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.
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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
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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,
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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
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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.
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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
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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
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- -- 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,
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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
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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
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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,
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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.
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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)
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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)
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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)
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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.
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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.
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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: ___________________________
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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
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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
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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
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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.-
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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
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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
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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.
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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,
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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
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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
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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.
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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:
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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
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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.
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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
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"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
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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'
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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
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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
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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.
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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.
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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
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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
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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.
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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
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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.
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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
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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
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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.
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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.
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B. The Administrative Law Judge's Rulings
Regarding Discovery of Edison Documents
Edison requests Commission review of the ALJ's rulings compelling
production of documents requested by applicants containing
confidential and proprietary strategic business information about
Edison, its parent company, and its unregulated affiliates (the
Edison Documents). Edison seeks reversal of the rulings admitting
18 of those documents into the record. It is Edison's contention
that, under a reasonable interpretation of Section 854,
confidential information about Edison's prospective business
activities is not relevant to the inquiry whether the merger is in
the public interest.
On September 9, 1997, the ALJ ordered Edison to produce portions
of 58 confidential documents to the applicants, noting that "[t]he
material that I am ordering to be discoverable, subject to the
protective order, concerns Edison's current plans in the area of
competition which are relevant to the issue of the merger's effect
on competition." (Tr. 1177.) Edison contended during discovery,
and continues to maintain, that such inquiry is not relevant to
the merger's effect on competition, and therefore, falls outside
the scope of permissible discovery, which is limited to material
that is reasonably calculated to lead to the discovery of
admissible evidence. On October 23, 1997, the ALJ admitted the
Edison Documents into the record, stating that "[t]he reason I am
admitting [the Edison Documents] in is because of the competitive
environment that will exist subsequent to the consummation of the
proposed merger of Pacific Enterprises and Enova Corporation,
assuming the merger is approved." (Tr. 3426.) Edison asserts that
such documents are not relevant to the inquiry before the
Commission on this application, and therefore, should not have
been admitted.
Edison argues that the interpretation urged by applicants and
adopted by the ALJ sets a policy which is contrary to public
policy and the public interest. Edison says: First, it creates
incentives for applicants to game the regulatory process-to co-opt
the Section 854 review process in order to pilfer their rival's
competitive secrets. A determination that Section 854 requires-or
even permits-a review of all market participants' competition
plans will transform every Section 854 application into a
114
skeleton key unlocking the applicants' competitors' most sensitive
business strategies. Ratification of the current discovery and
evidentiary rulings is fundamentally inconsistent with sound business
practices and public policy, and invites parties to manipulate the
regulatory process to subvert the competitive process.
Second, it drastically raises the cost of intervening in a Section
854 proceeding to unacceptable heights. A determination that
intervention into a merger proceeding constitutes even a partial
waiver of the confidentiality of the intervenor's strategic plans,
making that information presumptively relevant to the proceeding
and therefore subject to discovery and release to all other market
participants, will serve as an insurmountable disincentive to the
voluntary participation of any competitor in a Section 854
proceeding. The public interest cannot be served by such a result.
Third, the experience of this case has demonstrated that a set of
applicants can, and will indeed, profit by using this new
"regulatory" tool selectively to target and harass specific
competitors. Applicants have only pursued such information from
Edison and Enron, and retracted their demands for Enron's
commercially sensitive documents once Enron acceded to publicly
support the merger.
Finally, Edison contends that the plain language of Section
854(b)(3), requiring a finding that the proposed merger "does ...
not adversely affect competition"-does not explicitly or
implicitly require the Commission to predict a future competitive
landscape and the proposed merger's impact thereon. Adoption of
the applicants' interpretation would constitute an unprecedented
and unwarranted expansion of the Section 854 inquiry. Edison notes
that to date, this Commission has considered three other
applications under Section 854: the SCE-SDG&E merger (D.91-05-
028), the GTE-Contel merger (D.94-04-083), and the PacTel/SBC
merger (D.97-03-067). It asserts that in none of those cases did
the Commission engage in a generalized review and survey of the
future competitive landscape; the Commission's Section 854(b)(3)
inquiry was largely focused on assessing the impact of the
applicants' proposed post-merger activities upon the then-existing
market conditions, but does not engage in direct review of the
potential activities of other market participants or entrants.
115
On another aspect of this issue Edison asserts, without citation,
that the presiding ALJ has no authority to impose discovery
sanctions.
Discussion
We affirm the ALJ's discovery Rulings. Among the many changes
deregulation is bringing, not the least is change in the nature of
litigation before the Commission. Utilities are challenging
utilities more frequently, intervenors are more strident, and
antitrust has become a leading issue. Those factors plus the
legislative requirement to complete hearings expeditiously,
all increase the pressure on the discovery phase of proceedings.
Our basic discovery statutes are brief to the extreme.
