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Key Takeaways | Finding and Structuring Development Capital for Renewable Platforms and Projects

by Christopher Gladbach and Joel A. Hugenberger | Jan 21, 2022 | Project Development and Finance, Renewables

During the latest webinar in our Energy Transition series, McDermott Partners Christopher Gladbach and Joel Hugenberger hosted Angel Fierro, managing partner of PLEXUS Solutions, and Jorge Vargas, managing partner & co-founder of Aspen Power Partners, to discuss what financing is available to fund the development of projects before they reach notice to proceed (NTP). They also covered what capital providers and developers consider when approaching development capital to fund pre-NTP expenses and general business expansion and the challenges and opportunities associated with these financing products.

Below are key takeaways from the webinar:

1. The market for pre-NTP financing is expanding and diversifying. Traditionally, pre-NTP costs were covered by a developer using the development fee they received from selling a completed project or by granting preferred equity. Today, large credit funds, Environmental, Social and Corporate Governance (ESG) funds, boutique finance groups, family offices, oil and gas companies and corporations are all providing pre-NTP financing, and development loans are becoming a more common way for developers to cover pre-NTP costs.

2. Sponsors should look for development lenders that understand the typical risks and delays associated with the project development process. Development lenders need to be flexible and ready to accommodate development delays and other unexpected issues that arise as a project is brought to market. (This includes flexibility related to amendments and consents.) Lenders should be prepared to quickly provide amendments and waivers to address changes in a project’s timeline as it progresses toward NTP.

3. Price should not be the only thing developers consider when deciding which source of development capital to use. Developers should ensure that they and the capital providers are aligned when it comes to deadlines for NTP to occur, capacity to accommodate delays in the development process and the share of income generated from the project.

4. Development capital is essentially a bet on a development team, and in evaluating a development team, development lenders assess what experience management has and their success working together to bring projects to market. Development lenders want to see that a development team has people who know how to mitigate risk across the various segments of the development process (e.g., origination, site control, permitting, power marketing, etc.).

5. Power purchase agreements (PPAs) are becoming scarcer and shorter (10-year terms are replacing 25-year terms), and lenders and investors are getting more comfortable with providing capital to merchant projects and other projects that have traditionally struggled to obtain financing.

To access past webinars in this series and to begin receiving Energy updates, including invitations to the webinar series, please click here.

Key Takeaways | Lender Outlook on the Debt Financing of Renewables and Transactions

by Robert da Silva Ashley and McDermott Will & Emery | Nov 4, 2021 | Power Markets, Project Development and Finance, Renewables

During the latest webinar in our Energy Transition series, McDermott Partners Robert da Silva Ashley and John Bridge hosted Paul Pace, SVP and team leader at KeyBank, and Andrew Chen, managing director at CIT, to discuss the current outlook of leading lenders in the US renewables and transactions space. More specifically, they focused on lender outlook regarding the state of debt market support for the growing range of renewable power generation and clean energy infrastructure projects.

Below are key takeaways from the webinar:

1. The financing market for renewable projects remains extremely competitive, compressing pricing for lenders and driving innovations in financing structures with credit increasingly given to shorter tenured power purchased agreements (PPAs) and earlier merchant tails.

2. Current supply chain delays and inflationary pressures are creating significant stress. Solar panels and other major equipment are stuck in ports and sharp rises in project costs (insurance, labor wages, operations and maintenance, etc.) are starting to have a noticeable effect on the viability of certain project developments.

3. Lenders have been leaning heavily on client relationships with established track records of successful project developments, strong financial footing and credibility with industry counterparties helping to navigate the current challenges.

4. Environmental, Social and Governance (ESG) remains a focus for banking institutions driven by regulatory and environmental factors.

To access past webinars in this series and to begin receiving Energy updates, including invitations to the webinar series, please click here.

