III. Discussion

A. Overview of Long-Term Plans

1. PG&E

In its long-term plan, PG&E proposes to meet its 2010 goal by acquiring about 900-1000 gigawatt-hours per year (GWh/yr) of new renewable energy, a rate that is about 1-¼ per cent of its projected annual retail sales. PG&E states a strong preference for renewable resources in its service territory, providing a "resource stack" that ranks its current resource planning preferences:

a. Renewable dispatchable resources in NP-15;

b. Renewable firm baseload resources in NP-15;

c. Repowered wind in NP-15;

d. Solar in NP-15;

e. Solar outside of NP-15;

f. New wind in NP-15;

g. Firm baseload resources outside of NP-15; and

h. New wind outside of NP-15.

PG&E applies these planning preferences in its illustrative plan for its renewable resource acquisitions, which we show in a tabular form below.

PG&E 2010 Illustrative Projections

Resource	MW	Approx. % of RPS
New wind*	450	28
Repowered wind*	400	24
Geothermal	400	24
Biomass	150	9
Biodiesel	50	3
Solar	200	12
TOTAL	1650	100

PG&E 2014 Illustrative Projections

Resource	MW	Approx. % of RPS
New wind*	550	28
Repowered wind*	400	20
Geothermal	450	23
Biomass	150	8
Biodiesel	150	8
Solar	250	13
TOTAL	1950	100

*In PG&E's service territory

PG&E intends to use all procurement options, including RPS solicitations, general procurement, bilateral negotiations, and possible utility ownership, to obtain the projected quantity of renewable energy. PG&E reports that its initial conceptual analysis of transmission upgrades needed in its service territory to achieve the 2010 goal showed costs of upgrades between $170 and $230 million, but does not provide any information about the location, scope, or timing of any of the possible upgrades. PG&E, relying on the Energy Commission's Renewable Resource Development Report (Nov. 24, 2003),² does not anticipate requiring resources from outside its service territory, and does not address any out-of-territory transmission issues.

2. SCE

SCE provides a "base case," "high need case," and "low need case" in its analysis.³ Although it has not developed a formal resource "stack," SCE indicates that its current view of resources that best meet its operational need is: (1) peaking resources, such as solar; (2) baseload resources, such as geothermal and biomass; and (3) intermittent resources, such as wind. SCE notes that its planning is roughly based on the current mix of renewable resources delivered under Qualifying Facility (QF) contracts pursuant to the federal Public Utility Regulatory Policies Act of 1978 (PURPA). In terms of capacity, this mix is about 42% wind, 31% geothermal, 15% solar, 10% biomass and 2% small hydro.⁴ SCE adds that it intends to contract with a large solar project that will begin deliveries in phases, beginning with 2010. By 2010, SCE intends to procure approximately 403 MW, shown in tabular form below.

SCE 2010 Illustrative Projections

Resource	MW	Approx. % of RPS
Wind	1680	42
Geothermal	68	17
Biofuels	37	9
Small hydro	5	1
Solar thermal	1250	31
TOTAL	403	100

SCE 2014 Illustrative Projections (with solar)

Resource	MW	Approx. % of RPS
Wind	297	30
Geothermal	120	12
Biofuels	63	6
Small hydro	10	1
Solar thermal	500	51
TOTAL	890	100

In its planning without the large solar project, SCE eliminates the "solar" category, leading to a 2014 mix of about 68% wind, about 15% for each of geothermal and biomass, and less than 2% small hydro.⁵

SCE identifies a number of transmission upgrades and new projects that could accommodate additional geothermal and wind generation, as well as some solar generation. SCE projects these upgrades coming into service between 2007 and 2014.⁶ These transmission projections are not linked to specific renewable projects, but rather to estimates of future RPS procurement from the various resource areas SCE identifies.

