In June the White House issued a “Climate Action Plan” that increases the pressure on power generators to reduce carbon emissions. U.S. utilities have already announced the retirement of 60 GW of coal-fired generation by 2020 as a result of current regulations. Unless technological innovation can beat the regulatory clock (which seems unlikely), more early retirements are ahead.

Although there have been previous attempts at the federal level to regulate carbon dioxide (CO2) emitted from U.S. coal-fired power plants (remember the Waxman-Markey Bill, the American Clean Energy and Security Act of 2009?), after a lull in action on the greenhouse gas (GHG) regulation front, the past year has seen accelerated action. Pressure to regulate GHGs in general and CO2 from coal-fired power plants in particular (because they are the largest stationary source of the gas) has been building for well over a decade, as a quick review of the regulatory history shows. But now, in part because of the way the administration is approaching GHG regulation, the likelihood of unattainable limits on emissions from coal-fired generation becoming final rules within a mere three years has increased significantly.

We got to this point by a circuitous route. The question now is where U.S. coal-fired generation owners go from here.

A Brief History of CO2 Regulation

By now, most readers are familiar with the latest development in the history of attempts to regulate GHGs. On June 25, 2013, a Presidential Memorandum issued by the White House gave the green light for the Environmental Protection Agency (EPA) to further increase the regulation of carbon emissions from electric generating units (EGUs). This memo was conveniently timed, as it was issued exactly one year from the cutoff date of the comment period for the Carbon Pollution Standard (“Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Generating Units”) and days before implementation of the third step of the Greenhouse Gas Tailoring Rule (“Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule”) on July 1, 2013. In addition to urging the EPA to expedite publication of the final Carbon Pollution Standard for new sources, the Climate Action Plan memo opened the door for regulating carbon emissions from modified, reconstructed, and existing EGUs.

But the stage for this action was set by previous actions and decisions….

Massachusetts v. EPA

In the Presidential Memorandum the White House outlines the actions already taken by the EPA to regulate the emissions of carbon pollution from the transportation sector. The EPA has a timeline that limits GHG emissions from new cars and light trucks through 2025 and heavy duty trucks through 2018 using the Clean Air Act (CAA) to enforce these limitations. But how exactly is the EPA able to use the CAA, which didn’t include CO2 as a pollutant, and the regulation of mobile engines to enforce new GHG standards on EGUs?

In October 1999, several parties petitioned the EPA to regulate GHG emissions from new motor vehicles to reduce the effects of global warming. They argued that GHGs were defined as an air pollutant under 302(g) of the CAA and that the EPA had a mandatory duty to regulate their emission under Section 202 of the CAA. The petitioners were looking for the EPA to impose stricter fuel efficiency standards on motor vehicles as the means to reduce CO2 emissions.

On Sept. 8, 2003, the EPA made two determinations that created a conflict among multiple parties. The first determination was that the EPA did not have the authority under the CAA to regulate CO2 or other GHGs because they were not defined as pollutants. The second was that if the EPA did have the authority under the CAA to regulate CO2 and GHGs, it would decline to set emission limits for mobile engines. The agency argued that increasing the fuel efficiency of motor vehicles was a function of the Department of Transportation, not the EPA.

As a result of this determination, a lawsuit, Massachusetts v. EPA (2007), was filed against the EPA. The Supreme Court found that CO2 and other GHGs could fall within the broad definition of an air pollutant and that the EPA had the authority to regulate emissions of GHGs.

Endangerment and Cause or Contribute Findings

The Supreme Court ruling pushed the EPA to further examine the effect of GHGs on public health and welfare and clearly identify which combustion byproducts are considered GHGs under Section 202(a) of the CAA. In the Endangerment and Cause or Contribute Findings for Greenhouse Gases, the EPA determined that GHG emissions from motor vehicles did contribute to GHG pollution. The EPA also identified CO2, methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6) as six key GHGs that “threaten the public health and welfare of current and future generations.”

These finding alone did not constitute a regulation of GHGs—only a determination by the EPA that these gases were harmful and fell under the domain of the CAA. In anticipation of these results, the EPA issued a new rule regulating GHG emissions from stationary sources. On Sept. 30, 2009, the EPA proposed the Greenhouse Gas Tailoring Rule to regulate emissions of the six GHGs as Prevention of Significant Deterioration (PSD) pollutants.

Greenhouse Gas Tailoring Rule

Intended as a phased approach to regulating the emission of GHGs from stationary sources, the third step of the Greenhouse Gas Tailoring Rule was phased in on July 1, 2013. The rule requires new and existing facilities with GHG emissions of at least 100,000 tons per year carbon dioxide equivalent (CO2e) to obtain PSD permits. In addition to the PSD permit, these facilities must also now obtain a Title V operating permit. Facilities already holding a PSD permit that increase GHG emissions by 75,000 tons per year CO2e must now address the increase in emissions.

