Untitled California Attorney General Opinion

TO BE PUBLISHED IN THE OFFICIAL REPORTS

OFFICE OF THE ATTORNEY GENERAL

State of California

DANIEL E. LUNGREN

Attorney General

______________________________________

OPINION :

: No. 97-1216

of :

: January 2, 1998

DANIEL E. LUNGREN :

Attorney General :

:

J. LINDSAY BOWER :

Deputy Attorney :

General

:

______________________________________________________________________

THE PUBLIC UTILITIES COMMISSION has requested an advisory opinion, pursuant to

Public Utilities Code section 854, on the following questions:

1. Will the proposed merger between Pacific Enterprises and Enova Corporation

adversely affect competition?

2. What mitigation measures could be adopted to avoid any adverse effects on

competition that do result?

CONCLUSIONS

1. The proposed acquisition between Pacific Enterprises and Enova Corporation 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.

ANALYSIS

The proposed merger of Pacific Enterprises and Enova Corporation is a response to the

mandatory restructuring of the electric industry which began 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. In any event, SoCalGas

cannot significantly increase the costs of southern California gas-fired plants, whose gas prices

are determined in the competitive interstate market and most of whose intrastate transportation

rates are at their regulatory caps.

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 of reexamining the question of

whether the merged entity has used its intrastate gas transmission system for the purpose of

manipulating the price of electricity it sells in the wholesale market.

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. Footnote No. 1 NewCo Enova

Sub would merge 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. Footnote No. 2 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." Footnote No. 3 The applicants subsequently incorporated those conditions,

along with other proposed restrictions, within their merger application. Footnote No. 4

B. This Advisory Opinion

This is the fifth opinion letter submitted by this office under the 1989 amendments to

Section 854. Footnote No. 5 Public Utility Code section 854 refers to the opinion as advisory.

Footnote No. 6 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.

Footnote No. 7 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 plants.

SDG&E, which actively buys and sells power in the wholesale market, Footnote No. 8 sells

electricity to 1.2 million retail customers in San Diego and southern Orange Counties (including

parts of the SoCalGas service area). SDG&E also purchases gas in the interstate market, Footnote

No. 9 which it distributes within its separate service areas. Footnote No. 10 SDG&E provides no gas

transmission services outside of San Diego County. Footnote No. 11 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." Footnote No. 12 The applicants

also recently purchased AIG Trading, a natural gas and electricity marketer and a trader in

financial markets for electricity and gas contracts. Footnote No. 13 Both of those companies are

actively involved in the electricity and gas markets in California. This section discusses intrastate

gas transmission services supplied by SoCalGas and SDG&E purchases and sales in the

restructured electric industry. Interstate gas and electric 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, Footnote No. 14 with "access to adequate quantities of capital on favorable

terms." The parties also believe that the merged company will achieve certain efficiencies and

will respond more effectively to customer demand for 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. Footnote No. 15 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, Footnote No. 16 and the remaining 17 percent from the San Onofre

Nuclear Generating Station (SONGS). Footnote No. 17 In 1996, the peak load for the SDG&E

system was 3,299 MW. Footnote No. 18

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

establish a single clearing price for all hourly transactions. Footnote No. 19 Participating

distribution companies and end users will submit "demand side" bids to the PX. Footnote No. 20

Generation plants and marketers will simultaneously submit advance supply bids. Footnote No. 21

The total capacity of WSCC members, including capacity divested from Edison and PG&E,

Footnote No. 22 which can bid into the PX exceeds 150,000 MW. Footnote No. 23 From the

resulting demand and supply schedules, the PX will establish Footnote No. 24 the market "clearing

price" governing all purchases and included sales. Footnote No. 25

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 Footnote No. 26 -- will be sold at their variable operating costs. Footnote No. 27 The ISO

Governing Board "has chosen all of SDG&E's units for Must-Run status." Footnote No. 28 Must-

take resources, which include SONGS and other nuclear plants, qualifying facilities (QFs) and

pre-existing power contracts, Footnote No. 29 provide more than half of the electricity

requirements of the California IOUs. Footnote No. 30 A "performance incentive mechanism . . .

will isolate SONGS revenue received by SDG&E from the PX price." Footnote No. 31 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" Footnote No. 32 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." Footnote No. 33 The remaining ten

percent will apparently be applied to SDG&E stranded costs through the competitive transition

charge (CTC) mechanism. Footnote No. 34 On October 30, 1997, FERC concluded that this

arrangement "adequately mitigate[s] [SDG&E's] generation market power for PX sales of

energy." Footnote No. 35

In conjunction with the PX, the ISO will coordinate intrastate power flows and provide

open access to the California transmission grid. Footnote No. 36 On January 1, 1998, all

participants will transfer operational control of their transmission facilities to the ISO. Footnote

No. 37 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. Footnote No. 38 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. Footnote No. 39

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 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. Footnote No. 40 In the northern part of its service area, SoCalGas receives gas from

