VIII. Electric Generation
A. Single EG Rate for Both Utilities
Electric generators that require gas transportation over the systems of two utilities operate today under a regulatory structure that causes a mismatch between the pricing of gas and electricity. For gas transportation, the rates of each transporting utility are cumulated -- or "pancaked" -- so that the ultimate gas transportation rate the customer sees increases with the number of utilities involved in the transport. In this proceeding, SDG&E and SoCalGas propose to layer SDG&E's transportation rates on top of SoCalGas' wholesale rates to develop the transportation rates paid by EG customers in SDG&E's territory. The price the Power Exchange (PX) sets for purchases of electricity, by contrast, is uniform throughout the state (or within a zone if congestion occurs) -- a "postage stamp" rate that does not vary with distance or the number of utilities involved in the transmission from generator to customer.
The consequence of this pricing discrepancy is that some California generators pay much higher rates for gas transmission service than others, solely due to their location and the mismatch in regulatory pricing regimes, while all California generators receive the same price for sales made through the PX (in the absence of congestion). In the context of this case, generators in SDG&E's service area currently pay much higher gas transportation rates than those in the territory of SoCalGas, but they receive exactly the same price for their sales into the PX. This imposition of higher costs on San Diego-area generators means that less efficient generators in SoCalGas' territory will be more likely to make winning bids to the PX and be selected to dispatch and sell their electricity than will more efficient counterparts located across the border between these two companies. EGA says competition should be based on the efficiency of generating units and the shrewdness of their owners in the gas procurement and financial markets, not on the happenstance of which Sempra affiliate provides local gas service. It urges the Commission to overcome what it perceives as the anticompetitive distortions created by the current regulatory pricing arrangements by adopting a single EG gas transportation rate for SoCalGas and SDG&E.
The current pricing structure charges SDG&E electric generators an average of 11.5% more than electric generators located in SoCal's service area, thereby discouraging the operation of existing generators and the location of new generators in San Diego. Since all entities in California sell into the same PX and Independent System Operator (ISO) market, this 11.5% higher cost to SDG&E generators means that the SDG&E units are disadvantaged. EGA maintains that the discrepancies between the pricing of gas and electricity have harmful effects on consumers and on competition. The pricing mismatch favors inefficient generators in SoCalGas' territory over more efficient generators in SDG&E's territory. EGA contends that this mismatch gives new generators the wrong incentives for locating their generating facilities. New generators are encouraged by this pricing structure to locate outside of SDG&E's territory, even though more generation closer to the San Diego load center would be extremely valuable in terms of relieving transmission congestion and promoting system reliability. As more generators avoid SDG&E's territory, pressure builds to construct additional transmission lines into San Diego, which, EGA argues, creates its own problems.
Without a Sempra-wide EG rate, EGA believes the only option to building new transmission lines into SDG&E's territory is to increase reliance on reliability must-run (RMR) contracts between the ISO and individual generation units. These contracts allow the ISO to call on RMR units to operate on demand in order to relieve congestion and other problems on the transmission grid. But reliance on RMR contracts is expensive. They are cost-based contracts, and they tend to increase electricity prices over the prevailing prices in the PX. In EGA's opinion, reliance on RMR contracts inhibits the ability of the competitive market to develop.
EGA argues that the single rate proposal provides a simple and elegant solution to these problems. The single rate proposal promotes the proper incentives to attract generation to SDG&E's territory and to allow existing generators to take full advantage of their operating efficiencies when they compete in the market. Most important, the single rate proposal promotes competition and allows for development of creative and inexpensive market-based solutions to problems. TURN and UCAN support the single rate proposal. They assert that the single rate will produce benefits in the form of lower PX prices in some hours, less reliance on RMR units, and lower costs for RMR units when they are called on.
ORA, in opposition, responds that none of the arguments advanced by proponents of a single EG rate for both utilities justifies a departure from cost-based rates for gas transportation services. The fundamental problem with the single rate proposal, in ORA's opinion, is that it would reverse over a decade of progress in the effort to develop cost-based transportation rates for each of the state's gas utilities. Should SDG&E's EGs receive a lower rate, some other class of customers will have to pay more. Under the various proposals, this would either be the EGs in SoCalGas' territory or some other customer class. The proponents of the single rate have failed to justify the cross-subsidy inherent in the proposal.
