For a century, coal-fired power plants have generated most of the United States’ base-load electricity. At times along the way, alternatives emerged and flourished briefly—first oil-fired generation, then nuclear, and most recently natural gas. But these waves ended badly, often bringing financial ruin to the companies that had championed them too enthusiastically. Meanwhile, the more-cautious companies that kept on building coal-fired plants have survived and prospered.
Now, coal faces more uncertainty than any other base-load generating source. Two new factors, hitherto irrelevant to the U.S. industry, will shape future generation investment—imports of liquefied natural gas (LNG) and greenhouse-gas (GHG) restrictions. Taken together, they point to a bleak future for coal unless its technology advances dramatically … or a political consensus fails to emerge.
A decade ago, global warming was fodder for stand-up comics on late-night television. This year, both of the front runners in the Democratic campaign for president have endorsed draconian long-term restrictions on GHG emissions (reductions of 80 percent from 1990 levels by 2050). And the presumed Republican nominee, John McCain, has endorsed restrictions nearly as severe. Significant legislation seems more likely than not in the 2009 to 2010 time period, even if its exact shape is now unclear.
If GHG emissions are restricted, the burden of adjustment likely will fall on the nation’s fleet of coal-fired power plants. Other sectors of the economy would continue expanding their emissions as they grow, albeit at a slower rate due to CAFE limits, etc., while the coal-fired fleet brings down its emissions far enough and fast enough to offset capacity expansion and still meet economy-wide reduction targets.
The reason is economic. In most sectors, reducing the emissions from a stationary source requires separating out and sequestering the greenhouse gases from its flue-gas stream. The cost of doing that with today’s technology generally exceeds $90 to $100 per ton sequestered. (Note: All dollar quantities are expressed in 2007 dollars and all greenhouse gas quantities are expressed in tons of CO2 equivalent.) However, the power-generation sector has another alternative available—replacing existing coal-fired plants with new-built plants using an alternative generation technology with much lower GHG emissions, such as natural-gas combined cycle.
At current prices, the all-in cost of doing so amounts to only $30 to $40 per ton of GHG emissions avoided. So regulators have strong incentives to meet their emissions targets by squeezing coal-fired plants nearly to extinction before significantly restricting other stationary sources.
That could happen fairly rapidly. If U.S. emissions merely are capped at 2006 levels with no actual reductions, then expansion elsewhere in the economy would cause about half of today’s coal-fired production to be replaced over the next 20 years (see Figure 1). And more aggressive targets would lead to correspondingly faster replacement.
Other considerations will help accelerate this transition. In particular, Phase II of the Clean Air Act takes effect in 2010, requiring nearly 200 additional existing coal plants to retrofit to reduce sulfur dioxide and nitrogen oxide emission levels. The additional pressure of prospective GHG restrictions makes those investments even less attractive.
The logic of GHG regulation cuts both ways. Most politicians favor implementing GHG restrictions through some sort of economy-wide cap-and-trade scheme that puts a market price on GHG-emission allowances. But at what price? The lowest price that will hold economy-wide emissions flat (much less reduce them) must be high enough to motivate the replacement of existing coal-fired plants. At today’s natural-gas prices, that means emissions allowances trading at $30 to $40 a ton or higher. Conversely, an allowance price in that range will motivate ample volumes of conversion, so the price need not go much higher for many years. In effect, the price of natural gas sets the price of emissions allowances, over a fairly-wide range.
This is happening in other jurisdictions. The European Union (EU) has imposed a broad-based cap-and-trade program on its GHG emissions. That program had a clumsy start, with an unsustainable level of emission allowances issued in the first round. But it now has moved to a second round, with allowances more closely managed. The market has priced these second-round allowances at $30 to $40 a ton, because the cost of converting from coal to natural gas is roughly the same in Europe as it is in North America.
It’s worth noting how all this would concentrate America’s response to greenhouse gases in a few key regions. The mix of coal-fired generation ranges from about 80 percent coal-fired in ECAR and MAPP down to around 15 percent in California, New York and New England generally. In particular, an economy-wide cap-and-trade program would have coal-light regions buying up emissions allowances from coal-heavy regions, which would use the proceeds to fund conversion away from coal.
