On June 2, 2014, EPA released proposed guidelines for states to use in developing plans to control greenhouse gas (GHG) emissions from the nation’s fleet of existing fossil fuel fired electric generating units (EGUs). The proposal is being dubbed the “Clean Power Plan.” This Client Alert provides background for the proposal, provides a preliminary summary of the key provisions and discusses the potential impacts to the regulated community. EPA has not yet published the official proposed rule in the Federal Register, so some changes may be made in the official published proposed rule.

Procedural Background

Upon taking office in 2008, one of President Obama’s key initiatives was the creation of legislation purposefully crafted and designed to address climate change. That effort failed to muster support in Congress despite both houses being controlled by a Democratic majority. Without legislation, President Obama’s administration turned to the executive powers that had been given to EPA under the Clean Air Act (CAA) as a mechanism to regulate GHGs.

As part of this initiative, President Obama issued a memorandum on June 25, 2013, directing EPA to use its authority under Section 111(d) of the CAA to issue standards, regulations or guidelines to control GHG emissions from existing fossil fuel fired power plants. EPA was instructed to propose these rules or guidelines by June 2, 2014, and finalize them by June 2, 2015.

The President was quite prescriptive and deliberate in requiring that this proposal be developed under Section 111(d) of the CAA. The provision provides states with flexibility and conditional autonomy in crafting regulatory approaches to achieve emission reduction goals. By using this authority, EPA believes it can better account for the varying emission reduction opportunities that are available to each individual state. States can account for the unique characteristics of the electric generation systems which operate within their respective jurisdictions (e.g., differences in utility regulatory and rate structures, generation asset mixes, fuel use portfolios, state renewable portfolio standards, energy efficiency incentives, power distribution systems, power customer profiles, etc.).

Legal Background

Section 111(d) has rarely been used by EPA.[1] Most CAA programs require EPA to establish prescriptive performance standards that apply on an emission unit level and which states are obligated to implement. Section 111(d) differs from this approach in two ways. First, it requires states (not EPA) to set performance standards for emission sources that merely follow suggested EPA guidelines and meet the targets identified by EPA. Second, EPA interprets section 111(d) as allowing states to regulate sources on a system wide basis. Although these approaches provide more flexibility and autonomy to states, it makes the rule more vulnerable to legal challenges.

In this regard, section 111(d) requires that EPA establish guidelines for states to use in defining the level of emission reduction required of regulated emission sources. These guidelines help establish “performance standards” which are defined as:

“A standard for emissions of air pollutants which reflects the degree of emission limitation achievablethrough the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.”

This definition is pregnant with possibilities for legal mischief and challenges (especially the highlighted phrases). For example, EPA’s proposal relies heavily on anticipated GHG emission reduction activities that will occur “beyond the fence” of a power plant (discussed below), as opposed to the more traditional approach of requiring emission reductions to be achieved at the emission unit itself. This interpretation, if finalized, will certainly be the topic of litigation. It is unclear whether EPA has the authority to force regulation of activities that are not part of the “regulated unit” as defined by the section 111 program.

The Proposed Standards

EPA’s proposal is premised on reducing GHG emissions from the nation’s fleet of fossil fuel fired power plants by anational average of 30%, and on state specific reductions, by 2030. The rule will impact approximately 1,000 fossil fuel power plants in the United States, combined these plants consist of approximately 3,000 EGUs. The average age of the coal fired EGUs is 42 years which is just shy of the anticipated life expectancy for the units. EPA’s proposal assumes that many coal fired units will be retired during the compliance horizon associated with the program.

The national average 30% emission reduction target will be measured from a 2005 baseline, which sounds like a significant concession to industry since 2005 had some of the highest CO2 emissions on record. Between 2005 and 2012, CO2 emissions dropped an average of 16% in the power sector, meaning that an additional 15%, or so, in emission reductions are still needed to meet the national average goals in the proposal. However, emission reductions achieved between 2005 and 2012 have been backed into the proposed state specific emission rate baselines (discussed below), and therefore cannot be counted toward achieving the interim or final reduction goals.[2]

The specific reduction targets for each state vary based on the unique characteristics of the state’s EGU fleet. Each state is given its own emission reduction targets. These targets are expressed as a “rate-based” emission average to be achieved by the combined fleet of EGUs within the state. States would be expected to make "meaningful progress" towards these reductions by 2020 and meet their respective targets by 2030.

The state specific rate-based targets are expressed as a measure of the average carbon intensity of the state’s EGU fleet (tons of COper megawatt of electricity produced), as opposed to a simple cap on the overall tons of CO2emitted by the fleet. The rate-based targets are essentially established by dividing the total tons of CO2 emitted by a state’s EGU fleet by the amount of electricity produced by those units.

States can switch from a “rate-based” regulatory target to a mass-based goal which would establish an overall CO2tonnage cap for a state EGU fleet. Under this mass-based approach, states can participate in a multi-state trading program to comply with their cap. The Midwest Governors Association explored a regional cap and trade program in the late 2000s.

A mass-based approach provides a simpler regulatory tool. However, a rate based approach would be more accommodating to future expansions of a state’s power sector.

