Building the Low-Emissions Future

Last week The Economist published a detailed assessment of the state of play for capturing and storing the carbon dioxide emitted by power plants and factories. Although it skirted the assertion of many environmentalists that "clean coal" is inherently an oxymoron, the article's tone was generally skeptical concerning the cost and ultimate efficacy of the technology. Coincidentally, Greenpeace released a study featuring an ultra-low-carbon scenario created in conjunction with the European Renewable Energy Council. It proposes that by 2050 the US could shed all coal-fired power generation, as well as all nuclear power and most natural gas-fired power, along with nearly 80% of the petroleum used in transportation--all replaced by renewable electricity and biofuels. If the Economist regards carbon capture and sequestration (CCS) as "expensive and unproven", I can only imagine the terms it might use to describe the extraordinary transformation required to achieve the outcome Greenpeace envisions. The necessity of reducing greenhouse gas emissions dramatically by mid-century and the serious obstacles to replacing our entire energy economy with renewable energy sources in that time frame reinforce the importance of continuing to pursue CCS, in spite of its uncertainties.

I've been following CCS for a long time, and I've written about it many times on this blog. Without diminishing the technical challenges involved, I see them as being manageable with existing and foreseeable engineering know-how, without a scientific breakthrough. I attribute the prolonged absence of a large-scale demonstration of fully-integrated CCS on energy sources more carbon-intensive than natural gas to the mismatch between its costs and current monetary benefits. Whether the cost proves to be closer to the low or high end of the range of estimates included in the article, from roughly $40-115 per ton of captured CO2, it's hard to imagine a utility or oil company taking on the investment and operating expenses involved without the incentive of a transparent and fairly predictable price on carbon emissions. Whatever the cost of CCS might be, it can't be considered in a vacuum, and that is the biggest shortcoming of the Economist's otherwise thorough analysis.

As the US Congress prepares to embark on its latest effort to enact a greenhouse gas cap and trade bill, it's important to think about where its enormous pool of emissions savings will be found, and at what cost. CCS is only one option among many. Happily, a fair amount of work has been done in this regard, including a study by McKinsey & Co. for the Conference Board a little more than a year ago. A key chart from their report portrays a potential medium-term supply curve for emissions reductions. It indicates that while there might be a number of ways to cut CO2 at low or even negative cost--changes that would pay for themselves--achieving deeper cuts would require the contribution of costlier solutions, including CCS.

It's also worth noting that the current cost per ton of CO2 reductions from some of our current climate change strategies exceeds most estimates for CCS. In my recent posting on the application of energy storage to solar power, I calculated an effective cost of power for a couple of utility-scale solar projects in Florida at around $0.25/kWh. That's a premium of at least $0.20/kWh compared to a coal-fired power plant (without sequestration.) Based on typical emissions of 2.1 lb. of CO2 per kWh generated from coal, that implies an abatement cost of $190/ton of avoided CO2. In the likelier event that the power backed out by solar was generated from natural gas, the effective abatement cost could be even higher, because of the smaller emissions savings involved, despite the higher cost of gas-fired power compared to coal.

That comparison doesn't imply that solar power will always be a high-cost source of emissions reductions, or that CCS represents some kind of silver bullet for climate change. At the same time, coal now accounts for 23% of US primary energy consumption, 49% of our electricity generation, and nearly two-thirds of our baseload-capable generation. The difficulty of replacing baseload power with cyclical or intermittent sources makes me very skeptical of any low-emissions scenario that ignores CCS or assumes we can jettison coal entirely, not to mention forgoing nuclear power, the second-largest baseload power source in the US and by far our largest source of low-CO2 power. My specific comments on the Greenpeace scenario are posted elsewhere. At a minimum, any claims that it proves we can achieve the administration's 2050 emissions goals with only "green" energy options and efficiency gains are unwarranted. As useful as they are, scenarios can only point the way to possible futures. They can't provide firm proof of anything.

