The Gasoline Stimulus

US gasoline prices have attracted a fair amount of attention recently, as they climbed from a national average of just over $2.00 per gallon in mid-April to $2.69 last week. Much of that increase came just before Memorial Day, which historically signals the start of the driving season and higher consumption. Some regions have even begun to see prices at $3.00 or higher. As the news media has reported on this trend, I've heard more than one reporter comment that the recent price hikes have erased the effective economic stimulus that lower gasoline prices provided earlier this year. That didn't sound quite right, considering how much higher prices were last summer, but it wasn't until I looked at the actual data that I realized the stimulus has actually grown in the last month or so, not shrunk. However, unless oil prices are headed for an even bigger collapse than they experienced last fall, this stimulus must be short-lived. It will probably end entirely by November.

The aspect of economic stimulus I'm considering here results from the year-on-year comparison of average US gasoline prices. As the graph below shows, since slumping oil prices drove the pump price of gasoline below its level of a year earlier, starting last October, US unleaded regular has averaged $1.25/gal. cheaper than in the same week a year earlier. Even with gasoline demand down by around 3%, that equated to an injection of roughly $170 billion after-tax dollars per year into consumers' pockets. Despite the recent increase in prices at the pump, that year-on-year gap has grown, averaging $1.41/gal. since Memorial Day. For the average household, which owns two-plus cars and drives nearly 25,000 miles per year, that has reduced monthly expense budgets by around $120, compared to 2008. This has surely come in handy, as unemployment grew and we all waited for the federal government's $787 billion stimulus to ramp up.

Unfortunately, by the same definition I've used above this gasoline stimulus has a time limit, because it is essentially a mirror image of last year's pricing trends. The effect is widening just now, as we approach the anniversary of the all-time peak of oil prices of $145 per barrel on July 14, and the all-time high US gasoline price of $4.11/gal. that accompanied it. However, once we pass that point the normal seasonal weakening of the gasoline market would be hard-pressed to echo the slide that took oil prices all the way down to a more than four-year low under $34 by year-end 2008. While gas prices should retreat closer to $2/gal. again by fall, they're unlikely to go lower, ending the 2009 vs. 2008 pump-price gap.

As the economy recovers, we should expect prices to trend back up, independent of the eventual increase we can expect from the climate bill the House of Representatives passed last Friday--assuming the Senate ultimately passes a bill similar enough to the House version of cap & trade to be reconciled and become law. That means that future fuel prices are likelier to be a drag on the economy than a boost. Anyone putting off a road trip this summer due to "high gas prices" should perform a quick reality check on whether they are ever again likely to be much lower at this time of year.

A Funny Thing Happened on the Way To Cap and Trade

How much of an unappetizing jumble can you put into a dog's breakfast, before the dog refuses to eat it? That is the question that the authors of the Waxman-Markey "climate bill" appear intent on testing, before it goes to an expected vote of the entire House of Representatives tomorrow. Aside from addressing truly momentous, economy-altering matters--a cap & trade system for greenhouse gas emissions and a national renewable electricity standard to promote green power even more than cap & trade would, anyway--this bill includes more than its share of tenuously-related add-ons, some of which might be nearly as significant as the provisions that have garnered the headlines. Nor has last week's Congressional Budget Office analysis settled all the questions about the bill's likely cost to the public, except to raise suspicions that if it truly amounted to only $175 per household per year, there wouldn't be so much fuss about it.

Let's start with those costs, before we come back to the miscellaneous provisions that begin on page 808 of 1092. The CBO examined the cap & trade provisions of Waxman-Markey and its issuance of free emissions permits to various sectors and groups. They then allocated the costs among all American households by quintile of income. That's an important detail, because of the bill's provisions for rebates and other assistance to lower-income families, the lowest-earning of which would actually come out ahead in their analysis. For the rest of us, I believe the key figures to focus on are not the estimated $235-340 per year "net cost", but the range of $555-1,380 per year in expected "gross costs" before "direct relief to households"--which if you read the bill doesn't look very direct at all. It consists mainly of those free emissions permit allocations that go to utilities and various other industries and groups, not consumers.

The other aspect of the CBO analysis to focus on is its assumptions, explicit and implicit. The key explicit one is the emissions permit price of $28/ton of CO2 from which these costs were derived. While it's certainly possible that permit prices might be that low in 2020--the equivalent of $0.25 on a gallon of gasoline or roughly $0.03/kWh on coal-fired electricity--in the long run they would likely rise much higher, in order to cover the cost of deeper, more difficult reductions in industrial and transportation emissions. The CBO's big, implicit assumption relates to the impact of cap & trade on the economy as a whole, which footnote 3 indicates is excluded, along with the impact of the bill's many other provisions. If cap & trade slows growth, as seems very likely, incomes would be lower and jobs less plentiful than otherwise--even if "green jobs" grew--and other taxes would need to increase to service the debt and cover growing entitlement costs. When you factor in these uncertainties, the probability that cap & trade would cost American families no more than a couple of hundred bucks a year looks low.

