3. Changes to the Indifference Amount Methodology
Parties generally agree that revisions are warranted in the methodology to derive the Power Charge Indifference Amount (PCIA or indifference amount) paid by DA customers. Parties disagree, however, as to what the modifications should be. As a framework for evaluating proposed changes, we review the principles underlying the indifference methodology.
The indifference amount is designed to ensure that DA customers that have departed from bundled IOU procurement service remain responsible for paying any IOU costs incurred on their behalf. In other words, remaining bundled customers must be protected from any cost shifting and left economically indifferent as the result of DA customers leaving the system.
The DA program was suspended following the events of 2000-2001 which led to extraordinary wholesale power cost increases, threatening the solvency of California's major electric utilities and the reliability of service. On February 1, 2001, AB 1 from the First Extraordinary Session (Ch. 4, First Extraordinary Session 2001) (AB1X) was signed into law to address the energy crisis. AB1X suspended DA, and required DWR to procure electric power supplies sufficient to meet the needs of retail customers.3
We implemented the DA suspension, permitting DA contracts executed on or prior to September 20, 2001, to continue on the condition that DA customers bear their fair share of cost responsibility, thereby leaving bundled customers indifferent to DA departure from bundled load. AB 117 required bundled customer indifference to prevent any shifting of recoverable costs among customers.
Except for the limited authorization for increased DA under SB 695, DA remains suspended until repealed by legislation, or otherwise authorized. The Commission issued Decision (D.) 10-03-022 to implement preliminary provisions relating to SB 695, by adopting capped limits for the maximum DA load in each of the IOUs' service areas, to be phased-in over four-years.
The DA load caps imposed under SB 695 reflect the historic highs in DA load in the IOU's service areas. Even with the caps, the DA market size would tend to be higher on an absolute kilowatt-hour basis than it was in 2003, when the market was limited by the suspension imposed by AB 1X. The DA load caps provide the IOUs with certainty as to the maximum DA load they can expect in their service area, even though the actual amount of DA load at any particular time remains uncertain.
In D.02-11-022, the Commission established a cost responsibility surcharge (CRS) methodology which incorporated an indifference amount. A revised methodology to determine the indifference amount was approved in D.06-07-030, (subsequently modified by D.07-01-030, D.07-05-022, and D.07-05-005). The indifference amount is updated annually in each IOU's Energy Resource Recovery Account (ERRA) proceeding.
The Indifference principle involves the interaction of three elements;
a) a non-bypassable surcharge which DA customers pay to offset any cost impacts on bundled customers associated with their departure from or return to bundled service;
b) switching rules which govern the movement of customers between DA and bundled service; and
c) Transition Bundled Service (TBS) rates which accommodate customer movement while allowing the utility to adjust its generation portfolio without cost impacts on bundled customers.
To derive the indifference amount, the market value of the IOU's supply portfolio is subtracted from the total portfolio cost. The market price benchmark (MPB) is a calculated proxy which represents the market value of the IOU total energy resource portfolio. The IOU total portfolio includes IOU-owned generation, purchased power, DWR contracts, fuel costs, and California Independent System Operator (CAISO) costs. A positive indifference amount indicates that the IOU portfolio cost is above-market for that year. The indifference amount is recovered from DA customers through a non-bypassable surcharge to maintain bundled service customer indifference.
A distinct vintage portfolio of generation resources is calculated for each year which is assigned a separate indifference amount. The total portfolio cost for each vintage year is calculated and compared to the market value of energy and capacity produced by the portfolio. Assigning costs by vintage ensures that the customers departing in a particular year pay only the costs incurred on their behalf prior to departure. For each vintage year, the cost of the total portfolio is calculated for resources procured for that year to serve bundled customer load. The generation portfolio for each vintage includes all resources and contracts entered into to serve bundled load, including all previous contracts still in place and new ones signed for that vintage year. To ensure that departing load does not pay for above-market costs of utility procurement commitments after the load departs, the Commission approved the vintage methodology for DA departing load to ensure the proper matching of departing load with the utility procurement process.
While these underlying indifference principles have not changed, the manner in which indifference is calculated needs to be updated to reflect changes in regulatory and industry conditions that have occurred in recent years. Accordingly, we adopt provisions in this Phase III as set forth below.
3.1. Changes in the Market Price Benchmark (MPB) to Account for Renewable Resource Requirements
The current indifference methodology only recognizes the IOUs' cost of renewable resources in the calculation of the Total Portfolio Cost, but does not account for the market value of renewable resources in the MPB. Parties generally agree that the indifference methodology should be revised to reflect the market value of renewable resources in the MPB, but disagree on how to do so.
All load serving entities are subject to increasing requirements to procure renewable resources pursuant to Pub. Util. Code, Article 16, commencing with § 399.1. Renewable resources are more costly than traditional gas-fired generation, and thus have a higher market price as compared to the embedded cost of the utilities' portfolios. As the utilities add renewable generation, their average portfolio costs will increase. ESPs are facing the same mandate to buy a certain percentage of their power from renewable generation sources, and their costs are affected as well. Both the utilities and the ESPs thus face new requirements to purchase renewable power for a certain percentage of their load, causing their average portfolio costs to increase.
Parties agree (except for Reid) that the MPB should be amended to reflect the value of Renewable Portfolio Standard (RPS)-compliant renewable resources in the portfolios of the IOUs (i.e., RPS adder). However, parties disagree on the methodology by which to do so.
PG&E and SDG&E disagree with the DA parties as to the treatment of energy associated with renewable pre-2004 Qualifying Facility contracts and irrigation district contracts. The MPB used to determine the PCIA is multiplied by the entire amount of RPS-eligible energy in the IOU's portfolio. Much of the RPS-eligible energy in PG&E's portfolio, however, is from pre-2004 QF contracts and irrigation district contracts that are not included in the PCIA. These contracts are included instead in the Ongoing Competition Transition Charge (CTC).
