AMEREN CORP
FORM U-1/A (Amended Application for Public Utility Holding Company)
Filed 4/19/2005
Address 1901 CHOUTEAU AVE MC 1370 ST LOUIS, Missouri 63166-6149 Telephone 314-621-3222 CIK 0001002910 Industry Electric Utilities Sector Utilities Fiscal Year 12/31 (As filed April 19, 2005)
File No. 70-10180 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM U-1/A
AMENDMENT NO. 2 TO APPLICATION OR DECLARATION UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
AMEREN CORPORATION CENTRAL ILLINOIS PUBLIC SERVICE COMPANY UNION ELECTRIC COMPANY 607 East Adams Street 1901 Chouteau Avenue Springfield, Illinois 62739 St. Louis, Missouri 63103
(Name of company or companies filing this statement and address of principal executive offices)
AMEREN CORPORATION
(Name of top registered holding company parent of each applicant or declarant)
Steven R. Sullivan, Senior Vice President, General Counsel and Secretary Ameren Services Company 1901 Chouteau Avenue St. Louis, Missouri 63103
(Name and address of agent for service) The Commission is requested to mail signed copies of all orders, notices and communications to:
Joseph H. Raybuck, Esq. William T. Baker, Jr., Esq. Managing Associate General Counsel Thelen Reid & Priest LLP Ameren Services Company 875 Third Avenue 1901 Chouteau Avenue New York, New York 10022 St. Louis, Missouri 63103
ii The Application or Declaration filed in this proceeding on October 16, 2003, as previously amended and restated in its entirety by Amendment No. 1, filed on April 30, 2004, is hereby further amended and restated in its entirety to read as follows:
ITEM 1. DESCRIPTION OF PROPOSED TRANSACTION.
1.1. Introduction.
Ameren Corporation ("Ameren"), whose principal business address is at 1901 Chouteau Avenue, St. Louis, Missouri 63103, is a registered holding company under the Public Utility Holding Company Act of 1935, as amended (the "Act")./1/ Ameren directly owns all of the issued and outstanding common stock of Union Electric Company (d/b/a "AmerenUE"), Central Illinois Public Service Company (d/b/a "AmerenCIPS"), and Illinois Power Company (d/b/a "AmerenIP"), and indirectly through CILCORP, Inc. ("CILCORP"), an exempt holding company, all of the issued and outstanding common stock of Central Illinois Light Company (d/b/a "AmerenCILCO") and AmerenEnergy Resources Generating Company ("AERG"), an electric utility generating subsidiary of AmerenCILCO./2/ Together, AmerenUE, AmerenCIPS, AmerenIP and AmerenCILCO provide retail and wholesale electric service to approximately 2.3 million customers and retail natural gas service to approximately 935,000 customers in portions of Missouri and Illinois./3/
AmerenUE generates, transmits and distributes electricity and distributes natural gas at retail in a 24,500 square-mile area of central and eastern Missouri and west central Illinois, including the greater St. Louis area. AmerenUE provides electric service to approximately 1.2 million customers and natural gas to approximately 140,000 customers. Approximately 95% of AmerenUE's electric customers and 87% of its gas customers are located in Missouri. At December 31, 2004, AmerenUE owned 8,425 MW (net) of generating capacity. AmerenCIPS provides electric and natural gas transmission and distribution service in a 20,000 square-mile area of central and southern Illinois. AmerenCIPS provides electric service to approximately 325,000 customers and natural gas service to approximately 170,000 customers. AmerenCIPS does not own any generating capacity./4/
1 See Ameren Corporation, et al., Holding Co. Act Release No. 26809 (Dec. 30, 1997) (the "Merger Order").
2 AERG owns and operates substantially all of the generating assets previously owned by AmerenCILCO. AERG sells power at wholesale to AmerenCILCO under a full requirements contract that extends through 2006.
3 The Commission authorized the formation of Ameren and Ameren's acquisition of AmerenUE and AmerenCIPS in the Merger Order. Ameren was authorized to acquire AmerenCILCO in Ameren Corporation, et al., Holding Company Act Release No. 27645 (Jan. 29, 2003), and was authorized to acquire AmerenIP in Ameren Corporation, et al., Holding Co. Act Release No. 27896 (Sept. 27, 2004).
4 AmerenIP serves approximately 600,000 electric customers and 415,00 gas customers and AmerenCILCO serves approximately 203,000 electric customers and 208,000 gas customers, all in Illinois.
1 AmerenUE and AmerenCIPS, indirectly through Grid America LLC, are transmission-owning members of the Midwest Independent Transmission System Operator, Inc. (the "Midwest ISO") and provide open access transmission service over their combined transmission facilities pursuant to the terms of the Midwest ISO Open Access Transmission Tariff on file at the Federal Energy Regulatory Commission ("FERC"). AmerenUE and AmerenCIPS are also members of the Mid-America Interconnected Network ("MAIN"), which is one of the ten regional electric reliability councils organized for coordinating the planning and operation of the nation's bulk power supply./5/
In May 2000, AmerenCIPS transferred all of its electric generation facilities to Ameren Energy Generating Company ("Ameren GenCo"), an affiliated generation-only company. Ameren GenCo, which has been certified by the FERC pursuant to Section 32 of the Act as an "exempt wholesale generator" ("EWG"),/6/ has continued to acquire additional generation capacity since that time. Power generated by Ameren GenCo is sold to wholesale purchasers under both cost-based and market-based rates which are subject to the jurisdiction of the FERC. As of December 31, 2004, Ameren GenCo had approximately 4,751 MW (net) of total installed generating capacity. The generation facilities of AmerenUE and Ameren GenCo are dispatched in a coordinated manner in accordance with the terms of a Joint Dispatch Agreement on file at the FERC. The Joint Dispatch Agreement requires each company to serve its load requirements from its own least-cost generation first, but then allows the other company to have access to any available excess generating capacity at cost./7/
In addition to AmerenUE, AmerenCIPS, AmerenIP and CILCORP and its subsidiaries, Ameren owns directly all of the issued and outstanding common stock of, inter alia, Ameren Energy Resources Company ("AERC"), which is an intermediate non-utility holding company. AERC directly and indirectly holds the
5 AmerenIP and AmerenCILCO are also members of the Midwest ISO and MAIN. The MAIN member utilities operate in Illinois and portions of Michigan, Wisconsin, Iowa, Minnesota and Missouri. In July 2004, AmerenUE, AmerenCIPS and AmerenCILCO provided formal written notice to the MAIN Board of Directors of their intent to withdraw from MAIN effective January 1, 2006, provided that the configuration of MAIN remains the same. (AmerenIP had previously given notice of its intent to withdraw from MAIN effective December 31, 2004, but has remained a member pending its transition to ownership by Ameren.) The four Ameren utilities intend to join another regional electric reliability organization prior to their withdrawal from MAIN. Until their withdrawal is effective, they will continue to honor all of their obligations as members of MAIN. If they do not join another regional electric reliability organization, they may withdraw their notice of intent to withdraw from MAIN.
6 AmerenGenCo. filed an application for EWG status in FERC Docket No. EG00-117-000 on March 23, 2000, as amended on May 18, 2000. The EWG status of Ameren GenCo was affirmed by the FERC in Ameren Energy Generating Company, 92 FERC P. 62,023 (July 14, 2000); Ameren Energy Generating Company, 93 FERC P. 62,210 (December 18, 2000).
7 Power generated from AERG's generating units is not subject to the Joint Dispatch Agreement, but instead is dispatched separately from AmerenCILCO's control area, which is separate from, and adjacent to, the Ameren control area.
2 securities of other exempt and authorized non-utility companies, including, insofar as relevant to this Application/Declaration, Ameren GenCo, Ameren Energy Marketing Company ("AEM"), and Ameren Energy Fuels and Services Company ("AFS"), the last two of which are "energy- related" companies under Rule 58.
1.2 Summary of Requested Approvals.
Authorization is sought herein for certain transactions (the "Illinois Asset Transfer") that will result in the acquisition by AmerenCIPS of AmerenUE's electric transmission and distribution assets in Illinois other than those associated with AmerenUE's Venice, Illinois generating plant, its Keokuk, Iowa generating plant, and also minor amounts of property in Illinois to be retained by AmerenUE to ensure the smooth operation of its electric utility system in Missouri (the "Retained Assets"). The Illinois Asset Transfer will also result in the acquisition by AmerenCIPS of AmerenUE's retail gas distribution facilities in Illinois. The assets to be acquired by AmerenCIPS are identified collectively herein as the "Acquired Assets."/8/ The Acquired Assets will be transferred to AmerenCIPS at their net book value. Prior to closing, AmerenUE will obtain a release of the Acquired Assets from the lien of its first mortgage bond indenture by certifying unfunded property additions to the trustee, as required under the terms of the indenture. Approximately one-half of the Acquired Assets (designated as "Transferred Assets") will be transferred by AmerenUE directly to AmerenCIPS in consideration for AmerenCIPS' promissory note, the form of which is filed herewith as Exhibit B-3, and approximately one-half of the Acquired Assets (designated as "Dividend Assets") will be transferred to AmerenCIPS by means of a dividend in kind from AmerenUE to Ameren followed by a contribution of the Dividend Assets by Ameren to AmerenCIPS./9/ In connection with the Illinois Asset Transfer, AmerenCIPS will assume certain obligations of AmerenUE that are associated with the Acquired Assets. These transactions will be consummated in accordance with the Asset Transfer Agreement, the form of which is filed herewith as Exhibit B-1.
In addition to the foregoing, AmerenUE is requesting authorization herein to acquire from Ameren GenCo four 44 MW combustion turbine generator ("CTG") units and four 35 MW CTG units located at Ameren GenCo's Pinckneyville, Illinois facility (the "Pinckneyville Plant") and two 116 MW CTG units located at Ameren GenCo's Kinmundy, Illinois generation facility (the "Kinmundy Plant") and, in conjunction therewith, to assume certain liabilities and obligations of Ameren GenCo related to such units (the "Generation Transfer"). These assets will also be transferred at their net book value. The terms of these transactions are set forth in the form of Asset Transfer Agreement-Pinckneyville Generation Station between Ameren GenCo and AmerenUE (Exhibit B-5) and the form of Asset Transfer
8 An application to implement the Illinois Asset Transfer was previously filed with the Commission in December 2000 in Ameren Corporation, et al., File No. 70-9805. However, that application was subsequently withdrawn by letter dated August 20, 2001 before the application was acted upon by the Commission.
9 The Asset Transfer Agreement provides for AmerenUE to prepare a schedule to be delivered at the time of closing which specifically enumerates the assets, properties and rights to be acquired by AmerenCIPS. The schedule will further designate whether such specific assets are to be conveyed as Dividend Assets or Transferred Assets. The percentages of Acquired Assets that are to be conveyed as Transferred Assets and as Dividend Assets, respectively, will be determined by Ameren immediately prior to the closing.
3 Agreement-Kinmundy Generation Station between Ameren GenCo and AmerenUE (Exhibit B-6).
1.3 Reasons for Proposed Transactions.
As indicated above, AmerenUE provides service to approximately 1.2 million electric customers and 140,000 gas customers in parts of Missouri and Illinois. AmerenUE also provides wholesale full requirements service to certain municipal electric utilities in Missouri. AmerenUE's peak load in 2004 was 8,351 MW. AmerenUE currently owns approximately 8,425 MW (net) of generation capacity. Power from these generation resources, as supplemented by power purchased by AmerenUE from others, is used to supply the demands of its electric service customers. AmerenUE is subject to regulation with respect to retail sales of natural gas and electricity in Missouri by the Missouri Public Service Commission ("MoPSC") and with respect to retail sales of natural gas and electricity in Illinois by the Illinois Commerce Commission ("ICC").
As a regulated electric utility in Missouri, it is incumbent upon AmerenUE to have or to acquire sufficient generating capacity with which to serve the forecasted demands of its electric service customers and to maintain an adequate reserve margin. Standards established by MAIN require member utilities to meet certain minimum short-term and long-term planning reserve requirements.
In July 2002, AmerenUE entered into a Stipulation and Agreement in order to resolve certain retail rate issues in Missouri. The Stipulation and Agreement (Exhibit B-4 hereto) fixes retail electric service rates for AmerenUE in Missouri that, except under certain specified conditions, will remain in place without modification through June 30, 2006. AmerenUE also agreed to undertake commercially reasonable efforts to make energy infrastructure investments totaling $2.25 billion to $2.75 billion from January 1, 2002 through June 30, 2006. This includes the obligation to acquire 700 MW of new generating capacity, which may be satisfied by the purchase of generation facilities from an affiliate "at net book value." The Stipulation and Agreement also requires AmerenUE to make enhancements to its transmission infrastructure.
The Generation Transfer is intended as an efficient means of enabling AmerenUE to meet its generation capacity obligations under the Stipulation and Agreement and under the MAIN standards. AmerenUE needs a significant amount of additional generation in 2005 and 2006 in order to meet the applicable MAIN generation capacity requirements. The Generation Transfer will provide AmerenUE with a total of 548 MW of additional generating capacity, which will be acquired at the net book value of the Pinckneyville and Kinmundy Plants. Because both the Pinckneyville Plant and the Kinmundy Plant are connected directly to the Ameren transmission system with no operating guide restrictions, concerns over the availability of transmission capacity to allow delivery of power from those units reliably to AmerenUE are obviated. Additionally, the Pinckneyville Plant has black start capability and can be ramped up quickly to provide service, which will allow AmerenUE to respond quickly to system emergencies.
The regulatory regime under which AmerenUE operates in Illinois is very different from that which exists in Missouri. Although Missouri law does not authorize competition in retail electric service markets, the Illinois Electric
4 Service Customer Choice and Rate Relief Law (the "Customer Choice Law"), which was enacted in 1997, permits retail electric service customers in Illinois to purchase power from alternative power suppliers. Nevertheless, AmerenUE continues to be regulated as an electric public utility in Illinois. Therefore, as long as AmerenUE continues to provide retail electric utility service in Illinois, it will need approval of the ICC to consummate the Generation Transfer.
A Petition for Approval of Asset Transfer Agreements with AmerenGenCo was filed by AmerenUE with the ICC in February 2003. However, the ICC Staff expressed concerns about the terms of the Generation Transfer and has recommended that the ICC deny approval of the Generation Transfer as proposed. For that reason, AmerenUE has advised the ICC that it intends to limit its public utility operations to Missouri and to discontinue operating as a public utility subject to ICC regulation. In so doing, AmerenUE explained that the concerns expressed by the ICC Staff regarding the means by which AmerenUE proposes to satisfy its generating capacity needs, juxtaposed with the MoPSC views of this matter, has demonstrated the difficulty for a single company to operate as an electric utility in both a regulated generation jurisdiction such as Missouri and an unregulated generation jurisdiction such as Illinois. Accordingly, on May 30, 2003, AmerenUE filed a Notice of Withdrawal of its petition to the ICC.
The effect of the proposed Illinois Asset Transfer is to transfer to and consolidate within AmerenCIPS responsibility for serving electric and gas utility customers in Illinois that are currently served by AmerenUE. Upon the transfer of AmerenUE's retail electric and gas assets in Illinois, AmerenCIPS will succeed to AmerenUE's retail utility operations in Illinois and will provide the retail electric and gas services currently provided by AmerenUE pursuant to the ICC-approved tariffs currently in effect for AmerenUE.
The Illinois Asset Transfer will realign the retail electric and gas utility operations of Ameren so that AmerenUE will be regulated as a public utility only in Missouri. Because AmerenUE will not be a regulated utility in Illinois, it will not be required to make regulatory filings in Illinois after the Illinois Asset Transfer./10/ Most significantly, after the Illinois Asset Transfer has been consummated, it will not be necessary for AmerenUE to obtain ICC authorization in order to acquire the Pinckneyville Plant and the Kinmundy Plant from Ameren GenCo. The transfer to AmerenCIPS of retail electric service loads in Illinois that are currently served by AmerenUE will also help to reduce the amount of generation capacity that AmerenUE needs to maintain in order to comply with MAIN generation capacity standards.
1.4 Illinois Asset Transfer.
Pursuant to the Asset Transfer Agreement, AmerenUE will transfer its electric transmission and distribution and gas distribution assets and associated general plant assets and related liabilities in Illinois to
10 AmerenUE will continue to own and operate generation facilities that are located in Illinois, together with minor amounts of other facilities to ensure the smooth operation of its electric system. However, because it will no longer have a public service obligation to provide retail electric or natural gas service in Illinois, AmerenUE will not be subject to regulatory requirements established by the ICC.
5 AmerenCIPS. AmerenCIPS will not assume any indebtedness of AmerenUE in the transaction. As referenced above, AmerenUE would retain generating facilities and also minor amounts of other facilities in Illinois. AmerenUE will also assign all related obligations to AmerenCIPS, including without limitation, the certificates of public convenience and necessity granted by the ICC authorizing AmerenUE to provide electric utility service and gas utility service in Illinois, environmental permits and obligations, all municipal and county franchises, labor agreements (as applicable), and any other relevant agreements that exist as of the transfer date. After the Illinois Asset Transfer, the Acquired Assets will be utilized by AmerenCIPS in its electric and natural gas utility business in Illinois.
At the present time, AmerenUE personnel operate and maintain the Acquired Assets in conjunction with their other responsibilities. It is expected that after the Illinois Asset Transfer has been consummated, certain AmerenUE employees responsible for operation and maintenance of these facilities may be transferred to AmerenCIPS. Other employees of AmerenUE, who are responsible for substation and transmission maintenance and for protective relay installation, testing and maintenance, may also spend a portion of their time operating and maintaining the Acquired Assets for AmerenCIPS for the life of those facilities./11/ The continued use of AmerenUE personnel will enable AmerenCIPS to avoid the inconvenience and additional costs associated with hiring and training additional personnel for this purpose.
The Illinois Asset Transfer is planned to be accomplished in the following manner:
1. AmerenUE will transfer approximately 50% of the Acquired Assets to AmerenCIPS in exchange for AmerenCIPS' subordinated promissory note in a principal amount not to exceed $69 million, which is equal to approximately 50% of the total net book value ($138 million) of such Acquired Assets, net of liabilities, as of December 31, 2004./12/
2. AmerenUE will hold the note and receive payments including interest from AmerenCIPS.
3. AmerenUE will declare an "in kind" dividend to Ameren equal to the remaining balance (approximately 50%) of the net book value of the Acquired Assets net of liabilities, or approximately $69 million as of December 31, 2004.
4. Ameren will then contribute the Dividend Assets and associated liabilities to AmerenCIPS.
11 The Commission recognized in the Merger Order that AmerenUE may provide services to AmerenCIPS, including services of linemen and gas trouble crews, that are incidental to its utility business. These services will be provided at cost in accordance with the standards of the Act and the Commission's rules and regulations under the Act.
12 A list and description of the electric and gas utility assets to be transferred to AmerenCIPS and the associated liabilities are contained in Exhibit B-2 hereto.
6 The Commission determined in the Merger Order that the existing electric transmission and distribution facilities of AmerenUE and AmerenCIPS are physically interconnected and operated as a single integrated electric utility system. Likewise, the Commission held in the Merger Order that the combined gas utility properties of AmerenUE and AmerenCIPS constitute an integrated gas utility system. The Illinois Asset Transfer will not affect the coordinated operation of any electric transmission or distribution plant, which will continue to be operated in the same manner, by the same personnel, and with the same degree of safety and reliability, as they are today. Similarly, the transfer of the gas distribution assets of AmerenUE will not affect the coordinated operation of the existing gas utility properties of AmerenUE and AmerenCIPS.
1.5 Generation Transfer.
The Pinckneyville Plant and the Kinmundy Plant, which were installed by Ameren GenCo in 2001, are integrated into the Ameren system. The Pinckneyville Plant consists of four simple cycle CTGs rated at approximately 44 MW each at summer peak conditions, and four CTGs rated at approximately 35 MW each at summer peak conditions. The Kinmundy Plant consists of two CTGs with dual fuel capability which are rated at approximately 116 MW each under summer peak conditions. Since their acquisition by Ameren GenCo, these generating units have proven themselves to be superior performing generating assets that have served the Ameren system reliably.
Under the terms of the Transfer Agreements, AmerenUE will purchase the Pinckneyville Plant and the Kinmundy Plant for cash and will acquire associated assets and obligations from Ameren GenCo based on the net book value of the assets and obligations being transferred as of the closing date. The net depreciated book value of generation facilities at the Pinckneyville Plant as of December 31, 2004 was approximately $150.0 million ($475/kW). The net depreciated book value of generation facilities at the Kinmundy Plant as of December 31, 2004 was approximately $90.3 million ($389/kW). AmerenUE will also acquire certain assets (fuel stock, materials and supplies and prepaid insurance) and assume certain obligations of Ameren GenCo (primarily property tax accruals) that are associated with the generating units being transferred. The detailed accounting treatment of the Generation Transfer is set forth in Exhibit FS-10.
ITEM 2. FEES, COMMISSIONS AND EXPENSES.
The fees, commissions and expenses incurred or to be incurred by AmerenUE and AmererCIPS in connection with the Illinois Asset Transfer will not exceed $600,000 in the case of AmerenUE and $570,000 in the case of AmerenCIPS, and the fees, commissions and expenses incurred or to be incurred by AmerenUE in connection with the Generation Transfer will not exceed $1,000,000. These fees, commissions and expenses consist primarily of outside legal fees, charges billed or to be billed to AmerenUE and AmerenCIPS by Ameren Services, and a $165,600 fee to be paid to the ICC in connection with the issuance of AmerenCIPS' subordinated promissory note to AmerenUE.
7 ITEM 3. APPLICABLE STATUTORY PROVISIONS.
The following sections of the Act and the Commission's rules thereunder are or may be applicable to the transactions proposed herein:
SECTIONS OF THE ACT TRANSACTIONS TO WHICH SECTION OR RULE MAY BE APPLICABLE
6(a), 7, 9(a), 10 and 12 Issuance of a promissory note by AmerenCIPS in connection with the acquisition of the Transferred Assets and acquisition thereof by AmerenUE ------9(a)(1), 10 Acquisition of Acquired Assets by AmerenCIPS; acquisition of Pinckneyville and Kinmundy Plant assets by AmerenUE ------12(b) Assumption of obligations of AmerenUE by AmerenCIPS in connection with Illinois Asset Transfer and assumption of obligations of AmerenGenCo by AmerenUE ------12(c) In-kind distribution of Dividend Assets by AmerenUE to Ameren ------12(b) Contribution of Dividend Assets by Ameren to AmerenCIPS ------12(d), 12(f) Sale of Transferred Assets by AmerenUE to AmerenCIPS ------Rules ------43, 44 Sale of Transferred Assets by AmerenUE to AmerenCIPS ------45 Contribution of Dividend Assets by Ameren to AmerenCIPS and assumption by AmerenCIPS of liabilities of AmerenUE ------46 In-kind distribution of Dividend Assets by AmerenUE to Ameren ------
AmerenCIPS' acquisition of the Transferred Assets will be exempt from the requirements of Sections 9(a)(1) and 10 pursuant to Section 9(b) (1), as such acquisition will be expressly authorized by the ICC (see Item 4).
8 Section 32 of the Act and Rule 54 thereunder are also generally applicable to the transactions described above. To the extent that other sections of the Act or the Commission's rules thereunder are deemed to be applicable to the Illinois Asset Transfer, such sections and rules should be considered to be set forth in this Item 3.
A. Illinois Asset Transfer
Section 6(a) of the Act provides that it is unlawful for any registered holding company or subsidiary thereof "to issue or sell any security of such company" except in accordance with an order of the Commission issued pursuant to Section 7 of the Act. Correspondingly, Section 12(b) of the Act requires Commission authorization for a registered public utility holding company or subsidiary thereof "to lend or in any manner extend its credit to or indemnify any company in the same holding-company system." As a result, the issuance of a promissory note by AmerenCIPS to AmerenUE and the assumption by AmerenCIPS of certain obligations of AmerenUE relating to the Acquired Assets require prior Commission approval under Sections 6, 7, and 12(b) of the Act.
Section 9(a)(1) of the Act declares that it shall be unlawful for any registered holding company or subsidiary thereof to acquire any utility assets or any securities unless the acquisition of such assets or securities has been approved by the Commission pursuant to Section 10 of the Act. However, Section 9(b)(1) of the Act exempts from the requirements of Section 9(a) any "acquisition by a public-utility company of utility assets the acquisition of which has been expressly authorized by a State commission."
Section 12(c) of the Act declares that it shall be unlawful for any registered holding company or subsidiary thereof to declare or pay any dividend on any security except in accordance with such rules and regulations or orders as the Commission may adopt with respect to issuance of dividends. The applicable standards for declaration and payment of dividends are set forth in Rule 46.
Section 12(d) of the Act states that it is unlawful for a registered holding company to sell any utility assets in contravention of rules and regulations or orders as the Commission shall adopt. Section 12(f) of the Act requires Commission approval for a subsidiary of a registered holding company to sell utility assets to any affiliate or associate company.
As set forth below, the Illinois Asset Transfer complies with all of the applicable provisions of the Act and should be approved by the Commission.
1. Sections 6(a) and 12(b)
As indicated, the promissory note to be issued by AmerenCIPS will be in an amount equal to approximately 50% of the net book value of the Transferred Assets, not to exceed $69 million. The promissory note will have a fixed rate of interest based on interest rates charged for generally-comparable unsecured five-year notes issued by companies whose credit quality and bond ratings are
9 comparable to those of AmerenCIPS. The yield of 5-year U.S. Treasury Notes and of U.S. Treasury Notes and Bonds having 5 years remaining until maturity may be used as a benchmark to establish the interest rate for the promissory note. Based on the current yield of the 5-year U.S. Treasury Notes plus a credit spread between yields of U.S. Treasury Notes and yields on generally-comparable unsecured corporate notes derived from a variety of external sources, current interest rate levels for the promissory note would be approximately 4.5%.
Although the initial term of the promissory note will be five years, payments of amounts due under the promissory note will be based on a ten- year amortization schedule. Accordingly, a balloon payment will become due at the end of the fifth year unless the note's term is extended for an additional five years by agreement of the parties and subject to further approval by the ICC. The promissory note will be unsecured and will be subordinate to all other debt of AmerenCIPS, whether incurred currently or in the future, except indebtedness which, by its terms, provides that such indebtedness is not superior in right of payment of principal of or interest on the promissory note or that such indebtedness is subordinated to all other indebtedness of AmerenCIPS.
In addition, AmerenCIPS will assume all obligations of AmerenUE relating to its utility business of transmitting and distributing electricity and natural gas in Illinois. As shown in Exhibit B-2 hereto, these obligations include trade payables relating to such businesses, accounts payable, accrued payroll, accrued vacation liabilities, customer liabilities, environmental liabilities and taxes. AmerenCIPS will also assume all maintenance and labor agreements (as applicable) and any similar agreements relating to the Acquired Assets as those agreements exist on the transfer date. AmerenCIPS will not assume any indebtedness of AmerenUE in the transaction.
Section 6(a) requires the issuance of an order of the Commission pursuant to Section 7 of the Act before a registered holding company or subsidiary thereof may issue any security. Section 7(c)(2)(B) of the Act provides that the Commission shall not permit a declaration regarding the issue or sale of any security to become effective unless it finds, inter alia, that "such security is to be issued or sold solely...for the purpose of financing the business of the declarant as a public utility company." Section 7(d) further provides that if the requirements of Section 7(c) and Section 7(g) of the Act are satisfied:
The Commission shall permit a declaration regarding the issue or sale of a security to become effective unless the Commission finds that--
(1) the security is not reasonably adapted to the security structure of the declarant and other companies in the same holding company system; (2) the security is not reasonably adapted to the earning power of the declarant. (3) financing by the issue and sale of the particular security is not necessary or appropriate to the economical and efficient operation of a business in which the applicant lawfully is engaged or has an interest;
10 (4) the fees, commissions, or other remuneration, to whomsoever paid, directly or indirectly, in connection with the issue, sale or distribution of the security are not reasonable. (5) in the case of a security that is a guaranty of, or assumption of liability on, a security of another company, the circumstances are such as to constitute the making of such guaranty or the assumption of such liability an improper risk for the declarant. (6) the terms and conditions of the issue or sale of the security are detrimental to the public interest or the interest of investors or consumers.
In this case, the promissory note to be issued by AmerenCIPS is to be used for the purpose of financing expansion of its business as a public utility company in Illinois by acquiring the electric utility and gas utility operations of AmerenUE in Illinois. Pursuant to the Asset Transfer Agreement, AmerenCIPS will acquire not only certain transmission and distribution assets, but also AmerenUE's retail electric business in Illinois, including the certificates of public convenience and necessity granted by the ICC authorizing AmerenUE to provide retail electric service in Illinois, environmental permits, all municipal and county franchises, and any other relevant agreements. Additionally, AmerenCIPS will acquire both AmerenUE's gas assets in Illinois and all related obligations, including the certificates of public convenience and necessity granted by the ICC authorizing AmerenUE to provide gas utility service in Illinois, environmental permits, all municipal and county franchises, and any other relevant agreements. As noted above, the Illinois Asset Transfer is being financed in part by the issuance of the promissory note by AmerenCIPS. It is therefore evident that issuance of the promissory note by AmerenCIPS is consistent with Section 7(c)(2)(B) of the Act.
The issuance of the promissory note is also consistent with the criteria established in Section 7(d) of the Act. At December 31, 2004, AmerenCIPS' total capitalization ($1,008 million) consisted of approximately 43.7% common stock equity, 5.0% preferred stock equity, 44.6% long-term debt (including current maturities) and 6.7% short-term debt (including money pool borrowings). The acquisition of assets by AmerenCIPS from AmerenUE is being financed in approximately equal parts by the subordinated promissory note to be issued by AmerenCIPS and by a capital contribution by Ameren. Because long-term debt and equity of AmerenCIPS will increase in the same amounts, the capital structure of AmerenCIPS after the Illinois Asset Transfer will be substantially the same as its present capital structure. Thus, on a pro forma basis, assuming that the transaction had closed on December 31, 2004, the capitalization of AmerenCIPS will be approximately 44.4% common stock equity, 4.4% preferred stock equity, 45.3% long-term debt (including current maturities), and 5.9% short-term debt (including money pool borrowings). (See Exhibit FS-8.)
Moreover, the combination of the utility assets of AmerenUE in Illinois with the utility assets of AmerenCIPS will result in savings through elimination of duplicative regulatory burdens in Illinois, without any loss of operating economies and efficiencies.
It is believed that the fees and expenses paid or to be paid by AmerenUE and AmerenCIPS in connection with the Illinois Asset Transfer (see Item 2 - Fees, Commissions and Expenses) bear a fair relation to the book value of the
11 assets being transferred and the benefits to be achieved by AmerenUE and AmerenCIPS as a result of the Illinois Asset Transfer.
To the extent that AmerenCIPS is assuming liabilities of AmerenUE that are associated with the Acquired Assets, the assumption of such liabilities is not an improper risk for AmerenCIPS. The Acquired Assets represent a part of a going concern and are capable of generating revenues sufficient to meet the obligations being assumed by AmerenCIPS. It is therefore reasonable for AmerenCIPS to assume the risks associated with the Acquired Assets.
Finally, the terms and conditions of the promissory note as described above are not detrimental to the public interest or the interest of investors or consumers. The promissory note will carry a market rate of interest, will have a relatively short term, and will be subordinated to other debt of AmerenCIPS.
2. Sections 12(d) and 12(f)
Sections 12(d) and 12(f) of the Act contemplate that where a transaction involves sale of utility assets by one utility in a holding company system to an associate company, the Commission may evaluate the fairness of the consideration to be paid and received for such sale by both the buyer and seller. In Entergy Corporation, et al., 50 S.E.C. 305, 322 (1990), the Commission ruled that "as noted above in the discussion of section 10(b)(2), the Commission believes that section 12(d) is satisfied by the intrasystem sales of assets at depreciated book value on an after tax basis." The terms of the Illinois Asset Transfer are consistent with this policy.
The transfer of the Acquired Assets from AmerenUE to AmerenCIPS on the basis of their net book value as recorded on the books and records of AmerenUE is reasonable for several reasons. The Acquired Assets are primarily electric and natural gas facilities for which there is a limited market. After the Illinois Asset Transfer has occurred, those assets will continue to be used by AmerenCIPS to provide electric and natural gas service at regulated rates that are subject to regulation by the ICC. Electric service customers being transferred from AmerenUE to AmerenCIPS will continue to pay the rates they are currently charged under AmerenUE's tariff at least until December 31, 2006. It is expected that any cost-of-service study performed thereafter in order to evaluate the reasonableness of rates being charged for service to those customers would impute a value to the Acquired Assets based on their book cost depreciated.
3. Sections 9(a)(1) and 10
Section (9)(a)(1) of the Act requires the approval of the Commission pursuant to Section 10 of the Act before a registered holding company or subsidiary thereof may acquire utility assets or any securities. Section 10(b) provides that, if the requirements of Section 10(f) are satisfied, the Commission shall approve an acquisition under Section 9(a) unless the Commission finds that:
12 (1) such acquisition will tend towards interlocking relations or the concentration of control of public-utility companies, of a kind or to an extent detrimental to the public interest or the interests of investors or consumers;
(2) in case of the acquisition of securities or utility assets, the consideration, including all fees, commissions, and other remuneration, to whomsoever paid, to be given, directly or indirectly, in connection with such acquisition is not reasonable or does not bear a fair relation to the sums invested in or the earning capacity of the utility assets to be acquired or the utility assets underlying the securities to be acquired; or
(3) such acquisition will unduly complicate the capital structure of the holding-company system of the applicant or will be detrimental to the public interest or the interests of investors or consumers or the proper functioning of such holding-company system.
Clearly, in this case, the acquisition of the Acquired Assets by AmerenCIPS will not contribute to an undue concentration of control of public utility assets. Both AmerenCIPS and AmerenUE are subsidiaries of Ameren, which, as their corporate parent, has ultimate control over both subsidiaries and their public utility assets. Ameren's control over these assets will not be affected by the proposed Illinois Asset Transfer.
The amounts to be paid by AmerenCIPS bear a fair relation to the sums invested in and the earning capacity of the Acquired Assets. The Acquired Assets are being transferred at their net book values. At December 31, 2004, the net book value of the electric transmission and distribution assets to be acquired by AmerenCIPS net of liabilities was $109.4 million, and the net book value of the gas assets to be acquired by AmerenCIPS net of liabilities was $17.1 million. The rates for electric and natural gas service provided by AmerenUE in Illinois are cost- based rates that are predicated in part on the book value of these assets. It is thus evident that the amount to be paid by AmerenCIPS is consistent with Section 10(b)(2) of the Act. See Georgia Power Company, et al., 49 S.E.C. 309, 312 (1984).
As noted above, the acquisition of the Acquired Assets by AmerenCIPS will not unduly complicate its capital structure. Approximately one- half of the Acquired Assets will be transferred to AmerenCIPS through distribution by AmerenUE to Ameren followed by contribution of such assets to AmerenCIPS, and the remainder will be transferred to AmerenCIPS in return for a promissory note. As a result, the transaction will not have a significant effect on the capital structure of AmerenCIPS.
The acquisition of the Acquired Assets by AmerenCIPS will not have an adverse effect on the interests of consumers of either AmerenUE or AmerenCIPS. Existing and new retail electric service customers of AmerenCIPS will continue to be served in accordance with tariffs that have previously been approved by the ICC. Rates of captive retail electric service customers currently served by AmerenCIPS are not subject to change prior to January 1, 2007, when the transition to full retail customer choice in Illinois will be completed.
13 AmerenCIPS has an electricity supply agreement with AEM pursuant to which it purchases its full requirements for electricity at demand and energy charges that are fixed and not subject to modification prior to December 31, 2006. AEM has sufficient generation capacity available to be able to accommodate the additional load being transferred to AmerenCIPS. The stability provided by this contract will insulate retail electric service customers in Illinois that transfer from AmerenUE to AmerenCIPS from any meaningful risk of a rate increase during the term of that electricity supply agreement. After 2006, AmerenCIPS is expected to purchase electricity needed to serve all of its customers under competitive market conditions.
Finally, AmerenCIPS and AmerenUE have integrated their gas utility operations and rely extensively on support services provided by Ameren Services Company and AFS. Moreover, AmerenCIPS will adopt the service classifications and rates in AmerenUE's retail tariffs for natural gas service in Illinois and will assume the obligations of AmerenUE under certificates of public convenience and necessity granted by the ICC and all municipal and county franchises authorizing AmerenUE to provide gas utility service in Illinois. Therefore, insofar as the natural gas service customers of AmerenUE in Illinois are concerned, the Illinois Asset Transfer will simply result in a change in name of their service provider without having any impact on the quality or cost of service provided.
Section 10(c) of the Act provides that, notwithstanding the provisions of Section 10(b), the Commission shall not approve:
(1) an acquisition of securities or utility assets, or of any other interest, which is unlawful under the provisions of section 8 or is detrimental to the carrying out of the provisions under section 11; or
(2) the acquisition of securities or utility assets of a public utility or public utility holding company unless the Commission finds that such acquisition will serve the public interest by tending towards the economical and the efficient development of an integrated public utility system.
The Commission approved the formation of Ameren and its acquisition of AmerenUE and AmerenCIPS in 1997. As indicated above, the Commission concluded in the Merger Order that the combined electric properties of AmerenUE and AmerenCIPS constitute an integrated electric system and that "the proposed acquisition by Ameren of this electric integrated system will `ten[d] towards the economical and efficient development of an integrated public-utility system,' and so as to satisfy the requirements of section 10(c)(2) of the Act."/13/ The Commission further concluded that the gas properties of AmerenUE and AmerenCIPS "constitute a gas integrated system within the meaning of section 2(a)(29)(B) of the Act."/14/ The transfer of the Acquired Assets from AmerenUE
13 See Merger Order, 66 SEC Docket at 490, fn. 17.
14 Id. at 491. The Commission reviewed its findings as to the integration of the Ameren electric utility system and Ameren gas utility system in connection with its subsequent approvals of the acquisitions of AmerenCILCO and AmerenIP.
14 to AmerenCIPS will not affect the integrated operation of these facilities. It is thus evident that Section 10(c) of the Act does not preclude issuance of a Commission order authorizing acquisition of the Acquired Assets by AmerenCIPS.
4. Section 12(c)
The Dividend Assets are to be transferred through distribution of an in-kind dividend by AmerenUE to Ameren, and a capital contribution by Ameren to AmerenCIPS. Section 12(c) of the Act precludes the declaration or payment of a dividend by a registered holding company or subsidiary thereof:
...in contravention of such rules and regulations or orders as the Commission deems necessary or appropriate to protect the financial integrity of companies in holding-company systems, to safeguard the working capital of public-utility companies, to prevent the payment of dividends out of capital or unearned surplus, or to prevent the circumvention of the provisions of this title or the rules, regulations, or orders thereunder.
The only relevant rule adopted by the Commission relating to declaration or payment of dividends by a subsidiary company of a registered public utility holding company is Rule 46(a), which precludes payment of a dividend "out of capital or unearned surplus, except pursuant to a declaration notifying the Commission of the proposed transaction, which has become effective in accordance with the procedure specified in ss. 250.23." As of December 31, 2004, AmerenUE had retained earnings of approximately $1,688,000,000. The distribution of the Dividend Assets will result in a charge against retained earnings of AmerenUE of approximately $69 million. It is therefore evident that AmerenUE has sufficient retained earnings in which to make an in-kind dividend to Ameren for the purpose of implementing the Illinois Asset Transfer.
B. Generation Transfer
As noted above, Ameren GenCo is an EWG. Section 32(e) of the Act provides in pertinent part that an EWG "shall be exempt from all provisions of this Act." Therefore, the participation of Ameren GenCo in the Generation Transfer does not require Commission authorization. However, the acquisition of the Pinckneyville Plant and the Kinmundy Plant by AmerenUE is subject to the requirements of Sections 9(a)(1) and 10 of the Act, and the assumption by AmerenUE of certain obligations of Ameren GenCo is subject to Rule 45.
The standards established by Sections 9(a) and 10 of the Act for acquisition of utility assets by a subsidiary of a registered public utility holding company are set forth above. The Generation Transfer is consistent with these standards.
The acquisition of the Pinckneyville Plant and the Kinmundy Plant by AmerenUE will not contribute to an undue concentration of control of public utility assets. AmerenUE and Ameren GenCo are affiliated entities within the Ameren corporate family, and their respective generation facilities are already being dispatched in accordance with the Joint Dispatch Agreement. Because the transaction will involve only the intra- corporate transfer of generation
15 facilities, it will not affect concentration of control of generation assets. Although the Generation Transfer will increase the amount of generation capacity owned by AmerenUE, such capacity is needed by AmerenUE to meet its existing public service obligations in Missouri and maintain an adequate generation capacity reserve margin.