3. SDG&E

SDG&E reaffirms its commitment to reach the 20% goal by 2010, and estimates that eligible renewable resources constituting about 5.7% of its baseline retail energy supply are now under contract for 2010, leaving about 2,500 GWh to be procured. SDG&E continues its use of a resource stack to show its preferences for types of procurement, but notes that the stack is illustrative. Its current resource preferences are:

a. Biomass or biogas in its service area;

b. Wind in its service area;

c. Solar in its service area;

d. Solar outside its service area;

e. Geothermal outside its service area;

f. Biomass or biogas outside its service area; and

g. Wind outside its service area.

SDG&E's projections for 2010 are presented in tabular form below. About a quarter of this total is estimated to be from within its service territory.

SDG&E 2010 Illustrative Projections

Resource	MW	Approx. % of RPS
Wind	312	40
Geothermal	190	24
Biogas	45	6
Biomass	40	5
Small hydro	11	1
Solar	182	24
TOTAL	780	100

SDG&E adopts a target of 24% renewables by 2014, continuing incremental growth of 1% per year past 2010. It currently has about 4.6% of that total under contract. Its projections for 2014 are given in tabular form below. The proportion of resources from its service territory remains at about 25%.

SDG&E 2014 Illustrative Projections

Resource	MW	Approx. % of RPS
Wind	484	45
Geothermal	210	20
Biogas	45	4
Biomass	40	4
Small hydro	11	1
Solar	285	26
TOTAL	1075	100

SDG&E also states that, unless a major transmission upgrade is in place and a market mechanism for trading renewable energy credits (RECs) is available, it will not in fact attain the RPS target in 2010. Its plan therefore assumes that significant new transmission will be built, in the form of at least a new 500 kV transmission line. The plan does not include any proposals for new transmission, nor does it identify the issues that would require discussion in an application for a certificate of public convenience and necessity (CPCN) for any new transmission.

B. Common issues

1. Planning

In the Scoping Memo⁷, the utilities were directed to prepare

. . . an RPS plan that accomplished three things: attainment of RPS goals for 2005. . .; a detailed plan for RPS procurement over the period 2005-2014, with an emphasis on achieving the 20% RPS goal in 2010 and including necessary transmission expansion; and a plan for attaining the optimum amount of generation from re-powered renewable facilities presently under contract to the utility. All three components of the plan should incorporate lessons learned during the 2004 RFP solicitations.

The Scoping Memo makes clear that the point of the long-term planning exercise is to prepare a map that will get the utilities to the 20% goal in 2010. To be effective, such a map should not simply express the utilities' preferences, other things being equal. It should also identify and analyze potential problems and delays and develop alternate routes to respond to identified problems.

Each element of the plan should be directed to analyzing, identifying, and implementing steps to reach the 2010 goal and maintain or expand it in future years.⁸ To the extent that the plans submitted do not adequately focus on particular elements that are necessary to planning for compliance, we will direct the utilities to supplement their plans.⁹

Both PG&E and SDG&E present resource "stacks" as part of their plans; SCE identifies operational preferences. As we observed in D.05-07-039, these "stacks" and preferences can only be illustrative, and cannot substitute for the least cost/best fit analysis of actual bids in RPS solicitations. In long-term planning, even more than annual procurement, however, it is difficult to strike a balance between the utilities' reasonable planning assumptions and initial preferences and the rigorous application of least cost/best fit analysis to specific project proposals for RPS procurement. Without making some initial assumptions, the utilities are not planning. If the assumptions are too rigid or too limited, the planning process is not robust enough to be useful and may impinge on the least cost/best fit evaluation process. The plans need to be more than bald statements of preference; if they prioritize resources, they must provide analysis that justifies the preference in terms of meeting the utility's RPS targets. At the least, the utilities must make explicit the basis of the initial planning assumptions about resources, whether ordered stack or, in SCE's case, projection of current renewables mix. In addition, all utilities should include high, low, and base cases, with supporting analysis, as SCE did in its current plan.

