New Methane Regulations Proposed for the Oil and Gas Sector: What You Need to Know

(Federal GHG Regulations, Renewable Fuel Standards and Biofuels) Permanent link
On August 18, 2015, EPA proposed a slate of rulemakings under the Clean Air Act (the “Act”) directed at the oil and gas industry. Today Vinson & Elkins published an article outlining the key provisions of these rulemakings. These rulemakings would, if promulgated along the lines proposed, achieve the following:
  • establish New Source Performance Standards (“NSPS”) for methane and volatile organic compound (“VOC”) emissions from the oil and gas sector;

  • redefine the fundamental term “source” in a way that may add burdensome requirements, extend the time and permitting risks associated with permitting sources, and potentially require additional controls; and

  • require states to mandate additional pollution controls in states that are non-attainment for ozone, through Controls Technique Guidelines (“CTGs”) that states will be forced to implement.

The changes from the existing regulations under Subpart OOOO are summarized below:

These rules will have widespread application to the oil and gas industry and could have impacts on production, processing, transmission, and storage vessels. Businesses and individuals concerned about this proposed rule or interested in participating in EPA’s decision making process have only 60 days after the proposed rule is published in the federal register to submit comments to the agency.

It is important to note that these changes — once adopted — will apply to any covered source built or modified after the Federal Register proposal date, regardless of when the rule is made final. Accordingly, owners and operators need to begin now to design and build their operations to comply with the performance requirements imposed by these proposed rules. Read the entire article here.

Posted by Corinne Snow at 08/27/2015 11:45 AM

EPA Proposes Regulations to Require 40 to 45% Reduction in Methane Emissions from the Oil and Gas Sector

(Adaptation, Federal GHG Regulations, Climate Change Science) Permanent link

On April, 18, 2015, EPA proposed rules that would directly regulate methane emissions from the oil and gas sector, including from new or modified wells, and compressor stations. The proposal is a layer of additional regulation beyond the regulation of VOCs from oil and natural gas regulations that EPA finalized as subpart OOOO to the New Source Performance Standards (“NSPS”) in 2012. EPA released several proposed rules, the first is a proposed new source performance standard that would set new methane emission limitations on many sources, including new wells. It would also apply VOC and methane emission limitations to certain sources that were not previously regulated by the NSPS including wet seal centrifugal compressors and reciprocating compressors used in transmission and storage of natural gas and in crude oil pipelines. In addition, these regulations call for upstream and mid-stream operations to undertake a robust regime of monitoring for leaks and fugitive emissions, which are defined more broadly than industry and prior regulatory concepts include.

Another proposal involves a set of control technique guidelines that would apply to VOC emissions in certain ozone nonattainment areas. In addition, EPA also proposed to re-define when a group of operations should be considered a “single source” instead of individual sources under the Clean Air Act. This change could have very significant impacts on the type of permitting that is required and the nature (and cost) of the pollution controls needed for upstream and gathering operations. These proposals are described by the EPA as “a key component . . . needed to set the Administration on track to achieve its goal to cut methane emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025.” 

The Wall Street Journal is reporting that while some have criticized the rules as duplicative of the VOC NSPS under subpart OOOO, some companies are already voluntarily pursuing the methane control measures that will be required under the rules. The New York Times points out that the EPA’s proposals will cost the oil and gas industry up to $420 million to implement but 2025, but that EPA believes implementing the controls required in the rule will yield a net benefit of $150 million.  

EPA reached this conclusion by using a measurement akin to the Social Cost of Carbon that places a value on reductions in Greenhouse Gas emissions. By using a 3 percent discount rate, EPA concluded that the estimated reductions in emissions resulting from the proposed rule would create a “methane-related monetized climate benefits are estimated to be $200 to $210 million in 2020 and $460 to $550 million in 2025.” Notably, EPA used a different (7 percent) discount rate to evaluate the total capital costs and estimated annualized engineering costs associated with complying with the proposal’s new requirements.

The currently available versions of each of these proposals call for comments to be received within 60 days of publication in the Federal Register, which has not happened as of the date of this posting. Vinson & Elkins attorneys are currently analyzing thousand-plus pages of materials released with these proposals, so please check back in the coming weeks for more information.

