description of my qualifications and expert witness experience Q. PLEASE SUMMARIZE YOUR TESTIMONY. A. I worked with the Companies to develop a methodology, consistent with SPP and industry practices, to support PSO and SWEPCO in analyzing the costs and benefits of developing the Project. This methodology, which PSO and SWEPCO utilize for analyzing the proposed Project, allows for assessment of estimated customer cost savings resulting from the Project, and supports comparison of Project costs and benefits relative to the alternative of procuring generic wind in the SPP footprint through power purchase agreements (PPAs). To support this Project alternative, I also estimated the cost of generic wind generation in SPP, which the Companies utilized for comparing the costs and benefits of the proposed Project with a conventional wind procurement alternative. My estimates for the cost of alternative wind procurements in SPP are reasonable and within the range of cost estimates obtainable from public sources tracking such wind generation development costs. The quantification of the costs and benefits of the proposed Project and the generic wind alternative from a PSO and SWEPCO customer perspective is presented by Company witness Kelly Pearce. My testimony addresses only the methodology of this quantification, making the following points: Analytical Framework: To support the Companies benefits and cost evaluation of the Project, I first worked with the Companies to develop an analytical framework based on three market simulation Cases the Base Case, the Project Case, and the Generic Wind Case. The Base Case reflects the baseline approach to meeting the Companies future energy needs without the development or purchase of future wind resources between 01 and 0. The Project Case reflects the development of DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

128 ,00 MW of high-quality Oklahoma panhandle wind generation delivered directly to Tulsa via the proposed kv Gen-Tie. Finally, the Generic Wind Case was developed as an alternative to the Project Case, and reflects the procurement of 1,00 MW of wind generation delivered from multiple projects at various sites across the SPP footprint over SPP s existing and planned regional transmission system. The Companies staff simulated each of these three cases using PROMOD and PLEXOS simulation tools to estimate the production related costs and benefits of each case. The difference of simulated benefits and costs between the Project Case and the Base Case quantifies the net benefits of physically delivering to Tulsa 1,00 MW of high quality wind from the panhandle region of Oklahoma, while the difference between the Project Case and the Generic Wind case identifies the savings that can be realized through the Project relative to purchasing 1,00 MW of generic wind generation with delivery to the SPP system at the wind plants various SPP locations. Key Benefit Metrics and Evaluation Methodology: To analyze the benefits of the Project, I supported the Companies in employing the following benefit metrics: (1) Adjusted Production Cost (APC) Savings, () Additional Congestion & Loss Savings, including Reduced Quantity of Transmission Loss Savings () Wind Curtailment Cost Savings, and () Avoided/Deferred Capacity Cost Savings. 1. APC Savings: Adjusted production costs were first evaluated through the Companies PLEXOS simulations of their future production cost, net of offsystem market purchase costs and off system sales revenues, for all three cases analyzed. To evaluate APC savings, the difference in APCs between two relevant cases were calculated.. Additional Congestion & Loss Savings: The Project, with its dedicated Gen-Tie to Tulsa, can avoid the potentially significant future congestion charges between wind sites and the Companies load that would be incurred in the Generic Wind Case. The extent to which wind-generation-related congestion costs incurred in the Generic Wind Case can be avoided in the Project Case, will be a benefit in addition to the APC savings estimated in the PLEXOS simulations. Additionally, the Project avoids marginal-loss-related costs relative to the Generic Wind Case, DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

129 and reduces the quantity of transmission system losses because of differences in the electrical proximity between the wind sites and the operating company loads. These benefits need to be added to the APC savings because the Companies PLEXOS-based APC calculations simply credit hourly wind generation against the Companies load, which is valued at the zonal load price and consequently does not capture the additional congestion- and loss-related costs incurred by injecting generic wind at more distant, and more transmission constrained locations.. Wind Curtailment Cost Savings: New wind generation connected to SPP s existing transmission system in the future very likely will be subject to economic curtailment during high-wind and low-load hours. Curtailed wind outputs require the replacement of the curtailed energy through energy purchases at market prices, imposing a curtailment-related cost on off-taking utilities. This curtailment cost would be especially pronounced in the Generic Wind Case, lacking direct delivery to the Companies load. Differences in expected curtailment costs between the Generic Wind and the Project Case had to be evaluated as an additional benefit to the Project because the cost of curtailments is not reflected in the PLEXOS-based APC calculations.. Avoided/Deferred Capacity Cost Savings: Both the Project and the Generic Wind Cases will reduce the Companies future resource adequacy requirement by a capacity value of up to 1% of the installed generating capacity of the wind resources. This capacity-value benefit, which is not captured in production cost simulations and the associated APC calculations, was quantified as avoiding or deferring the construction of gas-fired generating capacity that would otherwise be needed to meet the future resource adequacy needs of the companies. This additional benefit will exist for both the Project Case and the Generic Wind Case relative to the Base Case. Details on Market Simulations: The Companies performed simulations of future market performance of all three cases using both PROMOD and PLEXOS to assess the benefits of the Project. Both simulation tools are widely used and accepted in the DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

130 industry. The PROMOD datasets used for this analysis were originally developed by SPP and its stakeholders in 01 1 for SPP s 01 ITP transmission planning studies, and reflect expected SPP-wide future system conditions in years 00 and 0. The PROMOD simulations were necessary to assess the extent to which locational wholesale power prices, congestion costs, and marginal-loss-related costs are affected by the proposed 1,00 MW wind development. However, because SPP s PROMOD model, which simulates locational prices for the entire SPP footprint and neighboring systems, does not contain sufficient detail to analyze customer costs for the individual Companies over the 01 0 evaluation period, the companies employed PLEXOS simulations that are already set up for this purpose. Relying on PLEXOS enabled simulations to assess changes in production costs, market purchase costs, off-system sales revenues, and other customer cost items at the operatingcompany level also facilitated the simulation of customer impacts for the entire 01 0 evaluation period. However, unlike PROMOD, the Companies PLEXOS model is not set up for simulating transmission constraints and marginal losses and their effect on locational pricing in the SPP footprint, which required reliance on PROMOD as explained further in Section III of this testimony. Estimation of PPA Prices for Generic Wind: To assess the benefits of the Project relative to the Generic Wind alternative, it was necessary to estimate the likely pricing of PPAs that would be incurred by the companies in the Generic Wind Case. To perform this analysis, I estimated the levelized costs of new wind resources in SPP by relying on publicly-available information of overnight capital costs and related data for the construction of wind generation in the SPP region. Specifically, I relied on the U.S. Energy Information Administration s 01 Annual Energy Outlook (AEO) report, which reports both cost and operating characteristics of new generating technologies by region. My calculations resulted in a levelized cost of wind energy of $1./MWh in 01, escalating at.% annually for years. This estimate is consistent with the range of PPA pricing of wind generation in SPP as reported in a number of public sources. DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

131 II. CASE DEVELOPMENT BACKGROUND Q. PLEASE DESCRIBE THE ANALYTICAL FRAMEWORK EMPLOYED FOR BENEFITS EVALUATION OF THE PROJECT. A. To support the Companies benefits and cost evaluation of the Project, I worked with AEP to develop an analytical framework comprised of three main Cases of alternative resource procurement paths. The first case, which represents the baseline case, assumes no new development or purchase of wind resources between 01 and 0. This Base Case reflects an approach to meeting future energy needs of the Companies without additional wind generation. My second case the Project Case reflects the development of the Project. As explained by Companies witness Kelly Pearce in his prepared direct testimony, the Project consists of high quality wind resources in the Oklahoma panhandle that would deliver 1,00 MW and approximately. TWh of energy annually to Tulsa over a dedicated kv Gen-Tie. The Project is proposed to begin operation by December 00. In addition to the Project Case and the Base Case, the Company evaluated a third alternative the generic wind procurement alternative, entitled Generic Wind Case. The Generic Wind Case reflects the procurement of 1,00 MW of wind generation from multiple projects across the entire SPP footprint over SPP s existing and planned regional transmission system. DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

132 Figure 1 below summarizes these cases. Figure 1: Case Description Case Wind MW at Point of Delivery to SPP System Annual Energy at Point of Delivery to SPP System Point of Delivery to SPP System Mode of Delivery from Wind Sites to AEP Load Base Case Project Case 0 MW. TWh Tulsa kv system Dedicated kv Gen- Tie to Tulsa, and SPP s transmission system from Tulsa to rest of SPP's AEP load zone Generic Wind Case 0 MW.0 TWh At different wind sites across SPP system SPP s Bulk Transmission system from wind sites to SPP's AEP load zone The difference of costs between the Project Case and the Base Case quantifies the benefits of physically delivering to Tulsa 1,00 MW of high-quality wind generation from the panhandle region of Oklahoma. The difference between the Project Case and the Generic Wind case identifies the savings the Companies can realize through the Project relative to purchasing 1,00 MW of wind generation delivered to the SPP system at the wind plants various locations. Each of these three cases was first simulated by the Companies, using the 00 and 0 PROMOD models that SPP and its stakeholders had developed for the 01 ITP 1 transmission planning process, 1 to estimate future SPP locational prices (including 1 1 congestion and marginal losses) at the Companies load zone, conventional generation resources, and wind generation resources. The Companies then used these locational price 1 01 ITP Modeling Assumption p. 0 of Final Report accessed here: DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

133 data as inputs for their PLEXOS market simulations to estimate costs and benefits. For each of the three simulation cases, I relied on the locational price results obtained from the PROMOD simulations for 00 and 0 to first interpolate locational pricing results for the 01 0 portion of the evaluation period. I then extrapolated the PROMOD-based locational pricing results for 0 to the 0 0 portion of the evaluation period based on the Companies long-term fundamental forecast between 0 and 0. With these locational pricing data as inputs, PLEXOS was then employed to evaluate production cost savings and the impact of estimated SPP congestion and loss charges over the -year evaluation period, commencing in 01. Note that the estimated congestion and loss charges reflected in the PLEXOS cost-of-service calculations are based on inputs from PROMOD simulation results. It is important to note that the 00 PROMOD simulations with 1,00 MW of wind (both in the Project Case and the Generic Wind Case) was utilized only to interpolate 01 0 pricing estimates, recognizing that the proposed wind generation is planned to become operational only in December III. SIMULATION TOOLS & KEY ASSUMPTIONS Q. PLEASE DESCRIBE THE PROMOD SIMULATION TOOL. A. PROMOD is a widely-used and universally-accepted market simulation tool, primarily employed for forward-looking locational market simulations. PROMOD simulations are premised on a competitive wholesale electricity market and the tool is used by SPP to simulate chronological hourly dispatch of the entire SPP footprint and neighboring markets subject to transmission constraints for the assumed market conditions. The DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

134 PROMOD simulations, like other similar models, need to make certain simplified assumptions about market conditions that tend to lead to somewhat conservative results with respect to market price fluctuations and congestion levels. For example, PROMOD simulations assume that all resources bid their variable costs, that only the normal generation outage patterns will occur, and that no transmission outages would occur in the simulated years. The main outputs of the PROMOD market simulation is the locational marginal price (LMP) for energy at various pricing nodes on the SPP system. PROMOD outputs also include the hourly marginal congestion cost and marginal loss charge components of the LMP for each pricing node Q. PLEASE DESCRIBE THE PROMOD DATASET DEVELOPED BY SPP AND HOW IT IS USED. A. SPP employs PROMOD simulation for its transmission planning and economic studies (ITP studies) as well as for transmission benefits review assessments performed as part of its Regional Cost Allocation Review (RCAR) studies. These PROMOD models developed for SPP s 01 ITP reflect expected future system conditions in 00 and 0, reflecting all SPP-planned and -approved transmission projects as well as planned and/or needed future capacity resources, including wind resources at levels and locations that SPP and its stakeholders have deemed most feasible for development by 00 and 0. Note, however, while the SPP PROMOD simulates prices and production costs for all of SPP s transmission zones, including the AEP zone, the model does not contain sufficient detail to analyze the costs for the individual Companies (PSO and SWEPCO), nor does it contain enough detail to analyze how certain costs and revenues would be shared between PSO, SWEPCO, and their customers. DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

135 Q. WHAT WERE THE KEY ASSUMPTIONS USED IN THE PROMOD SIMULATIONS AS THEY RELATE TO THIS PROJECT? A. The Companies PROMOD simulations began with the SPP s 01 ITP base PROMOD models, but with a few modifications to its key assumptions. The key assumptions, including modifications made, are summarized below. I have described additional details relating to these assumptions in my prepared Exhibit PROMOD Assumptions and Benefits Extrapolation Details (Exhibit JPP-). SPP Future Analyzed: The Companies employed 01 ITP models that reflected SPP s Future a future that assumed no pricing on carbon emission by thermal generation resources. Future Wind Resources: SPP s Future base models included approximately 00 MW and 00 MW of new future wind resources in SPP s AEP zone in 00 and 0 respectively. The Companies modified this assumption to retain only 00 MW in each year, to reflect inclusion of only planned wind procurement by PSO and SWEPCO. Throughout the SPP footprint, the SPP base models add,0 MW of new wind generation between 01 and 00 and an additional 0 MW of new wind by 0, for a total of 1,00 MW of existing and new wind installed by 0. Future Capacity Needs: To meet projected reserve margin requirement, SPP s base models assumed development of new combined cycle and combustion turbine generating resources in several of its zones, including in the AEP zone. The Companies PROMOD simulation of the Project Case and the Generic Wind Case modified these assumed future capacities slightly to reflect the capacity value of the 1,00 MW of new wind. Gas Prices: SPP s Future base PROMOD models assumed an annual average natural gas price of $.0/MMBtu in 00 and $./MMBtu in 0. The Companies PROMOD simulations modified this assumption by updating the gas price inputs to reflect those of the Companies longterm Fundamental Forecast for the commodity. Company witness Karl Bletzacker provides additional details on these long-term fundamental forecasts of natural gas prices. Provided by the companies based on review of SPP s 01 ITP PROMOD Models for 00 and 0 DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

136 The Companies New Wind Resources: As described above, the companies modeled 1,00 MW of new wind generation delivered to the companies in the Project Case and the Generic Wind Case, and no new wind generation in the Base Case. The Project Case, additionally included a new kv Gen-Tie connecting the Companies contemplated Oklahoma panhandle wind generation to PSO s existing Tulsa North kv substation. In the Generic Wind Case, to model 1,00 MW of wind generation delivered to the companies at existing SPP points of interconnection, the Companies PROMOD simulations used the full range of wind locations that SPP and its stakeholders had assumed to be feasible and likely interconnection locations for such future wind. There were such locations in Oklahoma, Kansas, Missouri, and Nebraska as shown in Figure below. The SPP-assumed new wind generating resources at these locations were scaled up for the Generic Wind Case to add 1,00 MW of additional purchases. Figure : New Wind Procurement Locations in the Generic Wind Case 1 0 Source: SPP s 01 ITP Report DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

137 Q. PLEASE EXPLAIN IN MORE DETAIL THE PURPOSE OF EMPLOYING BOTH PROMOD AND PLEXOS. A. Both PROMOD and PLEXOS are simulation tools that can be employed to perform the type of forward-looking market simulations necessary to assess the benefits of the Project. However, in this case both simulation tools had to be utilized for a number of reasons. First, the Companies have historically relied on PLEXOS for analyzing the market performance of their resources and for evaluating their expected market revenues and dispatch outcomes for resource planning purposes. Relying on PLEXOS has several advantages. The model is already set up to simulate several years of future market performance quickly and to link and provide input to the customer rate impact assessments, for the Companies. Most importantly, unlike PROMOD, the Companies PLEXOS model is set up to simulate PSO and SWEPCO individually, and therefore is able to assess changes in production costs, market purchase costs, off-system sales revenues, and other customer cost items at the operating-company level. Unlike PROMOD, however, the Companies PLEXOS model is not set up to simulate the entire SPP footprint and does not simulate transmission constraints or marginal losses, which means it is unable to assess the extent to which wholesale power prices, congestion costs, and marginal-loss-related costs are affected by the proposed 1,00 MW wind generation development. In contrast, SPP s PROMOD models simulate the entire SPP system (and surrounding market areas), including the full SPP transmission network and associated transmission constraints and marginal losses. Transmission constraints have a significant DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

138 effect on optimal SPP-wide market dispatch outcomes and the associated locational marginal prices. Given the large additions of wind generation, it is important to capture these effects of the transmission network on locational prices when evaluating the costs and benefits of the Project and its potential alternatives. Unfortunately, the region-wide and locational simulations undertaking in the SPP PROMOD cases makes it computationally challenging and time consuming to analyze more than a few years the main reason why SPP has produced PROMOD cases for only two future years: 00 and 0. SPP s PROMOD model is further limited by the fact that it has been set up to analyze cost impacts only for individual SPP transmission zones such as the AEP zone, which aggregates both AEP companies (PSO and SWEPCO) as well as other public power entities and without the level of detail that is required to separately assess impacts on customer rates of the two companies. Therefore, to assess the present value of future benefits of the Project and its two alternatives, over the entire -year horizon from 01 through 0 and for each of the two companies, PLEXOS was employed in conjunction with SPP s PROMOD models to capture the impact on the individual operating companies as well as the impact of the additional wind generation on the transmission system and the associated locational marginal prices. DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

139 Q. DESCRIBE HOW PROMOD SIMULATION RESULTS WERE USED AS INPUTS FOR THE COMPANIES PLEXOS SIMULATIONS. A. To properly evaluate the full benefits of each case analyzed, the Companies had to employ PROMOD in conjunction with PLEXOS for performing forward-looking market simulations. To facilitate these simulations, I performed several data processing tasks that involved preparing PLEXOS inputs from relevant outputs of the PROMOD simulations for 00 and 0. I summarize below the data processing tasks I performed on PROMOD outputs for each of the three cases analyzed. Details are provided in PROMOD Assumptions and Benefits Extrapolation Details (Exhibit JPP-) Monthly Average Peak, Weekend, and Night Prices: As illustrated in Figure below, I processed PROMOD s hourly prices from the 00 and 0 simulations to evaluate monthly, generation-weighted average prices for PSO s and SWEPCO s thermal units, and load-weighted average prices for the PROMOD defined AEP SPP zone. I calculated these averages for three different timedefinitions Weekday Peak, Weekend Peak, and Night. These generation and load prices are the standard price inputs used by the Companies for its PLEXOS simulations.. Monthly Prices for 01 through 0: Since PROMOD markets simulations were performed only for 00 and 0, I interpolated monthly prices for the intervening years by straight-lining between the PROMOD-based prices, and extrapolated 0 monthly PROMOD-based prices using the Companies fundamental forecast for the Around-the-Clock ( ATC ) prices to 0.. Congestion, Marginal Losses and Wind-Curtailment Charges for 01-0: I evaluated the monthly congestion and marginal loss charges associated with PSO s and SWEPCO s existing and new wind generation resources by calculating PROMOD-simulated congestion and loss differences between wind locations Time Definitions are as follows: Weekday Peak = am to pm, Monday through Friday; Weekend Peak = am to pm on Saturday and Sunday, and on NERC Holidays; Night = pm to am on seven days of the week, including NERC holidays The net loss charges for each operating company was estimated as one-half the marginal loss component differences between wind and load locations to reflect the refund of surplus marginal loss congestion revenues, consistent with the theoretical 1/ relation between average and marginal losses. DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

