BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF
CALIFORNIA
In the Matter of the Application of San Diego Gas )
& Electric Company (U 902 E) for a Certificate of )
Public Convenience and Necessity for the Sunrise ) Application 06-08-010
Transmission Project )
__________________________________________)
PHASE II OPENING BRIEF OF UTILITY CONSUMERS' ACTION
NETWORK
Michael Shames
On behalf of UCAN
3100 Fifth Ave. Suite B
San Diego, CA 92103
619-696-6966
mshames@ucan.org
May 30, 2008

As will be set forth below, the evidentiary record in Phase II of this proceeding establishes the following:

1) SDG&E's proposed project and/or the Enhanced Northern Route are suboptimal relative to other alternatives and should be rejected;

2) UCAN's No-Project, No-Action alternative is the optimal alternative on all grounds: cost, environmental impact, reliability and flexibility. SDG&E now admits that by its own calculations, its Enhanced Northern Route is only $40 million per year cheaper than a GT Reference Case and only $10 million per year cheaper than a GT-CC Reference Case with a 7165 Btu/kwh heat rate, versus claimed benefits of $142 million per year in Phase 1 for Sunrise Transmission Project (STP) versus a GT Reference Case. Its claimed benefit/cost ratio is down from 1.91 to between 1.06 and 1.25. However, SDG&E's Phase II numbers continue to ignore errors pointed out by UCAN in Phase 1 and Phase 2, errors which by themselves when corrected swing the economic balance sharply towards non-Sunrise Alternatives. Just as the Phase 1 record showed that SDG&E's claimed B/C ratio of 1.91 was really less than 1 (Ex. U-3, Table 1), so now the Phase 2 record shows that SDG&E's new B/C ratio of 1.06-1.25 is really much less than 1. And as shown in Attachment 2, there are at least six
alternatives that are more cost-effective than STP. Additionally, UCAN's incremental approach to transmission upgrades proves to be more flexible and less controversial than any of SDG&E's proposals.

3) SDG&E's cost-benefit analysis justifying its proposed project is fatally flawed by its failure to incorporate the following:

• SDG&E incorrectly assumes 1000 Mw of increased non-local RA capacity required due to STP will be free.
• SDG&E ignores the economic benefits of upgrading the Miguel inlet capacity, benefits which are largest in the GT Reference Case and other no-STP cases, and non-existent in the STP cases.
• SDG&E ignores the economic benefits of upgrading Path 44 instead of building
  new CTs.
• SDG&E ignores the impact on natural gas consumers of STP, which UCAN calculated in Phase 1 (with no rebuttal or cross-examination from SDG&E then or since) would be several million dollars per year.
• SDG&E ignores its own testimony on achievable AMI load reductions from its GRC and LTPP, and uses older, lower estimates based on older, lower incentive payments to customers than those adopted in the SDG&E GRC.
• SDG&E continues to ignore its own LTPP testimony, previously brought up in Phase 1 and since approved by the Commission in the LTPP decision of 12/07, that it will have 139 Mw of dispatchable RMR capacity and not the 29 Mw it is now assuming or the 59 Mw (with EnerNoc) that it and the ISO assumed in Phase 1. An extra 80 Mw of dispatchable RMR capacity would reduce the number of CTs needed for the GT Reference case by one or two each year, saving approximately 80/322 of the $44 million per year capital cost of CTs in the GT Reference Case, or $11 million per year.
• SDG&E made 16 changes to its GridView modeling between the Phase 1 Cases 200/201 that it relied upon (see SDG&E Phase 1 OB, p. 150) and its Phase 1 Case 300, all of them in response to UCAN-identified issues (see Ex. SD-27, Table 13, pp. 50-51). It made a further 20+ changes to Case 300 for Phase 2. However, SDG&E continues to include faulty GridView input assumptions that were identified in Phase 1 but not changed for either Case 300 in Phase 1 or Case 300 in Phase 2.
• SDG&E has reduced its Phase 2 forecast of 2008-2015 IID-area geothermal additions by 185 Mw, to 1600 Mw, which is still far above the IVSG projection.
• SDG&E's own numbers contained in its own responses to UCAN data request 39-9 and its revisions done for the ALJ (Ex. SD-142) show that a variation on DEIR Alternative 1 would be economically preferable to any of SDG&E's STP alternatives

When SDG&E's cost-effectiveness analysis is adjusted to reflect the above, the Commission will conclude that the applicants have put forth a project that will cost the state's ratepayers a levelized $74 million per year compared to a CT Reference Case, and up to $120 million per year compared to other alternatives. Over the 58-year depreciable life of the project, this amounts to a net loss to state's ratepayers of $4.3-7 billion.1 UCAN submits that the STP project is simply too expensive given the questionable nature of the benefits offered.

4) STP is not needed to meet SDG&E reliability needs. SDG&E's own revised Table 11-1 shows a need of no more than 300 Mw through 2016. UCAN's baseline assumptions result in a need for only 49 additional Mw through 2016. When known and likely resources are considered, SDG&E can expect a 150-300 Mw surplus in 2016. Additionally, SDG&E's revised Table 11-1 is deeply flawed because it omits various preferred loading order demand-side resources that should be developed with or without STP;

5) STP is not needed to meet SDG&E's RPS goals SDG&E admits that RPS generation does not have to be delivered to SDG&E. Moreover, UCAN shows that sufficient RPS generation can be delivered to SDG&E's service territory over SWPL and Path 44, particularly with the minimal-cost Miguel RAS modifications proposed by UCAN in Phase 1 and the ISO in its 2008 Transmission Plan.

