How do you get Americans to pay for something they don’t really want in the first place? Most of the time – as in the case of New Coke, Harley Davidson Perfume, and the U.S. Football League – the answer is simple: you can’t.

But where the Edsel failed, corn ethanol has somehow succeeded. Despite its drawbacks (which are legion – a point we’ll get to later), more than 13 billion gallons of corn ethanol were sold in the United States last year.

How did it happen? Corn ethanol has outlived Pepsi AM and the Betamax because its backers hit upon a three-part recipe for success: a huge dose of federal subsidies mixed with high gas prices and untethered rhetoric.

For decades, ethanol producers have promised that their product will revitalize America’s farming communities, end our dependence on foreign fuel, save the environment, and lower gas prices. Presumably a product that good would sell itself, but the federal government rigged the market anyway by creating the Renewable Fuel Standard (RFS), the Volumetric Ethanol Excise Tax Credit (VEETC), and a host of other measures worth billions of dollars each year to the biofuels industry. The RFS mandates a nine-fold increase in the amount of biofuels used in the US (from four billion gallons in 2006 to 36 billion gallons by 2022), while the VEETC gave away tax breaks to companies that add ethanol to gasoline (even though Americans were already required by the RFS to consume that ethanol).

Mercifully, the VEETC expired at the end of 2011, but the ethanol lobby quickly fixed its sights on a new target. In order to produce, distribute, and sell the rapidly growing volume of ethanol mandated by the RFS each year, the biofuels industry needs to develop a new, ethanol-specific infrastructure. And, true to form, it would prefer that the government pay for it. In particular, the industry now wants funding to install ethanol-friendly blender pumps at gas stations around the country.

Cue Congress. In late April, the Senate Agriculture Committee passed a Farm Bill that included $800 million for energy-related programs. The largest component of the proposed package is $241 million for the Rural Energy for America Program (REAP), which previously helped farmers improve their energy efficiency, install solar panels, and conduct energy audits. This year, thanks to aggressive lobbying by the ethanol gang, REAP has a new function. In late 2011 – just before VEETC finally expired – the Department of Agriculture began approving the use of REAP funds to defray the cost of blender pumps. USDA’s decision to repurpose REAP was endorsed by key members of Congress during the recent discussions around reauthorization of the Farm Bill.

Why are policymakers so invested in ensuring the success of corn ethanol? According to U.S. EPA’s own 2011 Triennial Report, continued production of corn ethanol will have significant negative consequences for air and water quality, soil conservation, and habitat preservation. EPA data also show that the corn ethanol being sold in 2012 emits more greenhouse gas over its lifecycle than gasoline. In 2009, Clean Air Task Force analyzed EPA’s data and found that the lifecycle greenhouse gas emissions from the additional corn ethanol produced pursuant to the RFS will exceed those from gasoline until 2054.

Meanwhile, for all the flag-draped rhetoric coming from its backers, corn ethanol simply cannot provide energy independence. Already, more than forty percent of corn grown in the United States is turned into ethanol. If all of the corn grown in the United States in 2011 had been used to make ethanol, it would have offset national gasoline consumption by just 18 percent.

Finally, the ethanol lobby’s contention that corn ethanol is dramatically reducing the price of gas is wrong. The study they cite depends on a mix of mistaken and unrealistic assumptions about petroleum refiners’ ability to react to supply disruptions. Moreover, their claim conveniently ignores a fact that’s critically important to consumers: a gallon of ethanol provides only two-thirds as much energy as a gallon of gasoline. Once these factors are taken into account, it becomes clear that the price reductions being trumpeted by industry fall somewhere between negligible to nonexistent.

These flaws and others are catalogued in a letter recently circulated by a bipartisan group of Congressmen. From their perspective, the RFS is a “broken policy” that damages the economy, pushes up food prices, and degrades natural resources. Using REAP funds to underwrite blender pumps will only exacerbate these problems. If Congress and the Administration are going to continue to require Americans to buy corn ethanol, the least they could do is ask the ethanol companies to pay the freight.

Two years ago the world turned its attention to the Gulf of Mexico and the tragedy that was unfolding there, with the explosion of the Deepwater Horizon drilling platform. This disaster brought a reinvigorated focus to the safety of offshore drilling, but the term safety must now be understood to not just cover spills and leaks, but also the impacts that drilling has on the climate, especially when done in the fragile environment of the Arctic.

It is well understood that carbon dioxide emissions from fossil fuel combustion in our cars and power plants are responsible for the majority of earth’s global warming. Less appreciated, though, is that methane emissions account for nearly half as much of the warming we are currently experiencing as carbon dioxide. The oil and natural gas industries are the largest source of methane emissions from the US. Oil and gas extraction can also be significant sources of black carbon, another potent climate pollutant.

Changing technology and climate change itself, with receding Arctic ice, have made oil and gas production activities in the Arctic region more feasible. This trend is expected to accelerate, with the potential for vastly more methane and black carbon emissions. According to the United States Geological Survey (USGS), the Arctic holds one-fifth of the world’s undiscovered, recoverable oil and natural gas. As the ice retreats, oil and gas developers are moving in to exploit previously hard-to-access resources. Melting has also enabled increased shipping activity through the region, further elevating concerns over emissions in the region.

