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.

Solar Power Had a Big Day at FERC

Today was a big day for the solar power industry at the Federal Energy Regulatory Commission (FERC).

In its monthly open meeting, FERC announced two decisions that significantly impact the industry — one involving PURPA and the other related to PJM’s Minimum Offer Price Rule (MOPR).

First, FERC reversed its Broadview Solar decision issued in September 2020, which prior decision overturned decades of precedent related to the method for determining the net output of qualifying facilities under PURPA.  That September decision provided that qualifying facilities could not take into account devices that can limit their output, such as inverters, in determining their net output.  And that meant, in Broadview Solar’s case, that a solar power qualifying facility with greater than 80 MW of solar panel capacity, but only 80 MW of inverter capability, would not be eligible for qualifying facility status.  But today FERC reversed that decision, finding that a qualifying facility’s net output should reflect the facility’s design and its actual capabilities (not theoretical ones).

Next, FERC responded to a petition for declaratory order in which an applicant sought confirmation that local property tax relief that is available to solar power facilities as Pollution Control Equipment (Va. Code Ann. Sec. 58.1-3660) is not a State Subsidy that would subject the applicant to the expanded MOPR in the forthcoming PJM Base Residual Auction.  Just a few months ago, PJM had determined that the very same tax relief would cause recipients to be subject to the MOPR.  But FERC disagreed and as a result solar power project owners may utilize this tax relief in Virginia without consequence in PJM’s capacity auctions.

The orders in these proceedings have not yet been released, and we will provide further updates as needed once they are available for review.

Minnesota drives forward with EV rules

On December 21, the Minnesota Pollution Control Agency (MPCA) set forth its plans to amend the state’s clean air rules to adopt Low-Emission Vehicles (LEV) and Zero-Emission Vehicles (ZEV) standards, known as the Clean Cars Minnesota rule.  As described in MPCA’s Notice of Intent to Adopt Rules with a Hearing, the LEV standard would require automobile manufacturers to deliver for sale in Minnesota only those vehicles that can meet California’s more stringent greenhouse gas and other air pollutant emissions standards.  The ZEV standard would further require automobile manufacturers to deliver for sale in Minnesota a certain percentage of vehicles with no tailpipe emissions.  Automobile manufacturers could comply with the ZEV standard through the delivery of battery electric vehicles, plug-in hybrid electric vehicles, and hydrogen-fueled vehicles.  If approved, the rule would apply to new passenger cars and light trucks beginning in 2024.

The rule’s LEV standard will prohibit motor vehicle manufacturers from exceeding the fleet average non-methane organic gas plus oxides of nitrogen emission values and fleet average greenhouse gas emission values contained in the California Code of Regulations.  A vehicle manufacturer will have to submit an annual report to MPCA demonstrating that it did not exceed the fleet average emissions. Continue Reading

LIBOR Transition Will Begin to Accelerate as 2021 Approaches

Over the course of the next several months, participants that are actively engaged in project financing will need to begin thinking about how to manage the transition away from the London interbank offer rate (LIBOR, known as the “most important number in finance”).  LIBOR forms the basis for many financing agreements.  LIBOR is scheduled to be phased out by market regulators on December 31, 2021, and many large banks and investment managers have been busy preparing for this fundamental shift.  The Federal Reserve’s Alternative Reference Rate Committee (ARRC) selected the “Secured Overnight Financing Rate” (SOFR) as the successor rate to LIBOR.  SOFR is certainly the leading candidate to replace LIBOR, although there are other alternative rates that are also “competing” to replace LIBOR, such as American Financial Exchange’s “Ameribor” and ICE’s “Bank Yield Index.”  (These non-SOFR rates may be available to borrowers, but this depends in large part on whether an active market in pricing non-SOFR loans develops between now and the end of 2021.)

SOFR is in certain respects fundamentally different from LIBOR.  Thus, the transition will not necessarily be as simple as replacing one interest rate with an equivalent fallback rate.  For instance, one structural difference is that SOFR does not currently have a forward-looking term structure like LIBOR, meaning that it is backward-looking (calculated in arrears).  If a liquid derivatives market based on SOFR develops before the end of 2021, then SOFR may develop a forward-looking term structure – but, until that happens, participants may find this feature to be one of the most significant operational differences between LIBOR and SOFR .  Further, SOFR is a secured overnight rate, whereas LIBOR is an unsecured rate with various tenors.  Fundamentally, this means that LIBOR has an implicit credit component that SOFR does not have – which means that the adoption of SOFR as a replacement rate will need to incorporate a credit spread adjustment that effectively replaces LIBOR’s implied credit component.

