2. Background

A. Brief Overview of the Recent Changes in the Natural Gas Industry

The natural gas industry underwent considerable change in the 1980s and 1990s, with major policy changes occurring at both the federal and state level. Before these changes, investor-owned utilities provided all natural gas services to customers within their service territories. The three largest investor-owned natural gas utilities in California are Pacific Gas and Electric Company (PG&E), Southern California Gas Company (SoCalGas), and San Diego Gas and Electric Company (SDG&E). Historically, the Commission has regulated these utilities' monopoly activities and, under traditional ratemaking, has authorized and reviewed most utility actions and operations. The Commission determined the utility customers' gas costs through regulatory ratemaking decisions, which set rates for the entire "bundle" of services the utility provides (including supply, pipeline transmission, distribution, storage, metering, and billing.) Historically, rates were based principally on the costs of purchasing and delivering natural gas.

Today in California, some gas customers can choose to purchase different natural gas services from different companies. Increasingly, large commercial and industrial customers and groups of smaller customers are arranging to purchase their own natural gas supplies directly from gas producers, and then are paying pipeline companies and local gas utilities to deliver the purchased gas to the customers' facilities. These customers may also benefit from purchasing natural gas storage services. This service allows customers to purchase and store gas when prices are relatively low and supplies are relatively high. These customers can then withdraw the gas from storage for use when prices are high or supplies are scarce, such as during a severe cold spell.

The rapid changes in the natural gas industry during the past decade started when the Federal Energy Regulatory Commission (FERC) mandated open access and allowed unbundled services on interstate natural gas pipelines throughout the United States. Under open access, pipeline companies must allow other gas companies and customers to bid for and reserve transportation capacity on their pipelines. California gas users could then purchase their gas supplies directly from natural gas producers across the western half of North America and arrange with other companies to provide the other gas services they need.

In 1992, the California Legislature formally expressed its objective of creating competition for natural gas storage services. The Legislature passed and the Governor approved Assembly Bill (AB) 2744 (Chapter 1337 of the California Statutes of 1992, which is uncodified), which made certain findings about gas storage and urged certain action by the Commission. The Commission has summarized AB 2744 as not requiring, but urging, Commission action in the gas storage area.

"...AB 2744 does not require action by the Commission, but it does make legislative findings about gas storage and urges certain actions by the Commission.

"In summary, AB 2744 finds that: (a) storage has gas service benefits; (b) there are barriers to investment in new storage facilities; primarily the inability of independent storage providers to compete in an open storage market; and (c) unbundling of utility storage service will greatly increase the benefits of storage. The Legislature then urges that the Commission: (1) expeditiously unbundle utility storage service, (2) encourage the development of independent storage by establishing interconnection rules and reasonable cost allocations, (3) adopt market-based storage rates, (4) give expedited consideration of applications for certificates of public convenience and necessity (CPCNs) filed by independent storage providers, and (5) ensure that storage costs borne by core customers are commensurate with benefits.

"This decision [the Gas Storage Decision] directly responds to all of the Legislature's urgings except the item on expedited handling of CPCN applications. We intend to give CPCN applications a high administrative priority, but we cannot overlook due process and other statutory requirements in doing so." (Re Natural Gas Procurement and System Reliability Issues; Re Southern California Gas Company, Decision (D.) 93-02-013, 48 CPUC2d 107, 126 (Gas Storage Decision).)

The Commission issued various decisions in order to increase competition in the gas industry. Among other things, the Commission removed the cross-subsidies of utility-provided non-core natural gas storage services,¹ and responded to the Legislature's urgings in AB 2744. (See generally the Gas Storage Decision.) Specifically, in the 1993 Gas Storage Decision, the Commission adopted a "let the market decide" policy for gas storage. The Commission stated that it should not test the need for new gas storage projects on a resource planning basis, so long as all of the risk of the unused new capacity resides with the builders and users of the new facility.² The Gas Storage Decision also adopted market-based rates for noncore storage including incremental rates for service derived from new or expanded facilities. The Gas Storage Decision also approved SoCalGas' and SDG&E's proposed permanent storage programs. In a subsequent decision, D.94-05-069, the Commission adopted a permanent storage program for PG&E as well.

