Understanding EPA’s Cost Analysis in the Proposed Methane NSPS

(Federal GHG Regulations) Permanent link

Oil & Gas Financial Journal recently published an article by V&E partner Larry Nettles and associate Corinne Snow discussing the assumptions underlying the cost analysis in EPA’s recently proposed New Source Performance Standards (NSPS) for methane and volatile organic compound emissions from the oil and gas sector. The article explains how EPA was able to conclude that the proposed rule will have an net economic benefit by assuming that upstream operators will be able to generate revenue from the additional methane gas that they capture as a result of complying with the rule, and by using a model known as the social cost of methane to assign a value in present-day dollars to each ton of reductions in methane that will result from this rule.

As explained more fully in the article, EPA assigned a value of $4/Mcf to additional natural gas that it anticipates that the industry will capture as a result of the new control methods required under the proposed NSPS. This estimate is higher than current market rates for natural gas, which have declined over the past year. According to the Henry Hub Natural Gas Futures Quotes, natural gas is currently valued just over $2/Mcf, and is predicted to stay below $4/Mcf until the end of 2024. As the chart below demonstrates, EPA was able to reduce its estimates of the costs associated with the proposed NSPS by assuming the $4/Mcf in revenue for the captured gas, which industry is unlikely to actually realize.

EPA also compared the estimated compliance costs to the climate-related benefits that it anticipates resulting from this proposed NSPS. The social cost of methane metric is a variation on another model frequently used by EPA to assess climate change regulations, known as the social cost of carbon. In part because methane is considered a far more potent greenhouse gas than carbon dioxide, the social cost of methane model results in a far higher value for each ton of methane emissions than for carbon emissions. For the sake of performing its cost analysis, EPA valued the methane reductions at $1,100/ton in 2015, while carbon dioxide is currently valued at $36/ton.

EPA used the $1,100/ton figure to conclude that its proposed NSPS would result in a monetized climate benefit of $200-210 million in 2020, and $460-550 million in 2025. These figures outweigh the $170-180 million in new compliance costs for 2020, and estimated $280-330 million in compliance costs in 2025. As a result, EPA concluded that the proposed NSPS has a net economic benefit. 

Posted by Corinne Snow at 11/19/2015 12:09 PM

The Obama Administration Announces New Measures Aimed at Limiting HFCs

(Federal GHG Regulations) Permanent link

On October 15, 2015, the Environmental Protection Agency (“EPA”) announced its proposal for updated measures to curb emissions of ozone-depleting refrigerants (primarily chlorofluorocarbons (“CFCs”)) and certain non-ozone-depleting substitute refrigerants, including hydrofluorocarbons (“HFCs”). If adopted, these rules could significantly impact owners and operators of industrial and commercial refrigeration and air-conditioning equipment. HFCs were widely used as a substitute for ozone-depleting CFC refrigerants when the CAA phased out use of CFCs. Now EPA seeks to phase out the HFCs because of climate change effects.

Section 608(a) of the Clean Air Act requires EPA to promulgate regulations governing the use and disposal of ozone-depleting substances that will reduce emissions from such substances to the lowest achievable level and maximize the recycling of such substances. Section 608(c) prohibits any person from knowingly venting or releasing into the environment any ozone-depleting or non-ozone-depleting substitute refrigerant while maintaining, repairing, or disposing of air-conditioning or refrigeration appliances or industrial process refrigeration. EPA initially issued regulations related to ozone-depleting substances in 1993.

Pursuant to Section 608, EPA issued a proposed rule that would update and expand existing regulatory requirements under the National Recycling and Emission Reduction Program found at 40 CFR Part 82, Subpart F. The Agency proposes to update those requirements applicable to persons that sell, manufacture, own, operate, maintain, or dispose of ozone-depleting refrigerants. Proposed updates would include requiring a number of industry best practices, strengthening leak repair requirements, and establishing recordkeeping requirements for the disposal of certain appliances.

Perhaps more significantly, the proposed rule would extend those requirements to non-ozone-depleting substitute refrigerants, such as HFCs. The proposed rule was published in the Federal Register on November 9, 2015 and will be open to public comment for 60 days after that date.