PG&E and SDG&E contend that pre-2004 resources in the IOUs portfolios should not be valued using RPS adder because, although these resources count for purposes of determining IOU compliance with the RPS standards and contribute significantly towards such compliance, the IOUs are unable to sell this RPS benefit to a third party. PG&E thus proposes that the MPB used to determine the indifference amount only include an RPS adder that reflects the percentage of RPS-eligible energy in contracts signed after 2003. PG&E would not include the energy associated with renewable QFs in the vintaged portfolio's MPB adder. Instead, the renewable benefit associated with the renewable QF would be accounted for in the MPB used to calculate the Ongoing CTC.
PG&E argues that prior Commission decisions reaffirmed that Ongoing CTC is calculated based on the statutory methodology and that the indifference calculation has no bearing on the determination of Ongoing CTC. PG&E argues that California Renewable Energy Credits (REC) cannot be derived from resources under contract prior to 2005. Thus, PG&E argues that it is not appropriate to impute a REC value into the MPB used to determine Ongoing CTC when the underlying contracts do not transfer ownership of the REC to the buyer and the underlying megawatt-hours (MWhs) are not eligible to be unbundled and counted as a California tradable REC. Otherwise PG&E claims the MPB used to determine the Ongoing CTC would overstate the value in the underlying portfolio relative to the energy (or REC attribute) value in the market place.
The Joint Parties object to the extent any RPS-eligible volumes are excluded from the MPB. They argue that the exemption proposed by PG&E and SDG&E would have the effect of substantially reducing the volume of energy from renewable resources for which the value of renewable attributes is recognized. The reduced RPS volumes would be compared against the system (brown) power benchmark, understating the value of those resources.
Reid recommends adopting the proposal in TURN's post-workshop comments which maintains the current MPB methodology such that the PCIA would incorporate the entire RPS adder premium inherent in the IOUs'costs of procurement to meet the RPS goals, but non-utility retail suppliers would be given RPS credit for their proportionate share of the IOU's RPS purchases. Reid's rationale appears to be that this would obviate the need for bundled customers to pay for the renewable attributes they retain.
The Joint Parties object to Reid's proposal, arguing that it reduces the ability of a competitive provider to manage a resource portfolio that is optimized to meet the specific demands of its customer base. Competitive providers may have specific renewable resource technology or resource locational preferences that appeal to their customers or otherwise fit well within their supply portfolio, and an allocation of RPS resources from the IOU portfolio may be inconsistent with those preferences. In short, customers who choose to depart utility service are simply not looking to have their supply come from the utility portfolio.
CLECA witness Barkovitch testified that Reid's proposal undermines the potential benefit of retail competition, which is to give DA and Community Choice Aggregator (CCA) customer the opportunity to receive power from a different portfolio, as long as it meets state and Commission procurement requirements.
The IOUs, DRA, and TURN disagree with the Joint DA Parties as to how the RPS-eligible energy should be valued (i.e., the RPS adder). The Joint DA Parties propose that the MPB incorporate a Green Benchmark for RPS-eligible energy using available information regarding the IOUs' current cost to obtain RPS-compliant renewable resources. The Joint Parties agree that if the MPB is otherwise adjusted for capacity, the Green Benchmark should be adjusted to subtract the value of capacity provided by those resources, to prevent double counting of capacity. The Joint Parties proposed using resources expected to commence delivery or having commenced delivery in the upcoming or most recent past year in order to recognize that new generating resources are not added in a smooth fashion.
For purposes of calculating the RPS adder under the Joint Parties' proposal, for illustrative purposes, the value of renewables in each IOU vintaged generation portfolio would be established as follows for 2011:
1. Each utility would identify all RPS-compliant resources that began delivery in year 2010 and those projected in their ERRA forecast applications to begin delivery in 2011. This would include both contracts and IOU-owned resources.
2. The IOUs would identify the projected costs of energy produced by each of these resources in 2011, and the net qualifying capacity (NQC) of those resources.
3. IOUs would provide these data (costs in dollars and volumes in MWh and QC in kW)) to the Energy Division.
4. The Energy Division would then calculate the average cost of power from these resources in 2011 by summing up all the costs from all three IOUs, subtracting the product of the NQCs of those resources times the CAISO's Interim Capacity Procurement Mechanism, and dividing by the sum of all the MWhs from all three IOUs.
In addition to PG&E's proposal to exclude pre-2004 resources from the RPS adder, as noted previously, PG&E proposes that the RPS adder incorporate use of publicly available market indices for California Tradable Renewable Energy Credits (TRECs). SCE proposes that pending the availability of publicly available, transparent market indices, the Commission should determine a RPS value by use of a variety of data sources. SDG&E proposes setting an interim RPS adder using data compiled by the Department of Energy (DOE) National Renewable Energy Laboratory (NREL) reflecting premiums paid by retail energy consumers in the market and self-reported by utilities and other ESPs. This data reflects premiums paid by retail energy consumers in the market and
self-reported by utilities and other energy service providers. This data is publicly available and reflects premiums paid by energy consumers in the market for renewable energy over and above the prices for non-renewable energy.
The Joint Parties assert that no functioning market exists for renewable attributes, and consequently, that no relevant market indices are available that meet the following necessary criteria:
1) The indices must be for the same types of products as those to be valued;
2) The indices should be transparent and robust; and
3) The indices should be based on sufficient volume and consistent information.
The Joint Parties maintain that given the lack of a functioning market and available index, the MPB adder should be based on an average of the forecasted cost of RPS resources built or contracted for by the IOUs that commenced or are projected to commence delivery during the year in question and the prior year. The Joint Parties thus propose that the RPS adder be based on the percentage of RPS-eligible energy included in an IOU's portfolio. For example, if the IOU had 18% RPS-eligible energy, the MPB would equal 0.82 times the commodity price plus 0.18 times the RPS-eligible energy.
PG&E and SCE claim that the benchmark proposed by the Joint Parties does not reflect the value of renewable energy. The MPB is designed to determine the market value of an IOU's resource portfolio. The Joint Parties' benchmark uses IOU contract costs rather than market value. If IOU cost rather than market value is used for the MPB, and the MPB is then compared to the same costs in the IOU portfolio, PG&E contends that there will never be a difference between the MPB and the IOU portfolio cost. PG&E argues that the Joint Parties' proposal will thus cause bundled customers to pay a substantial portion of the above-market costs associated with RPS-eligible resources created when load departs.