Posted by Margaret Peloso and Corinne Snow at 08/21/2015 3:30 PM

Join Our Clean Power Plan Live Twitter Chat

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Join V&E lawyers Margaret Peloso, Barry Smitherman, and others for a live Twitter chat on Thursday, August 20th from 11:30 a.m. to 12:30 p.m. CDT to answer your questions about the #CleanPowerPlan.

Please submit questions to @VinsonandElkins, @Margaretepeloso, or @SmithermanTX using #VEchats or email Margaret Peloso.

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Clean Power Plan: An Overview of EPA’s New CO2 Emissions Standards for New, Modified, and Reconstructed Stationary Sources

(Federal GHG Regulations, Renewable Fuel Standards and Biofuels) Permanent link

Concurrent with its issuance of final emission guidelines to limit CO2 emissions from existing sources under Section 111(d) of the Clean Air Act, EPA issued performance standards (“NSPS”) to limit CO2 emissions from new, modified, and reconstructed sources under Section 111(b) of the Clean Air Act. The latter is a legal predicate to the former. The NSPS establishes separate standards for stationary combustion turbines (firing natural gas) and electric utility steam generating units (generally firing coal) that commence construction, modification or reconstruction on or after January 8, 2014.

Stationary Combustion Turbines (Natural Gas)

A.        Overview

The standard applicable to a new or reconstructed stationary combustion turbine depends on whether it is a base load or non-base load unit. EPA determined that the best system of emission reduction (“BSER”) for base load units is a standard based on the performance of an efficient combined-cycle unit. Non-base load units, however, must only meet a standard based on burning clean fuels. 

EPA finalized a sliding-scale approach for deriving a unit-specific, percentage electric sales threshold above which a combustion turbine transitions from the subcategory for non-base load units to the one for base load units. Specifically, all units that have electric sales greater than their net lower heating value design efficiencies (as a percentage of potential electric output) are base load units. All units that have electric sales less than or equal to their net lower heating value design efficiencies are non-base load units.

Subcategory BSER Emission Standard
Base load natural gas-fired combustion turbines Efficient NGCC 1,000 lb CO2/MWH-g or 1,030 lb CO2/MWh-n
Non-base load natural gas fired combustion turbines Clean fuels 120 lb CO2/MMBtu

EPA did not set a standard for modified stationary combustion turbines because, based on public comments, it decided it needs additional information to do so.

B.        Analysis

Many commenters asked EPA to exclude simple-cycle combustion turbines from rule coverage, just as EPA proposed to do in its original (withdrawn) proposed rule. EPA did not do so, instead preferring to direct turbine choice: “NGCC technology is the BSER for base load turbine applications [and] if an owner or operator wants to sell more electricity to the grid than the amount derived from a unit’s nameplate design efficiency calculated as a percentage of potential electric output, then the owner or operator should install a NGCC unit.”

However, EPA expects the “non-base load” standard will apply to the vast majority of simple cycle combustion turbines, and expects that owners and operators of new highly-efficient simple cycle turbines “will be able to sell between 35 to 44 percent of the turbine’s potential electric output” without transitioning to a “base load” unit.

But for those simple-cycle units that are deemed to be “base load,” EPA has set a performance standard based on the performance of a combined cycle unit. An NSPS must be “adequately demonstrated” to be achievable, and performance (thermodynamic performance, operating characteristics, emissions profiles, etc.) can differ within a category of stationary sources, so there may be legal challenges over whether it was appropriate for EPA to set a performance standard applicable to simple cycle turbines that is based not on the best performing simple cycle turbines, but instead on the performance of efficient combined cycle turbines.

Electric Utility Steam Generating Units (Coal)

A.        Overview

EPA determined that the BSER for new electric utility steam generating units is the performance of a highly-efficient supercritical pulverized coal unit equipped with partial carbon capture and storage (“CCS”) capability. The final standard is an emission limit of 1,400 lb CO2/MWh. EPA expects a new unit could meet the standard by capturing roughly 20 percent of CO2 emissions.