These Commission decisions set the stage for allowing other non-utility companies to develop storage facilities in competition with PG&E and SoCalGas, the only two California utilities presently able to offer storage services. Several years ago, the Commission approved a CPCN for the first of these non-utility storage facilities, the Wild Goose facility in Butte County, to operate. (See Application of Wild Goose Storage Inc. for a CPCN to Construct Facilities for Gas Storage Operations, D.97-06-091 (Wild Goose Decision).) The instant application is the second application for a CPCN to offer competitive gas storage services to be considered by the Commission.

In the Gas Storage Decision, the Commission left open the issue of whether independent gas storage providers are public utilities. This issue is significant to this application because if an independent gas storage provider is a public utility, it would have the power of eminent domain under the rationale set forth below. However, Wild Goose's application resolved this issue, because after receiving its CPCN, Wild Goose became a public utility (see D.97-06-091, slip op. at p. 20, Finding of Fact 11), and subsequently exercised the power of eminent domain for property necessary for the construction and maintenance of its gas storage facility.

The underlying rationale is that upon receipt of a CPCN, an applicant becomes a "gas corporation," which Pub. Util. Code § 222 defines as "every corporation or person owning, controlling, operating, or managing any gas plant for compensation within this state... ." Pub. Util. Code § 221 defines "gas plant" as including all real estate, fixtures, and personal property, owned, controlled, operated, or managed in connection with or to facilitate, among other things, gas storage. Pub. Util. Code § 613 provides that a gas corporation may condemn any property necessary for the construction and maintenance of its gas plant.

The Commission has also recently initiated its Gas Strategy Rulemaking 98-01-011, which is assessing the current market and regulatory framework for California's natural gas industry to identify services for which the public interest suggests the need for greater competition and to determine the steps that the Legislature and this Commission must take to facilitate healthy competition.

D.99-07-015, slip op. at 23, discussed methods other than constructing competitive gas storage facilities to further increase competition in the gas storage area, such as creating a system of tradable storage rights to existing gas storage.

"There is reason to believe that it would promote more efficient use of the hard-to-find gas storage resources if individual shippers and customers could bid for firm storage access rights. In addition, the local distribution company will be motivated to pursue more complete utilization of its storage assets if its shareholders bear the risk for cost recovery. If accompanied by an active secondary market, the bidding and trading of storage rights should lead to pricing that reflects demand. A market-based price for storage should spur the development of more storage capacity, or other alternatives to storage, when existing capacity becomes scarce.

"In addition, we anticipate that the existence of an active secondary market for storage would reduce a utility's ability to increase its storage revenues in an unfair manner. Shippers should be more willing to acquire storage rights when they know they will have the ability to sell unused capacity on the secondary market. As more of the storage rights are held by market participants other than the utilities, the utilities' ability to gain from manipulation of storage prices is reduced. As with our proposal for transmission rights trading, this option should advance our goals of mitigating potential competitive abuses, and providing a wider array of choices to market participants.

"In the next phase of this inquiry, we ask parties to consider the costs and benefits related to creating a system of tradable storage rights in Southern California that places the utility at risk for unused resources and preserving such a market in Northern California beyond the period of the Gas Accord. As part of that discussion, we wish to consider the merits of treating the utilities' core procurement departments like any other customer, allowing the core group to bid for and acquire needed storage in the same manner as all others." (D.99-07-015, slip op. at pp. 22-23.)

B. Overview of LGS and the Proposed Project

1. LGS

LGS is a wholly-owned subsidiary of Western Hub Properties, LLC (WHP). Haddington Ventures, LLC (Haddington) formed WHP in 1998 to develop natural gas facilities, primarily in the western United States and Canada. WHP is presently owned by two limited partnerships, Haddington Energy Partners, L.P. and Haddington/Chase Energy Partners (WHP), L.P., respectively.

