2. Forecasts, Resources, and Need Determination
2.1. General Approach to Need Determination
The need determination made in this section for each IOU is based on a service area assessment because the IOUs are responsible to plan for new capacity additions within the IOUs' distribution service territories.16 Load forecasts, resource and supply assumptions, and planning reserve margins are discussed by topic in the following subsections. Each subsection provides a general discussion followed by IOU-specific results. Tables PGE-1, SCE-1, and SDGE-1, located at the end of Section 2, use each IOU's preferred or recommended plan as a base that is then adjusted to reflect the conclusions drawn in the various load and resource subsections.
After all of the inputs are addressed, we develop a need determination for each IOU in the need determination subsection. Recent experience suggests that the time required to develop and carry out competitive long-term RFOs, then finance, permit and construct new generation resources - including a cushion to account for unanticipated delays - requires that these procurement decisions be made up to seven years in advance of when the resources are needed. Otherwise, we are forced to perform "just-in-time" procurement that threatens reliability, drives up the costs of delivering power, and typically does not result in additional preferred/renewable resources. Given this up to seven-year lag from authorization to in-service date and the one-year schedule slip in this decision, the need determinations made in this decision are based on the IOUs' summer 2015 residual net short.
Finally, Section 2 concludes with a discussion of, and proposed process for making refinements to, IOU identification of system versus bundled resources.
2.2. Load Forecasts
The last LTPP decision, D.04-12-048, directed the IOUs to prepare a Medium-Load Plan Scenario in future LTPPs using the CEC's IEPR base case load-forecast scenario or an Alternative Base Case load-forecast scenario, if the utility chose to file one. In R.04-04-003, the predecessor LTPP rulemaking that resulted in D.04-12-048, the assigned Commissioner issued a ruling on March 14, 2005 (hereinafter referred to as the "IEPR Ruling") directing all parties interested in the IOUs' load forecasts for 2006 to participate in the CEC's 2005 IEPR process since the Commission did not intend to re-examine specified issues resolved during the IEPR process.17
Since the IEPR load forecast was the subject of considerable testimony by numerous parties in this proceeding, we find it useful to summarize the procedural history of the 2005 IEPR load forecast. In June 2005, the CEC issued a draft staff energy and demand forecast.18 The draft staff forecast was based on results from the CEC's end-use forecasting model and used data supplied by the IOUs and other sources. At a June 30, 2005 hearing, CEC staff and utility staff presented their respective forecasts and discussed possible reasons for discrepancies, including whether end-use or econometric forecasting techniques are better suited to long-term demand forecasts. In September 2005, the CEC adopted a final staff forecast,19 which, based on parties' comments, presented a revised baseline forecast and additional forecasts for high and low stress cases. Further, in its 2005 IEPR transmittal to the Commission, the CEC found that "end-use modeling methods are more appropriate for long-term planning purposes."20 In June 2006, pursuant to D.05-10-042, the CEC issued staff's updated 2007 peak demand forecast,21 describing several plausibility adjustments to the September 2005 revised forecast, including significant increases in the forecast for all IOUs.22
The IEPR, with revisions, established growth rates and weather multipliers that, when applied to the June 2006 revised forecast for each IOU, established base (medium or expected), high and low demand forecasts under 1-in-2 ("baseline"), 1-in-5, 1-in-10 and 1-in-20 temperature conditions over the 10-year planning period of this LTPP. To be clear, the range of projected demand in the CEC forecasts (base, high, and low) was due to different assumptions about non-weather related variables. Pursuant to D.05-10-042, and the Commission's determination that the CEC's demand forecast shall serve as the "state's official load forecast," the CEC defines 1-in-2 temperatures as the baseline weather condition. Variations due to weather conditions were captured in the temperature scenarios, and not in the composition of forecasts themselves.
The IEPR Ruling stated that, "with very narrow exceptions," 23 the 2006 LTPP proceeding would not allow reexamination of the load forecast. The IEPR ruling went on to define these exceptions as "(i) material new information that could not reasonably have been considered by the CEC during the 2005 IEPR or (ii) materially changed circumstances."24 The Scoping Memo for this proceeding required the IOUs to use the CEC's revised demand forecast for 2007-2016. Consistent with the IEPR Ruling, the Scoping Memo indicated that, if an IOU wanted to adjust the IEPR demand forecast in light of "new information," the IOU was to introduce and litigate that information in the proceeding.25
In order to provide some context to parties' comments and the discussion on load forecast, it is instructive to look back at the historical accuracy of the CEC's 10-year forecasts as a predictor of actual peak demand. Figure 1 illustrates this for the SCE planning area. SCE is selected as an example because it is the utility for which CEC has the most comparison points and because SCE's load forecast was the most heavily litigated in this proceeding. For the five forecasts of demand in the SCE planning area adopted by the CEC in its Electricity Reports from 1988 to 1996, the average annual absolute error over the forecast horizon was 4%.26 There also does not appear to be any consistent bias above or below actual peak demand in the collective CEC forecasts.
Figure 1. Forecasted versus Actual Peak Demand in the SCE Planning Area
Another point of comparison is to look at the year-ahead peak demand forecast versus actual peak. For SP-26, the planning area on which SCE's system reliability tables are based, the 2007 actual peak load was 28,230 MW.27 The CEC's June 2006 forecast update to the 2005 IEPR and the 2007 draft IEPR forecast predicted 28,400 MW28 and 28,100 MW29 peaks, respectively, which were both within one percent of the actual SP-26 peak. In contrast, the SP-26 forecast in SCE's 2006 LTPP was 28,910 MW, 30 which over-predicted the actual peak by 2.5%.
2.2.1. Summaries of Parties' Positions on General Forecasting Issues
The CEC strongly argues in its argument that the IOUs are to use the IEPR load forecast. In particular, the CEC considers SCE's approach to the load forecast to be in conflict with the expressed directives of the Scoping Memo and the IEPR Ruling. The CEC points to various and repeated Commission decisions and rulings supporting its view that "...the IEPR load forecast stands unmodified as the sole authorized basis for long-term planning in this proceeding."31 In particular, the CEC stresses that the burden of proof lies with the IOUs to substantiate whether and how new information introduced into this proceeding conforms with the aforementioned narrow exceptions defined in the IEPR Ruling.
Other parties echo or make no objection to the CEC's pointed assertion that litigation of the load forecast, with narrow exceptions, is out-of-scope in this proceeding. DRA found that the IOU's treatment of growth rates in the LTPP is consistent with the IEPR.32
WPTF and other parties ask that the Commission require the IOUs to use a single, independently established load forecast for all their procurement and RA requirements, instead of having the IOUs use two separate planning criteria. One uniform planning criteria for the IOUs would benefit investors, buyers and sellers to assess the market and make investment decisions; would allow the Commission to assess the cost-benefit tradeoffs between reliability and cost; would allow all LSEs to meet their RA obligations; and would facilitate Commission staff oversight of the IOUs procurement choices. WPTF further notes that "every single organized market uses a single load forecast..."33
CLECA observes that the Commission's policies to encourage energy efficiency exacerbate a steady erosion of load factor statewide, leading to faster growth in peak demand relative to energy demand.34
We discuss in the individual IOU subsections below the extent to which each IOU followed the Scoping Memo guidance in developing its load forecast. We clarify in this decision, and will reiterate in the OIR for the next LTPP proceeding, that the IOUs are to use the CEC's forecast in their LTPPs. The CEC's IEPR process is the proper forum to litigate and contest issues related to each IOU's demand forecast. If an IOU believes that the CEC's forecast is too "conservative" or that the CEC should use different forecasting models, data or other inputs, that IOU must bring those issues up and have them resolved in the IEPR proceeding.
The Scoping Memo recognized the importance, for long-term planning purposes, of analyzing a range of load forecasts. As such, the Commission directed the IOUs to identify a range of need stemming from the CEC's three demand forecasts (low, base, and high), as well as other planning uncertainties.35 Although the Scoping Memo did not specify which forecast and temperature condition should apply in the IOUs' approved plans, previous Commission decisions provide some direction on this issue. In D.04-12-048, we concluded that, in approving the 2004 LTPPs, "...the medium, preferred case should be followed for making planning and procurement decisions."36 The same decision found as fact the following statement:
Existing resource planning uses average weather (1-in-2) and then adds a reserve margin which, in part, provides the cushion should hotter than average weather occur. This is the approach we adopted to implement our resource adequacy requirements and should also be applied here.37
We find it prudent to review load forecast sensitivities, but for purposes of granting procurement authority, need determination should be based on the CEC's base forecast under baseline (1-in-2) temperature conditions pursuant to D.04-12-048.
We generally agree with intervenors' comments regarding the value of uniform planning criteria, such as load forecast, capacity counting protocols, and planning reserve margin (PRM). The Commission has taken just such a position, in D.04-04-033 and in this decision, with regard to standardization of the load forecast in the RA and LTPP processes.
Parties in favor of uniform planning criteria identify numerous benefits, but one in particular resonates with the Commission: the ability of the Commission to oversee prudent procurement choices. Due to the inherent complexity of electric resource planning, on the one hand, and the need for meaningful public participation, on the other hand, we believe it is in the public interest to standardize the presentation of capacity resource counting tables and to require that future LTPPs conform to a format substantially similar to the Need Determination tables provided later in this section.
We concur with many of the concerns raised by the CEC and other parties. To address these concerns and conform to our own policy directives, we base the IOU need determination tables on the CEC's base case, 1 in 2 summer temperature demand forecast (the three need tables, PGE-1, SCE-1, and SDGE-1, all use the forecasts from CEC's 2007 IEPR issued on November 21, 2007).38 Specific issues associated with the load forecast treatment in each IOU's LTPP are addressed below.
PG&E developed four scenarios to represent the potential conditions that its candidate procurement plans will be exposed to over the next 10 years. Each scenario represents a collection of events which have a particular effect or stress condition, including changes to the load forecast.
Scenario 1 exposes PG&E's portfolio to "stranded cost" conditions and assumes a low demand for electricity, using the CEC's low demand forecast for PG&E's service area.
Scenarios 2 and 3 represent "current world" conditions and assume a high demand for electricity, using the CEC's high demand forecast. Higher market availability of preferred resources distinguishes Scenario 3 from Scenario 2. Scenario 4 is characterized by high market prices and very high demand conditions. In this "high growth/high price" scenario, PG&E assumed a growth rate 0.3% higher than the CEC's high-load case growth rate in order to reflect a growth rate similar to that exhibited during the 1995-2000 era of dot-com/telecom expansion. According to PG&E, the scenarios were designed to test candidate plans under low, moderate and high stress conditions. Notably absent from PG&E's load forecast scenarios, however, is the CEC's base forecast. PG&E based its scenarios on either the CEC's low forecast, its high forecast, or some derivation thereof; but PG&E does not use the CEC's base forecast in any of its scenarios.
All four load forecast scenarios used by PG&E begin with the 2007 PG&E load forecast approved by the CEC in July 2006 for use in PG&E's 2007 RA compliance filing. In order to project load growth for the remainder of the forecast horizon (2008-2015), PG&E used the growth rates corresponding to CEC's 2005 IEPR low and high case projections.
Because PG&E has more recent information on EE and self-generation (including CSI) than was available when the 2005 IEPR was produced, the growth rates from the 2005 IEPR could not be used directly in PG&E's development of the load scenarios for the 2006 LTPP. Working with the CEC staff, PG&E first developed an adjustment to the published IEPR growth rates to net out EE and self-generation effects from the IEPR growth rates. Once this was accomplished, PG&E replaced the IEPR assumptions with respect to EE and self-generation with updated assumptions.
Parties made no comments regarding PG&E's load forecasting methodology for system peak. Numerous intervenors opined on whether PG&E's methodology accurately predicts potential CCA and DA departing load. PG&E responds that migration to or from PG&E to an alternative provider within PG&E's service area will not have an impact on the forecast since it is developed for the entire service area. In addition, PG&E claims that, since the CEC did not include large DA or CCA load changes in its 2005 IEPR, PG&E's scenarios are consistent with the CEC's forecast approach.
PG&E is aware of the concerns of many intervenors that if it does not properly predict possible DA and CCA expansion, it could "over-procure" and then departing load could be saddled with a NBC. PG&E responds to these arguments by repeating its position that its numbers are for the entire service area, and that includes DA and CCA, and even if there are significant load departures, PG&E can adjust its portfolio to address these changes.
PG&E asserts that the methodology underlying its load projections is consistent with the requirements of the Scoping Memo.39 We find otherwise. As stated in the general load forecast discussion, the Scoping Memo explicitly required the IOUs to use the CEC's revised demand forecast. Not one of PG&E's four scenario analyses used CEC's base forecast, as required by the Scoping Memo.40
As noted earlier in the general forecasting discussion, we establish PG&E's need determination using the CEC's base forecast. Table PGE-1 reflects this adjustment to PG&E's preferred plan demand forecast.
Regarding parties' concerns over PG&E's assessment of departing load, we concur with PG&E's response that its analysis of system need is not impacted by possible future load shifting due to DA and CCA, and that future DG and MDL is captured by historical trends used to develop the forecast.
SCE evaluated each of its two candidate plans using two different load forecast scenarios, a CEC-based load forecast and its own recommended load forecast, which provides a higher peak demand growth rate than the CEC forecast.
SCE explains that its recommended forecast differs from the CEC's because the CEC uses an end-use forecasting model, while SCE uses an econometric model. SCE makes three main arguments supporting the validity of its forecast. First, SCE contends that its data is more consistent with the demographic and economic data in its distribution service territory that shows that peak demand is growing faster than energy.41 SCE's preferred forecast has peak demand growing at 3.1% annually, compared to the CEC's 1.6% peak growth rate. In particular, SCE states that CEC's data is inconsistent with SCE's analysis showing that "[r]esidential customers are building larger homes in the hotter inland areas, resulting in greater air conditioning usage and faster growth in peak demand."42 Second, SCE defends its forecast as being more accurate than the CEC's with regard to future projections of declining load factor based on an analysis of historical trending data. And third, SCE claims that its load forecast is more current than the CEC's, since SCE included data through the summer of 2006, whereas the CEC forecast was published in September 2005. SCE acknowledges that the CEC updated its peak demand forecast beyond 2005, but SCE still believes its own forecast is more accurate.
Not all intervenors agreed with SCE's methodology or with its projected load growth. In particular, the CEC objects to SCE's manipulation of the CEC's IEPR numbers and SCE's attempt to "re-litigate" issues contested and addressed by the CEC in its 2005 IEPR proceeding. SCE presents its own load forecast as its recommended case instead of utilizing the CEC's IEPR forecast, and the CEC believes this causes SCE to over-inflate its need. CEC observes that, in the years 2010 and 2016, SCE's forecasted system need is, respectively, 1,364 MW and 2,007 MW greater than the IEPR forecast. According to the CEC, "these are very large forecast differences and not minor adjustments."43
SCE states it is not seeking to "re-litigate" the CEC's IEPR forecast in this proceeding. Rather, SCE proposes to evaluate its plan under an alternative load forecast, based on "new information" introduced and litigated in the proceeding, as permitted by the Scoping Memo.44 SCE contends that, in compliance with the Scoping Memo, it evaluate both of its candidate plans under the CEC forecast. But, SCE believes that the Commission should approve its plan under the alternative SCE forecast, because it allegedly introduced sufficient evidence of new information.
Citing the IEPR Ruling, the CEC insists that SCE has not met its burden of proving "material new information" and states that the information SCE introduced into this proceeding is "neither `new' nor `material'."45 The CEC maintains that SCE is attempting to rehash arguments that were presented and rejected in the 2005 IEPR proceeding. According to CEC, in the 2005 IEPR proceeding, it specifically addressed and denied, the assertion that SCE's forecast reflects higher peak demand growth and greater declines in load factor than the CEC's own forecast. Therefore, the Commission should not accept this as "new" information. In response to SCE's claim that its forecast uses more current data than the CEC forecast, CEC points out that their analysis, which uses data from over 44 years, could "at most only be negligibly impacted by the addition of a single recent data point."46 Consequently, the Commission should not be convinced that this constitutes "material" information.
Finally, CEC and CMA underscore the testimony of SCE's own witness, Art Canning, whose stated opinion that econometric techniques are superior to end-use techniques for long-range load forecasting was offered as the sole, unsubstantiated source of new information in this proceeding.47 The CEC asks that the Commission direct SCE to use the CEC's forecast as they should have for their 2006 LTPP.
