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 17^th 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.

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.

Conclusion

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.

Acknowledgement

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

The most interesting story for 2010 is that the dash for gas in the U.S. has begun–again. In Part II or this two-part report, we will explore the challenges facing nuclear, coal, and renewable energy electricity sources in 2010 and beyond.

Business Climate–Energy Demand

As we enter the second decade of the 21st century and a second year of avoiding an economic collapse, the U.S. business climate seems to have become more positive. A growing sense of cautious optimism is appearing. A mid-October survey by the National Association for Business Economics concluded that the largest recession since the 1930s Great Depression is over, and economic growth is likely for the U.S. economy in 2010. The government announced that third-quarter 2009 economic growth hit 3.5%, the first positive growth in five quarters, suggesting an end to the recession (Figure 1).

Figure 1. Electricity growth resumes in 2010. After a two-year contracting market, total electricity consumption in the U.S. in 2010 is expected to increase. Source: EIA, November 2009 Short-Term Energy Outlook

The implications for electric generation are mixed. What gets built depends on a complex stew of credit markets, regulatory responses, economic growth, technology, and national politics. Some of those are leading economic indicators, some lagging, some not clear at all.

Renewable generation has not made a convincing economic case in the market. But politically it has the upper hand. Coal and nuclear continue to take a political battering at the hands of the renewables advocates. The politics of energy is being upended by new implications for natural gas. The political and regulatory landscape is a dog’s dinner (a Britishism for an undigested mess).

The need for new generation to supply load appears less urgent than in previous years. According to the EIA, demand for electricity has fallen since the economy tanked in 2008. The demand down-tick is the first since the EIA has accumulated these statistics in 1977.

Facing a sluggish economy, consumers have reduced thermostats, cut off air conditioning, and dialed down appliances, leading to the decline in electricity demand. A cool 2009 summer in most of the U.S. helped to reduce air conditioning load. Net electric generation dropped 6.8% from June 2008 to June 2009. That was the 11th consecutive month that electric generation slid downward, compared to the same month in the prior year.

Analysts say they expect the declining demand trend to reverse when economic growth shows up at the beginning of 2010 or thereabouts. But they have been wrong before and may be wrong again. The EIA, the U.S. Department of Energy’s statistical agency, says it suspects the decline in demand will continue into early 2010, despite what appears to be a bottoming-out of the recession.

Many electric power company long-term capital spending plans have been built on the dire forecasts of the past decade, particularly from NERC. For years, the conventional wisdom in the generating industry was that the U.S. was running out of generating capacity. Year after year NERC had the same message: It’s time to build baseload, particularly nuclear and coal, and make major investments in high-voltage transmission.

Maybe not. Intermediate-load and peaking units, suggesting new gas plants, may be the ways to hedge big investment bets on future baseload units. A recent Washington Post article quoted anonymous sources as saying that new nuclear plants aren’t economical until natural gas prices are above $7/mmBtu. That’s more than double the current price.

The urgency for long-distance, high-voltage electric transmission investment, premised on optimistic estimates of growth in demand, also seems to have declined. Capital requirements for the big transmission projects, along with the political risks, have scared off investors, including conventional utilities and free-standing investment companies. Those who want to build large transmission systems linking areas of surplus power generation (West Virginia, for example) to big markets in New Jersey and New York are facing not only citizen opposition but also indifference from Wall Street investors, who don’t see an acceptable market return on investment (Figure 2).

Figure 2. New transmission is key in future years. The North American Electric Reliability Corp. predicts that expanding critical transmission capacity will be a national priority over the next five years. Source: NERC

The bullish generating market in late 2008—despite signals of a worldwide economic crisis—turned into a financial quagmire. Today, lenders are unwilling to pony up cash for new generation and transmission without guaranteed returns, regulators are reluctant to bless projects without iron-clad promises of stable prices, and customers are unwilling to support new projects that threaten rate hikes and environmental impairment. Governments at the federal and state level are demonstrating distinct ambiguity about generation and transmission projects.

Where does that land us? Overall, the generating market has slowed. Raising credit has become difficult for major projects of any kind, from new nuclear reactors to petroleum refineries to coal mines. Money wasn’t a problem a decade ago. Today, it’s a big problem. Tomorrow, meaning 2010 and beyond, that may change. But don’t bet the company. It’s a jungle out there.

The Political Environment for Power

After a year with a new political crew in Washington—Democrats in the White House and controlling both the House and Senate—how has the political landscape for electric generation changed? It’s not clear. Democrats have said they want substantial reforms in the way the nation addresses energy, including the alleged specter of climate change. The party, including the Obama administration, is pushing legislation in Congress that appears unlikely to be enacted this year.

Complicating the administration’s policy agenda, the political clock has already started ticking toward the 2010 mid-term elections, when all of the U.S. House and a third of the Senate seats are up for election. Traditionally, the party in power loses seats in off-year elections. The Obama administration likely will take heroic steps to prevent that outcome, particularly to ward off losing the Democrats’ 60-40 margin in the Senate, where it takes 60 votes to avoid a filibuster. Ducking a filibuster is a prerequisite for passing Senate legislation in these days of total partisan warfare.

In that context, what has changed since 2009 when it comes to energy legislation and the economic prospects for energy development? Paradoxically, very little. The administration promised new directions in energy, with an emphasis on controlling greenhouse gas emissions and increasing energy efficiency, without much in the way of specifics. The Obama administration attempted to create a dramatic picture of how it differed from the Bush administration. The optics succeeded, but the reality is far less than meets the eye.

The Obama administration’s position on energy legislation is not very different from that of its predecessor. Both offered generalities and platitudes but not much practical red meat. The current administration has largely stayed away from the legislative details of climate legislation (as it has done with health care). The House passed a cap-and-trade bill (Waxman-Markey) that takes the approach that if the policy causes you any pain, we will pay to make you feel better. Republicans correctly call the House bill “pork” but have had nothing to offer in response.

The Senate Environment and Public Works Committee bill is not much different than the House-passed measure and leaves many details to be fleshed out in markup in the committee, chaired by California Democrat Barbara Boxer, an enthusiast for measures to control greenhouse gas emissions. Republicans have indicated that they will be unanimous in attempting to block the bill. The GOP may be able to pick a few Democrats to oppose the Boxer bill, dooming the legislation. In November, the Democrats reported out the committee bill, without Republican participation, as the GOP boycotted the committee markup session. That does not bode well for legislation anytime soon.

The Senate Energy and Natural Resources Committee, chaired by New Mexico Democrat Jeff Bingaman will also have a powerful legislative and political oar to dip into energy policy waters. Bingaman’s state is a major producer of coal, natural gas, and uranium, but it is a minor state when it comes to electricity production. How he will approach the greenhouse gas issues is not clear.

Four more Senate committees will have a say in the final legislation. Energy politics tend to be regional, not ideological, as both parties are prepared to spend taxpayer dollars for fuels and technologies that touch their constituents.

The legislative fight could carry deep into 2010 without resolution.

Record Gas Reserves Discovered

“Holy cow, there’s a lot of gas.”

That was the reaction of Penn State geologist Terry Englander, as reported in the Massachusetts Institute of Technology’s Technology Review last October. Three years ago, Englander was asked to assess the natural gas potential of Marcellus shale deposits in the U.S. Midwest and Mid-Atlantic regions. It now appears that deep shale beds—the Carboniferous (350 million years ago) Barnett shale deposits in the Texas and the enormous Devonian (400 million years ago) Marcellus shale deposits in the East—could be game-changers in the U.S. energy and power generation markets for years to come.

Shale formed in those deposits contained methane bound so tightly into the rock formations that conventional drilling technology could not get at it, according to the geologists. That’s changed. Deep drilling, horizontal drilling, and hydraulic fracturing (pumping water down the borehole at great pressures to shatter the shale strata, releasing the methane from the rock) make the gas accessible. Both shale finds are providing drillers with gas bonanzas.

