STATE OF INDIANA

INDIANA UTILITY REGULATORY COMMISSION

JOINT PETITION OF PSI ENERGY, INC.
AND CINCAP VII LLC, PURSUANT TO
IND. CODEss.8-1-8.5 ET SEQ.: (1) FOR
THE ISSUANCE OF CERTIFICATES OF
PUBLIC CONVENIENCE AND
NECESSITY FOR PSI ENERGY, INC TO
PURCHASE GENERATING FACILITIES
FOR THE FURNISHING OF ELECTRIC
UTILITY SERVICE TO THE PUBLIC;
(2) FOR THE APPROVAL OF THE COSTS
OF SUCH FACILITIES; AND (3) FOR
APPROVAL FOR CINCAP VII TO
TRANSFER OWNERSHIP OF GENERATING
ASSETS TO PSI ENERGY, INC. )
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CAUSE NO. 42145

APPROVED: 12/19/02

BY THE COMMISSION:

David E. Ziegner, CommissionerScott
R. Storms, Chief Administrative Law Judge

        On December 27, 2001, PSI Energy, Inc. (“PSI”) and CinCap VII, LLC (“CinCap VII”) (collectively “Joint Petitioners” or “Petitioners”) filed their Joint Petition with the Indiana Utility Regulatory Commission (“Commission”) for the issuance of certificates of public convenience and necessity for PSI in connection with the purchase of certain generating facilities pursuant to Ind. Code (IC) § 8-1-8.5 et seq., for approval of the costs of such facilities, and for approval for CinCap VII to transfer ownership of certain generating facilities to PSI.

        On February 15, 2002, March 8, 2002, and April 15, 2002, respectively, the Midwest Independent Power Suppliers Association (“MWIPS”), the PSI-Industrial Group (“PSI-IG”), and Nucor Corporation (“Nucor”) filed petitions to intervene in this Cause. Such petitions to intervene were granted by the Commission on February 15, 2002, March 14, 2002 and April 26, 2002, respectively.

        On February 15, 2002, the Commission designated Dr. Bradley K. Borum and David R. Johnston of the IURC Electricity Division, and Dr. Douglas J. Gotham of the State Utility Forecasting Group (“SUFG”) as testimonial staff in this Cause (“IURC Testimonial Staff”).

        Pursuant to notice, and as provided for in 170 IAC 1-1.1-15, a Prehearing Conference was held on February 15, 2002, at 9:30 a.m. in Room E306 of the Indiana Government Center South, Indianapolis, Indiana. On February 27, 2002, a Prehearing Conference Order was issued setting forth the procedural schedule in this Cause.

        On March 1, 2002, Joint Petitioners filed a Motion to Amend their Joint Petition, along with an Amended Joint Petition in this Cause. The Presiding Officers granted Petitioners’ Motion to Amend their Joint Petition, in a Docket Entry dated March 12, 2002. Also on March 1, 2002, Petitioners filed their case-in-chief testimony and exhibits in support of their Petition, along with a Motion for Protection of Confidential and Proprietary Information. Petitioners’ Motion for Protection of Confidential and Proprietary Information was accompanied by the sworn affidavits of Judah Rose and Douglas F Esamann. The Motion for Protection was granted by the Presiding Officers, on a preliminary basis, on March 11, 2002.

        On June 18, 2002, Petitioners filed supplemental testimony and exhibits. On July 12, 2002, MWIPS filed its testimony and exhibits. On July 17, 2002, the Office of Utility Consumer Counselor (“OUCC”) and PSI-IG filed their respective testimony and exhibits. On July 26, 2002, the IURC Testimonial Staff filed their direct testimony and exhibits. On August 23, 2002 PSI filed its rebuttal testimony and exhibits. On August 30, 2002, Dr. Borum and Mr. Johnston filed supplemental testimony and exhibits in this Cause.

        A public Field Hearing was conducted in this Cause on August 13, at 6:00 p.m., in New Castle, Indiana. At the field hearing, approximately 20 individuals including, Vernon and Marilyn Cherrett, Mr. Grant Smith, John Cooper, Jr., Dr. Nancy Fischer, Ms. Marsha Gratner, Dr. Helen Steussy, and Dr. Jim Rybarczyk, testified regarding PSI’s proposal to purchase the Henry County and Madison Generating Stations. The citizens that testified at the Field Hearing were generally opposed to PSI’s proposal in this Cause. As part of a thorough and comprehensive presentation of the issues, the citizens that testified expressed concern with the history and development of the Henry County Generating Station; the affiliate relationship between PSI and Cinergy; the proposed price of the facilities; the lack of profitability of the facilities; and, their belief that PSI should expend additional resources on exploring the expansion of conservation programs in its service area. All comments made at the Field Hearing, either orally or in writing, were made part of the record in this proceeding.

        The Evidentiary Hearing in this Cause was originally scheduled to begin on August 13, 2002. By agreement of the parties, the hearing was continued until September 18, 2002. However, on September 18, 2002, Petitioners filed a Settlement Agreement entered into by Petitioners, the OUCC, and the IURC Testimonial Staff (the “Settling Parties”). As a result, at the scheduled September 18, 2002 hearing, the parties reached an agreement as to a new procedural schedule that would allow Petitioners to file testimony in support of the Settlement Agreement, allow MWIPS, PSI-IG, and Nucor (the “Intervenors” or “Non-Settling Parties”) to file testimony in response to the Settlement Agreement, and allow Petitioners to file reply testimony. Petitioners filed testimony in support of the Settlement Agreement on September 23, 2002. MWIPS and PSI-IG filed responsive testimony on October 9, 2002, and Petitioners filed reply testimony on October 16, 2002.

        On October 17, 2002, Intervenor MWIPS filed a “Motion for Modification of Procedures,” requesting that the Commission establish additional filing and hearing procedures in this Cause. On October 18, 2002, Intervenors PSI-IG and Nucor filed pleadings in support of MWIPS’ motion.

        Pursuant to notice as provided by law, proof of which was incorporated into the record by reference and placed in the official files of the Commission, an Evidentiary Hearing in this Cause was held on October 21, 2002, in Room TC10 of the Indiana Government Center South, Indianapolis, Indiana. At the evidentiary hearing, evidence was submitted by Petitioners, IURC Testimonial Staff, MWIPS and PSI-IG. Members of the general public were present at the Evidentiary Hearing.

        Based upon the applicable law and evidence herein, the Commission now finds:

1.     Notice and Jurisdiction. Due, legal and timely notice of the Evidentiary Hearing in this Cause was given and published by the Commission as required by law. Petitioners are public utilities within the meaning of the Public Service Commission Act, as amended, Ind. Code § 8-1-2 et seq. Petitioners are subject to the jurisdiction of the Commission, in the manner and to the extent provided by the laws of the State of Indiana. Petitioner PSI requests relief pursuant to Ind. Code § 8-1-8.5-1 et seq. Petitioner CinCap VII requests relief pursuant to the Commission’s April 23, 2001 Order in Cause No. 41569. Therefore, the Commission has jurisdiction over Petitioners and the subject matter of this proceeding.

2.     Petitioners’ Characteristics and Business. PSI is a public utility organized and existing under the laws of the State of Indiana, and has its principal office at 1000 E. Main Street, Plainfield, Indiana 46168. It is engaged in rendering electric utility service in the State of Indiana and owns, operates, manages, and controls, among other things, plant and equipment within the State of Indiana used and useful for the production, transmission, delivery and furnishing of such electric service to the public. PSI directly supplies electric energy to over 700,000 customers located in 69 counties in the central, north central and southern parts of the State of Indiana. [Pet. Ex. B-1 (Esamann), pp. 1-2.]

        CinCap VII is a limited liability company organized under the laws of the State of Delaware, registered to do business in the State of Indiana. CinCap VII owns and operates the Henry County Generating Station that was the subject of the Commission’s April 23, 2001 Order in Cause No. 41569, and is subject to the authority of this Commission as provided in said Order; specifically, the transfer of ownership provisions of paragraph 5 of such Order. [Pet. Ex. B-1 (Esamann), p. 2.]

3.     Relief Requested by Petitioners. In their Amended Joint Petition, Petitioners requested that the Commission: (1) grant PSI certificates of public convenience and necessity under Ind. Code 8-1-8.5 for the purchase of the Madison and Henry County Generating Stations; (2) approve the costs associated with the purchase of the Madison and Henry County Generating Stations; (3) approve CinCap VII’s transfer of the Henry County Station to PSI (such approval being required by our Order in Cause No. 41569); and (4) grant such other relief as may be appropriate. In light of the settlement reached among Petitioners, OUCC, and IURC Testimonial Staff, Petitioners have also requested that the Commission approve the Settlement Agreement in its entirety. [Pet. Ex.     B-1 (Esamann), pp. 4-5; Pet. Ex. V (Esamann), p. 2.]

4.     Applicable Law; Statutory Framework. Under Ind. Code § 8-1-8.5-2, a public utility may not begin construction, purchase, or lease of any facility for the generation of electricity without first obtaining a certificate of public convenience and necessity (“CPCN”) from the Commission. Under Ind. Code § 8-1-8.5-4, when determining whether a CPCN should be issued, the Commission is directed to take into account the utility’s current and potential arrangement with other utilities for the interchange of power; the pooling of facilities; the purchase of power; joint ownership of facilities; and other methods for providing reliable, efficient and economical electric service, including the refurbishment of existing facilities, conservation, load management, cogeneration and renewable energy sources.

        Under Ind. Code § 8-1-8.5-5, an application for a CPCN may only be granted after a hearing, and if the Commission has (1) approved the estimated construction, purchase, or lease costs; (2) made a finding that either such construction, purchase, or lease will be consistent with the Commission’s plan for expansion of electric generation capacity, or that the construction, purchase, or lease will be consistent with a utility specific proposal as to the future needs for electricity to serve the people of the state or the area served by the utility; and (3) made a finding that the public convenience and necessity require or will require the construction, purchase or lease of the facility.

        We have indicated in previous CPCN cases that “least-cost planning is an essential component of our Certificate of Need law.” In re Petition of Southern Indiana Gas & Electric Co., Cause No. 38738, at p. 5 (Ind. Util. Reg. Comm’n, October 25, 1989). We have defined “least-cost planning” as a “planning approach which will find the set of options most likely to provide utility services at the lowest cost once appropriate service and reliability levels are determined.” Id. However, we have emphasized that the Certificate of Need statute does not require the utility to automatically select the least cost alternative. Nor does the statute require the utility to ignore its obligation to provide reliable service or to disregard its exercise of reasonable judgment as to how best to meet its obligation to serve. “If an Indiana utility reasonably considers and evaluates the statutorily required options for providing reliable, efficient, and economic service, then the utility should, in recognition that it bears the service obligation of IC 8-1-2-4, be given some discretion to exercise its reasonable judgment in selecting the options or options to implement which minimize the cost of providing such service.” In re Petition of PSI Energy, Inc., Cause No. 39175, at p. 14 (Ind. Util. Reg. Comm’n, May 13, 1992).

5.     Description of the Madison and Henry County Plants. Petitioner PSI proposes to purchase two gas-fired peaking plants (the Madison and Henry County Generating Stations) from affiliated companies. The Madison and Henry County plants (along with a third gas-fired peaking plant, the Vermillion plant) were developed in the 1999-2001 timeframe by Cinergy and Duke Energy Corporation through a 50/50 joint venture arrangement. Cinergy and Duke Energy dissolved their joint venture arrangement in 2001; as a result of this dissolution, two Cinergy subsidiaries took 100% ownership of the Madison and Henry County plants, while Duke Energy took 100% ownership of the Vermillion plant. [Pet. Ex. A (Rogers), pp. 5-7.]

        The Madison Generating Station is currently owned by CinCap Madison, LLC. The Madison plant began commercial operations in 2000, and consists of eight GE 7EA natural gas-fired combustion turbine (“CT”) generating units, nominally rated at 80 MW per unit, for a total nominal rating of 640 MW. The plant is located in Butler County, Ohio, adjacent to The Cincinnati Gas & Electric Company’s (“CG&E,” PSI’s sister utility in Ohio) Woodsdale Generating Station, and is directly interconnected with the Cinergy transmission system by a 345 kV gas circuit breaker. The Madison plant is able to operate year-round using natural gas while meeting environmental permit limits. Since commercial operation, the Madison plant has operated with station reliability exceeding 90% year-round. In Summer 2002 (June 1 through August 15), the Madison plant operated with station operating reliability at 100%. [Pet. Ex. B (Esamann), p. 3; Pet. Ex. G (Roebel), p. 3; Pet. Ex. O (Esamann), p. 17.]

        As mentioned above, the Henry County Generating Station is owned by CinCap VII and is located in Henry County, Indiana. The Henry County plant began commercial operation in Summer 2001, and consists of three GE LM6000 natural gas-fired CTs, having a total nominal rating of 135 MW. The plant is directly interconnected to the Cinergy transmission system by a 138 kV gas circuit breaker. The plant is located within 45 miles of PSI’s Connersville peaking station and within 65 miles of PSI’s Miami-Wabash peaking station. The Henry County plant is currently not equipped to operate in the winter. However, PSI has proposed to install the equipment necessary to enable winter operations if the purchase of the plant is approved.

Additionally, PSI has proposed to install equipment to enable the plant to achieve “quick start” capability (the ability to start and achieve baseload within ten minutes) if the purchase of the plant is approved. In Summer 2002 (June 1 through August 15), the Henry Count plant operated with station operating reliability exceeding 98%. [Pet. G (Roebel), pp. 3-4; Pet. Ex. O (Esamann), p. 17.]

        PSI retained Burns & McDonnell Engineering Company, (“Burns & McDonnell”) to perform an independent inspection and assessment of the condition of the Madison and Henry County Generating Stations. Burns & McDonnell concluded that both plants are in excellent condition, have been well maintained, and should be fully capable of providing long-term reliable service as peaking power facilities if they continue to be operated and maintained in accordance with good utility practice. [Pet. Ex. J (Ege), p. 4.]

        Petitioners’ witness Judah Rose, Managing Director of ICF Consulting, reviewed the capital and operation and maintenance (“O&M”) costs associated with the Madison and Henry County plants and concluded that capital and O&M costs combined were reasonable based on comparison with new peaking plant units. More specifically, Mr. Rose determined that the capital costs of the two plants are generally in line with the costs of building new peaking units.

