Tag: Energy Law

H2 Production: A Shift Towards Electrolysis

Hydrogen production technology, according to the joint EPO-IEA report summarizing patent trends in the hydrogen economy (summarized here), accounts for the largest percentage of patenting activity since 2011 among the three primary stages of the hydrogen value chain (i.e., (i) production, (ii) storage, distribution, and transformation, and (iii) end-use industrial applications). Trends show a shift in hydrogen production from carbon-intensive methods to technologies that do not rely on fossil fuels. The bulk of recent increased patent activity is directed to electrolysis development, while patent activity related to production from biomass and waste has decreased.

Electrolysis

Electrolysis is attractive because it’s a low-emission source, meaning that hydrogen produced through electrolysis creates little to no greenhouse gas emissions. It is possible that water electrolyzers are powered by electricity derived from natural gas or fossil fuels, but unlike most other hydrogen production technology, electrolyzers do not produce greenhouse gas emissions and thereby offer the ability to produce hydrogen with net zero carbon emissions.

In this article, we will first briefly explain electrolysis and conventional concepts using electrolysis. Then, we will give an example of a technology that recently emerged from conventional electrolysis-based solutions. We will close with a brief description of alternative technologies for hydrogen production.

State of the Art

Electrolyzers use electricity to split water into hydrogen and oxygen. Specifically, an electrolyzer cell includes an anode and a cathode separated by a polymer electrolyte membrane. Water reacts at the anode to form oxygen and positively charged hydrogen ions. The hydrogen ions selectively move across the membrane to the cathode, where they combine with electrons from an external circuit to form hydrogen gas. A number of cells are assembled into a cell stack that efficiently produces hydrogen and oxygen. A standard electrolyzer stack includes membrane electrode assemblies, current collectors, and separator or bipolar plates.

Electrolyzers also range in size and type. Electrolyzer sizes range from small, appliance-size units to large-scale, central production facilities. Electrolyzer types include polymer electrolyte membrane (PEM) electrolyzers, alkaline electrolyzers, and solid oxide electrolyzers. Conventional electrolyzer stacks have capacities of 5 MW to 100 MW per stack, depending primarily on the membrane technology.

Emerging Technologies

EvolOh is a California-based startup planning to build the world’s largest hydrogen manufacturing plant in Massachusetts this year to manufacture its anion-exchange membrane (AEM) electrolyzers. The plant will be used for fabrication and assembly of the AEM electrolyzer stacks for producing green hydrogen1. These compact and high-power density electrolyzer stacks should allow for high-speed manufacturing using low-cost materials based on domestic supply chain and no precious metals. With anticipated power ratings of up to 5 MW for a single stack and 50 MW for a single module, EvolOH’s stacks are intended to be designed for large-scale facilities.

As disclosed in EvolOH’s IP, its electrolyzer stack features a bipolar plate assembly including a bipolar plate, a hydrogen seal, a water seal, and a fluid distribution frame. The fluid distribution frame serves multiple purposes within the electrolyzer stack, including containing a cathode flow field, distributing water flow from one water delivery window to a leading edge of the anode flow field, collecting water and oxygen flow from the anode flow field and distributing the flows to oxygen collection windows, and engaging and curing hydrogen seal between the frame and a bipolar plate adjacent to the cathode flow field and a water seal between the frame and a bipolar plate adjacent to the anode flow field.2 In contrast to conventional bipolar plates that include simple flow distribution channels, the bipolar plate assembly of the EvolOH electrolyzer stack is intended to provide for a scalable electrolysis cell that can be utilized in a variety of electrolyzer types.

Also as described in EvolOH’s IP, its electrolyzer stack includes a compression system having a lower wrap and an upper wrap connected at a joint to form a continuous vertical tension boundary around the cell stack and its end units while providing access to opposite lateral ends of the stack.3 Conventional electrolyzer stacks may apply a compressive load on the cell stack using end structural plates drawn together by tie rods and adjustable elements such as screws, nuts, and springs. Unlike the conventional tie rod compression, the compressive system of EvolOH’s electrolyzer stack is intended to maintain adequate compression on the stack over a range of temperatures taking into account thermal expansion and compression.

EvolOH is among many companies focused on the development of electrolyzer technology to scale-up hydrogen to reach a broader market. For example, Air Liquide and Siemens Energy recently teamed up to form a joint venture last year to produce large-scale hydrogen electrolyzers in Europe. Set to open in 2023, they intend to produce a large-scale electrolyzer with an intended capacity of 100 MW that may reduce costs per kW by 33% by 2030. The EPO-IEA study finds that Siemens is one of the leading applicants in electrolyzer patent families since 2011 and that Air Liquide is a top applicant in patent families directed to established hydrogen production technologies as well as hydrogen storage and distribution technologies.

