With the Supreme Court’s April decision that the Environmental Protection Agency has the authority to regulate carbon dioxide as a pollutant under the Clean Air Act, momentum shifted dramatically toward a mandatory program to cap greenhouse-gas (GHG) emissions in the United States. While the ruling initially covers only emissions from mobile sources, eventually there will be huge implications for power generation.
In the absence of federal action, states have led the charge on greenhouse-gas controls, with the Northeast’s Regional Greenhouse Gas Initiative covering 10 states due to begin in 2009 and Western states building a program around California’s developing model.
Sensing the inevitable, trade associations and U.S. industry have begun to change strategy. Rather than relying on the usual delay tactics, various groups have issued a set of criteria outlining policies they would be prepared to support. Most notably, the U.S. Climate Action Partnership, a coalition of U.S. companies and non-governmental groups including four utilities, is calling for a federal cap-and-trade program to cut GHG emissions by up to 80 percent by 2050.
Scientific reports such as the recently released UN International Panel on Climate Change fourth report are narrowing the uncertainty held up by the Bush administration as one of the reasons to proceed cautiously with limiting GHG emissions. The question now is not whether to regulate, but how to regulate, and how much.
The pace of work on climate legislation has accelerated quickly since Democrats took control of Congress this year. But a slew of bills with varying degrees of stringency and widely divergent methods of control must be whittled down to a smaller package to foster constructive debate.
Former Vice President Al Gore’s visit to Congress in March served to highlight several issues lawmakers will have to consider. Legislation may move first in the House, as the rules there will make it easier for Democrats to take action without the threat of a filibuster. But most of the proposals to date have come from the Senate.
The Climate Stewardship and Innovation Act, introduced in January by Sens. John McCain, R-Ariz., and Joe Lieberman, I-Conn., covers 85 percent of U.S. emissions. It has the longest history of any existing proposal, with earlier legislation defeated twice before, in 2003 and again in 2005. The new bill has a declining cap that would cut economy-wide emissions by 65 percent of 2004 levels by 2050.
Sen. Bernie Sanders, I-Vt., introduced another economywide bill, the Global Warming Pollution Reduction Act. It calls for an 80 percent reduction in GHG emissions from 1990 levels by 2050, one of the most stringent climate-change proposals. Sen. Jim Jeffords, I-Vt., first introduced the bill last year. Specific provisions to attain those targets include mandatory GHG standards for all electric power plants built after 2012, with a compliance date of 2016. Finalized GHG standards for the electric sector will apply to all facilities by 2030, regardless of when they went on line. Sens. John Kerry, D-Mass., and Olympia Snowe, R-Maine, introduced a bill cutting economy-wide GHG emissions by 65 percent by 2050 by creating a cap-and-trade program and setting new standards for automobiles and electricity generation.
Some proposals are focusing on the power sector, usually the first target of environmental regulation because large stationary emission sources are easiest to regulate. Sen. Dianne Feinstein, D-Calif., introduced legislation to reduce power-plant GHG emissions by at least 25 percent as part of a broader strategy to be proposed later. Feinstein’s Electric Utility Cap-and-Trade Act would start by capping emissions at 2006 levels in 2011 and then lower the cap to 2001 levels by 2015. From 2016 to 2020, the cap would be lowered an additional 1 percent a year, resulting in emissions that are 25 percent lower than projected levels.
The utility cap-and-trade bill is co-sponsored by Sen. Tom Carper, D-Del., who sees it as an extension of his previously introduced legislation, the Clean Air Planning Act (CAPA). CAPA also calls for cuts in NOX, SO2 and mercury emissions, and caps CO2 emissions at current levels in 2010 and 2001 levels in 2015. But progress on the bill has been stalled by diverging views between Carper and co-sponsor Lamar Alexander, R-Tenn., on allowance allocation.
Alexander recently introduced his own Clean Air/Climate Change Act, which includes similar emissions caps as CAPA but uses a different allocation method. Sanders also has introduced a utility sector bill that would require a 17-percent reduction from 1990 levels by 2025.
While the details of allowance distribution will be contentious, it is the stringency of the cap and the baseline that will be the biggest price driver. All of the above proposals will increase the cost of producing power by making generators factor in the cost of carbon allowances.
Senate Energy and Natural Resources Committee Chair Jeff Bingaman, D-N.M., has a plan to limit the economic impact of climate legislation by using an economy-wide intensity target. Economic growth would not be restricted by an outright emissions cap, and cost would be limited by issuing unlimited allowances if the safety valve price is reached. In a discussion draft circulated in January, emissions intensity would be reduced 2.6 percent a year between 2012 and 2021, and 3 percent a year thereafter.