    Mr. Rose found that both plants’ O&M costs are low, due primarily to the location of the Madison plant (adjacent to CG&E’s Woodsdale Station) and economies of scale related to plant O&M at Cinergy. [Pet. Ex. C (Rose), pp. 31-32; Pet. Ex. C-11 and C-12 (Rose).]

    Mr. Rose and Petitioners’ witness Ronald C. Snead, Cinergy’s Manager of Bulk Transmission Planning, examined the capability of the transmission system to deliver power from the Madison and Henry County plants to PSI load. As mentioned above, both plants are directly interconnected to the Cinergy transmission system. Further, both plants are designated “network resources” for transmission purposes, meaning that they are entitled to the highest level of transmission service priority. Messrs. Rose and Snead both concluded that the Madison and Henry County plants are well suited to serving PSI from a transmission reliability perspective.

Mr. Snead noted that both plants provide benefits to the transmission system, and that PSI ownership of the plants should enhance the transmission system benefits, due to the increased operating flexibility, control, and power flow changes that would occur under PSI ownership. Dr. Douglas J. Gotham, Associate Director of the SUFG and a member of the IURC Testimonial Staff in this case, also examined the transmission system’s ability to deliver power from the Madison and Henry County plants to PSI loads, and concluded that no additional transmission congestion is expected as a result of the power transfers. [Pet. Ex. C (Rose), pp. 32-34; Pet. Ex. H (Snead), pp. 9-14; Pet. Ex. S (Snead), pp. 3-4; IURC Staff Report No. 3 (Gotham), pp. 4-5.]

6.     Petitioners’ Initial Proposal and Overview of Settlement Agreement. PSI is requesting that the Commission approve its proposal to purchase the Madison and Henry County plants (including all associated real estate, inventory, materials and supplies, contracts and permits), pursuant to Ind. Code 8-1-8.5. As required by our Order in Cause No. 41569, CinCap VII is seeking Commission approval to sell the Henry County plant to PSI. In connection with its proposed plant purchases, Petitioner PSI is also requesting approval of: the costs of the purchases; the assignment of certain plant agreements in place between the CinCap Madison and CinCap VII and other Cinergy affiliates (i.e., a water supply agreement relating to the Madison plant and fuel supply agreements in place for both plants); a ratemaking proposal relating to the Henry County plant, whereby the costs and revenues associated with a 50 MW “slice” of the plant will be separated out for retail ratemaking purposes. Additionally, with respect to the Henry County plant, PSI is proposing to adopt the commitments made by CinCap VII in Cause No. 41569 relating to the following issues: (1) air quality; (2) water supply; (3) noise; (4) County comprehensive plan; (5) future abandonment; and (6) emergency planning. (These six commitments are memorialized at page 8 of our April 23, 2001 Order in Cause No. 41569.) [Pet. Ex. B (Esamann), pp. 3-4, 26-28.]

        Petitioners initially proposed purchase prices based on the actual book values of the plants, net of accrued depreciation, as of January 1, 2002 (the approximate date when the plants were officially offered and held open for sale to PSI), plus a carrying cost component (for carrying costs incurred from January 1, 2002 until the date(s) of closing). According to PSI, the carrying cost component of the purchase price was intended to serve as compensation for both the exclusive right effectively being granted to PSI to purchase the assets at a fixed price through the pendency of this certificate of need proceeding and the option being offered to PSI to use the plants (and their output) until the asset purchase transactions were completed, almost as if PSI owned the plants beginning in 2002. [Pet. Ex. A (Rogers), pp. 7-10; Pet. Ex. B (Esamann), p. 3.] In its June 18, 2002 supplemental testimony, Petitioners reduced the proposed purchase prices to reflect the payment by PSI to the CinCap companies of capacity reservation charges in June through September 2002, as a result of a unit power sales agreement put in place for a portion of 2002 whereby PSI had access to the capacity from the Madison and Henry County plants. [Pet. Ex. L (Esamann), pp. 2-3.]

        In September 2002, the Petitioners, the OUCC, and the IURC Testimonial Staff reached a settlement intended to resolve all issues in this Cause (as well as in Cause No. 42195). See Pet. Ex. V-1 (copy of the Settlement Agreement). Petitioners request Commission approval of the Settlement Agreement as it relates to this Cause No. 42145 in its entirety. The Settlement Agreement, which is attached to this Order and hereby incorporated by reference in its entirety, can be summarized as follows as it pertains to Cause No. 42145:

(1)     Authority to purchase the Madison and Henry County Generating Stations — The Settlement Agreement provides that PSI shall be authorized, pursuant to Ind. Code 8-1-8.5 et seq., to purchase the Madison and Henry County Generating Stations, and shall be granted certificates of public convenience and necessity under Ind. Code 8-1-8.5 et seq. for such purchases. CinCap VII shall be authorized to transfer the Henry County Generating Station to PSI. [Pet. Ex. V-1, p. 2.]

(2)     Transfer pricing for the Plants — The Settlement Agreement provides that PSI shall be authorized to purchase the Plants at the following purchase prices, such purchase prices to be recovered through rates over the lives of the Plants: (a) net book value of the respective Plants at the earlier of: (i) the date of the IURC Order granting PSI certificates of public convenience and necessity for the Plants; or (ii) December 1, 2002, plus (b) accrued carrying costs (calculated at PSI’s weighted cost of capital using the return on equity from PSI’s last base retail rate case) from the date above to the date of actual transfer of the Plants; minus (c) $5 million constituting the deferred purchase price adjustment associated with the Henry County Plant. [Pet. Ex. V-1, p. 2.]

(3)     Associated Inventory — The Settlement Agreement provides that PSI shall also be authorized to purchase the inventory associated with the Plants, at cost. [Pet. Ex. V-1, p. 2.]

(4)     Interim Purchased Power — The Settlement Agreement provides that, subject to the approval of the Settlement Agreement, PSI and the owner of the Plants’ output (Cinergy Capital & Trading) will enter into an interim unit power sales arrangement whereby PSI will have “first call” access to the Plants’ available capacity for serving native load customers, from January 1, 2003 until the actual date of transfer following FERC and SEC approvals. And, in the event that either the FERC or SEC disapproves the transfer of the Plants to PSI, PSI shall have “first call” access to the Plants’ available capacity through September 30, 2003. PSI shall pay CC&T capacity and energy charges as outlined in the unit power sales agreement, but the capacity charges shall be refunded to PSI upon transfer of the Plants. In the event of FERC or SEC disapproval, however, PSI shall be authorized to recover through retail rates on a timely basis (i.e., through a tracking mechanism) 50% of any such capacity charges paid and not refunded, along with the actual energy charges. [Pet. Ex. V-1, pp. 2-3.]

(5)     Performance Guarantees — The Settlement Agreement provides that PSI will implement a transmission “hold harmless” guarantee associated with the Madison plant and a plant performance guarantee associated with both the Madison and Henry County plants. Under the Madison “hold harmless” provision, PSI will track any transmission congestion-related native load curtailments from the Madison plant, and compare any such curtailments to the transmission congestion curtailments throughout the PSI system. In the event the level of native load transmission curtailments from the Madison plant is higher than the system average of such curtailments, PSI has agreed to hold retail customers harmless by capping the actual energy costs required to replace the energy needed due to any applicable transmission curtailment at the cost of energy from the Madison plant. This hold harmless provision will continue for a period of 2 years, or until locational marginal pricing is implemented on the Cinergy transmission system, whichever is earlier. With regard to the plant performance guarantee, PSI has agreed to certain operating reliability standards for the Madison and Henry County plants for 2003 and 2004. In the event the plants do not meet the operating reliability standards, PSI has agreed to implement retail rate credits of up to $1 million in each of the those two years. [Pet. Ex. V-1, p. 3.]

(6)     Assignment of Plant Affiliate Agreements – The Settlement Agreement provides that several affiliate agreements in place at the Madison and Henry County plants may be assigned to PSI along with the purchase of the plants themselves. Specifically, the Settlement Agreement provides for the assignment to PSI of a water supply agreement (with CG&E) pertaining to the Madison plant and natural gas supply agreements (with Cinergy Marketing & Trading) that pertain to both plants. [Pet. Ex. V-1, p. 4.]

(7)     Ratemaking for Henry County Plant – The Settlement Agreement provides that the costs and revenues associated with 50 MWs of capacity of the Henry County plant should be separated out for retail ratemaking purposes. [Pet. Ex. V-1, p. 4.]

(8)     Revisions to Proposed Asset Purchase Agreements – The Settlement Agreement provides that Petitioners’ proposed asset purchase agreements should be revised so as to eliminate the assumption by PSI of environmental and tort liabilities that accrue prior to the date of transfer. We note that Petitioners’ revised asset purchase agreements, contained in Petitioners’ Exhibits V-3 and V-4, have been revised in accordance with this provision of the Settlement Agreement. [Pet. Ex. V-1, p. 4.]

7.     Need For Additional Generating Capacity. PSI’s testimony demonstrates that PSI’s peak demand load growth over the last decade has outstripped PSI’s capacity additions. Our threshold inquiry addresses whether PSI does in fact need additional generating capacity. To make this determination, it is necessary to review all of the sources utilized by PSI to satisfy its customers’ electricity demands, PSI’s projected demand growth, PSI’s ability to meet its growing customer demands, and the type of additional capacity that may be needed.

    a.        PSI’s Existing Portfolio of Supply Resources. PSI’s existing fleet of generating properties provides the bulk of its existing supply resources. This fleet consists of 6,211 MWs (summer-rated) of generation (plus 7 MWs of QF capacity). PSI is currently in the process of repowering its Noblesville Generating Station. This repowering project, when completed in 2003, will add approximately 200 MWs of incremental generating capacity to the PSI system. [Pet. Ex. B (Esamann), pp. 9, 22.]

        PSI’s generating fleet is heavily weighted toward coal-fired baseload capacity. At present, baseload makes up 65% of the PSI generation, intermediate makes up 26%, and peaking makes up 9%. PSI’s current generation mix is 89% coal-fired, 10% oil or gas-fired, and 1% hydro. The average age of PSI’s generating plants is approximately 30 years, with the newest plants generally found in the large coal-fired baseload segment. The average age of PSI’s existing peaking units is over 36 years. With the exception of PSI’s Cayuga 4 peaker (9 years old), no peaking unit on the PSI system is less than 29 years old. [Pet. Ex. B (Esamann), pp. 19, 21; Pet. Ex.     B-2 (Esamann).]

        Another portion of PSI’s peak load obligation is met with a combination of conservation and load management products. These products consist of a set of traditional demand-side management (“DSM”) programs PSI has had in place for residential and small commercial and industrial customers for a number of years; several innovative peak load management pricing options for larger commercial and industrial customers; and a number of interruptible contracts in place with large industrial customers. These conservation and load management products provided approximately 350 MWs of peak demand reduction capability on the PSI system during the summer of 2002. [Pet. Ex. B (Esamann), p. 9; Pet. Ex. E (Stevie), pp. 15-18; Pet. Ex. F (Darnell), pp. 3-9.] PSI’s current resource portfolio is supplemented by the use of forward reliability purchases from the wholesale power market. In the summer of 2002, PSI made forward reliability purchases totaling just over 880 MWs. [Pet. Ex. B (Esamann), pp. 9-10; Pet. Ex. O (Esamann), p. 14.]

        PSI’s President, Douglas F Esamann, characterized its utilization of multiple resources for satisfying its customers’ electricity demands as a “portfolio approach.” Mr. Esamann’s testified that a portfolio approach allows PSI to optimize its resource mix and have the necessary flexibility to economically and reliably meet its native load customers’ demand requirements. At the same time, Mr. Esamann emphasized that, in light of the increased risks associated with purchased power (e.g., transmission constraints and supplier credit risks), PSI questioned the wisdom of a heavy reliance on imported purchased power. [Pet. Ex. B (Esamann), pp. 7-8, 33-34.]

    b.        PSI’s Load Obligations. PSI has experienced native load peak demand load growth of approximately 2% annually (over 100 MWs per year) over the last five years. PSI projects that the retail component of its native load demand will increase about 1.6% annually over the next few years. This load growth is not unique to the PSI system. Both ECAR and the State of Indiana have experienced strong peak demand growth for years, even through periods of economic downturn. Electricity demand continues to grow even during recessions due to population growth and the continuing development of new uses for electricity. [Pet. Ex. B (Esamann), p. 17; Pet. Ex. C (Rose), pp. 10-12; 25; Pet. Ex. C-4 and C-5 (Rose).]

        PSI’s peak demand forecast and the SUFG’s peak demand forecast both indicate continued peak demand growth for the PSI system. Richard G. Stevie, Cinergy’s General Manager, Market Analysis, testified that for the summer of 2003 (the expected in-service date of the Noblesville repowering project) PSI’s 2001 forecast projected a system peak demand of 6,304 MW, and PSI’s most current load forecast (prepared in 2002) projects a system peak demand of 6,427 MWs. When adjusted for interruptible, peak reduction, and wholesale loads, PSI’s current forecasted peak demand for summer of 2003 is 5,797 MWs. In comparison, for summer 2003, the SUFG estimates PSI’s peak demand will be 5,769 MWs. The SUFG’s forecast subtracts interruptible load capability and wholesale loads, thus the PSI forecast of 5,797 MWs is the most comparable to the SUFG forecast. In Dr. Stevie’s opinion, the difference between the PSI and SUFG forecasts is quite small, even though the SUFG performs a completely independent assessment of projected load, using different databases and a different methodology than PSI uses to prepare its forecast. [Pet. Ex. E (Stevie), p. 9; Pet. Ex. T (Stevie), pp. 5-6; Pet. Ex.T-1 (Stevie).] Dr. Stevie testified that in the summer of 2001, PSI’s system experienced a new summer peak demand of 6,019 MW, and during the summer of 2002, PSI’s system experienced two new peak demand records (6,153 MWs on July 22 and 6,196 MWs on August 1). [Pet. Ex. E (Stevie), p. 9; Pet. Ex. T (Stevie), p. 5.]

    c.        PSI’s Ability to Meet its Load Obligations with Existing Resources. PSI’s onsystem reserve margin for 2002 was less than 1%, necessitating PSI’s reliance on approximately 880 MWs of forward purchased power during the summer of 2002 to reach a 15% reserve margin. PSI’s projected reserve margin for 2003 is only 3.6%, even after the expected completion of the Noblesville repowering project. [Pet. Ex. B (Esamann), p. 16.]

