-----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, U15lFO5ll/OsHsvBE8bFGhTS5Z22pX9vk3Djic+vO7MMXzb5Ma5yiV6AQE7hXe12 81J6CRAddpleeCMftJhAnw== 0000940170-98-000011.txt : 19980408 0000940170-98-000011.hdr.sgml : 19980408 ACCESSION NUMBER: 0000940170-98-000011 CONFORMED SUBMISSION TYPE: U-1/A PUBLIC DOCUMENT COUNT: 7 FILED AS OF DATE: 19980407 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: MINERAL ENERGY CO CENTRAL INDEX KEY: 0001032208 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 330732627 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: U-1/A SEC ACT: SEC FILE NUMBER: 070-09033 FILM NUMBER: 98588909 BUSINESS ADDRESS: STREET 1: 101ASH STREET STREET 2: P O BOX 129400 CITY: SAN DIEGO STATE: CA ZIP: 92112-9400 BUSINESS PHONE: 6192397700 MAIL ADDRESS: STREET 1: 101 ASH STREET STREET 2: P O BOX 129400 CITY: SAN DIEGO STATE: CA ZIP: 92112-9400 U-1/A 1 As filed with the Securities and Exchange Commission on April 7 1998. File No. 70-09033 UNITED STATES OF AMERICA SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ___________________________________________________________ AMENDMENT NO. 3 TO FORM U-1 APPLICATION OR DECLARATION UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 Sempra Energy (formerly Mineral Energy Company) 101 Ash Street San Diego, California 92101 (Name of company or companies filing this statement and address of principal executive offices) None (Name of top registered holding company parent of each applicant or declarant) Richard D. Farman Stephen L. Baum President and Chief Operating Officer President and Chief Executive Officer Pacific Enterprises Enova Corporation 555 West Fifth Street, Suite 2900 101 Ash Street Los Angeles, California 90013-1001 San Diego, California (213) 895-5000 (619) 696-2000 (Name and address of agents for service) ___________________________________________________________ The Commission is requested to send copies of all notices, orders and communciations in connection with this Application to: Ruth S. Epstein, Esq. Covington & Burling 1201 Pennsylvania Avenue, N.W. P.O. Box 7566 Washington, D.C. 20044-7566 UNITED STATES OF AMERICA SECURITIES AND EXCHANGE COMMISSION SEMPRA ENERGY ) (formerly Mineral Energy Company) ) ) File No. 70-9033 Amendment No. 3 To Application On ) Form U-1 ) INTRODUCTION On March 26, 1997, Mineral Energy Company, a newly formed California corporation that now has been renamed Sempra Energy (the "Company"), filed an application on Form U-1 (the "Application") with the Securities and Exchange Commission (the "SEC" or the "Commission") seeking (1) authorization for its acquisition of Pacific Enterprises ("Pacific") and Enova Corporation ("Enova") (the "Transaction") under Sections 9(a)(2) and 10 of the Public Utility Holding Company Act of 1935) (the "1935 Act" or the "Act"); and (2) an order exempting the Company under Section 3(a)(1) of the Act from all provisions of the Act except Section 9(a)(2). The Application was amended on May 13, 1997, by the submission of additional exhibits, and was further amended on January 28, 1998, by submitting information about the progress of related approval proceedings and the submission of additional exhibits. On March 26, 1998, the California Public Utilities Commission (the "CPUC") voted to approve the Transaction. The CPUC found that the Transaction will benefit customers, maintain or improve the financial condition of the constituent utilities and quality of management, and be fair to shareholders and employees, and, as conditioned, would enhance rather than adversely affect competition. A copy of the CPUC's order (the "CPUC Order"), which was issued on April 1, is included as Exhibit D-10 to this Application. - 1 - All other regulatory approval proceedings for the Transaction are virtually complete as well. The Nuclear Regulatory Commission approved the Transaction on August 29, 1997. The Federal Energy Regulatory Commission ("FERC") approved the Transaction on June 25, 1997, subject to certain conditions that have now been satisfied. Accordingly, the Company has requested FERC to enter its final order and expects this order shortly. Finally, on March 9, 1998, Enova reached an agreement with the U.S. Department of Justice ("DOJ"), which terminated DOJ's review and cleared the Transaction under the notification requirements of the Hart-Scott-Rodino Antitrust Improvements Act. The favorable resolution of these regulatory proceedings demonstrates that the Transaction is in the public interest, and that all concerns have been carefully studied and resolved. It is critical to reaping the substantial benefits of the Transaction for both shareholders and consumers that the Transaction be consummated as soon as possible. Now that the CPUC has approved the Transaction, the constituent companies have commenced the final phase of preparation for the Transaction, and will be ready to close the Transaction by June 1, 1998. The Company therefore requests the that Commission issue its final order on the Application promptly, and in any event no later than May 29, 1998. In order to expedite the Commission's final decision in this matter, this Amendment is being filed to provide a description of the CPUC approval order and the other final regulatory proceedings (previous proceedings are described in Amendment No. 2 to the application filed on January 28, 1998). This Amendment also provides, as a supplement to the Application, certain 1997 year-end financial information relating to Enova and Pacific, and to the - 2 - Company on a pro forma basis. All capitalized terms used in this amendment will refer to the definitions in the Application, unless otherwise indicated. Item numbers used are those found in the Form U-1. Item 1. Description of the Proposed Transaction Pacific The common stock of Pacific, without par value, is listed on the New York Stock Exchange and the Pacific Stock Exchange ("PSE"), and the preferred stock of Pacific, without par value, is listed on the American Stock Exchange and the PSE. As of the close of business on December 31, 1997, there were 81,103,449 shares of Pacific Common Stock and 800,253 shares of Pacific Preferred Stock issued and outstanding. For the year ended December 31, 1997, Pacific's operating revenues on a consolidated basis were approximately $2.738 billion (net of $5 million in balancing and other adjustments), of which approximately $2.228 billion were attributable to sales of natural gas, $408 million were attributable to natural gas transportation revenues, and $97 million were attributable to non-utility activities. Consolidated assets of Pacific and its subsidiaries at December 31, 1997, were approximately $4.977 billion, of which approximately $3.154 billion consisted of net gas plant. At December 31, 1997, Pacific employed approximately 7,215 persons, approximately 6,615 of which were employed by SoCalGas. Enova The common stock of Enova, without par value, is listed on the NYSE and the PSE. As of the close of business on December 31, 1997, there were 113,634,744 shares of Enova Common Stock issued and outstanding. Enova has no other equity securities outstanding. For the year ended December 31, 1997, Enova's operating revenues on a consolidated basis were approximately $2.217 billion, - 3 - of which approximately $1.769 billion were attributable to its electric utility operations, approximately $398 million were attributable to its gas utility operations, and approximately $50 million were attributable to its energy-related and other operations. Consolidated assets of Enova and its subsidiaries at December 31, 1997, were approximately $5.234 billion, of which approximately $2.487 billion consists of net electric plant and $449 million consists of net gas plant. At December 31, 1997, Enova employed 3,665 people, of which 3,576 people were employed by SDG&E. In November 1997, SDG&E's board of directors approved a plan to auction the company's power plants and other electric- generating assets, enabling SDG&E to continue to concentrate its business on the transmission and distribution of electricity and natural gas as California opens its electric utility industry to competition in 1998. The plan includes the divestiture of SDG&E's fossil power plants -- the Encina (Carlsbad, California) and South Bay (Chula Vista, California) plants -- and its combustion turbines, as well as its 20-percent interest in the San Onofre Nuclear Generating Station ("SONGS") and its portfolio of long-term purchased-power contracts, including those with qualifying facilities. The power plants, including the interest in SONGS, have a net book value as of December 31, 1997, of $800 million ($200 million for fossil and $600 million for SONGS) and a combined generating capacity of 2,400 megawatts. In December 1997, SDG&E filed with the CPUC for approval of the auction plan. The sale of the nonnuclear generating assets is expected to be completed by the end of the first quarter of 1999. Management and Operations of the Company Following the Transaction On a combined pro forma basis, using information as of December 31, 1997, the utility subsidiaries of the Company would - 4 - serve approximately 1.2 million electric customers and 5.4 million natural gas customers in southern and central California. The Company would have operating revenues of $4.900 billion, consisting of $2.984 billion attributable to gas operations, $1.769 billion attributable to electric operations, and $147 million attributable to nonutility operations. The Company would have total assets of $10.112 billion, including $3.603 billion attributable to net gas plant and $2.487 billion attributable to net electric plant. Set forth below are summaries of the historical capital structure of Pacific and Enova as of December 31, 1997, and the pro forma consolidated capital structure of the Company as of the same date. - 5 - Pacific and Enova's Historical Capitalizations As of December 31, 1997 (dollars in millions) (audited) Enova Pacific $ % $ % Common Stock Equity 1,570 42.1 1,389 51.8 Preferred Stock --- --- 80 3.0 Long-term Debt * 2,057 55.1 1,118 41.7 Preferred Stock of a 104 2.8 95 3.5 Subsidiary Total** 3,731 100 2,682 100 The Company Pro Forma Consolidated Capitalization As of December 31, 1997 (dollars in millions) (unaudited) $ % Common Stock Equity 2,959 46.1 Preferred Stock 80 1.3 Long-term Debt * 3,175 49.5 Preferred Stock of 199 3.1 Subsidiaries Total** 6,413 100 * Includes $658 million of electric rate-reduction bonds. ** Does not include $502 million in short-term debt and long-term debt due within one year of Pacific and $122 million in long-term debt due within one year of Enova. Joint Ventures Between Enova and Pacific Sempra Energy Solutions (formerly Energy Pacific), jointly owned, 50% each by Enova and Pacific, provides a broad range of energy-related products and services in California and throughout the United States. Sempra Energy Trading Corp. (formerly AIG Trading Corp.), also jointly owned, 50% each by Enova and Pacific, is engaged in the business of marketing and trading physical and financial energy - 6 - products, including natural gas, power, crude oil and associated commodities. Item 3. Applicable Statutory Provisions Section 3(a)(1) Intrastate Exemption Based on pro forma financial information for the year ended December 31, 1997, less than 3% of the consolidated utility revenues of the Company, none of its retail natural gas sales, and approximately 6% of its revenues from sales of electricity would be from the Company's utility operations located outside of California. Virtually all (99%) of the systems' net utility plant (based on book value) and utility customers (based on number of customers) would be located in California. Commencing March 31, 1998, all of SDG&E's wholesale electricity output will be bid into the California Power Exchange, pursuant to the restructuring of the California electric markets. All purchasers will take delivery of the electricity within the state. Following the divestiture of SDG&E's generating assets, SDG&E will not be making wholesale sales of electricity; all of SDG&E's retail sales are within the state of California. Item 4. Regulatory Approvals A. State Regulatory Authority The CPUC voted to approve the Transaction on March 26, 1998. In its decision, the CPUC found that the Transaction satisfies the key statutory criteria: that it will benefit the state and local economies and customers, maintain or improve the financial condition of the utilities and quality of management, and be fair to employees and shareholders. The decision also noted that the California Attorney General's November 20, 1998 opinion recommended approval of the Transaction. The decision requires SDG&E to divest by December 31, 1999 its gas-fired generation units - 7 - - -- which it had already decided to do -- and Southern California Gas Company to sell by September 1, 1998 its options to purchase those portions of the Kern River and Mojave Pipeline gas transmission facilities within California. These options are not exercisable until the year 2012. Significantly, in its order, the CPUC found that the remedial measures submitted by Enova and Pacific, together with its ongoing regulation of SoCalGas and SDG&E, the restrictions adopted in its affiliate rulemaking, divestiture of SDG&E's gas-fired generators, and divestiture of SoCalGas's option to purchase the Kern River and Mojave pipeline facilities, would "effectively protect against the exercise of market power by the merged entity." Accordingly, the CPUC approved the Transaction subject to those mitigation measures and specifically undertook to enforce them: This Commission has the authority and shall enforce SoCalGas's compliance with Federal Energy Regulatory Commission Order No. 497 and each of the other remedial measures ordered by this decision. Indeed, to assure further the effectiveness of such enforcement, the CPUC provided that it would retain -- at the merged entity's expense -- an independent accounting or consulting firm with appropriate technical expertise to monitor how the combined utilities (a) operate their gas systems (b) comply with adopted safeguards to ensure open and nondiscriminatory service, and (c) comply with specific restrictions and guidelines. That firm is to have "continuous access to the gas control rooms of applicants, and to all appropriate records, operating information, and data of applicants." It will report to the CPUC as appropriate and shall immediately report any violations of the safeguards imposed or abuse of market power. See CPUC Order at 67a. B. Federal Power Act. On June 25, 1997, FERC approved the Transaction subject to the condition that the CPUC agree to accept and enforce certain measures relating to market power mitigation. As described above, - 8 - in its order approving the Transaction, the CPUC has adopted and undertaken to enforce mitigation measures that fully satisfy the conditions imposed by FERC in the June 25 Order. In its order, FERC also observed that divestiture of SDG&E's gas-fired generation would be another method of eliminating vertical market power concerns. SDG&E's commitment to such divestiture, which is now a requirement of its agreement with DOJ and a condition of the CPUC's approval, thus serves as an independent basis for meeting FERC's concerns. SDG&E has filed the CPUC order with FERC and requested that FERC issue its final order promptly. Inasmuch as FERC's conditions and the underlying concerns have been fully satisfied, the Company expects FERC's final order to be issued shortly. C. Antitrust Pacific and Enova submitted Notification and Report Forms to the Antitrust Division of the DOJ and to the Federal Trade Commission on January 9, 1998, pursuant to the Hart-Scott-Rodino Antitrust Improvements Act. On March 9, 1998, Enova reached an agreement with DOJ, which resolved DOJ's concerns as to the competitive effect of the Transaction. Pursuant to that agreement, Enova and DOJ filed a stipulation and order in the United States District Court for the District of Columbia on March 9, simultaneously with an underlying complaint filed by DOJ. Under the terms of that stipulation, SDG&E is required to divest its two gas-fired generation stations, Encina and South Bay, within 18 months. Bidders for the capacity must be approved by DOJ. Enova's ability to acquire other generating capacity in California in the future is, moreover, severely restricted: subject to certain exceptions, Enova may not hold more than 500 megawatts of existing generation capacity, including the 75 megawatts it - 9 - currently purchases from Portland General Electric Company under a long-term contract. The March 9 filing clears the Transaction for consummation for Hart-Scott-Rodino Act purposes. While the order is not final until it is entered by the District Court, after a 60- day public comment period (which should commence soon upon publication of the settlement in the Federal Register), the Company believes that any chance that the order will not be entered is remote. In any event, Enova and Pacific are now free to consummate the Transaction under the Hart-Scott-Rodino Act and the antitrust laws. D. Atomic Energy Act. On August 29, 1997, the Nuclear Regulatory Commission approved the Transaction, ruling that the creation of the new company will not affect SDG&E's qualifications to hold the license for its 20-percent interest in SONGS. Watchful Deference In the year that this Application has been pending before the Commission, during which all members of the public have had the opportunity to submit comments, the only issue that has been raised as to satisfaction of the requirements of the 1935 Act is whether the Transaction will adversely affect competition. As described above, the effect of the Transaction on competition has also been a central issue in the proceedings before the CPUC and FERC and in discussions with DOJ. All of these agencies have studied this issue extensively and, with the additional protections that they have adopted as conditions, concluded that the Transaction should be permitted to proceed. The Company has repeatedly urged the Commission to apply the doctrine of "watchful deference" with respect to this issue, that is, to defer in a considered manner to the determination of - 10 - the regulators that have already addressed these concerns. In Amendment No. 2 to this application, filed with the Commission on January 28, 1998, the Company set forth at length the relevant circumstances and precedents, all of which overwhelmingly support application of the doctrine in this case. In light of the final approval that has now been granted by the CPUC, some of those circumstances bear repeating in connection with the Commission's evaluation of the CPUC order. First, to approve the transaction, the CPUC was required by Section 854 of the California Public Utilities Code to find, among other things, that the Transaction will not adversely affect competition. The CPUC has not only so found but has gone further. To quote the CPUC's words: "in fact, it will enhance competition." CPUC Order at 144. Second, the proceedings have been comprehensive: they have included over 45 submissions of prepared direct testimony; the applicants have responded to over 3,800 detailed interrogatories and data requests propounded by interested parties and have produced over 100,000 pages of documents; certain intervenors took the oral depositions of eight of the applicants' employees, eliciting 12 days of testimony; evidentiary hearings began on September 17, 1997, and continued, with some recesses, through October 23; the evidentiary record developed during these hearings includes 277 exhibits and 2,232 transcript pages of oral testimony taken over 16 hearing days. Third, the Attorney General for the State of California, who was required by statute to submit an advisory opinion to the CPUC, recommended approval of the Transaction after concluding that the Transaction would not adversely affect competition within either the wholesale electricity or interstate gas markets. This opinion is fully described in Amendment No. 2 to this Application, - 11 - and the full text is included therein as an exhibit. Finally, the CPUC undertook a detailed examination of the Transaction and its effects. The 150-page decision methodically discusses all the issues raised. In support of its conclusion that the Transaction serves the public interest, the CPUC makes 170 specific findings of fact, including that (a) the driving force of the merger of Pacific and Enova is to position the companies to be able to compete in the deregulated national energy market; (b) the proposed merger holds significant strategic benefits for the new company and its shareholders; (c) the merger will be beneficial on an overall basis to state and local economies and to the communities in the area served by SDG&E and SoCalGas; and (d) the merger brings together two experienced management teams with complementary skills and experience and will provide SDG&E and SoCalGas access to additional management skills and resources. Significantly, the CPUC makes a specific finding that the Transaction will preserve the CPUC's own jurisdiction and its own capacity to effectively regulate and audit SDG&E's and SoCalGas' public utility operations. Last, and of course most importantly, the CPUC addresses the competition issue, and the mitigation measures proposed by the Company and finds that "[t]he proposed merger properly mitigated will not adversely affect competition; in fact, it will enhance competition." CPUC Order at 144 (emphasis added). Based on the complete record now before the Commission, the Company believes it is appropriate for the Commission to defer to the conclusions reached by the CPUC, as well as by FERC, DOJ, and the California Attorney General, and to issue its decision as expeditiously as possible so that the Transaction may be consummated by June 1, 1998. - 12 - Item 6. Exhibits and Financial Statements The following exhibits have been filed with the Application or an amendment thereto. EXHIBITS A-1 Articles of Incorporation of the Company (filed as Annex J to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) A-2 Bylaws of the Company (filed as Annex K to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) B-1 Merger Agreement (filed as Annex A to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) and Amendment thereto (filed herewith) B-2 Joint Venture Marketing Agreement (filed as Exhibit 10.5 to the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) B-3 Employment Agreement by and between the Company and Richard D. Farman dated October 12, 1996 (filed as Annex E to the joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) B-4 Employment Agreement by and between the Company and Stephen L. Baum dated October 12, 1996 (filed as Annex F to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997 File No. 333-21229, and incorporated herein by reference) B-5 Employment Agreement by and between the Company and Warren I. Mitchell dated October 12, 1996 (filed as Annex G to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) - 13 - B-6 Employment Agreement by and between the Company and Donald E. Felsinger dated October 12, 1996 (filed as Annex H to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 4, 1997, File No. 333-21229, and incorporated herein by reference) C-1 Registration Statement on Form S-4 (filed on February 5, 1997, File No. 333-21229, and incorporated herein by reference) D-1 Joint Application of Pacific, Enova, the Company, Pacific Sub and Enova Sub to the CPUC, filed October 30, 1996 (filed with Amendment No. 1 to this Application and incorporated herein by reference) D-2 Testimony of T. J. Flaherty, F. H. Ault & D. L. Reed before the CPUC, "Identification of Merger Synergies." (filed with Amendment No. 1 to this Application and incorporated herein by reference) D-3 Joint Petition for a Declaratory Order of Pacific and Enova before FERC filed December 6, 1996 (filed with Amendment No. 1 to this Application and incorporated herein by reference) D-4 Joint Application of Enova and SDG&E before FERC, filed January 27, 1997 (filed with Amendment No. 1 to this Application and incorporated herein by reference) D-5 Testimony of William Hieronymous before FERC, filed October 30, 1996 (filed with Amendment No. 1 to this Application and incorporated herein by reference) D-6 Order of FERC (filed with amendment No. 2 to this Application and incorporated herein by reference) D-7 Letter on behalf of SDG&E to the NRC, submitted December 2, 1996 (filed with Amendment No. 1 to this Application and incorporated herein by reference) D-8 Chart of Testimony before the CPUC (filed with Amendment No. 2 to this Application and incorporated herein by reference) D-9 Opinion of Attorney General on Competitive Effects of Proposed Merger between Pacific Enterprises and Enova Corporation, submitted to the CPUC on November 20, 1997 (filed with Amendment No. 2 to this Application and incorporated herein by reference) - 14 - D-10 Order of the CPUC approving the Transaction, dated March 26, 1998 (filed herewith) D-11 Order of the Nuclear Regulatory Commission approving the Transaction, dated August 29, 1997 (filed herewith) E-1 Map of SoCalGas gas service areas (filed in paper under cover of Form SE) E-2 Map of SDG&E electric and gas service areas (filed in paper under cover of Form SE) E-3 Map showing overlap of Pacific and Enova service territories (filed in paper under cover of Form SE) F-1 Opinions of Counsel (filed herewith) F-2 Past Tense Opinion of Counsel (to be filed by amendment) G-1 Opinion of Merrill Lynch to the Pacific Board dated February 6, 1997 (filed as Annex C to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 4, 1997, File No. 333-21229, and incorporated herein by reference) G-2 Opinion of Barr Devlin to the Pacific Board dated February 6, 1997 (filed as Annex B to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) G-3 Opinion of Morgan Stanley to the Enova Board dated February 6, 1997 (filed as Annex D to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4 on February 5, 1997, File No. 333-21229, and incorporated herein by reference) H-1 Pacific Annual Report on Form 10-K for the year ended December 31, 1997 (filed with the Commission by Pacific on March 26, 1998 and incorporated herein by reference) H-2 Enova Annual Report on Form 10-K for the year ended December 31, 1997 (filed with the Commission by Enova on February 26, 1998, and incorporated herein by reference) H-3 Pacific 1997 Annual Report to Shareholders (furnished to the Commission and incorporated herein by reference) - 15 - H-4 Enova 1997 Annual Report to Shareholders (furnished to the Commission and incorporated herein by reference) I-1 Proposed form of Notice b. Financial Statements FS-1 Company Pro Forma Consolidated Balance Sheet as of December 31, 1997 (filed herewith) FS-2 Company Pro Forma Consolidated Statement of Income for the year ended December 31, 1997 and notes to pro forma combined financial statements (filed herewith) FS-3 Pacific Consolidated Balance Sheets as of December 31, 1997 (filed with the Commission in the Pacific Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated herein by reference) FS-4 Pacific Consolidated Statement of Income for the year ended December 31, 1997 (filed with the Commission in the Pacific Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated herein by reference) FS-5 Enova Consolidated Balance Sheets as of December 31, 1997 (filed with the Commission in the Enova Annual Report on Form 10-K for the year ended December 31, 1997, filed by Enova on February 26, 1998, File No. 0001-11439, and incorporated herein by reference) FS-6 Enova Consolidated Statement of Income for the year ended December 31, 1997 (previously filed with the Commission in the Enova Annual Report on Form 10-K for the year ended December 31, 1997, filed by Enova on February 26, 1998, File No. 0001-11439, and incorporated herein by reference) Item 7. Information as to Environmental Effects On September 12, 1997, the CPUC staff issued a Negative Declaration, concluding that the Transaction will not result in any activities or operational changes that may cause significant adverse effect on the environment. The CPUC's order of April 1, 1998 affirms that ruling. - 16 - SIGNATURE Pursuant to the requirements of the Public Utility Holding Company Act of 1935, the undersigned company has duly caused this Amendment to the Application to be signed on its behalf by the undersigned thereunto duly authorized. SEMPRA ENERGY Date: April 3, 1998 By: /s/ Richard D. Farman _____________________ Richard D. Farman President The procedures for implementing this agreement are described in Item 4.C of this Amendment. Delayed regulatory approval that would postpone consummation of the Transaction beyond June 1, as planned, would result in: (1) further deferral of hundreds of millions of dollars in bill credits to California consumers; (2) continued business and personal uncertainty for those employees of the two companies who will be affected by the Transaction; and (3) deferral of the benefits that will arise from the presence of the merged entity as a more efficient, effective, competitor in the restructured retail and wholesale electricity markets that began operation on March 31, 1998. It is customary for DOJ to file a complaint contemporaneously with a consent decree. This convention reflects the fact that DOJ does not have the statutory authority to impose conditions on a merger. To make the terms of a settlement agreement enforceable, DOJ must initiate a lawsuit under Section 7 of the Clayton Act as well as file the agreement as a proposed final judgment. . The Company estimated before the CPUC that savings to result from the Transaction would be over $1.1 billion during a ten-year period, an amount that some parties to the proceeding asserted was understated. In allocating the savings between shareholders and ratepayers, the CPUC decided to allocate only the first five years' savings and leave any allocation of subsequent savings to future proceedings. - 17 - EX-99 2 EX B-1 AMENDMENT TO MERGER AGREEMENT AMENDMENT NO. 2 To AMENDMENT AND PLAN OF REORGANIZATION This Amendment No. 2 is dated as of August 6, 1997, and amends the Agreement and Plan of Merger and Reorganization dated as of October 12, 1996, as previously amended (the "Merger Agreement"), among the parties named below. The parties named below, which constitute all of the parties to the Merger Agreement, agree that the date September 1, 1998 is substituted for the date April 30, 1998 appearing in Section 8.01(b) of the Merger Agreement. ENOVA CORPORATION By: ____________________________ PACIFIC ENTERPRISES By: ____________________________ MINERAL ENERGY COMPANY By: ____________________________ G MINERAL ENERGY SUB By: ____________________________ B MINERAL ENERGY SUB By: ___________________________ - 1 - EX-99 3 EX D-10 ORDER OF CPUC D.98-03-073, Opinion on Merger of Pacific Enterprises and Enova Corporation Decision 98-03-073 March 26, 1998 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Joint Application of Pacific Enterprises, : Enova Corporation, Mineral Energy Company, : B Mineral Energy Sub and G Mineral Energy : Sub for Approval of a Plan of Merger of : Application Pacific Enterprises and Enova Corporation : 96-10-038 With and Into B Mineral Energy Sub ("Newco : Pacific Sub") and G Mineral Energy Sub : (Filed 10/30/96) ("Newco Enova Sub"), the Wholly Owned : Subsidiaries of A Newly Created Holding : Company, Mineral Energy Company. : (Appearances are listed in Attachment A.) 1 D.98-03-073, Opinion on Merger of Pacific Enterprises and Enova Corporation TABLE OF CONTENTS OPINION.........................................................2 Summary.....................................................2 I. Background..................................................2 A. Applicants and Their Principal Subsidiaries.............3 1. Pacific Enterprises..................................3 2. Enova................................................4 3. Energy Pacific.......................................5 4. AIG Trading Corporation..............................5 B. Intervenors.............................................6 C. The FERC Decision.......................................6 D. The Affiliate Transaction Decision......................9 II. Short- and Long-Term Benefits (Sec. 854(b)(1) and (2)).....12 A. Allocation and Sharing of Merger Savings...............12 1. Length of Sharing Period............................12 2. Allocation of Savings...............................15 B. Merger Savings.........................................18 1. PBR Productivity....................................21 C. Recovery of Costs to Achieve...........................23 1. Amount of Costs to Achieve..........................23 2. Transaction Costs (Investment Banking Fees).........26 3. Employee Retention Costs............................28 4. Communications Costs................................33 D. Ratemaking Treatment of Merger Savings.................35 III. Effect on Competition (Sec. 854(b)(3))....................37 A. Attorney General's Advisory Opinion....................40 B. Market Power...........................................41 1. Horizontal Market Power Effect of Eliminating SDG&E as a Separate Potential Competitor and Customer.....43 2. SoCalGas's Market Power.............................50 3. Vertical Market Power of the Merged Entity..........58 4. Mitigation of Market Power .........................64 a) Applicants' Response to FERC Order No. 497 Conditions.........................64 b) Changes to Wholesale Gas Cost Allocation and Rate Design..................................68 c) Divestiture of SDG&E's Existing Gas-fired Electric Generation Facilities...................69 d) Divestiture of Kern River and Mojave Options to Purchase..............................71 e) Restrictions on Post-Merger Subsidiaries.........79 f) Divestiture of Transmission, Storage, and Distribution.................................79 g) Gas Purchasing...................................83 IV. Is the Merger in the Public Interest (Sec. 854(c))?........83 A. Will the merger maintain or improve the financial condition of the public utilities involved?.............83 i B. Will the merger maintain or improve the quality of service to public utility ratepayers in the state?......84 1. Customer Service and Assistance......................84 2. Energy Efficiency....................................90 C. Will the merger maintain or improve the quality of the utilities' managements?.................................92 D. Will the merger be fair and reasonable to affected public utility employees, including both union and nonunion employees?.....................................94 E. Will the merger be fair and reasonable to the majority of all affected public utility shareholders?............94 F. Will the merger be beneficial to state and local economies and to the communities in the areas served by the public utilities?................................95 1. Charitable Contributions.............................95 2. Staffing in San Diego................................99 G. Will the merger preserve the jurisdiction of the Commission and the capacity of the Commission to effectively regulate and audit public utility operations in the state?...............................101 V. Environmental Review......................................107 VI. Miscellaneous.............................................108 A. Line 6900 and Line 6902................................108 B. The Administrative Law Judge's Rulings.................114 1. Edison's Business Plans Are Discoverable............123 2. The Authority of the Presiding Administrative Law Judge...........................................125 VII. Proposed Decision........................................127 VIII. Findings of Fact........................................128 IX. Conclusions of Law........................................145 ORDER.........................................................145 ATTACHMENT A ATTACHMENT B ii OPINION Summary This decision approves the merger of Pacific Enterprises and Enova Corporation. It finds that savings from the merger are $288 million to be computed over five years and distributed to ratepayers and shareholders, 50/50, over five years. (Because of adjustments ratepayers will receive $175 million.) It finds that to mitigate the effects of San Diego Gas & Electric Company's (SDG&E) loss as a potential competitor and Southern California Gas Company's (SoCalGas) market power, SDG&E should sell its gas-fired generation and SoCalGas should sell its options to acquire the California portions of the Kern River pipeline and the Mojave pipeline. The decision approves various conditions to prevent improper use of information and to prevent cross-subsidies of affiliates by regulated utilities, but it does not require costly utility-to-utility transaction rules. It finds that there are no environmental problems resulting from the merger and it approves the Administrative Law Judge's (ALJ) rulings regarding discovery and sanctions. I. Background Pacific Enterprises, Enova Corporation, Mineral Energy Company (Mineral Energy), B Mineral Energy Sub (Newco Pacific Sub) and G Mineral Energy Sub (Newco Enova Sub) (collectively referred to as applicants) request approval for a plan of merger of their respective companies. SoCalGas is the principal subsidiary of Pacific Enterprises; SDG&E is the principal subsidiary of Enova Corporation. Pursuant to the Agreement and Plan of Merger and Reorganization dated as of October 12, 1996 (Merger Agreement), Mineral Energy (whose name will be changed prior to completion of the merger), a California corporation, has been formed for the purpose of facilitating this merger. The outstanding capital stock of Mineral Energy is owned currently 50% by Enova Corporation and 50% by Pacific Enterprises. Under the 2 plan of merger, two subsidiary companies of Mineral Energy have been created solely for the purpose of facilitating the plan of merger. G Mineral Energy Sub and B Mineral Energy Sub will merge with and into Enova Corporation and Pacific Enterprises, respectively, and as a result Enova Corporation and Pacific Enterprises will become subsidiaries of Mineral Energy, owning all of Enova Corporation's and Pacific Enterprises' outstanding common stock. Each share of each other class of capital stock of Enova Corporation and Pacific Enterprises shall be unaffected and shall remain outstanding. Following this transaction, Newco Pacific Sub and Newco Enova Sub will cease to exist. Mineral Energy will become the parent of Pacific Enterprises and Enova Corporation. Therefore, the corporate structures of Pacific Enterprises, SoCalGas, Enova Corporation, and SDG&E will remain unchanged. Pacific Enterprises and Enova Corporation will be controlled directly by Mineral Energy, and SoCalGas and SDG&E will become second tier subsidiaries of Mineral Energy. The existing common shareholders of Pacific Enterprises and Enova Corporation will be the common shareholders of Mineral Energy. No lines, facilities, franchises, or permits of either SoCalGas or SDG&E will be merged with or transferred to the other utility or any other entity. Both utilities will remain as they are today- regulated in their tariffed utility services by the Commission, having no change in the status of their outstanding securities or debt, having the same assets and liabilities, and both still under the ownership of their respective parent holding companies. A. Applicants and Their Principal Subsidiaries 1. Pacific Enterprises Pacific Enterprises is a public utility holding company. Its principal subsidiary is SoCalGas, which is a public utility engaged primarily in the purchase, storage, distribution, transportation, and sale of natural gas throughout most of southern California and portions of central California. Its service area contains approximately 17 million persons. SoCalGas provides retail natural gas service through approximately 4.7 million independent active meters serving residential, commercial, 3 industrial, and utility electric generating customers. SoCalGas provides both wholesale and retail gas service, and is a "Hinshaw" pipeline, meaning that it owns high-pressure transmission pipelines receiving gas from outside California and is exempt from Federal Energy Regulatory Commission (FERC) jurisdiction under Section 1(c) of the Natural Gas Act (the NGA). SoCalGas's high- pressure transmission system receives gas from local California production and from: Transwestern Pipeline Company (Transwestern) at North Needles, California; El Paso Natural Gas Company (El Paso) at Topock, California and at Blythe, California; Pacific Gas and Electric Company (PG&E) at Kern River Station and at Pisgah, California; and from Kern River Gas Transmission Company (Kern River) and Mojave Pipeline Company (Mojave) systems at Wheeler Ridge and at Hector Road. The SoCalGas transmission system is physically capable of receiving approximately 3.5 Bcf/d of flowing gas supply under ideal conditions. SoCalGas meets peak demand of approximately 5 Bcf/d through a combination of flowing gas supply and withdrawal of gas from storage. Pursuant to its tariffs, SoCalGas provides noncore customers with firm and as available storage capacity. Pacific Enterprises has several other subsidiaries engaged in energy and nonenergy businesses, including Pacific Interstate Transmission Company and Pacific Interstate Offshore Company (PITCO), both of which are interstate pipelines subject to FERC jurisdiction under the NGA, and Pacific Offshore Pipeline Company (POPCO), which FERC has found to be exempt from its jurisdiction under the NGA. 2. Enova Enova is an energy management company providing electricity, natural gas, and value-added products and services to customers throughout California and certain other states. Enova is the parent company of SDG&E and six other subsidiaries-Enova Energy, Enova Financial, Enova International, Enova Technologies, Califia Company, and Pacific Diversified Capital Company. SDG&E, Enova's principal subsidiary, is a public utility that provides regulated electric service to 1.2 million customers in San Diego and southern Orange Counties, and regulated natural gas service to over 700,000 customers in San Diego 4 County. SDG&E's service area encompasses 4,100 square miles, covering two counties and 25 cities. SDG&E has a total generating capacity of 2,433 megawatts (MW). This capacity includes two gas-fired generation stations-Encina (951 MW) and South Bay (690 MW)-as well as SDG&E's 20% (460 MW) share of the San Onofre Nuclear Generation Station (SONGS), which is operated by Southern California Edison (Edison). SDG&E's generation capacity also includes several gas-fired combustion turbines (332 MW) that operate only during peak-load periods. Because SDG&E's peak load of over 3,900 MW far exceeds its own generating capacity, SDG&E is an importer of electricity. The only other subsidiary of Enova engaged in natural gas or electricity is Enova Energy, a power marketer authorized by FERC to sell power at market-based rates. None of Enova's remaining affiliates is engaged in activities subject to the jurisdiction of FERC or this Commission. 3. Energy Pacific Energy Pacific, formed in 1996, is a joint venture in which Enova and Pacific Enterprises each owns a 50% interest. Energy Pacific has registered with the Commission as an energy service provider under Section 394 of the Public Utilities (PU) Code. It offers, among other things, strategic energy planning and integrated energy management, including services related to energy usage evaluation, commodity management, energy efficiency, and efficient plant operation. Energy Pacific also provides billing and payment processing services. Energy Pacific currently has offices in Los Angeles, San Diego, and Pleasanton, California, and Boston. 4. AIG Trading Corporation On August 6, 1997, Pacific Enterprises and Enova agreed to acquire all of the outstanding stock of AIG Trading Corporation (AIG) from AIG Trading Group, Inc. AIG is headquartered in Greenwich, Connecticut and maintains regional offices in Houston, Calgary, and Toronto. AIG's primary business is trading and marketing natural gas, oil, electricity, and other energy-related products at the wholesale level. It trades both physical and financial contracts in those commodities. AIG neither owns 5 nor controls any physical facilities for the production, generation, refining, processing, or transportation of any of the commodities that it trades or sells. Although AIG ships natural gas on numerous pipelines, it does so predominantly under interruptible or monthly firm rights purchased in the secondary market. The acquisition of AIG by Enova and Pacific Enterprises is subject to FERC approval. An application for that approval is pending. B. Intervenors In addition to the Commission's Office of Ratepayer Advocates (ORA), 15 intervenors participated actively in the proceeding and/or filed briefs: Edison; The Utility Reform Network and Utility Consumers Action Network (TURN/UCAN); Southern California Utility Power Pool (SCUPP); Imperial Irrigation District (IID); City of Long Beach (Long Beach); City of Vernon (Vernon); Southern California Public Power Authority (SCPPA); California Cogeneration Council and Watson Cogeneration Company (CCC); City of Los Angeles Department of Water and Power (LADWP); Greenlining Institute and Latino Issues Forum (Greenlining); Natural Resources Defense Council (NRDC); Watson Cogeneration Company (Watson); PG&E; Kern River; and Mojave. Neither ORA nor any intervenor supported the merger without conditions and some intervenors opposed the merger entirely. Public hearing was held before Commissioners Duque and Neeper and Administrative Law Judge Barnett. C. The FERC Decision On January 27,1997, SDG&E and Enova filed an application for approval of the merger at the FERC, in Docket No. EC97-12-000. On June 25, 1997, the FERC issued an order in which it found that the proposed merger "raises vertical market power - ------------------ The members of SCUPP are the Los Angeles Department of Water and Power and the cities of Burbank, Glendale, and Pasadena. The members of SCPPA include all members of SCUPP plus IID and the cities of Anaheim, Azusa, Banning, Colton, Riverside, and Vernon. 6 concerns and the potential for the merged entity to exercise market power that could adversely affect wholesale power markets." 79 FERC ? 61,372 at 62,533 (1997). The FERC summarized the potentially anticompetitive effects of the merger as follows: "Based on the above analysis, we have determined that, without appropriate regulatory safeguards, SDG&E and SoCalGas could impair the marketability of power that is produced by competing gas-fired generators and sold in interstate wholesale power markets. In summary, we have determined that SoCalGas could potentially: "(1) use competitive market information (such as gas usage, service requirements of competing generators, advance knowledge of competitors' projected fuel consumption, patterns, and costs) to manipulate costs and service to SDG&E's advantage; "(2) offer transportation discounts to SDG&E that are not offered or made available to competing generators; "(3) withhold or deny access to pipeline capacity to competing generators; "(4) offer service contracts providing SoCalGas with unilateral and arbitrary control over pipeline access, delivery points, etc.; "(5) manipulate storage injection schedules to effectively withhold pipeline capacity from competing generators at strategic times and thereby drive up wholesale electricity prices; "(6) force competing generators to renominate volumes to other delivery points or purchase additional firm pipeline capacity by citing the existence of difficult to verify operational constraints on SoCalGas's system; and/or "(7) manipulate the terms and conditions of intrastate gas tariffs to SDG&E's advantage by, for example, enforcing the letter of SoCalGas's tariff when dealing with competing generators while enforcing the terms of the tariff less rigorously when dealing with SDG&E. "Such actions could discourage entry and raise competing generators' costs and/or limit their generation output, and, consequently, raise electricity prices in interstate wholesale power markets." 7 Id. at 62,563-564. The FERC determined, however, that "these market power concerns could be mitigated." Id. at 62,553. The FERC set forth several mitigation measures as follows: "First, it will be necessary to ensure that SoCalGas and SDG&E do not inappropriately share market information. We have frequently discussed our concerns regarding the sharing of market information in market-based rate cases, and have routinely imposed related restrictions through the pertinent public utility's code of conduct. (Citations omitted). The same concerns arise here. Therefore, to satisfy our concerns in this regard, SDG&E would need to file a code of conduct, and Enova Energy would need to revise its code of conduct, to comport with the restrictions we require in codes of conduct for market-based rate schedules. "Second, with regard to the commitments offered to the California Commission by the Applicants, we conclude that if the Order No. 497 restrictions were applied to SoCalGas, and if the focus of the restrictions were expanded, this would alleviate several concerns. The Order No. 497 regulations are directed toward abuses between natural gas pipelines and their affiliated marketers. Here, we are concerned not just with the potential for abuse between SoCalGas and affiliated marketers (such as Enova Energy), but also with the potential for abuse between any combination of the energy companies that would be affiliated under the proposed transaction -- particularly abuse between SoCalGas and SDG&E (a non-marketer). Therefore, the Applicants would need to revise their commitment so that the restrictions and requirements would be applicable to the corporate family as a whole, and the California Commission would need to accept and enforce application of the requirements to SoCalGas. "Third, in order to safeguard against discriminatory treatment, SoCalGas's GasSelect EBB [electronic bulletin board] must be an interactive same-time reservation and information system for its gas transportation service, especially with respect to service for gas-fired generation, and the California Commission would need to accept and enforce application of this requirement to SoCalGas. Additionally, SDG&E and Enova Energy must separate the purchases they make from SoCalGas (or any affiliate of SoCalGas) of transportation of gas that is used in electric gas-fired facilities used for wholesale sales; in other words, they must make such purchases separate from other delivered gas purchases (e.g., gas that is resold to retail customers) and they must make such purchases on SoCalGas's GasSelect EBB under the same terms and conditions as SoCalGas's non-affiliated gas-fired generation customers. 8 Also, SoCalGas must publicize in advance on the GasSelect EBB its planned use of pipeline capacity to fill storage." Id. at 62,565. The FERC said that its vertical market power concerns would be eliminated by SDG&E's divestiture of its gas-fired generation plants. (Id. at 62,565, fn. 58.) The FERC concluded that if applicants commit to the remedial measures that the FERC had required and if this Commission accepts the FERC's required remedial mechanisms to the extent to which the mechanisms are in this Commission's jurisdiction, the FERC would approve the merger. The FERC explicitly deferred to this Commission for a determination regarding "the terms by which remedies within [the CPUC's] jurisdiction are to be accomplished." Id. at 62,565. Applicants' and other parties' responses to the FERC order are discussed in Section III, below. D. The Affiliate Transaction Decision In Decision (D.) 97-12-088 in Rulemaking (R.) 97-04-011 and Investigation (I.) 97-04-012, we adopted rules governing the relationship between California's natural gas local distribution companies and electric utilities and certain of their affiliates. The rules cover interactions between utilities and their affiliates marketing energy and energy-related services. Examples of covered activities include utility interactions with an affiliate that (1) markets gas or electric power, or that provides (2) power plant construction and permitting services, (3) energy metering services, (4) energy billing services, (5) energy products manufacturing, or (6) demand-side management services. Our basic standards were: 1. Preference should not be accorded to customers of affiliates, or requests for service from affiliates, relative to nonaffiliated suppliers and their customers. 2. Disclosure of utility and utility customer information should be prohibited, with the exception of customer-specific information where the customer has consented to disclosure. 9 3. The utility's and the affiliate's operations should be separate to prevent cross-subsidization of the marketing affiliate by the utility's customers. The utility and affiliate should maintain separate books of accounts and records. 4. There should be uniformity of rules in a competitive market. 5. Utility affiliates should not be disadvantaged relative to competitors. 6. Rules should be within the power of the Commission to enforce. 7. Rules should not conflict with the FERC's standards, and, when taken together with the FERC's rules, should create seamless regulation. The OIR/OII set forth two objectives: (1) to foster competition and (2) to protect consumer interests. We were concerned with the behavior of Commission-regulated utilities, not the affiliates, to meet those objectives. We noted that it is not clear that the near-term savings that result, for example, from joint utility and affiliate procurement, would actually translate into lower prices for consumers or ratepayers. The assumption that competition would require a single firm to pass along cost savings must assume the corollary that most competing firms obtain comparable cost savings. A firm which has a singular competitive advantage, for whatever reason, may retain extraordinary profits for some period rather than pass them through in the form of lower prices. We wanted to prevent cross-subsidization, so that a utility's customers will not subsidize the affiliate's operation. We reasoned that such leveraging, together with a utility's market power, could inefficiently skew the market to the detriment of other potential entrants. We recognized that customer-specific information can become quite valuable to businesses in a competitive environment, and we wanted to protect the utility's release of customer-specific information, except where the customer has consented in writing to the disclosure. We considered that the utilities' primary competitors will be large corporations that may be subject to few or no affiliate transaction guidelines. Our rules should not hinder a utility in such competition. We included a holding company within the definition of "affiliate" only to the extent the holding company is engaged in the provision of products and services as set out in the rules, but the utility must demonstrate that it is not utilizing the holding 10 company or any of its affiliates not covered by the rules as a conduit to circumvent the rules. In regard to market power, we said that an investor-owned utility's affiliates may be targeting the same customers that the investor-owned utility is currently serving or they might be offering services which the utility does not offer to the utility's customers. The presence of the investor-owned utility in the same service territory as the utility's affiliate raises market power concerns because of their ownership ties and the pre- existing market dominance of the monopoly utility. We previously recognized that the development of competitive markets would be undermined if the utility were able to leverage its market power into the related markets in which their affiliates compete. (See D.97-05-040, pp. 64-67.) We also articulated these concerns in SoCalGas's Performance-based Ratemaking (PBR) Decision, D.97-07- 054, at p. 63: "By the very nature of SoCal's monopoly position in the energy and energy services market, its access to comprehensive customer records, its access to an established billing system, and its `name brand' recognition, it may be that SoCal enjoys significant market power with respect to any new product or service in the energy field." In reference to the Pacific Enterprises/Enova merger application, we said that the affiliate rules include transactions between a Commission-regulated utility and another affiliate utility. However, in the context of reviewing a merger application, the Commission has reserved the right to make specific modifications to the application of the rules, or to apply additional rules as appropriate. The rules specifically state: C. These Rules apply to transactions between a Commission-regulated utility and another affiliated utility, unless specifically modified by the Commission in addressing a separate application to merge or otherwise conduct joint ventures related to regulated services. (Affiliate Transaction Rules, II.C.) The rules apply to all services provided by a utility unless otherwise stated. In this merger application intervenors have made numerous requests to modify the rules to make them more stringent so as to restrict applicants' market power. Applicants 11 request modification of the rules to exempt some utility-to-utility transactions. Those requests are discussed in Section IV.G. Here we emphasize that having just reviewed affiliate rules in a statewide proceeding where all affected parties participated, we are not inclined to carve out exceptions absent clear and convincing evidence. II. Short- and Long-Term Benefits (Section 854(b)(1) and (2)) A. Allocation and Sharing of Merger Savings 1. Length of Sharing Period Applicants have estimated that over the first ten years of the merger there will be approximately $1.1 billion in forecasted net merger savings which should be allocated over a ten-year period on a 50/50 basis between shareholders and ratepayers. The key aspects of applicants' proposal are: 1. Use of a ten-year period to evaluated the long-term benefits of the merger; 2. The net savings are adopted on a forecasted basis and the net savings available for sharing are allocated 50/50 between ratepayers and shareholders. The ratepayer portion of the forecasted savings is guaranteed; 3. The ratepayer portion of merger savings is returned through an annual bill credit; and 4. The merger savings are tracked and amortized in a memorandum account, and are adjusted prospectively for necessary regulatory changes. ORA, TURN/UCAN, and SCUPP recommend a five-year sharing period. They argue that there is little record support for applicants' proposal for a ten-year sharing period other than applicants' assertion that a ten-year sharing period would be "fair" to shareholders. They identify critical considerations for a five- year sharing period. First, limiting sharing to five years with revised rates taking effect January 1, 2003 would end the sharing period as of December 31, 2002. This would coincide exactly with the end of the SoCalGas PBR scheme approved in D.97-07-054. 