The full Gas Accord document is 87 pages long; it is reproduced in Appendix B to this decision. As required by Rule 51.1(e) of the Commission’s Rules of Practice and Procedure, we can approve the settlement only if it is reasonable in light of the whole record, consistent with law, and in the public interest. We must make an independent determination on these issues rather than simply deferring to the number of parties supporting the settlement.
In a nutshell, the Gas Accord would: (1) unbundle gas transportation service into specific paths, with assignment of capacity to core customers, and partial roll-in of Line 401 costs into Line 400 rates; (2) offer various service options to existing Line 401 firm service customers; (3) include core procurement costs in rates based on two CPIM proposals; (4) settle contested issues regarding ITCS amortization, Line 401 capital costs, and recent gas reasonableness reviews, including PG&E’s federal district court challenge to one of our reasonableness reviews; and (5) set transmission , and storage rates for the Gas Accord period through December 31, 2002.
In the Gas Accord (p. 68), PG&E has specifically agreed that if the Gas Accord is approved without modifications or with modifications acceptable to PG&E and DRA, PG&E would "permanently forego recovering from its ratepayers any of the disallowance ordered by Decision 94-03-050, which has been (or will be) refunded to ratepayers, notwithstanding the outcome of its pending lawsuit in Federal District Court (Civil No. C-94-4381 WHO)." [ In ORA’s October 4, 1996 reply comments on the Gas Accord settlement (p. 17), ORA explained that this provision "would assure that ratepayers would retain the $90 million (plus interest) disallowance ordered by the Commission…" A substantial amount of this disallowance resulted in a refund from PG&E to its own UEG and the Gas Accord states that this amount would be credited to PG&E’s Energy Cost Adjustment Clause (ECAC) balancing account. In light of the passage of AB 1890, subsequent to the August 21, 1996 filing of the Gas Accord, the amounts in the ECAC balancing account would not inure to the benefit of the PG&E’s ratepayers, as DRA had intended, unless the UEG’s share of the disallowed amounts was refunded from a different account. However, we have already resolved this matter in D.96-12-025, D.96-12-026, and D.96-12-027 issued on December 9, 1996, where we held that disallowed amounts must be credited to an Electric Deferred Refund Account (EDRA), instead of PG&E’s ECAC, and then refunded to PG&E’s electric ratepayers. Our approval of the Gas Accord does not alter our rulings in D.96-12-025, D.96-12-026, and D.96-12-027, and, therefore, PG&E must adhere to our explicit ruling in D.96-12-026, which already required the UEG’s share of the $90 million (plus interest) disallowed amounts to be returned to electric ratepayers through the EDRA, and to our general requirement in D.96-12-025 that any and all settled disallowed amounts must be returned to ratepayers through the EDRA rather than be credited to PG&E’s ECAC.] On page 8 of PG&E’s April 23, 1997 comments on the ALJ’s proposed decision, PG&E also explicitly represented to the Commission that with the approval of the Gas Accord, PG&E would "forego appeals of other Commission decisions, such as the 1988-90 Gas Reasonableness Decision (Re Pacific Gas and Electric Co., D.94-03-050; 53 CPUC 2d 481 (1994)), presently on appeal to the Federal District Court (Civil No. 94-4381 SBA)." [ In PG&E’s June 18, 1997 comments on the Proposed Alternate Order, PG&E incorrectly asserts that the Proposed Alternate Order assumed that under the Gas Accord, PG&E would "forego" its federal district court challenge. However, the Proposed Alternate Order did not state this as an assumption; the Proposed Alternate Order referenced PG&E’s April 23, 1997 comments for PG&E’s explicit representation in this regard. ]
Presumably, DRA had made a concession to PG&E as a quid pro quo for PG&E’s commitment to forego its federal court case. Accordingly, our approval of the Gas Accord is based upon PG&E’s following through on all of its commitments, including PG&E foregoing its federal district court challenge as represented in PG&E’s April 23, 1997 comments (at p. 8). We are therefore explicitly stating in our Ordering Paragraph that our approval of the Gas Accord is based, in part, upon PG&E’s commitments to permanently forego recovering from its ratepayers any of the disallowance order by D.94-03-050 which has been (or will be) refunded and to forego its appeal of the D.94-03-050 to the Federal District Court (Civil No. 94-4381).
