FERC Grants Limited Waiver to the CAISO to Immediately Interconnect Gas Turbines

In the wake of Governor Newsom’s July 30, 2021 Emergency Proclamation intended to mitigate the strain on the California energy grid, the California Department of Water Resources (CDWR) and the California Energy Commission have been reaching out to generation owners that could accommodate the addition of 30 MW gas turbines generators, an effort now referred to as the State Power Augmentation Project.  So far, two sites have been found:  Greenleaf 1 in Yuba City and Roseville Energy Park.  Each site will accommodate two turbines.  The units were supposed to come online in mid-September.

The two turbines at Roseville Energy Park will be interconnected through the Balancing Authority of Northern California and will participate in the California ISO’s (CAISO) energy imbalance market.  The two turbines at Greenleaf 1 will interconnect to the CAISO.  Under current tariff provisions, the CAISO can interconnect 50 MWs of the 60 MW total.  The Greenleaf 1 site has cogeneration facilities that are currently mothballed but still retain existing interconnection capacity of 49.2 MWs.  Because both the cogeneration facilities and the new gas turbines are gas-fired, there will be no change to the electrical characteristics, and the CAISO can therefore interconnect the two turbines under the repowering provisions of the tariff, but only up to 49.2 MWs. Continue Reading

CPUC Issues Net-Qualifying Capacity Values to Be Used for Mid-Term Reliability Procurement

In June 2021, the California Public Utilities Commission (Commission) issued its Mid-Term Reliability Procurement Decision, Decision (D.) 21-06-035, which directed load-serving entities subject to its jurisdiction (investor-owned utilities, community choice aggregators, and energy service providers) to procure at least 11,500 megawatts (MW) of net-qualifying capacity (NQC) for reliability for the period 2023 through 2026.  The decision established cumulative annual procurement requirements: 2,000 MW in 2023, 6,000 MW in 2024, 1,500 MW in 2025, and 2,000 in 2026.  The decision also states that the Commission expects all of the resources procured pursuant to that decision to be zero-emitting, unless they otherwise qualify under renewables portfolio standard eligibility requirements (biomass, for example). Continue Reading

California Energy Commission Adopts Expedited Siting Order for Energy Storage

The California Energy Commission (CEC) has continued its efforts to implement Governor Newsom’s July 30, 2021 Emergency Proclamation, which was intended to free up energy supply to meet demand during extreme heat events and wildfires, and to expedite the deployment of additional generation.

The Emergency Proclamation authorized the CEC, which is responsible for licensing thermal powerplants of 50 megawatts (MW) or more, to also license new, or expansions of, battery storage systems of 20 MW or more that are capable of discharging for at least two hours and will deliver net peak energy by October 31, 2022. Continue Reading

California ISO Holds Summer Readiness Update Call for August

On August 31, 2021, the California ISO held its August Summer Readiness Update Call.  During the month of August, the California ISO grid faired well, as temperatures were more mild, and any hot weather was localized, rather than extending across the western United States.

The California ISO also noted recent transparency improvements, including publication of a daily RA Capacity Trend and 7-Day Capacity Trend, as well a Daily Day-Ahead Summer Report and a monthly Summer Market Performance Report. Continue Reading

California Energy Commission Holds Workshop on Midterm Reliability; Finds No Reliability Need for Additional Gas Resources

On August 30, 2021, the California Energy Commission (CEC) held a workshop on its Midterm Reliability Analysis and Incremental Efficiency Improvements to Natural Gas Power Plants.  CEC Commissioners Gunda and Douglas were in attendance, as were California Public Utilities Commission (CPUC) Commissioners Rechtschaffen and Houck.  CEC staff covered midterm (2022-2026) capacity needs, and potential thermal capacity needs, as well as permitted and potential thermal capacity additions.  The workshop also included a panel discussing the deployment and performance of battery energy storage, including a discussion of the risks that could impact California’s planned reliance on large amounts of battery energy storage (over 14,000 MW by 2032 in the CPUC’s recently-released draft Preferred System Portfolio).

