III. Cost and Revenue Sharing Mechanism
A. Background of Proposal
SoCalGas currently operates natural gas storage fields at four different locations. Over the years, SoCalGas has produced small volumes of "native gas"3 from the geological zones located adjacent to, its storage reservoirs.4 The application seeks Commission authorization to allow SoCalGas to establish a sharing mechanism so that it can produce this native gas.5 SoCalGas' sharing mechanism, which allocates costs and revenues between SoCalGas' shareholders and its customers is intended to provide SoCalGas with an economic incentive to incur the expenses to locate and produce the native gas.
The application, as filed, proposes that SoCalGas' shareholders fund the entire cost of the exploration, development, and production activity needed to locate and produce native gas.6 Under the proposal, SoCalGas will provide the lesser of 68,000 dth per year of the native gas that is produced, or the total native gas produced during the year, to core ratepayers at no charge.7 SoCalGas will then sell the remaining native gas on the open market,8 and ratepayers will receive a 10% royalty on the sale of the native gas.9 According to SoCalGas, this revenue sharing mechanism is patterned after the procedures that landowners and exploration and production companies have used, as well as the revenue sharing mechanism that was approved for Southern California Edison Company (SCE) in D.99-09-070.
SoCalGas is aware of two potential economically viable reservoirs of native gas which are not connected to any existing storage reservoir. The first is located at Aliso Canyon. Based on prior testing, SoCalGas estimates this reservoir contains up to 0.5 billion cubic feet (Bcf) of recoverable gas. SoCalGas anticipates that at a price of $5 per thousand cubic feet (Mcf), two years of production at this reservoir could result in a gross value of approximately $775,000.
The second reservoir that SoCalGas is aware of is located at the La Goleta storage field. SoCalGas believes that the amount of native gas in this reservoir is between 3 Bcf and 12 Bcf. The uncertainties for this project are whether a permit can be obtained from the County of Santa Barbara, the cost to obtain the permit, and whether the permit conditions will be acceptable.
B. Background of Settlement Agreement
A copy of the Settlement Agreement that was entered into by SoCalGas, DRA, SCGC and TURN on July 25, 2005, is attached to this decision as Appendix B. A summary of the terms and conditions of the Settlement Agreement are described in the paragraphs which follow.
The Settlement Agreement proposes a mechanism for the equal sharing of costs and revenues between utility shareholders and customers. The Settlement Agreement is based in part on SoCalGas' prior determination that a reservoir located under its La Goleta storage reservoir contains native gas, that this reservoir could be used to provide storage service, and that the native gas in the reservoir could be sold. If SoCalGas is successful at obtaining any needed approvals at La Goleta, the proceeds from the sale of the storage services and the sale of the gas can then be used to fund additional drilling activity at other storage fields to determine if there are additional gas reservoirs that make it economically viable to produce native gas.
Under the proposed Settlement Agreement, the costs and revenues from the sale of native gas would be equally shared between SoCalGas' shareholders and its customers, with a limit on the customers' share of the costs. The Settlement Agreement proposes to allocate 70% of the customers' share to core customers and 30% to noncore customers.
The limit on the amount of costs that SoCalGas' customers would pay is limited to $3 million. If the sale of the gas, and the revenues from the storage inventory and associated withdrawal rights at the known native gas reservoir at La Goleta are insufficient to cover the ratepayers' share of the $3 million of capital to fund additional native gas drilling, the ratepayers' exposure is limited to the ratepayers' share of the net revenues obtained from the sale of the gas and the sale of the storage inventory and withdrawal rights at other prospects until the total funding reaches the $3 million cap.
The Settlement Agreement also recognizes the known native gas reservoir at the Aliso Canyon storage field. According to the Settlement Agreement, this reservoir can be produced immediately without incremental capital investment and without obtaining any new permits. The Settlement Agreement proposes to authorize SoCalGas to begin production of this gas. The revenues from the sale of this gas would be allocated to core and noncore customers unless SoCalGas is unsuccessful in obtaining the permits that may be needed to develop the known native gas at La Goleta, in which event one-half of the revenues from the sale of the native gas from the known Aliso Canyon reservoir will be used to fund one-half of the unsuccessful permitting costs at La Goleta. If the net revenues from the native gas reservoir at Aliso Canyon are not enough to cover one-half of the unsuccessful permitting costs at La Goleta, the ratepayer contribution to such costs will be limited to the total amount recorded in the native gas reservoir at Aliso Canyon, and SoCalGas' shareholders will bear all additional unsuccessful permitting costs.
The Settlement Agreement provides that all native gas or associated oil sales to a SoCalGas affiliate or to SoCalGas' Gas Acquisition Department is to be done through an open, competitive bidding process.
The Settlement Agreement also provides that SoCalGas will file reports with the Commission that describe, among other things, the volume of native gas production, the revenues received from the sale of the native gas, and the allocation of revenues among customers. The Settlement Agreement also requires SoCalGas to actively monitor native gas production and storage reservoir data to ensure that the production of native gas is not storage gas. The Settlement Agreement also provides that the Commission has full authority to audit any aspect of the native gas program.
With the exception of the La Goleta native gas reservoir, the Settlement Agreement requires SoCalGas to file an application with the Commission to seek approval before using the native gas reservoirs and any related facilities for gas storage purposes. For the native gas reservoir at La Goleta, the Settlement Agreement states that "SoCalGas has sufficient information that it can determine that this reservoir will be used to provide Commission-regulated storage service," and that SoCalGas will put this reservoir into storage service without seeking additional Commission approval. (Settlement Agreement, p. 11.) The Settlement Agreement also provides that nothing in the agreement "is intended to pre-judge the allocation of the storage capacity and any incremental costs associated with the known native gas reservoir at La Goleta." Those issues are to be decided by the Commission in a rate proceeding in which storage costs are addressed.
C. Revised Joint Stipulation
A copy of the Revised Joint Stipulation is attached to this decision as Appendix C. The August 20, 2004 "Interim Rules Applicable to Native Gas," which was part of the supplement to the original July 13, 2004 stipulation, and which was discussed at the September 19, 2005 PHC, is considered to be part of the Revised Joint Stipulation and is attached to this decision as Appendix D. The paragraphs which follow provide a summary of those two documents.
The Revised Joint Stipulation was the result of the efforts of the stipulating parties to reconcile the inconsistencies between the Settlement Agreement and the original stipulation. The original stipulation resolved a number of issues between the parties representing California gas producers and SoCalGas, and also resulted in the filing of A.04-08-018 with the Commission.
The original stipulation, however, conflicted with the Settlement Agreement regarding how the costs and revenues of the native gas program were to be borne. The Settlement Agreement provides for the equal sharing of costs and revenues between shareholders and ratepayers, while the original stipulation requires SoCalGas' shareholders to bear all of the costs of the native gas program, and to receive 90% of the revenues from the sale of any native gas that is produced. The original stipulation also requires SoCalGas to reimburse utility customers for the use of rate-based facilities, whereas the Settlement Agreement does not require any specific reimbursement to utility customers for the use of such facilities.
The Revised Joint Stipulation accepts the revenue and cost allocation provisions that are contained in the Settlement Agreement. The rest of the Revised Joint Stipulation contains most of the same provisions that appear in the original stipulation.10 These provisions address: the terms and conditions of access to the SoCalGas transportation system by the native gas program and by other gas producers; the monitoring and reporting requirements that SoCalGas is to follow in order to ensure that none of the gas produced comes from storage gas; and the process to be followed for converting depleted native gas reservoirs to storage facilities.
The Interim Rules Applicable to Native Gas are to be applied to the native gas program until access rules are adopted in A.04-08-018. These interim rules are referred to in Paragraph 7 of the Revised Joint Stipulation, and address nomination and scheduling procedures, balancing provisions, capacity expansion studies, the sampling of native gas, when gas quality measuring is to take place if regulated facilities are used to process native gas, the terms under which SoCalGas will provide to other non-utility producers the right to use the same facilities, and the operating and maintenance fees that will be charged to the native gas program.
The parties were given time to resolve their differences with Paragraphs 7.d.v. and 12 of the Revised Joint Stipulation. Paragraph 7.d.v. provides that the California producers are to have access to the gas processing facilities at SoCalGas' incremental cost. Paragraph 12 provides that native gas will have access to SoCalGas' transmission system on an interruptible basis, and that preference shall be given to producers who have Maximum Daily Volume (MDV) rights in their access agreements, and to Exxon Mobil and Pacific Offshore Pipeline Company (POPCO) for a volume of not less than 70 million cubic feet per day (MMcfd). The parties were unable to resolve those differences, and evidentiary hearings on those two issues were held on December 13 and 14, 2005.
