On April 5, 2012, the California Public Utilities Commission (CPUC) issued a proposal that, if adopted, will dramatically change the way utilities purchase renewable energy in California. The ruling, authored by CPUC Commissioner Mark Ferron as part of the 2012 Renewables Portfolio Standard (RPS) Procurement proceeding, proposes to increase substantially the role of transmission planning in renewable procurement, thereby prioritizing those projects sited near existing transmission facilities with available capacity ahead of those not sited near existing facilities or those near facilities requiring substantial transmission system upgrades. The proposal also provides a new formula for quantifying a project’s value, including its potential positive impact on grid operation (through provision of “ancillary services”) or negative cost impact (due to intermittent output). The ruling is not yet final, and parties will have an opportunity to provide comments on the proposal and on the utilities’ RPS Procurement Plans.
Historically, development of electricity transmission lines and facilities in California has occurred primarily in a bottom-up fashion: energy project developers choose where to site their projects, and then (hopefully) transmission follows. The need to build renewable generation where the wind blows, the sun shines or geothermal resources are accessible has exposed weaknesses in the “if you build-it”-transmission-will-come paradigm. The problem has been compounded by a glut of renewable energy projects requesting grid interconnection; the capacity of the renewable projects currently in the California Independent System Operator (CAISO) interconnection queue exceed California’s entire forecasted load in 2020 and, thus, far exceed the amount of new capacity needed for the investor-owned utilities (IOUs) and other load-serving entities (LSEs) to meet their 33 percent renewable obligation by 2020.
Recognizing that most of these proposed renewable projects will never be built, the CPUC and the CAISO wish to promote development of cost-effective and location-appropriate transmission first and encourage renewable resources to develop near existing and proposed transmission.1 The overall objective of these efforts is to save money for ratepayers; the CAISO has estimated RPS transmission infrastructure costs will be about $7.2 Billion.2 The CPUC and CAISO proceedings that relate to integrated planning include:
Limiting RPS Procurement to Avoid Triggering Costly Network Upgrades
Delivery network upgrades are required where the existing transmission system is not robust enough to ensure that the full capacity of the new resource is deliverable under peak demand conditions. Utilities generally prefer renewable resources that can meet the CAISO’s full-capacity deliverability requirements so they can count those resources towards their CPUC-mandated Resource Adequacy (RA) requirements. Given the large number of projects in the CAISO’s interconnection queue, many of the proposed projects required costly delivery network upgrades that would ultimately be borne by ratepayers. Accordingly, the CAISO has adapted its procedures to ensure that transmission build-out focuses on high value projects, which will avoid triggering expensive delivery network upgrades.3 Full deliverability transmission rights will be granted only to a limited amount of capacity that falls below the upgrade-triggering thresholds.
The CPUC is now following suit. Commissioner Ferron’s ruling provides a series of proposals “to limit the total volume of power purchase agreements executed by the IOUs to projects of high value and viability without triggering unnecessary reliability or deliverability upgrades.” To do this, the Commission would limit the total capacity of RPS procurement to the CAISO-determined threshold for each geographic area. If the IOUs collectively proposed to procure more than this threshold, the Commission will determine which projects’ contracts can be approved based on project need, viability and value.
Along with changes in the CAISO Transmission Planning Process, the CPUC’s proposal may increase the attractiveness of energy-only contracts; i.e., contracts under which the generator cannot guarantee that its full capacity can be made available to load under peak demand conditions. Such projects avoid triggering deliverability network upgrades and thus reduce interconnection costs. Although such projects cannot usually be relied upon to meet the IOUs’ RA requirements, the glut of renewable procurement in recent years has made RA a decreasing concern for utilities.