The CEC staff’s Midterm Reliability Analysis consisted of a loss of load expectation (LOLE) analysis of a variety of scenarios built around various assumed procurement portfolios, including the CPUC’s draft PSP and a scenario based upon procurement already ordered by the CPUC (1,505 MW NQC from D.19-11-016, and either 9,500 or 11,500 MW NQC from D.21-06-035).  The Analysis focused on the May through October time frame, not the entire year.  It also assumed that procured resources would show up.  Finally, it did not evaluate the impact of extreme weather events. Continue Reading

Minnesota Court of Appeals Handles Supreme Court Remand by Deferring to MPUC’s Findings on Gas Plant Need

As a follow up to our post here, the Minnesota Court of Appeals issued a decision on August 23 affirming the MPUC’s decisions related to the Nemadji Trail Energy Center natural gas plant (NTEC) that will be constructed in Superior, Wisconsin.  Applying a deferential standard of review, the Court analyzed the appeal (on remand from the Minnesota Supreme Court) and evidence under the MPUC’s novel standard for addressing affiliated interest agreements related to power plant construction outside of Minnesota.

Specifically, the Court analyzed whether the record before the MPUC demonstrates both (i) a need for NTEC and (ii) that a fossil fueled generating resource is more appropriate on Minnesota Power’s system than a renewable generating resource.

The Court determined that, viewed in its entirety, there was substantial record evidence supporting Minnesota Power’s need for NTEC, including testimony and extensive modeling from Minnesota Power and the Minnesota Department of Commerce – Division of Energy Resources (DOC-DER).  The Court found that the record as a whole “reveals ample evidence” that NTEC is a reasonable choice to meet forecasted demand, is cost effective (even when considering environmental costs under Minn. Stat. § 216B.2422 subd. 3), and is better than various renewable sources that could expose Minnesota Power’s ratepayers to market price fluctuations.

Leveraging its findings on market price risk, the Court went on to find that the renewable preference in Minn. Stat. § 216B.2422 subd. 4 was overcome by testimony from Minnesota Power and the DOC-DER “showing that the transition away from coal and toward intermittent renewable resources impairs reliability and could increase reliance on energy markets, thereby increasing costs.”  In so doing, the Court summarized the MPUC’s application of the public interest standard in Minn. Stat. 216B.2422 subd. 4 on the basis of cost—finding “a wind or solar alternative is not in the public interest because the comprehensive costs for such resources are higher than those associated with NTEC.”

More to certainly come on this front in Minnesota, as the state wrestles with the best timing for meeting the 80% reduction by 2050 goal set forth in Minn. Stat. § 216H.02 and other energy policy provisions applicable to the MPUC and rate setting processes.

 

California Public Utilities Commission Ruling Seeks Comments on Preferred System Plan for 2022-2032

In docket R.20-05-003, its Integrated Resource Planning (IRP) proceeding, the California Public Utilities Commission is considering its preferred portfolio of new resources for the next ten years.  A lengthy administrative law judge ruling issued August 17, 2021 set out a suggested Preferred System Plan (PSP) for the proceeding, including a suggested resource portfolio through 2032, based on a greenhouse gas goal of 38 million metric tons.  As part of the Commission’s IRP process, all load-serving entities (LSEs) subject to the Commission’s jurisdiction (investor-owned utilities, community choice aggregators, and energy service providers) submit individual resource plans setting out the resources those LSEs plan to rely upon and procure over a ten-year planning horizon.  The LSEs submitted individual integrated resource plans in September 2020, for a planning horizon through 2030.

Once those plans were submitted, the Commission aggregated all of those plans and evaluated whether the aggregated plans meet the Commission’s reliability and greenhouse gas requirements.   Commission staff also worked with the California Energy Commission to include resources under existing contracts with publicly-owned utilities serving load within the California ISO, which are not under Commission jurisdiction.

