CFTC Proposed Rule Benefits Certain Financially-Settled Offtake Arrangements

On February 20, 2020, the Commodity Futures Trading Commission (CFTC)  unanimously approved a proposed rule that would revise certain reporting requirements for financially-settled offtake contracts that qualify as “swaps” under the Commodity Exchange Act (as amended by the Dodd-Frank Act), such as proxy revenue swaps, fixed-volume price swaps and certain virtual PPAs.  Many counterparties to these kinds of agreements — such as project companies that sell renewable energy – are considered “end-users” under Dodd-Frank, and, in certain cases, bear a transaction reporting burden under parts 43 and 45 of CFTC regulations.

For example, under the proposal end-users would have an additional day to comply with certain reporting obligations under §45.3 of CFTC regulations , such that the transaction would need to be reported on or before the second business day after the date of execution, instead of within 24 hours from execution as provided under the current rule.  In his statement, CFTC Chairman Heath Tarbert recognized that that “[e]nd users often lack the reporting infrastructure of big banks, and may be unable to report data as quickly as swap dealers and financial institutions.”   The proposed rule also explained that “[t]his extended deadline reflects the [CFTC’s] interest in relieving some of the swap data reporting burdens previously imposed on end users in a way that should also help improve data quality.”   These acknowledgments are a welcome shift for end-users, which do not necessarily have the same level of operational resources devoted to swap data reporting as swap dealers or other financial entities.

If you have any questions regarding how the CFTC’s swap reporting regulations apply to cash-settled offtake contracts, please do not hesitate to reach out to your Stoel Rives LLP contacts.

Minnesota Court of Appeals Determines MEPA Review Required for Wisconsin Natural Gas Generating Facility

On December 23, 2019, the Minnesota Court of Appeals reversed and remanded a decision by the Minnesota Public Utilities Commission (the “Commission”) approving affiliated-interest agreements permitting Minnesota Power and its Wisconsin affiliate to move forward with the construction of a large natural gas facility – the Nemadji Trail Energy Center (“NTEC”) – in Superior, Wisconsin (the “Order”). The result of the Order may complicate the already complex issue of state permitting, specifically a state’s ability to regulate activity occurring in another state.

Honor the Earth and certain Clean Energy Organizations sought additional review of the Commission’s order based on concern about the lack of a Commission-ordered environmental assessment worksheet (“EAW”) pursuant to the Minnesota Environmental Policy Act (“MEPA”). During the initial Commission proceeding, Minnesota Power, and indeed the Commission, determined that an EAW was not necessary because (1) MEPA does not apply to the affiliated-interest agreements because NTEC does not meet the definition of “project” under MEPA, and (2) the Commission does not have authority to order an EAW for a project located in Wisconsin. In its Order, the Court of Appeals addresses each point, in turn.

The Order holds that MEPA applies to affiliated-interest agreements. Contrary to the Commission’s interpretation, the Court of Appeals concludes that the NTEC affiliated-interest agreements are “projects” as defined by MEPA. The Court’s definition of “project” is “a definite, site-specific, action that contemplates on-the-ground environmental changes.” The Order notes that the construction and operation of NTEC are definite and site-specific actions that will affect the immediate location as well as the surrounding environment (including Minnesota – 2.5 miles away – and Lake Superior). The Court went on to note that because the construction of NTEC is an environmentally significant event that may not occur without Commission approval of the affiliated-interest agreements, Commission approval of such agreements constitutes indirect governmental action manipulating the environment and triggering MEPA. Therefore, the Court concluded that MEPA “applies to the governmental action of approving the NTEC affiliated-interest agreements.”

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CAISO Clarifies Generator Deliverability Assessment Proposal

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

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.

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