Good Riddance to the Clean Power Plan

Now … Can We Please Have a Serious Conversation about a Sensible Policy that Works for Both Sides?

The Trump Administration has wheeled the Clean Power Plan back into the garage, and clearly plans to remove the wheels and motor, take a cutting torch to whatever’s left, then ship the pieces to the scrapyard. This has prompted cheers of approval from the Right, and howls of anguish from the Left.

It’s not quite that easy, of course. A bedrock principle of administrative law holds that an agency cannot simply rescind or change rules issued by a previous administration. So the Environmental Protection Agency (EPA) must assemble a record supporting any change to the existing Clean Power Plan (CPP), which is likely to take several years. And all the while, the agency will be fighting a guerilla war — in the courts of law, and in the court of public opinion.

This is deeply unfortunate, for two reasons.

First, although the CPP may have a lot of symbolic value (likewise Trump’s order to withdraw it), it was not a particularly meaningful or well-designed program.

Second, unless we’re careful, the years about to be spent wrangling in the courts and the Congress and the media over the Clean Power Plan’s repeal and/or replacement could be lost years. Those years could (and should) be spent identifying (and then doing) things on which both Left and Right can agree — developing and implementing policies to modernize the parts of America’s electricity infrastructure that desperately need attention,

The danger here is that everyone loses.

Absent an outbreak of common sense and bipartisan policy-making in Washington, the rancor that will attend EPA’s reconsideration of the CPP will likely make rational conversation all but impossible, even though there’s common ground aplenty. There are clearly policies and programs that can meet the Left’s legitimate desire for long-term, sustainable reductions in carbon emissions and, at the same time, meet the Right’s equally legitimate need to create investment and jobs, modernize aging critical infrastructure and, yes, preserve a role for coal in the nation’s energy portfolio.

For the sake of argument, let’s stipulate that climate change is a serious threat. That it will lead to sea-level rise, more severe weather events, billions of dollars in property damage. That it is a geopolitical threat, an additional source of global stress, as vast numbers of displaced people compete with their neighbors for access to basic necessities, and as nations jockey over rights to resources in places like the Arctic that are newly accessible. That it increases the likelihood of failed nation-states, which are breeding grounds for terrorism.

Structurally Flawed and Insufficiently Aggressive

Even accepting those impacts, and worse, it’s difficult to mourn the CPP’s passing. Leaving aside the plan’s byzantine complexity, which would have made compliance a nightmare, the CPP was structurally flawed, and did little to reduce carbon emissions beyond what could be expected to occur anyway as a result of market forces.

First, the structural flaws. The CPP set state-by-state compliance targets, expressed either in terms of carbon intensity (i.e., pounds of CO2 per megawatt-hour) or in tons of CO2. The first was a “rate” limit; the second, a “mass” limit (derived from the rate limit). In its rate-setting formula, EPA ignored the one-third of the existing electric system that is zero-carbon — all nuclear, hydropower, wind and solar built before 2012. Although ignored when calculating compliance, EPA assumed that this portion of the electric system would simply continue to operate indefinitely.

Any program to reduce carbon emissions that would allow carbon-free generating capacity to be replaced with carbon-emitting generating capacity without penalty is obviously poorly designed and, to be blunt, a bit of a charade.

This led to some unexpected outcomes, particularly with nuclear power, which represents almost two-thirds of the carbon-free electricity in the United States. Under the Clean Power Plan, a state could allow existing nuclear power plants to shut down, and replace them with new gas-fired power plants that met the CO2 emissions limit for new gas-fired generating capacity. The result? The state would comply with its CPP rate-based obligation, but its carbon emissions would increase dramatically.

Any program to reduce carbon emissions that would allow carbon-free generating capacity to be replaced with carbon-emitting generating capacity without penalty is obviously poorly designed and, to be blunt, a bit of a charade.

Even if this, and other, unintended consequences had been fixed in the final regulation, the plain fact is that the CPP was not particularly aggressive. Although widely advertised by the Left as “transformative” and by the Right as a “war on coal,” it was neither.

Roughly 40 gigawatts (GW) of US coal-fired capacity retired between 2012 (the base year for the CPP) and the end of 2015, forced out of the market by low-cost natural gas and EPA’s MATS (Mercury and Air Toxics) rule. Consensus estimates are that another 40-GW-or-so of coal-fired capacity will retire by 2022 (when compliance with the CPP was scheduled to begin), and another 30 GW by 2030.