Posted by Lauren Sidner at 11/13/2015 10:30 AM

EPA Extends Deadline to Comment on Proposed Methane Rules and Guidelines for the Oil and Gas Sector

(Federal GHG Regulations) Permanent link

EPA has granted a 30-day extension to comment on the proposed methane emission rule and two other key documents, each of which could have significant impacts on upstream and midstream segments of the oil and gas industry. Comments are now due by December 4, 2015.

Oil and Gas Air Emissions: EPA’s Three Proposals

On September 18, 2015, EPA published two proposed rules and one set of Control Technical Guidelines (“CTG”) for the oil and gas sector in the Federal Register. The two proposed rules are the New Source Performance Standards (“NSPS”) for methane and volatile organic compound (“VOC”) emissions, and (2) new methods of defining the terms “source” and “adjacent.”

The NSPS requires new, modified, or reconstructed “facilities” in the upstream and midstream industry to install equipment or use certain processes to limit emissions, and requires operators to perform leak detection and repair surveys for fugitive emissions at new, modified, or reconstructed well sites and compressor stations. The proposed source definition seeks comment on two possible methods for EPA to use when determining whether certain oil and gas actions are “adjacent” to each other. This definition is important because it could affect whether oil and gas activities under common control trigger major source air permitting requirements.

The CTG recommends a number of requirements that states can adopt for existing sources to meet standards for air quality in areas that are out of attainment with EPA’s ground-level ozone standards designations. Many of the recommendations are similar to the requirements under the proposed methane NSPS. In October, EPA lowered the National Ambient Air Quality Standards (“NAAQS”) for ground-level ozone from 75 to 70 parts per billion (ppb). When an area is out of attainment with the NAAQS, states must develop additional requirements to limit emissions from certain ozone precursors, such as VOCs, from sources in those non-attainment areas. This CTG is essentially a set of EPA recommendations for requirements that states can impose on sources of air pollution in those non-attainment areas.

EPA has not yet determined which regions of the country are out of attainment with its new, stricter standard. However, it is likely that additional areas where oil and gas activities occur will be out of attainment with the new standard, and thus be subject to additional control measures for VOC emissions. These control measures would apply to both new and existing sources.

More information about these 3 proposals and the impacts that they could have on the oil and gas sector is available here and here.

Public Comments

Originally EPA provided the public with 60 days to comment on these 3 proposals. In response to requests from industry, EPA has extended the deadline by 30 days. The public comment period is an important part of the rulemaking process. Because EPA must read and consider all of the comments that it receives during this period, commenting on a proposal offers the public with a chance to provide EPA more information or to correct potential problems or shortcomings in the proposals. The comments also become part of the official record for the rulemaking, meaning that they form part of the body of information that a court can look at when reviewing the agency’s rules. If a point has not been raised to the agency during the comment period, then a party cannot later raise that argument in a legal challenge to the rule.

Posted by Corinne Snow at 11/09/2015 3:44 PM

India Submits Climate Plan Ahead of UN Paris Summit

(International) Permanent link

In anticipation of the United Nations Framework Convention on Climate Change (UNFCCC) Summit this December, India submitted a plan to reduce its GHG emissions just hours before the UN's deadline on October 8. Under the Lima Accord reached at last year's summit, which this blog reports on here, participating countries agreed to submit such climate plans -- also known as Intended Nationally Determined Contributions (INDCs) -- over the course of this year. These INDCs are to form the basis of an international agreement to reduce global emissions, which the UNFCCC hopes to reach this year in Paris.

India's INDC merits particular attention. India is the world’s third largest carbon emitter and is considered a pivotal player in international climate negotiations. The country's plan can be broken down into four parts:

(1) Reduce emission intensity by 33 - 35% compared to 2005 levels by 2030

(2) Achieve 40% of its energy capacity from renewable energy sources by 2030

(3) Create carbon sinks of 2.5 – 3 billion metric tons of CO2 equivalent by 2030

(4) Improve adaptation through water conservation and climate resilient agriculture

The commitment to reduce emission intensity is the focal point of the plan. This is not a promise to reduce overall emissions. Rather it is a promise to reduce the amount of carbon emissions per unit of GDP. In other words, as India's economy grows, the rise in carbon emissions will occur more slowly than it would have otherwise. Under business-as-usual, emissions would grow with the economy on a one-to-one ratio. Under the terms of the plan, some commentators estimate that while India’s economy will grow seven times larger by 2030, its emissions will merely triple.