PG&E at Kern River Station and Pisgah, Footnote No. 41 and from the Kern River and Mojave

lines at Wheeler Ridge and Hector Road. Footnote No. 42 The SoCalGas system is capable of

receiving approximately 3.5 Bcf/d at these connection points. Footnote No. 43

The SoCalGas Acquisition Group purchases about 1000 MMcf/d, which is ultimately

transported to core customers. Footnote No. 44 SoCalGas noncore transportation customers include

Edison, members of SCUPP, SDG&E, the City of Long Beach, and various large commercial

and industrial customers. Footnote No. 45 SoCalGas supplies 42 gas-fired generation plants,

including plants owned by SDG&E, Edison, Imperial Irrigation District (IID) and SCUPP

members. Footnote No. 46 These plants have a total generating capacity of 15,837 MW. Footnote

No. 47 SoCalGas is the only intrastate gas pipeline to which SCUPP members can feasibly

connect. Footnote No. 48

To coordinate deliveries to these customers and to preserve "system integrity," Footnote No.

49 SoCalGas calculates in advance of "flow day" Footnote No. 50 a system "window" from the

difference between estimated overall next-day demand Footnote No. 51 and local Footnote No. 52

California gas production. Footnote No. 53 This "take away" capacity figure is then adjusted by

anticipated injection or withdrawal volumes Footnote No. 54 for SoCalGas storage fields, Footnote

No. 55 which according to Edison "are used to satisfy the majority -- approximately 57% -- of

peak day demand." Footnote No. 56 Windows are also established at each of the individual receipt

points. Footnote No. 57 SoCalGas uses a variety of procedures, including "custody cut" Footnote No.

58 and Rule No. 30 restrictions, Footnote No. 59 to achieve system balance when demand

"nominations" for core and noncore customers exceed system or individual receipt point

windows. Footnote No. 60

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

transportation, even though it still prohibits "brokering on the intrastate system." Footnote No. 61

The GasSelect electronic bulletin board, "an interactive same-time Footnote No. 62 reservation and

information system," Footnote No. 63 provides information within this secondary market about

intrastate transportation transactions between SoCalGas and its affiliates. Footnote No. 64

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. Footnote No. 65 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. Footnote No. 66 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." Footnote No. 67

This competition has induced SoCalGas to "provide discounted Footnote No. 68

transportation rates and associated cost saving to numerous customers [perhaps including

SDG&E Footnote No. 69] on its system." Footnote No. 70 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. Footnote No. 71 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. Footnote No. 72

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. Footnote No. 73

To mitigate the resulting losses, the PUC has required customers to pay SoCalGas an ITCS

(Interstate Transportation Cost Surcharge) Footnote No. 74 to help recover certain fixed capacity

costs. Footnote No. 75

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. Footnote No. 76 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. Footnote No. 77 Production and interstate transmission

services within both of those markets are highly integrated at the California border. Moreover,

California 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." Footnote No. 78 As a result of FERC's

deregulatory policies, "an active and viable spot market has developed for gas." Footnote No. 79

FERC transformed the gas industry by providing open access to interstate pipelines,

removing all controls over the wellhead price of natural gas, Footnote No. 80 and establishing

secondary markets for storage and pipeline capacity. Footnote No. 81 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. Footnote No. 82 Because end users attempt to minimize their

"delivered prices," Footnote No. 83 competitive forces have also linked the production and

transmission markets.

FERC's open access policies, instituted in Orders 436 Footnote No. 84 and 636, required that

interstate pipelines separate gas sales from transportation services, Footnote No. 85 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 Footnote No. 86 by allowing "holders of unutilized firm capacity [to resell] them in

competition with any capacity offered directly by the pipeline." Footnote No. 87 Previously,

shippers were only able to purchase capacity rights directly from pipelines. Footnote No. 88 Under

Order 636, shippers who wish to sell (i.e. "release") their firm capacity rights must first offer

Footnote No. 89 those rights on the pipeline's electronic bulletin boards ("EBB") Footnote No. 90,

which carry "information about available and consummated capacity release transactions."

Footnote No. 91

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. Footnote No.

92 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. Footnote No. 93 Pacific Gas Transmission Company ("PGT"), a

PG&E subsidiary, transports gas from Canada to the California border on its own 1.89 Bcf/d

pipeline. Coupled with downstream pipeline system operated by SoCalGas and SDG&E, PG&E

can serve end users in most of California. Footnote No. 94 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. Footnote No.

95 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. Footnote No. 96 In other instances,

customers have substituted by transporting over the same pipeline to California gas purchased in

entirely different basins. Footnote No. 97 Customers committed to a particular supply source can

also substitute between firm contracts and capacity released in the secondary market. Footnote No.

98 Commodity and transportation markets are also linked, Footnote No. 99 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. Footnote No. 100

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." Footnote No. 101 Through Order 888 and earlier mandates, Footnote No. 102 FERC

simultaneously encouraged open access and other "wheeling" transactions between non-

contiguous buyers and sellers. Footnote No. 103 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." Footnote No. 104

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." Footnote No. 105 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." Footnote No. 106 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, Footnote No.

107 exceeds 150,000 MW. Footnote No. 108

As a result of industry deregulation, suppliers can now sell to any purchaser on the grid.