Last June, the U.S. Potential Gas Committee (PGC) issued a report that estimated total U.S. natural gas reserves at over 1,800 trillion cubic feet, the highest in the committee’s 44-year history, and 40% above its 2006 estimate. John Curtis of the Colorado School of Mines, head of the PGC, said that the estimate “reaffirms the committee’s conviction that abundant, recoverable natural gas resources exist within our borders, both onshore and offshore, in all types of reservoirs.” Prices fell, reflecting the optimistic supply predictions. Exploration in shale deposits continued growing.

The PGC is an independent, industry-funded technical group that examines natural gas reserves in the U.S. Said Curtis, “Our knowledge of the geological endowment of technically recoverable gas continues to improve with each assessment. Furthermore, new and advanced exploration, well drilling, and completion technologies are allowing us increasingly better access to domestic gas resources—especially ‘unconventional’ gas—which, not all that long ago, were considered impractical or uneconomical to pursue.” That’s a reference to shale gas, as well as gas in deep deposits.

Significantly, the shale gas deposits are close to, and in some cases, directly underneath, natural gas pipelines and gathering hubs and near large markets. Bringing the gas to market could be easy and cheap.

In a press release, the PGC noted, “When the PGC’s results are combined with the U.S. Department of Energy’s latest available determination of proved gas reserves, 238 Tcf [trillion cubic feet] as of year-end 2007, the United States has a total available future supply of 2,074 Tcf, an increase of 542 Tcf over the previous evaluation.”

That’s a stunning figure—an increase of over 25% above previous estimates. The Energy Information Administration (EIA) defines “proved reserves” as “those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.” In other words, they are real.

The supply optimism is good news for existing and potential electric generators, as the projections, bolstered by successful drilling in shale, have resulted in dramatically lower natural gas prices. The most recent reports from the EIA found natural gas prices at the Henry Hub at $2.76 per million Btu (mmBtu). Futures prices at the New York Mercantile Exchange for September 2009 contracts were at $2.91 per mmBtu. A couple of years ago, the NYMEX price was in the $9 range for short forward contracts (Figure 3).

Figure 3. Gas prices expected to stabilize in 2010. The U.S. Energy Information Administration (EIA) predicts natural gas prices will fluctuate less and be more predictable in the future given the significant increase in gas reserves. Source: EIA November 2009 Short-Term Energy Outlook

Say Goodbye, LNG?

Among the implications of the optimism about shale gas recovery in the U.S. is a crash landing for plans to build imported liquefied natural gas (LNG) terminals in the U.S. Three years ago, LNG was the rage of the age, with predictions of terminals across the coastal U.S. Daniel Yergin’s Cambridge Energy Research Associates (CERA) was bullish on LNG, predicting a worldwide LNG boom.

No longer. No recent publicly available material on LNG has shown up on the CERA web site, although there was reporting available to paying customers (the price tag is very high). Could the consultancy’s enthusiasm for LNG have cooled considerably on current and projected natural gas prices? The guess here is that it has.

On the other hand, CERA’s web site now touts shale gas, saying, “Some call it a revolution,” adding that shale gas “could change the global natural gas balance.”

To date, according to the Federal Energy Regulatory Commission (FERC), four new LNG terminals are under construction in the U.S., with just under 4 billion cubic feet of gas capacity. Three of the four are in the Southeast or Southwest, where they serve petrochemical plants. FERC has approved another 14 LNG projects for the U.S., but analysts expect few of those will actually see the light.

Summarizing its most recent data, the Energy Information Administration (EIA) said, “In 2008, increased U.S. natural gas production led to reduced demand for natural gas imports. The drop in total imports occurred despite a 2007-to-2008 increase in domestic consumption—a factor that typically requires higher levels of imports to meet consumer demand. Total exports to Mexico and Canada via pipeline and Japan via LNG tanker were higher in 2008. Consequently, net imports to the United States fell more than 20 percent from 2007 totals to the lowest level since 1997. The decline in U.S. natural gas imports had a larger impact on LNG imports than Canadian pipeline imports. Given the ease of transporting gas to alternative markets, some LNG that historically landed in the United States went elsewhere in 2008.”

The EIA went on to say that “The increased supply of LNG brought about by the start-up of several large LNG supply projects in late-2009 and in 2010 contributes to an increase in the outlook for U.S. LNG imports next year. However, the timing of these new liquefaction additions is extremely difficult to judge.”

Favorite Power Generation Fuel Returns

For 2010, gas sees its prospects gaining in the power market, bolstered by new technology and large new supplies. The leader of the generating pack in the 1980s and early 1990s, gas went into a deep decline on high prices and diminishing reserves in the first part of the 21st century. Many analysts said the days of gas as a major generating fuel were over.

No more. Given that gas is less polluting than coal (by any measure), produces half as much carbon dioxide (CO2) per unit of energy output, and requires plants that are quick to build and not capital-intensive, new gas reserves appear to position the fuel as a winner in generating markets. The U.S., once seen as a declining gas producer, may be a world leader in gas.

In November, The Energy Daily reported that the North American Electric Reliability Corp. (NERC) has found that “Electric utilities are increasingly showing an ‘overwhelming’ preference for building natural gas–fueled plants, a trend that is expected to drive gas past coal as the dominant North American fuel for on-peak power production by 2011.” According to the newsletter, “NERC said both regulated utilities and merchant generators are increasingly favoring gas plants because the fuel has been discovered in more abundance and is cheaper than in the past. In addition, gas plants are easy to site, can be built quickly and produce less carbon emissions than other types of traditional generation.”

This overabundance of natural gas reserves may also have a downside, according to a report released by NERC on October 29. NERC’s “2009 Long-Term Reliability Assessment 2009–2018” report notes that natural gas–fired on-peak power production may push past coal-fired generation by 2011, portending system reliability problems. NERC also cited cyber-security concerns, the integration of fast-growing renewable resources into the grid, and uncertainties created by the economic slowdown as emerging reliability worries that it faces (Figure 4).

Figure 4. Demand for electricity will rise in 2010. The top figure describes the expected growth of capacity that will be available during peak hours. The bottom figure describes the expected growth of installed capacity. Coal and gas will continue to be the fuels of choice during peak generating hours. Wind generation will continue to grow faster than any other but will contribute little to peak supplies. Source: NERC

NERC recognized that existing reserve margins are adequate across the U.S. for the next few years, but the first priority must be to expand the grid and increase the capacity of existing transmission and distribution systems to handle the expected growth of renewable generation. The report concluded, “More than 11,000 miles (or 35%) of transmission (200 kV and above) proposed and projected in this report must be developed on time to ensure reliability over the next 5 years. 32,000 miles of transmission (200 kV and above) are projected for construction from 2009 to 2013 overall.” NERC strongly believes that transmission siting and construction is the most urgent issue for the power generation industry, now and well into the future.

Electricity growth has stalled over the past two years, given the chaos in the global economy. However, NERC projects that demand will increased 15% between 2009 and 2018, compared to its 17% forecast in last year’s report. The projected demand increase has steadily decreased over the past several years. Once again, NERC underlined the need for grid expansion and new transmission capacity to handle renewables and ensure reliability, with particular urgency seen in areas of the Southwest.

“These competitive advantages have resulted in an overwhelming preference for electricity over the ten-year period, as installed natural gas capacity is projected to increase 38 percent over the ten-year period, while coal is projected to increase by only 6 percent,” NERC’s assessment said. Its predictions of demand for new generation have been overly generous in the past but now appear to be more realistic (Table 1). The EIA predictions of electricity demand growth do not include peak demand growth as a separate category, but rather predict energy consumption will grow 8.2% through 2018. Together, the NERC and EIA data clearly show that the need for additional, dispatchable load during on-peak hours will be a primary focus for electricity system planners. Expect more gas-fired reciprocating engine and combined-cycle plants designed for intermediate peaking service to be announced in the coming year.