Alternative Hydrogen Production Options

In addition to electrolysis, hydrogen can be produced from other methods such as biomass or waste via gasification or pyrolysis, recovery of by-product hydrogen from chlor-alkali electrolysis, and methane pyrolysis. Hydrogen can be produced from natural gas through methods such as steam reforming, which emits carbon dioxide in the process. Widespread natural gas infrastructure makes hydrogen production from natural gas appealing, and developments in carbon capture, utilization, and storage technology may make this option even more appealing.

In our next post on the EPO-IEA’s report, “Hydrogen Patents for a Clean Energy Future: A Global Trend Analysis of Innovation Along Hydrogen Value Chains,” we will dive into the second technology segment of the hydrogen value chain—hydrogen storage, distribution, and transformation.

Article By Jason A. Engel, Dr. Benjamin Fechner, and Clare Frederick of K&L Gates

For more energy and environment legal news, click here to visit the National Law Review.

Copyright 2023 K & L Gates

Tax Credits in the Inflation Reduction Act Aim to Build a More Equitable EV Market

In February of this year, it was high time for me to buy a new car. I had driven the same car since 2008, and getting this-or-that replaced was costing more and more every year. As a first-time car buyer, I had two criteria: I wanted to go fast, and I wanted the car to plug in.

Like many prospective purchasers, I started my search online and by speaking with friends and who drove electric vehicles, or EVs for short. I settled on a plug-in hybrid sedan, reasoning that a plug-in hybrid electric vehicle (PHEV) was the best of both worlds: the 20-mile electric range was perfect for my short commute and getting around Houston’s inner loop, and the 10-gallon gas tank offered freedom to roam. In the eight months since I’ve had the car, I’ve bought less than ten tanks of gas. As the price of a gallon in Texas soared to $4.69 in June, the timing of my purchase seemed miraculous.

When it was time to transact, the dealer made vague mention of rebates and tax credits, but didn’t have a comprehensive understanding of the details. Enter Texas’s Light-Duty Motor Vehicle Purchase or Lease Incentive Program (LDPLIP). Administered by the Texas Commission on Environmental Quality (TCEQ), the program grants rebates of up to $5,000 for consumers, businesses, and government entities who buy or lease new vehicles powered by compressed natural gas or liquefied petroleum gas (propane), and up to $2,500 for those who buy or lease new EVs or vehicles powered by hydrogen fuel cells.

Rebates are only available to purchasers who buy or lease from dealerships (so some of the most popular EVs in the U.S. don’t qualify). There is no vehicle price cap, nor is there an income limit for purchasers. In June of 2022, the average price for a new electric vehicle was over $66,000, according to Kelley Blue Book estimates. But the median Texan household income (in 2020 dollars) for 2016-2020 was $63,826.

According to the grant specialist to whom I initially sent my application, the TCEQ has received “a vigorous response” from applicants, however, the TCEQ is limited in the number of rebate grants that it can award: 2,000 grants for EVs or vehicles powered by hydrogen fuel cells, and 1,000 grants for vehicles powered by compressed natural gas or liquefied petroleum gas (propane).

The grant period in Texas ends on January 7, 2023, but on July 5, 2022, the TCEQ suspended acceptance of applications for EVs or vehicles powered by hydrogen fuel cells. As of the writing of this post, the total number of applications received and reservations pending on the program’s website is 2,480.

In comparison with Texas’s rebate program, the EV tax credits in the Inflation Reduction Act of 2022 demonstrate a commitment to building a more equitable EV market. While EVs may be cheaper to own than gas-powered vehicles—especially when gas prices are high—a lot of lower and middle-income families have historically been priced out of the EV market. The IRA takes several meaningful steps towards accessibility and sustainability for a more diverse swath of consumers:

  • Allows point-of-sale incentives starting in 2024. Purchasers will be able to apply the credit (up to $7,500) at the dealership, and because sticker price is such an important factor for so many purchasers, this incentive will make buying an EV more attractive up front.
  • Removes 200,000 vehicle-per-manufacturer cap. Some American manufacturers are already past the maximum. Eliminating the cap means bringing back the tax credit for many popular and affordable EVs, which should attract new buyers.
  • Creates income and purchase price limits. SUVs, vans, and pickup trucks under $80,000, and all other vehicles (e.g. sedans) under $55,000, will qualify for the EV tax credit. For new vehicles, purchaser income will be subject to an AGI cap: $150,000 for individuals and $300,000 for a joint filers.
  • Extends the tax credit to pre-owned EVs. As long as the purchase price does not exceed $25,000, purchasers of pre-owned EVs (EVs whose model year is at least two years earlier than the calendar year in which the purchase occurs) will receive a tax credit for 30% of the sale price up to $4,000. The income cap for pre-owned EVs is $75,000 for individuals and $150,000 for a joint filers.

