Friday, October 29, 2010

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.

Wednesday, October 27, 2010

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.

Monday, October 25, 2010

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.

Thursday, October 21, 2010

Are EV Incentives Justified?

The Wall St. Journal has been running an interesting series of articles on electric vehicles this week, coinciding with the mounting excitement surrounding the arrival of the first truly mass-market EVs in the US within a month or two. The articles cover a wide range of issues, including the cost of the batteries, efforts to overcome the lack of recharging infrastructure, the lifecycle environmental benefits of EVs, and the real-world experience of a participant in one of several EV consumer tests now underway. Although I've blogged about most of these topics in the past, I also found some insights in the articles that deserve to be highlighted, along with serious questions regarding the assumptions behind federal and state EV policies and incentives and the benefits of these vehicles for the country.

The US government is investing large sums to create a domestic EV industry and ensure there's a market for its output. Between the stimulus grants for battery and component factories and recharging infrastructure, and the ultra-generous tax credits for the first million or so vehicles, it adds up to around $10 B, and that's not counting the federal loans and loan guarantees to unproven EV manufacturers, at least a few of whom might not survive long enough to repay them. It also doesn't include more than $1 B in foregone federal and state motor fuel taxes over the lives of these cars. This is all justified on the grounds of energy security and emissions reductions and predicated on the idea that by making early sales more affordable for customers, the government can help the industry expand its volume to the point at which costs would come down dramatically. That would ultimately make EVs competitive with conventional cars on their own merits, without perennial subsidies. The Journal articles identify at least two major factors calling this model into question.

The first and most important of these relates to the high initial cost of the batteries that contribute a major portion of the total cost of an EV, and essentially all of its cost premium over a conventional car. Citing several battery experts, the Journal raised doubts about how quickly battery costs are likely to fall, based on an assessment of the components of these batteries. Although the Lithium-ion batteries that go into EVs are new products, many of the things that go into them are not new at all, and are thus unlikely to become dramatically cheaper. Should we really expect that EV batteries would follow an entirely new "experience curve" of their own, yielding sharp cost declines over the first few years as output grows, or do they really fall within the larger category of all Lithium-ion batteries, for which the cost curve has flattened significantly in recent years, in applications such as laptop computers and cellphones? This is a crucial point, because if volume/experience effects do not quickly drive down the cost of EV batteries, then when the current subsidies expire EVs would become prohibitively expensive relative to their non-EV competition, and sales could collapse. That would force the government to choose between extending generous EV subsidies for a much longer period or standing by as US factories producing EVs and their components shut down.

The other assumption that looks questionable is the basis of competition between EVs and non-EVs. The Journal makes a good case that most of the developments that could make EVs cheaper and more effective would also benefit hybrid cars. Cheaper batteries for fully-electric cars mean much cheaper battery capacity for hybrids, even those providing a few miles of all-electric driving. That strengthens the argument that consumers won't be choosing between EVs and big, gas-guzzling cars, but between EVs and hybrids that already capture the most valuable portion of the available fuel--and fuel cost--savings. That shrinks the consumer benefits that would offset the inconvenience purchasers will take on when they buy plug-in cars without onboard generators. When you aggregate the annual fuel savings of the first million EVs on the basis of their displacing 50 mpg hybrids rather than 25 mpg average cars, they shrink from 480 million gallons per year to 240 million gpy, or just 16,000 barrels of oil per day. At that rate, it would take 22 years to repay the government's $10 B investment in them, even ignoring the cost of the energy from other sources--mostly domestic natural gas and coal--that these cars will consume.

So while I still regard the electrification of transportation as an inevitable trend, as I have for more than a decade, and am tremendously impressed by the engineering that went into the Chevrolet Volt and the other new models on their way--20 in all, by the Journal's count--I'm left with some serious doubts about their viability as a sustainable national energy strategy. It seems pretty clear that we wouldn't be seeing nearly this level of activity without the huge commitment to EVs by this administration and, to a lesser extent, the previous one. Although these decisions have largely already been made, the EV tax credit would still have to be renewed next year, as I understand it.

$10 billion is a lot of taxpayer money to invest in making these cars more attractive to a group of relatively well-off early adopters. Consumers in states like California will receive as much as $12,500 for buying a Nissan Leaf or other qualifying EV. Nor do I buy the argument that if we don't invest in this industry now, China will own it within a few years--not because I don't think they would, but because it's not clear to me that we have any particular competitive advantage for building millions of Lithium-ion car batteries cheaply enough to hold our own, particularly when we'll be importing many of their components and could come up short on access to any rare earth metals required. Spend a few minutes gazing at the accumulating federal and state debts and even larger unfunded liabilities displayed at and you might join me in wondering whether, as cool as these cars promise to be, the generous incentives associated with them are a luxury we can't afford just now. While it wouldn't be fair to the companies that have invested in factories and hired workers on the basis of these incentives to cut them off suddenly, it might make sense to slim them down and phase them out faster than currently planned.

