The ISO Flexible Capacity Procurement Proposal
The ISO submitted a proposal related to flexible capacity procurement at the January 26-27, 2012 RA workshop, with a revised version filed on March 2, 2012. The ISO presented another version of the proposal at the March 30, 2012 workshop, which it outlined in its April 11, 2012 reply comments.
In its comments the ISO contends that increasing renewable energy generation will displace conventional flexible generation, thus putting conventional resources at risk of retirement. The ISO explains that without RA contracts, existing flexible resources may not receive sufficient revenues from the energy and ancillary service markets to remain economically viable. The ISO asserts that there is a real operational need for the flexibility conventional resources provide, especially during critical ramping periods and thus, the RA program must ensure that these flexible resources remain economically viable and available to the ISO to maintain system reliability and to minimize the need for procurement through the ISO backstop procurement mechanism. The ISO also states that if retirement of all planned OTC resources were to occur, insufficient flexibility will occur potentially as early as 2018.
The ISO proposes that the Commission adopt three new categories of flexible capacity in the RA proceeding: regulation, load following capability, and maximum ramping. Regulation is the capability of a generating unit to respond to four-second signals from the ISO to adjust its output to balance the system. Load following capability is the capability of generating units to respond to the ISO's five-minute dispatch instructions to balance load and generation. Maximum ramping needs reflect the flexibility needs to ensure the longest continuous net load ramp can be achieved by the fleet.
As noted by several parties in comments, more discussion is required to translate these three proposed flexible capacity categories into an explicit RA requirement and load-serving entity procurement terms. To that end, the ISO is no longer requesting that the Commission impose a mandatory flexible capacity requirement for the 2013 compliance year. Instead, the ISO is asking the Commission to adopt the ISO's three flexible capacity categories as a framework for 2013, including the methodology for how the three flexible capacity categories are calculated. With this framework in place as advisory targets in 2013, the ISO recommends a separate phase of the RA proceeding (or a new Rulemaking) to study and further refine how to integrate a flexible capacity requirement into the resource adequacy program for 2014 compliance.
Discussion
No party disputes that grid operations and reliability may suffer without sufficient generation capable of being flexibly dispatched. We agree that we need to define flexible attributes for local reliability purposes in order to ensure ongoing reliability in a changing load and supply environment. Both the ISO and Energy Division have presented worthwhile proposals intended to address, from different perspectives, the need for flexible capacity on the grid in order for the ISO to continue to operate the grid reliably as increasing levels of generation from renewable, often intermittent, sources of power are operational and generating electricity. We appreciate that both proposals involve a significant effort to proactively address the potential for reliability concerns in the coming years. We agree with parties that additional effort is needed, and we thank the parties for their efforts to refine these proposals and identify questions to be answered before they can be implemented.
Although the objectives of both proposals are similar, there are significant differences in the approach proposed by the ISO and Energy Division. The following chart summarizes the major differences in approach:
Comparison of ISO and Energy Division Proposals
ISO |
Energy Division | |
General Concept |
seeks active procurement of flexible resources |
limits procurement of |
Definition of Eligibility |
categorizes resources based on qualitative class (base load, intermittent etc.) |
categorizes eligible units based on operational characteristics (ramp rate, startup time etc.) |
Compliance Metric |
quantifies amount of flexibility a resource can provide by computing Maximum Continuous Ramping and Load Following, which varies every month, |
relies on net qualifying capacity (NQC) values |
Definition of Flexibility |
a bundle of characteristics, which varies, based on the needs the grid is trying to manage at a particular interval |
defines "flexibility" uniformly for all intervals with quantitative metrics. |
Procurement Requirements |
defines procurement requirements based on extreme cases from actual operating history |
defines procurement requirements based on analysis of "typical" or "expected" needs based on actual historical events |
Many of the active parties commented on either or both of the ISO and Energy Division proposals. In general, while many parties praised both proposals for their significant efforts to address changing local reliability needs, nearly all parties found one or both proposals to be incomplete. Some parties recommend tentative steps to move forward with one or the other proposal. For example, GenOn recommends adopting the ISO proposal with modifications, but not the Energy Division proposal. CEERT Technology supports the Energy Division proposal subject to ISO revision. DRA recommends adoption of the Energy Division proposal for a trial in 2013. However, many parties called for the Commission to not adopt either proposal at this time.