Table 1. Electricity use increases, slowly. The North American Electric Reliability Corp. (NERC) expects the rate of peak demand and energy consumption growth to slow in coming years. Source: NERC

Further, NERC said that “on-peak natural gas capacity is projected to grow by more than double the amount of any other resource, and by more than five times any other resource when dual fuel resources (primarily fired by natural gas and another, alternate fuel) are excluded.” NERC said a “plausible” future scenario involves flat or negative power demand growth for the next seven or eight years, followed by an “abrupt change to normal or high demand growth.”

From NERC’s perspective, however, that trend is not all good. NERC said the growing reliance on gas could create grid problems if gas usage strains the infrastructure that delivers gas to power plants. “The projected growing reliance on natural gas increases the potential for adverse reliability impacts due to fuel supply and storage and delivery infrastructure adequacy issues,” NERC said.

Increased gas demand this past summer already put a strain on existing gas transmission infrastructure. Chesapeake Energy Corp. admitted that it briefly slowed production because natural gas pipelines and gathering systems were already operating at maximum capacity (Figure 5).

Figure 5. Gas storage and pipelines full in 2010. An excess of natural gas is packing gas lines and storage facilities. Shown is the predicted rate of natural gas storage for 2010 compared to historic amounts. Source: EIA November 2009 Short-Term Energy Outlook

Unexpected Trend: Fuel Switching

When the Acid Rain Program under the Clean Air Act took effect in 1995, utilities searched for ways to avoid installing expensive flue gas desulfurization systems. One approach much favored by plants in the eastern U.S. was to perform a boiler fuel switch from high-sulfur eastern bituminous coal to low-sulfur Powder River Basin coal. A side benefit was that the coal was significantly less expensive to purchase, even if the delivery charges were much higher given where the coal is mined. Today, with the nation expected to be awash in natural gas, several utilities have announced plans to, in essence, fuel switch from coal to natural gas.

A good example is Progress Energy Carolinas’ August announcement of its plans to permanently shut down three coal-fired power plants near Goldsboro and, in exchange, construct a new, high-efficiency, gas-fired 950-MW combined-cycle power plant. The business case for the fuel switch is compelling. The utility gets bragging rights, not to mention emissions credits, for shuttering three coal plants totaling almost 400 MW at the H.F. Lee Plant in Wayne County. The utility makes a compelling case that its plan will reduce overall emissions (including those of CO2, should carbon controls eventually become law), increase the efficiency of electricity production in its system, and, if natural gas prices remain low, lower the cost of electricity production. The cost of the new intermediate-load plant, expected to be in service by 2013, is estimated to be around $900 million.

A final advantage to Progress Energy: Adding a natural gas–fired plant will broaden the company’s fuel resource base away from coal and nuclear. As a side benefit, shuttering the older three plants sidesteps the requirements of North Carolina’s Clean Smokestacks Act, which established very aggressive emission-reduction targets in 2013. Instead of cleaning up the old plant, Progress Energy decided it was wiser to invest the money in a new plant.

“This is an important milestone for our company and for our state,” said Lloyd Yates, president and CEO of Progress Energy Carolinas. “The Lee Plant has been producing electricity reliably and cost-effectively for our customers for more than 50 years, but as emission targets continue to change, and as legislation to reduce carbon emissions appears likely, we believe in this case, it’s in the best interest of our customers to invest in advanced-design, cleaner-burning generation for the future.”

Yates went on to say, “Our objective is to maintain the right balance of resources—nuclear, natural gas, coal, hydroelectric, solar, biomass, and energy efficiency—to make our company and state more energy independent and to minimize the risk of customer price spikes due to volatility in cost or supply of any single fuel source.”

The economic advantage to Progress Energy is apparent, but in an unusual display of harmony, North Carolina regulators have disarmed all the explosives in the usual regulatory minefield encountered when permitting a new gas plant. The North Carolina General Assembly recently approved legislation to facilitate a fuel or technology replacement project as Progress Energy has proposed. Senate Bill 1004 established a streamlined certificate process (45 days versus the standard six months or more) to enable Progress Energy to shut down the coal units and replace them with natural gas–fueled technology. The shorter certification period was needed to enable the company to replace the coal-fired plants by 2013, when the stricter statewide emission targets come into effect.

Expect additional state legislatures to quickly open an express lane for permitting gas-fired combined-cycle plants that replace older, less-efficient ones. Utilities will quickly respond to this economic carrot faster than the regulatory stick.

The second emerging fuel-switching trend is retooling a coal plant to burn other fuels in order to help meet state renewable portfolio standards and to avoid costly emissions equipment retrofits.

The most interesting project in this genre of plant makeovers is FirstEnergy Corp.’s plan, announced in April, to repower two units at its R.E. Burger coal-fired power plant to burn biomass. Those two coal-fired units, totaling 312 MW, would become the largest biomass power plants in the U.S.

Burger Units 4 and 5 were targeted by the Environmental Protection Agency for alleged violations of the Clean Air Act’s New Source Review provisions. A consent decree signed in 2005 settled those charges but gave FirstEnergy until midnight March 31 to decide whether to shut down the units or agree to retrofit with expensive air emission control equipment estimated to cost $330 million. Instead, the utility decided to invest $200 million to convert the two units to burn biomass. The fuel switch also furthers FirstEnergy progress toward meeting Ohio’s standard that requires utilities to obtain 25% of their power from renewable resources—at least half of which must be generated within Ohio.

According to First Energy, the two Burger units will use wood wastes and other biomass to fuel the facility. FirstEnergy’s goal, however, is to operate the plant as a “closed loop” or carbon-neutral biomass plant, which means it will use fuel derived from trees grown to serve as feedstock for the biomass. The energy crop trees would act as a carbon sink, storing carbon in the trees’ tissues and roots.

When harvested and burned, the stored carbon would be released, but the net carbon footprint would be zero. Fast-growing, bioengineered cottonwood trees and grasses grown in Ohio will be harvested and pressed into cubes before delivery to the plant. The plant will then pulverize and blow the biomass fuel into the boiler in much the same way as coal plants use pulverized coal.

A number of other utilities have announced similar plans to retrofit fossil-fueled plants to burn biomass fuels. Over the past three years, Southern Co., Northeast Utilities, Dynegy, Xcel Energy, and DTE Energy have either converted plants or are in the process of doing so.

More to Come
In Part II, we will predict what the future holds for the remaining fuel-source power generation technologies (nuclear, coal, and renewables).

—Dr. Robert Peltier, PE is editor-in-chief of POWER. Kennedy Maize is Executive Editor of MANAGING POWER

Yet Kennedy’s proposal ignores the extremely high cost of fuel conversion (upwards of $100 million for a medium-size coal plant) and the added fuel cost to burn gas. He seriously mischaracterizes how an electricity market operates. And Joe Romm (Climate Progress) had added to the confusion by calling Kennedy’s proposal a “game changer.” For Romm plentiful gas means “damn easy and cheap” compliance with the Waxman-Markey climate bill (HR 2454).

Environmentalists looking to draft the natural gas industry in a forced conversion effort against coal do not know what the gas industry does: it is highly uneconomic and would overload the pipeline system that was not built with coal conversions in mind.

Gore’s 100% Dream … and Round Two

Late last year Al Gore, self-appointed father of the climate-change movement, astonished his most ardent acolytes with a plan to produce 100% of the nation’s electricity from renewable energy and carbon-free sources within 10 years. In making the announcement, Gore noted that “The quickest, cheapest, and best way to start using all this renewable energy is in the production of electricity. In fact, we can start right now using solar power, wind power, and geothermal power to make electricity for our homes and businesses.” As always, Gore carefully sidesteps the impact of his proposals to the consumer’s pocketbook and our country’s future economic well-being.

