APPENDIX A
PRELIMINARY SCOPING MEMO
1. Phase 1 Issue Areas
1.1. Standardized Resource Planning Practices, Assumptions & Analytical Techniques
Electric resource planning is inherently complex, uncertain and high-stakes, because the process guides multi-billion dollar decisions about enduring capital infrastructure investments whose economics depend on accurate predictions about an uncertain future. The investor-owned utilities (IOUs) face the very difficult task of sorting through these complexities and making reasonable recommendations to the Commission about which resource portfolios strike the best balance between countervailing objectives of low-cost, reliability, and environmental stewardship. In Rulemaking (R.) 06-02-013, the IOUs demonstrated, with varying degrees of ingenuity, that some (though not all) of this complexity could be synthesized and juxtaposed into explicit comparisons among candidate resource plans that, for example, trade total supply cost against increased reliability or more preferred resources. Despite these bright spots, in Decision (D.) 07-12-052, we identified opportunities for improvement in the IOUs' long-term procurement plan (LTPP) planning process. We signaled to the IOUs and stakeholders that the Commission intends to improve upon, and adopt a best-practices approach to, electric resource planning methods:
In subsequent iterations of the long term procurement process, the IOUs will be expected in their resource planning to meet and exceed the high standards Californians expect as pacesetters on energy and environmental issues. We agree with parties that find areas that could be improved on throughout the IOUs' planning process from planning assumptions and scenario development, to candidate portfolios and portfolio analysis, and ultimately, evaluation and final selection of a preferred portfolio.1
Because "we expect the IOUs to integrate the best, most recent planning methodologies and analytical techniques [in the LTPPs],"2 this Order Instituting Rulemaking (OIR) provides a venue for the IOUs and other parties to come forward with proven, innovative, and effective proposals to build on California's rich legacy of resource planning leadership, while continuously improving its technical and analytical underpinnings.
In the 2007 Integrated Energy Policy Report (IEPR), the California Energy Commission (CEC) also concluded that the resource planning practices and techniques that the IOUs used to develop their LTPPs were insufficient to effectively analyze trade-offs between resource alternatives and to address certain long-term risk factors in the electric resource planning environment. During the 2007 IEPR proceeding, CEC staff reviewed the IOUs' LTPPs with a focus on risk management, including an assessment of the Commission's To Expiration Value at Risk (TEVaR) metric.3 While the resulting report found that TEVaR is an appropriate tool to manage electric price risk and insulate from short-term fluctuations in market power and natural gas costs, according to the report, the same methodology does not readily apply to risk factors over the long-term time horizon. Among other recommendations, the IEPR calls for "a common portfolio analytic method, such as the application of, to the maximum extent practicable, common planning assumptions, particularly for key risk drivers such as natural gas price trends, greenhouse gas mitigation costs, and technology characteristics."4 Further, the 2007 IEPR states:
The Energy Commission will make the development of a common portfolio analytic methodology a core focus of the 2008 IEPR Update, with the clear objective of influencing the long-term procurement plans filed by the investor-owned utilities with the CPUC... This methodology should use common assumptions across utilities to the maximum extent practicable; extend over a 20-30 year period of analysis; discount future fuel costs at the same social discount rate used in standard-setting activities unless these costs are shown to be shareholder liabilities; and focus upon an "efficient frontier" from a consumer perspective utilizing a cost-based metric, with a sufficiently broad scope to incorporate environmental impacts.5
In essence, the CEC is calling for incorporating aspects of an integrated resource planning (IRP)6 approach into the long-term procurement process, much as this Commission has indicated in past rulings. For example, in the 2006 LTPP OIR, we stated that "the long-term plan review process will reflect an [IRP] approach to planning for the future of the state's electric system."7 In general, parties' views on IRP exhibit a continuum of opinions from strictly regulated, utility-driven resource planning to loosely regulated, market-driven resource development. In the run up to the 2006 LTPP, some parties expressed concern over the concept of utilities' conducting IRP in conjunction with their long-term plan filings. For example, advocates for market competition stated that IRP is a term that only refers to vertically-integrated utilities and their internal tradeoffs between generation and transmission.8 In R.01-10-024, parties "urged the Commission to develop a fully integrated resource planning process."9 More recently, parties expressed concerns in R.06-02-013 that the IOUs' plans were hastily developed and/or lacked sufficient analytical rigor to quantify significant price risks to California ratepayers, such as carbon risk.10 The utilities, in their own defense, complained that the 2006 LTPP schedule gave insufficient time to develop their plans to the extent that parties (and they themselves) would have liked.11 The Commission intends to respond to this concern by scheduling at least six months in the 2010 LTPP cycle for IOUs to develop plans following the issuance of the 2010 LTPP scoping memo.