12 Second, limiting sharing to five years would result in the sharing period ending at about the same time as the end of the electric rate freeze established by Assembly Bill (AB) 1890. Third, a five-year sharing period would permit the regulated utilities, SoCalGas and SDG&E, to earn in excess of their authorized return for five years, which benefits shareholders, but only for five years, which benefits ratepayers. Fourth, limiting sharing to five years recognizes that applicants' primary reason for pursuing the merger is that it will permit applicants to realize substantial benefits and increased earnings in unregulated businesses. Fifth, a five-year sharing period would be consistent with the sharing period found to be appropriate for most other merging utilities in the United States. Applicants take strong exception to the proposed five-year sharing period. They contend it is inequitable to have shareholders finance the costs to achieve, but be denied merger benefits that occur after year five. They say that sharing the savings from regulated businesses is critical to shareholders as the unregulated businesses strive to achieve market share in the new, competitive arenas. An equitable allocation that includes an appropriate level of benefits for shareholders is particularly critical when one considers that shareholders are financing the entire $205 million in costs to achieve this merger. The savings from regulated businesses are near-term and tangible, and shareholders need these near-term cash flows to support investments necessary to achieve the expected growth of the business. As energy markets continue to restructure, competition will escalate and the new company will need to make additional investments to compete aggressively. Customers will, in turn, benefit from these investments through the pressures this competition will impose on the market, leading to reduced prices and an increased availability of new products and services. Only a full ten years of protection will, in their opinion, satisfy the fairness to shareholders requirement of Section 854(c)(5). We cannot agree with applicants. They have presented no persuasive evidence showing that ten years is a reasonable sharing period. All the credible evidence is to the contrary. The primary purpose of this merger is to provide the opportunity to participate more effectively in competitive markets. The entire profits 13 from the unregulated side of applicants to go to shareholders; ratepayers do not receive one dollar of those profits, yet it is the ratepayers who provide the enhanced strength of the merged company. Applicants say that savings from regulated businesses are needed to provide the cash flows to support investments on the unregulated side of the business. But it is axiomatic that ratepayers do not fund nonregulated business. Ratepayers provide a return which shareholders can invest as they wish, but no portion of that return is guaranteed and excess earnings often lead to a reduction in rates. SoCalGas has met or exceeded its authorized return on equity for 14 consecutive years, while SDG&E has exceeded its authorized return on equity for the last seven years and by a substantial margin over the last five years. By definition, any savings after the merger will increase the utilities' rate of return. The statute requires part of those savings be allocated to shareholders, but the amount is left to our discretion. The reasons supporting a five-year allocation period are persuasive. A compelling reason to hold sharing to five years is found in recent activity of this Commission and other Commissions. We have held that the definition of long term may vary with circumstances of each individual case. (Re SCEcorp (1991) [D.91- 05-028] 40 CPUC2d 159, 174.) In both the GTEC/Contel case and the PacTel/SBC case, we adopted relatively short definitions of "long term." (Re GTE Corporation (1994) [D.94-04-083] 54 CPUC2d 268, 284 (a 5-year long term period); D.97-03-067 (Re Pacific Telesis Group) (a 5.6-year long term period). The energy industry is changing rapidly. As applicants explained, "Shortly after a decision is rendered in this proceeding, the independent system operator and power exchange will begin operation and the ability of consumers to choose their energy supplier will be, or will soon become, a reality. In addition, certain utility services will be unbundled. As a result, the pace of competition in the energy business will increase." Similarly, with respect to the gas industry, the Commission has issued a rulemaking that will further restructure and address issues that are fundamental to the gas industry in California. To meet this increased pace of competition with what is essentially a fixed return for ten years will not only keep the merged companies' rates higher than they would otherwise be, but also would allow 14 competitors to have higher rates than might otherwise prevail. This is detrimental to ratepayers. Using a five-year period for the determination of allocable merger savings is also consistent with merger cost savings sharing mechanisms adopted in other jurisdictions. (Re Wisconsin Electric Power Company [Michigan] (1996) 168 PUR4th 168, 171 (four-year rate reduction); Re Washington Water Power Company [Idaho] (1995) 164 PUR4th 270, 276, 282 (five-year rate freeze); Re Baltimore Gas and Electric Company [Maryland] (1997) 176 PUR4th 316, 349 (three- year rate freeze); Re Southwestern Public Service Company, Case No. 2678 [New Mexico] November 15, 1996, slip opinion (five-year savings period); Re Puget Sound Power and Light Company [Washington] (1997) 176 PUR4th 239, 253-254, 257 (five-year rate plan).) Finally, we agree with the TURN/UCAN witness's comments on the problems of a ten-year plan in conjunction with the Sec. 368(a) electric rate freeze and SoCalGas's PBR mechanism which anticipates a cost of service review in 2003: "It will be difficult and artificial to conduct this cost of service review with a merger savings overlay. If the utilities true up forecast merger savings to actual savings, they would have an incentive to change from a narrow view of merger savings now to an expansive view of merger savings later. If the utilities lock in merger savings now, any future cost-of- service review will be artificial. We will have to add non-existent costs back into the utility system to develop a cost-of-service review for stand-alone utility operations and redesign earnings sharing mechanisms. In fact, the Applicants changed their proposal to specifically propose future artificial rate cases on page 36 of their Update testimony." By choosing a five-year savings period, we are not ordering a rate case for either SoCalGas or SDG&E five years from now. We deliberately refrain from binding (or attempting to bind) future Commissions. The economic climate five years hence will determine the need for a rate case. 2. Allocation of Savings Public Utilities Code Section 854(b)(2) provides that, before authorizing the merger, the Commission shall find that the proposal: 15 "Equitably allocates, where the commission has ratemaking authority, the total short-term and long-term forecasted economic benefits, as determined by the commission, of the proposed merger, acquisition, or control, between shareholders and ratepayers. Ratepayers shall receive not less than 50 percent of those benefits." ORA recommends that the forecast merger savings be allocated between ratepayers and shareholders under the following phased schedule: Year 1: 50% to ratepayers, 50% to shareholders Year 2: 60% to ratepayers, 40% to shareholders Year 3: 70% to ratepayers, 30% to shareholders Year 4: 80% to ratepayers, 20% to shareholders Year 5: 90% to ratepayers, 10% to shareholders In the 6th year, the full impacts of the merger should be incorporated into customer rates effective January 1, 2003, for both utilities. ORA states that its proposal will allow shareholders to recover all of the costs, both regulated and unregulated, and to earn a return on equity in excess of the currently authorized return on equity for the initial five years after approval of the merger. ORA argues that applicants' estimate of savings is extremely conservative, so that in all likelihood they will overachieve their forecast savings. In addition, as applicants ultimately control both the realization of merger savings and the costs to achieve the merger, they can effectively mitigate risk on behalf of their shareholders. ORA proposes to adjust SoCalGas's annual PBR revenue requirement by the annual forecast merger savings before determining PBR sharing. In other words, SoCalGas will not have to share any revenues with ratepayers under PBR until and unless it realizes the forecast merger savings on an actual basis, thus reducing shareholder risk of recovering their share of merger savings. Finally, ORA contends that applicants' argument that shareholders require the absolute maximum allocation of merger savings in order to compensate Enova shareholders for an initial post-merger dilution in earnings, and Pacific Enterprises' shareholders for a potential reduction in earnings multiple is unpersuasive, 16 given the enormous expectations of the companies for the enhanced opportunities and benefits that will occur as a result of this merger. For all these reasons, ORA believes its savings allocation proposal fairly compensates shareholders for undertaking this merger. Applicants claim that only a 50/50 sharing is fair. They downplay ORA's principal rationale that shareholders will receive their portion of merger benefits through the unregulated affiliates and, therefore, the larger reallocation of merger savings to ratepayers is justified. Obviously, applicants argue, they have high goals regarding the ability of the new company to compete in the restructured energy industry. At the same time, however, they point out that these unregulated markets are extremely competitive, and that the anticipated benefits from unregulated businesses will be received only after risking the substantial shareholder investments required to enter these new and uncertain markets. TURN supports a 50/50 allocation if a five-year sharing period is adopted. We find that a 50/50 allocation is reasonable. In the GTEC/Contel merger, we allocated half of the benefits to ratepayers, finding that "a 50/50 sharing of the forecasted economic savings is equitable," partly on the basis that other benefits would accrue to ratepayers as competition and incentive regulation evolve. (D.96-04-053, p. 12.) We reasoned (1) shareholders undertake the negative effects of the merger and hence should be allowed to benefit from rewards of their decision as well; (2) shareholders face additional risk as a result of earnings dilution; (3) shareholders will decide in favor of mergers only if on balance the return on their investment is commensurate with the level of risk they are willing to assume; and (4) ratepayers may receive additional benefits through incentive regulation and competition. (D.96-04-053, pp. 8-12.) In the PacTel/SBC decision, we agreed that 50/50 sharing between ratepayers and shareholders is reasonable for the same reasons as in GTEC/Contel: "Here, as there, many qualitative benefits may accrue to ratepayers which we do not or cannot quantify here." (D.96-03-067, p. 38.) The same rationales that governed the 50/50 sharing outcome in GTEC/Contel and PacTel/SBC apply with equal force to this merger. Mergers are 17 risky. Applicants' shareholders are financing the entire costs to achieve as well as absorbing half of the costs to achieve. Earnings dilution is possible for Enova. In addition, shareholders assume the risks associated with entering unregulated markets. The precise outcome of applicants' efforts in unregulated businesses is uncertain. We have not in the past construed forecasted revenues from unregulated businesses as savings resulting from mergers. We have no jurisdiction over those revenues. In the case of gas and electric utilities, we have more control over rates than with telephone utilities. Ratepayers will receive additional benefits through the PBR sharing mechanism where savings exceed forecast. Accordingly, in balancing these critical factors the equitable outcome in this proceeding is to allocate the merger savings evenly between shareholders and ratepayers over a five-year period. B. Merger Savings The following table sets forth the estimated savings and costs proposed by the parties for a five-year sharing period, with our adopted estimates. We will discuss only the major items in dispute. We reject ORA's gross savings estimates as they are based, generally, on averages from other transactions that are not sufficiently similar to this merger's characteristics. TURN/UCAN accepts applicants' gross savings estimate for the five-year period. We adopt applicants' gross savings estimate as it is based on a merger-specific analysis, reduced to account for our use of a lesser inflation factor than used by applicants. While they assumed a base inflation rate of 3.50% and a rate of 4.75% for labor, benefits, advertising, and professional services, our overall factor is 3% based on a more up-to-date analysis of current trends. The only adopted savings difference from applicants' estimate is their PBR productivity adjustment, which we reject. - ----------------------- As we find that a five-year sharing period is reasonable, there is no need to discuss the savings estimated by the parties for the ten-year period proposed by applicants. 18 Estimated Savings and Costs
Applicants ORA TURN/UCAN SCUPP Estimate Estimate Estimate Estimate ADOPTED Category Years 1-5 Years 1-5 Years 1-5 Years 1-5 A. Gross Savings Accounting & Finance 63.9 77.4 63.9 77.4 61.6 Human Resources 31.4 33.3 31.4 33.3 30.1 Information Systems 158.4 165.5 158.4 165.5 52.9 Legal 23.9 29.5 23.9 29.5 23.1 External Relations 14.7 15.1 14.7 15.1 14.0 Corporate Services 52.9 53.9 52.9 53.9 51.3 Support Services 29.4 44.2 29.4 44.2 28.1 Customer Services 43.7 48.2 43.7 48.2 41.6 Marketing 49.8 54.3 49.8 54.3 47.8 Transmission & Distribution 38.8 60.4 38.8 60.4 37.0 Gas Supply & Operations 13.6 13.6 13.6 13.6 13.1 Executive Management 38.3 38.3 38.3 38.3 36.4 Initial Proposed Savings 558.5 633.7 558.5 633.7 537.0 B. Withdrawn Savings: Gas Procurement (11.6) - (11.6) (11.6) (11.6) Customer Services Disconnect (3.4) - ( 3.4) ( 3.4) ( 3.4) C. PBR Adjustments Pension & Benefits (11.4) - (11.4) - (11.4) Reg Affairs Consultant (0.7) - - - (0.7) Non-labor Inflation (1.2) - (1.2) - (1.2) Inflation Adjustment (14.5) - - - (14.5) Multifactor Alloc Formula (0.7) - (0.7) - (0.7) Lobbying Expense (1.5) - (0.2) - (1.5) Legal (1.3) - - - (1.3) Non-DSM ERC Marketing (0.9) - - - (0.9) Facilities (5.6) - (5.6) - (5.6) PBR Productivity (110.7) Adjustment D. Other Adjustments 100% Shareholder Savings: Unregulated Savings (15.0) (15.0) (15.0) (15.0) (15.0) Long-term Incentive Plan Savings (2.6) (2.6) (2.6) (2.6) (2.6) Savings Subject to Balancing Accounts (100% Ratepayer): DSM, CARE, LEV (24.2) (24.2) (24.2) (24.2) (24.2) Gas Supply - (3.8) - - - RD&D (6.8) (6.8) (6.8) (6.8) (6.8) Interaction Impacts: 0.2 - 0.2 0.2 0.2 Total Reduction in Savings (101.2) (52.4) (82.5) (63.4) (101.2) Resulting Merger Savings: 457.3 581.3 476.0 570.3 435.8 19 E. Costs to Achieve Systems Consolidation 56.8 56.8 56.8 56.8 56.8 Employee Separation Programs 48.0 48.0 48.0 48.0 48.0 Transaction Costs 38.0 19.0 5.0 9.0 9.0 Employee Retention Programs 20.0 10.0 - 9.3 - Employee Relocation Programs 13.5 13.5 13.5 13.5 13.5 Telecommunications 8.0 8.0 8.0 8.0 8.0 Employee Retraining 7.0 7.0 7.0 7.0 7.0 Internal/External Communications 5.3 2.7 0.3 - 0.3 Transition Costs 4.0 2.0 4.0 4.0 4.0 Facilities Integration 3.3 3.3 3.3 3.3 3.3 D&O Liability Tail Coverage 0.5 - - - 0.5 Equipment Disposal 0.2 0.2 0.2 0.2 0.2 Inventory Relocation/Disposal 0.1 0.1 0.1 0.1 0.1 Initial Costs to Achieve: 204.7 170.6 146.2 159.2 150.7 F. Adjustments to Costs to Achieve: Contract Services (0.1) (0.1) (0.1) (0.1) (0.1) Inflation adjustment (2.5) - - - (2.5) Multifactor Formula/ERC Adj. - - (0.3) - Resulting Costs to Achieve: 202.1 170.5 145.8 159.1 148.1 Net Util. Sharable Savings 255.2 410.9 330.2 411.2 287.7 G. Ratepayer Allocation of Savings Year 1-5 127.6 205.4 165.1 205.6 143.9 100% ratepayer portion of savings 31.0 34.8 31.0 31.0 31.0 Total Ratepayer: 158.6 240.2 196.1 236.6 174.9 Savings Returned Thru PBR: 110.7 - - - Ratepayer Savings for Bill Credit: 47.9 240.2 196.1 236.6 174.9 H. Shareholder Allocation of Savings: Year 1-5 127.6 205.4 165.1 205.6 143.9 100% shareholder portion of savings 17.6 17.6 17.6 17.6 17.6 Total Shareholder 145.2 223.0 182.7 223.2 161.5
The merger savings calculation with a 3% inflation factor PBR Productivity Adjustment is shown here for the sake of completeness but is not included in the total. See the Ratepayer Allocation of Savings section. 20 1. PBR Productivity In D.97-07-054, we adopted performance-based ratemaking for the portion of SoCalGas's rates that recovers the costs of providing gas utility service that had been considered in a general rate case. In that decision we adopted a productivity factor (used to revise rates annually) which measured historical industry productivity, plus a target based upon potential productivity that the utility can expect to achieve over the historical average. We adopted a productivity factor which increased from 1.1% to 1.5% over five years. Applicants contend that the Commission in the PBR decision adopted a productivity factor that included potential merger savings. In their opinion the PBR productivity factor of 1.1% to 1.5% included 0.5% which reflected merger savings. Applicants argue that the method of calculating merger savings in this proceeding is unaffected by the inclusion in the PBR proceeding of a productivity index with a 0.5% potential merger savings component. Rather, inclusion by the Commission of the merger-related component of 0.5% is simply an expression by the Commission of its prerogative to return a portion of the merger savings to customers earlier through the PBR productivity factor in the form of rate reductions, the very same savings that would otherwise be included in this proceeding for ultimate disbursement to ratepayers. Applicants say that a given item should be reflected as merger savings if the item is now included in rates but will not be required following the merger. However, to the extent activities are no longer funded in rates as a result of the PBR decision, the savings associated with those activities should be eliminated from the calculation of merger savings. As a result of the PBR decision, applicants propose a reduction of $148.5 million in merger savings allocated to ratepayers. This reduction comprises $110.7 million which applicants claim will be returned to ratepayers through the PBR productivity factor and $37.8 million in PBR adjustments to specific items. This proposal would reduce the merger savings allocated to ratepayers in the first five years, using applicants' numbers, from $196.4 million to $47.9 million. 21 ORA and TURN/UCAN argue that the explanation of the PBR productivity factor provided by applicants is not supported by the PBR decision and it violates Sec. 854(b)(2). The PBR decision does not state that merger savings are being returned to ratepayers through the productivity factor. The decision states that "the subject of merger savings is not a part of our consideration here. ..." (D.97-07-054, p. 28.) They say that applicants' argument that the Commission, having said it was not considering savings, then passed savings through to ratepayers via the productivity factor makes little sense. The Commission knew that the merger was pending and that the sharing of savings between ratepayers and shareholders would be an issue in this proceeding. If the Commission had intended to address the sharing of those savings through the PBR mechanism, the Commission would have said so. We agree with ORA and TURN/UCAN that applicants' proposed productivity factor adjustment would violate the not less than 50% benefit to ratepayer requirement of PU Code Sec. 854(b)(2). Applicants calculated $110.7 million associated with a 0.5% portion of the productivity factor adopted for SoCalGas's PBR (over a five-year period). They proceed to reduce the forecast merger savings allocated to SoCalGas's ratepayers by this $110.7 million. Because D.97-07-054 did not consider merger savings when determining the productivity factor, applicants' merger proposal would no longer comply with PU Code Sec. 854(b)(2); ratepayers would receive less than 50% of the forecast merger savings. The logic that links SoCalGas's PBR productivity with Pacific Enterprises/Enova merger savings is tenuous. There is strong opposition to the merger; it might have been rejected. Therefore, it would have been manifestly unfair to impute productivity to SoCalGas from a merger that might not take place. For applicants to argue that their merger proposal allocates not less than 50% of the benefits to ratepayers because the Commission issued a decision almost one year ago in a rate case involving only the subsidiary of one of the applicants makes a mockery of Section 854. We agree with applicants that to the extent activities are no longer funded in rates as a result of the PBR decision, the savings associated with those activities should be eliminated from the calculation of merger savings. 22 C. Recovery of Costs to Achieve 1. Amount of Costs to Achieve Costs to achieve of approximately $202 million reflect expenditures applicants believe necessary to effectuate the transaction and to realize cost savings. These costs include, among other items, employee separation programs, employee relocation, systems development and integration, telecommunications, internal/external communications, employee retraining, facilities consolidation, and transition costs. Financial transaction costs, which include investment banking and legal fees, are also included. Allowable costs to achieve should be subtracted from the savings calculation to determine the net savings available to be shared. Applicants request that the costs to achieve be deducted from gross savings, with the net savings allocated 50% to ratepayers. Applicants' estimated breakdown is: - - systems consolidation $ 56.8 million - - employee separation programs 48.0 million - - transaction costs 38.0 million - - employee retention costs 20.0 million - - employee relocation programs 13.5 million - - telecommunications 8.0 million - - employee retraining 7.0 million - - internal/external communications 5.3 million - - transaction costs 4.0 million - - facilities integration 3.3 million - - Directors and Officers liability coverage 0.5 million - - equipment disposal 0.2 million - - inventory relocation/disposal 0.1 million Total $204.7 million - - inflation and service adjustment (2.6) million Net $202.1 million 23 When analyzing costs to achieve, it is important to recognize that this merger is not being undertaken for the benefit of ratepayers. It is being undertaken for the benefit of shareholders. Any savings in regulated activities received by ratepayers are incidental. SDG&E and SoCalGas will continue their separate corporate existences under their existing names. Both utilities will remain as they are today-regulated in their tariffed utility services by the Commission-with no change in the status of their outstanding securities or debt, and with both still under the ownership of their respective parent holding companies, and headquartered as they are today. The merger brings together two major southern California energy players at the very time that the California electricity market is being deregulated and, thus, offers profit opportunities in unregulated energy markets. Independently, each company faces competition and earnings pressure in core regulated businesses, contrasted with rising investor expectations for earnings growth in unregulated businesses. And each company sees unregulated energy services (particularly electricity marketing) as a way to increase earnings. But each feels that it lacks critical skills and physical assets. As SDG&E's president testified: This increased financial strength and operational capability will enable the merged organization to encounter and manage significantly more risk in the diversity and scale of competitive services and products it brings to the California and national energy markets. The ability of the new organization to compete in emerging energy business opportunities is most important because other out-of-state competitors have already made significant advances in that regard. Companies such as UtiliCorp, PacifiCorp (both of which have already consummated mergers, thereby increasing their scale), New England Electric System, and Louisville Gas & Electric have announced their intentions to enter the newly competitive energy retail markets on a national scale. The merger and the applicants' consolidation of their unregulated activities into new joint ventures are the proposed solutions to their search for increased earnings. Energy Pacific and AIG will be the primary vehicles by which applicants will seek unregulated business opportunities to meet investors' profit expectations. This 24 merger is the alliance of two entities with strong and complementary interests in developing unregulated activities where each can help the other. SDG&E brings to this merger billions of dollars of cash from electric restructuring from competitive transition charges-CTC-and rate reduction bonds. A significant portion of this money will be paid by SDG&E to Enova as dividends to maintain SDG&E's capital structure. This cash can be invested in unregulated activities. Pacific Enterprises brings a relationship with over 4.5 million customers in southern California who constitute a prime market for energy and other services that could be delivered by a diversified company. Applying Enova's electric expertise to SoCalGas's customer base means that the merged company could deliver one-stop gas and electric service throughout southern California. The merger can therefore largely be justified in terms of the ability of the merged company to conduct more extensive and comprehensive unregulated activities than the two individual unmerged companies. Applicants assert that the merger will save approximately $457.3 million over five years. They propose to reduce that amount by the $202 million it is expected to cost to achieve the merger, and divide the remainder with half going to shareholders and half going to ratepayers. In this section of the opinion, we deal with the $202 million costs to achieve that $457.3 million savings. Applicants' expert witness compared the costs to achieve this merger with 12 other energy utility mergers and proposed mergers and concluded that applicants' costs are reasonable. TURN, SCUPP, and ORA challenged the estimates. Their recommended allowance of major categories of costs to achieve are: (Millions) Applicants TURN SCUPP ORA ADOPTED Transaction Costs 38.0 5.0 9.0 19.0 5.0 Employee Retention Costs 20.0 0.0 9.3 10.0 0.0 Internal/External Comm. 5.0 0.3 --- 2.7 0.3 25 Based on their estimate of allowable costs, their recommended costs to achieve are: TURN about $146 million; SCUPP about $159 million; and ORA about $171 million. (See Table, p. 20.) The total costs to achieve is an estimate as many costs will not be incurred until the merger is completed and savings are phased in over at least three years. Some costs may not be incurred at all. 2. Transaction Costs (Investment Banking Fees) Pacific Enterprises employed Barr Devlin and Merrill Lynch as its investment bankers at a cost of $16 million plus another $1.6 million in expenses, while Enova hired Morgan Stanley at a cost of $10.5 million plus another $1 million in expenses. The investment bankers were paid on a flat fee basis without regard for hours worked, quality of work, innovation, or insulation of Pacific Enterprises or Enova from risk. In preparing their fairness opinions, the investment bankers relied upon information that was provided to them by Pacific Enterprises and Enova without conducting any audits or otherwise verifying the information. The investment bankers were fully indemnified against liabilities, including those arising under the Federal Securities Act relating to their engagement by applicants. Thus, the investment bankers were not at risk for their opinions about the fairness of the merger. TURN/UCAN argue that the investment bankers' opinions amount to nothing more than enormously expensive financial analyses, not too dissimilar to the sort of analyses that are conducted in a cost of capital case. By contrast, HGP, a nationally recognized consulting firm, rendered a highly complex opinion regarding the soundness of Enova's nuclear and other generating facilities as well as its transmission and distribution system for only $275,000. Furthermore, Enova's own witnesses agreed that the fairness opinions were for the benefit of the Pacific Enterprises and Enova Boards of Directors and shareholders with only derivative benefits, if any, for ratepayers. Since the cost of the investment bankers' opinions was excessive, and since the opinions were for the benefit of the Boards of Directors and 26 shareholders, not ratepayers, the $29 million in investment banking fees should be excluded from the costs to achieve. When ORA's witness used the Merrill Lynch analysis to support his position that ratepayers should be allocated more savings, applicants' own witness deprecated the Merrill Lynch work as follows: "Merrill Lynch's analysis relied upon internal forecasts prepared by Pacific Enterprises and Enova. These forecasts included significant productivity gains throughout both companies as well as aggressive forecasts of revenue growth in the non-regulated businesses. In using these forecasts, it is important to recognize the role of SoCalGas's financial plan as a goal setting and motivational tool, which is linked to the incentive compensation system. As a result, the projections in the plan are more akin to `stretch' targets than purely objective forecasts of future financial results. In general, the forecasts used by Merrill Lynch are not the type a credit rating agency would rely on in determining credit ratings. A credit rating agency would exercise additional prudence through the use of more conservative forecasts." Applicants argue that ORA's use of investment banker analysis is clouded by the fact that the Merrill Lynch analysis regarding expected financial ratios assumed an aggressive approach to productivity and in turn an aggressive forecast of revenue growth in the nonregulated businesses. They hold that a financial plan of this nature is not the same as a conservative forecast projecting less optimistic conclusions about future productivity and upon which a credit rating agency would typically and prudently rely in determining credit ratings. We certainly agree that an aggressive approach to forecasting will lead to substantially different results than a conservative approach. But when the analysis is done for nonregulated businesses, we see no reason to charge any costs of the analysis to ratepayers. Applicants' testimony makes clear that increased opportunities to pursue unregulated ventures are the prime motivation of this merger. Those ventures, if successful, will financially benefit shareholders, not ratepayers. The transaction costs 27 should therefore be assigned to shareholders. We note that in the PacTel/SBC merger this kind of cost was not requested for ratepayer recovery. Applicants' position is untenable. If ORA should not rely on the financial projections, we see no reason for this Commission to rely on the information nor the ratepayers to pay for it. We cannot approve $29 million for the costs of advice given on such tendentious data. Rather than demonstrating the value to ratepayers of the financial services claimed as costs to achieve, applicants have cast serious doubt about whether the financial advisors were given reliable information. Any advice they received based on unreliable data is suspect, and millions of dollars spent on obtaining suspect advice is highly questionable. Accepting applicants' own view expressed in their testimony regarding the unreliability of the information given their financial advisors, we, like the credit agency referred to in applicants' testimony, will "exercise additional prudence through the use of more conservative forecasts" and deny the banking fees as part of costs to achieve. Consultant fees of $4 million are included in transaction costs. Applicants maintain that these costs are necessary to complete the merger. The dollars in this category were spent on specialists to devise a merger strategy, identify savings, and estimate separation costs more accurately. We understand that part of these costs were incurred in presenting this application. As there are substantial savings to ratepayers because of the merger, we will allow the fees. The difference between our treatment of consultant fees and investment banking fees is that the consultants primarily identified savings from the merger which benefit ratepayers; the bankers provided analysis to persuade directors and shareholders that the merger would be profitable in the nonregulated arena. 3. Employee Retention Costs Applicants forecast expenditures of $20 million for the costs (bonuses) of retaining corporate officers and other highly paid executives of the two companies during the pendency of the merger. ORA, TURN/UCAN, and SCUPP oppose this 28 expenditure. SCUPP would eliminate $10.7 million; ORA and TURN/UCAN would eliminate the entire $20 million. Applicants argue that one of the many significant challenges faced during the long pendency of the merger is the retention of key employees. Applicants say the executive retention incentives are largely focused on retaining officers who are principally engaged in supporting the regulated utilities within their current assignments. These executives are responsible for continuing to ensure safe, reliable, and cost-effective service to customers during the pendency of the merger, as well as for ensuring that the merger creates cost savings for utility customers. With no job guarantee after the merger, executives may be inclined to seek outside employment or will, at a minimum, be more receptive to inquiries when approached by prospective employers or search firms. If experienced executives leave, it is extremely difficult and more costly to replace them with a merger pending. Costs incurred by corporations to hire executives, particularly under less than ideal circumstances such as a pending merger, typically include significant search agency fees, high relocation costs, large sign- on bonuses, and other costs. In sum, the costs associated with hiring a replacement executive may far exceed the retention costs of an existing executive. The assertion that executive retention costs should be excluded because they were not included as costs to achieve in other utility mergers should be rejected, in applicants' opinion, because other utility mergers have included executive severance costs, which can far exceed executive retention costs. Applicants did not include severance costs in their costs to achieve. TURN/UCAN argue that applicants' retention cost is not supported by precedent from this Commission or by mergers in other jurisdictions, and applicants have presented no good reason for reducing merger savings to further compensate the companies' most highly paid employees. Applicants have presented no evidence that including such bonuses as a cost to achieve has been found appropriate by any regulatory agency. Such bonuses were not identified as costs in the recent PacTel/SBC merger before this Commission or in the proposed Edison-SDG&E merger. Applicants' 29 own expert confirmed that such costs were not identified in any of the 12 mergers that he referenced in his testimony. TURN/UCAN assert that applicants have not presented any sound policy reasons why such costs should be included. If the merger improves the competitive positioning of the new company, as applicants assert it will, then top executives will want to stay with the company to share in that future. The claim that these bonuses are necessary to keep high level employees with the companies is not consistent with the exciting future applicants envision for the new company. Moreover, from the perspective of ratepayers, it is not clear that corporate performance as it impacts utility service would be greatly affected by the identity of the top officers at Pacific Enterprises or Enova over the period of time covered by the bonuses. Finally, in the case of SoCalGas, the Commission just found in D.97-07-054 (pp. 67-68) that the company's executives were excessively compensated. It would be unreasonable to include the costs of additional executive compensation as a legitimate cost of the merger, especially when hundreds of employee positions are being reduced to achieve merger savings. ORA argues that there are no direct regulatory merger benefits generated by these corporate employee bonus agreements, no evidence that Pacific Enterprises and Enova were at particular risk for the loss of these employees, and no evidence that the termination of these employment would reduce the forecast merger savings. Furthermore, these officers are already compensated for their services in SoCalGas's and SDG&E's rates. SCUPP points out that both Pacific Enterprises and Enova have long- term incentive compensation plans for executives and officers which are intended to give the executives an incentive to remain with the company. The same executives who participate in the long-term incentive program benefit from the retention bonuses. SCUPP would deny the executive portion of the retention costs to achieve, $10.7 million. Applicants assert that it is inappropriate to draw comparisons with other mergers without considering the specific circumstances associated with each of those mergers, such as the number of executive positions to be eliminated in each case, the 30 extent to which executives in those instances were offered severance packages, the number of executives who left prior to completion of the merger, and the extent to which the importance of retaining key employees was overlooked, causing those companies to suffer negative consequences. We find no evidence that but for the retention bonuses, any executives would have left because of the merger. The fact that the number of executives after the merger will be fewer than before can be the result of normal attrition, retirement, etc. The joint proxy statement of Pacific Enterprises and Enova of February 6, 1997, is pertinent. New employment agreements were made with the top four officers of the merged company, severance agreements were made with Pacific Enterprises executives, and incentive/retention bonus agreements were made with both Pacific Enterprises and Enova executives. The language is instructive. "As of December 31, 1996, Pacific Enterprises and its subsidiaries had entered into severance agreements with 24 individuals. If all covered individuals were to be terminated as of January 1, 1998 under circumstances giving rise to an entitlement to severance benefits, the aggregate value of the lump sum cash severance benefits so payable would be approximately $9 million. The approximate amounts payable to executive officers of Pacific Enterprises under such circumstances are as follows: Richard D. Farman, $930,000; Warren I. Mitchell, $670,000; Larry J. Dagley, $650,000; Frederick E. John, $550,000; Leslie E. LoBaugh, Jr., $530,000; Debra L. Reed, $500,000; Lee M. Stewart, $480,000; Eric B. Nelson, $440,000; Ralph Todaro, $280,000; and Dennis V. Arriola, $230,000. The agreements entered into with Messrs. Farman and Mitchell will be superseded by their respective employment agreements upon the completion of the business combination. "Incentive/Retention Bonus Agreements. The Board of Directors of Pacific Enterprises has authorized incentive/retention bonus agreements with 23 executives, officers and key employees and the Boards of Directors of Enova and SDG&E have authorized incentive/retention bonus agreements with 10 selected executives and officers. The purpose of the agreements is to (i) compensate covered individuals for the performance of services related to the business combination, in addition to their ongoing duties, and (ii) provide an incentive for these individuals to continue their employment with the New Holding Company." * * * 31 "The incentive/retention bonus agreements of Pacific Enterprises and its subsidiaries provide for maximum aggregate incentive/retention bonus payments of approximately $6 million, assuming the business combination is completed on January 1, 1998. The approximate amounts payable to executive officers of Pacific Enterprises (excluding any increase or decrease attributable to the deferral of such amounts) are as follows: Richard D. Farman, $1,220,000; Warren I. Mitchell, $620,000; Larry J. Dagley, $910,000; Frederick E. John, $290,000; Leslie E. LoBaugh, Jr., $280,000; Debra L. Reed, $260,000; Lee M. Stewart, $250,000; Eric B. Nelson, $230,000; Ralph Todaro, $200,000; and Dennis V. Arriola, $160,000. "The incentive/retention bonus agreements of Enova and its subsidiaries provide for maximum aggregate incentive/retention bonus payments of approximately $4.7 million, assuming the business combination is completed on January 1, 1998. The approximate amounts payable to executive officers of Enova (excluding any increase or decrease attributable to the deferral of such amounts) are as follows: Thomas A. Page, $880,000; Stephen L. Baum, $1,032,000; Donald E. Felsinger, $704,000; David R. Kuzma, $692,000; Edwin A. Guiles, $316,000; and Gary D. Cotton, $223,000. "In addition, the Chairman of the Board of Pacific Enterprises and the Chief Executive Officer of Enova have each been granted the authority to provide incentive/retention bonus agreements to other non-officer employees. The maximum aggregate bonus amounts payable under such agreements is $5 million for each company." The record is not clear whether Enova has a similar severance package as Pacific Enterprises, but the record is clear that the executives of both companies are well protected; that Pacific Enterprises executives have employment contracts, severance agreements, and retention bonuses. Ratepayers should not pay for lavishness in the guise of retention bonuses. We agree with those opposed to including retention bonuses in costs to achieve. We will disallow the entire $20 million. No merger approved by this Commission, or any other Commission to our knowledge, has allowed such costs. The executives covered by the retention plan have numerous reasons to stay: high salaries, stock options, bonus incentives, and substantial severance pay. To add a new category of retention bonuses, 50% to be paid by ratepayers, is gilding the lily. 32 4. Communications Costs Applicants have estimated $5.3 million in costs to achieve for internal and external communications. Included in this amount are costs associated with a new corporate name and logo ($1,275,000), advertising related to the merger ($1,525,000), and a public affairs campaign prior to the merger ($2,000,000). Several parties objected to applicants' proposal. TURN/UCAN propose that only $320,000 be included as a cost to achieve, arguing that the costs of a new corporate name and logo, the costs of advertising, and the costs of a public affairs campaign should be assigned to shareholders, and that other mergers have not included such costs. SCUPP proposes that the $5.3 million be excluded in its entirely from the costs to achieve because the companies will be maintaining their existing identities. And, ORA proposes that 50% of the $5.3 million be allocated directly to the unregulated portion of the combined company, arguing that the primary purpose of the merger is to develop unregulated revenues, that these proposed expenditures support such an objective, and that it is uncertain how the proposed expenditure level will help capture the benefits of the merger. Applicants argue that TURN/UCAN, ORA, and SCUPP have mischaracterized necessary communications concerning the merger as "advertising and marketing costs." Applicants claim the costs in question are not intended to market any product or service, but instead are necessary to successfully communicate a number of significant messages regarding the merger to customers and to the community at large. Applicants' witness explained that the communications effort is specifically targeted towards education and not marketing. These expenses are targeted to educate customers about the merger and its potential impacts on them. Applicants contend that by educating customers before the merger takes place, it is likely that future costs can be avoided and negative impacts on service reduced, thus providing obvious benefits to customers. For instance, if customers are uninformed and therefore concerned or confused about the merger, they are more likely to telephone the respective customer service centers unnecessarily. If call volumes increase, operational expenses and the time it takes to respond to customer calls will also increase. As a result, because 33 applicants' merger-related communications benefit the customer by reducing call center activity, the associated costs represent valid and reasonable costs to achieve. Applicants justify the inclusion in costs to achieve of the expenses associated with a new corporate name and identity, as being the result of a merger expected to deliver millions of dollars in savings to utility customers. The expenses related to a new corporate name and identity are important for SDG&E and SoCalGas to raise operating capital in financial markets at reasonable rates, a critical step in the consummation of the merger, plus the need to communicate the new name of the merged company to customers, as well as the need to maintain the continued separate existence of both SDG&E and SoCalGas. Applicants assert that the Commission has recently been much more receptive to the importance of educating ratepayers about impending changes in the energy and telecommunications marketplaces, particularly on the eve of implementing significant changes for customers regarding their electric service. They refer to our recently established Customer Education Program related to electric restructuring, endowing the fund with an initial investment of $89 million. They conclude that including communications costs as part of costs to achieve is justified based on past precedent and current utility industry practices endorsed by the Commission. TURN/UCAN point out that the requested communications costs exceed those in all of the 12 merger cases cited by applicants in both absolute dollars and as a percentage of savings. TURN/UCAN believe applicants present no compelling reason to depart from established policy regarding the costs associated with a new corporate name and logo. Such costs have typically been borne by shareholders. For example, costs resulting from the initial creation of SCECorp as a holding company for Edison were not included in rates, nor have similar costs for Edison International been included in rates. The costs of developing new logos, repainting vehicles, and similar expenses were not included in rates for PG&E when it changed its logo in the early 1990s. TURN/UCAN argue that applicants have not demonstrated that the development of a new corporate name and logo is necessary to the merger. It is management's decision not to retain the name of one of the existing companies (Pacific 34 Enterprises or Enova) as the name of the new company. Ratepayers should not pay for that decision. Neither utility will change its current name, therefore the merger name has no relevance to consumers of regulated utility services. Applicants' arguments in support of advertising and public relations costs are no more compelling, in TURN/UCAN's opinion. They note that ratepayers do not now pay for lobbying or campaigns to influence public opinion, which are chargeable below the line for electric utilities. A merger does not create an exception to this rule. Applicants' claim that these costs are not primarily intended to influence public opinion lacks credibility. Applicants' own workpapers refer to these as "advertising" costs and direct their campaign to "opinion leaders, elected officials, and community leaders." Our long-established policy has been to disallow costs for energy utility corporate advertising other than advertising related to safety, conservation, and certain financial issues. In particular, advertising aimed at establishing or building a corporate image has faced the most severe restrictions. This is precisely the intent of the bulk of the advertising included in costs to achieve. Inclusion of the costs associated with a new corporate name, advertising related to the merger, and a public affairs campaign in costs to achieve to be paid in part by ratepayers, is inconsistent with Commission policy. (Re So.Cal.Edison (1976) 81 CPUC 49, 79; Re PG&E (1975) 78 CPUC 638, 691-696.) We will include in costs to achieve the TURN/UCAN recommendation of $320,000. This includes the following costs as identified by the applicants: $40,000 for employee packets, $30,000 for media news releases and print material, and $250,000 for bill inserts to inform customers that their service will not be changing as a result of the merger. D. Ratemaking Treatment of Merger Savings We will order that the total net savings allocated to ratepayers ($174.9 million) be refunded to ratepayers through an annual bill credit over five years commencing September 1, 1998. SoCalGas will refund approximately $117.9 million (67.4%); SDG&E will refund approximately $57.0 million (32.6%). The percentage split is based on applicants' recommendation in Exhibit 4. 35 SoCalGas will allocate annual merger savings among customer classes using current long-run marginal costs. SoCalGas will file an advice letter no later than July 1 of each year following merger approval to reflect the fixed annual net cost savings identified and adopted in this merger to be credited on customer bills in September following. If the bill credit exceeds the amount of a customer's September bill, the credit balance will be carried over and applied against the customer's October bill, and will continue to be credited to subsequent bills until the credit is exhausted. For SDG&E, it is necessary to allocate savings between the gas and electric departments, and also among each major customer class within the respective gas and electric departments. To allocate the net utility merger savings between SDG&E's gas and electric departments, SDG&E will use the ratio of the number of gas and electric customers for each department. SDG&E will use current long-run marginal costs to allocate net utility merger savings among gas (62%) and electric (38%) customer classes. For gas service, this method is based on the factors adopted in SDG&E's 1996 Biennial Cost Allocation Proceeding (BCAP). For electric service, this method is based on the factors adopted in SDG&E's Rate and Product Unbundling Application (A.) 96-12-011, filed December 6, 1996, in the Commission's electric restructuring proceeding. Those factors are based on the combination of customer and distribution long-run marginal costs. SDG&E will provide an annual bill credit to each of its customers to flow back the annual forecasted net utility cost savings allocated to customers. SDG&E will file an advice letter annually on July 1 of each year to reflect the fixed annual net cost savings identified and adopted in this merger proceeding to be reflected on customer bills in September following. If the bill credit exceeds the amount of a customer's September bill, the credit balance will be carried over and applied against the customer's October bill, and will continue to be credited to subsequent bills until the credit is exhausted. SoCalGas and SDG&E may implement such memorandum accounts as they deem necessary to effectuate the proper accounting for the ratepayer credits and shareholder allocation. The memorandum accounts shall be submitted by advice letter for the Energy Division's approval. 36 We emphasize, regardless of whether the forecast savings are actually achieved, applicants shall refund $174.9 million to ratepayers over five years. The savings that applicants would credit to balancing accounts shall, instead, be refunded directly to ratepayers as part of the bill credit. III. Effect on Competition (Section 854(b)(3)) Section 854(b)(3) provides that a merger of public utilities may be approved if we find that the proposal does not adversely affect competition. In making this finding, we are to be guided by an advisory opinion from the Attorney General "regarding whether competition will be adversely affected and what mitigation measures could be adopted to avoid this result." Intervenors argue that the proposed combination of Pacific Enterprises and Enova, along with the ongoing consolidation of their unregulated subsidiaries' operations, will likely have a severe negative effect on competition in California gas and electricity markets. They contend that the consolidation of SoCalGas's dominance of gas transportation in and into southern California, gas storage in the region, and core gas purchasing in the region, with and into SDG&E's electricity generation and Energy Pacific's unregulated electric market activities (including the almost certain acquisition of generation) creates a degree of vertical integration arousing serious concerns. This vertical integration promises to enhance both the ability and the incentive of the merged company to evade regulation by using its market power over gas prices and services to disadvantage rivals in electricity markets, and, by using its affiliates' activities in electricity markets, to extract monopoly profits not previously available to it in gas markets. Accordingly, the Commission cannot find that the applicants' proposal "does ...not adversely affect competition," as required for approval under Section 854(b)(3). Intervenors assert that vertical market power may lead to at least three kinds of anticompetitive effects. First, a vertical merger may allow the new, vertically integrated firm to raise its rivals' costs by foreclosing access to or raising prices for upstream inputs required by rivals in the downstream market. Through SoCalGas, Pacific 37 Enterprises has market power over and operational control of in-state transportation and storage, in- state hub services, the largest block of in-state demand, and ultimately, the price of gas at the California border. This upstream power gives it enormous ability to raise the price of gas to electricity rivals and to deny access to or raise the price of in-state storage to electricity rivals. Second, a vertical merger can facilitate the tacit or express exchange of information about the upstream or downstream markets that ultimately can lead to reduced competition in the affected market. Through SoCalGas, Pacific Enterprises has access to nonpublic operational information about the gas system that is of inestimable value to gas shippers and that can be shared with its affiliates with interests in electricity markets to the detriment of their rivals. Finally, a vertical merger can allow a regulated firm with market power to avoid the effects of regulation by integrating into an upstream or downstream market. Intervenors believe it is this third form of anticompetitive activity that is likely to occur if the merger is allowed to proceed as proposed. They argue that through SoCalGas the new company will have market power in the upstream gas supply market, enjoying extensive discretion in its operation of critical gas transportation and storage assets and controlling the largest block of gas demand in southern California. Previously, SoCalGas had little, if any, incentive to exercise its market power because as a regulated gas company, it had little ability to increase its ultimate earnings and had no affiliated electric generation or financial positions in futures markets to benefit. The merger changes everything. Post-merger, Pacific Enterprises will have affiliates with electric generation. And in anticipation of the merger, Pacific Enterprises and Enova have created unregulated affiliates with significant positions in soon-to-be unregulated electricity markets. Intervenors assert that the merger and the creation of Energy Pacific marries the ability to manipulate gas prices with the ability to profit from that anticompetitive conduct at the expense of competition and electricity consumers. Applicants contend that the merger of Pacific Enterprises and Enova will not adversely affect competition. They say SoCalGas and SDG&E are not head-to-head competitors in any relevant product market. The forthcoming retail market for electricity will likely be so fiercely contested that the loss of one potential competitor 38 will not have any appreciable affect. They expect the new company to stimulate the introduction of retail competition in California, with the merger providing a considerably more effective competitive option to millions of electric customers currently served by Pacific Enterprises. They claim the very prospect of this merger is already imposing competitive pressures that are forcing competitors to pursue alliances and other strategies, presumably to reduce the cost or improve the quality of energy products and service in southern California. Intervenors have hypothesized various ways in which SoCalGas could exercise its vertical market power in gas markets so that the new company can profit in electricity markets. SoCalGas contends that it does not have the market power that intervenors allege. As a buyer of gas, it accounts (with or without SDG&E) for a very small share of the production in the basins that supply California. These markets are highly competitive and not susceptible to monopsony power by any single market participant. As a holder of rights to use interstate pipeline capacity into California-of which there is a glut-SoCalGas argues it cannot affect prevailing transportation costs. As a transporter, distributor, and operator of storage within California, it is already pervasively regulated by this Commission and is not capable of manipulating prices. Moreover, applicants are of the opinion that the highly integrated nature of the western power market assures that any effort by SoCalGas to raise electricity prices by raising gas prices would be substantially undercut by generators SoCalGas does not serve. Indeed, an effort to raise gas prices would-apart from the enormous legal and regulatory risk-almost certainly prove unprofitable to the merged entity since lost gas transportation revenues would overwhelm any gain in electricity revenues. Applicants assert that to claim that the merger would induce SoCalGas to exercise market power is flatly wrong: if anything, the merged entity will have a palpable disincentive to raise gas prices. Finally, applicants point out that SoCalGas has the ability, without the merger, to do all the manipulative, anticompetitive activities of which it stands accused. The merger adds nothing. And it is the effects of the merger that move the legal inquiry. 39 In later portions of this opinion we discuss in detail the contentions of intervenors and the responses of applicants. Here, we present the framework which guides our analysis. First: We are deciding to approve or disapprove a merger. The question presented is-will the merger "adversely affect competition"? (Sec. 854(b)(3).) SoCalGas's present market power is not the issue. Second: Market power is defined as the ability of one or more firms profitably to maintain prices above competitive levels for a significant period of time. (U.S. Dept. of Justice Merger Guidelines Sec 0.1 in Scher, Antitrust Advisor, Fourth Ed., Appendix 3-1, p. 3-197, 198.) Third: The firm with market power must not be subject to price regulation. (Id., Sec. 1.0, p. 3-199.) Fourth: The use of purchasing power and the allocation of services to discriminate profitably, to evade rate regulation, to raise costs to rivals, and to create barriers to entry must be prevented. Fifth: Our goal is to protect competition, not competitors. A. Attorney General's Advisory Opinion The Attorney General of California has submitted his advisory opinion on the merger, pursuant to PU Code Sec. 854, including his recommendations on mitigation measures that could be adopted to avoid any adverse competitive effects that do result. This is the fifth opinion letter submitted by the Attorney General under the 1989 amendments to Section 854. PU Code Sec. 854 refers to the opinion as advisory. Consequently, this document does not control our finding under Sec. 854 (b)(3). However, the Attorney General's advice is entitled to the weight commonly accorded an Attorney General's opinion (see, e.g., Moore v. Panish (1982) 32 Cal.3d 535, 544 ("Attorney General opinions are generally accorded great weight"); Farron v. City and County of San Francisco (1989) 216 Cal.App.3d 1071). The opinion was served November 20, after receipt of evidence and opening briefs. 