-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Rgye2zZBlvcMfJxMw7Yls8IAmuqn6sHd22Xz3O87olD5Y4RWCu7UFKYcre78i0jp Qp8M7mc364XN0SVkSryqVA== 0000950131-97-004449.txt : 19970716 0000950131-97-004449.hdr.sgml : 19970716 ACCESSION NUMBER: 0000950131-97-004449 CONFORMED SUBMISSION TYPE: U-1/A PUBLIC DOCUMENT COUNT: 5 FILED AS OF DATE: 19970715 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMEREN CORP CENTRAL INDEX KEY: 0001002910 STANDARD INDUSTRIAL CLASSIFICATION: METAL MINING [1000] IRS NUMBER: 431723446 STATE OF INCORPORATION: MO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: U-1/A SEC ACT: 1935 Act SEC FILE NUMBER: 070-08945 FILM NUMBER: 97641093 BUSINESS ADDRESS: STREET 1: 1901 CHOUTEAU AVE CITY: ST LOUIS STATE: MO ZIP: 63103 BUSINESS PHONE: 3146213222 MAIL ADDRESS: STREET 1: 1901 CHOUTEAU AVE CITY: ST LOUIS STATE: MO ZIP: 63103 U-1/A 1 FORM U-1/A As filed with the Securities and Exchange Commission on July 15, 1997 File No. 70-8945 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ______________________________ AMENDMENT NO. 1 TO FORM U-1 APPLICATION/DECLARATION UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 ______________________________ Ameren Corporation 1901 Chouteau Avenue St. Louis, Missouri 63103 (Name of company filing this statement and address of principal executive offices) None (Name of top registered holding company) William E. Jaudes Registered Agent Ameren Corporation 1901 Chouteau Avenue St. Louis, Missouri 63103 (Names and addresses of agents of service) The Commission is requested to send copies of all notices, orders and communications in connection with this Application to: James J. Cook William J. Harmon William Niehoff Jones, Day, Reavis & Pogue Union Electric Company 77 West Wacker, Suite 3500 1901 Chouteau Avenue Chicago, Illinois 60601-1692 P.O. Box 149 St. Louis, Missouri 63166 A. Introduction This Application/Declaration, originally filed October 31, 1996 (the "Application"), seeks approvals relating to the proposed business combination transaction among Ameren Corporation ("Ameren"), Union Electric Company ("UE") and CIPSCO Incorporated ("CIPSCO"), by which UE and CIPSCO's utility subsidiary, Central Illinois Public Service Company ("CIPS"), will become wholly owned subsidiaries of Ameren, a new Missouri holding company (the "Transaction"). Following the consummation of the Transaction, Ameren will register with the Securities and Exchange Commission (the "Commission") as a holding company under the Public Utility Holding Company Act of 1935 (the "Act"). Ameren submits this Amendment No. 1 (i) to file additional information regarding the retention by Ameren of the gas utility operations of UE and CIPS, (ii) to file certain Exhibits hereto as described below and (iii) to reply to comments of the Missouri Public Service Commission filed with the Commission in this docket on March 17, 1997. B. Retention of Gas Operations Item 3. A. 2. a. i. of the Application describes Ameren's position that, in light of current conditions, the Act does not prohibit UE or CIPS from continuing to conduct their gas operations as part of the single integrated public utility system to be controlled by Ameren after the Transaction. In particular, part (A) of that section demonstrates the significant level of lost economies that would result if each of the UE gas operations and the CIPS gas operations were separately operated -- i.e., as two stand-alone companies. As pointed out in such part, the lost economies would be significantly higher than in other cases where the Commission held that the additional system could be retained. In Item 3.A.2.b.ii.(B) of the Application, Ameren demonstrates that the gas operations of UE and the gas operations of CIPS, together, constitute a "single integrated public utility system." Because the existing separate gas systems of UE and CIPS may be operated as a single integrated system, it may be appropriate to analyze the loss of economies that would occur if the gas operations were to be divested on the assumption that the gas operations of UE and CIPS are combined as part of the divestiture into a single new and separate gas utility company. In order to demonstrate the effects of such a divestiture of both the UE and CIPS gas operations into a single separate entity, UE and CIPS have prepared a Supplemental Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS (the "Supplemental Study"). The Supplemental Study uses the same methodology as used in the original Analysis of Economic Impact of Divestiture of the Gas Operations of UE and CIPS dated September 19, 1996 and 2 previously filed in this matter as Exhibit K-1 (the "1996 Study"), except that it is assumed that one newly formed corporation would assume all of the divested gas operations. As would be expected, the Supplemental Study shows that total lost economies are less than shown by the 1996 Study because the "double" costs of two corporations are eliminated. However, even assuming that only one new company were created, the lost economies are significantly higher than in Commission precedents. See Exhibit K-2 to the Application. Thus, the Supplemental Study supports, as does the 1996 Study, the conclusion that the test of Clause A of Section 11(b)(1) is met in this case. Historically, in determining whether lost economies are "substantial" under Section 11(b)(1)(A), the Commission has given consideration to four ratios, which measure the projected loss of economies as a percentage of: (1) total gas operating revenues; (2) total gas expense or "operating revenue deductions"; (3) gross gas income; and (4) net gas income or net gas utility operating income. Although the Commission has declined to draw a bright-line numerical test under Section 11(b)(1)(A), it has indicated that cost increases resulting in a 6.78% loss of operating revenues, a 9.72% increase in operating revenue deductions, a 25.44% loss of gross income and a 42.46% loss of net income would afford an "impressive basis for finding a loss of substantial economies." In re Engineers Public Service Co., 12 SEC 41, 59 (Sept. 16, 1942) ("Engineers"). Here, the lost economies would be far greater than in Engineers if the gas properties of UE and CIPS were to be operated as a combined new single entity on a stand-alone basis, with no offsetting increase in benefits to consumers. These lost economies result from the need to replicate services, the sacrifice of economies of scale, the costs of reorganization, and other factors, and are described more fully in the Supplemental Study (Exhibit K-1.1 hereto). As set forth in the Supplemental Study, divestiture of the gas operations of UE and CIPS into one stand-alone company would result in lost economies of $34.8 million. (This compares to lost economies of $22.1 million for UE and $36.3 million for CIPS, totalling $58.4 million, as found by the 1996 Study). These lost economies compare with 1995 pro forma combined gas operating revenues of $217.4 million for UE and CIPS; pro forma combined gas operating revenue deductions of $197.9 million; pro forma combined gas gross income of $19.6; and pro forma combined gas net income of $13.8 million. On a percentage basis, the lost economies amount to 252% of 1995 pro forma combined gas net income -- far in excess of the loss of net income in Unitil Corp., 51 SEC Docket 562 (Apr. 24, 1992) (Unitil), where the Commission allowed the retention of gas 3 utility operations, and the 30% loss in New England Electric System that the Commission has described as the highest loss of net income in any past divestiture order./1/ As a percentage of 1995 pro forma combined gas operating revenues, these lost economies described in the Supplemental Study amount to 16% - --losses higher than the losses in any past divestiture order. The projected loss of economies as a percentage of operating revenues is even higher than the loss in Unitil./2/ As a percentage of - --------------------- /1/ See Unitil Corp., 51 SEC Docket 562, 567 & n.42 (Apr. 24, 1992) ("The Commission has required divestment where the anticipated loss in income of the stand-alone company was approximately 30%" or "29.9% of net income before taxes") (citing SEC v. New England Elec. Sys., 390 U.S. 207, 214 n.11 (1968)). This percentage compares to the 425% of 1995 UE gas net income and 424% of 1995 CIPS gas net income shown by the 1996 Study. /2/ The loss as a percentage of operating revenues in Unitil was 13.94%. The highest loss of operating revenues in any case ordering divestiture is commonly said to be 6.58%. See, e.g., Unitil Corp., 51 SEC Docket 562, 567 n.41 (Apr. 24, 1992) ("[o]f cases in which the Commission has required divestment, the highest estimated loss of operating revenues of a stand- alone company was 6.58%") (citing In re Engineers Public Service Co., 12 SEC 41 (Sept. 16, 1942)). In fact, however, the 6.58% ratio is not cited in Engineers and is a post hoc calculation derived from claimed cost increases which the Commission had found were "overstated" and "doubtful" in a number of respects. Engineers Public Service Co., 12 SEC at 80-81. See also In re Philadelphia Co., 28 SEC 35, 51 n.26 (June 1, 1948) (Engineers' "estimate . . . of increased expenses . . . was overstated in several respects"). While the SEC made no finding as to actual cost increases or ratios for the Gulf States gas properties, it found that Engineers' estimate of divestiture- related cost increases for certain sister gas properties in Virginia were also overstated and cut them and the resulting ratios in half. Engineers Public Service Co., 12 SEC at 60. If the same 50% discount had been applied to Engineers' Gulf States gas properties, the loss of operating revenues would have been 3.29%, the increase in expenses would have been 4.73%, the loss of gross income would have been 10.43%, and the loss of net income would have been 12.63%. Disregarding the 6.58% ratio incorrectly attributed to the Engineers/Gulf States case, the highest loss of operating revenues in any past divestiture order was 5.85%. See table of ratios in In re New England Elec. Sys., 41 SEC 888, 905 App. (Mar. 19, 1964). This figure would be even lower if adjusted for the increase in purchased gas costs since the 1940s. The percentage shown by the Supplemental Study compares to the (continued.....) 4 1995 pro forma combined gas expenses or operating revenue deductions, the lost economies described in the Supplemental Study would amount to 17.6% -- higher than the losses in any past divestiture order and higher than the losses in both Unitil and Entergy, another case in which the Commission authorized the retention of gas operations./3/ As a percentage of 1995 pro forma combined gas gross income, the lost economies described in the Supplemental Study amount to 178% --far in excess of the highest loss of gross income in any divestiture order. The applicable percentages in past cases are summarized in Exhibit K-2 previously filed (Table of Estimated Losses of Economies in Prior Decisions on Divestiture and Retention of Gas Operations). In order to recover these lost economies, the single, new stand-alone company divested from UE and CIPS would need to increase customer rates by about 23% ($50.4 million) in order to provide an 11.07% rate of return on rate base. This rate of return was conservatively estimated using the weighted average approximate costs for capital of UE and CIPS rather than the higher returns that would likely be required by the financial community for a single, stand-alone company. Finally, it should be noted that the lost economies would, in the absence of rate relief, result in a negative rate of return on rate base for the gas operations of minus 4.78% --significantly more detrimental than the 2.01% projected stand- - ------------------------- /2/(continued.....) 25% and 28% reduction, respectively, for UE and CIPS shown by the 1996 Study. /3/ The highest percentage of loss related to operating revenue deduction is sometimes attributed to the Gulf States gas properties of Engineers Public Service Co. See, e.g., In re New England Elec. Sys., 41 SEC 888, 905 App. (March 19, 1964) (attributing 9.46% to the Engineers/Gulf States case). This percentage, however, is based on claimed losses expressly rejected by the Commission in the Engineers decision. In re Engineers Public Service Co., 12 SEC 41, 80-81 (Sept. 16, 1942). Disregarding the 9.46% figure erroneously attributed to the Engineers case, the highest expense percentage in the cases ordering divestiture appears to have been either 8.01% or 7.42%, depending on how the ratio is calculated. See In re North American Co., 18 SEC 611 (Apr. 7, 1945); In re Philadelphia Co., 28 SEC 35, 51 Table VI (June 1, 1948) (attributing expense ratio of 7.42% to North American) with In re New England Electric System, 41 SEC 888, 905 App. (1964) (attributing expense ratio of 8.01% to North American). The combined total loss as a percentage of gas operating revenue deductions shown in the 1996 Study was 29.5%. 5 alone rate of return in Unitil, where retention was authorized. This return is significantly lower than the returns of other utilities in the region and represents a decline from UE's and CIPS' indicated rates of return for 1995. The above data show that, even assuming the gas operations of CIPS and UE were divested by forming one stand-alone company, the loss of economies would be significant, in excess of that present in other cases where retention was allowed and sufficient to support a finding that requirement of Clause A of Section 11(b)(1) is met in this case. This conclusion is even more dramatically demonstrated if it is assumed that each gas operation would be in a separate stand-alone company as shown by the 1996 Study. Additional support for the conclusion that retention of the gas operations is supported by the Act is found in the Legal Memorandum on the Retention of Gas Operations by Ameren Corporation (the "Gas Legal Memorandum") filed herewith as Exhibit K-3. C. Additional or Updated Exhibits. The Exhibits filed herewith include Exhibit D-2.2, the Report and Order of the Missouri Public Service Commission (MPSC) dated February 21, 1997 (the "Final Missouri Order), approving the merger between Union Electric Company (UE) and Central Illinois Public Service Company (CIPSCO) and the pleading filed by UE accepting conditions contained therein. In the Final Missouri Order, the MPSC adopted and approved the terms of the Stipulation entered into by the parties. (See Exhibit D-2.3) The MPSC also imposed two other conditions beyond those reflected in the Stipulation. First, Ameren must agree to file or join in the filing of regional independent system operator ("ISO") proposal at the FERC no later than December 31, 1997, or, if not, by March 31, 1998, Ameren must develop and file with the MPSC a plan for establishing an independent entity charged with the operation, pricing and planning of its transmission system. Second, UE must file with the MPSC by January 1, 1998, a report assessing the potential ability of the merged companies to exercise market power in the price of deregulated retail generation. UE has consented to these two conditions. The Final Missouri Order became effective March 4, 1997. As described in Part A hereto, the Supplemental Study and the Gas Legal Memorandum are also filed herewith. Finally, recent financial information and Exhibits are filed as noted in Item 6 below. 6 D. Reply to Comments of the Missouri Public Service Commission Ameren has no objection to the late-filed comments being received and considered by the Commission. However, Ameren does not believe that any reason exists to grant the requested relief as the issues raised were the subject of negotiation and were fully addressed in agreements accepted by the MPSC when it approved the merger on February 21, 1997. In negotiations during the pre-approval process, the MPSC Staff expressed the desire to retain the ability of the MPSC to continue regulatory oversight of UE and Ameren. The MPSC Staff proposed that contracts contain similar language to that which has been suggested in its comments. For a variety of reasons, including that placing the language in contracts would have been an administrative hardship and may have unnecessarily created uncertainties regarding the enforceability of contracts, the proposal ultimately was dropped and other means were adopted to provide the assurances the MPSC Staff sought. Thus, the Stipulation (previously filed as Exhibit D-2.3 hereto) signed by UE and approved by the MPSC contains numerous provisions specifically designed to preserve the MPSC's ability to examine books and records of the merged companies and to engage in ratemaking determinations. For example, the Stipulation states, in part as follows: 8. State Jurisdictional Issues a. Access to Books, Records, and Personnel. UE and its prospective holding company, Ameren, agree to make available to the [MPSC], at reasonable times and places, all books and records and employees and officers of Ameren, UE and any affiliate or subsidiary of Ameren as provided under applicable law and [MPSC] rules; provided, that Ameren, UE and any affiliate or subsidiary of Ameren shall have the right to object to such production of records or personnel on any basis under applicable law and [MPSC] rules excluding any objection that such records and personnel are not subject to [MPSC] jurisdiction by operation of the Public Utility Holding Company Act of 1935. . . . **** d. Contracts Required to be Filed with the SEC. All contracts, agreements or arrangements, including any amendments thereto, of any kind between UE and any affiliate, associate, holding, mutual service, or subsidiary company within the same holding company system, as these terms are defined in 15 U.S.C. (S) 79b, as subsequently amended, required to be filed with 7 and/or approved by the Securities and Exchange Commission ("SEC") pursuant to PUHCA, as subsequently amended, shall be conditioned upon the following without modification or alteration: UE and Ameren and each of its affiliates and subsidiaries will not seek to overturn, reverse, set aside, change or enjoin, whether through appeal or the initiation or maintenance of any action in any forum, a decision or order of the [MPSC] which pertains to recovery, disallowance, deferral or ratemaking treatment of any expense, charge, cost or allocation incurred or accrued by UE in or as a result of a contract, agreement, arrangement or transaction with any affiliate, associate, holding, mutual service or subsidiary company on the basis that such expense, charge, cost or allocation has itself been filed with or approved by the SEC or was incurred pursuant to a contract, arrangement, agreement or allocation method which was filed with or approved by the SEC. (Stipulation, Exhibit D-2.3, pp. 22-24) (emphasis supplied). ----------- In addition, the Stipulation contains a contingent jurisdictional stipulation providing for pre-approval of contracts by the MPSC in the event that anyone raises objection to MPSC action on the basis of SEC preemption. (Stipulation, Attachment D)(U-1 Exhibit D-2.3). Thus, Ameren and UE have clearly demonstrated that they did not act to deprive the MPSC of jurisdiction in structuring the transaction so that Ameren would become a registered holding company. Furthermore, there are agreements in place which are more than adequate to govern relationships between the parties. Including the conditions proposed by the MPSC would not add to that protection already in place, but has the potential to create administrative hardship and uncertainty for Applicants post-merger. For these reasons Applicants respectfully request that the Commission decline to include in its Order conditions suggested by the MPSC unit's comments. 8 Item 6. Exhibits and Financial Statements A. Exhibits The following Exhibits are filed with this Amendment No. 1: D-2.2 Final MPSC Report and Order dated February 21, 1997 G-1.1 Financial Data Schedule (March 1997) (Electronic filing only) I-1.1 Annual Report of UE on Form 10-K for the year ended December 31, 1996 (Incorporated by reference) I-2.1 Annual Report of CIPSCO and CIPS on Form 10-K for the year ended December 31, 1996 (Incorporated by reference) I-3.1 Portions of UE 1996 Annual Report to Shareholders (Exhibit 13 to UE 1996 Form 10-K; Incorporated by reference) I-4.1 Statement of CIPS on Form U-3A-2 dated February 28, 1997 (Incorporated by reference) I-5.1 UE Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 (Incorporated by reference) I-6.1 CIPSCO and CIPS Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 (Incorporated by reference) K-1.1 Supplemental Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS (the "Supplemental Study") K-3 Legal Memorandum Regarding Standards for Retention of Gas Properties 9 B. Financial Statements FS-1.1 Ameren Unaudited Pro Forma Combined Condensed Consolidated Balance Sheets as of March 31, 1997 (see Quarterly Report of UE on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-5.1 hereto), at p. 11) FS-2.1 Ameren Unaudited Pro Forma Combined Condensed Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994 (see Annual Report of UE on Form 10-K for the year ended December 31, 1996 (Exhibit I-1.1 hereto), at pp. 17-19) FS-3.1 CIPSCO Consolidated Balance Sheets as of March 31, 1997 (see Quarterly Report of CIPSCO on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-6.1 hereto), at p. 5) FS-4.1 CIPSCO Consolidated Statements of Income for its last three fiscal years (see Annual Report of CIPSCO on Form 10-K for the year ended December 31, 1996 (Exhibit I-2.1 hereto), at p. 40) FS-5.1 CIPS Balance Sheets as of March 31, 1997 (see Quarterly Report of CIPS on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-6.1 hereto), at p. 8) FS-6.1 CIPS Statements of Income for its last three fiscal years (see Annual Report of CIPS on Form 10-K for the year ended December 31, 1996 (Exhibit I-2.1 hereto), at p. 66) FS-7.1 UE Consolidated Balance Sheet as of March 31, 1997 (see Quarterly Report of UE on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-5.1 hereto), at p. 2) FS-8.1 UE Statement of Income for its last three fiscal years (see UE Annual Report to Shareholders for the year ended December 31, 1996 (Exhibit I-3.1 hereto), at p. 22) 10 SIGNATURE Pursuant to the requirements of the Public Utility Holding Company Act of 1935, the undersigned company has duly caused this Amendment No. 1 to Application/Declaration to be signed on its behalf by the undersigned thereunto duly authorized. Date: July 15, 1997 AMEREN CORPORATION /s/ William E. Jaudes ------------------------------------- By: William E. Jaudes Secretary 11 Exhibit Index to Amendment No. 1
A. Exhibits Form of Exhibit No. Description Transmission - ----------- ----------- ------------ D-2.2 Final MPSC Report and Order dated Electronic February 21, 1997 (filed herewith) G-1.1 Financial Data Schedule (March 1997) Electronic (filed herewith) I-1.1 Annual Report of UE on Form 10-K for By Reference the year ended December 31, 1996 (Incorporated by reference) I-2.1 Annual Report of CIPSCO and CIPS on By Reference Form 10-K for the year ended December 31, 1996 (Incorporated by reference) I-3.1 Portions of UE 1996 Annual Report to By Reference Shareholders (Exhibit 13 to UE 1996 Form 10-K; Incorporated by reference) I-4.1 Statement of CIPS on Form U-3A-2 By Reference dated February 28, 1997 (Incorporated by reference) I-5.1 UE Quarterly Report on Form 10-Q for By Reference the quarter ended March 31, 1997 (Incorporated by reference) I-6.1 CIPSCO and CIPS Quarterly Report on By Reference Form 10-Q for the quarter ended March 31, 1997 (Incorporated by reference)
