To hear the good and the great at Cancun, the sustainability issue of energy poverty is hidden. Occasionally, one of the climate-change grandees slips up and admits that this the real subject is wealth redistribution, not climate. But that is about as close as it gets.

All the more reason that the international forums on climate change, energy environment, and the like should get to first principles and study this map:  The World At Night (courtesy of Bert Christensen)

When you fly overnight from Johannesburg to Europe the lights thin out just north of Lusaka, Zambia, a few more in Zambia’s Copper Belt and then nothing (and I mean nothing) until the North African coastline.  For most of this 11-12 hour flight there are no artificial lights below.  From the Sahara on south, but excluding South Africa, a region that is home to more than 400 million people consumes less electricity than New York City.

The International Energy Agency has looked at the issue of energy poverty.  They conclude that for less than a 1% increase in CO₂ output everyone in the world could be connected to the modern energy economy.

UN and Energy Poverty

Recently, the UN has revisited the topic of energy and poverty as a part of its Millennium Development Goals Report for 2010.  They rely on the mostly sensible IEA suggestions:

• Move people away from traditional energy sources and toward modern fuels, especially LPG;
• Reduce the reliance on subsidies for energy consumers;
• Strive to maintain modern energy availability at affordable prices – in conjunction with the reduction in subsidies, that means cost effective modern technology to supply energy;
• Remove barriers to trade for modern energy sources; and
• Promote decentralized decisionmaking regarding supply and use of energy – i.e., use markets.

The word wind is mentioned once in this 20-page report; LPG is used 7 times.

Some People Are Catching On – Reliable Electricity is a Wonderful Thing

South Africa, one of three sub-Saharan countries with universal electrification (the others are Namibia and Botswana), supplies electricity the old fashioned way:  they burn coal for more than 90% of their electricity generation.  Nuclear and (big dam) hydro provide the rest.  Not for them the run of river hydro projects or rooftop solar collectors.

Most other countries in the region are overrun with proposals to erect wind farms, solar collectors, run of river hydro and the like.  Nothing in this approach can provide a modern economy with energy.  Pressed to sign on with renewable energy projects and incentivized by Clean Development Mechanism (CDM) revenues, the scarce human and business resources of Sub-Saharan Africa are diverted into schemes that do not produce much economic benefit for the country.

We have found elsewhere that this approach to energy does not produce the kind of electricity supply that is needed for industry.  It is fine, however, for tourists (and keeps the wages of waiters and game preserve guides quite reasonable).

For years governments and their international advisors have assumed that poor people are not willing pay for reliable energy.  They have never had a choice in the matter.  They should, it is the only way to light up that map.

Even the august Atlantic Monthly, usually a treasure trove of “correct thinking” on energy and environment, is taking a new look at what clean, reliable energy really means in developing countries.  In its most recent issue author James Fallows weighs in on how China can increase access to affordable modern energy and still reduce the country’s damaging pollution from coal-fired electricity.

In the past, or in the hands of Tom Friedman, this always leads to extoling China’s new dedication to wind and solar.  They do it, we don’t, they’re smart, we’re stupid.[i]

According to the Atlantic article, China has made extensive investments in cleaner ways to use coal – gasification and higher boiler pressures and temperatures.[ii] In fact, the country is the leading builder of coal gasification and “clean coal” power plants.  These investments will result in reduced emissions of Plain Old Pollution[iii] as well as reductions in overall fuel consumption, and hence carbon emissions, for power generation.

The math is elementary: replacing 33% efficient coal plants with generation units that achieve 45% conversion reduces fuel consumption per kWh by 27%.  The widespread deployment of these technologies for using coal more efficiently can help developing countries increase electricity output and reduce pollution.

Currently, the average Chinese consumer uses about 18% as much electricity as the average US consumer.  By using its coal resources more effectively China can continue to spread the benefits of modern energy to their huge population while mitigating environmental impacts.  Just the changeover to better technologies in the current power plant fleet in China will permit consumers to raise their per capita consumption of electricity to 25% of the US level accompanied by a reduction in emissions.