40 The Attorney General concludes that this merger will not adversely affect competition within either the wholesale electricity or interstate gas markets. He says because gas-fired plants now owned by SDG&E are subject to comprehensive price regulation, the merged entity will lack any incentive (or, usually, the ability) to manipulate wholesale electricity prices. (Should SDG&E sell its gas-fired plants, as it has announced, there is even less reason to affect wholesale electricity prices.) Moreover, the wholesale electricity and interstate gas markets are already highly integrated, and comprise most of the western United States. Price data-as opposed to theoretical models-show that the wholesale electricity market connects California with numerous out-of-state suppliers over a transmission system that has never reached capacity. Those out-of-state suppliers, along with California generation plants outside the SoCalGas service area, would defeat any attempt by the merged entity to raise wholesale electricity prices above competitive levels. He also concludes that the merger of the utilities' procurement operations will not adversely affect competition in the interstate gas market and that the applicants are not actual potential competitors for retail electricity services. On the other hand, because the merger may eliminate the disciplining effect of SDG&E as a potential competitor in the partially regulated intrastate gas transmission market, he recommends that the Commission consider requiring SoCalGas to auction offsetting volumes of transportation rights within that system. Finally, because of the uncertain effects of electric industry restructuring, he recommends that the Commission retain limited jurisdiction over this merger for the purpose of re-examining the question of whether the merged entity has used its intrastate gas transmission system for the purpose of manipulating the price of electricity it sells in the wholesale market. B. Market Power Market power is generally defined as the ability of a firm or group of firms to profitably raise and maintain the price of products they sell significantly above a competitive level. Conversely, market power for a buyer is the ability to profitably set and maintain prices below competitive levels. In D.91-05-028, our decision regarding 41 the proposed merger of Edison and SDG&E, we set forth a conceptual framework for analyzing competitive effects for purposes of Section 854(b)(3). In so doing we distinguished between "horizontal" effects and "vertical" effects: A consolidation of two companies performing similar functions in the production or sale of comparable goods or services at the same level is characterized as "horizontal." Thus, a merger between two manufacturers or two retailers of comparable goods or services would be a "horizontal" alignment. By contrast economic arrangements between companies which conduct operations at different levels up and down the distribution chain (e.g., wholesale and retail) are characterized as "vertical." (Re SCE Corp. (1991) 40 CPUC2d 159, 184, [D.91-05-028, mimeo. at pp. 29, 30]. We described the standard method of performing a horizontal market analysis, as reflected in the United States Department of Justice Merger Guidelines (the Merger Guidelines). This method entails defining a relevant geographic and product market: The product market is a range of products or services that are relatively interchangeable, so that pricing decisions by one firm are influenced by the range of alternative suppliers available to the purchaser.... The relevant geographic market is defined as the area in which sellers compete and to which buyers can practically turn for supply. (Id. p. 184.) In a market analysis of horizontal effects, we noted that we would consider direct evidence of harm to competition "where the power to exclude competition is proved directly by actual exclusion." (Id. p. 185.) Under this approach, however, it must be shown, "that there has been an actual exercise of market power that has been even further exacerbated by the merger." (Id. p. 186.) Vertical exercise of market power entails the foreclosure of competitors' access to suppliers or customers. These problems "are assessed not by calculating market shares, but by realistically assessing the potential for market manipulation, resulting in disadvantage to competitors or consumers." (Id. p. 186.) Of overriding importance for purposes of vertical or horizontal analysis is the effect of the merger on the competitive situation. The parties have presented cogent evidence of SoCalGas's market power. As we discuss in Section III.B.4.d below, it is 42 clear that SoCalGas currently has market power due to its near- monopoly control over facilities used for the transport and storage of natural gas for electric power plants within southern California. The existence of market power is of serious concern to this Commission. Nevertheless, the problem of market power in this industry is better addressed in the natural gas strategy OIR (R.98- 01-011), where we will consider the overall policy issues facing the Commission for the future of this significant, diverse, and protean market. For example, the Rulemaking requests comment on issues such as divestiture of the utility procurement function and other options for mitigating potential anticompetitive behavior. The issue in this proceeding is not whether market power exists, but whether it is likely to be enhanced by this proposed merger. What matters in assessing a merger is how the merger itself will change the competitive circumstances that would obtain absent the merger. We emphasized that point in our recent decision approving the PacTel/SBC merger: "Thus, whatever market power Pacific possesses in the various relevant markets discussed below, our inquiry focuses on specific evidence as to whether this merger increases or enhances that market power. Several of intervenors' arguments regarding barriers to entry, as discussed more fully below, would exist with or without the merger. We, and certain federal regulators, are examining these arguments in the appropriate proceedings to determine ways to promote robust competition in all telecommunications markets, a goal to which we are strongly committed. However, we do not find in the absence of specific evidence, that a merger in itself adversely affects competition simply by making a large and strong company larger and stronger." (D.97-03-067 at p. 43.) 1. Horizontal Market Power Effect of Eliminating SDG&E as a Separate Potential Competitor and Customer IID and others argue that two aspects of applicants' merger-created market power cannot be mitigated by any means: (1) the elimination of potential bypass competition, and (2) the elimination of potential competition in the retail electric market. They conclude because the merger, however else it might be conditioned, 43 would adversely affect competition in these two respects, the merger fails to satisfy the requirements of PU Code Sec. 854(b)(3), and should be rejected outright by the Commission. Intervenors argue that because SoCalGas owns and controls all of the intrastate gas pipeline transportation facilities in California south of San Bernardino County and Kern County, the only competitive force that disciplines SoCalGas's pricing behavior for gas transportation within southern California is the threat of construction of additional gas transportation facilities that would enable customers to bypass the SoCalGas system-that is, the threat of potential entry by a competitor into SoCalGas's monopoly area. SoCalGas has historically viewed SDG&E as a significant potential bypass threat and has entered into at least one agreement (Project Vecinos) that recognizes the economic value to SDG&E of the leverage that its bypass threat affords. IID asserts that SoCalGas has historically evaluated IID as a potential bypass threat in conjunction with SDG&E, presumably under a scenario in which both SDG&E and IID would participate in a bypass pipeline constructed from El Paso's Yuma, Arizona terminus, along the border of the United States and Mexico and into San Diego. The threat of entry through potential bypass competition constrains the ability of an incumbent monopolist, such as SoCalGas, to charge prices for gas transportation that exceed a competitive level and the elimination of the threat of potential competition eliminates the limitations on SoCalGas's pricing. Thus, because the merger would effectively eliminate SDG&E as a participant in a potential bypass pipeline, the merger eliminates both actual and perceived potential competition, and threatens direct competitive harm to IID-in the form of higher gas transportation prices than would have prevailed as a result of the threat of a bypass pipeline by SDG&E. IID maintains that SDG&E's presence as a potential bypass competitor has affected SoCalGas's pricing behavior in the past, and would likely continue to do so in the future if the merger is denied. Inasmuch as SoCalGas has also evaluated IID as part of an SDG&E bypass scenario, the proposed merger would impose direct economic harm on IID because the merged company's gas transportation pricing will not be constrained-as SoCalGas's has been constrained historically-by the threat of bypass 44 posed by SDG&E. As long as SDG&E remains an independent company, IID benefits from the threat of potential bypass competition that SDG&E poses to SoCalGas. Once SDG&E merges with SoCalGas, IID will confront a monopoly provider of gas transportation whose pricing is unconstrained by any relevant threat of potential bypass competition. IID also maintains that the proposed merger will adversely affect competition by eliminating actual potential competition in deregulated retail electric markets. Absent the merger, affiliates of one of the merging companies independently would have entered the retail electricity markets in the current service area of the utility affiliate of the other merging company-thereby deconcentrating the market represented by that service area. IID believes the merger destroys two opportunities for deconcentrating existing retail electric monopolies following implementation of direct access in 1998. The first such opportunity would have been the entry by an Enova electric affiliate into former retail electric monopoly service areas within the SoCalGas retail gas service territory. The second opportunity would have been the entry by a Pacific Enterprises electric marketing affiliate into the SDG&E service territory. IID cites our prior recognition that a merger's elimination of the opportunity that direct entry into relevant markets by a significant competitor would provide for improving the competitive structure of such markets is a type of anticompetitive effect proscribed by PU Code Sec. 854(b)(3). IID claims that the merger's elimination of the possibility of independent entry by marketing affiliates of one applicant into the retail electric service area of the utility affiliate of the other applicant is sufficient cause, by itself, for denial of the merger. - --------------------- As the Commission explained in Re Pacific Telesis Group/SBC Communications, Inc., (l997) [D.97-03-067], 177 P.U.R. 4th 462, 1997 CalPUC LEXIS 629 at *86 (PacTel/SBC): If in lieu of entering the market independently or through toehold acquisition, the actual potential entrant merges with a significant incumbent firm, its incentives to enter the market independently disappear and the market would lose the amount of new competition that the potential competitor would have generated. 45 Applicants assert that eliminating SDG&E as a competitor does not harm competition because (i) the merger has no horizontal effect on wholesale electric competition, (ii) the merger will enhance retail electric competition, (iii) the merger will not adversely affect competition in natural gas sales, and (iv) the merger will not eliminate SDG&E as a potential bypass customer. Applicants point out that the electric utilities in the western region of the United States are interconnected by a highly integrated high-voltage transmission grid that allows for extensive trading of power and coordination of operations for reliability purposes. SDG&E owns approximately 2,400 MW of generating capacity; Pacific Enterprises owns no capacity; the WSCC as a whole includes over 140,000 MW. Because SDG&E's peak load exceeds 3,900 MW, it is overwhelmingly a net buyer of power. SDG&E's total capacity is less than 3% of WSCC capacity. When transmission is constrained from the north, SDG&E's share goes up to 7%. The merger produces no increase in concentration. In regard to retail electric competition, applicants maintain the merger will enhance competition; the new company will be a strong competitor. Retail competition in electricity will begin in California in 1998. Accordingly, Enova and Pacific Enterprises do not now compete for retail electricity customers, and the loss of SDG&E as a competitor is, at most, the loss of a potential competitor. The retail supply of electricity will be characterized by easy entry and fierce competition among a large number of firms, including existing wholesale marketers, power brokers, and energy service companies. As a result, the loss of one potential competitor would not affect the degree of competition. Over 170 Energy Service Providers have registered with the Commission to compete in the retail electric market. One more or less will have no effect. - ----------------------- The regional reliability council, the Western Systems Coordinating Council (WSCC) encompasses all of Idaho, California, Oregon, Washington, Arizona, New Mexico, Nevada, Utah, Wyoming, Alberta and British Columbia, as well as the western portions of Montana and Colorado. 46 As to competition in natural gas sales, applicants argue that in the competitive noncore market, in which SoCalGas is precluded by Commission regulation from offering service other than its core subscription service, SoCalGas has a share of less than 5%. SDG&E, which is allowed to compete for its noncore load, has retained less than 42% of its noncore customers. Neither has made sales to noncore customers outside its own service territory. Any market share increase by combining companies is negligible. Further, applicants do not propose at this time to merge the core procurement functions of SoCalGas and SDG&E. In regard to the important point raised by intervenors, that the merger will eliminate SDG&E as a potential bypass customer, applicants deny it. Applicants claim that bypass has never made sense to SDG&E. SDG&E has previously considered a bypass of SoCalGas's system, but in each instance, the service provided by SoCalGas made more economic sense. If it had not, SDG&E would now be receiving intrastate transportation service from someone else. Additionally, continuing Commission regulation and the Memorandum of Understanding among SDG&E, Enova, and the City of San Diego (the MOU) would make it difficult for SDG&E, after the merger, to refuse to investigate, interconnect with, or decline to make full use of another pipeline offering an economic alternative to SoCalGas. Applicants note that SDG&E is not the only potential anchor in the area for a bypass pipeline. SDG&E is no longer the exclusive natural gas supplier in its service area. Noncore customers as well as core aggregators use SDG&E's system for transportation or distribution; they account for a large part of the load on the SDG&E system, and are free to procure not only the gas commodity, but upstream transportation wherever it is available. Thus, this portion of SDG&E's load could attract, in itself or with other gas purchasers in southern California, a pipeline interested in competing with SoCalGas if doing so were potentially profitable. Applicants view the potential for future bypass opportunities in light of all relevant circumstances. SDG&E is geographically isolated from SoCalGas's other major load centers, including the Los Angeles basin. Any participation by SDG&E as an anchor tenant in a bypass project also serving loads in the Los Angeles basin would 47 almost certainly require SDG&E to pay for many miles of pipeline. This fact does not make bypass impossible for SDG&E, but it certainly calls into question intervenors' contention that SDG&E would be a superb anchor tenant for their future projects. Additionally, applicants say, in recent years SoCalGas customers considered potential bypass opportunities in part because of the significant transition costs embedded in SoCalGas's transportation rates. The Global Settlement and recent contractual step-downs on both the El Paso and Transwestern pipelines offer rate relief and transportation for SoCalGas customers such as SDG&E. Until the Commission's cost allocation policies change dramatically, in the near future noncore and wholesale transportation customers of SoCalGas, including SDG&E, should see substantial decreases in their transportation rates as transition costs decline. These rate reductions will tend to make SoCalGas's service to SDG&E more economical than bypass alternatives. Finally, as SDG&E is a regulated local distribution company, applicants contend that SDG&E simply will not be in a position to decline to interconnect with another pipeline offering more economic and equally reliable service as SoCalGas, or continue to insist on using transportation service over the SoCalGas system in the face of less expensive (bypass) alternatives. For one thing, restrictions adopted by the Commission for Enova and its affiliates, including SDG&E, on affiliate dealings specifically prohibit the acquisition of goods or services, including gas transportation and storage service, from an affiliate at any price above fair market value. So, if a competitor were offering service at or below the transportation rates offered by SoCalGas (including any discounts above variable cost offered by SoCalGas to meet the competition), SDG&E would risk disallowance and penalties by opting to continue taking service from SoCalGas. Such conduct would be easily detectable by interested parties (such as competing pipelines). Indeed, apart from the Commission's power to disallow excessive costs arising from refusal to use an alternative that is less expensive than an affiliate's, the Commission has the power simply to compel interconnection. In short, applicants believe the merger will not discourage new or existing pipelines from building into southern California in order to interconnect with SDG&E's system. 48 Discussion Here we discuss the elimination of SDG&E as an "actual potential competitor" in the retail electricity competition in southern California. No party claims that the merger will have any adverse horizontal effects on wholesale electricity competition. The effect of the elimination of SDG&E as a customer of a competing gas pipeline is treated elsewhere (see III.B(4)(d)). In our PacTel/SBC decision, we described a four-part evidentiary showing required to establish loss of actual potential competition. The four elements of the showing are: (1) the relevant markets are presently concentrated; (2) one or both of the merging parties would have entered the relevant markets directly absent the merger; (3) entry through merger confers competitive advantages on the merging parties that are not available to other potential entrants; and (4) it is likely that independent entry, absent the merger, would have deconcentrated the market or had other procompetitive effects. (D.97-03-067 at p. 51.) It is obvious to us that the criteria of PacTel/SBC have not been met. For this analysis, we consider the relevant geographic market for retail electricity sales to be the SoCalGas service territory. There is at present no competition in retail electricity sales in California. Competition will begin in 1998. As of November 1, 1997, no fewer than 169 separate firms had registered with the Commission to compete as Energy Service Providers. For that reason alone the market cannot be characterized as "concentrated." Major competition for electricity retail sales in both SoCalGas's territory and SDG&E's territory is expected to include strong, nationwide firms such as Enron, Duke/Louis Dreyfus/PanEnergy, PacifiCorp/Energy Group/Citizens Lehman, Engage Energy/Coastal/Westcoast, and Southern Energy/Vastar, all of whom have extensive experience in energy trading to bring to retail electricity markets. They also have experience and capability in hedging and other facets of marketing that will be necessary in retail electricity competition. One electricity sales provider, more or less, will have no impact in either utility's service area. The relevant market in 1998 is not concentrated. The merger will not cause the loss of actual potential competition. 49 2. SoCalGas's Market Power SoCalGas is one of the largest gas transmission and distribution companies in the world and has a virtually exclusive monopoly in a franchised service territory that encompasses the southern half of California. Natural gas plays a critical role in the California electricity market because it acts as the marginal (i.e., price- setting) fuel for many hours in the year. After restructuring of California's electricity markets, this significance will be greatly magnified, because the bid of the marginal generator in the new Power Exchange (PX) spot market will become the price for nearly all spot market power. Whenever gas will be on the margin, a change in the price of gas will lead to a change in the wholesale and spot retail electricity prices in California. Thus, because SoCalGas has a monopoly over gas transportation and distribution facilities in southern California, any exercise of its market power could improperly restrict nonaffiliated generators' access to delivered gas services and raise those nonaffiliated generators' input costs. SoCalGas provides transportation, distribution, storage, and related services to noncore and wholesale customers, including electric generators which will be rivals of SoCalGas's affiliates following the merger. SoCalGas is the supplier of delivered gas services to approximately 100 gas-fired utility generating stations and cogeneration facilities located in southern California, including 11 of Edison's 12 generating facilities and all of SDG&E's generating stations. For gas purchased outside - ----------------------- During a four-year transition period beginning in 1998, investor-owned utilities (IOUs) must purchase and sell all of their power through the PX, which will establish a single clearing price for all hourly transactions. Participating distribution companies and end-users will submit demand-side bids to the PX. Generation plants and marketers will simultaneously submit advance supply bids. The total capacity of WSCC members, including capacity divested from Edison and PG&E, which can bid into the PX exceeds 150,000 MW. (Native power will reduce the amount available to be bid into the PX, but the threat is always a factor.) From the resulting demand and supply schedules, the PX will establish the market clearing price governing all purchases and included sales. The highest-cost unit that is needed in order to meet the hour's demand will establish the price for power in that hour. 50 of California, SoCalGas provides the only intrastate transportation service available to the majority of those generating stations. SoCalGas currently owns and operates five storage fields with a combined working gas capacity of 115 Bcf. No other company offers storage services in southern California. SoCalGas not only operates these facilities, but directly controls 65% of the storage capacity of the facilities. These storage facilities provide SoCalGas with significant operational flexibility and discretion which SoCalGas could use to benefit its affiliates and to disadvantage its rivals. SoCalGas also provides three "hub" services-loaning, parking, and wheeling. SoCalGas loans gas to a customer when it provides a certain quantity of gas to a customer who later returns the same quantity at a specific time and location. Customers park gas when SoCalGas receives natural gas for a customer's account for short- term interruptible storage, such as when a customer delivers more gas to the SoCalGas system than it actually uses and wants to avoid an imbalance situation. SoCalGas provides a wheeling service when it receives a certain quantity of gas at an interconnection point on its system and subsequently delivers that same quantity of gas- to the original customer or to another party-at another point either on or off of SoCalGas's system. SoCalGas provides these services on a best efforts, interruptible basis at rates negotiated by the parties based on prevailing market conditions and individual customer circumstances. SoCalGas has significant latitude in pricing these services. Intervenors maintain that SoCalGas can exercise market power to benefit its affiliates. As the operator who controls gas transportation, storage, distribution, and other related gas services in southern California and as the dominant holder of interstate capacity rights into Topock, SoCalGas has several tools at its disposal by which it could benefit its affiliates and disadvantage their rivals. In some cases, SoCalGas could directly benefit an affiliate through lower costs or improved access. In other cases, SoCalGas could adversely affect the costs and access of its affiliates' competitors. 51 There are at least five tools available to SoCalGas for accomplishing those objectives: (1) nonpublic operational information; (2) intrastate access; (3) pricing of intrastate services; (4) core procurement behavior; and (5) interstate access and its effect on the border price of gas. Each of these tools could be used to materially affect the price of gas or the quality of service to a competing electric generator, and could be used in a discretionary manner to favor affiliates without violating the proposed conditions that will govern affiliate relationships post- merger. Applicants assert that SoCalGas, as a transporter of natural gas, faces significant competition for customers in southern California. The competitive alternatives available to natural gas customers include: alternative pipelines and storage facilities delivering interstate or surplus local California production of natural gas, alternate fuels, municipalization of SoCalGas's distribution facilities, and "bypass by wire" (competition to local gas generation by out-of-state electricity generators). Applicants point out that the interstate gas supply market is highly competitive. Currently, there are four major supply, or production, basins serving California: western Canada, the Rocky Mountains, the San Juan Basin, and the Permian Basin. In 1995, total production from those four basins (and local California production) was 9,040 Bcf. California power generators consumed just 5.9% of that total production. In total, 7,130 million cubic feet per day (MMcf/d) of interstate pipeline capacity serves California today. This represents approximately 50% excess capacity on a peak day. SoCalGas currently holds 1,450 MMcf/d of firm capacity rights on El Paso and Transwestern, reflecting approximately 20% of the total interstate capacity serving California. SoCalGas's recent relinquishments of 1,050 MMcf/d of capacity to those pipelines, along with PG&E's upcoming relinquishments of capacity to El Paso, are among the 2,200 MMcf/d of capacity rights that either have been or will soon be relinquished to the interstate pipelines. Applicants respond to intervenors' claim that SoCalGas already has the ability to force higher costs on generators and the merger will simply furnish incentive for it to do so, by reference to this Commission's regulation. Without authorization SoCalGas cannot unilaterally raise the price of its own tariffed transportation services to 52 unaffiliated generators. Moreover, because it is effectively barred from competing to make sales of gas to noncore customers, SoCalGas cannot simply raise the price of the commodity purchased by generators. In defining market power in relation to PX prices if delivered gas is the relevant product, then applicants assert that the relevant geographic market encompasses natural gas sold or purchased at any point on the supply network serving California. They argue that because Edison and other intervenors assert that SoCalGas will be able to influence PX prices by affecting the price of gas paid by generators selling into the PX, the definition of the relevant market must focus on where those generators who will sell into the PX actually purchase gas, i.e., the sources to which generators could turn for substitute supplies. Like other end-users in both northern and southern California, power generators draw their suppliers from producing basins in Canada, the Rocky Mountains, the San Juan Basin (roughly, the Four Corners area), and the Permian Basin (west Texas, southeast New Mexico), as well as from basins in California itself. Precisely because generators in northern as well as southern California rely on the same sources of supply, there is no sound reason to distinguish between basins as serving one part of the state or the other. Moreover, electric generators purchase gas not just at the wellhead, but also at downstream points along the supply network, notably at the California border or from storage. These locations, too, are properly within the relevant geographic market. Applicants' answer to the claim that SoCalGas could raise the price of gas at the California border by manipulating the terms on which it releases the capacity it holds on interstate pipelines is that the mechanics of capacity release do not enable a capacity holder to withhold capacity from the market. If the holder of capacity rights does not use them, i.e., does not either release those rights to another party or schedule gas pursuant to those rights, the underlying capacity reverts to the pipeline to be marketed as interruptible transportation. The FERC specifically so held in dismissing an Edison complaint against SoCalGas: "Moreover, even if SoCalGas does not release its available capacity, that capacity is available as interruptible capacity from the pipeline. Thus, no capacity is effectively being withheld from the market." (Southern 53 California Edison Co. v. Southern California Gas Co. (1997) 79 FERC ? 61,157, 61,662, emphasis added.) Applicants state that SoCalGas cannot affect the border price of gas by manipulating receipt point windows. They explain: SoCalGas establishes an overall system "window" or quantity of gas that it can take into its system on each day by estimating actual consumption on its system (minus California gas production) and adding to that figure its storage injection capacity. The system window is allocated among SoCalGas's individual receipt points, i.e., interconnections with upstream pipelines, taking into account the physical capacity at each point and customer nominations to deliver gas into the system at that point. - -------------------- After SoCalGas Gas Operations determines the system window, it receives nominations from core customers (by SoCalGas Gas Acquisition or their authorized agents or marketers) and from noncore customers and/or their authorized agents or customers. It is not unusual, however, for customers' initial nominations to exceed the system window due to customers' nominations exceeding their expected usage. When expected deliveries exceed the system window, all as-available storage injections and hub transactions are immediately terminated. SoCalGas Gas Operations attempts to avoid the need to reduce nominations submitted by customers by notifying all customers via GasSelect of an overnomination condition, and by requesting that customers voluntarily reduce their nominations so that they will not exceed 110% of their expected usage plus firm storage injection rights. If this effort is not successful and expected deliveries still exceed the level of the next day's system window, SoCalGas Gas Operations calls an "overnomination event" and reduces nomination in accordance with the provisions of SoCalGas Rule No. 30. This CPUC-approved rule requires SoCalGas to invoke "daily balancing," meaning that customers are subject to penalty if they deliver more than 110% of that day's usage plus any firm storage injection rights. In such circumstances, customers are permitted to deliver any volume less than 110% of usage plus firm storage injection rights, and thus can deliver no gas to the SoCalGas system, while burning as much gas as they like, without incurring daily imbalance penalties. In addition to establishing the overall system window, SoCalGas must establish the window at the individual receipt points from the interstate pipelines. It does so based on relative levels of customer nominations at the various receipt points. If customers' intended delivery volumes are more than the windows at these receipt points the interstate pipelines reduce customer nominations in accordance with their FERC-jurisdictional tariffs and their ability to confirm upstream deliveries to the pipeline. If scheduled deliveries are less than the windows set at individual receipt points, SoCalGas Operations accepts intraday nominations to available receipt point capacity to permit maximum deliveries into the SoCalGas system. 54 Applicants say that a windows manipulation strategy would fail because there is an abundance of unused pipeline capacity into California. As a result, even were one to assume that SoCalGas could artificially limit deliveries into its system at one location, such a limit would increase prices to California power generators only if it pushed prices up at all border locations. Border prices at various points of delivery into California have, in recent years, increasingly converged. In today's highly integrated gas market, there is no sustained advantage in being able to take gas at one location over another. Nor can it properly be assumed that an electric generator whose nominated volumes were the target of a suddenly closed window would be forced to select an alternative point at which to have gas delivered into the SoCalGas system. Customers on the SoCalGas system can simply burn as much gas as they need without either delivering gas into the SoCalGas system or incurring daily balancing penalties. Applicants contend that SoCalGas cannot manipulate gas prices through its core procurement. SoCalGas's purchases on an average day on behalf of its core customers, even combined with those of SDG&E, amount to about five percent of the total production in the four producing basins that supply California. In light of SoCalGas's small market share, the assertion that SoCalGas can affect prices as a purchaser is, in applicants' opinion, contrary to common sense. They believe, as a practical matter, even if SoCalGas could otherwise manipulate core purchases by the use of storage injections or withdrawals to a degree that would actually affect the price of gas to electric generators in California, that conduct would not be difficult to detect and would carry with it exposure to substantial civil liability and regulatory penalties. That will be all the more true under the conditions proposed by SoCalGas in this proceeding, which require it to post on its EBB each day estimated storage injections, withdrawals, and day-end inventory. Finally, applicants assert that SoCalGas cannot manipulate prices or terms of transportation or storage on the SoCalGas system. Intervenors allege that SoCalGas can operate its system in a discriminatory fashion to favor affiliates or to disadvantage their competitors in terms of service or price, such as by granting preferential discounts to affiliates. Applicants admit the possibility of such abuse is not, of course, confined to 55 the merger, or to the applicants. Because of this, affiliate transaction rules are the subject of the statewide Affiliate Transaction Rulemaking. Applicants believe conduct in violation of the standards adopted in that Rulemaking would entail such risk as to make it utterly impracticable, quite apart from existing corporate policies of Enova and SoCalGas that prohibit such abuse. Nevertheless, applicants have not only accepted FERC's conditions, but have added substantially to them in restricting SoCalGas's future operations and in requiring the posting of information about the status of the SoCalGas system. Discussion We review SoCalGas's market power in the context of the acquisition of SDG&E. That SoCalGas has market power is clear; whether the acquisition of SDG&E enhances that market power and, if so, what mitigation measures will negate that enhancement is the subject of this opinion. We cannot emphasize too strongly that SoCalGas is a regulated utility whose rates and services are regulated by this Commission. After the merger, its rates and services will continue to be regulated. ORA has succinctly stated what others have devoted hundreds of pages of briefs: "ORA does not contend that SoCalGas currently has or inappropriately exercises undue market power beyond that subject to regulatory review." (ORA Opening Brief, p. 63.) A discussion of market power starts with the description of a product market and a geographic market. A merger may involve more than one product and more than one product market. In this application, the product market includes delivered gas and retail electricity. The geographic market is southern California for gas sales, and the basins supplying gas to southern California for gas purchases. For retail electricity, the geographic market is southern California for sales, and the WSCC for purchases. In regard to delivered gas, intervenors do not dispute that SoCalGas's transportation charge is regulated by this Commission, but they claim that because of SoCalGas's manipulation of storage injections and withdrawals, as well as gas purchases for the core, SoCalGas controls the price of gas at the California border, especially at Topock. 56 The evidence is otherwise. SoCalGas, in the normal operation of its system must purchase gas for its core customers, at times must inject gas for storage, at times must withdraw gas from storage, at times gets overnominations at its various receipt points which must be allocated. If these activities affect the price of gas or other costs of nonaffiliated generators they are unavoidable. Intervenors claim that by timing those events SoCalGas can benefit its affiliates who compete in electricity generation or who trade in gas and electric commodity futures. Natural gas producing basins serving California are part of an integrated market in which SoCalGas purchases only a small portion of the total production of those basins. We find no correlation between SoCalGas's injections or withdrawals and the border price of gas. EBB posting obligations undertaken by SoCalGas-covering storage injections and withdrawals as well as storage inventory levels-would make any efforts at manipulation easy to detect. Storage manipulation would shift purchases only temporarily; we believe producers would tend to disregard short-term fluctuations in SoCalGas's purchases in setting prices. Further, unaffiliated generators could balance long-term price arrangements in contracts with producers to offset any short-term effects of SoCalGas's core purchasing. San Juan Basin prices when compared against storage activity shows a small negative relation between those prices and SoCalGas's storage injection timing. The evidence purporting to show a correlation between SoCalGas's storage and core activity and the border price of gas failed to take account of activity of other purchasers, effects of weather, transportation constraints, and market activity in general. We are in agreement with the Attorney General who has rejected the "core procurement" theory. He notes that SoCalGas accounts for only a 4% share of the production from the four basins serving California, certainly not enough to manipulate prices. Our analysis is buttressed by this perception. If we are wrong and there is a correlation between storage activity, core purchases, and the border price of gas, the market will know it and adjust. It will affect all parties equally. Unaffiliated generators can adjust to these fluctuations by using their storage gas, and will benefit by 57 purchasing gas on the downswing. We agree with applicants' evidence that a deliberate increase in the price of gas to unaffiliated generators would be self-defeating as the expected increase in electricity prices would cause cheaper energy to flow into California thereby reducing southern California generation, thereby reducing SoCalGas's throughput. We are not saying that SoCalGas's practices do not affect the price of gas; they are one of the largest purchasers of gas in the United States. We are saying that the evidence shows they are not now manipulating and have little incentive in the future to manipulate the price of gas. In regard to the retail electricity market, our analysis follows that of delivered gas. Our inquiry concerns the effect of gas prices on gas-fired generation. We have found that SoCalGas has not used its purchases of natural gas and its operation of its system to manipulate the price of gas. It follows, therefore, that it has not manipulated the gas-fired generation retail electricity market. We end this discussion as we began it. SoCalGas has market power. Whether its merger with SDG&E will increase that market power is discussed below. 3. Vertical Market Power of the Merged Entity Vertical market power with anticompetitive effects may result when an "upstream" firm, e.g. a wholesaler, mergers with a "downstream" firm, e.g. a retailer. The FERC has concisely set forth the problem this merger presents. Unlike horizontal mergers, which eliminate a seller in the market and therefore increase concentration, vertical mergers do not involve firms competing in the same product market and therefore do not increase concentration in a single product market. While vertical mergers can result in efficiencies from integrating input and output operations, they can also increase the merged firm's incentives to use its market position in one segment of its vertically integrated business to adversely affect competition in a related segment of its business. Any benefits arising from a vertical merger are necessarily weighed against the competitive harm the merger is likely to cause. As discussed below, the proposed transaction before us raises vertical market power concerns because it would consolidate the intrastate gas operations of SoCalGas with the electric operations of SDG&E. SoCalGas 58 delivers natural gas not only to SDG&E's gas-fired generators but to virtually all gas-fired generators in southern California that compete with SDG&E in the wholesale electricity market. (Re Enova/Pacific Merger, 79 FERC at 62 560.) For the purpose of this discussion, we assume that SDG&E will divest all of its generation, thus complying with FERC's primary mitigation measure (see Section I.C above). Nevertheless, in the opinion of intervenors, that divestiture is inadequate to mitigate the anticompetitive merger effects envisioned by them. Edison contends that whether or not SDG&E's electric generation is divested post-merger applicants will have the ability to manipulate the supply and price of natural gas in southern California, and thereby to affect the price of electricity statewide, and to profit (directly or by creating competitive advantages for their affiliates) by that activity, reasonably free from detection by regulators. Intervenors assert that the post-merger family of companies will be able to leverage SoCalGas's unique position as a monopolist provider of gas transportation and storage services essential to electricity generation-its unique access to and control of system information and/or its ability to exercise its substantial operational discretion-to create anticompetitive advantages for affiliates who ship natural gas on SoCalGas's system (i.e., affiliates with interests in generation), or to create disadvantages for their competitors. Such preferential actions can be targeted to favor any affiliated generation holdings, not just the facilities of SDG&E. - -------------------- Among other things, the post-merger entity will be positioned to (a) provide preferential access to system operational information to its affiliates, giving them unique ability to avoid certain transportation cost increases, or employ its operational discretion to ensure that such costs do not accrue to its generation affiliates; (b) restrict or deny access to its monopoly services (through, e.g., custody cuts or Rule 30 declarations), thereby raising its generation affiliates' rivals' costs; (c) employ discretion in the pricing of transportation and related services with preferential consequences to its affiliates; (d) manipulate the price of natural gas in the physical (primary) natural gas market (through the timing of its core procurement and injection decisions) in a manner favorable to its affiliates' purchasing needs; and (e) withhold strategic capacity rights it controls out of the marginal supply basins of the Southwest (thereby artificially increasing demand) in order to artificially raise the price of natural gas from those basins to supracompetitive levels. 59 IID claims that, in addition to the FERC's findings with respect to the southern California wholesale electric market, the merger poses the threat of anticompetitive effects in two other product and geographic markets that are not amenable to mitigation: (1) the elimination of potential pipeline bypass competition in the southern California delivered gas market and (2) the elimination of actual potential competition in the forthcoming deregulated southern California retail electricity market. The merger's other adverse effects on competition arise, IID believes, because it gives the merged company the ability to leverage SoCalGas's market power in the upstream southern California delivered gas market into monopoly profits in the downstream southern California wholesale and retail electric markets. IID says the merged company will wield its merger-created market power in connection with California's shift to market-based electricity pricing at the wholesale and retail levels, and will thus be free to a considerable extent from the restraints that cost-of-service ratemaking imposes on pricing. Also, the merger enables the leveraging of SoCalGas's monopoly position in the southern California delivered gas market into the price of gas-fired generation that will, in turn, assume an increasingly significant role in setting market prices in the Power Exchange through which most of California's electricity will be bought and sold. IID argues that applicants' merger-created vertical market power has ramifications beyond basic manipulation of the market-clearing price of electricity through the merged company's control of the price of delivered gas in southern California. It says the merged company would have the ability to increase volatility in the Power Exchange clearing price and thereby create barriers to entry by new generation into California's electricity markets. The merged company's ability to 60 leverage SoCalGas's monopoly position in the southern California delivered gas market into the Power Exchange price setting would also enable the merged company to dictate profitable outcomes in financial derivatives related to California's electricity markets, either as a means of enhancing its own monopoly profits or as a means of creating financial insecurity on the part of its competitors. IID argues that virtually all of the adverse effects on competition that would result from the proposed merger are "vertical" in the sense that they follow from the integration of SoCalGas's market power in the upstream delivered gas market into the downstream wholesale and retail electric markets in southern California. The merger makes a difference in that it creates vertical anticompetitive effects, in addition to those found by the FERC, in southern California wholesale and retail electricity commodity markets, and in financial markets related to those commodity markets. IID's witness explained that the problems that the FERC found to exist with reference only to the integration of SoCalGas's upstream market power with SDG&E's existing generation-i.e., the creation of the ability of a monopoly gas supplier to reap monopoly profits in the downstream electric markets-are readily exacerbated through the merged company's construction or acquisition of additional generating capacity with the ability to bid into the Power Exchange. This sort of activity constitutes a significant part of the business plan of the applicants' Energy Pacific joint venture. Indeed, negotiations are already underway to transfer to Energy Pacific the partial interest of Enova Energy in a 450 MW gas-fired merchant generating plant proposed to be constructed in Nevada. IID refers to applicants' own evidence that gas-fired generation in southern California will be "on the margin"-i.e., setting the market clearing price in the Power Exchange-during 53.6% of all hours, and during 74% of peak hours (when the market clearing price is expected to be highest). SoCalGas has the exclusive ability to supply gas to 96% of that gas-fired southern California generation. Finally, IID asserts that applicants' proposal to expand their corporate family to include AIG Trading Corp.-the nation's tenth- largest natural gas marketer, an active trader in both physical and financial contracts for electricity and gas-is 61 troublesome. It demonstrates, in IID's opinion, that applicants are preparing to capture monopoly profits from the exercise of market power in the delivered gas market through electricity derivatives trading. Applicants argue that the flaws in intervenors' vertical claims trivialize those claims. They note that the bulk power market in which the generators served by SoCalGas operate is highly competitive. Thus, even if SoCalGas could manipulate gas prices as alleged, competition from generators not served by SoCalGas, and the fact that gas is not the marginal, price-setting fuel in many hours, would substantially undercut any effort by SoCalGas to raise PX prices. Nor could SoCalGas benefit its affiliates' trading positions in futures contracts, even assuming, again, that it could manipulate gas prices as alleged. Applicants' analysis shows that the considerations that drive gas and electricity futures prices are not the fluctuations in spot prices that SoCalGas is allegedly capable of creating, but rather more fundamental factors such as weather, general levels of storage inventories, or the outage of a major generating facility. In any event, Pacific Enterprises did not need a merger to trade in futures contracts; as intervenors' own testimony states, Pacific Enterprises is already doing so. Applicants point out that the Attorney General's opinion affirms this analysis. In particular, the opinion finds that, because the WSCC is an integrated regional market, "out of state suppliers would defeat any attempt by the merged entity to manipulate the price of wholesale electricity sold in southern California." It also finds that, in the future restructured electric market, former inframarginal generation, may, by bidding into the PX on the basis of opportunity cost, become a marginal supply source, displacing gas-fired generation as marginal generation. Similarly, the opinion finds that the merger would not enhance any existing ability of SoCalGas to profit in the futures market and that, in any event, "adverse effects upon competition within the futures markets-which are characterized by their liquidity and ease of entry and exit-are extremely unlikely." On that basis, among others, the Attorney General finds the vertical effects of the merger to be "negligible." Applicants assert that even if it is assumed that SoCalGas could manipulate gas prices by the various stratagems concocted by intervenors, the links 62 between gas prices and electricity prices are tenuous at best because of the competitive pressure of generators not served by SoCalGas, and because in many hours, gas does not set the PX price. Whether or not the evidence flatly precludes the possibility that SoCalGas could influence electricity prices, it plainly shows that any such influence would at most be minor, certainly of a far smaller dimension than suggested by intervenors. The fundamental questions are: (1) whether the hypothesized maneuvers would be reasonably likely to escape detection by this Commission, by other market participants, or by the PX-Independent System Operator (ISO) monitoring units, and (2) whether they would be profitable to the merged entity at all. Applicants maintain the answer to both questions is no; it is only by piling one improbable assumption on another that Edison, IID, and other intervenors can fabricate any vertical market power threat. Discussion Here we are concerned with the market power of the merged entity- whether the combination of SoCalGas and SDG&E will increase market power of either company to the detriment of competition. No party has argued that the merger will increase SDG&E's market power. The argument has always been directed towards an increase in SoCalGas's market power. We have already agreed that SoCalGas has market power; we have also noted that making a strong company larger and stronger does not by itself adversely affect competition. (Re PacTel/SBC Merger, D.97-03-067 at p. 43.) In sections below (III.B(4)(c)(d)) we find that divestiture of SDG&E's gas-fired generation and divestiture of SoCalGas's options to purchase the California assets of Kern River pipeline and Mojave pipeline are necessary to eliminate the incentive of the merged company to benefit SDG&E's generation to the detriment of competing generation, to mitigate the loss of SDG&E as a potential bypass candidate, and to increase competition. The manipulative schemes imputed to the merged entity are sheer speculation and, even if they were executed, can be accomplished by SoCalGas and its affiliates without help from SDG&E and its affiliates. The assertion that the merged 63 company can increase volatility in the PX clearing price and thereby create a barrier to entry by new generation is not supported by persuasive evidence. The Attorney General argues, and we agree, that out-of-state suppliers will compete for sales of wholesale electricity sold through the PX, and their participation will equalize prices between the PX and the larger market. Any differences between the PX price and the prevailing wholesale price would also be disciplined by marketers and California utility customers who would bypass the PX and arrange direct purchases from out-of-state sources. The argument that the merged company will use inside information to dictate profitable outcomes in financial derivatives falls of its own weight. We will not presume that officers of the merged company are prepared to conspire to violate criminal statutes and Commission regulation. 4. Mitigation of Market Power a) Applicants' Response to FERC Order No. 497 Conditions In its decision giving conditional approval of this merger, the FERC required applicants to comply with its Order 497. In response, applicants submitted to us 23 remedial measures. (Those measures are set forth in Attachment B and are referred to as "Standards".) The first 11 measures are to implement Order 497. In addition to Order 497 compliance, SoCalGas has proposed the following remedial measures not required by the FERC order: (1) SoCalGas will further separate its Gas Operations and Gas Acquisition functions; (2) SoCalGas will restrict information flow with regard to financial positions in futures markets; (3) SoCalGas will seek prior Commission approval of transportation rate discounts or rate designs offered to any affiliated shipper; and (4) SoCalGas will post information regarding the operation of the SoCalGas system so that all parties may be satisfied that SoCalGas is not attempting to manipulate the operation of its system to benefit affiliates. SoCalGas and SDG&E must abide by the Commission's gas marketing affiliate transaction rules, as adopted in D.91-02-022, that apply to the relationship between gas utilities and their gas marketing affiliates, as well as those 64 adopted in D.97-12-088. Pursuant to the FERC order, both SDG&E and Enova Energy Inc. have filed standards of conduct as have Pacific Enterprises subsidiaries Pacific Interstate Transmission Company (PITCO) and Pacific Interstate Offshore Company (PIOC), both subject to FERC jurisdictional standards of conduct. Applicants also have committed to the FERC to treat AIG as a gas marketing affiliate. Further, AIG has submitted its own standard of conduct to the FERC, and has committed to post transactions between AIG and SoCalGas involving discounts. The Order 497 conditions require SoCalGas to apply its tariff provisions relating to gas transportation in the same manner as for similarly situated shippers if there is discretion in the application of tariff provisions, and to strictly enforce a tariff provision for which there is no discretion in its application (Order 497 Standards A, B). SoCalGas is precluded from providing SDG&E, AIG, or any other marketing affiliate any preference over nonaffiliated shippers in matters relating to transportation scheduling, balancing, storage, or curtailment priority (Order 497 Standard C). SoCalGas must process all similar requests for transportation in the same manner and within the same period of time (Order 497 Standard D) and SoCalGas may not disclose information obtained from nonaffiliated shippers or potential nonaffiliated shippers to marketing affiliates or to employees of SDG&E engaged in the gas or electric merchant function, unless the prior written consent of the parties to which the information relates has been voluntarily given (Order 497 Standard E). If SoCalGas provides information related to its transportation services to its marketing affiliates or to employees of SDG&E engaged in the gas or electric merchant function, SoCalGas is required to disclose such information contemporaneously to all potential shippers, affiliated and nonaffiliated, on its system (Order 497 Standard F). For purposes of contemporaneous disclosure requirements in all of the rules proposed in this proceeding, SoCalGas will post information on its GasSelect EBB. The Order 497 conditions further require that, to the maximum extent practicable, SoCalGas's operating employees and employees of its marketing affiliates, including employees of SDG&E engaged in the gas or electric merchant function, shall operate independently of each other (Order 497 Standard G). 