As mentioned, states must use a “best system of emission reduction” (BSER) to meet their target of reduced CO2emissions. EPA’s proposal establishes guidelines for states to follow with options for achieving these reductions. In the most general terms, states are given four options which EPA refers to as “building blocks:”

  • Increasing the efficiency of an EGU itself. This is an “inside the fence” option that would improve the carbon intensity of the power produced by a particular EGU. Some stakeholders have suggested that most EGUs have already undergone efficiency improvement projects and there is little more that can be done in this area. EPA believes that a 6% improvement is available. It appears that fuel switching to natural gas would also be an option to improve the carbon intensity rating of coal fired units. Although the proposal recognizes that biomass fuels can be part of a state’s compliance strategy, EPA still treats biomass based fuels like a fossil fuel (but EPA states that it continues to work on a more favorable accounting method). EPA has not provided regulatory relief from New Source Review requirements that could arise from modifications undertaken to increase efficiency or switch to new fuels.
  • Using low emitting power sources on a more frequent basis. This is an “outside the fence” option that involves prioritizing the dispatch of lower carbon intensity units. This would likely require coordination with the local independent system operator for the transmission grid. EPA’s Regulatory Impact Analysis projects that coal plant capacity utilization will decrease under the proposal to around 75%, and natural gas plant capacity utilization may increase to 70%.
  • Expanding the use of low and no carbon power sources such as wind, nuclear and solar. This is another “outside the fence” option that would dovetail with a state’s renewable portfolio standards.
  • Improving demand side energy efficiency to reduce electric use. Another “outside the fence” option that would focus on improving the efficiency of residential, commercial and industrial energy usage. Many industrial sources assert that they have already made significant investments in energy efficiency and there is little more that can be done in this area.

Importantly, anything included in a state plan to achieve compliance with 111(d) will be federally enforceable by EPA, including any “outside the fence” efficiency programs (e.g., building code requirements) and plans for projects to develop low or no carbon power sources. EPA takes care to describe these four building blocks as severable. This means that if a court were to vacate one or more of them in response to a legal challenge, the remaining options would remain viable.

EPA has posted an interactive set of maps that allow a user to click on a state to understand the state actions already undertaken to address climate change that were considered by EPA in its proposal, EPA’s assumptions for each fossil fuel fired power plant in that state and information on EPA’s proposal for that state.

As for Wisconsin, EPA acknowledges that the state already has programs in place that could be part of its individual or regional plan to reduce carbon pollution, including:

  • Energy efficiency standards or goals;
  • Demand-side energy efficiency programs that advance energy efficiency improvements for electricity use;
  • Energy efficiency codes (meeting 2006 International Energy Conservation Code) for residential buildings;
  • Energy efficiency codes (meeting ASHRAE Standard 90.1-2004) for commercial buildings; and
  • Renewable energy portfolio standards.

Putting the Reduction Targets in Context

As mentioned, the reduction targets for each state are expressed as an average carbon intensity rate. The 2030 target for the State of Wisconsin is 1,203 pounds of COper megawatt hour. EPA quantifies Wisconsin’s 2012[3] average carbon intensity rate as 1,827 pounds of COper megawatt hour,[4] meaning that Wisconsin must reduce the carbon intensity of the state’s EGU fleet by 34% from the 2012 rate to meet the proposed 2030 target. In terms of reduction percentages and final carbon intensity, Wisconsin is roughly in the middle of the pack. The targets proposed for Midwestern states are set forth below:

Click here to view table.

It remains unclear what states might need to do to reach these targets. States generally have diverse sets of power generation assets – coal, natural gas and renewable units – each with its own carbon intensity rating. The carbon emission profile of a state’s existing portfolio of EGUs will need to be closely examined to determine how best to achieve compliance with the 2030 goal.

On this point, the allowable COemission rate for a modern coal fired EGU is between 2,100 and 2,900 pounds of COper megawatt hour.[5] A modern natural gas combined cycle plant emits in the range of 1,100 pounds per megawatt hour.

EPA assumes that Wisconsin’s 2012 energy mix was comprised of the following: 51% coal; 22% nuclear; 18% natural gas; 2.6% biomass; 2.4% wind; 2.3 % hydro; and 0.5% petroleum.

Given Wisconsin’s heavy reliance on a coal fired EGU fleet, EPA’s proposed average emission rate of 1,203 pounds of COper megawatt hour seems ambitious, at least from a superficial view. Wisconsin may need more generation from natural gas and renewable units to off-set the much higher carbon intensity of coal plants, or otherwise force the retirement of more coal units altogether. The 22% assumption on nuclear generation (a “no carbon” source) may be a concern if that percentage includes the recently shuttered Kewaunee Power Station, or if the percentage is further reduced in the future and that generation needs to be replaced.

Illinois officials, on the other hand, have stated that they anticipate no problems in meeting their 33% reduction goal or achieving an average carbon intensity of 1,271 pounds of COper megawatt hour by 2030.

States will need to closely scrutinize their budgets, including the underlying assumptions used by EPA. Once the final goals have been promulgated, a state will no longer have the opportunity to seek an adjustment.

