OFAC revokes so-called U-turn authorization for Cuba-related financial transactions
OFAC published a final rule that modifies the Cuban Assets Control Regulations to revoke the so-called "U-turn" authorization.
Chadbourne held a webinar in late August on “What to Ask on Diligence in the Wake of the Clean Power Plan.”
The US government is asking each state to come up with a plan to reduce carbon dioxide emissions from power plants. The amount varies by state. Overall, a 32% drop in carbon dioxide emissions compared to 2005 levels is required by 2030. Fossil fuel-fired power plants are being built, financed, and refinanced despite pending litigation, speculation about how the Clean Power Plan will fare with a new administration, and speculation about how, or even if, some states will implement the plan.
Sue Cowell and Richard Waddington, two environmental lawyers based in Washington, discussed questions that banks, tax equity investors and other project participants should ask on diligence when financing potentially-affected projects.
The first point about due diligence is it should be informed by the deadlines that states face to submit implementation plans to the US Environmental Protection Agency and the associated deadlines to show emissions reductions.
The Environmental Protection Agency issued the Clean Power Plan in August. It is a final rule that will become effective 60 days after being published in the Federal Register, which some expect will occur in October.
EPA also issued a proposed federal plan for reducing carbon dioxide emissions that will apply in states that fail to submit their own plans, and model trading rules intended to guide states in devising trading rules of their own.
EPA will be taking comments on certain aspects of the proposed federal plan and model trading rules. Unless the comment period is extended, comments will be accepted for 90 days after publication in the Federal Register.
We will highlight certain proposals under consideration and explain their relevance.
State implementation plans are due on September 6, 2016. EPA plans to approve or disapprove of a state plan within 12 months after submittal.
States also have the option to submit an initial plan on September 6, 2016 and request a two-year extension for submission of a final plan by September 6, 2018. According to EPA, such extensions will be granted if the initial plan has enough detail for the federal government to understand the final plan the state is considering and explains why additional time is required to complete a final plan. States will be granted automatic extensions if the initial plan contains the required elements unless EPA notifies the state otherwise within 90 days. States granted an extension must submit an update by September 6, 2017 of their progress toward completing a final plan by September 6, 2018.
Some states have already indicated that they do not intend to submit an initial plan. EPA has suggested that it will come up with a federal plan for each such state by the fall 2017 at the latest; however, it may do so more quickly.
States are required to begin taking steps to reduce emissions starting in 2022. The reductions will be phased in over three multi-year interim compliance periods through a final compliance deadline in 2030. During the interim compliance periods, states and affected power plants may meet their respective emission reduction obligations “on average,” thereby providing a degree of compliance flexibility to affected power plants.
Covered Power Plant?
A threshold diligence question is whether the Clean Power Plan even applies to a particular power plant.
The Clean Power Plan covers existing electric generating units – called EGUs – that were in operation or under construction on January 8, 2014 and that meet certain criteria.
Keep in mind that EPA also issued a separate set of carbon standards in August that applies to certain new, modified and reconstructed generating units, so understanding whether an EGU at a power plant is covered under the Clean Power Plan or the separate carbon pollution standards is important.
What it means to have a modification or reconstruction under the carbon pollution standards is beyond the scope of this discussion.
Determining whether an EGU was under construction on January 8, 2014 may require you to dig deeper.
As an initial matter, a new major source of carbon dioxide emissions needs a construction permit under the prevention of significant deterioration program. What is considered a new major source of carbon dioxide emissions is discussed at length in the Clean Power Plan.
There are two ways that an EGU might be considered under construction. The first is through a continuous program of “actual on-site construction” that will be completed within a reasonable time. The second is entry into binding contracts to undertake a program of actual construction that is expected to be completed within a reasonable time.
EPA offered examples of things that count as on-site construction such as placement, assembly, or installation of equipment that will form part of the structure of the new power plant. An example of something that does not generally count is site clearing.
