Thursday, December 23, 2010

Big Energy Stories of 2010

Many of the main energy trends of 2010 were predictable at the year's start, including the growing reliance of renewable energy on government assistance in the aftermath of the financial crisis, the debate over US greenhouse gas legislation, the emphasis on green jobs and competition with China, the delayed arrival of cellulosic biofuels, and the anticipation surrounding the product launches of the first mass-market electric vehicles. As interesting as all this was, the year in energy was dominated by two transformative events: the Deepwater Horizon accident and the multi-million barrel leak that ensued, and the less spectacular but no less profound awakening to the possibilities of the shale gas revolution.

The Deepwater Horizon disaster has been the subject of such extensive coverage and investigation that there's little I can add concerning the facts, other than to note that we have not heard the last word on just how much oil actually leaked into the Gulf of Mexico. The consequences of our response to the spill will be with us for a long time, both in terms of reduced offshore drilling activity and the decline in US oil output that must inevitably follow. The impact will reach far beyond the tens of thousands of workers whose livelihoods are directly or indirectly linked to the US offshore industry. Early in 2010 it looked like the industry would finally be offered access to areas that had been off-limits for decades, and by year-end not only has drilling in the central and western Gulf come to a near standstill, but the prospect of leases in the eastern Gulf and the mid-Atlantic coast has been foreclosed, perhaps permanently.

The psychological impact of the event could extend even farther than its physical and economic fallout. Whatever misgivings many people had about offshore drilling before the accident, the industry had built up trust through an impressive string of technical achievements--pushing the boundaries of resource accessibility from depths of a few hundred feet into nearly two miles of inhospitable ocean--and a solid reputation for safety. In the space of one day and the following weeks, that trust was shattered. Coming on the heels of a financial crisis that destroyed the trust of millions of Americans in the nation's largest financial institutions and markets likely amplified the effect. As fickle as we Americans sometimes seem, I wouldn't bet that this trust can be restored quickly, or to the same degree.

The shale gas revolution is a completely different kind of story, though it, too, has arguably been tainted by Deepwater Horizon. As it unlocks a resource that has converted the US natural gas supply outlook from one of scarcity and growing import dependence to expected abundance for decades, the gas industry can't assume it will receive the benefit of the doubt concerning the environmental impact of the drilling techniques that have made this turnabout possible.

Perhaps one reason the impact of cheap natural gas hasn't sunk in yet is that the main market price for gas, the futures price at the Henry Hub in Louisiana, doesn't have much relevance for the average consumer. Residential gas customers don't buy their gas in the million-BTU (MMBTU) lots in which the futures contract is denominated; we buy gas in therms--one tenth of an MMBTU--and by the time we see it on our bills all sorts of handling and distribution fees and mark-ups have been added on. But when you compare the price of traded gas in barrels of oil equivalent (BOE) to the price of West Texas Intermediate crude, the remarkable divergence of the last two years becomes obvious, as shown in the chart above. Between 2000 and 2006 gas and oil tracked each other closely, allowing for the greater seasonal volatility of the former. There were even periods when a barrel-equivalent of gas was worth more than a barrel of oil. Yet while oil and gas prices fell precipitously when the recession and financial crisis burst the various asset bubbles, they have diverged sharply since then, with oil advancing back up to today's $91/bbl and gas settling into the $20-25/bbl range in which we were accustomed to see oil prices a decade ago. Adjust that for inflation and you're looking at an average natural gas price for 2010 equivalent to $20/bbl in 2000.

That might help explain why the developers of renewable electricity sources such as wind have struggled so much this year, despite receiving $3.9 billion in direct cash grants from the US Treasury. They're not competing with $90 oil; the US generated less than 1% of its electricity from petroleum this year, through September. Instead, they're competing with gas at an effective price of $25/bbl or less. But if this is a new obstacle for some renewables, it surely represents a huge opportunity for the country as a whole, as we struggle to find our way out of the fiscal and competitive pit we've dug. Cheap energy has always been a key to growth, and right now, gas is the only energy source offering that without requiring an enormous up-front investment. It's no panacea, and it can't take on every burden without being spread so thin that its price advantage would disappear. But I'd much rather be looking at the possibilities this presents than at the constraints that high-priced oil and natural gas imposed only a couple of years ago.

That's probably as good a note as any on which to end the year. New postings will resume the week of January 3, 2011. In the meantime, I wish my readers a happy holiday season.

Monday, December 20, 2010

UL Study Raises New Questions About E15

One of the energy stories I've followed with great interest all year concerns efforts to increase the proportion of ethanol blended into ordinary US gasoline. This began last year when Growth Energy, an ethanol trade association, asked the Environmental Protection Agency for a waiver to increase the allowed percentage of ethanol in gasoline from 10% to 15%. In October EPA issued a partial approval of the request, but only for vehicles built in model year 2007 or later. However, a new report from Underwriters Laboratories (UL) indirectly casts doubt, not only EPA's ruling, but on whether the agency was assessing all the relevant issues.

I ran across the UL report on the compatibility of mid-level ethanol/gasoline blends in gasoline dispensing equipment--the pumps, hoses and tanks in gas stations--in a posting on API's EnergyTomorrow blog. It cited the UL study, which had been commissioned by the Department of Energy, as evidence that E15, the 15% blend of ethanol and gasoline that the EPA just approved for use in newer cars, could result in serious failures of gas pumps. Yet when I read the report, I immediately encountered its innocuous-sounding conclusion stating, "The overall results of the program were not conclusive insofar as no clear trends in the overall performance of all equipment could be established." It went on to say that the equipment "generally performed well." If I had stopped reading there, I'd have concluded that API was blowing the whole story out of proportion.

When I read the data included in the report, however, a different story emerged. Of the new and used gasoline dispensers and associated equipment tested, very few exhibited no problems on the 17% ethanol test fuel used. In fact, in UL's long-term exposure test, many hoses, nozzles and swivels leaked. 100% of the meter, manifold and valve assemblies tested leaked or failed to shut off. Perhaps most worryingly, two-thirds of the breakaway couplings tested leaked, failed their pressure tests, or required more than the recommended pull to separate. (A breakaway is designed to pop the hose off the dispenser when a customer forgets to remove the nozzle from his car's gas intake and attempts to drive off. This happens a surprising number of times a year, and before the deployment of breakaways such incidents imposed significant repair costs on dealers, even when the resulting spills didn't cause fires.)

The common denominator in these failures was what the report refers to as "nonmetals", gaskets, seals and parts made from various polymers. From that I would draw two conclusions: First, it ought to be possible to design new dispensers and retrofit existing dispensers with new gaskets, seals and plastic parts designed to withstand higher concentrations of ethanol, just as the fuel systems in flexible fuel vehicles are designed to tolerate blends of up to 85% ethanol. However, considering that the US has between 90,000 and 160,000 gas stations, depending how you count them, the number of dispensers that would have to be modified is at least in the high tens of thousands, if not well into the hundreds of thousands. To my knowledge the ethanol industry has not offered to defray the cost of these conversions for a retail fuel industry that operates with extremely lean margins. Nor is it obvious that dealers would qualify for federal assistance, as they do when they add E85 capability.

My second conclusion--really more of a suspicion--has nothing to do with gas pumps or gas stations, and everything to do with cars. After reading the UL report I went back and reread portions of the EPA's official waiver response, which ran to 58 pages in the Federal Register. From what I can tell, EPA wasn't really looking at whether cars would suffer damage from operating on a higher percentage of ethanol than the fuel for which they were designed. The waiver was granted on the basis of those cars not emitting more pollutants than on the fuel for which they were designed. Quoting from the EPA document:

"For MY 2007 and newer light-duty motor vehicles, the DOE Catalyst Study and other information before EPA adequately demonstrates that the impact of E15 on overall emissions, including both immediate and durability related emissions, will not cause or contribute to violations of the emissions standards for these motor vehicles. Likewise, the data and information adequately show that E15 will not lead to violations of the evaporative emissions standards, so long as the fuel does not exceed a Reid Vapor Pressure (RVP) of 9.0 psi in the summertime control season. The information on materials compatibility and drivability also supports this conclusion."

