Shrinking the Strategic Petroleum Reserve

• Selling oil from the Strategic Petroleum Reserve as part of the Congressional budget compromise raises serious questions about the SPR's future role.
• Shrinking the SPR without first bringing its coverage into line with 21st century needs risks strengthening OPEC's hand. 

Last month's Congressional budget compromise included plans to sell 58 million barrels of oil from the US Strategic Petroleum Reserve, beginning in 2018. That decision raises serious questions. The world has changed enormously since the SPR was established in the 1970s, but the realignment of such an asset for the 21st century deserves a full strategic review and debate. Leaping ahead to treat the SPR like an ATM  seems unwise on multiple grounds.

My initial reaction was that the sale would result in the US government effectively buying high and selling low. However, using the last-in, first-out (LIFO) accounting common in the oil industry, the SPR release during the 2011 Libyan revolution should have removed any barrels purchased as prices surged past $100 per barrel (bbl) to over $140, prior to the financial crisis. The oil now slated to be sold in 2018-25 was likely injected between December 2003 and June 2005, when West Texas Intermediate crude oil averaged around $44/bbl. The Treasury should at least break even on these sales, allowing us to dispense with judging the trading acumen of the Congress and focus on the strategic aspects of this decision.

It is also true that the combination of revived US oil production and lower domestic petroleum demand effectively doubled the notional import protection that the SPR provides. That has made policy makers comfortable enough with the coverage the reserve provides to consider shrinking it. Yet as Energy Secretary Moniz  and a growing body of experts have concluded, the SPR's present configuration is inadequate to deal with whole categories of plausible oil-supply disruptions.

Today's SPR consists entirely of crude oil stored in caverns near the major refining centers of the Gulf Coast, to which it is connected via pipelines. However, while crude oil imports into the Gulf Coast have fallen dramatically, the long-term decline of oil production in Alaska and California has forced West Coast refiners to import 1-1.5 million bbl/day of oil, including more than half of California's crude supply, much of it from OPEC producers. In the event of an interruption of those deliveries, and under current oil-export restrictions, getting SPR oil from Texas and Louisiana to L.A. and San Francisco would pose enormous logistical challenges.

We have also learned that natural disasters such as hurricanes Katrina and Rita in 2005 and Superstorm Sandy in 2012 affect refinery operations, as well as oil deliveries.  A crude oil SPR is of little value if its contents can't be processed into the fuels that consumers and industry actually use.  The newer Northeast heating oil and gasoline reserves were intended to address that limitation, though on a much smaller scale.

It is thus fair to say that the SPR established in the Ford Administration and filled by the next five US presidents to a level now equivalent to 137 days of US crude oil imports is not diverse enough in its composition or locations, and too big for our current needs. If we could count on a continuation of cheap, abundant oil for the next two decades, selling off some SPR inventory wouldn't create problems. However, the purpose of such a reserve is to mitigate the risks of uncertain and inherently unpredictable future conditions and events. That should be factored into any decision to shrink it.

We don't have to look far to find reasons to suspect that oil prices might someday be higher and more volatile--perhaps as soon as the 2018-25 legislated sales period--or to worry that oil supplies from the Middle East might become less secure. Consider the consequences of the oil price collapse that began over a year ago. Low oil prices have indeed put pressure on the highly flexible US shale sector, where production is now expected to drop by around 500,000 bbl/day by next year. The impact on large-scale, long-lead-time capital investments in places like Canada, the North Sea and Gulf of Mexico has been even more profound. Over $200 billion of new projects and exploration activity have been deferred or canceled. Unlike shale, most of these projects could not be revived quickly if prices rebounded.

As production from existing fields declines without replacement, the current global oil surplus will dissipate, bringing the market back into balance. However, that balance is likely to be more precarious than before, since last fall's strategic shift by OPEC to protect its market share instead of managing prices entails the depletion of OPEC's "spare capacity." That means that in a future crisis, Saudi Arabia and other OPEC producers will have little flexibility to increase production to make up for lost output elsewhere.

Barring an unforeseen reduction in global  oil demand, the scenario that is beginning to take shape fits the  pattern of risks that the SPR was originally intended to address. It includes the prospect of rising US oil imports, increasing reliance on OPEC, and the threat posed by ISIS in the world's oil "breadbasket".  In that light it is hard to justify reducing the size of the SPR without a clear plan for making the remaining volume more effective at shoring up future vulnerabilities in US energy security.

In their haste to reach a deal, Congressional negotiators may also have overlooked some SPR-related alternatives that could generate revenue without draining inventories. These might include allowing other countries to buy into the reserve by means of "special drawing rights," or simply selling long-dated call options backed by the SPR, to be settled in the future by delivery or cash, at the government's discretion.

Taken together, there are ample reasons for the next Congress and administration to revisit the SPR sales provisions of the 2016 budget deal, before they go into effect.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation

Net Exports and Gasoline Prices

US petroleum product exports have been in the news, along with the welcome discovery that we are apparently on track to become a net exporter of these fuels this year, for the first time since the 1940s. This is a far cry from energy independence, as various oil skeptics have been quick to point out, but it's still a noteworthy inflection point in energy trends. However, I've also seen stories suggesting that US consumers will pay a lot more at the pump as a result of this change, to which the most succinct response so far is "rubbish." Being a net exporter hasn't suddenly connected US fuel prices to the world market, as if they had somehow been insulated from it until now. In fact, we've been exporting products for many years--as I know from personal experience--but for most of that time we just happened to be importing more. The net effect of our new status on prices here will be minimal, while the main impact will be a positive nudge to our trade deficit.

I am sympathetic to the present urge to see a cloud in every silver lining; we seem to be going through one of those phases in our history. At the same time we should understand that to the extent net petroleum product exports aren't entirely good news, it's because the main driver of this departure from a long trend of steadily increasing net imports was the sudden slowdown of consumer activity that accompanied the recession and financial crisis, from which we are still recovering. And while I agree that more efficient cars have contributed, recent fuel economy improvements have been too incremental to our fleet of 240 million light-duty vehicles (passenger cars, SUVs and light trucks) to have made such a big dent in demand, quite so soon. Mainly, we're driving less, as the statistics on vehicle miles traveled indicate. That might be better news if it reflected a massive lifestyle change, instead of the grim reality of millions of un- and under-employed Americans for whom driving has become a luxury.

Even in that negative context, the fact that we are now exporting more gasoline and other petroleum products than we import is a plus, since without buoyant non-US demand, US refiners might have been forced to reduce operations by more than they have, or to idle more facilities and lay off staff. Today's net exports imply a positive margin between crude oil imports and product exports sufficient to cover refiners' costs, even after netting out freight. That results in more economic activity and value added here, driven by overseas demand, following the same export-led strategy that other industries are pursuing in order to compensate for lower US demand for their output.

More exports and fewer imports mean a smaller trade deficit, but the question on some people's minds is apparently whether this is being accomplished at the expense of US consumers. That might have been the case if, for example, exports had been banned until recently and refiners forced to create an artificial glut of petroleum products to drive down prices. (That's effectively the case in some other countries.) Instead, the US has long been part of a global market for both crude oil and refined products, and refiners and traders have always been alert for gaps between regional markets that could be profitably exploited. When I traded refined products for Texaco's west coast refineries in the 1980s, we occasionally took advantage of export opportunities, even though we were more often importers. When I traded products in London, my team routinely sold cargoes of gasoline, diesel or jet fuel from the US into Europe and Asia, and we did the reverse when the "arbitrage" worked in the other direction. We accounted for just a small portion of the trade in cargoes passing back and forth between continents, which continues today.