The amounts to be paid by AmerenUE bear a fair relation to the sums invested in and the earning capacity of the Pinckneyville Plant and the Kinmundy Plant. As noted above, these plants are to be acquired by AmerenUE at their net book value (i.e., original cost of construction less accumulated depreciation). Power from these units will be sold primarily to retail electric service customers in Missouri at cost-based rates which are subject to regulation by the MoPSC. The transaction will therefore be consistent with the standards for intra-corporate asset transfers cited above.
The price at which AmerenUE will acquire the Pinckneyville Plant and the Kinmundy Plant is also consistent with the price of capacity from alternative sources that were considered by AmerenUE. Prior to entering into this transaction, AmerenUE undertook an Asset Mix Optimization Analysis, which showed that the addition of a mix of simple cycle and combined cycle combustion turbines during its planning horizon would satisfy AmerenUE's needs on a least-cost planning basis. AmerenUE then evaluated a number of options for obtaining the energy and capacity needed to meet its reliability and customer service obligations, including the purchase of power from other wholesale energy suppliers, the purchase of existing generation assets from non-affiliated generation owners, and the construction of new capacity, as well as the Generation Transfer. None of these alternatives were entirely satisfactory.
In the fall of 2001, AmerenUE issued a Request for Proposals for capacity and energy with the intent of purchasing up to 500 MW of capacity for the time period of 2002 through 2011. The Net Present Value of offers of power submitted in response to this RFP, coupled with the construction of simple cycle combustion turbine generators at the end of the 10-year contracting period (2002-2011), were comparable to the cost to AmerenUE of purchasing the Pinckneyville Plant and the Kinmundy Plant from Ameren GenCo. However, the MoPSC Staff expressed a preference for AmerenUE to own generation facilities rather than to purchase power at wholesale. The possibility of purchasing generation facilities from non-affiliated entities was unsuitable because of concerns over the availability of a reliable transmission path for delivery of power to AmerenUE customers, because of concerns about transmission constraints, and because of concerns about the creditworthiness of such non-affiliated entities. Finally, the cost of purchasing the Pinckneyville Plant and the Kinmundy Plant from Ameren GenCo at net book value was comparable to or less than the estimated cost of building new combustion turbine generating units that offer similar flexibility and operating characteristics.
The acquisition of the Pinckneyville Plant and the Kinmundy Plant and associated assets by AmerenUE will not unduly complicate AmerenUE's capital structure. At December 31, 2004, AmerenUE's total capitalization ($5,435 million) consisted of approximately 53.1% common stock equity, 2.1% preferred stock equity, 37.9% long-term debt (including current maturities) and 6.9% short-term debt (including money pool borrowings). AmerenUE expects to finance the acquisition of these assets initially with borrowings under the Ameren
16 System Utility Money Pool Agreement./15/ On a pro forma basis, taking into account both the Illinois Asset Transfer and the Generation Transfer, and assuming that both transactions had closed on December 31, 2004, the capitalization of AmerenUE will be approximately 50.2% common stock equity, 2.0% preferred stock equity, 36.8% long-term debt (including current maturities), and 11.0% short-term debt (including money pool borrowings). (See Exhibit FS-7.)
The acquisition of the Pinckneyville Plant and the Kinmundy Plant by AmerenUE will not have an adverse effect on the interests of consumers of AmerenUE. As noted above, the Stipulation and Agreement protects existing retail customers of AmerenUE in Missouri from a change in rates for electric service, except in limited circumstances, prior to 2006. Because AmerenUE is transferring its current retail electric service obligations in Illinois to AmerenCIPS, it will no longer have retail customers in Illinois that might be affected by the Generation Transfer.
Finally, the acquisition of the Pinckneyville Plant and the Kinmundy Plant by AmerenUE will enhance the integration of those facilities with the existing AmerenUE generating units. As noted above, these units are connected directly to the Ameren transmission system. However, the Joint Dispatch Agreement requires AmerenUE and AmerenGenCo each to serve its load requirements from its own least-cost generation facilities first, before relying on excess generation that may be available from the other company. By acquiring these generating units, AmerenUE will be able to dispatch them in the optimal manner to serve the needs of its retail and wholesale electricity customers without consideration of the use of those units by Ameren GenCo.
The transactions proposed herein are also subject to Section 12(b) of the Act and Rule 45 thereunder. Rule 45 permits a subsidiary of a registered holding company to make extensions of credit without interest in connection with service, construction or sales contracts (including sales of materials and supplies); provided that payment is made as soon as reasonably practicable.
In this case, the extensions of credit relate to the assumption by AmerenUE of certain obligations of Ameren GenCo that are associated with the Pinckneyville Plant and the Kinmundy Plant. These obligations include accrued property taxes, state and federal deferred tax liabilities, and a small account payable. Payment of these obligations will be made by AmerenUE in the ordinary course of business without interest.
Ameren GenCo will utilize the proceeds of the sale of the Pinckneyville and Kinmundy Plants to repay money pool borrowings and a portion of maturing long-term debt, including, specifically, $225 million principal amount of unsecured notes maturing on November 1, 2005, and for other corporate purposes.
15 See Ameren Corporation, et al., Holding Co. Act Release No. 27655 (Feb. 27, 2003). Ultimately, AmerenUE expects to retire some or all of the money pool borrowings with internally generated cash flow or with the proceeds of long-term debt and/or equity, or a combination thereof.
17 C. Rule 54
The transactions proposed herein are also subject to Section 32(h)(4) of the Act and Rule 54 thereunder. Rule 54 provides that, in determining whether to approve any transaction that does not relate to an EWG or "foreign utility company" ("FUCO"), the Commission shall not consider the effect of the capitalization or earnings of any subsidiary which is an EWG or FUCO upon the registered holding company system if paragraphs (a), (b) and (c) are satisfied.
Ameren has complied or will comply with the record-keeping requirements of Rule 53(a)(2), the limitation under Rule 53(a)(3) on the use of the Ameren system's domestic public-utility company personnel to render services to EWGs and FUCOs, and the requirements of Rule 53(a)(4) concerning the submission of copies of certain filings under the Act to retail regulatory commissions. Further, none of the circumstances described in Rule 53(b) has occurred or is continuing. Rule 53(c) is inapplicable by its terms because the proposals contained herein do not involve the issue and sale of securities (including any guarantees) to finance an acquisition of an EWG or FUCO.
Rule 53(a)(1) limits a registered holding company's financing of investments in EWGs if such holding company's "aggregate investment" in EWGs and FUCOs exceed 50% of its "consolidated retained earnings." Ameren's "aggregate investment"(as defined in Rule 53(a)(1)(i)) in all EWGs is approximately $605,634,775, or 32.2% of Ameren's "consolidated retained earnings" (as defined in Rule 53(a)(1)(ii)) for the four quarters ended December 31, 2004 ($1,879,931,775). The sale of the Pinckneyville Plant and the Kinmundy Plant by Ameren GenCo to AmerenUE and the associated transactions will have the effect of reducing Ameren's "aggregate investment" in EWGs. Ameren does not hold an interest in any FUCO.
ITEM 4. REGULATORY APPROVALS.
The Illinois Asset Transfer has been approved by the ICC (see Exhibits D-4, D-6 and D-6(a) hereto), the MoPSC (see Exhibits D-8 and D-8( a) hereto) and the FERC (see Exhibit D-10 hereto). No other state commission, and no other federal commission, other than the Commission, has jurisdiction over the proposed transactions associated with the Illinois Asset Transfer.
The FERC has also approved the Generation Transfer (see Exhibit D-12 hereto). Although MoPSC approval is not required for the Generation Transfer, the MoPSC has stated in filings with the FERC that this transaction is consistent with and supported by the Stipulation and Agreement (Exhibit B-4 hereto), which was approved by the MoPSC in August 2002 (see Exhibit D-13 hereto). Because the Generation Transfer will not occur until the Illinois Asset Transfer has been completed, approval of the ICC will not be required for the Generation Transfer. No other state commission, and no other federal commission, other than the Commission, has jurisdiction over the Generation Transfer.
18 ITEM 5. PROCEDURE.
The Commission has published a notice under Rule 23 with respect to the filing of this Application or Declaration and there has been no request for hearing (Holding Co. Act Release No. 27841). It is respectfully requested that the Commission's Order be issued as soon as the rules allow, and that there should not be a 30-day waiting period between issuance of the Commission's order and the date on which the order is to become effective. Ameren, AmerenUE and AmerenCIPS hereby waive a recommended decision by a hearing officer or any other responsible officer of the Commission and consent that the Division of Investment Management may assist in the preparation of the Commission's decision and/or order, unless the Division opposes the matters proposed herein.
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS.
A. Exhibits.
A None.
B-1 Form of Illinois Asset Transfer Agreement among Union Electric Company, Central Illinois Public Service Company, and Ameren Corporation (previously filed).
B-2 Proposed Listing of Electric Assets and Liabilities and Gas Assets and Liabilities Being Transferred from AmerenUE to AmerenCIPS (previously filed).
B-3 Form of Promissory Note to be issued to AmerenUE by AmerenCIPS (previously filed).
B-4 Stipulation and Agreement between the Staff of the MoPSC and AmerenUE dated July 15, 2002 (previously filed).
B-5 Form of Asset Transfer Agreement-Pinckneyville Generating Station (previously filed).
B-6 Form of Asset Transfer Agreement-Kinmundy Generating Station (previously filed).
C None.
D-1 Notice to Illinois Commerce Commission of transfer of Electric Distribution and Transmission Assets and Retail Electric Business (previously filed).
19 D-2 Petition to Illinois Commerce Commission for authorization to transfer certificates of public convenience and necessity issued to AmerenUE to provide retail electric service in Illinois (previously filed).
D-3 Petition to Illinois Commerce Commission for authorization to transfer gas system assets and gas public utility business (previously filed).
D-4 Order of Illinois Commerce Commission relating to transfer of Electric Distribution and Transmission Assets, Retail Electric Business and Certificates of Public Convenience and Necessity, and Approval of Related Tariffs (previously filed).
D-5 [Intentionally Omitted]
D-6 Order of Illinois Commerce Commission relating to transfer of gas system assets and gas public utility business (filed herewith).
D-6(a) Order on Reopening of Illinois Commerce Commission Extending Deadline For Consummating Transactions (filed herewith).
D-7 Application to Missouri Public Service Commission for authorization to transfer assets and related contracts, dated August 25, 2003 (previously filed).
D-8 Report and Order on Rehearing of Missouri Public Service Commission (filed herewith).
D-8(a) Order of Missouri Public Service Commission Denying Application for Rehearing and Granting Motion for Clarification (filed herewith).
D-9 Application to Federal Energy Regulatory Commission pursuant to Section 203 of Federal Power Act to transfer jurisdictional assets associated with Illinois Asset Transfer (previously filed).
D-10 Order of Federal Energy Regulatory Commission authorizing the Illinois Asset Transfer (previously filed).
D-11 Application to Federal Energy Regulatory Commission pursuant to Section 203 of the Federal Power Act to transfer jurisdictional assets associated with the Generation Transfer, dated February 5, 2003 (previously filed).
D-12 Order of Federal Energy Regulatory Commission authorizing the Generation Transfer (filed herewith).
20 D-13 Report and Order of the Missouri Public Service Commission approving the Stipulation and Agreement identified in Exhibit B-4, dated July 25, 2002 (filed herewith).
E Map of combined service areas of AmerenUE and AmerenCIPS (Paper format - Form SE) (filed herewith).
F Opinion of Counsel (filed herewith).
G Proposed Form of Federal Register Notice (previously filed).
B. Financial Statements.
FS-1 Balance Sheet of Ameren and consolidated subsidiaries, as of December 31, 2004 (incorporated by reference to the Annual Report on Form 10-K of Ameren for the year ended December 31, 2004) (File No. 001-14756).
FS-2 Statement of Income of Ameren and consolidated subsidiaries for the year ended December 31, 2004 (incorporated by reference to the Annual Report on Form 10-K of Ameren for the year ended December 31, 2004) (File No. 001-14756).
FS-3 Balance Sheet of AmerenUE and consolidated subsidiaries as of December 31, 2004 (incorporated by reference to the Annual Report on Form 10-K of AmerenUE for the year ended December 31, 2004) (File No. 001-02967).
FS-4 Statement of Income of AmerenUE and consolidated subsidiaries for the year ended December 31, 2004 (incorporated by reference to the Annual Report on Form 10-K of AmerenUE for the year ended December 31, 2004) (File No. 001-02967).
FS-5 Balance Sheet of AmerenCIPS as of December 31, 2004 (incorporated by reference to the Annual Report on Form 10-K of AmerenCIPS for the year ended December 31, 2004) (File No. 001-03672).
FS-6 Statement of Income of AmerenCIPS for the year ended December 31, 2004 (incorporated by reference to the Annual Report on Form 10- K of AmerenCIPS for the year ended December 31, 2004) (File No. 001-03672).
FS-7 Pro Forma Balance Sheet of AmerenUE as of December 31, 2004 (filed herewith).
21 FS-8 Pro Forma Balance Sheet of AmerenCIPS as of December 31, 2004 (filed herewith).
FS-9 Preliminary Accounting Entries for Transfer of Electric Assets and Liabilities and Gas Assets and Liabilities from AmerenUE to AmerenCIPS estimated at December 31, 2004 (filed herewith).
FS-10 Pro Forma Balance Sheet of Ameren GenCo as of December 31, 2004 and Preliminary Accounting Entries for Transfer of Pinckneyville Plant and Kinmundy Plant estimated at December 31, 2004 (filed herewith).
FS-11 Pro Forma Balance Sheet of Ameren (stand-alone) as of December 31, 2004 (filed herewith).
FS-12 Preliminary Accounting Entries for Receipt of Dividend Assets by Ameren from AmerenUE and Contribution of Dividend Assets by Ameren to AmerenCIPS estimated at December 31, 2004 (filed herewith).
ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS.
None of the matters that are the subject of this Application or Declaration involve a "major federal action" nor do they "significantly affect the quality of the human environment" as those terms are used in section 102(2)(C) of the National Environmental Policy Act. The transactions that are the subject of this Application or Declaration will not result in changes in the operation of AmerenUE or AmerenCIPS that will have an impact on the environment. AmerenUE and AmerenCIPS are not aware of any federal agency that has prepared or is preparing an environmental impact statement with respect to the transactions that are the subject of this Application or Declaration.
SIGNATURES
Pursuant to the requirements of the Public Utility Holding Company Act of 1935, as amended, the undersigned companies have duly caused this amended Application or Declaration filed herein to be signed on their behalves by the undersigned thereunto duly authorized.
AMEREN CORPORATION CENTRAL ILLINOIS PUBLIC SERVICE COMPANY UNION ELECTRIC COMPANY
By: /s/ Steven R. Sullivan ------Name: Steven R. Sullivan Title: Senior Vice President, General Counsel and Secretary
Date: April 19, 2005
22 EXHIBIT D-6
STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, UNION : ELECTRIC COMPANY :
: 03-0657 PETITION FOR APPROVAL OF TRANSFER OF GAS SYSTEM : ASSETS AND GAS PUBLIC UTILITY BUSINESS AND FOR : APPROVAL OF ENTRY INTO VARIOUS AGREEMENTS RELATED : THERETO. :
:
ORDER
DATED: September 22, 2004 03-0657
TABLE OF CONTENTS
I. PROCEDURAL HISTORY...... 1
II. BACKGROUND; NATURE OF OPERATIONS...... 2
III. DESCRIPTION OF PROPOSED TRANSACTIONS...... 4
IV. STATUTORY AUTHORITY...... 6
V. ARTICLE VI REQUIREMENTS - CAPITALIZATION...... 8
VI. ARTICLE VII REQUIREMENTS...... 11
VII. RATES; TARIFFS; PGA; TERMS AND CONDITIONS OF SERVICE...... 19
VIII. ACCOUNTING ENTRIES; ANNUAL REPORT; OTHER ISSUES...... 20
IX. PRIMARY AREAS OF DISAGREEMENT IN EXCEPTIONS AND REPLIES...... 21
X. FINDINGS AND ORDERING PARAGRAPHS...... 24
1 STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, UNION : ELECTRIC COMPANY : : 03-0657 PETITION FOR APPROVAL OF TRANSFER OF GAS SYSTEM : ASSETS AND GAS PUBLIC UTILITY BUSINESS AND FOR : APPROVAL OF ENTRY INTO VARIOUS AGREEMENTS RELATED : THERETO. : :
ORDER -----
By the Commission:
I. PROCEDURAL HISTORY
In this proceeding, Union Electric Company d/b/a AmerenUE ("AmerenUE") and Central Illinois Public Service Company d/b/a AmerenCIPS ("AmerenCIPS") (collectively the "Companies" or "Applicants") filed the above-referenced petition with the Illinois Commerce Commission ("Commission"). Thereafter, the Companies filed an Amended Petition, a Second Amended Petition and a motion to modify the Second Amended Petition. In these filings, the Companies seek approval, pursuant to Sections 6-102, 6-103, 7-101, 7-102, 7-203, 7-204 and 9-201 of the Public Utilities Act ("Act"), 220 ILCS 5/1-101 et seq., to transfer AmerenUE's retail gas operations and related assets to AmerenCIPS, pursuant to an "Asset Transfer Agreement" attached as Schedule 1 to Ameren Exhibit 1.0. The Companies also seek various other approvals relating thereto, including the issuance of a promissory note by AmerenCIPS, as described below.
Pursuant to due notice given in accordance with the law and the rules of the Commission, prehearing conferences and an evidentiary hearing were held before a duly authorized Administrative Law Judge of the Commission in Springfield, Illinois. Appearances were entered by the Companies and Commission Staff. No other appearances were entered, and no petitions for leave to intervene were filed in this proceeding.
At the evidentiary hearing, testimony and other evidence submitted by the Companies and Staff was admitted into the evidentiary record. Admitted into evidence on behalf of the Companies were the Direct, Supplemental Direct, Additional Supplemental Direct and Rebuttal Testimony of Craig D. Nelson (Ameren Exhibits 1.0, 3.0, 4.0 and 5.0, respectively), who is the Vice President - Corporate Planning for Ameren Services Company and Vice President of AmerenCIPS. Also admitted on behalf of the Companies were the Direct and Rebuttal Testimony 03-0657 of Mr. Jon R. Carls. (Ameren Exhibits 2.0 and 6.0, respectively) Mr. Carls is the Director, Regulatory Services for Ameren Services Company. Also admitted on behalf of the Companies were Ameren Exhibits 7.0, 7.0 Revised, 8.0, 9.0 and 10.0.
For the Commission Staff, Ms. Rochelle Phipps, a Senior Financial Analyst in the Finance Department of the Financial Analysis Division, sponsored Staff Exhibit 1.0R Public and 1.0R Proprietary. Ms. Dianna Hathhorn, an Accountant in the Accounting Department of the Financial Analysis Division and a Certified Public Accountant, sponsored Staff Exhibit 2.0. Mr. Eric Lounsberry, Supervisor of the Gas Section of the Engineering Department of the Energy Division, sponsored Staff Exhibit 3.0. Mr. Peter Lazare, Senior Economic Analyst with the Commission's Financial Analysis Division, submitted testimony identified as Staff Exhibit 4.0. Mr. David Rearden, a Senior Economist for the Commission's Energy Division, sponsored Staff Exhibit 5.0.
Pursuant to a post-hearing schedule adopted at the hearing, a draft order was filed by the Companies. A proposed order was served on the parties. Briefs on exceptions ("BOEs") were filed by Applicants and by Staff. A reply brief on exceptions ("RBOE") was filed by Staff.
In their BOE, the Applicants assert, among other things, that the draft order they filed was "supported by" Staff. (Ameren BOE at 1-2) Staff disagrees with this characterization, arguing that Staff had "no objection" to the Companies' draft order. (Staff RBOE at 1-2)
II. BACKGROUND; NATURE OF OPERATIONS
AmerenUE is a combination gas and electric utility that provides natural gas and/or gas transportation service to approximately 18,200 customers in Alton, Illinois, and the immediate vicinity. By class, there are approximately 16,900 residential customers, 1,290 commercial customers, and 10 large industrial firm, interruptible and transportation customers. AmerenUE says it owns and operates approximately 294 miles of gas distribution mains used to serve its customers in Illinois. The Companies state that the major portion of gas purchased by AmerenUE for the Alton areas is transported to the area by Mississippi River Transmission Corporation. The remaining portion is transported to Alton by Illinois Gas Transmission Company through its interconnection with Natural Gas Pipeline Company of America ("NGPL").
AmerenUE has a propane air-mixing plant for supplementing its natural gas supply on days of peak requirements. AmerenUE has no on-system storage capability; it either contracts for such services from interstate pipelines with which it deals or obtains storage services from third-party suppliers. According to the Companies, AmerenUE's peak usage day in 2003 occurred on January 23, 2003, when a throughput of 26,684 MMBtu was experienced on its distribution system. (Second Amended Petition at 2-3)
2 03-0657
AmerenCIPS is also a combination gas and electric utility providing natural gas and/or gas transportation service to over 170,000 customers in 267 communities in central and southern Illinois. By class, AmerenCIPS has approximately 153,000 residential customers, 17,000 commercial customers and 309 large industrial firm, interruptible and transportation customers. The Companies state that AmerenCIPS owns and operates approximately 4,950 miles of gas transmission and distribution mains in serving its customers. They assert that the major portion of the gas purchased by AmerenCIPS is transported to the area by the following interstate pipelines: Panhandle Eastern Pipe Line Company, Texas Eastern Transmission Corporation, Trunkline Gas Company, NGPL, Texas Gas Transmission Corporation and Midwestern Gas Transmission Company. (Second Amended Petition at 3)
The Companies also state that AmerenCIPS' gas system is connected to two other Illinois gas utility systems: Northern Illinois Gas Company and Central Illinois Light Company, d/b/a AmerenCILCO. They add that AmerenCIPS owns and operates four gas storage reservoirs directly connected to its system, and either contracts for additional storage services from the interstate pipelines with which it deals, or obtains such services from third-party suppliers. AmerenCIPS also has a propane air-mixing plant for supplementing its supply. AmerenCIPS' peak demand in 2003 occurred on January 23, 2003, with a total demand of 300,960 MMBtu. (Second Amended Petition at 3)
AmerenUE and AmerenCIPS are both first tier subsidiaries of Ameren Corporation ("Ameren"), a registered holding company under the federal Public Utility Holding Company Act of 1935 ("PUHCA"). The Companies came under common control pursuant to a merger of AmerenUE and CIPSCO Incorporated, AmerenCIPS' previous parent company. The Commission approved that merger in Docket No. 95- 0551, subject to certain conditions. The Companies state that both rely extensively on support services provided by a common service company, Ameren Services Company, and also receive services from Ameren Energy Fuels and Services Company. (Second Amended Petition at 3-4)
The Companies state that they now seek to structure their gas utility operations along state lines. Under this proposal, for which authorization is sought in the instant proceeding, AmerenCIPS would acquire AmerenUE's gas utility operations and assets in Illinois while AmerenUE would remain responsible for all gas utility operations in Missouri. (Second Amended Petition at 4)
The Companies state that they had previously sought approval for substantially the same transaction from the Commission in Docket No. 00- 0648. The Companies add that due to an unexpected delay in a related proceeding before the Missouri Public Service Commission, the Companies sought and received an Order from the Commission in Docket No. 00-0648 granting the withdrawal of that petition.
The Companies also state that in Docket Nos. 00-0650 and 00-0655 (cons.), they had provided notice of their intent to transfer AmerenUE's
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Illinois electric business to AmerenCIPS and that the Commission had entered an Order in those consolidated dockets acknowledging the transfer of the electric business. (Second Amended Petition at 4-5)
III. DESCRIPTION OF PROPOSED TRANSACTIONS
In the instant proceeding, the Companies seek approval to transfer AmerenUE's retail gas operations and related assets to AmerenCIPS, pursuant to an Asset Transfer Agreement, along with various other approvals relating thereto. The Asset Transfer Agreement was attached as Schedule 1 to Ameren Exhibit 1.0.
As a result of the proposed gas asset transfer, which is the subject of this docket, and the proposed electric asset transfer, which is not, AmerenUE represents that its only remaining "Illinois assets" would be electric generating plants in Venice, Illinois, and Keokuk, Iowa, and a limited number of transmission towers and related facilities. (Ameren draft order at 3) A description of the gas assets to be transferred is included in the Asset Transfer Agreement attached to Ameren Exhibit 1.0. AmerenUE also intends to assign all related obligations to AmerenCIPS, including, without limitation, the certificates of public convenience and necessity granted by the Commission authorizing AmerenUE to provide gas utility service in Illinois, environmental permits, all municipal and county franchises, supply contracts, maintenance and labor agreements (as applicable), and any other relevant agreements that exist as of the Closing Date, and all obligations covered by AmerenUE's existing Illinois tariffs and riders. (Second Amended Petition at 5; Staff RBOE at 5-6)
In terms of the STRUCTURE of and FINANCING for the proposed transaction, including the issuance of a promissory note by AmerenCIPS for which approval is sought, the Companies propose that the following transactions will occur:
(1) AmerenUE will transfer approximately 50% of the combined electric and gas net assets to AmerenCIPS in exchange for a promissory note in an amount equal to approximately 50% of AmerenUE's total net book value, estimated to be approximately $69 million. AmerenUE will hold the promissory note and receive payments, including interest at a market rate, from AmerenCIPS.
(2) AmerenUE will also declare an "in kind" dividend to Ameren equal to the remaining balance (approximately 50%) of the net book value of the combined assets net of liabilities, estimated to be approximately $69 million; and
(3) Ameren will then transfer the dividended assets and liabilities to AmerenCIPS as a capital contribution.
(Second Amended Petition at 5-6)
The Commission takes notice that AmerenCIPS' capital structure as of December 31, 2003, per books and pro forma, may be summarized as follows:
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AMERENCIPS DECEMBER 31, 2003 CAPITAL STRUCTURE
Capital Component Amount Percentage ------Common Equity $531,699,468 52.31% Long-Term Debt $484,687,043 47.69% ------Total $1,016,386,511 100%
Source: Central Illinois Public Service Company, 2003 Form 21 ILCC Page 4
AMERENCIPS PRO FORMA CAPITAL STRUCTURE AFTER PROPOSED TRANSACTION
Capital Component Amount Percentage ------Common Equity $600,699,468 52.04% Long-Term Debt $553,687,043 47.96% ------Total $1,154,386,511 100%
Note: $69 million added to December 31, 2003 common equity and long term debt balances
The promissory note would have an initial 5-year term, with a 10-year amortization schedule. There will be a balloon payment at the end of the 5th year, unless the note term is extended for an additional five years by agreement of the parties. The note will be subordinated to all other debt of AmerenCIPS. (Second Amended Petition at 6)
Ameren witness Nelson alleged that the transfer would produce benefits for Ameren, AmerenUE, AmerenCIPS and their customers. The Companies assert that it will be more practical and efficient for the two companies to organize themselves along state lines, and would simplify the reporting processes. The Companies claim the reduction in reporting requirements and overall reduction in regulatory administration will, in time, reduce operating costs and expenses, and enhance regulatory efficiencies. The Companies also assert that the transfer will not impose any detriment to customers. They contend that AmerenCIPS remains qualified to provide gas service to Illinois customers.
Mr. Nelson also claims the transfer is consistent with the path in which each of the states currently views competitive choice. That is, he states, Illinois allows for retail choice for all electric customers, while Missouri remains the more traditional vertically integrated utility regime. He further
5 03-0657 claims that separating or consolidating utility functions along state lines will serve to limit regulatory conflicts for AmerenUE and its Illinois operations, and avoid duplicative administrative functions.
According to Mr. Nelson, it is Ameren's intention to transfer the natural gas assets and associated obligations of AmerenUE's Metro East retail operations in Illinois to AmerenCIPS. Under the Companies' overall plan, AmerenUE would cease doing business as a gas utility, as proposed in this docket, and as an electric utility, in the State of Illinois. Thus, under the Companies' plan, AmerenUE would cease doing business as a public utility in Illinois.
For the current AmerenUE service area, AmerenCIPS proposes to initially adopt the service classifications and rates in AmerenUE's tariffs. AmerenCIPS is not proposing any change in the actual rates or charges, or service at this time. AmerenCIPS requests, pursuant to Section 9- 201 of the Act, that the tariffs attached as Schedule 2 to the testimony of Mr. Carls become effective as of the transfer. The Companies also say that many of the support services currently offered by Ameren Services Company and Ameren Energy Fuels and Services Company to the Ameren Companies will continue to be offered to AmerenCIPS after the transfer. They claim that the provision of these services serves to assure that the former AmerenUE Illinois customers will continue to receive quality service.
IV. STATUTORY AUTHORITY
As noted above, in their petition as amended, the Companies request the Commission's approval under Sections 6-102, 6-103, 7-101, 7-102, 7- 203, 7-204 and 9-201 of the Illinois Public Utilities Act.
Section 6-101 of the Act places the power to issue securities under the authority of the Commission and provides for the Commission to provide identification numbers to be placed on the face of securities issued by utilities. In addition, Section 6-108 of the Act governs fees that utilities must pay for security issuances authorized by the Commission.
Section 6-102(a) provides that, in order to issue a note payable at periods of more than 12 months, a public utility must first receive an Order of the Commission authorizing such issue. The Commission must find in the Order that "...the money, property or labor to be procured or paid for by such issue is reasonably required for the purpose or purposes specified in the order." (220 ILCS 5/6-102(a))
Section 6-103 of the Act provides, in relevant part, that "in any reorganization of a public utility, . . . the amount of capitalization . . . shall be such as is authorized by the Commission, which in making its determination, shall not exceed the fair value of the property involved." (220 ILCS 5/6-103)
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Section 7-101(3), provides in part, "No . . . financial or similar contract and no contract or arrangement for the purchase, sale, lease or exchange of any property, or for the furnishing of any service, property or thing, hereafter made with any affiliated interest . . . shall be effective until it has first been filed with and consented to by the Commission . . . ." (220 ILCS 5/7-101(3)) The Commission observes that the Asset Transfer Agreement and the promissory note require approval under Section 7-101(3) of the Act.
Section 7-102(A) provides, in part, that unless approved by the Commission:
(b) No public utility may purchase, lease, or in any other manner acquire control, direct or indirect, over the franchises, licenses, permits, plants, equipment, business or other property of any other public utility.
(c) No public utility may assign, transfer, lease, mortgage, sell (by option or otherwise), or otherwise dispose of or encumber the whole or any part of its franchises, licenses, permits, plant, equipment, business, or other property, but the consent and approval of the Commission shall not be required for the sale, lease, assignment or transfer (1) by any public utility of any tangible personal property which is not necessary or useful in the performance of its duties to the public, or (2) by any railroad of any real or tangible personal property.
(d) No public utility may by any means, direct or indirect, merge or consolidate its franchises, licenses, permits, plants, equipment, business or other property with that of any other public utility.
(220 ILCS 5/7-102)
Section 7-102(C) of the Act provides, in part, that the Commission may grant a request under Section 7-102 if it finds that "the public will be convenienced thereby."
Section 7-203 of the Act provides in part:
No franchise, license, permit or right to own, operate, manage or control any public utility shall be assigned, transferred or leased nor shall any contract or agreement with reference to or affecting any such franchise, license, permit or right be valid or of any force or effect whatsoever, unless such assignment, lease, contract, or agreement shall have been approved by the Commission.
(220 ILCS 5/7-203)
At the request of the Staff, the Companies amended their Petition to seek approval under Section 7-204 of the Act. In reviewing a proposed reorganization, Section 7-204(b) requires that the Commission find the following:
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(1) the proposed reorganization will not diminish the utility's ability to provide adequate, reliable, efficient, safe and least-cost public utility service;
(2) the proposed reorganization will not result in the unjustified subsidization of non- utility activities by the utility or its customers;
(3) costs and facilities are fairly and reasonably allocated between utility and non-utility activities in such a manner that the Commission may identify those costs and facilities which are properly included by the utility for ratemaking purposes;
(4) the proposed reorganization will not significantly impair the utility's ability to raise necessary capital on reasonable terms or to maintain a reasonable capital structure;
(5) the utility will remain subject to all applicable laws, regulations, rules, decisions and policies governing the regulation of Illinois public utilities;
(6) the proposed reorganization is not likely to have a significant adverse effect on competition in those markets over which the Commission has jurisdiction; and
(7) the proposed reorganization is not likely to result in any adverse rate impacts on retail customers.
(220 ILCS 5/7-204(b))
Section 7-204(c) states as follows:
(c) The Commission shall not approve a reorganization without ruling on: (i) the allocation of any savings resulting from the proposed reorganization; and (ii) whether the companies should be allowed to recover any costs incurred in accomplishing the proposed reorganization and, if so, the amount of costs eligible for recovery and how the costs will be allocated.
V. ARTICLE VI REQUIREMENTS - CAPITALIZATION
Article VI of the Act is entitled "Capitalization" and certain provisions in Article VI are set forth above.
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As explained more fully above, part of the Companies' plan involves the issuance, by AmerenCIPS, of a promissory note in an amount equal to approximately 50% of the total book value, estimated to be approximately $69 million.
Mr. Nelson asserted that the proposed transfer will not adversely affect the capitalization of AmerenCIPS. He testified that the 50% note and 50% dividend structure of this transaction will maintain a capital structure at AmerenCIPS substantially the same as its current CAPITAL STRUCTURE. According to Mr. Nelson, AmerenCIPS will continue to maintain a reasonable capital structure and its overall capitalization will not be adversely affected. (Ameren Ex. 3.0 at 5)
Staff witness Phipps stated that the promissory note will have an initial five-year term, with a ten-year amortization schedule, and a balloon payment at the end of the fifth year, unless the note's term is extended for an additional five years by agreement of the parties. She says the promissory note will be subordinated to all other of AmerenCIPS' debt. (Staff Ex. 1.0 at 11, citing Second Amended Petition, paragraph 10)
According to Ms. Phipps, other than upon agreement of both parties, there are no specific provisions or conditions that must be satisfied in order to extend the term of the promissory note at the end of the fifth year. She says that in the instant docket, the Companies are not requesting approval to extend the term of the promissory note. (Staff Ex. 1.0 at 12)
Ms. Phipps testified that the actual interest rate will be based on interest rates charged for comparable unsecured five-year notes issued by companies whose credit quality and bond ratings are comparable to those of AmerenCIPS. She says the formula used to derive the interest rate will be based on yields on the five-year U.S. Treasury notes and bonds having five years remaining until maturity, plus a premium based on AmerenCIPS' credit quality and the terms of the promissory note.
Ms. Phipps adds that based on current market conditions, the Companies estimate the promissory note will bear an interest rate of approximately 4.75%. Given that the exact interest rate of the proposed indebtedness is currently unknown, Ms. Phipps recommends that the Commission Order indicate that approval of the indebtedness should not be construed as a determination that the promissory note's interest rate is reasonable for ratemaking purposes. (Staff Ex. 1.0 at 12-13)
Ms. Phipps also testified that AmerenCIPS' capital structure ratios would remain substantially the same following the proposed reorganization. She recommends that the Commission authorize AmerenCIPS to issue a promissory note to AmerenUE in exchange for AmerenUE's Metro East assets in an amount equaling 50% of the net book value of those assets up to a maximum of $69 million subject to the following conditions: (1) AmerenCIPS seeks Commission authority before agreeing to extend the promissory note from five to ten years; (2) within ten business days of establishing an interest rate on the note, AmerenCIPS file a special report with the Commission disclosing that interest rate and
9 03-0657 demonstrating how that interest rate was set, including supporting source documents; and (3) AmerenCIPS submit quarterly reports in connection with the promissory note, as described in 83 Illinois Administrative Code 240.
In response, Mr. Nelson testified that Ameren is willing to accept the three conditions proposed by Ms. Phipps as described immediately above. (Ameren Ex. 5.0 at 2-3)
Ms. Phipps further stated that should the Commission authorize the proposed indebtedness, SECTION 6-108 of the Act requires AmerenCIPS pay a FEE equal to 24 cents for every $100 of the principal amount of the promissory note due no later than 30 days after the Commission authorizes such indebtedness. She says AmerenCIPS requests authority to issue indebtedness in an amount not to exceed $69 million; thus, AmerenCIPS will owe fees totaling $165,600 due within 30 days of the Commission Order authorizing such indebtedness. (Staff Ex. 1.0 at 14)
In his supplemental direct testimony, Ameren witness Nelson acknowledged that Ameren is required to pay such a fee pursuant to Section 6- 108 of the Act. (Ameren Ex. 3.0 at 4)
SECTION 6-103 of the Act requires that in any reorganization, the Commission shall authorize the amount of capitalization of a public utility formed by a reorganization, which shall not exceed the FAIR VALUE of the property involved. Staff witness Phipps testified that AmerenUE's Metro East assets are being transferred to AmerenCIPS for an amount equaling their net book value; thus, in her view, the proposed reorganization satisfies the requirements of Section 6-103 of the Act. (Staff Ex. 1.0 at 10)
With regard to the requirements in Article VI as discussed above, the Commission has reviewed the evidence presented in this proceeding and hereby finds, subject to the conditions set forth herein, that AmerenCIPS should be authorized to issue a promissory note in an amount of up to $69 million. The proceeds of the issuance are to be used solely to acquire the utility assets of AmerenUE in order to consummate the proposed transaction described more fully above. Consistent with the requirements of Section 6-102(a), the Commission finds that the property to be procured by such issue is reasonably required for the purposes stated above.
The Commission also finds that approval of the proposed indebtedness shall not be construed as a determination that the interest rate on the promissory note is reasonable for ratemaking purposes. The Commission further concludes that the three conditions proposed by Ms. Phipps, as described above, are reasonable and they are hereby adopted.
The Commission also finds that Section 6-108 of the Act is applicable to the promissory note, and that AmerenCIPS will owe fees totaling $165,600, which shall be due within 30 days of the final order in this proceeding.
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With respect to the requirements of Section 6-103 of the Act, the Commission observes that the AmerenUE assets will be transferred to AmerenCIPS for an amount equaling their net book value. Furthermore, the structure of the proposed transaction, which utilizes the promissory note for 50% of the cost and dividend transactions combined with a capital contribution for the other 50%, will not substantially alter the existing capital structure of AmerenCIPS. The Commission concludes that the resulting capitalization of AmerenCIPS, after completion of the proposed transaction, will be reasonable and is hereby approved.
VI. ARTICLE VII REQUIREMENTS
Pursuant to SECTION 7-203 of the Act, no "franchise, license, permit or right to own, operate, manage or control any public utility shall be assigned, transferred or leased nor shall any contract or agreement with reference to or affecting any such franchise, license, permit or right be valid or of any force or effect whatsoever, unless such assignment, lease, contract, or agreement shall have been approved by the Commission."
Under the proposed transaction, the Companies intend to assign all of AmerenUE's obligations to AmerenCIPS at the time of the closing of the transfer agreement. Ameren witness Nelson stated that AmerenUE will assign all related obligations to AmerenCIPS, including the certificates of public convenience and necessity granted by the Commission, environmental permits and obligations, all municipal and county franchises, supply contracts, maintenance and labor agreements, and any other relevant agreements that exist as of the time of the closing of the transfer agreement. (Ameren Ex. 1.0 at 5)
Staff witness Lounsberry recommended that the Commission grant approval, pursuant to Section 7-203 of the Act, of the transfer of the assets and liabilities as requested by the Companies. In direct testimony, however, he did recommend that the Companies provide a listing of each certificate of public convenience and necessity granted by the Commission that AmerenUE intends to assign to AmerenCIPS, as well as a listing of all other relevant documents that AmerenUE intends to assign to AmerenCIPS. (Staff Ex. 3 at 4) The information requested by Mr. Lounsberry was provided as Ameren Ex. 7.0 and Ameren Ex. 7.0 Revised.
Having reviewed the record, the Commission finds that because certain franchises, licenses, permits or right to own, operate, manage or control a public utility will be assigned, transferred or leased under the proposed transaction, Section 7-203 of the Act is applicable. Given the conclusions in this Order that the proposed transfer of gas system assets should be approved, the Commission hereby approves, subject to the conditions set forth herein, the proposed transfer of the identified certificates of public convenience and necessity granted by the Commission, environmental permits and obligations, municipal and county franchises, supply contracts, maintenance and labor
11 03-0657 agreements, and other relevant agreements for purposes of Section 7-203 of the Act.
SECTION 7-204 of the Act defines "reorganizations" and sets forth requirements relating to Commission approval therefore. SECTION 7-204 (B)(1) of the Act requires a Commission finding that "the proposed reorganization will not diminish the utility's ability to provide adequate, reliable, efficient, safe and least-cost public utility service."
