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Uncertainties Persist in Greenhouse Gas Permitting: a Quartet of Power Projects

07.20.2012

By Larry Kane, Attorney, Bingham Greenebaum Doll LLP

Unsurprisingly, the evolving application of EPA’s guidance for preconstruction permitting of major sources of greenhouse gas (GHG) emissions remains fraught with uncertainty.  This state of affairs is aptly illustrated by the circumstances of four pending power generation projects, each of which offers questions on a different aspect of GHG permitting.

Christian County Generation, LLC

The first project, the Taylorsville Energy Center project owned by Christian County Generation,  LLC (CCG), illustrates, through a rather unusual sequence of events, the highly volatile and unsettled status of carbon capture and sequestration (CCS) as a candidate for best available control technology (BACT) for control of GHG emissions.  CCG recently (April 30, 2012) received an air permit from the Illinois EPA (IEPA) under the Prevention of Significant Deterioration (PSD) requirements of the Clean Air Act for the proposed construction of a coal gasification facility to produce synthetic natural gas (SNG) and a natural gas-fired combined cycle electric generating facility that could be, but need not be, fueled by the SNG.  A significant aspect of the PSD permit, as issued, was IEPA’s rejection of carbon capture and sequestration (CCS) as best available control technology (BACT) for control of GHG emissions.  This determination became the principal focus of a petition for review filed by the Natural Resources Defense Council and the Sierra Club with EPA’s Environmental Appeals Board (EAB) on May 30, 2012 challenging the permit’s validity.  The Petitioners’ primary challenge to the permit was that IEPA failed to conduct a detailed case-by-case analysis of the question of technical feasibility of CCS in the context of CCG’s project as required by EPA regulation and policy, and instead relied on general concerns over the overall technical feasibility of CCS to reject its consideration as a GHG control technology.  Petitioners contend that not only is IEPA’s approach contrary to the general regulatory framework and policy direction of the PSD program but it further contradicts the specific direction of EPA’s PSD and Permitting Guidance for Greenhouse Gases (“GHG BACT Guidance” or simply “GHG Guidance”), which finds CCS to be an available technology for purposes of BACT analyses for GHGs. 

Less than two weeks after the petition for review was filed, EPA Region 5’s Regional Administrator wrote to the IEPA soliciting the state agency’s reconsideration of its rejection of CCS as BACT for the CCG project and offering a collaborative approach to crafting appropriate BACT conditions, while at the same time subtly reminding IEPA that Region 5 planned to address the issue in the appeal pending before the EAB.  An intriguing feature of the Region 5 letter is its suggestion for how CCS could be flexibly addressed in the PSD permit.  Specifically, Region 5 ventured that, “. . .  there are many ways that IEPA could have addressed any possible uncertainties about the feasibility of implementing a CCS system for the . . . project.  For example, IEPA could have included an adjustable BACT limit contingent on the level of sequestration achieved or a fixed BACT limit based on a specific level of sequestration, with the possibility of revising that limit in the future if CCS was not actually achieved at anticipated levels . . . .”  (The letter to IEPA can be accessed from Region 5’s website.)  Region 5’s gambit had its intended effect on the delegated state PSD program:  on July 9, the IEPA filed a notice with the EAB advising that IEPA is withdrawing the CCG permit in its entirety so that the agency may further consider the permitting decision for this source, including the BACT analysis (presumably with respect to CCS).  IEPA indicated its intent to consult with Region 5 and CCG during the reconsideration process.

Milwaukee Metropolitan Sewerage District

A PSD permit issued May 25, 2012 by the Wisconsin Department of Natural Resources (WDNR), another state with a delegated PSD program, to the Milwaukee Metropolitan Sewerage District (MMSD) for its landfill gas-fueled power plant for the Jones Island wastewater treatment facility raises different, as well as similar, issues regarding the application of EPA’s GHG Guidance.  In comments provided to WDNR on the draft permit, EPA Region 5 raised several questions on the GHG BACT analysis for the project.