D. Position of the Parties
SoCalGas recommends that the Commission approve the native gas program at the earliest possible date. SoCalGas contends that the record establishes that this program will provide benefits to California gas consumers by making additional gas supplies available at a time when gas prices are extremely high, and that it will create additional storage capacity. The native gas program will also provide financial benefits to SoCalGas' core and noncore customers from the sharing of revenues generated by the sale of native gas.
SoCalGas recommends that the Commission adopt the Settlement Agreement and the Revised Joint Stipulation without change. SoCalGas asserts that the Settlement Agreement provides the Commission with a reasonable negotiated settlement of native gas issues that directly affect SoCalGas customers, while the Revised Joint Stipulation provides a reasonable negotiated settlement of native gas issues directly affecting California natural gas producers.
SoCalGas contends that because no one objected to the adoption of the Settlement Agreement in its entirety, and because it represents a reasonable, negotiated resolution of the issues that most affect the customers of SoCalGas, the Commission should adopt the Settlement Agreement without modification.
SoCalGas contends that the Settlement Agreement is in the interests of its shareholders and customers because it establishes a structure for the equal sharing of costs and revenues from the sale of native gas.11 Such a structure is possible because the Settlement Agreement recognizes that SoCalGas has previously determined that a reservoir containing native gas is located under its La Goleta storage reservoir. This reservoir could be used to provide Commission-regulated storage service, and the gas in the reservoir could be sold, along with associated injection and withdrawal rights to fund additional native gas drilling activity at other storage fields.
The Settlement Agreement recognizes that utility customers should not have an unlimited obligation to fund the cost of drilling for native gas and places a cost cap of $3 million on the utility customers. This $3 million is to come from the sale of storage inventory, native gas, and withdrawal rights from the known native gas reservoir at La Goleta. However, if the sale of this storage inventory, native gas, and withdrawal rights is not enough to provide $3 million of capital to fund the customers' share of the native gas drilling costs, the Settlement Agreement provides that the customers' share will come from the sale of gas from other prospects until the total funding reaches the $3 million cap.
SoCalGas points out that the Settlement Agreement recognizes that there is a known native gas reservoir at SoCalGas' Aliso Canyon storage field that can be produced immediately without incremental capital investment and without obtaining any new permits. The Settlement Agreement authorizes SoCalGas to begin production of this gas. The revenues from the sale of this gas would be allocated to core and noncore customers unless SoCalGas is unsuccessful in obtaining the permits to develop the known La Goleta native gas reservoir for use in storage service, in which case the revenues from the sale of native gas from the known Aliso Canyon reservoir will be used to fund one-half of such unsuccessful permitting costs.
SoCalGas contends that the Revised Joint Stipulation represents a negotiated resolution of the issues that most affect the relationship of native gas to other California production. SoCalGas contends that because native gas is new California production, it is appropriate to require native gas to abide by the same terms and conditions that are applied to other new California production.
SoCalGas recommends that the Commission reject the position of DRA, SCGC and TURN that Paragraphs 7.d.v. and 12 of the Revised Joint Stipulation be deleted or modified.
SoCalGas recommends that Paragraph 7.d.v. of the Revised Joint Stipulation remain unchanged. According to SoCalGas, this provision addresses the concern of the California producers that SoCalGas' native gas, which will compete with California production, will obtain a competitive advantage by being able to use existing ratepayer-funded processing facilities at no additional charge, as provided for in Paragraph 8 of the Settlement Agreement. Providing California producers with access to these facilities at SoCalGas' incremental cost will minimize any competitive advantage provided to SoCalGas' production of native gas.
SoCalGas recommends that Paragraph 12 of the Revised Joint Stipulation should not be rejected or modified as recommended by DRA, SCGC and TURN. SoCalGas contends that this paragraph will ensure that native gas will be treated the same as other new California gas production.
SoCalGas contends the evidence demonstrates that the scheduling priority for native gas will not restrict the flow of new California production, including native gas. That is because California production in the North Coastal system has steadily declined, and the average producer deliveries to SoCalGas on this system have fallen to about 100 MMcfd, including Exxon Mobil's relatively steady deliveries of about 70 MMcfd. With a capacity on the North Coastal system of 150 MMcfd, that leaves approximately 50 MMcfd for gas to flow, and substantially more capacity on other days depending on system conditions. The expected withdrawal from the known native gas reservoir at La Goleta is expected to be 10 to 15 MMcfd. According to SoCalGas, native gas will be able to flow freely even if Exxon Mobil and its affiliate, POPCO, are given the scheduling priority set forth in Paragraph 12 of the Revised Joint Stipulation.
SoCalGas also contends that the argument that new California production with interruptible access will reduce the value of new production is not supported by the evidence. As long as there is sufficient unutilized capacity on the North Coastal system to allow the gas to flow freely, SoCalGas does not expect the value of new gas production to decrease.
SoCalGas points out that Paragraph 12 is subject to the establishment of the capacity rights that are to be addressed by the Commission this year in A.04-12-004. Even if the native gas program is approved by the Commission, and the County of Santa Barbara does not require extensive permitting, SoCalGas believes that it will be a challenge to complete the work needed to withdraw this native gas during the 2006-2007 storage withdrawal season. SoCalGas contends it is likely that the approval of the Revised Joint Stipulation will amount to nothing more than an interim approach, and any withdrawals from this storage reservoir in subsequent storage withdrawal seasons will be subject to whatever system the Commission adopts in A.04-12-004.
SoCalGas agrees with DRA, SCGC and TURN that none of the agreements that SoCalGas has with Exxon Mobil or POPCO provides them with a specific MDV. However, the evidence demonstrates that SoCalGas has treated approximately 70 MMcfd of the production by Exxon Mobil and POPCO as having MDV-like rights, which is consistent with Paragraph 12. SoCalGas contends that this arrangement should continue until such time system-wide capacity rights are resolved in A.04-12-004.
SCGC stated that granting Exxon Mobil MDV-like rights would be unfair to other California producers. SoCalGas contends that if such an argument were true, the California producers in this proceeding would be making that argument, which they have not. SoCalGas contends that since the California producers support Paragraph 12 of the Revised Joint Stipulation, the Commission should support the inclusion of that paragraph as well.
SCGC claims that Paragraph 12 of the Revised Joint Stipulation violates the ALJ ruling of June 30, 2005 which stated that "Access issues pertaining to the future terms and conditions of access to the gas system of SoCalGas by California gas producers shall be addressed in A.04-08-018." SoCalGas contends that the language of the ruling must be read in the context of the scope of A.04-08-018, which was intended to address producer access issues such as gas quality monitoring and balancing. SoCalGas contends that receipt point access priority is to be decided in A.04-12-004.
SoCalGas believes that it is too early to assess whether any of the native gas reservoirs can be converted for use as gas storage. The reservoir at Aliso Canyon is of poor quality and size, and SoCalGas does not believe that reservoir is well suited for storage. The reservoir at La Goleta might be suited for conversion to gas storage, but that cannot be determined until the reservoir is produced and factors such as the amount of water drive and water interference are known.
The scoping memo identified the issue of whether it would be more cost effective for SoCalGas to have a third party drill the wells and produce the gas. Before SoCalGas filed its application, it considered this option. This option was rejected because SoCalGas would have to spend significant time and money to lease all of the potential land over which the native gas prospect could extend. In addition, someone could lease and drill from another parcel if the information about a native gas prospect was made public. SoCalGas would also have to spend considerable effort and expense in order to assemble and negotiate the bid for drilling the native gas prospects. Also, the royalties due to the shareholders and ratepayers would be much higher than typical royalties for similar kinds of gas projects. Another concern is the liability of the gas producer if storage gas is produced instead of native gas.
In response to the scoping memo's inquiry into whether the native gas project will result in the use of existing ratepayer funded resources and facilities, SoCalGas states that ratepayers will be compensated for the use of rate-based assets, and that SoCalGas has historically reimbursed ratepayers for the use of rate-based assets using the revenue requirement model. In addition, SoCalGas plans to provide an annual report to the Commission that details all of the costs and revenues, and a description of any existing storage equipment or employee resources used by the native gas program.
SoCalGas states that all of its native gas production will be subject to the same rules, regulations, agreements, standards, protocols, tariffs or other terms and conditions that California non-utility natural gas production is subject to.
For access to SoCalGas' transportation system, the native gas production would be treated the same as new California production, or production in excess of a producer's existing MDV amount specified in its access agreement. These new volumes would have interruptible access into the SoCalGas transportation system, unless the producer acquires MDV rights from another producer or funds expansion of the utility system.
The California producers12 generally support SoCalGas' proposal to produce native gas, but are concerned about the potential for cross-subsidies from ratepayers to shareholders and anti-competitive behavior. To resolve the concerns of the California producers, they entered into the original stipulation with SoCalGas. The original stipulation was later replaced by the Joint Revised Stipulation, which the California producers believe adequately mitigates their competitive market concerns.