New Reliance on CAISO Interconnection Cost Estimates
To calculate transmission network upgrade costs, each IOU has traditionally relied on its own Transmission Ranking Cost Report (TRCR), which approximates a project’s transmission looking at the total network upgrades required for renewable generation connecting to a single substation and allocating these costs proportionally among the projects in the cluster. These estimates have historically been less accurate than the project-specific transmission cost estimates included in the CAISO studies. Commissioner Ferron’s ruling now proposes to require utilities to instead incorporate a project’s transmission costs as identified in CAISO Generation Interconnection Procedure (GIP) studies (or their equivalent) into the IOU's Least-Cost, Best-Fit (LCBF) analysis, when available.
Notably, although this proposal will result in more accurate bid estimates for projects that are directly interconnecting to the CAISO’s system, the proposal provides no guidance for RPS-eligible projects with proposed interconnection into a neighboring balancing authority area with differing cost calculation and allocation methods for a project’s transmission costs. Under SB1X 2, enacted last year, the output of any renewable generators that interconnects to a “California Balancing Authority Area” (CA BAA) or is dynamically transferred to a CA BAA can be counted toward RPS requirements. Numerous valuable RPS eligible projects can connect directly into one of the four CA BAAs other than the CAISO.4 For efficiency reasons, both IOUs and generators interconnecting into other CA BAAs have an incentive to make sure these RPS eligible projects are not unfairly disadvantaged. The draft RPS compliance plans filed by the utilities may address how such projects will be evaluated, and parties to the CPUC proceeding may comment on the plans.
Requiring Interconnection Progress Before Securing Approval of the Power Purchase Agreement
Commissioner Ferron proposes to limit contract approval of renewable projects to those that have met certain milestones in the interconnection process — either completion of the GIP Phase II interconnection study (or its equivalent)5 or execution of a generator interconnection agreement. The decision further proposes a new 12-month holding period between when a project gets shortlisted by an IOU and when the Power Purchase Agreement (PPA) must be submitted for Commission approval. The net effect of these proposals is that projects, once shortlisted, have one year to: (1) obtain GIP Phase II Study results (or equivalent) or secure an interconnection agreement, and (2) execute a PPA. Projects that fail to do so would be removed from the shortlist, and the IOU would not be permitted to negotiate bilaterally with that project. Rather, the project would have to wait for the next RPS procurement cycle.6
New Least-Cost, Best-Fit (LCBF) Metrics
The traditional Commission approach to RPS procurement has been one of “flexibility and accountability,” which has allowed IOUs to reach RPS program goals subject only to certain compliance criteria.7 Accordingly, subject to certain limitations, the Commission has conditionally accepted the IOUs’ RPS procurement plans, each of which has employed different metrics in performing the LCBF analysis for potential projects. In contrast, Commissioner Ferron’s proposal prescribes a new “net market value metric” that an IOU would be required to include in its LCBF analysis. Such a proposal is evidence of a shift toward more centralized control of the RPS procurement process by the CPUC. The formula provides:
Adjusted Net Market Value = (Energy Value) + (Capacity Value) + (Ancillary Services Value) - (PPA Price) - (Transmission Network Upgrade Costs) - (Congestion Costs) - (Integration Costs)
Impact of Integration Costs and Ancillary Services Benefits Recognized
Intermittent resources — such as solar photovoltaic (PV) and wind — trigger additional costs for ratepayers given the need to firm their output with other resources that can be ramped up or down output. The new ruling proposes to require IOUs to include a quantitative value for such “integration costs” of certain renewable resources as one variable in the net market value calculation. The Commission has denied previous IOU efforts to include non-zero integration adders in their LCBF analyses, having previously found RPS integration costs to be negligible.8 The ruling does not describe how integration costs for any particular resource should be calculated. However, the CAISO 33 percent Renewable Integration Study is scheduled for release later this year as part of its stakeholder proceeding regarding Integration of Renewable Resources and may provide the basis for this valuation.
In a related vein, Commissioner Ferron’s ruling also seeks to require IOUs to quantify the Ancillary Services Value of an RPS-eligible project. Ancillary services are the ability of flexible generation resources to increase or decrease project output based on directions from the grid operator due to fluctuations in energy demand. The Commission has not indicated how it expects to calculate the ancillary services adder in the Adjusted Net Market Value equation although the IOUs do have experience calculating this metric.
