3. Reasonableness of the Proposed Projects

As set forth in the Scoping Memo, a threshold issue is whether the SCE and PG&E Fuel Cell Projects are reasonable from a ratepayer perspective, and whether the Commission should approve the projects, including the proposed ratemaking, as proposed or with modifications. A secondary issue, as indicated by the scoping memo, pertains to what additional ratepayer benefits, if any, result from utility ownership of fuel cells compared to private investment in fuel cells through the SGIP and feed-in tariffs for CHP plants.

3.1. Parties' Positions

PG&E and SCE claim their projects will advance acceptance of fuel cell technologies in California, provide clean, reliable, low emission electricity to the grid, and provide fuel cell by-products to the host campuses, namely waste heat to serve campus thermal load and discharged water for landscape irrigation. According to both utilities, fuel cells generate electricity through an electrochemical process rather than through combustion, and therefore, the fuel cell power plants emit low amounts of pollutants such as nitrogen oxides and sulfur oxides, as well as fewer emissions of GHGs than conventional power plants.

SCE maintains the project is reasonable because it has the full endorsement of the Governor's Office and is consistent with the Governor's Green Building Action Plan, which directs the Commission to facilitate ratepayer supported efficiency programs for commercial and industrial buildings, and Assembly Bill (AB) 32, which calls for reductions in GHG emissions. Moreover, SCE states that the universities are not in a financial position to pay any premium over their otherwise applicable tariff to locate the fuel cell facilities on their premises. Thus, the universities have indicated they will only participate in the project if SCE owns and operates the fuel cells as utility assets, allowing the state to incur no additional costs. (Exh. 100 at 6.) PG&E provides a similar statement that the State has indicated its preference that PG&E own and operate the fuel cell facilities, and therefore it was infeasible for PG&E to conduct a competitive Request for Offer (RFO) for the project. (Exh. 2 at 1-6.)

Both utilities argue that their projects will advance fuel cell technologies by contributing to a better understanding of fuel cell operations and processes, and by sharing the benefits of fuel cell technology through community outreach and education. SCE alleges that fuel cell installations have lagged behind other forms of clean technologies due, in part, to lack of understanding by the general public of this advanced technology. PG&E plans to monitor fuel cell performance in comparison to performance of conventional power plants and to evaluate the use of fuel cell by-products by the universities. Through the community outreach that PG&E will coordinate at the universities, PG&E believes the project will enhance the university sustainable instructional programs in business, engineering, and environmental studies. Likewise, SCE asserts that a key benefit of the project is that the universities will be able to incorporate the fuel cell applications into their educational curriculum, "offering visual demonstrations of the technology to students and the public, and making available, as permitted, the operating and performance characteristics of the fuel cell systems for public knowledge." (Exhibit 102, SCE Rebuttal Testimony at 5.)

In addition, PG&E and SCE claim their projects do not conflict with other Commission programs supporting fuel cells and will advance fuel cells in addition to efforts in SGIP and the feed-in tariff program. PG&E notes that although the SGIP provides financial incentives to fuel cells, fuel cells have not significantly penetrated the market. SCE claims that while over 1300 projects have been installed under SGIP since its inception in 2001, only 20 projects and 12 MW of capacity are fuel cell based. (SCE Brief, 12/30/09 at 17.) PG&E maintains that only 11 fuel cells projects, comprising 6.1 MW have been installed in its service area under SGIP since 2001. (PG&E Brief, 12/30/09 at 7.) Moreover, PG&E claims even though the Commission has implemented a CHP Feed-in Tariff in R.08-06-024, in accordance with AB 1613,4 it is unclear whether this feed-in tariff will accelerate the installation of fuel cells since the price paid under the tariff appears to be lower than the expected levelized cost of energy from PG&E's proposed fuel cell projects.

DRA and TURN oppose the PG&E and SCE Fuel Cell Projects, arguing that the capital costs of both projects are unreasonable, the projects have questionable educational benefits, and the Commission should instead focus on other renewable generation and DG programs.

Regarding project costs, TURN contends SCE's forecasted capital costs of $7.20 per watt (5/29/09 at 3) and PG&E's forecasted capital costs of $7.35 per watt (3/27/09 at 2) are unreasonable for a project that cannot be classified as renewable generation. According to TURN, the funds proposed to support the Fuel Cell Projects could be used more effectively to advance renewable generation or used to promote private installation of fuel cells through SGIP. TURN argues that although the proposed fuel cells may be considered clean generation, they are, nevertheless, fossil fuel based because they use natural gas as the hydrogen source. Thus, scarce ratepayer funds should not be spent on expensive non-renewable generation sources that do not advance the state's Renewable Portfolio Standard (RPS) goals.