As a result of this global market in refined petroleum products, US consumers of gasoline and other fuels have always been competing with consumers in other countries, whether we realized it or not, especially in parts of the country where refiners have easy access to export markets. That's been true since the days when my former employer's advertising touted its success in "lighting the (kerosene) lamps of China". In terms of the impact on domestic prices, it doesn't matter much whether we're net exporters or net importers, as long as we're connected to the global market--a linkage that has saved our bacon on many occasions when US refineries were hit by hurricanes, blackouts, or other disasters.

A more tangible way to test the consequences of product exports involves comparing past and present crude oil and gasoline prices. Making that comparison accurately is complicated by the breakdown of the main US oil market indicator, the price of West Texas Intermediate crude, which for more than a year has been burdened by excessive inventory at Cushing, OK and other factors. For now the price of Louisiana Light Sweet (LLS) is a better gauge of the oil market. LLS has been relatively unaffected by WTI's problems and trended much closer to global oil prices, such as UK Brent crude. It turns out that 104% of the higher retail price of gasoline this November vs. a year ago is explained by the $23 per barrel increase in LLS since then. In other words, crude prices have increased by slightly more than gasoline, suggesting that raw material costs still have a much larger impact on prices at the pump than does the recent shift in US petroleum product trade patterns.

Although the evidence that product exports don't hurt consumers is strong, I don't expect it to dispel this handy new rationale for complaining about gas prices. After all, the price of gasoline is one of the most visible and volatile prices we're exposed to, and for which we have few practical alternatives. Having a narrative to explain these spikes and dips is empowering, even if it's wrong. However, in the midst of all the grumbling it's worth spending a moment thinking about the benefits of having an oil refining industry that has been able to find alternative outlets for its products while it waits for the US economy to recover, instead of yet another manufacturing industry on the ropes, shedding jobs and moving offshore.

The East Coast Refinery Gap

I see that ConocoPhillips has announced it will idle its 185,000 barrel-per-day Philadelphia area refinery, as a prelude to selling it or closing it permanently. Combined with the recent announcement that Sunoco would exit the refining business and sell or close its two refineries in Philadelphia, this amounts to just under half of the operating refining capacity on the US east coast, and that's counting PBF Energy's Delaware refinery, which is apparently in the process of starting up again after having been sold last year by Valero. If none of these three facilities finds a buyer, the resulting closures would leave a large gap in the east coast petroleum product market that must be filled either by shipping more products via pipeline from the Gulf Coast, to the extent capacity permits, or by means of increased imports from Europe and Canada. East coast gasoline and diesel prices could be higher for years to come.

The story in Reuters gives a good overview of the circumstances leading to Conoco's decision, and you've read about most of these factors in previous postings here. Topping the list is the persistent divergence of crude oil prices between the US mid-continent and the global oil market, due to a bottleneck at Cushing, OK resulting from several factors. Last week the gross margin ("3:2:1 crack") for importing crude priced at the level of UK Brent and turning it into gasoline and diesel or heating oil for the northeast market stood at a breakeven, and it's only a few dollars a barrel in the black today, after yesterday's market recovery. That's not much of an inducement to hang onto massively complex, capital-intensive facilities and to continue investing in them to keep them in compliance with ever more stringent regulations. Sometimes it just makes more sense to take a write-down and sell to someone else, who then starts with a lower capital base and has a better chance of making a return--not unlike the restaurant business. The problem in this environment is that it's not obvious who would step into the shoes of Sunoco and Conoco in Philadelphia. A few years ago buying refineries from integrated companies that wanted to redeploy their capital was a thriving game, with lots of players. Not so much, now.

Conoco's timing on this move is interesting, too. If it were only a question of margins, I'd think they'd wait to see how much profitability improved after Sunoco's plants shut down. Instead, it appears they are focused on a bigger picture. Even if they don't find a buyer, closing a marginal or money-losing facility will improve their overall refinery portfolio as they prepare to spin off the refining and marketing business, while allowing them to use the capital expenditures they won't have to put into the Trainer refinery for more lucrative opportunities like shale gas, which the company has been touting in a series of ads. That probably makes sense for the company's shareholders, though it won't do much for consumers in my neck of the woods, especially if the company's larger New Jersey refinery meets the same fate.

Oil refining has always been a tough business, with its occasional good years normally more than offset by years or decades in the doldrums. But the combination of reduced demand from the recession-weakened economy and the increased supply of biofuel--mainly corn ethanol, so far--has increased the pressure. When I ponder all this it makes me wonder why so many startups are so eager to get into the fuels manufacturing business, even if it will be based on biomass rather than oil, when they will ultimately be exposed to similar market forces.

Turning to Energy for Jobs

Yesterday's Energy Jobs Summit at the US Capitol, hosted by The Hill and API, focused on the potential of the energy sector to add large numbers of new jobs to help alleviate the national jobs crisis that President Obama will discuss in tonight's speech. The figures presented by API and others were impressive, with the oil and gas sector alone capable of creating over a million jobs if provided increased access to US resources. Panelists also discussed "green jobs", including those from energy efficiency projects. Yet I was struck by the inherent tension between today's job-creation imperative and our long-term need for an energy sector that is as productive and cost-effective as possible, in order to support economic growth and reemployment in the roughly 92% of the economy beyond energy. That makes highly productive private-sector energy jobs requiring little or no public investment especially valuable.

In a new study released at the summit, Wood Mackenzie estimates that the US oil and gas industry could increase its employment by 1.4 million by 2030, with a million of those jobs attainable by 2018--more than half in the next two years--under new policies that would lift the current bans on offshore drilling outside the established areas of the Gulf of Mexico and on shale drilling in New York, speed up permit issuance in the Gulf, open up new onshore acreage for leasing, and approve the Keystone XL pipeline. In the process, domestic production of oil and gas liquids could eventually nearly double, while natural gas output would grow by over 60%. Even better, from a deficit-and-debt reduction perspective, this effort would require no new government expenditures and stands to contribute a cumulative $800 billion in additional federal and state royalties and tax receipts.

The potential jobs impact is extraordinary, when you think about it. Oil and gas is an incredibly capital-intensive industry with very high worker productivity--one reason that salaries in the industry tend to be much higher than average. An industry like that is hardly the first place one might think to look when seeking massive job growth. The fact that such growth is even possible is both a validation of the tremendous untapped resource potential we still possess, and an indictment of decades of bipartisan energy policy mismanagement that has preferentially outsourced US energy production, rather than exploiting our own resources.

What about the contribution of "green jobs"? The growth of cleantech--renewable energy and energy efficiency--can certainly contribute to US job growth, yet we should understand clearly that such jobs won't spring forth spontaneously from the private sector without substantial continued government incentives and subsidies. Nor are those a guarantee of success. The US wind industry installed just 2,151 MW of new capacity in the first half of 2011. While that was considerably better than last year's pace of 1,250 MW, it's still 47% below installations in the first half of 2009, despite last December's against-the-odds extension of the Treasury renewable energy grants, which paid out $2.2 billion to wind projects this year. And the recent solar bankruptcies and the aggressive offshoring by solar manufacturers fighting to stay competitive with Asian suppliers also demonstrate that green jobs, other than those in installation and construction, are just as vulnerable to global competition as in any other US manufacturing industry.