Footnote No. 109 In fact, the availability of displacement contracts and the physics of electricity

transmission has rendered irrelevant transmission constraints between any two points within the

network. Footnote No. 110 The existence of "loop flows," Footnote No. 111 in particular, means that

power in a network "moves across many parallel lines in often circuitous routes." Footnote No. 112

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. Footnote No. 113 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. Footnote No. 114 Using data from 1994-1996

transactions, De Vany 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.

Footnote No. 115 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 Footnote No. 116 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. Footnote No. 117

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. Footnote No. 118 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. Footnote No. 119

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. Footnote No. 120 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. Footnote No. 121

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. Footnote No. 122 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, Footnote No. 123 reflecting the system's low variable supply costs. Implicit peak

hour transmission rates are higher, but wholesale electricity prices at the four delivery points

during those times remain cointegrated within arbitrage bounds. Footnote No. 124 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." Footnote No. 125 In theory, the horizontal and vertical

dimensions of the relevant market are "immaterial." Footnote No. 126 In fact, however, empirical

limitations require a "noticeable 'gap in the chain'" of substitutes and complements. Footnote No.

127 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. Footnote No. 128

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. Footnote No. 129 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 the 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." Footnote No. 130 Accordingly, "[p]rice

relationships are clearly the best single guide to geographic market definition." Footnote No. 131

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. Footnote No. 132 In a gas network, the ability of a customer

(like SoCalGas) to deviate rates from competitive levels is determined by conditions at the

wellhead, within the network itself, and at the ultimate delivery points. As noted above, users

base their purchasing decision upon the overall delivered cost of the commodity, not the price at

a particular 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, Footnote

No. 133 and across these various service levels. Footnote No. 134 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.

Footnote No. 135 In 1995, total average production by these basins was 24,000 MMcf/d. Footnote

No. 136 Estimated peak day supplies to California are 3,536 MMcf/d. Footnote No. 137 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. Footnote No.

138 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. Footnote No. 139

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,

Footnote No. 140 entry barriers, and the short-run ability of existing competitors to increase their

output. Footnote No. 141 The courts also recognize the use of "direct evidence" to resolve market

power questions. Footnote No. 142 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 in the natural gas industry, customers purchase wholesale electricity as

the "delivered" combination of generation and transmission services. Footnote No. 143 Thus, the

relevant market includes all suppliers whose combined "netback" and transportation costs would

be competitive at California delivery points. Footnote No. 144 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." Footnote No. 145

The relevant product market includes "all" effectively unregulated delivered electricity

which can compete in the Power Exchange for residual wholesale electricity demand. Footnote No.

146 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

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" Footnote No. 147 within some range

Footnote No. 148 of the variable costs of producing electricity on Edison and other WSCC gas-

fired plants. Intervenors contend that gas-fired plants 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 Footnote No. 149 that are equally likely to establish the clearing

price. Footnote No. 150

Intervenors exclude these other generation sources by implicitly assuming that out-of-state

participants do not incur opportunity costs. Footnote No. 151 Theoretically, PX participants will

offer wholesale electricity at their marginal supply costs, including fuel and other variable

production expenses. Footnote No. 152 In addition, however, the relevant economic cost to out-of-

state sellers Footnote No. 153 will include returns foregone by selling to the Power Exchange

instead of other western United States buyers. Footnote No. 154 The existence of these opportunity

costs explains why gas is not "the" marginal fuel, Footnote No. 155 why out-of-state suppliers will

equalize the PX and prevailing WSCC prices Footnote No. 156 and, at least in part, why gas and

electricity prices are weakly correlated in southern California. Footnote No. 157 Their existence

also means that the relevant product market includes the output of "inframarginal," out-of-state

suppliers. Footnote No. 158

2. The Temporal Dimension

Similarly, the relevant market is not time-sensitive. A relevant market includes all firms

which would respond to a hypothetical "small but significant and nontransitory" price increase.

Footnote No. 159 These firms include plants which are already "committed" to the market, but

which make no contemporaneous sales. Accordingly, the relevant wholesale electricity market

during peak periods includes all out-of-state WSCC suppliers.

As discussed above, WSCC suppliers can sell electricity throughout the grid during both

peak and off-peak hours. Footnote No. 160 Some intervenors have suggested that the relevant

market will be limited during peak hours. Footnote No. 161 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 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 EOR 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. Footnote No. 162 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. Footnote No. 163 SoCalGas also price discriminates between transportation customers, and

can sometimes discount without Commission approval. Footnote No. 164 The ability to persistently

price discriminate between similarly situated customers also implies that a seller possesses

market power. Footnote No. 165

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. Footnote No. 166 Under the DOJ/FTC Guidelines, the effects of a

"horizontal" merger depend upon several related factors, including changes in concentration

levels, entry conditions, and 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." Footnote No. 167 A failure to properly define the relevant markets is fatal to a

plaintiff's prima facie case. Footnote No. 168 A plaintiff must also demonstrate "probabilities"--not

"ephemeral possibilities"--of anticompetitive effects within those markets. Footnote No. 169

A. The Vertical Integration of SoCalGas Intrastate Gas Transmission and SDG&E

Wholesale Electricity Operations

Although this merger has some horizontal features, 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." Footnote No. 170 This is because, unlike horizontal consolidations, vertical

mergers do not eliminate competitors from the market. Footnote No. 171 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.