That's good as far as it goes, but from my perspective this finding reflects a necessary but hardly sufficient standard for putting a new fuel into the marketplace, particularly when the failures of the dispensers in the UL study point to the possibility of similar failures of "nonmetals" in the fuel systems of cars or other devices not designed to run on more than 10% ethanol. Even if the leaks found in the testing of product dispensers didn't result in safety hazards, they would at a minimum increase the evaporative emissions from infrastructure, aside from the automotive impact on which EPA apparently focused. I also find it interesting that a bill was introduced in Congress this summer, as EPA was considering the waiver request, that would appear to make it more difficult for consumers to recover the cost of damages resulting from compatibility problems in approved vehicles or misfueling of non-approved vehicles.

As I've noted in my previous postings on this topic, I'm sympathetic to the box into which altered circumstances have placed both the ethanol industry and the federal government with regard to ethanol blending. US gasoline sales, which stagnated after the financial crisis and are only growing by a historically modest 0.7% this year (through November) according to API's latest statistics, are not expanding fast enough to accommodate the output of all the ethanol plants that have been built or are under now construction. When the Renewable Fuels Standard was enacted as part of the Energy Independence and Security Act of 2007, the bill's architects presumably expected that E85 sales would take up any slack. The fact that that hasn't happened does not justify creating a new outlet for additional ethanol in automobiles not designed to accommodate it, any more than it would justify running a new fuel through infrastructure that has been shown not to be up to the challenge. If EPA doesn't revisit the more comprehensive aspects of this question as part of its deferred decision on allowing E15 for cars made before 2007, then perhaps it's time for another government agency with a broader charter to take over this issue.

Friday, December 17, 2010

Christmas for Renewables

Last night the US House of Representatives passed the compromise tax bill without any amendments and by a healthy margin, though narrower than the 81-19 vote in the Senate on Wednesday. The bill now goes to the President for his signature. The provisions added after the initial negotiations between the White House and Republican leadership delivered a substantial Christmas present to the nation's renewable energy industry, including several key items on the industry's wish list: extension of the ethanol blenders' tax credit at its current rate of $0.45 per gallon; extension of the Treasury Renewable Energy Grants, which provide cash in lieu of investment tax credits; and a retroactive extension of the $1.00 per gallon biodiesel tax credit, which had lapsed at the end of 2009. However, as with many Christmas presents, the bill that will come due next year is also substantial. And the one-year extensions granted to these incentives leaves their long-term fate in the hands of the new Congress, which is widely expected to be more focused on deficit reduction than on stimulus.

This result constitutes a remarkable trifecta. As recently as a week ago it seemed likely that the Treasury Grant program would expire on schedule, and that the ethanol credit, if not actually allowed to expire, would at least be reduced to reflect its redundancy with the Renewable Fuel Standard (RFS), which requires refiners and fuel blenders to add biofuel to gasoline. As for the biodiesel tax credit, it looked like a lost cause all year, having failed on multiple previous attempts to reinstate it. The US ethanol industry even prevailed in having the $0.54 per gallon duty on imported ethanol extended for another year, in order to shield taxpayers from paying incentives to foreign producers and the industry from cheaper competition--though I'm not sure how competitive Brazilian cane ethanol really is these days, with sugar trading at around $0.30/lb ex duty. (As I understand the tradeoff, a gallon of cane ethanol consumes roughly the same raw materials as 10 lb. of cane sugar.)

It's a tribute to the greatly expanded scale of renewable energy that the price tag for the one-year extension of these three incentives is as high as it will be. This year, even with US wind turbine installations running well behind their record pace in 2009, the Treasury has spent $3.9 billion on the grant program for projects installing geothermal, solar, wind and other renewable electricity equipment. With continued strong growth in both solar thermal and photovoltaic projects and even a modest uptick in wind installations, the tab for 2011 could easily break $4 B. (A separate manufacturers tax credit, which had a better claim on creating green jobs here in the US, was not extended.) Meanwhile, with conventional ethanol and biodiesel blended at the mandated rates for next year, they should account for around $5.9B and $0.8 B, respectively. That comes to $10.7 billion for all three programs.

Although the tax compromise has extended the energy policy status quo for another year, change is in the air. With continued, though narrower bi-partisan support, the ethanol industry's argument that its tax credit is still necessary after 32 years--even with a steadily increasing RFS mandate--is losing credibility. Part of the industry would prefer this money to be spent encouraging infrastructure for E85 and other higher-percentage blends that represent ethanol's future growth opportunity, if any. As for the Treasury Grants, a temporary stimulus measure intended to make up for the disappearance of the tax equity market during the financial crisis, the defensibility of treating the investment tax credit on which it is based differently from any other credit in the tax code is waning. This mechanism looks increasingly exposed as the broader category of "tax expenditures" becomes an obvious target for deficit cutters, and the justification for extending it beyond next year would probably vanish if the Congress enacted legislation along the lines of Senator Graham's Clean Energy Standard. The industry should make the most of the current Christmas package, because the odds are against a repetition of it turning up under next year's tree.

Wednesday, December 15, 2010

Natural Gas and The Gulf Hiatus

With so much attention focused on the boom in natural gas from new shale resources, we shouldn't lose sight of the importance of domestic offshore gas, mainly from the Gulf of Mexico. Although it has been declining for the last decade, offshore production still accounts for about 13% of US gas output. Before the Deepwater Horizon disaster the Department of Energy expected that proportion to increase again to as much as 18% of a larger total. However, if drilling in the Gulf doesn't resume--and fairly soon--not only could that portion of our supply deplete rapidly, but its shrinkage would erase much of the incremental contribution from shale gas, a scenario depicted in the chart below. If that occurred, ambitious plans to capitalize on shale gas to displace coal or imported oil would be nullified, and gas prices would shortly revert to their previous upward trajectory.

Despite the official end of the deepwater drilling moratorium and the recent release of new guidelines to aid the industry in filing for deepwater permits, it doesn't look like drilling has resumed or is likely to do so any time soon. Meanwhile, deepwater drilling outside the US seems to be recovering rapidly. It's almost irrelevant whether the ongoing US offshore hiatus is the result of the complexity of new rules and regulations, inadequate staffing of the reorganized Bureau of Ocean Energy Management, Regulation and Enforcement, or what some believe is a tacit, unofficial moratorium on the part of the administration. Together with the recent withdrawal of plans to lease portions of the Eastern Gulf of Mexico, where significant gas resources had already been discovered, the hiatus threatens to return the US to our previous situation of increasing reliance on LNG imports, in spite of growing shale gas output.

Aside from the gas volumes and the significant number of industry and related jobs involved, there's also a fair amount of government revenue at stake in the form of forgone royalties and bid bonuses. Salazar's announcement indicated new offshore leasing wouldn't resume until late next year, at the earliest. That wipes out at least $500 million of expected bonuses--the figure for 2008 was $6.9 B--and the aggregate production decline resulting from no new drilling would lead to a steadily increasing loss of annual royalties, as existing fields deplete and aren't replaced. Between extended environmental studies, delayed permits, and areas re-designated as off-limits that were expected to be available within the 2007-12 cycle, our offshore energy supplies are looking precarious, and that will eventually influence the price we pay for energy--for both gas and imported oil. Recent polling suggests the majority of Americans understand that.

As I've noted before, no one expects things to revert to the way they were before this summer's massive oil spill. However, if we erect too many obstacles in the way of exploiting the abundant hydrocarbon resources of the Gulf of Mexico--even for natural gas, which although subject to the risk of blowouts presents little or no risk of spills like the one from the Macondo well--the costs will not just be financial; they will extend to our environment and energy security.

