Recent California Public Utilities Commission Decision Charts Path Forward for its IRP Proceeding

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

FERC Reaffirms Concurrent Jurisdiction Over PPAs in Bankruptcy

The Federal Energy Regulatory Commission (“FERC” or the “Commission”) issued an order on May 1, 2019 denying rehearing of its orders asserting concurrent jurisdiction with a bankruptcy court over wholesale power contracts.

In January, prior to Pacific Gas & Electric (“PG&E”) filing for bankruptcy, NextEra Energy, Inc. and Exelon Corporation both filed complaints and petitions for declaratory orders from FERC, requesting that the Commission find that PG&E could not abrogate, amend, or reject in a bankruptcy proceeding any rates, terms, and conditions of its FERC-jurisdictional wholesale power contracts without first obtaining approval from the Commission.  The Commission quickly issued a brief order holding that a party to a FERC-jurisdictional wholesale power contract must obtain approval from both the bankruptcy court and the Commission  to reject a contract and modify the filed rate, respectively.  PG&E then filed its petition for bankruptcy and initiated an adversarial proceeding against FERC, requesting preliminary and injunctive relief.  That matter has continued to play out in the Northern District of California and there has not yet been a resolution by the bankruptcy court.  Meanwhile, PG&E requested rehearing of the Commission’s decision.  The Commission’s order on rehearing offers a more in-depth analysis of its jurisdiction.

The order first highlights the distinct roles that FERC and a bankruptcy court play in evaluating wholesale power contracts.  While FERC’s role is to protect the public interest, the bankruptcy court’s role is to provide a path to rehabilitate debtors.  The Commission held that the existence of bankruptcy proceedings does not alter its obligation, and exclusive authorization, to consider whether wholesale rates are just and reasonable.  Continue Reading

Electric Vehicles and Zero Emission Transportation Related Bills Introduced in the 2019-2020 Legislative Session

February 22, 2019 marked the deadline by which bills could be introduced for the first half of the 2019-2020 California Legislative Session.  More than 1,800 Assembly Bills and nearly 800 Senate bills were introduced; among them, legislation focused on the electrification of vehicles and the infrastructure for charging them.

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

Key Upcoming Dates:  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.

AB 40 (Ting, D)   Zero-emission vehicles: comprehensive strategy.
Status: Introduced December 3, 2018; referred to Assembly Committees on Transportation and Natural Resources January 24, 2019.
AB 40 would require by no later than January 1, 2021, the California Air Resources Board (CARB) 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.

AB 753 (Garcia, D)  alternative and Renewable Fuel and Vehicle Technology Program: fuels: fueling infrastructure.
Status:  Introduced February 19, 2019; referred to Assembly Committee on Transportation February 28, 2019
Existing law establishes the California Alternative and Renewable Fuel, Vehicle Technology, Clean Air, and Carbon Reduction Act of 2007, which includes the Alternative and Renewable Fuel and Vehicle Technology Program, administered by the State Energy Resources Conservation and Development Commission (Energy Commission), and the Air Quality Improvement Program, administered by CARB.

This bill would require the Energy Commission to make available at least 30 percent of the moneys available for allocation as part of the Alternative and Renewable Fuel and Vehicle Technology Program for projects to produce alternative and renewable low-carbon fuels in the state, as specified, and projects to develop stand-alone alternative and renewable fuel infrastructure, fueling stations, and equipment, as specified. Continue Reading

California Public Utilities Commission Opens Rulemaking to Consider Expansion of Direct Access

At its March 14, 2019 voting meeting, the California Public Utilities Commission (“CPUC”) voted out an Order Instituting Rulemaking (“OIR”) to Implement Senate Bill 237 (“SB 237”) Regarding Direct Access and to Consider Changes to Existing Direct Access Procedures.  The Rulemaking will address the expansion of Direct Access, as required by SB 237.