PG&E supports use of publicly available TREC market indices. The Commission approved the use of TRECs in January 2011. PG&E claimed that a transparent TREC market would be available by third quarter 2011, to include the development of published, transparent REC indices.
PG&E proposes that a renewables adder be based on the REC price published in the SNL Financial Publications California REC index. SNL Financial publishes an index for REC prices throughout the United States, including for California. SNL's published index reflects the value of renewable attributes (i.e., RECs) based on multiple broker quotes, and updated on a weekly basis. Pricing information is from Evolution Markets, Karbone, CFS Traditions, and Clear Energy. (PG&E/Pappas, Tr. Vol. 2, at 286:26-28, 287:1-3.) PG&E claims that the SNL Index is transparent in that the sources of data (i.e., the specific brokers) have been identified and the index is publicly available. PG&E claims the index is robust and liquid, and includes quotes from a number of California brokers that represent numerous buyers and sellers. Information is reported and updated weekly.
DRA supports use of publicly available, transparent REC market values to determine a market value for the MPB when this information becomes available. DRA confirmed that SNL Financials publishes a California REC index using data provided by Evolution Markets, Traditional Financial Services, and Clear Energy Brokerage and Consulting. DRA finds no reason to doubt the accuracy of the published data or the appropriateness of using it to determine the value of the renewable attributes. Because a broader pool of data generally results in greater accuracy, DRA suggests that the Commission may want to use additional data sources as more REC indices become available in the future.
The Joint Parties argue that although RPS market and related indices could be useful for valuing renewables in the future, this alternative is premature. Given the limits on the use of TRECs for purposes of RPS compliance in California, the Joint Parties contend that TREC price indices will likely understate the value of RPS-compliant renewables in the IOUs portfolio. Moreover, the Joint Parties argue that specific indices were not available for review in this proceeding to evaluate whether they are adequate.
SCE proposes that the Commission set an interim RPS adder based on consideration of a variety of available data points and range of value. SCE specifically identifies four possible sources of data, as follows.
a. The United States (U.S.) DOE survey of reported contract premiums for renewable energy in the Western U.S. of approximately $20/MWh. The DOE data was recently adopted for use as the "green premium" for net surplus compensation pursuant to AB 920 in D.11-06-016 issued in A.10-03-001 et al.
b. IOU data on the cost of renewable generation resources in their total portfolios as of 2009, which - for SCE - showed a renewable premium relative to the 2011 forward strip price-based MPB of $20 to $40 per MWh, depending on whether the premium reflects energy costs only, or energy and capacity costs.
c. The Marin Energy Authority (MEA) renewable cost data in its power purchase agreement, showing two renewable energy premiums of $10.50/MWh and $39/MWh.
d. Since the majority of SCE's RPS contracts have been below the Market Price Referent (MPR), as confirmed by a recent DRA report,4 SCE suggests this MPR amount could serve as a maximum value for a proxy.
We affirm the consensus among parties that the MPB methodology needs to be revised to recognize the market value of RPS-eligible resources for purposes of calculating the indifference amount. The correct way to adjust the MPB would be based on a benchmark that accurately reflects the market value of all relevant sources of the California renewables market. To accurately reflect the market value of RPS-compliant renewables, the benchmark should reflect prices paid by buyers and sellers in recent transactions for delivery of RPS-compliant power in California for the forecast year. Based on the record developed in this proceeding, however, we are left with conflicting proposals, all of which suffer from various deficiencies in completeness, relevance, and/or transparency of the data proposed to be used. We discuss the flaws in the various proposals before setting out our adopted RPS adder methodology.
We conclude that Reid's proposal is unduly complex and not sufficiently developed to warrant adoption at this time. Reid proposes that instead of a renewables adder, DA providers would receive RPS credit for their proportional share of the IOU's RPS purchases. Reid's proposal lacks specificity regarding the intended mechanism for allocating RPS credits. It is unclear whether Reid is proposing to create a new RPS compliance product called an "RPS Credit" or if he is proposing to allocate existing Western Renewable Energy Generation Information System (WREGIS) certificates to load-serving entities (LSEs).5 The latter approach would require a methodology be developed to fairly allocate the various renewable resources in the IOU portfolio to LSEs.
The Joint Parties' proposed RPS benchmark does not reflect all California-delivered RPS-eligible wholesale supply, but is only limited to IOU procurement costs. The Joint Parties' benchmark excludes RPS costs of ESPs, CCAs and publicly-owned utilities that make up more than 32% of California load. The IOUs' load represents 68% of the load subject to the RPS requirement. To the extent that the RPS costs incurred by other LSEs are lower than that of the IOUs, the exclusion of the other LSEs' RPS sources would overstate the benchmark. The IOU portfolios have higher percentages of new renewable resources than those of ESPs and CCAs. IOUs also have restrictions on contracting that do not apply to ESPs or CCAs, which tends to restrict what IOUs can do to meet RPS. Thus, the inclusion of ESP and CCA cost data would be expected to lower the perceived market value.
The Joint Parties' proposal also only applies IOU average RPS resource contract prices from the first two contract years, regardless of contract duration. This approach fails to capture the benefit of long-term contracts and overestimates the average cost of front-loaded generation facilities. The Joint Parties' proposal relies on IOU data filed with the Commission annually in ERRA proceedings. To maintain the confidentiality of the data, the Energy Division would need to compile the data from the respective IOU filings to develop the RPS adder, consistent with the current practice where the Energy Division calculates the MPB
Some parties express concern that the Joint Parties proposed RPS methodology could result in double counting of the capacity value of renewable resources. The Joint Parties suggested a refinement to eliminate from the price any value for capacity in order to avoid double counting. SCE witness Schichtl agreed that the correction proposed by the Joint Parties would address the concern. PG&E claims that the Joint Parties' proposed methodology will result in an inflated value because it includes long-term transactions. PG&E contends that the MPB should reflect short-term transactions only, citing testimony by Joint Parties witness Fulmer that the MPB is based on a one-year forward price.