Conventional energy jobs aren't immune from competition, either. I was startled to read yesterday that regional refiner Sunoco plans to exit the refining business after more than 100 years. Its two Philadelphia-area refineries will either be sold or shut down by mid-2012, with 1,500 jobs at stake. Prospects for a quick sale of these facilities look poor, because these plants are among the most exposed to global oil prices that have been running more than $20 per barrel higher than for crudes produced in Canada and the US mid-continent. Idling these plants would take a big bite out of east coast gasoline supplies and inevitably lead to both higher product imports and higher gasoline prices in the northeast and mid-Atlantic regions. As someone pointed out at yesterday's session, it's a sad commentary that Sunoco can make more money selling sodas and snacks at its retail facilities than it can refining crude oil.

That dynamic makes the production-related jobs in the Wood Mac study even more attractive: Despite being tied to a depleting resource, US oil & gas exploration and production enjoys a greater sustainable competitive advantage in the global marketplace than either refining or cleantech manufacturing, at least when it has sufficient access to domestic resources.

However, these opportunities also pose a test of our seriousness on the jobs issue. Opening up the Virginia and California coastlines, for starters, along with the coastal plain of the Arctic National Wildlife Refuge to exploration raises a host of NIMBY and environmental concerns. I don't want to trivialize them, but I would suggest that the time when we could afford such sensibilities may have passed, heralded by our continued descent in the rankings of national global competitiveness and the rapid growth of our indebtedness. Creating a number of "green jobs" comparable to Wood Mac's estimate of 1.4 million from oil and gas would require the expenditure of tens to hundreds of billions of dollars the federal government doesn't have, and that the current Congress seems unlikely to be willing to appropriate. It would also risk embedding expensive energy at the core of the US economy, hobbling our non-energy economy, where most Americans are employed.

Yesterday's energy jobs summit was held in the new Capitol Visitor Center, which I hadn't seen before. It's a gorgeous facility and a suitable addition to the paramount edifice of our democracy. However, I was also struck by the contrast it provided with the meeting's subject matter. Recall that the Visitor's Center ended up costing over $600 million, well over twice its original plan. I hope that when the President presents his jobs program tonight, it will be grounded in the crucial distinction between that kind of government-funded, "shovel-ready" project that might put some of our fellow citizens back to work for a few years and an energy-and-jobs resurgence funded entirely by companies and their investors.

The Oil Earnings Backlash

Another oil industry earnings season bolstered by high oil prices has sparked the customary controversies about price gouging and industry subsidies. Last Thursday I participated in ExxonMobil's press call following the release of that company's first quarter earnings. In addition to the responses to my questions about access to non-US energy resources and the progress of the company's algae venture with Synthetic Genomics, I was intrigued by the answer of Ken Cohen, VP of Public and Government Affairs, to a question concerning Exxon's crude oil sales to other refiners. It resonated with my own experience in commodities trading at Texaco in the 1980s and '90s. Not only do major companies like Exxon, Chevron, Shell and BP control only a small fraction of the world's petroleum reserves and production, but they are often large net buyers of crude oil for their refining operations. Understanding the relationship between industry profits, gas prices and the federal tax deductions and credits designed to promote domestic energy production requires a deeper look into the results.

It's discouraging how much confusion still exists in the media concerning oil prices and gasoline prices, as noted in an excellent posting on the topic by Robert Rapier. Members of the public who are convinced that oil companies are manipulating prices to gouge them can always find some poorly reported news story or garbled explanation to justify their belief. Yet while it's certainly true that oil companies benefit from the higher oil prices that result when global demand for petroleum products is strong and supply is constrained and/or subject to unusual risks--both factors are at work today--their interests are not quite as divorced from those of gasoline consumers as they appear, because they are, to a very large extent, also consumers themselves.

A quick look at ExxonMobil's 1Q11 earnings release shows their net global production of crude oil and natural gas liquids at 2.4 million barrels per day (MBD). Meanwhile the company's refineries processed nearly 5.2 MBD in support of global refined product sales of nearly 6.3 MBD. In other words, Exxon had to buy more crude oil from other suppliers than it produced itself in order to feed its refineries, and then still had to acquire more than a million barrels per day of additional refined products from other refiners to meet its marketing demand. Meanwhile, 81% of its nearly $10.7 billion of first quarter earnings was attributable to oil and gas production, and 85% of that was from production outside the US. By comparison, just 6% of that $10.7 billion came from the domestic refining and marketing activities affected by US gasoline prices.

That's a fairly typical pattern for the majors, which have generally been short of crude oil for their refining systems since the big wave of nationalizations and expropriations in the 1970s. My old company, Texaco, refined about twice as much oil as it produced and sold roughly half-again more products than it refined. That meant that my trading colleagues and I were in the market every day, buying crude oil and refined products from our competitors, in order to keep our refineries and marketing outlets supplied. When supplies were tight, the only way to secure what we needed was to bid more than the next company, and that reinforced the dynamic of rising prices until supplies expanded or demand slackened. I see that as of the first quarter, Texaco's successor Chevron Corp. (of which I am a shareholder) produced about as much oil globally as it refined, though not in the US, where it processed 80% more crude than it produced domestically. Global product sales exceeded refinery throughput by more than a million barrels per day. Royal Dutch Shell's results exhibit an even more pronounced case of net purchases of both crude oil and refined products.

So while higher oil prices are good for some parts of these companies' businesses--the exploration and production divisions that contribute the majority of profitability in most years--other business segments find higher prices a mixed blessing, at best. That's particularly true for the parts of these companies with which US consumers have the most contact.

As for the questions I posed to Mr. Cohen, I was somewhat surprised to hear that ExxonMobil isn't looking for the US government to provide it with any assistance in gaining access to resources around the world. Foreign governments routinely help their national and quasi-national oil companies to negotiate for access. ExxonMobil seems able to compete in this arena without help from the US government but is much more concerned about the latter's restrictions on access here at home, and its efforts to tax non-US income that has already been taxed by host governments overseas. And with regard to ExxonMobil's activities in algae, I was informed that R&D is progressing well in both California and in Baytown, TX, where a large pond has just been completed. Mr. Cohen stressed that it was still early days for algae.

The purpose of drawing my readers' attention to the distinction concerning oil companies' large net oil and product purchases isn't to solicit sympathy for an industry that's obviously having a very profitable run, but to remind you that the oil and gasoline price situation is a lot more complicated than suggested by the sound bites we often hear. The biggest companies make most of their profits producing oil and gas outside the US, while refining and marketing here remains a capital-intensive and relatively low-return sideline that many of them have been quietly exiting for years. Ending the industry's tax breaks outside of the comprehensive tax system reform I believe to be necessary probably wouldn't harm the big oil companies as much as it would accelerate their shift away from operations in the US that contribute less to company profits than they do to US energy security.

The Year of Regulation?

Some new years seem newer than others, bringing major changes rather than just the turning of a calendar page. 2011 is shaping up that way, with a return to divided government in the US and the beginning of national greenhouse gas regulation by the EPA based on that agency's interpretation of the Clean Air Act, rather than as a result of explicit new Congressional legislation. As the ongoing legal battle over this between the EPA and the state of Texas demonstrates, there's a lot at stake, and the final outcome has not yet been determined.

When the US Supreme Court ruled in 2007 that CO2 and other greenhouse gases constituted pollution that was subject to regulation under the Clean Air Act, it set in motion the process that is now culminating with the EPA's proposed rules for regulating these gases. Initially this will take the form of what the agency calls New Source Performance Standards, applying only to new facilities and modifications within existing facilitates, and only for sources emitting more than 50,000 tons per year of greenhouse gases (GHGs). That exempts residential and most business activities using less than the energy equivalent of about two gasoline tank-trucks per day. The first phase of these regulations is specifically targeted at power plants and oil refineries, and over time it could significantly alter the way that electricity is produced and oil refined in this country.

