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Senate Democrats Propose Overhaul of Clean Energy Incentives

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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Following Recent Maryland Ruling, Federal Court Declares New Jersey Scheme to Promote Investment in In-State Generation Unconstitutional

by Ari Peskoe

A Federal District Court Judge for New Jersey struck down the state’s incentive program to encourage construction of in-state generation capacity.  New Jersey’s scheme was similar to Maryland’s scheme that was the subject of a District Court ruling last month.  The Judges in both cases found that the state intruded on Federal ratemaking authority in violation of the Supremacy Clause of the Constitution.

New Jersey regulators concluded that insufficient transmission and increasing demand could lead to reliability problems in the state.  Working with state legislators, the Board of Public Utilities (BPU) developed the Long-Term Capacity Agreement Pilot Program (LCAPP), an incentive scheme designed to encourage gas-fired generation in or near New Jersey.  Like the Maryland incentive, New Jersey’s program guaranteed developers of new generation payments from the state’s incumbent utilities if PJM’s capacity auction resulted in a price lower than a set price that reflected development costs of new in-state generation.

The Judge found that state’s LCAPP occupies the same field of regulation and intrudes upon FERC’s authority to set wholesale rates through its approved PJM capacity auction.  Because LCAPP requires generators to clear the PJM capacity auction and the LCAPP rules incorporate PJM’s auction rules, the Judge determined that the state’s LCAPP is “not separate from, and to the contrary, occup[ies] the same field” as PJM’s auction.  The Judge rejected the state’s argument that LCAPP contracts are merely financial arrangements and therefore not subject to FERC jurisdiction.  According to testimony presented by a plaintiff witness and cited by the Judge, a purely financial contract does not “involve any real performance.”  New Jersey, on the other hand, required developers to build a plant, make capacity available, and clear that capacity in the PJM auction.  The Judge therefore found that payments under the state’s LCAPP contracts were in exchange for performance.

The Judge also found that plaintiffs had not met their burden of proof that LCAPP violated the Commerce Clause of the Constitution.  Plaintiffs argued that in-state generators had advantages in securing LCAPP contracts, which effectively prohibited out-of-state generators from competing.  According to the Judge, the BPU has authority to incentivize construction in New Jersey, and it “appears reasonable that the [BPU] would incentivize construction in areas where reliability concerns are in flux.”  The Judge therefore found that the in-state benefit is reasonable in light of New Jersey’s interest in ensuring reliable electric service.

The decisions in this case and in the Maryland case both struck down state incentive schemes that required utilities to pay the difference between a set contract price and a price determined by a FERC-regulated wholesale auction market.  Such a scheme, according to these two judges, sets the price received by a generator and therefore impermissibly intrudes on federal ratemaking and is void under the Supremacy Clause.

The Judge in the New Jersey case suggested alternative incentives, including tax exempt financing, property tax relief and favorable leases on public lands.  However, rather than routing incentives through [...]

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Federal Court Rules Maryland Scheme to Promote Investment in In-State Generation Unconstitutional

by Ari Peskoe

On September 30, a Federal District Court Judge for Maryland declared that the state’s incentive scheme to encourage the construction of new gas-fired generation capacity violates the Supremacy Clause of the Constitution.  By requiring incumbent utilities to supplement PJM’s market-clearing prices with payments to the developer of a new gas-fired generator, the Judge determined that Maryland’s incentive scheme impermissibly sets a wholesale rate.  The Judge’s ruling may complicate states’ efforts to ensure that FERC-jurisdictional electricity markets meet the goals of individual states.

In 1999, Maryland restructured its electricity industry, requiring its investor-owned utilities to divest their generation assets and purchase electricity in federally regulated, regional wholesale markets. In 2007, at the direction of the Maryland General Assembly, the state’s Public Service Commission (PSC) published a report that concluded that the state faced a critical shortage of generation capacity.   According to the PSC, Maryland was located in a highly congested portion of the regional PJM market and therefore paid higher than average prices for wholesale energy.  The PSC found that while the PJM markets are “structured ostensibly to create price incentives for [investment in] new generation and transmission,” the markets had not responded to the state’s “looming capacity shortage.”