Key Takeaways | How Traditional Energy Funds are Shifting Toward Green Energy: A Conversation with Encap Investments and Quantum Energy Partners

by Edward Zaelke and Parker A. Lee | Jun 10, 2021 | Project Development and Finance, Renewables

The energy market has undergone significant change in the past 12 months, with even more on the horizon. Our webinar series explores how these changes have shaped—and will continue to impact—the energy industry, including discussions of what’s to come.

Our latest webinar featured McDermott partners Edward Zaelke and Parker Lee, as well as Shawn Cumberland, Managing Partner of Energy Transition of EnCap Investments, and Alex Jackson, Director at Quantum Energy Partners.

Below are key takeaways from the webinar:

1. Although energy transition investment funds may have different focuses, they generally take an all-of-the-above approach, with respect to investing, in the various subsectors of the energy transition and are willing to invest in any technology, in any portion of the energy industry (except for highly capital intensive projects with binary risk profiles).

2. Similar to the approach for conventional oil and gas investments, investment funds are focused on investing in strong management teams with a successful track record, which is manifested either through a management team that already has an interesting business plan or a management team that can successfully implement the investment fund’s strategy for a new business.

3. Environmental, social and corporate governance (ESG) policies have become pervasive in all industries—especially within the energy industry—and must permeate all aspects of an investment fund’s strategy. Effective ESG policies and proper environmental stewardship have become licenses to operate within the energy industry and without them, operating companies and investment funds will have extremely limited ability to gain legitimate interest from potential investment partners.

4. When developing a relationship between an investment fund and a management team for a new investment, it is critical for both parties to ensure there are aligned interests and expectations between the two parties.

5. Investment funds see abundant opportunities within the energy transitions space and are bullish on those investments’ capability to satisfy energy demand over the next two to three decades but are also looking to achieve diversification to protect their limited partners from the cyclical nature of energy investment.

To access past webinars in this series and to begin receiving Energy updates, including invitations to the webinar series, please click here.

Senate Democrats Propose Overhaul of Clean Energy Incentives

by Philip Tingle, Heather Cooper, Carl J. Fleming, Elle Hayes, Brian Moore and McDermott Will & Emery | Apr 23, 2021 | Project Development and Finance, Renewables, Tax, U.S. Congress

US Senate Finance Committee Chairman Ron Wyden (D-OR) introduced the Clean Energy for America Act (the Act), along with two dozen Democratic co-sponsors, on April 21, 2021. The Act will likely be a starting point for the Biden administration tax proposals intended to limit carbon emissions. The Act would change the current system for incentives for the renewable energy industry to a technology-neutral approach for generation that is carbon free or has net negative carbon emissions. The Act would also provide tax incentives for qualifying improvements in transmission assets and stand-alone energy storage with the aim of improving reliability of the transmission grid. Instead of requiring that taxpayers who qualify for the clean energy incentives have current or prior tax liabilities, the Act would create a new direct pay option allowing for refunds of the tax credits.

The Act would replace the current renewable energy incentives with a new clean electricity production and investment credit, which would allow taxpayers to choose between a 30% investment tax credit (ITC) or a production tax credit (PTC) equal to 2.5 cents per kilowatt hour. The credit would apply to new construction of and certain improvements to existing facilities with zero or net negative carbon emissions placed in service after December 31, 2022. The Act would phase out the current system of credits for specific technologies. To provide time for transition relief and for coordination between the US Department of the Treasury (Treasury) and Environmental Protection Agency (EPA), the Act extends current expiring clean energy provisions through December 31, 2022.

The Secretary of Treasury, in consultation with the Administrator of the EPA shall establish greenhouse gas emissions rates for types or categories of facilities which qualify for the credits. To incentivize additional emissions reductions from existing fossil fuel power plants and industrial sources, the Section 45Q tax credit would be extended until the power and industrial sectors meet emissions goals. The Act would modify the qualifying capture thresholds to require that a minimum percentage of emissions are captured. Once certain emissions targets are met—namely, a reduction in emissions for the electric power sector to 75% below 2021 levels—the incentives will phase out over five years.