ORA says that merely because EGs in SDG&E's territory pay a higher gas transportation than EGs in SoCalGas' territory is not justification for a subsidy. The new owners of SDG&E's gas fired power plants were aware of the transportation pricing differences at the time they elected to bid on the plants and were apparently of the view this was no obstacle to the profitable operation of the facilities. ORA maintains that the Commission should not try to improve their competitive position in the marketplace through an after-the fact change in the rules.
ORA disputes that a single rate would benefit ratepayers by lowering PX prices. It points out that the studies that show a strong correlation between gas prices and PX energy prices were completed before the start of the deregulated electric market; current data fail to support the correlation. The argument that a continuation of the pancaked rate structure will discourage the construction of new generation facilities in SDG&E's territory and increased reliance on expensive RMR contracts or the construction of expensive electric transmission facilities is similarly unpersuasive, in ORA's view. ORA refers to the presence of USGen as a viable option for new generation in SDG&E's territory as evidence refuting the contention that pancaked rates are discouraging new generation. This project was conceived well before there were proposals for a single EG rate across the two utilities.
We find that the public interest requires a single EG rate for both utilities. The argument and analysis presented by EGA, TURN, and UCAN are persuasive; ORA's objections have been overtaken by time.
ORA's argument that a single EG rate is a departure from cost-based rates is misleading. The costs ORA refers to are not expenses of the utility which can be confirmed by audit, but estimates of long run marginal costs increased by a "scaler" to reach the revenue requirement of the utility. The evidence presented in this case showed disputes over all estimates of marginal costs, disputes over the categorization of costs, disputes over the allocation of costs, and, most certainly, disputes over the scaler. Not only are ORA's "cost-based" rates more accurately "estimated cost-based rates plus scaler," but also each party who estimated costs managed to find that its costs were too high and others' too low. We must decide based on the evidence of record, but we have no illusions regarding the firmness of the costs we deal with. Nevertheless, with a Sempra-wide EG rate, the Sempra-wide costs (as accurately as we can predict) will be recovered.
ORA's second objection goes to the heart of the matter. A Sempra-wide EG rate will cause SoCalGas' EG customers to pay more and SDG&E's EG customers to pay less.5 This is the type of cross-subsidy that long run marginal cost ratemaking was supposed to eliminate. And more to the point, one utility is not supposed to subsidize another utility. It is here where time and events have overtaken prior regulatory practices.
Changes in the energy industry are compelling this Commission to rethink its approach to regulation. Recent developments in the natural gas and electric industries have been dramatic: the restructuring of the electric utility industry, the rapid growth of competition in electric generation, competitive gas pipelines in California, the divestiture of electric utilities' generation plants, federal initiatives to promote competition in electric generation and gas transportation, the creation of the Power Exchange and Independent System Operator, and most important, the much-anticipated convergence between the natural gas and electricity industries. The growth of an increasingly competitive energy industry has exacerbated the tension between market-based pricing prevalent in competitive markets and cost-based pricing characteristic of traditional rate regulation. The single rate proposal is a feasible and realistic response to one of the tensions created by changes in and convergence of the energy industries -- the mismatch between the pricing of gas transportation service and the pricing of sales and transmission of electricity in the competitive market.
Generators in SoCalGas' territory will not suffer a rate increase because of this shift. Appendix D, Table 8 shows that SoCalGas EG rates in effect as of January 1, 2000, are reduced by $20 million annually after the Sempra-wide rate becomes effective.
We are concerned that higher rates for EG service in SDG&E's territory than in SoCalGas' territory (estimated at over 11%) create a disincentive to build new generation in SDG&E's territory. Without new generation, future electric load growth will be served by additional electric transmission and RMR units, at increased costs. That increase will be paid by SDG&E's electric customers, primarily residential. A Sempra-wide gas rate reduces gas costs for SDG&E's customers and also reduces electric costs for SDG&E's customers. Further, the Sempra-wide rate increases competition between generators at the PX which is expected to reduce electric rates for all Californians. As a by-product of increased generation in SDG&E's territory some experts predict an improvement in air emissions as more efficient combined-cycle generators reduce the need for current, less efficient, generators.