Before Units 2 and 3 at the San Onofre nuclear plant in southern California closed in 2013, the CO2 intensity of California power production was around 0.5 pounds (lb) per kilowatt-hour (kWh), according to analysis by IHS Energy. Replacement power from in-state gas-fired power plants had associated emissions of about 0.9 lb per kWh; from the rest of the Western Interconnection, 1.5 lb per kWh; from wind and solar in California backed up with gas-fired power plants, 0.7 lb per kWh. So under any scenario, the power that replaced San Onofre had higher carbon emissions. But under the Clean Power Plan, California would face no penalty for having increased its carbon emissions.

These shutdowns will be driven by (again) low-cost natural gas and a huge expansion of renewables. The renewable boom is driven partly by dramatic improvements in cost and performance of wind turbines and solar photovoltaics; partly by state mandates, and partly by federal tax policy. Thanks to the extension of the federal wind production tax credit and the solar investment tax credit at the end of 2015, construction of new wind and solar facilities will more than double beyond what had been expected. Without the tax extension, about 60 gigawatts of new renewable capacity would be built in the next five years; with the extension, almost 140 GW.

A number of analyses conducted after the final CPP was published in October 2015 demonstrated that the CPP did little more than institutionalize the status quo. For example:

  • M.J. Bradley Associates, an environmental consulting firms, modeled a number of mass-based compliance options (using the same model EPA used), and the model produced very low allowance prices — $0 per ton in 2025, and a range from $0 to $6.05 per ton in 2030. Allowance price is a proxy for severity. The stricter the program, the higher the allowance price. Just for reference, the carbon tax proposed in February by former Cabinet members George Schultz, James Baker and Henry Paulson, among others, would start at $40 per ton.
  • One large electric generating company was approached during last year’s election campaign by the Clinton campaign, which recognized the lack of rigor in the CPP and was soliciting suggestions for how to encourage states to “overcomply” with the CPP — i.e., go beyond the plan’s targets. The company’s modeling showed that the CPP’s limits on CO2 emissions should be 20% lower to ensure CO2 reductions beyond “business as usual.” This worked out to an allowance price of about $12 per ton in 2022 when compliance started.
  • Another large consulting firm conducted a detailed state-by-state analysis of CPP compliance, and distilled the results into two maps of the United States — one assuming the states chose to comply with the CPP’s rate goals, the other assuming they chose the mass goals. The states were color-coded, according to the degree of challenge they faced: either green (limited to no additional effort), orange (moderate additional effort), or red (substantial additional effort). The maps are overwhelmingly green. If the states chose rate compliance, only six states were red; nine were orange. Under mass-based compliance, only seven states were red; eight were orange. (This analysis was proprietary to the company’s clients, so best not to divulge the company’s name. But anyone with even a passing acquaintance with energy and environmental policy would recognize the firm as one of the most capable in the field.)

This is not to say that CO2 emissions won’t be lower in 2030 than today. EPA’s modeling shows CO2 emissions lower by about 400 million tons year, but most of that reduction is the result of market forces, not regulatory constraints.

Stalemate or Solutions?

So America has a choice.

We can have several years of divisive, pointless wrangling over a Clean Power Plan of dubious value.

Or we could have a rational, even-handed conversation about what should be done to modernize America’s electricity infrastructure, leading to policy solutions on which the Left and Right can both agree.

If the latter, the question, then, is this: What parts of the infrastructure need attention? Although the American Society of Civil Engineers graded America’s energy infrastructure a D+ in its recent report card, parts of the electricity infrastructure are in reasonably solid shape. For our purposes here, “solid shape” means significant capital investment is occurring.

Capital investment by America’s investor-owned power companies has increased steadily over the last 15 years — from approximately $40 billion a year in the early 2000s to about $120 billion a year today. Where, then, are the gaps?

Transmission and distribution should not be cause for concern.

Capital investment in transmission and distribution (T&D) has grown steadily over the last 15 years. In 2016, investor-owned companies pumped a little over $50 billion into T&D. Transmission alone has grown from approximately $4 billion a year in the early 2000s to the $20-billion-a-year range. This is partly owing to supportive rate-setting by the Federal Energy Regulatory Commission (FERC) authorized by the 2005 Energy Policy Act.