140 and SPP s AEP zonal load, and applying those per-mwh congestion and loss charges to the hourly output from each wind site. I then calculated congestion and loss charges on a monthly basis for each operating company. Additionally, I assumed that on average about % of the annual expected wind energy that could be produced by new wind generation resources in the Generic Wind Case would be curtailed due to limitations on the SPP transmission system. I evaluated a monthly cost associated with such curtailments by using specific PROMODbased load prices. Note that while the estimated congestion, marginal losses, and curtailment charges I calculated utilized PROMOD simulation outputs, these charges are integrated into the Companies PLEXOS-based cost of service calculations by the Companies, and thus are reflected in the overall PLEXOS quantification of costs and benefits of the Project. It was necessary to evaluate congestion, losses, and curtailment charges using PROMOD outputs because the Companies PLEXOS simulations do not include a representation of the SPP s transmission network, and thus are unable to evaluate these important transmission-related charges. The Companies employed their in-house pricing tool to disaggregate the monthly average into the hourly PSO and SWEPCO thermal generation prices and SPP s AEP zone load prices that are used as PLEXOS simulation inputs. The Companies then simulated in PLEXOS the dispatch of PSO and SWEPCO thermal units against these hourly generation prices for each operating company. PLEXOS calculates each operating company s production cost, adjusted for the cost of any off-system market purchases and for the market revenues from sale of any surplus generation. In addition to this calculation of net production costs for PSO and SWEPCO, PLEXOS accounts for the monthly congestion, loss, and curtailment-related costs associated with delivering 1,00 MW of wind generation resources based on the PROMOD-derived inputs. The use of PROMOD and PLEXOS simulations is summarized in Figure below. The % curtailment future assumption is based on my review of the historical curtailment experience in MISO, and ERCOT as discussed in more detail below. DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

141 Figure : Process employed for integrating PROMOD and PLEXOS Simulations Q. PLEASE SUMMARIZE THE METHODOLOGY USED TO INTERPOLATE AND EXTRAPOLATE YEAR 00 AND 0 PROMOD PRICES EMPLOYED IN PLEXOS SIMULATIONS FOR THE -YEAR STUDY HORIZON. A. As I noted above, I began with PROMOD simulation results for prices for 00 and 0. To interpolate and extrapolate these price results to the other years of the 01 0 evaluation period, I employed the following methodology: I began by calculating hourly generation revenue from thermal units for PSO and SWEPCO as simulated by PROMOD. I then aggregated, for each month and each operating company, the total thermal-unit generation revenue and total thermal-unit generation output for three time definitions Weekday Peak, Weekend Peak, and Nights. The aggregated thermal-unit generation revenues divided by the aggregated thermal unit generation output for each month and each set of peak/night hours yielded the monthly generation-weighted average prices for PSO and SWEPCO. DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

142 Similarly, for load prices, I calculated hourly costs to load for the AEP SPP zone in PROMOD, and then aggregated hourly costs to load, and the load MWh for the AEP SPP zone, for each month, by the three defined time frames. I then divided the aggregated costs to load by their corresponding aggregated load MWhs to calculate a load-weighted average monthly load zone price for the three time frames. These computations resulted in twelve monthly average generation prices for each peak/night time frame, for each operating company, for each PROMODsimulated year. It also resulted in twelve monthly average load zone prices for each time frame and each simulation year. The load zone prices used are the same for the two operating companies.. Next, for interpolating the time-differentiated monthly average prices (load and generation prices), I calculated a constant annual growth rate for each month of the year, based on PROMOD outputs for 00 and 0. I then grew the 00 time-defined monthly average prices for PSO and SWEPCO generation, and load by this constant annual growth rate to produce monthly prices for 01 through 0.. For years 0 0, I employed the annual growth rates for each month implied in the Companies long-term fundamentals forecast for monthly Around-The- Clock (ATC) prices, and applied the rate of these price changes to the 0 monthly time-differentiated prices calculated from the PROMOD simulations. Since the Companies analyses include certain gas price sensitivities, I used the Companies sensitivity-specific fundamental forecasts of ATC prices to extrapolate monthly time-differentiated PROMOD based prices.. For congestion, losses, and curtailment costs I employed the same methodology (as outlined in items and above) to interpolate and extrapolate the monthly costs for the 01 0 evaluation period. IV. BENEFIT METRICS AND METHODOLOGY 0 1 Q. DESCRIBE THE BENEFIT METRICS USED IN THIS ANALYSIS. A. The key benefit metrics employed for analyzing the benefits of the Project are described below. The quantifications of these benefit metrics are presented by company witness Kelly Pearce in his prepared direct testimony. DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

143 Adjusted Production Cost (APC) Savings: The Companies PLEXOS simulations evaluate the operating Companies future production costs, net of off-system market purchases and sales of energy, for all three cases analyzed. To evaluate APC savings, it is necessary to calculate the difference in APCs between two relevant cases. This requires that total APC is first calculated for each of the three cases. The Companies estimated these APC savings for (1) the Project Case relative to Base Case; and () the Project Case relative to the Generic Wind Case. These savings are calculated annually based on the PLEXOS simulations for 01 through 0. Company witness Kelly Pearce provides a summary of APC savings resulting from the development of the Project relative to both the Base Case and the Generic Wind Case.. Additional Cost Savings from Reduced Congestion and Transmission Losses: The Project can avoid the potentially significant congestion charges between wind sites and the AEP load zone that would be incurred in the Generic Wind Case. As a result, avoiding these wind-generation-related congestion charges incurred in the Generic Wind Case will be a benefit that is realized in addition to the APC savings estimated in the PLEXOS simulations. This is because the PLEXOS simulations do not consider any congestion charges that are incurred serving the Companies load with the Companies generation. In addition to congestion relief, the Project is expected to reduce SPP marginalloss-related costs relative to the Generic Wind Case because the Project s generation is injected near Tulsa in close proximity to the Companies load. Such loss-related SPP costs can differ between the cases because of differences in the electrical proximity between the wind sites and the operating company loads. Beyond reducing the marginal loss-related charges associated with delivering wind resources to load, the project can also reduce the MWh quantity of transmission losses in the Companies load zone. Standard production cost simulations, such as PROMOD, used to simulate forward-looking market prices (including the charges for transmission losses) hold the MWh quantity of transmission losses constant. This means they do not reflect that delivering large amount of wind energy closer to load in Tulsa may reduce the MWh quantity of transmission losses. As recognized by SPP s Metric Task Force and the Economic Studies Working Group, the additional production cost savings due to such MWh loss reductions can be estimated by postprocessing the Marginal Loss Component (MLC) of the LMPs evaluated and reported in PROMOD simulation results. To estimate this benefit, I employ the methodology developed and used by SPP in the company s PROMOD simulation results. I discuss the details of this benefit metric in Exhibit JPP-.. Reduced Curtailment of Wind Generation: Wind generation connected to SPP s existing transmission system likely will be subject to curtailment during real-time operations with high-wind and low-load hours. Curtailed wind outputs require the replacement of the curtailed energy through purchases at market prices, imposing Losses on the Gen-Tie have been accounted for in the companies analyses by reducing the Project s MWh delivered at Tulsa. See Section pg. 1 of SPP Benefit Metrics Manual, November, 01 for a detailed description of SPP Board approved calculation methodology for evaluating changes in MWh quantity of losses based on the Marginal Loss Component of LMPs DIRECT TESTIMONY 0 JOHANNES P. PFEIFENBERGER

144 curtailment-related costs on the contracting utilities. These curtailment costs would be especially pronounced in the Generic Wind Case, wherein the procured generic wind resources are assumed to be delivered over the SPP transmission system rather than delivered directly to the Tulsa area via the dedicated Gen-Tie. The difference in expected curtailment costs between the Generic Wind and the Project Case is an additional benefit that accrues to the Project.. Capacity Cost Savings: 1,00 MW of delivered wind generation resources, whether developed as Project or procured from generic wind sites, can reduce the Companies resource adequacy requirement by a capacity value of approximately 1% of the installed generating capacity. This capacity-value benefit is quantified as the avoided or deferred construction cost of gas-fired generating capacity that would otherwise be needed to meet the future resource adequacy needs of the Companies. Relative to the Base Case, this capacity value benefit will exist for both the Project and the Generic Wind procurement case. Q. DESCRIBE HOW EACH BENEFIT METRIC WAS CALCULATED IN THIS ANALYSIS. A. The methodologies used for calculating these benefits are summarized below. Company witness Kelly Pearce discusses in more detail, the calculations undertaken for the APC Savings and Capacity Savings benefit metrics. 1. Adjusted Production Cost (APC) Savings: The Companies PLEXOS simulations evaluate the operating Companies future production costs, net of off-system market purchases and sales of energy, for all three cases analyzed annually for Savings are calculated as the difference between APC costs incurred in cases under comparison.. Additional Cost Savings from Reducing Congestion and Transmission Losses: These savings are evaluated by using PROMOD-based hourly congestion and marginal loss spreads between wind sites and SPP s AEP zone load in 00 and 0, and the contemporaneous wind generation outputs. For evaluating transmission losses, I used marginal loss pricing spreads between generation and load in SPP s AEP zone, as well as the loss components associated with purchases imported into the AEP zone. The congestion- and loss-related costs are then aggregated on a monthly basis and interpolated/extrapolated between 01 and 0 using the same methodology as described for prices previously. These monthly congestion and loss charges are then integrated into the Companies PLEXOS-based cost-of-service calculations. Similar to the APC savings, congestion and loss related savings are calculated as the difference between the costs incurred in each case under comparison. DIRECT TESTIMONY 1 JOHANNES P. PFEIFENBERGER

145 Reduced Curtailment of Wind Generation: Evaluated by applying the contemporaneous monthly average load price (from PROMOD) on an assumed curtailment of % of total annual production of Generic Wind, occurring in the night hours of five select months March, April, October, November, and December. The difference in curtailment costs between the Generic Wind Case and the Project Case is an additional benefit that accrues to the Project. The monthly charges for curtailment are integrated into the PLEXOS-based cost-of-service calculations.. Capacity Cost Savings: Evaluated by the Companies as the avoided and/or delayed cost of planned Natural Gas Combined Cycle generation resources that can be avoided or deferred as a result of developing or procuring 1,00 MW of new wind generation resources. Calculations include estimating annual savings in the carrying charge as a result of avoiding or deferring planned capacity resources for the operating companies in the Project Case and the Generic Wind Cases, relative to the Base Case. Q. PLEASE SUMMARIZE THE RESULTS OF PRICES AND BENEFITS EVALUATED BASED ON PROMOD SIMULATIONS A. Applying the methodology outlined above, and using the PROMOD outputs for 00 and 0, I evaluated hourly marginal congestion and loss related costs, transmission loss quantity related costs, and the costs of wind curtailments (applicable only to Generic Wind) for each of the three main cases and the relevant sensitivities analyzed. As explained previously, all benefits are evaluated as the difference in costs incurred in the Project and Base Cases (or the Project and Generic Wind Cases). Figure below provides a summary of the annual average values of the 00 and 0 PROMOD simulation results for the Base Case and the Project Case. The Figure includes a summary of annual average values for time-differentiated locational wholesale marginal prices (Generation LMPs) for PSO and SWEPCO thermal generation resources and for SPP s AEP load zone (which reflects the Load LMP used for both Companies), which are used as inputs for the PLEXOS-based calculations of adjusted production costs presented in company witness Pearce s testimony. Additional details, including summary DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

146 of the PROMOD simulations annual average prices and costs and benefits for the Generic Wind Case are provided in Figure of Exhibit JPP-. Figure : Summary of PROMOD-based Prices and Costs, for Base Case and Project Case in 00 and Base Case Project Case Base Case Project Case Annual Average Weekday-Peak Load LMP ($/MWh) $. $. $. $. Annual Average Weekend-Peak Load LMP ($/MWh) $. $. $. $. Annual Average Night Load LMP ($/MWh) $.0 $. $0. $. Annual Average Weekday-Peak PSO Gen LMP ($/MWh) $. $. $. $1.1 Annual Average Weekend-Peak PSO Gen LMP ($/MWh) $.1 $. $. $.00 Annual Average Night PSO Gen LMP ($/MWh) $. $0. $. $.0 Annual Average Weekday-Peak SWEPCO Gen LMP ($/MWh) $. $. $. $.1 Annual Average Weekend-Peak SWEPCO Gen LMP ($/MWh) $. $.0 $0.1 $. Annual Average Night SWEPCO Gen LMP ($/MWh) $. $.1 $0. $0. Annual Congestion Cost for Wind ($million) $ $ $0 $ Annual Loss Cost for Wind ($million) $1 $ $1 $0 Annual Transmission Loss Quantity Related Costs ($million) - $0. - ($1.) Notes: 1. Figure shows prices and costs incurred for Base Case and Project Case.. Reduced Transmission Loss Quantity benefit metric evaluated using SPP methodology, which directly evaluates the difference between two cases under comparison. Negative value in figure above (for Project Case in 0) reflects the cost reduction associated with the reduced quantity of transmission losses for the Project Case relative to Base Case. Q. WHY DID YOU SEPARATELY ESTIMATE FUTURE WIND CURTAILMENT LEVELS AS OPPOSED TO RELYING ON THE PROMOD SIMULATIONS OF SUCH CURTAILMENTS? A. As explained earlier, PROMOD simulations are based on somewhat simplified assumptions that do not fully capture real-world market outcomes. From a wind curtailment perspective, the most impactful simplifying assumption is that PROMOD is DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

147 based on deterministic inputs for all operating conditions, meaning that it is implicitly assumed that market operators would have perfect foresight of actual system conditions when they make generation unit commitment decisions on a day-ahead basis. This, however, ignores the considerable uncertainty that exists with respect to load and wind generation and makes the PROMOD simulations more akin to a day-ahead market. Just as there are very few wind curtailments scheduled on a day-ahead basis, PROMOD simulations yield very few wind curtailments. Under actual operating conditions, such curtailments do however exist in the real-time market. Because PROMOD does not simulate the uncertainties associated with real-time market conditions, a realistic level of real-time wind curtailments has to be added to the PROMOD simulation results. On a related note, another simplified assumption is the fact that PROMOD simulations are based on a fully-intact transmission system with transmission constraints defined such that the system would remain reliable for some period of time even if there was an outage on a major transmission line. In other words, the constraints simulated are based on N-1 contingency conditions defined by SPP for planning assessments. The simulations, however, do not consider any actual transmission outages which would 1 create more severe transmission constraints based on N- contingency conditions. Not simulating actual transmission outages understates estimated congestion charges, which means that the simulated congestion costs associated with generic wind developments will be a conservative estimate. N-1 contingency condition refers to a grid planning and design criteria which allows for the outage of one transmission element of the bulk transmission system. At a minimum, networked transmission systems are designed to withstand the outage of any one transmission element. In other words, the transmission network is designed so that it will not get overloaded even if there is an outage on a major transmission line. Once such an N-1 condition occurs, the rest of the system needs to be operated at lower throughput such that it can remain reliable and dynamically stable if a second transmission line were subject to outage (i.e., creating an N- condition). DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

148 Q. PLEASE DESCRIBE YOUR ASSUMPTIONS FOR ESTIMATING ANTICIPATED FUTURE WIND GENERATION CURTAILMENT LEVELS. A. To determine a reasonable estimate of anticipated future wind generation curtailment, I first reviewed historical annual wind generation curtailment data in SPP and other RTOs. SPP s historical curtailment data indicates that economic curtailments of wind generation in SPP thus far have been low: around 1% to % annually. However, historical curtailment levels in neighboring regions that have experienced more significant growth in wind generation Electric Reliability Council of Texas ( ERCOT ) and western MISO have averaged around % annually between 00 and 01. ERCOT, for example, has experienced very high curtailment reaching up to 1% in 00. Wind curtailment levels in MISO have been relatively less varied (see Figure ) but have also averaged around % during the same period. Because SPP is currently in the midst of a similar build-out of wind resources, with significant levels of new wind generation expected between now and 01, I assumed that SPP average curtailment levels in the Generic Wind case will rise to the average levels similar to those experienced in ERCOT and MISO historically. DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

149 Figure : Historical Estimate of Wind Curtailment by Region Source: 01 Wind Technologies Market Report (Figure 1 on p. 1) V. ESTIMATING PRICES OF GENERIC WIND PROCUREMENT Q. PLEASE DESCRIBE HOW YOU ESTIMATED THE PRICES OF GENERIC FUTURE WIND PROCUREMENTS IN SPP. A. To estimate the likely PPA pricing of wind generation that would be incurred in the Generic Wind Case, I estimated the levelized costs of new wind resources developed in SPP. To undertake this analysis I relied on the U.S. Energy Information Administration s 01 AEO report, which covers both cost and performance characteristics of new generating technologies by region. The 01 AEO reported the total overnight costs of on-shore wind resources in the SPP South region, available for operation as of 01, as $1,/kW. I use this overnight cost as a reasonable proxy for the 01 wind additions assumed in the Generic Wind Case. Additionally, I used AEO-reported fixed O&M of $/kw-year estimate (nominal$) for on-shore wind, and assumed an annual price escalation rate of.%. I also assumed an average capacity factor of % for the DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

150 generic wind as a reasonable estimate based on my review of NREL s wind capacity factor data for locations across SPP. As NREL data indicates, wind generation capacity factors can vary significantly across SPP, averaging around % at the sites used by SPP to model generic wind resources in PROMOD. Because SPP s ITP PROMOD model used the 01 data set from NREL and newer technologies have continued to increase average capacity factors, I assumed a higher % capacity factor as a more reasonable estimate. The financial assumptions to estimate the levelized cost of energy (increasing at.% a year in nominal terms) are summarized in Figure below. Figure : Financial Assumptions for Estimating the Levelized Cost of Generic Wind Economic Life of Asset Years Equity Capitalization 0% Cost of Equity 1.0% Cost of Debt % Marginal Tax Rate.0% Tax Depreciation Schedule yr MACRS Production Tax Credit in 01 $/MWh Q. WHAT PRICING ESTIMATE DID YOUR CALCULATIONS YIELD, AND IS IT REASONABLE? A. My calculations resulted in a levelized cost of wind energy of $1./MWh in 01, escalating at.% annually for years. I believe that this is a reasonable estimate for pricing of new wind generation resources in SPP. For reference, the most recent estimates from Lazard s Levelized Cost of Energy Analysis, shows the levelized costs for wind (when able to take advantage of production tax credits) range from $1/MWh to Provided by the companies based on SPP s 01 ITP PROMOD Models for 00 and 0 DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