Similarly, DRA notes that fuel cells are an extremely expensive way to produce non-renewable electricity, at a levelized cost of over 30 cents/kWh, when the average cost of energy in the state is 7 cents/kWh. DRA notes this levelized costs is more than three times the current Market Price Referent (MPR) rate of 10 cent/kWh that the Commission uses as a reasonableness benchmark for renewable energy solicitations under its RPS program. DRA contends that costs of this magnitude should be examined in the context of alternatives to accomplish the same goals.

Both DRA and TURN question the educational value of the projects and whether they will result in advancement of fuel cell technologies. DRA claims that the educational value of the projects is speculative because applicants provide little evidence how the fuel cells will be used to further class work. DRA contends it would be more economical to transport students to visit an installed fuel cell at another site, which does not need to be on a college campus. TURN claims that the high cost of fuel cells is the primary barrier to their market penetration and that utility ownership of fuel cells, although it could provide educational value and raise public awareness, will do little to affect this cost barrier and achieve "market transformation" in the fuel cell industry.

In response to utility claims that the projects enhance state policy to promote fuel cell development, TURN maintains that although the Legislature has created ratepayer subsidy programs such as SGIP to promote private installations of fuel cells facilities, this does not translate into a state policy to provide 100 percent ratepayer support for utility-owned fuel cells. DRA claims the projects are unnecessary given that the SGIP encourages investment in fuel cells. In addition, DRA questions the need for the Fuel Cell Projects given the Commission's implementation of the AB 1613 CHP Feed-in Tariff in R.08-06-024.

3.2. Discussion

The question of reasonableness of the proposed Fuel Cell projects comes down to a comparison of the cost for these two projects with the benefits that might be achieved from the projects. The parties do not dispute the levelized costs of the projects, but PG&E and SCE claim the costs are warranted based on alleged educational and market transformational benefits, while DRA and TURN assert the costs are unreasonable given the speculative nature of those benefits.

DRA and TURN are both correct that the fuel cell projects are expensive on a levelized cost per kWh basis. They are also correct that the Commission established the SGIP to support the advancement of fuel cell and other technologies by providing up-front ratepayer incentives to leverage private capital and promote investment. Furthermore, we agree that projects pursued under SGIP use less ratepayer funds per MW than projects paid for entirely by ratepayers, such as the Fuel Cell Projects proposed here.

Nevertheless, we find that DRA's and TURN's arguments regarding the high cost of fuel cells relative to conventional and some renewable technologies, while factually accurate, are not a sufficient reason to reject the proposed projects. These projects can help advance industry learning and maturation of fuel cell technologies. The comparison to conventional resources is particularly irrelevant as it implies that the motivation for these projects is energy procurement, when, in fact, the point is to help advance the market and technology of a preferred resource. The fact that these technologies are more expensive than conventional and other resources is precisely why additional support is required. Similarly, the mere fact that there are other renewable resources that are lower cost does not mean that we should not seek to support fuel cells to the extent we believe such investments can advance a technology that the State has deemed as having an important role to play in California's future energy mix, as evidenced by the Governor's support for these projects, the eligibility of fuel cells for incentives under SGIP, and the state's loading order.

Nor does the current availability of incentives through SGIP obviate the need for these Fuel Cell Projects, which can serve as a complementary effort to advance this technology given the relatively low participation rates we have seen for fuel cells in SGIP. The data provided by both PG&E and SCE regarding participation in SGIP, specifically regarding the limited number of fuel cell projects and the amount of installed fuel cell capacity, strongly suggests that the proposed projects can provide a much needed boost to this technology and help support the goals of SGIP. If a substantial number of projects were being developed under the current incentive regime there would be little reason to support the applicants' proposal. At this time, however, that does not appear to be the case.