Equally important, though, T&D are “safe” businesses because they’re regulated by FERC or the states, and the companies are guaranteed the opportunity to recover their costs, plus a return. The entire electricity industry today is in full flight from the (much riskier) generating side of the business. So it’s safe to assume that T&D investment will continue because business fundamentals are driving companies in that direction. It’s a low-risk way to produce the steady earnings and dividends that investors expect.

On the generating side of the business, there are no grounds for concern about investment in gas-fired generating capacity, or in midstream infrastructure to support that generating capacity, or in deployment of wind and solar energy facilities.

Over the last five years, natural gas, wind and solar have dominated additions to new generating capacity. Of 113,000 megawatts of generating capacity added over the last five years, gas accounted for 42,000 MW, wind for 35,000 MW and solar for 22,000 MW — 87 percent of the total.

Investment in renewables will continue, thanks to the extension of the wind production tax credit and the solar investment tax credit at the end of 2015, and continuing state initiatives to ratchet up renewable portfolio standards.

Investment in gas-fired generating capacity will also continue because it’s the lowest-risk option available to a sector that’s generally about as risk-averse as it’s possible to be. Similarly, investment in gas transmission infrastructure is not a concern. In a study last year, ICF Inc. concluded that future (i.e., post-2020) midstream investment will be lower than it has been recently, thanks to healthy levels of investment ($40-$50 billion a year) between 2010 and 2015. “After 2019, the investments for gas infrastructure are much lower … because new capacity installed in 2015–2019 is sufficient to support a large portion of projected [natural gas] production growth. Therefore, average investments after 2020 are about a quarter of the investments during 2016–2019,” ICF found.

(One side note: If there’s a constraint on electric and gas transmission, it’s not capital investment. It’s siting and permitting.)

The Investment Gap

So where, then, is the problem? Where is investment not occurring?

Nuclear and coal.

The U.S. electric system consists of approximately one million megawatts of generating capacity. Almost two-thirds of that is over 30 years old, and much of the older capacity consists of coal-fired and nuclear plants. These two sources represent roughly one-half of America’s electricity supply.

This is a big problem for two reasons. First, these two sources represent roughly one-half of America’s electricity supply and thus can’t simply be ignored.

Second, the U.S. electric system consists of approximately one million megawatts of generating capacity. Almost two-thirds of that is over 30 years old, and much of the older capacity consists of coal-fired and nuclear plants.

Both sources of electricity have a big role to play in any workable, credible program that balances the interests of both sides to the climate change debate. Both sources need capital investment — and policy initiatives to stimulate that capital investment — to do so.

The Nuclear Power Challenge

By 2030, several nuclear power reactors in the U.S. will have been generating electricity for 60 years. By 2040, half the nation’s nuclear fleet will have turned 60. Some of this capacity — maybe as much as one-half of it — will seek a second license renewal to operate past 60 years. But this generating capacity must be replaced eventually. And anyone concerned about CO2 emissions and climate change, or the value of fuel and technology diversity in the electricity portfolio, or regaining America’s leadership position in global nuclear governance should want retiring nuclear assets replaced with new nuclear plants.

Replacing today’s nuclear reactors will be a challenge — a bigger challenge than is commonly recognized by policy-makers, and one the U.S. electric power industry is generally content to ignore.

Other carbon-free sources cannot fill that hole. This is not a criticism of other carbon-free sources — simply a recognition of scale. Consider: The four new 1,100-megawatt nuclear reactors now being built in Georgia and South Carolina will produce about as much electricity in a year as the entire nation produces from solar photovoltaics (roughly 36 billion kilowatt-hours). America’s nuclear power plants produced about 800 billion kilowatt-hours of electricity last year. The Energy Information Administration’s Annual Energy Outlook doesn’t expect wind and solar to approach that level until 2035. So it will take the next 20 years for wind and solar to approach where nuclear energy is today.

Replacing today’s nuclear reactors will be a challenge — a bigger challenge than is commonly recognized by policy-makers, and one the U.S. electric power industry is generally content to ignore. It involves:

Providing sufficient incentive to keep operating nuclear plants operating— New York and Illinois have figured this out, by providing “zero emission credits,” similar to the renewable energy credits provided to wind and solar. Ohio, Pennsylvania, New Jersey and Connecticut need to figure it out, too.

Providing a financial incentive to companies that pursue second license renewal — Preparing a nuclear power plant for operation past 60 years will require capital investment — likely on the order of $1 billion to $1.5 billion — to replace major components and systems and perform other upgrades necessary to ensure safe, reliable operation beyond 60 years. Some form of tax benefit or production credit would provide a signal that these plants are valuable assets and should be preserved.

