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Time to Repeal New Source Review? (Up to 30 GW of coal-plant upgrades hangs in the balance)

The typical pulverized coal power plant in the U.S. is about 35 years old, yet the fleet will continue to operate for many years to come. New coal-fired plants, meanwhile, will continue to enter service but at a slow rate. There may not be a future price for carbon dioxide (CO2) given the dramatic scientific and political developments that we are going through, but cheap natural gas makes it difficult to justify the higher up-front costs of a new coal plant.

Still, there is significant new electricity generation capacity is possible from these older plants, perhaps as much as 30,000 MW–twice EIA’s projected growth of coal power over the next two decades. In addition, new technology upgrades have the potential of improving the operating efficiency by 3% to 5%. But the impediment for such win-wins is the risk of a New Source Review violation, years of litigation, and possibly fines.

Given the Obama Administration’s stance against coal, many attendees of the National Coal Council’s December meeting were caught flat-footed when DOE Assistant Secretary for Fossil Energy James Markowsky suggested an exception be made under Clean Air Act’s New Source Review (NSR) program. Mr. Markowsky proposed easing the NSR requirements for power plants that make modifications to improve their operating efficiency–assuming those plants would be good candidates for a later retrofit of a carbon capture and sequestration (CCS) system.

Markowsky’s trial balloon also suggested that candidate plants would already have installed flue gas desulfurization (FGD) systems. The concept is intriguing but doesn’t go near far enough in solving the nation’s energy woes.

NSR Definitions Remain Murky

NSR is the process established by the Clean Air Act (CAA) that requires utilities to add a host of new and expensive emission controls should they make any “major modifications” to the plant that increase emissions. The definition of a major modification has been the subject of numerous court battles since the Clinton Administration yet stills remains murky. Even when upgrades were discussed with the EPA in advance of their installation, Justice has routinely lowered the legal boom on utilities that made common maintenance changes to their plants The usual result has been a decade of legal maneuvering followed by a consent decree agreement where the utility agrees to install new emission controls and pay a fine.

The historic and current definition of a major modification to an exiting plant under NSR is, according to the EPA: “Any physical change in or change in the method of operation of an existing major source that would result in a significant net emissions increase of any pollutant subject to regulation under the CAA.” There is no bright line that shouldn’t be crossed or list of changes in the plant to be avoided. The definition of significant is subjective and historically been guided by political whim.

Physical and operational changes are excluded from NSR under the routine maintenance, repair, and replacement (RMR&R) exclusion. However, after all these years there is no firm decision on questions such as: “Is the repaired steam turbine (and perhaps the only available upgrade physically possible) a major upgrade or an RMR&R?” Who knows? The WEPCO rule adopted in 1992 did give plants a longer past actual emission baseline period and other exclusions, but it didn’t firm up the RMR&R definition. The Bush administration also tried to quantify RMR&R and failed.

However, if an owner improves the plant’s efficiency by installing modern technology replacement parts, it may cause the plant to increase its hours of operation and therefore produce sufficient net emissions such that it triggers an NSR review. Note that the rule does not allow a utility to offset emissions by suggesting that the increased efficiency of one plant results in a decrease in the number of operating hours at another facility and therefore the system has a net decrease in emissions. After all, for any particular operating hour, it’s a zero sum game—the number of megawatt-hours will be supplied by some combination of coal plants optimized on price, not emissions. NSR does not allow a macro view of the nation’s overall emissions, but rather, is focused on the microscopic or a singular plant.

Triggering an NSR review requires the EPA to review force the plant to meet the latest emissions standards. A good analogy would be if you put a new carburetor on your 1957 Chevy you would then have to meet all the 2010 air quality standards. Often the cost of the upgrades cost more than the first cost of the plant.

Today, the EPA has maintained that what constitutes RMR&R is determined on a case-by-case basis where EPA staff “weigh[s] the nature and extent, purpose, frequency and cost of a project as well as other relevant factors, with no one factor necessarily conclusive.” The end result is that few utilities will make any plant modifications or upgrades that might possibly be construed as a major modification and trigger NSR.

For years, the NSR rule has provided a disincentive for utility plant efficiency improvements and redefined the term “upgrade” as a dirty word in the industry. From personal experience, many utility engineers avoid the word “upgrade” when speaking of maintenance modifications completed during their last overhaul outage.