65 Applicants have proposed conditions that were not required by the FERC. Remedial Measure No. 19 takes the FERC's Order 497 rules regarding discounts to affiliated shippers a step further by requiring SoCalGas to seek prior Commission approval of any transportation rate discount or rate design agreement offered to any affiliated shipper on the SoCalGas system. Remedial Measure No. 19 will permit interested parties the opportunity to see the nature of the discounts or rate design provided to affiliated shippers and to request a similar discount or rate design. Applicants are willing to accept certain clarifications suggested by intervenors. SCUPP claims that applicants have not literally complied with the provisions of FERC Order 497 in that the wording of some of the conditions varies slightly from the language of the FERC's regulations. Applicants do not see any material difference between their proposed Remedial Measures and the specific language of the FERC's regulations cited by SCUPP. Accordingly, applicants have no objection to replacing the word "will" with "shall" and eliminating the "reasonable steps" language from Remedial Measure No. 4. Applicants also have no objection to the suggestion of Edison to eliminate the word "its" from Remedial Measure No. 6. As a further clarification, applicants intended that the language in proposed Remedial Measure No. 13, that the merged company shall not permit any employee or third party to be used as a conduit to avoid enforcement of the rule, apply to all of the rules proposed by applicants. SCUPP believes out that applicants' proposed conditions do not include all of the commitments made by applicants in their testimony. Applicants have no objection to the following items being included as specific merger remedial measures as identified by SCUPP: SoCalGas shall provide any customer requesting a transportation rate discount an analysis of whether the discount would optimize transportation revenues; and SoCalGas shall provide a transportation rate discount if it will optimize transportation revenues, regardless of any impact on affiliate revenues. Applicants will incorporate these changes in the compliance plan they will file. This compliance plan will put all of the affiliate transaction rules into a single document, 66 including the rules from the Affiliate Transaction Rulemaking, and applicable existing rules such as this Commission's gas marketing affiliate rules. Intervenors have criticized applicants' use of language that is drawn directly from the FERC's regulations. For example, Edison criticizes the FERC requirement of "contemporaneous" disclosure of certain information within 24 hours, even though this is the FERC rule. Intervenors are also critical of the use of the term "similarly-situated," even though this is a term taken directly from the FERC's regulations. Applicants agree that SoCalGas shall not share noncore customer information with any of its affiliates, or with those employees at SDG&E engaged in the gas or electric merchant function, except as permitted by this Commission's affiliate transaction rules. ORA recommends that to ensure any future negotiated gas transportation contract between SDG&E and SoCalGas will be negotiated at arms' length, and to avoid anticompetitive impacts, Commission approval be obtained of any gas transportation contract between SDG&E and SoCalGas prior to execution and that SoCalGas file an application within 30 days following approval of the merger identifying and proposing means to mitigate any potential discriminatory impacts of the transportation rates for SDG&E's utility electric generation (UEG) facilities relative to other generators. Applicants have no objection to ORA's recommendation, with the understanding that the applicants do not agree that a rate design for any customer that reflects a demand charge/volumetric charge approach is either anticompetitive or discriminatory. In our opinion, applicants have complied with FERC Order 497. The additional restrictions and modifications offered by applicants are reasonable and should allay fears of manipulation, although we doubt any measures taken by applicants would satisfy intervenors. We see no need to impose additional restrictions. Our Affiliate Transaction decision is adequate. We are confident that should the FERC require changes to applicants' Order 497 response, applicants will comply. 67 In order to ensure that applicants comply with Attachment B, we will create an independent verification process to protect abuses of market power. This verification will be accomplished by an independent firm, such as an accounting or consulting firm, with the necessary technical expertise regarding the operations and control of natural gas systems. The firm will be hired by the Commission, and shall not have any significant conflict-of-interest with either the applicants or other market participants. The costs of the firm will be paid by applicants' shareholders. The firm will be hired as soon as possible and the initial term of the contract shall be for 12 months. The contract shall not be effective until approved by a vote of the Commission. In our Gas Strategy proceeding the Commission may choose to amend, extend, or terminate the contract. The firm's duties shall be to monitor, audit, and report on how the combined utilities a) operate their gas system, b) comply with adopted safeguards to ensure open and nondiscriminatory service, and c) comply with the restrictions and guidelines in Attachment B. The firm shall have continuous access to the gas control rooms of applicants, and to all appropriate records, operating information, and data of applicants. The firm shall report to the Commission as appropriate and shall immediately report any violations of the safeguards contained in Attachment B or abuse of market power. The Commission may take further action as appropriate. If directed by the Commission, the firm will prepare a report for the Commission's use in the Gas Strategy proceeding on the adequacy of applicants' safeguards and may submit additional recommendations. 67a b) Changes to Wholesale Gas Cost Allocation and Rate Design Several intervenors have attempted to use this merger proceeding to obtain changes to existing Commission policy regarding wholesale cost allocation and rate design. Parties have raised the same issues that they have raised in past cost allocation proceedings, but have failed to explain how the merger is connected to proposed policy changes that the Commission has rejected before. In certain cases, parties are clearly just seeking a handout from the Commission as compensation for the merged company's alleged market power. These concerns have nothing to do with this merger, and are rejected. For example, Vernon recommends that all wholesale customers (presumably including Vernon, even though it is not yet a true wholesale customer) be provided the same transmission rate that SoCalGas has proposed to provide to DGN, the shipper of gas across the SoCalGas system for delivery to Mexicali. The transportation rate to be provided DGN is a rate intended to compete with alternatives available to Mexicali to natural gas service through the SoCalGas system. The proper forum to examine this issue is in SoCalGas's next BCAP. Similarly, there is no reason to consider in this proceeding SCUPP's proposal that the Commission order a uniform one-part volumetric gas transmission rate design for all electric generators served by SoCalGas and SDG&E. A one-size rate design may not fit all. And this type of request should be made in a proceeding where all parties are focused on rates, not mergers. SoCalGas will file a tariff for all shippers transporting gas to the SDG&E service territory. SoCalGas also will execute separate transportation and storage service agreements for SDG&E's UEG and its nonUEG loads. Finally, SoCalGas will submit all contracts with SDG&E (or any other affiliate) that deviate from Commission-approved tariffs for prior Commission review and approval, including any discounted transportation agreements or rate design agreements. This provides all parties with a chance to object or to claim they are similarly situated and entitled to the same treatment. 68 c) Divestiture of SDG&E's Existing Gas-fired Electric Generation Facilities ORA takes the general position that divestiture of all generation facilities of all California investor-owned utilities is required in order to mitigate their market power and assuage other competitive concerns. It asserts that the proposed merger of SoCalGas and SDG&E in conjunction with the advent of a competitive electric market only increases the conflicts of interest and potential for market abuses by creating an additional vertical market relationship. It says in order for a competitive market to thrive, SoCalGas should not have an interest in providing preferential treatment to its affiliate SDG&E's electric generation. The most direct and effective means to avoid such potential conflict of interest, and to mitigate the regulatory burden of attempting to police such affiliated transactions, is simply to order the divestiture of SDG&E's gas-fired generation. It recommends that the Commission order SDG&E to file a divestiture application within three months following approval of the merger. TURN/UCAN, the Attorney General, LADWP, and SCUPP support ORA. In its merger decision, FERC commented "Another method of eliminating the vertical market power problems discussed herein would be divestiture by SDG&E of gas-fired generation plants. However, this remedy also would require the authorization of the California Commission." (79 FERC Order at 62,565 fn. 58.) On November 25, 1997, SDG&E announced its intention to divest all of its gas-fired generation facilities, its 20% interest in SONGS, and its interest in any power purchase agreements, including qualifying facility (QF) contracts. SDG&E intends to seek the regulatory approvals necessary to accomplish this divestiture. On December 1, 1997, the presiding ALJ requested supplemental briefs on the issue of SDG&E's gas-fired generation divestiture. Applicants responded, as did ORA, the Attorney General, IID, SCUPP, Edison, and Vernon. IID, SCUPP, Edison, and Vernon all believe that the divestiture is meaningless. IID argues that SDG&E's divestiture of generation assets is neither a necessary nor a sufficient condition to mitigate the market power created by applicants' proposed merger. IID says that its assessment of the ineffectiveness of the sale of 69 SDG&E's generation assets as a means of market power mitigation recognizes that the basic vertical market power problems posed by this merger will arise under any circumstances in which SoCalGas is permitted to leverage its upstream monopoly in the southern California delivered gas market into downstream, and unregulated, electricity markets. The merged company's ownership or control of SDG&E's generating assets is but one of several means through which the merged company will be capable of exercising vertical market power. IID contends that the merged company's ownership or control of any generation producing output that can be bid into the PX will enable the same anticompetitive result. SCUPP, Edison, and Vernon make essentially the same argument. The Attorney General says that the divestiture reinforces his conclusion that the merger will not adversely affect competition in the wholesale electricity market; it resolves all issues about competition in the wholesale electricity market raised in his Section 854(b) opinion. ORA, of course, supports divestiture, but is concerned about details. It points out that SDG&E's announcement is not binding on SDG&E. Even if SDG&E does enter into an agreement to sell its generation assets, the sale will be subject to Commission approval, which may not be granted to the satisfaction of the buyer and seller. As the Commission should not base its decision on an assumption that the sale takes place, ORA proposes that the Commission order the divestiture of SDG&E's gas-fired electric generation. Applicants believe a divestiture order is unnecessary. Discussion SDG&E's announcement regarding divestiture accepts a mitigation measure sought by ORA, the FERC, and others. We agree with ORA that divestiture should be ordered with assurance that the divested plant will not go, directly or indirectly, to an affiliate. The concerns of those who claim that this divestiture is inadequate are discussed elsewhere in this opinion. 70 d) Divestiture of Kern River and Mojave Options to Purchase Kern River competes with SoCalGas in providing gas transportation services to end-users in southern California who have, or who are in a position to acquire, the ability to take service directly from Kern River's pipeline. Kern River's shippers include producers and marketers who sell gas to SoCalGas's retail and wholesale customers, including SDG&E and customers on SDG&E's system. The proposed merger will significantly affect the principal market where Kern River does business, southern California. Mojave competes with SoCalGas in the same manner as Kern River. Kern River's gas pipeline system originates in southwestern Wyoming and extends from the Rocky Mountain Overthrust Belt gas producing area to terminal points in Kern County, California. Kern River's system includes 322 miles of pipe in California. Kern River's single largest market consists of the enhanced oil recovery (EOR) operations and cogeneration projects associated with the heavy oil fields of Kern County. Kern River's system also interconnects with the gas transmission facilities of both SoCalGas and PG&E and serves loads attached to those systems. In addition, the system's location allows Kern River to offer potential customers in southern California a direct connection to Kern River's system on terms competitive with those available from the existing transmission providers. Kern River's system was designed to transport 700,000 thousand cubic feet (Mcf) of gas from the Overthrust region to the Kern County oil fields on an average summer day. Moreover, the system is designed to be substantially expanded through the addition of compression. Capacity can be increased by 70%, i.e., up to a total of 1,200,000 Mcf/day, at an estimated cost of roughly 35% of the cost of the original system. Kern River commenced service to its customers in February 1992. Throughput on the system grew steadily for the first several months, before reaching a load factor that has remained at consistently high levels. Mojave's 30" pipeline is designed to transport 400,000 Mcf/d from southwestern United States gas fields through Topock, Arizona to SoCalGas's interconnection in Kern County. 71 Kern River and Mojave believe that the proposed merger would have short-term and long-term adverse effects on competition in the market for gas transportation services in southern California. They assert that a critical element of these adverse effects is SoCalGas's contractual options to acquire the California facilities of Kern River and Mojave in the year 2012. Those options, acquired in 1989, give SoCalGas the right to eliminate its only meaningful pipeline competitors in southern California just 15 years from now, well within the time horizon typically used in the gas transmission and distribution industry for long-term supply contracts. SoCalGas holds its option pursuant to a 1989 agreement between SoCalGas and Kern River. The option is exercisable 20 years after Kern River's commencement of service, i.e., in the year 2012, and encompasses the existing California system and any additions to the system within California. If SoCalGas exercises the option, the parties will negotiate a purchase price for the facilities. SoCalGas has a similar option to purchase the California facilities of Mojave, its only other interstate pipeline competitor. Kern River and Mojave point out that new gas transmission competitors do not appear overnight. The gas transmission industry is characterized by high capital requirements for new systems. Kern River's system, the first independent interstate pipeline to enter the state, was proposed in 1985, but did not commence service until 1992. The barriers to entry remain formidable. A new independently owned pipeline from gas supply areas to California would confront an extended regulatory process, vigorous regulatory opposition and economic competition from incumbents, and a lengthy construction period. Kern River and Mojave ask us to consider that, within the time frame relevant to consideration of this merger, SoCalGas has the contractual right to eliminate from the marketplace its only significant gas transmission competitors. If it does, SoCalGas will be able to escape throughout all of southern California the discipline of the marketplace in providing gas transportation service to California consumers. The Commission's regulatory supervision of SoCalGas would no longer be complemented by competitive checks and balances on SoCalGas's behavior, because 72 there would be no credible competitive alternatives to SoCalGas's control of essentially all gas pipelines in southern California. Kern River actively competes with SoCalGas. It is highly motivated to locate and capitalize on market opportunities in all of the regions it serves, including California. Kern River has a large capacity system that can be economically expanded and the pipeline's route passes relatively near substantial existing loads on SoCalGas's system. Kern River is actively marketing its transportation service in California. Kern River's capability for relatively inexpensive, large-volume expansion (i.e., up to an additional 500,000 Mcf/day solely through additional compression) virtually guarantees that Kern River will be a major competitive force confronting SoCalGas in the years following the merger, if it is not hindered by barriers like SoCalGas's purchase option. Kern River believes that the merger would result in adverse competitive effects because it creates vertical market power for the merged companies. The merged companies would have the capability to manipulate price and nonprice terms for natural gas transport and related services with the purpose of affecting competitive outcomes in California's restructured electricity business. Kern River recommends that should the merger be approved, it should be conditioned so as to preserve an aggressive competitor, by striking the option SoCalGas has to purchase the in- state facilities of Kern River, as well as the comparable option for Mojave. This option impedes Kern River's ability to compete today and, if exercised, would eliminate Kern River as a competitor altogether by the year 2012. With the merged companies in place and functioning in an increasingly deregulated marketplace, the proven consumer benefits of having Kern River as an active competitor will furnish a counterweight and market discipline. Mojave's argument echoes Kern River's. Mojave states that the present prospect of SoCalGas's exercise of its options to purchase has had a chilling effect on both investors and end-user customers alike in terms of sponsoring pipeline capacity additions or extensions that might compete against SoCalGas. Given SoCalGas's options and the considerable lead time associated with significant pipeline 73 projects, Mojave believes that a new entrant, considering a major pipeline extension from either Kern River or Mojave, would face the prospect that its competitor, SoCalGas, would acquire the upstream facilities before it could recover its investment. While the new entrant could insist on rates that would depreciate its investment prior to SoCalGas's exercise of its options, the higher rates associated with the shorter depreciation schedule would undermine the new entrant's ability to attract a customer base. The market power attributable to the SoCalGas options is further enhanced as time passes and a new entrant's possible need to recover costs over a shorter time frame would discourage customer commitments. In regard to the 2012 option date, Mojave is concerned that the long-range planning required for the construction, financing, and/or acquisition of a major fuel consuming facility must consider costs and stability of source. Fifteen years falls within relevant long-range planning parameters. Given the forward assessments required in the planning stages of major fuel using projects, if it were known that the fuel transporter proposed for a project would very likely be acquired by its principal competitor, that prospect would have a negative effect on the proposal. Removing SDG&E as potential customer for either Kern River or Mojave as a consequence of the merger will enhance the value of the SoCalGas options and will operate, for all practical purposes, as a market entry barrier to assure neither actual nor threatened competition in southern California's natural gas markets. The threat of exercising the options will enable SoCalGas to eliminate from the southern California marketplace its only gas transmission competitors and avoid the discipline of the marketplace in providing gas transportation service to California consumers. Applicants argue that the Commission must not allow Kern River to use this merger proceeding to escape from a material term of a settlement agreement with SoCalGas that provides SoCalGas the option to purchase Kern River's California facilities in 2012 to bring them within the jurisdiction of this Commission. This issue is not related to the merger at all since SoCalGas's affiliation with SDG&E has nothing to do with the Kern River option. The Commission should retain the agreement it approved and not try to prejudge market conditions as they will exist 15 years from 74 now. They contend that SDG&E is just one of many customers that could support a bypass pipeline. Noncore throughput excluding SDG&E's load exceeds 1 Bcf/d, well above Kern River's admitted low-cost expansion capability. Even removing a large customer like SDG&E from that assessment, there remains a significantly large volume of load on the SoCalGas system to support a 500 MMcf/d bypass pipeline. Although SoCalGas has the contractual option to purchase Kern River's California facilities, this option has not stopped Kern River's California marketing activities. Applicants maintain that SDG&E may not be the ideal anchor tenant of the future as Kern River, IID, and others seem to believe. SDG&E has considered bypass in the past and each time concluded that it does not make economic sense. Moreover, SDG&E may in the future no longer sell gas to its noncore load. That load, combined with other load in southern California (such as Edison's divested plants) is at least as plausible an anchor tenant as SDG&E. Moreover, electric industry restructuring will likely subject SDG&E's generation units to greater competition, adding future uncertainty to its UEG gas use. For example, under either unbundling or a scenario under which market conditions displace SDG&E's UEG, SDG&E as a bypass customer may represent only 125-200 MMcf/d (compared to 300 MMcf/d today). LADWP, individual Edison plants (and clusters of Edison plants in close proximity), other industrial customers, and future merchant facilities represent comparably sized customers. Applicants argue that the option to purchase Kern River's facilities was an arms' length commercial negotiation. They assert the Commission supported the option agreement in large part because the facilities would become Commission-jurisdictional if SoCalGas exercised the option. Although market conditions may have changed compared to when Kern River concluded the negotiation with SoCalGas and Kern River's actual deliveries to the EOR market may be lower than Kern River had originally planned as lower oil prices have reduced the expectation for EOR gas demand, Kern River's throughput continues to exceed a 100% load factor. The proposed merger with SDG&E does not fundamentally change the competitive market situation, and therefore provides insufficient reason to compel SoCalGas to divest the 75 purchase option. Since the asset purchase requires Commission approval, the Commission need not act now on this matter without knowing market conditions well into the future. The Commission should not allow Kern River to use this merger proceeding to bail it out of a bargain it now would like to disavow. Discussion SoCalGas has near-monopoly control over facilities used for the transport and storage of natural gas for electric power plants within southern California. And, with regard to interstate transport facilities, SoCalGas has been judged by the FERC to have market power due to the concentrated control of interstate transport to southern California in general, and SoCalGas's control of close to 30% of the capacity for deliveries of gas from the San Juan Basin in particular. Furthermore, the opportunity for SoCalGas to exercise such vertical market power is substantial since it serves 42 different electric power plants with a total of 15,837 MW of generating capacity. This 15,837 MW of gas-fired generating capacity constitutes 94% of all gas-fired capacity in southern California. Because gas-fired generation will dictate the market price of electricity in California much of the time, there could be significant consequences for failing to effectively mitigate the vertical market power created by the proposed merger. Indeed, if the mitigation is not effective, the success of electric industry restructuring in California could be undermined. Kern River has not only brought benefits to the customers it directly serves, it has benefited all gas consumers in the region by introducing competition for gas supply and transport. Kern River gave southern California access to new and lower cost gas supply regions (Rocky Mountain and Canada) as well as diversification which increases gas supply reliability and flexibility for southern California. In addition to providing a higher level of reliability to EOR customers, the price is lower, too, because Kern River provides access to lower cost gas supply. There are savings in general because SoCalGas has had to lower its rates (offer discounts) in order to compete. Kern River also benefits southern California consumers whom it does not directly serve. First, for at least some customers, it forces a local distribution company (LDC) like SoCalGas to compete on quality and price of service. For example, some of 76 SoCalGas's noncore customers have benefited from discounts that SoCalGas offered in response to the competitive presence of Kern River, Mojave, and others. SoCalGas makes this same point itself. SoCalGas, for example, in its 1996 Annual Report said that "SoCalGas is continuing to reduce its costs to maintain competitive rates to transportation customers to avoid losing these noncore customers to a competing interstate pipeline." Core customers have not been negatively affected by the new interstate competition. Comparing the core residential rates in 1991 (before Kern River) and the rate in 1995 (after Kern River), we see that SoCalGas, who had been hit the hardest by bypass, had an 3.3% decrease in residential rates compared to PG&E and SDG&E, which experienced a total of an 8% increase and a 14.4% increase in residential rates over the same four-year period, respectively. SoCalGas's witness testified in the company's 1996 BCAP, that SoCalGas's core weighted average cost of gas "declined from $2.45 MMbtu in 1989/1990 to less than $1.40/MMbtu in 1995." This decline was due, in part, to the impact of gas-on-gas competition created by new interstate capacity. That the Kern River pipeline has caused gas transportation rates to fall cannot be denied. This Commission has authorized numerous reductions of SoCalGas's tariffed rates to prevent bypass. When SoCalGas seeks such authority, it frequently cites the potential for bypass caused by Kern River. SDG&E's own witness testified to the efficacy of the threat of bypass to keep transportation rates down. He said SDG&E has considered bypass and concluded it did not make economic sense; that SoCalGas could beat the competition. We have no doubt that the primary competitive force that disciplines SoCalGas's pricing behavior for gas transportation within southern California is the threat of construction of gas transportation facilities that would enable customers to bypass the SoCalGas system-that is, the threat of potential entry by a competitor into SoCalGas's monopoly area. SoCalGas has historically viewed SDG&E as a significant potential bypass threat, and has entered into at least one agreement that recognized the economic value to SDG&E of the leverage that a bypass threat affords. The 1994 Project Vecinos agreement between SoCalGas and SDG&E concerns development of natural gas transportation projects to deliver gas to the U.S.- 77 Mexican border for consumption in Mexico. As part of that agreement, a rate was agreed to which was "calculated to compensate SDG&E for the lost opportunity value of not utilizing an alternative pipeline located in Baja, California to bypass SoCalGas's system." Clearly SDG&E has considered itself an anchor tenant for a possible new pipeline and has used that threat to obtain favorable rates from SoCalGas. To eliminate the strongest potential threats-Kern River and Mojave-by permitting SoCalGas to exercise its options and own all pipelines in southern California would contradict all of our recent pronouncements regarding the benefits of competition. We acknowledge that in 1990 we conditioned our support for the Kern River and Mojave pipelines on their grant of the options to SoCalGas. At the time we felt that having all pipelines in California under our jurisdiction was a valuable adjunct to our ability to administer reasonable rates. (D.90-10-034; 38 CPUC2d 6.) We are also aware of one consequence of bypass: that those customers remaining on the SoCalGas system might be required to pay increased rates to compensate for the lost revenue caused by the bypass. Nevertheless, we have chosen competition and therefore competitors and the threat of competition must be encouraged. Our experience has been that core rates have declined due to gas-on-gas competition caused by Kern River's and Mojave's entry into the California market. We find that Kern River and Mojave are strong competitors and should be supported, not eliminated. We will condition our approval of the merger on SoCalGas's divestiture of its Kern River and Mojave options to purchase. However, divestiture will not be the result of an order of relinquishment as requested by Kern River and Mojave, but as the result of a sale. The options were bargained for and have value. That value should be determined in an open market and inure to the benefit of SoCalGas's shareholders. The Attorney General recommends that we require SoCalGas, as a mitigation measure of SDG&E's acquisition, to auction volumes of its intrastate transmission rights equal to SDG&E's use. We are of the opinion that such an auction is unnecessary in light of our requiring divestiture of the options to purchase the Kern 78 River and Mojave facilities. Having a competing pipeline is a much more effective mitigation measure. e) Restrictions on Post-Merger Subsidiaries Various intervenors have suggested that restrictions be placed on future subsidiaries of the merged company such as a restriction preventing any subsidiary from owning electric-generating capacity in the WSCC. The basis for these remedies is the intervenor contention that regulation by this Commission is insufficient to protect against vertical market power abuse. Intervenors' proposals and related contentions regarding Commission regulation do not have merit. We have already discussed why we believe SoCalGas will not manipulate gas prices, much less electricity prices. Intervenors ignore the fact that this Commission has comprehensive regulatory jurisdiction over both SoCalGas and SDG&E, who will remain Commission-regulated utilities after the merger. Our comprehensive authority and enforcement powers ensure that SoCalGas and SDG&E will not engage in the market manipulations alleged by intervenors. The FERC has similar power. Courts and other agencies (such as the Department of Justice and the Securities and Exchange Commission) protect against market power abuse and the sort of insider trading alleged by intervenors. The hypothetical vertical market power abuses raised by intervenors are unfounded. f) Divestiture of Transmission, Storage, and Distribution Edison, IID, and others assert that the Commission must impose structural remedies on the merged company to prevent it from abusing vertical market power over delivered gas prices and services to the detriment of competition in downstream California electricity markets. They say the merged company will control the California gas market through its operation of SoCalGas's large intrastate transportation and storage monopoly. They claim SoCalGas will use its discretion to operate its system operations in many ways to favor its affiliates and disadvantage their competitors. It does not need to provide its affiliates with any operational information to accomplish this result. These discretionary activities undertaken by SoCalGas in its operational judgment will be nearly impossible to monitor, detect, and police. In 79 intervenors' opinion, SoCalGas will not operate the system in a manner that will make its preferential affiliate treatment obvious. Rather, SoCalGas will likely engage in those activities episodically and opportunistically when it will be difficult to distinguish those activities from legitimate system operations. SoCalGas will not simply raise prices or refuse service requests from competitors. These parties contend that only structural remedies can ensure that the operator of the pipeline infrastructure has no interest in manipulating it to advantage affiliates in downstream electricity markets and disadvantage its affiliates' rivals. To prevent the exercise of market power and to check the discretionary operational activities by the merged company and SoCalGas that could unfairly advantage SoCalGas's affiliates, Edison recommends the Commission should require that SoCalGas divest its intrastate gas transportation and gas storage system to a nonaffiliated, third party with no incentive to engage in discriminatory or preferential conduct on behalf of affiliated shippers. The new owner would perform discretionary operational activities, but there would be no concerns regarding favoritism. Informational flow concerns would also be eliminated, thereby creating a level playing field for all shippers. Similarly, the Commission should require that SoCalGas shed the 406 MMcf/day of interstate pipeline capacity in excess of the core reservation through an auction to nonaffiliated shippers submitting the highest bids. IID does not agree with divestiture to a third party because such a requirement would simply result in the substitution of a different monopolist. IID recommends the imposition of an ISO to operate SoCalGas's intrastate gas transportation and storage system. Vernon agrees. IID, in addition, recommends that the merged company must be precluded from having a financial interest in any generating unit not currently owned by the applicants that is capable of selling wholesale electric power in California; the merged company must be precluded from transacting (buying or selling) financial derivatives based on electricity that could be delivered to California; and the merged company must be precluded from selling electricity at retail in the present SoCalGas retail gas distribution service area. 80 Under IID's analysis, there is nothing in applicants' proposed mitigation conditions that limits the merged company's discretion to operate SoCalGas's intrastate transportation and storage system in ways that will create advantages for its affiliates. SoCalGas's operational discretion as to system windows, declaring overnomination events, manipulating the availability of storage, and a host of other operational issues remain absolutely unaffected by their proposed mitigation conditions. In addition, applicants' proposed mitigation conditions impose an unwieldly monitoring and enforcement burden on both the Commission and on customers-all of which could be efficiently avoided by the adoption of structural remedies. ORA opposes divestiture of transmission and storage and the appointment of an ISO. It says it is not clear what function the ISO is intended to perform. In the electric industry restructuring, it was determined that an ISO was necessary in order "to meet the critical objectives of providing open, nondiscriminatory access to the transmission grid while preserving reliability and achieving the lowest total cost for all uses of the transmission system" by "coordinat[ing] the actual use of the system and apply[ing] a pricing structure that supports competition and avoids cost shifting." (D.95-12-063 as modified by D.96-01-009, p. 15.) However, these functions are already being performed in the gas industry without an ISO: interstate capacity is unbundled for noncore customers, gas commodity is unbundled, and SoCalGas's intrastate transportation rates are regulated. In addition, to the extent the Commission wishes to restructure the regulation of the gas transportation industry, ORA believes it must be done in the context of statewide gas industry restructuring. It is not appropriate to attempt to address such a proposal in the context of this application. Finally, ORA submits, no party presented evidence of the cost of establishing a gas ISO. The experience in the electric industry is that the cost can be enormous. The intervenors who recommend an ISO have not offered any cost-benefit analysis of the ISO or how it would impact the economics of the proposed merger. TURN/UCAN take a different track in opposing divesting transmission and storage. Divestiture would have adverse impacts on small customers, 81 in their opinion. Their witness testified that divestiture of SoCalGas's transmission and storage facilities would create a situation in which uneconomic bypass of the remaining distribution system would be a constant threat, requiring frequent rate discounting and raising the potential for cost-shifting to small customers. Any customer of significant size that was located within reasonable proximity to a transmission line would seek a direct connection in an effort to avoid paying its allocated share of distribution costs. Even if such construction were totally uneconomic and wasteful from a societal perspective, it would surely be threatened as a lever in negotiations with the residual distribution company. The result could easily become a "death spiral" in which the distribution company found itself continually attempting to raise its rates in order to spread its fixed costs over less throughput. Applicants oppose divestiture for the same reasons as ORA and TURN/UCAN. Applicants add, if the failure to divest were truly harmful to competition or consumers, consumer representatives and the California Attorney General would support this remedy, but they do not because it is clear that such a remedy advantages only competitors, not competition. Furthermore, in the intact system, employee accountability encourages innovation, reduces costs, and permits a seamless response to emergencies and therefore such accountability must remain with the utility. Finally, applicants point out that the merger has no effect on SoCalGas's ability to manipulate the system as alleged; SoCalGas can do it now. Discussion Divestiture of transmission and storage is as drastic a mitigation measure as can be devised short of denying the application. It will not be imposed. The reasons given by ORA and TURN/UCAN to oppose divestiture are persuasive: divestiture, if needed should be statewide; there is no cost analysis; the remaining distribution system would be devastated; the effect on rates for residential and small commercial customers is not considered. Divestiture will help competitors, not competition. Divestiture might lower rates for intervenor electric generators (although we doubt it), but it is likely to raise rates for other customers. We are not persuaded that SoCalGas will contrive to 82 manipulate the system as Edison, IID, and others maintain. Their allegations are the merest speculation, offered not to benefit ratepayers but to benefit competitors. Section 854 requires us to find that the merger "not adversely affect competition." The manipulations perceived by Edison, IID, and others to adversely affect competition could as well be done by SoCalGas alone. The merger does not cause nor increase the likelihood of their employment. g) Gas Purchasing Applicants have withdrawn their proposal to consolidate the gas procurement functions of SoCalGas and SDG&E. Some parties have criticized applicants for not committing never to reconsider the consolidation of procurement functions. It is unnecessary to address this issue at this time as its resolution may depend upon the direction we take in our gas industry restructuring proceeding. Vernon recommends that SoCalGas be required to publish all details of all the gas volumes it purchases, including both the prices and the timing of such purchases. Adoption of this proposal would place SoCalGas's gas acquisition function at a distinct disadvantage as it negotiates with sellers of gas and therefore would increase core gas costs, much the same way that core gas costs would be increased if SoCalGas were to post immediately the requests made by SoCalGas Operations for SoCalGas Gas Acquisition to purchase supplies for delivery at particular receipt points to ensure system integrity. Vernon's proposal is rejected. IV. Is the Merger in the Public Interest (Section 854(c))? A. Will the merger maintain or improve the financial condition of the public utilities involved? The merger of Enova and Pacific Enterprises will maintain or improve the financial condition of both SDG&E and SoCalGas. The existing legal and regulatory status of SDG&E and SoCalGas will continue after the merger. There will be no change in the status of outstanding securities or debt of the two companies, and both will remain separate entities with their own Commission-approved capital structures. In 83 addition, the quantitative measures of financial strength commonly considered by bond rating agencies-pretax interest coverage, funds from operations interest coverage, funds from operations to total debt, internal generation (net cash flow to capital spending), and debt ratio (total debt to total capital)-will improve, or at least stay the same, for both SDG&E and SoCalGas after the merger. Commission oversight over both utilities should help preserve their financial strength. In short, the financial condition of both SDG&E and SoCalGas should continue or improve after the merger. B. Will the merger maintain or improve the quality of service to public utility ratepayers in the state? 1. Customer Service and Assistance Applicants assert that the merger will maintain or improve customer service quality because: (1) customer satisfaction and safe, reliable service will be unaffected by the merger and will continue to remain top priorities; (2) customer service levels are maintained and in some cases enhanced as a result of the merger; and (3) all current low-income program commitments are maintained. TURN/UCAN and ORA take strong exception to applicants' quality of customer service, especially SDG&E's telephone response time. As a result of the merger, applicants will share certain types of calls. TURN/UCAN and ORA say such an arrangement can adversely affect customer service because SDG&E's starting telephone service levels are substandard. Furthermore, applicants propose disproportionate staffing cuts for Customer Service Representatives (CSRs) after the merger which will adversely affect telephone service. TURN/UCAN and ORA state that the evidence shows that service levels are likely to decline as a direct consequence of the proposed merger. In their opinion the decline is attributable to the following: 1. Applicants are proposing to share customer inquiries at their call centers. The absence of an objective service standard at SDG&E will detrimentally impact SoCalGas customers, whose utility has a more stringent and clearly defined call center performance standard. 84 2. The actions of SDG&E's management, including denial of the problem, failure to monitor its contractor for emergency calls, offering non-regulated products and services, and reducing staff while introducing new computer systems, have further aggravated SDG&E's poor telephone performance. 3. Applicants are proposing almost 20% of the merger workforce reductions in the area of customer service, a larger staff reduction than in any other business function. Applicants have not demonstrated how the large staff cuts in call centers can be achieved without adversely impacting telephone service. 4. Applicants do not have a comprehensive system in place to monitor complaints received directly from customers, thus a decline in customer service is not likely to be adequately tracked. TURN/UCAN argue that under SDG&E's PBR mechanism, customer satisfaction is determined by a composite of seven service areas measured by the Customer Service Monitoring System (CSMS) questionnaire. In the PBR of SoCalGas, on the other hand, in addition to survey responses the utility's performance is measured against a standard that 80% of all telephone calls should be answered within 60 seconds, and 90% of all leak and emergency calls should be answered within 20 seconds. Thus, SDG&E's call center performance standard in its PBR is less stringent and less objective than that of SoCalGas. SDG&E's looser performance requirement creates a perverse incentive to serve SoCalGas's customers ahead of SDG&E's. TURN/UCAN presented the following table graphically showing the decline in telephone responses by SDG&E during the recent past: 85 Table 1 SDG&E % CALLS ANSWERED WITHIN 60 SECS. Proposed Standard 80 % Actuals: Jan-96 69 % Feb-96 89 Mar-96 85 Apr-96 85 May-96 76 Jun-96 86 Jul-96 74 Aug-96 69 Sep-96 61 Oct-96 50 Nov-96 67 Dec-96 65 Jan-97 60 Feb-97 67 Mar-97 56 Apr-97 52 May-97 44 Jun-97 33 Jul-97 32 Aug-97 33 86 TURN/UCAN introduced evidence to show that from 1994 to August 1997 there has been an increase of nearly three-fold in call wait times. Callers have waited as long as 38 minutes to reach a customer service representative. An independent survey of SDG&E's call center response time documented the decline in service in 1997, including extensive busy signals and increased wait time. Telephone service levels at SDG&E have declined sharply since the announcement of the merger. TURN/UCAN's witness concluded that SDG&E's performance is below national norms; SDG&E's performance is even worse in emergencies; and SDG&E's performance is worse than its statistics indicate. In response to the problem identified, we are urged to mitigate the merger's impact to the primary stakeholders-the customers. TURN/UCAN recommend the Commission adopt the following mitigation actions: 1. SDG&E's call center should be subject to an objective standard for telephone service levels: 90% of leak and emergency calls should be answered in 20 seconds, and 80% of total calls should be answered in 60 seconds, including all calls contracted to outside services. The penalties for SDG&E's failure to meet this standard should be determined in SDG&E's 1999 Distribution PBR application. The abandoned call rate for SDG&E should also be subject to an objective standard of 5%, with a penalty to be determined in SDG&E's PBR review. 2. SDG&E should be required to report to the Commission on a quarterly basis its monthly level of busy signals received on the 800 numbers. (Applicants have accepted this proposed measure.) The busy report on all calls should be judged against the company's business objective of no more than 3% busies. Busies on emergency calls should be less than that. 3. The mitigation measures 1 and 2 should be met each month for a period beginning with the first complete calendar month after the merger, through the subsequent November 30, or at least six consecutive months, whichever is longer. An Advice Letter should notify compliance with this measure. Failure to comply with this mitigation should result in doubling the penalties (yet to be determined for SDG&E) applicable to telephone standards for the two utilities for the period of one year. 87 4. SDG&E should be subject to a penalty for every 0.1 increase in System Average Interruption Frequency Index (SAIFI), inclusive of major events, above 1.0. A penalty of $325,000 per 0.1 increase in SAIFI should apply. 5. Offerings of non-regulated products and services through the call center by either applicant should be contingent on meeting telephone performance standards for a period of at least three consecutive months. Applicants should report compliance with this measure via an Advice Letter. 6. The planned merger reduction of 55 CSRs should be further substantiated with an Advice Letter documenting how the reductions can be accomplished without reducing service levels. If after these merger CSR reductions the telephone service goals are not met, the PBR penalties applicable to telephone service levels (yet to be determined for SDG&E) should be tripled. 7. Applicants should create a combined centralized tracking mechanism for complaints taken at their call centers and taken by field personnel. The system should contain complaint categories sufficiently narrow in scope so that the utilities will be able to ascertain appropriate remedial measures. Applicants vehemently dispute the position of TURN/UCAN and ORA. Applicants state that SDG&E's outstanding call center performance will not suffer as a result of the merger. They believe that they have shown conclusively that the merger will maintain or improve customer service at both utilities. Moreover, that SDG&E's call center provides quality telephone service is demonstrated by the company's consistently excellent customer ratings. TURN/UCAN's conclusion to the contrary is simply incorrect. Applicants claim that TURN/UCAN used old data and incorrect business standards to bolster their contention that SDG&E's call center service is inadequate. For example, Table 1 above appears to be intentionally misleading. The graph shows the percentage of calls answered within 60 seconds at SDG&E only through July 1997-the month before call answer times returned to normal. Additionally, TURN/UCAN claim that SDG&E did not "meet in any month in 1997" a 88 "business objective of 75 percent or 80 percent of calls answered within 60 seconds." In fact, SDG&E's business objective is to answer 60% of all calls within 60 seconds. Applicants expect customer satisfaction to rise as customers experience SDG&E's new customer information (CISCO) and automated dispatching (SORT) systems. Applicants says the addition of CISCO and SORT presented significant implementation challenges. As a consequence, SDG&E's call center performance-as measured by calls answered within 60 seconds-declined for a period when these advanced systems were being implemented. Contrary to TURN/UCAN's contention, however, this decline had nothing to do with SDG&E's call center offering non-regulated products and services, nor with staff reductions. SDG&E declares that its call center management moved aggressively to improve call answer times. For example, the call center hired and trained new CSRs in the last quarter of 1996 and in 1997 to assist during the transition to the new systems. In addition, three new classes of CSRs completed CISCO training in the third and fourth quarters of 1997 to further support SDG&E's effort to continue providing quality customer service. Due to these and other management efforts, the percentage of customer calls answered within 60 seconds has improved dramatically since August 1997. During the week of September 15-21, 1997, SDG&E's call center answered 73% of all calls in 60 seconds or less. And since then, SDG&E's call center has continued to meet or exceed service level objectives. Discussion The merger must maintain or improve customer service. Specifically, Section 854(c)(2) requires that the merger "maintain or improve the quality of service to public utility ratepayers in the state." We have addressed such customer service concerns in previous Section 854 decisions. (See Telesis and SBC Communications, Inc., D.97-03-067 at 72; and Re SCE Corp. (1991) 40 CPUC2d at 230.) Similar to other merger cases, our decision here must reflect a concern for the merger's impact upon customers and quality of service. On the evidence presented in this case, it is clear that in the recent past SDG&E's customer service telephone response time was below standard, by any 89 measurement. Table 1 is based on SDG&E's own statistics. However, we cannot dismiss out-of-hand SDG&E's explanation that service declined during a period when there was a transition to new operating systems. Technology requires upgrades; upgrades require training time. We take SDG&E at its word that improvements are up and running and that service is improving. But we have two caveats: We are not satisfied with a response time objective of answering 60% of calls within 60 seconds. SoCalGas's response time of 80% within 60 seconds is much more reasonable. This issue is squarely before us in SDG&E's distribution PBR (A.98-01-014) which decision is expected by January 1, 1999. Our other caveat is that as a result of the merger SDG&E expects to eliminate a substantial number of telephone operator positions. Reducing staff to improve service is not a method that immediately springs to mind. 2. Energy Efficiency The Natural Resources Defense Council (NRDC) argues that in the interest of conservation SoCalGas and SDG&E should include a distribution pricing structure that severs the link between retail electricity and natural gas throughput and the recovery of fixed transmission and distribution costs. This, NRDC contends, will encourage cost-effective investments in energy efficiency. NRDC recommends a revenue cap or similar mechanism. It also recommends that the Commission should require a commitment from applicants to actively support the establishment of a public purpose surcharge on natural gas distribution service at a minimum funding level equal to the 1996 authorized level. It explains that public purpose activities should be funded in a manner that avoids or minimizes unfair competition, and captures overlapping benefits between natural gas and electric activities. Establishing a public purpose surcharge for natural gas would relieve pressure from natural gas utilities to cut proven investments in favor of short- term cost considerations, and would increase incentives for collaborative efforts between electric and gas. Whether applicants commit to actively support the establishment of a charge is a crucial issue for this proceeding, in NRDC's opinion. Requiring a commitment from applicants now would bring the merger more in line with the public interest. Finally, NRDC believes that applicants' 90 institutional commitment to public purpose programs must be strengthened significantly over SoCalGas's current record. It says the drastic cuts to SoCalGas's energy efficiency, research, development, and demonstration (RD&D), and low-income programs and services are extremely disturbing and are symptoms of weakening institutional commitments to these programs. This is especially true in light of applicants' intent to unify around a common vision. Approval of the merger without strengthening these commitments creates serious doubt that the public interest requirement will be met. Greenlining also seeks additional commitments in this area. Applicants oppose the recommendations of NRDC and Greenlining. In regard to energy efficiency, they point out that there is no record in this case to determine whether, or by how much, to adjust energy efficiency funding levels. Applicants propose no merger-related changes that would affect the utilities' Commission-approved energy efficiency programs. The Commission has just completed its review of SoCalGas's 1997 energy efficiency effort, including programs for low-income customers, in SoCalGas's PBR proceeding. SDG&E's funding levels for 1997 energy efficiency programs were approved pursuant to Advice Letter 1001-E/1030-G. In regard to a public purpose surcharge, applicants note that the Commission recently deferred imposing a surcharge on customers of jurisdictional gas utilities until it has further opportunity to coordinate with the Legislature. The Commission has already declared its intention to establish a surcharge for gas public purpose programs. (See D.97-06-108.) The Commission recognizes, however, that such a surcharge must be nonbypassable-that is, paid by all gas customers whether served by a public utility or not-in order to promote a level playing field in a competitive market. While NRDC correctly observes that we have the authority to require gas utility customers to pay a public purpose surcharge, we cannot impose such a charge on the customers of unregulated gas distributors or on unregulated fuels without legislative action. NRDC proposes as merger mitigation measures that we require SDG&E and SoCalGas: (1) to operate under revenue-cap PBRs which NRDC argues will 91 encourage investments in energy efficiency; and (2) to make their individual PBRs consistent after 2001. Applicants state that these concerns are best left to each utility's PBR proceeding. We are in agreement with applicants. The energy issues raised by NRDC and Greenlining are best left to PBRs (where they were recently considered) and other specific proceedings. The record in this application is inadequate to address their concerns. C. Will the merger maintain or improve the quality of the utilities' managements? ORA reviewed the respective utilities' management training programs as well as the number of civil litigation actions filed against them within the last five years. ORA observes that SDG&E's management training programs are much more extensive than SoCalGas's. While SoCalGas has only two sets of employee development materials dealing with employee development and performance management, SDG&E has numerous programs dealing with affirmative action, sexual harassment, and other issues of equal employment opportunities. At the same time, SoCalGas had almost three times the number of discrimination lawsuits filed against it as SDG&E. ORA submits that it is reasonable to attribute this difference in large part to the difference in the companies' management training programs. ORA therefore recommends that, as a condition of approving the merger, the Commission direct SoCalGas to implement SDG&E's management training program. ORA recommends that the Commission require applicants to submit a showing on the quality of management for evaluation as part of the cost-of-service review to occur at the end of ORA's proposed five-year savings sharing period. Greenlining believes that SDG&E's management will not be improved by the merger because now SDG&E's charitable contributions further the elitist interests of SDG&E's all-white top management rather than the interests of those in the community and management has not said that after the merger it will change. Greenlining argues that in addition to executive compensation far exceeding charitable giving at SDG&E, a major focus of its charitable commitments is toward organizations which promote the elitist interests of the affluent, all-white top management at SDG&E. Of the $1.4 million 92 in current charitable contributions made by SDG&E, less than one-third went to low-income groups. No minorities sit on the committee that determines charitable contributions. Recently that committee made a grant of approximately 10%, or $150,000, of SDG&E's annual charitable contributions to the La Jolla Chamber Music Society and gave $100,000 to support the America's Cup race. In contrast, low-income groups and minority groups, on average, receive about $1,000 each. This same disparity continues today. Applicants, in response, submit that the merger will bring together experienced management teams with complementary skills and experience. They assert that the leaders at both SDG&E and SoCalGas are capable, talented, and highly regarded in the utility industry. These leaders will now be able to work together to provide superior service to customers at reasonable prices. The merger will make both utilities stronger by providing SDG&E and SoCalGas with access to additional management skills and resources. Even though SDG&E and SoCalGas will remain separate entities, the merger will undoubtedly maintain or improve the quality of management at both. Applicants take issue with ORA's proposal that applicants be required to demonstrate that the quality of management has not deteriorated at SDG&E and SoCalGas after the merger. They contend that given the numerous indicators of utility management performance that are already available to the Commission, and given the existing PBR mechanisms which provide strong performance incentives to management at both SDG&E and SoCalGas, the additional performance demonstration requested by ORA is unnecessary and unwarranted. We agree with applicants. The merger will certainly maintain the quality of current management and, with normal interaction between utility management, is expected to improve. Should deficiencies occur, the PBR proceeding is the appropriate forum in which to seek remedies. The issue of charitable contributions is discussed below. 