Taking due CAIR

US power utilities face new regulations controlling emissions of SO2 and NOx. But, even before the Environmental Protection Agency introduced its new rules, rising allowance prices had already driven emissions up the corporate agenda. David Biello reports

Ameren, a utility operating primarily in Missouri and Illinois, owns more than 14,800MW of power generation in those two states. The company operates more than 5,400MW of coal-fired generation in Missouri alone, running power plants from the 1950s, 1960s and 1970s. Together, they burn millions of tons of coal each year and emit thousands of tons of sulphur dioxide (SO₂) and nitrogen oxides (NOx).

Throughout the 1990s, Ameren participated in the Acid Rain Program, the US Environmental Protection Agency’s (EPA’s) ‘cap-and-trade’ programme to cut back on the SO₂ emissions responsible for acid rain. For every ton of SO₂ its plants emitted, Ameren had to surrender an allowance. By buying needed allowances or selling excess allowances, the company was able to find the least cost way to lower its emissions.

Until 2004, those allowances rarely cost more than $300 per ton. But, over the course of the past year or so, SO₂ allowance prices jumped from $260 in January to more than $700 per ton in December. And that has finally changed the calculus for companies like Ameren.

“At $200 it never mattered,” says Jim Moore, St Louis-based general executive in the coal supply and emissions department of Ameren. “At $700 it matters.”

Moore’s title reflects the changed stance of emissions. “It used to be that I did SO₂ off to the side and [Ameren’s] coal buyers would come to me once in a blue moon,” he explains. “Every time we do a coal bid now, we have to scrub those SO₂ numbers harder.”

Moore and his colleagues must now factor SO₂, NOx and – potentially – mercury prices (see box) into every fuel purchase decision they make. If they buy high sulphur coal from Illinois they will have to buy more allowances. If they buy low sulphur coal from the Powder River Basin in Wyoming, they may have extra allowances to sell.

This means Ameren must take a position on whether SO₂ allowance prices will rise or fall or stay the same and, as Moore points out, utilities hate to take a view. “We don’t like risk,” he says.

Ameren is hardly alone in this predicament. “It’s really market view questions that I get most of the time,” says Gary Payne, an emissions trader at Virginia-based utility Dominion. “Is the liquidity there to be able to handle us selling allowances in a couple of years? Are these prices going to be sustained for 12 to 18 months?”

Throughout the US, utilities are grappling with high SO₂ prices and new regulatory programmes to address acid rain, smog, soot and other emissions-related problems. The EPA’s Clean Air Interstate Rule (CAIR), introduced last month, adds new reductions to the Acid Rain Program – cutting SO₂ emissions in 23 eastern states by 73% below 2003 levels by 2016. It is these future reductions that the market has been factoring in over the course of the last year, according to market participants: “From a market perspective, a lot of the perceived impact has already been built into prices,” Payne says.

But, with prices high for SO2 allowances and deeper cuts looming under CAIR, utilities are now looking at speeding up the deployment of technology, such as flue gas desulphurisation equipment, commonly called scrubbers, to reduce emissions. “If my cost to remove a ton with a scrubber is less than $650, maybe I want to get it in earlier and maybe I can sell those allowances,” Payne says. “With SO₂ allowance prices at these levels, companies are asking ‘How does that change my reduction technology schedule?’”

That has certainly been the case at industry giants Southern Company and American Electric Power (AEP). In 2004 AEP committed to invest more than $3 billion in pollution control technologies at its coal-fired power plants and hopes to have that equipment in place by 2008. And Southern plans to “invest some $6 billion over the next 10 years to further reduce emissions of NOx and SO2 by installing scrubbers and additional selective catalytic reduction systems [SCRs] on our larger coal-fired generating units,” says Tiffany Gilstrap, a company spokeswoman.

By installing scrubbers, utilities can almost eliminate their SO₂ emissions, significantly reducing their need for allowances. But it isn’t only through retrofitting existing technology that utilities are adapting. “We’re looking at needing 1200MW of new capacity by the end of the decade,” says Melissa McHenry, a spokeswoman for Ohio-based AEP. “Right now, we’re looking to fulfil that need with IGCC.”