EGUs are divided into two broad categories for purposes of analyzing whether they are covered by the Clean Power Plan: fossil-fueled steam generating units and stationary combustion turbines.
A coal- or oil-fired utility boiler or an integrated-gasification combined-cycle unit is covered by the Clean Power Plan if it serves a generator capable of selling more than 25 megawatts to a utility, has a base-load rating greater than 250 million BTUs per hour heat input of fossil fuel alone or in combination with another fuel, and historically supplied more than a third of its potential electric output and at least 219,000 megawatt hours as net electric sales during any three consecutive calendar years.
For a stationary combustion turbine, the unit is covered by the Clean Power Plan if the unit falls under the definition of a combined-cycle or combined heat and power combustion turbine, serves a generator capable of selling more than 25 megawatts to a utility, has a base-load rating greater than 250 million BTUs per hour heat input of natural gas, and historically combusted more than 90% natural gas on a heat input basis on an annual basis.
How Will It Comply?
Once an applicability determination has been made, then the next diligence question is which of the several rate-based and mass-based compliance options applies to the EGU.
Starting with rate-based compliance, under the federal rate-based proposed plan, EPA set interim and final emissions rate goals for affected steam generating units and separate rates for stationary combustion turbines. The same rate of carbon dioxide emissions will be permitted for every unit of the same type regardless of the state where the unit is located. For example, the final rate for affected steam generating units is 1,305 pounds of carbon dioxide per megawatt hour, while the final rate for a natural gas-fired unit is 771 pounds per megawatt hour. EPA also issued three interim rates for the periods before the final emissions performance rates take effect.
One important aspect of the rate-based option is that, unlike the mass-based approach, the rate-based approach is not designed to be expanded later to include new, modified and reconstructed EGUs at power plants or, as in the current California cap-and-trade program, other sectors of the economy. This may be an important consideration for some states when choosing a rate versus mass system, as the mass system can be expanded.
If a state wants to use a rate-based system, then it will have three basic approaches to choose from.
One approach is for states to adopt separate emissions rates for affected fossil-fuel-fired steam generating units and affected stationary combustion units. States choosing this approach will end up with final emissions standards for affected fossil-fuel-fired steam generating units of 1,305 pounds of carbon dioxide per megawatt hour and 771 pounds of carbon dioxide per megawatt hour for affected natural gas-fired units.
Another approach is for states to set one emissions rate that applies to all affected units in the state. EPA calculated the rate goals for each state. Each state has slightly different rate goals because the mix of generation in each state is different as are EPA’s projected reductions in each state through 2030. For example, the final emissions rate for West Virginia, a state that relies heavily on coal-fired power plants, is 1,305 pounds of carbon dioxide per megawatt hour while the final rate for Rhode Island is 771 of pounds of carbon dioxide per megawatt hour.
Finally, states can come up with their own rate-based programs. However, a state must demonstrate to EPA that its performance standards will result in meeting the overall emissions reduction goal for the state.
Now let’s talk about mass-based programs. The difference between a rate-based approach and a mass-based approach is that the former sets an amount of carbon dioxide emissions per megawatt hour of electricity generated while the latter assigns each state a number of tons of carbon dioxide that it is allowed to emit. Under a mass-based program, each affected EGU is assigned a certain number of tons of carbon dioxide that it is allowed to emit. One allowance would be needed to emit one ton of carbon dioxide. Each state is assigned a budget for each of the three compliance periods from 2022 to 2030.
The federal mass-based plan is not the only option. States that prefer a mass-based approach have several alternatives. One is to impose mass limits on individual EGUs by dividing up the state’s total allowable emissions. It would be up to each power plant to remain within its emissions limit for the affected EGU.
Another alternative is to allow emissions allowances to be traded.
A third alternative is for a state to adopt a range of measures, such as renewable energy standards and energy efficiency programs, potentially as a supplement to a mass-based plan. Any state choosing this approach would have as a backstop federally-enforceable emissions standards for affected EGUs that would be triggered if the state-measures plan fails to achieve the required emissions reductions on schedule.
