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EPA's New CO2 Rules Create Opportunities for Natural Gas, for Now

Geoffrey Styles's picture
GSW Strategy Group, LLC

Geoffrey Styles is Managing Director of GSW Strategy Group, LLC, an energy and environmental strategy consulting firm. Since 2002 he has served as a consultant and advisor, helping organizations...

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  • Jun 23, 2014

natural gas and epa rules

  • EPA’s proposed rule for reducing CO2 emissions from power plants could increase natural gas demand in the utility sector by as much as 50%, at the expense of coal.
  • Cutting emissions by regulation rather than legislation entails legal and political uncertainties that could hamper the investment necessary to meet EPA’s targets.

Earlier this month the Environmental Protection Agency announced its proposal for regulating the greenhouse gas emissions from all currently operating US power plants. Unsurprisingly, initial assessments suggested it favors the renewable energy, energy efficiency and nuclear power industries–and especially natural gas–all at the expense of coal. However, the longer-term outcome is subject to significant uncertainties, because of the way this policy is being implemented.

EPA’s proposed “Clean Power Plan” regulation would reduce CO2 emissions from the US electric power sector by 25% by 2020 and 30% by 2030, compared to 2005. Although it does not specify that the annual reduction of over 700 million metric tons of CO2–half of which had already been achieved by 2012–must all come from coal-burning power plants, such plants accounted for 75% of 2012 emissions from power generation.

It’s worth recalling how we got here. In the last decade the US Congress made several attempts to enact comprehensive climate legislation, based on an economy-wide cap on CO2 and a system of trading emissions allowances: “cap and trade.” In 2009 the House of Representatives passed the Waxman-Markey bill, with its rather distorted version of cap and trade. It died in the US Senate, where the President’s party briefly held a filibuster-proof supermajority.

The Clean Power Plan is the culmination of the administration’s efforts to regulate the major CO2 sources in the US economy, in the absence of comprehensive climate legislation. Although Administrator McCarthy touted the flexibility of the plan in her enthusiastic rollout speech on Monday, and suggested that its implementation might include state or regional cap and trade markets for emissions, the net result will look very different than an economy-wide approach.

For starters, there won’t be a cap on overall emissions, but rather a set of state-level performance targets for emissions per megawatt-hour generated in 2020 and 2030. If electricity demand grew 29% by 2040, as recently forecast by the Energy Information Administration of the US Department of Energy, the CO2 savings in the EPA plan might even be largely negated. EPA is banking on the widespread adoption of energy efficiency measures to avoid such an outcome.

Since we have many technologies for generating electricity, with varying emissions all the way down to nearly zero, many different future generating mixes could achieve the plan’s goals, though not at equal cost or reliability. Ironically, since coal’s share of power generation has declined from 50%  in 2005 to 39% as of last year, it could be done by replacing all the older coal-fired power plants in the US with state of the art plants using either ultra-supercritical pulverized coal combustion (USC ) or integrated gasification combined cycle (IGCC). 

That won’t happen for a variety of reasons, not least of which is EPA’s “New Source Performance Standards” published last November. That rule effectively requires new coal-fired power plants to emit around a third less CO2 than today’s most efficient coal plant designs. That’s only possibly if they capture and sequester (CCS) at least some of their emissions, a feature found in only a couple of power plants now under construction globally.

It’s also questionable how the capital required to upgrade the entire US coal generating fleet could be raised. Returns on such facilities have fallen, due to competition from shale gas and from renewables like wind power with very low marginal costs–sometimes negative after factoring in tax credits. Some are interpreting EPA’s aggressive CO2 target for 2020 and relatively milder 2030 step as an indication that the latter target could be made much more stringent, later.

So while coal is likely to remain an important  part of the US power mix in 2030, as the EPA’s administrator noted, meeting these goals in the real world will likely entail a significant shift from coal to gas and renewable energy sources, while preserving roughly the current nuclear generating fleet, including those units now under construction.

If the entire burden of the shift fell to gas, it would entail increasing the utilization of existing natural gas combined cycle power plants (NGCC) and likely building new units in some states. In the documentation of its draft rules, EPA cited average 2012 NGCC utilization of 46%. Increasing utilization up to 75% would deliver over 600 million additional MWh from gas annually–a 56% increase over total 2013 gas-fired generation, exceeding the output of all US renewables last year–at an emissions reduction of around 340 million metric tons vs. coal. That would be just sufficient to meet the 30% emissions reduction target for the electricity demand and generating mix we had in 2013.