IGCC stands for Integrated Gasification Combined Cycle, a new technology that turns coal into gas before burning it to turn turbines. This allows utilities to capture SO₂, NOx, mercury and even carbon dioxide before the fuel is even burned, rather than catching it in the smokestack.

“There’s also an additional ability to use an expanded fuel base with IGCC,” McHenry explains. “Some of the higher sulphur and higher BTU [British thermal unit] coals that haven’t been attractive for power generation in the last few years can be used pretty successfully in an IGCC facility and still achieve reductions in SO₂.”

Ultimately, between scrubbers and new facilities, SO₂ emissions could – potentially – fall to zero. But market analysts view that as unlikely. “There will still be some units that are too expensive to control and those companies will be better off buying allowances in the marketplace,” says John Blaney, Virginia-based managing director at consultancy ICF. “The controls that are going in place won’t be sufficient. We won’t be in an overcontrol situation.”

Of course, SO₂ is not the only emission utilities must worry about reducing. Under CAIR, utilities in 25 Eastern states will be responsible for cutting NOx emissions by 61% below 2003 levels by 2016, over the course of several phases. Much like SO2, NOx can be reduced by retrofitting existing coal-fired power plants with pollution control technology, such as SCRs.

But NOx is a more complicated pollutant, responsible for smog in the summer and soot year-round. Therefore, at the 11th hour, the EPA crafted two programmes to address NOx pollution – one building on the existing NOx Budget Trading Program for the summer months to address smog, and one covering the entire year to comply with new soot standards.

“CAIR was going to take an ozone season requirement and turn it into an annual programme” to tackle both problems, explains Thaddeus Huetteman, president of Atlanta-based consultancy Power and Energy Analytic Resources. “People were worried that reductions would be made in winter months and used to offset emissions in summer months and we’d get worsening [of the smog problem]. EPA responded to that with an annual programme and an ozone season programme together.”

To further complicate the issue, states will now have to submit to the EPA plans to comply with these targets. And their targets relate to the air quality both inside the state, and in surrounding states. Further, while trading will be allowed within each overall programme, allowances will not be tradable between the two programmes.

This complication has made CAIR’s impact on NOx prices much more difficult to ascertain. “I think that originally the market was anticipating that NOx values were going to come off because a utility can recover its SCR cost over a year rather than just the ozone season,” Dominion’s Payne explains. “But the dual programme is an interesting dynamic and I don’t think the market has digested it. We haven’t from an internal perspective.”

Most predict that NOx prices in both markets will be lower than current prices, simply due to that expanded ability to recover the cost of an SCR, but prices in the summer programme may be higher or lower than in the annual programme, depending on the weather. “If we don’t have the weather during the summer to sustain NOx prices, the market just plummets,” says Francisco Padua, a Houston-based broker at brokerage Amerex. “It also depends on how the equipment is operating. An SCR malfunctioned last summer and that turned into a need for three thousand 2004 NOx allowances.”

Equipment malfunctions may prove a stumbling block. “SCRs are a huge piece of equipment that you currently only turn on during the ozone season,” Padua adds. “Currently, you have October through April to fine-tune it, maintain it and test it. They’re not going to have that time in future. Those things are going to be on full blast all the time.”

Litigation may cloud the issue even further. Environmentalists are likely to sue, and activist New York Attorney General Eliot Spitzer has already complained about CAIR. Utilities have their own gripes, including the CAIR requirement that eastern utilities give up two allowances for every ton of SO₂ emitted to comply with the new, deeper cuts and new clean air standards for soot.

“It’s putting on a tighter standard but using the existing market to achieve that,” explains Robert LaCount, director of the North American environmental strategy service for Boston-based consultancy Cambridge Energy Research Associates (CERA). “Come 2010, every company will continue to comply with the Acid Rain Program with one allowance for one ton of emissions. CAIR asks the states to put a second layer of regulation on top of that, requiring the utilities, because they’re in the East, to give up another allowance because of the programme for fine particulate matter.”

Whether the states will follow the CAIR guidelines also remains to be seen. Each state must individually come up with a plan to meet its targets under the EPA’s new rules, but there is nothing to say that they must all come up with the same plan, or interconnect their plans. “The states have to pick up the torch and implement the programmes and connect up with other states,” LaCount says. “This time we’re modifying a very effective SO₂ trading programme. Certainly EPA has laid out what they want to see happen, but will the states fall in line?”