The Arctic is particularly vulnerable to climate change impacts, where, according to the Intergovernmental Panel on Global Climate Change (IPCC), Arctic temperatures have increased at about twice the global average rate over the past 100 years. September 2011 represented the largest retreat of Arctic sea ice on record, opening wider the fabled Northwest Passage to ship traffic.

Methane is an extremely potent climate pollutant, packing 25 times the punch of carbon dioxide when compared over a 100-year lifetime and 72 times its potency over a 20-year lifetime. Natural gas and oil production is one of the largest human-caused sources of methane, representing 20% of global anthropogenic methane emissions. Black carbon too, punches above its weight as a climate pollutant, but its major impact in the Arctic is hastening melting by depositing heat-absorbing black soot on white ice surfaces. Emissions from gas flaring, diesel engines, and shipping associated with gas and oil operations also represent potentially large in-region sources of black carbon. If oil and gas production is to occur in the Arctic, we must ensure that emissions of CO2, methane and black carbon are held to a bare minimum.

While oil production is the primary focus of current exploration and production activities due to high oil prices, natural gas is almost always produced along with oil, posing the problem of what to do with it. Crude oil usually contains some amount of “associated” natural gas that is dissolved in the oil or exists as a cap of free gas above the oil in the geological formation. In some cases, this represents a large volume of gas. For example, nearly 3 trillion cubic feet (Tcf) per year of gas is produced in association with oil in Alaska. The largest potential source (but by no means the only) of either methane or black carbon from oil production is the disposition of this “associated” natural gas.

When pipelines are available, the natural gas can be delivered to industrial, commercial and residential consumers. If there is no pipeline to bring the gas to market and no local use for the gas, then the “stranded” gas has little economic value and is often flared. While flaring the associated gas destroys most of the methane, it also creates a large source of CO2 and can create black carbon. Estimates of the volume of associated gas flared are substantial, with estimates showing as much as 5.3 trillion cubic feet of gas being flared each year. That’s about 25 percent of the US’s annual natural gas consumption. This leads to the release of approximately 400 million tons of CO2 per year, the equivalent to the emissions from over 70 million cars.

Fortunately, technologies and best practices exist to reduce the impact of oil and gas production. If we are going to extract the oil from the Arctic, we must do it in a way that does not exacerbate the very real problem that climate change is already posing there. In order to do so, the US should take the lead in ensuring that only the best practices are acceptable when it comes to Arctic exploration and drilling. The technologies and practices below can dramatically reduce the emissions associated with oil and natural gas, in some cases by 100%.

First, we need better characterization of emissions in the region, and better monitoring and reporting information. Methane and black carbon emissions from oil and natural gas production, especially in the Arctic, are not well characterized. Establishing standardized monitoring and reporting protocols, backed by legislation, is essential to quantifying these emissions and then adopting the best mitigation techniques.

Second, we must deal with the methane and black carbon from associated gas and well completions.

This means capturing all associated and completion gas (i.e., no venting). Where feasible, all gas should be sent to consumers through pipelines or LNG or beneficially consumed on-site or locally (for power generation or thermal or feedstock uses). Or, where geologically feasible, we should require reinjection of the gas into underground reservoirs. When there is no reasonable alternative to flaring, we should require the use of efficient flares.

Next, we need to deal with vented and fugitive methane emissions. Here we need vapor recovery units on storage, process tanks and floating production, storage and offloading units. Operators should use compressed air or electric control systems rather than pneumatic controllers, mitigation of methane emissions from all dehydrators should be required, and the use of wet seal compressors without gas capture systems should be prohibited. To detect leaks and equipment failures, we should require inspection and maintenance programs for all facilities operating in the Arctic.

Finally, for the mitigation of black carbon emissions, we should require ultra low sulfur diesel (ULSD) and Diesel Particulate Filters (DPF) for all stationary engines and small ships – either new or retrofit. And we should push to establish International Maritime Organization requirements for BC emission reductions for international shipping affecting the Arctic.

The opening of the Arctic to increased oil and gas development is a cause for concern. The Arctic is already being hammered by climate change and other environmental impacts. If we are on the verge of an Arctic oil and gas rush, this will only add to the issues facing this fragile environment. If we implement the above policies domestically, and pressure our other Arctic neighbors to do the same, we will greatly reduce, but certainly not eliminate, the air and climate impacts of oil and gas development in the Arctic.

Last week, EPA announced New Source Performance Standards (NSPS) for the oil and natural gas industry. These new rules are an important and long-awaited step towards better control of the air pollution emitted by this rapidly expanding sector.