In the mid-1980s, and before forming Haddington Ventures, LLC, the three Haddington principals, Larry Bickle, John Strom and Chris Jones formed and managed Tejas Power Corporation, which later became TPC Corporation (TPC). Under the management of the three principals, TPC developed the Moss Bluff (Texas), Egan (Louisana) and Tioga (Pennsylvania) salt cavern gas storage projects. The two Gulf Coast projects have a combined deliverability of 1.5 Bcfd and, as of mid-1999, Tioga is about to begin construction. TPC was also an independent gas marketer and one of the largest independent natural gas pipeline companies in the Gulf of Mexico. TPC was sold to PacifiCorp in the spring of 1997. The LGS project management team, Mssrs. Dill (LGS' President) and Bergquist (a WHP Vice President) have substantial experience in the natural gas industry, including gas storage.

2. The Proposed Project

All components of this proposed project are more thoroughly defined in the final EIR, which consists of two separate documents, the Draft EIR and the Final EIR, which cumulatively make up the EIR.³ We generally refer to the cumulative documents as the EIR, unless referring to a particular section or discussion, in which case we will specifically reference either the Draft or Final EIR.

Lodi Gas proposes to convert a depleted natural gas production field into a storage facility. The field LGS has chosen comprises about 1,450 acres, and is located approximately 5.4 miles, northeast of Lodi in San Joaquin County. The EIR describes the project area as characterized by a mosaic of agricultural fields and orchards. In addition to agricultural lands, which grow wine grapes, among other crops, other land uses in the vicinity of the project include dairies, a fish farm, scattered light-industrial uses, single family residences, and recreation.

According to the EIR, although the gas field was declared depleted in 1972, the field still has large pockets of gas trapped in two reservoirs, one on top of the other, that are more than 2,000 feet under the ground surface. A dome-shaped layer of hard shale caps each reservoir and keeps gas trapped in the reservoirs. Each reservoir is pressurized from beneath by a deep, brackish water table. LGS would drill 10 or up to 11 new wells into the two reservoirs to allow customers to inject or withdraw gas from the facility several times a day.

The project has the following principal components: the Lodi gas field, a field collection and water separation facility, a gas dehydration and compressor facility, approximately 33 miles of field and transmission gas pipeline, and two PG&E interconnect and meter stations. The compressor facility and gas pipeline would enable LGS to get the gas into and out of the storage facility, and the pipeline would connect the facility to PG&E's gas transmission pipeline network. LGS' storage customers would make their own arrangements for purchasing the gas and transporting it to and through PG&E's natural gas pipeline system for delivery to the storage facility, and for delivery from the storage facility to the customer.

LGS explains that only the storage rights, and not the mineral rights, are required for the project because the right to store natural gas in a depleted or non-gas bearing reservoir on a property is not a mineral right. Rather, it is part of the rights of a surface owner unless this right has been specifically severed in a deed or other conveyance. However, LGS is also seeking either the mineral rights to the property or consent and agreement of the mineral owners, in some instance limited to the specific zones to be utilized for natural gas storage. According to LGS, this is being done for two purposes: (1) to preclude another owner of the mineral rights from drilling into or through the storage reservoirs and causing damage or recovering the stored gas; and (2) to preclude claims that there exist remaining recoverable gas reserves in the storage reserves prior to injection of new gas.

The EIR proposes several alternative pipeline routes to that proposed by LGS. These alternatives are discussed more fully below. The EIR also considers an alternative location for the dehydration and compressor facility. In its initial application, LGS proposed to locate the dehydration and compressor facility near Highway 99 and adjacent to a frontage road, where LGS states that noise produced by the compressor facility would be less noticeable. The primary components of this facility include three large piston-type compressors fueled by natural gas plus an operator's control room and related facilities. The compressors would be housed in an approximately 60 foot by 125 foot by 30 foot tall prefabricated metal building. The ventilation sound dampers and the engine exhaust piping may be as tall as 35 feet. Several other small maintenance buildings would also be located on the site. LGS has committed to spend more than $60,000 on air emission mitigation equipment at the compressor facility.