In addition to preparing its own forecast, SCE modified the CEC's forecast to account for uncommitted EE that in SCE's opinion should not be represented in the forecast. As a result, SCE's "CEC" forecast, for the years 2010 and 2016, is 489 MW and 1,408 MW lower than the CEC's unmodified forecast. According to CEC witness, Ms. Sylvia Bender, "SCE incorrectly subtracts all post-2008 DSM from the Energy Commission forecast, when some of these effects are already in the forecast..."48 Bender went on to explain that since the CEC uses an end-use modeling technique, "a large portion of the impacts attributed by SCE to utility programs...are already occurring in the [CEC] models as naturally occurring efficiency, market effects, or as the effects of building and appliance standards."49 SCE responds that to put the CEC forecast on the same comparative basis as the SCE forecast, uncommitted EE must be deducted from the forecast.50
Pursuant to the IEPR Ruling, the test we apply here is whether SCE introduced "materially new information" into this proceeding that could not have been provided in the 2005 IEPR process. We concur with CEC's and CMA's position that SCE failed to demonstrate that its LTPP forecast was based on new and material information that was not available in the IEPR proceeding. Therefore, its recommended use of an alternative load forecast is unjustified.
SCE also had no basis for modifying CEC's forecast, as SCE appears to have done so to compare the CEC's end-use model results with SCE's econometric model. The IEPR proceeding already concluded that the end-use forecast would be the approved methodology for long-term forecasting; tinkering with the CEC forecast to fit SCE's econometric approach is unwarranted. Consequently, SCE's need determination should be based on neither SCE's forecast nor SCE's representation of the CEC's IEPR forecast; rather, need determination shall be based on the 2007 IEPR base forecast, and Table SCE-1 reflects this forecasting adjustment to the need determination in SCE's recommended plan.
Regarding parties' concerns over SCE's assessment of departing load, we concur with the position that system need is not impacted by possible future load shifting due to DA and CCA, and that future DG and MDL is captured by historical trends used to develop the forecast.
SDG&E derived its energy and peak demand forecasts for its LTPP from the CEC's June 2006 updated service area demand forecast. In addition to this base case, SDG&E developed both a high and low forecast reflecting possible changes in its bundled customer need. From SDG&E's perspective, the CEC's baseline forecast is conservatively low, so the utility used as its low case a forecast it argues is more moderate than the CEC's base case and uses a high case forecast that is twice its low case.
SDG&E applied the implied growth rates from the 2006 IEPR base case forecasts to the CEC's updated 2007 system demand levels to project loads through 2016.51 In consultation with the CEC, SDG&E made an adjustment to the IEPR forecast, adding back self-served load and uncommitted EE for the years 2009-2016. For the SDG&E service area, the modified CEC forecast projects customer growth at 1.2%, with load growth at 1.5% over the next 10 years. According to the CEC, SDG&E's assumptions for self-served load and energy efficiency are equivalent to the IEPR forecast.
SDG&E's high and low forecast cases reflect potential changes in its customer demand from movement to/from DA and CCA. SDG&E assumes a 1-2% load growth from 2007-2010 for its high forecast, followed by a .25-.50% growth adder for the rest of the planning period. SDG&E's low need case is half of the high case and assumes load loss from direct access over a five-year period, and a load loss from movement to a CCA in the next three years.
In its initial testimony, DRA objected to SDG&E's upward adjustment to the IEPR forecast, which DRA believed, resulted in netting out of EE from SDG&E's plan in the years 2009-2016.52 Later, in its opening brief, DRA retracted its objection, after it consulted with SDG&E, reviewed actual growth data, and was persuaded that the adjustment was practical and consistent with the intent of the 2005 IEPR forecast.53 In rebuttal testimony, SDG&E witness, Robert Anderson, illustrated that the unadjusted CEC forecast indicated a 0.4% peak demand growth rate for the years 2009-2016 - "an implausibly low forecast." 54 The adjusted forecast raises the growth rate to 1.5%, which is still low compared to the 3% growth rate observed during the historical period, 1990-2006. According to DRA, the CEC is in agreement with SDG&E's treatment of load growth. Energy Division confirmed with CEC that SDG&E made a legitimate adjustment to the load forecast.
As noted earlier in the general forecasting discussion, we establish SDG&E's need determination using the CEC's 2007 IEPR base forecast. Table SDGE-1 reflects this adjustment to SDG&E's preferred plan demand forecast.
Based on the record in this proceeding, SDG&E's handling of the load forecast appears consistent with the intent of the CEC's 2005 IEPR. We note, however, that any manipulation of the CEC's approved forecast can raise legitimate questions from concerned parties. To the greatest extent possible, such adjustments should be avoided in future LTPP proceedings, in order to maintain the integrity and credibility of load forecast calculations across all jurisdictional utilities. Pursuant to the IEPR Ruling, we encourage the CEC and the utilities to resolve such inconsistencies in the IEPR process, and not the LTPP proceeding.
Regarding departing load, we note that system need is not impacted by possible future load shifting due to DA and CCA, and that future DG and MDL is captured by historical trends used to develop the forecast.
2.3. Resource Assumptions
The CEC forecasting methodology distinguishes between committed EE (which consists of EE resulting from approved and funded three-year forward Commission programs and is incorporated into the load forecast) and uncommitted EE (which consists of projected EE savings beyond and/or outside of the projected savings from committed EE programs and is treated as a resource). An issue that complicates this distinction considerably is that the CEC embeds into its forecast beyond the three-year program cycle some EE savings from existing programs (especially from Building Codes and Standards) that the IOUs count as uncommitted EE resources.
DRA's analysis of each IOU's treatment of EE relative to the CEC's demand forecast reveals inconsistencies in how the Commission's assigned EE goals were applied. DRA recommends that the CEC and the utilities should come to a clear understanding of what proportion of the Commission's EE goals are embedded in the forecast and apply that forecast consistently in the LTPPs.
TURN states that the Commission ordered the utilities to reflect their EE goals in their LTPPs "so that ratepayers do not procure redundant supply-side resources over the short- or long-term." TURN fully concurs with this goal.
Similar to our position on the load forecasting debate, the Commission does not intend to relitigate EE treatment in the CEC load forecast in this proceeding. We concur with DRA's recommendation that the CEC and the IOUs need to come to a consensus on what proportion of the Commission's EE goals are embedded in the CEC load forecast, and with TURN's position that the IOUs accurately reflect their EE goals in their LTPPs.
We also agree with CEC's recommendation that the portion of IOU's EE goals not included in the forecast (i.e., the uncommitted EE that does not overlap with EE-induced reductions embedded in the CEC forecast in the years beyond the Commission EE programs' three-year program cycle) should be treated as a resource in the LTPPs.
It is important to clarify the definition of "uncommitted" in the context of the LTPPs. The terms, "committed" and "uncommitted," have specific meanings in the CEC demand forecast, however, in this Decision our use of the terms differs slightly and therefore requires clarification. According to the CEC, "committed programs are defined as programs that have already been implemented or for which funding has been approved."55 In the CEC's use of the term, committed EE includes (but is not limited to) savings from the 2006-2008 EE program cycle, and is treated as a load forecast reduction embedded in the forecasting methodology. According to the CEC, "uncommitted effects are the incremental impacts of the level of future programs...impacts of new programs, and impacts from expansions of current programs."56 The CEC's methodology calculates EE savings by looking at the unique characteristics (e.g., useful life) of each EE measure (e.g., lighting). If future portfolios contain a different mix of measures or new measures, those incremental savings would not be reflected in the CEC's demand forecast. Therefore, in the CEC's forecast "committed" EE projects EE savings from IOU programs through 2016, based, in part, on an assessment of the savings from the specific measures contained in the IOUs' 2006-2008 EE and earlier program portfolios. These EE measures are treated as a load forecast reduction embedded in the forecasting methodology.
In this Decision, we define "committed EE" as only those savings attributed to the IOUs' 2006-2008 and earlier EE programs, that meet or exceed Commission-adopted EE goals. We define "uncommitted" EE as the projected savings attributable to future EE program cycles (2009-2011 and beyond) that meet or exceed the Commission-adopted EE goals.57 Due to the mechanics in the CEC's demand forecasting methodology discussed above, uncommitted EE (in this Commission's use of the term) is reflected in one of two places in the 2006 LTPPs: either: (1) embedded as a reduction in the load forecast (to the extent that uncommitted EE does overlap with the CEC's concept of committed effects); or (2) forecasted as an available resource (to the extent that uncommitted EE does not overlap with the CEC's concept of committed effects. The question that we must address here is the degree of "overlap" between our post-2008 EE goals and the amount of savings from EE programs that are embedded in the CEC's demand forecast. A 100% overlap in uncommitted EE savings means that 100% of our EE goals are embedded in the CEC demand forecast.
In the PD, we applied a 60% overlap factor developed by the CEC for PG&E to both PG&E and SCE's uncommitted EE goals,58 and we applied a 100% overlap factor to SDG&E's goals. We applied a different factor to SDG&E because we recently ruled that we would revisit SDG&E's EE goals in recognition of the fact that SDG&E's goals as a percentage of economic EE potential are higher than PG&E's or SCE's goals. (D.07-10-032, p. 77.)
Based on parties' comments, review of the CEC's updated forecast and in consultation with CEC staff, we have reviewed the uncommitted EE overlap factor used in the PD. The 60% overlap factor developed for PG&E was based on quantifications from an earlier forecast period that reflected a different mix of EE measures (i.e., 2004-2005 and earlier EE program cycles) than those represented in current programs (i.e., 2006-2008 EE program cycle). Because the EE savings embedded in the CEC forecast are program specific, the previous forecast did not accurately reflect the overlap in uncommitted EE savings associated with the 2006-2008 programs.
For example, the current mix of programs heavily emphasizes commercial lighting, which is already represented in the CEC's model as recently passed standards are applied to buildings being replaced or retrofitted. But those same lighting standards were not in effect for much of the time period which the CEC used to calculate the 60% overlap factor, and the program mix during that period placed less emphasis on lighting.
In its "California Energy Demand 2008-2018 Staff Revised Forecast (November 16, 2007), the CEC undertook additional analysis of this issue, developing quantifications explicitly for the 2006-2008 portfolios. Tables in Appendix A of the document provide quantifications of the direct program impacts (i.e., the portion of uncommitted EE goals not embedded in the forecast based on past and existing measures). Using the same methodology employed by the CEC to develop the 60% overlap, with the updated data included in the Staff Revised Forecast, results in overlap factors for PG&E and SCE of 85% and 95%, respectively.
However, two factors may significantly impact the CEC analysis. First, we are confident that measures adopted in the 2009-2011 and 2012-2014 EE program cycles will result in lower overlap factors. In D.07-10-032, we required the IOUs to focus on programs that produce measures with longer-term savings, increase savings from existing measures, and emphasize programs to achieve market transformation for EE measures in their 2009-2011 EE portfolios. All of these directives are likely to result in major changes in the IOUs' portfolio composition, and thus, impact the CEC's demand forecasts in the future. Second, it is unclear how the CEC has incorporated cumulative EE savings into its forecast. In D.07-10-032, we reiterated our definition of cumulative savings:
. . . in any given year, the IOUs are responsible for implementing additional energy efficiency measures that deliver savings in that year equal to the Total Annual Electricity Savings goal established for that year. In addition, the utilities remain responsible for ensuring the total savings available in a given year are equal to the cumulative savings goal for that year. If measures implemented in an earlier year to achieve that earlier year's annual electricity savings goal are no longer in service (e.g., reached their full expected useful life), then in order to achieve their Total Cumulative Savings goal the IOUs will have to undertake additional actions to maintain the target efficiency resource. (Page 77.)
It is important to recognize two additional issues associated with this uncommitted EE overlap estimate. First, neither this analysis nor any other demand estimate affects the IOUs' EE goals themselves. The overlap estimate is an accounting exercise that attributes, based on the CEC's model architecture, the portion of uncommitted EE goals embedded in the CEC's forecast and the portion that are not - the CEC model does not set or adjust our EE goals. The IOU EE goals are adopted in the EE proceeding, and the analysis of what the level of goals should be and whether or to what extent the goals are achieved is based on the measurement and verification programs also developed within the EE proceeding.
Second, there is a clear recognition among the IOUs, the CEC, this Commission, and a number of intervenors, that these issues must be better understood, and a robust methodology is needed to quantify the portion of future EE program measures that are embedded in the CEC forecast and the portion that should be treated as a resource. In the CEC's 2007 Integrated Energy Policy Report (IEPR), the CEC has committed to "[c]onduct[ing] a public process including the CPUC, utilities and other stakeholders to determine an effective method to better delineate the energy efficiency savings assumptions in the Energy Commission's staff forecasts."59 It is anticipated that this issue will be the subject of significant evaluation in both the CEC IEPR update for 2008 and in the 2008 Long Term Procurement Proceeding at this Commission.
Based on the CEC's analyses and our direction to the IOUs in D.07-10-032, there is evidence that suggests that the overlap factors may be in the range of 60% to 95%. Until a methodology is developed to more accurately estimate future EE savings in the CEC forecast, we will apply an 80% overlap factor to PG&E and SCE. This is a reasonable adjustment to properly balance between reliability concerns that could result from underestimating the overlap factor and over-procurement that could result from overestimating the overlap factor. Consistent with the CEC's assessment and the concerns identified in D.07-10-032 regarding SDG&E's EE goals, we will retain the 100% overlap factor used in the PD for SDG&E. We recognize that further adjustments to the IOUs procurement need may be warranted based on the outcome of the completed analysis.
The CEC notes that in its revised testimony, PG&E proposed that the Commission's EE targets be used in establishing the range of need for its 2006 LTPP. The CEC notes that PG&E predicates achievement of the efficiency goals on changes to Commission policies for post-2008 programs. The CEC recommends that until such time as the Commission formally revises the established targets for energy efficiency, the Commission should limit the procurement of non-designated capacity by PG&E to amounts consistent with the levels of uncommitted energy efficiency set forth in D.04-09-060.
DRA states that in its supplemental filing, PG&E lists several energy efficiency policy issues that it urges the Commission to act upon in order for it to be able to meet its energy savings goals. DRA recommends that PG&E refer any issues it believes need Commission attention, such as those in its LTPP February 2, 2007 supplemental filing, to the Energy Efficiency proceeding. In that venue all interested parties can participate on the record.
NRDC notes that PG&E's Supplemental Testimony (February 2, 2007) indicates that PG&E has updated the EE section of its procurement plan such that EE savings in all planning scenarios now meet the existing goals, extending through 2013, set forth by the Commission in D.04-09-060. NRDC believes this update is reasonable, as it would be premature to adopt in the utilities' LTPPs any energy savings goals other than those that are Commission-approved, until the Commission adopts any changes to its energy savings targets in the energy efficiency proceeding.
Adopting the CEC forecast builds PG&E's committed EE goals and the embedded portion of PG&E's uncommitted EE goals into the need determination. In its preferred plan, PG&E applies a CEC-recommended 60% "overlap factor" to adjust the amount of uncommitted EE available as a resource (i.e., it treats approximately 40% of the total uncommitted EE projections as uncommitted EE resources).60 In this decision, we apply an 80% overlap factor for the reasons described above. Line 16 of Table PGE-1 reflects these adjusted uncommitted EE resource values, including a 10% line loss adder. This approach is consistent with PG&E's intention to include all of its EE goals in its LTPP, and it reflects the recommendations of CEC, DRA, TURN, and NRDC.
According to the CEC, SCE recommends the use of "...levels of energy efficiency that are reliably achievable based on the most credible, up-to-date information and analysis available." The Transmittal Report clearly states that "SCE's long-term planning and procurement should be based on the targets established at the CPUC that consider statutory directives." The Transmittal Report goes on to say that "While some of the concerns raised by SCE [in their 2004 LTTP] may be valid, these concerns should be addressed through monitoring and evaluating approved programs and through future energy efficiency proceedings at the Commission that establish funding for programs for 2009 and later years and adjust energy efficiency targets as appropriate."
The CEC states that SCE's use of levels of uncommitted energy efficiency for 2009 - 2016 that are below those set as targets by the Commission in D.04-09-060 in their Best Estimate Plan result in capacity shortfalls ranging from 72 MW - 77 MW in 2009 (depending on whether the Energy Commission or SCE load forecast is used) to 667 MW - 705 MW in 2016.
The CEC recommends that the Commission should direct SCE to incorporate the efficiency goals from D.04-09-060 into any resource plan that they intend to pursue. Any proposed changes to these efficiency procurement targets should be addressed in the appropriate efficiency proceedings at the Commission, and at such time that new targets are established, the procurement limits for non-designated capacity should be adjusted accordingly. SCE should not be allowed to re-litigate efficiency targets based on the State's statutory directives in this procurement proceeding.
According to DRA, the Commission should not allow SCE to use its own EE potential study as the basis for altering goals established in Commission decision D.04-09-060. If SCE has concerns about its energy efficiency savings targets, it should appropriately address them within the parameters of the energy efficiency proceeding.