Ameren witness Nelson submits that AmerenCIPS has a long-standing history with the Commission as a public utility providing high quality services to its customers. He asserts that the acquisition of the AmerenUE gas assets will not detrimentally affect AmerenCIPS' service to its customers. He says that all of AmerenUE's Illinois gas properties and personnel will be transferred to AmerenCIPS, including all entitlements under existing gas supply contracts used by AmerenUE to provide service to its Illinois customers. Mr. Nelson concludes that AmerenCIPS will continue to deliver the high quality service its customers have come to expect. (Ameren Ex. 3.0 at 2)
According to Staff witness Lounsberry, the Companies do not anticipate any changes in the number of gas operations personnel nor would any changes to the capital expenditure and the operations and maintenance expense budgets occur as a result of the Commission's approval of the Companies' proposal. (Staff Ex. 3.0 at 5)
Based upon his review of the Companies' petition, testimony, responses to data requests, as well as his participation in both Companies' rate cases before the Commission, Docket Nos. 02-0798, 03-0008 and 03-0009 (Consolidated), Mr. Lounsberry believes that the Companies meet the requirements of Section 7-204(b)(1) of the Act. (Staff Ex. 3.0 at 5-6)
The Commission has reviewed the evidence of record and concludes that the proposed transfer of assets, and reorganization, will not diminish AmerenCIPS' ability to provide adequate, reliable, efficient, safe and least-cost public utility service to customers.
Under SECTION 7-204(B)(2) of the Act, the Commission must find that the proposed reorganization "will not result in the unjustified SUBSIDIZATION OF NON-UTILITY ACTIVITIES by the utility or its customers." (Emphasis added) Ameren witness Nelson testified that given the nature of the proposed transaction, there will be no subsidization of non-utility activities. He asserts that the proposed transaction is simply the transfer of regulated property and customers from one regulated utility to another regulated utility. According to Mr. Nelson, there is no impact on non-utility activities. He also claims that there are Commission-approved agreements in place to ensure proper cost allocation between utility and non-utility activities. Mr. Nelson stated that the proposed transfer would not affect these agreements to the extent their applicability is at issue. (Ameren Ex. 3.0 at 2)
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With respect to this requirement, Staff witness Ms. Hathhorn stated that Ameren has previously provided its guidelines and procedures applicable to non-utility transactions. She believes these guidelines are adequate to ensure that the proposed reorganization will not result in any unjustified subsidization. Therefore, Ms. Hathhorn recommends that the Commission find the Companies are in compliance with Section 7-204(b)(2) of the Act. (Staff Ex. 2.0 at 2)
Given the nature of proposed reorganization along with the existing guidelines and procedures applicable to non-utility transactions, the Commission finds that the proposed reorganization would not result in the unjustified subsidization of non-utility activities by AmerenCIPS or its customers.
Under SECTION 7-204(B)(3) of the Act, the Commission must find that "costs and facilities are fairly and reasonably allocated between utility and non-utility activities in such a manner that the Commission may identify those costs and facilities which are properly included by the utility for ratemaking purposes". Ameren witness Nelson asserts that for the same reasons the Commission can make the required finding with respect to Section, 7-204(b)(2) of the Act, it can make the finding required by Section 7-204(b)(3). According to Mr. Nelson, the allocation of costs and facilities between AmerenCIPS and non-utility activities is a non-issue. He says he is not aware of any reason why the transfer will impede or affect the Commission's ability to identify the appropriate costs and facilities for ratemaking purposes. (Ameren Ex. 3.0 at 3)
Staff witness Hathhorn concurs in Mr. Nelson's conclusion. She says that Ameren has approved agreements in place to ensure that the proposed reorganization will not result in any inappropriate allocations of costs. Ms. Hathhorn recommends that the Commission find that the Companies' proposal is in compliance with Section 7-204(b)(3) of the Act. (Staff Ex. 2.0 at 3)
Given the nature of proposed reorganization along with the existing guidelines and procedures related to allocating costs, the Commission concludes that after completion of the proposed reorganization, costs and facilities will be fairly and reasonably allocated between utility and non-utility activities in a manner that will allow the Commission to identify those costs and facilities which are properly included by AmerenCIPS for ratemaking purposes.
Under SECTION 7-204(B)(4) of the Act, the Commission must find that the proposed reorganization "will not significantly impair the utility's ability to raise necessary capital on reasonable terms or to maintain a reasonable capital structure." A table showing AmerenCIPS' capital structure is contained above. Ameren witness Nelson testified that the 50% note and 50% dividend structure of this proposed transaction will maintain a capital structure at AmerenCIPS substantially the same as its current capital structure. He said the capital ratios would not be materially affected as a result of the proposed transfer. Accordingly, Mr. Nelson concluded that AmerenCIPS will continue to be able to raise necessary capital on reasonable terms and will maintain a reasonable capital structure. (Ameren Ex. 3.0 at 3)
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Staff witness Phipps testified that following the proposed reorganization, there will be no change in the manner in which AmerenCIPS obtains equity and debt capital. Ms. Phipps indicated that she performed a ratio analysis that indicates AmerenCIPS' financial condition will remain strong following the proposed reorganization. Ms. Phipps compared AmerenCIPS' forecasted 2004 and 2005 financial ratios to (1) published Standard and Poor's ("S&P") Benchmark ratios and (2) average 2002 S&P Benchmark ratios for A rated electric utilities. She stated that AmerenCIPS' forecasted 2004 and 2005 financial ratios compare favorably to the published S&P Benchmark ratios and the 2002 average ratios for A rated electric utilities. Thus, Ms. Phipps concludes that the proposed reorganization will not significantly impair AmerenCIPS' access to the capital markets. (Staff Ex. 1.0 at 6-8; Staff BOE at 2))
Having reviewed the record, the Commission observes that the manner in which the proposed asset transfer and reorganization has been structured will produce capital structure ratios that are not materially different than AmerenCIPS' existing capital structure. In addition, the record indicates that AmerenCIPS would continue to raise capital in the same manner if the proposed reorganization were approved. Therefore, the Commission finds that the proposed reorganization will not impair AmerenCIPS' ability to maintain a reasonable capital structure. In the Commission's view, the analysis performed by Staff witness Phipps further demonstrates that the proposed reorganization will not significantly impair AmerenCIPS' ability to raise necessary capital on reasonable terms.
SECTION 7-204(B)(6) of the Act mandates that the Commission find that "the proposed reorganization is not likely to have a significant adverse effect on competition in those markets over which the Commission has jurisdiction."
According to Ameren witness Nelson, the proposed transfer will have no bearing on competition in those markets over which the Commission has jurisdiction. He claims there is no "market power" issue since the Companies are not and will not be able to influence the market price for gas. In regard to the proposed transfer of these gas customers to AmerenCIPS, he asserts that there is no real "marketing" as currently exists for electric customers. He also argues that to the extent there is a "market" for transportation customers, the proposed change from AmerenUE to AmerenCIPS is a non-event. Mr. Nelson contends that they will still be able to use the same pipelines and suppliers they currently use. In Mr. Nelson's view, to the extent there is any movement toward residential aggregation for purposes of gas supply, whether those customers remained at AmerenUE or AmerenCIPS is not material. (Ameren Ex. 3.0 at 3-4)
Staff witness Rearden stated that there are two relevant markets that could be affected by the proposed transfer. First, there is the competition for commodity sales to transportation customers. Second, there can be competition for building out facilities to new customers on the borders of franchise territories, also referred to as line extensions. (Staff Ex. 5.0 at 4)
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Mr. Rearden testified that because Ameren is transferring the assets from one affiliate to another, there is a change neither in the number of marketers competing to sell gas in Illinois nor in the number of firms or control of existing firms vying to sign up new customers to the gas distribution network. He stated that this transaction is in effect an intra-corporate transfer that does not change the entity in control of the assets since Ameren proposes to transfer the assets from one affiliate to another. He testified that there is no change in the corporate control of the transferred assets and that the tariffs are unchanged in these service areas. Therefore, Mr. Rearden believes Ameren cannot immediately change its line extension behavior. (Staff Ex. 5.0 at 4-5)
Mr. Rearden concluded that that the proposed reorganization meets the standard in Section 7-204(b)(6) of the Act. In his view, it is unlikely to hurt competition in those markets under the Commission's jurisdiction. (Staff Ex. 5.0 at 5)
The Commission has reviewed the testimony of Ameren witness Nelson and Staff witness Rearden. The record demonstrates that the proposed reorganization will transfer control of certain public utility assets from one Ameren company to another Ameren company. Given the nature of the transfer, the Commission concludes that the proposed reorganization is not likely to have a significant adverse effect on competition in those markets over which the Commission has jurisdiction.
Under SECTION 7-204(B)(7) of the Act, the Commission must find that "the proposed reorganization is not likely to result in any ADVERSE RATE IMPACTS on retail customers." (Emphasis added)
Staff witness Ms. Phipps testified that an adverse rate impact would occur if the proposed reorganization reduced AmerenCIPS' rate of return on common equity to a level that would entitle AmerenCIPS to request an increase in electric base rates, pursuant to Section 16-111(d) of the Act, which AmerenCIPS could not have requested absent the reorganization. She further stated that while not a part of the proposed reorganization before the Commission in this docket, Staff was also concerned as to whether circumstances had changed sufficiently since 2000 such that the transfer of AmerenUE's retail electric operations in Illinois to AmerenCIPS could also entitle AmerenCIPS to request an increase in its electric base rates. (Staff Ex. 1.0 at 8-9)
On this issue, Ameren witness Mr. Nelson said there is no expectation that AmerenCIPS will need to seek rate relief during the mandatory transition period, whether or not the transfer takes place, and that AmerenCIPS has no plans to seek rate relief during this period. Nevertheless, Mr. Nelson stated that AmerenCIPS is making a proposal that is intended to ameliorate Staff's concerns. (Ameren Ex. 4.0 at 1-2)
According to Mr. Nelson, AmerenCIPS commits that for the remainder of the Illinois statutory rate freeze, if AmerenCIPS' actual two-year average earned rate of return on common equity ("ROE"), calculated in accordance with Section 16-111(d) of the Act, falls below the two-year average yield of the applicable U.S. Treasury securities for the same period, then AmerenCIPS will
15 03-0657 adjust its ROE as though the asset transfer had not occurred. Mr. Nelson stated that AmerenCIPS would be entitled to request an increase in its base rates only if the two-year average ROE, as so adjusted, is still below the two-year average yield of the applicable U.S. Treasury securities. . (Ameren Ex. 4.0 at 2-3)
Mr. Nelson asserted that since the revenues and operating expenses related to the Metro East asset transfer will be recorded separately in the accounting records of Ameren Corporation, the actual revenues and expenses will be known. Thus, Mr. Nelson claims it will be possible to eliminate the Metro East gross margin (revenues less power cost), Metro East operating and maintenance expenses, Metro East taxes other than income, Metro East depreciation expense, and the interest expense paid on the promissory note and principal payment. He says the net total of the gross margin less the expenses adjusted for income taxes will be used to adjust the AmerenCIPS earnings applicable to common equity. (Ameren Ex. 4.0 at 3; Staff RBOE at 7) The methodology presented by Mr. Nelson is set forth in a proprietary schedule, identified as Ameren Exhibit 4.1, that was attached to Ameren Exhibit 4.0. (Ameren BOE at 5) A public version of that schedule was provided as Attachment A to Staff's RBOE. (Staff RBOE at 6-7)
Mr. Nelson also stated that the AmerenCIPS common equity will be reduced to eliminate the capital contribution received from the Metro East asset transfer and the retained earnings will be adjusted for the net adjustment to the earnings applicable to common. He says the AmerenCIPS' earnings applicable to common will be decreased and the AmerenCIPS common equity will be decreased; however, the net result is an increase in the AmerenCIPS' ROE. (Ameren Ex. 4.0 at 3)
According to the Companies, the proposed commitment provides assurances that during the remainder of the rate freeze, any determination that AmerenCIPS is entitled to request an increase in its bundled electric or gas base rates will be based on financial results that approximate the results that would have occurred had the Metro East asset transfer not occurred. (Ameren Ex. 4.0 at 4-5)
Ms. Phipps stated that under AmerenCIPS' commitment proposal described above, AmerenCIPS would be entitled to request an increase in its base rates pursuant to Section 16 111(d) only if AmerenCIPS' two-year average ROE, adjusted as though the asset transfer had not occurred, is still below the two-year average yield of the applicable U.S. Treasury securities. Accordingly, she recommends that the Commission approve that commitment and require AmerenCIPS to maintain separate accounting records for the Metro East assets until the end of the mandatory transition period. According to Ms. Phipps, the latter requirement would ensure that the alternative ROE could be calculated, if necessary. In Ms. Phipps' view, given the AmerenCIPS proposal, the proposed reorganization satisfies the requirements of Section 7-204(b)(7) of the Act as it pertains to electric base rates. (Staff Ex. 1.0 at 9-10)
16 03-0657
Staff witness Lazare also addressed Section 7-204(b)(7). He stated that because the Companies' proposed tariff changes are reasonable and there will be no material impacts on affected ratepayers, the provisions of Section 7-204(b)(7) will be satisfied by the Companies' transfer proposal. (Staff Ex. 4 at 3-4)
Having reviewed the record, the Commission finds that approval of the proposed asset transfer and reorganization shall be subject to certain conditions during the remainder of the mandatory transition period, as defined in Section 16-102 of the Act, in order to ensure that the requirements of Section 7-204(b)(7) of the Act are met. Accordingly, in the event AmerenCIPS' actual two-year average earned rate of return on common equity, calculated in accordance with Section 16-111(d) of the Act, falls below the two-year average yield of the applicable U.S. Treasury securities for the same period, AmerenCIPS shall adjust its ROE as though the asset transfer had not occurred. Only if the two-year average ROE, as so adjusted, is still below the two-year average yield of the applicable U.S. Treasury securities, will AmerenCIPS be deemed to be entitled to request an increase in its base rates pursuant to Section 16-111(d) of the Act.
As a further condition on the approvals granted herein, the Commission also finds that AmerenCIPS is required to maintain separate accounting records for the Metro East assets until the end of the mandatory transition period. With the imposition of these conditions, the Commission concludes that the proposed reorganization is not likely to result in any adverse rate impacts on retail customers.
With respect to SECTION 7-101(3) of the Act, Staff witness Phipps stated that a financial contract for the exchange of any property made with any AFFILIATED INTEREST requires Commission approval. She said the Act states further that the Commission may attach any conditions to its approval that are necessary to safeguard the public interest. Ms. Phipps believes that the AmerenCIPS' proposed debt issuance is in the public interest because it is necessary to consummate the proposed reorganization, which satisfies the requirements set forth in Articles VI and VII of the Act. (Staff Ex. 1.0 at 14-15)
The Commission observes that AmerenUE and AmerenCIPS are affiliated interests within the meaning of the Act, and the requirements of Section 7-101 of the Act are applicable. Having reviewed the record, the Commission finds that the proposed Asset Transfer Agreement and the promissory note are in the public interest and they are hereby approved and consented to, subject to the conditions imposed in this Order. As one condition of approving the proposed promissory note, the Commission finds that AmerenCIPS shall be required to seek authorization from the Commission before agreeing to extend the term of the promissory note from five years to ten years.
Furthermore, AmerenCIPS is directed to file a special report with the Commission disclosing the interest rate and demonstrating how that interest rate was set, including supporting source documents, within ten business days of the
17 03-0657 establishment of the interest rate on the promissory note. Finally, the Commission finds that approval of the proposed promissory note shall not be construed as a finding that the interest rate on the promissory note is reasonable for ratemaking purposes.
Under SECTION 7-102(C) of the Act, the Commission may approve a proposed transaction requiring approval under Section 7-102 if it finds that "the public will be convenienced thereby." The record of this proceeding indicates that neither the ratepayers of AmerenUE nor of AmerenCIPS are likely to be adversely affected in the event the proposed asset transfer and reorganization takes place. Furthermore, it appears likely that certain efficiencies will accrue should the proposed reorganization occur, some of which are expected to benefit ratepayers. Therefore, based upon the entire record of this proceeding, the Commission finds that public will be convenienced by the proposed asset transfer, reorganization and related transactions. Thus, the transactions requiring approval pursuant Section 7-102 of the Act are hereby approved, subject to the conditions imposed herein.
SECTION 7-204(C) of the Act requires that the Commission rule on: (i) the allocation of any SAVINGS resulting from the proposed reorganization; and (ii) whether the companies should be allowed to recover any COSTS incurred in accomplishing the proposed reorganization and, if so, the amount of costs eligible for recovery and how the costs will be allocated.
Ameren witness Nelson stated that the anticipated costs of the transfer are de minimus and AmerenCIPS will not seek to recover these costs in a future rate case. (Ameren Ex. 5.0 at 1)
Staff witness Hathhorn recommends that the Commission accept Ameren's proposal regarding the allocation of savings resulting from the proposed reorganization and the recovery of any costs incurred in accomplishing the proposed reorganization, and find that:
1) any savings that result from the transfer will be reflected in the cost of service in Ameren CIPS' next gas rate case; and
2) no costs incurred in accomplishing the proposed reorganization will be eligible for recovery in a future rate case.
(Staff Ex. 2.0 at 4)
According to Ms. Hathhorn, the Companies anticipate that any savings resulting from the transfer will be reflected in the cost of service in AmerenCIPS' next gas rate case. She also states that the anticipated costs of the transfer are de minimus, occurring over a one to two year period, relating to changing the name from "AmerenUE" to "AmerenCIPS" on items such as customer bills and paychecks. Ms. Hathhorn also said there is no premium associated with the transfer that will be recovered. (Staff Ex. 2.0 at 4)
18 03-0657
The Commission has reviewed the testimony of Ameren witness Nelson and Staff witness Hathhorn relating to the allocation of savings and costs resulting from the proposed reorganization. Consistent with the requirements of Section 7-204(c) of the Act, the Commission finds that in future rate proceedings, any and all savings from the proposed reorganization shall be allocated entirely to the ratepayers of AmerenCIPS. In addition, the Commission finds that AmerenCIPS will not be allowed to recover any costs incurred in accomplishing the proposed reorganization, and all such costs shall instead be allocated to AmerenCIPS and its shareholders.
VII. RATES; TARIFFS; PGA; TERMS AND CONDITIONS OF SERVICE
Proposed changes in rates and tariffs are subject to the provisions of Section 9-201 of the Act. For customers in the current AmerenUE service area, AmerenCIPS proposes to initially adopt all rates and service classifications in AmerenUE's tariffs. AmerenCIPS is not proposing any substantive change in the actual rates or charges, or terms and conditions of service, at this time.
Ameren witness Mr. Carls said the proposed tariff sheets to be applicable in the current AmerenUE service area will reflect the new rate schedule designation that corresponds to the AmerenCIPS numbering sequence, but will maintain the same tariff sheet numbering convention as is currently used by AmerenUE. Staff witness Lazare did not object to the Companies' proposal. He also observed that any future proposal for further consolidation of tariffs would be subject to Commission approval at that time.
AmerenCIPS also proposes to maintain a separate AmerenCIPS Metro East purchased gas adjustment ("PGA") rate area for the former AmerenUE Illinois PGA rate area.
Staff witness Hathhorn is in agreement with the Companies' proposal to maintain a separate AmerenCIPS Metro East PGA rate area for the former AmerenUE PGA rate area. Ms. Hathhorn proposes that the costs and revenues flowing through the AmerenUE/Metro East PGA during the year of the transfer be treated as a single PGA reconciliation submitted by AmerenCIPS. According to Ms. Hathhorn, AmerenCIPS indicated that a 12-month reconciliation for the Metro East PGA rate area will be included as part of AmerenCIPS' PGA reconciliation in the year of the transfer.
In addition, she says that AmerenCIPS agreed to provide supplemental schedules supporting the annual PGA reconciliation for each rate area. Ms. Hathhorn stated that the schedules for the Metro East PGA rate area will show 12 months of revenues and costs flowed through the PGA, reflecting the period when the rate area was part of AmerenUE, prior to the transfer, as well as the period when revenues and costs flowed through the AmerenCIPS Metro East PGA rate area, after the transfer. (Staff Ex. 2.0 at 6-7)
19 03-0657
Ms. Hathhorn also recommended the Commission order AmerenCIPS to provide the supplemental cost and sales summary schedules described in her testimony as part of its annual PGA reconciliation as long as AmerenCIPS maintains the two separate rate areas. (Staff Ex. 2.0 at 7) Ameren witness Carls indicated that Ameren would maintain the records as proposed by Ms. Hathhorn. (Ameren Ex. 6.0 at 2)
Having reviewed the record, the Commission finds that AmerenCIPS shall file tariffs that adopt all rates, service classifications and other substantive terms and conditions of service currently contained in AmerenUE's tariffs for the Metro East service area. Any further changes beyond those proposed in this proceeding will require Commission approval.
The Commission also directs AmerenCIPS to establish a separate AmerenCIPS Metro East PGA rate area for the former AmerenUE PGA rate area. The Commission finds that the costs and revenues flowing through the AmerenUE/Metro East PGA during the year of the transfer shall be treated as a single PGA reconciliation submitted by AmerenCIPS. In addition, the Commission directs AmerenCIPS to provide the supplemental cost and sales summary schedules described by Staff witness Hathhorn as part of its annual PGA reconciliation as long as AmerenCIPS maintains the two separate rate areas.
VIII. ACCOUNTING ENTRIES; ANNUAL REPORT; OTHER ISSUES
Schedule 2 attached to Ameren witness' Nelson's testimony presented the Companies' proposed ACCOUNTING ENTRIES associated with the proposed transaction. Mr. Nelson testifies that PricewaterhouseCoopers, LLP has reviewed the proposed accounting entries and concluded they are in accord with generally accepted accounting practices. (Ameren Ex. 1.0 at 4-5 and Schedules 2 and 4)
According to Staff witness Hathhorn, she discovered a difference, other than the book value amounts, between the journal entries in Mr. Nelson's Schedule 2 and those offered by the Companies in the electric proceeding, Docket Nos. 00 -0650 and 00-0655 (Consolidated). Specifically, she says that the deferred tax gain calculation was inadvertently omitted from the calculation of the 2000 journal entries. (Staff Ex. 2.0 at 5) Ms. Hathhorn found no reason to object to this correction from the previous proceeding, and she recommended that the Commission accept the proposed journal entries. (Staff BOE at 3)
Ms. Hathhorn also recommends that the Commission order the Companies to file with the Commission, within 60 days after the date of the acquisition, the final accounting entries for the transaction, both on AmerenUE's and AmerenCIPS' books, showing the actual dollar values of all involved accounts. Additionally, Ms. Hathhorn says the Companies should provide a copy of this filing to the Manager of the Commission's Accounting Department at the time it is filed with the Commission. (Staff Ex. 2.0 at 5-6) Ameren witness Carls indicated that Ameren would provide the journal entries within the time frame proposed by Ms. Hathhorn. (Ameren Ex. 6.0 at 2)
20 03-0657
Having reviewed the record, the Commission finds the Companies' proposed journal entries to be reasonable, and those journal entries are approved. Within 60 days after completion of the proposed transaction, the Companies are directed to file, with the Commission, the final accounting entries for the transaction for both AmerenUE and AmerenCIPS, showing the actual dollar values of all involved accounts. At the time this filing is made, a copy thereof shall be provided by the Companies to the Manager of the Accounting Department of the Commission's Financial Analysis Division.
Ms. Hathhorn also stated that AmerenCIPS should provide supplements to pages 8, 8a, 9, 9a, 10, 10a, 11, and 11a of the Form 21 ILCC reflecting 12 months of information, stated separately, for the AmerenCIPS PGA and Metro East PGA rate areas. Finally, Ms. Hathhorn testified that AmerenUE is required to file a final Form 21 ILCC annual report in the year of the transfer. (Staff Ex. 2.0 at 7-8) Ameren witness Carls stated that the Companies would provide the information described by Ms. Hathhorn. (Ameren Ex. 6.0 at 2)
Upon reviewing the evidence, the Commission finds these proposals to be reasonable. AmerenUE is directed to file an ILCC Form 21 annual report for the year in which the transfer is completed. Additionally, AmerenCIPS is directed to provide supplements to pages 8, 8a, 9, 9a, 10, 10a, 11, and 11a of the Form 21 ILCC reflecting 12 months of information, stated separately, for the AmerenCIPS PGA and Metro East PGA rate areas as long as AmerenCIPS maintains the two separate rate areas.
Ameren witness Nelson stated that AmerenCIPS' contribution to the PUBLIC UTILITY FUND as provided for under 220 ILCS 5/2-203, and the ENERGY EFFICIENCY TRUST FUND as provided for under 20 ILCS 687/6-6, is measured by the kilowatt-hours delivered to retail customers in the 12 months preceding the year of contribution. According to Mr. Nelson, AmerenCIPS is committed to ensure the same funding levels for these two programs in that year as if the transfer had not taken place. He stated that thereafter, the funding levels for the programs will be based on AmerenCIPS' kilowatt-hours delivered as otherwise prescribed by the statutes. (Ameren Ex. 3.0 at 5)
As a condition of approving the proposed transfer and reorganization, the Commission finds that AmerenCIPS is required to ensure the same funding levels for the Public Utility Fund and the Energy Efficiency Trust Fund, in the year of the transfer, as if the transfer had not taken place. Thereafter, the funding levels for these programs will be based on AmerenCIPS' kilowatt-hours delivered or as otherwise prescribed by the statute or the Commission.
IX. PRIMARY AREAS OF DISAGREEMENT IN EXCEPTIONS AND REPLIES
Most of the arguments in the BOEs and RBOEs involved the two issues discussed below. In each instance, the Applicants propose certain changes, and Staff opposes them.
21 03-0657
Subject to certain conditions, the First Ordering Paragraph of the Proposed Order stated, in part, that "authorization is hereby granted for (1) the transfer of AmerenUE's retail gas operations and related assets in Illinois to AmerenCIPS pursuant to the terms of an Asset Transfer Agreement attached as Schedule 1 to Ameren Exhibit 1.0." Similar language is contained in Finding No. (3).
In its BOE, Applicants propose that the words "an Asset Transfer Agreement" be changed to "form of a Asset Transfer Agreement." Applicants ask that a similar change be made in Finding No. (3), and in the first sentence of Section III of the proposed order. (Ameren BOE at 2-4) In its RBOE, Staff objects to these proposed modifications. (Staff RBOE at 3-6)
Applicants argue that the Asset Transfer Agreement attached to Ameren Exhibit 1.0 is a "form", and "is not a complete document that could be the final agreement for this transfer." (Ameren BOE at 2-3) Applicants assert, for example, that there are schedules, addenda and exhibits that will be prepared near the time of closing and will be used to effectuate the intention of the parties pursuant to the Asset Transfer Agreement. (Id.) The Companies also assert that their intent to seek approval of the "form of" the Agreement was noted in Paragraph 9 of their petition.
According to the Applicants, neither the Applicants nor the Staff have advocated that the Commission authorize only the approval of the Asset Transfer Agreement as it currently exists, but rather requested approval of the "form" of the agreement which includes all of the material terms and conditions as agreed by the parties and which will be approved by the Commission in this proceeding. (Ameren BOE at 3)
The Commission Staff opposes the changes proposed by the Companies. Staff asserts that the Second Amended Petition requests Commission "approval of the Asset Transfer Agreement" itself, not the "form of" such an agreement. (Staff RBOE at 3, citing Second Amended Petition at 1) Staff also contends that Section 7-203 of the Act "clearly contemplates Commission approval of the agreement itself and not of some facsimile." (Staff RBOE at 4)
Staff notes that Ameren has not yet received final approval of the same transaction from the Missouri Public Service Commission ("PSC") in case number EO-2004-0108. ICC Staff says it is "unwilling to carte blanche approve a `form of' the Asset Transfer Agreement, which could later be changed." (Staff RBOE at 5) For example, Staff states, a number of conditions and/or requirements ultimately imposed in the Missouri case could change the terms of the Asset Transfer Agreement without ever having been before the Illinois Commerce Commission.
Finally, Staff believes the intent of the Act is to approve and set conditions for the actual transaction, not the "form of" the transaction. In Staff's view, it is illogical for the Commission to approve and potentially set conditions to a "form of" a transaction when the potential exists that the "form of" language could provide for later substantial changes to the previously approved transaction. Staff believes the Commission should have the opportunity
22 03-0657 to review any changes to the Asset Transfer Agreement in order to determine whether Illinois ratepayers or the Commission's own requirements and/or conditions are impacted by subsequent changes to the transaction. (Staff RBOE at 5)
Having reviewed the arguments of the parties, the Commission agrees with Staff that the transaction before the Commission is the Asset Transfer Agreement itself, not the "form of" such an agreement. The prayer for relief on page 13 of the Second Amended Petition requests approval of the "Asset Transfer Agreement." Similarly, the first paragraph of the Second Amended Petition states that the Companies are requesting "approval of the Asset Transfer Agreement."
Furthermore, as observed by Staff, authorization to enter into the "form of" such an agreement is simply too open-ended, arguably leaving room for post-approval changes in the substantive terms and provisions of the agreement without an opportunity for review by the Commission or Commission Staff. Such a result would be an inappropriate delegation to the utilities of the Commission's responsibilities under the Act.
To the extent the Companies are concerned that there are documents they will need to prepare prior to and in connection with the closing, the Commission finds that Applicants are authorized by this Order to engage in such transactions as are necessary to effectuate the closing on the Asset Transfer Agreement, provided that such transactions are fully consistent with the substantive terms and provisions of the approved Asset Transfer Agreement.
With regard to the other BOE issue discussed in this section of the Order, Applicants take exception to language in Finding No. (7) of the Proposed Order that the approvals and authorizations contained therein are granted on the condition that the transactions in question are consummated not later than December 31, 2004. According to Applicants, there is no statutory deadline in the related proceeding before the Missouri PSC. While Applicants expect a favorable ruling from the Missouri PSC in the near term, Applicants say they cannot be assured that all regulatory approvals will be in place by year's end. (Ameren BOE at 5) Applicants claim the December 31, 2004 date is not supported by the record; however, they do not propose any alternative date.
In their reply brief on exceptions, the Commission Staff argues that Ameren's exception should be rejected. Staff supports the December 31, 2004, deadline for the proposed transaction. Without a deadline, Staff argues, the transaction could occur at any time in the future, once Ameren receives a decision from the Missouri PSC where the transaction as proposed could be rejected, reorganized, or approved under different terms in Missouri sometime after 2004. If the Commission's Order in the instant proceeding has no deadline, Staff argues, it is conceivable that a transfer different from the one approved will result. (Staff RBOE at 8-9)
23 03-0657
Further, Staff asserts, the history of this transaction indicates that a deadline is essential. According to Staff, Ameren originally filed its gas asset transfer case in 2000, in Docket No. 00-0648, and that proceeding terminated without a final Commission Order after Ameren sought to withdraw its request as a result of serious concerns regarding the proposed transfer at the Missouri PSC. In the current proceeding before the Missouri PSC, Staff says there is no indication yet whether the Missouri PSC will impose certain conditions, and if so, whether Ameren will accept them.
The Commission has reviewed the positions of the parties on this issue. In the Commission's opinion, some deadline for completing the transaction should be contained in the order. Under Applicants' position, an approved transaction could remain unconsummated for years, and may never be completed. It is difficult to see what useful purposes or appropriate regulatory policies are served when agreements approved by this Commission are not consummated within a reasonable period of time, if at all. As noted by Staff, an earlier application for authorization to transfer the AmerenUE gas system in Illinois to AmerenCIPS in Docket 00-0648 was withdrawn due to complications in a related proceeding that was pending before the Missouri PSC at that time.
Given the concerns expressed by Applicants, however, the Commission finds that the deadline for consummating the transaction should be extended from December 31, 2004 to a date six months from the date of this Order. Given Applicants' representations that a favorable ruling from the MPSC is expected in the near term, the six-month period should provide sufficient time to complete the transaction.
X. FINDINGS AND ORDERING PARAGRAPHS
The Commission, having considered the entire record herein, is of the opinion and finds that:
(1) the Commission has jurisdiction over the Applicants and the subject matter hereof;
(2) the facts recited and conclusions reached in the prefatory portion of this Order are supported by the record and are hereby adopted as findings of fact and law;
(3) subject to the conditions set forth herein, authorization should be granted for the transfer of AmerenUE's retail gas operations and related assets in Illinois to AmerenCIPS pursuant to the terms of an Asset Transfer Agreement attached as Schedule 1 to Ameren Exhibit 1.0; for the issuance by AmerenCIPS of a promissory note to Ameren UE, in an amount not to exceed $69 million, as described above; and for such other related transactions as are expressly found appropriate for approval above;
24 03-0657
(4) in accordance with Section 6-101 of the Act, AmerenCIPS shall, before issuance of the promissory note described herein, cause the following identification number to be placed on the face of such securities: Ill. C.C. No. 6277;
(5) AmerenCIPS is required to pay a fee of $165,600.00 in accordance with Section 6-108 of the Act; this fee shall be paid no later than 30 days after service of this Commission order;
(6) AmerenCIPS shall comply with the reporting requirements of 83 Ill. Adm. Code 240;
(7) the approvals and authorizations granted in this order are granted on the condition that the transactions in question are consummated not later than six months from the date of this Order;
(8) the tariffs to be filed in implementation of the transactions authorized herein shall be filed within 30 days after all necessary regulatory approvals relating to the subject transfer have been received, and these tariffs shall bear an effective date at least five days after the date of filing.
(9) AmerenCIPS shall comply with all other determinations and conditions set out in this Order.
IT IS THEREFORE ORDERED that subject to the conditions set forth herein, authorization is hereby granted for (1) the transfer of AmerenUE's retail gas operations and related assets in Illinois to AmerenCIPS pursuant to the terms of an Asset Transfer Agreement attached as Schedule 1 to Ameren Exhibit 1.0; (2) the issuance by AmerenCIPS of a promissory note to AmerenUE, in an amount not to exceed $69 million, in the form provided in Schedule 3 to Ameren Exhibit 1.0; and (3) such other related transactions as are found appropriate for approval above.
IT IS FURTHER ORDERED that the authorizations and approvals granted in this Order are subject to the condition that AmerenCIPS complies with Findings (4) through (9) above and with all other conditions and determinations set forth in this Order, wherever they may appear.
IT IS FURTHER ORDERED that that subject to the provisions of Section 10-113 of the Public Utilities Act and 83 Ill. Adm. Code 200.880, this Order is final; it is not subject to the Administrative Review Law.
By order of the Commission this 22nd day of September, 2004.
(SIGNED) EDWARD C. HURLEY
Chairman EXHIBIT D-6(a)
STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, UNION : ELECTRIC COMPANY :
: PETITION FOR APPROVAL OF TRANSFER OF GAS SYSTEM : 03-0657 ASSETS AND GAS PUBLIC UTILITY BUSINESS AND FOR : APPROVAL OF ENTRY INTO VARIOUS AGREEMENTS RELATED : THERETO. : :
ORDER ON REOPENING ------
By the Commission:
On September 22, 2004, the Illinois Commerce Commission ("Commission") entered an Order in the above-referenced matter. Among other things, the Order granted authorization for the transfer by Union Electric Company, d/b/a AmerenUE ("AmerenUE" or "Applicant") of its retail gas operations and related assets in Illinois to Central Illinois Public Service Company, d/b/a AmerenCIPS ("AmerenCIPS" or "Applicant") pursuant to the terms of an Asset Transfer Agreement, and for the issuance by AmerenCIPS of a promissory note to AmerenUE in an amount not to exceed $69 million, subject to certain conditions.
One such condition was that the approvals and authorizations in the order were granted on the condition that the subject transactions are consummated not later than six months from the date of the Order. Thus, the Order established a deadline of March 22, 2005.
No petitions for rehearing were filed in this matter.
On February 28, 2005 a "Motion to Extend Transfer Deadline" was filed by Applicants. On March 4, 2005, they filed an "Amended Motion to Extend Transfer Deadline" ("Amended Motion").
In their Amended Motion, Applicants specifically request that the Commission reopen the proceeding and enter an order, pursuant to Section 200.900 of the Commission's Rules of Practice, 83 Ill. Adm. Code 200.900, "extending the deadline for the transfer of the AmerenUE-Illinois retail gas operations and related assets [from March 22, 2005 to] June 1, 2005."
In support of their request, Applicants state that the additional time is needed because the "parallel proceeding" before the Missouri Public Service Commission, EO -2004 -0108, was extended by virtue of a rehearing resulting in 03-0657 Order on Reopening entry by the MPSC of an Order on Rehearing on February 10, 2005. Applicants also state that approval is still required from the Securities and Exchange Commission.
On March 11, 2005, the Commission Staff provided notice that it does not oppose the relief sought by Applicants in their Amended Motion, and will not be filing a formal response to the Amended Motion.
Having reviewed the Amended Motion, the Commission finds that pursuant to 83 Ill. Adm. 200.900, the proceeding should be reopened and that the relief requested by Applicants is reasonable and should be granted in this Order on Reopening.
The Commission, having considered the entire record herein, is of the opinion and finds that:
(1) the Commission has jurisdiction over the Applicants and the subject matter hereof;
(2) the facts recited and conclusions reached in the prefatory portion of this Order are supported by the record and are hereby adopted as findings of fact and law;
(3) the deadline for consummating the transactions that were authorized in the Order of September 22, 2004 should be extended from March 22, 2005 to June 1, 2005;
(4) except as expressly modified herein, the terms and conditions of the Commission's Order entered in this proceeding on September 22, 2004 are hereby affirmed and remain in effect.
IT IS THEREFORE ORDERED by the Commission that the instant proceeding is hereby reopened, on the Commission's own motion, pursuant to Section 200.900 of the Commission's Rules of Practice, 83 Ill. Adm. Code 200.900.
IT IS FURTHER ORDERED that the deadline for consummating the transactions that were authorized in the Commission's Order of September 22, 2004 is hereby extended from March 22, 2005 to June 1, 2005.
IT IS FURTHER ORDERED that except as expressly modified herein, the terms and conditions of the Commission's Order entered in this proceeding on September 22, 2004 are hereby affirmed and they remain in effect
IT IS FURTHER ORDERED that the proceeding on reopening is deemed concluded.
2 03-0657 Order on Reopening
IT IS FURTHER ORDERED that subject to the provisions of Section 10-113 of the Public Utilities Act and 83 Ill. Adm. Code 200.880, this Order is final; it is not subject to the Administrative Review Law.
By order of the Commission this 23rd day of March, 2005.
(SIGNED) EDWARD C. HURLEY
Chairman
3 EXHIBIT D-8
BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MISSOURI
[GRAPHIC OMITTED]
In the Matter of the Application of Union Electric )
Company, Doing Business as AmerenUE, for an ) Order Authorizing the Sale, Transfer and Assign- ) ment of Certain Assets, Real Estate, Leased ) CASE NO. EO-2004-0108 ------Property, Easements and Contractual Agreements ) to Central Illinois Public Service Company, Doing ) Business as AmerenCIPS, and, in Connection ) Therewith, Certain Other Related Transactions. )
REPORT AND ORDER ON REHEARING
ISSUE DATE: FEBRUARY 10, 2005
EFFECTIVE DATE: FEBRUARY 20, 2005 BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of the Application of Union Electric ) Company, Doing Business as AmerenUE, for an ) Order Authorizing the Sale, Transfer and ) Assignment of Certain Assets, Real Estate, Leased ) CASE NO. EO-2004-0108 ------Property, Easements and Contractual Agreements ) to Central Illinois Public Service Company, Doing ) Business as AmerenCIPS, and, in Connection ) Therewith, Certain Other Related Transactions. )
TABLE OF CONTENTS
Appearances...... 2 Procedural History...... 3 Issues ...... 11 Findings of Fact...... 13 Conclusions of Law ...... 42 Ordered Paragraphs ...... 67
APPEARANCES
JOSEPH H. RAYBUCK, THOMAS M. BYRNE, EDWARD C. FITZHENRY, and DAVID B. HENNEN, Attorneys at Law, Ameren Corporation, 1901 Chouteau Avenue, St. Louis, Missouri 63101, for Union Electric Company, doing business as AmerenUE, and
JAMES B. LOWERY, Attorney at Law, Smith, Lewis, 111 South Ninth Street, Suite 200, Columbia, Missouri 65205, for Union Electric Company, doing business as AmerenUE.
JAMES M. FISCHER, Attorney at Law, Fischer & Dority, 101 Madison Street, Suite 400, Jefferson City, Missouri 65101, for Intervenor Kansas City Power & Light Company.
2 ROBERT C. JOHNSON, Attorney at Law, 911 Washington Avenue, St. Louis, Missouri 63101, for Intervenors the Missouri Energy Group.
DIANA VUYLSTEKE, Attorney at Law, Bryan Cave, LLP, 211 N. Broadway, Suite 3600, St. Louis, Missouri 63102, for Intervenors the Missouri Industrial Energy Consumers.
JOHN B. COFFMAN, Public Counsel, and DOUGLAS E. MICHEEL, Senior Public Counsel, Post Office Box 2230, Jefferson City, Missouri 65102, for the Office of the Public Counsel and the public.
STEVEN DOTTHEIM, Chief Deputy General Counsel, DENNIS L. FREY, Senior Counsel, and LERA L. SHEMWELL, Senior Counsel, Missouri Public Service Commission, Post Office Box 360, Jefferson City, Missouri 65102, for the Staff of the Missouri Public Service Commission.
REGULATORY LAW JUDGE: LEWIS R. MILLS, JR.