Notably, the standards include the first federal air pollution regulations for hydraulically fractured (fracked) natural gas wells. That, plus new regulation of other equipment in this industry, represents significant progress in combating air pollution, especially as forecasts project increasing reliance on natural gas for generating electricity. Without these rules, air pollution from new gas wells and equipment would continue to increase; now the industry must begin to clean up nationwide. Once the rule finally goes into full effect, VOC emissions, a precursor of ground-level smog, will be reduced by hundreds of thousands of tons per year; toxic chemicals like benzene will be reduced by 12,000 – 20,000 tons per year. And, as a co-benefit of the pollution control measures needed to achieve the new standards, emissions of methane will be reduced by 1.0 – 1.7 million tons a year. This rule therefore eventually will provide significant air quality and climate benefits.

The bad news is that the rule has some substantial gaps. The worst gap is a two and a half year delay of the requirement to “green-complete” fracked wells – a process that prevents emission of pollutants into the atmosphere. EPA found that green completion is the best system of emissions reduction for these wells – but that it can’t be required until January 2015. This is dismaying because it is unnecessary. The technology for green completions consists of a set of tanks and traps, mounted on trucks, which use gravity to separate the natural gas from fracking fluids and solids. If it sounds simple, that’s because it is. It’s also cheap. Owners of over 1,600 wells have reported costs equaling less than $20,000 per well. That’s before accounting for the revenue generated by selling the natural gas that this technology captures. In fact, green completion actually makes money for natural gas producers. Even with gas prices very low right now, the required equipment rapidly pays for itself, and using it prevents vast amounts of pollution. Green completions are cheap and easy and in several states they’re already required.

So why wait until 2015? Well, the industry made many arguments to delay, and even to eliminate, the green completion requirement. However, CATF and others have demonstrated these arguments are without merit. For example, last fall the American Petroleum Institute (API) – an industry advocacy group – told EPA that only 200 sets of the equipment needed for green completions can be fabricated per year. Did we mention that this is fairly simple equipment? The petroleum industry has deployed vast amounts of equipment in shale gas basins over the past few years – for example, drilling thousands of wells and installing almost a hundred compressor stations in one year in a single state – Pennsylvania. The notion that this industry cannot fabricate more than a few hundred sets of tanks and traps a year is just not credible.

As even API acknowledges, 300 sets of completion equipment exist today. Using their recent figure for the number of wells which require fracking – 25,000 wells a year (up from 20,000 wells per year in their November comments) only 700 more sets of completion equipment are needed, since a single set can be used on 25 wells per year. EPA’s final estimate is that almost 13,000 gas wells are fracked a year, so by that figure, only 220 new sets are needed. Either way, a one-year delay would have been very sufficient for the gas industry to obtain the required equipment, which pays for itself, and enables the capture of serious air pollution. This industry does not lack for financial resources. As such, it is CATF’s position that the 2.5-year delay is simply not justified on the facts.

Now, EPA did not leave fracked wells entirely unregulated during the delay period – and that is a good thing, as vented wells are astoundingly dirty. In the interim, EPA has required the gas producers to flare, or burn off, the waste natural gas at fracked wells. But the final rule fails to impose any limits or requirements on the practice to ensure that flares burn cleanly to reduce emissions. To be sure, flares will eliminate a lot of methane emissions and reduce certain VOCs. But it will replace those emissions with carbon dioxide, smoke and other deadly particulates, NOx, and other unhealthful air pollutants. Clearly, flaring does not eliminate the air pollution problems experienced by people living nearby who already suffer from the impacts of drilling. It is not adequate, much less state of the art pollution control, as EPA recognized when basing the standard on the use of green completion techniques.

What’s more, EPA also determined that other sources in the industry, like conventional gas wells, oil wells, and existing natural gas equipment, will remain unregulated. For example, EPA has given the whole transmission and storage segment of the natural gas industry a hall pass. These are the interstate pipelines that move natural gas around the country. Again, this weakening from the proposed rule responded to industry arguments – they claimed that air pollution from pipelines and storage facilities is too diluted (with methane!) to be regulated. The additional reductions in VOC and methane that would have resulted from regulating that part of the industry would have come at only modest costs. It is unfortunate that natural gas transmission and storage, which emits over 2 million tons of methane and 65,000 tons of VOC a year, will not be covered at all under these rules.

We’ll probably be hearing a lot about the costs of this rule. The costs of the rule are very low – in many cases, like green completions, the required measures conserve gas for sale which can offset the cost of the measure completely or in part. Nevertheless, industry has claimed very high costs – based on incorrect arguments. For example, API has used the wildly inflated figure of $180,000 per green completion, which they got by arguing that each set of equipment would need to be rented for 30 days per well. But no producer has ever reported actual costs even approaching that number. Moreover, API’s estimate is based on the unreasonable idea that equipment must be separately rented for at least 30 days for each separate well, despite the fact that gas producers are drilling multiple wells on single pads that all can be completed one after the other. Well completion takes about a week, so there is no need to rent equipment for 30 days per well. API’s figure is based on that flawed assumption (and others) and is too high.

