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.

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A Wind Bubble?

New US wind turbine installations have slowed significantly this year, compared to 2009, and the decline is having consequences. Among other fallout, Suzlon is mothballing a four-year-old wind turbine factory in Minnesota and laying off the remaining 110 workers, due to a lack of new orders. While the industry pins most of the blame for the slowdown on insufficiently aggressive federal energy policies, it suddenly occurred to me to wonder whether wind power, like housing, might have been caught up in an investment bubble that has finally popped, somewhat belatedly.

The idea of a wind bubble goes against all conventional wisdom, including the importance of expanding electricity generation from low-emission sources in order to mitigate climate change; the desire to build a vibrant "new energy" economy in the US for energy security and competitive reasons; and the persistent mantra of the green jobs that are supposed to turn the economy around. Yet every bubble must have a compelling, plausible narrative, or it would never take off.

When you examine the charts of annual and quarterly US wind turbine installations on pages 2 and 3 of the "Third Quarter 2010 Market Report" from the American Wind Energy Association, there are at least two ways to look at them. The customary perspective would attribute the dramatic increase in wind installations beginning in 2006, which set records in each of the next three years, to the rapid scaling up of an industry that many envision supplying 20% of US electricity generation within two decades, up from its current level of around 2%. This growth has been supported by a variety of incentives and mandates, including the federal renewable production tax credit (PTC), the stimulus grants, and state renewable portfolio standards. But in this scenario it's hard to explain why installations would have fallen off so much this year, when all of these benefits are still in place, other than the imminent expiration of eligibility for the stimulus grants--which in another year might have been expected to trigger a mad rush for projects to get in under the wire, as we saw in 2008 when the PTC was due to expire at year end. How can we attribute this year's drop in installations to the absence of a policy--either a national renewable electricity standard or a comprehensive climate bill--that we've never had?

So turn this picture around and ask why wind might have been in a bubble, and why that bubble might have only popped now, roughly two years after the other bubbles for stocks, housing and possibly oil prices. Aside from the policies promoting wind and other renewables, which have not changed, wind power developers would have looked at two other indicators: credit and demand. Wind projects are capital intensive, and in the run-up to the financial crisis they benefited from the same kind of cheap and readily available credit as other businesses and homeowners did. At the same time, between 2000 and 2007 US demand for electricity was growing at about 1.3% per year. That might not seem like much, but at the scale of the US power sector, that translated into the need to add around 7,000 MW of new generating capacity each year. If all of that was from wind turbines, the required nameplate capacity would approach 20,000 MW, because of wind's lower average output per MW. Wind was also becoming a preferred technology, despite its intermittency, because coal was falling out of favor for environmental reasons and the price of natural gas, the fuel for the dominant incremental generation technology for the last 20 years, had spiked and become very volatile.

If wind was indeed being carried along either by its own bubble or by the froth from the other bubbles fueling the economy in the middle of the decade, why has it only now run out of steam, rather than popping in 2008 or 2009? After all, electricity demand growth evaporated when the financial crisis and recession hit, and demand has not yet recovered to its 2007 peak. For 2008, perhaps the dash to complete projects before the expected expiration of the PTC--it wasn't extended until October of that year--provides sufficient explanation. As for 2009, the charts show that installations did fall dramatically until the implementation of the Treasury stimulus grant program, which injected $1.7 B into wind projects last year and another $2.9 B this year. Moreover, the stimulus grants were more valuable to wind developers than the PTC they formerly received. That isn't just because developers got the money up front, rather than having to wait until a project started up and produced electricity, but also because the grants were based on the 30% investment tax credit (ITC). Using NREL's simplified calculator for the levelized cost of electricity, at a typical cost of around $2,200/kW of capacity the ITC could be worth at least 20% more than the 2.2¢/kWh PTC. In other words, just as the wind market was collapsing last year, the government increased its incentives and accelerated them into up-front cash. That might have been enough to keep a bubble going for a while longer.

Of course there's no way to know whether this scenario is more accurate than the standard explanation for what has happened to the US wind market this year. Nor does it doom wind power to the doldrums even after the economy resumes growing and creating jobs at a healthier rate, and electricity demand picks up. However, if there is a grain of truth in this view, then it might alter our perspective on providing more aggressive support for the wind industry based on the notion that installations should still be running at 10,000 MW per year or more, as they were in 2009, rather than at the lower rate of around 5,000 MW we see today.