PG&E's proposes to use published indices from SNL Financial Publications to determine RPS market value although no specific SNL indices were introduced into the record. The SNL Energy Power Daily report compiles data from a range of indicative market data that may not necessarily represent completed trades or transactions. The record is not clear about the types of transactions reflected in the SNL indices; which indices should be used; and if more than one index is used, how to weight them. The record does not indicate the California REC volumes represented in the reported indices. When Joint Parties representatives contacted the brokerage services purportedly surveyed to compile the SNL information on California RECs, these services said they do not provide California REC data systematically to SNL. The information in the report is thus subject to deficiencies regarding data reliability.
Questions also remain concerning the effects of Senate Bill
(SB) 2 (2011-12 First Extraordinary Session, Stats. 2011, Ch 1)(SB 2 (1X)) which was signed into law after the conclusion of evidentiary hearings. Under SB 2 (1X), three product categories can be used to meet RPS requirements: (1) bundled products, (2) firmed and shaped products, and (3) a category of products that includes unbundled RECs. It is uncertain whether or how the SNL data would evolve in view of SB 2 (1X), and whether the index reflects an appropriate level of market liquidity.
SB 2 (1X) requires that initially, an RPS-compliant portfolio include at least 50% bundled products, increasing to 75% in 2017. SB 2 (1X) initially allows use of firmed and shaped products for up to 50% of the RPS requirement, but decreases the limit on these to no more than 25% by 2017. The third category of products, including unbundled renewable energy credits, remains limited to no more than 25% initially, ramping down to no more than 10% in 2017.
If California REC market indices are used to establish the RPS adder, it is uncertain which of the three categories of products the market indices would reflect. The Joint Parties express concern about the exclusive use of market indices tied to a product that can only be used to fulfill a limited part of the RPS requirement, to value all RPS products in the IOUs' portfolio.
Joint Parties witnesses Meal, Dalessi, and Fulmer testified that the TRECs traded in the market envisioned to arise as a result of D.11-01-25 cannot be used broadly for compliance purposes, as the decision explicitly limits the amount and price of TRECs that can be used for RPS compliance. They believe that the TREC is unlikely to fully reflect the renewable attribute value of resources in the IOU portfolio and would not be a good basis for the renewable price component of the MPB.
CLECA/CMTA witness Dr. Barkovich testified that the Commission decision cited by PG&E as permitting the use of RECs for compliance with renewable portfolio standard requirements limits the use of RECs for such compliance. Thus, most of the renewable compliance will come from renewable generation contracts, not REC contracts. According to Barkovich, it is too soon to be able to determine if the price of unbundled RECs in the market will track what utilities are paying for the renewable attribute in their renewable generation purchases.
SCE proposes that the Commission should reject an approach based on the cost of IOU's renewable contracts in the current year and instead, administratively set a proxy renewable premium price - to be used in the interim pending the development of the REC index - based on the all available data points on the value of renewable attributes, including the costs of all RPS-compliant renewables in the IOUs' portfolios as of 2009, which could include resources committed to decades ago. SCE doesn't justify why the average cost of recent IOU RPS-compliant renewables should not be considered, particularly since these procurements comprise 68% of the activity in the market.
SCE points to DOE data as another data source, even though this data refers to a different product, and is well below the value of California RPS renewables. Dr. Barkovich testified that this source of data is not a suitable proxy as it captures an entirely different metric and has nothing to do with a wholesale market premium for renewable generation compared to gas-fired generation.
For a third source, SCE points to the prices committed to by MEA in 2010 for both RPS-compliant and non-RPS compliant resources (a premium of $39/MWh and $10.50/MWh respectively). SCE fails to show how prices paid by MEA for non-RPS compliant resources represent the value of RPS-compliant resources.
Since none of the parties' proposals for computing a market-based RPS value are entirely acceptable, we shall determine a suitable proxy to serve as a RPS value based upon a weighting of different data sources. We shall utilize, in part, the IOUs' costs for RPS based on the methodology proposed by the Joint Parties, but only in combination additional data covering a broader spectrum of the California RPS market. If the IOUs' cost to purchase RPS-eligible power was to be used as the sole measure of the RPS market proxy, the IOUs argue that there would never be any above-market RPS costs to recover as an indifference amount. In order to produce a more broad-based weighting of the RPS adder, therefore, we shall make use of sources of RPS data that incorporate transactions of other load serving entities. In the absence of any superior source that has been identified for this purpose, we shall make use of the western regional renewable energy contract premiums published by U.S. DOE.
We shall weight the adopted RPS adder by 68% allocated to the IOU costs for RPS based on Joint Parties' proposed methodology. We shall weight the remaining 32% of the RPS adder allocated to the DOE data. This weighting corresponds to the percentage of the total load subject to RPS requirements currently represented by IOU load. The applicable percentages are subject to updated data in subsequent years.
We recognize that questions and concerns have been raised regarding the usefulness of the DOE data sources as representative of the California market. We conclude, however, these concerns go to the weight that should be accorded to the DOE data sources. Considering the lack of more accurate alternative RPS data sources other than IOU resource data, we conclude that some recognition of the DOE data sources offers an opportunity for a broader measure of the California RPS market compared with exclusive reliance on IOU resource data. We conclude that a weighting of DOE data together with IOU resource data is preferable to the alternative proposals by parties given the deficiencies noted above.
We shall thus direct the IOUs each to submit a subsequent advice letter filing, due within 30 calendar days following the issuance of this decision, providing the most recent DOE index figure or figures of reported contract premiums for renewable energy in the Western U.S. suitable for use in calculating the RPS adder. For purposes of developing the relevant RPS adder, we shall also direct the IOUs each to include in the advice letter filing with the Energy Division the following data.
Each IOU advice letter shall provide the following information:
1. All RPS-compliant resources that are used to serve customers during the current year (i.e., most recent 12 months) and those projected to serve customers during the next year, including both contracts and IOU-owned resources.
2. The projected costs together with the net qualifying capacity of energy produced by each of these resources (providing relevant costs in dollars and volumes in MWh and qualifying capacity in kW).
