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 -


 



 

 










                              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 - 
 






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.

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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

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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.

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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 
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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.

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      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.

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          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.

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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 

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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





                     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 -







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

















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.








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.