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Interpreting the Election Results

The results of yesterday's election will be interpreted and spun in many ways in the days and weeks ahead. Republicans gained control of the House of Representatives and several key governorships but fell short of capturing control of the Senate. In the process they picked up enough seats--along with at least one like-minded Democratic Senator-elect--to put cap & trade or a national carbon tax out of reach for at least the next two years. Meanwhile, voters resoundingly defeated a ballot initiative in California that would have forestalled implementation of the state's tough greenhouse gas policies. But even if comprehensive federal energy legislation is off the table, divided government doesn't rule out the possibility of a national renewable energy standard or other energy measures, provided they don't involve significant additional expenditures.

On the surface, the election outcome appears to set up a return to the pre-2009 situation, when California and other states were pushing aggressively for action on climate change while the federal government remained deadlocked on the issue. Too much has changed since then for that picture to be accurate. In the absence of Congressional action on greenhouse gas emissions the EPA is forging ahead with its own regulations under the Clean Air Act, and that could provide an early test of the willingness of the new Congress to try to modify the administration's regulatory approach. Meanwhile, although the proposition that would have suspended California's A.B. 32 climate rules was swamped after being portrayed--unfairly, in my view--as mainly benefiting out-of-state oil companies at the expense of the state's new Cleantech industry, California voters passed another initiative, Proposition 26, that will make it harder to impose a variety of new fees on businesses and consumers, including fees related to the environment. Further complicating the outlook, the results of several key governor's races, including in New Mexico and possibly Oregon, could limit the number of other states that might "opt in" to A.B. 32, as well as raising the possibility of more defections from the Western Climate Initiative.

Although as I noted on Monday our fundamental energy situation is largely pre-determined for at least the next few years, last night's results could affect energy policy in a number of other ways, aside from climate change. One example is the President's desire to eliminate subsidies for conventional energy, as part of an initiative of the G-20 group of nations. The main subsidies targeted by this international effort are those that increase demand by limiting the price of fossil fuels for consumers, particularly in developing countries, yet President Obama has linked this to his goal of eliminating a variety of tax breaks benefiting domestic energy production, including the Section 199 tax deduction that all US manufacturers enjoy. Unless this measure is somehow passed in the lame duck session when Congress returns from its election break, it looks dead on arrival come January. From an energy security perspective we should be glad of that.

The change in control of the House also puts the extension of the expiring ethanol blending credit in doubt, along with the prospect of extending eligibility for Treasury renewable energy stimulus grants beyond the end of this year. Even though the latter appears deficit-neutral, and might thus attract bi-partisan support, it accelerates benefits that project developers would otherwise have to wait until their next tax filing to receive, and it probably lets some marginal projects that might not otherwise find private funding escape winnowing. If the lame duck doesn't pass this, the odds of the 112th Congress extending it or anything else connected to the stimulus look poor.

Ultimately the likelihood of meaningful energy legislation of any kind will hinge on the willingness of the President and the new Congress to meet somewhere in the middle to get things done. Otherwise, the scope is limited to a few lowest-common-denominator efforts, which might include a modest national renewable electricity standard, with everything else effectively blocked by the other chamber of Congress or the President's veto pen. I don't expect to lack for topics on which to blog in the next two years.

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What Won't Change After the Election?

Tomorrow's US mid-term election dominates today's headlines, with most analysts expecting a dramatic shift in control, at least in the House of Representatives. However, from an energy perspective, many aspects of the situation in which we will find ourselves after the ballots are counted will remain largely predetermined for the next two years, going into the 2012 election. As candidates debate differing perspectives on energy it's worth recalling the tremendous inertia of our energy systems. The seeds of significant change have already been planted and are promoting a gradual transformation, but the results will be more evident when we look back at the end of the decade than while it is underway.