Tuesday, October 19, 2010

French Strikes and US Gas Prices

My reaction to the ongoing refinery strikes and fuel depot blockades in France was probably best described as bewilderment, until it occurred to me that they could have a significant effect on what consumers elsewhere pay for gasoline and diesel, including here in the US. That's clearly a much smaller inconvenience than French consumers are having to endure, but it at least provides a good reason for Americans to pay closer attention than we usually do to what happens on the other side of the Atlantic. You can't shut down a dozen refineries anywhere in the world without affecting global fuel markets, let alone in one of the main regions on which the US relies for its considerable gasoline imports.

I don't pretend to understand the intricacies of the pension reforms apparently motivating the strikes by French refinery, transport and other workers' unions. Like many European countries, France faces serious demographic and fiscal challenges, and an editorial in today's New York Times suggests that raising the retirement age is a necessity, whatever the politics involved. Either way, that is something for the French to work out. However, by selecting the nation's fuel infrastructure as the focus of their "industrial action" French unions have chosen a strategy with both regional and trans-Atlantic implications. That's because European and US fuel markets are connected by significant trade flows in both directions. The ripples caused by these strikes are likely to affect the economics of petroleum products on both sides of the pond in the weeks ahead.

Much of this connection is due to the complementary overlap between the US appetite for gasoline and our long-term shortage of refinery capacity, and Europe's strong preference for diesel-powered cars, despite a refining system that was built to accommodate much higher gasoline demand. Last year the US imported an average of 940,000 barrels per day of finished and unfinished gasoline, and about 40% of that came from Northwest Europe and Spain--though little of it directly from France. In return, a similar fraction of the 587,000 bbl/day of diesel the US exported last year went to these same countries, about half of it in the form of ultra-low-sulfur road diesel. But while some of this product flows day in and day out on long-term contracts, a significant portion is in the form of "spot" cargoes, which depend on transitory price differentials between markets opening wide enough to cover freight costs plus a bit of profit. I haven't looked at freight rates recently, but I doubt these costs are much less than the $0.06-0.08/gal. that was typical when I executed transactions like this from Texaco's London trading room twenty years ago.

According to the International Energy Agency's statistics, France consumes about 1.5 million bbl/day of petroleum products, mainly supplied by the country's dozen refineries, with some help from imports. It's not clear from the news stories I've read whether all of these refineries are now shut down or operating at reduced rates, but it seems clear that even with many of its service stations running out of product, France is consuming much more petroleum product than it is now producing or importing, with the shortfall being made up from "compulsory stocks"--their equivalent of our Strategic Petroleum Reserve, with the key difference that it's mostly held in the form of refined products in the storage tanks of companies that are required to maintain a 90-day inventory cushion for eventualities such as the current one. After the strikes end and the refineries are back to normal operations--and assuming no accidents occur during all these start-ups--these stocks will have to be replenished. That seems likely to affect the US market in two ways.

The most obvious one is that if re-stocking French fuel inventories causes prices there to spike, as you'd expect, then France will absorb many of the cargoes that would otherwise have made their way across the Atlantic, particularly from the UK and the enormous refinery hub at ARA (Amsterdam/Rotterdam/Antwerp). And if the differential gets wide enough, we could see gasoline cargoes and additional diesel cargoes leaving the US for France, motivated by the arbitrage opportunity, or "arb." The combination of these mechanisms would feed into fuel prices on the US east coast and Gulf Coast, supporting the recent upward trend. And because French consumption is skewed so heavily towards "gasoil" (diesel), that's where we should see the biggest impact.

Although some reports suggest it has helped to prop up crude oil above $80/bbl, this effect isn't yet apparent in the futures prices of refined products. This morning November diesel was trading on the NYMEX at $2.23/gal, while November gasoil on London's ICE was at $703.50/ton, equating to about $2.26/gal. That's not wide enough to constitute an arb, but then this shift probably won't kick into gear until traders at least know that French ports will be open to receive and unload their cargoes. The bottom line is that if you were hoping for some relief at the gas or diesel pump in the next few weeks, you shouldn't be surprised to see prices going even higher for a while, instead, thanks to the current mess in France.

Thursday, October 14, 2010

Splitting the Baby on E15

I've been going over the EPA's ruling yesterday partially granting the waiver request from Growth Energy, an ethanol trade association, to allow gasoline with up to 15% ethanol to be used in cars not specifically designed as flexible fuel vehicles. The request had created a serious dilemma for the EPA, because granting it could jeopardize the integrity of millions of consumers' car engines and fuel systems, but turning it down would call the entire national renewable fuels strategy into question. What looks like the agency's attempt to find a middle ground that could satisfy all parties might turn out to have little practical impact on the ethanol market for some time, while still unleashing a potentially very disruptive shock wave on the entire motor fuels industry in this country.

If that sounds contradictory, you have to look at the specifics of what the EPA has agreed to here, and overlay them on the highly-competitive, relatively low-return network of gasoline blending, distribution and sales infrastructure through which it must eventually feed. Instead of approving E15, a blend of 15% ethanol and 85% gasoline for all vehicles, or even just for vehicles produced since 2001--as many had speculated they would--the agency has only given the green light for putting this fuel into cars made in the last four years. I might note that this interval includes some of the lowest US car sales rates in recent memory, so yesterday's ruling affects just a fifth or so of the total US light-duty vehicle fleet. The decision for another tranche of cars built between 2001-2006 is to be made after further study, perhaps by the end of the year.