In short, EPA’s new oil and gas rule is a big improvement over the status quo but is weaker than current technology and economics allow. We will be working to defend the standards against further attacks (rhetorical and otherwise) based on the inconsistent and inaccurate claims that we have seen already. CATF also intends to continue working with EPA, states, industry partners, and our NGO partners to achieve further emissions reductions from the oil and gas industry. Few other sources of air and climate pollution can be cleaned up as rapidly and cheaply as this one, and that’s where our focus will remain.

Methane – the primary component of natural gas – is both a valuable fuel and a potent pollutant, 25 times more potent than carbon dioxide as a driver of climate change over a 100-year period. The methane emissions from U.S. oil and gas operations warm global climate as much as 16% of all the CO2 from U.S. coal-fired power plants. With a strong rule, those emissions will be cut by a quarter, so EPA clearly has an excellent opportunity to begin to address this dangerous climate pollutant.

Moreover, because all government and private forecasters project an increase in natural gas use for generating electricity, demand for natural gas will continue to increase, including natural gas produced from hydraulically-fractured (“fracked”) wells. Using “green completions” or “reduced emission completions” (RECs) on fracked wells can help avoid release of both conventional and methane pollution that otherwise will skyrocket as fracking booms all over the country. So at the heart of the final standards must be the requirement to capture the burst of pollution from newly fracked and refracked natural gas wells using “green completion” technology.

Yet, even though EPA has shown that green completions could actually make money for the gas industry, as they can ultimately sell the captured natural gas from a green completion, industry lobbyists are claiming that the cost of green completion is too high. Industry further claims that gas streams containing less than 10% volatile organic compounds (“VOCs,” pollutants which pose significant health risks to the public) are insignificant and should not be regulated. And, they advocate for flaring, saying that simply burning the methane and VOCs released upon fracking would be sufficient.

All of these assertions are false – and alarming for those who care about the climate and health impacts of this industry. Gas releases containing less than 10% VOCs are, in fact, quite significant when hundreds of tons of gas are being released into the air in a short time. And VOC tonnage from these sources is very substantial, and capturing it also captures quite a lot of climate-damaging methane. Flaring is a very crude and ineffective solution when green completion is a readily available and inexpensive technology. Flaring is certainly not the “best system of emissions reduction” as required by law.

Moreover, the methane emitted to the air during the fracking process is so damaging to the environment that it should be regulated on its own. EPA’s proposed rule does not do that – but at the very least, the methane co-benefits of regulating conventional smog-causing pollution must not be lost through a weakened rule.

This week, CATF and others sent a letter to the White House insisting that the Administration stand firm in issuing strong performance standards for the oil and gas industry — the first federal limits on air pollution from fracked natural gas wells. All of the measures required under these standards are common sense, in use already in states like Colorado and Wyoming, and they are cost-effective. Weakening the standards, as industry advocates, will allow the release of very large amounts of dangerous air pollution – pollutants that form ozone smog, and that contribute to climate change. This pollution is a threat to our children, our communities and our planet.

EPA must resist the calls by industry lobbyists to weaken the oil and gas performance standards. If the Agency does not, public health and climate threats will dramatically increase as the natural gas drilling boom expands into new shale gas regions of our country. Now more than ever, we need a strong NSPS rule.

Last week, the Administration took a bold step forward to curb greenhouse gas emissions. In a long-anticipated action, EPA proposed new source performance standards (NSPS) for fossil-fueled power plants that would limit emissions from new plants to a rate of 1,000 lbs. of CO2 per megawatt-hour, averaged annually. This level is comparable to the annual average emissions rate of the existing fleet of U.S. natural gas power plants. The rule levels the playing field between coal and gas on greenhouse gas emissions, so new coal and gas plants will compete on price. When finalized, the rule will provide a much-needed and long-overdue step on the path towards full decarbonization of all domestic coal and gas power plants.

In the ensuing swirl of media coverage and stakeholder debate after the release of the draft rule, three key points must be considered:

• New coal plants can meet this standard using carbon capture and sequestration (CCS) technology, which is available and cost-effective today;
• Already, commercial CCS projects are in operation today, and several coal CCS projects under development can beat the proposed emissions standard;
• The regulatory signal provided by the proposed performance standards sets the stage for wider adoption of CCS technology.

All the key elements of CCS technology — capture, transport and sequestration of CO2 — for meeting the new standard are available and in use today. Scrubbers that can capture some or virtually all of the CO2 from smokestack emissions and synthesis gases have been available for decades and are already used today on coal and natural gas power plants. To transport the captured CO2, the U.S. has 4,000 miles of CO2 pipelines currently serving the enhanced oil recovery (EOR) industry, primarily in Texas. And, the U.S. oil industry has safely injected over a billion tons of CO2 since the mid 1970s into oil fields for enhanced oil recovery, and that CO2 remains trapped in the rocks that formerly held the recovered oil.

There are several examples of commercial carbon capture in the U.S., including carbon capture from a coal power plant in Trona, California and a natural gas power plant in Bellingham, Massachusetts, where the captured CO2 was used for commercial purposes.