Following several proceedings at the PSC, including the issuance of an RFP to construct new gas-fired capacity in Maryland, in April of 2012 the PSC issued an order directing the state’s three incumbent utilities to enter into contracts for differences (CfDs) with a developer that would construct 661 megawatts of new in-state generation capacity. Under the CfDs, the utilities would pay the developer the difference between set contract prices and the PJM clearing prices for energy and capacity.  When the PJM prices were lower than the contract prices, the utilities would pay the developer.  When PJM prices were higher than the contract prices, the developer would pay the utilities.

The plaintiffs – primarily existing generators – complained that the PSC’s order impermissibly regulated the price of wholesale energy sales.  Such sales, they argued, may not be regulated by states because the “scheme of federal regulation . . . [is] so pervasive as to make reasonable the inference that Congress left no room for the states to supplement it.”  The Judge agreed, concluding that the PSC is “establish[ing] the price ultimately received [by the developer] for its physical energy and capacity sales to PJM . . . under field preemption principles, the PSC is impotent to take regulatory action to establish the price for wholesale energy and capacity sales.”  In other words, the Judge concluded that the PSC set the rate and not merely that its order affected the rate by inducing the developer to bid into the PJM markets.

The Judge rejected the defendant’s argument that the CfDs merely finance construction and therefore do intrude on FERC’s ratemaking.  First, to get paid under the CfDs the developer’s bids had to clear the PJM market.  Payment required delivery of energy and not [...]

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Massachusetts DOER Finalizes Rules for Solar Carve-Out Program

by William Friedman

The Massachusetts Department of Energy Resources (DOER) announced that it re-filed its Solar Carve-Out Emergency Regulation without any changes, thereby finalizing the temporary regulations that had been in effect for the past three months and bringing stability to the existing Solar Carve-Out program.  The Solar Carve-Out program enables participating solar units to produce valuable Solar Renewable Energy Credits (SRECs), which can be sold on the open market or at auction.  Earlier this year, DOER announced that applications exceeded the Solar Carve-Out program’s 400 MW cap.  In late June, DOER released the Emergency Regulation to deal with the program’s oversubscription and to offer a path forward for projects that were uncertain as to whether they would still qualify for incentives under the Solar Carve-Out. 

Under Massachusetts law, however, the Emergency Regulation could only remain in effect for three months if not finalized into law.  Finalizing the regulations gives all projects relying on the terms of the Emergency Regulation certainty that the previously announced requirements and construction timeline will remain in force.

Along with its announcement of the re-filed regulations, DOER released a draft guideline for qualified Solar Carve-Out units seeking an extension of the December 31, 2013 construction deadline.  Under the regulations, in order to qualify for the Solar Carve-Out, a solar project must be completely installed and receive authorization to interconnect from the local distribution company by December 31, 2013.  If a project does not meet the December 31 deadline, it may receive an extension until June 30, 2014, if it can demonstrate that it expended at least 50 percent of its total construction costs by December 31, 2013. 

The draft guideline explains that DOER will only consider costs associated with building the generating units as construction costs, and will not take into account legal fees, permitting, or financing costs.  The guideline provides two alternative methods for calculating the total construction costs of a generation unit.  First, the owner or operator can multiply the solar unit’s direct current capacity by the corresponding dollar per watt cost, as set out in the table below.  Second, the owner or operator of the generation unit can provide DOER with actual demonstrated costs.  All eligible costs must be incurred no later than December 31, 2013.

No later than January 6, 2014, all generation units seeking an extension must submit their applications for extension to DOER. DOER will notify applicants of its decision within 30 days.

Finally, if a project can demonstrate that it is ready to begin operations and is only waiting for a distribution company to issue its authority to interconnect, the interconnection deadline is extended indefinitely.




Solar Energy Industries Association Proposes Compromise Plan for U.S. – China Solar Conflict

by Raymond Paretzky and Melissa Dorn

The Solar Energy Industries Association (SEIA) has announced a proposal to address the trade dispute between the United States and China regarding solar generating equipment.  Both China and the U.S. have imposed duties on imports of solar equipment: (i) the U.S. Commerce Department found that certain Chinese solar companies had benefited from government subsidies and “dumped” their products into the U.S. market at prices below fair value, and (ii) in July, China began imposing duties as high as 57 percent on imports of polysilicon, a main ingredient in solar cells, from the U.S.  SEIA’s proposal would result in the termination of current disputes, a prohibition on new trade actions, and the establishment of funds to support the U.S. solar industry.