Parties raised several concerns about the Energy Division proposal. PG&E contends that the proposal lacked a clear methodology to determine the size of the buckets, or to determine how these buckets should change in the future as more intermittent generation is added to the system. The ISO argues that the Energy Division's approach of limiting the amount of non-flexible resources does not ensure provision of sufficient flexible resources and could also lead to a portfolio of RA resources that is not as durable as the fleet becomes more variable. The ISO further asserts that a significant deficiency in the Energy Division's proposal is that it does not adequately address intra-hour variability or capture the very short term changes in wind and solar generation.
Parties also raised a number of concerns about the ISO proposal. NRG argues that certain aspects of the ISO's proposal warrants further clarification, discussion and refinement, such as whether hydro resources are dispatchable, and whether resources that provide flexibility can be self-scheduled in the ISO's markets. SCE contends that the ISO has not defined how much of a particular attribute each resource would count for and thus how much capacity a generator has to sell and this aspect had to be transparent if the ISO's proposal is going to be commercially viable. In reply comments, the ISO concedes that more discussion is required to translate these flexible categories into procurement requirements.
We agree with Energy Division, the ISO and all parties that there is no immediate need to impose flexibility requirements in 2013. However, we must take steps to ensure that the grid has sufficient flexible resources in the future. TURN echoes the sentiments of most parties in its comments: "(t)he Commission can reasonably defer implementing any flexible capacity requirement beyond the 2013 RA compliance year. However...the Commission should begin addressing possible flexible capacity needs and policies in the very near future with the goal of assessing if such requirements should be imposed for the 2014 RA compliance year."
We will immediately begin the effort to finalize a framework for filling flexible capacity needs in this proceeding. Our intent is to adopt a framework by or near the end of 2012, for implementation in the 2014 RA compliance year. We will also coordinate our efforts in this proceeding with those in the LTPP proceeding. The Scoping Memo in the LTPP proceeding foresees a Commission decision by or near the end of 2012 potentially allowing or requiring utilities and/or other LSEs to procure for local reliability needs. The flexible needs framework we expect to adopt in this proceeding could potentially be used for subsequent Request for Offers to fulfill procurement determined in the LTPP proceeding.
At this time, we will provide direction to allow parties to build upon the efforts to date of the ISO and the Energy Division. We agree with SCE's comments on this point: "For a structure to remain commercially viable, we should strive to find the simplest definition of `flexibility' possible that will provide the CAISO a reliable grid." SCE continues: "Otherwise, we risk making capacity procurement unnecessarily difficult and costly, and the marginal reliability benefits of a complex vs. simple definition of `flexibility' will be too expensive to rationally justify."
With the goal of ensuring reliability without undue complexity in mind, parties should work towards clearly defining flexibility in terms of specific operational characteristics of generators that the Commission should consider when authorizing new generation. Specifically, parties should consider:
· whether flexibility should be defined variably in intervals or if a consistent definition is more appropriate;
· whether flexibility should be based on essential key characteristics or if a broad definition better serves the purpose; and
· whether flexibility should be defined as a choice between operational characteristics such as magnitude of need, speed of response and contractual availability.
The ALJ and/or assigned Commissioner will provide more detail on the process to be used in this proceeding to be considered by the Commission in a decision in time for the 2014 compliance year.
After such a decision, the next step would be the implementation details of incorporating flexible capacity in the RA program. This could include vetting a clear methodology on how flexibility needs would be calculated annually; which generation would be considered flexible under the adopted definitions; how flexibility would be accounted for; how costs would be allocated for flexible resources; and how all of this would affect procurement and contracting. Parties could examine how these requirements would affect market prices for flexible and inflexible capacity. We agree with Shell's comment that parties should address the current and future need for these flexible procurement obligations, the specific resource characteristics that are sought, the classification of generation facilities in each resource category, and implementation details for the adopted approach.
As we are not adopting either the Energy Division new MCC buckets proposal or the ISO's flexible capacity proposal at this time, we look to the Energy Division's default proposal to update MCC buckets and implement a new demand response MCC bucket at this time. This proposal, from the January workshops, updates the load duration shapes that were used to determine the four buckets in 2005, which are still in use. The proposed update uses 2009, 2010 and 2011 data to create new load duration curves. In addition, the default proposal creates the new demand response bucket ordered by the Commission in D.11-10-003. We will adopt the Energy Division proposal to update the percentages used for the MCC buckets to reflect more current load shapes, and to add a bucket specifically for Demand Response resources as modified below, Energy Division shall implement this via the RA template.
In comments on the Proposed Decision, Energy Division default SCE points out that existing DR allocations amount to nearly the entire MW capacity limit in the DR bucket, and that several DR programs can operate at more than twice the
12 hour limit set for the DR bucket. SCE proposes that the 5.7% limit on the Demand Response bucket, as contained in the Energy Division's default proposal, be revised upwards.
