As filed with the Securities and Exchange Commission on January 28, 1998.
File No. 70-09033
UNITED STATES OF AMERICA
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
___________________________________________________________
AMENDMENT NO. 2 TO
FORM U-1 APPLICATION OR DECLARATION
UNDER
THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
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
President and Chief Operating Officer
Pacific Enterprises
555 West Fifth Street, Suite 2900
Los Angeles, California 90013-1001
(213) 895-5000
Stephen L. Baum
President and Chief Executive Officer
Enova Corporation
101 Ash Street
San Diego, California
(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 {PRIVATE}
SECURITIES AND EXCHANGE COMMISSION
Mineral Energy Company )
) File No. 70-9033
Amendment No. 2 To Application On )
Form U-1 Of Mineral Energy Company )
INTRODUCTION
On March 26, 1997, Mineral Energy Company, a newly
formed California corporation (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 and July 21, 1997, by the submission of
additional exhibits.
The Company hereby amends the Application for the
purpose of expediting the Commission's action on the Application
by providing information about the progress of related approval
proceedings before the California Public Utilities Commission (the
"CPUC"), and the Federal Energy Regulatory Commission ("FERC").
These proceedings are in their final phases. FERC has approved
the Transaction, subject to certain conditions over which it
retains jurisdiction. The CPUC has completed extensive hearings
concerning all issues raised by the Transaction, and has received
a favorable opinion from the California Attorney General regarding
the absence of any adverse effect of the Transaction on
competition. A
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preliminary decision by the administrative law judge in the CPUC
proceeding is expected in February, with a final decision by the
CPUC likely in March.
The CPUC and FERC proceedings directly address a
number of issues that overlap, to some extent, with the issues in
this proceeding under the 1935 Act. The most significant of these
issues is the effect of the Transaction on competition, an issue
that has been raised by intervenors in all three proceedings. As
to this issue, the Company requests the Commission to apply the
doctrine of "watchful deference." Where the Commission and
another regulatory agency both have jurisdiction over a particular
transaction, the Commission, with judicial approval, has held that
it is appropriate for the Commission to "watchfully defer" to the
proceedings before -- and the results reached by -- that other
agency.
The Company requests the Commission to issue its final
order on the Application promptly upon completion of these
regulatory proceedings. [FN1] FERC has already found that,
subject to certain conditions, the Transaction is in the public
interest. The California Attorney General's opinion, based upon
the extensive record compiled in the CPUC proceeding, concludes
that with one possible, and quite limited exception, the
Transaction will not adversely affect competition. Favorable
action by the CPUC would reflect the determination by that agency
that the Transaction is in the public interest. It is critical to
reaping the substantial benefits of the Transaction for both
shareholders and consumers that all unnecessary delays in the
regulatory process be eliminated. The Company believes that this
Amendment -- by keeping the Commission apprised of the progress of
those
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proceedings -- will assist in expediting the Commission's final
decision when those proceedings conclude, and thus will avoid such
delay.
To this end, this Amendment will include:
1. A discussion of the competitive issues raised in
the various proceedings, and of the watchful deference doctrine.
2. A discussion of the mandate of the CPUC, its
expertise, and its proceedings in this matter;
3. A description of the FERC order and matters
remaining to be resolved in that proceeding; and
4. Information concerning Enova's recent decision
to divest SDG&E's generation assets, which bears on the
competition issues.
Information provided in this Amendment will generally
follow the format of Form U-1. The description of the divestiture
of generation assets will be described in Item 1: Description of
the Parties to the Transaction. The competition issues, the
watchful deference doctrine, and the effects of the generation
divestiture on competition will be addressed in Item 3: Applicable
Statutory Provisions. The discussion of the FERC and CPUC
proceedings will be provided in Item 4: Regulatory Approvals.
[FN2]
All capitalized terms used in this amendment will
refer to the definitions in the Application, unless otherwise
indicated.
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Item 1. Description of the Parties to the Transaction
Divestiture of Generation Facilities by SDG&E
On November 24, 1997, the Board of Directors of
SDG&E approved a proposal to auction all of its electric
generation assets. The auction will include SDG&E's two fossil
power plants, its 19 combustion turbines, its 20-percent interest
in the San Onofre Nuclear Generating Station, and its portfolio of
long-term power contracts. The proposed divestiture of these
assets reflects SDG&E's long-term business strategy of
concentrating on the distribution and transmission of electric
power, rather than electric power generation.
The proposed sale of SDG&E's electric generation
assets is subject to the prior approval of the CPUC, and SDG&E
filed a request for such approval on December 19, 1997. Once
SDG&E has received approval from the CPUC, it will proceed with an
auction of its generating assets. The CPUC must then approve any
transaction that results from the auction. The disposition of
SDG&E's interest in the San Onofre Nuclear Generating Station is
subject to approval by the Nuclear Regulatory Commission.
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Item 2. Applicable Statutory Provisions
A. Vertical Market Power
Under Section 10(b)(1) of the Act, the Commission may
disapprove a proposed acquisition if it finds that the acquisition
"will tend towards interlocking relations or the concentration of
control of public-utility companies, of a kind or to an extent
detrimental to the public interest or the interest of investors or
consumers." Two parties seeking to intervene in this proceeding
(the "Intervenors") have argued that the Transaction will enable
the merged entity to exercise vertical market power in the
California electricity market, i.e., that SoCalGas will be able to
exercise its market power in gas transportation to benefit SDG&E's
gas-fired electric generation assets. The core of this attack on
the Transaction, which the Intervenors have also made before FERC
and the CPUC, has been the allegation that SoCalGas will raise (or
otherwise manipulate) electricity prices in California by raising
(or otherwise manipulating) the price of the gas that it delivers
to gas-fired electric generators. In this manner, the Intervenors
contend, SoCalGas will be able to increase the profits of its
electric affiliates, principally SDG&E.
The Company has submitted showings to FERC and the
CPUC that this allegation is without basis because, inter alia:
(1) the CPUC's pervasive regulation of gas transportation and
storage services on the SoCalGas system precludes the kind of
price manipulation that would be necessary for such a scheme to be
effective; (2) SoCalGas and SDG&E account for only a small share
of the natural gas production and interstate pipeline capacity
that serves California; (3) the market for wholesale electric
power in the western
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United States is highly competitive and would discipline any
effort to manipulate the overall market price of electricity; and
(4) the merged entity will have a strong disincentive to increase
the price of wholesale electric power. [FN3] Moreover, to
alleviate any concerns about vertical market power and to fulfill
the conditions imposed by FERC in its order approving the
Transaction, discussed below, the Company has proposed stringent
remedial measures that would govern SoCalGas' provision of service
to SDG&E and other utility electric generators. These measures,
the Company has stated, preclude any possibility that SoCalGas
could exercise vertical market power. As described below, the
California Attorney General found the vertical effects of the
Transaction to be "negligible".
In light of the foregoing, the Commission should
"watchfully defer" to FERC and the CPUC with respect to the claim
that the Transaction would have an adverse vertical effect on
competition. FERC has already fully considered these vertical
competition concerns, and has imposed conditions that it has found
sufficient to allay them. Similarly, the CPUC has committed
extensive time and resources to addressing the vertical
competition issue. As further discussed in Item 4 of this
Amendment, prior to approving the Transaction the CPUC is required
by law to find that the Transaction will not adversely affect
competition. Pursuant to its express statutory mandate, the CPUC
has requested an advisory opinion from the California Attorney
General as to the effect of the Transaction on competition and the
appropriate mitigation measures, and the Attorney General has
opined that the Transaction will have no adverse effect on
competition in the California electricity
market. Both FERC and the CPUC have longstanding expertise in
this area and staff - 6 -
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dedicated to addressing these issues; both agencies enjoy
reputations for diligence, fairness, and a commitment to
competitive markets. [FN4]
This Transaction thus presents a classic case for
application of the doctrine of "watchful deference." That
doctrine was succinctly stated by the United States Court of
Appeals for the District of Columbia Circuit: The Commission
should not "pretend that it is the only agency addressing the
issue when it is not;
that would only lead it to conduct a
wasteful, duplicative proceeding. Rather,
when the SEC and another regulatory agency
both have jurisdiction over a particular
transaction, the SEC may watchfully defer
to the proceedings held before -- and the
result reached by -- that other agency."
[FN5]
There could hardly be a more compelling case for
watchful deference than this one, with respect to competition
issues. First, at least two other agencies will resolve these
issues. [FN6] Second, since the asserted market power concern
centers on anticompetetive effects in California, the CPUC is
especially entitled to deference on this issue.
FERC's expertise and competence to resolve the
competition issues is beyond question. Moreover, state regulation
in this case is anything but lax, pro forma, or otherwise
undeserving of the customary deference. The CPUC has demonstrated
in past proceedings under the predecessor statute to the one at
issue here that its review of a proposed merger is exhaustive. In
1991, the CPUC disapproved the proposed acquisition of SDG&E by
the parent corporation of Southern California Edison. [FN7]
Earlier this year, the CPUC approved the merger of two Bell
regional holding companies, Pacific Telesis Group and SBC
Communications, Inc. [FN8] In both instances, the CPUC rendered
its decision on the basis
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of a thoroughly developed written and oral record which included
extensive discovery and evidentiary hearings and applied the
statutory criteria with rigor. If the doctrine of watchful
deference cannot be applied here, it can never be applied at all.
Finally, it should be noted that the Company's showing
on vertical market power was submitted to FERC, and the California
Attorney General rendered his opinion, before the Company's
announcement that it would divest its generation. As described
more fully below, FERC, in its June 25 order conditionally
approving the merger, stated that such divestiture, in and of
itself, would "eliminate" vertical market power concerns.
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IV. Regulatory Approvals
A. State Regulatory Authority
1. CPUC Proceedings
The CPUC's review of the proposed Transaction pursuant
to Section 854 of the California Public Utilities Code is well
underway. Under that statute, the CPUC must find that the
acquisition (1) provides short-term and long-term economic
benefits to utility ratepayers; and (2) will not adversely affect
competition. The CPUC will be required to find that the business
combination equitably allocates short-term and long-term
forecasted economic benefits of the business combination between
shareholders and utility ratepayers, with ratepayers receiving not
less than 50% of the benefits from regulated operations. In
addition, the CPUC must find that the Transaction is, on balance,
in the public interest upon due consideration of specified public
interest factors, including (1) the fairness and reasonableness of
the acquisition to affected employees and shareholders; (2) the
overall benefits to the California and local economies and to
communities served by the utilities; and (3) mitigation of
significant adverse consequences arising from the merger. The
CPUC is also required to take into consideration an advisory
opinion of the Attorney General of the State of California, which
is summarized below.
An Administrative Law Judge has presided over a
hearing to review the proposed merger, together with the regular
participation of one or more assigned CPUC Commissioners.
Throughout the proceedings, there have been over 45 submissions of
prepared direct testimony, including supplemental and rebuttal
testimony. The Applicants
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have responded to over 3,800 detailed interrogatories and data
requests propounded by interested parties, and have produced over
100,000 pages of documents. In addition, 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. [FN9]
The Company and interested intervenors submitted
opening briefs on November 5, and reply briefs on November 26,
1997. Supplemental briefs to address the proposed divestiture of
SDG&E's generating assets were filed on December 19, 1997. It is
presently expected that the Administrative Law Judge will issue a
proposed order in late February. [FN10] Thereafter, the parties
will have 20 days to comment on the proposed order, and five days
to reply to those comments. The CPUC is expected to issue a final
order by the end of March. [FN11]
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2. Attorney General's Opinion
On November 20, 1997, the Attorney General of the
State of California submitted to the CPUC an advisory opinion as
required by Section 854 of the California Public Utilities Code.
[FN12] (See Exhibit D-9.) The Attorney General there concluded
that the merger will not adversely affect competition within
either the wholesale electricity or interstate gas markets. A.G.
Op. at 1. The Attorney General further concluded that the merger
of the utilities [gas] 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. Id.
The only area in which the Attorney General expressed
even limited concern was with respect to SDG&E's status as a
potential competitor of SoCalGas in the intrastate gas
transmission market. [FN13] The Attorney General recommended
that, if the CPUC were to find that SDG&E is a significant
potential competitor of SoCalGas, the CPUC should require SoCalGas
to auction a quantity of transmission rights over the SoCalGas
system equal to SDG&E's average usage of the system. (The Opinion
expressed no view as to whether SDG&E is, in fact, a potential
competitor of SoCalGas.) The Attorney General made this
recommendation with the expectation that the auctioned
transmission rights would constitute an alternative source of
intrastate transportation, thereby offsetting the loss of SDG&E as
a potential competitor. Id. at 45.
Lastly, the Attorney General recommended that the CPUC
retain jurisdiction over the merger for a period of two years for
the limited purpose of determining whether the
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restructured California marketplace, now scheduled to become
effective on March 31, 1998, will have any effect on the merged
entity's ability to affect the price of wholesale electric power.
Although stating that such an outcome was unlikely, id. at 46,
the Attorney General expressed concern that the full extent of
competition within the restructured marketplace will not be known
until the market is operational. Accordingly, the Attorney
General suggested that the CPUC retain jurisdiction over the
merger to monitor the extent to which competition in the
restructured marketplace imposes constraints on electric power
prices.
3. Affiliate Transaction Ruling
On December 19, 1997, in the context of a general
rulemaking proceeding, the CPUC adopted certain restrictions on
dealings between utility companies and their unregulated
affiliates that engage in energy-related activities. The purpose
of these restrictions is to prevent utilities from favoring their
affiliates in providing either services or information relevant to
the affiliates' marketing activities, and to prevent regulated
utility assets from being used for the benefit of unregulated
affiliate business.
The CPUC's order adopting these restrictions states
that it will be determined in the course of the CPUC's approval
proceeding for the Transaction whether any variations in these
restrictions are appropriate for the Company. The ALJ has
indicated that, unless the evidence compels a different result, he
will recommend adoption of the pertinent generic provisions
without variation. The ALJ has requested submissions on this
point, which were filed on January 23, 1998. The Company will not
object to application of the restrictions as
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they relate to transactions between utilities on the one hand and
unregulated entities on the other hand. The Company expects to
request limitations on the application of the restrictions to
transactions between utility companies, to the extent necessary to
maximize the synergies expected from the Transaction.
B. Federal Power Act
On April 30, 1997, FERC issued an order stating that
the disposition of jurisdictional facilities that would result
from the proposed merger of Enova and Pacific was subject to
FERC's jurisdiction and approval under Section 203 of the Federal
Power Act. See Enova Corporation and Pacific Enterprises, 79 FERC
61,107 (1997). Accordingly, the Commission proceeded to consider
the request for authorization and approval of the Transaction that
the Applicants in that case (the "Applicants") had filed in the
event that FERC found the Transaction to be jurisdictional.
On June 25, 1997, FERC issued an order conditionally
approving the Transaction. [FN14] In that order, FERC found that
Transaction raised potential concerns about vertical market power,
in that it would bring the gas transportation and storage
operations of SoCalGas under common ownership with the electric
generation operations of SDG&E. The Commission further found,
however, that the vertical market power concerns raised by the
merger could be adequately mitigated and that the most effective
mitigation mechanisms are within the jurisdiction of the [CPUC].
Id. at 62,553. The Commission stated that while this Commission
has the authority under [the Federal Power Act] to determine what
remedies are necessary to mitigate market power concerns and to
condition
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our approval of a transaction on those conditions being
implemented, in this particular case effectuation of most of the
[required] remedies is within the jurisdiction of the [CPUC].Id.
at 62,565. Specifically, the Commission observed that the
intrastate gas transmission and distribution operations of
SoCalGas that are the source of the vertical market power concerns
are within the regulatory jurisdiction of the CPUC. Accordingly,
the Commission approved the Transaction on the condition that the
Applicants adopt specific remedial measures intended to allay
vertical market power concerns, and that the CPUC commit to
enforce certain of those measures with respect to SoCalGas, whose
operations are within its exclusive jurisdiction. [FN15]
FERC also specifically noted that divestiture of
SDG&E's electric generation would eliminate any concerns about
vertical market power arising from the Transaction:
Another method of eliminating the vertical
market power problems herein would be
divestiture by SDG&E of gas fired
generation plants. However this remedy
would require authorization of the
California Commission. [FN16]
Thus divestiture, independently of the conditions proposed by
FERC, resolves the vertical competition question.
The remedial measures required by FERC with respect to
SoCalGas are based largely on FERC's Order No. 497 regulations,
which are designed to prevent abuses between natural gas pipelines
and affiliated natural gas marketers. In essence, the goal of
these regulations is to place downstream affiliates on the same
competitive basis as non-affiliated entities, and to require a
strong measure of transparency in the pipeline's
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operations. FERC also required the Applicants to adopt additional
remedial measures above and beyond those required by Order No.
497. [FN17]
In the proceedings before the CPUC, the Applicants
have proposed specific remedial measures to fulfill FERC's
conditions, as well as additional remedial measures not required
by the FERC order. [FN18] Taken together, these commitments
completely allay whatever concern might exist concerning the
exercise of vertical market power by the merged entity prior to
the divestiture of SDG&E's electric generation assets. Moreover,
as shown above, SDG&E's divestiture plan independently resolves
the concerns underlying the conditions provided in FERC's order,
by eliminating any factual basis for such concern.
Item 6. Exhibits and Financial Statements
The following exhibits are filed with this Amendment:
Exhibit D-6 Order of FERC Conditionally Approving
Disposition of Facilities, Dismissing Complaint
as Moot, and Denying Request for Consolidation,
issued June 25, 1997.
Exhibit D-8 Chart of Testimony Before the CPUC.
Exhibit D-9 Opinion of the Attorney General on Competitive
Effects of Proposed Merger Between Pacific
Enterprises and Enova Corporation, submitted to
the CPUC on November 20, 1997.
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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.
MINERAL ENERGY COMPANY
Date: January 26, 1998 By: __________________________
Stephen L. Baum
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[FN1] The Company has requested the Commission to issue a
conditional order approving the Transaction, upon completion of
the Commission's consideration of all issues within its expertise,
without waiting for the conclusion of either the FERC or CPUC
proceedings. This order would be contingent on satisfactory
approvals from both of those agencies. See Reply of Mineral
Energy Company to Motion to Intervene of Southern California
Edison Company (June 4, 1997).
[FN2] Recent financial and other information relating to Enova,
Pacific and their subsidiaries is included in the periodic and
current reports of those companies filed with the Commission under
Section 13(a) of the Securities Exchange Act of 1934. To the
extent relevant to this Application, such reports are incorporated
herein by reference.
[FN3] SDG&E's retail electricity rates are subject to a four-year
freeze. Within the "headroom" allowed by this cap on its rates,
SDG&E must recover not only its costs for distribution,
transmission, and generation, but also any recovery it seeks for
stranded asset costs. Thus, to the extent that the wholesale
price for electricity goes up, SDG&E's opportunity for stranded
cost recovery is diminished.
[FN4] A third agency expert in competitive issues, the Antitrust
Division of the U.S. Justice Department, is also reviewing the
Transaction. Under the Hart-Scott-Rodino Act, the Transaction may
not be consummated until Pacific and Enova have given formal
notification and submitted certain information, and the applicable
waiting period has terminated. Such notification was given on
January 9, 1998.
[FN5] City of Holyoke Gas & Electric Dept. v. SEC, 972 F.2d 358,
363-364 (D.C. Cir. 1992) (citing Wisconsin's Environmental Decade
v. SEC, 882 F.2d 523, 527 (D.C. Cir. 1989).
[FN6] The doctrine clearly applies both to state as well as
federal agency action. See Wisconsin's Environmental Decade,
Inc., v. SEC, 882 F.2d 523 (D.C. Cir. 1989).
[FN7] Re SCEcorp, 122 P.U.R.4th 225 (1991).
[FN8] Re Pacific Telesis Group, 177 P.U.R.4th 462 (1997).
[FN9] A list of witnesses and the subject matter of this testimony
is included as Exhibit D-8, filed with this amendment.
[FN10] Based on a scheduling order dated July 1, 1997, the
proposed decision of the Administrative Law Judge (the "ALJ") was
previously expected in January. In an order dated December 24,
1997, the ALJ modified that date, stating that he expected his
proposed decision to issue on February 25, 1998, although he would
strive for an earlier date. This extension will provide the ALJ
with time to consider submissions relating to affiliate
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transaction restrictions and synergies, discussed below, which
were filed on January 23, 1998.
[FN11] By order dated December 30, 1997, the ALJ stated his
preliminary recommendation with respect to scheduling and
allocation of savings to be realized by the Transaction, and
directed the parties to provide certain related information.
Those submissions were filed on January 23, 1998.
[FN12] As noted above, the Attorney General issued his opinion
shortly before SDG&E announced the proposed divestiture of its
generation assets. Accordingly, the opinion does not take into
account the effect that the divestiture will have on allegations
of vertical market power.
[FN13] Significantly, this is not a concern raised by the
Intervenors in this proceeding.
[FN14] San Diego Gas & Electric Company, 79 FERC 61,372 (1997). A
copy of the FERC's order is included as Exhibit D-6. The Company
has previously described FERC's June 25 order in the Reply of
Mineral Energy Company to Supplement to Motion to Intervene of
Southern California Edison Company, filed in this docket on
October 1, 1997.
[FN15] FERC further conditioned its approval of the Transaction on
the adoption of certain remedial measures that are within its own
jurisdiction. Specifically, the Commission required that SDG&E
file a code of conduct and Enova Energy file a revised code of
conduct that comports with FERC's requirements for codes of
conduct for utilities or marketers with market-based rate
authority. Both SDG&E and Enova Energy have made these filings
with FERC.
[FN16] 79 FERC 61,372 at 62,565 n.58.
[FN17] FERC's specific conditions were as follows:
1. SoCalGas must commit to the affiliate dealing
restrictions set forth in Order No. 497 and apply them to its
dealings with all members of the Pacific-Enova corporate family.
2. SoCalGas must operate its GasSelect electronic bulletin
board as an interactive, same-day reservation and information
system.
3. SDG&E and Enova Energy must separate their purchases of
transportation by SoCalGas as between (a) electric generation
volumes, and (b) other volumes, and make purchases of
transportation for electric generation volumes on the SoCalGas
GasSelect bulletin board under terms and conditions comparable to
non-affiliated electric generation shippers.
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4. SoCalGas must publicize in advance on GasSelect its
planned use of pipeline capacity to fill storage.
[FN18] The additional remedial measures proposed by the applicants
are as follows:
1. SoCalGas will further separate its Gas Operations and
Gas Acquisitions functions;
2. SoCalGas will restrict information flow with regard to
financial positions in futures markets;
3. SoCalGas will seek prior CPUC approval of
transportation rate discounts or rate designs offered to any
affiliated shipper; and
4. SoCalGas will post an unprecedented volume of
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.
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(..continued)
San Diego Gas & Electric Company and Enova Energy, Inc.
Enova Corporation and Pacific Enterprises
Southern California Edison Company
V.
San Diego Gas & Electric Company, Enova Energy, Inc., and
Ensource Corp.,
Docket No. EC97-12-000
Docket No. EL97-15-001
Docket No. EL97-21-000
Order Conditionally Approving Disposition of Facilities,
Dismissing Complaint as Moot, and Denying Request for
Consolidation
(Issued June 25, 1997)
Before Commissioners: James J. Hoecker, Chairman; Vicky A. Bailey,
William L. Massey, and Donald F. Santa, Jr.
On January 27, 1997, San Diego Gas & Electric Company
(SDG&E) and Enova Energy, Inc. (Enova Energy) (collectively,
Applicants) filed an application in Docket No. EC97-12-000
pursuant to section 203 of the Federal Power Act (FPA) [FN1] for
an order approving the merger of Enova Corporation (Enova) and
Pacific Enterprises (Pacific). Enova and Pacific are both exempt
public utility holding companies under section 3(a)(1) of the
Public Utility Holding Company Act (PUHCA) of 1935. [FN2] Enova is
the parent of SDG&E, a traditional utility, and Enova Energy, a
power marketer authorized to sell power at market-based rates.
[FN3] Pacific is the parent of Southern California Gas Company
(SoCalGas), a natural gas distribution company.
