9. Comments on Proposed Decision

The PD of ALJ Simon in this matter was mailed to the parties in accordance with Pub. Util. Code § 311(g)(1) and Rule 14.3 of the Rules of Practice and Procedure. Comments were filed on April 19, 2007 by AReM, CalpinePowerAmerica-CA, LLC (Calpine), CCSF (joined by the City of Chula Vista), GPI, MU, PG&E, SES, TURN, and UCS. Reply comments were filed on April 24, 2007 by AReM, Calpine, MU, PG&E, SCE, and TURN.

Metric

TURN, as it did in its initial comments, argues that APT should provide the metric for the minimum quantity. No other commenter now seeks an APT metric. We do not change the PD's adoption of prior year's sales as the metric for the minimum quantity.

Minimum Quantity

Calpine urges us to set the minimum quantity at zero, at least for small LSEs. MU notes that it is in the unique situation of having no connection to the grid, and thus-regardless of our position about other small LSEs-it should have a minimum quantity of zero. TURN continues to argue that the minimum quantity should be an escalating percentage of APT, up to 80% in 2010. SES, supported by AReM, seeks to defer the 2007 requirement to 2008, creating a zero minimum quantity in 2007 and 0.50% of prior year's sales in 2008. UCS seeks a change, for the year 2010 only, to provide that 25% of the RPS-eligible energy required to meet the 20% goal be in the form of long-term contracts and/or short-term contracts with new facilities. UCS asserts that this change would reduce the likelihood that LSEs other than PG&E, SCE, and SDG&E will make too small a contribution to new renewable generation.

We do not change the minimum quantity in the PD. Even for small LSEs, a minimum quantity of zero is unnecessary. They have the possibilities of carrying forward "excess" contracted energy for future years and using repackaged contracts originally negotiated by larger entities to comply with § 399.14(b)(2) requirements. Further, LSEs that do not seek to count short-term contracts with existing facilities for RPS compliance do not have any obligations under § 399.14(b)(2). MU, because it is not connected to the grid, is a clear example of an LSE that is not going to be affected by § 399.14(b)(2); an LSE that generates all its own RPS-eligible power is another example. TURN's proposal for a large and escalating requirement is not more persuasive now than it was originally.

We also decline to adopt the two proposals that would change the temporal aspects of the PD. The UCS proposal might or might not require a large jump in long-term contracts and contracts with new facilities in 2010, depending on an LSE's progress toward the 20% goal. It would introduce unnecessary uncertainty into RPS procurement planning, especially for smaller LSEs that may need deliveries from only one or two contracts to meet their 20% goal. The SES proposal to postpone compliance to 2008 is not justified, since all parties have known since late September 2007 that § 399.14(b)(2) would be effective January 1, 2007.

Enforcement and Compliance

CCSF and AReM, supported by PG&E, urge that we allow energy contracted for in excess of the 0.25% requirement in any calendar year to be carried forward and used for compliance with § 399.14(b)(2) in subsequent years. Although implementing such banking of credit for long-term contracts and short-term contracts with new facilities would add some reporting and monitoring complexity, we are persuaded by CCSF's numerical demonstration that it could make it easier for smaller and/or newer LSEs to comply. Allowing LSEs to carry forward credit will also give them more incentive to sign larger contracts, sooner rather than later, which will advance overall RPS program goals. The PD has therefore been changed to allow credit, but not deficits, in meeting the 0.25% requirement to be carried forward.

AReM also seeks clarification of the role of" repackaged" contracts originating between an RPS-eligible generator and a purchaser who then divides some or all of the contract into smaller pieces and sells them to RPS-obligated LSEs. The discussion in the PD has been expanded and the requirements for allowing the use of repackaged contracts made more explicit. We also adopt TURN's suggestion that Energy Division staff have access to the underlying contract that has been repackaged.

GPI suggests that an LSE that fails to meet its § 399.14(b)(2) requirements be allowed to swap its otherwise RPS-eligible short-term contracts with existing facilities to another RPS-obligated LSE that will be able to count them for RPS compliance. This proposal has some of the same drawbacks as TURN's original proposal for "trading" credit for contracts. It would add complexity in reporting and monitoring, without predictable gains for compliance.

AReM elaborates on this idea by proposing that failure to meet the 0.25% requirement be subject to monetary penalties, but the LSE be allowed to swap or sell its otherwise RPS-eligible short-term contracts with existing facilities to other RPS-obligated LSEs. The addition of penalties does not eliminate the problems with swapping credit for contracts. It also introduces penalties for a shortfall in meeting a requirement that is neither APT or the 20% goal, contrary to our intention to keep implementation of § 399.14(b)(2) as simple as possible.

TURN suggests that penalties be imposed if actual deliveries fall short of the contract amount of energy used for compliance with the 0.25% requirement. This proposal, as SCE points out, does not take into account the fact that some contracts will not deliver, or will deliver less energy than contracted, for a variety of reasons other than deliberately constructing an infeasible contract in order to meet § 399.14(b)(2) requirements. TURN ignores, moreover, the likelihood that knowingly undertaking contracts that never deliver would subject an LSE to more significant penalties for failing to meet its APT, as well as the 20% goal. We do not change the PD's rejection of penalties for failing to meet § 399.14(b)(2) requirements.

AReM proposes that we allow waivers of the 0.25% requirement on an LSE's showing of scarcity of available contracts or market power conditions. Since penalties are not assessed for failure to meet the 0.25% requirement, this waiver proposal is unnecessary. If and when an LSE is subject to a possible penalty for failing to meet its APT or the 20% goal, it may avail itself of the established reasons to seek to avoid imposition of a penalty.

AReM also proposes that LSEs newly doing business in California be required to meet the 0.25% requirement in their first year of retail operation. We do not adopt this proposal, which is inconsistent with our reporting regime and with our treatment of other RPS obligations.

SES, citing the table in Appendix A, urges that the 0.25% requirement end in the year an LSE attains the 20% goal, rather than the following year, as the text of the PD states. This comment reveals an error in the table, which we correct in a revised table reflecting changes made to the PD. We do not change the termination of the requirement as stated in the PD.

Administration

AReM asks us to "grandfather" all short-term contracts with existing facilities that are signed prior to the effective date of this order. We note initially that contracts signed prior to January 1, 2007 are not subject to § 399.14(b)(2). Contracts signed in 2007 and later years are subject to the requirements of that section. We do not adopt AReM's grandfathering proposal. As TURN points out, grandfathering could allow an LSE to sign short-term contracts with existing facilities for large amounts of energy, with no additional obligation to sign long-term contracts or short-term contracts with existing facilities. The LSE would thus effectively avoid the § 399.14(b)(2) requirements. There is no reason to allow this result, or even to create the risk of this result.

Finally, TURN asks that non-market participants, in addition to Commission staff, receive copies of contracts and other documentation of compliance with § 399.14(b)(2). For the large utilities, such information is already available through participation in procurement review groups (PRGs). We decline to create quasi-PRGs for ESPs, CCAs, and small and multi-jurisdictional utilities and will not require documentation to be provided to non-market participants.

The PD has also been revised to eliminate inconsistencies and to correct minor errors.