Survey captures industry’s carbon concerns

Black & Veatch recently published 2007 Strategic Directions in the Electric Utility Industry Survey: The Changing Climate in the Electric Utility Industry, which reports the expectations, activities, and plans of energy companies in the North American power industry, based on the responses of nearly 400 executives to the company’s survey.

A little over one-third of the execs work at investor-owned utilities, and 17% are with munis. Some 45% of respondents classified their firm as “other,” a survey category that includes independent power producers (IPPs), consultants, and regulators. Three out of four respondents said they hold an executive or management/supervisory position at their company.

As expected, service reliability was the executives’ top overall concern, with the aging workforce problem in second place. Environmental issues took the third spot, followed by aging infrastructure. Other reported concerns included security, regulation, and long-term and technology investment.

Some 82% of survey respondents said they believe that global warming is indeed occurring, and 44% answered that it is caused by human activity. Overall, about 36% of the executives believe global warming is real and caused by human activities. Nearly 35% of respondents said they were highly confident about the accuracy of climate change science. But a greater share (42%) said they doubted its usefulness.

“Those were surprising results,” said Richard Rudden, a senior VP and managing director of Black & Veatch, a leading engineering/procurement/construction firm. “They suggest less support for the underlying science than we had expected. The results also underscore the substantial differences in views of global warming between U.S. executives and executives of nations that have endorsed the Kyoto Protocol.”

Most expect CO2 controls soon

Seventy-two percent of respondents believe that some form of federal CO2 legislation will be enacted by 2011. “Given the executives’ expressions of great uncertainty about the timing and level of carbon caps, and heightened public awareness of the effects of climate change, one would have expected that percentage to be higher in our 2007 survey than in years past,” said Rudden. “One explanation for the low number is that respondents may have expected some action by Congress on this issue in 2007, which did not occur.”

Asked which type of carbon controls they would prefer, 29% of survey respondents said a cap-and-trade system for CO2 emissions, 14% preferred a straight carbon tax, 8% voted for statutory restrictions on physical emissions, and 49% wanted a combination of the three approaches.

Although the reality and cause of climate change continue to be debated, the issue’s higher public profile has led to significant changes in corporate strategies and behavior. For example, nearly 20% of respondents said they have deferred or canceled a planned coal-fired power project due to uncertainty about carbon regulations. Independent analysis by Black & Veatch indicates that plans for 13 coal plants, representing 11 GW of baseload capacity, have been scrapped or delayed over the past year, despite an urgent and growing need for new capacity identified by the DOE and the North American Electric Reliability Corp.

Another interesting survey result: Despite the wariness of 42% of executives about climate change science, almost 50% of respondents said their organizations now publicly acknowledge that global warming is a manmade problem. In addition, 86% expressed confidence that their organizations are doing enough to position themselves as environmentally aware.

The executives said they expect the business costs of cutting carbon caps or paying a carbon tax to be high—although not as high as independent estimates by Black & Veatch. Some 22% of survey respondents believe that the all-in (operating, fuel, and capital) costs of coal-fired generation will increase between 10% and 20% under a carbon-control regime. Many more (62%) expect costs to rise between 21% and 50%. Only 15% of respondents think that complying with carbon regulations will increase their costs by more than 50%.

Where to invest to cut costs

By comparison, independent analyses by Black & Veatch suggest that all-in coal plant costs under carbon controls will rise between 40% and 80%. The specific increase for a particular utility or IPP will reflect its carbon-capture technology choices, the size of its plants, and their proximity to suitable sequestration sites.

The top five supply-side technologies that respondents believe should be emphasized in the future are, in order of preference: nuclear, coal gasification, wind power, carbon capture and sequestration, and solar power. The ranking correlates with the top five environmental concerns reported by respondents: carbon emissions, water supply, mercury control, and emissions of NOx and SOx. Nuclear fuel disposal ranked sixth on the list of environmental concerns, suggesting that the industry is reasonably comfortable with this downside of nuclear power.