As discussed below, on April 30, 1997, the Commission issued
an order in Docket No. EL97-15-000 asserting jurisdiction over the
disposition of the jurisdictional facilities of SDG&E and Enova
Energy that would occur as a consequence of the merger of Enova
and Pacific. However, the Commission did not assert jurisdiction
over the merger of Enova and Pacific. [FN4] Therefore, we will
consider the application for section 203 merger approval in Docket
No. EC97-12-000 as a section 203 application for approval of the
disposition of SDG&E's and Enova Energy's jurisdictional
facilities occurring in conjunction with the merger of Enova and
Pacific.
The April 30 order addressed only the question of whether the
Commission's section 203 jurisdiction is applicable to the instant
corporate realignment, or any aspect thereof. Some intervenors in
that docket raised additional issues and concerns relating to the
propriety of approving the proposed transaction and/or requested
evidentiary hearing on certain matters. The April 30 order
deferred addressing those additional concerns until after the
matter of jurisdiction was established. Therefore, we will address
those concerns in the context of our review of the
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application for section 203 approval filed in Docket No. EC97-12-
000.
On January 10, 1997, Southern California Edison Company
(SoCal Edison) filed a complaint against SDG&E, Enova Energy, and
Ensource Corporation, a subsidiary of Pacific, in Docket No.
EL97-21-000 requesting that the Commission find the merger of
Enova and Pacific subject to the Commission's jurisdiction under
section 203. Since the jurisdictional status of the merger of
Enova and Pacific and the consequential disposition of the
jurisdictional facilities of SDG&E and Enova Energy were
established in the April 30 order, we will dismiss SoCal Edison's
complaint as moot. [FN5]
As discussed more fully below, the Commission concludes that
the proposed disposition of facilities raises vertical market
power concerns and the potential for the merged entity to exercise
market power that could adversely affect wholesale power markets.
However, we believe that these market power concerns could be
mitigated. In particular, the most effective mitigation mechanisms
are within the jurisdiction of the California Commission.
Therefore, we will conditionally approve the proposed disposition
conditioned upon the adoption of market power mitigation remedies,
as discussed below.
I. Description of the Corporate Realignment, Participants, and
Contents of the
Application
A. Description of Corporate Realignment Participants
1. Enova, SDG&E, and Enova Energy
As indicated above, Enova is an exempt public utility
holding company [FN6] and the parent of two public utilities:
SDG&E, an electric utility, and Enova Energy, a power marketer.
SDG&E owns and operates electric generation, transmission, and
distribution facilities, and serves electric and natural gas
customers at retail in California. Enova Energy is a power
marketer with market-based power sales rate authority. [FN7]
2. Pacific and Subsidiaries
Pacific is also an exempt public utility holding company and
the parent of, among others, SoCalGas. [FN8] SoCalGas provides gas
service to customers in California and owns certain qualifying
facilities (QFs) with a total of 1.6 megawatts (MW) of capacity.
Pacific's subsidiaries also include various natural gas pipelines,
specifically: Pacific Interstate Transmission Company, Pacific
Interstate Offshore Pipeline Company, and Pacific Offshore
Pipeline Company. Pacific's subsidiary, Pacific Energy, has direct
and indirect ownership interests in certain QFs totaling 182 MW of
capacity. However, the Applicants state that Pacific Energy
intends to divest itself of 88.5 MW of QF capacity in order to
maintain QF status under the Public Utility Regulatory Policies
Act.
B. Description of the Corporate Realignment
The application states that the two holding companies, Enova
and Pacific, would be combined under a newly created holding
company, NewCo. [FN9] NewCo would own all of the
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stock of Enova and Pacific and would be owned by Enova's and
Pacific's stockholders. NewCo Enova Sub, a subsidiary of NewCo,
would merge into Enova, with Enova as the surviving corporation.
NewCo Pacific Sub, also a subsidiary of NewCo, would merge into
Pacific, with Pacific surviving. All Enova and Pacific common
stock would be converted into the right to receive NewCo common
stock. Upon consummation of this transaction, Enova and Pacific
would be wholly owned subsidiaries of NewCo. Enova, Pacific,
SDG&E, and SoCalGas would continue their separate corporate
existence and would continue to operate under their existing
names.
The application further explains that Enova and Pacific have
formed a joint venture that would engage in marketing natural gas
and electricity. The application states that the joint venture
would not make jurisdictional power sales until after consummation
of the merger and after filing a separate application for, and
receiving, sales authorization from the Commission.
C. Application for Approval under Section 203
The Applicants state that the proposed transaction satisfies
the criteria set forth in the Merger Policy Statement. The
Applicants state that the competitive screen analysis established
in the Merger Policy Statement is not required in this case
because the parties to the corporate realignment do not have
facilities or sell relevant products in common geographic markets.
The Applicants further state that Pacific's role in sales
and transportation of natural gas does not give rise to concerns
related to the sale of electricity. The Applicants state that the
Public Utilities Commission of the State of California (California
Commission) imposes restrictions that prevent SoCalGas from
operating in a discriminatory manner by either favoring SDG&E over
competing generators in terms of service or pricing, or by
providing market information to its affiliates that is not also
provided to competing power sellers. Further, the Applicants state
that SoCalGas has undertaken to post contemporaneously, and to
offer to other similarly-situated non-affiliated shippers, any
discounts it offers to SDG&E, and that Pacific and Enova have
adopted a code of conduct that would forbid SoCalGas from
providing sensitive market information to any marketing affiliate
unless it simultaneously makes the information available to
unaffiliated electric marketers.
The Applicants also assert that the corporate realignment
will have no adverse effects upon competition in transmission
since Pacific owns no electric transmission and SDG&E has an open
access tariff. The Applicants also point out that SDG&E will turn
over operational control of its transmission system to an
Independent System Operator (ISO) under the California
restructuring. The Applicants further assert that any effects on
the retail market resulting from the corporate realignment would
be reviewed by the California Commission. Nevertheless, the
Applicants prepared an analysis of the competitive effects of the
proposed corporate realignment in a portion of Orange County,
California, where SDG&E's and SoCalGas' service territories
overlap. The Applicants state that there is "scant fuel
substitutability and little competition between the two fuels."
Also, the Applicants assert that, with the advent of retail
customer choice resulting from the current restructuring of the
electric industry in California, "intrafuel competition will
discipline the market more effectively than interfuel competition
could."
The Applicants state that the proposed corporate realignment
would have no effect on competition in electric generation
markets. The Applicants state that the only generation owned by
Pacific is an ownership interest in 182 MW of QFs. The Applicants
state that Pacific will divest itself of some or all of its
interests prior to consummation of the corporate realignment to
the
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extent necessary to maintain QF status under the Public Utility
Regulatory Policies Act. Nevertheless, the Applicants assert that
application of the competitive screen analysis to this aspect of
the transaction indicates that there would be no increase of more
than 16 points in the Herfindahl-Hirschman Index (HHI) for any
destination market. The Applicants state that this shows there is
no basis for concern in this regard.
The Applicants further explain that SDG&E is able to
exercise horizontal market power within the San Diego Basin
because its own units are needed to meet load under certain
conditions due to transmission constraints into the Basin.
However, the Applicants argue that the Commission need not be
concerned about this matter for two reasons: (1) SDG&E has no
wholesale customers within the San Diego Basin; and (2) this
existing situation would not be affected by the proposed corporate
realignment.
The Applicants also state that the proposed corporate
realignment would have no adverse effect on rates because neither
SDG&E nor Enova Energy has firm wholesale customers. The
Applicants state that SDG&E's only wholesale sales are economy
energy sales and short-term sales of capacity. Further, the
Applicants state that SDG&E will be obligated, after commencement
of the proposed California Power Exchange (PX or California PX),
to bid all of the output of its fossil generation into the PX for
a five-year period at variable costs and to rebate to customers
any PX revenues for such generation exceeding variable costs.
Since SDG&E's variable costs would not be affected by the proposed
corporate realignment, the Applicants opine that the transaction
would have no adverse effect on wholesale rates.
The Applicants also state that SDG&E has no firm
transmission contracts for service through its system other than
for short-term as- available service and mutual assistance
short-term back-up transmission assignments. Any other
transmission commitments involve interchange contracts, Western
System Power Pool as-available commitments, or transmission under
SDG&E's open access tariff. Nevertheless, the Applicants state
that SDG&E will hold its future wholesale and transmission
customers harmless from any increase in jurisdictional costs
arising out of the transaction for at least five years after the
corporate realignment is consummated. Also, the Applicants state
that SDG&E would undertake the burden in any Commission rate case
it files within five years after the consummation of the corporate
realignment to show that its rates are not higher than they
otherwise would have been absent the merger.
The Applicants assert that the proposed corporate
realignment would have no effect on regulation since the
transaction is subject to approval by the California Commission,
and since a registered holding company would not be created as a
result of the transaction.
II. Notice of Application, Interventions, Protests, and Answer
Notice of the Applicants' application in Docket No.
EC97-12-000 was published in the Federal Register, with comments,
protests, and interventions due on or before March 28, 1997.
[FN10] Timely motions to intervene were filed by the California
Industrial Group and the California Manufacturers Association,
jointly; Electric Clearinghouse, Inc.; El Paso Natural Gas Company
and Mojave Pipeline Company, jointly; International Brotherhood of
Electrical Workers, Locals 18 and 47; KN Marketing, Inc.; Nutra
Sweet Kelco Company; and Pan- Alberta Gas Ltd. The California
Commission filed a notice of intervention. The above-listed
motions and notice raise no substantive issues.
Pacific Gas and Electric Company (PG&E) and the City of San
Diego (San Diego) filed
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timely motions to intervene which take no position on whether the
proposed disposition of facilities should be approved. However,
San Diego raises certain issues for consideration which are noted
in the following discussion. PG&E, while not stating a position
regarding the requested approval, states that the Commission
should consider the impact of the proposed corporate realignment
on: (1) the competitiveness of electricity markets; (2) electric
industry restructuring; (3) possible affiliate transaction issues
that may arise; (4) existing transmission contracts, including the
Pacific Intertie agreements; and (5) how the merged entity will
interact with the ISO being proposed for California.
U.S. Generating Company (USGen), Imperial Irrigation
District (Imperial Irrigation), Kern River Gas Transmission
Company (Kern River), SoCal Edison, the Southern California
Utility Power Pool (the Power Pool) [FN11] and the City of Vernon
(Vernon) filed timely motions to intervene and requests for
hearing regarding the competitive effect of the propose corporate
realignment. The Southern California Public Power Authority
(Public Power Authority) [FN12] filed a timely motion to intervene
and a motion to consolidate the instant docket with Docket Nos.
EL97-15-000 and EL97-21-000, stating that the three proceedings
are integrated in issues and concerns such that their disposition
must be consolidated to avoid redundant proceedings and
litigation. Imperial, Kern River, the Power Pool, Public Power
Authority, SoCal Edison, and Vernon also protest the application.
Intervenors [FN13] assert that the proposed corporate
realignment would combine a company with monopoly power over
interstate gas transportation release capacity to southern
California and a monopoly in intrastate natural gas transportation
and storage capacity in southern California, [FN14] with an
electric utility in a position to exploit the opportunity to
control the market-based price of electricity to be traded in the
California PX. [FN15] Intervenors assert that the Applicants'
control of essentially all natural gas pipelines in southern
California, and the Applicants' control of interstate gas pipeline
capacity entering southern California through the pipeline's
capacity release mechanism, would allow the Applicants to
manipulate the delivered price of natural gas to SDG&E's gas-fired
generators and other competing gas-fired generators. Through such
manipulations, the Applicants could: (1) force SDG&E's competitors
to charge higher, anticompetitive prices for generation; [FN16]
(2) discriminate in the degree of convenience, reliability, or
flexibility of gas supply to SDG&E to the detriment of its
competitors; [FN17] (3) act as a barrier to entry for competing
electric generators; [FN18] and (4) raise the PX spot market
price. [FN19]
Regarding the PX, Intervenors assert that a relevant market
for the analysis of the potential anticompetitive effects of the
proposed corporate transaction is the market for gas-fired
generation in southern California, since gas-fired generation
within the state is expected to set the California PX hourly spot
price during the majority of hours. Intervenors assert that since
the PX hourly spot bids would reflect the higher delivered gas
costs paid by SDG&E's competitors (assuming SoCalGas favored SDG&E
over other customers), the spot price would be artificially
increased. Since SDG&E arguably would not have to pay the higher
gas costs, the Intervenors assert that SDG&E's bid into the PX
would be lower than that of its competitors, and thus SDG&E would
profit from the higher spot price resulting from SoCalGas'
manipulations of delivered gas prices to SDG&E's competitors.
[FN20]
Intervenors state that the Merger Policy Statement is
directed primarily toward horizontal mergers (or other forms of
corporate realignment) and that the Merger Policy Statement
adopted the Department of Justice and Federal Trade Commission
Horizontal Merger Guidelines [FN21]
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as the analytical framework for evaluating proposed corporate
realignments. Intervenors state that the instant proposal raises
vertical merger issues (i.e., the merged entities' ability to
manipulate delivered gas costs to gas-fired generators that
compete with SDG&E's gas-fired generators), in addition to
horizontal issues, and suggest that the vertical analytical
framework outlined in the Department of Justice 1984 Merger
Guidelines, [FN22] should be applied rather than the 1992
Horizontal Merger Guidelines adopted in the Merger Policy
Statement as the basis for analyzing the proposed corporate
realignment. [FN23] San Diego suggests that the Applicants be
required to submit a competitive screen analysis in the form of
computer simulations.
Intervenors also express concern that the SoCalGas could
share real-time knowledge of the gas usage and costs of SDG&E's
generation competitors, as well as other types of customer
information, that SDG&E would be able to use to its competitive
advantage. Public Power Authority suggests imposition of standards
of conduct and restrictions on affiliate abuse to alleviate this
concern. [FN24] Similarly, the combination of managerial control
over electric and gas subsidiaries operating in the same
geographic market region has been raised as a concern. [FN25]
Further, Intervenors argue that the Applicants will be able
to manipulate gas supply in order to evade rate regulation. [FN26]
Intervenors state that by "assigning" higher priced gas to SDG&E
for retail ratemaking purposes, the Applicants could pass these
increases through to downstream ratepayers, collecting the
increased profits despite retail rate regulation.
Intervenors also raise concerns regarding the Applicants'
ability to use SoCalGas' natural gas transportation and storage
services to adversely affect natural gas competition in southern
California. For example, Intervenors argue that the Applicants
will be able to impose short-term and long-term adverse effects on
competition in the transportation of natural gas in southern
California, and limit expansion of current pipeline capacity into
southern California. [FN27] Kern River and Power Pool state that
this situation would be alleviated to some extent if the
Commission required termination of SoCalGas' existing option to
acquire Kern Rivers' interstate pipeline facilities located in
California. Intervenors also assert that the proposed transaction
would serve to eliminate SDG&E as a potential competitor of
SoCalGas, or, alternatively, as a direct customer and anchor
tenant of any other pipeline that might seek to enter the San
Diego market. [FN28]
USGen also states that SDG&E holds the only available
pollution allowances under the regulations of the San Diego Air
Pollution Control District for oxides of nitrogen (NO/x\) in the
San Diego Basin for boilers and gas turbines used for the
generation of electric power in the San Diego area. USGen states
that any new entrant into the electric generating market, such as
USGen, must obtain NO/x\ allowances from SDG&E, and that SDG&E is
under no requirement to make these allowances available to others;
USGen concludes that this creates a barrier to entry that, along
with control of fuel access, should be investigated through
hearing.
Intervenors raise concerns regarding Energy Pacific, the
joint venture created by Enova and Pacific. [FN29] Intervenors
state that the creation of Energy Pacific encompasses a de facto
merger within the Commission's section 203 jurisdiction. Further,
Intervenors intimate that Energy Pacific is engaging in
jurisdictional activities (i.e., wholesale power sales) without
proper authorization from the Commission. Intervenors request that
the Commission impose restrictions on the activities of Energy
Pacific. Intervenors also argue that Energy Pacific should be
precluded from having a financial interest in any gas-fired unit
served by SoCalGas or own or contract to supply gas to any such
unit, and that Energy Pacific should be precluded from
participating in any
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futures markets that involve southern California power generation.
Intervenors assert that an important product market that
would be affected by the proposed corporate realignment is the
energy services market, and that the Commission should either
include the energy services market in its market power evaluations
or investigate this issue at hearing. [FN30]
Intervenors request that the Commission impose conditions
that would: (1) ensure that the merged company and its
subsidiaries cannot favor their own gas transportation
requirements over the gas transportation requirements of
competitors; (2) provide transparency with respect to supply,
availability, and price of gas transportation services; and (3)
increase available interstate gas transportation capacity that is
not controlled by SoCalGas. [FN31]
Intervenors also ask that the merging entities be required
to offer discounts, capacity, contracts, or other information for
interstate gas transportation on a non-discriminatory basis. Power
Pool states that the Applicants' commitment to offer gas
transportation capacity discounts to all "similarly situated"
customers should not be used to discriminate between wholesale
customers (such as SDG&E) and gas-fired generators (retail
customers). Further, it is suggested that the Commission require
that the merging entities offer for sale at cost any gas
transportation capacity that is not required to meet their own
retail native gas distribution load. [FN32] Vernon asks that the
Commission condition any approval of the proposed transaction on a
requirement that competition in gas transmission in southern
California not be diminished.
Power Pool states that SDG&E's gas operations should be
merged into SoCalGas so that all California generators would be
served under uniform tariff provisions, cost allocation
principles, and rates. Power Pool also states that SoCalGas should
be required to hold an open season permitting customers, and
possibly others, to acquire an undivided interest in SoCalGas
transmission and associated storage facilities.
Power Pool also suggests that the Commission order the
merging entities to separate their interstate gas transportation
and gas marketing operations to ensure that the Applicants have no
opportunity to favor their own gas marketing efforts over those of
their competitors, and impose standards of conduct which would
preclude any communications regarding the availability, or price,
terms, or conditions of gas transportation services between the
merging parties and their affiliates' gas transportation
operations and marketing personnel.
Intervenors also request that SoCalGas be required to divest
itself of its gas transmission and storage facilities and that
SDG&E be required to divest itself of its gas distribution
facilities, or that SDG&E and SoCalGas be required to divest
themselves of all of their gas-fired generators and SoCalGas be
required to divest itself of all of its contract and other rights
in interstate pipelines. [FN33] Intervenors assert that such
divestiture would increase competition by providing access to
facilities necessary for marketers or new market entrants to
provide competitive services, and that barring such divestiture,
new entrants would be unable to enter the market. Intervenors also
argue that SoCalGas' control of interstate gas transportation
facilities and related capacity rights on interstate pipelines
serving the relevant markets is sufficient to require the
suggested divestiture of facilities.
On April 14, 1997, the Applicants filed an answer to various
motions, arguing (1) that the Intervenors fail to state adequate
grounds for an evidentiary hearing; (2) that the claims that
Energy Pacific represents a de facto merger are baseless; and (3)
that the Intervenors' requests for consolidation, a revised market
power analysis, and a hearing on NO/x\ issues should be denied.
The Applicants assert that Intervenors have failed to state
adequate grounds for setting
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this application for hearing to investigate the proposed corporate
realignment's potential adverse effects on competition. The
Applicants state that any discounts in transportation rates to
SDG&E could not be targeted to SDG&E's electric generation
function, as distinct from SDG&E's own core and noncore customers,
absent specific approval from the California Commission; that
SoCalGas has committed in a California Commission proceeding to
abide by the Commission's order No. 497 [FN34] restrictions on
transportation discounts to affiliates; that SoCalGas had proposed
to the California Commission strict limitations on the transfer of
valuable customer information to affiliated entities; and that
SoCalGas would apply the same strictures to conveyance of customer
information to SDG&E's electric-merchant function. The Applicants
also state that with the price cap imposed by the California
Legislature in Assembly Bill 1890 any increases in the PX price
for electricity would diminish SDG&E's ability to recover stranded
costs; therefore, the Applicants state that there would be a
strong disincentive to increase PX prices as long as the price cap
is in effect.
The Applicants further assert that all of SDG&E's fossil
generators are must run, and that the Applicants are seeking ISO
concurrence on that issue. The Applicants also state that any of
SDG&E's gas-fired capacity not covered by a must-run contract that
assures recovery of fixed operating and maintenance costs would be
unprofitable at PX prices and would be shut down. Therefore, the
Applicants state that any generation deemed to be must run would
almost certainly be placed under one of the two versions of the
ISO's must-run contract (the "B" or "C" contract) under which the
Applicants could not benefit from a higher PX price. [FN35]
The Applicants assert that the vertical arguments made by
Intervenors relate to matters within the California Commission's
jurisdiction, and that these issues are currently being addressed
by the California Commission. Aside from their filing with the
California Commission, the Applicants report that the California
Commission has recently instituted a rulemaking and companion
investigation "to establish standards of conduct governing
relationships between California's natural gas local distribution
companies and electric utilities and their affiliated, unregulated
entities providing energy and energy-related services, and to
determine whether the utilities should be required to have their
nonregulated or potentially competitive activities conducted by
their affiliate companies." [FN36] The Applicants also relate that
the California Commission intends to "coordinate our consideration
of any affiliate transaction rules in the PE/Enova [California
Commission] docket." [FN37] The Applicants also state that in its
1997 Business Plan, the California Commission has indicated its
intention to take actions to "remove alleged market distortion in
transportation and to ensure, equal, adequate access to market
information." [FN38]
The Applicants also refute the allegations that the merged
company can increase the border price of gas flowing into
California by manipulating capacity release practices on an
interstate pipeline. The Applicants state that this issue is
before the Commission in a complaint proceeding in Docket No.
RP97-284-000. [FN39] The Applicants further state that the
Interstate Transition Cost Surcharge, which is the means through
which it is alleged that the Applicants could recover from
SoCalGas' customers the demand charges for any unused pipeline
capacity that is not recovered in the capacity release market is a
matter of state regulation, specifically the manner in which the
California Commission allocates excess capacity costs between core
and noncore classes.
III. Discussion
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A. Procedural Matters
Pursuant to Rule 214 of the Commission's Rules of Practice
and Procedure, [FN40] the timely, unopposed motions to intervene
and notice of intervention serve to make the following parties in
Docket No. EC97-12-000: the California Industrial Group and the
California Manufacturers Association, jointly; Electric
Clearinghouse, Inc.; El Paso Natural Gas Company and Mojave
Pipeline Company, jointly; International Brotherhood of Electrical
Workers; KN Marketing, Inc.; Nutra Sweet Kelco Company;
Pan-Alberta Gas Ltd.; the California Commission; PG&E; San Diego;
USGen; Imperial Irrigation; Kern River; SoCal Edison; Public Power
Authority; the Power Pool; and Vernon. Pursuant to Rule 213(a)(2),
[FN41] the Commission will not consider those aspects of the
answer filed by the Applicants that respond to protests.
Public Power Authority filed a motion to consolidate the
instant docket with Docket Nos. EL97-15-000 and EL97-21-000,
stating that the three proceedings are integrated in issues and
concerns such that their disposition must be consolidated to avoid
redundant proceedings and litigation. However, in light of the
fact that Docket No. EL97-21-000 is being dismissed as moot, and
that any remaining issues raised in Docket No. EL97-15-000 (that
were not address in the April 30 order) are being addressed in the
context of Docket No. EC97-12- 000, consolidation is not required.
B. Background
1. Statutory Criteria
As noted, on April 30, 1997, the Commission issued an order
which determined that the corporate realignment of Enova and
Pacific would result in the disposition (via a transfer of
control) of the jurisdictional facilities of SDG&E and Enova
Energy which requires Commission authorization under section 203
of the FPA. Section 203 reads in pertinent part:
(a) No utility shall sell, lease, or otherwise dispose of .
. . its facilities subject to the jurisdiction of the Commission .
. . or by any means whatsoever, directly or indirectly, merge or
consolidate such facilities or any part thereof with those of any
other person, or purchase, acquire, or take any security of any
other public utility, without first having secured an order of the
Commission authorizing it to do so. . . . After notice and
opportunity for hearing, if the Commission finds that the proposed
disposition, consolidation, acquisition, or control will be
consistent with the public interest, it shall approve the same.