REPORT AND ORDER
PROCEDURAL HISTORY
On August 25, 2003, Union Electric Company, doing business as AmerenUE (UE), filed its Application for Transfer of Assets, Change in Decommissioning Trust Fund, Waiver of Affiliate Transaction Rules, and Motion for Expedited Treatment seeking authority to transfer certain assets and to complete certain other related transactions. UE originally requested that the Commission approve its application "in the first quarter of 2004."
UE seeks leave to transfer to AmerenCIPS, an affiliated regulated utility, all of its Illinois electric utility service area assets, including certificates of convenience and necessity, permits, licenses, and franchises issued by the state of Illinois and various Illinois counties and municipalities, its retail electric business, customers, transmission and distribution plant, and maintenance and labor agreements, as well as related liabilities. Certain electric service assets, including generating assets located in Venice,
3 Illinois, and Keokuk, Iowa, however, will not be transferred. UE also seeks leave to transfer to AmerenCIPS its gas utility service assets located in the Metro East Service Area, including certificates, franchises, permits, and licenses, general plant, customers, agreements, and related liabilities. UE states that none of these assets are located in the state of Missouri and that, consequently, there will be no impact on the tax revenues of any Missouri political subdivision. UE states that the proposed transaction is in the public interest because it will allow it to reallocate to Missouri its generation capacity presently devoted to its Illinois electric service area, thus providing additional generating capacity to serve its Missouri customers.
In connection with the above transfers, UE prays that the Commission will either find that its affiliate transaction rules do not apply to these transactions or else waive them. UE also prays that the Commission will authorize certain changes to its Nuclear Decommissioning Trust Fund to reflect the proposed transactions. UE states that it has also applied for all other necessary regulatory approvals and that it will close the transactions as soon as the necessary approvals have all been granted.
On August 27, the Commission issued its Order and Notice, establishing a deadline for applications to intervene of September 17. The Missouri Energy Group (MEG)/1/ filed its Application to Intervene on September 15, Kansas City Power & Light Company (KCPL)/2/ filed its Application to Intervene on September
/1/ The Missouri Energy Group is an unincorporated association consisting of Barnes-Jewish Hospital, Emerson Electric Company, Holcim, Inc., Lone Star Industries, Inc., River Cement Company, SSM HealthCare, and St. John's Mercy Health Care. Each of these companies purchases substantial amounts of energy from AmerenUE. /2/ Kansas City Power & Light Company is itself a regulated Missouri utility.
4 16, and the Missouri Industrial Energy Consumers (MIEC)/3/ filed its Application to Intervene on September 17. All of the applications were timely and unopposed. The Commission granted intervention as requested on October 6.
The parties were unable to agree on a procedural schedule and the Commission, on December 2, adopted the somewhat longer, but still expedited, schedule proposed by Staff and supported by Public Counsel, MEG, and MIEC.
Pursuant to notice as required by statute, an evidentiary hearing was convened at the Commission's offices in Jefferson City, Missouri, on March 25, 2004, and continued on March 26, March 31, April 1, April 2, and April 7, concluding on April 8. During these seven days of hearing, the Commission heard the testimony of 17 witnesses and received 81 exhibits. Much of the testimony, and many of the exhibits, was Highly Confidential and extensive proceedings were had in camera.
The parties filed post-hearing briefs and also filed proposed findings of fact and conclusions of law. The case was submitted on June 9, 2004.
MOTION FOR A PRELIMINARY ORDER:
On October 4, 2004, pursuant to Commission Rule 4 CSR 240-2.150(4), UE moved for the issuance of a preliminary Report and Order and an opportunity to respond. Public Counsel, on October 4, and Staff, on October 5, opposed the request. The Commission is of the opinion that the parties have already provided
/3/ The Missouri Industrial Energy Consumers is an unincorporated association consisting of Alcoa Foil Products, Anheuser-Busch Companies, Inc., The Boeing Company, Ford Motor Company, General Motors Corporation, Hussmann Refrigeration, ISP Minerals, Monsanto Company, Pfizer, Precoat Metals, Procter & Gamble Manufacturing, Nestle Purina, and Solutia. Each of these companies is a large customer of AmerenUE.
5 ample guidance in this matter and that the public interest would not be served thereby. Consequently, the Commission will deny UE's motion.
FIRST REPORT AND ORDER
Two days later, on October 6, 2004, the Commission issued its Report and Order, which was to become effective on October 16, 2004 (the "First Report and Order"). The First Report and Order approved the transfer, subject to several conditions found by the Commission to be necessary in order that the transfer would not be detrimental to the public interest. Each of those conditions was directed to a particular potential detriment the Commission found could occur as a result of the transfer. By imposing conditions that addressed those detriments, the Commission adjudged that the transfer, with those conditions, was not detrimental to the public interest and should be approved. AmerenUE timely filed its Application for Rehearing and Alternative Motion for Clarification on October 15, 2004. Public Counsel also timely filed its Application for Rehearing on that day. AmerenUE, Staff, Public Counsel, and MIEC subsequently filed pleadings respecting the Applications for Rehearing. On December 30, 2004, the Commission granted both Applications for Rehearing, set aside the First Report and Order, and re- assigned this case to the undersigned Regulatory Law Judge as required by Section 536.083, RSMo. Additional pleadings have also been filed since that time.
THE APPLICATIONS FOR REHEARING
AmerenUE's Application for Rehearing claimed a number of errors in the First Report and Order, some of which are discussed here. AmerenUE first alleged that the Commission exceeded its authority by, as AmerenUE asserted, effectively requiring AmerenUE to hold harmless ratepayers from potential detriments from the transfer that AmerenUE alleged had not been sufficiently established in the
6 record. AmerenUE alleged that this unlawfully shifted the burden of production with respect to the alleged detriments to AmerenUE and away from the proponents of the detriments. AmerenUE's basis for this allegation was that the law required those who allege that potential detriments exist to go forward with sufficient evidence to establish that the detriments are presently existing and likely to occur. Related to AmerenUE's first allegation of error was its claim that the Commission misinterpreted or misapplied AG Processing, Inc. v. Pub. Serv. Comm'n./4/ AmerenUE claimed that none of the issues relating to the detriments alleged to exist by Staff and Public Counsel were "necessary or essential" within the meaning of the AG Processing decision and therefore the Commission should not have denied the transfer, or imposed conditions on its approval, based upon those detriments. AmerenUE argued that the Commission further misapplied AG Processing by assuming, for purposes of the cost-benefit analysis performed by the Commission, that the alleged detriments would occur at the worst possible level supported by the record but that the benefits of the transfer would be at the minimal levels supported by the record. Another central allegation of error by AmerenUE was that the Commission had no authority to impose conditions in the absence of a utility's consent. AmerenUE also alleged several other errors. AmerenUE also sought clarification of several matters in the First Report and Order regardless of whether or not the Commission ultimately granted rehearing.
AmerenUE also argued that two of the conditions included in the First Report and Order were not only unlawful, but would prevent it from completing the transfer, namely, conditions relating to certain liabilities that might
/4/ 120 S.W.3d 732 (Mo. banc 2003).
7 later appear based upon events or occurrences that took place prior to closing of the transfer and relating to the transfer of energy from AmerenUE to its affiliates at incremental cost rather than at a market price. AmerenUE advised the Commission in its Application for Rehearing that it would be willing to consent to all of the conditions imposed by the Commission in the First Report and Order, except those two. AmerenUE also provided the Commission with modified conditions addressing the liabilities and energy transfer issues.
Public Counsel's Application for Rehearing also alleged errors on the part of the Commission. While AmerenUE alleged that the Commission had overstated the detriments and understated the benefits, Public Counsel alleged the opposite was true. Public Counsel alleged that no generation-related savings existed and that the Commission's finding that a small level of generation-related saving existed was in error. Public Counsel also alleged that the Commission had failed to properly consider a negative tax impact relating to sulfur dioxide (SO2) emission allowances, failed to recognize that AmerenUE is entitled to all output from the Electric Energy, Inc. plant in Joppa, Illinois, and assigned other errors.
OTHER PROCEEDINGS OCCURRING AFTER THE APPLICATIONS FOR REHEARING WERE FILED
In addition to the pleadings filed by AmerenUE, Staff, and MIEC, as referenced above, after granting rehearing the undersigned Regulatory Law Judge, by delegation of authority pursuant to Section 386.240, RSMo 2000, issued other orders. First, on December 30, 2004, an Order Directing Filing was issued requiring AmerenUE to provide certain additional analyses reflecting scenarios that would take into account the possible later addition of the load of Noranda Aluminum, Inc., which is the subject of a separate docket pending at the Commission, Case No. EA-2005-0180. AmerenUE has since filed the requested
8 analyses as required by the December 30, 2004 Order and Staff and Public Counsel filed responses thereto on February 7, 2005, as also ordered by the Commission. An Order Scheduling an On-the-Record Session was also issued on January 12, 2005. An on-the-record session was held on January 19, 2005.
After the on-the-record session, as requested by a Commissioner, AmerenUE filed a Motion to Issue Report and Order After Rehearing which included a proposed Report and Order on Rehearing.
THIS REPORT AND ORDER ON REHEARING
Section 386.500.1, RSMo 2000, governs the Commission's proceedings on rehearing. If the Commission determines that its First Report and Order to be in any part unjust, unwarranted, or in need of change, then the Commission may abrogate, change or modify the order or decision. Section 386.500.4, RSMo. In its December 30, 2004 Order Granting Rehearing and Re-Assigning Case, the Commission vacated the First Report and Order. This Report and Order on Remand replaces the Report and Order issued on October 6, 2004. Much of this order is the same as the earlier one; the salient changes are to two of the conditions imposed on the transfer and to the attendant discussion of those conditions; this order also addresses points raised by Public Counsel in its application for rehearing. The Commission also finds that the Order Directing Filing dated December 30, 2004, and the analyses requested thereby are not necessary to its decision on rehearing because the existing record is adequate to support this modified order.
Specifically, this Report and Order on Remand is based upon the original record in this case, and is not based upon the filings of the parties made in response to the December 30, 2004 Order Directing Filing or on filings of the
9 parties made in response to any of those filings, and provides for each and every condition the Commission found necessary to render the transfer not detrimental to the public interest in the First Report and Order, except two of those conditions. Those two conditions were required in order to protect Missouri ratepayers against specific potential detriments and were found in Ordering Paragraphs 4 and 6 of the First Report and Order. The Commission has imposed alternative conditions directed toward each of those two, specific potential detriments that appropriately protect the public interest. The Commission specifically finds, based upon the existing record in this case and without consideration of the filings made by AmerenUE or other parties in response to the Order Directing Filing dated December 30, 2004, or in response to those filings, that those modified conditions, together with the other original conditions, adequately and fairly protect Missouri ratepayers and cause the transfer to not be detrimental to the public interest.
ADOPTION OF THE EXISTING RECORD
The Commission hereby adopts, for the purposes of rehearing, the existing record in this case. The Commission finds that with the original conditions retained in this order, together with the two additional conditions which address the potential detriments identified in the First Report and Order, additional evidentiary hearings are not necessary. Additional evidentiary hearings are not necessary because the conditions imposed by this Report and Order on Rehearing and the existing record adequately address the potential detriments appearing of record. The Commission finds that the arguments of Staff, Public Counsel, and others to the effect that an additional evidentiary record is necessary in order to develop the mechanics of how AmerenUE would meet its burden to prove that benefits attributable to the transfer exceed the potential detriment relating to the liabilities and incremental cost pricing of
10 energy transfers to affiliates as discussed in more detail later in this order, are not well taken. A further record in this case is not necessary as it remains AmerenUE's legal burden to prove, by a preponderance of the evidence as provided for herein, that those benefits exist and exceed the potential detriments. If AmerenUE fails to convince the Commission by evidence, however presented, then AmerenUE (and, effectively, AmerenUE's shareholders), will bear the consequences associated with the two detriments at issue - the subject liabilities or incremental cost pricing under the Joint Dispatch Agreement ("JDA"), as discussed below - as the case may be. Staff, Public Counsel, and any other proper parties in future AmerenUE rate cases will have a full and fair opportunity to challenge AmerenUE's effort to meet its burden as to those two conditions, and the Commission will have the opportunity to rule, consistent with law and the record, on whether AmerenUE has or has not met that burden.
ISSUES
Because contested cases before the Commission often do not include issue-framing pleadings, the Commission generally directs the parties in cases pending before it to jointly develop and file a list of issues for determination by the Commission. Shortly before the hearing, the parties must each file a statement of position on each issue. In this way, the contested issues are framed for decision.
In the present case, the parties were unable to develop a joint list of issues and the principal litigants - UE, Staff and the Public Counsel - each submitted a list. Due to the delay occasioned by the parties' inability to agree, the issues lists and the position statements were submitted together. To reproduce the entirety of any of those documents here would needlessly consume many pages of text. Furthermore, some of the issues and position statements are
11 designated Highly Confidential and cannot be set out here. Therefore, the Commission will briefly summarize the parties' principal contentions. Further details, so far as necessary to understand the Commission's Order, will be set out in the Findings of Fact and Conclusions of Law that follow.
The transaction proposed by UE has been summarized above, on pages 3 and 4 of this Report and Order. UE asserted that, if the proposed transaction were approved, certain benefits would be realized, including the addition of nearly 600 megawatts (MWs) of low-cost, coal-fired, base-load generation to serve UE's Missouri customers. Other benefits include reducing UE to a one-state utility operation, subject at the state level only to this Commission, and no longer subject to the competing requirements of the Illinois Commerce Commission (I.C.C.). If the transaction were not approved, on the other hand, UE warned that it might not have sufficient generating capacity to meet its needs, perhaps as early as the summer of 2004. Finally, UE argued that the governing legal standard requires the Commission to approve the proposed transaction unless it is found that approval will cause a certain, immediate and calculable detriment to the public interest.
The Commission's Staff and the Public Counsel opposed the proposed transaction, contending that it would indeed cause substantial detriments to the public interest and that the benefits asserted by UE are illusory. In particular, Staff and the Public Counsel argued that the generation assets the transfer would make available are neither the best nor the least expensive alternative for providing additional capacity for the future. In addition, they asserted that the transfer would unreasonably expose Missouri ratepayers to the risk of future, "hidden" costs of significant magnitude. Their position is that
12 the governing legal standard does not permit the Commission to approve a transaction of this sort if doing so will expose ratepayers to an unreasonable risk of higher rates in the future.
FINDINGS OF FACT
The Missouri Public Service Commission, having considered all of the competent and substantial evidence upon the whole record, makes the following findings of fact. The Commission has considered the positions and arguments of all of the parties in making this decision. Failure to specifically address a piece of evidence, position, or argument of any party does not indicate that the Commission has failed to consider it, but indicates rather that the omitted material was not dispositive.
In making its Findings of Fact and Conclusions of Law, the Commission is mindful that it is required, after a hearing, to "make a report in writing in respect thereto, which shall state the conclusion of the commission, together with its decision, order or requirement in the premises."/5/ Because Section 386.420 does not explain what constitutes adequate findings of fact, Missouri courts have turned to Section 536.090, which applies to "every decision and order in a contested case," to fill in the gaps of Section 386.420./6/ Section 536.090 provides, in pertinent part:
Every decision and order in a contested case shall be in writing, and . . . the decision . . . shall include or be accompanied by findings of fact and conclusions of law. The findings of fact shall be stated separately from the conclusions of law and shall include a concise statement of the findings on which the agency bases its order.
/5/ Section 386.420.2, RSMo 2000. All further statutory references, unless otherwise specified, are to the Revised Statutes of Missouri (RSMo), revision of 2000. /6/ State ex rel. Laclede Gas Co. v. PSC of Mo., 103 S.W.3d 813, 816 (Mo. App., W.D. 2003); State ex rel. Noranda Aluminum, Inc. v. PSC, 24 S.W.3d 243, 245 (Mo. App., W.D. 2000).
13 Missouri courts have not adopted a bright-line standard for determining the adequacy of findings of fact./7/ Nonetheless, the following formulation is often cited:
The most reasonable and practical standard is to require that the findings of fact be sufficiently definite and certain or specific under the circumstances of the particular case to enable the court to review the decision intelligently and ascertain if the facts afford a reasonable basis for the order without resorting to the evidence./8/
Findings of fact are inadequate when they "leave the reviewing court to speculate as to what part of the evidence the [Commission] believed and found to be true and what part it rejected."/9/ Findings of fact are also inadequate that "provide no insight into how controlling issues were resolved" or that are "completely conclusory."/10/
With these points in mind, the Commission renders the following Findings of Fact.
THE PARTIES:
UE, the Applicant, is a traditional, vertically-integrated electric and gas utility that presently provides retail electric and gas services to the public in both Missouri and Illinois. As a "vertically-integrated" electric utility, UE is engaged in the generation, transmission and retail distribution of electricity. UE's Missouri operations are regulated by this Commission and its Illinois operations are regulated by the I.C.C. Various federal agencies, including the Federal Energy Regulatory Commission (FERC) and the Nuclear
/7/ Glasnapp v. State Banking Bd., 545 S.W.2d 382, 387 (Mo. App. 1976). /8/ Id. (quoting 2 Am.Jur.2d Administrative Law ss. 455, at 268). /9/ State ex rel. Int'l. Telecharge, Inc. v. Mo. Pub. Serv. Comm'n, 806 S.W.2d 680, 684 (Mo. App., W.D. 1991) (quoting State ex rel. Am. Tel. & Tel. Co. v. Pub. Serv. Comm'n, 701 S.W.2d 745, 754 (Mo. App., W.D. 1985)). /10/ State ex rel. Monsanto Co. v. Pub. Serv. Comm'n, 716 S.W.2d 791, 795 (Mo. banc 1986) (relying on State ex rel. Rice v. Pub. Serv. Comm'n, 359 Mo. 109, 220 S.W.2d 61 (1949)).
14 Regulatory Agency (NRA) also regulate aspects of UE's operations. UE serves 1.167 million retail electric customers in Missouri and 62,000 in Illinois, and 112,000 retail gas customers in Missouri and 18,000 in Illinois. UE's Illinois retail electric operations constitute about 6 percent of its total retail electric operations; its Illinois natural gas customers are about 16 percent of its total gas customers. UE's Missouri electric rates are frozen until June 30, 2006, as a result of Case No. EC-2002-1. UE's Missouri natural gas rates are frozen until June 30, 2006, as a result of Case No. GR-2003-0517.
UE is owned by a publicly-traded, registered holding company, Ameren Corporation (Ameren), that is not a regulated utility. Ameren owns other companies in addition to UE, some of which are also regulated utilities, such as AmerenCIPS (CIPS) and AmerenCILCO, operating in Illinois, and some of which are not. Ameren owns Ameren Energy Resources Company that, in turn, owns Ameren Energy Marketing Company (AEM), an unregulated company engaged in the sale of electricity at wholesale, and Ameren Energy Generating Company (AEG or Genco), an unregulated company engaged in the generation of electricity for sale at wholesale. Genco's generating assets, located in Illinois, formerly belonged to CIPS.
Of the intervenors, two - MEG and MIEC - are associations of industrial customers of UE. Their members are listed in Footnotes 1 and 3, above, respectively. They intervened in this matter to protect their interest, which is the continued availability of a safe and adequate supply of electricity at just and reasonable rates. The other intervenor KCPL, is also a traditional regulated utility providing electricity at retail in Missouri.
The Staff of the Commission traditionally appears as a party in Commission proceedings and is represented by the Commission's General Counsel, an employee
15 of the Commission authorized by statute to "represent and appear for the Commission in all actions and proceedings involving this or any other law [involving the Commission.]"/11/
The Public Counsel is appointed by the Director of the Missouri Department of Economic Development and is authorized to "represent and protect the interests of the public in any proceeding before or appeal from the public service commission[.]"/12/
THE PROPOSED TRANSACTION:
UE seeks leave to transfer its Illinois retail electric and natural gas operations, including customers and the T&D (transmission and distribution) facilities serving them, to its regulated affiliate CIPS at $138 million net book value. UE's Illinois gas and electric service areas are located just east of St. Louis in an area referred to as "Metro East." The proposed transfer includes UE's certificates, permits, licenses, and franchises, its transmission and distribution plant, its retail electric and natural gas businesses, including its customers, and various associated maintenance and labor agreements and related liabilities. Some of UE's electric service assets in Illinois, however, including generating plants located in Venice, Illinois, and Keokuk, Iowa, are excluded from the proposed transfer. The transfer, if approved and effected, is irreversible for all practical purposes.
The transfer of UE's Metro East electric service area to CIPS would reduce UE's load requirement by 510 MWs of firm load. By this reduction, 597 MWs of additional capacity would become available for UE's Missouri customers./13/ Because it is not possible to specify that any particular generating plant is
/11/ Section 386.071. /12/ Sections 386.700 and 386.710. /13/ Calculated using a certain reserve figure that is Highly Confidential.
16 serving the Metro East load, that load is considered to use about 6-percent of the output of each of UE's plants, wherever located. Most of UE's generation assets are relatively low-cost, coal-fired, base-load plants, although there are also nuclear, hydroelectric, and natural gas-fired combustion turbine generation (CTGs) assets in UE's fleet, for a total capacity of 8,437 MWs. The proposed transfer, if approved, would make an additional 6-percent slice of the output of each of these plants available to UE's Missouri customers. This 6-percent slice has a book value of $223 million.
With the availability of an additional 6-percent slice of UE's generation output, an equivalent 6-percent slice of the associated operating costs, administrative costs, and contingent liabilities would necessarily become the responsibility of UE's Missouri ratepayers. The transfer would not affect the capital structure of either UE or CIPS, nor would it affect UE's return on equity or the tax revenues of any political subdivision. The transfer would make UE a Missouri-only utility, no longer subject to the I.C.C.
The compensation for the transfer is structured in this way: CIPS will give UE a promissory note for approximately $69 million in exchange for half of the Metro East assets. CIPS will make payments, including interest at a market rate, to UE to retire the note. UE will transfer the remaining half of the Metro East assets to its parent, Ameren, as an "in-kind" dividend. UE will then transfer the assets to CIPS as a capital contribution. Ameren has structured the transaction in this way so that CIPS' and UE's capital structures and UE's return on equity will not be significantly affected.
The transfer proposed here has been before this Commission before, in differing configurations, and has been approved. It has not occurred because it has never been approved simultaneously by all three regulating bodies: this Commission, the I.C.C. and the FERC. The record shows that Staff generally
17 favors the transfer, but is opposed to the present configuration. The I.C.C. has approved the electric part of the present proposal and is expected to approve the natural gas part soon. FERC has also approved the transfer.
CIPS:
CIPS is a regulated electric and gas utility that provides services at retail to the public in Illinois. CIPS has approximately 320,000 electric customers and 170,000 gas customers. Because Illinois has deregulated utilities, CIPS is a "pipes and wires" company that owns no generation assets of its own and must purchase electricity to serve its ratepayers. That electricity is provided by AEM, an unregulated UE subsidiary, under a Power Supply Agreement that will expire on December 31, 2006. The electricity sold by AEM to CIPS is produced by Genco, which owns the generating assets that formerly belonged to CIPS and sells electricity, through AEM, both to CIPS and on the wholesale market. Genco owns fossil fuel plants with a total capacity of 3,231 MWs and CTGs with a total capacity of 926 MWs.
UE, CIPS, and Genco are operated as a "single control area" under a Joint Dispatch Agreement (JDA) approved by both this Commission and the I.C.C. Under the JDA, capacity - available energy - is dispatched to serve load without regard to whose capacity or whose load is involved. However, inter-company transfers of energy are tracked and billed at incremental cost. "Incremental cost" is a costing methodology that measures only the additional costs incurred to produce the specified increment of service; necessarily, incremental cost excludes all fixed costs. There are no transmission charges applied to such energy transfers under the JDA. Excess capacity is sold off-system at whatever
18 price the market will bear. Under the JDA, profits from such sales are shared on the basis of proportionate native load rather than on the basis of proportionate generation. Under this arrangement, AEG receives a larger share of the off-system sales profits than it would if the profits were shared on the basis of generation. The proposed transfer, by transferring load from UE to CIPS, would also result in an increase in AEG's share of the profits from off-system sales.
GENERATION-RELATED ISSUES:
The proposed transfer would make 597 MWs of additional, existing generating capacity available to serve the present and future needs of UE's Missouri load. UE estimates that the capacity increase provided by the proposed transfer would permit it to avoid new construction that would cost ratepayers about $7.7 million annually. Ratepayers would realize additional savings because the cost per megawatt-hour (MWh) of the output of UE's existing plants is significantly lower than the cost per MWh of either purchased power or power produced by gas-fired CTGs.
1. UE'S NEED FOR ADDITIONAL CAPACITY:
Public Counsel's expert economic witness Ryan Kind testified that UE does not even need additional capacity at the present. However, Staff's expert economist, Dr. Michael Proctor, disagreed with Kind and testified that his calculations were "incorrect" and "overstate the capacity surplus of AmerenUE." The specific figures and calculations produced by the expert witnesses were designated Highly Confidential and cannot be set out here. Nonetheless, a review of the figures produced by Kind shows that they contradict his testimony. Kind calculated a deficit of several hundred MWs per year for each year from 2004 through 2007 if the proposed transfer were not approved, even assuming that AEG
19 transfers to UE some 550 MWs of CTGs at Kinmundy and Pinckneyville.14 Proctor testified that UE will need additional capacity by 2006 even if the Metro East transfer is approved. His analysis shows the greatest deficit figures of all, three or more times the level calculated by Kind. All three expert witnesses agree, and the Commission finds, that UE is presently in need of several hundred MWs of additional capacity./15/
A finding that UE needs additional capacity is not the same as a finding that it needs the amount of capacity that the Metro East transfer would provide. Economist Kind testified that UE does not need all of the 597 MWs of additional capacity right now. Dr. Proctor also testified that UE could phase new CTGs in over a three-year period, a position that is at odds with his calculation of UE's capacity needs at UE's chosen reserve margin figure. The Commission will return to this point later in conjunction with its discussion of the JDA.
2. UE'S RESERVE MARGIN:
The amount of capacity UE needs turns on the size of its capacity reserve margin. The record shows that the Ameren system has enough capacity now to meet its load and maintain a reserve. However, as its load grows, more capacity will be necessary. UE operates with a certain percentage of capacity in excess of that actually needed to meet its load - the specific percentage is Highly Confidential./16/ This reserve margin is necessary because a particular generating plant and its output might unexpectedly become unavailable at any
/14/ The schedule in question, No. 2 to Kind's Rebuttal Testimony, is marked Highly Confidential and so the specific figures are not set out here. /15/ The third expert witness referred to was Richard Voytas, Jr. /16/ More technically, "reserve margin" is the amount of unused and available generation when the system is at peak load, expressed as a percentage of total capacity.
20 time; thus, a reserve is essential to avoid service interruptions or a forced purchase of power at unfavorable prices. The number of MWs that UE needs necessarily varies with the reserve level selected. Economist Kind testified that UE's chosen reserve percentage is too high and that the cost of the alternative considered by UE, that of building CTGs, would be lower if UE's reserve margin were smaller./17/ However, the record shows that UE's selected reserve margin figure is within the range recommended by the Mid-America Interconnected Network (MAIN). The Commission is of the opinion that it is not sound public policy to urge an electric utility to reduce an otherwise reasonable reserve margin for reasons of economy. The Commission finds UE's reserve margin figure to be reasonable and accepts that it is the appropriate figure to use in resource planning to meet UE's present and future capacity needs. The Commission also notes Dr. Proctor's testimony that Kind's focus on UE's capacity need and reserve margin ignores the energy cost savings that the transfer would bestow on UE's Missouri customers.
3. THE LEAST COST ALTERNATIVE ANALYSIS:
UE calculated that the proposed transfer is the "least-cost alternative" by which to provide the necessary additional capacity. UE compared the proposed transfer to a single alternative scenario, in which it would instead immediately build sufficient new CTGs to provide an equivalent amount of additional capacity - these are the source of the avoided construction costs cited by UE as a benefit of the transfer. Public Counsel and Staff criticized UE's least cost analysis for several reasons, one being that it improperly inflated the cost of
/17/ Because less MWs would be needed and fewer CTGs would have to be built.
21 the CTG option by assuming that all of these units would be built immediately. The Commission will return to this point below in its discussion of the JDA.
UE's least-cost analysis showed that, with respect to providing additional generation capacity, the proposed transfer would save $2.4 million to $2.5 million annually over the alternative of constructing CTGs. UE's analyst, Richard Voytas, testified that the Metro East transfer's cost is estimated at $418.4 million present value ($43.1 million annually on a levelized annual cost basis) compared to an estimated $429.4 million present value ($45.5 million annually on a levelized annual cost basis) for adding 597 MWs of CTGs./18/ Voytas calculated the cost difference between the two options using a test year analysis, which he then projected out over 25 years. Consequently, his analysis did not reflect how the test year values might actually vary over the course of 25 years. For example, one element included in Voytas' calculation was revenue derived from the sale of SO2 emission allowances. The record shows conclusively that the level of revenue Voytas used for the test year could not actually be sustained over 25 years because insufficient allowances are available. For this reason, Staff's witness Proctor suggested that the Commission should delay the transfer and require UE to redo its 25-year analysis as a true multi-year analysis.
Voytas used the 12 months ending December 31, 2002, as his test year. However, he used 2001 figures for revenue from the sale of SO2 emission allowances rather than the 2002 figures because he considered the former to be a more typical year. The 2001 figures were almost twice those of 2002. Kind
/18/ The estimated cost of the CTG option used here, $429.4 million present value, includes the $12.3 million adjustment for likely revenues from off-system sales discussed below.
22 testified for the Public Counsel that using the 2002 SO2 allowance sales figures would result in a higher revenue requirement for the Metro East transfer option and would reduce its purported benefits by more than half, to an annual figure of only $1.7 million.
In its Application for Rehearing, Public Counsel also urged the Commission to make a further adjustment to the least cost analysis results relating to what Public Counsel claims is a negative tax impact relating to the annual SO2 adjustment. Public Counsel's contention in this regard is incorrect. The least cost analysis performed by the Company assumes that the Company will receive $7 million more per year in revenues from SO2 allowance sales. As noted above, the Commission disagrees and has made the adjustment to disregard the $7 million. If, however, the Company was to receive an additional $7 million in SO2 revenues, those SO2 revenues would reduce the revenue requirement by a like amount - $7 million - resulting in a net effect on net income of zero. The Commission therefore finds that there is no tax impact as Public Counsel alleges.
Voytas admitted that he overstated the cost of the CTG option by some $800,000 by use of a 2-percent annual escalation factor for operations and maintenance (O&M) costs in that option that was not applied in the transfer option. Public Counsel asserted that Voytas also overstated the cost of the CTG option by pricing CTGs at $471 per kilowatt (kW) where a more reasonable price would be $450/kW. In fact, Kind testified that making only two adjustments to the analysis, namely, (1) the use of the 2002 SO2 allowance sales revenue figures rather than 2001 figures and (2) pricing CTGs at $450/kW rather than $471/kW, shows that the CTG option actually would cost about $100,000 less than the Metro East transfer option.
23 First, the Commission generally agrees with UE that Voytas' projection of his test year analysis over 25 years was reasonable given the necessarily highly speculative nature of predictions of how the test year values might change over that period. As UE explained, this position does not ignore the change of values over time but rather assumes that pressures in either direction will cancel out. With respect to the SO2 allowance revenue figures, however, it was clearly incorrect to use the 2001 figures, however typical, where that level of sales cannot be sustained over the 25-year period. For this reason, the Commission accepts Public Counsel's estimate, based on the 2002 sales figures, and finds that the value of the generation-related benefit of the Metro East transfer must be reduced from $2.4 million to $1.7 million on an annual basis to reflect the use of the 2002 SO2 sales revenue figures.
The Commission notes that the record does not show what level of SO2 sales could be sustained over 25 years; Public Counsel's figure is accepted as the correct figure for the test year. The Commission does not agree with Public Counsel, however, that UE erred by pricing CTGs at $471/kW. Staff witness Proctor testified that UE's $471/kW figure was based on the average cost of a mix of larger, less expensive CTGs and smaller, more-flexible-but-more expensive CTGs. The record shows that such a mix of units is required in order to achieve the greatest possible operating flexibility and efficiency and that UE would build such a mix if the proposed transfer is not approved. For this reason, the Commission finds that the $471/kW figure used by UE was appropriate.
Another area of disagreement involved the degree to which revenues from the sale of excess capacity could be expected to offset the cost of the CTG option. Staff asserted that Voytas used inappropriate assumptions concerning the total
24 margin on sales of excess capacity. Voytas' "mark to market"/19/ analysis assumed that the CTGs would operate whenever the incremental cost of CTG generation was below the current spot market price of electricity; but Voytas also assumed that UE would sell only 50-percent of the power so generated, thereby reducing the level of profits from off-system sales available to offset costs. Voytas testified that he made this reduction to address transmission constraints, depth of market, and the use of CTG generation to serve native load. Staff witness Proctor criticized the 50-percent reduction as "arbitrary" and testified that UE should have performed a detailed analysis to determine the actual effect of these three factors on off-system sales revenue rather than simply applying an arbitrary reduction factor unsupported by any empirical data. For example, Proctor testified that if UE actually needs the output of the CTGs to serve native load only 5-percent of the time, then off-system sales should be rated at $23.3 million in present value rather than $12.3 million, with the result that the CTG option would cost only $418.4 million, exactly the cost of the Metro East transfer option as estimated by Voytas.
Voytas, however, testified that Proctor's 5-percent figure was unreasonable because it assumed that virtually all of the output of the CTGs would be available for sale off-system over a 25-year period. In 2003, Voytas testified, UE used 49.4-percent of the output of its newest CTGs at Peno Creek to serve native load. Voytas further testified that UE's Asset Mix Optimization (AMO) studies showed that between 35-percent to 80-percent of the output of the CTGs would be available for off-system sales, depending on the scenario. Voytas
/19/ A "mark to market" analysis compares forward electric price curves to the variable cost of operating the CTGs for every hour of the analysis period.
25 testified that the 50-percent reduction figure he used was therefore a "reasonable and prudent" choice in the middle of the range predicted by the AMO studies. Based on UE's actual experience with the Peno Creek CTGs and the results of UE's AMO studies, the Commission finds that the 50-percent figure used by Voytas was not arbitrary and was a reasonable estimate of the output likely to be available for off-system sales. Therefore, the Commission finds that the appropriate estimated revenue level for off-system sales under the CTG option is $12.3 million.
The Commission agrees with Public Counsel that it is appropriate to reduce the cost of the CTG option by the amount of expected off-system sales revenue, thereby reducing the cost from $441.7 million to $429.4 million, only about $11 million higher than the present value cost of the Metro East transfer option at $418.4 million. Proctor characterized this $11 million difference between the two options as "extremely small," given the scale of the figures involved, so that, "from a purely economic perspective, the expected costs of the two alternatives are almost identical."
Both Kind and Proctor testified that not all of the 597 MWs of additional capacity that the transfer would provide are needed immediately by UE. In that case, the excess production should be available for sale and the proceeds should be deducted from the cost of the Metro East transfer option just as the expected off-system sales proceeds are deducted from the cost of the CTG option. However, any excess capacity released by the Metro East transfer would not be available for sale due to the JDA and the Power Supply Agreement referred to above. Under those agreements, the excess capacity produced by the Metro East transfer would be used to meet CIPS' native load, including the Metro East load transferred away by UE.
26 4. RFPS AND THE JOPPA PLANT:
Kind testified that Voytas' Least Cost Analysis was improper because it compared the cost of the Metro East transfer option to only a single alternative. Kind suggested that UE should have used RFPs - Requests For Proposals - to identify other possible options. Kind also testified that UE had ignored the approximately 400 MWs received annually from a particularly efficient - and thus low-cost - coal-fired plant at Joppa, Illinois, owned by EEInc. Ameren owns a controlling interest in EEInc. and, according to Kind, should therefore be able to dictate that those 400 MWs remain available.
Both the Commission's Staff and UE joined in the view, which the Commission accepts, that RFPs are not appropriate for long-term resource planning. Dr. Proctor testified that the appropriate way to meet long-term capacity needs is to build a new plant. RFPs, by contrast, are a way to obtain short-term power supplies.
The Joppa Plant presents a different issue. UE owns 40-percent of EEInc. and receives 40-percent of the Joppa Plant's output under a contract that will expire at the end of December 2005. UE offered testimony that that contract will not be renewed because it is unprofitable for EEInc. to sell that power to UE at the price mandated by this Commission's Affiliate Transaction Rules, a price that is below market price. UE's share of EEInc. is an investment owned by UE's shareholders and UE has an obligation to maximize the return on that investment. The record shows that EEInc. no longer bids on UE's RFPs.
The Commission finds that the record shows that the output of the Joppa Plant will not be available after the end of 2005. Whether it should be available is a different question, one that is outside the scope of this case. Proctor disagreed with Kind regarding the EEInc. contract. Proctor testified
27 that, in UE's long-range resource plan, the termination of the EEInc. contract is linked not to the Metro East transfer, but rather to the addition of 330 MWs of CTGs at Venice, Illinois. The Venice CTGs will replace a coal-fired plant at that location that UE retired. Proctor specifically disagreed with Kind's conclusion that the capacity freed by the transfer would be unnecessary if the EEInc. contract were renewed and stated that renewal of that contract would permit UE to delay the addition of new capacity by only a year. Proctor stated that renewal of the EEInc. contract should not be a condition for approval of the Metro East transfer.
The Commission finds Proctor's testimony on this point to be more credible than Kind's. The record shows that the Joppa output will not be available after the end of 2005 and that UE is replacing that capacity with CTGs at Venice. Thus, as Proctor testified, the proposed Metro East transfer is unrelated to the Joppa contract. A simple count of the MWs involved supports Proctor's conclusion that UE would soon need additional capacity even if the Joppa contract were renewed.
5. THE JOINT DISPATCH AGREEMENT:
As has been stated above, UE and CIPS are operated as a single control area under a JDA. The JDA provides that profits from off-system sales are distributed to the participants on the basis of comparative load rather than comparative generation. This arrangement favors CIPS rather than UE because CIPS has a large load and no generation. The transfer of the Metro East load from UE to CIPS will exacerbate this inequity. Although UE doesn't believe the JDA needs to be modified in this respect, UE has stated that it will obtain a modification of the JDA to distribute profits from off-system sales based on generation rather than load if necessary to gain approval of this transfer. This amendment
28 would provide financial benefits to UE of at least $7 million annually, and perhaps as much as $24 million annually.
The JDA also provides for the transfer of energy between the participating entities at incremental cost. As noted above, the effect of the JDA and the Power Supply Agreement in the event that the Metro East transfer is carried out would be to require that any power produced by UE that is not needed to meet its load would be available to CIPS at incremental cost to meet its load requirements. In other words, the Metro East ratepayers would continue to be served by the same 6-percent slice of UE's generation that serves them now, but they would no longer pay any portion of the fixed costs of that generation. At present, the Metro East ratepayers pay approximately 6-percent of UE's generation-related fixed costs. Fixed costs are those that do not vary with the amount of production.
TRANSMISSION-RELATED ISSUES:
The proposed transfer includes certain transmission assets owned by UE, constituting 14.33-percent of all of UE's transmission plant. These facilities connect the generating plants at Venice, Illinois (75 MWs, soon to be increased by 330 MWs to 405 MWs), Pinckneyville, Illinois (330 MWs), Joppa, Illinois (405 MWs), and Keokuk, Iowa (134 MWs), to the Missouri grid. These transmission assets presently serve UE's Missouri customers and will continue to be necessary to serve UE's Missouri customers. If the proposed transfer is approved, title to these transmission assets will be transferred to CIPS.
UE performed an analysis of the financial impact on Missouri ratepayers of the transfer of the Metro East transmission assets. That analysis showed that the transfer would confer a net annual benefit on Missouri ratepayers of $0.385 million, increasing to $1.503 million after movement to the Midwest Independent
29 System Operator (MISO) due to the reduction of transmission revenues by 25-percent. Proctor testified that UE made certain errors in its analysis that caused it to significantly understate the net annual benefit of the transfer to Missouri ratepayers. Specifically, Proctor stated that UE had failed to include the further allocation between its Missouri retail customers and its wholesale customers, an error that resulted in an overstatement of the transmission cost of service for Missouri retail customers of about $1.4 million. Proctor also stated that UE made an additional rounding error that resulted in the understatement of the benefits of the transfer by $271,000 annually. Finally, Proctor stated that using the traditional 12-coincident-peak allocation factor rather than the 4-coincident-peak allocation factor adopted by UE for its analysis results in additional benefits of $100,000 to $200,000 annually. Proctor concluded that the net annual benefit of the transfer would actually be $2.033 million, increasing to $3.089 million after movement to MISO. No party contested Proctor's conclusions and the Commission accepts Dr. Proctor's figures.
Under the JDA, as noted previously, UE and CIPS are operated as a single control area. The transmission assets in question play a fundamental role in the single control area architecture because they are the conduit over which power is exchanged by UE and CIPS. The purpose of a control area is to dispatch and regulate generation. Every control area is connected at various points with adjacent control areas; these points of interchange are metered on a real-time basis. This metering provides instantaneous information to the control area operator so that generation output can be regulated to maintain balance with native load and net scheduled interchange, that is, net imports or exports of power.