The incremental natural gas required to produce this extra power works out to about 4.4 trillion cubic feet (TCF) per year. That would increase gas consumption in the power sector by just over half, compared to 2013, and boost total US gas demand by 17%. To put that in perspective, US dry natural gas production has grown by 4.1 TCF/y since 2008.

EPA apparently anticipates power sector gas consumption increasing by just 1.2 TCF/y by 2020, and falling thereafter as end-use efficiency improves.  Fuel-switching is only one of the four Best System of Emission Reduction “building blocks” EPA envisions states using, including efficiency improvements at existing power plants, increased penetration of renewable generation, and demand-side efficiency measures. The ultimate mix will vary by state and be influenced by changes in gas, coal and power prices.

I mentioned uncertainties at the beginning of this post. Aside from the inevitable legal challenges to EPA’s regulation of power plant CO2 under the 1990 Clean Air Act, its imposition by executive authority, rather than legislation, leaves future administrations free to strengthen, weaken, or even abandon this approach.

Since EPA’s planned emission reductions from the power sector are large on a national scale (10% of total US 2005 emissions) but still small on a global scale (2% of 2013 world emissions) their long-term political sustainability may depend on the extent to which they succeed in prompting the large developing countries to follow suit in reducing their growing emissions.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Photo Credit: Natural Gas and New EPA Rules/shutterstock

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John Miller's picture
John Miller on Jun 23, 2014

Geoffrey, since you and I agree that fuels switching from coal-to-natural gas is the most likely and dominate solution to achieving the 30% carbon reduction target, Investors and Consumers need to be aware of the potential impacts on energy prices and supply.  Using the EIA AEO projections it appears that essentially all future projected natural gas exports could be consumed domestically as coal consumption rapidly decreases in order to comply with the very aggressive EPA carbon reduction targets.  This potentially puts enormous Investor risk on those LNG export projects in progress and planned.  The current natural gas market prices could also double relatively quickly as excess supply rapidly declines.  Consumers will very likely experience substantial increases in electric and heating bills (issues apparently not addressed by the EPA in developing the proposed new carbon regulation).

Ed Dodge's picture
Ed Dodge on Jun 24, 2014


It will be interesting to see if the New Source Performance Standards survive the inevitable legal challenge.  There are some pretty compelling arguments that the EPA over-reached in declaring IGCC w/ partial CCS as the Best System for Emissions Reduction. Among the reasons is that all the facilities EPA pointed to as examples, such as Kemper, were heavily government funded, and this is apparently not legal under the 2005 Energy Policy Act. Other example plants EPA used have not been constructed at all, which makes it difficult to claim they are “adequately demonstrated”.

Industry interests have been arguing that IGCC without CCS and Supercritical Pulverized Coal should have been the BSER.  We will see what the courts say.  And if the New Source Performance Standards, 111(b), get shot down, where does that leave 111(d)? My understanding is 111(d) requires having 111(b) in place.

The coal industry seems to support CCS, they just can’t shoulder the costs all on their own. It would be unfortunate if their claim proves true that these new standards actually slow down the roll out of CCS because it pushes all the investment capital to natural gas at the expense of coal.

John’s point is also on the mark, no one can accurately project future prices for natural gas which are historically volatile. We could end up in a bad squeeze if no new advanced coal plants get built and natural gas prices rise due to wide demand from numerous industries and world events disrupting markets. 


Geoffrey Styles's picture
Geoffrey Styles on Jun 24, 2014


Official forecasts of future natural gas prices and supply don’t envision the kind of demand growth that the Clean Power Plan could trigger. However, we no longer seem to be resource-limited in this area, at least over the period between such a coal-to-gas transition and the eventual displacement of gas by renewables and advanced nuclear power, or some other, as-yet unspecified large-scale technology. The shape of the gas supply curve is the key: how much additional gas would a $1 or $2/MCF price increase elicit from producers, and how much of a price increase would be required to get production up to the level required to displace coal, export LNG, displace some oil from transport, grow industry and do all the other things that advocates of each of these strategies expect? My sense from watching shale gas develop over the last decade is that the supply curve will turn out to be much less steep than pessimists expect, but still not flat.

Jim Stack's picture
Jim Stack on Jun 27, 2014

Let’s just stop the subsidizes that have been in place for over 50 years on COAL, NG and Nuclear and everyone will see clearly that Renewable Energy is and has been the best choice. We hit Peak NG in 2004 and only have excess now because of Fracking. Once we stop we will again see that NG is not a solution.