The California producers point out that SoCalGas supports the Settlement Agreement and the Joint Revised Stipulation, and that SoCalGas believes the provisions of both documents are consistent. For that reason, and the reasons set forth below, the California producers recommend that the Joint Revised Stipulation be adopted without modification.
When the California producers protested the application, they raised concerns that the production of native gas by SoCalGas would result in preferential access to utility facilities or that it would result in undue preference. Paragraph 12 of the Revised Joint Stipulation is intended to ensure that native gas will be treated the same as other new California gas production, and that the native gas does not displace existing California production or impair existing access rights held by other California producers.
The California producers contend that the Revised Joint Stipulation preserves the status quo. The status quo for new California gas production is to have interruptible access unless the producer acquires firm access rights currently held by other producers, or the producer funds an expansion of the utility system to accommodate the additional supplies. The status quo needs to be maintained because the minimum firm capacities on Line 85 and the North Coastal system have been fully subscribed. Paragraph 12 of the Revised Joint Stipulation prevents oversubscription on those two systems, which is consistent with SoCalGas' policy of not entering into new access agreements with new gas producers.
The California producers point out that because SoCalGas is confident that interruptible access is sufficient to accommodate its native gas production on Line 85 and the North Coastal systems, the Commission should have similar confidence that the interruptible access will be able to accommodate the production of native gas. In addition, the data regarding utilization of capacity on Line 85 and North Coastal demonstrates that interruptible capacity has increased over time from January 2001 to July 2005. Another factor that results in more interruptible capacity is that the combined total of 310 MMcfd on Line 85 and North Coastal is a conservative estimate of the firm capacities.
The Revised Joint Stipulation states that the firm access rights to SoCalGas receipt points, including Line 85 and North Coastal, will be developed in A.04-12-004, the proceeding in which firm access rights for SoCalGas and SDG&E are being examined. The Revised Joint Stipulation recognizes that the interim rules agreed to in this proceeding may be revised by the outcome in A.04-12-004. The California producers contend that there is no need to modify the current proposal for interruptible access because the firm access rights issues are likely to be decided before native gas even begins to flow.
The California producers recommend that Paragraph 7.d.v. of the Revised Joint Stipulation be adopted because it provides other California producers with the same, non-discriminatory access to existing gas processing facilities that the native gas project will have. The California producers contend that the compensation for the use of the facilities is appropriate as well.
The California producers contend that the Joint Revised Stipulation contains other important provisions to mitigate potential competitive harm. These provisions guard against preferential access by the native gas project to utility facilities. The provisions also provide that all native gas sales to an affiliate or to SoCalGas' Gas Acquisition Department is to be through an open, competitive bidding process, and that there is to be monitoring and reporting to ensure that none of the gas produced and sold as native gas is injected storage gas. In addition, the Revised Joint Stipulation ensures that the native gas project will not intrude on the rights of competing gas producers by limiting SoCalGas' exercise of eminent domain.
The California producers contend that the Revised Joint Stipulation should be adopted without change because it falls within the range of possible outcomes should litigation continue, avoids the time and expense of the adjudicatory process, and results in a mutually acceptable outcome to the parties interested in California gas production.
Exxon Mobil is a signatory to the Revised Joint Stipulation. Exxon Mobil recommends that the Revised Joint Stipulation be adopted in its entirety.
Exxon Mobil contends that Paragraph 12 of the Revised Joint Stipulation is intended to maintain the status quo with respect to all California producer access to the SoCalGas system for an interim period until the Commission adopts a system of firm access rights for all receipt points on the SoCalGas system. Under Paragraph 12, the native gas produced by SoCalGas will be treated the same as any other new California gas production, i.e., as interruptible access to the SoCalGas system. Exxon Mobil contends that Paragraph 12 does not impair the access rights of California producers under existing contracts with SoCalGas, or with SoCalGas' treatment of Exxon Mobil's production. Exxon Mobil contends that Paragraph 12 preserves the existing access rights of California producers and Exxon Mobil and POPCO. Furthermore, Paragraph 12 is based upon the historical deliveries of Exxon Mobil and POPCO, SoCalGas' longstanding treatment of the Exxon Mobil deliveries, and the access agreements between and among SoCalGas, Exxon Mobil and POPCO. Exxon Mobil contends that its access rights should be recognized in the same manner as other producers' access rights, and to treat Exxon Mobil otherwise would be discriminatory under Pub. Util. Code § 453.
Exxon Mobil contends that for most California producers, the term "existing access rights," is defined as the MDV specified in the producer's access agreement with SoCalGas. Exxon Mobil does not claim to have an MDV agreement with SoCalGas, and points out that Paragraph 12 does not extend MDV rights to Exxon Mobil. Instead, Paragraph 12 defines "existing access rights" for Exxon Mobil and POPCO to mean a volume of not less than 70 MMcfd.
Exxon Mobil contends that the evidentiary record includes the Exxon Mobil and POPCO agreements with SoCalGas, which fully justify the existing access rights of not less than 70 MMcfd for Exxon Mobil. According to SoCalGas' witness, SoCalGas has treated Exxon Mobil since the year 2000 as having "MDV-like" rights of at least 70 MMcfd. In addition, Exxon Mobil's contracts with SoCalGas show a commitment on SoCalGas' part to accept Exxon Mobil's deliveries, and Exxon Mobil has consistently delivered gas volumes equal to or exceeding 70 MMcfd.13 Also, in October and November 1999, Exxon Mobil and POPCO agreed to limit Exxon Mobil and POPCO's daily deliveries to 78,000 million British thermal units (MMbtu), and their conduct since that time is consistent with that limitation. SoCalGas' treatment of Exxon Mobil's access rights is also demonstrated by SoCalGas' response to a data request of DRA, SCGC and TURN asking for a list of all MDV agreements with producers for access to the North Coastal system. Listed in the response was Exxon Mobil's inferred MDV-like rights of 75,000 MMcfd.
Exxon Mobil contends that even if no specific MDV applies to Exxon Mobil, the 1994 Settlement Agreement resulted in a "full requirements" commitment on the part of SoCalGas to accept the full amount of Exxon Mobil's gas deliveries, which is similar to the "full requirements" provision found in SoCalGas' Tariff GT-F.
Another argument of DRA, SCGC and TURN is that Paragraph 12 will prevent native gas from accessing SoCalGas' North Coastal system. Exxon Mobil contends there is ample available capacity on the North Coastal system to accommodate new California production, including native gas. SoCalGas witness Watson testified that the maximum capacity on the North Coastal backbone system is approximately 415 MMcfd, and that the minimum level of firm capacity on the North Coastal system is approximately 150 MMcfd. Since January 2001, Exxon Mobil's actual deliveries into the North Coastal system have been generally constant at or slightly above 70 MMcfd. In contrast, actual deliveries by all other existing California producers have steadily declined over the same period, from about 60 MMcfd to 30 MMcfd. Even SCGC witness Yap acknowledged that "currently there must be a considerable amount of unused MDV rights." (Ex. 10 at p. 7.) Exxon Mobil contends that this means there is consistently more than 60 MMcfd of interruptible capacity available for producer deliveries on the North Coastal system, and that this level of available capacity substantially exceeds the projected level of native gas production to be delivered into the North Coastal system.
SoCalGas expects the native gas production at the known La Goleta field, and delivered into the North Coastal system, will be 10 to 15 MMcfd for approximately one year. Since total available unused capacity on the North Coastal system is at least 60 MMcfd, Exxon Mobil contends there will be no constraint on the delivery of new gas supplies into the North Coastal system as a result of Exxon Mobil being granted 70 plus MMcfd of access rights.
When SoCalGas filed its application, it proposed that its shareholders bear the primary risks for the costs associated with exploration and production. SoCalGas also proposed that the native gas production be treated like all other new California production, i.e., interruptible access. Exxon Mobil asserts that SoCalGas' willingness to rely on interruptible access reflects SoCalGas' confidence that interruptible access for native gas will be sufficient to accommodate the expected delivery of native gas into the North Coastal system, especially during the interim period covered by Paragraph 12 of the Revised Joint Stipulation.
DRA, SCGC and TURN make the argument that the treatment of native gas as interruptible transmission violates the Commission's statement in D.04-09-022 that "new gas supplies should have the opportunity for firm access into the utility system and should be allowed to compete on an equal footing with existing supplies." Exxon Mobil contends that this argument is wrong. The terms and conditions of firm access to the SoCalGas system is to be addressed in the firm access rights phase of A.04-12-004. Exxon Mobil asserts that the parties are free to argue in that proceeding on whether new California production, including native gas production, should be able to gain firm access to SoCalGas' receipt points.