The U.S. trade remedy orders on Chinese solar cells and modules have resulted in Chinese manufacturers attempting to circumvent the antidumping and countervailing duty (AD/CVD) orders by assembling third-country cells into modules in China and then legally importing those modules into the U.S. free of AD/CVD duties.  (See McDermott’s Energy Business Law blog post on the AD/CVD orders.)  SEIA contends that the U.S. and Chinese trade remedy orders currently in place are causing adverse effects in the global solar industry without ultimately addressing the causes of unfair trade competition.

SEIA has been actively involved in the trade proceedings both in the U.S. and in China, and through its proposal hopes to provide a solution that is a “win-win” for both countries, the industry and consumers.  The SEIA proposal would:

  • Establish a U.S. Solar Manufacturing Settlement Fund (Fund) and a U.S. Solar Development Institute (Institute), both funded by Chinese solar manufacturers.  The Fund would help finance the production of solar equipment in the U.S. through investments in capital equipment, facilities, research and development, worker training and other areas.  The Institute would work to expand the U.S. solar market and grow the U.S. solar manufacturing base. Money for the Fund and the Institute would come from Chinese companies contributing a percentage of the price premium they currently pay to third-country cell producers to avoid the U.S. AD/CVD orders.  The U.S. entered into a similar settlement arrangement regarding the Brazilian cotton industry.
  • Require both the U.S. and China to revoke all AD/CVD orders and terminate all regulatory and judicial proceedings related to U.S. imports of solar cells and modules from China and Chinese imports of polysilicon from the U.S.
  • Prohibit the initiation of any new trade remedy investigations or other actions between the U.S. and China regarding imports of polysilicon, solar cells, or modules for the five-year term of the proposed agreement plus 12 additional months thereafter.

While the proposal has not met with an entirely positive response from the U.S. solar manufacturing industry, certain U.S. Senators, including Senators Patty Murray and Maria Cantwell, have expressed support for the proposal.   In the meantime, China recently announced additional tax breaks, in the form of refunds of 50 percent [...]

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

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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DOE Announces Funding for Hydrokinetic Power Projects

by Bethany Hatef

The Department of Energy (DOE) announced last week that it will commit $16 million toward 17 projects to capture energy from waves, tides and currents.  In a press release, DOE stated that the commitment is “part of the Obama Administration’s all-of-the-above strategy to deploy every available source of American energy.”  Although DOE’s committed funds are relatively modest, they may spur the growth of a largely untapped but potentially significant clean source of domestic power.

Wave and tidal, or hydrokinetic, energy, a renewable fuel source, may be captured where large volumes of water are moved (e.g., changing tides and currents).  According to DOE, development of this resource may supply clean and reliable power to millions of homes, including in many coastal U.S. cities with high power demands.  DOE’s latest assessments found that wave and tidal energy could potentially generate up to 1,400 terawatt hours (or 1.4 billion megawatt hours) annually.  (One terawatt hour would be sufficient to power 85,000 homes.)

A hint of government support for hydrokinetic energy production first arose in 2009, when the Federal Energy Regulatory Commission (FERC) and the Bureau of Ocean Energy Management (BOEM) entered into a memorandum of understanding addressing their respective jurisdiction over hydrokinetic projects on the Outer Continental Shelf.  In January 2012, FERC issued its first pilot project license for a hydrokinetic project, which will generate power from the tidal flow of the East River in New York.  In August of this year, BOEM issued a Finding of No Significant Impact with respect to a proposed hydrokinetic power project off the Florida coast, giving the go-ahead for the first such BOEM-leased project.

DOE’s commitment consists of $13.5 million for eight projects to assist American companies with building wave and tidal devices to reduce production costs and maximize the harnessed energy.  These projects “will develop new drivetrain, generator and structural components as well as develop software that predicts ocean conditions and adjusts device settings accordingly to optimize power production,” according to DOE’s press release.  Additionally, DOE will provide $2.4 million to nine projects “that will gather and analyze environmental data from wave and tidal projects as well as potential development zones” to proactively handle environmental impacts and promote efficient development.