IREC's comments on the Proposed Decision point out that although the Energy Division proposal explicitly included a place for CHP and storage, the default proposal does not specifically list storage as a resource for RA.
We modify the Proposed Decision to resolve the issues SCE and IREC point out. First, we determine that all existing programs can operate at a minimum of 16 hours in the month, and when that limit is compared to load duration curves, the limit on the DR bucket is may be larger. We require Energy Division to discuss this change in the upcoming 2013 RA Guide and set percentages so as to ensure that load impacts from all existing event based DR programs continue to count towards RA obligations. For example, with 16 hours of availability in a month, the maximum cumulative capacity would imply a limit of 6.7%; a final number will be calculated by Energy Division after workshops. In addition, the existing buckets are constructed based on hours of availability, not resource type. DR programs that are available for more hours may fit into other buckets, and thus not be limited by the percentage applied to the DR bucket.
Second, to resolve the concerns presented by IREC with regards to storage facilities and QC calculations, we point out that the existing QC counting methodology2 differentiates in general between three classes of resources in setting QC - dispatchable resources, non-dispatchable resources, and wind/solar resources. Storage is not called out specifically, but depending on whether it was dispatchable or non-dispatchable, storage would count towards RA obligations under the existing QC methodology.
The coincident adjustment factor is a number calculated by comparison of total aggregate LSE peak load forecasts and the coincident ISO peak load, in order to make each LSE's peak load forecast reflective of the LSE's contribution to load at the time of ISO's peak load. This factor is used in determining RA obligations by adjusting individual LSE peak forecasts for the fact that each LSE may or may not peak at the time of the ISO's coincident peak.
D.05-10-042 adopted the current coincident adjustment methodology, which uses an average coincident adjustment factor to take advantage of the pooling effect; that is, using an average factor partially balances out the fact that LSEs serve diverse customer classes. This methodology uses historical coincident factors and the same coincident adjustment factor for all LSEs. The Commission adopted this method because "averaging is more stable and easier to calculate, monitor, and apply."3 LSEs have both coincident demand (the level of an LSE's demand at the time of system peak demand) and non-coincident load (the peak level of demand for the customers of that LSE, which may not occur at the time of system peak demand). Per D.05-10-042, each LSE's non-coincidental monthly demand is reduced by a factor that reflects the average load diversity in the ISO's control area in that month.4 This adjusted demand level is the basis for each LSE's RA obligations.
Historically, all customers were required to take all power from the monopoly IOUs. In the 1990s, customers were allowed to take power from other electric service providers (ESPs), a service known as Direct Access. Direct Access was suspended in the early 2000s, due to adverse market conditions. However, existing Direct Access customers were "grandfathered" into their then-current contracts with ESPs. Direct Access reopened in 2010 under defined circumstances5 for commercial and industrial customers, who again were allowed to begin migrating from their current ESP to another ESP.
In R.09-10-032, Alliance for Retail Energy Markets proposed changing the coincident adjustment factor. Instead of using a system average approach as adopted in D.05-10-042, AReM proposed using an approach that is more specific to classes or types of LSEs. Specifically, AReM proposes developing three or more LSE load profiles categories:
1. LSEs serving all customers;
2. LSEs serving commercial and industrial customers only; and
3. LSEs serving only residential and small commercial customers.
Each LSE would be assigned to the load profile category that most closely reflects their particular profile of customers. Based on the load profile categories the California Energy Commission (CEC) would establish three average coincident adjustment factors and apply the adjustment factor to the LSEs associated with each category.
AReM argued that since ESPs serve mainly commercial and industrial customers, the current system average approach competitively disadvantages the ESPs, compared to other LSEs, and shifts costs to Direct Access customers. This is because IOUs have an obligation to serve all customers, while ESPs do not. Thus, according to AReM, using the averaging approach allocates more RA costs to some ESPs and fewer costs to IOUs than if RA costs were allocated based on which customers are actually served by that entity.
Additionally, AReM contended that the re-opening of Direct Access adds to the problem because "since the market re-opening, ESPs have added commercial and industrial load, thereby increasing the `peakiness' of [IOU] loads that have lost commercial and industrial customers. However because each LSE's RA requirement is calculated using the single, system average coincident adjustment factor, the additional `peakiness' present in other LSE's load profiles, since market re-opening, is not appropriately reflected in their RA capacity obligations."