Exxon Mobil asserts that like the Commission's treatment of core supplies on the North Desert Zone in D.04-09-022, Paragraph 12 of the Revised Joint Stipulation preserves the status quo for existing production. Exxon Mobil contends that maintaining the status quo until the Commission addresses a system of firm access rights in A.04-12-004 is consistent with D.04-09-022, and enables all California gas producers, including SoCalGas, to compete on an equal footing.
SCGC proposed replacing Paragraph 12 of the Revised Joint Stipulation with an alternate paragraph. Exxon Mobil recommends that SCGC's alternate paragraph be rejected for two reasons. First, SCGC's proposal is based on the premise that the allocation of access rights for California receipt points should be addressed in A.04-08-018. Exxon Mobil contends that establishing a system of allocating access rights should be addressed in the firm access rights phase in A.04-12-004, and not in A.04-08-018. Exxon Mobil asserts that A.04-08-018 is to address the terms and conditions of access for California producers under a standardized operational balancing agreement.
The second reason why Exxon Mobil recommends the alternate paragraph be rejected is that it discriminates unfairly against Exxon Mobil's existing production because it would not be treated as if it had existing access rights.
DRA, SCGC and TURN recommend that the Settlement Agreement be adopted in its entirety. TURN contends that the Settlement Agreement was not opposed by any party and therefore constitutes an uncontested settlement. TURN also asserts that the Settlement Agreement is in the public interest and should be adopted.
SoCalGas proposed in its application to fund any native gas production at shareholders' expense and to share 10% of the revenues with ratepayers.14 The Settlement Agreement, in general, proposes to share costs and revenues on a 50/50 basis between shareholders and ratepayers. TURN contends that the risk exposure of ratepayers is negligible because the seed money for producing the native gas will come from selling the native gas from the known reservoir at Aliso Canyon. The Settlement Agreement specifically provides that if the net revenues from the sale of this gas from the reservoir are insufficient to cover the permitting costs at La Goleta, SoCalGas' shareholders are to bear all additional unsuccessful permitting costs. If the permitting for La Goleta is successful, the revenues from the sales shall become the seed money for any subsequent acquisition and exploration costs, up to a maximum of $3 million. All of the net revenues in excess of the acquisition, development and production costs, and in excess of the $3 million ratepayer amount for unsuccessful A&E, will be split 50/50 between shareholders and ratepayers.
The Revised Joint Stipulation is an agreement between SoCalGas and the California producers, and was not signed by any ratepayer representatives. DRA, SCGC and TURN recommend that the Commission reject Paragraphs 7.d.v. and 12 of the Revised Joint Stipulation to better protect ratepayer interests, or that these paragraphs be modified as described below.
DRA, SCGC and TURN oppose Paragraph 7.d.v. of the Revised Joint Stipulation because it allows California producers to use SoCalGas' processing facilities at SoCalGas' incremental cost without making any contribution to help offset the fixed cost of the ratepayers' investment in the gas processing facilities. The ratepayers who pay for the fixed costs of the gas processing facilities end up subsidizing the producers' gas processing activities.
As an alternative, DRA and SCGC recommend that Paragraph 7.d.v. be modified to require the producers to pay a fully allocated cost of service charge for using rate-based facilities. This would result in the producers contributing to the fixed cost of the facilities, eliminate the subsidy problem, and spare the producers the cost of having to build their own gas processing facilities.
DRA, SCGC and TURN contend that Paragraph 12 of the Revised Joint Stipulation, which would grant Exxon Mobil and POPCO rights to 70 MMcfd of firm capacity on the SoCalGas transmission system, is unnecessary, amounts to a revision of the current system, grants them valuable rights without compensation, is unfair to other producers, and may deter new California production. If Exxon Mobil and POPCO are granted such rights, this will relegate new production from the native gas program, or any other new California production flowing into the North Coastal system, to interruptible status because this will tie up all available firm capacity on the North Coastal system.
DRA, SCGC and TURN contend that the existing contracts that govern the relationship between Exxon Mobil, POPCO, and SoCalGas do not establish a right to firm capacity of 70 MMcfd. Instead, their right to deliver gas into the SoCalGas system is secondary to the primary rights held by producers who have MDV agreements.
SCGC contends that the exchange of letters in October and November 1999 failed to establish an amendment of the 1994 Settlement Agreement, and that the letters specifically avoided a reference to MDV, choosing instead to use Maximum Total Daily Quantity. SCGC contends that the letters were intended to address operational problems on SoCalGas' pipeline systems, and did not establish a right on Exxon Mobil's part to deliver gas into the SoCalGas system up to a given volume.
SCGC also contends that the manner in which SoCalGas has treated Exxon Mobil does not amount to an amendment of the 1994 Settlement Agreement or the 1999 Operational Agreement because there has not been a meeting of the minds sufficient to amend or modify those agreements to establish that Exxon Mobil has an MDV-like right to deliver a volume of not less than 70 MMcfd into the SoCalGas system. SCGC refers to a SoCalGas data response in which it stated that it has treated Exxon Mobil's deliveries as having 70 MMcfd or more MDV rights because "SoCalGas has chosen not to litigate with Exxon Mobil the question of whether the various agreements provide Exxon Mobil the contractual right that Exxon Mobil claims." (Ex. 10, App. K, Q.1.)
SCGC and TURN contend that, at most, the contracts establish that Exxon Mobil has the right to interruptible capacity on the North Coastal system. SCGC asserts that interruptible rights are of lower value than gas with access on a firm basis, which is the reason why Exxon Mobil seeks approval of Paragraph 12.
DRA and SCGC contend that giving MDV rights to Exxon Mobil is contrary to the open access policy in SoCalGas' Rule No. 39, and in D.04-09-022 which states that "New gas supplies should have the opportunity for firm access into the utility system and should be allowed to compete on an equal footing with existing supplies." (D.04-09-022, COL 18.) SCGC asserts that it would be discriminatory if the Commission approves an agreement that provides Exxon Mobil with MDV rights without Exxon Mobil undertaking the obligations and burdens that are contained in an MDV agreement.
SCGC contends that Paragraph 12 provides Exxon Mobil with MDV rights for a period of time which extends beyond the date for new rules for producer access that are being developed in A.04-08-018. SCGC contends that this violates the June 30, 2005 ruling in this proceeding which stated that "future terms and conditions of access for California gas production to SoCalGas' system shall be addressed in A.04-08-018," and that the access rules developed in this proceeding shall last only until superseding rules are developed in A.04-08-018. According to SCGC, Paragraph 12 violates the June 30, 2005 ruling by tying the duration of access rights that would be established by Paragraph 12 to the timetable in A.04-12-004 rather than A.04-08-018.
SCGC contends that the rejection of Paragraph 12 will not have an adverse effect on Exxon Mobil. Exxon Mobil would still be allowed to deliver gas into the SoCalGas system up to such a level that would fill the capacity of the North Coastal system.
SCGC recommends that Paragraph 12 of the Revised Joint Stipulation be modified to read as follows:15
"SoCalGas will accept a condition to its authorization in A.01-04-034 that until the Commission adopts a program for allocating access rights for California gas production to the SoCalGas system in A.04-08-018, native gas and any other new production will be provided access to the SoCalGas system that is equal to access provided to any existing production, provided, however, that such access shall not impair existing access rights held by California producers under existing agreements establishing rights to delivery of Maximum Daily Volumes."
SCGC contends that this modified Paragraph 12 will allow new production to enter the SoCalGas system without having to purchase an MDV right from another producer or having to pay for system expansion.
SCGC contends that Exxon Mobil's argument that the two agreements it has with SoCalGas creates a "full requirements" obligation on the part of SoCalGas is preposterous. Article XVII of the 1994 Settlement Agreement specifically provides that SoCalGas shall "continue to accept into its transportation system" the Exxon Mobil gas "provided such gas meets the gas quality specifications and marketability standards ... and is not injurious to SoCalGas' pipelines or other facilities." (Ex. 10, App. C at p. 10.) SCGC contends that Exxon Mobil cannot continue to inject gas into the SoCalGas system if it overpressurizes the system or could cause other problems.
SCGC also contends that Exxon Mobil's use of SoCalGas Schedule No. GT-F as analogous to its argument that SoCalGas has a full requirements obligation is erroneous because SoCalGas may curtail service to certain customers when demand reaches the point where SoCalGas may be unable to serve the full requirements of all customers.
Another argument of Exxon Mobil is that a new producer will have access to interruptible service if the system is fully subscribed. SCGC contends that interruptible access to the SoCalGas system is not currently available on the North Coastal or Line 85 systems. The interruptible access will not be available until sometime in 2006. The only two options available to producers are to purchase MDV from an existing producer, or pay the incremental cost of an expansion.