151 $/MWh across the country. Within that range, the U.S. Department of Energy s 01 Wind Technologies Market Report reported that the average wind PPA prices (averaged by PPA execution date) for the Interior region of the nation had steadily trended down, with a 01 average executed price of around $1/MWh as shown in Figure below. Figure : Historical Average of Wind PPA Prices Source: 01 Wind Technologies Market Report (Figure on p. ) Q. DOES THIS CONCLUDE YOUR TESTIMONY? A. Yes, it does. Lazard s Levelized Cost of Energy Analysis version.0 accessed here: DIRECT TESTIMONY JOHANNES P. PFEIFENBERGER

152 EXHIBIT JPP-1 Page 1 of 1 QUALIFICATIONS OF JOHANNES P. PFEIFENBERGER Johannes Pfeifenberger is a Principal of The Brattle Group where he is a member of the firm s Utility Regulation and Electric Power practices. He received a M.A. in Economics and Finance from Brandeis University and holds a M.S. ( Diplom Ingenieur ) in Electrical Engineering, with a specialization in Power Engineering and Energy Economics from the University of Technology in Vienna, Austria. Prior to joining The Brattle Group in, Mr. Pfeifenberger was a consultant with Cambridge Energy Research Associates of Cambridge, Massachusetts, and a research assistant at the Institute of Energy Economics in Vienna, Austria. TESTIMONY AND REGULATORY FILINGS Before the Federal Energy Regulatory Commission, Docket No. AD , Comments of Mr. Johannes P. Pfeifenberger and Ms. Judy Chang Regarding Competitive Transmission Development Technical Conference, October, 01. Before the Cour Supérieure, Province de Québec, District de Montréal, Canada, Case No , Expert Report of Johannes Pfeifenberger: CF(L)Co s Sales of Interruptible Power, in Hydro Québec vs. Churchill Falls (Labrador) Corporation Limited, April 1, 01. Before the National Energy Board, Canada, Filing A01, Market Assessment Report, Annex to ITC Lake Erie Connector LLC (ITC or ITC Lake Erie) Application for an Election Certificate for the Lake Erie Connector Project, May, 01. Before the Missouri Public Service Commission, File No. EA-01-00, Wind Integration Analysis for the Grain Belt Express HVDC Line, report on behalf of Clean Line Energy Partners, April 1, 01. Before the Federal Energy Regulatory Commission, Docket No. ER , re PJM Interconnection, LLC, Affidavit of Johannes P. Pfeifenberger and Bin Zhou, November, 01. Attachment B to Answer of PJM Interconnection, L.L.C. to Protests and Comments, November, 01. Before the Federal Energy Regulatory Commission, Docket No. ER1--0, EL (Not consolidated), re ISO New England Inc., Affidavit of Johannes P. Pfeifenberger, November, 01, Attachment A to Brookfield Energy Marketing LP s Protest and Motion to Intervene, November, 01. Before the Federal Energy Regulatory Commission, Docket Nos. ER1- and ER1-1, re DATC Path 1, Prepared Direct Testimony of Johannes P. Pfeifenberger on behalf of DATC Path 1 LLC, February 1, 01. Before the State of Maine Public Utilities Commission, Docket No re: Maine Public Utilities Commission Investigation into Reliability of Electric Service in Northern Maine, Testimony and Exhibits of Judy Chang and Johannes Pfeifenberger on behalf of Maine GenLead, LLC August, 01; Supplemental Testimony of Judy Chang and Johannes Pfeifenberger, January 1, 01.

153 EXHIBIT JPP-1 Page of 1 Before the Federal Energy Regulatory Commission (Docket Nos. EC and EL , Exhibit No. ITC-00), the Louisiana Public Service Commission (Docket No. U-), the Council of the City of New Orleans (Docket No. UD-1-01), the Arkansas Public Service Commission (Docket No. 1-0-U), the Mississippi Public Service Commission (01-UA- ), and the Public Utilities Commission of Texas (Docket No. 1), Direct, Rebuttal, and Sur-Rebuttal (CNA and Arkansas) Testimonies of Johannes Pfeifenberger on behalf of ITC Holdings re: ITC s acquisition of the Entergy Transmission System, September 01 August 01. Before the Federal Energy Regulatory Commission, Docket No. EL1-, Affidavit of Johannes Pfeifenberger on behalf of Hudson Transmission Partners, LLC re: NYISO capacity market offer mitigation, filed August, 01. Before the Federal Energy Regulatory Commission, Docket No. EL-0, Affidavit and Reply Affidavit of Johannes Pfeifenberger on behalf of NRG Energy re: NYISO capacity market offer mitigation, filed September and October, 0. Before the Federal Energy Regulatory Commission, Docket Nos. ER-0 and ER-00, Direct Testimony of Johannes Pfeifenberger and Samuel Newell on behalf of the RITELine Companies re: the Public Policy, Congestion Relief, and Economic Benefits of the RITELine Transmission Project, filed July 1, 0. Before the Alberta Utilities Commission, Application, Proceeding ID 1, Rebuttal Testimony on behalf of AltaLink Management Ltd re: Treatment of Construction Work in Progress, filed April, 0. Before the Federal Energy Regulatory Commission, Docket No. RM--000, Filed Comments re: Notice of Proposed Rulemaking on Planning Resource Adequacy Assessment Reliability Standard, December, 0 (with K. Carden and N. Wintermantel). Before the Federal Energy Regulatory Commission, Docket No. No. EL-1-000, Direct testimony of Johannes Pfeifenberger and Samuel Newell on behalf of The AWC Companies re: the Public Policy, Reliability, Congestion Relief, and Economic Benefits of the Atlantic Wind Connection Project, filed December 0, 0. Before the Maryland Public Service Commission, Administrative Docket PC, Filed Comments In the Matter of the Reliability Pricing Model and the 01/01 Delivery Year Base Residual Auction Results, October 1, 0 (with K. Spees). Before the Federal Energy Regulatory Commission, Docket No. RM--000, Filed Comments re: Notice of Proposed Rulemaking on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, September, 0 (with P. Fox-Penner and D. Hou). In the United States District Court for the Eastern District of Pennsylvania, Case No. 0-cv- -NS, Expert Report on behalf of PJM Interconnection LLC re: hedge fund trading activities of financial transmission rights, February, 0. American Arbitration Association, AAA No , General Electric International, Inc. vs. Project Orange Associates, LLC; Expert Report and Oral Testimony on behalf of

154 EXHIBIT JPP-1 Page of 1 General Electric International re: Operating Agreement Dispute, October 1, 00 and January, 0. Before the Federal Energy Regulatory Commission, Docket No. AD0--000, Filed Comments re: regional transmission planning and cost allocation, December 1, 00 (with P. Fox-Penner and D. Hou). Before the Missouri Public Utilities Commission, Case No. ER-0-00, Direct Testimony on Interim Rates on Behalf of AmerenUE, October 0, 00. Before the Maine Public Utilities Commission, Docket No. 00-1, Assessment of a Maine ISA Structure as a Possible Alternative to ISO-NE Participation, Report and Oral Testimony on behalf of Central Maine Power Company and the Industrial Energy Consumer Group, May 00. Before the Public Service Commission of Wisconsin, Docket 1-CE-1, Direct Testimony on behalf of American Transmission Company re: transmission cost-benefit analysis, January 1, 00. Before the Missouri Public Utilities Commission, Case No. EO-00-00, Rebuttal, Supplemental Rebuttal, and Surrebuttal Testimony on behalf of Midwest Independent Transmission System Operator, Inc. re: Aquila RTO cost-benefit analyses, November 0, 00, December, 00 and February, 00. Before the Maine Public Utilities Commission, Docket No. 00-1, An Assessment of Retail Rate Trends and Generation Costs in Maine, Whitepaper filed on behalf of Independent Energy Producers of Maine, September, 00 (with A. Schumacher). Before the Public Service Commission of Wisconsin, Docket 1-CE-1, Planning Analysis of the Paddock-Rockdale Project, report by American Transmission Company re: transmission cost-benefit analysis, April, 00 (with S. Newell and others). Before the Alberta Energy and Utilities Board, Proceeding No. 1, submission on behalf of AltaLink Management Ltd. re: Benchmarking the Costs and Performance of Utilities using a Uniform System of Accounts, October 00 (with C. Lapuerta). Before the Arizona Power Plant and Transmission Line Siting Committee, Docket No. L A , Case No., Oral Testimony on behalf of Southern California Edison Company re: economic impacts of the proposed Devers-Palo Verde No. transmission line, September and October, 00. Before the Federal Energy Regulatory Commission, Docket No. EL , Affidavit and Rebuttal Affidavit on behalf of WPS Resources Corporation re: benefits of implementing a joint and common market across the MISO-PJM service areas, August 1 and October, 00. Before the Maine Public Utilities Commission, Docket No. 00-, Direct Testimony and Surrebuttal on behalf of Penobscot Energy Recovery Company re: retail rate structure for station-use distribution service, June and September, 00. Before the Colorado Public Utilities Commission, Docket No. 0S-EG, Direct Testimony on behalf of Public Service Company of Colorado re: purchased power rate adjustment mechanisms and imputed debt of purchased power, April 1, 00.

155 EXHIBIT JPP-1 Page of 1 In the Matter of Binding Arbitration Between La Paloma Generating Trust, Ltd, as Revocably Assigned to La Paloma Generating Company, LLC, v. Southern California Edison Company, JAMS CASE NO. 01, Direct and Rebuttal Testimony on behalf of Southern California Edison re: Power Contract Dispute, June and July 00. Before the Federal Energy Regulatory Commission, Docket No. EC0--000, Affidavit and Supplemental Affidavit on behalf of Ameren Services Company re: Exelon Corporation and Public Service Enterprise Group Incorporated, Joint Application for Approval of Merger, April and May, 00 (with P. Fox-Penner). Before the Illinois Commerce Commission, Docket Nos. 0-, et al., Direct Testimony on Behalf of Central Illinois Light Company, Central Illinois Public Service Company, and Illinois Power Company re: Competitive Procurement of Retail Supply Obligations, February, 00. Before the Federal Energy Regulatory Commission, Docket Nos. ER et al., Prepared Supplemental Testimony on Behalf of the Michigan Utilities re: Financial Impact of ComEd's and AEP's RTO Choices, December 1, 00 (with S. Newell). Before the Federal Energy Regulatory Commission, Docket Nos. ER0--00 et al., Declaration re: Financial Impact of ComEd s and AEP s RTO Choices on Michigan and Wisconsin, August 1, 00; Prepared Direct and Answering Testimony on Behalf of the Michigan-Wisconsin Utilities, September 1, 00 (with S. Newell). Before the Federal Energy Regulatory Commission, Docket No. ER , California Independent System Operator Corporation, Direct Testimony and Rebuttal Testimony on Behalf of the California Independent System Operator re: Redesign of Transmission Access Charges, February 1, 00 and October, 00. Before the Federal Energy Regulatory Commission, Docket No. ES0--000, Midwest Independent Transmission System Operator, Inc., Prepared Direct Testimony on Behalf of the Midwest Independent Transmission System Operator re: Rate Design for ISO Administrative Cost Recovery, September, 00. Before the Federal Energy Regulatory Commission, Docket No. RT , Midwest Independent Transmission System Operator, Inc., Affidavit on Behalf of the Midwest Independent Transmission System Operator re: Inter-RTO Coordination, August 1, 001 (with P. Fox-Penner). Before the Public Service Commission of the State of Missouri, Case No. EM--1, White Paper on Incentive Regulation: Assessing Union Electric s Experimental Alternative Regulation Plan, on behalf of Ameren Services Company, February 1, 001 (with D. Sappington, P. Hanser, and G. Basheda). Before the Federal Energy Regulatory Commission, Docket No. ER , California Independent System Operator Corporation, Testimony before Settlement Judge on behalf of the California ISO re: Redesign of Transmission Access Charges, July 1 and August, 000. Before the State of New York Public Service Commission, In the Matter of Customer Billing Arrangements, Case -M-01, Affidavit on behalf of New York State Electric and Gas Corporation, April 1, 000 (with F. Graves).

156 EXHIBIT JPP-1 Page of 1 Before the Federal Communications Commission, An Economic Assessment of the Risks and Benefits of Direct Access to INTELSAT in the United States, Report filed In the Matter of Direct Access to the INTELSAT System, IB Docket No. -1, File No. 0-SAT-ISP-, December 1, 1 (with H. Houthakker and J. Green). Before the Federal Communications Commission, A Response to the Economists Inc. Study: Preliminary Competition Analysis of Proposed Lockheed Martin/COMSAT Transaction, December 1 (with C. Lapuerta). Before the United States District Court, Central District of California, Expert Report of The Brattle Group re: Contract Termination Damages; Comsat Corporation v. The News Corporation, Limited, et al., July 1, 1. Before the Federal Communications Commission, Response to Comments on Comsat s Reclassification Petition, File No. 0-SAT-ISP-, July, 1 (with H. Houthakker and W. Tye). Before the Federal Communications Commission, The Economic Basis for Reclassification of Comsat as a Non-Dominant Carrier, Report filed In the Matter of Comsat Corporation Petition for Forbearance from Dominant Carrier Regulation and for Reclassification As a Non- Dominant Carrier, April, 1 (with H. Houthakker and W. Tye). Before the Federal Communications Commission, Competition in Transoceanic Switched Voice and Private Line Services to and from the U.S.: 1 Update, Report filed In the Matter of Comsat Corporation Petition for Forbearance from Dominant Carrier Regulation and for Reclassification As a Non-Dominant Carrier, April, 1 (with H. Houthakker and W. Tye). Before the Federal Communications Commission, Response to Statement of Professor Jerry A. Hausman, in re Hughes Communications, Inc., File Nos. -SAT-AL-(), et al., December 1, 1 (with W. Tye). Before the Federal Communications Commission, The Economic Implications of the Proposed Hughes-PanAmSat Transaction, Written Statement in re Hughes Communications, Inc., File Nos. -SAT-AL-(), et al., December, 1 (with W. Tye). Before the Federal Communications Commission, Competition in the Market for Trans-Oceanic Video Services to and from the U.S., Report filed In the Matter of Comsat Corporation Petition for Partial Relief from the Current Regulatory Treatment of Comsat World Systems Switched Voice, Private Line, and Video and Audio Services, Docket No. RM-1, October, 1, (with H. Houthakker and W. Tye). Before the U.S. House of Representatives, Committee on Commerce, Subcommittee on Telecommunications and Finance, Oversight Hearing on the Restructuring of the International Satellite Organizations, Written Testimony, September, 1. Before the Federal Communications Commission, Competition in the Market for Trans-Oceanic Facilities-Based Telecommunications Services, Report filed In the Matter of Petition for Partial Relief From the Current Regulatory Treatment of COMSAT World Systems' Switched Voice, Private Line, and Video and Audio Services, Docket No. RM-1, June, 1 (with H. Houthakker and W. Tye).

157 EXHIBIT JPP-1 Page of 1 Before the State of New York Public Service Commission, Fuel Switching and Demand Side Management, Prepared Written Testimony on behalf of National Fuel Gas Distribution Company, Case Nos. and 0, September 1 (with D. Weinstein). Mr. Pfeifenberger has also presented research findings related to mergers and network access matters to government and antitrust enforcement agencies, including the U.S. Department of Justice, the Merger Task Force of the European Community, the German Cartel Office, the German Ministry of Economics, and the White House National Economic Council. ARTICLES, REPORTS AND PRESENTATIONS Advancing Past Baseload to a Flexible Grid: How Grid Planners and Power Markets Are Better Defining System Needs to Achieve a Cost-Effective and Reliable Supply Mix, Prepared for NRDC (with J. Chang, M. Geronimo Aydin, and others), June, 01. Reforming Ontario s Wholesale Electricity Market: The Costs and Benefits, Published in Energy Regulation Quarterly (with K. Spess, J. Chang, and others), Volume, Issue, June 01. The Future of Ontario's Electricity Market: A Benefits Case Assessment of the Market Renewal Project, Prepared for IESO (with K. Spees, J. Chang and others), April 0, 01. Western Regional Market Developments: Impact on Renewable Generation Investments and Balancing Costs, Presented at the Wind Power Finance & Investment Summit (with O. Aydin and J. Chang), February, 01. The Role of RTO/ISO Markets in Facilitating Renewable Generation Development, The Brattle Group (with J. Chang, O. Aydin, and D.L. Oates), December, 01. Electricity Market Restructuring: Where Are We Now?, National Council of State Legislators Energy Policy Forum, December, 01. Production Cost Savings Offered by Regional Transmission and a Regional Market in the Mountain West Transmission Group Footprint, Prepared for Basin Electric Power Cooperative, Black Hills Corporation, Colorado Springs Utilities, Platte River Power Authority, Public Service Company of Colorado, Tri-State Generation and Transmission Cooperative, and Western Area Power Administration (with J. Chang and J. Tsoukalis), December 1, 01. Western Regional Market Developments: Impact on Renewable Generation Investments and Balancing Costs, Presented at the th Annual Large Solar Conference (with J. Chang), October 1, 01. The Future for Competitive Transmission: What Have We Learned and Where Do We Go From Here? Energy Bar Association's (EBA) 01 Mid-Year Energy Forum (with J. Chang), October, 01. Improved Transmission Planning for a Carbon-Constrained Future, BRINK, (with J. Chang and O. Aydin), September 1, 01. Senate Bill 0 Study: The Impacts of a Regional ISO-Operated Power Market on California, prepared for CAISO (with J. Chang and others), July, 01.