Emissions Trading Issues
If the power plant is in a state that participates in an emissions trading program, then it is important to understand whether the trading is rate based or mass based and what difference it makes.
Under a rate-based trading program, one emissions reduction credit or “ERC” represents one megawatt hour of electric generation or one megawatt hour of reduced energy use. Under the federal trading plan, EPA would issue ERCs that could then be bought and sold or banked for use.
Under the federal plan ERCs could be generated in various ways.
One way is by operating an affected EGU so that carbon dioxide emissions are lower than what the EGU is allowed to emit. The emissions limits ratchet down over time. Therefore, a plant that earns ERCs initially because it is operating below the limit might find itself having to buy ERCs later.
Another way ERCs are generated is by shifting generation from coal-fired to natural gas-fired units. Only the incremental generation from the shift away from affected coal-fired units might qualify for ERCs. EPA is taking comments on how to measure the shift, particularly so as not to create incentives to rearrange dispatch among existing affected power plants to generate ERCs without changing the overall mix of coal versus gas plants.
EPA’s model trading rule allows eligible new nuclear units and existing nuclear units that add new generating capacity and can provide data from a revenue-quality meter to generate ERCs.
What looks to be a big way to generate ERCs under the federal plan is eligible wind, solar, geothermal and hydro projects with the ability to provide data from a revenue-quality meter will qualify for ERCs. Thus, these types of renewable energy projects in states that end up living under a federal emissions trading program may receive another revenue stream on which they may not have counted: tradeable ERCs.
EPA is considering whether to add biomass projects to the list of renewable energy power plants that might receive ERCs. It wants to know how to measure ERCs from these types of power plants. EPA is also considering ERCs from waste-to-energy and combined-heat-and-power projects. EPA will also be soliciting comments on demand-side energy efficiency measures like state and utility energy efficiency programs.
States could also receive matching ERCs for projects covered under something called the “clean energy incentive program.”
If you are considering possible impacts to an affected power plant that needs ERCs to cover its carbon dioxide emissions, the diligence on this may involve figuring out whether the affected power plant must buy ERCs on the market or has room to generate the ERCs it needs by adjusting how it generates electricity from its portfolio of power plants. This will be a very big part of future diligence when buying projects.
The Clean Power Plan may have an effect on how power plants are dispatched in the future in regional power pools.
About two thirds US electricity is served through regional transmission organizations, called RTOs, or independent system operators. Without going into a lot of detail, RTOs dispatch electricity from all generation in the region by using day-ahead and real-time bids from generators. Power plants get dispatched based on bids to the RTO that take into account the plant’s variable costs. Under typical conditions, a grid operator in an RTO dispatches a power plant with the lowest variable cost first. EPA expects each power plant bidding into an RTO in the future might have to take into account the cost of compliance with the Clean Power Plan as part of its variable costs.
Independent power producers may be able to recover their costs to comply with environmental obligations through longterm power purchase agreements or other bilateral contracts where the utility pays an electricity price that takes into account compliance costs.
A utility facing its own compliance costs might be able to obtain cost recovery through the rates it charges its customers. The compliance costs are a cost of service. This will be an important area to watch for diligence purposes as people try to handle on the real costs to affected power plants to comply.
The market is waiting for a lot more detail about how ERCs will work. The market has some experience with a similar product – offset credits in the California cap-and-trade market. Stay tuned as more details are released by EPA on the measurement, verification and validation aspects of ERCs after the public comment period.
It will be interesting to see whether insurance products emerge to cover invalidation risk in an ERC market.
We have been talking about the mechanics of emissions trading in a rate-based program. Now let’s dive into mass-based emissions trading.
Under the federal plan, the total allowances would equal the number of tons of emissions that each state has been budgeted during the compliance period. A portion of the allowances would be reserved for issuance to certain affected natural gas-fired power plants and certain types of renewable energy projects. The remaining allowances would be divided among all the affected EGUs in the state.