Another argument of Exxon Mobil is that there is sufficient capacity on the North Coastal system to accommodate new California production, including native gas production. SCGC contends that this available capacity on the North Coastal system should provide assurance to Exxon Mobil that it can still deliver its gas into the SoCalGas system without having to reinterpret Exxon Mobil's rights under the unambiguous terms of the 1994 Settlement Agreement and the 1999 Operational Agreement.
Exxon Mobil argued that the SCGC witness did not review any other producer access agreements with SoCalGas. SCGC contends that the SCGC witness did review and introduce into the record SoCalGas' standard California gas producer access agreement, which is what SoCalGas is using for all areas for its MDV producer access agreements.
In their opening brief, the California producers state that "It is not clear how the Settlement Agreement will account for the native gas venture's use of rate-based equipment." SCGC points out that Paragraph 8 of the Settlement Agreement addresses this point. That paragraph provides that the native gas program is to have access to ratepayer-funded facilities at no charge. According to SCGC, the reasoning for that is that ratepayers will receive half of the net revenues of the native gas program, and charging for the use of ratepayer-funded facilities will reduce the net revenues received by ratepayers.
SCGC recommends that the Commission take steps to ensure that storage gas is not produced from the native gas wells. SoCalGas should be required to regularly monitor native gas composition and pressure to ensure that storage gas is not being produced. If native gas is produced by SoCalGas, SCGC proposes that shareholders fund the cost of using independent auditors to regularly monitor reservoir pressure and the chemical composition of the gas to ensure that no storage gas is being produced.
E. Discussion
We have before us an application which seeks authorization to allow SoCalGas to establish a cost and revenue sharing mechanism so that it can explore for, develop, produce, and sell any native gas adjoining its existing gas storage reservoirs. Two documents, the July 25, 2005 Settlement Agreement and the September 7, 2005 Revised Joint Stipulation, need to be addressed because they affect the terms and conditions of how the production of native gas by SoCalGas is to take place.
Our discussion below analyzes the Settlement Agreement and the Revised Joint Stipulation in light of the sharing mechanism that SoCalGas is requesting authority for.
Before we begin that analysis, we address Exxon Mobil's motion to re-open this proceeding to allow into evidence the testimony from another proceeding.
On March 9, 2006, Exxon Mobil filed its motion to re-open the evidentiary record to allow the admission of the rebuttal testimony of SCGC witness Catherine Yap that was admitted into evidence as Exhibit 17 in A.04-08-018. SCGC filed a response in opposition to Exxon Mobil's motion, followed by Exxon Mobil's reply.
Exxon Mobil argues that Yap's rebuttal testimony in A.04-08-018 "acknowledges that SoCalGas and Exxon Mobil amended their 1999 Operational Agreement to establish a maximum total daily quantity," which contradicts Yap's testimony in Exhibit 10 of this proceeding in which she stated that "[t]here are no MDV rights provided in either of the existing agreements between SoCalGas and Exxon Mobil...." (Exxon Mobil Motion, p. 2.) Exxon Mobil also asserts that the rebuttal testimony in A.04-08-018 contradicts statements made by SCGC in its opening and reply briefs in this proceeding regarding whether any MDV-like rights were ever agreed to between SoCalGas and Exxon Mobil.
Exxon Mobil argues that Yap's testimony in A.04-08-018 is relevant to the issues in this proceeding because it contradicts SCGC's reply brief in this proceeding, at pages 12 to 14, that the parties did not amend the May 1999 Operational Agreement, and Yap's testimony in this proceeding that none of the agreements contained provisions regarding MDV-like rights.
SCGC opposes Exxon Mobil's motion. SCGC argues that Yap's rebuttal testimony in A.04-08-018 should not be admitted as evidence in this proceeding because the issues addressed in that testimony "are completely different from and are irrelevant to any issues in the instant proceeding," and that the rebuttal testimony does not contradict statements made by the witness in this proceeding. (SCGC Response, p. 1.) SCGC contends that its witness was unaware of Exhibits 13 and 14 when she presented her direct testimony in this proceeding. Those two exhibits were produced during the cross-examination of SoCalGas witness Watson in this proceeding on December 13, 2005, but were not used in the cross-examination of SCGC witness Yap by Exxon Mobil's counsel. It was only after the close of briefs in this proceeding that SCGC witness Yap submitted her opening and rebuttal testimony in A.04-08-018, in which she made reference to Exhibits 13 and 14. Furthermore, Exxon Mobil's motion was not filed in this proceeding until the evidentiary hearings in A.04-08-018 had been completed.
In the event Exxon Mobil's motion is granted, SCGC believes that there should be a further round of briefing to allow the parties to address the additional evidence.
The motion of Exxon Mobil to re-open the evidentiary record to allow the admission of SCGC witness Yap's rebuttal testimony in A.04-08-018 should be denied. The evidentiary record in this proceeding already contains the 1994 Settlement Agreement and the May 1999 Operational Agreement. In addition, Exhibits 13 and 14 were admitted into evidence in this proceeding without objection. One of the key issues regarding the delivery of gas by Exxon Mobil and POPCO into the SoCalGas system is the manner in which SoCalGas has treated these deliveries. The exhibits needed to shed light on this issue are already in the record, and parties had the opportunity to rebut them and to cross-examine the witnesses sponsoring the exhibits. To re-open and admit additional testimony from another proceeding to rebut points that were already raised in connection with exhibits, testimony, and argument in this proceeding is unnecessary and will unreasonably prolong this proceeding. Accordingly, Exxon Mobil's motion to re-open the evidentiary record to admit additional evidence is denied.
In deciding whether the Commission should adopt the original proposal for a sharing mechanism, the Settlement Agreement, or the Revised Joint Stipulation, it is useful to compare the prominent features of each.
Under the original native gas sharing mechanism proposal, all of the costs of exploration, development and production of the native gas is to be borne by SoCalGas. SoCalGas' sharing mechanism also proposes to transfer 68,000 dth per year of native gas, or less depending on the production of native gas, to core customers without charge. Assuming a value of $5 per dth, this confers a monetary benefit to the core of $340,000 per year. Any additional native gas would be sold on the open market, and SoCalGas' ratepayers would be paid 10% of the revenues.
SoCalGas' sharing mechanism proposal does not address how the gas production of Exxon Mobil and POPCO would be treated.
Under SoCalGas' sharing mechanism proposal, SoCalGas' use of underutilized rate-based equipment and facilities would be compensated through reduced utility transportation rates. The appropriate compensation would be determined based on the equipment being used, its design capacity, and the volume of native gas flowing through such facilities. Under the proposal, other California producers would be permitted to use the existing facilities on the same terms and conditions as the native gas program.
Under the Settlement Agreement, the core would not receive 68,000 dth per year of native gas without charge. Instead, the costs and the revenues from the production and sale of the native gas would be split equally among SoCalGas' shareholders and ratepayers, subject to the $3 million cost cap for ratepayers. SoCalGas estimates that its known native gas reservoir at Aliso Canyon contains up to 0.5 Bcf of recoverable native gas. At an assumed price of $5 per Mcf, the first year of production at this reservoir could result in a gross value of approximately $465,000. In the second year, production is likely to go down, and the gross value would amount to approximately $310,000. Production at this native gas reservoir is expected to decrease in subsequent years. The second native gas reservoir that SoCalGas is aware of is located at its La Goleta storage field. SoCalGas believes that the amount of native gas in this reservoir is between 3 Bcf and 12 Bcf.
The treatment of the Exxon Mobil and POPCO gas production is not explicitly addressed in the Settlement Agreement. However, numbered Paragraph 22 of the Settlement Agreement provides that the Settlement Agreement "is not intended to address issues associated with native gas `access' into the SoCalGas system."
The Settlement Agreement does not address the use of existing rate-based facilities by other California gas producers.
The Revised Joint Stipulation concurs in the treatment of costs and revenues as contained in the Settlement Agreement. Paragraph 7.d.v. of the Revised Joint Stipulation provides that SoCalGas is to provide other California gas producers with access to gas processing facilities at "SoCalGas' incremental cost of providing such access."
Paragraph 12 of the Revised Joint Stipulation provides in part that "native gas will be provided access to the SoCalGas system on an interruptible basis ... in a manner that does not impair existing access rights held by other California producers." The term "existing access rights held by other California producers" is defined to mean the "Maximum Daily Volumes specified in a producer access agreement or, for Exxon Mobil and its affiliate POPCO, a volume not less than 70 MMcfd."
Before we discuss what sharing mechanism should be adopted, we need to address the issue in the scoping memo of whether a sharing mechanism for the production of native gas is appropriate at all.