I've argued for years that this is entirely the wrong way to go about reducing emissions, because greenhouse gases are global, rather than local in effect, and a command and control approach applied to point sources of CO2 and other GHGs will miss many of the least expensive emission reduction opportunities while forcing businesses to focus their efforts on some of the most expensive. Cap and trade or some other means of establishing a price on emissions would have been much more efficient, although the version of cap and trade passed by the House of Representatives in 2009 was a miserable excuse for such a system, distorted as it was by preferential treatment for favored groups and sectors.

But this isn't just a question of economic efficiency; it's also a question of effectiveness. Regulating power plant emissions addresses 34% of total gross US GHG emissions, including roughly 92% of the emissions from the coal value chain, while regulating refineries tackles less than 10% of the emissions from the petroleum value chain--and some of the hardest ones to cut, at that. Refineries are already about 90% efficient. Squeezing even more efficiency from them--which would be the net effect of capping their GHG emissions, since most of those are associated with the combustion of fossil fuels--is likely to cost a lot more than the value of any energy savings such changes would yield. That could have a significant impact on states like Texas, which is home to more than a quarter of the country's refining capacity. The result would also increase national energy costs in either of two ways, with higher operating costs at US refineries being passed on to consumers in the price of fuels, or by reducing US refining throughput and capacity and increasing our reliance on product imports. The latter works directly against the widely-held notion that anything that reduces emissions must automatically be good for our energy security.

None of this is set in stone, although I certainly wouldn't bet against some version of it coming into effect. The incoming Republican chairman of the House Energy and Commerce Committee has already indicated his determination to restrain the regulation of GHGs by the EPA, and even without a majority in the Senate the House, which controls the government's purse strings, could make it much harder for EPA to pursue this course. At the same time, several previous sponsors of Senate energy and climate legislation have expressed interest in a new, bi-partisan approach to energy, and it's not inconceivable that watering down the proposed EPA regs could become part of a deal to establish a national low-emission energy standard that would include not just renewables, but also nuclear energy and possibly even natural gas. I will be watching these developments with great interest in the weeks and months ahead.

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.

Delaware Refinery Swims Against the Tide

When I saw this headline in today's Wall St. Journal, "Governor Stays Closure of Delaware Refinery," the first thought that crossed my mind was of King Canute and his order to stop the tide. Valero Energy Corp., which owns the Delaware City refinery, had announced last fall that it would be shut down and dismantled. That was a pretty remarkable turn of events, considering that not very long ago refining margins were at all-time highs, boosting the fortunes of independent refiners like Valero and causing politicians and energy experts to despair that the US didn't have enough refinery capacity to keep pace with future demand. But while I understand the state government's desire to preserve the jobs and tax base involved, it's worth asking whether Governor Markell and the firm that appears ready to buy the refinery for $220 million are making a good bet or merely postponing the inevitable. Two graphs of the key fundamentals for this sort of refinery raise serious doubts.

More than 100 US refineries have closed in the last several decades, but few of those were as large or sophisticated as the Delaware City Plant (DCP), which was originally built by Getty Oil to process heavy oil from the Neutral Zone between Kuwait and Saudi Arabia. My former employer, Texaco, owned it for a while, as a result of its acquisition of Getty, before putting it into its refining and marketing joint venture with Saudi Refining Inc., which later included Shell. That JV sold DCP to Premcor, Inc., an independent refiner then run by the current CEO of PBF Energy Partners, LP, the company that is now buying it from Valero, which has owned it since its purchase of Premcor in 2005. The number of times it changed hands probably says more about the evolution of the US refining industry than about any inherent shortcomings of the facility, which is a complex machine for turning low quality crude into lots of gasoline and other valuable light products. Unfortunately, that description encapsulates the two biggest challenges its new owners, creditors and employees face.

Start with gasoline, which remains the most important product for most US refineries, accounting for about half of all US petroleum product sales and roughly 60% of refinery yield on crude oil input. Historically, US gasoline consumption rose by a steady 1-2% per year, and refineries often struggled to keep pace with demand, resulting in significant imports of gasoline and blending components. Two factors have altered that relationship, perhaps permanently. First, rapidly-increasing ethanol production, backed by subsidies and a steadily-escalating mandate, is eroding the market share of the gasoline that refiners make from crude oil. So now even when "gasoline" sales go up, they include an increasing proportion of ethanol. And as a result of the recession, total gasoline sales--including the ethanol blended in--fell by 3.2% between 2007 and 2008. When you factor out the ethanol, the drop was more than 5%. So because of weak demand and increasing ethanol use, refineries like DCP have experienced a shrinking market for their most important product, as the graph below depicts.

Then there's the issue of refinery complexity, which is a two-edged sword. When both crude and product markets are tight, as they were in 2006 and 2007, complex refineries like DCP enjoy a cost advantage over less sophisticated competitors, because they can make the same products from cheaper, lower-quality crude oils--typically heavier and higher in sulfur and other contaminants. But when the global economy stalled in 2008 and oil demand plummeted, many of those low-quality crude streams were the first ones that producers cut back, because they yielded less profit at the well-head than lighter, sweeter crudes. With less supply, the discount for them relative to lighter crudes shrank, and with it the competitive edge of facilities like DCP. In the case of Saudi Heavy crude, shown below, it looks like that discount was cut in half starting in late 2008, which was probably the last time DCP made decent returns.
What must happen in order for DCP to become a viable proposition in the future, other than for PBF to buy the facility for a fraction of its replacement cost--even less than Mr. O'Malley paid Motiva for it in 2004? Number one would be for light/heavy crude differentials to widen again. That could reasonably be expected to occur when the global economy grows by enough to bump up against OPEC's spare capacity limits, again. With spare capacity currently standing at more than 5 million barrels per day, that's unlikely to happen soon. However, even with a wide enough discount for its preferred crude supply, DCP will still be pushing gasoline into a weak market, thanks at least in part to continued expansion of ethanol. One indication of that comes from Valero's earnings report for the fourth quarter of last year, in which its ethanol business earned operating profits of $94 million, while its refining business, with more than 40 times the throughput, lost $226 million.

I would have been sorry to see the Delaware City Plant, with all its history, sold off for parts and scrap. After all, this is pretty much the kind of refinery that some were hoping the US would build, just a few years ago: large, complex, close to major markets and outside the hurricane belt of the Gulf Coast. However, the world changed in the interim. Will it change back enough to make DCP a going concern, again, or are the taxpayers of Delaware sinking more money into a facility that is destined to be a victim of Peak Demand, as more efficient cars and more prevalent biofuels squeeze enough petroleum products out of the market to ruin the economics of all but the most-efficient, lowest-cost refineries? We should know within a few years.

What's the Alternative to KGL?

Although I haven't yet seen the latest discussion draft of the "tri-partisan" energy and climate proposal of Senators Kerry, Graham and Lieberman (KGL), I've been thinking about its rumored provisions for a while. These apparently include a cap & trade system for the electricity sector, eventually expanding to include most industries, and a "carbon fee" on petroleum fuels that would be linked to the cap & trade market, along with measures to increase domestic energy production from a wide range of sources, including oil. It occurs to me that the most important question about the resulting legislation may not concern its actual contents, but what we ought to compare it to.

