Phase I Issues: SDG&E

The following parties filed post-hearing briefs on Phase I Issues: Cabrillo I, LLC and Cabrillo II, LLC (Cabrillo); Gasoducto Rosarito (GR); SDG&E and SoCalGas; Office of Ratepayer Advocates (ORA); Duke Energy North America (Duke); Sempra; PG&E National Energy Group (PG&E NEG) and Calpine Corporation (Calpine); City of Long Beach (Long Beach); California Independent System Operator Corporation (ISO); Calpeak Power LLC (Calpeak); San Diego County Air Pollution Control District (APCD); California Industrial Group and California Manufacturers & Technology Association (CIG/CMTA); The Utility Reform Network (TURN); and Southern California Generation Coalition (SCGC).

I. Past and Future Planning and System Expansion

The focal point of this OII is whether SDG&E's gas transmission system planning was reasonable and consistent with the Commission's adopted planning criteria. In its 1998 BCAP Application A.98-10-031, SDG&E proposed a resource plan of $25 million. ORA proposed a resource plan of $42.7 million. In D.00-04-060, the Commission ultimately adopted a $31 million plan, which was the amount agreed to by the parties to the SDG&E Joint Recommendation. The Joint Recommendation does not indicate what specific system improvements were agreed to by the settling parties, which system improvements were added to the SDG&E plan, or which were eliminated from the ORA plan.

In the 1996 BCAP, the Commission ordered SDG&E to provide "an explicit non-core reliability standard for its firm service transportation customers that reflects the level of service its system is able to provide" (D.97-04-082, mimeo., at 139). In response to that order SDG&E filed a reliability report based on 1 curtailment in 5 years (1-in-5) firm noncore reliability standard. In the 1998 BCAP, SDG&E continued to advance this 1-in-5 firm noncore reliability standard.

SDG&E curtailed service to firm noncore customers on 17 days between November 2000 and March 2001. SDG&E states that in October 1998, when the BCAP application was filed, it did not contemplate extending firm service to EG customers. SDG&E argues that at that time, SDG&E owned its generation plants and the plants were not sold until April and May of 1999.

We find this a poor excuse for the inadequate planning which caused the service interruptions to SDG&E firm noncore customers over a period of four months in late 2000 and early 2001. Hearings in the BCAP were held in April 1999. SDG&E certainly should have anticipated that the plants were to be sold when they filed the 1998 BCAP Application, and had ample time to update its resource plan prior to hearings to encompass the fact that it would no longer be operating the generation plants. Instead, SDG&E continued to advance a resource plan based on its ownership and operation of the plants and past demand. SDG&E then entered into a joint agreement to adjust the resource plan without regard to necessary and specific system improvements or the changes in operation that were to follow.

Further indication of SDG&E's failure at system planning is evidenced by the fact that in April 2000, a full year later, when all three EGs elected firm service, SDG&E still did nothing to improve its system capacity to meet the new firm load. A review of the transcript from the hearing on the testimony and cross-examination of Ben Montoya, sponsor of Section 2 of the direct testimony of SDG&E and SoCalGas in Phase I, and the exhibits used by SCGC on cross-examination (Exhibits 803 and 804)⁴ show that SDG&E knew that curtailments were imminent in 2000. Exhibit 803, SDG&E's Gas Department update for presentation at the Fuels and Purchase Power Team (F&PP) meetings June 22, 1999, and May 4, 2000, demonstrates knowledge by SDG&E that there was a possibility of curtailment in Summer and Winter 2000, increased curtailment likely in 2001 and 2002, substantial curtailment in 2003 if the Otay Mesa Plant is in service, and that a Miramar enhancement would reduce, but not eliminate curtailment.

The SDG&E meeting and slide presentation on May 4, 2000, took place after the EG customers had signed up for firm service. At that time SDG&E management fully understood the lack of capacity on the system, but chose not to commit money to any expansions without a guarantee of recovery. We find SDG&E's past system capacity planning to be both inadequate and irresponsible.