In deciding whether a sharing mechanism is appropriate, the benefits and drawbacks of such a mechanism should be examined. The likely benefits of exploring for and producing native gas is that it will increase the amount of gas available and dampen the price of gas. Also, ratepayers may be able to share in the native gas revenues, additional gas storage may be created, and the exploration and production of native gas will have an economic ripple effect. The possible drawbacks to a sharing mechanism are that little or no native gas will be produced, and that ratepayers will end up paying for a disproportionate share of the exploration and production costs.
A sharing mechanism will provide an incentive framework for SoCalGas to explore for, and produce native gas located near its existing gas storage fields. With two known native gas reservoirs under its control, SoCalGas is aware of the production potential at these two reservoirs. If a sharing mechanism is approved, other possible sites could be investigated as well. In the absence of an approved sharing mechanism, SoCalGas is hesitant to expend the resources needed to develop these native gas prospects.
If an appropriate sharing mechanism is approved, the benefits of exploring for and producing native gas will be maximized, while minimizing the risks to ratepayers. Accordingly, a sharing mechanism is in the public interest, and we should proceed with an evaluation of the different sharing mechanism options that are before us.
None of the parties object to the concept of a sharing mechanism. Instead, the parties who protested and raised issues in this proceeding are concerned with how the costs and revenues are to be allocated, how the mechanism will impact current California gas production, whether existing storage services will be impacted, and whether any necessary permits and approvals will be secured before any exploration and production of native gas takes place. All of these concerns, along with others, were identified in the scoping memo and are discussed below.
The original sharing mechanism proposed by SoCalGas puts all of the risk of exploration and production of native gas on SoCalGas. Although the core would receive up to 68,000 dth per year of native gas without charge under the proposal, the upside for core and noncore ratepayers would be limited to 10% of the revenues from the remaining native gas that may be produced. The proposal minimizes the economic risk to SoCalGas' ratepayers, but it also minimizes the potential to share in any native gas revenues that might result should the native gas production exceed expectations.
The Settlement Agreement, as compared to SoCalGas' proposal, increases the economic risk to ratepayers by eliminating the free 68,000 dth of native gas per year, and increasing the ratepayers' exposure to exploration and production costs up to a cost cap of $3 million. Although the ratepayers' risk increases under the Settlement Agreement, the ratepayers risk under the cost cap is mitigated by being tied to the amount of native gas production at the known native gas reservoirs at Aliso Canyon and La Goleta. If the native gas production at Aliso Canyon does not meet expectations, or if the permitting efforts for La Goleta are unsuccessful, the ratepayers' cost exposure is limited. The provisions of the Settlement Agreement also lessen the monetary risk for shareholders by having some of the exploration and production costs paid for by the ratepayers.
The Settlement Agreement allows ratepayers to equally share in the revenues from the sale of the native gas. If the native gas production at Aliso Canyon exceeds expectations, and other native gas prospects are successful, SoCalGas ratepayers would be in a position to reap economic benefits from such projects.
The Revised Joint Stipulation concurs in the cost and revenue treatment that is in the Settlement Agreement. It also expands on how much other California gas producers should have to pay to use rate-based equipment and facilities that the native gas project may use. Under the Revised Joint Stipulation, the other California producers are likely to pay less for using rate-based equipment and facilities by paying SoCalGas' incremental cost. The Revised Joint Stipulation also specifically provides a preference for gas from Exxon Mobil and POPCO over native gas production.
In deciding what cost and revenue sharing mechanism we should adopt for SoCalGas' native gas program, we should consider the parties' original positions, and their movement toward, and willingness to embrace the Settlement Agreement or the Revised Joint Stipulation. The original proposal of SoCalGas reflects the risks that SoCalGas was willing to undertake. These risks include bearing all of the costs for the exploration and production of the native gas prospects, and that SoCalGas will be able to transport the native gas over its transmission system in order to sell the gas. DRA, SCGC and TURN object to the original proposal because the proposed royalty to be paid to SoCalGas' ratepayers is viewed as too little. The California gas producers were concerned that SoCalGas' native gas production would be given preferential treatment.
To address the California gas producers' concerns, SoCalGas signed the original stipulation with the producers. SoCalGas then entered into the Settlement Agreement with DRA, SCGC, and TURN. The Settlement Agreement reflects a greater potential for ratepayers to monetarily benefit from the native gas program, while reducing SoCalGas' cost exposure. In order to resolve the cost and revenue sharing inconsistencies between the original stipulation and the Settlement Agreement, SoCalGas and the California producers agreed to the Revised Joint Stipulation, which accepted the sharing of costs and revenues as set forth in the Settlement Agreement. The Revised Joint Stipulation also specified that access to rate-based facilities by the California producers would be at SoCalGas' incremental cost, and that Exxon Mobil and POPCO would be given a preference over native gas in accessing SoCalGas' transmission system.
With the Revised Joint Stipulation, all of the parties have moved away from their original positions and gravitated toward an acceptance of the sharing mechanism as set forth in the Settlement Agreement. However, DRA, TURN and SCGC object to Paragraphs 7.d.v. and 12 of the Revised Joint Stipulation. We discuss those objections below.
Paragraph 7.d.v. of the Revised Joint Stipulation states:
"SoCalGas will provide equal access with native gas to any other nonutility producer to use the similarly situated gas processing facilities at SoCalGas' incremental cost of providing such access."
DRA, TURN and SCGC are concerned with this provision because they believe other California gas producers should be required to pay more than SoCalGas' incremental costs to use facilities that are already in rate-base. They contend that to do otherwise will result in a subsidy by ratepayers.
Paragraph 7.d.v. was included as part of the Revised Joint Stipulation to even the playing field for the California producers. Under the Settlement Agreement, SoCalGas' production of native gas is entitled to use the spare capacity of the rate-based storage facilities at no additional charge. The use of these facilities by SoCalGas without charge results in lower production costs for native gas, which increases the revenues to be shared between SoCalGas' ratepayers and shareholders.
In deciding whether Paragraph 7.d.v. should remain as part of the Revised Joint Stipulation, we should keep in mind that the Settlement Agreement and the Revised Joint Stipulation were the result of negotiations by the parties to this proceeding. In reaching those agreements, the parties' positions have changed to accommodate concessions by the various parties.
The Revised Joint Stipulation was the result of an examination by the California producers and SoCalGas as to how the original stipulation could be reconciled with the Settlement Agreement. As a result, the parties to the Revised Joint Stipulation agreed to the treatment of costs and revenues as set forth in the Settlement Agreement, including the use of rate-based facilities by SoCalGas without charge. In addition, the parties to the Revised Joint Stipulation agreed that the California producers' access to rate-based facilities should be at SoCalGas' incremental costs.
Paragraph 7.d.v. is a reasonable resolution of ensuring that SoCalGas' native gas does not gain a competitive advantage over other California gas producers. Under the Settlement Agreement, SoCalGas is not charged for the use of the rate-based facilities. As a result, this lowers the production cost of the native gas and increases revenues for shareholders and ratepayers. Paragraph 7.d.v. would require California producers to pay SoCalGas' incremental cost for using such facilities. This paragraph fairly balances the use of rate-based facilities by both SoCalGas and the California producers.
Paragraph 7.d.v. also reflects a compromise of the California producers in their acceptance of how the costs and revenues are treated in the Settlement Agreement, and with the incremental costs that they would have to pay to use rate-based facilities. When Paragraph 7.d.v. is viewed in this light, that paragraph is a reasonable compromise and resolution of how California providers should have to pay to use the same rate-based facilities that SoCalGas' native gas will be using. Accordingly, Paragraph 7.d.v. of the Revised Joint Stipulation should remain unchanged.
The other concern that DRA, SCGC, and TURN have with the Revised Joint Stipulation is with Paragraph 12. Paragraph 12 states:
"SoCalGas will accept a condition to its authorization in A.01-04-034 that until the Commission adopts a final, systemwide program for allocating firm access rights to SoCalGas receipt points,16 native gas will be provided access to the SoCalGas system on an interruptible basis (or through firm access acquired through any procedure available to new California production), in a manner that does not impair existing access rights held by other California producers. For purposes of this provision: `new California production' means production not already covered by an existing agreement for delivering onshore or offshore gas into the SoCalGas system at an existing point of receipt; and `existing access rights held by other California producers' means Maximum Daily Volumes specified in a producer access agreement or, for Exxon Mobil and its affiliate POPCO, a volume not less than 70 MMcfd."
In particular, DRA, TURN and SCGC are concerned that the paragraph's use of the term "existing access rights" gives Exxon Mobil and POPCO preference over native gas without having to undertake the burdens associated with having MDV rights. In addition, they contend that because native gas will only have interruptible access, the access rights granted to Exxon Mobil and POPCO will prevent the native gas from being transported over the SoCalGas transmission system.