In essence this means that no fuel producer can afford to stop supplying the E10 (or less) fuel that is compatible with all those pre-2007 cars, and precious few retailers are likely to take a bet on switching one of their tanks to a new fuel that only a fraction of their customers can take advantage of, once all the other legalities of introducing E15 into the market have been satisfied. So while this decision might seem to be about promoting the use of more home-grown, renewable fuel in preference to petroleum products that depend on deepwater wells and foreign suppliers, its implementation hinges on a very lopsided business decision for a group of mainly independent fuel retailers and distributors, rather than the major oil companies whose brands we see on filling station polesigns.

A retail gas station has a finite number of product dispensers drawing on an even smaller number of underground storage tanks. In order for a retailer to introduce a new fuel without ripping up the forecourt (which entails being out of business for several months and possibly longer, should he have the misfortune to discover a leak in the process) then he must do the math on how many gallons per month of the new product he might sell, and at what margin, against how many gallons and how much margin he'd lose from the discontinued product. This is the dynamic that has contributed to the excruciatingly slow lift-off of E85, which is at the heart of why E15 even became an issue. It was never supposed to be necessary, because the extra ethanol mandated under the federal Renewable Fuel Standard (RFS) was intended to be sold in big, 85% at-a-time chunks, not little 10-15% slices, and into a gasoline market that was still growing at its historical 1-2% per year clip.

So as a retailer--a small and not very lucrative business--do you give up premium unleaded? Seems an obvious choice, since it's probably your lowest-volume offering. But unless you have a dedicated mid-grade tank, you need premium to blend in the pump to make mid-grade, which accounts for more of your sales. Worse yet, your margin per gallon on premium is your best, followed by your margin on mid-grade. Or you could give up diesel, though if you do, you'll never see those customers again: not on the forecourt, and not in your store, where you make much of your monthly profit. The alternative is an expensive investment in a new tank and dispenser, against a highly questionable return. By now it should be obvious this is a losing game for retailers, who as far as I can see would choose to continue to sell E10 to everyone, including post-2006 cars affected by the E15 ruling, and just ignore the EPA.

The folks who won't be able to ignore the EPA will be the refiners and major fuel blenders. That's because they continue to fall under the authority of the steadily increasing RFS mandates, requiring them to sell a higher percentage of biofuel every year until 2022, or pay large penalties. And while the EPA was kind enough to reduce the mandate for cellulosic ethanol last year and this year--for the very good reason that it isn't yet available in the expected quantities--the chances of getting a waiver in the future because a company has run out of room to blend ethanol into E10 look pretty low, when the EPA can just insist that you make E15 or E85, both now legal. This sets up a situation in which suppliers will shortly need to induce their retailers to take on one or both of these products and make it worth their while, further depressing the margins in this part of the business and making an exit strategy even more attractive.

It's hard to gauge exactly what this could mean for consumers. At a minimum, it might lead to drivers of older cars pulling into some gas stations only to find that the unleaded fuel advertised on the sign is actually not compatible with their particular car. (The EPA as part of yesterday's ruling has promised pump labeling sufficiently clear that no one will fill up with E15 by mistake.) Or in a bigger station, all the E10 pumps might be over on one side of the convenience store, and all the E15 pumps on the other. And of course this raises the awkward question of why consumers would ever consciously choose to fill up with a fuel containing at least 2% fewer BTUs and thus offering 2% lower mpg and range, unless it's going to be cheaper for them--which is inconsistent with E15 carrying sufficiently higher margins to make it worth the retailer's effort to sell.

The result looks like a dog's breakfast, although I can't honestly say I'd have ruled much differently if I were running the EPA and only charged with upholding the RFS and making this ruling on the basis of whether it would increase the overall pollution from the affected vehicles, rather than on whether its policy and ostensible environmental benefits outweigh its costs and risks for vehicle longevity and consumer value. The EPA's supporting documents included evidence that a significant proportion of E10 already approaches 11% ethanol, so E15 means routinely exposing engines and fuel systems to a mix of 16% or more ethanol, even if they were only designed with 10% in mind. Who will bear the liability for the expensive repairs that some cars will require? There are few aspects of this situation that offer consumers any upside, but I see ample downside, if only from having to bear the additional costs that will be passed on by retailers who are in no position to absorb them.

Wednesday, October 13, 2010

Solar Warming and Our Sulfur Sunshield

Two unrelated stories concerning the science of climate change caught my attention yesterday. The first was the announcement of a new report on solar variability, published in Nature, which appeared to upend established thinking about the impact of solar cycles on the earth's climate. The other was a discussion on Shell's climate blog of the potential impact of regulations affecting the sulfur content of marine fuel oil on an effect that has been partly mitigating climate change for decades. Both are interesting in their own right, while together providing a useful reminder that climate change is much more complex than the soundbites we typically hear from the media and advocacy groups, especially after we've had a run of unusually hot or cold weather.