(b) The Commission may grant any application for an order
under this section in whole or in part and upon such terms and
conditions as it finds necessary or appropriate to secure the
maintenance of adequate service and the coordination in the public
interest of facilities subject to the jurisdiction of the
Commission. The Commission may from time to time for good cause
shown make such orders supplemental to any order made under this
section as it may find necessary or appropriate.
2. Merger Policy Statement
The Commission's Merger Policy Statement sets forth the
criteria and considerations for
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evaluating applications under section 203. [FN42] The Commission
examines three factors in analyzing whether a proposed transaction
is consistent with the public interest: the effect on competition,
the effect on rates, and the effect on regulation. The Commission
also recognized:
[A]s the industry evolves to meet the challenges of a more
competitive marketplace, new types of mergers and consolidations
will be proposed. For example, in addition to mergers between
public utilities, market participants already are considering
restructuring options that include mergers between public
utilities and natural gas distributors and pipelines,
consolidations of electric power marketer businesses with other
electric or gas marketer businesses, and combinations of
jurisdictional electric operations with other energy services.
(Footnote omitted.) As a consequence, our merger policy must be
sufficiently flexible to accommodate the review of these new and
innovative business combinations that are subject to our
jurisdiction under section 203 and to determine their implications
on competitive markets. We believe that the analytical framework
articulated in this Policy Statement provides a suitable
methodology for determining whether such mergers will be
consistent with the public interest. [FN43]
C. Evaluation of the Proposed Disposition of Facilities
1. The Effect on Competition: Vertical Market Power
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 [FN44] with the electric operations of
SDG&E. SoCalGas 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.
The Commission has evaluated the competitive concerns raised
by the proposed transaction within the context of a framework that
is consistent with our Merger Policy Statement. This framework is
informed by the Department of Justice's (DOJ's) approach to
evaluating the competitive effects of vertical mergers. [FN45]
However, although the same general factors that govern our
analysis under the Merger Policy Statement apply here, the Merger
Policy Statement originally was crafted to apply primarily to
horizontal mergers. The Commission's approach to evaluating the
competitive effects of vertical mergers is evolving as the
Commission gains more experience with the convergence of gas and
electric utilities. Additional experience will undoubtedly bring
new insights to bear in refining our analysis.
Vertical mergers raise three types of general competitive
concerns: (1) denying rival firms access to inputs or raising
their input costs; [FN46] (2) increased anticompetitive
coordination; and (3) regulatory evasion. These potential actions
can adversely affect competition through higher prices or reduced
output in the downstream output market.
Applicants performed no analysis of the vertical effects of
the proposed transaction.
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However, based on our own evaluation of vertical concerns, we
believe that the proposed transaction poses the first two of the
competitive problems discussed above: (1) foreclosure/raising
rivals' costs; and (2) increased anticompetitive coordination. On
the facts of this particular case, the Commission views regulatory
evasion as largely a retail issue that does not require additional
investigation by this Commission. [FN47]
For a vertical merger to have a potentially adverse effect
on competition in the wholesale electricity market, resulting in
lower output or higher prices, it is necessary for the upstream
delivered gas and downstream wholesale power markets to be
conducive to the exercise of market power after the merger. A
vertical merger is unlikely to have an adverse effect on
competition unless the merged company has the incentive and
ability to affect prices or quantities in the upstream and
downstream markets.
As a starting point to evaluating the competitive effects of
the proposed transaction, we have used the basic principles laid
out in the 1992 Horizontal Merger Guidelines and adopted in the
Commission's Merger Policy Statement, applied to both the upstream
delivered gas and downstream wholesale power markets to determine
whether those markets are conducive to the exercise of market
power after the merger. The Commission views this approach as the
correct framework in which to evaluate the competitive effects of
vertical mergers. As such, we have: (1) defined relevant product
and geographic markets; (2) examined the competitive circumstances
in the upstream market (here, delivered gas) and the effect of
entry into that market; (3) examined the competitive circumstances
in the downstream market (here, wholesale electricity) and the
effect of entry into that market; and (4) considered, based on the
circumstances in the upstream delivered gas market and downstream
wholesale electricity market, whether the net effect of the merger
would likely be significantly higher wholesale electricity prices.
Both the Applicants and Intervenors address the effects of
the proposed transaction assuming that the California PX defines
the wholesale power market. However, our concerns are not limited
to a market arrangement consisting of a PX in California. In large
part, our analysis regarding the competitive effects of the
proposed transaction applies equally to a bilateral or PX market
arrangement. Where our analysis here differs depending on whether
a PX or bilateral market arrangement is assumed, we specifically
note that fact.
a. Relevant Markets
i. Product Market
As a first step, it is necessary to define relevant product
and geographic markets. In the upstream (or input) market, the
product is delivered gas.
With respect to the downstream market, the Applicants point
out that SDG&E is capacity-short at least through the rest of the
decade and, as such, only participates in the energy markets. The
Commission agrees that it is reasonable to consider energy the
relevant product for the purposes of analyzing the competitive
effects of the proposed transaction in the downstream wholesale
power market. As discussed below, this conclusion applies under
any market arrangement, i.e., either the current, bilateral
trading arrangement or the planned PX auction for spot energy into
which SDG&E will sell all its generation.
ii. Geographic Market
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We conclude that southern California is the relevant
geographic market in both the upstream and downstream markets.
SDG&E and SoCalGas have operations in a common geographic area -
southern California. This area contains many of the potential
wholesale customers who may be affected by the proposed merger,
i.e., those customers who can purchase from the merged company and
its competitors. Under the proposed PX electricity market
arrangement, the relevant geographic market is defined as
California, since SDG&E, SoCal Edison and PG&E are required to bid
all of their generation into the PX. However, Intervenors argue
that transmission constraints between northern and southern
California define southern California as the relevant market for
some of the year. Together, these factors suggest that southern
California, therefore, is a reasonable starting point for defining
the relevant geographic market.
Wholesale power customers in the relevant geographic market,
however, could potentially purchase from entities outside southern
California, if it were physically possible and economic to do so.
Entities outside California may also bid into the proposed PX. As
discussed more fully in the Merger Policy Statement, transmission
rates and transmission constraints play an important role in
determining whether such energy would be economic under the
delivered price test. Applicants have not performed a delivered
price test. Nevertheless, the Commission notes that while southern
California utilities historically have purchased from regions
outside California, including the desert Southwest, Nevada,
Utah/Colorado, the Pacific Northwest and northern California, such
imports are limited by available transfer capability on the
associated transmission ties and transmission constraints.
b. Upstream Delivered Gas Market
i. Competitive Conditions
In southern California, SoCalGas is the dominant supplier of
delivered gas services to gas-fired generators. These services are
regulated by the California Commission. Intervenor City of Vernon
estimates, and applicants do not refute, that SoCalGas delivers
gas to 96% of gas-fired steam and combined cycle generators
(excluding qualifying facilities) in southern California. As a
result, gas-fired generators competing with the merged company
have few, if any, alternatives to SoCalGas for delivered gas
services. Additionally, SoCalGas' near-monopoly on delivered gas
services in southern California means that it transacts with
virtually all gas-fired generators in southern California and has
access to potentially sensitive market information regarding those
competing generators' costs and fuel usage.
Under these circumstances in the delivered gas market, the
Commission concludes that the merged company may use its market
power to restrict competing generators' access to delivered gas
services and to raise such generators' input costs, as discussed
below and further summarized in section e.
ii. Entry
The Merger Policy Statement discusses the importance of
entry into markets affected by potential mergers. If entry by
competitors is timely, likely, and sufficient, this can
effectively
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discourage the merged company's strategy of raising competing
generators' input costs. There is nothing in this record to
support a conclusion that entry is easy in the upstream delivered
gas market. For example, Intervenors argue that the merger may
reduce potential competition, and therefore entry, in the
delivered gas market by eliminating SDG&E as a potential "anchor
tenant" of a new pipeline entrant. Perhaps more important,
SoCalGas is the single, largest regulated gas distributor in
southern California. By virtue of its regulated franchise, it
controls the distribution and storage infrastructure in southern
California. Moreover, a competing distributor or bypass pipeline
would have to be approved by the California Commission. In the
Commission's view, this would not occur, if at all, in a time
frame which would effectively discourage the merged company from
raising competing generator's input costs.
c. Downstream Wholesale Electricity Market
i. Competitive Conditions and Effects of Imports
As discussed earlier, the Commission recognizes that a
broader definition of the relevant geographic market would include
imports from various regions outside southern California. However,
a precise definition of the geographic market is not possible on
this record because the Applicants did not prepare a delivered
price analysis. Nevertheless, in assessing the effect of the
merger on competition in the downstream wholesale power market,
the Commission has considered two cases, one with maximum imports
and one without any imports. We believe that the actual effect on
competition likely will be between these two extremes and note
that even under the "import" case generators served by SoCalGas
still represent a significant share of the market.
Presently, gas-fired steam and combined cycle generation
account for the preponderance of generation on SDG&E's system and
the systems of other southern California utilities. [FN48] As
such, this generation=particularly gas-fired steam generation =is
a major determinant of the market price for energy. The Commission
notes that under the proposed PX market arrangement, gas-fired
generation in southern California is more likely than not to set
the market price for spot energy in the PX for much of the year.
As suggested in our Merger Policy Statement, a reasonable measure
to evaluate conditions in energy markets is economic capacity,
that is, all capacity whose variable costs are no more than 5%
above the market price.
Under a bilateral market arrangement, wholesale power
customers' range of alternative economic suppliers in the southern
California geographic market is largely limited to energy from
generating capacity competitive with gas-fired steam capacity.
Included in this economic capacity would be capacity whose
variable cost is equal to or less than 5% above the cost of
gas-fired steam generation. The Commission's analysis shows that
almost 60% of generating capacity that can potentially supply
energy from economic capacity is served by SoCalGas. Generation
served by SoCalGas, therefore, has a significant presence in the
wholesale electricity market in southern California.
An indicator of the ability of wholesale power purchasers
to turn to capacity not served by SoCalGas would be a statistic
analogous to an HHI. Ideally, such a statistic would be calculated
on the basis of economic capacity served by SoCalGas and economic
capacity not served by SoCalGas. However, given the absence of a
delivered price analysis, we have relied upon installed gas- fired
capacity in our analysis. Assuming no imports, the southern
California
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wholesale electricity market would be characterized as "highly"
concentrated (i.e., a concentration statistic substantially above
1800). [FN49] This statistic indicates that before and after the
merger, wholesale power customers would have relatively few
alternatives within southern California to capacity served by
SoCalGas. Under these circumstances, higher delivered gas costs to
generators served by SoCalGas would likely result in higher
wholesale electricity prices.
Similarly, under a PX market arrangement, since gas-fired
steam generation is expected to set the market price and SoCalGas
controls gas deliveries to almost all such generation, there is
the potential for higher wholesale electricity prices.
Under a bilateral market arrangement, the only effective
discipline on higher wholesale electricity prices resulting from
the merger would come from energy from economic capacity not
served by SoCalGas. This energy could be imported from outside
southern California. Similarly, the only effective discipline on
wholesale electricity prices under a PX market arrangement would
come from economic capacity bidding into the PX from outside
southern California. In both the bilateral and PX cases,
transmission prices, simultaneous import limitations and
transmission constraints would all materially affect the amount of
capacity that could supply energy into southern California. If
this energy is not available at prices close to the market price
for energy in southern California, those suppliers could not
discipline a potential price increase brought about by the merged
company.
Even assuming maximum imports into southern California,
generation served by SoCalGas still accounts for over 30% of all
capacity in the market. Under this assumption, the relevant market
would be characterized as "moderately" concentrated (i.e.,
concentration statistic above 1000 and below 1800).
Based on the foregoing, the Commission believes that even
after accounting for imports into the relevant geographic market,
wholesale power customers would still be limited in their ability
to switch to suppliers with capacity not served by SoCalGas. As
such, the effect of the merger would be the potential increase in
wholesale electricity prices.
ii. Entry
As noted earlier, the Merger Policy Statement discusses the
role of entry in discouraging price increases in markets affected
by potential mergers. If entry into the downstream market were
timely, likely, and sufficient, it could effectively discourage
higher wholesale power prices resulting from the merger. However,
such entry does not appear to be likely in this case. The effect
of the proposed merger could be to discourage competitive entry
into the wholesale power market in southern California, since
higher delivered gas costs would make new entry in that market
difficult and unattractive. In particular, economic capacity,
i.e., gas-fired steam and combined cycle plants, could be
discouraged from entering the market. As aesult of these factors,
the Commission believes that the effect of the merger would be to
potentially increase wholesale electricity prices.
d. Net Effect of the Merger
On the whole, circumstances in the upstream delivered gas
and downstream wholesale electricity markets indicate that the
merged company could potentially raise input costs to competing
generators, therefore resulting in higher wholesale electric
prices. Under the
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circumstances of this case, the Commission believes that the
proportion of economic capacity (not including SDG&E) served by
SoCalGas is still high enough to effectively limit wholesale power
customers' alternatives to economic capacity not served by
SoCalGas.
e. Mitigation Remedies
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' 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' 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.
According to the Applicants, regulation over intrastate
pipelines by the California Commission combined with the
additional commitments made by the Applicants to the California
Commission provide sufficient safeguards to alleviate any vertical
market power concerns. For example, the Applicants have committed
to comply with the requirements of this Commission's Order No. 497
with respect to SoCalGas' sales of transportation in intrastate
gas markets. [FN50] The regulations promulgated under Order No.
497 [FN51] require that any interstate natural gas pipeline that
has gas marketing or brokering affiliates and that transports
[FN52] gas for others conform to a code of conduct that requires
non-discriminatory treatment of the same or similarly situated
persons, as set out in 18 C.F.R. s 161.3(a) through (k).
The Applicants also state that the California Public
Utilities Code prohibits public utilities from granting any
preference or advantage to any corporation or person or subjecting
any corporation or person to any prejudice or disadvantage, and
that the transportation tariffs for California gas utilities
prohibit "unduly discriminatory" transportation rates to any
particular transportation customer. [FN53] The Applicants also
state that SoCalGas has an electronic bulletin board, called
"GasSelect," and that SoCalGas would provide the type of posting
required by Order No. 497 if it provided any discount to SDG&E.
[FN54]
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<PAGE>
The Applicants also state that, in connection with any power
marketing affiliate of either SDG&E or SoCalGas, a standard of
conduct has been proposed to the California Commission which
provides as follows:
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 (sic) 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.
The Applicants state that this standard of conduct would
ensure that any power marketing affiliate of SoCalGas would not
receive confidential, market-sensitive information obtained by
SoCalGas by virtue of its position as a gas transporter, unless
such information is shared with unaffiliated power marketers. The
Applicants further state that this same restriction would apply to
any employee or group of employees employed by SDG&E, or any other
subsidiary of the merged entity, that engages in a merchant sales
function with respect to electricity. The Applicants add that
this would allow Enova and Pacific to consolidate functions such
as information systems in general and billing in particular, while
ensuring that any employees of SDG&E who are involved in the sale
or trading of power do not obtain access to information from
SoCalGas that could provide an advantage in
electricmarkets. [FN55]
We believe that the most direct and effective way to address
the potential that SoCalGas will unduly discriminate in favor of
downstream affiliates, and thereby put SDG&E's competitors at a
disadvantage, is through specific mitigation requirements that
would: preclude discriminatory conduct by SoCalGas; ensure
transparency of transactions involving sales and purchase of gas
transportation services; and require separation of SDG&E's
purchases of transportation service from SoCalGas for gas that
would be used for its electric generators. We discuss specific
mitigation requirements in detail below.
While this Commission has the authority under FPA section
203 to determine what remedies are necessary to mitigate market
power concerns and to condition our approval of a transaction on
those conditions being implemented, in this particular case
effectuation of most of the remedies discussed below is within the
jurisdiction of the California Commission. Specifically,
acceptance and enforcement of the Applicants' commitments to
non-discriminatory treatment by SoCalGas and transparency of
SoCalGas transactions are matters within the jurisdiction of the
California Commission. As a natural gas distribution company, as
well as a Hinshaw pipeline, SoCalGas falls within the regulatory
oversight of the California Commission, and matters relating to
the terms and conditions of SoCalGas' intrastate gas
transportation service must be addressed and enforced by that
commission. On the other hand, other remedies discussed below
(those imposed directly on the public utilities in the proposed
transaction, SDG&E and Enova Energy) are within this Commission's
jurisdiction to effectuate. [FN56]
We conclude that if the Applicants commit to the remedial
mechanisms discussed below, and if the California Commission in
its ongoing merger proceeding accepts those remedial mechanisms
discussed below that are within its jurisdiction, the proposed
transaction will be consistent with the public interest. We
therefore will approve the proposed disposition of facilities on
the condition that the following remedies are adopted. In the
interest of comity, we will defer to the California Commission in
specifying the terms by which remedies within its jurisdiction are
to be accomplished.
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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. [FN57] 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' GasSelect EBB 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' GasSelect EBB under the same terms and
conditions as SoCalGas' non-affiliated gas-fired generation
customers. Also, SoCalGas must publicize in advance on the
GasSelect EBB its planned use of pipeline capacity to fill
storage.
As discussed above, acceptance and enforcement by the
California Commission of remedies within its jurisdiction are of
paramount importance. We expect that the California Commission
will at a minimum adopt the mechanisms discussed above to preclude
SoCalGas from manipulating wholesale power markets through
discriminatory treatment of other competitors. [FN58] We direct
the Applicants to file proposed mitigation measures with us no
later than 30 days after the California Commission issues its
merger decision in Application 96- 10-038. If there is any
material deviation from the remedies described above, we will
determine if the deviations are acceptable. [FN59] We note that
the California Commission's current anticipated decision date is
March 1998. If this timetable is delayed, the Applicants should
inform us of the status of the California proceeding as soon as
possible, and we will at that time determine whether other action,
if any, is appropriate.
2. The Effect on Competition: Horizontal Market Power
The proposed merger would potentially eliminate an electric
generation competitor by consolidating generation owned and
operated by SDG&E with ownership interests in QFs held by
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Pacific. The Applicants contend that the consolidation of
generation would have no adverse impact on competition. The
application shows that change in concentration in the smallest
possible geographic market=southern California=resulting from the
consolidation of Pacific's QF generation and SDG&E's generation is
de minimis. [FN60] We agree, and note that no intervenor has
raised concerns to the contrary.
The proposed merger would also consolidate retail gas
service provided by SoCalGas and retail electricity service
provided by SDG&E in the southern part of Orange County,
California, where SoCalGas' and SDG&E's service territories
overlap. This could potentially eliminate a competitor to the
extent that gas and electricity compete in end-use energy
services. Several intervenors voice concern about this possible
effect of the proposed merger. We note that the California
Commission, which also has jurisdiction over this transaction, can
adequately address this issue and has not requested our assistance
in this regard. [FN61]
3. The Effect on Rates
The Merger Policy Statement explains that the protection of
wholesale ratepayers and transmission customers is the
Commission's primary concern regarding the effects of a section
203 proposal on rates. [FN62] As stated earlier, the Applicants
state that the proposed corporate realignment would have no
adverse effect on rates because neither SDG&E nor Enova Energy has
firm wholesale customers; instead, SDG&E's only wholesale sales
are economy energy sales and short-term sales of capacity. The
Applicants also state that SDG&E has no firm transmission
contracts for service through its system other than for short-term
as-available service and mutual assistance short-term back-up
transmission assignments. The Applicants state that any other
transmission commitments involve interchange contracts, Western
System Power Pool as- available commitments, or transmission under
SDG&E's open access tariff. In any event, the Applicants state
that SDG&E will hold its future wholesale and transmission
customers harmless from any increase in jurisdictional costs
arising out of the proposed transaction for at least five years
after the corporate realignment is consummated. The Applicants
also state that SDG&E would undertake the burden, in any
Commission rate case it files within five years after the
consummation of the corporate realignment, to show that its rates
are not higher than they otherwise would have been absent the
merger. The Applicants' hold harmless provision and commitment to
accept the burden of proof in any future related rate case should
adequately protect ratepayers from the recovery of merger-related
costs, particularly given the types of wholesale transactions in
which SDG&E engages.
Intervenors contend that the Applicants' plan to consolidate
the gas purchase portfolios of SoCalGas' sales customers and
SDG&E's customers would provide SoCalGas the opportunity to
"assign" higher priced gas supplies to SDG&E; the Applicants then
could pass these increases through to retail ratepayers,
collecting the increased profits and evading rate regulation.
Except as this issue affects competition in wholesale power
markets, which is being considered as discussed above, this issue
is squarely a retail ratemaking matter more appropriately
addressed by the California Commission. Therefore, we will not
pursue the issue further.
4. The Effect on Regulation
The Merger Policy Statement discusses the Commission's
concerns relating to (1)
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creation of a regulatory gap as a consequence of a corporate
realignment, or (2) shifts of regulatory authority between the
Commission and state commissions or the Securities and Exchange
Commission (SEC). [FN63] However, since it is anticipated that the
newly-formed holding company will be granted an exemption under
section 3(c) of PUHCA, the corporate realignment will not affect
the Commission's jurisdiction vis-a-vis the SEC. Also, the
California Commission has not raised concerns regarding impairment
of its regulatory authority and will be able to approve or
disapprove the merger. Therefore, regulatory authority would not
be impaired by virtue of the proposed disposition of facilities.
The Commission orders:
(A) SoCal Edison's complaint in Docket No. EL97-21-000 is
hereby dismissed as moot.
(B) The motion to consolidate filed by Public Power
Authority in Docket No. EC97-12-000 is denied.
(C) The Applicants' proposed disposition of facilities is
conditionally approved, as discussed in the body of this order.
FN1 16 U.S.C. s 824b (1994).
FN2 15 U.S.C. s 79c(a)(1) (1994).
FN3 Enova Energy, Inc., 76 FERC P 61,242 (1996).
FN4 Enova Corporation and Pacific Enterprises, 79 FERC P
61,107 (1997).
FN5 SoCal Edison raised various anticompetitive concerns in
its complaint that are repeated in its intervention in Docket No.
EC97-12-000, and, thus, are addressed in this proceeding.
FN6 The creation of Enova was approved by the Commission
two years ago, whereupon Enova became the holder of all of SDG&E's
common stock and SDG&E's common stockholders became the
stockholders of Enova. San Diego Gas & Electric Company, 70 FERC P
62,118 (1995).
FN7 76 FERC P 61,242 (1996).
FN8 As noted in the April 30 order, Pacific has another
subsidiary, Ensource, that was a power marketer authorized to sell
power at market-based rates. However, on December 6, 1996,
Ensource filed a notice of cancellation of its market-based rate
schedule, which was accepted for filing by order issued January
29, 1997. See Ensource, 78 FERC P 61,064 (1997).
FN9 The Agreement and Plan of Merger and Reorganization
submitted with the application does not refer to NewCo, but
instead refers to the new holding company as Mineral Energy
Company. NewCo Enova Sub and NewCo Pacific Sub are referred to as
G Mineral Energy Sub and B Mineral Energy Sub, respectively.
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FN10 62 Fed. Reg. 4993 (1997).
FN11 Power Pool states that its members are the Los Angeles
Department of Water and Power, and the Cities of Burbank,
Glendale, and Pasadena, California. Power Pool states that its
members own and operate gas-fired generation resources in the Los
Angeles Basin, and that SoCalGas is the sole provider of gas
transmission service to their facilities.
FN12 Public Power Authority states that it is a joint powers
agency under California law and a "municipality" as defined by
section 3(7) of the FPA. Public Power Authority's members are: the
Cities of Anaheim, Banning, Burbank, Colton, Glendale, Pasadena,
Riverside, and Vernon, California; the Los Angeles Department of
Water and Power; and the Imperial Irrigation District. Each of the
members is engaged in the generation, transmission, and
distribution of electric energy and provide electric service
tocustomers in California.
FN13 Imperial Irrigation, Kern River, Public Power
Authority, the Power Pool, SoCal Edison, and USGen.
