Is An Ethanol Compromise on the Horizon?

• The RFS ethanol mandate increasingly benefits farmers and ethanol producers at the expense of motorists, small-engine users, food producers and restaurants.
• Repeal of the RFS looks unlikely, but equitable reforms addressing the needs of all affected groups are possible, if Congress is willing to compromise.

Earlier this month, National Journal hosted an event on the “Biofuels Mandate: Defend, Reform, or Repeal” from Washington, DC. I encourage you to skim through the replay. The session highlighted a wide range of views concerning the US Renewable Fuels Standard (RFS), including those of the corn ethanol and advanced biofuels industries, poultry growers, chain restaurants, environmentalists, and small engine manufacturers. Although these broke down pretty sharply along pro- and anti-RFS lines, I thought I detected hints of the kind of compromise that might resolve this issue. I’d like to focus on the elements of such a deal, rather than rehashing the positions of all of the participants, with one necessary exception.

The most disappointing contributions to the discussion occurred during the interview with Representative Steve King (R, IA) by National Journal’s Amy Harder. If we accept Mr. King’s perspective, we should embrace the RFS as being as relevant today as when it was conceived, with no changes required. That flies in the face of the serious market distortions now manifesting in the “blend wall” at 10% ethanol content in gasoline.

Among other things, Mr. King claimed that a 2008 reduction of $0.06 per gallon in the now-expired ethanol blenders tax credit brought the expansion of the corn ethanol industry to a standstill. The industry’s own statistics tell a very different story, with US ethanol production capacity having grown by a further 86% since that point.

Rep. King also characterized “food vs. fuel” concerns as a bumper sticker issue, with no basis in fact. That issue might be controversial, but it is far too substantive to dismiss so cavalierly. The latest evidence of that is a vote by the European Parliament to cap the contribution of conventional biofuel — ethanol and biodiesel derived from food crops — at 6% of transportation energy out of a 2020 target of 10%, based on concerns about sustainability and competition with food. It seemed fairly clear that the Congressman views the RFS more as a farm support measure than an energy program.

The only one of Mr. King’s comments that seemed to find traction with the other pro-RFS panelists was his odd suggestion that without a mandate for biofuels, the only federal mandate in place would be one for petroleum-based fuels. Certainly, gasoline and diesel have advantages in terms of infrastructure, energy density and the legacy fleet, but he appeared to have something else in mind. From the way others picked up on this, perhaps it was his earlier reference to the tax benefits that conventional fuel producers have long enjoyed. This is the first and easiest element on which to compromise.

If ethanol producers and advanced biofuels developers are convinced that fossil fuels get a better deal from the federal government than the one they have under the RFS and the $1.01 per gallon producer tax credit for second-generation biofuels, it would be a simple matter to replace these programs with the same incentives received by oil and gas producers and petroleum refiners. After all, the biofuel industry already benefits from the Section 199 tax deduction that accounts for a third of budgeted federal tax benefits for the oil industry, and it shouldn’t be hard to devise an accelerated depreciation benefit analogous to “percentage depletion” and the expensing of intangible drilling expenses. Combined, the value of these tax benefits is about 1.3¢ per equivalent gallon of oil or natural gas produced this year.

Other concerns came across clearly. Despite the endorsement of 15% ethanol blends by the Environmental Protection Agency, blending more than 10% ethanol in gasoline creates serious risks for the US’s 500 million existing gasoline engines, large and small. The scale of corn diversion necessary to go beyond 10% is also distorting the US agricultural economy and food value chain, all the way to the restaurants in our communities. However, those engaged in developing new biofuels that don’t rely on edible crops, or that are fully compatible with existing infrastructure and engines, are legitimately worried that the repeal of the entire mandate would strand the significant investments in new technology that have already been made, and possibly smother their industry just as it nears its first commercial-scale deployments. All these points of view struck me as eminently reconcilable within a reformed RFS that recognizes that most of the assumptions of the 2007 mandate are no longer valid.

The starting point for reform of the RFS should be a 10% cap on ethanol from all sources in mass-market gasoline — excluding E85 — combined with measures to give ethanol from non-food sources priority within that cap over ethanol produced from corn or other food crops. The advanced biofuel targets of the RFS should also be scaled back significantly to reflect the reality that the 2007 targets were wildly optimistic. Ideally, they should be adjusted each year based on the previous year’s actual output. In return, the current producer tax credit for cellulosic and other second-generation biofuels could be extended beyond its scheduled expiration at the end of this year, and then phased out over a reasonable, predictable period, perhaps tied to cumulative output.