Direct Access permits customers of a California investor-owned utility (“IOU”) (e.g., Pacific Gas and Electric, San Diego Gas and Electric, Southern California Edison) to obtain their electricity from an electric service provider registered with the CPUC.  The IOU continues to provide transmission and distribution service to the customer.  Direct access was instituted in 1998 as part of California’s efforts to deregulate the electric sector.

As part of California’s efforts to recover from the energy crisis in 2000-2001, the California legislature passed Assembly Bill 1X (“AB1X”), which authorized the Department of Water Resources (“DWR”) to begin procuring electricity on behalf of IOU customers, and required the CPUC to allow DWR to recover the costs of such procurement from IOU ratepayers.  AB1X also authorized the CPUC to suspend Direct Access, motivated by a concern that IOU ratepayers would flee to Direct Access to avoid paying the cost of DWR procurement.

Continue Reading

CAISO Proposes Second Set of Resource Adequacy Enhancements – Aims to Reduce Reliance on Resource Adequacy Availability Incentive Mechanism (RAAIM)

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 effective forced outage rate of demand, or the probability that a resource will be unavailable due to forced outages or forced deratings when there is demand on the unit to operate, to assess resource availability up front.  The CAISO plans to take from the best practices, including a review of resources’ forced outage rates to include in RA valuation and ultimately reduce the reliance on RAAIM.  The CAISO’s admittedly ambitious schedule aims to wrap up the policy development and get board approval by the end of the year, anticipating implementation for RA year 2021.

The proposal includes three main topics:

(1) RA counting rules and assessments: The CAISO proposes a new framework that assesses the forced outage rates for resources and is considering how to incorporate these rates in RA assessments. The CAISO is not proposing to adjust NQC, as this will still be important for local RA assessments and studies and must offer obligations, but to also annually publish unforced capacity (UCAP) values, or the installed capacity that is not on average experiencing a forced outage or derating. The intention is to develop RA rules that incentivize the procurement of reliable resources rather than only the cheapest and to encourage showing all RA capacity that is under RA contract, as opposed to the minimum amount as is currently incentivized under the RAAIM framework. The CAISO is exploring options to develop UCAP for all resource types that do not rely on ELCC methodology (solar and wind), as it intends to rely on CPUC ELCC methodology where applicable. Proposals will be included in the revised straw proposal.

Additionally, the CAISO continues to explore a new planned outage substitution concept where planned outages will not be required to provide substitute capacity if LSE’s available unforced capacity exceeds the minimum UCAP threshold. Further, the CAISO believes it is possible to eliminate forced outage substitution as UCAP values will provide incentives for timely maintenance and quick repairs. Resources shown for RA capacity will continue to have a must offer obligation.

(2) Backstop capacity procurement: The CAISO’s proposal includes three pathways for new CPM authority for individual deficiencies including (a) LSE specific UCAP test (b) system UCAP test and (c) capacity incentive mechanism. The CAISO may also modify the competitive solicitation process to implement it with daily granularity as it may be used to allow scheduling coordinators to backstop planned outages in the future.

(3) RA import capability provisions: The CAISO is evaluating whether the current allocation process timing causes barriers for new LSEs beginning operations and commencing RA compliance. It will also consider potential enhancements to the Available Import Capability Assignment including (a) considering modifications to allow for release and relocation or transfer of unused import capability after initial monthly RA showings (b) incorporating an auction or other market based mechanism and (c) enhancing the provisions for reassignment, trading, or other forms of sales of import capability among LSEs.

The CAISO is accepting comments on these proposals until March 20 and anticipates posting a revised straw proposal on May 20.

As always, our attorneys can provide counsel regarding the impact of the proposed changes on your business and work with you to participate in this process.



Key Energy Related Bills Introduced in the 2019-2020 Legislative Session

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.


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

FERC Approves CAISO Tariff Changes re Generator Interconnection and Deliverability Allocation Procedures

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 promote efficiency in the CAISO’s interconnection procedures in light of changes in the generation development marketplace.