For modified and reconstructed electric utility steam generating units, the standard is not based on the performance of a unit equipped with partial CCS. Modified units must instead meet a standard consistent with the facility’s best historical annual performance during the years from 2002 to the time of modification. (EPA expects that this can be accomplished through operating practices and equipment upgrades.) And reconstructed units must instead meet a standard based on the performance of the most efficient generating technology for the type of unit, which could require reconstructing the boiler if necessary to use steam with higher temperatures and pressure, even if the boiler was not originally designed to do so.

Category BSER Emission Standard
New construction Efficient new supercritical pulverized coal utility boiler implementing carbon capture and storage 1,400 lb CO2/MWH-g
Modification Most efficient generation at the affected EGU achievable through a combination of best operating practices and equipment upgrades Sources making modifications resulting in an increase in CO2 hourly emissions of more than 10 percent are required to meet a unit-specific emission limit determined by the unit’s best historical annual CO2 emission rate (from 2002 to the date of the modification), but the emission limit will be no more stringent than (1) 1,800 lb CO2/MWH-g for sources with heat input greater than 2,000 MMBtu/h or (2) 2,000 lb CO2/MWH-g for sources with heat input less than or equal to 2,000 MMBtu/h.
Reconstruction Most efficient generating technology at the affected source (supercritical steam conditions for the larger; subcritical conditions for the smaller)

Sources with heat input greater than 2,000 MMBtu/h are required to meet an emission limit of 1,800 lb CO2/MWh-g.

Sources with heat input less than or equal to 2,000 MMBtu/h are required to meet an emission limit of 2,000 lb CO2/MWh-g.

B.        Analysis

Although EPA raised its “new source” limit from 1,100 lb CO2/MWh (proposed) to 1,400 lb CO2/MWh (final), an issue is whether this limit has been “adequately demonstrated” to be achievable, as is required by the Clean Air Act.

EPA asserts that “CCS has been demonstrated to be technically feasible and is in use or under construction in various industrial sectors, including the power sector.” However, federal law prohibits EPA from using federally-funded sources to make a BSER demonstration: “No technology, or level of emission reduction, solely by reason of the use of the technology, or the achievement of the emission reduction, by 1 or more facilities receiving assistance under this [Energy Policy] Act, shall be considered to be adequately demonstrated for purposes of section 111 of the Clean Air Act.” EPA interprets that prohibition to say that federally-funded sources can support a BSER determination “so long as there is additional evidence supporting the determination.” Its interpretation may be litigated.

Perhaps anticipating that litigation, EPA went further, saying that it “finds that a new EGU implementing partial CCS is adequately demonstrated and is doing so based in greater part on performance of facilities receiving no assistance under [the Energy Policy Act]” and that “corroborative information from [Energy Policy Act] facilities, though supportive, is not necessary to the EPA’s findings.” But to show that “post combustion” carbon capture has been adequately demonstrated, for example, EPA identifies only three projects not supported with federal funding. The first is a CCS project in Estevan, Canada, which “is the world’s first commercial-scale fully integrated post-combustion CCS project at a coal-fired power plant.” But that facility only integrates a 110 MW unit with CCS, it only began operation in October 2014, and it received financial assistance from the Canadian federal government. The second is the AES Warrior Run and Shady Point coal-fired plants in Oklahoma, where roughly 5-10 percent of CO2 is captured, but that CO2 is re-sold for food processing industry use and EPA concedes that “these projects do not demonstrate the CO2 storage component of CCS.” The third is a California soda ash plant using post-combustion amine scrubbing to capture CO2 from flue gas of a coal-fired plant, but EPA again concedes that the captured CO2 is not being sequestered and therefore does not demonstrate the CO2 storage component of CCS. Whether these three projects provide a sufficient basis for an “adequate demonstration” of achievability under the Clean Air Act may be litigated.