As a less-than-fully reformed science nerd, I loved the simple elegance of the first sentence of the abstract of the Haigh, et al paper in Nature: "The thermal structure and composition of the atmosphere is determined fundamentally by the incoming solar irradiance." Paragraphs of exposition boiled down to 16 words that neatly frame the importance of the researchers' finding that for the last several years, and contrary to what we'd have expected from being in the low part of the solar cycle, featuring few or no sunspots for several years, the earth has been receiving more energy from the sun where it really counts--in the lower part of the atmosphere, or troposphere. If their interpretation of the satellite data is correct, then it pretty well torpedoes the notion from two years ago that a weak sun was about to flip global warming into global cooling. Of course it would also defuse some of the determined attempts to attribute this year's record temperatures entirely to humanity's greenhouse gas emissions.

While this finding isn't expected to alter the decade-to-decade view of climate change, it certainly suggests that we should be paying attention to a lot more than just CO2 and its sibling GHGs over shorter intervals, and in that respect it's a nice lead-in to the discussion of atmospheric cooling due to sulfur emissions from ships. That also applies to its implication that we still have a lot more to learn about the earth's atmosphere--where climate lives--and its dynamic interaction with the solar system.

In his blog on Shell's corporate website, Shell climate advisor David Hone shared his observations from a recent meeting exploring the impact of sulfur emissions on climate change. This apparently led to discussions of sulfur-based strategies for geoengineering the climate, but even without going that far it seems clear that this issue deserves a lot more attention that it has received. I was aware that such emissions tend to offset at least part of our greenhouse gas emissions, and that previous reductions in sulfur for onshore fuels--necessary for local air quality and modern vehicle anti-pollution equipment--might have given an unintended boost to warming. However, I think this is the first time I've seen the estimated climate forcing associated with marine fuels of -0.6 W/m2, which as Mr. Hone notes is not small relative to the total greenhouse gas forcing of around 2 W/m2. This situation surely justifies a serious re-think of the International Maritime Organization's decision to slash the sulfur content of all marine fuel burned globally, particularly since it is hardly the only alternative available to address the negative effects of these emissions on most human populations. It's also a much more expensive option for shippers--and thus anyone who benefits from international trade--than confining the low-sulfur rules to coastal waters. According to the analysis cited by Mr. Hone, the latter scenario would preserve nearly 80% of our sulfur sunshade, while the global low-sulfur rule would more than halve it.

When I was involved in marine fuel supply and distribution on the West Coast early in my career, it was already clear that the emissions from burning high-sulfur bunker fuel were a major source of pollution in port cities and coastal areas, and that the importance of addressing them would grow once most onshore emission sources, from power plants, trains and other mobile sources had been dealt with. Some of the sulfur was eliminated as large marine diesel engines replaced the old steam turbines, and much of the rest was addressed with restrictions on the quality of fuel that could be burned in port and along the coast. For now, vessel owners can comply with these rules by carrying two different fuels: enough of the more expensive low-sulfur fuel for use in US and other regulated coastal waters, and the rest consisting of much cheaper high-sulfur fuel for use on the high seas. That approach, which would no longer be an option after 2020 under the IMO rules, cleans up the air where it matters most but still puts enough SO2 into the atmosphere to scatter some of the incoming solar energy and offset part of the warming from CO2.

Using one form of pollution to offset another is hardly a perfect solution, but just as many scientists and environmentalists urge caution about introducing new geoengineering measures before we understand their consequences well enough, we should think long and hard about tampering with this long-standing, if inadvertent geoengineering process until we have something better in mind to replace it, or until we no longer need it.

Monday, October 11, 2010

After the Drilling Moratorium Is Lifted

As I was thinking about the offshore drilling moratoria--both the official one that's scheduled to end in a few weeks and the unofficial one that might drag on for months or years--it occurred to me that the Deepwater Horizon accident couldn't have happened at a worse time, in terms of our grasping its impact on our energy economy. There's never a good time for a tragedy on that scale, but the fact that it occurred during a period in which slack global oil demand and temporarily abundant OPEC spare production capacity have insulated oil markets from its effects has created a misleading impression of its inconsequentiality to our oil supplies. If you doubt that, imagine how the oil market--and the stock market--might have reacted if the accident and our response to it had begun on April 20, 2008, when oil futures traded at $117 per barrel, on their way to $145 a couple months later. Unless drilling resumes fairly soon on something close to the previous scale, or unless expectations of an uptick in global oil demand next year prove premature, we could all be in for a taste of those masked consequences within a year or two.

No one expects drilling to resume as though Deepwater Horizon had never occurred, and the industry has its work cut out for it to restore trust in its capacity to develop this energy in a safe and environmentally acceptable manner. New regulations, more consistent enforcement, and initiatives such as the new Marine Well Containment System, to which several of the major oil companies have committed, should help. But until the government and public are satisfied that all of the key lessons from the Deepwater Horizon disaster have been identified and put into practice, the industry will remain on probation. It's somewhat ironic that while we are still grappling with all this, the Parliament of the European Union--widely regarded as being more environmentally sensitive than the US--just voted against a proposed drilling ban. In the meantime, the effects of delayed development will begin to compound, in the absence of any near-term alternative that can fill the gap at the scale required, other than increased oil imports.