Most significantly, the CAISO’s tariff changes include revisions to the Transmission Plan (TP) Deliverability allocation process in order to award deliverability to customers most likely to proceed towards construction. The CAISO will allocate in the following order: (1) customers with an executed power purchase agreement or customers that are load serving entities serving their own load, (2) customers actively negotiating a power purchase agreement or short listed in an RFO, (3) interconnection customers electing to proceed without a power purchase agreement.  This is a departure from the prior provisions that allocated deliverability based on a system that equally weighed three criteria related to financing status: being balance-sheet financed, having a regulator-approved power purchase agreement, and proceeding without a power purchase agreement. The CAISO believes this change better reflects the likelihood of proceeding to construction because projects without a power purchase agreement, in the CAISO’s experience, delay putting construction funds at risk and nearly always withdraw if they do not secure a power purchase agreement.  The CAISO has also changed to a similar priority system for allocating any available TP Deliverability in the Annual Full Capacity Deliverability Option process.

Other changes that will impact potential and existing interconnection customers include:

  • Allowing CAISO to remove network upgrades that are no longer needed from interconnection customers’ financial security postings, even before CAISO issues the next study results;
  • Requiring interconnection customers to provide copies of their power purchase agreements when demonstrating commercial viability;
  • Eliminating the criteria required of withdrawing interconnection customers in order to recover their refundable portion of financial security, which should result in more timely refunds;
  • Aligning the deposits required for customer-requested repowering studies and serial re-studies with current study costs by increasing deposits from $10,000 to $50,000;
  • Prohibiting fuel-type modifications for interconnection customers that have remained in the interconnection queue beyond the anticipated limits of seven years for cluster process or ten years for serial process;
  • Applying the commercial viability criteria to all requests for modifications beyond the anticipated tariff timelines;
  • Requiring projects in the queue beyond the anticipated tariff timelines to have a regulator-approved power purchase agreement to modify their project and retain deliverability (removing the balance-sheet financed option) – this change will not apply retroactively;
  • Allowing interconnection customers to convert to energy only deliverability status at any time, so long as costs are not shifted to other interconnection customers or transmission owners.

Changes also include revisions to suspension notification provisions to include a good faith estimate of anticipated time of suspension, adding project names to the CAISO’s public interconnection queue, and embedding the generator interconnection study process agreement in the interconnection request. Additionally, the CAISO has added a simple provision clarifying that interconnection customers must go through the new resource implementation process prior to synchronization and a clarification that interconnection customers that have not achieved commercial operation are subject to a material modification assessment for proposed changes, whereas online generators may modify their projects so long as they do not increase their capacity nor change electrical characteristics in a way that threatens reliability.

The CAISO has filed additional tariff changes which they have requested to be approved before the April 1, 2019 opening of the interconnection request window. These changes enumerate specific requirements for interconnection requests to be considered complete and valid. A third set of enhancements was approved by the Board of Governors earlier this month but have not yet been filed with FERC. These changes include clarifications to network upgrade cost responsibilities and framework.

Oregon Adopts Temporary Rules Limiting Solar Siting on Certain High-Value Farmlands

On January 29, 2019, the Oregon Department of Land Conservation and Development, the state’s land use agency, filed temporary rules amending the standards for siting solar PV facilities on agricultural lands.  Although the Land Conservation and Development Commission stopped short of making the changes permanent in order to further consider stakeholder interests at its May 23, 2019 meeting, the Commission carried forward the bulk of the proposed limitations that we discussed in our previous posts here and here.  Notably, the commission opted to retain the prohibition on siting solar on Class I or II, Prime or Unique soils.  Under the temporary rules, developers may site solar PV on these particular lands only (1) if the county adopts, and an applicant satisfies, land use provisions authorizing sub-20 acre “dual-use” projects or (2) by securing a Statewide Planning Goal Exception.  Written comments are due May 7, 2019, and a public hearing will be held on May 23, 2019.