We recognize that our decision on this issue is a departure from conventional regulatory theory. But we cannot ignore the vast changes energy restructuring has engendered, nor can we ignore the merger of SoCalGas and SDG&E and its implication of joint activity. We deliberately do not single out any one indicator, or group of indicia, upon which we base our result. Rather, we find that the public interest, as exemplified by all of the factors discussed, requires a single Sempra-wide EG rate.
B. EG Rate Segmentation
SoCalGas supports implementation of a segmentation process that would require a one-step analysis and be easy for its customers to comprehend. It proposes segmenting the EG rate based only on the throughput level of each EG customer. One rate would apply to EG customers whose annual throughput is less than three million therms. This rate would include both a volumetric transmission charge and a nominal customer charge. A second rate would apply to all EG customers whose annual throughput is greater than three million therms. This would be an all-volumetric rate applicable to 100% of the customer's throughput.
ORA supports the SoCalGas proposal. SCGC supports segmentation but proposes that it occur on the basis of level of service: distribution versus transmission.
SCGC recommends that the EG class be segmented to reflect the higher costs that distribution-level EG customers place on the system compared to transmission-level customers and that EG customers served through the high pressure distribution (HPD) system that consume more than three million therms per year be billed at the transmission level rate. SCGC argues that throughput is not a significant factor in the cost of service compared to the level of service, and there is very little difference in serving a three million therm load than a six million therm load. There is, however, a significant difference in the cost of delivering those therms through SoCalGas' transmission system, rather than through its more expensive distribution system. SCGC believes throughput is a fundamentally arbitrary basis for segmenting rates. If EG rates are segmented at three million therms without a cost basis, the precedent will be established for further segmentation based solely on throughput.
The major parties support segmenting the EG rate. SCGC qualifies its argument by agreeing that distribution level customers consuming over 3 million therms per year should be billed at the transmission level rate. Implementation of the SCGC proposal would require a two-step analysis: (1) does that customer use distribution or transmission level service? and (2) if the customer uses distribution service, does the customer consume over 3 million therms per year? SoCalGas supports implementation of a segmentation process that would require a one-step analysis and be easy for its customers to comprehend. SoCalGas proposes segmenting the EG rate based only on the throughput level of each EG customer. We agree with SoCalGas. Segmenting the EG rate based upon customers throughput maintains a ratemaking format easily understood by customers while also adhering to the cost-based ratemaking principles of the Commission. The adopted segmentation is equally applicable to SDG&E's EG class.6
A segmented transportation rate clearly complies with the cogeneration parity requirements of Pub. Util. Code § 454.4:
The Commission shall establish rates for gas which is utilized in cogeneration technology projects not higher than the rates established for gas utilized as a fuel by an electric plant in the generation of electricity, except that this rate shall apply only to that quantity of gas which an electrical corporation serving the area where a cogeneration technology project is located, or an equivalent area, would require in the generation of an equivalent amount of electricity based on the corporation's average annual incremental heat rate and reasonable transmission losses or that quantity of gas actually consumed by the cogeneration technology project in the sequential production of electricity and steam, heat, or useful work, whichever is the lower quantity.
Interpretation of this requirement has been controversial, and the controversy has only increased with the divestiture of SCE's and SDG&E's fossil-fired generating plants. The quantity of gas that the utility would consume to generate electricity -- the basis for the cogeneration parity that this statute is intended to guarantee -- loses all meaning when the utility no longer uses gas to generate electricity.
Section 454.4 may be outdated, and it may not be applicable, but it would not be improper to comply with its spirit. SDG&E initially proposed a rate design which it acknowledged did not meet the statute's requirements. Several parties presented proposals that split the EG class into segments. The answer to the question whether the segmented rate designs proposed in this proceeding comply with § 454.4's requirements appears to turn on fine points such as the number of segments and whether the segments are defined by usage or service level. Amidst all this, one clear point emerges: The adopted segmented rate proposal complies with § 454.4. Because it treats all electric generators alike, regardless of their size, location, or present or former ownership, the adopted segmented rate proposal grants parity to cogenerators, former utility electric generation plants, independent merchant plants, and any other gas-fired generator.