At this time, we reject TURN's proposal that utility transmission resource plans be considered in a new BCAP. However, it is abundantly clear that SDG&E's past resource planning was not adequate to plan for the evolution of its system load. Therefore, we direct SDG&E and other affected parties to address the resource plan in the upcoming General Rate Cap (GRC), or other appropriate proceeding, with great care so that the demands on the system will be met within SDG&E's newly adopted reliability standard for firm noncore service of 1-in-10, cold year conditions.

A key component of the future planning and system expansion plans of SDG&E is the reliability standard adopted for firm noncore customers, including EGs. Parties offered a range of reliability standards for our consideration. For example, SDG&E proposed a standard of one curtailment in every 10 years, normal weather conditions, with each such curtailment lasting no longer than 3 days, (1-in-10) and Duke and Cabrillo advocated one curtailment in every 35 years, using an abnormal cold year peak day as the standard. (1-in-35). As many parties to the OII discussed, the reliability standard is inextricably connected to cost allocation issues and system expansion concerns. Although reliability issues impact cost, cost must not be the sole determining factor in developing system capacity to support the demand on the SDG&E system.

The reliability standard adopted also determines the amount of excess or "slack" capacity that is on SDG&E's transmission system. Many parties argued that there should be at least 15 to 20% slack capacity on the system despite the fact that slack capacity is costly because it provides capacity that is available to accommodate scheduled and unscheduled outages, higher than anticipated peak demands, and increases in new and existing customers' demands. In balancing the concerns over who pays for this excess capacity against the increased reliability the excess provides, the Commission finds it is in the interest of all gas transmission users to adopt a 1-in-10 (one curtailment in ten years), cold year conditions, reliability standard for SDG&E. With this standard, the Commission will not adopt a mandatory slack capacity requirement.

If SDG&E expands its system to meet a 1-in-10, cold year reliability standard, for even its firm noncore customers, SDG&E's transmission system infrastructure should be adequate to meet the needs of both its core and noncore customers. To begin, at the time this investigation was initiated, all of SDG&E's customers were receiving firm service. This decision authorizes SDG&E to only offer firm noncore service when it has the capacity. In addition, Line 6900, a line on SoCalGas' system, flows directly into SDG&E's territory, is now in service and adds 70MMcfd⁵ to southern California. When Line 6900's capacity is combined with the Baja Norte pipeline's capacity will help in easing capacity constraints.

As discussed further below, the Commission is also authorizing a service interruption credit (SIC) for firm customers. SoCalGas had a similar SIC for over ten years, during which time there were no curtailments. When the 1-in-10, cold year reliability standard is combined with the SIC, the additional capacity Line 6900 already provides, and the anticipated relief Baja Norte will bring, the Commission trusts that SDG&E will design and implement appropriate system expansions that will reduce or eliminate the likelihood of curtailments, yet not contain excess slack that will result in stranded costs.

To maintain a 1-in-10 reliability standard with the accompanying necessary, excess capacity, SDG&E will have to be realistic, proactive, and regularly update its resource plan. We direct SDG&E to submit a report on its capacity planning, demand forecast, and the status of its expansion projects to the Energy Division (ED) with the first report due on October 30, 2002, and subsequent reports following every six-months thereafter. This report must contain information regarding all requests for firm service that SDG&E was unable to provide and for which it offered interruptible service at interruptible rates instead.

II. Curtailment Protocol

When the OII was initiated in November 2000, the SDG&E gas transmission system had been running at peak capacity on numerous days since July 2000, and gas curtailments to noncore customers seemed imminent. During the week of November 13, 2000, noncore customers suffered curtailments. SDG&E's curtailment protocol is described in Gas Tariff Rule 14 (Rule 14). A.L. 1210-G proposed to alter Rule 14 and temporarily treat SDG&E's three major EGs, Dynegy Marketing and Trade (Dynegy), Duke, and GR⁶ as interruptible customers, despite the fact that all three EGs had contracted for firm service. Numerous parties filed protests to the A.L. and SDG&E ultimately withdrew it.