NRDC states that SCE's Best Estimate Plan includes EE savings based on its own forecast of "maximum reliably-achievable and cost-effective potential," which is significantly lower than the Commission's current energy saving targets. SCE states that its forecast of the "maximum reliably-achievable potential" is based on an SCE-specific version of a recent statewide potential study. However, NRDC notes that statewide potential study estimates that the maximum achievable cost-effective energy and demand savings for the three California IOUs over the next decade is 23,974 GWh and 4,887 MW, respectively, which is slightly higher than the 10-year saving targets adopted by the Commission in D.04-09-060 for all three utilities (23,183 GWh and 4,885 MW). Since this most recent potential study does not appear to show any reductions in the cost-effective achievable potential since the last time the Commission adopted energy saving targets, it appears reasonable to NRDC for SCE to plan to continue to meet the Commission's targets.
NRDC also notes that SCE has used assumptions in developing its efficiency forecast that result in an underestimation of the cost-effective achievable savings. First, SCE states that it uses avoided costs that exclude the environmental adders, an assumption that effectively reduces the amount of cost-effective savings and is contrary to Commission policy. Second, SCE assumes a 10-year average life, which is shorter than the 12-year average life that the efficiency programs have demonstrated historically; this assumption also reduces the amount of cost-effective savings. Third, SCE estimates a "total resource cost" (TRC) cost-benefit ratio of 2.38 for the 2006-08 program cycle, but estimates a TRC ratio of less than 1.35 (a 43% reduction) for every year thereafter, without providing explanation. It is unreasonable to assume that the cost-benefit ratio will drop so dramatically following the current program cycle. And finally, even with these assumptions, SCE shows an average lifecycle cost of the efficiency programs for 2009-2016 of 3.3¢/kWh, which is significantly less than its forecast of the expected market marginal price of approximately 5¢/kWh (which, in turn, would be less than the full avoided cost), implying that more cost-effective savings would remain untapped.
NRDC concludes that SCE has not provided sufficient evidence that its Best Estimate Plan is superior to the Required Plan, or sufficient justification for not planning to achieve its EE goals. The Commission should require SCE to plan to achieve the current targets unless and until the Commission makes a different determination in R.06-04-010.
We concur with NRDC's evaluation of EE potential and its conclusion that SCE has not provided sufficient justification for not planning to achieve its EE goals. Consequently, by adopting the CEC forecast we build SCE's committed EE goals and the embedded portion of its uncommitted EE goals into the need determination.
In addition, we find that SCE incorrectly embeds all of its EE goals into its load forecasts, and as a result of this approach we have no SCE-specific information on the level of overlap between CEC's forecast beyond the committed program years and SCE's uncommitted EE goals. In this decision, we apply an 80% overlap factor for the reasons described above. Consequently, Line 12 of Table SCE-1 reflects these adjusted uncommitted EE resource values (and an 8% line loss adder). This approach reflects the recommendations of CEC, DRA, TURN, and NRDC.
The CEC states that for program years 2004 and 2005, SDG&E met and exceeded the goals established by the Commission for both energy savings and peak savings. SDG&E's 2006-2008 portfolio exceeds the Commission targets, but SDG&E's procurement filing "only reflects the Commission targets adopted in D.04-09-060 because final measured and certified results may be less than the portfolio targets."
The CEC also notes that SDG&E indicates that the Commission's EE goals are very aggressive and may not be attainable from a technical standpoint or at cost-effective levels for the long term. The original goals decision knowingly set SDG&E's goals at 118% of the maximum achievable potential. The decision recognized the need for a fresh look at the underlying 2004-2005 baseline assumptions that created the disparity when the savings potential estimates are updated in the future.
The Transmittal Report acknowledges agreement that the post-2009 goals are "somewhat unrealistic and will be revisited and revised in the next Commission proceeding when new cost-effectiveness and performance information is available." SDG&E expects that "when the Commission updates its energy savings goals for the next program cycle 2009-2011, it will adopt more realistic goals that will be consistent with future energy efficiency study estimates for SDG&E's service territory."
UCAN notes that improvements to SDG&E's distribution system can result in significant energy efficiency savings not included in SDG&E's LTPP, based on the findings of an Energy Policy Initiatives Center (EPIC) study of "Smart Grid" technologies that UCAN and SDG&E jointly commissioned (the 193-page study was provided as an attachment). Despite the fact that SDG&E was a co-funder of the study, and despite the fact that it was completed by the fall of 2006, it is not mentioned nor is its recommendations incorporated into SDG&E's LTPP. Also excluded from the LTPP is the fact that SDG&E's distribution grid upgrade is likely to occur during the LTPP time frame. Pursuant to a settlement entered into in early 2007, the Commission is likely to allow SDG&E to move forward with a full deployment of its Smart Grid upgrades that would be completed by
2011 - five years before the end of the LTPP.
UCAN states that one very tangible and real example of Smart Grid upgrades is the home area network (HAN) that is to be fully deployed throughout San Diego County by SDG&E by 2011. UCAN also states that SDG&E states "the Commission's goals in the area of energy efficiency...are very aggressive," but offers no support for this self-fulfilling assessment. UCAN disagrees, due to anticipated advances over the 10-year planning period in Light-emitting diode (LED) and distribution grid technologies.
SDG&E adds its uncommitted EE goals to the CEC forecast, then subtracts them back out as a resource, which is essentially equivalent to embedding them fully into the forecast. While this approach is not consistent with the CEC's methodology, the CEC has acknowledged that based on its forecast for SDG&E and the aggressive goals adopted in the EE proceeding for SDG&E, this is an appropriate treatment of SDG&E's EE goals. Consequently, we adopted SDG&E's treatment of its load forecast and Table SDGE-1 does not include a separate line that treats uncommitted EE as a resource.
We also expect that if, per UCAN's suggestion, additional EE opportunities arise in excess of existing program levels as a result of SDG&E's Smart Grid upgrades, SDG&E will reflect these improvements in future EE goals in the EE proceeding (and those goals will in turn be incorporated into future LTPPs, either as embedded in the adopted CEC forecast or as an uncommitted EE resource).
DR gives customers the ability to reduce or adjust their electricity usage in a given time period or shift that usage to another time period in response to a price signal, a financial incentive, or an emergency signal.61 The Commission distinguishes two forms of DR: reliability-triggered and price-responsive. Reliability-triggered programs are typically used on short notice, when grid conditions may warrant an immediate load reduction "in which customers agree to reduce their load to some contractually-determined level in exchange for an incentive, often a commodity price discount."62 Customers participating in reliability-triggered programs agree to quickly curtail their energy use when asked in exchange for a reduction of rates or, possibly, an increase in rates should they be unwilling or unable to reduce their load when asked.
Price-responsive programs are those that respond when market prices reflect a financial benefit to customers to reduce energy consumption "in which customers choose how much load reduction they can provide based on either the electricity price or a kW or kWh load reduction incentive." 63 Customers participating in price-responsive programs have the ability to curtail their energy use when market prices indicate increased demand in the system.
Demand response is second in the EAP II loading order, after energy efficiency. In EAP II, state agencies are called to "Integrate demand response into retail sellers' electricity resource procurement efforts so that these programs are considered equally with supply options."64 In D.03-06-032, the Commission established DR goals for the IOUs at "5% of the annual system peak demand"65 and the goal is met with "programs and tariffs that are triggered by price and not by emergency conditions."66 The IOU LTPPs provide explanation of their DR programs of both types and how they fit into their DR goals and strategies.
In compliance with the Scoping Memo, PG&E detailed both its price-responsive and reliability-triggered DR programs in its LTPP. PG&E advocates counting both types of DR programs to meet Commission goals. By counting just price-responsive programs, PG&E could achieve the targets in all scenarios under the Increased Reliability and Preferred Resources Plan. They would be considerably less successful meeting the Commission goals under the Basic Procurement Plan or the Increased Reliability Plan.67
Aglet believes that PG&E's DR assumptions are unrealistic.68 Aglet testified that PG&E assumes existing programs will not change for 10 years and that its proposed enhancements will not increase from 2010-2016. The historical growth of demand response programs is not fully reflected in PG&E's demand response assumptions. Aglet recommends that for planning purposes a 10% annual growth rate in DR be assumed. Without additional information on what additional DR programs can be added or how existing programs can be improved, PG&E finds Aglet's recommendation without merit and not within the scope of the LTPP proceeding.69
DRA recommends that PG&E adjust its recommended plan to reflect the position that all Commission-approved programs are cost-effective as well as to use "Best Estimates" of MW reductions for all DR programs in the near-term and for reliability DR programs for 2009-2016. It should also ramp-up price-responsive DR to the full 5% goal during the first summer after the "full deployment" year of Advanced Metering Infrastructure (AMI) in 2011. DRA finds these assumptions are reasonable for planning purposes given the numerous initiatives underway to increase the availability of DR.70
DRA believes that until DR cost-effectiveness tests and measurement protocols are developed pursuant to R.07-01-041, PG&E is not in a position to determine which DR programs are cost effective. For the purposes of LTPP, DRA believes PG&E should assume all Commission-approved programs are cost-effective.
WPTF testified that PG&E's DR forecasts are inflated based on PG&E's LTPP plan noting unresolved issues in some DR programs. WPTF cautions the Commission not to endorse PG&E's DR projections without careful analysis and review.71 PG&E claims that its updated LTPP identifies all DR programs the Commission has either approved (AMI) or expressed interest in (AC recycling) and its DR projections are reasonable.72
The SCE LTPP presents two plan scenarios that both meet Commission targets. Its Required Plan meets the goals through price responsive programs only. SCE cautions that though customers are enrolling in the price responsive programs many are not actually responding to events. In its Best Estimate plan, SCE meets the Commission targets by also using reliability driven DR that it considers most reliable and realistically achievable levels of DR. SCE asks the Commission to approve their Best Estimate Plan.
The CEC states that SCE implements the loading order as specified in the goals decision in the Required Plan, but not in its Best Estimate Plan.73 SCE states that it "first included the maximum amount of cost effective energy efficiency, demand response and distributed generation that is expected to be developed in the future."74 SCE further states that its candidate plans "include all regulatory-preferred resources first and then identify remaining capacity and energy need. The remaining need is met on a least-cost basis using peaking, intermediate, and base load resource types."75 SCE contends that its Best Estimate Plan is "based on procurement goals that are both achievable and cost-effective."76
The CEC states that SCE argues that the 5% DR goal would be exceeded "if all types of demand response resources were taken into account" and argues that the Commission policy of counting only "price-responsive" DR toward the goal "ignores the important role served by other types of demand response programs."77 SCE asserts that despite their "aggressive outreach and education campaign" and the "success" they have achieved by enrolling 350 MW of price-responsive DR resources that only 50 MW of actual load reductions from these customers has actually been observed.78
The CEC states that SCE is not consistent with the Energy Commission's Transmittal Report because the level of DR reported in SCE's Best Estimate Plan "is the level that is reliably and realistically achievable for resource planning purposes." This is inconsistent with the Transmittal Report, which specifically provides that "SCE's long-term planning and procurement should be based on the targets established at the Commission that consider statutory directives."79
The CEC recommends that until a revision takes place and new goals are established, the Commission should direct SCE to incorporate the goals from D.03-06-032 and D.05-01-056 into any resource plan that they intend to pursue. Any proposed changes to these demand response targets should be addressed in the appropriate proceedings at the Commission. SCE should not be allowed to re-litigate demand response targets based on the State's statutory directives in this procurement proceeding.80
DRA recommends that SCE adjust its recommended plan to reflect the position that all Commission-approved programs are cost-effective as well as to use "Best Estimates" of MW reductions for all DR programs in the near-term and for reliability DR programs for 2009-2016. It should also ramp-up price-responsive DR to the full 5% goal during the first summer after the "full deployment" year of AMI in 2013. DRA asserts that these assumptions are reasonable for planning purposes given the numerous initiatives underway to increase the availability of DR.81
DRA believes that The Best Estimate plan does not reflect the Commission's 5% goal for price-responsive programs even over the long term. The plan shows SCE reaching only 75% of the Commission's 5% goal in 2016. SCE's Required Plan, on the other hand, reflects the Commission's 5% goal for price-responsive programs throughout 2007-2016. DRA believes neither the Best Estimate plan nor the Required Plan include realistic DR reductions that can be achieved throughout 2007-2016.
SDG&E's LTPP includes the approved 2007-2008 DR targets plus 2009-2016 targets of 5% of peak.82
Aglet recommends that SDG&E's DR should use a 10% growth rate over the 10-year planning period, having over 900 MW of DR by 2016.83 SDG&E claims that based on that recommendation, it would have to call on DR for up to 250 - 300 hours per year, which is beyond the dispatch limit envisioned in current DR programs.84 SDG&E also claims that Aglet incorrectly states that SDG&E's DR results have grown from 75 MW in 2005 to 218 MW in 2007. SDG&E explains that Aglet's claim is based on targets from SDG&E's expected peak DR enrollment and not actual peak reduction.
The CEC states that SDG&E addresses the issue of demand response in its LTPP filing by using three different planning scenarios, all "derived from the Energy Commission's June 2006 updated demand forecast," for capacity resources in their LTPP: a "preferred resource" scenario, and "high" and "low" cases. Each is reported to use the "adopted targets for DR." The plan states that the DR goals are "very aggressive" and cautions that "SDG&E has not determined" whether the goals can be met cost-effectively. However, the report also notes that "holding room for these goals" in the long-term procurement plans "means that resource commitments today do not foreclose opportunities in these policy areas in the future" and suggests that the two-year planning review process "provides ample room for adjustment." Consistent with this perspective, SDG&E reports actual projected enrollment of DR resources in 2007 and 2008 while including the DR targets for years 2009-2016 in all three scenarios of their capacity resource accounting tables.85
CEC recommends that the Commission direct SDG&E to provide additional testimony describing the process SDG&E used to forecast the DR goals for each scenario for 2009-2016 and to either account for the shortfalls or amend the capacity resource tables. CEC testified that SDG&E should also be directed to amend its LTPP to reflect any changes in DR impact measurement and DR goals that result from R.07-01-041.86
SDG&E clarifies that it uses the Commission definition of "system peak" for DR as that from bundled and direct access customers. SDG&E understands that CEC used what is often referred to as "area peak" which adds to system self-served load and uncommitted energy efficiency. SDG&E claims that it is the CEC that is using an "adjusted peak."87
DRA recommends that SDG&E adjust its recommended plan to reflect the position that all Commission-approved programs are cost-effective as well as to use "Best Estimates" of MW reductions for all DR programs in the near-term and for reliability DR programs for 2009-2016. It should also ramp-up price-responsive DR to the full 5% goal during the first summer after the "full deployment" year of AMI in 2011. These assumptions are reasonable for planning purposes given the numerous initiatives underway to increase the availability of DR.88
DRA states that SDG&E presents a "Preferred Plan" with a "base" need scenario and also with a "high" need and a "low" need scenario. None of the three scenarios include a "Best Estimate" scenario that reflects realistic DR reductions that can be achieved in the mid-term based on the actual DR reductions achieved during summer 2006. SDG&E simply assumes that as early as 2009 it will procure and meet its 5% goal. DRA thinks this is unrealistic given that SDG&E does not expect to reach even 50% of its 5% goal in 2008 and it does not expect to fully deploy its AMI until 2011, at the earliest. DRA believes SDG&E could expand its price-responsive programs only gradually corresponding to its AMI deployment and reach the 5% goal by 2011.
While agreeable to DRA's recommendation to ramp up its 2009-2010 DR targets to get to 5% by 2011 while its AMI program is being installed, SDG&E clarifies that DR targets for 2008 and on will be set in R.07-01-041.
In their attempts to meet Commission goals, the IOU LTPPs provide demand response forecasts and expectations based on enrollment and percentage of the enrollment that is expected to actually participate. Considering the present state of the IOU's DR portfolios and the limited IOU experience with the effects of AMI, we believe the IOUs projections are an acceptable estimate of firm DR reductions for the purposes of planning for new supply-side resources. We emphasize here that the IOUs should continue to aggressively increase their DR portfolios to meet the 5% system peak demand goal until that goal is otherwise modified in R.07-01-041 or any subsequent DR proceeding.
The CEC, DRA, Aglet, and WPTF recommend changes to the projection, implementation, and counting of the IOU's DR resources. These issues are best addressed in R.07-01-041, and we will not adjust or revisit DR program goals or enrollment estimates in this proceeding.