Financial Impacts

The financial impacts of this proposal have been broadly disputed. EPA estimates the cost of compliance to range between $7.3 to $8.8 billion, with economic benefits of roughly ten times that amount. The majority of these expenses will be passed along to rate payers in the form of higher rates. EPA estimates that this rule will increase rates by 3.0% by 2030 (which assumes that natural gas prices will be roughly $6.33/mmbtu in 2030). These increases will impact the heavy manufacturing industries in Wisconsin and other Midwestern states, particularly the paper industry which is a heavy power user.

The increased rates associated with this proposal, coupled with the costs required to comply with other EPA rules, may increase interest in distributed self-generation options. EPA seems to anticipate this development and is soliciting comments on whether industrial combined heat and power approaches warrant consideration as a potential way to avoid affected EGU emissions.

The Obama Administration is being criticized for appearing inconsistent as to the anticipated impact of the proposal on electric rates. The proposal predicts a drop in average electric bills of 8% by 2030, chiefly attributable to an expected decrease in the use of electricity that will come from improved energy efficiencies. In other words, the rate increases will be offset by the reduced usage of power caused by expenditures that will improve efficiency. EPA’s position is also being characterized as contrary to President Obama’s statement in 2008 that “under my plan…electricity rates would necessarily skyrocket.”

Timing

President Obama’s June 2013 memorandum requires EPA to finalize its section 111(d) guidelines by June 30, 2015, and states must submit their initial compliance plans by June 30, 2016. Allowing states only one year to submit plans is generally viewed as aggressive. As such, the proposal provides states with more time, if needed.

The proposal would allow states to file an initial compliance plan before June 30, 2016, and a final plan a year later. States that choose to participate in a multi-state trading program would be eligible for a two year extension, with initial plans due June 30, 2017, and final plans a year later.

Although states have been given less time than normal to create a plan (generally states have three years to develop SIP plans under the CAA), EPA is given more time than usual to review states plans. EPA will have one year to review section 111(d) state plans (EPA is normally allowed four months to review a state plans under the CAA). EPA claims it needs this additional time given that the flexibility provided to states will lead to divergent plans.

EPA has not been clear as to what, if anything, would happen to states that fail to timely submit plans. Presumably, EPA would step in and craft a plan for a state if that were to occur.

Odds and Ends

The rule is over 600 pages, and the technical support documents amount to hundreds more, and will be the subject of close scrutiny over the next several months. We will continue to review the rule and its supporting record. However, some preliminary issues that warrant mention include the following:

  • Although the rule targets GHG emissions, it could result in significant co-benefits in terms of reductions of criteria pollutants such as NOx, SO2, and particulate matter. These reductions could be so profound as to warrant limiting or removing Wisconsin (or other states) from interstate air pollution transport rules.
  • The proposal will be a significant political topic going forward. Congressional Republicans have announced their intent to hold hearings, introduce legislation and perhaps pursue legal action to limit the proposal. Democrats in “coal states” are also feeling pressure and speaking out publically against the proposal.
  • The timeline associated with the proposal has the final version being implemented after President Obama leaves office. This adds uncertainty as to how his predecessor might change the rule in the future.
  • Will this approach be used as a template to craft programs to limit GHG emissions from other industry sectors?
  • Arguably, sources that are subject to hazardous air pollutant (HAP) emission standards under the CAA cannot be regulated under section 111(d). Yet, many of the EGUs that would be regulated under the EPA proposal are already subject to such HAP emissions standards. This will likely be an issue addressed in litigation.
  • Some states have enacted or are considering legislation that would freeze state energy efficiency and renewable portfolio standards at existing levels (e.g., Ohio and Indiana). These efforts could affect a state’s options in crafting plans to fulfill their section 111(d) obligations under this proposal.
  • The proposal, if implemented, risks stranding capital that has been invested in existing plants in order to comply with other environmental rules, including EPA’s rules limiting mercury emissions from power plants.

Coincident with issuance of the proposed rule for existing EGUs under its section 111(d) authority, EPA issued proposed guidelines to control GHG emissions from modified and reconstructed EGUs under its section 111(b) authority. Specifically, EPA proposed numeric standards for modified and reconstructed fossil fuel-fired utility boilers and IGCC units, and modified and reconstructed natural gas-fired stationary combustion turbines. Based on the low number of units that have previously notified EPA of NSPS modifications or reconstructions, EPA anticipates that very few units will trigger these requirements. However, units that do undergo modifications or reconstructions after being subject to a state plan for existing units will be required to comply with both the state plan and the numeric performance standard for the modification.

Public Input

There will be a 120-day public comment period for the proposal beginning on the date of publication in the Federal Register. EPA will hold four public hearings on the proposal, none of which will be in the Midwest:

  • July 29 in Atlanta, Georgia
  • July 29 in Denver, Colorado
  • The week of July 28 in Washington, D.C. (exact day to be determined later)
  • July 31 in Pittsburgh, Pennsylvania

Wisconsin Department of Natural Resources has stated its intention to reach out to stakeholders early in the process as part of its effort to develop comments for EPA.