Form of Exhibit No. Description Transmission - ----------- ----------- ------------ K-1.1 Supplemental Analysis of the Electronic Economic Impact of a Divestiture of the Gas Operations of UE and CIPS (the "Supplemental Study") (filed herewith) K-3 Legal Memorandum Regarding Standards Electronic for Retention of Gas Properties (filed herewith) B. Financial Statements Form of F.S. No. Description Transmission -------- ----------- ------------ FS-1.1 Ameren Unaudited Pro Forma Combined By Reference Condensed Consolidated Balance Sheets as of March 31, 1997 (see Quarterly Report of UE on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-5.1 hereto), at p. 11) FS-2.1 Ameren Unaudited Pro Forma Combined By Reference Condensed Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994 (see Annual Report of UE on Form 10-K for the year ended December 31, 1996 (Exhibit I-1.1 hereto), at pp. 17-19) FS-3.1 CIPSCO Consolidated Balance Sheets as By Reference of March 31, 1997 (see Quarterly Report of CIPSCO on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-6.1 hereto), at p. 5) FS-4.1 CIPSCO Consolidated Statements of By Reference Income for its last three fiscal years (see Annual Report of CIPSCO on Form 10-K for the year ended December 31, 1996 (Exhibit I-2.1 hereto), at p. 40) FS-5.1 CIPS Balance Sheets as of March 31, By Reference 1997 (see Quarterly Report of CIPS on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-6.1 hereto), at p. 8) Form of F.S. No. Description Transmission - -------- ----------- ------------ FS-6.1 CIPS Statements of Income for its last By Reference three fiscal years (see Annual Report of CIPS on Form 10-K for the year ended December 31, 1996 (Exhibit I-2.1 hereto), at p. 66) FS-7.1 UE Consolidated Balance Sheet as of By Reference March 31, 1997 (see Quarterly Report of UE on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-5.1 hereto), at p. 2) FS-8.1 UE Statement of Income for its last By Reference three fiscal years (see UE Annual Report to Shareholders for the year ended December 31, 1996 (Exhibit I-3.1 hereto), at p. 22) EX-99.D-2.2 2 FINAL MPSC REPORT AND ORDER DATED FEB. 21, 1997 Exhibit D-2.2 BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MISSOURI In the Matter of the Application of Union Electric ) Company for an Order Authorizing (1) Certain Merger ) Transactions Involving Union Electric Company; ) (2) the Transfer of Certain Assets, Real Estate, ) Leased Property, Easements and Contractual ) Case No. EM-96-149 Agreements to Central Illinois Public Service ) ------------------ Company; and (3) in Connection Therewith, Certain ) Other Related Transactions. ) ================================================================================ REPORT AND ORDER ================================================================================ Issue Date: February 21, 1997 Effective Date: March 4, 1997 BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MISSOURI In the Matter of the Application of Union Electric ) Company for an Order Authorizing (1) Certain Merger ) Transactions Involving Union Electric Company; ) (2) the Transfer of Certain Assets, Real Estate, ) Leased Property, Easements and Contractual ) Case No. EM-96-149 Agreements to Central Illinois Public Service ) ------------------ Company; and (3) in Connection Therewith, Certain ) Other Related Transactions ) APPEARANCES ----------- James J. Cook, Associate General Counsel, Joseph H. Raybuck, Attorney, and William J. Niehoff, Attorney, Union Electric Company, Post Office Box 149, St. Louis, Missouri 63166, for Union Electric Company. Richard W. French, French & Stewart Law Offices, 1001 Cherry Street, Suite 302, Columbia, Missouri 65201, for Trigen-St. Louis Energy Corporation. Sondra B. Morgan and James C. Swearengen, Brydon, Swearengen & England, P.C., Post Office Box 456, 312 East Capitol Avenue, Jefferson City, Missouri 65102, for The Empire District Electric Company and UtiliCorp United Inc. Sondra B. Morgan and Gary W. Duffy, Brydon, Swearengen & England, P.C., Post Office Box 456, 312 East Capitol Avenue, Jefferson City, Missouri 65102, for Missouri Gas Energy, a division of Southern Union Company. Thomas M. Byrne, Associate Counsel, Laclede Gas Company, 720 Olive Street, St. Louis, Missouri 63101, for Laclede Gas Company. Robert C. Johnson, Diana M. Schmidt, and Michael R. Annis, Peper, Martin, Jensen, Maichel and Hetlage, 720 Olive Street, 24th Floor, St. Louis, Missouri 63101, for: Anheuser-Busch, Inc., Barnes and Jewish Hospitals, Chrysler Corporation, Emerson Electric Company, Hussmann Refrigeration, Lincoln Industrial, MEMC Electronic Materials, Mallinckrodt, Inc., McDonnell Douglas Corporation, Monsanto Company, and The Doe Run Company (the Missouri Industrial Energy Consumers). James M. Fischer, Attorney at Law, 101 West McCarty Street, Suite 215, Jefferson City, Missouri 65101, and William G. Riggins, Staff Attorney, Kansas City Power & Light Company, 1201 Walnut Street, Post Office Box 418679, Kansas City, Missouri 64141, for Kansas City Power & Light Company. Paul S. DeFord, Lathrop & Gage, 2345 Grand Boulevard, Kansas City, Missouri 64108, for Illinois Power Company. Marilyn S. Teitelbaum, Schuchat, Cook & Werner, 1221 Locust Street, Second Floor, St. Louis, Missouri 63103, for Local 2, Local 309, Local 702 and Local 1455, International Brotherhood of Electrical Workers, AFL-CIO. Daryl R. Hylton, Assistant Attorney General, and Michelle Smith, Assistant Attorney General, Office of the Attorney General, Post Office Box 899, Jefferson City, Missouri 65102, for the State of Missouri, at the relation of Jeremiah W. (Jay) Nixon, Attorney General. Lewis R. Mills, Jr., Deputy Public Counsel, Office of the Public Counsel, Post Office Box 7800, Jefferson City, Missouri 65102, for the Office of the Public Counsel and the public. Steven Dottheim, Acting General Counsel, Roger W. Steiner, Assistant General Counsel, and Aisha Ginwalla, Assistant General Counsel, Missouri Public Service Commission, Post Office Box 360, Jefferson City, Missouri 65102, for the staff of the Missouri Public Service Commission. ADMINISTRATIVE - -------------- LAW JUDGE: Joseph A. Derque, III. - --------- REPORT AND ORDER ================ Procedural History ------------------ On November 7, 1995, Union Electric Company (UE) filed an application with the Missouri Public Service Commission (Commission) requesting an order from the Commission authorizing certain merger transactions, the transfer of certain assets, real estate, leased property, easements and contractual agreements, and authorizing certain other transactions, all to effectuate a proposed merger between UE and CIPSCO Incorporated (CIPSCO). UE is a Missouri corporation engaged in the provision of energy services to the public in the state of Missouri and regulated by the Commission as a public utility. CIPSCO is an Illinois corporation and the parent corporation of its wholly owned subsidiary, Central Illinois Public 2 Service Company (CIPS). CIPS is engaged in the business of providing energy services in the state of Illinois and, as such, is a regulated public utility in that state. In addition, two other corporations have been formed for the purpose of facilitating the proposed merger, those being Arch Merger, Inc. (Arch) and Ameren Corporation (Ameren). The corporate structure resulting from the proposed merger will include Ameren as a federally regulated utility holding company, with UE as a Missouri subsidiary operating company and CIPS and CIPSCO as other subsidiaries. The merger transactions are intended to result in a tax-free exchange. In addition to the Staff of the Commission (Staff), UE, and the Office of the Public Counsel (OPC), the following parties were also granted intervention: the Missouri Industrial Energy Consumers (MIEC)/1/; Laclede Gas Company (LGC); The Empire District Electric Company (EDE); Locals 2, 309, 702 and 1455 of the International Brotherhood of Electrical Workers, AFL-CIO (Unions); Kansas City Power & Light Company (KCPL); the State of Missouri ex rel. The Attorney General (State); Missouri Gas Energy, a division of Southern Union Company (MGE); Trigen-St. Louis Energy Corporation (Trigen); Illinois Power Company (IP); and UtiliCorp United Inc. (UtiliCorp). - ----------------------- /1/The MIEC is composed of the following: Anheuser-Busch, Inc., Barnes and Jewish Hospitals, Chrysler Corporation, Emerson Electric Company, Hussmann Refrigeration, Lincoln Industrial, MEMC Electronic Materials, Mallinckrodt, Inc., McDonnell Douglas Corporation, Monsanto Company, and The Doe Run Company. 3 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. A. Stipulation And Agreement On July 12, 1996, a Stipulation And Agreement was filed purporting to settle all issues raised by the parties and seeking Commission approval of the proposed transaction. This Stipulation And Agreement is appended to this Report And Order as Attachment 1 and incorporated herein by reference. Various intervenors did not sign the proposed Stipulation And Agreement. Those parties were given the opportunity to exercise their due process right to compel an evidentiary hearing, but all chose not to do so. Those parties who are not signatories to the agreement are LGC, MIEC, IP, and the Unions. All have stated in filed documents that, while not signatories to the agreement, none wish to litigate any issue and none are opposed to Commission approval of the proposed stipulation. The Commission, therefore, in accordance with rule 4 CSR 240-2.115, will treat the Stipulation And Agreement as a unanimous stipulation and agreement. The Stipulation And Agreement contains the following terms and conditions. In setting out this summary it is not the intent of the Commission to alter any terms and conditions therein. The Stipulation And Agreement specifies that the proposed merger, as specified in the merger agreement, filed with the original application on November 7, 1995, should be approved by the Commission as not 4 detrimental to the public interest, subject to the conditions and modifications as set out in the remainder of the Stipulation And Agreement. UE has agreed that it will not seek to recover the asserted merger premium of $232 million in rates in any Missouri proceeding. The merger premium represents the portion of the purchase price that exceeds the current book value of the acquired company's assets or market value of the acquired company's stock. UE will, however, retain the right to state, in any future proceedings, alleged benefits of the merger. UE will forgo any additional specific adjustments to cost of service related to the merger savings or any claim to merger savings other than the adjustments to cost of service and claims to merger savings resulting from the Commission's approval of the Stipulation And Agreement or the benefits and savings which would occur through regular ratemaking treatment or the current Experimental Alternative Regulation Plan (ARP) or the new Experimental Alternative Regulation Plan (EARP) effective July 1, 1998, pursuant to the Stipulation And Agreement. Actual prudent and reasonable merger transaction and transition costs (estimated to be $71.5 million) shall be amortized over ten years beginning the date the merger closes. The annual amortization of merger transaction and transition costs will be the lesser of: (1) the Missouri jurisdictional portion of the total Ameren amount of $7.2 million; or (2) the Missouri jurisdictional portion of the total Ameren unamortized amount of actual merger transaction and transition costs incurred to date. No rate base treatment of the unamortized costs will be included in the determination of rate base for any regulatory purposes in Missouri. UE commits that it will propose and file with the Commission an experimental retail wheeling pilot program for 100 MW of electric power, 5 to be available to all major classes of Missouri retail electric customers, as soon as practical, but no later than March 1, 1997./2/ The commitment to file such a pilot program for Commission consideration and determination covered by this provision is made by UE alone. Prior to filing its proposal with the Commission, UE will seek substantive input from Missouri retail electric customers, Staff, OPC and others. The parties concur that earnings monitoring in Case No. EO-96-14 will result in a general change in rates charged and revenues collected after August 31, 1998. The change in revenues collected will be equal to the average annual total revenues credited to customers during the three ARP years ending June 30, 1998, adjusted to reflect normal weather. Any rate reduction shall be spread within and among revenue classes on the basis of the Commission decision in Case No. EO-96-15, which is the UE customer class cost of service and comprehensive rate design docket created as a result of Case No. ER-95-411. In the event that a Commission decision has not been reached in Case No. EO-96-15, the parties will jointly or severally propose to the Commission a basis or bases on which a rate reduction may be spread on an interim basis within and among the classes pending issuance of the Commission's decision in Case No. EO-96-15. UE will make a good faith effort to provide the earnings report for the final Sharing Period in Case No. ER-95-411 in time to implement this rate reduction on September 1, 1998. In the event the earnings data is not available, or in the event the review process of the earnings data or the weather normalization review process does not allow for a September 1, 1998 effective date, the following will occur: An additional - ----------------------- /2/The Commission will entertain a motion to modify the above date in order to ensure that UE has the opportunity to receive "substantive input" from the parties and others. 6 credit, equal to the excess revenues billed between September 1, 1998 and the effective date of the rate reduction, will be made. Said credit will be made at the same time and pursuant to the same procedures as the Sharing Credits in Case Nos. ER-95-411 and EO-96-14. If no Sharing Credits are to be made for the third Sharing Period in Case Nos. ER-95-411 and EO-96-14, the excess revenue credit will be made as expeditiously as possible. UE shall file tariff sheets for Commission approval consistent with this section. The EARP will be instituted July 1, 1998 at the end of the ARP created in Case No. ER-95-411. In its Report And Order approving this Stipulation and Agreement, the Commission shall create a new docket to facilitate the EARP (EARP Docket). All signatories to the Stipulation And Agreement shall be made parties to the EARP Docket, as intervenors or as a matter of right, as will the parties to Case No. EO-96-14 who are not parties to Case No. EO-96-149, without the necessity of taking further action. The following sharing grid is to be utilized as part of the EARP: =============================================================== Sharing Sharing Earnings Level (Missouri Level Level Retail Electric Operations) ------- -------- UE Customer =============================================================== 1. Up to and including 12.61% 100% 0% Return and Equity (ROE) 2. That portion of earnings 50% 50% greater than 12.61% up to and including 14.00% ROE 3. That portion of earnings 10% 90% greater than 14.00% up to and including 16.00% ROE 4. That portion of earnings 0% 100% greater than 16.00% ROE =============================================================== The EARP will be in effect for a full three-year period. 7 In the event UE files an electric rate increase case, any Sharing Credits due for the current or prior Sharing Period will remain the obligation of UE, and the EARP shall terminate at the conclusion of the then current Sharing Period. In the event any signatory to the Stipulation and Agreement files a rate reduction case, any Sharing Credits due for the current or prior Sharing Period will remain the obligation of UE, and the parties to that case will recommend to the Commission whether the EARP should remain in effect as currently structured, be modified or terminated. Upon any termination of the EARP pursuant to the foregoing, the signatories will have no further obligation under this section. Monitoring of the EARP will be based on UE supplying to Staff and OPC, on a timely basis, the reports and data identified in the Stipulation and Agreement. These reports and data must be provided as part of the EARP. Staff, OPC and the other signatories participating in the monitoring of the EARP may follow up with data requests, meetings and interviews, as required, to which UE will respond on a timely basis. UE will not be required to develop any new reports, but information presently being recorded and maintained by UE may be requested. The sharing of earnings in excess of 12.61 percent, as contemplated in the sharing grid set out above, is to be accomplished by the granting of a credit to UE's Missouri retain electric customers by applying credits to customers' bills in the same manner as applied in Case No. ER-95-411, and as set forth in the Stipulation and Agreement. In the final year of the EARP, UE, Staff, OPC and other signatories to the Stipulation and Agreement shall meet to review the monitoring reports and additional information required to be provided. By 8 February 1, 2001, UE, Staff and OPC will file and other signatories may file their recommendations with the Commission as to whether the EARP should be continued as is, continued with changes, or discontinued. The rates resulting from the Stipulation and Agreement will continued in effect after the three-year EARP period until UE's rates are changed as a result of a rate increase case, a rate reduction case, or other appropriate Commission action. UE and its prospective holding company, Ameren, agree to make available to the Commission, at reasonable times and places, all books and records and employees and officers of Ameren, UE and any affiliate or subsidiary of Ameren as provided under applicable law and Commission rules; provided, that Ameren, UE and any affiliate or subsidiary of Ameren shall have the right to object to such production of records or personnel on any basis under applicable law and Commission rules, excluding any objection that such records and personnel are not subject to Commission jurisdiction by operation of the Public Utility Holding Company Act of 1935 (PUHCA). UE, Ameren and any affiliate or subsidiary thereof agree to continue voluntary and cooperative discovery practices. UE, Ameren and each of its affiliates and subsidiaries shall employ accounting and other procedures and controls related to cost allocations and transfer pricing to ensure and facilitate full review by the Commission and to protect against cross-subsidization of non-UE Ameren businesses by UE's retail customers. UE and Ameren and each of its affiliates and subsidiaries will not seek to overturn, reverse, set aside, change or enjoin, whether through appeal or the initiation or maintenance of any action in any forum, a decision or order of the Commission which pertains to recovery, disallow- 9 ance, deferral or ratemaking treatment of any expense, charge, cost or allocation incurred or accrued by UE in or as a result of a contract, agreement, arrangement or transaction with any affiliate, associate, holding, mutual service or subsidiary company on the basis that such expense, charge, cost or allocation has itself been filed with or approved by the Securities and Exchange Commission (SEC) or was incurred pursuant to a contract, arrangement, agreement or allocation method which was filed with or approved by the SEC. This provision is also applied to both gas and electric contracts filed with the Federal Energy Regulatory Commission (FERC). No preapproval of affiliated transactions will be required, but all filings with the SEC or FERC for affiliated transactions will be provided to the Commission and the OPC. The Commission may make its determination regarding the ratemaking treatment to be accorded these transactions in a later ratemaking proceeding or a proceeding respecting any alternative regulation plan. Finally, the parties have agreed to a proposed system support agreement between UE and CIPS for a term of ten years. This agreement allows UE to transfer its current Illinois customers to CIPS, and provides for the transfer of electric power and capacity to CIPS for the ten-year period. This is capacity and energy currently used to supply UE's Illinois customers. The Stipulation and Agreement provides that the Commission has the authority to allocate energy and capacity addressed in the system support agreement in future ratemaking proceedings. 10 B. Market Power Issues In its September 25, 1996 order, the Commission requested additional testimony regarding the potential harm to the public interest from any increase in market power which may be created by the approval of the merger. Because market power might be of greatest concern to Missouri customers if full retail competition were authorized, the Commission specifically requested that the parties include retail competition as a scenario in their analysis. In response to this request, UE witness Rodney Frame stated that because retail competition will require changes to existing institutions that will affect how markets should be analyzed, it is neither reasonable nor advisable to address the implications of market power until these more fundamental issues are addressed. UE witness Maureen A. Borkowski stated that UE's transmission system was designed so that its power plants would serve its native load. Therefore, the import capability into the St. Louis area is limited by the capacity of its own transmission system. Further, Ms. Borkowski stated that these limits only become important to retail competition, and it would be premature to deal with such a scenario now. Mr. Frame believed that market power problems are likely to require more scrutiny when generation supplies are deregulated and individual retail customers can shop among alternative suppliers. UE witness Donald E. Brandt stated that the time to address potential market power problems associated with deregulation and retail customer choice is when the decision is made to go down that path, not now. Further, Mr. Brandt stated that any market power which UE or Ameren possesses in the retail market is currently mitigated by the regulatory oversight of the Commission. 11 OPC stated that the Commission is correct in its concern for the potential harm to the public interest from an increase in market power from the merger, especially under the assumption of retail competition. OPC's witness Dr. Richard A. Rosen recommended that the Commission require UE to analyze carefully and thoroughly whether the ability of the merged utilities to exercise market power under retail competition is likely to be greater than the ability of either individual utility. If there is a significant increase in market power resulting from the merger, the Commission should identify and implement all appropriate measures to mitigate the market power. OPC takes the position that the applicants for the merger have the responsibility to analyze market power, and that the Commission should require the companies to perform such an analysis as a condition for approving the merger. OPC does not argue that such a study must be completed prior to the Commission giving approval of the merger. Instead, it believes that if market power proves to be a problem, appropriate measures are available to mitigate market power, and the Commission should mandate such measures prior to implementation of retail competition. In his testimony, Staff's witness Dr. John W. Wilson presented an analysis of market power under retail competition. He defined the relevant market to be requirements power for both wholesale and retail customers served in the joint service territories of UE and CIPS. Two scenarios were considered: with and without pancaked transmission rates. With pancaked transmission rates, Dr. Wilson found that Ameren would have a price advantage over any competitors having to pay an additional transmission charge, and would therefore have significant market power. Without pancaked transmission rates, the relevant geographic market was found to 12 be limited by the nonsimultaneous first contingency total transfer capability into the Eastern Missouri (EMO) and South Central Illinois (SCILL) subregions of the Mid-America Interconnected Network (MAIN). Taking these transmission constraints into account, Dr. Wilson performed a concentration analysis to measure the likelihood of the merged firm exercising market power and found significant increases in concentration that exceeded the "safe harbor" limits established in the Department of Justice/Federal Trade Commission Merger Guidelines ("Guidelines"). Dr. Wilson then examined other factors, as suggested by the Guidelines, including: (1) the potential of the merger to give rise to anticompetitive effects; (2) entry conditions; (3) efficiencies; and (4) whether one of the firms is likely to exit the market because of financial stress. He found that the merger was likely to enhance the anticompetitive behavior associated with markets that are characterized as oligopolistic (few competitors with each recognizing that its own competitive conduct will significantly affect the other competitors), and will likely elicit defensive responses that allow dominant firms to exercise price leadership. With Ameren having just under 35 percent of the share of total capacity in the relevant market, Dr. Wilson expressed concern that the merged firm may find it profitable to increase price and reduce output below pre-merger levels because "the lost markups on the foregone sales may be outweighed by the resulting price increase on the merged base of sales" (Guidelines S 2.22). Market dominance was also seen as a potential barrier to entry for new firms. Most significant was the potential for vertical market power (the ability to exert market power in one or more horizontal markets as a result of the monopoly control of an essential element in a vertical chain of horizontal markets), based on Ameren's control of the transmission 13 system required to serve the requirements markets for generation within UE's and CIPS's service territories. While Dr. Wilson recommended against approval of the merger, the Staff continues to support the Stipulation and Agreement, as do UE and OPC. However, Dr. Wilson has made several recommendations regarding mitigation of market power should the Commission approve the merger. These include: (1) Ameren turning over the operation of its transmission system to an Independent System Operator (ISO) with a region-wide "postage-stamp" transmission rate; (2) divestiture of generation resources to reduce barriers to entry that arise from vertical integration; (3) introduction of retail access in Ameren's service territory to stimulate entry into retail generation sales; and (4) denial of stranded cost recovery by the merged entity to assure that any merger savings will be used to offset any above-market, uneconomic cost for generation. UE witnesses Mr. Brandt and Ms. Borkowski stated that requiring it to eliminate pancaking or to participate in an ISO would be unnecessary, inappropriate and premature. For example, UE witness Rodney Frame argued that requiring UE to join an ISO could produce adverse consequences for UE's native load customers due to cost shifting of a $42 million increase in transmission costs. Mr. Frame also cited FERC's Order 889, which sets forth a code of conduct and which requires that transmission owners participate in an Open Access Same- Time Information System (OASIS) for handling any concerns for the exercise of vertical market power in the markets that exist today. Thus, UE argues that the Commission should not require it to participate in an ISO until the terms of participation are known, and should also delay any consideration of the impact on retail markets until retail competition becomes a reality. 14 Dr. Wilson stated that the purpose for turning the operation of the transmission system over to an ISO is to alleviate the concern that, as the owner of both transmission and generation, the vertically integrated utility would be able to use the transmission system to "depress competition in generation markets." Dr. Wilson further pointed out that if an ISO is not established in a fully independent manner, vertically integrated owners of generation and transmission could have influence over who becomes and remains as the ISO operator, in which case nonowner generation rivals may not receive equal consideration. Dr. Rosen stated that while FERC Order 888 recognizes transmission access and pricing as core requirements to deal with potential vertical market power abuse, the FERC also identified regional ISOs as an important measure for mitigating potential vertical market power. Dr. Rosen summarized the FERC guidelines which specify that an ISO: "1) have no financial interest in the economic performance of any market power participant; 2) should have control over the operation of interconnected transmission facilities within its region; 3) should identify constraints on the system and be able to take operational action to relieve those constraints within the trading rules; and 4) should make transmission system information publicly available to all suppliers on a timely basis." In addition, Dr. Rosen noted that the FERC identified expansion of transfer capability by enlarging transmission capacity as a mitigation measure for vertical market power, but recognized that utilities must obtain approvals for such expansion from state and local authorities under applicable laws. The Commission finds there are sufficient facts in evidence to be concerned about the potential increase in market power from the proposed merger. The merger could have a significant adverse impact on the degree 15 of competition within UE's Missouri service territory due to limited transfer capability for imported power, as well as the disincentives caused by pancaked transmission rates. In order to eliminate pancaked transmission rates, Ameren would need to belong to a regional transmission group having a region-wide transmission rate. To address the vertical market power concern that Ameren could use its transmission system to restrict competition from other generation, the regional transmission group should be an entity that will independently operate the transmission systems of the vertically integrated utilities within the region. While the Commission agrees that UE and Ameren should not participate in an ISO at "any cost" to the Missouri ratepayers, now is the time for UE to take into account the impact that vertical market power could have on the requirements market under retail competition. Therefore, the Commission approves the merger upon the condition that UE shall participate in a regional ISO that eliminates pancaked transmission rates and that is consistent with the ISO guidelines set out in FERC Order 888. Such an ISO proposal could be formed in conjunction with the current efforts by UE and other regional utilities to establish a Midwest ISO or be organized by the merged company with membership open to other regional utilities. While the Commission understands that joining an ISO at "any cost" would be unwise, the participation by UE and Ameren in an ISO is a prudent, necessary condition to assure that the merger is not detrimental to the public interest. The Commission also finds that the concerns expressed by OPC regarding horizontal market power are valid. Such market power can take place at any level of the production chain as a consequence of there being a very small number of competing sellers and significant barriers to entry. 