One, the BACT analysis for GHGs considered only simple cycle gas-fired combustion turbines and did not consider combined cycle turbines or combined heat and power (CHP) systems to be available.  Given the emphasis of EPA’s GHG BACT Guidance on achieving high efficiency of energy generation as a key element of BACT, EPA’s comments requested that WDNR either revise its BACT analysis to consider both combined cycle turbines and CHP systems, both of which achieve higher efficiencies in power production than simple cycle turbines, or augment the record to explain why these technologies were not considered available.  In its response to the EPA comments, WDNR explained that combined cycle turbines were not considered because such a system could not be implemented on the site due to the unavailability of sufficient space for the larger footprint of combined cycle turbines, which would require heat exchangers and a steam turbine/generator in addition to the combustion turbines.  WDNR further explained that the simple cycle turbines selected in the BACT analysis, while not specifically described as a CHP system, will operate similarly to a CHP system at the MMSD’s wastewater treatment plant since waste heat from the turbine exhaust duct will be used to supplement other heat sources for building heat and sludge drying operations.      

Two, while the BACT analysis considered CCS to be available, it found CCS to be economically infeasible due to the cost of constructing a pipeline to transport captured CO2.  Since there was no cost or economic evaluation in the BACT analysis to support this finding, EPA requested in its comments on the draft permit that WDNR revise the BACT analysis to include an economic evaluation of costs related to installing and operating a CCS system.  WDNR responded that the closest CO2 storage field to be constructed “in the foreseeable future” according to the U.S. DOE is in Decatur, Illinois, which is roughly 270 miles from Milwaukee.  Given that a pipeline from the project site to Decatur would have to traverse the Milwaukee metropolitan area and the western suburban area of Chicago, WDNR estimated the cost of constructing a CO2 pipeline to be in the order of $405 million, which was asserted to render CCS to be economically infeasible.

Also, with respect to the draft permit’s use of an efficiency limit on BTUs per kwh generated to address GHG BACT while not requiring a numeric GHG BACT emission limit, EPA requested that WDNR add a single numeric BACT limit on GHGs on a 12-month rolling basis or explain in the permit record why a numerical limit is technologically or economically infeasible.   EPA further questioned the practical enforceability of the variable aspect of the efficiency limit, which varies with ambient air temperature and turbine load.  WDNR responded that a GHG numeric limit would effectively be the same as a limit on BTUs per kwh since the amount of pounds GHGs per million BTUs has been established in the GHG Mandatory Reporting Rule (40 CFR Part 98).  The agency further responded that the variable efficiency limit was determined to be necessary as a result of the direct relationship between ambient temperature and turbine performance.  The agency opined that a variable limit provides a more effective limit on continual efficiency than would a single value limit that would have to be set low enough to accommodate the worst case ambient conditions for efficiency.

Indiana Gasification LLC (IG)

A third recent energy project involving GHG permitting is the Indiana Gasification LLC’s coal gasification project in southwestern Indiana, which received a PSD permit from the Indiana Department of Environmental Management (IDEM) on June 27, 2012.  The project proposes construction of a coal gasification facility to produce pipeline quality synthetic natural gas (SNG) and about 4.9 million tons per year of liquefied CO2 that will be sold to third parties for use in EOR. 

According to the Technical Support Document (TSD) for the draft permit, the principal source of CO2 emissions from the IG project would be the Acid Gas Recovery (AGR) Units, which separate acid gases, such as CO2 and H2S, from the syngas stream.  The AGR units are said to be capable of capturing 80 percent of CO2 contained in the produced syngas, which can be liquefied and sold for use in EOR.  The remainder of the CO2 in the waste gas from the AGR units would be vented to the atmosphere after being routed through regenerative thermal oxidizers intended to oxidize small amounts of CO2 COS, methane and VOCs (methanol) in the waste gas.

  • BACT for GHGs

IDEM’s approach to a BACT determination for GHGs is illustrated by brief examination of sources of GHGs from IG’s gasification facility operations:  (i) GHG emissions from the AGR vents; (ii) GHG emissions from the wet sulfuric acid (WSA) plants; and (iii) all other, smaller GHG emission units.

An initial observation is that the BACT analysis for GHG emissions from this source focuses on CO2, which is used as a surrogate for other GHGs.  This is justified in the TSD on the basis that, while other GHGs will be present in trace quantities, there are no known control technologies that would reduce or control these pollutants any differently than CO2.