On November 17, 2000, Dynegy and Duke each filed a motion to modify Rule 14. The Commission then solicited comments from the parties on proposals for interim changes to Rule 14. On June 7, 2001, the Commission issued D.01-06-008 to establish an interim order changing the curtailment rules.

The interim order authorizes curtailments to EGs receiving firm service on a pro rata basis and curtails firm service for noncore customers on a rotating block basis in the event the amount of load curtailment from firm service EGs' is insufficient to meet demand requirements.

When SDG&E administered curtailments pursuant to the former protocol, all firm service noncore customers, including noncore commercial and industrial customers and EGs, were curtailed pursuant to a rotating block formula. All of the comments support exempting the noncore commercial and industrial customers from the initial curtailment protocol because they were so adversely affected when curtailed, yet their total load was insignificant compared to that of the EGs.

The parties differ extensively, however, on their recommendations for EG curtailments. Cabrillo and APCD recommend that GR, since it is providing service to an EG outside SDG&E's service territory, be curtailed before either of SDG&E's local EG customers. APCD's primary concern is with the air quality in the San Diego area and its fear that if Duke and Dynegy are curtailed, they will continue to generate by burning oil, and compromising air quality and posing health risks to San Diego citizens. Conversely, GR and other parties maintain that GR should be curtailed last since it is the most efficient generating facility. SDG&E, ORA, and SCGC contend that there is no justification for differentiating between the three EGs since they all pay the same rate and take service pursuant to identical conditions. GR agrees with this position and opposes any discrimination between like service classes.

The interim order adopts a pro rata curtailment for all SDG&E EG customers. Pro rata curtailment for the EGs is fair, treats GR equally with the other SDG&E EG customers, and maximizes the amount of gas available to EGs and other customers. We note that as of the date of the issuance of this proposed decision, SDG&E has not had to administer any gas curtailments for any of its customers pursuant to the changes to Rule 14. We will adopt the interim rules on a permanent basis.

A. Limiting Firm Noncore

Under its applicable tariffs, SDG&E must offer service to all customers who so request within its service territory. A critical question for this proceeding is whether SDG&E may limit firm noncore service to the amount of firm capacity on the system. Currently, SDG&E does not have the authority under its tariff structure to limit its firm noncore service. If either a new customer or an existing customer wants firm service, SDG&E is presently obligated to provide firm service whether or not there is sufficient capacity to

guarantee this level of service. This obligation, coupled with the fact that SDG&E's EG rates for interruptible service and firm service are identical, contributed to the capacity constraints on SDG&E's system that necessitated the gas curtailments in the fall and winter of 2000 and 2001.

When GR signed up for service from SDG&E it requested firm service. Dynegy and Duke, who were not then receiving firm service, soon followed suit. All EGs received firm service at the same rate as interruptible service. SDG&E was obligated under its tariff to convert these customers to firm service, even though it appears that SDG&E did not have enough firm capacity available to guarantee uninterrupted service to these noncore customers. SDG&E has only a finite amount of available firm capacity on its system at any one time. Therefore, it is fair to customers who opt for, and pay for, firm service that their service is firm-and not interruptible by default. As we discuss later in this decision we are also requiring SDG&E to price interruptible service differently from firm service. Thus, SDG&E contends that it must be authorized to limit firm service to available firm capacity. If it does not receive such approval, SDG&E maintains that firm service customers for all practical purposes are getting service that is subject to interruption.

ORA supports SDG&E's proposal, as do Cabrillo and Duke. Cabrillo and Duke, however, suggest that once SDG&E upgrades its system to meet the appropriate reliability levels for existing customers, it should conduct an open season to allocate firm service to new firm customers and incremental load. GR also backs SDG&E's recommendation, as long as all noncore customers have an equal, nondiscriminatory opportunity to opt for the service they desire, including firm or interruptible service. CIG/CMTA is willing to support SDG&E's proposal, but only if it doesn't impair the quality of existing firm service.