That leaves us with the hard work of cobbling together a broad set of climate solutions, in response to a price signal on emissions. In my assessment, that mix is very likely to include awkward elements such as CCS, along with deeply unglamorous things like improved farming and ranching practices. Contrary to the conclusions of the editorial accompanying the article on CCS, the technology is worth pursuing for reasons that have nothing to do with "placating the coal lobby." Nor does the cost of proving its feasibility look so high as to "deprive potentially cheaper methods of cutting emissions of cash and attention," particularly when the administration expects to carve out $120 billion for energy R&D from the proceeds of cap & trade over the next ten years. And even if it did, it's one of the few options that could be applied to reduce directly the emissions from the fossil fuels that still account for 85% of the energy we consume. That could make the difference between a manageable transition to a low-emissions world and an upheaval as bad as the current financial crisis.

Read More

Mark to Market

The practice of requiring banks and other businesses to mark their investments to market has drawn increasing criticism in the last several weeks from pundits and high-profile investors who would like to see it at least relaxed, if not rescinded. When I traded commodities in Texaco's international oil trading operation in London in the early 1990s I acquired some first-hand experience with "mark to market." Although I wasn't dealing with multi-billion dollar investments in exotic credit derivatives, the principles are sufficiently similar for me to offer some thoughts on the benefits and risks of this methodology, which appears to be feeding a vicious cycle of asset deflation in the financial sector.

The other night while watching our favorite TV cop show, "Life", my wife and I got a laugh out of the bumbled attempts of several of the characters to explain a derivative, and the confusion that greeted the accurate definition when it was finally given. I suspect the writers were reminding us how few people truly understand some of the financial instruments and regulations at the heart of the current crisis. Mark-to-market accounting likely falls into this category.

In the case of the futures market and physical oil market deals in which I was involved in London, the mark to market (MTM) provided a way to issue a daily report card on each of the trading positions we had taken on behalf of the company. This removed much of the element of surprise, if the value of something we had bought or sold changed significantly before the deal was ultimately completed. It entailed assigning a market-based price to each component of the deal at the end of every trading day, as if the product had been delivered or the position unwound that day, even though that might not actually happen for weeks. When the commodities in which we were dealing were ones for which there was an active, liquid market at all times, this accounting was relatively easy to perform. For some of the more unusual things we dealt in, for which there was no futures market and only occasional, sometimes unreliable reports of recent transactions, it generated uncertainty and anxiety.

The purpose of undertaking this effort, which consumed valuable time and was not exactly popular with the trading team, was to promote accountability and action. If the MTM on a particular trade showed a steady negative trend--particularly if it had moved from an expected profit to a loss--this triggered a discussion with management about why it was happening and what should be done. When handled well, this sometimes led to new insights about the market that we had failed to recognize. It normally resulted in a decision on whether to hang in there a bit longer, because we could justify our view that things would turn our way, or to modify or unravel the position--even at a loss--and regroup. Of course, that wasn't always possible; sometimes the cargo was on the water, bought and paid for, and there was nothing we could do but watch the red ink swell. That gets at the essence of my concern with the application of MTM to the big banks and institutions that the government has been forced to assist, for fear of "systemic risk"--the chance of the whole financial system crashing like the Blue Screen of Death on your PC.

Crucially, the reliability of mark to market depends on the ability to obtain an accurate reading of the value of what you are holding. That requires credible reporting of current transactions--preferably many of them--in something that, if not identical, at least looks enough like your asset to serve as a good proxy. If the only deals reported are distressed sales by desperate firms, you must write down your position to that level, even if you would never willingly sell it for so little. In the worst case a series of such write-downs causes a large enough deterioration in the balance sheet of the firm that it is compelled to sell some of these assets, driving their market value even lower and triggering a cascade of further sales by depressing the MTMs of other institutions.

Throughout the financial crisis, the practice of MTM has been defended as an unpleasant but necessary discipline to prevent an outcome such as was seen in Japan after its property bubble collapsed, with numerous "zombie banks" that were effectively insolvent but kept alive by the fictitious value of assets that were worth only a fraction of the level at which they were carried on the books. That argument still has some merit. However, it seems equally possible to destroy investor (and ultimately depositor) confidence in otherwise profitable, solvent institutions through the steady mechanical deflation of their illiquid assets, the potential buyers for which understand clearly that time is on their side.

Having run this experiment in its pure form until now, I'd like to see the administration test the opposite hypothesis for a few months: suspend MTM for bank capital purposes and restore the "uptick rule" on short-selling, while they're at it. We'd quickly find out whether these steps helped to stabilize the system. If they made things worse, they could quickly be reversed. It wouldn't be the first course correction we've seen during this crisis.