In D.11-06-022 at 17, we stated:
We are committed to greater cost transparency and cost allocation based on cost causation for the RA program. All customer classes should be aware of the costs unique to the "peakiness" of that particular customer class, and all LSEs should face costs consistent with cost causation. An average coincidence factor across all customer classes hides certain cost differences among classes and LSEs. In essence, this method serves as a cross subsidy from industrial and commercial customers to residential customers.
Nevertheless, we will not adopt AReM's proposal at this time. We agree that there is significant technical analysis which remains to be produced before this proposal can be implemented. We request Energy Division and CEC staff to work to refine this concept over the course of the next year and provide a recommendation to the Commission in next year's RA proceeding for further consideration and possible implementation in 2013.
AReM states that it has now developed a modified proposal in consultation with the CEC, as discussed in workshops in last year's RA proceeding and in the January 26, 2012 workshop in this proceeding. AReM's proposal (as refined by the CEC) includes two main components: 1) A calculation to determine the applicable coincidence adjustment factor to apply for the annual RA obligations; and 2) a calculation to determine the applicable coincidence adjustment factor to apply for the monthly RA obligations, as follows:
Annual RA Requirements - The CEC would calculate a
LSE-specific coincidence adjustment factor using LSE hourly loads as described in the CEC's January 26th workshop presentation.Monthly RA Requirements - The CEC would calculate an ESP composite coincidence factor, which would be applied to each ESP's migrating load for the month; migrating load for community choice aggregators would be treated separately.
DRA generally supports the principle whereby all LSEs should face costs consistent with cost causation. However, DRA believes that additional determinations and analysis of the appropriate customer categories of coincident adjustment factor are required before implementation, and therefore opposes making changes at this time. PG&E recommends the Commission not adopt the AReM proposal at this time. PG&E suggests the Commission may want to consider changing the allocation of load diversity after incorporating flexible capacity requirements. SCE agree with PG&E.
Discussion
D.05-12-042 adopted the average coincidence factor adjustment in 2005 partially due to administrative simplicity and overall fairness. Since 2005, conditions have changed. The argument for simplicity is no longer valid. The CEC currently does not use an average coincidence factor in developing forecasts in its Integrated Energy Policy Report process, but instead applies a coincidence factor to each type of load class based on analysis and determinations supporting greater accuracy. The CEC uses a different coincidence factor to determine LSE specific loads. Harmonizing the two coincidence factors would promote greater simplicity, as well as improve cost allocation related to cost causation. Coincidence factors for bundled customers served by IOUs and ESPs are estimated separately, taking into account the customer mix of ESPs versus IOUs, and the restriction on residential load migration.6
The average coincident factor method is also inconsistent with methods used to develop a bundled customer forecast in support of the Commission's long-term procurement process. In both RA and long-term procurement proceedings, the Commission has determined that the adopted CEC forecast is to serve as the reference case. The CEC also provides LSE-specific coincidence adjustments to each California LSE which is outside of the Commission's jurisdiction for LSEs' use in ISO RA compliance filings. Adopting an
LSE-specific methodology for RA would harmonize the long-term procurement process and RA procurement process, as well as improve cost allocation related to cost causation.
As we stated last year in D.11-06-022 at 16-17:
While changes to the coincident adjustment factor would not directly change the overall distribution of customers among all LSEs, it would change the allocation of costs among LSEs. It is possible that more accurate reflection of cost drivers for different LSEs would increase the incentive for some customers to migrate from IOUs to ESPs, as ESPs' costs decrease and IOUs' costs increase. However, there is no data showing this would be a significant factor. Further, current Direct Access rules provide very limited ability currently for customers to move between IOUs and ESPs. Therefore, any changes in cost allocation resulting from changes to the coincident adjustment factor would appear to be minimal.
We now have more information about how AReM's proposal would work, and specific implementation data from the CEC to make it work. We will adopt the coincident adjustment factor methodology for Annual RA and Monthly RA proposed by AReM with CEC input, as specified in the Ordering Paragraph. After considerable discussion among parties in the RA workshops this year and last and in subsequent filings, there is sufficient record to adopt this proposal. The concerns of DRA, SCE and PG&E are non-specific; any implementation issues can be addressed in future RA proceedings if necessary.
2 The adopted QC manual is available on the following page of the CPUC website: http://www.cpuc.ca.gov/PUC/energy/Procurement/RA/ra_compliance_materials.htm.
3 D.05-10-042 at 38.
4 Id.
5 See D.10-03-022, implementing Senate Bill 695 (Stats. 2009, ch. 377).
6 See http://www.energy.ca.gov/2009publications/CEC-200-2009-012/CEC-200-2009-012-CMF.PDF at 51.