PSI witness Diane L. Jenner, Cinergy's Manager of Asset Planning and Analysis, explained that 4% reserves are needed to meet ECAR and NERC operating reserve requirements; at least 8% reserves are needed for normal generating unit outages and derates, based on historical experience; and at least a 3% reserve component is needed to cover potential variations in load, particularly weather-induced load. [Pet. Ex. D (Jenner), pp. 4-5.]

        For these reasons, in PSI’s view, a reserve margin of at least 15% is necessary for PSI in today’s environment. Ms. Jenner explained, however, that PSI continues to evaluate how best to optimize its planning reserve margin level. She noted that, in light of the age of PSI’s generating system, the large impact that weather can have upon actual loads, and the impact of losing the largest unit on the system (one of the five Gibson units), a higher planning reserve margin may be desirable. [Pet. Ex. D (Jenner), pp. 5-6.]

    Dr. Borum, Director of the IURC’s Electricity Division and a member of the IURC Testimonial Staff in this case, concurred that a planning reserve margin of at least 15% is necessary for PSI. Dr. Borum testified that “Staff believes that a reserve margin of 15% for planning purposes is at the low end of reasonableness. . . . Given the size of a single Gibson unit relative to PSI’s projected peak load, Staff believes that PSI could justify using as much as a 10% margin for unit forced outages and derates rather than the current 8%.” [IURC Staff Report No. 1 (Borum), p. 11.]

    d.        Type of Capacity Needed. Mr. Esamann emphasized in his testimony that PSI’s generating system is heavily weighted toward baseload, with only 9% of its capacity consisting of peaking capacity. At the same time, PSI’s current aggregate customer load profile indicates that, optimally, as much as 20% of its capacity should be comprised of peaking capacity. For these reasons, in PSI’s view, its next capacity additions should be peaking capacity. [Pet. Ex. B (Esamann), p. 18-20; Pet. Ex. B-2 (Esamann).]

        Petitioners’ witness James E. Rogers, Chairman and CEO of both Cinergy and PSI, explained that he believes that the addition of gas-fired generation is an excellent choice for PSI from both a flexibility and a risk mitigation perspective. Mr. Esamann also testified that gas-fired peaking capacity is the obvious choice, in terms of improving PSI’s fuel diversity (currently 89% coal-fired) and potentially mitigating PSI’s exposure to future environmental regulations and costs. Petitioners’ witness William F. Tyndall, Vice President of Environmental Services and Federal Affairs for Cinergy, supported this view, as well. Mr. Tyndall’s testimony discussed a series of major environmental requirements looming on the horizon that will impact coal-fired units far more than they will gas-fired units. In Mr. Tyndall’s view, moving to increase the fuel diversity on the PSI system and decrease the average age of the PSI portfolio can be characterized as an insurance policy to protect PSI against these oncoming environmental risks and costs. [Pet. Ex. A (Rogers), pp. 22-24; Pet. Ex. B (Esamann), p. 21; Pet. Ex. B-2 (Esamann); Pet. Ex. K (Tyndall), pp. 5-6; 13-14.]

8.     PSI’s Integrated Resource Planning Process. One objective of the integrated resource planning (“IRP”) process is to determine an optimal combination of resources that can be used to reliably and cost-effectively meet customers’ future electricity requirements. In the present proceeding, PSI considered a multitude of resource options and combinations of options in its IRP process, including DSM programs, peaking units, combined cycle units, coal-fired units, fuel cells, renewable resources (such as wind and solar), and purchased power. [Pet. Ex. D (Jenner), pp. 3, 7-8.]

        PSI’s evidence described at length the resource planning process that was used to first identify the range of viable alternatives, and then narrow those choices to the best alternative. The initial steps in PSI’s IRP process consisted of the development of planning objectives and assumptions, and the preparation of an electric load forecast. The major objectives of PSI’s IRP process are to: (1) provide adequate, reliable and economical service to customers while meeting all environmental requirements; (2) maintain the flexibility and ability to alter the plan in the future as circumstances change; (3) choose a near-term plan that is robust over a wide variety of possible futures; and (4) minimize risk. Assumptions used in PSI’s IRP process include economic factors, environmental regulations, fuel prices, and supply-side, demand-side, and environmental compliance resource costs. PSI’s electric load forecast presented in this case and sponsored by Dr. Stevie was discussed supra. [Pet. Ex. D (Jenner), pp. 8-9.]

        Once PSI’s demand-side resource programs and impacts were factored into the IRP, the next major steps in the process were identification of, screening of, and performing sensitivity analysis around the cost-effectiveness of potential electric supply-side resources. PSI considered over one hundred different supply-side resource alternatives in its IRP process. PSI used several sources to obtain information about potential resource options and costs, such as EPRI’s Technical Assessment Guide® (“EPRI TAG®”) for up-to-date information about both conventional and advanced power generation technologies; PSI-specific price estimates for combustion turbines, combined cycle units, and repowering PSI’s Edwardsport Station; a study from an outside engineering firm for new pulverized coal and fluidized bed plants; and the 2001 “Repowering the Midwest” report for additional information about the costs of renewable energy options. [Pet. Ex. D (Jenner), pp. 9-10.]

        As explained by PSI, screening is a necessary step because of the size and “run time” limitations of the integration model. The first screen is a technical screening, performed to eliminate technologies that are not feasible in PSI’s service territory. The next screen is an economic screening of the technologies within each technology “class” to determine the “best in class.” Finally, an economic screen is performed across the classes to select the final set of alternatives to model. [Pet. Ex. D (Jenner), p. 10-12.] In connection with its supply-side screening process, PSI performed sensitivity analyses on each “best in class” final technology type in the 2001-2010 modeling period, to determine what assumption changes would be necessary to move each into the economic group. In PSI’s view, using the screening model rather than performing all sensitivities at the end of the analysis, is more efficient and gives PSI a better understanding of the magnitude of changes in certain assumptions that will affect resource decisions. [Pet. Ex. D (Jenner), p. 12.]

        The next step in the process is integration. The goal of the integration process is to take all of the pre-screened demand and supply-side options, along with environmental compliance plans, and develop an integrated resource plan using a consistent method of evaluation. The primary tool used to perform this final integration is the STRATEGIST® computer model.

STRATEGIST® is a commercially available and widely-accepted system expansion model. The STRATEGIST® computer model uses load forecast and other data, in concert with data concerning existing generating units, demand-side resources, environmental compliance resources, and future supply-side resource alternatives, to simulate electric production system operation. The STRATEGIST® model then dynamically analyzes the cost-effectiveness of a multitude of combinations of the resource alternatives resulting from the screening analyses described previously, ultimately producing a number of resource expansion plans that meet the prescribed technical reliability criteria. The expansion plans produced by the STRATEGIST® model are ranked from lowest to highest in terms of present value revenue requirements (“PVRR”). By comparing the PVRR of the various plans selected by the model, the utility can compare the forecasted costs of the various expansion plans. However, Ms. Jenner stressed that while the PVRR of each plan is a key factor in selecting a plan, the plan should also take into account other issues, such as flexibility, risk, availability of equipment, constructability, and transmission constraints. [Pet. Ex. D (Jenner), pp. 14-15.]

        The screening described above resulted in a number of alternatives being included in the integration modeling process, along with the Madison and Henry County plant purchase option. These alternatives included simple cycle CTs (including the Madison and Henry County plants), repowering of PSI’s Edwardsport Station, “Greenfield” combined cycle units, 100 MW block purchases from the wholesale market, and fuel cells. The estimated costs of these various alternatives were included in the integration modeling process, as well. The costs of the various alternatives were obtained from a number of sources, including Cinergy engineers, EPRI TAG® data, general market data, wholesale power market price forecasts provided by ICF Consulting, and fuel price forecasts provided by both Cinergy personnel and outside consultants. In addition, the integration modeling process included projected levels of demand reductions from PSI’s traditional DSM programs, from PSI’s interruptible and as available customer-specific contracts, and from PSI’s PowerShare and Real-Time Pricing programs. [Pet. Ex. D (Jenner), pp. 13, 15-16.]

        The integration modeling process produced over 4200 different long-term expansion plans. PSI identified the Henry County/Madison plan as the “number one” plan, with the lowest PVRR. In fact, out of the more than 4200 expansion plans produced by the integration model, the top 20 of such plans (ranked on a PVRR basis) included the purchase of the Madison and Henry County plants as components of those plans. [Pet. Ex. D (Jenner), pp. 16, 17.]

        PSI next analyzed the Henry County/Madison plan and three other low-PVRR/ plans for further sensitivity analysis, focusing on the first five years of the planning period. The primary differences between the plans during the first five years concerned the timing of capacity additions, the types of capacity additions, and the magnitude of purchases from the wholesale market. The purpose of this additional sensitivity analysis was to explore the impact of changes in possible alternative futures on certain plans, with the goal being to find out whether the best plan or plans (from cost-effectiveness or reliability standpoints) are robust enough to withstand changes in certain future variables. The following major sensitivities were analyzed at this integration stage: changes in gas prices, changes in wholesale market power prices, and changes in service area load. The sensitivity analysis indicated that, while there is little comparative downside risk with the Henry County/Madison plan from changes in gas prices, changes in load level, or decreases in market prices, there is tremendous comparative downside risk with the alternative plans with respect to wholesale power market price increases, due to the high levels of purchases contained in those plans. [Pet, Ex. D (Jenner), pp. 16-21.]

        PSI’s IRP process also included the consideration of risk-related qualitative or judgment factors. Specifically, PSI considered factors such as construction, siting and permitting delays applicable to construction of new capacity. PSI witness Jenner noted that these construction risks are not present with the Madison and Henry County plants, as both plants are already sited, permitted, constructed, and operating. In addition, PSI considered factors such as pricing, non-performance, supplier credit, and deliverability risks associated with the purchase of imported power. Ms. Jenner also noted that these purchased power risks would not be present with the acquisition of the Madison and Henry County plants. Finally, PSI considered risks associated with future environmental regulations, although as Ms. Jenner pointed out, because all of the top resource alternatives consisted of gas-fired generation and market purchases, environmental risks did not play a significant role in this analysis. [Pet. Ex. D (Jenner), p. 22.]

        PSI ultimately selected the Henry County/Madison plan as its preferred IRP plan, based on the results of both its quantitative and qualitative analyses. The economic analysis slightly favored the Henry County/Madison plan, and the qualitative, risk-related factors all tended to support the Henry County/Madison option. Ms. Jenner characterized the influence of these qualitative factors as “confirming that the selection of the Henry County/Madison Plan is the right course of action for PSI.” In sum, PSI believes that the purchase of the Madison and Henry County plants presents the optimal solution for meeting its customers’ electricity needs in a reliable, low-risk, and cost-effective manner over the long term. [Pet. Ex. D (Jenner), p. 23; Pet. Ex. B (Esamann), pp. 5-6.]

        The IURC Testimonial Staff conducted an in-depth examination of PSI’s IRP process in connection with preparing its reports for this Cause. Dr. Borum concluded in testimony that “[t]he analysis by PSI was reasonably well done and substantiates that PSI’s recommended resource plan is one that can do well over a range of uncertainties.” [IURC Staff Report No. 1 (Borum), p. 22.]

9.     Statutory Alternatives Considered in PSI’s Integrated Resource Planning Process. Ind. Code § 8-1-8.5-4 requires that the Commission, in acting upon any petition for the construction, purchase, or lease of any facility for the generation of electricity, take into account the Petitioner’s current and potential arrangement with other electric utilities for (a) the interchange of power; (b) the purchase of power; (c) the pooling of facilities; (d) joint ownership of facilities; and other methods of providing reliable, efficient, and economical electric service, including (e) the refurbishment of existing facilities; (f) conservation and load management; and (g) cogeneration and renewable energy sources.

        In accordance with IC § 8-1-8.5-4, a petitioner must fully address the enumerated alternatives in order for the Commission to make an informed decision as to whether a pending proposal is in the public interest. As we noted in In re Petition of PSI Energy, Inc., Cause No. 41924, the statute does not require a utility to exhaust all statutory alternatives before it may request a CPCN for new capacity. Id. at p. 5. Rather, what is important is that the Commission be given enough information so that the Commission can take into account all of the enumerated alternatives in making its determination. Id. The statute does not limit the Commission’s discretion to weigh the importance of each alternative in determining the public interest. Id. We consider the evidence on each of these statutory alternatives as follows:

a.     The Interchange of Power. With regard to interchange power, the evidence indicates that interchange power is useful when available and economic to meet short-term system needs. PSI regularly uses interchange power as it continuously dispatches its generation and market purchases to meet its native load customers’ demand requirements. But, in its testimony presented in this Cause, PSI indicates that it believes that hourly spot purchases are not a good substitute for, and cannot be depended upon to take the place of, firm capacity such as on-system generation and forward reliability purchases. [Pet. Ex. B (Esamann), pp. 36-37.]

b.     The Purchase of Power. Over the past few years, PSI has relied on forward reliability purchases to help meet its native load customers’ peak load requirements. Even with the addition of the Madison and Henry County plants, PSI expects to continue to rely on such power purchases as a component of its supply portfolio necessary to maintain system reliability, albeit in lesser amounts than the almost 900 MWs of forward purchases needed for Summer 2002. However, PSI determined in its testimony that the use of purchased power must be compared to the addition of on-system resources, both from reliability, risk, and economic perspectives. [Pet. Ex. B (Esamann), pp. 33-34.]

        PSI’s integrated resource planning analysis considered purchased power as an alternative, both quantitatively and qualitatively, and compared that alternative to the purchase of the Madison and Henry County plants in terms of economics, risk, and reliability. [Pet. Ex. B (Esamann), pp. 33-34; Pet. Ex. C (Rose), pp. 20-27; Pet. Ex. D (Jenner), pp. 15-23; Pet. Ex. H (Snead), pp. 12-13.] Quantitatively, PSI’s IRP analysis considered purchased power alternatives by means of utilizing a wholesale power price forecast, as it has done in past IRPs and in past CPCN cases.