In comments on the proposed decision, TURN argues that that the existence of SGIP and the eligibility of fuel cells not only makes the approval of the proposed projects duplicative, but illegal.5 This argument is without merit. The fact that the legislature has established one mechanism for supporting a given technology or preferred resource, does not, in and of itself, limit the authority of the Commission to establish complementary efforts to support the same technology. TURN also argues that as a research and development (R&D) program, approval of these projects must meet the criteria identified in Pub. Util. Code Section 740.1.6 We disagree with TURN's premise that this is an R&D program. The current SGIP guidelines require technologies to be "commercially available." Furthermore, the technologies proposed by SCE and PG&E in their applications are eligible under SGIP, as noted by TURN. It follows that they are commercially available technologies, which directly contradicts TURN's assertion that the proposed deployments constitute R&D and are therefore subject to Section 740.1.

Furthermore, we discussed in D.09-12-047 that SGIP currently has spent significantly less than its authorized annual budget and has a significant carryover budget, estimated at $310 million. (D.09-12-047 at 8.) The persistent and high levels of unspent monies in SGIP mean these monies are not being deployed to support the advancement of SGIP eligible technologies and thus, are not advancing the specific goals of the program. To this end, ratepayers are not receiving the various market transformation benefits intended through the creation of SGIP in terms of the development of a viable market for clean, distributed generation technologies. As the extensive unspent carryover amounts imply, the incentive levels in SGIP have not been sufficient to drive significant uptake of SGIP eligible technologies. The reasons for this are unclear and could be due to the relative expense of eligible technologies, the global economic downturn, or possibly the California budget crisis. Regardless of the reasons why SGIP funds are not fully deployed, we believe the proposal before us can serve to supplement SGIP and further prime the market for adoption of fuel cell technologies.

In comments on the proposed decision, a number of parties argue that the market transformation benefits of the proposed projects are speculative and/or unsupported and because of this, the applications should be denied.7 We reject these arguments. SGIP was established to support the deployment of clean and ultra-efficient generation. In doing so the program seeks to help these emerging technologies achieve scale and gain practical market experience as a way to drive costs down over the longer term. The proposed projects here would provide additional support for SGIP eligible technologies by increasing the amount of deployed capacity. With the Fuel Cell Projects as a complementary effort to SGIP, we do not feel there is a need to revisit the fundamental market-development premise on which SGIP is founded. When constructed, the proposed Fuel Cell Projects will represent up to 6 MW of additional fuel cell capacity, compared to an existing fuel cell capacity of 12 MW in California.8 The Fuel Cell Projects will increase this capacity by as much as 50 percent. It is reasonable to conclude that this substantial increase in deployed capacity will facilitate market transformation for fuel cell technologies consistent with the goals of SGIP.

Accordingly, we approve the Fuel Cell Projects proposed by PG&E and SCE in their separate applications, subject to modification of the capital cost contingency rate in both applications and removal of PG&E's education and outreach specialist, which we discuss in further detail below. Additionally, we will require that each fuel cell deployed pursuant to this program be equipped with metering and monitoring equipment sufficient to provide the following information:

In addition to installing metering and monitoring equipment for these purposes, we shall also require that PG&E and SCE each submit annual compliance reports to Energy Division providing summary performance information for each of the installed projects. These compliance reports should provide information for each of the fuel cells deployed including each project's annual capacity factor, system availability during system peak hours, annual fuel consumption, annual electrical and thermal output, overall electrical efficiency for the year, and overall system efficiency for the year, as well as any other information that PG&E and SCE believe would be useful in helping the Commission assess the performance of these systems. The costs of metering, monitoring and reporting shall be deemed part of the projects' costs and will not be recovered separately.

Regarding capital cost contingencies, we agree with TURN and DRA that the amounts requested by PG&E and SCE, which are more than double those recommended by TURN and DRA, are unreasonable. As TURN notes, the contingency rates proposed by PG&E and SCE are significantly higher than other contingency rates, generally in the 5 to 8 percent range, previously approved by the Commission. (See D.06-11-048 at 21-22 and fn. 12.)

TURN suggests a contingency on the fuel cell equipment component of capital costs of five percent equivalent to the 5 percent contingency the Commission approved in D.06-11-048 for PG&E's Humboldt power plant and in D.03-12-059 for SCE's Mountainview Power Project. (Ibid.) For the installation component of capital costs, TURN proposes the Commission adopt PG&E's proposed contingency, which is lower than SCE's proposed rate. DRA suggests no contingency allowance for equipment costs, and at most a 10 percent contingency on remaining capital costs.