30 Because of the single control area operating design, there are now no transmission charges for power transferred between UE and AEG/CIPS. However, Staff fears that CIPS may seek to recoup lost revenues by imposing such transmission charges if the JDA is modified as has been suggested in this proceeding. Staff witness Proctor described a "worst-case scenario" in which Missouri ratepayers would have to pay $13.8 million annually to access the generation from Venice, Pinckneyville, Joppa, and Keokuk over CIPS' transmission facilities. The Commission notes that Proctor himself rated the worst-case scenario as only 20-percent to 25-percent likely to occur. If it did occur, the impact would be an additional $0.80 per UE customer per year. UE has transferred functional control of these transmission assets to the MISO via its relationship with GridAmerica./20/
ISSUES RELATED TO THE DECOMMISSIONING TRUST FUND:
One of UE's generating stations, in Callaway County, Missouri, is a nuclear reactor. A large sum, some $515,339,000 in 2002 dollars, will eventually be needed to decommission that plant at the end of its useful life. UE's electric customers, including the 62,000 retail electric customers in the Metro East area, contribute toward that amount through the rates that they pay. The collected amounts are held in the Callaway Decommissioning Trust Fund, which presently has an estimated after-tax market value of $191,220,140.59.
The Commission redetermines the eventual cost of decommissioning, and the necessary contribution of the ratepayers to meet that cost, every three years in a proceeding referred to as the triennial review. The estimated cost of
/20/ Approved by this Commission in Case No. EO-2003-0271.
31 decommissioning is allocated to UE's three jurisdictions using 12-month coincident peak demand allocation factors. The three jurisdictions are Missouri Retail, Illinois Retail and Wholesale; Missouri Retail is allocated responsibility for 91.27-percent of the estimated cost of decommissioning. The start of the next triennial review, on September 1, 2005, was about 15 months away at the time of hearing in April 2004. Decommissioning costs, according to UE's 10-K filed with the SEC, will increase by 3.5-percent annually through 2033. The Commission's estimate of total decommissioning costs has increased at each triennial review.
If the Metro East transfer is approved, there will only be two jurisdictions, Missouri Retail and Wholesale. The allocation factor applicable to Missouri Retail will increase to 98.01-percent and Missouri ratepayers will become responsible for approximately $22.0 million in decommissioning costs that are presently the responsibility of the Illinois Retail ratepayers in the Metro East area./21/ As an offset to this amount, UE will transfer 98-percent - $13.8 million in after tax value - of the funds in the Illinois subaccount of the Decommissioning Trust Fund to the Missouri subaccount. Decommissioning costs will be allocated 98-percent to Missouri Retail and 2-percent to Wholesale, which is how the energy will be used after the transfer. Decommissioning costs were reallocated in this manner when UE sold its Iowa retail electric service area in 1992 and Missouri ratepayers became responsible for the portion of the decommissioning costs that had been the responsibility of UE's Iowa ratepayers.
Until the next triennial review, UE would contribute $6,214,184 annually to the Decommissioning Trust Fund as established by this Commission at the last
/21/ Calculated as follows: $536,000,000 (total decommissioning cost in 2003 dollars) x 0.9801 (Missouri share after the transfer) - $536,000,000 x 0.9127 (Missouri share before the transfer) = $36,126,000 - $13,526,000 (current market value of the Illinois sub-account) = $22,600,000.
32 triennial review. This amount, equal to 0.37-percent of UE's annual Missouri operating expenses, excludes the $272,554 collected annually for this purpose from the Metro East ratepayers in Illinois. UE has offered a "Zone of Reasonableness" analysis that suggests that there is no need for the $272,554 contribution at decommissioning inflation rates up to 3.854-percent; in other words, that the annual contribution of $6.2 million will result in adequate funding even if that target is inflated annually by the designated percentage. UE's witness Kevin Redhage testified that the present decommissioning inflation rate is 3.472-percent, calculated using three weighted factors (labor, 65-percent; energy, 13- percent; and burial cost, 22-percent). Nonetheless, UE has offered to make that contribution itself until the next triennial review if it is necessary to obtain approval of the proposed transfer.
COSTS AND LIABILITIES:
Both Staff and the Public Counsel argued that the proposed transfer would be detrimental to the interests of Missouri ratepayers because of the treatment of certain costs and liabilities under the agreement between UE and CIPS. These include items arising prior to the transfer, such as debt on the property transferred to Illinois, workers compensation and other employee-related claims, personal injury claims, products liabilities, common general liabilities, under-reserved claims, and environmental liabilities. Many of these categories include items both known and unknown. Another consideration is items arising after the transfer, such as capital investments necessary in the future to comply with increasingly stringent environmental regulations. With respect to
33 the items arising pre-transfer, Staff and Public Counsel contend that the UE's proposal will not leave CIPS with its fair share of the known items and will release the Metro East ratepayers from their fair share of the unknown items. With respect to future capital costs made necessary by environmental regulations, Staff and Public Counsel contend that UE's least cost analysis is seriously flawed because it does not include the likely rate impact of these costs. The net impact of the transfer will be to increase the existing exposure of Missouri's ratepayers on these liabilities by 6-percent.
1. PRE-TRANSFER COSTS AND LIABILITIES:
The agreement between UE and CIPS provides for the transfer of certain liabilities to CIPS. These include (i) balance sheet liabilities relating to UE's Illinois retail operations; (ii) trade payables relating to UE's Illinois retail operations; (iii) liabilities and obligations on contracts relating to UE's Illinois retail operations, insofar as they arise after the closing date of the transfer; (iv) litigation-related liabilities relating to UE's Illinois retail operations, insofar as they arise after the closing date of the transfer; (v) environmental liabilities relating to UE's Illinois retail operations, insofar as they arise after the closing date of the transfer, specifically including (1) the Alton Manufactured Gas site and (2) any pre-closing environmental liabilities relating to UE's Illinois retail operations insofar as they are covered by UE's existing environmental adjustment clause riders approved by the I.C.C.; (vi) accounts payable on natural gas purchased for resale and not yet paid; (vii) accrued payroll and employee vacation liability; (viii) liabilities relating to customers of UE's Illinois retail operations, whether arising pre-closing or post-closing; and (ix) franchise fees, gross receipts taxes and utility taxes relating to UE's Illinois retail operations, whether arising pre-closing or post-closing.
The agreement provides that any liabilities not expressly noted as transferring to CIPS will remain with UE, including (i) all pre-closing liabilities relating to UE's Illinois retail operations; (ii) all employee
34 liabilities relating to UE's Illinois retail operations, whenever asserted, arising prior to closing, including workers compensation, wage and hour, and the like; (iii) liabilities due to litigation relating to UE's Illinois retail operations, whether pending at closing or filed after closing but based on pre-closing events; (iv) products liabilities, safety liabilities and environmental liabilities based in whole or in part on pre-closing events or conditions, including claims over services, personal injury, property damage, environmental claims, hazardous materials, employee health and safety, and violation of applicable laws; (v) taxes, except as expressly assumed by CIPS; and (vi) all liabilities relating to assets retained by UE, including generation-related environmental liabilities.
The agreement between UE and CIPS provides that almost all of the existing general corporate liabilities will stay with UE. "General corporate liabilities" are those which cannot be assigned directly to a particular line of business. There are 22 liability accounts on UE's balance sheet and the record shows how each balance sheet account will be treated if the transfer occurs. The Unrecovered Purchased Gas Costs account is not affected by the transfer and will stay with UE. Reserves for existing lawsuits, asbestos claims, and worker's compensation claims will stay with UE. These amounts have already been expensed. Environmental liabilities with a reserve on the books will stay with UE, except for the Alton Manufactured Gas Site, which will be transferred to CIPS. The Asset Retirement Obligation Liability account, which is offset by a balance sheet asset, will stay with UE, as will the corresponding asset. These accounts will have no cost of service impact going forward.
Accounts Payable will stay with UE, but these amounts are already expensed and will thus have no impact on rates. Invoices from Mississippi River Transmission for natural gas used in Illinois will transfer to CIPS. The latter
35 amounts have never been included in Missouri's cost of service. Charges owed to Ameren Services (AMS) will move to CIPS post-closing. These amounts have already been expensed and will have no impact on rates. Illinois customer deposits will transfer to CIPS, as will Illinois customer advances in aid of construction.
Interest on long-term debt will stay with UE; there is no cost of service impact because the interest is "below the line." Short-term debt will also stay with UE. The interest expense is "below the line" and thus excluded from cost of service. Also, short-term debt is not included in calculating UE's return on equity. Public Counsel's Application for Rehearing takes issue with the Commission's findings above related to UE's debt. Public Counsel's contentions are incorrect in that Public Counsel confuses the effect of debt on UE's capital structure (the capital structure does impact rates) versus the effect of interest paid on debt, which does not affect return on rate base or cost of service. Indeed, the record shows that by retaining this debt, which is lower cost than equity financing, UE's overall cost of capital is reduced and thus its cost of service is reduced. The Dividends Declared account will stay with UE. This item is also "below the line" and will have no cost of service impact. Taxes applicable to the transferred assets will be transferred to CIPS. Taxes collected by UE from its employees and customers will be paid over to the various taxing authorities. A proportionate amount of Accumulated Deferred Income Taxes will be transferred to CIPS.
Liability for Employee Wages Payable for transferred employees will transfer to CIPS. Accrued vacation liability for transferred employees will transfer to CIPS. Other items in the Miscellaneous Current and Accrued Liabilities account will stay with UE, but have already been expensed. Pre-closing pension liability will not be transferred. Post-closing pension
36 liability for transferred employees will transfer to CIPS. Current pension liability has already been expensed. Current liabilities for Post Retirement Benefits have already been collected in rates and will stay with UE.
Post-closing liabilities will transfer to CIPS. Derivative Instrument Liability under Financial Accounting Standards (FAS) 133 is not applicable to the businesses being transferred, and so will stay with UE. Accumulated Nuclear Decommissioning will not be transferred. The Other Regulatory Liabilities account is the other side of the FAS 109 balance sheet entry. It is offset by entries in the Accumulated Deferred Income Taxes account already mentioned. A proportionate amount of this account is being transferred to CIPS. It has no cost of service impact. A proportionate amount of Accumulated Deferred Investment Tax Credits is being transferred to CIPS, as is a proportionate amount of the Accumulated Deferred Income Taxes Accelerated Amortization Property, the Accumulated Deferred Income Taxes Other Property, and the Accumulated Deferred Income Taxes Other accounts.
Staff contends that the compensation that UE would receive under the agreement is thus inadequate, because it represents only the net book value of the transferred assets and includes nothing additional for the retained liabilities. The record shows that the assets being transferred are security for certain bonds that UE will retain. Missouri ratepayers, therefore, will be responsible for paying the debt on the assets being transferred.
UE will retain all pre-transfer environmental liabilities except for the Alton Manufactured Gas Plant and any other such liabilities covered by UE's existing riders. UE dismisses these liabilities as "speculative" because their
37 eventual magnitude cannot now be known. Staff asserts that Missouri ratepayers should not pay for the 6-percent of the environmental liabilities that arose when that share of the generation benefited Illinois ratepayers. Staff argues that 6-percent of these liabilities should either stay with Illinois or that UE should be adequately compensated for assuming them. Some 49 lawsuits regarding injuries due to asbestos exposure at UE premises have already been filed, seeking a total of $2,450,000 in damages outside of legal fees and costs. UE will retain these liabilities under the transfer agreement. When CIPS and CILCO transferred generation assets to Genco and AERG, they agreed to indemnify them for any pre-transfer, asbestos-related claims. The agreement between UE and CIPS does not include any such indemnity clause. With respect to the asbestos claims, the record shows that, while 49 are pending, UE has obtained dismissal of 50 and has settled 22 more. UE has established a reserve of $30 million for such claims and the potential exposure of Missouri ratepayers if the transfer is approved is 6-percent of any shortfall.
UE must fund the cleanup of hazardous waste sites regardless of fault. One such site is the former Sauget Generating Station in Illinois. While UE's estimated share of the Sauget remediation costs is proprietary and cannot be set out here, the likely impact on Missouri ratepayers is less than $1 million. However, the other company liable for the Sauget cleanup, Solutia - formerly known as Monsanto - is in bankruptcy and may not be able to pay its share of the Sauget remediation costs. UE's 10-K suggests that the Sauget costs could be as much as $26 million if Solutia makes no contribution. The impact of that amount on Missouri ratepayers would be $1.56 million by 2010.
The agreement between UE and CIPS specifically transfers all liability for remediation at the Alton Manufactured Gas Plant to CIPS. The I.C.C. allows
38 utilities to recover remediation costs in rates from Illinois ratepayers and that remediation is in rates in the Metro East service area. The current amount deferred for UE, net of recoveries, is $1 million.
2. FUTURE ENVIRONMENTAL-RELATED CAPITAL COSTS:
One criticism that Public Counsel made of Voytas' least cost analysis was that his projection of test year values over 25 years inappropriately assumed that the cost of complying with environmental regulations would not change over that period. UE's own 10-K, a form filed with the S.E.C., however, projects environment-related capital investments of $863 million to $1,163 million over the next 15 years, an additional 6- percent of which will become the responsibility of Missouri ratepayers if the Metro East transfer is approved. Assuming a 10-percent Return on Equity (ROE), these capital investments will cost ratepayers between $5.1 million and $7.0 million annually due to the increased rate base on which UE would be earning a return. Although the figures in the 10-K are estimates, the Missouri Supreme Court has said that the PSC should use estimates where actual figures are unavailable./22/ These projected expenditures are not speculative; they are likely enough that UE included them in its 10-K for consideration by investors.
The proposed transfer will make available for UE's Missouri customers an additional 6-percent slice UE's existing generating capacity. Necessarily, with this extra capacity will come responsibility for an additional 6 -percent of any associated future environmental liabilities. As noted above, Public Counsel calculated this additional burden at between $5.1 million and $7 million annually. For this reason, Kind testified that these coal-fired plants are not
/22/ St. ex rel. Martigney Creek Sewer Co. v. Public Service Commission, 537 S.W.2d 388, 396 (Mo. banc 1976).
39 "low-cost" plants, as UE claims, but increasingly high-cost plants as increased environmental regulation takes hold in the near future.
An associated matter has to do with SO2 emission allowances, already discussed above. SO2 is a pollutant released into the air by burning coal. The allowances, each of which authorizes the release of one ton of pollutants, are necessary for utilities with coal-fired plants. The Environmental Protection Agency allocates a number of allowances to each utility each year. UE aggressively markets its SO2 allowances to other utilities, leading Staff and Public Counsel to fear that UE will find itself without the necessary number of allowances. In that case, the company would have to install expensive pollution-control equipment at its plants sooner than would otherwise be necessary and, should the Metro East transfer be approved, Missouri ratepayers would have to pay an additional 6-percent of the costs of such a debacle. Staff's witness Campbell testified that the costs of emission-control systems would run into the hundreds of millions of dollars.
The record shows that UE has one of the largest SO2 allowance banks in the country. If environmental regulations don't change and UE makes no further sales, it has enough allowances on hand now to last through 2033. UE was allotted 1.6 million Phase I allowances and it has sold only 474,829, which is less than half of the total. The forecasts in UE's 10-K are possible levels of future capital expenditures for environmental purposes. It is by no means certain that these expenditures will ever actually be made. In any event, UE's Missouri ratepayers will certainly bear the costs of over 90-percent of such expenditures as are actually made. What is at issue is an additional 6-percent share, or an annual increase of $6.54 to each UE customer if the capital expenditures are actually as high as Public Counsel predicts, at a 10-percent ROE.
40 NATURAL GAS ISSUES:
Staff witness Dave Sommerer suggested that there are two detriments with respect to the proposed transfer of the Alton natural gas retail service area. First, that the small Fisk/Lutesville service area in Missouri might then be unable to obtain transportation on as good terms as it has heretofore enjoyed. Specifically, the Missouri Fisk/Lutesville customers will lose the benefit of including their supply contracts in the much larger Alton gas supply contracts. Second, that gas-related costs at the Venice and Meramec power plants might increase due to the loss of a beneficial "piggybacking" relationship with the Alton natural gas service area. The Alton and Fisk/Lutesville Local Distribution Companies (LDCs) are served by a single firm transportation contract that will expire on Oct. 31, 2006. At that time, AEFS - another Ameren subsidiary - will negotiate a new contract, which UE's witness Massman testified will probably be just as good. Sommerer, however, testified that, if the transfer is approved, the power plants will replace firm, no-notice contracts for peak summer demand with uncertain, stand-alone supply and transportation arrangements relying on the volatile spot market. Massman insisted that the gas supply to the Venice and Meramec plants would not become either less certain or more costly because of the proposed transfer. The plants' needs were always subordinate to those of the Alton LDC. The plants were charged the market price for transportation and can thus still obtain it at that price; the plants used the arrangement rarely; Alton allocated the highest-priced gas to the plants each month; and the plants can still obtain storage from the transporter just as Alton did.
Dave Sommerer testified for Staff that the "worst-case scenario" impact for Fisk/Lutesville would be a $10,000 annual cost increase, equating to a $0.50 per
41 month increase for the average customer. UE's witness Massman testified that neither asserted detriment is plausible in his opinion. Massman testified that the impact of the worst-case scenario with respect to the Venice and Meramec power plants would be an annual increase of $0.084 to the electric bill of UE's average Missouri customer. Based on the record, the Commission finds that the asserted detriments are not likely to occur. If they do occur, their impact would be minimal. Sommerer testified that the worst-case outcomes might occur, while Massman, who actually manages these matters for UE, insisted that they were unlikely. The Commission finds Massman's testimony to be the more credible. The record shows, and the Commission finds, that the financial impact of even the worst-case scenarios would be very small.
CONCLUSIONS OF LAW
The Missouri Public Service Commission has reached the following conclusions of law.
JURISDICTION:
The record shows that UE is in the business of owning, operating, controlling, and managing electric plant and natural gas plant for the purpose of selling electricity and natural gas to others. UE is therefore both an electric corporation and a gas corporation as defined in Section 386.020, and is a public utility as defined in that section, subject to regulation by this Commission under Chapters 386 and 393, RSMo.
UE proposes to sell to its affiliate, CIPS, its retail natural gas and electric operations in Illinois, including the customers and the transmission and distribution facilities that serve them. None of the property is located in Missouri, but some of it, particularly certain electric transmission facilities, directly serves UE's Missouri customers by transmitting electricity to them from
42 UE's Illinois and Iowa power plants. Some of the other assets, such as the natural gas LDC in Alton, Illinois, indirectly impact UE's Missouri gas and electric operations. The effect of the transaction will be to reduce UE's native load, thereby making a larger percentage of the output of its existing power plants available to serve its remaining customers, all of whom will be located in Missouri.
Section 393.190.1 provides, in pertinent part:
No gas corporation, electrical corporation, water corporation or sewer corporation shall hereafter sell, assign, lease, transfer, mortgage or otherwise dispose of or encumber the whole or any part of its franchise, works or system, necessary or useful in the performance of its duties to the public * * * without having first secured from the commission an order authorizing it so to do. Every such sale, assignment, lease, transfer, mortgage, disposition, encumbrance, merger or consolidation made other than in accordance with the order of the commission authorizing same shall be void. * * * Nothing in this subsection contained shall be construed to prevent the sale, assignment, lease or other disposition by any corporation, person or public utility of a class designated in this subsection of property which is not necessary or useful in the performance of its duties to the public, and any sale of its property by such corporation, person or public utility shall be conclusively presumed to have been of property which is not useful or necessary in the performance of its duties to the public, as to any purchaser of such property in good faith for value.
The cited statute does not make any distinction as to the location of the property in question, whether in Missouri or elsewhere. Rather, it makes a distinction that turns on whether or not the property in question is "necessary or useful" to the utility in the performance of its duties to the public. The record shows that all of the property in question is "necessary and useful" to UE in serving its natural gas and electric retail customers. Therefore, the Missouri Public Service Commission finds that it has jurisdiction over the proposed transfer pursuant to Section 393.190.1.
43 THE AFFILIATE TRANSACTION RULE:
UE seeks a waiver of the Commission's electric and gas affiliate transaction rules, 4 CSR 240-20.015 and 4 CSR 250-40.015, to the extent necessary to authorize the Metro East transfer. However, UE contends that a waiver is not necessary in the circumstances presented by this case because the transfer is not within the scope of those rules. The rules are designed to protect ratepayers from a transaction that is not at arms- length and which may thus result in exorbitant prices being imposed on ratepayers./23/
Staff and OPC contend that it is not in the best interests of UE's regulated customers to acquire power plants with pre-existing environmental liabilities. And, for this reason, they argue that the proposed compensation is not prudent, adequate, nor reasonable. They assert that this is exactly the sort of transaction to which the affiliate transaction rules were meant to apply. They argue that the present transaction is within the affiliate transaction rules because it involves the regulated entity (UE), its unregulated parent (Ameren) and a regulated affiliate (CIPS).
The Commission has authority to "inquire as to, and prescribe the apportionment of, capital, earnings, debts and expenses" between the regulated entity and its parent and affiliates./24/ In utility regulation, "the dominant thought and purpose of the policy is the protection of the public while the protection given the utility is merely incidental."/25/ The purpose of the affiliate transaction rules is to prevent cross- subsidization, in which a conglomerate including a regulated entity seeks to shift the costs of its unregulated activities to its regulated customers. The Commission agrees with
/23/ Atmos Energy Corp. v. Public Service Commission, 103 S.W.3d 753 (Mo. banc 2003). /24/ Section 393.140(12). /25/ De Paul Hosp. School of Nursing, Inc. v. Southwestern Bell Telephone Co., 539 S.W.2d 542, 548 (Mo. App., W.D. 1976).
44 Staff and Public Counsel that the affiliate transaction rules necessarily apply to the Metro East transfer, involving as it does UE, its parent and its affiliates.
UE seeks a waiver of Commission Rules 4 CSR 240-20.015 and 4 CSR 250-40.015. UE points out that, under 015(10)(A) (the two rules are identical in this respect), there are two ways to obtain a waiver, and only the second of these - (10)(A)2 - includes the "best interests of the regulated customers" standard cited by Staff and Public Counsel. The first way - (10)(A)1 - simply requires a written application to the Commission. The Commission agrees that UE has correctly analyzed the regulations and its Application constitutes the required written application. The Commission may grant the written application for good cause shown. In the present case, "good cause" would be a finding that the proposed transfer will confer a net benefit.
THE GOVERNING STANDARD UNDER SECTION 393.190.1:
Section 393.190.1 does not contain a standard to guide the Commission in the exercise of its discretion; that standard is provided by the Commission's own rules. An applicant for such authority must state in its application "[t]he reason the proposed sale of the assets is not detrimental to the public interest."/26/ A court has said of Section 393.190.1, that "[t]he obvious purpose of this provision is to ensure the continuation of adequate service to the public served by the utility."/27/ To that end, the Commission has previously considered such factors as the applicant's experience in the utility industry; the applicant's history of service difficulties; the applicant's general financial health and ability to absorb the proposed transaction; and the
/26/ Commission Rule 4 CSR 240-2.060(7)(D). /27/ State ex rel. Fee Fee Trunk Sewer, Inc. v. Litz, 596 S.W.2d 466, 468 (Mo. App., E.D. 1980).
45 applicant's ability to operate the assets safely and efficiently./28/ None of these factors are at issue in the present case; neither is UE's ability to continue to provide adequate service to its customers.
The parties do not agree on the interpretation or application of the "not detrimental to the public" standard. UE asserts that the Commission must grant approval unless it finds the transfer would be detrimental to the public interest./29/ UE emphasizes the opinion of one court, quoted above, that the purpose of the statute is to ensure the continuation of adequate service to the public./30/ UE quotes prior decisions of this Commission to the effect that denial requires compelling evidence on the record that a public detriment is likely to occur./31/ According to UE, while the Applicant has the burden of proof, those asserting a specific detriment have the burden of proof as to that allegation./32/ Finally, UE notes that the Applicant is not required to show that the transfer is beneficial to the public./33/
Staff points out that this is the Commission's first contested case under Section 393.190.1 since AG Processing, a decision in which the Missouri Supreme Court reversed a Commission decision under that section./34/ That case held,
/28/ See In the Matter of the Joint Application of Missouri Gas Energy, et al., Case No. GM-94-252 (Report and Order, issued October 12, 1994), 3 Mo. P.S.C.3rd 216, 220. /29/ St. ex rel. City of St. Louis v. Public Service Commission, 73 S.W.2d 393, 400 (Mo. banc 1934). /30/ Fee Fee Trunk Sewer, supra. /31/ In the Matter of KCP&L, Case No. EM-2001-464 (Order Approving Stipulation & Agreement and Closing Case, issued Aug. 2, 2001). /32/ Anchor Centre Partners, Ltd. v. Mercantile Bank, NA, 803 S.W.2d 23, 30 (Mo. banc 1991); In the Matter of Gateway Pipeline Co., Inc., Case No. GM-2001-585 (Report & Order, issued Oct. 9, 2001). /33/ In the Matter of Sho-Me Power Corp., Case No. EO-93-259 (Report & Order, issued Sep. 17, 1993). /34/ AG Processing, Inc. v. Public Service Commission, 120 S.W.3d 732 (Mo. banc 2003).
46 Staff asserts, that the Commission must evaluate both the present and future impacts of a transfer at the time it makes its decision. Staff further contends that, while the "not detrimental" standard applies to the transfer itself, UE seeks some additional relief that is governed by other, higher standards. For example, Staff argues that UE seeks several ratemaking determinations that are subject to the "just and reasonable" standard and that UE seeks a waiver from the Commission's affiliate transaction rules governed by the "best interests of the regulated customers" standard.
Public Counsel, in turn, agrees that Section 393.190.1 requires prior Commission authority for a utility to transfer any part of its system or assets; such authority is to be granted only where the proposed transfer is "not detrimental to the public interest."/35/ The applicant utility bears the burden of proof and, contrary to UE's notion, this burden does not shift. Public Counsel urges the Commission to ignore UE's quotations of erroneous language from past Commission orders that approval must be granted unless "compelling" evidence shows that a "direct and present" detriment is "likely" to occur. Instead, as recently articulated by the Missouri Supreme Court in AG Processing, and restated by the Commission itself,/36/ "a detriment to the public interest includes a risk of harm to ratepayers." Thus, Public Counsel takes the position that the mere risk itself of higher rates in the future is a detriment to the public. Public Counsel insists that the law requires that the Commission deny
/35/ City of St. Louis, supra. /36/ In the Matter of Aquila, Inc., Case No. EF-2003-0465 (Report & Order, issued Feb. 24, 2004) pp. 6-7, In the Mater of Aquila, Inc., Case No. EF -2003-0465 (Report & Order, issued Feb. 24, 2004) pp. 6-7,
47 the proposed transaction even if the detriments found are the result of events that would simply be set into motion or which involve the probability of significant harm which could likely occur, but is not certain to occur.
In the AG Processing case, the Commission approved an acquisition and merger by Aquila, Inc. - then called UtiliCorp - that involved an acquisition premium of $92,000,000./37/ Although the Commission rejected Aquila's proposed regulatory plan, under which a portion of the acquisition premium would be recovered in rates, the Commission refused to consider the recoupment of the acquisition premium on the grounds that it was a rate case issue. The Missouri Supreme Court reversed, saying:
The fact that the acquisition premium recoupment issue could be addressed in a subsequent ratemaking case did not relieve the PSC of the duty of deciding it as a relevant and critical issue when ruling on the proposed merger. While PSC may be unable to speculate about future merger- related rate increases, it can determine whether the acquisition premium was reasonable, and it should have considered it as part of the cost analysis when evaluating whether the proposed merger would be detrimental to the public. The PSC's refusal to consider this issue in conjunction with the other issues raised by the PSC staff may have substantially impacted the weight of the evidence evaluated to approve the merger. The PSC erred when determining whether to approve the merger because it failed to consider and decide all the necessary and essential issues, primarily the issue of UtiliCorp's being allowed to recoup the acquisition premium./38/
The Missouri Supreme Court did not announce a new standard for asset transfers in AG Processing, but rather restated the existing "not detrimental to the public" standard. In particular, the Court clarified the analytical use of the standard. What is required is a cost-benefit analysis in which all of the benefits and detriments in evidence are considered. The AG Processing decision does not, as Public Counsel asserts, require the Commission to deny approval
/37/ An acquisition premium is the amount by which the purchase price exceeds the book value of the assets purchased. /38/ AG Processing, supra, 120 S.W.3d at 736 (internal footnotes omitted).
48 where a risk of future rate increases exists. Rather, it requires the Commission to consider this risk together with the other possible benefits and detriments and determine whether the proposed transaction is likely to be a net benefit or a net detriment to the public. Approval should be based upon a finding of no net detriment. Likewise, contrary to UE's position, the AG Processing decision does not allow the Commission to defer issues with ratemaking impact to the next rate case. Such issues are not irrelevant or moot because UE is under a temporary rate freeze; the effects of the transfer will still exist when the rate freeze ends.
In considering whether or not the proposed transaction is likely to be detrimental to the public interest, the Commission notes that its duty is to ensure that UE provides safe and adequate service to its customers at just and reasonable rates. A detriment, then, is any direct or indirect effect of the transaction that tends to make the power supply less safe or less adequate, or which tends to make rates less just or less reasonable. The presence of detriments, thus defined, is not conclusive to the Commission's ultimate decision because detriments can be offset by attendant benefits. The mere fact that a proposed transaction is not the least cost alternative or will cause rates to increase is not detrimental to the public interest where the transaction will confer a benefit of equal or greater value or remedy a deficiency that threatens the safety or adequacy of the service.
In cases brought under Section 393.190.1 and the Commission's implementing regulations, the applicant bears the burden of proof. That burden does not shift. Thus, a failure of proof requires a finding against the applicant.
49 RESOLUTION OF CONTESTED ISSUES:
The Commission has determined that it must resolve the contested issues set out below in order to determine whether or not the proposed transfer would have a net detrimental effect on the public interest.
1. GENERATION-RELATED ISSUES:
The Commission has found that UE needs additional capacity, both now and in the future, and that the additional energy made available by the transfer would be cheaper, on a per-MWh basis, than either purchased power or power generated by CTGs. Underlying these findings is the Commission's finding that the reserve margin figure selected by UE is reasonable and appropriate. UE calculated the generation-related savings at $2.4 million annually. These points weigh in favor of the proposed transfer.
Public Counsel and Staff claim that the proposed transfer would be detrimental to the public interest if it is not, in fact, the least cost alternative. The Commission is, of course, concerned that necessary additional capacity be added at no greater cost to ratepayers than necessary. However, the Commission's greater concern in this case is that it not be a vehicle whereby the Ameren group shifts costs to Missouri ratepayers in order to maximize its revenues from its unregulated activities.
The Commission agrees with UE and Staff that the appropriate alternative with which to compare the proposed transfer is the option of building CTGs. The Commission has found that RFPs are inappropriate in long-term resource planning and that the output of the Joppa Plant will not be available after the end of 2005. The Commission has also found that the generation-related savings realized from the transfer must be reduced from $2.4 million, as calculated by UE, to $1.7 million annually in order to remove the inappropriate level of revenue from
50 the sale of SO2 emission allowances. The Commission has further found that the level of generation-related benefits must be further reduced by $0.8 million in order to remove the effect of the escalation factor that Mr. Voytas admittedly applied only to the CTG option. Thus, the Commission finds that the level of generation-related savings conferred by the Metro East transfer would be $0.9 million annually. This level of difference between the two options is, as Dr. Proctor testified, so "thin" as to make them essentially identical in economic terms./39/
With respect to the JDA, Staff urges two amendments as conditions of the approval of the proposed transfer. The first of these, the sharing of the profits of off-system sales based on comparative generation rather than comparative load, UE is willing to accept. The record shows that that amendment will yield about $7.0 million annually to UE. This figure is an additional benefit that the transfer would confer.
The second recommended JDA amendment has to do with the pricing of inter-company energy transfers. Currently, such transfers are accounted for at incremental cost. Staff recommends that they be accounted for at market price instead. UE is not willing to accept this amendment, characterizing it as a complex matter requiring further study. UE is willing, however, to "study alternatives" in cooperation with Staff. UE has also proposed an alternative to this amendment, to address the potential detriment relating to pricing these transfers at incremental cost instead of market, discussed further below.
The record shows that, under the JDA and the related Power Supply Agreement that bind UE, CIPS and Genco into a single control area, the Metro East load
/39/ Proctor was speaking of the $2.4 million figure. Presumably, these considerations are all the more pertinent to the lower figure of $0.9 million.
51 transferred from UE to CIPS must still be served by whatever power supplies are available to UE and Genco through the end of 2006. Therefore, of the 597 MWs of additional capacity made available by the Metro East transfer, any portion not needed by UE to serve its native load will be available to serve CIPS' native load, including UE's former Metro East ratepayers. If CIPS needs any of this power, it cannot be sold off-system at market price. Instead, AEG will pay only incremental cost for any power generated by UE that it uses. UE's fixed costs, however, will be the sole responsibility of UE's Missouri customers after the transfer, with no contribution from CIPS or from the Metro East ratepayers.
The record does not show whether or not CIPS and Genco have sufficient capacity to absorb the transferred Metro East load without substantial power input from UE./40/ Because UE has the burden of proof, this failure of proof requires a finding that substantial input from UE would be required. The Commission finds that the sale of power by UE to AEG to serve the transferred Metro East load at incremental cost, with no contribution to fixed costs, would be detrimental to the interests of UE's Missouri customers. An additional detriment is the value of the lost off-system sales revenue for the power used by CIPS, less the value of the incremental costs actually paid by AEG./41/
If the financial effects of the JDA sought to be addressed by the second amendment are not addressed in a fair and equitable manner, then the transfer could indeed result in shifting costs to Missouri ratepayers in order to benefit the Ameren group as a whole. The Commission cannot permit that result to occur. However, those effects can be addressed in a different way than the second
/40/ Dr. Proctor testified, "Under the current JDA, the excess base-load capacity gained from the transfer must be used to serve the load that was transferred rather than be available for spot market sales. Moreover, the excess base-load generation that would have otherwise been available to sell into the wholesale spot market is committed to serve the AmerenCIPS load at AmerenUE's incremental cost." Ex. 14:10. /41/ The likely value of this detriment was never quantified in the record.
52 amendment to the JDA recommended by Staff. In summary, as addressed in more detail below, a mechanism can be established whereby revenues can be imputed to UE unless UE is able to establish in its next rate proceeding that the benefits to Missouri ratepayers arising from the transfer exceed the negative financial effects caused by the incremental cost pricing of additional energy transfers from UE to AEG that will occur as a result of the transfer.
2. TRANSMISSION-RELATED ISSUES:
Staff asserts that the transfer should not be approved because UE's Missouri ratepayers might someday be required to pay transmission costs in order to receive the power generated at UE's Illinois and Iowa power plants. Dr. Proctor described a "worst-case scenario" that would cost Missouri ratepayers $13.8 million annually. While the record suggests that this outcome is not likely, the Commission must nonetheless consider it.
UE's analysis of the revenue requirement impact of the transfer in the transmission area revealed a substantial monetary benefit for Missouri ratepayers. Staff's own expert on this topic, Dr. Proctor, filed an affidavit stating that UE had understated the level of this monetary benefit. Proctor calculated the net annual benefit of the transfer at $2.033 million, increasing to $3.089 million after movement to MISO.
3. ISSUES RELATED TO THE DECOMMISSIONING TRUST FUND:
UE seeks leave to reduce its decommissioning contribution by $272,554, the amount collected annually from its Metro East ratepayers. Staff and Public Counsel oppose this proposal and contend that permitting UE to stop making this portion of its annual Decommissioning Trust Fund contribution would harm Missouri ratepayers. The Commission agrees with Staff and Public Counsel.
53 As a matter of simple common sense, any dollars not contributed now are dollars that will not be available when decommissioning starts in 2024. While the Commission does not reject UE's "Zone of Reasonableness" analysis, it recognizes that that analysis is merely a forecast of the result of the complex interactions of numerous factors over many years. However artfully devised and implemented, the forecast may prove to be wrong. It is reasonable, therefore, to require UE to continue to contribute the portion of the decommissioning cost allocated to the Metro East ratepayers until the next triennial review establishes a new contribution level based on changed circumstances and a new forecast.
In connection with this point, UE explains that the Commission has required it to establish and maintain the Decommissioning Trust Fund in a manner that takes the maximum advantage of the provisions of the Internal Revenue Code in order to reduce the amount of the fund lost to federal taxes so far as is possible. UE asserts that, if the Commission requires UE to increase the amount of its Missouri-jurisdictional contribution by $272,554 annually, it will not be able to continue to make tax-deductible contributions to the fund under existing rulings by the Internal Revenue Service. It will have to seek new rulings. In order for UE to obtain these rulings, the Commission will have to find that the new contribution amount of $6,486,738 is included in UE's Missouri-jurisdictional cost-of-service for ratemaking purposes. Further, UE states that the Commission will also have to find that the new contribution amount was established based on the economic and financial input parameters used in the "Zone of Reasonableness" analysis attached as Schedule 4 to Redhage's Surrebuttal Testimony. UE points to Regulation 26 C.F.R. Section 1.468A-3(g):
(g) Requirement Of Determination By Public Utility Commission Of Decommissioning Costs To Be Included In Cost Of Service. The Internal Revenue Service shall not provide a taxpayer with a schedule of ruling amounts for any nuclear decommissioning fund unless a public utility commission that
54 establishes or approves rates for electric energy generated by the nuclear power plant to which the nuclear decommissioning fund relates has--
(1) Determined the amount of decommissioning costs of such nuclear power plant to be included in the taxpayer's cost of service for ratemaking purposes; and
(2) Disclosed the after-tax return and any other assumptions and determinations used in establishing or approving such amount for any taxable year beginning on or after January l, 1987.
The language of the cited regulation is clear. The Commission will make the requested findings. The Commission finds that UE's new Missouri jurisdictional Decommissioning Trust Fund annual contribution amount of $6,486,378 is included in UE's Missouri -jurisdictional cost-of- service for ratemaking purposes and is established based on the economic and financial input parameters used in the "Zone of Reasonableness" analysis attached as Schedule 4 to Kevin Redhage's Surrebuttal Testimony.
If UE continues to contribute the Metro East share of the decommissioning expense until September 1, 2005, the Commission considers the Decommissioning Trust Fund issues to be neither detrimental nor beneficial to the public interest.
4. COSTS AND LIABILITIES:
This category includes costs and liabilities, both known and unknown, arising from events occurring prior to the transfer and also costs that may be incurred for future capital improvements required by environmental regulations. The scope of the latter is not now certain, but estimates of some of these amounts exist in UE's 10-K filed with the S.E.C.
The Commission considers it inequitable, and thus detrimental, to transfer to Missouri ratepayers all of the share of UE's pre-closing costs and
55 liabilities now borne by the Metro East ratepayers. Most of these liabilities are not presently known and it is thus not possible for the Commission to weigh them against the benefits that the transfer will produce. However, the "worst case scenario" for the Sauget remediation alone is a significant amount. Likewise, any pre-closing environmental liabilities that become apparent only after the transfer has occurred are also likely to be significant amounts. The Commission is of the opinion that an appropriate condition must be imposed on the transfer in order to protect Missouri ratepayers from these unknown but potentially significant costs.
If the proposed transaction is approved, UE's Missouri customers will become responsible for an additional 6-percent slice of any costs relating to capital improvements at UE's power plants necessary to meet changing environmental regulations. As already discussed, the Metro East ratepayers would continue to be served by that generation, free of any responsibility for these costs. Based on figures in UE's 10-K filed with the S.E.C., the potential annual impact of the additional share of costs relating to such capital improvements is estimated at $5.1 million to $7.0 million annually.
5. NATURAL GAS ISSUES:
These issues are purely factual. Staff presented testimony suggesting that the natural gas aspects of the proposed transaction may result in certain detrimental impacts on UE's Missouri gas and electric operations. The record shows that the asserted detrimental impacts are not likely to occur. The record further shows that, if they do occur, their impact would be $0.01 million for the Fisk/Lutesville LDC and $0.98 million for the power plants.