Qualifying transmission grid improvements are also eligible for the 30% ITC including standalone energy storage property. Storage technologies are not required to be co-located with power plants and include any technologies that can receive, store and provide electricity or energy for conversion to electricity. Transmission property includes transmission lines of 275 kilovolts (kv) or higher, plus any necessary ancillary equipment. Regulated utilities have the option to opt-out of tax normalization requirements for purposes of the grid improvement credit. However, the Act does not include a similar option to opt-out of the tax normalization provisions for other types of qualifying facilities, such as solar or wind projects.

Under the Act, investments qualifying for the clean emission investment credit, grid credit or energy storage property in qualifying low-income areas qualify for higher credit rates. The Act also includes new provisions requiring [...]

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Power Plant Cases in the Supreme Court

by McDermott Will & Emery | Oct 7, 2013 | Environmental

by Jacob Hollinger

The Supreme Court’s 2013 term just began but it is already shaping up to be an important one for power plant owners and operators. Three points stand out: First, on October 7, the Court denied cert. in Luminant Generation Co. LLC v. EPA, a case in which several power companies were challenging the Environmental Protection Agency’s (EPA) current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. The Court’s action leaves in place a Fifth Circuit decision which upheld EPA’s approach, at least as applied to the Clean Air Act state implementation plan (SIP) for the State of Texas. More importantly, the Court’s action is likely to bolster EPA’s confidence as it pursues its ongoing rulemaking concerning the SSM provisions in 39 other SIPs, a rulemaking in which EPA has proposed eliminating affirmative defenses for excess emissions that occur during “planned” SSM events. More information about EPA’s ongoing SSM rulemaking can be found here: https://www.epa.gov/airquality/urbanair/sipstatus/emissions.html.

Second, the Court is actively considering whether to hear an industry challenge to EPA’s regulation of greenhouse gases under the Clean Air Act’s (CAA) prevention of significant deterioration (PSD) program. The Court currently has before it eight cert. petitions seeking review of the D.C. Circuit’s August 2012 decision in Coalition for Responsible Regulation v. EPA, 684 F.3d 102 (D.C. Cir. 2012). That decision rejected industry challenges to EPA’s four “core” greenhouse gas (GHG) regulations – the Endangerment Finding, in which EPA concluded that carbon dioxide emissions from motor vehicles contribute to air pollution reasonably anticipated to endanger public health and welfare; the Tailpipe Rule, in which EPA set motor vehicle GHG emission limits; the Timing Rule, in which EPA announced that GHGs are “subject to regulation” under the CAA as of January 2, 2011; and the Tailoring Rule, in which EPA announced that with respect to GHG emissions it was raising the statutory threshold for PSD applicability. A central point of dispute in the Coalition matter is whether EPA’s conclusion that it is required to regulate motor vehicle GHG emissions means that EPA must also regulate stationary source GHG emissions. We should know shortly whether the Supreme Court will address that dispute.

Finally, the Court is scheduled to hear oral argument on December 8 concerning EPA’s Cross State Air Pollution Rule, a rule which the D.C. Circuit invalidated last summer. The Supreme Court’s eventual decision in that case, EPA v. EME Homer City Generation, L.P., No. 12-1182, is likely to be extremely significant for power plant owners regardless of which side prevails. A ruling in EPA’s favor will reinstate stringent emission limits on upwind power plants, but a ruling against EPA may simply lead to more stringent emission limits being imposed in downwind states. In all events, the case concerns a complex and difficult problem – interstate air pollution – and the Supreme Court’s decision is likely to clarify EPA’s authority to address that problem.

