EPA's Big Bet on Green Trading

Deck: 

Environmental Emissions: The cost to power markets of the Clean Air Interstate Rule depends on the ability to trade mercury.

Fortnightly Magazine - June 2005

Billions of dollars of ratepayer money will be spent in the next decade on pollution-control equipment to meet new rules that amount to an Environmental Protection Agency (EPA) bet that mercury can be traded like soybeans, oil, and more pertinent, SO2 and NOx.

Most of the projected $52 billion in new equipment—scrubbers for SO2 and selective catalytic reduction units (SCRs) for NOx—are a result of tighter limits on those two pollutants, according to EPA estimates.

By throwing in mercury, the EPA has provided cover for utilities that were reluctant to spend on one of those other devices, while giving an immediate and long-term boost to the handful of companies that make equipment aimed at curbing mercury.

Both of EPA’s latest rules—the Clean Air Interstate Rule (CAIR) for SO2  and NOx, and the Clean Air Mercury Rule—will have dramatic impacts on the type of fuel used for current and new plants. They also will determine whether new control equipment is installed, and the value of emissions allowances. The impact realized from mercury will be felt later than initially envisaged, as the first round of emissions cuts in 2010 are expected to be achieved strictly from the “co-benefits” of installing NOx and SO2 controls on coal-fired boilers. Incentives to make early reductions—a handicap for Western low-sulfur coal—and uncertainty over the rules, are affecting plant owners’ near-term emissions-control decisions.

First, look at the rules themselves. CAIR cuts the current cap on SO2 emissions levels from the 10.6 million tons emitted in 2003 to 5 million tons in 2010, and to 4.3 million tons in 2018. However, according to the rule finalized March 10, the reductions will come only in the 28 Eastern states where the creation of pollutants is at its most acute.

Figure 1 - Coal vs Emissions ($/ton)

The current cap-and-trade regime for SO2 applies nationally. Those states not part of the new CAIR program will remain under the Acid Rain regime that was created as part of the 1990 Clean Air Act amendments. Acid Rain rules still will govern the trading program in CAIR states, although with the fewer tons of SO2 allowed.

Utilities and merchant generators in the states governed by CAIR are speedily adding new SO2 controls to their large coal plants, including wet flue-gas desulfurization units, or FGDs—the most effective and expensive scrubbing devices. This is the wave of controls that some had expected under the Acid Rain program, which instead led to massive fuel switching that continues to this day. To meet those earlier SO2 rules, existing plants changed to low-sulfur coal, and today, nearly every new fossil-fired unit built since 1995 runs on natural gas, which has much lower emissions of SO2,  and other pollutants.

CAIR also reduces NOx from 3.2 million tons in 2003 to 1.5 million tons in 2009, and 1.3 million tons in 2015.

Key Differences

The creation of year-round  limits is one of the key differences between CAIR and existing cap-and-trade programs for the pollutant, which is a precursor to ground-level ozone and a greenhouse gas. Reducing NOx 12 months a year will change how coal-fired generators operate their selective catalytic reduction systems, how they manage regular maintenance outages, and how they should reduce the cost of  allowances as the marginal cost for those controls falls.

Figure 2 - Low vs High-Sulfur Production

Prior to the run-up in prices for SO2 allowances that began in early 2004, NOx was more volatile, and was the greater variable for generators and the power market overall. NOx prices, which just prior to the ozone season were trading around $3,475/ton, have ranged from below $1,000 up to $8,000 in the first six years of activity. NOx is currently limited in the 20 states under the State Implementation Plan (SIP Call) that began in 2003, a program that followed the establishment of the Ozone Trading Commission market in the mid-Atlantic and New England states in 1999.

Including state programs in California, market prices have gone even higher than the $8,000 seen in April 2003.  Allowances under the regional air quality management districts in California became in incredibly short supply during the 2000-2001 energy crisis, when even the dirtiest or least economic generators were needed to address electricity shortfalls.

The most recent spike in SIP Call prices came in early 2003, as states were trying to determine if they would have sufficient allowances to cover the program’s first ozone season. That concern became more acute as natural gas prices surged, thereby ensuring coal generation was well in the money during the summer and that the need for allowances would grow.