One given is that for at least the next two years, fossil fuels will continue to supply well over 90% of US transportation energy and more than 2/3rds of US electricity generation, with nuclear and conventional hydropower accounting for more than 80% of the low-emitting remainder. Even though wind and solar power are still growing rapidly, though the former has slowed down appreciably compared to last year, they are still too small to make a significant difference in our consumption or emissions, and that will remain the case in 2012. Advocates of wind power and other renewables lament the lack of comprehensive energy legislation or a more focused national renewable electricity standard, but weak fundamentals have at least as much to do with the slowing rate of wind installations. US electricity demand has recovered somewhat from its low point last year, but it remains around 2% below its high of 2007. That has made utilities more reluctant to add generation of any kind, particularly in light of the strong emphasis on efficiency measures in the policies enacted in the last several years, starting with the Energy Independence and Security Act of 2007 and reinforced by last year's stimulus.

Another given is that oil will continue to dominate our concerns about energy security. The economic slowdown reduced net US imports of crude oil and petroleum products by 20%, compared to 2007, but even at this level imports are still a third larger than domestic production of crude oil and natural gas liquids--a disparity that is set to grow for two reasons. First, the greatly reduced rate of drilling in the Gulf of Mexico following the Deepwater Horizon disaster and the moratorium that was imposed in response is already starting to reverse the gains in US oil output that we saw in the last several years. Mature offshore fields are declining, while new projects will be slower to come online. Not even the remarkable success of onshore drilling in the Bakken formation of the Dakotas and Montana, which has moved North Dakota up to number four among oil producing states--past perennial heavyweights like Louisiana and Oklahoma--is likely to compensate for slower growth from the Gulf.

Nor are biofuels likely to add enough production in the next two years to avoid an increase in our oil imports, as ethanol approaches the limits of corn ethanol output and faces the expiration of the tax credit it has enjoyed since 1978. And while the proliferation of hybrids, electric vehicles and other efficient car models is a step in the right direction, their numbers are too small for now to counteract any increase in miles traveled. Even a modest amount of demand growth from a recovering economy will set US oil and refined product imports climbing again, with a corresponding impact on world oil prices and our trade deficit.

There's little doubt that the incoming 112th Congress will have a different approach to energy and its related environmental issues than the outgoing 111th has had. That could prove significant for many aspects of US energy policy, including climate policy. At the same time, the new members of the House and Senate are likely to find, as past Congresses have, that our energy challenges are less responsive to intervention than they assumed. I wouldn't be surprised if the biggest impact on energy in the next two years comes not from energy legislation, but from the indirect effect of whatever steps are taken to address our larger economic problems.

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Ammonia As An Alternative Fuel?

In the last seven years I've written extensively about a wide variety of alternative fuels, including ethanol, methanol, and higher alcohols like butanol, along with compressed and liquefied natural gas (CNG and LNG), hydrogen, and electricity, but I find I haven't said anything about anhydrous ammonia. It turns out that there is a small but enthusiastic group of people promoting its use as an alternative fuel, going back to at least the 1940s. Much of the recent interest in this stems from the fact that ammonia releases little or no greenhouse gas when burned, and that it's possible to produce it by means that involve minimal GHG emissions throughout its lifecycle. However, when you dig into this a little deeper, you discover that almost all ammonia today is produced by the Haber process, using hydrogen sourced from natural gas. And if that weren't enough of a deterrent, the physical properties of ammonia render it an unattractive candidate for a mass-market fuel.

So-called "green ammonia" would avoid natural gas by substituting hydrogen from electrolysis using wind, solar or other renewable electricity. As long as natural gas remains abundant, it's hard to envision this growing beyond a small niche, because the price of ammonia will ultimately be set by the price of natural gas, which remains a cheaper source of hydrogen than electricity from any source, let alone from expensive renewable power sources. Moreover, electricity is fungible, and the best use of renewable or other low-emission power (e.g., nuclear) is probably in backing out power from higher-emitting sources, rather than diverting it into inefficient production of chemicals. As a result green ammonia, like green power, would require subsidies for at least the near-to-medium term if it is to compete with conventional ammonia, which seems like a crucial prerequisite for competing with conventional fuels. And without green ammonia, the whole rationale for an ammonia fuel-and-vehicle network looks questionable--why not just use the gas as CNG or LNG instead, with a fraction of the headaches?

Even if that weren't the case, ammonia faces serious obstacles as a consumer fuel, compared to either conventional fuels or to many other alternatives. Start with energy density, which is less than half that of gasoline by weight, and about 40% by volume. So a gallon of ammonia would only take you about 40% as far as a gallon of gas, even if you could burn pure ammonia in your engine--and from what I've read it still requires help from another fuel to sustain combustion. (That means two fuel tanks, which constitutes another major hurdle with consumers.)