The State of California has adopted aggressive policies focused on increasing the state's reliance on renewable resources for its energy needs. As stated in EAP II, adopted by the Commission and the CEC: "California can reduce its greenhouse gas emissions, moderate its increasing dependence on natural gas, and mitigate the associated risks of electricity price volatility by aggressively developing renewable energy resources to meet the Renewables Portfolio Standard (RPS) requirements." In addition, the development of renewable energy will likely be a key component in achieving GHG reduction goals as defined in AB 32. The standards and guidelines of the RPS program were outlined in detail in R.06-05-027, the Rulemaking to Implement the California RPS Program, and as such, many of the issues raised by IOUs and Intervenors alike are best addressed by that or subsequent RPS proceedings. However, several areas of the RPS proceeding have a direct overlap with this LTPP proceeding and will thus be analyzed in detail below. Furthermore, this decision attempts to provide clarification and guidance on uncertainties in the RPS program that were raised by both IOUs and Intervenors in the testimony.
In the Scoping Memo of this proceeding, IOUs were directed to provide detailed information on their individual renewable energy procurement strategies for the planning period, including information on existing and planned renewable projects. Furthermore, IOUs were directed to discuss their compliance with RPS program targets and to discuss renewable integration costs, as necessary. Finally, IOUs were directed to show how they could get to a 33% renewables target by 2020, as discussed in EAP II. This final mandate is examined in the 33% Renewables Target section of this decision.
D.04-12-048, FOFs #53 and #54, provided the IOUs with direction for their renewable procurement strategies:
53. In general, IOUs must procure the maximum feasible amount of renewable energy in the general solicitations authorized by this decision, and will be allowed to credit this procurement towards their Renewables Portfolio Standards (RPS) targets. If an IOU succeeds in procuring sufficient renewable resources to meet its RPS Annual Procurement Target (APT) via an all-source RFO, it will not be required to undertake an RPS-specific solicitation.
54. ...The IOUs must provide detailed annual analysis of renewable resource potential over the next 10 years in their 2006 LTPPs and must include transmission planning for renewable resources in their 2006 LTPPs. Transmission issues will be further addressed in I.00-11-001, in coordination with the RPS docket.
GPI states that all three IOUs expect to achieve 20% renewables by 2011 or 2012; however, GPI is concerned that the IOUs assume that 100% of their signed RPS contracts for projects under development will be fulfilled. GPI disagrees with this assumption and prefers the CEC's suggestion of a 70% contract fulfillment rate. For this reason, GPI feels that none of the three IOUs are on a trajectory to achieve the 20% goal by 2010. GPI disagrees with PG&E and SCE's arguments that California is experiencing a shortage of renewables, agreeing instead with the CEC that California has a bountiful endowment of renewable resources. GPI notes that, to the extent that there are impediments to the development of new renewable generating facilities in California, it is not in the area of inadequate physical renewable resources or inadequate technologies to harness these resources. GPI feels that the real problem might be an unrealistic view of what "reasonably priced renewables" means.89
IEP states that the IOUs, particularly PG&E and SCE, assume unreasonably high percentages of recontracts with qualifying facilities and other renewable contracts due to expire during the planning period. IEP suggests that a re-contracting rate of zero would allow the IOUs to most accurately calculate their expected need and adequately solicit offers.90
UCAN recommends the development of energy parks, referred to as "site banking" to harvest the sun and other renewable energy sources.
PG&E states that it strongly supports renewable resources and renewable energy's preference in the State Loading Order. PG&E intends to aggressively pursue renewable energy procurement throughout the planning horizon of the 2006 LTPP to meet and exceed the renewable targets set by SB 107 and Commission decisions.91 PG&E also intends to develop new programs, including the Emerging Renewable Resource Program (ERRP) in order to further facilitate the development of available renewable energy resources.92 PG&E states that it filed its 2006 RPS compliance report on August 1, 2006, showing RPS-eligible deliveries of approximately 8,800 GWh in 2006.93 PG&E plans to pursue RPS targets through annual RPS solicitations and bilateral agreements.
PG&E states that it solicited renewable ownership offers for the first time as part of its 2005 RPS plan; however, no ownership offers were competitive with the power purchase offers received. In 2006, PG&E expanded its 2006 RPS solicitation to include offers for sites on which the utility could develop eligible renewable ownership options, and PG&E planned to employ, for the evaluation of any such offers, the protocol used to evaluate offers for utility ownership.94
PG&E believes that the development of new renewable technologies and resource areas is essential to a healthy renewables market in the post-2010 time frame and is actively pursuing a number of emerging technologies. Furthermore, PG&E seeks to build upon its efforts with emerging technology by proposing the ERRP.95 In order to support development of existing renewable resources, PG&E plans to expand transmission and engage in active market development and resource validation. PG&E's resource mix for planned renewable resources includes wind, geothermal, solar, biomass, emerging technologies, repowering, British Columbia renewables96 and identification of other available renewable resources in California.97
PG&E forecasts that 50% of all renewable energy added between 2007 and 2016 will be from wind. However, as a "safety-valve" pending more knowledge of the operating effects and integration costs of intermittent renewables, PG&E established a planning and modeling limit that no more than 10% of the bundled energy load should be made up of incremental intermittent wind energy. That level was never achieved in the plan by 2016. PG&E states that CEC and NRDC have misunderstood the purpose and effect of this 10% limit. The theoretical limit did not include projects currently delivering, under contract but not delivering, or wind that has been firmed and shaped before delivery. Had these resources been included, the threshold limit would have been more than 13% of bundled energy load.98
GPI strongly disagrees with PG&E's statement that PG&E will be unable to reach the statutorily mandated 20% renewables by 2010 but will achieve 20% by 2011 or 2012. GPI states that, by its calculations, PG&E will achieve only 15.2% renewables in 2010, thus making it highly unlikely that PG&E will achieve 20% by 2012.
The CEC argues that PG&E's plan does not meet the 20% renewables goal by 2010; rather, PG&E anticipates achieving approximately 18% to 19% renewable deliveries in 2010 and 20% in 2011 or 2012, depending upon the scenario. The CEC claims that PG&E should be required to develop a conforming plan showing what steps they could take to meet the 20% by 2010 goal. The CEC recommends at least a 30% margin of safety to account for contract failure. The CEC states that PG&E should be directed to not limit intermittent renewables to 10% of its bundled sales.
DRA proposes that the Commission require PG&E in its "preferred plan" to separate, by resource, the costs of increased reliability from the costs of increased use of preferred resources. DRA notes that the combined costs do not indicate the incremental cost of using additional renewable resources.
NRDC posits that PG&E gives no rationale for the 10% cap on intermittent renewables that it proposes in its LTPP. NRDC states that studies of several electricity systems have shown that wind energy penetration levels of up to 20% can be readily accommodated at minimal cost. NRDC thus suggests that PG&E amend its plan.
SCE estimates that 16.5% of its 2006 retail load was served by eligible renewable resources. SCE's strategy for meeting the 20% RPS by 2010 includes using existing ERRs currently under contract, projects for which SCE executed contracts in its 2003 and 2005 solicitations and projects with which SCE will execute contracts in its 2006 RPS solicitation.99,100 For planning purposes, SCE assumed that all contracts executed in the 2003 and 2005 solicitations will result in meter-spin commencing consistent with current projections of transmission capacity becoming available.101 This assumption relies on the timely addition of transmission capacity to permit deliveries under contracts executed by SCE with ERRs in these three solicitations. SCE assumed a re-contracting rate of 90% through 2013 with existing resources currently under contract with SCE. In 2014 through the end of the planning period, SCE dropped that re-contracting rate to 60%.
SCE notes that GPI has offered no basis for its argument (discussed below) for discounting the likelihood that signed contracts will come online, and further notes that SCE plans for a variety of contingencies, including transmission considerations, contract delay, and unexercised options. SCE did assume that most of the executed projects will come online, but not at the maximum potential of the contract in cases in which project expansions are an option. SCE states that this issue has also been addressed in R.06-05-027, the Rulemaking to Implement the California RPS Program.
SCE contends that existing law requires the Commission to develop a market price referent (MPR). To the extent that the contract price of renewable generation exceeds the MPR, it is to be funded with Supplemental Energy Payments (SEPs), which are supported by the public goods charge (PGC). If the SEP funds are exhausted, the obligation to procure renewable energy priced above the MPR is relieved. Thus, the overall cost of RPS contracting could act as a constraint on procurement.102 Upon exhaustion of SEP funds, it is up to the Legislature to either increase the amount of SEP funding or abandon above-market RPS procurement activities.103 The planning scenarios presented by SCE assume a sufficient level of SEP funding to cover the above-market costs of any renewable contracts entered into during the planning period; however, the truth of this assumption is not verifiable, as the actual future price of contracted RPS energy will determine how quickly the SEP fund is exhausted.104
GPI maintains that SCE had the largest initial base renewable portfolio of the three IOUs; however, due to load growth, SCE has seen a decrease in the percentage of its load served by renewables. GPI argues that SCE predicts assured achievement of the 20% standard by 2011 yet provides little detail as to how it will move beyond its current portfolio of operating renewable generators and PPAs with renewable projects under development. GPI notes that, like PG&E, SCE assumes a 100% success rate for all projects under development; using an assumed success rate of 70%, SCE would see its renewable percentage shrink steadily. GPI comments that SCE relies heavily on the success of the Tehachapi project, which puts the company at substantial risk of delay in achieving RPS compliance due to potential transmission project delays.
SCE contends that its LTPP meets the 20% renewables goal by 2010 in the two scenarios analyzed in its Required Plan and Best Estimate Plan, with one exception; however, the CEC states that both SCE's testimony and the CEC's 2006 IEPR cast doubt on whether physical deliveries will actually be sufficient by 2010. The CEC argues that the Commission should not approve SCE's Best Estimate Plan and that SCE should be required to amend its Required Plan to better reflect the cost-effectiveness of renewable resources.
NRDC claims that SCE assumes that the cost of renewable resources is 25% above the Commission's MPR. NRDC notes that, at the time of NRDC's filing, only two of the contracts signed under the RPS exceeded the MPR. While SCE offers several reasons for this increase in cost, NRDC claims that SCE does not consider countervailing factors, such as economies of scale, that tend to lower cost.
SDG&E's position is that it continues to move aggressively toward the 20% by 2010 requirement. To achieve this objective, SDG&E plans to issue competitive solicitations, pursue ownership opportunities, and, to the extent necessary, utilize flexible compliance mechanisms permitted under the RPS program.105 SDG&E's resource assumptions presented in this LTPP assume that new transmission facilities will be built as required to allow SDG&E to access out-of-area renewables by 2010 and beyond.106 SDG&E plans to meet the 20% renewables goal, in part, through RFOs issued in 2003, 2004, 2005, and 2006. In addition, SDG&E is considering ownership of certain renewables and will continue to do so. SDG&E estimates that it will need to procure incremental renewable energy in 2010 equal to approximately 3.6% of its portfolio needs; that is, SDG&E currently has 16.4% of renewable energy under contract for delivery in 2010. SDG&E may contract for energy in excess of this amount due to contract delivery uncertainties. SDG&E states that lack of transmission is a major impediment to achieving 20% by 2010 and higher percentages in future years.107
GPI finds that SDG&E has made impressive progress in procuring renewables, exceeding its annual RPS procurement target in every year of required program performance. Nevertheless, SDG&E is still a long way from achieving the 20% goal by 2010. GPI is encouraged by SDG&E's recognition of the need to over procure renewables in order to account for contract fulfillment risk. GPI notes that SDG&E, due to the inherent geographic limitations of its service territory, has a particularly strong need to develop new transmission capacity to bring renewable power into its territory from adjacent jurisdictions and/or be given the ability to use tradable RECs as a means of compliance with the RPS.
GPI, along with the CEC, raise objections to SDG&E's desire to roll renewable procurements into an all-source RFO process for renewable energy procurement beyond 20%.
SDG&E contends that its LTPP meets the 20% renewables goal by 2010 in its preferred plan. As in the case of SCE, however, both SDG&E's testimony and the CEC's 2006 IEPR Update cast doubt on whether physical deliveries will be sufficient by 2010. The CEC also argues that SDG&E's LTPP does not include an adequate margin of safety to prepare for possible contract failure.
The State of California has taken an aggressive position toward achieving energy independence and reduced GHG emissions. The development of renewable energy is an important component to achieving these goals and has further environmental, economic, and public health benefits enumerated in the Legislation establishing the RPS program. Achievement of California's ambitious renewable energy goals is thus of great importance to the Governor, the State of California, and the Commission.
In this proceeding, the three IOUs were directed to provide detailed information on their individual renewable energy procurement strategies for the planning period, including information on existing and planned renewables. Furthermore, IOUs were directed to discuss their compliance with RPS program targets - including such issues as procurement, resource mix, resource potential and rate impacts - and to discuss renewable integration costs, as necessary. The Commission finds the IOUs' LTPPs provide, with some exceptions, sufficient information to meet the minimum requirements mandated in the Scoping Memo. However, all LTPPs could have been strengthened by providing more detailed information that would more fully enable the Commission to understand how each IOU's long-term RPS strategy fits into and impacts a more integrated approach to procurement. Although not directly mandated in the Scoping Memo, the plans could have more completely addressed and analyzed the possibility of contract failure and its impact on the IOUs' respective strategies. In addition, the plans would have been strengthened by providing renewables needs assessments that are informed by general and resource-specific uncertainties (general DA departure, increased competition for renewables from municipal utilities, CCAs, and neighboring states, project performance, technological change) and risks (contract failure, transmission project delays). We recognize that a more detailed filing of short-term renewable procurement plans occurs within the RPS proceeding; however, the LTPP proceeding is designed to capture the IOUs long-term renewable procurement plans. In recognition of the direction the State is taking in regards to overall IOU procurement, the IOUs did not make sufficient traditional resource need determinations based on "reasonable expectations" of renewable supply; that is to say, they did not incorporate the breadth of the EAP II goals in their projected fossil-based needs.
Recognizing the complexity associated with the development and implementation of a long-term renewables strategy, the Commission acknowledges that the IOUs' LTPPs provide useful information in several areas. SDG&E provides a complete breakdown of how much baseload and as-available energy it wants to obtain between 2006 and 2010. In addition, all three IOUs do a good job of forecasting supply from existing contracts and those undeveloped resource areas that have been studied.
The Commission recognizes that much of the uncertainty in the LTPPs comes from the need for guidance provided by established scenario analyses going forward. We further recognize that the market for renewable energy in California is extremely dynamic, and that developments in the past year - the record response to the 2007 RPS solicitations, for example - provide information that could obviously not be captured in the 2006 plans but will be very valuable in subsequent long-term plans. Therefore, the Commission finds the treatment of RPS by all three IOUs to be acceptable for the purposes of this proceeding, with some notable exceptions discussed below. We also identify below those issues raised by Intervenors and the IOUs that are best handled in the RPS proceedings, R.06-02-012 and R.06-05-027, and/or their successor proceedings.
The methodology established in the Scoping Memo for long-term renewable resource planning was not as robust as we believe is necessary for effective resource planning decisions; therefore, we direct the IOUs to work with ED staff to refine this planning methodology. We anticipate methodology that employs an integrated portfolio approach. We expect that this methodology will explore renewable procurement within a broader post-2010 paradigm, given the lead time associated with the development of those renewable resources that are procured in 2008. Designing a robust methodology process lends itself to the development of a trajectory towards achieving the 33% renewables target as well as an integrated GHG-constrained portfolio that takes into account the various resource types that will be necessary to develop in order to comply with AB 32 goals. We agree with several of the parties, however, that the 33% by 2020 goal warrants further analysis; this issue is further addressed in the section of the decision addressing the IOUs' discussion of the 33% goal.
Several intervening parties raised concerns about the IOUs' lack of adequate margins of safety in procuring renewable resources to allow for contract failures and other uncertainties. The Commission recognizes the potential value in a margin of safety and addressed this issue within the RPS proceeding (R.06-05-027), through D.06-05-039. We here uphold the finding in that decision that each IOU is ultimately responsible for taking all necessary actions to ensure that it meets its RPS targets, and that building another requirement into an already complex RPS program will add little value. The RPS proceeding gives the IOUs flexibility to procure renewables in a manner that best meets their overall procurement strategies; failure to meet their targets will result in fines as discussed in that proceeding. As D.06-05-039 states, "We expect an IOU, in any non-compliance defense, to show its plan included a reasonable margin of safety, or it took other reasonable actions, to satisfy its RPS targets."108 Therefore, the Commission denies the requests of Intervenors to mandate here a margin of safety for the procurement of renewable energy sources, while noting that each IOU states that it is already over-contracting. Any failure to comply with the 20% renewable standard by 2010 will be addressed in the RPS proceeding.