6) SDG&E filings in another CPUC proceeding (Exhibit U-91) reveal that SDG&E can import an incremental 1752 Mw of additional renewable resources from the north using its existing transmission facilities, with no STP and with no upgrades required. 1752 Mw is about 35% of SDG&E's roughly 5000 Mw peak load, and thus is far more than enough transmission capacity to allow SDG&E to meet a 20% RPS standard, even with zero imports from the east and zero local RPS generation. It is even enough to meet a 33% RPS standard with zero imports from the east and zero local generation. Thus, SDG&E could meet its RPS obligations, both current and potential, with no new transmission.

7) The evidence does not support the construction of a singular transmission line. However, to the extent that the Commission deems it necessary to build transmission to renewable resources, UCAN's proposed Jacumba-Sycamore route is the optimal choice available. If projections for the installation of thousands of Mw of Mexican wind are accurate, a new line from Jacumba will eventually be needed. Building a
Jacumba-Sycamore Canyon line allows deliverability for the already signed Sempra-SCE contract and the already-pending Sempra Generation application to DOE for up to 1250 Mw of imports at Jacumba, plus another 460 Mw from pending ISO queue projects 106A and 112. When and if Imperial Valley development occurs which cannot be accommodated over the existing SWPL, adding an Imperial Valley-Jacumba line will be straightforward. Moreover, the environmental impacts of a Jacumba-Sycamore Canyon line will be less than those of any STP alternative. A
Jacumba-Sycamore Canyon line will allow new wind generation to have two paths to SDG&E's 230 kV grid, and will thus allow it to be counted for reliability.

8) UCAN's proposed Southern Route is the optimal major transmission route into Imperial Valley. In fact, southern routing allows the Jacumba option to be further developed and thus allows phasing of transmission development.

9) SDG&E's Phase 2 application is riddled with errors and contradictions from its Phase 1 testimony. SDG&E introduces new economic analysis errors which by themselves are enough -- when corrected -- to strongly swing the economic balance in favor of without-Sunrise Alternatives. To wit:

• SDG&E ignores its signed EnerNoc contract which it has consciously chosen not to submit to the CPUC via a CPCN application.
• SDG&E has cut its STP O&M cost estimate by a factor of 4, from $10 million/year to $2.5 million per year.
• SDG&E' s RMR capital cost estimates for the GT-CC Reference case contain errors and omissions, and ignore opportunities to reduce RMR costs in at least 2011 and 2014-15, even using SDG&E's own methodology
• SDG&E has manipulated its cost data so that in Phase 1, STP cost $1265 million, which translated into annual costs of $156.1 million. Yet, in Phase 2, despite increasing the capital cost estimate by over 36% to $1723 million , the projected levelized cost of STP has gone up only 3 percent, to $161 million per year.

10) SDG&E has exaggerated the potential that a new transmission line will be available by 2011. The record shows that the Northern routes won't be built any sooner thanSouthern routes. Because SDG&E's reliability needs are covered through 2018, there is no rush for build the line or, in the alternative, it can be constructed incrementally so as to address the IID interconnections to the north, to Devers and/or GPN.

11) Contrary to SDG&E's assertions about greenhouse gas reductions, STP will be directly responsible for an increase in NOx and, most likely, CO2 emissions as well. The record also suggests that STP will lead to increased import of coal-powered electricity.

12) SDG&E (and the ISO) have substantially understated the very severe risks of risk of outages to both SWPL and ENR due to fire and seismic risk of an N-2 condition due to the active faults proximate to IV substation. The Commission must question the wisdom of SDG&E's locating two of the three major transmission conduits serving San Diego at the same seismically-exposed substation and routing them through highfire-risk backcountry.

13) UCAN is very concerned that SDG&E's prime motivation behind its application is the promise of $1.32 billion in net profit - with over $700 million of that inuring to the company in the first 8 years of the project. This significant and guaranteed profit, when combined with the benefits reaped by SDG&E's parent company (Sempra Energy), as explained in UCAN's Phase 1 brief, amounts to a compelling self-interest
which explains SDG&E's aggressive pursuit of this project despite the absence of evidentiary support for the project. These motivations also blind SDG&E to the numerous alternatives which are better for the region, better for the state's ratepayers but not as lucrative for SDG&E or Sempra.

14) SDG&E's undervaluing of the potential for PV is representative of a company philosophy or strategy, not an informed difference of opinion. It is antipathy and exemplary of its laser-like focus upon a singular transmission project into the Imperial Valley. This antipathy to in-region renewable and its almost illogical preference for imported solar thermal to the exclusion of in-basic photovoltaic is presents a conundrum to the Commission. It must consider the value of a $1.7+ transmission line to import $6+ per watt power2 compared to an expenditure of
approximately the same to generate distributed PV power within the region. UCAN submits that a more-enlightened attitude within SDG&E could result in the PV deployment plan contained within the Smart Energy 2020 report being incorporated into UCAN's No-Action plan of greater in-basin generation combined with increased import capacity at a cost that approximates the total cost of STP.

15) SDG&E's Phase II testimony is procedurally flawed. It fails to satisfy state and federal environmental requirements, it violates the Commission's prohibition of adjusting Phase 1 assumptions that are not prompted by the DEIR, its revised cost caps are meaningless and it wrongfully introduces expandability as a decision criterion.

Footnote 1: $74 million/yr x 58 years = $4.292 billion; $120 million per year x 58 years = $6.960 billion.

Footnote 2: The Stirling cost is actually optimistic. No informed observer believes that Stirling will be able to adhere
to its contracted costs of power. And SDG&E’s evidence of inflation in the cost of materials is to be
believed, it is unlikely that Stirling will be immune from the upwards cost pressures imposed upon
SDG&E. Moreover, the CEC estimated costs for Stirling suggest much higher prices than $6 per watt. RT
at 3921 (Powers) Read the entire brief by clicking on the attachment below.