Posted by Taylor Holcomb at 08/18/2015 8:25 AM

U.S. Corporations Pledge Sponsorship of Renewable Energy, Low-Carbon Investments

(Federal GHG Regulations, Renewable Fuel Standards and Biofuels) Permanent link

On July 27, 2015, thirteen of the largest companies in the United States, including Microsoft, General Motors, Pepsi, and Alcoa, pledged to invest $140 billion in renewable energy and other low-carbon initiatives as part of the American Business Act on Climate Pledge. The pledges are part of a White House initiative to gather private, voluntary commitments to reduce companies’ carbon footprints prior to the U.N. climate change negotiations in Paris this December. Each company promised to reduce its environmental impact in various ways and generally “voiced support for a strong Paris outcome,” “demonstrated an ongoing commitment to climate action,” and “set an example for [its] peers.” The White House has scheduled a second round of pledges later this year.


A White House statement accompanying the pledges reflects the Administration’s continued emphasis on taking steps to reduce climate change. According to the statement, “[t]he impacts of climate change are being felt worldwide,” and “no corner of the planet and no sector of the global economy will remain unaffected by climate change in the years ahead.” It noted that “the federal government is doing its part to combat climate change [and] hundreds of private companies . . . have stepped up to increase energy efficiency, boost low-carbon investing, and make solar energy more accessible to low-income Americans.” The White House praised the U.S. private sector for “stepping up and doing its part in taking on this global challenge.”

The pledges outline the companies’ environmental goals. Bank of America, Berkshire Hathaway, and Goldman Sachs, for example, focused on “financing for low-carbon activities to help address climate change.” Goldman Sachs also reported that it has “mobilized $33 billion of capital for solar, wind, smart grid, and other clean technologies” since 2012 and will use 100% renewable energy by 2020. Alcoa, for its part, pledged to reduce absolute GHG emission in the U.S. by 50%, while Cargill and General Motors committed to improving their energy efficiency and renewable energy use. Walmart will seek to procure 7 billion kilowatt hours of renewable energy globally by 2020 and double the number of on-site solar energy projects at its U.S. stores. UPS’s plan focused on investments in fuel-saving technologies and alternative fuel vehicles, which it hoped will accumulate one billion miles in its “alternative fuel/technology truck fleet.” In addition, Coca-Cola will reduce its greenhouse gas emissions by 25% by 2020, and Pepsi will expand the use of sustainable farming practices at 500,000 acres of farmland used by its North American agricultural suppliers. Finally, Apple, Google, and Microsoft all pledged to power their operations with 100% renewable energy and offset their carbon use in various ways.

The pledges’ impact on the United Nations climate change negotiations in Paris remains to be seen. Brian Deese, a senior advisor to the President, said that the White House hoped the pledges were “the beginning of a substantial mobilization effort” that would “continue to build momentum” as the climate summit approached. Kevin McKnight, Alcoa’s chief sustainability officer, said that an international climate agreement could “level the playing field” for American manufacturers competing with companies around the world.

Posted by Ross Woessner at 08/14/2015 2:22 PM

EPA Proposes Credit Trading Schemes as Part of the Federal Plan for the Clean Power Plan

(Federal GHG Regulations, Renewable Fuel Standards and Biofuels) Permanent link

In addition to issuing the finalized Clean Power Plan rule, EPA simultaneously released a proposal for a carbon credit trading scheme to use in regions of the country where EPA has not approved a state plan. This proposed federal plan (FP) includes a proposal for either a rate- or mass-based federal trading scheme, as well as rate- and mass-based model trading programs that states can adopt as part of their own state plans. The public may submit comments on the proposed FP during the 90 days following its publication, and EPA intends to finalize the FP next summer.

Who will be impacted by the FP?

The FP will directly apply to EGUs in federal and Indian lands, as well as in states where EPA has not approved a state plan as directed by the Clean Power Plan rules. This might be the case either because a state chose not to submit a plan, or because EPA determined that the state plan does not meet the CPP’s requirements. States have until September 6, 2016 (or upon making an initial submittal, until September 6, 2018) to submit state plans. Even after a FP is put in place, a state can still submit its own plan for EPA approval at a later time. EPA is also proposing changes to its state plan approval process, which would allow it to partially or conditionally approve a state plan.