Section 1701. Rules of practice and procedure;
technical rules of evidence; effect of
informality
(a) All hearings, investigations, and
proceedings shall be governed by this part and
by rules of practice and procedure adopted by
the commission, and in the conduct thereof the
technical rule of evidence need not be applied.
No informality in any hearing, investigation, or
proceeding or in the manner of taking testimony
shall invalidate any order, decision or rule
made, approved, or confirmed by the commission.
Section 1794. Depositions
The commission or any commissioner or any party may,
in any investigation or hearing before the commission,
cause the deposition of witnesses residing within or
without the State to be taken in the manner prescribed
by law for like depositions in civil actions in the
superior
- ------------------
. Senate Bill 960 (1996) Section 1:
It is further the intent of the Legislature that the
Public Utilities Commission establish reasonable time
periods for the resolution of proceedings, that it meet
those deadlines, that those deadlines not exceed 18
months and be consistent with the rate case plans,
whichever is shorter.
Sec. 1701.2(d) Adjudication cases shall be resolved within 12 months
of initiation unless the Commission ... issues an order extending
that deadline.
116
courts of this State and to that end may
compel the attendance of witnesses and the production
of books, waybills, documents, papers, and accounts.
The PU Code sections providing for administrative law judges give
them substantial power:
Section 7:
Whenever a power is granted to, or a duty is imposed
upon, a public officer, the power may be exercised or
the duty may be performed by a deputy of the officer
or by a person authorized, pursuant to law, by the
officer, unless this code expressly provides
otherwise.
310. ... Any investigation, inquiry, or hearing which the
commission may undertake or hold may be undertaken or held
by or before any commissioner or commissioners designated
for the purpose by the commission. The evidence in any
investigation, inquiry, or hearing may be taken by the
commissioner or commissioners to whom the investigation,
inquiry, or hearing has been assigned or, in his, her, or
their behalf, by an administrative law judge designated for
that purpose. ...
311. (b) The administrative law judges may administer oaths,
examine witnesses, issue subpoenas, and receive evidence,
under rules that the commission adopts. (Emphasis added.)
(c) The evidence in any hearing shall be taken by the
commissioner or the administrative law judge designated for
that purpose. The commissioner or the administrative law
judge may receive and exclude evidence offered in the
hearing in accordance with the rules of practice and
procedure of the commission. (Emphasis added.)
Buildings on those statutes we have provided broad scope for our
administrative law judges.
117
Commission's Rules of Practice and Procedure, Article 16.
Presiding Officers
62. (Rule 62) Designation
When evidence is to be taken in a proceeding
before the Commission, one or more of the
Commissioners, or an Administrative Law Judge,
may preside at the hearing.
63. (Rule 63) Authority
The presiding officer may set hearings and
control the course thereof; administer oaths;
issue subpoenas; receive evidence; hold
appropriate conferences before or during
hearings; rules upon all objections or motions
which do not involve final determination of
proceedings; receive offers of proof; hear
argument; and fix the time for the filing of
briefs. He may take such other action as may be
necessary and appropriate to the discharge of
his duties, consistent with the statutory or
other authorities under which the Commission
functions and with the rules and policies of the
Commission.
In Re Alternative Regulatory Framework for Local Exchange Carriers
(1994) D.94-08-028, 55 CPUC2d 672, where an administrative law
judge's discovery ruling was being contested, we reviewed our
discovery procedures and said:
"The Commission's closest expression of any discovery
related procedures is found in PU Code section 1794
.... For other discovery related procedures, the
Commission generally follows the discovery rules that
re found in the Code of Civil Procedure (CCP).
* * *
"For a party to a proceeding, a wide range of
discovery procedures is available. (See, CCP sections
2025, 2028, 2030, 2031, 2032, 2033.)" (55 CPUC2d at
677.)
The next important landmark in the evolution of our discovery
practice occurred in Re Merger of Pacific Telesis and SBC
Communications (D.97-03-067).
In the PacTel/SBC merger proceedings, intervenor AT&T made several
allegations regarding the impact of the proposed merger on
competition in California telecommunications markets. In response,
SBC propounded data requests similar to those at issue here:
seeking documents related to AT&T's business plans (past and
future), any post-merger analyses of the California
telecommunications industry,
118
identification of actual and potential competitors, and AT&T's
projected revenues and market share in California by year through
1999. AT&T refused to produce the responsive documents, making
the same arguments Enron and Edison are making here. AT&T claimed
the documents were irrelevant because the proceeding was about
SBC's proposed acquisition of PacTel, not AT&T's conduct. Further,
AT&T argued the documents constituted AT&T's most commercially
sensitive information and were protected from discovery. Finally,
like Edison, AT&T argued on policy grounds that requiring competitors
to divulge their confidential marketing business strategies will
discourage participation in Commission proceedings.