SCGC is concerned that SDG&E would have no incentive to invest in expanding its system, if the Commission authorizes SDG&E to limit firm service to available firm capacity, and the result will be reduced firm capacity. Sempra also opposes allowing SDG&E to limit firm service. Sempra contends that nondiscriminatory treatment within each customer class requires SDG&E to offer firm service to new EG customers, or else they will be barred from entry into the market.

We authorize SDG&E to limit firm service to noncore customers to the firm capacity available, but, as discussed, we have also authorized a reliability standard of 1-in-10. This reliability standard, along with the service interruption credits, will serve as sufficient incentive to SDG&E to continue making investments in its system to meet the needs of its firm noncore customers and to avoid curtailments.

In summary, SDG&E must still provide service to any customer in its service territory that requests service. If a customer requests firm service, and SDG&E determines there is insufficient capacity on its system to ensure firm service, it must offer that customer interruptible service at an interruptible rate. However, SDG&E must also expand its gas transmission system so that it complies with the 1-in-10, cold weather conditions, reliability standard adopted in this decision. As previously indicated in Section I, SDG&E must submit in its semi-annual report to the Energy Division information on all requests for firm service that it was unable to provide and for which it offered interruptible service at interruptible rates instead.

In addition, we order SDG&E file an Advice Letter with interruptible rates for interruptible noncore service, within 30 days of this decision.

B. Allocation of Firm Capacity in an Open Season

We expect major changes in SDG&E's territory within the next two years. The Baja Norte Pipeline is scheduled to come on line in 2003. This has potential to relieve some of the constraint on the SDG&E system. The Otay Mesa Generating Project is scheduled to begin operation and it may impact the system. Because of the dynamic environment affecting gas demand in the San Diego area, we order SDG&E to initiate an Open Season for firm noncore service within 30 days from the date of this decision. The Open Season commitment will be for a period of 24 months, with all customers bidding by month for any of the 24 months in which they desire to receive firm service.

In the Open Season, customers will be required to commit to the level of their bid, for those months for which they bid. There will be a take-or-pay provision for customer commitments to encourage customers to bid realistically and to prevent gaming on the system. There will be no tradable rights at this time because SDG&E does not have the mechanisms in place to administer those rights. When SDG&E and its customers have a better understanding of how the changes taking place in SDG&E's territory affect them, they can apply for authority to implement tradable rights with a proposed administrative mechanism.

The parties suggested numerous ways to allocate the firm capacity between existing customers and new customers. To avoid favoring any one customer group to the detriment of another, we establish an allocation protocol for firm noncore capacity as follows: After the conclusion of the open season, existing customers will be allocated firm capacity to the demand level of their most recent 12 months. SDG&E must assign any remaining firm capacity to the new incremental load of existing customers and to new customers. If available firm capacity is oversubscribed by the new incremental load of existing customers and that of new customers for any month, SDG&E must prorate the available capacity equally across that customer base.

C. Curtailment Credit

Several parties urge the Commission to adopt a service interruption credit (SIC) or curtailment credit for SDG&E similar to SoCalGas' Rule 23.⁷ SDG&E opposes the SIC and argues that the Commission has full authority to take action against SDG&E if it doesn't live up to the noncore reliability standards. SDG&E argues that a curtailment credit would give the utility an "artificial incentive" to pursue additional pipeline and compressor related capital improvements that would raise transportation costs (SDG&E Opening Brief, p. 20). ORA is not convinced that a curtailment credit is warranted, but states that parties are free to negotiate such a provision.

PG&E NEG and Calpine support a curtailment credit to compensate customers if SDG&E fails to meet its service reliability obligations. SCGC favors the curtailment credit as an incentive tool. In agreement with SCGC, CIG/CMTA argue that "absent a curtailment credit or service guarantee, SDG&E's firm noncore reliability standards would be nothing more than aspirational goals" (CIG/CMTA Opening Brief, p. 5). CIG/CMTA maintain that should SDG&E fail to achieve its reliability standards, there would be no specific penalty, other than a vague promise that Commission might take some unspecified action. We find merit in CIG/CMTA's argument.