This proposed FP could also impact the way that states decide to design their own plans under the CPP. The FP includes two model trading schemes, and explains that any state that submits a plan adopting EPA’s model plan will be “presumptively approvable” by EPA. Rather than take on the onerous task of attempting to develop an entire trading scheme or other compliance mechanism which EPA might reject, states may be tempted to simply adopt EPA’s model trade plan into their own state plan. Alternatively, states may decide not to submit a plan at all, and simply have EPA develop and administer its own state-specific trading scheme through a FP for the regulated EGUs within a state’s borders. EPA has created this decision tree outlining the states’ choices.

What kind of trading scheme is EPA proposing?

EPA has proposed both a mass- and a rate-based carbon credit trading scheme, although in the final rule it will only adopt one of these schemes. The proposed FP also provides a mechanism for state trading plans to “link” to the federal trading plan, so long as the state scheme meets certain requirements and is compatible with the FP. EGUs in any state covered by a federal plan could trade with EGUs in any other state covered by a FP or a state plan linked to the FP.

How does the proposed rate-based plan work?

Under the rate-based plan, emissions are expressed as a rate of emissions of CO2 per unit of energy output for two sub-categories of sources: natural gas-fired stationary combustion turbines and fossil fuel-fired SGUs. EGUs will either need to emit at or below their emission rate standard, or they will need to purchase credits, called ERCs, to achieve compliance. An ERC is a tradable compliance unit equal to one MWh of electric generation (or reduced electricity use) with zero associated CO2 emissions. For each ERC, one MWh is added to the denominator of the reported CO2 emission rate, resulting in a lower adjusted CO2 emission rate. Only designated categories of EGUs, renewable energy (RE) resources, and nuclear generation can create ERCs, although EPA is considering adding other sources.

EPA proposes using the agency’s already-existing automated allowance tracking and compliance system (ATCS) to monitor the scheme. ATCS would track the generation of ERCs, holdings of ERCs accounts, deductions for compliance, and transfers between accounts. Entities could put ERCs in one of two types of accounts: compliance accounts to meet emissions requirements, or general accounts for holding or trading.

How does the mass-based plan work?

Under the mass-based approach, the trading credits are called “allowances” rather than ERCs. EPA would create an emissions budget for each state equal to the total tons of CO2 allowed to be emitted by the affected EGUs in each state per the CPP. Each allowance would authorize the emission of one short ton of CO2 during the compliance period.

EPA would initially determine the number of allowances for each state budget based on the historical generation of the state’s regulated EGUs. States covered by the FP also have the option of creating their own method for determining how to distribute allowances to EGUs within their jurisdiction, rather than relying on EPA’s approach. Allowances could then be transferred, bought, and sold on the open market, or banked for future use. Allowances do not expire, and may be banked for use in any future compliance period. Regulated EGUs would then have to surrender the number of allowances sufficient to cover their emissions at the end of a given compliance period. EPA has proposed using multi-year compliance periods to ease its own administrative burden, and allow for greater flexibility for the EGUs.

EPA is also proposing to hold back certain allowance “set asides” which could be used in case of an electric reliability emergency: (1) For a Clean Energy Incentive Program; (2) to support RE projects; and (3) to allocate allowances based on an updating measurement of affected-EGU generation. EPA has included state-specific set-asides within the proposed FP.

According to EPA, the Clean Energy Incentive Program (CEIP) is designed to “reward early investments in renewable energy (RE) generation and demand-side energy efficiency (EE) measures that generate carbon-free MWh or reduce end-use energy demand during 2020 and/or 2021. State participation in the program is optional.”

Check back in the upcoming weeks for further analysis of these plans.

Posted by Corinne Snow at 08/13/2015 4:38 PM


The Clean Power Plan: Just the Basics

(Federal GHG Regulations, Renewable Fuel Standards and Biofuels, Climate Change Science) Permanent link

On Monday, August 3, 2015, EPA released its much anticipated “Clean Power Plan,” which calls on each state to reconfigure its electrical generation portfolio to achieve the standards of performance for carbon dioxide (CO2) emissions that EPA has determined to be achievable from an idealized generation portfolio for each state. Together with the concurrently finalized new source performance standards (“NSPS”) for power plants, the Clean Power Plan is the centerpiece of the Obama Administration’s climate change efforts. The Clean Power Plan is an unprecedented use of EPA’s authority under section 111(d) of the Clean Air Act (“CAA”), which will face numerous legal challenges. While we will explore the legal challenges brought to the Clean Power Plan in subsequent posts, this post only sets forth the basic features of EPA’s final rule.