In her Ruling, the presiding ALJ stated:
"[t]he documents sought by SBC are relevant to the subject matter
of this proceeding and appear reasonably calculated to lead to the
discovery of admissible evidence. [Citation omitted.] For example,
AT&T's pre- and post-merger business and marketing plans for
California may address market concentration and also may contain
statistical assumptions about the markets which might be relevant
to AT&T's protest. Similarly, AT&T's revenue and market share
projections for the local market may address market concentration
of the local market and barriers to entry for newcomers, which
also might be relevant to the protest." (A.96-04-038, Ruling of
ALJ Econome, September 3, 1996, p. 7.)
Without commenting directly on ALJ Econome's ruling in our
decision, we discussed with approval the need to understand
competition in the emerging markets. We said that it is important
to consider "the presence of many other firms which are equally
ready and willing to enter" a given market (D.97-03-067, mimeo. p.
60). We pointed out that the California Attorney General, in
supporting the merger, considered those firms that "are all
planning to aggressively expand the range of that competition."
(Mimeo. p. 62.) Findings of Fact 43 discussed the potential
competitors capable of competing. (Mimeo. p. 100.)
Just as AT&T's future competitive plans could lead to evidence
necessary to an understanding of the PacTel/SBC merger, so too,
Edison's future competitive plans could lead to evidence necessary
to an understanding of the Pacific Enterprises/Enova
119
merger. It may be that the discovered information would not lead to
relevant evidence, but we cannot determine that fact prior to discovery.
The Findings of Fact and Conclusions of Law that caused the ALJ to
impose sanctions are set forth in the ALJ Ruling of August 18,
1997:
Findings of Fact
1. On April 29, 1997, applicants served their
First Data Request seeking documents regarding
Edison's prospective business plans on Edison.
2. On May 14, 1997, Edison filed objections to
each and every question in applicants' First
Data Request arguing "lack of relevance" for
some questions and claiming a "privilege" for
others. Edison asserted that its strategic
business plan documents fall completely outside
the scope of proper discovery.
3. On May 28, 1997, applicants and Edison
participated in the first of four meet-and-
confer sessions regarding the First Data
Request. At that session, applicants emphasized
the need for Edison to immediately respond to
these questions, and to provide a privilege log
for documents subject to a claim of either
"trade secret" or "work product" privilege.
4. On June 2, 1997, applicants and Edison held a
second meet-and-confer session regarding the
First Data Request during which applicants
restated their need for the privilege log and
immediate responses to the questions in dispute.
5. On June 3, 1997, at the third meet-and-
confer, applicants provided an explanation of
the relevance of each question in the First Data
Request. Edison agreed to provide a trade secret
privilege log by June 17, 1997, but stated that
such log would list only those documents Edison
deemed relevant to the proceeding.
6. At the final meet-and-confer session held on
June 5, 1997, counsel for Edison reconfirmed his
intention to provide a privilege log containing
only "relevant" documents no sooner than
June 17, 1997.
120
7. On June 6, 1997, applicants filed a Motion to
Compel Edison to respond to every question
presented in the First Data Request. Edison
filed its Response to the Motion to Compel on
June 11, 1997. At the June 13, 1997 Law and
Motion hearing, counsel for Edison represented
that Edison would produce a trade secret
privilege log by June 17.
8. On July 3, 1997, Edison filed a Motion to
Quash Discovery.
9. On July 3, 1997, applicants filed a Motion
for an Order Imposing Sanctions on Edison for
its complete failure to comply with its
discovery obligations in this proceeding.
10. At the Law and Motion hearing on July 11,
1997, the presiding Administrative Law Judge
(ALJ) denied virtually all of Edison's Motion to
Quash and granted applicants' Motion to Compel
the remaining responses in dispute, specifically
questions 1-6, 25, and 37-44. The presiding ALJ
ordered that responses to these questions and a
complete trade secret log be produced by Edison
on or before July 25. The ALJ declined to impose
sanctions on Edison at that time. Counsel for
Edison stated the company's intention to produce
the contested material, should the ALJ so order.
11. On July 24, 1997, Edison filed a Motion for
Reconsideration of the ALJ's Ruling denying
Edison's Motion to Quash Discovery and a Motion
for Stay of the ALJ's Ruling compelling
responses.
12. At the Law and Motion hearing on July 25,
1997, the presiding ALJ denied Edison's Motion
for Stay.
13. At the Law and Motion hearing on August 1,
1997, the ALJ denied Edison's Motion to
Reconsider his July 11, 1997, Ruling and found
specifically that there were no circumstances
that cause the imposition of sanctions against
Edison pursuant to the Code of Civil Procedure
to be "unjust."
14. At the Law and Motion hearing on August 1,
1997, the ALJ also specifically found that
Edison had misused the
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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.
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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
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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
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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
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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.
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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
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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.
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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.
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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.
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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.
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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
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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
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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.
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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.
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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).
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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.
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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.
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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.
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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.
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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
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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
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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.
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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
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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
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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.
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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.
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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
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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.
