FERC Issues Orders Revising Requirements for Market-Based Rate Sellers

The Federal Energy Regulatory Commission (“FERC” or the “Commission”) issued two orders on July 18, 2019 revising the requirements applicable to market-based rate (“MBR”) sellers.  The first, Order No. 861, lightens the regulatory requirements for MBR sellers in certain RTO/ISO-administered markets by eliminating the requirement to submit indicative screens in the horizontal market power analysis in initial MBR applications, triennial updates, and change-in-status notices.  The second, Order No. 860, may also lighten regulation by reducing the amount of ownership information MBR sellers must report to the Commission, but also imposes new reporting requirements, including submissions to a relational database that will be maintained by FERC Staff to link MBR sellers and their affiliates.

Order No. 861

Order No. 861 eliminates the requirement that MBR sellers in RTO/ISO-administered energy, ancillary services, and capacity markets subject to FERC-approved RTO/ISO market monitoring and mitigation submit indicative horizontal market power screens.  Instead, a seller may include a statement in its filing that it is relying on FERC-approved market monitoring and mitigation to mitigate any potential market power.  With the exception of MBR sellers making capacity sales in CAISO and SPP, discussed below, this will lighten regulation on MBR sellers in ISOs/RTOs by eliminating the requirement to submit indicative screens in their initial MBR applications, triennial updates, and change-in-status notices.

The exemption will not apply to MBR sellers making capacity sales in CAISO or SPP, because CAISO and SPP do not have an RTO/ISO-administered capacity market.  In addition, the Commission determined that MBR capacity sellers in CAISO and SPP can no longer rely on the rebuttable presumption that FERC-approved RTO/ISO market monitoring and mitigation is sufficient to address horizontal market power concerns for their capacity sales in CAISO and SPP.  Therefore, SPP and CAISO capacity sellers must still submit indicative screens and, now, any seller that fails the indicative screens must submit a delivered price test or other evidence that it lacks market power in the capacity markets.  CAISO and SPP sellers will be able to rely on Order No. 861’s exemption for their sales of energy and ancillary services.

The order is effective September 24, 2019 and FERC Staff announced that the new rules will be applicable to triennial reviews for the Northeast region due in December 2019 and June 2020.

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Oregon’s DLCD Finalizes Solar Siting Rules

This post was co-authored by Stoel Rives summer associate Ken Pearson.

On May 23, the Oregon Department of Land Conservation and Development made permanent the Temporary Amendments to OAR 660-033-0130, promulgated on January 29, 2019, which restrict the extent to which counties may approve construction of new commercial solar facilities on high-value farm land. You can find the final rules here and our earlier discussion of the amendments here, here, and here. As predicted, the rules were adopted with few changes.

The rule amendments include two controversial changes. The first change is that the rules now limit the amount of EFU land a solar facility may use, occupy, or cover. Previously, solar facility restrictions focused on the amount of agriculture land precluded from use, but there was no agreement among DLCD, counties, and stakeholders over the meaning of “preclude.”   Under the new rules, local jurisdictions are required to consider the entire facility footprint when calculating the size of the facility for purposes of determining compliance with applicable land use standards.

The second, and perhaps more controversial, change is the insertion of rule (h)(E), which, with few exceptions, prohibits solar projects on “the best” of the high-value soils, defined by 660-033-0020(8)(a) as “Prime, Unique, Class I or Class II soils” or simply (8)(a) soils. This map from the Oregon Working Lands database helps demonstrate the scope of the restriction; the first four categories are defined as (8)(a) soils.

The new rules contain a narrow “dual-use” exception that allows counties to site solar facilities on more than 12 acres on certain non-8(a), high-value farmland if other criteria are met.   However, counties are under no obligation to create a “dual-use” permitting pathway.

Solar industry trade organizations, developers, and operators were understandably opposed to the change. However, a wide range of environmental justice and community advocacy groups also opposed the amendments, arguing that it would limit opportunities for new community solar projects. Conversely, vineyard owners, agriculture industry organizations, and wildlife protection groups argued that the restrictions did not go far enough.

It is important to understand what the amendment does—and doesn’t—do. The (h)(E) amendment prohibits the development of commercial solar facilities in 86% of the Willamette Valley, even under the dual-use exception. Developers may still seek an exception to Statewide Planning Goal 3 (Preservation of Agricultural Lands), although this is likely not practicable in most instances. Developers may also utilize the portion of a tract of land that is not (8)(a) soil. The State, seeking to illustrate its position on the impact on qualified facilities/community solar, points to a Marion County case study in Appendix E as evidence that there are still viable tracts throughout the Willamette Valley.

With Oregon’s ambitious renewable energy goal, there is no question that these amendments present a major hurdle to solar developers, particularly in the Willamette Valley.  Nonetheless, even under the new rules, there are still opportunities to develop community solar in the Willamette Valley, and larger-scale solar projects elsewhere in Oregon on sites not composed of the “best of the best” soils.

Renewable Energy Trending in State Legislative Sessions

State legislatures across the country have been active this spring debating ambitious new targets and renewable energy market reforms, following the successful passage of multiple renewable energy mandates in certain states.  Last year California passed SB 100, which sets the target of 100% carbon-free electricity by 2045.  At least other three states—Hawaii, New Mexico, and Washington—have also adopted 100% renewable energy targets and, according to Inside Climate News, several other states debated 100% renewable energy legislation this spring including Minnesota, Illinois, Nevada, Maine, and Massachusetts.

Like other states adopting renewable energy mandates, the Washington legislature specifically concluded “that Washington must address the impacts of climate change by leading the transition to a clean energy economy … by transforming its energy supply.”  To support this goal, the Act mandates 100% renewable electricity generation by 2045.  To help achieve this, section six of the Washington law mandates that utilities must file a
“four-year clean energy implementation plan” by 2022 and every four years after that.  Each action plan must include “specific actions to be taken by investor-owned utility[ies] over the next four years … that demonstrate progress toward meeting the standards … of [the] act.”  By requiring the utilities to provide relatively frequent updates, the Washington legislature appears to indicate a desire for strong oversight of the transition to 100% renewable electricity generation.

In other states, such as Minnesota, 100% carbon-free targets were the subject of substantial attention and debate but were not ultimately adopted.  The Minnesota legislature ultimately passed a jobs and energy omnibus bill in a special session this year with more limited ambition—including provisions for energy storage pilot programs, which will allow public utilities to pursue and recover costs for such programs.  The pilot program petitions, at a minimum, must provide: (1) the storage technology utilized; (2) the energy storage capacity and the duration of the output at the capacity; (3) the proposed location; (4) the cost of purchase and installation; (5) the interplay between the storage facility and existing distributed generation resources; and (6) the overall goals of the project.  Continue Reading

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.

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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.