Commission staff then made two additional adjustments to the aggregated portfolio.  First, staff added in the resource procurement ordered by the Commission in its June 2021 mid-term reliability decision (D.21-06-035), consisting of 11,500 MWs of net qualifying capacity.  Then, because the PSP will be transmitted to the California ISO to be used for the reliability and policy-driven base case scenario for the 2022-2023 transmission planning process, and that process also covers a ten-year planning horizon (through 2032), staff used the RESOLVE model to select additional resources for the 2031-2032 period.  This was necessary as LSE plans were only required to cover the period through 2030.

The Commission’s analysis showed that the aggregated portfolios, with the addition of the mid-term reliability decision procurement, generally met reliability and greenhouse gas goals, only requiring the procurement of an additional 286 MW of additional utility-scale solar to meet greenhouse gas emissions targets.  The ruling suggested that this scenario be adopted as the PSP and transmitted to the California ISO for the 2022-2023 transmission planning process.  The Commission staff also developed a number of other scenarios as alternate options for the PSP.

The proposed PSP includes a new resource buildout of 14,751 MWs of battery storage, 18,883 MWs of utility-scale solar, 3,553 MWs of wind, 1,500 MWs of out-of-state wind on new transmission, 1,708 MWs of offshore wind, and 1,000 MWs of pumped hydroelectric storage by 2032.  The proposed PSP will result in a portfolio that is 74% RPS-eligible and 87% greenhouse gas-free by 2032.

The ruling also poses numerous questions for parties to the proceeding, including questions about the need to accelerate the mid-term reliability procurement, and whether additional new fossil fuel-fired resources are required.  The Commission will hold a workshop on the ruling on September 1, 2021.  Comments on the ruling are due September 27, 2021, and reply comments are due October 11, 2021.

For additional energy regulatory updates, see our weekly energy regulatory update here, or sign up for the distribution list.

Biden Administration Proposes Rollback of Trump Administration Migratory Bird Rule

This post was co-authored by Stoel Rives summer associate Lydia Heye.

In May, the U.S. Fish and Wildlife Service (“Service”) announced a proposed rule revoking the Trump administration’s final rule on incidental take under the Migratory Bird Treaty Act (“MBTA”). In the January 7, 2021 final regulation, the Trump administration interpreted the MBTA’s take prohibition (the subject of a current split in federal circuit courts), excluding the “incidental” take of migratory birds from the scope of the MBTA’s take prohibition. The Service initially delayed the date the Trump final rule would go into effect but ultimately decided to propose revoking the rule entirely for the sake of transparency and efficiency. The Service’s proposed rule would give the Department of the Interior discretion to prosecute for the incidental take of migratory birds. However, without a replacement rule, the revocation of the Trump administration’s rule leaves room for unsettled and conflicting interpretations of the MBTA as it applies to incidental take, which has varied between administrations and has split the circuit courts for years.

The Trump administration’s MBTA regulations were subject to significant public scrutiny and legal challenges from various domestic and international stakeholders, but the rollback of the regulations brings renewed uncertainty for clients in the oil and gas, telecommunications, energy transmission, and renewable generation sectors.  Because there is not currently a permitting program for these clients to secure permits for take associated with their otherwise lawful activities, many of these clients are reasonably concerned that MBTA enforcement and prosecution may increase.  As such, this is a good time for clients to be reviewing and updating (as necessary) their internal migratory bird compliance programs.

 

MEPA Review Not Required as Part of Wisconsin Gas Plant Affiliated-Interest Agreements, Says Minnesota Supreme Court

As a follow up to a previous post the Minnesota Supreme Court issued its decision on April 21, 2021, reversing the Minnesota Court of Appeals and remanding the matter for further review.  In so doing, the Court concluded that the Minnesota Public Utilities Commission properly concluded that MEPA review was not required.