56 COST-BENEFIT ANALYSIS:
A cost-benefit analysis compares costs to benefits to determine whether a net cost or a net benefit is likely to result. The costs and benefits identified in this proceeding are set out below:
------DESCRIPTION BENEFITS DETRIMENTS ------Generation-related savings $ 0.900 million ------JDA amendment to share profits by generation $ 7.000 million ------Transmission-related savings $ 2.033 - 3.089 million ------Decommissioning Trust Fund issues ------JDA requirement that surplus UE power be available to -- ? CIPS at incremental cost ------Possible transmission charges -- $ 13.800 million ------Sauget remediation -- $ 1.560 million (one-time cost) ------Future environmental capital investments -- $ 5.100 - 7.000 million ------Natural gas: possible Fisk/Lutesville impact -- $ 0.010 million ------Natural gas: possible power plant impact -- $ 0.098 million ------TOTALS: $ 9.933 - 10.989 million $ 19.008 - 20.908 million ------$8.019 - 10.975 MILLION DIFFERENCE: (PLUS A POSSIBLE ONE-TIME COST OF $1.56 MILLION) ------
A comparison of the benefits of the proposed transfer, conservatively calculated, to the possible negative impacts reveals that, if the transfer's certain benefits are realized at what has been characterized as the lowest possible level, and all of the potential negative impacts do actually occur, the public interest will sustain a detriment on the order of $8 million to $11 million dollars annually, plus a possible one-time cost of $1.56 million for remediation of the Sauget site.
57 However, this is not the end of the analysis. The benefits itemized above are certain, while the detriments, for the most part, are not. UE expects that the benefits will actually be much greater than the level shown above, and the record shows that this expectation is not unreasonable. For example, UE expects that the JDA amendment it has offered will more likely yield $24.0 million annually than $7.0 million. Additionally, load-growth and high natural gas prices will both magnify the level of the benefits. Both of these conditions are so likely as to be nearly certain. However, even if the Commission considers the benefits at a conservative level and the detriments at the "worst-case scenario" level, the Commission can impose conditions on the transfer that will mitigate any potential detriments.
NECESSARY CONDITIONS:
The Commission has authority to impose conditions on a proposed asset transfer in order to ensure that the transfer does not have detrimental effects. The Commission's Staff proposed a number of conditions.
1. RATEMAKING TREATMENT:
Staff advised the Commission, as is its practice in asset transfer cases, to state that no ratemaking treatment is intended. The Commission will continue its usual practice, with such exceptions as are noted below.
2. THE JDA:
Staff recommended that the Commission require amendment of the JDA: (1) to distribute profits from off-system sales on the basis of generation rather than load; and (2) to price the incremental inter-company energy transfers resulting from the Metro East transfer at market price rather than at incremental cost.
58 Staff further recommended that the Commission require UE to terminate the JDA if these amendments cannot be obtained.
Termination of the JDA would expose Missouri ratepayers to transmission charges on power generated at UE's Illinois and Iowa power plants. This was Staff's primary concern with respect to the transfer of the transmission facilities. The Commission will not include any condition requiring termination of the JDA.
UE has offered to make the first amendment to the JDA that Staff recommended and the Commission will require that condition. UE has not agreed to make the second JDA amendment recommended by Staff, but has committed to doing an analysis of inter-company energy transfer pricing with a view to possibly modifying the JDA in the future. However, the record shows, and the Commission has found, that the transfer would be detrimental to the public if the Commission does not impose a condition to address the possibility of a detriment from the inter- company energy transfer pricing currently in the JDA. If the Commission does not impose such a condition, the Ameren group could shift costs to Missouri ratepayers for the benefit of Ameren's unregulated activities. The Commission will impose a condition that requires revenues to be imputed to AmerenUE in a future rate case unless AmerenUE is able to prove that benefits directly resulting from the Metro East transfer exceed the difference between market price and incremental cost for incremental inter-company energy transfers.
Staff's recommendation, as proposed, would have the effect of reducing AmerenUE's Missouri revenue requirement to the benefit of Missouri ratepayers by an amount equal to the increased margins AmerenUE would receive from energy transferred to AEG at market prices rather than at incremental cost. That effect would occur, if Staff's proposed second JDA amendment is required, without
59 regard to whether the Metro East transfer otherwise produces benefits for Missouri ratepayers. If the Commission requires Staff's proposed second JDA amendment, and if actual results after the transfer demonstrate that the Metro East transfer provided affirmative benefits to Missouri ratepayers, Missouri ratepayers would receive both those increased margins caused by the second amendment to the JDA, in addition to the benefits that flowed from the Metro East transfer independent of this JDA issue. This result would unfairly penalize AmerenUE, so the Commission will not adopt the Staff's proposed second JDA amendment, but rather allow AmerenUE the opportunity in a future rate case to prove that benefits from the Metro East transfer outweigh revenues that it would have received if the second JDA amendment were required.
Specifically, the Commission will require that revenues be imputed to AmerenUE equal to the difference between the market prices AmerenUE could have received for the increased quantities of energy transferred to AEG as a result of the Metro East transfer and the incremental cost that AmerenUE actually received for such transfers under the JDA, unless AmerenUE is able to demonstrate, in its next general rate proceeding, that the benefits from the Metro East transfer exceed that difference. If AmerenUE meets its burden to demonstrate that such benefits exceed such difference, then revenues will not be imputed.
3. COSTS AND LIABILITIES:
Staff recommended a number of conditions relating to liabilities and costs, which are summarized here. Staff notes that these liabilities and costs fall into two categories, those directly assigned to the Illinois ratepayers and those allocated between Illinois and Missouri. Staff recommends that costs and
60 liabilities directly relating to UE's Illinois operations shall transfer to CIPS, whether arising pre-transfer or post-transfer. As to allocated costs and liabilities, Staff recommends that amounts allocated to UE's Illinois retail operations shall either transfer to CIPS or be separately tracked by UE in its books and records until either the amount that would have been allocated to Illinois is reduced to zero or UE can demonstrate savings due to the transfer that exceed those amounts. Staff further recommends that UE forego recovery of 8% of pre-closing generation- related liabilities, including litigation costs, employee-related items, product liabilities, and environmental-related capital costs and liabilities. Staff also recommends that UE be responsible for post-closing generation-related costs and liabilities, but shall be required to use its "best efforts to maximize contributions to offset these costs and liabilities from entities other than AmerenUE that receive the benefit of the power from these generation assets." Finally, Staff recommends that UE shall forego recovery of all pre-closing natural gas-related costs and liabilities.
The Commission is of the opinion that pre-closing liabilities that are directly assignable to UE's Illinois retail operations, or to the transferred assets, must transfer to CIPS as a condition of the Commission's approval of the transfer. Otherwise, the transfer would be detrimental to the public interest. To the extent that UE retains any such liabilities, contrary to the opinion of the Commission, such amounts shall be excluded from rates in the future.
With respect to allocated liabilities, the record shows that the proposed transfer would expose Missouri ratepayers to a risk of increased costs related to environmental and other pre-closing liabilities. Specifically, the increased risk is that Missouri ratepayers will have to pay the 6- percent share of such
61 potential liabilities now borne by the Metro East ratepayers. Most of these liabilities are presently unknown and it is not possible, consequently, to accurately assess this risk. In the absence of proof on this point, the Commission must assume that the risk is substantial. The record reveals that, when CIPS and CILCO transferred generation assets to Genco and AERG, they agreed to indemnify them for any pre-transfer, asbestos- related claims. UE's agreement with CIPS does not contain any such indemnity clause and UE has refused to agree to hold harmless its Missouri ratepayers with respect to the additional 6-percent share of this risk that the transfer will impose on them, although it has proposed conditions that will require Missouri ratepayers to pay the costs associated with this risk only if benefits to them are proven to outweigh such costs. The Commission is of the opinion that some such protective mechanism is necessary if the transfer is to occur. For that reason, the Commission will exclude 6-percent of any such liabilities arising from pre-closing events and conditions from UE's rates as a condition of its approval of the transfer, unless AmerenUE, in a future rate case where it seeks to recover 6-percent of such liabilities, is able to prove that benefits directly flowing from the Metro East transfer are greater than 6-percent of these liabilities. In addition to unknown environmental and other liabilities, this includes general corporate liabilities and pre-closing natural gas costs not directly assignable to UE's Illinois retail operations.
One pre-closing environmental liability is known, namely, the Sauget remediation. If the proposed transfer did not occur, the Metro East ratepayers would be responsible for 6-percent of the Sauget remediation costs. The Commission is of the opinion that the transfer of this liability to UE's Missouri ratepayers would be detrimental to the public interest. Therefore, as a
62 condition of its approval of the transfer, the Commission will exclude from rates 6-percent of any costs incurred by UE in the Sauget remediation unless, as with the other liabilities discussed above, UE can meet its burden to establish that such costs are outweighed by transfer- related benefits. The potential Sauget costs will therefore be treated like other liabilities discussed above.
The remaining category of liabilities concerns future capital investments required to meet increasingly stringent environmental standards. The Company is due a return of and on its capital investments dedicated to the public service and those amounts are collected from ratepayers in rates. These are generation-related costs and the generation resources will stay with UE; however, if the transfer did not occur, the Metro East ratepayers would be responsible for 6-percent of these costs. Staff's suggested condition was that UE use its "best efforts to maximize contributions to offset these costs and liabilities from entities other than AmerenUE that receive the benefit of the power from these generation assets." The Commission is of the opinion that the condition recommended by Staff on this point is unnecessary because the benefits of the proposed transfer outweigh these potential costs, even if realized at the level feared by Public Counsel. They may not be realized at that level. The Commission notes that potential prospective environmental liabilities of this sort are an inevitable quid pro quo of the use of relatively low-cost, coal-based generation.
4. SO2 ALLOWANCES:
The Commission has already adjusted the level of generation-related benefits to reflect the fact that the record shows that UE included a level of revenue from SO2 emission allowances sales that cannot be sustained over 25 years.
63 The Commission agrees with UE that the SO2 allowance bank management issue has no place in this case because it is not a matter directly related to the proposed transfer. Its relevance is the exposure of Missouri ratepayers to an additional 6-percent slice of any such costs as may actually occur. These costs, in fact, are included among the environmental liabilities discussed above. For this reason, the Commission is of the opinion that the further condition recommended by Staff on this point is unnecessary. If events ever do occur that call into question UE's prudence in managing its allowance bank, the Commission will take appropriate action at that time.
5. IDENTIFICATION OF ASSETS:
This issue was settled by the parties.
6. NATURAL GAS ISSUES:
Staff recommends that UE be required to renegotiate the Fisk/Lutesville, Alton and other Illinois gas transportation contracts as a package. Further, Staff recommends that Fisk/Lutesville pay rates no higher than Alton pays. Additionally, Staff recommends that UE hold harmless its electric customers from any change in costs due to the loss of the beneficial arrangement of its Illinois power plants and the Alton LDC.
The Commission is of the opinion that the conditions recommended by Staff on this point are unnecessary because the benefits of the transfer outweigh the potential detriment, even if Staff's "worst-case scenario" should occur. The record suggests that the potential detriments identified by Staff are not likely to occur and would have minimal impact if they did.
64 7. AFFILIATE TRANSACTION RULES:
Staff recommends that the Commission limit the waiver of the affiliate transaction rules to the pricing portion of the rules only and that the record-keeping portion of the rules should not be waived.
The Commission will not waive the record-keeping portion of the affiliate transaction rules.
8. THE NUCLEAR DECOMMISSIONING TRUST FUND:
UE has offered to contribute the $272,554 now collected from the Metro East ratepayers until the next triennial review. This offer is essentially equivalent to Staff's recommended condition on this point. The Commission will require the contribution offered by UE and will make the findings requested by UE to support the desired tax treatment of that contribution.
9. TRANSMISSION:
Staff recommends that the transfer be delayed until UE has done a study showing that there would be no detrimental impact on operations or revenue requirement. Staff further recommends that UE hold harmless its Missouri retail customers from any detrimental impact. Staff also recommends that UE forego recovery of any increased transmission costs solely due to the transfer. Staff also recommends that UE shall ensure that 405 MWs are available to replace the 405 MWs now obtained from EEInc.'s Joppa plant. Finally, Staff recommends that the Commission open a case to investigate Ameren's decision to not make 405 MWs available from EEInc.'s Joppa plant after December 31, 2005.
65 The Commission notes that UE has done the analysis requested by Staff. Therefore, that recommendation is no longer an issue.
The Commission does not need UE to agree to hold Missouri ratepayers harmless or to agree to forego recovery of increased transmission costs. In order to protect Missouri ratepayers from the risk of increased transmission costs resulting solely from the Metro East transfer, the Commission will exclude any such costs from UE's rates in the future as a condition of its approval of the transfer. The Commission agrees with UE that the record shows that such increased costs are unlikely. Dr. Proctor, who testified as to these possible costs, rated them as only 20- percent to 25-percent likely. Nonetheless, the level of these costs is such that additional protection for Missouri ratepayers is necessary.
The Commission considers the recommended conditions relating to the Joppa plant to be unnecessary. The record shows that the power received under the contract with EEInc. will be replaced by new capacity at the Venice plant. The Commission further considers that the record contains satisfactory explanations for the end of that contract.
10. ACCESS TO BOOKS, RECORDS, EMPLOYEES, AND OFFICERS:
Staff recommends that UE, Ameren, and UE's affiliates be required to make these available and to waive any claim that they are not available under PUHCA or because they are not in UE's possession or control.
The Commission is of the opinion that this condition is unnecessary because it has not waived the record-keeping requirements of the affiliate transaction rules.
The purpose of these conditions is to protect ratepayers by mitigating or avoiding the possible detriments. Set out below is an amended cost- benefit analysis reflecting the conditions adopted by the Commission. The figures changed by the above-conditions are in bold. The difference is now shown in the
66 Benefits column because, with the conditions adopted by the Commission, the benefits of the transfer will outweigh the possible detriments.
------DESCRIPTION BENEFITS DETRIMENTS ------Generation-related savings $ 0.900 million ------JDA amendment to share profits by generation $ 7.000 million ------Transmission-related savings $ 2.033 - 3.089 million ------Decommissioning Trust Fund issues ------JDA requirement that surplus UE power be available to -- $ 0 CIPS at incremental cost ------Possible transmission charges -- $ 0 ------Sauget remediation -- $ 0 ------Future environmental capital investments -- $ 5.100 - 7.000 million ------Natural gas: possible Fisk/Lutesville impact -- $ 0.010 million ------Natural gas: possible power plant impact -- $ 0.098 million ------TOTALS: $ 9.933 - 10.989 million $ 5.928 - 7.828 MILLION ------DIFFERENCE: $ 2.105 - 5.061 MILLION ------
CONCLUSION:
Based on its review of the Application, the testimony and exhibits adduced at the hearing, and the briefs, memoranda and arguments of the parties, and with the imposition of the conditions listed above, the Commission concludes that the proposed transfer is not detrimental to the public interest and should be approved. The Commission expressly notes that, in the absence of these conditions, the transfer would cause a substantial detriment to the public interest such that it could not be approved.
IT IS THEREFORE ORDERED:
1. That the Motion for Issuance of a Preliminary Order, filed by AmerenUE, on October 4, 2004, is denied.
67 2. That the Application filed on August 25, 2003, by AmerenUE, is approved, subject to the conditions herein set out. AmerenUE is hereby authorized to transfer its electric and natural gas retail operations in Illinois, including associated system assets, to AmerenCIPS, including normal additions and retirements since December 31, 2003; and is further authorized to perform in accordance with its Asset Transfer Agreement with AmerenCIPS. The parties are further authorized to take such other lawful actions as may be reasonably necessary to consummate the transaction herein authorized.
3. That the Commission hereby waives the pricing portion, but not the record-keeping requirements, of Commission Rules 4 CSR 240-20.015 and 4 CSR 250-40.015, pertaining to Affiliate Transactions, with respect to the Application approved in Ordered Paragraph 2, above.
4. That AmerenUE shall amend its Joint Dispatch Agreement to provide that profits from off-system sales are shared on the basis of generation output rather than based on load.
5. That, in a future rate case, revenues equal to the difference between the market prices AmerenUE could have received for incremental (i.e., as a result of the transfer herein authorized) energy transfers between the companies governed by the Joint Dispatch Agreement and the revenues AmerenUE actually received for such transfers will be imputed unless AmerenUE proves by a preponderance of the evidence that benefits directly flowing from the transfer authorized herein are greater than that difference.
6. That Union Electric Company, doing business as AmerenUE, shall annually contribute $6,486,378 to the Decommissioning Trust Fund with respect to its Missouri-jurisdictional operations pending the further order of this Commission.
68 This amount is included in Union Electric Company, doing business as AmerenUE's Missouri-jurisdictional cost-of-service for ratemaking purposes and is established based on the economic and financial input parameters used in the "Zone of Reasonableness" analysis attached as Schedule 4 to Exhibit 2 received in this proceeding. Union Electric Company, doing business as AmerenUE, shall transfer 98-percent of the contents of the Illinois Retail Subaccount to the Missouri Retail Subaccount.
7. That AmerenUE may seek recovery in a future rate proceeding (a rate increase or an excess earnings complaint) of up to 6% of the unknown generation-related liabilities associated with the generation that was formerly allocated to AmerenUE's Metro East service territory, if it proves by a preponderance of the evidence that the sum of the Missouri ratepayer benefits attributable to the transfer in the applicable test year is greater than the 6% of such unknown generation-related liabilities sought to be recovered. AmerenUE will be entitled to recover that part of the 6% that is offset by benefits directly flowing from the transfer. Transfer-related benefits in this Paragraph and Ordered Paragraph 5 may only be used once (that is, the same dollar amount of transfer-related benefit cannot be used to offset unknown generation-related liabilities sought to be recovered pursuant to this Paragraph and to offset revenues imputed pursuant to Ordered Paragraph 5).
8. That Union Electric Company, doing business as AmerenUE, as a condition of the approval herein contained, shall not recover in rates any portion of any increased costs due solely to transmission charges for the use of the transmission facilities herein transferred to AmerenCIPS to the extent that the costs in question would not have been incurred had the facilities not been transferred.
69 9. That by closing the Metro East transfer and transferring the Metro East assets pursuant to the permission granted herein, AmerenUE shall and hereby is deemed to have consented to each and every condition imposed by this order.
10. That nothing in this order shall be considered a finding by the Commission of the value for ratemaking purposes of the properties, transactions or expenditures herein involved, except as is expressly stated to the contrary. The Commission reserves the right to consider any ratemaking treatment to be afforded the properties, transactions and expenditures herein involved in a later proceeding.
11. That the three Stipulations and Agreements submitted by the parties during the course of this proceeding, relating to charges by AMS (Ex. 33), the 13.8kV switchgear at the Venice generating plant (Ex. 60), and the Asset Transfer List (Ex. 67), are hereby approved. The parties are directed to comply with the terms of these agreements.
12. That Union Electric Company, doing business as AmerenUE, shall file a pleading in this case within ten (10) days of the consummation of the transfer herein authorized, so advising the Commission.
13. That Staff's Motion for Leave to File the Affidavit of Dr. Proctor, filed on April 27, 2004, its Motion for Leave to Late-file its Initial Brief, filed on May 18, 2004, and its Motion for Leave to Late-file its Table of Contents and Conclusions to its Initial Brief, filed on May 19, 2004, are granted. All other pending and unruled motions are denied.
14. That this Report and Order shall become effective on February 20, 2005.
70 15. That this case may be closed on February 21, 2005.
BY THE COMMISSION
DALE HARDY ROBERTS SECRETARY/CHIEF REGULATORY LAW JUDGE
( S E A L )
Davis, Ch., Murray and Appling, CC., concur; Gaw, C., dissents, with dissent to follow; Clayton, C., dissents; certify compliance with the provisions of Section 536.080, RSMo 2000.
Dated at Jefferson City, Missouri, on this 10th day of February, 2005. EXHIBIT D-8(a)
STATE OF MISSOURI PUBLIC SERVICE COMMISSION
At a session of the Public Service Commission held at its office in Jefferson City on the 10th day of March, 2005.
In the Matter of the Application of Union Electric ) Company, Doing Business as AmerenUE, for an ) Order Authorizing the Sale, Transfer and ) Assignment of Certain Assets, Real Estate, Leased ) CASE NO. EO-2004-0108 Property, Easements and Contractual Agreements ) ------to Central Illinois Public Service Company, Doing ) Business as AmerenCIPS, and, in Connection ) Therewith, Certain Other Related Transactions )
ORDER DENYING APPLICATION FOR REHEARING AND GRANTING MOTION FOR CLARIFICATION
On February 18, 2005, the Office of the Public Counsel filed its Second Application for Rehearing. Pursuant to Section 386.500, RSMo 2000, the Commission shall grant a rehearing if in its judgment there is sufficient reason to do so. Public Counsel has not provided sufficient reason for the Commission to grant a rehearing, and the Commission will deny the application for rehearing.
Also on February 18, Union Electric Company d/b/a AmerenUE filed a motion for clarification. AmerenUE states that it believes it will be impossible to timely receive all necessary regulatory approvals for the changes to the Joint Dispatch Agreement (JDA) required in the Report and Order on Remand. The Report and Order on Remand, at Ordered Paragraph 4, required AmerenUE to "amend its [JDA] to provide that profits from off-system sales are shared on the basis of generation output rather than based on load."
AmerenUE states that it has a deadline of April 22, 2005, pursuant to its contract with Noranda Aluminum, Inc., by which it must advise Noranda whether or not it will be able to serve Noranda's load pursuant to that contract. AmerenUE also states that the contract provides that service to Noranda will begin on June 1, 2005, if the Commission grants approval in Case No. EA-2005-0180. AmerenUE does not believe that it will receive all necessary approvals for amending the JDA in time to meet those dates.
The Report and Order on Remand does not explicitly require that modifications to the JDA gain all necessary approvals and be implemented before the transaction closes. It requires the JDA amendments, and authorizes the Metro East transfer, but does not require that the latter be completed before the former can take place. AmerenUE asks that the Commission clarify that the Report and Order on Remand allows it to proceed with closing the Metro East transfer, even though all regulatory approvals have not been granted, and the modifications to the JDA have not been implemented. AmerenUE also states, that for ratemaking purposes in future rate cases, the Commission should deem the first JDA amendment to have been made by the AmerenUE as of the date the Metro East transfer is closed. AmerenUE states that it is willing to quantify and maintain accounting records of the impact the first JDA amendment would have had if it would have been in effect on the date of the Metro East transfer.
On March 9, 2005, in response to a Commission order, AmerenUE provided additional information about the process of modifying the JDA. AmerenUE stated
2 that the only regulatory approval required would be from the Federal Energy Regulatory Commission (FERC), that AmerenUE had not yet applied to the FERC for approval, and that it could not make any valid prediction of the amount of time it might take to obtain approval from the FERC.
No party responded to AmerenUE's motion for clarification. The request is reasonable, since Missouri ratepayers are completely protected even if the FERC does not approve the JDA amendment, or if approval is delayed until after AmerenUE rates are changed in a future proceeding. The Commission will grant AmerenUE's motion for clarification.
IT IS THEREFORE ORDERED:
1. That the application for rehearing filed by the Office of the Public Counsel on February 18, 2005, is denied.
2. That the Motion for Clarification filed by Union Electric Company d/b/a AmerenUE on February 18, 2005, is granted, and Union Electric Company d/b/a AmerenUE shall quantify and maintain accounting records of the impact the first Joint Dispatch Agreement amendment would have had if the amendment had been in effect on the date of the Metro East transfer.
3 3. That this order shall become effective on March 10, 2005.
BY THE COMMISSION
DALE HARDY ROBERTS SECRETARY/CHIEF REGULATORY LAW JUDGE
( S E A L )
Davis, Ch., Murray and Appling, CC., concur Gaw and Clayton, CC., dissent
Mills, Deputy Chief Regulatory Law Judge
4 EXHIBIT D-12
108 FERC P. 61,081 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION
OPINION NO. 473
Ameren Energy Generating Company and Docket Nos. EC03-53-000 Union Electric Company, d/b/a AmerenUE EC03-53-001
OPINION AND ORDER AFFIRMING INITIAL DECISION IN PART, DENYING REQUESTS FOR REHEARING AND ANNOUNCING NEW GUIDELINES FOR EVALUATING SECTION 203 AFFILIATE TRANSACTIONS
Issued: July 28, 2004 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION
Ameren Energy Generating Company and Docket Nos. EC03-53-000 Union Electric Company, d/b/a AmerenUE EC03-53-001
OPINION NO. 473
APPEARANCES
Douglas O. Waikart, Esq., David S. Berman, Esq., and Kristian M. Dahl, Esq. on behalf of Ameren Energy Generating Company and Union Electric Company d/b/a AmerenUE.
Peter W. Brown, Esq., David K. Weisner, Esq., and Richard C. Mooney, Esq. on behalf of NRG Power Marketing, Inc., and NRG Audrain, LLC.
Larry F. Eisenstat, Esq., Michael Wentworth, Esq., and Danielle K. Schonback, Esq., on behalf of the Electric Power Supply Association.
Joel M. Cockrell, Esq. and Arnold H. Meltz, Esq. on behalf of the Federal Energy Regulatory Commission. 108 FERC P. 61,081 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, Joseph T. Kelliher,
and Suedeen G. Kelly.
Ameren Energy Generating Company and Docket Nos. EC03-53-000 Union Electric Company, d/b/a AmerenUE EC03-53-001
OPINION NO. 473
OPINION AND ORDER AFFIRMING INITIAL DECISION IN PART, DENYING REQUESTS FOR REHEARING AND ANNOUNCING NEW GUIDELINES FOR EVALUATING SECTION 203 AFFILIATE TRANSACTIONS
(Issued July 28, 2004)
1. In a Hearing Order,/1/ the Commission set for hearing the effect on competition of a proposed disposition from Ameren Energy Generating Company (AEG) to its corporate affiliate Union Electric Company d/b/a AmerenUE (AmerenUE) (collectively, Applicants) of jurisdictional facilities associated with the sale of certain generating assets. The Presiding Administrative Law Judge (judge) issued an Initial Decision/2/ finding that the proposed transaction will not have an adverse effect on competition. As discussed below, we affirm the Initial Decision in part, with discussion of certain findings. Since we already found in the Hearing Order that the proposed disposition has no adverse effect on rates and regulation,/3/ we will authorize the proposed disposition of facilities as consistent with the public interest.
2. In addition, as discussed below, we announce our expectations for future section 203 transactions involving disposition of jurisdictional facilities between affiliates (hereinafter called affiliate transactions). The Commission
1 Ameren Energy Generating Company, Union Electric Company, d/b/a AmerenUE, 103 FERC P.61,128 (2003 (Hearing Order).
2 Ameren Energy Generating Company and Union Electric Company, d/b/a AmerenUE, 106 FERC P.63,011 (2004)(Initial Decision).
3 See 103 FERC P.61,128 at P 53 and P 59. Docket Nos. EC03-53-000 and EC03-53-001 - 2 - has concluded that there should be more definition as to what showing is adequate to demonstrate that a proposed affiliate transaction will not harm competition or otherwise be inconsistent with the public interest. The objective of this policy is to ensure that the conduct of competitive solicitations involving affiliates does not harm competitive markets by favoring those affiliates and foreclosing opportunities to competition. This policy will allow us to quickly identify affiliate transactions that are unlikely to involve affiliate abuse and can be approved without a trial- type hearing. This expectation will be applied prospectively to avoid regulatory effect on transactions already filed for Commission approval, i.e., filed as of the date of issuance of this order.
3. This order benefits customers by approving this acquisition for AmerenUE to better serve its load and by clarifying Commission policy on affiliate acquisitions.
I. BACKGROUND
A. APPLICATION
4. AmerenUE, a subsidiary of the Ameren Corporation (Ameren), provides wholesale and retail electric service and retail gas service to customers in Missouri and Illinois./4/ AmerenUE owns about 8,500 megawatts (MW) of generating capacity and also purchases power to meet its peak load, which exceeded 8,600 MW in 2002. Central Illinois Public Service Company d/b/a AmerenCIPS (AmerenCIPS), also a subsidiary of Ameren, provides retail electric and gas service to customers in Illinois. Both AmerenUE and AmerenCIPS provide transmission service under the Ameren Open Access Transmission Tariff, and Ameren has joined the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) through GridAmerica, an independent transmission company.
5. AEG owns generating resources of approximately 4,600 MW and sells wholesale power to its affiliate, Ameren Energy Marketing Company (AEM), and to non-affiliates./5/ AEG owns the Pinckneyville, Illinois generation facility (Pinckneyville), consisting of eight combustion turbine generator units with a total capacity of 316 MW, and the Kinmundy, Illinois generation facility (Kinmundy), consisting of two combustion turbine generator units with a total capacity of 232 MW.
4 AmerenUE serves wholesale electric load (at market-based rates) only in Missouri. Most of its retail electric load is in Missouri, where retail service has not been deregulated. Retail electric service has been deregulated in Illinois.
5 AEG does not own a transmission system and does not provide retail service. Most of AEG's resources were transferred to it from AmerenCIPS in 1999. AEM's purchases from AEG are principally resold to AmerenCIPS and used to serve AmerenCIPS' retail customers. Docket Nos. EC03-53-000 and EC03-53-001 -3-
6. On February 5, 2003, AEG and AmerenUE filed an application under section 203 of the Federal Power Act (FPA)/6/ requesting Commission authorization for the transfer of certain jurisdictional transmission facilities associated with the sale of the Pinckneyville and the Kinmundy facilities from AEG to AmerenUE (proposed transaction). Upon consummation of the transaction, AmerenUE would own an additional 548 MW of generation capacity.
7. According to Applicants, the purpose of the transaction is to enable AmerenUE to meet its peak load requirements, both short-term and long- term, including planning reserve requirements (15 percent for 2003 and 17 percent for 2006) of the Mid-America Interconnected Network, Inc. (MAIN) regional reliability council. Applicants state that to meet its peak load requirements AmerenUE needs an additional 543 MW in 2003, increasing to 991 MW in 2006.
8. Applicants argued that AmerenUE's decision to meet its needs by buying the Pinckneyville and Kinmundy plants was a reasonable one that does not reflect affiliate preference. Applicants stated that the choice of these plants was based on AmerenUE's resource planning process and was consistent with a Stipulation and Agreement (Missouri Stipulation) among AmerenUE, the Missouri Public Service Commission (Missouri Commission) Staff and other entities that was approved by the Missouri Commission./7/ Applicants also asserted that the proposed price of the facilities was reasonable, in comparison with other recent sales of similar types of generating capacity used for peaking purposes. According to Applicants, AmerenUE analyzed several options in addition to the proposed purchase, such as purchasing power on the market, purchasing existing assets from non-affiliates, and building new capacity, before reaching a decision.
6 U.S.C. sess.824b (2000).
7 The Missouri Stipulation requires AmerenUE to acwuire 700 MW of new "regulated" generating capacity by June 30, 2006, and specifically states that this requirement may be met by the purchase of generation plant from an Ameren affiliate at net book value. The Missouri Stipulation also requires that AmerenUE construct new transmission lines and transmission upgrades that will increase transmission import capability by 1,300 MW. In addition, the Missouri Stipulation provides that retail rates will remain frozen, except for certain specified rate decreases, through June 30, 2006. Docket Nos. EC03-53-000 and EC03-53-001 -4-
B. HEARING ORDER
9. Section 203(a) of the FPA provides that:
No public utility shall sell, lease, or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $50,000, or by any means whatsoever, directly or indirectly, merge or consolidate such facilities such facilities or any part hereof with those of any other person, or purchase, acquire, or take any security of any other public utility, without first having secured an order of the Commission authorizing it to do so./8/
10. In 1996, the Commission issued the Merger Policy Statement setting forth procedures, criteria and policies applicable to public utility mergers and other dispositions of jurisdictional facilities./9/ The Merger Policy Statement and Order No. 642,/10/ which sets forth the Commission's filing requirements for section 203 applications, provide that the Commission will generally take account of three factors in its section 203 analysis: (a) the effect on competition; (b) the effect on rates; and (c) the effect on regulation.
11. In the Hearing Order, the Commission found that while the proposed transaction would have no adverse effect on rates and regulation, Applicants had not shown that the proposed transaction would not adversely affect competition. The Commission noted that the proposed transaction was the second time within a very short period that our approval had been sought for this type of affiliate transaction. In the prior case, Cinergy Services, Inc., et al., we approved the transaction but expressed our concern over the possible implications of these types of affiliate transactions./11/ We noted that "the ability of a franchised utility to assume its affiliated merchant's generation when market demand declines gives the affiliated merchant a 'safety net' that merchant generators
8 16 U.S.C. ss.824b(a) (2000).
9 See Inquiry Concerning the Commission's Merger Policy under the Federal Power Act: Policy Statement, Order No. 592, 61 Fed. Reg. 68,595 (1996), FERC Stats. & Regs. P.31,044 at 30,117-18 (1996), order on reconsideration, Order No. 592-A, 62 Fed. Reg. 33, 341 (1997), 79 FERC P.61,321 (1997) (Merger Policy Statement).
10 Revised Filing Requirements Under Part 33 of the Commission's Regulations, FERC Stats. & Regs., Regs. Preambles July 1996 - December 2000 P. 31,111 (2000) (Order No. 642), order on reh'g, Order No. 642-A, 66 Fed. Reg. 16,121 (22001), 94 FERC P.61,289 (2001).
11 102 FERC P.61,128 at 61,345 (2003), reh'g pending (Cinergy). Docket Nos. EC03-53-000 and EC03-53-001 -5- not affiliated with a franchised utility lack."/12/ We expressed concern that "the existence of a safety net may affect the incentive of new merchant generators to invest in new facilities," erecting a barrier to entry that harms the competitive process and raises prices to customers in the long run "because affiliated merchant generation with a safety net option will not be subject to the price discipline of a competitive MARKET."/13/ We further indicated, in Cinergy, that in light of our concerns, we would modify our future approach to analyzing the competitive effects of intra-corporate transactions of this nature.
12. In the Hearing Order, we stated that Applicants' proposed transaction presented the types of competitive concerns we expressed in Cinergy. We further stated that we had no established standards to evaluate section 203 affiliate transactions to ensure that affiliate abuse has not occurred. In contrast, we noted, we do have such standards, developed in Boston Edison Company Re: Edgar Electric Co.,/14/ for evaluating the justness and reasonableness of a franchised utility's wholesale transactions (contracts) involving an affiliate to ensure that affiliate abuse has not occurred and to ensure prices that are consistent with competitive outcomes. That case presents several examples of how a utility can demonstrate that there was no affiliate abuse. We stated that the two situations are similar and that a franchised utility should be required to demonstrate that its purchase of an affiliate's plant is on terms similar to any other competitive alternatives available. Finally, we expressed our concerns regarding the adequacy of the evidence offered by Applicants and, therefore, we set the proposed transaction for hearing to examine its possible effects on competition.
12 Id.
13 Id.
14 55 FERC P.61,382 (1991) (Edgar). In Edgar, the Commission gave three examples of how to demonstrate lack of affiliate abuse: (1) evidence of direct head-to-head competition between affiliated and unaffiliated suppliers; (2) evidence of the prices that non-affiliated buyers were willing to pay for similar services from the affiliate; and (3) "benchmark" evidence of the prices, terms and conditions of sales made by non-affiliated sellers. These examples were not an all-inclusive list; the individual facts of a case could bring forth other examples not expressed in Edgar to show that a transaction is without affiliate abuse. -6-
13. On June 3, 2003, the Missouri Commission filed comments asking the Commission to reconsider the Hearing Order. On June 4, 2003, the Electric Power Supply Association (EPSA) filed a request for rehearing of the Hearing Order. On June 4, 2003, Applicants filed a request for rehearing of the Hearing Order and termination of the hearing procedures. On June 4, 2003, the Missouri Office of the Public Counsel (MOPC) filed a motion to intervene out of time./15/
C. INITIAL DECISION
14. In the Initial Decision, the judge found that there was no evidence of affiliate abuse in this case. The judge found that the proposed transaction is on terms similar to any other competitive alternatives available and is consistent with the public interest.
15. The judge concluded that AmerenUE had established that the proposed transaction would not have an adverse impact on competition. The judge found that because AmerenUE and AEG are affiliates, the proposed transaction will result in no change in market concentration. In addition, the judge stated that since the Commission has granted both AmerenUE and AEG market-based rate authority, the Commission believed that Ameren's wholesale markets were workably competitive. The judge further determined that AmerenUE's customers are adequately protected because AmerenUE was subject to a retail rate freeze through June 2006, and any subsequent retail rate filing would be subject to state review, thus hindering AmerenUE's ability to recover an acquisition premium from its ratepayers.
16. The judge also found that the Commission's safety net theory was not valid, and even if the theory is valid, the proposed transaction does not raise safety net concerns. The judge agreed with AmerenUE's and Trial Staff's witnesses, and found that before the safety net concern can be viewed as a valid competitive theory, there must be, among other things, evidence of a sale above market value. The judge found that there was no evidence here that the acquisition prices of the Pinckneyville and Kinmundy facilities at net book value were above market prices and concluded that the acquisition prices resulted from a competitive process. The judge further concluded that it had not been shown that the proposed transaction would have a significant effect on the cost of capital.
15 When late intervention is sought after the issuance of a dispositive order, the prejudice to other parties and burden upon the Commission of granting the late intervention may be substantial. Thus, movants bear a higher burden to demonstrate good cause for granting such late intervention. We do not believe that it is in the public interest to permit the MOPC motion to intervene in this proceeding at this late date. Docket Nos. EC03-53-000 and EC03-53-001 -7-
Moreover, the judge gave substantial weight to testimony that the safety net theory ultimately fails because it assumes widespread, systematic regulatory failure. In fact, the judge noted, the relevant state regulator - the Missouri Commission - has demonstrated that it is capable and willing to protect its retail customers.
17. Furthermore, the judge found that in the Hearing Order the Commission did not mandate the use of the Edgar examples in this case. Moreover, the judge determined that the facts in this case are clearly distinguishable from the circumstances in Edgar. Thus, the judge decided against a strict application of the Edgar examples. However, the judge held that the Edgar examples should be treated as guidelines for analyzing the proposed transaction.
18. In addition, the judge concluded that no evidence of affiliate abuse was present in AmerenUE's Request for Proposal (RFP) process. The judge found that AmerenUE used an adequate RFP process, which considered various non -affiliated suppliers but properly eliminated them as contenders for a variety of price and non-price reasons. She determined that the evidence demonstrated that there were no improvements to AmerenUE's transmission infrastructure since the RFP was issued in August 2001 that would make more viable those options that had been excluded due to transmission concerns. Furthermore, the judge found that there had been no material change in market fundamentals since the issuance of the RFP that would produce any significant difference in price. She concluded, therefore, that a more current RFP in this case would not be useful because it was unlikely to bring forth any viable new options.
19. EPSA and NRG Power Marketing, Inc. and NRG Audrain, LLC (jointly referred to as NRG) filed briefs on exceptions to the Initial Decision. Applicants and Commission Trial Staff filed briefs opposing exceptions.
20. On March 30, 2004, the Missouri Commission filed a motion to intervene out of time requesting leave to file an out-of-time brief, and a brief in response to the briefs on exception. The Missouri Commission states that it did not formally intervene/16/ earlier in this proceeding because it did not want appear
16 The Missouri Commission has participated in this proceeding through letters filed on March 18, 2003 (indicating that the proposed transfer was consistent with the Missouri Stipulation and that the Missouri Commission would protect Missouri retail customers from any adverse effects of the transfer) and on June 3, 2003 (stating that: (1) the option for AmerenUE to purchase generating plants from AEG was provided for in the Missouri Stipulation; (2) at the time of the Missouri Stipulation, AmerenUE's ability to purchase generating units from AEG was a known and viable option for meeting AmerenUE's infrastructure needs; and (3) the Missouri Commission prefers company-owned generation instead of power purchase agreements (PPAs) to meet Missouri load requirements and protect Missouri customers.) Docket Nos. EC03-53-000 and EC03-53-001 -8- to prejudge any prudence, reasonableness or other issues that might come before it arising out the proposed transfer to the transaction at issue. The Missouri Commission states that it now seeks to intervene to respond to certain allegations about its preferences with respect to the resource planning decisions of AmerenUE.
21. On April 9, 2004, EPSA filed a response to the Missouri Commission's motion to intervene out of time. On April 14, 2004, NRG did the same. On April 26, 2004, Applicants filed a response in support of the Missouri Commission's motion to intervene out of time.
II. REHEARING
A. SETTING MATTER FOR HEARING
22. EPSA argues that the Commission should reconsider the decision to set Applicants' section 203 application for hearing rather than rejecting it or sending a deficiency letter. EPSA contends that the application was incomplete because Applicants failed to address the concerns expressed by the Commission in the Cinergy order by doing an Edgar-type analysis. A complete application would have fully evaluated the effects of the proposed transaction on competition and ratepayers.
23. The courts have repeatedly recognized that the Commission has broad discretion in managing its proceedings./17/ Based on the written submissions in this proceeding, we concluded that there were issues of material fact concerning the competitive effect of Applicants' filing that were best resolved through a trial-type evidentiary hearing. Furthermore, a hearing has already taken place in these proceedings. Accordingly, EPSA's request for rehearing has been overtaken by events and, therefore, will be dismissed as moot.