93 D. Will the merger be fair and reasonable to affected public utility employees, including both union and nonunion employees? Applicants have demonstrated that the merger will be fair and reasonable to all employees. To that end, applicants are implementing a number of measures to minimize the disruption and anxiety created by the merger, including: (a) open communications with all employees; (b) a policy of no layoffs as a result of the merger for nonofficer employees; (c) voluntary separation packages; (d) relocation assistance; (e) an open and fair selection process; (f) a continuing commitment to employee diversity; (g) competitive compensation and benefits; (h) career planning, retirement planning, and outplacement services; (i) an ongoing commitment to employee development and training; and (j) an employee retention program. Generally speaking, applicants have not been challenged on any employee-related aspects of the merger, with the exception of executive retention costs and employee diversity. Executive retention costs are addressed above in Section II.C.3. Employee diversity will be addressed below. E. Will the merger be fair and reasonable to the majority of all affected public utility shareholders? Applicants maintain that the merger will make both Enova and Pacific Enterprises stronger by joining together the complementary abilities of both companies. They argue that the merger is consistent with the current trend of companies in the natural gas and electric industries to merge and thereby empower themselves, through increased scope, financial strength, and product diversity, to compete effectively in the new energy industry and to provide increased service to their customers. The stock conversion ratio agreed upon by Enova and Pacific Enterprises is fair to the shareholders of both companies, and in particular, the premium being paid by Enova shareholders is reasonable and consistent with other recent transactions. This determination is supported by written fairness opinions from three teams of investment bankers. Moreover, applicants believe the investment community views the merger favorably, another important sign that the merger will be good for both groups of affected shareholders. 94 Applicants expect the merger to be fair and reasonable to all Enova and Pacific Enterprises shareholders so long as applicants' sharing proposal is adopted. However, applicants contend that if Enova and Pacific Enterprises shareholders do not receive a reasonable share of merger savings, then the merger will not be fair to them. They observe fairness to shareholders does not require that the Commission adopt the exact sharing proposal presented by applicants, but fairness does require that shareholders have an opportunity to achieve total savings that are close, if not equal to, the total savings over ten years that applicants have proposed. Applicants warn that savings of only $300 million (an amount greater than shareholders would receive under virtually all of the sharing proposals presented by intervenors) would be unacceptable for shareholders. We are of the opinion that this merger will be fair to the shareholders of both companies despite our finding that savings should be based on a forecast of five years rather than ten. It is the merged company's expected improvement through "increased scope, financial strength, and product diversity, to compete effectively" that motivates this merger. The savings are a mere lagniappe. F. Will the merger be beneficial to state and local economies and to the communities in the areas served by the public utilities? 1. Charitable Contributions Greenlining contends that this merger, at no cost to the resulting merged company, has the potential to create between 5,200 and 20,000 new jobs in San Diego, through creation of a $30 million equity fund plus potential investors' matching funds, to be administered by the San Diego City-County Reinvestment Task Force (RTF), a citizen's group composed of six major banks, four local government officials, and seven community economic development groups. It claims that this can be achieved by a five cent-a-month reduction in the refund to ratepayers with a high likelihood that the $30 million investment will be fully repaid with interest within 15 years. Greenlining asserts that in the PacTel/SBC merger, D.97-03-067, the Commission said that PU Code Section 854 benefits to ratepayers are not to be narrowly 95 defined as small and often inconsequential rebates to customers, but rather may encompass leveraged fund benefits. Greenlining believes that its $30 million Reinvestment Task Force Equity Fund proposal meets that standard. It equates RTF with the Community Partnership Commitment described in D.97-03-067: "[W]e acknowledge that the objectives of the Community Partnership Commitment (CPC) are desirable and commendable ideas. The elements of the CPC demonstrate a plan of action that seeks long term solutions to increase access to telecommunications services for the underserved communities of California. For example, the CPC would establish a Technology Fund that promotes access to advanced telecommunications services in under-served communities and fund it over ten years by up to $10 million per year over ten years; it would contribute $200,000 per year to promote universal service among community groups to achieve a 98% penetration in low-income, minority and limited-English speaking communities within the next seven years; it would encourage the formation of a `Think Tank' to research the interests of communities in the evolving competitive telecommunications market; and among other things, it commits Applicants to promote and contract with minorities, women and people with disabilities. We consider the benefits that will accrue as a result of these commitments important to all ratepayers specifically and California in general since it encourages economic development. The benefits of the CPC will go beyond benefits arising from a simple refund to ratepayers." (Emphasis added.) (D.97-03-067 at p. 88.) The Commission reduced the PacTel/SBC merger benefits to ratepayers by $34 million-the net present value of the $50 million value placed on the Community Partnership Commitment. Greenlining maintains that a large fund leveraged to benefit ratepayers in an era of rapid deregulation satisfies the mandates of Section 854(c), as well as Section 854(b)(1), far better than trivial refunds can. It observes that the Commission is presented with an enormous opportunity to create an equity fund with reverberating job creation, economic development, and housing construction potential that could be matched by major financial institutions. Moreover, the money to trigger such significant financial gains will be an investment which applicants could recoup in its 96 entirety. It is truly a "win-win" situation for applicants, shareholders, ratepayers, and the broader San Diego economy, as well as that of southern California, since the $30 million can just as easily be allocated to the entire service area of applicants. Applicants respond that Greenlining's fund-creation proposal has nothing to do with this merger and would be a disservice to the public interest. The proposal purports to mitigate for Enova's alleged past unresponsiveness to the needs of minorities and "underserved" customers by diverting a substantial portion of ratepayer merger benefits to funds that will assist such communities. The proposal should be rejected as it is not pertinent to this merger under Section 854, and a misappropriation of customer money for special interests. Applicants say that neither Greenlining nor Latino Issues Forum define "underserved," a term they use throughout their testimony without definition or explanation. Applicants believe it to be derived from a usage in bank and communications regulation, where "underserved" connotes the lack of credit availability or telephone penetration in low-income areas. This problem in banking was addressed by Congress. With respect to electric and gas utility service, the term is empty, given that both industries have been obliged for generations to provide and plan for the existing and foreseeable demand of their service territories. No one alleges here that there are any residents of applicants' respective service areas that are, or will be "underserved" with respect to electric or gas utility service. Applicants distinguish the PacTel/SBC merger decision. There the Commission faced a very different situation. First, there was no parallel communications restructuring proceeding addressing issues of minority and underserved community consumer education. Second, California was losing a large corporate headquarter to Texas. In this regard, the PacTel/SBC undertaking included a commitment to expand its California employment base by 1,000 jobs. Third, PacTel/SBC presented a settlement to the Commission which was supported by Greenlining and others; the Commission has a strong policy supporting settlements. Fourth, PacTel/SBC was a much larger merger in terms of the magnitude of assets and revenue streams involved. 97 Our inquiry into the merits of Greenlining's proposal begins and ends with Pacific Tel v. CPUC (1965) 62 C2d 634, where this Commission's decision disallowing charitable contributions as a charge against ratepayers was sustained by the Supreme Court in no uncertain terms. We had said: "Ratepayers should be encouraged to contribute directly to worthy causes and not involuntarily through an allowance in utility rates. [Pacific] should not be permitted to be generous with ratepayers' money but may use its own funds in any lawful manner." (62 C2d at 668.) The Supreme Court agreed: "We believe that the view expressed by the further declaration in the decision now before us that Pacific `hereby is placed on notice that it shall be the policy of this Commission henceforth to exclude from operating expenses for rate-fixing purposes all amounts claimed for dues, donations and contributions' (italics added) states the correct rule; it also accords with the approach adopted in certain other jurisdictions." (Citations omitted.) (62 C2d at 669.) The PacTel/SBC merger CPC is clearly distinguishable. In the quotation cited by Greenlining, the emphasis is on "long term solutions to increase access to telecommunications services for the underserved communities of California." We also said, "We encourage the entity that will implement the CPC to consider all requests that further the goals of the CPC including customer education and reaching underserved communities to meet 98% penetration rate." It was in furtherance of "our overall goal to ensure that California's under-served communities have access to the evolving telecommunications services" (D.97-03-067 at p. 88) that we approved the CPC. The funds in PacTel/SBC were to be used to educate the public-the under-served public-in telecommunication services. This is consistent with our use of ratepayer funds for utility education purposes. (Re PG&E (1972) 73 CPUC 729, 741.) The RTF, no matter how laudable its goals, is not a utility function and we should not order ratepayer money to support it. It is a distinction without a difference to say that PacTel v. CPUC dealt with rates and this merger is not a rate case. Both cases involve 98 ratepayer money. "Ratepayers shall receive not less than 50 percent of those benefits." (Section 854(b)(2), emphasis added.) Other requests for us to meddle in donations to worthy causes engenders the same reply. We shall not be generous with ratepayers' money. Nor will we tell applicants how to spend their profits. 2. Staffing in San Diego Applicants' witness testified that the corporate headquarters of the merged company will be located in San Diego. The headquarters will house the merged company's top executives, and sufficient officers and staff to support corporate-wide policy setting. Accordingly, the following divisions will likely be based at the San Diego headquarters: legal affairs, governmental and regulatory affairs, human resources, finance, information systems, the international business unit, and various corporate governance functions such as shareholder/investor relations and external financial reporting. Headquarters staffing levels are targeted to be in the neighborhood of 350 to 400 workers. TURN/UCAN propose that the merged company be required to maintain staffing at the San Diego corporate headquarters which is at or above the ratio of projected employees at corporate headquarters (350) to projected total employees at the merged company and all of its subsidiaries (11,700). If in the future applicants fail to satisfy this 350/11,700 (or l/33) ratio, TURN/UCAN want the Commission to require the merged company to pay 1/33 of its net revenues into a San Diego job retaining and community development fund. Applicants, in opposition, argue TURN/UCAN have failed to show why the merged company should be penalized if it does not maintain a specific level of headquarters staffing. Such a recommendation is completely unprecedented. To applicants' knowledge, the Commission has never set minimum standards for utility workforce levels and locations as a condition of approving a merger. We agree with applicants. We are not prepared to micromanage the utilities, especially not the nonutility affiliate. 99 Greenlining takes aim at SDG&E's management staffing. It warns us that top management at SDG&E is shockingly homogenous. There are 18 senior managers at SDG&E who comprise the Management Council, none of whom is African American or Latino; further, there are no Latinos or African Americans in the top 10% of management, and the top 40 managers by salary are white. Greenlining disputes SDG&E's assertion that the lack of diversity in SDG&E's top management is due to the available workforce. It claims that no major California utility regulated by the Commission and no utility so close to the Mexico-U.S. border has such a lack of diversity. It says SDG&E's two largest California competitors have the diversity and resultant competitive edge necessary to survive in our increasingly multicultural country and abroad. Of the top 10% of the employees at Edison, 17% are people of color. PG&E has 93 people of color in upper management and recently received an award from the Labor Department on diversity. Many of these senior Edison and PG&E employees were hired over the last ten years and could have been recruited by SDG&E as 25% of SDG&E's upper management were hired from outside SDG&E since 1989. In mitigation of the merger, Greenlining recommends that applicants be required to increase diversity in upper management at least to the levels of other major California utilities such as PG&E and Edison, consistent with Section 854(c)(3) and (c)(6). Applicants argue that the evidence shows that when evaluated correctly, minorities are well represented in Enova's and Pacific Enterprises's workforce; the percentage of minorities employed by applicants exceeds the available minority workforce in their respective service territories. Applicants believe that the merged companies' workforce should reflect the markets where they conduct business in order to ensure customer and community insight. They explain that in the context of the merged companies' corporate values, goals, and objectives, diversity means engaging the full potential of employees of different ages, genders, races, ethnicities, beliefs, religions, sexual orientations, lifestyles, and physical abilities. Diversity also encompasses appreciation for the richness and strength brought to their companies by 100 different perspectives, attitudes, and approaches. Applicants agree that maintaining a diverse workforce is one of their chief objectives. There is no question that overall, applicants have a diverse workforce that reflects the available minority workforce in their respective service territories. But it is clear that diversity has not yet filtered up to the higher levels of SDG&E's management. We are confident that over time it will. Commentary such as this should hasten the process. No formal order is necessary. G. Will the merger preserve the jurisdiction of the Commission and the capacity of the Commission to effectively regulate and audit public utility operations in the state? The affiliate transaction conditions proposed by applicants and other parties are the subject of this section. This application was heard and submitted prior to our affiliate transaction decision (D.97-12-088, discussed above, I.D.). After that decision was issued the presiding ALJ requested comments on its effect on the proposed affiliate transaction conditions submitted herein. Those comments have been received. The major issue in the comments is the request of applicants that the affiliate transaction decision rules should not be applied to transactions between SoCalGas and SDG&E; utility-to-utility transactions should be exempt. Before discussing the exemption request we briefly deal with the affiliate transaction rule proposals made in this proceeding prior to issuance of D.97-12-088. ORA proposed 86 affiliate transaction conditions on this merger, 53 of which applicants were in agreement. TURN/UCAN offered proposals to prohibit sharing of information that would be an incentive for utilities to engage in unregulated activities; to increase penalties for rule violations; to refund certain costs to ratepayers; and to prevent the shifting of costs between utilities (PBR manipulation). Edison, SCUPP, and Vernon proposed their own affiliate rules, mostly a duplication of ORA's and TURN/UCAN's. IID summarized 45 proposals in its brief. We need not discuss those proposals as our affiliate transaction decision exhaustively reviewed the problems of cross-subsidization and the possible anticompetitive behavior in affiliate transactions, and promulgated detailed rules. We shall not revisit that decision at this time. 101 We intend that all the rules promulgated in D.97-12-088 be applicable to SoCalGas, SDG&E, and their affiliates, both before and after the merger, except for the utility-to-utility rule waiver discussed below. Applicants argue that to the extent their merger offers the potential for substantial savings to be enjoyed by ratepayers and shareholders, much of that potential is based on efficiencies which can be realized only through the appropriate integration of utility functions common to both SDG&E and SoCalGas, none of which involve the subsidization of nonutility ventures by the utilities, the stated purpose of the affiliate transactions rulemaking. They say the creation of common or shared utility functions to achieve operating efficiencies neither confers a competitive advantage nor provides a cross-subsidy to an unregulated affiliate. Nevertheless, in response to concerns that have been expressed, applicants have proposed a number of safeguards applicable to transactions between SoCalGas and SDG&E, including the requirement that transfers of goods and services not produced or developed for sale must be priced at fully loaded cost, thus preventing the subsidization of one utility's customers by the other's. Applicants warn that unless transactions between SDG&E and SoCalGas are exempted from application of the new rules, the estimate of potential merger savings will have to be reduced by approximately $343 million, based on applicants' proposed ten-year period for the estimation of merger savings. Using our five-year analysis, the savings would be reduced by about $92 million of which $46 million would be forgone by ratepayers. Of course, in the years beyond five years the loss to both ratepayers and shareholders would exceed even applicants' estimates. Utility rules in this day of competition should reduce expenses, not add to them. Applicants assert that to apply the Commission's new affiliate rules to transactions between SDG&E and SoCalGas would (1) preclude efficiencies that could otherwise be captured and flowed back to ratepayers in the form of lower utility bills; (2) institute a firewall between affiliated utilities resulting in a novel and duplicative layer of regulation; and (3) ignore the reasons why the affiliate transactions rulemaking was instituted in the first place. They reason that because we will continue to have full 102 regulatory authority over SoCalGas and SDG&E following the merger, every transaction between the two utilities will continue to be scrutinized for possible adverse consequences. Thus, whether a particular transaction is a simple efficiency gain for utility customers, or something that unfairly disadvantages competitors, it will be revealed by existing regulatory conventions. To add a redundant layer of regulatory protection by banning or effectively preventing such transactions is unnecessary and costly. Applicants question whether, as affiliated utilities under a common parent, SoCalGas and SDG&E are any different than the gas and electric departments of a combination utility like PG&E or a utility made up of separate regional divisions. They ask, why ban transactions between affiliated utilities when it can be nullified by the simple act of merging the utilities? They point out that we did not institute the affiliate transaction rulemaking to foreclose the realization of the efficiencies produced by creating affiliated utilities through a merger. The rulemaking's purpose was to create rules which would prevent market power abuse by regulated utilities and/or their unregulated affiliates and avoid improper subsidization by utilities of their unregulated affiliates. Neither of these considerations is relevant to the issue of whether the public interest requires that transactions between affiliated utilities be subjected to additional layers of regulatory scrutiny. Allowing SDG&E and SoCalGas to engage in efficiency-enhancing transactions that benefit their customers does not mean that such transactions are anticompetitive; to the contrary, low costs evolve into low rates which are competitive. Comments were also submitted by ORA, TURN/UCAN, Edison, SCUPP, Vernon, IID, Kern River, and UCAN (filing separately in addition to its joint submission with TURN). Most comments acknowledge that it might be appropriate for the Commission to allow certain efficiency-yielding transactions between SoCalGas and SDG&E that would otherwise be barred by the affiliate rules adopted in D.97- 12-088. Where applicants and such comments differ is over whether the exemption should extend to all interutility transactions in this merger, except in specific situations, or 103 whether the exemption should apply only to specified transactions, and presumptively exclude all others. Those comments assert that applicants must show, for any exceptions claimed, that such exceptions will not lead to cross-subsidy or anticompetitive conduct. ORA and SCUPP each offer examples of specific efficiencies that the merger can achieve through exempting certain SoCalGas-SDG&E transactions from the affiliate rules, and they each advocate exemption from the rules for these specific transactions. ORA observes that Rules V.C and D, which bar affiliates from sharing facilities, equipment, and joint purchases, would adversely affect merger savings: [P]ermitting such transactions between the regulated affiliates as part of this proposed merger is not reasonably expected to result in inappropriate cross-subsidization: both affiliates are utilities regulated by this Commission, and each utility would be credited with its proportionate share of resulting merger savings. In addition, it is not apparent that the utilities' ability, through this merger, to reduce the costs of their regulated operations would have an adverse impact on competition. SCUPP concurs with ORA on exempting joint SoCalGas/SDG&E purchasing from the rules, and also supports exempting SoCalGas/SDG&E customer service activities from the rule's information-sharing provisions, as well as from limitations on sharing corporate support services. Applicants believe that limiting the affiliate rules' application to specified circumstances optimizes merger savings and other public interest benefits. In contrast, applying the affiliate rules to interutility dealings, except for certain specific transactions, substantially hinders attaining merger efficiency benefits for utility customers without any offsetting protection to other public interest concerns. They make the point that even where savings are achieved through a transaction specific exception to the rules, there are substantial hard-to-quantify costs that result from the presumptive overall application of the affiliate rules to interutility transactions. The affiliate rules are designed to reinforce one another and therefore reach broadly and may cause unintended consequences when applied to arenas with no potential for cross-subsidy or anticompetitive effect. 104 Applicants say they do not seek a blanket exemption from rules governing interutility transactions. They note that the specific affiliate transactions policies and conditions submitted as part of their case would continue to apply to interutility transactions. In addition, applicants recommend certain specific applications of the affiliate rules to interutility transactions in this merger. 1. Applicants agree with ORA that interutility tying arrangements should be barred; it is appropriate to apply Rule III.c to interutility transactions. 2. Applicants agree that the provisions of Rules V.G.2.a, b, and c should apply to any transfer of employees between SoCalGas Operations or SoCalGas Gas Acquisition, and any group at SDG&E engaged in a gas or electric merchant function. 3. Applicants ask that the Commission authorize the following limited exceptions to Rules V.G.2.a, b, and c: (a) That Rules V.G.2.a, V.G.2.b, and V.G.2.c not be applied to transfers of employees between SoCalGas and SDG&E subsequent to the merger other than transfers subject to paragraph 2, above; and (b) That the Commission provide for a six-month transition period after all merger regulatory approvals have been obtained during which employee transfers between utilities and unregulated affiliates that are necessary to implement the merger would be exempted from Rules V.G.2.b and V.G.2.c. Applicants claim that they require the flexibility and increased options of these limited waivers so that employees whose existing jobs are eliminated to achieve merger savings can be assisted. Restrictions on transfers and the imposition of a transfer fee limit the options of displaced employees and hinder the achievement of savings. Given the lack of potential for anticompetitive conduct and cross-subsidy here, as well as the explicit concern in Section 854 of the PU Code for ensuring fairness to employees, applicants submit that the Commission should grant these narrow exceptions. Accordingly, applicants request the Commission to (1) uphold the exceptions to the affiliate rules specified in Attachment l to applicants' January 23 comments; (2) provide that the affiliate rules apply to interutility transactions only in the limited circumstances described above; (3) generally apply the limitations to interutility transaction proposed 105 by applicants in this proceeding; and (4) grant the limited exceptions to Rules V.G.2.a, b, and c requested above. Discussion Throughout this proceeding we have noted the concern of various parties that the merger is too complex as proposed to preserve the jurisdiction of the Commission and to provide effective oversight of utility operations. Some parties have contended that to prevent abuse of market power, regulation is a poor substitute for divestiture or outright prohibition of certain activities. We have disposed of those contentions above. Others assert that without scores of specifically tailored rules, in addition to our affiliate rules, applicants will run wild. We see it differently. In regard to utility-to-utility transactions, our concern for regulatory efficiency in preventing cross-subsidization and anticompetitive practices takes on a different hue. Here, more is less. The more regulations we impose, the less able we will be to distinguish productive conduct from prohibited conduct. From the utility's viewpoint the more regulation, the more cost to comply, and the less efficient the delivery of service. Our goal is low rates for ratepayers. Low costs, efficient operations, and competition are the means to achieve that goal. Commenters who propose increased regulation with the burden on the utility to seek exceptions are misguided. Regulations should be imposed upon a showing of need, and in this case the showing in regard to utility-to-utility transactions has been sparse indeed. D.97-12-088 recognized this situation when it specifically provided that mergers and joint ventures might require different rules. The evidence in this proceeding clearly shows the wisdom of D.97-12-088. To apply the affiliate transaction rules to utility-to-utility transactions would immediately cause the loss of some $46 million to ratepayers over the next five years; would lose uncounted millions more after five years; would increase costs to the utilities; would cause higher rates than otherwise would prevail; would increase costs to the Commission to analyze the plethora of reports which would result; and, perniciously, would be a windfall to competitors who would not have those costs and would not have to reduce rates to 106 compete. A competitor's optimal rate is not based on its own cost, but the cost of the next most competitive producer. The accounting practices and reporting requirements now in place are adequate to provide the information needed for responsible regulatory oversight. There is no evidence in this proceeding that persuades us that more are needed. We exempt SoCalGas and SDG&E from the utility-to-utility affiliate transaction rules to the extent requested by applicants. V. Environmental Review The California Environmental Quality Act (CEQA), and the State CEQA Guidelines promulgated by the California Resources Agency to implement CEQA, require a public agency that issues a discretionary approval of a project to consider whether the project is subject to CEQA, and if it is, to prepare an Initial Study to determine whether the project may have a significant effect on the environment. If the Initial Study shows that there is no substantial evidence that the project or any of its aspects may have a significant effect on the environment, then the public agency shall prepare and adopt a Negative Declaration. If the Initial Study shows that the project may have a significant effect on the environment, the public agency must prepare an Environmental Impact Report. The Commission's Rule 17.1 codifies its procedure for implementing CEQA. - ----------------- California Public Resources Code section 21000 et seq. 14 CCR section 15000 et seq. 14 CCR sections 15061, 15063; California Public Resources Code Sec. 21080. California Public Resources Code section 21080(c); 14 CCR sections 15070-15075. California Public Resources Code section 21100; 14 CCR section 15063(b). 107 Applicants filed a Preliminary Environmental Assessment (PEA) with their merger application. ORA requested that an Initial Study be prepared and that applicants file an amended PEA. Applicants filed an amended PEA with the Commission. Public comments on the PEA were filed. The Commission staff issued a Notice of Publication of a Negative Declaration, in which it advised that it had completed an Initial Study and a draft Negative Declaration, which the Commission made available for a 30-day public review period. The public review period closed on May 20, 1997. On September 12, 1997, the Commission staff notified all interested parties that it had reviewed the public comments, made minor revisions to the proposed Negative Declaration for clarity, and considered the Negative Declaration to comply with CEQA and Rule 17.1. With the notice, all interested parties were provided a copy of the final Negative Declaration and Initial Study. Accordingly, the Negative Declaration has been prepared in compliance with the procedural requirements of CEQA and Rule 17.1. It concludes that the proposed merger will not have one or more potentially significant environmental effects based on the whole record, including the Initial Study. For those reasons, the Commission will adopt the Negative Declaration. As a part of the CEQA process, the Commission will file a Notice of Determination with the Office of Planning and Research. The Commission notes that on December 19, 1997, SDG&E filed an application for authority to sell electrical generation facilities and power contracts (A.97-12-039). That application included a Proponent's Environmental Assessment (PEA) for the proposed divestiture. The appropriate environmental review under CEQA for the proposed divestiture will be conducted in A.97-12-039. VI. Miscellaneous A. Line 6900 and Line 6902 The Commission has referred to this proceeding the issue of whether to include the cost of uncompleted portions of Line 6900 and Line 6902 in the SoCalGas 108 Transmission Resource Plan (Resource Plan). "The specific ratemaking treatment to be given Line 6900 and Line 6902 should be further investigated and fully resolved prior to final Commission action on the proposed Pacific Enterprises/Enova merger. SoCalGas's PBR proceeding and the merger proceeding are appropriate forums for this review." (D.97-04-082, p. 42.) SCUPP recommends that the Commission order SoCalGas to exclude Line 6900 (Phases II and III) expansion costs from the SoCalGas Resource Plan, effective immediately; SDG&E to include Line 6900 in the SDG&E Resource Plan; and SoCalGas to exclude Line 6902 expansion costs from the SoCalGas Resource Plan, effective immediately. Line 6900 is a high-pressure transmission line that is being built in four phases parallel to Lines 1027 and 1028 in the pipeline corridor that exists between the SDG&E Moreno compressor station in SoCalGas's service territory and the SDG&E Rainbow station in SDG&E's service territory. Phases I and IV have been completed. Phases III and II are planned at a cost of $12 million and $7 million, respectively. Line 6902 is the reinforcement of SoCalGas's transmission facilities in the Imperial Valley corridor, a point from which SoCalGas intends to provide service to Mexicali. The projected looping of Line 6902 by the addition of 40 miles of 16-inch pipe is estimated to cost about $12.3 million. We have raised concerns as to whether the cost of uncompleted portions of Line 6900 and Line 6902 should be included in the SoCalGas Resource Plan. In its most recent BCAP, SoCalGas proposed including the cost of uncompleted portions of Line 6900 and Line 6902 in its Resource Plan. We determined that SoCalGas had not met its burden of proof to show the reasonableness of including the expansions in its Resource Plan. (D.97- 04-082, p. 42.) In this merger proceeding SCUPP's witness testified that Line 6900 expansion is not needed to meet the forecasted load growth associated with SoCalGas's retail customers. The witness presented extensive testimony on forecasted load growth through 2010 and concluded that SoCalGas's forecasts are unreliable and inflated. The witness said that the pipeline expansion was to meet project load in Mexico. She said 109 that SoCalGas and SDG&E are attempting to shift the costs of serving Mexico by inflating forecasts to justify incremental additions before they are actually needed to serve the native loads and by installing bigger pipes than are actually needed. She said that SoCalGas is subsidizing SDG&E at the expense of SoCalGas's retail customers. SoCalGas's proposal to include the cost of uncompleted portion of Line 6900 in its Resource Plan allows SDG&E to escape including the cost in its own resource plan. This benefits SDG&E's UEG in terms of lowering SDG&E's marginal cost of transmission, hence, its cost allocation. This constitutes preferential treatment by SoCalGas of its proposed merger affiliate, SDG&E. She claims including Line 6900 as a part of the SoCalGas Resource Plan, rather than making it a customer specific facility assigned to SDG&E, adversely affects SoCalGas's customers. If Line 6900 is excluded from the SoCalGas Resource Plan, the rates for both core and noncore customers will go down. The effect of this exclusion is to transfer $9.9 million from SoCalGas's retail core and $6.4 million from SoCalGas's retail noncore of cost responsibility to SDG&E. Under SoCalGas's proposal to include Line 6900 in its Resource Plan, SoCalGas's retail customers pay an additional $16.3 million while SDG&E's electric department saves about $6.3 million. Therefore, including Line 6900 in the SoCalGas Resource Plan creates a substantial subsidy for SDG&E's UEG load at the direct expense of SoCalGas's customers, particularly SoCalGas's UEG customers, many of whom SCUPP represents. SCUPP points out that Line 6900 was planned at SDG&E's request to serve SDG&E load. SCUPP asserts that the attempt to shift the cost from SDG&E to SoCalGas's retail customers developed only after SoCalGas started to develop a close business relationship with SDG&E that has culminated in the current Pacific Enterprises/Enova merger proposal. Prior to the 1993 BCAP, Line 6900 was considered to be an exclusive use facility, with all costs allocated to SDG&E. The Commission explicitly addressed the ratemaking treatment for Line 6900 three times prior to its 1993 BCAP decision. - D.90-11-023, 38 CPUC2d 77, 99 regarding SoCalGas's 1990 Annual Cost Allocation Proceeding (ACAP), approved 110 SoCalGas's allocation to SDG&E of 100% of the cost of new transmission Line 6900. - D.92-12-058, 47 CPUC2d 438, 452 adopted an LRMC ratemaking methodology, and classified Line 6900 as exclusively for SDG&E. - D.93-12-043, 52 CPUC2d 471, 552 regarding SoCalGas's Test Year 1994 General Rate Case (GRC) said Line 6900 is needed to serve SDG&E. In its 1993 BCAP, SoCalGas began advocating the position that Line 6900 should be treated as a common facility rather than customer specific. SoCalGas, SDG&E, and Division of Ratepayer Advocates submitted a joint recommendation supporting such rate treatment in the 1993 BCAP. In D.94-12-052, 58 CPUC2d 306, the Commission adopted the joint recommendation. We noted that treating Line 6900 as common transmission cost resulted in an increase in the marginal cost of transmission for SoCalGas's system because Line 6900 became part of the SoCalGas Resource Plan, and that SDG&E's customer cost would decrease. Finally, we found that SDG&E should exclude Phases II, III, and IV of Line 6900 from its 20-year transmission plan for purposes of computing marginal transmission costs. The effect of this was to reduce costs to SDG&E noncore customers, including the SDG&E UEG. In the recently completed SoCalGas PBR case, we addressed the appropriate ratemaking treatment for completed portions of Lines 6900 and 6902. We eliminated the cost of the completed facilities from the base year PBR revenues. D.97-07-054, pp. 77-79. We accepted ORA's recommendation that Phase IV of Line 6900 was not intended to primarily serve retail customers. We said, "In each instance, the line appears to have been constructed for the primary purpose of serving the needs of noncore customers, and any benefits they may provide to the core are incidental. ORA has reflected those benefits in its recommended disallowances." (D.97-07-054, p. 79.) SCUPP argues that the future phases Line 6900, Phases II and III, should be treated consistently with Phase IV. Therefore, Phases II and III costs should be entirely excluded from the SoCalGas Resource Plan and included in the SDG&E Resource Plan. 111 SCUPP also recommends that Line 6902 should be removed immediately from the SoCalGas Resource Plan; we should not wait for SoCalGas's next BCAP. Applicants opposes SCUPP's recommendation. Applicants state that the load forecast presented by them in this proceeding shows that the need for and timing of the future phases of Line 6900 in the SoCalGas Resource Plan are driven by load growth both from SoCalGas retail customers and from SDG&E, and not at all by load growth from Mexico. As such, the proper treatment under LRMC cost allocation principles is to consider the additions to be common transmission facilities and to include them in the calculation of the overall SoCalGas system LRMC for the gas transmission function. This is how the Commission set SoCalGas's rates in its decision in the 1996 BCAP decision, pending its further examination of Line 6900 additions in the SoCalGas Resource Plan. Furthermore, applicants maintain, SCUPP's claims make no sense about what the effect on rates should be of classifying the Phases II and III expansions of Line 6900 as "exclusive use" facilities. SCUPP says the effect should be to reduce SoCalGas's rates to its retail customers by $16.3 million per year and to increase SoCalGas's rate to SDG&E by an equivalent amount, with $6.3 million per year of that shift allocated to SDG&E's electric department. SCUPP's proposed annual shift would continue for a considerable number of years because Phase III would remain in the LRMC resource plan until 2005 and Phase II until 2011. However, the entire capital cost of Phase II is estimated at $6.994 million and of Phase III at $11.765 million, for a total of only $18.759 million. SCUPP's quantification of the rate impact cannot be right, in applicants' opinion, because SCUPP's proposed shift to SDG&E's customers would recoup the entire capital cost of Phases II and III in little more than a year. Contrary to SCUPP's claims, the real result under LRMC methodology of classifying Line 6900 expansions in the resource plan as "exclusive use" facilities would be to lower SoCalGas's system transmission LRMC and to cause an increase in rates to SoCalGas's retail core customers of about $4 million per year. SoCalGas notes that the detail of these calculations under LRMC costing theory are a complicated matter, and they belong in a cost allocation proceeding, not in a merger application. 112 Discussion We have set out SCUPP's position at great length. Had we gone further into the details that SCUPP presented (and applicants opposed) this decision would be substantially longer. There is nothing about this issue that requires it to be settled in this merger proceeding. To the contrary, a rate case is the proper forum. The question of service to Mexico looms large in SCUPP's presentation. There is no gas service at all now in the Tijuana/Rosarita Beach area of Mexico, which is the area that might be served through the Moreno- to-Rainbow corridor and SDG&E's system. If in the future the likelihood of SoCalGas and SDG&E providing upstream transmission service for that market is sufficient to justify reflecting such a load in SoCalGas's and SDG&E's resource plans used for LRMC cost allocation purposes, we can then address in a cost allocation proceeding what the impact of that future load should have on the allocation of costs in current rates. SoCalGas agrees that based on current factors, including the market uncertainty associated with the competitive restructuring of electricity supply, SoCalGas would not plan to construct during the planning horizon the additional phase of Imperial Valley transmission Line 6902 that was shown in the SoCalGas Resource Plan for the 1996 BCAP. With the 1998 BCAP to be filed this October, we see no reason to try to recalculate SoCalGas's system transmission LRMC and redo cost allocations. After a decision in this case, SoCalGas would have to file a complicated recalculation of cost allocations for all customers. This recalculation might shift costs in either direction between its core and noncore customers, but would not be a shift of significant size. Parties would then litigate whether the way in which SoCalGas proposed to reallocate costs was appropriate. Then, the Commission would have to issue another decision on the cost reallocation. We agree with applicants that all of this activity makes no sense considering the 1998 SoCalGas BCAP is going to be filed by October 1998 and the whole process will recommence from scratch. 113 B. The Administrative Law Judge's Rulings Regarding Discovery of Edison Documents Edison requests Commission review of the ALJ's rulings compelling production of documents requested by applicants containing confidential and proprietary strategic business information about Edison, its parent company, and its unregulated affiliates (the Edison Documents). Edison seeks reversal of the rulings admitting 18 of those documents into the record. It is Edison's contention that, under a reasonable interpretation of Section 854, confidential information about Edison's prospective business activities is not relevant to the inquiry whether the merger is in the public interest. On September 9, 1997, the ALJ ordered Edison to produce portions of 58 confidential documents to the applicants, noting that "[t]he material that I am ordering to be discoverable, subject to the protective order, concerns Edison's current plans in the area of competition which are relevant to the issue of the merger's effect on competition." (Tr. 1177.) Edison contended during discovery, and continues to maintain, that such inquiry is not relevant to the merger's effect on competition, and therefore, falls outside the scope of permissible discovery, which is limited to material that is reasonably calculated to lead to the discovery of admissible evidence. On October 23, 1997, the ALJ admitted the Edison Documents into the record, stating that "[t]he reason I am admitting [the Edison Documents] in is because of the competitive environment that will exist subsequent to the consummation of the proposed merger of Pacific Enterprises and Enova Corporation, assuming the merger is approved." (Tr. 3426.) Edison asserts that such documents are not relevant to the inquiry before the Commission on this application, and therefore, should not have been admitted. Edison argues that the interpretation urged by applicants and adopted by the ALJ sets a policy which is contrary to public policy and the public interest. Edison says: First, it creates incentives for applicants to game the regulatory process-to co-opt the Section 854 review process in order to pilfer their rival's competitive secrets. A determination that Section 854 requires-or even permits-a review of all market participants' competition plans will transform every Section 854 application into a 114 skeleton key unlocking the applicants' competitors' most sensitive business strategies. Ratification of the current discovery and evidentiary rulings is fundamentally inconsistent with sound business practices and public policy, and invites parties to manipulate the regulatory process to subvert the competitive process. Second, it drastically raises the cost of intervening in a Section 854 proceeding to unacceptable heights. A determination that intervention into a merger proceeding constitutes even a partial waiver of the confidentiality of the intervenor's strategic plans, making that information presumptively relevant to the proceeding and therefore subject to discovery and release to all other market participants, will serve as an insurmountable disincentive to the voluntary participation of any competitor in a Section 854 proceeding. The public interest cannot be served by such a result. Third, the experience of this case has demonstrated that a set of applicants can, and will indeed, profit by using this new "regulatory" tool selectively to target and harass specific competitors. Applicants have only pursued such information from Edison and Enron, and retracted their demands for Enron's commercially sensitive documents once Enron acceded to publicly support the merger. Finally, Edison contends that the plain language of Section 854(b)(3), requiring a finding that the proposed merger "does ... not adversely affect competition"-does not explicitly or implicitly require the Commission to predict a future competitive landscape and the proposed merger's impact thereon. Adoption of the applicants' interpretation would constitute an unprecedented and unwarranted expansion of the Section 854 inquiry. Edison notes that to date, this Commission has considered three other applications under Section 854: the SCE-SDG&E merger (D.91-05- 028), the GTE-Contel merger (D.94-04-083), and the PacTel/SBC merger (D.97-03-067). It asserts that in none of those cases did the Commission engage in a generalized review and survey of the future competitive landscape; the Commission's Section 854(b)(3) inquiry was largely focused on assessing the impact of the applicants' proposed post-merger activities upon the then-existing market conditions, but does not engage in direct review of the potential activities of other market participants or entrants. 115 On another aspect of this issue Edison asserts, without citation, that the presiding ALJ has no authority to impose discovery sanctions. Discussion We affirm the ALJ's discovery Rulings. Among the many changes deregulation is bringing, not the least is change in the nature of litigation before the Commission. Utilities are challenging utilities more frequently, intervenors are more strident, and antitrust has become a leading issue. Those factors plus the legislative requirement to complete hearings expeditiously, all increase the pressure on the discovery phase of proceedings. Our basic discovery statutes are brief to the extreme. Section 1701. Rules of practice and procedure; technical rules of evidence; effect of informality (a) All hearings, investigations, and proceedings shall be governed by this part and by rules of practice and procedure adopted by the commission, and in the conduct thereof the technical rule of evidence need not be applied. No informality in any hearing, investigation, or proceeding or in the manner of taking testimony shall invalidate any order, decision or rule made, approved, or confirmed by the commission. Section 1794. Depositions The commission or any commissioner or any party may, in any investigation or hearing before the commission, cause the deposition of witnesses residing within or without the State to be taken in the manner prescribed by law for like depositions in civil actions in the superior - ------------------ . Senate Bill 960 (1996) Section 1: It is further the intent of the Legislature that the Public Utilities Commission establish reasonable time periods for the resolution of proceedings, that it meet those deadlines, that those deadlines not exceed 18 months and be consistent with the rate case plans, whichever is shorter. Sec. 1701.2(d) Adjudication cases shall be resolved within 12 months of initiation unless the Commission ... issues an order extending that deadline. 116 courts of this State and to that end may compel the attendance of witnesses and the production of books, waybills, documents, papers, and accounts. The PU Code sections providing for administrative law judges give them substantial power: Section 7: Whenever a power is granted to, or a duty is imposed upon, a public officer, the power may be exercised or the duty may be performed by a deputy of the officer or by a person authorized, pursuant to law, by the officer, unless this code expressly provides otherwise. 310. ... Any investigation, inquiry, or hearing which the commission may undertake or hold may be undertaken or held by or before any commissioner or commissioners designated for the purpose by the commission. The evidence in any investigation, inquiry, or hearing may be taken by the commissioner or commissioners to whom the investigation, inquiry, or hearing has been assigned or, in his, her, or their behalf, by an administrative law judge designated for that purpose. ... 311. (b) The administrative law judges may administer oaths, examine witnesses, issue subpoenas, and receive evidence, under rules that the commission adopts. (Emphasis added.) (c) The evidence in any hearing shall be taken by the commissioner or the administrative law judge designated for that purpose. The commissioner or the administrative law judge may receive and exclude evidence offered in the hearing in accordance with the rules of practice and procedure of the commission. (Emphasis added.) Buildings on those statutes we have provided broad scope for our administrative law judges. 117 Commission's Rules of Practice and Procedure, Article 16. Presiding Officers 62. (Rule 62) Designation When evidence is to be taken in a proceeding before the Commission, one or more of the Commissioners, or an Administrative Law Judge, may preside at the hearing. 63. (Rule 63) Authority The presiding officer may set hearings and control the course thereof; administer oaths; issue subpoenas; receive evidence; hold appropriate conferences before or during hearings; rules upon all objections or motions which do not involve final determination of proceedings; receive offers of proof; hear argument; and fix the time for the filing of briefs. He may take such other action as may be necessary and appropriate to the discharge of his duties, consistent with the statutory or other authorities under which the Commission functions and with the rules and policies of the Commission. In Re Alternative Regulatory Framework for Local Exchange Carriers (1994) D.94-08-028, 55 CPUC2d 672, where an administrative law judge's discovery ruling was being contested, we reviewed our discovery procedures and said: "The Commission's closest expression of any discovery related procedures is found in PU Code section 1794 .... For other discovery related procedures, the Commission generally follows the discovery rules that re found in the Code of Civil Procedure (CCP). * * * "For a party to a proceeding, a wide range of discovery procedures is available. (See, CCP sections 2025, 2028, 2030, 2031, 2032, 2033.)" (55 CPUC2d at 677.) The next important landmark in the evolution of our discovery practice occurred in Re Merger of Pacific Telesis and SBC Communications (D.97-03-067). In the PacTel/SBC merger proceedings, intervenor AT&T made several allegations regarding the impact of the proposed merger on competition in California telecommunications markets. In response, SBC propounded data requests similar to those at issue here: seeking documents related to AT&T's business plans (past and future), any post-merger analyses of the California telecommunications industry, 118 identification of actual and potential competitors, and AT&T's projected revenues and market share in California by year through 1999. AT&T refused to produce the responsive documents, making the same arguments Enron and Edison are making here. AT&T claimed the documents were irrelevant because the proceeding was about SBC's proposed acquisition of PacTel, not AT&T's conduct. Further, AT&T argued the documents constituted AT&T's most commercially sensitive information and were protected from discovery. Finally, like Edison, AT&T argued on policy grounds that requiring competitors to divulge their confidential marketing business strategies will discourage participation in Commission proceedings. In her Ruling, the presiding ALJ stated: "[t]he documents sought by SBC are relevant to the subject matter of this proceeding and appear reasonably calculated to lead to the discovery of admissible evidence. [Citation omitted.] For example, AT&T's pre- and post-merger business and marketing plans for California may address market concentration and also may contain statistical assumptions about the markets which might be relevant to AT&T's protest. Similarly, AT&T's revenue and market share projections for the local market may address market concentration of the local market and barriers to entry for newcomers, which also might be relevant to the protest." (A.96-04-038, Ruling of ALJ Econome, September 3, 1996, p. 7.) Without commenting directly on ALJ Econome's ruling in our decision, we discussed with approval the need to understand competition in the emerging markets. We said that it is important to consider "the presence of many other firms which are equally ready and willing to enter" a given market (D.97-03-067, mimeo. p. 60). We pointed out that the California Attorney General, in supporting the merger, considered those firms that "are all planning to aggressively expand the range of that competition." (Mimeo. p. 62.) Findings of Fact 43 discussed the potential competitors capable of competing. (Mimeo. p. 100.) Just as AT&T's future competitive plans could lead to evidence necessary to an understanding of the PacTel/SBC merger, so too, Edison's future competitive plans could lead to evidence necessary to an understanding of the Pacific Enterprises/Enova 119 merger. It may be that the discovered information would not lead to relevant evidence, but we cannot determine that fact prior to discovery. The Findings of Fact and Conclusions of Law that caused the ALJ to impose sanctions are set forth in the ALJ Ruling of August 18, 1997: Findings of Fact 1. On April 29, 1997, applicants served their First Data Request seeking documents regarding Edison's prospective business plans on Edison. 2. On May 14, 1997, Edison filed objections to each and every question in applicants' First Data Request arguing "lack of relevance" for some questions and claiming a "privilege" for others. Edison asserted that its strategic business plan documents fall completely outside the scope of proper discovery. 3. On May 28, 1997, applicants and Edison participated in the first of four meet-and- confer sessions regarding the First Data Request. At that session, applicants emphasized the need for Edison to immediately respond to these questions, and to provide a privilege log for documents subject to a claim of either "trade secret" or "work product" privilege. 4. On June 2, 1997, applicants and Edison held a second meet-and-confer session regarding the First Data Request during which applicants restated their need for the privilege log and immediate responses to the questions in dispute. 5. On June 3, 1997, at the third meet-and- confer, applicants provided an explanation of the relevance of each question in the First Data Request. Edison agreed to provide a trade secret privilege log by June 17, 1997, but stated that such log would list only those documents Edison deemed relevant to the proceeding. 6. At the final meet-and-confer session held on June 5, 1997, counsel for Edison reconfirmed his intention to provide a privilege log containing only "relevant" documents no sooner than June 17, 1997. 120 7. On June 6, 1997, applicants filed a Motion to Compel Edison to respond to every question presented in the First Data Request. Edison filed its Response to the Motion to Compel on June 11, 1997. At the June 13, 1997 Law and Motion hearing, counsel for Edison represented that Edison would produce a trade secret privilege log by June 17. 8. On July 3, 1997, Edison filed a Motion to Quash Discovery. 9. On July 3, 1997, applicants filed a Motion for an Order Imposing Sanctions on Edison for its complete failure to comply with its discovery obligations in this proceeding. 