Figure shows India’s future greenhouse gas emissions depending on future emission intensity. Source: CarbonBrief (analysis based on emissions data from BP and WRI, GDP data from World Bank, and GDP growth forecasts from OECD and India’s INDC).

Opinions vary on whether the plan goes far enough. Some commentators view the plan as “conservative.” Significantly, as noted above, the plan does not commit to an overall reduction in emissions, nor does it commit to peaking its emissions in a given year as China has promised. The plan’s success may also depend on funding by the international community. India’s INDC states that its efforts may cost around $2.5 trillion over the next 15 years. While the plan does not specify how much of that should be funded by the international community, it does request aid from the Green Climate Fund, a United Nations entity that solicits adaptation-related donations from developed countries. Because of the plan’s hefty price tag and the uncertainty surrounding how it will be paid, some commentators question the likelihood that India will achieve its goals.

On the other hand, the plan exceeds the expectations of many. India has previously been regarded as obstructionist in climate negotiations by both the United States and Europe, largely for its hardline position that developed countries alone should bear the responsibility for reducing emissions. The commitment to reduce emissions intensity and to aggressively build up renewable energy is therefore viewed as a significant shift in position. Some also predict that the renewable energy commitment will lead to a greater decrease in emission intensity than promised in the INDC.

Despite concerns, the reaction to India’s INDC submission has been largely positive. At the very least, the INDC signals that India is ready to play a more positive role in international climate negotiations.

Posted by Kristen Miller at 10/28/2015 10:49 PM

The Clean Power Plan’s Building Block 3: New Zero-emitting Renewable Generating Capacity

(Clean Power Plan) Permanent link

This is the fourth in a series of posts explaining the “building blocks” that EPA used to determine emission goals for existing power plants in the Clean Power Plan.  This post focuses on what EPA calls building block 3.  Building block 3 is based on EPA’s assumption about the extent to which generation from fossil fuel-fired EGUs can be replaced by expanding the amount of zero-emitting renewable electricity (“RE”) generating capacity.

The renewable electricity technologies used to quantify building block 3 generation levels were: (1) onshore wind, (2) utility-scale solar PV, (3) concentrating solar power (“CSP”), (4) geothermal and (5) hydropower.    Each is a utility-scale, zero-emitting resource. EPA expressly chose not to include distributed technologies as part of the BSER.  Additionally, EPA excluded any renewable electricity technologies that have not been deployed in the U.S., including “demonstrated RE technologies for which there is clear evidence of technical feasibility and cost-effectiveness (e.g., offshore wind) . . . These RE technologies are consequently reserved for compliance.”

EPA quantified building block 3 generation levels for each of the three BSER regions in terms of incremental, rather than total, RE generation. To calculate the Building Block 3 generation levels:

  1. EPA collected historical data on the annual change in capacity for each RE technology over the most recent five-year period. Using this data, EPA calculated each RE technology’s:  
    • average change in capacity from year to year over a five year period (2010 – 2014), and
    • maximum annual change in capacity during the same five year period. 
  2. EPA assigned each RE technology a capacity factor representative of expected future performance from 2022 through 2030.  EPA reportedly relied on the National Renewable Energy Laboratory’s (NREL) 2015 Annual Technology Baseline (ATB) to determine the appropriate capacity factor for each RE technology.

  3. EPA then used the data from steps (1) and (2) above to calculate two levels of generation change for each RE technology.  
    • The first was the annual generation change for each RE technology associated with that technology’s five-year average capacity change (or the product of the five-year average capacity change and the capacity factor).
    • The second was the annual generation change for each RE technology associated with that technology’s maximum capacity change (or the product of the five-year maximum annual capacity change and the capacity factor).
  4. EPA estimated the RE generation from capacity commencing operation after 2012 that could be expected in 2021 without implementation of the final rule. Using base case power sector modeling projections, EPA assumed RE generation of 213,084,125 MWh in 2021. 
  6. To calculate projected RE generation for the first two years of the interim period, EPA used the more moderate level of generation change from step (3) above (the generation change associated with the historical average capacity change). This resulted in projected RE generation levels of:
    • 241,880,347 MWh in 2022, and
    • 270,676,570 MWh in 2023.
  7. For each year of the interim period after 2023, EPA applied RE generation associated with the maximum annual capacity change from the historical data analysis.1 Aggregated across the three BSER regions, this produced generation levels of:
    • 332,869,933 MWh in 2024, and
    • 706,030,112 MWh by 2030.