A final sensitivity: Justice Department and legal counsel for defendants have many times contacted POWER magazine (where I am Editor-in-Chief) because we used words like “upgrade” or “performance improvement” in articles describing work completed at a plant as evidence of an NSR infraction. We also now avoid these and similar terms when writing about industry projects.

Efficiency Improvements vs. NSR

A recent example of an NSR consent decree is Duke Energy’s Gallagher Plant that entered into an agreement with the Justice Department last December ending 10-years of litigation over the Indiana power plant. Duke agreed to pay $88 million for emissions retrofits including a $1.75 million penalty to settle the NSR violation allegations. Duke maintains the plant modifications were regular maintenance projects that do not come under the NSR rules. Under the agreement, Duke must retire two of the four units at the Gallagher plant or convert them to run natural gas (not likely, according to Duke) and add FGD systems costing about $80 million to the remaining two units plus other environmental projects.

The Gallagher plant consent decree was the 17th settlement secured by the Justice Department. Settlement of this suit doesn’t affect other NSR suits Justice is pursuing against Duke. In January, Justice also settled with Westar Energy for the $500 million cost of adding FGD systems to the Jeffrey Energy Center plus an agreement to pay for a lengthy list of other environmental projects.

Given the recent active enforcement of NSR (although Justice’s NSR prosecution success rate over the past year is around 50%) merely suggesting exceptions to NSR to improve coal plant operating efficiency was a gutsy move by Markowsky given the post-conference flak he received from the usual environmental groups. “We think there is an opportunity of maybe carving out part of the fleet and having a relaxation [of NSR standards] so we can do things that we feel we can do with existing technologies and increase their efficiency and…reduce CO2.”

Markowsky went on to say:

If it’s attractive to [the Environmental Protection Agency], maybe we can carve out a fleet….. Say, for instance, you have part of the fleet that has high probability of being retrofitted with carbon capture and storage in the future—[they] would be good candidates to improve their efficiency right now.

When pressed about which plants would be good candidates, Markowsky said that good CCS-candidate plants should be allowed to make efficiency improvements “without going through the kind of process that would trip a lot of other things because that right now is holding back the industry from doing these types of enhancements.”

Markowsky, an executive vice president for American Electric Power until 2000, certainly understands that the quickest and most economic way to reduce carbon emissions from the 1,445 existing coal-fired power plants in the U.S. is to increase the efficiency and net power produced of a facility. Remember, CCS will require as much as 25% to 35% of the plant’s electrical output to run the chemical plant used to capture the carbon and therefore decimate the plant’s operating economics so perhaps this is Markowsky’s way of throwing sweetening the bad medicine that comes with CCS retrofits.

In the European Union (EU), utilities are encouraged to improve the efficiency of their coal-fired plants, and additional carbon allowances have been awarded under the EU Emissions Trading Scheme to the owners of those upgraded plants. To their credit, the EU emissions regulators understand that their responsibilities include reducing their overall system’s carbon emissions rather than micromanaging the emissions from individual units.

NSR Forces Utility Inaction

Today, as Markowsky notes, there is little or no motivation for U.S. utilities to increase the operating efficiency of coal-fired power plants beyond the day-to-day tweaking of controls or other obviously minor maintenance modifications. Given that the average age of the nation’s coal-fired fleet is around 35 years, it’s a safe bet that there are many technology improvements available to plant owners to improve operating efficiencies. Unfortunately, usual practice is to forgo state-of-the-art upgrades, such a steam turbine rotor and blade upgrades when the original equipment is worn out, to avoid even the appearance of an NSR infraction.

Since the establishment of NSR, there have been many technical improvements in power generation theory and practice. The upgraded steam path components are an example that is well-documented and proven in practice. Other improvements include advanced heat transfer alloys, digital controls, and automated and more efficient fire-side cleaning options. Technology advances continue, and so do efficiency improvement opportunities.

Over the life of the existing coal fleet, fuel costs have escalated by a factor of 10 in cost per million Btus, making efficiency improvements much more attractive now than at any time in the past. New equipment designs, such as larger and more efficient air heaters for reducing boiler exit gas temperatures to a lower level and reducing air leakage rates, are now available. Easily understood and documented improvements are also are available for steam cycle upgrades, such as installing more advanced and larger condensers or cooling towers for improved turbine performance.

These upgrades were not discussed by Markowsky in his presentation. Upgrades that can tap the efficiency improvement and uprated power output potential that remains locked away in our nation’s coal-fired power plants. Quantifying the uprates is not a simple task but a quick screening study will give some insights. I thought the results were quite interesting.