The Energy Division will then calculate the average cost of power from these resources by summing up all the costs from all three IOUs, subtracting the product of the NQCs of those resources times the IOU's current RA capacity adder used in the Market Price Benchmark, and dividing by the sum of all the MWHs from all three IOUs.
As better sources of market indices of California RPS values become available in the future, we shall consider them in setting the MPB in subsequent periods.
We further direct that pre-2004 resources be included in the RPS adder calculation. All the IOUs confirmed that they claim RPS compliance credit for renewables procured before 2004. The requirement to procure additional RPS-compliant renewable resources is reduced one for one, for every MWh of pre 2004 renewable resources generated in the IOU portfolio. We reject the claim that the renewable attributes associated with pre-2004 renewables in the IOUs' portfolios are of no value to the IOUs and bundled customers. Even if the IOUs cannot sell the renewable attributes, they still benefit from them.
The pre-2004 renewable resource volumes in question are substantial, so it is critical to ensure that these volumes are treated appropriately in the methodology. Excluding such resources would significantly understate the value of renewable resources in each of the IOUs portfolios.
SCE witness Schichtl testified there is no reason to limit the application of the renewable adder only to post-2003 renewable resources: Because SCE's proposal was simply to create a weighted average market price benchmark using the percentage of renewable resources in each vintage year, SCE saw no reason to exclude the renewable resources from any particular vintage of resources.
We disagree with PG&E's argument that exclusion of pre-2004 resources is justified because recognizing the value of renewable attributes in pre-2004 resources, including those resources used to calculate CTC, would result in double counting. As Joint Parties observe, no double counting would occur as long as all portfolios are weighted based on RPS-eligible volumes, and the MPB is calculated the same for all portfolios, including for CTC resources. Therefore, we shall include pre-2004 resources in calculating the RPS adder for calculating the indifference amount. Once the requisite data has been provided to the Energy Division, we shall consider a draft resolution to adopt an interim RPS adder, weighted 68% for IOU costs and 32% for DOE data sources.
3.2. Revised Capacity Adder for the MPB
The current MPB includes a capacity adder to reflect the cost of resource adequacy (RA). In this manner, the RA benefits of generation resources acquired to meet system or local area reliability needs is reflected in the value allocated among customers. The RA capacity adder was agreed to by the parties as a part of an overall settlement, and approved in D.06-07-030. Current capacity values used in the MPB are based on the annualized cost of a combined cycle combustion turbine; but there is no means of updating the capacity values over time. Parties generally agree that RA capacity reflected in the MPB should be subject to updating, but disagree on how to do so for purposes of this proceeding.
The IOUs' joint workshop proposal would establish the capacity value of the utility portfolio based on the total "Net Qualifying Capacity" (NQC) of all generation resources (utility owned and power purchases) in the utility portfolio and the price for capacity established by the CAISO for the Capacity Procurement Mechanism (CPM), as that price is modified and approved by the Federal Energy Regulatory Commission (FERC) from time to time. The capacity value would vary for each portfolio vintage, as the NQC would reflect the specific resources included in each vintage. Specifically, the NQC of each vintaged supply portfolio and the currently approved CPM would be used to value the capacity of the portfolio. The supply portfolio NQC would be the sum of the individual NQC of all resources included in each vintaged supply portfolio, varied by vintage. These data would be made available for verification by the Energy Division.
SCE also proposed adjusting the MPB calculation to incorporate an RA value based on the amount of capacity actually included in each vintaged portfolio. SCE believes that a reasonable method of updating the RA adder is preferred over a fixed RA adder price to account for market changes.
SCE proposed a method of updating the RA capacity adder based on the California Energy Commission's (CEC's) determination of the going-forward cost of a simple cycle combustion turbine, evaluated bi-annually as part of the CEC's generation cost study. This same method was used by the CAISO to establish the short-term capacity price currently represented by the CPM. The current capacity value is set at $7/MWh for SCE and $4/MWh for PG&E.
The Joint Parties agreed with the approach described above as proposed by the IOUs.
At the time of the workshop, the CAISO had filed a proposal for the CPM with FERC based on the going forward costs of a hypothetical 50 MW simple-cycle, gas-fired unit built by a merchant generator, based on studies conducted by the CEC, with a 10 percent adder. Based on this methodology, the price for CPM was proposed at $55/kilowatt (kW)-year. At the time, FERC had not acted on the proposal. Reid proposes the use of the Interim CPM (ICPM) price of $41/kw-year pending further developments on the CPM.
A few days before evidentiary hearings began, FERC issued an order expressing concern about the methodology proposed to set the CPM price and establishing a technical conference to address this issue. Given the uncertainty about the CPM price going forward, the Joint Parties recommend that the Commission adopt a revised capacity price that uses the methodology proposed by the IOUs, but with the caveat the proposed CPM value of $55/kW-year be used until further action by the Commission. Upon issuance of a final FERC order on the CPM, the Joint Parties would seek a limited opportunity to file further comments on whether or how the final FERC order should affect the updated capacity adder.
Because the MPB is calculated on an annual basis to determine if an IOU's portfolio costs for a single year exceed market prices, PG&E proposes to look at short-term, RA capacity values. PG&E and DRA support continued use of the existing RA capacity adder, claiming the existing adders more accurately reflect current RA prices. The existing adder was agreed to by parties as part of a settlement approved in D.06-07-030. PG&E and DRA argue that the ICPM and CPM prices are too high to reflect short-term capacity prices. PG&E testified that in general, short-term RA is less than the $41/kW-year ICPM backstop price of capacity. The sources relied on by PG&E show that RA prices have been at or below $45/kW-year. The ICPM price of $41/kW-year was on the high side of the range, but was within the range of prices cited by PG&E's sources as reflective of RA capacity prices.
DRA believes that although the CPM price is publicly available and transparent, it is not accurate or appropriate for determining the market value of RA capacity. DRA thus does not support using the CPM to determine the market value of RA capacity, and recommends maintaining the existing RA capacity adder.