In a posting in May I described the potential impact of a protracted halt in US offshore drilling, particularly from the deeper waters of the Gulf of Mexico, and explained why neither expanded biofuels production nor the deployment of electric vehicles (EVs) or highly fuel-efficient hybrids can substitute for domestic oil production. We require these alternatives in any case, but it will be quite a few years before they could plug the resulting gap in our energy supplies. Replacing the equivalent of each 50,000 barrel-per-day oil field that's not developed in the next year or two would require 20 additional ethanol plants, 1.6 million EVs, or a like quantity of foreign crude oil or imported gasoline, diesel, jet fuel, lubricants and other products. And as I noted at the time, delay amplifies the effects of the decline of existing fields, so that the hole out of which we must dig ourselves grows larger with every month that new exploration and production are deferred.

What makes this particularly worrying now is that it has become evident in the last few months that the scheduled lapse of Interior Secretary Salazar's deepwater moratorium at the end of November will almost certainly not restore drilling even in the Gulf of Mexico to anything close to its former level for some time. The impact on technically non-moratorium shallow water drilling from the reorganization of the former Minerals Management Service into the new Bureau of Ocean Energy Management, Regulation and Enforcement, under new management and with a new, stricter set of regulations to enforce, makes that clear. It's also evident that offshore drilling in the Arctic, which is needed to backfill declining output from the Alaskan North Slope, could be delayed even longer.

For the moment, this might not seem like a big deal, when weighed against the universally-shared objective of reducing the risk of another major oil spill as much as humanly possible. With US petroleum demand still depressed by the aftermath of the recession and financial crisis, and with domestic oil production having recovered to levels not seen since before Hurricane Katrina--thanks in large part to the success of deepwater drilling--our net petroleum imports are actually 2 million barrels per day (bpd) lower than they were in 2007. That has helped set up a global oil market in which OPEC has had to keep a tight lid on its output to prevent prices from falling. However, if the analysis in this week's Economist is correct concerning the significant growth of demand from the developing world this year and next, along with an impending peak in non-OPEC oil production, then OPEC's problem will become much easier to manage and prices will begin to head back upward.

The resulting scenario isn't very appealing, unless you're convinced that higher oil prices are a good thing and perhaps the only thing that will get us to address our energy security and emissions challenges head on--though that ignores the lessons from a couple of years ago concerning how the competitive breakeven price of many alternative energy technologies tends to recede as oil prices rise. The deepwater drilling moratorium has nothing to do with the upward trend of oil prices in the last few weeks, and it probably won't be the actual trigger for higher prices next year. However, if oil prices do resume their pre-recession trajectory, the accumulating lagged effects of the moratorium and its aftermath could reinforce the impact on our wobbly recovery and gaping deficits in very unpleasant ways. By the time we wake up to this, it will be too late for second-guessing whether the US government has moved swiftly enough to get this key industry back to work.

Thursday, October 07, 2010

California Prop. 23 vs. A.B. 32

Aside from the question of which party will control the House and Senate for the next two years, next month's mid-term elections also feature a number of important state contests, including California's closely-watched Proposition 23, a ballot initiative that would suspend enforcement of the state's major greenhouse gas legislation, Assembly Bill 32. Prop 23 has national implications, since California has taken a leadership position on emissions regulations at a time when national climate policy has become deadlocked. Yet as I've watched the coverage of Prop 23 in the blogosphere and mainstream media, I've been amazed by the consistent mischaracterization of precisely what is at stake in this initiative, most recently in Tom Friedman's column in yesterday's New York Times. Californians surely deserve a better assessment of the issues involved.

When the loudest objections to any candidacy or initiative are focused on vilifying its financial backers, this often indicates that its opponents' arguments on its merits are weak. The fact that several oil companies with refineries and other operations in the state are supporting Prop 23 shouldn't trump the pros and cons of the actual initiative, any more than the fact that much of the funding for the anti-Prop 23 effort apparently comes from venture capitalists and companies that stand to profit if Prop 23 is defeated. For example, the portfolio of VC firm Kleiner Perkins Caufield & Byers, one of whose prominent partners is reported to have donated $2 million to oppose Prop 23, includes investments in biofuels, wind, solar and geothermal power, along with other green technologies, many of which would benefit if A.B. 32 were upheld. From my perspective, this whole line of argument is a colossal red herring. Valero, Tesoro and the other oil company supporters of Prop 23 are part of a $50 billion-a-year California refining industry that employs thousands of Californians and fuels more than 99.9% of the state's 33.6 million registered motor vehicles. The initiative's cleantech-based opponents are part of a smaller but growing sector that has emerged as an offshoot of Silicon Valley and the state's premier research universities. All of these entities have a stake in the outcome, and an equal right to take a position. Their involvement shouldn't constitute a compelling argument for or against Prop 23.