10. At the Law and Motion hearing on July 11, 1997, the presiding Administrative Law Judge (ALJ) denied virtually all of Edison's Motion to Quash and granted applicants' Motion to Compel the remaining responses in dispute, specifically questions 1-6, 25, and 37-44. The presiding ALJ ordered that responses to these questions and a complete trade secret log be produced by Edison on or before July 25. The ALJ declined to impose sanctions on Edison at that time. Counsel for Edison stated the company's intention to produce the contested material, should the ALJ so order. 11. On July 24, 1997, Edison filed a Motion for Reconsideration of the ALJ's Ruling denying Edison's Motion to Quash Discovery and a Motion for Stay of the ALJ's Ruling compelling responses. 12. At the Law and Motion hearing on July 25, 1997, the presiding ALJ denied Edison's Motion for Stay. 13. At the Law and Motion hearing on August 1, 1997, the ALJ denied Edison's Motion to Reconsider his July 11, 1997, Ruling and found specifically that there were no circumstances that cause the imposition of sanctions against Edison pursuant to the Code of Civil Procedure to be "unjust." 14. At the Law and Motion hearing on August 1, 1997, the ALJ also specifically found that Edison had misused the 121 discovery process, as described in Code of Civil Procedure Section 2023 and stated his intention to impose sanctions on Edison. In order to afford Edison the requisite time and place to respond, the ALJ requested that applicants file another request for sanctions to be considered at an August 15, 1997 hearing. 15. As of August 15, 1997, Edison has failed to respond to applicants' data requests in direct violation of the ALJ's Ruling of July 11, 1997. Conclusions of Law 1. Edison has intentionally misused the discovery process as defined by Section 2023 of the Code of Civil Procedure. 2. Edison opposed, "without substantial justification", a motion to compel discovery as defined by Section 2023(a)(8) of the Code of Civil Procedure. 3. There is no "substantial justification" that would make imposition of sanctions against Edison under Section 2023 of the Code of Civil Procedure "unjust." 4. Edison violated the ALJ's Ruling of July 11, 1997, to comply with outstanding discovery. 5. The presiding ALJ may impose sanctions on Edison for discovery violations under Sections 2030 and 2023 of the Code of Civil Procedure, and Rules 62 and 63 of the Commission's Rules of Practice and Procedure. It is "necessary and appropriate" that this be done (Rule 63). 6. Edison's intentional disregard of its discovery obligations has irreparably harmed applicants' due process rights to conduct full and fair discovery in this proceeding. 7. Edison's intentional disregard of its discovery obligations has impeded the Commission from obtaining the full spectrum of information relating to its inquiry under Section 854(b)(3) of the PU Code. 122 The sanctions imposed by the ALJ were: 1. Edison shall produce all documents responding to applicant's First Data Request in unredacted form. 2. Edison shall reimburse the applicants for all expenses associated with litigating this discovery dispute: For Pacific Enterprises, $27,075; for Enova, $11,420. 3. Edison shall provide restitution to the State of California for the Commission's expenses associated with conducting the July 25, August 1, and August 15, 1997 Law and Motion hearings and all other costs related to addressing Edison's failure to comply with its discovery obligations, in the amount of $10,000. 4. Should Edison not fulfill its discovery obligations by the date of the next Commission conference on September 3, Edison shall be precluded from submitting testimony and evidence, and from conducting cross-examination, on Section 854(b)(3) issues. Edison thereupon fulfilled its discovery obligations. 1. Edison's Business Plans Are Discoverable Edison urges rejection of the view that section 854(b)(3) requires inquiry into the state of future competition in the relevant markets as affected by the potential activities of current market participants and potential market entrants. Edison urges, without citation, that we adopt the view that the plans of potential entrants are not relevant to the question of whether the merger will have an adverse impact on competition. Our review of our decisions, the case law, the merger guidelines, and the commentators is exactly contrary to Edison's position. The PacTel/SBC merger case, discussed above, is not only applicable for its discussion of our discovery authority, but also for its approval of obtaining discovery from future potential competitors. Courts have had no hesitation in considering the effect on competition of potential entrants when appraising a merger. (United States v. Waste Management (2d 123 Cir. 1984) 743 F 2d 976, 982 citing United States v. Falstaff Brewing Corp. (1973) 410 US 526, 35 L ed 2d 475.) In government antitrust proceedings, it is usual for the government to require potential competitors to describe their position should the merger take place. In United States v. Country Lake Foods (1990) 754 F.Supp. 669,672, 675-76, potential competitors were asked what their response would be if the merger participants raised prices in a "small but significant and nontransitory" way. Their answer was that potential competitors would enter the market and compete. (754 F. Supp. at 672.) Generally, under the 1992 Horizontal Merger Guidelines (Guidelines), review of mergers is forward-looking. Examples abound: "Market shares will be calculated using the best indicator of firms' future competitive significance." (Guidelines 1.41.) "[T]he Agency will identify other firms not currently producing or selling the relevant product in the relevant area as participating in the relevant market if their inclusion would more accurately reflect probable supply responses." (Guidelines 1.32.) "Throughout the Guidelines, the analysis is focused on whether consumers or producers `likely would' take certain actions. ..." (Guidelines 0.1.) "The Agency normally will calculate market shares for all firms ... based on total sales or capacity currently devoted to the ... market together with that which likely would be devoted to the relevant market in response to a `small but significant and nontransitory' price increase." (Guidelines 1.41.) The United States Department of Justice and the Federal Trade Commission seek market share information from firms being investigated as well as from third-party firms. (See Scher, Antitrust Advisor, 3.16, at p. 3-53; "In government investigations, the antitrust enforcement agency also may use third-party compulsory process to obtain the data from other market participants.") Statutes authorize the Attorney General and the Antitrust Division to obtain "documentary material" or information "relevant to a civil antitrust investigation" pursuant to a civil investigative 124 demand. (15 U.S.C. section 1312.) Such demands are specifically authorized in merger proceedings. (See id. section 1311, subd. c. and 1312, subd. (b)(1)(B).) Such information is relevant not just in the context of reducing the market share of a merging entity but also-as Guidelines 1.521 notes-in the "proper computation of market shares." (Areeda & Turner, Antitrust Law, section 932, at Vol. IV, p. 131.) We conclude that a potential competitor's business plans in relevant markets are discoverable. Edison is clearly a potential competitor. In its brief, it said: "This Commission should similarly focus upstream on delivered gas, and should focus downstream on retail electric energy. Upstream, the relevant geographic market is southern California. Downstream, the relevant geographic market is all of California, because the Power Exchange (PX) will set the price for spot power in the whole state and bilateral arrangements likely will use spot prices as benchmarks." (Edison's Opening Brief p. 9.) Edison is the largest seller of electricity (or, indeed, energy of any form) in southern California. Edison has retained its coal- fired, hydroelectric, and nuclear generation, much of which lies outside of southern California. Edison will sell into the PX. Edison, too, has marketing affiliates. Edison will compete kilowatt-to-kilowatt with the merged company in southern California and may be a prime customer for a bypass pipeline. The presiding ALJ's Ruling regarding the production of Edison's business plans was correct and is affirmed. 2. The Authority of the Presiding Administrative Law Judge The presiding officer controls the day-to-day activity of a proceeding. That officer may be one or more Commissioners, or one or more Administrative Law Judges (Rule 62). The presiding officer, of necessity, must have the authority to pass on discovery motions and impose sanctions for discovery abuse. To hold otherwise would impose a burden on the Commission that Rules 62 and 63 were designed to avoid. Further, if sanctions could not be imposed by the presiding officer material evidence would remain undisclosed or unconscionable delay incurred as parties seek relief from the Commission. We discuss this problem at length in Re Alternative Regulatory 125 Frameworks for Local Exchange Carriers (1994) 55 CPUC2d 672, where we reviewed a discovery motion to compel granted by a presiding officer (in this instance an ALJ). We said: "We note at the outset, that today's decision is a rare occurrence in that we are reviewing a ruling made by an ALJ before we have considered the merits of the entire proceeding. Normally, we are reluctant to review evidentiary and procedural rulings before the proceeding has been submitted. (See Rule 65.) Our reasoning for that has been expressed previously: `There is no appeal from a procedural or evidentiary ruling of a presiding officer prior to consideration by the Commission of the entire merits of the matter. The primary reasons for this rule are to prevent piecemeal disposition of litigation and to prevent litigants from frustrating the Commission in the performance of its regulatory functions by inundating the Commission with interlocutory appeals on procedural and evidentiary matters.' (D.87070 [81 CPUC 389, 390]; D.90-02-048 at p. 4.) "Parties who contemplate appealing a ruling with which they are dissatisfied should recognize that we frown on such a practice, and view this kind of a decision as the rare exception rather than the rule." (55 CPUC2d at 676.) Since that decision, we have a further reason to assure the presiding officer adequate power to control a hearing. We now have to decide, with few exceptions, adjudicatory cases within 12 months of filing and other matters within 18 months. An impotent presiding officer faced with an intransigent litigant could not manage the case expeditiously, resulting, perhaps, in actual harm to other participants. Under the Administrative Procedure Act ALJs in other agencies have the power to impose discovery sanctions: Government Code Sec. 11455.30. Bad faith actions; Order to pay expenses including attorney's fees (a) The presiding officer may order a party, the party's attorney or other authorized representative, or both, to pay reasonable expenses, including - ------------------ . Government Code section 11405.80. "Presiding officer" "Presiding officer" means the agency head, member of the agency head, administrative law judge, hearing officer, or other person who presides in an adjudicative proceeding. 126 attorney's fees, incurred by another party as a result of bad faith actions or tactics that are frivolous or solely intended to cause unnecessary delay as defined in Section 128.5 of the Code of Civil Procedure. Law Revision Commission Comments: 1995 - Section 11455.30 permits monetary sanctions against a party (including the agency) for bad faith actions or tactics. Bad faith actions or tactics could include failure or refusal to comply with a deposition order, discovery request, subpoena, or other order of the presiding officer in discovery, or moving to compel discovery, frivolously or solely intended to cause delay. A person who requests a hearing without legal grounds would not be subject to sanctions under this section unless the request was made in bad faith and frivolously or solely intended to cause unnecessary delay. An order imposing sanctions (or denial of such an order) is reviewable in the same manner as administrative decisions generally. (Administrative Procedure Act, Government Code Sec. 11400 et seq.) It seems to us incongruous to grant to a presiding officer the authority to control the course of a hearing, rule on all motions, and recommend a decision to the full Commission, and yet deny that officer authority to assure the soundness of the fact- finding process. Without an adequate evidentiary sanction, a party served with a discovery order in the course of a Commission hearing has no incentive to comply and often has every incentive to refuse to comply. Evidentiary sanctions for recalcitrance in discovery are part and parcel of the power to control a hearing and recommend a decision based on all relevant evidence. The presiding ALJ's sanctions against Edison are affirmed. VII. Proposed Decision This decision was issued as a Proposed Decision to which the parties filed comments. Most comments merely reiterated positions taken during the hearing and in briefs already considered. They need no further elaboration. Some comments, however, pointed out details overlooked. Kern River submits that SoCalGas's sale of its pipeline options should be completed earlier than December 31, 1999, as their anticompetitive effect grows steadily as long as they are in existence. Kern River recommends 127 September 1, 1998. We agree that the earlier the sale, the earlier the salutary effects of competition. We have modified this decision accordingly. We note that SoCalGas may not assign the option to a non-affiliate without Kern River's consent, but the option provides that such "consent shall not be unreasonably withheld." Kern River states that if SoCalGas arranges to sell the option to a bona fide non-affiliate through an open-market auction, Kern River will consent to the transfer. Mojave will be treated similarly. CCC/Watson requests establishing a single customer class for all electricity generators to provide several important benefits, including the mitigation of the merged company's ability to design special rates that are favorable to generators of its choice (including affiliates or generators under contract with affiliates), a major market power concern of many participants in this proceeding. SoCalGas has agreed to implement, as a market power mitigation measure, a single electricity generation customer class within its service territory. We will adopt this mitigation measure. On March 9, 1998, Enova and the United States Department of Justice (DOJ) jointly filed in the United States District Court of the District of Columbia the Stipulation and Order requiring Enova to divest SDG&E's gas-fired plants at Encina and South Bay-all of its gas-fired capacity except for certain peaking turbines-within 18 months. Enova's failure to do so will empower an independent trustee to undertake the sale. Each bid for the generation facilities at issue must be approved by the DOJ. Further, Enova's ability to acquire generating capacity in the future is severely constrained. We take official notice of this stipulation. Our divestiture order adds no further burden on applicants. Attachment B has been revised. VIII. Findings of Fact 1. The driving force of the merger of Pacific Enterprises and Enova is to position the companies to be able to compete in the deregulated national energy markets. 2. The proposed merger holds significant strategic benefits for the new company and its shareholders. 128 3. The decision to retain separate identities for SDG&E and SoCalGas provides strategic benefits to applicants. 4. Maintaining the separate identities of the two utilities allows the merged company to benefit from the brand name equity which both companies currently have. 5. A five-year period for the determination of allocable merger savings fairly reflects the changes that are occurring over the near-term in the energy industry. 6. A five-year period for the determination of allocable merger savings closely coincides with the end of the electric restructuring transition period and SDG&E's electric rate freeze, as well as the term of SoCalGas's PBR mechanism. 7. A five-year period for the determination of allocable merger savings is consistent with merger cost savings sharing mechanisms adopted in other jurisdictions for similar utility mergers. 8. Limiting the sharing period to five years recognizes that the applicants' primary reason for pursuing the merger is that the merger will permit the applicants to realize substantial benefits and increased earnings in unregulated business. 9. The ten-year sharing period proposed by applicants will increase regulatory complexity, and, in effect, would freeze rates for ten years, thus defeating the benefits of competition expected to flow from the merger. 10. The alleged risk faced by shareholders does not justify a ten- year sharing period. 11. With a five-year sharing period and properly adjusted costs to achieve, a 50/50 sharing of savings between ratepayers and shareholders is reasonable. 12. The enhanced opportunities and benefits, including future earnings potential associated with the unregulated activities, that will result from the merger will compensate shareholders for Enova's initial post-merger dilution in earnings and Pacific Enterprises's potential reduction in earnings multiple. 13. The need for applicants to undertake this merger in order to be a competitor in the electric services market, and the potential for future earnings from the unregulated businesses as a result of this merger, provide ample incentive to shareholders to 129 undertake this merger. A ten-year sharing period is not needed to provide an incentive to shareholders to enter this merger. A ten-year sharing period is unreasonable. 14. Applicants' proposal to reduce merger savings to ratepayers by $110 million is an attempt to modify the SoCalGas PBR decision to make it more favorable to shareholders. 15. The SoCalGas PBR decision clearly adopted the ORA productivity factor, which included no consideration of the merger at all. 16. Applicants' proposal to ascribe 0.5% of the PBR productivity factor to the merger is without support and unreasonable. 17. In both absolute dollars and as a percentage of savings, the costs to achieve claimed by applicants are higher than for any of the other mergers cited by applicants. 18. Amortizing costs to achieve over a five-year sharing period further reduces shareholder risk of recovering costs to achieve. 19. The investment bankers' opinions were for the benefit of the Boards of Directors and shareholders of applicants, not ratepayers. Investment banking fees of $33 million should be assigned entirely to shareholders, consistent with the Commission's past practice. 20. The requested $20 million in costs to achieve for retention bonuses to officers and executives is not supported by precedent from this Commission or by mergers in other jurisdictions, and applicants have presented no good reason for reducing merger savings in order to further compensate the companies' most highly paid employees. 21. There is no evidence that the $20 million retention/incentive program for corporate officers and other key employees will generate regulatory merger benefits, that the utilities were at risk of losing these employees, or that loss of these employees would reduce merger savings. 22. The long-term incentive programs of applicants were designed to retain executives, obviating the need for partial retention bonuses for the executives. 23. Applicants' proposed advertising costs are clearly related to the activities of the unregulated portions of the merged entities, not to SoCalGas and SDG&E. 130 24. Inclusion of costs for name and logo, radio and television advertising, and a public relations campaign prior to the merger would be unreasonable and inconsistent with this Commission's policies. The $1.3 million of transaction costs to generate a new name and identity for the merged corporation provides equal or greater benefit to the unregulated businesses than to the regulated businesses, as the regulated operations will continue to preserve their separate names and identities and operate as stand- alone distribution companies in two separate geographic areas with two distinct program/ product lines. 25. The Commission should include $320,000 as costs to achieve for internal and external communications. This includes the following costs as identified by applicants: $40,000 for employee packets, $30,000 for media news releases and print material, and $250,000 for bill inserts to inform customers that their service will not be changing as a result of the merger. 26. Merger savings of $435.8 million are reasonable and are adopted. 27. Costs to achieve of $148.1 million are reasonable and should be amortized over a five-year period. 28. Net ratepayer merger savings of $174.9 million shall be allocated 67.4% to SoCalGas ($117.9 million), and 32.6% to SDG&E ($57.0 million). All $174.9 million shall be refunded to ratepayers over five years through an annual bill credit as set forth in this opinion. 29. Applicants' proposal to return the merger savings to customers through an annual bill credit should be adopted. 30. Applicants' proposal to establish memorandum accounts to recognize the customer and shareholder portions of net regulated merger savings is reasonable and should be adopted. 31. Because of the merged entity's small share of the sales at wholesale to any electric utility to which SDG&E is interconnected, the merger will not adversely affect competition in wholesale electricity sales. 32. Because of the large number of firms that are likely to compete for retail electricity customers in California after the onset of competition expected in 1998, and 131 because other firms have skills and experience that are as valuable as those of the merged entity, the merger will not adversely affect competition in retail electricity sales. 33. SDG&E and SoCalGas account for only a small share of retail gas sales to noncore customers, and the merger will only marginally increase the concentration among sellers of gas at retail in southern California, as well as in California. Accordingly, the merger will not adversely affect competition in retail gas sales. 34. Because of the limited extent to which end users may substitute one for the other, natural gas and electricity are not properly considered a single "product" for the purpose of determining the competitive effects of the merger. 35. The producing basins that supply natural gas to California produce about 9,000 Bcf annually, of which SoCalGas's and SDG&E's combined purchases are about 5%. 36. Natural gas prices in the producing basins that serve California, as well as at points downstream, are highly co- integrated, evidencing the fact that those basins comprise, or are components of, a single market. 37. The more than 7,000 MMcf/d of interstate pipeline capacity serving California exceeds peak day demand in California by approximately 50%. 38. SoCalGas holds approximately 20% of the interstate pipeline capacity serving California. 39. Under FERC's capacity release rules, it is impossible for SoCalGas, or any other holder of pipeline capacity, to withhold such capacity from the market. 40. SoCalGas sets the pipeline "window" based on maintaining operational reliability of its transmission system. Because of the large amount of excess pipeline capacity, manipulation of the "windows" at their points of interconnection with upstream pipelines would not enable SoCalGas materially to affect the market price of gas in producing basins serving California. 41. As a general matter, the WSCC constitutes a single integrated market for the sale of electricity, as evidenced by the high degree of co-integration among prices at different locations throughout the WSCC. Any differences between the PX price and the prevailing wholesale price would also be disciplined by marketers and California utility customers who could bypass the PX. 132 42. The correlation between gas spot prices at the California border and electricity spot prices in California is weak; fluctuations in gas prices account for only a small part of the fluctuation of electricity prices. 43. SoCalGas lacks the ability, by manipulating storage injections or withdrawals, to affect spot gas prices to any degree that would enable it consistently to render the position taken by an affiliate in gas or electricity futures contracts profitable. Other factors, such as weather, storage demand, and overall storage levels, affect futures prices to a far greater degree. 44. An increase in delivered gas prices to generators served by SoCalGas would cause losses in transportation revenues to SoCalGas that exceed any gains in electricity revenues to SDG&E or to SoCalGas's investments in the electricity futures market. 45. SoCalGas has a near monopoly in the gas transmission market in southern California. 46. The relevant geographic area of the gas transmission market is southern California, which consists of the counties corresponding to the combined SoCalGas, SDG&E, and Long Beach service territories. For gas purchases, the relevant markets are the basins supplying gas to southern California. 47. The relevant product markets are delivered gas, storage, and hub services, plus retail electricity. For gas sales, the relevant geographic market is southern California. 48. SoCalGas owns and operates the greatest share of the intrastate capacity found within southern California. 49. SoCalGas sells unbundled gas delivery services, including gas transmission, gas distribution, and gas storage, under separate tariffs, for noncore customers including UEGs. 50. SoCalGas serves forty-two different electric power plants with a total of 15,837 MW of generating capacity. 51. This 15,837 MW of gas-fired generating capacity constitutes 96% of all gas-fired capacity in southern California. 133 52. Gas-fired generators competing with the merged company will have few, if any, alternatives to SoCalGas for delivered gas service, other than the expansion of Kern River and Mojave. 53. SoCalGas's near-monopoly on delivered gas service in southern California means that it has access to potentially sensitive market information regarding those competing generators' costs and fuel usage. 54. SoCalGas's transportation and storage system constitutes a natural monopoly in southern California. 55. SoCalGas is the dominant supplier of delivered gas services to approximately 100 gas-fired utility generating stations and cogeneration facilities located in southern California, including 11 of Edison's 12 generating facilities and all of SDG&E's generating facilities. 56. For gas purchased outside of California, SoCalGas provides the only intrastate transportation service available to the majority of the electric generating stations located in southern California. 57. SoCalGas primarily purchases natural gas from Southwest supply basins and transports that gas over the El Paso and Transwestern pipelines. 58. SoCalGas is a dominant holder of interstate capacity out of the southwestern United States. 59. SoCalGas has capacity rights totaling 1,450 MMcf/d on El Paso and Transwestern, of which it reserves approximately 1,044 MMcf/d for core needs. 60. SoCalGas can release capacity not needed to serve the core into the secondary capacity market. 61. SoCalGas provides hub services (loaning, parking, and wheeling services) on a best efforts, interruptible basis at rates negotiated by the parties based on prevailing market conditions and individual customer circumstances. 62. SoCalGas is the only provider of hub services in southern California. 63. SoCalGas has significant latitude in pricing hub services, which absent regulation could lead to discrimination against nonaffiliated shippers. 134 64. SoCalGas can declare an overnomination event (under Rule 30) which allows SoCalGas to impose daily balancing requirements on shippers and can affect shippers' nominations. SoCalGas has discretion regarding whether to declare a Rule 30 event, but this could be modified by Commission action. 65. SoCalGas has discretion in determining the daily receipt point capability at each interstate pipeline interconnect (window). After establishing the daily window, SoCalGas allocates that window to the various receipt points on its system. 66. When SoCalGas determines that it cannot receive the full amount of gas nominated for delivery to a particular receipt point, SoCalGas informs the interconnecting interstate pipeline who imposes a "custody cut," prorating the shippers' nominations to match the allocated window. 67. SoCalGas has discretion regarding whether to provide hub services and whether to suspend those services once initiated. 68. SoCalGas can and does provide cost-free operational services in lieu of hub services at negotiated rates. 69. Under its interpretation of the term "similarly-situated," SoCalGas will be required to offer nonaffiliated shippers the same discount it provides to affiliated shippers. 70. SoCalGas has a substantial amount of market area storage located behind the city gate. 71. SoCalGas has considerable flexibility in the operation of its storage facilities. 72. SoCalGas is the largest single purchaser of gas in the southern California market, averaging 31% of the gas purchased each day in the region. 73. SoCalGas has limited ability to change its volume of gas purchases daily by using its significant amount of gas storage. 74. In combination, the merged company will be responsible for about 39% of the gas purchases for southern California. 75. PX prices will be set by gas-fired generation at least during certain portions of the year. 135 76. Assuming SoCalGas could use its monopoly of the gas delivery system to increase the cost of gas to electric generation customers, and, thus, drive up PX prices, it has no incentive to do so. It would lose more throughput revenue than it would gain otherwise. 77. Assuming SoCalGas's discretion over the day-to-day operations of its system gives the merged entity opportunities to increase costs for its UEG customers who are wholesale electric competitors of SDG&E, SoCalGas lacks the incentive to utilize these opportunities 78. SoCalGas does not have buyer market power to reduce PX prices during periods of high demand for electricity by moving substantial additional quantities of gas from storage rather than purchasing gas. 79. The FERC imposed Order No. 497 restrictions on SoCalGas and required applicants to revise their commitments so that the restrictions and requirements would be applicable to the corporate family as a whole. 80. SoCalGas should be required to submit all contracts with SDG&E (or any other affiliate) that deviate from Commission-approved tariffs for prior Commission review and approval, including any discounted transportation agreements or any rate design agreements. 81. SoCalGas controls approximately 30% of the interstate pipeline capacity from the San Juan Basin gas production area to SoCalGas's pipeline system at the Arizona-California border. 82. SDG&E is one of the largest purchasers of natural gas in southern California. Its purchases comprise, on average, about 9% of all daily purchases in southern California. 83. SDG&E is engaged in the generation and sale of electric energy. SDG&E owns and operates gas-fired generation plants. 84. SoCalGas is the sole transporter of gas to SDG&E and its customers. 85. SDG&E procures gas for its core and non-core customers, as well as for its UEG operations. 86. Gas-fired generation located in southern California is likely to be "on the margin," and therefore will set the market price for electric energy, in the California PX 137 during one-half or more of all hours and during an even greater proportion of peak demand hours. 87. Restructuring of California's electric services industry and creation of the PX, combined with the substantial reliance by the state's electric generators on gas-fired generating plants, will create a strong relationship between the gas-fired generators' cost of gas delivered to their burnertips and the prevailing price for electric energy in the PX during certain hours. 88. There are significant barriers to entry by new gas transmission pipelines in the southern California gas market. 89. SoCalGas possesses market power in the market for natural gas transportation services in southern California, but that market power is subject to regulation by this Commission. 90. The establishment of a single customer class for all electricity generators in SoCalGas's service territory will mitigate the ability of the merged company to use its market power in the gas industry to affect prices in the electricity generation market in an anticompetitive manner. 91. The establishment of a single class for all electricity generators will provide a legal playing field for all gas-fired generators that receive gas service from SoCalGas by ensuring that all generators have access to monopoly intrastate gas transportation service at equitable rates. 92. Establishment of a single customer class for all electricity generators in SoCalGas's service territory is in the public interest and should be adopted as a condition to the merger. 93. The merger creates the potential for vertical market power due to SoCalGas's potential conflict of interest in providing preferential treatment to its affiliate SDG&E over other electric generators that will compete with SDG&E's generation. 94. The most direct and effective means to avoid SoCalGas's potential conflict of interest, and to mitigate the regulatory burden of attempting to police such affiliated transactions, is for SDG&E to divest its gas-fired electric generation facilities. 137 95. The merger of SoCalGas and SDG&E will increase the concentration of the gas transportation system in southern California by the two local distribution companies. 96. Divestiture of SDG&E's gas-fired generation is the most efficient way to mitigate potential market power abuses. Divestiture of gas-fired generation would eliminate the incentive to engage in cross-subsidy and anticompetitive behavior. 97. SDG&E in the past has evaluated alternative pipelines to bypass the SoCalGas system and has found at least two such alternatives to be economically and technically feasible at the time of its evaluations. 98. The proposed merger will effectively remove SDG&E as a potential customer of a new gas transmission pipeline in southern California, but divestiture of its gas-fired generation would create a competitive load. 99. Kern River and Mojave are the only interstate pipelines in California. 100. Kern River and Mojave provide the only meaningful competition for SoCalGas for transportation service to noncore and wholesale customers in southern California. Such competition includes the potential for pipeline expansions and extensions of the Kern River and/or Mojave systems in southern California. 101. SoCalGas holds contractual options to purchase the facilities of Kern River and Mojave in California in the year 2012. 102. Kern River is a potential alternative transporter of gas to up to one-half of all existing gas-fired generation capacity in southern California and to new gas-fired generation plants. 103. SoCalGas's options to acquire the Kern River and Mojave facilities impede competition by Kern River and Mojave presently and give SoCalGas the ability to eliminate its only meaningful pipeline competition in the near future and within the time horizon relevant to the Commission's consideration of this proposed merger. 104. Effective mitigation of the proposed merger's adverse effects on competition requires ensuring that SoCalGas will be subjected to meaningful competitive discipline in providing gas transportation services to gas-fired electric generators in southern California. 138 105. Ensuring that SoCalGas will be subjected to meaningful competitive discipline in providing gas transportation services to gas-fired electric generators in southern California after the merger requires elimination of SoCalGas's options to acquire the Kern River and Mojave facilities. 106. The elimination of SDG&E as a separate potential competitor and customer has a detrimental effect on competition in the gas transmission market. 107. The loss of an independent SDG&E would reduce the potential for pipeline-to-pipeline competition to discipline gas transportation rates in southern California. 108. SDG&E is one of the few companies that could anchor the construction of a major new pipeline into southern California. 109. The threat of bypass provides a powerful motivation for the utility to reduce its rates to competitive levels. 110. A major new pipeline project to serve the SDG&E territory, such as Kern River or Mojave, could be expected to exercise additional competitive discipline on SoCalGas' rates throughout its service territory. 111. The agreement between SoCalGas and Kern River permitting SoCalGas the option to purchase Kern River's California facilities in 2012 was an arms' length commercial transaction. SoCalGas's options to purchase Kern River's and Mojave's California facilities have clear value. 112. SoCalGas's options to purchase Kern River's California facilities and Mojave's California facilities are related to the merger as a mitigation measure to assure competition in the delivered gas market in southern California. 113. It is not in the public interest for SoCalGas to exercise the option to purchase Kern River's California facilities or Mojave's California facilities. 114. As a measure to mitigate the adverse effect on competition created by this merger, SoCalGas should sell its options to purchase Kern River's and Mojave's California facilities to a nonaffiliate of the merged company on or before September 1, 1998. 115. SoCalGas's gas procurement group is an integral part of SoCalGas's operations. 139 116. SoCalGas operations personnel have regular contact with SoCalGas gas procurement personnel, interacting through meetings, telephone conversations, memoranda, and electronic mail. 117. The supply of gas, the purchase of gas, and the scheduling of gas associated with core activities are integral to the operations of SoCalGas's system. SoCalGas operation personnel need to be aware of and knowledgeable about what is occurring on the gas procurement side. 118. There is no evidence that SoCalGas has manipulated its system in the manner described by intervenors to intentionally increase costs to customers. In releasing its interstate pipeline capacity it has sought to obtain the highest price possible, which is a direct benefit to its ratepayers. 119. The merger will maintain the existing legal and regulatory status of SDG&E and SoCalGas. 120. There will be no change to the status of outstanding securities or debt of SDG&E and SoCalGas, and both will remain separate entities with their own Commission-approved capital structures. 121. The quantitative measures of financial strength commonly considered by bond rating agencies are expected to improve or stay the same for both SDG&E and SoCalGas after the merger, for the foreseeable future. 122. Bond rating agencies expect that both SDG&E and SoCalGas should maintain their current bond ratings after the merger. 123. The financial constraints established by the Commission in the SDG&E parent company decision to help safeguard SDG&E's financial condition will be extended to SoCalGas by applicants after the merger. 124. The merger is expected to maintain or improve the financial condition of SDG&E and SoCalGas. 125. The merger is expected to maintain the quality of service to SDG&E and SoCalGas ratepayers. 126. Greenlining's proposal that applicants establish a Community Education Trust Fund is irrelevant to the Commission's review of the merger and is rejected. 140 127. Greenlining's and Latino Issues Forum's various fund-creation proposals have nothing to do with this merger and would be a disservice to the public interest. 128. Latino Issues Forum's proposals regarding CARE and low-income weatherization programs are irrelevant to the Commission's review of the merger and should be considered in other Commission forums addressing low-income issues. 129. ORA's proposal to require applicants to file an advice letter prior to closing or changing authorized payment agencies is unnecessary. 130. TURN's proposal to make branch office closures contingent on specific criteria including call center performance and adequacy of replacement services, is rejected because the rationale for office closures will necessarily vary from location to location. 131. The merger brings together two experienced management teams with complementary skills and experience. The merger will provide SDG&E and SoCalGas access to additional management skills and resources. The merger is expected to maintain the quality of SDG&E's and SoCalGas's managements. 132. The merger will be fair and reasonable to SDG&E and SoCalGas employees, including both union and nonunion employees. 133. The conversion ratio agreed upon by Enova and Pacific Enterprises is fair to the shareholders of both companies. 134. The merger will be fair and reasonable to the majority of Enova and Pacific Enterprises shareholders. 135. The merger will be beneficial on an overall basis to state and local economies and to the communities in the areas served by SDG&E and SoCalGas. 136. UCAN's proposal for the Commission to mandate charitable contributions at a specific level is without support in fact or law. 137. Greenlining's proposal that SDG&E's annual charitable contributions equal or exceed $5 million or the total compensation of its top five officers, is without support in fact or law. 138. ORA has not shown why additional reporting requirements for charitable contributions are necessary. 141 139. UCAN's recommendation that the merged company be required to maintain a particular ratio of its employees in San Diego is without support in fact or law. 140. Applicants have demonstrated that their strong commitment to supplier diversity and the WMDVBE program will continue after the merger. 141. UCAN's proposal that SDG&E maintain a Hispanic contracting goal of 25% is misplaced in this proceeding. 142. Applicants have demonstrated that their commitment to conservation, energy efficiency, and environmental issues will be sustained after the merger. 143. NRDC's proposal to modify the utilities' PBR mechanisms to encourage energy efficiency is misplaced in this proceeding. 144. NRDC's proposals that applicants support a natural gas public purpose programs surcharge and increase their commitment to such programs belong in the Commission's gas industry restructuring proceeding. Similarly, NRDC's proposal to establish future levels for natural gas public purpose programs is not germane to this application. 145. TURN's proposal to prohibit the merged company from engaging in ex parte communications at the Commission is without merit and is rejected. 146. After the merger, both SDG&E and SoCalGas will remain separate Commission-regulated public utilities, subject to all of the Commission's regulatory authority and audit power. 147. The merger will preserve the jurisdiction of the Commission and the capacity of the Commission to effectively regulate and audit SDG&E's and SoCalGas's public utility operations. 148. Post-merger, SoCalGas and SDG&E will combine the functions of their calling centers during seasonal peaks, periods of emergency volume, and in answering calls such as requests for seasonal lights, meter turn-ons, and meter closes. 149. In order to prevent SoCalGas's call center from off-loading calls to SDG&E's call center to avoid a penalty, which will at the same time adversely impact SDG&E's customer service quality, as well as to minimize the administrative costs of measuring 142 the companies' respective customer service performances, SDG&E's customer service standards should be aligned with SoCalGas's. 150. SDG&E's management training programs are much more extensive than SoCalGas's. SoCalGas should implement SDG&E's management training programs. 151. SoCalGas shall, following the merger, have separate transportation and storage contracts for SDG&E's UEG and non-UEG loads. 152. The Commission will not use the merger proceeding to address changes in wholesale rate design or cost allocation. 153. Issues raised by ORA in connection with the SoCalGas-SDG&E storage contract are not merger-related and will not be addressed in this proceeding. 154. The revenue sharing agreement between SoCalGas and SDG&E pre- dated the merger and will be examined in pending A.97-03-015. 155. Intervenors have not demonstrated any need for, or the costs and benefits of, a gas ISO. 156. SDG&E's current Base Rate PBR mechanism does not have a specific objective indicator that focuses on call center performance. 157. SDG&E's percent of calls answered within 60 seconds has declined since mid-1996 and was well below the objective standard applicable to SoCalGas by mid-1997. 158. In comparison to other utilities nationwide and in California, SDG&E's telephone performance is considerably worse. 159. The Commission prepared an Initial Study demonstrating that the proposed merger would not have a significant effect on the environment. The Commission prepared a Negative Declaration which was made available for a 30-day public review and comment period. The Commission responded to comments made on the proposed Negative Declaration and published a final Negative Declaration and Initial Study. 160. The Commission has independently reviewed and analyzed the Negative Declaration and finds that the document reflects its independent judgment. 161. Based upon the record as a whole, including the Initial Study, there is no substantial evidence that the merger may have one or more significant effects on the environment. 143 162. The Negative Declaration and Initial Study have been prepared in compliance with the requirements of CEQA and Rule 17.1. 163. The Negative Declaration should be adopted. 164. The Commission should file a Notice of Determination with the Office of Planning and Research pursuant to 14 CCR Sec. 15075. 165. Excluding Line 6900 Phase II and III from SoCalGas's Resource Plan would shift approximately $4 million from noncore to core customers, resulting in higher rates for core customers and lower rates for noncore customers.The removal of the Line 6902 expansion from SoCalGas's Resource Plan should be addressed in SoCalGas's next cost allocation proceeding. 166. The Commission will not use the merger proceeding to change SoCalGas's Resource Plan. 167. The merger provides short-term and long-term economic benefits to ratepayers. 168. The merger equitably allocates the total short-term and long- term forecasted economic benefits from the merger, between shareholders and ratepayers, by adopting a 50/50 division of the benefits. 169. The mitigation measures proposed by the applicants, in conjunction with (a) this Commission's ongoing regulation of SoCalGas and SDG&E, (b) restrictions adopted in the Affiliate Transaction Rulemaking, (c) ongoing monitoring by the ISO and PX as required by FERC's orders in Docket Nos. EC96-19 and ER96-1663, (d) divestiture of SDG&E's gas-fired generation and SoCalGas's options to purchase Kern River and Mojave, and (e) hiring of an independent firm to ensure compliance with applicable safeguards, effectively protect against the exercise of market power by the merged entity. The proposed merger properly mitigated will not adversely affect competition; in fact, it will enhance competition. With the adoption of the mitigation measures ordered by this decision, the merger does not adversely affect competition. 170. On balance, the merger is in the public interest. 144 IX. Conclusions of Law 1. The proposed merger complies with PU Code Sec. 854 and should be authorized, with conditions. 2. As conditions of the merger: a. On or before September 1, 1998, SoCalGas shall sell its options to purchase the California facilities of Kern River and Mojave pipelines to nonaffiliates of the merged company. b. On or before December 31, 1999, SDG&E shall sell its gas-fired generation facilities to nonaffiliates of the merged company. c. The merged company shall adopt the mitigation measures set forth in Attachment B. d. Applicants shall consent to the hiring of an independent firm to ensure compliance with applicable safeguards. 3. The discovery rulings of the presiding ALJ are affirmed; Edison shall comply forthwith. 4. Applicants' request for admission of late-filed Exhibit 433 is denied; Greenlining's Motion to take Official Notice of Facts is denied. 5. Section 851 approval is hereby granted to the extent necessary to achieve the savings from this merger. 6. The Commission has the authority and shall enforce SoCalGas's compliance with FERC Order 497 and each other remedial measure ordered by this decision. ORDER IT IS ORDERED that: 1. The application of Pacific Enterprises, Enova Corporation, Mineral Energy Company, B Mineral Energy Sub and G Mineral Energy Sub for approval of a plan of merger of Pacific Enterprises and Enova Corporation with and into B Energy Sub and G Energy Sub, the wholly owned subsidiaries of a newly created holding company, Mineral Energy Company, is granted on conditions. 145 2. As conditions of the merger: a. By September 1, 1998, Southern California Gas Company (SoCalGas) shall sell its options to purchase the California facilities of Kern River Gas Transmission Company and Mojave Pipeline Company to an entity or entities not affiliated with the merged company. If SoCalGas has not arranged such sales to Kern River and Mojave, respectively, within 60 days after the effective date of this order, it shall post a notice of the sale of the options on its electronic bulletin board, GasSelectTM, and shall conduct an open-bid, cash auction for each option for qualified bidders. If such an auction is held, no affiliate of the merged company may participate in it. SoCalGas shall complete the sale to the winning bidder for each option within the time set by this paragraph. b. On or before December 31, 1999, San Diego Gas & Electric Company (SDG&E) shall sell its gas-fired generation facilities to nonaffiliates of the merged company. c. The merged company shall adopt the mitigation measures set forth in Attachment B to this decision. d. SoCalGas and SDG&E shall return merger savings in the amount of $174.9 million in the manner set forth in this decision and shall file an advice letter to be approved by the Energy Division providing the procedures to be used. e. Applicants shall consent to the hiring of an independent firm to ensure compliance with applicable safeguards. 3. Applicants shall file written notice with the Commission, served on all parties to this proceeding, of their agreement, evidenced by a resolution of their respective boards of directors duly authenticated by a secretary or assistant secretary, to the conditions set forth in this decision. Failure of applicants to file such notice and failure of applicants to merge their companies pursuant to this order within 60 days after the final jurisdictional approval is received shall result in the lapse of the authority granted by this decision. 4. This Commission has the authority and shall enforce SoCalGas's compliance with Federal Energy Regulatory Commission Order No. 497 and each of the other remedial measures ordered by this decision. 5. The discovery rulings of the presiding Administrative Law Judge are affirmed; Southern California Edison Company shall comply forthwith. 146 6. The Executive Director shall file a Notice of Determination of the Negative Declaration with the Office of Planning and Research. 