In their future long-term plan filings (but not in the supplements ordered today), the utilities must also include a discussion of "lessons learned" from all prior planning cycles. We would expect this discussion to include, at a minimum, analysis of whether the utilities' assumptions were borne out in practice, changes to the utilities' situation that require major revisions to assumptions, and other necessary adjustments as time goes on.

Assumptions about the mix of resources also impact other critical planning elements, such as transmission planning. If the utility's planning assumptions suggest minimal need for investment in transmission, but those assumptions are not justified, a necessary planning step (transmission improvements) will be missed. If the assumptions suggest too much need for transmission, steps that the utility could take to facilitate easier or less expensive methods of RPS procurement may be overlooked.

2. Transmission Planning

The Scoping Memo emphasized that analysis of transmission needs is a required part of the utilities' long-term RPS planning process. This is only common sense, since theoretically available renewable resources will become delivered electricity only if the electricity can be delivered. PG&E and SDG&E did not meet this requirement, as we discuss more fully below. SCE did include transmission planning, but should bolster its analysis.

This issue is not merely theoretical. Wind, new or repowered, geothermal resources, and (for SCE), a large solar thermal project play a major part in the utilities' illustrative plans. For the most part, these resources are in areas remote from the utilities' load centers. This makes analysis of transmission issues and transmission planning not optional, but imperative. The plans are disappointing in this regard, even though the Scoping Memo required transmission planning to be discussed. Since transmission planning and construction take a long time and involve the potential for significant delays, scenarios including all projected transmission additions and upgrades, less than all projected transmission upgrades, and no transmission additions and upgrades should be expressly considered in the long-term plans.

Efforts begun in Investigation (I.) 00-11-011 to examine systematically the issues of transmission of renewable energy from remote resource areas demonstrate that evaluation and discussion of such issues should be included as part of the analysis of transmission needs in RPS plans. See "Development Plan for the Phased Expansion of Transmission in the Tehachapi Wind Resource Area: Report of the Tehachapi Collaborative Study Group" (March 16, 2005).¹⁰ This report points to the need for utilities to include some understanding of renewable resources groupings, possible economies of scale for transmission from areas with potentially concentrated resources, and network benefits and costs of concentrated renewable resources, as well as alternatives to building new transmission to access renewable resources.

When we recently initiated I.05-09-005, we made the many issues involved in transmission planning and construction for renewable resources the focus of that proceeding. We intend to coordinate this proceeding and that one closely. The existence of I.05-09-005 does not, however, relieve the utilities of the responsibility of analyzing transmission issues and identifying appropriate steps to deal with them in both their short-term and long-term RPS procurement plans.

In D.05-07-039, we required that utilities allow delivery points outside their service territories and bids having curtailability as an attribute, as immediate steps that could reduce the impact of transmission constraints on RPS procurement. The utilities' current long-term plans do not include these elements. We will require that analysis of the impact of delivery points, curtailability, remarketing costs and benefits, and other delivery-related issues be included in future long-term plans, in the transmission planning component. PG&E and SCE are free to include a preliminary analysis in their supplemental plans under this order, but are not required to do so. SDG&E should, however, incorporate this preliminary analysis in its current supplement, since it has identified transmission as its primary constraint in attaining the 2010 target.

3. Contingency Planning

None of the utilities has included any alternative or contingency planning. SDG&E simply says that it has no contingency plan, even though it believes that its non-contingency planning for RPS compliance will fail if new transmission is not available by 2010. SCE has made planning estimates for base case, high need case, and low need case, which is a good start, but has not analyzed the contingencies that might impede attaining RPS targets or identified steps it might take to overcome such impediments. PG&E does not discuss contingency planning at all.