Each of the IOUs mentions transmission constraints as a major barrier to achieving renewable energy procurement targets. The Commission recognizes the need for sufficient transmission for new renewable sources; for this reason, the Scoping Memo directed the IOUs to "discuss how to integrate long-range transmission planning into the long-term procurement process for all resource categories, especially renewables." We find that none of the IOUs fully addressed long-term transmission needs for the duration of the planning period beyond those projects that are already set to come on-line, and we anticipate greater discussion of this issue in the next LTPP proceeding. The Commission, in conjunction with the CEC, the CAISO, IOUs, municipal utilities, and other stakeholders, has recently launched the California Renewable Energy Transmission Initiative (RETI),109 a statewide initiative to help identify the transmission projects needed to accommodate our clean energy goals, support future energy policy, and facilitate transmission corridor designation and transmission and generation siting and permitting. Because RETI begins with a thorough assessment of the renewable resource potential in California and neighboring regions, the output from RETI will be a critical input for the renewable procurement sections of the IOUs' future LTPPs. The Commission thus encourages the IOUs and all other interested parties to participate fully in RETI as a means of addressing both transmission and procurement shortages in the renewable energy sector.
The IOUs mention a shortage of renewable sources as another barrier to achieving renewable portfolio targets. The Commission recognizes that, in the short term, transmission shortages present a challenge to procuring renewable energy. The Commission notes, however, that the IOUs have dozens of RPS contracts in the pipeline, that the response to the IOUs' RPS solicitations has increased dramatically, that much new transmission for renewables is already under consideration at the Commission, and that more needed transmission will be identified by RETI. This shortage may therefore be relieved in the longer term, provided other project development challenges can be overcome. Beyond lack of transmission capacity, oft-cited reasons for project delay include project permitting, site control, and interconnection delays associated with the CAISO queue process. The Commission is working with the relevant state and federal entities to address these hurdles to project development; all of these issues, however, are beyond the scope of this proceeding.
The Commission acknowledges several parties' comments about the MPR and the difficulty of properly assessing the value and costs of RPS procurement. The MPR methodology will be revisited in R.06-02-012 in 2008, and we direct parties to raise any issues and suggest improvement in that proceeding. We agree that assessing the cost of California's RPS is one of the biggest challenges facing the program. Given the rise in bid prices that we have observed from solicitation to solicitation, we find it advisable to include, in developing a work plan for 33% by 2020, a portfolio-wide assessment of the costs of such a plan. The Commission also recognizes that utility-owned generation from renewable energy sources can potentially put a downward pressure on increasing renewable prices, and therefore encourages the three IOUs to continue their examination of utility-owned renewable generation (UOG). The Commission generally discourages UOG unless UOG helps to meet a policy objective; however, given the rapid increase in bid prices among already existing renewables, the Commission finds this to be the case in renewable energy procurement. Also, the Commission acknowledges SDG&E's comment that RECs may be necessary to achieve RPS targets; however, this issue is being addressed in the RPS docket, R.06-02-012.
The Commission recognizes that the cap on intermittent generation capacity proposed by PG&E is an inherently complex issue involving both capacity requirements and system reliability. The Commission acknowledges that wind generation capacity and integration costs are currently under study at the CAISO and elsewhere - the Commission declines, therefore, to make a determination on this issue within this proceeding. The Commission will address this issue in other proceedings as more information becomes available.
The Commission rejects PG&E's request to change the qualifying capacity to 3% of installed capacity for wind, noting that the Commission has, in D.05-10-042, Section 7.7 and D.07-06-029, Section 9.2, adopted qualifying capacity counting rules for wind based on unit-specific historical data. Changes to the RA qualifying capacity counting conventions are not within the scope of this proceeding.
In regards to SDG&E's request to roll RPS procurement beyond 20% into an all-source RFO, this issue is best considered in RPS proceedings that will carry RPS beyond the 20% goal. We note that the consistency of the timing and parameters of the RPS solicitations are helpful at this stage in the development of the market for renewable energy in California. Renewable developers are free now to bid into all-source RFOs if they so choose and in fact, we encourage them to do so; several have already done so. In the interim, we provide guidance on the inclusion of RPS procurement in all-source RFOs in Section 3.3.2.3.
Finally, the Commission acknowledges that UCAN's suggestion to create an Energy Parks program is an interesting idea worth consideration. It is best considered, however, within Phase I of RETI, as the Commission does not have the jurisdiction to order such a program. RETI includes a robust stakeholder process, and we encourage UCAN to participate fully.
There are a number of definitions of DG. D.03-04-030 defines customer generation as a resource that wholly or in part serves its on-site load, or wholly or in part serves its on-site load and serves over-the fence load as permitted by statute. Customer generation DG is addressed in this section. DG that produces significantly more power than it needs and exports (or is intended to export) the surplus to the grid is addressed in the following section on QFs and CHP.
With respect to customer generation DG, all three IOUs state that they are committed to implementing the state's preferred resource loading order, and particularly the California Solar Initiative (CSI).
In its LTPP, PG&E used historical growth rates to forecast future DG installations, which PG&E testified was consistent with the CEC's approach. Many intervenors challenged PG&E's numbers as being too conservative, but the utility responded that its DG numbers do not include DG designed to export power to the grid (addressed separately in the QF/CHP subsection).
SCE defines DG as `[g]eneration of 5 MW or less sited at or near the point of consumption and designed primarily to serve on-site load."110 This includes solar development spurred on by CSI. SCE assumes that distributed/self generation will increase by an average of 25 MW per year from 2005 - 2016.
SDG&E used the CEC's forecast for DG and added the impacts of CSI as an incremental load reduction to that number. SDG&E's DG assumption numbers were also challenged as too low and potentially leading to "over-procurement of non-DG resources."111 SDG&E stands by its CEC embedded DG forecast, but argues that if the DG numbers increase, it has time to adjust for these changes in its procurement plan.
CCC argues that the utilities take too narrow of a view of DG, and ignore larger CHP projects which can be a significant indigenous resource for new, clean, efficient generation sited in or near the state's load centers.
We find that the IOUs followed the OIR and Scoping Memo directives and included forecasts for DG in their LTPPs. CSI goals were embedded in demand reduction forecasts pursuant to CEC forecasting methodology. The following section on QFs and CHP addresses issues pertinent to DG resources with excess power to sell to the grid.
Qualifying facilities (QFs) are producers of energy and capacity as defined by the Public Utilities Regulatory Policy Act of 1978 (PURPA).112 PURPA was passed to encourage resource competition and the development of cogeneration and renewable energy technologies by non-utility power producers, called QFs. PURPA encouraged such development by requiring the electric utilities to purchase electric power from the QFs, at a rate that may not exceed "the incremental cost to the electric utility of alternative electric energy."113
For over 20 years, QFs were functioning under various pricing systems and contracts, many of which have expired since 2000. Many parties raised concerns regarding whether the QFs were being paid too much or not paid enough to stay in the energy business, and the corollary issue of where IOUs would get the alternative power if the QFs went out of business.
In 2004, the Commission opened two Rulemakings, R.04-04-003 and R.04-04-025 to address the QF issues. R.04-04-003 was the 2004 LTPP proceeding, and one important procurement topic was the development of a long-term policy for handling QFs with expiring contracts. R.04-04-025 was initiated to develop avoided costs in a consistent and coordinated manner across Commission proceedings. Both proceedings were joined for evidentiary hearings and briefings.
SCE assumes it will recontract with parties representing 90% of the energy from existing QFs in its service territory as their contracts expire and that the operating characteristics of the facilities will remain the same. PG&E made a similar assumption: it would recontract with 90% of their current QF providers. Both SCE and PG&E assumed that existing QFs in their service territories would continue to provide power to some LSE, whether it was an IOU or not, so it was reasonable for both SCE and PG&E to assume that level of QF capacity and power going forward. In its system reliability evaluation, SDG&E assumes that existing QF resources in its service territory will be available.
CCC argues that since CHP results in the efficient use of natural gas to meet the combined electrical and thermal needs of California industries and institutions, optimizing use of CHP should be a top priority for the state. CCC also believes that with supportive state policies more than 7,000 MW of CHP capacity could be developed. CCC also states that there needs to be more support for existing CHP projects to repower or expand.
CCDG claims that the IOUs underestimate the amount of CHP DG likely to be installed over the next decade, which may lead the IOUs to over procure other resources. CCDG is also concerned with the possibility that its customers, or IOU ratepayers, or a combination of both will end up paying the cost of excess power.
CAC/EPUC urges the Commission to take steps that would preserve existing and promote new CHP development. In particular, CAC/EPUC recommends that the Commission direct the IOUs to (1) recognize CHP as a loading order preference, (2) reserve a specific amount of space in their portfolios for CHP resources, and (3) have an option to interface with the CAISO for CHP resources.
The Commission had not issued a decision in the QF proceedings at the time the IOUs filed their LTPPs in December 2006, and we find their treatment of QF resources for system reliability purposes to be reasonable given the information available to the IOUs at the time of their filing. We note that on September 20, 2007, the Commission issued D.07-09-040,114 which adopts policies and pricing mechanisms for the IOUs' purchase of energy and capacity from the QFs. The Commission indicated that "we do not want to see erosion of the utilities' QF supplies, therefore we expect that as old QF contracts expire, new or renewed QF contracts will replace them."115 The availability of new QFs is predicted in the 2005 IEPR that states that "CHP has significant market potential, as high as 5,400 MW, despite high natural gas prices."116 Thus, we require the IOUs to at least maintain their current QF capacity over the next decade. The IOUs current QF capacities are recorded as 2,166 MW for PG&E; 4,162 MW for SCE; and 270 MW for SDG&E117 and shall be preserved through re-contracting with existing QFs and contracting with new QFs. These changes are consistent with the pricing and policy mechanisms for the IOUs' purchase of energy and capacity from QFs that the Commission adopted in D.07-09-040. We anticipate that any changes in QF development and/or re-contracting policy the IOUs experience and anticipate will be addressed in their subsequent LTPP filings.
2.4. Existing Plant Retirements
Predicting when aging plants will retire presents a significant challenge to capacity planning. Most of the state's fleet of aging plants are owned by unregulated entities, and the factors that inform an owner's decision to retire the plant are not within the knowledge or control of the IOUs or the Commission. Estimates of future retirements in an IOU's service territory are based on public announcements, general knowledge about the plants and their economics, and the IOU's predicted contracting plans. However, these plants can also contract with non-IOU LSEs, so this is not necessarily sufficient information to predict retirements. Ultimately, the IOUs can only guess when a plant in its service territory might retire.
The CEC provides assumptions about aging power plants in its IEPR and Transmittal Report and in testimony provided in this proceeding. The CEC recommends the orderly retirement of approximately 50 aging plants totaling 14,000 MW of capacity in the three IOUs' service territories between 2008 and 2012. From the CEC's perspective, keeping aging power plants on "life-support" by giving them short-term contracts has the negative effect of deterring the construction of new, more efficient plants. In addition, while these old plants "limp" along, the LSEs do not have to replace that power with preferred resources, such as energy efficiency, demand response or renewable resources.
The other side of the retirement coin is that these units are generally retained for capacity rather than energy needs, and are often only called during peak periods (and consequently run only a very small percentage of the time). In this role, these aging units are much more cost-effective compared with developing new peaking resources (though the aging plants are not usually as operationally flexible).
PG&E adopts the CEC's aging plant analysis in its recommended Plan and assumes that approximately 4,400 MW of aging generation in its service territory will retire by 2012.
Of the 8,100 MW of aging generation CEC identifies for retirement by 2012 in SCE's service territory, SCE estimates in its recommended plan that 2,850 MW of existing capacity in SP 26 might retire during the 10-year planning horizon. SCE based its retirement predictions on public statements and its knowledge of particular generators with which it has contracts.118
The CEC identifies two potential retirements in SDG&E's service territory: the South Bay Power Plant (South Bay) and Encina Power Plant, totaling approximately 1,600 MW. Both in its 2004 and its 2006 LTPP, SDG&E assumed that the South Bay Power Plant would retire at the end of 2009. This is consistent with the CAISO's grid planning assumption that the plant will be retired by 2010─but the CAISO assumption depends on other contingencies that will replace the electricity from the South Bay facility (the Otay Mesa Generating Plant coming on-line, some peaking-units being completed and the Sunrise Power Link transmission line being approved and built119). In addition, the Port of Chula Vista, the owner of the land on which the South Bay plant is built,120 has publicly stated that it hopes to be able to retire the plant at the end of 2009.121 However, none of these facts is a guarantee as to when the plant will actually close, and numerous parties criticized SDG&E for this assumption. SDG&E states that it makes no assumptions about the Encina plant retiring, but does not include any capacity purchases from Encina in its 2007 - 2016 resource estimates.
Not all parties agree with the CEC's recommended retirement deadline. Ratepayer groups argue that if the IOUs do not contract with these older units in order to encourage their retirement, direct access providers or out-of-state users will still have the option to purchase their relatively inexpensive capacity while utility ratepayers are left to pay for the new, more costly replacement plants.
TURN recommends against arbitrary retirement dates for the aging power plants, suggesting that market forces instead should dictate the pace of retirements. TURN is concerned that if an IOU is too aggressive in forecasting retirements, it may end up constructing new conventional units as a contingency for delays in the development of preferred resources. TURN sees aging plants serving to "bridge the gap" as an IOU brings preferred resources on-line.122
WPTF does not think a plant should be considered "retirement age" until its owner/operator declares an intention to retire the plant.123 Some parties were much more specific - LS Power argues forcefully that SDG&E should not assume that South Bay will retire in 2009 since the CAISO has identified the plant as being needed for reliability unless several contingencies are met, such as the Otay Mesa generating plant and the Sunrise transmission project being built.
We have no better information than the IOUs or other intervenors regarding the timing of plant retirements by private, unregulated owners. While we recognize that these aging plants will not continue to operate indefinitely, we suspect that the CEC's retirement timeline is unlikely.
We find merit in TURN's position that these units represent a natural contingency for a number of uncertainties that the IOUs, and in particular PG&E, have raised in identifying their need for additional generation. However, we also recognize the benefits of transitioning from the use of these aging units as relatively inflexible peaking resources (a number of them are over 40 years old, and many are former baseload resources) to new peaking and intermediate units with much greater flexibility that will better support the anticipated intermittent-heavy, GHG-constrained portfolios resulting from AB 32.
Encouraging the retirement or repowering of these older units also supports a variety of California's policy aims (e.g., reduction of once-through cooling units, Brownfield development per the goals set out in AB 1576, air quality goals, and reduction of GHGs). Consequently, our goal is to strike a balance between inducing retirements or repowerings through our procurement authorizations and containing the costs associated with replacing many of these facilities in a short period of time.
In light of these concerns, we have revised PG&E's unannounced retirement schedule, which was based on the CEC's fairly aggressive aging plant retirement goals, to reflect a more measured retirement pace of approximately 600 MW per year beginning in 2009 until all 4,400 MW are retired by 2015. This revision is reflected in Table PGE-1, but this does not result in any material change since procurement authority in this decision is provided through 2015.
Similarly, we have added to SCE's SP-26 retirement assumptions the laddered retirement of approximately 500 MW per year (this reduced value reflects the fact that SCE's announced or anticipated retirement estimate was significantly higher than PG&E's announced level) beginning in 2009 until 6,850 MW of the identified 8,100 MW are retired by 2016. This assumption results in a total 6,350 MW of retirements in SP-26 through 2015, and this revision is reflected in Table SCE-1.
We have not revised SDG&E's retirement assumptions.
The biennial nature of the LTPP process allows us to incorporate better information into the process relatively quickly after it is obtained. We will continue to evaluate the trends in actual retirements and repowerings relative to IOU assumptions and will revise our approach to these assumptions based on these trends in future LTPP cycles. In addition, if any protocol for developing retirement assumptions results from the recently announced PRM rulemaking, it will be incorporated into future LTPPs.
2.5. Planning Reserve Margin/Other Contingencies
D.04-01-050 required all LSEs within CA to procure sufficient capacity to meet an RA obligation equal to their 1 in 2 monthly peak load forecast plus a 15%-17% Planning Reserve Margin (PRM). D.06-06-064 adopted a local capacity requirement based on a 1 in 10 annual peak load forecast and uses CAISO recommended contingencies as the planning reserve.
Applying the PRM to the IOU's system reliability obligation is complicated. As explained in the general approach to need determination discussion at the beginning of Section 2, recent experience suggests that there is an up to seven-year lag from authorization to in-service date to avoid "just-in-time" procurement that threatens reliability, drives up the costs of delivering power, and typically does not result in additional preferred/renewable resources. This seven-year lead time in turn exacerbates uncertainties associated with the need determination (i.e., resources contracted to come online in the interim, retirement assumptions for aging resources, etc.,) and contributes to a concern among the IOUs and other parties regarding whether the 15%-17% PRM will be met if additional "contingency generation" is not procured.