IEA, China, and Atlantic Monthly Knows, Why Don’t We?

Current approaches to electricity supply in developing countries are mostly bankrupt.  The methods tried after independence – state-owned monopoly with subsidized prices – did not work.  The state-owned companies, with a few exceptions, are mostly broke, unable to invest in new capacity and suffering serious reliability problems.

It has been noted on this blog that the US Government pointedly ignores the potential for the technologies that could lead to a dramatic reduction in emissions and fuel use in the power sector both in this country and in those that receive US foreign assistance.  Just recently US Government participation in an advanced technology coal project was cancelled.  But that cancellation is only the tip of the iceberg.

Like China, the US has a fleet of old, inefficient and dirty coal-fired plants.  It has become operationally impossible to take them out of service given their importance to baseload supplies and they cannot be rehabilitated to modern technologies cost-effectively.  Holding out a vain hope for the promise of renewables governments at all levels in the US have created increasing reliance on these old plants instead of replacing those 40 year old plants with new ones.  In fact, for a number of years cancellations of new coal-fired plants in the US  have outpaced new construction.  The cancellations are mostly due to the difficulty in obtaining approvals and permits for new coal facilities – even though these new plants would result in a dramatic net reduction in emissions.

US consumers, like most of the rest of the world, are willing to pay for reliable electricity supplies.  They are even prepared to pay to clean up the air.  Willing-buyers willing sellers; it would be a shame if we have to turn to China to restart the engineering and construction of large power plants that are at the heart of a modern economy.

The understanding that reliable, inexpensive energy is one of the most important elements of development has not been lost on China, or on the IEA, or even, apparently, on some at the UN.  Unfortunately, this wisdom has been lost on many of us in the developed world, especially those in a position to turn back the energy clock.

[ii] Usually referred to as supercritical or ultra supercritical combustion.  See Peltier for a description of the technology.

[iii] That would be ash, carbon monoxide, sulphur, trace metals and other delights.

Editor Note: Robert Peltier, Ph.D., PE, is editor-in-chief of POWER magazine. His bio is at the end of this post.

Environmental retrofits at coal plants have experienced costs greater than estimated by the Energy Information Administration. That is the bad news. The good news is:

• There are no significant technical problems with flue gas desulphurization (FGD) or selective catalytic reduction (SCR) technologies.  Utilities are not buying “serial number one” so the performance or compliance risk is negligible.  Completion risk for any project also appears to be minimal.
• The costs to construct either technology are reasonably well understood so that project capital cost estimates should be on the money.
• The cost escalation (updated below) during the boom is now subsiding.

The overall result is that the “dirtiest” power plants have been and are being cleaned up to current stringent air-emission standards via the Clean Air Act and other pollution regulation. This is real news–cleaned-up coal versus the political moniker “clean coal” (a separate issue dealing with a non-criteria air pollutant, carbon dioxide).

Background

Mary Hutzler’s excellent summary of the significant emissions reductions achieved by the electric utility industry (The Facts About Air Quality and Coal-Fired Power Plants, June 1) should be required reading by any proponent of coal-fired power generation. I have used the statistics cited for “criteria pollutants” in many public presentations, and few present were aware of this great “untold success story.”

One topic Hutzler succinctly reviewed was the background of the 1990 Clean Air Act and its evolution through the Acid Rain Program and up to the Clean Air Interstate Rule (CAIR), which requires significant reductions of NOx and SO2 from 21 states and the District of Columbia. Regardless of CAIR’s current legal status, many utilities can’t avoid similar air emissions reductions because they are either under a consent decree or have state emission limits to meet. Regardless, utilities otherwise covered by CAIR are moving ahead with the installation of flue gas desulphurization (FGD) and selective catalytic reduction (SCR) systems at a brisk rate.