Even without the restrictions of Agreement B, however, SoCalGas could not significantly

increase the costs of SDG&E's southern California competitors, whose gas prices are determined

in the competitive interstate market and most of whose intrastate transportation rates are already

at their regulatory caps. (Their current transportation rates are binding because the Commission

prohibits SoCalGas from raising intrastate rates above existing tariff levels, which SoCalGas has

discounted for only a small minority of the plants it serves. Footnote No. 171.1) Moreover, out-of-

state suppliers would defeat any attempt by the merged entity to manipulate the price of

wholesale electricity sold in southern California. Footnote No. 172 The total capacity of plants

supplied by SoCalGas is 15,837 MW. These plants will compete for end-users who can purchase

electricity through the PX or through "direct access" agreements, with aggregate WSCC, out-of-

state capacity exceeding 100,000 MW. Footnote No. 173 Because out-of-state suppliers account for

their opportunity costs Footnote No. 174 and because of the absence of entry barriers faced by out-

of-state suppliers wishing to make such sales, the resulting PX price will equal the prevailing

WSCC spot price. Footnote No. 174.1 Price data -- as opposed to simulation models -- demonstrate

that WSCC prices are competitively determined. Footnote No. 174.2 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

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, Footnote No. 175 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. Footnote No.

176 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 generation plants). Footnote No. 177 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. Footnote No. 178 Thus, they contend, the merged entity would

essentially trade on "inside" information. Footnote No. 179 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. Footnote No. 180 Moreover, adverse

effects upon competition within the futures markets -- which are characterized by their liquidity

and ease of entry and exit Footnote No. 181 -- are extremely unlikely. Footnote No. 182 In any event,

the hypothetical conduct would be unlawful under the Commodity Futures Trading Commission

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 California

operations of the Kern River and Mojave pipelines. Footnote No. 183 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.

Footnote No. 184

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. Footnote No. 185 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 alternative suppliers a

substantial period in which to respond the possible exercise of these options. Footnote No. 186 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. Footnote

No. 187 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 plants and other potential "bypass" customers. The merger will not provide new

opportunities for profitable price or non-price Footnote No. 188 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 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. Footnote No. 189

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. Footnote No. 190 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 Footnote No. 191 and 255 Footnote No. 192 MMcf/d, respectively, while

total production in the relevant interstate market averaged 24,000 MMcf/d. Footnote No. 193 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

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. Footnote No. 194

The merger will also combine the two companies' partially deregulated non-core gas

retailing functions. Footnote No. 195 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. Footnote No. 196 Moreover, neither firm has made non-core sales outside

its service area. Footnote No. 197 In 1996, total non-core sales in southern California averaged

1821 MMcf/d. Footnote No. 198 SoCalGas and SDG&E sales to non-core customers during that

year averaged 58 and 144 MMcf/d, respectively. Footnote No. 199 We conclude that the

consolidation of these non-competing, relatively limited operations will not adversely affect

competition for non-core retail services.

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, Footnote No. 200 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 Footnote No. 201 -- applies if the acquiring firm

would have "probably" entered a concentrated market, thereby providing significant

procompetitive effects. Footnote No. 202 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. Footnote No. 203 The courts, however, require showings of an intent to enter Footnote

No. 204 that go beyond evidence of generalized abilities and incentives. To avoid speculation,

Footnote No. 205 they also require a showing that entry will occur, not in the "reasonably

foreseeable" future, but in the near future. Footnote No. 206 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." Footnote No. 207 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. Footnote

No. 208 SDG&E considered at least two other bypass proposals during the next six years. Footnote

No. 209 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." Footnote No.

210

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, Footnote No. 211

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," Footnote No. 212 the 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."

Footnote No. 213 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, 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. Footnote No. 214 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." Footnote No. 215

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. Footnote No. 216 Furthermore, SoCalGas has no competitive retail affiliates

and limited experience within the electricity industry. Footnote No. 217 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.

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, 1998. 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 manipulate 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 SoCalGas intrastate transportation

system. Thus, we recommend that 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.

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 and because SoCalGas cannot significantly increase

either the gas prices or the transportation rates paid by southern California gas-fired plants. 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.

*****

Footnote No. 1

Application at 26.

Footnote No. 2 See San Diego Gas & Electric Co., 79 FERC par. 61,372 (1997)("FERC June 1997 Merger

Order").

Footnote No. 3

Exhibit 14, Chapter 3, at 11 ("Stewart Rebuttal").

Footnote No. 4

Stewart Rebuttal at 9-10.

Footnote No. 5

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).

Footnote No. 6

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.

Footnote No. 7

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.

Footnote No. 8

SDG&E wholesale sales are "economy energy sales and short-term sales of capacity." FERC June 1997 Merger

Order, mimeo at 6.

Footnote No. 9

Exhibit 2 at 30 ("Hieronymous Direct").

Footnote No. 10

According to SCUPP, SDG&E "represents a total load of about 350 MMcfd." Exhibit 105 at 52 ("Yap Direct").

Footnote No. 11

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").

Footnote No. 12

Application at 30.

