3. Relevant Programs
1. Energy Efficiency Program(s), including incentives costs and front-end loaded costs;
2. Demand Response Program(s);
3. California Solar Initiative;
4. Low-Income Energy Efficiency;
5. Renewables Portfolio Standard (RPS):
i. RPS payments in excess of the Market Price Referent;
ii. Costs of non-renewable generation needed to operate when intermittent renewables are not running; these costs would include those of additional California Independent System Operator (CAISO) ramping requirements and utility quick start and quick ramping fossil generation that are required to work around wind (in particular) and solar facilities;
6. Renewables Research, Development and Deployment;
7. Low Emission Vehicle Research, Development and Deployment;
8. Solar Water Heating;
9. Self-Generation Incentive Program incentives for reduction of GHG emissions associated with electricity consumption;
10. PG&E Climate Protection Tariff;
11. University of California Climate Research Proposal; and
12. Any other program which contributes to a reduction of greenhouse gases.
3.1. Quantifying EE in the CEC Load Forecast
In D.07-12-052 and previous decisions, we directed the IOUs to use the CEC 1-in-2 base load forecast in preparing their LTPPs. The CEC forecasting methodology distinguishes between committed and uncommitted effects to account for energy efficiency in the load forecast. According to the CEC, "committed programs are defined as programs that have already been implemented or for which funding has been approved...and only the effects of committed programs are included in the demand forecast."31 These committed effects "may include some impacts associated with the historical and ongoing levels of programs to the extent they represent impacts associated with replacement of aging [or installation of new] building stock and equipment at efficiency levels that comply with current building and appliance standards."32 Uncommitted effects on the other hand, are defined as "the incremental impacts of the level of future programs (for example, savings associated with new equipment that exceeds current standards or early replacement of existing stock) impacts of new programs, and impacts from expansions of current programs."33
Due to certain mechanics in the CEC's demand forecasting methodology, uncommitted34 EE was 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). A question that this OIR must address 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.
According to the CEC, "a difficulty arises in correctly projecting uncommitted impacts versus...savings from...utility programs that are captured in forecast models. Building and appliance standards are modeled within the residential and commercial forecast models. The models account for building decay, equipment replacement, and market-induced impacts."35 Within the sector models, some utility program savings are attributed to more stringent building codes and standards or price effects, whereas others are modeled separately.36 Further complicating the issue, "as models are calibrated to historical actual data, they implicitly account for effects of many years of energy efficiency programs."
The degree of overlap between the Commission's EE goals in a given year and the amount of EE that the CEC forecasting methodology considers committed in that year is, at present, unclear. In order for the Commission to have confidence that the adoption of future long-term plans does not result in over- or under-procurement of new generation, an in-depth examination of the issues and development of an accepted methodology to accurately account for the overlap may be publicly vetted and adopted in this proceeding. In its 2007 IEPR, the CEC recommended that this issue be addressed as part of the 2008 IEPR Update:
As an early part of the 2008 IEPR Update, the Energy Commission will conduct a public process that includes CPUC staff, utilities, and other stakeholders to determine an effective method of better delineating the energy efficiency savings assumptions included in the Energy Commission staff demand forecast, both from historic as well as future standards and programs. The Energy Commission recognizes the value that such a methodology can provide in future state planning efforts related to both energy policy and greenhouse gas emissions reduction.37
3.2. Long-Term Firm Capacity Projections for Demand-side Resources
In the 2006 LTPP Scoping Memo, the Commission directed the IOUs to "include expectations of the supply of various procurement resources, including, EE, DR, renewables, distributed generation (DG) and non-renewable generation over the long-term time horizon."38 This emphasis on the long-term availability of various resource alternatives is particularly salient with respect to demand-side resources which are less predictable and dependent on voluntary customer participation. Whereas the project viability risk of supply-side resources can be mitigated by issuing replacement Request for Offers, or by over-contracting in the first place, demand-side resources are more subject to variations in consumer behavior that are often difficult to predict.
The Commission recognizes that a distinction needs to be made between (1) loading order resource goals established in resource-focused proceedings that IOUs must work to achieve, and (2) prudent resource planning assumptions that affect need determination, procurement authority, and ultimately system reliability across a six-plus-year time horizon. To the extent that prudent planning assumptions result in lower resource "counting," in terms of firm capacity, than the goals established in these underlying proceedings, such a finding does nothing to undermine the preferred resource goals themselves, or the Commission's directives to achieve them. On the contrary, this exercise would have the intended effect of demonstrating the consequences to California of not achieving the goals, namely more backstop procurement of fossil generation to replace potential shortages in demand-side resource availability.