The other day I described the severe mismatch between actual US emissions and the sectors chosen in Waxman-Markey to receive the lion's share of free emission permits. The bill would also establish an "Emission Allowance Rebate Program" to help energy-intensive industries engaged in international trade. Remarkably, however, it states, "The petroleum refining sector shall not be an eligible industrial sector." So US refineries, which under this bill would be responsible for both their own emissions and those from the subsequent use of their products--in our cars, for example--could not seek relief for the permit costs associated with products they export to the Caribbean and other markets, while other industries could. That would hamper not only refinery profitability, but also their ability to produce a suitable mix of products for domestic consumption. Last year US refineries exported 1.8 million barrels per day of products to balance their operations and meet stringent US fuel specifications. Raising the cost of those exports would ultimately result in fewer US refineries and more petroleum product imports. That would make US fuel prices more volatile, while increasing the average Waxman-Markey premium at the pump, over and above the direct cost of emissions permits.

Now let's consider what else has been included in this bill. Among the surprises I found in its last few hundred pages was another $4 billion of funding for the cash-for-clunkers program I discussed last Friday, along with its extension until next April 1st. Another provision would give the Secretary of Transportation broad powers under an "Open Fuel Standard" to require auto makers to produce large volumes of flexible fuel vehicles--a key enabler for increasing the country's biofuel production above the amount that can safely be blended into ordinary gasoline. According to yesterday's Washington Post, it would also establish and fund a new multi-billion-dollar federal agency, the Clean Energy Deployment Administration, in apparent competition with the Department of Energy.

Moving further afield, Waxman-Markey would also impose sweeping new rules on energy commodity markets to allow the Commodity Futures Trading Commission to regulate derivatives and swaps and limit speculation. The CFTC would decide what constituted a "bona fide hedge" and what didn't, setting limits on how many contracts a non-hedging entity could hold--not just in the US but also on foreign exchanges dealing with US-based commodities. It would also control energy commodity speculation by index funds. And while these measures at least have a connection to energy, that certainly does not hold for Section 355, which would place strict limits on who could buy a credit default swap, and under what circumstances.

I hope you haven't concluded from the above that I am a wide-eyed idealist who is easily shocked by the way the world really works. This is not a case of liking an idea only in its most abstract form. Although I have long supported cap & trade as the best approach for reducing emissions, I always expected a certain amount of horse-trading to get there--and note that the Senate has yet to weigh in on this bill. Unfortunately, the central cap & trade provisions of Waxman-Markey have been sufficiently distorted to cast serious doubt on their likely efficacy in managing our actual emissions, while issues as important as the regulation of energy markets and credit default swaps surely warrant separate legislation that would expose these proposals to the scrutiny and transparency they deserve. This might be the way laws are made these days, but the insertion of a grab-bag of disparate provisions into a bill of this magnitude represents an act of legislative mischief. In the context of the similar process that shaped last year's version of cap & trade, the Boxer-Lieberman-Warner Bill, I have begun to wonder if it's even possible for cap & trade to be implemented effectively under our political system, or whether a simpler carbon tax might be less prone to this sort of excessive creativity.

Sustainable Energy

I just ran a quick search on Google Trends to check my hunch that the phrase "sustainable energy" has become a lot more common, lately. That seems to be the case, at least based on the volume of news references tracked by Google. While I would regard a greater focus on sustainability as a positive development, I'm much less comfortable with its indiscriminate use as a synonym for "renewable". It's dangerously simplistic to think that the only parameters of sustainability that matter for a given energy technology are the extent of the energy supply it taps and the greenhouse gas emissions associated with its use. However understandable that might be in light of concerns about climate change and energy security, the complexities it obscures could ultimately prove just as limiting, in their own way, as the depletion of finite reserves of fossil fuels or the response of the global climate to increasing concentrations of carbon dioxide in the atmosphere.

Sustainable energy means different things to different people, as even a Wikipedia definition that points mainly to standard renewables admits. All too often, though, these definitions focus on the consumption of fossil energy sources and their accompanying emissions, while ignoring the use of other scarce resources, particularly water. In a recent posting I highlighted the high water consumption associated with the production of corn ethanol, a fuel widely regarded as more or less infinitely renewable, and thus much more sustainable than the oil it is intended to displace. Ironically, petroleum production and refining on average consume far less water per gallon or BTU of marketed fuel than most biofuels. The production of biofuels from non-food sources requiring little or no irrigation would alter that comparison, but still might not close this gap.

Biofuels aren't the only components of our energy mix that use lots of water. Electricity generation also consumes huge quantities, though much of it is returned downstream without degradation. Most thermal power plants use water for cooling and steam generation. That includes both fossil and nuclear power plants. Some renewable energy sources are also subject to this constraint, including solar thermal power, as noted in a recent Washington Post article. Enhanced geothermal power, which has great potential as a low-emission energy source, requires the injection of large volumes of water underground to create artificial hydrothermal reservoirs, and to transfer heat to the surface for power generation. In fact, at least 80% of the electricity generated in the US last year involved the use of water to some degree, a dependency that attracted critical attention during the Southeast drought in 2007.

Water is hardly the only input that should be considered in a broader view of sustainable energy. The consumption of rare earths and scarce metals in the production of thin-film solar panels, advanced batteries, wind turbine generators, and other aspects of the developing green-energy economy is starting to worry some experts. While I haven't delved into it in much detail, I'd be surprised if these factors proved limiting in the near term. After all, the technologies in question have only been around for a few years, so there hasn't been much time for the sources of these exotic ingredients to ramp up to support their growing demand. This scaling issue cuts both ways, however. For example, if solar energy is to expand from its present contribution of less than 1% of renewable power generated here last year to, say, 10% of our total power supply, the use of an ingredient in proportions as small as a hundred grams per kilowatt of capacity would translate into a cumulative requirement for tens of thousands of tons. If the substance in question was the Tellurium used in Cadmium-telluride solar cells, its global output would have to expand by at least 10X within a decade or two. That might not be possible, or at least economically feasible.