FN14 For example, Vernon asserts that, if the corporate
realignment is approved, the merged entity would: (1) provide
natural gas transportation to 96% of the gas-fired, steam, or
combined cycle plants in southern California; (2) provide retail
or wholesale transportation service to 85% of the southern
California natural gas market; and (3) directly control 72% of all
gas storage capacity in southern California. Vernon asserts that
SoCalGas and SDG&E together purchase 39% of the California gas
commodity market (SoCalGas purchases 29%, while SDG&E purchases
10%).
FN15 See Pacific Gas and Electric Company, 77 FERC P 61,204
(1996) and 77 FERC P 61,265 (1996) for descriptions and
discussions of the California PX, which is one aspect of the
current restructuring of theelectric utility industry in
California. The related proceeding before this Commission is often
referred to as the WEPEX proceeding; WEPEX is an acronym for the
Western Power Exchange, which was established to implement the
California Commission's restructuring objectives.
FN16 Imperial Irrigation, Kern River, the Power Pool, San
Diego, and SoCal Edison.
FN17 SoCal Edison.
FN18 Imperial Irrigation, Kern River, Public Power
Authority, SoCal Edison, and Vernon.
FN19 Imperial Irrigation, the Power Pool, San Diego, SoCal
Edison, and Vernon.
FN20 Imperial Irrigation, the Power Pool, San Diego, SoCal
Edison, and Vernon.
FN21 57 Fed. Reg. 41,533 (1992).
FN22 49 Fed. Reg. 26,823 (1984).
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FN23 Imperial Irrigation, Public Power Authority, and SoCal
Edison.
FN24 Kern River, Public Power Authority, SoCal Edison, and
Vernon.
FN25 SoCal Edison and Vernon.
FN26 Imperial Irrigation and SoCal Edison.
FN27 Kern River and the Power Pool.
FN28 Imperial Irrigation, Kern River, the Power Pool, Public
Power Authority, San Diego, and Vernon.
FN29 Public Power Authority and SoCal Edison.
FN30 Power Pool and Public Power Authority.
FN31 For example, see Public Power Authority's motion to
intervene.
FN32 Public Power Authority.
FN33 SoCal Edison and Public Power Authority
FN34 Inquiry Into Alleged Anticompetitive Practices Related
to Marketing Affiliates of Interstate Pipelines, Order No. 497, 53
Fed. Reg. 22139 (1988), FERC Statutes and Regulations, Regulations
Preambles 1986-1990 P 30,820 (1988), order on rehearing, Order No.
497-A, 54 Fed. Reg. 52781 (1989), FERC Statutes and Regulations,
Regulations Preambles 1986-1990 P 30,868 (1989), order extending
sunset date, Order No. 497-B, 55 Fed. Reg. 53291 (1990), FERC
Statutes and Regulations, Regulations Preambles 1986-1990 P 30,908
(1990), order extending sunset date and amending final rule, Order
No. 497-C, 57 Fed. Reg. 9 (1992), FERC Statutes and RegulationsP
30,934 (1991), reh'g denied, 57 Fed. Reg. 5815, 58 FERC P
61,139(1992), aff'd in part and remanded in part, Tenneco Gas v.
Federal Energy Regulatory Commission, 969 F.2d 1187 (D.C. Cir.
1992), order on remand, Order No. 497-D, 57 Fed. Reg. 58978
(1992), FERC Statutes and Regulations P 30,958 (1992), order on
reh'g and extending sunset date, Order No. 497-E, 59 Fed. Reg. 243
(1994), FERC Statutes and Regulations P 30,987 (1994), order on
reh'g, Order No. 497-F, 59 Fed. Reg. 15336 (1994), 66 FERC P
61,347 (1994).
FN35 Under the "B" contract, any revenues from the PX in
excess of variable costs must be rebated back to the ISO as a
credit against availability charges. Under the contract "C", the
unit may not bid into thePX.
FN36 See Applicants' answer, appendix A, p. 1.
FN37 See Applicants' answer, appendix B, p. 6.
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FN38 See Applicants' answer, pp. 7-8.
FN39 Subsequent to the filing of the Applicants' answer, the
Commission issued an order in Docket No. RP97-284-000, finding
that SoCalGas has not violated the Commission's capacity release
regulations or policies. Southern California Edison Company v.
Southern California Gas Company, 79 FERC P 61,157 (1997).
FN40 18 C.F.R. s 385.214 (1996).
FN41 18 C.F.R. s 385.213(a)(2) (1996).
FN42 See Inquiry Concerning the Commission's Merger Policy
Under the Federal Power Act: Policy Statement, Order No. 592, 61
Fed. Reg. 68,595 (1996), FERC Statutes and Regulations P 31,044
(1996) (Merger Policy Statement).
FN43 Merger Policy Statement at p. 30,113 (footnote
omitted).
FN44 SoCalGas is an intrastate pipeline by virtue of the
Hinshaw provision in section 1(c) of the Natural Gas Act (NGA). A
Hinshaw pipeline is exempt from the provisions of the NGA and is
defined by section 1(c) of that act as:
any person engaged in or legally authorized to engage in the
transportation in interstate commerce or the sale in interstate
commerce for resale, of natural gas received by such person from
another person within or at the boundary of a State if all the
natural gas so received is ultimately consumed within such State,
or to any facilities used by such person for such transportation
or sale, provided that the rates and service of such person and
facilities be subject to regulation by a State commission.
15 U.S.C. s 717 (1994).
FNIn this case, we do not reach the question of whether the
Hinshaw exemption properly applies to SoCalGas.
FN45 The 1984 Guidelines, which are incorporated by
reference in the 1992 Horizontal Merger Guidelines discussed at
length in the Merger Policy Statement, describe four concerns
raised by vertical mergers and the corresponding basis upon which
DOJ would challenge a merger. Those four concerns are: elimination
of potential entrants, barriers to entry, facilitating collusion,
and evasion of rate regulation.As we discuss later, the first two
of these concerns can be restated as foreclosure/raising rivals
costs. The third and fourth concerns can be restated as increased
anticompetitive coordination and regulatory evasion, respectively.
See, e.g., Michael H. Riordan and Steven C. Salop, "Evaluating
Vertical Mergers: A Post- Chicago Approach," 63 Antitrust Law
Journal 513 (1995).
FN46 A related concern is denying or giving rivals limited
access to downstream customers.
FN47 Regulatory evasion can result from passing higher input
prices through to the retail
- 22 -
<PAGE>
customers of a regulated affiliate. In this case, the California
Commission has jurisdiction over both SoCalGas and over the
proposed transaction and therefore can address this issue.
FN48 According to San Diego, gas-fired capacity accounts for
68% of installed generating capacity of southern California
utilities.
FN49 See Prepared Testimony of John R. Morris on behalf of
the City of San Diego, exhibit No. <<< (JRM-3), Schedule 1.
Witness Morris' analysis overstates concentration because his
analysis: (1) includescertain peaking capacity that may not be
competitive; and (2) assumes that all utilities not served by
SoCalGas are one seller when that obviously is not the case.
However, correction for these deficiencies still results in an HHI
well over 1800.
FN50 See n.4.
FN51 See 18 C.F.R. Part 161 and s 250.16 (1996).
FN52 "Transportation . . . includes storage, exchange,
backhaul, displacement, or other methods of transportation." 18
C.F.R. s 161.2(e) (1996).
FN53 See Application for Approval and Authorization of
Merger, Vol. I, Prepared Direct Testimony ofJeffrey K. Hartman, p.
5.
FN54 We note that Order No. 497 and the regulations
promulgated thereunder address business practices between
interstate gas pipelines and their affiliated marketers or
brokers. Our concern in this case is how business is conducted
between SoCalGas and SDG&E, which is not a marketer or broker as
those terms are used in Order No. 497.
FN55 Application for Approval and Authorization of Merger,
Vol. I, Prepared Direct Testimony of JeffreyK. Hartman, pp. 7-9.
FN56 Specifically, the Commission has the authority to
impose requirements on the public utilities regarding the sharing
of market information between the public utilities and SoCalGas,
and the separation and transparency of SDG&E's and Enova Energy's
gas transportation purchases from SoCalGas.
FN57 See, e.g., Heartland Energy Services, Inc., 68 FERC P
61,223 at p. 62,063 (1994); Wholesale Power Services, Inc., 72
FERC P 61,284 at p. 62,227 (1995); USGen Power Services, L.P., 73
FERC P 61,302 at p. 61,845 (1995).
FN58 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.
FN59 Our concern would be over deviations that weaken the
remedial terms outlined above.
- 23 -
<PAGE>
FN60 The Applicants' analysis evaluates concentration under
a number of load conditions and shows that the largest HHI change
is 8 points. This is well under the DOJ Guideline's threshold for
concern for either moderately or highly concentrated markets.
FN61 See, e.g., Baltimore Gas and Electric Company and
Potomac Electric Power Company, 79 FERC P 61,027 at pp. 61,115-16
(1997); Merger Policy Statement at pp. 30,127-28.
FN62 Merger Policy Statement at p. 30,123.
FN63 Merger Policy Statement at pp. 30,124-25.
- 24 -
SUMMARY OF TESTIMONY RECEIVED BY CPUC TO DATE
WITNESS(ES)
ON BEHALF OF
GENERAL SUBJECT MATTER
S.L. Baum and R.D. Farman
Enova/Pacific
Corporate policy issues related to merger
W.L. Hieronymus
Enova/Pacific
Market power; impacts of the merger on the competitiveness of
electricity markets and retail gas markets.
T.J. Flaherty, F.H. Ault, and D.L. Reed
Enova/Pacific
Merger synergies
F.H. Ault and R. Todaro
Enova/Pacific
Allocation of merger synergies
F.H. Ault and R. Todaro
Enova/Pacific
Affiliate relationships
D.L. Reed, R. Todaro, and F.H. Ault
Enova/Pacific
Fairness to stakeholders
D.L. Reed, R. Todaro, and F.H. Ault (supplemental testimony)
Enova/Pacific
Effect of CPUC Performance-Based Ratemaking decision
S.L. Baum, R.D. Farman, and J.J. Leitzinger (supplemental testimony)
Enova/Pacific
Effect of FERC order conditionally approving merger; effect of proposed
acquisition of AIG Trading Corp.
F.H. Ault, D.L. Reed, R. Todaro, and T.J. Flaherty (supplemental
testimony)
Enova/Pacific
Impact of affiliate transaction rules and FERC conditions on merger
approval
T.J. Flaherty, D.L. Reed, and R. Todaro (rebuttal testimony)
1
<PAGE>
Enova/Pacific
Merger synergies
F.H. Ault and R. Todaro (rebuttal testimony)
Enova/Pacific
Affiliate relationship
D.L. Reed and F.H. Ault (rebuttal testimony)
Enova/Pacific
Fairness to stakeholders
W.H. Hieronymus, J.J. Leitzinger, L.M. Stewart, and D.S. Penney
(rebuttal testimony)
Enova/Pacific
Market power
Office of Ratepayer Advocates
Office of Ratepayer Advocates
Affiliate relationship; cost allocation; market power
G.T.C. Taylor
Imperial Irrigation District
Market power; effect on competition in electric and gas markets.
C.E. Yap
Southern California Utility Power Pool
Market power; effect on competition in electric and gas markets.
K. Harper
Southern California Public Power Authority
Affiliate relationship
R. Sinclair
Southern California Public Power Authority
Market power; effect on competition in electric and gas markets.
R.T. Beach
City of Vernon
Market power; effect on competition in electric and gas markets.
C.J. Garner
City of Long Beach
Affiliate relationship; market power
T.F. Daniels
Watson Cogeneration
2
<PAGE>
Effect of SoCalGas option to purchase Mojave Pipeline
P.J. Muller
California Cogeneration Council & Watson Cogeneration
Market power
L. Larsen and C. Wadlington
Kern River Gas Transmission Co.
Effect of SDG&E option to acquire Kern River
C. Roach
Kern River Gas Transmission Co.
Market power; effect on competition in electric and gas markets;
affiliate relationship
W.B. Marcus
Toward Utility Rate Normalization/Utility Consumer Action Network
("TURN/UCAN")
Affiliate relationship; cost-sharing issues
M.P. Florio
TURN/UCAN
Market power
G. Shilberg
TURN/UCAN
Customer service issues
M. Shames
UCAN
Customer service, community impact, and allocation of cost savings
G. Rodriguez
Latino Issues Forum
Customer service issues
J. Gamboa
Greenlining Institute
Labor issues
S. Carter
Natural Resources Defense Council
Effect on environment and public purpose programs
P. Carpenter
Southern California Edison Company ("SCE")
Vertical market power; affiliate relationship
3
<PAGE>
R. Graves
SCE
Vertical market power; effect on competition in electric and gas markets
J. Kelly
SCE
Affiliate relationship
Office of Ratepayer Advocates (rebuttal testimony)
Office of Ratepayer Advocates (ORA)
Market power; affiliate relationship
C. Roach (rebuttal testimony)
Kern River Gas Transmission Co.
Market power; affiliate relationship
C.E. Yap (rebuttal testimony)
Southern California Utility Power Pool
Market power
G.T.C. Taylor (rebuttal testimony)
Imperial Irrigation District
Market power
M.P. Florio (rebuttal testimony)
TURN/UCAN
Market power
W.B. Marcus (rebuttal testimony)
TURN/UCAN
Impact of SoCalGas Performance-Based Ratemaking decision
M. Shames (rebuttal testimony)
UCAN
Affiliate transaction rules
G. Rodriguez (rebuttal testimony)
Latino Issues Forum
Customer service issues
P. Carpenter (rebuttal testimony)
SCE
Market power
4
<Page)
S. Montovano
Enron Capital & Trade Resources
Market power; affiliate relationship
5
November 1997 ATTORNEY GENERAL'S OPINION
November 20, 1997
Requested by: PUBLIC UTILITIES COMMISSION
DANIEL E. LUNGREN, Attorney General
Wayne Smith, Chief Deputy Attorney General
Roderick E. Walston, Chief Assistant Attorney General
Thomas Greene, Assistant Attorney General
Kathleen Foote, Supervising Deputy Attorney General
Lindsay Bower, Deputy Attorney General
THE PUBLIC UTILITIES COMMISSION has requested an advisory opinion,
pursuant to Public Utilities Code section 854, on the competitive
effects of the proposed merger between Pacific Enterprises and Enova
Corporation. The Commission has also asked for an opinion on mitigation
measures that could be adopted to avoid any adverse competitive effects
that do result.
CONCLUSIONS
(1) The proposed acquisition should not by itself adversely,
affect competition in the markets for interstate gas or
wholesale electricity.
(2) The merger may eliminate the disciplining effect of San
Diego Gas & Electric as a potential competitor in the
partially regulated intrastate gas transmission market. We
recommend that the Commission consider requiring the merged
entity to auction offsetting volumes of transportation
rights within that system.
<PAGE>
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
____________________________________________________
In the Matter of the Joint Application of Pacific | A. 96-10-038
Enova Corporation, Mineral Energy Company, B |
Mineral Energy Sub and G Mineral Energy Sub | Opinion of
For Approval Of A Plan Of Merger Of Pacific | the Attorney
Enterprises And Enova Corporation With And Into | General on
B Mineral Energy Sub ("Newco Pacific Sub") And | Competitive
G Mineral Energy Sub ("Newco Enova Sub"), The | Effects of
Wholly-Owned Subsidiaries Of A Newly Created | Proposed
Holding Company, Mineral Energy Company. | Merger
| Between
| Pacific Enter-
| prises and
____________________________________________________| Enova Corp.
DANIEL E. LUNGREN,
Attorney General of the
State of California
WAYNE R. SMITH,
Special Assistant Attorney General
RODERICK E. WALSTON,
Chief Assistant Attorney General
THOMAS GREENE,
Assistant Attorney General
KATHLEEN E. FOOTE
Supervising Deputy Attorney General
LINDSAY BOWER
Deputy Attorney General
50 Fremont Street, Suite 300
San Francisco, California 94105-2239
415) 356-6377
Attorneys for the State of California
<PAGE>
OUTLINE OF ANALYSIS
INTRODUCTION
I. ROCEEDINGS AND THE NATURE OF THIS OPINION
A. Prior Proceedings
B. This Advisory Opinion
II. THE APPLICANTS AND THE INTRASTATE GAS TRANSPORTATION AND
ELECTRICITY SERVICES THEY PROVIDE
A. The Purpose of this Merger
B. SDG&E Market Power Mitigation under Electric Restructuring
C. SoCalGas Intrastate Gas Transmission Services
1. The SoCalGas Intrastate System
2. Transportation "Unbundling" and System Bypass
III. INTERSTATE GAS AND WHOLESALE ELECTRICITY MARKETS AT THE CALIFORNIA
BORDER
A. Federal Deregulation and the Interstate Gas Market
B. Federal Wholesale Electricity Deregulation
C. The PX and the Western United States Wholesale Market
IV. THE RELEVANT MARKETS
A. The Relevant Interstate Gas Market
B. The Relevant Wholesale Electricity Market
1. Alleged "Swing Capacity" Markets
2. The Temporal Dimension
C. The Relevant Intrastate Gas Transportation Market
V. THE COMPETITIVE EFFECTS
A. The Vertical Integration of SoCalGas Intrastate Gas
Transmission and SDG&E Wholesale Electricity Operations
1. The Intervenors' Vertical Integration Models
2. Futures Markets
3. The Kern River and Mojave Pipeline Purchase Options
4. The Applicants' "Remedial Measures"
<PAGE>
B. Horizontal Effects in the "Gas Procurement" and Retail Gas
Markets
C. Potential Competition for Intrastate Gas Transportation and
Electricity Retail Services
1. The Perceived Potential Competition Doctrine
2. The Retail Electric Services Market
VI. RETENTION OF JURISDICTION
VII. CONCLUSION
<PAGE>
INTRODUCTION
The proposed merger of Pacific Enterprises and Enova Corporation is
a response to the mandatory restructuring of the electric industry which
will begin on January 1, 1998. Through their subsidiaries, Pacific is
the leading southern California supplier of intrastate gas transmission
services, Enova is an electric distributor and a relatively minor
participant in the wholesale electricity market, and both firms
distribute gas within their respective service areas. As regulated
utilities doing substantial business within this state, the parties have
submitted their application under Public Utility Code section 854. This
memorandum responds to a Commission request for an opinion on the
competitive effects of the transaction.
Challenges to the merger have primarily focused upon alleged
effects in the markets for wholesale electricity, interstate gas and
intrastate gas transmission. Through Southern California Gas Company
(SoCalGas), Pacific provides gas transmission services to many of the
gas-fired generation plants within southern California, including plants
now owned by San Diego Gas and Electric (SDG&E) and Southern California
Edison (Edison). Edison and others contend that the merged company will
"leverage" its position in the gas transmission market to manipulate the
price of electricity sold by these plants in the wholesale market.
Intervenors also allege that the applicants will unfairly benefit in
financial markets and that, by exercising options to purchase competing
intrastate facilities, their alleged ability to manipulate electricity
prices will be enhanced in the future.
We conclude that this merger will not adversely affect competition
within either the wholesale electricity or interstate gas markets.
Because gas-fired plants now owned by SDG&E will be subject to
comprehensive price regulation, the merged entity will lack any
incentive (or, usually, the ability) to manipulate 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 -- shows that
the wholesale electricity market connects California with numerous out-
of-state suppliers over a transmission system that has never reached
capacity. These 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.
We also conclude 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, we recommend
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, we also
recommend that the Commission retain limited jurisdiction over this
merger for the purpose or reexamining the
1
<PAGE>
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.
I. PRIOR PROCEEDINGS AND THE NATURE OF THIS OPINION
A. Prior Proceedings
This merger would be completed by combining Enova and Pacific into
NewCo, a holding company created for the purpose of consummating this
transaction. into Enova, with Enova as the surviving corporation.
Likewise, NewCo Pacific Sub would merge into Pacific with Pacific as the
surviving corporation. Enova and Pacific would be wholly-owned NewCo
subsidiaries. Enova, Pacific, SDG&E, and SoCalGas would operate
separately and under their existing names.
On June 25, 1997, the Federal Energy Regulatory Commission (FERC)
conditionally approved the merger. FN / In general, the conditions
imposed by FERC would require SoCalGas to treat SDG&E and other
affiliates "in the same way pipelines treat their gas' marketing
affiliates." FN / The applicants subsequently incorporated those
conditions, along with other proposed restrictions, within their merger
application. FN /
B. This Advisory Opinion
This is the fifth Opinion letter submitted by this office under
the 1989 amendments to Section 854. FN / Public Utility Code section
854 refers to the opinion as advisory. FN / Consequently this document
does not control the PUC's finding under section 854, subdivision
(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).
II. THE APPLICANTS AND THE INTRASTATE GAS TRANSPORTATION AND
ELECTRICITY SERVICES THEY PROVIDE
Pacific Enterprises and Enova Corporation currently compete on a
very limited basis. SoCalGas purchases gas in the interstate market,
which it distributes to its 4.7 million residential and other "core"
customers In southern and central California. Core customers include
residential and commercial customers without alternate fuel capability,
whereas "non-core" customers are large commercial and Industrial
consumers that can buy gas from different sources. SoCalGas is the
leading supplier of intrastate gas transmission and gas storage services
for both "core" and "noncore" customers within southern California.
Pacific Enterprises also sold electricity in the wholesale market
through QF facilities, all of which were recently divested. FN / In
1996, Pacific generated revenues of $1,613 million from its gas
distribution operations and $778 million from intrastate gas
transportation services provided to commercial/industrial and gas-fired
generation
<PAGE>
2
plants.
market, FN / sells electricity to 1.2 million retail customers in San
Diego and southern Orange Counties (including parts of the SoCaIcas
service area). SDG&E also purchases gas in the interstate market, FN /
which it distributes within its separate service areas." FN / SDG&E
provides no gas transmission services outside of San Diego County."
FN / In addition, an affiliate of Enova Corporation, Enova Energy,
conducts extensive wholesale and retail energy marketing activities
throughout California. In 1996, Enova generated revenues of $1,591 and
$348 million from its electricity and gas distribution operations,
respectively.
Applicants have formed a joint venture, Energy Pacific, to market
gas, power and a "broad range of value-added energy management products
and services." FN / The applicants also recently purchased AIG
Trading, a natural gas and electricity marketer and a trader in
financial markets for electricity and gas contracts. FN / Both of
those companies are actively section discusses intrastate gas
transmission services supplied by SoCalGas and SDG&E purchases and sales
in the restructured electric industry. Interstate gas and services are
discussed in Section III.
A. The Purpose of the Merger
The applicants claim that their merger will produce a firm with the
necessary breadth and financial strength to compete with Edison, PG&E
and out-of-state suppliers in the restructured electric industry
mandated by AB 1890. As a result of that restructuring program, SDG&E
and other California electric utilities will lose their exclusive
"franchises" on January 1, 1998. The applicants contend that the merger
will provide Enova, which is approximately one-fifth the size of Edison
and PG&E," FN / with "access to adequate quantities of capital on
favorable terms." The parties also believe that the merged company will
achieve certain efficiencies s and will respond more effectively to
customer demand or broader and more cost effective energy services.
