Natural gas as a near-term CO2 mitigation strategy.
Sean Casten is president and CEO of Recycled Energy Development. Email him at firstname.lastname@example.org.
Discussions on CO2 reductions tend to start from a presumption of near-term economic disruption coupled with long-term investments in green technology. The presumption isn’t right. Simply by ramping up our nation’s generation of electricity from underutilized natural gas plants and ramping down our generation from coal, the United States could reduce its total CO2 footprint by 14 percent to 20 percent tomorrow with no disruption in access to energy services and no new infrastructure investments. The Waxman-Markey proposal to reduce CO2 emissions by 17 percent over 10 years is constrained only by its ambition.
The scale and potential for immediate impact deserves consideration, as even partial action toward this goal would have dramatic political and environmental consequences, establishing U.S. leadership and credibility in global climate negotiations.
About half of U.S. electricity is produced from coal, while roughly 20 percent comes from gas. However, this is caused by operations, not installations. The U.S. coal fleet runs most of the time, while (comparatively larger) gas plants tend to run intermittently, only during those hours when the lower cost coal/nuclear/hydro is unable to serve the full needs of the electric grid.
Thus, even though coal contributes far more to our current electricity needs, the existing gas fleet has a much larger potential to meet future needs.
Today’s gas fleet mostly was built out after the electric regulatory reforms of the late 1990s—and to a significant degree, it isn’t used. Take, for example the capacity factors1 of the gas and coal fleets. While the coal fleet tends to run, and run often, the gas fleet does not.
Therein lays the potential. A driver stuck in traffic might glance enviously at an empty commuter train buzzing past the highway; likewise, one should take a closer look at the potential to shift electricity generation away from a dirty, congested and comparatively small resource and into one that is larger, cleaner and comes with a lot more legroom.
Why doesn’t the gas fleet run more often? This simple answer is fuel price. Natural gas historically has been more expensive than coal, giving an economic advantage to coal-fired generators (see Figure 1).
However, the price of fuel isn’t the price of electricity. Electric price is a strong function of fuel cost, but also depends on operating costs and fuel conversion efficiencies. Fuel conversion efficiencies tend to be higher for gas plants relative to coal—and this advantage is growing with time, steadily eroding the coal fleet’s fuel cost advantage (see Figure 2).
The steady reduction in MWh/ton of coal has been caused by a shift toward low Btu, compliance coals, but also towards an increasing parasitic load on plants to operate Clean Air Act-mandated pollution-control devices. Meanwhile, there exists a technology-driven steady increase in MWh/scf of natural gas.
Broadly speaking, the U.S. gas fleet consists of three distinct technologies: 1) gas-fired steam boilers; 2) simple-cycle turbine plants; and 3) combined-cycle turbine plants with heat-recovery steam generators and steam turbines on the back end. Combined cycles are by far the most efficient of the three technologies, and were the preferred technology in the late 1990s fleet build-out.
In upcoming years, the coal fleet is likely to get less efficient as the inexorable bias towards lower-quality coal and tighter environmental standards continue. Moreover, as the gas fleet ramps up, it will preferentially favor combined cycles—the most efficient part of the fleet. Combined cycles today only run 35 percent of the time.
Given a 35-percent current capacity factor on 223 GW of capacity, the potential exists to produce an additional 1.3 million GWh/year from the existing combined-cycle fleet. The heat rate on this fleet—7,434 Btu/kWh in 2008—is likely lower on the margin, due to efficiency penalties at partial load.
How does this compare to the coal fleet? The most efficient coal plant in the country has a heat rate of 9,100 Btu/kWh—meaning that the plant consumes 2,000 more Btus of fuel for every kWh of output than does the combined-cycle gas turbine fleet. The rest of the coal fleet is worse.
To increase the operation of the U.S. combined-cycle fleet, the least efficient coal plants would be turned off first. These plants require nearly 15,000 Btu/kWh. Subsequently, more efficient facilities would be idled. CO2 emissions would fall as a function of the fixed differential in fuel carbon content and variable differential in the efficiency of each marginal generating station.
This has implications for electricity price. By taking the fuel price history (see Figure 1) and calculating the electricity-generation cost—given a 7,100 Btu/kWh marginal heat rate on the combined-cycle fleet and an 11,500 Btu/kWh marginal heat rate on the coal fleet (see Figure 3)—the higher value on the coal fleet shows the vulnerable coal plants on the margin. While it isn’t representative of the entire fleet, it indicates the point at which—on fuel price alone—there’s an economic logic to drive a shift in the dispatch order.
During the early and mid 1990s, there was a long period during which—had the current combined-cycle fleet existed—it would have been dispatched preferentially ahead of the marginal coal fleet. This further explains the explosion in gas fleet construction in the latter half of that decade. Not only were markets finally liberalized to allow greater private sector investment, but investors had reason to believe that there was an arbitrage opportunity from those combined cycles. Subsequent gas price spikes left many of those assets underutilized, but the fleet is now there, capital costs sunk, waiting for another opportunity. That opportunity might be here now, even before any consideration of CO2 pricing.
But CO2 prices could well prove to be the final straw, as shown by the CO2 price required to shift the dispatch over a range of gas and coal prices (see Figure 4).
At current gas and coal prices, the break-even point already is reached. Moreover, even if gas returns to the $5 to $7/MMBtu price implied by current NYMEX futures, a carbon price of less than $30 a ton would shift the dispatch decisively toward natural gas-fired generation. With a price on carbon of between $15 to $30 a ton, power from natural gas can become significantly cheaper than coal.