Ready Efficiency Improvements

Here are some examples of significant improvements that could be implemented for less cost than the current installed cost of new fossil-fueled generation capacity, which is around $2,000/kW. The examples are based on three actual coal plants that represent a large segment of the nation’s existing coal-fired fleet of more than 1,400 individual units.

(We’re going to get a little technical at this point by defining some improvements available to existing steam plants in some detail. If the details are of little interest, just skip to the last section of the article.) For the screening study, we defined three general classes of coal-fired plants:

· Plant A: 600 MW pulverized coal 2,400 psi/1,000F main steam/1,000F reheat steam, corner-fired unit burning western Powder River Basin (PRB) coal.

· Plant B: 500 MW pulverized coal 2,400 psi/1,000F/1,000F, wall-fired unit burning PRB coal.

· Plant C: 650 MW pulverized coal 2,400 psi/1,000F/1,000F wall-fired unit, burning eastern bituminous coal.

Given these operating conditions, a set of candidate physical upgrades to the boilers were developed, unconstrained by the limits imposed by an NSR, including these:

· Install new regenerative air heaters and replace aging ductwork from the boiler to the induced draft fans.

· Change the superheater and reheater surfaces to permit the furnace exit gas temperatures (FEGT) to be combustion-tuned to be consistent with new fuel source requirements. Some boilers have insufficient superheater or reheater surface to produce design steam temperatures with a furnace-side best possible FEGT. The insufficient superheater (SH) and reheater (RH) surface requires the FEGT higher than optimum, which reduces combustion efficiency.

· The higher-than-optimum FEGT required for best steam-side thermal performance is not compatible with the best fire-side slagging and fouling performance. The elevated upper furnace temperatures contribute to accelerated slagging and fouling, which is mitigated by aggressive sootblowing.

· Upgrade the alloy of the existing superheaters and reheaters.

· Replace existing feedwater heaters with upgraded alloy and improved heaters.

· Redesign and upgrade the furnace waterwalls and add water-cooled platens.

· Install new and larger condensers and/or cooling towers for reduced condenser back pressure.

· Install hybrid air-cooled/water-cooled condensers to reduce cooling water usage.

· Install new, more efficient steam turbine rotors to upgrade and uprate capacity and efficiency.

· Other changes as required to “debottleneck” both the combustion process and the steam cycle.

· Upgrade coal pulverizers for less auxiliary power consumption, larger capacity, and better fineness.

Plant A Improvement Potential

This unit was originally designed for a higher-quality fuel than what is currently fired. PRB subbituminous fuel is the typical fuel today because of its lower sulfur, lower price, and lower NOx production. PRB fuel operates best when the FEGT is about 2,150F for reduced slagging and fouling. For both reasons of the fuel change and the changing firing conditions of low-NOx operation, the FEGT now tends to operate at about 2,400F rather than the desired 2,150F. The reduced FEGT is desirable for reduced slagging and less-aggressive sootblowing. When the FEGT is reduced for more favorable fire-side slagging and fouling conditions, then the superheater and reheater temperatures cannot achieve the design and required 1,000F (Figure 1).

1. Upgrade options for Plant A configuration. Source: Storm Technologies Inc.

Specific upgrades to the plant, in a non-NSR world, include:

· Redesigned superheater and reheater surfaces and upgraded metals

· New and upgraded cooling towers, possibly a hybrid air-cooled conventional to reduce water evaporation losses

· Upgraded turbine rotors

· New feedwater heaters

· New and larger boiler feed pumps

· New and larger coal pulverizers

· Condenser metals upgrades

Another possible improvement and upgrade is a complete redesign of the superheater and reheater to add more tube surface and upgrading the alloy for increased reliability and life.

These boiler upgrades are estimated to cost about $5 million per plant. The turbine rotors and steam path improvements are also feasible. Between the combination of steam path improvements and boiler surface changes, an expected 50 MW in increased power output could be added to the plant, plus a plant efficiency increase of 300 to 500 Btu/kWh (3% to 5%), not to mention approximately 3% to 5% less carbon emissions and lower NOx and SO2 emissions on an hourly basis.