An excellent example of the significant investment many utilities have made over the past decade is American Electric Power (AEP), one of the largest public utilities in the U.S. with 39,000 MW of installed capacity with 69% of that capacity coal-fired. AEP is under a New Source Review (NSR) consent decree signed in 2007 that requires the utility install air quality control systems to reduce NOx by 90% and SO2 by at least 95% on selected coal-fired plant in their system (reference). AEP’s total capital investment in systems to improve air quality is $5.2 billion spread over several years, $1.0 billion for 2009-2010 alone (reference).

The estimated cost to install either an FGD or an SCR system has risen steadily over the past few years making the familiar cost estimates obsolete. Hutzler reports the EIA estimates for a typical 700 MW plant in 2006 dollars as $98/kW for an SCR with 90% NOx removal and $190/kW for a FGD that removes 95% of the SO2 in the stack gas. Both removal rates are typical specifications used in the power industry. However, the cost estimates are long-outdated and should no longer be cited.

One more current data set is the historic capital costs reported by AEP averaged over several years and dozens of completed projects. For example, AEP reports that their historic average capital costs for SCR systems are $162/kW for 85% to 93% NOx removal—65% higher than the EIA estimates. Also, AEP’s FGD systems were installed at an average of $262/kW for 95% to 98% SO2 removal or 38% higher than the EIA estimate (reference).

What’s a Utility to Do?

So what are the actual costs a utility should expect when estimating the cost of installing an SCR and/or FGD system? Public benchmarking data sets are few and far between and those in existence are usually maintained and marketed by consulting firms that are in business to make a profit.

A better option for obtaining good estimates of the installed cost of an SCR or FGD system is the benchmarking data collected by the EUCG, an association of electric utility professionals that provides a forum in which utilities can improve their operation and maintenance practices and construction performance. One of the EUCG’s key activities is developing process and market benchmarks, unit reliability strategies, and best-practice applications to foster performance and cost excellence within the utility industry and competitive markets.

The EUCG’s Fossil Productivity Committee has more than 40 electric utility members reporting operating data on more than 300 individual coal-fired units. That number represents more than 30% of operating coal plants in the U.S. therefore making that dataset perhaps the most robust benchmarking data on coal-fired plants available anywhere. However, the complete datasets are only available to member utilities and those utilities that participate in the surveys. POWER magazine has been privileged to have access to those data sets and permission to publish top-level results from those surveys.

The following two sections present the reported historical costs of SCR and FGD systems based on the EUCG datasets. In sum, the EUCG historical data finds the installed cost of an SCR system of the 700MW-class as approximately $125/kW over 22 units with a maximum reported cost of $221/kW in 2004 dollars. This data was reported prior to the dramatic increase in commodity prices of 14% per year average experienced from 2004 to 2006 (from the FGD survey results). Applying those annual increases to the 2004 estimates for three years (from the date of the survey to the end of 2007) produces an average SCR system installed cost of $185/kW. Also, the average installed cost of a typical 700MW-class FGD system was reported in the EUCG survey as $380 for units under construction in 2007. Both historical installed costs reported in these two EUCG surveys far exceed the outdated and extremely optimistic estimates developed and reported by the EIA.

I. The Real Cost of Installing an SCR

Our first benchmarking survey (data reported in 2005, first published in 2006) focused on SCR system installation costs and the project and design attributes that contribute to them. Specifically, it identified the costs of construction labor, equipment, materials, and project management-engineering-construction management (PMEC). The survey addressed 11 specific scope/design unit attributes such as the type of ammonia system used, the NO_x-removal efficiency design basis of the system, and SCR-related plant upgrades (economizer, air heater, fans, etc.) on a $/kW basis.

The responses to the survey yielded scope, cost, and design information on 72 individual units totaling 41 GW (representing 39% of installed SCR systems in the U.S. by MW at the time of the study) owned by eight large utilities from SIP Call states. They included Southern Company, Duke, TVA, Progress Energy, Constellation Energy, Ameren, Ontario Hydro, and AEP. The sample also reflected the distribution of installations in the U.S., so the survey results can be considered a valid top-level view of system costs.