The use of the PRM and other contingencies for system reliability is addressed below, followed by a discussion of the additional contingencies proposed in PG&E's LTPP to address these uncertainties.
PG&E's preferred plan recommends a 16% PRM for system reliability, but basing it on a one in ten weather forecast. SCE performs an "adverse conditions" analysis for system reliability, using a 1 in 2-year temperature demand forecast and a PRM of 5%. SDG&E makes no changes to the PRM for its service area reliability analysis.
Aglet recommends not changing PG&E's PRM, based on an analysis of a 2005 PG&E Value of Service Study conducted by Freeman Sullivan and Company. Aglet argues that the study "found that 71% of residential customers, 58% of small/medium business customers, 79% of agricultural customers, and 21% of big business customers considered at least one 1-to-4-hour outage per year to be acceptable." (Exhibit 52, p. 2-10.) Aglet performed a cost-benefit analysis of PG&E's PRM proposal and found that an increase in the PRM would not be cost-effective for PG&E's residential ratepayers. (Exhibit 52, p. 2-11.)
The CEC contends that the LTPP proceeding is not the appropriate forum in which to consider changes to the PRM. Specific to PG&E, the CEC notes that PG&E has not demonstrated that the probability of involuntary load curtailments is unacceptably high if the current PRM is maintained. In addition, the CEC states that PG&E does not present enough data to demonstrate that customers would benefit from a higher reserve margin. The CEC claims that the consequences of approving PG&E's higher reserve margin would be that PG&E would be authorized to acquire extra capacity resources that would be paid for by all LSEs. According to the CEC, this is an undue burden for other LSEs, who would not have the option of determining how to best meet the reliability needs of their customers. The CEC claims that the decision to allow PG&E to procure to a higher reserve margin would effectively allow PG&E to determine the tradeoff between cost and reliability for the customers of all LSEs in its service area.
More specifically, the CEC argues that PG&E's assessment of the insufficiency of the 15% PRM based on a 1-in-2 peak weather demand forecast to meet one-in-ten peak demand conditions is flawed. The CEC further states that PG&E claims that Table Vol. 2, IVA-1 illustrates that "[t]he current planning reserves do not provide sufficient margin to cover load increases due to one-in-ten or hotter temperatures." The CEC finds that by including minimum operating reserves equal to 7% of the peak load, PG&E is effectively assessing the PRM needed to avoid a Stage 1 alert, not to avoid involuntary load shedding. Consequently, PG&E has merely illustrated that the current reserve margin would fail to prevent a Stage 1 alert under conditions more adverse than once in ten years.
The CEC also mentions that the inclusion of 429 MW to meet regulation needs assumes that, at the moment load is at its very highest, additional capacity is needed to handle upward fluctuations in demand. The definition of "peak demand" precludes this capacity from being necessary.124
DRA contends that, "PG&E's justification for moving to a 16% PRM appears to be based upon a `perfect storm' of extreme demand and supply conditions occurring at the same time, e.g., 1-in-10 temperature demand level and high forced outages." (Exh. 82, DRA's Vol. B, p. 15.)
WPTF advocates in both this and in the RA proceedings that a single planning criterion be used for all procurement - specifically, a single load forecast, counting protocol, and reserve margin.
The Commission recognizes the need to develop a consistent and transparent standard for the three IOUs to use in determining their system reliability responsibilities. An approach that is standard across all Commission jurisdictional LSEs will (1) determine an appropriate level of procurement necessary to enable the CAISO to operate the system in compliance with minimum operating standards; (2) ensure that ratepayers all bear equal burdens of the costs associated with providing reliability; and (3) avoid, to the extent possible, the procurement of excess resources as a result of poor coordination among IOUs or between IOUs, ESPs, CCAs, and POUs. An approach that is transparent and consistent across the forward planning horizon will (1) consistently and transparently integrate all the planning processes within the Commission (transmission, generation, renewable development, demand response) for maximum efficacy and efficiency and; (2) provide all market participants with the information needed to make investment decisions in infrastructure without relying solely on ratepayer-backed contracts.
The design and implementation of a statewide capacity trading mechanism, including some form of forward capacity component, is being addressed in Phase II of the RA proceeding. This effort has highlighted the need for a comprehensive, transparent PRM methodology for all jurisdictional LSEs, and an ACR issued in R.05-12-013 and R.06-02-013125 signaling the Commission's intent to open a rulemaking to accomplish this objective. Collectively, these two forums will address the interplay between the bundled and system reliability planning reserves, including the system reliability backstop function that the IOUs are currently providing.
We plan to adopt for the LTPP program the system reliability backstop function and associated PRM methodology that results from these processes, and believe that this approach appropriately addresses the intervening parties' concerns. It would be premature at this time to adopt for a system reliability reserve margin methodology any of the variations proposed by the IOUs from the existing 15%-17% PRM currently used for bundled customer load. Consequently, the IOU need determination tables calculate need based on a 1 in 2 year weather demand forecast and a 15%-17% PRM.
In addition to the recommended change in the PRM, PG&E recommends the following contingencies be included in its need determination:
· 600 MW of contracted resource uncertainty - 10% of the approximately 6,000 MW of new resources currently in PG&E's pipeline (various future resource additions in PG&E's NP-26 need determination tables have been reduced below the contracted values to reflect this reduction);
· 500 MW in anticipated revisions to RA counting rules, especially for DR and wind resources (Line 2 in PG&E's NP-26 need determination tables reflects this anticipated decrease); and
· 500 MW of authority to procure, either (1) as additional backup for contracted resource uncertainty (if one of the large generation units procured in PG&E's last Long-Term RFO does not materialize) or (2) for RFO "optionality" if all the previous Long-Term RFO resources do materialize, but PG&E nonetheless identifies an offer that in its opinion is to good to pass up in its next Long -erm RFO.
Aglet recommends that the Commission reject PG&E's request to discount existing contracts based on questionable viability, noting that it is inconsistent with historic Commission practices. Aglet also urges that the Commission reject PG&E's request to procure an additional 500 MW of capacity, noting that it is unaware of any instance where the Commission has allowed a regulated utility to over-procure.
DRA criticizes PG&E's need estimate because of its request for an uncertainty contingency for its contracted resources.
TURN interprets PG&E's request for additional contingencies as a permanent adder to its PRM with a corresponding permanent addition in cost to ratepayers. TURN does recommend, however, that PG&E be allowed to procure a limited amount of new resources beyond those needed for the PRM, but only if these resources reduce the Net Present Value of ratepayer costs when compared with not procuring such new resources.126
Each of the contingencies PG&E identifies in its LTPP is discussed in turn below:
RA Counting Contingency - The LTPP proceeding is not the appropriate forum to address this concern.127 Parties should address any recommended changes to RA counting rules in the current RA proceeding, or any successor proceeding. Should the RA proceeding(s) result in changes in the qualifying capacities of resources, the LTPP proceeding shall incorporate those changes.
Contract Uncertainty Contingency - We agree with Aglet's position that discounting existing contracts based on questionable viability is inconsistent with historic Commission practices and we do not adopt such a contingency for PG&E in this decision.
Regarding the portion of this contract uncertainty contingency that is the result of viability concerns of contracts for renewable resources, we reaffirm the need for PG&E to reach, at a minimum, its mandated RPS goals. To the extent that PG&E has contract viability concerns with a portion of its renewable contracts, it needs to address this concern within its renewables procurement strategy (for instance, by adopting a viability adder), not turn to this proceeding and request to make up this shortfall with fossil fuel resources. We do not subscribe to the philosophy that IOUs should be able to replace renewable resources (or any preferred resource) with fossil generation, and we will not adopt a general procurement framework that will allow the IOUs to crowd out preferred resources and/or systematically overprocure. This type of procurement would only lead to "stranded assets" to the detriment of customers of all LSEs.
Regarding the portion of this contingency that is the result of conventional generation contracts, we would expect the IOUs to handle this uncertainty in a similar manner that they did with the many viability challenges that plagued the vertically integrated utility era - delaying retirements (in this case, via contract extensions with aging facilities) until these uncertainties are addressed.
Alternate System Reliability PRM - We find merit in PG&E's request to use an alternate, more conservative planning approach for system reliability. However, as we noted in the PRM subsection, a separate rulemaking has been opened to develop a comprehensive PRM methodology that will address this issue, so we will not formally adopt an outcome in this decision that could undermine the analysis and conclusions we anticipate will come out of the PRM rulemaking. While we acknowledge that in the interim we must determine need for system reliability, PG&E has not supplied sufficient analysis to support its alternate system reliability PRM, and therefore we have an incomplete record to adopt the policy PG&E proposes in this proceeding.
500 MW RFO "Optionality" or Additional Contract Contingency - Two conditions would need to be met to authorize the concept of providing additional procurement authority to IOUs to obtain an additional, attractively-priced resource in an RFO:
· An anticipated need for the additional resource within a sufficiently short period after it comes on line to justify, economically, its "early" procurement.
· Certainty that market conditions provide a good benchmark for assessing a "good deal."
PG&E has provided no analysis with which we might make the assessment that additional resources will be needed within a sufficiently short period after it comes on line to justify its early procurement. In fact, based on PG&E's own need determination tables, which factor in PG&E's other requested contingencies, there is no additional unmet need through the 10-year planning cycle (e.g., preferred loading order resources and/or new resources currently under contract fully meet additional load growth in the 2013-2015 timeframe). In addition, as discussed earlier in this decision, there is currently considerable uncertainty associated with the types of resources the IOUs will need to procure to meet future GHG requirements. Absent any scenario analysis by PG&E, we are unable to evaluate whether the "extra resource" PG&E might decide to procure based on price attractiveness in an RFO would be optimal for a future, GHG-constrained portfolio.
There is also little certainty that market conditions provide a good benchmark for assessing a good deal. On the contrary, the current pricing environment for building new generation is an extremely tight one (national scarcity of skilled utility labor, high demand for power plant engineering and design services, scarcity of metals resulting in inflated turbine prices, etc.). A reasonably likely conclusion is that a "good deal" by today's standards may not look so good to the extent that these are near-term imbalances that normalize in a few years.
Without information that substantiates that these two conditions are met, we do not provide PG&E with this discretionary authority. More generally, we find it unlikely that these conditions could be proven sufficiently to convince us it would be prudent to grant optional procurement authority.
To the extent that PG&E is requesting this 500 MW to replace one of the resources that PG&E secured in its last Long Term RFO (i.e., as a default contingency for a subset of the new generation currently under contract above and beyond the 10% default cushion described above, effectively raising the 600 MW contingency to 1,100 MW, or nearly 20% of the contracted "pipeline" resources), our position here is consistent with the discussion above - we would expect the IOUs to handle these uncertainties by delaying retirements (in this case, via contracts) until these uncertainties are addressed. However, we will address PG&E's position concerning these two contingency requests regarding the viability of its 6,000 MW of new resource contracts.
One point raised by PG&E in its litany of contingencies raises particular concern to the Commission, and bears additional discussion here. In its analysis of additional resource needs associated with an increase in the PRM to 16% based on a one in 10-year temperature demand, PG&E requests in this proceeding only 700 MW of the additional 1,100 MW need driven by this increase, indicating that it anticipates meeting the balance of this need (approximately 30%) with preferred resources.
First, since at least 800 MW of the remaining 1,600 MW of fossil fuel contingency generation PG&E is requesting replaces capacity from preferred resources (i.e., much if not all of the 500 MW of RA counting capacity reductions and over half of its 600 MW contract viability contingency), it is unclear why PG&E is not proposing to replace these resources in-kind, or at the very least why it would not apply this same 30% reduction for preferred loading order resources to all of its requested contingencies.
Of more fundamental concern, though, is the question of why PG&E believes that there would be additional preferred resources available to procure. The conventional generation procurement authority we grant in the LTPP proceeding is, essentially, a backstop authorization that results from additional identified net short after all preferred loading order resources are exhausted. PG&E's intent to procure a portion of its identified residual need with preferred loading order resources suggests to us that the IOU does not believe it has exhausted all preferred loading order resources available to it in its residual net short calculation for this planning period.
2.6. Need Determination
The Scoping Memo, and in particular Attachment A, advised the IOUs to make their need determinations based on the "net" of their demand and load assumptions and forecasts.128 In addition, decisions D.04-12-048 and D.06-07-029 designate the IOUs as the entities responsible for providing new investment in system reliability resources on behalf of all customers within their respective service territories. Consequently, need analyses are required - one for system reliability across the IOU's service territories and one for the IOU's own bundled customers. As noted at the beginning of Section II, the need determination made in this section for each IOU is based on a service area assessment.
One of the most controversial subjects in the LTPP proceeding is each IOU's need determination. Generally, stakeholders want the IOUs to procure sufficient resources to ensure reliable service, without interruptions or black-outs. However, a number of intervenors have a financial stake in the amount and types of resources the IOUs propose and the Commission authorizes. Other intervenors, including DA providers, potential CCA providers, and current or potential self-generation customers, want to ensure that the IOUs do not over-procure resources, which could result in some form of an NBC. Intervenors representing green and renewable interests scrutinize how much of the identified need will be filled with preferred versus conventional resources. Ratepayer groups are mindful of the need for preferred resources and reliability, yet are also cognizant of the cost of these attributes to the ratepayers.
As noted in the previous PRM discussion, this controversy is compounded by the fact that given the time required to hold competitive RFOs and then finance, permit and construct new generation resources, these procurement decisions must be made approximately seven years in advance of when the resources are needed.
2.6.1. Summary of Parties' General Positions on Need Determination
CMA recommends that authority be provided to allow IOUs to meet their RA requirements only, noting that procurement beyond this level will interfere with the end-state of a competitive wholesale market. MMID requests that the Commission require IOUs to use prudent planning and not procure power or system reliability resources on behalf of departing load identified in the POU forecasts provided to the CEC.
DRA is concerned with the cost-risks associated with the Commission's pre-approval of the three IOUs' procurement activities for the 10-year planning horizon, especially in the areas of construction costs, GHG requirements and meeting renewable resource targets. Basically, DRA fears that the IOUs will over-procure fossil fueled resources that will crowd out other preferred options and leave little to no room for compliance with any GHG policies.
TURN's primary interest in the IOUs' need assessment numbers is whether the IOUs procure more than necessary then burden ratepayers with stranded costs.129 TURN agrees with the IOUs that any changes in CCA or DA load will not affect the physical resource need in an IOU's service territory, but TURN is still concerned with the impact load migrations will have on future bundled customer needs and costs.
As discussed earlier in the PRM subsection, a separate rulemaking will be opened to develop a comprehensive PRM methodology that addresses, among other things, lead time needed to bring new system resources on line. Consequently, it would be premature to adopt any of the reserve margin methodologies or specific contingency approaches proposed by IOUs in their Plans at this time.
However, until a standard, consistent, and transparent system reliability reserve margin methodology has been developed we must make need determinations today that, in our assessment, will result in sufficient system resources to permit all jurisdictional LSEs to meet their PRM obligations in the seven-year new resource procurement timeframe.
To accommodate the seven-year procurement timeframe, and given the schedule slip in issuing this decision, we have identified need determinations for each IOU through 2015, rather than through 2012, as the IOUs do in their LTPPs, and IOUs are to structure their RFOs for authorized resources to coincide with the projected system need on a timeline that ensures system reliability.
A need determination is made for each IOU in the following three subsections based on: (1) the load, resource, and PRM assessments discussed previously in this section, (2) other relevant information IOUs and other parties have provided in the record in this proceeding, and (3) the principle that each of the three IOUs should provide approximately the same level of system reliability to its customers.
Also, in addition to the few instances in which the IOUs' bundled need determinations were addressed in this section, all revisions to system load and resources that apply to the bundled need analyses should be made in the compliance filing stipulated in this decision. With these adjustments, the IOUs' bundled need assessments are adopted, and the IOUs are authorized to procure existing resources (in addition to the authorized new generation) as needed to meet their bundled need.
Finally, as noted earlier in this section the need determination tables developed in this decision include retirement assumptions designed to promote procurement that will result in the retirement of some of the state's aging, inefficient generation facilities. We make abundantly clear that any procurement authority granted herein shall in no way be used by the IOUs to instead reduce or adversely impact procurement of EE, DR, renewables, or QF resources to the maximum extent feasible. ED and the PRG are directed to provide close oversight of IOU procurement activities to ensure that this unintended consequence does not materialize.
PG&E calculates its service area needs by subtracting all identified NP-26 resources from the NP-26 load forecast (including the reserve margin), then multiplying the resulting net short (or long) by 92% to remove the 8% of the control area that consists of municipal providers.