16 Specifically, Dr. Richard A. Rosen expressed concern about horizontal market power for the generation end of the production chain, as well as in the retail merchant (demand-side aggregator) markets. Dr. Rosen expressed concern that alternative generators might find it difficult to enter certain submarkets for electricity such as the base load, long term market for capacity and energy, or areas where transmission constraints and strategically located generation facilities combine to form local "load pockets." In the retail merchant markets, Dr. Rosen believes that new aggregators would find it difficult to compete with the incumbent utility because of lack of name recognition. In order to deal with this potential for horizontal market power, Dr. Rosen proposed a two-part analysis: (1) theoretical and empirical characterizations of the market; and (2) simulations of the particular electricity market under consideration. In both, the unique characteristics of electricity markets in at least the nine submarkets (base, cycling and peaking by short, medium and long term) should be examined. In the first analysis, Dr. Rosen suggested that a more sophisticated version of the Herfindahl-Hirschman Index (HHI) be developed. In the second analysis, Dr. Rosen recommended that the simulations include real data from various utilities in a proposed ISO, and that various gaming scenarios and bidding strategies be analyzed. The Commission finds that there are sufficient facts in evidence for it to be concerned about horizontal market power for both generation and aggregation. The Commission also finds that these concerns are in part related to the merger of the two companies, but are also related to conditions that should be considered before implementing retail competition. OPC's proposal balances these two relationships. Therefore, the 17 Commission will require UE and interested parties to assess the potential ability of the merged companies to exercise vertical and especially horizontal market power in price deregulated retail generation markets. Based on this analysis, if the market power under retail competition proves to be a problem, then the Commission will consider taking appropriate action to mitigate market power prior to establishing statewide retail competition. Because the level of detail and development of a study of horizontal market power will require significant effort and time, the Commission will require UE to undertake this study with the participation of Staff and OPC, with a completion date of January 1, 1998. This study need not be submitted before the merger is completed. Therefore, the Commission finds the proposed Stipulation And Agreement to be reasonable and in the public interest if it is modified to include the conditions which the Commission requires to mitigate market power. As set out in the Stipulation, after review of both the testimony filed in this matter and the proposed merger agreement of November 7, 1995, the Commission also finds the proposed merger, as modified and subject to the conditions of the attached Stipulation And Agreement, to not be detrimental to the public interest. Therefore, the Commission will approve the proposed Stipulation And Agreement as set out in Attachment 1 and the resulting merger transaction, and order UE to file tariffs in accordance therewith. Conclusions of Law ------------------ The Missouri Public Service Commission has arrived at the following conclusions of law. 18 The applicant, Union Electric Company, is a public utility under the jurisdiction of the Commission, regulated generally by Chapter 393, RSMo 1994. Specifically, the proposed sale, transfer and assignment of certain rights, properties, and assets is controlled by Section 393.190(1), which states in 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, nor by any means, direct or indirect, merge or consolidate such works or system, or franchises, or any part thereof, with any other corporation, person or public utility, without having first secured from the commission an order authorizing it to do so. The Commission has found the Stipulation And Agreement, as set out in Attachment 1 hereto, to be just and reasonable, and will approve the Stipulation And Agreement. In addition, the Commission finds the proposed merger transaction, as reflected in the contractual agreement contained as a part of the Union Electric Company filing of November 7, 1995, and subject to the conditions and modifications as set out in the above Stipulation And Agreement, is not detrimental to the public interest. The Commission further concludes that Union Electric Company should file tariffs in full compliance with the merger agreement, the Stipulation And Agreement, and this Report And Order. IT IS THEREFORE ORDERED: 1. That the Stipulation And Agreement, marked Attachment 1 to this Report And Order, will be approved by order of the Commission provided that Union Electric Company files a pleading in this docket within ten (10) 19 days of the date of issuance of this order consenting to the following conditions: (a) No later than December 31, 1997, Union Electric Company shall file or join in the filing of a regional ISO proposal at the Federal Energy Regulatory Commission that eliminates pancaked transmission rates, that is consistent with the ISO guidelines set out in FERC Order 888, and the meets the following requirements: (1) If the ISO proposal filed filed at FERC is the result of the current efforts by UE and other utilities to establish a Midwest ISO, UE shall simultaneously file at this Commission a request for approval of its participation in the proposed ISO; (2) If the Midwest ISO proposal is filed at FERC and UE has chosen not to participate, then UE shall advise this Commission within thirty (30) days of the FERC filing why it is not participating in the Midwest ISO; (3) If the Midwest ISO proposal is not filed before the FERC by December 31, 1997, then by March 31, 1998 UE shall file with this Commission a plan for establishing an independent entity charged with the operation, pricing and planning of its transmission system. This plan shall be developed in cooperation with Staff and the Office of the Public Counsel, shall provide for the formation and expansion of this 20 independent entity to include other utilities, and shall be filed with the FERC; and (b) By January 1, 1998 and with the participation of Staff and the Office of Public Counsel, Union Electric Company shall file with this Commission a report that assesses the potential ability of the merged companies to exercise vertical and especially horizontal market power in price deregulated retail generation. 2. That, with the consent of the parties, the testimony of Union Electric Company witnesses Rodney Frame, Maureen A. Borkowski and Donald E. Brandt; Office of the Public Counsel witness Dr. Richard A. Rosen; and the Commission Staff witness Dr. John W. Wilson is hereby entered into evidence and made a part of the record in this proceeding. 3. That this Report And Order shall become effective on March 4, 1997. BY THE COMMISSION /s/ Cecil I. Wright Cecil I. Wright Executive Secretary ( S E A L ) McClure and Kincheloe, CC., concur; Zobrist, Chm., Crumpton and Drainer, CC., concur, with concurring opinions to follow. Dated at Jefferson City, Missouri, on this 21st day of February, 1997. 21 BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MISSOURI In the Matter of the Application of ) Union Electric Company for an Order ) Authorizing (1) Certain Merger ) Transactions Involving Union Electric ) Company; (2) the Transfer of Certain ) Case No. EM-96-149 Assets, Real Estate, Leased Property, ) ------------------ Easements and Contractual Agreements ) to Central Illinois Public Service ) Company; and (3) in Connection ) Therewith, Certain Other Related ) Transactions. ) CONCURRING OPINION OF COMMISSIONER HAROLD CRUMPTON ================================================== AND VICE CHAIR M. DIANNE DRAINER ================================ We concur with the Commission's decision in Case No. EM-96-149, which approved the Stipulation and Agreement and specified that the proposed merger transaction between Union Electric Company (UE) and CIPSCO Incorporated (CIPSCO) is not detrimental to the public interest. However, we respectfully do not agree with the majority that the additional conditions set out in the order are appropriate or necessary at this time. It is premature to state that participation in an independent system operator (ISO) company is a necessary condition in order to assure that the merger is not detrimental to the public interest. Although we would encourage UE to recognize that becoming a member of an ISO is a prudent move in the current pre-competitive electric environment, it is going too far to make it a necessary condition when, in fact, there is presently no Midwest ISO established for UE to join in Missouri. Additionally, although the Commission states "that joining an ISO at 'any cost' would be unwise", it does not define the criteria that UE should use to evaluate when the ISO concept has become too costly to join. With respect to the obligation placed on UE to complete a market power report in this docket, we agree with UE witness Rodney Frame that it was premature to require an analysis of the market power implications of the proposed merger, given the many uncertain and unknown changes facing the electric industry. It would be more prudent at this time to open a new docket to review the restructuring of the electric industry and retail wheeling in Missouri, in which all interested parties may participate. If and when competition and restructuring become a part of the electric utility environment in Missouri, there should be an assessment of all market power issues for all electric companies in the state. This was not the case to demand such an assessment. We should not be bureaucratic in demanding a report in this docket which will be incomplete because numerous variables needed for a future market power analysis are currently unknown. In addition, parties essential to providing a thorough market power report have not been given the opportunity to participate in the drafting of that report. Finally, all companies have limited human resources to depend upon to gather data and write analytical reports. These resources place expense demands on companies that translate into increased revenue requirements. Therefore, we must be prudent when requesting additional reporting documents from companies. Respectfully Submitted, /s/ Harold Crumpton Harold Crumpton Commissioner (SEAL) /s/ M. Dianne Drainer M. Dianne Drainer Vice Chair Dated at Jefferson City, Missouri, on this 6th day of March, 1997. BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MISSOURI In the Matter of the Application of Union Electric ) Company for an Order Authorizing (1) Certain ) Merger Transactions Involving Union Electric ) Company; (2) the Transfer of Certain Assets, ) Case No. EM-96-149 Real Estate, Leased Property, Easements and ) ------------------ Contractual Agreements to Central Illinois Public ) Service Company; and (3) in Connection There- ) with, Certain Other Related Transactions. ) CONCURRING OPINION ------------------ Zobrist, Chairman: This case stands as an example of the difficult issues facing state commissions considering mergers and consolidations at a time when Congress and state legislatures debate the merits of restructuring the electric industry. On the important issue of market power, I found it puzzling that the parties apparently avoided discussion of this topic in their efforts to arrive at the Stipulation and Agreement. If such discussions occurred, the record initially contained very little hint of it. While there exists no universally accepted method to analyze post-merger market power under the current system of monopoly franchises, all parties must engage in a comprehensive effort to develop the analytical tools to study this issue. While economies of scale through consolidation and merger may bring the benefits of lower prices, better service and more choices to customers, the market power of such new entities cannot be allowed to manipulate prices to generate excessive profits. The study which the Commission ordered should use those tools which can best measure the ability of Ameren to achieve benefits for its customers. I encourage the Commission's Staff 1 and the Office of the Public Counsel to work constructively with the company to produce an analysis which is meaningful and practical. The parties should consider the use of computer models, such as those which are a part of the record in the proposed merger of Northern States Power Company and Wisconsin Electric Power Company into Primergy Corporation. See In re Wisconsin Elec. Power Co., et al., Docket No. EC95-16-000 (F.E.R.C., Aug. 29, 1996) (presiding administrative law judge's initial decision). Although these kinds of tools may be works in progress, like the Hatfield Model and other proxy cost models being developed in the telecommunications arena, they should be explored and used if they offer hope of advancing the analysis. I am not certain that the Federal Energy Regulatory Commission's adoption of the Department of Justice/Federal Trade Commission Merger Guidelines, which include the Herfindal-Hirschman Index (HHI), gives us the best tool to analyze market power in the electricity industry. See In re Commission's Merger Policy under the Federal Power Act: Policy Statement, Order No. 592, Docket No. RM96-6-000 (F.E.R.C., Dec. 18, 1996). It may be that the Guidelines are a first and necessary step in a long series of steps to better market analysis. I expect that more sophisticated tools will develop as the electricity industry changes. Any future merger case brought before this Commission should contain a careful analysis of market power issues, in addition to the traditional means used to measure the alleged merger benefits for ratepayers. All parties, including Staff, should be careful in their selection of expert witnesses. Staff's position endorsing the Stipulation and Agreement in this case was weakened by its retention of an expert who opposed Staff's recommendations. While he offered certain helpful observations on market power, his argument for divestiture under the facts of this case was not at 2 all persuasive. Finally, I believe that the Commission wisely approved this merger upon the condition that Union Electric Company and its holding company Ameren join an independent system operator (ISO). The concept of an ISO which offers non- discriminatory access to the integrated transmission system over a broad region is the last, best hope for those who wish to avoid mitigating market power at the local level through the divestiture of generation assets. Many knowledgeable individuals have expressed the belief that an ISO cannot function as a truly independent operator because the transmission owners will refuse to grant the necessary authority to the ISO governors. While such skepticism may be justified, I believe that governing principles can be developed which grant sufficient powers to the "trustees" of the transmission system to make the ISO truly independent. See "Declaration of Independence" (signed by 18 state commissioners) (Oct. 22, 1996). This Declaration, which follows my opinion, expresses the belief that an ISO can function properly only if its independence is guaranteed. While the owners of the transmission system are entitled to retain a voice in the operation, maintenance and planning of the system, they must absolutely relinquish any ability to control or unduly influence the ISO. Otherwise, they have proven the case that divestiture is the only solution. /s/ Karl Zobrist ---------------------------------- Karl Zobrist, Chair March 10, 1997 3 A DECLARATION OF INDEPENDENCE Why Transmission and System Operation Must Be Truly Independent from the Ownership of Generation Efforts to restructure the electric power industry are based on the conviction that open competition in power supply will advance consumer interests better than traditional economic regulation. The objective of restructuring must be to create conditions that will allow genuine competition to thrive. The ultimate measure of success is whether competition delivers benefits to consumers, not just to those in the electricity business, either competitive electricity suppliers or providers of monopoly wire services. To succeed, the restructuring process must address the inherent market power problems caused by ownership or control of the monopoly transmission system that connects competitive generators with their customers. The divergent interests of suppliers and customers are clear: * In competitive electricity markets, all generators will benefit from high prices while customers benefit from low prices; * In competitive markets, higher prices achieved through any action, including control of the transmission system, by any generator or group of generators, will benefit all generators; * Decisions regarding transmission pricing, dispatch rules, and new investment in the transmission system can add value to generation. An unnecessarily constrained transmission system will lead to overpriced electricity and excess profits for suppliers; * Many techniques for leveraging transmission and system operation to add value to generation assets are complex, subtle, and difficult to control through regulatory oversight. This means that steps taken to deregulate supply could harm rather than advance consumer interests, if not paired with measures to sever suppliers' control over transmission services. To ensure that the transmission system is operated and expanded to suit the needs of society at large rather than the narrower interest of generators, most nations implementing competition in generation have chosen to completely separate the ownership of power plants from ownership or control of transmission lines. Such separation provides a clear, workable and effective means of protection against the potential for many types of abuse. However, many US utilities oppose divestiture of either generation or transmission assets. They offer instead to separate ownership from control, by placing control of the transmission system in an "Independent System Operator" or ISO. Unfortunately, most ISO proposals put forth to date have been seriously deficient in one or both of two key areas: (1) the scope of functions entrusted to the ISO is too limited, so it does not effectively control transmission pricing and system operation, and (2) the ISO is not truly independent. Each ISO should have a mandate to manage and expand the portion of the nation's grid under its control so as to ensure reliability while minimizing costs. The management of the transmission system involves the exercise of hundreds of small and large decisions, many of them subjective judgment calls, involving such matters as the pricing of transmission service, construction of new lines, and operation and maintenance of the existing system. All of these decisions should be made by the ISO, subject to regulatory oversight. The transmission system should be operated and expanded so as to encourage rather than limit competitive challenges among suppliers. Most ISO proposals fall short by giving suppliers substantial, or in some cases, majority control of the system. Independence is not achieved by simply sharing control of the transmission system among different types of suppliers. To achieve independence, ISOs should be responsible to boards that are completely independent of suppliers. In the absence of a clear structural solution such as divestiture, we must create solutions equivalent to a non- voting "transmission trust": generating companies must cede all control of their transmission lines to the ISO; they will be entitled to fair compensation on their investment, but afforded no opportunity to influence the use of those lines. The ISO should, in turn, be subject to appropriate regulatory oversight. This regulatory framework should strive to harmonize the interests of the ISO with those of the public: reliability and stability, low generation and transmission prices, and minimum environmental impact. Such regulation must reflect both federal and state interests, ensuring the development of regional markets while recognizing states' interests in siting, and in shaping regulatory reform to suit local concerns. Effective regulation of regional markets and transmission systems may require creation of new regional governance mechanisms, such as regional joint boards or councils under existing or new enabling legislation. However this is accomplished, FERC, the States, and Congress must insist upon creation of ISOs that have authority to operate and improve regional transmission systems, and that are truly independent from the owners of generation resources. Only when transmission constraints cannot be used to leverage above-market value from generation assets will the public's interests in genuine competition be well served. Richard H. Cowart, Chair John B. Howe, Char Suzanne D. Rude Janet Gail Besser David Coen Massachusetts DPU Vermont PSB Karl Zobrist, Chair Edward M. Meyers, Com. Duncan E. Kincheloe District of Columbia PSC Missouri PSC Roger Hamilton, Chair Wayne Shirley, Chair Ron Eachus New Mexico PUC Joan Smith Oregon PUC Renz D. Jennings, Chair Arizona Corp. Commission John Hanger Craig A. Glazer, Chair Pennsylvania PUC Ohio PUC James J. Malachowski, Chair Karl A. McDermott Paul E. Hanaway Illinois Commerce Com. Kate F. Racine Rhode Island PUC Sharon L. Nelson, Chair Richard Hemstad, Com. William R. Gillis, Com. Washington U & TC BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MISSOURI In the matter of the Application ) of Union Electric Company for an ) order authorizing: (1) certain merger ) transactions involving Union Electric ) Company; (2) the transfer of certain ) Case No. EM-96-149 Assets, Real Estate, Leased Property, ) Easements and Contractual Agreements ) to Central Illinois Public Service ) Company; and (3) in connection ) therewith, certain other related ) transactions. ) NOTICE OF ACCEPTANCE OF CONDITIONS ---------------------------------- COMES NOW Union Electric Company and states that it accepts the conditions set forth in the Ordered section, paragraph 1(a)(1)-(3) and 1(b), in the Missouri Public Service Commission Report and Order effective March 4, 1997. Respectfully submitted, UNION ELECTRIC COMPANY By /s/ James J. Cook ------------------------------ James J. Cook, MBE 22697 Joseph H. Raybuck, MBE 31241 William J. Niehoff, NBE 36448 Attorneys for Union Electric Company 1901 Chouteau Avenue P.O. Box 149 (M/C 1310) St. Louis, Missouri 63166 (314) 554-2237 (314) 554-2976 (314) 554-2514 (314) 554-4014 (fax) CERTIFICATE OF SERVICE ---------------------- I hereby certify that on this 24th day of February, 1997, a copy of the foregoing was served upon All Parties of Record. /s/ James J. Cook ------------------------------ James J.Cook EX-99.G-1.1 3 FINANCIAL DATA SCHEDULE EXHIBIT G-1.1 AMEREN CORPORATION UNAUDITED PRO FORMA COMBINED FINANCIAL DATA SCHEDULE (Thousands of Dollars Except Per Share Amounts) Three Months Ended March 31, 1997
Pro Forma Pro Forma Caption Heading UE CIPSCO Adjustments Combined --------------- ---------- ---------- ----------- ---------- 1 Total net utility plant $5,390,727 $1,455,388 $ 106,165 $6,952,280 2 Other property and investments 100,366 115,830 0 216,196 3 Total current assets 435,682 194,399 52,250 682,331 4 Total deferred charges 39,572 29,743 (2,694) 66,621 5 Balancing amount for total assets 849,642 174,877 0 1,024,519 6 Total assets 6,815,989 1,970,237 155,721 8,941,947 7 Common stock 510,619 356,812 (866,059) 1,372 8 Capital surplus, paid in 716,879 0 866,059 1,582,938 9 Retained earnings 1,091,090 302,592 0 1,393,682 10 Total common stockholders equity 2,318,588 659,404 0 2,977,992 11 Preferred stock subject to mandatory redemption 0 0 0 0 12 Preferred stock not subject to mandatory redemption 155,197 80,000 0 235,197 13 Long term debt, net 1,879,651 493,303 115,556 2,488,510 14 Short term notes 33,900 0 0 33,900 15 Notes payable 0 0 0 0 16 Commercial paper 0 41,025 14,444 41,025 17 Long term debt-current portion 5,000 58,000 0 77,444 18 Preferred stock-current portion 0 0 0 0 19 Obligations under capital leases 80,798 0 0 80,798 20 Obligations under capital leases-current portion 32,631 0 0 32,631 21 Balancing amount for capitalization and liabilities 2,310,224 638,505 25,721 2,974,450 22 Total capitalization and liabilities 6,815,989 1,970,237 155,721 8,941,947 23 Gross operating revenue 487,258 225,343 48,377 760,978 24 Federal and state income taxes expense 21,335 9,476 2,033 32,844 25 Other operating expenses 400,336 191,394 40,943 632,673 26 Total operating expenses 421,671 200,870 42,976 665,517 27 Operating income (loss) 65,587 24,473 5,401 95,461 28 Other income (loss), net (204) 146 (2,940) (2,998) 29 Income before interest charges 65,383 24,619 2,461 92,463 30 Total interest charges 33,753 8,155 2,461 44,369 31 Net income 29,426 15,551 0 44,977 32 Preferred stock dividends 2,204 913 0 3,117 33 Earnings available for common stock 29,426 15,551 0 44,977 34 Common stock dividends 64,849 17,716 4,567 87,132 35 Total annual interest charges on all bonds * 0 0 0 0 36 Cash flow from operations 63,351 (14,104) 13,181 62,428 37 Earnings per share-primary $0.29 $0.46 0 $0.33 38 Earnings per share-fully diluted $0.29 $0.46 0 $0.33