Since the inception of the SIC for SoCalGas in D.91-11-025, SoCalGas has not experienced a curtailment necessitating payment of the SIC. It appears the penalty has been an effective measure in motivating SoCalGas to plan its system capacity. It is apparent that SDG&E has not been so motivated in planning the capacity of its system. Increasing convergence of the gas and electric markets makes lack of capacity planning not only a serious problem for gas customers, but impacts SDG&E's electric service as well. We do not find the SIC to be an artificial incentive as SDG&E argues. Instead, we find that it encourages considered capacity planning and related enhancements to meet increased load. The customers of SDG&E cannot be subject to the gas capacity curtailments of 2000 and 2001.

Therefore, although the SIC plan for SoCalGas is no longer in effect, we will adopt a SIC for SDG&E with the same properties as that of the former Rule 23 for SoCalGas. The SIC shall be set at $.25 per therm. We will not consider high demand for gas due to weather conditions to be a force majure event, nor will we place an annual cap of $1 million on SDG&E's curtailment-related obligations. We find that weather conditions must be an integral part of a utility's capacity planning process and will hold SDG&E to the same $5 million cap as was contained in Rule 23 for SoCalGas. We are optimistic

that this curtailment credit will work as well as it did for SoCalGas and increase

SDG&E's service reliability without penalizing it.⁸

D. Long-Term Commitments and Tradable Rights

SDG&E argues that the key for its effective future planning for noncore customer demand is to require long-term commitments from customers demanding firm service. Specifically, SDG&E wants to require small noncore customers⁹ to make a five-year commitment, and large noncore customers¹⁰ to make a 15-year commitment. SDG&E believes these commitments will enable it to pursue least-cost resource planning and eliminate potential investment that are not necessary to meet firm noncore reliability needs.

ORA and TURN were the only parties advocating 15-year commitments. GR, while it concurred with SDG&E's desire to obtain commitments on which to gauge and base expansion needs, contends that 15-years might be impractical for some large, noncore customers. Cabrillo, SCGC, Duke, PG&E NEG, Calpeak, and CIG/CMTA all oppose the 15-year commitment as excessive and unnecessary, because it forces the customers to commit to long term contracts, and penalizes them with harsh take-or-pay penalties. On the other hand, many parties view the five-year commitment as reasonable if the noncore have tradable rights to the capacity.

We agree that SDG&E could improve its long-term resource plan forecast if noncore customers are required to make long-term commitments. We note that ORA and TURN agree with SDG&E's 15-year requirement for large EG customers. Some parties are concerned that the EGs will be enticed away from the SDG&E system by competing interstate pipelines, or even by Baja Norte, and then captive customers will be left paying for any stranded costs unless long term commitments are required.

Other parties believe requiring long-term commitments places extraordinary risk on customers who, in a constantly changing and volatile energy market, are expected to project their monthly demand for 15 years and pay a substantial penalty if their projections are too high. Those parties state that allowing for tradable rights would ameliorate this problem.

As mentioned above, however, SDG&E does not have a mechanism in place to manage tradable rights and there are still a number of significant questions concerning tradable rights that need to be aired. The record in this proceeding does not support the Commission's authorization of tradable rights at this time. So we will not require customers to make long-term commitment at this time.

III. Pre-Construction Activities¹¹ on Written
Indication of Interest

SDG&E projects that there is a two-to-four year lag period between the time a need for additional capacity on its system is identified and the time the system is expanded and that capacity becomes available. SDG&E is concerned that if it initiates pre-construction activities when it receives a written indication of interest, but the customer fails to follow through with a firm commitment, SDG&E would have incurred costs for a project that may be unnecessary and useless. On the other hand, if the utility doesn't begin the pre-construction activities upon the indication of interest, and the customer does follow through with the project, the system expansion will not be ready in time to provide needed new capacity.