B. SDG&E Market Power Mitigation under Electric Restructuring
Under industry restructuring, two separate central authorities, the
Power Exchange (PX) and the Independent Service Operator (ISO), will
coordinate all transactions between SDG&E and other California
utilities. FN / SDG&E currently purchases a majority of the
electricity it sells to its retail customers. In 1995, for example,
SDG&E obtained 61 percent of its power requirements from short-term
Western States Coordinating Council (WSCC) purchases, 22 percent from
fossil generation plants--including its own 1,973 MW capacity plants--
located within the San Diego Basin, FN / and the remaining 17 percent
from the San Onofre Nuclear Generating Station (SONGS). FN / In 1996,
the peak load for the SDG&E system was 3,299 MW. FN /
During a five year transition period beginning January 1, 1998,
SDG&E and other investor owned utilities (IOUs) must purchase and sell
all of their power through the PX, which will
3
<PAGE>
establish a single clearing price for all hourly transactions. FN /
Participating distribution companies and end users will submit "demand
side" bids to the PX. FN / Generation plants and marketers will
simultaneously submit advance supply bids. FN / The total capacity of
WSCC members, including capacity divested from Edison and PG&E, FN /
which can bid into the PX exceeds 150,000 MW. FN / From the resulting
demand and supply schedules, the PX will establish FN / the market
"clearing price" governing all purchases and included sales. FN /
Power produced by "must-take" and "must-run" resources will be
priced separately. The output of must-run units -- the fossil
generating plants used by the ISO to maintain system integrity FN / --
will be sold at their variable operating costs. FN /The ISO Governing
Board "has chosen all of SDG&E's units for Must-Run status." FN /
Must-take resources, which include SONGS and other nuclear plants,
qualifying facilities (QFs) and pre-existing power contracts, FN /
provide more than half of the electricity requirements of the California
IOUs. FN / A "performance incentive mechanism . . . will isolate SONGS
revenue received by SDG&E from the PX price." FN / Other nuclear power
output prices will be regulated by the PUC, and existing contracts will
determine the price of purchased power and QF output.
To preclude the exercise of any possible market power, SDG&E will
bid the output of its gas-fired and other plants into the PX under ISO
"Agreement B" FN / during periods when those plants are not operated on
a must-run basis. That agreement applies separate payment provisions to
the two periods. As noted above, SDG&E will recover its variable costs
during must-run periods. At other times, Agreement B requires the
operator to return to the ISO "90 percent of any revenues earned in
excess of the running costs." FN / The remaining ten percent will
apparently be applied to SDG&E stranded costs through the competitive
transition charge (CTC) mechanism. FN / On October 30, 1997, FERC
concluded that this arrangement "adequately mitigate[s] [SDG&E's]
generation market power for PX sales of energy." FN /
In conjunction with the PX, the ISO will coordinate intrastate
power flows and provide open access to the California transmission grid.
FN / On January 1, 1998, all participants will transfer operational
control of their transmission facilities to the ISO. FN / The state
will initially be divided into "congestion zones" for northern and
southern California, within each of which little or no congestion is
expected. Users within the zones will pay a single transmission access
charge based upon the revenue requirements of the owners of the
transmission facilities. FN / A bidding process, similar to that used
by the PX, will establish usage charges for entities which transmit
power over congested paths through or out of the ISO grid. FN /
C. SoCalGas Intrastate Gas Transmission Services
SoCalGas carries gas to its "core" and "noncore" customers from
delivery points for interstate pipelines or their intrastate extensions.
When it created these customer
4
<PAGE>
classifications in 1986, the PUC required SoCalGas to offer
"transportation only" services to its noncore customers, including
generation plants owned by some of the intervenors in this proceeding.
Since 1986, the ability of noncore customers to choose among gas
producers and transportation services has been significantly expanded.
1. The SoCalGas Intrastate System
Five interstate pipelines carry natural gas to California: the
Transwestern Pipeline Company ("Transwestern"); the El Paso Natural Gas
Company ("El Paso"); the Pacific Gas Transmission Company ("PGT"), a
PG&E subsidiary; the Kern River Transmission Company, ("Kern River");
and the Mojave Pipeline Company ("Mojave"). At the Arizona-California
border, SoCalGas receives gas from the Transwestern line at North
Needles and from the El Paso line at Topock and Blythe. FN / In the
northern part of its service area, SoCalGas receives gas from PG&E at
Kern River Station and Pisgah, FN / and from the Kern River and Mojave
lines at Wheeler Ridge and Hector Road. FN /The SoCalGas system is
capable of receiving approximately 3.5 Bcf/d at these connection points.
FN /
The SoCalGas Acquisition Group purchases about 1000 MMcf/d, which
is ultimately transported to core customers. FN / SoCalGas noncore
transportation customers include Edison, members of SCUPP, SDG&E, the
City of Long Beach, and various large commercial and industrial
customers. FN / SoCalGas supplies 42 gas-fired generation plants,
including plants owned by SDG&E, Edison, Imperial Irrigation District
(IID) and SCUPP members. FN / These plants have a total generating
capacity of 15.837 MW. FN / SoCalGas is the only intrastate gas
pipeline to which SCUPP members can feasibly connect. FN /
To coordinate deliveries to these customers and to preserve "system
integrity." FN /SoCalGas calculates in advance of "flow day" FN / a
system "window" from the difference between estimated overall next-day
demand FN / and local FN / California gas production. FN / This
"take away" capacity figure is then adjusted by anticipated injection or
withdrawal volumes FN / for SoCalGas storage fields, FN / which
according to Edison "are used to satisfy the majority -- approximately
57 per cent -- of peak day demand." FN / Windows are also established
at each of the individual receipt points. FN /SoCalGas uses a variety
of procedures, including "custody cut" FN / and Rule No. 30
restrictions, FN / to achieve system balance when demand "nominations"
for core and noncore customers exceed system or individual receipt point
windows. FN /
2. Transportation "Unbundling" and System Bypass
When the PUC "unbundled" transportation services in 1986, noncore
customers were able to directly purchase commodity from wellhead
producers at competitive prices and to make their own arrangements for
the transport of that gas over interstate pipelines. In subsequent
years, the Commission has also permitted the creation of a limited
secondary market for intrastate
5
<PAGE>
transportation, even though it still prohibits "brokering on the
intrastate system. FN / The GasSelect electronic bulletin board, "an
interactive same-time FN / reservation and information system," FN /
provides information within this secondary market about intrastate
transportation transactions between SoCalGas and its affiliates. FN /
Bypass opportunities for noncore customers have also been expanded.
The Kern River and Mojave pipelines responded to these opportunities by
extending their interstate systems across the California border into the
SoCalGas service territory. FN / SoCalGas withdrew its initial
opposition under 1989 agreements providing it with options to purchase
in the year 2012 the California extensions of those two lines. FN /
Since their completion in 1992, both systems have delivered gas to
Enhanced Oil Recovery (EOR) and related cogeneration loads, and "to
SoCalGas and PG&E for redelivery to other industrial and commercial
loads." FN /
This competition has induced SoCalGas to "provide discounted FN /
transportation rates and associated cost saving to numerous customers
[perhaps including SDG&E FN /] on its system." FN / SoCalGas can
provide such discounted service to noncore customers without obtaining
prior CPUC approval. SoCalGas estimates that, since 1992, it has lost
transportation volumes of 400 million cubic feet per day to competing
gas pipelines. FN / SoCalGas also claims that competition from out-of-
state electric generation plants ("bypass by wire") has reduced the
aggregate load of California gas-fired facilities by an additional 275
million cubic feet per day. FN /
Along with federal deregulation efforts, these changes left
SoCalGas and other utilities with contracts for interstate pipeline
capacity that exceeded their market requirements. Accordingly, SoCalGas
has since 1992 reduced its firm capacity on the El Paso pipeline from
1750 MMcf/d to 1150 MMcf/d and from 750 MMcf/d to 300 MMcf/d on the
Transwestern system. FN /To mitigate the resulting losses, the PUC has
required customers to pay SoCalGas an ITCS (Interstate Transportation
Cost Surcharge) FN / to help recover certain fixed capacity costs.
FN /
III. INTERSTATE GAS AND WHOLESALE ELECTRICITY MARKETS AT THE
CALIFORNIA BORDER
SoCalGas and California generation plants purchase the majority of
their gas supplies from four producing basins in the western United
States and Canada. FN /Likewise, SDG&E purchases the majority of its
electricity supplies from western United States and Canadian generation
plants.
As a result of federal deregulatory efforts, these western United
States gas and electricity markets are fully competitive. Both
industries consist of three vertically-related stages: production,
transmission, and distribution. FN / Production and interstate
transmission services within both of those markets are highly integrated
at the California border. Moreover, California
6
<PAGE>
wholesale electricity transactions, which SDG&E and other utilities now
make throughout the western United States, will remain integrated with
the interstate market after the January 1, 1998 restructuring.
A. Federal Deregulation and the Interstate Gas Market
Federal deregulation of the gas market has created a network of
transmission suppliers connecting purchasers at the wholesale level with
middlemen and well operators at the production level. Prior to these
efforts, each interstate "pipeline would purchase natural gas from
producers, transport it largely along their own proprietary pipeline
system, and resell the rebundled product to local distribution companies
(LDCs) and other large customers." This institutional structure meant
that "each producer could sell gas to a limited number of buyers" and
that "LDCs and large end users had limited options in terms of the
number of pipeline companies from which they could purchase gas." FN /
As a result of FERC's deregulatory policies, "an active and viable spot
market has developed for gas." FN /
FERC transformed the gas industry by providing open access to
interstate pipelines, removing all controls over the wellhead price of
natural gas, FN / and establishing secondary markets for storage and
pipeline capacity. FN / Pipelines now compete to provide
transportation services with each other and with middlemen and with
other owners of capacity rights. Wellhead deregulation has
simultaneously generated competition between producers in different
basins. FN / Because end users attempt to minimize their "delivered
prices," FN / competitive forces have also linked the production and
transmission markets.
FERC's open access policies, instituted in Orders 436 FN / and
636, required that interstate pipelines separate gas sales from
transportation services, FN / allowing users to enter into direct
agreements with producers at the wellhead and arrange transportation in
a separate transaction. Orders 436 and 636 also created a "secondary
transportation market" for natural gas FN / by allowing "holders of
unutilized firm capacity [to resell] them in competition with any
capacity offered directly by the pipeline." FN / Previously, shippers
were only able to purchase capacity rights directly from pipelines.
FN / Under Order 636, shippers who wish to sell (i.e. "release") their
firm capacity rights must first offer FN / those rights on the
pipeline's electronic bulletin boards ("EBB") FN /, which carry
"information about available and consummated capacity release
transactions." FN /
These policies have allowed producers in Canada, the Rocky
Mountains, the San Juan and Permian Basins, as well as other regions to
compete for sales throughout California. The five pipelines which
deliver this gas have an aggregate capacity of 7,130 MMcf per day. FN /
The 3.5 Bcf/d El Paso Natural Gas Company and the 1.1 Bcf/d
Transwestern Pipeline Company lines are the primary links between the
southern California border and producers in the San Juan and Permian
basins. FN / Pacific Gas Transmission Company ("PGT"), a PG&E
subsidiary, transport gas from Canada to the California border on its
own 1.89 Bcf/d pipeline.
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Coupled with downstream pipeline system operated by SoCalGas and SDG&E,
PG&E can serve end users in most of California. FN / As noted in
Section II, the 770 MMcf/d Kern River line, which originates in the
Rocky Mountain Basin, and the 400 MMcf/d Mojave pipelines began
commercial operations in 1992.
In this deregulated interstate market, both purchasers and
suppliers have various alternatives as they seek to minimize the overall
cost of purchasing, transporting and storing gas. FN / Thus, many EOR
customers, who previously transported gas from Southwest fields over the
El Paso or Transwestern lines, substituted when they found it more
economical to transport Rocky Mountain gas over the Kern River or Mojave
lines. FN / In other instances, customers have substituted by
transporting over the same pipeline to California gas purchased in
entirely different basins. FN / Customers committed to a particular
supply source can also substitute between firm contracts and capacity
released in the secondary market. FN / Commodity and transportation
markets are also linked, FN / as producers in the San Juan Basin
demonstrated between November 1990 and April 1992 and again between
March 1995 and December 1996 by reducing commodity prices to offset the
temporarily increased cost of transporting gas over the constrained El
Paso line. FN /
B. Federal Wholesale Electricity Deregulation
Federal deregulation has had similar effects on wholesale
electricity prices at California delivery points. Congress initiated
deregulation of the electricity industry by first allowing independent
power producers and then utility affiliates to offer wholesale
electricity at "market-based prices." FN / Through Order 888 and
earlier mandates, FN / FERC simultaneously encouraged open access and
other "wheeling" transactions between non-contiguous buyers and sellers.
FN / By 1993, the "wholesale sector of the U.S. electricity industry
[had] been transformed from an industry dominated by ineffectively
regulated inefficient monopolists to an industry that is increasingly
dominated by robust competition." FN /
Edison, SDG&E and PG&E actively participate in one of the most
integrated of these wholesale electricity markets, the WSCC, which
includes "fifteen states in the western United States and part of
Canada." FN / The WSCC "is a highly complex network that
interconnects the entire western United States from Canada to Mexico and
east as far as Montana, Utah, and New Mexico." FN / WSCC members
include Bonneville Power & Light, British Columbia Hydro, Los Angeles
DWP, SMUD, and the Salt River Project. The aggregate capacity of WSCC
members, which arrange wholesale electricity transactions through the
Western States Power Pool ("WSPP") or through separate bilateral
transactions, FN / exceeds 150,000 MW. FN /
As a result of industry deregulation, suppliers can now sell to any
purchaser on the grid. FN / In fact, the availability of displacement
contracts and the physics of electricity transmission has rendered
irrelevant transmission constraints between any two points within the
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network. FN / The existence of "loop flows," FN / in particular,
means the power in a network "moves across many parallel lines in often
circuitous routes." FN / Likewise, suppliers facing transmission
constraints can indirectly meet their contractual obligations by
entering into offsetting displacement contracts with sellers located on
unconstrained links to the delivery point. FN / Accordingly, sellers
must now compete for any sale with utility affiliates, independent power
producers and power marketers.
The resulting competition has dramatically increased the
integration and efficiency of the wholesale electricity market. The
WSCC, in particular, had actually become a highly integrated market even
before FERC issued Order 888. FN / Using data from 1994-1996
transactions, DeVany and Walls have shown that the implicit delivered
price of wholesale electricity is identical throughout the western
United States during most hours of the day. FN / The market is so
highly integrated, in fact, that arbitrage opportunities are virtually
nonexistent between supply points during both "peak" and "off-peak"
hours. Thus, De Vany and Walls found that the California-Oregon Border
("COB"), Northern California, Palo Verde and Southern California were
cointegrated FN / with all ten of the other major WSCC delivery points
examined during off-peak hours; and with 9, 9, 10, and 9 of the other 10
delivery points, respectively, during peak hours. Order 888 has
undoubtedly strengthened these results. FN /
C. The PX and the Western United States Wholesale Market
ISO and PX rules will allow out-of-state utilities to bid into the
PX. FN / Those out-of-state suppliers will compete for sales of
wholesale electricity sold through the Power Exchange, and their
participation will equalize prices between the Exchange and the larger
market. Any differences between the Power Exchange 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. FN /
As noted above, loop flows maintain system viability when
constraints arise over individual transmission paths. The "contract
path" between a generating plant and a customer is a "fiction," which
"may and often does diverge" from the actual flow of power. FN /
Thus, the physics of electrical networks would allow southern California
customers to withdraw from the WSCC transmission grid power
simultaneously generated by BPA, even if a link in the most direct
transmission route between the two parties (e.g., Path 15) were at
capacity. For that reason, the precise capacity of any single link
between California and other WSCC members is not relevant to this
proceeding. FN /
Price data -- which provides the best measure of market performance
- -- confirms the implications of engineering data which show that
California has never been isolated from the rest of the WSCC. FN /
During off-peak hours, the implicit "shadow" price for transmitting
electricity between the four major California delivery points at off-
peak hours is virtually zero,` FN / reflecting the system's low
variable supply costs. Implicit peak hour transmission rates
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are higher, but wholesale electricity prices at the four delivery points
during those times remain cointegrated within arbitrage bounds. FN /
These data are inconsistent with the fragmented transmission system and
isolated wholesale markets alleged by some intervenors.
IV. THE RELEVANT MARKETS
The traditional antitrust model assesses the competitive effects of
a merger within a "relevant market," which generally exhibits both
product and geographic dimensions. The relevant product refers to the
"horizontal" range of products or services that are or could be easily
be made relatively interchangeable, so that pricing decisions by one
firm are influenced by the range of alternative supplies available to
the purchaser. The substitutes comprising the product market can be
differentiated, at least to some extent. Thus, local telephone calls
within the same exchange between A and B and between C and D are not
identical services, but they are still in the same product market
because they are such close substitutes.
The relevant product also has a vertical dimension. In most
antitrust cases, there is a "range of possible markets of varying
breadth." FN / In theory, the horizontal and vertical dimensions of
the relevant market are "immaterial." FN / In fact, however,
empirical limitations require a "noticeable 'gap in the chain'" of
substitutes and complements. FN / For example, it would usually be
misleading to define separate product markets for left and right shoes
or, because they are so strongly linked, for ski boots and ski bindings.
FN /More generally, the relevant product is defined by including the
good which is immediately in question along with all other substitutes
and complements which significantly affect the ability of the supplier
to raise price above marginal cost.
Similar considerations govern the delineation of the relevant
geographic market. The relevant geographic market is defined as the
area in which sellers compete and in which buyers can practicably turn
for supply. FN /In any market, including interstate gas or wholesale
electricity networks, the relevant geographic market will include all
supplies whose prices remain closely linked, after transportation and
other transaction costs are accounted for. Thus, distant seller A and
local Seller B are in the same market if the price at B equals the price
at A plus the cost of transportation between two points. More
generally, two locations are in the same market if the differential
between their (possibly independently varying) prices remains "less than
the potential wedge created by arbitrage costs." FN /Accordingly
"[p]rice relationships are clearly the best single guide to geographic
market definition." FN /
A. The Relevant Interstate Gas Market
For purposes of analyzing this merger, a relevant market can be
defined as gas delivered at interstate receipt points by pipelines from
the San Juan Basin, the Permian Basin, and basins in the Rocky Mountains
and Canada. FN / In a gas network, the ability of a customer (like
SoCalGas) to deviate rates from competitive levels is determined by
conditions at the
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wellhead or the cost of transmission over a single line. Prices are
inextricably linked between basins, between pipelines, between firm and
interruptible capacity on each line, FN / and across these various
service levels. FN / The most limited product market providing a
"gap" in this "chain" of complements is delivered interstate gas.
The geographical extent of this market includes at least deliveries
from the four basin area. FN / In 1995, total average production by
these basins was 24,000 MMcf/d. FN / Estimated peak day supplies to
California are 3,536 MMcf/d. FN / Because gas deliveries throughout
the network are close substitutes, after transportation is accounted
for, the geographic market is broader than gas deliveries to southern
California customers. FN / Similarly, the relevant product and
geographic market is broader than capacity rights on the El Paso line
between the San Juan basin and the California border. FN /
Competition within this market is intense. The ability of a firm
to raise prices above competitive levels is "commonly" shown with
circumstantial evidence of industry concentration, FN / entry
barriers, and the short-run ability of existing competitors to increase
their output. FN / The courts also recognize the use of "direct
evidence" to resolve market power questions. FN / In the relevant
interstate gas market, there are many buyers and sellers at the wellhead
level, numerous holders of capacity rights competing with pipeline
owners for transportation services, and strong price interactions
between those levels. Moreover, "direct" evidence shows that prices at
delivery points within the four basin area remain cointegrated within
arbitrage bounds.
B. The Relevant Wholesale Electricity Market
A relevant market also exists for wholesale electricity delivered
throughout the WSCC. Like their counterparts i the natural gas
industry, customers purchase wholesale electricity as the "delivered"
combination of generation and transmission services. FN / Thus, the
relevant market includes all suppliers whose combined "netback" and
transportation costs would be competitive at California delivery points.
FN / The relevant geographic market is the WSCC because that is "the
region from which generators will be able to bid power into the Power
Exchange." FN /
The relevant product market includes "all" effectively unregulated
delivered electricity which can compete in the Power Exchange for
residual wholesale electricity demand. FN / Within the WSCC, the
total capacity of competitive gas-fired, hydro, and coal plants exceeds
150,000 MW. These resources will compete for the demand remaining in
the PX after sales of price-regulated must-run and must-take capacity
are completed. As in the gas industry, there are numerous buyers and
sellers in the wholesale electricity market, strong interactions between
generation and transmission prices, and highly cointegrated prices at
delivery points.
1. Alleged "Swing Capacity" Markets
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The relevant product market for wholesale electricity cannot be
meaningfully limited to "swing capacity" producers. Edison and other
intervenors implicitly allege a product market consisting of generation
with "full load marginal costs" FN / within some range FN / of the
variable costs of producing electricity on Edison and other WSCC gas-
fired plants. Intervenors contend that gas-fired plans with their
relatively high production costs will be the only firms bidding at or
near the "clearing Prices" established by the Power Exchange. This
proposed market, however, excludes Bonneville Power and other
"inframarginal" suppliers located throughout the WSCC FN / that are
equally likely to establish the clearing price. FN /
Intervenors exclude these other generation sources by implicitly
assuming that out-of-state participants do not incur opportunity costs.
FN / Theoretically, PX participants will offer wholesale electricity
at their marginal supply costs, including fuel and other variable
production expenses. FN / In addition, however, the relevant economic
cost to out-of-state sellers FN / will include returns foregone by
selling to the Power Exchange instead of other western United States
buyers. FN / The existence of these opportunity costs explains why
gas is not "the" marginal fuel, FN / why out-of-state suppliers will
equalize the PX and prevailing WSCC prices FN / and, at least in part,
why gas and electricity prices are weakly correlated in southern
California. FN / Their existence also means that the relevant product
market includes the output of "inframarginal," out-of-state suppliers.
FN /
2. The Temporal Dimension
Similarly, the relevant market is not time-sensitive. A relevant
market includes all firms which would respond to a hypothetical a"small
but significant and nontransitory" price increase. FN /
As discussed above, WSCC suppliers can sell electricity throughout
the grid during both peak and off-peak hours. FN / Some intervenors
have suggested that the relevant market will be limited during peak
hours. FN / It is true that during those periods, supply costs
increase as some firms begin to reach capacity and (in some cases) as
individual transmission paths become congested. These transitory,
geographically dispersed costs increase price volatility. Even so,
there is no evidence that, during peak periods, any WSCC firms withdraw
from the market or that any out-of-state suppliers will be
systematically excluded from the PX. In fact, price data shows that
even before FERC issued Order 888 the major California delivery points
were highly cointegrated during peak periods with the rest of the WSCC.
C. The Relevant Intrastate Gas Transportation Market
Although the applicants and many intervenors combine it with the
interstate gas market, a separate relevant market can be defined for
intrastate gas transportation and storage services within southern
California. Ten years ago, SoCalGas and PG"&E were the principal
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suppliers of these services. Since the completion of their intrastate
extensions in 1992, Kern River and Mojave pipelines have also competed
for transportation services to EOPR and related cogeneration loads.
Private pipelines provide additional competition.
Despite this recent competition, SoCalGas has maintained
significant market power over these services. SoCalGas controls most of
the intrastate capacity within southern California, including all
transportation facilities located within Los Angeles, Orange and
Riverside Counties. FN / Moreover, as the extended kern River and
Mojave pipeline application process demonstrated,potential suppliers
face substantial regulatory entry barriers. A controlling market
position reinforced by high regulatory barriers to entry is strong
evidence of market power. FN / SoCalGas also price discriminates
between transportation customers, and can sometimes discount without
Commission approval. FN / The ability to persistently price
discriminate between similarly situated customers also implies that a
seller possesses market power. FN /
V. THE COMPETITIVE EFFECTS
Mergers are generally categorized as "horizontal," "vertical," or
"conglomerate." The competitive effects of a merger are assessed by
first defining the relevant markets and then determining whether the
merged entity will have an enhanced ability to profitably skew price or
output from competitive levels. FN / Under the DOJ/FTC Guidelines,
the effects of a "horizontal" merger depend upon several related
factors, including changes in concentration levels, entry conditions,a
nd efficiency enhancements. The government's vertical merger guidelines
"recognize only three possible anticompetitive effects: that vertical
mergers might create entry barriers, facilitate horizontal coordination,
or allow a regulated firm to evade rate regulation." FN / A failure
to properly define the relevant markets is fatal to a plaintiff's prima
facie case. FN / A plaintiff must also demonstrate "probabilities"--
not "ephemeral possibilities"--of anticompetitive effects within those
markets. FN /
A. The Vertical Integration of SoCalGas Intrastate
Gas Transmission and SDG&E Wholesale Electricity Operations
Although this merger has some horizontal feathers, the primary link
between the applicants is the gas transportation services SoCalGas
provides to SDG&E. Those transportation services are an important
component in the cost of generating electricity to SDG&E and other gas-
fired plants in southern California. Vertical integrations do not,
however, "automatically have an anticompetitive effect." FN / This is
because, unlike horizontal consolidations, vertical mergers do not
eliminate competitors from the market. FN / The vertical integration
resulting from this merger, in particular, will not adversely affect
competition in the wholesale electricity market because Agreement B
negates any incentive of SDG&E (or the merged entity) to manipulate PX
prices.