So what is this really all about? Contrary to one of Mr. Friedman's assertions yesterday, it is most certainly not about "making the state a healthier place". The conflation of the greenhouse gas emissions (GHGs) that A.B. 32 explicitly addresses with local air quality is probably the most misleading aspect of the entire debate. Perhaps this was an inevitable consequence of the US Supreme Court decision that labeled GHGs as pollution, but it is a most unfortunate one, because it obscures the crucial differences between a law that was intended to restore California's GHG emissions to their 1990 level by 2020--thereby reducing the state's impact on global climate change--and the extensive state, federal and local laws and regs targeting the causes of the smog for which parts of California became infamous. As a long-time California resident during the period when most of the latter were implemented, I can attest to their effectiveness at cleaning up the state's air, despite the enormous growth in population and vehicles that has occurred in the meantime. However, voters should understand clearly that none of this progress, and none of those existing measures regulating the emissions of SOx, NOx, carbon monoxide, unburned hydrocarbons, and the other contributors to local air pollution is at risk on November 2nd. Simply put, both A.B. 32 and Prop 23 deal with climate change, not local pollution.

As for health effects, any connection between the emissions that A.B. 32 regulates and public health in California is tenuous, at best. Understanding why depends on the numbers involved. In 2007 California emitted just over 400 million metric tons of CO2, the primary greenhouse gas implicated in climate change. This constituted 6.7% of total US CO2 emissions, an enviable performance considering that the Golden State accounts for about 12% of US population and roughly 13% of US gross domestic product (GDP). But on a global basis--and climate change is very much a global problem--California emits just 1.4% of the world's anthropogenic CO2. The state could stop emitting CO2 altogether and the global climate would never notice the difference. That doesn't justify doing nothing about the problem or shirking responsibility for the state's contribution to climate change, but it does mean that tracing the future health impacts of the expected future warming of California to the highly attenuated effects of the state's current emissions stretches cause and effect to the breaking point.

Then there are the economics that are at the heart of Prop 23's proposal to delay implementation of A.B. 32 until the state is in better financial shape, and of the opposition's arguments concerning the current law's benefits in fostering a clean energy economy in California. It's noteworthy that when the legislature passed A.B. 32 in 2006, California's economy was booming. Nominal state GDP in 2006 grew by over 6%, on top of 7% growth in 2005 and 8% in 2004. And while Mr. Friedman notes that the state's unemployment rarely falls below the 5.5% threshold on which Prop 23 would make the implementation of A.B. 32 contingent, that's precisely where unemployment was when the law was passed, and for the following year. I don't think that's a coincidence or an arbitrary choice. Whatever its merits--and it has more than a few, in my view--A.B. 32 is the kind of thing you take on when an economy is healthy, not when it's on its knees. That's because it cannot help but increase the cost of energy and the cost of doing business.

California has been down this road before. Starting in the 1980s the state imposed some of the most restrictive specifications in the world on gasoline and other fuels sold there. It also made it much more difficult for refiners to expand operations to keep pace with the growth in fuel demand in a state with a rapidly growing human and vehicle population. This turned California into a virtual "gasoline island", which has contributed to consumers in the state paying an average of 25 cents more per gallon--or 11% more--than the national average for gasoline over the last decade. With the implementation of the Low Carbon Fuel Standard (LCFS) included in A.B. 32, it will become even costlier to make gasoline in California, and this price differential could expand significantly. Considering that the state consumes 42 million gallons of gasoline each day, this already amounts to an extra $3.8 billion per year in costs. Increasing that disadvantage is not a trivial consideration. It won't even do much for the domestic ethanol industry, since much of the ethanol produced in the US won't qualify as "low-carbon" under the LCFS's definitions. This is a matter over which the ethanol industry is currently suing California.

With regard to the "green jobs" and cleantech growth that Prop 23's opponents cite, I am skeptical that these will result in meaningful growth in overall employment and output, as the pressure on the rest of the state's economy increases with the ratcheting-down of A.B. 32's emissions cap and LCFS. The recent experience with green-energy deployment incentives at the national level suggests caution in assessing how effective these measures will be in stimulating green jobs in California or the rest of the US, as opposed to offshore, where much of the green energy hardware that is being installed is manufactured. A recent article in MIT's Technology Review also questioned whether the consequences of Prop 23's passage would be quite as severe for the state's emerging cleantech sector as opponents suggest, because other incentives would remain unaffected. Ultimately, the market that matters most for California's cleantech companies is the global one, where they must compete with manufacturers from Asia and Europe. Creating a bubble market on their home turf will do little to advance that cause, as German photovoltaic firms are currently learning to their regret.

When we dispense with all the questionable arguments concerning who is for and against this initiative, whether it will alter the quality of the air Californians breathe, and how many green jobs it might affect, the choice becomes clearer. Proposition 23 asks voters to decide whether California should proceed with the nation's most aggressive effort to curb the greenhouse gas emissions implicated in global warming now--despite high unemployment, low growth and deep deficits--or whether that effort should be postponed until the state has returned to growth of the kind that prevailed when the law was passed, before the housing collapse, financial crisis and recession. The context of this choice should be equally clear, consisting of a complex global environmental challenge that California's efforts can't solve alone, but might help to influence at the margin. Having spent so much of my life in the state, including my entire education, I can easily understand that many Californians would believe it was their responsibility to move ahead at any cost, even if no one else followed. However, I can also envision that many of the state's voters would conclude that, for the moment, the costs and risks associated with A.B. 32 look too high. This is a difficult and consequential decision, even if some choose to portray it as a one-sided no-brainer.