Continuing to Build New Nuclear Power Plants — The mere thought of building new nuclear power plants sounds counterintuitive, given the difficulties with construction of Vogtle Units 3 and 4 in Georgia and Summer 2 and 3 in South Carolina. Painful though they are, however, these teething pains are the inevitable consequence of a 30-year hiatus in reactor construction. The surest way to tackle these challenges — and reduce the cost of new nuclear plants — is to build more. And yes, the economics can be made to work, partly with innovative project structures and financing, supported by the loan guarantee program created by the 2005 Energy Policy Act. The “old-fashioned” way — projects developed and financed by a single, relatively small company, or even a small group of relatively small companies — simply won’t work. “Business as usual” is a bankrupt concept.

Creating New Ways to Finance Research, Development, Demonstration — The advanced nuclear technologies now on the drawing board hold enormous promise, but financing their development and demonstration is an equally enormous challenge. The Secretary of Energy Advisory Board last year recommended a $10-billion program, and that appears to cover the cost of demonstrating only a single advanced reactor concept. Even spread over 10 years, a $1-billion-a-year program is much larger than any program currently contemplated. Funding for advanced reactors in the 2016 fiscal year was $141 million. The Obama Administration requested $109 million for FY2017; the 2017 budget just approved by Congress provides $132 million. As with new nuclear plant construction, there’s no way “business as usual” — i.e., annual appropriations — will generate the amount of money required. Even if it could, prudence dictates another approach. The appropriations process lacks the stability necessary to execute programs that may take a decade to reach fruition. And worse, the annual appropriations dance has been corrupted by influence-peddling and rent-seekers. The spoils in that game do not always belong to those technologies most likely to succeed in the marketplace. Here, too, a different business model is required.

The Challenge with Coal

For those concerned about climate change, nuclear energy is a relatively easy sell. After all, it’s carbon-free. But coal? Those concerned about climate say: “Why coal? Coal’s dirty. We have coal on the run. Why bother?”

Why bother? Because even if America leaves its coal in the ground, the rest of the world won’t. Coal is abundant and low-cost, and construction of coal-fired power plants presents no technical or financial challenges. “There are many uncertainties with respect to global climate change,” says Howard Herzog, a senior research engineer at the Massachusetts Institute of Technology and one of the co-authors of MIT’s 2007 report on The Future of Coal. “But there is one thing about which I have no doubts: we will not solve climate change by running out of fossil fuels.”

So there’s an enormous global imperative for development, demonstration and large-scale commercial deployment of technologies that capture (and use or sequester) the CO2 released during combustion. The United States could (and should) lead the development of those technologies. They represent an export opportunity. Even if Trump Inc. doesn’t think climate change is a problem, the rest of the world does.

On the Right, those anxious to preserve existing coal-fired generating capacity in the United States, and to create a foundation for new coal-based generation, should embrace carbon capture use and storage (CCUS). It represents the only way to make coal socially and politically acceptable. And it may slow the bleeding — continuing replacement of existing coal-fired power stations with gas-fired combined cycle plants.

According to the International Energy Agency, the two largest contributions to cumulative emissions reductions in the 2DS (two degree scenario) over the period 2013–50 would come from end-use fuel and electricity efficiency and renewables. Carbon capture and storage (CCS) would come in third place, followed by nuclear.

On the Left, those concerned about climate change and CO2 emissions should also embrace CCUS. This suite of technologies, processes and infrastructure is an essential tool to limit global warming to 2 degrees C. In 2014, the Intergovernmental Panel on Climate Change (IPCC) concluded that, without CCUS, the cost of climate change mitigation would increase by 138%. In its Energy Technology Perspectives 2016, the International Energy Agency (IEA) found: “The two largest contributions to cumulative emissions reductions in the 2DS [two degree scenario] over the period 2013–50 would come from end-use fuel and electricity efficiency and renewables. Carbon capture and storage (CCS) would come in third place, followed by nuclear.”

Like all credible analyses, work by the IEA consistently shows that it will take a portfolio of technologies to hold global temperature change below 2 degrees C, and that CCS must be part of that portfolio. In the 2-degree-scenario, IEA says, “the total CO2 capture and storage rate must grow from the tens of megatonnes of CO2 captured in 2013 to thousands of megatonnes of CO2 in 2050.”