The point here is not to suggest that we're stuck in some depressing dynamic in which we encounter bottlenecks and unintended consequences in every direction we turn, as we seek alternatives to conventional energy. Instead, we need to remember that oil, gas and coal aren't the only finite substances in the earth's crust. We must consider all our energy options in terms of trade-offs, and not just with regard to the aesthetics of wind farms and solar panels in our back yards vs. oil derricks and central power plants in someone else's. The choices we are making demand a thorough look at their lifecycle impacts, including all the inputs and outputs along the way. That won't be easy, and it clearly will not be convenient for those sectors that have benefited from an overly narrow view of this issue, such as the interests that are supporting legislation to block the EPA from factoring in the effect of global land-use changes in the agency's lifecycle assessment of corn ethanol.

This broader view of sustainable energy is another reason to moderate our faddish focus on all things renewable, as I noted recently when I argued that we need a low-emission electricity standard, instead of a renewable electricity standard. Tackling climate change effectively will require clear goals that address outcomes, rather than preconceived notions about pathways. And when it comes to energy security, we need a framework that recognizes that oil in tankers is not the only energy-sector import that bears watching.

Cash for Guzzlers Enacted

Yesterday the Senate passed this year's war funding bill, to which had been added the "cash for gas guzzlers" provisions that I described in early May. The bill should be signed by President Obama shortly and become law, just in time to help car dealers--including some who are losing their GM or Chrysler franchises--clear out the backlog of new cars that has accumulated during this protracted period of slow sales. The final version of this measure importantly requires that the "clunkers" traded in be scrapped, so that they don't end up consuming fuel and emitting pollutants somewhere else. While it is overly generous to new pickups and SUVs that would use only slightly less fuel than their predecessors, its minimum threshold of a 4 mpg improvement for passenger cars, or 10 mpg to qualify for the full $4,500 benefit, should still result in meaningful levels of avoided fuel consumption, while helping to compensate for the expiration of tax credits for many popular hybrid vehicles.

Every excursion I make into the details of energy-related legislation feels like a civics lesson. Cash-for-guzzlers took a lot of flak during its comparatively brief trip through the Congress, with the Wall St. Journal referring to it as "Cash from Lunkheads" and two prominent Senators penning an op-ed criticizing it roundly as "Handouts for Hummers". It probably couldn't have passed as a separate bill, and it just squeaked into the war funding bill in the Senate. It took a bit of scouting to track down its details, which appear as Title XIII of HR-2346, the "Supplemental Appropriations Act, 2009", carrying the vague description of "Consumer Assistance to Recycle and Save Program". While it clearly could have been better, from my perspective it's hardly the worst piece of energy legislation to come out of this Congress, considering that for the average motorist moving up from an 18 mpg car to one getting at least 28 mpg would save as much gas as a 50 mpg Prius consumes in total. Here are the basic rules, as I read them:

• The car traded in must be no more than 25 years old, in drivable condition and certified at 18 mpg or less in EPA "combined fuel economy". (15 mpg for a typical SUV/light truck.)
• It must have been insured and registered to the owner for at least one year prior to trade-in.
• It must be shredded or crushed, though not before the auto recycler sells off any desirable parts.
• The new vehicle must get at least 22 mpg (15 mpg SUV/light truck) and
• at least 4 mpg more than the trade-in (1 mpg SUV/light truck) to qualify for a $3,500 tax-free voucher, or
• at least 10 mpg more (2 mpg SUV/light truck) to qualify for the maximum $4,500 tax-free voucher.
• It can't cost over $45,000.

If you are in any doubt as to whether your present ride qualifies as a guzzler, the Detroit News has provided this handy search tool.

Whatever its merits as energy policy, in some respects the cash-for-guzzlers program looks like a clever insurance policy for the government's investment in GM and Chrysler, which will only achieve its intended goals if these companies can survive the recession and live on to produce the efficient cars the administration targeted with its new CAFE standard. That requires selling millions more of the current models, which only conform to the current, lower standard of 27.5 mpg for passenger cars and 23.1 mpg for SUVs and light trucks. And while the legislation doesn't require qualifying new cars to be American or even American-made--that would have run afoul of WTO rules--the Detroit 3 stand to benefit disproportionately, given the generous benefits for the large vehicles that dominate their current mix. The program only runs from July 1 through November 1, 2009 and is funded at $1 billion, enough for around 250,000 cars. If you intend to take advantage of it, I wouldn't wait too long.

Food vs. Fuel and Ethanol Bankruptcies

A couple of weeks ago an editorial in the Wall St. Journal called attention to a study by the Congressional Budget Office entitled, "The Impact of Ethanol Use on Food Prices and Greenhouse Gas Emissions." I finally found time to read the report and was surprised that, in addition to its main topic, it provides a useful analysis of the economics of ethanol manufacturing. Application of the CBO's rule of thumb correlating ethanol profitability to gasoline and corn prices goes a long way toward explaining the dismal current state of the industry, which has experienced a long string of bankruptcies in the last year--enough to warrant an entire conference devoted to that topic. The underlying dynamic in the ethanol sector turns out to be quite similar to one that has taught the oil refining industry some painful lessons in the last couple of decades. Potential investors in ethanol plants, conventional or even cellulosic, would do well to consider this relationship.