As this phased approach to regulating GHGs progresses, permitting agencies are beginning to increase their efforts in reviewing and issuing permits addressing GHGs. By the end of 2012, permitting agencies had 139 applications under review and had final permits issued for 50 facilities. By the middle of 2013, these same agencies had 183 permits under review and had issued 33 final permits (Figure 1).

1. GHG permits under review and finalized. Source: EPA

The vast majority of workload addressing GHG emissions has been executed by state and local permitting agencies. The current workload for state/local agencies through the middle of 2013 was 172 permits. The bulk of the EPA’s GHG workload came from Region 6 EPA, which had a workload of 67 permits, while the combined other regions had a workload of 21 permits through the middle of 2013.

Almost half (46% to be exact) of the GHG permits being reviewed and issued are coming from the power generation sector. The next closest industries with permits addressing GHG emissions are oil and gas (18%), chemicals (16%), and mining/metals (9%). An analysis of the permits being issued show the Best Available Control Technology method, which was being designed to streamline the review process for GHG control technologies, has overwhelmingly chosen energy efficiency as the preferred method for GHG control. This is evident as 92% of permits issued have required energy efficiency, while 6% require add-on controls unrelated to CO2, and 2% require add-on controls for CO2 control.

The Carbon Pollution Standard Is Quickly Tightening

On Apr. 13, 2012, the EPA proposed the first CAA regulation that was intended to regulate carbon pollution from new power plants. The proposed regulation would limit emissions to 1,000 pounds CO2 per megawatt-hour of electricity produced. Holding CO2 emissions to this level would allow 95%+ of new combined cycle power plants to readily overcome the hurdle but would stifle any new solid fuel power generation. Supercritical pulverized coal and integrated gasification combined cycle power plants, the most energy-efficient of the coal power generation options, operate at around 1,800 pounds CO2/MWh, thus creating the need for carbon capture and sequestration (CCS).

This quickly became a controversial move by the EPA, and the agency has been overwhelmed by more than two million comments from industry and the general public. Due to the quantity and content of these comments, the EPA indicated it would issue a new proposed Carbon Pollution Standard; however, it has taken longer than expected to release this information. To further expedite action, the president issued orders for the EPA to propose a new regulation by Sept. 20, 2013, for public comment.

The president, in his June 25 memo, took the regulation of CO2 one step further and ordered the EPA to expand from limiting CO2 emissions from just new power plants to also including modified, reconstructed, and existing power plants. The president requested that the EPA, under Section 111 of the CAA, “issue standards, regulations, or guidelines, as appropriate, that address carbon pollution… and build on State efforts to move toward a cleaner power sector.” Along with this statement came a timeline for when the EPA is to implement this new rule. The timeline is as follows:


■ Issue proposed regulations no later than June 1, 2014.

■ Finalize carbon regulations by no later than June 1, 2015.

■ Require updated State Implementation Plans (SIPs) to include carbon dioxide regulations under Section 111(d) of the CAA by no later than June 30, 2016.


It’s one thing to require SIPs in less than three years. It’s quite another to develop workable, economic compliance strategies within that timeframe.

Compliance Strategies: Just Demos and R&D

In the U.S., very few power generation facilities have implemented a CCS project. The two major challenges any CCS project faces are the limited technologies available for capturing CO2 and limited options for storing or utilizing the sequestered gas after capture. The majority of power generation facilities that implemented CCS projects have used a pre-combustion capture mechanism and then used the sequestered CO2 for enhanced oil recovery (EOR).

For most operating coal-fired power plants, a pre-combustion CCS isn’t practical or feasible. (See this issue’s cover story on the Edwardsport plant for one demonstration of the economic hurdles.) The vast majority of utility coal power generation utilizes some form of pulverized coal combustion, and those systems would need to be converted to fire a non-carbon-based fuel. At issue is that coal as a fuel source consists largely of carbon molecules. If the carbon molecules in coal are removed prior to combustion, there is little energy remaining for thermal power production.

This is why facilities such as NRG’s W.A. Parish plant are testing the effectiveness of large-scale post-combustion CCS. W.A. Parish is expecting to implement a commercial-scale post-combustion CCS project using a 250-MW slipstream for carbon capture. It is anticipated that 90% of the CO2 in the slipstream will be captured, resulting in a 1.65 million ton annual reduction in CO2 emissions.

To achieve this large reduction in CO2 emissions, the plant is testing an amine technology designed to remove the GHG gas from the flue gas. The amine will absorb CO2 from the flue gas and then move it to a stripping process to sequester the captured gas and regenerate the amine. One caveat for the technology is that the flue gas needs to be free from flyash, sulfur, and nitrogen to be effective.

The captured CO2 will be compressed and used for EOR at the nearby West Ranch Oil Field in Jackson County, Texas. The U.S. Department of Energy issued its final National Environmental Policy Act Environmental Impact Statement in February 2013 and also issued a Record of Decision in May 2013 giving the project a potential operational timeframe of the first quarter of 2015.