* Required on fiscal year-end only EX-99.K-1.1 4 SUPPLEMENTAL ANALYSIS OF THE ECONOMIC IMPACT Exhibit K-1.1 UNION ELECTRIC COMPANY & CENTRAL ILLINOIS PUBLIC SERVICE COMPANY SUPPLEMENTAL ANALYSIS OF THE ECONOMIC IMPACT OF A DIVESTITURE OF THE GAS OPERATIONS OF UE AND CIPS The management and staffs of Union Electric Company (UE) and Central Illinois Public Service Company (CIPS) conducted this supplemental study to the "Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS" dated September 19, 1996. The Analysis dated September 19, 1996 determined the economic effects on shareholders and customers of divesting UE and CIPS of their natural gas assets and businesses by spinning them off into two separate and distinct entities. This supplemental study evaluates the additional costs from lost economies that would be associated with the spin-off of UE's and CIPS' natural gas assets and businesses followed by a combination of the two entities into one gas entity, all of which would take place after the merger and creation of Ameren Corporation. July 10, 1997 TABLE OF CONTENTS -----------------
PAGE ---- SECTION I. EXECUTIVE SUMMARY AND CONCLUSIONS 1 SECTION II. GENERAL STUDY ASSUMPTIONS 5 SECTION III. NEWGAS-UE/CIPS A. OVERVIEW 7 B. ANALYSIS 8 C. SCHEDULE OF EXHIBITS 15
=============================================== SECTION I. EXECUTIVE SUMMARY AND CONCLUSIONS =============================================== On September 19, 1996, the management and staffs of Union Electric Company (UE) and Central Illinois Public Service Company (CIPS) completed a study entitled "Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS" (Study). The Study, submitted as Exhibit K-1 to the Form U-1 filed on October 31, 1996, demonstrated that substantial additional costs from "lost economies" would be associated with the divestiture of the separate gas companies of UE and CIPS. The present study, entitled "Supplemental Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS" (Supplemental Study), evaluates the additional costs from lost economies that would be associated with the spin-off of UE's and CIPS' natural gas assets and businesses followed by a combination of the two entities into one gas entity, all of which would take place after the merger and creation of Ameren Corporation. The Supplemental Study shows that while lost economies would be somewhat smaller if the gas operations of UE and CIPS were combined, the additional costs are nonetheless very significant. The Supplemental Study further demonstrates that continued retention of the gas operations by UE and CIPS following the merger is in the best interest of the ratepayers and shareholders alike. As with the original Study, where possible, estimates of the operating costs were compared to similar investor-owned gas distribution companies in the Midwest. The effects on shareholders were calculated using the increased costs caused by divestiture assuming no rate relief. The effects on customers were calculated assuming recovery of additional costs through rate increases. To facilitate comparisons, the Supplemental Study utilizes data for the same time period used in the Study. INCOME TAXES ON THE DIVESTITURE TRANSACTION - ------------------------------------------- Under current law, the divestiture of the gas businesses of UE and CIPS into a single, combined company, after the merger and creation of Ameren Corporation, could be accomplished on a tax-free basis. However, legislation is pending in the U.S. Congress that, if passed, would apply to this transaction and would impose substantial income taxes. Under the proposed legislation, CIPS would be subject to income tax on the difference between the fair market value of its gas assets (as of the date they are spun off from CIPS) and the tax basis of those assets. Using the net book value as a conservative minimum fair market value for these assets, it is estimated that these income taxes would be at least $24,000,000. These costs would, if incurred, substantially increase the lost economies already illustrated in Section I, Tables I-1 and I-2, to follow. 1 SHAREHOLDERS - ------------ The projected effects on the shareholders of the lost economies resulting from the spin-off of UE's and CIPS' gas businesses into NEWGAS-UE/CIPS are shown in Table I-1:
TABLE I-1* ANNUAL EFFECT OF LOST ECONOMIES ON SHAREHOLDERS ------------------------------------------------------------ NEWGAS-UE/CIPS ------------------------------------------------------------ Lost Economies $34,768,000 Lost Economies as a Percent of: Total Gas Operating Revenue 15.99% Total Gas Operating Revenue Deductions 17.57% Gross Gas Income 177.66% Net Gas Income 252.34% In the Absence of Rate Relief: Return on Rate Base -4.78% Return on Net Plant -4.32% ------------------------------------------------------------ * The effect of lost economies shown in this table does not reflect income tax liability from proposed tax legislation, as previously explained. ------------------------------------------------------------
In Table I-1, Lost Economies represents the increased costs, excluding income taxes, to operate as one stand-alone company. Total Gas Operating Revenue is the sum of all gas revenues for the 12 months ended December 31, 1995. Total Gas Operating Revenue Deductions include all purchased gas and gas withdrawn from storage, operation and maintenance expenses, depreciation and taxes other than income taxes. Gross Gas Income is the difference between Total Gas Operating Revenue and Total Gas Operating Revenue Deductions. Net Gas Income is Gross Gas Income minus Income Taxes. (See SECTION III.C. NEWGAS-UE/CIPS Exhibit 1 for detailed information.) GAS CUSTOMERS - ------------- The projected effect on gas customers, assuming the stand-alone organization is allowed rate increases to recover lost economies and applicable income taxes, is shown in Table I-2: 2
-------------------------------------------------- TABLE I-2* ANNUAL EFFECT OF LOST ECONOMIES ON GAS CUSTOMERS -------------------------------------------------- RATE REVENUE NEWGAS-UE/CIPS Pre Spin-off $217,425,000 Post Spin-off $267,857,000 Dollar Increase $ 50,432,000 Percent Increase 23.20% -------------------------------------------------- * The effect of lost economies shown in this table does not reflect income tax liability from proposed tax legislation, as previously explained --------------------------------------------------
(See SECTION III.C. NEWGAS-UE/CIPS Exhibit 1 for detailed information supporting Table I-2.) ELECTRIC CUSTOMERS - ------------------ In addition to the forgoing impacts, divesting the gas business would result in rate increases of .73% for CIPS electric customers and .11% for UE electric customers. This impact is due to each company transferring all common property into the electric rate base, requiring rate increases to maintain the existing rates of return. CONCLUSIONS - ----------- The economies that CIPS and UE realize from combined electric and gas operations provide significant benefits to customers and shareholders. This Supplemental Study demonstrates that spinning off the two gas divisions into a separate entity would be inefficient due to lost economies, which would be passed on to gas customers, electric customers and/or to shareholders. Without increased rates, the immediate negative effect on shareholders' earnings would be substantial, making ownership of shares in NEWGAS-UE/CIPS unattractive. The pass-through of increased costs to customers would cause significant increases in gas rates, with no increase in the level or quality of service. The rate increases required to operate NEWGAS-UE/CIPS would total about $50,432,000 (Table I-2). Such increases would make NEWGAS-UE/CIPS less competitive at a time when competition in the energy industry is rapidly increasing due to Federal Energy Regulatory Commission (FERC) Order 636 and other FERC and state regulatory initiatives. In addition, NEWGAS-UE/CIPS would receive none of the benefits expected to accrue from the proposed merger. It is estimated there would be no substantial benefits from the divestiture of the gas businesses for electric customers. Minimal savings could be achieved for items such as data processing costs, and minimal personnel reductions could occur in the combination gas and electric districts. These savings would be offset by additional costs such as changing meter reading routes and modifying data processing applications. 3 Proposed tax legislation would substantially increase the lost economies, previously illustrated on Tables I-1 and I-2. 4 SECTION II. GENERAL STUDY ASSUMPTIONS The assumptions, information and data utilized for this Supplemental Study are based on the industry expertise and experience of the management and staffs of UE and CIPS. Below are the major assumptions employed for this Supplemental Study, which are substantially the same as was used in the original Study: 1. Organization: Each of the gas organizations to be spun off would combine to operate as one independent, stand-alone, publicly held, regulated company. It would have all the necessary management personnel, along with facilities, equipment, materials, supplies, etc., required to operate as a stand-alone company. 2. System Operation & Maintenance: The gas and electric systems would continue to be operated and administered in the existing manner to insure safe and reliable service. In addition, current system renewal programs would be continued. 3. Staffing: A sufficient number of employees would be included within the stand-alone gas company to ensure that customers receive the present level and quality of service. 4. Labor Costs: Labor cost estimates were based upon assessments of work assignments, using UE and CIPS wage structures. Senior management salary estimates were based on industry averages. 5. Non-labor Costs: These costs were estimated based upon actual costs incurred by UE and CIPS for their gas businesses assuming the customers of NEWGAS- UE/CIPS would receive existing levels and quality of service. 6. Cost Pass-through: Full pass-through to customers of increased costs due to lost economies would be allowed in formal rate proceedings. 7. Specific Labor Assumptions: --------------------------- a) Organization size and spans of control were estimated using existing UE and CIPS structures, adjusted to recognize the broader functional responsibilities that would exist in the new, smaller company. b) Pensions and benefits were estimated as a percent of direct labor cost. c) Employee benefits would be similar to the combined companies of UE and CIPS. 8. Capital Expenditure and Cost Assumptions: ----------------------------------------- a) The accounting for direct and indirect capital expenditures would remain the same as that currently used in the combined utilities of UE and CIPS. b) The actual capital costs for the divested company would be considerably higher than those of UE and CIPS. Since gas purchases are highly seasonal, the 5 b) The actual capital costs for the divested company would be considerably higher than those of UE and CIPS. Since gas purchases are highly seasonal, the stand-alone gas company would experience great volatility in its cash positions. At the same time, the book value of the assets of NEWGAS-UE/CIPS would be much smaller than those of the combined utility predecessors. As a result, the new company would be perceived as riskier and would be subject to higher borrowing rates. Because of the constraints of the CIPS and UE mortgage indentures, the debt associated with the spun-off facilities would have to be refinanced at today's rates. 9. Transition Cost Assumptions: Costs such as the legal, investment banking, filing and printing fees associated with the public spin-off of stock, creation of new indenture agreements, negotiation of new service contracts and costs to establish business processes would be incurred and amortized appropriately. 10. Transactions Between Companies: All transactions and transfers between NEWGAS-UE/CIPS and UE/CIPS, would be arms-length transactions based upon fair market values. 11. Other Assumptions: ------------------ a) Facility costs would include separate headquarters, storerooms, and office space for employees currently using facilities shared by the electric and gas businesses. b) To facilitate the assessment of financial effects, it was assumed the costs for outsourcing and performing work in-house would be comparable. c) Information Services work would be outsourced. d) Additional equipment (i.e., vehicles, trenchers, heavy power operated equipment) would be leased under an operating lease. e) External auditing costs were estimated based on industry surveys. f) Insurance costs were quotes based on protecting the gas utility against losses and damages to leased properties used in its operations, as well as injuries and damage claims. g) Regulatory commission expenses would be similar to those currently incurred in connection with formal cases before regulatory commissions involving gas operations. h) Potential costs for clean-up of environmental sites (coal gasification plants) would be the same whether or not the gas businesses are spun off. For this reason such costs were not considered in this Supplemental Study. 6 ================================================================================ SECTION III.A. NEWGAS-UE/CIPS OVERVIEW ================================================================================ Spinning off UE's and CIPS' gas operations into a separate stand-alone company (NEWGAS-UE/CIPS) would result in the following: . NEWGAS-UE/CIPS would need to establish service functions duplicating those at UE and CIPS, including treasury, financial planning, accounting, tax planning and compliance, rates, risk management, employee benefits, marketing, legal, customer service, regulatory and public affairs. . Annual operating revenue deductions, exclusive of income taxes, for NEWGAS- UE/CIPS would be about 18% ($34.8 million) greater than UE's and CIPS gas operating revenue deductions. (SECTION III.C, Exhibit 1). . NEWGAS-UE/CIPS' customers would experience a rate increase of about 23% ($50.4 million) in order to provide an 11.07% rate of return for stockholders (SECTION III.C, Exhibit 1). . NEWGAS-UE/CIPS would be at a competitive disadvantage because of high operating expenses. . There would be no substantial benefits for customers or stockholders. 7 ================================================================================ SECTION III.B. NEWGAS-UE/CIPS ANALYSIS ================================================================================ The UE and CIPS gas distribution systems serve a total of approximately 288,000 (as of December 31, 1995) customers over a 23,000 square mile area in Missouri and Illinois. There are 7,150 miles of mains and 3,955 miles of service lines in the combined systems. Natural gas revenues for 1995 were $217.4 million on total system throughputs of 53.5 billion cubic feet of gas. UE and CIPS operate as tightly integrated companies with many employees supporting both gas and electric operations. Of UE's and CIPS' 8,618 employees (as of December 31, 1995), only 349 devote 100% of their time to gas operations. Shared operations include customer service personnel who deal with service requests for both gas and electric customers, and meter readers who read both the electric and gas meters. Additionally, UE's and CIPS' gas and electric businesses also share services in the areas of treasury, financial planning, accounting, tax planning and compliance, rates, risk management, employee benefits, marketing, legal, customer service, regulatory and public affairs. The shared gas/electric responsibilities of many of UE's and CIPS' employees have enabled UE and CIPS to provide quality service at low costs. ORGANIZATION STRUCTURE AND STAFFING IMPACT - ------------------------------------------ The UE and CIPS organizations, as of December 31, 1995, were used as a pattern for developing the NEWGAS-UE/CIPS organization structure. See SECTION III.C, Exhibit 5 for the proposed organization. Divesting the gas operations would eliminate the effective use of shared staff to the detriment of both the gas and electric operations. To operate the gas business on a stand-alone basis, 553 additional employees would be required, in addition to the 349 employees mentioned above. UE and CIPS could expect very minimal staffing reductions in the electric business as a result of a gas divestiture. SECTION III.C, Exhibit 6 shows the proposed staffing, salaries, and wages summary, while Exhibit 2d shows that NEWGAS-UE/CIPS would incur an estimated net labor increase, including benefits, of $14,522,000. Exhibit 7 shows that with this proposed staffing, NEWGAS-UE/CIPS compares favorably with other gas utilities in the number of customers per employee. The following comments demonstrate some of the reasons for additional staffing: Each customer of UE and CIPS receives one bill for both gas and electric service and pays with one check. When treasury personnel process the checks, automated equipment posts both electric and gas payments to customers' accounts. NEWGAS-UE/CIPS would have to hire staff to handle gas payments that are now handled at essentially no additional cost by UE and CIPS. Spinning off the gas operations would only minimally reduce the workload on UE's and CIPS' cash 8 processing personnel, since most gas customers also have electric service and would still send a check monthly. UE's and CIPS' meter readers read gas and electric meters in the same routes. NEWGAS-UE/CIPS would have to hire meter readers to re-trace the same routes to read the gas meters. Spinning off the gas operations would not reduce the number of meter readers needed by UE and CIPS since their routes would remain essentially the same. UE's Finance, Accounting and Corporate Services and CIPS' Finance and Accounting personnel maintain the books of the Companies and arrange for insurance. They arrange for long-term financing and borrow short-term funds for operations. They maintain stockholder records and perform various investor services. NEWGAS-UE/CIPS would require personnel to provide the same services. Spinning off the gas operations would not provide any measurable savings for UE and CIPS in the finance and accounting area, since all the existing books and records of the Company would remain essentially unchanged, insurance needs would be similar, and staff time devoted to financing activities would not be significantly reduced. UE's and CIPS' Human Resources Divisions administer benefit and salary plans. NEWGAS-UE/CIPS would need to hire personnel to perform the same duties. Spinning off the gas operations would not provide substantial savings to UE and CIPS, because each of UE's and CIPS' existing benefit and salary plans, and the associated reporting requirements, would remain. UE's Supply Service Division and CIPS' Purchasing and General Services Departments provide materials, supplies, transportation equipment, etc. to operating divisions. NEWGAS-UE/CIPS would need to hire personnel to perform the same duties for gas operations. Spinning off the gas operations would reduce the number of purchase orders handled by UE and CIPS as well as the amount of material handled and storage costs. However, the quantities involved are a small percentage of the total, so few, if any, staffing reductions could be affected and no facilities could be eliminated, making the actual savings for UE and CIPS minimal. UE's engineering staff provides engineering expertise to gas operating divisions, while CIPS has dedicated gas engineering staff. NEWGAS-UE/CIPS would need to hire personnel to perform gas engineering duties since CIPS gas engineering would not be capable of performing all of the additional work previously performed by UE engineering. Spinning off the gas operations would reduce the workload on UE engineering personnel, but since gas operations analysis is a small 9 percentage of their work, spread over a geographically dispersed area, UE would not be able to eliminate any engineering positions. UE's legal staff provides legal, regulatory and claims services for UE's operating divisions, while CIPS uses outside counsel to perform these services. NEWGAS-UE/CIPS would need to hire personnel to perform these duties, or pay the increased cost of additional outside counsel. Since many legal issues are not divided into gas and electric considerations, the amount of work performed by UE's legal departments would not decrease significantly, and there would be no staffing reductions. INDEPENDENT ACCOUNTANT IMPACT - ----------------------------- UE and CIPS hire independent accountants to audit the financial statements of the companies. NEWGAS-UE/CIPS would need to hire independent accountants to perform the same duties. UE and CIPS would not achieve any savings, since the existing level of work for the independent accountants would remain the same. INFORMATION TECHNOLOGY IMPACT - ----------------------------- UE and CIPS provide extensive information technology assistance to its operating and support divisions. NEWGAS-UE/CIPS would need to provide the same assistance to its divisions. Hardware costs are reflective of the quantity of information to be processed, so NEWGAS-UE/CIPS' hardware and telecommunications costs would be substantially less than UE's and CIPS'. Software costs are generally less dependent on quantity and more dependent on function, so NEWGAS-UE/CIPS' software costs would be similar to UE's and CIPS'. See SECTION III. C, Exhibit 2b, which identifies a net increase in cost for information services of $14,754,000. Divesting the gas operations would eliminate opportunities for sharing information technology resources to the detriment of both the gas and electric operations: NEWGAS-UE/CIPS would be subject to the same regulatory accounting requirements as UE and CIPS, so similar general ledger, payroll distribution, fixed asset and other accounting systems would be needed. It is estimated that the required software would be similar to UE's and CIPS', and would cost about $4.8 million. UE and CIPS would retain all existing software, resulting in no software savings. Also, UE and CIPS would expend considerable resources changing accounting systems to reflect the divestiture of the gas business. UE and CIPS operate integrated material management, purchasing and accounts payable systems. The systems provide ordering, purchasing, tracking, receiving, 10 paying and inventory control functions. To maintain existing levels of customer service, NEWGAS-UE/CIPS would need a similar integrated system, which would cost about $2.4 million. UE and CIPS would require slightly less data storage, producing negligible savings. There would be no software savings since UE and CIPS would require all existing software. UE's investor services system handles stockholder and bondholder service requests, makes dividend and bond payments and keeps track of unclaimed checks and correspondence. CIPS currently outsources these responsibilities. NEWGAS-UE/CIPS would need a system with capabilities similar to those of UE to maintain the current level of service to stockholders and bondholders. Such a system would cost about $450,000. UE and CIPS would retain the same number of stockholders and bondholders, resulting in no savings. UE's and CIPS' customer information systems are extensively integrated with numerous other systems, providing seamless flow of information and efficient processing of customer service requests, payments and data updates. When customers call, the systems retrieve information and presents it to the call-taker, requiring customers to spend less time on the line. The systems automatically handle customers' payments made by mail, electronically, at pay stations or banks, or by charitable and government organizations. It provides a multitude of services such as budget billing, installment financing payments, combined billing for electric and gas, preferred pay dates, etc. NEWGAS-UE/CIPS would require a similar system to maintain the current level of service to customers. Recently installed utility billing systems have cost $25 - $50 million. Scaling down might be possible for a small utility, making the estimated cost about $20 million. Since there would be fewer customer records to process, UE and CIPS would require less data storage, postage, forms, etc., saving about $330,000 annually. UE and CIPS would expend considerable resources to final bill existing combination gas/electric customers and re- establish the electric accounts. Both UE and CIPS maintain distribution job management systems that receive and track customer requests for service or work, maintain the status of jobs for customer inquiries, automatically bill the customers for work completed and provide accurate accounting and work order control. NEWGAS- UE/CIPS would need a similar system, costing about $4,000,000, to maintain current levels of customer service. UE and CIPS would no longer process gas customers but data storage savings would be insignificant. UE maintains pension management software that provides valuation of the retirement plan for accounting purposes, maintains records of retirees, accumulates information for active employees for pension calculations and interfaces with 11 payroll systems to maintain accurate information. CIPS currently outsources this work. To maintain the current levels of work for both UE's and CIPS' gas employees, NEWGAS-UE/CIPS would need a system similar to UE's, costing about $100,000. The assumed reduction of about 349 UE and CIPS employees who perform only gas related work would have a minimal effect on UE's and CIPS' data storage requirements, providing insignificant savings. UE and CIPS maintain sophisticated human resources, payroll, scheduling, time entry and absence tracking systems. The systems provide scheduling for time worked, vacation and other allowed time. They track absences and automatically update records and restore sick leave bank balances. The systems provide distributed entry of time worked and the associated accounting. The systems provide for the reporting of information to government, regulatory and other agencies. NEWGAS-UE/CIPS would need a similar system. UE's and CIPS' systems combined cost more than $6 million to develop. Since the UE and CIPS systems include processes required only for electric generating plant operations, NEWGAS-UE/CIPS could use simpler software, estimated at about $4,000,000. Processing 349 fewer employees would provide insignificant savings for UE and CIPS. UE's and CIPS' Information Technology personnel maintain the above systems. To maintain similar systems, it is estimated NEWGAS-UE/CIPS would expend about $2,150,000 annually. NEWGAS-UE/CIPS software maintenance would cost about three-fourth's of UE's cost since some systems would not exist in a gas-only company. Because all of the existing systems would remain, UE and CIPS would achieve no maintenance savings by spinning off the gas operations. UE and CIPS maintain communications networks, telephone services, radio systems, etc. To maintain similar systems, NEWGAS-UE/CIPS would need personnel and equipment costing about $5,860,000 annually. Due to fewer employees and locations, NEWGAS-UE/CIPS would spend an amount estimated at 10 percent of UE's and 36 percent of CIPS' costs. UE and CIPS would achieve minimal savings because the number of locations would remain the same, although slightly less equipment (e.g. telephones) would be needed because there would be fewer employees at some locations. UE and CIPS maintain data centers to serve all of the above systems. To operate similar systems, NEWGAS-UE/CIPS would need a similar data center, costing about $3,700,000 annually. There would be no equipment or manpower savings for UE and CIPS, since all existing systems would remain. 