A purchaser who qualifies under both programs can get both incentives. Comparing Texas’s state government-level incentives and those soon to be offered at the federal level reveals a few telling differences—new vs. used, income caps, purchase price caps, post-purchase rebates vs. up-front point-of-sale incentives—but the differences all fall under the same umbrella: equity. The IRA’s tax credits are designed, among other things, to make purchasing an EV more attractive to a wider audience.

Of course, the EV incentive landscape has greatly changed since the Energy Improvement and Extension Act of 2008 first granted tax credits for new, qualified EVs. The LDPLIP wasn’t approved by the TCEQ until late 2013, so the U.S. government has arguably had more time to get it right. Some might say that the fact that Texas’s program offers the purchaser of the $150,000+ PHEV the same opportunity to access grant funds as the purchaser of the $30,000 EV means that the LDPLIP is even more “equal.”

It is worth noting that the IRA also sets a handful of production and assembly requirements. For instance, to qualify for the credit, a vehicle’s final assembly must occur in North America. Further, at least 40% the value of the critical minerals contained in the vehicle’s battery must be “extracted or processed in any country with which the United States has a free trade agreement in effect” or be “recycled in North America”—and this percentage increases each year, topping out at 80% in 2027. There is also a rising requirement that 50% of the vehicle’s battery components be manufactured or assembled in North America, with the requirement set to hit 100% in 2029. It is unclear whether automotive manufacturers and the U.S. critical mineral supply chains will be able to meet these targets—and that uncertainty may cause a potential limiting effect on the options a purchaser would have for EVs that qualify for the tax credit.

Time will tell whether the intentions behind the EV tax credits in the IRA have the effect that this particular blogger and PHEV owner is hoping for. While we wait to see whether this bid at creating an equitable EV market bears fruit, we can at least admire this attempt at, as the saying goes, “giving everyone a pair of shoes that fits.”

Article By Dania Abbasi of Foley & Lardner LLP

For more energy and environment legal news, click here to visit the National Law Review.

© 2022 Foley & Lardner LLP

Declaring National Emergency, President Trump Orders Restrictions on Electrical Equipment Supplied By “Foreign Adversaries”

In an Executive Order issued on May 1, 2020, President Trump declared that the unrestricted supply of electrical equipment from foreign countries represents an “unusual and extraordinary threat to the national security, foreign policy, and economy of the United States” because foreign adversaries may use such equipment to sabotage the nation’s electric power supply. While the scope of the order will not be clear until rules to carry it out are put in place, the order could prove disruptive to the supply chains for substations, transformers, and other equipment essential to operation of the nation’s electric power system, as well as to a new generation of “smart grid” devices that are transforming the electric grid, especially for devices that are manufactured in China.

The vulnerability of the electric system to malicious software and other threats embedded in equipment or components manufactured in the territory of hostile powers has long been recognized as a potential problem. In fact, the North American Electric Reliability Corporation, the entity responsible for promulgating and enforcing mandatory electric reliability standards, has developed a reliability standard (CIP-013-1) governing “Supply Chain Risk Management,” although the effective date for the standard was recently delayed by the Federal Energy Regulatory Commission due to the COVID-19 crisis.

In contrast to CIP-013-1, which requires each entity subject to the standard to develop its own plan for ensuring that relevant supply chains are free from cybersecurity risks, the new Executive Order contemplates a top-down approach, in which certain “foreign adversaries” would be identified and imports from those “adversaries” would be prohibited, although transactions with certain vendors would be allowed if they are on a “pre-approval” list. Notably, the Executive Order applies “notwithstanding any contract entered into or any license or permit granted prior to the date of this order” and authorizes the Secretary of Energy to act against “pending transactions” that might violate the order. Hence, the Executive Order could be applied retroactively, particularly to transactions that are now in process.

This aspect of the Executive Order is particularly troubling because it is likely to be at least several months before the exact reach of the Order is known. The Order directs the Secretary of Energy, in cooperation with other federal departments, to promulgate rules carrying out the Executive Order within 150 days. It is likely that the list of “foreign adversaries” will include China, which is an important link in the supply chain for many companies, as well as Russia, Iran, and North Korea. But that remains an unknown, as does the list of suppliers that might be included on the pre-approved list. The Executive Order is limited to the “bulk electric system”—high voltage transmission lines, substations, and related equipment – but contains a provision that could expand its reach to electric distribution systems, an area generally left to state regulation, based on recommendations from a security task force to be formed under the Executive Order.