To avoid this dilemma, we authorize SDG&E to take the following actions upon receipt of a written indication of interest in firm service: 1) determine if a system expansion is necessary to serve the new projected demand; 2) if so, collect a deposit of 20% of the cost of forecast pre construction activities from the potential customer, or customers, if there is multiple customer interest; 3) undertake pre-construction tasks necessary to meet the projected incremental demand; and 4) if the customer follows through with a firm commitment for service, refund the deposit and commence construction otherwise, keep the deposit. From that point forward, normal ratemaking principles would apply to the expansion project.

V. Cost Allocation and Rate Design

A. Differential Between Firm and Interruptible Rates

Presently, SDG&E's rates for firm and interruptible service are the same. SDG&E recommends a price differential between these two levels of service to reflect the differing reliability standards associated with each service level. PG&E NEG and Calpine agree with SDG&E. They propose that firm rates should include a monthly demand charge, for the reservation of capacity, and interruptible rates should be all volumetric without a use-or-pay requirement. PG&E Neg and Calpine argue that a price differential between the levels of service would make SDG&E more competitive and facilitate greater pipeline-to-pipeline competition in Southern California.

ORA argues that SDG&E should use the Sempra-wide EG rate for interruptible EG service, and use the current, non-Sempra-wide EG rate for firm service. TURN opposes price differentiation of noncore rates.

Not surprisingly, many of the large noncore customers that benefit from the undifferentiated rate structure by paying no more for receiving an explicit level of reliability, urge the Commission to keep both rates the same. SCGC argues that the current rate structure takes into account the price differentiation between the levels of service by permitting negotiated rates for interruptible service.

Other parties, such as Cabrillo and GR, agree with the general principle that a price differential should exist between true firm service and interruptible service, but GR states that the price differentiation must be disclosed to the customers in advance of the customer's service election.

We will authorize SDG&E to charge different rates for firm and interruptible service. As previously stated, SDG&E shall file an Advice Letter with interruptible rates on interruptible noncore service within 30 days of this decision. On a policy level, it is reasonable to charge higher rates to those customers that benefit from firm transmission service. In addition, offering customers differing levels of service reliability at commensurate rates may allow SDG&E to compete on a more comparable footing with rates of new interstate and international pipelines and may facilitate pipeline-to-pipeline competition in Southern California by enabling customers to evaluate and compare competitive options.

VI. Affiliate Interests

A. Corporate Affiliate Interests

One of the questions within the scope of this OII is whether the corporate affiliate interests of Sempra, the parent company of both SoCalGas and SDG&E, affected SDG&E's transmission service and its system expansions. SDG&E maintains that its corporate affiliate interests have not played a role in its resource planning. SDG&E contends that projects were not delayed, accelerated, added, or subtracted based on information or direction from an affiliate or Sempra. SDG&E argues that it and SoCalGas independently analyze their respective system needs and pursue the appropriate funding for such needs.

Many parties argue that SDG&E's decision to provide firm noncore service to GR compromised its ability to serve the current and possibly the future needs of its existing core and noncore customers. SDG&E does admit that providing service to GR meant less excess capacity was available to serve other noncore customers, but it argues that the same condition would have existed if they had provided service to any new customer.

APCD reviewed the Sempra affiliate list and concludes that Sempra can make more money supplying gas to GR than to the local San Diego EGs. APCD is concerned that because of GR and the demand it makes on SDG&E's system, the probability of gas curtailments to the local San Diego EGs is heightened. If Dynegy and Duke are curtailed, they have the capability of converting to oil; but burning oil contributes to air pollution that can damage the environment and the health and safety of San Diego residents. San Diego air quality standards also limit the amount of oil that can be burned. APCD contends that SDG&E misled the Commission and others when it requested the tariff for GR, and omitted the Duke and Dynegy EGs from its forecasts for gas transmission capacity. SDG&E should have known its "sister affiliate" GR would elect firm service, and that other large EGs would follow. APCD feels that SDG&E should have only offered GR interruptible service, and not put the local San Diego EGs at risk for curtailments.