12 INSURANCE COSTS - --------------- UE and CIPS obtain property, liability, directors and officers, workers compensation and other insurance. NEWGAS-UE/CIPS would require similar policies, at similar costs. See SECTION III.C, Exhibit 2c, which shows an estimated increase in insurance cost of $525,000 to NEWGAS-UE/CIPS. Since all coverages would remain in effect, UE and CIPS would experience no savings for insurance. OFFICE AND CREW FACILITIES COSTS - -------------------------------- UE and CIPS maintain combined electric and gas office and crew facilities at several locations. NEWGAS-UE/CIPS would need facilities for office and crew personnel at each of the existing combined electric/gas locations. See SECTION III.C, Exhibit 2e-2, which identifies $3,038,549 in additional office and crew facilities costs. Since UE and CIPS would still operate the electric systems, the existing office and crew facilities would still be needed at each location. TRANSPORTATION AND MOTORIZED EQUIPMENT COSTS - -------------------------------------------- UE and CIPS maintain transportation and motorized equipment used by both gas and electric crew and support personnel. NEWGAS-UE/CIPS would need to obtain similar equipment for gas operations. NEWGAS-UE/CIPS' additional transportation cost would be about $637,271 as identified in SECTION III.C, Exhibit 2g-1. Since vehicle needs correlate closely with personnel needs, it is estimated that the reduction in equipment to be achieved by UE and CIPS would equal the additional equipment required by NEWGAS-UE/CIPS, except for vehicles used by meter readers to read both electric and gas meters. UE and CIPS would still need about the same number of meter reader vehicles currently used in the combination gas and electric districts, but the costs currently allocated to the gas business would be absorbed by the electric customers, resulting in increased annual meter reading vehicle costs to UE and CIPS of about $79,497. TRANSITION COSTS - ---------------- The divestiture of the gas operations of UE and CIPS and the creation of a stand-alone gas company would be a complex legal and financial transaction that would involve substantial transition costs. These costs would include legal and financial advising fees, and the services of independent accountants, actuaries and other consultants. Real estate services would be needed to procure facilities. Several hundred personnel would have to be hired and trained. Benefit plans would need to be established. The estimated transition costs of $11,031,000 for NEWGAS-UE/CIPS were developed by calculating 13 the average of such costs incurred in several other publicly reported business spin-offs. See SECTION III.C, Exhibit 2f. COST OF CAPITAL - --------------- The effective cost of capital for the stand-alone gas business was based upon capitalization ratios of UE's and CIPS' capital structure as of December 31, 1995, and estimated current costs of debt and equity, which average about 11.07%. See SECTION III.C, Exhibit 4 for detailed information. INCOME TAXES ON THE DIVESTITURE TRANSACTION - ------------------------------------------- Under current law, the divestiture of the gas businesses of UE and CIPS into a single, combined company, after the merger and creation of Ameren Corporation, could be accomplished on a tax-free basis. However, legislation is pending in the U.S. Congress that, if passed, would apply to this transaction and would impose substantial income taxes. Under the proposed legislation, CIPS would be subject to income tax on the difference between the fair market value of its gas assets (as of the date they are spun off from CIPS) and the tax basis of those assets. Using the net book value as a conservative minimum fair market value for these assets, it is estimated that these income taxes would be at least $24,000,000. These costs would, if incurred, substantially increase the lost economies already illustrated in Section I, Tables I-1 and I-2. CONCLUSION - ---------- The Supplemental Study concludes that a separate gas distribution company would require 902 full-time employees, an increase of approximately 158% over the number of employees currently devoted to UE and CIPS gas operations full-time. Based upon the assumptions set forth in SECTION II and the staffing requirements of the organizational structure, increased annual costs (excluding Federal and State income taxes) for NEWGAS-UE/CIPS are projected to be $34,768,000. The exhibits (SECTION III.C) that follow show the economic effects of operating UE's and CIPS' gas divisions as one separate entity. 14 ================================================================================ SECTION III.C. NEWGAS-UE/CIPS SCHEDULE OF EXHIBITS ================================================================================
Exhibit No. Exhibit Title ========================= =================================================== 1 Income Statement, Proforma Adjustments & Revenue Requirement 1a Consolidation of UE's & CIPS' Income Statements 2 Estimated Additional Operating Expenses 2a Estimated External Audit Fees Based on Survey Data 2b Estimated Information Services Costs 2c Estimated Increased Cost of Insurance Coverage 2d Estimated Net Labor Increase, Including Benefits 2e-1 & 2e-2 Estimated Operating Lease Facilities and Furniture Costs 2f Estimated Transition Costs 2g-1 thru 2g-3 Estimated Net Increase in Transportation & Motorized Equipment Expense 3 Rate Base 3a Consolidation of UE's and CIPS' Rate Base 3b Consolidation of UE's and CIPS' Common Plant Allocated to Gas 4 Cost of Capital 5 Corporate Structure 6 Salaries and Wages Summary 7 Comparable Investor Owned Gas Companies (Customers Per Employee Ratios) 8 Estimated Executive Salaries 9 UE's and CIPS' Electric Rate Base & Rate of Return 9a Consolidation of UE's and CIPS' Electric Rate Base
15 NEWGAS-UE/CIPS EXHIBIT 1 NEWGAS-UE/CIPS INCOME STATEMENT PROFORMA ADJUSTMENTS & REVENUE REQUIREMENT (In Thousands of Dollars)
Existing UE/CIPS Consolidated Proformed Revenue Year Ending Proforma NEWGAS- Requirement 12/31/95 (1) Adjustments (2) UE/CIPS Increase (3) ------------ --------------- ---------- ------------ Operating Revenue: $ 217,425 $ - $ 217,425 $ 267,857 Operating Revenue Deductions: - ----------------------------- Purchased Gas $ 118,652 $ 118,652 $ 118,652 Gas Withdrawn From Storage $ 6,653 $ 6,653 $ 6,653 O & M $ 43,379 $ 34,011 $ 77,390 $ 77,390 Depreciation $ 11,526 $ 11,526 $ 11,526 Taxes Other Than Income $ 17,645 $ 757 $ 18,402 $ 18,402 --------- -------- ---------- --------- Total Operating Revenue Deductions $ 197,855 $ 34,768 $ 232,623 $ 232,623 --------- -------- ---------- --------- Gross Gas Income $ 19,570 $ (15,198) $ 35,234 Federal & State Income Taxes (4) $ 5,792 $ (4,407) $ 10,218 --------- ---------- --------- Net Gas Income $ 13,778 $ (10,791) $ 25,016 ========= ========== ========= Rate Base (5) $ 237,408 $ 225,980 $ 225,980 ========= ========== ========= Indicated Rate of Return 5.80% -4.78% 11.07%(6) ========= ========== =========
(1) See Exhibit 1a for consolidation detail. (2) See Exhibit 2 for a detailed summary of proforma adjustments. (3) An increase of $50,432,000 or 23.20% in revenue is required to achieve a rate of return of 11.07%. For the purposes of this Supplemental Study, gross receipts taxes were not considered since both the resulting revenue and taxes (revenue deduction) would nullify any impact from this calculation. (4) For twelve months ended 12/31/95, UE's and CIPS' combined effective Federal & State Income Taxes were 29.60% of gross income. This effective tax rate was used to calculate taxes for the Proformed NEWGAS-UE/CIPS and Revenue Requirement Increase columns. (5) See Exhibit 3. (6) The effective rate of return is assumed to be the weighted cost of capital per Exhibit 4. NEWGAS-US/CIPS EXHIBIT 1a CONSOLIDATION OF UE's & CIPS' INCOME STATEMENTS FOR THE YEAR ENDING 12/31/95
Existing Existing Existing UE Gas CIPS Gas UE/CIPS Company Company Consolidated Year Ending Year Ending Year Ending 12/31/95 12/31/95 12/31/95 ----------- ----------- ------------ Operating Revenue: $ 87,814 $ 129,611 $ 217,425 Operating Revenue Deductions: Purchased Gas $ 47,189 $ 71,463 $ 118,652 Gas Withdrawn From Storage $ 4,062 $ 2,591 $ 6,653 O & M $ 16,822 $ 26,557 $ 43,379 Depreciation $ 4,722 $ 6,804 $ 11,526 Taxes Other Than Income $ 7,683 $ 9,962 $ 17,645 -------- --------- --------- Total Operating Revenue Deductions $ 80,478 $ 117,377 $ 197,855 -------- --------- --------- Gross Gas Income $ 7,336 $ 12,234 $ 19,570 Federal & State Income Taxes (3) $ 2,131 $ 3,661 $ 5,792 -------- --------- --------- Net Gas Income $ 5,205 $ 8,573 $ 13,778 ======== ========= =========
NEWGAS-UE/CIPS EXHIBIT 2 NEW GAS-UE/CIPS ESTIMATED ADDITIONAL OPERATING EXPENSES PROFORMA ADJUSTMENTS (In Thousands of Dollars)
Exhibit Reference Number Amount --------- ------- External Auditing Costs 2a $ 188 Information Services (Outsourced) 2b $14,754 Insurance Premiums 2c $ 525 Labor & Benefits 2d $14,522 Leased Facilities/Furniture 2e-2 $ 3,039 Transition Costs (Amortized) 2f $ 1,103 Transportation & Work equipment 2g-1 $ 637 ------- Total Additional Expenses $34,768 Less: FICA and Unemployment Insurance 2d $ 757 ------- TOTAL ADDITIONAL O & M EXPENSES $34,011 =======
NEWGAS-UE/CIPS EXHIBIT 2a NEWGAS-UE/CIPS EXTERNAL AUDITOR COSTS ESTIMATED EXTERNAL AUDIT FEES BASED ON SURVEY DATA PROFORMA ADJUSTMENT
Surveys comparing External Audit Fees Amount ------------------------------------- ====== Average fee for Utility companies with less than 300,000 Customers in 1994 $191,000 Average fee for Peer Group comparison with less than 300,000 Customers in 1994 $188,000 -------- Average of External Audit Fee Surveys $189,500 Average Audit Fee for Pension Plans with less than 5,000 employees $ 38,693 -------- Total Estimated Annual Audit Fees for NEWGAS-UE/CIPS $228,193 Less: External Audit Fees Allocated to UE's & CIPS' Gas operations in 1995 $ 40,000 -------- Net Estimated Annual Audit Fees Increase for NEWGAS-UE/CIPS $188,193 ======== Sources: Illinois Power Audit Fee Peer Group Comparison - 1994 American Gas Association/Edison Electric Institute External Audit Fees - October 1995
NEWGAS-UE EXHIBIT 2b
NEWGAS-UE/CIPS INFORMATION SERVICES ESTIMATED INFORMATION SERVICES (IS) COSTS PROFORMA ADJUSTMENT (In Thousands of Dollars) Software Application Costs: Amount -------------------------- ------ General Ledger/Capital Projects/Asset Management/Accounts Payable $ 4,800 Payroll Distribution $ 250 Investor Services $ 450 Customer Information System (CIS) $20,000 Computer Telephone Integration System (CTI) $ 1,000 Distribution Operating Job Management (DOJM) $ 4,000 Gas Systems $ 6,250 Materials Management Information System (MMIS) $ 2,400 Pension Manager $ 100 Payroll/Human Resource System $ 3,000 Time Reporting $ 1,000 Miscellaneous $ 1,500 ------- Total Software Application Costs $44,750 ------- Annual System Operating Costs Data Processing $ 3,700 Software Maintenance and Support $ 2,153 Telecommunciations $ 5,864 ------- Total Annual System Operating Costs $11,717 ------- Estimated Cost to Outsource IS ------------------------------ Annualized Software Application Costs (10 year amortization) $ 4,475 Total Annual System Operating Costs $11,717 ------- Total Annual Cost to Outsource Information Services $16,192 Less: IS Expenses Allocated to UE's and CIPS' Gas Operations in 1995 $ 1,438 ------- Net Increase in Cost for Information Services $14,754 =======
NEWGAS-UE EXHIBIT 2c NEWGAS-UE/CIPS ESTIMATED INCREASED COST OF INSURANCE COVERAGE PROFORMA ADJUSTMENT
Estimated Net Increase to Limits Stand Alone NEWGAS- Coverage (Millions) Deductible Premium Cost UE/CIPS - -------------------------- ---------- ---------- ------------ ------------ Property $ 5 $ 250,000 $ 40,000 General Liability $ 60 $ 250,000 $ 350,000 Auto Liability $ 1 $ - $ 100,000 Directors & Officers Liability $ 10 $ 250,000 $ 75,000 Workers Compensation Statutory $ 350,000 $ 122,000 Fiduciary Liability $ 5 $ 5,000 $ 10,000 Crime (Fidelity) $ 5 $ 5,000 $ 10,000 ---------- Total NEWGAS-UE/CIPS Premium $ 707,000 Less: 1995 Insurance Cost Allocated to UE and CIPS Gas Operations $ 182,000 ---------- Net Increase in Insurance Costs for NEWGAS-UE/CIPS $525,000 ======== Source: Premiums are based on estimated costs obtained from the UE Secretary's Department, Insurance Division.
NEWGAS-UE EXHIBIT 2d NEWGAS-UE/CIPS ESTIMATED NET LABOR INCREASE, INCLUDING BENEFITS PROFORMA ADJUSTMENT (In Thousands of Dollars)
Total Estimated Salaries and Wages for NEWGAS-UE/CIPS (Exhibit 6) $ 40,484 Less: Amount for Construction & Removals (26.72%) - (1) $ 10,817 -------- Total Estimated NEWGAS-UE/CIPS Salaries & Wages Charged to O & M $ 29,667 Less: 1995 UE and CIPS Gas Salaries & Wages Charged to O & M $ 19,441 -------- Increase in NEWGAS-UE Salaries & Wages Charged to O & M $ 10,226 Benefits (2): Employee Life, Hospitalization, savings plans, etc. $ 2,250 Pension Plan $ 931 FICA & Unemployment Insurance $ 757 Other $ 358 -------- Total Benefits $ 4,296 -------- NEWGAS-UE/CIPS Net Labor Increase, Including Benefits $ 14,522 ======== (1) The amount of direct labor allocated to construction and removal is based on the actual amount spent by UE and CIPS in 1995. (2) Benefit costs were estimated based upon the cost (as a percentage of payroll) currently budgeted for: Life, Hospitalization, savings plans, post employment benefit, etc. 22.00% Pension Plan 9.10% FICA & Unemployment Insurance 7.40% Other 3.50% -------- Total 42.00% ========
NEWGAS-EU/CIPS EXHIBIT 2e-1 NEWGAS-UE/CIPS ESTIMATED OPERATING LEASE FACILITIES PROFORMA ADJUSTMENT
Office Space Calculation --------------------------------------------------- Management Office Space & Staff Needs in Cost Per Total Works Total Leased Employee Square Feet Square Foot Office Space Hqtrs. Facilities Count (1) (2) Cost (3) Cost ---------- ------------ ----------- ------------ ------- ------------ General Office: St. Louis, Mo. 357 109,956 $15.00 $1,649,340 -- $1,649,340 Southeast District (MO): Cape Girardeau 13 4,004 $ 6.00 $ 24,024 $38,400 Chaffee 0 -- $ -- $17,000 Dexter 0 -- $ -- $38,400 ------- Total $ 117,824 Wentzville District (MO): Louisiana 9 2,772 $ 5.50 $ 15,246 $17,000 Troy 0 -- $ -- $17,000 ------- Total $ 49,246 Little Dixie District (MO): Boonville 0 -- $ -- $17,000 Centralia 0 -- $ -- $17,000 Columbia 17 5,236 $ 9.00 $ 47,124 $ -- Mexico 0 -- $ -- $38,400 Moberly 0 -- $ -- $38,400 ------- Total $ 157,924 Capital District (MO): Jefferson City 12 3,696 $ 8.00 $ 29,568 $38,400 Versailles 0 -- $ -- $17,000 ------- Total $ 84,968 Alton District (IL): 10 3,080 $ 9.00 $ 27,720 $38,400 $ 66,120 Eastern Division (IL): Effingham 3 -- $ -- $ -- $17,000 Hoopeston 3 -- $ -- $ -- $17,000 Mattoon 18 5,544 $10.00 $ 55,440 $55,400 Paris 3 -- $ -- $ -- $17,000 Robinson 3 -- $ -- $ -- $17,000 Taylorville 3 -- $ -- $ -- $17,000 ------- Total $ 195,840
NEWGAS-UE/CIPS EXHIBIT 2e-2 NEWGAS-UE/CIPS ESTIMATED OPERATING LEASE FACILITIES AND FURNITURE COSTS PROFORMA ADJUSTMENT
Office Space Calculation ---------------------------------------------------------- Management Office Total Total & Staff Space Cost Per Office Works Leased Employee Needs in Square Space Hqtrs. Facilities Count Square Feet (1) Foot (2) Cost (3) Cost ---------------------------------------------------------- ----------- ----------- Southern Division (IL): Benton 3 - $ - $ - $ 17,000 Carbondale 3 - $ - $ - $ 17,000 Marion 16 4,928 $ 9.00 $ 44,352 $ 55,400 -------- Total $ 133,752 Western Division (IL): Beardstown 18 5,544 $ 7.00 $ 38,808 $ 55,400 Canton 3 - $ - $ - $ 17,000 Jerseyville 3 - $ - $ - $ 17,000 Macomb 3 - $ - $ - $ 17,000 Petersburg 3 - $ - $ - $ 17,000 Quincy 3 - $ - $ - $ 55,400 -------- Total $ 217,608 Estimated Office Furniture Operating Lease Expense For All Areas: $ 602,000 ----------- NEWGAS-UE FACILITIES - GRAND TOTAL $ 3,274,622 Less: UE & CIPS allocated costs for gas facilities $ 236,073 ----------- NET NEWGAS-UE FACILITIES COST: $ 3,038,549 ===========
(1) This cost was based on an average of 308 square feet per employee. (2) Cost per square foot per annum was obtained from UE's Real Estate Department and/or calculated by taking the purchased cost of buildings amortized over 7 years to determine the lease expense. (3) This includes space for construction and service supervision, staff, materials and supplies, and vehicles and equipment. Annual lease costs were based on actual appraised values of utility facilities capable of accommodating applicable staff, materials & equipment. Columbia, Mo. is the only city having a UE headquarters facility already dedicated to gas operations. NEWGAS-UE/CIPS EXHIBIT 2f NEWGAS-UE/CIPS ESTIMATED TRANSITION COSTS PROFORMA ADJUSTMENT Transition costs required to establish a new corporation would include the following: Legal fees Financial advisory fees Consulting services of independent accountants, actuaries, and others Real estate services for acquisitions Hiring and training costs to staff newly created positions Benefit plans established Data Conversion Transition costs for NEWGAS-UE/CIPS were estimated based upon an average of the following published transition costs for other corporate spin-offs:
Transition Original Corporation Spin-off Company Costs(000) -------------------- ---------------- ---------- Baxter International Caremark $ 13,300 Adolph Coors ACX Technologies $ 7,200 Dial Corporation GFC Financial $ 13,000 Union Carbide Praxair $ 11,000 Ryder Avial $ 9,000 Price Costco Price Enterprises $ 15,250 Humana Galen $ 15,000 Honeywell Aliant $ 4,500 ---------- Average Transition Costs of the Above Companies $ 11,031 ---------- Annual amortization of Transition Costs for NEWGAS-UE/CIPS (10%) $ 1,103 =========
Source: Transition costs reported in SEC Form 10-K filings. NEWGAS-UE/CIPS EXHIBIT 2g-1 NEWGAS-UE/CIPS ESTIMATED NET INCREASE IN TRANSPORTATION & MORTORIZED EQUIPMENT EXPENSE PROFORMA ADJUSTMENT
Est. Annual Location (1): Cost - ------------------------- ---------- General Office $ 104,136 Southeast District $ 415,068 Wentzville District $ 185,976 Little Dixie District $ 813,132 Capital District $ 429,624 Alton District $ 232,320 Eastern Division $ 127,620 Southern Division $ 115,500 Western Division $ 133,680 ========== NEWGAS-UE/CIPS TOTAL $2,557,056 Less: Amount Charged by UE & CIPS to Gas Operations in 1995 $1,919,785 ---------- NET INCREASE IN EXPENSE $ 637,271 ==========
(1) See Exhibits 2g-2 & 2g-3 for detail information. Projected costs were based on management's assessment of transportation & equipment needs and operating & maintenance experience. NEWGAS-UE/CIPS EXHIBIT 2g-2 NEWGAS-UE/CIPS ESTIMATED TRANSPORTATION & MOTORIZED EQUIPMENT EXPENSE PROFORMA AJDUSTMENT
General Office(GO)\ Pool Southeast District Wentzville District ------------------------ ------------------------ ----------------------- Rate Per Est. Annual Est. Annual Est. Annual Description Month Number Cost Number Cost Number Cost - --------------------------- -------- ------------------------ ------------------------ ----------------------- GO\Pool Vehicles - Standard $ 470 10 $ 56,400 - --------------------------- -------- ------------------------ ------------------------ ----------------------- GO\Pool Vehicles - Compact $ 442 9 $ 47,736 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Manager $ 470 1 $ 5,640 1 $ 5,640 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Operations Superintendent $ 442 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Construction Supervisor $ 442 3 $ 15,912 3 $ 15,912 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Distribution Supervisor $ 442 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Supervising Engineer $ 442 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Engineer $ 442 1 $ 5,304 0 $ - - --------------------------- -------- ------------------------ ------------------------ ----------------------- Engineer Assistant $ 505 2 $ 12,120 1 $ 6,060 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Office Manager $ 442 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Meter Reader $ 505 5 $ 30,300 2 $ 12,120 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Customer Service Advisor $ 442 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- - --------------------------- -------- ------------------------ ------------------------ ----------------------- Other transportation & - --------------------------- -------- ------------------------ ------------------------ ----------------------- Motorized Equipment - --------------------------- -------- ------------------------ ------------------------ ----------------------- Not Indicated Above $ - $ 319,272 $ 119,724 - --------------------------- -------- ------------------------ ------------------------ ----------------------- TOTAL $ 104,136 $ 415,068 $ 185,976 ============ ============== ============== Little Dixie District Capital District Alton District ------------------------ ------------------------ ----------------------- Rate Per Est. Annual Est. Annual Est. Annual Description Month Number Cost Number Cost Number Cost - --------------------------- -------- ------------------------ ------------------------ ----------------------- Manager $ 470 1 $ 5,640 1 $ 5,640 1 $ 5,640 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Operations Superintendent $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Construction Supervisor $ 442 4 $ 21,216 4 $ 21,216 2 $ 10,608 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Distribution Supervisor $ 442 3 $ 15,912 2 $ 10,608 0 $ - - --------------------------- -------- ------------------------ ------------------------ ----------------------- Supervising Engineer $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Engineer $ 442 1 $ 5,304 1 $ 5,304 0 $ - - --------------------------- -------- ------------------------ ------------------------ ----------------------- Engineer Assistant $ 505 3 $ 18,180 2 $ 12,120 0 $ - - --------------------------- -------- ------------------------ ------------------------ ----------------------- Office Manager $ 442 1 $ 5,304 1 $ 5,304 0 $ - - --------------------------- -------- ------------------------ ------------------------ ----------------------- Meter Reader $ 505 7 $ 42,420 3 $ 18,180 2 $ 12,120 - --------------------------- -------- ------------------------ ------------------------ ----------------------- Customer Service Advisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304 - --------------------------- -------- ------------------------ ------------------------ ----------------------- - --------------------------- -------- ------------------------ ------------------------ ----------------------- Other transportation & - --------------------------- -------- ------------------------ ------------------------ ----------------------- Motorized Equipment - --------------------------- -------- ------------------------ ------------------------ ----------------------- Not Indicated Above $ 683,244 $ 335,340 $ 188,040 - --------------------------- -------- ------------------------ ------------------------ ----------------------- TOTAL $ 813,132 $ 429,624 $ 232,320 ============ ============== ============
NEWGAS-UE/CIPS EXHIBIT 2g-3 NEWGAS-UE/CIPS ESTIMATED TRANSPORTATION & MOTORIZED EQUIPMENT EXPENSE PROFORMA ADJUSTMENT
---------------------- ------------------------ -------------------- Eastern Division Southern Division Western Division ---------------------- ------------------------ -------------------- - --------------------------- -------- ------ ----------- ------ ----------- ------ ----------- Rate Per Est. Annual Est. Annual Est. Annual Description Month Number Cost Number Cost Number Cost - --------------------------- -------- ------ ----------- ------ ----------- ------ ----------- Manager $ 470 1 $ 5,640 1 $ 5,640 1 $ 5,640 Superintendent $ 442 6 $ 31,824 6 $ 31,824 6 $ 31,824 H/R Supervisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304 New Business Supervisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304 C/S & N/B Representatives $ 442 4 $ 21,216 4 $ 21,216 4 $ 21,216 Engineer $ 442 2 $ 10,608 2 $ 10,608 2 $ 10,608 Operating Supervisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304 Meter Reader $ 505 7 $ 42,420 5 $ 30,300 8 $ 48,480 - --------------------------- -------- ------ ----------- ------ ----------- ------ ----------- DIVISION TOTALS $127,620 $115,500 $133,680 =========== =========== ===========
NEWGAS-UE/CIPS EXHIBIT 3 NEWGAS-UE/CIPS RATE BASE (In Thousands of Dollars)
Existing UE/CIPS Reduction Consolidated for UE's & NEWGAS- Year Ending CIPS' Common UE/CIPS 12/31/95 Gas Plant (1) Net of Common (Exhibit 3a) (Exhibit 3b) Plant 12/31/95 ------------ ------------- -------------- Gas Plant In Service $408,192 $(12,762) $395,430 Reserve For Depreciation $147,197 $ (1,334) $145,863 -------- -------- -------- Net Plant $260,995 $(11,428) $249,567 Materials & Supplies $ 12,940 $ 12,940 Prepayments $ (750) $ (750) Customer Advances $ (1,401) $ (1,401) Accumulated Deferred Income Taxes $(34,376) $(34,376) -------- -------- -------- TOTAL RATE BASE $237,408 $(11,428) $225,980 ======== ======== ========
(1) Mainly buildings and equipment jointly used by the electric and gas departments. Under a divestiture, all common property would go with the electric company. NEWGAS-UE/CIPS EXHIBIT 3a CONSOLIDATION OF UE's & CIPS' RATE BASE FOR YEAR ENDING 12/31/95
Existing Existing Existing UE Gas CIPS Gas UE/CIPS Company Company Consolidated Year Ending Year Ending Year Ending 12/31/95 12/31/95 12/31/95 ----------- ----------- ------------ Gas Plant In Service $179,985 $228,207 $408,192 Reserve For Depreciation $ 53,744 $ 93,453 $147,197 -------- -------- -------- Net Plant $126,241 $134,754 $260,995 Materials & Supplies $ 11,892 $ 1,048 $ 12,940 Prepayments $ 236 $ (986) $ (750) Customer Advances $ (937) $ (464) $ (1,401) Accumulated Deferred Income Taxes $(12,616) $(21,760) $(34,376) -------- -------- -------- TOTAL RATE BASE $124,816 $112,592 $237,408 ======== ======== ========
NEWGAS-UE/CIPS EXHIBIT 3b
CONSOLIDATION OF UE's & CIPS' COMMON PLANT ALLOCATED TO GAS FOR YEAR ENDED 12/31/95 UE CIPS UE & CIPS Common Plant Common Plant Common Plant Allocated to Allocated to Allocated to Gas Plant(1) Gas Plant (1) Gas Plant (1) ----------- ------------- -------------- Gas Plant In Service $ 5,738 $ 7,024 $ 12,762 Reserve For Depreciation $ 1,083 $ 251 $ 1,334 ----------- ------------ -------------- Net Plant $ 4,655 $ 6,773 $ 11,428 =========== ============ ============== (1) Mainly buildings and equipment jointly used by the electric and gas departments. Under a divestiture, all common property would go with the electric company.