Gas Accord service paths would begin at Malin, Topock, or California facilities. Delivery points, generally, would be labeled on-system (within the PG&E service territory) and off-system (outside the service territory). Core reservations would be approximately 600 MMcf/d on Line 400 and 150 to 600 MMcf/d on Line 300, the latter varying seasonally. There would be no crossover ban and no balancing account to guarantee PG&E revenues. Rates for noncore distribution service would be seasonally differentiated.
Current Line 401 firm shippers would face rates based on $736 million of Line 401 capital costs. Shippers could choose among three options: (1) Accord service, available if the shipper waives Universal Terms of Service (UTS) rights; (2) G-XF service, which is much like present service but with UTS rights limited to firm service; or (3) individually negotiated options, subject to Commission approval.
The first CPIM, applicable to the period from June 1, 1994, through December 31, 1997, incorporates a core procurement price formula agreed upon by PG&E and DRA in A.94-12-039, PG&E’s current CPIM application. From January 1, 1998, through December 31, 2002, the formula would be modified to include daily sequencing in place of monthly price weightings, a Topock price index in place of Southwest basin prices, limited recovery of Transwestern pipeline demand charges, and other terms.
Several general rate case and gas reasonableness issues would be settled. Line 401 initial capital costs of $736 million would be included in Line 400/401 rolled-in rates and Line 401 incremental rates. PG&E would absorb 50% of outstanding noncore ITCS costs, 100% of core ITCS costs, the backbone credit account balance, and $3.7 million of contested 1988-1990 costs. PG&E would not be responsible for any "statewide ITCS" costs, which are essentially Southern California stranded costs caused by Line 401. Commission proceedings regarding PG&E’s decision to construct and related Rule 1 allegations would be terminated.
Most core and noncore transportation rates would be reduced from current values, but would be subject to 2.5% annual escalation from 1998 through 2002. Utility intentions about ratemaking treatment of the side deal payment from Edison to PG&E are not in the record.
The Gas Accord has several attractive features. First, the settlement has the support of a broad spectrum of active parties. ORA is a government entity that represents the interests of all customers, and CIG, CMA, and CLFP represent noncore customers specifically. With the support of Edison and SDG&E, which came after the settlement was reached, a majority of current firm shippers on Line 401 have joined the Gas Accord. Other endorsements are the result of bilateral agreements, or side deals, between PG&E and individual parties. The side deals generally settle issues of reduced interest to other parties. For example, the sale of pipeline equity shares to SMUD is very important to SMUD itself, but is not of compelling interest to other parties.
Second, the Gas Accord would unbundle PG&E’s gas transmission system into separate services. This would improve flexibility and customer choice among noncore service options, and would allow a closer match of transportation rates with facilities used to provide service. With unbundling comes a logical reliance on embedded costs in calculating rates. Direct comparison between marginal cost and embedded cost methods has not been the focus of this proceeding, but in general the matching of rates and facilities is enhanced by embedded cost ratemaking. Marginal costs (after adjustment for embedded cost revenue requirement) can be used to allocate utility costs fairly among customer classes, but resulting rates can be very sensitive to initial marginal cost decision choices. As service is unbundled into manageable components, cost allocation problems and the need for marginal cost allocation procedures are diminished. PG&E responsibility for the transmission revenue requirement is also a desirable element of the proposed unbundling scheme, with attendant elimination of balancing accounts. It would assist in protecting original system ratepayers from costs or risks associated with Line 401, as PG&E promised in the certification proceeding.
Third, the Gas Accord would resolve difficult issues in various Commission proceedings. There is no common yardstick for comparing administrative benefits against the risk that issues might be settled unfairly or inefficiently. That is why support from parties with diverse interests is important. Nonetheless, settlement of contested issues in arduous proceedings has value for the Commission and the parties. In the Line 401 general rate case, the Gas Accord would settle issues regarding capital costs, operations and maintenance expenses, receipt point capacity allocation, the crossover ban, ITCS amortization and past conflicts of interest, backbone credit balancing account amortization, core capacity reservation, and the decision to construct. In other proceedings, the Gas Accord would settle CPIM issues, gas reasonableness review disputes, and details of PG&E’s core aggregation program. Along with resolution of contested issues comes the benefit of rate certainty during the Gas Accord period.
Fourth, PG&E’s divestiture of gas gathering facilities would be a step toward a more rational market structure. It would put gas gathering assets in the hands of parties most affected by their management.