Monday, December 13, 2010

The Post-Kyoto World

Saturday's conclusion of the Cancun climate talks yielded modest agreements that allowed the meeting to be described in positive terms by its hosts and organizers, but at least on the major question of a globally-binding treaty to extend or replace the expiring Kyoto Protocol, it merely kicked the can down the road to the late-2011 session in Durban, South Africa. As low as the expectations going into Cancun were, keeping the UN climate process on life support looks like a good result, compared to last year's fiasco in Copenhagen. However, in light of the objections raised by Japan, Russia, Canada and others, it's difficult to see how the Durban meeting could succeed where Cancun and Copenhagen failed. It looks increasingly likely that the replacement for Kyoto might appear face-savingly similar, but will lack that document's cohesiveness and global authority.

As I read the portion of the "Cancun Agreements" dealing with the extension of the Kyoto Protocol beyond its previously-set 2008-2012 term, the delegates mainly agreed to keep talking and to try to come up with a framework in time to avoid a "gap between the first and second commitment periods." Considering that last year's session in Copenhagen was widely viewed before its start as the last, best chance to accomplish that goal based on the timeline set in Bali two years prior, the end of 2011 looks pretty late in the game to deliver on that. Moreover, while Cancun was able to get by on low expectations, Durban will be unable to repeat that trick and avoid the kind of set-up that helped doom the Copenhagen talks.

The chasm that remains to be bridged doesn't seem to have changed much: the developing countries still insist on binding emissions reduction targets from the developed countries, to which the UN process attributes the majority of emissions under the "principle of historical responsibility, their emissions debt and addressing the needs of developing countries", but won't commit to binding targets themselves. (I've discussed this notion of "emissions debt" previously.) But while the US has signed up for voluntary emissions reductions under the Copenhagen Accord, it won't agree to binding cuts unless the world's largest emitter, China, also does. And all China appears willing to agree to, based on its Copenhagen commitments, is the sort of productivity-based reductions that the rest of the developed world rejected when the US advanced this idea for managing our emissions in the first term of the Bush administration. Even if China succeeds in cutting its emissions per GDP by 40-45% while its economy continues on its present growth trend, its overall emissions would still increase in absolute terms. Japan and some other Kyoto signatories are understandably reluctant to sign up for deeper cuts themselves, unless the world's two biggest emitters commit to sharing their pain.

And this is where the timing of any substantive Kyoto extension hits the wall of US politics. If the administration wasn't able to pass cap and trade legislation in the last Congressional session, when its party had an effective majority of 60 seats in the US Senate in 2009 and 59 in 2010, the prospect of ratifying a climate treaty with a majority of just 53 next year--including one who campaigned vocally against cap and trade--is nearly non-existent. The administration is struggling just to get the new strategic arms treaty with Russia ratified in the Lame Duck session--a treaty with solid bi-partisan endorsements from the foreign policy leadership of past administrations. The likely reception for a new climate treaty would be much less favorable than that until at least 2013 and probably beyond, in light of the ratio of seats up for reelection in 2012.

Unless I'm missing something major, without the US and China on board for binding cuts Japan and others won't agree to deeper reductions in the next round of Kyoto. That doesn't mean that the Durban Climate Conference won't cobble together an eleventh-hour agreement that looks like an extension of Kyoto, in order to avoid an irreparable rupture between the developed and developing world parties to the talks. The subtext for that is already in place in the Cancun outcome. However, it seems highly unlikely that such a document would actually do what Kyoto was intended to do. As a result, the UN process seems to be consigned to focusing on the secondary areas that progressed in Cancun, relating to funding for adaptation and technology transfer, and emissions reductions from sectors like land-use changes and forestry. With the economies of the developed world looking as weak as they do, and with domestic expenditure cuts in the EU having generated noisy and sometimes violent protests, coming up with the funding for those efforts looks more than challenging enough for now.

Friday, December 10, 2010

Temperature Extremes and EV Battery Trade-offs

The first production-model Nissan Leaf electric vehicle is scheduled to be delivered to a customer in the San Francisco Bay Area tomorrow. I know if I were on the receiving end, I'd be as excited as a kid on Christmas morning, particularly in a place where having the first Leaf will score its owner many green points. However, if the assessment by MIT's Technology Review of Nissan's choices concerning the temperature control of the Leaf's battery pack is accurate, then it's probably just as well that the first one is going to a location with such a benevolent climate, instead of the Midwest, upstate New York, or the desert Southwest. Batteries are sensitive to external temperature, in terms of both performance and longevity, and Nissan appears to be betting that making the battery simpler to replace is a higher priority than optimizing its condition at all times, as GM has done for the battery pack in the Chevrolet Volt.

It's easy to forget that batteries are fundamentally chemical, rather than just electronic devices. The chemical reactions in a battery absorb or release heat during the charge/discharge cycle, and the capacity of the battery's environment to accommodate those heat flows can affect these reactions. For a battery pack storing and delivering as much energy as required to run a car, these interactions are significant, and early adopters of EVs are already learning that the range of EVs becomes more limited in hot or cold weather. It's not as clear that they understand the degree to which extreme temperatures can degrade battery life. The economics of an EV could look very different if a battery pack only lasted six or seven years, instead of ten.

As the article explains, GM chose a liquid cooling system for the battery pack in its Volt range-extended EV. This system cools or heats all of the battery's cells, as necessary, and sometimes draws power for this purpose even when the vehicle is parked, as I learned when I test-drove one with the Volt's Vehicle Line Director last winter. According to him, GM's design team knew it had to go to extraordinary lengths to ensure the battery would perform reliably and last the expected ten years or 150,000 miles. Nissan appears to have taken a different path to battery management, providing a cooling fan for the battery pack and an optional battery heater--an option reportedly not available on the first Leafs. You don't have to be an expert in heat transfer to guess that air won't move heat around the battery pack's cells as well as liquid can, and that as a result, at least part of the Leaf's battery could potentially be exposed to more heat and cold--and possibly suffer more performance impact from them--than the Volt's.

That trade-off might reflect a different vision for how the battery will be used. Nissan (with its alliance partner Renault) is the main carmaker working with Better Place, Shai Agassi's EV battery recharging-and-exchanging start-up. A battery pack with only electrical connections to the car will be much easier and neater to swap in and out than one with liquid hoses running to a radiator and heater. This situation wouldn't even be a consideration for the Volt, which has an onboard generator to take over when the battery's charge falls too low. But for battery-only EVs, battery-swapping is as close as they can get to replicating the convenience of refueling a gasoline or diesel car in a few minutes. If EVs catch on via a business model like Better Place's, in which consumers routinely exchange their flat batteries for fully-charged ones (and might not even own the battery pack, but instead rent it by the month or the mile) any shortcomings from Nissan's less robust battery-conditioning strategy would fall on someone other than the consumer, as a statistical cost of doing business.

From my perspective this is just one of the uncertainties concerning the operation and consumer acceptance of EVs about which we'll learn more as their numbers climb from the low thousands to the hundreds of thousands and millions. However, I find it interesting that few journalists have picked up on an issue that could have far more impact on the EV ownership experience than the tempest in a teapot that some stirred up when they found out that the Volt's wheels are occasionally driven partly by the engine-generator, rather than entirely electrically. If I were buying one of these cars, I'd be a lot more interested in how far its expensive battery pack will carry me and how long it will last, than in whether the car is truly a range-extended EV or just a plug-in hybrid.

Wednesday, December 08, 2010

Worse than Coal?

As I noted in last Wednesday's posting, one of the questions that came up in a webinar on shale gas in which I participated concerned the climate consequences of higher recent estimates of methane leakage from US natural gas systems. In reading further comments and blog postings on this subject, I was surprised to see assertions that went beyond drawing attention to the importance of the leakage of a high-value, high global-warming-impact gas, to suggest that the apparent rate of leakage renders the lifecycle emissions from natural gas as bad as those from coal, or worse. If that were true, it would have significant implications not only for the development of shale and other natural gas resources, but also for our entire emissions reduction strategy. From what I can tell, however, such claims have not been substantiated by current studies.