This summary of the report barely scratches its surface. To fully appreciate its depth and breadth, download the pdf from


Sequestering coal plant emissions

“Sequester” is an interesting word. Our industry has been using it to describe any way to permanently store the carbon dioxide produced by fossil-fueled power plants so it no longer contributes to climate change. Various references provide synonyms such as “isolate” and “impound.”

However, the first definition of “sequester” that pops up in the thesaurus of my version of Word is the one that lawyers use: to “confiscate,” or take custody of property belonging to a defendant who may be in contempt of a court until he or she complies with its orders. In the court of public opinion regarding climate change, the coal industry is the defendant and the “property” is the “right” to build a new coal-fired unit. Make no mistake: It is coal-fired electricity production that is already being sequestered. Without a credible plan for managing carbon, new projects are being squelched across the U.S., even in what normally would be considered coal-friendly states.

What became painfully obvious at Carbon Capture: Status and Outlook—a conference organized and presented by Infocast last December in Washington, D.C.—is this: A defensible, commercial, and financeable solution for capturing and sequestering large volumes of carbon dioxide is at least a decade—and probably more like 15 years—away. The necessary process technology has not been demonstrated at scale; long-term storage, monitoring, testing, and verification of sequestration sites has not been accomplished for the various geologic structures being considered (Figure 1); and, most critically, we’re not even close to a legal framework for permitting and siting such facilities. Without these pieces in place, it’s not worthwhile dwelling on the exorbitant costs of stripping CO2 from flue gas, storing it underground, and monitoring a site forever, or at least for a very long time.

1. Drilling to store gas. Properly sited, engineered, and managed geological reservoirs can be expected to retain stored CO2 for hundreds to thousands of years. However, there are many legal issues remaining for developers of sequestration facilities. Source: EPRI

To give you an idea of the volumes we’re talking about, a large coal-fired plant discharges 6 million tons of CO2 annually. According to one estimate given at the meeting, the total from 800 coal plants would be twice the volume of oil transported in the U.S. For this reason, one speaker—Bill Martin of Atlantic Energy Ventures LLC—said we need a “CO2 superhighway” to service many plants. Imagining the necessary infrastructure boggles the mind.

The technical issues

Speakers who addressed process technology, engineering, and construction issues drove home some important points:

  • Mark Langford of Kiewit Industrial Co. asked, “Is 50% [carbon dioxide] capture without enhanced oil recovery economical?” He answered his own question “no,” but then elaborated by saying that integrated gasification combined-cycle (IGCC) technology alone can’t be made economical on a straight electricity-output basis. Later, Tom Lynch of ConocoPhillips said that the costs of IGCC—without carbon capture—calculate out to around $3,200/kW for projects today “across the board.”
  • Christopher Wedig of Shaw Group observed that a total post-combustion carbon capture and storage (CCS) system has not been demonstrated at commercial scale, and that the capture process impacts most other parts of the power plant design, including the electrical system (large parasitic load), main steam turbine flow (steam is consumed in CO2 absorption), stack discharge (lower temperature), and plant water balance. “Scale-up,” he said, “is a big risk issue.”
  • Hope Chase, also of Shaw Group, addressed similar issues for in-situ CCS employing oxygen-fired combustion. For this option, total system design and operation have not been demonstrated. She also noted that operating and feedstock (fuel) flexibilities are “non-trivial” issues.”

Calvin Hartman of Worley Parsons probably summed up the predicament for coal best. One year ago, “capture-ready” was the requirement for a coal-fired project to move forward. Not too long after that, 50% capture became a popular target. Today, even that doesn’t sell. Even higher carbon capture levels are being discussed. This is an important trend, said Hartman, because 80% capture is an inflection point. Going from 80% to 90% “triples the amount of equipment,” he said.

The financial and legal issues

Coal’s road forward appeared even more difficult as the meeting waded into financial and institutional issues. David Reisinger of AIG Global Marine & Energy asked a question that was surely dreaded by the audience: Could a CO2 sequestration site be labeled “hazardous” or even a Superfund site? Swaminathan Venkataram of Standard & Poor’s stated that power companies are not the logical entities to be liable for sequestration sites; however, he did not identify who that logical candidate might be. Venkataram also noted that CCS-equipped plants would have to plan for more down time, build in contingent O&M reserves, plan for longer ramp-up times, and expect lower capacity factors. All this “impacts credit quality,” he said.