CCUS is not just about CO2 produced during power generation. Industrial CO2 emissions must be addressed, too. Almost one-half of the CO2 that must be captured between 2015 and 2050 in the 2-degree-C scenario is from industrial processes, according to the IEA. In the United States, electric power accounts for about 35% of CO2 emissions; industry for almost 20%. Data from the Clean Air Task Force notes that “if China’s industrial emissions (about 3,300 million tonnes) were their own country, they would rank 3rd overall [in the world]. If the industrial emissions (937 million tonnes) in the U.S. could be separated into their own country, they would rank 6th.” And virtually none of these non-power industrial applications could be replaced by renewables.

It’s also a lot less costly to scrub CO2 out of industrial processes because CO2 concentrations in the gas stream are higher. The cost of CO2 removal rises as the CO2 becomes more dilute. So it’s cheaper to strip CO2 from a coal-fired plant’s flue gas than a gas-fired power plant (see chart above).

Where to Look for the Future of Coal. The future of coal can be found partly in places like Estevan, Saskatchewan; Thompson, TX; Decatur, IL, and Port Arthur, TX.

  • In Saskatchewan, SaskPower, the provincial utility, is capturing CO2 at the 115-megawatt (MW) Unit 3 of its Boundary Dam power plant. The goal is 90% removal, or one million tonnes a year of CO2. Most of the CO2 goes to the Weyburn oil field about 40 miles away (supplementing CO2 captured at the Great Plains coal gasification plant just across the border in North Dakota) where it’s used for enhanced oil recovery (EOR). A small amount of the CO2 captured is sequestered in a saline formation about two miles deep, part of a test program. According to the Global CCS Institute, the carbon capture unit was on line about 85% of the time on average in 2016, and captured about 800,000 tonnes of CO2.
  • In Thompson, TX, just southwest of Houston, NRG in January started up a unit to capture CO2 from the 240-MW Unit 8 at its W.A. Parish power plant. Like Boundary Dam, the goal is 90% removal and the CO2 will be piped about 80 miles and used for enhanced oil recovery. The cost of the so-called Petra Nova project was about $1 billion (and it was delivered on time and on budget).
NRG’s W.A. Parish power plant is the largest fossil-fueled plant in the United States — nine units generating 3,653 megawatts. Units 1–4 and 9 are gas-fired; units 5–8 (2,462 MW) run on Powder River Basin coal. The Petra Nova project, a joint venture between NRG and JX Nippon Oil Exploration, started up in January and scrubs CO2 from Unit 8’s flue gas. The plant’s coal-fired units are also equipped with selective catalytic reduction for NOx control and baghouses to control particulate emissions. Unit 8 also has flue gas desulfurization equipment installed. Photo: NRG.
  • In Port Arthur, TX, Air Products has retrofitted carbon capture technology on two large steam methane reformers, which produce hydrogen. The goal: 90-plus-percent carbon capture; the compressed CO2 is used for enhanced oil recovery. Project cost: about $431 million, of which DOE paid $284 million (in funds provided by the American Recovery and Reinvestment Act). The Air Products project has been operating for several years and, last June, shipped its three millionth tonne of CO2 to the West Hastings oil field.
  • In April, Archer Daniels Midland started up a carbon capture unit at a plant in Decatur, IL, that processes corn into fuel-grade ethanol. The project will produce about one million tons of CO2 a year, which will be injected into an underground saline reservoir. This $208-million project ($141 million from DOE) has a lot of firsts: the first to receive a Class VI CO2 injection well permit from EPA; the largest saline storage project in the United States; the first to use leading-edge technologies downhole (courtesy of Schlumberger, among others) in the disposal wells to verify that the CO2 is staying put.

Good News, Bad News

In conversations with the companies involved in these projects and other experts in the field, a number of common themes emerge. There’s good news and bad news.

The good news. CO2 recovery from coal-fired power plant flue gas is not particularly challenging. The basic process is widely used to remove CO2 and hydrogen sulfide (H2S) from natural gas and other refinery gases, and a number of companies supply CO2 capture systems. Boundary Channel uses a Shell system; Petra Nova, a Mitsubishi system.