The Executive Order creates new and potentially serious regulatory, contractual, and supply chain management issues for companies engaged in operation of the bulk electric system, in the manufacture of equipment necessary for operating the bulk electric system, and for emerging “smart grid” technologies that promise to improve the operation and efficiency of the bulk electric system.

© 2020 Beveridge & Diamond PC

For more on America’s electric infrastructure, see the National Law Review Environmental, Energy & Resource law section.

Three Strategies to Develop Renewable Energy Projects on Potentially Contaminated Lands

Developing renewable energy on contaminated lands has proven to be both effective and cost-effective for companies pursuing a new solar or wind energy project. The utility-scale solar farm constructed on the 120-acre Reilly Tar & Chemical Corporation Superfund site is a great example, and there are thousands more that are ripe for redevelopment.

Renewable energy continues to grow in volume and importance in the U.S. as corporations drive demand for sustainable energy, with 166 companies to date committing to go 100 percent renewable as part of a global initiative called RE100. At the same time, states and local governments are driving policy that prioritizes sustainable energy development. Two recent Illinois bills, the Path to 100 Act (HB 2966/SB1781) and Clean Energy Jobs Act (HB3624/SB2132), seek to incentivize the development of new renewable energy and move the state to 100 percent renewable energy by 2050. Other states, including California, New Jersey, New York, and Wisconsin, have called for or passed similar laws.

Using Superfund sites, brownfields, retired power plants, and landfills offers potential benefits to developers and community stakeholders:

  • Preserve Open Space: Large-scale renewable energy facilities – often called “utility scale” projects – can require a lot of land that may displace or impact agricultural lands, open space, or other “greenspace.” Developing renewable energy on potentially contaminated properties can help to preserve the “greenspace” while returning blighted lands to sustainable and productive use.

  • Lower Costs and Shorter Timeline: Developers can significantly lower costs and timelines because contaminated sites are usually already served by existing infrastructure, like substations, power lines, and roads, which would otherwise need to be constructed. Streamlined permitting and zoning can also reduce costs and timelines because potentially contaminated property is often already zoned for industrial or commercial use, which likely poses fewer obstacles to constructing renewable energy structures. Decreased land costs, programs for the procurement of renewable energy credits generated from developing renewable energy projects on brownfields or potentially contaminated properties, and federal and state brownfield tax incentives can drive costs down even further.

  • Greater Community Support: Communities may be quicker to get behind renewable energy projects that are sited on potentially contaminated lands because, rather than taking agricultural land out of production, the projects can clean up the otherwise abandoned sites, boost surrounding property values, increase tax revenues, and provide low-cost clean power.

Despite these benefits, developers often build renewable energy facilities on greenspaces rather than brownfields because of concerns related to potential liabilities or contamination. Below are three strategies that developers can use to move past those concerns and develop a successful renewable energy project on potentially contaminated lands.

  1. Screen Sites for Renewable Energy Potential

Screen potentially contaminated properties to see whether they’d be a good fit for your renewable energy project. For example, confirm that a property has enough usable space and is close enough to transmission or distribution lines to support development. Determine whether a site is free from land-use restrictions that would preclude the use of your chosen renewable energy. Ensure the community doesn’t already have a plan in mind to redevelop the property you’re assessing. And inspect the property for evidence of potential contamination, like soil surface staining or debris stockpiles. If a site has not yet been assessed, you will need to investigate the site to determine whether redevelopment is appropriate. To help, the EPA has published guidance to assist prospective developers in screening prospective sites for solar and wind projects on potentially contaminated lands.

  1. Coordinate the Cleanup and Renewable Energy Development

Developing renewable energy can occur at any stage of a property cleanup, from site inspection and preliminary assessment to post-construction completion. However, identifying and coming to a site at the beginning of or early on in the cleanup process has its advantages. It allows you to engage the community and other stakeholders, including potentially responsible parties, from the start of the redevelopment. It also allows you to coordinate and integrate the cleanup and renewable energy development decisions. For example, you can work with the governmental agency overseeing the site to fold renewable energy design requirements into the remedial design, rather than having to construct renewable energy structures on top of and around the completed remedy. Getting in early will ensure that the renewable energy project is compatible with the remedial design, institutional controls, monitoring activities, and engineering controls.

  1. Protect Yourself from Liability Exposure

Many prospective developers, purchasers, and lenders stay away from or tread cautiously around building on contaminated properties for fear of liability under federal or state cleanup laws. However, many state cleanup programs provide liability protections for new owners or lessees, like a developer, who are not responsible for prior contamination at a site. The federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) also generally limits EPA enforcement at certain qualifying brownfield sites, known as “eligible response sites”, where a party is conducting a response action in compliance with a state cleanup response program. Contact a lawyer and work with state government early on in the process to see what liability protections are available to you and how to qualify.