In its amended application, LGS submitted an alternative location for the compressor facility on the southwest corner of the Lind Airport property. The individual facilities and structures on the compressor site would be the same as those described for the proposed project. However, the site would likely be laid out differently than the proposed project site because of the orientation of the field, transmission pipelines, and access road.

The field collection and water separation facility would prepare the gas for transportation through PG&E's system. LGS proposes to construct the water separation facility near the injection wells and a dehydration facility at the gas compressor facility. The purpose of these facilities would be to remove any water absorbed into the gas during storage. LGS would then pump that water back into the gas storage reservoirs using separate water injection wells which it would drill into the reservoirs at locations where the injected water would not interfere with the injection/withdrawal wells.

In its application, LGS describes its own system capability as offering both firm and interruptible storage services and designed to accommodate an inventory of 12 billion cubic feet (Bcf) of working gas, with a maximum firm deliverability of 500 million cubic feet per day (MMcf/d) and a maximum firm injection capability of 400 MMcf/d.⁴

C. Procedural Background

1. The Application

LGS filed its initial application on November 5, 1998. Subsequently, LGS filed three amendments to the application, dated January 22, February 5, and April 29, 1999, respectively. The first two amendments primarily addressed additions to LGS' Environmental Assessment, and the third amendment primarily addressed LGS' proposed relocation of the compressor facility.

Rule 17.1 of the Commission's Rules of Practice and Procedure (Commission's Rules) provides that notice of the preparation of either a negative declaration or Draft EIR should be given to, inter alia, owners of land, under, or on which the project may be located, and owners of land adjacent thereto. Rule 18(b), which provides service requirements for applications, does not contain such a requirement. In order to promote efficiency, so that interested landowners could receive notice of this proceeding as soon as possible, a January 7, 1999 Administrative Law Judge (ALJ) ruling, inter alia, required LGS to serve a notice of availability of its application and the ruling on all owners of land, under, or on which the project may be located, and owners of land adjacent thereto.⁵ Because the third amendment to the application presented an alternative siting of the compressor station, LGS was also required to undertake similar service requirements as set forth above on landowners affected by the third amendment to the application.

The following parties filed limited or full protests, or responses to the application: The Office of Ratepayer Advocates (ORA); PG&E; and SoCalGas.⁶

2. Non-Environmental Review

After a February 11, 1999 prehearing conference, the Assigned Commissioner and ALJ issued a joint scoping memo and ruling (scoping memo) which recognized that the application involved the interplay between hearings on the non-environmental issues and environmental review. The scoping memo stated that the Commission's Energy Division (ED) would be conducting the environmental review and did not provide a detailed scope and schedule for that process. The scoping memo identified the issues to be addressed in hearings on the non-environmental issues and set forth the schedule for the rest of the proceeding. Pursuant to Pub. Util. Code § 1701.3, the scoping memo designated ALJ Econome as the principal hearing officer.

Hearings on the non-environmental issues were held from June 14 through 16, 1999. The parties participated in closing argument before Assigned Commissioner Bilas, as well as the ALJ, on June 22, 1999. Additionally, the Commission held two public participation hearings in Lodi on October 19, 1999, where the public could comment on both the non-environmental issues and the Draft EIR.

Pursuant to Rule 8(d), parties were given until June 30, 1999, to submit a written request for final oral argument before the entire Commission. A July 16, 1999 ALJ ruling confirmed that no party submitted such a request, and that such argument would therefore not be scheduled or heard.