158 EXHIBIT JPP-1 Page of 1 Well-Planned Electric Transmission Saves Customer Costs: Improved Transmission Planning is Key to the Transition to a Carbon-Constrained Future, prepared for WIRES (with J. Chang), June 01. Open Letter to GAO: Response to U.S. Senators Capacity Market Questions, Sent to the U.S. Government Accountability Office (GAO) (with S. Newell, K. Spees and R Lueken), May, 01. PJM Capacity Auction Results and Market Fundamentals, Prepared for the Bloomberg Analyst Briefing (with S. Newell and D.L. Oates), September 1, 01. Transmission: A Valuable Investment for New England s Energy Future, Presented at the New England Energy Policy Discussion, Boston, MA (with J. Chang), July, 01. Investment Trends and Fundamentals in U.S. Transmission and Electricity Infrastructure, Presented to the JP Morgan Investor Conference (with J. Chang and J. Tsoukalis), July 1, 01. Hidden Values, Missing Markets, and Electricity Policy: The Experience with Storage and Transmission, Harvard Electricity Policy Group, (with J. Chang), June, 01. Impacts of Distributed Storage on Electricity Markets, Utility Operations, and Customers, MIT Energy Initiative Symposium (with J. Chang, K. Spees, and M. Davis), May 1, 01. Transmission As a Market Enabler: The Costs and Risks of an Insufficiently Flexible Electricity Grid, WIRES University, Washington, DC (with J. Chang), April 1, 01. Toward More Effective Transmission Planning: Addressing the Costs and Risks of an Insufficiently Flexible Electricity Grid, prepared for WIRES (with J. Chang and A. Sheilendranath), April 01. Emerging Business Models for Non-Incumbent Transmission Projects, 1th Annual INFOCAST Transmission Summit 01, Washington, DC, March 1, 01. The Value of Distributed Electricity Storage in Texas - Proposed Policy for Enabling Grid- Integrated Storage Investments (Full Technical Report), (with J. Chang, K. Spees, M. Davis, and others), prepared for Oncor, March 01. The Value of Distributed Electrical Energy Storage in Texas: Proposed Policy for Enabling Grid-Integrated Storage Investments, (with J. Chang, K. Spees, and M. Davis), Energy Storage Policy Forum 01, Washington, DC, January, 01. Nebraska Renewable Energy Exports: Challenges and Opportunities, (with J. Chang, M. Hagerty, and A. Murray), prepared for the Nebraska Power Review Board, December 1, 01. Dynamics and Opportunities in Transmission Development, (with J. Chang and J. Tsoukalis), TransForum East, Washington, DC, December, 01. The Value of Distributed Electricity Storage in Texas: Proposed Policy for Enabling Grid- Integrated Storage Investments (with J. Chang, K. Spees, M. Davis, I. Karkatsouli, L. Regan, and J. Marshal), prepared for Oncor, November 01.

159 EXHIBIT JPP-1 Page of 1 Resource Adequacy Requirements, Scarcity Pricing, and Electricity Market Design Implications, presented at the IEA Electricity Security Advisory Panel (ESAP), Paris, France, July, 01. Third Triennial Review of PJM s Variable Resource Requirement Curve (with S. Newell, K. Spees, and others), capacity market design review prepared for PJM, May 1, 01. Cost of New Entry Estimates for Combustion Turbine and Combined Cycle Plants in PJM: with June 1, 01 Online Date (with K. Spees, S. Newell, J.M. Hagerty, and others), prepared for PJM, May 1, 01. Contrasting Competitively-Bid Transmission Investments in the U.S. and Abroad, UBS Conference Call webinar, May 1, 01 (with J. Chang, M. Davis, and M. Geronimo). Transmission to Capture Geographic Diversity of Renewables: Cost Savings Associated with Interconnecting Systems with High Renewables Penetration (with J. Chang, P. Ruiz, and K Van Horn), Presented to TransForum West, San Diego, CA, May, 01. Energy and Capacity Markets: Tradeoffs in Reliability, Costs, and Risks (prepared with S. Newell and K. Spees), Presented at the Harvard Electricity Policy Group Seventy-Fourth Plenary Session, February, 01. Market-Based Approaches to Resource Adequacy, prepared for IESO Stakeholder Summit, Toronto, Ontario, Canada, February, 01. Competition in Transmission Planning and Development: Current Status and International Experience (with Judy Chang, Matthew K. Davis, and Mariko Geronimo), prepared for the EUCI's Transmission Policy: A National Summit, Washington, DC, January 1, 01. Estimating the Economically Optimal Reserve Margin in ERCOT (with S. Newell, K. Spees, I. Karkatsouli, N. Wintermantel, and K. Carden), prepared for The Public Utility Commission of Texas, January 1, 01. Using Virtual Bids to Manipulate the Value of Financial Transmission Rights (with S. Ledgerwood), The Electricity Journal, Vol., Issue, November 01. Characteristics of Successful Capacity Markets (with K. Spees), APEx Conference, New York, NY, October 1, 01. Recommendations for Enhancing ERCOT s Long-Term Transmission Planning Process (with J. Chang, S. Newell, B. Tsuchida and M. Hagerty), prepared for ERCOT, October 01. Resource Adequacy Requirements: Reliability and Economic Implications (with K. Spees, K. Carden, and N. Wintermantel), prepared for the Federal Energy Regulatory Commission (FERC), September 01. Capacity Markets: Lessons Learned from the First Decade (with K. Spees and S. Newell), Economics of Energy & Environmental Policy, Vol., No., Fall 01. Trends and Benefits of Transmission Investments: Identifying and Analyzing Value (with J. Chang and M. Hagerty), presented to the CEA Transmission Council, Ottawa, Canada, September, 01.

160 EXHIBIT JPP-1 Page of 1 Examining Hydroelectricity s Potential Role in the Alberta Market: Impacts of Market Structure and Economics, Alberta Power Symposium, Calgary, September, 01. The Benefits of Electric Transmission: Identifying and Analyzing the Value of Investments (with J. Chang and M. Hagerty), prepared for WIRES, July 01. "Making Energy-Only Markets Work: Market Fundamentals and Resource Adequacy in Alberta," presented at the Harvard Electricity Policy Group meeting, June 1, 01. "Independent Transmission Companies: Business Models, Opportunities, and Challenges," presented at the American Antitrust Institute's 1th Annual Energy Roundtable, Washington, DC, April, 01. "Evaluation of Market Fundamentals and Challenges to Long-Term System Adequacy in Alberta s Electricity Market: 01 Update" (with K. Spees and M. DeLucia), prepared for the Alberta Electric System Operator, March 01. "Structural Challenges with California s Current Forward Procurement Construct," presented at the CPUC and CAISO Long-Term Resource Adequacy Summit, February, 01. Bridging the Seams: Interregional Planning Under FERC Order 00 (with J. Chang and D. Hou), Public Utilities Fortnightly, November 01. Interregional Cost Allocation: A Flexible Framework to Support Interregional Transmission Planning, presented to the Harvard Electricity Policy Group, October, 01. Resource Adequacy in California: Options for Improving Efficiency and Effectiveness (with K. Spees and S. Newell), prepared for Calpine, October 01. Resource Adequacy Designs in U.S. Power Markets: PJM, presented at the Gulf Coast Power Association th Annual Fall Conference, Austin, TX, October 1, 01. Resource Adequacy in International Power Markets and Alberta, presented at the Gulf Coast Power Association th Annual Fall Conference, Austin, TX, October 1, 01. Resource Adequacy and Capacity Markets: Overview, Trends, and Policy Questions, presented at New England Electricity Restructuring Roundtable, Boston, MA, September 1, 01. Transmission Investment Trends and Planning Challenges, presented at the EEI Transmission and Wholesale Markets School, Madison, WI, August, 01. Seams Inefficiencies: Problems and Solutions at Energy Market Borders (with K. Spees), presented at the EUCI Canadian Transmission Summit, July 1, 01. The Benefits of Transmission Expansion, presented at the EUCI Canadian Transmission Summit, July 1, 01. The Economics of Reliability and Resource Adequacy Planning, presented at the Mid-America Regulatory Conference, Des Moines, IA, June 1, 01.

161 EXHIBIT JPP-1 Page of 1 ERCOT Investment Incentives and Resource Adequacy (with S. A. Newell, K. Spees, R. S. Mudge, M. DeLucia, and R. Carlton), prepared for the Electric Reliability Council of Texas, June 1, 01. Resource Adequacy, presented at the IRC Board Conference, Dallas, TX, May, 01. Review of EIPC s Phase 1 Report (with P.S. Fox-Penner, and D. Hou), prepared for the Working Group for Investment in Reliable and Economic Electric Systems (WIRES), May, 01. Using Virtual Bids to Manipulate the Value of Financial Transmission Rights (with by S.D. Ledgerwood), SSRN Working Paper Series, May, 01. Seams Cost Allocation: A Flexible Framework to Support Interregional Transmission Planning (with D. Hou), prepared for the Southwest Power Pool Regional State Committee, April 01. Transmission s True Value: Adding Up the Benefits of Infrastructure Investments (with D. Hou), Public Utilities Fortnightly, February 01. Update on RSC Seams Cost Allocation Effort (with D. Hou), Presented to FERC Staff, February, 01. Modernizing America s Grid: How can better planning deliver the grid we need? New England Clean Energy Transmission Summit, Boston, MA, January, 01. Trusting Capacity Markets: Does the Lack of Long-term Pricing Undermine the Financing of New Power Plants? (with S. Newell), Public Utilities Fortnightly, December 0. Reliability and Economics: Separate Realities or Part of the Same Continuum? Harvard Electricity Policy Group, December 1, 0. Resource Adequacy: Current Issues in North American Power Markets (with K. Spees), Alberta Power Summit, November, 0. Recent FERC Actions and Implications for Transmission in the West, EUCI Western Transmission Conference: Connecting Renewables to the Grid in the Southwest, Scottsdale, Arizona, October, 0. Summary of Transmission Project Cost Control Mechanisms in Selected U.S. Power Markets (with D. Hou), prepared for the Alberta Electric System Operator, October 0. Transmission Cost Allocation and Cost Recovery in the West, Transmission Executive Forum West 0 Strategies for Meeting the Transmission Needs in the West, San Francisco, September 1, 0. Resource Adequacy: More than just keeping the lights on (with K. Carden), NRRI Teleseminar, September 1, 0. Second Performance Assessment of PJM s Reliability Pricing Model (with S.A. Newell, K. Spees, A. Hajos, and K. Madjarov), August, 0. Cost of New Entry Estimates For Combustion-Turbine and Combined-Cycle Plants in PJM (with K. Spees, S. A. Newell, R. Carlton, and B. Zhou), August, 0.

162 EXHIBIT JPP-1 Page of 1 Restructuring Realities: Can higher electricity prices be more affordable? (with A.C. Schumacher), Public Utilities Fortnightly, July 0. Employment and Economic Benefits of Transmission Infrastructure Investment in the U.S. and Canada (with D. Hou), Report prepared for WIRES, May 0. U.S. Transmission Needs and Planning Challenges, EEI Transmission Policy Task Force, May, 0. Evaluation of Market Fundamentals and Challenges to Long-Term System Adequacy in Alberta s Electricity Market (with K. Spees), Report prepared for the Alberta Electric System Operator, April 0. Barriers to Transmission Investments and Implications for Competition in Wholesale Power Markets, The American Antitrust Institute, April 1, 0. The Economics of Resource Adequacy Planning: Why Reserve Margins Are Not Just About Keeping the Lights On (with K. Carden and N. Wintermantel), NRRI Report -0, April 0. The Value of Resource Adequacy: Why Reserve Margins Aren t Just About Keeping the Lights On (with K. Carden and N. Wintermantel), Public Utilities Fortnightly, March 0. Demand Response Review (with A. Hajos), Report prepared for Alberta Electric System Operator, March 0. Easier Said Than Done: The Continuing Saga of Transmission Cost Allocation, Harvard Electricity Policy Group meeting, Los Angeles, February, 0. Executive Summary An Assessment of the Public Policy, Reliability, Congestion Relief, and Economic Benefits of the Atlantic Wind Connection (with S. Newell), December 1, 0. Transmission Investments and Cost Allocation: What are the Options? ELCON Fall Workshop, October, 0. Transmission Planning: Economic vs. Reliability Projects, EUCI Conference, Chicago, October 1, 0. Renewable Energy Development and Transmission Expansion Who Benefits and Who Pays, October 1, 0. Resource Adequacy and Renewable Energy in Competitive Wholesale Electricity Markets (with S. Hesmondhalgh and D. Robinson), article presented at the th British Institute of Energy Economics (BIEE) Academic Conference, Oxford, September 0. Transmission Planning and Cost Benefit Analysis (with D. Hou), EUCI Web Conference, September, 0. Transmission Planning: Overarching Challenges to Regional Expansion, Electric Transmission 0: Planning to Expand and Upgrade the Grid, WIRES and EESI Senate Staff Briefing Series, June, 0.

163 EXHIBIT JPP-1 Page 1 of 1 Potential Carbon Emission Reductions and Costs of Delivering Wind Energy from the Plains & Eastern Clean Line Transmission Project (with J. Weiss and D. Hou), report prepared for Cleanline Energy Partners, June 0. For Grid Expansion, Think Subregionally (with P. Fox-Penner and D. Hou), Energy Daily, June, 0. Incentive Regulation: Lessons from other Jurisdictions (with T. Brown and P. Carpenter), Alberta Utilities Commission workshop, Edmonton, May, 0. Incentive Regulation: Introduction and Context, Alberta Utilities Commission workshop, Edmonton, May, 0. Job and Economic Benefits of Transmission and Wind Generation Investments in the SPP Region (with J. Chang, D. Hou, and K. Madjarov), Report prepared for Southwest Power Pool, March 0. Challenges to Alberta s Energy-Only Market Structure?, IPPSA 1 th Annual Conference, Banff Springs, Alberta, March 1, 0. Best Practices in Resource Adequacy, presented at the PJM Long Term Capacity Issues Symposium (with K. Spees), January, 0. Transmission Investment Needs and Cost Allocation: New Challenges and Models (with P.S. Fox-Penner and D. Hou), December 1, 00. A Comparison of PJM s RPM with Alternative Energy and Capacity Market Designs (with K. Spees and A. Schumacher), Report prepared for PJM Interconnection LLC, September 00. Assessment of a Maine ISA Structure as a Possible Alternative to ISO-NE Participation (with K. Belcher, J. Chang, and D. Hou), Report prepared for Central Maine Power Company and the Industrial Energy Consumer Group, May 00. Review of PJM s Reliability Pricing Model (RPM) (with S. Newell, R. Earle, A. Hajos, and M. Geronimo), Report prepared for PJM Interconnection LLC, June 0, 00. Assessing the Benefits of Transmission Investments, Working Group for Investment in Reliable and Economic Electric Systems (WIRES) meeting, Washington, DC, February 1, 00. The Power of Five Percent (with A. Faruqui, R. Hledik, and S. Newell), The Electricity Journal, October 00. Review of PJM s Market Power Mitigation Practices in Comparison to Other Organized Electricity Markets (with J. Reitzes, P. Fox-Penner and others), Report prepared for PJM Interconnection LLC, September 1, 00. Restructuring Revisited: What We Can Learn from Retail Rate Increases in Restructured and Non-Restructured States (with G. Basheda and A. Schumacher), Public Utilities Fortnightly, June 00.

164 EXHIBIT JPP-1 Page 1 of 1 The Power of Five Percent: How Dynamic Pricing Can Save $ Billion in Electricity Costs (with A. Faruqui, R. Hledik, and S. Newell), Discussion Paper, The Brattle Group, May 1, 00. Evaluating the Economic Benefits of Transmission Investments (with S. Newell), EUCI Conference, Nashville, Tennessee, May, 00. Valuing Demand-Response Benefits in Eastern PJM (with S. Newell and F. Felder), Public Utilities Fortnightly, March 00. Financial Challenges of Rising Utility Costs and Capital Investment Needs (with A. Schumacher), 00 NASUCA Annual Meeting, Miami, Florida, November 1, 00. Financial Pressures Ahead: Can Utilities Simultaneously Manage Rising Costs and Pressing Capital Investment Needs?, Public Utilities Fortnightly, October 00. Behind the Rise in Prices: Electricity Price Increases are Occurring Across the Country, Among all Types of Electricity Providers Why? (with G. Basheda, M. Chupka, P. Fox-Penner, and A. Schumacher), Electric Perspectives, July/August 00. Why Are Electricity Prices Increasing: An Industry-Wide Perspective (with G. Basheda, M. Chupka, P. Fox-Penner, and A. Schumacher), prepared for The Edison Foundation, June 00. Understanding Utility Cost Drivers and Challenges Ahead (with A. Schumacher), AESP Pricing Conference, Chicago, May 1, 00. Modeling Power Markets: Uses and Abuses of Locational Market Simulation Models (with S. Newell), Energy, Vol, 00. When Sparks Fly: Economic Issues in Complex Energy Contract Litigation (with D. Murphy and G. Taylor), Energy, Vol 1, 00. Innovative Regulatory Models to Address Environmental Compliance Costs in the Utility Industry (with S. Newell), Newsletter of the American Bar Association, Section on Environment, Energy, and Resources, pp. -, October 00. Keeping Up with Retail Access? Developments in U.S. Restructuring and Resource Procurement for Regulated Retail Service (with J. Wharton and A. Schumacher), The Electricity Journal, December 00. Can Utilities Play on the Street? Issues in ROE and Capital Structure, opening comments for panel discussion on Traditional and Alternative Methods for Determining Return on Investment, Financial Research Institute Conference, Columbia, Missouri, September 1, 00. What is Reasonable? How to Benchmark Return on Equity (ROE) and Depreciation Expense in Utility Rate Cases (with M.Jenkins), Public Utilities Fortnightly, October 1, 00. Efficiency as a Discovery Process: Why Enhanced Incentives Outperform Regulatory Mandates (with D. Weisman), The Electricity Journal, January/February 00. Big City Bias: The Problem with Simple Rate Comparisons (with M. Jenkins), Public Utilities Fortnightly, December 00.

165 EXHIBIT JPP-1 Page 1 of 1 Power Market Design in Europe: The Experience in the U.K. and Scandinavia (with C. Lapuerta), Energy Bar Association, th Annual Meeting, Washington, DC, April 1, 00. REx Incentives: PBR Choices that Reflect Firms Performance Expectations (with P. Carpenter and P. Liu), The Electricity Journal, November 001. The State of Performance-Based Regulation in the U.S. Electric Utility Industry (with D. Sappington, P. Hanser and G. Basheda), The Electricity Journal, October 001. Eine wettbewerbliche Analyse beabsichtigter Zusammenschluesse in der Deutschen Elektrizitaetswirtschaft (A Competitive Analysis of Proposed Mergers in the German Power Industry), presentations to the German Cartel Office and the Merger Task Force of the European Commissions, February 000. Transmission Access, Episode II: FERC s Journey Has Only Begun (with P. Fox-Penner), Public Utilities Fortnightly, August 1. Netzzugang in Deutschland im internationalen Vergleich (International Benchmarking of German Transmission Access) (with C. Lapuerta, W. Pfaffenberger, and J. Weiss), Energiewirtschaftliche Tagesfragen, July 1. Netzzugang in Deutschland ein Ländervergleich (Transmission Access in Germany an International Comparison) (with C. Lapuerta and W. Pfaffenberger), Wirtschaftswelt Energie, March 1, pp. - (Part I) and April 1, pp. 1-1 (Part II). Transmission Access In Germany Compared to Other Transmission Markets (with C. Lapuerta and W. Pfaffenberger), commissioned by Enron Europe Ltd., December 1, updated February 1. Competition to International Satellite Communications Services (with H. Houthakker), Information Economics and Policy, Vol. (1) 0-0. In What Shape is Your ISO (with P. Hanser, G. Basheda, and P. Fox-Penner), The Electricity Journal, July 1. Distributed Generation: Threats and Opportunities (with P. Hanser and D. Chodorow), Electric Distribution Conference, Denver Colorado, April -, 1. What s in the Cards for Regulated Distribution Companies (with P. Hanser and D. Chodorow), Electric Distribution Conference, Denver Colorado, April -, 1. Does Generation Divestiture Mitigate Market Power, 1 Energy Futures Forum, Woodbridge, NJ, April, 1. Joint Response to the Satellite Users Coalition Analysis of the Privatization of the Intergovernmental Satellite Organizations as Proposed in H.R. 1 and S. 1 (with H. Houthakker, M. Schwartz, W. Tye, and A. Maniatis), March, 1. What s in the Cards for Distributed Resources? (with P. Ammann and P. Hanser), The Energy Journal, Special Issue, January 1.

