Opinion No. (1998)
This text of Opinion No. (1998) (Opinion No. (1998)) is published on Counsel Stack Legal Research, covering California Attorney General Reports primary law. Counsel Stack provides free access to over 12 million legal documents including statutes, case law, regulations, and constitutions.
Opinion
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
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?
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.
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 (SDGE) 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 SDGE 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 SDGE 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.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, SDGE, and SoCalGas would operate separately and under their existing names.
On June 25, 1997, the Federal Energy Regulatory Commission (FERC) conditionally approved the merger.2 In general, the conditions imposed by FERC would require SoCalGas to treat SDGE and other affiliates "in the same way pipelines treat their gas marketing affiliates."3 The applicants subsequently incorporated those conditions, along with other proposed restrictions, within their merger application.4
B. This Advisory Opinion
This is the fifth opinion letter submitted by this office under the 1989 amendments to Section
II. THE APPLICANTS AND THE INTRASTATE GAS TRANSPORTATION ANDELECTRICITY 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.7
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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
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?
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.
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 (SDGE) 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 SDGE 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 SDGE 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.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, SDGE, and SoCalGas would operate separately and under their existing names.
On June 25, 1997, the Federal Energy Regulatory Commission (FERC) conditionally approved the merger.2 In general, the conditions imposed by FERC would require SoCalGas to treat SDGE and other affiliates "in the same way pipelines treat their gas marketing affiliates."3 The applicants subsequently incorporated those conditions, along with other proposed restrictions, within their merger application.4
B. This Advisory Opinion
This is the fifth opinion letter submitted by this office under the 1989 amendments to Section
II. THE APPLICANTS AND THE INTRASTATE GAS TRANSPORTATION ANDELECTRICITY 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.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.
SDGE, which actively buys and sells power in the wholesale market,8 sells electricity to 1.2 million retail customers in San Diego and southern Orange Counties (including parts of the SoCalGas service area). SDGE also purchases gas in the interstate market,9 which it distributes within its separate service areas.10 SDGE provides no gas transmission services outside of San Diego County.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."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.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 SDGE 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, PGE and out-of-state suppliers in the restructured electric industry mandated by AB 1890. As a result of that restructuring program, SDGE 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 PGE,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. SDGE 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 SDGE and other California utilities.15 SDGE currently purchases a majority of the electricity it sells to its retail customers. In 1995, for example, SDGE 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,16 and the remaining 17 percent from the San Onofre Nuclear Generating Station (SONGS).17 In 1996, the peak load for the SDGE system was 3,299 MW.18
During a five year transition period beginning January 1, 1998, SDGE 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.19 Participating distribution companies and end users will submit "demand side" bids to the PX.20 Generation plants and marketers will simultaneously submit advance supply bids.21 The total capacity of WSCC members, including capacity divested from Edison and PGE,22 which can bid into the PX exceeds 150,000 MW.23 From the resulting demand and supply schedules, the PX will establish24 the market "clearing price" governing all purchases and included sales.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 integrity26 — will be sold at their variable operating costs.27 The ISO Governing Board "has chosen all of SDGE's units for Must-Run status."28 Must-take resources, which include SONGS and other nuclear plants, qualifying facilities (QFs) and pre-existing power contracts,29 provide more than half of the electricity requirements of the California IOUs.30 A "performance incentive mechanism . . . will isolate SONGS revenue received by SDGE from the PX price."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, SDGE will bid the output of its gas-fired and other plants into the PX under ISO "Agreement B"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, SDGE 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."33 The remaining ten percent will apparently be applied to SDGE stranded costs through the competitive transition charge (CTC) mechanism.34 On October 30, 1997, FERC concluded that this arrangement "adequately mitigate[s] [SDGE's] generation market power for PX sales of energy."35
In conjunction with the PX, the ISO will coordinate intrastate power flows and provide open access to the California transmission grid.36 On January 1, 1998, all participants will transfer operational control of their transmission facilities to the ISO.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.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.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 PGE 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.40 In the northern part of its service area, SoCalGas receives gas from PGE at Kern River Station and Pisgah,41 and from the Kern River and Mojave lines at Wheeler Ridge and Hector Road.42 The SoCalGas system is capable of receiving approximately 3.5 Bcf/d at these connection points.43
The SoCalGas Acquisition Group purchases about 1000 MMcf/d, which is ultimately transported to core customers.44 SoCalGas noncore transportation customers include Edison, members of SCUPP, SDGE, the City of Long Beach, and various large commercial and industrial customers.45 SoCalGas supplies 42 gas-fired generation plants, including plants owned by SDGE, Edison, Imperial Irrigation District (IID) and SCUPP members.46 These plants have a total generating capacity of 15,837 MW.47 SoCalGas is the only intrastate gas pipeline to which SCUPP members can feasibly connect.48
To coordinate deliveries to these customers and to preserve "system integrity,"49 SoCalGas calculates in advance of "flow day"50 a system "window" from the difference between estimated overall next-day demand51 and local52 California gas production.53 This "take away" capacity figure is then adjusted by anticipated injection or withdrawal volumes54 for SoCalGas storage fields,55 which according to Edison "are used to satisfy the majority — approximately 57% — of peak day demand."56 Windows are also established at each of the individual receipt points.57 SoCalGas uses a variety of procedures, including "custody cut"58 and Rule No. 30 restrictions,59 to achieve system balance when demand "nominations" for core and noncore customers exceed system or individual receipt point windows.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."61 The GasSelect electronic bulletin board, "an interactive same-time62 reservation and information system,"63 provides information within this secondary market about intrastate transportation transactions between SoCalGas and its affiliates.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.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.66 Since their completion in 1992, both systems have delivered gas to Enhanced Oil Recovery (EOR) and related cogeneration loads, and "to SoCalGas and PGE for redelivery to other industrial and commercial loads."67
This competition has induced SoCalGas to "provide discounted68 transportation rates and associated cost saving to numerous customers [perhaps including SDGE69] on its system."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.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.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.73 To mitigate the resulting losses, the PUC has required customers to pay SoCalGas an ITCS (Interstate Transportation Cost Surcharge)74 to help recover certain fixed capacity costs.75