Already some states have shown a desire to go their own way. For example, North Carolina passed its Clean Smokestacks Act in 2004, limiting emissions trading within the state. It then petitioned the EPA to force 13 ‘upwind’ states to enact similarly stringent programmes so that North Carolina could reap the benefits of its cleaner air. A ruling as to whether CAIR fulfils that requirement is expected this summer.

And, to top it all off, not every state has the same pollution profile. For example, Arkansas is only in the summer NOx programme while Georgia is only in the annual NOx programme. “I don’t know how your average person is going to sort out what their trading strategy should be or what their compliance strategy should be,” ICF’s Blaney says.

But Moore believes that in complexity lies potential opportunity, perhaps because Ameren’s service area borders several states with less stringent mandates from the EPA. “We did some things with fuel substitution back when the Acid Rain Program happened that saved this company a lot of money,” Moore says. “There’s stuff in here that can make a lot of money. You’ve just got to read the rules.” EF

BOX: MERCURY RISING

In addition to the Clean Air Interstate Rule (CAIR) for sulphur dioxide (SO₂) and nitrogen oxides (NOx) pollution, the Environmental Protection Agency (EPA) also released the Clean Air Mercury Rule last month, in an effort to reduce the roughly 48 tons of mercury pollution emitted from US power plants every year.

Steve Johnson, EPA: US first to address mercury from power plants

“This rule marks the first time the US has regulated mercury emissions from power plants,” said Steve Johnson, acting EPA administrator, when announcing the rules on 15 March. “In so doing, we become the first nation in the world to address this remaining source of mercury pollution.”

Mercury is a potent neurotoxin and has been linked to birth defects and health problems, such as heart disease. While it has relatively low concentrations in the atmosphere, it settles to earth and concentrates as it moves up the food chain, typically winding up in humans via seafood.

With the new rule, the EPA has set an overall cap for power plant emissions in the US at 38 tons by 2010 and allows trading between power companies to achieve the least-cost emission reductions.

But the cap-and-trade approach to what was formerly a hazardous pollutant (the EPA has reclassified it to allow trading) has many critics, including several state attorneys general and environmentalists throughout the nation. “For policy reasons, not for technical reasons, there are people who will not accept the trading of mercury,” says Thaddeus Huetteman, president of Atlanta-based consultancy Power and Energy Analytic Resources. “There will be some states that won’t trade mercury. The question is: what does that mean for the EPA’s efficient transfer of tons?”

Many environmentalists have also complained that the initial mercury cap – 38 tons – was set at the same level which would be reached as a “co-benefit” of the SO₂ and NOx reductions under CAIR. “Essentially, the agency adopted a ‘do-nothing’ approach to mercury for the next 12 years,” said John Walke, director of the clean air programme for environmental group Natural Resources Defense Council, which has intimated that it will sue to halt the regulations.

If a coal-fired power plant has both a scrubber – to remove SO₂ pollution – and an SCR – to remove NOx pollution – it can also expect a major reduction in mercury emissions, possibly as much as 90%, according to John Blaney,Virginia-based managing director at consultancy ICF. “If there is a mercury market, it essentially reduces the cost of a scrubber,” he says.

Nevertheless, industry argues that there is no proven mercury control technology at the moment and therefore cap-and-trade is the only way to go. “We don’t know of a vendor of these technologies who will guarantee that they will achieve 90% mercury removal, 365 days a year, which is what we need to commit to that sort of installation,” says Melissa McHenry, spokeswoman for Ohio-based power producer American Electric Power (AEP).

Reliability aside, it is still cost that most concerns utilities. “The bottom line is still price. This puts another adder into the price of producing electricity. We’ve got one for SO₂, now we add one for mercury,” says Jim Moore, St Louis-based general executive in the coal supply and emissions department at power producer Ameren. “The problem is: we don’t have any idea what that adder should be.”

And it may be significant. “If the market works, there will be a substantial allowance price for mercury in the $20,000 a pound range, going up over time,” ICF’s Blaney predicts. The only problem is, with litigation, reluctant state governments, and unproven technology, the market looks very unlikely to work any time soon.