        The wholesale power price forecast used in the IRP process was developed by ICF Consulting (“ICF”), using ICF’s proprietary Integrated Planning Model. [Pet. Ex. D (Jenner), p. 17; Pet. Ex. C (Rose), pp. 2-4; Pet. Ex. C-1 and C-2 (Rose).] ICF’s wholesale power price forecast, consisting of an assessment of wholesale power prices for the Southern ECAR region, was included in PSI’s IRP process via the STRATEGIST® model. The price projections developed by ICF were used by PSI as a resource alternative, specifically, continued reliance on market-priced block purchases of 5x16 power for peak periods (e.g., July and August). ICF’s wholesale power price forecast is based on detailed, region-wide generating unit-level data, publicly reviewed assumptions with regard to the costs and performance of electric power supply options, with full integration of fuel and environmental markets. ICF’s proprietary forecasting model forecasts prices, generation dispatch, transmission, capacity expansion, fuel choice, environmental compliance, coal prices, and emission allowance prices. [Pet. Ex. C (Rose), p. 36; IURC Staff Report No. 1 (Borum), p.13.]

        ICF developed a “base case” wholesale power price forecast, as well as several sensitivity scenarios: a high natural gas prices scenario; a low natural gas prices scenario; a higher market price (high demand growth) scenario; and a lower market price (high power plant supply) scenario. PSI used ICF’s base case forecast, and all four of ICF’s sensitivity scenarios, in its IRP process. [Pet. Ex. C (Rose), pp. 45-46; Pet. Ex. D (Jenner), pp. 15-16, 20; IURC Staff Report No. 1 (Borum), p. 14.]

        ICF’s wholesale power price forecast assumes the wholesale markets are perfectly competitive, and does not attempt to quantify certain risks associated with a utility’s reliance on imported purchased power, such as supplier credit risk and transmission/deliverability risk. Similarly, PSI’s quantitative IRP modeling process did not attempt to assign any costs to such risks. Thus, if anything, ICF’s wholesale power price forecast and PSI’s quantitative IRP process are biased in favor of the purchased power alternative. [Pet. Ex. C (Rose), pp. 38-39; Pet. Ex. O (Esamann), p. 8; 10/21/02 cross-examination of Mr. Rose.] Even with this preferential treatment accorded purchased power, the purchased power alternative was determined to be less economic than the purchase of the Madison and Henry County plants over the long term. Dr. Borum, noted that “Staff is of the opinion that the terms of a unit power purchase agreement for a peaker facility over a long period of time (e.g., 10-20 years) is likely to closely track the cost of owning, building and operating a combustion turbine.” [Pet. Ex. D (Jenner), p. 22; Pet. Ex. C (Rose), p. 20; IURC Staff Report No. 1 (Borum), p. 16.]

        PSI also qualitatively considered the purchased power alternative in its IRP process. Specifically, PSI considered the relative advantages and disadvantages of the purchased power alternative as compared to the purchase and ownership of the Madison and Henry County plants. Potential advantages of purchased power noted by PSI include optionality, price transparency and, with long-term asset-backed purchases, some assurance of source of capacity and costs.

Disadvantages and risks of relying on imported purchased power identified by PSI include: market price volatility risk; potential scarcity of power available on the market; supplier credit risk; transmission constraint/deliverability risk; and lack of ownership and control of the assets used to produce the power. [Pet. Ex. B (Esamann), pp. 10-14; Pet. Ex. C (Rose), pp. 20-22.]

        In its testimony, PSI focused on the state of the wholesale power market today, and the risks of reliance on purchased power instead of utility owned assets. PSI ultimately rejected the purchased power alternative in favor of the purchase of the Madison and Henry County plants.

PSI’s decision was based on several factors, including: the superior economics over the long term of the Madison/Henry County plant purchase option as compared to the purchased power option; the size of PSI’s capacity need; the risks prevalent in the wholesale markets today; and the increased reliability and reduced risk associated with relying on power plants that are already built and operational, are directly interconnected to the Cinergy transmission system, and will be subject to the ownership and control of PSI. In PSI’s view, purchasing the Madison and Henry County plants will effectively eliminate the transmission deliverability risks associated with importing large amounts of purchased power. Further, PSI concluded that purchasing the two plants will reduce PSI’s exposure to the volatility, the uncertainty, and the credit risks inherent in today’s wholesale power market. [Pet. Ex. D (Jenner), pp. 22-23; Pet. Ex. H (Snead), pp. 12-13; Pet. Ex. C (Rose), pp. 20-22; Pet. Ex. A (Rogers), pp. 18-21.]

c.     The Pooling of Facilities. PSI testified that it believes that power pooling is not a viable alternative to the acquisition of the Madison and Henry County plants. PSI presented evidence that growth in the power marketing industry, along with ECAR’s automatic reserve sharing system, helps ensure that the use of existing resources is maximized. Nevertheless, there is a demonstrated need for additional capacity resources in the ECAR region, according to Petitioners’ witnesses Esamann and Rose. Mr. Esamann further testified that pooling of facilities does not add any incremental capacity to the regional mix, and until such time as supply is adequate to meet and exceed demand in the region, pooling is not a viable option. [Pet. Ex. B (Esamann), pp. 37-38.].

d.     Joint Ownership of Facilities. PSI presented evidence that joint ownership is not a viable alternative to the acquisition of the Madison and Henry County plants, due to PSI’s current large capacity needs, its low on-system reserve margin, and its current need for peaking capacity. PSI testified that it is not opposed to joint ownership; and indicated that at present, Petitioner jointly owns both generating and transmission facilities: the Gibson Station Unit No. 5 is jointly owned, and PSI’s transmission system is jointly owned with Wabash Valley Power Association, Inc. and the Indiana Municipal Power Agency. [Pet. Ex. B (Esamann), p. 38; Pet, Ex. H (Snead), p. 4.]

e.     The Refurbishment of Existing Facilities. PSI presented evidence that it has considered the refurbishment of existing facilities. PSI noted that it has had a refurbishment or engineering condition assessment program (“ECAP”) in place for many years. PSI testified that it has performed an ECAP assessment on a number of its generating units and has taken steps necessary to preserve the existing capacity of those units. PSI has also made system improvements aimed at maintaining and improving the reliability of its generating system. [Pet. Ex. G (Roebel), p. 7.]

f.     Conservation and Load Management. PSI presented evidence that, given the substantial need for capacity on the PSI system, additional conservation or load management programs are not a realistic substitute for the purchase of the Madison and Henry County plants. PSI currently has in place a number of conservation and load management programs, including traditional DSM programs, interruptible contracts, real time pricing, and PowerShare.

Combined, all of these demand-side programs contributed approximately 350 MWs of peak demand reduction capability during the summer of 2002. PSI’s most recent DSM settlement agreement, which was approved by the Commission on May 31, 2002, in Cause No. 41875, increases funding for its existing programs and adds two new pilot programs, including a load management program for mass-market customers, and a solar power program that gives incentives to customers to install solar generators. PSI’s resource plan continues to rely on these demand reductions for the upcoming years. [Pet. Ex. E (Stevie), pp. 15-18; Pet. Ex. F (Darnell), pp. 3-9; Pet. Ex. D (Jenner), pp. 26-28.]

        PSI witness Diane Jenner presented analyses indicating that even when she doubled the incremental DSM program impacts and included a system-wide direct load control component at aggressive participation levels, the capacity from the Madison and Henry County plants was still required to meet a minimum 15 % reserve margin for 2003 and beyond. Similarly, even when Ms. Jenner assumed aggressive real-time pricing and PowerShare CallOption impacts the Madison and Henry County plant capacity was still needed. In sum, PSI believes its need for additional capacity is just too great to be met through increased conservation and load management programs alone. [Pet. Ex. D (Jenner), pp. 24-25, 29; Pet. Ex. D-9 (Jenner); Pet. Ex. B (Esamann), p. 12.] On this point, Dr. Borum of the IURC Testimonial Staff testified that “[t]he immediacy and size of the resource requirements (over 700 MW in 2003) mean that DSM programs, no matter how ambitious and efficiently implemented, cannot be realistically considered to significantly close this resource gap.” [Staff Report No. 1 (Borum), p. 5.]

g.     Cogeneration and Renewable Energy Sources. PSI presented evidence that cogeneration and renewable energy sources are not adequate alternatives to the purchase of the Madison and Henry County plants. Mr. Rose pointed out that ICF forecasts that some cogeneration will be added over time, but the economic potential is limited compared to some other areas of the country. ICF’s conclusion derives from its assessment of the boiler population/steam loads in the U.S., limited prospects for key industries in the ECAR area with large steam loads (e.g., integrated blast furnaces), and the only moderate economics of cogeneration in the ECAR region due to low non-peak electricity prices. [Pet. Ex. C (Rose), p. 18.]

        In developing its IRP, PSI included the cogeneration capacity PSI expects on its system over the period of the IRP. PSI’s IRP analysis also included a number of renewable resources including wind, solar and fuel cells. With the current state of technical development and the costs of these technologies, PSI concluded that none of the options was economically attractive in the time frame required. PSI’s resource plan does call for the addition of fuel cells in the later years, assuming the technology develops as anticipated. [Pet. Ex. D (Jenner), pp. 28-29.]

10.     Intervenor Criticisms of PSI’s Proposal. MWIPS and PSI-IG directed four basic criticisms toward Petitioners’ proposal: (1) they both criticized PSI’s resource planning process for its lack of use of a “Requests for Proposals” (“RFP”); (2) MWIPS in particular criticized PSI’s preference for an “iron-in-the-ground” solution to its capacity needs, as opposed to what it termed a “pay-for-performance” purchased power arrangement; (3) MWIPS and PSI-IG questioned the reasonableness of the proposed plant purchase prices; and (4) MWIPS, and to a lesser extent PSI-IG, questioned Cinergy’s motives for proposing to transfer the plants to PSI.

        Intervenors did not dispute the reasonableness of ICF’s wholesale power price forecast, the manner in which PSI used that forecast in its IRP analysis, or even PSI’s overall IRP analysis. Rather, Intervenors focused almost exclusively on the fact that PSI did not conduct an RFP. With regard to PSI’s decision not to utilize an RFP process, MWIPS and PSI-IG took the position that PSI’s proposal should be rejected by the Commission based on the lack of an RFP.

MWIPS also recommended that the Commission institute a structured RFP process and order PSI to conduct an RFP consistent with that process. [MWIPS Ex. 1 (Roach), pp. 6, 45-49; PSI-IG Ex. 1 (Phillips), pp. 7-8.]

        PSI-IG witness Nicholas Phillips, Jr., a consultant and a principal with the firm of Brubaker & Associates, took the position that in circumstances such as this, where a utility seeks to purchase generating facilities from an affiliate, an RFP is a “necessity.” In Mr. Phillips’ view, price and a host of non-price factors (reliability, deliverability, delivery location, etc.) can simply be factored into an RFP by utilizing a performance-based contract. [PSI-IG Ex. 1 (Phillips), pp. 8-10.]

        MWIPS argued that PSI’s IRP process was deficient due to its lack of RFP results. In MWIPS’ view, because PSI did not go through an RFP process, PSI’s IRP analysis contained only “hypothetical,” as opposed to “real world,” resource alternatives. MWIPS’ witness Craig R. Roach, a partner with Boston Pacific Company, identified what he believed to be a minimum of 16 “real world” alternatives that PSI should have evaluated explicitly in its IRP process. Dr. Roach went so far as to suggest that PSI’s IRP analysis could be considered a “distraction” that could divert the Commission’s attention from the real issues at hand. [MWIPS Ex. 1 (Roach), pp. 7-17, 22.]

        With regard to MWIPS’ proposal for a structured RFP process, MWIPS’ witness Roach made clear that the end result of such an RFP process “must be one or more pay-for-performance contracts.” Other essential elements of MWIPS’ structured RFP process include: PSI must bid and must be held to its bid; an independent third-party evaluator should lead bid evaluation efforts; PSI should be required to bid all capacity needs through 2005 (with subsequent RFPs to be used to fulfill additional PSI capacity needs in 2006 and thereafter); bids having differing term lengths should be compared by annuitizing the present values of the bids and comparing the annuities; and the Commission and Commission Staff should actively participate in both bid design and bid evaluation. [MWIPS Ex. 1 (Roach), pp. 6, 46-49.]

        In connection with his 16 “real-world” alternatives that MWIPS indicated could be used to fulfill PSI’s capacity needs via a purchased power arrangement, in his prefiled testimony Dr. Roach addressed the credit quality issues, raised by PSI with respect to the owners of those 16 alternatives, stating “these ratings are somewhat fluid and could change in the near future.” At the October 21, 2002 evidentiary hearing, Dr. Roach stated on cross-examination that there had been “a couple” of credit quality changes from what he laid out in his prefiled testimony. [MWIPS Ex. 1 (Roach), p. 18; 10/21/02 cross-examination of Roach.]

        In its testimony MWIPS’ exhibited a strong preference for retail utilities such as PSI to rely on imported purchased power as opposed to utility-owned and controlled generating plants to meet their service obligations. MWIPS witness Roach testified that he believes that pay-for-performance purchased power arrangements offer more certainty while shifting risks away from retail customers. Specifically, Dr. Roach claimed that purchased power arrangements are preferable to utility-owned generation in the following ways: a fixed or fixed-formula capacity price; a “performance guarantee” tied to that capacity price; a fixed-formula energy price; a fixed-formula price for both fixed and variable O&M costs; and a conventional force majeure clause (i.e., performance excused when events occur that are out of control of either party). [MWIPS Ex. 1 (Roach), pp. 23-25.] In Dr. Roach’s view, purchased power arrangements manage and minimize risk better than plant ownership. Risks specifically identified by Dr. Roach in this context were: equipment cost and performance risk; construction risk; financing risk; fuel risk; and operating risk. Dr. Roach also opined that competitive power suppliers would be willing to “take on market risk,” as well, which he defined as entering into purchased power contracts of shorter duration than those implied by the plant purchase scenario. [MWIPS Ex. 1 (Roach), pp. 26-27.]