GR, on the other hand, asserts that the uncontroverted facts in this case demonstrate that SDG&E's transmission service and system expansions have not been affected by Sempra's affiliate interests. GR claims that in SDG&E's tariff application for GR, intervenors argued that, because the contract had been awarded to a Sempra affiliate, the potential for affiliate favoritism required the Commission's strictest scrutiny. In fact, GR, continues, under this strict scrutiny it was determined that GR would be treated like the other EGs, and service to GR should be at the same tariff rates. Conversely, Cabrillo believes that SDG&E took advantage of the need for system expansions to meet its customer's needs, and instead of expanding to meet the existing noncore customers, expanded to provide service to GR. Cabrillo suggests that the Commission must be extra vigilant and alert to any signs of improper arrangements between Sempra and any of its affiliates and must vigorously enforce the affiliate transaction rules.

TURN presents a different analysis. TURN contends that Sempra has long sought to capture the developing Mexican market and tried to prevent a challenge from competing pipelines by offering a discounted rate for utility services. When the Commission denied Sempra's request to offer reduced tariff rates to Mexico, TURN states that Sempra and its affiliates began building the Baja Norte pipeline to serve the largest EG load in Mexico. TURN argues that the Baja Norte pipeline creates a conflict of interest for Sempra between the ratepayers of its regulated utilities and its shareholders' interest in the profitability of the Baja Norte pipeline. TURN fears that when Baja Norte is completed, it will attract significant load-load that could be served by the existing utilities' system. If there are stranded costs for expansions for SDG&E's system because of an exodus to Baja Norte, TURN is concerned that the ratepayers will be at risk for these costs.

B. Baja Norte Pipeline

Inextricably intertwined with the question on the corporate affiliate interests of Sempra is Sempra's decision to go forward with the Baja Norte pipeline expansion. The pipeline project will run from Ehrenberg, Arizona to Tijuana, Baja California. The project was announced June 12, 2000, and an open season was held June 19 to July 14, 2000. A Sempra affiliate owns the 135 miles of pipeline in Mexico.

As stated in the OII, the Commission is concerned that Sempra's decision to go forward with the Baja Norte project was made at the expense of SDG&E's needs for its core and noncore customers. When the project was announced in June 2000, SDG&E clearly knew there existed a lack of capacity on its system and a substantial likelihood of curtailments.

SDG&E claims the Baja Norte pipeline has not affected the system expansions of either SDG&E or SoCalGas. In fact, SDG&E agrees with part of TURN's analysis i.e., when the Commission denied SDG&E's application to offer discounted rates to Mexico, the stage was set for Baja Norte. SDG&E denies that the timing of the Line 6900 Expansion had anything to do with promoting Baja Norte. Instead, SDG&E argues that as soon as the utilities became aware that the increased EG demand was putting a strain on the system, the utilities¹² went forward with the Line 6900 Expansion.

GR contends that the evidence indicates that SDG&E is responsible for its own system resource planning and the Baja Norte pipeline did not interfere with expansion plans. In fact, GR maintains that SDG&E timed its open season to compete with Baja Norte's initial open season to gauge interest in long-term, firm-service commitments to plan for appropriate facility expansions. Even though no customers signed up for SDG&E's open season,¹³ GR contends that SDG&E entered into a long-term contract with SoCalGas to encourage SoCalGas to move forward expeditiously with the Line 6900 expansion.

Cabrillo agrees with SDG&E that the Baja Norte pipeline did not affect SDG&E's or SoCalGas' system expansion. Cabrillo contends that the Line 6900 Expansion was needed regardless of the status of the Baja Norte pipeline. However, Cabrillo argues that SDG&E should factor the existence of Baja Norte into account in its future system planning.

APCD questions the "curious chronology" of events in summer 2000 over the announcement of the Baja Norte pipeline and SDG&E's open season, and the fact that Sempra chose to pursue Baja Norte. APCD views this choice as an opportunity for Sempra to maximize its corporate profits by placing its capital investment money in the unregulated business instead of SDG&E.