Although it is impossible to exactly predict firm capacities from demand-side resources on a 5-10 year forward-looking basis, it is precisely this prediction that this proceeding must make in order to make reasonable need determinations. The very real consequences of that prediction are either more or less procurement authority, well in advance (5-8 years) of the need date. In general, the trade-off continuum before us is between overprocuring resources (in a conservative view of firm capacity) at risk of crowding out preferred resources that have shorter development timelines (or causing excess ratepayer costs due to excess resources), or underprocuring resources at the risk of poorer environmental performance from more aging plant generation, higher costs and poorer environmental performance from "just-in-time" procurement resources, or reliability problems.
While we emphasize that this issue deserves consideration prior to the next LTPP filing, the LTPP proceeding is just one of several possible procedural venues for addressing it. The issue could be alternatively taken up in the individual resource proceedings or the upcoming PRM rulemaking. We make no determination at this time which the forum will be, other than to identify this proceeding as an option for addressing some or all of the resource alternatives.
3.3. Customer Risk Preference Study
Customer Risk Tolerance (CRT) and TEVaR are the metrics currently required by the Commission to monitor and manage rate level risk. The TEVaR represents an estimate, at a given confidence level, of the amount of electric rate increase that could occur due to changes in market conditions such as hydro-power availability risk, electricity spot market price volatility, and gas price volatility (which represents the single greatest historical source of price volatility). For example, TEVaR 95% measures the maximum rate increase beyond the expected value with a 95% confidence level (in other words, it is the 1-in-20 worst case scenario). CRT is essentially a Commission-adopted target limit on unforeseen electric rate increases looking 12 months into the future. This has been set by the Commission at one cent per kilowatt-hour (kWh). The current policy sets a notification trigger when utilities are required to consult with the Procurement Review Group (PRG), if TEVaR reaches 125% of the CRT (that is, TEVaR 95% ≥ 1.25 ¢/kWh). The Commission requires the utilities to submit to Energy Division Staff (ED) monthly reports on TEVaR 95% on a rolling 12-month basis. These monthly submissions also report the TEVaR 95% on a quarterly basis for months 13-24 looking forward, and on an annual basis for months 25-60.
The 2006 LTPP proceeding considered and resolved several issues related to risk management, as identified in Attachment A to the September 25, 2006 Scoping Memo. In their comments, replies, oral testimony, and briefs, parties addressed all of these questions, and raised additional outstanding ones. The 2006 LTPP Scoping Memo asked parties for their opinions on the following issues:
· Whether consistency in hedging across DWR and non-DWR portfolios is desirable;
· Whether to mandate hedging "best practices;"
· Whether to modify the CRT level; and
· Regarding TEVaR, whether to:
o Standardize calculations;
o Require tracking on 12-month rolling or calendar year basis;
o Set "confidence level" at 99% or 95%; and/or;
o Use other metrics, such as TEVaR beyond one year, forward-start TEVaR, etc.
D.07-12-052 made determinations on many of these issues, including:
· Facilitating DWR and non-DWR portfolio risk management by allowing for them to better coordinate;
· Declining to establish "best practices" for hedges, or to establish preferred ratios of fixed price instruments (such as futures) to options;
· Declining to the modify the CRT level (set at 1 cent/kWh) or the trigger level which triggers PRG review (set at 1.25 cents/kWh) currently in place; and
· Regarding TEVaR:
o Declining to standardize calculations;
o Requiring a 12-month rolling TEVaR report, as opposed to a calendar year approach;
o Changing TEVaR reporting from a 99% confidence level to a 95% level; and
o Allowing use of metrics other than the 12-month TEVaR.
Outstanding issues not addressed by D.07-12-052 include:
· The study which D.02-10-062 ordered ED to administer to empirically determine electric customer risk preferences;
· A review and modification of CRT levels and TEVaR metrics based upon empirical customer preference data; and
· Aglet's argument (reply brief) that Black Model results are not being reported, contrary to D.02-12-074, Ordering Paragraph 10.
We note our previous commitment to completion of a customer risk preference study. In one scenario, ED could contract with a consultant who surveys customers across the state's various IOUs. In another scenario, each IOU could independently administer a survey, either with in-house expertise or with assistance from a consultant, all under the guidance of its respective PRG. An advantage of having one consultant perform the survey would be a uniform methodology applied state-wide. An advantage of having each utility perform or sponsor (with PRG oversight) its own study would be the significant easing of problems of confidentiality that likely would arise.
Related to this matter, we note that Section 1.8 of the Settlement Agreement (Public Version) for long-term core gas hedging program adopted in D.07-06-013 required Pacific Gas and Electric Company (PG&E) to consult with its core hedging advisory group, regarding
... a market assessment study regarding the risk preferences of PG&E's core gas customers. The goal of such a study will be to obtain a quantitative estimate of the consumer risk tolerance of PG&E's core gas customers, or the amount PG&E's core customers might be willing to spend on hedging to mitigate the impacts of commodity price volatility.39
It may be instructive to wait for this study to be completed and reported on prior to launching a comparable study or studies of electric customers' risk preference, although we are also reluctant to further delay this overdue work.