        PSI-IG witness Phillips testified that, in his opinion, the current wholesale power market is not that risky, and cited relatively low forward calendar 5x16 power prices for 2003-2005 in support of his opinion. Mr. Phillips suggested that PSI could build its own new combustion turbines, thus adding capacity to the region, while relying on power purchases in the interim period during such construction. [PSI-IG Ex. 1 (Phillips), pp. 7, 9-10.]

        MWIPS and PSI-IG questioned the reasonableness of the proposed plant purchase prices. MWIPS witness Roach was of the opinion that the pre-Settlement Agreement proposed purchase prices were “at the high end of the potential range of capital costs for a peaking plant.” While Dr. Roach acknowledged that publicly available capital cost information is difficult to obtain, due to plant owners’ confidentiality concerns, he cited three bases as support for his assertion that the pre-Settlement Agreement prices were at or above the high end of a reasonable range of peaking plant capital costs: (1) published capital cost estimates for other peaking plants obtained from the Ohio Power Siting Board; (2) a Cinergy management presentation made in connection with the dissolution of the Cinergy/Duke Energy joint venture; and (3) pricing data relating to other plant sales. [MWIPS Ex. 1 (Roach), pp. 30-33.]

        PSI-IG witness Phillips also questioned the reasonableness of the pre-Settlement Agreement proposed purchase prices, noting that the proposed prices appeared to be significantly higher than industry standard prices for construction of conventional combustion turbines. Mr. Phillips also questioned the reasonableness of the Settlement Agreement proposed prices, citing generalized concerns with allowing transfers between an affiliate and a utility at net book value.

Finally, Mr. Phillips referred to the lower cost to construct one IPL peaking unit in 2000 as reported in Indianapolis Power & Light Company’s FERC Form 1. [PSI-IG Ex. 1 (Phillips), pp. 8-9; PSI-IG Ex. 4 (Phillips), p. 4.]

        PSI-IG also offered a portion of the prefiled testimony of Mr. Robert M. Endris and Dr. Peter M. Boerger in which they questioned the reasonableness of the pre-Settlement Agreement proposed purchase prices. Dr. Boerger questioned the reasonableness of including a “carrying cost” or “option value” component in the originally proposed purchase price, and raised several questions about an option value analysis performed by Mr. Rose. Dr. Boerger concluded that there should be no such component in the purchase price. [PSI-IG Ex. 2 and 3.] Mr. Endris cited the same Cinergy management presentation referred to by Dr. Roach and also questioned the comparison of the pre-Settlement Agreement proposed purchase prices with a detailed study preformed by Mr. Rose. Mr. Endris also offered his view that there were inconsistencies between the proposed purchase prices and information presented to Cinergy’s Board of directors. [PSI-IG Ex. 2 and 3.]

        As to the specific pricing prescribed by the Settlement Agreement, Dr. Roach claimed in his responsive testimony that the proposed purchase prices are still higher than comparable plant sales. And Mr. Phillips stated his opposition to the “date certain” aspect of the Settlement Agreement – i.e., the net book valuation of the plants at the earlier of the date of this IURC Order or December 1, 2002, with accrual of carrying costs from that “date certain” until the date of closing. In Mr. Phillips’ view, this “date certain”/carrying cost accrual component would unreasonably increase the cost of the assets. Additionally, Mr. Phillips testified that such carrying costs should not be calculated at PSI’s cost of capital in its last rate case, as that could result in customers paying more than PSI’s actual cost of capital. [MWIPS Ex. 2 (Roach), p. 4; PSI-IG Ex. 4 (Phillips), p. 8.]

        Finally, MWIPS questioned Cinergy’s motivation for proposing to transfer the Madison and Henry County plants to PSI, speculating that fear of falling prices drove Cinergy to propose the transfer. As support for his speculation, Dr. Roach cited his belief that, in their first year or two of operations the plants were not profitable. [MWIPS Ex. 1 (Roach), pp. 34-36; PSI-IG Ex. 1 ].

11.     Responses to the Positions Set-forth by the Intervenors. PSI stressed in its rebuttal testimony that is has a substantial need for additional peaking capacity, and indicated that the Madison and Henry County plants have the ability to reliably and efficiently meet that need. PSI also stressed that, with the turmoil in the wholesale power markets, no one except MWIPS, a group with a vested interest in promoting purchased power, was strongly advocating that PSI rely on imported purchased power to meet its significant capacity needs. Both PSI President Esamann and ICF expert Judah Rose noted the irony of advocating a purchased power solution at a time when PSI has almost zero electricity reserves and while the wholesale power market is experiencing the worst credit crisis in its history. [Pet. Ex. O (Esamann), p. 2; Pet. Ex W (Esamann), pp. 2-3; 10/21/02 cross-examination of Rose.]

        PSI indicated that an RFP process is but one means of gathering data and considering resource alternatives, and is not necessarily the best way to gather data. Moreover, PSI testified that it believed that an RFP would add little or no value in this case, due to PSI’s legitimate desire for directly interconnected “iron-in-the-ground” resources. Regardless of the possible value of an RFP, PSI concluded that the Intervenors’ testimony merely reflects an unsubstantiated contention that “there might be a better deal out there somewhere,” while ignoring PSI’s IRP analysis and the market data presented by PSI. [Pet. Ex. O (Esamann), pp. 2-3.]

        Petitioners and IURC Testimonial Staff both responded to Intervenors’ suggestion that PSI’s proposed purchase of the plants should be delayed in order for PSI to go through an RFP process. Both parties emphasized the importance of finalizing a lengthy IRP and CPCN process, the necessity of making and implementing resource decisions almost a year into the process, and the risks involved if PSI were to delay implementation of its resource plan. Dr. Borum noted that any decision to defer the acquisition of the peaking plants must recognize numerous uncertainties and the associated risks, including: the likely need to initiate and fully process a new, lengthy CPCN proceeding for other proposed capacity additions; construction lead time for such capacity additions; and the volatility, transmission, and other risks associated with relying heavily on purchased power in the interim. [IURC Staff Report No. 4 (Borum), p.3; IURC Staff Report No. 2 (Johnston), pp. 8-9; Pet. Ex. O (Esamann), pp. 25-28; Pet. Ex. Q (Murdock), pp. 4-9.]

    Mr. Esamann observed that, at its essence, this case is about pricing. Specifically, what is a fair and reasonable price for PSI to pay for the Madison and Henry County peaking plants. In PSI’s view, the Settlement Agreement reflects cost-based pricing, the economics of which are supported by PSI’s IRP analysis and are consistent with the costs and sales prices of truly comparable plants. [Pet. Ex. O (Esamann), p. 3; Pet. Ex. V (Esamann), pp. 3-6; Pet. Ex. W (Esamann), pp. 4, 8-10.]

a.     PSI’s Planning Process and the Lack of an RFP. (1) The RFP Issue. Several of Petitioners’ witnesses responded to Intervenors’ suggestion that PSI’s integrated resource planning process was fatally flawed by the lack of an RFP process. Briefly summarized, Petitioners’ witnesses explained the uncertainties and complexities inherent in relying on an RFP process, particularly an RFP seeking long-term peaking power, concluding that in many cases an RFP process adds little value in terms of market data, certainty, or even achieving a contract.

        Dale A. Murdock (an independent consultant associated with ICF) testified that he believes that the RFP process is not, and should not be represented as, a simple exercise whose outcome will provide efficient certainty. An RFP that is carefully written to capture the essence of the types of energy products and services equivalent to owning and/or fully controlling dispatchable peaking generation will by nature and necessity be very complex. According to Mr. Murdock, it is by no means certain that the outcome of an RFP process will provide an accurate representation of known or knowable resource alternatives. Mr. Murdock further emphasized that RFPs are not the only means of identifying market alternatives and are not the predominant means used by wholesale market participants to transact energy. In fact, the amount of energy purchased through RFPs represents a small fraction of the energy bought and sold in the wholesale market. [Pet. Ex. Q (Murdock), pp. 4-5.]

        Effectively using RFPs to deal with critical issues such as transmission service and transmission cost is particularly problematic, according to Mr. Murdock. These issues can greatly complicate the process of evaluating proposals from multiple suppliers. Because power plants are location specific, each will have a different set of constraints associated with transmission access, capacity, and congestion. Normalizing these differences, particularly for a long-term contract, can be a difficult process. In fact, bidders often specify an alternative delivery location than that requested by the utility, leaving the problem of transmission congestion and residual transmission capacity needs for the utility. [Pet. Ex. Q (Murdock), p. 7.]

    Mr. Murdock also noted specific complications presented when using an RFP for peaking capacity. By definition, the need for capacity during times of system peak implies a corresponding need for a high degree of flexibility, reliability and control. The utility, in this case PSI, needs to be able to quickly dispatch the peaking capacity when system conditions so require. Developing language for an RFP, and eventually developing an operational contract that approaches the control that plant ownership brings, is particularly difficult for highly flexible peaking resources. [Pet. Ex. Q (Murdock), pp. 7-8.]

Another important and complex RFP issue involves supplier credit risk. Mr. Rose pointed out that purchasing power from companies that are not regulated is likely to involve more credit-related risks than having PSI own it. In the event the power supplier defaults, PSI would have to contract for a supply of replacement power. This could require the purchase of more expensive power if prices in the market are high at that point in time. Attempting to address these credit-related issues in an RFP is a complicated and uncertain task. Unfortunately, as Mr. Rose noted, credit concerns in the wholesale power industry are particularly relevant today. [Pet.     Ex. P (Rose), pp. 18-19.]

        In response to PSI-IG’s contention that an RFP is necessary due to the affiliate nature of the proposed transactions, Mr. Esamann emphasized that, while this is an affiliate transaction, this proposed transaction is very public, and the Commission and the parties have had over 10 months to scrutinize the proposal in detail. Mr. Rogers testified that these plants were developed with the idea that they might later be transferred to PSI to meet PSI’s growing capacity needs. In addition, the proposed purchase prices are cost-based (based on the plants’ net book values). While Cinergy and PSI do not have an arms’ length relationship, the Settlement Agreement (and the substantially reduced purchase prices reflected in that Settlement Agreement) are the product of arms’ length bargaining between Petitioners on the one side, and the OUCC and the IURC Testimonial Staff on the other. [Pet. Ex. W (Esamann), pp. 8-9.]

The IURC Testimonial Staff commented on the RFP issue as well. Mr. Johnston expressed his opinion that a utility can adequately assess wholesale market options in its IRP process by means of a wholesale market forecast, as PSI has utilized in this case. In his testimony, Mr. Johnston recognized that Hoosier Energy had issued an RFP for peaking power in late 2001, but found that the RFP responses it received were similar to Hoosier’s proposed costs of acquiring and building its own new peaking plants. At the same time, Hoosier Energy noted that there were a number of non-price related factors which favored ownership and control of its own plants, including transmission risk; construction risk; the availability of the resources to be used to meet operating requirements; and advantages in scheduling and dispatching. [IURC Staff Report No. 2 (Johnston), pp. 2-10.]

(2)     Discussion of Possible Alternatives. Ms. Jenner testified that PSI considered over 100 supply-side resources as potential alternatives. While many of the alternatives were generic resources from the EPRI TAG®, there were also estimates prepared by Cinergy’s engineering group to install specific combustion turbines (7EA and 7FA CTs) at sites on the PSI system.

PSI’s IRP process also considered an estimate to repower its Edwardsport Station; estimates to install new coal-fired generation at a site in Northern Kentucky; DSM programs; and, numerous renewable resources (such as wind, solar and biomass) based on cost estimates contained in the “Repowering the Midwest” report. [Pet. Ex. R (Jenner), p. 2.] Ms. Jenner also testified that PSI considered purchased power in its IRP based on detailed, region-wide, generation-unit data, costs and performance of power supply options, and fully integrated fuel and environmental markets. [Pet. Ex. R (Jenner), p. 3; Pet. Ex. C (Rose), p. 36.]

(3)     Response to the Alternatives Identified by the Intervenors. Mr. Esamann addressed Dr. Roach’s testimony regarding the 16 “real world” alternatives that Dr. Roach indicated that PSI failed to explicitly evaluate in its IRP process. First, Mr. Esamann addressed the plants on Dr. Roach’s list that have been cancelled, delayed or are no longer under construction. Next, Mr. Esamann discussed the plants whose capacity is already committed to other utilities. Mr. Esamann then testified regarding plants that are not directly interconnected to the Cinergy transmission system. Mr. Esamann next discussed the non-peaking plants on the list, and indicated that PSI’s capacity need is for peaking power. [Pet. Ex. O (Esamann), pp. 18-25.] In his testimony Mr. Esamann indicates that, with respect to the two remaining plants on Dr. Roach’s list that he had not previously discussed, Cinergy had previously explored purchasing those two plants (Wheatland and Duke Vermillion), but the prices were too high.

b.     Utility Owned Assets and Purchased Power Arrangements.

(1)     Purchased Power Testimony. PSI’s evidence demonstrates that the wholesale market continues to exhibit great potential for unexpected price spikes. This potential for price spikes and price volatility stems from the potential gap between available supply and demand during peak demand periods. This potential gap, and the associated potential for price volatility, is exacerbated by the recent cancellation of thousands (approximately 75,000) of megawatts of planned construction of new generating capacity across the country. Mr. Rose testified that, in his opinion, the question is not whether there will be price spikes, but how frequent and how high they will be. [Pet. Ex. P (Rose), pp. 12-17; Pet. Ex. P-4 (Updated) (Rose); Pet. Ex. O (Esamann), pp. 10-11.]

        PSI concluded that heavy reliance on purchased power would require PSI to take on significant credit-related risk. In the event the supplier defaults on its contract to supply power, PSI would have to obtain replacement power. Market price volatility risks would come into play in such a situation. PSI would be at the mercy of then-existing market conditions and risks – including price and availability risks – in order to replace potentially hundreds of megawatts of needed capacity. [Pet. Ex. P (Rose), pp. 19-23; Pet. Ex. O (Esamann), pp. 11-12.]