EPA Proposes CO2 Emission Limits for New Power Plants and on Track to Regulate CO2 Emissions from Existing Plants by 2015

by McDermott Will & Emery | Sep 23, 2013 | Environmental, Power Markets, Project Development and Finance

by Jacob Hollinger and Bethany Hatef

The U.S. Environmental Protection Agency (EPA) has issued a proposed rule concerning carbon dioxide (CO2) emissions from new coal-fired and natural gas-fired power plants. The September 20 proposal meets a deadline set by President Obama in a June 25 Presidential Memorandum and keeps EPA on track to meet the President’s June 2015 deadline for regulating emissions from existing power plants. Once the September 20 proposed rule is published in the Federal Register, interested parties will have 60 days to comment on it.

Under EPA’s September 20 proposal, which replaces an earlier, April 2012 proposal, new coal plants would be limited to 1,100 pounds of CO2 emissions per megawatt-hour (lbs/MWh) of electricity produced, with compliance measured on a 12-operating month rolling average basis. The proposed rule would also require new small natural gas plants to meet a 1,100 lbs/MWh emission limit, while requiring larger, more efficient natural gas units to meet a limit of 1,000 lbs/MWh.

EPA is required to set emission limits for new plants at a level that reflects use of the “best system of emission reduction” (BSER) that it determines has been “adequately demonstrated.” For coal, EPA has determined that the BSER is installation of carbon capture and sequestration (CCS) technology that captures some of the CO2 released by burning coal. In essence, EPA is saying partial CCS is the BSER for new coal plants. But for gas, EPA is saying that the BSER is a modern, efficient, combined cycle plant. Thus, CCS is not required for new gas plants.

An important feature of the proposed rule is the definition of a “new” plant. Under the pertinent section of the Clean Air Act (CAA), a “new” plant is one for which construction commences after publication of a proposed rule. EPA’s regulations, in turn, define “construction” as the “fabrication, erection, or installation of an affected facility,” and define “commenced” as undertaking “a continuous program of construction” or entering “into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction.”

EPA has concluded that its new proposal will have “negligible” benefits and costs – it won’t reduce CO2 emissions and it won’t raise the cost of electricity. This is based on EPA’s conclusion that even in the absence of the new proposed rule, all foreseeable new fossil fuel plants will be either modern, efficient combined cycle natural gas plants or coal plants that have CCS. In essence, EPA is proposing emission limits that it thinks would be met even in the absence of new regulations.

But if the rule won’t reduce CO2 emissions, why issue it? First, EPA is of the view that it is required by the CAA to issue the rule; having already determined that CO2 emissions are endangering public health and welfare, EPA is required by § 111(b) of the CAA to publish regulations to address those emissions. Second, EPA thinks the rule will provide regulatory certainty about what is expected of new plants. Third, and perhaps most importantly, the rule [...]

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Third Circuit PSD Decision is a Loss for EPA, But Also Contains Warnings for Power Plant Owners

by McDermott Will & Emery | Sep 4, 2013 | Environmental

by Jacob Hollinger

The federal Environmental Protection Agency (EPA) suffered an important loss on August 21 when the U.S. Court of Appeals for the Third Circuit affirmed the dismissal EPA’s prevention of significant deterioration (PSD) enforcement action against the current and former owners of Pennsylvania’s coal-fired Homer City Generating Station.

In United States v. EME Homer City Generation, L.P., No. 11-4408 (3d Cir. Aug. 21, 2013), the Third Circuit held that although the Clean Air Act’s PSD provisions prohibit plant owners from modifying their facilities without getting a PSD permit and implementing the best available control technology (BACT), those provisions do not prohibit operating modified facilities without those items. That means that owners who acquire a plant after it has been modified may be shielded from PSD liability for those modifications and may be able to avoid having to install costly pollution control equipment. The decision also contains many other important holdings and is a significant loss for EPA.

Some commentators have suggested that the Homer City decision may spell the end of EPA’s PSD enforcement initiative against older coal-fired power plants. But do not expect EPA (or other plaintiffs) to give up so easily. The decision depends in part on the nuances of the Pennsylvania state implementation plan (SIP), which may differ from other SIPs, and EPA may find other ways to distinguish the decision. EPA may also seek Supreme Court review.