III. INTERSTATE GAS AND WHOLESALE ELECTRICITY MARKETS AT THE CALIFORNIABORDER
SoCalGas and California generation plants purchase the majority of their gas supplies from four producing basins in the western United States and Canada.76 Likewise, SDGE 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.77 Production and interstate transmission services within both of those markets are highly integrated at the California border. Moreover, California wholesale electricity transactions, which SDGE 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."78 As a result of FERC's deregulatory policies, "an active and viable spot market has developed for gas."79
FERC transformed the gas industry by providing open access to interstate pipelines, removing all controls over the wellhead price of natural gas,80 and establishing secondary markets for storage and pipeline capacity.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.82 Because end users attempt to minimize their "delivered prices,"83 competitive forces have also linked the production and transmission markets.
FERC's open access policies, instituted in Orders 43684 and 636, required that interstate pipelines separate gas sales from transportation services,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 gas86 by allowing "holders of unutilized firm capacity [to resell] them in competition with any capacity offered directly by the pipeline."87 Previously, shippers were only able to purchase capacity rights directly from pipelines.88 Under Order 636, shippers who wish to sell (i.e. "release") their firm capacity rights must first offer89 those rights on the pipeline's electronic bulletin boards ("EBB")90, which carry "information about available and consummated capacity release transactions."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.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.93 Pacific Gas Transmission Company ("PGT"), a PGE 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 SDGE, PGE can serve end users in most of California.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.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.96 In other instances, customers have substituted by transporting over the same pipeline to California gas purchased in entirely different basins.97 Customers committed to a particular supply source can also substitute between firm contracts and capacity released in the secondary market.98 Commodity and transportation markets are also linked,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.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."101 Through Order 888 and earlier mandates,102 FERC simultaneously encouraged open access and other "wheeling" transactions between non-contiguous buyers and sellers.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."104
Edison, SDGE and PGE 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."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."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,107 exceeds 150,000 MW.108
As a result of industry deregulation, suppliers can now sell to any purchaser on the grid.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.110 The existence of "loop flows,"111 in particular, means that power in a network "moves across many parallel lines in often circuitous routes."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.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 888.114 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.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 cointegrated116 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.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.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.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.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.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.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,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.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."125 In theory, the horizontal and vertical dimensions of the relevant market are "immaterial."126 In fact, however, empirical limitations require a "noticeable `gap in the chain'" of substitutes and complements.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.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.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."130 Accordingly, "[p]rice relationships are clearly the best single guide to geographic market definition."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.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,133 and across these various service levels.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.135 In 1995, total average production by these basins was 24,000 MMcf/d.136 Estimated peak day supplies to California are 3,536 MMcf/d.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.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.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,140 entry barriers, and the short-run ability of existing competitors to increase their output.141 The courts also recognize the use of "direct evidence" to resolve market power questions.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.143 Thus, the relevant market includes all suppliers whose combined "netback" and transportation costs would be competitive at California delivery points.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."145
The relevant product market includes "all" effectively unregulated delivered electricity which can compete in the Power Exchange for residual wholesale electricity demand.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"147 within some range148 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 WSCC149 that are equally likely to establish the clearing price.150
Intervenors exclude these other generation sources by implicitly assuming that out-of-state participants do not incur opportunity costs.151 Theoretically, PX participants will offer wholesale electricity at their marginal supply costs, including fuel and other variable production expenses.152 In addition, however, the relevant economic cost to out-of-state sellers153 will include returns foregone by selling to the Power Exchange instead of other western United States buyers.154 The existence of these opportunity costs explains why gas is not "the" marginal fuel,155 why out-of-state suppliers will equalize the PX and prevailing WSCC prices156 and, at least in part, why gas and electricity prices are weakly correlated in southern California.157 Their existence also means that the relevant product market includes the output of "inframarginal," out-of-state suppliers.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.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.160 Some intervenors have suggested that the relevant market will be limited during peak hours.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 PGE 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.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.163 SoCalGas also price discriminates between transportation customers, and can sometimes discount without Commission approval.164 The ability to persistently price discriminate between similarly situated customers also implies that a seller possesses market power.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.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."167 A failure to properly define the relevant markets is fatal to a plaintiff's prima facie case.168 A plaintiff must also demonstrate "probabilities" — not "ephemeral possibilities" — of anticompetitive effects within those markets.169
A. The Vertical Integration of SoCalGas Intrastate Gas Transmissionand SDGE Wholesale Electricity Operations
Although this merger has some horizontal features, the primary link between the applicants is the gas transportation services SoCalGas provides to SDGE. Those transportation services are an important component in the cost of generating electricity to SDGE and other gas-fired plants in southern California. Vertical integrations do not, however, "automatically have an anticompetitive effect."170 This is because, unlike horizontal consolidations, vertical mergers do not eliminate competitors from the market.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 SDGE (or the merged entity) to manipulate PX prices.