We do not expect extraordinarily detailed contingency planning, but we agree with ORA that prudent planning includes reasonable analysis of the possibility that not all of the assumptions and actions outlined in the main plan will hold true or occur in the timeframe assigned to them. This is especially critical with respect to transmission, since failure or extended delay of planned transmission could have a large impact on RPS procurement. ORA and UCS note that both PG&E and SDG&E include assumptions or proposals that are not now part of the RPS program (e.g., out-of-state delivery of electricity, RECs that are tradable in a market). The utilities' contingency planning should also assume that current conditions of the RPS program will continue, unless there is a clearly articulated basis for assuming that certain changes will occur in a particular time frame.

4. Procurement Strategies

All the issues discussed above suggest that, as ORA, TURN and UCS urge, it is not wise for the utilities to set as their target 20.0% of their retail sales to be procured from eligible renewable resources in 2010. The 2010 target date is fast approaching. The utilities' planning ought to include procuring more than the exact amount of their projected incremental procurement target (IPT) each year. TURN points out that not all contracts come to fruition. SCE notes that some attrition in its baseline resources is expected.

Many elements must be in place for planned resource development to turn into delivered energy. Since the utilities are subject to being penalized if they fail to meet RPS goals,¹¹ they should employ some margin of safety to guard against reasonably likely problems, such as errors in projections, big changes in load that could not be forecast, and delays in upgrading transmission. We therefore will require the utilities in their supplements to make an initial quantification of their "margin of safety" in RPS procurement, both in terms of their annual procurement targets and in relation to the 2010 target date. We recognize that these efforts will necessarily be preliminary, but it is nonetheless important for the utilities to begin to develop such margins of safety. We intend to require such quantification, with supporting analysis, in both annual RPS plans and long-term RPS planning components in the future.

We note finally that Energy Action Plan II expresses our intention to press forward toward Governor Schwarzenegger's goal of having 33% of California's electricity generated from renewable resources by 2020. Thus, the full value of any procurement of renewables that is planned as greater than 1% annually or 20% by 2010 will be captured either to make up for unexpected shortfalls in other renewables deliveries, or to make progress toward the state's next goal for renewable energy.

C. Individual Utility Plans

1. PG&E

Commenters have raised questions about PG&E's analysis of renewable resources and its approach to repowering. Both areas should receive more attention than PG&E's current plan provides.

Overall, PG&E relies on the Energy Commission's estimate of possible renewable resources in its service territory. PG&E then concludes, without any further analysis, that it should have no problems meeting its RPS goals without major transmission upgrades and without aggressive repowering efforts. As CEERT points out, however, relying on a study of theoretically available renewable resources is not the same as planning for attainment of the 20% RPS goal by 2010. PG&E does not identify any resources or class of resources, or any amount of resources, that it believes will be available in a particular time frame. PG&E will certainly find out what is available in its RPS solicitations, but its current plan will not help it determine if any transmission changes could be needed, or if remarketing agreements with other utilities would be beneficial, or if the utility should set a particular goal for repowered wind contracts.

This relatively passive approach carries over to PG&E's discussion of its resource planning preferences. Its resource "stack" has biomass and biodiesel as its first two choices. Yet PG&E also notes that these resources are likely to be too expensive. This calls into question the value of the preference ranking, since the meaning of a preference for a resource that cannot economically be deployed is unclear.

The high ranking given to biofuels pushes wind repowering down to third on PG&E's list, although PG&E concedes that repowering would be efficient and effective. The Altamont Pass Wind Resource Area (Altamont Pass) is in PG&E's service territory. It is currently providing electricity to PG&E's customers and is well-understood. Here, the ranking is more than merely illustrative. For resources that bid into an RPS solicitation, a utility's low planning ranking of a particular resource would not be allowed to interfere with the least cost/best fit analysis of the bid. But repowering contracts may be bilaterally negotiated rather than bid into a solicitation, as PG&E notes in its plan.¹² If the utility's internal planning downgrades repowering, it could have a negative impact on the utility's pursuit of repowering opportunities.