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Even without the restrictions of Agreement B, however, out-of-state
suppliers would defeat any attempt by the merged entity to manipulate
the price of wholesale electricity sold in southern California. FN /
The total capacity of plants supplied by SoCalGas is 15,837 MW. These
plants will compete with aggregate WSCC, out-of-state capacity exceeding
100,000 MW FN / for California's relatively modest "residual" demand.
Because out-of-state suppliers account for their opportunity costs,
FN / the resulting PX price will equal the prevailing WSCC spot price.
Price data -- as opposed to simulation models -- demonstrate that WSCC
prices are competitively determined. Neither SoCalGas nor the merged
entity will have the ability to profitably deviate prices from
competitive levels within that market.
1. The Intervenors' Vertical Integration Models
The Intervenors have failed to demonstrate with "probabilities"
that the integration of these vertically-related operations will have
adverse competitive effects in any relevant market. Relying upon an
engineering simulation instead of price data, FN / the Edison"swing
capacity model" discussed above ignores opportunity costs incurred by
low cost producers and fails to define a cognizable relevant market.
Similarly, SCUPP cites a vertical integration model which assumes that
inputs are consumed only by suppliers in the endproduct market. FN /
That assumption does not hold in this case, where core and other noncore
customers consume the vast majority of the gas transportation input gas-
fired plants used to generate the wholesale electricity endproduct.
Because both models assume that all suppliers employ the same technology
to produce the endproduct, they also fail to account for other sources
of competition in the wholesale market (e.g., hydro and coal general
plants.) FN / Finally, and most important, neither model reflects the
incentives of suppliers offering a price-regulated output, such as
electricity sold by the merged entity under Agreement B.
2. Futures Markets
Edison, SCUPP and other intervenors also allege that the merged
entity could "unfairly benefit" from vertical integration by
manipulating wholesale electricity prices after it purchased contracts
in the futures markets. FN / Thus, they contend, the merged entity
would essentially trade on "inside" information. FN / As before,
however, the merged entity would still be unable to manipulate wholesale
prices and the merger would not enhance any existing ability of SoCalGas
to profit in the futures markets. FN / Moreover, adverse effects upon
competition within the futures markets -- which are characterized by
their liquidity and ease of entry and exit FN / -- are extremely
unlikely. FN / In any event, the hypothetical conduct would be
unlawful under the Commodity Futures Trading Act.
3. The Kern River and Mojave Pipeline Purchase Options
Kern River claims that the merged entity can extract increased
supracompetitive profits in the wholesale electricity market by
exercising its options to purchase in 2012 the
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California operations of the Kern River and Mojave pipelines. FN /
This theory, which relies upon the swing capacity model, again
overstates the significance of gas-fired generation and ignores the
ability of an independent SoCalGas to obtain available supracompetitive
profits. FN /
Kern River also ignores the competitive nature of the purchase
options, whose effects should be assessed from the perspective of the
original settlement agreements. Economic efficiency considerations
require courts to establish rights and obligations "ex ante;" i.e., on
the date on which a crucial choice was made. FN / In 1987, SoCalGas
and PG&E dominated transportation service markets in southern
California. The purchase options, which the applicants contend were
integral to the settlements between the parties, permit Kern River and
Mojave to compete for those services from 1987 to 2012. If the parties
had not settled their dispute, entry by those two pipelines would have
been delayed and the subsequent competition they furnished would have
been reduced. Abrogating the purchase options now would reduce
incentives of other firms to enter into similar pro-competitive
settlements in the future.
In addition, the year 2012 effective date allows purchasers and
alterative suppliers a substantial period in which to respond the
possible exercise of these options FN / In any event, predictions
about competitive effects 15 years into the future are highly
speculative, particularly when they concern markets as dynamic as the
rapidly changing gas industry. FN / We conclude that the purchase
options, which contemplated increased competition within the intrastate
market and which will not endow the surviving entity with additional
market power, should not be abrogated by the merger.
4. The Applicants' "Remedial Measures"
Although this vertical integration does not "create" market power,
it could alter the manner in which SoCalGas exercises its existing
market power over intrastate transportation services. SoCalGas now
exercises market power by discriminating in the price of services
charged to gas-fired generation plans and other potential "bypass"
customers. The merger will not provide new opportunities for profitable
price or non-price FN / discrimination. We are also not aware of any
evidence that the merged entity would use its market power to require
simultaneous competitive entry into the gas and electricity markets or
to facilitate coordination between SDG&E and other WSCC suppliers.
In fact, the remedial conditions proposed by the applicants will
reduce the ability of the merged entity to engage in either price or
non-price discrimination. Those proposed conditions expand FERC's
requirement that Order 497 govern intrastate transactions between
SoCalGas and SDG&E and other marketing affiliates. Order 497 generally
requires interstate gas pipelines to treat their marketing and other
affiliates and "similarly situated persons" on a non-discriminatory
basis. Here, the applicants will retain their ability to price
discriminate, but they have agreed to submit any planned discounts to
the Commission for approval. In addition, they
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have agreed to refrain from discriminating in the provision of various
types of services, including: the application of tariff provisions;
transportation scheduling, balancing, storage, or curtailments; the
processing of transportation requests; the disclosure of transportation
information; and the offering of intrastate transportation discounts.
FN /
B. Horizontal Effects in the Intrastate Gas Transportation, "Gas
Procurement" and Retail Gas Markets
The principal horizontal feature of this merger is the consolidated
ownership of the applicants' gas procurement functions. FN / Both of
the applicants purchase gas in the interstate market for their core and
some of their noncore customers and SDG&E makes significant purchases
for its electricity generation plants. In 1996, SoCalGas and SDG&E gas
purchases averaged 963 FN /and 255 FN / MMcf/d, respectively, while
total production in the relevant interstate market averaged 24,000
MMcf/d. FN / Thus, SoCalGas and the merged entity would account for
approximately four and five percent, respectively, of purchases within
the unconcentrated four basin gas market. We assume for within the
unconcentrated four basin gas market. We assume for purposes of
analyzing this merger that SoCalGas is among the largest purchasers in
the western United States. Following the Guidelines, we conclude from
this assumed distribution of buyers that the merger of the two companies
will have an insignificant effect upon competition in the interstate gas
market. FN /
The merger will also combine the two companies' partially
deregulated non-core gas retailing functions. FN / Although both
applicants currently distribute gas to non-core customers, PUC rules
significantly restrict the ability of SoCalGas to compete for such sales
within its service area. FN / Moreover, neither firm has made non-
core sales outside its service area. FN / In 1996, total non-core
sales in southern California averaged 1821 MMcf/d. FN / SoCalGas and
SDG&E sales to non-core customers during that year averaged 58 and 144
MMcf/d, respectively. FN / We conclude that the consolidation of
these non-competing, relatively limited operations will not adversely
affect competition for non-core retail services.
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C. Potential Competition for Intrastate Gas Transportation and
Electric Retail Services
This merger may eliminate SDG&E as a limited potential competitor
in the market for intrastate gas transportation services. The demand
for intrastate transportation in southern California is approximately 1
Bcf per day for SoCalGas core customers, between 125 and 300 MMcf per
day for SDG&E, FN / and approximately 1 Bcf per day for other noncore
customers. The Project Vecinos agreement between the applicants and
other evidence suggests, although not conclusively, that the threat of
independent entry by SDG&E has provided some discipline to this less
than fully competitive, high-entry-barrier market. We recommend that
the Commission consider requiring SoCalGas to auction a volume of
transmission rights over its system equal to the average SDG&E load.
The courts recognize two theories under which a merger between
potential competitors may be challenged. The actual potential
competition doctrine -- which is so speculative that it has never
provided the basis for a successful challenge FN / -- applies if the
acquiring firm would have "probably" entered a concentrated market,
thereby providing significant procompetitive effects. FN / SDG&E may
present a "threat of competitive entry by a bypass pipeline" and it may
be an "attractive anchor customer" for pipeline construction "within"
California. FN / The courts, however, require showings of an intent
to enter FN / that go beyond evidence of generalized abilities and
incentives. To avoid speculation, FN / they also require a showing
that entry will occur, not in the "reasonably foreseeable" future, but
in the near future. FN / We are not aware of any evidence that SDG&E
had current or even reasonably contemporaneous plans to enter the gas
transportation market.
1. The Perceived Potential Competition Doctrine
A merger may also be challenged if the acquiring firm is a
"perceived potential entrant." This doctrine applies if the acquiring
firm is "(1) perceived by existing firms as a potential independent
entrant and (2) has exercised a tempering impact on the competitive
conduct of existing sellers." FN / In this case, SDG&E may have
tempered the pricing of intrastate transportation services by
threatening to bypass the SoCalGas system. Thus, in 1988, SDG&E
considered building a pipeline to directly interconnect with the El Paso
system. FN / SDG&E considered at least two other bypass proposals
during the next six years. FN / Finally, in 1994, the parties entered
into their Project Vecinos Revenue Sharing Agreement, where SoCalGas
agreed to reduce transportation rates by an amount equal to: "the
potential benefits that SDG&E would have received had it partially or
totally bypassed SoCalGas by utilizing transportation services from a
pipeline constructed in Baja California. FN /
Despite this tempering effect, it is unclear if SDG&E is a current
entry threat or if the Kern River pipeline and other suppliers view
SDG&E as a potential entrant to the intrastate market. Because the
Revenue Sharing Agreement remained confidential until recently, FN /
these other suppliers may not have recognized that SDG&E was considering
bypass alternatives. Similarly, because SDG&E would have to build
dedicated facilities to bypass SoCalGas, SDG&E entry or withdrawal may
not affect price or output levels elsewhere in the market. More
important, SDG&E may not still be a potential supplier of intrastate
services. Although SDG&E would constitute a valuable "anchor tenant,"
FN / perceived potential competition doctrine applies to suppliers,
not customers, which have the ability to compete with their merging
partners. Unfortunately, the record fails to clarify these issues.
If the Commission does conclude that SDG&E is a significant
potential competitor, we recommend that it require the merged entity to
auction transmission rights over the SoCalGas system equal in volume to
the average SDG&E load which will be withdrawn from the intrastate
market. Following SCUPP, we suggest that buyers of those rights obtain
undivided interests based on contract paths "from an established point
of receipt to an established point of delivery." FN / Those auctioned
rights will constitute an alternative source of intrastate
transportation, thereby offsetting the loss of SDG&E as a potential
competitor. We propose an auction, with a long run marginal cost (LRMC)
minimum bid, because it will ensure that the highest valued users
receive these rights and because it will help reimburse SoCalGas for
losses in the value of its system. Finally,m because the competitive
effects of SDG&E withdrawal from the intrastate market appears somewhat
isolated, we suggest that the Commission establish this auction in
separate proceedings following the completion of this merger.
2. The Retail Electric Services Market
IID alleges that SoCalGas is a potential competitor for retail
electric sales within its gas distribution area. FN / For the actual
potential competition theory to apply, entry must have a deconcentrating
or other significant procompetitive effect. This predicate effect will
not exist "if there are numerous potential competitors," because the
elimination of one of many "would not be significant." FN /
As the applicants demonstrate, however, Edison and the Los Angeles
Department of Water & Power already provide retail services within that
region and 92 other companies, including eight of the leading firms in
the industry, have already registered as Energy Service Providers with
the Commission. FN / Furthermore, SoCalGas has no competitive retail
affiliates and limited experience within the electricity industry.
FN /There is also no evidence that Pacific had "actual" plans to
provide such services or that Pacific's entry would have had significant
procompetitive effects in any retail electricity markets. We conclude
that the elimination of SoCalGas as a potential supplier would not have
a significant effect upon competition in any California retail
electricity market.
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VI. RETENTION OF JURISDICTION
This office recognizes the uncertainty of the transition to the
restructured system of wholesale electricity sales and transmission that
will go into effect on January 1, 998. Although we believe it is
unlikely, we acknowledge the possibility that out-of-state sellers will
fail to discipline the pricing of electricity sold by the merged entity.
We do expect, however, that SoCalGas will continue to provide
intrastate transportation services to the vast majority of gas-fired
generation plants within southern California. In the unlikely event
that the merged entity can manipulated the PX price, plants supplied by
the Kern River and Mojave pipelines and plants subject to "take-or-pay"
contracts may provide valuable competition in the restructured market.
Accordingly, we recommend that the PUC, during its continuing review of
the competitiveness of the wholesale market, specifically examine the
pricing practices of the merged entity and the relationship between
those practices and the operation of the Commission consider retaining
jurisdiction over this merger for a period of two years for the purpose
of reexamining the limited questions of whether: (1) the merged entity
has used its intrastate system to manipulate the price of electricity it
sells in the wholesale market; and (2) whether abrogating the Kern River
and Mojave pipeline options and the take-or-pay options would limit the
ability of the merged entity to engage in such practices.
VII. CONCLUSION
The only difficult factual issue raised by this merger is whether
the applicants are potential competitors in the intrastate gas
transportation market. The merger has no adverse "horizontal" effects
because competition between the applicants is limited to such areas as
the vast interstate gas market and non-core gas retailing. Vertical
effects are also negligible because wholesale electricity offered by the
merged entity will be subject to the constraints of comprehensive price
regulation mandated by ISO Agreement B. In addition, out-of-state WSCC
sellers, which are highly integrated with southern California during
both peak and off-peak hours, would defeat any attempt by the merged
entity to manipulate wholesale electricity prices. Edison's swing
capacity model comes to an opposite conclusion by overlooking the
fundamental concept of opportunity costs.
Some evidence does suggest that SDG&E is a potential supplier of
intrastate gas transportation services. If the Commission finds that
evidence persuasive, we recommend that it consider, in proceedings
subsequent to the completion of this merger, requiring SoCalGas to
auction a volume of intrastate transmission rights equal to the SDG&E
load which will be withdrawn from the market by this merger. This
remedy would introduce competition into the intrastate market, thereby
offsetting any adverse effect of the merger and reducing incentives to
construct duplicative, "uneconomic bypass" facilities. Finally, we
recommend that the Commission retain limited jurisdiction over this
matter for a period of two years during which it can review whether the
merged entity uses its intrastate system to manipulate the price of
electricity it sells in the wholesale market.
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FN ./ See San Diego Gas & Electric Co., 79 FERC &61,372 (1997) ("FERC
June 1997 Merger Order").
FN ./ Exhibit 14, Chapter 3, at 11 ("Stewart Rebuttal").
FN ./ Stewart Rebuttal at 9-10.
FN ./ See Opinion of the Attorney General on Competitive Effects of
Proposed Merger between Pacific Telesis Group and SBC Communications,
Inc., 79 Cal.Ops.Atty.Gen. 301 (1996); Opinion of the Attorney General
on Competitive Effects of Proposed Merger of American Telephone &
Telegraph Company and McCaw Cellular Communications, Inc., 77
Cal.Ops.Atty.Gen. 50 (1994); Opinion of the Attorney General on
Competitive Effects of Proposed Merger of GTE and Contel Corporations,
Submitted Pursuant to PU Code Section 854(b)(2); Opinion of the Attorney
General on the Proposed Acquisition of San Diego Gas and Electric
Company by SCEcorp, the Parent of Southern California Edison Co., 73
Cal.Ops.Atty.Gen. 366 (1990).
FN ./ Section 854(b) provides in pertinent part:
Before authorizing the merger, acquisition or control of any electric,
gas, or telephone utility organized and doing business in this state . .
., the commission shall find that the proposal does all of the
following:
(1) Provide short-term and long-term benefits to ratepayers.
(2) 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.
(3) Not adversely affect competition. In making this finding, the
commission shall request 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.
FN ./ Applicants' Opening Brief, at 86. These QF facilities included 67
MW capacity wastewood, 30 MW capacity hydroelectric, and 37 MW capacity
landfill projects. Application at 16 n.11.
FN ./ SDG&E wholesale sales are "economy energy sales and short-term
sales of capacity." FERC June 1997 Merger Order, mimeo at 6.
FN ./ Exhibit 2 at 30 ("Hieronymous Direct").
FN ./ According to SCUPP, SDG&E "represents a total load of about 350
MMcfd." Exhibit 105 at 52 ("Yap Direct").
FN ./ Hieronymous Direct at 30. In fact, San Diego Gas & Electric
purchases its gas supplies from out-of-state producers, and transports
them to San Diego over interstate pipelines and the SoCalGas intrastate
system. Exhibit 104 at 6 ("Taylor Direct").
FN ./ Application at 30.
FN ./ The applicants state that AIG is the nation's 15th largest gas
marketer and the 19th largest
20
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electricity marketer. Exhibit 14, Chapter 1 at 44 ("Hieronymous
Rebuttal"). Edison claims that AIG is the tenth largest gas marketer in
the United States. Exhibit 209 at 17 ("Carpenter Rebuttal").
FN ./ Hieronymous Direct 6.
FN ./ Following "guidance" proceedings, FERC conditionally approved the
ISO and PX on October 30, 1997. Pacific Gas and Elec. Co., San Diego
Gas & Elec. Co., and Southern Cal. Edison Co. 81 FERC &61,122 (1997)
("FERC October 1997 ISO/ PX Order"). See Pacific Gas and Elec. Co., San
Diego Gas & Elec. Co., and Southern Cal. Edison Co., 77 FERC &61,204
(1996) ("FERC November 1996 ISO/ PX Order"); Pacific Gas and Elec. Co.,
San Diego Gas & Elec. Co., and Southern Cal. Edison Co., 77 FERC &61,265
(1996) ("FERC December 1996 ISO/ PX Order"), and Pacific Gas and Elec.
Co., San Diego Gas & Elec. Co., and Southern Cal. Edison Co., 80 FERC
&61,128 (1997) ("FERC July 1997 ISO/ PX Order").
FN ./ Exhibit 2, Attachment A, Chapter III at III-9: Southern
California Edison Company and San Diego Gas & Electric Company Report on
Horizontal Market Power Issues ("Hieronymous MBR").
FN ./ Hieronymous Direct at 5. Firm purchases during 1996 were 1,434
MW. Id.
FN ./ Hieronymous Direct at 5 n.7.
FN ./ "After the transition period, the Companies' participation in the
PX will be voluntary." FERC December 1996 ISO/ PX Order, mimeo at 2.
FN ./ End users who pay exit fees, however, can "directly access"
suppliers in the wholesale market which are "interconnected to the ISO
grid (directly or through wheeling arrangements)." Exhibit 2,
Attachment A at I-5.
FN ./ After January 1, 1998, "utilities that join the ISO and PX will
sell the output from their generating stations into the PX." Yap Direct
at 75. "A uniform market-clearing price for PX buyers in a congestion
management zone will be established based on the cost of the marginal
generator in the zone for each hour." FERC December 1996 ISO/ OX Order,
mimeo at 3.
FN ./ The Commission ordered Edison and PG&E to sell at least 50
percent of their fossil-fuel-fired generation capacity. FERC December
1996 ISO/ PX Order, supra, at 26. PG&E will divest nearly all of its
gas-fired capacity. Exhibit 125, Chapter 2 at 77 ("Graves Direct").
Edison's Board of Directors has voted to divest all 9,600 MW of its gas
generation. Id.
FN ./ Graves Direct at 84.
FN ./ The schedules devised by the PX, however, "are subject to
adjustment by the ISO for reliability and congestion management
purposes." FERC November 1996 ISO/ PX Order, supra, at 61,804.
FN ./ "The price received for energy sold into the PX will be
established through a 'second price auction.' . . . [Thus,] the highest
cost unit that is needed in order to meet the hour's demand will
establish the price for power in that hour." Yap Direct at 75.
FN ./ "Must-run" units, would be "certain generating units the
Companies would designate to provide necessary support services to the
transmission system at cost-based rates." FERC December 1996 ISO/ PX
Order, mimeo at 34-35 n.48. Under "call contracts" proposed by the
21
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IOUs, these must-run units "would be paid a reservation fee or demand
charge to be available. When that unit is required by the ISO to
generate for reliability purposes, it would be paid its variable
operating costs. When it is not required to generate, it would be
treated like any other generator, i.e., it would be dispatched based on
its bid and paid the market price." FERC December 1996 ISO/ PX Order,
mimeo at 25-26.
FN ./ ISO Agreement B discussed below "provides an availability payment
which covers the annual contribution to the initial capital investment,
fixed fuel costs, fixed annual O&M costs, and annual auxiliary power
costs; it also provides a payment for running costs when a unit is
called to run." FERC October 1997 ISO/ PX Order, supra, at 251.
FN ./ FERC October 1997 ISO/ PX Order, supra, mimeo at 219-20. SDG&E
expects to enter into "Agreement B," which "is intended for units that
can participate in the market profitably in some periods but not in
others."
FN ./ FERC December 1996 ISO/ PX Order, mimeo at 34 n. 48. "In the
restructured California energy market, at least during the initial years
of operation, nuclear units, QF contracts and pre-existing wholesale
purchase contracts will not be bid into the PX and market-based prices
will not apply to their output. Instead, these will be regulatory must-
take resources scheduled by the ISO." Exhibit 2, Attachment B at &30:
Affidavit of Joe D. Pace ("Pace MBR").
FN ./ Pace MBR at &27.
FN ./ Hieronymous MBR at III-15.
FN ./ ISO Agreement A will actually govern SDG&E from January 1, 1998
to April 1, 1998, after which Agreement B will be effective. "[T]he ISO
has committed to revise the Agreement [B] by October 31, 1998." FERC
October 1997 ISO/ PX Order, supra, mimeo at 225.
FN ./ FERC October 1997 ISO/ PX Order, supra, mimeo at 251; Hieronymous
Rebuttal at 5 n.1.
FN ./ Proposed Decision of ALJ Minkin, A.96-08-001, slop op. at 50
(Oct. 20, 1997).
FN ./ FERC October 1997 ISO/ PX Order, supra, mimeo at 233-235.
FN ./ / An ISO "Oversight Board" will (1) establish nominating/
qualification procedures and determine the composition of the board
representation and select the ISO and PX Governing Board members and (2)
serve as a permanent appeal board for reviewing ISO Governing Board
decisions. FERC November 1996 ISO/ PX Order, supra, at 61,817.
FN ./ See Hieronymous Direct at 21.
FN ./ FERC November 1996 ISO/ PX Order, supra at 61,799.
FN ./ See FERC July 1997 ISO/ PX Order, supra, at 26-27; FERC November
1996 ISO/ PX Order, supra, at 61,828-61, 834 (discussing congestion
pricing).
FN ./ Stewart Rebuttal at 4.
FN ./ Line 401 runs from the California-Oregon border at Malin to the
Kern River Station. That line, which went into service on November 1,
1993, has an average annual firm capacity of 755 MMcf per day.
FN ./ Stewart Rebuttal at 4. Edison claims, though, that SoCalGas does
not "list Hector as a delivery point." Carpenter Direct at 37-38.
22
<PAGE>
FN ./ Stewart, Rebuttal at 4. IID estimates that the system capacity
is 3,700 MMcfd. Exhibit 104 at 23 ("Taylor Direct").
FN ./ Stewart Rebuttal at 9.
FN ./ Taylor direct at 5; Stewart Rebuttal at 3. See Yap Direct at 69.
The SoCalGas "noncore throughput excluding SDG&E's load exceeds 1 bcf/
d." Stewart Rebuttal at 32.
FN ./ Exhibit 115 at 25 ("Roach Direct"); Taylor Direct at 6.
FN ./ Id.
FN ./ SCUPP alleges that the intrastate system is an "essential
facility." YAP direct at 65.
FN ./ Stewart Trans. at 2595.
FN ./ Stewart Trans. at 2556.