We agree that it is reasonable to provide a means for updating the RA capacity value included in the MPB over time as more updated data becomes available. We conclude that SCE proposes the most appropriate alternative for determining the capacity adder based on the going-forward costs of a simple combined-cycle combustion turbine as estimated by the CEC. Both PG&E and SCE indicated at hearings that they no longer supported use of the CPM to determine the RA capacity value. Both the ICPM and CPM prices are substantially higher than the general level of resource adequacy. (PG&E/Martyn, Transcript (Tr.) Vol. 2, at 300:22-24.) Although SCE had proposed to use the CPM for determining for the RA adder, this support was based on SCE's understanding that the CPM would reflect the going-forward costs of RA capacity. (SCE/Schichtl, Tr. Vol. 1, at 123-125.) However, if the CAISO were to change its CPM Compensation methodology as a result of the recent FERC decision on CPM Compensation, SCE may not continue this support. (SCE/Schichtl, Tr. Vol. 1, at 125, 9-19; 126:1-9.)
FERC has determined that the CPM may be unjust and unreasonable. FERC allowed the CPM to go into effect April 1, 2011, but made the CPM subject to refund and established a process to review the reasonableness of the CPM price. FERC has initiated an effort to modify the CPM so that it reflects the value of long-term capacity investments.
The CPM was not developed to be a proxy for short-term RA values, but was developed as the price paid to generators to provide a backstop to procure capacity in cases of system deficiencies. The CPM is intended to be a proxy for the going forward costs of operating a specific unit and a 10% adder for the generator. The CPM does not reflect the market price for RA capacity or
short-term capacity costs. Thus, there is a fundamental mismatch between the short-term capacity adder meant to reflect RA values to be included in the MPB, and the CPM that was developed as a part of a backstop mechanism to compensate generators for operating costs plus a 10% adder.
The Commission has previously determined that the CPM overstates the value of RA capacity. In December 2, 2010 comments filed with FERC on the CAISO's CPM proposal, the Commission stated that the proposed $55/kW-year CPM price was above prices observed in the current RA capacity markets.6 PG&E argues that the Commission cannot approve as just and reasonable using the CPM as a proxy for short-term RA capacity prices since it argued at FERC that the CPM is significantly higher than actual RA costs. PG&E argues that CPM does not reasonably reflect the value of RA capacity.
The existing capacity adder was agreed to by parties as a result of a settlement process and approved by the Commission in D.06-07-030 as just and reasonable.
In adopting a forecast market price benchmark methodology for calculating the indifference rate, D.06-07-030 acknowledged the need for an RA/capacity adder to capture the cost of complying with resource adequacy requirements. The Decision stated that no capacity market was then available to provide transparent RA/capacity adders, for 2006. D.06-07-030 adopted the parties' consensus for RA/capacity cost adders, which were negotiated as part of workshop discussions. For 2007 and beyond, D.06-07-030 directed the Energy Division to coordinate a meeting of the Working Group to discuss RA/capacity adders based on publicly reported transactions in a California capacity market or another suitable public index once available.
In D.07-01-030, the Commission adopted the Working Group's consensus for the 2007 RA/capacity adders of $7/MWh for SCE and SDG&E, and $4/MWh for PG&E. If a functioning and transparent capacity market or a suitable public index became available, the Working Group Parties agreed to recommend, for 2008 and beyond, a RA/capacity adder based on such a market or public index. Otherwise, Working Group Parties were to formulate the RA/capacity adder based on consensus until such market or public index becomes available.
Accordingly, we shall adopt SCE's proposal to update the RA capacity adder using the California Energy Commission's estimates of the going forward costs of a combustion turbine, which is updated biannually, including the Net Qualifying Capacity of all generation resources in the utility portfolio. Adopting this approach represent the most practical way to updatethe RA capacity value in the MPB.
3.3. CAISO Load-Based Costs
The total portfolio calculation currently includes certain CAISO load-related costs. No party disputes that the IOUs avoid load-related CAISO charges when load departs for DA service. Parties agree that all load-based CAISO costs that vary based on the amount of load should be excluded from the total portfolio and MPB calculation. The exclusion of such data will eliminate the need to calculate the reduction in load-related CAISO costs as load departs.
PG&E agreed that only CAISO load-related costs should be excluded from the total portfolio calculation instead of all CAISO charges because some of the charges are not load-related. PG&E originally proposed simply excluding all CAISO charges from the total portfolio calculation as an administratively simple approach to addressing this issue since it is difficult to determine exactly which CAISO charges are load-related.
SCE testified that the load-related subset is fairly easy to identify; thus, only load-related CAISO costs should be removed from the total portfolio costs in the interest of bundled service customer indifference. The Joint Parties entered into evidence a list of load-related CAISO charge types, which no party challenged.7
Currently the IOUs include forecasted CAISO costs in the ERRA proceeding for recovery in generation rates. These costs are also included in the Total Portfolio Cost for purposes of calculating the PCIA and CTC. The current methodology inappropriately treats avoidable CAISO costs as if they are unavoidable, above market utility generation-related costs. DA and DL customers thus pay for the CAISO costs associated with their load through their non-utility provider and also pay a share of bundled service customers' CAISO costs through the PCIA. The load-based costs of CAISO services should be removed from the Total Portfolio Cost for purposes of calculating the PCIA and CTC so that DA and DL customers don't pay more than necessary to maintain bundled customer indifference.
We thus conclude that all load-driven CAISO costs be excluded from the total portfolio calculation. It is not appropriate for ESPs to pay a share of the CAISO charges for bundled load when they pay the same charges for their own load. This is a cost that varies directly with the load served. Accordingly, we adopt the consensus recommendation that utility load-related CAISO charges be excluded from the total portfolio cost used in the indifference calculation.
We adopt the list of load-related CAISO charges identified by the Joint Parties in Exhibit 100, Appendix A, as constituting the pertinent charges to be excluded from the total portfolio and MPB calculation. Exclusion of CAISO congestion costs, including load-based congestion costs, from the IOUs' total portfolio costs is appropriate because these costs are also avoided when load departs for DA service.