In addition, for the past 12 years the Dakota Gasification plant in Beulah, North Dakota has captured up to 2 million tons of CO2 per year and piped it to the oil fields in Saskatchewan, where it is sequestered. And, there are several U.S. coal projects under development that incorporate CCS technology, including:

• Southern Company’s Plant Ratcliffe, a coal gasification power plant that is already under construction in Kemper County, Mississippi and will produce 524 MWe of electricity, but emit CO2 at a rate of about 550 lbs. per megawatt-hour of gross generation (“MWh” here)– below the proposed all-new source 1000 lbs./MWh performance standard — because it will capture 3.5 million tons of CO2 per year for EOR sequestration.
• Summit Energy’s Texas Clean Energy Project, another coal gasification plant, is expected to begin construction in the Spring of 2012 in Midland Texas, and will produce 195 MWe of electricity with a CO2 emissions rate of 228 lbs./MWh — well below the EPA performance standard, by capturing 2.5 million tons of CO2 per year for EOR sequestration.
• Tenaska’s Taylorville Energy Center, a proposed coal gasification power plant awaiting final permitting, is planned to produce 603 MWe of electricity annually while only emitting CO2 at a rate of 642 lbs./MWh — well below the EPA performance standard, by sequestering approximately 3.45 million tons of CO2 per year.

Figure 1 below compares the relative emission levels of these proposed plants with the EPA’s proposed standard.:

Figure 1. Source: Clean Air Task Force

EPA’s draft rule has broad implications for building coal or gas power plants and points the way to the future of zero-carbon fossil energy. Even without the rule EPA has proposed, developers today favor new gas plant construction because natural gas prices are at an all time low and natural gas plants have lower capital and operating costs than coal plants. And, while natural gas prices appear likely to remain low due to the current boom in unconventional gas development, that may not always be the case (see figures 2 and 3). EPA’s proposed standards provide an important hedge against future energy sector CO2 emissions, which is necessary to keep CO2 emissions down after the point when natural gas prices ultimately increase.

Figure 2. Source: Clean Air Task Force

Figure 3. Source: NYMEX

In addition to the important first regulatory signal provided by EPA’s proposal, there is latent commercial demand for CO2 that also can help move the CCS industry forward. According to a 2011 report by the National Energy Technology Laboratory, there is 20 billion tons of potential commercial CO2 demand related to enhanced oil recovery at existing on-shore oil fields in the U.S. This industry currently relies mostly on mined natural CO2. While there is not enough mined CO2 to meet that demand, new sources of captured anthropogenic CO2 from the power sector can. The EOR industry can utilize up to 94 GW worth of CO2 captured from coal-fired power plants over the next 30 years. This amount is substantially larger than the growth in base-load fossil power generation in the U.S. through 2035, as projected by the Energy Information Administration.

In short, the proposed standards provide the first-ever step in regulating the CO2 emissions from this leading emitting industry. They are not likely to change current power generation technology choices, but the new rules do provide an important limit for future emissions should the market swing back to coal power generation. And, because the standards by law must be reevaluated and revised periodically, and because existing source standards also must be evaluated now, EPA’s proposal also provides an important beginning to the much-needed process of reducing the carbon emissions from the entire fossil-fueled power sector. Clean Air Task Force therefore applauds EPA for proposing this rule and urges them to finalize it as soon as possible.

CATF commissioned a study on the environmental impacts of both new diesel and new CNG transit buses that concluded that while both have much smaller negative environmental impacts than the older buses currently in use, a new CNG bus is not necessarily better for air quality or climate impact than a new diesel bus. Specifically, the study found that while new CNG buses may have marginally lower particulate matter and volatile organic compound emissions, they may have higher greenhouse gas and nitrogen oxide emissions. Additionally, CNG engines are simply less efficient than diesel engines at traveling the same distance, which must be taken into account.

Importantly, most transit agencies have limited funding available for purchase of new buses. In a capital-constrained environment, the higher purchase price of CNG buses may limit the number of new CNG buses that can be purchased compared to new diesel buses, thus reducing the number of older diesel buses that can be retired, despite the potential for life-cycle cost savings as discussed above. For every $10 million of capital funding, a transit agency could purchase approximately 26 new diesel buses or 21 new CNG buses (and associated fueling infrastructure), and retire an equivalent number of old buses. Given that a greater number of older, high emitting buses could be retired, fleet-wide emission reductions of NOx, PM, and HC per dollar of capital funding could be 47%, 23%, and 11% higher, respectively, if new diesel buses are purchased than if new CNG buses are purchased. For climate impacts, assuming GWP20 factors to assess the short-term climate impact of CH4 and BC, annual fleet-wide reductions in GHG emissions would be 62% less from purchasing 21 new CNG buses than from purchasing 26 new diesel buses with $10 million in capital funding. However, assuming GWP100 factors to assess the long-term climate impact of CH4 and BC, annual fleet-wide reductions in GHG emissions (MT CO2-e) would be 18% greater from purchasing 21 new CNG buses than from purchasing 26 new diesel buses.