Footnote No. 13

The applicants state that AIG is the nation's 15th largest gas marketer and the 19th largest 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").

Footnote No. 14

Hieronymous Direct 6.

Footnote No. 15

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 par. 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 par. 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 par. 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 par. 61,128 (1997) ("FERC July 1997 ISO/PX Order").

Footnote No. 16

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").

Footnote No. 17

Hieronymous Direct at 5. Firm purchases during 1996 were 1,434 MW. Id.

Footnote No. 18

Hieronymous Direct at 5 n. 7.

Footnote No. 19

"After the transition period, the Companies' participation in the PX will be voluntary." FERC December 1996

ISO/PX Order, mimeo at 2.

Footnote No. 20

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.

Footnote No. 21

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 that zone for each hour." FERC December 1996 ISO/PX

Order, mimeo at 3.

Footnote No. 22

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.

Footnote No. 23

Graves Direct at 84.

Footnote No. 24

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.

Footnote No. 25

"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.

Footnote No. 26

"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 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.

Footnote No. 27

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.

Footnote No. 28

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."

Footnote No. 29

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 par. 30: Affidavit of Joe D. Pace ("Pace MBR").

Footnote No. 30

Pace MBR at par. 27.

Footnote No. 31

Hieronymous MBR at III-15.

Footnote No. 32

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.

Footnote No. 33

FERC October 1997 ISO/PX Order, supra, mimeo at 251; Hieronymous Rebuttal at 5 n. 1.

Footnote No. 34

Proposed Decision of ALJ Minkin, A.96-08-001, slop op. at 50 (Oct. 20, 1997).

Footnote No. 35

FERC October 1997 ISO/PX Order, supra, mimeo at 233-235.

Footnote No. 36

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

Footnote No. 37

See Hieronymous Direct at 21.

Footnote No. 38

FERC November 1996 ISO/PX Order, supra at 61,799.

Footnote No. 39

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).

Footnote No. 40

Stewart Rebuttal at 4.

Footnote No. 41

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.

Footnote No. 42

Stewart Rebuttal at 4. Edison claims, though, that SoCalGas does not "list Hector as a delivery point." Carpenter

Direct at 37-38.

Footnote No. 43

Stewart Rebuttal at 4. IID estimates that the system capacity is 3,700 MMcfd. Exhibit 104 at 23 ("Taylor Direct").

Footnote No. 44

Stewart Rebuttal at 9.

Footnote No. 45

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.

Footnote No. 46

Exhibit 115 at 25 ("Roach Direct"); Taylor Direct at 6.

Footnote No. 47

Id.

Footnote No. 48

SCUPP alleges that the intrastate system is an "essential facility." Yap Direct at 65.

Footnote No. 49

Stewart Trans. at 2595.

Footnote No. 50

Stewart Trans. at 2556.

Footnote No. 51

SoCalGas estimates core demand from a statistical model and noncore demand from gas nomination information.

Stewart Rebuttal at 5.

Footnote No. 52

"[O]ut-of-state sources supplied the vast majority -- approximately 84% -- of the total demand in southern California

in 1996." Carpenter Direct at 21.

Footnote No. 53

Stewart Rebuttal at 5.

Footnote No. 54

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").

Footnote No. 55

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.

Footnote No. 56

Carpenter Direct at 49.

Footnote No. 57

Stewart Trans. at 2401; Stewart Rebuttal at 7.

Footnote No. 58

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.

Footnote No. 59

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.

Footnote No. 60

Stewart Trans. at 2406-2409, 2547-2555; Stewart Rebuttal at 6-7.

Footnote No. 61

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").

Footnote No. 62

SoCalGas estimates that it posts transactions on GasSelect "within the hour." Stewart Trans. at 2578.

Footnote No. 63

Stewart Trans. at 2575-2576, 2583.

Footnote No. 64

Stewart Trans. at 2577.

Footnote No. 65

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: 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.

Footnote No. 66

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.

Footnote No. 67

Roach Direct at 25.

Footnote No. 68

Hieronymous Direct at 28.

Footnote No. 69

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).

Footnote No. 70

Larsen Direct at 9. See Stewart Trans. at 2744 ("we compete vigorously against 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).

Footnote No. 71

Yap Direct at 50.

Footnote No. 72

Stewart Rebuttal at 31. See Leitzinger Rebuttal at 31.

Footnote No. 73

Stewart Rebuttal at 20.

Footnote No. 74

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.

Footnote No. 75

See Stewart Trans. at 2744.

Footnote No. 76

Leitzinger Rebuttal at 8.

Footnote No. 77

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").

Footnote No. 78

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." De Vany and Walls, The Emerging New

Order in Natural Gas, at 5 (Quorum Books 1995).

Footnote No. 79

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) par. 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).

Footnote No. 80

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 entitlments 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).

Footnote No. 81

DOE/EIA, supra, at 40.

Footnote No. 82

Leitzinger Rebuttal at 16.

Footnote No. 83

Leitzinger Rebuttal at 25.

Footnote No. 84

Regulation of Natural Gas Pipelines after Partial Wellhead Decontrol, F.E.R.C. Stats. and Regs. par. 30,665 (1985),

vacated and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C.Cir. 1987).