For the initial compliance period of 2022 through 2024, affected EGUs would receive allowances equal to their average generation during the period 2010 through 2012. In subsequent compliance periods, the number of allowances would be reduced proportionately across all recipients during the initial period. EPA is taking comments on the proposed use of historic generation to allocate allowances and whether it should auction allowances rather than give them out for free. EPA will receive a large number of comments on this issue given the financial and compliance issues at stake.
Many affected power plants are still expected to need additional allowances to meet their compliance obligations and may have to go into the market to buy them, transfer allowances from other affected power plants or store unused allowances for use in subsequent compliance periods.
EPA proposes to use part of the budgeted allowances to encourage a shift from coal to natural gas and renewables.
Some allowances will be set aside for solar and wind projects under a “clean energy incentive program.” New solar and wind projects that generate electricity in 2020 and 2021 will qualify for allowances. The program also will reward anyone investing in energy efficiency projects in low-income communities during the same two years. The two years were chosen for special emphasis because they are the two years immediately before the first compliance period when the government will be looking to the power sector to start showing progress on scaling back carbon dioxide emissions.
The allowances offered through the clean energy incentive program would be withheld from the total allowances budgeted for the first interim compliance period, beginning in 2022. It appears that qualifying projects that generate or save electricity in years 2020 and 2021 would be entitled to claim their allowances in or before 2022. Two allotments of allowances should be available: one allotment earmarked for qualifying projects in states subject to a federal plan, and a second matching allotment earmarked for states that elect to participate in the clean energy incentive program.
The clean energy incentive program focuses on solar and onshore wind projects rather than renewable energy more broadly. The reason appears to be that EPA believes solar and onshore wind projects can be built relatively quickly in order to provide electricity in 2020 and 2021. New renewable energy projects with more lengthy development timelines, such as offshore wind projects, would not benefit from the program, at least as currently proposed, given the requirement that qualifying projects must be generating electricity in 2020 and 2021.
The program will only apply in states that have an approved implementation plan that provides for participation in the clean energy incentive program. Not all states may decide to participate. To qualify, a solar or wind project must be physically in the state and not already be under construction. A qualifying energy efficiency project must not be in operation on the date the state submits its implementation plan to EPA.
Some allowances will also be set aside for distribution beginning in the second compliance period, 2025 to 2027, for natural gas-fired power plants that increase output from the initial compliance period to the second compliance period and subsequent compliance periods. These allowances will be used to reduce the potential for leakage. “Leakage” is the shifting of generation from existing power plants to new, modified or reconstructed power plants that are subject to less stringent emissions limits under the EPA carbon pollution standards. The concern EPA has with leakage is that displacement of existing generation by new generation could lead to a net increase in emissions. EPA hopes to mitigate leakage by providing a financial incentive to natural-gas fired power plants in the form of allowances.
Beginning in the second compliance period, a portion of the total allowances would be allocated to existing natural gas units based, in part, on their levels of electricity generation in the previous compliance period. Each eligible natural gas unit would receive a larger allowance allocation from the gas set-aside if it generates more than in the prior period. This is part of the effort to shift generation to gas. The total number of allowances available for distribution in this manner is limited.
Finally, EPA proposes to set aside 5% of each state’s allowances for distribution to renewable energy. This set-aside would be for developers of in-state renewable energy projects that provide capacity incremental to 2012, and would be implemented in all compliance periods.
EPA views this set-aside as a tool to reduce the marginal cost of generating electricity from renewable energy. It is considering whether to increase the percentage from 5% to 10%.
OFAC published a final rule that modifies the Cuban Assets Control Regulations to revoke the so-called "U-turn" authorization.
On 5 September 2019, Professor John McMillan AO’s Final Report (Report) on the operation of the Narcotic Drugs Act 1967 (ND Act) was tabled in Parliament. Section 26A of the ND Act required the Minster to cause a review of the operation of the ND Act to be undertaken.