We believe there is merit in developing tools that allow stakeholders (decision-makers, IOUs, market participants, environmental and ratepayer stewards) to better understand the economic, reliability, and environmental trade-offs between different resource choices - both across different types of supply- and demand-side "generation" and between generation and transmission. Many parties have identified the absence of any analysis of this type as a significant data gap in this proceeding, and we believe the planning principles that emerge from this effort will promote market goals of transparency, fairness, economic efficiency, and reduced costs to ratepayers.
A primary objective of this effort will be to provide greater transparency with regard to how resource planning decisions are made.12 Allowing market participants to operate from a common understanding of planning assumptions should result in increased confidence in private investment in resources and projects that are most efficient and aligned with those assumptions.
We anticipate that one of the more challenging policy considerations we will face in developing this resource planning framework will be to balance the regulated aspects of a portfolio analysis methodology with our ongoing goal of developing a more functional competitive electricity market. We are confident that this balance can be struck, though, and we will welcome input from various stakeholders to assist us in structuring a methodology that is consistent with this goal.
Our task in this policy analysis will be to determine:
(1) How electric resource planning in California ought to be conducted in the next six to ten years,13
(2) What transitional states are appropriate towards that end-state in the next two to five years; and
(3) What incremental steps are actionable in the next two years14 given the current hybrid market structure.
While we by no means intend to predetermine the outcome of this important issue in the OIR, we do suggest a possible framework for considering refinements to resource planning methods in the LTPP arena. As a general theme, the Commission would like to see a planning framework emerge out of this process that balances two opposing objectives: standardization and flexibility. Standardization, so that (a) LTPPs can be compared to each other and work products from other proceedings, and (b) LTPP results can be aggregated to produce meaningful statewide assessments. Flexibility inspires creativity, allows planning methods to be adapted to IOUs' unique systems, and leverages the IOUs' formidable resources and knowhow in this area.
A starting point might be to establish a common format for loads and resources (L&R) tables and a master data request for populating the underlying inputs to the L&R tables. The master data request could clearly spell out minimum requirements (i.e., specific data sources that must be utilized in a base case run), flexible requirements (i.e., data sources that IOUs seek out to leverage market knowhow and demonstrate their "best guess" at the expected value of critical planning inputs), or both, depending on the data point in question. Examples of planning input variables include (but are not limited to):
· Supply curves or levelized cost;
· Capital cost or capacity payments;
· Fuel and other operating costs;
· Capacity credit (or firm capacity value);
· Integration cost (of intermittent renewables);
· Environmental regulatory compliance costs such as greenhouse gas (GHG); and
· Opportunity cost of generation from multi-use resources (e.g., hydro).
With standardized L&R tables in place, the Commission could consider (also in the short-term) minimum and/or flexible requirements for scenario analysis. It is likely that a standard reference case scenario would be required, as well as certain sensitivity cases to test critical planning assumptions. In addition to these minimum requirements, utilities would be encouraged to develop their own planning scenarios to fill analytical gaps, apply the knowledge and expertise of utility resource planners, and propose innovative techniques to better evaluate cost-benefit and risk tradeoffs. Examples of planning assumptions that might be targeted under certain required scenarios include (but are not limited to):
· load migration;
· availability of energy efficiency (EE), demand response (DR), and other demand-side resources;
· New Qualifying Facility (QF) and QF recontracting;
· discount rates and other financial assumptions;
· viability of low-carbon technologies such as nuclear, carbon capture and sequestration, energy storage, and emerging technologies;
· power imports from Western Electricity Coordinating Council and their GHG and renewable content;
· GHG mitigation costs (see Section A.b.); and
· 33% renewables goal (see discussion below).
Finally, the Commission might consider prescribing certain types of output variables that candidate resource portfolios should be evaluated against. With the proper analytical tools and modeling capabilities, candidate portfolios might be quantified in the following terms:
· Expected value or total supply cost (in levelized and/or absolute terms)
· Portfolio risk or variance of total supply cost;
· Rate impact (both expected value and variance);
· Reliability (Loss of Load Probability, Expected Unserved Energy, or other metrics);15
· Emissions of GHGs and other criteria pollutants (in absolute and per Megawatt-hours terms); and
· Energy mix and renewable content.