Parties filed opening and reply briefs on the non-environmental issues in July 1999. In addition to LGS, the following parties participated in the hearings or filed briefs: LGS, Calpine Corporation (Calpine), California Farm Bureau Federation and the San Joaquin Farm Bureau Federation (Farm Bureau), District Council No. 36,⁷ Pacific Realty Associates, L.P. (Pacific Realty), PG&E, Wild Goose Storage, Inc. (Wild Goose), and a group of interested landowner parties referred to as Williams.⁸

On March 24, 2000, after the ALJ's proposed decision in this matter had issued, Pacific Realty moved to withdraw from this proceeding because it had satisfactorily resolved all outstanding issues it had with LGS. In particular, Pacific Realty states that it and LGS "have satisfactorily resolved all issues with respect to the depth and alternate routing of the pipeline, an easement to be granted by Pacific Realty to LGS in connection therewith, and certain environmental concerns relating to the presence of the pipeline on the M&T Ranch. Pacific Realty and LGS have agreed on routing and construction methods for the Pipeline which will not interfere with the farming operations and will enhance the habitat development activities on the M&T Ranch, resulting in a substantial local benefit due to the LGS project." (Pacific Realty March 24 Motion, pages 1-2.) Pacific Realty therefore requests to withdraw James M. Shanks' prepared written testimony as well as his oral testimony at the June 1999 hearings, and the comments of James and Sally Shanks at the public participation hearings held in October 1999, and requests to withdraw as a party to this proceeding.

Pacific Realty's March 24 Motion to withdraw from this proceeding is denied because it is filed after the Commission has expended much time and resources on this proceeding. Because Pacific Realty has settled its differences with LGS, we will consider this information as supplementing its original testimony. However, we do not eliminate the prior testimony from this record at this late date.

On October 7, 1999, the Governor signed into law Senate Bill (SB) 177, which places conditions on the ability of certain public utilities to exercise the power of eminent domain for purposes of providing competitive services. (SB 177 is discussed more fully below.) Because this legislation was not enacted when parties had filed their briefs in July, the ALJ afforded parties the opportunity to file supplemental briefs on SB 177. The following parties filed opening or reply supplemental briefs: Lodi, the Farm Bureau, PG&E, Wild Goose, and the Williams.

Altogether, the Commission held six days of hearings in this case (including the prehearing conference). Assigned Commissioner Bilas was present for three of those days.

3. The EIR

The EIR sets forth a detailed schedule of the environmental process. On February 17, 1999, the Commission, through its ED, notified LGS that its application had been deemed complete for purposes of Rule 17.1.⁹ On February 17, the Commission also mailed a Notice of Preparation (NOP) for the EIR to local, state and federal agencies and the State Clearinghouse for a 30-day review period. The NOP provided a general description of the proposed project and a summary of the main regulations and permit conditions applicable to its development and operation. Responses from these agencies helped to determine relevant environmental issues associated with the project.

Also, to gather information related to the possible environmental effects of this application, the Commission consulted with other affected agencies and jurisdictions. The Commission conducted a Public Agency Outreach Program to establish early contact and open lines of communication with key public agencies that would be directly affected by the proposed project. The program included consultations with more than 25 public agencies conducted at central meeting locations, in agency offices, and by telephone. Local agency representatives provided background information, community perceptions, and local environmental concerns.

The Commission also conducted two public scoping meetings to explain the environmental review process and to receive public comment on the scope of the EIR. The Commission held these widely-noticed meetings in two locations convenient to residents who live in the area where LGS proposes to develop its project, as described more fully in the EIR.

In September 1999, the Commission issued its Draft EIR. The Commission accepted written comments on the Draft EIR through November 12, 1999. The Commission held two public information meetings on the Draft EIR in Lodi and Isleton so that the public could learn about the draft EIR and the status of the project, and to answer questions prior to the conclusion of the Draft EIR comment period. In addition, the Commission held two public participation meetings on October 19, 1999, where individuals could make formal comment on the Draft EIR in lieu of submitting written comments.¹⁰

Jones & Stokes Associates, Inc. were the consultants which assisted the Commission's ED in the EIR's preparation.