The 2004 summer was atypical in that it began with sufficient tons of NOx, to cover any bump in demand, leaving prices hovering above $2,000/ton. In the 2005 season, the first full summer for several key coal-fired generating states, the potential for a more intense cooling season, and with 7 GW of capacity running SCRs for the first time, prices are starting higher than the previous summer. An overhang of allowances from the prior summer remains, though those cannot be converted at full value in 2005.

Figure 3 - SO2 Volatility, Weekly Annualized

American Electric Power Co. (AEP) estimates that an uncontrolled coal plant in the summer of 2004 faced a cost of $2.70/MWh for NOx and $4/MWh for SO2. This July, those costs are estimated at $4.20 and $6.20, respectively, according to an April 14 presentation. While SO2 costs have risen each year since 2003, the  expectations for NOx actually are below those seen two summers ago.

Restrictions on how many unused tons of NOx can be used in future years is another key difference between that market and the one for SO2. Flow control—the process that limits carrying banked tons from one year to the next to prevent too large a short-term increase in pollution—will not be used when CAIR begins in 2009. Utilities and other participants in the  market are struggling to appropriately value tons of NOx in the first years of the CAIR program. In 2009, 23 states and the District of Columbia will have separate seasonal and year-round  programs, a further complication to those seeking to manage their allowance portfolio.

Over the next four years, prices will peak at $3,575 in 2006 before dipping to $2,625, according to forward-year assessments by Argus Air Daily. The start of limits on mercury in 2010, barring any delays by the lawsuits filed against the EPA’s mercury rule and those still expected, may have a mild impact on SO2 prices into the start of the next decade.

With SO2 having more than tripled in price between April 2004 and April 2005, it is being watched more closely and is driving most of the pollution control decisions, as well as the cost of coal (see Figure 1). AEP alone is adding more than 8,700 MW of scrubbing capacity over the next five years as part of its $3.7 billion plan for emissions controls this decade.

Figure 4 - Scrubber Installations

The largest coal-fired-owning utilities have been out front in installing and planning new controls, as well as preaching the benefits of those decisions to its investors. AEP and Cinergy, for instance, the two large Ohio River valley plant owners, largely have the ability to pass on the cost of their environmental spending through rate cases in Ohio, Kentucky, Virginia, West Virginia, Indiana, and Illinois. Southern Co., another large coal generator, also is exploring rate mechanisms to offset its environmental capital spending. Those three companies make up the lion’s share of new scrubbers and SCRs earmarked for the existing eastern U.S. coal fleet, and a third of all the existing and planned scrubbers throughout the nation (see Figure 4), according to Argus Media data.

Clear Skies: The “Un-finalized” Law of the Land

Though CAIR was finalized only in March, the plans for scrubbers and SCRs were laid out three years earlier, when President Bush outlined his similar Clear Skies legislative proposal forcing utilities to evaluate the potential for sharp cuts in emission limits over the next two decades. The administration is pushing to move the legislation through Congress, despite the EPA rules being finalized, because it feels Clear Skies will provide a stronger defense against litigation from either environmental groups or the utility industry. Utilities are forging ahead with their control construction projects regardless of the potential for years of litigation, as well as discord within the industry itself.

“These rules are the law of the land,” said Larry Monroe, program manager for emissions control research at Southern Co.

Southern, Cinergy, and AEP were among those ahead of the pack in securing deals to install the vast amount of controls needed, though they may not be able to mitigate the rising costs of other components, including steel, fuel, and transport costs. “There is no question there’s a shortage of boiler manufacturers,” said Tom Mason, Cinergy’s vice president for coal policy. Cinergy is adding as many as 11 new scrubbers, including the ones on plants it co-owns.