Finally, since few on the panel seemed impressed by the EPA’s exercise to date of its statutory power to adjust the RFS to fit changing circumstances, that authority should be transferred to another agency, along with clearer guidelines on when adjustments would become mandatory.

I’d be the first to admit that the reforms I’ve outlined above fall well short of the outright repeal of the RFS that many, including myself, would prefer. That’s the essence of compromise. Having just experienced a government shutdown and debt ceiling crisis brought on by the clash of two intransigent positions, this might be preferable to an impasse that leaves an unsustainable status quo untouched. And if the assessment of Representative Welch (D-VT) concerning the appetite of the Congress to take up this matter is accurate, something along these lines might just be achievable.

Reform of the RFS would leave in place for a while longer the outlines of a mechanism that one of the session's panelists accurately described as a Rube Goldberg construction. Short of a guarantee to bail out everyone who invested in biofuels production or research on the basis of the RFS that Congress put in place in 2007, should they fail in a post-repeal market, I’m not sure there’s another course that would be sufficiently equitable to all parties involved.

A different version of this posting was previously published on Energy Trends Insider. 

UK Nuclear Deal Is A Bet on Baseload Power

• An agreement to build the UK's first new nuclear power plants since 1995 endorses the role of baseload generation in the future low-emission energy mix.
• Rather than constituting a choice of nuclear instead of renewables, this looks like nuclear plus renewables as a hedge on rising UK natural gas prices.

Monday's agreement between the UK government and French utility EDF and a pair of Chinese firms marks the start of the long-awaited turnover of the country's aging nuclear power infrastructure. The deal is controversial, not least for the power price of £92.50 per megawatt-hour (MWh) guaranteed to the developers. That's equivalent to about $0.15 per kilowatt-hour (kWh) at today's exchange rates. It's also strikingly different from the choices Germany and France itself have made recently.

The UK has a long history with nuclear power, having started up the world's first commercial-scale civilian reactor in 1956, following demonstration units in the US and USSR a few years earlier. Many of the plants built in the construction wave that followed have already been retired, and none has been started up since 1995. Another 40% of the country's remaining 10,000 MW of nuclear capacity is due to shut down by the end of this decade, with all but the newest, largest nuclear plant at Sizewell scheduled for retirement by the early 2020s. Even if the two new reactors that EDF and its partners will build at the Hinkley Point site in Somerset--adjacent to two 1970s-vintage reactors still in service--are completed on schedule, Britain's nuclear output is likely to shrink before it grows again.

The Hinkley C deal hinged on a question that can still only be answered theoretically today: What is the most effective future electric generating mix for achieving the necessary combination of affordability, reliability and low greenhouse gas emissions? In the aftermath of the Fukushima accident the German government decided that nuclear had no place in that mix and doubled down on its commitment to renewable energy, particularly wind and solar power, though that shift appears to require an increase in coal-fired generation to pull off. Meanwhile, France, which currently gets 75% of its electricity from nuclear, has embarked on a plan to reduce its share to 50% while expanding renewables.

The electricity mix in the UK is already changing as large offshore wind projects and onshore wind farms come online, and as the country's inexplicable flirtation with solar power increases. The gas turbines that dominated the previous wave of power plant construction are becoming more expensive to operate as waning UK North Sea gas output must increasingly be replaced by imported gas, while more coal plants shut down. All of this is underpinned by a legally binding commitment to reduce greenhouse gas emissions by 80%, compared to 1990, by 2050.

The UK's options for devising a reliable low-emission electricity mix are limited. If it wanted to build that mix around the combination of gas and renewables that California has chosen, then it would need a cheaper source of gas. That explains the government's interest in shale gas, although the outcome--both in terms of the rate of development and the future extent and cost of shale gas production--remains uncertain. It also can't rely nearly as much on solar, since it receives on average around half as much sunlight as the Golden State. Coal won't fit without carbon capture and sequestration (CCS) that is still expensive, and large-scale hydropower potential appears to be limited. That leaves nuclear as the largest-scale low-emission baseload option to anchor the energy mix, with quick-reacting natural gas turbines left to even out the fluctuations of offshore and onshore wind, and possible future wave and tidal installations.

In that context, it was surprising that the UK energy minister apparentlhy chose to frame this week's transaction as a choice for nuclear over the "blight" of the tens of thousands of wind turbines required to generate the same electricity, annually. Configuring wind power to provide enough reliable baseload energy to make nuclear unnecessary would require more overcapacity, grid upgrades and energy storage than even California's legislators could imagine. That would cost far more than the £92.50/MWh price tag for new nuclear.