Several commenters note issues that may hamper the bilateral negotiation of repowered wind contracts. While we continue to encourage the utilities to seek repowered wind contracts through bilateral negotiation, we also urge them to seek repowered wind projects through RPS solicitations, where the repowers would be evaluated on least cost/best fit criteria and would, if relevant, be eligible to apply for SEPs.

CalWEA urges that SCE's repowering principles be imposed on PG&E.¹³ We decline to do that, since the situations of PG&E and SCE with respect to wind repowering are not identical. We will, however, require PG&E to develop an analogous set of principles, focused on wind repowering at Altamont Pass (though not excluding other facilities). PG&E should include those principles in its supplement, as part of a conceptual plan, including a timeline, for acquiring repowered wind resources. We expect that PG&E will accord repowering a high priority, which would be reflected in actual contracts submitted for approval well before 2010.

CalWEA makes a number of suggestions for further Commission requirements for repowering projects.¹⁴ As we did in D.05-07-039, we prefer to rely on the business judgment of the parties with respect to contracting issues beyond those addressed in D.04-06-014.¹⁵ Although we share CalWEA's concern that PG&E and SCE have not yet taken full advantage of the opportunities provided by repowering, we are not persuaded that imposing CalWEA's detailed requirements at this time will induce them to do so. We continue to believe that repowering existing wind facilities is an important resource for the RPS program and are concerned that more progress has not been made to date. As we stated in D.03-06-071, ". . . the repowering of existing wind facilities in prime locations is a common-sense approach to increasing procurement of renewable energy, with costs that should be lower than for new greenfield projects." (Mimeo., p. 58.) But it is also important that we not, by too-detailed prescription, create a special status for repowering, which is one of an array of renewable resource options. The utilities have annual procurement targets to meet in an aggressive time frame; this should be incentive enough to make appropriate bilateral repowering deals and encourage repowered wind projects to bid in RPS solicitations.

The Center for Biological Diversity (CBD) is highly critical of the management of Altamont Pass wind turbines, citing a study by the Energy Commission on the high number of bird deaths associated with the facilities. (Developing Methods to Reduce Bird Mortality In the Altamont Pass Wind Resource Area, August 2004.¹⁶ CBD urges that PG&E be required to include in any repowering contracts a set of conditions that would be more protective of birds than the current operations at Altamont Pass. We decline to require PG&E to include these conditions. As CBD acknowledges, the Alameda County Board of Supervisors, not this Commission, is the permitting agency for the Altamont Pass wind facilities. We will not require specific contract provisions for repowering projects at Altamont Pass, since we do not want to create inconsistencies with permit conditions recently set by Alameda County. PG&E remains able to negotiate terms with Altamont Pass projects that are consistent with permitting and RPS requirements.

PG&E has not presented any transmission analysis. It is not enough to say "we don't anticipate any need for transmission; " some analysis of why not is needed. As an example, the Tehachapi Study Group report includes the possibility of transmission from the Tehachapi region to PG&E, as well as to SCE. PG&E may decide not to pursue such ideas, but in submitting an RPS plan that goes out to 2014, it must include some discussion of a range of possibilities - including transmission from the Tehachapi region -- even if it discounts some of them. It must articulate analysis of the value, probability of occurring, and rough costs and benefits of a variety of transmission options. Otherwise, it is not planning, but merely projecting the status quo into the future.

No contingency planning appears in PG&E's plan, perhaps because of PG&E's reliance on the Energy Commission's estimates of potential resources. Some effort, however, needs to be made to anticipate potential issues and problems that could impede PG&E's RPS compliance.

In its supplement, PG&E should include more specific discussion of available resources; a conceptual plan, including principles for repowering and a timeline, for pursuing repowered wind contracts; a discussion of what transmission may or may not be needed, with reasons, to attain the RPS goals in 2010; and an analysis and plan for contingencies that may impede attainment of RPS goals.