17 See Vermont Yankee Nuclear Power Corp. v. Natural Resources Defense Council, Inc., 435 U.S. 519, 524-25 (1978) (agencies have broad discretion over the formulation of their procedures); Florida Municipal Power Agency v. FERC, 315 F.3d 362, 366 (D.C. Cir. 2003); Telecom Resellers Assoc. v FCC, 141 F.3d 1193, 1196 (D.C. Cir. 1998); Alabama Power Company v. FERC, 993 F.2d 1557, 1565 (D.C. Cir. 1993); Michigan Public Power Agency, et al. v FERC, 963 F.2d 1574, 1575, 1578-79 (D.C. Cir. 1992) (Commission has discretion to mold its procedures to the exigencies of the particular case); City of Lafayette, Louisiana v. SEC, 454 F.2d 941, 953 -5 (D.C. Cir. 1971) (same). Docket Nos. EC03-53-000 and EC03-53-001 -9-
B. JURISDICTION
24. Applicants argue that the Commission lacks jurisdiction over the generating assets at issue and therefore that any inquiry into the competitive effect of the transfer of these units is beyond the Commission's jurisdiction. They note that the Commission only has jurisdiction over a minor portion of the transaction -- the transfer of the facilities used to interconnect the Kinmundy and Pinckneyville units to the bulk transmission grid./18/ Applicants reason that since the Commission does not have jurisdiction over the transfer of generation assets, the Commission cannot use its jurisdiction over these minor transmission facilities to regulate indirectly what it cannot regulate directly; the Commission erred by using its jurisdiction over this minor portion of the transaction to consider the effects of the remainder of the transaction. Moreover, Applicants argue that the Commission did not identify, nor did anyone claim, that the proposed transfer of these interconnection facilities would have any adverse effect on competition. Furthermore, Applicants state that these interconnection facilities do not perform a transmission function.
25. We need not decide this point, since we find in any event that the proposed transaction is consistent with the public interest. As such, we approve the transaction. Furthermore, we note that even Applicants concede that the disposition of the interconnection facilities associated with the proposed transaction requires Commission authorization pursuant to section 203. When reviewing applications made under that section, the Commission evaluates the entire transaction to determine whether the proposed disposition of jurisdictional facilities is consistent with the public interest. If a portion of a transaction requires authorization under section 203, the overall effect of the transaction must be considered before approval may be granted./19/ We cannot ignore the full implications of a transaction for the public interest; the disposition of the transmission facilities is an integral part of the overall transaction.
18 Applicants estimate that the total value of the interconnection facilities is approximately five percent of the total value of the transaction.
19 See Iowa Southern Utilities Company, 35 FERC P.61,149 at 61,360, n.1 (1986) [The Commission determined that if a portion of a transaction requires authorization under section 203, the entire transaction is to be considered in determining whether the public interest is satisfied before approval may be granted.] See also Trans-Elect, Inc. et al., 98 FERC P.61,368 at 62,594 (2002); Niagara Mohawk Power Corp., et al., 89 FERC P.61,124 at 61,347 (1999); Duquesne Light Co., 88 FERC P.61, 248 at 61,793 (1999). Docket Nos. EC03-53-000 and EC03-53-001 -10-
C. MISSOURI STIPULATION
26. Applicants note that the proposed transaction is supported by the Missouri Commission, the only state commission affected by the transfer./20/ Moreover, they contend that when they entered into the Missouri Stipulation they relied on the Commission's pre-Cinergy precedent regarding intra-corporate transfers of generation, in which the Commission held that intra-corporate transactions generally do not present any concerns about harm to competition. Applicants argue that failure to approve the proposed transfer will undermine the Missouri Stipulation and the Missouri Commission's preference for AmerenUE to acquire dedicated assets to meet its load requirements.
27. The Missouri Commission affirms in its June 3, 2003 filing that infrastructure improvement was a fundamental component of the Missouri Stipulation and that AmerenUE's ability to purchase the generating units from AEG was a known and viable option for meeting capacity infrastructure needs at the time of the Missouri Stipulation. The Missouri Commission states that while it is mindful of the Commission's policy concerns expressed in Cinergy, the Missouri Stipulation became effective before Cinergy. It requests that the Commission recognize AmerenUE's need to acquire secure supplies. The Missouri Commission states that it prefers the certainty and reliability of dedicated assets and that AmerenUE's application to purchase the generating units is consistent with this preference and with the Missouri Stipulation. Moreover, the Missouri Commission states that it will review the prudence of the transaction.
28. The Missouri Commission is responsible for, and as a matter of law, can protect only Missouri retail customers, and not wholesale customers of public utilities or markets. In any event, this Commission has an independent obligation under the FPA to ensure that the disposition of facilities subject to our jurisdiction is consistent with the public interest, and we cannot abdicate
20 When the application was filed, the Illinois Commerce Commission (Illinois Commission) also had review authority over the proposed asset transfers. As we noted in the Hearing Order, 103 FERC P. 61,128 at P 48, the Illinois Commission had initiated a proceeding to address AmerenUE's proposed acquisitions. In that proceeding, the staff of the Illinois Commission had filed testimony urging the Illinois Commission to disallow the proposed asset transfer. Applicants state that on May 30, 2003, AmerenUE submitted a notice of withdrawal of its petition before the Illinois Commission. According to Applicants, AmerenUE has committed to transfer its Illinois retail service territory to AmerenCIPS. As a result, Applicants state, AmerenUE will no longer be an Illinois utility and therefore no Illinois Commission approval of this transaction will be required. Docket Nos. EC03-53-000 and EC03-53-001 -11- that responsibility or delegate it to the states./21/ This obligation requires the Commission to independently review this proposed transaction to ensure that it is consistent with the public interest.
D. SAFETY NET
29. Applicants argue that the Commission's focus on the competitive effect of this particular transaction is misplaced because this transaction is not a typical sale of merchant generation by an independent power producer to an affiliated IOU. They argue that AEG is not a true merchant generator, since the AEG units are designated resources (under a Commission-approved Joint Dispatch Agreement (JDA)) that are committed exclusively to serve load requirements before any output can be sold on the market. As a result, Applicants contend, AEG is closer to being a franchised utility than a true merchant generator. Applicants allege that after the transfer to AmerenUE, the generating units will continue to operate in the same manner and will continue to serve the same overall Ameren load (via the JDA). Thus, they argue, there can be no effect on competition and the safety net concerns are not valid here.
30. Applicants also argue that, as verified by an independent consultant, AmerenUE undertook a legitimate and unbiased analysis of the options available through a formal RFP process and, as a result, properly determined that the purchase of AEG's Kinmundy and Pinckneyville units was a reasonable one. Applicants further state that AmerenUE has adequately demonstrated that the price of the proposed transaction was within the range of recent, comparable sales.
31. We will address the safety net issues below.
III. DISCUSSION OF THE INITIAL DECISION FINDINGS
A. PROCEDURAL MATTERS
32. Since the issuance of the Hearing Order, the Missouri Commission has filed an untimely motion to intervene. When late intervention is sought after the issuance of a dispositive order, the prejudice to other parties and burden upon the Commission of granting the late intervention may be substantial. Thus, movants bear a higher burden to demonstrate good cause for granting such late intervention./22/
21 See, e.g., Northeast Utilities Service Co., 66 FERC P.61,332, reh'g denied, 68 FERC P.61,041, aff'd sub nom, Northeast Utilities Service Co. v FERC, 55 F.3d 686 (1st Cir. 1995).
22 See, e.g., Midwest Independent Transmission System Operator, Inc., 102 FERC P.61,250 at P 7 (2003). Docket Nos. EC03-53-000 and EC03-53-001 -12-
33. The Missouri Commission has a unique interest in representing retail customers that would be affected by the proposed transfer. In addition, the Missouri Commission states that it did not formally intervene earlier so as not to appear to prejudge prudence or other issues that may come before it. Under these circumstances, we believe that the public interest is served by allowing the Missouri Commission to intervene, and we find that to do so will not delay, disrupt or otherwise prejudice this proceeding or other parties to this proceeding. We will also accept the responses of EPSA, NRG and Applicants.
B. COMMISSION OPINION ON INITIAL DECISION
1. INTRODUCTION
34. After reviewing the record, the Initial Decision and the briefs, we find that this proposed transaction will not adversely affect competition, and therefore, is consistent with the public interest. While we largely affirm the judge's findings in the Initial Decision, we disagree with certain of the judge's findings and will discuss those as well other findings more fully below. In particular, we will discuss the following findings: (1) the "safety net" findings; (2) the application of the Edgar examples to section 203 filings; and (3) AmerenUE's Benchmark Analyses.
35. The Commission finds that the other issues were properly decided by the Initial Decision. We therefore deny the exceptions and affirm and adopt those findings.
2. DISCUSSION a. SAFETY NET ISSUE
36. Endorsing the reasoning of Trial Staff's witness Boner and Applicants' witnesses Frame and Asselstine, the judge dismissed the "safety net" hypothesis as theoretically unsound, lacking empirical basis, and unsubstantiated by the facts of this case./23/ She found that the proposed transaction resulted from a competitive process and that acquisition prices in this case were not proved to be above market value. Citing to witness Asselstine's testimony, the judge also found no evidence that potential non-affiliated generators generally face higher costs of capital in obtaining investment capital because lenders or investors perceive a safety net advantage for affiliated generator competitors. She further found no evidence that in this case, the developers of AEG's plants paid less for capital because of a perceived "safety net."/24/
23 106 FERC P.63,011 at P 44-51.
24 Id. P 45 -46. Docket Nos. EC03-53-000 and EC03-53-001 -13-
37. In addition, the judge agreed with Trial Staff's witness Boner and Applicants' witness Frame that in order for the safety net predictions to come true, there must be regulatory failure; i.e., the theory assumes that state and federal regulators will not prevent affiliate abuse and will allow recovery of above-market prices in their prudence reviews of the transaction when the acquiring entity attempts to include in its rate base the cost of the acquisition./25/ She also found persuasive witness Boner's point that even if the investment community perceives that there is a safety net for affiliated generators because of ineffective regulation in one state, possibly resulting in higher capital costs for potential non- affiliated generators that may locate in markets affected in that state, this would not be a barrier to entry into other markets. The judge placed great weight on the Missouri Commission's support for the transaction and its assurance that a state prudence review will be conducted in the future./26/
38. On exceptions, NRG claims that the Hearing Order did not set the validity of the "safety net" concerns for hearing. It also contends that the judge ignored the very important point made by witness Roach that the safety net concern does not assume regulatory failure, because even if regulation works perfectly, any remedy at the prudence review stage would be too late to protect the wholesale market from the adverse effects of intra-corporate transactions./27/
39. EPSA also criticizes the judge for rejecting both generically and specifically the safety net hypothesis and for relying on a regulatory commission's after-the fact review to prevent harm to wholesale competition. Rather, EPSA says, the Commission has long recognized that requiring a fair competitive process to be conducted up front is the best means to ensure long-term low-cost supplies. It also contends that an after-the-fact prudence review may actually harm ratepayers, since a disallowance could weaken the financial structure of the utility. EPSA questions whether the proposed transaction will in fact be reviewed at all if the next AmerenUE rate case results in a settlement without the prudence of the transaction being assessed. EPSA suggests that AmerenUE may be indirectly recovering the full purchase price of the units as a factor incorporated into the Missouri Stipulation, since the retail rates were conditioned on its ability to acquire affiliate genera- tion./28/
25 Id. at P 47.
26 Id. at P 48-49.
27 NRG Brief on Exceptions at 17-20; Exhibit No. EPS-15 at 16-21.
28 EPSA Brief on Exceptions at 32 -36. Docket Nos. EC03-53-000 and EC03-53-001 -14-
40. EPSA argues that the combination of a declining Midwestern power market, a glut of simple cycle generation, a rise in natural gas prices and the introduction of competition to serve AmerenCIPS's load in Illinois beginning in 2005 has exposed AEM (Ameren's marketing subsidiary) to increased market risk. EPSA believes that to reduce this risk or offset its effect, Ameren has an incentive to transfer excess capacity from AEG to its franchised AmerenUE subsidiary in order to meet AmerenUE's forecasted capacity deficits rather than making long- term purchases from non-affiliates. In this situation, even a transfer at net book value is a type of safety net, since AEG's investors would be fully recovering their investment at a time when other merchant generators are effectively forced to sell their assets at distressed prices. EPSA also asserts that the risk of not recovering fixed costs after placing the assets in regulated retail rate base would be less than trying to sell power in an unregulated market when AmerenCIPS' load would be subjected to wholesale competition. Further, since AmerenUE has no state- imposed earning limits, but does have market-based rate authority, EPSA argues that AmerenUE could offset any disallowance by the Missouri Commission through sales in the wholesale market./29/
41. EPSA challenges the evidence purporting to show that the safety net theory has no empirical basis. That evidence reflects the fact that this concern has only recently arisen because of declining wholesale markets. EPSA thus argues that whether a safety net was intended by the utility or was considered by investors is irrelevant, because the plants at issue were built at a time when rising market prices were anticipated. EPSA argues that a safety net will distort the cost of capital in favor of affiliated generators, since Applicants' own witnesses confirm that investors favor merchant capacity that can earn a steady cash flow, which would exist after a transfer of capacity to a franchised utility's rate base to serve captive load./30/
42. Trial Staff argues that because safety net concerns obviously were a factor in the Commission's decision to set the application for hearing, the judge properly considered both whether the safety net theory is valid in a general sense and whether in this case a safety net had harmed competition. Trial Staff contends that because price does not exceed market value, based on a comparison of prices of competing alternatives that takes account of non-price factors,/31/ no competitive harm has occurred even if a safety net does exist in this case. According to Trial Staff, a safety net cannot succeed without regulatory failure at either the wholesale level or retail level./32/ AmerenUE has no assurance
29 Id. at 31-32.
30 Id. at 36-40.
31 Trial Staff Brief Opposing Exceptions at 36-37.
32 Id. at 38 -40. Docket Nos. EC03-53-000 and EC03-53-001 -15- that it will be able to recover any premium paid above market value through market-based rates in the wholesale market because that market is workably competitive, or in cost-based wholesale rates, because the Commission will be able to review the affiliated transaction in reviewing any proposed wholesale rate increase (prudence review)./33/ In a similar vein, Trial Staff believes that AmerenUE cannot be assured of recovering any above-market payment in its retail rates because of the Missouri Commission's prudence review./34/
43. Trial Staff says it is unlikely that the safety net factor is so pervasive in the capital market as to raise the cost of capital and erect a barrier to entry for non-affiliated generators. It agrees with Applicants' witness Asselstine that differences in the cost of capital for affiliated generators versus non-affiliated generators are caused by other factors/.35/ Even if the regulator in a given state failed to prevent affiliate abuse, thereby possibly causing unaffiliated projects in that state to face a higher cost of capital, the cost of capital for unaffiliated projects versus affiliated projects in other states would not be affected and thus not impede entry by unaffiliated generators generally into the wholesale market. In this case, Trial Staff points out, the Missouri Commission has affirmed that it will review the prudence of the proposed transaction./36/
44. Applicants agree with the judge that the safety net theory assumes that regulators will not effectively scrutinize affiliate asset transactions for affiliate abuse. In this case, Applicants believe that the record is clear that the Missouri Commission will perform a rigorous prudence review of the transaction to assure that the transaction took place at market value, thus ensuring that Ameren has no incentive to take advantage of any safety net by paying an above-market price. Applicants also assert that the judge properly considered the Missouri Commission's support for the transaction, in conjunction with its prudence review, as similar to the role of the Indiana Utility Regulatory Commission's approval of the transaction at issue in Cinergy.
45. Applicants also state that notwithstanding her finding that the safety net hypothesis is unsound, the judge nevertheless evaluated whether the circumstances of the safety net hypothesis are met in this case and properly determined that such concerns are not present here. Most importantly, Applicants argue, there cannot be a safety net when the price of a transaction is at or below market value, as is the case here. The claim that regulatory review would come too late or be ineffective to remedy the supposed harm to competition is,
33 Id. at 35-36.
34 Id. at 38-40.
35 Id. at 38.
36 Id. at 37 -38. Docket Nos. EC03-53-000 and EC03-53-001 -16- in this case, irrelevant. Applicants point to testimony by witness Asselstine, who was involved with the financing of the AEG units, that the cost of capital was not affected by an "option to retreat" to regulation and that he received no inquiries from potential investors about a possible safety net in the AEG financings. Applicants also state that no evidence shows that Ameren had intended to take advantage of a safety net.
COMMISSION DETERMINATION
46. We agree with the judge that the validity of the safety net theory both generally and specifically in this case were proper issues to consider. We affirm the judge's finding that affiliate abuse did not occur; AmerenUE appropriately decided among alternatives on the basis of price and non-price factors. Therefore, AmerenUE's acquisition of the Pinckneyville and Kinmundy facilities will not represent an exercise of a safety net for Ameren and its subsidiaries.
47. However, we reverse the judge's findings that safety net is not a generally valid concern and that for a safety net transaction to harm competition, there must be regulatory failure and such regulatory failure must be widespread and systematic. In addition, the judge gave undue credence to the proposition that a utility that sells power in a competitive market, and thus is not guaranteed recovery of its costs, has no incentive to pay more than market value for a generating asset being used for sales for resale in interstate commerce, i.e., to engage in a safety net transaction that benefits its affiliate. As we explain below, the Commission continues to believe that affiliate acquisitions by their very nature raise concerns about the potential for discriminatory treatment in favor of the affiliate's plant, which can undermine competition and harm the public interest.
48. The Commission recognizes that effective regulatory review at the federal and state levels can prevent excessive rates to wholesale and retail customers respectively of the acquiring utility. However, our obligation under section 203 is to decide at the time a transaction is filed, and before it is consummated, whether the transaction will adversely affect competition and is consistent with the public interest. While effective state regulatory review can prevent excessive rates to the retail customers of the acquiring utility, it is not a remedy for the anticompetitive effects of affiliate preference, which harm all customers. The possibility of eventual regulatory review does not prevent the exercise of affiliate preference before the transaction occurs. We are also not convinced that such eventual regulatory review of rates is an effective remedy for anticompetitive effects that arise at the time affiliate preference occurs. Ultimately, all customers are harmed because competition is undermined. Docket Nos. EC03-53-000 and EC03-53-001 -17- b. APPLICATION OF EDGAR EXAMPLES IN SECTION 203 AFFILIATE CASES
49. The judge concluded that the Hearing Order did not require that the Edgar examples be strictly applied here. Noting that this transaction does not involve PPAs, the judge said that the Edgar examples cannot be strictly applied here because no credible alternatives exist to compare to the proposed transaction and because the benchmark evidence offered did not meet the relevancy criteria in Ocean State Power II./37/ The judge also noted that although only benchmark evidence was available in Ocean State, the Commission analyzed that evidence to determine whether abuse occurred. The judge agreed with Applicants that it is the affiliate presence that gives rise to the need to determine whether the proposed transaction reflects a competitive outcome. On that basis, and because a more specific test had not been proffered or adopted, the judge treated the Edgar examples only as guidelines in order to dispose of the ultimate issue of whether there was affiliate abuse and whether the transaction is above suspicion./38/
50. NRG disagrees and contends that the Commission clearly intended to have the Edgar examples strictly applied in this case, rather than merely used as guidelines. It argues that most of the Commission's specific requests for evidence on particular issues in the Hearing Order are relevant to the first Edgar example (evidence of head-to-head competition between the affiliated supplier and competing unaffiliated suppliers, either in a formal solicitation or an informal negotiation process). According to NRG, this first example requires that: (1) neither the design nor the implementation of the solicitation process unduly prefer the affiliate; (2) the analysis of the bids not favor the affiliate, particularly with respect to evaluation of price and non-price factors; (3) the selection of the affiliate be based on some reasonable combination of price and non- price factors; and (4) the applicant justify why it selected the affiliate if the affiliate was not the lowest-priced option. NRG challenges the judge's conclusion that this transaction is distinguishable from Edgar because there were no credible alternatives; it argues that based on this standard, the Applicants' transaction fails on all counts and is not the least-cost option after consideration of non-cost factors.
51. EPSA also urges the Commission to apply Edgar's examples strictly, rather than as only guidelines, given the strong circumstantial evidence of affiliate preference and the absence of any prior review by a state commission. EPSA notes that in Edgar, the Commission held that transactions must be "above suspicion in
37 59 FERC P. 61,360 (1992), reh'g denied, 69 FERC P.61,146 (1994)(Ocean State).
38 106 FERC P. 63,011 at P 70 -75. Docket Nos. EC03-53-000 and EC03-53-001 -18- order to ensure that the market is not distorted."/39/ It notes that the judge acknowledged that the proposed transaction does not satisfy the Edgar standard. Like NRG, EPSA states that the judge's conclusion that Edgar should only serve as a guideline stems from the assumption that no other viable alternatives remained with which to compare the proposed transaction. EPSA summarizes the Hearing Order as "simply looking to determine whether the proposed transaction is at least as good a deal as those offered by non-affiliates." A franchised utility like AmerenUE can always satisfy Edgar by conducting a fair, transparent and contemporaneous RFP, even if benchmark evidence is not available. However, according to EPSA, AmerenUE could not provide either evidence of actual head-to-head competition, through a fair and timely RFP, or valid benchmark evidence. A fair, transparent and contemporaneous process would have shown that viable alternatives exist, and AmerenUE has not shown that these alternatives were validly rejected on the basis of a combination of price and non-price factors.
COMMISSION DETERMINATION
52. The judge properly determined that although a strict application of the Edgar examples was not possible, Edgar could be used as a guideline to analyze the issues.
53. As discussed below, however, we believe that the competitive implications of intra-corporate asset transfers are similar to those of intra- corporate sales contracts; therefore, we will apply the standards developed in Edgar to future section 203 applications involving affiliated generation./40/ Moreover, as noted by the Federal Trade Commission (FTC):
FERC already has a policy in place (the Edgar policy) that is intended to promote objective make-or-buy decisions by utilities regarding contracts for power. Because the issues involved in affiliate asset transfers are similar to the issues involved in power supply contracts
39 Citing 55 FERC at 62,128.
40 As we have stated in a series of cases, we believe that affiliate preference, or the possibility thereof, whether in market-based or cost-based PPAs or in asset acquisitions, harms competition. See, e.g., Southern California Edison Company on behalf of Mountainview Power Company, LLC (Mountainview) 106 FERC P.61,183 (2004), reh'g pending: "We are also concerned that granting undue preference to affiliates, whether through cost-based or market-based transactions, could cause long-term harm to the wholesale competitive market. Affiliate preference could discourage non -affiliates from adding supply in the local area, harming wholesale competition and, ultimately, wholesale customers." Docket Nos. EC03-53-000 and EC03-53-001 -19- with affiliates are similar to those entailed by affiliate asset transfers, FERC may wish to consider a similar framework for reviewing affiliate asset transfers./41/ c. AMEREN'S BENCHMARK STUDIES
54. Applicants submitted testimony by Metcalfe/42/ and Voytas/43/ on benchmark evidence of comparable transactions in an attempt to meet the third Edgar example. Using coal and gas-fired plants over the years 2001 to 2003, both concluded that the net book value of the proposed transaction was within the range of benchmark prices. To enhance comparability, Trial Staff witness Fager modified their analyses to exclude plants outside the Eastern Interconnect, plants that are not gas-fired, and affiliate transactions./44/ As a result, the average price of the benchmark transactions in the revised analysis was $450/kW, compared to the average price of $467/kW of the Pinckneyville and Kinmundy transfers. Although she concluded that the remaining transactions in the revised analysis still lacked sufficient comparability to firmly support the price of the AEG plants, the judge noted that they were in line with the acquisition cost./45/ The judge found that both Metcalfe and Fager followed the standards of Ocean State,/46/ and gave both their studies substantial weight./47/
41 Comments of the Federal Trade Commission, Solicitation Processes for Electric Utilities and Acquisition and Disposition of Merchant Generation Assets by Public Utilities, Docket Nos. PL04-6-000 and PL04-9-000 (July 14, 2004) (FTC Comments) at 4.
42 Initial Decision, 106 FERC P.63,011 at P 202.
43 Id.
44 Id. at P 212.
45 Id. at P 236.
46 Id. at P 237-241.
47 Id. at P 238. Docket Nos. EC03-53-000 and EC03-53-001 -20-
55. EPSA contends that the benchmarks used by Applicants and Trial Staff fail to satisfy the strict Ocean State relevancy criteria for benchmarks./48/ Combined cycle plants were included in the benchmarks even though Ameren stated that combined cycle plants were unsuitable for its needs. Moreover, transactions in some cases are not comparable: plants that were part of "multifaceted" deals should also be excluded./49/ EPSA thus argues that the benchmark analysis does not "provide meaningful insight into the fair market price of the proposed transaction."/50/
56. NRG objects to the judge's treatment of the Ocean State criteria (requiring applicants to offer benchmark evidence of the market value, based on both price and no-price terms and conditions of contemporaneous transactions completed by nonaffiliated sellers for similar services in the relevant market) as guidelines./51/ Moreover, it objects to the judge's acceptance of Applicants' and Trial Staff's benchmark evidence. NRG argues that Applicants provided evidence of non-contemporaneous transactions by offering evidence of transactions that occurred before the collapse of Enron in December 2001 despite evidence that market conditions changed significantly after that time. It further objects to Applicants' inclusion of plants outside the Midwest as a part of the relevant market, and Applicants' use of NRG's initial purchase price of Audrain after NRG had offered it to AmerenUE at a substantially lower price./52/
COMMISSION DETERMINATION
57. EPSA is correct that these benchmark analyses provide little insight. The seven plants in Trial Staff Witness Fager's revised analysis use different technologies./53/ There is no trend or real sense of market conditions. Indeed, Fager gives only qualified support to the benchmark evidence, noting that she could "not verify the price is correct, although it has not been shown to be incorrect."/54/
48 EPSA Brief on Exceptions at 46, citing Initial Decision, 106 FERC P.63,011 at P 233.
49 Id. at 48, citing Tr. 853:18-855:7.
50 Id. at 52.
51 NRG Brief on Exceptions at 58.
52 Id. at 60-61.
53 Exhibit S-11.
54 Exhibit S -9 at 33. Docket Nos. EC03-53-000 and EC03-53-001 -21-
58. Furthermore, Trial Staff's revised analysis mistakenly included as Eastern Interconnect plants two plants (Frederickson and Manchief) shown in Exhibit S-11 that are actually in the Western Interconnect. Excluding these two plants reduces the average price of the benchmark transactions from $450/kW to $384/kW. The decline in the average price results almost entirely from the exclusion of Frederickson, which is by far the most expensive plant at $790/kW. The new maximum price is $485/kW, which is higher than the average price of the proposed transaction at $469/kW,/55/ but below Pinckneyville's price of $511/kW./56/ Thus, this benchmark analysis demonstrates very little. One very cheap or very expensive transaction can change the average price of the benchmark plants significantly.
IV. GUIDELINES FOR REVIEWING FUTURE SECTION 203 AFFILIATE TRANSACTIONS
59. In future section 203 applications that involve the acquisition of an affiliate's assets, we will review the transaction's effect on competition based on the standards developed in Edgar./57/ Acquisitions involving affiliates have an inherent potential for discriminatory treatment in favor of the affiliate. Affiliate preference when acquiring assets can have serious adverse effects on competition and may therefore not be consistent with the public interest. In determining that such acquisitions are consistent with the public interest, as section 203 requires, the Commission must assure that a public utility's acquisition of a plant from an affiliate is free from preferential treatment. The public interest requires policies that do not harm the development of vibrant, fully competitive generation markets.
60. Preferential procurement of an affiliate asset by a public utility may harm competition in electricity markets in a number of ways. These include raising entry barriers, increasing market power and impeding market efficiency. Such harm can adversely affect existing market conditions or impede innovation and efficiency in the long run. As noted by the FTC, "utilities may have both incentives and the ability to exercise market power and harm consumers by discriminating in favor of their own affiliates and against independent suppliers."/58/
55 Initial Decision, 106 FERC P.63,011 at P 236.
56 Id. at P 165.
57 Supra n.14.
58 FTC Comments at 1. Docket Nos. EC03-53-000 and EC03-53-001 -22-
61. Potential non-affiliated generators that perceive that affiliated generators have a "safety net" available to them may be discouraged from entering the market. While after-the-fact prudence reviews by regulators may insulate ratepayers from the effects of a purchase price that is too high, they will not remedy the foreclosure of additional competitors from the market. The Commission must decide at the time of a section 203 application whether an acquisition will adversely affect competition or the public interest. Our responsibility under section 203 is to protect the public interest, and Congress intended us to take action before the disposition of facilities is consummated./59/
62. Affiliate preference in procurement may harm competition and thereby efficiency. If non-affiliated generators (i.e., wholesale competitors) leave or do not enter the market due to preferential procurement competition in wholesale markets will be harmed, and market concentration and market power may even increase. Further, if the utility's affiliate preference causes less efficient generation to be used and more efficient capacity to exit or not enter the market, the costs of providing power are unnecessarily higher. One such example would be when a more efficient generator exits the market because a key buyer, the franchised local utility, acquires a less efficient generating facility from an affiliate. In a competitive market, the less efficient generator would exit, resulting in more efficient dispatch and lower prices./60/
63. Preferential procurement also raises entry barriers by increasing the cost of unsuccessful entry. One of the factors a potential entrant would rationally consider before entering a market is the extent to which it is likely to recover its investment in fixed assets. A franchised public utility is generally a major purchaser of generation resources in a region and thus may have some degree of buyer market power, or monopsony power. Purchase of an asset through a utility
59 An analogous situation occurs in our consideration of another factor in our section 203 analysis, the effect of a disposition of facilities on rates. We do not postpone an analysis of the effect on rates until an acquiring utility makes a rate filing under section 205; under section 203, we also analyze the likely effect on rates of a disposition of facilities before we approve it.
60 See, FTC Comments at 10: "One potential adverse impact is that discrimination in affiliate transactions (procurement of generation assets or power supply contracts from affiliates at inflated prices, or below-market sales to affiliates) may result in the exit of more efficient generation assets and the retention of less efficient generation assets in the event, for example, that demand declines enough to force some exit from the market. In a market where capacity exceeds demand, some assets may exit from the market. Absent discrimination, the least efficient assets are the most likely assets to exit. In the presence of discrimination, less efficient assets owned by the utility or its affiliates are more likely to remain in the market while more efficient independent suppliers are forced to exit." Docket Nos. EC03-53-000 and EC03-53-001 -23- procurement to serve the utility's franchised load may be the best opportunity in some regions for a power plant investment to succeed or, in the event of failure, to recover its investment. In a less concentrated buyer's market (less monopsony power), a firm seeking to exit a particular market would sell its assets to other market participants for a fair market value. However, if a franchised utility has buyer market power, the price that the exiting firm will recover is likely to be less. This increased proportion of total costs likely to be unrecoverable by an exiting firm is a barrier to entry./61/
64. The Commission has not required a competitive analysis screen for intra-corporate transfers. The Commission found in the past that "anticompetitive effects are unlikely to arise with regard to internal corporate reorganizations or transactions."/62/ However, that statement referred to anticompetitive effects of a consolidation of generation - an increase in the market share of the acquiring firm, market concentration (e.g. the Herfindahl-Hirschman Index (HHI)), and potentially, an increase in market power. Today, to fulfill our responsibility under the FPA to analyze effects on the public interest generally, and on the competitiveness of markets in particular, we have come to the conclusion that a section 203 affiliate transaction is not consistent with the public interest unless shown not to be result of affiliate abuse. We conclude that, absent other compelling public interest considerations, we can no longer find a section 203 affiliate transaction to be consistent with the public interest unless the applicants demonstrate that appropriate steps were taken to safeguard against affiliate abuse, consistent with the Edgar standard.
65. As we explained in El Paso Electric Co., et al.,/63/ the Commission's view of what is "consistent with the public interest" necessarily evolves over time, as conditions change, and with experience. This is not the first time we have
61 See, e.g., DENNIS W. CARLTON AND JEFFREY M. PERLOFF, MODERN INDUSTRIAL ORGANIZATION (Addison Wesley 2nd ed. 1994) at 111: "An important consideration in understanding a firm's incentive to enter an industry is, paradoxically, the firm's ability to exit the industry. If it is costly to exit an industry, the incentives to enter are reduced." See also FTC Comments at 11: "Absent discrimination, any specific generation entrant can reasonably expect to sell its generation assets at the fair market price in the event that its entry fails. In the presence of discrimination by utilities, the selling price for liquidated stand-alone generation assets is likely to be lower where the distribution utility in the area is one of the most likely purchasers of such assets, absent discrimination, or where there are few potential buyers. The result of this increased risk is that entry becomes less likely." (footnote omitted)."
62 Order No. 642 at 31,902.
63 68 FERC P.61,181(1994) (El Paso). Docket Nos. EC03-53-000 and EC03-53-001 -24- revised the focus of our analysis for section 203 transactions. For many years, we looked at six factors;/64/ in 1996, in the Merger Policy Statement, we said that we will generally look at three factors, the three we use today. Now the problem of affiliate abuse is frequently arising in section 203 cases.
66. In El Paso, we announced a transmission comparability standard for evaluating whether a transaction is consistent with the public interest. Our concern was, in part, that not offering comparable transmission service would be unduly discriminatory. We continue to believe that undue discrimination is an appropriate public interest consideration in evaluating transactions under section 203. Affiliate abuse is a form of undue discrimination. We have expressed our concern about affiliate abuse in a variety of contexts/65/ and have become increasingly concerned about the effect of affiliate abuse in cases involving the disposition of facilities in today's market conditions. To address these concerns, and to ensure that asset purchases from affiliates as well as purchase power contracts with affiliates are both reviewed for affiliate preference, we believe it is appropriate to evaluate section 203 transactions based on the Edgar standards used under section 205./66/
67. We note that there are three ways to demonstrate lack of affiliate abuse under the Edgar standard: (1) evidence of direct head-to-head competition between the affiliate and competing unaffiliated suppliers in a formal solicitation or informal negotiation process; (2) evidence of the prices which non-affiliated buyers were willing to pay for similar services from the affiliate; and (3) and benchmark evidence that shows the prices, terms and conditions of sales made by non-affiliated sellers. Because the market for generating assets is not nearly as liquid as the market for PPAs, a competitive solicitation through a formal RFP in future section 203 cases is likely to be the most effective way to show that an affiliate transaction is not marred by affiliate abuse. In the context of an acquisition of affiliated generation, a competitive solicitation is the most direct and reliable way to ensure no affiliate preference.
64 The six-factor approach was upheld in Utility Users League v. FPC, 394 F.2d 16 (7th Cir. 1968), cert. denied, 393 U.S. (1968).
65 See, e.g., Edgar, 55 FERC at 62,127-28; Mountainview, 106 FERC P. 61,183 at P 58-59.
66 We note the FTC recommended that the Commission consider such a policy for affiliated asset acquisitions as well as affiliate power sales. See FTC Comments at 4. Docket Nos. EC03-53-000 and EC03-53-001 -25-
68. We will not make competitive solicitations mandatory in this order. However, to the extent a utility demonstrates that its RFP process follows the guidelines discussed below, it should greatly reduce application processing time (including litigation) and increase the likelihood of timely Commission approval because an adequate showing of meeting the Edgar standard has been made. In other words, the guidelines described below will allow us to more easily identify transactions that are not consistent with the public interest, and, therefore, expedite their approval./67/
69. The fundamental objective of the solicitation guidelines is that the affiliate should have no undue advantage over non-affiliates in the solicitation process. Adhering to the guidelines will ensure that wholesale customers receive the benefit of the marketplace, including an unbiased assessment of the full range of choices, whether the soliciting utility provides service at cost- or market-based rates.
70. The solicitation guidelines have four principles: a. Transparency: the competitive solicitation process should be open and fair. b. Definition: the product or products sought through the competitive solicitation should be precisely defined. c. Evaluation: evaluation criteria should be standardized and applied equally to all bids and bidders. d. Oversight: an independent third party should design the solicitation, administer bidding, and evaluate bids prior to the company's selection./68/
67 This is similar to our use of the Appendix A "screens" adopted in the Merger Policy Statement to quickly identify transactions that are unlikely to harm competition. Largely due to these screens, this Commission has succeeded in reducing the amount of time necessary to analyze and approve section 203 applications.
68 We note that in a section 205 proceeding involving an affiliate power sales contract that is being issued concurrently, an independent consultant was selected by the state commission, and its compensation determined by the state commission, to monitor the RFP process. The independent consultant reported its findings to the state commission, which also supervised other aspects of the RFP process. See Allegheny Energy Supply Company, LLC, 108 FERC P. 61,082 (2004). Docket Nos. EC03-53-000 and EC03-53-001 -26-
71. These principles apply to different stages and aspects of the solicitation process. The transparency and oversight principles apply to all aspects of the competitive solicitation, the definition principle applies in the design of the RFP, the evaluation principle applies as bids are evaluated, and the oversight principle, like the transparency principle, applies to all aspects of the competitive solicitation. These principles are also interrelated. For example, oversight is effective only where there is transparency.
TRANSPARENCY PRINCIPLE
72. Transparency is the free flow of information to all parties. No party, particularly the affiliate, should have an informational advantage in any part of the solicitation process. The RFP and all relevant information about it should be released to all potential bidders at the same time. Instead of individually inviting specific bidders, the utility should allow all interested parties to bid on the RFP. All aspects of the competitive solicitation should be widely publicized. For example, the issuer can post the RFP on its website and issue a press release to that effect and/or advertise in the trade press. To compete effectively, bidders should have equal access to data relevant to the RFP. Any communication between RFP issuer and bidder that is not part of the bid should be made available to all other bidders. For example, the answers to clarifying questions should be released to all other bidders, but proprietary bid information should not be released.
73. These principles enhance the fairness and transparency of the entire process. Specific steps in the solicitation process may require more guidance to achieve optimal transparency. Two such examples are when a collaborative design is used or when post-bidding negotiation occurs.
74. If the RFP is to be designed through a collaborative process, the entire process should be widely publicized and open. An independent third party can ensure meaningful participation by nonaffiliates and eliminate characteristics that improperly give an advantage to the affiliate, e.g., the only acceptable interconnection point for a new nonaffiliate plant is at an affiliate's existing plant.
75. Negotiation may occur after the bidding; for example, when a shortlist has been compiled or a winner has been selected. If the affiliate is on the shortlist or wins, it is important to ensure that the affiliate has no undue advantage resulting from its affiliate relationship. One way to prevent such an advantage from occurring is for the independent third party to be the RFP issuer's agent in the negotiation with the affiliate. Docket Nos. EC03-53-000 and EC03-53-001 -27-
DEFINITION PRINCIPLE
76. The product or products sought through the RFP should be defined in a manner that is clear and nondiscriminatory. The RFP should state all relevant aspects of the product or products sought. At a minimum, these aspects include capacity and term, but other characteristics are usually necessary, among them fuel type, plant technology (e.g., simple cycle gas turbine), and transmission requirements. If there are changes in the product specification, rebids should be allowed.
77. An RFP should not be written to exclude products that can appropriately fill the issuing company's objectives. This is particularly important if such exclusions tend to favor affiliates. This approach will enable us to address a subsequent section 203 application proposing to acquire assets from an affiliate.
EVALUATION PRINCIPLE
78. To fulfill the evaluation principle, RFPs should clearly specify the price and nonprice criteria under which the bids are evaluated. Price criteria should specify the relative importance of each item as well as the discount rate to be used in the evaluation. Non-price criteria should also specify the relative importance of items such as firm transmission reservation requirements, including acceptable delivery points; credit evaluation criteria, such as the bond rating; the plant technology if more than one technology is listed in the RFP; plant performance requirements, such as availability; and the anticipated in-service date if the plant needs to be constructed.
79. Naturally, these criteria are not meant to be exhaustive; they are merely illustrative. Keeping in mind that affiliates should have no informational advantage, all criteria should be specific and detailed so that all bidders can effectively respond to the RFP. Clear evaluation criteria will ensure that the RFP does not give an advantage to the affiliate.
80. RFP issuer and bidders will usually need to divulge commercially sensitive information in the solicitation process. Confidentiality agreements between the issuer and bidders can be signed to address this concern.
OVERSIGHT PRINCIPLE
81. Effective oversight of competitive solicitations can be accomplished by using an independent third party in the design, administration, and evaluation stages of the competitive solicitation process. Ensuring that the third party is independent and granting it at the outset the responsibility of ensuring that these guidelines are followed throughout the process will also minimize Docket Nos. EC03-53-000 and EC03-53-001 -28- perceptions of affiliate abuse. Minimum standards for assuring independence and the scope of the third party's role are set forth below.
82. A minimum criterion for independence is that the third party has no financial interest in any of the potential bidders, including the affiliate, or in the outcome of the process./69/ Preferably, the independence criterion would be the same as that of an ISO or RTO./70/ In this context, "independence" means that the third party's decision-making process is independent of the affiliate and all bidders./71/ Without such independence, the third party could be biased towards the affiliate in order to enhance its financial position. Obviously, a similar concern could arise regarding an actual or potential financial interest link between the third party and any potential bidder. Independence can also be satisfied if the state commission has approved the selection of a third party on the basis of established independence criteria. In addition, the third party should not own or operate facilities that participate in the market affected by the RFP.