Reasonably priced electricity is the lifeblood of this nation. Many, such as Gore and Kennedy, honestly believe that this nation can go “cold-turkey” by instantly opening the circuit breakers on thousands of coal-fired power plants to facilitate a transition to a renewables-based economy. The resulting cost to our economy in loss of jobs and a depressed GDP are incalculable.

Yet Gore’s economy-busting electricity resource plan was not persuasive to the public and utility regulators charged with ensuring a reliable and affordable power supply system. Others, not burdened with those responsibilities, have elected to take a more subtle, but no less destructive, approach by adding a little sugar to Gore’s medicinal cure.

The latest flavor of this “renewables only” approach to resource planning is Robert Kennedy’s suggestion that natural gas should be used as a “transitional fuel” until sufficient wind turbines and photovoltaic systems are constructed some day in the future. Make no mistake—this is just Gore’s proposal but with slower operating circuit breakers.

Kennedy is correct in one small way about natural gas supplies but he neglected to read the report’s fine print. Yes, the Potential Gas Committee (PGC)—a group of industry, government, and academic volunteers—concluded in a recent report that U.S. natural gas reserves were likely up 39% from their estimate two years ago. New and advanced exploration, well drilling, and completion technologies have allowed the committee to reach those conclusions. Reserves are up, not supplies as Kennedy wrote.

But an increase in reserves doesn’t immediately translate, as Kennedy suggests, to natural gas available for use in power plants. In fact, John Curtis, a committee member and professor of geology at the Colorado School of Mines, cautioned that the current assessment is a “baseline estimate” of what the committee considers to be “technically recoverable” gas and assumes “neither a time schedule nor a specific market price for the discovery and production of future gas supply.”

Kennedy Missed the Memo

Kennedy’s column then digressed into a discussion of electricity market mechanisms that are just flat wrong: “[P]ublic regulators generally require utilities to dispatch coal-generated power in preference to gas. For that reason, high-efficiency gas plants are in operation only 36 percent of the time.” I suspect this is a case of wishful thinking rather than an accurate description of how a power market operates.

In our open energy markets, power generators bid to supply energy and other services to the local independent system operator. Every power generator determines their costs of production and prices their commodity bid accordingly. Regulators do not determine the dispatch order of plants in a region—the market mechanisms of a competitively bid energy market determine the most economic combination of bids. If natural gas prices are high, then the price of electricity produced by every gas-fired plant will be higher than bids submitted by owners with coal-fired plants. A free market selects the lowest bid price independent of the technology used to produce the electricity—it’s not a market where dispatch orders are determined by ideology.

Kennedy then makes the fallacious argument that the age of a coal-fired power plant is somehow related to what he calls “horrendously inefficient” plants. Not true—those supercritical power plants built over 30 years ago are still running strong and sport very respectable thermal efficiencies. I wrote in POWER last February, TVA’s 10-unit, 1,369 MW Shawnee Fossil Plant’s Unit 6 operated for over 1,093 continuous days, a new industry record. The last unit at Shawnee was constructed in 1957, yet each of the ten units continues to operate with a thermal efficiency around 40%. I’m not aware of any modern gas-fired combined cycle plant that has demonstrated the reliability of this 50+-year-old plant. The age of a well-maintained coal-fired power plant is not necessarily an indicator of the plant’s efficiency or reliability, its useful life, nor its cost to produce electricity.

Kennedy then deftly attempts to equate plant efficiency with production costs but his logic leap results in a face plant. Kennedy states that older coal plants are “60 to 75 per cent less fuel-efficient than combined cycle gas plants.” Looking beyond the patently false claims that there are coal-fired plants in the U.S. operating with a thermal efficiency of 15%, Kennedy overlooks the market mechanisms that reward those with the lowest cost of production, not the age of a plant or its thermal efficiency. The busbar price of electricity drives every decision made by generators seeking a return on their investment.

Coal Conversion Misinformation

Kennedy concludes his diatribe by naively suggesting that a coal-fired plant can make a fuel change to burn natural gas at the snap of his fingers. “In an instant, this simple change [converting coal plants to burn natural gas] could eliminate three-quarters of America’s coal-burning generators and save a fortune in energy costs.”

Beginning upstream, someone must first invest in facilities and equipment to convert “technically recoverable” natural gas reserves into compressed gas in the pipeline and then construct a vast system of gas interstate pipelines to connect deliver the gas to hundreds of coal-fired plants. It would take decades to construct these pipelines, for starters.

There are a number of fundamental design issues that Kennedy’s arm-chair engineering overlooks. A fuel conversion from coal to natural gas is not a “simple change” but is a major plant reconstruction in order to burn a fuel that the furnace and balance of the plant equipment were not designed for.

Every coal-fired boiler furnace was designed for a specific fuel much like your automobile engine is designed for gasoline and not diesel fuel. Dramatically change the fuel specification and the boiler furnace may work for a time but it won’t work safely and reliably and certainly not at rated output. For example, boiler furnace dimensions are selected based on fuel type, ranging from very large for poor fuels such as Texas lignite to a relatively small furnace (half the size or less) to burn natural gas. Also, the heat transfer surface design would be completely inappropriate for natural gas (too much surface in some areas and not enough in others), the combustion controls and all the burners systems would require replacement, all the air quality control equipment are inappropriate for natural gas, and so on. A solid to gas fuel conversion project of this magnitude could easily require reconstructing major portions of the furnace and backpass plus replacement of primary air fans, ductwork, etc. that would cost tens of millions of dollars and many months to complete.

Often overlooked in the cost accounting of utility projects are the extraordinarily expensive replacement and purchase power costs that a utility must absorb during an unplanned plant outage. These costs often exceed the construction cost of a project. Using Kennedy’s hypothetical 500-MW coal plant as an example, a six month outage at a 90% capacity factor will cost the generator about $59 million, using $50/MWh for the spot market price of the replacement power and $20/MWh as the marginal cost of generating power from that plant.

To estimate the total project cost, sum the pipeline extension cost, about $200,000/mile according to the Institute of Transportation Studies, to transport the natural gas from that conveniently located main trunk line next to the plant, with the construction costs and the replacement power costs and my back of the envelope estimate for converting a single, moderately size coal-fired unit to burn natural gas could easily top $100,000,000.

The Physical World

There are no shortcuts to success in the business of generating power. If converting a coal plant to burn natural gas made economic sense, dozens of utilities executives would have made the switch years ago. No self-respecting PUC commissioner would entertain a proposal to spend so much money to “fix” a well-operating, inexpensive plant so that it can burn a more expensive fuel with a long history of extreme price volatility.

Proposals such as Kennedy’s work only in the realm of wishful thinking, where corrections are made on a computer with the delete key. Power plant engineers work in a more practical world of concrete and steel that produce the electricity to power that computer. It’s a world of difference.

“A reliable and affordable supply of energy is absolutely critical to maintaining and expanding economic prosperity where such prosperity already exists and to creating it where it does not.”

- John Holdren, “Memorandum to the President: The Energy-Climate Challenge,” in Donald Kennedy and John Riggs, eds., U.S. Policy and the Global Environment: Memos to the President (Washington, D.C.: The Aspen Institute, 2000), p. 21.

Julian Simon (1932–98) is an inspiration to many of us here at MasterResource. Indeed, this blog is named for Simon’s characterization of energy as the master resource. In honor of Simon, I have reproduced some quotations from the vast literature on that theme.

The primal importance of energy is recognized across the political spectrum as the views of John Holdren, Paul Ehrlich, and Amory Lovins attest. Affordable, reliable energy is thus the starting point for public policy debate. And oil, gas, and coal are the backbone of energy plenty, as even politicians are realizing now that government-forced energy transformation (energy rationing) is under debate.

“The future belongs to the efficient,” it has been said. And the foreseeable future belongs to the carbon-based energies.