SCE responds that its contingency is necessary to cover scope modifications required during the final development and engineering phase of the project, and to accommodate site specific construction and design requirements. Further, SCE contends that its "Fuel Cell Program is in the conceptual design phase, which means that a larger contingency is required."(SCE Opening Brief at 14.) PG&E claims the contingency factor is within normal levels for construction projects where the final scope of the project is not yet defined, and it received a similar contingency for its Diablo Canyon steam generator replacement project, but provides no citation to any decision for verification of this claim. (Exhibit 4, PG&E Rebuttal Testimony at 3-2.) In D.06-11-048, the Commission discussed the various contingency rates adopted in D.05-02-052 for the Diablo Canyon steam generator replacement and why the different factors for discrete portions of that nuclear project where not applicable to the Humboldt project. (D.06-11-048 at 22, fn. 12.) Based on that same reasoning, we will not base our contingency for this fuel cell project on the Diablo Canyon steam generator replacement case.

We agree with TURN that approval of large contingencies for capital costs sends an improper incentive to the utilities and vendors that they can enhance the project scope within the limits of the contingencies. A large contingency also suggests that the applicant should further define the project scope before seeking approval. We will reduce the contingency rates on capital costs for the PG&E and SCE Fuel Cell Projects in line with the 5 to 10 percent contingencies proposed by TURN and DRA and supported by prior Commission decision. We will not reveal the actual percent of the contingency that we incorporate because the utilities requested confidential treatment of the contingency percent so that fuel cell bidders would not be able to calculate competitor's bid prices. We provide the final capital cost number adopted for each utility, which incorporates a substantial reduction in the proposed contingency rates. For PG&E, we adopt reduced total project capital costs of $20.3 million and for SCE, we adopt reduced total project capital costs of $19.1 million. Both of these reduced capital cost figures include a new, lower contingency factor.

In addition to a capital cost contingency factor, PG&E requests a contingency for non-fuel O&M expenses as well. SCE does not request a contingency for non-fuel O&M. DRA suggests reducing PG&E's proposed O&M contingency to 0 percent for fixed O&M costs, which are the majority of O&M costs, and 10 percent for the small portion of variable O&M costs. In considering PG&E's requested contingency, we note that PG&E's estimated O&M costs are considerably higher than SCE's estimated O&M costs, in large part due to higher costs for labor and vendor service agreements. This results in PG&E requesting $5.79 million for the first four years of non-fuel O&M costs, while SCE requests $8.9 million in non-fuel O&M for the life of the fuel cell. Given PG&E's already higher O&M costs, we will not approve a contingency for PG&E's non-fuel O&M. Plus, we note that if actual non-fuel O&M costs exceed the figure we adopt without a contingency, PG&E may apply for reasonableness review of the difference.

Second, TURN recommends the Commission disallow from PG&E's project costs approximately $80,000 per year in fixed O&M labor costs for an "education and outreach specialist." PG&E's testimony indicates it has included several hundred thousand dollars in education and outreach labor in its four year estimate of total fixed O&M costs for the Fuel Cell Project. (Exhibit 1-C at 4-10, Table 4-10.) PG&E justifies this cost by stating it will coordinate with the two universities in implementing a community outreach program to maximize the educational benefits of the fuel cell facilities both on campus and in the community as a whole. PG&E plans to install an educational kiosk at each campus, update signage and educational material, help develop class curriculum, host tours of the facilities, and facilitate other educational and community outreach actions. We agree with TURN that these types of community education and outreach are not properly funded by ratepayers and we direct PG&E to remove all education and outreach labor costs from its O&M costs for its Fuel Cell Project. The combined effect of removing education and outreach labor costs and the contingency factor from PG&E's non-fuel O&M costs is to reduce these non-fuel O&M costs to $4.71 million for the first four years of plant operation. For later years, PG&E must seek its non-fuel O&M costs in its general rate case.

Parties suggested other modifications which we decline to adopt. First, TURN recommends that if the Commission approves the Fuel Cell Projects, it eliminate the 200 kW "electric-only" fuel cell plants included in both the PG&E and SCE applications, thereby reducing capital installation costs for the two projects by over $6 million. According to TURN, the electric-only units cost about twice as much on a per unit basis as the other fuel cells, their GHG emissions are almost identical to combined cycle natural gas plants, and their educational value is not justified by their price. The utilities defend the electric only plants, maintaining that the demonstrative attributes of their projects are greatly enhanced by the installation of this distinct technology which operates at a much higher efficiency by recycling the heat exhaust from the fuel cell to generate electricity. We will not disallow the electric-only projects, agreeing that it will be worthwhile for utilities and students to study the attributes of these plants alongside the other fuel cell technologies, as well as to provide important support for an emerging technology.