        PSI indicated that two Indiana Utilities have experienced repercussions from the current wholesale power credit crisis. Hoosier Energy recently had its debt downgraded due to its relationship with Williams Energy. [Pet. Ex. P (Rose), p. 19.] And Wabash Valley Power Association recently had to obtain a replacement for a purchased power agreement with Enron, due to Enron’s descent into bankruptcy. See, In re Petition of Wabash Valley Power Assn., Cause No. 42185 (Ind. Util. Reg. Comm’n, October 10, 2002). As Mr. Rose testified on cross-examination, this is perhaps the worst time for a utility to be relying heavily on purchased power to meet its needs. [Pet. Ex. N (Rogers), pp. 9-10; Pet. Ex. P (Rose), p. 19; Pet. Ex. O (Esamann), p. 11; 10/21/02 cross- examination of Rose.]

        With regard to these qualitative, risk-related factors, IURC Testimonial Staff witness Johnston emphasized that there are non-price factors that should be considered in a utility’s resource decision-making process. One such factor is the extent to which the utility should be exposed to the market. In Mr. Johnston’s view, each utility’s management should weigh all of the relevant factors in order to arrive at an answer for their company that will enable it to meet its obligation to serve. [IURC Staff Ex. 2 (Johnston), p. 10.]

(2)     Possible Benefits of Pay-for-Performance Contracts Versus Benefits of Ownership of Madison and Henry County Plants. Mr. Esamann testified that he believed that the benefits of pay-for-performance purchased power contracts, touted by Dr. Roach, were largely illusory when compared to the benefits of PSI owning the Madison and Henry County plants. Mr. Esamann took issue with Dr. Roach’s claim that the capacity costs of a pay-for-performance contract would be known, whereas the costs of the Madison and Henry County plants are unknown. In reality, the capital costs and associated rate impacts of the plants will in large part be fixed based upon the purchase prices approved by the Commission in this case. Mr. Esamann testified that energy costs for both the plants and pay-for-performance contracts will likely vary with natural gas market fluctuations. Finally, Mr. Esamann challenged Dr. Roach’s position on contractual performance guarantees. He pointed out that contractual performance guarantees cannot and do not guarantee actual physical performance. Rather, they provide for financial consequences if physical performance does not occur.

        PSI presented actual operating data demonstrating that the Madison and Henry County plants are experiencing outstanding starting and operating reliability. On top of that, the Settlement Agreement contains two performance guarantees (described supra). [Pet. Ex. O (Esamann), pp. 15-16; Pet. Ex. V (Esamann), p. 8; Pet. Ex. V-1, p. 3.] Mr. Esamann and Ms. Jenner pointed out additional benefits offered by plant ownership over pay-for-performance purchased power contracts. These benefits include potential transmission cost savings; and savings offered by the purely dispatchable nature of owned plants. [Pet. Ex. O (Esamann), p. 17; Pet. Ex. R (Jenner), pp. 4-5.]

c.     Reasonableness of the Proposed Plant Purchase Prices. Petitioners supported the reasonableness of the proposed purchase prices ultimately reflected in the Settlement Agreement in several ways. First, Petitioners pointed to the cost-based nature of the pricing. As recognized by Dr. Borum, cost-based pricing between affiliates is generally considered to be acceptable by agencies such as the Securities and Exchange Commission. [Pet. Ex. V (Esamann), pp. 3-5; IURC Staff Report No. 1 (Borum), p. 24.]

        With regard to Cinergy’s internal valuation of the plants, Mr. Rogers explained that Dr. Roach and Mr. Endris had both misinterpreted the Cinergy management presentation made in connection with the dissolution of the Cinergy/Duke Energy joint venture. He pointed out that this report valued the Henry County Plant as of April 2001, before the plant was completed. Mr. Rogers also pointed out that, despite Dr. Roach’s assertion, Cinergy did not believe the Madison Plant to be less valuable than the Vermillion Plant; rather, Duke did and was willing to pay more for the Vermillion plant. Mr. Esamann explained what Mr. Endris perceived as inconsistencies in a Cinergy Board of Directors presentation were due to the treatment of carrying costs, inventory, and the cost of proposed inlet heater and quick start modifications at Henry County, in addition to whether the figure quoted included 100% or 64.24% (the native load portion) of Henry County. Mr. Rose explained that Mr. Endris was mistaken in his criticism of the use of his detailed study, not in the least because Mr. Endris ignored several caveats and comments reflecting the conservatism of the study and also ignored the fact that the fixed O&M costs of Madison and Henry County are lower than those of comparable units. [Pet. Ex. N (Rogers), pp. 18-19; Pet. Ex. O (Esamann), pp. 33-34; Pet. Ex. P (Rose), pp. 9-11.]

    Mr. Rogers directly addressed Cinergy’s and PSI’s motivation with respect to the proposed transfer of the Madison and Henry County plants. Mr. Rogers emphasized that Cinergy’s and PSI’s motivation has been and continues to be to meet PSI customers’ growing demands for electricity in the most economic, reliable and low risk manner. Even though the Madison and Henry County plants were initially developed on the merchant side of the business, Cinergy has always recognized – and articulated – the possibility that these plants would be used to meet PSI’s growing retail native load obligations. Specifically, Mr. Rogers pointed to a number of previous statements addressing this possibility, made by him as a witness in a December 1999 evidentiary hearing before the Commission (in Cause No. 41448). Those statements make clear that in Mr. Rogers’ and Cinergy’s view, by participating in the Cinergy/Duke Energy joint venture Cinergy was preserving the option for PSI to come to the Commission and request a CPCN to purchase these plants, to use these plants to meet PSI’s growing capacity needs. [Pet. Ex. N (Rogers), pp. 3-5.]

    Mr. Rogers 1999 testimony cited PSI’s dwindling reserve margins, and explained that the two plants were initially developed as merchant plants for purposes of expediency while preserving the option for retail native load customers: “we had a window of opportunity to buy this generation, if we were going to buy it in the regulated company, we’d had to come here, get a certificate, go through the process, and would have lost the opportunity to buy that generation. . . . It was an opportunity [to buy the generation] that arose in August 1999, and based on what we knew is that we had a couple of months to buy it.” [Pet. Ex. N (Rogers), pp. 5-6.]

        Once it became clear to PSI that purchased power was no longer the most economic and viable long-term resource option, and once the Duke Energy/Cinergy joint venture partnership was dissolved, thus giving Cinergy “free and clear” ownership of the Madison and Henry County plants, PSI analyzed the Madison and Henry County purchase option through its normal IRP processes. Once that analysis was complete, confirming PSI’s judgment since 1999 that new generation would soon be needed on the PSI system, PSI filed its CPCN petition with the Commission initiating this Cause. [Pet. Ex. N (Rogers), p. 7.]

12.     Other Provisions of the Settlement Agreement Relating to this Cause No. 42145. In addition to providing for the purchase by PSI of the Madison and Henry County plants at the purchase prices prescribed therein, the Settlement Agreement also addressed several other tangentially related issues: (1) an interim purchased power arrangement; (2) certain performance guarantees; (3) assignment of certain plant-related affiliate agreements; (4) specific ratemaking for the Henry County plant; and (5) certain revisions to Petitioners’ proposed asset purchase agreements. Petitioners addressed and supported each of these issues in initial testimony, rebuttal testimony, and testimony in support of the settlement agreement.

        With respect to the interim purchased power arrangement, Mr. Esamann explained that this provision came about as a result of the other Settling Parties’ desire to provide PSI and its customers with “seamless” access to the Madison/Henry County capacity until the plants are actually transferred to PSI. Further, the other Settling Parties desired to provide PSI and customers with access to the plants through the Summer of 2003, even in the event of federal agency disapproval of the transfers. Accordingly, the Settling Parties fashioned a unit power sales arrangement (very similar to the 2002 arrangement approved by the Commission in Cause No. 42196) whereby PSI will pay CC&T capacity and energy charges for the capacity, but will be refunded the capacity charges upon transfer of the plants. In the event of federal agency disapproval of the transactions, PSI will be entitled to recover the energy charges and 50% of the capacity charges from customers via a rate tracking mechanism. No party took issue with this provision of the Settlement Agreement. [Pet. Ex. V (Esamann), pp. 6-7; Pet. Ex. V-1.]

        With respect to performance guarantees, Mr. Esamann explained that in order to alleviate any doubts on these issues, the Settlement Agreement contains two short-term performance guarantees – a Madison transmission “hold harmless” provision and an operating reliability guarantee applicable to both plants. No party contested this provision of the Settlement Agreement. [Pet. Ex. V (Esamann), pp. 7-8.]

        The Settlement Agreement requires that PSI separate out for retail ratemaking purposes, the costs and revenues associated with 50 MWs of capacity of the Henry County plant. Mr. Esamann explained that this 50 MWs of Henry County capacity will “stand on its own” for ratemaking purposes, and neither the costs nor the revenues will be reflected in PSI’s retail rates. [Pet. Ex. V (Esamann), p. 9.]

13.     MWIPS’ Motion for Modification of Procedures. On October 16, 2002, just days prior to the Evidentiary Hearing scheduled in this Cause, MWIPS filed a “Motion for Modification of Procedures.” PSI-IG and Nucor subsequently joined in that Motion. At the close of the October 21, 2002 Evidentiary Hearing, MWIPS’ argued in favor of its Motion, and claimed that several of its members had indicated an interest in submitting purchased power bids to PSI. MWIPS requested that the Commission schedule additional filing and hearing dates to address these indications of interest.

        Petitioners, joined by IURC Testimonial Staff, opposed MWIPS’ motion. The primary basis for Petitioners’ opposition was that MWIPS had numerous opportunities since Petitioners initiated this case in December 2001 to submit whatever evidence it desired, including indications of interest in selling power to PSI. There was nothing that prohibited MWIPS from filing any and all evidence it desired to file in accordance with the procedural schedule established in this Cause. Rather, MWIPS made a deliberate choice not to file this type of evidence when it had the procedurally appropriate opportunity to do so, and that appropriate time had passed.

        The Presiding Officers denied MWIPS’ Motion on the record on October 21, 2002. Subsequently, MWIPS appealed the denial of it Motion to the full Commission. By a vote of 3:0, the Commission upheld each of the determinations made by the Presiding Officers and rejected MWIPS’ appeal.

14.     Commission Findings and Determinations. As we have observed in previous cases, Indiana law strongly favors settlement as a means of resolving contested proceedings. See, e.g., Manns v. State Department of Highways, (1989), Ind., 541 N.E.2d 929, 932; Klebes v. Forest Lake Corp., (1993), Ind. App., 607 N.E.2d 978, 982; Harding v. State (1992), Ind. App., 603 N.E.2d 176, 179. A settlement agreement “may be adopted as a resolution on the merits if [the Commission] makes an independent finding, supported by substantial evidence on the record as a whole, that the proposal will establish ‘just and reasonable’ rates.” Mobil Oil Corp. v. FPC (1974), 417 U.S. 283, 314 (emphasis in original). See, Indianapolis Power & Light Co., Cause No. 39936, at p. 7 (Ind. Util. Reg. Comm’n, August 24, 1995); In re NIPSCO Investigation, Cause No. 41746 (Ind. Util. Reg. Comm’n, September 23, 2002). See also, Mendenhall v. Skinner & Broadbent Co., 728 N.E.2d 140, 145 (Ind. 2000)(“The policy of the law generally is to discourage litigation and encourage negotiation and settlement of disputes”); In re Assignment of Courtrooms, Judge’s Offices and Other Facilities of St. Joseph Superior Court, 715 N.E.2d 372, 376 (Ind. 1999) (“Without question, state judicial policy strongly favors settlement of disputes over litigation”). Notably, the Commission specifically recognizes the role of settlements in Commission proceedings in its procedural rules under 170 IAC 1-1.1-17.

        Our policy favoring settlements applies even in cases of settlements between less than all parties. Quoting from Pennsylvania Gas & Water Co. v. Federal Power Comm’n, 463 F.2d, 1242, 1246 (D.C. Cir. 1972). (“Pennsylvania Gas”), we observed in In re Public Service Co. of Indiana, Inc., 72 PUR4th 660, 683 (Ind. Util. Reg. Comm’n, March 7, 1986), “[I]n agency proceedings settlements are frequently suggested by some, but not necessarily all, of the parties; if on examination they are found equitable by the regulatory agency, then the terms of the settlement form the substance of an order binding on all the parties, even though not all are in accord as to the result.” 463 F.2d at 1246.

        The OUCC’s participation in the Settlement Agreement is notable. As we have observed in the past, we should give heightened consideration to a settlement that is supported by the OUCC. As we stated in both In re NIPSCO Investigation and In re Public Service Co. of Ind., Inc.:

Because the OUCC is a party to the proposed Settlement Agreement, the Commission has an increased responsibility to carefully consider the merits of the agreement. The utility consumer counselor is mandated by statute to “have charge of the interests of the ratepayers and consumers of the utility . . . .” I.C. 8-1-1.1-5(e). [The OUCC] “represents all 5.4 million consumers of utility services in Indiana. [The OUCC’s] representation encompasses the interests even of those who have elected to be independently represented in these proceedings. Given [the OUCC’s] statutory mandate, this Commission must carefully consider the merits of any proposed settlement which the UCC supports as being in the best interests of [its] constituency, the consumers.

In re Petition of Public Service Co. of Ind., Cause No. 37414 (Ind. Util. Reg. Comm’n, March 7, 1986); see also, In re NIPSCO Investigation, Cause No. 41746 (Ind. Util. Reg. Comm’n, September 23, 2002).

        At the same time, settlements presented to the Commission are not ordinary contracts between private parties. United States Gypsum, Inc. v. Indiana Gas Co., 735 N.E.2d 790, 803 (Ind. 2000). When the Commission approves a settlement, that settlement “loses its status as a strictly private contract and takes on a public interest gloss.” Id. (quoting Citizens Action Coalition v. PSI Energy, 664 N.E.2d 401, 406 (Ind.Ct.App. 1996). Thus, the Commission “may not accept a settlement merely because the private parties are satisfied; rather [the Commission] must consider whether the public interest will be served by accepting the settlement.” Citizens Action Coalition, 664 N.E.2d at 406. Further, any Commission decision, ruling, or order – including the approval of a settlement agreement – must be supported by specific findings of fact and sufficient evidence. United States Gypsum, 735 N.E.2d at 795 (citing Citizens Action Coalition v. Public Service Co., 582 N.E.2d 330, 331 (Ind. 1991). The Commission’s own procedural rules require that settlements be supported by probative evidence. 170 IAC 1-1.1-17(d). Therefore, before the Commission can approve the Settlement Agreement, we must determine whether the evidence in this Cause sufficiently supports the conclusions that the Settlement Agreement is reasonable, just, and consistent with the purpose of Ind. Code 8-1-2, and that such an agreement is consistent with the public interest.

