FERC Rules on Order No. 841 Compliance Filings

In February 2018, as part of its efforts to remove barriers for electric storage resources, the Federal Energy Regulatory Commission (FERC) issued its final rule on electric storage participation in organized markets (Order No. 841).  Order No. 841 directed Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) to revise their tariffs to establish a participation model that recognized the physical and operational characteristics of electric storage resources.  FERC required that the participation model: (1) ensure that a resource is eligible to provide all capacity, energy, and ancillary services that the resource is technically capable of providing, (2) ensure that a resource can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, (3) account for physical and operational characteristics of electric storage resources through bidding parameters or other means, (4) establish a minimum size requirement that does not exceed 100 kW, and (5) specify that the sale of electric energy to an electric storage resource that the resource then resells back must be at the wholesale locational marginal price.

On Thursday, October 17, 2019, FERC issued its first two orders on Order No. 841 compliance filings – largely accepting the PJM Interconnection’s (PJM) and Southwest Power Pool’s (SPP) Order No 841 filings.  FERC found that both PJM (Docket No. ER19-469) and SPP (Docket No. ER19-460) submitted tariff revisions that were consistent with Order No. 841 and proposed market rules that recognized the physical and operational characteristics of electric storage resources and that facilitate their participation in the market.  But, even though it was not directly addressed in Order No. 841, FERC also directed SPP and PJM to further amend their tariffs to specify minimum run-time requirements for resources adequacy and capacity requirements, respectively, for all resources types.  Furthermore, going further outside Order No. 841, FERC also instituted a paper hearing on PJM’s minimum run-time rules for capacity storage resources.

FERC has taken its first steps in establishing the electric storage participation model in individual markets, with more to come in the remaining organized markets.

San Diego Joins Community Choice Aggregation Program⁠ – Set to Launch in 2021

On September 17, 2019 the San Diego City Council voted 7-2 to implement community choice aggregation (CCA), which included approving a resolution authorizing the city’s entry into a Joint Powers Agreement with the cities of Chula Vista, Encinitas, La Mesa and Imperial Beach, forming one of the largest CCAs in the state of California.

Under the CCA model, communities aggregate their loads – and purchasing power – in order to procure energy from renewable or traditional sources in large amounts.  Some CCAs give customers some flexibility in deciding how much of how much of their energy comes from renewable sources, but it remains to be seen how the details of the plan will play out in terms of the various options that will become available to residents of San Diego and neighboring cities.

As the number of CCAs in California continues to grow – California Community Choice Association estimates that there are 19 CCA programs in the state with more considering forming a CCA – they will likely continue to re-shape the market for renewable power.  San Diego’s 2018 business plan addressing the potential for a CCA program forecasted that the total load to be served by a CCA would be slightly over 6,000 GWhs, so the adoption by San Diego of a CCA model is noteworthy.  The expected launch is planned for 2021 and is important to achieving the city’s goal of running on 100% renewable energy by 2035.

States Split over Clean Power Plan and Affordable Clean Energy Rule

A coalition of more than 25 states, including Minnesota as of last week, and various cities have petitioned the U.S. Court of Appeals for the District of Columbia for review of the Trump administration’s promulgation of the Affordable Clean Energy Rule (ACE Rule).  The ACE Rule repeals the Obama administration’s Clean Power Plan (CPP) and sets a new course for federal regulation of carbon (CO2) emissions from power plants.

Under the CPP, states were required to develop plans to reduce CO2 emissions by meeting either state-specific mass caps (tons/year) or state-specific emission rate intensity limits (lb/netMWh). Under the ACE Rule, states are authorized to set plant-specific standards based on what existing coal plants can do “inside the fence line” through efficiency measures, referred to as heat-rate improvements (HRIs).  In setting each plant’s specific emission rate standards, states may consider source-specific factors, such as remaining useful life and cost.

States will have three years to submit implementation plans and EPA will have 12 months to review and approve/disapprove state implementation plans after the plans are determined to be complete. The U.S. Environmental Protection Agency (EPA) has offered minimal guidance about what the compliance plans should ultimately look like, so states will likely have discretion in how they implement the ACE Rule, although states would need to justify a more stringent approach to EPA if they propose a more stringent plan than required by the ACE Rule.

In any event, litigation over regulation of coal-fired power plant CO2 emissions is proceeding in earnest, with the possibility that the U.S. Supreme Court will ultimately be asked to decide the extent of EPA’s authority under the Clean Air Act to regulate CO2.

Ninth Circuit Strikes Down California ReMAT in Winding Creek Solar Case

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

CAISO Seeks Stakeholder Feedback on Hybrid Resource Market Participation

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.

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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

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