NEWGAS-UE/CIPS EXHIBIT 4
NEWGAS-UE/CIPS STAND-ALONE COST OF CAPITAL UE CIPS UE/CIPS --------------------------------- --------------------------------- ------------------------------- Weighted Capital- % of Capital- % of Capital- ization UE/CIPS Gas Weighted ization UE/CIPS Gas Weighted ization Cost Weighted Type of Capital Ratios Rate Base Ratios Ratios Rate Base Ratios Ratios Component Cost - ------------------------ -------- ----------- -------- -------- ----------- -------- -------- --------- -------- Long Term Debt 41.00% 53.17% 21.80% 42.41% 46.83% 19.86% 41.66% 8.41% 3.50% Preferred 5.10% 53.17% 2.71% 7.08% 46.83% 3.32% 6.03% 8.41% 0.51% Common Equity 53.90% 53.17% 28.66% 50.51% 46.83% 23.65% 52.31% 13.50% 7.06% ------ Weighted Cost of Capital 11.07% ======
Note: Capitalization ratios are based on the total UE and CIPS capital structures as of 12/31/95. Debt and equity were estimated at then current costs. Current cost of debt and preferred = 30 year, 10 Year No Call first mortgage bond @ 7.91% (all-in-cost) + 50 basis points. Bond and preferred stock rate provided on April 19, 1996 by Smith Barney. NEWGAS-UE/CIPS EXHIBIT 5 NEWGAS-UE/CIPS Organization Chart President & CEO Vice President - Customer Service Manager - Customer Service Support Manager - Southeast District Manager - Wentzville District Manager - Little Dixie District Manager - Capital District Manager - Alton District Manager - Eastern Division Manager - Western Division Manager - Southern Division Manager - Corporate Communications Manager - Gas Marketing Vice President - Corporate Services Manager - Purchasing Manager - Stores Manager - Motor Transportation Manager - Real Estate & Facilities Manager - General Services General Counsel Associate General Counsel - Regulatory Associate General Counsel - Claims Vice President - Finance Manager - Accounting Manager - Tax Manager - Internal Audit Secretary/Treasurer Manager - Investor Relations Manager - Treasury Operations Assistant Secretary - Insurance & Records Vice President - Human Resources Manager - Employment Services Manager - Industrial Relations Vice President - Gas Supply Manager - Gas Supply Manager - System Planning & Engineering Manager - Corporate Planning NEWGAS-UE/CIPS EXHIBIT 6 NEWGAS-UE/CIPS SALARIES AND WAGES SUMMARY (In Thousands of Dollars)
Totals -------------------------- Employees Salaries/Wages Employees Salaries/Wages --------- -------------- --------- -------------- Executive Staff & Secretarial Support 16 $ 1,120 Customer Service Division: Customer Service Support 62 $2,698 Gas Marketing 25 $1,218 Southeast District 46 $2,041 Wentzville District 26 $1,190 Little Dixie District 102 $4,376 Capital District 45 $2,106 Alton District 34 $1,592 Eastern Division 96 $3,834 Western Divsion 107 $4,242 Southern Division 73 $2,915 Corporate Communications 5 $ 262 --- ------ Customer Service Division Total 621 $26,474 Corporate Services Division: Purchasing 9 $ 533 Stores 7 $ 369 Motor Transportation 4 $ 225 Real Estate & Facilities 4 $ 225 General Services 36 $1,364 --- ------ Corporate Services Division Total 60 $ 2,716 General Counsel Division: Regulatory 6 $ 370 Claims 5 $ 268 --- ------ General Counsel Division Total 11 $ 638 Controller Division: Accounting, Payroll, Accounts Payable 42 $1,751 Internal Audit 11 $ 640 Tax 14 $ 713 --- ------ Controller Division Total 67 $ 3,104 Secretary/Treasurer Division: Investor Relations 4 $ 199 Treasury Operations 18 $ 755 Insurance & Records 8 $ 351 --- ------ Secretary/Treasurer Division Total 30 $ 1,305 Human Resources Division: Employment Services 36 $1,848 Industrial Relations 5 $ 285 --- ------ Human Resources Division Total 41 $ 2,133 Gas Supply: Gas Supply 6 $ 365 System Planning & Engineering 30 $1,645 Corporate Planning 20 $ 984 --- ------ Gas Supply Division Total 56 $ 2,994 --- ------- GRAND TOTAL 902 $40,484 === =======
NEWGAS-UE/CIPS EXHIBIT 7 COMPARABLE INVESTOR OWNED GAS UTILITIES CUSTOMERS PER EMPLOYEE
Customers Companies Customers Employees Per Employee - ---------------------- --------- --------- ------------ NEWGAS-UE/CIPS 288,000 902 319 Connecticut Natural Gas 138,000 642 215 ENERGEN 435,000 1,488 292 Southern Connecticut Gas 153,000 572 267 United Cities Gas 295,000 1,343 220 Yankee Gas Service 177,000 670 264
Source: American Gas Association - Directory of Member Companies (Selection Criteria - Total Number of Customers Similar to NEWGAS-UE and NEWGAS- CIPS as shown in the previous Study, and also to NEWGAS-UE/CIPS in this Supplemental Study) NEWGAS-UE/CIPS EXHIBIT 8 ESTIMATED EXECUTIVE SALARIES ---------------------------- Salary Survey Data for Companies with Revenues less than $300 million were used to establish a reasonable range for the NEWGAS-UE/CIPS executive salary levels. For existing positions that would become part of the spun-off company, existing UE salaries were used. NEWGAS-UE/CIPS -------------- POSITION SURVEY DATA RANGE SALARY LEVELS -------- ----------------- ------------- President $212,000 $200,000 Vice President Level $73,600-$106,300 $80,000-$110,000 Source: 1996 Edison Electric Institute Executive Compensation Survey NEWGAS-UE/CIPS EXHIBIT 9 UE/CIPS ELECTRIC RATE BASE & RATE OF RETURN TWELVE MONTHS ENDED 12/31/95 (In Thousands of Dollars)
Existing UE/CIPS Addition Electric For Common UE/CIPS Consolidated Plant (1) Electric (Exhibit 9a) (Exhibit 3b) As Adjusted ------------ ---------- ----------- Electric Plant In Service $ 10,081,927 $ 12,762 $10,094,689 Reserve For Depreciation $ 3,858,615 $ 1,334 $ 3,859,949 ------------ ---------- ----------- Net Plant $ 6,223,312 $ 11,428 $ 6,234,740 Fuel and Materials & Supplies $ 223,883 $ 223,883 Prepayments $ 20,606 $ 20,606 Customer Advances $ (7,677) $ (7,677) Accumulated Deferred Income Taxes $ (1,175,397) $(1,175,397) ------------- ---------- ------------ TOTAL RATE BASE $ 5,284,727 $ 11,428 $ 5,296,155 ============ ========== =========== NET OPERATING INCOME $ 534,247 $ 534,247 ------------ ----------- RETURN ON RATE BASE 10.11% 10.09% ============ =========== (1) This represents an allocation of all plant and property jointly used by the electric and gas departments. Under a divestiture, all common property would go with the electric company.
NEWGAS-UE/CIPS EXHIBIT 9a CONSOLIDATION OF UE's & CIPS' ELECTRIC RATE BASE FOR THE YEAR ENDING 12/31/95
UE's CIPS' Existing Electric Electric UE/CIPS Company Company Electric as of 12/31/95 as of 12/31/95 Consolidated -------------- -------------- ------------ Electric Plant In Service $7,796,628 $2,285,299 $10,081,927 Reserve For Depreciation $2,819,806 $1,038,809 $ 3,858,615 ---------- ---------- ----------- Net Plant $4,976,822 $1,246,490 $ 6,223,312 Fuel and Materials & Supplies $ 184,684 $ 39,199 $ 223,883 Prepayments $ 13,425 $ 7,181 $ 20,606 Customer Advances $ (6,935) $ (742) $ (7,677) Accumulated Deferred Income Taxes $ (848,543) $ (326,854) $(1,175,397) ---------- ---------- ----------- $4,319,453 $ 965,274 $ 5,284,727 ========== ========== ===========
EX-99.K-3 5 LEGAL MEMO REG.STANDARDS FOR RETENTION GAS PRO EXHIBIT K-3 JONES, DAY, REAVIS & POGUE 77 West Wacker Drive Suite 3500 Chicago, Illinois 60601 (312) 782-3939 LEGAL MEMORANDUM ON THE RETENTION OF GAS OPERATIONS BY AMEREN CORPORATION ------------------------------------ INTRODUCTION The combination of Union Electric Company ("UE") and Central Illinois Public Service Company ("CIPS") in a merger transaction (the "Transaction") will result in UE and CIPS becoming wholly owned subsidiaries of Ameren Corporation ("Ameren"), a holding company which will be registered under the Public Utility Holding Company Act of 1935 (the "Act"). Ameren has filed an Application/Declaration on Form U-1 (as amended, the "Application") seeking the approval of the Securities and Exchange Commission (the "Commission") under the Act for the Transaction and related matters. The Application seeks the Commission's authorization for UE and CIPS to retain their gas utility systems following the consummation of the Transaction. This memorandum supplements the Application with respect to legal issues related to Ameren's request for authority to retain these gas systems following its registration as a holding company under the Act. SUMMARY Both the legislative history of the Act as well as the Commission's early interpretation of the Act indicate that the purpose of the Act was to facilitate the process by which state utility regulatory commissions determine whether registered combination gas and electric holding company systems are permissible, and not to impose a more restrictive federal view./1/ In addition, as the Commission has noted in a number of prior decisions, the Act is intended to provide for a flexible regulatory scheme that is capable of adapting to changes in the utility industry. The industry is in the process of its most radical change (from regulation to competition) since the changes which occurred in the 1930's and 1940's as a result of the adoption of the Act. It is clear that the industry is currently evolving in a direction that requires utility company systems to offer their customers a range of energy options in order to remain competitive. In the short time since the Application was filed in October, 1996, the industry has taken a dramatic and unmistakable turn toward "convergence" -- the development - -------------------- /1/ See Note 7 and accompanying text below. of an "energy" industry. In this new industry, companies provide electricity, gas and a variety of energy services and products to customers. Because of these changes, and to maintain the traditions of a flexible regulatory scheme, the Commission should analyze the retention of UE's and CIPS' gas systems by focusing on those sections of the Act (Sections 8 and 21) that give primacy to state utility commission decisions with regard to combination registered holding companies and should "watchfully defer" to such local decision makers who are in the optimum position to regulate the combination utility. The Division of Investment Management (the "Division") in a report approved by the Commission for issuance by the Division in 1995 entitled "The Regulation of Public Utility Holding Companies" (the "1995 Report") urged a flexible administration of the Act. Under such flexible analysis of Sections 8 and 21, Ameren must be allowed to retain the gas systems of UE and CIPS as long as the Missouri Public Service Commission ("MPSC") and the Illinois Commerce Commission ("ICC"), who have, and will continue to have, direct jurisdiction over Ameren's gas operations in their respective states, permit the continued existence of a combination system. The MPSC has given final approval to the Transaction. UE has provided combination service in Missouri for many years and no issue relating to such combination service was raised in the MPSC proceeding. The MPSC has not found any detriment to the public interest in this area. An order of the ICC is expected this summer. No issue concerning combination gas and electric operations has been raised by any party in the ICC proceeding. Even if the Commission chooses not to focus on state commission determinations, Section 11 of the Act contains additional provisions that permit the retention of UE's and CIPS' gas systems -- namely, the so-called A-B-C clauses (the "A-B-C Clauses") of Section 11(b)(1), under which the Commission in the past has permitted retention of an additional utility system within a registered holding company system. Again, the standards set forth in this section should be read in light of the current changes in the utility industry. In any event, Ameren without a doubt meets these standards with regard to the retention of the gas operations discussed herein. DISCUSSION I. Section 10(c) 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 of Section 11/2/; or - -------------------- /2/ By their terms, Sections 8 and 11 only apply to registered holding companies and are (continued...) 2 (2) the acquisition of securities or utility assets of a public utility or 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 . . . . Section 10(c)(1) requires that the proposed acquisition be lawful under Section 8. Section 8 prohibits registered holding companies from acquiring, owning interests in or operating both a gas and an electric utility serving substantially the same area if state law prohibits it or requires specific approval for such combinations. Each of UE and CIPS has provided combination gas and electric utility services in Missouri and Illinois for many years. Because Missouri and Illinois law do not in any way prohibit or require special approval for combination gas and electric utilities serving the same area, the Transaction does not raise any issue under Section 8 and, accordingly, the first clause of Section 10(c)(1). As more fully discussed below, Section 8 in fact indicates that a registered holding company may own both gas and electric utilities where there is no conflicting state policy. Section 10(c)(1) also requires that the Transaction not be detrimental to carrying out the provisions of Section 11. Three provisions of Section 11 are relevant here. Section 11(a) of the Act requires the Commission to examine the corporate structure of registered holding companies to ensure that unnecessary complexities are eliminated and voting powers are fairly and equitably distributed. Similarly, Section 11(b)(2) directs the Commission "to ensure that the corporate structure or continued existence of any company in the holding company system does not unduly or unnecessarily complicate the structure, or unfairly or inequitably distribute voting power among security holders, of such holding company system." As described in the Application, the Transaction will not result in unnecessary complexities or unfair voting powers. As noted, in this regard Ameren will be similar to the existing registered holding companies. See Item 3.A.1(a) and (c) of the Application. - ------------------------------- /2/(...continued) therefore inapplicable at present to UE, CIPSCO or CIPS, since none of these companies is now a registered holding company. The retention by UE of the combination gas and electric business was approved in In re Union Elec. Co., 40 SEC 1072 (Apr. 2, 1962). While divestiture had been ordered in In re Union Elec. Co., 1972 SEC LEXIS 4264 (Sept. 19, 1972), jurisdiction over such issue was reserved and UE was allowed to retain its gas properties in In re Union Elec. Co., 45 SEC 489 (Apr. 10, 1974), the leading case concerning operation of combination utilities by exempt holding companies. The current view of the Commission as to retainability of combination utilities for an exempt holding company is reflected in CIPSCO Inc., 47 SEC Docket 174 (Sept. 18, 1990) where the retention by CIPSCO and CIPS of the combination gas and electric business was unconditionally approved by the Commission. The following discussion of Sections 8 and 11 is included only because, under the present Transaction structure, Ameren will register as a holding company after consummation of the Transaction. 3 Finally, Section 11(b)(1) generally requires a registered holding company system to limit its operations "to a single integrated public utility system, and to such other businesses as are reasonably incidental, or economically necessary or appropriate to the operations of such integrated public utility system." One or more "additional" integrated public utility systems may be retained if, as here, the "A-B-C Clauses" described below are satisfied. This Memorandum will address the issue raised under Section (10)(c)(1) and by reference Section 11(b)(1) of whether Ameren may retain, through control of UE and CIPS, control of integrated combination gas and electric utility companies. As detailed below, retention by Ameren of the combination utilities will not be detrimental to the carrying out of any of the provisions of Section 11. II. Retention of Gas Operations This Memorandum will first demonstrate how Ameren would clearly meet the traditional A-B-C Clauses requirements, but will also demonstrate that the Commission should approve the Transaction without reference to the Clauses -- that is, on the basis that the acquisition by Ameren of combination companies CIPS and UE is not detrimental to the provisions of Section 11 because they constitute a "single integrated public utility system." (A) Ameren Satisfies the Traditional "A-B-C" Test Section 11(b)(1) of the Act generally requires a registered holding company system to limit its operations "to a single integrated public utility system, and to such other businesses as are reasonably incidental, or economically necessary or appropriate to the operations of such integrated public utility system." Section 11(b)(1) of the Act expressly permits a registered holding company to control one or more "additional integrated public utility systems" if: A) each of such additional systems cannot be operated as an independent system without the loss of substantial economies which can be secured by the retention of control by such holding company of such system; B) all of such additional systems are located in one state, adjoining states, or a contiguous foreign country; and C) the continued combination of such systems under the control of such holding company is not so large (considering the state of the art and the area or region affected) as to impair the advantages of localized management, efficient operation, or the effectiveness of regulation. (1) Clause (A) Since 1968, in interpreting clause (A) of Section 11(b)(1), the Commission has looked to the Supreme Court decisions in SEC v. New England Elec. Sys., 384 U.S. 176 (1966) ("NEES I") and SEC v. New England Elec. Sys., 390 U.S. 207 (1968) ("NEES II"). In NEES I, the Supreme Court accepted the Commission's interpretation of the "loss of 4 substantial economies" language of clause (A) to require an applicant seeking to own an electric and gas utility system to show that the additional system, if separated from the principal system, would be incapable of independent economic operation. Historically, in determining whether lost economies are "substantial" as required under Section 11(b)(1)(A), the Commission has given consideration to four ratios, which measure the projected loss of economies as a percentage of: (1) total gas operating revenues; (2) total gas expense or "operating revenue deductions"; (3) gross gas income; and (4) net gas income or net gas utility operating income. Although the Commission has declined to draw a bright-line numerical test under Section 11(b)(1)(A), it has indicated that cost increases resulting in a 6.78% loss of operating revenues, a 9.72% increase in operating revenue deductions, a 25.44% loss of gross income and a 42.46% loss of net income would afford an "impressive basis for finding a loss of substantial economies." In re Engineers Public Service Co., 12 SEC 41, 59 (Sept. 16, 1942) ("Engineers"). Here, the lost economies would be far greater than in Engineers if the gas properties of UE and CIPS were to be operated on a stand-alone basis, with no offsetting increase in benefits to consumers. These lost economies result from the need to replicate services, the sacrifice of economies of scale, the costs of reorganization, and other factors, and are described more fully in the Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS (the "1996 Study") (Exhibit K-1 to the Application) and the Supplemental Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS (the "Supplemental Study") (Exhibit K-1.1 to the Application). The 1996 Study and the Supplemental Study are referred to as the "Gas Study." The lost economies of this case would exceed those of Engineers, whether the gas operations are divested to two, stand-alone companies or one, stand- alone company. Two Companies. As set forth in the 1996 Study, divestiture of the gas operations of UE and CIPS into two stand-alone companies would result in lost economies of $22.1 million for UE and $36.3 million for CIPS. These lost economies compare with 1995 gas operating revenues of $87.8 million for UE and $129.6 million for CIPS; gas operating revenue deductions of $80.5 million for UE and $117.4 million for CIPS; gas gross income of $7.3 million for UE and $12.2 million for CIPS; and gas net income of $5.2 million for UE and $8.6 million for CIPS. On a percentage basis, the lost economies amount to 425% of 1995 UE gas net income and 424% of 1995 CIPS gas net income (424% of pro forma combined gas net income). As a percentage of 1995 gas operating revenues, these lost economies described in the 1996 Study amount to 25% for UE and 28% for CIPS. As a percentage of 1995 gas expenses or operating revenue deductions, the lost economies described in the 1996 Study would amount to 27% for UE and 31% for CIPS. Finally, the 1996 Study shows that as a percentage of 1995 gas gross income, the lost economies amount to 301% for UE and 297% for CIPS. In order to recover these lost economies, the stand-alone company divested from UE would need to increase customer rates by about 38% ($33.7 million) in order to provide an 11.15% return on rate base. Similarly, the stand-alone company divested from CIPS would need to increase 5 customer rates by about 31% (40.7 million) in order to provide a 10.98% rate of return on rate base. Without rate relief, the stand-alone companies would have significant negative returns of minus 8.73% and 15.93% for UE and CIPS, respectively. The gas system operations of UE and CIPS, of course, are currently operating as separate operations because UE and CIPS are unaffiliated companies. Each company's gas operations are closely integrated with their electric operations. To present a truly accurate picture of the loss that would be sustained to shareholders and ratepayers by a divestiture of such operations, it is appropriate to consider each gas operation separately. In other words, the analysis should be of the loss to UE of the spin-off of the UE gas system in a separate company AND the loss to CIPS of the spin-off of the CIPS gas system in a separate company. Section 11(b)(1) clearly allows a registered holding company to retain "one or more" additional systems. As shown by the 1996 Study, as summarized in the preceding paragraphs, the loss of economies resulting from the separate divestiture of the UE and CIPS gas systems would be devastating and significantly more than in several Commission precedents. (Exact comparisons will be detailed below). Accordingly, Ameren should, according to Commission precedent be allowed to retain the gas operations of UE and CIPS. One Company. When the Transaction is consummated, UE and CIPS will operate as a "single integrated public utility system." As a result, it may be relevant to consider whether, as such a single system, and assuming the Transaction had occurred, the divestiture of the gas operations into a SINGLE, new stand-alone company would also produce a "loss of substantial economies" within the meaning of Section 11(b)(1)(A) of the Act. As demonstrated by the Supplemental Study, such a divestiture would clearly result in such a loss of substantial economies. As set forth in the Supplemental Study, divestiture of the gas operations of UE and CIPS into one stand-alone company would result in lost economies of $34.8 million. (This compares to lost economies of $22.1 million for UE and $36.3 million for CIPS, totalling $58.4 million, as found by the 1996 Study). These lost economies compare with 1995 pro forma combined UE and CIPS gas operating revenues of $217.4 million; pro forma combined gas operating revenue deductions of $197.9 million; pro forma combined gas gross income of $19.6; and pro forma combined gas net income of $13.8 million. On a percentage basis, the lost economies shown by the Supplemental Study amount to 252% of 1995 pro forma combined gas net income -- far in excess of the loss of net income in Unitil Corp., 51 SEC Docket 562 (Apr. 24, 1992) (Unitil), where the Commission allowed the retention of gas utility operations, and the 30% loss in New England Electric System that the Commission has described as the highest loss of net income in any past divestiture order./3/ As a percentage of 1995 pro forma combined gas operating revenues, these lost economies - -------------------- /3/ See Unitil Corp., 51 SEC Docket 562, 567 & n.42 (Apr. 24, 1992) ("The Commission has required divestment where the anticipated loss in income of the stand-alone company was approximately 30%" or "29.9% of net income before taxes") (citing SEC v. New England Elec. Sys., 390 U.S. 207, 214 n.11 (1968)). This percentage compares to the 425% of 1995 UE gas net income and 424% of 1995 CIPS gas net income shown by the 1996 Study. 