3.4. Shaping Profile to Reflect MPB value of Portfolio Resources
Under the current method for calculating the indifference amount, the total portfolio reflects the profile of the underlying generation resources or contracts; however, the MPB calculation essentially reflects a flat load profile. Prices used in determining the MPB vary for on-peak and off-peak periods, but there is currently no weighting in the MPB to reflect variations in load shape by time-of-use (TOU) periods. The current MPB is thus based on an implicit assumption that the IOU supply portfolio serves a flatter load profile than it actually serves, creating an artificially low MPB value and artificially high Indifference Amount impacting the PCIA and CTC. Parties agree that the MPB methodology should be modified to reflect load shape variations by TOU period, but disagree on how to do so.
The Joint DA Parties propose a weighting that aligns the MPB with the load shape, to increase the weighting of the on-peak portion of the market price and lower the weighting of the off-peak price. Because the IOU supply portfolio is constructed to serve the load of bundled service customers as that load varies from hour-to-hour, the Joint DA Parties argue that the load profile of bundled service customers should be used as a weighting factor. The Joint DA Parties prefer use of the bundled load profile rather than the generation profile because the bundled load profile is more transparent. They argue that the public would have no way of validating the generation profile without access to the IOU's confidential system dispatch and production cost simulation model. The bundled load profile, on the other hand, they believe can be estimated using publicly available information.
PG&E agrees that the weighting factor should be modified, but rather than basing the weighting factor on bundled load data, PG&E proposes that the MPB weighting be based on the generation profile, consistent with the profile underlying the total portfolio cost. Since the MPB is used as a part of the indifference calculation to determine the combined production profile of generation in the utility's portfolio, PG&E and SCE argue that it should be weighted based on a generation portfolio. In addition, they believe a single weighting factor should be used for the MPB, rather then trying to develop a separate generation weighting for each vintage. Developing a single weighting factor would make calculating of the MPB administratively easier.
DRA argues that proposals to use either load or generating profiles would require use of confidential data, which is inconsistent with the objective of transparency. In response to DRA, SCE proposed to use historical bundled load profiles from prior calendar years to weight the MPB, because the historical data is not confidential. The bundled load profile is not expected to differ substantially from the generation output profile, and would therefore "serve as a reasonable and transparent alternative." The Joint Parties acknowledge that historical bundled load profiles are an acceptable alternative and could be used to derive a profile adjustment for the MPB. They concur that there appears to be little difference in the adjustment factor whether one uses the generation profile or the bundled load profile.
The proposals of the Joint Parties and the IOUs yield similar results for the peak and off peak weighting factors. The current weighting factors give significantly more weight to off-peak energy prices than do either the Joint Parties or IOU proposed weighting factors.
We conclude that the MPB should be weighted based on the historical IOU bundled load profile. In order to promote transparency, we shall direct that historical bundled load data be used, as suggested by SCE. The use of historical bundled load data will avoid the need to use confidential data, and will still promote reasonable accuracy. The use of such data will promote consistency with the load profile reflected in the total portfolio. Because SCE already makes historical bundled load profiles by rate group publicly available, as do the other IOUs, no additional calculations should be required for purposes of the MPB. The use of current generation profile data would involve confidential data, with the necessity for the Commission's Energy Division to validate the confidential data and calculations.
We shall not require a separate calculation of load shape for each vintage year as proposed by DRA. Otherwise, the IOU would have to run multiple calculations rather than just one. This difference would grow larger as the number of vintages increases. We conclude that there will be no significant variation in the load shapes adjustment from year to year and the extra analysis required to develop different profiles for different vintages is not likely to change the numbers sufficient to warrant the effort involved. Adoption of these modifications will cause the MPB to more accurately reflect the profile of the supply portfolio to more accurately measure bundled customer indifference.
3.5. Credit for Negative Indifference
CLECA/CMTA argue that bundled service ratepayers should pay DA-eligible customers departing for DA service when the indifference calculation results in a negative indifference amount. Under current rules adopted in D.06-07-030, DA customers cannot be paid by bundled customers if the indifference calculation shows that bundled customers are better off if DA or CCA load departs (i.e. negative indifference). Instead, if the indifference calculation results in an amount less than zero, the PCIA is set to the opposite of the CTC, resulting in an indifference amount of zero.
The difference between the PCIA that results from this calculation and the PCIA that would result from recognizing the value of negative indifference is carried forward. The benefit of this additional negative PCIA is not available to the DA customer until later in time. If a DA or CCA customer returns to bundled service, it would never get the value of this negative PCIA in rates.
CLECA/CMTA acknowledge that the negative indifference offsets future positive indifference, but complain that if a DA or CCA customer returns to bundled service, it would never get the value of this negative indifference. CLECA/CMTA find this result inequitable, arguing that departing customers should be able to be paid for leaving the system if this creates a benefit for remaining bundled customers. Under this circumstance, they should certainly not receive credit for energy or capacity or renewable attributes of the utility contracts
SCE opposes the CLECA/CMTA proposal, arguing that they bring forth no new evidence to support a change in policy on this issue.
We do not find sufficient basis to adopt the CLECA/CMTA proposal. This issue was previously considered and rejected in the Commission's adoption of an indifference methodology in D.06-07-030. CLECA/CMTA simply reargue for adoption of a policy previously rejected by the Commission in D.06-07-030. We find no new arguments that warrant a change in the treatment of negative indifference amounts that has been previously adopted.
3.6. Adjustment to Account for Congestion
The Joint Parties propose adjusting the MPB using a "basis adjustment" to account for congestion. PG&E agrees that CAISO load-related costs, which include congestion costs, should be excluded from the total portfolio cost calculation, but does not agree with the Joint Parties' proposal to increase the MPB by using an adder that compares prices at the NP 15 trading hub and default load aggregation point. PG&E states that congestion costs are
load-related. Since PG&E has already agreed to remove all CAISO load-related costs from the total portfolio calculation, PG&E contends there is no need to make an additional adjustment to address congestion costs.
The Joint Parties' proposal comparing trading hub and load aggregation point prices would capture both congestion and losses. However, the MPB already includes and adjustment for losses and thus PG&E argues that the Joint Parties' proposed adder would be duplicative
We agree with PG&E that there is no need to make a separate adjustment for congestion costs since we have already required the exclusion of CAISO load-related costs from the total portfolio calculation which includes congestion costs.