Tuesday, October 05, 2010

Locking In Gas Prices

I recently received an offer from my household natural gas supplier, Washington Gas, to lock in my gas purchases for the next 12 months at a price of $0.699/therm. They reminded me that I had paid as much as $0.96/therm and as little as $0.68/therm over the last 12 months, before distribution charges, so on the surface this looks like a good deal. Of course the real measure of the attractiveness of this offer is not what I've paid in the past, but what I'm likely to pay in the future if I don't take advantage of it. Unsurprisingly, Washington Gas left that for me to work out. This is no simple task, even if you follow energy trends as closely as I try to do.

The price of natural gas is notoriously volatile, particularly in years when supply is tight, the economy strong, and weather extreme. Historically, gas often spiked in the winter months, as cold weather drew down stockpiles, and traders bid up the price for prompt delivery. That pattern has shifted somewhat in recent years, as seen in the chart below, not because global warming is making winters warmer--though that seems to be the case in the most general sense--but because US gas consumption patterns have shifted.

In 1997 residential users accounted for 22% of total US gas demand, commercial and industrial users took nearly 52%, and just 18% went to power generation. Last year residential use was 21%, but commercial and industrial had fallen to 40%, while the power sector took over 30%. And since power generation, for which gas turbines are often the incremental supply, typically peaks in the summer months, the annual peak of gas prices is now as likely to occur in June or July as in January or February. That's an important consideration if you're a residential customer like me. Of the roughly 1,100 therms my household consumes each year, 84% are bought between November and March.

In this context the first place to check on whether the offer from Washington Gas is fair was the futures market. Yesterday's average closing price for the one-year "strip" from November 2010 to October 2011 was $4.26/million BTUs. That's the price at the Henry Hub, a gas distribution point in Louisiana. In order to compare it to what I've been offered, I need to account for the average differential, or "basis", between that location and the supply point for Northern Virginia. The "city gate" price for Virginia over the last year averaged $2.39/MMBTU higher than Henry Hub. Even that doesn't quite get me to the Purchased Gas Price that shows up on my utility bills. Over the last 12 months I paid an additional $0.60/MMBTU, on average, because the mix Washington Gas sells me includes gas purchased under long-term contracts, as well as incorporating the results of its hedging activities. When I add all this together, the equivalent futures-based price to compare to the deal I've been offered for the next 12 months works out to about $7.25/MMBTU, or $0.73/therm. For the November-March period that will affect me most, it's around $0.71/therm.

From that I conclude that my supplier is offering me a price that's in line with the market, and that I couldn't beat it even if I did the hedging myself. However, it's important to recall that the futures market isn't a forecast; it's just the current consensus on what buyers and sellers are willing to agree on today, based on everything they know. In order to decide whether I should lock that in and give up any upside or downside, I ought to have a point of view on gas prices, based on supply, demand and inventories. The supply side is dominated by surging shale gas output, which has taken US gas production to levels we haven't seen since the 1970s. For production to drop by enough to drive up prices significantly within the next year, the shale gas bandwagon would have to slow appreciably. That's certainly possible. In several presentations at the recent IHS Herold Pacesetters Energy Conference I saw graphs indicating that a number of producers aren't covering all their costs at current prices. Some of them must continue drilling new wells in order to satisfy the terms of their leases, but others could slow down if they chose. A slowdown in drilling would translate into reduced supplies fairly quickly, because of the rapid drop-off of output from individual wells. Even bigger supply risks are inherent in the growing environmental concerns surrounding shale gas drilling, which have seen New York's state senate vote to impose a moratorium on shale drilling. Yet while it's hard to envision a big enough drop in output from any of these factors, soon enough to affect this winter's prices, it's even harder to see so much additional shale gas coming to market in the next year that it would drive prices well below current levels.

On the demand side, the weak economy dominates, particularly in the industrial sector, which despite having rebounded from last year's lows is still running well below its consumption in the early 2000s. A sizable fraction of that lost demand isn't coming back, even if the economy started growing at rates more characteristic of past post-recession expansions, because the high gas prices of the previous decade drove some fertilizer and petrochemicals producers out of business or offshore. The biggest upside demand potential comes from the power sector, which is also suffering from low demand, at the same time we see low gas prices and environmental pressures displacing coal with gas and renewables. That's a clear medium-term trend, though as with reduced shale drilling, the situation seem unlikely to change much in the next 3-6 months.

That leaves gas inventory as the last major fundamental factor to assess. As of the most recent figures, gas storage was running about 5% below the same week last year, but ahead of the previous three years. A severe cold snap might test these inventories, but they don't loom as a big upside price risk today.