166 EXHIBIT JPP-1 Page 1 of 1 An Economic Assessment of H.R. 1 (analyzing the impact of a bill attempting to restructure the international satellite organizations) (with H. Houthakker and A. Maniatis), September, 1. Considerations in the Design of ISO and Power Exchange Protocols: Procurement Bidding and Market Rules (with F. Graves), Electric Utility Consultants Bulk Power Markets Conference, Vail, Colorado, June, 1. The Top Other Challenges to Success in Utility Mergers (with W. Tye), 1 Energy Futures Forum, NJAEE, Woodbridge, New Jersey, April 1, 1. Introduction to Market Power Concerns in a Restructured Electric Industry (with others) Brattle Presentation, July 1. Does Intelsat Face Effective Competition (with H. Houthakker), Columbia Institute for Tele- Information, Conference, April, 1. Distributed Generation Technology in a Newly Competitive Electric Power Industry (with P. Ammann and G. Taylor), American Power Conference, Chicago, April, 1. Handle with Care: A Primer on Incentive Regulation (with W. Tye), Energy Policy, Vol 1, No., September 1. Measuring Property Value Impacts of Hazardous Waste Sites (with K. Wise), Air & Waste Management Association, th Annual Meeting, June 1-, 1. The Not-So-Strange Economics of Stranded Investments (with W. Tye), The Electricity Journal, Reply, November 1. Purchased Power: Hidden Costs or Benefits? (with S. Johnson, L. Kolbe, and D. Weinstein), The Electricity Journal, September 1. Pricing Transmission and Power in the Era of Retail Competition (with F. Graves), Electric Utility Consultants: Retail Wheeling Conference, June 1. The Enigma of Stigma: The Case of the Industrial Excess Landfill (with K. Wise), Toxics Law Reporter, Bureau of National Affairs, May 1, 1. Banking on NUG Reliability: Do Leveraged Capital Structures Threaten Reliability? (with S. Johnson and L. Kolbe) Public Utilities Fortnightly, May 1, 1. Valuation and Renegotiation of Purchased Power Contracts (with others), The Brattle Group Presentation, May, 1. Still More on Purchased Power (with S. Johnson), The Electricity Journal, Reply, February 1. Purchased Power Risks and Rewards (with A.L. Kolbe and S. Johnson), Presentation at the AGA/EEI Budgeting and Financial Forecasting Committee Meeting, February, 1, Evaluation of Demand-Side Management Programs (with others), Capital Budgeting Notebook, Electric Power Research Institute, Chapter 1, 1.

167 EXHIBIT JPP-1 Page 1 of 1 Purchased Power Risks and Rewards (with S. Johnson and A.L. Kolbe), Report for the Edison Electric Institute, Fall 1. Purchased Power Incentives (with S. Johnson), The Electricity Journal, Reply, November, 1. It s Time For A Market-based Approach to Demand-side Management (with A.L. Kolbe), PowerGen Conference, November 1. Incentive Regulation: Dos and Don ts (with W. Tye), Electric Utility Consultants: Strategic Utility Planning Conference, June 1. It s Time For A Market-based Approach to DSM (with A.L. Kolbe, A. Maniatis, and D. Weinstein), The Electricity Journal, May, 1. Charge It Financing DSM Programs (with D. Weinstein), Public Utilities Fortnightly, May 1, 1. Fuel Switching and Demand-side Management (with D. Weinstein) Public Utilities Fortnightly, May 1, 1. Development of Sectoral Energy Requirements in the Japanese Economy: to, Master s Project in International Economics, Brandeis University, May. The Costs of Hydropower: Evidence on Learning-by-Doing, Economies of Scale, and Resource Constraints in Austria (with F. Wirl), International Journal of Energy Research, Vol. 1, pp. -,. Eine ökonomische Analyse alternativer Kraftwerkstypen (an economic analysis of power supply alternatives) (with F. Wirl), Girozentrale Quartalshefte, pp. 1-0, January. Eine einfache Charakterisierung der saisonalen Elektrizitätsnachfrage (a simple characterization of seasonal electricity demand), Österreichische Zeitschrift für Elektrizitätswirtschaft, March. Kraftwerksausbauplanung mit Linearen Optimierungsmodellen am Beispiel Österreichs (power systems expansion planning for Austria with mixed-integer and linear-programming models), Master s Thesis, Institute of Energy Economics, University of Technology, Vienna, May 1.

168 Details of Key Assumptions used in PROMOD Simulations As noted in my Direct Testimony (Exhibit JPP-1), the 00 and 0 PROMOD models used in this effort were developed by SPP in 01/1 for use in its 01 ITP studies. The Companies PROMOD simulations in this case are based on these SPP PROMOD models, but with few modifications to the key assumptions. The key assumptions, including modifications made, are detailed below. 1. SPP Future Analyzed: The Companies employed the 01 ITP models that reflected SPP s Future a future that assumed no pricing on carbon emission by thermal generation resources through 0. EXHIBIT JPP- Page 1 of. Future Wind Resources: SPP s Future base models included approximately 00 MW and 00 MW of new future wind resources in SPP s AEP zone in 00 and 0. The Companies modified this assumption to retain 00 MW of these wind plants in each simulation year, reflecting the Companies planned 01 wind procurement. The rest of SPP s assumed wind capacities in SPP s AEP zone (i.e., 00 MW in 00 and 00 MW in 0) were still retained in the models, but were allocated to SPP s merchant ownership zone. This assumption was maintained consistently across all three cases used in this analysis. In total, this SPP case assumed,0 MW of new wind in 00 and, MW of new wind in 0. Other than the change in how much of these new wind plants is contracted by AEP companies, however, none of these other SPP new wind assumptions were modified.. Future Capacity Needs: To meet projected reserve margin requirement, SPP s base models assumed development of new combined cycle and combustion turbine generating resources in several of its zones, including in the AEP zone. SPP s base models also accredited some capacity value to future wind modeled, and used those towards meeting project reserve margin requirement. The Companies PROMOD simulation of the Project Case and Generic Wind Case with 1,00 MW of delivered new wind, slightly modified these assumed future capacities in the SPP base model by: (1) reducing AEP Companies purchase of a 1 MW share of a new combined cycle unit in 00, and () eliminating the need for a 1 MW future combustion turbine resource assumed by SPP to be needed in 0. The Base Case was additionally modified slightly by adding a combustion turbine for meeting the Companies reserve margin requirement in 0 and beyond. This capacity need was created because 00 MW of SPPassumed future AEP wind were shifted to SPP s merchant ownership zone, as explained above in item No.. The Companies PROMOD simulations implemented these changes to reflect that adding 1,00 MW of new wind in the Project and Generic Wind Cases would provide some capacity value, which would supplant some of the new generating resources that SPP determined to be needed in the AEP zone. For the Base Case, in which no new wind development is assumed, the Companies PROMOD simulations retained the same capacity additions assumptions used in

169 EXHIBIT JPP- Page of SPP s 00 PROMOD model, but as explained above, included a new combustion turbine generation in the 0 model to meet AEP s projected base-case reserve margin requirements.. Gas Prices: SPP s Future base PROMOD models assumed annual average natural gas prices of $.0/MMBtu in 00 and $./MMBtu 1 in 0. The Companies PROMOD simulations modify this assumption by updating the base case gas price inputs (and providing a low gas price sensitivity) to reflect those of the AEP Companies long-term fundamental forecast for the commodity. Company witness Karl Bletzacker provides additional details on these long-term fundamental forecasts of natural gas prices.. New PSO/SWEPCO Wind Resources: As described in the analysis methodology discussion in my prepared direct testimony (Exhibit JPP-1), the Companies modeled 1,00 MW of delivered new wind resources in the Project Case and the Generic Wind Case. In the Project Case, the PROMOD model included modeling new GE. MW turbines connecting to a new kv Oklahoma Panhandle substation and a kv Gen-Tie line connecting this substation to the SPP s Tulsa substation. The Tulsa substation was modified to include a kv/ kv transformation, plus some local transmission upgrades expected to be necessary for interconnection purposes.. Other: In the Generic Wind Case, to model 1,00 MW of wind delivered at existing SPP points of interconnection, the Companies PROMOD simulations used the full range of wind locations that SPP and its stakeholders had assumed to be feasible and likely interconnection locations for such future wind. There were such locations in Oklahoma, Kansas, Missouri, and Nebraska as shown in my Direct Testimony (Exhibit JPP-1). Note that, the Companies PROMOD simulations did not modify the future wind resources already modeled by SPP in these locations. Rather, the PROMOD simulations proportionally increased the output of the already modeled wind resources to collectively provide an additional 1,00 MW of delivered wind capacity. The wind profiles for the Project Case and Generic Wind case were developed by the Companies for use in its PLEXOS simulations based on most up-to-date wind profile information. For the purpose of Companies PROMOD simulations, the wind profiles for the locations simulated in the Generic Wind Case were kept identical to the profiles modeled by SPP in its 01 ITP PROMOD models. Locational Pricing and Benefits Extrapolation Details As explained in my Direct Testimony (Exhibit JPP-1), to evaluate the full benefits of each case analyzed, PROMOD was utilized in conjunction with PLEXOS to perform the necessary forward-looking market simulations. To facilitate PLEXOS forward-looking 1 Provided by the Operating Companies based on review of SPP s 01 ITP PROMOD Models for 00 and 0

170 EXHIBIT JPP- Page of market simulations, its locational wholesale marginal price inputs were based on PROMOD simulations for 00 and 0. The following data processing tasks were performed to prepare the necessary 01 0 PLEXOS market pricing inputs from relevant outputs of the PROMOD simulations for 00 and Calculation of Monthly Average Peak, Weekend, and Night Prices: As illustrated in my Direct Testimony (Figure ), I processed PROMOD s hourly prices from the 00 and 0 simulations to calculate three sets of monthly, generation-weighted average prices for PSO s and SWEPCO s thermal units, and three sets of monthly, load-weighted average prices, for the PROMOD-defined AEP zone. The three sets of prices in each month were Weekday Peak, Weekend Peak, and Night hours. These are the standard price inputs used by the Companies for their PLEXOS simulations.. Evaluation of Monthly Prices for 01 through 0: Since PROMOD markets simulations were performed only for the 00 and 0 cases available from SPP, monthly prices for the 01 0 portion of the evaluation period were interpolated using a constant annual growth rate between the 00 and 0 PROMOD-based monthly prices. Monthly prices for the 0 0 portion of the evaluation period were then extrapolated from the monthly 0 PROMOD-based prices using the Companies Fundamentals forecast of Around-the-Clock (ATC) power prices for each month through 0. For instance, a January 0 PROMOD-based price would be calculated by taking the growth rate between PSO s/swepco s January 0 Fundamentals ATC price and the January 0 ATC price, and applying it to the January 0 PROMOD-based price.. Processing of Congestion Charges, Marginal Loss Charges, Reduced Quantity of Transmission Losses, and Wind-Curtailment Costs for 01 0: The monthly congestion and marginal loss charges associated with PSO s and SWEPCO s existing and new wind resources as an input into the Companies PLEXOS simulations were determined based on PROMOD-simulated congestion and loss differences between wind locations and SPP s AEP zone load, and applying those Time Definitions are as follows: Weekday Peak = am to pm, Monday through Friday; Weekend Peak = am to pm on Saturday and Sunday, and on NERC Holidays; Night = pm to am for all seven days of the week, including holidays. The net loss charges for each operating company was estimated as one-half the marginal loss component differences between wind and load locations to reflect the refund of surplus marginal loss congestion revenues, consistent with the theoretical 1/ relationship between average and marginal losses.

171 EXHIBIT JPP- Page of per-mwh charges to the hourly output from each wind site. Congestion- and lossrelated costs for the Companies wind resources were calculated on a monthly basis for each operating company. As explained in my direct testimony (Exhibit JPP-1), I also assumed that an average of % of the annual expected wind energy that could be produced by new wind resources in the Generic Wind Case would be curtailed due to limitations on the SPP transmission system. I evaluated a monthly cost associated with such curtailments by using PROMOD night-time load prices during windier months of March, April, October, November and December. To interpolate and extrapolate congestion, losses, and curtailment costs from the 00 and 0 PROMOD simulation years to the entire 01 0 evaluation period, I employed the same methodology used for the interpolation and extrapolation of PROMODbased PSO/SWEPCO generation and load prices. In addition to evaluating marginal-loss-related charges for the Companies wind resources, I also evaluated the MWh loss quantity reduction that would occur due to the Project. To make simulation-run times more manageable, PROMOD simulations reflect zonal loads that are grossed up for an assumed average MWh quantity of transmission losses. Because this gross-up for losses does not change across simulation cases, the simulations do not capture any of the potential savings from a reduced MWh quantity of losses that may be realized with delivering the wind energy from the project directly to the Tulsa area. The additional production cost savings due to such a reduction in the quantity of energy losses can be estimated by post-processing of Marginal Loss Component (MLC) of the LMPs evaluated and reported in PROMOD simulation results. Applying the same methodology approved by SPP s Metric Task Force and the Economic Studies Working Group, and used by SPP in its RCAR analyses, I estimated the MWh quantity of losses and associated costs to the Companies for 00 and 0 for the Project Case, Generic Wind Case and the Base Case. The difference in the MWh quantity of losses between the cases, valued at LMPs, provide the estimate of cost savings from reducing the MWh quantity of transmission losses. The % curtailment future assumption is based on my review of the historical curtailment experience in MISO and ERCOT as discussed in more detail in my Direct Testimony (Exhibit JPP-1). See Section, p. 1 of SPP Benefit Metrics Manual, November, 01 for a detailed description of SPP Board approved calculation methodology for evaluating changes in MWh quantity of losses based on Marginal Loss Component of LMPs. Accessed here:

172 EXHIBIT JPP- Page of To interpolate and extrapolate these loss savings, from the 00 and 0 PROMOD simulation years to the entire 01 0 evaluation period, I employed the same methodology used for the interpolation and extrapolation of PROMODbased PSO/SWEPCO generation and load prices. Figure below provides a summary of the annual average values of location marginal prices and calculated benefit metrics based on 00 and 0 PROMOD outputs for the Base Case, Project Case, and Generic Wind Case. Figure 1: Summary of PROMOD-based Prices and Costs for 00 and 0

173 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF KARL R. BLETZACKER FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

174 Q. PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS. A. My name is Karl R. Bletzacker. My position is Director, Fundamentals Analysis, American Electric Power Service Corporation (AEPSC). AEPSC supplies engineering, financial, accounting, planning and advisory services to the electric operating companies of American Electric Power Company, Inc. (AEP), including Public Service of Oklahoma and Southwestern Electric Power Company (SWEPCO or Company). My business address is 1 Riverside Plaza, Columbus, Ohio 1. Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND BUSINESS EXPERIENCE. A. I received a BSMEng degree from The Ohio State University in and have over years of energy-industry experience, which includes petroleum engineering and the management of the purchasing, interstate transmission and distribution of natural gas and power to both regulated and wholesale customers. I have implemented risk management strategies using New York Mercantile Exchange (NYMEX) and over-the-counter natural gas futures, swaps, and options since the NYMEX natural gas contract was created in June of. I have purchased short- and long-term natural gas supply from major and independent producers and marketing companies and I have monetized arbitrage opportunities using NYMEX futures contract, local and contract storage, pipeline imbalances and local distribution company banks. As Vice-President and Chief Operating Officer of National Gas & Oil Company (a publicly-traded Ohio natural gas utility) and Licking Rural Electric Cooperative (an Ohio electric cooperative), I was responsible for the natural gas pricing and risk management policies that ensured reliable delivery and managed customers exposure DIRECT TESTIMONY 1 KARL R. BLETZACKER

175 to volatile commodity prices. As the North American Manager of Energy Procurement for Honda of America Mfg., Inc., I implemented hedging strategies utilizing NYMEX natural gas futures contracts and operated a natural gas supply pool for the benefit of Honda and its suppliers in North America. I also utilized my energy markets expertise while serving as Vice-Chairman of the Industrial Energy Users-Ohio which is an organization of large Ohio energy consumers that spend collectively over $ billion per year on electricity and natural gas for their plants and facilities and whose members employ over 0,000 people. I joined AEP in 00 to focus on the creation of long-term North American energy market forecasts primarily to support the resource and strategic planning of its operating companies. Q. HAVE YOU PREVIOUSLY FILED TESTIMONY IN A REGULATORY PROCEEDING? A. Yes. I have presented testimony on behalf of AEP operating companies and others in Texas, Arkansas, Indiana, Kentucky, Ohio, Virginia and West Virginia. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? A. I sponsor the Long-Term North American Energy Market Forecast (Fundamentals Forecast) utilized by Company witnesses Kelly D. Pearce and Johannes P. Pfeifenberger as a basis for certain elements of their respective analyses. I describe how those market forecasts are derived, in particular, the basis for the natural gas, electric generation energy and capacity, and CO allowance price forecasts. Q. WHAT DID YOU PROVIDE TO COMPANY WITNESSES PEARCE AND PFEIFENBERGER FOR THEIR RESPECTIVE ANALYSES IN THIS CASE? DIRECT TESTIMONY KARL R. BLETZACKER