Next are the environmental consequences. As a fuel, natural gas contains 40-percent less carbon than coal.2 Once differential generation efficiencies are factored in, electricity from natural gas releases 60-percent less CO2 than electricity does from coal.
So how much of the coal fleet could the gas fleet displace? Shutting off the U.S. coal fleet would require utilizing the entire combined-cycle fleet and increasing the operation of a portion of the less efficient gas generators to a 58-percent capacity factor. At that level, the overall capacity factor for gas would be at 72 percent, about where the coal fleet stands today.
Ramping up existing combined-cycle plants to full capacity would reduce total U.S. CO2 emissions by 14 percent. Increasing utilization of the less efficient portions of the gas fleet up to the level required to shut off all the nation’s coal plants would reduce U.S. CO2 emissions by a whopping 20 percent.
Because such meaningful reductions could be accomplished tomorrow, practically with the flip of a switch, they immediately call into question the ambition of current proposed regulations to seek a 17-percent reduction over 10 years.
Limitations and Uncertainties
This opportunity clearly is subject to constraints beyond the simple size and power output of the gas and coal fleet.
The first issue is gas supply. The U.S. power sector today consumes 6.6 quadrillion Btus (quads) of natural gas per year, out of a total, economy-wide gas demand of 23.3 quads per year. Fully shutting down the entire U.S. coal fleet and replacing it with gas would increase the power sector as demand by another 16 quads per year, increasing total U.S. gas demand by 71 percent.
This raises obvious questions about gas supply and price. Such questions are particularly resonant in light of the recent shale developments that have drastically increased U.S. proven gas reserves and—according to their supporters—changed the dynamics of gas exploration in ways that could affect gas price and volatility. Whether these predictions materialize or not, it’s clear that any gas-coal shift ultimately will be constrained by gas price and supply.
At a minimum, this suggests the industry might be in the midst of a transition. Prior to the 1990s, gas prices tended to correlate with oil, as one swapped out the other as a heating fuel. That relationship has broken down in recent years and it raises the question of whether a period is beginning in which the gas-oil arbitrage is replaced by a gas-coal-plus-CO2 price arbitrage. In any event, supply constraints are no reason not to start this switch; they simply set limits on how far it’s possible to go.
A second issue involves gas and electric transmission constraints. Significant limiting factors on the ability to fully execute a coal-gas swap are the geographical distribution of gas assets and limited transmission capabilities. Those parts of the country that are heavily dominated by gas or coal generation won’t be able to fully effectuate this switch without compromising electric power availability, absent upgrades in transmission capacity. Fully quantifying this limit requires a more detailed analysis of the electric power grid. However, as a first approximation, consider a map of the United States ranking states only by the ratio of their gas-coal generation capacity (see Figure 5).
A high ratio (e.g., green states depicted in Figure 5) implies that a state is dominated by gas, and therefore likely to run into overvoltage problems if it increased local gas generation. By contrast, a very low ratio (e.g., the light orange states) implies the state is dominated by coal, and therefore unlikely to be able to bring in gas-fired generation to maintain grid stability if it were to shut down coal plants.
A gas-coal switch is unlikely to be realized in the coal-dominated Appalachian and Montana-Utah regions, nor in the gas-dominated Northeast and California regions. But for much of the country, it does appear viable. Interestingly, the states with a particularly high coal or gas concentration comprise a fairly small fraction of the total coal fleet.
States with extreme concentrations of coal or gas-fired electricity—e.g., greater than 90 percent—represent less than 20 percent of the total coal fleet. Thus, it would appear on first glance that gas and electric transmission constraints are unlikely to reduce this opportunity by more than 20 to 30 percent—and even that limit theoretically could be addressed with transmission system upgrades.
Third, long-term and demand considerations will affect the coal-to-gas transition. There are two obvious limitations of this analysis:
• It doesn’t address the question of what will be built in response to carbon pricing, only how to change operation of existing assets; and
• It’s a supply-side assessment that assumes no change in current electricity demand.
Note that both of these limitations would, if factored in, give greater significance to energy efficiency, both with respect to more efficient new generators (i.e., the lowest cost source of new generation) and with respect to demand-side measures that would lower the total demand. By reducing the relative demand for upstream fossil fuels, the inclusion of such measures would make it easier to achieve the transition described herein.
Finally, political constraints play a significant role; indeed, perhaps the most important factor. The current climate debate again has proven the political aphorism that “losers cry louder than winners cheer.” As E&E Daily reports, coal-fired utilities spent $35.1 million lobbying Congress in the first quarter of 2009 alone, while the entire gas industry spent just $3.3 million during the same period.3 Indeed, the gas industry trade associations publicly have all but conceded that they were non-players during the Waxman-Markey negotiations.
This political reality is unlikely to change much, even as the gas industry raises tens of millions of dollars for a more robust lobbying and public relations effort. The coal industry knows exactly how much it stands to lose, and can be expected to play an appropriately aggressive defensive strategy. This will surely lead to any number of carve outs and protections on a federal and local level that will limit the ability of this shift to occur.
No Silver Bullet
A coal-gas swap is by no means a silver bullet for climate policy. The long-term stability of the climate demands massive success on multiple fronts given the size of our collective environmental footprint. However, the potential for this switch to immediately lower CO2 emissions is larger than any other near-term solution—short of slashing people’s access to energy. On that basis alone, it deserves attention.
1. Total actual annual generation divided by (generator nameplate x 8760 hours/year). All raw data for this and subsequent data come from DOE/Energy Information Administration unless otherwise noted.
2. ~115 lbs/MMBtu for natural gas vs. ~200 lbs/MMBtu for coal.