Geoffrey Styles's picture
Geoffrey Styles on Jun 30, 2014

Claims that “shale gas is worse than coal” have been thoroughly refuted, not least by actual measurements at hundreds of well sites. See:

Geoffrey Styles's picture
Geoffrey Styles on Jun 30, 2014

The pros and cons of renewables and oil & gas are complex, but you’ve focused on subsidies. US tax incentives for renewable energy are now in the same ballpark as the roughly $4 billion per year of federal tax beneftis for oil and gas production. Let’s put some numbers to your assertion about their relative merit by comparing the value we receive for these investments, which unlike externalities represent real money that could be spent on other priorities or returned to taxpayers.

Last year the value of all electricity generated by non-hydro renewables in the US, at the current average wholesale power price, was around $10 billion. 

Last year’s US oil and gas production from shale deposits–which due to their higher cost are presumably more affected by tax incentives than conventional production–was equivalent to 7.9 million barrels per day. At relevant wholesale prices, that output was worth around $140 billion. (A significant portion of that came back to the government as tax collections.) At least in terms of the return on tax benefits this still looks like a good deal for taxpayers.

Joris van Dorp's picture
Joris van Dorp on Jul 1, 2014

Fully agree.

FWIW, I believe the mounting confusion about the state of taxes and subsidies for conventional and alternative energies is being caused deliberately by pro-alternative energy groups to make alternative energies appear cost effective.

Research shows that global subsidies for fossil fuels are dwarfed by global tax revenues from fossil fuels by a ratio of two to one. Moreover, the subsidies take place mostly in developing (oil exporting) countries, while the total tax revenues are highest in OECD countries. In OECD countries tax revenues exceed subsidies by a ratio of four to one. So clearly, there is no net subsidy for fossil fuels at all. Claims by proponents of alternative energies that the fossil fuel subsidies are all that is making alternative energies uncompetitive are thoroughly untrue, yet they appear and reappear with surprising frequency.

Furthermore, the way subsidies are calculated leaves a lot to be desired, in my opinion. For example, the IEA counts as a subsidy the choice by oil exporting countries to sell oil products near cost of production domestically, rather than at the international market price. While it is certainly possible to choose to call this a subsidy, it can muddle the discussion about the real economic value of fossil fuels versus alternative energies. It seems to support the (false) conclusion that oil exporting countries would benefit financially from switching to alternative energy. In reality, consumers in those countries would end up paying far more for their energy if they were forced to switch to alternatives, although this cost would be compensated to a large degree at the state level by potentially increased exports of high priced oil that is no longer consumed domestically. However, for this benefit to return to the energy consumers in those countries, those countries would still have to massively subsidise the alternative energy. There is no free lunch in that sense. Alternative energy will do nothing to reduce subsidies in those countries, unless the price of energy is allowed to rise. 

Nevertheless, moderate amounts of alternative energy would enable a cost effective increase in exports of high priced oil products in some cases. But this would not help reduce global co2 emissions. Those countries would simply shift from consuming more fossil fuels to exporting more of them them. They would have to export more, in order to pay for the subsidies for using alternative energy domestically. The net amount of fossil fuel burning globally would not decrease, presumably. On the contrary: using more alternative energy domestically would free up more oil for exports which would potentially reduce the international price of oil products thereby raising demand for it and reducing the business case of alternative energies in oil importing countries.

In the end, the only way to economically reduce greenhouse gas emissions is to enable technology that can compete in the free market with fossil fuels. I believe only nuclear power has the potential do that at the scale required. I also believe that the continuous attempts by some green groups to muddle the discussion on taxes and subsidies is an implicit confession by these groups that alternative energies do NOT in fact compete with fossil fuels. It would be good if they stopped muddling the discussion, in my opinion.

Geoffrey Styles's picture
Geoffrey Styles on Jul 1, 2014


I’ve read every word of the UT study, and from my training and experience believe I understand them. They certainly identified areas for improvement–leaks that could be remedied and likely for a profit or at least low net cost. However, unlike virtually every study pointed to by opponents of fracking, this one examined real wells, up close, during the various phases of completion and operation. That means that unlike all the overflights with model-based interpretations, very few assumptions were needed, and most of those were verifiable.

Of course it’s true the producers agreed to participate, so the study wouldn’t include those with anything to hide. But the ones that did participate are among the largest shale gas developers in the business, including Anadarko, Encana, Pioneer and XTO (ExxonMobil). The numbers speak for themselves. This wasn’t a snapshot view of a few wells, but a detailed look at 190 sites, including “Measurements of active equipment at 150 production sites with 489 wells, 27 well completion flowbacks, nine well unloadings and four well workovers were included in the study.” No other study I’m aware of has a sample size within an order of magnitude of this one.

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