Read More

Storing Sunlight

An article in MIT's Technology Review on a new liquid battery technology got me rethinking an assumption I've been making for some time concerning the synergy between renewable energy and better batteries. The article's author makes a similar assumption, suggesting that with bigger, cheaper batteries, electricity from solar power might be supplied around the clock. But while this new battery, consisting of a combination of molten metals and molten salts, looks clever, I'm not sure it would make sense to use it to store solar electricity in the way the author envisions. The main impediment to the large-scale application of solar power today is not so much its cyclical nature--which storage can address--but its high cost per generated kilowatt-hour, compared to other technologies. The power likeliest to be stored for later delivery won't be the most expensive, but the cheapest.

My focus here is not on the rooftop solar panels being installed on homes. Storage isn't an issue in most such cases, unless you're in a remote location or insist on grid independence. Net metering--the ability to sell excess electricity back to the grid and buy power from it when the sun isn't shining--typically offers a much better deal for homeowners than batteries, by effectively using the grid as free storage. Since rooftop solar has the inherent advantage of competing with retail, rather than wholesale electricity prices, I'm more interested in the utility-scale solar installations springing up all over. These compete directly with the output of gas-fired simple-cycle turbines, the standard "peaking" power plant technology. Utility solar projects currently cost around $6,000 per installed kilowatt (kW) based on several recent project announcements turned up by a quick web search. Even with the 30% solar investment tax credit and a site in a sunny location, such as Florida, that results in an amortized cost of generation of roughly $0.25 per kilowatt-hour (kWh), based on a 20-year life and 6% interest rate. That might be acceptable for peak demand periods, such as hot, sunny afternoons, but it doesn't compare very well to off-peak wholesale power costs from other technologies, including wind and gas turbines, let alone coal or nuclear power.

Nor is the cost per kWh the only barrier solar power must overcome, in order to be competitive around the clock, even if the cost of storing it were negligible--which is certainly not the case today. The capital involved in amassing enough capacity to serve a given market 24/7 is much higher for utility-scale solar power than for other technologies because solar's capacity factors, reflecting the fraction of time when these facilities are available and generating peak power, often average below 20%. In the Florida example above, a solar array would receive an average amount of sunlight equivalent to 4-4.5 hours of peak sun per day. That equates to a capacity factor between 17-19%. Replacing the baseload power from a 500 MW coal-fired power plant operating at an average capacity factor of 80% would require 2,200 MW of solar power plus a commensurate amount of storage. So at $6,000/kW, a solar power plant capable of generating as many kWhs as a $1.5 B coal-fired plant would cost $13.2 B, excluding the cost of delivering power when needed, instead of when the sun happens to be shining. (It also implies a very high cost per ton for the avoided CO2 emissions.)

With current solar technology, the entire proposition of storing lots of solar power looks impractical and unnecessary. Using large-scale, cheap storage--of whatever technology, whether batteries, compressed air, or pumped water--to time-shift renewable power makes much more sense when applied to lower-cost generation from wind power, the normal output of which also has a much poorer overlap with typical daily and seasonal power demand curves than solar power. In most markets, solar power should be going after the premium associated with the afternoon demand peak. Solar needs little or no storage for that, other than to buffer the effects of cloudiness or extend its output by an hour or two on either side of its natural output peaks. That looks easiest with solar thermal technology, which stores energy as heat, rather than electricity. As a result, developers of new batteries should not pin their hopes on the growth of a market for storing solar power.

Read More

The End of the World As We Know It?

The opinion section of the Sunday New York Times made for sobering reading this weekend. While the Times has hardly been a bastion of economic optimism of late, three op-eds stood out for their shared sense that we might be on the brink of truly wrenching change. Tom Friedman invoked an enviro-economic tipping point, citing one expert's prognosis of a "Great Disruption;" a best-selling author saw the risk of "economic cataclysm" in the bursting of Eastern Europe's foreign debt bubble; and another found parallels to the Austria-Hungary of 1913, one year before the war that ended at least three empires and mortally wounded a couple of others. But while the systemic unraveling of the past six months or so makes such possibilities likelier than they would have been just a few years ago, the odds still favor a much less drastic result than revolution or apocalypse. The enormous recent increase in the range of uncertainties we face lends added credibility to the direst scenarios. However, it's important to realize that these predictions are not certainties, unless our responses make them so. That applies to energy, as well.