These climate results are dependent upon two very important assumptions. The first is the leakage rate of methane from natural gas production and transportation through pipelines. The method of natural gas production currently in use also produces non-trivial methane leakage and methane is twenty-five times more efficient at climate forcing than carbon dioxide. So, while the municipality using a CNG bus may not note fugitive methane leaking from the tailpipe, the methane leaked as a result of the production and transportation of the CNG that is running the bus will nevertheless be part of its environmental impact. Data on methane leakage rates, however, is poor and some studies have suggested that it might be lower than assumed. Additionally, CATF supports EPA setting performance standards for the oil and gas industry that could result in the reduction of methane leakage from gas production. Therefore this assumption could change in the future, potentially changing the conclusion as well. For example, if the leakage rate assumed in the CATF study were reduced by half, then these two types of engines would have comparable climate impacts.

The second variable assumption of the study, global warming potential (GWP), also has a significant impact upon the conclusion. Generally, GWP100 — the global warming potential likely over the span of 100 years – is the standard measurement for evaluating the impact of a pollutant. However, the climate forcing of two of the particular pollutants examined – methane and black carbon — is realized within a twenty-year span (GWP20). Using GWP20 in the analysis gives the advantage to new diesel buses. If the analysis employed GWP100, the climate impacts of the diesel and CNG buses would be comparable.

What’s driving the interest in CNG buses? Cost. The price of CNG fuel now is so low that even though the CNG buses are more expensive and less efficient than new diesel buses, the payback period is only a few years. Moreover, under the federal transportation funding formula, the federal government shoulders 80 percent of the cost of a new transit bus (compared to 20 percent for the local transit agency) while the transit agency typically pays 100 percent of the fuel cost. That creates a powerful incentive for a transit agency to choose CNG for their new buses, even though that may not necessarily be the best outcome for public health and the environment.

Enhanced Oil Recovery has been successfully utilized in West Texas since 1972, pumping pressurized CO2 deep underground into depleted oil fields to force up hundreds of millions of barrels of oil that would be otherwise not recoverable. During EOR, most CO2 is trapped in the rock., but because CO2 is both valuable and limited in supply, the CO2 that is not trapped returns to the surface mixed with the oil, and is separated, recycled and reused for additional EOR. Eventually, all the CO2 that is purchased by the EOR facility stays trapped in the micro-pores of the oil field, just as the oil was – deep below layers of impermeable caprock. Nearly a billion tons of CO2 have been safely injected since the practice of CO2 EOR began 40 years ago. EOR currently accounts for 281,000 barrels of oil per day, or 6% of our total domestic oil production. But, with next-generation technology, CO2 EOR could provide the U.S. with an additional 67 billion barrels of oil, and requiring 20 billion tons of CO2 to produce it – resulting in millions of additional barrels per day. Moreover, this figure could be much higher as new CO2 EOR oil reserves known as “residual oil zones” are proven. So what’s the holdup? Essentially, adequate supplies of CO2.

Meanwhile, abundant supplies of CO2 are being vented from industrial sources each year, trapping more and more heat in our atmosphere. For example, coal and gas power plants in the U.S. emit 2.4 billion tons to the atmosphere each year. And, according to a study last year by the National Energy Technology Laboratory, the EOR industry is facing 20 billion tons of unmet demand for CO2. If we could direct the CO2 from being emitted where it harms the climate to US oil fields, we would reduce CO2 emissions to the atmosphere while also reducing the amount of oil imported into the US. We would also begin broad deployment of a technology that is necessary for decarbonizing our energy system – carbon capture and sequestration (CCS). The potential scale of deployment for this technology will spur innovation and reduce costs.

To increase US EOR production and drive the deployment of low carbon energy technology, the NEORI study recommends a number of federal and state incentives, including tax breaks for CO2 capturers, such as power plant operators, and for transporters, including pipeline operators, to jumpstart the fledgling CO2 industry in this country. The recommendations include the development of a new tax incentive that would provide a tax credit for the first ten years for CO2 emitters who become CO2 suppliers to the EOR industry. This tax incentive more than pays for itself through additional revenue from federal taxes on the incremental additional oil that is produced. In other words, the cost of the incentive is smaller than the additional revenue that would be generated by the additional production and sale of new domestic oil. And this incremental new oil (and taxes) can’t be produced without the CO2, so it’s new, real money to help with our federal balance sheet problems. NEORI estimates this program would add a net present value of $100 billion to the US treasury over a 40-year period. NEORI also offers recommendations for modifying the existing Section 45Q Federal Tax Credit for Carbon Dioxide Sequestration, and suggests a number of model state policies including tax credits, exemptions or abatements, and the inclusion of CCS in electricity portfolio standards, among others.

All the supporters of this effort may not share a common view about fossil fuels or climate change, but they all understand this is indeed a win-win-win. Are there risks? Sure, if oil prices dropped substantially and stayed there, then the incentive might not pay for itself. An even bigger challenge is that the atmosphere in Washington may be so toxic that even a no-brainer like this idea won’t move forward. But if there was ever a chance for a big idea to succeed in our current political climate – EOR is it.