6 described in the Supplemental Study amount to 16% -- losses higher than the losses in any past divestiture order. The projected loss of economies as a percentage of operating revenues is even higher than the loss in Unitil./4/ As a percentage of 1995 pro forma combined gas expenses or operating revenue deductions, the lost economies described in the Supplemental Study would amount to 17.6% -- higher than the losses in any past divestiture order and higher than the losses in both Unitil and Entergy, another case in which the Commission authorized the retention of gas operations./5/ As a percentage of 1995 pro forma combined gas gross income, the lost economies described in the Supplemental Study amount to 178% -- far in excess of the highest loss of gross income in any divestiture order. The applicable percentages in past cases are summarized in Exhibit K-2 to the Application (Table of Estimated Losses of Economies in Prior Decisions on Divestiture and Retention of Gas Operations). In order to recover these lost economies, the single, new stand-alone company divested from UE and CIPS would need to increase customer rates by about 23% ($50.4 million) in order to provide an 11.07% rate of return on rate base. This rate of return was conservatively - ---------------------- /4/ The loss as a percentage of operating revenues in Unitil was 13.94%. The highest loss of operating revenues in any case ordering divestiture is commonly said to be 6.58%. See, e.g., Unitil Corp., 51 SEC Docket 562, 567 n.41 (Apr. 24, 1992) ("[o]f cases in which the Commission has required divestment, the highest estimated loss of operating revenues of a stand- alone company was 6.58%") (citing In re Engineers Public Service Co., 12 SEC 41 (Sept. 16, 1942)). In fact, however, the 6.58% ratio is not cited in Engineers and is a post hoc calculation derived from claimed cost increases which the Commission had found were "overstated" and "doubtful" in a number of respects. Engineers Public Service Co., 12 SEC at 80-81. See also In re Philadelphia Co., 28 SEC 35, 51 n.26 (June 1, 1948) (Engineers' "estimate . . . of increased expenses . . . was overstated in several respects"). While the SEC made no finding as to actual cost increases or ratios for the Gulf States gas properties, it found that Engineers' estimate of divestiture- related cost increases for certain sister gas properties in Virginia were also overstated and cut them and the resulting ratios in half. Engineers Public Service Co., 12 SEC at 60. If the same 50% discount had been applied to Engineers' Gulf States gas properties, the loss of operating revenues would have been 3.29%, the increase in expenses would have been 4.73%, the loss of gross income would have been 10.43%, and the loss of net income would have been 12.63%. Disregarding the 6.58% ratio incorrectly attributed to the Engineers/Gulf States case, the highest loss of operating revenues in any past divestiture order was 5.85%. See table of ratios in In re New England Elec. Sys., 41 SEC 888, 905 App. (Mar. 19, 1964). This figure would be even lower if adjusted for the increase in purchased gas costs since the 1940s. The percentage shown by the Supplemental Study compares to the 25% and 28% reduction, respectively, for UE and CIPS shown by the 1996 Study. /5/ The highest percentage of loss related to operating revenue deduction is sometimes attributed to the Gulf States gas properties of Engineers Public Service Co. See, e.g., In re New England Elec. Sys., 41 SEC 888, 905 App. (March 19, 1964) (attributing 9.46% to the Engineers/Gulf States case). This percentage, however, is based on claimed losses expressly rejected by the Commission in the Engineers decision. In re Engineers Public Service Co., 12 SEC 41, 80-81 (Sept. 16, 1942). Disregarding the 9.46% figure erroneously attributed to the Engineers case, the highest expense percentage in the cases ordering divestiture appears to have been either 8.01% or 7.42%, depending on how the ratio is calculated. See In re North American Co., 18 SEC 611 (Apr. 7, 1945); In re Philadelphia Co., 28 SEC 35, 51 Table VI (June 1, 1948) (attributing expense ratio of 7.42% to North American) with In re New England Electric System, 41 SEC 888, 905 App. (1964) (attributing expense ratio of 8.01% to North American). The combined total loss as a percentage of gas operating revenue deductions shown in the 1996 Study was 29.5%. 7 estimated using the weighted average approximate costs for capital of UE and CIPS rather than the higher returns that would likely be required by the financial community for a single, stand-alone company. See the Supplemental Study, Exhibit 4. Finally, it should be noted that the lost economies would, in the absence of rate relief, result in a negative rate of return on rate base for the gas operations of minus 4.78% -- significantly more detrimental than the 2.01% projected stand-alone rate of return in Unitil, where retention was authorized. This return is significantly lower than the returns of other utilities in the region and represent a decline from UE's and CIPS' indicated rates of return for 1995. See the Supplemental Study. The above data show that, even assuming the gas operations of CIPS and UE were divested by forming one stand-alone company, the loss of economies would be significant, in excess of that present in other cases where retention was allowed and sufficient to support a finding that requirement of Clause A of Section 11(b)(1) is met in this case. This conclusion is even more dramatically demonstrated if it is assumed that each gas operation would be in a separate stand-alone company as shown by the 1996 Study. (2) Clauses (B) and (C) of Section 11(b)(1) are Satisfied. The remaining requirements of Section 11(b)(1) are met because the gas operations of UE and CIPS are located in the adjoining states of Missouri and Illinois and because the continued combination of the gas operations under Ameren is not so large, considering the state of the art and the area or region affected, as to impair the advantages of localized management, efficient operation or the effectiveness of regulation. The gas systems are confined to a relatively small area and are not as large as other gas systems in the same area and will preserve the advantages of localized management, efficient operation and effectiveness of regulation. Moreover, as the Commission has recognized elsewhere, the determinative consideration is not size alone or size in an absolute sense, either big or small, but size in relation to its effect, if any, on localized management, efficient operation and effective regulation. See Centerior Energy Corp., 35 SEC Docket 769 (Apr. 29, 1986). From these perspectives, it is clear that the continued combination of the gas operations under Ameren is not too large. Even after the combination, the gas operations of UE and CIPS, with some 285,403 customers combined in only two states, will be significantly smaller than neighboring Northern Illinois Gas Company (1,769,800 customers), People's Gas Light and Coke Company (842,510 customers), Laclede Gas Co. (553,000 customers), Missouri Gas Energy (450,000 customers) and Illinois Power Co. (388,170 customers). Localized management is discussed for the Transaction as a whole under Item 3.A.2.b.(ii)(A) and (B) of the Application. Applied solely to the gas operations, the current UE and CIPS gas systems enhance localized management within the larger corporate structure and will continue to do so after the Transaction is completed. 8 As a result of the Transaction, the centralized functions of Ameren will continue to be handled from St. Louis, Missouri and Springfield, Illinois and from regional offices. No reduction in customer service or support crews is expected. Management will therefore remain geographically close to the gas operations, thereby preserving the advantages of a localized management. With respect to efficient operation, as described in Item 3.A.2.b.(ii) of the Application, as part of the Ameren system, the gas operations of UE and CIPS are expected to reduce delivered gas costs by $37 million in the first 10 years after the Mergers. Substantially all of these reductions will be passed on directly to customers under the purchased gas adjustment ("PGA") clauses in UE's and CIPS' tariffs, if all of the system's purchased gas costs continue to receive PGA treatment as at present. Far from impairing the advantages of efficient operation, the combination of the gas operations under Ameren will facilitate and enhance the efficiency of gas operations. As discussed in Item 3.A.2.a.(i)(B) of the Application, the "state of the art" with respect to gas operations has changed significantly in recent years. In the light of current communications technology and the nature of today's gas business, the combination of the UE and CIPS gas businesses, under the control of Ameren, will not jeopardize local control and will significantly improve operating efficiency. Based on its traditional application of the A-B-C Clauses, therefore, the Commission should find that UE and CIPS may retain the combined gas businesses as an "additional" integrated system. (B) The Commission Should Not Require Ameren to Satisfy the Traditional "A-B-C" Test. Although for many years the Commission has interpreted the Act as not permitting a registered holding company to control subsidiaries that were combination gas and electric utilities, except where the "A-B-C" test is met, there are significant legal and policy reasons for the Commission to revise its interpretation of the Act, in light of recent changes both in national energy policy and in the energy markets./6/ (1) The Act Does Not Prohibit Combination Companies. Nothing in the Act directly prohibits a registered holding company from owning an integrated gas and electric system if such a structure does not violate the laws of the state(s) having jurisdiction over such a system. Section 8 of the Act provides that: [w]henever a State law prohibits, or requires approval or authorization of, the ownership or operation by a single company of the utility assets of an electric utility company and a gas utility company serving substantially the same territory, it shall be unlawful for a registered holding company, or any - ------------------- /6/ These changes are described below and have been recognized by the Commission. See Consolidated Natural Gas, Release No. 35-26512 (Apr. 30, 1996); Northeast Utilities, Release No. 35-26554 (August 13, 1996). 9 subsidiary company thereof . . . (1) to take any step, without the express approval of the state commission of such State, which results in its having a direct or indirect interest in an electric utility company and a gas company serving substantially the same territory; or (2) if it already has any such interest, to acquire, without the express approval of the state commission, any direct or indirect interest in an electric utility company or gas utility company serving substantially the same territory as that served by such companies in which it already has an interest. Thus, on its face, the Act only precludes the use of the registered holding company form to circumvent any state law restrictions on the ownership of gas and electric assets by the same company. Further, the legislative history of the Act indicates that Congress saw the question of whether combination companies are desirable as one that should be left to the states. The Senate Committee on Interstate Commerce in its report on the Act noted that the provision in Section 8 concerning combination companies "is concerned with competition in the field of distribution of gas and electric energy -- a field which is essentially a question of State policy, but which becomes a proper subject of Federal action where the extra-State device of a holding company is used to circumvent State policy."/7/ In addition, attached to the committee report is the Report of the National Power Policy Committee on Public-Utility Holding Companies, which sets forth a recommended policy that: "Unless approval of a State commission can be obtained the commission would not permit the use of the holding-company form to combine a gas and electric utility serving the same territory where local law prohibits their combination in a single entity." Congress clearly recognized that local regulators are in the best position to assess the needs of their communities. The Act was never intended to supplant local regulation but, rather, was intended to create conditions under which local regulation was possible. Section 21 of the Act states: Nothing in [the Act] shall affect . . . the jurisdiction of any other commission, board, agency or officer of . . . any State, or political subdivision of any State, over any person, security, or contract, insofar as such jurisdiction does not conflict with any provision of [the Act]. . . . The legislative history reveals that Section 21 of the Act was further intended "to ensure the autonomy of State commissions [and] nothing in the [Act] shall exempt any public utility company from obedience to the requirements of State regulatory law." S. Rep. No. 621, 74th Cong., 1st Sess. 10 (1935). - ------------------- /7/ The Report of the Committee on Interstate Commerce, S. Rep. No. 621 74th Cong., 1st Sess. 31 (1935). 10 The Act should not be used as a tool to override state policy, particularly where the holding company involved is subject to both state and federal regulation and where the affected state regulatory commissions have supported the combined electric and gas operations in one holding company system. To do otherwise would be to act contrary to Congress' intent. (2) The Commission's Interpretation of the Act. In its early decisions under the Act, the Commission adhered to the concept that Section 8 of the Act evidenced the policy of Congress that the decision of whether to allow combination companies was one that states should make (although the Commission might have to implement it in certain cases) and, where such systems were permissible, the role of the Commission was to ensure that both such systems were integrated as defined in the Act. If the electric systems were integrated and the electric and gas properties were in close geographic proximity and were related so that substantial economies were obtained by their coordination under common control, then combined ownership by the registered holding company would be permitted. See American Water Works & Elec. Co., 2 SEC 972 (Dec. 30, 1937); 1995 Report at 62. If a combination company did not violate state policy, there was no need for the Commission to exercise jurisdiction to implement state policy. By the early 1940s, however, the Commission, faced with further perceived abuses and based on then existing competitive conditions, switched its focus to Section 11 and adopted a narrow interpretation of the standards contained therein as the controlling factor with regard to combination registered holding companies./8/ In this period of the administration of the Act, facing vigorous constitutional challenges to the Act's validity as well as concerted resistance in many proceedings to the specific attempts to order divestiture by holding companies of utility subsidiaries, the Commission pursued a policy of strict interpretation of the Act to best effectuate the directive from Congress that the monolithic holding companies be broken up./9/ Furthermore, in connection with its analysis of combination companies under Section 11, the Commission frequently noted a policy concern existing at that time which advocated separating the management of gas and electric utilities based on the belief that the gas utility business tended to be overlooked by combination company management who focused on the - -------------------- /8/ See, e.g., In re Columbia Gas & Elec. Corp., 8 SEC 443, 463 (Jan. 10, 1941); In re United Gas Improvement Co., 9 SEC 52 (1941); SEC v. New England Elec. Sys., 384 U.S. 175 (1966). It should be noted that the Commission continued to give primacy to state utility commission determinations in making decisions regarding combination exempt holding companies. See, e.g., In re Northern States Power Co., 36 SEC 1 (Sept. 16, 1954); Delmarva Power & Light Co., 46 SEC 710 (Oct. 19, 1976); WPL Holdings, Release No. 35-24590 (Feb. 26, 1988); CIPSCO Inc., 47 SEC Docket 174 (Sept. 18, 1990). /9/ That goal has been long accomplished. 1995 Report at ix. 11 electric business. Therefore, it was believed that gas utilities would benefit from having separate management focused entirely on the gas utility business. /10/ (3) The Commission Should Revise Its Interpretation of the Act. The Commission is not bound by its historical emphasis on Section 11 of the Act when assessing combination companies. An agency may revise its interpretation of its governing statute where its revised interpretation is reasonable and where it provides a reasoned basis for its change. Chevron USA, Inc. v. Nat'l Resources Defense Council, Inc., 467 U.S. 837 (1984); Rust v. Sullivan, 500 U.S. 173, 186-87 (1991) (agency's reversal of policy in effect for 18 years was consistent with intent of statute and was supported by reasoned analysis, and thus permissible). The Supreme Court has indicated that the governing principle is the intent of Congress, not an agency's long-standing practice. In Chevron, the Court stated: When a court reviews an agency's construction of the statute which it administers, it is confronted with two questions. First, always, is the question whether Congress has directly spoken to the precise question at issue. If the intent of Congress is clear, that is the end of the matter; for the court, as well as the agency, must give effect to the unambiguously expressed intent of Congress. If, however, the court determines Congress has not directly addressed the precise question at issue, the court does not simply impose its own construction on the statute, as would be necessary in the absence of an administrative interpretation. Rather, if the statute is silent or ambiguous with respect to the specific issue, the question for the court is whether the agency's answer is based on a permissible construction of the statute. Chevron, 467 U.S. at 842-43 (citations omitted; emphasis added). Moreover, the Court has stated: [An agency's] revised interpretation [of a statute] deserves deference because an initial agency interpretation is not instantly carved in stone and the agency, to engage in informed rulemaking, must consider varying interpretations and the wisdom of its policy on a continuing basis. An agency is not required to establish rules of - ------------------- /10/ See, e.g., In re Philadelphia Co., 28 SEC 35, 48 (June 1, 1948); In re North American Co., 11 SEC 194, 216-17 (Apr. 14, 1942); In re Illinois Power Co., 44 SEC 140 (Jan. 2, 1970). The principal reasons for this change in policy was to better administer the Act in light of perceived abuses and conditions in the industry at the time. As noted, industry conditions are significantly different now than in the 1940s. Also, the actual statutory basis for this changed policy rested on a very technical interpretation of the definition of "integrated public utility system." As will be shown, this strained interpretation ignores the clear language of Section 8. See 1995 Report at 63, 65. As noted below, the Commission has the authority to reinterpret the meaning of the Act in light of changed conditions. 12 conduct to last forever, but rather must be given ample latitude to adapt its rules and policies to the demands of changing circumstances. Rust, 500 U.S. at 186-87 (citations and internal quotation marks omitted). The Commission has begun a re-evaluation of the requirements of Section 11 in light of contemporary conditions. To date, that review has principally focused on the meaning of the A-B-C Clauses and whether it is necessary to continue a narrow, restrictive interpretation of those provisions. In NEES I, the Supreme Court specifically recognized that the language of clause (A) of Section 11(b)(1) was "not crystal clear" and deferred to the Commission's "expertise on the total competitive situation." 384 U.S. at 185 (emphasis in original); see also NEES II, 390 U.S. at 219. In NEES I and NEES II, the Court accepted the Commission's interpretation of Clause A as a "construction well within the permissible range given to those who are charged with the task of giving an intricate statutory scheme practical sense and application." 384 U.S. at 185. The NEES interpretation however, is not the only permissible interpretation. There is strong support for the Commission's application of a different interpretation of Clause A, and the Commission may use its expertise to develop a different interpretation which is both consistent with Congress' intent and which properly addresses the "demands of changing circumstances." Rust, 500 U.S. at 186-87. This Commission is free to apply its expertise to administer the Act in light of changes in legal, regulatory and economic circumstances which were not foreseen at the time of the NEES decisions, including federal legislation (described below) which has "substantially changed" the Act. See Chevron, 476 U.S. at 842. The Division recognized in the 1995 Report that the Commission should no longer be bound by the narrow interpretation of Clause (A) under the NEES decisions. In so doing, the Division stated: [T]he SEC has generally required electric registered holding companies that seek to own gas utility properties to satisfy the requirements of the A-B-C clauses concerning additional integrated systems. In contrast, exempt holding companies have generally been permitted to retain or acquire combination systems so long as combined ownership of gas and electric operations is permitted by state law and is supported by the interested regulatory authorities. In the past, the SEC has construed the A-B-C clauses narrowly to permit retention only where the additional system, if separated from the principal system, would be incapable of independent economic operations. Although the Supreme Court upheld the SEC's reading, two justices dissented, contending that the "serious impairment" standard was at odds with the wording of the Act, had little basis in the statutory history or aims of the Act, and could not be sustained by agency or 13 judicial precedent. The dissenting justices believed that the statutory language "called for a business judgment of what would be a significant loss." Applicants in recent matters have argued that, in a competitive utility environment, any loss of economies threatens a utility's competitive position, and even a "small" loss of economies may render a utility vulnerable to significant erosion of its competitive position. There is general support for a more relaxed standard. A number of commenters emphasize that these are essentially state issues. It does not appear that the SEC's precedent concerning additional systems precludes the SEC from relaxing its interpretation of section 11(b)(1)(A). Indeed, the SEC has recognized that section 11 does not impose "rigid concepts" but rather creates a "flexible" standard designed "to accommodate changes in the electric utility industry." Congress, in 1935, recognized that competition in the field of distribution of gas and electric energy is essentially a question of state policy. The Act was intended to ensure compliance with state law in this regard. Moreover, it appears that the utility industry is evolving toward the creation of one-source energy companies that will provide their customers with whatever type of energy supply they want, whether electricity or gas. Accordingly, the Division believes it is appropriate to reconcile the treatment of registered and exempt companies in this regard, and so recommends that the SEC permit registered holding companies to own gas and electric utility systems pursuant to the A-B-C clauses of section 11(b)(1), where the affected states agree./11/ The Commission approved the Report on June 20, 1995. The Division's recommendation regarding Clause A would represent sound policy by the Commission. Indeed, the policy so expressed would equally support a finding that a combination company, if it meets the requirements of the American Water Works decision, constitutes a single integrated public utility system. From a policy perspective, the Commission's historic concern underpinning its 1964 NEES decision and a host of earlier decisions where the retainability of gas properties by registered electric systems was at issue -- namely, of fostering competition between electric and gas -- is simply no longer valid given the current "state of the art" in the electric and gas utility industries. In the three decades since the Commission decided the NEES cases, profound economic and regulatory factors have wrought a fundamental transformation in the gas supply and electric generation industry, rendering obsolete the Commission's earlier premises regarding the primacy of competition between gas and electric service and the lack of competition within electric and gas service. - ------------------- /11/ 1995 Report at 74, 75, 76. Footnotes omitted. 