Economies of Scale

As Figure 1 shows, although almost three-fourths of the surveyed units have a capacity of 300 to 900 MW, together they represent only a little over half the total capacity studied. Overall, costs were reported to be in the $100 to $200/kW range for the majority of the systems (Figure 2), with only three reported installations exceeding $200/kW. System size (with a 644-MW average unit size in the $100 to $150/kW range) seems to dominate; larger average system costs are significantly less than the next survey category (the $150 to $200/kW range, with a 309-MW average unit size). The data also suggest that the larger units were installed earlier: the average unit size retrofit before 2003 was 623 MW, vs. 466 MW since 2003.

1. SCR cost survey results, categorized by plant size, covered approximately 39% of the new SCR capacity installed through early 2004. Source: EUCG as published in POWER

2. Number of units surveyed by average cost category. Source: EUCG as published in POWER

The range of category costs by unit size ($/kW) provides insight into SCR projects’ relative complexities. For example, the aggregated reported costs in the defined categories (Figure 3) point to several conclusions:

· The cost of construction labor on smaller projects exceeds the average construction labor cost in all categories by about 50%. The implication is that small plants will be cost-penalized by their lack of economies of scale because they may be more difficult to retrofit.

· Construction labor costs were relatively constant for plants larger than 300 MW, with an average cost of just over $64/kW.

· As expected, economies of scale also impact SCR material costs, with larger units costing less to retrofit, on a $/kW basis, than smaller units.

· Sophisticated regression modeling techniques (multivariate analysis) generally did not do a very good job of predicting overall installed costs; too many site-specific variables impact construction costs.

· PMEC costs are relatively consistent regardless of unit size.

3. Cost distribution for 72 units with SCR installed by survey size range. Source: EUCG as published in POWER

The Good Old Days

The survey data also revealed that deviations from average installation costs correlate strongly with project timing, especially for those units installed after 2003 (Figure 4). The significantly higher construction labor costs for later projects most likely reflect increased project complexity—“easier” projects were already completed—but also perhaps increased competition for skilled labor resources as the number of SCR installation projects underway in the U.S. skyrocketed.

4. Deviation of category costs as a function of project completion date. Source: EUCG, POWER

Interestingly, the variation in material costs was constant over the survey period, most likely reflecting increased competitiveness among SCR suppliers. By contrast, PMEC costs showed higher variability, which—as in the case of construction labor costs—reflected the greater complexity of later projects. Average cost variation by cost category is summarized in Table 1.

Table 1. Variation of surveyed cost categories by unit size. Source: EUCG as published in POWER

One Survey, Many Conclusions

Although the survey results provide useful insight into expected installed costs, they also confirm that there is no “one size fits all” SCR design. What the data also make clear is that site-specific characteristics of units and plants can drive a project’s cost much higher than anticipated. Together, these conclusions suggest that “retrofit difficulty” is indeed relative. Units with a capacity of 600 to 900 MW appear to experience more retrofit difficulty than those in other size ranges.

Since SCRs are unitized, greater economies of scale were expected from the survey results. Some possible explanations include:

· The impact of newer plants’ tighter layouts, which often necessitate much more complex duct installations, raising costs).

· Plants’ limited ability to use the most cost-effective method of equipment transportation. Some 41% of the units surveyed in the 600- to 900-MW range are close to navigable waters, vs. 76% of units larger than 900 MW.

· The increasingly modular design of SCR systems, which reduces their capital costs but still requires them to be delivered by sea or river.

II. The Real Cost of Installing an FGD System

Flue gas desulfurization (FGD) projects continue to be the largest line item for many utility construction budgets. The technology is sound, so the operational risks have decreased remarkably over the past decade. What remains, however, is the risk of project overruns caused primarily by rapidly rising commodity prices. In this 2007 survey (for which data were collected in 2006) we found that the base cost of an FGD system was $319/kW averaged over 49 separate projects. That was an increase of 21% since the previous survey was completed in 2005.