The issue of what rights Exxon Mobil and POPCO have with respect to access to SoCalGas' transmission facilities was extensively examined through the testimony of the witnesses and in the briefs of the parties. The most significant point is how SoCalGas has treated the gas of Exxon Mobil and POPCO since at least the year 2000. SoCalGas has treated Exxon Mobil and POPCO as if it has MDV-like rights, and chose not to litigate this issue with them. Exhibits 13 and 14 also lend support to SoCalGas' treatment of the gas received from Exxon Mobil and POPCO. This treatment by SoCalGas justifies the inclusion of Paragraph 12 as part of the Revised Joint Stipulation.
We also agree with the argument of SoCalGas and Exxon Mobil that interruptible access for SoCalGas' native gas production, and for new California gas production, should be sufficient. The evidence demonstrates that even though there is a preference for gas from producers that have an MDV access agreement and a preference for the Exxon Mobil and POPCO gas, there will still be sufficient capacity for SoCalGas' native gas to access SoCalGas' Line 85 and the North Coastal system because of the decline in California gas production in recent years.
In addition, SoCalGas was willing under its original proposal to have its native gas production treated as interruptible access, the same as how new California gas production would be treated. This willingness on the part of SoCalGas suggests that it expects that there will be sufficient capacity to move the native gas on its system on an interruptible basis.
SoCalGas also makes an important point regarding the preference given to Exxon Mobil and POPCO in Paragraph 12 of the Revised Joint Stipulation. The California producers signed the Revised Joint Stipulation with SoCalGas, and specifically agreed to Paragraph 12. If the granting of such rights to Exxon Mobil and POPCO is unfair to the California producers, the producers would not have agreed to the inclusion of Paragraph 12.
We also agree with the arguments of SoCalGas and Exxon Mobil that Paragraph 12 of the Revised Joint Stipulation treats native gas the same as other new California gas production, and is consistent with the Commission's statements in D.04-09-022 that new gas supplies should be allowed to compete on an equal footing with existing supplies.
For all of the above reasons, Paragraph 12 of the Revised Joint Stipulation should remain unchanged.
The scoping memo identified the issue of whether the cost/revenue sharing mechanism compensates ratepayers equitably. This issue was first raised in connection with SoCalGas' original sharing mechanism, and the royalty that SoCalGas proposed that ratepayers should receive.
Under the Settlement Agreement, the costs and revenues would be shared equally, subject to the cost cap of $3 million for ratepayers. The Revised Joint Stipulation agrees with the Settlement Agreement's treatment of the costs and revenues.
As mentioned earlier, the ratepayers' cost exposure is greater under the Settlement Agreement, as compared to the original sharing mechanism proposal. However, the ratepayers' cost exposure is limited by the $3 million cost cap, and the revenues that are generated from the sale of the native gas. With respect to the ratepayers' share of the native gas revenues, the ratepayers are in a position to benefit if the production from the native gas prospects is successful. The equal sharing of the native gas revenues between SoCalGas' shareholders and ratepayers allows ratepayers to share in the profit potential of the native gas prospects. Accordingly, we find that the Settlement Agreement's treatment of the costs and revenues equitably compensates ratepayers, and is fair to both SoCalGas' shareholders and ratepayers.
Another issue identified in the scoping memo is whether the allocation from the ratepayers' share of the sharing mechanism to the core and non-core is reasonable. Under the original sharing mechanism proposal, the Settlement Agreement, and the Revised Joint Stipulation, the ratepayers' share of the revenues is to be allocated 70% to core customers and 30% to non-core customers. None of the parties disagree with this allocation. Both SoCalGas and SCGC point out that this allocation appropriately "reflects the historic average share of storage cost of service paid by the core and noncore customer classes." (Ex. 9, p. 10; Ex. 3, p. 3.) We find the allocation method to be reasonable.
The sharing mechanism for the production of native gas raised three issues in the scoping memo pertaining to the permit and approval process. The first issue is whether SoCalGas' application contemplates that the approval by the Commission authorizes "SoCalGas to drill additional wells at or near SoCalGas' existing storage fields." (Scoping Memo, p. 3.) The second issue is "Whether the additional drilling contemplated by SoCalGas is subject to CEQA [California Environmental Quality Act] review by this Commission or another lead agency." (Ibid.) The third issue is "Whether SoCalGas filed, or plans to file, for any necessary city, county or state permits, licenses, or authorizations to allow it to drill additional wells." (Ibid.)
The permitting and approval process, and possible CEQA review was raised as an issue by the County of Santa Barbara. The known native gas reservoir at La Goleta, which is located in that county, may require permits, approvals, and CEQA review. Other native gas prospects may also be subject to similar review and approval before any work begins at these sites.
The scoping memo identified these three issues to ensure that all necessary permits, approvals, and any environmental review, are obtained before any drilling for native gas takes place. SoCalGas' supplemental testimony in Exhibit 2 provides the Commission with that assurance. Once SoCalGas decides that a native gas prospect is economically viable to pursue, SoCalGas states that it "will seek the permits for such projects from State and local agencies that would be required." (Ex. 2, p. 2.) Once SoCalGas decides to pursue a project, and seeks to obtain any necessary permit, SoCalGas acknowledges that this "will trigger a CEQA review of the specific project." (Ibid.)
No CEQA review is needed at this juncture because all that SoCalGas is seeking in this proceeding is the approval of a sharing mechanism in the event it decides to seek out and produce native gas prospects. Since SoCalGas is not requesting that the Commission approve native gas exploration at any particular site, there is no "project" before us that requires CEQA review. (See Public Resources Code §§ 21065, 21080.) As a condition of our approval of the sharing mechanism, we shall require SoCalGas to obtain all permits and approvals that a local or state agency may require before any exploration or production of native gas, or gas storage activities, take place.
Another concern of the scoping memo was whether the native gas projects would be subject to the same kind of gas quality requirements that are in place for other gas producers. Under Paragraph 7 of the Revised Joint Stipulation, SoCalGas agrees to "apply all rules, regulations, agreements, standards, protocols, tariffs or other terms and conditions (`access rules') to its native gas production operations in the same manner in which it applies these access rules to other California nonutility natural gas producers."
The list of applicable access rules that SoCalGas agrees to use was filed on August 20, 2004 in its Supplement to the original stipulation. The Supplement, which is labeled "Interim Rules Applicable to Native Gas" is attached to this decision as Appendix D. The Supplement sets forth the access rules that SoCalGas will apply to the production of native gas. As part of these access rules, SoCalGas will sample and test the native gas for the gas characteristics shown in the Supplement. None of the parties raised any concern with SoCalGas' testing of the gas quality for native gas.
In addition to the testing of the gas characteristics, Paragraph 16 of the Settlement Agreement and Paragraph 8 of the Revised Joint Stipulation contain similar provisions which require SoCalGas to file a quarterly report with the Commission which details the total volume of gas produced in each field and delivered into any regulated facilities, as well as "all native gas quality data for the relevant period...."
The access rules and reporting requirement, as agreed to by SoCalGas, will ensure that the native gas that is produced will meet the same gas quality specifications as other California gas producers are required to meet.
The scoping memo expressed concern about the impact of the native gas project on existing gas storage operations, and that none of the native gas production come from storage gas. Both the Settlement Agreement and the Revised Joint Stipulation contain provisions to actively monitor native gas production and storage reservoir data. This monitoring is to guard against such events from happening. These monitoring provisions appear in Paragraph 19 of the Settlement Agreement and in Paragraph 11 of the Revised Joint Stipulation.
In addition to the reporting requirement, we interpret these two monitoring paragraphs to mean that SoCalGas shall immediately notify the Commission if SoCalGas discovers that storage gas has been produced as a result of the production of native gas. This interpretation is consistent with the requirement to "actively monitor" to prevent the gas storage operations from being compromised.
The scoping memo identified the issue of whether additional gas storage will be created as a result of the native gas project, and who will retain control over the use of the depleted well. Paragraphs 20 and 21 of the Settlement Agreement address the additional gas storage issue.
Paragraph 21 addresses the known native gas reservoir at the La Goleta storage field. This gas reservoir is located underneath the existing La Goleta storage reservoir. According to the Settlement Agreement, SoCalGas has sufficient information to determine that this reservoir can be used to provide Commission-regulated gas storage service. SoCalGas plans to design and construct the wells and related facilities for storage service, and will not seek additional Commission approval to do so. SoCalGas expects that the costs to utilize the new reservoir for gas storage will be minimal. If there are additional costs to make the reservoir ready for gas storage purposes, SoCalGas plans to add these incremental costs as part of SoCalGas' storage costs in the next rate proceeding which addresses such costs.
With respect to all other depleted native gas or oil reservoirs, or any wells or other facilities that have been installed pursuant to the Settlement Agreement, if they are suitable and economic to use in providing gas storage service, SoCalGas will seek Commission approval by filing an application before the reservoir or facilities are used to provide gas storage services.