For all the remaining uncertainty about the risks of climate change, which this week's Economist details, the US regulatory baseline for it has already moved beyond doing nothing. Having issued its Endangerment Finding, the EPA is gearing up to regulate greenhouse gas emissions from both stationary and mobile sources. Almost any other approach to these emissions would be preferable, since regulating point sources ignores the fundamental differences between CO2 and the traditional pollutants like the oxides of nitrogen or sulfur they've been dealing with for decades. If we fail to capitalize on the helpful reality that all GHG emissions anywhere are essentially equivalent in their effect on the climate, we likely won't tackle the cheapest reductions first, and that could cost us a fortune. Yet even without some form of national greenhouse gas legislation or regulations, these emissions are already being regulated at the state level through efforts such as California's A.B. 32 and the Regional Greenhouse Gas Initiative. In that context, whatever one's assessment of the underlying science, we all have a stake in Congress passing the most practical and cost-effective greenhouse gas legislation possible. Sadly, the blatant favoritism and profligate spending of the Waxman-Markey bill that passed the House last spring disqualify it on both of these criteria.

One of the biggest challenges for KGL is ensuring that their bill doesn't end up as a bloated monstrosity like Waxman-Markey. You don't need 1,000 or more pages to define a cap & trade regime or a carbon tax, or to set up "cap & dividend", under which most of the money collected from selling emissions permits would flow back to taxpayers. (That approach has its own problems.) You do need hundreds or thousands of pages, however, to accommodate all the pork and giveaways that seem to be necessary to get any major legislation passed these days, one vote at a time. Careful scrutiny of the text of the Waxman-Markey bill suggests that there is not a majority of this Congress--or perhaps of any actual Congress we're likely to get--that sees the necessity of crafting a clear response to climate change as trumping the need to score goodies for their districts and favorite causes or constituencies. Messrs. K, G and L have their work cut out for them, finding enough support for their proposal through its primary provisions, rather than accreting dozens or hundreds of tit-for-tat favors.

Perhaps the key to a successful bi/tri-partisan bill could be found in its approach to the uses of the enormous revenues it would generate. The healthcare bill that passed the House last weekend only achieved deficit neutrality by taking a huge bite out of the revenues and savings that might otherwise have gone to bringing Medicare or Social Security back into balance, and that's not a partisan talking point. If we are indeed facing an entitlements crisis on the scale that many expect, and some form of consumption tax is on the horizon as the only viable revenue alternative to a return to the bad old days of confiscatory taxation on upper-income Americans who already pay 86% of all the federal income tax collected, then energy might be a good place to start. A fee of 25 cents per gallon--roughly equivalent to $25/ton of CO2 emitted--on gasoline, diesel and jet fuel would collect on the order of a half-trillion dollars over 10 years.

If KGL do go down the path of a carbon fee on petroleum, the biggest mistake they could make would be to follow the advice of the economists and experts who advise collecting it as far "upstream" as possible. Taxing refineries is a sure recipe for offshoring one of the few remaining basic manufacturing industries in this country that has managed to remain globally competitive, even if it has fallen on hard times recently. Likewise, taxing US oil & gas exploration and production would make them uncompetitive with foreign sources free from such burdens. Instead, since most of the emissions from the petroleum value chain occur during consumption, rather than production, the best place to apply a carbon fee--can't call it a tax--is at the gas pump. This would subject domestic and imported fuels to the same cost without having to go through gyrations to manage "leakage", only to find out later that they violate international trade rules. Best of all, the government already has the mechanism in place to collect such a fee without adding another expensive bureaucracy: Simply tack it onto the federal fuel excise tax and post the amount on every fuel dispenser whenever it changes.

In a perfect world, we'd establish a price on carbon using a simple and transparent cap & trade mechanism and return every penny collected to the public, in order to minimize the burden on the economy while shifting it in the direction of greater energy efficiency and lower emissions. In the last several years it has become abundantly clear that we don't live in that world, if we ever did. I still favor cap & trade as an efficient mechanism for price discovery, but not if its implementation comes with as much baggage as Waxman-Markey carried. I will eagerly await the details of the KGL proposal to see whether they can navigate the narrow gap between an effective, efficient approach to GHG management and the political forces seeking to feast on the bonanza it represents.

Cap & Trade, Gas Prices and Uncertainty

Over the weekend a New York Times editorial critical of the energy industry for trying to stir up opposition to the Waxman-Markey climate bill prompted some further thought on the potential impact of the legislation on gasoline prices. The Times appears to accept the government's analysis suggesting that the increase would amount to no more than 20 cents per gallon by 2020, though this conventional wisdom collides with common sense, since such a low price on carbon seems unlikely to stimulate sufficient conservation and investments in efficiency to deliver on a steadily-shrinking national emissions cap. In particular, the Times seems unfazed by the way the bill's allocation of free emission allowances is stacked against the oil industry, suggesting that it, of all industries, can surely afford the extra burden. Yet it's precisely that distortion that I believe could throw all of the official estimates of future permit prices--and thus gas prices--into a cocked hat, when you consider the possible dynamics of a market established along these lines.

Let's start by stating the obvious: I don't have a detailed computer model of the energy markets and US economy to query on the likely outcome from the cap & trade system that would be instituted under Waxman-Markey, though I could probably come up with some drastically-undervalued credit default swaps for anyone who believes in the infallibility of such models. My assessment relies instead on logic and the experience of a career that included a long stint in energy commodity trading, including futures, options and derivatives. Based on that experience, I believe the crucial starting point for any attempt to understand how a new market might function is supply and demand: who has the commodity in question and who needs it.

Begin with demand. The Department of Energy's recent "flash estimate" of US CO2 emissions indicates that the electricity sector accounts for 41% of emissions, followed by transportation with 33%, and the non-electricity-related emissions of the industrial sector a distant third at around 17%. These three segments thus account for 91% of our CO2 emissions, by far the largest component of our greenhouse gas output. Under cap & trade, every ton of those emissions would have to be matched with a corresponding emission allowance, or the emitter would be liable for penalties at a multiple of the going price for allowances. Anyone who is given fewer allowances than their current emissions must thus either reduce their emissions directly or purchase allowances from others. But who are the likely sellers? A careful reading of the bill provides strong hints

Under President Obama's original concept of cap & trade, in which 100% of emission allowances would have been auctioned by the government to the emitters that needed them, all sectors of the economy would have been in the same position of needing to cover their entire shortfall in the market. The government would have been the primary seller, though as the market evolved, companies that found cheap ways to reduce their own emissions would have ended up reselling allowances they had bought earlier, at a profit. Under Waxman-Markey, by my tally roughly 60% of the emission allowances would be handed out to emitters such as utilities, refiners and other industrial firms. Another 30% or so would be doled out in lieu of cash to fund efforts such as renewable energy R&D and deployment, climate adaptation and assistance to low-income consumers. Something less than 10% would be auctioned by the government itself to fund deficit reduction and other initiatives.