Proposed Changes to CAISO’s Resource Adequacy Framework

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 one straw proposal in this process, as the CAISO works with stakeholders to develop the appropriate policy solutions. Comments regarding this portion of the proposal are due February 6. CAISO’s proposal:

Import RA:

  • Reassess the requirements and rules for specifying the sources behind RA import showings (prevent double counting in meeting EIM resource sufficiency requirements and RA requirements)
  • Implement real time bidding requirement for all MWs of import RA – not just those awarded in IFM and RUC (day-ahead market)
  • Explore expanding must offer obligation for import RA to 24/7
  • Require 15 minute bidding/scheduling for import RA
  • Change import RA designations to be resource-specific

Resource Adequacy Availability Incentive Mechanism (“RAAIM”):

  • Explore moving RAAIM  from predetermined hours to event-based triggers
  • Implement changes that will resolve gaps in current planned outage approval process, including looking at rules that will incentivize submission of planned outages over reliance on forced outages. Two proposed options are under consideration, namely (i) prohibiting resources that are taking planned outages during a month from providing RA capacity, and (ii) authorizing ISO to procure capacity for any days on which resource is on planned outage using standing CSP bids
  • Limit exemptions from various levels of RAAIM penalties
  • Consider a RAAIM assessment based on both availability and performance. Currently RAAIM does not assess how resources perform in response to ISO dispatch instructions)
  • Seek different pricing structures for each type of capacity (i.e., system, local, flexible)

Local Resource Adequacy Needs:

  • Consider proposals to allow slow demand response to help meet local RA needs
  • Plan to better outline enhancements to the local capacity technical study to inform stakeholders of availability needs within local capacity areas – including providing additional data

Note that CAISO’s straw proposal part 2 will come out in February with additional changes. 

We are happy to provide counsel regarding the impact of the proposed changes on your business and work with you to participate in this process.

Oregon Department of Land Conservation and Development Issues Staff Report/Clarifications Regarding Proposed Solar PV Rules

As a follow up to last week’s post about the proposed rules that would limit the development of solar PV on certain high-value farmland in Oregon, the Oregon Department of Land Conservation and Development issued its staff report on the proposed rules.  The staff report provides an overview of the rationale for the proposed changes and clarification on several key issues, including:

  • Continued availability of Statewide Planning Goal exceptions. The staff report confirms that, if the rules are adopted, project developers may still pursue development on Class I, Class II, Prime, and Unique soils by seeking an Exception to the Statewide Planning Goal 3 (Agricultural Lands).  Although this is not a practicable permitting pathway in most instances, the Exception option nonetheless remains.
  • Treatment of tracts composed of a mix of Class I or II, Prime or Unique soils and “other” soils. The staff report confirms that a county could approve a conditional use permit for a solar PV facility on a tract of land that contains Class I or II, Prime, or Unique soils on the portion of the tract that contains other soils.  DLCD staff provided the following example in an email to the rulemaking list serve:  “If an 80-acre tract includes 50 acres of class I, II, prime or unique soils and 30 acres of other soil types, those 30 acres of other soil types remain eligible for a conditional use application for commercial solar development.”
  • Application of rule to solar PV powering onsite facilities. The staff report clarifies that the new limitations only apply to “commercial utility facilities” and not to solar installations that power onsite facilities such as agricultural buildings or electric fences.

The staff report also contains a case study prepared by DLCD staff that is designed to highlight the effect of the proposed limitation related to Class I or II, Prime or Unique soils.  The case study (Attachment E to the staff report) provides several example tracts in Marion County that contain 12 acres or more of high-value farmland that is not Class I or II, Prime or Unique (and thus eligible for solar PV siting without a Statewide Planning Goal Exception).  The case study also includes an overview map showing the mix of Class I or II, Prime or Unique soils and “other” high-value farmland in that area of Marion County.

As we noted previously, DLCD is currently accepting comments and will hold a public hearing in Salem on January 24.  The agenda is available here.