Photo of Sarah Kozal

Sarah Kozal is an associate in Stoel Rives’ Energy Development group.

Before joining Stoel Rives, Sarah was an associate with Western Energy & Water (2016-2018). While in law school, she interned at the California Independent System Operator (CAISO) and was a legal clerk and research assistant at several organizations and law firms in Southern California, including the Emmett Institute on Climate Change and the Environment. Sarah also served as a member of the Delegation of The Republic of Palau to the United Nations Framework Convention on Climate Change Conference of Parties in 2014 and 2015.

Prior to beginning her career as a lawyer, Sarah worked in museum education in Los Angeles, focusing on outreach to and programming for underserved student populations.

In a stakeholder call yesterday, the CAISO discussed the Revised Draft Final Proposal in the Generator Deliverability Assessment stakeholder initiative. During the call, the CAISO addressed outstanding stakeholder questions, including confirming key upcoming dates for project developers.

Background on the Proposal

The CAISO is proposing revisions to its deliverability assessment methodology in response to the rapid increase in the amount of solar resources and the California Public Utilities Commission’s (CPUC) resulting transition to an Effective Load Carrying Capability (ELCC) approach to calculating qualifying capacity (QC). The CAISO’s revisions are intended to more closely align the capacity studied in the deliverability assessment with the generator’s anticipated QC under the CPUC’s new ELCC methodology. Under the current deliverability assessment methodology, generators are studied at a higher capacity than the projects can qualify for under the ELCC methodology. Under the revised deliverability methodology, projects are expected to retain their full capacity deliverability status (FCDS) and their NQC value will not be reduced, but the proposed change should be beneficial to future interconnection customers because it will free up some unused deliverability and likely result in fewer required network upgrades to receive FCDS.

As part of the proposal the CAISO is also creating a new sub-status for solar and wind projects: Off-Peak Deliverability Status (OPDS). New solar and wind OPDS resources will receive market scheduling priority by continuing to be allowed to self-schedule as an incentive for resources to develop in locations that do not trigger upgrades or trigger only low-cost localized transmission upgrades.
Continue Reading CAISO Clarifies Generator Deliverability Assessment Proposal

On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the lower court’s decision in Winding Creek Solar LLC v. Peterman et al., ruling that California’s feed-in tariff for small qualifying facilities (QFs), the Renewable Market Adjusting Tariff (ReMAT), violates the federal Public Utility Regulatory Policies Act (PURPA) (Ninth Circuit Case No. 17-17531). ReMAT provides small QFs of three megawatts (MW) or less with a standard contract for energy offtake, on a first-come, first-served basis. Under ReMAT, rates available to any given generator fluctuate based on the price the developers ahead in the contract queue will accept. The California investor-owned utilities must offer ReMAT contracts up to a program cap of 750 MW, which is proportionately split among the utilities, and then further divided across different types of generation, including baseload and peak/non-peak resources.

The Ninth Circuit ruled that ReMAT violated two tenets of PURPA. Under PURPA, subject to certain exemptions, utilities are required to buy at the avoided cost rate all the power produced by a QF. First, contrary to PURPA’s requirement that a utility buy all of a QF’s output, the Ninth Circuit found that ReMAT limits the amount of energy that utilities are required to purchase from QFs by placing caps on procurement. Second, ReMAT sets a market-based rate for energy from participating QFs, rather than a price based on the utilities’ avoided cost as required under PURPA.
Continue Reading Ninth Circuit Strikes Down California ReMAT in Winding Creek Solar Case

The California Independent System Operator (CAISO) is accepting stakeholder comments until August 13, 2019 on its new Hybrid Resources Issue Paper, kicking off a stakeholder initiative expected to proceed until April 2020. Initial comments submitted now will help shape the direction of the initiative and potential market changes.