CIG/CMTA is also interested in Sempra's involvement in the Baja Norte pipeline. CIG/CMTA wonders whether Sempra's involvement creates an incentive for Sempra to benefit from scarcity on the SoCalGas and SDG&E systems.

TURN too, is convinced that the Baja Norte pipeline has affected the utilities' expansion plans. TURN claims SDG&E's open season to compete with the Baja Norte open season was a sham. The SDG&E open season started when Baja Norte ended, required 15-year commitments, and only provided capacity up to 200 MMcfd (half of the projected Baja Norte capacity). In addition, TURN contends that supplying gas through the Baja Norte pipeline provides greater returns for Sempra shareholders at the expense of utility ratepayers. Simply put, TURN states that Baja Norte, which is subject to Federal Energy Regulatory Commission jurisdiction, can net Sempra a higher rate of return than Sempra can make from its Commission-regulated investments in SoCalGas' or SDG&E's service territories. Thus, TURN claims, utility ratepayers will lose revenues and throughput if users flock to Baja Norte and leave the SDG&E system. TURN argues that the only appropriate remedy for the Commission is to eliminate Sempra's conflict of interest between the Commission-regulated utilities and Sempra's unregulated affiliates.

C. Discussion

In the face of conflicting evidence it is difficult to determine with finality whether Sempra allowed its corporate affiliate interest to affect or influence SDG&E's service and system expansions, including the Baja Norte pipeline. What does appear clear, however, is that SDG&E was less than forthright when it applied for its tariff for GR. Specifically, SDG&E represented that the addition of service to GR would not adversely impact the gas customers in San Diego's service territory. Obviously, that was not true.

Even after days of cross-examination, it is also unclear whether Sempra, SDG&E, or SoCalGas violated the letter of any of the affiliate rules. Many of the parties questioned whether the commitment of firm service to GR, coupled with the construction of the Baja Norte pipeline, could ever have been viewed as being in the best interests of SDG&E's core and noncore customers. Sempra, SDG&E, and SoCalGas, on the other hand, insist that they all independently make system expansion plans that are in the best interest of both ratepayers and shareholders.

The only evidence produced at the hearing that belies this assertion is the testimony of Benjamin Montoya on May 22, 2001. Mr. Montoya, in his role as sponsor of Section 2 of the direct testimony of SDG&E and SoCalGas, discusses the presentation he made to SDG&E's F&PP meeting on June 22, 1999.¹⁴ Mr. Montoya testified that although F&PP is a SDG&E committee, Sempra corporate members sometimes do attend and Mr. Reed, senior vice president for regulatory affairs for Sempra Energy did attend this meeting.¹⁵ Thus, based on Mr. Montoya's presentation at that meeting, Sempra had to be aware of the decision by SDG&E to do nothing about expanding its system, despite the fact that there was lack of capacity on the system and curtailments were imminent. This may not show abuse of the affiliate rules, but does point to close integration between Sempra and SDG&E.

VII. Summary Phase I

It is clear we had a gas transmission crisis in SDG&E's service territory that not only threatened curtailments, but actually resulted in curtailed service to firm noncore customers on 17 days between November 2000 and March 2001. The Commission initiated this OII in response to this critical situation from concern over the ability of SDG&E to meet the gas needs of its customers. After all the testimony, exhibits, and briefs are in, the Commission still faces the question: Was it a classic case of conflict of interest when SDG&E, a Sempra owned utility, decided to provide service to GR, a Sempra affiliate, and despite its knowledge that this contract would further strain an already constrained gas transmission system, chose to make no system expansions within its service territory-at the exact same time as Sempra, through another affiliate, was building the Baja Norte pipeline expansion, OR is it only in hind-sight that we can see that the amalgam of unexpected circumstances from about June 2000 through March 2001- such as extreme weather conditions, dry-hydro circumstances, unprecedented electric demand, high electric costs, and constraints on the gas transportation system-converged to create a gas transmission crisis. Although there is insufficient evidence in the record to answer this question or to impose sanctions, we can proceed in this decision to implement new rules and procedures to prevent such a confluence of factors from threatening our gas and electricity supply.