Survey Background

The data for the current survey were collected during the period December 2007 through June 2008 and then presented to the Fossil Productivity Committee (FPC) at the EUCG fall meeting in late 2008. There are important differences between the two surveys. First, the number of utility participants remained the same, at an even dozen, although there were four new participants. The survey continues to cover an excellent cross-section of coal-fired utility plants involved in FGD retrofits (Figure 5).

5. New survey update. The 2008 EUCG FGD cost survey includes 78 units total 41 GW. Source: EUCG as published in POWER

The 2008 survey covered more than 41 GW and 78 scrubbed units and represent the largest FGD data set analyzed in the industry. The average unit size in this survey was 956 MW, down slightly from 1,019 MW in the 2007 survey.

The survey data reflect the wide variety of plants, locations, and fuels used in this industry. The survey also covered a nice range of FGD system start-up dates (Figure 6). Nearly 50% of forecasted in-service dates were 2009 and 2010, the average start-up date is 2010, and the latest is 2015. As the reported start-up dates are in the near future, we have high confidence in the final construction cost estimates, which reinforces the usefulness of the data. We have included results from the 2007 survey in the figures to illustrate recent industry cost trends for FGD systems.

6.    Latest cost data. The majority of the survey data come from scrubbers that were recently installed or are currently under construction. Source: EUCG as published in POWER

System design characteristics and assumptions for units covered in the current survey were not unlike those in the 2007 survey and are summarized below:

· All the surveyed facilities are using limestone forced oxidation technology.

· Tower technology selection varies by site, although more than half of the units still prefer spray technology (Figure 7).

· The FGD average sulfur dioxide removal design basis selected by respondents remained in the range of 4.0 to 4.9 lb/mmBtu, although the number of respondents reporting the mean value almost doubled (Figure 8).

· Sixty percent of the respondents stated that their design includes a single stack/double flue configuration; another 29% specified a single stack/single flue design. These results are very similar to the 2007 survey data.

· There was more agreement with the flue material selection. In 79% (70% in 2007) of surveyed plants the flue is fiberglass resin; 12% (14% in 2007) selected an alloy steel or C-276 clad flue.

· For FGD waste disposal, 60% (53% in 2007) of respondents are using an old or new landfill; slightly fewer (26%) are recycling at a wallboard plant (35% in 2007).

· Reagent prep delivery is mostly by truck (57%); the remainder use rail (24%) and marine vessel (17%). These results are within a few percentage points of the 2007 survey results.

7.    Make your choice. Although all of the FGD units reported on in the current survey were of the limestone forced oxidation technology, almost two-thirds were of the spray type, and a third were jet bubbling reactors. Source: EUCG as published in POWER

8.    Capture the SO₂. The average FGD SO₂ removal design point is about 4.5 lb of SO₂ removed per million Btu of fuel consumed. Source: EUCG as published in POWER

Cost Survey Results

Average total installed costs reported by the survey respondents were expected to have wide variation, principally because of the peculiarities that exist at each project site, the retrofit project complexity, and the timing differences between projects. Therefore, defining an average project cost is difficult without some understanding of the project-specific details of each of the 78 units surveyed. A look at the summary or “fully loaded” installed costs clearly shows that costs continue to rise (Figure 9) and continue to stay consistently above $300/kW. The data clearly show there are economies of scale for larger plants, but they are not as pronounced as you might expect.

9.    Big bucks. “Fully loaded” FGD system capital costs were reported by unit rating and show a significant increase since the previous survey. Source: EUCG as published in POWER

The survey data go into much more detail, although the in-depth data are restricted to those that participated in the survey. However, we can take one more step and strip out the FGD-only costs from the installed cost data to evaluate system-only cost changes since the 2007 survey.