When I think about the possible paths of energy supply and demand over the next few years, they depend much less on specific energy or environmental trends than on the future state of the economy. Forecasting oil prices has become meaningless without a clear view of growth, particularly in the US and China. Demand may have rebounded recently in the US, but the combination of a crippling financial crisis with a deep cyclical downturn has Americans questioning the future in ways that I haven't seen in decades, other than the immediate aftermath of 9/11. The tangible effects of what noted historian Niall Ferguson has dubbed the "Great Recession" serve to reinforce the hangover of millennial angst from the turn of the century, which manifested in the more extreme views of Y2K and more recently Peak Oil. Layer in the propensity of my own Baby Boom generation to see itself at the epicenter of great events, and the stage is set for receptiveness to the view that we stand on the brink of unprecedented, permanently life-altering change.

When I was involved in my first scenario planning project at Texaco, we came up with three remarkably insightful views of the future of the energy industry, at least two of which have remained relevant far longer than any of us could have guessed. They received wide distribution throughout the company and had the general support of many in upper management. However, that project also came up with the seeds of another scenario, a much darker view involving the rejection of globalization and a growing wave of anti-Americanism around the world. Although in some respects it was no less prescient--or challenging--than the other three scenarios, it went nowhere, because the context for exploring it didn't exist in 1997. The external consultants who guided us through the process advised us not to pursue it, or risk destroying the credibility of the entire effort. That was good advice, even in retrospect, and it served as a useful lesson about the way that assessments of the future interact with our views of the present and our experience of the past. They must also be grounded in reality.

That's certainly true for energy, today. However much we might consider our energy future to be in flux, our views of it must take into account the embedded dominance of fossil fuels in our energy systems. Given the scale of these systems, that dominance will still exist next year and the following year, no matter what policies are enacted in the US or elsewhere. This might all seem to be up for grabs, but that's really only true in the long term. I've believed for a long time that we are on the threshold of a revolution in the ways that we produce and use energy, and it has arguably already begun. But no matter what happens in the economy, short of a massive global collapse, this revolution cannot be completed overnight. It will take decades, and that is equally true of our response to man-made climate change, which took a century to create.

Whenever I watch the news or read the latest statistics about the economy, I worry about what next year might look like. The uncertainties are huge and daunting. But I also know that while the chances of a Great Depression-style collapse or a radical socio-enviro-political transformation have risen, the economic future is likelier to resemble the last few decades, minus the unsustainable levels of personal and institutional debt. In the same way, the energy transformation is likely to play out as a set of big, gradual shifts: away from coal and other carbon-intensive fuels and toward renewable energy and nuclear power, and away from liquid transportation fuels and towards the eventual electrification of most ground vehicles. These transitions will take time, and that means that, whatever their price, a decade from now there will still be electricity and natural gas for the appliances and devices you buy today, and there will still be fuel for the car you buy today. That's one set of uncertainties over which we shouldn't lose sleep.

Read More

Raising A Hidden Tax

Since the administration has apparently ruled out an increase in the gasoline tax to cover declining Highway Trust Fund revenues, it's surprising that it appears to be giving serious consideration to a proposal that would raise a hidden tax on gasoline. This is even more perplexing, when you realize that this increase would actually reduce the government's net take on every gallon of gasoline sold, while simultaneously diminishing the value of the product for consumers. As reported in today's Washington Post, the US ethanol industry is petitioning the government to increase the percentage of ethanol allowable for inclusion in gasoline from 10% to 15%. At the current average gasoline pump price of $1.93 per gallon, this would effectively raise the price by 3.4 cents per gallon, while reducing federal tax revenue by 2.2 cents.