FN ./ SoCalGas estimates core demand from a statistical model and
noncore demand from gas nomination information. Stewart Rebuttal at 5.
FN ./ "[O]ut-of-state sources supplied the vast majority --
approximately 84% -- of the total demand in southern California in
1996." Carpenter Direct at 21.
FN ./ Stewart Rebuttal at 5.
FN ./ See Stewart Trans. at 2560-2563. See also Stewart Trans. at
2407-2411, 2414 (discussing the consequences to SoCalGas under the Gas
Cost Incentive Mechanism (GCIM) "of not meeting injection or withdrawal
targets or storage levels").
FN ./ Stewart Rebuttal at 5. "SoCalGas owns all of the approximately
115 Bcf of gas storage in southern California. SoCalGas reserves 70 Bcf
of this capacity for its core customers, reserves 5 Bcf for balancing,
and markets the remaining 40 Bcf to noncore customers." Taylor Direct
at 44.
FN ./ Carpenter Direct at 49.
FN ./ Stewart Trans. at 2401; Stewart Rebuttal at 7.
FN ./ A custody cut occurs when SoCalGas notifies an interstate
pipeline that it cannot accept the full amount of gas nominated for
delivery at a particular receipt point. Approximately 600 custody cuts
occurred in 1995 and 1996. SoCalGas matches the window at that receipt
point by pro-rating shippers' nominations. Carpenter Direct at 34.
FN ./ See Carpenter Direct at 31-37; Stewart Trans. at 2551-2557.
SoCalGas imposes Rule 30 when its system is overnominated. Carpenter
Direct at 35. SoCalGas has "called" Rule 30 events six times in 1997.
Carpenter Direct at 36.
FN ./ Stewart Trans. at 2406-2409, 2547-2555; Stewart Rebuttal at 6-7.
FN ./ Re Gas Utility Procurement Practices and Refinement to the
Regulatory Framework for Gas Utilities, D.91-11-025, mimeo at 20; 41
CPUC 2d 668 (1991) (CPUC 1990). See Exhibit 14, Chapter 2 at 9 n.24
("Leitzinger Rebuttal").
FN ./ SoCalGas estimates that it posts transactions on GasSelect
"within the hour." Stewart Trans. at 2578.
FN ./ Stewart Trans. at 2575-2576, 2583.
FN ./ Stewart Trans. at 2577.
FN ./ See Broadman and Kalt, How Natural Is Monopoly? The Case of
Bypass in Natural Gas Distribution Markets, 6 Yale J. on Reg. 181
(1989); Kelly, Intrastate Natural Gas Regulation:
23
<PAGE>
Finding Order in the Chaos, 9 Yale J. on Reg. 365 (1992); Pierce,
Intrastate Natural Gas Regulation: An Alternative Perspective, 9 Yale
J. On Reg. 407 (1992). Because PG&E and SoCalGas have "exclusive
service territories," PG&E cannot "offer any customer in SoCalGas"
service area direct connection to Line 300-A or -B." Stewart Trans. at
2776-2777.
FN ./ Exhibit 114, Chapter 1, at 5-7 ("Larsen Direct"); Exhibit 114,
Chapter 2 at 9 ("Wadlington Direct"); Stewart Rebuttal at 34-35 ("There
appears to be no dispute that Kern River only acceded to provide
SoCalGas the option to purchase its California facilities as a means to
induce SoCalGas and the Commission to withdraw their opposition before
the FERC"); Stewart Trans. at 2524-2525, 2783-2786; Roach Direct at 63;
Yap Direct at 58-60.
FN ./ Roach Direct at 25.
FN ./ Hieronymous Direct at 28.
FN ./ See Taylor Direct at 12, 51 ("SoCalGas provides gas
transportation to SDG&E at less than the regulated rate because SDG&E
could bypass SoCalGas gas transportation."); Yap Direct at 52-53. But
see Stewart Rebuttal at 38 (contending that SDG&E merely shifted risk by
agreeing to pay a higher demand charge and lower volumetric rate).
FN ./ Larsen Direct at 9. See Stewart Trans. at 2744 ("we compete
vigorously against bypass and against all kinds of bypass and against
all kinds of bypass including by wire and everything else"), 2772-2775
(referring to "local gas production as a form of competition," and
competition from "municipalization efforts similar to Vernon's");
Leitzinger Rebuttal at 30 ("new construction" has "been a source of
competitive discipline in the pipeline business"); Roach Direct at 69
(estimating that Kern River customers pay approximately 18% less for
their transportation services).
FN ./ Yap Direct at 50.
FN ./ Stewart Rebuttal at 31. See Leitzinger Rebuttal at 31.
FN ./ Stewart Rebuttal at 20.
FN ./ The CPUC established the ITCS in Decision No. 91-11-025, Re Gas
Utility Procurement Practices and Refinement to the Regulatory Framework
for Gas Utilities, 41 CPUC 2d 668 (1991). The ITCS for any shipment
equals the difference between "the maximum rates charged by the
interstate pipelines for firm capacity" ("as-billed rate") and the
actual shipping rate. The PUC capped ITCS charges recoverable from core
customers at 10 percent of the core's total capacity reservation costs.
D.91-11-025, mimeo at 51. Noncore customers, including Edison, pay all
additional ITCS costs. The PUC annual "BCAP" proceedings establish the
size of these ITCS funds and transfer balances from year to year. The
amount SoCalGas and other intrastate pipelines can recover from ITCS
funds is also limited, in some cases, by settlements which have
discounted the maximum rate which the end-user must pay. Since May 1,
1996, SoCalGas has also offered "released" capacity on interstate
pipelines at rates "posted" on "electronic bulletin boards" for all
requirements beyond those of its core customers. As SoCalGas releases
capacity, resulting revenues reduce the ITCS surcharge amount.
FN ./ See Stewart Trans. at 2744.
FN ./ Leitzinger Rebuttal at 8.
24
<PAGE>
FN ./ Doane and Spulber, Open Access and Evolution of the U.S. Spot
Market for Natural Gas, 37 J.L. & Econ. 477, 479 (1994); Black and
Pierce, The Choice between Markets and Central Planning in Regulating
the U.S. Electricity Industry, 93 Columbia L.Rev. 1339, 1343 (1993) (the
electricity industry combines "production of wholesale electricity;
transmission of bulk power over high-voltage lines from power plants to
local geographic areas; and distribution of power to retail customers").
FN ./ DOE/ EIA, Natural Gas 1996, Issues and Trends, at 40 (Washington,
D.C. Dec. 1996). Thus, each "pipeline was a link in a supply chain from
a field whose resources were dedicated by contract to that line to the
distribution company which was obligated by contract to buy gas from the
pipeline." DeVany and Walls, The Emerging New Order in Natural Gas, at
5 (Quorum Books 1995).
FN ./ Order No. 636, Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation and Regulation of
Natural Gas Pipelines After Partial Wellhead Decontrol under Part 284 of
the Commission's Regulations, F.E.R.C. Stats. & Regs. (CCH) &30,939, at
30,396 (1992). See Black and Pierce, supra, at 1351; Pierce,
Reconstituting the Natural Gas Industry from Wellhead to Burnertip, 9
Energy L.J. 1 (1988).
FN ./ The 1978 Natural Gas Policy Act, together with FERC Order 436 and
the 1989 Decontrol Act, removed all controls over the wellhead price of
natural gas. Order 636, supra, at 30,397. "Take or pay" disputes
subsequently arose, however, because price regulation was retained for
"old," "high cost," and other subcategories. "By the end of 1986, $10
billion worth of contracts were involved in take-or-pay disputes."
Doane & Spulber, supra, at 483.
"Take-or-pay liabilities arise from a typical provision in a
contract between an LDC and a gas producer which obliges the LDC to take
a minimum volume of gas from the producer or pay for it anyway." Kelly,
supra, 9 Yale J. on Reg. at 361 n.16. Order 436 "gave pipelines facing
mounting take-or-pay liability the right to convert their sales
obligations under their wellhead contracts to transportation
entitlements from other suppliers." Fagan, From Regulation to
Deregulation: The Diminishing Role of the Small Consumer within the
Natural Gas Industry, 29 Tulsa L.J. 707, 721 (1994). FERC Order 500
attempted to resolve further disputes by, among other things, allowing
the establishment of a "gas inventory charge" (GIC). Lyon and Hackett,
Bottlenecks and Governance Structures: Open Access and Long-term
Contracting in Natural Gas, 9 J. Law. Econ. & Org. 380, 387 (1993).
Order 500, however, "fared poorly on judicial review." United
Distribution Cos. v. F.E.R.C., 88 F.3d 1105, 1125-26 (D.C. Cir. 1996).
FN ./ DOE/ EIA, supra, at 40.
FN ./ Leitzinger Rebuttal at 16.
FN ./ Leitzinger Rebuttal at 25.
FN ./ Regulation of Natural Gas Pipelines after Partial Wellhead
Decontrol, F.E.R.C. Stats. and Regs. &30,665 (1985), vacated and
remanded, Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir.
1987).
FN ./ Doane & Spulber, supra, at 477; Order 636, supra, at 30,396.
25
<PAGE>
FN ./ "Among the central goals of Order Nos. 436 and 636 has been the
conversion of bundled sales arrangements into separate transportation
and gas sales transactions. On the transportation side, the Commission
recognized that while much of the nation's interstate pipeline capacity
was reserved for firm transportation those transportation rights
ultimately were not being utilized . . . . FERC therefore sought to
develop an active 'secondary transportation market,' with holders of
unutilized firm capacity rights reselling them in competition with any
capacity offered directly by the pipeline." United Distribution Cos. v.
F.E.R.C., Circuit Review: September 1992-August 1993, 62 Geo.
Wash.L.Rev. 718, 740 (1994) ("Order 636 mandates pipelines to 'unbundle'
their gas services" and "offer the same quality of service to all
potential customers, irrespective of where the gas was purchased.")
FN ./ "Brokering arrangements allowed a holder of firm capacity rights
(the "releasing shipper") to sell those rights to a 'replacement
shipper.' The transaction took place directly between the two parties
and the replacement shipper essentially stepped into the shoes of the
releasing shipper." United Distribution Cos., supra, 88 F.3d at 1149.
FN ./ Id.
FN ./ Edison alleges that, in developing that offer, SoCalGas can "take
as tough a negotiating stance as it wants because there is no regulatory
requirement for it to release any of the capacity it holds and the ITCS
guarantees full recovery of all cost associated with the capacity."
Opening Brief of Southern California Edison, at 40. Edison further
alleges that "SoCalGas' minimum bid, minimum take, and other capacity
release practices -- by withholding capacity from the market -- have the
potential to raise the price of gas at the southern California border
from what it otherwise would have been." Carpenter Direct at 53. As
indicated below, however, this theory fails to account for the full
extent of the competition that exists throughout the four basin
interstate market. It also fails to explain how SoCalGas can limit
supply in a market where unused capacity rights revert to the pipeline,
which can then sell that capacity as interruptible transportation.
Leitzinger Rebuttal at 20. Finally, Edison fails to reconcile its
theory that SoCalGas capacity releases occur at prices under the initial
opening offer." Stewart Rebuttal at 25; Leitzinger Rebuttal at 25.
FN ./ Leitzinger Rebuttal at 19. "[E]ach interstate pipeline is
required to establish and administer an electronic bulletin board
('EBB') . . . The EBB carries information about available and
consummated capacity release transactions. For example, holders of
excess firm capacity rights may 'post' their available capacity on the
EBB . . . . Pipelines are also required to post on the EBB any firm
capacity that they have available for sale, where the capacity competes
for buyers against capacity made available for resale by shippers."
United Distribution Cos., supra, 88 F.3d at 1150.
FN ./ United Distribution Cos., supra, at 1150-1151. FERC requires
that end users contract with gas producers during "bid week." Bid week
"generally occurs about the last week of the previous month." Exhibit
353, Vol. I, at 56:2-4 ("Lorenz Depo.").
FN ./ Leitzinger Rebuttal at 21. See Yap Direct at 21.
FN ./ Stewart Rebuttal at 22. Transwestern and El Paso substantially
increased the capacity of
26
<PAGE>
those pipelines in 1991, and again in 1996. Leitzinger Rebuttal at 24.
See Stewart Rebuttal at 23.
FN ./ PG&E "transports this gas across northern California to an
interconnection with the SoCalGas system in Kern County, providing
access to Canadian gas supplies for customers in southern California."
Taylor Direct at 33.
FN ./ Leitzinger Rebuttal at 16; Leitzinger Trans. at 3148, 3155.
FN ./ Following its line 401 expansion, PG&E likewise increased its
transportation of Canadian gas into California, while announcing plans
to terminate its 1.14 Bcf/ d capacity contract with El Paso. Leitzinger
at 21.
FN ./ Leitzinger Trans. at 3164. Edison notes that El Paso and
Transwestern carry gas to California "from Canada via Northwest
pipelines." Carpenter Direct at 21.
FN ./ Leitzinger Trans. at 3167. See Samuels, supra, 62
Geo.Wash.L.Rev. at 722 (Gas service is either provided on a firm or
interruptible basis.)
FN ./ Leitzinger Rebuttal at 16.
FN ./ Leitzinger Rebuttal at Exhibit JJL-6, 24 (discussing "netback
pricing"); Leitzinger Trans. at 3149-50. See also Leitzinger Rebuttal
at 16 ("(T)o compete for southern California customers Canadian
producers on some occasions agreed to contract pricing involving a
netback price starting with the price of southwest gas delivered to
southern California"); Leitzinger Trans. at 3145 ("if the price of
transportation capacity goes up, it has the effect of lowering the basin
price").
FN ./ Black and Pierce, supra, at 1348.
FN ./ Order No. 888, Promoting Wholesale Competition through Open
Access Non-Discriminatory Transmission Services by Public Utilities;
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, F.E.R.C. Stats. & Regs. (CCH) &31,036 (1996). FERC also
effectively deregulated non-firm transmission services. Id. at 31,743.
FN ./ Black and Pierce, supra, at 1349.
FN ./ Black and Pierce, supra, at 1350.
FN ./ Cities of Anaheim, Cal. et al. v. Southern Cal. Edison Co.,,
1990-2 Trade Cases &69,246 at 64,899-64,900 (C.D.Ca. 1990), aff'd 955
F.2d 1363 ("Anaheim v. Edison").
FN ./ Exhibit 379 at 4: DeVany and Walls, Open Transmission and Spot
Markets for Power (July 1997) ("DeVany and Walls"). See Hieronymous
Direct at 16-17 ("the WSCC transmission grid . . . is characterized by a
great number of interconnections and includes companies with
transmission ownership and rights covering wide geographic areas.") The
WSCC includes two regional transmission groups, the Western Regional
Transmission Association and the Northwestern Regional Transmission
Association, both of which require members to provide open access,
comparable service tariffed transmission services. WRTA, 71 FERC
&61,158 (1995); NWRTA, 71 FERC &61,397 (1995).
FN ./ The WSPP, a power pool consisting of approximately 70 WSCC
members, allows participating electric utilities to sell economy energy,
capacity service and transmission service at "rates determined between
predetermined price floors and ceilings." WSPP, 55 FERC &61,099 at
27
<PAGE>
61,300. In approving the WSPP, FERC set the ceiling rate for power
sales at 'sellers' forecasted incremental cost plus up to . . . 18.3
mills/ kWh." Id. at 61,321. Because WSPP and other applicable price
ceilings are rarely binding, however, the vast majority of WSCC sales
are effectively unregulated. Hieronymous Trans. at 2971. See Graves
Direct at 96 (referring to "(largely) unregulated generation").
FN ./ Graves Direct at 84. The annual average WSCC load is 82,000 MW.
Graves Direct at 79.
FN ./ The network provides multiple, alternative connections between
generating plants, substations, and load centers, as well as multiple
interconnections with other control areas, utilities and regions."
DeVany and Walls, supra, at 6.
FN ./ LADWP, for example, obtains power from generation units located
in the eastern half of Montana. Hieronymous Direct at 17. Likewise,
after January 1, 1998, TRW will obtain power for its 44 California
facilities from Montana Power Group. See TRW to Switch to Montana
Energy Firm, Los Angeles Times (Orange Cty.), Nov. 6, 1997, at D1.
FN ./ See Hieronymous Trans. at 2973-2974 ("[A] loop flow . . . refers
to the fact that electrons flow in the path of least resistance
according to Kirchoff's laws. And so despite that you have a contract
path from A to B, the electrons may actually go from A to C to B, or may
even never get to B as electrons at all, and that's a loop flow. It
loops around the area covered by the contract path.").
FN ./ Hogan, Contract Networks for Electric Power Transmission, 14
J.Reg.Econ. 211, 215 (1992) (also noting that "[o]ne of the most
important economic implications of this prevalence of loop flow is that
the power transmission highway is very unlike other highways, and
analogies comparing other highways, railroads, or pipelines can be quite
misleading").
FN ./ Hieronymous Trans. at 2976.
FN ./ DeVany and Walls, supra, at 3 n.2.
FN ./ De Vany and Walls, supra, at 2, 15.
FN ./ Cointegration is a statistical relationship which "occurs when
variability over time in two respective data series which cannot be
associated with a trend in either series individually is closely related
as between those data series." Leitzinger Rebuttal at 12. See Michaels
and De Vany, Market-Based Rats for Interstate Gas Pipelines: The
Relevant Market and the Real Market, 16 Energy L.J. 299, 327 (1995) ("If
two areas are in the same competitive market, their prices will inhabit
a band whose width reflects the cost of arbitrage. Those costs include
transportation, risk exposure, and information about profitable
opportunities. If competition exists, it will quickly bring disparate
prices back within their arbitrage limits. . . . If the cost of
arbitrage varies little over time, two areas are in the same market if
the difference between their prices is relatively constant. The
statistical technique known as cointegration provides a criterion under
which to determine the relative constancy of such a difference.").
FN ./ Hieronymous Trans. at 2978.
FN ./ "Any interfacing utility (or generators/ sellers with access to
an interface) can sell into the PX and will be treated comparably to
other market participants operating in the PX area."
28
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FERC December 1996 ISO/ PX Order, mimeo at 4; FERC July 1997 ISO/ PX
Order, mimeo at 18 (rejecting a "special settlement rule" and related
"reciprocal transmission service" requirements). In our Reply Comments
of Attorney General of California on Electric Industry Restructuring
Proposals, R. 94-04-031 (Aug. 24, 1995), this office noted that an
earlier version of the PX, which prohibited "Direct Access" transactions
and which did not clearly permit sales into the PX by out-of-state
suppliers, was vulnerable to coordinated bidding. We do not believe the
formulation of the PX approved by FERC contains that defect.
FN ./ Joskow MBR at II-57 ("Other capacity, including that owned by
entities other than the IOUs, and all of the IOUs' generating capacity
that is divested or otherwise brought to market, is free to enter into
physical bilateral contracts as an alternative to bidding into the PX.
These contracts will be confidential and presumably could facilitate
secret price cuts and output expansion that would further undermine the
potential for coordinated pricing behavior by sellers in the PX.").
FN ./ Hogan, Contract Networks for Electric Power Transmission, 14
J.Reg.Econ. 211, 216 (1992).
FN ./ Nevertheless, FERC conducted such an analysis in one of its
reviews of the PX and ISO. See FERC December 1996 ISO/ PX Order, mimeo
at 22.
FN ./ In the WEPEX proceedings before FERC, Edison contended that
"there will in fact be large quantities of resources chasing a
relatively small residual demand curve." Joskow MBR at II-51. In Table
14 of its submission, Edison noted that its "must-take" resources
"include [its] nuclear units (2,222 megawatts), its QF purchases (3,688
megawatts), and its purchases from other utilities (2,002 megawatts)."
Joskow MBR at II-45. Demand in "SCE's control area" ranges between a
low of around 5,670 megawatts and a peak of around 13,500 megawatts.
Accordingly, Edison roughly estimated that residual demand in its
control area will vary between 837 and 5499 megawatts. PG&E faces
similar supply and demand schedules. These amounts are a small
percentage of supplies available from California and out-of-state
suppliers in the wholesale market.
In fact, Edison argued that the capacity of the transmission system
connecting California to out-of-state suppliers easily satisfies demand.
Thus, for Edison, the lines from the desert Southwest "were never
constrained and [have been] never even particularly close to being
constrained" (Joskow MBR, at II-20) and the capacity of North to South
lines have never been fully loaded. Joshkow MBR, at II-20. similarly,
"there has been an abundance of unused transmission capability into
SCE's control area at . . . high demand times -- 5,303 megawatts on
average during summer peak hours, 6,056 megawatts on average during
summer mid-peak hours, and 6,165 megawatts on average during winter mid-
peak hours." Joskow MBR, at II-48.
The capacity of transmission lines from the Pacific Northwest
includes 3200 megawatts over the Pacific Intertie (PACI), 1600 megawatts
over the California Oregon Transmission Project (COTP) and 3500-3800
megawatts over Path 15. Pace MBF, at 24, 26.
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Power over these lines flows to southern California over the Midway to
Vincent path. Joskow MBR, at II-21. Another path, the PDCI, "goes
around PG&E's area and directly interconnects the Pacific Northwest with
southern California." Pace MBR, at 24, 28. Although Path 15 can be
individually constrained, these lines have so much excess capacity in
the aggregate that 95 percent of the time, over 2,374 megawatts of their
capacity was unused in 1995. Joskow MBR, at II-20. See also Pace MBR,
at 25.
FN ./ Hogan defines the "efficient" short-run price of transmission as
the difference between prices at delivery points. See Hogan, supra, at
214, 233.
FN ./ DeVany and Walls at 12-13, Table 2.
FN ./ Landes and Posner, Market Power in Antitrust Cases, 94 Harv.
L.Rev. 937, 978 (1981).
FN ./ Id.
FN ./ Schmalensee, On the Use of Economic Models in Antitrust: The
ReaLemon Case, 127 U.Pa.L.Rev. 994, 1010 (1979).
FN ./ Fisher, Diagnosing Monopoly, 19 Q.Rev.Econ. & Bus. 7, (Summer
1979).
FN ./ U.S. v. Connecticut National Bank, 418 U.S. 656, 668 (1974).
See also Stigler and Sherwin, The Extent of the Market, 28 J.L. Econ.
555, 556 (1985) ("[T]he market area embraces the buyers who are willing
to deal with any seller, or the sellers who are willing to deal with any
buyer, or both.")
FN ./ Spiller and Huang, On the Extent of the Market: Wholesale
Gasoline in the Northeastern United States, 33 J.Ind,.Econ. 131, 133
(1985). Spiller and Huang note: "Arbitrage costs, however, do not
necessarily separate producers in different markets. Consider the case
of two different geographic regions with one continuously exporting to
the other. Prices will differ exactly by the arbitrage costs, and the
two regions will be in the same economic market." Id. at 133 n.7.
FN ./ Areeda & Turner, 2 Antitrust Law &522a.
FN ./ See Leitzinger Rebuttal at 3, 10 (including within the relevant
market "those locations where gas is bought and sold along the
interstate gas supply network extending from [basins in the western
United States] to points of interconnection with local California gas
distribution systems"). See also Yap Direct at 29 (essentially alleging
effects in the interstate market [see Leitzinger Rebuttal at 3] and
referring to supplies from the "southwestern U.S., Rocky Mountain, and
Canadian regions," but limiting the buyers within her proposed market to
southern California customers). FERC uses "delivered gas" as the
relevant product in its analysis and IID contends that the relevant
product is "natural gas delivered to the burner tip." Taylor Direct at
32, 33. The relevant market employed by the applicants is generally
equivalent to the combined interstate gas and intrastate gas
transportation markets employed here.
FN ./ Stewart Rebuttal at 21.
FN ./ "The ability of customers to contract independently for pieces
of the network acts both to discipline price differences along the
network and bring locations across the network into competitive
association with one another. Not only does the network mean that
producers in the various basins compete and that pipelines serving the
different basins compete, it also means that
30
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producers in one basin discipline pipeline charges in other basins and
vice versa." Leitzinger Rebuttal at 16.