And that brings us back to the price guarantee, or "strike price", which was apparently the key to getting EDF and its partners to commit to proceed on Hinkley Point. Since the UK's coalition partners had previously determined to provide no subsidies for nuclear power, arrangements such as the loan guarantees offered to US nuclear developers were out of the question. Whether the "contract for difference" scheme chosen to support Hinkley Point's future revenue--funded by ratepayers rather than taxpayers--constitutes a subsidy by another name, it is functionally similar to the Feed-In Tariffs (FITs) offered to wind, solar and other renewables in Germany and elsewhere. For comparison, the current German solar FIT guarantees utility-scale installations the equivalent of £84/MWh for a period extending past the planned start-up of Hinkley C.

Solar and nuclear power aren't interchangeable on the grid, but the spread between them highlights the financial risks involved in the current deal. The UK is placing a potentially expensive bet on low-emission baseload power from nuclear energy, while its biggest neighbors on the Continent are turning away from nuclear to pursue steadily rising shares of intermittent wind and solar power, the cost of which keeps falling. The government's call looks justifiable today for reasons of reliability and as a long-term investment--Hinkley C should still be producing billions of kilowatt-hours a year when the wind turbines and solar panels installed in Britain this year are rust and dust. However, if the UK's Bowland shale turns out to be the first Marcellus-like play outside the US, that price guarantee could cost future British ratepayers hundreds of millions of pounds per year.

Study Sheds Light on the Environmental Impact of Shale Gas

• The view that methane leaks render shale gas "worse than coal" has been further undermined by the release of a new study based on actual measurements at hundreds of gas wells.
• Previous estimates of methane leakage relied on modeling or extrapolation from remote measurements. The University of Texas study addresses these shortcomings.

Since the late 1990s natural gas has been identified by both energy experts and environmentalists as a likely "bridge fuel" to facilitate the transition to cleaner energy sources. This view has recently been challenged by suggestions that methane leakage from natural gas systems--particularly from shale gas development--might be significant enough to negate the downstream climate benefits of switching to natural gas. The results of a new study from the University of Texas, sponsored by the Environmental Defense Fund (EDF) and nine energy companies, should alleviate many of those concerns.

In order to understand why indications of potential natural gas leakage rates well above the previously assumed level of around 1% would cast doubt on the environmental benefits of gas, a brief primer on greenhouse gases (GHGs) is necessary. When present in the atmosphere, these gases contribute to global warming by trapping infrared radiation that would otherwise be emitted to space. Carbon dioxide is the primary GHG implicated in climate change. It currently makes up roughly 400 parts per million (ppm)--equivalent to 0.04%--of earth's atmosphere and is increasing by around 2 ppm per year.

The main constituent of natural gas is methane. Although atmospheric concentrations of methane are much lower than that of CO2, totaling less than 2 ppm, pound for pound it is a much stronger GHG. Its "global warming potential" is 25 times higher than CO2's over a 100-year time horizon, and even higher on a shorter time span. While most atmospheric methane has been traced to natural or agricultural sources, a large increase in atmospheric methane from natural gas production could overwhelm the undisputed downstream emissions benefits of gas in  electricity generation, compared to coal.

Several academic studies raised precisely this concern with regard to natural gas produced from shale by hydraulic fracturing, or "fracking", starting with a widely-publicized paper from a professor at Cornell University in 2010. This work relied on estimates and limited data from early shale production to arrive at a conclusion that shale gas wells leak 3.6-7.9% of their cumulative output. A more recent series of studies from the National Oceanic and Atmospheric Administration (NOAA) and the University of Colorado Boulder used airborne remote sensing techniques to calculate leakage rates similar to Professor Howarth's.

Other studies from groups as diverse as IHS CERA, Carnegie Mellon University, and Worldwatch Institute and Deutsche Bank addressed the same question but arrived at much lower leakage rates and impacts. And earlier this year the US Environmental Protection Agency reduced its previous estimate of overall natural gas leakage to a figure equivalent to 1.7%.

However, until now all scientific studies of this issue--on both sides--were based on limited data, or on indirect measurements obtained at a significant distance from actual production sites. They relied heavily on assumptions about what was happening at large numbers of gas wells, in the absence of direct observations at these sites.

That's what makes the UT study so significant; it is based on a wealth of data from actual, on-site measurements at "190 production sites throughout the US, with access provide by nine participating energy companies." That translates to roughly 500 shale gas wells in different stages of development and production. 

Overall, for the segment of the gas lifecycle they investigated, the UT team found methane emissions that were lower than EPA's latest estimates.  Emissions from "completion flowbacks" were  98% lower, partially offset by somewhat higher observed leaks from valves and other equipment. Although this study did not measure emissions from the entire gas lifecycle, including pipelines, it would be very hard to reconcile their observed average leakage rate of 0.4% of gross gas production with leakage estimates as high as those embraced by many of shale's critics.