14 The Commission itself has noted that the Act "creates a system of pervasive and continuing economic regulation that must in some measure at least be refashioned from time to time to keep pace with changing economic and regulatory climates." Union Electric Co., 45 S.E.C. 489,503 n.52 (1974), aff'd sub nom. City of Cape Girardeau v. SEC, 521 F.2d 324 (D.C. Cir. 1974). See also Eastern Utilities Assoc., Holding Co. Act Release No. 26232 (Feb. 15, 1995). The Commission has specifically recognized that the "changing realities of the utility industry" include "the increasing integration of energy markets, as deregulation and competition increase." Consolidated Natural Gas Co., Release No. 35-26512 (Apr. 30, 1996) ("Consolidated"). The Commission took further steps toward the conclusion urged here in Consolidated. In that case, Consolidated, a registered gas utility company, received approval to enter into the wholesale electric marketing business. The Commission indicated it would approve retail marketing of electricity when state laws had developed to allow such activity. Quoting an earlier release, the Commission noted that "the utility industry is evolving toward a broadly based energy-related business that is no longer focused solely on the traditional, regulated, production and distribution functions of a utility." Under the Consolidated decision, Consolidated (a gas utility) may own electric generating facilities (e.g., through an EWG) and may sell electricity through the approved marketing subsidiary. Several months after Consolidated, the Commission took a further step. Recognizing that "the electric and gas industries are no longer separate, but are instead increasingly integrated," the Commission approved the application of an electric registered holding company system to engage in retail marketing of energy commodities (including electricity and gas). SEI Holdings, Release No. 35-26581 (Sept. 26, 1996) ("SEI Holdings"). Thus, registered holding companies are now able to offer their wholesale and retail customers integrated gas and electric energy services -- exactly what Ameren wishes to offer its customers. Consolidated, SEI Holdings and the cases following them strongly suggest that the Commission is changing its interpretation of the Act including those activities deemed "detrimental to carrying out the provisions of Section 11."/12/ UE and CIPS have conducted combined electric and gas operations for many years. As the energy markets have developed, especially in recent years, CIPS and UE have developed, and are further developing, as "energy service" companies. The provision of gas and electric products is only the start of a utility's job. In addition, the utility must provide an entire package of both energy products and services. In this area, CIPS' and UE's efforts are part of a trend by utilities to organize themselves as "energy service companies," that is, - ------------------- /12/ See Northeast Utilities, Release No. 35-26554 (Aug. 13, 1996) and cases cited in note 14 thereof. See also American Electric Power Co., Release No. 35-26572 (Sept. 13, 1996). While Consolidated, and SEI Holdings do not directly interpret the meaning of "single integrated public utility company," but rather find that the approved marketing activities constitute a permissible other business under Section 11(b)(1), the finding by the Commission that marketing of electricity by a gas registered holding company system is not "detrimental to the carrying out of the provisions of Section 11" constitutes substantial support for the proposition urged here: that combination companies are likewise not detrimental to the purposes of Section 11. The Commission has extended Consolidated to also allow electric registered holding company systems to engage in electric and gas brokering and marketing activities. 15 as providers of a total package of energy services rather than merely suppliers of gas and electric products. The goal of an energy service company is to retain its current customers and obtain new customers in an increasingly competitive environment by meeting customers' needs better than the competition. An energy service company can provide the customer with a low cost energy option (i.e., gas, electricity or conservation) without inefficient subsidies. As energy services companies, UE and CIPS are not solely electric or gas utilities and do not operate in a manner which could lead to the abuses which, under competitive conditions previously prevailing in the industry, were perceived as likely to arise from the combination of gas and electric utilities under common ownership in a single holding company system -- i.e., the "favoring of one of these competing forms of energy over the other." NEES I at 183. Rather, UE and CIPS offer (and the Ameren system will offer) diverse forms of energy to their consumers, thereby allowing customers to choose among different forms of energy and fostering efficiency and conservation. This increasing competition to supply all forms of energy will prevent a holding company from "favoring" one form over the other. Furthermore, consumers and regulators today must be -- and are -- more careful with limited energy resources than was required in 1935. See Eastern Utilities Associates, Release No. 35-26232 (Feb. 15, 1995) and the 1995 Report at 22-23 and 30-31. One energy company which allows its customers to select among different forms of energy based on environmental and economic factors is a sensible means of allocating scarce national resources under the purview of local regulators who are most familiar with the needs of local constituencies. This trend is exemplified by several transactions including the proposed merger of Texas Utilities, an electric utility, with Enserch Corp., which is a natural gas concern, and the acquisition by Enron Corp., a major integrated gas company with electric power marketing business, of the electric utility Portland General Corp. Referring to such cross industry transactions, Elizabeth A. Moler, Former Chairwoman of the Federal Energy Regulatory Commission ("FERC") said: "They have the potential to increase competition and make more options available to consumers." Allen R. Myerson, Enron Will Buy Oregon Utility In Deal Valued at $2.1 Billion, New York Times, July 23, 1996 at D1. Since these transactions were announced, Houston Industries, an exempt electric utility holding company, announced a merger with NorAm Energy Corp., a natural gas pipeline and local gas distribution company, and Enova Corp., the holding company for San Diego Gas & Electric, an electric company agreed to merge with Pacific Enterprises, a natural gas distribution utility. This merger will produce the largest customer base of any investor owned utility. Benjamin A. Holden, Deal Valued at $2.8 Billion Would Establish Giant for California Energy, Wall Street Journal, Oct. 15, 1996 at A3. Each of these companies is responding to industry realities and customer demands that utilities be capable of supplying total energy services, not merely one energy commodity. As the Commission noted in SEI Holdings, "Industry trends and competitive pressures make it important for registered system companies to be poised to compete in new markets as they are created." See also Consolidated Natural Gas, Release No. 35-26512 (Apr. 30, 1996). Since the Ameren Application was filed in October, 1996, at least five other "convergence" transactions have been announced, including: Brooklyn Union Gas Co. and Long Island Lighting Co.; PG&E Corp. and Valero Energy; Destec Energy Inc. and NGC Corp.; Duke Power and PanEnergy and Pacificorp and TPC Corp. 16 These proposed cross industry transactions clearly demonstrate that market forces are demanding the unified delivery of energy services and that such combinations will be beneficial to the interests of investors and consumers and accordingly the public interest. None of the announced mergers is anticipated to be restrained by the Act./13/ Continued reliance on outdated premises which prevent registered combination companies and do not reflect current competitive conditions will put registered holding companies at a severe competitive disadvantage. FERC Commissioner Donald F. Santa has stated "the cause for concern about combination electric and gas providers largely has disappeared . . . . In a converged electric and gas market, there will be additional opportunities for scale economies, for innovation and for competition -- all of which should be beneficial to consumers and the economy." Foster Natural Gas Report, May 29, 1997 at 4. There are many benefits of such combined electric and gas energy services providers. For customers, the energy service utility provides the convenience and efficiency of service by a single energy provider and reduces transaction costs incurred in gathering and analyzing information, contacting energy suppliers and negotiating terms of service. For the communities in which the energy service company operates, the combining of gas and electric operations simplifies community planning on energy-related matters through coordination with a single energy provider. For society, the combination energy services company will allow customers to efficiently choose energy sources thus ensuring an environmentally efficient allocation of energy. For utility shareholders and employees, the energy services company is better able to respond to a competitive environment and to remain an attractive investment opportunity for shareholders and an appealing employer for utility employees. Thus, combination utilities benefit all utility stakeholders. The benefits to the public interest from these combinations is demonstrated by the approvals several have already received from FERC./14/ The development of energy services companies stems from dramatic changes in the regulatory framework of the industry. In the gas area, regulatory changes have introduced competition into what was formerly a monopoly and have expanded the availability of "transportation-only service" as an alternative to sales services from the local gas utility company. CIPS and UE have "open access" transportation-only service tariffs on file with their respective state commissions, and approximately 39% and 14% of the gas delivered by CIPS and UE, respectively, in 1995 was directly purchased by customers. FERC Order 636 is resulting in the separation of the commodity function from the transportation function at both wholesale and retail levels. - ------------------- /13/ It appears that most, if not all, the proposed mergers of predominantly gas businesses with predominantly electric businesses can be structured to meet the intrastate exemption of Section 3(a)(1) or otherwise not be subject to the Act. The benefits to investors and consumers that will flow from such combinations should not be limited to only those enterprises operating within one state, but should be available to all investors and consumers. /14/ See e.g., Duke Power Company and PanEnergy Company, 79 FERC (P) 61,236 (May 28, 1997); San Diego Gas & Electric Co. and Enova Energy, Inc., 79 FERC (P) 61,372 (June 25, 1997). 17 As a result, combination utilities such as UE and CIPS have less ability than they did in 1935 to "favor" electric -- the principal policy concern in decisions ordering the separation of gas and electric systems -- by curtailing the availability or increasing the price of gas./15/ Combination utilities also have less incentive to favor electric over gas in light of the increasing importance of demand-side management, the costs and risks involved in the construction of new generating capacity and the incentives to avoid such construction, and, as noted in the June 1994 issue of The Electricity Journal, the emergence of integrated resource planning involving both gas and electric service. In the electric area, the Energy Policy Act of 1992 and the Public Utility Regulatory Policies Act of 1978 have introduced competition into the electric utility business. As the chairman of the Senate Banking Committee stated as early as three years ago: "[The Act] was substantially changed by the Energy Policy Act of 1992. That law restructured the utility industry to promote greater competition for the benefit of energy customers. The Energy Policy Act of 1992 was the product of a cooperative effort on the part of the Banking Committee and the Energy Committee to create a more market- oriented regulatory framework for the energy industry." Hearing on S.182, The Communications Act of 1994, before the Comm. on Commerce, Science and Transportation, 103rd Cong. 2nd Sess. 344-345 (1994) (prepared Statement of Senator Riegle) (emphasis added). As a continuation of the trend towards more competition, on April 24, 1996, the FERC entered Orders 888 and 889. These orders, entered after more than a year of debate and public comment, open up wholesale power sales to competition. All utilities subject to Order 888 must provide transmission service to qualified wholesale buyers and sellers on terms set by universally applicable tariffs. This mandatory "wholesale wheeling" will bring competition to the market for electricity provided to customers for resale./16/ Finally, many states have adopted electric open access or customer choice laws or regulations or have other "retail wheeling" measures under discussion which are likely to have the effect of extending electric supply competition to the retail level. Illinois and Missouri are each in the process of evaluating various options that could increase electric supply competition at the retail level./17/ Federal legislation is being proposed which would require - ------------------- /15/ See, e.g., NEES I at 183-184. It is important to note that this issue -- basically an antitrust issue -- was the principal concern in previous decisions ordering the separation of gas and electric systems and clearly is no longer applicable to the changed utility competitive environment. /16/ UE and CIPS filed their electric open-access transmission tariffs in compliance with Order 888 on July 9, 1996. /17/ The Illinois General Assembly has appointed a special legislative committee to develop a policy to introduce retail electric competition. Legislation was introduced, and passed in the House, but not adopted by the Senate, in the 1997 Spring Session of the General Assembly (H.B. 263). Legislation 18 all states to adopt a retail wheeling scheme by early in the next century./18/ These initiatives could soon bring direct commodity competition to retail electric customers much as such competition already exists for natural gas. Many of these recent changes to the energy industry are noted in SEI Holdings, Release No. 35-26581 (Sept. 26, 1996). Accordingly, instead of relying on the blunt instrument of competition between gas and electric energy sources (the driving force behind the Commission's historic interpretation of the Act), national policy has now created direct competition within the gas and electric utility industries. Thus, combination ownership does not eliminate competition, since a combination utility now has competitors for both gas and electric service. Moreover, competition is not an end in itself, but is merely a means to the end of efficient, cost-effective service. Since combination ownership creates efficiencies and no longer has the effect of eliminating competition, there is no reason for the Commission to prohibit combination ownership, at least under the circumstances presented here. Further, there is nothing in national energy policy that would override the deference Congress intended should be given to the states on this question. Indeed, as discussed above, in the 1995 Report the Division recommended that the Commission interpret Section 11(b)(1) of the Act to allow registered holding companies to hold both gas and electric operations as long as each affected state utility regulatory commission approves of the existence of such a company./19/ As noted, the Commission has begun to reevaluate Section 11, to place more meaning on Section 8 in its review of the A-B-C Clauses and to accommodate electric and gas marketing by a single registered holding company in its decisions in Consolidated, SEI Holdings and the cases following them. The Commission should take the further step, justified by all the same facts, circumstances and policies, and permitted under Chevron and Rust, to determine that a registered holding company may control combination gas and electric utility companies. - ------------------------ /17/(...continued) could be adopted in the Fall of 1997. Two Illinois utilities have initiated pilot programs which give retail customers a choice in electricity providers. CIPS has received approval to participate as a supplier in those programs. Further information concerning Illinois initiatives is included in CIPSCO's 1996 Form 10-K and its 1997 Form 10-Q's filed as exhibits to the Application. In Missouri, a joint agreement among the parties in the MPSC proceeding to approve the Transaction calls for UE to propose an experimental retail wheeling pilot program in Missouri for 100 mW of electric power. This agreement filed as Exhibit D-2.3 was included in the settlement approved in the final MPSC Order. See Exhibit D-2.2 to the Application. /18/ See, e.g., HR 655 (105th Cong.; 1st Session) (by 2000); S 237 (105th Cong.; 1st Session) (by 2003). /19/ The 1995 Report urges flexible interpretation of the ABC Clauses. However, as demonstrated herein, there is ample reason, in light of changed national energy policy for the Commission to go further and return to its pre-1940s reliance on Section 8's clear language to permit State- sanctioned combination companies. 19 Such a reemphasis on Section 8 fits within the overall regulatory scheme of the Act. Section 11 of the Act is flexible and was designed to change as the policy concerns over the regulation of utility holding companies changed./20/ Moreover, a registered holding company would still be required to demonstrate that any acquisition or transaction by which it would become a combination company would not be detrimental to carrying out the provisions of Section 11 of the Act. In other words, its electric system would have to constitute an integrated electric system and its gas system would have to constitute an integrated gas system and both systems would have to be capable of being operated efficiently together (all facts which are clearly present in the instant case). See American Water Works & Elec. Co., 2 SEC 972 (Dec. 30, 1937). Thus, the standards of Section 11 would still have to be met, but the application of those standards should take into account the fundamental policy of the Act and allow local regulators to make the threshold determination with regard to combination companies. As shown under Item 3.A.b.ii. of the Application, the electric systems of UE and CIPS constitute an "integrated" electric system and the gas systems constitute an "integrated" gas system. Moreover, as the Gas Study clearly shows, the electric system and the gas system together are operated as a single integrated energy company. The integration standard of the Act is designed to require efficient operations. The Gas Study shows that separating the existing gas systems from the existing fully integrated companies would result in a loss of significant economies if two new companies were formed and even if only one new company conducted the integrated gas operations. These economies relate to more than just corporate operations but also include substantial savings resulting from such operational matters as joint gas and electric meter reading, combined field service facilities, combined engineering services, combined customer service facilities and combined transportation services. Section 11 was intended to require the separation and independent operation of utilities that were commonly controlled through the holding company but had no operational connection. That situation is not presented in any way by the Transaction, thus the purposes of the Act would not be compromised in any way by approval of retention of the combination gas and electric businesses. Furthermore, the Commission has had the opportunity to review the gas utility operations of UE and CIPS in prior orders and found that continued combination activity would not be "detrimental to the public interest or the interest of investors or consumers" and would not be "detrimental to the carrying out of the provision of Section 11." See the CIPSCO and Union Electric cases cited in note 2 above. (4) UE's and CIPS' Combination Systems Are Not Prohibited by State Law Each of UE and CIPS as a combination company is permissible pursuant to the terms of Section 8 of the Act because the continued combined activities in no way violate state - ------------------------ /20/ In re Mississippi Valley Generating Co., 36 SEC 159 (Feb. 9, 1955) (noting that Congress intended the concept of integration to be flexible); Unitil Corp., 51 SEC Docket 562 (Apr. 24, 1992) (noting that Section 11 contains a flexible standard designed to accommodate changes in the industry). 20 policy. Moreover, continuation of each as a combination company is in the public interest. The ICC and MPSC have on numerous occasions over the years had opportunity to review the combined operations in light of public interest standards in rate cases and other proceedings. These cases have approved cost allocation methods, accounting procedures and other factors which insure that combination activities are not harmful to customers. Furthermore, as part of state merger approvals, approval of the ICC will be sought for the acquisition by CIPS of the UE Illinois gas properties. The MPSC has given final approval to the Transaction, including the transfer of the gas properties. Although the transfer of UE's Illinois utility properties to CIPS has been contested in the ICC proceeding, the concern does not relate to combining gas and electric properties. Finally, as required by Section 11, in addition to the fact that the electric systems of CIPS and UE constitute an integrated electric system, the gas systems will together constitute an integrated gas system as explained in detail below. With respect to Section 8, the combination of electric and gas operations is lawful under all applicable state laws for each of UE and CIPS and has been considered and approved indirectly on numerous occasions by Missouri and Illinois regulators who have, and will continue to have, direct jurisdiction over the Ameren gas operations. The use of Ameren as a holding company for two combination companies will not circumvent any state regulations, since the gas utility operations of each of UE and CIPS individually will continue to be regulated by the relevant jurisdictions. Both the ICC and the MPSC will have the opportunity to review the continued operation of combination companies as part of their approval of the Transaction and would have the ability to impose conditions on their approval if they felt it necessary to protect the public interest. See, e.g., 220 ILCS 5/7-204. Given the long-standing operation of combined electric and gas businesses in both Missouri and Illinois, the statutory authority of the MPSC and ICC and the many opportunities for review of such combined operations, including the review of the Transaction, it is clear that state regulators do not believe combination operations lead to harm to utility customers. UE and CIPSCO will notify the Commission when the ICC approval is received. Such state commission actions manifest the recognition by those commissions that the existence of both gas and electric systems in the Ameren holding company system will allow Ameren's customers greater choice to meet their energy needs, especially given the fact that the electric and gas systems operate in substantially the same territory, while sharing in the synergies that result from the Transaction. Moreover, the prior fear that a holding company such as Ameren would be able to greatly emphasize one form of energy over the other based on its own agenda has dissipated both because of the competitive nature of the energy market, which requires utilities to meet customer energy supply requirements or risk losing the customer to a competing supplier, and because state regulators will have sufficient control over, and would be unlikely to approve, a combination company that attempts to undertake such practices. For all these reasons, the Commission should change its policy and approve the retention by UE and CIPS of their respective gas properties as contemplated by the Transaction. No policy would be furthered by requiring divestiture, and, indeed, state and national policy would be thwarted by such a requirement. 21 CONCLUSION For the reasons set forth above, and in Ameren's Application and supporting exhibits, it is respectfully submitted that the Commission should allow Ameren to retain the gas utility operations of UE and CIPS following the consummation of the Transaction and the registration of Ameren as a holding company under the Act. Jones, Day, Reavis & Pogue July 15, 1997 22 -----END PRIVACY-ENHANCED MESSAGE-----