7. The Executive Director shall take the necessary steps to develop a contract for the hiring of an independent firm with sufficient technical expertise to carry out the duties assigned to it over the time period specified in this decision. The contract shall not be effective until approved by a vote of the Commission. The firm's duties shall be to monitor, audit, and report on how the combined utilities a) operate their gas system, b) comply with adopted safeguards to ensure open and nondiscriminatory service, c) comply with the restrictions and guidelines in Attachment B and to raise concerns of market power abuse identified during its review. The firm shall have continuous access to the gas control rooms of applicants, and to all appropriate records, operating information, and data of applicants. The applicants at shareholders' expense will reimburse the Commission for all costs of the firm. This order is effective today. Dated March 26, 1998, at San Francisco, California. RICHARD A. BILAS President P. GREGORY CONLON JESSIE J. KNIGHT, JR. HENRY M. DUQUE JOSIAH L. NEEPER Commissioners I will file a concurring opinion. /s/ P. GREGORY CONLON Commissioner 147 SERVICE LIST Last updated on 09-MAR-1998 by: LIL A9620038 LIST **************APPEARANCES************** Catherine E. Yap BARKOVICH AND YAP, INC Marc D. Joseph PO BOX 11031 L. REYNOLDS OAKLAND CA 94611 Attorney (510) 652-9778 ADAMS AND BROADWELL For: SOUTHERN CALIFORNIA 651 GATEWAY BLVD., SUITE 900 UTILITY POWER POOL SO SAN FRANCISCO CA 94080 For: IBEW LOCALS 18 AND 47 Reed V. Schmidt Vice President Evelyn K. Elsesser BARTLE WELLS ASSOCIATES Attorney at Law 1636 BUSH STREET ALCANTAR AND ELSESSER LLP SAN FRANCISCO CA 4109 SUITE 2420 (415)775-3113 ONE EMBARCADERO CENTER For: CALIFORNIA CITY-COUNTY SAN FRANCISCO CA 94111 STREET LIGHT ASSOC (415) 421-4143 For: ENERGY PRODUCERS AND USERS COLLATION Michael P. Alcantar John Burkholder Atty At Law BETA CONSULTING ALCANTAR AND ELSESSER LLP SUITE 601 ONE EMBARCADERO CENTER SUITE 2420 4364 BONITA ROAD SAN FRANCISCO CA 94111 BONITA CA 91902 For: COGENERATION ASSN. OF CALIFORNIA (619) 479-1290 For: CITY OF LONG BEACH Susan Bergles Attorney At Law BRADY AND BERLINER ALCANTAR AND ELSESSER LLP 1225 19TH ST, NW, SUITE 800 SUITE 2420 WASHINGTON DC 20036 ONE EMBARCADERO CENTER For: CITY OF VERNON SAN FRANCISCO CA 94111 (415) 421-4143 For: INDICATED PRODUCERS Roger Berliner BRADY AND BERLINER 1225 19TH ST. NW, STE 800 David J. Bardin Esq WASHINGTON DC 20036 ARENT FOX KINTNER PLOTKIN & KAHN For: WATSON COGENERATION CO 105 CONNECTICUT AVE., N.W. WASHINGTON DC 29936-5336 Susan Brown Legal Counsel Melissa Metzler 785 MARKET STREET 3RD FLOOR BARAKAT AND CHAMBERLIN SAN FRANCISCO CA 94103-2003 1800 HARRISON STREET, 18T FL. (415) 284-7220 OAKLAND CA 94612 For: LATINO ISSUES FORUM SERVICE LIST Lindsay Bower Tom Beach JOHN W. JIMISON CROSSBORDER, INC. Attorney At Law STE 316 CALIFORNIA DEPARTMENT OF JUSTICE 2560 9TH STREET SUITE 300 BERKELEY CA 94710 50 FREMONT STREET (510) 649-9790 SAN FRANCISCO CA 94105 For: SELF Traci Bone Attorney At Law Ronald Liebert DAVIS WRIGHT TREMAINE Associate Counsel SUITE 600 CALIFORNIA FARM BUREAU FEDERATION ONE EMBARCADERO CENTER 2300 RIVER PLAZA DRIVE SAN FRANCISCO CA 94111 SACRAMENTO CA 95833 For: ENSERCH ENERGY (916) 561-5657 SERVICES, INC. Francisco V. Chavez Frank De Rosa 3534 FIRST AVENUE 100 PINE STREET SACRAMENTO CA 95817 SAN FRANCISCO CA 94111 For: U.S. GENERATING CO Ronald V. Stassi CITY OF BURBANK - PUBLIC SERVICE DEPT Tamara Dragotta 164 WEST MAGNOLIA BOULEVARD SUITE 105 BURBANK CA 91502 4000 EXECUTIVE PARKWAY (818) 238-3651 SAN RAMON CA 94583-4206 For: CITY OF BURBANK For: DUKE/LOUIS DREYFUS Bernard V. Palk Donald R. Allen Public Service Department JOHN COYLE CITY OF GLENDALE Attorneys At Law 4TH LEVEL DUNCAN AND ALLEN 141 NORTH GLENDALE AVENUE SUITE 300 GLENDALE CA 91206 1575 EYE STREET, NW (181) 548-3179 WASHINGTON DC 20005-1175 For: CITY OF GLENDALE For: IMPERIAL IRRIGATION DISTRICT Deborah Bergert T. MC ATTEER Barry F. Mc Carthy CITY OF SAN DIEGO Attorney At Law SUITE 1200 DUNCAN WEINBERG MILLER & 1200 THIRD AVENUE PEMBROKE, P.C. SAN DIEGO CA 92101 MCCANDLESS TOWER For: CITY OF SAN DIEGO 3945 FREEDOM CIRCLE, ST 620 SANTA CLARA CA 95054 For: SOUTHERN CALIFORNIA Nicholas W. Fels PUBLIC POWER AUTHORITY COVINGTON AND BURLING 1201 PENNSYLVANIA AVENUE, NW WASHINGTON DC 20044-7566 Wallace L. Duncan For: ENOVA CORPORATION Attorney At Law DUNCAN WEINBERG MILLER PERMBROKE 1615 M STREET, NW STE 800 WASHINGTON DC 20036 For: SO CA PUBLIC POWER AUTH SERVICE LIST Joseph R. Deulloa Catherine George Legal Division Attorney At Law RM 5035 GOODIN MACBRIDE SQUERI 505 VAN NESS AVE SCHLOTZ & RITCHIE SAN FRANCISCO CA 94102 SUITE 900 (415) 703-1998 505 SANSOME STREET For: ORA SAN FRANCISCO CA 94111 (415) 392-7900 For: ENRON CAPITOL & TRADE John Morris RESOURCES/PAN-ALBERT GAS LTD ECONOMISTS, INC. SUITE 400 1200 NEW HAMPSHIRE AVE., NW WASHINGTON DC 20036 James D. Squeri For: CITY OF SAN DIEGO T. J. MACBRIDE Attorney At Law GOODIN MACBRIDE SQUERI Carolyn A. Baker SCHLOTZ & RITCHIE Attorney At Law 234 VAN NESS AVENUE EDSON AND MODISETTE SAN FRANCISCO CA 94102 925 L STREET, SUITE 1490 (415) 703-6000 SACRAMENTO CA 95814 For: NUTRASWEET KELCO CO (916) 552-7070 For: SHEVRON, U.S.A./OTHER INTERESTED CLIENTS James W. Mc Tarnaghan Attorney At Law GOODIN MACBRIDE SQUERI SCHLOTZ & RITCHIE James Mccotter SUITE 900 PHILIP ENDOM 505 SANSOME STREET Regulatory Analyst SAN FRANCISCO CA 94111 EL PASO NATURAL GAS COMPANY (415) 392-7900 SUITE 2400 For: ENRON CAPITAL AND TRADE 650 CALIFORNIA STREET RESOURCES/STRATEG INTEGRATED SAN FRANCISCO CA 94108 (415) 765-6400 Thomas J. Macbride, Jr. Attorney At Law Christopher Ellison GOODIN MACBRIDE SQUERI Attorney At Law SCHLOTZ & RITCHIE ELLISON AND SCHNEIDER SUITE 900 2015 H STREET 505 SANDOME STREET SACRAMENTO CA 95814-3109 SAN FRANCISCO CA 94111 (916) 447-2166 For: CITY OF VERNON For: INDEPENDENT ENERGY PRODUCERS ASSOC Martin A. Mattes P. HANSCHEN E. Gregory Barnes Attys. At Law ENOVA CORPORATION GRAHAM AND JAMES LAW DEPARTMENT SUITE 300 PO BOX 129400 ONE MARITIME PLAZA SAN DIEGO CA 92112-9400 SAN FRANCISCO CA 94111-3492 (415) 954-0313 For: AGRICULTURAL ENERGY Ruben J. Garcia CONSUMERS ASSN. 600 S NEW HAMPSHIRE AV 2ND FLR LOS ANGELES CA 90005 For: GAS WORKERS COUNCIL LOCALS Gil Guevara 132, 483, 170, 522 PO BOX 1681 SANTA MARIA CA 93456 For: AMERICAN G.I. FORUM OF CA CONSUMER EDUCATION SERVICE LIST Rufus Hightower Christopher A. Hilen 150 S. LOST ROBLES STREET, STE 200 Attorney At Law PASADENA CA 91101 LEBOEUF LAMB GREEN&MACRAELLP (626) 405-4478 SUITE 400 For: CITY OF PASADENA ONE EMBARCADERO CENTER SAN FRANCISCO CA 94111 (415) 951-1141 James Hodges For: PACIFIC GAS TRANS CO 4720 BRAND WAY SACRAMENTO CA 95819 Ed Perez Assistant City Attorney L A CITY ATTORNEY'S OFFICE William Marcus CITY HALL EAST Cnsltg Economist 200 NORTH MAIN ST., RM 1800 J B S ENERGY, INC. LOS ANGELES CA 90012 SUITE A For: JAMES K HAHN, CTY ATTNY 311 D STREET SACRAMENTO CA 95605 Stanton J. Snyder (916) 372-0534 LA DEPT OF WATER & POWER For: JBS ENERGY, INC. ROOM 340 111 N. HOPE STREET LOS ANGELES CA 90012-2694 Norman Pedersen (213) 367-4540 Attorney At Law JONES DAY REAVIS AND POGUE David Marcus ONE METROPOLITAN SQUARE PO BOX 1287 140 'G' STREET, NW BERKELEY CA 94701-1287 WASHINGTON DC 20005-2088 (510) 528-0728 For: SOUTHERN CALIFORNIA UTILITY For: IBEW LOCALS 18 & 47 POWER POOL (SCUPP) James R. Dodson MINERAL ENERGY COMPANY Mark C. Moench PO BOX 1831 Attorney At Law 101 ASH STREET KERN RIVER GAS TRANSMISSION COMPANY SAN DIEGO CA 92112 295 CHIPETA WAY SALT LAKE CITY UT 84108 Jerry R. Bloom (801) 584-7059 JOSEPH KARP/LISA COTTLE For: KERN RIVER GAS TRANSMISSION Attorney At Law MORRISON & FOERSTER LLP 425 MARKET STREET Yvonnne Ladson Webb SAN FRANCISCO CA 94105-2482 Atty. At Law For: CA COGENERATION COUNCIL LADSON ASSOCIATES 870 MARKET STREET, SUITE 765 Robert B. Weisenmiller SAN FRANCISCO CA 94102 MRW & ASSOCIATES (415) 296-8388 1999 HARRISON ST, STE 1400 For: PASADENA WATER & POWER DEPT OAKLAND CA 94612-3517 (510) 834-1994 For: CITY OF SAN DIEGO SERVICE LIST Sheryl Carter Douglas A. Oglesby Senior Project Policy Analyst VP & General Counsel NATURAL RESOURCES DEFENSE COUNCIL PG&E ENERGY SERVICES 71 STEVENSON STREET, SUITE 1825 SUITE 2600 SAN FRANCISCO CA 94105 345 CALIFORNIA STREET (415) 777-0220 SAN FRANCISCO CA 94104 (415) 733-4500 For: VANTUS ENERGY CORP Roy E. Potts Attorney At Law Patrick J. Power OVERTON, LYMAN AND PRICE Attorney At Law 37TH FLOOR 2101 WEBSTER ST RM 1500 777 SOUTH FIGUEROA OAKLAND CA 94612 LOS ANGELES CA 90017 (510) 446-7742 For: CITY OF LONG BEACH Daniel J. Mccarthy Edward C. Remedios Attorney At Law 33 TOLEDO WAY PACIFIC BELL SAN FRANCISCO CA 94123-2108 SIXTEENTH FLOOR For: BHR & Associates 140 NEW MONTGOMERY STREET SAN FRANCISCO CA 94105 Patrick Mealoy (415) 542-7547 RESOURCE MANAGEMENT INT'L SUITE 600 3100 ZINFANDEL DRIVE Brian Cherry SACRAMENTO CA 85670 PACIFIC ENTERPRISES For: RESOURCE MGMT INT'L 555 WEST 5TH STREET, M.L. 25A1 LOS ANGELES CA 90013-1011 Robert B. Keeler Attorney At Law REZNIK & REZNIK Joyce A. Padleschat 5TH FLOOR PACIFIC ENTERPRISES 15456 VENTURA BLVD. B MINERAL ENERGY SUB MINERAL ENERGY SHERMAN OAKS CA 91403-3026 633 WEST FIFTH STREET, SUITE 5200 For: self LOS ANGELES CA 90071 James D. Bliesner Reinvestment Director Patrick G. Golden SAN DIEGO CITY/COUNTY Attorney At Law REINVESTMENT TASK PACIFIC GAS & ELECTRIC COMPANY 3989 RUFFIN RD MS 0231 LAW DEPARTMENT SAN DIEGO CA 92123 PO BOX 7442 SAN FRANCISCO CA 94120 Patricia Diaz Dennis (415) 973-6642 Assistant General Counsel SBC COMMUNICATIONS INC. 175 E. HOUSTON STREET 4-A-70 Jane Pearson SAN ANTONIA TX 78205 TOM SKUPNJAK SUITE 150 2500 CITY WEST BOULEVARD HOUSTON TX 77042 For: CHALK CLIFF, LTD./ MCKITTRICK, LTD. SERVICE LIST Janet K. Lohmann Theresa Mueller JONATHAN ABRAM Attorney At Law Attorney At Law THE UTILITY REFORM NETWORK SOUTHERN CALIFORNIA EDISON COMPANY SUITE 350 PO BOX 800 711 VAN NESS AVENUE 2244 WALNUT GROVE AVENUE SAN FRANCISCO CA 94102 ROSEMEAD CA 91770 (415) 929-8876 Stephen E. Pickett Michael Shames Attorney At Law C. CARBONE SOUTHERN CALIFORNIA EDISON COMPANY Attorney At LAW PO BOX 800 UTILITY CNSMRS ACTION NTWRK 2244 WALNUT GROVE AVENUE 1717 KETTNER BLVD STE. 105 ROSEMEAD CA 91770 SAN DIEGO CA 92101-2532 For: EDISON & EDISON INT'L (619) 696-6966 Andrew J. Van Horn David J. Gilmore VAN HORN CONSULTING LESLIE E. LO BAUGH,D.GILMORE,D.FOLLETT 61 MORAGA WAY, SUITE 1 Attorney At Law ORINDA CA 94563-3029 SOUTHERN CALIFORNIA GAS COMPANY 633 WEST FIFTH ST RM 5200 LOS ANGELES CA 90071-2071 Alan R. Watts (213) 895-5138 Attorney At Law For: PACIFIC ENTERPRISES WOODRUFF SPADLIN & SMART SUITE 7000 701 S. PARKER STREET Eric Woychik ORANGE CA 92668 STRATEGY INTEGRATION For: SO CA PUBLIC PWR ATH'TY 9901 CALODEN LANE OAKLAND CA 94605 Jeanne M. Bennett (510) 635-2359 Attorney At Law WRIGHT & TALISMAN 1200 G STREET John R. Staffier WASHINGTON DC 20005 STUNTZ & DAVIS For: ENRON CPTL & TRADE RES SUITE 819 1201 PENNSYLVANIA AV NW Michael J. Thompson WASHINGTON DC 20004 MARGARET A. ROSTKER (202) 662-6780 Attorney At Law For: PAN-ALBERTA GAS LTD WRIGHT & TALISMAN 1200 G STREET NW STE 600 WASHINGTON DC 20005 Keith R. Mccrea (202) 393-1200 Attorney At Law For: KERN RVR GAS TRANSPORT SUTHERLAND, ASBILL & BRENNAN 1275 PENNSYLVANIA AV NW Hallie Yacknin WASHINGTON DC 20004-2404 Legal Division (202) 383-0705 RM. 5001 For: INDUSTRIAL GROUP/CA MFG ASSN 505 VAN NESS AVE SAN FRANCISCO CA 94102 (415) 703-2195 For: ORA SERVICE LIST ***********STATE SERVICE********** Laura L. Manina Energy Division Robert A. Barnett AREA 4-A Administrative Law Judge Division 505 VAN NESS AVE RM 5017 SAN FRANCISCO CA 94102 505 VAN NESS AVE (415) 703-2181 SAN FRANCISCO CA 94102 (415) 703-1504 Barbara Ortega Executive Division RM. 5109 ENERGY DIVISION 107 S. BROADWAY, RM 5109 ROOM 4002 LOS ANGELES CA 90012 CPUC (213) 897-4158 Daniel Tormey Edwin Quan ENTRIX, INC. Energy Division SUITE 210 AREA 4-A 411 NORTH CENTRAL AVENUE 505 VAN NESS AVE GLENDALE CA 91203 SAN FRANCISCO CA 94102 (415) 703-2494 Jay Abbott ENTRIX, INC. Martha Sullivan SUITE 200 Energy Division 2601 FAIR OAKS BLVD. AREA 4-A SACRAMENTO CA 95864 505 VAN NESS AVE SAN FRANCISCO CA 94102 Paul Premo (415) 703-1214 FOSTER ASSOCIATES, INC. 120 MONTGOMERY STREET RM 1776 *******INFORMATON ONLY****** SAN FRANCISCO CA 94104 (415) 391-3558 Donald L. Jackson Valuation Division David K. Fukutome BOARD OF EQUALIZATION Office or Ratepayer Advocates PO BOX 842879 RM. 4208 450 N STREET, MIC:61 505 VAN NESS AVE SACRAMENTO CA 94279-0061 SAN FRANCISCO CA 94102 (415) 703-1136 Libby Brydolf 2419 BANCROFT STREET Jack Fulcher SAN DIEGO CA 92104 Energy Division AREA 4-A J. A. Savage 505 VAN NESS AVE Journalist SAN FRANCISCO CA 94102 CALIFORNIA ENERGY MARKETS (415) 703-1711 3006 SHEFFIELD AVENUE OAKLAND CA 94602-1545 Kent Dauss Legal Division Jason Mihos 1227 O STREET, 4TH FLOOR CALIFORNIA ENERGY MARKETS SACRAMENTO CA 95814 9 ROSCOE STREET (916) 657-4561 SAN FRANCISCO CA 94110 (415) 824-3222 SERVICE LIST Joy Omania Brian Brokowski Action Association NELSON COMMUNICATIONS GROUP CALIFORNIA/NEVADA COMMUNITY SUITE 2000 225 30TH STREET, SUITE 200 402 W. BROADWAY SACRAMENTO CA 95816 SAN DIEGO CA 92101 Michael S. Hundus Brian Kelly CAMERON MCCKENNA LLP % SENATOR BILL LOCKYER TWO TRANSAMERICA CENTER CALIFORNIA STATE SENATE 505 SANSOME STREET, 5TH FLOOR STATE CAPITOL, ROOM 400 SAN FRANCISCO CA 94111 SACRAMENTO CA 94248 Chico Chavis William E. Claycomb 3534 FIRST AVENUE SAVE OUR BAY, INC. SACRAMENT CA 95817 SUITE 100 409 PALM AVENUE Steven F. Greenwald IMPERIAL BEACH CA 91932-1121 Attorney At Law DAVIS WRIGHT TREMAINE LLP Mitchel A. Mick ONE EMBARCADERO, SUITE 600 SIDLEY & AUSTIN SAN FRANCISCO CA 94111-3834 SUITE 400 (415) 276-6512 ONE FIRST NATIONAL PLAZA CHICAGO IL 60603 Carol Davis 2496 STARLIGHT GLEN Robert Gnaizda ESCONDIDO CA 92026 General Counsel/Policy Dir THE GREENLINING INSTITUTE Bill Johnson 3RD FLOOR ASSOCIATES 785 MARKET STREET 601 MONTGOMERY STREET, SUITE 500 SAN FRANCISCO CA 94103 SAN FRANCISCO CA 94111 (415) 284-7200 Robert A. Burka FOLEY & LARDNER SUITE 500 3000K AVENUE NW WASHINGTON DC 20007 Linda R. Whelan Director Western Region Commercial Devel HOUSTON INDUSTRIES POWER GENERATION, INC. 1111 LOUISIANA HOUSTON TX 77251-1700 (713) 207-5148 Ann M. Pougiales Attorney At Law LAW OFFICES OF ANN M. POUGIALES 333 MARKET STREET, 24TH FLOOR SAN FRANCISCO CA 94105 Sara Steck Myers Attorney At Law 122 28TH AVENUE SAN FRANCISCO CA 94121 (415) 387-1904 ATTACHMENT B TABLE OF CONTENTS Page(s) I. DIVESTITURE OF SOCALGAS' OPTIONS TO PURCHASE KERN RIVER AND MOJAVE.................2 II. SDG&E FOSSIL POWER PLANT DIVESTITURE.......2 III. APPLICANTS' 25 REMEDIAL MEASURES..........2 IV. AFFILIATE TRANSACTION CONDITIONS...........6 A. MINERAL ENERGY COMPANY CONDITIONS..............................6 B. MINERAL ENERGY COMPANY POLICY AND GUIDELINES FOR AFFILIATE COMPANY TRANSACTIONS...................12 1. INTRODUCTION AND GENERAL POLICY.....12 (a) DEFINITIONS.....................12 (b) STATEMENT OF POLICY.............13 (c) OVERALL ACCOUNTABILITY..........15 (d) SCOPE...........................15 (e) PURPOSE.........................15 (f) IMPLEMENTATION..................15 (g) COMMUNICATIONS..................16 2. ORGANIZATIONAL GUIDELINES...........16 (a) PARENT COMPANY..................16 (b) UTILITY AFFILIATES..............18 (c) NON-UTILITY AFFILIATES..........18 3. TRANSFER OF ASSETS, GOODS AND SERVICES............................19 (a) GENERAL.........................19 (b) TRANSFERS OF ASSETS OR RIGHTS TO USE ASSETS............20 i (i) Identification..............20 (ii) Valuation..................21 (iii) Recording.................21 (c) TRANSFERS OF GOODS AND SERVICES PRODUCED, PURCHASED OR DEVELOPED FOR SALE........................22 (i) Identification..............22 (ii) Valuation..................22 (iii) Recording.................22 (d) TRANSFERS OF GOODS OR SERVICES NOT PRODUCED, PURCHASED OR DEVELOPED FOR SALE........................23 (i) Identification..............23 (ii) Valuation..................23 (iii) Recording.................23 (e) STANDARD PRACTICES..............26 4. EMPLOYEE TRANSFERS..................27 (a) GENERAL.........................27 (b) EMPLOYEE TRANSFER GUIDELINES......................27 (c) REPORTING OF EMPLOYEE TRANSFERS.......................28 5. INTERCOMPANY BILLINGS AND PAYMENTS............................28 (a) GENERAL.........................28 (b) INTERCOMPANY BILLINGS...........28 (c) INTERCOMPANY PAYMENTS...........28 (d) RECORDING.......................29 6. INCOME TAX ALLOCATION/OTHER TAXES...............................29 ii ATTACHMENT B (a) INCOME TAXES....................29 (b) INCOME TAX ALLOCATION METHODOLOGY.....................29 (c) BILLING AND PAYMENT PROCEDURES......................29 (d) PROPERTY AND OTHER TAXES........30 7. FINANCIAL REPORTING.................30 (a) GENERAL.........................30 (b) FINANCIAL REPORTING REQUIREMENTS....................30 (c) REPORTING OF INTERCOMPANY TRANSACTIONS....................30 (d) SPECIFICATIONS..................31 (i) Consistent Format...........31 (ii) Time Constraints...........31 (iii) Conformance with GAAP.....31 (iv) Regulatory Agencies........31 8. INTERNAL CONTROLS AND AUDITING......31 (a) GENERAL.........................31 (b) INTERNAL CONTROL REQUIREMENTS....................32 (i) Document Procedures.........32 (ii) Record Maintenance.........32 (iii) Budgeting.................32 (iv) Audits.....................32 C. THE LIMITED PORTIONS OF THE D.97-12-088 AFFILIATE RULES THAT WILL APPLY TO INTERUTILITY TRANSACTIONS WITHIN THE NEW MERGED ORGANIZATION, AND THE LIMITED EXEMPTION FOR POST-MERGER TRANSFERS OF UTILITY EMPLOYEES TO UNREGULATED AFFILIATES.................33 iii V. SINGLE SOCALGAS TRANSPORTATION RATE FOR ALL ELECTRIC GENERATORS, INCLUDING COGENERATORS, IN SOCALGAS' SERVICE TERRITORY..................................34 VI. FERC CODES OF CONDUCT.....................34 A. AIG TRADING CORPORATION CODE OF CONDUCT.34 1. POWER PURCHASES......................34 2. NON-POWER GOODS AND SERVICES.........34 3. SHARING OF MARKET INFORMATION........34 4. DISCOUNTED GAS TRANSPORTATION AND STORAGE SERVICES.................34 B. ENOVA ENERGY, INC. CODE OF CONDUCT......35 1. DEFINITIONS..........................35 (a) Affiliate........................35 (b) Non-Power Goods and Services.....35 2. PROHIBITION ON INFORMATION SHARING...35 3. AFFILIATE TRANSACTIONS...............35 4. BROKERAGE............................36 5. SEPARATE BOOKS AND ACCOUNTS..........36 C. SAN DIEGO GAS & ELECTRIC COMPANY CODE OF CONDUCT.........................36 1. DEFINITIONS..........................36 (a) Affiliate........................36 (b) Electric Marketing Affiliate.....36 (c) Non-Power Goods and Services.....36 2. PROHIBITION ON INFORMATION SHARING...36 3. AFFILIATE TRANSACTIONS...............37 4. BROKERAGE............................37 5. SEPARATE BOOKS AND ACCOUNTS..........37 REQUIRED MITIGATION MEASURES iv ATTACHMENT B REQUIRED MITIGATION MEASURES 1 ATTACHMENT B REQUIRED MITIGATION MEASURES I. DIVESTITURE OF SOCALGAS' OPTIONS TO PURCHASE KERN RIVER AND MOJAVE On or before September 1, 1998, SoCalGas shall sell its options to purchase the California facilities of Kern River and Mojave pipelines to nonaffiliates of the merged company. II. SDG&E FOSSIL POWER PLANT DIVESTITURE On or before December 31, 1999, SDG&E shall sell its gas-fired generation facilities to nonaffiliates of the merged company. III. APPLICANTS' 25 REMEDIAL MEASURES A. The Terms and Conditions of the tariff provisions relating to transportation shall be applied in the same manner to the same or similarly situated persons if there is discretion in the application of those tariff provisions. (Remedial Measure 1.) B. SoCalGas shall strictly enforce a tariff provision for which there is no discretion in the application of the provision. (Remedial Measure 2.) C. SoCalGas shall not, through a tariff provision or otherwise, give its marketing affiliates (including SDG&E) preference over non-affiliated shippers in matters relating to transportation including, but not limited to, scheduling, balancing, transportation, storage or curtailment priority. (Remedial Measure 3.) D. SoCalGas shall process all similar requests for transportation in the same manner and within the same period of time. (Remedial Measure 4.) E. SoCalGas shall not disclose to its marketing affiliates or to employees of SDG&E engaged in the gas or electric merchant function any information SoCalGas receives from a non-affiliated shipper or potential non-affiliated shipper. (Remedial Measure 5.) F. To the extent SoCalGas provides information related to transportation of natural gas to its marketing affiliates or to employees of SDG&E engaged in the gas or electric 2 ATTACHMENT B merchant function, SoCalGas shall provide that information contemporaneously to all potential shippers, affiliated and nonaffiliated, on its system. (Remedial Measure 6.) G. To the maximum extent practicable, SoCalGas' operating employees and the employees of its marketing affiliates, including employees of SDG&E engaged in the electric merchant function, shall function independently of each other. (Remedial Measure 7.) H. If SoCalGas offers a transportation discount to a marketing affiliate, including the SDG&E gas or electric merchant function, or offers a transportation discount for a transaction on its intrastate pipeline system in which a marketing affiliate, or the SDG&E gas or electric merchant function, is involved, SoCalGas shall make a comparable discount contemporaneously available to all similarly-situated non-affiliated shippers; and within 24 hours of the time at which gas first flows under a transportation transaction in which a marketing affiliate receives a discounted rate or a transportation transaction at a discounted rate in which a marketing affiliate is involved, SoCalGas shall post a notice on its Electronic Bulletin Board, operated in a manner consistent with 18 C.F.R. Section 284.10(a), providing the name of the marketing affiliate involved in the discounted transportation transaction, the rate charged, the maximum rate, the time period for which the discount applies, the quantity of gas scheduled to be moved, the receipts points into the SoCalGas system under the transaction, any conditions or requirements applicable to the discount, and the procedures by which a non-affiliated shipper can request a comparable offer. The posting shall remain on the Electronic Bulletin Board for 30 days from the date of the posting. The posting shall conform with the requirements of 18 C.F.R. Section 284.10(a). (Remedial Measure 8.) I. SoCalGas shall file with the CPUC procedures that will enable shippers and the CPUC to determine how SoCalGas is complying with the standards of 18 C.F.R. Section 161. (Remedial Measure 9.) J. SoCalGas shall maintain its books of account and records (as prescribed under Part 201) separately from those of its affiliate. (Remedial Measure 10.) K. SoCalGas shall maintain a written log of waivers that it grants with respect to tariff provisions that provide for such discretionary waivers and provide the log to any person requesting it within 24 hours of the request. (Remedial Measure 11.) 3 ATTACHMENT B L. The merged company's Gas Operations shall operate independently and shall be physically separate from Gas Acquisition. (Remedial Measure 12.) M. Communications pertaining to gas transportation between Gas Operations and any shipper on the SoCalGas system, including Gas Acquisition, shall, except as specifically exempted below, occur on a nondiscriminatory basis, preferably through SoCalGas' interactive GasSelect EBB. The merged company shall not permit any employee or third party to be used as a conduit to avoid enforcement of any of these rules. (Remedial Measure 13.) N. The SoCalGas GasSelect EBB shall be the primary means of communication between Gas Operations and any shipper on the SoCalGas system, including Gas Acquisition. Telephonic and facsimile communications between Gas Operations and any shipper on the SoCalGas system, including Gas Acquisition, shall be limited to the status and administration of that shipper's transportation and storage capacity, volumes, and, if relevant, expected gas usage. Telephonic communications shall be tape recorded. In addition, SoCalGas shall permit a representative of the CPUC and/or the California Power Exchange to audit or monitor the application of the procedures and protocols being used to operate the system and respond to the service requests of all system users. (Remedial Measure 14.) O. The merged company shall preclude Gas Operations or Gas Acquisition from learning the financial positions in futures markets of any affiliate. If non-public information of this nature is received by personnel working at Gas Operations or Gas Acquisition, it shall be contemporaneously posted on the GasSelect EBB. (Remedial Measure 15.) P. Unrestricted communications shall be permitted between Gas Operations and SoCalGas Gas Acquisition to the extent necessary for Gas Acquisition to provide system reliability and balancing services. Such communications shall be posted on the GasSelect EBB no later than seven (7) days after the communication to avoid an artificial increase in the cost of such services that may result from posting this information contemporaneously. (Remedial Measure 16.) - --------------------- . "Gas Operations" includes the SoCalGas Gas Operations Center at the Spence Street facility and its employees, the SoCalGas Gas Transactions group, and the SDG&E Gas Operations group. . "Gas Acquisition" means the gas acquisition function at SoCalGas and SDG&E and all energy marketing affiliates unless otherwise stated. 4 ATTACHMENT B Q. SoCalGas shall propose to the Commission in the upcoming Gas Industry Restructuring proceeding a set of provisions designed to eliminate the need for SoCalGas Gas Acquisition to provide system balancing. If the system reliability and balancing function is separated from SoCalGas Gas Acquisition, all communications between Gas Operations and SoCalGas Gas Acquisition shall be through, and posted contemporaneously on, the GasSelect EBB, except for the telephonic and facsimile communications addressed above in (3). (Remedial Measure 17.) R. Any affiliate of SoCalGas (including SDG&E) or of SDG&E shipping gas on the system of SoCalGas, SDG&E, or both for use in electric generation shall use the GasSelect EBB to nominate and schedule such volumes separately from any other volumes that it ships on either system. Such gas will be transported under rates and terms (including rate design) no more favorable than the rates and terms available to similarly-situated non-affiliated shippers for the transportation of gas used in electric generation. (Remedial Measure 18.) S. SoCalGas shall seek prior Commission approval of any transportation rate discount or rate design offered to any affiliated shipper on the SoCalGas system using existing procedures established by the Commission for review of discounted transportation contracts. (Remedial Measure 19.) T. SoCalGas shall continue to maintain an EBB that is an interactive same-day reservation and information system. In any case where SoCalGas is required to post information on the Gas Select EBB, it shall post such information within one hour of an executed transaction or the receipt/transmission of any relevant information. (Remedial Measure 20.) U. SoCalGas shall post daily on the GasSelect EBB the following information for that day: estimated gas receipts by receipt point; necessary minimum flows at each receipt point; estimated system sendout; estimated storage injections and withdrawals; and estimated day-end system underground storage inventory. SoCalGas shall post within one hour the following information: gas receipts by receipt point, and net storage injections and withdrawals. SoCalGas shall also post daily on the GasSelect EBB information depicted in graphic form to show the relationship between storage inventory levels and underdeliveries to the SoCalGas system. (Remedial Measure 21.) V. SoCalGas shall post daily the following "next-day" information: capacity available at eachreceipt point; total confirmed nominations by receipt point; estimated system storage injections and withdrawals; estimated as-available storage capacity; and the status of system balancing rules (daily or monthly). (Remedial Measure 22.) 5 ATTACHMENT B W. SoCalGas shall post system status data such as maintenance information, facilities out-of-service, expected duration of outage, etc., as soon as such information is known to SoCalGas. (Remedial Measure 23.) X. SoCalGas shall provide any customer requesting a transportation rate discount an analysis of whether the discount would optimize transportation revenues. (Remedial Measure 24.) Y. SoCalGas shall provide a transportation rate discount to any shipper on the SoCalGas system if such a discount will optimize transportation revenues, regardless of any impact on affiliate revenues. (Remedial Measure 25.) IV. AFFILIATE TRANSACTION CONDITIONS A. MINERAL ENERGY COMPANY CONDITIONS 1. The officers and employees of Mineral Energy Company (hereinafter "Parent") and its subsidiaries shall be available to appear and testify in Commission proceedings as necessary or required. The Commission shall have access to all books and records of SoCalGas, SDG&E (hereinafter referred collectively as "Utilities"), Parent, and any affiliate pursuant to PU Code Section 314. Objections concerning requests for production pursuant to PU Code Section 314 made by Commission staff or agents are to be resolved pursuant to ALJ Resolution 164 or any superseding Commission rules applicable to discovery disputes. Utilities are placed on notice that the Commission will interpret Section 314 broadly as it applies to transactions between Utilities and Parent or its affiliates and subsidiaries in fulfilling its regulatory responsibilities as carried out by the Commission, its staff and its authorized agents. Requests for production pursuant to Section 314 made by Commission staff or agents are deemed preemptively valid, material and relevant. Any objections to such request shall be timely raised by Utilities, Parent or their affiliates. In making such an objection, respondents shall demonstrate that the request is not reasonably related to any issue that may be properly brought before the Commission and, further, is not reasonably calculated to result in the discovery of admissible evidence in any proceeding. 2. The "Mineral Energy Company Corporate Policies and Guidelines for Affiliate Transactions" ("Corporate Policies and Guidelines") shall be implemented in its entirety by Utilities, Parent, and their affiliates. 6 ATTACHMENT B 3. Between January 1999 and January 2002, the Executive Director of the Commission shall make staff assignments as necessary to conduct an audit of Parent, Utilities and controlled affiliates, at the expense of shareholders of Parent for an audit of Utilities' affiliate transactions for the purpose of verifying Utilities' compliance with the Corporate Policies and Guidelines and other applicable Commission orders and regulations (Verification Audit). The Office of Ratepayer Advocates (ORA, which, for purposes of this condition shall mean ORA or such other staff organization that the Executive Director designates for the purpose) shall be the designated staff organization having responsibility for the audit unless the Executive Director determines that the needs of the Commission dictate otherwise. Parent shall provide funding for the costs of the audit, including the fees and expenses of an outside auditor or consultant and ORA's incremental travel costs, subject to the following: (a) ORA may contract with the outside auditor or consultant, or Parent may contract directly with the outside auditor or consultant, in which case ORA shall be a third-party beneficiary of the contracted services, for which ORA shall have the ultimate authority and responsibility for selection, direction, monitoring and supervision of the contractor; and (b) prior to the selection of an outside auditor or consultant, ORA shall consult with Utilities, UCAN, TURN, and FEA regarding the identity of potential contractors. The Utilities, Parent, and all controlled affiliates shall retain, at least until the completion of the Verification Audit, (i) all internal and external correspondence between Utilities' officers and department heads and controlled affiliates, and (ii) to the extent prepared in the normal course of business, desk calendars, meeting summaries, phone call summaries or logs and E-mail correspondence between Utilities' officers and department heads and controlled affiliates. The auditor's report shall then be filed by ORA with the Commission and served on the parties to this Application, which shall remain open solely for such purpose. The Administrative Law Judge ("ALJ") assigned to this proceeding is directed to hold a pre-hearing conference during the last quarter of the first, second, and third years following the date of the decision in this proceeding, as necessary to assure that the Verification Audit is scheduled. ORA shall file and serve the results of the Verification Audit in the docket for this proceeding and, at the same time, shall file and serve its motion to consolidate the docket for this proceeding with any joint proceeding of Utilities then pending, or, if none, to institute an investigation for such review. The ALJ shall consider ORA's motion, and the responses of other parties, if any, and shall either issue a ruling consolidating this docket into the appropriate existing proceeding or prepare an order for the Commission to institute an investigation for such purpose. After the Verification Audit, customers of Utilities shall continue to fund the normal PU Code Sections 314.5 and 797 audits. However, in no event shall customers of Utilities be required to fund another Verification Audit until at least three years have elapsed since the completion of the first Verification Audit, with the exception of audits performed in connection with PU Code Section 851 proceedings. 7 ATTACHMENT B 4. The dividend policy of Utilities shall continue to be established by each Utility's respective Board of Directors as though each of the Utilities were a stand-alone utility company. 5. The capital requirements of each of the Utilities, as determined to be necessary to meet its obligations to serve, shall be given first priority by their respective Boards of Directors and the Board of Directors of Parent. 6. Utilities shall each maintain balanced capital structures consistent with that determined to be reasonable for each of them by the Commission in its most recent decisions on their capital structures. Utilities' equity shall be retained such that the Commission's adopted capital structure for each shall be maintained (adjusted in the case of SDG&E to reflect the imputation of its long-term capital leases) on average over the period the capital structure is in effect for ratemaking purposes. 7. When an employee of Utilities is transferred to either Parent or any non-utility affiliate, that entity shall make a one-time payment to the affected utility in an amount equivalent to 25% of the employee's base annual compensation, unless the affected utility can demonstrate that some lesser percentage (equal to at least 15%) is appropriate for the class of employee involved. The aggregate of all such fees paid to Utilities shall be credited to SDG&E's Electric Revenue Adjustment Mechanism (ERAM) account or SoCalGas' miscellaneous revenue account, as appropriate, on an annual basis, or as otherwise necessary to ensure that the customers of Utilities receive the fees. This transfer payment provision will not apply to clerical workers. Nor will it apply to the initial transfer of employees to SDG&E or SoCalGas business units which become non-utility affiliates at the time of the initial separation of the business units from SoCalGas or SDG&E pursuant to PU Code Section 851 application or other commission proceeding. However, it will apply to any subsequent transfers between Utilities and previously separated business units. 8. Utilities shall avoid a diversion of management talent that would adversely affect them. 8 ATTACHMENT B 9. Neither Parent nor any of Parent's subsidiaries shall provide interconnection facilities or related electrical equipment to SDG&E, directly or indirectly, where third-party power producers are required to purchase or otherwise pay for such facilities or equipment in conjunction with the sale of electrical energy to SDG&E, unless the third party may obtain and provide facilities and equipment of like or superior design and quality through competitive bidding. Parent and its non-utility subsidiaries may participate in any competitive bidding for such facilities and equipment. 10. Valuable customer information, such as customer lists, billing records, or usage patterns transferred, directly or indirectly, from Utilities to any non-utility affiliate shall be made available to the public subject to the terms and conditions under which such data was made available to the non-utility affiliate. This condition will not apply to such information that is proprietary to and in the possession of a business unit of Utilities at the time it is initially separated as a non-utility affiliate. 11. Utilities shall comply fully with OIR 92-08-008 (as modified by D.93-02-019) including, but not limited to, (1) reporting the sale or transfer of any tangible asset between Utilities, any Parent or any affiliate and (2) reporting certain information on all affiliates of Utilities. Such full compliance does not require the reporting of transactions between SDG&E and SoCalGas, which transactions are outside the scope of the Affiliate Transactions Order. 12. For transactions between SDG&E and SoCalGas the following conditions must be followed: (a) The transfer of goods or services not produced or developed for sale must be priced at fully-loaded cost. (b) The Utilities must establish security measures to protect the confidentiality of customer information transferred between them to prevent inappropriate access by non-utility affiliates. 9 ATTACHMENT B (c) The Utilities must maintain current records created in the normal course of business of (i) all goods and services provided by one utility to the other including the costs incurred to provide the goods and services and the consideration paid, and (ii) all assets transferred between them including the date of transfer, price paid, how the price was calculated, and date of payment. (d) The utilities must establish security measures to ensure that SDG&E employees engaged in the electricity market function cannot obtain access to confidential gas information of SoCalGas. 13. If SoCalGas offers a transportation discount to an affiliated shipper, SoCalGas must make a comparable discount available to all similarly situated non-affiliated shippers. 14. In addition to compliance with Conditions 1-13, inclusive, all gas and power marketing affiliates of Utilities shall comply with the following: (a) General Conditions - - Utilities may not endorse or recommend a gas or power marketing affiliate to SoCalGas or SDG&E customers with respect to gas or power marketing. - - Utilities may not inform either gas or electric customers of the existence or business of a gas or power marketing affiliate unless the customer is provided a list of others who offer the same service. - - Any non-tariffed goods and services provided to a gas or power marketing affiliate by Utilities must be provided to others on the same terms and conditions. - - A gas or power marketing affiliate cannot share photocopying, word processing or fax equipment with Utilities. - - A gas or power marketing affiliate may hire employees of Utilities, but any such employees may not remove proprietary utility property or information that could give the gas or power marketing company a marketing advantage. - - Energy marketing affiliates must maintain separate facilities from those of the Utilities and have those facilities available for inspection by the CPUC. 10 ATTACHMENT B - - The Utilities shall not share employees with gas and power marketing affiliates; employees of the gas and power marketing affiliates will function independently from employees of the utilities. - - The gas and power marketing affiliates must maintain separate books and records from the Utilities. - - The Utilities must prohibit booking to their accounts the costs or revenues of their gas and power marketing affiliates. - - The Utilities shall not seek to pass on to their customers the costs of any brokerage fee or commission paid to a power marketing affiliate. - - No power marketing affiliate will make sales of power to affiliated Utilities or purchase energy or electric transmission capacity from the Utilities without either prior regulatory approval or pursuant to filed tariffs of the Utilities. - - The gas and power marketing affiliates can only use the affiliated Utilities' transmission services according to the utility transmission tariffs. - - Employees of Utilities shall not provide confidential gas or power marketing or operational information to a gas or power marketing affiliate, unless such information is made available contemporaneously to other gas and power marketers. Examples of confidential marketing information include customer gas and power consumption data, name and address. Examples of confidential operational information include real-time storage injection/withdrawal information, gas purchase plans and recent gas purchases. Operational information may be valuable only for a period of time past which the market becomes fully aware of it and, thereafter, is no longer restricted. - - Gas and power marketing affiliate employees shall have no access to the physical facilities of Utilities except as provided to other gas and power marketers. This applies to buildings, offices and other physical utility facilities, but does not apply to computer systems, phone systems or other information systems. Password protection must be used to prevent employees of a gas and power marketing affiliate from obtaining from Utilities' confidential marketing information that otherwise must be made available to all marketing companies. (b) As it pertains to gas marketing affiliates, such affiliates shall comply with the FERC affiliate standards of conduct for gas pipeline companies (18 CFR SECTION 161.1) and the CPUC rules for utility gas marketing affiliates (D.90-09-089, pp. 14-16, modified by D.91-02-022). (c) A power marketing affiliate of the utilities must comply with FERC Order 889 Standards of Conduct (18 CFR SECTIONS 37.3 and 37.4). 11 ATTACHMENT B B. MINERAL ENERGY COMPANY POLICY AND GUIDELINES FOR AFFILIATE COMPANY TRANSACTIONS 1. INTRODUCTION AND GENERAL POLICY (a) DEFINITIONS Affiliate: Mineral Energy Company and all its subsidiaries are Affiliates. Affiliates other than SDG&E, SoCalGas, and their subsidiaries are "non-utility Affiliates." SDG&E, SoCalGas and their regulated subsidiaries and any other public utility company which may be formed or acquired is considered a "utility Affiliate." Corporate Support Services: Services performed for and benefiting one or more entities within the Affiliated group. Cost of Sales: The direct cost of goods sold during an accounting period. Directly Requested Services: Those services explicitly requested and provided exclusively for the benefit of the requesting party. Fair Market Value: The price at which a willing seller would sell to a willing buyer, neither under a compulsion to buy nor sell. Generally, it will be determined through reference to transactions within a specified market. In the absence of a specified market from which to determine Fair Market Value, Fair Market Value may be determined under a variety of methods discussed in Section III of this policy. Fully Loaded Cost: The value at which a good or service is recorded in the transferee's accounting records. It includes all applicable direct charges, indirect charges, and overheads. For the purposes of these policies and guidelines Fully Loaded Cost will include an additional 5 percent premium applied to Labor Charges but only when a good or service is transferred from a utility Affiliate to a non-utility Affiliate. Intangible Asset: An asset having no physical existence, whose value is limited by the rights and anticipated benefits that possession conveys upon the owner. 12 ATTACHMENT B Intellectual Property: Includes copyrights, patent rights, trade secrets, customer lists, royalty interests, licenses, franchises, and proprietary, market, or technological data not publicly available. Labor Charges: Consist of direct payroll costs, including all employee benefits such as pension, post employment benefits, health insurance, etc.; but not general office expenses such as space and supplies. Mineral Energy Company: The parent company of Enova Corporation and Pacific Enterprises, who are, respectively, the parent companies of San Diego Gas & Electric Company and Southern California Gas Company. The name "Mineral Energy Company" is a temporary name and will be changed at an appropriate time. In this document "Mineral Energy Company" is also referred to as "Parent Company." Personal Property: Includes vehicles, airplanes, machinery, furniture, fixtures not appurtenant to land, equipment, materials and supplies, computer hardware and related software applications, and any other tangible property which is not real property. Real Property: Includes land, buildings, improvements and fixtures which are appurtenant to land, and timber. It also includes mineral rights, water rights, easements, and other real property rights. SDG&E: San Diego Gas & Electric Company, a regulated public utility. SoCalGas: Southern California Gas Company, a regulated public utility. Subsidiary: An entity controlled by another, generally through majority ownership. Third Parties: A party that is not an Affiliate, as defined in this policy. (b) STATEMENT OF POLICY The following corporate policy has been established to guide relationships between and among Mineral Energy Company (the "Parent Company"), the regulated utility Affiliates (principally, SDG&E and SoCalGas) and the non-utility Affiliates. All such relationships shall be conducted in a fashion that is consistent with this general corporate policy. 13 ATTACHMENT B It is the policy of SDG&E, SoCalGas, the Parent Company, and all Affiliates (collectively, the Company) to ensure that the business activities of non-utility Affiliates are not subsidized by utility operations. Towards this end, it is the Company's policy to conduct the non-utility business ventures, where practical, economic or efficient, independently of the Company's utility operations. Specifically, - - All relationships between utility and non-utility Affiliates (including the Parent Company) are to be conducted so as to avoid cross-subsidization of non-utility operations by utility operations. - - Prompt and fair compensation or reimbursement is to be given/received for all assets, goods and services transferred or provided between the Parent Company, the utility Affiliates and the non-utility Affiliates. - - Resource sharing and intercompany transactions are to be conducted to ensure non-utility Affiliates' operations are not subsidized by utility operations. Non-utility Affiliates should utilize their own employees and third party suppliers to the extent practical in lieu of directly requesting the services of employees of utility Affiliates and/or the Parent Company. In accordance with the foregoing, Affiliates shall, where feasible, and to the extent practical, acquire, operate and maintain their own facilities and equipment and retain their own administrative staffs. This policy does not prohibit resource sharing for economies and efficiencies. - - In the event that a utility Affiliate's nonpublic proprietary information is made available to non-utility Affiliates, the utility Affiliate shall be compensated in accordance with the provisions of this policy and guidelines or the information shall be made available to similarly situated third parties. However, if the nonpublic proprietary information is valuable customer information, that information shall automatically be made available to the public subject to the terms and conditions it was made available to the non-utility Affiliate. - - There shall be no preferential treatment by a utility Affiliate in favor of a non-utility Affiliate in business activities that the utility Affiliate also conducts with unrelated third parties, and such business activities shall be conducted at arm's length and in accordance with any applicable regulatory requirements. An arm's length basis of conducting business is one where a party seeks to satisfy its separate best interests in dealing with another party. - ------------------ . With respect to utility affiliates under FERC jurisdiction, information must be made available to similarly situated third parties regardless of compensation to the extent required by FERC order. In all cases, regulatory rules take precedence over this corporate policy. Should regulatory requirements of the different jurisdictions be in conflict with each other, the officers of the Parent Company will be responsible for solving the conflict. 14 ATTACHMENT B (c) OVERALL ACCOUNTABILITY The Vice President and Controller of Parent Company is responsible for issuing, updating, and monitoring compliance with this policy. (d) SCOPE This policy applies to the Parent Company, SDG&E, SoCalGas, and all Affiliates. (e) PURPOSE The purpose of these policies and guidelines is to set forth business practices to be observed in the transactions between and among utility Affiliates, non-utility Affiliates, and the Parent Company, after the consummation of the merger between Enova Corporation and Pacific Enterprises. All transactions between and among these parties are to follow the policies and guidelines stated herein. These policies and guidelines have been developed to ensure that prompt and fair compensation or reimbursement is given/received for all assets, goods and services transferred between the Parent Company, utility and non-utility Affiliates and that information reported to the Parent Company meets the various reporting requirements to which SDG&E, SoCalGas, and the Parent Company are subject. The flow of information and the transfer of assets, goods and services between and among these parties are to be conducted in accordance with the policies and guidelines contained herein. Such policies and guidelines will be modified as experience dictates in order to ensure that all Affiliate transactions are duly recorded, the policies comply with regulatory requirements and there is prompt and fair reimbursement of costs associated with transactions between Affiliates on an ongoing basis. (f) IMPLEMENTATION The Parent Company and each of its Affiliates will be responsible for the implementation of these policies and guidelines within their respective organizations. Procedures will be developed by each Affiliate to ensure that Affiliated employees are cognizant of, and can properly implement, the following policies and guidelines. All Affiliated transactions will be adequately documented. Internal control measures will be reviewed, tested and monitored to ensure that policies and guidelines are observed and that potential or actual deviations are detected and corrected. 15 ATTACHMENT B In the event a situation has not been addressed by the policies and guidelines contained herein arises, the situation shall be brought to the attention of the applicable officers of the utility Affiliate involved, or, if no utility Affiliate is involved to the officers of the Parent Company, for review and/or approval. (g) COMMUNICATIONS In the event that proprietary information of an utility Affiliate is made available to any other Affiliate for non-utility commercial purposes, including the Parent Company, the utility Affiliate shall be compensated for such information in accordance with the provisions of these policies and guidelines or the information shall also be made available to similarly situated third parties. However, if the nonpublic proprietary information is valuable customer information, that information shall automatically be made available to the public subject to the terms and conditions it was made available to the non-utility Affiliate. These policies and guidelines are not intended to restrict or inhibit transfer price communications by the Parent Company or an Affiliate necessary to conduct their business, or information that is generally in the public domain. Specifically, it does not restrict: - - communications concerning intercompany billings, payments, audits, treasury, financial and tax reporting, corporate support activities, employee benefits, risk management, human resources and the like; - - communications about general corporate policies and practices; - - communications of public information or of information also available to similarly situated third parties; or - - incidental communications that do not involve the transfer of proprietary information or other Intellectual Property, as defined in this policy. - ------------------ . See footnote 4 above for discussion of FERC requirements related to transfers of information. 2. ORGANIZATIONAL GUIDELINES (a) PARENT COMPANY 16 ATTACHMENT B The Parent Company will be organized in a manner which results in effective and efficient management of SDG&E, SoCalGas, and other utility Affiliates. The costs of the Parent Company are to be allocated among the Affiliates in accordance with this policy. In the near term, the utilization of existing SDG&E, SoCalGas, Enova Corporation, or Pacific Enterprises departments to provide the level of corporate services required by the Parent Company will result in efficiencies. Corporate functions such as shareholder services, corporate accounting and consolidation, corporate communications and business planning and budgeting will be performed by one or more utility or non-utility Affiliates. The Fully Loaded Cost of these services will be billed to the Parent Company and other Affiliates, as appropriate. The cost of these services will be allocated as follows: The first step consists of directly assigning to the Parent Company all costs for services which have been specifically requested by or performed on behalf of the Parent Company. For example, direct labor costs of employees in the SDG&E Law Department who provide legal research requested by the Parent Company, will be charged based on directly assigned labor charges, including employee benefits and other overheads. The second step involves allocating costs of functions which benefit the Parent Company and other Affiliates but cannot be directly assigned to individual entities. Corporate functions such as shareholder services and investor relations are examples. These costs will be indirectly assigned based on causal or beneficiary relationships. For example, the cost of shareholder services may be allocated based on equity investment and advances to Affiliates. Allocation of Parent Company Costs It is the intention that all Parent Company costs shall be allocated among the Affiliates, including utility Affiliates. Accordingly, all Parent Company costs, regardless of whether incurred directly by the Parent Company or incurred by an Affiliate and charged to the Parent Company, shall be allocated among all the Affiliates in the manner described below. 1. All costs that can be directly or indirectly assigned to Affiliates shall be so directly charged or allocated. 2. Common costs not assignable directly or indirectly shall be allocated based on a formula representing the activity of the Affiliate as it relates to the total activity of the Affiliated group (four factor formula). The formula will be based on the 17 ATTACHMENT B Affiliate's proportionate share of (1) total assets, (2) operating revenues, (3) operating and maintenance expenses (excluding the direct Cost of Sales, purchased gas, cost of electric generation for utility operations and income taxes), and (4) number of employees. Each factor shall be equally weighted. The factors included in the formula will be periodically reviewed and modified to the extent required. The allocation of Parent Company costs shall not change the nature of the costs incurred. Therefore, costs which are not recoverable in rates of the utility Affiliate, such as charitable contributions and governmental relations activities, must be appropriately recorded "below the line" by the utility Affiliates. It shall be the responsibility of the Parent Company (and the utility Affiliates, if acting on behalf of the Parent Company) to properly identify such charges in intercompany billings and maintain appropriate records supporting the amount and nature of the charges. Organizational expenses related to the formation of the Parent Company will not be recorded in the operations expense accounts of the utility Affiliates included in the determination of their rates, to the extent they are incurred by or allocated to the utility Affiliates. (b) UTILITY AFFILIATES SDG&E and SoCalGas will be organized in a manner that allows them to provide the highest quality utility service that focuses on safety and reliability, and is responsive to customers' needs. Each utility Affiliate will, to the extent it makes business sense, share resources with the other utility Affiliate. The corporate officers and directors of the utility Affiliates will devote sufficient time and effort to utility matters such that utility services are not compromised. To the extent that officers and directors spend time on Affiliate matters, such time will be billed to the Affiliates in accordance with the guidelines in Section III. (c) NON-UTILITY AFFILIATES As a general policy, resource sharing, and intercompany transactions will be conducted to ensure non-utility Affiliates' operations are not subsidized by utility operations. The following corporate organizational objectives have been established to prevent any cross-subsidization: - - Non-utility Affiliates shall utilize their own employees and third-party suppliers, to the extent practical. 18 ATTACHMENT B - - Non-utility Affiliates shall acquire, operate and maintain their own facilities and equipment, where practical. - - Non-Utility Affiliates shall retain their own administrative staffs, to the extent practical. 3. TRANSFER OF ASSETS, GOODS AND SERVICES (a) GENERAL The purpose of the corporate transfer-pricing policies and guidelines in this section is to assign a monetary value to all assets, goods or services transferred between the Parent Company, SDG&E, SoCalGas, and the other utility and non-utility Affiliates. The transfer pricing methodology will ensure that transactions between the Affiliates do not adversely affect the Parent Company, SDG&E, SoCalGas, the other utility Affiliates, or their respective customers. The objective in accounting for transfers within the Affiliated group involves the appropriate: (1) identification, (2) valuation, and (3) recording of transactions between entities. There are three general types of transfers that will occur: - - Transfers of assets or rights to use assets; - - Transfers of goods or services produced, purchased or developed for sale; and - - Transfers of goods or services not produced, purchased or developed for sale. Transfers of assets or rights to use assets and transfers of goods and services produced, purchased or developed for sale will be priced based on the following: - - TARIFF/LIST PRICE -- between utility Affiliates - - FAIR MARKET VALUE -- between utility Affiliates and the Parent Company, or between non-utility Affiliates and other utility Affiliates Transfers of goods or services not produced, purchased or developed for sale will be priced as follows: - - HIGHER OF FAIR MARKET VALUE OR FULLY LOADED COST -- from utility Affiliates to the Parent Company or non-utility Affiliates - - LOWER OF FAIR MAKRET VALUE OR FULLY LOADED COST -- from the - Parent Company or a non-utility Affiliate to utility Affiliates 19 ATTACHMENT B - - FULLY LOADED COST -- between utility Affiliates, such as SDG&E and SoCalGas These procedures provide the accounting safeguards to prevent cross-subsidization of non-utility goods and services. The transfer price for all goods and services with annual billings less than $250,000 may be at Fully Loaded Cost or net book value whichever is applicable, at the option of the transferor. Fully Loaded Cost will include a 5% premium applied to Labor Charges when labor is provided by a utility Affiliate to a non-utility Affiliate. Each of the transfers is discussed in more detail below. As specific goods and services are identified, an arrangement should be formalized in writing covering the specific goods or services to be provided. Accounting and billing of the related costs should be included in the arrangement and developed for each product or service using the guidelines in this section. These arrangements are discussed in more detail below in subsection E. (b) TRANSFERS OF ASSETS OR RIGHTS TO USE ASSETS (i) Identification: Transfers of assets include transfers of tangible real or personal property and Intellectual Property used in a trade or business. Transfers of assets also include rights to use assets through leases or other arrangements in excess of one year. REAL PROPERTY Includes, but is not limited to: - - Land - - Buildings - - Improvements - - Timber - - Mineral rights - - Easements - - Other real property rights PERSONAL PROPERTY Includes, but is not limited to: - - Automobiles - - Airplanes - - Power-operated equipment - - Computer hardware - - Computer software or application software - - Furniture 20 ATTACHMENT B - - Materials and supplies INTELLECTUAL PROPERTY Includes, but is not limited to: - - Copyrights - - Patent rights - - Trade secrets - - Customer lists - - Royalty interests - - Licenses - - Franchises However, it does not include Intellectual Property to which the Affiliate does not have rights. These rights must be in the Affiliate's possession or specifically granted to it. (ii) Valuation: Transfers of assets or rights to use assets will be valued at Fair Market Value, which will be determined through methods appropriate for the asset. Fair Market Value shall be used for all transfers of assets in excess of $250,000 in net book value and for transfers of goods and services when annual billings are in excess of $250,000. In order to ease administrative burdens for transfers, if the net book value of a transferred asset is equal to or less than $250,000, the transfer may be priced at net book value at the transferor's option. Examples of methods that may be used to determine Fair Market Value include: - - Appraisals from qualified, independent appraisers - - Averaging bid and ask prices as published in newspapers or trade journals - - Reference to a specified market The determination of Fair Market Value must be adequately documented to ensure that a proper audit trail exists. For transfers of product rights, patents, copyrights and other Intellectual Property, valuation shall be at Fair Market Value which may be a single cost price, a royalty on future revenues or a combination of both. Such royalty payments, if any, shall be developed on a case-by-case basis. (iii) Recording: Transfers of assets or rights to use assets will be recorded through a direct charge based on valuation of the transferred asset as described above. 21 ATTACHMENT B (c) TRANSFERS OF GOODS AND SERVICES PRODUCED, PURCHASED OR DEVELOPED FOR SALE (i) Identification: Transfers of goods or services produced, purchased or developed for sale include those goods or services intended for sale in the normal course of the Affiliate's business. In order to be considered produced, purchased or developed for sale, the goods and services must be available to third-parties in addition to other Affiliates. Goods or services produced, purchased or developed for sale could include among others: - - Gas transmission and distribution services - - Electric generation, transmission and distribution services - - Gas Marketing - - Office space rental - - Engineering and development services - - Facility operations and maintenance services - - Other related energy services Goods or services produced, purchased or developed for sale would usually be the product of resources which are planned and dedicated to providing those goods or services. (ii) Valuation: Transfers of goods and services produced, purchased or developed for sale will be valued at tariff or list price or Fair Market Value, depending upon the nature of the Affiliate. - - Transfers from utility Affiliates for regulated services will be based on rates authorized by a regulatory agency. - - Transfers from non-utility Affiliates will be based on Fair Market Value determined by an appropriate method such as: a. Reference to current prices in comparable transactions for similar goods or services between non-Affiliated parties b. Published prices c. Reference to a specified market (iii) Recording: Transfers of goods or services produced, purchased or developed for sale will be recorded through a direct charge to the recipient based upon the valuation described above. 