The survey instructions requested that respondents define project costs for their just-completed, current, under construction, and/or planned FGD projects and that they include the following line items, at a minimum, so that comparable data were reported that could be compared across projects:

· Project design costs

· New stack and ductwork costs

· Reagent prep method and costs

· Absorber island/reactor technology costs

· Site prep costs

· Wastewater treatment costs

· Balance-of-plant costs

· Other direct costs (such as engineering and project management)

· Associated boiler work (such as boiler modifications and draft fans)

Comparing these costs to the “FGD only” cost summary, we begin to see some of the economies of scale expected for projects of this size, although they are not as pronounced as might be expected (Figure 10). The FGD-only costs were calculated as the sum of the FGD absorber reactor costs, reagent preparation system costs, the FGD waste disposal system costs, and the balance-of-plant cost. Stacks, site preparation, wastewater systems, and other project costs for boiler cleaning systems, coal blending or major electrical upgrades are excluded. This definition was refined before the current survey in order to obtain better cost data for the different cost categories.

10.    Costs have risen. Significant cost increases have occurred for “FGD system only” capital costs, yet the economies of scale do not seem to apply for units 600 MW and larger. Source: EUCG as published in POWER

Total project costs reported in the 2008 survey were approximately 28% higher than those reported in the 2007 survey (which used data from late 2006), representing an average annual escalation rate of 14%. The data also show a project cost escalation rate from 2006 to 2007 of approximately 22%. This number may seem large, but it is very similar to escalation rates for other major utility projects during the same period. Also, the 2008 survey shows essentially no difference in fully loaded project costs from conceptual design through start-up (Figure 11). The conclusion we draw is that FGD project installed costs may be rising significantly, but costs have become more predictable.

11.    Reach for the sky. In the 2007 survey, “fully loaded” FGD system costs were much higher for preliminary engineering than for later phases and already completed FGD projects. The 2008 survey shows fully loaded costs to be very flat and independent of project phase. Source: EUCG as published in POWER

——————————————-

Robert Peltier began his power industry career with the regulated utility, San Diego Gas & Electric Co., the unregulated power developer Energy Factors, and gas turbine supplier, Solar Turbines, Inc and later was manager of production engineering Stewart & Stevenson’s Gas Turbine Division (now part of General Electric).

Dr. Peltier was also a tenured professor at Arizona State University for eight years where he taught numerous power generation-related courses. In 1999, Captain Peltier was recalled to active duty in the United States Navy to serve in Washington, D.C. on the staff of the Naval Sea Systems Command. He left active duty in September 2002 and completed two major command tours before retiring from the Navy Reserve in January 2007.  Bob also joined POWER magazine’s editorial staff as senior editor in September 2002 and was named Editor-in-Chief of POWER on April 1, 2003.

Peltier has a BS, MS and Ph.D. in mechanical engineering and is a registered engineer in California and Arizona.

Air quality from America’s coal plants have been improving for decades, even before Congress passed the Clean Air Act of 1970. And since 1970, the six so-called criteria pollutants have declined significantly overall and in the generation of electricity, even though coal-fired generation has increased by more than 180 percent.[i] (The “criteria pollutants”—those for which the EPA has set criteria for permissable levels—are carbon monoxide, lead, sulfur dioxide [SO2], nitrogen oxides [NOx], ground-level ozone, and particulate matter [PM]).

Specifically, total SO₂ emissions from coal-fired plants were reduced by about 40 percent between 1970 and 2006, and NO_x emissions were reduced by almost 50 percent between 1980 and 2006. On an output basis, the percent reduction is even greater, with SO₂ emissions (in pounds per megawatt-hour) almost 80 percent lower, and NO_x emissions 70 percent lower.

The figure below shows the increases in Gross Domestic Product, vehicle miles traveled, energy consumption, and population since 1980, and compares them to the decline in the aggregate emissions of criteria pollutants. Today, we produce more energy, drive further, and live more comfortably than we did in the past, all the while enjoying a cleaner environment.

EPA’s Comparison of Air Quality, Emissions, and Societal Trend

One factor in improving air quality has been the pollution-control technologies used by coal-fired power plants. Today’s coal-fired electricity generating plants produce more power, with less emission of criteria pollutants, than ever before. According to the National Energy Technology Laboratory (NETL), a new pulverized coal plant (operating at lower, “subcritical” temperatures and pressures) reduces the emission of NO_x by 86 percent, SO₂ by 98 percent, and particulate matter (PM) by 99.8 percent, as compared with a similar plant having no pollution controls. Undoubtedly, air quality will continue to improve in the future because of improved technology.