What is EPA’s Statutory Justification for the Clean Power Plan?

Section 111 of the CAA establishes EPA’s authority to issue control technology-based rules for listed categories of air emission sources. Section 111(b) calls on EPA to establish and directly enforce emission limits achievable through application of the “best system of emission reduction” (“BSER”) on all new sources that “cause[ ] or contribute[ ] significantly to air pollution which may reasonably be anticipated to endanger public health and welfare.” Following the adoption of an NSPS under section 111(b), EPA has authority under section 111(d) to establish procedures that require states to submit plans establishing standards of performance for existing sources within its jurisdiction that would be subject to the NSPS if they were new sources. When the state creates a section 111(d) plan, the CAA allows it to consider “among other factors, the remaining useful life of the existing source to which such standard applies.” If the state fails to submit a satisfactory plan, EPA is authorized to adopt one instead.  

The rule packages signed by the EPA Administrator on August 3, 2015, simultaneously adopt both the section 111(b) NSPS governing carbon dioxide emissions from new power plants and direct the adoption of the plans for existing sources under section 111(d). It is the latter of these two rule packages that EPA has called its “Clean Power Plan.” The Administrator also signed a proposed rule describing the federal plan that EPA intends to impose on any state that does not submit an adequate state plan by the deadlines set forth in the Clean Power Plan.  

What types of power plants are regulated under the Clean Power Plan?

EPA requires each state plan to consider all “affected EGUs,” which are defined by the rule to be steam generating units, IGCC, or stationary combustion turbines that commenced construction before January 8, 2014, that have a nameplate capacity of 25MW or greater and a base load rating of more than 250 MMBtu/hr, as well as stationary combustion turbines that meet the definition of either a combined cycle or combined heat and power combustion turbine.

What are the requirements for power plants regulated under the Clean Power Plan?

The exact requirements for any specific power plant cannot be determined yet; they will depend upon how each state chooses to implement EPA’s assigned emission performance rates.

What are EPA’s emission performance rates under the Clean Power Plan?

The Clean Power Plan establishes two sets of emission performance rates: one that applies to the interim period (2022-2029) and the final 2030 goal. These performance rates are as follows:

Affected EGU

Interim Rate

(lbs CO2/MWh)

Final Rate

(lbs CO2/MWh)

Steam generating unit or IGCC 1,534 1,305
Stationary CT 832 771

EPA determined that these emission rates reflect BSER based on the application of three “building blocks:”

  1. Improving heat rate at coal-fired EGUs;
  2. Substituting lower-emitting generation from natural gas combined cycle (“NGCC”) units; and
  3. Substituting generation from new zero-emitting renewable energy.

Because the building blocks that EPA has determined constitute the BSER include “beyond the fence line” measures—an approach that many challengers contend exceeds EPA’s legal authority under the CAA—EPA does not necessarily expect that any individual affected EGU will achieve the prescribed performance rate. Rather, the states are called upon to develop and submit implementation plans that demonstrate the state’s overall generation portfolio will result in CO2 emission rates that do not exceed these standards.

There are several significant changes in EPA’s building block approach from the proposed rule:

  • EPA determined that building block 4 from the proposal, which relied upon energy efficiency measures, could not be included in the BSER, so the final standard is based on only three building blocks. 
  • EPA’s proposal called for an across-the-board 6% heat rate improvement at coal-fired power plants, while the final rule is based upon regional heat rate improvements for the Eastern (4.3%), Western (2.1%), and Texas (2.3%) interconnections. 
  • EPA’s target NGCC capacity factor is based on 75% of summer capacity, instead of the 70% nameplate capacity used in the proposal. 
  • Building block 3 no longer includes the preservation of existing nuclear capacity because EPA determined that preservation of existing nuclear capacity will not result in further emissions reductions.