Also leading the wave of new controls and helping determine the size of the near-term emissions and coal markets are generators in North Carolina. That state had sharp reductions of SO2 and NOx enacted in 2002, prior to implementation of the federal rules, requiring plant owners such as Duke Energy’s Duke Power unit and Progress Energy’s Progress Carolinas to retrofit much of their coal fleet. The added value in complying with the new federal rules has encouraged Duke to fit its scrubbers sooner than originally planned, pushing installation on the five units at its Allen station up by two to three years, to 2009. Unit installation at Cliffside and Bellews Creek also will move up by one year each to 2008 and 2007, respectively, the utility said in a filing to state regulators in early April.

While there are limits under the current  program in carrying or “banking” allowances from one year to the next, SO2 maintains its value each year. And under CAIR, SO2 allowances given out prior to 2010 will be usable on a one-for-one basis from 2010 on, while those allocations made in 2010 and after will require two allowances for every ton emitted. This calculation is one of the principal reasons for the rise in SO2 prices, and for the increased volatility (see Figure 3, p. 79), as coal generators seek to hoard allowances prior to 2010.

Emissions of SO2 have been above the EPA cap each year since 2000, which has diminished the bank to about 6.5 million tons entering 2005. And while emissions were almost flat in 2004 and are estimated to be slightly lower in the first quarter of 2005 than the previous year, the bank continues to be depleted.

As much of these pollution control costs are passed directly to ratepayers or amoritized over many years, the impact on wholesale power rates may be mitigated. The choice of fuels and changes that occur as a result of these new controls will be the driver for baseload and off-peak pricing during the next decade.

Assuming most large coal plants are not retired as a result of these rules and enough capacity is maintained to meet at least that minimum demand, the power price in the Midwest will be driven by the cost of the most expensive delivered coal. Off-peak prices edged up beginning in late 2003 as prices for low-sulfur eastern coal were moving higher. If enough plants install scrubbers, then the use of high-sulfur Illinois Basin and Northern Appalachian coals may become attractive again. That depends on both the ability of the region’s producers to boost output and getting the coal to market cheaply.

The continued 5 percent per year growth of ultra low-sulfur coal from Wyoming’s Powder River Basin (PRB), which is accelerating this year, will depend on the calculation of its delivered cost in Btus against higher-sulfur varieties. A coal plant with a scrubber can choose whichever coal it wants and ignore the sulfur penalty, but without one at current emissions allowance prices, the plant will face double the cost for coal.

Improved performance by Western railroads in 2005 and the memory of missed shipments in 2004 from Central Appalachian and other Eastern coal fields will encourage generators to at least try PRB coal. But if extra production can be squeezed out of the Illinois basin without pulling prices up too much, high-sulfur coals may be competitive even in markets where that fuel previously did not have many buyers.

The delivered cost of that coal will determine the ability to reverse the decade-long decline in high-sulfur production, which is especially dramatic when compared with the gains from producers in Wyoming (see Figure 3, p. 79).

Some generators still may be weighing their options, though the continued rise in SO2 allowances prices likely will convince those on the fence. Some smaller utilities had been waiting to see if the mercury limits would subsidize the other controls, but the initial 2010 cap is high enough not to affect near-term emissions-control decisions.

Still A Guessing Game

The mercury rules themselves, even if adopted in their entirety by states, will not create a shift in coal markets. The rules rely on the expectation that the installation of scrubbers and SCRs will trim mercury levels enough to meet the extremely soft 38-ton emissions cap. Therefore, the marginal compliance cost is covered under SO2 and NOx, at least until 2018, when the level is expected to drop to a much tighter 18 tons.

Given the difficulty in measuring levels of mercury—there are no commercial continuous emissions monitors for mercury like there are for the other major pollutants—many utilities will be guessing at their projected levels of mercury output. The EPA decided to allow generators to trade around their mercury position rather than force installation of control technology that is also not yet commercially proven. To do so, it had to circumvent a decision made by the agency in 2000 that added mercury to a list of pollutants that require controls to be put on plants, which is one of the key issues in upcoming legal battles over the mercury rule.

If more units need to have mercury controls to come into compliance with the 2010 cap, then prices for those installations, or for the allowances under the cap-and-trade program, will affect the marginal cost of power production in the major coal-fired regions. As the mercury rule also sets a discount for different coal types, it could further the drive toward Western PRB coal, or at least encourage more blending of coal types over the next few years.