Footnote No. 85

Doane & Spulber, supra, at 477; Order 636, supra, at 30,396.

Footnote No. 86

"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., 88 F.3d 1105, 1149 (D.C.Cir. 1996). See also Samuels, The D.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.").

Footnote No. 87

"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.

Footnote No. 88

Id.

Footnote No. 89

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 has absolute discretion in establishing its opening bid with evidence that "over 70 percent of all SoCalGas

capacity releases occur at prices under the initial opening offer." Stewart Rebuttal at 25; Leitzinger Rebuttal at 25.

Footnote No. 90

Leitzinger Rebuttal at 19. "[E]ach interstate pipeline is required to establish and administer an electronic bulletin

board ('EBB') . . . The EBB caries 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.

Footnote No. 91

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.").

Footnote No. 92

Leitzinger Rebuttal at 21. See Yap Direct at 21.

Footnote No. 93

Stewart Rebuttal at 22. Transwestern and El Paso substantially increased the capacity of those pipelines in 1991, and

again in 1996. Leitzinger Rebuttal at 24. See Stewart Rebuttal at 23.

Footnote No. 94

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.

Footnote No. 95

Leitzinger Rebuttal at 16; Leitzinger Trans. at 3148, 3155.

Footnote No. 96

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.

Footnote No. 97

Leitzinger Trans. at 3164. Edison notes that El Paso and Transwestern carry gas to California "from Canada via

Northwest pipelines." Carpenter Direct at 21.

Footnote No. 98

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.)

Footnote No. 99

Leitzinger Rebuttal at 16.

Footnote No. 100

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").

Footnote No. 101

Black and Pierce, supra, at 1348.

Footnote No. 102

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) par. 31,036 (1996). FERC also effectively deregulated non-firm transmission services. Id. at 31,743.

Footnote No. 103

Black and Pierce, supra, at 1349.

Footnote No. 104

Black and Pierce, supra, at 1350.

Footnote No. 105

Cities of Anaheim, Cal., et al. v. Southern Cal. Edison Co., 1990-2 Trade Cases par. 69,246 at 64,899-64,900

(C.D.Ca. 1990), affd. 955 F.2d 1363 ("Anaheim v. Edison").

Footnote No. 106

Exhibit 379 at 4: DeVany and Walls, Open Transmission and Spot Markets for Power (July 1997)("De Vany 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 par. 61,158 (1995); NWRTA, 71 FERC par.

61,397 (1995).

Footnote No. 107

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 par. 61,099 at 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").

Footnote No. 108

Graves Direct at 84. The annual average WSCC load is 82,000 MW. Graves Direct at 79.

Footnote No. 109

"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." De Vany and Walls, supra, at 6.

Footnote No. 110

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.

Footnote No. 111

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."). Thus, loop flows can be broadly defined to include all flows "parallel" to

the "direct" path between two points. See Watkiss and Smith, The Energy Policy Act of 1992 -- A Watershed for

Competition in the Wholesale Power Market, 10 Yale J. on Reg. 447, 479 (1993) ("The difference between

hypothetical flows on the contract path (point A directly to point B) and the actual electrical flows according to

physical laws is referred to as 'loop flow' or parallel path, which is generally defined 'as the difference between

scheduled and actual flow of electricity over a given established transfer path'"). We recognize, however, that loop

flows can impose uncompensated costs ("externalities") on owners of parallel transmission systems and that some

observers reserve the term for flows which are outside the transmission control area serving the parties to a

particular transaction. See Fox-Penner, Electric Power Transmission and Wheeling, at 56 (Edison Electric Institute,

1990).

Footnote No. 112

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").

Footnote No. 113

Hieronymous Trans. at 2976. Although they are now rare, displacement contracts provide a mechanism that is

available to arbitrage price differentials resulting from "pancaking" and similar effects that might otherwise render

transmission costs prohibitive.

Footnote No. 114

DeVany and Walls, supra, at 3 n.2.

Footnote No. 115

De Vany and Walls, supra, at 2, 15.

Footnote No. 116

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 Rates 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.").

Footnote No. 117

Hieronymous Trans. at 2978.

Footnote No. 118

"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." 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.

Footnote No. 119

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.").

Footnote No. 120

Hogan, Contract Networks for Electric Power Transmission, 14 J.Reg.Econ. 211, 216 (1992).

Footnote No. 121

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.

Footnote No. 122

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. Joskow 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 MBR, at 24, 26. 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.

Footnote No. 123

Hogan defines the "efficient" short-run price of transmission as the difference between prices at delivery points. See

Hogan, supra, at 214, 233.

Footnote No. 124

De Vany and Walls at 12-13, Table 2.

Footnote No. 125

Landes and Posner, Market Power in Antitrust Cases, 94 Harv. L.Rev. 937, 978 (1981).

Footnote No. 126

Id.

Footnote No. 127

Schmalensee, On the Use of Economic Models in Antitrust: The ReaLemon Case, 127 U.Pa.L.Rev. 994, 1010

(1979).

Footnote No. 128

Fisher, Diagnosing Monopoly, 19 Q.Rev.Econ. & Bus. 7, 15 (Summer 1979).