83. The independent third party should be able to make a determination that RFP process is transparent and fair, and that the RFP issuer's decision is not influenced by any affiliate relationships. For example, if the RFP issuer wishes to use a collaborative RFP design process, the independent third party should be the clearinghouse for comments by potential bidders on a draft RFP and should evaluate those comments as possible revisions to the RFP. The independent third party's role as the sole link for transmitting information between potential bidders and the RFP issuer would also help to ensure that the RFP design will not favor any particular bidder, particularly an affiliate. The independent third party should continue to be a conduit of information between utility and bidders in determining which of the original bid responses are qualified bids or may be included in a short list.
69 See, e.g., Technical Conference Comments of Maine Public Utilities Commission Chairman Welch, Conference on Solicitation Processes for Electric Utilities, Docket No. PL04-6-000, (June 10, 2004) (PL04-6 Conference) at Tr. 78.
70 See, e.g., Technical Conference Comments of John Hilke, Federal Trade Commission, PL04-6 Conference at Tr. 4.
71 Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (2000), FERC Stats. & Regs., Regulations Preambles July 1996 - December 2000 P. 31,089 at 31,061 (1999), order on reh'g, Order No. 2000- A, 65 Fed. Reg. 12, 088 (2000), FERC Stats. & Regs., Regulations Preambles July 1996 - December 2000 P. 31,092 (2000), affirmed sub nom. Public Utility District No. 1 of Snohomish County, Washington, et al. v FERC, 272 F. 3d 607 (D.C. Cir. 2001). Docket Nos. EC03-53-000 and EC03-53-001 -29-
84. At the evaluation stage of the RFP process, the third party should be able to credibly assess all bids based on both price and nonprice factors. It should be able to consider both generation asset bids and power purchase agreements. Also, it should be able to independently verify transmission characteristics that may limit the suitability of certain alternatives. The third party should have access to the same information that the RFP issuer uses in its evaluation and should be able to independently verify its correctness. The third party should also be able to evaluate nonprice traits of various alternatives.
The Commission orders:
(A) The Initial Decision in these proceedings is hereby affirmed in part, as discussed in the body of this order.
(B) The proposed transaction is authorized upon the terms and conditions and for the purposes set forth in the application.
(C) The foregoing authorization is without prejudice to the authority of the Commission or any other regulatory body with respect to rates, service, accounts, valuation, estimates or determinations of costs, or any other matter whatsoever now pending or which may come before the Commission.
(D) Nothing in this order shall be construed to imply acquiescence in any estimate or determination of cost or any valuation of property claimed or asserted.
(E) The Commission retains authority under sections 203(b) and 309 of the FPA to issue supplemental orders as appropriate.
(F) Applicants shall notify the Commission within 10 days of the date that the disposition of the jurisdiction facilities has been consummated.
(G) EPSA's request for rehearing of the Hearing Order is dismissed as moot, as discussed in the body of this order.
(H) Applicants request for rehearing of the Hearing Order is denied, as discussed in the body of this order.
By the Commission. Commissioner Kelliher dissenting in part with a separate statement attached. ( S E A L )
Magalie R. Salas, Secretary. UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION
Ameren Energy Generating Company and Docket Nos. EC03-53-000 Union Electric Company, d/b/a Ameren UE EC03-53-001
(Issued July 29, 2004)
Joseph T. KELLIHER, Commissioner dissenting in part:
I agree that the proposed disposition of facilities is consistent with the public interest and should be authorized. I am writing separately to explain my views on the new competitive solicitation policy announced in this order.
I do not support the new competitive solicitation policy for consideration of dispositions of affiliated jurisdictional facilities under section 203 of the Federal Power Act (FPA). Since 1991, the Commission has applied the Edgar policy to consideration of power purchase agreements involving affiliates under section 205 of the FPA. The policy announced in this order would expand that policy and extend it to dispositions involving affiliates.
In my view, the Commission's interest in proceedings under section 203 is fundamentally different from its interest under section 205. In a power purchase agreement involving an affiliate, the Commission has a legitimate interest in assuring that the process was fair, because we have a legal duty to assure just and reasonable rates and prevent undue discrimination or preference. In a section 203 proceeding, our interest is different because the legal standard is different. The Commission does not have a legal duty to assure that acquisitions of facilities are just and reasonable, or to prevent undue discrimination or preference in such dispositions. The public interest standard governs. While the Commission has discretion to determine just what that means, our interpretation must be guided by the fact that our legal duty to prevent undue discrimination and preference is limited to wholesale power sales and the transmission of electric energy in interstate commerce./1/ The disposition of a facility is neither. The Commission does not have a general charge to prevent any undue
1 See 16 U.S.C. ss. 824d (2000). Docket Nos. EC03-53-000 and EC03-53-001 et al. -2- discrimination or preference in the electricity industry, but only in these two discrete areas./2/
This competitive solicitation policy is designed to prevent an unfair solicitation in the acquisition of an affiliated facility by a public utility. I can appreciate that a competitive solicitation process can guard against a public utility overpaying or underpaying in such an acquisition. The Commission has a legal duty to prevent abusive self-dealing and cross-subsidies in jurisdictional services. However, it is the responsibility of a state commission, not this Commission, to ensure that a state-regulated utility does not subsidize an affiliate in the purchase of an asset. Like the presiding judge, I am not prepared to assume regulatory failure on the part of state commissions./3/
The Commission's interest in a jurisdictional disposition is on consideration of (1) the effect on competition, (2) the effect on rates, and (3) the effect on regulation./4/ The Commission previously found the proposed disposition in this order would have no adverse effect on rates and regulation,/5/ and I see no reason to disturb those findings. The narrow question before the Commission in this order is whether the proposed transaction would have an effect on competition. In my view, the principal inquiry should be the impact of a proposed disposition on a public utility's market power. By this measure, the proposed disposition would not have a negative effect on competition.
I agree with the criticisms of the "safety net" theory offered by both the presiding judge/6/ and Trial Staff./7/ Our competitive solicitations policy appears designed to guard against competitive impacts based on a theory that is speculative at best. I disagree with the competitive solicitations policy because I believe it is designed to solve a problem that does not exist, and
2 See generally NAACP v. Federal Power Commission, 425 U.S. 662, 664 (1976) (holding that the legislative intent of neither the Federal Power Act nor the Natural Gas Act included a "public interest" in eliminating employment discrimination).
3 The competitive solicitation policy may also be designed to ensure that nonaffiliated generators have access to cash infusions from asset sales. If so, this seems to go beyond the pale. The Commission has a legal duty to promote competition, not competitors.
4 See Merger Policy Statement.
5 See Hearing Order at P 53 and P 59.
6 See Initial Decision at P 44-51.
7 See Ex Nos. S -12R at 12 -24, AS -38 at 9 -19 and AS -75 at 13 -16. Docket Nos. EC03-53-000 and EC03-53-001 et al. -3- does not advance the Commission's ability to assess legitimate market power issues.
Joseph T. Kelliher EXHIBIT D-13
STATE OF MISSOURI PUBLIC SERVICE COMMISSION
At a session of the Public Service Commission held at its office in Jefferson City on the 25th day of July, 2002.
Staff of the Missouri Public Service ) Commission, ) ) Complainant, ) ) CASE NO. EC-2002-1 v. ) ------Union Electric Company, ) d/b/a AmerenUE, ) ) Respondent. )
REPORT AND ORDER APPROVING STIPULATION AND AGREEMENT
Syllabus: This order approves a settlement reached by the parties that, inter alia, requires Union Electric Company d/b/a AmerenUE to reduce rates by $110 million over three years, and provide a one-time credit of $40 million to its customers.
The evidentiary hearing in this case began on July 11, 2002. On July 12, the parties informed the Commission that they had reached an agreement in principle that would resolve all issues. The Commission recessed the hearing to allow the parties the opportunity to finalize the agreement and reduce it to writing. On July 16, most of the parties filed a Stipulation and Agreement that resolves all outstanding issues for the purpose of this case. Later that day, the only two parties that did not join in the agreement (Kansas City Power and Light Company and Laclede Gas Company) each filed a pleading in which each stated that it did not oppose the stipulation and waived a hearing. Pursuant to 4 CSR 240- 2.115, the Commission will treat the agreement as unanimous.
The agreement is somewhat complex, and its salient points will be discussed here. The agreement itself is attached to this order.
The first portion of the agreement deals with rate reductions and credits. AmerenUE agrees to make a one-time credit to its Missouri retail electric customers of $40 million. This credit is in settlement of Case Nos. EM-96-149, EC-2002-1025, and EC-2002-1059, all of which relate to the now-expired Experimental Alternative Regulation Plan. AmerenUE will reduce rates as of April 1, 2002, by $50 million. A credit reflecting the reduction in rates for the period between April 1 and the effective date of this order will be made to all customers. AmerenUE will again reduce rates on April 1, 2003, by $30 million, and again on April 1, 2004, by $30 million. The parties agree that none of them1/ shall file a case to institute a general rate increase or decrease before January 1, 2006.
The agreement also provides that AmerenUE will make necessary infrastructure investments during the period of time covered by the agreement. These investments include 700 megawatts of new capacity, upratings of existing
1 The agreement specifically exempts the Office of the Attorney General from this moratorium. While the question of the authority of the Attorney General's Office to file a case to change the rates resulting from this agreement has not been briefed, the reason for the exemption appears to be the Office of the Attorney General's desire to not concede its statutory or constitutional authority.
2 plants of 270 megawatts, and new transmission lines and upgrades to existing transmission lines that will increase import capability by 1300 megawatts. These investments will total $2.25 to 2.75 billion.
AmerenUE, as part of the agreement, also commits to make certain investments in the communities it serves. It will make an initial $5 million contribution to its Dollar More Program on September 1, 2002, and will contribute $1 million more each year for the next four years. It will create a weatherization fund for its low-income customers, and initially fund it with $2 million on September 1, 2002, and will contribute an additional $500,000 each year for the next four years. AmerenUE will also create a community development corporation and fund it with $5 million on September 1, 2002, and an additional $1 million each year for the next four years. Finally, AmerenUE will create a residential and commercial energy efficiency fund and fund it with $2 million on September 1, 2002, and an additional $500,000 each year for the next four years. All of these investments will be recorded below the line, and not treated as a regulated expense. The details for several of the programs will be worked out through the collaborative efforts of interested entities.
The agreement also contains a number of miscellaneous provisions. For example, AmerenUE will modify the way it calculated its dismantling costs and/or service lines for certain assets with the result that it will decrease its depreciation expense by approximately $20 million annually. AmerenUE also commits to provide to the signatories a cost of service study by January 1, 2006, covering the twelve months ending June 30, 2005. Collaborative efforts will also be used to design and implement a residential time-of-use pilot project, and to increase the amount of demand-response options (including interruptible load).
3 On July 19, 2002, the Staff of the Commission filed a memorandum in support of the agreement, as required by paragraph 15a of the agreement. Staff explains its rationale for entering into the agreement, and explains in some detail why the agreement is in the public interest. Staff tried to anticipate the questions the Commission might have regarding the agreement, and gave its answers to those questions.
On July 24, 2002, the Missouri Industrial Energy Consumers (MIEC), a group of AmerenUE's industrial customers, filed a response to the Staff memorandum. The MIEC explained that it supports the agreement for some of the same reasons as the Staff, but disagreed with others of the Staff's reasons. Also on July 24, the Staff filed an addendum to its memorandum, and a revised version of the attachment to the agreement. The addendum addresses and explains the provisions in the agreement about the decommissioning of the Callaway nuclear power plant, and raises an issue about the proper treatment of credits that would be due to AmerenUE customers that have been transferred to an electric cooperative pursuant to a Commission order. The revised attachment simply refines the calculations in the original attachment, resulting in a change of $.001 to one rate element in the second year of the moratorium period, and another change of the same amount to a rate element in the third year. Any party that objects to the revisions to the attachment must file a pleading raising its objection as soon as possible, and will be ordered to do so.
The Commission re-convened the hearing on July 24, 2002, for the purpose of asking questions of the parties and of the parties' witnesses. At
4 that hearing, all parties who had not already filed a response to the Staff's memorandum waived their right to do so. The Missouri Energy Group, a group of AmerenUE's industrial customers, concurred with the response to the Staff memorandum filed by the MIEC. The parties affirmed their support for the agreement, and explained why it is in the public interest. The Commission admitted into the record all of the prefiled testimony that had not already been admitted.
Pursuant to Section 536.060, RSMo 2000, the Commission may accept the agreement as a resolution of the issues in this case. The most compelling evidence supporting the conclusion that the agreement is in the public interest is the broad range of interests that entered into it. The parties include representatives of the spectrum of AmerenUE customers, from the small residential customers to the largest industrial customers. The parties also include other utilities and the Missouri Department of Natural Resources. For such a diversity of interests to be able to reach a comprehensive resolution of the 47 separate issues that were in dispute at the beginning of the hearing, the agreement must necessarily be in the public interest. The responses of the parties to Commission questions at the hearing on July 24 confirm this conclusion.
Another important consideration in the Commission's conclusion that the agreement is in the public interest is that it does not restrict the Commission's powers in any way. The Commission has the right under Section 386.390, RSMo 2000, to institute a complaint about the reasonableness of AmerenUE's rates, and that right is not affected by the agreement. Although the parties (see footnote 1) have agreed to give up some of their rights, the Commission does not, by approving the agreement, give up any of its rights. Furthermore, the Commission has broad oversight over AmerenUE in addition to its right to institute a rate complaint, and the agreement does not limit the Commission's oversight.
5 The Commission has reviewed the agreement, the memorandum in support of it and the responses to that memorandum, the testimony filed and admitted into the record, and finds the agreement to be reasonable and in the public interest and will, therefore, approve it.
IT IS THEREFORE ORDERED:
1. That the Stipulation and Agreement filed on July 16, 2002, is approved, and all parties shall be bound by its terms.
2. That any party that objects to the revisions, filed by the Staff of the Commission on July 24, 2002, to Attachment A to the Stipulation and Agreement must file a pleading raising its objection no later than July 30, 2002.
3. That this order shall become effective on August 4, 2002.
BY THE COMMISSION
DALE HARDY ROBERTS SECRETARY/CHIEF REGULATORY LAW JUDGE
(S E A L)
Simmons, Ch., Murray, Lumpe and Forbis, CC., concur Gaw, C., concurs, concurrence to follow
Mills, Deputy Chief Regulatory Law Judge
6 EXHIBIT F
[On Letterhead of Steven R. Sullivan, Esquire]
April 19, 2005
Securities and Exchange Commission 450 Fifth Street, NW Washington, DC 20549
Re: Ameren Corporation, et al. - File No. 70-10180
Dear Sirs:
I am Senior Vice President, General Counsel and Secretary of Ameren Corporation ("Ameren"), a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (the "Act"), and of its wholly-owned subsidiaries, Union Electric Company ("AmerenUE") and Central Illinois Public Service Company ("AmerenCIPS"). I am furnishing this opinion in connection with the Application/Declaration filed on Form U-1 jointly by Ameren, AmerenUE and AmerenCIPS (collectively referred to as the "Applicants"). I am an attorney licensed to practice law in the State of Missouri and have acted as counsel for the Applicants in connection with the Application.
In the Application, the Applicants request that the Commission grant them authorization for certain transactions that will result in (a) the acquisition by AmerenCIPS of AmerenUE's electric transmission and distribution assets in Illinois (other than certain generation assets and related facilities), and AmerenUE's retail gas distribution facilities in Illinois (together, the "Acquired Assets"), a portion of the consideration for which will consist of AmerenCIPS' promissory note, and (b) the acquisition by AmerenUE, for cash, of two electric generating plants, the Pinckneyville Plant and the Kinmundy Plant, which are currently owned by Ameren Energy Generating Company, an "exempt wholesale generator" under the Act (together, the "Proposed Transactions").
In connection with this opinion, I have examined the original, certified, or conformed copies of the Application, all relevant corporate records, agreements, instruments and documents of the Applicants and certificates of public officials and officers of the Applicants, and have made such other investigations, as I have deemed to be necessary or appropriate for the purpose of rendering this opinion. In my examination, I have assumed the genuineness of all signatures, the authenticity of all documents submitted to me as originals, and the conformity to originals of all documents submitted to me as conformed copies.
The opinions expressed below with respect to the Proposed Transactions are subject to the following assumptions and conditions: (a) The Proposed Transactions shall have been duly authorized and approved, to the extent required by the governing documents and applicable state laws, by the Board of Directors of Ameren or other Applicants, as appropriate.
(b) The Commission shall have duly entered an appropriate order or orders with respect to the Proposed Transactions as described in the Application granting and permitting the Application to become effective under the Act and the rules and regulations thereunder.
(c) The Applicants shall have obtained all consents, waivers and releases, if any, required to consummate the Proposed Transactions under all applicable governing corporate documents, contracts, agreements, debt instruments, indentures, franchises, licenses and permits.
(d) The Proposed Transactions are consummated in accordance with the Application and in accordance with all other requisite approvals and authorizations, corporate or otherwise.
(e) No act or event other than as described herein shall have occurred subsequent to the date hereof which would change the opinions expressed above.
(f) The closing of the Proposed Transactions shall be conducted under my supervision and all legal matters incident thereto shall be satisfactory to me, including the receipt in satisfactory form of opinions of other counsel, qualified to practice in jurisdictions pertaining to such Proposed Transactions in which I am not admitted to practice, as I may deem appropriate.
Based on the foregoing, and subject to the assumptions and conditions set forth herein, and having regard to legal considerations which I deem relevant, I am of the opinion that, in the event the Proposed Transactions are consummated in accordance with the Application:
1. All state laws applicable to the Proposed Transactions will have been complied with.
2. The Applicants are validly organized and duly existing under the laws of their respective states of incorporation.
3. The promissory note to be issued by AmerenCIPS in partial consideration for the Acquired Assets will be a valid and binding obligation of AmerenCIPS.
4. AmerenCIPS will legally acquire the Acquired Assets and AmerenUE will legally acquire AmerenCIPS' promissory note.
5. The consummation of the Proposed Transactions will not violate the legal rights of the holder of any securities issued by any of the Applicants.
2 I hereby consent to the use of this opinion in connection with the Application. The opinions expressed herein are intended solely for the benefit of the Commission, and may not be relied upon for any purpose by any other person.
Sincerely,
/s/ Steven R. Sullivan ------Steven R. Sullivan
3 EXHIBIT FS-7
UNION ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (In millions, except per share amounts)
Reported Service Territory Generating Pro Forma DECEMBER 31, TRANSFER ASSET TRANSFER DECEMBER 31, 2004 ADJUSTMENTS (A) ADJUSTMENTS(B) 2004 ------ASSETS Current Assets: Cash and cash equivalents $ 48 $ - $ - $ 48 Accounts receivable - trade (less allowance for doubtful accounts of $3 and $6, respectively) 188 (10) - 178 Unbilled revenue 118 (9) - 109 Miscellaneous accounts and notes receivable 21 69 - 90 Materials and supplies 199 (4) 2 197 Other current assets 18 - - 18 ------Total current assets 592 46 2 640 ------Property and Plant, Net 7,075 (126) 240 7,189 Investments and Other Non-Current Assets: Nuclear decommissioning trust fund 235 - - 235 Other assets 263 - - 263 ------Total investments and other non-current assets 498 - - 498 ------Regulatory Assets 585 (4) - 581 ------TOTAL ASSETS $ 8,750 $ (84) $ 242 $ 8,908 ======
LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Current maturities of long-term debt $ 3 $ - $ - $ - Short-term debt 375 - - 375 Borrowings from money pool 2 - 242 244 Accounts and wages payable 325 (2) - 323 Taxes accrued 51 (2) - 49 Other current liabilities 108 (1) - 107 ------Total current liabilities 864 (5) 242 1,101 ------Long-term Debt, Net 2,059 - - 2,059 Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 1,217 - - 1,217 Accumulated deferred investment tax credits 108 (6) - 102 Regulatory liabilities 776 (3) - 773 Asset retirement obligations 431 - - 431 Accrued pension and other postretirement benefits 219 - - 219 Other deferred credits and liabilities 80 (1) - 79 ------Total deferred credits and other non-current 2,831 (10) - 2,821 liabilities ------Commitments and Contingencies (Notes 1, 3, 15 and 16) Stockholders' Equity: Common stock, $5 par value, 150.0 shares authorized - 511 - - 511 102.1 shares outstanding Preferred stock not subject to mandatory redemption 113 - - 113 Other paid-in capital, principally premium on common 718 - - 718 stock Retained earnings 1,688 (69) - 1,619 Accumulated other comprehensive loss (34) - - (34) ------Total stockholders' equity 2,996 (69) - 2,927 ------TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 8,750 $ (84) $ 242 $ 8,908 ======
(A) TO REFLECT THE TRANSFER OF UE'S ILLINOIS-BASED ELECTRIC AND GAS BUSINESSES, INCLUDING ITS ILLINOIS-BASED DISTRIBUTION ASSETS AND CERTAIN OF ITS TRANSMISSION ASSETS, TO CIPS. ASSUMES UE TRANSFERS APPROXIMATELY ONE-HALF OF THE ASSETS DIRECTLY TO CIPS IN CONSIDERATION FOR A CIPS SUBORDINATED PROMISSORY NOTE, AND APPROXIMATELY ONE-HALF OF THE ASSETS BY MEANS OF A DIVIDEND IN KIND TO AMEREN FOLLOWED BY A CAPITAL CONTRIBUTION BY AMEREN.
(B) TO REFLECT THE TRANSFER OF KINMUNDY AND PINCKNEYVILLE CTS FROM AMEREN ENERGY GENERATING COMPANY ASSUMING UE FINANCES THE TRANSACTION UTILIZING SHORT-TERM BORROWINGS.
EXHIBIT FS-8
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY BALANCE SHEET (IN MILLIONS)
REPORTED SERVICE TERRITORY PRO FORMA DECEMBER 31, TRANSFER DECEMBER 31, 2004 ADJUSTMENTS (A) 2004 ------ASSETS CURRENT ASSETS: Cash and cash equivalents $ 2 $ - 2 Accounts receivable - trade (less allowance for doubtful accounts of $1 and $1, respectively) 48 10 58 Unbilled revenue 71 9 80 Miscellaneous accounts and notes receivable 13 - 13 Current portion of intercompany note receivable - Genco 249 - 249 Current portion of intercompany tax receivable - Genco 11 - 11 Materials and supplies 56 4 60 Other current assets 18 - 18 ------Total current assets 468 23 491 ------PROPERTY AND PLANT, NET 953 126 1,079 INVESTMENTS AND OTHER NON-CURRENT ASSETS: Intercompany note receivable - Genco - - - Intercompany tax receivable - Genco 138 - 138 Other assets 23 - 23 ------Total investments and other non-current assets 161 - 161 ------REGULATORY ASSETS 33 4 37 ------TOTAL ASSETS $ 1,615 $ 153 $ 1,768 ======
LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt $ 20 $ - $ 20 Accounts and wages payable 76 2 78 Borrowings from money pool 68 - 68 Taxes accrued - 2 2 Other current liabilities 32 1 33 ------Total current liabilities 196 5 201 ------LONG-TERM DEBT, NET 430 - 430 INTERCOMPANY NOTES PAYABLE - UE - 69 69 DEFERRED CREDITS AND OTHER NON-CURRENT LIABILITIES: Accumulated deferred income taxes, net 298 - 298 Accumulated deferred investment tax credits 10 6 16 Regulatory liabilities 151 3 154 Other deferred credits and liabilities 40 1 41 ------Total deferred credits and other non-current liabilities 499 10 509 ------COMMITMENTS AND CONTINGENCIES (NOTES 1, 3, AND 15) STOCKHOLDERS' EQUITY: Common stock, no par value, 45.0 shares authorized - - - - 25.5 shares outstanding Other paid-in capital 121 69 190 Preferred stock not subject to mandatory redemption 50 - 50 Retained earnings 323 - 323 Accumulated other comprehensive loss (4) - (4) ------Total stockholders' equity 490 69 559 ------TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,615 $ 153 $ 1,768 ======
(A) TO REFLECT THE TRANSFER OF UE'S ILLINOIS-BASED ELECTRIC AND GAS BUSINESSES, INCLUDING ITS ILLINOIS-BASED DISTRIBUTION ASSETS AND CERTAIN OF ITS TRANSMISSION ASSETS, TO CIPS. ASSUMES UE TRANSFERS APPROXIMATELY ONE-HALF OF THE ASSETS DIRECTLY TO CIPS IN CONSIDERATION FOR A CIPS SUBORDINATED PROMISSORY NOTE, AND APPROXIMATELY ONE-HALF OF THE ASSETS BY MEANS OF A DIVIDEND IN KIND TO AMEREN FOLLOWED BY A CAPITAL CONTRIBUTION BY AMEREN.
EXHIBIT FS-9
Central Illinois Public Service Proposed Accounting Entries for Transfer of Electric Assets and Liabilities to Central Illinois Public Service from Union Electric Company Assuming December 31, 2004 closing
Proposed Account Number Account Description Debit Credit ------
102 Utility plant purchased or sold $109,363,670 101 Electric plant in service $254,007,369 121 Non-utility property $16,199 107 Construction work in progress $4,425,442 108 Accumulated provision for depreciation $148,281,054 111 Accumulated provision for amortization $788,087 135 Working funds $4,000 142 Accounts receivable $7,843,776 144 Provision for uncollectible accounts $811,077 154 Plant materials and operating supplies $0 163 Undistributed stores expense $0 173 Accrued electric revenues $7,792,000 182 Regulatory asset FAS 109 $2,747,958 190 Accumulated deferred income taxes $2,296,499 232 Payroll payable $311,392 235 Customer deposits $1,325,443 236 Accrued taxes $1,699,596 242 Accrued vacation liability $453,102 252 Customer advances $141,741 254 Other regulatory liabilities $2,589,086 255 Accumulated deferred investment tax credit $5,580,225 282 Accumulated deferred income taxes - $16,657,941 other property 283 Deferred income tax liability $14,361,442 233 Notes payable $2,746,135 211 Paid in capital $2,746,136
------Balance $293,494,685 $293,494,685 ======
To clear Account 102, Utility Plant Purchased or Sold, and charge Account 233 Notes Payable to Associated Companies and Account 211 Paid in Capital for the assets and liabilities transferred to AmerenCIPS.
102 Utility plant purchased or sold $109,363,670 233 Notes payable $54,681,835 211 Paid in capital $54,681,835
The total effect on notes payable and paid in capital is shown below:
233 Notes payable $57,427,970 211 Paid in capital $57,427,971
Proposed Account Number Account Description Debit Credit ------
102 Utility plant purchased or sold $17,104,105 101 Gas plant in service $31,734,619 107 Construction work in progress $899,925 108 Accumulated provision for depreciation $15,530,439 142 Accounts receivable $2,554,238 144 Provision for uncollectible accounts $41,999 151 Propane fuel stock $144,147 154 Plant materials and operating supplies $12,486 164 Gas storage $3,752,724 173 Accrued gas revenues $1,677,000 182 Regulatory asset FAS 109 $578,729 186 Environmental adjustment clause $813,694 190 Accumulated deferred income taxes $126,896 232 Accounts payable - to natural gas supplier $2,054,218 232 Payroll payable $61,549 236 Accrued taxes $95,669 242 Accrued vacation liability $80,539 252 Customer advances $111,104 253 Environmental cleanup deferred credit $1,000,000 254 Other regulatory liabilities $198,882 255 Accumulated deferred investment tax credit $205,240 282 Accumulated deferred income taxes - $3,028,012 other property 283 Deferred income tax liability $2,901,116 233 Notes payable $2,841,909 211 Paid in capital $2,841,909
------Balance $45,195,574 $45,195,574 ======
To clear Account 102, Utility Plant Purchased or Sold, and charge Account 233 Notes Payable to Associated Companies and Account 211 Paid in Capital for the assets and liabilities transferred to AmerenCIPS.
102 Utility plant purchased or sold $17,104,105 233 Notes payable $8,552,053 211 Paid in capital $8,552,052
The total effect on notes payable and paid in capital is shown below:
233 Notes payable $11,393,962 211 Paid in capital $11,393,961
Proposed Account Number Account Description Debit Credit ------
102 Utility plant purchased or sold $109,363,670 101 Electric plant in service 254,007,369 121 Non-utility property $16,199 107 Construction work in progress $4,425,442 108 Accumulated provision for depreciation $148,281,054 111 Accumulated provision for amortization $788,087 135 Working funds $4,000 142 Accounts receivable $7,843,776 144 Provision for uncollectible accounts $811,077 154 Plant materials and operating supplies $0 163 Undistributed stores expense $0 173 Accrued electric revenues $7,792,000 182 Regulatory asset FAS 109 $2,747,958 190 Accumulated deferred income taxes $2,296,499 232 Payroll payable $311,392 235 Customer deposits $1,325,443 236 Accrued taxes $1,699,596 242 Accrued vacation liability $453,102 252 Customer advances $141,741 254 Other regulatory liabilities $2,589,086 255 Accumulated deferred investment tax credit $5,580,225 282 Accumulated deferred income taxes - $16,657,941 other property 283 Deferred income tax liability $14,361,442 145 Notes receivable $2,746,135 216 Retained earnings $2,746,136
------Balance $293,494,685 $293,494,685 ======
To clear Account 102, Utility Plant Purchased or Sold, and charge Account 145 Notes Receivable from Associated Companies for the assets and liabilities transferred to AmerenCIPS.
216 Retained earnings $54,681,835 145 Notes receivable $54,681,835 102 Utility plant purchased or sold $109,363,670
The total effect on notes receivable and retained earnings is shown below:
145 Notes receivable $57,427,970 216 Retained earnings $57,427,971
Union Electric Company Electric Utility Plant Assuming December 31, 2004 closing
Account 101 Account 107 Accounts 108 & 111 ------Accumulated Estimated Construction Amortization & Plant Category Electric Plant Work in Progress Depreciation Net Plant ------Transmission $78,192,366 $1,909,200 -$35,583,418 $44,518,148 Distribution 162,996,870 2,516,242 -107,060,692 58,452,420 General 12,818,133 0 -6,425,031 6,393,102 ------Total Electric 254,007,369 4,425,442 -149,069,141 109,363,670
Account 121 ------
Non-Utility Property ------Non-Utility 16,199 16,199 ------
------Total Property and Plant $254,023,568 $4,425,442 -$149,069,141 $109,379,869 ======
Union Electric Company Proposed Accounting Entries for Transfer of Gas Assets and Liabilities from Union Electric Company to Central Illinois Public Service Assuming December 31, 2004 closing
Proposed Account Number Account Description Debit Credit ------
102 Utility plant purchased or sold $17,104,105 101 Gas plant in service $31,734,619 107 Construction work in progress $899,925 108 Accumulated provision for depreciation $15,530,439 142 Accounts receivable $2,554,238 144 Provision for uncollectible accounts $41,999 151 Propane fuel stock $144,147 154 Plant materials and operating supplies $12,486 164 Gas storage $3,752,724 173 Accrued gas revenues $1,677,000 182 Regulatory asset FAS 109 $578,729 186 Environmental adjustment clause $813,694 190 Accumulated deferred income taxes $126,896 232 Accounts payable - to natural gas supplier $2,054,218 232 Payroll payable $61,549 236 Accrued taxes $95,669 242 Accrued vacation liability $80,539 252 Customer advances $111,104 253 Environmental cleanup deferred credit $1,000,000 254 Other regulatory liabilities $198,882 255 Accumulated deferred investment tax credit $205,240 282 Accumulated deferred income taxes - $3,028,012 other property 283 Deferred income tax liability $2,901,116 145 Notes receivable $2,841,909 216 Retained earnings $2,841,909
------Balance $45,195,574 $45,195,574 ======
To clear Account 102, Utility Plant Purchased or Sold, and charge Account 145 Notes Receivable from Associated Companies for the assets and liabilities transferred to AmerenCIPS.
216 Retained earnings $8,552,052 145 Notes receivable $8,552,053 102 Utility plant purchased or sold $17,104,105
The total effect on notes receivable and retained earnings is shown below:
145 Notes receivable $11,393,962 216 Retained earnings $11,393,961
Account 101 Account 107 Accounts 108 & 111 ------Accumulated Estimated Construction Amortization & Plant Category Electric Plant Work in Progress Depreciation Net Plant ------
Estimated Construction Accumulated Plant Category Gas Plant Work in Progress Depreciation Net Plant ------Production $815,815 -$794,189 $21,626 Distribution 29,557,965 899,925 -14,082,883 16,375,007 General 1,360,839 -653,367 707,472 ------Total Gas $31,734,619 $899,925 -$15,530,439 $17,104,105 ======
EXHIBIT FS-10
AMEREN ENERGY GENERATING COMPANY CONSOLIDATED BALANCE SHEET (IN MILLIONS, EXCEPT SHARES)
REPORTED GENERATING PRO FORMA DECEMBER 31, ASSET TRANSFER DECEMBER 31, 2004 ADJUSTMENTS (A) 2004 ------ASSETS CURRENT ASSETS: Cash and cash equivalents $ 1 $ 242 $ 243 Accounts receivable 96 96 Materials and supplies 89 (2) 87 Other current assets 2 2 ------Total current assets 188 240 428 ------PROPERTY AND PLANT, NET 1,749 (240) 1,509 OTHER NONCURRENT ASSETS 18 18 ------TOTAL ASSETS $ 1,955 $ - $ 1,955 ======
LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES: Current maturities of long-term debt $ 225 $ 225 Current portion of intercompany notes payable - 283 283 CIPS and Ameren Borrowings from money pool 116 116 Accounts and wages payable 54 54 Current portion of intercompany tax payable - CIPS 11 11 Taxes accrued 35 35 Other current liabilities 22 22 ------Total current liabilities 746 - 746 ------LONG-TERM DEBT, NET 473 473 INTERCOMPANY NOTES PAYABLE - CIPS AND AMEREN - - DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Accumulated deferred income taxes, net 144 144 Accumulated deferred investment tax credits 12 12 Intercompany tax payable - CIPS 138 138 Accrued pension and other postretirement benefits 5 5 Other deferred credits and liabilities 2 2 ------Total deferred credits and other noncurrent liabilities 301 - 301 ------COMMITMENTS AND CONTINGENCIES (NOTE 1, 3 AND 15) STOCKHOLDER'S EQUITY: Common stock, no par value, 10,000 shares authorized - - - 2,000 shares outstanding Other paid-in capital 225 225 Retained earnings 211 211 Accumulated other comprehensive income (loss) (1) (1) ------Total stockholder's equity 435 - 435 ------TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 1,955 $ - $ 1,955 ======
(A) TO REFLECT THE TRANSFER OF KINMUNDY AND PINCKNEYVILLE CTS FROM AMEREN ENERGY GENERATING COMPANY TO AMEREN UE.
AMEREN ENERGY GENERATING COMPANY PROPOSED ACCOUNTING ENTRIES FOR TRANSFER OF ASSETS AND LIABILITIES FROM AMEREN ENERGY GENERATING COMPANY TO UNION ELECTRIC COMPANY ASSUMING DECEMBER 31, 2004 CLOSING
PROPOSED ACCOUNT NUMBER ACCOUNT DESCRIPTION DEBIT CREDIT ------102 Utility plant purchased or sold $240,297,586 101 Electric plant in service $274,385,317 108 Accumulated provision for depreciation $34,087,731 131 Cash $1,922,520 135 Working funds $25,000 151 Fuel stock $802,521 154 Plant materials and operating supplies $1,571,228 165 Prepayments - insurance $173,771 236 Accrued taxes $650,000 282 Accumulated deferred income taxes - other property $26,167,964 283 Deferred income tax liability $26,167,964
------Balance $303,125,801 $303,125,801 ======
To clear Account 102, Utility Plant Purchased or Sold, and charge Account 131, Cash, for the assets and liabilities transferred to AmerenUE.
131 Cash $240,297,586 102 Utility plant purchased or sold $240,297,586
The total effect on cash is shown below:
131 Cash $242,220,106
EXHIBIT FS-11
AMEREN CORPORATION BALANCE SHEET IN MILLIONS
REPORTED PROPERTY PROPERTY PRO FORMA DECEMBER 31, TRANSFER TO TRANSFER FROM DECEMBER 31, 2004 AMEREN FROM UE AMEREN TO CIPS 2004 ------Current Assets: Cash and cash equivalents $ 4 $ - $ 4 Accounts receivable - trade - 5 (5) - Unbilled revenue - 5 (5) - Intercompany notes receivable 544 - 544 Miscellaneous accounts and notes receivable 24 24 Current portion of long-term notes receivable 34 - 34 Other current assets - 2 (2) ------Total Current Assets 606 12 (12) 606
Property & Plant, Net - 63 (63) -
Investments and Other Non-Current Assets: Accumulated deferred income taxes 2 2 Other assets 5,709 (69) 69 5,709 ------Total Investments and Other Non-Current Assets 5,711 (69) 69 5,711
Regulatory Assets - 2 (2) -
TOTAL ASSETS $ 6,317 $ 8 $ (8) $ 6,317 ======
Current Liabilities: Current maturities of long-term debt $ - Current portion of intercompany tax payable - - Accounts and wages payable 12 1 (1) 12 Taxes accrued (receivable) (15) 1 (1) (15) Other current liabilities 18 1 (1) 18 ------Total Current Liabilities 15 3 (3) 15
Long-term Debt, Net 445 445
Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 4 4 Accumulated deferred investment tax credits - 3 (3) - Intercompany tax payable 2 2 Regulatory liabilities - 1 (1) - Other deferred credits and liabilities 6 1 (1) 6 ------Total Deferred Credits and Other Non-Current Liabilities 12 5 (5) 12
Stockholders' Equity: Common stock 2 2 Other paid-in capital 3,949 3,949 Retained earnings 1,904 1,904 Accumulated other comprehensive income (loss) - Other (10) (10) ------Total Common Stockholders' Equity 5,845 - - 5,845
------TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 6,317 $ 8 $ (8) $ 6,317 ======
EXHIBIT FS-12
AMEREN CORP PROPOSED ACCOUNTING ENTRIES FOR TRANSFER OF ASSETS AND LIABILITIES TO AMEREN CORP FROM UNION ELECTRIC COMPANY ASSUMING DECEMBER 31, 2004 CLOSING
PROPOSED ACCOUNT NUMBER ACCOUNT DESCRIPTION DEBIT CREDIT ------101 Plant in service $142,870,994 121 Non-utility property $8,100 107 Construction work in progress $2,662,684 108 Accumulated provision for depreciation $81,905,747 111 Accumulated provision for amortization $394,044 123 Investment in Union Electric Company $68,821,929 135 Working funds $2,000 142 Accounts receivable $5,199,006 144 Provision for uncollectible accounts $426,538 151 Propane fuel stock $72,074 154 Plant materials and operating supplies $6,243 164 Gas storage $1,876,362 173 Accrued electric revenues $4,734,500 182 Regulatory asset FAS 109 $1,663,344 186 Environmental adjustment clause $406,847 190 Accumulated deferred income taxes $1,211,697 232 Accounts payable - to natural gas supplier $1,027,109 232 Payroll payable $186,471 235 Customer deposits $662,722 236 Accrued taxes $897,633 242 Accrued vacation liability $266,821 252 Customer advances $126,423 253 Environmental cleanup deferred credit $500,000 254 Other regulatory liabilities $1,393,984 255 Accumulated deferred investment tax credit $2,892,733 282 Accumulated deferred income taxes - other property $9,842,977 283 Deferred income tax liability $8,631,279
------Balance $169,345,130 $169,345,130 ======
AMEREN CORP PROPOSED ACCOUNTING ENTRIES FOR TRANSFER OF ASSETS AND LIABILITIES TO CENTRAL ILLINOIS PUBLIC SERVICE FROM AMEREN CORP ASSUMING DECEMBER 31, 2004 CLOSING
PROPOSED ACCOUNT NUMBER ACCOUNT DESCRIPTION DEBIT CREDIT ------101 Plant in service $142,870,994 121 Non-utility property $8,100 107 Construction work in progress $2,662,684 108 Accumulated provision for depreciation $81,905,747 111 Accumulated provision for amortization $394,044 123 Investment in Central Illinois Public Service $68,821,929 135 Working funds $2,000 142 Accounts receivable $5,199,006 144 Provision for uncollectible accounts $426,538 151 Propane fuel stock $72,074 154 Plant materials and operating supplies $6,243 164 Gas storage $1,876,362 173 Accrued electric revenues $4,734,500 182 Regulatory asset FAS 109 $1,663,344 186 Environmental adjustment clause $406,847 190 Accumulated deferred income taxes $1,211,697 232 Accounts payable - to natural gas supplier $1,027,109 232 Payroll payable $186,471 235 Customer deposits $662,722 236 Accrued taxes $897,633 242 Accrued vacation liability $266,821 252 Customer advances $126,423 253 Environmental cleanup deferred credit $500,000 254 Other regulatory liabilities $1,393,984 255 Accumulated deferred investment tax credit $2,892,733 282 Accumulated deferred income taxes - other property $9,842,977 283 Deferred income tax liability $8,631,279
------Balance $169,345,130 $169,345,130 ======
End of Filing
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