From there, EPA conducted an analysis using an Integrated Planning Model (“IPM”) to further evaluate the cost-effectiveness and technical feasibility of these generation levels. The IPM projections incorporated a variety of constraints on the deployment of RE, including “resource constraints such as resource quality, land use exclusions, terrain variability, distance to existing transmission, and population density; system constraints such as interregional transmission limits, partial reserve margin credit for intermittent RE installations, minimum turndown constraints for fossil fuel-fired EGUs, and short-term capital cost adders to reflect the potential added cost due to competition for scarce labor and materials; and technology constraints such as construction lead times and hourly generation profiles for non-dispatchable resources by season.” 2 Additionally, the modeling framework assumed that “deployment of variable, non-dispatchable RE resources is limited to 20 percent of net energy for load by technology type and 30 percent of net energy for load in total at each of IPM’s 64 U.S. sub-regions.” 3 This 30 percent constraint reportedly reflects levels commonly modeled in grid integration studies at the level of the interconnection. EPA claimed that such studies have demonstrated that impacts to the grid in reaching levels as high as 30 percent of net energy for load from RE are relatively minor. a

The IPM also served as the basis for apportionment of the generation levels across the three interconnections. EPA concluded that the majority of RE deployment was projected to occur in the Eastern Interconnection. The following table describes the annual building block 3 generation levels for each interconnection from 2022 through 2030.

  Eastern Western Texas
2022 166,253,134 56,663,541 18,963,672
2023 181,542,775 60,956,363 28,177,431
2024 218,243,050 75,244,721 39,382,162
2025 254,943,325 89,533,078 50,586,893
2026 291,643,600 103,821,436 61,791,623
2027 365,044,150 365,044,150 84,201,085
2028 365,044,150 132,398,151 365,044,150
2029 401,744,425 146,686,508 95,405,816
2030 438,444,700 160,974,866 106,610,547

1 EPA explained its decision to apply the five-year average capacity change to the first two years of the interim period while applying higher RE deployment levels for later years as a means “to ensure adequate opportunity to plan for and implement any necessary RE integration strategies and investments in advance of the higher RE deployment levels assumed for later years.”

2 Preamble, Pg. 758-759.

3 Preamble, Pg. 759.

Posted by Margaret Peloso and Lauren Sidner at 10/08/2015 2:00 PM

The Clean Power Plan’s Building Block 2: Generation Shifts Among Affected EGUs

(Clean Power Plan) Permanent link

This is the third in a series of posts explaining the “building blocks” that EPA used to determine emission goals for existing power plants in the Clean Power Plan. This post focuses on what EPA calls building block 2. In the final rule, building block 2 assumed a shift of generation—phased in gradually over the 2022 to 2030 interim period—from existing fossil-fuel fired steam generating units to existing natural gas combined cycle (“NGCC”) units, increasing the annual utilization rates of NGCC units, on average and within each region, to 75 percent on a net summer capacity basis.

EPA explained that “substituting generation from less carbon-intensive affected EGUs . . . for generation from the most carbon-intensive affected EGUs . . . is a component of the BSER for steam EGUs because generation shifts that will reduce the amount of CO2 emissions at higher-emitting EGUs . . . are technically feasible, are of reasonable cost, and perform well with respect to other factors relevant to” BSER.1 By carbon intensity EPA means the pounds of CO2 that are emitted for each MWh of electricity that is generated. 