Footnote No. 129

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.").

Footnote No. 130

Spiller and Huang, On the Extent of the Market: Wholesale Gasoline in the Northeastern United States, 35

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.

Footnote No. 131

Areeda & Turner, 2 Antitrust Law par. 522a.

Footnote No. 132

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.

Footnote No. 133

Stewart Rebuttal at 21.

Footnote No. 134

"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 producers in one basin discipline pipeline charges in other basins and vice versa."

Leitzinger Rebuttal at 16.

Footnote No. 135

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.

Footnote No. 136

Leitzinger Rebuttal at Exhibit JJL-2.

Footnote No. 137

Leitzinger Rebuttal at 21.

Footnote No. 138

See Yap Direct at 29 (alleging a southern California gas procurement market).

Footnote No. 139

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").

Footnote No. 140

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."

Footnote No. 141

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 Landes and Posner,

supra; Pace MBR at par. 23 (referring to "concentration statistics . . . calculated slavishly or interpreted

mechanistically").

Footnote No. 142

FTC v. Indiana Fed'n of Dentists, 476 U.S. 447, 460-61 (1986); Rebel Oil, supra, at 1434.

Footnote No. 143

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.

Footnote No. 144

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.

Footnote No. 145

Graves Direct at 78. In 1990, a federal district court rejected the WSCC as a relevant geographic market because

plaintiff wholesale purchasers "were not completely free to purchase bulk power from . . . other suppliers in the

western 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).

Footnote No. 146

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.

Footnote No. 147

Joskow MBR at II-42.

Footnote No. 148

See Graves Direct at 79 (referring to all generation within one standard deviation of the 82,000 MW average WSCC

load).

Footnote No. 149

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.

Footnote No. 150

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.

Footnote No. 151

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, Peak 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.

Footnote No. 152

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.

Footnote No. 153

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.

Footnote No. 154

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 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).

Footnote No. 155

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 "proportion of hours that gas delivered to southern California

generators is the marginal fuel).

Footnote No. 156

Hieronymous Trans. at 2980.

Footnote No. 157

While the correlation between gas and electric prices is only .22 (Hieronymous Rebuttal at 11; Surrebuttal at 9),

wholesale rates throughout the WSCC are strongly cointegrated. See De Vany and Walls, supra.

Footnote No. 158

Moreover, as then Judge Breyer 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.

Footnote No. 159

Merger Guidelines §1.01; State of N.Y. v. Kraft General Foods, Inc., 926 F.Supp. 321, 359 (S.D.N.Y. 1995).

Footnote No. 160

Hieronymous Trans. at 2976.

Footnote No. 161

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.

Footnote No. 162

Yap Direct at 49.

Footnote No. 163

See U.S. v. Syufy Enterprises, 903 F.2d 659, 672 n.21 (9th Cir. 1990).

Footnote No. 164

Hieronymous Direct at 28.

Footnote No. 165

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 are at the tariff level. See State of Ill. ex Rel. Hartigan

v. Panhandle Eastern, 730 F.supp. 826, 905 (C.D.Ill. 1990).

Footnote No. 166

See U.S. v. Connecticut Nat'l Bank, 418 U.S. 656, 669 (1974).

Footnote No. 167

Areeda and Hovenkamp, Antitrust Law, § 1015.1 (1997 Supp.).

Footnote No. 168

U.S. v. Mercy Health Services, 1995-2 Trade Cases par. 71,162.

Footnote No. 169

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' will not suffice." Fruehauf Corp. v. F.T.C., 603 F.2d. 345, 351 (2nd

Cir. 1979).

Footnote No. 170

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 endproduct." See

Town of Concord, 915 F.2d 17, 23 (1st Cir. 1990) (noting 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, par. 1015.1. See also 3A Areeda

& Hovenkamp, Antitrust Law, par. 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 "squeeze" 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, this merger presents a mixture of the regulated and unregulated cases analyzed in the Town of Concord

decision.

Footnote No. 171

Areeda & Turner, 2 Antitrust Law par. 527a at 376 (1978).

Footnote No. 171.1

See Stewart Rebuttal at 27. The Commission has authorized discounts below existing tariff levels only for the

Mandalay station, in D.95-02-043, and for cogeneration plants with total capacity of 364 MW (whose capacity

appears in QF contracts with purchasing utilities approved by the Commission), in D.93-06-096, D.93-11-021,

D.95-01-040, D.95-11-048, D.96-09-096, D.97-04-071, D.97-03-005. We understand that no other cogeneration

discounts have been filed with the Commission. See also Applicants' Opening Brief at 99-107.

Footnote No. 172

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.

Footnote No. 173

See WSCC, Summary of Estimated Loads and Resources (April 1997).

Footnote No. 174

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.