The CBO study's headline findings merit more attention than they have received in the media, considering the intensity of the food vs. fuel controversy this time last year. We truly have the attention spans of ferrets, these days. The CBO examined the effect of rapidly rising ethanol production on the supply and demand for corn in all its uses, along with the relationship between corn prices and broader food prices, and the impact of energy prices on both. They concluded that between April 2007 and April 2008, ethanol accounted for 10-15% of the increase in food prices in that period. Even considering only the resulting increase in the cost of federal food assistance programs, that added an extra $600-900 million to the roughly $4.6 billion in direct ethanol blending subsidies paid out by the federal government last year. The Journal estimated the additional cost to consumers at between $5.5 and $8.8 billion. If you add those figures together and divide by the 9 billion gallons of ethanol produced in US distilleries in 2008, the hidden cost of every gallon of ethanol that comes out of a gasoline dispenser averages around $1.40.

Even more remarkably, despite this sizable "externality" and the truly extraordinary five-year growth run of the industry, ethanol processing appears to be a miserable, wealth-destroying business for its owners. The CBO report explains this in a text box starting on page 4, which concludes that unless the retail price of gasoline exceeds 90% of the price of corn before factoring in ethanol subsidies, or 70% after subsidies, an ethanol plant cannot cover its fixed and variable costs and turn a profit. The box includes a chart showing the precipitous decline of that ratio since 2005, from a high above 1.0 to below 0.6. When I calculated the current ratio based on this week's average retail gasoline price and yesterday's Chicago Board of Trade prompt corn contract, I came up with a figure of 0.65. That's still below breakeven, despite the recent spike in gasoline prices.

While I've never looked at it quite this way before, the CBO's rule of thumb makes perfect sense as an example of how capacity investments tend to destroy the margins that justified those investments. It's much the same as when an oil refiner sees high prices for gasoline and low prices for residual fuel and decides to invest in a new coking unit to convert the latter into the former. When the unit starts up, it increases the supply of gasoline and raises the demand for feedstock, squeezing its own operating margin from both ends--along with the margins of everyone else in the industry. In the case of the dozen or so ethanol companies that have gone into Chapter 11 or de-facto Chapter 7 lately, we must conclude that a lot of their expected profits never materialized, either, for a similar reason. All those new ethanol plants increased the supply of "gasoline" while simultaneously increasing the demand for their feedstock, corn.

US corn ethanol output is still expected to expand by another 50% or so before it bumps into the artificial ceiling the Congress and the EPA set for it in the revised Renewable Fuel Standard. Yet this is an industry that has raised food prices, destroyed billions of dollars in shareholder value, and according to the CBO reduced US greenhouse gas emissions by only about 0.2%, even if we ignore offsetting global land-use changes. The best thing that can be said for it is that it displaces around 420,000 barrels per day of mostly imported petroleum-based gasoline. That's hardly trivial, but I leave it to you to assess whether it has been worth the cost.

Iran's Election

Oil markets seem unfazed by the unrest in Iran, in the aftermath of that country's Presidential election. Mahmoud Ahmadinejad and Iran's Supreme Leader, the Ayatollah Khamenei, remain firmly in control, and there's no reason to expect that the ongoing demonstrations against perceived election fraud constitute a threat to Iranian oil exports. In that respect, the markets have it right. However, the conduct of the election--more than its outcome--may have altered the calculations of the nations determined to constrain Iran's nuclear ambitions, and may have inadvertently nudged Israel a step closer to acting on its own, should diplomatic efforts to halt nuclear enrichment remain stymied. But even a preemptive attack on Iran's nuclear complex might only result in a brief spike in oil prices, at least in the short run, because the fundamentals look so different than just a year ago.

The disappointment of the supporters of Mir Housein Mousavi and the other opposition candidates is palpable. We may never know whether they were cheated or merely out-polled, as some observers have suggested. If the latter view is correct, then the government was doubly inept in its handling of the situation, leaping to proclaim Mr. Ahmadinejad the resounding winner and cutting off access to the outside world, thus creating at least the strong appearance of a stolen election--a virtual coup, as some have called it. This appearance of illegitimacy, accurate or not, could haunt the government and strengthen the resolve of the "EU-3" countries leading the nuclear talks with Iran. It could also make Israel's new government even more determined that such a nation should never attain nuclear weapons, at any cost.

As described in an op-ed in the Wall St. Journal last week, air strikes by Israel on Iran's nuclear facilities could result in all sorts of adverse consequences, though this might still be seen as the least bad option should Iran remain adamant in pursuing its nuclear program. Iran's leaders proclaim their peaceful intent, an argument that resonates with the non-aligned nations and their sympathizers. However, nothing has changed the conclusion that I reached when I examined this subject in depth in 2005: the likeliest explanation for Iran's behavior and for the existence of its visible nuclear program in a country so blessed with other energy resources is that it intends to develop nuclear weapons. Even the risk of alienating Iran's moderates and uniting the country behind the hard-liners looks like less of a deterrent, if those moderates will never be allowed to win an election.