In 2012, national average CO2 emission rates across the following technology types on a net generation basis were:  

  • Coal Steam: 2,217 lbs/MWh
  • Oil/Gas Steam: 1,435 lbs/MWh
  • NGCC: 905 lbs/MWh2  

Building block 2 only took “existing EGUs” utilizing NGCC into account, but for purposes of the final rule, the phrase “existing EGUs” included units that were under construction as of January 8, 2014.

EPA’s Basis for the Magnitude of Generation Shift

EPA concluded that “an annual average utilization rate of 75 percent on a net summer basis is a conservative assessment of what existing NGCC units are capable of sustaining for extended periods of time.” This is compared to EPA’s calculation that the NGCC fleet operated with an average annual capacity factor of 46% in 2012. EPA’s estimation of the amount of generation that can be shifted to NGCC was based on the assessment of two factors. First, EPA examined the ability of NGCC capacity to shift from its traditional use for peaking to serving as baseload generation with a higher utilization rate. Second, EPA examined the technical capacity of NGCC to sustain higher utilization rates.

To determine the extent to which generation could be shifted from existing coal to existing NGCC capacity, EPA looked at historical generation shifts to NGCC generation. Between 2005 and 2012, EPA determined that NGCC generation increased by approximately 439 TWh, representing an 83 percent increase. Importantly, while the GHG Mitigation Measures TSD was not explicit on this point, it appears that EPA’s evaluation of historical generation growth included both increased utilization of natural gas capacity that was already in existence, as well as the installation of new generation capacity over the period of analysis. EPA used this historical overall growth rate in NGCC as the basis for its expectation of the rate at which NGCC generation at existing units would grow under the Clean Power Plan. 

EPA compared its calculated 2005 to 2012 growth rate to the 2015 to 2022 time period (a time period of the same duration) to determine the potential growth in NGCC capacity that would result from the application of building block 2. Applying building block 2, total NGCC generation from these existing sources in 2022 was expected to be 1,498 TWh, which is an increase of approximately 44% over 2014 generation levels.

In addition to technical capability to support shifting generation, EPA concluded that the increase in NGCC generation assumed for building block 2 can be achieved without impairing power system reliability. EPA’s conclusion was based in large part on the fact that a shift in average annual utilization across existing EGUs will not interfere with the power sector’s ability to maintain adequate dispatchable resources to maintain reliability. Moreover, because sources are not required to achieve the full extent of building block 2, sources will have the flexibility they need to preserve reliability.

EPA also looked at the technical capability of existing natural gas infrastructure and the electricity transmission system to take on increased quantities of natural gas and to accommodate shifting generation. EPA determined that the natural gas pipeline system is already supporting national average NGCC utilization rates of 60 percent or higher during peak hours and concluded that it is reasonable to expect that similar utilization rates are possible in non-peak hours when constraints are typically less severe. 

EPA looked at projected natural gas production going forward and determined that the increase in NGCC generation contemplated under building block 2 is consistent with the production potential of domestic natural gas supplies. 

EPA evaluated the potential impact on the transmission planning process and concluded that the generation shift would not impose a significant additional burden on the transmission planning process and would not necessitate major construction projects. EPA’s conclusion was based in part on the fact that building block 2 does not call for the connection of any new capacity to the power grid. Moreover, EPA determined that regional grids are already supporting the operation of NGCC units at high capacity factors and for sustained periods of time. As such, EPA does not expect building block 2 to necessitate significant new construction beyond upgrades that are part of the normal planning process. 

Phase-In Schedule

EPA established the building block 2 phase-in schedule in two steps. The Agency first determined the generation shift that would be feasible by 2022, the first year of the interim period. It then considered how quickly that amount could grow until the full amount of NGCC generation (all existing plants operating at 75% of peak summer load) could be achieved as part of the BSER. EPA based both determinations on historical growth rates.

To determine the 2022 level, EPA identified the single largest annual increase in power sector gas-fired generation since 1990. The largest annual increase occurred between 2011 and 2012 and was equal to 22 percent. Therefore, EPA assumed that between 2012 and 2022 gas-fired generation would increase by 22 percent. For each year after 2022, EPA applied the average annual growth in gas-fired generation in the power sector between 1990 and 2012: approximately 5 percent per year.