Most operate with amine solvents (amine is a derivative of ammonia), which have a natural affinity for CO2 and H2S. Basically, the “sour” gas (in a refinery or gas processing plant) or the flue gas (in a power plant) is routed into the bottom of a vessel (like the distillation columns in refineries). The flue gas rises through the column; the amine solution flows down from the top. As it does so, it scavenges the CO2 from the flue gas. Clean flue gas flows out of the top of the tower; “rich” amine solution (“rich” in CO2), out of the bottom. The rich amine solution is heated, and the heat forces the CO2 out of solution. The CO2 is condensed and cooled and the “lean” amine solution, now stripped of CO2, is recycled and the process repeats.

Good news: What’s a pollutant in the power industry is a valuable commodity in the oil industry, although the value depends on oil prices. More good news: Oil producers are short on CO2.

More good news: What’s a pollutant in the power industry is a valuable commodity in the oil industry, although the value depends on oil prices. Primary production from an oil field (relying on natural reservoir pressure and pumps) typically recovers about 10% of the oil in place. Waterflooding and steamflooding can recover another 20–40%. So as much as 70% of the oil is still trapped below ground. Unlike water, which does not mix with oil, CO2 does, thinning the oil and allowing it to flow to the producing wells. At the Weyburn field in Canada — the destination for CO2 from SaskPower’s Boundary Dam project and the Great Plains synthetic fuels plant — EOR with CO2 drove production from 8,000 barrels per day (b/d) to 30,000 b/d. At the surface, the oil and CO2 are separated and the CO2 reinjected.

IEA studies show that as much as 140 billion tons of CO2 could be sequestered in oil reservoirs through CO2 EOR. That works out to a net emissions reduction of about 88 billion tons (because the oil produced through CO2 flooding releases carbon when burned). But 88 billion tons is non-trivial: It’s more than 40 times current U.S. power sector emissions of CO2.

Large-scale CO2 EOR was first demonstrated in the Permian Basin of West Texas in the early 1970s and has been used extensively there since the mid-1980s. Oil producers in the Permian Basin buy more than 1.7 billion cubic feet a day (35 million tons per year) of CO2, transport it through 3,400 miles of CO2 pipelines, and produce more than 65 million barrels of oil annually using EOR techniques. Occidental Petrolum, in particular, is heavily committed to EOR using CO2 flooding in the Permian Basin, and plans to invest over half-a-billion dollars in CO2 floods in its Permian acreage over the next several years.

Even more good news: Oil producers are short on CO2. They get limited supplies from natural gas processing facilities. Most of it comes from natural CO2 reservoirs in New Mexico and Colorado (although, from a climate perspective, there’s no gain from producing CO2, piping it to an oilfield, then reinjecting it). Analysis a few years ago by Tenaska for a new 600-MW coal-fired plant with carbon capture (later abandoned) noted: “After nearly two decades where available CO2 supplies to the Permian Basin outpaced demand from CO2 EOR projects, since 2005 there has been a shortfall of CO2 supply.” Worldwide demand for CO2 for EOR could increase 4–6 times by 2050, according to one IEA analysis — from 60,000 million tons per year (mtpy) today to 240,000–360,000 mtpy.

IEA studies also show that as much as 140 billion tons of CO2 could be sequestered in oil reservoirs through CO2 EOR. That works out to a net emissions reduction of about 88 billion tons (because the oil produced through CO2 flooding releases carbon when burned). But 88 billion tons is non-trivial: It’s more than 40 times current U.S. power sector emissions of CO2.

The Bad News. CO2 capture from flue gas is expensive. There’s a substantial capital cost associated with the carbon capture technology — approaching the $1-billion-range for Petra Nova (although that included the cost of the CO2 pipeline). Then add operating costs and the energy penalty (the parasitic load to power the carbon capture unit). Project developers are extremely coy about releasing project-specific cost data, but there’s rough agreement among the experts.

DOE’s Office of Fossil Energy puts the cost of CO2 capture from existing coal-fired power plants at $60-$70 per tonne. Another expert says CCS on an existing coal-fired plant adds $70-$80 per megawatt-hour (MWh) to the plant’s generating cost. That would push total generating cost to the $100-per-MWh range, which would not clear in any U.S. market, absent some policy support.

Revenues from the sale of CO2 offset some of this additional cost, but not all.

As with nuclear energy, the right combination of policies, incentives and project structures could drive substantial CCS deployment. And there’s a good bit of political interest.