Though not exclusively limited to renewables + storage (the CAISO defines “hybrid” to mean any combination of multiple technologies or fuel types combined into a single resource with a single point of interconnection), the CAISO emphasizes the anticipated impacts of increased storage market penetration, including new operational and forecasting challenges,  as a driving force for the initiative. The CAISO has observed that the number of hybrid resource configurations seeking interconnection comprises approximately 41% of the CAISO’s Generator Interconnection Queue’s total capacity.Continue Reading CAISO Seeks Stakeholder Feedback on Hybrid Resource Market Participation

On April 25, the California Public Utilities Commission (“CPUC”) adopted a decision (“Decision”) in its Integrated Resource Plan (“IRP”) proceeding, R.16-02-007.

The Decision examined the first round of integrated resource plans filed by each of the load-serving entities subject to CPUC jurisdiction. The Decision approved the plans filed by 20 load-serving entities, found that another eight load-serving entities were not required to file integrated resource plans, and found that 19 plans were insufficient as they failed to address criteria pollutant issues. One load-serving entity—Commercial Energy of California, an energy service provider—failed to file an integrated resource plan at all. The Decision also provides specific guidance for plan development for each load-serving entity for the next IRP cycle.

CPUC staff also aggregated all of the resource plans into a single portfolio—after certain adjustments to render it feasible—defined as the Hybrid Conforming Portfolio, or HCP. Adjustments were necessary to ensure that the consolidated new resource procurement proposals did not exceed resource potential in a geographic area or existing transmission availability. Commission staff identified four regions where the proposed new wind resources exceeded assumed resource potential (Northern California, Solano, Southern California Desert, and Riverside East Palm Springs). Where resource potential was exceeded, staff adjusted the resources to come from nearby regions. There were also five regions where the proposed renewable buildout appeared to exceed assumed available transmission capacity (Central Valley North Los Banos, Greater Carrizo, Southern California Desert, Northern California, and Solano). Adjustments were made in these regions by converting the proposed projects to energy-only, or moving resources to nearby locations when transmission assumptions were exceeded. No resource selections for out-of-state resources that required transmission upgrades, however, were adjusted based on transmission limitations. The Decision requires load-serving entities to disclose the contractual and development status of their resource selections in future IRPs, in order to help avoid adjustment issues in the future, and to provide an updated filing with that information to the CPUC by August 16, 2019.
Continue Reading Recent California Public Utilities Commission Decision Charts Path Forward for its IRP Proceeding

The CAISO recently issued Part 2 of its Resource Adequacy Enhancements Straw Proposal and stakeholders met with the CAISO this week to discuss the paper and get further clarifications on the initial skeletal structure provided.

As part of the process, the CAISO reviewed the counting rules in other ISO/RTOs and found that most ISO/RTOs use

The 2019-2020 California Legislative Session has reached its first deadline.  February 22, 2019 marked the deadline by which bills could be introduced for the first half of the Legislative Session. Lawmakers will begin Spring Recess April 12 and reconvene April 22.  The last day for bills to be passed out of the house of origin is May 31, 2019.

Below is a list of some of the key bills Stoel Rives’ Energy Team will be monitoring throughout the Legislative Session.  We note that some bills do not contain language beyond the “intent of the Legislature.”  However, we will continue to monitor these bills in case of substantive amendments.  These bills are set forth separately below under the heading “Legislative Intent.”

The majority of the bills introduced this Legislative Session relate in some way to California’s efforts to reduce greenhouse gas emissions and move to cleaner sources of generation, including legislation governing electric vehicles, energy storage, and renewable energy.  A number of bills introduced in February also attempt to address the impacts of wildfires, or to reduce wildfire risk.


ASSEMBLY BILLS

AB 40 (Ting, D)   Zero-emission vehicles: comprehensive strategy.

Status: Introduced December 3, 2018; referred to Committees on Transportation and Natural Resources January 24, 2019.

AB 40 would require by no later than January 1, 2021, the State Air Resources Board to develop a comprehensive strategy to ensure that the sales of new motor vehicles and new light-duty trucks in the state have transitioned fully to zero-emission vehicles, as defined, by 2040, as specified.
Continue Reading Key Energy Related Bills Introduced in the 2019-2020 Legislative Session

FERC approved new changes to the CAISO tariff on February 19, 2019, with a retroactive effective date of November 27, 2018, that will impact projects in the CAISO’s generator interconnection queue. These changes are the result of a several month stakeholder initiative to enhance the interconnection process and follow a history of reforms intended to

The CAISO is proposing several changes to the Resource Adequacy framework that will be relevant to generators both within and outside of California. CAISO is in the initial stages of developing their policy changes and it is a good time to voice concerns or offer suggestions before the changes are solidified.  We expect more than

The California Public Utilities Commission (“Commission”) voted recently to approve $768 million in expenditures for electric vehicle infrastructure programs proposed by the state’s three investor-owned utilities (“IOUs”). The programs are part of a directive of SB 350 that requires utilities to undertake transportation electrification activities.