Here are some quotations, beginning with Julian Simon’s classic.

“Energy is the master resource, because energy enables us to convert one material into another. As natural scientists continue to learn more about the transformation of materials from one form to another with the aid of energy, energy will be even more important. . . . For example, low energy costs would enable people to create enormous quantities of useful land. The cost of energy is the prime reason that water desalination now is too expensive for general use; reduction in energy cost would make water desalination feasible, and irrigated farming would follow in many areas that are now deserts. And if energy were much cheaper, it would be feasible to transport sweet water from areas of surplus to arid areas far away. Another example: If energy costs were low enough, all kinds of raw materials could be mined from the sea.”

- Julian Simon, The Ultimate Resource 2 (Princeton: Princeton University Press, 1996), p. 162.

“Energy will do anything that can be done in the world.”

- Johann Wolfgang von Goethe (1749–1832), quoted in Vaclav Smil, Energy: A beginner’s Guide (Oxford: One World, 2006), epigraph.

“Every event in history can occur only insofar as there is available whatever amount of energy (i.e., work) is necessary to carry it out. We can think thoughts wildly, but if we do not have the wherewithal to convert them into action, they will remain [just] thoughts.”

- Richard Adam, Paradoxical Harvest (1982), quoted in Vaclav Smil, Energy in World History(Boulder, CO: Westview, 1994), epigraph.

“Coal, in truth, stands not beside but entirely above all other commodities. It is the material energy of the country—the universal aid—the factor in everything we do. With coal almost any feat is possible or easy; without it we are thrown back in the laborious poverty of early times.”

- William Stanley Jevons, The Coal Question (London: Macmillan, 1865), p. viii.

“Coal is everything to us. Without coal, our factories will become idle, our foundries and workshops be still as the grave; the locomotive will rust in the shed, and the rail be buried in the weeds. Our streets will be dark, our houses uninhabitable. Our rivers will forget the paddlewheel, and we shall again be separated by days from France, by months for the United States. The post will lengthen its periods and protract its dates. A thousand special arts and manufacturers, one by one, then in a crowd, will fly the empty soil, as boon companies are said to disappear when the cask is dry. We shall miss our grand dependence, as a man misses his companion, his fortune, or a limb, every hour and at every turn reminded of the irreparable loss. Wise England will then be the silly virgin without the oil in her lamp.”

- Anonymous, The Times, April 19, 1866, p. 10; reprinted in Sandra Peart, ed., W. S. Jevons: Critical Responses, 4 vol. (New York: Routledge, 2003), vol. 4, p. 196.

“As medical science, by deferring death, has allowed many more people to live on the earth, so the energy of fossil fuels, by deferring physical scarcity, has kept those people alive.”

- Amory Lovins, World Energy Strategies: Facts, Issues, and Options (New York: Friends of the Earth International, 1975), p. 3.

“Man was not man until he could use fire, a chemical energy with a thousand uses; he was not civilized until he had learned through domestication to appropriate the ‘foreign’ energy of animals and through agriculture to harness better the ‘free’ energy of solar radiation and the chemical energies of light, water, and soil.”

- Erich Zimmermann, World Resources and Industries (New York: Harper & Brothers, 1951), p 55.

“In its widest sense on its material side, history is the story of man’s increasing ability to control energy. By energy we mean the capacity for doing work, for causing—not controlling—movement, for making things go or making things stop, whether they be trains or watches or mills or men. In order that anything may be done, energy is required.”

- James Fairgrieve, Geography and World Power (New York: E.P. Dutton & Co., 1921), p. 3.

“Substitution of energy-intensive technologies powered by commercial energy forms for human and animal labor and the attendant productivity gains first led to abolition of slavery, serfdom, and child labor and culminated with the emancipation of women in the West. Thus, societal advances are inextricably linked to growing energy abundance and electrification and increasing personal mobility. Gross domestic product (GDP) per capita, life expectancy and literacy correlate closely with primary energy and electricity consumption, as does energy scarcity with poverty and environmental degradation. Electrification with modern, efficient and non-polluting power sources is by far the most effective way to improve environmental quality.”

- Henry Linden, “Operational, Technological and Economic Drivers for Convergence of the Electric Power and Gas Industries,” The Electricity Journal, May 1997, p. 14.

“Virtually all of the benefits that now seem necessary to the ‘American way’ have required vast amounts of energy. Energy, in short, has been our ultimate raw material, for our commitment to economic growth has also been a commitment to the use of steadily increasing amounts of energy necessary to the production of goods and services.”

- John Holdren and Philip Herrera, Energy (San Francisco: Sierra Club, 1971), p. 10.

“Energy is necessary for daily survival. Future development crucially depends on its long-term availability in increasing quantities from sources that are dependable, safe, and environmentally sound.”

- The World Commission on Environment and Development, Our Common Future (New York: Oxford University Press, 1987), p. 168.

“Seemingly abundant and cheap sources of energy permitted large-scale replacement of human labor in both manufacturing and agricultural production. . . . The availability of ‘cheap’ energy also made possible the development of powerful farm machinery, and abundant oil and gas allowed development of synthetic fertilizers, pesticides, and other products to boost crop yields (production per acre) considerably above those achieved with traditional methods. Similarly, we can thank fossil energy for facilitating the production of many useful goods and for stimulating unprecedented rapid expansion of economies and of food production. In effect, fossil energy facilitated the population explosion of the twentieth century.”

- Paul and Anne Ehrlich, The Population Explosion (New York: Simon & Schuster, 1990), p. 27.

“Energy . . . is the great enabler for all peoples around the world. It can also be expected to remain primary in future centuries as ocean and space colonization proceed. The sudden disappearance of hydrocarbons—for example, following a ten-year forced phase-out as urged by a popular book sounding the global warming alarm—could snap the support system maintaining current population levels and force a return to ecologically inferior primitive biomass. It would not be energy sustainability but energy holocaust.”

- Robert Bradley Jr., Julian Simon and the Triumph of Energy Sustainability (Washington, DC: American Legislative Exchange Council, 2000), pp. 27-28.

“By providing energy flows of high power density, fossil fuels and electricity made it possible to embark on a large-scale industrialization creating a predominantly urban civilization with unprecedented levels of economic growth reflected in better health, greater social opportunities, higher disposable incomes, expanded transportation and an overwhelming flow of information.”

- Vaclav Smil, Energies (Cambridge, MA: The MIT Press, 1999), p. 134.

“Energy is the only universal currency: one of its many forms must be transformed to another in order for stars to shine, planets to rotate, plants to grow, and civilizations to evolve. Recognition of this universality was one of the great achievements of nineteenth-century science, but, surprisingly, this recognition has not led to comprehensive, systematic studies that view our world through the power prism of energy.”

- Vaclav Smil, Energies (Cambridge, MA: The MIT Press, 1999), p. x.

“Energy is the biggest business in the world; there just isn’t any other industry that begins to compare.”

- Lee Raymond, Chairman, ExxonMobil, quoted in Staff Article, “The Slumbering Giants Awake,” The Economist, February 10-16, 2001, p. 6.

“The twentieth century was the first era dominated by fossil fuels and electricity, and their vastly expanded supply, lower cost, increasing flexibility of use, and ease of control created the first high-energy civilization in history. Mechanization and chemization of agriculture have given us a plentiful and varied food supply: more than a four fold increase in crop productivity during the twentieth century has been made possible by a roughly 150-fold increase of fossil fuels and electricity used directly and indirectly in global cropping.”

- Vaclav Smil, “The Energy Question, Again,” Current History, December 2000, p. 408.

“The great dramatic shift to mineral energy is the very basis of technological progress. One could almost concentrate the whole history of economic development into this simple transition: man power to animal power to machine power.”

- Erich Zimmermann, World Resources and Industries (New York: Harper & Brothers, 1951), p. 58.