Other beneficial features of the Gas Accord include core aggregator flexibility, phasing out of PG&E’s core subscription program, and assignment of Expedited Application Docket (EAD) contract shortfalls to PG&E. Core aggregator unbundling and the equity sale to SMUD, now underway in separate applications, are benefits of the Gas Accord process but are not incremental benefits of the outcome. They will go forward independent of Commission approval or rejection of the Gas Accord.
In our estimation, the most troublesome feature of the Gas Accord is its failure to resolve or mitigate PG&E’s basic conflict between customer and shareholder interests. PG&E’s position is that the Gas Accord resolves alleged conflict of interests. We disagree. The Canadian price advantage over Southwest supplies creates the opportunity to gain economic value on northern path pipelines. PG&E’s present conflict of interest, accompanied by utility market power within California, results in a transfer of economic value from Southwest producers to Canadian producers, PG&E, and holders of pipeline capacity north of California. El Paso argues that PG&E’s minimum bids for brokered capacity have raised Topock prices, thereby transferring value from end users to northern interests. We cannot be certain this is true, as PG&E claims that minimum bids do not affect final capacity brokering prices. At a minimum, ratepayers are harmed by loss of capacity brokering credits. PG&E argues that El Paso receives its full demand charges whether PG&E’s contract capacity is used or not, and ratepayers as a whole are not harmed. PG&E is looking at the wrong group of ratepayers. It is true that total revenues paid to El Paso by ratepayers are unaffected by capacity brokering, if one assumes that incremental shippers on Line 401 that cause the loss of capacity brokering credits are also PG&E customers. However, the set of all ratepayers except the incremental shippers suffers a net loss of the forgone capacity brokering credits. That value is transferred to PG&E shareholders and northern interests.
Under the Gas Accord, loss of current capacity brokering credits would not be a major problem because PG&E’s contracts with El Paso will expire at the end of 1997. However, if PG&E controls future pipeline prices or revenues for supplies from Canada and the Southwest, PG&E would retain its conflict of interest. The transfer of benefits from noncore end users to PG&E and northern interests might even be exacerbated. As long as the Canadian supply price advantage endures, which seems reasonable for the Gas Accord period, end user benefits will be linked to the delivered price of Southwest gas. Currently the market value of unused pipeline capacity from the Southwest is very small, equal to variable costs plus a contribution to fixed costs sufficient to encourage El Paso and PG&E to sell idle capacity. Under the Gas Accord, the average Topock to on-system rate would be approximately $0.165/Dth. [ Appendix B, Accord Rates, Table 2, p. 71. Topock to On - System rates would be $0.145/Dth in 1997, $0.155/Dth in 1998, $0.164/Dth in 1999, $0.169/Dth in 2000, $0.172/Dth in 2001, and $0.175/Dth in 2002. These rates include costs for Line 300 and other backbone and local transmission facilities. Malin to On-System rates for Line 400/401 are $0.238/Dth in 1997, $0.253/Dth in 1998, $0.265/Dth in 1999, $0.267/Dth in 2000, $0.269/Dth in 2001, and $0.269/Dth in 2002.] The Line 300 rate is roughly $0.15/Dth higher than market value, resulting in a transfer of economic value from end users to northern interests, even if the present balance between Canadian and Southwest gas sales to the noncore is maintained. We do not know which entities would receive those benefits, but value tends to migrate toward holders of constrained capacity. Annual harm to end users could be in the tens of millions of dollars. There would also be a small efficiency loss, relative to market prices for Line 300.
Under the Gas Accord, PG&E would retain its preference for Canadian noncore supplies, because PG&E has higher rates and would receive greater revenues from increases in throughput on its Line 400/401 in lieu of throughput on its Line 300, and PG&E’s affiliate, PGT, would also receive greater revenues from increases in throughput on PGT in lieu of throughput on Southwestern interstate pipelines. PG&E could exert its market power to maximize California customer revenues by discounting service beginning at Malin (over rolled-in Line 400/401, if capacity is available) instead of service beginning at Topock (over Line 300). This unfair competition could cause higher burnertip gas prices in California and would harm Southwest producers and pipelines, to the eventual detriment of California end users through loss of supply diversity. Indeed, PG&E’s incentive to discount only its Canadian path rates (i.e. from Malin) and not its Southwestern path rates (i.e. from Topock) could also result in unduly discriminatory discounting practices and in unfair competition between Canadian suppliers and Southwest suppliers. We cannot evaluate the benefits of supply diversity in dollar terms, but we should promote diversity by promoting fair competition among supply sources.