One area in particular that the Commission intends to highlight and address in this process is building analytical capability to assess the Energy Action Plan (EAP) goal of 33% renewables by 2020. The EAP called on all California load serving entities (LSEs) to "evaluate and develop implementation paths for achieving [the 33% renewables goal] in light of cost-benefit and risk analysis."16 In D.07-12-052, we found that "all three IOUs' 2006 LTPPs provided insufficient information for the Commission to accurately assess how the IOUs will achieve a 33% renewables target by 2020"17 and "did not include the detail, integrated approach, or forward-thinking suggested in the [2006 LTPP] Scoping Memo."18
In general, we agreed with certain IOUs that "further analysis is needed regarding the feasibility and cost of a 33% renewables target,"19 and we directed the parties "to work with ED staff to refine a methodology for resource planning and analysis that will allow them to adequately address the issue of a 33% renewables target by 2020 in subsequent LTPPs."20
The Commission, in conjunction with other state agencies and stakeholders, recently launched the California Renewable Energy Transmission Initiative (RETI), a statewide proposal 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.21 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.
RETI Phase I is targeted for completion by June 2008. We expect the data produced out of the RETI decision to be utilized in this proceeding. As stated in the 2006 LTPP decision, "we expect [the 33% renewables] sections to be much more robust in subsequent LTPPs, and expect that parties will work to make RETI more useful in this regard."22
We pose the following questions to parties with regard to the consideration of standardized resource planning practices, assumptions and analytical techniques in the development of LTPPs:
· What does IRP look like in a hybrid market?
· Are there any confidentiality issues that present themselves in the context of IRP, with regard to planning input assumptions, proprietary modeling tools, etc.?
· What aspects of portfolio analysis23 are best suited to electric resource planning in California? What are the potential benefits and pitfalls of portfolio analysis? How should portfolio analysis techniques be incorporated into the LTPPs, if at all, to leverage its benefits and avoid any shortcomings?
· What are the gaps, if any, in the assessment of resource planning risks in the LTPPs? Why do the gaps exist? What can be done to close the gaps?
· How should reliability impacts of various resource types be integrated into the planning process?
· Are forward natural gas prices an appropriate planning input to evaluate the risk trade-offs of gas-fired generation against other resources? What comparable "fuel risk" metrics are need for renewables and other resources?
We expect that this planning approach, including a response to 2008 IEPR Update findings, will define the requirements of future LTPP filings.
1.2. Interim GHG Uncertainty Assessment
The Commission found, in D.07-12-052 that "the overarching problem in all three LTPPs is the absence of any scenario analysis regarding what types of resources the IOUs should use to fill their net short positions to best transition to the inevitably GHG-constrained world we are moving towards."24 In order to strengthen future LTPP filings, the Commission stated that procurement plans ought to be "detailed enough to enable adequate analysis of fuel mix under various scenarios, overall cost to customers, risks faced by customers and environmental impact."25 Apart from analyzing fuel risk, procurement plans should also assess the underlying technology risk, as the technologies selected to serve load pre-determine the fuel mix and operating cost of carbon-emitting resources.
One obstacle cited by the IOUs in their 2006 LTPP filings was the degree of uncertainty associated with GHG regulations at the time those filings were being completed. It is true that the Commission had only firmly announced its intention of establishing a load-based cap in April 2006.26 Furthermore, the passage of AB 32 later that year added another layer of uncertainty to the future direction of GHG policies in California. While we maintain that uncertainty surrounding GHG policies at the time of the 2006 filings should not have prevented the IOUs from conducting a more thorough analysis of the implications of GHG constraint on their LTPPs, we acknowledge the difficulties these uncertainties imposed on IOUs. Many of the policy uncertainties noted by the IOUs will have been resolved by late 2008, and the decisions made by the Commission and the California Air Resource Board (ARB) should facilitate a more detailed treatment of GHG mitigation policies in subsequent LTPPs.
AB 32 designated ARB the lead agency on establishing and enforcing climate policies. It also set several important milestones for ARB related to the design of GHG policies. Two of these milestones are especially germane to the issues facing the IOUs as they prepare their LTPPs. The first directed ARB to approve mandatory GHG reporting protocols by January 1, 2008. On September 6, the California Public Utilities Commission (CPUC) issued a decision D.07-09-017 recommending a reporting protocol for the electricity sector. On December 6, 2007 the ARB approved this protocol, as well as protocols for other sectors developed by ARB staff.