How do these improvements translate into savings? For an average-performing midsize coal-fired plant, an extra 50 MW of additional power sales at $20/MWh translates into perhaps another $2 million of net power sales revenue each year. Also, a 500-Btu/kWh improvement in plant heat rate for a typical 500-MW coal plant operating at an 80% capacity factor burning PRB coal will reduce fuel consumption by about 10,000 tons each year. At $40/ton delivered, that’s $400,000 saved each year. Overall, this efficiency upgrade has a simple payback on its $5 million cost of only two years. Without NSR, a utility would perform these upgrades in an instant.

Plant B Improvement Potential

This wall-fired boiler has a similar steam-side, fire-side incompatibility (Figure 2). The FEGT must be increased to over 2,300F average bulk gas temperature in order to reach the design steam temperature. Here, too, the redesign of the superheater and reheater on this boiler to match the heat transfer surfaces with today’s fuels and steam demand will yield significant overall heat rate improvement.

2. Upgrade options for Plant B configuration. Source: Storm Technologies Inc.

Combining the boiler improvements with uprated and upgraded steam turbine rotors and controls (discussed above) could increase output by an estimated 35 MW or more and also improve the overall heat rate by 500 Btu/kWh, for about a 5% increase in plant efficiency (resulting in 5% less CO2 emissions).

Plant C Improvement Potential

The improvement potential for this boiler mainly involves the boiler exit gas ductwork and air heater replacement (Figure 3). The existing air heaters are an unusual design and tend to have leakage rates well over 15%. Also, the exit gas temperature corrected to no leakage can be reduced at least 35F. The combination of replacing the air heaters with the latest and most advanced regenerative ones, increasing the boiler heat transfer surface area, and reducing the total leakage can improve the heat rate by about 200 Btu/kWh.

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3. Upgrade options for Plant C configuration. Source: Storm Technologies Inc.

Combining the improvements to the combustion process with advanced steam turbine rotors and steam path improvements could result in a 50-MW increase in capacity and an estimated overall heat rate improvement of about 500 Btu/kWh or better.

We cannot name the plants used as examples for obvious reasons. However, they demonstrate the huge incentives in both CO2 reduction as well as fuel cost savings and capacity increases that exist in the power generation industry.

Finally, and perhaps most important, these upgrades could be completed for far less cost than the very high costs of building a new coal plant.

Apply Results to Many Plants

In general, we estimate about 20% (roughly 250 plants) in the U.S. fall into each of these three categories. Upgrading the efficiency of these plants by 3% to 5% reduces the carbon emissions for the same power production by also about 3% to 5%. However, the technology advances also produce significant incremental power increases, perhaps as much as 30,000 MW or more if applied across the fleet. This increase in coal-fired electricity is more than the projected coal plant capacity additions estimated by the EIA through 2030 as shown in the 2010 Annual Energy Outlook.


In my opinion, the existing fleet of coal-fired plants are a national asset that are under utilized and can be easily upgraded for improved efficiency and increased power generation. For those plants that have the full complement of emission controls (FGD, selective catalytic reduction, electrostatic precipitators, and so on) and meet all the existing ambient air quality standards, NSR should be removed so the nation can benefit from the incremental power and efficiency improvements possible at existing coal plants.


Dick Storm, senior consultant for Storm Technologies Inc. provided the three example coal plants, the figures, and other technical assistance in preparing this article.


1 Ashby Lynch { 02.04.10 at 1:32 pm }

These improvements make sense and need to be done. What portion of the labor and materials would originate in the U.S for these upgrades? Can the unions be employed to lobby for this?

I would like to see a thorough discussion of the pump storage issue for the U. S. I live in West Virginia, and have worked in the past in the coal industy, particularly the permitting of underground and surface mines. I think one of the great wastes of opportunity in the past several years is the neglect to use the massive surface mine sites to create a post mining land use of pump storage resevoirs. The earth is being moved, in most cases a vertical differential of 500 to 1000 feet is available, and the industry has expertise in dam construction. However, the interrelations of the land owners, mineral owners, and coal mining companies is such that it is difficult to sell and coordinate such an endeavor.

It seems that the pump storage facilities in operation in Bath County by Dominion, Raccoon Mt. by TVA, etc. are fully utilized.
Is there a need for more pump storage? What would the combination of pump storage and increased efficiency of our power plants do for our energy production?

2 Time to Repeal New Source Review? (Up to 30 GW of coal-plant upgrades hangs in the balance) | Storm Energy Blog { 12.12.10 at 9:08 pm }

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