Several comments I received in email or on the posting pointed to the work of Professor Robert Howarth of Cornell University, and specifically to a press release describing a paper he has apparently submitted addressing the climate impact of methane leaks from shale gas production, transportation and storage. Until the details of the paper are available, the information provided in the press release simply doesn't stand on its own or merit further analysis. In the meantime, a recent EPA report evaluating greenhouse gas emissions from the oil and gas industry identifies significantly higher estimates for methane emissions from natural gas systems than those incorporated into that agency's most recent US Greenhouse Gas Inventory. I became aware of the EPA report in the course of reading one of the blog postings I alluded to above.

The EPA estimated the total CO2-equivalent methane leakage from the production, processing, transportation, storage and distribution of natural gas in the US in 2006 at 261 million tons per year. That amounts to more than 4% of total net US emissions for that year, so it is hardly insignificant. It's also about 2.5 times the figure reported in the agency's latest GHG inventory. Converting that quantity back into natural gas at normal conditions yields 656 billion cubic feet of gas, or 3.4% of marketed US natural gas production in 2006. That's a lot higher than typical leakage estimates of less than 1%, as David Lewis notes in his blog. The question is whether this higher level of leaks, or some even higher notional level of leaks proposed by other critics, would be sufficient to make the emissions from gas worse than those from coal.

To understand why that might even be possible, you have to know something about the relative strength of different greenhouse gases (GHGs). While much of the public's attention has been focused on CO2, the most prevalent man-made GHG, other gases have dozens or hundreds of times the impact on climate, per ton. Because of the way it decays in the atmosphere, methane's global warming potential (GWP) starts high and diminishes over longer time spans. Most reports, including the EPA's, use a 100-year GWP estimate indicating methane is around 21 times worse than CO2.

However, it's not correct to infer from that that upstream leaks of 3.4% of all natural gas must therefore inflate the lifecycle emissions of the gas we consume by 21 times 3.4%, or 71%. That's because a ton of methane doesn't convert to a ton of CO2 when burned; it yields 2.75 tons, as a result of basic high school chemistry:

CH4 + 2O2 --> CO2 + 2H20

So for each ton of natural gas, it's roughly 7.6 time worse for it to be vented or leaked than burned, after adjusting methane's standard GWP for the ratio of molecular weights from the above reaction equation. In fact, when I added the EPA's latest methane emissions estimates to their figures for indirect and direct CO2 emissions from natural gas in the GHG inventory, the result was very close to the 26% increase you'd get from multiplying 3.4% by 7.6. As a result, although the emissions advantage of natural gas over coal is less than it would be without such a high rate of leakage, gas still emits 35% less CO2 equivalent per BTU over its lifecycle than coal, on average.

When you consider how natural gas actually competes with coal, its effective emissions advantage should be larger than that. Even after accounting for upstream emissions (including leakage) that add 30% to its CO2 emissions from combustion, an efficient combined-cycle power plant still generates electricity with emissions per kilowatt-hour that are more than 40% lower than those from a highly-efficient coal plant. That's because the combined cycle turbine converts more than half the BTUs in its fuel into electricity, while the coal plant converts less than 40% of coal's BTUs into power. Fewer BTUs for the same output results in fewer emissions.

I don't claim my back-of-the-envelope analysis is definitive, but it certainly doesn't support the notion that gas is worse than coal. Barring conclusive evidence of a much higher level of upstream natural gas leakage than indicated by the EPA's latest work on the subject, natural gas--even with existing infrastructure--could reduce the emissions associated with coal use in power generation by at least a third, and by much more than that depending on the specific generating facilities involved. At the same time, that shouldn't be read as excusing avoidable leaks of gas. If that 3% figure is accurate or low, then several billion dollars worth of gas--even at today's depressed prices--is escaping into the atmosphere rather than being captured and turned into useful energy by gas customers. That sounds like the epitome of low-hanging fruit to me.

Monday, December 06, 2010

Turning Biomass into Power or Fuel

This morning I ran across a news item indicating that Dow Chemical was installing a biomass cogeneration unit at its facility in Aratu, Brazil to provide process steam with minimal greenhouse gas emissions. It's a good example of another way to convert biomass into energy that hasn't attracted nearly as much interest as advanced biofuels have. That's somewhat surprising, since biomass power shares most of the logistical limitations but few of the technical challenges that have made the production of biofuel from non-food biomass so difficult. Perhaps the relative neglect of biomass power results more from motivation than outcomes.

I'm sure I paid more attention to this story because of Dow's choice of eucalyptus as the biomass source. I grew up under the spreading limbs of a giant eucalyptus tree in California--limbs that periodically fell off in storms, including a 9-ton monster that practically cut our house in half. In the years before that tree was finally cut down I raked up enormous quantities of the eucalyptus leaves and nuts that bombarded our yard. It would be fair to say that I developed a strong distaste for the species, at least for the ornamental and wind-break purposes for which many Californians had chosen this Australian import. However, many of these same features, including its fast growth and dense, oily wood, seem to be good attributes for biomass supply.

As noted in a recent Wall St. Journal article, the Achilles heel of biomass power is logistics. The lower the energy density of the biomass, relative to the fossil fuels it is intended to replace, the closer the source must be to the facility where it will be used, before transportation erodes any cost benefits, even after considering emissions reductions. Wood chips provide about 2/3 as much energy per pound as bituminous coal, but they can take up more than six times as much volume, unless they are first dried and turned into pellets. As is the case for cellulosic biofuels, these supply-chain considerations limit the scale of biomass power application and impose an additional constraint of sustainability: It doesn't pay to build a biomass power plant (or a cellulosic biofuel plant) unless you can be sure of a long-term supply of the raw material. The Journal article included examples of projects that paid a high price for miscalculations in this regard. One strategy for mitigating this limitation is co-firing, which relies on biomass for only a portion of a power plant's fuel needs.

The lower energy density of biomass also makes it essential to extract as much energy as possible from each pound or cubic foot. One of the reasons for the high efficiency of the Brazilian ethanol industry is that many of its mills turn the bagasse, the waste left over after extracting the juice from sugar cane, into process heat and power and need little or no fossil energy. Burning biomass in a high-efficiency combined heat and power application, as the Dow project appears to do--based on the scant information I could find--provides another way to get the most bang for the biomass buck.

That brings us back to motivation. One of the main justifications for the pursuit of cellulosic biofuels is that we have relatively few practical, cost-effective alternative fuels that could replace more than a small fraction of our petroleum use. On the other hand, we have many ways to generate electricity, including more than a few that emit little or no greenhouse gas, one of the main benefits of biomass power--though this point is not without controversy. However, I can't help wondering whether in the long run the best way to turn non-food biomass into energy for vehicles is to turn it into electricity first, rather than working so hard to break down plant structures that have evolved over millions of years to resist easy conversion into chemical energy. Resolving that dilemma depends on a lot more than engineering considerations, however, since we still don't know much about how consumer preferences will play into it. In the meantime, projects like Dow's provide another option for reducing emissions from facilities that must meet increasingly stringent sustainability criteria.

Friday, December 03, 2010

Will Oil Prices Rescue Ethanol?

Time is running out for the ethanol blenders credit and the matching ethanol import tariff, which at least one industry publication suggests are likely to survive, but at "sharply reduced rates." Although I'm among those who suspect that the blenders credit probably benefits consumers more than ethanol producers, as long as the national Renewable Fuel Standard is binding on blenders, it seems fortunate for the US ethanol industry that this situation is playing out when crude and gasoline prices have risen to levels we haven't seen since spring, and could go higher if current economic indicators hold up.

The US benchmark futures price for crude oil is suddenly flirting with $90/bbl again, and UK Brent crude, a better gauge of world oil prices whenever WTI inventories at Cushing, OK are this high, has already surpassed that mark. Even if oil's move is at least partly the result of recent currency fluctuations, it is supported by fundamentals in the form of gasoline and distillate inventories that for the first time in months are back within their normal seasonal ranges. Crack spreads, an indicator of refining margins, look strong, reflecting solid demand. All of that suggests that if crude prices move higher, increases will be passed on in product prices, rather than being absorbed partly by refiners. That doesn't sound like good news for motorists, but how could it help compensate the ethanol industry for the potential loss of some or all of the $0.45 /gal. blenders credit?