We cannot anticipate all future PG&E and market responses to PG&E’s future conflict of interest, in the same way we did not predict backbone credit exchange agreements and other market reactions to earlier Commission decisions. However, we are convinced that under the Gas Accord PG&E would have an incentive to use market power in ways that could harm California end users and Southwest interests. Acting to keep Line 300 rates high is only one example. The conflict of interest could also extend to PG&E’s use of its contracted Transwestern pipeline capacity.
Second, rolled-in rate treatment for Line 401 and the proposed path-specific unbundling scheme would be inefficient and contrary to incremental ratemaking principles. Loss of economic inefficiency is built into the averaging process because shippers would not face the costs of individual pipeline assets. In A.89-04-033, PG&E promised to insulate original system ratepayers from any risks and costs of Line 401. [ Exhibits 532 and 533.] The Commission confirmed that none of the costs of Line 401 would be allocated to original system ratepayers. [ D.90 - 12 - 119, Finding of Fact 41, 39 CPUC2d 69, 152 (1990).] When PG&E determined the scale and timing of the expansion project, it took advantage of the Commission’s "let the market decide" policy for new pipeline capacity, in exchange for assuming responsibility for associated costs and risks. We are obligated to defend those customer protections vigorously. Only a showing of substantial customer benefits can overcome the allocation of Line 401 costs to customers that do not need or desire Line 401 capacity. Path-specific unbundling would further obscure the incremental nature of Line 401.
Third, as TURN argues, allowing rolled-in ratemaking could undermine future market tests for new capacity in the gas pipeline industry and perhaps in other industries. To weaken "let the market decide" policies after construction of utility expansions could harm the Commission’s credibility. If PG&E is now allowed to roll the cost of unnecessary assets into original system rates, then future market players might be tempted to deter competition by overbuilding new capacity, hoping the Commission will later shift the risks of undersubscription or underutilization back to captive customers. Utilities and their competitors would question the Commission’s resolve in enforcing the assignment of risks and costs to the sponsors of new capacity.
Fourth, the Gas Accord holds few direct economic benefits for core customers. The Gas Accord offers immediate short-term rate reductions, but they are offset by 2.5% annual escalation through 2002. The settled escalation factor may be a reasonable estimate of general inflation, but it seems to exclude productivity opportunities, and it applies to entire transmission rates. Escalation is not restricted to cost elements that are generally subject to inflation. The embedded costs of existing pipelines are driven by sunk capital costs, not capital additions or operations and maintenance costs that might be affected by inflation.
See Appendix C to this decision for a simplified present value analysis of core and noncore benefits. The analysis shows that net core costs would be 1.2% lower under the Gas Accord, and net noncore costs would be 7.7% lower under the Gas Accord. In this instance we are principally concerned about effects on the core, because noncore parties have agreed to the Gas Accord, and noncore benefits are more substantial. The ORA represents all customers, but no party representing only core customers has endorsed the Gas Accord.
We should comment on PG&E’s characterization of direct economic benefits. PG&E offers to forgo $283 million of utility costs. [ The total consists of $74 million of Line 401 capital costs, $160 million of ITCS undercollections, $25 million of backbone credits, $20 million of EAD shortfalls over the Gas Accord period, and $3.7 million of reasonableness review payments.] These customer benefits are not all assignable to the Gas Accord, but are concessions relative to PG&E’s positions in the underlying proceedings. It is possible that full litigation of the issues would result in disallowances that are higher than $283 million. The total is, however, within the overall range of dispute.
Fifth, we are concerned that the Gas Accord does not fairly reflect the interests of core customers or Southwest producers and pipeline companies. PG&E has settled with: (1) noncore customers, (2) ORA as a representative of all customers, (3) most Line 401 firm shippers, and (4) individual parties with narrow interests. Noticeably absent are TURN, El Paso, and New Mexico. The fairness of representation in a settlement is a matter of judgment, but the exclusion of PG&E’s competitors is especially troubling. We disagree with the suggestion of CIG and CMA that we should not expect competitors to come together in settlements. In comments to the proposed decision, PG&E describes the Gas Accord as an all-party settlement, and characterizes Gas Accord signatories as "the market itself." The claims are overblown. Representatives of core customers, noncore customers, and Southwest interests oppose the Gas Accord.
Sixth, we are uncertain about the disposition of Edison’s $80 million termination payment to PG&E. Edison may seek to include in rates the cost of its payment, and PG&E may intend to retain the payment instead of using it to reduce the rolled-in revenue requirement for Line 400/401.