Applying each of the above quantities, the final rule provided that for purposes of calculating BSER:  

  • NGCC generation in 2022 is limited to a maximum of a 22% increase from 2012 levels in each region.
  • In each subsequent year, NGCC generation is limited to a maximum of a 5% increase from the previous year.
  • The phase-in continues until the full level (75%) is reached in each region.  
BSER Maximum NGCC Generation by Region and Year (TWh).

1 Preamble, Pg. 429. 
2 Greenhouse Gas Mitigation Measures Technical Support Document, Pg. 3 – 4.

Posted by Margaret Peloso and Lauren Sidner at 10/05/2015 4:25 PM

The Clean Power Plan’s Building Block 1: Efficiency Improvements at Affected Coal-Fired Steam EGUs

(Clean Power Plan) Permanent link

This is the second in a series of posts explaining the “building blocks” that EPA used to determine emission goals for existing power plants in the Clean Power Plan. This post focuses on what EPA calls building block 1. Building block 1 consists of measures that improve heat rate at coal-fired steam electric generating units (“EGUs”). In the final rule, EPA concluded that “a well-supported and conservative estimate of the potential heat rate improvements” achievable through best practices and equipment upgrades is a 4.3% improvement in the Eastern Interconnection, a 2.1% improvement in the Western Interconnection and a 2.3% improvement in the Texas Interconnection.

An EGU’s heat rate refers to the amount of fuel energy input required (Btu) to produce 1 kWh of electrical output, and EPA described heat rate improvements as “changes that increase the efficiency with which an EGU converts fuel energy to electric energy, thereby reducing the amount of fuel needed to produce the same amount of electricity.” Because fuel combustion is the primary source of GHG emissions from EGUs, decreasing the amount of fuel required to produce a particular amount of electricity through heat rate improvements would also reduce the carbon intensity of a source’s generation.  

To calculate heat rate improvement potential for coal-fired EGUs, EPA employed three different analytical approaches to determine the degree of heat rate improvements reasonably achievable by each interconnection through the application of best practices and equipment upgrades.  EPA described the three analytical approaches as follows:  

  1. The “efficiency and consistency improvements under similar conditions” approach;
  2. The “best historical performance” approach; and
  3. The “best historical performance under similar conditions” approach.
For all three approaches, EPA used a dataset comprised of 11 years’ worth (from 2002 – 2012) of hourly gross heat rate for 884 coal-fired EGUs, and EPA reportedly employed a unit-specific approach, comparing each EGU’s performance against its own historical performance, rather than comparing an EGU’s performance against other EGU’s with similar characteristics.

Additionally, in each of the three approaches, EPA assessed potential heat rate improvements regionally, within the Eastern, Western, and Texas Interconnections. The Texas Interconnection generally corresponds to the portion of the state of Texas covered by the Electric Reliability Council of Texas.  

Each of the approaches resulted in heat rate improvement values that differed by several percent. According to EPA, the different values all represented reasonable estimates of the potential for heat rate improvements by EGU’s in the three interconnections, but EPA ultimately selected the most conservative value (meaning the smallest heat rate improvement) for each region. In all three regions, the most conservative values were generated using the “efficiency and consistency improvements under similar conditions” approach. As such, this approach is described detail below.

The “efficiency and consistency improvements under similar conditions” approach:

EPA determined that there are three sets of factors that influence an EGU’s heat rate (1) ambient temperature, (2) hourly capacity factor at the unit in question, and (3) unit-specific factors that are within the control of the operator. To control for the factors that are outside of the operator’s control, EPA structured its analysis of heat rate improvements under the “similar conditions” approach by segmenting each unit’s performance based on historical emissions in a series of capacity factor and ambient temperature combinations. To do so, EPA created a matrix comprised of 168 “bins,” each of which represented a 10-degree Fahrenheit range in ambient temperature, and a 10-percent range in capacity factor. EPA then distributed each hour of gross heat rate data for each EGU into the matrix. For example, one bin would contain all of an EGU’s hourly gross heat rate data generated from 2002 through 2012 while that EGU was operating at an 80- to 89-percent capacity while the ambient temperatures were between 70oF and 79oF.