It helps in two ways. First, by pushing wholesale gasoline prices above those for prompt ethanol even without factoring in the credit, this gives refiners more incentive to add as much ethanol to gasoline as they can, to increase their profit margins. That should put positive pressure on ethanol prices, even as blenders approach the 10% "blend wall" that the recent EPA decision on E15 hasn't yet affected. That opens up headroom for ethanol producers who have recently seen their margins, or "crush spreads", squeezed by strong corn prices. And it's especially crucial for those producers who only recently emerged from Chapter 11 protection after a protracted margin squeeze in late 2008 though mid-2009. This is an industry that spent the last five years in a frenzy of capacity building, and that only escaped creating a severe and persistent glut of ethanol because some of the marginal operators couldn't afford to run their plants. If gasoline prices fell while corn prices remain high, losing the blenders credit could put a number of plants back into bankruptcy; rising gasoline prices constitute a lucky break.

It's anyone's guess whether the present configuration of markets will remain in place long enough to ease the ethanol industry through the transition it faces after December 31, if the Congress cuts the blenders credit and tariff or allows them to lapse. After all, Europe has just dodged another bullet with Ireland, and the Euro could come under renewed threat from Portugal, Spain or Italy at any time. If recent shopping results are any indication, the US economy is looking healthier, although joblessness remains high and unemployment benefits for millions are set to end before the holiday bills come due. If oil prices swooned in the next few weeks, consumers might be relieved, but ethanol producers would see it as another lump of coal in their stocking.

Wednesday, December 01, 2010

Is Shale Gas Too Good to Be True?

Yesterday I participated in a webinar examining the sustainability aspects of the shale gas revolution. The online audience asked good, probing questions, and if there was a theme to them, it seemed to be that somehow the sudden abundance of natural gas resulting from a novel combination of shale-exploitation technologies--as well as the technologies themselves--must at a minimum be considered a mixed blessing, if not actually too bitter a pill to swallow, because of its perceived shortcomings and the potential threat it poses to other, favored energy technologies. I find that simultaneously understandable and unfortunate.

I came of age just as US attitudes concerning energy shifted from the assumption of perpetual abundance to perennial insecurity and periodic scarcity. Energy security has been a consistent theme of public discourse for my entire adult life, varying only in intensity as we lurched from crisis to crisis with long respites in between. If the shale gas revolution had arrived thirty years earlier, I'm confident it would have been embraced as a national windfall--a jackpot lottery win. After all, we're talking about a newly accessible resource that is equivalent to finding an Iraq's worth of hydrocarbons under our feet, not deep offshore or in some distant country. Yet despite boosting US gas production to levels unseen since the early 1970s and resetting gas prices to pre-2000 levels, after adjusting for inflation, the reception of shale gas has been decidedly mixed, as witnessed by yesterday's vote by the New York legislature to impose a six-month moratorium on gas drilling in a state overlying a portion of one of the largest gas reservoirs in the world.

Shale gas isn't the silver bullet for our energy and emissions problems, but it can contribute significantly towards alleviating both. Combined-cycle power plants burning gas emit only about 45% as much greenhouse gases as best-in-class coal-fired power plants, and comparisons to the oldest, least-efficient US coal plants are even more favorable. At current gas prices, which are mainly the result of the shale gas boom, the resulting power is cheaper than from any renewable source without substantial subsidies, and than most even after subsidies. In the last several years gas-fired power plants have taken market share from coal equivalent to the entire output of all US wind farms, and there's no wait for scaling-up.

At the same time, the concerns about shale gas reflected in some of yesterday's questions are entirely understandable, particularly in an era dominated by low trust in all institutions. For example, is it possible that unreported natural gas leaks are releasing enough methane, which is a strong greenhouse gas, to offset all the emissions benefits from gas-fired generation? Perhaps, even though the gas leaks identified in a new GAO report amount to just 0.2% of US marketed production, and thus equate to only about 6% of the CO2-equivalent emissions associated with US gas consumption. But as I noted in the webinar, even if the leaks are in fact much larger they are controllable; they are not an inherent feature of shale gas production in the way coal's CO2 emissions are inherent in coal combustion.

Concerns about water consumption and safety hit even closer to home. Having reviewed the list of fracking chemicals on Halliburton's website, I wouldn't want them in my drinking water, either, any more than I'd want my family consuming any of the various household chemicals under our kitchen sink or elsewhere in our home. However, there's nothing about the process of hydraulically fracturing shale strata thousands of feet deeper underground than the deepest aquifers that puts our drinking water at any greater risk than many routine industrial or agricultural operations. As a technology fracking is neither newer nor riskier than many other things to which we don't give the slightest thought. Much of the attention it has gained is the result of its application in unaccustomed places--a reaction shared by wind turbines, utility-scale solar plants, and long-distance transmission lines.

The biggest uncertainties associated with shale gas don't concern the size of the resource or our ability to extract it safely, but whether we will decide to allow this to be done on a scale that would make a meaningful difference in our energy and emissions balances, or under such tight restrictions that we will forgo its game-changing potential. Like anything, shale gas drilling and fracking must be done responsibly, in accordance with state and local regulations and to industry standards that are constantly improving. Post-Deepwater Horizon, that's a much tougher sell, but it doesn't make it any less important. Shale gas isn't perfect energy, not because of any unique imperfections, but because there is no perfect energy source. It requires mature, reasonable assessments of its risks that don't assume that there is.

Monday, November 29, 2010

Cancun Climate Talks: Irrelevant?

The mood going into this week's global climate conference in Cancun, Mexico is decidedly different than that for last year's session in Copenhagen, which had been intended to culminate the process begun two years earlier in Bali. It's not just that expectations for a comprehensive and binding global climate treaty have been dramatically lowered; much of the debate since Copenhagen has moved away from the notion that it's even possible to reduce emissions sufficiently to avert many of the adverse consequences of a warming and less stable climate. It's no coincidence that the cover story of this week's Economist is dedicated to the increased need for adaptation to climate change, while the lead op-ed in the energy pull-out section in today's Wall St. Journal highlights an agenda for making clean energy the cheapest kind--not by subsidizing it even more than we already are, but by driving innovation.

After describing the magnitude of the challenge involved in decarbonizing the global economy by enough, soon enough, to limit the increase in global average temperatures in this century to 2° C, The Economist concludes, "The fight to limit global warming to easily tolerated levels is thus over." That doesn't mean that agreements to bend the trajectory of emissions growth below the status quo trendline aren't worth pursuing, but it suggests that we need to devote much greater attention and resources to adapting to a world that will likely include more droughts, floods, famines, and human migration than we've had to deal with thus far, and for which both the drivers and consequences are being amplified by economic development and population growth. The Economist sees climate adaptation focused on three main areas: infrastructure, migration and food, and their analysis is worth reading.

Another factor I believe the magazine should have highlighted is the difficulty of undertaking any of these efforts at a time when the developed world is hobbled by weak economic growth and related deficit and debt problems that threaten to render even the current level of subsidies for renewable energy sources unsustainable. As the EU grapples with the debts of Greece and Ireland, with Portugal and Spain waiting in the wings, it's no accident that Spain has just cut its feed-in tariff for solar power, which had already been reduced from previously lavish levels. The elephant in the room in Cancun, as it was in Copenhagen, is that binding agreements requiring severe emissions reductions by and large transfer payments from the developed countries might have looked attainable when the economy was booming, but they have become much less feasible in the wake of the worst recession and financial crisis since the Great Depression.

That same fundamental challenge makes the innovation arguments raised by Ted Nordhaus and Michael Shellengerger of the Breakthrough Institute more urgent than they would be otherwise. Because today's renewable energy technologies remain more expensive without subsidies than coal, oil and natural gas--even when the consumption subsidies the latter receive are stripped away--the cost of replacing our existing, high-emitting energy sources with entirely green ones looks unaffordable in today's world. I would add that reliance on experience curve effects--building out a subsidized green energy economy and depending on volume to drive down its cost to the point of competitiveness--is unlikely close that gap, and where it can, there is no guarantee that the country providing the incentives will receive the benefits it is entitled to expect. To cite the most obvious current example, Germany has invested tens of billions of Euros subsidizing solar energy and has indeed created a globally competitive solar industry--mainly in developing Asia.