EPA also finalized alternative state performance goals as both rate-based and mass-based goals. According to EPA, these alternative goals are intended to maximize states’ flexibility in implementing the BSER. EPA describes the state-specific goals as “an alternative yet equivalent expression of the BSER.”

What are the state-wide goals for my state?

Each state has a different set of interim and final goals based on EPA’s analysis of the building blocks. EPA has set forth the state goals both as target CO2 emission rates and as mass-based goals that could be used if a state wants to implement a cap-and-trade program. EPA has released a series of state-specific fact sheets that provide the details of what will be required in each state.

What are the state’s options to implement EPA’s emission performance rates?

States have four basic options to implement EPA’s emission performance rates:

  1. Apply EPA’s emission performance rates to each affected EGU;
  2. Create a rate-based plan where affected EGUs attain the CO2 emission rate set by EPA through a combination of on-site emission reduction measures and emission rate credits (“ERCs”);
  3. Create a mass-based plan where the affected EGUs demonstrate compliance through participation in a cap-and-trade program; or
  4. Make no submission and wait for EPA to impose a rate or mass-based plan consistent with the proposed federal plan.

When must states submit their plans?

States are required to submit their final plans to EPA by September 6, 2016. If the state cannot complete its plan by this date, it may make an initial submittal to the EPA containing (1) a description of the approach to be taken in the final plan; (2) an explanation of why the state requires additional time to finalize the plan; and (3) a demonstration of completed and continuing community engagement during plan development. States that make a submission meeting these criteria will be granted an extension and their final plans will be due on September 6, 2018.

When will power plants need to comply?

The final emission goals must be met by 2030, while the interim goals will apply between 2022 and 2029. EPA has established 3 “steps” in the interim period: (1) 2022 through 2024; (2) 2025 through 2027; and (3) 2028 through 2029. While states will be required to establish some sort of emission limitations for affected EGUs beginning in 2022, states have flexibility in how they structure emission limits or mass-based caps during the interim period and do not have to follow EPA’s “steps.” However, if a state fails to submit a plan, the interim period “steps” will be a component of a federal plan drafted for the state.  

What are the incentives for states to write their own plans?

There are two significant incentives for states to write their own plans. First, a state plan may include “state measures” as part of the demonstration that EPA’s emission performance rate is being met. For example, while EPA has determined that demand-side energy efficiency is not part of BSER, states could adopt energy efficiency programs as part of their own plans. Such measures would not be part of a federal plan created by EPA, meaning that states have opportunities to lower the degree of emissions reduction required for affected EGUs.

Second, EPA has created incentives for early action and investment in renewable energy and energy efficiency through a system of early reduction credits and the Clean Energy Incentive Program (“CEIP”). Under the CEIP, EPA will match emission rate credits issued by the states for renewable energy or energy efficiency projects that achieve emission reductions in 2020 and 2021. However, CEIP incentives are available only to projects that commence after the state's submission of a final plan or September 6, 2018, if no final plan is submitted before that date. Were states to meet the initial 2016 deadline for implementation plan submittals, they would provide two additional years for construction of projects that could benefit from the CEIP.  

Is the Clean Power Plan a cap-and-trade program?

Maybe. The Clean Power Plan itself does not require cap and trade. However, it appears that many states may find that adoption of a cap-and-trade program will be the most efficient way to comply with EPA’s emission performance rates. In fact, the preamble to the final rule states “EPA believes that it is reasonable to anticipate that a virtually nationwide emissions trading market for compliance will
emerge . . . .”

We will provide more details on each of these topics and many others in an upcoming series of blog posts. Join V&E lawyers Margaret Peloso, Barry Smitherman, and others for a live Twitter chat on Thursday, August 20th from 11:30 a.m. to 12:30 p.m. CDT to answer your questions about the #CleanPowerPlan. Please submit questions to @VinsonandElkins, @Margaretepeloso, or @SmithermanTX using #VEchats or email Margaret Peloso.

Posted by Margaret Peloso at 08/12/2015 5:55 PM