        Based upon the evidence presented at the public hearings in this Cause, and based upon our review of the provisions of the Settlement Agreement, we are persuaded that the Settlement Agreement as it relates to Cause No. 42145 is, in its entirety, just, reasonable, and consistent with the purpose of Ind. Code 8-1-2 and in the public interest. Our findings in this regard are described in more detail below.

        With regard to future citation of the Settlement Agreement and Order, we find our approval herein should be construed in a manner consistent with our finding in In Re Richmond Power & Light, Cause No. 40434, (Ind. Util. Reg. Comm’n, March 19, 1997). Consistent with the Settling Parties’ agreement, the settlement shall not constitute a waiver of any position that any of the Settling Parties may take with respect to any or all of the items and issues resolved herein in any future regulatory or other proceedings.

a.     Commission’s Obligations Under Ind. Code 8-1-8.5-4 and –5. Under Ind. Code § 8-1-8.5-4 and -5 and related provisions, an application for a CPCN may only be granted after a hearing, and if the Commission has (1) made a finding as to the best estimate of construction, purchase, or lease costs; (2) made a finding that either the construction, purchase, or lease will be consistent with the Commission’s plan for expansion of electric generation capacity, or that the construction, purchase, or lease will be consistent with a utility specific proposal as to the future needs for electricity to serve the people of the state or the area served by the utility; and (3) and made a finding that the public convenience and necessity require or will require the construction, purchase, or lease of the facility. In addition, the Commission must take into account the utility’s current and potential arrangement with other utilities for the interchange of power; the pooling of facilities; the purchase of power; joint ownership of facilities; and other methods for providing reliable, efficient and economical electric service, including the refurbishment of existing facilities, conservation and load management, cogeneration and renewable energy sources.

(1)     PSI’s Capacity Needs. PSI has experienced, and continues to experience, strong peak demand growth. PSI’s existing resources are insufficient for PSI to reliably meet its current and projected customer peak demands, including the maintenance of a reasonable level of reserves. The evidence shows that PSI’s current reserve margin with on-system resources is less than 1%, necessitating reliance on almost 900 MWs of purchased power during the Summer of 2002. Even with the anticipated addition of the Noblesville repowering project in 2003, PSI’s on-system reserve margin will be less than 4%. Thus, based on the evidence of record, the Commission finds that PSI is in need of additional capacity on its system.

        The evidence also indicates that PSI’s current generating resources are heavily weighted toward baseload capacity, while optimally, the PSI system should be comprised of relatively more peaking capacity. The evidence further indicates that the addition of gas-fired peaking capacity will benefit the PSI system in terms of fuel diversity and mitigating future environmental regulation risk. Based on this evidence of record, the Commission finds that peaking capacity is an appropriate choice for the next increment of capacity to the PSI system.

(2)     PSI’s Resource Planning Process. PSI’s evidence described at great length the process that was used to identify the range of viable resource alternatives, followed by various screening, integration, and sensitivity analyses, ultimately narrowing the myriad of potential resource alternatives until reaching an optimal combination of feasible and economic alternatives that will reliably meet projected customer load requirements. PSI’s evidence detailed the multitude of alternatives, both supply-side and demand-side, considered in its quantitative IRP process. PSI’s evidence also described the risks and benefits qualitatively considered in its IRP process.

        PSI’s evidence demonstrated that, of the over 4200 alternative expansion plans produced by its IRP modeling, the purchase of the Madison and Henry County plan was the “number one” “least cost” plan, and the purchase of the plants was the primary near-term component in each of the top 20 of such plans (ranked in terms of savings to customers over the relevant study period). PSI’s evidence further demonstrated that it performed a number of sensitivity analyses around the top “significantly different” expansion plans, and that the Madison/Henry County plan performed equally well or superior to all other plans in all of the sensitivity analyses. PSI’s evidence also demonstrated that it considered a number of qualitative, risk-related factors in connection with its IRP process, and that in its judgment, from risk and reliability perspectives, the Madison/Henry County plan is superior to other plans, especially those plans that would rely more heavily on purchased power.

        The IURC Testimonial Staff, after examining PSI’s resource planning process, concluded that “the analysis by PSI was reasonably well done and substantiates that PSI’s recommend resource plan is one that can do well over a range of uncertainties.” [IURC Staff Report No. 1 (Borum), p. 3.]

        The only real dispute in this case relative to PSI’s planning process was whether or not PSI should be required to utilize an RFP process. As we have noted in previous orders, RFPs are not required by either the CPCN statute or by the Commission’s IRP rules. See, e.g., In re Petition of PSI Energy, Inc., Cause No. 39175 (Ind. Util. Reg. Comm’n, May 13, 1992). PSI presented evidence that it considered the purchased power alternative in its planning process, by means of utilizing an independent wholesale power price forecast prepared by ICF. The IURC Testimonial Staff recognized the legitimacy of using a wholesale market price forecast in the IRP process. PSI also presented evidence that it gathered other market data that supported its IRP conclusions. PSI witnesses’ testified at length as to why PSI believes that an RFP process was neither necessary nor desirable in this case. PSI presented evidence concerning the various types of market and comparable plant data it reviewed, all of which, in PSI’s view, supported its conclusion that the purchase of the Madison and Henry County plants was appropriate.

Additionally, PSI presented evidence concerning the risks of relying on the current wholesale power market, in particular supplier credit risks and transmission constraint risks. PSI offered persuasive evidence as to why, in light of these market risks, in its judgment heavy reliance on purchased power to meet almost 100% of its reserve requirements is not the best course of action for either PSI or its customers.

        This Commission has previously established the standard for determining the adequacy of a utility’s planning process for purposes of our CPCN statute:

If an Indiana utility reasonably considers and evaluates the statutorily required options for providing reliable, efficient, and economic service, then the utility should, in recognition that it bears the service obligation of IC 8-1-2-4, be given some discretion to exercise its reasonable judgment in selecting the options or options to implement which minimize the cost of providing such service.

In re Petition of PSI Energy, Inc., Cause No. 39175, at pp. 3-4, 14 (Ind. Util. Reg. Comm’n, May 13, 1992); In re Petition of PSI Energy, Inc. Cause No. 41924, at p. 12 (Ind. Util. Reg. Comm’n, December 17, 2001).

        As the utility that has a legal obligation to provide adequate and reliable electric service to Indiana customers, we continue to believe that a utility should be given some discretion to exercise its judgment in its resource planning process. For all of these reasons, the Commission finds that PSI’s resource planning process adequately reviewed the range of appropriate alternatives, that PSI’s method of narrowing down the range of alternatives for further consideration was reasonable, and that the resulting decision in favor of the purchase of the Madison and Henry County plants was reasonable.

(3)     PSI’s Consideration of the Statutory Alternatives. As we have previously observed, the CPCN statute “requires public utilities in Indiana to evaluate and consider reasonable alternatives to installing additional generating capacity to meet the utility’s forecasted probable future growth of the use of electricity and requires the Commission to consider the utility’s evaluation of alternative means of meeting capacity requirements. . . . We believe that some deference should be given to a utility’s judgment, provided the utility has made a reasonable, good faith effort to evaluate and consider available alternatives. . . .: In Re Petition of PSI Energy, Inc., Cause No. 39175, at pp. 3-4 (Ind. Util. Reg. Comm’n, May 13, 1992); In re Petition of PSI Energy, Inc., Cause No. 41924, at p. 12 (Ind. Util. Reg. Comm’n, December 17, 2001).

        The statutory alternatives required to be considered are: (a) the interchange of power; (b) the purchase of power; (c) the pooling of facilities; (d) joint ownership of facilities; and other methods of providing reliable, efficient, and economical electric service, including (e) the refurbishment of existing facilities; (f) conservation and load management; and (g) cogeneration and renewable energy sources. Our findings as to the adequacy of PSI’s consideration of these factors are described below.

        The evidence shows that PSI considered interchange of power, pooling of facilities, joint ownership of facilities, and refurbishment of existing facilities, and that PSI reasonably concluded that none of these alternatives would provide the capacity to be provided by the purchase of the Madison and Henry County plants. Accordingly, we find that PSI has adequate considered interchange of power, pooling of facilities, joint ownership of facilities, and refurbishment of existing facilities, and that PSI’s decision to rely on a source of capacity other than these alternatives is reasonable.

        The evidence also shows that PSI adequately considered conservation and load management alternatives in its resource planning process, and that PSI reasonably concluded that conservation and load management cannot be used to substitute for or replace the capacity represented by the Madison and Henry County plants. No party disputed PSI’s conclusions concerning conservation and load management alternatives. The Commission finds that PSI has adequately considered these alternatives and has further demonstrated that increased conservation and load management programs alone cannot satisfy PSI’s substantial need for additional capacity. The evidence also indicates that PSI adequately considered cogeneration and renewable energy sources in its resource planning process. PSI demonstrated that, for both technical and economic reasons, cogeneration and renewable energy sources cannot be used as substitutes for the Madison and Henry County capacity. We find that PSI has adequately considered cogeneration and renewable energy alternatives and that its decision to acquire needed capacity by means other than cogeneration and renewable energy sources is reasonable.

        Finally, the evidence indicates that PSI adequately considered the purchase of power, both quantitatively and qualitatively, in its resource planning process. PSI’s quantitative analysis indicated that the purchase of the Madison and Henry County plants should be more cost-effective than reliance on purchased power over the long-term. Based on the evidence presented by the parties, PSI reasonably concluded that the purchase of the Madison and Henry County plants was superior to the purchased power alternative in terms of risk and reliability. Accordingly, we find that PSI has adequately considered the purchase of power, and that its preference for the purchase of the Madison and Henry County plants in lieu of an increasingly heavy reliance on imported purchased power is reasonable.

(4)     Consistency of the Purchase of the Madison and Henry County Plants with PSI’s Utility-Specific IRP and with the State’s Expansion Plan. With regard to PSI’s utility-specific IRP proposal, the key additions shown in PSI’s current, near-term IRP plan for reliably meeting its native load customers’ demand requirements are: purchase of the Madison and Henry County plants in 2003; completion of the Noblesville repowering project in 2003; purchases (approximately 200 to 300 MWs) from the forward wholesale power markets in 2003 and for succeeding years.

        Along with these contemplated supply-side additions, PSI’s IRP plan continues to rely on significant levels of peak demand reductions from traditional DSM programs, PowerShare and RTP, and customer-specific interruptible contracts. PSI emphasized that its current IRP is both flexible and robust. It is flexible in that PSI can adjust the purchase amounts as needed, or move up (or back) the addition of combustion turbines. The plan is robust in that it reacts favorably under varying economic, fuel price, wholesale power price, and load scenarios.

        We find that PSI’s proposed purchase of the Madison and Henry County Generating Stations is consistent with PSI’s utility-specific proposal. We further find that the utility-specific proposal for satisfying the future needs of electricity in PSI’s service territory should be approved, but, in conformance with Ind. Code 8-1-8.5-5(d), we find such approval should be construed no more broadly than necessary to support Commission approval of CPCNs for the purchases of the Madison and Henry County plants.

        The Commission has engaged the SUFG to prepare periodic forecasts of future electricity requirements for the State of Indiana. The SUFG report presented in this Cause indicates a need for new capacity in Indiana. Further, the SUFG’s plan shows that peaking capacity, among other types, needs to be installed to maintain adequate reserves in the State. Dr. Gotham explained that the SUFG determines capacity requirements using a target 15 percent reserve margin for the state as a whole and then assigns these needed resources to the individual utilities in the state. Dr. Gotham also stated that the SUFG projections indicate that PSI needs both peaking and base load capacity, with the need for peaking capacity slightly higher. He also stated that additional capacity above the amounts assigned by SUFG would be expected to be peaking capacity, since it would not be expected to be called upon as often. Importantly, Dr. Gotham also explained that due to differences in forecast methodology and assumptions, one would expect SUFG’s projections for PSI to differ from PSI’s IRP. [IURC Staff Report No. 3 (Gotham), pp. 1-2.]

        Based on the discussion above, and because the Madison and Henry County plants will provide additional peaking capacity dedicated to Indiana retail customers, we find that PSI’s purchase of the Madison and Henry County plants, is consistent with the overall plan for electricity requirements prepared by the SUFG.

(5)     Reasonableness of the Purchase Prices; Finding on Cost Estimate. The Commission recognizes that the plant purchase prices we are asked to approve were the subject of negotiation between Petitioners, the OUCC, and the IURC Staff. Based on the evidence presented it appears that the plant purchase prices prescribed by the Settlement Agreement are cost-based. Petitioners (and IURC Testimonial Staff) presented evidence that when accurately compared to comparable plant sales, the Settlement Agreement’s purchase prices are within a range of reasonableness for facilities of this type. For these reasons, we conclude and find that the purchase prices reflected in the Settlement are reasonable, are part of a “least cost” IRP plan for PSI, and should be approved for subsequent recovery in PSI’s retail electric rates in accordance with the provisions of Ind. Code 8-1-8.5 et seq.

(6)     Public Convenience and Necessity. Finally, we consider whether the public convenience and necessity requires approval of PSI’s purchase of the Madison and Henry County plants. We previously determined that PSI has a need for capacity; that the type of capacity most needed by the PSI system is peaking capacity; that PSI adequately considered the statutory factors set forth at IC § 8-1-8.5-4; and that PSI’s resource planning process was reasonable. Further, we determined that the Madison and Henry County plants represent an economic and reliable option for PSI to utilize in meeting its obligation to provide reliable electric service. In light of those findings, and the evidence presented herein, we find that the public convenience and necessity require that PSI be granted certificates to undertake the purchase of the Madison and Henry County plants as described in the Settlement Agreement and in this Order.