Even without the restrictions of Agreement B, however, SoCalGas could not significantly increase the costs of SDGE'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.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.173 Because out-of-state suppliers account for their opportunity costs174 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,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.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).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.178 Thus, they contend, the merged entity would essentially trade on "inside" information.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.180 Moreover, adverse effects upon competition within the futures markets — which are characterized by their liquidity and ease of entry and exit181 — are extremely unlikely.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.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.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.185 In 1987, SoCalGas and PGE 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.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.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-price188 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 SDGE 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 SDGE 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.189
B. Horizontal Effects in the Intrastate Gas Transportation, "GasProcurement" and Retail Gas Markets
The principal horizontal feature of this merger is the consolidated ownership of the applicants' gas procurement functions.190 Both of the applicants purchase gas in the interstate market for their core and some of their noncore customers and SDGE makes significant purchases for its electricity generation plants. In 1996, SoCalGas and SDGE gas purchases averaged 963191 and 255192 MMcf/d, respectively, while total production in the relevant interstate market averaged 24,000 MMcf/d.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.194
The merger will also combine the two companies' partially deregulated non-core gas retailing functions.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.196 Moreover, neither firm has made non-core sales outside its service area.197 In 1996, total non-core sales in southern California averaged 1821 MMcf/d.198 SoCalGas and SDGE sales to non-core customers during that year averaged 58 and 144 MMcf/d, respectively.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 andElectric Retail Services
This merger may eliminate SDGE 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 SDGE,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 SDGE 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 SDGE 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 challenge201 — applies if the acquiring firm would have "probably" entered a concentrated market, thereby providing significant procompetitive effects.202 SDGE may present a "threat of competitive entry by a bypass pipeline" and it may be an "attractive anchor customer" for pipeline construction "within" California.203 The courts, however, require showings of an intent to enter204 that go beyond evidence of generalized abilities and incentives. To avoid speculation,205 they also require a showing that entry will occur, not in the "reasonably foreseeable" future, but in the near future.206 We are not aware of any evidence that SDGE 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."207 In this case, SDGE may have tempered the pricing of intrastate transportation services by threatening to bypass the SoCalGas system. Thus, in 1988, SDGE considered building a pipeline to directly interconnect with the El Paso system.208 SDGE considered at least two other bypass proposals during the next six years.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 SDGE would have received had it partially or totally bypassed SoCalGas by utilizing transportation services from a pipeline constructed in Baja California."210
Despite this tempering effect, it is unclear if SDGE is a current entry threat or if the Kern River pipeline and other suppliers view SDGE as a potential entrant to the intrastate market. Because the Revenue Sharing Agreement remained confidential until recently,211 these other suppliers may not have recognized that SDGE was considering bypass alternatives. Similarly, because SDGE would have to build dedicated facilities to bypass SoCalGas, SDGE entry or withdrawal may not affect price or output levels elsewhere in the market. More important, SDGE may not still be a potential supplier of intrastate services. Although SDGE would constitute a valuable "anchor tenant,"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 SDGE 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 SDGE 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."213 Those auctioned rights will constitute an alternative source of intrastate transportation, thereby offsetting the loss of SDGE 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 SDGE 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.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."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.216 Furthermore, SoCalGas has no competitive retail affiliates and limited experience within the electricity industry.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.
Some evidence does suggest that SDGE 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 SDGE 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.
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.
"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 Roleof 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.,
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 PGE'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.
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").
In general, "there is but one maximum monopoly profit to be gained from the sale of an endproduct." See Town of Concord,
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,
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.,
De Vany and Walls, supra. See also Lehr Van Vactor, Evolution ofWholesale 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.").
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 SDGE 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.
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