Having already mandated, in D.07-12-052, the use of a 12-month rolling TEVaR set at a confidence level of 95%, there are no risk management guidelines that urgently need to be addressed. However, a review of the risk management guidelines, and the CRT level (and associated trigger level) in particular, will be useful once more information becomes available about customer risk preferences. Therefore, we will await the results of the customer risk preference study, or studies, before addressing these in a more thorough fashion. If there is time, then we will address these additional issues in the 2008 LTPP proceeding. If not, then we will review the overall risk management approach in a subsequent proceeding.
In this OIR, we seek parties' opinions as to how to proceed with the customer risk preference study, both as regards the method of execution and the timing.
3.4. Other Implementation Issues
Finally, experience to date implementing the LTPP program has demonstrated, in a variety of instances, that the LTPP proceeding must have sufficient flexibility to address additional procurement related implementation issues, on an as-needed basis. For example, review and adoption an "AB 57 Procurement Plan Implementation Manual," pursuant to D.07-12-052, may require the introduction of additional issues into the scope of this proceeding on an as-needed basis.
In addition, as discussed in D.07-12-052, we understand that when the Market Redesign Technology Update (MRTU) is implemented, some aspects of the IOUs' procurement plans may need to me modified. For example, the three IOUs already sought and obtained initial authority to acquire Congestion Revenue Rights (CRR) in the fall of 2007.40 We note that ratepayers and LSEs may benefit from the development of more clarified and refined upfront standards regarding acquisition of CRRs.41
Also, the Commission recognized that ratepayers and LSEs may benefit from LSE participation in virtual or convergence bidding, which the CAISO expects to implement one year after MRTU startup. The IOUs' procurement plans would have to be modified to include upfront achievable standards for procurement of this new energy-related product.
Since it is anticipated that MRTU will be implemented during this LTPP cycle, we will assume that such MRTU related issues such as CRRs and virtual bidding are within the scope of the proceeding. If necessary, we will designate a separate Phase to deal with MRTU related issues when timely.
31 CEC. California Energy Demand 2008-2018 Staff Revised Forecast, CEC-200-2007-015-SF2, November 2007, at p. 25.
32 Id.
33 Id. (Emphasis added.)
34 We clarify that the CEC's definitions of "committed" and "uncommitted" differs from this Commission's use of the same terms in the context of the LTPP. In this OIR, as in D.07-12-052, we define "committed EE" as only those savings attributed to the IOUs' most recent (2006-2008) and earlier EE program portfolios designed to 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) designed to meet or exceed the Commission-adopted EE goals. Hereinafter, all references to "committed" or "uncommitted" EE savings refers to the Commission definition, unless otherwise noted.
35 CEC (2007). California Energy Demand 2008-2018 Staff Revised Forecast, CEC-200-2007-015-SF2, November 2007, at p. 25.
36 Within the CEC's end-use forecasting model, conservation savings (EE) is quantified in two main places: (1) the sector models, including residential and commercial, which quantify EE attributable to codes and standards, market effects, and some utility program effects; and (2) a summary model, which incorporates CEC staff assessments of additional EE savings attributable to utility programs not already captured in the sector model (so-called "direct program adjustments"). (See the CEC's Energy Demand Forecast Methods Report, CEC-400-2005-036, June 2005.)
37 California Energy Commission, 2007 Integrated Energy Policy Report, "Final Errata," CEC-100-2007-008-CTF-ERRATA, December 5, 2007 at p. 3.
38 September 25, 2006 ACR/Scoping Memo, at p. 17.
39 D.07-06-013, Attachment A, Settlement Agreement (Public Version) Regarding PG&E Long-term Core Hedge Program Application (A.06-05-007), the Core Procurement Incentive Mechanism (CPIM), and Transportation Capacity Held on Behalf of Core Customers, at pp. 2-3.
40 See e.g., Resolution E-4136, issued December 6, 2007, approving with criteria for implementation the request by SDG&E to amend its procurement plans to allow for procurement of CRRs with potential expense to ratepayers. CRRs are a financial tool designed to hedge the variable transmission costs expected under MRTU, and are akin to the currently used Firm Transmission Rights.
41 For example, the quantities and durations of CRRs available to market participants will not necessarily exactly match the energy deliveries expected by LSEs. Thus, while the Commission granted LSEs permission to hedge their expected energy deliveries rather than speculate, LSEs may benefit from greater clarity regarding how to match hedges to their expected grid use without risking disallowances of CRR expenses that may arguably qualify as "speculative."