176 A. I provided Company witnesses Pearce and Pfeifenberger AEPSC s Fundamentals Forecast, which was available to all AEP electric operating companies on October, 01. Q. WERE THERE ANY SUBSEQUENT FORECASTS AVAILABLE TO ANY OF THE AEP ELECTRIC OPERATING COMPANIES AT THE TIME COMPANY WITNESS PEARCE USED THE FUNDAMENTALS FORECAST? A. No. To date, no subsequent Fundamentals Forecast has been undertaken. Q. WHAT IS THE FUNDAMENTALS FORECAST? A. The Fundamentals Forecast is a long-term, weather-normalized commodity market forecast. It is not created to meet a specific regulatory need in a particular jurisdiction; rather, it is made available to all AEP operating companies after completion. It is often referenced for purposes such as fixed asset impairment accounting, capital improvement analyses, resource planning, and strategic planning. These projections cover the electricity market within the Eastern Interconnect (which includes the Southwest Power Pool), the Electric Reliability Council of Texas and the Western Electricity Coordinating Council. The Fundamentals Forecast includes: 1) monthly and annual regional power prices (in both nominal and real dollars), ) prices for various qualities of Central Appalachian (CAPP), Northern Appalachian (NAPP), Illinois Basin (ILB), Powder River Basin (PRB) and Colorado coals, ) monthly and annual locational natural gas prices, including the benchmark Henry Hub, ) uranium fuel prices, ) SO, NOx and CO values, ) locational implied heat rates, ) electric generation capacity values, ) renewable energy subsidies, and ) inflation factors, among others. DIRECT TESTIMONY KARL R. BLETZACKER

177 To complement the Base Case Fundamentals Forecast, three associated cases are also created: the Lower Band, Upper Band and No Carbon cases. The associated cases were designed and generated to define a plausible range of outcomes surrounding the Base Case. The Lower and Upper Band forecasts consider lower and higher North American demand for electric generation and fuels and, consequently, lower and higher fuels prices. Nominally, fossil fuel prices vary one standard deviation above and below Base Case values. The No Carbon case assumes there will be no regulations limiting CO emissions throughout the entire forecast period. Q. WHAT TOOLS DID YOU USE TO DEVELOP THE FUNDAMENTALS FORECAST? A. The primary tool used for the development of the North American long-term energy market pricing forecasts is the AURORAxmp Energy Market model. It iteratively generates zonal, but not company-specific, long-term capacity expansion plans, annual energy dispatch, fuel burns and emission totals from inputs including fuel, load, emissions and capital costs, among others. Ultimately, AURORAxmp creates a weather-normalized, long-term forecast of the market in which a utility would be operating. AEPSC also has ample energy market research information available for its reference, which includes many well-accepted energy consultancies such as Cambridge Energy Research Associates, PIRA Energy Group and WoodMackenzie. Although no exact forecast inputs from these sources of energy market research information is utilized, an in-depth assessment of this research information can yield, DIRECT TESTIMONY KARL R. BLETZACKER

178 among other things, an indication of the supply, demand and price relationship (price elasticity) over a period of time. This price elasticity, when applied to the AURORAxmp natural gas burn, yields a corresponding change in natural gas prices which is recycled through the AURORAxmp model iteratively until the change in natural gas burn is de minimis. Figure 1 illustrates that the magnitude of that effect must be recycled through AURORAxmp to determine a new merit order of dispatch. It is this new merit order of dispatch that takes into account the effect of operating conditions across North America and, in turn, determines zonal energy market prices. Figure 1 Input Output Fuel Forecast Longterm Capacity Expansion Load Forecast Annual Dispatch Generate Report Emission Totals Fuel Burn Totals Market Prices Emissions Forecast Capital Cost Forecast Emission Retrofits Recycle DIRECT TESTIMONY KARL R. BLETZACKER

179 Q. WHY IS IT IMPORTANT TO RECOGNIZE THAT THE FUNDAMENTALS FORECAST IS WEATHER-NORMALIZED? A. It is important to recognize that the Fundamentals Forecast is a long-term, weather-normalized energy market forecast. Although there is the credible modeling expectation that each forecast-year experiences 0-year average heating and cooling degree days, actual weather can deviate dramatically. The combination of both heating degree day departure and above- or below-normal natural gas storage inventory levels are primary factors affecting any nearby deviation from a weather-normalized forecast value. For example, the winter of was the warmest winter on record in the lower states and it resulted in significantly reduced natural gas demand, -year average high natural gas storage inventory levels and materially depressed natural gas prices. Understandably, the Polar Vortex winter of had the opposite effects. When comparing actual results to a weather-normalized forecast, it is imperative to account for these impacts. Q. WOULD YOU EXPAND ON OTHER DETAILS ABOUT THE FUNDAMENTALS FORECAST? A. Yes. The AURORAxmp Energy Market Model is widely used by utilities for integrated resource and transmission planning, power cost analysis and detailed generator evaluation. The database includes approximately,000 electric generating facilities in the contiguous United States, Canada and Baja Mexico. These generating facilities include wind, solar, biomass, nuclear, coal, natural gas and oil. A licensed online data provider, ABB Velocity Suite, provides up-to-date information on DIRECT TESTIMONY KARL R. BLETZACKER

180 markets, entities and transactions along with the operating characteristics of each generating facility, which are subsequently exported to the AURORAxmp model. Q. WOULD IT BE REASONABLE TO RELY UPON NYMEX FUTURES CONTRACT PRICING IN LIEU OF A FUNDAMENTALS FORECAST FOR LONG-TERM CORPORATE PLANNING PURPOSES? A. No. NYMEX energy-complex futures contract prices are not a reliable forecast of future, weather-normalized, long-term energy market fundamentals. Futures market participants are either speculating or escaping the volatility of energy prices through risk management activities (hedging). NYMEX futures represent the price point at which a buyer and a seller can realize price certainty, but those commercial expectations do not represent the economic principles of demand, supply and the resulting price. For example, natural gas-consuming entities that have natural gas costs and manufacturing revenues that move independently may need to protect margin through hedging activities and the NYMEX futures market satisfies that need (by buying futures contracts). On the other side of that trade, a natural gas producer that is concerned about covering future exploration and production costs will also utilize futures market contracts (by selling futures contracts). Both sides of the transaction are satisfied with their hedged position, but neither participant is then concerned with the actual future price of natural gas. Q. WHY ARE NATURAL GAS PRICES IMPORTANT IN A FUNDAMENTALS ANALYSIS? A. Natural gas prices are important because fuel prices are a key component in determining the supply stack, or merit order, for the dispatch of generating units. DIRECT TESTIMONY KARL R. BLETZACKER

181 Generating units with the lowest variable operating cost are the first to dispatch and plants with incrementally higher variable operating cost are called upon sequentially as electricity demand increases. The latest vintage of gas-fired generators have improved efficiencies making them competitive with coal-fired generation s variable costs in some instances. But changes in gas prices can quickly advantage or disadvantage them relative to some coal-fired generation. Q. WHY ARE POTENTIAL CO ALLOWANCE PRICES IMPORTANT IN A FUNDAMENTALS FORECAST? A. CO emission costs would adversely affect the prices of electricity generated by fossil fuels relative to lower and zero carbon-intensive generating resources such as renewables. CO regulations would also affect fuel markets, e.g., an increase in natural gas consumption will result in increased natural gas prices. The direct effect of a $ per tonne allowance price for a coal plant is an approximate $ per MWh increase in plant variable operating costs. And likewise, a $ per tonne allowance price for a natural gas-fired combined cycle plant is an approximate $ per MWh increase in plant variable operating costs. Q. WHAT ARE THE SALIENT FEATURES OF YOUR MOST RECENT (LATE-01) FUNDAMENTALS FORECAST? A. Natural Gas. Figure illustrates the most recent natural gas price forecast in real dollars for the Base, High and Low scenarios at the benchmark Henry Hub. The Fundamentals Forecast recognizes the balance between long-term increase in demand (the expanding role of natural gas for electric generation, the prospect of liquefied natural gas exports, natural gas for use as a transportation fuel, and others) and the DIRECT TESTIMONY KARL R. BLETZACKER

182 likelihood of cost-effective advances in shale-directed drilling and completion techniques (longer laterals, increased fracturing stages, proppant delivery, and others). Abundant, relatively low-cost natural gas reserves and productive capacity will continue to grow domestically and globally as shale gas extraction technology becomes more widespread. Despite negative reaction in some regions of the country, the long-term environmental impacts of shale gas development will ultimately be manageable. Natural gas pipeline capacity is expected to keep pace with the evolving locations of supply and consumption as the extensive domestic natural gas transportation infrastructure is sufficiently robust to overcome constraints through existing capacity expansions, flow reversals and new construction. DIRECT TESTIMONY KARL R. BLETZACKER

183 Figure 01H Henry Hub Natural Gas $ $ $ Natural Gas Prices - $/mmbtu $ $ $ $ 1 $ Base Real 01$ Low Real 01$ High Real 01$ CO Mitigation. The 01 Fundamentals Forecast employed a CO dispatch burden (allowance price) on all existing fossil fuel-fired generating units that escalates from $. per ton in 0 to $.1 per ton in 0 in order to achieve national mass-based emission targets similar to those proposed in the Clean Power Plan. Q. DO NEAR-TERM LOW NATURAL GAS PRICES INDICATE THAT PRICES WILL BE LOW FOR A LONG TIME? A. No, not necessarily. Natural Gas prices can deviate from fundamental price for extended periods due to a variety of reasons including weather and force majeure situations such as hurricanes Katrina and Rita. As discussed earlier, actual heating- DIRECT TESTIMONY KARL R. BLETZACKER

184 and cooling-season weather can deviate dramatically from normal. Warmer-than-normal winters result in less gas demand and less storage re-fill demand in the following summer with correspondingly discounted natural gas prices. This is exactly what the U.S. experienced in the winters of and (some of the warmest winters in recorded history), which resulted in natural gas spot prices that were significantly lower than weather-normal values. Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes, it does. DIRECT TESTIMONY KARL R. BLETZACKER

185 PUBLIC UTILITY COMMISSION OF TEXAS APPLICATION OF SOUTHWESTERN ELECTRIC POWER COMPANY FOR CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZATION AND RELATED RELIEF FOR THE WIND CATCHER ENERGY CONNECTION PROJECT DIRECT TESTIMONY OF RENEE V. HAWKINS FOR SOUTHWESTERN ELECTRIC POWER COMPANY JULY 1, 01

186 SECTION TESTIMONY INDEX PAGE I. INTRODUCTION...1 II. PURPOSE OF TESTIMONY... III. FINANCING PLAN... IV. CREDIT RATING IMPACTS... V. RETURN ON EQUITY... VI. DISCOUNT RATE FOR ANALYSIS... EXHIBITS EXHIBIT EXHIBIT RVH-1 EXHIBIT RVH- EXHIBIT RVH- DESCRIPTION Moody s: Rate-Basing Wind Generation Adds Momentum to Renewables Moody s SWEPCO Credit Opinion dated September 01 Standard and Poor s Ratings Upgrade to A- dated February 01 DIRECT TESTIMONY i RENEE V. HAWKINS

187 I. INTRODUCTION Q. PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS. A. My name is Renee V. Hawkins. I am Assistant Treasurer and Managing Director, Corporate Finance for American Electric Power Service Corporation (AEPSC), a wholly owned subsidiary of American Electric Power Company, Inc. (AEP). AEP is the parent company of Southwestern Electric Power Company (SWEPCO or Company) and AEPSC is SWEPCO s service company. In addition, I am the Assistant Treasurer of SWEPCO. My business address is One Riverside Plaza, Columbus, Ohio 1. Q. WHAT IS YOUR EDUCATIONAL BACKGROUND? A. I received a Bachelor s Degree in Finance and International Business from The Ohio State University in Columbus, Ohio in 1, and a Master s Degree in Business Administration with a Finance concentration from the Simon School at the University of Rochester in Rochester, New York in. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND. A. I was first employed by State Teachers Retirement System of Ohio in 1 in the Real Estate section where I was assigned to asset management. In June, I was employed by General Motors as an analyst for AC Delco, which is now a subsidiary of Delphi East. In June 1, I was hired by Cablevision Systems Corporation, first as a Senior Financial Analyst and then promoted to Treasury Manager. My responsibilities included managing capitalization and liquidity for a number of subsidiaries. Included in those responsibilities was raising capital through bank DIRECT TESTIMONY 1 RENEE V. HAWKINS

188 markets and financial markets, managing compliance, and supporting investor and rating agency relations. In 1, I joined AEPSC as a Corporate Finance Senior Analyst supporting financing activity for the AEP operating companies. In 1, I was named Manager, Corporate Finance. In 000, I was named Director, Corporate Finance, a position that was renamed Director, Regulated Finance in 001. In 00, I was promoted to Managing Director, Corporate Finance with the responsibility for capital markets activity for the regulated utilities, and such things as establishing dividend recommendations and capitalization targets, supporting the rating agency relationships to maintain credit ratings and assisting in the management of liquidity for the overall AEP system. In 00, I was named Assistant Treasurer of AEP, SWEPCO and the other utilities. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE OR BEEN AN EXPERT WITNESS IN PROCEEDINGS BEFORE REGULATORY BODIES? A. Yes, I most recently testified on behalf of SWEPCO in the Company s base rate proceeding, Public Utility Commission of Texas (PUC or Commission) Docket No. and I also testified in Docket Nos, 1, 0, and 1. I have also provided testimony or testified on financial matters such as financial integrity and cost of capital on behalf of: SWEPCO before the Arkansas Public Service Commission and the Louisiana Public Service Commission; Public Service Company of Oklahoma (PSO) before the Oklahoma Corporation Commission; Appalachian Power Company before the Public Service Commission of West Virginia and the Virginia State Corporation Commission; Indiana Michigan Power Company before DIRECT TESTIMONY RENEE V. HAWKINS

189 the Indiana Utility Regulatory Commission and the Michigan Public Service Commission; and Ohio Power before the Public Utilities Commission of Ohio. II. PURPOSE OF TESTIMONY Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? A. The purpose of my testimony is to address how the Company intends to finance the purchase of the Wind Catcher Facility (Wind Facility) and the construction of the associated Wind Catcher Generation-Tie line (Gen-Tie Line), together referred to as the Wind Catcher Energy Connection Project (Project), as well as discuss the impact on credit ratings and support the return on equity (ROE) III. FINANCING PLAN Q. PLEASE GIVE AN OVERVIEW OF HOW THE COMPANY INTENDS TO FINANCE THE PROJECT. A. Ownership percentages for the Project are targeted at 0% and 0%, for SWEPCO and PSO, respectively. SWEPCO intends to utilize a combination of short- and long-term debt and equity contributions from its parent, AEP, to fund the Project with an approximate capital structure of % - % debt and % % equity. This is consistent with SWEPCO s current capital structure. The Company may enter into a revolving credit agreement to initially fund the construction expenditures prior to issuing long-term debt. Q. PLEASE DESCRIBE THE ACCESS THE COMPANY HAS TO SHORT-TERM DEBT FINANCING. DIRECT TESTIMONY RENEE V. HAWKINS

190 A. SWEPCO participates in the Utility Money Pool through which it can lend and borrow short-term funds from other AEP utility subsidiaries. SWEPCO has authorization from the Federal Energy Regulatory Commission (FERC) to access up to $0 million of short-term financing from that source. As part of financing the Project, SWEPCO may file an application with the FERC for additional short-term debt issuance authority, which would provide the Company with additional liquidity for the Project. Q. DO YOU HAVE AN ESTIMATE OF LONG-TERM DEBT ISSUANCES TO FINANCE THE PROJECTS? A. The debt issuances associated with this Project will be approximately $1. billion. Q. PLEASE DESCRIBE SWEPCO S LONG-TERM DEBT FINANCING CAPABILITIES DURING CONSTRUCTION OF THE GEN-TIE LINE. A. SWEPCO has an application pending with the FERC to issue long-term debt not to exceed $0 million in order to refinance the 01 maturities of $ million and repay short-term debt. In order to finance this Project, SWEPCO intends to file an application with the FERC to issue up to $. billion in long-term debt for 01 through 00, inclusive of $ million in maturities. Q. PLEASE DISCUSS SWEPCO S EQUITY CONTRIBUTIONS FROM ITS PARENT AS A FINANCING METHOD. A. As needed, SWEPCO will also receive equity contributions from AEP to finance the Project. This is consistent with how AEP currently contributes equity for major projects. The intent of the capital contributions will be to maintain a capital structure consistent with the current levels of debt and equity, and the equity contributions are DIRECT TESTIMONY RENEE V. HAWKINS

191 approximately $1. billion for the Project. A portion of this requirement may be met by deferring dividends to SWEPCO s parent company, AEP. Q. DO YOU HAVE ANY CONCERNS REGARDING FINANCING A PROJECT OF THIS MAGNITUDE FOR SWEPCO? A. No. Based on SWEPCO's current credit ratings, we are able to finance a project of this size at a reasonable cost. As I mentioned previously, a revolving credit agreement may also be pursued to manage the timing of the long-term debt issuances IV. CREDIT RATING IMPACTS Q. DO YOU EXPECT THIS PROJECT TO IMPACT SWEPCO S CREDIT RATINGS? A. No. The Project is supportive of the long-term credit ratings of the Company. In fact, Moody s Investor Service (Moody s) published a report that I have attached as EXHIBIT RVH-1 indicating that rate-based wind projects are positive for credit quality. The Moody s article states: Wind in rate base creates a 'win-win-win' situation for utilities, regulators and customers, characterized by higher rate base and earnings for utilities, lower utility rates and a cleaner portfolio for customers and regulators. Q. WHAT ARE SWEPCO S CURRENT CREDIT RATINGS? A. SWEPCO is currently rated Baa (stable outlook) and A- (stable outlook) from Moody s and Standard and Poor s (S&P), respectively. The most recently published reports are included as EXHIBITs RVH- and RVH-. DIRECT TESTIMONY RENEE V. HAWKINS

192 The rating agencies use a number of factors to determine the credit ratings of utilities, which include both the regulatory recovery mechanisms and the quantitative factors such as debt to capitalization and cash flow generated versus the debt obligations. In February 01, S&P upgraded AEP s senior unsecured credit rating to BBB+ and the utilities to A-. This was upon AEP s completion of the sale of the merchant business. S&P uses a group methodology whereby all the subsidiary ratings are based on the consolidated rating. I do not expect any impact from this Project on SWEPCO s S&P rating given the group methodology. Q. HOW DOES SWEPCO PLAN TO RECOVER THE COSTS OF THE PROJECT? A. As discussed by SWEPCO witness John O. Aaron, SWEPCO is requesting that it be allowed to pass the Project revenue requirement and PTCs to customers through fuel expense until the Project is included in SWEPCO s base rates. Q. DO YOU AGREE THAT THIS METHOD IS NECESSARY TO RECOVER THE COSTS OF THE PROJECT? A. Yes. The Company will be making a significant investment in these assets and will need recovery of the costs as soon as the assets go into service. SWEPCO s current net plant is approximately $. billion and upon completion this Project will grow assets by an additional $. billion or a % increase in net plant assets. For an investment of this magnitude, the Company requires recovery of both a return on and a return of the assets in order to protect the financial condition of the Company as soon as the Project becomes commercial. The absence of timely recovery of the costs DIRECT TESTIMONY RENEE V. HAWKINS