Footnote No. 174.1

As the Ninth Circuit has recognized, a firm cannot control prices without "significant" entry barriers -- "they must be

capable of constraining the normal operation of the firm to the extent that the problem is unlikely to be self-

correcting." Rebel Oil Co., Inc. v. Atlantic Richfield Co., 51 F.3d 1421, 1439 (9th Cir. 1995). See also Ryko Mfg. Co.

v. Eden Services, 823 F.2d 1215 (8th Cir. 1987)("direct evidence of competitive pressure -- demonstrated by a

significant number of viable competitors in the market [citations omitted] or even by the product's price sensitivity --

indicates a lack of market power"). In any event, it is questionable whether the intermittent price increases

hypothesized by Edison would constitute an unlawful exercise of market power. Colorado Interstate Gas v. Natural

Gas Pipeline, 885 F.l2d 683, 695 (10th Cir. 1989)(refusing to find violation of Sherman Act "where the evidence

indicates that a firm's ability to charge monopoly prices will necessarily be temporary"); Metro Mobil CTS, Inc. v.

Newvector Communications, Inc., 661 F.Supp. 1504, 1523-24 (1987).

Footnote No. 174.2

De Vany and Walls, supra. See also Lehr & Van Vactor, Evolution of Wholesale Power Price Structures in the

Western Power Market: Implications for US Power Markets, The US Power Market/Risk Publications (July 1997) at

233 ("The synchronous movement of prices within [the western United States], combined with a fragmented and

diverse group of suppliers, indicate there is substantial competition in the market.").

Footnote No. 175

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/MULTISYM 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. at 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 located in 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 Electric 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 border." 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% gas price increase

translates to a 3.8% 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 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. Graves Trans. at 3407.

Footnote No. 176

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 game 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 from 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.

Footnote No. 177

See Areeda & Hovenkamp, supra, at par. 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] --

vertical integration into a competitive market -- is a clear candidate for a rule of absolute legality.").

Footnote No. 178

See Yap Direct at 102-120;

Footnote No. 179

Yap Direct at 108.

Footnote No. 180

"Ensource or some other affiliate of SoCalGas could theoretically benefit from precisely the same of machinations

today." Applicants' Opening Brief, at 112.

Footnote No. 181

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 Markets, 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).

Footnote No. 182

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 ("no one has ever seriously alleged, let alone documented, a

manipulation of a financial futures contract"). The Hunt Brothers did attempt to monopolize silver futures, but their

unsuccessful efforts cost them several billion dollars. Hieronymous Trans. at 2981; Easterbrook, supra, 59 J. of

Business at S110 n.5.

Footnote No. 183

See Roach Direct at 73, Yap Direct at 58-60, Beach Direct at 31.

Footnote No. 184

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.

Footnote No. 185

See Easterbrook, The Supreme Court 1983 Term; Foreword: The Court and the Economic System, 98 Harv.L.Rev.

4, 10-12 (1984).

Footnote No. 186

A new pipeline can be built in one to four years. Stewart Trans. at 2526.

Footnote No. 187

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).

Footnote No. 188

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.

Footnote No. 189

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 of gas acquisitions and

marketing groups and of SDG&E employees providing "electric merchant functions."

Footnote No. 190

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 where 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.

Footnote No. 191

Yap Direct at 32.

Footnote No. 192

Yap Direct at 34.

Footnote No. 193

Leitzinger Rebuttal at Exhibit JJL-2.

Footnote No. 194

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.

Footnote No. 195

Until recently, PUC rules prohibited the companies from competing for sales to core customers. Hieronymous

Rebuttal at 30.

Footnote No. 196

Hieronymous Rebuttal at 30.

Footnote No. 197

Id.

Footnote No. 198

Hieronymous Rebuttal at 31.

Footnote No. 199

Id.

Footnote No. 200

Stewart Trans. at 2781.

Footnote No. 201

Brodley, Potential Competition under the Merger Guidelines, 71 Cal. L.Rev. 376, 378 (1983). Areeda and

Hovenkamp also question the doctrine as a basis for a section 7 violation. Areeda and Hovenkamp, Antitrust Law §

1118 (1996 Supp.).

Footnote No. 202

Marine Bancorporation, supra, at 630-32.

Footnote No. 203

See Yap Direct at 48, 55; Taylor Direct at 53. But see Stewart Rebuttal at 32 (noting that SDG&E loads are

increasingly fragmented).

Footnote No. 204

Tenneco v. FTC, 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").

Footnote No. 205

See BOC Int'l Ltd. v. FTC, 557 F.2d 24, 29 (2d Cir. 1977)(rejecting a finding of "eventual" entry as "uncabined

speculation").

Footnote No. 206

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.

Footnote No. 207

Tenneco, supra, at 355; Merger Guidelines §4.11.

Footnote No. 208

Exhibit 385 at Response to Request 6.16.

Footnote No. 209

Id.

Footnote No. 210

Yap Direct at 53.

Footnote No. 211

Yap Direct at 184.

Footnote No. 212

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

par. 1004, at 211 (foreclosure argument has "grave weaknesses").

Footnote No. 213

Yap Direct at 61.

Footnote No. 214

Taylor Direct at 35.

Footnote No. 215

Mercantile Texas Corp. 638 F.2d at 1267. See also U.S. v. First National State Bancorporation, 499 F.Supp. 793,

814 (D.N.J. 1980).

Footnote No. 216

Hieronymous Rebuttal at 42-43.

Footnote No. 217

Hieronymous Rebuttal at 43.