16.     Request for Confidential Treatment. Petitioners filed a Motion for Protection of Confidential and Proprietary Information, with Affidavits of Messrs. Judah Rose and Douglas F. Esamann, on March 1, 2002. In this Motion, Petitioners demonstrated a need for confidential treatment for data relating to market forecasts of purchased power and natural gas prices, as well as data relating to the costs and proposed purchase prices of the Madison and Henry County Generating Stations. In a March 11, 2002, Docket Entry, the Presiding Officers made a preliminarily finding that such information should be subject to confidential procedures. The Affidavits of Messrs. Rose and Esamann indicate that such confidential information has actual or potential independent economic value to competitors, the disclosure of the confidential information could provide competitors with an unfair advantage, and Petitioners and ICF have taken all reasonable steps to protect the confidential information from disclosure. Accordingly, pursuant to IC §§ 5-14-3-4(a)-(4), we find that the data concerning the market forecasts presented in this case, as well as data pertaining to the costs and proposed purchase prices of the Madison and Henry County plants, are “trade secrets” and should be afforded confidential treatment. The Commission orders that procedures should be taken so that such information is appropriately secured and made available only to selected members of the Commission Staff who are under an obligation not to publicly disclose such information.

    17.        Ultimate Conclusion. In the Finding Paragraphs above, the Commission has determined that the public convenience and necessity support PSI’s proposed purchase of the Madison and Henry County plants, that the associated utility specific proposal should be approved, that the purchase of the Madison and Henry County plants is consistent with the utility specific proposal, and that the proposed plant purchase prices as set out in the Settlement Agreement are reasonable. Further, we have found the other provisions of the Settlement Agreement as it relates to this Cause No. 42145 to be reasonable. In light of those findings, the Commission finds that the Settlement Agreement as it relates to Cause No. 42145 should be approved in its entirety, that PSI should be issued certificates of public convenience and necessity for the purchase of the Madison and Henry County plants, and that CinCap VII should be authorized to sell the Henry County plant to PSI.

IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION that:

1.     The Settlement Agreement presented in this Cause is hereby approved by the Commission.

2.     Consistent with Ind. Code 8-1-8.5 et seq. and the Settlement Agreement, Petitioner is hereby issued Certificates of Public Convenience and Necessity for the purchase of the Madison Generating Station and the Henry County Generating Station, consistent with the Settlement Agreement and as described herein. This Order constitutes the Certificates.

3.     The purchase price formulas set out in the Settlement Agreement for the Madison and Henry County Generating Stations are hereby approved as the estimated costs for the plant purchases and are hereby approved as reasonable.

4.     CinCap VII is hereby authorized to transfer the Henry County Generating Station to PSI, consistent with the Settlement Agreement and this Order.

5.     PSI shall adopt the commitments made by CinCap VII in Cause No. 41569 relating to air quality; water quality; noise; County comprehensive plan; future abandonment; and emergency planning.

6.     Consistent with the Settlement Agreement, in future retail electric rate proceedings PSI shall separate out for ratemaking purposes the costs and revenues associated with 50 megawatts of the Henry County Generating Station that was previously committed to Wabash Valley Power Association, Inc., in Cause No. 41569.

7.     Petitioner shall file executed copies of the Asset Purchase Agreements applicable to PSI’s purchase of the Madison and Henry County Generating Stations, with the Secretary of this Commission.

8.     PSI shall file executed assignments of the plant affiliate agreements to be assigned to PSI as discussed in this Order, with the Secretary of this Commission.

9.     Information pertaining to the market price forecasts presented in this case, as well as information pertaining to the costs and the proposed purchase prices for the Madison and Henry County Generating Stations contained in the testimony, exhibits, and workpapers filed in this Cause are found to be confidential and trade secrets and, therefore, exempt from disclosure as public records.

10.     This Order shall be effective on and after the date of its approval.

McCARTY, HADLEY AND ZIEGNER CONCUR; RIPLEY CONCURRING IN PART AND DISSENTING IN PART; APPROVED:

I hereby certify that the above is a true and correct copy of the Order as approved.

______________________________________
Nancy E. Manley
Secretary to the Commission

[TEXT OF FOOTNOTES]

The SUFG was established pursuant to Ind. Code 8-1-8.5-3.5 to forecast the probable future growth of the use of electricity within Indiana and within this region of the nation. The Commission uses the SUFG’s methodology as the Commission’s primary methodology in the development of its analysis of the long range needs for expansion of facilities for the generation of electricity, consistent with Ind. Code 8-1-8.5-3.5(c).

As permitted by the Presiding Officer at the Field Hearing, on August 21 and 30, 2002, the OUCC filed supplemental public comments with the Commission in this Cause. The additional public comments filed by the OUCC are also part of the record of this proceeding.

The costs of the inlet heaters and the “quick start” equipment, while not included in the proposed plant purchase prices, were included in PSI’s resource planning analysis of the economics of the proposed plant purchases. [Pet. Ex. D (Jenner), p. 21.]

50 megawatts of output from the Henry County Generating Station was specifically dedicated for use by Wabash Valley Power Association, Inc., in Cause No. 41569. This unit power sales arrangement, and the associated capacity reservation charge payments, were the subject of a settlement agreement in Cause No. 42196 (Ind. Util. Reg. Comm’n, May 29, 2002). Although the capacity reservation charges were required for the summer months only, PSI also had access to the plants’ capacity for the remainder of 2002 as needed for native load customers. See, Cause No. 42196, (Ind. Util. Reg. Comm’n, May 29, 2002). Approximately 660 of the 880 MWs were purchased from the Madison and Henry County plants, pursuant to the unit power sales arrangement referenced supra.

Calculated on a projected basis without purchases, but including on-system generating resources, traditional DSM impacts, interruptible contract impacts, real-time pricing impacts, and PowerShare CallOption impacts. [Pet. Ex. B (Esamann), p. 16.]

Approximately 660 MWs of which was provided by the Madison/Henry County plant capacity. We note that a minimum 15% planning reserve margin is consistent with our determination, in connection with approval of PSI's Noblesville repowering project, that a 15% reserve margin was appropriate for purposes of that case. See, Cause No. 41924, (Ind. Util. Reg. Comm'n, December 17, 2001).

The estimated PVRR savings that will accrue to PSI and its customers over the 20-year study period as a result of pursuing the Madison/Henry County plan were estimated to be approximately $24 million prior to the negotiation of reduced plant purchase prices in the Settlement Agreement. [Pet. Ex. M-1 (Jenner).] The negotiated reduced plant purchase prices reflected in the Settlement Agreement will only increase (significantly) the PVRR savings associated with the Madison/Henry County plan. [Pet. Ex. V (Esamann), pp. 5-6.]

MWIPS is a group of 14 independent power producers, many of whom are experiencing serious financial difficulty and all of whom are solely dependent upon selling power in the wholesale power markets. [Pet. C-X Ex. 1; Pet. Ex. P-6 (Updated).] PSI-IG consists of 5 industrial customers of PSI.

Mr. Esamann testified that PSI believes that an RFP would have added little or no value to the IRP process. In support of this belief, he cited PSI’s substantial capacity needs, the considerable amount of market data from other sources, the reliability and risk concerns that a utility must take into account today, and the resulting small universe of resource options that are even remotely capable of reliably meeting PSI’s capacity needs. [Pet. Ex. O (Esamann), p. 25.]

As to the affiliate nature of the transaction, Dr. Borum noted that affiliate transactions of this type are not unheard of, citing a recent purchase by Louisville Gas and Electric Company and Kentucky Utilities Company of two combustion turbine facilities from an affiliated company. The Kentucky PSC approved that purchase, at cost. [IURC Staff Report No. 1 (Borum), p. 24.]

The Petitioners and IURC Testimonial Staff noted that the proposed purchase prices are comparable to the recently approved purchase price for the Worthington plant, proposed to be purchased by Hoosier Energy from Williams Energy. See, In re Petition of Hoosier Energy, Cause No. 42079 (Ind. Util. Reg. Comm’n, August 16, 2002), amended order September 18, 2002). [Pet. Ex. R (Jenner), pp. 6-8; IURC Staff Report No. 2 (Johnston), pp. 3-4.]

The OUCC took no position concerning MWIPS’ Motion. Further, consistent with the requirements of Ind. Code 8-1-8.5-5, we find that the purchase price formula contained in the Settlement Agreement, as illustrated by various confidential exhibits presented to the Commission in this case, constitutes the best estimate of the purchase costs that will be incurred by PSI in connection with its purchase of the Madison and Henry County Generating Stations.

STATE OF INDIANA

INDIANA UTILITY REGULATORY COMMISSION

OPINION

CONCURRING IN PART AND DISSENTING IN PARTOF
COMMISSIONER JUDITH G. RIPLEY

JOINT PETITION OF PSI ENERGY, INC.
AND CINCAP VII LLC, PURSUANT TO
IND. CODEss.8-1-8.5 ET SEQ.: (1) FOR
THE ISSUANCE OF CERTIFICATES OF
PUBLIC CONVENIENCE AND
NECESSITY FOR PSI ENERGY, INC TO
PURCHASE GENERATING FACILITIES
FOR THE FURNISHING OF ELECTRIC
UTILITY SERVICE TO THE PUBLIC;
(2) FOR THE APPROVAL OF THE COSTS
OF SUCH FACILITIES; AND (3) FOR
APPROVAL FOR CINCAP VII TO
TRANSFER OWNERSHIP OF GENERATING
ASSETS TO PSI ENERGY, INC. )
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CAUSE NO. 42145

dated 12-19-02

I agree with the majority opinion based on the work of the Commission Staff and other parties that PSI has demonstrated a need for new resources to bolster their reserve margin. I am further convinced of this need by the SUFG’s similar findings. I am also impressed that the IURC testimonial staff and the OUCC have worked together to craft a settlement that addresses some of my concerns. Unfortunately, with regard to Cinergy’s planning, I am concerned that their desired “end result” of transferring the generating facilities from the ravages of the competitive market to the protection of the regulated market may have driven their planning process rather than a truly objective assessment of cost-effective and reliable options.

I also concur with my colleagues in the majority that a Request For Proposals (“RFP”) is not an end to itself. I regard the RFP process to be an important element of a well-functioning planning process. In this case, I agree that even if PSI had issued an RFP it might not have changed the decisions in this Cause. I do, however, agree with Dr. Boerger, the PSI Industrial Group and the MWIPS testimony that an RFP should have been conducted in this cause to aid in the decision making process. I am concerned that others might infer from this Order that we have dismissed the idea of RFPs as part of a reasoned planning process. Our Staff informed me that a requirement for RFPs was considered during the formulation of our Integrated Resource Planning Rules (“IRPs”). The utilities, however, persuaded the Commission that such rules were not necessary because no utility would ever embark on a major construction program without conducting an RFP process that considered all available cost-effective options.

Further, the very nature of this transaction creates suspicions that this contract was not negotiated at “arm’s length.” I take some comfort that the IURC staff and the OUCC negotiated a settlement, however, had PSI issued an RFP in this Cause it would have done much to avoid the appearance this creates. (The Commission decided in Cause No. 41410, Commission Investigation into the Operation of South Haven, that the affiliate transactions involved required further information and the order required the utility to provide an RFP prior to approving the costs.)

PSI, in my opinion, has been extremely progressive in the area of demand-response. While I know that PSI evaluated demand response programs, including renewable energy resources, in their planning process, I don’t know that the evaluation was in the context of the “future” wholesale market that would, in large part, be operated by the Midwest Independent System Operator (“MISO”) that might increase the “cost effectiveness” of certain options. I certainly would take more comfort in this Order if I were persuaded that PSI gave due affect to the potential for more accurate prices emanating from the wholesale market as a basis for determining the cost-effectiveness of demand response programs in comparison to other alternatives. Certainly, we want to avoid engaging in “hindsight” regulation but I would have liked to have more certainty regarding the options for purchasing power, buying existing merchant facilities that were “distressed” in this down market, or demand-side management alternatives that were available to PSI at the time that this case was filed to have greater assurance that this was the best option for PSI’s customers. This is the second case involving PSI where they have not conducted an RFP. This “ala carte” consideration of individual projects gives rise to the concern that PSI’s planning process is not as comprehensive as it could be. The electric industry seems to be “boom or bust” going from supply deficiency to excess supply. In the former case, the utilities argue that there is no time for a more comprehensive consideration of demand side and other options. In the latter case of excess capacity, the utilities tell us that the low costs of power resulting from excess supply renders any alternative such as demand side management to be not cost effective.

        At the time that the Henry County plant was originally considered, an argument was advanced that this Commission could approve the development of this facility as a “merchant plant” because it, like other contemporaneous merchant plants that this Commission approved, would have little -if any — impact on ratepayers since the facility would not be in PSI’s ratebase. The comments of Chairman Rogers notwithstanding, that is the strong message that Cinergy put forth. The comments of MWIPS allege that PSI’s petition to purchase Madison and Henry County is merely a “bailout” for Cinergy. On cross-examination, PSI admitted that the two plants have not yet been profitable. I agree with the intervenors in this matter that this is a “bailout” of Cinergy’s failed venture into competitive markets. Yet, the fact remains, that PSI needs additional resources to economically and reliably serve its Indiana customers.

To that end, I am persuaded that the favorable treatment of the Madison acquisition will contribute needed generation for PSI. As I set forth in my dissenting opinions regarding the approval of previous merchant plants, I support the building of additional generation when the need is shown. The Madison plant appears to satisfy a significant part of the need for additional generation. It provides enough power to make a difference and it is located adjacent to an already existing plant in an industrial area. Unfortunately, there was no RFP provided to prove that this was the best option. The Henry County project, which, in my opinion, was ill conceived from the outset, does not offer any of the advantages that the Madison plant does. Of the available 135 megawatts, 50 are already committed to WVPA for twenty years. The remaining 85 megawatts which will be available to serve native load is not enough to justify the purchase. The additional costs necessary to provide the inlet heater and quick start modifications only reinforce my opinion. The location of this plant and the manor in which it was built has been a source of major concern to me. Had the Henry County project been presented as a stand-alone request under 8-1-8.5 et.seq., I doubt it could have been approved without significant modifications and maybe not at all. Tying it to the Madison acquisition is the Petitioner’s attempt to make it palatable.

The legislature has set forth standards this Commission must observe when approving the expansion of public utilities. I feel that the evidence fails to support this settlement. Therefore, it is my opinion that a finding that this meets the requirements of I.C. 8-1-8.5-4 is premature at best. While I concur with many findings in this Order, I must respectfully dissent from the majority’s ultimate decision.