So on a given day, who would be selling and who would be buying? Consider the utilities and merchant power generators. As generous as the bill's authors were to this sector, it would still be short allowances from day 1, with a gap between actual emissions and free allowances equal to roughly 4% of US emissions. Non-energy industrial firms probably wouldn't be selling, either, at least unless the price got high enough to stimulate the big investments in energy efficiency that haven't risen to the top of their capital budget priorities so far. Initially, they would need to acquire allowances equal to around 5% of all emissions. And that brings us to refiners, who under Waxman-Markey would be responsible for their own emissions plus all of the emissions from the end-use of their products by non-regulated consumers, yet would receive only a 2% allocation of free allowances. Depending on how upstream production and oil imports are counted, the gap that refiners would need to cover could amount to more than 31% of all US emissions, or 3/4ths of the allowances given to non-emitting entities or auctioned directly by the government. At the same time, they have only modest scope for further reductions in their own emissions, considering that they are already 90% energy-efficient, on average. Who would be likely to have the advantage in such a situation? It sure looks like a "sellers' market" to me.

I don't doubt that refiners could probably scoop up some relatively cheap allowances from groups that get handed these tickets and don't quite know what to do with them, though market sophistication--and for-fee advice on such matters--might spread quickly. But refiners wouldn't just need to sweep up the stragglers, here. They'd require the entire allowance streams of many of the legislation's chosen beneficiaries for years to come, nor could they risk coming up massively short in any year. To me that suggests an average acquisition price for allowances that could rise well above the notional $15-$20/ton expounded by the EPA and DOE, considering that the effective price ceiling provided by brute-force CO2 reductions such as carbon capture and sequestration is probably north of $50/ton, equating to 50 cents per gallon of gasoline. While an increase that high might not be the likeliest outcome, it is at least plausible, and it would be added not to current gas prices, which have been depressed by the recession, but to those that would prevail after the legislation went into effect, when the economy--and perhaps even fuel demand--was presumably growing again. It doesn't take a leap of imagination to combine these factors to get to the $4 per gallon that the Times appears to dismiss.

From the last sentence of the editorial, I have to conclude that the Times doesn't understand the rationale for cap & trade nearly as well as they think they do. The point of this approach and any well-structured legislation implementing it is not to wean the US off of petroleum, but to reduce our emissions of the greenhouse gases implicated in climate change. While that certainly implies lower emissions from the oil sector, and thus lower consumption, it is perverse and counter-productive to shelter higher-emitting sectors that have greater flexibility for reducing emissions. The Congress may have judged that consumers would complain more about higher electricity bills than about increases at the gas pump, which could always be blamed on other factors--and on a singularly unpopular industry. But in creating such a wide disparity of demand for allowances among business sectors, they risk driving the price of those allowances much higher than otherwise, imposing an unnecessary drag on the economy. Even if their protests are motivated by self-interest, the oil industry and oil consumers are right to point this out.

US Refineries Under Cap & Trade

A new study confirms my previous suspicions that the allocation of free emission allowances in the Waxman-Markey climate bill would disproportionately disadvantage the US oil sector, with serious consequences for our energy security. In particular, it quantifies the impact on the refining sector, which was chosen by the bill's authors as the focal point for collecting the "tax" on all carbon emissions from the use of petroleum products. In the view of EnSys Energy Systems, Inc., based on their model of global downstream petroleum markets, US refineries would run much less crude oil and be able to invest much less in modernization. As a result, US imports of refined products would grow significantly, despite lower overall consumption, and employment in the US refining sector would fall, while the reductions in greenhouse gas emissions from domestic refineries would be largely offset by increases abroad. Such an outcome would benefit neither the global climate nor US national security.

When I examined the preliminary version of Waxman-Markey in early June, I concluded that because it doled out so many free emission allowances to the electricity sector, its main effect for at least the first two decades would be to function as a tax on the petroleum sector, though without the clarity and transparency of a gasoline tax. Those allocations didn't change materially during negotiations, with the final House bill offering roughly 2% of emission allowances to refineries that would be saddled with the responsibility for between 33% and 44% of all US GHG emissions, depending on how you slice them. Compare that to the electricity sector, which accounts for 39% of emissions but would get at least 35% of the free allowances.

Rather than going through the details of the EnSys study, which was commissioned by API, I'd like to approach this by considering how an evenly-distributed cap & trade system (or carbon tax) should reasonably be expected to affect the oil industry, which after all accounts for a major share of US emissions. You'd hardly expect it to get off scot-free. However, it's a fact that most emissions in the petroleum value chain occur when refined fuel is burned, rather than during production (extraction) or refining. The Ensys study puts the refining contribution at less than 10% of all emissions from well to wheels. Although refiners ought to see their operating costs rise under cap & trade, giving them further incentives to increase their already impressive efficiency of roughly 90% (energy out vs. energy in), the impact should properly be relatively modest. The bulk of the impact from cap & trade should manifest in the form of higher end-user prices for gasoline, diesel and jet fuel, putting commensurate pressure on consumers to use less. The outcome of that reduction would fall on the marginal suppliers of refined products to the US market: foreign refiners that sent us over 3 million barrels per day last year. EnSys concludes that Waxman-Markey would have entirely the opposite result, enriching foreign refiners at the expense of the employees and owners of US facilities.

I wouldn't be surprised if the EnSys study were greeted with the customary skepticism of a finding that supports the interests of the constituency that paid for it. API and its member companies have much at stake in this debate. But if you doubt the likelihood of the scenario it describes, you need only review the regulatory history of the US refining industry and the long-term trend of our refined product imports, which have increased at double the rate of our crude oil imports. Between 1993 and 2007--before the recession axed them--net US refined product imports (after subtracting out exports) grew by a compound average rate of roughly 6% per year, compared to an average increase of 3% per year for net crude imports over the same period. This coincided with increasingly strict regulations on permits for new facilities and on refinery emissions of criteria pollutants, along with ever-tougher rules on gasoline and diesel fuel specifications, culminating in the current reformulated gasoline and ultra-low-sulfur diesel specs. With the exception of a couple of years of stellar margins late in that interval, returns on refinery investments were very poor, and the major oil companies were steadily shedding refining capacity as a bad bet. Today, even the independent refining companies that created profitable businesses by purchasing these assets at a fraction of their replacement cost are suffering from low profits.

If anything, the economic impact on the US refining industry from regulating carbon emissions could be even worse than this recent history, since it hinges on the basic chemistry of combustion itself, rather than the removal of impurities that constitute only a small percentage of their feedstock inputs, even for the highest-sulfur crudes. That could happen even with an even-handed approach to cap & trade or a carbon tax, but it would be a certainty under a system that appears designed mainly to shield utilities and their customers at the expense of the entire existing transportation fuel system. The principal means of reducing GHGs from the latter is through cuts in consumption, not more efficient refining, and even our recent low level of product imports offers the opportunity to cut our emissions from petroleum products by roughly 7% with a minimal effect on US refineries. Instead, Waxman-Markey would effectively offshore many of those refineries--and their emissions. In a world transfixed by market failures, that would constitute a regulatory failure of the first magnitude.

"Over a Barrel" - Part II

Picking up where I left off in Friday's posting addressing the issues raised by ABC's recent "Over a Barrel" report, concerning what Americans ought to know about oil, let's turn to the products that we get from it. Over the course of a century and a half of production--this month marks the sesquicentennial of Drake's well--petroleum has provided us with a cornucopia of fuels, lubricants, and raw materials for industry, many of which grew out of the search for substitutes for other, scarcer commodities or the availability of low-value byproducts from earlier, less-sophisticated refining techniques. In recent years, however, we've acquired a greater awareness of oil's adverse consequences, and it has attracted its first serious competition in many decades in its primary transportation fuels market.