Three years ago, MIT’s Richard Lester published a simple analysis of what would be required to meet President Obama’s 83%-by-2050 greenhouse gas emission reduction target. The results were stark: Even if energy efficiency were to improve at rates 50% better than historical averages, and biofuels were able to meaningfully reduce transportation emissions in the near term (a proposition with which we disagree), meeting Obama’s goal would require retrofitting every existing coal plant in the country with carbon capture and sequestration (CCS), building twice again that much fossil capacity with CCS, building close to 3,000 wind farms the size of Massachusetts’ Cape Wind, and building nearly 4,000 solar farms the size of California’s Ivanpah. And, having done all that, increasing the amount of nuclear power we generate by a factor of five.

Just on its face, this is a tall order. The capital investment is jaw-dropping, and it is becoming increasingly difficult to site new energy projects, regardless of whether they are solar or wind farms, transmission lines, CCS infrastructure, shale gas drilling, or nuclear facilities. More subtly, integrating these various energy sources—especially balancing output of intermittent renewables in an electric grid with no significant ability to store energy—is a major challenge; it is far from certain it can even be done at very large scale. To maximize our odds of meeting the target, we will need to prioritize development and deployment of technologies that appear capable of growing economically to full scale.

Cheap unscrubbed natural gas is a “McSolution” to the problem—tempting, but probably not the healthiest long-term choice. In order to make a major contribution to climate abatement, methane emissions from natural gas production and distribution will need to be reduced, and gas-fired power plants will need to use CCS technologies. And, although gas in the United States today is sold at prices below production costs, that cannot continue for long, especially in increasingly international markets. Similarly, “soft energy paths” like PV power (also sometimes today sold below cost) will need significant grid support and zero-carbon balancing to generate meaningful emission reductions. The economic supply curve for large, attractive sites for these projects is bound to bend sharply upwards over time as well.

In this context, nuclear power has potentially significant advantages to offer: It is demonstrably low-carbon; it provides baseload energy; unlike wind and solar, it has high power density; and, although gas is cheap today, the price of new nuclear power appears to approach that of new coal. Perhaps more importantly, the price of new nuclear plants will decline as years pass. Standardization will lead to some cost reductions; factory assembly of small, modular units could bring about further step-change reductions (as it has for automobiles and airplanes) in production costs.

None of this means that nuclear is poised for a renaissance in the United States. Utilities and their regulators won’t argue with $3 gas, Congress is unwilling to put a price on carbon, and some people remain vehemently opposed to nuclear energy. Ultimately, however, nuclear energy is probably an indispensible element of any credible plan to substantially decarbonize the country. The Nuclear Regulatory Commission’s recent approval of the new Westinghouse reactor design is good news in this regard, as it should help revitalize the American nuclear industry and keep it moving on a path of continuous improvement. In the longer term, a host of newer technologies, including passively cooled small reactors, gas-cooled reactors, and reactors with liquid fuels offer significant potential for further improvements in cost and safety. The country would do well to support continued development and deployment of these designs.

In an ideal world, we might wait to scale up nuclear power until after we’ve exhausted all efficiency and renewables options. Unfortunately, however, we don’t have decades to do this, even if we thought traditional green sources would eventually fill the zero-carbon void, which seems unrealistic. Half of the CO2 emitted today will still be warming the planet 1,000 years from now, and these legacy emissions won’t erase themselves. We need to develop all low-carbon energy options now to hedge against the risk of serious climate consequences; nuclear power, despite its genuine challenges, cannot be left off the table.

Whatever the symbolic importance of the Keystone XL decision, it is only one of several climate-related policy decisions facing the Administration this year – and arguably one of the less significant ones. The Environmental Impact Statement on the project produced by the U.S. Department of State estimates that stopping the pipeline would avoid between 3 and 21 MMT CO2e (carbon dioxide equivalent) in U.S. greenhouse gas emissions annually. While environmental commenters have suggested that this estimate may understate these benefits, they haven’t yet provided alternatives.

The bar chart below compares the CO2e emissions of the Keystone XL project (showing the highest estimate for that project) with several other current opportunities to reduce greenhouse gases:

Last year, EPA Administrator Jackson promised to promulgate a New Source Performance Standard (NSPS) for greenhouse gases from new and existing coal-fired power plants. A policy that achieves a 15 percent reduction in coal plant CO2 by 2020 merely by relying more on existing, cleaner generation resources, would reduce annual GHG emissions by 305 MMT CO2e. At this point, it is unclear whether the EPA will propose a final NSPS rule this year, although a long-overdue court-ordered draft rule is about to be released.

In August 2011, US EPA proposed a significant update to the New Source Performance Standards (NSPS) for the oil & gas industries. EPA is scheduled to issue a finalized rule by 3 April 2012. EPA estimates that these rules will reduce annual methane emissions from the oil production and the entire natural gas industry by 3.1 MMT of methane, or 78 MMT CO2e per year (using a 100-year global warming potential for methane).