Another speaker, Martin Smith of Xcel Energy, reviewed his company’s experience trying to develop a 600-MW IGCC project over the past several years in Colorado. The project committed to CCS from the beginning. First, it was 50% capture, a level that would make the IGCC plant’s discharge equivalent to that from a gas-fired combined-cycle plant. Then the target moved to 80% capture. However, the issues moved way beyond the technical. Despite well surveys, seismic analysis, and 3-D geospatial modeling, there is much uncertainly about sequestration—for example, who owns the “pore space” below the surface? Dozens of land owners are involved. Eminent domain issues crop up. Post-closure requirements are not specified. EPA’s designation of Class V wells is not adequate for commercial sequestration. Smith concluded that although Xcel has done the work, it has barely scratched the surface of the problem.

Julio Friedmann of Lawrence Livermore Laboratory advised that, since you cannot ensure the integrity of the storage site, you must select a low-risk site, conduct a thorough site characterization, and provide a technical basis for decision-making. There are three major hazards to consider: atmospheric release, groundwater degradation, and deformation of the boundary material holding the CO2 volumes in place. Operational protocols for sequestration sites are only now being formulated. He also proclaimed that the “window of opportunity” for pairing CCS with enhanced oil recovery (EOR) would close in a few short years.

Not technically ready for prime time

The good news, if there was any, from the meeting is that CCS is a robust solution to the problem of climate change. Estimates are that it can deal with 15% to 50% of global greenhouse gas emissions. The bad news: The U.S. lags in developing and implementing the technology. There are no operational large-scale sequestration facilities, and proposed projects are proceeding with “great uncertainty.” (The Great Plains Gasification Plant in North Dakota does transport large volumes of CO2 several hundred miles to Canada for use in EOR. Recovering power plant CO2 for EOR represents an opportunity for actually selling the material, but it is currently considered a limited opportunity in the U.S. EOR also requires use of very pure CO2.)

A generally accepted definition of a “commercial” technology for electric utility application (especially one that provides no competitive advantage) is one for which three variations (or vendor offerings) have been operating for several years at appropriate scale. If that’s the goal, and you consider both that no facilities are operating today and that institutional and legal frameworks are ambiguous at best, it doesn’t take a genius to see that we’re at least a decade away from new coal plants being technically viable in our apparently carbon-constrained future. Most utility executives now believe legislation to address global warming is inevitable, and several are actively lobbying for such legislation sooner rather than later, simply to provide the certainty needed to go forward with the business of building new generating capacity.

Still failing the economic test

Placing a firm value on a ton of carbon (either via a cap-and-trade system or a carbon tax) could provide the monetary incentive necessary to accelerate CCS development. Venkataram reported numbers showing that IGCC with CSS, assuming storage in EOR wells and revenues from CO2 sales, becomes competitive at a $40/ton price for carbon. However, forecasts based on proposed legislative frameworks now before Congress don’t show the carbon markets reaching such a level until 2020. This suggests that CCS won’t be economically competitive for at least another decade, and probably longer.

At that point, of course, the question is whether coal would remain a lower-cost option for electricity generation than nuclear or renewables. Another speaker estimated that CCS would increase capital costs by 30% to 40%, operating costs by 30% to 50%, and bus-bar electricity costs by 30%.

To sum up, America’s most plentiful source of electricity is being not just sequestered, but bound, tied, and gagged, while other options have the freedom to progress forward. In that respect, sequester is not just an interesting word; it’s a dangerous word.

—Contributed by Jason Makansi, president of Pearl Street Inc. (


Comparing mercury measurement methods

The U.S. EPA has designated mercury a persistent, bio-accumulative, and toxic pollutant and says that a significant portion of anthropomorphic (manmade) levels of the element in the environment comes from burning coal. The Great Lakes Initiative (, a cooperative effort of the U.S. EPA and Environment Canada, was established to eliminate anthropogenic sources of mercury.