FN ./ Various intervenors allege a delivered gas product market, but
they apparently exclude from the geographic market delivered gas
supplies which can be economically transported to California. See FERC
at 20.
FN ./ Leitzinger Rebuttal at Exhibit JJL-2.
FN ./ Leitzinger Rebuttal at 21.
FN ./ See Yap Direct at 29 (alleging a southern California gas
procurement market).
FN ./ Interruptible and short term firm transmission are strong
substitutes for capacity rights held by SoCalGas on the El Paso and
Transwestern pipelines. Leitzinger Rebuttal at 19. Because these rates
interact so strongly with commodity prices, interstate gas
transportation is not a separate product market. Leitzinger Rebuttal at
23 (discussing "derived demand"). Similarly, "inframarginal" southwest
supplies, which have no price advantage at the California border, are
included within the broader relevant market. Leitzinger Rebuttal at 14.
Edison alleges that the price of gas at the southwest border
determines the price of gas coming from Canada and Rocky Mountain basins
because the southwest is the "marginal supply region for California."
Carpenter Direct at 24-25. It is true that prices at those basins are
very strongly related. Leitzinger Rebuttal at 13, 26. We conclude in
the absence of evidence of collusion, however, that those highly
volatile prices are competitively determined. See Carpenter Direct at
27 ("gas prices vary significantly on a daily basis").
FN ./ Market share statistics are often misleading, however, and their
value is particularly dubious when a proposed market is part of an
integrated network. This is because any grouping composed of only a
part of the network (such as the proposed capacity release and southern
California gas procurement markets) will lack the required "gap in the
chain of substitutes."
FN ./ Rebel Oil Co., Inc. v. Atlantic Richfield, 51 F.3d 1421, 1434
(9th Cir. 1995); Ryko Mfg. Co. v. Eden Serv. 828 F.2d 1215, 1232 (8th
Cir. 1987). Thus, isolated concentration figures are inherently
meaningless. See Lades and Posner, supra; Pace MBR at &23 (referring to
"concentration statistics . . . calculated slavishly or interpreted
mechanistically").
FN ./ FTC v. Indiana Fed'n of Dentists, 476 U.S. 447, 460-61 (1986);
Rebel Oil, supra, at 1434.
FN ./ Hieronymous Trans. at 2979. Prior to open access, transmission
services constituted separate product markets. See Town of Concord,
supra, at 29; Anaheim v. Edison, supra, at 64,899-64,900.
FN ./ Hieronymous Rebuttal at 11. Thus, spot prices at Palo Verde and
California "should be identical on a netback basis. That is, the Palo
Verde price should equal the California electricity price, less the cost
of interruptible transmission. The reason, simply, is that if
electricity is available from Palo Verde at a lower price than the
incremental price of producing it in California, utilities will purchase
rather than generate." Id.
FN ./ Graves Direct at 78. In 1990, a federal district court rejected
the WSCC as a relevant
31
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geographic market because plaintiff wholesale purchasers "were not
completely free to purchase bulk power from . . . other suppliers in the
wester United States." Anaheim v. Edison, supra, at 64,899. FERC Order
888, however, subsequently provided wholesale purchasers with that
freedom. See also Town of Concord, Mass. v. Boston Edison Co., 915 F.2d
17, 30 (1st Cir. 1990); Lopatka, The Electric Utility Price Squeeze as
an Antitrust Cause of Action, 31 UCLA L.Rev. 563, 611 (1984).
FN ./ Similarly, FERC found that the relevant product was: "all
capacity whose variable costs are no more than 5% above the market
price," which FERC equated with the "cost of gas-fired steam
generation." FERC June 1997 Merger Order, mimeo at 22. FERC, however,
excluded out-of-state supplies from its analysis because the "Applicants
did not prepare a delivered price analysis." Id.
FN ./ Joskow MBR at II-42.
FN ./ Edison contends that in "off-peak periods bid are likely to be
fairly close to short run variable cost (mostly fuel cost)." Graves
Direct at 96.
FN ./ Of the total WSCC capacity, coal plants account for 26 percent,
gas/ oil for 21 percent, hydro for 33 percent, nuclear for 6 percent,
geothermal for 1 percent, and remaining plants for 13 percent. Yap
Direct at 78.
FN ./ See, e.g., Roach Direct at 32, who "stacked" power plants within
the WSCC from lowest to highest cost, and excluded "plants owned by
competitive power suppliers" by "view[ing]" them as "must run." These
plants, in fact, are not must run and their incentive will be to bid
their full marginal costs, including their opportunity costs, into the
PX.
FN ./ Thus, Edison claims that, "The reason that competition from
generators outside California to import power [sic] does not counteract
the effect of higher gas prices is that the margin of the WSCC supply
curve is dominated by California gas capacity. The inexpensive hydro,
coal and nuclear capacity that is available from out-of-state (as well
as in-state) generating stations is being utilized most of the time in
any case, so it is inframarginal and does not directly affect the
electricity price." Carpenter Direct at 85-86. It is true that some
plant owners must consider the costs they incur throughout the day as
those of a joint product, requiring them to calculate all bids
simultaneously. Hieronymous Trans. at 2983-2984. See Hirshleifer,
Peaks Loads and Efficient Pricing, 72 Q.J. Econ. 451 (1958). In
general, however, out-of-state suppliers have sales alternatives
throughout the WSCC and they "are going to bid where the prices are the
highest, that's their incentive." Hieronymous Trans. at 2989.
FN ./ Edison contends that in "off-peak periods, bids are likely to be
fairly close to short run variable cost (mostly fuel cost)." Graves
Direct at 96.
FN ./ California utilities, on the other hand, will not recognize such
costs because they will be required to sell their entire output to the
Power Exchange.
FN ./ See Pace MBR at 40-41, 48, 57 (noting that swing analysis "fails
to capture one extremely important source of potential supply
responsiveness -- that is, the ability of owners with hydroelectric
resources . . . to shape the output of those resources in an effort to
maximize their
32
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value"). See also Graves Direct at 86 (explicitly recognizing the
concept of opportunity costs and its applicability to the analysis of
competition within the WSCC).
FN ./ Contrary to the positions taken by the applicants and other
parties in this proceeding, when several types of generation sell
electricity in California, gas will not be the marginal fuel, even if it
(along with coal or hydro or other types of fuel) is on the margin, and
even if gas-fired generation has the highest variable costs. See Taylor
Direct at 13, 52 (gas fired generation is "expected to be the marginal
generation"); Hieronymous Trans. at 2866; Hieronymous Rebuttal at 10
(referring to the "production of hours that gas delivered to southern
California generators is the marginal fuel).
FN ./ Hieronymous Trans. at 2980.
FN ./ While the correlation between gas and electric prices is only
.22 (Hieronymous Rebuttal at 11; Surrebuttal at 9), wholesale rates
throughout the WSCC are strong cointegrated. See De Vany and Walls,
supra.
FN ./ Moreover, as then Judge Bryer recognized in assessing the market
power of a low cost generation supplier, the "'extra profit' resulting
from lower costs is not a monopoly profit," and the existence of these
"economic rents" is "consistent with a perfectly competitive
marketplace." Town of Concord, supra at 30. In a competitive market
like the WSCC, the "opportunity costs" to a low cost firm foregoing
alternative sales will equal its scarcity rents, which are the
difference between the market price and its production costs.
FN ./ Merger Guidelines '1.01; State of N.Y. v.Kraft General Foods,
Inc., 926 F.Supp. 321, 359 (S.D.N.Y. 1995).
FN ./ Hieronymous Trans. at 2976.
FN ./ Edison contends that "for the few percent of hours near peak
demand (perhaps a few hundred out of 8760 hours per year), it is very
likely that the marginal bid will substantially exceed short run costs
of the marginal unit, particularly once the supply of peaking generation
in the region tightens up." Graves Direct at 97. In fact, the optimal
bid in a competitive auction will include variable and opportunity costs
during both peak and off-peak periods.
FN ./ Yap Direct at 49.
FN ./ See U.S. v. Syufy Enterprises, 903 F.2d 659, 672 n.21 (9th Cir.
1990).
FN ./ Hieronymous Direct at 28.
FN ./ Posner, Antitrust Law: An Economic Perspective, at 63 (1976).
It is not clear, however, whether SoCalGas has market power over those
customers whose transmission rates re at the tariff level. See State of
Ill. of ex Rel. Hartigan v. Panhandle Eastern, 730 F.Supp. 826, 905
(C.D. Ill. 1990).
FN ./ See U.S. v. Connecticut Nat'l Bank, 418 U.S. 656, 669 (1974).
FN ./ Areeda and Hovenkamp, Antitrust Law, '1015.1 (1977) Supp.).
FN ./ U.S. v. Mercy Health Services, 1995-2 Trade Cases &71,162.
FN ./ Section 7 "deals in 'probability,' not 'ephemeral
possibilities.'" U.S. v. Marine Bancorporation, Inc., 418 U.S. 602,
622-623 (1974). "There must be 'the reasonable probability' of a
substantial impairment of competition to render a merger illegal under
'7. A 'mere possibility'
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<PAGE>
will not suffice." Fruehauf Corp. v. F.T.C., 603 F.2d. 345, 351 (2nd
Cir. 1979).
FN ./ Fruehauf Corp. v. F.T.C., 603 F.2d 345, 351 (2d Cir. 1979),
citing R. Posner, Antitrust Law, An Economic Perspective 200 (1976). In
fact,the FTC and the DOJ "appear not to have challenged a purely
vertical transaction during the period from 1981-1993." Roscoe B.
Starek, III, Reinventing Antitrust Enforcement? Antitrust Enforcement
at the FTC in 1995 and Beyond, Remarks at "A New Age of Antitrust
Enforcement: Antitrust in 1995" (Marina Del Rey, CA Feb. 24, 1995).
In general, "there is but one maximum monopoly profit to be gained
from the sale of an end product." See Town of Concord, 915 F.2d 17, 23
(1st Cir. 1990) (nothing that "several members of the Supreme Court have
pointed out [this] 'widely accepted' (albeit 'counterintuitive')
economic argument"). It is for this reason that the "government's 1984
vertical merger guidelines are not concerned . . . with the possible use
of vertical integration to 'leverage' monopoly from one market into
another." Areeda & Hovenkamp, supra, &1015.1. See also 3A Areeda &
Hovenkamp, Antitrust Law, &756b at 12; Western Resources, Inc. v.
Surface Transp. Bd., 109 F.3d 782 (D.C. Cir. 1997); Alaska Airlines,
Inc. v. United Airlines, Inc., 948 F.2d 536 (1991), cert. denied, 112
S.Ct. 1603 (1992).
Relying in part upon the single monopoly rent theory, Judge (now
Supreme Court Justice) Breyer rejected a claim in town of Concord that
the defendant utility manipulated the price of input generation and
transmission services to "squ
eeze" the plaintiff in the endproduct delivered wholesale electricity
market. Here, the endproduct is also delivered wholesale electricity,
but the inputs are interstate gas, intrastate gas transmission, and
electricity transmission. "[A] price squeeze occurs when the integrated
firm's price at the first level is too high, or its price is too low,
for the independent to cover its costs and stay in business." Town of
Concord, supra, 915 F.2d at 18. The swing capacity theory advanced by
the intervenors essentially alleges that the merged entity will
"squeeze" the gas-fired plants served by SoCalGas. See Yap Direct at
67. Because SoCalGas tariff rates are not binding for all noncore
customers,t his merger presents a mixture of the regulated and
unregulated cases analyzed in the Town of Concord decision.
FN ./ Areeda & Turner, 2 Antitrust Law &527a at 376 (978).
FN ./ Apart from the issue of whether out-of-state competition
constrains SoCalGas transportation rates, it is also highly questionable
whether the merged entity would benefit from higher rates. As the
applicants note, "SDG&E's share of revenues from SONGS is subject to the
incentive-based ratemaking mechanism approved by the Commission in D.96-
01-011 and D.96-04-059. Under this mechanism, the market price of
electricity will have no impact on SDG&E's earning from SONGS through
2003." surrebuttal at 18. For other plants, higher transportation
costs will reduce the stranded costs recoverable by the merged entity
during the four year transition period, during which time AB 1890 has
"frozen" retail electricity rates. The merged entity must recover all
of these stranded costs through a Competitive Transition Charge ("CTC")
which expires in 2002.
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<PAGE>
FN ./ See WSCC, Summary of Estimated Loads and Resources (April
1997).
FN ./ Edison acknowledges the applicability of the opportunity cost
concept to the analysis of competition within the WSCC and, similarly,
that suppliers will bid into the PX what "they believe the market will
bear." Graves Direct at 86, 96.
FN ./ It is widely understood that "[a]lternative simulation models
can give substantially different results." Lande & Langenfeld, The
Evolution of Federal Merger Policy, 11 Antitrust at 9 n. 22 (Spring
1997). Thus, "the answers may come flowing out of the machine highly
dependent upon the approach, depending upon how the data are handled,
depending upon the framework, the functional form, and the method of
estimation. . . . [I]n an adversarial setting with different data sets,
lack of cooperation, and a very narrow group of players, only a few of
whom understand the technical issues, the outcome can be really skewed."
Interview with Economist Robert D. Willig, 11 Antitrust 11, at 13
(Spring 1997).
In this case, Edison and the applicants rely upon swing capacity
models to support their positions on the questions of whether the merged
entity would have the ability and incentive to manipulate California
electricity prices. The applicants' PROSYM/ MULTISM model, based upon
assumptions listed on "four inches of printout material," uses a "cost
minimization approach. . . to identify the lowest cost mix of generators
available to serve the electric load." Hartman Trans. 2434; Surrebuttal
at 5. Inputs to the model include "fuel prices, transmission line, and
pathways, and the ratings on those pathways." Hartman Trans. at 2434.
From the resulting least-cost mix, the hourly marginal clearing price is
"calculated based on the marginal generator's marginal cost and
allocation of that particular generator's commitment costs during the
peak period load period." Surrebuttal at 6. This model predicts that
increased gas prices (Hartman Trans. at 2459-2461) would reduce
electricity sales by SDG&E and other southern California gas-fired
plants (Hartman Trans. at 2449, 2452), increase sales for plants locate
din other parts of the WSCC (Hartman Trans. at 2449, 2452-55), and
reduce revenues for the merged entity (Surrebuttal at 18).
Edison employed the Inter-Regional Market Model (IREMM) of the WSCC
to predict the effect on California electricity prices of "changes in
the price of gas delivered to the California boarder. Graves Direct at
84. This model "segments" the market into California and the remainder
of the WSCC and "forecast[s] the market price of electricity by
simulating power trades between electric utilities or market areas based
on opportunities to buy and/ or sell electricity." Graves Direct at
Attachment H. The IREMM model predicts that "a 5 per cent gas price
increase translates to a 3.8 per cent electricity price increase."
Graves Direct at 85.
For reasons discussed above, we conclude that both of those models
are highly misleading because of their failures to account for
competition from low cost, out-of-state supplies. Both models also
overstate electricity revenues resulting from gas price increases
because they assume the merged entity will receive the PX price, instead
of the levels set forth in Agreement B. We do
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<PAGE>
note, however, that PROSYM/ MULTISYM, unlike IREMM, can simulate the
effects of cost increases to gas-fired plants located in southern
California. Graves Trans. at 3408. We also note Edison's admission
that a hypothesized increase in electricity revenues resulting from
higher gas prices would be more than offset by reduced transportation
revenues. Gravel Trans. at 3407.
FN ./ Riordan and Salop, Evaluating Vertical Mergers: A Post-Chicago
Approach, 63 Antitrust L.J. 513 (1995). In any event Riordan and Salop
overstate the circumstances under which variable proportion models
predict adverse competitive effects from vertical integration. See
Reiffen and Vita, Comment: IS There new Thinking on Vertical Mergers?
63 Antitrust L.J. 917 (1995). Moreover, the economic model upon which
Riordan and Salop apparently rely contains extremely limiting gage
theory assumptions which necessarily restrict its applicability. Id. at
924-33 (noting that model uses a "static . . . game to analyze premerger
equilibrium [which] shift[s] implicitly to a multi-stage, dynamic game
to analyze post-merger conduct"); Remarks of Roscoe B. Starek, III,
supra, at 8 (noting that vertical integration models "are notorious for
their lack of generality -- their inability to predict likely as
distinguished form possible, effect even under the most strictly devised
theoretical conditions -- and for ignoring procompetitive rationales for
vertical mergers that have greater empirical support"). Thus, Reiffen
and Vita warn, "[e]nforcers must have some reason to believe that a
particular model -- and a particular (anticompetitive) equilibrium of
that model -- better describes behavior than some alternative model."
Id. at 928.
FN ./ See Areeda & Hovenkamp, supra, at &759c at 38 ("When [a] primary
market monopolist integrates into a competitive secondary market, no
injury to competition is ordinarily apparent. . . . [This form of
integration] -- is a clear candidate for a rule of absolute legality.").
FN ./ See Yap Direct at 102-120.
FN ./ Yap Direct at 108.
FN ./ Ensource or some other affiliate of SoCalGas could theoretically
benefit from precisely the same machinations today." Applicants'
Opening Brief, at 112.
FN ./ A seller wishing to corner a market must be able to limit
supply. The supply of futures contacts is not "fixed," however, because
the total volume of contracts promising future delivery expands with
each new contract that is written. See Hieronymous Trans. at 2982
("People can just come piling into the market."). See also Easterbrook,
Monopoly, Manipulation, and the Regulation of Futures Market, 59 J. of
Business S103, S109 (1986 ("Entry and exit [into futures markets] are so
easy that monopoly cannot thrive."). Moreover, sellers wishing to
corner a futures market must also control the underlying commodity
market. See Sanner v. Board of Trade of City of Chicago, 62 F.3d 918,
927 (7th Cir. 1995) (recognizing that cash and futures markets move
together).
FN ./ Few, if any, futures markets have been successfully cornered
within the past 20 years. Hieronymous Trans. at 2981. See Easterbrook,
supra, 59 J. of Business at S111 n. 7 ("n one has ever seriously
alleged, let alone documented, a manipulation of a financial futures
contract"). The Hut Browers did attempt to monopolize silver futures,
but their unsuccessful efforts cost them several billion dollars.
Hieronymous Trans. at 2981; Easterbrook, supra, 59 J. Business at S110
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<PAGE>
n.5.
FN ./ See Roach Direct at 73, Yap Direct at 58-60, Beach Direct at 31.
FN ./ We agree that the merged entity may be able to enhance its
market power over intrastate gas transportation services by exercising
those options, but there is no evidence that the gas-fired generation
served by SoCalGas and these other two pipelines actually have market
power in the broad wholesale electricity market.
FN ./ See Easterbrook, The Supreme Court 1983 Term; Forward: The
Court and the Economic System, 98 Harv.L.Rev. 4, 10-12 (1984).
FN ./ A new pipeline can be built in one to four years. Steward Trans.
at 2526.
FN ./ See Schuykill Energy Resources, Inc. v. Pennsylvania Power &
Light Co., 113 F.3d 405 (3d Cir. 1997) (rejecting as speculation claims
about competitive conditions in electricity markets in the year 2001).
FN ./ Edison and other intervenors contend that the merged entity
could raise the costs of rival gas-fired generation plants by
manipulating the windows into the SoCalGas transportation system to
force re-routings or renominations of gas supplies. We conclude,
however, that SoCalGas lacks the ability to impose such costs with the
"surgical precision" alleged by these intervenors. As the applicants
point out, "there is no significant or persistent advantage to be gained
[for UEGs] by buying at one location over the others." Leitzinger
Rebuttal at 26. In fact, when SoCalGas imposes Rule No. 30
restrictions, customers may still deliver up to the sum of 110% of their
expected daily usage plus their firm storage injection rights. Stewart
Rebuttal at 6. Thus, overnominations have not caused any plant to
curtail operations within the past several years. Hieronymous Rebuttal
at 8.
FN ./ To preclude the transfer of "inside" information, the applicants
have also agreed to maintain an interactive EBB reservation and
information system for its gas transportation network which would report
all significant operational data, including maintenance and system
status information. In addition, SDG&E will separately nominate and
schedule its UEG volumes over the EBB and obtain CPUC approval before
providing transportation discounts to any affiliates. Finally, groups
responsible for gas operations will operate independently the gas
acquisitions and marketing groups and of SDG&E employees providing
"electric merchant functions."
FN ./ The Southern California Public Power Authority contends that the
merger will adversely affect competition within an alleged "BTU" product
market. Sinclair Direct at 21. The Power Authority fails, however, to
provide any evidence of a significant cross-elasticity of demand between
electricity and gas. See United States v. E.I. du Pont de Nemours &
Co., 351 U.S. 377, 404 (1956). In fact, there is a significant cost
difference between gas and electricity for those applications were
substitution is theoretically possible. Hieronymous Rebuttal at 32.
Moreover, evidence that the two resources are jointly marketed is wholly
inconclusive, and may suggest that they are actually complements. We
conclude that a significant "gap" exists in the "chain" between these
two hypothetical substitutes, and that "BTUs" is not a cognizable
relevant product for purposes of reviewing this merger.
FN ./ Yap Direct at 32.
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<PAGE>
FN ./ Yap Direct at 34.
FN ./ Leitzinger Rebuttal at Exhibit JJL-2.
FN ./ In fact, because the procurement activities of the two companies
will not be combined, market share statistics overstate the market power
of the combined entity. See Leitzinger Rebuttal at 28.
FN ./ Until recently, PUC rules prohibited the companies from
competing for sales to core customers. Hieronymous Rebuttal at 30.
FN ./ Hieronymous Rebuttal at 30.
FN ./ Id.
FN ./ Hieronymous Rebuttal at 31.
FN ./ Id.
FN ./ Stewart Trans. at 2781.
FN ./ Broadley, Potential Competition under the Merger Guidelines, 71
Ca. L.Rev. 376, 378 (1983). Areeda and Hovenkamp also question the
doctrine as a basis for a section 7 violation. Agreeda and Hovenkamp,
Antitrust Law ' 1118 (1996 Supp.).
FN ./ Marine Bancorporation, supra, at 630-32.
FN ./ See Yap Direct at 48, 55; Taylor Direct at 53. But see Stewart
Rebuttal at 32 (noting that SDG&E loads are increasingly fragmented).
FN ./ Tenneco v. F.T., 689 F.2d 346 (2d Cir. 1982). See B.A.T.
Indus., 104 F.T.C. 852 (the "best evidence . . . is likely to be
subjective").
FN ./ See BOC Int'l Ltd. v. FTC, 557 F.2d 24, 29 (2d Cir. 1977)
(rejecting a finding of "eventual" entry as "uncabined speculation").
FN ./ Republic of Texas Corp. v. Board of Governors of the Fed.
Reserve Sys., 649 F.2d 1026, 1047 (5th Cir. 1981) (demonstrating entry
in the "reasonably foreseeable future" was insufficient); BOC Int'l,
supra, 557 F.2d at 29.
FN ./ Tenneco, supra, at 355; Merger Guidelines ' 4.11.
FN ./ Exhibit 3985 at Response to Request 6.16.
FN ./ Id.
FN ./ Yap Direct at 53.
FN ./ Yap Direct at 184.
FN ./ The anchor tenant theory advanced by some intervenors, although
presented as a potential competition question, essentially alleges that
the merger will vertically "foreclose" opportunities for Kern River and
other competitors in the intrastate gas transportation market. The
issue may have been reframed because the courts view foreclosure
allegations in vertical merger cases with considerable skepticism. See
Alberta Gas Chems. v. E.I. du Pont de Nemours, 826 F.2d 1235, 1244 (3d
Cir. 1987) cert. denied, 486 U.S. 1059 (1988); 4 Areeda & Turner,
Antitrust Law & 1004, at 211 (foreclosure argument has "grave
weaknesses").
FN ./ Yap Direct at 61.
FN ./ Taylor Direct at 35.
FN ./ Mercantile Texas Corp., 638 F.2d at 1267. See also U.S. v.
First National State
38
<PAGE>
Bancorporation, 499 F. Supp. 793, 814 (D.N.J. 1980).
FN ./ Hieronymous Rebuttal at 42-43.
FN ./ Hieronymous Rebuttal at 43.