As previously noted in this section, PG&E also builds the following assumptions into its need determination:
· 700 MW of additional conventional generation associated with using a 1 in 10 weather forecast with a 16% PRM rather than a 1 in 2 weather forecast with a 15%-17% PRM (this approach results in an total need of 1,100 MW, but PG&E assumes that approximately 30% of the total need would be met with preferred resources);
· 4,400 MW of retirements (i.e., the aging plants the CEC has identified in PG&E's service area);
· 600 MW of contracted resource uncertainty - 10% of the approximately 6,000 MW of new resources currently in PG&E's pipeline (PG&E reduces various future resource additions in its NP-26 need determination tables to below the contracted values to reflect this reduction);
· 500 MW in anticipated revisions to RA counting rules, especially for DR and wind resources (Line 2 in PG&E's NP-26 need determination tables reflects this anticipated decrease); and
· 500 MW of authority to procure, either (1) as additional backup for contracted resource uncertainty (if one of the large generation units procured in PG&E's last Long-Term RFO does not materialize) or (2) for RFO "optionality" if all the previous Long-Term RFO resources do materialize, but PG&E nonetheless identifies an offer that is "to good to pass up" in its next Long-Term RFO.
Based on these adjustments, PG&E requests that the Commission approve its Recommended Plan and allow the utility to procure up to 2,300 MW in new resources for its service area, although based on a straight calculation this number would appear to be 2,500 MW [i.e., 4,200 - (4,400+600+500+700+500)].130
Most of parties' positions with PG&E's need determination are directed at its load, resource, or PRM/contingency assumptions or proposals, and are addressed in those subsections. Generally, though, DRA is concerned that the IOUs will over-procure fossil fueled resources that will crowd out other preferred options and leave little to no room for compliance with future GHG policies.
In addition, the CEC believes that PG&E overstates the export of energy and therefore commensurately overstates the amount of new capacity needed to meet its service territory's needs. Aglet believes PG&E's request represents substantial over-procurement, and recommends authorizing 662 MW of additional procurement.
Table PGE-1 provides a need determination for PG&E for the 10-year planning period using the assumptions and conclusions reached in this decision. Based on this analysis, PG&E's service area shows a need of 800 to 1,200 MW (to provide a PRM between 15% and 17%) by 2015.
We also note that if a previously authorized resource is determined unviable during the development process and the associated contract is terminated, the procurement authority for those megawatts remains. PG&E is encouraged to take any viability concerns it has with its contracted 2004 LTRFO resources into account in the design and timing of its RFO for resources authorized in this decision.
To support the types of needs we anticipate in a GHG-constrained portfolio and to replace the aging units on which some of this authorization is based, we require PG&E to procure dispatchable ramping resources that can be used to adjust for the morning and evening ramps created by the intermittent types of renewable resources. Preference should be given to procurement that will encourage the retirement of aging plants, particularly inefficient facilities with once-through cooling, by providing, at minimum, qualitative preference to bids involving repowering of these units or bids for new facilities at locations in or near the load pockets in which these units are located.131
Prior to its solicitation for these resources, we require that PG&E provide ED and the PRG with a description of the resources it is soliciting and how these resources support PG&E's transition to a GHG-constrained portfolio, an analysis we had asked the IOUs to include in their 2006 LTPPs (additional RFO process refinements are described in the Procurement Process Issues section of this decision).
SCE's LTPP provides distinctions, in various locations, between CAISO control area SP-26, SCE's bundled customers, and SDG&E's system, which is also located within SP-26. As discussed in the PRM section, SCE performs an "adverse conditions" analysis for system reliability using a 1 in 2-year temperature demand forecast and a planning reserve margin of 5%. SCE then calculates its service area share of SP-26 system reliability responsibilities as 80% to account for SDG&E's system reliability responsibilities within SP-26. Based on its LTPP need analysis, SCE did not identify a need for additional new generation through 2012 beyond the 1,500 MW authorized in D.06-07-029 to serve system needs.
SCE's analysis assumed that the second Devers-Palo Verde transmission line (DPV2) would be completed in 2009 and that about 900 MW of new firm imports would be deliverable on that path. On May 30, 2007, the Arizona Corporation Commission (the Arizona Commission) rejected SCE's application to construct DPV2. SCE estimates that the Arizona Commission's rejection of the project will delay DPV2 by at least two years and may delay the project indefinitely.
Pursuant to ALJ Brown's June 29, 2007 ruling in this proceeding, on July 12, 2007, SCE distributed an update of its SP-26 regional need outlook to remove DPV2 as a resource addition. The updated SP-26 regional need outlook removes 900 MW from imports for 2010 through 2016. Based on this update, and extending the target COD date by one year (from 2012 to 2013) due to the delay in the LTPP proceeding timeline, SCE requests authority to procure an additional 1,380 MW of new system generation resources in SCE's distribution territory by 2013 (in addition to the 1,500 MW of new generation resources authorized under D.06-07-029).
The CEC argues that because SCE uses its own load forecast as its recommended case rather than the CEC's IEPR forecast, SCE's need is inflated. In the future, the CEC asks that the Commission direct SCE to use the CEC's forecast as they should have for their 2006 LTPP (and as discussed above in the load forecast subsection, we adopt that recommendation).
Aglet recommends that the Commission deny SCE's late-filed request for authority to fill the gap resulting from the delay or elimination of the DVP2 project, reasoning that the next LTPP proceeding will provide SCE with sufficient time to adjust for this change.
CMA contends that while SCE made a filing, it was insufficient to evaluate SCE's revised needs assessment, particularly since the Commission's approval of the DPV2 project was not premised on it satisfying a reliability or capacity need, but rather that it provided access to economy energy, particularly during the winter peaking months.
NRG believes that, given the unanimous vote of the Arizona Corporation Commission, the DPV2 project will be delayed significantly longer than two years. Consequently, NRG recommends that this decision include a finding that at least an additional 1,000 MW of in-basin, load pocket, gas-fired intermediate and peaking generation to support intermittent renewable resources within SCE's current Standard Track RFO.
TURN notes that SCE's request is supported if the Commission adopts SCE's load forecast, but if the CEC's forecast is adopted then this need goes away. TURN recommends that if any new resource procurement is authorized for SCE, it should not exceed 1,000 MW given the uncertainties regarding the actual need for SP-26.
Table SCE-1 provides SCE's service area need determination based on its recommended plan, with the revisions described in the previous load and resource discussions and the additional revisions described below.
First, SCE's system need determination did not back out POUs' contributions to system load or POU resources. Consequently, SCE's approach provides backstop reliability resources for POUs in SP-26 who (1) may not procure to the same reserve requirements used by SCE, (2) SCE cannot bill with the CAM charge associated with system resources, resulting in a cost shift to SCE's bundled customers and the other system LSEs, and (3) may have resource procurement plans or load curtailment behaviors that SCE is not aware of or does not factor into its analysis (e.g., DWR's pumping station load, which represents approximately 2% of SP-26 load, is curtailed during periods of forecasted peak load), which would result in SCE over-procuring system resources. Consequently, Table SCE-1 calculates SCE's proportion of system resources based on its regional (bundled plus DA) forecast divided by the system forecast.
Second, because there is insufficient information at this time to determine if or when the DPV2 project will be developed, SCE-1 reflects a 450 MW addition for DPV2 beginning in 2012. This "splitting of the difference" will either halve the amount of procurement SCE will need to perform in a tight timeframe if DPV2 is not developed or is substantially delayed, or it will halve the amount of resources SCE brings on line earlier than needed if the project is developed by 2012. This approach represents our best judgment regarding how to address the uncertainty associated with this significant potential resource addition to SCE's portfolio.
This approach reflects this Commission's optimism that this project, which we believe is mutually beneficial to both California and Arizona, will ultimately be constructed, but that the process involved in providing Arizona with sufficient information in support of this assessment will take some time. We encourage SCE to provide as complete an update as possible on the status of this resource in its next LTPP so the Commission can revise this admittedly "half- right and half-wrong" approach to counting this resource at that time.
We find that parties' positions on whether DPV2 was intended as a reliability or economy energy resource, and therefore whether any increase in the need determination is warranted in its absence, appear to miss the point. Regardless of the initial purpose for which the project was proposed, SCE has attempted to estimate the resulting capacity value that it would provide the system on peak. Consequently, it was used in SCE's need determination tables as a resource that decreased the determined need by that amount. If SCE has overestimated this resource's ability to deliver the estimated capacity on peak, or if deployment of the resource is delayed or does not come to pass then SCE's need determination would only increase, regardless of the original rationale for developing the resource.
We recognize the concerns parties have raised regarding SCE's introduction of the DPV2 issue into the proceeding on the final day of evidentiary hearings and not subjecting the information to a full discovery process. However, we need to balance our objective of having a full vetting of information by all interested parties on as many topics that impact this proceeding as possible with our responsibility to make need determinations based on the most accurate information available to ensure system reliability. If this proceeding cannot demonstrate the flexibility to react to changes in the "facts on the ground," the IOUs are likely to provide much more conservative assumptions on the COD dates for future resources, and the accuracy of this process will be eroded, at the expense of the ratepayers.
When faced with this choice, our best judgment is to apply the methodology developed through the publicly noticed and fully vetted process, but to consider an update of the numbers that are inputs into that methodology depending on our informed opinion of their veracity. In this case, as noted above, any answer to the question of whether and how much of this resource SCE should have counted towards peak capacity would only increase the need determination. The only significant question of fact is when, if at all, this resource will become available.
Finally, Table SCE-1 also reflects 400 MW of additional generation in SDG&E's service territory authorized later in this decision (the remaining 130 MW of authorization were already included in SCE's resource estimates), since SDG&E's resources are included in SCE's system reliability evaluation.
As indicated in Table SCE-1, our need determination analysis indicates that SCE's service area shows a need of 1,200 - 1,700 MW (to provide a PRM between 15% and 17%) by 2015. We note that this need is in addition to the 305 MW of previously authorized resources remaining in SCE's Standard Track RFO.
To support the types of needs we anticipate in a GHG-constrained portfolio and to replace the aging units on which some of this authorization is based, we require SCE to procure dispatchable ramping resources that can be used to adjust for the morning and evening ramps created by the intermittent types of renewable resources. Preference should be given to procurement that will encourage the retirement of aging plants, particularly inefficient facilities with once-through cooling, by providing, at minimum, qualitative preference to bids involving repowering of these units or bids for new facilities at locations in or near the load pockets in which these units are located.132
Prior to its solicitation for these resources, we require that SCE provide ED and the PRG with a description of the resources it is soliciting and how these resources support SCE's transition to a GHG-constrained portfolio, an analysis we had asked the IOUs to include in their 2006 LTPPs (additional RFO process refinements are described in the Procurement Process Issues section of this decision).
Finally, we note that there was confusion on the part of some intervenors regarding SCE's request for authority to procure to a 17% reserve margin plus 1,950 MW (850 MW to deal with the possible outage of a major generation unit, and 1,100 MW to protect against an error in the near-term peak load forecast). We clarify here that this was not a system reliability request for new generation, but was a request for an adjustment to SCE's self-imposed forward procurement limits for its bundled load under its ratable rate methodology (i.e., contractual need). This request and SCE's proposed ratable rate methodology in general are discussed in the Risk Management portion of Section III (Procurement Process Issues) of this decision.
SDG&E provides three need analyses in its LTPP: a bundled need analysis using the 1 in 2-year temperature demand forecast and a planning reserve margin of 15%; a system need analysis using the CAISO N-1/G-1 criteria; and a bundled local capacity requirement analysis also using the CAISO N-1/G-1 criteria.
SDG&E's analyses indicate that its need determination is constrained by local capacity requirements rather than system need, and that its bundled and system needs are substantially altered with the addition of the Sunrise Powerlink.
From the CEC's perspective, SDG&E's need numbers are deficient since SDG&E did not properly consider potential plant retirements or make the proper assumptions for procurement of renewable resources. Aglet recommends that SDG&E's maximum authority be reduced to 813 MW, which reflects no additional authorization for Sunrise Powerlink uncertainty.
DRA recommends the Commission approve SDG&E's "contractual procurement need...(but) only those physical resources SDG&E would need before 2012 under its Preferred Plan." (DRA Opening Brief, 8/1/07, p. 37.) DRA recommends that the Commission defer approval of the combined cycle plant SDG&E proposes to procure in 2012 until the next LTPP when more information will be available regarding the South Bay Power Plant.
Table SDGE-1 provides SDG&E's service area need determination based on the 1 in 2 demand forecast with a 15%-17% PRM approach (we have included in Table SDGE-1 the 480 MW El Dorado baseload power plant, approved in Commission decision D.07-11-046, which has a projected on-line date of October 2011 and 130 MW of peaking units with on-line dates in 2008, approved in Commission decision D.07-09-010133). As indicated by the table, SDG&E does not have any system need in the 2015 timeframe.
However, as previously noted, SDG&E's need determination is constrained by local capacity requirements. Without the Sunrise Powerlink project, and updating SDG&E's local capacity need assessment to reflect the CEC's 2007 demand forecast, SDG&E's local capacity requirements result in a need for approximately 530 MW of new local capacity by 2015. As noted above, though, subsequent to its 2006 LTPP filing SDG&E has procured 130 MW of local peaking units.134 Backing these 130 MW of local resources out of SDG&E's need determination results in a remaining procurement need of 400 MW of local resources if the Sunrise Powerlink project is not developed (the El Dorado facility is not a local resource and is therefore not backed out of this local capacity-driven need).
Because there is insufficient information at this time to determine if or when the Sunrise Powerlink project will be available to meet local capacity needs, we authorize SDG&E to procure 530 MW of additional local capacity (which includes the 130 MW of local peakers already approved by the Commission for a residual of 400 MW remaining procurement authorization) if its application for the Sunrise Powerlink is denied. If the Sunrise project is developed, only the 130 MW of local peakers are (retroactively) authorized.
We also note that if a previously authorized resource is determined unviable during the development process and the associated contract is terminated, the procurement authority for those megawatts remains. In addition, we authorize SDG&E to procure the equivalent quantity of local capacity associated with any retirements of local area resources that occur beyond the amount of retirements it forecasts in its LTPP.
To support the types of needs we anticipate in a GHG-constrained portfolio, we require SDG&E to procure dispatchable ramping resources that can be used to adjust for the morning and evening ramps created by the intermittent types of renewable resources. Preference should be given to procurement that will encourage the retirement of aging plants, particularly inefficient facilities with once-through cooling, by providing, at minimum, qualitative preference to bids involving repowering of these units or bids for new facilities at locations in or near the load pockets in which these units are located.135
Prior to its solicitation for these resources, we require that SDG&E provide ED and the PRG with a description of the resources it is soliciting and how these resources support its transition to a GHG-constrained portfolio, an analysis we had asked the IOUs to include in their 2006 LTPPs (additional RFO process refinements are described in the Procurement Process Issues section of this decision).
The Scoping Memo prescribed the development of two need analyses for each IOU, one for the IOUs' bundled customers and one for system need. SDG&E is the only utility that provides an explicit comparison of the two need analyses in its LTPP.
SCE's LTPP includes a significant amount of discussion on system need and bundled need, but does not ultimately derive a residual net bundled customer need similar to the net system need analysis provided in Tables IV-7/IV-8 of its Plan. Also, SCE's system need analysis includes SDG&E's system information, since it is within SCE's CAISO control area, but provides little information on how it distinguishes the two utilities' systems, and no explanation of how SCE will coordinate its planning and procurement with SDG&E to ensure the two utilities do not develop duplicative system resources. PG&E's analysis distinguishes between CAISO control area NP-26 and PG&E service area need, but does not provide a separate bundled versus service area need analysis.
This issue is of particular concern because IOUs are permitted to make use of the CAM developed in D.06-07-029 for resources procured for system reliability, but the decision deferred to Phase II of the proceeding the development of CAM implementation details. So far, the utilities are not approaching this issue in a consistent manner in practice. For instance, SDG&E has not sought CAM treatment for any resources procured since D.06-07-029, nor has it indicated any intention to do so. PG&E sought CAM treatment for one of the non-UOG resources procured in its most recent Long-Term RFO. SCE, on the other hand, has identified all of its newly developed, long-term generation contracts as system resources (except for UOG, which is ineligible for CAM treatment).
The absence of a standard methodology or consistent practices for identifying system versus bundled resource needs raises several concerns. First, as noted above, it is unclear how SCE and SDG&E will coordinate the identification of system need to ensure that they do not procure duplicate system resources.
Second, without a standard methodology for differentiating system and bundled need, there is no way to ensure whether an IOU election to utilize the CAM for a new resource is appropriate. AReM raised this concern (and specifically the need to link cost allocation with cost causation) in the context of SCE's shrinking bundled customer load factor that SCE attributes to increased inland residential development. AReM states that, "Using the principle of cost causation, the customers causing the particular need for the resource should pay for it. If bundled customers' load is exacerbating the peak or decreasing the load factor (as SCE suggested), then the bundled customers should pay for the resources necessary to meet that need. In determining whether to apply the adopted cost allocation mechanism in D.06-07-029 in this phase of the proceeding, the Commission should only do so when the costs creating the need can be attributed to all customers." (3/2/07 Testimony on Behalf of AReM, p. 8.)