A second large-scale demonstration of CCS technology is the repowering of Ameren’s Meredosia Unit 4 using oxyfuel combustion. That $1.65 billion project will convert the existing 200-MW unit to a 167-MW oxy-combustion unit (also known as FutureGen 2.0) with a 90% CO2 capture rate. The first phase of the project, primarily consisting of the project’s power purchase agreement, was completed in February 2013; the project has now entered its second phase, consisting of final permitting activities and engineering and design. The second phase is expected to continue into summer 2014 with commercial operations expected to begin in 2017.

For domestic power generation, this will be the first major CCS project that does not use the sequestered CO2 for EOR. Instead, the CO2 will be transported and injected below ground into a geological formation. In this region, the Mount Simon Sandstone is located below an impermeable caprock and contains a saline aquifer. The porosity and depth of the formation is expected to be an ideal setting for long-term storage of CO2.

There is hope that the EPA will be flexible about the timeframe for enforcing regulations for existing power plants—allowing new technologies to emerge and be applied in time to meet compliance deadlines. CO2 removal technologies are not new processes; however, they are new for the power generation industry.

Post-combustion CO2 removal methods currently under development can be broken down into three main removal categories: solvents, sorbents, and membranes. (A few other very early-stage approaches were covered in the August issue feature “R&D Projects Target Cheaper Carbon Capture, Use, and Storage.”) Solvent-based CO2 capture involves the chemical or physical absorption of the GHG gas from flue gas into the liquid carrier. Using thermal energy, CO2 is liberated from the solvent outside of the flue gas stream, thus regenerating the solvent and sequestering the CO2 from the combustion gases.

Solid particles referred to as sorbents are similar to solvent-based post-combustion CO2 capture systems in that they chemically or physically adsorb CO2 from the flue gas stream. Also similar to solvents, sorbents may be regenerated by use of thermal energy, thus reducing the amount of virgin sorbent required. Methods of contact (between sorbent and flue gas) that are ideal for regeneration of the sorbent include fixed, moving, and fluidized beds.

Membrane-based CO2 capture methods consist of permeable or semi-permeable membranes that allow for selective separation of CO2 from the flue gas stream. Although these systems are ideal in pre-combustion high-pressure systems, advancements are being made for selective membranes compatible with low-partial-pressure CO2 environments (typical of a flue gas stream). Membrane systems offer a potential operating cost savings because there is no need for regeneration, as is typical with solvent and sorbent capture systems.

CO2 Capture Is Only Half the Battle

Capturing CO2 emissions from a flue gas stream constitutes half of the CCS process; the other half involves sequestering all the captured gas. Long-term storage presents significant challenges to existing coal-fired power plants, as their geographical location may not be suitable for long-term storage of CO2. FutureGen 2.0 and W.A. Parish are utilizing the two most common types of storage in geological formations. Typically, the captured gas is injected in a supercritical state into the desired geological formation and held underground by impermeable caprock or a geochemical trapping mechanism. Other forms of geological storage include mature gas fields and un-mineable coal seams.

Other storage mechanisms have been proposed, but they have not been tested for their long-term viability. Mineral storage is a concept that utilizes the process of carbonate formation (reaction of CO2 and metal oxides) as a mechanism for stable, long-term storage of CO2. In nature this process occurs over several years and results in a significant portion of surface limestone. A pilot plant based in Newcastle, Australia (expected to be operational this year) is currently studying the economics of this mineral storage–based mechanism.

There are also several pilot plants worldwide that have studied the potential of using sequestered CO2 for biomass generation. Sequestered CO2 is utilized in bioreactors that provide ideal growing environments for algae. The algae produced is harvested and used to either produce fuels such as biodiesel or to generate animal feed.

Limited Flexibility

It is unclear at this time what the regulation for CO2 emissions will look like for new and existing power plants, but it is certain that increased regulations will be proposed. Although the EPA will have flexibility with implementing carbon regulations, the fact of the matter remains that CO2 is becoming increasingly regulated. With an already volatile regulatory environment consisting of promulgated regulations (Mercury and Air Toxics Standards), regulations expected to be released shortly (316(b) Cooling Water Intake Structures and Coal Combustion Residuals), and the potential reinstatement of overturned regulations (Cross-State Air Pollution Rule), the potential of new regulations further complicates the future of coal-fired power generation.

Technologies to address the capture and storage of CO2 are available but have yet to been proven on a large-scale basis. In addition to being unproven, CCS projects are capital- and energy-intensive. Natural gas remains at a low price point and, from a regulatory standpoint, retains a favorable position as the “fossil fuel of choice” for future power generation. However, over 40% of current U.S. power is still being produced by coal-fired power plants. It is uncertain what overall effect the expansion of CO2 regulations will have on fossil fuel power generation—and grid reliability—but the trend of retiring coal-fired power generation units due to existing or future regulations is likely to continue. ■

Brandon Bell, PE is a project manager at Valdes Engineering and a POWER contributing editor.