Here is a brief overview of the approved programs:

  • Approved at $137 million, SDG&E’s program provides rebates to up to 60,000 residential customers that install Level 2 (“L2”) charging stations, which refer to electric vehicle supply equipment (“EVSE”) connected to a 240-volt outlet.
  • PG&E was approved for $22 million to install make-ready infrastructure to support 234 fast charging stations, as well as $236 million to support 6,500 medium- or heavy-duty EVs (like electric buses and trucks).
  • SCE similarly received approval for $343 million to install make-ready infrastructure to support 8,490 medium- or heavy-duty EVs.
  • In addition, the Commission approved $29.5 million for program evaluation.

Here is our analysis of what the Commission’s order means for the future of EVs and what the industry should be paying attention to:

In terms of charging technology, 150 kW fast charging and residential L2 are the minimum.

The Commission’s order emphasizes the need to use up-to-date technology to ensure some longevity for the investments. For example, in response to PG&E’s proposal for three levels of fast charging stations, the Commission directed the utility to forgo the lowest level and only install customer-side electric infrastructure necessary to support EVSE of 150kW or larger, approving a 25% contingency due to the increased cost of the faster chargers. Additionally, the Commission also noted that participants in rebate programs will be responsible for the full cost of proprietary made-to-order EVSE and make-ready infrastructure, since these are not scalable and may result in stranded assets should the manufacturer go out of business or change technology. In the case of SDG&E’s program, the Commission sided with the utility over concerns raised by stakeholders that Level 1 charging (which uses a standard household 120-volt outlet) is sufficient for residential purposes. SDG&E argued that the more advanced L2 will provide grid benefits by allowing for managed charging when paired with time-variable rates that reflect grid conditions. The Commission also noted the ability of these chargers to provide valuable data on patterns of charging.
Continue Reading California Approves $768 Million for EV Infrastructure

The Federal Energy Regulatory Commission’s (“FERC”) long-awaited Order 845 (Reform of Generator Interconnection Procedures and Agreements) was issued on April 19 after over two years of consideration of the issues. Order 845 is the first grid-wide major reform of FERC’s Generator Interconnection Procedures and Agreements since Order 2003 was issued 15 years ago.  Order 845 adopts reforms that are designed to address three goals: (1) improving certainty for interconnection customers, (2) promoting more informed interconnection decisions, and (3) enhancing the interconnection process.

Order 845 revises FERC’s pro forma Large Generator Interconnection Procedures (“LGIP”) and Large Generator Interconnection Agreement (“LGIA”) to recognize the changing landscape of technology and is intended to provide interconnection customers with new opportunities to interconnect their projects faster and more cost-effectively.  For example, transmission providers must now allow interconnection customers (at the interconnection customer’s option) to build the needed transmission owner interconnection facilities and stand-alone network upgrades in all cases. Previously, interconnection customers only had this option if the transmission owner could not meet the dates proposed by the interconnection customer.  Thus, an interconnection customer has newly granted flexibility in the construction of the transmission owner interconnection facilities and stand-alone network upgrades. If the transmission owner returns a high cost estimate, then the interconnection customer can manage the construction of the transmission owner interconnection facilities. On the other hand, if the transmission owner cost estimate is reasonable, the interconnection customer can choose to leave the construction responsibilities for the transmission owner interconnection facilities and stand-alone network upgrade with the transmission owner. Interconnection customers can now make these decisions based on both timing and cost considerations.Continue Reading Helping the Hook-Up: FERC’s Generator Interconnection Procedures Reform Seeks to Improve Information Flow, Recognizes Changing Technology and Opens Further Opportunities for Storage