It’s difficult to generalize from the Petra Nova project, due to its unique project structure. This was a highly structured financing. NRG and its partner, JX Nippon Oil and Gas Exploration, each put in about $300 million. The Department of Energy added $190 million. The two Japanese export credit agencies — Japan Bank for International Cooperation (JBIC) and Nippon Export and Investment Insurance (NEXI) — provided $250 million in debt. The carbon capture unit was financed with $127-million in tax-exempt private activity bonds issued by the county.

NRG sidestepped the energy penalty by building a dedicated gas-fired plant to power the carbon capture unit. And rather than just selling the CO2 to Hilcorp., which owned the West Branch field about 80 miles away, the NRG/JX Nippon joint venture owns the CO2 pipeline and took a 50% equity stake in the oil field. So Petra Nova generates revenue from the sale of CO2 and from the sale of oil produced by the CO2 flooding. The word on the street suggests that Petra Nova is “in the money” as long as oil prices stay above $50 per barrel.

Unique though it is, the Petra Nova project suggests a path forward for CCS. As with nuclear energy, the right combination of policies, incentives and project structures could drive substantial CCS deployment. And there’s a good bit of political interest. For example:

  • In its 2017 budget request, the Obama Administration proposed a 30% investment tax credit for CCS equipment, and a tax credit of $50 per ton for CO2 that’s sequestered, $10 per ton for CO2 that’s used for EOR.
  • Rep. Michael Conaway (R-TX) has approaching 50 cosponsors for his Carbon Capture Act (H.R.4622 in the last Congress). It would make the existing Section 45Q tax credit (enacted in 2008) permanent, and remove the restrictions that have limited the 45Q credit’s value. (It’s limited to 75 million tons of CO2 sequestered; the recipient must own the facility from which the CO2 is captured and inject the CO2; and the credit cannot be transferred.) Conaway’s legislation would also increase the value of the credit to $30 per ton (from $10 per ton today).
  • Sens. Heidi Heitkamp (D-ND) and Sheldon Whitehouse (D-RI) introduced the Carbon Capture Utilization and Storage Act (S.3179 in the 114th Congress) to increase the 45Q credit to $35 per ton for EOR and $50 per ton for sequestered CO2. It would also lift the 75-million-ton cap and make the credit transferable.
  • Sens. Rob Portman (R-OH) and Michael Bennet (D-CO) introduced legislation (S.2305) to allow the use of tax-exempt private activity bonds (which lower the cost of capital) for CCS equipment. Private activity bonds were widely used to finance flue gas desulfurization equipment at power plants in the 1990s.
  • And members in both houses of Congress have introduced legislation to make CCUS facilities eligible for Master Limited Partnership (MLP) status. MLPs are tax-exempt structures that should increase access to capital. On the Senate side, Sen. Chris Coons (D-DE) has taken the lead (S.1656); in the House, Rep. Ted Poe (R-TX) with H.R.2883.

These policy incentives — particularly new and improved 45Q credits and the private activity bonds — enjoy remarkable support from a coalition of institutions that do not always see eye to eye. The coalition includes environmental organizations like the Clean Air Task Force; foundations like ClearPath (the conservative clean energy organization founded by Jay Faison); at least three major coal companies; oil companies (like Occidental) with a big interest in enhanced oil recovery; labor unions, and others.

A section 45Q credit of $35 per ton for EOR, $50 per ton for sequestration produced about 10 GW of CCS by 2030, about 15 GW by 2040. But a case that assumed achievement of the cost and performance goals of DOE’s CCS program, plus the more generous 45Q credit, produced almost 30 GW of CCS by 2030, and nearly 50 GW by 2050.

The consensus holds that the right combination of incentives would drive substantial CCS deployment — perhaps as many as 100 retrofit units in the power sector, as well as new coal- and gas-fired construction, according to John Thompson, director of the Clean Air Task Force’s Fossil Transition Project. And Thompson believes that building more will drive down costs and drive up innovation in new capture techniques. The combination of more generous 45Q credits and private activity bonds would have a “multiplier effect,” says Rich Powell, ClearPath’s executive director, leading to as much as 50 gigawatts (GW) of generating capacity fitted with CCS.