During most of the Bush administration, Iran's nuclear efforts were effectively shielded by its implicit threat to destabilize the global oil market. As I noted last fall, that was a trump card, until the global recession slashed demand, and oil inventories and spare production capacity began to accumulate. We shouldn't be fooled by the current price of oil, in this regard. It's where it is not because supply is physically constrained, as it was for much of 2007 and into 2008, but because OPEC's discipline is holding 3.25 million barrels per day off the market, according to a recent IEA assessment. That quantity is roughly 50% larger than Iran's exports. Saudi Arabia alone could cover any shortfall from Iran, particularly once its new Khurais field starts up. While many of OPEC's big producers are hardly models of democracy themselves, the perception of an illegitimate regime in Tehran would lend them significant political cover to open their taps, if the need arose.

Timing is everything, and Iran's oil weapon has been neutralized, for now; any threat of an embargo would ring hollow. The longer-term outlook is less certain. Once a global economic recovery is well under way, growing oil demand and the decline of mature fields in other producing regions will erode the current global oil capacity cushion and restore Iran's leverage. Time is now on Iran's side, and its adversaries are likely to understand that very well. Don't be surprised if the pressure on Iran ratchets up in the weeks and months ahead, before this window closes.

Toward a Low-Emission Electricity Standard

McDermott International, Inc. announced yesterday that its Babcock & Wilcox subsidiary will begin marketing a 125 MW small-scale nuclear power plant design. Their press release also indicated that the company has a letter of intent from the Tennessee Valley Authority and a group of municipal utilities to use this technology. This development looks particularly interesting in the context of the debate over the proposed national Renewable Electricity Standard (RES) in the Waxman-Markey Bill, along with another version of an RES in a new bill from the Senate Energy & Natural Resources Committee. However, if we really want to address climate change on a meaningful scale, then both bills should focus not on renewable electricity but on low-emission electricity.

When I looked at the proposed RES a month ago, I was frustrated by its narrow list of included technologies, and in particular by the way it excluded our largest current renewable electricity source, existing hydropower installations. Nuclear power wasn't even mentioned. Since that posting, the RES target in Waxman-Markey was revised downward, and nuclear power has apparently been included in an odd, backhand way. If I understand it correctly, an electricity supplier’s “base amount” on which the RES would apply would shrink as it brought on new nuclear capacity. While that might alleviate a small part of the financial burden of investing up to $10 billion in a new nuclear power plant by requiring the generating company to build somewhat less renewable capacity, in order to comply with its RES target, this seems a paltry incentive for our largest low-emission energy source by far—a status nuclear seems likely to enjoy for many more years.

So how would small reactors fit into this equation? Mainly by reducing the sheer scale of investment required to bring new nuclear capacity online, and presumably by making nuclear project timelines more manageable by replacing much of the time-consuming onsite construction activity with more efficient offsite manufacturing. So even under Waxman-Markey, a utility would benefit from small nuclear that arrived in increments every year or two, instead of having to wait a decade or more for a new large-scale plant to be approved, funded and built—all the while having to add a larger quantity of wind, solar or other “qualified” renewable power.

Of course, if the Congress saw fit to reconfigure the RES as a low-emission standard, or LES, including all low-greenhouse-gas technologies on an even playing field, a small nuclear reactor might look especially attractive. Assuming that the 125 MW version could be run as reliably as its 10X-larger cousins—and a half-century of nuclear naval propulsion argues that case pretty effectively—then a mini-nuke such as McDermott’s “mPower” reactor would provide as many annual kilowatt-hours of generation as a 400 MW onshore wind farm or a 500 MW solar installation in a sunny location, while doing so more predictably and dependably, and for a similar investment cost. Nor is McDermott the only company with a horse in this race. Veteran nuclear vendors such as GE-Hitachi and Toshiba-Westinghouse are pursuing small-scale reactors, and Hyperion, a start-up out of Los Alamos National Laboratory, has designed a 25 MW plant. There’s even a regular reader of this blog with his own small-nuclear start-up.

So when you see those full-page ads from the American Wind Energy Association promoting “Global Wind Day” next Monday and exhorting you to support a strong Renewable Electricity Standard, remember that wind is only one of a number of energy options we can deploy against global warming, and that the renewable energy distinction ought to matter much less than low emissions, regardless of the source.

Is Oil Shock 2.5 Imminent?

The rebound of oil prices has been getting a good deal of attention, lately, though we haven't yet reached the point at which, like much of last year, the daily closing price of WTI is reported on every evening news broadcast. I've even seen the dreaded "s-word" bandied about, implying that oil might have become disconnected from its fundamentals in ways that ought to worry those responsible for ensuring that the nascent economic recovery is not extinguished before it can gather momentum. Such fears look premature at this stage. Despite reaching $70 per barrel during last Friday's session--an increase of 107% from its post-crash lows last December--crude remains far below its highs of 2008 and currently trades at a level it first reached in spring 2006. Nor does it seem likely that US demand would support a return to $4 gasoline, which helped alter consumer behavior in ways that set the stage for oil's precipitous collapse and could do so again.

To understand current pricing, we have to pull apart the threads affecting supply and demand. On the supply side, the dampening effect of high oil inventories is offset by worries that high decline rates from mature fields and deferred and canceled production projects are setting the stage for a repeat of the capacity crunch of 2004-7 as soon as global demand growth resumes. Last week's Economist did a fine job explaining how each oil bust contains the seeds of the next boom, and why that cycle could be even shorter this time around. And in a recent "Heard on the Street" column, the Wall Street Journal's Liam Denning provided some insightful analysis on how traders playing the spread between short- and long-dated oil futures can translate higher prices for the out-year contracts into a boost for near-term prices. (He also questions the sustainability of China's recent oil import spike.) But if current oil prices are being dragged up by concerns about future supply--abetted by inflation fears and the recent weakness of the dollar--weak demand and its demonstrated elasticity should forestall an imminent return to last year's peak.