Immediate criticisms of this study also missed several crucial points. First, without the industry involvement that they characterized as a "fatal flaw", access on this scale for direct measurements at production sites--surely the gold standard for emissions studies compared to estimates based on assumption-laden models--would have been difficult or impossible to obtain. More importantly, they also ignored the fact that the principal sources of methane emissions found by the UT team involved valves and equipment by no means unique to shale development, many of which should be amenable to hardware improvements or different technology choices.

While the UT team and their sponsors at EDF stated clearly that more work needs to be done to measure methane emissions from other parts of the gas value chain, the current paper convincingly dispels the notion that the emissions from shale gas development are inherently much higher than those for gas produced from vertical wells in conventional oil and gas reservoirs. Since shale gas already accounts for over a third of US natural gas production and is widely expected to dominate future production, that result has large implications for the environmental benefits of further fuel switching and other applications for natural gas.

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

As US Oil Production Revives, New Vulnerabilities Appear

• The expansion of US oil production is centered in a handful of states, and in particular two whose gains more than offset declines in two former production leaders.
• For various reasons the West Coast has missed out on this revival, straining infrastructure and creating new vulnerabilities that should be addressed.

On the front page of today's Wall St. Journal I see that "US Rises To No. 1 Energy Producer." This news builds on a number of recent headlines such as, "US oil production reaches highest level in 24 years." Stories like these aren't as attention-grabbing as they were when this streak began more than a year ago, once shale oil production ramped up dramatically.  What occurred to me this time, however, was how different the current distribution of US oil output is than it was in the late 1980s.

A handful of states still account for the lion's share of US oil production. Then and now, Texas tops the list, exceeding its 1989 output by 37%. At nearly 2.6 million barrels per day (MBD) in the most recent reported month --140% above at its low point in 2007--its share of US oil production had grown to around 35% by June. However, beneath Texas  the list of top oil states has been jumbled in ways few would have anticipated two decades ago.

Alaska, California and Louisiana, the second-, third- and fourth-ranked producers in 1989, then supplied 41% of total US crude oil output. After decades of decline, the same three states now contribute just 17%, excluding production from the federal waters off Louisiana's coast. Meanwhile, thanks to the development of the Bakken shale, North Dakota has jumped from the number  6 spot just five years ago to number two, eclipsing Alaska early in 2012.  Traditional mid-tier producers like Colorado, Oklahoma and New Mexico are also contributing to the overall US oil revival. This surge of highly productive drilling in roughly the middle third of the country, on top of a million-plus barrels per day from the Gulf of Mexico --mainly from deepwater rigs--has scrambled existing oil transportation arrangements.

When onshore production in Texas and the rest of the mid-Continent shrank in the 1990s and 2000s, the region's pipeline network gradually evolved into the country's principal oil-import conduit. The growth of production in the federal waters of the Gulf of Mexico, which had reached 1.6 MBD at the time of the Deepwater Horizon accident in 2010 but subsequently declined to about 1.2 MBD, meshed well with that model.

Today's big challenge goes against that grain: moving the growing surplus of oil in the upper plains states to markets on the West, Gulf and East Coasts, increasingly by rail. Much of the turbulence we've seen in the US oil market  in the last two years reflects the delays inherent in realigning and expanding that network to accommodate newly abundant domestic supplies.

Yet on the other side of the Rockies, the picture looks very different. When I was trading crude oil for Texaco's west coast refining system in the late 1980s, balancing the crude oil surplus on the Pacific coast required shipping multiple tankers a month of Alaskan North Slope oil to the Gulf, where production was shrinking, and prompted the construction of a new pipeline to send surplus oil to east Texas over land. After two decades of decline from mature fields, along with moratoria on tapping new offshore fields, imports now make up roughly half of west coast refinery supply, even though regional petroleum demand is essentially back to 1989 levels. It remains unclear whether and when California will allow producers to tap the state's potentially game-changing oil resources in the Monterey shale deposit.

Barring further change, the regional nature of these shifts means that the energy security benefits accompanying the revival of US oil production are a party to which the West Coast has not been invited, or has perhaps declined the invitation. That's significant, because it leaves residents of California, Oregon, Nevada and Washington much more exposed to any disruptions in global oil trade, since the existing US Strategic Petroleum Reserve was never intended to provide coverage west of the Rockies. In this light, the appetite of west coast refiners for trainloads of Bakken and Eagle Ford crude looks strategic, rather than just a temporary response to market conditions.

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