“The shift to machine power changed America from a rural agricultural nation to an industrial giant. It also made men’s lives easier and richer. In 1850, the average American worked seventy hours a week. Today he works forty-three. In 1850, our average American produced about 27 cents’ worth of goods in an hour. Today he produces about $1.40 worth in dollars of the same purchasing power.”

- Erich Zimmermann, World Resources and Industries (New York: Harper & Brothers, 1951), p. 58.

“Civilizations resting on the modern resource pattern of inanimate energy-metal-science-capital are highly efficient as systems of physical production and therefore, theoretically at least, they are capable of freeing man from drudgery and of giving him leisure and wealth, the basis of higher spiritual development and the larger life.”

- Erich Zimmermann, World Resources and Industries (New York: Harper & Brothers, 1951), p. 73.

“Natural resources are the foundation for human life and underpin sustainable development. They provide the raw materials for meeting basic human needs: food and water, clothing and shelter, medicine, tools, energy and communication. They also provide recreational and other non-consumptive services for increasing numbers of people. Beyond these human needs, natural resources play an important role in providing the food, habitat, and reproductive bases for virtually all living resources, and in meeting ecosystem functions like carbon and nitrogen fixation, water catchment and temperature buffering.”

- Organisation for Economic Co-operation and Development, Sustainable Development: Critical Issues (Paris: OECD, 2001), p. 273.

“Kerosene has, in one sense, increased the length of life among the agricultural population. Those who, on account of the dearness or inefficiency of whale oil, were accustomed to go to bed soon after sunset and spend almost half their time in sleep, now occupy a portion of the night in reading and other amusements; and this is more particularly true of the winter seasons.”

- John Draper (1864), quoted in Harold Williamson and Arnold Daum, The American Petroleum Industry: The Age of Illumination(Evanston: Northwestern University Press, 1959), p. 320.

“The great forward steps of civilization are at least connected in part to breakthroughs on the energy front. The discovery of fire gave primitive man security and comfort on the ground; the domestication of animals added their greater muscle capacity to his. Later on, the waterwheel opened up a new source of energy to exploitation, greatly increasing the power available to his tasks. Then, in the nineteenth century the industrial revolution was fueled by coal.”

- John Fowler, Energy and the Environment (New York: McGraw-Hill, 1975), p. 296.

“Technology and change follow the liberation of energy. The lifestyle of contemporary America was destined by the development of fossil fuels in this seminal era.”

- Wilson Clark, Energy for Survival: The Alternative to Extinction (Garden City, NY: Anchor Books, 1974), p. 45.

“Reliable and affordable access to modern energy services is an indicator of sustainable development, for without it basic needs cannot be satisfied.”

- World Energy Council, Living in One World (London: World Energy Council, 2001), p. 74.

“After 1820 the world’s economy became increasingly based on work done by nonmuscular energy. By 1950 any society that did not deploy copious energy was doomed to poverty.”

- J. R. McNeil, Something New Under the Sun (New York: W. W. Norton & Company, 2000), p. 298.

“Energy is the lifeblood of the world’s economy, the underlying means by which modern societies function. Oil, coal, natural gas, and electricity are needed for virtually every important function in industrial societies—from growing and cooking food, to manufacturing, heating and cooling buildings, and moving people and goods. The interruption of supplies by storms, earthquakes, wars, or other events quickly demonstrates how totally dependent we have become on the energy-consuming machines.”

- James MacKenzie, “Oil as a Finite Resource: When is Global Production Likely to Peak?” World Resources Institute, March 1996, p. 2.

I am reminded of Jevons with the headline from the June 17th Guardian, “Carbon capture plans threaten shutdown of all UK coal-fired power stations.” It read in part:

All of Britain’s coal-fired power stations, including Drax, the country’s largest emitter of carbon, could be forced to close down under radical plans unveiled by government today. Ed Miliband, the energy secretary, is proposing to extend his plans to force companies to fit carbon capture and storage technology (CCS) onto new coal plants – as revealed by the Guardian – to cover a dozen existing coal plants. The consultation published by his Department of Energy and Climate Change (DECC) conceded that if this happened “we could expect them to close”.

Timeless Wisdom from 1865

Here is the MasterResource post (January 31) on Jevons and coal. What would he think today of the politics and policies of climate change in his home country?

Each renewable energy, Jevons explained, was either too scarce or too unreliable for the new industrial era. The energy savior was coal, a concentrated, plentiful, storable, and transportable source of energy that was England’s bounty for the world.

There was no going back to renewables. Coal–and that included oil and gas manufactured from coal–was the new master of the master resource of energy in the 18th and 19th centuries. As Jevons stated in the introduction (p. viii) of The Coal Question (1865):

Coal, in truth, stands not beside but entirely above all other commodities. It is the material energy of the country—the universal aid—the factor in everything we do. With coal almost any feat is possible or easy; without it we are thrown back into the laborious poverty of early times.

Jevons drew attention to one remarkable new use of the new fuel (ibid., p. 100):

Perhaps the most wonderful mode of employing coal is in the ice-machine, two kinds of which, of French and English invention respectively, were at work in the Exhibition of 1862. By such machines, we may make fire, in the hottest climate, produce the cold of the Polar Regions! With fuel and fire, then, almost anything is easy.

Another writer of the day appreciated what coal meant for all:

Coal is everything to us. Without coal, our factories will become idle, our foundries and workshops be still as the grave; the locomotive will rust in the shed, and the rail be buried in the weeds. Our streets will be dark, our houses uninhabitable. Our rivers will forget the paddlewheel, and we shall again be separated by days from France, by months for the United States. The post will lengthen its periods and protract its dates. A thousand special arts and manufacturers, one by one, then in a crowd, will fly the empty soil, as boon companies are said to disappear when the cask is dry. We shall miss our grand dependence, as a man misses his companion, his fortune, or a limb, every hour and at every turn reminded of the irreparable loss. Wise England will then be the silly virgin without the [coal] oil in her lamp.

   – Anonymous, The Times, April 19, 1866, p. 10; reprinted in Sandra Peart, ed., W. S. Jevons: Critical Responses, 4 vol. (New York: Routledge, 2003), vol. 4, p. 196.

Today, scholars recognize the wisdom of Jevons’s appreciation for the energy upgrade from (dilute) renewables to (rich) fossil fuel. Vaclav Smil has written (Energies [Cambridge, MA: The MIT Press, 1999], p. 134):

By providing energy flows of high power density, fossil fuels and electricity made it possible to embark on a large-scale industrialization creating a predominantly urban civilization with unprecedented levels of economic growth reflected in better health, greater social opportunities, higher disposable incomes, expanded transportation and an overwhelming flow of information.

Today, some radical environmentalists want to ban coal in favor of renewable energies.  But I must wonder: what would have powered the Industrial Revolution without coal, and what will our future be without the most abundant fossil fuel in a primary role?

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

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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.

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[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.

This question has been a topic of heated controversy ever since 1999, when technology analyst Mark P. Mills published a study provocatively titled “The Internet Begins with Coal,” and co-authored with Peter Huber a Forbes column titled ”Dig more coal – the PCs are coming.”

Others–notably Joe Romm and researchers at the Lawrence Berkeley National Laboratory–argued that the Internet was a minor contributor to electricity demand and potentially a major contributor to energy savings in such areas as supply chain management, telecommuting, and online purchasing.

Mills and Huber argued that digital networks, server farms, chip manufacture, and information technology had become  a new key driver of electricity demand. And, they said, as the digital economy grows, so does demand for super-reliable power–the kind you can’t get from intermittent sources like wind turbines and solar panels.

Huber and Mills were not shy about pointing out the policy implications of their analysis. To wire the world, we must electrify the world. For most nations, that means burning more coal. The Kyoto agenda imperils the digital economy, and vice versa.