From a documentation standpoint, LIBOR transition will require the modification of existing loan agreements that reference LIBOR, in addition to any interest rate swaps that are based on the rate.  This means that projects with debt plus a hedge will need to think about any switch to SOFR as a “package,” with a primary goal of ensuring that the interest rate hedge remains stable and tightly aligned with the terms of the project debt.  If a project sponsor only hedges a portion of the notional value of the project debt – effectively carrying a certain amount of floating rate exposure – then the unhedged portion will be based on SOFR.

To this end, on October 23, 2020, the International Swaps and Derivatives Association (ISDA) published a protocol addressing the upcoming transition, which was one of the final major pieces of the puzzle that the market needed to see in order to begin taking steps to transition the derivatives market away from LIBOR.  On the loan side, the Loan Syndications and Trading Association (LSTA) recently published a concept credit agreement that utilizes SOFR.  We will be publishing additional content on LIBOR’s phase-out in the future. This initial post is intended to flag this upcoming shift in the debt market’s financial plumbing for sponsors that are actively financing (or refinancing) projects.

California CCAs, including San Diego Community Power, Receive Proposed Decision for 2019 RPS Plan

On August 19, the California Public Utilities Commission (CPUC) issued a proposed decision accepting the 2019 Renewables Portfolio Standard Procurement Plans submitted by four new Community Choice Aggregators (CCAs): Butte Choice Energy Authority; Clean Energy Alliance; the City of Santa Barbara; and San Diego Community Power.  Each of these CCAs is anticipated to start providing electricity to customers in 2021.  As we have noted previously, San Diego’s CCA is forecasted to serve a total load of over 6,000 GWhs, making it one of the largest CCAs in California.

While the CPUC accepted, and deemed as final, the RPS Plans for these CCAs, the CPUC cautioned that going forward the CCAs must submit more detailed RPS Plans and improve the quality of their filings.  San Diego Community Power’s RPS Plan deficiencies recognized by the CPUC included (i) a more robust assessment of risk was needed, (ii) clarification of whether San Diego anticipated being able to use its excess renewable resources to meet its Minimum Margin of Procurement (MMoP), (iii) more detailed information on the bid solicitation protocol when procurement activities commence, (iv) how it will address curtailment concerns, and (v) additional description of the organization’s approach to safety.  For instance, the CPUC noted that San Diego Community Power raised concerns about the “impact[] of the COVID-19 pandemic and ramping up with long-term procurement; but [did] not explain what their exact concerns are or what the impacts of supply chain disruption could be for new renewable project development[.]”

The CPUC acknowledged that some of the deficiencies were the result of the CCA’s new status and lack of signing long term contracts for RPS resources.  Nonetheless, the CPUC was clear that it expected more responsive details and correction of the deficiencies in future filings of the following issues:

  • future plans should provide more details on their long-term contracting processes and timeframe, particularly providing a basis for potential delays related to issues raised for COVID-19 pandemic or their ability as a new CCA to meet this requirement;
  • clarifying mixed messages of noting concerns for meeting requirements due to the current pandemic, reopening of direct access market and signaling the need for a long-term contracting on-ramp, while stating that the CCAs will be able to meet the procurement requirements;
  • clarification of (i) whether over-procurement of renewables will be RPS-eligible, (ii) whether they anticipate being able to use their excess RPS resources as their MMoP, and (iii) the process they will use for adjusting their MMoP in the future as the procurement quantity requirement increases, forecasts change, and risks evolve;
  • given the 65 percent long-term contracting requirement commences in 2021, clarification of plans for how they will meet the long-term procurement requirement in Compliance Period 2021-2024.

In addition to the foregoing recommendations, which applied to all four CCAs, the CPUC also had additional recommendations directed specifically to Butte Choice Energy and the City of Santa Barbara CCA.

U.S. District Court Upholds California’s Cap-and-Trade Agreement with Québec

On July 17, 2020, the U.S. District Court for the Eastern District of California rendered its decision in U.S. v. California (Case 2:19-cv-02142-WBS-EFB), upholding the agreement between California and the Canadian Province of Québec that links California and Québec’s respective cap-and-trade programs.  In its opinion, the District Court rejected the federal government’s claim that the California-Québec agreement is preempted under the Foreign Affairs Doctrine.  The District Court ruled earlier this year on the federal government’s other claims, finding that the agreement did not violate either the Treaty or Compact Clauses of the U.S. Constitution.  With the decision on July 17, the California-Québec agreement will remain in place, allowing the two jurisdictions to continue to link their cap-and-trade programs.  The federal government has not yet stated whether it will appeal the District Court’s decision.

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