Other contaminated properties may be addressed under the CERCLA cleanup program. CERCLA has several self-implementing liability protections for developers and the like who acquire contaminated property but did not cause the contamination, including a protection for “bona fide prospective purchasers.” Ensure that you take the required steps to qualify for the BFPP protection, which will include, among other things, working with an environmental consultant to conduct “all appropriate inquiries” through a Phase I environmental site assessment. CERCLA can also offer liability protections for people who lease contaminated properties.

 

© 2019 Schiff Hardin LLP
This post was written by Alex Garel-Frantzen and Amy Antoniolli of Schiff Hardin LLP.

DOE Releases 2014-2015 Offshore Wind Technologies Market Report

On September 29, 2015 the Department of Energy released the 2014-2015 Offshore Wind Technologies Market Report, assessing the nation’s offshore wind potential and planned projects through June 30, 2015. The report summarizes domestic and global market developments, technology trends, and economic data with the purpose of aiding U.S. offshore wind industry stakeholders. The Report builds upon previous market reports conducted by the Navigant Consortium between 2012 and 2014, which would track U.S. wind projects that had reached an “advanced stage” of development. The 2015 Market Report not only assesses the progress of offshore wind projects in various stages but it also analyzes projects in a range of countries. To learn more about where the U.S. offshore wind industry stands in comparison to other countries as well as about domestic and global ongoing projects and expected trends, read on!

New Method for Tracking Offshore Wind Projects

The National Renewable Energy Laboratory (NREL) re-developed its system for classifying and tracking the progress of projects within the development pipeline. The purpose of this new method is to increase connectivity across markets and regulatory regimes as well as to objectively assess the status of projects.

Global Offshore Wind Market on Target to Set Annual Deployment Record in 2015

The increase in offshore wind projects in the pipeline is leading to an upsurge in operational capacity spread out across the world. While 1,069 megawatts (MW) of new wind capacity was installed in 2014, it is expected that 2015 will provide approximately 3,996 MW of wind capacity, making 2015 a record year for offshore wind deployment. The total global installed capacity is now 8,990 MW. At this rate, the global cumulative capacity could exceed 47,000 MW by 2020. Projects are also beginning to spread out beyond Europe. While currently 63% of the projects are located in Europe, 23% are located in Asia, 9% in North America, and 5% spread across the rest of the world.

15,650 MW of U.S. Projects are in Various Stages of Development

There are 21 U.S. offshore wind projects in the development pipeline, which equates to 15,650 MW of potential installed capacity. 13 of these projects have achieved site control or a more advanced phase of development. While most of the offshore wind projects are located in the North Atlantic region, there seem to be feasible offshore resources in the South Atlantic, Great Lakes, Gulf of Mexico, and Pacific regions of the U.S.

Deepwater Wind Begins Installation of First U.S. Offshore Wind Project

The Block Island Wind Farm (BIWF) began offshore construction in 2015. Led by Deepwater Wind, clients of ML Strategies, BIWF is expected to be the nation’s first offshore commercial wind project, it also has the potential to lower electricity prices for the residents of Block Island, provide substantial clean energy to the mainland townships of southern Rhode Island as well as produce approximately 300 jobs during its construction phase.

Cost Trends and Learning from Europe

Offshore wind projects are capital-intensive, where utility scale projects (>200 MW) generally require investments of over $1 billion. With projects expected to be built in locations that are located in deeper water, further away from shore, and larger in size, operating costs becomes an even greater concern. The industry is focused on introducing a variety of technological innovations to drive down the cost. The DOE’s Report suggests the U.S. will likely enact a cost structure similar to that of Europe. Part of the reason Europe’s offshore wind industry is so widespread is due to its ability to subsidize projects via investors and its action on the part of policymakers. For instance, policymakers in the UK have set goals to reduce the Levelized Cost of Electricity (LCOE) and are implementing programs designed to lower costs, reduce risk to developers, and minimize the prices required to make projects financially viable as evidenced by their initiation of competitive auctions for subsidies, their classification of zones that emphasize size affordability (choosing projects closer to shore), and their sponsoring early-stage development activities to reduce uncertainty about site conditions. Recent state and federal policy developments including President Obama’s issuance of the Clean Power Plan regulation and the initiation of the BIWF project provide hope for the U.S.’ offshore wind industry.

Overall, even though the EU continues to lead projects in the wind industry, the industry is becoming more geographically dispersed with projects now underway in the U.S. and Asian markets. While the biggest challenge the U.S. offshore industry faces is the current high cost of offshore wind generation, the industry is focused on cutting such costs through leveraging European technology and experience.  It is also the hope that cost reductions of projects in the EU caused by its target to reduce the LCOE for offshore wind projects, the Cost Reduction Monitoring Framework set up by the UK government, and additional actions by policymakers, will translate to the U.S., further strengthening the wind industry in the U.S.