Under the procedures set forth in Paragraphs 20 and 21 of the Settlement Agreement, the Commission, with the exception of the native gas reservoir at La Goleta, will need to approve all applications to convert depleted wells, reservoirs, and related facilities to gas storage service. Such a review will provide the Commission, with the input of interested parties, to determine how to allocate the storage capacity, the costs, and the revenues, of any new storage reservoirs and related facilities.
As for SoCalGas' plan to use the native gas reservoir at La Goleta, once it is depleted, for gas storage without further Commission approval, we will allow that to occur provided that SoCalGas obtains any permits or approvals that may be required by any other local or state agency to produce the native gas at this known reservoir, or to use the depleted reservoir for gas storage. In particular, the County of Santa Barbara may require a permit before any drilling at La Goleta takes place. This requirement is consistent with SoCalGas' June 17, 2004 supplemental testimony, Exhibit 2, in which SoCalGas' witness states that it will seek the permits that may be needed from the local and state agencies.
In the protests to SoCalGas' native gas proposal, some of the parties raised the issue of whether it would be more cost effective for SoCalGas to have a third-party drill the wells and produce the gas. This issue was included in the scoping memo.
Under the Settlement Agreement and the Revised Joint Stipulation, Paragraphs 1 of both documents contemplate that SoCalGas will be doing the exploration and production of the native gas. If necessary, SoCalGas might utilize a partner company to assist in the exploration and production.
Prior to filing this application, SoCalGas considered, but decided against, having third-party exploration and production companies bidding for the rights to explore and produce the native gas prospects located at the SoCalGas storage fields. According to Exhibit 2, SoCalGas decided not to pursue this option because of the pre-bidding costs and resources that were needed in order to assemble the bidding packages, the issues regarding possible production of storage gas as a result of the native gas projects, and the royalty amount that SoCalGas would likely receive from the exploration and production companies.
Due to these considerations, it is appropriate that SoCalGas control all the exploration and production activities related to the native gas prospects. SoCalGas' retention of these activities should minimize the costs of the native gas prospects while maximizing the revenue potential for SoCalGas' shareholders and customers.
The scoping memo identified the issue of whether the native gas production will affect SoCalGas' Gas Cost Incentive Mechanism (GCIM). The supplemental testimony of SoCalGas witness Garry Yee stated that "any gas sold to the Gas Acquisition Department (or an affiliate) would be pursuant to an open, competitive bidding process." (Ex. 4, p. 2.) If SoCalGas' Gas Acquisition Department is awarded a native gas purchase contract in that bidding process, the cost of that gas purchase contract would be included in the GCIM. Paragraph 6 of the Revised Joint Stipulation provides that "all native gas sales either to an affiliate or to the SoCalGas Gas Acquisition Department shall be through an open, competitive bidding process...."
The GCIM provides an incentive framework for SoCalGas to make gas purchases below the benchmark. As long as the purchases of native gas by SoCalGas are done through an open, competitive bidding process, which SoCalGas has agreed to in the Revised Joint Stipulation, the purchase of native gas by the Gas Acquisition Department should not pose any affiliate transaction problems or result in any gaming of the GCIM results.
Based on the above discussion of the different sharing mechanism proposals, it is clear that all of the parties favor the Settlement Agreement, provided that the Revised Joint Stipulation, or portions of it, is also adopted. The original sharing mechanism proposal of SoCalGas is not satisfactory to the other parties unless changes to the proposal are made. The changes that the other parties propose, and which SoCalGas agrees to, are contained in the Settlement Agreement and the Revised Joint Stipulation. For that reason, we focus on these two proposals.
In evaluating whether the Commission should adopt or reject a settlement or a stipulation, we rely on the settlement and stipulation rules set forth in Rules 51 to 51.10 of the Commission's Rules of Practice and Procedure. In particular, Rule 51.1(e) provides that: "The Commission will not approve stipulations or settlements, whether contested or uncontested, unless the stipulation or settlement is reasonable in light of the whole record, consistent with law, and in the public interest."
A "settlement" is defined in Rule 51(c) to mean "an agreement between some or all of the parties to a Commission proceeding on a mutually acceptable outcome to the proceedings." A "stipulation" is defined in Rule 51(d) to mean "an agreement between some or all of the parties to a Commission proceeding on the resolution of any issue of law or fact material to the proceeding."
A "contested" settlement or stipulation is when any party is opposed in whole or in part to the settlement or stipulation that is being proposed for adoption by the Commission. (Rule 51(e).) If a settlement or stipulation is contested, the Commission will schedule a hearing on the contested issues.
After a lengthy review by the parties of the original stipulation, the Settlement Agreement, and the Revised Joint Stipulation, the only two issues that parties contested were Paragraphs 7.d.v. and 12 of the Revised Joint Stipulation. Evidentiary hearings on those issues were held in December 2005, as discussed above.
The Settlement Agreement and the Revised Joint Stipulation should be adopted by the Commission. The Settlement Agreement resolves issues that were of concern to DRA, TURN, SCGC, and SoCalGas. With the filing of the Revised Joint Stipulation, no other party objects to the adoption of the Settlement Agreement.
Although DRA, TURN, and SCGC object to two paragraphs in the Revised Joint Stipulation, the Revised Joint Stipulation is acceptable to SoCalGas and the parties representing California gas producers. For the reasons we discussed earlier, the two paragraphs in the Revised Joint Stipulation should remain, and the proposals of DRA, TURN and SCGC to modify or eliminate those two paragraphs should be rejected.
Based on the interaction between all of the parties to this proceeding, the compromises that the parties agreed to in the Settlement Agreement and the Revised Joint Stipulation, our discussion of the two paragraphs in the Revised Joint Stipulation, and our discussion of the other issues identified in the scoping memo, both the Settlement Agreement and the Revised Joint Stipulation are reasonable in light of the record in this proceeding, consistent with the law, and in the public interest. The Settlement Agreement and the Revised Joint Stipulation, as clarified by us in our discussion above, should be adopted by the Commission as the cost and revenue sharing mechanism for SoCalGas' exploration and production of native gas. As part of the adopted sharing mechanism, the Interim Rules Applicable to Native Gas as set forth in the August 20, 2004 supplement and attached hereto as Appendix D, shall also be part of the adopted sharing mechanism.
In accordance with Rule 51.8 of our Rules of Practice and Procedure, the adoption of the Settlement Agreement and the Revised Joint Stipulation in this proceeding shall not be considered as precedent for use in any other proceeding.
3 The term "native gas" refers to the natural gas that naturally occurs in subsurface formations which adjoin the SoCalGas storage fields, but which is not connected to these storage fields.
4 According to the testimony of the SoCalGas witness, SoCalGas has produced approximately 68,000 decatherms (dth) per year of natural gas in association with its gas storage operations over the five-year period of 1998 through 2002. This gas was transferred to the core and core subscription customers at no cost, which resulted in lowering the cost of gas for core customers.
5 SoCalGas is not seeking Commission approval for any specific drilling project. If the revenue sharing mechanism is approved, SoCalGas will determine if any of the native gas projects are economically viable, and then obtain any permits that may be needed.
6 SoCalGas' proposed revenue sharing mechanism would not apply to the production of native gas from SoCalGas' Montebello storage field. A revenue sharing mechanism for the sale of native gas from Montebello was previously approved in D.01-06-081.
7 The effect of this will lower the weighted average cost of gas that is charged to core procurement customers through the Purchased Gas Account.
8 Under the proposal, if crude oil is produced in association with the production of native gas, the revenue from the sale of that oil will be treated in the same manner as the revenue from the sale of native gas.
9 The application proposes that the ratepayers' proceeds be allocated 70% to core customers and 30% to noncore customers.
10 Paragraphs 7.d.v. and 12 of the Revised Joint Stipulation, in which DRA, TURN and SCGC object to, were included as part of the original stipulation in slightly different language.
11 Under the Settlement Agreement, the ratepayers' share of the revenues would be allocated 70% to core customers and 30% to noncore customers.
12 The "California producers" refer to the Indicated Producers, the California Independent Petroleum Association, the California Natural Gas Producers Association, and the Western States Petroleum Association.
13 SoCalGas witness Watson testified that the agreed upon Maximum Total Daily Quantity (TDQ) of 78,000 MMbtu corresponds to an MDV around 70,000 MMcfd. (1 RT 104.)
14 TURN opposed SoCalGas' original proposal that ratepayers receive 10% of the gross revenues from the native gas production. TURN recommended that ratepayers receive 35% of the gross revenues.
15 According to Exhibit 10 at page 1, this proposed modification of Paragraph 12 of the Revised Joint Stipulation is also supported by TURN and DRA.
16 Footnote 2 of the Revised Joint Stipulation appears at this point, but is not repeated here.