We will approve the Gas Accord. In our judgment, the persistence of PG&E’s conflicts of interest can be reasonably mitigated by future Commission proceedings concerning matters not specifically addressed by the Gas Accord and by our imposition of a discounting rule in this order. With continued Commission oversight concerning PG&E’s conflicts of interest and with certain policy clarifications and the discounting rule discussed in Chapter 6 below, we find that the Gas Accord is reasonable in light of the whole record, consistent with law, and in the public interest.
We are impressed with the breadth of support for the Gas Accord. PG&E, utilities and other transportation customers of Line 401, and representatives of both core and noncore customers have settled many difficult economic and regulatory issues. Asset-based unbundling of PG&E’s gas transportation service would be preferable to the settled path-based unbundling, but PG&E’s acceptance of responsibility for revenue requirements without balancing account treatment offsets that defect. Increased costs associated with partial roll-in of Line 400 and Line 401 costs will be borne by noncore customers that freely entered into the settlement. Direct benefits to the core are smaller than benefits to the noncore, but core customers will benefit from seasonal reservations of pipeline capacity and access to Line 400 service at vintaged rates. All customers will benefit from regulatory certainty during the Gas Accord period, and from resolution of ITCS and backbone credit issues, as discussed in Chapter 8 herein.
Pursuant to Rule 51.1(e) of the Commission’s Rules of Practice and Procedure, we specifically find that the Gas Accord is reasonable in light of the whole record, consistent with law, and in the public interest, because it represents a significant improvement over PG&E’s currently bundled rates and services, provides PG&E’s customers with greater flexibility and competitive alternatives, and resolves rate issues within the zone of reasonableness such that we can find PG&E’s rates to be just and reasonable. It is not clear that PG&E’s rates would be as favorable for its ratepayers through continued litigation as the rates provided in the Gas Accord, and, as discussed elsewhere in this decision, the resolution of the rate issues in the Gas Accord represents a fair accommodation of the various arguments in the litigation in the proceedings.
The problems we have identified with the Gas Accord primarily focus on how the Gas Accord does not go far enough in mitigating PG&E’s conflicts of interest and the resulting unfair competition concerning PG&E’s marketing of Line 400/401 and use of Line 300 and in mitigating potential conflicts of interest in PG&E’s procurement of gas for its core customers. We are also concerned that the Gas Accord has not provided enough unbundling and that parties may attempt to improperly cite our approval of the Gas Accord as a precedent in favor of rolled-in rates (when our policies continue to be in favor of incremental rates) or that parties will claim that the Gas Accord resolved numerous issues which were never specifically addressed by the Gas Accord. Rather than reject the Gas Accord in light of these concerns, we believe that the much better course is to approve the Gas Accord in light of its improvement over PG&E’s present rates, to narrowly interpret the Gas Accord and our order approving the Gas Accord so that it will not limit our ability to further address PG&E’s conflicts of interest and unbundling issues, to clarify our policies and various ambiguities in the Gas Accord so that parties will not misinterpret this decision and to impose a discounting rule in this order to address PG&E’s marketing conflicts of interest. Nothing in the Gas Accord gave PG&E complete discretion in its discounting of its services, and we will therefore impose a discounting rule which we believe will mitigate PG&E’s conflict of interest (between its marketing of Line 400/401 services and use of Line 300) and provide for fairer competition between shippers accessing Canadian, California, or Southwest suppliers.
We will continue to scrutinize PG&E’s procurement of gas for its core customers and will not hesitate to impose penalties or disallowances if PG&E’s CPIM proves to be inadequate in protecting PG&E’s ratepayers from PG&E’s conflicts of interest. We would note in this regard, that our approval of the Gas Accord in no way prejudices our consideration or approval of rules addressing affiliate abuse issues, or our consideration or determinations concerning PG&E’s procurement practices based upon our review of the reports PG&E is required to file under the Gas Accord. We also intend to go forward with our Natural Gas Strategic Plan to consider and implement unbundling polices beyond the unbundling in the Gas Accord, as well as to consider other means to produce a more competitive gas market for all classes of utility customers.
In our discussion below, we also make it crystal clear that our approval of the Gas Accord cannot be cited as a precedent in favor of rolled-in rates, and we further clarify ambiguities concerning other issues in the Gas Accord.
Accordingly, we find that the Gas Accord is in the public interest subject to the discounting rule in this order and the Commission’s continued oversight in subsequent Commission proceedings of PG&E’s rates, services, and practices.
Footnotes are bracketed and in blue