Another problematic example is the scenario in which ESPs have procured their proportional share of long-term resources (an outcome that various policy initiatives in this and other proceedings are attempting to facilitate), yet the IOU has not procured its appropriate share. Until a methodology is in place that accurately accounts for this, the IOU could inappropriately elect CAM treatment of new resources procured to meet this bundled need.
AReM points out in its brief that testimony from each of the IOUs clearly indicates that changes in IOU load factors resulting from bundled customer growth are currently driving much of the recent need for peaking resources:
SCE's prepared testimony indicates that residential air conditioning load is the primary cause of the extreme "peakiness" of the bundled load shape, noting "the continuing trend of new meters [i.e., customers] being set in the hotter inland areas of the SCE service are where air conditioning is used to a much larger extent (causing higher growth in peak demand)..." SCE says that it expects that the increasing residential air conditioning load will cause peak load to increase at nearly twice the rate of energy demand for at least the next five years. (AReM Reply Brief, p. 9.)
...as SDG&E's witness explained at the hearing, the peaker plants currently being developed by the utility will be needed to meet its bundled load. Accordingly, SDG&E is not requesting authorization to apply the CAM to these new resources. (AReM Reply Brief, p. 10.)
For PG&E, the evidence that direct access customers are not contributing in any material way to the need for new capacity is found in the utility's own peak load forecasts and capacity tables. For example, according to PG&E's own figures, the highest peak DA load in 2011 will occur in April (936 MW), and the next highest peak in September (903 MW). The months of July and August, which have the highest "system" peaks, show the third and second lowest DA peak loads, respectively (797 MW and 785 MW). And the DA peak load for June (833 MW), which is the other peak summer month, falls in the middle range of the DA peak loads. Since the months of highest system peak demand do not correspond with the highest DA peak loads, the need for new system reliability resources in PG&E's service area cannot be attributed to DA customers. (AReM Reply Brief, pp. 10-11.)
Third, as AReM points out, without some clear methodology for identifying system need versus bundled need, there is no way to ensure that IOUs will not elect to utilize the CAM for less attractive new resource acquisitions, while keeping "good" deals for bundled customers only.
None of the IOUs provided explicit arguments in response to AReM's recommendation that implementation of the CAM be linked to resource need causation. PG&E and SCE instead argue that AReM is attempting to relitigate the D.06-07-026 decision. However, Ordering Paragraph (OP) #5 of D.06-07-029 indicates that, "It is reasonable to defer many of the implementation details of this cost-allocation mechanism (to Phase II of this proceeding) along with associated ratemaking issues." Clearly, developing a methodology to determine whether new resources are needed to address changes in bundled or unbundled load growth represents an implementation detail, so PG&E and SCE's argument is unfounded.
AReM did not propose the components of a methodology that would identify separate bundled versus system resource needs, nor did any of the IOUs or other intervening parties. In the next LTPP procurement cycle scoping document, the IOUs and other interested intervenors will be instructed to develop proposals for methodologies for identifying bundled- versus system-driven resource needs to:
· Capture respective growth trends of bundled and unbundled components of service area load (rather than the static "snapshot" of current bundled and unbundled contributions to system peak used to develop overall need).
· Identify how load growth trends and any resources ESPs are procuring to serve their own load can be included in this analysis, given the confidential nature of these data.
· If not addressed by the capacity market design in Phase II of the RA proceeding, develop mechanisms for ESP self-provisioning to opt out of the CAM and penalties for instances in which ESP self-provisioning plans do not materialize.
· Explore how re-opening of DA would affect the proposed methodology (i.e., can a sufficiently robust methodology be developed at this time, or will the methodology need to be revised if and when DA is reopened).
Based on the record in this docket, it is clear that the election of a resource for CAM treatment when the application is submitted (i.e., after an RFO) creates the potential for IOUs, in their dual role as bundled customer electricity providers and system-reliability providers, to "cherry-pick" resources for their bundled customers, to the detriment of DA customers. Until the system versus bundled methodology is developed, we anticipate that the development of a separate CAM review group (as described in the PRG subsection of Section 3) will prevent this outcome. We direct ED to monitor the veracity of this assumption and bring any claims of unfair treatment by IOUs of CAM and non-CAM elections of selected resources to the Commission's attention.
16 D.06-07-029, at p. 26.
17 Assigned Commissioner's Ruling Detailing How the California Energy Commission 2005 Integrated Energy Policy Report Process will be used in the California Public Utilities Commission's 2006 Procurement Proceedings and Addressing Related Procedural Details, R.04-04-003, March 14, 2005.
18 California Energy Demand 2006-2016 Staff Energy Demand Forecast, CEC-400-2005-034-SD, June 2005.
19 California Energy Demand 2006-2016 Staff Energy Demand Forecast, Revised September 2005, CEC-400-2005-034-SF-ED2, September 2005.
20 Transmittal of 2005 Energy Report Range of Need and Policy Recommendations to the California Public Utilities Commission, CEC-100-2005-008-CMF, November 2005.
21 Staff Forecast of 2007 Peak Demand, CEC-400-2006-008, June 2006.
22 The CEC's June 2006 update raised PG&E's, SCE's and SDG&E's summer 2007 forecasts by 526 MW, 960 MW and 79 MW, respectively.
23 March 14, 2005 ACR, at p. 4.
24 Id., at p. 10.
25 September 9, 2005 ACR/Scoping Memo, Attachment A, at p. 13.
26 2007 Integrated Energy Policy Report, CEC-100-2007-008-CTF, at p. 30, available at http://www.energy.ca.gov/2007publications/CEC-100-2007-008/CEC-100-2007-008-CTF.PDF
27 Based on CAISO records, and factoring in a 1% peak coincidence adjustment for SDG&E.
28 Staff Forecast of 2007 Peak Demand, CEC-400-2006-008, June 2006.
29 California Energy Demand 2008-2018 Staff Draft Forecast, CEC-200-2007-015SD, July 2007.
30 SCE's Need Determination Tables.
31 Post-Hearing Closing Brief of the California Energy Commission for Phase II of the LongTerm Procurement Plan Proceeding, R.06-02-013, August 29, 2007, at 15.
32 Opening Brief of the Division of Ratepayer Advocates, August 1, 2007, at p. 9.
33 Opening Brief on Phase II Issues of the Western Power Trading Forum, August 1, 2007, at p. 11.
34 Opening Brief of the California Large Energy Consumers Association, August 1, 2007, at p. 6.
35 September 9, 2005 ACR/Scoping Memo, Attachment A, at p. 13.
36 D.04-12-048, Conclusion of Law (COL) #3. (Emphasis added.)
37 D.04-12-048, FOF #11. (Emphasis added.)
38 While we recognize that the 2007 IEPR forecast estimates were not vetted in this proceeding, many aspects of the IEPR forecasting process were. The IEPR process is a public one, involving many of the same participants that are parties to this proceeding, and the IEPR document is a public document. We find it prudent to update the forecast estimates used as inputs in this decision based on the most current public information available to us, particularly given the long time lag that has occurred since the LTPPs were developed. The California Energy Demand Forecast, 2008-2018, the underlying load forecast which the 2007 IEPR assumes, had not been officially adopted by the CEC, as of the mailing of this Proposed Decision. We note that the incorporation of the draft 2007 IEPR demand forecast into our overall needs analysis may give certain parties concern, however, we believe that the draft forecast provides a better `snapshot' of the current needs of the system.
39 PG&E's 2006 Long-Term Procurement Plan, Vol. I - Amendment, at p. IV-6.
40 September 9, 2005, ACR/Scoping Memo, Attachment A, at p. 13.
41 Southern California Edison Company's Opening Brief, August 1, 2007, p. 7, citing SCE/Canning, Ex. 37 at pp. 34-35.
42 Southern Californa Edison Company's Opening Brief, p. 6, citing Canning testimony, Ex. 37 at pp. 34-35.
43 Post-Hearing Opening Brief of the California Energy Commission, July 31, 2007.
44 Southern California Edison Company's (U-338-EE) Reply Brief, August 30, 2007, at p. 4.
45 Post-Hearing Opening Brief of the California Energy Commission, July 31, 2007, at p. iv.
46 Post-Hearing Closing Brief of the CEC for Phase II of the LTPP Proceeding, August 29, 2007, at p. 14.
47 Post-Hearing Opening Brief of the California Energy Commission, July 31, 2007, at pp. 17-19, and Opening Brief of the Competitive Market Advocates, August 1, 2007, at p. 6.
48 Prepared Direct Testimony of Sylvia Bender on Behalf of the California Energy Commission Regarding the Issue of Load Forecast in the Long-Term Procurement Plan of Southern California Edison (SCE), March 1, 2007, at p. 10.
49 Id., at p. 13.
50 Southern California Edison Company's 2006 Long-Term Procurement Plan Reply Testimony - Vol. I, at p. 37.
51 San Diego Gas & Electric's Opening Brief, August 1, 2007, p. 7.
52 Division of Ratepayer Advocates, Report on the Long-Term Procurement Plans of San Diego Gas & Electric Company, Vol. D, March 2, 2007, at pp. 12-14.
53 Opening Brief of the Division of Ratepayer Advocates, August 1, 2007, at p. 10.
54 Rebuttal Testimony of Robert B. Anderson San Diego Gas & Electric Company, April 9, 2007, at p. 2.
55 CEC. California Energy Demand 2008-2018 Staff Revised Forecast, CEC-200-2007-015-SF2, November 2007, at p. 25.
56 Id. (emphasis added)
57 Hereinafter, all references to "committed" or "uncommitted" EE savings refers to the Commission definition, unless otherwise noted.
58 We also increase the goals via a line loss multiplier which reflects the additional benefits of this demand-side resource relative to generation resources.
59 Executive Summary to 2007 Integrated Energy Policy Report, Committee Final Report, December 5, 2007, at p. 8.
60 We anticipate that this percentage of overlap will change as new EE programs are developed, and that this shift will be reflected in future LTPPs.
61 D.03-06-032, Attachment A, California Demand Response, A Vision for the Future, p. 1.
62 D.06-03-024, p. 5.
63 D.06-03-024, p. 5.
64 Energy Action Plan II, Demand Response Key Action #7, p. 5.
65 D.03-06-032, p. 9.
66 D.03-06-032, footnote, p. 8.
67 PG&E 2006 LTPP Vol. 1 amended, VI-7.
68 Aglet Initial Testimony, pp. 1-10.
69 PG&E Rebuttal Testimony, p. 4-3.
70 DRA Initial Testimony, Vol. B, pp. 20-21.
71 WPTF Initial Testimony, p. 2-7.
72 PG&E Opening Brief, p. 12.
73 CEC Initial Testimony, (Bender) EE and DR in the LTPP of SCE, p. 12.
74 SCE 2006 LTPP Vol. IB, p. 48.
75 SCE 2006 LTPP Vol. IB, p. 49.
76 SCE 2006 LTPP Vol. IB, p. 52.
77 CEC Initial Testimony, (Bender) EE and DR in the LTPP of SCE, p. 15.
78 SCE 2006 LTPP Vol. IB, p. 71.
79 CEC Initial Testimony, (Bender) EE and DR in the LTPP of SCE, p. 16.
80 CEC Initial Testimony, (Bender) EE and DR in the LTPP of SCE, pp. 16-17.
81 DRA Initial Testimony, Vol. C, pp. 19-20.
82 SDG&E 2006 LTPP Vol. 1, p. 186.
83 Aglet Initial Testimony, pp. 6-4, 6-5.
84 SDG&E Rebuttal Testimony, (Anderson) p. 4.
85 CEC Initial Testimony, (Bender) EE and DR in the LTPP of SDG&E, p. 4.
86 CEC Initial Testimony, (Bender) EE and DR in the LTPP of SDG&E, p. 11.
87 SDG&E Rebuttal Testimony, (Anderson) p. 3.
88 DRA Initial Testimony, Vol. D, p. 15.
89 GPI Initial Testimony.
90 IEP Initial Testimony.
91 PG&E Volume I at V-20.
92 Id.
93 Actual 2006 deliveries for PG&E were 9,114 GWh.
94 PG&E Volume I at V-24.
95 The May 2, 2007 R.06-02-013 ruling determined that PG&E's ERRP proposal would be more appropriately submitted as a separate application. PG&E and SDG&E subsequently filed a joint application, A.07-07-015.
96 Emerging technologies and British Columbia renewables are more long-term solutions that may help to meet a 33% renewables target rather than the 20% 2010 target.
97 PG&E Volume 1 at IV-33.
98 PG&E Reply Comments.
99 SCE Volume 1B at 76.
100 In addition, at the time of this writing, SCE has issued and closed a 2007 RPS solicitation.
101 SCE Volume 1B at 77.
102 SCE Volume 1B at 75.
103 SCE initially made reference only to the PGC; however, SEP payments were the actual funding source, which were supported by the PGC. This change was made for clarification purposes.
104 We note that SB 1036, effective January 1, 2008, abolishes the current SEP process and redistributes PCG money among the large utilities. SCE's discussion is, thus, rendered moot.
105 SDG&E Volume 1 at 189.
106 SDG&E Volume 1 at 190.
107 SDG&E Volume 1 at 192.
108 D.06-05-039 at 23.
109 http://www.energy.ca.gov/reti/index.html
110 SCE opening Brief, p. 10, citing Testimony of Horwatt, Ex. 21/22C, p. 17.
111 SDG&E Opening Brief, p. 20, citing Wong/CCDG, Exhibit 59, p. 7.
112 The United States Congress passed PURPA in 1978, as codified in the United States Codes (U.S.C.) at 16 U.S.C. Section 824a-3, and 18 Code of Federal Regulations (CFR) Sections 292.301 et seq.
113 16 U.S.C. Section 824a-3(b).
114 Applications for Rehearing have been timely filed, but D.07-09-040 remains in full force and effect unless superseded by subsequent Commission decision.
115 D.07-09-040 at p. 122.
116 2005 IEPR at p. 76.
117 D.07-09-040 at p. 123.
118 SCE Opening Brief, August 1, 2007, p. 11.
119 CPUC Proceeding A.06-08-010.
120 LS Power owns the actual South Bay Plant.
121 Union-Tribune, 3/13/07.
122 TURN Opening Brief, August 1, 2007, p. 2.
123 SDG&E Opening Brief, August 1, 2007, p. 24, citing WPTF Testimony, Ackerman, Exhibit 119, p. 1-15.
124 In addition, regulation is considered by the WECC to be a component of the minimum operating requirement.
125 ACR, issued November 19, 2007 in R.05-12-013 and R.06-02-013.
126 Ibid., p. 2.
127 ALJ Brown's 05/02/07 ruling explicitly ruled RA Requirement issues outside the scope of this proceeding, noting that "This rulemaking will serve as an umbrella proceeding to handle procurement policy issues that do not warrant a separate rulemaking..." (Pages 6-7.)
128 Scoping Memo, Attachment A, p. 13.
129 TURN Opening Brief, August 1, 2007, p. 1.
130 PG&E has indicated to ED staff that this discrepancy is due to the fact that these values are not strictly additive, but PG&E does not make clear in its Plan how they overlap.
131 ED, the PRGs, and the IEs are to work with the IOUs in the RFO bid development process described in Section 3.3 to determine the manner in which this qualitative or additional quantitative preferences for resources will be incorporated into bid evaluation criteria on an RFO-specific basis.
132 ED, the PRGs, and the IEs are to work with the IOUs in the RFO bid development process described in Section 3.3 to determine the manner in which this qualitative or additional quantitative preferences for resources will be incorporated into bid evaluation criteria on an RFO-specific basis.
133 While it would not generally be appropriate for an IOU to seek or procure new resources for system reliability need prior to evaluation of the need determination and authorization of the procurement via an LTPP proceeding, the Commission recognized unique circumstances associated with these procurement requests and approved the El Dorado and peaker applications prior to this decision on SDG&E's 2006 LTPP.
134 Per the discussion in the previous footnote, the Commission recognized unique circumstances associated with this procurement request-in this case an identified local capacity need in the 2008 timeframe-and approved SDG&E's application for these resources prior to this decision on SDG&E's 2006 LTPP.
135 ED, the PRGs, and the IEs are to work with the IOUs in the RFO bid development process described in Section 3.3 to determine the manner in which this qualitative or additional quantitative preferences for resources will be incorporated into bid evaluation criteria on an RFO-specific basis.