Article By R. Neal Martin & Sarah Litke of Mintz, Levin, Cohn, Ferris, Glovsky and Popeo, P.C.

©1994-2015 Mintz, Levin, Cohn, Ferris, Glovsky and Popeo, P.C. All Rights Reserved.

IRS Releases Favorable Guidance for Individual Investors in Community Solar to Claim Section 25D Tax Credit

The IRS recently issued a Private Letter Ruling (PLR) clarifying that an individual investor in a net-meted community solar project may claim the federal residential Investment Tax Credit (ITC) under Section 25D of the Internal Revenue Code. (A copy of the PLR is available here.) The PLR is also significant because it appears to eliminate a number of contractual requirements that the utility and taxpayer needed to agree to regarding the tracking and ownership of the power produced by the solar project to be eligible for the credit.

Section 25D Tax Credit and Prior IRS Guidance

Just like the Section 48 ITC, the Section 25D ITC permits an owner of solar and other renewable energy property installed before January 1, 2017 to receive a 30% tax credit against federal income taxes. However, in order to claim the credit the property must “generate electricity for use in a dwelling … used as a residence by the taxpayer.” Some tax practitioners interpreted that to meant the credit was limited to solar projects on or adjacent to the taxpayer’s residence. A few years ago, the IRS provided some guidance in Notice 2013-70 (at Q&A Nos. 26 and 27) that taxpayers could in fact claim the credit for off-site solar projects. However, the fact pattern in the Notice described an off-site net-metered project that was owned by the taxpayer, so questions remained whether taxpayers could claim the credit for investments in co-owned community solar projects. Further, the IRS limited the Notice so that it only applied to net-metering arrangements whereby the taxpayer specifically contracts with its local utility to track “the amount of electricity produced by the taxpayer’s solar panels and transmitted to the grid and the amount of electricity used by the taxpayer’s residence and drawn from the grid” as well as stipulate in the contract that the taxpayer holds title to the energy until it is delivered to the taxpayer’s residence. These requirements were problematic because they were often at odds with utility tariffs and state net-metering laws.

The PLR

The PLR is partially redacted but it was provided to a Vermont taxpayer requesting clarification as to whether his investment to purchase 10 solar panels in a 640-panel community solar farm along with a partial ownership in related racking, inverters and wiring is eligible for the Section 25D ITC. (A brief write-up about the project and taxpayer in the local press is available here.) The PLR explains that the project’s entire solar energy output is provided to the taxpayer’s local utility which then calculates a net-metering credit pursuant to its tariff and applies a portion of that credit against the taxpayer’s monthly electric bills. The PLR also explains that the taxpayer’s solar panels are not expected to generate electricity in excess of what the taxpayer will consume at his residence and that the taxpayer along with the other owners of the community solar project are members of an entity that coordinates with the utility the information needed to calculate each person’s allocable share of energy produced by the entire project. Based on these facts, the IRS determined that the taxpayer is entitled to the Section 25D credit. The PLR makes clear the fact that other individuals own solar panels in the project’s solar array does not disqualify the taxpayer from claiming the Section 25D ITC. The PLR did away with the requirement the utility specifically track the exact amount of electricity produced by the taxpayer’s portion of the community solar project and can instead determine the taxpayer’s allocable share of the entire project. The PLR also did away with the requirement the utility contractually agree that the taxpayer retains ownership of the electricity until delivered at his residence. Thus, to recap, under the PLR a taxpayer investing in a community solar project is generally entitled to the Section 25D ITC so long as: (1) the community solar project provides power to the taxpayer’s local utility, (2) the utility provides a credit for the taxpayer’s allocated energy production of the entire project, and (3) the taxpayer’s allocable share is not in excess of its residential needs.

Impact

It is important to note PLRs only apply to the individual taxpayer requesting the ruling and may not be cited or relied upon as precedent by other taxpayers. That said, PLRs provide valuable insight to the IRS’s views on a particular matter, and we expect that this PLR should incentivize investment in community solar and lead to even further expansion in the market. Until now, the market has been primarily driven by tax equity investors claiming the Section 48 ITC and depreciation, however, this PLR opens up opportunities for homeowners who cannot install solar systems for various reasons to invest in community solar.

Article By David B. Weisblat & Kurt R. Rempe of Foley & Lardner LLP
© 2015 Foley & Lardner LLP

Federal District Court sets aside 30-Year Eagle Take Permit

On August 11, 2015, a United States District Court judge halted a years-long effort by the United States Fish & Wildlife Service (“FWS”) to smooth the federal permitting path for wind energy. Shearwater et al. v. Ashe, No. 14-CV-02830-LHK (N. D. Cal.)(August 11, 2015). Specifically, the judge set aside a rule allowing for activities such as wind energy projects to kill bald eagles and golden eagles for up to 30 years.