What makes Nordhaus and Shellenberger's suggestion seem much more practical than global climate treaties and mountains of green subsidies is that the money currently being spent on renewable energy deployment incentives, which constitute a small fraction of the total annual investment in energy infrastructure, would go much farther buying R&D, rather than hardware. The US investment tax credit paid to a single 100 MW wind farm could fund an entire university energy innovation laboratory and graduate degree program.

Of course none of these strategies should be regarded as entirely either/or propositions. Adaptation doesn't let us off the hook for trying to address the causes of climate change, nor does shifting more of government's limited resources into clean energy R&D mean we don't need any of the real-world learnings that only come from deploying technology and seeing how it works under uncontrolled conditions. There's also a parallel role for research into geoengineering to provide a backstop--a potential Hail Mary pass--should all of these other efforts fall short and climate change move beyond a range we can live with. If nothing else, the COP 16 meeting in Cancun might shed more light on the degree to which the UN body is the right umbrella to cover all this work.

Tomorrow at 1:00 PM EST I'll be presenting in a webinar entitled, "Natural Gas: Sustainability Friend or Foe". To sign up follow this link.

Tuesday, November 23, 2010

Chicago's Climate Exchange Shuts Down

I see that the Chicago Climate Exchange (CCX) will be winding down its CO2 trading operations by the end of the year and laying off staff. This is only surprising considering that the parent company of the CCX was acquired just this summer by the Intercontinental Exchange, though mainly for its successful European emissions trading market. In case you were wondering how long the odds against enacting cap & trade legislation in the US have become, the demise of the CCX is a signpost you can't ignore. If the symbolism of a popular Democratic governor using the Waxman-Markey climate bill for target practice during his recent successful bid for the US Senate wasn't clear enough, it looks like his bullet may have also hit the CCX.

I recall a meeting with one of the founders of CCX at Texaco's corporate headquarters in New York prior to my leaving the company at the end of 2001. At that time, Texaco's management was coming around to the idea that sooner or later emissions of CO2 and other greenhouse gases would carry a price, for the first time in human history. Cap & trade offered a proven way to discover that price, based on the pioneering experience of US markets for sulfur dioxide, a cause of acid rain, and nitrogen oxides. The principles of emissions trading had been embedded in the Kyoto Protocol, largely thanks to the efforts of the US delegation, and European countries were setting up the precursors of the EU Emissions Trading System to manage mandatory carbon reductions. Such developments still appeared to be somewhere over the horizon in the US, which never ratified Kyoto, but they seemed likely to find their way here, eventually. One of the main selling points of the CCX, which was based on voluntary emission reduction commitments by member companies, was that it would provide valuable early experience in a formal market for emissions reductions, giving participants a leg up when such trading was required by law. This argument didn't persuade my former employer, but a number of other companies signed up.

If this scenario now seems like a quaint strand of alternate history--a "what if?" that never materialized--that perspective is quite recent. The prospects for CCX and wider emissions trading looked reasonable for a long time. The value of the CCX contract peaked in mid-2008, when it had become apparent that the ultimate presidential nominees of both major US political parties would be candidates who supported cap & trade, with the Republican even having previously co-authored Senate legislation on the subject. After a severe dip during the worst of the financial crisis, the contract recovered to around $2/ton after the new administration took office, but then swooned again as the Waxman-Markey bill, with its heavily skewed version of cap & trade, neared passage. As the likelihood of parallel Senate action on climate legislation receded, it never really recovered.

In its editorial on the termination of the Chicago Climate Exchange, the Wall Street Journal suggested that the market has delivered its verdict and the idea of national-level cap & trade is now dead in the US. Perhaps, but it certainly doesn't signal an end to all CO2 trading here. Aside from the state and regional programs to which the Journal alluded, companies with global operations subject to emissions caps in other countries will still be active participants in non-US emissions markets, and firms that remain committed to voluntary reductions in the US may continue to trade with each other, via brokers, or with over-the-counter market makers.

For that matter, I can't help wondering whether cap & trade is truly as dead as a Monty Python parrot or just resting. I'm reluctant to let go of an idea I've supported for a long time, but I also still see significant advantages for cap & trade over other means of putting a price on greenhouse gas emissions. Although the idea of carbon pricing may have gone out of fashion in the US, major tax reform for the purpose of deficit reduction could make it much more difficult to provide the monetary incentives for renewable energy technologies that we do today. Without those subsidies or a price on CO2, renewables will have a hard time competing with fossil fuels. And if our only other choices for emissions reduction were mandates or the command-and-control approach for which the EPA is now gearing up, then cap & trade and the emissions trading that makes it work might no longer look quite so appalling to their critics. In that case, the companies that participated in the CCX during the last seven years might not have wasted their time, after all.

FYI, I'll be participating in a webinar on the sustainability aspects of natural gas next Monday at The Energy Collective . To sign up follow this link. In the meantime, I wish my US readers a very enjoyable Thanksgiving. New postings will resume next week.

Friday, November 19, 2010

Energy Implications of Tax Reform

I've been thinking about the implications for energy of a major deficit reduction effort along the lines suggested by the co-chairs of the President's fiscal responsibility and reform commission. Our present approach to providing incentives for various energy sources and technologies, new and old, is embedded in a tax code and taxation philosophy that might not survive the upheaval required to bring the US deficit and resulting federal debt back into a manageable range. This goes far beyond the comparatively minor question of extending expiring grants and tax credits that I discussed the other day; under the most stringent of the proposals from Mr. Bowles and Senator Simpson, such things wouldn't even exist. It's not clear how the Administration or Congress would promote favored energy technologies and strategies without these well-established but costly tools.

Start with renewable energy. We currently promote renewable fuels and electricity generation with a combination of mandates--policies such as the federal Renewable Fuels Standard (RFS) and state Renewable Portfolio Standards--and subsidy payments. Until last year's stimulus bill established the Treasury renewable energy grants, for which eligibility is due to expire in a few weeks, most of those subsidy payments have come in the form of reductions in federal taxes, via either an investment tax credit (ITC) based on the cost of a project or a production tax credit (PTC) for actual energy generated. Both of these measures, which have had a checkered history of expirations and extensions, fall into the broad category of "tax expenditures". The Zero Option proposed by Messrs. Bowles and Simpson would permanently eliminate over $1 trillion of such tax expenditures, in exchange for much lower tax rates.

Even if the renewable energy tax credits were reloaded into a streamlined tax code under the "Wyden-Gregg-style" reform presented as Option 2 from the co-chairs, the value of those credits would be reduced--or at least rendered harder to extract--because the corporate tax rate would be reduced from the current 35% to 26%. That means that a higher proportion of companies would likely not pay large enough taxes to take full advantage of the renewable energy tax credits--or have as much appetite for others' credits via "tax equity" swaps. Compounding that, the likelihood of enacting cash grants to get around this restriction would probably be much lower in an environment in which entire herds of sacred cows were being slaughtered in the cause of averting a looming national deficit and debt crisis.

In the absence of such tax credits, renewable energy developers and manufacturers would be forced to rely even more on state-level mandates or a proposed federal renewable electricity standard. The first test of such a mandates-only approach might come in a few weeks, if the ethanol blenders' credit is allowed to expire, while the annual RFS mandate continues to ratchet up. Or companies might simply conclude that without generous tax subsidies for renewable energy deployment here, their best opportunities would be found in markets that are growing much faster than ours, based on actual energy demand, rather than better incentives. Developing Asia comes to mind. That shift might not be the worst outcome, in terms of both the US trade deficit and global emissions reductions.