California’s current dilemma illustrates this point nicely. The state has essentially no coal-fired generation within its borders, and only imports a limited amount of coal-generated power. Yet California recently has launched an initiative to roll its GHG emissions back to 1990 levels by 2020—an anticipated 25 percent reduction. If this reduction must come from actually abating in-state sources such as industrial plants and vehicle tailpipes, then the abatement costs likely will run to $100 a ton or more. But if in-state sources can meet their reduction targets by paying for abatements in coal-fired generation elsewhere, then the same GHG reduction can be achieved for only $30 to $40 a ton. (It remains uncertain if California will accept such out-of-state abatements as an integral part of its GHG program.)
Of course, predictions of coal’s decline assume alternative generation technologies and fuels will be available at reasonable costs—natural gas, or perhaps nuclear. For natural gas, the sticking point is supply availability at a reasonable price.
Historically, a price spread has existed between coal and natural gas. In the 1990s, when the dynamics of both markets were driven by push supply rather than pull demand, the spread varied between $1.00 and $1.50 per million Btu (MMBtu). At that spread, natural gas promised a cheap, abundant and clean alternative to coal. Low gas prices, relatively low plant construction costs, and growing public concerns over environmental issues made gas-fired plants the technology of choice. Investment in new coal-fired plants stopped for almost a decade, while natural-gas combined-cycle capacity increased rapidly.
The resulting boost in consumption, combined with declining traditional production, significantly increased natural gas prices to $7 to $8 from $2 to $3 per MMBtu in the late 1990s. While coal prices also have been under pressure from global demand and associated transportation costs, the coal-to-gas spread nonetheless has risen to about $5 per MMBtu.
At these prices, natural gas generation is uncompetitive versus conventional coal, even excluding GHG issues; it would have to decline to between $5 and $6 (see Figure 2). But such price levels are unlikely based on North American sources, due to sustained demand from industrial consumers, physical production declines, weather-driven disruptions, and seasonal demand uncertainties. In fact, core-reserve depletion, combined with the increased reliance on non-conventional production, will lead to future lower levels of production.
Thus, while North America historically has been self-sufficient in gas, that’s changing. Incremental supplies will come in the form of LNG imported from overseas. The International Energy Agency anticipates the United States will import about 6 trillion cubic feet a year of LNG by 2030—about equal to the amount of additional natural gas needed to replace coal-fired generation under a flat-emissions restriction.
As the source of incremental supply, LNG likely will set the long-term price for all U.S. natural gas. But LNG is a globally-traded commodity with a more-or-less global price like crude oil, not a collection of separate local and regional markets like electricity. So the U.S. will be a price taker in this global market.
For at least the next few decades, the incremental global demand for LNG will continue to be for power generation—as it will be in the United States. Nuclear generation stands as the principal economic alternative to natural gas as a source of low-GHG electricity, putting an effective cap on LNG prices globally.
Of course, nuclear’s prospects in any jurisdiction depends as much on political and social factors as they do on economic questions. For example, France generates 80 percent of its electricity from nuclear, while neighboring Germany anticipates phasing out its remaining nuclear generation. But the global nature of the LNG market makes the nuclear alternative effective everywhere. In other words, if the global price of LNG (and the linked price of GHG emissions) rises too far, then some jurisdiction somewhere in the world will shift its next power plant from gas-fired to nuclear, and all jurisdictions will benefit from the resulting price cap.
In short, the emerging global market for LNG helps ensure that the United States has an alternative to coal-fired generation that’s acceptable from both an economic and a political standpoint. And that makes it less likely that regulatory pressure on greenhouse-gas emissions will abate.
Uncertainty about future U.S. policy towards greenhouse-gas emissions has proven more burdensome to the electricity sector than any actual policy that’s likely to be adopted. For some years, new generation-capacity development has been at a standstill, with more capacity additions being cancelled than announced. Last year that eased somewhat, with a significant increase in new generating-capacity announcements. Interestingly, coal is a key component, but the number of corresponding cancellations demonstrates widespread uncertainty. The commitment toward gas, nuclear and renewables has been aggressive and appears poised to overtake coal (see Figure 3).