Critics, noting that Mills’s study was funded by the Western Fuels Association, attacked Huber and Mills as “lackeys” of the fossil fuel industry. Researchers from the Lawrence Berkeley Laboratory produced several critiques and claimed they had decisively refuted Mills, directing a lot of fire at his “ballpark” estimate that the digital economy accounted for 8% of all U.S. electricity demand in 1999. I won’t try to settle that part of the controversy.

However, a new report by the International Energy Agency (IEA) confirms the basic correctness of the Mills-Huber thesis.

Here are some highlights from Gadgets and Gigawatts: Policies for Energy-Efficient Technologies, as summarized by E&E News Network’s Climatewire (subscription required):

• Efforts by countries worldwide to reduce greenhouse gas emissions and increase energy security are in trouble if nothing is done to check the energy gobbled by both information and communication technologies and consumer electronics.
• Energy used by computers and consumer electronics will double by 2022 and increase threefold by 2030.
• The projected increase is equivalent to the current combined total residential electricity consumption of the United States and Japan.
• To operate these devices, households around the world will spend around $200 billion in electricity bills and require the addition of approximately 280 Gigawatts (GW) of new generating capacity between now and 2030.
• The number of people using PCs will exceed 1 billion over the next seven months, and nearly 2 billion television sets are in use worldwide, averaging more than 1.3 sets per each household with access to electricity.
• More than 3.5 billion people will be mobile phone subscribers by 2010.
• In many households in OECD countries, electronic devices–a category that includes televisions, desktop computers, laptops, DVD players and recorders, modems, printers, set-top boxes, portable telephones, answering machines, game consoles, audio equipment, clocks, battery chargers, mobile phones and children’s games–consume more electricity than do traditional large appliances.
• Household use of electronic devices is the major reason that residential electricity consumption is increasing in most countries.
• Electricity consumption by small electrical and electronic devices has shot up more rapidly than that of any other type of appliance over the past five years, in both OECD and non-OECD countries.
• Computers, related equipment and consumer electronics are responsible for close to 15 percent of total residential electricity consumption today, a share similar to that of other major appliance categories such as water heating or refrigeration. However, the growth has been faster, about 7 percent per year since 1990.
• Residential electricity consumption has been on the rise in all regions of the globe at an average of 3.4 percent a year since 1990. In European industrialized nations, it grew by 1.9 percent yearly between 1990 and 2006. One-quarter of this growth resulted from increases in population; per capita electricity consumption grew by 1.4 percent over the same period.
• Even with improvements foreseen in energy efficiency, consumption by electronics in the residential sector is set to increase by 250 percent by 2030.
• “The share of electricity consumption by these appliances is therefore increasing to the extent that they will most likely comprise the largest end-use category in many countries before 2020, unless effective steps are taken,” said IEA Executive Director Nobuo Tanaka in a press release.
• “These estimates suggest that total residential electricity consumption will increase more than many previous forecasts, and therefore pose a serious challenge to all governments with policy ambitions to increase energy security and economic development, and to mitigate climate change,” states the report.

If I were writing a press release about the IEA study for Mark Mills, the headline would say, “Told ya so!”

[Editor's Note: Projected emissions from China will more than cancel the effects of Waxman-Markey in the year 2050 when the proposed law's 83% cut in U.S. emissions would be fully imposed. This finding, calculated with the assistance of Chip Knappenberger and the MAGICC model, is part of a wide-ranging analysis below. Discussion, comments, and questions are invited by the author.]

The Waxman-Markey climate bill–characterized as a “648 page cap-and-trade monstrosity” by Al Gore’s mentor, James Hansen–is intended to bring the U.S. into line with Europe and Japan on CO₂ policy. But as I have explained previously, the current U.S. policy discouraging new coal and new nuclear capacity will:

1. Make the U.S. more dependent on energy imports,
2. Drive up generation costs,
3. Artificially incite demand for fickle natural gas, and related infrastructure such as LNG regasification facilities, and
4. Increase reliance on old coal and old nuclear for baseload power, resulting in less efficient, less clean, and less reliable electricity.

Such government intervention will block self-interested private investors who would otherwise provide America with more domestic, lower-cost energy, and more modern infrastructure for better reliability. And ironically, our more expensive, imported and unreliable electricity system will hardly make a difference in worldwide CO₂ levels and associated global climate change.

A One-Country Negation

The expected growth of coal-fired generation in China over the next 20 years will result in a net increase in CO₂ emissions from their power sector of more than ten times that of reduced U.S. emissions due to coal constraints.

Using the IPCC base case conventions for converting carbon emissions to temperature changes, the U.S. policy of limiting coal-fired power generation will, on net, decrease temperatures by about 0.02°C by the year 2100, while China’s growth in emissions will increase temperatures by about 0.25°C over than same period. The climatic effects of a costly U.S. policy to substitute more expensive sources of electricity for less expensive ones needs to be seen in the context of continued high rates of growth in China (and elsewhere) without substantial limitations on coal use.

Thus U.S. efforts are essentially part of the statistical “noise” and not a real option for reducing world emissions of carbon.

The Future of Power Generation Is In China

Since 2003 electricity generating capacity in China has risen from 365,000 MW, a little more than one third of U.S. generation capacity, to more than 700,000 MW in 2008. In 2006 alone, China added 106,000 MW of capacity, roughly equivalent to two new large coal-fired power plants every week.

In China almost all of the thermal generating capacity additions (which account for 82% of total capacity additions) use coal. Importantly, China pushes its power plants harder than do U.S. generators, supplying roughly the same number of kWh from its power plants as does the U.S. with its greater total capacity.

In contrast, the rate of growth of power generation in the U.S. is a small fraction of that in China. Between 2003 and 2007, the U.S. added 49,000 (net) MW (less than 6 months’ work for China at its current growth rate), and an average of 236 MW per week (181 MW thermal, the rest was wind), about one-fourth the rate of China during the same period.

By 2030 the consensus forecast is that China will generate 70% more electricity than the US, with about 25% more generating capacity. More than 60% of China’s total generating capacity (1,034,000 MW) is projected to be based on coal in 2030. Under cap-and-trade restrictions, revised projections show that the U.S. is likely to expand generating capacity at a rate below its historic level of about 1.2% annually, with the fraction provided by coal falling from 30% of capacity (50% of generation) to 28% of capacity in 2030 (~360,000 MW and 41% of generation).

The vast differentials in the climate impacts of the reduction in U.S. emissions with a restrictive policy on coal vs. the increase in Chinese emissions gives the lie to current ideas that restrictive U.S. energy policies can successfully tackle climate change. In fact, the impacts of expanded coal use for electricity (only!) in China far outweigh the impacts of U.S. restrictions on coal consumption, using the conventions of the IPCC on climatic impacts of carbon emissions over the next 90 years.

U.S. Coal: A Shackled Giant

The U.S. boats the largest coal reserves in the world, with about 27-28% of the world’s total. China, with about half the U.S. reserves, produces almost 40% of all coal mined every year.

In spite of the vast U.S. coal resources, coal has lost ground in the US energy mix. In fact, the U.S. is not even among the top five coal exporters. Indeed, for a generation coal has lost ground in the U.S. energy mix, mostly to natural gas.

Most of the thermal generation capacity added in the U.S. since 1990 uses natural gas as a fuel. Regulatory delays, lender reticence in the face of pending carbon restrictions, and the attractiveness and cleanliness of gas technology for meeting variable demand levels have combined to make natural gas the preferred generation technology in the U.S. When presented with the already issued permits for new plants using more efficient and low emission coal combustion technologies, U.S. regulators at both the state (Kansas) and federal (re New Mexico) levels have summoned a full load of sanctimony and have rescinded the permits for the two plants.

Plants in China are commissioned in weeks; two coal plants in the U.S. have been stuck in regulatory limbo for years. And the China plants  burn more coal per kWh and lack the emissions controls that have been standard on U.S. plants for almost 20 years. This is reality.