Initial estimates indicate this would result in a 75 percent reduction in emissions growth from 2013 to 2020. It would place a cap on upstream GHG emissions, regulating sectors including oil refineries, natural-gas producers and coal mines. Bingaman says he will increase the originally proposed $7/metric tonne safety valve price and strengthen the targets. An Energy Information Administration (EIA) analysis of the proposal found that the safety valve would inhibit emissions reductions after about 2025, as most companies would find it more affordable to pay rather than control emissions. But the plan would cost just 0.1 percent of U.S. gross domestic product (GDP) through 2030, EIA said.
A majority of the Senate voted for Bingaman’s 2005 resolution calling for mandatory GHG regulation that does not hurt the U.S. economy and encourages similar action by developing nations. But those are high hurdles.
Some of these proposals are mirrored in the House. Rep. Wayne Gilchrest, R-Md., and John Olver, D-Mass., introduced a companion bill to McCain and Lieberman’s Climate Stewardship and Innovation Act with an equivalent declining cap, resulting in a 70 percent cut from 1990 emission levels by 2050. Rep. Henry Waxman, D-Calif., sponsored the most recent legislation to be reintroduced, the Safe Climate Act, calling for an 80 percent cut in greenhouse-gas emissions by 2050. It is similar to legislation introduced by Sen. Sanders. The bill has 125 co-sponsors.
Republicans on the Senate Environment and Public Works Committee remain either skeptical or at least very cautious of restricting emissions from the entire U.S. economy. Such a closely divided committee vote would not bode well for cap supporters to get the 60 votes needed to avoid a filibuster on the floor of the Senate.
There appears to be some room to bring a few Republicans on board. The bulk of their questioning of Gore focused on the role of nuclear energy in a carbon-constrained world, suggesting that more government support for nuclear generation could give them some reason to support legislation. And incentives for clean-coal generation that uses carbon capture and sequestration would go a long way toward satisfying coal-state lawmakers from both parties.
The cost of any program will depend on how quickly technology advances. Switching to lower-emitting fuels such as gas has been the primary method of compliance in Europe so far, but supply is limited. An MIT analysis has found that bills being considered by Congress that specify GHG emissions reductions of 50 to 80 percent below 1990 levels by 2050 would result in prices between $30 to $50 per metric tonne CO2 equivalent, with prices increasing by a factor of four by 2050. If allowances were auctioned, these proposals could produce $100 billion to $500 billion in annual revenue.
Another group of proposals establishes targets for constraining emissions intensity and sets a schedule for safety valve limits on the emission price to stabilize U.S. emissions at the 2008 level. Emissions prices range from $7 to $40, depending on how many allowances are freely distributed.
GHG-capture technology only now is emerging and has not been developed to commercial standards. AEP just announced the first commercial application of carbon-capture and storage (CCS) technology, using Alstom’s chilled-ammonia process. But the gas must be stored permanently, an as yet unproven technology. MIT said that CCS would be economic if carbon is priced at $30/metric tonne CO2 equivalent or higher. Another option for CO2 removal is an amine scrubber. The costs for that technology have come down from $70 to between $40 and $50 per ton of CO2 removed, while the chilled-ammonia-method removal costs will be about one third of those of the amine scrubber.
While the development and implementation of a U.S. carbon market will take time as proposals meander through the political and public processes, generators are beginning to examine how such a cost, in whatever form it may take, will change the current dynamics of fuel choice and power prices.
Examining data throughout the United States for the years 1990-2005 shows that an average coal unit now emits close to 1 ton of CO2 per megawatt-hour of power, a number that has remained stable as the few new coal units have offset the slow, and normal, efficiency losses as units age. Conversely, average natural-gas CO2 output has diminished markedly, an unintended benefit of the combined-cycle led construction boom that peaked in 2002.
Since 2000, these new units have pushed down average CO2/MWh output from 0.6/tons to 0.5/tons for natural gas units. Oil-fired generators emit only slightly less CO2 than coal generation, at about 0.95/tons CO2/MWh, though great strides in reducing this are occurring in PJM. But petroleum liquid generation has ebbed in the United States, despite the push for dual-fueled generation in the Northeast. Any shrinking of its margin from carbon costs will push the fuel further up the generation stack, making its usage more and more of a special localized phenomenon.