2. SCE

Commenters are generally supportive of SCE's long-term planning, and SCE indeed presents useful planning information. We note particularly the analysis underlying SCE's high/low/base case presentation. SCE's principles for repowering also are clear and provide useful guidance to the utility in that area. CEERT and IEP criticize SCE's inclusion of a potential large solar thermal project without analysis of its characteristics, likelihood of successful transition from experimental to commercial application, and lack of competitive bidding. SCE has since filed an advice letter seeking approval of a contract for the project. (AL 1909-E.) Without in any way prejudging the outcome of the review process for this contract, we note our agreement with the commenters that, in general, planning that relies on experimental technologies or other elements that have not yet been adapted for the use the utility intends, should include some analysis of the likelihood of success, and include contingency planning in case of total or partial failure of the project, delay in implementation, funding problems, and other typical problems of new projects.¹⁷

SCE's transmission plan presents a comprehensive list of possible transmission upgrades that would be relevant to RPS procurement. SCE does not, however, analyze which possibilities would be necessary for its compliance, nor analyze the possibilities that some or all of the listed transmission projects would not be built, or would not be available by 2010. The plan therefore does not provide assistance in identifying those transmission construction delays or deficiencies that would impede attainment of the 20% goal by 2010, and for which some alternate or contingency planning would be useful.

3. SDG&E

SDG&E estimates that 75% of the energy it will use to meet its RPS goals in 2010 will come from outside its service territory. It also notes that, without at least one new 500 kV transmission line coming into its territory from the east, it will not be able to bring into its service territory the volume of power needed for its compliance planning. SDG&E does not, however, present a transmission plan or a timeline for developing a proposal for new transmission. This large omission makes it difficult to evaluate SDG&E's planning, as ORA observes.

SDG&E also suggests that a market mechanism for trading RECs that can be used for RPS compliance will be needed in order for it to attain the 2010 goal. SDG&E does not however, estimate what percentage of its goal would require the use of tradable RECs, or how soon such RECs would be needed.

Since SDG&E states that its ability to attain the 2010 target requires on the existence of two circumstances that do not presently exist (the new 500 kV line and tradable RECs), it ought to have a contingency plan. In its supplement, SDG&E must include careful analysis of its situation if a program for tradable RECs does not exist, and/or if a new 500 kV transmission line is not operational by 2010. SDG&E should also include a transmission plan that addresses a range of issues related to transmission, including planning for a new transmission line, a timeline for permitting proceedings for a new transmission line, the impact of delay in building a new transmission line, delivery outside SDG&E's service territory, bids having curtailability as an attribute, remarketing, and other relevant steps to address transmission constraints.

D. Next Steps

To complete the long-term RPS planning from 2004 that we referred to this proceeding in D.04-12-048, the utilities must file and serve supplements to their long-term plans within 60 days of the date of this decision. The supplements for all utilities must analyze contingencies that might impede the planned procurement activities and/or delay attainment of the goal of 20% of electricity from renewable sources by 2010. Plans for dealing with those contingencies must also be set out, including an initial quantification of a margin of safety in procurement. PG&E and SDG&E must also include more specific transmission planning. PG&E must further provide a more complete conceptual plan for pursuing repowering at Altamont Pass wind facilities.

The supplements will conclude the 2004 long-term RPS planning process, but we expect that they will also inform the 2006 planning process. We anticipate that the assigned Commissioner and assigned administrative law judge will set a schedule for 2006 RPS draft procurement plans and requests for offers that will require submission in this proceeding late in 2005 or early in 2006. The 2006 long-term planning cycle in D.04-04-003 or a successor proceeding will begin early in 2006. In both forums, information and analysis developed in the supplements will be useful.

We now direct the utilities, as contemplated by § 399.14(a), to continue their long-term RPS planning by including robust RPS segments in their long-term procurement plans, to be filed in R.04-04-003 or its successor proceedings. As we noted in D.05-07-039, annual RPS plans and RFOs for solicitations will continue to be addressed in this proceeding or its successor proceedings.