Measuring the mercury content of the coal entering a plant, as well as the mercury content of coal combustion residue, can be helpful in the development of a plant’s mercury control strategy. The two commonly used analytical methods for doing so are ASTM D6414-99 (wet digestion) and ASTM 6722-01 (thermal decomposition). To compare these approaches, five portions of four coal samples were analyzed by both techniques.

Wet digestion

Table 1. Key operational parameters of the Hydra AA mercury analyzer. Source: Teledyne Leeman Labs

A Hydra AA mercury analyzer (Figure 2) from Teledyne Leeman Labs is well-suited to this method. Figure 3 is a schematic of the instrument; Table 1 lists its key operational parameters. The unit can analyze coal samples with differing mercury content. Samples are prepared by placing about 1 gram of each into separate 50-ml polypropylene tubes and then adding 2 ml of 15N HNO3 and 6 ml of 12N HCl. All of the tubes are then held at about 180F for one hour. Next, 36.5 ml of deionized water is added to each tube, followed by 5 ml of 5% KMnO4.

After allowing 10 minutes for oxidation, each tube is examined to ensure that there is an excess of oxidant, indicated by a purple color. Adding 0.5 ml of 12% NaCl:12% NH2OH removes the excess oxidant and completes the digestion.

Standard or sample solutions are then added to the analyzer’s autosampler. As Figure 3 shows, the unit pumps a 10% solution of stannous chloride solution and either the standard or sample into a gas/liquid separator to produce free mercury. The Hydra AA bubbles argon through the liquid mixture; the gas extracts the mercury and carries it to the atomic absorption cell (the upper right of Figure 3) for quantification.

Thermal decomposition

A Hydra-C direct mercury analyzer, also from Teledyne Leeman Labs, is suitable for running the thermal decomposition analysis and comparing its results to those of the wet digestion method. The instrument and its schematic are shown in Figures 4 and 5, respectively; Table 2 lists its key operational parameters. A feature of the Hydra-C that is important to users at coal-fired plants is its ability to measure the level of mercury in sorbent traps, as specified by CFR 40, part 75, Appendix K.

Table 3. Summarizing the results of the two measurement methods. Source: Teledyne Leeman Labs

Despite the fundamental differences between the wet digestion and the thermal decomposition approaches to mercury analysis, the two techniques show excellent correlation. The comparative results presented here showed no analytical bias and were well within the techniques’ confidence limits.

Practical application notes

It’s interesting to note that thermal decomposition can determine the mercury level in coal at lower concentrations than wet digestion. For coal samples, the wet digestion process results in about a 50-fold dilution of the sample, whereas no dilution occurs with thermal decomposition. What’s more, with thermal decomposition, all of the mercury contained in each sample is collected (that is, preconcentrated) on the amalgam tube before analysis. That helps give the technique its lower detection limits.

The thermal decomposition technique has two additional benefits that some laboratories may appreciate. First, with thermal decomposition, no concentrated mineral acids or strong redox reagents are used. Such chemicals must be handled with care by qualified personnel and with appropriate attention to safety. Second, because the aqueous digestion step is eliminated, no aqueous hazardous waste is produced. Specifically, there are no acidic wastes high in metal content (tin, manganese, sodium, and potassium) requiring disposal (Table 4).

Table 4. Pros and cons to consider when deciding which mercury measurement technique to use. Source: Teledyne Leeman Labs

For most samples, either technique will suffice, so the choice can depend on practical rather than analytical considerations. For many power plant chemistry labs, existing instrumentation or legislative requirements may dictate use of a specific technique.

In some applications, such as process control, minimizing the total time required from sampling to report generation may be the deciding factor. Others may prefer to keep things simple for operators who lack a strong background in chemistry, or to avoid the complexity involved in the reduction technique, with its reactive reagents and hazardous waste. Also, if your lab has an interest in 40 CFR, part 75, Appendix K, the thermal decomposition approach may be better-suited to your overall needs.

—Contributed by Bruce MacAllister and David Pfeil of Teledyne Leeman Labs (