Just as important – perhaps even more important – the Homer City decision points to three things that power plant owners will want to be conscious of going forward:

First, the decision all but encourages EPA to investigate planned equipment upgrades, not just past upgrades that might have triggered PSD obligations. The court explained: “we see no reason why the EPA and States lack authority to require the advance reporting of some or all proposed changes to facilities, whether or not they rise to a modification.”

Second, the decision may also prompt EPA to pay greater attention to Title V permit renewal applications for power plants. One significant feature of the decision is that it rejects, on jurisdictional grounds, EPA’s contention that the plant’s existing Title V operating permit was incomplete (because it failed to contain a requirement to use BACT). If EPA cannot complain about “incomplete” operating permits during enforcement actions, it may become more aggressive about raising PSD-related concerns during the permitting process.

Third, the court’s discussion of civil penalties for PSD violations is eye-opening. The court cautioned that where a plant owner modifies a plant in violation of the PSD requirements, civil penalties may not be limited to merely one day of violation. Rather, civil penalties may be available for each day that the modification is underway. For a modification that takes a month-long outage to implement, that could result in penalties greater than $1 million per modification.

Does the Clean Air Act Preempt State Law Nuisance Claims Against Power Plants?

by McDermott Will & Emery | Aug 30, 2013 | Environmental

by Jacob Hollinger

Last week, the U.S. Court of Appeals for the Third Circuit said “no” and the decision has already prompted at least one new air emissions lawsuit against a power plant owner.

In Kristie Bell, et al. v. Cheswick Generating Station, GenOn Power Midwest, L.P., No. 12-1426 (3d Cir. Aug. 20, 2013), the Third Circuit held that the Clean Air Act (CAA) does not prevent Pennsylvania residents from alleging that air emissions from a Pennsylvania power plant have created a nuisance under Pennsylvania state law. The decision holds, in essence, that the CAA’s “comprehensive” scheme for regulating air emissions is not so comprehensive as to preempt all air-related tort claims.

The Bell decision turns on the fact that the plaintiffs are relying on state tort law against an in-state source of air pollution; they are not relying on federal common law or trying to impose Pennsylvania’s tort law on an out-of-state source. The decision means that the plaintiffs – a putative class of individuals who live or own property within one mile of GenOn’s Springdale, Pennsylvania, coal-fired Cheswick Generating Station – will be able to press forward with their assertion that the facility’s particulate matter and other emissions have harmed their property, thereby entitling them to money damages under nuisance, negligence and trespass theories.

But the plaintiffs still have to prove their case, which may be difficult to do. The Fourth Circuit previously addressed similar nuisance claims arising under Alabama and Tennessee state law in North Carolina, ex rel. Cooper v. Tenn. Valley Auth., 615 F.3d 291 (4th Cir. 2010), and concluded that the plaintiffs there could not state a public nuisance claim because they were complaining about emissions that were expressly allowed by the defendant’s operating permits. The Bell plaintiffs, whose lawyers commenced a similar lawsuit against a second coal-fired power plant just days after the Bell decision came down, may face a similar problem under Pennsylvania nuisance law.

United Kingdom Government Confirms Change to Sustainability Criteria for Biomass

by Irina Denisova | Aug 30, 2013 | Environmental, EU Developments, Power Markets, Renewables

by Caroline Lindsey

The Department of Energy and Climate Change (DECC) in the United Kingdom published its response to its “Consultation on proposals to enhance the sustainability criteria for the use of biomass feedstocks under the Renewables Obligation (RO)” on 22 August 2013 (the Response). The original consultation was published on 7 September 2012.