Then there are the economics. Ammonia itself isn't exactly cheap, if you adjust for its energy content. The price of bulk ammonia for agricultural use appears to be around $550-$600/ton, which equates to $1.55-1.70/gal. But when you factor in its lower energy density, that raises it to at least $3.85/gal. of gasoline equivalent, without any fuel taxes. And while a distribution system exists to supply farms with ammonia, this is a long way from what would be required to fuel anything beyond farm vehicles. Because ammonia boils well below ambient temperature, it must either be refrigerated or stored under pressure, and dispensed through special equipment. And if all that weren't daunting enough for any service station owner considering adding an ammonia pump on the forecourt, the safety aspects of ammonia handling look even worse.

A glance at a typical material safety data sheet (MSDS) for anhydrous ammonia reveals that the recommended exposure limits are very low, under 50 parts per million in air, and the consequences of exposure include caustic burns and much more serious outcomes. Gasoline has its own issues, but spilling some on your hand won't send you to the hospital, and a larger spill or leak doesn't require first responders in hazmat suits. I simply can't imagine any fuel retailer wanting to take on the liabilities that would go along with this, even if there were an attractive margin in it, which there doesn't appear to be.

I concluded long ago that we're heading into a period of much greater fuel diversity, and that certainly seems to be true, with LNG catching on for big-rig trucks and CNG for a few cars but more fleet vehicles and buses, and even hydrogen appearing in a few places for fuel cell vehicles. However, it's very hard to imagine a substance with as many drawbacks as ammonia coming into wide use for consumers or even fleets. Our range of alternative fuel options seems sufficiently broad already, without having to consider a fuel that turns into a poison gas at atmospheric pressure and temperature.

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Green Jobs Aren't Renewable Energy's Value Proposition

The recession and its aftermath have been simply awful for the emerging renewable energy industry, even though governments have tried hard to insulate the industry from the worst effects of the slowdown. Not only did the recession make it much harder for renewable energy projects and technologies to secure financing, due to weak demand and the hangover from the financial crisis, but it has focused the industry's management on a counterproductive metric: green jobs. Factories and projects are pitched on the basis, not of their efficiency and profitability, but of adding jobs that "can never be outsourced." Tell that to the 3,000 Danes who are being laid off by wind turbine maker Vestas, or the Scots whose jobs are in jeopardy due to the financial problems of a smaller wind supplier, Skykon. This problem isn't unique to renewables, but the misplaced emphasis on green jobs makes them particularly vulnerable to the collision of this aspiration with the realities of global energy markets.

I don't blame the industry for picking up on this theme. Politicians hit on it first as a way to justify continuing to invest taxpayer money in the subsidies required to keep renewables growing. That included the large infusions that became necessary when the "tax equity" market upon which project developers had depended to convert future tax credits into current cash became frozen after the bankruptcy of Lehman Brothers. As of this month, the US government has spent $5.4 billion on these renewable energy grants to fill this gap, with nearly half of that awarded in the second, third and fourth quarters (to date) of this year, even though tax equity transactions are showing signs of life again. Without a compelling story linking this money to employment, which understandably remains one of the primary economic concerns of voters, this would have been an even harder sell than it was.

One problem with this rationale is that the world has changed a lot since most of the current members of Congress came to Washington. Supply chains for practically every industry have become globalized, and renewables are no exception. If anything, as renewables increasingly become a global industry--growing out of their localized roots in places like Denmark and Silicon Valley--that trend will accelerate. The lion's share of future demand will likely be focused on Asia and Latin America, because of their higher economic growth rates and the related need to add enormous amounts of new energy infrastructure. That's a very different proposition than replacing existing energy infrastructure in the mature, developed economies because we don't like its emissions or its dependence on unsustainable fuels. Vestas understands that to serve the market in China, it needs more factories in China, and fewer in Denmark.

An even bigger problem is that making renewable energy more, rather than less labor-intensive works against it in the long run, by increasing its costs relative to conventional energy. In a recent analysis on green jobs the Geothermal Energy Association (GEA) touted its finding that geothermal power plants create more than 10 times as many person-years of employment per megawatt of capacity as equivalent natural gas-fired power plants. Unfortunately for the GEA, outside the Washington beltway and the state capitals where this message might play well that counts as a disadvantage, not an edge, because it translates into higher construction and operating & maintenance expenses. In order to arrive at the point at which they can compete without subsidies that look increasingly unsustainable in light of the large fiscal deficits in the developed economies, renewables must focus on driving down these costs and improving their productivity.