The gasoline we put in our cars, the diesel that fuels trucks and buses and heats many homes, especially in the Northeast, and the jet fuel we can sometimes smell when the plane on which we're traveling has just refueled together accounted for 74% of the 19.5 million barrels per day of petroleum products consumed in the US last year. Throw in propane, lubricants, asphalt, petrochemical feedstocks and solvents, and you're up to around 90%, with most of the remainder coming out as heavy fuel oil for ships, petroleum coke (a solid, coal-like fuel,) and the fuel used by refineries in their processing. The average US refinery is 90% efficient, meaning that 90% of the energy that goes into it comes out in the products it sells, while the other 10% is consumed along the way. Greenhouse gas emissions follow a similar pattern, with the majority occurring not during processing but in the subsequent use of the products.

That's a crucial factor in the effort to reduce emissions. In the recent estimate of last year's US CO2 emissions, nearly 80% of oil's 42% share of the CO2 emitted by fossil fuels came from the combustion of transportation fuels. That means that by far the largest opportunities to reduce emissions from oil are associated with vehicle efficiency, not changes in refinery processes, which are already quite efficient. So while reducing direct refinery emissions by 1/3 would only cut total oil-related emissions by about 3%, increasing the efficiency of cars, trucks and planes by 1/3 would reduce those emissions by 26%. That is a realistic possibility, because most of our vehicles use these fuels so inefficiently. Although we can't easily reduce the 20 lb. of CO2 emitted from the combustion of each gallon of gasoline, we can certainly reduce the number of gallons we burn per mile.

If you asked most people why gasoline has been such a successful fuel for the last century, you'd get a variety of answers, including some entertaining conspiracy theories, but relatively few would zero in on the fuel's remarkable capacity to deliver lots of energy in a compact and easily portable form. Every gallon of E10 gasoline (10% ethanol blend) you put into your car carries roughly 110,000 BTUs, compared to 82,000 BTUs for the E85 ethanol/gasoline blend, or 66,000 BTUs for an 85% methanol/gasoline blend. Those extra BTUs translate into range and convenience, even though the typical internal combustion engine vehicle throws away roughly 80% of them as waste heat and other losses. That's why there's such a big opportunity for hybrids, advanced engines and transmissions, and other technologies to improve the fuel economy of most cars, if consumers are willing to pay the higher up-front costs. It's sobering to think that the advanced battery pack for GM's highly-anticipated Volt plug-in hybrid will hold the energy equivalent of just a half-gallon of gasoline, though the car's electric motor will use that energy much more efficiently than an internal combustion engine would.

So what are you buying when you fill up at the pump? If you watched "Over a Barrel", you probably got the impression that you are paying for an entirely generic fuel, a moderate slice of taxes and dealer margin, and a whole bunch of advertising and other marketing expenses. That's misleading on a couple of levels. It's true that the basic fuel is indeed generic--"fungible" in industry parlance--for the very good reason that this facilitates efficient pipeline shipment and inter-company purchases and exchanges to cover refinery problems and demand fluctuations, while reducing bulk transportation costs. However, there are real differences in the additives injected when the tank truck picks up a load of fuel at the distribution terminal, when the fuel becomes some company's branded product. If you own a newer car with a sophisticated engine, spending a little more to get a major oil company's additive package could pay off in better performance and reduced maintenance costs down the line.

But while the company from which you buy your gas might not have refined every gallon themselves, they must still stand behind it, and in my estimation that's the most important extra you're paying for. If you get a tank of bad gas or one blended with 20% ethanol instead of 10% and need to have your car's entire fuel system rebuilt, you stand a much better chance of getting compensated for the repair by a major gasoline brand than an independent or discount station. I consider myself fairly thrifty, but that's worth an extra 5-10 cents per gallon to me. I'll admit to a bias against buying gas from even a big supermarket chain for the same reason.

Finally, in terms of competition, it's ironic that the most viable competitor to gasoline at the moment is another petroleum product, diesel, which has captured half the new-car market in Europe and is getting a closer look here, thanks to some new technology. While biofuels hold great promise, they are still only available in relatively modest quantities, as explained in Friday's posting, and more as "hamburger helper" for traditional fuels than as fully independent alternatives to oil. While ethanol advocates would doubtless take issue with the characterization of E85 as a failure, so far, its sales have probably been hampered more by its poor value proposition--offering fewer miles per dollar than conventional fuels--than by infrastructure constraints and limited numbers of flexible fuel vehicles. In the long run, electricity looks like the strongest challenger, assuming battery prices come down and mainstream consumers find the trade-offs involved in recharging in hours rather than refueling in a few minutes acceptable.

If "Over a Barrel" accurately reflected Americans' frustration at being dependent on a commodity they feel they no longer control, it also highlighted oil's continuing indispensability. Petroleum and its products aren't about to disappear any time soon, though their dominance is starting to slip. From all indications, US oil demand has peaked, and the industry's remaining growth prospects are centered on developing Asia. The pressure to reduce oil consumption in developed countries is growing, and alternatives that were once dismissed will soon erode oil's share of the transportation energy market. However, absent a technology breakthrough, that transition seems likely to stretch out for decades, and it's a virtual certainty that the economics and geopolitics of oil will continue to frustrate us for many years to come.

Speculation and Physical Oil Prices

The story above the fold on the front page of this morning's Wall St. Journal suggested that the Commodity Futures Trading Commission (CFTC) is about to issue a report tying last year's oil price spike to speculation by non-industry participants in the oil futures, options and swaps markets. This would reverse the agency's previous finding that speculation had not played an important role in influencing the record-breaking prices we experienced in 2008. Although I plan to assess the report with an open mind, the dissemination of such contradictory conclusions--separated mainly by the handoff from one administration to another--hints that a jaundiced eye might be in order regarding both. More important than any politics that might be involved, however, is the deeper question of whether the futures-market speculation the CFTC has apparently uncovered actually harmed the real economy by spreading its contagion to the markets for physical oil with which consumers interact. The answer to that question has serious implications not just for the justification of stricter regulation of energy markets, but for overarching policies and trends affecting the production and consumption of real energy.

As I noted in a posting last summer, the growth of the futures exchanges over the last two decades has fundamentally changed oil trading. Most oil is now bought and sold on price formulas pegged to the futures prices, or to published market reports strongly influenced by them. What traders are agreeing to when they do a deal is not a fixed price, but a differential above or below a particular futures contract during a set period, usually aligned with the time when the shipment will be loaded or delivered. So while these differentials fluctuate due to a variety of factors, the price that refiners pay for crude oil remains directly tied to the futures price. That means that anything that drives up the futures market, whether a disruption in supply, higher demand, or speculation by a new class of commodity investors, has a direct impact on what we all pay for the products that refineries make.

When I discussed this issue last summer, I was careful to note that if the prices for physical grades of oil moved in lock step with the futures price, that might not by itself absolve speculators from driving up those prices, along with the futures. Other factors could produce a similar result, even if the futures were mainly driven by speculation. However, when I now look at last year's price relationships for two of the most important crude oil streams in the country, I see evidence that goes beyond a neutral result and undermines the notion that anything other than the fundamentals of supply and demand was driving prices in the run-up to oil's peak of $145 per barrel last July.