On balance, then, it appears I've been offered a fixed price that is not only in line with the current futures market, but at which I would also be giving up relatively little chance of paying significantly lower prices later--barring a double-dip recession--while gaining protection from weather or supply-related surprises. If the next year looked exactly like the last one did, I'd end up saving a bit less than $100. If you've followed my logic this far, you might think this was a lot of effort in order to convince myself that what looked like a good deal really was, but then I guess that's the lot of a former commodity trader who routinely had to make decisions like this, but for much larger stakes. And perhaps I've given you some food for thought, in case you're facing a similar decision.

Friday, October 01, 2010

Choosing Green Projects Wisely

One aspect of blogging I never anticipated was the degree to which it would put me on the radar screen of public relations agencies. Not a day goes by that I don't receive at least a half dozen emails from various PR firms seeking publicity for a new product, project, initiative or campaign. Their clients include companies, government agencies, and non-governmental organizations. Of course these emails aren't all equally interesting or informative, but now and again they catch my attention, as was the case with two I received today. The first was promoting "Ohio's Largest Rooftop Solar Array", to be installed on a transit bus garage in Akron. The second touted UPS's acquisition of another 130 hybrid-electric delivery vehicles. Both press releases framed these efforts in terms of their benefits for reducing fuel consumption and CO2 emissions. However, from the data provided, the costs of those reductions look quite different.

Start with the Akron Metro Regional Transit Authority's solar rooftop array. The project installed 488 kW of photovoltaic panels, with an expected annual generation of 486,760 kWh of electricity. RTA claims this will save the equivalent of 39,322 gallons of gasoline--an odd comparison, since roughly 86% of Ohio's power is generated from coal and less than 1% from oil--while reducing emissions by 350 tons of CO2 per year, all for a cost of $2.5 million. I give RTA and their solar installation contractor full credit for providing enough data to assess the effectiveness of this investment. Doing that properly would require a discounted cash flow analysis and a detailed knowledge of what RTA pays for power from the grid. However, interest rates are currently very low, reducing the impact of discounting on the calculations, and for a back-of-the-envelope estimate the EIA's national figures for commercial electricity rates should be close enough.

$2.5 million for 488 kW of panels works out to just over $5/Watt, which is right in the ballpark for installed PV at this scale. Estimating the effectiveness of this investment requires allocating that cost among the resulting benefits. From my perspective, aside from the intangible benefits of being greener plus the health benefits associated with reduced coal use, this boils down to two simple categories: power savings and CO2 reduction, with the latter being the real measure of how wise a green investment this was. Over the 20 years this installation could last, it should generate roughly 9.7 million kWh. At an average electricity price of 10.2¢/kWh, the value of that power is just under $1 million. (I've ignored future inflation in electricity prices, but I've also ignored the typical 1% per year accumulating loss of PV output over the life of the panels.) That leaves the other $1.5 million of cost to apply to the 7,000 tons of CO2 savings over 20 years, for an effective cost of $214/ton. Considering that you can buy emissions credits in the EU all the way out to 2020 for less than about $32/ton, the environmental benefits of this project look pretty expensive.

What accounts for that huge gap? Well, among other factors it's because these solar panels are in Ohio, not one of the most reliably sunny spots in America. Based on the information in the press release, they will be exposed to an average of just 2.7 hours of peak sun each day. The same array located in Los Angeles would generate more than twice as much power, halving the premium over commercial power costs in the calculation above. And even with California's cleaner average grid emissions, the effective cost per ton of CO2 avoided would be much lower, perhaps less than half the cost in Akron.

Contrast all this with the UPS purchase of 130 hybrid vehicles for their delivery fleet in New York, New Jersey and California. The estimated fuel and emissions savings are nearly double those of the Akron solar array, although the press release was missing the associated cost, citing only the $25 million that UPS has invested in its total fleet of over 2,000 alternative fuel vehicles (AFVs) including hybrids, plug-in hybrids, CNG and propane. The folks at Edelman were kind enough to put me in touch with a representative at UPS, from whom I learned that the figure I was seeking wasn't public, because of competitive issues involved in how UPS bids its fleet purchases. However, I also learned that UPS has a payout hurdle of 5 years for its AFVs, other than new models undergoing testing. That means that the 35% fuel savings these vehicles provide recoup the cost premium over conventional vehicles within 5 years, after taking into account any federal, state or local incentives involved. So the emissions benefits are essentially free to UPS--and at worst cost the equivalent of the incentives.

I hate to be second-guessed, and I don't enjoy second-guessing others. I don't know everything the Akron RTA management considered when they chose to spend $2.5 M on a solar roof array, so I can't say it was a bad decision. However, if I do know that if I were a stakeholder in Akron RTA, I would be asking some very pointed questions about the goals and criteria that drove them to make this decision, instead of investing in another green alternative that would either cost less or deliver more emissions savings bang for the buck. Did they look at buying more hybrid or natural gas buses, along the lines of what UPS is doing, or consider other efficiency investments in their facilities? A solar roof is a very visible symbol of "going green", but unless it's in the right location, it might not be the greenest choice, if the goal is the economical reduction of greenhouse gas emissions.