C. Anti-gaming Mechanism
SoCalGas supports elimination of the Cogenerator Gas Allowance (CGA) in conjunction with the adoption of anti-gaming measures aimed at insuring that the EG rate is limited to gas volumes that are used to generate electricity. The measures, which would be included as tariff conditions, would require separate metering where practical, for direct-fired electric generating facilities. Where metering is not practical, there would be a monthly volume limitation equal to the recorded power production in kWh multiplied by the average heat rate for the electric generation facilities. CCC/Watson supports the SoCalGas recommendations while SCGC opposes elimination of the CGA on the ground that it is required by Pub. Util. Code § 454.4.
ORA is uncertain whether the proposed tariff conditions are sufficient to prevent all gaming. ORA recommends a tariff condition requiring a meter on all electric generation facilities unless it can be demonstrated that it is not economically feasible or is otherwise impossible. This objective standard will help eliminate some of the uncertainty regarding SoCalGas' willingness to enforce a metering requirement.
In Resolution G-3242, provisionally approving an EG class advice letter, we found that the CGA can be eliminated without violating § 454.4 provided that it is accompanied by sufficient anti-gaming provisions aimed at limiting EG service to the amount of gas actually used in electric generation. Regardless of the anti-gaming provisions we adopt, we do not expect them to be totally successful. We expect some will try to beat the system. To minimize that happening, we adopt ORA's recommendation requiring a separate meter on all facilities used solely for the generation of electricity unless it can be demonstrated that it is not feasible. We would expect very few, if any, exceptions to this requirement.
D. Public Purpose Programs
CCC/Watson recommend that natural gas vehicle (NGV) program costs should not be paid by EG customers. They argue that since EG customers pay for the costs of low emission electric vehicles (EV) on the electric side, they should not have to also pay for NGV costs on the gas side.
ORA disagrees with the proposal and recommends that all customers continue to pay for NGV costs on an equal-cents-per-therm basis. The Commission, in considering low emission vehicle programs, has generally ruled that all customers in California benefit from having these programs. Because of this and the fact that no customer would volunteer to pay for these costs (similar to the Commission's policy on the allocation of transition costs), the Commission has ruled that all customers should pay NGV costs on an equal-cents-per-therm basis.
In D.95-11-035, the Low Emission Vehicle Investigation/Rulemaking (I.91-01-029, R.91-10-028), we continued our policy of allocating NGV costs on an equal-cents-per-therm basis: "Currently, the three natural gas utilities spread the cost of their natural gas vehicle programs on an equal-cents-per-therm basis over all volumes sold to all customer classes." (Re San Diego Gas & Electric Co., D.95-11-035, 62 CPUC2d 351, 449.) "We agree that the burden of these special programs should most accurately track the path of potential benefits and will require all three companies to continue allocating program costs on an equal-cents-per-therm basis." There is no reason to change this policy. All customers should continue to pay their fair share of NGV costs.
E. The CPUC Fee
CCC/Watson argues that SoCalGas' current method of collecting the CPUC fee from municipal utilities violates § 454.4 and should be modified. SoCalGas says this statement is inaccurate. Pub. Util. Code § 432(b) states:
"The commission may establish different and distinct methods of assessing fees for each class of public utility, if the revenues collected are consistent with paragraph (2) of subdivision (a), except that the commission shall establish a uniform charge per kilowatt hour for sales in kilowatt hours for the class of electrical corporations and a uniform charge per therm for sales in therms for the class of gas corporations."
Pub. Util. Code § 435 states, in pertinent part:
"Sales in therms' means deliveries of gas in therms, without regard to ownership of the gas, subject to the jurisdiction of the commission, directly to customers and subscribers of each gas corporation, except interdepartmental sales or transfers and sales to other privately owned or publicly owned public utilities furnishing electricity, gas or heat." (Emphasis added.)
Hence, it appears clear that the legislature intended to exempt the delivery of gas to certain recipients, like municipal utilities, from the CPUC fee addressed in Pub. Util. Code § 421.
We agree with SoCalGas.