Massachusetts DPU Adopts Procedures for Relaxing Eligibility for Net Metering Renewable Energy Facilities

by William Friedman

The Massachusetts Department of Public Utilities (DPU) recently issued an order giving greater flexibility to renewable energy projects seeking to qualify for Massachusetts’ net metering program. Net metering allows the owner of a renewable energy project (such as wind or solar) to receive a retail credit for at least a portion of electricity it generates and feeds back into the grid. In a previous order, the DPU defined the terms facility and unit in order to provide guidance as to which projects can qualify for net metering in Massachusetts.  

The recent order confers on the DPU and local distribution companies flexibility to relax certain eligibility requirements for net metering.  In a previous order, the DPU made eligibility contingent on the generating facility being located on a single parcel of land, with a single point of interconnection, behind a single meter.  While these eligibility criteria offer clear, easily verifiable parameters for net metering projects, they can also inhibit the development of certain net metering projects, such as large public net metering facilities up to 10 MW, which may be safer and more reliable and efficient if interconnected to the electric grid at multiple points.

The DPU’s recent order declines to grant any blanket exemptions from the eligibility criteria, but it does allow individual exceptions to be granted when required for optimal interconnection.  A petition for an exception to the single parcel rule may now be filed with the DPU, and an exception to the single meter or single point of interconnection may now be sought from the local distribution company.  The DPU explained that local distribution companies are best situated to determine what constitutes optimal interconnection on their distribution system.  The order directs the distribution companies to apply a consistent standard in granting exceptions, but it declines to establish additional documentation requirements that must be submitted to the distribution companies. 

Along with their new authority to grant exceptions, the distribution companies have the responsibility to ensure that net metering services are provided only to eligible customers.  The DPU is requiring distribution companies to develop a means of evaluating all customers’ and facilities’ eligibility for net metering services at an early stage of project design.  The distribution companies must submit a joint proposal addressing how they will evaluate eligibility for net metering services and when they will communicate with customers about eligibility.




California Proposes Energy Storage Procurement Requirement

by Melissa Dorn

The California Public Utilities Commission (CPUC) recently released a proposal that would require the major investor-owned utilities (IOUs) in the state to procure approximately 1.3 gigawatts (GWs) of energy storage by 2020.  Consistent with state’s energy storage bill, Assembly Bill 2514, which passed in 2010, the CPUC’s proposal aims to reduce market barriers and incentivize development of viable, cost-effective energy storage methods.  The CPUC hopes that the rapid growth of energy storage in California will support the state’s renewable energy industry as the state seeks to meet the legislature’s mandate to have one third of California’s energy generated from renewable sources by 2020.  Many renewable energy sources are intermittent, making energy storage technologies important for the integration of a large quantity of renewable energy into the existing electric system.

Central to the CPUC’s proposal are biannual procurement targets for the three major IOUs, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. The CPUC’s proposed aggregate procurement targets for each IOU are divided into three different “use cases” based on the end uses of the energy storage:  transmission-connected storage systems, distribution-connected storage systems, and customer-sited storage systems. The initial proposed procurement targets are: 

* The Totals include the additional interim targets for 2016 and 2018 that were intentionally omitted from this table.

To procure third-party owned energy storage to meet the targets, the CPUC proposed a “reverse auction” market mechanism, similar in structure to the state’s existing Renewable Auction Mechanism for renewable power sources. Under a reverse auction, energy storage providers would bid non-negotiable price bids, and the IOUs select projects starting with the lowest cost. The first auction, proposed for June of 2014, will require the IOUs to procure an aggregate 200 MW of storage. Subsequent auctions will be conducted every two years. The procurement targets are subject to change if the IOUs can demonstrate, among other things, that the energy storage resources bid into the reverse auction are not reasonable in cost, are not cost effective, or were insufficiently competitive.

The CPUC anticipates releasing its final order in October of this year.




Using the Bankruptcy Code “Safe Harbors”

by Iskender “Alex” H. Catto and Gregory Kopacz

Energy bankruptcies can be rich in opportunity for potential debtors, creditors and distressed-asset purchasers. Failing to understand the “safe harbors” of the bankruptcy code can lead to the evaporation of value, lost opportunity and potential severe disruption to a company’s operations. But, when properly understood, utilizing the safe harbors can be an effective tool in preserving value and mitigating risk.

Click here to read the full article.

This article was originally published in Daily Bankruptcy Review on July 10, 2013.




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