Conventional energy firms wouldn't escape unscathed, either. They stand to lose significant tax expenditures as well, in the form of oil & gas depletion allowances, the Section 199 manufacturing deduction, and other benefits. However, the oil and gas industry has been paying an effective corporate tax rate above 40% even after all these credits and deductions. A drop to 26% might more than offset the loss of the other benefits, while more importantly bridging the competitive gap between US firms and foreign competitors that operate under lower tax rates and a territorial tax system, rather than being taxed on worldwide earnings, as US companies are today. Bowles/Simpson also proposed increasing the federal gasoline tax by 15¢ per gallon to restore the Highway Trust Fund to solvency. That's a worthy goal, but as I've pointed out previously the Highway fund faces complex challenges as the US car fleet becomes steadily more fuel efficient and increasingly moves away from liquid fuels taxed at the pump. Raising the gas tax is a stop-gap measure, at best, on the way to a different means of collecting road taxes.

With regard to climate policy, tax reform that eliminated tax credits or reduced their value would also tend to nudge the debate back in the direction of putting an explicit price on carbon, either via cap & trade or with an outright tax. Might that prospect suddenly look more attractive as an adjunct to a fairer and simpler income tax system, than it seemed when it would have come as a further complication to an already enormously convoluted tax system that is widely viewed as unfair by both liberals and conservatives? My guess is not, without something else that motivates us to tackle climate change on a much more urgent basis.

Now let's come back to reality. The proposals of the commission's co-chairs have already received a frosty reception or outright hostility from both sides of the aisle, and they haven't yet gotten the buy-in of the rest of their team; the final report requires the consent of 14 of the 18 members. Their ideas must also compete with a growing number of deficit-reduction alternatives, including a widely-reported plan from another bi-partisan group, plus at least one solo proposal from another member of the President's commission. The chances are low for any of these proposals to gain enough traction to be enacted without first being significantly watered down. However, it is starting to look just as risky to assume that the present tax system--and its cornucopia of energy incentives--will continue unchanged indefinitely. A quick glance at the US debt clock ought to make that abundantly clear.

Wednesday, November 17, 2010

Closed-Loop Energy

This morning I received an emailed press release announcing that the Altamont landfill gas facility in California had been recognized by the state's governor for its achievement in sustainability. What makes this facility unique is that the methane gas generated by the landfill waste is collected and turned into liquefied natural gas (LNG) in a plant run by a joint venture of Waste Management and the North American subsidiary of the Linde Group and then used to power garbage trucks that haul San Francisco's waste to the landfill. That effectively "closes the loop" by turning trash into fuel to collect the trash. It's a clever concept, but I admit to being initially skeptical about the companies' claim that this approach saves 98% of the greenhouse gas emissions from the diesel fuel it replaces. How can that be, when every pound of methane burned in the trucks' engines yields 2.75 pounds of CO2?

The answer to this conundrum lies in the assumptions behind the analysis of the project done by Argonne National Laboratory, which is generally considered the gold standard for lifecycle, or "well-to-wheels" analysis of this kind. Quoting from their report, "At present most of the biomethane generated at U.S. landfills is flared in conjunction with emissions-abatement practices." Since 1996, landfills above a certain threshold have been required to collect methane and other gases produced by the decomposition of refuse and either flare it or put it through a thermal oxidizer to convert the methane to CO2. That's crucial from an emissions perspective, because it reduces the landfill's greenhouse gas emissions by a factor of 21 times versus simple venting. However, the report also states that over 500 projects around the US recover energy from landfill methane, with most either using it to generate power or steam or compressing it and injecting it into natural gas pipelines, where it becomes indistinguishable from the methane produced from natural gas wells. When Argonne confirms that Altamont's LNG emits practically no greenhouse gases, that result is relative to the option of flaring it, not compared to the other uses to which the recovered gas could be put.

The appropriateness of that assumption goes to the heart of the issue of "additionality" that has made the certification of emissions credits so challenging in many cases around the world. In this case, if the Altamont landfill gas in question weren't turned into LNG to fuel San Francisco garbage trucks, would it really be flared or would it be turned into power, as other gas produced at Altamont apparently is? On one level I can't answer that without knowing a lot more about the facility than is provided either on Waste Management's site or in the Argonne analysis. However, it helps to consider that an assessment of any other use of this gas would face the same question; they can't all be compared to each other. There must be a common reference, and going back to flaring, which is the basic standard required under the Landfill Rule of the Clean Air Act, seems the most consistent choice.

With that assumption in hand, and based on Argonne's analysis of the emissions from the different steps involved in producing the LNG, it's perfectly reasonable to claim that at least compared to burning petroleum diesel in Waste Management's trucks, the Altamont LNG is a nearly zero emission fuel. The more interesting question is whether this disposition, with its obvious green PR benefits, is actually the best use of the energy recovered from the landfill. The same Argonne report indicates that the total energy consumption in the landfill gas-LNG-motor fuel pathway is about 8% higher than in the oil well-refinery-motor fuel pathway for diesel fuel. That hints at the possibility that the total emissions reductions from Altamont might be even greater if the gas were used, not to power garbage trucks, but for another purpose, such as generating power to back out electricity imported into the state from coal-burning sources in places like Four Corners, New Mexico. In any case, lest we make the perfect the enemy of the good, what Waste Management and Linde are doing at Altamont is certainly good compared to the default option of flaring all that gas, and the kudos they have received look well deserved.

Monday, November 15, 2010

Extend or Reform?

As the US Congress returns from its election recess to take up its "lame duck" session, one of many crucial pending items it will likely take up is the so-called "extenders" package: key tax provisions that are due to expire at the end of the year, unless extended by legislative action. From an energy perspective, this includes both the expiring ethanol blenders credit and the Treasury renewable energy grants issued in lieu of the investment tax credit (ITC) for renewables. Both incentives face a much more uncertain reception when the new Congress is sworn in next January, so the lame duck might just be their last gasp.

For the ethanol credit, that is as it should be; if 32 years of federal subsidies haven't made corn ethanol competitive with gasoline--particularly when its use is now mandatory--then nothing will. The situation for the renewable energy grants is more complicated. This is a relatively new benefit that, as I've noted in previous postings, was instituted as part of last year's American Recovery and Reinvestment Act--a.k.a. the stimulus--to substitute for a class of market transactions ("tax equity") that renewable energy developers could no longer access as a result of the financial crisis. Bridging that gap became all but essential for smaller companies without enough taxable earnings to take full advantage of the tax credit on their own, or lacking adequate working capital to afford to wait until their next tax filing to recoup the applicable ITC portion of the cost of a project.

If that situation still obtained, justifying the extension of the grants for another year or two would be easy. In the meantime, however, much has changed. Although not yet functioning at the same pace as before the financial crisis, the tax equity market is recovering. Banks and insurance companies have announced a growing number of tax equity deals in the last few months. This market might revive even faster if it weren't competing with essentially free money from the Treasury.

The other aspect of the situation that has changed is the growing dominance of large players in renewable energy project development, particularly for wind. Contrary to the perception that the Treasury grants mainly benefited small companies, more than half of the $5.4 billion in grants awarded to date went to just three companies, all of them large and profitable enough to have waited until tax time to collect their ITC benefits--though I don't doubt that getting cash up front improved the economics of their projects. For example, EDP Renovaveis, through its Horizon Wind Energy subsidiary, collected around $565 million in grants in the first half of 2010, after receiving "in excess of 685 million dollars" in 2009. Meanwhile, between its 3Q2010 earnings presentation and its 2009 full-year presentation Iberdrola Renovables claimed approximately $983 million in US renewable energy grants. NextEra Energy (the renamed parent company of Florida Power & Light) booked $556 million in grants in the first 9 months of 2010, on top of $100 million last year. All of this was entirely appropriate under the provisions of the stimulus, but it doesn't quite fit the picture of an emergency measure intended to help small, struggling firms.

Some have argued that in any case the grants are merely a matter of timing for the government: paying eligible developers cash now, or paying them the same amount later, via reduced taxes. That would only be true if every project that was eligible for a grant could (or should) proceed without one. Sparing wind farms, solar installations and other projects from the discipline of rigorous review by private investors risks allowing weaker projects to proceed, when they should either be rethought or cancelled. That was an unavoidable risk in early 2009, when the renewable energy industry was in peril of imploding, but overlooking it seems less justifiable today.