EPA determined that its matrix appropriately controls for variations in temperature and capacity factor and that any remaining variation in each bin’s data would be primarily driven by factors within the EGU operator’s control, representing the possible range of heat rate improvements. EPA then established a benchmark for each bin based on each EGU’s 10th percentile hourly gross heat rate for each capacity-temperature bin. In other words, the benchmark was demonstrated by 10 percent of all measurements in each capacity-temperature bin. The Agency reportedly “chose the 10th percentile because it represents a demonstrably achievable gross heat rate indicating efficient operation of the EGU, but ignores unusually low outlier values.” EPA excluded outlier values that were greater than ±2.6 standard deviations from the EGU’s mean gross heat rate.

EPA then assessed the effect on overall heat rate that would occur if EGUs achieved more consistently efficient operation. To do so, EPA compared the data in each bin to the bin’s benchmark value and identified all hourly gross heat rate values that were greater than the benchmark. EPA then adjusted each hourly gross heat rate that was greater than the benchmark downward by a specific percentage, which EPA referred to as a “consistency factor.” EPA reportedly employed a statistical assessment of the overall variability of heat rate in each region to come up with the following consistency factors: 38.1% for Eastern Interconnection; 38.4% for the Western Interconnection; and 37.1% for the Texas Interconnection. For greater detail on the Agency’s procedure for calculating the applicable consistency factor, refer to page 2-48 of EPA’s Greenhouse Gas Mitigation Measures Technical Support Document (“GHG Mitigation Measures TSD”).

The Agency’s general approach is “based on the principle that a coal-fired EGU following best practices should be able to consistently operate closer to the demonstrated and achievable benchmark heat rate.” GHG Mitigation Measures TSD, pg. 2-46.

Applying this process to all 884 coal-fired EGUs in the dataset, EPA determined that it would be reasonable to conclude that, on average, EGUs are capable of improving heat rate by:
  • 4.3 percent in the Eastern Interconnection;
  • 2.1 percent in the Western Interconnection; and
  • 2.3 percent in the Texas Interconnection.
Example Equipment Upgrades and Best Practices for Heat Rate Improvements

EPA’s GHG Mitigation Measures TSD provides the following non-exhaustive lists of equipment upgrades and best practices that could be used to improve heat rates:

Equipment upgrades:
  • Install intelligent sootblowing system
  • Replace feed water pump steam turbine seals
  • Overhaul high pressure feed water pumps
  • Upgrade main steam turbine seals
  • Upgrade steam turbine internals
  • Install variable frequency drives for motors
  • Retube or expand the condenser
  • Install sorbent injection system to reduce flue gas sulfuric acid to allow lower temperature exhaust gas
  • Upgrade air heater baskets for lower temperature operation
  • Upgrade and repair flue gas desulfurization systems
  • Refurbish the economizer
  • Upgrade ESP components to lower auxiliary power consumption
  • Improve SCR and FGD system components to lower draft loss
Best practices 
  • Adopt training for O&M staff on heat rate improvements
  • Perform on-site appraisals to identify areas for improved heat rate performance
  • Install neural network software for combustion/optimization with monitoring system for heat rate optimization
  • Repair steam and water leaks – replace leaking valves and steam traps
  • Replace / repair worn air heater seals
  • Manage feed water quality
  • Chemical clean boiler to remove scale build-up from water side
  • Install and operate condenser tube cleaning system
  • Repair boiler furnace and ductwork cracks to prevent boiler air in-leakage
  • Clean air preheater coils to restore performance
  • Adopt sliding pressure operation to reduce turbine throttling losses
  • Reduce activation of attemperator which compensates for over-firing the unit
  • Remove deposits on turbine blades
Cost of Building Block 1

According to EPA, the cost attributable to emissions reductions under Building Block 1 is equal to the cost of achieving heat rate improvements less any savings from reduced fuel expenses. EPA expects that the savings in fuel cost associated with the percentage heat rate improvements identified for each region will cover much of the associated costs and predicts that even if EGUs were to rely primarily on equipment upgrades (rather than cheaper-to-implement best practices) to reduce heat rate, reductions could generally be achieved at $100 or less per kW, or approximately $23 per ton of  CO2 removed.

Posted by Margaret Peloso and Lauren Sidner at 10/05/2015 11:25 AM