FWS’s efforts began back in the current administration’s first year with the first ever authorization for either individual or programmatic take permits of bald or golden eagles under the Bald and Golden Eagle Protection Act (“BGEPA”) of 1940. (Decision at p. 6) The FWS explained at the time that “the rule limits permit tenure to five years or less because factors may change over a longer period of time such that a take authorized much earlier would later be incompatible with the preservation of the bald eagle or the golden eagle.” (Decision at p. 7, citing 74 Fed. Reg. at 46,856). As explained in the court’s decision, the FWS downplayed anticipated use of the new permits for wind energy projects, stating that “the wind power facility could obtain a programmatic permit only ‘[i]f [advanced conservation practices] can be developed to significantly reduce the take’ resulting from ‘the operation of turbines.’” (Decision at p. 8, citing 74 Fed. Reg. 46,842)(emphasis supplied).

Shortly after adopting its new 5-year rule, however, there was a significant increase in wind energy projects. Decision at p. 9. In response, the FWS developed its Eagle Conservation Plan Guidance, a voluntary guidance, which introduced advanced conservation practices or ACPs for the wind energy sector, including experimental ACPs (i.e., scientifically unproven). Id.

The wind energy industry, although undoubtedly pleased to have secured a programmatic take permit for the accidental or incidental killing of bald and golden eagles, commented on the 5-year permit program, complaining that a 5-year permit was unworkable in that projects were developed for a useful life of twenty to thirty years, and the shorter permit term made financing difficult. As a result of its concern that wind energy projects were not able to get permits as a result of the uncertainty of potential future regulatory changes regarding the killing of eagles, FWS proceeded with efforts to move to a 30-year permit “as soon as possible.” Decision at p. 10. The court notes that “[a]t bottom, FWS issued the Proposed 30-Year Rule ‘[b]ecause the industry has indicated that it desires a longer permit.’” Id.(emphasis supplied).

Internal debate ensued at the FWS regarding the proposed 30-year permit rule. Despite concerns and staff opinions that an EIS would be needed to support the rule, FWS Director Dan Ashe instructed his staff not to conduct further NEPA work, that an NGO lawsuit was unlikely, and to proceed. Id. at p. 13-16. The rule was finalized and effective as of January 8, 2014. A lawsuit followed five months later.

The FWS’s efforts to accommodate wind energy development and facilitate additional permitting through its 5-year and 30-year eagle take permits appear to pre-date the recent Clean Power Plan, which notably incentivizes the development of wind and other non-emitting energy sources. The effort, though, certainly is consistent with the Clean Power Plan and this administration’s encouragement of renewable energy sources.

In its August 11th ruling, the court concluded that FWS failed to comply with NEPA, set aside the 30-year rule and remanded the rule for further consideration by FWS. During the remand of the rule, the 5-year permit should still be available as an option for applicants.

Article By Allyn G. Turner of Steptoe & Johnson PLLC

© Steptoe & Johnson PLLC. All Rights Reserved.

New Report on Renewable Energy as an Airport Revenue Source

The Airport Cooperative Research Program (ACRP) has recently published a guidebook on Renewable Energy as an Airport Revenue Source. The link to the guidebook on the ACRP website is here. David Bannard is a co-author of the guidebook, for which the lead authors were Stephen Barrett and Philip DeVita of HMMH.

solar energy, sustainable, clean power, renewable, source, sun

Airports are exploring non-traditional revenue sources and cost-saving measures. Airports also present a unique and often accommodating environment for siting renewable energy facilities, from solar photovoltaics (PV) to thermal, geothermal, wind, biomass and other sources of renewable energy. Although the guidebook focuses on the financial benefits of renewable energy to airports, it also notes other business and public policy benefits that can accrue from use of renewable energy at airports.

The guidebook includes case summaries of 21 different renewable energy projects at airports across the United States and in Canada and the U.K. Projects summarized include solar PV, wind, solar thermal, biomass, and geothermal technologies. In addition the guidebook examines factors to be considered when evaluating airport renewable energy projects, conducting financial assessments of airport renewable energy and issues relating to implementing airport renewable energy projects. Airports present unique challenges and opportunities for development of renewable energy facilities. The ACRP’s recent publication helps both airport operators and renewable energy providers and financiers understand and address many of these complex issues presented in the airport environment.