I am sympathetic to the plight of the millions of unemployed workers in this country and elsewhere in the developed world, and cognizant of their effect on the overall economy. However, energy is by its nature a capital-intensive business, and not a particularly labor-intensive one. To the extent its capacity to provide low-cost energy to the rest of the economy is influenced by the number of workers it takes to produce a megawatt-hour of electricity or a barrel of oil, fewer are generally better. Without diminishing the value of the jobs involved, I can only hope that once the economy resumes creating many kinds of jobs at a decent rate the renewable energy industry will return its focus to its primary value proposition for consumers and investors: providing low-emission, diverse and secure--and hopefully someday cost-effective--sources of energy for the economy, rather than putting more people to work.

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German Solar: Too Much of a Good Thing?

Until the recent reduction of its feed-in tariff, Germany provided some of the most generous solar incentives in the world. However, based on a statement last week by the head of the German energy agency, DENA, the rapid solar buildup threatens to overwhelm the country's power grid. Stephan Kohler proposed capping the amount of new solar that could be added each year at 1,000 MW, or around 10% of the capacity in place as of the end of 2009, in contrast to the 3,800 MW added last year, and as much as 6,000 MW expected to be added this year. Germany's solar incentives are often held up as a model for others to follow, but that rarely takes into account a growing list of unintended consequences that now appears to include grid congestion at high solar penetration.

The problem that Herr Kohler identified is rooted in the large disparity between the average and peak output of solar panels installed in high latitudes and under Germany's notoriously cloudy skies. The principal consequence of this disparity has been economic: it takes a lot more megawatts (MW) of solar capacity to produce the same output in Germany as in a sunnier location such as Spain, North Africa, or the US Southwest. The German government has overcome this impediment by throwing money at the problem. Until recently Germany had some of the most generous solar incentives in the world--generous enough that Germany accounted for more than half of all new solar installations last year. Even after several rounds of cuts this year, the owner of a new building-mounted solar array can still collect up to €0.33/kWh, equating to $0.46/kWh at the current exchange rate. Under the feed-in tariff system, utilities pass on the extra cost of buying renewable power to ratepayers, and as reported by the German Energy Blog recently, that will add €0.035/kWh ($0.049/kWh) to the average consumer's bill next year. Nearly half of that premium is attributable to solar power, even though it apparently accounted for only about 7% of all renewable power generated in Germany in 2009, because the country is such a poor location for solar power.

On average, every MW of solar capacity installed in Germany generates only about 100 kW over the course of the year. If that were a constant, it would be a lot easier for grid managers to accommodate. But of course that capacity generates nothing at night, while still putting 1 MW into the grid at noon on a bright summer day. That's more than twice the peak-to-average output ratio for solar in a good location in Southern California, Arizona or Nevada. The difference affects how much backup capacity must be available to the grid and likewise how much other capacity must be taken offline as solar output ramps up daily and seasonally. It also determines the nature of that swing capacity. While in a sunny location it might suffice to keep a few "peaking" gas turbines on standby--a role that might even be filled by electricity storage in the future--in a place as un-sunny as Germany it requires substantial capacity capable of running economically for many hours a day, week after week. That doesn't sound like a recipe for replacing German coal-fired power plants (or nukes) with photovoltaics.

Everyone knows solar power is cyclical. However, while I've tended in the past to ignore peak output and focus on the average output of solar in a given location, because that's what determines how much energy is actually delivered over time, the implication of Herr Kohler's comments is that the low capacity utilization inherent in solar installations in northern, cloudy regions amplifies the impact of solar's cyclicality. It's starting to look like the German feed-in tariffs, which were certainly effective as a solar policy in maximizing installations, despite Germany's disadvantages of climate and geography, weren't a very smart energy policy. They've placed too much emphasis on a technology that under German conditions only yields a third as much energy, on average, as the same amount of wind capacity, while still being capable of swamping the grid when the sun does shine. I hope that policy makers and grid planners in such similarly sub-optimal locations for solar as New Jersey and Ontario, Canada are paying very close attention.

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