The chart below tracks the price difference between two important grades of physical oil and the monthly-average NYMEX futures price for West Texas Intermediate, which is the focus of the CFTC's investigation and the principal grade of oil against which most US oil--and indeed much of the world's--is typically priced. I chose Alaskan North Slope crude and West Texas Sour because both are produced in substantial quantities, are representative of the medium-gravity, medium-sulfur crudes that many US refineries turn into gasoline, and cannot be delivered into the NYMEX WTI contract. While there might conceivably be some degree of speculation in these grades, anyone buying them would be required either to take physical delivery themselves or sell to a refiner or other physical buyer before the oil was delivered. If futures market speculation had been driving the prices of these grades of oil last spring and summer, we'd expect to see their discounts either remain steady or widen, indicating that they were being dragged along by frothy futures. Instead, between March and July 2008 we see these grades strengthening relative to WTI--their discounts shrinking--both sequentially and relative to their average discounts since 2004. In other words, in that period the prices of these grades of physical oil appear to have been stronger than the futures market that was thought to be driving them.



Why is that important? First, the argument for stricter regulation of the commodity markets, beyond the very sensible suggestion to increase the transparency of participants' trading positions, depends on a finding that speculators not only influenced the futures markets in which they participated directly, but also the price of the physical oil purchased by refiners and thus the prices of the petroleum products that consumers, trucking companies, school districts, airlines and others purchased, to the detriment of the economy and our trade deficit. If speculation was driving oil futures but not the price of physical oil, the necessity for clamping down on it aggressively begins to resemble a fever remedy that works by banning thermometers that read above 99 degrees.

Of greater significance, I believe, is the psychological effect on our expectation of oil prices in the future. If we convince ourselves that $145 oil and $4 gasoline were mainly the fault of big, bad speculators, and that regulating them will avert such an outcome in the future, we foster a dangerous illusion that supply and demand will somehow always result in prices more congenial to our preferences and lifestyles. That's arrant nonsense, and you don't have to be an ardent believer in Peak Oil to see how unrealistic expectations of low future oil prices can stimulate demand and stifle expensive oil projects, with their long inherent time-lags. That would eventually lead to precisely the outcome we wish to avoid: much higher oil prices.

Since the summer of 2007 I have been arguing that speculation might have been influencing oil prices around the edges, but that with or without it the narrowing gap between growing demand and straining supply was the main factor behind high prices. The sudden inversion of those forces--the sharp drop in oil demand caused by the recession and the growth of inventory and restoration of adequate spare production capacity--equally and fully explains the price collapse that followed, pummeling exposed speculators and index investors. Whatever the CFTC concludes about last year's price spike, it shouldn't distract us from the necessity of investing in expanding oil production and alternative energy sources, while working hard to improve the efficiency with which we use energy, and particularly oil. Blaming it all on Wall St. would be the quickest way to undermine the gathering momentum for improving our real energy security.

Big Algae?

In spare moments during the last week I've been mulling over the implications of ExxonMobil's announcement of a very large investment in research and development on producing biofuels from algae, in collaboration with a leading biotech firm, Synthetic Genomics, Inc. While the reported figure of $600 million wouldn't buy much in the way of actual deployment, it could sure pay for a heck of a lot of R&D. The joint conference call about the announcement emphasized that the companies will be pursuing several possible technological pathways, though all appear to be focused on producing biofuel from algae continuously, rather than in a batch mode more analogous to farming. That would certainly increase the attractiveness for Exxon, which after all operates some of the world's biggest continuous production processes, in the form of its oil & gas fields, refineries, and chemical plants. The timing of this announcement is also interesting, coming just a few weeks after the US House of Representatives passed the first cap & trade bill to make it through either chamber of Congress.

The fundamental question I've been pondering is "why"? Why algae, and why ExxonMobil? For all of algae's enormous potential to produce large quantities of useful fuel, skepticism that this could ever be done economically on a useful scale abounds. And until now, Exxon had made a virtue of avoiding investments in renewable energy, generally seeing them as delivering returns well below those of the large oil & gas projects that have earned Exxon a sterling reputation for capital discipline. The answer to both questions likely resides in a word that appears frequently in the press release, in news coverage of the announcement, and in the press conference: scale. Two aspects of scale are relevant, here. First, in order to contribute meaningfully to our energy and climate problems, an alternative energy technology must be capable of being scaled up rapidly to a level comparable to today's oil, gas and coal industries. Current biofuels, solar power and wind still don't come close to matching the energy delivery of conventional sources. Exxon's website indicates potential liquid yields from algae of 2,000 gallons per acre, presumably in the form of the hydrocarbon-based "biocrude" emphasized repeatedly in the press conference. Even that relatively conservative estimate--my own back-of-the-envelope upper-bound estimate was 6,000 gal./acre--is at least ten times the current US yield of corn ethanol, after adjusting for energy content. Simplistically, if the acreage currently devoted to growing corn for ethanol were devoted to oil-excreting algae, it could replace nearly 60% of our gasoline supply from crude oil, rather than the 5% or so we get from ethanol.

Scale is also crucial for a firm of Exxon's size. A report in today's Wall St. Journal caught my eye. Occidental Petroleum announced its discovery of a 200 million barrel onshore oilfield in the middle of one of the most mature oil provinces in the world, in the San Joaquin Valley of California. I know that territory very well from my oil trading days, and it's an exciting development. However, Exxon is so big that it must find the equivalent of 8 such fields every year, just to stay even with its production. When I listen to the way Exxon describes its algae investment, I get the distinct sense that it views this arrangement as analogous to a very large oil exploration project, one that would be material to the results of the largest oil SuperMajor--and perhaps with similar odds of success. Now, it would be meaningless and of no value to Exxon if algae could produce the equivalent of hundreds of thousands of barrels per day of oil, but at a cost of $1,200/bbl. Exxon appears to be convinced that algae can contribute at a price very close to today's hydrocarbons, and probably without subsidies, knowing the firm's distaste for them. That has implications beyond algae.

In the conference call, Exxon's VP of R&D indicated that the company had assessed all of the advanced biofuels technologies and concluded that algae offered the best hope for producing fuels that would compete economically, with acceptable environmental impacts. That says something very worrying about the near-term prospects for cellulosic ethanol and the other "second-generation" biofuels technologies on which companies such as BP, Shell, and many others have pinned their hopes. Indeed, the US Congress pinned the whole country's hopes on the prompt commercialization of these unproven technologies in the remarkably ambitious national Renewable Fuels Standard they enacted in late 2007. If Exxon has concluded correctly that algae--which faces many serious hurdles of its own--is the best bet, then the entire US alternative fuels strategy could be in trouble.

There is also another way to look at this announcement. Exxon has been under enormous pressure to take a big stake in renewable energy. I vividly recall a Congressional hearing last year when committee chairman Ed Markey (D-Mass.) berated and belittled the Exxon representative for doing so little in this area. More recently, an environmental group took out full page ads targeting Exxon's opposition to cap & trade. I can't find the ad on the internet, but it said something like, "Poor Exxon, all alone in opposing Waxman-Markey." That has to get old, even for Exxon.

Could the algae tie-up with Synthetic Genomics, with its impressive expenditures contingent on achieving a series of unspecified milestones, be intended mainly to get this particular monkey off their backs? I doubt it, even though all the other advanced biofuel technologies being touted by their promoters also involve a substantial element of PR, until they actually produce commercial outcomes. If Exxon merely wanted to create some "green cred", it could have taken the same money and bought a dozen bankrupt corn ethanol plants or a few medium-sized wind farms. If the Exxon/Synthetic Genomics collaboration is about making Exxon greener, then it is certainly doing it the Exxon way, investing in something that, if successful, would neatly and profitably slot into their existing business model--and by the way into the hundreds of existing refineries and hundreds of millions of internal combustion engine vehicles globally. It's probably too early to imagine Big Oil becoming Big Algae, but the possibilities have obvious appeal, apparently even for the world's most successful oil company.