In recent weeks US gasoline demand has rebounded close to last spring's level. Driving season still matters, it seems, and we've seen pump prices respond accordingly. This reflects more than just the recent strength in crude oil. The NYMEX "gas crack", the spread between prompt gasoline and crude oil futures, averaged $2/bbl higher in April and May than in February and March, at the same time crude oil added $30/bbl. However, this strength is merely relative. US gasoline demand in the first quarter of 2009 was the lowest for that period since 2003, and that's before taking into account the approximately 175,000 bbl/day of demand--around 2%--met by higher mandated ethanol blending, after adjusting for energy content. Moreover, demand for distillate fuels--diesel and heating oil--is off even more than for gasoline. This isn't just a US phenomenon, either. The International Energy Agency sees global oil demand down by 2.6 million bbl/day, or 3%, vs. last year. That's no one's idea of a surge.

When we sum up all these developments, we see a very different dynamic than the one that took oil prices to the brink of $150/bbl. Then, demand seemed insatiable, and the capacity crunch was a measurable reality, not just a future prospect. Today, oil supply and demand and the global economy are linked in a set of counter-acting feedback loops. Higher petroleum product prices put greater pressure on price-sensitive consumers, whose ranks have been swelled by the recession. Even countries that insulate their consumers from the global oil market may have to adjust if prices edge closer to $100/bbl. So while higher oil prices could threaten economic growth, the demand response to higher prices--and any hesitation in expected growth--seem just as likely to stall oil's momentum and send it lower. This is a delicate balance, and it could be upset by many factors, including a sudden change in the value of a key currency, or an unanticipated supply disruption. Only time will tell whether, just as Oil Shock 1.0 (the Arab Oil Embargo) was followed a few years later by Oil Shock 1.5 (the Iranian Revolution), last year's Oil Shock 2.0 will soon be followed by version 2.5, or give way to entirely new scenario.

Shale Gas and Climate Change

In Wednesday's posting on the likely consequences of the latest version of greenhouse gas (GHG) cap & trade legislation, I hinted at an important option for electricity suppliers to reduce their emissions promptly. Today I'd like to elaborate on it. Although the power sector accounts for the largest share of US GHGs, its existing generating fleet already has the potential to reduce those emissions substantially by relying less on coal-burning plants and more on those that burn natural gas. That could be done with little or no new investment, at least on the part of generating companies. This isn't exactly a new idea, but what makes it feasible now--when it wouldn't have been not so long ago--is the development of enormous new US natural gas resources found in shale deposits such as the Barnett, Haynesville and Marcellus shales. Twice in just the last week I have seen shale gas referred to as a "game changer", without the least hint of exaggeration.

Capitalizing on shale gas to take a big bite out of US GHG emissions would depend on two key facts: First, gas-fired power plants emit on average 37% less CO2 than coal-fired plants. At the same time, although the US generated more than twice as much electricity from coal as from gas last year, we actually have more gas-fired generating capacity than coal-fired. The former is merely utilized less--an average of 25% of the time, compared to 73% for coal--for reasons that made perfect sense in a world in which CO2 emissions didn't matter. If we doubled our utilization of existing gas-fired power plants and burned correspondingly less coal, the country would emit roughly 330 million fewer tons of CO2 per year, representing about 13% of the emissions from the power sector, or a reduction of a bit more than 5% of all US net emissions. And that's probably a conservative estimate, since the best combined-cycle gas turbine power plants emit less than half the CO2 per kWh of the oldest, least efficient coal-fired plants.

There are two principal reasons we aren't doing this already. The simplest is that coal has generally been much cheaper than gas on a fuel cost per kWh basis. However, the recent drop in gas prices has already put significant pressure on coal prices. At $4 per million BTUs, even at an unspectacular turbine heat rate of 8,500 BTU/kWh, the marginal fuel cost of gas-fired power is only 3.4 cents/kWh. But $4 gas may not be sustainable, since shale deposits are not exactly low-cost sources. The current long-dated gas futures price of roughly $7/MMBTU reflects that. In order for gas to displace large quantities of coal, it would probably take both stable gas prices higher than today's plus the kind of CO2 pricing envisioned under cap & trade--provided the utility sector isn't entirely insulated from this by excessive free emissions permit allocations.

Another reason for the current fuel mix is that most coal-fired power plants were built to run in baseload mode at high utilization rates, while many gas turbines were built to run intermittently to cover mid-peak and peak power demand. They probably couldn't all run at an 80-90% utilization rate, though we wouldn't need them to. They're also not evenly distributed around the country. California has lots of gas turbines, because that's pretty much all you could build there since the 1970s. That's not true everywhere. However, probably the biggest limitation has been concerns about the long-term availability of gas. Power generation already consumes 29% of the US gas supply, which in 2008 was about 87% domestic and 13% net imports, mostly from Canada. Until recently, any incremental demand would have been expected to be met mainly from imported LNG, at a higher price than domestic gas, or by destruction of existing demand in other sectors, such as chemicals. Abundant shale gas has altered that outlook, while putting downward pressure on LNG prices, as well.