The second milestone directs the ARB to issue a scoping plan by January 1, 2009 that lays out the major design elements of the GHG mitigation program ARB must implement to meet the requirements of AB 32. Additional CPUC and CEC decisions will be forthcoming in 2008 related to the scoping plan, and these decisions will resolve other remaining issues. Another decision, expected in March 2008, will recommend that either electric utilities or electric generators be the point of regulation for ARB's GHG programs. This decision will also contain a broad recommendation on the question of allowance allocation in the electricity sector. In August or September 2008, the Commission and CEC will issue a more comprehensive set of recommendations to ARB covering all aspects of the GHG regulation for the electricity sector. This decision will give a more detailed recommendation on allowance allocation as well as recommendations related to offsets, banking and borrowing of allowances, the length of the compliance period, and other GHG program design issues.
Several factors will determine the costs of complying with AB 32 in the electricity sector and the distribution of those costs among utilities. These factors include population growth, natural gas prices, renewable technology prices, transmission developments, and the costs of implementing various energy efficiency measures across all sectors of the economy. Given the complexity of estimating these costs and devising plausible scenarios of how these factors may play out to 2020 and beyond, the Commission has hired a consulting firm, Energy and Environmental Economics, Inc. (E3), to perform a series of modeling runs at both the statewide and LSE levels to inform the August/September 2008 decision. Preliminary statewide results were presented to the public at a Commission workshop in November. These results will be further developed with new information from stakeholders and finalized in March 2008.
Once the statewide modeling runs are finalized, E3 will disaggregate the analysis at the LSE level. We expect the IOUs to work closely with E3 to help E3 deliver the most accurate results possible. Since E3 will be conducting what is essentially a long-run scenario analysis, the IOUs will be able to draw on E3's modeling results for information related to subsequent LTPP filings. Close cooperation among the IOUs, the Commission, and E3 will produce mutually acceptable results that facilitate analysis of the cost-effectiveness of IOU-specific GHG mitigation strategies given plausible developments in GHG prices and costs of GHG mitigation. Moreover, developing the scenarios and modeling runs in 2008 should provide valuable experience for assessing various approaches to designing a consistent methodology for GHG scenario analysis for future LTPPs.
In addition to the Commission's ongoing GHG modeling effort, the CEC conducted a Scenario Analysis Project, as part of the 2007 IEPR, to assess the GHG emissions consequences of policy strategies to support low-carbon resources. The study constructed and assessed various policy-driven scenarios, most with very high levels of EE and renewables, and evaluated their relative carbon emissions and cost of electricity against a reference case. The study also evaluated the sensitivity of cost and GHG emissions relative to natural gas prices and hydroelectric availability. Despite "scientific, technological and institutional uncertainties,"27 the CEC maintains the 2007 IEPR scenario analysis produced certain indicative results. Notably, the CEC found that:
Each of the policy-driven cases which increases the investment in efficiency and renewables beyond current requirements seems likely to fall within the range of 1990 CO2 emissions [AB 32's 2020 goal]. The more intensive preferred resource scenarios would enable a higher contribution to AB 32's 2020 goals than attaining 1990 levels.28
Given these recent and ongoing initiatives to understand the cost and GHG emissions of low-carbon resource portfolio alternatives, the Commission believes the time is ripe to gather, evaluate, and consolidate these and other data sources as a basis for developing consistent interim requirements and/or guidelines for evaluating carbon cost and risk in future LTPP filings. Again as a general theme, similar to our vision of a standardized resource planning framework, what we expect to emerge from this effort will be some combination of minimum requirements and flexible guidelines for evaluating carbon cost and risk in subsequent LTPPs.
We pose several questions to initiate discussion of how a GHG scenario analysis component of the IOUs' LTPPs should be constituted:
· A review of recent utility resource plans indicates there are myriad techniques, both deterministic and probabilistic, that utilities might employ to assess GHG mitigation risk. Some utilities assign probabilities to discrete cost outcomes and run probabilistic simulations to develop cost and risk assessments. Others similarly test sensitivities at discrete cost levels, but make no attempt to divine their probabilities. Is there value in doing probabilistic analysis, in the absence of historical data to define the necessary frequency distribution of GHG costs, or do reasonable deterministic assessments provide the same quality of analysis?