In the battle between coal and gas, which combined take up the lion’s share of clearing units, gas will see net revenues stay steady in the face of an additional carbon cost. Coal units, which now enjoy robust spark spreads during the peak, will see profits squeezed as increased revenues from a higher clearing price will not match the concomitant increase in generation costs. As a rule of thumb, a coal generator that is not the marginal clearing unit will see its margin diminish on a megawatt hour basis by one half of the dollars per ton in carbon costs that are incurred.
Argus’ assessed forward curve on power and generation fuels prices currently extends through 2009. Given the still-preliminary discussions occurring on carbon costs, modeling multiple carbon-price levels, based on the current fleet, provides important clues on the intermediate impact on power generation in the United States. Over the long-term, carbon costs will influence research and development spending and shift generation to less carbon-intense sources, but for the purpose of comparison of already installed or soon to be installed generation, four pricing levels per ton were chosen: $7, $10, $30, and $22.63/ton, the last of which corresponds to a recent 10-day average price for 2008 EU carbon credits. To focus on the possible effects, rather than politics, all assumptions are incorporated on day one of the new scheme. In reality, any scheme likely would be phased in over time.
PJM forward curves currently show Calendar-09 power pricing near $78/MWh for peak and $50/MWh for off-peak. The peak marginal heat rate for a gas unit that can just cover its fuel costs is 7,381 BTU/kWh. Coal units show positive spark spreads for a 10,000 BTU/kWh unit of between $48 and $56/MWh, depending upon coal source. Coal spark spreads for off-peak power are between $20 and $30/MWh, while a gas unit is out of the money in almost all cases. A carbon price of more than $120/ton would be needed before gas would firmly displace coal in the generation stack, an unlikely price given concerns about reducing carbon output without wrecking the American economy.
Walking through the four price levels, at a $7/ton price in PJM, power prices could be expected to rise $3.71/MWh, assuming the marginal generator stayed the same. Coal spark spreads would drop by $6.86/MWh. Increasing this carbon price to $10/MWh, power prices would rise by $5.30/MWh, with coal units giving up $9.80/MWh in spark spreads. Increasing the cost to the recent EU price, $22.63/ton, would push power prices up by $12/MWh, with coal units seeing a spark spread drop by $22.18/MWh. Finally, setting the carbon price at $30/ton would increase wholesale power prices by nearly $16/MWh, while coal units would see a hit of $29.40/MWh. At the outset, a carbon price would be paid for by essentially two groups, consumers in the form of higher power prices, and coal generators who would lose the large spark-spread advantage that has fueled the recent boom in new coal generation, requiring project developers to make their pro formas work with sharply reduced peak-power net revenue expectations.
Natural gas is rarely the marginal fuel generator for the off peak, though its share of the off-peak hours is rising in the Midwest. Given coal’s dominance as the top-of-the-stack generator for the off peak, and that fuel’s relatively high costs to spark that would occur in a carbon-constrained environment, off-peak prices likely will rise further than on-peak pricing, narrowing the spread between the two and helping to smooth out the peaks and valleys of hourly power prices, even as load remains close to the same levels. Such a narrowing would see pumped hydro storage units, which depend on a wide spread to recover costs, be an inadvertent loser in such a pricing environment, while natural-gas units would encroach upon coal’s dominance of the off peak the more the carbon price rises.
Developers have been encouraged by market factors to accelerate construction of dual-fueled generators in the Northeast. Such generators typically switch to residual or other petroleum product to produce power when natural gas is either unavailable, has been sold as part of a peak-shaving agreement, or is more economic to sell the gas. While residual fuel often shows a higher spark spread to natural gas in the winter, despite less efficient operations, the fuel is often hampered by environmental permitting constraints.
These additional operating costs require a significant discount for liquid-fired generation to take the place of natural gas. Any carbon cost will hit the liquid generation portion of a dual-fueled generator much more so than the natural-gas portion, diminishing the advantage a dual-fueled generator has, and increasing wholesale power prices more so than regions that do not depend on petroleum liquids generation for peak loads.
From an economic perspective for generators, winners will include nuclear, hydro, and wind generation units where revenues are determined by the clearing price of the most expensive dispatched generator. These units will see increased revenues with rising clearing prices, but flat generation costs. On a dollar-per-megawatt-hour basis, natural-gas units will tread water primarily by absorbing the cost but being compensated to nearly the same degree. Losers will be coal and liquid generation units that will see cost increases outstrip the increases in power prices. Coal will be hit doubly for both off peak and peak as nuclear generation comes on line, growing the “clean stack” for off-peak power and squeezing coal out of hours where spark spreads are now still strong.