In some respects, this is all somewhat "back to the future"; a decade ago it was widely assumed that natural gas would play a pivotal role in reducing our emissions. That notion went partly out of fashion, as gas prices climbed and environmentalists focused more on the lower emissions from wind and solar power, which despite their rapid growth still generated only 1/16th as much power as gas last year. The potential of shale and other "unconventional" resources makes gas once again a viable medium-term strategy for mitigating climate change, with a few caveats. I recall seeing similarly exuberant forecasts of gas supplies in the late 1990s, just before conventional onshore production nosedived and prices spiked. Shale gas looks more sustainable, but it depends on lots of well-capitalized companies drilling like crazy and earning enough from that to keep on drilling. If the economics don't hold up, most of that gas will stay underground. It also depends on drilling techniques that have suddenly become controversial, as noted on API's new blog. Preserving this option for reducing GHG emissions will require Congress and regulators to stay focused on the big picture.

A De Facto Gasoline Tax?

Between various consulting projects and a spot of vacation, I've struggled to keep up with the evolution of the Waxman-Markey climate change bill, officially H.R. 2454, the "American Clean Energy and Security Act of 2009". Reading through the bill's 932 pages was out of the question, though I hope to find time for at least a thorough skim once it gets closer to a House vote, perhaps later this summer. But while it contains many important measures, including a proposed national renewable electricity mandate, the core of the bill is its cap & trade provisions, and at the heart of those is its method for distributing emissions allocations and offsets, which I have just reviewed. The House Energy and Commerce Committee moved very far, indeed, from President Obama's ideal of a bill based on auctioning 100% of those allowances. That's probably a good thing, as I noted recently. However, the implications of the committee's choices for allocating those allowances are not so good. They heavily favor the electricity sector, largely at the expense of transportation. This flies in the face of the actual contributions to US greenhouse gas emissions from these sectors, and of their relative degrees of freedom for reducing emissions in the near future.

To understand how this version of cap & trade would work, you need to envision how its three strands would mesh. Total US emissions would be capped at a level that declines each year, beginning at 97% of 2005's emissions in 2012 and shrinking to 83% of 2005 in 2020, 58% in 2030, and a skimpy 17% in 2050. (The feasibility of actually achieving such reductions is a topic for another day.) In each of those years, emitters would have three choices for meeting these restrictions: They could physically reduce their emissions by investing in efficiency, changing their energy sources, or simply consuming or producing less; they could apply emissions permits received from the government or purchased at federal auction or from someone else with permits surplus to their requirements; or they could acquire emissions offsets from forestry and other qualifying activities, domestically or internationally.

Now, because greenhouse gases, once emitted, are entirely fungible, or equivalent in their impact on climate change, you might expect that once the Congress determined the total proportion of permits to allocate (for free) to current emitters, they might be distributed more or less evenly, so that all emitters would be in roughly the same position of needing to cut GHGs or buy extra permits or offsets. Instead, the Committee established an initial allocation to the electric power sector of 44% in 2012, declining gradually to 39% by 2025 and then rapidly phasing out between 2026-30. This allocation comes with the intent that electricity providers pass on the value of these allowances to consumers, presumably canceling out the cost of reductions or purchased permits required to meet the shrinking annual emissions caps. What makes this choice so bizarre is that the electricity sector accounts for the largest single block of US emissions: 41% in the Department of Energy's "flash" estimate of 2008 emissions, which incidentally showed a 2.8% drop in US emissions for the year.

Other stationary emissions sources also get a sizable free allocation, including 9% to natural gas distribution companies for the benefit of consumers, and 1.9% to home heating oil and propane users. Other allowances are assigned to encourage investments in energy efficiency and renewable energy, clean vehicle technology, and carbon capture and sequestration, or to protect trade-sensitive industries and support various causes, leaving an unspecified quantity for deficit reduction between 2012 and 2025. In fact, when you compare the allocations to our actual emissions, the single most exposed sector after permits are handed out is transportation fuels, which despite accounting for 33% of energy-related GHG emissions, are assigned only 2% of the free permits.

Now, I can hear all sorts of compelling justifications for this, ranging from the profitability of the oil industry, the need to encourage consumers to buy more efficient cars, and the promotion of energy security--though the bill appears to make no distinction between domestic petroleum sources that enhance energy security and imports that diminish it. But whatever the rationale, even if it simply boils down to more effective lobbying by utilities and other emitting sectors, the present version of cap & trade legislation would impose the heaviest burden on transportation fuel producers and consumers. Unlike their counterparts in electricity generation and power and natural gas distribution, petroleum producers, refiners and importers will have to pay for essentially all the permits and offsets they will need to meet their emissions targets, and the cost will be passed on to those who use their products. In other words, after you sift through all its complexity, Waxman-Markey's cap & trade system becomes in essence a targeted tax on gasoline, diesel and jet fuel.

The problem is that if the main driver here is climate change, and we really want big emissions reductions as soon as possible, this approach won't deliver that outcome. Utilities have more and better choices for producing low-emission power in the next decade or two, particularly with natural gas becoming cheap and abundant again, than refiners do for reducing the emissions of motor fuels or consumers and businesses for reducing the emissions from a car fleet, the turnover of which has been slowed by the recession and could be further impeded by the new CAFE regulations. In other words, actual emissions reductions look harder--and costlier--to achieve from transportation than from stationary sources, and Waxman-Markey would dole out free permits in a manner 180 degrees out of sync with that reality.