The Court first analyzed environmental review under Minn. Stat. § 216B.48, which governs the approval of affiliated-interest agreements, finding that nothing in the statute requires environmental review, and the legislature did not instruct the Commission to conduct environmental review as part of its analysis.  Additionally, the Court reasoned that the Commission properly analyzed whether the affiliated-interest agreements satisfied the public-interest test by considering Minnesota’s resource planning and certificate of need statutes.  The Court next analyzed whether the language within MEPA independently requires environmental review of affiliated-interest agreements.  Noting that “MEPA is not applicable unless [the] action has the potential for significant environmental effects,” and because “the decision to approve the terms and conditions of Minnesota Power’s affiliated-interest agreements does not grant a permit, does not approve the construction or operation of the NTEC power plant,” the Court concluded that MEPA does not independently require the Commission to conduct additional environmental review as part of its approval process.

Because of this conclusion, the Court did not address the remaining dormant Commerce Clause considerations, and, therefore, reversed the Minnesota Court of Appeals’ decision and remanded the matter for determination of whether the Commission otherwise erred in approving the affiliated-interest agreements, though its decision was not unanimous with Justice Chutich issuing a dissent.

With the matter once again before the Minnesota Court of Appeals, Stoel Rives will continue to track this matter and provide updates as necessary.

Battery Storage Procurement: It’s the Wild West Out There

As the energy storage industry continues on its trajectory of near-exponential growth, in the course of assisting our clients we are seeing a wide variety of battery energy storage system (BESS) offerings in the market, and we don’t always like what we see from a project finance and risk perspective.

Battery system offerings are all over the board, particularly when it comes to the suite of warranties and performance guarantees available. This is not unexpected for a relatively new technology or industry. However, there are some basic minimum expectations that have been set over the last few years, mainly by large utilities and owners of transmission globally. These standard offerings include power and energy capacity and round-trip efficiency (RTE) guarantees upon commissioning, as well as long-term system warranties that include energy retention. Most battery integrators will also offer long-term service agreements (LTSA) that include options for both traditional availability guarantees and capacity maintenance (also known as “battery augmentation” or an ”energy guarantee”).

The top-tier BESS suppliers are mostly large, vertically integrated multinationals with manufacturing capability within their corporate group and solid balance sheets. They are willing and able to provide the “standard offerings” noted above. Control of battery production allocation also gives them a big advantage in bidding for larger projects. Many of the second-tier suppliers are now starting to up their game and are providing fully bankable system offerings, albeit with a lot of variability.

Where we are seeing the most variability (and frankly, sometimes non-financeable product offerings) is with the growing number of small and mid-sized battery integrators bidding to procure and install smaller systems (e.g., 20 MWh and under). Some BESS integrators do not offer system warranties and will only provide material and workmanship warranties that exclude the batteries and other third-party components. Others may provide more robust warranties or guarantees, but only as part of an LTSA.

The reluctance of some integrators and EPC contractors to take technology risk is understandable, but at times it is necessary, not only from a financeability standpoint, but also to protect battery revenues. Since most batteries are manufactured overseas, from the owner’s perspective, warranty enforcement against the battery OEM (e.g., enforcement of long-term energy retention warranties) may be difficult or impractical. Also, the lead times to replace battery pods or other components may be extremely long, particularly now, given COVID-19-related shipping delays worldwide. Finally, the capabilities and reliability of the battery control system are extremely important. Battery control systems are typically updated by firmware. But what happens if that software developer goes bankrupt? Who controls the source code? These are the kinds of considerations that project financiers take into account.

In short, the BESS product offerings currently on the market are not uniform and may not always be financeable. Companies seeking to procure a battery system should treat it as a significant technology acquisition rather than a commodity, and BESS suppliers and integrators may need to adjust their product and service offerings to accommodate project finance, tax equity, owner and offtaker requirements.

LexBlog