In the Response, the UK Government confirms that it will proceed with its proposals to revise the content and significance of the sustainability criteria applicable to the use of solid biomass and biogas feedstocks for electricity generation under the Renewables Obligation (RO). The RO is currently the principal regime for incentivising the development of large-scale renewable electricity generation in the United Kingdom. Eligible electricity generators receive renewables obligation certificates (ROCs) for each megawatt hour (MWh) of renewable source electricity that they generate. Biomass qualifies as renewable source electricity, subject to some conditions.

Changes to the criteria

The sustainability criteria associated with the RO is broadly divided into greenhouse gas (GHG) lifecycle criteria, land use criteria and profiling criteria. There will be changes to all of the criteria, but the significant changes relate to the first two criteria, and will take effect from 1 April 2014.

In general terms, the GHG lifecycle criteria are designed to ensure that each delivery of biomass results in a minimum GHG emissions saving, when compared to the use of fossil fuel. The savings are measured in kilograms (kg) of carbon dioxide equivalent (CO2eq) per MWh over the lifecycle of the consignment (sometimes referred to as “field or forest to flame”). The UK Government has confirmed that all generating plants using solid biomass and / or biogas (including dedicated, co-firing or converted plants and new and existing plants) will be on the same GHG emissions trajectory from 1 April 2020 (200 kg CO2eq per MWh). In the meantime, new dedicated biomass power will be placed on an accelerated GHG emissions trajectory (240kg CO2eq per MWh). All other biomass power will remain on the standard GHG emissions trajectory (285kg CO2eq per MWh) until 1 April 2020.

Changes to the land use criteria will also be introduced. In particular, generating plants using feedstocks which are virgin wood or made from virgin wood will need to meet new sustainable forest management criteria based on the UK Government’s timber procurement policy principles.

The land use criteria set out in the European Union (EU) Renewable Energy Directive 2009 (RED) will continue to apply to the use of all other solid biomass and biogas, with some specific variations for energy crops. As is the current position, the land use criteria will not apply to the use of biomass waste or feedstocks wholly derived from waste, animal manure or slurry.

The new sustainability criteria will be fixed until 1 April 2027, except if the EU mandates or recommends specific changes to the sustainability criteria for solid biomass, biogas or bioliquids, or if changes are otherwise required by EU or international regulation.

Making compliance mandatory

Currently, whilst generators using [...]

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Possible UK Power Shortages Raise Concerns

by Irina Denisova | Aug 21, 2013 | Environmental, EU Developments, Power Markets

by Thomas Morgan and David McDonnell

A warning from the UK’s energy regulator, Ofgem, on 27 June 2013, that the ‘buffer’ capacity of spare electricity on the UK’s national power grid could drop to as little as 2% of national supplies by 2015, has raised concerns in relation to the possibility of widespread disruptions in service. This spare capacity currently stands at about 4%.

The warning was linked to an extensive Electricity Capacity Assessment Report, also published by Ofgem that same day. Revised studies have indicated that power supplies will shrink considerably by 2015, as electricity demand in the United Kingdom is not decreasing in the manner previously foreseen by successive governments. This is due to a variety of factors, among them, the low uptake by residential households of environmentally friendly incentives and energy-efficient practices.

Ofgem recommends the implementation of far-reaching market changes proposed by the Department of Energy and Climate Change (DECC). Among other things, DECC stated in a report, also published on 27 June 2013, that the UK electricity sector will require approximately £110 billion of capital investment in the next decade to modernise its infrastructure. This would create opportunities for investment which a range of market players are likely to monitor with interest.

DECC has also emphasised the need for a ‘Capacity Market’ – essentially an insurance policy against the possibility of future blackouts – which would work by providing financial incentives to generators to keep a certain percentage of energy capacity in reserve to cope with spikes in demand.

The British government has been quick to retort to concerns of service disruption, downplaying the risk of blackouts to domestic consumers and, while it is unlikely that blackouts reminiscent of those experienced in the United Kingdom in the 1970s will be relived, the very publication of a formal warning from Ofgem highlights the potential significance of the concern.

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