I have supported the idea of establishing a price for GHG emissions through cap and trade since long before I started writing this blog, but I must say I'm dismayed by the distorted version that has emerged from the Energy and Commerce Committee. If all they really wanted to do was tax petroleum products more heavily--and there are solid arguments in favor of that--then they could have done so without creating anything like the impenetrable bureaucratic intricacy that this bill would bequeath us. Unfortunately, Congressional action on emissions has become entangled by the overlapping but hardly congruent imperatives of energy security and climate change and the innate desire to shield consumers (voters) from anything that looks like a direct tax. What are the chances the Senate will strip out much of the bill's complexity and favoritism and deliver a simpler, cleaner (in all senses) piece of legislation?

Reliving Bankruptcy

As GM files for bankruptcy today, I can't help thinking about my own experience with corporate bankruptcy 22 years ago. The Chapter 11 filing of Texaco, Inc. in 1987 still ranks among the top five non-financial corporate bankruptcies in the US. After adjusting for inflation and the likely discount on GM's stated asset value they seem roughly comparable in scale. Although the causes were quite different--seeking relief from a crippling court judgment in one case, and the collapse of sales and cash flow on the other--the outcomes of Texaco's bankruptcy might provide some useful insights into what could lie ahead for GM.

This morning's Wall St. Journal included an example of the numerous recent articles speculating on the shape of a New GM that might emerge from bankruptcy this summer. Some of the elements are already evident: the sale of 65% of Opel and Vauxhall in Europe, along with the previously-announced decision to eliminate the Pontiac brand and sell or eliminate Saturn, Hummer and Saab. The new GM will be smaller and presumably leaner. That was true for Texaco, as well, which made a similar choice to sell mature assets in favor of retaining its growth platform in Asia-Pacific, in order to raise the cash to pay the $3 billion settlement with Pennzoil that allowed it to emerge from Chapter 11. So Texaco sold its German and Canadian operations, along with a 50% interest in its US refining and marketing business in the eastern half of the US. The latter formed the Star Enterprise joint venture with Saudi Aramco that later evolved into Motiva Enterprises LLC after a subsequent JV with Shell.

Even during bankruptcy, Texaco became leaner and nimbler. Corporate management was preoccupied with legal concerns, so local managers were empowered in ways that would never have been possible in the old, highly-centralized corporate culture. The company that ultimately emerged from Chapter 11 was lighter on its feet, more competitive, and less bureaucratic and paternalistic. It was also fatally flawed, in ways that took many years to manifest and that the architects of the future GM might do well to consider carefully.

The first problem was scale. Overnight, Texaco went from rough parity with its historical peers--other than Exxon, which was a giant, even then--to a sort of in-between status: much bigger than the second-tier integrated oil companies such as ARCO, Marathon, Conoco, and Phillips, but notably smaller than Shell, BP and Chevron, and consequently less able than these to participate in every market or new opportunity. The company struggled in this role for a dozen years, until the aftermath of the oil-price collapse of the late 1990s set up the industry consolidation in which Texaco was acquired by Chevron in 2001. The new GM might face a similar outcome. It will be much smaller than Toyota and possibly even smaller than Ford, and it must be nimble indeed to end up on the right side of the global car industry consolidation that many experts see coming. It would be truly ironic if GM, which in its first decade consolidated half the US car industry, survived Chapter 11 only to be gobbled up in a few years by a bigger fish.

Europe was a particular problem for Texaco, and it could be for GM, as well. Texaco hung onto its strong, integrated UK business, Texaco Ltd., along with marketing operations in the Benelux countries, Scandinavia and Spain, but the sale of Deutche Texaco put it at a permanent competitive disadvantage to the European majors and Exxon. It also left the company without an effective springboard into Eastern Europe once the Iron Curtain fell, and the shrinkage continued with a series of one-off asset sales. GM faces different challenges in Europe. Aside from the sheer size of the European market, it is the only place in the old GM's universe that already meets fuel economy restrictions as tough as the ones just imposed by the US administration. Although it will retain a 35% interest in Opel and Vauxhall, I anticipate that GM will struggle to extract technology and share model platforms with the alliance led by Magna International, which also supplies parts to GM's competitors. Ford and Nissan/Renault should have a clear edge in this regard.

I learned a lot about such alliances, when I led Texaco's alliance management group from 1994-97. Texaco's JVs in the US and Asia-Pacific enabled it to fight above its weight, giving it a much bigger footprint than it could have maintained alone. Our stake in Caltex allowed us to enjoy the financial gains from the rapid growth of Asian "tigers" S. Korea, Singapore and Thailand, along with near-tigers such as the Philippines. However, this came at the expense of quick decision making, cohesive brand management, and periodic turf wars and self-defeating instances of competing with ourselves. Even in a 50/50 relationship with another oil company, creating consensus wasn't easy. I can only imagine what this might be like dealing as a minority holder with a Russian bank and a car-parts maker, neither of which are likely to have much in the way of common interests to build on.

My sympathy goes out to the GM employees and managers today. The personal uncertainties of working for a company in Chapter 11 will be nerve-wracking, even if they've been anticipated for the last year or two. For their sake, I hope GM's ride through Chapter 11 proves smooth and quick--more like Chrysler's and less like the year that Texaco spent there. At the same time, as one of the 155 million new "shareholders" in GM, I would prefer that the company not put a higher priority on achieving a hasty exit from Chapter 11 than on ensuring the New GM can compete effectively in a global car industry and market for the long run. That means building reliable cars that consumers will be eager to own, and not just because they meet the new corporate average fuel economy and tailpipe greenhouse gas emissions standards.