· Parties in this proceeding have suggested possible process tools for estimating carbon risk in LTPPs, including the Delphi method29 and nominal group technique.30 Are these or other tools appropriate for the IOUs to consider or be required to utilize in their LTPP evaluation of carbon cost and risk?
· Should federal GHG regulation scenarios be evaluated, in addition to AB 32 scenarios? If so, how should these federal scenarios be assessed with respect to their structure, timing, and cost implications?
· Should the Commission require the IOUs to apply a GHG cost adder in their reference case LTPPs? If so, what should that cost be? Should it be fixed or escalating over the planning period?
· Should the Commission require the IOUs to assess high and low bandwidths and/or intermediate levels of GHG costs around an assumed reference case cost?
· What level of GHG uncertainty analysis would be reasonable and sufficient in the next round of LTPPs, given that real GHG cost data will not become available until after the AB 32 framework is implemented in 2012?
· What sort of Commission direction would most effectively foster IOU innovation and analytical ingenuity in the assessment of GHG uncertainty?
As an additional item, in response to the motion filed by the joint parties on December 11, 2007, we are requesting that the utilities prepare a report which provides the following required information for each of the relevant programs, which contribute to a reduction in GHG, listed below:
1 D.07-12-052, at pp. 6-7.
2 Id., at p. 6.
3 CEC. (2007). Portfolio Analysis and its Potential Application to Utility Long-term Planning, Final Staff Report, CEC-200-2007-012-SF, August 2007. See Appendix 1.
4 CEC. (2007). 2007 Integrated Energy Policy Report, CEC-100-2007-008-CTF, November 2007, at p. 67.
5 CEC. (2007), 2007 Integrated Energy Policy Report, "Final Errata," December 5, 2007, at p. 4.
6 Integrated resource planning (IRP) is a broadly used term to describe a planning process that evaluates supply and demand-side resource alternatives and optimizes the resource mix to serve electric load over a planning horizon under various cost/risk, reliability and environmental criteria.
7 Order Instituting Rulemaking to Integrate Procurement Policies and Consider Long-Term Procurement Plans, dated February 23, 2006 at p. 9.
8 Id., at p. 14.
9 D.02-08-071, at p. 13.
10 For example, see Opening Brief of the Division of Ratepayer Advocates, R.06-02-013 Track III, filed August 1, 2007, at p. 41.
11 For example, see Comments of San Diego Gas & Electric Company (U902E) on Proposed Decision, R.06-02-013 Track III, filed December 10, 2007, at p. 3.
12 While protecting market sensitive information pursuant to D.06-06-066 and the Commission's confidentiality matrix in D.06-06-066, Appendix A.
13 The approximate timeframe when Assembly Bill (AB) 32 framework will take effect and Department of Water Resources (DWR) contracts will expire, possibly reopening direct access (DA), both significant events that, if they occur, could radically affect how resource planning is done.
14 The timeframe before new LTPPs are filed in the 2010 LTPP planning cycle.
15 We note that the forthcoming Planning Reserve Margin (PRM) rulemaking will likely shed some light on accepted reliability targets for long-term resource planning purposes.
16 Energy Action Plan II, Key Action #5, at p. 8.
17 D.07-12-052, at pp. 255-256.
18 Id., at p. 256.
19 Id.
20 Id.
21 www.energy.ca.gov/reti/index.html
22 D.07-12-052, at p. 256.
23 For a discussion of portfolio analysis in the context of electric resource planning in California, see the CEC publication, Portfolio Analysis and its Potential Application to Utility Long-term Planning, Final Staff Report, CEC-200-2007-012-SF, August 2007.
24 D.07-12-052, at p. 5.
25 D.07-12-052, at p. 245.
26 See R.06-04-009.
27 2007 IEPR, at p. 62.
28 Id. (Emphasis added.)
29 The Delphi technique is a method for obtaining forecasts from a panel of independent experts over successive rounds of expert prediction, explanation and anonymous discussion to support or debate predictions, and averaging of final predictions. For further discussion, see Opening Brief of the Division of Ratepayer Advocates, R.06-02-013 Track III, filed August 1, 2007, at p. 42.
30 The nominal group technique is a decision-making method based on ranking various alternatives, 1st, 2nd, 3rd, 4th, and so on; explaining the rationale behind each group members' ranking; and tallying rank order votes, as opposed to all-or-nothing votes for 1st place. For further discussion, see Opening Brief of the Division of Ratepayer Advocates, R.06-02-013 Track III, filed August 1, 2007, at p. 42.