193 of these assets would negatively impact earnings, cash flows and the resulting financial metrics relied upon by fixed-income investors and the credit rating agencies V. RETURN ON EQUITY Q. WHAT IS THE COMPANY PROPOSING FOR RETURN ON EQUITY (ROE)? A. SWEPCO is proposing that the ROE be based on the approved ROE in effect during this initial recovery period. The ROE can be updated when a new ROE is established through a traditional rate proceeding. Q. WHAT ROE WAS USED IN THE ANALYSIS PRESENTED IN THIS CASE? A. For the analysis presented in this case, an ROE of.% was used. That ROE presents a reasonable view of the Project over its entire life and recognizes that interest rates are anticipated to be higher over the life of the Project. The U.S. Federal Reserve has begun to increase the Federal Funds rate resulting in an overall increase in interest rates. The 0-year treasury rate has already increased from the lows of.% in July of 01 to a rate of.% on June 0, VI. DISCOUNT RATE FOR ANALYSIS Q. ARE YOU SPONSORING THE DISCOUNT RATE USED IN SWEPCO WITNESS KELLY D. PEARCE S TESTIMONY? A. Yes. In the savings analysis completed by witness Pearce, he is using a discount rate of.%. This discount rate is a weighted average cost of capital (WACC) based on the average of the WACCs that have been approved in SWEPCO s jurisdictions and what was filed in the recent SWEPCO Texas rate case. DIRECT TESTIMONY RENEE V. HAWKINS

194 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes, it does. DIRECT TESTIMONY RENEE V. HAWKINS

195 EXHIBIT RVH-1 Page 1 of INFRASTRUCTURE AND PROJECT FINANCE SECTOR IN-DEPTH 1 March 01 Rate-Basing Wind Generation Adds Momentum to Renewables Contacts Jairo Chung Analyst jairo.chung@moodys.com US Power and Utilities 1--1 Swami 1--0 Venkataraman, CFA Senior Vice President swami.venkat@moodys.com Natividad Martel, 1--1 CFA VP-Senior Analyst natividad.martel@moodys.com Jillian Cardona Associate Analyst jillian.cardona@moodys.com John Medina VP-Senior Analyst john.medina@moodys.com 1--0 Lesley Ritter Analyst lesley.ritter@moodys.com 1-- Michael G. Haggarty 1--1 Associate Managing Director michael.haggarty@moodys.com Jim Hempstead 1--1 MD-Utilities james.hempstead@moodys.com There is growing support for low-cost wind generation in many states. Many utilities are replacing older, inefficient coal-fired plants with wind capacity, sometimes even in the absence of renewable portfolio standards (RPS). As utilities look to grow rate base by adding wind, the momentum behind renewable expansion continues to build. Declining wind generation cost puts coal plants at risk. Average wind power prices in the Great Plains are now ranging around $0/MWh versus over $0/MWh for just the operating costs of most coal plants. As a result, utilities can displace energy from coal with that from wind while growing rate base. We estimate about GW of coal capacity in the Great Plains has an operating cost higher than $0/MWh and faces lower capacity factors going forward, and potentially early retirement. About GW of this at risk capacity is owned by regulated utilities with at least,000 MW at risk. Rate base opportunity creates 'win-win-win' situation. Wind in rate base creates a 'win-win-win' situation for utilities, regulators and customers, characterized by higher rate base and earnings for utilities, lower utility rates and a cleaner portfolio for customers and regulators. States have varying motivations for allowing wind. States like Iowa and Kansas view wind as a natural option to lower costs even if there is not an RPS. States like Minnesota and Colorado already have a high RPS that has mostly been met. However, the low cost of wind is allowing them to exceed such targets with an eye towards longer term climate goals. Others such as MO and WY may see limited wind additions. Potential for 'stranded assets' as coal plants are replaced? Most likely limited. We believe regulators will allow cost recovery even if plants we identify as at risk are eventually retired. The remaining value of coal plants in rate base should be small for many companies given the age of the fleet, though some have about 0% of rate base in coal generation. Public power utilities are moving in a similar direction. Public power utilities in the Great Plains are also replacing traditional fuel based generating capacity with new wind power purchase agreements (PPAs) and natural gas plants. THIS REPORT WAS REPUBLISHED ON 1 MARCH 01 WITH CORRECTIONS TO THE APPENDIX.

196 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE Integration risks exist but wind is currently in a sweet spot. Improved wind forecasting has reduced wind variability risks significantly. Further, wind is currently in a sweet spot where a lot more wind can be added to the grid in most states without a substantial increase in integration costs. Utilities can also mitigate the loss of coal jobs over time. Declining cost of wind generation puts coal plants at risk Wind power has seen substantial cost decline over the past few years, making wind much more competitive compared to traditional fuel sources such as coal. In the Great Plains states, which have the best wind resources, the average long-term all-in purchase power agreement (PPA) prices for wind power are now in the $0/MWh range. In contrast, the majority of the coal-fired power plants in this region have operating costs (fuel + operating and maintenance (O&M) cost + maintenance capex) that are higher than $0/MWh. This cost difference is causing coal-fired power plants to lower their production, especially during the off-peak hours, and in some cases to retire them. When we speak of wind replacing coal, it is about wind displacing coal from the dispatch stack on an energy basis. Wind plants only provide a fraction of the capacity value of coal plants on account of the intermittent nature of the resource. Depending upon the wind resource and transmission constraints, this number varies anywhere from % to 0%. As more wind is added to the grid, coal plants will continue to operate, albeit with lower capacity factors. This would increase the per unit production costs of the coal units over time eventually leading to their retirement, a decision that utilities make on a case-by-case basis. Exhibit 1 shows a map of the wind resource in the US (left), highlighting the strength of the Great Plains region. To the right is a map of coal fired generation, mostly regulated, located in areas that also have a strong wind resource. Approximately GW of existing coal-fired power capacity is located in the 1 states that we include in our research. These are all regulated states and do not include unregulated states with strong wind resources such as Texas and Illinois. The decline of merchant coal power plants has been a welldocumented trend over the last several years, primarily driven by low natural gas prices. We believe regulated coal-fired power plants may also see a trend of earlier retirements in the Great Plains region, driven by low cost wind resources. Exhibit 1 Annual average wind speed is the highest in the middle of the U.S.; Older, expensive coal plants in the interior of the US are at risk Legend: Dot sizes reflect the size of the coal plant; a lighter shade reflects a lower capacity factor. Source: National Renewable Energy Laboratory (NREL) and SPGMI Exhibit illustrates the cost difference between existing coal plants and new wind generation. The operating costs of coal reflect a simple average of all the coal plants included in our study. The cost of wind, including integration costs, is lower than even the average variable costs of generation, although several coal plants do have lower variable costs than the all-in cost of wind. When considering the fixed O&M and maintenance capex costs of coal plants, there is potential for material cost reductions if coal plants are eventually shut down and replaced by wind. This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on for the most updated credit rating action information and rating history. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

197 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE Exhibit Operating cost for coal we estimate is higher than the cost of wind (Illustrative) Wind All-In Costs vs Coal Operating Costs $ $ $0 Generation Cost $/MWh $ $0 $ $0 $1 $ $ Fixed O&M and Maintenance Capex $1 Variable O&M $ Fuel $ Avg. Variable Cost of Coal Is Higher Than Avg. All-In Price Of Wind $ Integration Cost Adder $ All-In PPA Price $0 $0 Coal* Wind * Illustrative values based on the average cost of all coal plants studied Source: SPGMI, Moody's Investors Service Exhibit shows the percentage of coal-fired capacity at risk in each state. Approximately GW of capacity has an operating cost that exceeds $0/MWh (assuming $0/kW-yr for fixed O&M and maintenance capex), making them less competitive compared to the new wind generation. Coal plants that have costs less than $0/MWh tend to be either newer coal plants with higher efficiencies or plants located closer to coal mines, especially Powder River Basin (PRB) coal, and hence have a more competitive fuel cost. We identified approximately GW of capacity (see Exhibit ) owned and operated by major regulated utilities each with at least,000 MW at risk. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

198 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE Exhibit Approximately GW of coal-fired power generation, and GW at risk, in the 1 states with the best wind resource State Total MWs Risk Risk Total TWh Risk IN 1,1 1,1 0%.. MI,, %.1. MO 1,0, %.. KS,0,0 0%.. OK,, % MN,,1 %. 1. IA,,0 %. 1. CO,, % WY,,00 %. 1. NM,1 1,1 % 0.. UT, 1,1 0% NE,0 1%.. ND,0 0 1%.. SD 0% MT, % Total,, 0 Source: SPGMI, Moody's Investors Service Exhibit Companies with at least,000 MW of coal plants at risk Ultimate Parent Total MWs Risk Risk Total TWh Risk DTE Energy Company,0, %.. OGE Energy Corp.,1,1 0%.. Berkshire Hathaway, Inc.,,0 %. 1. Duke Energy Corporation,, 0% Xcel Energy Inc.,,01 %. 1. American Electric Power Co. Inc.,0,00 % Ameren Corporation,,01 % Westar Energy, Inc.,, 0% NiSource Inc.,, 0%.. Total 1,1 1,0. 1. Source: SPGMI, Moody's Investors Service Beyond 00, after the current tax credits expire, it is expected that continued cost reductions will keep wind competitive with existing coal plants even in the absence of PTCs. If PPAs in high wind areas today average $0/MWh, they are expected to average $0/MWh today without the PTC. In the next decade, a reduction in tax rates and/or equipment costs is expected to lower the cost of wind PPAs to $0-/MWh, a level that is likely to ensure continued growth of wind. Further, many coal plants may have fixed O&M and maintenance capex that exceeds Moody's assumption of $0/kW-yr, which would further support wind's competitive position. The general expectations for continued competitiveness of wind energy is reflected in the presence of plans for a number of large transmission lines to move wind from the Great Plains states, such as the Grain Belt Express (KS-MO-IL-IN), Plains & Eastern Clean Line (KS-AR-TN), and Rock Island Clean Line (IA-IL). However, if equipment prices do not decline, or rise due to a global upsurge in demand, and if other variables such as tax rates and interest deduction move in an unfavorable direction, the pace of wind s growth could be dampened. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

199 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE Rate base opportunity for wind creates potential 'win-win-win' situation Historically, utilities have been adding renewable generation through signing long-term PPAs to meet the RPS. The favorable pricing of wind generation gives utilities in the Great Plains states, which are mostly integrated utilities that own generation, the ability to invest in their rate base irrespective of the state's RPS. This creates a potential 'win-win-win' situation for utilities, regulators and customers, characterized by higher rate base and earnings, lower utility rates from displacing coal with wind and a cleaner portfolio. There is debate in many states about rate base vs PPAs for wind. While either option delivers cost savings compared to dispatching coal plants (even while continuing to recover coal capital costs via the rate base), there is some debate over which option would be better for ratepayers. Some of the issues involved are debated in any build vs buy decision. For example, buying implies that the resource goes away when the PPA ends. So, the build vs buy decision would be influenced by assumptions around the price at which the resource can be recontracted. Other differences relate to O&M costs at a regulated utility vs an unregulated IPP. One issue that is unique to wind relates to production tax credits (PTCs). IPPs utilize tax equity investors who can begin to monetize PTC benefits right away. In contrast, most utilities benefit from bonus depreciation through 00 and are not cash taxpayers currently. They will only realize PTC benefits over time, raising a question as to whether PPAs would be more cost effective. Nevertheless, it appears that most utilities are able to overcome this disadvantage because: (1) Utilities are generally required to pass-through the PTC benefits to rate payers as if they had been utilized in each year, either through the fuel clause or a reduction to the tax component of rates. To the extent that the utility has NOLs or bonus depreciation that exceed net income then a deferred tax asset is created. () Utilities have a materially lower cost of capital, with a roughly 0/0 debt/equity mix compared with IPPs for whom about 0% of the project cost is financed through tax equity and the rest often comes through sponsor equity as well. () Also, IPPs generally need to recover their capital costs within the 0- year term of the PPA while utilities can recover costs over the useful life of the asset. Ultimately, the split between utility rate base and PPAs seems to be a largely negotiated outcome, dictated both by benefits of utility ownership and a policy desire to support wind developers. Utilities we include fall into three categories (also see Appendix): 1. Utilities investing in wind driven largely by the economics. Utilities pursuing investments in lower cost wind generation based on a more aggressive environmental policy in the state where they operate. Utilities that are not pursuing any significant wind power investment Wind investment is driven primarily by economics in some states In recent integrated resource plans (IRP) filed by the utilities, we observe a meaningful amount of investments planned to add more wind generation capacity and to reduce the exposure to coal-fired power plants. For example, Westar Energy, Inc. (Westar, Baa1 stable) has been steadily adding wind to its generation portfolio. After initially owning and operating its own MW wind farm, the company added wind PPAs totaling 1, MW and additional 1 MW of owned wind between 0 and 01. Although there is no state RPS to meet (the state of Kansas repealed its RPS in May 01) Westar continues to look for opportunities to own or buy more wind generation that is economic for its customers. Companies such as Alliant Energy Corporation (Alliant, Baa1 stable) and MidAmerican Energy Company (MidAmerican, A1 stable) fall in a similar category. The RPS in Iowa requires the utilities to own or contract a combined total of MW of capacity. However, Alliant, which operates in Iowa through Interstate Power and Light Company (Interstate Power, Baa1 stable), has 00 MW of wind capacity in service with 0 MW to be added by mid-april 01. Interstate Power currently plans to request for an approval to add additional 00 MW of new wind capacity. The utility is also looking to either retire older coal- and gas-fired power plants or switch them to natural gas, and replace that capacity with combined cycle gas plants. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

200 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE MidAmerican owns more wind capacity in rate base than any other regulated utility in the U.S. In 01, it is expected that approximately % of its energy produced will be from wind. In August 01, the Iowa Utilities Board approved MidAmerican's plan to invest $. billion to increase its wind powered generating capacity through 01. This investment will add approximately GW of new wind capacity after which about % of the company's load will be supported by wind energy generation. Low-cost Wind enables some states to exceed RPS targets with a view towards long-term climate goals States such as Minnesota and Colorado have implemented strong RPS mandates. The economics of wind are now permitting these states to exceed today's RPS standards and target more aggressive longer term climate goals. Under Minnesota state law, utilities are required to lower emission levels by 0% below 00 levels by 0. They also have a RPS mandate of at least % of power sales. Allete, Inc. (Allete, A stable), has publicly stated a long-term target mix of /rd renewables and natural gas and 1/rd coal from a mix that is about /rd coal as of 01. Allete has MW of wind (imported from North Dakota where wind resource is better) in rate base at the end of 01 and plans to retire 0 MW of coal capacity by 00 as well as utilize a combination of hydro PPAs (with Manitoba Hydro) and new renewable projects not yet specified. In January 01, the Minnesota Commission approved the IRP of Xcel Energy Inc. s (Xcel, A stable) subsidiary Northern States Power Company Minnesota (NSP-Minnesota, A stable). The plan includes the retirement of two coal-fired units aggregating 1,00 MW through 0 as well as the addition of at least 1,000 MW of wind by 01 and potentially up to 0 MW. The mix between owning and signing PPAs was not specified but NSP-Minnesota is seeking authorization to rate base 0 MW. In combination with other initiatives, NSP-Minnesota expects to have 1.% of its generation from renewables by 00 compared with 1% in 01. Colorado has a 0% RPS standard by 00. Xcel's subsidiary Public Service Company of Colorado (PSCo, A stable) will invest $1 billion to build its first rate based 00 MW wind-farm in 01. PSCo s Electric Resource Plan, which is expected to go through the approval process this year, proposes to add an additional 00 MW of capacity by 0. PSCo had % of its supply coming from renewables in 01 and will likely exceed the state's RPS mandate by 00. Black Hills Corporation (Black Hills, Baa stable), through its subsidiary Colorado Electric, Inc. (not rated), has approximately MW owned wind generation and 1 MW of additional wind through a PPA. Some states will see limited wind investments States such as Missouri continue to see better economics for coal on account of the delivered cost of wind being somewhat higher than other states. Others such as Wyoming and the Dakotas have low coal prices and hence better competitiveness. However, some of these states, such as the Dakotas, have stronger wind resource and will see wind development to export to other states. Public power utilities are also moving in a similar direction Renewable energy additions for some public power utilities, e.g. in California, is driven by the state RPS. But like IOUs, the addition of wind capacity in the Midwest is driven by access to the regional energy markets such as the Southwest Power Pool and its abundant supply of low cost wind resources that are more economic than traditional sources. Most public power utilities are also seeing lower dispatch of coal units by their respective regional transmission operators (RTOs). Omaha Public Power District (OPPD, Aa stable) shut down its nuclear power plant Fort Calhoun Station at the end of 01 to start the early decommissioning process after determining this was the most cost effective route over the long-term. OPPD is long on power and thus does not have to replace all of the capacity of the plant. In addition, OPPD signed a 00 MW wind PPA to provide the utility with low cost replacement power that will immediately lower generation costs once operational at the end of 01. Utilities such as Lansing Board of Water and Light (Aa, stable) in Michigan and Unified Government of Wyandotte County/Kansas City, Kansas' Board of Public Utilities (BPU, A, positive) in Kansas intend to transition their fleet away from coal and towards natural gas and renewables over the next decade. This includes the addition of new wind - MW and 00 MW, respectively - and either new gas fired generation or conversion of coal to gas to help manage the intermittency of wind. Coal-fired power plants becoming 'stranded assets'? These trends raise the possibility that existing coal plants could be vulnerable to becoming 'stranded assets' in the future. In other words, they become obsolete well ahead of their useful life and there maybe questions on whether the utility can continue to recover costs through rate base, especially if the plants have been shutdown. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