Today, coal-fired electricity generation produces nearly half of the electricity generation in America and is job- and “shovel” ready. For example, Prairie State Energy Campus, a 1,600-megawatt coal plant under construction in southern Illinois, provides 1,200 people with jobs in around-the-clock construction. Between its power plant, coal mine, and other assets, the campus will inject some $2.8 billion into the Illinois economy, creating 2,300 to 2,500 temporary construction jobs and 500 permanent positions, while emitting 80 percent less in pollutants than most existing power plants.  When completed, the power plant will deliver electricity to 2.4 million homes in at least nine states.

Cap & Trade and Criteria Pollutant Reduction (1990 CAA)

The Clean Air Act, last modified in 1990, requires the Environmental Protection Agency (EPA) to set National Ambient Air Quality Standards to control pollutants considered harmful to public health or the environment: the so-called criteria pollutants. Two of these pollutants, SO₂ and NO_x are the principal pollutants that cause acid precipitation (colloquially known as acid rain). SO₂ and NO_x emissions react with water vapor and other chemicals in the air to form acids that fall back to earth. Criteria pollutants are localized emissions, so controlling for them produces better air quality to the local community; the situation is very different when controlling for global emissions, such as carbon dioxide and other greenhouse gases.

The 1990 changes to the Clean Air Act introduced a permanent cap on the total amount of SO₂ emissions that may be emitted by electric power plants nationwide, thereby reducing the level of these emissions in the atmosphere. The approach used was a cap-and-trade program with a steadily declining cap through 2010. In order to comply with the Clean Air Act Amendments of 1990, electric utilities could either switch to low-sulfur coal, add commercially available equipment (e.g., scrubbers) to existing coal-fired power plants to remove SO₂ emissions, purchase permits from other utilities that exceeded the reductions needed to comply with the cap, or use any other means of reducing emissions below the cap, such as operating high-sulfur units at a lower capacity utilization.

EPA also issues air pollution control standards, called New Source Performance Standards (NSPS) to which new plants must adhere. EPA’s current NSPS require all power plants for which construction commenced after February 28, 2005 to not exceed 1.0 lb/megawatt hour (0.11 lb/million Btu) of NOx, 1.4 lb/megawatt hour (0.15 lb/million Btu) of SO2, and 0.14 lb/megawatt hour (0.015 lb/million Btu) of particulate matter (PM). However, most new plants are built to even more stringent criteria. A study by the National Energy Technology Laboratory (NETL) compared the emission rates from pulverized coal plants and integrated gasification combined cycle plants based on the environmental regulations that would apply to plants built in 2010 using technology designs from several vendors. The rates range from .0105 to .0848 lbs/million Btu for SO₂, .055 to .07 lbs/million Btu for NO_x, and .0071 to .013 lbs/million Btu for PM, depending on technology type. They are 43 to 93 percent lower than the current NSPS for SO₂, 36 to 50 percent lower than the current NSPS for NO_x, and 13 to 53 percent lower than the current NSPS for PM. According to NETL, for a new pulverized coal plant (subcritical) built in 2008, pollution controls reduce NO_x emissions 86 percent, SO₂ emissions by 98 percent, and PM by 99.8 percent when compared with a similar plant with no pollution controls [ii].

The figure below graphically depicts the criteria pollutants from a new controlled plant vs. those from a new uncontrolled plant. NETL estimates that for a pulverized subcritical coal plant, the equipment to control NO_x, SO₂, and PM comprises $324/kW of the $1,549/kW plant cost (21 percent).

Note that the success of this program was principally due to the availability of cost-effective technology that could be added to existing as well as new power plants and to the America’s vast resources of low sulfur coal, principally in the Powder River Basin, that could be cost-effectively transported by unit trains to power plants across the nation.