These new metrics are likely to benefit geothermal projects as well as solar thermal projects while creating a relative market disadvantage for projects utilizing wind, solar PV and solar thermal without storage. Both geothermal and solar thermal with storage provide steady outputs, thereby minimizing integration costs. Additionally, solar thermal projects with storage can provide ancillary services to the grid.
Capacity Value May Be Revisited
Although capacity value has long been a factor in making LCBF determinations, how capacity values are calculated may well be revisited as a result of their inclusion in the Adjusted Net Market Value calculation. Capacity value is a measure of how reliably a resource will generate energy during periods of highest demand. Solar thermal projects with storage and geothermal resources will have higher capacity values than intermittent resources such as wind, solar thermal without storage and solar PV.9 Several pending proceedings both the CAISO and CPUC Energy Division have proposed new resource adequacy requirements to ensure that there are adequate flexible capacity resources available for the CAISO to dispatch in order to meet system needs. Inclusion of capacity value into the net market value calculation may therefore create relative market advantages for renewable technologies, which can help meet system needs for flexible capacity resources.
Commissioner Ferron’s ruling invites comments on the new approaches outlined above and sets out a timetable for their submission. It also lays out a schedule for submission by the IOUs of their RPS Procurement Plans and a timetable for the Commission reaching a final decision. That schedule is detailed below:
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1 In addition, state and federal agencies have undertaken efforts to coordinate large-scale renewable energy and related transmission facilities in California’s deserts and other areas in the West. Most notably, these efforts include: (1) development of the Desert Renewable Energy Conservation Plan by state and federal agencies; and (2) drafting of the Solar Energy Development Programmatic Environmental Impact Statement for projects in six western by the U.S. Department of Energy and the Department of the Interior, Bureau of Land Management.
2 Neil Millar, CAISO Executive Director, Infrastructure Development, “Decision on the 2011/2012 ISO Transmission Plan” at 7 (presentation by given at the CAISO Board of Governors Meeting, General Session, March 22-23, 2012) (available at http://www.caiso.com/Documents/Decision2011-12TransmissionPlan-Presentation-Mar2012.pdf).
3See CAISO Jan. 31, 2012, Technical Bulletin: “Generator Interconnection Procedures: Deliverability Requirements for Clusters 1-4"
4The other four CA BAAs include: Los Angeles Department of Water and Power, Balancing Authority of Northern California (formerly Sacramento Municipal Utility District), Imperial Irrigation District, and Turlock Irrigation District.
5Equivalent studies include Facilities Studies and Fast Track screens for distribution level interconnections and projects receiving equivalent studies for interconnection into non-CAISO systems.
6This process differs substantially from the prior procurement process in which: (a) there was no set-holding period or deadline for PPA approval, (b) parties were not prohibited from negotiating bilaterally if the shortlist process did not yield an approvable PPA, and (c) there was no requirement that interconnection process be demonstrated.
7D. 09-06-018 (Decision conditionally accepting the 2009 IOU RPS procurement Plans).
8See, e.g., D. 11-04-030, “Decision Conditionally Accepting 2011 Renewables Portfolio Standards Procurement Plans and Integrated Resource Plan Supplements” (April 14, 2011), finding that renewable integration costs were negligible and that adders should only be used if developed and considered in a public forum. The Commission did not consider integration cost adders in its rulemaking proceeding to “Integrate and Refine Procurement Policies and Consider Long-Term Procurement Plans” (Rulemaking 10-05-006).
9See National Renewable Energy Laboratories (NREL)Western Wind and Solar Integration Study (May 2010) at p. 308, noting that the capacity value of wind generation tends falls in the 10 percent -15 percent range, the capacity value of photoelectric generation falls in the 25 percent - 30 percent range, and the capacity value of concentrated solar thermal with storage falls in the 90 percent - 95 percent range.
This article was originally published by Bingham McCutchen LLP.