While this an important start, there are a number of feasible measures to reduce emissions from this sector that EPA could have included in the proposed NSPS, but did not. These include: covering emissions sources unregulated under the proposed NSPS, such as oil wells, conventional (non-fracked) gas wells, and gas distribution systems; more aggressive measures to mitigate some sources; and requiring mitigation measures for the equipment existing prior to August 2011. CATF estimates that implementation of these additional measures could reduce methane emissions by up to an additional 6.1 MMT of methane, or 152 MMT CO2e, per year (beyond the amount of emissions than will be mitigated by the NSPS, if finalized as proposed).

Lastly, the Energy Independence and Security Act (EISA) of 2007 mandated a substantial ramp-up of the minimum annual consumption of corn ethanol (Renewable Fuel Standard 2 or RFS2). Corn ethanol, as it is currently produced, has a much higher lifecycle impact on climate than gasoline, so this mandate substantially increases the lifecycle impact of burning US transportation fuels. If US drivers used gasoline instead of an energy equivalent amount of the corn ethanol being produced and consumed in 2010-2012 in accordance with the EISA-mandated ramp-up, the avoided GHG emissions during that period would have averaged 121 MMT CO2e per year. In theory at least, carbon re-sequestration by subsequently planted energy crops could eventually offset that difference — but that process will take about 40 years, according to an analysis of EPA data by CATF.

Whatever one’s view of Keystone, all of us in the environmental community need to not lose focus on other, much greater opportunities to slow climate change. The Obama Administration this year can take an important first step in the battle to significantly ramp down our CO2 emissions by proposing strong greenhouse gas performance standards for coal plants.

With the global explosion of unconventional gas production, reports of the death of the fossil fuel economy are, to paraphrase Mark Twain, greatly exaggerated. Gas may not stay at its current extraordinarily low price, but the market landscape seems to be altered for quite some time.

The explosion of low-cost shale gas reserves is a two-edged climate sword. Generating electricity with gas is 30 to 50 percent less carbon-intensive than coal when leaks and releases of methane, the main component of natural gas, are accounted for. (For other uses like vehicle fuel, we haven’t seen any evidence that gas is better than other fossil fuels, and if vehicles leak even a small amount, natural gas could be worse than gasoline). But even for electricity, gas is still a high-carbon fuel: replacing all coal-fired generation with gas would get us only part of the way to the 80 percent CO2 reduction needed by mid-century. Moreover, new gas plants are more likely to displace new zero-carbon generation sources than to displace existing cheap coal plants. Carbon dioxide emitted to the atmosphere stays there, causing warming, for many centuries. By some estimates, the amount of CO2 already emitted has committed the world to warming in excess of 2 degrees Celsius, which is well outside human experience; to hold the increase to 3-4 degrees might well require zeroing out carbon emissions by mid-century.

It would be very nice if we could supply most energy demand with wind, solar and energy efficiency. But there are a lot of real reasons to doubt that these technologies can achieve the necessary scope and scale to displace fossil fuels in the next thirty years. Serious challenges lie ahead for renewables, notably their low output, affordable energy storage, large land area requirements, and the need for back them up with fossil power such as gas when they are naturally not available. Biofuels in use and development today won’t do it because the large amount of new energy crops they require cause substantial carbon emissions (direct and indirect) and would cause other large-scale environmental problems. And, while more energy efficiency is important, it is notable that twenty-five years of the world’s most aggressive electric energy efficiency programs, in California, have reduced electric demand by only around 15 percent from business as usual – not enough to displace the 100% electric demand growth we expect to see in the world over the next two decades.

So, gas is less a “bridge to zero-carbon energy,” than it is a very long highway – gas will be used for some time. What must be done to ensure it makes more than a modest contribution to climate protection?

First, we must ensure that gas production itself does not get in the way. Gas that leaks and is released from US gas systems warms the climate about 40% as much as America’s coal plants, because methane, pound for pound, warms the climate seventy times more than CO2 (considering the warming over twenty years). Addressing this problem is not rocket science – it’s a matter of dollars and engineering. The EPA is currently considering rules that could have the co-benefit of reducing this leakage by about a quarter, but we can cost-effectively – certainly more than half – by focusing on methane directly.

Second, as a recent report of the National Petroleum Council, a petroleum industry-led organization, noted:

[I]f very deep reductions in GHG emissions are desired over the long run, fossil fuels, including natural gas, could play only a limited role in providing energy unless there is a means to capture and sequester the CO2 emissions from burning fossil fuels.

Fortunately, there is. CO2 capture technology is available now for natural gas power plants, geologic carbon sequestration is available in many areas of the country, and geologic sequestration through enhanced oil recovery has been in use for decades. Perhaps the single most important message EPA could send to the clean energy market when it sets CO2 performance standards for gas plants, would be to indicate that CCS will eventually be required on existing natural gas power plants (as well as on coal plants). Because gas is the cheapest new power option, and typically undercuts cleaner forms of energy on price, requiring CCS on gas in the next decades could level the environmental and economic playing field between zero- and near zero-emitting sources of electricity, spurring substantial incremental investment in all forms of clean energy going forward. The sooner we get started, the better.