It's entirely understandable that the ethanol industry would seek such a change. Having overbuilt capacity just as demand for the fuel into which their product was blended collapsed and the easy credit that enabled their expansion tightened drastically, ethanol producers aren't in much better shape than Detroit. Several are already in bankruptcy, and others are idling capacity because of poor margins and tight cash flow. And if that weren't bad enough, the primary market for their product--"E10" gasoline, a blend containing 10% ethanol--is approaching saturation at current production levels. Nor have E85 sales grown sufficiently to relieve the pressure created by the combination of a steadily-escalating federal Renewable Fuel Standard and weak motor gasoline sales. However, even if there were no risk of higher ethanol blends damaging the engines and fuel systems of cars not designed as Flexible Fuel Vehicles, increasing the ethanol limit in gasoline would cost us all at the pump.

A gallon of ethanol contains one-third less useful energy than a gallon of petroleum gasoline. This dilution effect is already at work in the standard E10 blend, which contains 3.4% fewer BTUs than "E0". E15 would increase this gap to 5.1%. The Oak Ridge National Laboratory of the Department of Energy recently tested a representative group of cars on fuel blends containing up to 20% ethanol and confirmed a fuel economy loss proportional to the energy dilution effect. An average car driving 10,000 miles per year would require an extra 7 gallons of fuel, compared to one using E10. The extra cost at current pump prices works out to the $0.034/gal cited above. The loss of tax revenue is even more straightforward. Every gallon of ethanol blended into gasoline confers a $0.45/gal excise tax credit on the blender. Blend 10% ethanol and get $0.045 for every gallon of gasoline; blend 15% and receive $0.067.

The long-term success of the government's ethanol policy hinges on increasing the sales of E85 into Flexible Fuel Vehicles, not on foisting inferior mid-level blends of fuel on the public in the guise of "gasoline" without a price discount to reflect its poorer fuel economy, such as has evolved for E85 in most markets. If a soft-drink bottler or beer brewery were watering down its product, while charging the same price, the outcry would be deafening. Yet that's precisely what the government would be encouraging fuel marketers to do, by raising the blend limit. As consumers and taxpayers, we have more than a nickel per gallon at stake in this decision.

Read More

Altered Terms

While I've devoted my last two postings to the climate change aspects of the administration's first budget, some of its other provisions could also have a significant effect on our energy economy--perhaps more, considering their potential impact on a source that still contributes one-third of our total energy diet: domestic oil and gas production. The President's budget seeks to alter many of the financial parameters under which this energy is produced and processed, ultimately affecting the energy prices consumers pay. It's not even clear that these changes would result in a net revenue gain for the federal government, after all their offsetting consequences are tallied.

Let me start by stipulating that the proposed modifications, to the extent they don't breach contractual obligations, are the government's prerogative as the custodian of the public's interest in the resources and activities involved. That's certainly true in the case of oil and gas produced from public lands and the Outer Continental Shelf (OCS). All governments change tax rates and tax benefits periodically, as circumstances change, and businesses shouldn't be surprised or offended by this. (Altering the terms of existing contracts, or enacting punitive taxes to achieve the same result after the courts have upheld companies' legal rights, is a different matter.) What's at issue here is not the government's authority to make these changes, but the wisdom of its doing so, and the ultimate consequences for a nation that still relies on petroleum for 95% of the energy we use in transportation. When it proposes singling this industry out to bar it from taking the manufacturing tax deduction, or ending the expensing of intangible drilling costs, these issues can't just be viewed as isolated line items, without examining their broader implications. In several cases, the changes likely wouldn't even raise overall government revenues.

Consider a provision in the budget to impose a new annual fee on Gulf of Mexico leases not currently producing oil or gas. This is clearly an outgrowth of last summer's spurious "idle leases" debate, which arose from a fundamental misunderstanding of the mechanics of oil and gas leasing and the way that companies determine which prospects to drill first. In any case, the $115 million per year the government hopes to raise with this fee only reflects its direct revenue, without considering the lower bid premiums on new leases that would ensue.

With the exception of the enormously controversial late-1990s leases subject to royalty relief, companies have bid for OCS leases under rules that specify that after paying the bid premium, they must pay rental fees until a property is developed, after which they would owe a 1/6th royalty on any production. (Note that both parties to these contracts have significant incentives for the deals to yield substantial production, and both are harmed when they don't.) The new fee would increase costs for leases that turn out not to have sufficient quantities of hydrocarbons to merit commercial development--over and above the cost of learning that bad news--or that simply never rise to the top of a company's constantly-evolving project list before they expire. Since neither of these outcomes is unusual, the "non-producing lease" fee would become an important consideration in calculating how much to bid in the first place. Net result: decreases in new lease bids would offset the revenue from the new fee, and in the worst case we'd see a significant drop in overall oil & gas "bonus bid", rent and royalty revenue that contributed $23 billion to the federal budget last year. Most of the budget's other energy provisions entail similar risks.