201 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE We believe this risk is generally low because utilities are able to maintain or even lower customer rates as they increase rate base with wind assets. Where coal plants have been retired thus far, utilities have been allowed to continue to recover their capital costs. In addition, over % of the coal-fired power plants by capacity we identified as being at risk are more than 0 years old (see Exhibit ). As a result, the amount of rate base associated with these plants is likely to be limited. However, utilities that own relatively new coal plants, or have invested substantially in pollution control equipment, may have a greater share of rate base in coal-fired power generation and hence greater risk. A number of utilities in the region have approximately 0% of their rate base in coal-fired generation. Exhibit The majority of the coal plants at risk we identified are over 0 years old,000 1.% 0,000 Capacity (MW) 1,000,000.% 1.% 1.%, % 0.% > > 0 Coal Plant Age (Years) Source: SPGMI, Moody's Investors Service Integration risks exist but wind industry is currently in a 'sweet spot' The intermittency of wind creates a need for back up generation. This has been the focus of the utility industry for more than a decade. A number of factors currently serve to mitigate this risk and support the growth of wind.» Wind forecasting has improved dramatically. A major reason for higher integration risks in the past was the relatively poor ability to forecast wind generation over the near term such as a day ahead. Forecasting capabilities have improved substantially over time, significantly reducing this risk.» Utility resource planning incorporates adders. IRPs at utilities incorporate adders when considering the cost of new wind resources compared to other options. There are also adders for the increased cost associated with cycling of coal plants as opposed to baseload operation.» Regional markets act as a mitigation factor. Regional transmission operators such as MISO make it easier to manage intermittency of wind and has been cited by utilities as a factor in supporting the wind build out.» Wind is currently in a 'sweet spot'. As a result of better wind forecasting, and given its very low cost, wind energy currently occupies a sweet spot as a low cost resource that does not impose large integration costs. States like Colorado and Iowa have very high wind penetration levels without the grid facing reliability issues or large integration costs. In most states, given the presence of other dispatchable resources and no load growth, wind is currently in a sweet spot where significantly more wind resources can be added to the grid without substantial increases in integration costs. For example, a study by the Minnesota Dept of Commerce, along with MISO, concluded that a 0% RPS standard can be reliably accommodated in the state by the electric power system with upgrades to existing transmission. The study also concluded that achieving a 0% RPS standard in Minnesota and % across MISO North-Central (% above current standards), would require significant transmission upgrades and expansions across five states of MISO North-Central.» Gas generation, storage needed in the long run. As the share of wind generation in the grid increases, additional gas fired generation or battery storage will eventually be needed to accommodate more wind resources. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

202 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE Coal jobs could be an issue, but mitigants exist Given the Trump administration s support for coal, the loss of coal jobs at plants that are shutdown could emerge as a political issue. We however think there are mitigants to this issue in the Great Plains states.» Except for Wyoming, the Great Plains states are not large coal mining states. Job losses are mainly at the coal plants themselves, which reduces potential losses. We think the shutdown of coal will happen in increments and not abruptly. Further, utilities have thus far mitigated the impact through a combination of reassignment and natural attrition. States such as Minnesota are also building gas-fired plants at the same site as the coal plant.» Wind energy has been a growth industry in the Great Plains states for many years now. Wind has brought significant growth in employment and tax base in most of these states. Wind energy also has the support of the farm lobby in these states as farmers earn income from leasing land for the wind towers while also growing crops around the footprint of the towers. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

203 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE Appendix 1 Exhibit Utility wind investment and coal retirement by state State RPS Company Wind investments Wind resource Coal retirements Black Hills PPA (1.MW); Own (.MW) N/A (all natural gas operations in CO) Colorado 0% renewables by 00 PPA(~,0MW) in 01 to a Medium Retired ~00MW between Will retire/convert ~0MW by Xcel combination of PPA and own (~,MW) 01. Decrease coal capacity to ~1,0MW by 01 by 01 North Dakota Oklahoma South Dakota Wyoming AES PPA (00MW) Retired/Coverted ~0MW between AEP Contracted renewables across all operating companies (,0MW) None Indiana Voluntary goal: % renewables by 01 Duke PPA (0MW) Medium-Low Cease coal burning at R. Gallagher Units and by 0 (0MW). NiSource PPA (0MW) Schahfer: Retire Units 1 and 1 end of 0 (~0MW). Bailly: Retire Units and by 01 (~0MW). Vectren Corp PPA (0MW) Warrick Unit to retire in 00 (M). AB Brown Units 1 and, and Culley Unit to retire in 0. (Total 0MW) Iowa Kansas 00MW wind in service. 00MW will be in Retire Prarie Creek Units 1, and by 0 and Unit by 01 Own or contract a Alliant service by 00. (1MW). Burlington ST fuel switch by 01 (0MW) combined total of MW High Own (,00MW); Under construction George Neal North retired 1& 01 (MW). Walter Scott Jr. Enery of renewables Berkshire Hathaway (,000MW). Center retired 1& 01 (1MW). Voluntary goal: 0% Great Plains PPA (0MW); Own (MW) (All future retirements are in Missouri) High renewables by 00 Westar PPA (1,MW); Own (0MW) Retired older, smaller units (MW) CMS Energy Corp PPA (MW); owned (1MW); MW under development; 00MW potential to Retired seven smaller generating units 0/01 rate base Michigan 1% renewables by 01 Low DTE expects to retire more coal to increase renewable & natural gas DTE Energy Company Own (0MW) proportions over next 1 years WEC Energy Group None Presque Isle: Retired/converted to natural gas (MW). ALLETE Own (MW) Laskin (1MW) converted to gas in 01. Taconite Harbor Energy Center Unit (1MW) retired in 01 and Units 1 and (MW) "idled" in 01. Boswell Units 1 and (1MW) retirement in 01. Minnesota.% renewables by 0 Ceasing coal-fired operations 00 (1,MW). Medium Otter Tail Corp PPA (.MW); Own (1MW) Retire Hoot Late by 01 (MW) PPA 1,0MW; Own MW in 01. Xcel Plans to add up to 1,00MW a Retire Sherco (1,00MW) Unit by 0 and Unit 1 by 0. combination of PPA and own. Ameren Corp PPA (MW) Converted Meramec Units to natural gas (~0MW) Missouri 1% renewables by 01 Great Plains Lake Road: Ceased burning coal at Unit (less than MW). Montrose: PPA (1MW). Will purchase power to Medium Will retire or convert to natural gas (MW). Sibley: Will retire or meet RPS. convert to natural gas (0MW). Empire District Electirc PPA (MW) N/A Montana New Mexico 1% renewables by 01 NorthWestern Corp PPA (1MW); Own (0MW) Medium N/A Puget Energy PPA (MW); Own (MW) Retire Colstrip Units 1 and by 0 (0MW) PPA (MW total, 1MW in NM); Own Pinnacle West 0% renewables by 00 (MW) Medium-Low Retired Four Corners Units 1- (0MW) in 01. PNM Resources Own (0MW) Retire San Juan Units and by Dec 01 (0MW) Voluntary goal: % renewables by 01 Otter Tail PPA (.MW); Own (1MW) High N/A Voluntary goal: 1% renewables by 01 PPA (MW); Own (MW) High Convert Muskogee Units and to natural gas (1,00MW) Voluntary goal: % renewables by 01 None Sources: Ks, Company Reports and Investor Presentations NorthWestern Corp Own (0MW) High Otter Tail PPA (.MW); Own (1MW) N/A Berkshire Hathaway PPA (1,000MW, solar and wind); Own (1,00MW) High-Medium Convert Naughton Unit to natural gas by year-end 01 (0MW) Black Hills PPA (.MW) N/A 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

204 MOODY'S INVESTORS SERVICE EXHIBIT RVH-1 Page of INFRASTRUCTURE AND PROJECT FINANCE Moody's Related Research Outlook» 01 Unregulated Power and Utilities - US Outlook - Against Persistent Headwinds, Fundamentals Remain Negative ()» 01 Regulated Utilities - US Outlook - Timely Cost-Recovery Drives Stable Outlook, November 01 (1) Sector-In-Depth» Economics, End-User Sustainability Policies Drive Renewables in a Post-CPP World (0)» Carbon Transition Brings Risks and Opportunities, October 01 (0)» Electric Car Growth Boosts Utilities; Mixed Implications for Autos and State Finances, October 01 (1)» Differentiating Major Utility Holding Companies Using Five Key Criteria, October 01 ()» State Formula Rate Plans Improve Utility Credit Quality, October 01 ()» Utility Diversification Strategies Seek Growth While Limiting Risk, October 01 (00)» Summer Heat Fails to Spark Power Prices Aug 01 ()» Exelon and Entergy Will Benefit from New York State s Nuclear Power Subsidy August, 01 (1)» Key Areas Where Financial Disclosure Varies, June 01 (0) To access any of these reports, click on the entry above. Note that these references are current as of the date of publication of this report and that more recent reports may be available. All research may not be available to all clients. 1 March 01 US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables

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206 EXHIBIT RVH- Page 1 of INFRASTRUCTURE AND PROJECT FINANCE CREDIT OPINION 1 September 01 Update Southwestern Electric Power Company Vertically integrated electric utility subsidiary of AEP Summary Rating Rationale RATINGS Southwestern Electric Power Company Domicile Shreveport, Louisiana, United States Long Term Rating Baa Type LT Issuer Rating Outlook Stable Please see the ratings section at the end of this report for more information. The ratings and outlook shown reflect information as of the publication date. Southwestern Electric Power Company s (SWEPCo) Baa rating reflects its position as a vertically integrated electric utility company operating in relatively supportive regulatory environments with financial metrics that are supportive of the rating. SWEPCo's coal and lignite fleets have incurred sizeable amounts of environmental capex in recent years, which has caused an increase in debt burden and resulted in negative free cash flow. However, due in part to the formulaic recovery mechanisms available in most of its jurisdictions, as well as the continued cash flow benefits of bonus depreciation, credit metrics have remained appropriate for the rating. Exhibit 1 Historical CFO Pre-W/C, Total Debt and CFO Pre-W/C to Debt ($ in millions) Analyst Contacts Laura Schumacher 1-- VP-Sr Credit Officer laura.schumacher@moodys.com Michael G. Haggarty 1--1 Associate Managing Director michael.haggarty@moodys.com Jim Hempstead 1--1 Associate Managing Director james.hempstead@moodys.com Source: Moody's Investors Service Credit Strengths» Diversified and relatively supportive regulatory jurisdictions» Appropriate financial metrics Credit Challenges» Arkansas' MW portion of the Turk coal plant is exposed to competitive markets» Capital spending will remain elevated

207 MOODY'S INVESTORS SERVICE EXHIBIT RVH- Page of INFRASTRUCTURE AND PROJECT FINANCE Rating Outlook SWEPCo's stable rating outlook reflects the company s diversified service territory, relatively supportive regulatory jurisdictions and appropriate financial metrics. The outlook incorporates our expectation that the company will continue to receive timely expense recovery, and that the environmental and other capital expenditures will be timely recovered via riders or base rates. Factors that Could Lead to an Upgrade» Interest coverage above.x and cash flow pre-working capital (CFO pre-w/c) to debt above 1%, on a sustainable basis» Continued progress in fuel diversification Factors that Could Lead to a Downgrade» A deterioration in the regulatory environment resulting in greater regulatory lag» A material decline in key financial credit metrics including CFO pre-w/c to Debt below 1%, on a sustained basis. Key Indicators Exhibit [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non-Financial Corporations. Source: Moody's Investors Service Detailed Rating Considerations Diversity and overall supportiveness of regulatory jurisdictions SWEPCo's operations are spread across Louisiana, Arkansas and Texas and the company also supplies energy to wholesale customers under Federal Energy Regulatory Commission (FERC) regulated contracts. We view all of these jurisdictions as relatively credit supportive. Of the three state regulatory jurisdictions, we consider Louisiana to be the most constructive due to its formula rate base (FRB) process and a comprehensive suite of recovery mechanisms. Arkansas provides an annual fuel cost pass-through and suite of recovery mechanisms, while Texas provides fuel cost recovery three times a year, a less prescriptive suite of recovery mechanisms, and has exhibited greater regulatory lag. Vertically integrated utilities operating in Texas have generally experienced less favorable regulatory treatment than transmission and distribution utilities. On balance, our rating assumes a continuation of reasonable rate treatment across SWEPCo s various jurisdictions. The service territories in which SWEPCo operates are all substantially exposed to industries that are impacted by energy prices such as mining, natural resources, and energy-related manufacturing. According to Moody s Economy.com, overall, Louisiana s economy will be slow to recover, as low oil and gas prices curb mining, shipping and state government. Arkansas slowdown is also expected to continue, with meaningful improvement unlikely before 01, while Texas will avoid a recession, but growth is expected to be slow for another year. There is a bright spot however, in the Fayetteville Arkansas region where employment is centered in professional services, food manufacturing and healthcare, and the area is flourishing. This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on for the most updated credit rating action information and rating history. 1 September 01 Southwestern Electric Power Company: Vertically integrated electric utility subsidiary of AEP

208 MOODY'S INVESTORS SERVICE EXHIBIT RVH- Page of INFRASTRUCTURE AND PROJECT FINANCE Arkansas portion of Turk plant exposed to competitive markets The 00 MW Turk plant, an ultra-supercritical coal generating facility located in Arkansas, began commercial operation in December 01 with a total capitalized cost of about $1. billion for SWEPCo s % (0 MW) share. While approximately 0% of the Turk investment is recovered under cost-based rate recovery in Texas (1 MW) and Louisiana (1 MW), and through SWEPCo s wholesale customers under FERC-based rates ( MW), such is not the case in Arkansas. The Arkansas Public Service Commission (ARPSC) granted approval for SWEPCo to build the Turk plant by issuing a certificate of environment compatibility and public need for the Arkansas jurisdiction share of the plant (approximately 0%). However, the Arkansas Supreme Court reversed the certificate grant following an appeal by certain interveners, resulting in the ARPSC s reversal of its order in June 0. In response, SWEPCo filed notice to the ARPSC stating that the MW not being recovered in retail rates would be available for market-based sales and FERC-regulated wholesale sales. To date, none of these megawatts have been contracted which means the entire Arkansas portion is exposed to the merchant market which, given low gas prices, is unlikely to permit full recovery of capital costs. Capital program is moderating, but will remain substantial For the past few years, SWEPCo has been spending heavily on environmental capital expenditures primarily to bring its coal-plants into compliance with the US Environmental Protection Agency s Mercury Air Toxics Standards (MATS), with total annual capital expenditures averaging about $00 million per year. In 01, SWEPCo completed modifications to the MW Units 1 and of the Welsh coal plant, and closed the similarly sized Unit in accordance with its compliance plan. As of June 0, 01, SWEPCo had incurred costs of $ million (including AFUDC), relating to the Welsh environmental projects, and had remaining construction obligations of $0 million. SWEPCo will recover the Louisiana and Arkansas components of these costs via formula/rider recovery and will seek approval for Texas and FERC jurisdictional portions of the investment through regular rate proceedings. Over the next few years capital expenditures are expected to moderate somewhat with plans for about $00 million per year focused primarily on transmission and distribution projects. SWEPCo estimates approximately $0 million of additional environmental compliance spending will be needed at Welsh to meet proposed more stringent environmental regulations expected by 0; however the bulk of this investment would likely begin around 0. Appropriate financial metrics For the twelve months ending June 0, 01, we calculate SWEPCo's ratio of CFO pre-w/c to debt as 1.1%; as of year-end 01, the ratio was 1.%. The ratio of CFO pre-w/c plus interest to interest (interest coverage) during the same two periods were.0x and.x, respectively. These ratios fall comfortably fall in the Baa scoring range for these factors indicated in our rating methodology for regulated electric and gas utilities under the standard grid. As of June 0, 01, SWEPCo generated a three year average CFO pre-w/c to debt metric of 1.% and a three year average interest coverage ratio of.x. Going forward we anticipate SWEPCo s metrics will remain appropriate for the rating with CFO pre-w/c to debt in the mid-teens and interest coverage in the low x range. Liquidity Analysis Given its large capital expenditure program and upcoming debt maturities, SWEPCo s liquidity profile is currently below average. In 01, the company generated about $ million of cash from operations, invested about $1 in capital expenditures and paid $1 million in dividends, resulting in a negative free cash flow of about $ million. The shortfall was primarily funded with long-term debt proceeds and use of intercompany borrowings. Going forward, we anticipate capital expenditures will moderate to about $00 million per year resulting in modest negative free cash flow that will continue to be funded via a combination of internal and external borrowings. The AEP family uses a corporate borrowing program to meet the short-term borrowing needs of all the subsidiaries, which includes a utility money pool. SWEPCO participates in the money pool with a FERC authorized borrowing limit of $0 million. As of June 0, 01, SWEPCO had approximately $1 million of cash and $1 million in net loans from the money pool. SWEPCo's next maturity is 1 September 01 Southwestern Electric Power Company: Vertically integrated electric utility subsidiary of AEP

209 MOODY'S INVESTORS SERVICE EXHIBIT RVH- Page of INFRASTRUCTURE AND PROJECT FINANCE in January 01, when $0 million in senior notes are due as well as in July 01, when a $0 million senior unsecured term loan is due. We expect SWEPCo will look to refinance these maturities comfortably in advance of their due dates. Corporate Profile Southwestern Electric Power Company (SWEPCo, Baa stable) is a vertically integrated electric utility, and a wholly owned subsidiary of American Electric Power Company, Inc. (AEP, Baa1 stable). SWEPCo s retail operations are regulated by the Louisiana Public Service Commission (LAPSC), the Arkansas Public Service Commission (ARPSC), and the Public Utility Commission of Texas (PUCT). The company also sells wholesale power under contracts regulated by the Federal Energy Regulatory Commission (FERC). As of Q 01, SWEPCo represented roughly 1% ($. billion) of AEP's jurisdictional rate base. SWEPCo serves approximately 0,000 retail customers in northwestern and central Louisiana, western Arkansas, East Texas and the panhandle area of North Texas. As of December 01, SWEPCo owned or contracted for approximately. GW of generating capacity and supplies wholesale electric power to other electric utility companies, municipalities, rural electric cooperatives and other market participants within the region. Its generating capacity is a mix of % coal/lignite, % natural gas, % thermal PPA, % wind ( MW under long-term contracts) and 1% demand response. In 01, we estimate approximately % of SWEPCo s delivered energy was supplied by its coal plants. Rating Methodology and Scorecard Factors Exhibit [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non-Financial Corporations. [] As of /0/01(L) [] This represents Moody's forward view; not the view of the issuer; and unless noted in the text, does not incorporate significant acquisitions and divestitures. Source: Moody's Investors Service 1 September 01 Southwestern Electric Power Company: Vertically integrated electric utility subsidiary of AEP

210 MOODY'S INVESTORS SERVICE EXHIBIT RVH- Page of INFRASTRUCTURE AND PROJECT FINANCE Ratings Exhibit Category Moody's Rating SOUTHWESTERN ELECTRIC POWER COMPANY Outlook Stable Issuer Rating Baa Senior Unsecured Baa PARENT: AMERICAN ELECTRIC POWER COMPANY, INC. Outlook Stable Senior Unsecured Baa1 Jr Subordinate Shelf (P)Baa Commercial Paper P- Source: Moody's Investors Service 1 September 01 Southwestern Electric Power Company: Vertically integrated electric utility subsidiary of AEP

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