ARTICLE BY David Y. Bannard, Jason W. Allen & Jeffery R. Atkin of Foley & Lardner LLP

© 2015 Foley & Lardner LLP

Part Three: An Overview of the Legal Mechanisms for Challenge and Redress by Those Potentially Affected by the Early Closure of the Renewables Obligation

In the first two parts of this series, we considered how the RO operates, possible plans to close the RO in 2016, and the potential impact of those plans upon the onshore wind industry. In this final post, we outline two possible legal avenues for challenge and redress by those who may be affected by the early closure of the RO: through the national courts and under international investment treaties.

windmill vertical

The first possibility is to challenge the Government’s actions through the national courts. This route recently has been used by the solar industry, with mixed results. In 2012, the Supreme Court refused the Government’s appeal to cut solar feed-in-tariffs before the completion of a consultation on the matter. However, in November 2014, the High Court refused an application for judicial review against the Government’s decision to close the RO to ground and building mounted solar photovoltaic capacity above 5 megawatts in 2015 rather than 2017.

Affected investors could also consider commencing international arbitration proceedings under an investment treaty. If successful, an investor could obtain compensation for the loss of their investment as a result of measures introduced by the Government. However, this option would only be available to foreign investors from member States that have an investment treaty in place with the UK, and who have made a qualifying investment in the UK, as defined by the applicable treaty.

A number of European states, including Spain, are currently being sued by foreign investors under the Energy Charter Treaty as a result of changes to national solar subsidies. Marcus Trinick QC, representing Renewables UK, has warned Energy Minister Amber Rudd to “be aware of the dangers of state aid discrimination and look at what is happening in international energy arbitration across Europe. In such a position we could not afford not to fight, especially if action is taken to interfere retrospectively.”

Media reports suggest that, given the extent of industry opposition, DECC is delaying an announcement to allow for further refinement of the proposed measures and their impact, in order to reduce the scope for legal challenges. Marcus Trinick QC has emphasised the need for dialogue between the industry and the Government before action is taken, which could reduce the risk of legal challenges arising.

The message from industry representatives is clear: the early closure of the RO would be a major blow to the future of onshore wind in the UK, which could spark a legal battle with the UK Government. As Maf Smith, deputy chief executive of RenewableUK, has stated, “[t]he industry will fight against any attempts to bring in drastic and unfair changes utilising the full range of options open, including legal means if appropriate.”

Part One: An Overview of the Renewables Obligation and Plans for Its Early Closure

Part Two: How Would the Renewables Obligation’s Early Closure Affect the UK Onshore Wind Industry?

ARTICLE BY William Lowery & Catherine Karia of Covington & Burling LLP

© 2015 Covington & Burling LLP

Part Two: How Would the Renewables Obligation’s Early Closure Affect the UK Onshore Wind Industry?

Part One of this series outlined the RO scheme and the expected announcement to close the RO earlier than anticipated. In this second post, we consider the potential impact of such measures upon the onshore wind industry.

Until the consultation with devolved authorities (Scotland and Northern Ireland) is completed, and detailed proposals are published, the timing and nature of the impact on the industry will be uncertain.

There are currently around 3,000 new turbines with a combined capacity of more than 7 gigawatts seeking planning permission, many of which would have been expecting to secure accreditation under the RO. Bloomberg Energy Finance has estimated that, if the RO closes to new generating capacity in 2016 and onshore wind was not eligible for public subsidy under the Contracts for Difference scheme, less than half the capacity of projects in advanced stages of planning would benefit from subsidies.

The majority of the planned projects are due to be located in Scotland. Given the apparent tension between the Scottish First Minister and Prime Minister over the future of onshore wind (referred to in our first post in this series), there is currently uncertainty as to whether or not the applicable RO in Scotland would close in 2016. This is an important consideration regarding the possible impact of any proposed measures.

It is unclear whether there would be a ‘grace period’ in relation to the changes, which could enable projects that already have planning permission to be included under the RO scheme, and closing the RO for those that do not. Ian Marchant, chairman of wind developer Infinis Energy, said: “The Government’s alleged plans to close down the Renewable Obligation-regime early for onshore wind beggar belief. . . . If the RO is terminated early without reasonable grace periods in place, not a single energy or large scale infrastructure project in the UK will be safe going forward.”

The potential impact of such measures is giving rise to considerable uncertainty and concern over the future of the onshore wind industry. In our final post in this series, we will consider what action could be taken by industry participants who may be affected by the early closure of the RO.

Part One: An Overview of the Renewables Obligation and Plans for Its Early Closure

Part Three: An Overview of the Legal Mechanisms for Challenge and Redress by Those Potentially Affected by the Early Closure of the Renewables Obligation

ARTICLE BY William Lowery & Catherine Karia
Covington & Burling LLP

© 2015 Covington & Burling LLP