The Treasury renewable energy grants were instituted as an extreme step at an unprecedented time. It's hard to imagine that anyone intended them to become a permanent entitlement to replace the existing renewable energy tax credits, which were simultaneously extended through the end of 2012 for wind power and 2013 for most other technologies. However, if this program is to be extended for now, it ought to be reformed to exclude beneficiaries for which it constitutes merely a convenience, rather than a necessity. That would mean either capping the maximum payout for any recipient at something less than $100 million, or imposing a corporate income threshold. I'll be watching this issue with great interest between now and the end of the year.

Thursday, November 11, 2010

Those Other Energy Subsidies

Energy subsidies have become a hot-button issue for both renewable and conventional energy, with each side claiming the other receives more than it should. This issue is on the agenda for the meeting of the G-20 group of nations in Seoul, because they committed to the phase-out of subsidies for fossil energy at last year's Pittsburgh summit and will report on progress at this week's session. This coincides with the release of a new forecast from the International Energy Agency highlighting the urgency of phasing out these subsidies for the sake of reducing greenhouse gas emissions. It's worth noting that unlike US incentives for energy production that have attracted so much flak here, the bulk of the subsidies the G-20 and IEA want to eliminate are for the consumption of fossil fuels; most of them are provided in the developing world, often by governments that can ill afford them. Putting an end to these practices is a worthy goal, and not just because of climate change.

In addition to promoting stronger government support for renewable energy, the IEA report highlighted $312 billion in counterproductive subsidies for fossil energy last year--the figure was much higher in 2008--compared with $57 billion for all renewables, including biofuels. The subsidies in question are mainly in the form of price controls and market manipulation by governments in developing countries, including both large net energy producers and large net consumers. These governments effectively pay consumers to use more energy by keeping prices lower than free market levels. This is clearly counterproductive with regard to combating climate change, because it leads to higher emissions, but I'd like to focus on another drawback, in terms of how it affects global energy markets. Its effects haven't been as obvious recently, with demand down and spare production capacity ample for the moment, but it contributed significantly to the extreme oil prices we saw in 2007 and especially 2008.

Whether as simple as fuel price caps set by government fiat or as complex as the Philippines' former Oil Price Stabilization Fund that I used to monitor regularly in the 1990s--it acted as a sort of central bank for energy prices, until it ran out of money--these mechanisms insulate consumers from the global price of energy, usually oil. The benefits on which these measures are justified even make a certain amount of sense, in terms of protecting consumers from the effects of market volatility and promoting prosperity. If all they did was to smooth out market fluctuations while still reflecting average market values over time, those benefits might outweigh the damage these policies do to both national treasuries and to the capacity of oil prices to match supply and demand. In practice, these efforts often become politicized and end up entrenching below-market prices for their most vocal constituencies. Unfortunately, this not only boosts consumption but it also muffles or blocks price signals when global demand approaches the limits of supply, as we saw a couple of years ago.

The consequences of this are both local and global. Locally, either oil companies or oil price funds require ever greater cash infusions from governments, as global prices go up but consumers miss receiving the message to conserve. This decoupling, compounded over large segments of global demand, amplifies global price increases and focuses the necessary demand response on those countries without such mechanisms, like the US. This helps explain why oil prices skyrocketed to $145/bbl from the $70s just a year earlier, because that's what it took to force demand in non-subsidized countries down by enough to adjust for the global tightness of supply. In other words, oil consumption subsidies intended to stabilize local markets are paradoxically destabilizing for global oil markets.

It's important to draw a distinction between consumption subsidies like these and the fossil fuel subsidies that have come in for significant criticism in the US, which are focused not on consumption but on production. In fact, if their critics' claims about the unresponsiveness of global oil prices to incremental US production were right, then they would have zero impact in promoting consumption, which is the issue of concern to the G-20 and IEA. I don't believe either side of that thesis is correct. Supporting US domestic production inherently helps stabilize global oil prices by reducing US oil imports, but it likely does increase consumption modestly by nudging prices a bit lower than they'd be otherwise. That gives rise to an awkward trade-off, pitting increased energy security against slightly higher emissions, contrary to the rhetoric of some "energy hawks" who suggest that these two issues are always aligned.

In any case, as long as the G-20's efforts are focused on phasing out subsidies intended to hold down fossil fuel prices, they are on the right track, though consumers in developing countries will be in for a nasty shock when their governments follow through with this initiative. At the same time, the alternative to incentives for energy production is not their unilateral elimination, but the rationalization of tax and regulatory structures so that producers in one country aren't at a disadvantage compared to producers in another country, or to other industries in their own country. Sorting that out would require an entirely different and much more complex effort, and not just by the G-20's membership.

Tuesday, November 09, 2010

Hydrocarbons and Geothermal Energy

Geothermal power is probably the lowest-profile renewable energy option we have. It doesn't get nearly the attention that wind and solar power do--even from me--although it has been quietly cranking out about 0.4% of the US electricity supply for many years. That roughly matches the expected output of all the wind turbines likely to be installed here this year. I've commented previously on the striking similarities between geothermal exploration and production and the processes and risk profile of oil and gas E&P, but I don't believe I've ever mentioned a small but potentially important overlap between the two: geothermal heat extracted from the fluids produced from oil and gas wells. The potential contribution of "geothermal hydrocarbon co-production" (GHCP) might not be as large as from conventional hydrothermal reservoirs or engineered geothermal systems (EGS), but this approach has the advantage of capitalizing on additional energy from a source that's already being exploited.

In its report on the US geothermal industry earlier this year, the Geothermal Energy Association listed five projects involving GHCP and related efforts to tap the mechanical energy of high-pressure gas reservoirs, or geopressured fluids. The Department of Energy has recognized this potential and provided partial funding for several of these projects under its stimulus programs. GEA also cited an estimate from Southern Methodist University's Geothermal Energy Program that GHCP from the onshore Gulf Coast region alone could provide up to 5,000 MW of reliable power. That doesn't include the potential for using the large volumes of produced water in new or abandoned wells to tap the energy of higher-temperature rock formations underlying the hydrocarbon reservoirs using engineered geothermal systems (EGS).

The benefits of these approaches for low-emission power generation seem obvious, but it's worth considering why they might be attractive for oil and gas companies that are mainly focused on producing hydrocarbons for processing and sale, not electricity. GHCP addresses two key, related problems of many mature US oil fields. The first is water, which in many cases is injected underground as part of "secondary recovery", in order to increase the total fraction of hydrocarbons recovered from an oil field during its life. Together with water already present in these reservoirs (as distinct from the shallower aquifers used for drinking water and irrigation) this contributes to high "water cuts"--large volumes of water produced with the oil and gas that sometimes exceed oil volumes by a factor of 20:1. If this water is in contact with hot rock, it will bring some of that heat to the surface, where it can be recovered using binary geothermal technology. SMU estimated total produced water from US oil production at 50 billion barrels per year.

That's an enormous volume of water for the industry to handle and dispose of in an appropriate manner, and it gives rise to another problem that GHCP can help tackle. It takes a lot of electricity to pump all that water out of the ground, process it, and pump it back down. That power must either be purchased or generated onsite. If GHCP can just provide enough power to cover an oil field's operating power requirements, it represents a significant savings in the cost per barrel of oil produced. The SMU study suggests that there is also an opportunity for net electricity production, representing another potential revenue source for an oil project. Depending on the investment required, that could improve overall project economics.

I see another, less obvious benefit for geothermal hydrocarbon co-production. The US geothermal industry hasn't attracted anything like the investment that's gone into wind and solar power; it is starved for capital. As a result, it can only tap a small fraction of the potential power from US hydrothermal reservoirs, let alone the orders-of-magnitude larger potential of EGS. If these projects don't offer quite the economic payoff of oil and gas production, they at least closely resemble what the oil industry does day in and day out, while being almost completely unlike what firms involved in wind, solar or even biomass power do. GHCP could be a natural bridge for more of the oil and gas industry, which its much larger capital, skills and technology base, to expand into geothermal energy that doesn't involve any hydrocarbons.