Their judgment is confirmed by modeling conducted last year by the Department of Energy. DOE’s Office of Energy Policy and Systems Analysis retained OnLocation, an energy consulting firm, to model the impact of various combinations of incentives. In one case, DOE assumed a more generous 45Q credit of $35 per ton for EOR, $50 per ton for sequestration. That produced about 10 GW of CCS by 2030 — mostly retrofits to existing coal-fired capacity — and about 15 GW by 2040. Another case assumed the more generous tax credit plus achievement of the cost and performance goals of DOE’s CCS program (CO2 capture cost reduced from $60-$70/tonne today to $30-$40/tonne). That case produced almost 30 GW of CCS by 2030, and nearly 50 GW by 2050.

The Importance of Research, Development, Demonstration

Not surprisingly, meeting the cost and performance goals of DOE’s CCS program had a big impact on the amount of deployment forecast by the modeling. This raises another issue: the adequacy of DOE’s research, development and demonstration programs.

Like the agency’s nuclear energy RD&D program, the fossil energy program seems to be underfunded.

DOE’s fossil energy R&D budget typically runs in the $600-million-a-year range. About one-third of that goes to run the National Energy Technology Lab, for program direction and other overheads. That leaves about $400-million-a-year for basic research, pilot and demonstration projects. In its most recent (July 2015) Advanced Coal Technology Roadmap, the Electric Power Research Institute and the Coal Utilization Research Council recommended $570 million a year during 2016–2020; $940 million a year during 2021–2025, and $493 million a year between 2026 and 2035.

In a report to the Secretary of Energy in 2015, the National Coal Council noted that “the DOE programs have consistently been inadequately funded and, as a result, DOE programs for deploying CCS are not as effective as they can be and should be.”

This echoes a finding in the Massachusetts Institute of Technology’s 2007 report on The Future of Coal: “At present government and private sector programs to implement on a timely basis the required large-scale demonstrations … are completely inadequate …. the level of funding [for the DOE clean coal program] falls far short of what is required.”

A problem identified in 2007 that still exists in 2015 is clearly a chronic condition that requires something more than a “business as usual” solution.

Productive Middle Ground?

“Regardless of who’s president, the trend toward CO2 reduction is going to continue,” says Clean Air Task Force’s John Thompson — either because the states move in that direction, because the electric power industry turns its back on new coal-fired generation (already happening), or because of international agreements. “So the question is: How do you get people into the productive middle ground?”

This much is clear: If current trends continue, U.S. power companies will continue to shut down coal-fired power plants and replace them with gas-fired combined cycle plants. If you care about the climate, what would you prefer? A new gas-fired power plant that emits 816 pounds of CO2 per megawatt-hour (MWh)? Or an existing coal-fired plant with 90% carbon capture that emits 280 pounds of CO2 per MWh? Or how about a new supercritical pulverized coal-fired unit with 90% carbon capture that emits 243 pounds of CO2 per MWh? (Emissions factors courtesy of Clean Air Task Force.)

The math is pretty simple and compelling, even for the arithmetically challenged among us. (And remember: It’s easier and cheaper to scrub CO2 out of the flue gas from a coal-fired power plant than it is to scrub CO2 out of a gas-fired plant’s flue gas.)

In order for any of this to work, however, two things must happen first. One side must choke back the bile that rises in their throats whenever someone utters the words “climate change.” The other side must suppress the fury that boils up inside whenever someone says the words “coal” or “fossil fuel” or “nuclear power.”

For lack of policies to encourage investment, the U.S. nuclear energy and coal sectors are both starved for capital to (1) extend the useful lives of existing nuclear assets; (2) extend the useful lives of existing coal-fired power plants by reducing their carbon emissions; (3) do the research and development necessary to demonstrate advanced coal and nuclear technologies, and (4) deploy those advanced technologies when today’s legacy assets are retired.

A well-structured program to address these four challenges would satisfy the need on one side to reduce carbon emissions, and the need on the other side to (1) preserve coal and nuclear energy and the jobs that go with them, and (2) create hundreds of thousands of new jobs in engineering, construction and equipment supply.

The United States has a limited period of time to create the policy conditions necessary to develop and build the new nuclear and clean coal technologies that will be needed in the 2020s, 2030s and beyond. A few of the policy tools needed are in place; most are not. Continuing down the same path as today, hoping that “business as usual” will deliver a desirable future, is delusional, magical thinking.

In order for any of this to work, however, two things must happen first.

One side must choke back the bile that rises in their throats whenever someone utters the words “climate change.”

The other side must suppress the fury that boils up inside whenever someone says the words “coal” or “fossil fuel” or “nuclear power.”

Then perhaps we can have a rational conversation.

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