Cap & Trade and Global GHG Emissions

The results of using a cap-and-trade system to fight “acid rain” have led some to argue that it is a model for efforts to reduce carbon dioxide emissions. However, stark differences exist between the “acid rain” emission-reduction program and the challenge of reducing carbon dioxide, a natural byproduct of combustion, emitted by natural and man-made sources.

Carbon dioxide is emitted by hundreds of millions of sources, including personal automobiles, the appliances used to cook our food and heat our homes, and the businesses upon which we depend for our livelihoods, to name just a few. The “acid rain” emission reduction program was initially limited to 110 site-specific utility plants, and then later expanded to 445 plants. In addition, carbon dioxide is a world-wide byproduct of combustion, whereas all criteria pollutants are local or regional. In other words, what the United States did for SO₂ and NO_x directly affected air quality here, while national action to limit carbon dioxide emissions will have little bearing on aggregate global greenhouse gas emissions.

Furthermore, at the time of the SO₂ and NO_x reduction program, alternative low-sulfur coal sources existed and utilities had available, affordable, and proven technologies to reduce their criteria emissions. When Congress passed the Clean Air Act Amendments of 1990, therefore, coal-fired utilities could responsibly reduce emissions from their plants using various options that limited cost impacts to the consumer.

In addition, attempts to extrapolate the “acid rain” success story to the challenge of reducing carbon dioxide emissions fail to recognize the history of similar programs in other parts of the world. For example, the “Emissions Trading Scheme” of the European Union has been ineffective at reducing carbon dioxide emissions and at the same time it has increased prices and harmed businesses and consumers. Further, the EU program has enriched some companies and industries at the expense of consumers.

A recent study by Laurie Williams and Allen Zabel, career employees of the Environmental Protection Agency, makes these points about what the authors call the “Acid Rain Myth.”  As the authors explain, those who champion the use of cap-and-trade to address global warming ignore the crucial distinctions between the issues the U.S. faced in 1990 with acid rain and the issues faced today with global warming.

The following highlights Williams and Zabel’s study demonstrate that the experience of the acid rain program cannot and should not be compared to cap and trade for greenhouse gas emissions:

• “Most importantly, the success of the Acid Rain program did not depend on replacing the vast majority of our existing energy infrastructure with new infrastructure in a relatively short time. Nor did it depend on spurring major innovation. Rather, the Acid Rain program was successful as a mechanism to guide existing facilities to undertake a fuel switch to a readily available substitute, the low sulfur coal in Wyoming’s Powder River Basin.”
• “The goal of the Acid Rain program was to reduce sulfur dioxide emissions, while keeping the cost of energy from coal low. To be effective, climate change legislation must do the opposite; it must gradually increase the relative price of energy from coal and other fossil fuels to create the appropriate incentives for both conservation and the scale-up of clean energy.”
• “Further, the Acid Rain program did not allow any outside offsets and so provides no basis for the widespread assumption that an offset program will help with climate change. In addition, the success of the program was aided by the low, competitive price of low-sulfur coal.”
• “According to Professor Don Munton, author of ‘Dispelling the Myths of the Acid Rain Story’ the impact of the program has been overstated: The potential for a massive switch to low sulfur coal was no secret. Such coal was cheap and available, and it became cheaper and more available throughout the 1980s. Indeed, low-sulfur coal became very competitive with high-sulfur supplied well before the Clean Air Act became law.”

In short, the mechanisms available to reduce pollutants allowed for more generation of energy with less pollution. But this success cannot be extrapolated to the regulation and reduction of carbon dioxide, a much more challenging undertaking. None of the conditions existing at the time of the apparent success of the SO₂ and NO_x reduction program apply to carbon dioxide. Unilateral action by the United States will have little impact upon global carbon dioxide concentrations. The challenges presented by the control and regulation of carbon dioxide have no parallels in the history of emission regulation.

---

[i] Air quality was improving before 1970, even before Congress created the Environmental Protection Agency in 1970 and passed the Clean Air Act Amendments of 1970.

[ii] Email from J. Kukielka ,NETL to M. Hutzler, IER, January 9, 2009.