3.7. Setting a Zero Default PCIA Value
PG&E, SDG&E and Jan Reid propose that in the event PCIA is negative, the PCIA charge should be set to zero and any negative PCIA should only be used to offset positive PCIA in future periods, rather than first offsetting that year's CTC charges. The DA parties contend this would be a violation of the indifference standard and should be rejected.
In D.06-07-030, the Commission applied the indifference principle in addressing the calculation of CTC. Specifically, we required that bundled customers be indifferent due to customers migrating from bundled to DA load, and that there be no cost shifting. To prevent cost shifting, we adopted a methodology to capture the relevant costs in the form of a CRS to be assessed on designated DA load. The CRS incorporates, among other elements, a DWR power charge and the ongoing CTC.
The Indifference Amount is determined on a total portfolio basis in order to achieve bundled customer indifference. The Indifference Amount consists of two elements: CTC and PCIA. The CTC is determined first, and then the PCIA is determined on a residual basis: Equal to the difference between the indifference amount and the CTC. In D.06-07-030, the Commission modified the Indifference Amount calculation in part by allowing the PCIA to go negative up to the level of the Ongoing CTC. A negative PCIA would result when CTC is higher than the indifference amount.
PG&E argues, however, that this treatment is discriminatory whereby some customers (i.e., bundled and exempt departing load) are required to pay Ongoing CTC, while other customers (i.e., DA and CCA departing load) are effectively not required to pay Ongoing CTCs. These latter customers get an offset (credit) through the negative PCIA. Thus, in this situation, exempt and non-exempt customers are treated differently. In addition, a negative PCIA effectively results in increased ERRA costs, which bundled customers are required to pay. Thus, while non-exempt customers would be paying a net result that is zero or at least lower than the Ongoing CTC, bundled customer costs in ERRA would increase.
Under statutory law, and Commission precedent, all customers are required to pay Ongoing CTC. Thus, PG&E argues that the current Indifference Amount methodology is contrary to original legislative intent articulated in Public Utilities Code Section 367(a), and contrary the Commission's attempt to resolve the issue as articulated in D.05-12-045.
SDG&E agrees with PG&E that none of the changes to the MPB proposed for purposes of calculating the PCIA should apply in the context of calculating CTC. SDG&E does not believe that the revised MPB methodology should be used to determine CTC revenue requirements. The revision to the MPB methodology for determining the indifference amount is intended to provide a better estimation of bundled customer indifference. SG&E argues that this reasoning does not extend to the CTC revenue requirement determination.
PG&E proposes that if the Indifference Amount is less than the Ongoing CTC, the PCIA would be set to zero. All customers would then make the same contribution towards Ongoing CTC obligations, and the actual negative PCIA that would have resulted under the formula would be banked to offset potential positive PCIA in future years. PG&E argues that this modification will correct a logical flaw in the current indifference calculation and results in fair and equal treatment for all affected customers.
The current Indifference Amount is calculated as the sum of the Ongoing CTC and the PCIA. If the Indifference Amount is negative (i.e., the total portfolio costs are less than the market value of the portfolio), the Indifference Amount is set to zero.
The use of negative PCIA was first addressed in D.06-07-030, where the Commission stated that the PCIA component of DA CRS may be a negative number in those instances in which Ongoing CTC is larger than the indifference charge, so that overall indifference is maintained. The Commission addressed a similar issue in D.07-05-005, issued in response to a petition for modification filed by PG&E. PG&E argued that negative CRS amounts should not be carried-forward to offset positive CRS amounts. In D.07-05-005, the Commission rejected PG&E's proposed modification, finding that the proposed modification would not result in bundled customer indifference. We affirmed that in order to maintain indifference, both positive and negative indifference effects must still be tracked, with the negative amounts offsetting positive amounts.
In R.06-02-013, we examined how the indifference amount should be calculated with the inclusion of so-called "new world" generation resources. In that proceeding, PG&E advanced a proposal that would have resulted in a negative indifference element not being used to offset the CTC. PG&E proposed to calculate CRS elements separately, not allowing the netting and carrying forward of any negative amount associated with new world generation resources. We rejected PG&E's proposal in D.08-09-012, affirming the ongoing relevance of D.07-05-005 with respect to the principle of bundled customer indifference, and stating that "[w]hile the Commission's reasoning in [D.07-05-005] applied to the existing DA/Departing Load (DL) CRS calculations, the basic principles directly relate to handling of negative charges in this proceeding...." (D.08-09-012 at 47.) As previously concluded in D.07-05-005, we likewise concluded in D.08-09-012 that "[i]t is similarly necessary that negative indifference amounts be carried over for use in subsequent years to maintain bundled customer indifference. The total portfolio approach is consistent with this principle. PG&E's separate approach is not." (Id.) we expressly concluded in D.08-09-012 that the total portfolio approach allows CTC to be offset by other negative CRS elements.
Consistent with our prior review of similar proposals as noted in the above-referenced decisions, we find no basis to approve PG&E's proposed modification here. Bundled customer indifference is determined with reference to total portfolio costs, not isolated costs related to just the ERRA costs. PG&E's proposal would violate the bundled customer indifference principle by recognizing only the cost to bundled customers from using more above-market CTC resources, while not recognizing the offsetting benefit accruing to bundled customers from also using more below-market utility resources. Accordingly, we decline to adopt PG&E's proposed change in the treatment of CTC in the calculation of the Indifference Amount.
3 The net short is the difference between customer loads and the power already under contract to the utilities or generated from a utility-owned asset.
4 See SCE Rebuttal Testimony, at 12, citing DRA's February 11, 2011 Report, Green Rush, at 10, Figure 2.
5 The WREGIS is an independent renewable energy tracking system for the region covered by the Western Electricity Coordinating Council.
6 The Commission attached to its FERC comments a declaration from Aram Shumavon of the Energy Division stating that the RA capacity values were significantly below the CPM price
7 See Exh. 100, Appendix A.