  • AGR Vent Emissions

As mentioned, the AGR is the predominant source of CO2 generated at the IG facility and is projected to generate 6.43 million tons per year of CO2.  BACT for CO2 emissions from the AGR vent has been set as  a series of phased-in limits:  (i) a limit of  4,690,000 tons of CO2 emissions is set for the first 12 months of operation; (ii) a limit of 6,430,000 tons of CO2 emissions is set for the second 12 months of operation; and (iii) a limit of 1,290,000 tons of CO2 is imposed for the third year of operation and for each consecutive 12-month period thereafter, determined on a rolling 12-month basis.   

These BACT limits are explained in the TSD on the basis of IG’s plans to sell the captured CO2 to EOR users on the Gulf Coast after transport through a pipeline to be constructed and operated by third parties.  Once the pipeline is operational, IG expects to sell and transport all captured CO2.  However, no pipeline currently exists and will need to be constructed by others.  Recognizing the time frame for regulatory approval and construction of this pipeline, the BACT limits are based on the expectation that the pipeline will not be available for the first two years of the IG facility’s operation while the facility is ramping up to full production.  Thus, the proposed CO2 limits for these first two operational years are based on emission of all captured CO2 from the AGR vents.  It is expected that the pipeline will be available by the third year of the gasification facility’s operation, so the BACT limits reflect the transport to sequestration sites represented by EOR operations of the captured fraction (80 percent or greater) of CO2 while the remainder of CO2 that is not susceptible to effective separation from other waste acid gases will be emitted from the AGR vents or the subsequent wet sulfuric acid plants without controls.

  • Local Sequestration Not Technically Feasible

While EPA’s guidance on development of BACT limits for GHG emissions specifies that capture and sequestration is to be considered “available”, IDEM’s BACT analysis concludes that sequestration (geologic) is, nonetheless, technically infeasible because it is not applicable to IG’s project.   The inapplicability of sequestration as a control technique appears primarily based on two points: one, IG “has neither access to, nor can develop, a suitable sequestion site for the volume of CO2 that may be vented from the AGR vents” (TSD at 151); and, two, even if a regional sequestration site were available, “the logistical challenges of constructing a second pipeline as a ‘backup’ to the EOR pipeline makes this option infeasible.”  (TSD at 153.)

  • Wet Sulfuric Acid Plant Emissions

The BACT analysis further concludes that no controls are technically feasible for CO2 emissions from the wet sulfuric acid units, based on the following points.  One, the CO2 emissions from the WSA units represent the small residual amounts of CO2 remaining in the waste gases after efficient capture in the AGR process.  CO2 is removed from the syngas stream using a solvent in which CO2, H2S, and COS are preferentially soluble and then applying a second process akin to fractional distillation in which the relative solubilities of these acid gases are used to selectively evaporate and recover CO2, which is least soluble of the three.  However, as the CO2 concentration significantly decreases, it becomes more difficult and, correspondingly, less efficient to separate CO2 from the other two gases.  To apply a secondary and different selective solvent removal of CO2 from the WSA gas stream would be considered technically infeasible, according to IDEM, under EPA’s BACT guidance for GHGs since the WSA waste gas stream could be realistically analogized to those post-combustion waste gases from which CO2 capture is considered inefficient due to low pressure and low concentrations and quantities of CO2 in the gas stream.

Hydrogen Energy California (HECA) Project

The final power plant project posing potential GHG permitting issues is the proposed Hydrogen Energy California (HECA) Project to be located near Bakersfield, California.  The proposed HECA Project consists of an Integrated Gasification Combined Cycle (IGCC) project slated to generate about 280 megawatts (net) of electrical power while capturing 90 percent of the CO2 resulting from the gasification process and sequestering the CO2 through its use in enhanced oil recovery (EOR) in a nearby oil field approximately 5 miles from the project site.  An amended application for certification recently filed on behalf of the HECA Project with the California Energy Commission states that the project will meet or exceed BACT requirements, including [GHG] BACT requirements for CO2 capture and sequestration (i.e., CCS).  It is unclear whether an updated application for a PSD permit has been filed for the project.  Presumably, the proximity of the project site to the EOR location, as well as the commitment of the oil field operator to construct the CO2 pipeline and injection wells for the EOR process, are factors contributing to the willingness of the project proponent, SCS Energy LLC, to commit to permit requirements for CCS.  Yet to be seen is how EPA Region 9 will approach the PSD permit conditions for CCS.


To view a complete PDF of the Second Quarter 2012 issue of the Air Quality Letter, click HERE.

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