Second, DRA suggests numerous disallowances to the capital and O&M costs for both projects. Generally, DRA advises the Commission to limit the pre-approved expenses to the lower of either a) what the other utility proposes for similar work, or b) what the United States Environmental Protection Agency published as typical capital and O&M costs for fuel cell installations in its Energy and Environmental Analysis Inc (EEAI) Report. Altogether, DRA proposes to reduce PG&E capital costs by $4.4 million and SCE's capital costs by $5.2 million. (Exhibit 202 at 26.) Similarly, DRA suggests reductions in annual O&M costs of approximately $635,000 for PG&E and $94,000 for SCE. (Exh. 202 at Table DRA-12 and DRA-13.)

The utilities object that DRA's disallowances are based on an outdated EEAI Report which provides cost estimates in 2007 dollars, whereas the applications are stated in 2009 dollars. According to SCE, when DRA's proposal is adjusted to 2009 dollars, the difference between the DRA and SCE cost estimates are minimal. Moreover, PG&E argues that the costs in its application are based on competitive proposals provided by fuel cell manufacturers for the selected locations, and are therefore more reliable as an estimate of actual project costs than the EEAI report which states that fuel cell prices "can vary significantly depending on the scope of the plant equipment, geological area, competitive marketing conditions, special site requirements, prevailing labor rates and whether the system is a new or retrofit application." (Exhibit 4 at 3-3.) We agree with SCE that it would be improper to disallow project costs based on a comparison of costs in different dollar terms, and we agree with PG&E that it is reasonable to rely on actual vendor cost estimates. Therefore, we decline to adopt DRA's proposed disallowances.

Finally, another modification we decline to accept relates to potential future GHG emission credits from the projects. TURN contends that it is possible that within the ten-year life of the fuel cells, the State or federal government will enact a cap and trade program that includes offsets and that the avoided GHG emissions due to waste heat production by the fuel cells will qualify as an offset mechanism. TURN suggests that because ratepayers will fund these fuel cells and provide the campuses with free waste heat, it is reasonable and fair to assign any potential value for avoided GHG emissions to ratepayers. Therefore, TURN asks the Commission to order PG&E and SCE to include terms in the contracts to ensure that such future value will be retained by ratepayers.

We will not require PG&E and SCE to renegotiate their contracts with the campuses to obtain value for potential future GHG emission offsets because it is highly doubtful that the waste heat itself will ever create a GHG emissions offset that can be sold into a GHG compliance market. Rather, the waste heat would more likely be classified as an emissions reduction within the emissions regime. Thus, we find that any future value of potential offsets is highly speculative and most likely minimal.

A similar issue arose in our recent decision on a CHP feed-in tariff, D.09-12-042. In that decision, we stated:

According to the contract, a CHP facility will convey all "green attributes" associated with the excess electricity delivered to the grid, including emissions reductions. However, the GHG emissions reductions that the facility experiences (compared to generating heat and electricity separately) cannot be isolated to delivered electricity but must be calculated on a facility-wide basis. For accounting purposes only, the utility will need to track the entire facility's avoided GHG emissions that occurred as a result of the installation of the new CHP facility. This information will be used for tracking purposes with the [Air Resources Board] Scoping Plan target for avoided GHG emissions from CHP. Thus, while there is no monetary value to the GHG reduction itself, for program accounting purposes the utility will count the avoided GHG emissions for any facility that signs up under this tariff.

In order to stay consistent with D.09-12-042, we will require the same tracking, for accounting purposes only, by PG&E and SCE for fuel cells deployed under this order that combine heat and power. This does not apply to the electric-only fuel cells, as these projects are not combined heat and power applications. As such, they should not be included in any accounting or tracking for CHP-related emission reductions.

4 AB 1613 charges the Commission with requiring electrical corporations to purchase excess electricity from certain new CHP systems.

5 TURN Comments, 3/22/10 at 1.

6 Id.

7 See TURN Comments, 3/22/10 at 5; WPTF Comments, 3/22/10 at 3, DRA Comments, 3/22/10 at 5.

8 Exh. 100 (SCE Direct Testimony) at 5.

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