Regardless of the preferences of regulatory bureaucrats in the U.S., the denial of construction permits for new coal-fired power plants will not eliminate the need to update our generation portfolio. The next few years are critical, since a number of the coal and nuclear plants now in service will need to be retired or extensively overhauled. Coal and nuclear together, roughly 40% of generation capacity, produces 70% of total output. Political authorities in the U.S. at either state or federal levels have all but ruled out new coal and nuclear plants to replace the ones to come out of service over the next few years. But things could change quickly if a grid crisis occurs to get the public’s attention on what is being done in government office buildings on both the state and federal side.

Natural Gas Now, Natural Gas Forever

So as U.S. baseload units go out of service they will be replaced by . . . . . ?

Wind cannot replace thousands of MW of baseload electricity. As explained in previous posts, wind is simply not comparable in terms of its supply quality. Solar has similar problems, and would require massive investments not only in generation but also in storage and transmission.

Oil – been there, done that.

Hydro, moving down not up.

One alternative, the default in the US for the past 20 years, is more natural gas. Gas-fired combined cycle power plants (CCGT), now more than one third of the U.S. generating fleet, produce about the same amount of electrical energy as the 10% share of capacity taken by nuclear plants.

The reason that gas-fired plants are not used as baseload facilities is not technical. Oil refineries and other critical reliability facilities use such plants, often with cogeneration of steam and process heat. Rather it is the simple fact of cost.

Coal plants are costly to construct, but once built they cost little to operate. A new high efficiency coal-fired plant built in the U.S. for about $2 million per MW will feature total generation costs that average about 6.7 cents per kWh, with oil ranging from $45 per barrel to $80 per barrel.

A new gas-fired CCGT plant, with construction costs less than half what a coal plant will run, and even accounting for the current weakness in gas prices relative to oil, will produce electricity at an average cost of 6.8 cents per kWh.

So there is hardly anything to choose from, is there? Not quite. The gas plant costs on average 3.2 cents per kWh for the fuel, while coal and the costs of emission reduction run less than half that, 1.3 cents per kWh. Anyone with a choice will operate a built new-technology coal plant before running the gas plant – such is normal utility procedure, one that we are apparently prepared to disrupt for a chimerical pursuit of emissions reductions.

And it should be noted that once we stoke gas demand by replacing coal and nuclear plant retirements, the gas price weakness is unlikely to last long and we shall find ourselves once again paying something like LNG price parity for gas supplies to generate electricity.

A return of U.S. domestic natural gas prices to the “pre shale discovery” levels of 2001-05 vis-à-vis oil would add about $0.4 cents per kWh on average, and raise fuel costs in a CCGT plant to about 3.6 cents/kWh at current crude oil prices.

Emissions “Benefits” Are Part of the Statistical Noise

So what precisely does the world gain if the U.S. ties itself to near total dependence on natural gas as the default option for electricity generation. If we imagine CCGT installations of about 10,000 MW annually for the next 20 years, then the U.S. electric power system will reduce its use of coal by almost 30% compared with the Department of Energy’s base case projections for fuel use in power generation.

That same forecast shows gas use falling by more than 15% over that same period. Nuclear power is expected (in this base case) to grow by roughly the same amount that gas falls. By 2030 the gas production and imports needed to replace the missing coal and nuclear generation will represent about 8 Quadrillion BTU/year of energy, accounting for the superior efficiency of CCGT plants in fuel conversion to electricity. That volume of energy represents 3.6 million barrels per day of oil equivalent energy (the US currently imports about 12 million b/d of oil and refined products). In terms of current US gas production meeting such a demand for additional fuel would require a production increase of more than 30% (7.6 TCF per year). It may be possible to meet much of this additional demand with aggressive domestic gas development and production.

Equivalently, should the current administration succeed in its efforts to retard development of incremental sources of domestic natural gas, the US would need the entire planned, proposed, posited, dreamed and doodled LNG production capacity worldwide through 2030.

And what if this dream actually did come true and the U.S. was able to replace 30% of its coal-generated electricity with CCGT in the next 20 years—what impact would this have on the course of future global climate? Basically none.

The cumulative emissions saving for the U.S. from 2010 to 2030 of the low-coal scenario described above compared with the base case projections amount to about 5,258 million metric tons of CO₂ (mmtCO₂). All the while, China, according to the base case projections, adds 77,190mmtCO₂ from its coal-powered electrical generation. So, even if a savings of 5,258mmtCO₂ from the U.S. meant something climatologically (it doesn’t), it will have only “saved” about three-thousandths of a °C by 2030. See here for a quick conversion from emissions to temperature).

U.S. reductions in CO₂ emissions would be replaced nearly 15 times over by China’s growth. Loosely extrapolating to the end of the century, while assuming that the 2030 emissions from coal and natural gas used to generate electricity from the U.S. and China remain constant (for example). China adds no new coal plants after 2030), US policy results in a cumulative savings of 36,327mmtCO₂ from the U.S. compared with a 477,081mmt CO₂ emissions addition from China. The former results in a global temperature “savings” of about two-hundredths of °C,[1] while the latter results in a temperature rise of about 0.25°C—again China’s greenhouse gas emissions from coal-fired electrical production add more than 10 times the amount of global warming that the U.S. saves by converting from coal to natural gas. Even without considering China, the temperature impact from U.S. actions alone is so tiny that it falls deep in the statistical noise of our natural climate variability—that is, you couldn’t detect it using current measuring equipment or statistical models.

Dr. Barker, who is director of the Cambridge Center for Climate Research, said the Great Depression of the 1930s reduced global emissions by 35% because so many factories shut down, especially in the United States. He adds:

The depression could be worse this time because of globalization. Emissions in the U.S. fell by 3 per cent last year and could fall by 10 to 20 per cent this year because the economy is dropping like a stone with up to 600,000 a month becoming unemployed.

The former Soviet Union provides additional proof of the emission-cutting power of economic collapse. In CO2 Emissions from Fuel Combustion Highlights (2005 Edition), the International Energy Agency reports the following emission reductions during 1990-2003: Bulgaria, 38%; Estonia, 35.3%, Latvia, 52.3%, Lithuania, 43.5%, Romania, 43.3%; Russia, 24.5%, Slovak Republic, 30.2%; and Ukraine, 50.1%.

So clearly, governments do have the power to achieve deep emission cuts in in a single decade or even in a few years. However, there’s not a shred of historical evidence that they can do this without first engineering severe economic contractions.

You might suppose Dr. Barker would worry that, if depressions produce deep emission cuts, then maybe mandating deep emission cuts would produce or prolong depressions, by making energy unaffordable.

But no, Barker reportedly views the current depression as a golden opportunity to launch a “Green New Deal.” He opines that, ”Even very stringent reductions in emissions can create a macroeconomic benefit, if governments go about it the right way.” This is but a green variant of the fatal conceit that elites know better than markets how to direct economic development. Government interventions in credit and housing markets are the root cause of the ongoing financial crisis. Yet instead of humbling would-be central planners, each policy disaster just seems to feed their hubris.   

You hear Barker’s message all the time. The revenues from carbon permit auctions or carbon taxes will be used to lower taxes on capital and labor, and fund R&D, making us more prosperous and competitive.

But if taxes on labor and capital are too high (they are), that’s an argument for cutting those taxes, not for imposing new or higher taxes on energy. So-called green industries and jobs were bit players even when the economy was booming. That’s because even when credit markets were flush and fossil energy prices were high, green industries were relatively unproductive. For example, as my colleague Iain Murray estimates, one coal-industry job supports seven times as much electricity as one wind-industry job.

It strains credulity to claim that diverting capital and labor from, e.g., the coal industry to the wind industry will create a macroeconomic benefit, or that economic recovery can be built on jobs and industries that depended heavily on subsidies, tax preferences, and mandates even in prosperous times.