Europe provides a current example of the uncertainty that blights investment. The original European scheme for restricting GHG provided assurance that existing facilities would have a gradually decreasing stream of emissions allowances without charge. Now Brussels is considering whether to auction off the allowances rather than award them to existing sites. The economic consequences are huge for existing sites with stranded investments. And the prospect that any new-build plant could become similarly stranded must stand as a deterrent to potential investors.
The future of coal-fired generation, under most commonly discussed carbon regimes, appears bleak based on the extremely high cost of separating post-combustion GHG from a flue-gas stream using today’s technology. Over the long term, prospects for carbon capture and sequestration (CCS) could improve dramatically. Effective CCS technology should be available for about $30 a ton sometime after 2020, versus about $100 a ton today.
More broadly, coal gasification could offer a potential pathway for employing coal that avoids the need for expensive post-combustion separation. Unfortunately, traditional gasification technologies with CCS will become economic only when natural gas prices exceed $11, compared to $7 to $8 today. And as discussed, alternatives such as nuclear generation make sustained gas prices that high seem unlikely.
Non-traditional catalyzed gasification technologies may be emerging that could provide a pathway from coal to natural gas at perhaps $5 per MMBtu with CCS. Today, these technologies exist only at lab-bench scale, but their potential for an extraordinary impact should not be overlooked. That impact would cut two ways. On one hand, it would revive the fortunes of coal mining, replacing LNG as the source of incremental gas supplies. On the other hand, it would accelerate the shift away from conventional coal-fired generation.
In a recent “carbon war game” exercise among seven major U.S. investor-owned utilities, GHG restrictions triggered a transition away from coal-fired generation, driving up real electricity prices by 5 percent a year for a decade in the coal-heavy markets (see “Carbon Wargames,” Fortnightly, December 2007). War game participants broadly agreed that increases of that magnitude would set off a political firestorm. How likely is such an outcome, and how likely is it to trigger a reversal of GHG policy?
The answer seems to depend heavily on the details of the GHG-restriction program. If it consists of a national economy-wide cap-and-trade program, and existing power-plant operators receive a continuing allocation of emissions allowances proportional to their historical emissions, only stepped down gradually in proportion to the national cap, then the burden will be fairly limited. In effect, the rest of the economy will subsidize the transition to non-coal generation by purchasing allowances from the departing coal plants. However, if the cap-and-trade is not economy-wide, or if the allocations largely are auctioned off, then the burden will fall directly on the coal-heavy regions. And the resulting price fly-up likely will cause a vigorous push-back from both households and businesses in the affected areas. This is not an unlikely scenario and strengthens the resilience of traditional coal—changing the game.
National security also may raise a whole different political issue. On one hand, increasing LNG imports would make the United States’ economy—and the larger world economy—ever more dependent on uninterrupted supplies from some of the world’s most politically unstable regions. On the other hand, the United States and the world already depend on the same regions for exports of petroleum liquids, so how much additional risk do LNG imports really impose?
Additionally, these projections anticipate business as usual largely will continue in both commerce and politics. That could change. If the intertwined issues of energy affordability, energy security and climate change achieve enough political salience, the federal government (and others) might commit large-scale resources to advancing the relevant technologies rapidly. Breakthroughs in the separation of greenhouse gases, or catalyzed coal gasification, could re-arrange the playing field quickly.
If and when GHG restrictions materialize, there’s little doubt that much of the burden will fall on coal-fired generation. With today’s prices and technologies, that would lead to substantial shrinkage of the coal-fired power fleet over the next two decades. Non-traditional gasification and CCS technologies hold promise for altering that path, but so do reinvigorating nuclear development, expanding renewables and intensifying demand management. The main dilemma for most utilities and generation developers is handicapping this technology race, as well as the associated politics. In short, it’s easier to envision the world of electricity generation after 2030 than to find a satisfactory strategy to get there.