It's not my intention to be naive, here. Other than their employees and stockholders, most people consider oil companies as at best a necessary evil. After another year in which many of these firms turned in more record profits--probably their last for a while--and with few other sectors looking as healthy, they make an inviting target for new taxes and fees. But whether the intention is merely to help stanch the red ink in the budget or to punish these companies for their success when everyone else was hurting, the outcome could be doubly counterproductive, reducing tax revenues by shrinking an activity we already tax pretty thoroughly. It's hard enough for companies to justify maintaining their drilling programs in a period of low energy prices, without making the fiscal terms under which they operate less attractive. How does that align with the administration's goals for energy independence, to which doubling the output of wind, solar and geothermal energy, from 1% to 2% of consumption, can only provide a partial answer?

Read More

Implicit Carbon Price

My posting last Friday on greenhouse gas cap & trade prompted some interesting reader comments and questions, one of which got me thinking about the price of carbon implied by the revenues included in the budget submitted to Congress. Estimating this required an examination of our recent greenhouse gas track record, along with some assumptions about how rapidly emissions would be reduced. The result appears to suggest that surprisingly modest CO2 permit prices in the initial period would be sufficient to generate the revenues shown in the budget.

President Obama campaigned on a pair of high-level greenhouse gas targets, to reduce emissions to 1990 levels by 2020, and to 80% below 1990 by 2050. That would entail a somewhat easier transition than the previous cap & trade legislation submitted to Congress, last year's Boxer-Lieberman-Warner bill, but a stricter long-term cap. Expressed in terms of tons of CO2-equivalent emissions per year, as of the most recent US greenhouse gas estimates from the Department of Energy, the President's goals would require a net reduction of slightly more than one billion tons per year (tpy) from 2007 levels by 2020, and a further 5 billion tpy in the subsequent 30 years. If emissions were flat between now and 2012, when the budget suggests reductions would begin, and the cuts proceeded in a linear fashion, cumulative emissions from 2012-2019 would be 54.1 billion tons, down from a baseline of 58.3 billion tons. Based on the $645.7 B in expected revenue from auctioning cap & trade permits over that period, the implied price per ton emitted works out to a surprisingly low $12/ton. Since this is well below the $20/ton that many experts expect to see initially, I took a look at my math and then my assumptions.

The biggest assumptions concern how much emissions might grow between 2007 and the start of cap & trade in 2012, and how rapidly they would be reduced subsequently. I initially assumed no growth to 2012, considering that emissions have increased at an average rate of 0.4% per year since 2000, spanning both the previous recession and the asset booms of the last few years. More realistically, I would expect 2008 emissions to reflect a drop from 2007, based on high energy prices in the first half and the effects of the recession in the second half, with 2009 emissions likely even lower. If we factored in a 5% cumulative drop through 2012, that would reduce the severity of cuts required to achieve 1990 levels by 2020, while also reducing the cumulative emissions over the 2012-2019 period, slightly increasing the effective cost per ton CO2e required to deliver the same revenue. Phasing in reductions more slowly would increase cumulative emissions and drive down the effective dollars per ton, perhaps to $11/ton. In other words, within reasonable bands of uncertainty about how emissions might change from 2007 levels before cap & trade started, and how rapidly the annual caps tightened toward achieving 1990 levels by 2020, the implied cost per ton of CO2 equivalent looks pretty modest in this period--the equivalent of roughly 1 cent per kWh for coal-generated electricity or 11 cents per gallon of gasoline.

Cap & trade still faces many hurdles, including the chance of a significantly different concept emerging from Congressional debate or a postponement due to the weak economy. However, at least in terms of the assumptions built into the budget, my back-of-the-envelope estimate indicates that it might not cause dramatic increases in energy prices in the first few years of the program, although the sums collected across the entire economy would still be material.

Read More