22 ATTACHMENT B (d) TRANSFERS OF GOODS OR SERVICES NOT PRODUCED, PURCHASED OR DEVELOPED FOR SALE (i) Identification: Transfers of goods or services not produced, purchased or developed for sale includes those goods or services that are provided only incidentally to the primary business of the Affiliate. Services that are provided to other Affiliates by an Affiliate within the Affiliate group for economic or other purposes would also be considered a service not produced, purchased or developed for sale. These goods or services will not be provided to independent third parties. Examples include: - - Data processing - - Audit services - - Incidental use of vehicles or office space - - Small tools and equipment Corporate functions such as shareholder services, finance, legal, corporate accounting and consolidation, internal auditing and corporate planning and budgeting will be performed for the Parent Company initially by employees of Affiliates (see Section A). In addition, the Affiliates may contract with other Affiliates for the services of support personnel in those instances where it is not practical for the Affiliate to have its own administrative staff. Use of utility Affiliate employees or services by non- utility Affiliates will require the appropriate approval. These transactions are covered by the transfer-pricing guidelines contained within this section. (ii) Valuation: Transfers of services not produced, purchased or developed for sale will be priced as follows: - - Higher of Fully Loaded Cost or Fair Market Value for transfers from utility Affiliates to non-utility Affiliates - - Lower of Fully Loaded Cost or Fair Market Value for transfers from non-utility Affiliates to utility Affiliates - - Fully Loaded Cost for transfers between utility Affiliates Fully Loaded Cost for goods and services transferred from a utility Affiliate to a non-utility Affiliate will include a 5 percent surcharge on Labor Charges, as defined. (iii) Recording: Transfers and Affiliate allocations will be performed and calculated by the Affiliate providing the service. In order to ease the administrative burdens, if annual billings for a good or service are equal to $250,000 or less, the transfer price may be the fully allocated cost including the 5% premium on Labor Charges at the option of the transferor. The Affiliate receiving the service will have the right to audit the 23 ATTACHMENT B allocation. Adjustments to allocations will be made in accordance with the policy discussed in Section VI. Costs will be assigned to the Affiliates depending on the nature of the transactions using a three-step process: 1) specifically identifiable costs will be charged directly to the entity requesting and benefiting from the services; 2) indirect costs which have a causal or beneficiary relationship will be proportionately allocated by that causal or benefit factor to the Affiliate; and 3) remaining indirect costs will be allocated by a multi-factor formula (four factor) representing the proportionate activity of each Affiliate as compared to the entire Affiliate group. The detail of this three-step process follows: (1) Step #1: Costs will be directly assigned to the entity requesting and benefiting from the goods or services provided. Examples of direct charges include: * Directly assigned Labor Charges, including applicable loadings for payroll additives of employees in utility Affiliate departments which provide requested services. This could include personnel in departments such as: - - Financial Planning and Analysis - - Law - - Tax Directly assigned Labor Charges will be based on the standard departmental rates of assigned employees including employee benefits and the actual number of hours devoted to providing services. Labor loadings include such items as paid time-off, payroll taxes, and pensions and benefits. A 5% premium shall be added to the direct Labor Charges of utility Affiliate employees providing services to a non-utility Affiliate. This premium is to serve as an additional safeguard against cross-subsidization. * Purchases of goods and services including: - - Materials, including applicable purchase and warehousing expense - - Office supplies - - Auditors' fees - - Legal fees for outside counsel * Required Payments such as: - - Income Taxes (see Section VI) - - Property Taxes * Office, Vehicle and Equipment Costs, which will be based on standard cost or specific usage of: - - Transportation vehicles 24 ATTACHMENT B - - Construction equipment - - Office equipment - - Computer equipment - - Facilities (2) Step #2: Costs for corporate functions performed by the Parent Company or an Affiliate not directly assigned will be allocated on the basis of causal or beneficiary relationships. These costs relate to shared functions for which it would be impractical or unreliable to record actual costs incurred. The following departments and functions may provide indirect benefits or services to Affiliates and costs would be allocated using this step: - - Shareholder Services - - Corporate Accounting - - Budget - - Corporate Communications - - Investor Relations - - Risk Management (insurance costs other than certain premiums) - - Computer Information Services - - Telecommunications Costs which are functionally related will be accumulated into cost pools and allocated on the basis of causal or beneficiary relationships. Examples of indirect costs and factors that may be used to allocate those costs include: * EQUITY INVESTMENTS AND ADVANCES TO THE PARENT COMPANY OR AFFILIATES to allocate the cost of providing services, such as: - - Investor relations - - Long-term financing * NUMBER OF EMPLOYEES to allocate the cost of providing services such as: - - Payroll services - - Compensation and Benefits - - Pension investment management * SQUARE FEET to allocate the cost of providing services such as: - - Office space - - Yard space - - Warehousing 25 ATTACHMENT B Any of these charges that can be directly assigned shall be directly assigned. Also, to the extent that casual or beneficiary relationships cannot be identified, the indirect costs shall be allocated using step #3 below. (3) Step #3: Those indirect costs that cannot be allocated using steps #1 and #2 above will be apportioned based on a formula which reflects the proportionate level of activity of each Affiliate as compared to the Affiliated group in total. The allocation formula will be based upon the Parent Company's or each Affiliate's proportionate share of the following factors: - - Total assets - - Operating revenues - - Operating and maintenance expense (excluding direct Cost of Sales, purchased gas, cost of electric generation for utility operations and income taxes) - - Number of employees (including equivalent personnel of Affiliates providing direct services) There will be an equal weighting of each factor, thereby recognizing each Affiliate's portion of the Affiliated group's activity as measured by total financial resources, revenues, cost of operations and the employee work force. (e) STANDARD PRACTICES Policies and procedures will be developed by each Affiliate to ensure that Affiliate transactions are transfer priced in accordance with this policy, to the extent practical. In certain circumstances, specific contracts or agreements will document specific transactions between Affiliates. Contracts and Standard Practices are not required for non-recurring or infrequent transactions. Each Standard Practice, contract, and agreement shall adhere to the policies contained herein and include the following information. (i) Purpose: The stated purpose and scope. (ii) Policy: A summary of the guiding principles regarding the accounting, budgeting and billing treatment of the particular assets, goods or services. 26 ATTACHMENT B (iii) Responsibilities/Procedures: A description of and detail procedures for accounting, budgeting and billing of the particular assets, goods or services. This may include, but is not limited to: - - Type of product(s) or service(s) - - Terms and conditions - - Accounting information (account numbers, cost center, work orders, etc.) - - Required level of approval - - Timing for processing the accounting, budgeting or billing of transactions (iv) Appendices and Exhibits: - - Copy of applicable service agreements - - List of billing rates - - List of cost centers and work order numbers 4. EMPLOYEE TRANSFERS (a) GENERAL Transfers or rotations of employees from a utility Affiliate to another Affiliate shall not adversely affect the utility Affiliate's ability to render safe and reliable service that meets the customers' needs. Utility Affiliate employees may provide corporate or other support services on behalf of the Parent Company or other Affiliates. Such services will be billed to Affiliates based on such employees' labor costs plus allocated indirect and overhead costs and an additional 5 percent premium applied to Labor Charges (if for a non-utility Affiliate), as described in Section Ill. (b) EMPLOYEE TRANSFER GUIDELINES The following guidelines will be utilized for employee transfers: (i) The transfer from a utility Affiliate to a non-utility Affiliate will not be to the detriment of the utility Affiliate's ability to render safe and reliable service that meets customers' needs. (ii) In instances where it may be desirable to transfer an employee of a utility Affiliate to the Parent Company or an Affiliate, officer approval of both companies involved in the transfer will be required before the transfer can occur. 27 ATTACHMENT B (c) REPORTING OF EMPLOYEE TRANSFERS SDG&E and SoCalGas will provide to the California Public Utilities Commission (CPUC) an annual report identifying all employees transferred to the Parent Company or any non-utility Affiliate. It shall be the policy of other utility Affiliates to report such information on employee transfers as required by their respective jurisdictional body (such as FERC or another state utility commission). 5. INTERCOMPANY BILLINGS AND PAYMENTS (a) GENERAL Billings for intercompany transactions shall be issued on a timely basis, generally monthly for goods or services and at the time of transfer for assets. Sufficient detail will be provided to ensure an adequate audit trail and enable prompt reimbursement from the recipient of the assets, goods or services. (b) INTERCOMPANY BILLINGS Intercompany billings issued for transfers of assets, goods or services will be accompanied by or reference appropriate supporting documents. Transfer-pricing computations will be based upon methods set forth in these policies and guidelines and the applicable Standard Practices. Such computations must be documented in order to facilitate verification of methods used to compute the cost or Fair Market Value of transferred assets, goods or services. Costs incurred on behalf of the Parent Company or Affiliates shall be accumulated, priced and billed in accordance with policies set forth in Sections II and III by the end of the following month to enable timely payment. (c) INTERCOMPANY PAYMENTS Payments for assets, goods or services received from an Affiliate shall be made within thirty (30) days after receipt of an invoice which complies with these guidelines. If reimbursements are not received by the payment due date, late charges may be assessed by the billing company. Intercompany billings and payments shall be adequately documented so that an audit trail exists to facilitate verification of the accuracy and completeness of all billings and reimbursements. See Section VI for billing and payment procedures applicable to federal and state income taxes. 28 ATTACHMENT B (d) RECORDING Upon receipt of an adequately invoiced intercompany billing, it shall immediately be recorded. Disputes shall not preclude recording of the billing. If disputes cannot be resolved by the Affiliates, then the matter shall be brought to the attention of the applicable officers of the utility Affiliate involved, if none are involved, then to the officers of the Parent Company for resolution. 6. INCOME TAX ALLOCATION/OTHER TAXES (a) INCOME TAXES The Parent Company is responsible for filing the Company's consolidated U.S. federal income tax return and all combined state income tax returns. These returns include the taxable income/loss of SDG&E, SoCalGas, and their Affiliates to the extent permitted by law and/or regulation. The tax liability or benefit resulting from inclusion of the Affiliates' taxable income/loss and tax credits in the consolidated income tax return is allocated to the Affiliates. Parent may elect not to pay non-utility Affiliates for tax losses, which said non-utility Affiliates could not utilize on a stand-alone basis. (b) INCOME TAX ALLOCATION METHODOLOGY The separate return method or other acceptable method will be used to allocate income tax expense to the Affiliates. The separate return method allocates tax liabilities and benefits to the Affiliates that generated them. This method is in agreement with the CPUC's established policy for income tax allocation, as discussed in Decision 84-05-036, resulting from Order Instituting Investigation No. 24. (c) BILLING AND PAYMENT PROCEDURES Billing for federal and state income taxes will include all supporting calculations to facilitate timely payments. The timing of payments made by the Affiliates for their tax liabilities (or payments received by Affiliates for their tax benefits) will coincide with the filing dates of the Parent Company unless amounts are not significant, in which case an annual billing will be made. The Parent Company reserves the right to adjust amounts due from or to Affiliates from prior years, based upon audits and or amendments to previously filed returns. 29 ATTACHMENT B (d) PROPERTY AND OTHER TAXES Property taxes are separately assessed on and paid by each Affiliate to the extent such tax applies. Sales and use, excise taxes and other miscellaneous taxes are separately imposed on and paid by each Affiliate to the extent such taxes apply. 7. FINANCIAL REPORTING (a) GENERAL All Affiliates are expected to provide monthly financial statements and/or other financial information necessary to compile the Parent Company's consolidated financial statements and to comply with other internal or external reporting requirements. All Affiliates are expected to provide sufficient information necessary to prepare the consolidated income tax returns. (b) FINANCIAL REPORTING REQUIREMENTS The financial information to be reported by the Affiliates includes, but is not necessarily limited to, the following: - - Balance sheet - - Income statement - - Cash flow statement - - Information necessary to develop appropriate disclosures (c) REPORTING OF INTERCOMPANY TRANSACTIONS The following transactions between utility Affiliates and non- utility Affiliates must be reported in sufficient detail to include the nature and terms thereof: - - Transfers of assets, goods or services - - Borrowings and loans - - Receivables and payables - - Revenues and expenses - - Interest - - Identification of utility employees who provide services to Affiliates - - Permanent transfers and rotational assignments of employees among utility Affiliates and non-utility Affiliates 30 ATTACHMENT B (d) SPECIFICATIONS The financial reporting and intercompany transaction information forwarded by the Affiliates must meet the following specifications: (i) Consistent Format: The format of the financial information submitted by each Affiliate will be determined by the Parent Company's reporting requirements. (ii) Time Constraints: Affiliate companies financial information must be submitted within the time constraints set by the Parent Company. Conformance with the established time frame is required in order to meet the deadlines for preparing consolidated financial statements and the other reporting requirements. (iii) Conformance with GAAP: The management of each Affiliate (with the necessary assistance from the Parent Company) is responsible for accumulating and preparing financial information in accordance with generally accepted accounting principles (GAAP) applied on a consistent basis. Year-end financial statements are to be accompanied by notes summarizing significant accounting policies and other disclosures required by GAAP to make the financial statements complete. Quarterly financial statements are to be accompanied by notes appropriate for interim statements. (iv) Regulatory Agencies: Accounting practices mandated by regulatory agencies are to be observed when an Affiliate is within the agency's jurisdiction. In addition, Affiliates are to comply with the reporting requirements placed on the Parent Company by regulatory agencies, including the Internal Revenue Services (IRS). Information regarding intercompany transactions must be presented in a form and manner which will assist in the regulatory review of those transactions. 8. INTERNAL CONTROLS AND AUDITING (a) GENERAL Internal accounting controls will be reviewed, tested and monitored by SDG&E, SoCalGas, the Parent Company and other Affiliates to provide reasonable assurance that: (i) Intercompany transactions are executed in accordance with management's authorization and properly recorded. (ii) Assets are safeguarded. 31 ATTACHMENT B (iii) Accounting records may be relied upon for the preparation of financial statements and other financial information. (b) INTERNAL CONTROL REQUIREMENTS (i) Document Procedures: All accounting policies, guidelines and procedures for transactions between SDG&E, SoCalGas, the Parent Company and Affiliates will be fully documented. The Affiliates will develop the necessary procedures and controls to ensure adherence to these policies and guidelines. Measures must be taken to ensure procedures are made available to and are observed by all employees. These procedures will be refined as necessary to ensure the accurate and complete recording of all transactions. (ii) Record Maintenance: Each Affiliate will maintain records to substantiate its books and financial statements. All intercompany transactions will be documented by records of sufficient detail to facilitate verification of relevant facts. Transfer prices are to adhere to policies and guidelines and be approved as appropriate. In most cases, guidelines and procedures will be developed to document the recordkeeping requirements for the provision of specific assets, goods and services. The financial records shall be monitored to assure compliance with these transfer-pricing policies. In addition to accounting records, each Affiliate will maintain other pertinent records such as minute books, stock books, and selected correspondence. The Affiliate's records will be retained for the period of time required by corporate and regulatory (IRS, CPUC, FERC, etc.) record-retention policies. (iii) Budgeting: Affiliates will be responsible for allocating resources and controlling costs. Budgets will be prepared, as required, for capital expenditures, operating expenditures and personnel staffing. These budgets will be supported by subordinate budgets in sufficient detail to be used as a guide during the budget period. Managers will monitor budget performance and take action, if necessary, to control costs. Budgets will be used as a tool to detect and provide early warning of variances from planned expenditures. Explanations for substantial variances will be provided as soon as they are detected. (iv) Audits: The Board of Directors of the Parent Company (the Board) will retain independent auditors to conduct an annual financial audit of the Company. The nature and scope of this audit will be determined by the auditors in conjunction with the Board. The Parent Company will also engage auditors to perform all audits necessary to satisfy regulatory requirements. In addition, the Parent Company may initiate any audit or investigation of Affiliate's activities it deems necessary. The audit or investigation may 32 ATTACHMENT B be performed by independent auditors or by internal auditors of the utility Affiliates. The Board and the designated corporate officer shall be responsible for supervising SDG&E's and SoCalGas' internal auditors. The cost of auditing services performed for Affiliate companies will be borne by the Affiliate audited, even when the Parent Company initiates the audit. Intercompany transactions and related transfer prices will be periodically audited to ensure that policies are observed and that potential or actual deviations are detected and corrected in a timely and cost efficient manner. The CPUC has statutory authority to inspect the books and records of the Parent Company and its non-utility Affiliates in regard to transactions with SDG&E or SoCalGas pursuant to California Public Utilities Code Section 314. C. THE LIMITED PORTIONS OF THE D.97-12-088 AFFILIATE RULES THAT WILL APPLY TO INTERUTILITY TRANSACTIONS WITHIN THE NEW MERGED ORGANIZATION, AND THE LIMITED EXEMPTION FOR POST-MERGER TRANSFERS OF UTILITY EMPLOYEES TO UNREGULATED AFFILIATES 1. Rule III.c shall apply to interutility transactions 2. Rules V.G.a, b, and c shall apply to any transfer of employees between SoCalGas Operations or SoCalGas Gas Acquisition, and any group at SDG&E engaged in the gas or electric merchant function 3. Rules V.G.2.a, V.G.2.b, and V.G.2.c shall not be applied to transfers of employees between SoCalGas and SDG&E subsequent to the merger other than transfers subject to the preceding paragraph; and 4. For a six-month transition period after all merger regulatory approvals have been obtained, employee transfers between the utilities and unregulated affiliates that are necessary to implement the merger shall be exempted from Rules V.G.2.b and V.G.2.c. 33 ATTACHMENT B V. SINGLE SOCALGAS TRANSPORTATION RATE FOR ALL ELECTRIC GENERATORS, INCLUDING COGENERATORS, IN SOCALGAS' SERVICE TERRITORY SoCalGas shall implement, with Commission approval, a single transportation rate schedule for all electric generators, including cogenerators, in SoCalGas' service territory, as proposed by the California Cogeneration Council, Watson Cogeneration Company, and SoCalGas. VI. FERC CODES OF CONDUCT A. AIG TRADING CORPORATION CODE OF CONDUCT The following conditions are adopted by AIG Trading Corporation ("AIG"), to be effective unless and until (a) the Commission denies authorization for the stock of AIG to be acquired by Wine Acquisition Inc. ("Wine"), (b) the agreement by Wine to acquire such stock is otherwise terminated, or (c) superseding conditions are filed and effective: 1. POWER PURCHASES AIG will make no purchases of power from San Diego Gas & Electric Company ("SDG&E") without acceptance of a rate schedule for such sale under section 205 of the Federal Power Act. 2. NON-POWER GOODS AND SERVICES AIG will provide no non-power goods or services (e.g., scheduling, accounting, legal, or similar services; computer hardware or software) to SDG&E at a price that is above a market price. 3. SHARING OF MARKET INFORMATION AIG will simultaneously publicly disclose any nonpublic market information concerning possible wholesale electric power transactions that AIG provides to SDG&E or Southern California Gas Company ("SoCalGas"). 4. DISCOUNTED GAS TRANSPORTATION AND STORAGE SERVICES Within 24 hours of the time at which gas first flows under a natural gas transportation or storage transaction in which AIG receives a discounted rate, where AIG is the purchaser and SDG&E or SoCalGas is the seller, AIG will cause to be posted 34 ATTACHMENT B electronically a notice providing the name of the seller, the contract rate, the maximum tariff rate, the beginning and end dates of the contract term, the maximum quantities to be transported, injected, inventoried, or withdrawn, as the case may be, the delivery points under the transaction, any conditions or requirements applicable to the discount and the procedures by which a non-affiliated shipper can request a comparable offer. The information posted will remain available for 30 days from the date of initial posting. B. ENOVA ENERGY, INC. CODE OF CONDUCT 1. DEFINITIONS (a) Affiliate: Any company with ten percent or more of its outstanding securities owned, controlled, or held with power to vote, directly or indirectly, by NewCo, Enova Corporation, or any of their subsidiaries, as well as any company in which NewCo, Enova Corporation, or any of their subsidiaries exert substantial control over the operation of the company and/or indirectly have substantial financial interests in the company exercised through means other than ownership. (b) Non-Power Goods and Services: All goods other than electric power and all services other than those services directly associated with the sale, transmission, and distribution of electric power. 2. PROHIBITION ON INFORMATION SHARING (a) All personnel of Enova Energy, Inc. ("EEI") shall abide by the Standards of Conduct for Public Utilities established by the Federal Energy Regulatory Commission in Order No. 889, as codified at 18 C.F.R. Sections 37.1 - 37.4. (b) No employee of EEI shall share directly or indirectly with any employee of San Diego Gas & Electric Company ("SDG&E") information concerning possible wholesale electric power transactions (e.g., customer information), unless such information is publicly available or simultaneously made publicly available. 3. AFFILIATE TRANSACTIONS (a) EEI shall purchase Non-Power Goods and Services from SDG&E at the higher of fully loaded cost or fair market value. (b) EEI shall not sell any Non-Power Goods and Services to SDG&E at a price above fair market value. 35 ATTACHMENT B 4. BROKERAGE EEI shall attempt to broker SDG&E's wholesale electric power before attempting to market its own wholesale electric power, provided that SDG&E's wholesale electric power is available for brokering and is no more expensive than EEI's wholesale electric power. 5. SEPARATE BOOKS AND ACCOUNTS EEI shall maintain separate books and accounts from NewCo, Enova Corporation, and their Affiliates. C. SAN DIEGO GAS & ELECTRIC COMPANY CODE OF CONDUCT 1. DEFINITIONS (a) Affiliate: Any company with ten percent or more of its outstanding securities owned, controlled, or held with power to vote, directly or indirectly, by NewCo, Enova Corporation, or any of their subsidiaries, as well as any company in which NewCo, Enova Corporation, or any of their subsidiaries exert substantial control over the operation of the company and/or indirectly have substantial financial interests in the company exercised through means other than ownership. (b) Electric Marketing Affiliate: Any Affiliate engaged in the brokerage or sale of electricity. (c) Non-Power Goods and Services: All goods other than electric power and all services other than those services directly associated with the sale, transmission, and distribution of electric power. 2. PROHIBITION ON INFORMATION SHARING (a) All personnel of San Diego Gas & Electric Company ("SDG&E") shall abide by the Standards of Conduct for Public Utilities established by the Federal Energy Regulatory Commission in Order No.889, as codified at 18 C.F.R. Sections 37.1 - 37.4. (b) No employee of SDG&E shall share directly or indirectly with any employee of an Electric Marketing Affiliate information concerning possible wholesale electric power transactions (e.g., customer information), unless such information is publicly available or simultaneously made publicly available. 36 ATTACHMENT B 3. AFFILIATE TRANSACTIONS (a) SDG&E shall sell Non-Power Goods and Services to an Electric Marketing Affiliate at the higher of fully loaded cost or fair market value. (b) SDG&E shall not purchase from an Electric Marketing Affiliate any Non-Power Goods and Services at a price above fair market value. 4. BROKERAGE (a) SDG&E shall not pay any brokerage fee or commission to an Electric Marketing Affiliate. (b) SDG&E shall make available to non-affiliated brokers any non- public information that it provides to an Electric Marketing Affiliate concerning possible electric wholesale transactions. (c) SDG&E shall utilize non-affiliated brokers for wholesale electric power transactions where such opportunities present themselves. 5. SEPARATE BOOKS AND ACCOUNTS SDG&E shall maintain separate books and accounts from NewCo, Enova Corporation, and their Affiliates. (END OF ATTACHMENT B) 37 COMMISSIONER P. GREGORY CONLON, CONCURRING: My major concern throughout this merger proceeding has been the issue of market power. I have always been troubled by the potential combination of Southern California Gas Company, which controls the gas supply to over 95 percent of the gas- fired electric generation in Southern California, with San Diego Gas and Electric, a major provider of electricity. I wanted to make sure that the combined utilities did not have an incentive to raise gas prices in order to effect the price of electricity in the Power Exchange. This is because it is the marginal gas-fired generators that set the price in the Power Exchange for most hours of the day. This concern was shared by a number of other parties in the proceeding, including Southern California Edison, Los Angeles Department of Water and Power, Southern California Utility Power Pool, Imperial Irrigation District, and the City of Vernon. Some of these parties believed the only adequate remedy to resolve the combined utilities' market power problem was for the combined utilities to divest themselves of their intra- state transmission and storage facilities. Another obtain would have been to turn these same facilities over to an independent party, creating in effect a "gas ISO" similar to what we did for electricity. I am also concerned that much of the analysis on the issue of market power focused solely on what would happen if San Diego Gas and Electric divested itself of its generation. This overlooked the effect that the combined utilities could have on the electric market through their control of retail sales, both regulated and unregulated. It also overlooked the effect of the combined utilities' purchasing significant amounts of generation after the merger is approved. Although the consent decree entered into by Enova. with the Department of Justice limits the combined utility from owning more than 500 megawatts of electric generation in California, the consent decree contains numerous exemptions. These exemptions include no limit on out-of-state purchases, no limit on in-state purchase of co-generation facilities, and no- limit on the purchase of new or repowered power plants WITHIN California. In voting to support the merger today, I support the market power safeguards that it contains. These include "fire- wall" and "transparency" guidelines, contained in Attachment B, that attempt to minimize the ability of the combined utilities to take advantage of their control of the gas system within Southern California. I also support the requirement to add an independent firm to monitor and audit over the next year, on a daily basis if necessary and agreed to by the Commission, the combined utilities' compliance with the market power safeguards that they agree to. This monitoring provides the Commission, and should provide all market participants, with an added level of assurance against potential market power abuses. Today's decision also realizes that significant structural changes may be considered in our Gas Strategy OII (R.98-01- 011). Many of the market power issues that I was concerned about in the merger, will be considered in the Gas Strategy proceeding. This includes such issues as: - - The divestiture of intra-state transmission and storaged; - - The need for a Gas ISO; and, - - Whether or not utilities should be in both the electric and as distribution industries. I want to make sure that the new combined utilities are aware that all of these issues are still under consideration the Gas Strategy, as well as other issues that may affect the combined utilities in the future. 5 VS 10 YEAR MERGER SAVINGS Finally, with regards to the length of the merger savings. I am supportive of the use of a 10-year period to track and allocate merger savings. I believe that it will take time for the utility to achieve its savings, and that a 10-year period better reflects the time needed to achieve these savings. /s/ P. Gregory Conlon P. Gregory Conlon, Commissioner April 1, 1998 San Francisco, California EX-99 4 EX D-11 ORDER OF NRC UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the Matter of ) ) SAN DIEGO GAS AND ELECTRIC COMPANY ) Docket Nos. 50-206, 50-361 ) and 50-362 (San Onofre Nuclear Generating Station, ) Units 1, 2 and 3) ) ORDER APPROVING APPLICATION REGARDING THE CORPORATE RESTRUCTURING OF ENOVA CORPORTION, PARENT OF SAN DIEGO GAS AND ELECTRIC COMPANY, BY ESTABISHMENT OF A HOLDING COMPANY WITH PACIFIC ENTERPRISES I. San Diego Gas and Electric Company (SDG&E) is a co-owner of San Onofre Nuclear Generating Station (SONGS), Units 1, 2 and 3, along with Southern California Edison (SCE), The City of Riverside, California (Riverside), and The City of Anaheim, California (Anaheim). SDG&E, SCE, Riverside and Anaheim are co- holders of Possession Only License No. DPR-13, and Facility Operating License Nos. NPF-10, and NPF-15, issued by the U.S. Nuclear Regulatory Commission (the Commission) pursuant to Part 50 of Title 10 of the Code of Federal Regulations (10 CFR Part 50) on October 23, 1992, February 16, 1982, and November 15, 1982, respectively. Under these licenses, SDG&E, SCE, Riverside, and Anaheim have the authority to posses the San Onofre Nuclear Generating Station. Units 1, 2 and 3, while SCE is authorized to oeprate Units 2 and 3. SONGS is located in San Diego County, California. II. By letter dated December 2, 1996, SDG&E, through its counsel Richard A. Meserve of Covington & Burling, informed the Commission that its parent company, Enova Corporation, was engaging in a corporate restructuring plan with Pacific Enterprises that will result in the creation of a holding company under the name Mineral Energy Company of which Enova and Pacific Enterprises would becom subsidiaries. SDG&E would continue to be a subsidiary of Enova. Under the restructuring, there will be no change in the capital structure of SDG&E. SDG&E will - 1 - continue to hold the SONGS licenses to the same extent as presently held: there will be no direct transfer of the SONGS licenses. The December 2, 1996, letter requested the Commission's approval pursuant to 10 CFR 50.80. to the extent necessary, in connection with the proposed restructuring. Notice of this request for approval was published in the FEDERAL REGISTER on July 1, 1997 (62 FR 35532). Under 10 CFR 50.80, no license shall be transferred, directly or indirectly, through transfer of control of the license, unless the Commission shall give its consent in writing. Upon review of the information submitted in the letter of December 2, 1996, and other information before the Commission, the NRC staff has determined that the restructuring of Enova, parent company of SDG&E, will not affect the qualifications of SDG&E as co-holder of the licenses, and that the transfer of control of the licenses for SONGS, to the extent effected by the restructuring of Enova, is otherwise consistent with applicable provisions of law, regulations, and orders issued by the Commission, subject to the conditions set forth herein. These findings are supported by a Safety Evaluation dated August 29, 1997. III. Accordingly, pursuant to Sections 161b, 161I, 161o, and 184 of the Atomic Energy Act of 1954, as amended, 42 USC Sections 2201(b), 2201(1), 2201(o), and 2234, and 10 CFR 50.80. IT IS HEREBY ORDERED that the Commission approves the application concerning the proposed restructuring of Enova, parent company of SDG&E, subject to the following conditions: (1) SDG&E shall provide the Director of the Office of Nuclear Reactor Regulation a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from SDG&E to its parent or to any other affiliated company, facilities for the production, transmission, or distribution of electric energy having a depreciated book value exceeding ten percent (10%) of - 2 - SDG&E's consolidated net utility plant, as recorded on SDG&E's books of account: and (2) should the restructuring of Enova as described herein not be completed by August 31, 1998, this Order shall become null and void, provided, however, on application and for good cause shown, such date may be extended. This Order is effective upon issuance. IV. By September , 1997, any person adversely affected by this Order may file a request for a hearing with respect to issuance of the Order. Any person requesting a hearing shall set forth with particularity how that interest is adversely affected by this Order and shall address the criteria set forth in 10 CFR 2.714(d). If a hearing is to be held, the Commission will issue an order designating the time and place of such hearing. The issue to be considered at any such hearing shall be whether this Order should be sustained. Any request for a hearing must be filed with the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, Attention: Rulemaking and Adjudications Staff, or may be delivered to the Commission's Public Document Room, the Gelman Building, 2120 L Street, N.W., Washington, D.C. by the above date. Copies should be also sent to the Office of the General Counsel, and to the Director, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, and to Richard A. Meserve, Covington & Burling, 1201 Pennsylvania Avenue, N.W., Post Office Box 7566, Washington, D.C. 20044-7566, attorney for SDG&E. For further details with respect to this action, see the December 2, 1995 letter application, which is available for public inspection at the Commission's Public Document Room, the Gelman Building, 2120 L Street, N.W., Washington, D.C., and at the local - 3 - public document room located at the Main Library, University of California, Irvine, California 92718. FOR THE NUCLEAR REGULATORY COMMISSION Samuel J. Collins, Director Office of Nuclear Reactor Regulation Dated at Rockville, Maryland, This 29th day of August 1997 - 4 - SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION PROPOSED RESTRUCTURING OF PARENT OF SAN DIEGO GAS AND ELECTRIC COMPANY SAN ONOFRE NUCLEAR GENERATING STATION, UNITS 1, 2, AND 3 DOCKET NOS. 50-206, 50-361, AND 50-362 1.0 BACKGROUND San Diego Gas and Electric Company (SDG&E) is a 20-percent possession only co-owner of San Onofre Generating Station (SONGS). Units 1, 2 and 3 (Possession Only License DPR-13, and Operating License Nos. NPF-10 and NPF-15, respectively). The remainder of the ownership is held by Southern California Edison Company (the sole authorized operator), the City of Anaheim, California and the City of Riverside California. SDG&E is a wholly-owned subsidiary of Enova Corporation (Enova), which is proposing to restructure itself by combining with Pacific Enterprises (Pacific), a holding company engaged in supplying natural gas throughout most of southern and central California through its wholly-owned subsidiary, Southern California Gas Company. Enova and Pacific propose to combine to form a new holding company. Mineral Energy Company which, after subsequent intervening transactions to effectuate the combination, will become the parent company of both Enova and Pacific. As a result of the merger, SDG&E will become a second-tier subsidiary of Mineral Energy Company through its parent company, Enova, but will remain an "electric utility" pursuant to 10 CFR 50.2, and will also continue to be a 20 percent owner of the SONGS units. No direct transfer of the operating licenses or ownership interests will result from the proposed restructuring. According to SDG&E's application to the Nuclear Regulatory Commission (NRC) dated December 2, 1996: Pacific and Enova view the combination of the two companies as a natural outgrowth of the utility deregulation and restructuring that is reshaping energy markets in California and throughout the nation. The combination joins two companies with highly complementary operations that are geographically contiguous. The combination is expected to provide substantial strategic, financial, and other benefits. These benefits include a greater capacity to compete effectively in a changing regulatory environment. . . . an ability to consolidate corporate and administrative functions, [and] the capacity to draw on a large and more diverse pool of management. . . . (Application dated December 2, 1996, p. 3) Under 10 CFR 50.80, "No license for a production or utilization facility or any right thereunder, shall be transferred, assigned, or in any manner disposed of, either voluntarily or involuntarily, directly or indirectly through transfer of control of the license to any person, unless the Commission shall give its consent in writing." (emphasis added). SDG&E requested NRC consent to the extent the restructuring of Enova will effect a transfer of control of the SONGS licenses with the scope of 10 CFR 50.80. 2.0 FINANCIAL QUALIFICATIONS Based on the information provided in SDG&E's December 2, 1996 application, the staff finds that there will be no near-term substantive change in SDG&E's financial ability to contribute appropriately to the operations and decommissioning of the SONGS units as a result of the proposed restructuring. SDG&E also would remain an "electric utility" - 1 - as defined in 10 CFR 50.2, engaged in the generation, transmission, and distribution of electric energy for wholesale and retail sale, the cost of which is recovered through rates established by the California Public Utility Commission and the Federal Energy Regulatory Commission (FERC). Thus, pursuant to 10 CFR 50.33(f), SDG&E is exempt from further financial qualifications review as an electric utility. However, in view of the NRC's concern that restructuring can lead to a diminution of assets necessary for the safe operation and decommissioning of a licensee's nuclear power plants, the NRC has sought to obtain commitments from its licensees that initiate restructuring actions not to transfer significant assets from the licensee without notifying the NRC. SDG&E has made such a commitment; "SDG&E hereby agrees to provide the Director of Nuclear Reactor Regulation with 60 day prior notice of a transfer (excluding grants of security interests or liens) from SDG&E to its proposed parent or to any other affiliated company of facilities for the production, transmission or distribution of electric energy having a depreciated book value exceeding one percent (1%) of SDG&E's consolidated net utility plant, as recorded on SDG&E's books of account." (SDG&E letter of March 24, 1995) Notwithstanding SDG&E's commitment regarding the transfer of 1% of SDG&E's consolidated net utility plant, the staff believes such commitment at a 10% threshold as a condition to the NRC's consent to the proposed restructuring, will enable the NRC to ensure that SDG&E will continue to maintain adequate resources to contribute to the safe operation and decommissioning of the SONGS units. 3.0 MANAGEMENT AND TECHNICAL QUALIFICATIONS SDG&E is a co-owner only licensee for the SONGS units and thus is not involved in the actual operation of the facility, which is exclusively the responsibility of Southern California Edison Company. To the extent relevant to SDG&E's status as a co-owner only licensee, SDG&E's application states that there will be no change in the management and technical qualifications of SDG&E's nuclear organization as a result of the restructuring. The proposed holding company structure retains the utility as a discrete and wholly separate entity that will function in the same fashion as it did prior to restructuring. Based upon the continuity of SDG&E's nuclear organization and management described above, the staff finds that the proposed restructuring will not adversely affect SDG&E's technical qualifications or the management of its nuclear plants. 4.0 ANTITRUST Section 105c of the Atomic Energy Act of 1954, as amended (the Act), requires the Commission to conduct an antitrust review in connection with an application for a license to construct or operate a utilization or production facility under Section 103 of the Act. Here, although Mineral Energy Company may become the second tier parent of SDG&E as a result of the proposed restructuring, and thus may indirectly acquire control of the licenses for the SONGS units held by SDG&E, the application filed by SDG&E does not indicate that mineral Energy Company will be performing activities for which a license is needed. Since approval of the application would not involve the issuance of a license, the procedures under Section 105c do not apply, including the making of any "significant changes" determination. In addition, no changes to the existing antitrust license conditions are being proposed, and no changes will occur as a result of the restructuring of Enova. Accordingly, there are no further antitrust matters that must be considered by the Commission in connection with the SDG&E application. 5.0 FOREIGN OWNERSHIP Information before the staff indicates that one percent or less of both Enova's and Pacific's voting stock are held by a foreign accounts, and that under the proposed restructuring plan, one percent or less of Mineral Energy Company's stock will be held by foreign accounts following an exchange of Enova and Pacific shares for Mineral shares. The NRC staff does not know or have reason to believe that either Enova or the proposed parent company, Mineral Energy Company, will be owned, controlled, or dominated by any alien, foreign corporation, or foreign government as a result of the proposed restructuring. 6.0 ENVIRONMENTAL CONSIDERATION Pursuant to 10 CFR 51.21 and 51.35, an environmental assessment and finding of no significant impact was published in the Federal Register on June 1, 1997 (62 FR 35532). 7.0 CONCLUSIONS In view of the foregoing, the staff concludes that the proposed restructuring of SDG&E's parent company, Enova, through the proposed combination with Pacific, to form a new holding company, Mineral Energy Company, will not adversely affect SDG&E's financial or technical qualifications with respect to the operation and decommissioning of the SONGS units. Also, there do not appear to be any problematic antitrust or foreign ownership issues requiring further consideration related to the SONGS licenses that would result from the proposed restructuring or the transactions to facilitate such a restructuring. Thus, the proposed restructuring will not affect the qualifications of SDG&Eas a holder of the licenses, and the transfer of control of the licenses to the extent effected by the proposed restructuring, is otherwise consistent with applicable provisions of law, regulations, and orders issued by the Commission. Accordingly, it is concluded that the application regarding the proposed restructuring should be approved. Principal Contribution: R. Wood M. Davis Date: August 29, 1997 - 2 - EX-99 5 EX F-1 AND F-1.1 OPINIONS OF COUNSEL EXHIBIT F-1 April 3, 1998 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Re: Mineral Energy Company Application on Form U-1 SEC File No. 70-9033 Dear Sirs and Madams: On behalf of Mineral Energy Company ("MEC"), I have examined the Application on Form U-1, dated March 26, 1997, under the Public Utility Holding Company Act of 1933 (the "Act"), filed by MEC with the Securities and Exchange Commission (the "Commission") and docketed by the Commission in SEC File No. 70-9033, as amended by Amendment No. 1 dated May 13, 1997, by Amendment No. 2 dated January 28, 1998, and by Amendment No. 3 dated April 3, 1998 of which this opinion is to be a part. The Application, as so amended, is hereinafter referred to as the "Application." Capitalized terms not defined herein have the meanings set forth in the Application. As set forth in the Application, MEC proposes to acquire all of the issued and outstanding common stock of Pacific and Enova, through a business combination (the "Proposed Transaction") in which (i) Pacific Sub will merge with and into Pacific, with Pacific remaining as the surviving corporation and becoming a subsidiary of MEC, and (ii) Enova Sub will merge with and into Enova, with Enova remaining as the surviving corporation and also becoming a subsidiary of MEC. I am an attorney licensed in the State of California and am the Assistant General Counsel for Enova. Enova is an affiliate company of MEC by virtue of holding 50% of MEC's issued and outstanding common stock. I am familiar with the issuance of securities by MEC and Enova and the issuance of securities by Enova associate companies. With all matters relating to Pacific, I have relied on the opinion of Leslie E. LoBaugh, Jr., filed as exhibit F-2 to Amendment No. 3 of the Application. I have acted as in-house counsel for MEC and I have examined copies, signed, certified or otherwise proven to my satisfaction, of the certificate of incorporation and by-laws of MEC and the Application. In addition, I have examined such other instruments, agreements and documents and made such other investigation as I have deemed necessary as a basis for this opinion. For the purposes of the opinions expressed below, I have assumed (except, and to the extent set forth in my opinions below, as to MEC) that all of the documents referred to in this opinion letter will have been duly authorized, executed and delivered by, and will constitute legal, valid, binding and enforceable obligations of, all of the parties to such documents, that all such signatories to such documents will have been duly authorized, that all such parties are duly organized and validly existing and will have the power and authority (corporate, partnership or other) to execute, deliver and perform such documents and that such authorization, execution and delivery by each such party will not, and such performance will not, breach or constitute a violation of any law of any jurisdiction. Based upon the foregoing, I am of the opinion, insofar as the laws of California are concerned that: (a) all State laws applicable to the Proposed Transaction on the part of MEC will have been complied with; (b) MEC is a validly organized and duly existing corporation in good standing under the laws of the State of California; (c) to the extent that the Proposed Transaction involves the issuance of stock, such stock will be validly issued, fully paid and nonassessable, and the holders thereof will be entitled to the rights and privileges appertaining thereto; (d) the consummation of the Proposed Transaction by MEC will not violate the legal rights of the holders of any securities issued by MEC or any associate company thereof. The opinions expressed above are subject to the following assumptions or conditions: a. The Proposed Transaction shall have been duly authorized and approved to the extent required by state law by the Board of Directors of MEC. b. The Commission shall have duly entered an appropriate order or orders granting and permitting the Application to become effective with respect to the Proposed Transaction. c. The Proposed Transaction shall be effected in accordance with required approvals, authorizations, consents, certificates and orders of any state or federal commission or regulatory authority with respect to the Proposed Transaction and all such required approvals, authorizations, consents, certificates and orders shall have been obtained and remain in full force and effect. d. No act or event other than as described herein shall have occurred subsequent to the date hereof which could change the opinions expressed above. I hereby consent to the filing of this opinion as an exhibit to Amendment No. 3 of the Application and in any proceedings before the Commission that may be held in connection therewith. Very truly yours, /s/ Kevin C. Sagara Assistant General Counsel EXHIBIT F-1.1 April 3, 1998 Kevin Sagara Assistant General Counsel Enova Corporation 101 Ash Street San Diego, CA 92101 Re: Mineral Energy Company Application on Form U-1 SEC File No. 70-9033 Dear Mr. Sagara: On behalf of Pacific Enterprises ("PE"), I have examined the Application on Form U-1, dated March 26, 1997, under the Public Utility Holding Company Act of 1933 (the "Act"), filed by Mineral Energy Company ("MEC") with the Securities and Exchange Commission (the "Commission") and docketed by the Commission in SEC File No. 70-9033, as amended by Amendment No. 1 dated May 13, 1997, by Amendment No. 2 dated January 28, 1998, and by Amendment No. 3 dated April 3, 1998 of which this opinion is to be a part. The Application, as so amended, is hereinafter referred to as the "Application." Capitalized terms not defined herein have the meanings set forth in the Application. As set forth in the Application, MEC proposes to acquire all of the issued and outstanding common stock of Pacific and Enova, through a business combination (the "Proposed Transaction") in which (i) Pacific Sub will merge with and into Pacific, with Pacific remaining as the surviving corporation and becoming a subsidiary of MEC, and (ii) Enova Sub will merge with and into Enova, with Enova remaining as the surviving corporation and also becoming a subsidiary of MEC. I am an attorney licensed in the State of California and am the General Counsel for Pacific. Pacific is an affiliate company of MEC by virtue of holding 50% of MEC's issued and outstanding common stock. I am familiar with the issuance of securities by Pacific and by Pacific associate companies. I have examined copies, signed, certified or otherwise proven to my satisfaction, of the Application. In addition, I have examined such other instruments, agreements and documents and made such other investigation as I have deemed necessary as a basis for this opinion. For the purposes of the opinions expressed below, I have assumed (except, and to the extent set forth in my opinions below, as to Pacific) that all of the documents referred to in this opinion letter will have been duly authorized, executed and delivered by, and will constitute legal, valid, binding and enforceable obligations of, all of the parties to such documents, that all such signatories to such documents will have been duly authorized, that all such parties are duly organized and validly existing and will have the power and authority (corporate, partnership or other) to execute, deliver and perform such documents and that such authorization, execution and delivery by each such party will not, and such performance will not, breach or constitute a violation of any law of any jurisdiction. Based upon the foregoing, I am of the opinion, insofar as the laws of California are concerned that: (a) the consummation of the Proposed Transaction will not violate the legal rights of the holders of any securities issued by Pacific or any associate company thereof. The opinion expressed above are subject to the following assumptions or conditions: a. The Commission shall have duly entered an appropriate order or orders granting and permitting the Application to become effective with respect to the Proposed Transaction. b. The Proposed Transaction shall be effected in accordance with required approvals, authorizations, consents, certificates and orders of any state or federal commission or regulatory authority with respect to the Proposed Transaction and all such required approvals, authorizations, consents, certificates and orders shall have been obtained and remain in full force and effect. c. No act or event other than as described herein shall have occurred subsequent to the date hereof which could change the opinion expressed above. I hereby consent to the filing of this opinion as an exhibit to Amendment No. 3 of the Application and in any proceedings before the Commission that may be held in connection therewith. Very truly yours, /s/ Leslie E. LoBaugh, Jr. General Counsel EX-99 6 EX FS-1 PRO FORMA BALANCE SHEET @ 12/31/97 SEMPRA ENERGY PRO FORMA COMBINED BALANCE SHEET In millions except per share amounts
For the Twelve Months Ended December 31, 1997 (Unaudited) ----------------------------- Pacific Enova Pro Forma Enterprises Corporation Adjustments Pro Forma (As Reported) (As Reported) (Note 3) Combined ------------- ------------- ------------- ------------- Assets Utility plant - at original cost $ 6,097 $ 5,889 $ -- $ 11,986 Accumulated depreciation and decommissioning (2,943) (2,953) -- (5,896) ------------- ------------- ------------- ------------- Utility plant - net 3,154 2,936 -- 6,090 ------------- ------------- ------------- ------------- Investments 191 516 -- 707 ------------- ------------- ------------- ------------- Nuclear decommissioning trusts -- 399 -- 399 ------------- ------------- ------------- ------------- Current assets Cash and temporary investments 153 624 -- 777 Accounts and notes receivable (Note 1) 530 259 (4) 785 Income taxes receivable and deferred income taxes 3 -- 7 10 Gas in storage 25 -- 14 39 Other inventories 16 67 (14) 69 Regulatory accounts receivable 355 -- (58) 297 Other 21 90 (44) 67 ------------- ------------- ------------- ------------- Total current assets 1,103 1,040 (99) 2,044 ------------- ------------- ------------- ------------- Deferred taxes recoverable in rates -- 185 (185) -- ------------- ------------- ------------- ------------- Regulatory assets 394 -- 215 609 ------------- ------------- ------------- ------------- Deferred charges and other assets 135 158 (30) 263 ------------- ------------- ------------- ------------- Total assets $ 4,977 $ 5,234 $ (99) $ 10,112 ============= ============= ============= ============= See notes to pro forma combined financial statements.
SEMPRA ENERGY PRO FORMA COMBINED BALANCE SHEET In millions except per share amounts
For the Twelve Months Ended December 31, 1997 (Unaudited) ----------------------------- Pacific Enova Pro Forma Enterprises Corporation Adjustments Pro Forma (As Reported) (As Reported) (Note 3) Combined ------------- ------------- ------------- ------------- Capitalization and Liabilities Capitalization Capital stock Preferred stock $ 80 $ -- $ -- $ 80 Common stock 1,064 785 -- 1,849 ------------- ------------- ------------- ------------- Total capital stock 1,144 785 -- 1,929 Retained earnings 372 785 -- 1,157 Deferred compensation relating to Employee Stock Ownership Plan (47) -- -- (47) ------------- ------------- ------------- ------------- Total shareholders' equity 1,469 1,570 -- 3,039 Preferred stock of subsidiary 95 104 -- 199 Long-term debt 988 2,057 -- 3,045 Debt of Employee Stock Ownership Plan 130 -- -- 130 ------------- ------------- ------------- ------------- Total capitalization 2,682 3,731 -- 6,413 ------------- ------------- ------------- ------------- Current liabilities Long-term debt due within one year 148 122 -- 270 Short-term debt 354 -- -- 354 Accounts payable (Note 1) 437 164 (4) 597 Taxes accrued 37 -- (37) -- Interest accrued 52 23 -- 75 Regulatory balancing accounts -- 58 (58) -- Dividends payable -- 46 (46) -- Other 87 146 46 279 ------------- ------------- ------------- ------------- Total current liabilities 1,115 559 (99) 1,575 ------------- ------------- ------------- ------------- Customer advances for construction 34 38 -- 72 ------------- ------------- ------------- ------------- Post-retirement benefits other than pensions 217 -- 31 248 ------------- ------------- ------------- ------------- Deferred income taxes 272 501 -- 773 ------------- ------------- ------------- ------------- Deferred investment tax credits 61 62 -- 123 ------------- ------------- ------------- ------------- Deferred credits and other liabilities 596 343 (31) 908 ------------- ------------- ------------- ------------- Total liabilities and $ 4,977 $ 5,234 $ (99) $ 10,112 shareholders' equity ============= ============= ============= ============= See notes to pro forma combined financial statements.
EX-99 7 EX FS-2 PRO FORMA STMT OF INCOME AND NOTES SEMPRA ENERGY PRO FORMA COMBINED STATEMENT OF INCOME In millions except per share amounts
For the Twelve Months Ended December 31, 1997 (Unaudited) ----------------------------- Pacific Enova Pro Forma Enterprises Corporation Adjustments Pro Forma (As Reported) (As Reported) (Note 3) Combined ------------- ------------- ------------- ------------- Revenues and Other Income Gas (Note 1) $ 2,641 $ 398 $ (55) $ 2,984 Electric 1,769 -- 1,769 Other 97 50 -- 147 ------------- ------------- ------------- ------------- Total operating revenues 2,738 2,217 (55) 4,900 Other Income 39 7 -- 46 ------------- ------------- ------------- ------------- Total 2,777 2,224 (55) 4,946 ------------- ------------- ------------- ------------- Expenses Cost of gas distributed (Note 1) 1,059 183 (55) 1,187 Electric fuel -- 164 -- 164 Purchased power -- 441 -- 441 Operating and maintenance 918 534 (35) 1,417 Depreciation and amortization 256 347 -- 603 Franchise payments and other taxes 99 44 35 178 Preferred dividends of subsidiaries 7 7 -- 14 ------------- ------------- ------------- ------------- Total 2,339 1,720 (55) 4,004 ------------- ------------- ------------- ------------- Income Before Interest and Income Taxes 438 504 -- 942 Interest expense 103 102 -- 205 ------------- ------------- ------------- ------------- Income Before Income Taxes 335 402 -- 737 Income taxes 151 150 -- 301 ------------- ------------- ------------- ------------- Net Income 184 252 -- 436 Dividends on preferred stock 4 -- -- 4 ------------- ------------- ------------- ------------- Net Income Applicable to Common Stock $ 180 $ 252 $ -- $ 432 ============= ============= ============= ============= Weighted Average Shares Outstanding (Note 2) 81.4 114.3 41.0 236.7 ============= ============= ============= ============= Net Income Per Share of Common Stock (Basic) $ 2.22 $ 2.20 $ 1.83 ============= ============= ============= Net Income Per Share of Common Stock (Diluted) $ 2.21 $ 2.20 $ 1.82 ============= ============= ============= See notes to pro forma combined financial statements.
Notes to Pro Forma Combined Financial Statements (1) Intercompany transactions between Pacific Enterprises and Enova during the period presented were considered to be material and, accordingly, pro forma adjustments were made to eliminate such transactions. (2) The pro forma combined statement of income reflects the conversion of each outstanding share of Pacific Enterprises common stock into 1.5038 shares of Sempra Energy common stock and the conversion of each outstanding share of Enova common stock into one share of Sempra Energy common stock, as provided in the merger agreement. The pro forma combined financial statements are presented as if the companies were combined during all periods included therein. (3) Financial statement presentation differences between Pacific Enterprises and Enova were considered to be material and, accordingly, have been adjusted in the pro forma combined financial statements. (4) None of the estimated cost savings or the costs to achieve such savings have been reflected in the pro forma combined financial statements. Transaction costs (including fees for financial advisors, attorneys, consultants, filings and printing) are being charged to operating and maintenance expense as incurred in accordance with Accounting Principles Board Opinion No. 16 "Business Combinations." (5) Accounting policy differences between Pacific Enterprises and Enova were considered to be immaterial and, accordingly, have not been adjusted in the pro forma combined financial statements. -----END PRIVACY-ENHANCED MESSAGE-----