Exporting US Oil to Mexico

• Mexico could become a major export destination for surplus US light crude oil, despite being one of the largest oil suppliers to the US, mainly of heavy oil.
• If structured as an exchange for other barrels, such exports might not require re-writing US oil export regulations, unlike sales to non-neighboring countries.

Two of the biggest energy stories of the last twelve months have been the reform of Mexico's oil sector after 75 years of state monopoly and the US oil industry's drive to gain approval to export a growing surplus of domestic light crude oil. The prospect of exporting US oil to Mexico connects these developments in a surprising way. It should make sense geographically and economically, though regulatory hurdles remain. Yet it could also increase tension between US oil producers and refiners over the merits of exporting crude versus refined products.

At first glance, the idea seems counterintuitive. Our southern neighbor was the third-largest exporter of oil to the US last year, consistently ranking above Venezuela. However, most of Mexico's oil is heavy and sour, in contrast to the light, low-sulfur "tight oil" (LTO) produced from US shale formations like the Eagle Ford of Texas.

Mexico has experienced supply and demand trends similar to what the US saw prior to our shale revolution. Total oil and gas liquids production has fallen by 25% since 2004, largely due to the declining output of Maya crude from the supergiant Cantarell field, while demand for refined products grew by around 20% in the same period. Lightening the crude oil slate of Pemex's oil refineries with LTO imported from the US could augment efforts to increase throughput and yields of transportation fuels.

The Commerce Department's recent approval for two US companies to export lightly-processed condensate, which despite its similarities is technically not crude oil, was followed by a hold on similar applications. These events have fueled both enthusiasm and confusion concerning US oil exports, which are still politically controversial, after decades of declining US production and periodic price spikes.

An easier sell might involve the exchange or "swap" of surplus LTO for imported heavy oil, and Mexico makes an ideal partner for this kind of transaction. Existing law at least recognizes the potential for such swaps with "adjacent countries", though it remains to be seen whether such a deal could be made to fit language specifying that the oil received be of "equal or better quality".

As a former oil trader, it strikes me that the best ways to close that gap might be to structure an LTO vs. Maya swap as a barrel-for-barrel exchange in which the US party would collect a financial premium in recognition of the quality difference--money being another measure of quality--or a "ratio exchange" in which every barrel of LTO delivered would be matched by a larger quantity of Maya, at a proportion determined by the refining values of the two oils. Either option would still require some regulatory finesse, but of a much different type than approving the outright, net export of US oil production.

The biggest stumbling block to an exchange of LTO for Mexican crude would probably be one of the same ones impeding the general lifting of a US oil export ban that the Washington Post has called "an economically incoherent policy." While US oil producers argue that allowing exports would enable their product to be sold for its global value and incentivize even higher future production, US oil refiners see exports as a threat to their margins and to the growth of their own exports of refined products. These have been crucial in sustaining arguably the world's best refining industry in the face of a weak economy and declining demand at home. 

Mexico is at the heart of this trend. Its imports of LPG, gasoline, diesel and other fuels from the US have increased to over 500,000 barrels per day (bpd) in recent years. Mexico accounted for 44% of all US gasoline and gasoline blending components exported last year, along with 10% of diesel fuel exports and 15% of LPG. I don't think it's controversial to suggest that exporting light crude oil to Mexico would come at least partly at the expense of our refined product exports to the country.

This boils down to the familiar economic dilemma of exporting raw materials versus capturing the value added from selling manufactured goods. I'm sympathetic to the refining industry's concerns, and not just as a former refinery engineer. However, those concerns would carry more weight if US refineries had the capacity to process all of the LTO the US is likely to produce in the years ahead, and to pay a world-market price for it. Refiners might benefit from access to lower-priced crude, but if driving down the value of LTO in a confined market choked production, net US oil imports would be higher than otherwise and the economy would be worse off.

Stepping back from the details of that debate, exporting US light crude oil in exchange for Mexican heavy crude looks attractive within a broader and increasingly credible vision of North American energy self-sufficiency. That wouldn't mean cutting North America off from the global oil market, but it would put us and our neighbors in the enviable position of being able to select imports based on opportunity rather than necessity. A reformed and revitalized Mexican oil industry, importing and exporting oil with its neighbors as it makes sense, could be a cornerstone of that vision.

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

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.

Defining Speculation

Oil market speculation is back in the news, because Vitol S.A., one of the world's largest oil-trading firms, has apparently been re-classified as a "non-commercial" market participant by the Commodity Futures Trading Commission (CFTC). That marks them as a speculator, this year's scarlet letter. Before we pass judgment on the influence of such firms on the price of oil, and thus on the petroleum products consumers buy, it's worth considering what we really mean by speculation, and how this might be distinct from the activities of the participants that the CFTC deems "commercial", i.e. those conducting futures, options and swap transactions in conjunction with their physical production or consumption of various forms of energy. More importantly, we should evaluate whether speculation is an important enough factor in the oil market to merit distracting us from the urgent pursuit of solutions that would expand energy supplies and shrink demand.

As big as they are, Vitol hardly fits the profile of the kind of speculators that stand accused of driving up the price of oil and everything connected to it to unprecedented levels. Vitol has been trading oil since the 1960s, and I did my first deal with them in the 1980s, when I traded petroleum products for Texaco's West Coast refining and marketing subsidiary. I got a much better sense for just how large a player they were in the physical markets for oil, feedstocks and refined products when I traded international products in London in 1989-91. There were few markets in which Vitol didn't participate, and a few niches that they dominated. Although I haven't had any contact with them in at least 14 years, their growth during that interval has been impressive. So I was hardly shocked to learn that they had apparently accounted for a significant fraction of the open interest in crude oil on the New York Mercantile Exchange (NYMEX) earlier this year. Any non-producer transacting the volumes of physical oil and products deals they do could not manage their business properly without extensive use of futures, options and over-the-counter swaps, little of which could fairly be called speculation.

Texaco's trading division had very firm rules about speculation on futures or options, which it defined as long or short positions that weren't directly linked to a like quantity of physical oil or products we were buying, selling, or holding in inventory, contemporaneously. Even for a group focused on "wet" cargoes--actual liquids on ships, barges, or in pipelines--that was sometimes limiting, because it meant we had to do the physical transaction first, and then scramble to hedge it. But while we couldn't take "naked" long or short positions in the market, we could transact "spreads" that were basically bets on some aspect of the market, such as a widening or narrowing of the price difference between futures contract months, or between different products, or different locations. While we weren't speculating on the absolute price, risking large swings in profit and loss, we were certainly risking smaller amounts on these other market attributes. I think most people would consider that speculation, since we didn't have to do it to support our physical trading or the company's much larger producing and refining businesses. But aside from some modest, inconsistent profits it gave us insights into market trends that passive observers don't usually gain: if you really want to understand a market, you have to be in the market.

Now consider Vitol, buying and selling oil and product cargoes all over the world and owning interests in oil terminals on three continents, a few oil fields, and a small refinery in the Persian Gulf. That doesn't put them in the same league as ExxonMobil--which, unless things have changed a great deal since the Exxon-Mobil merger in 1999, doesn't trade on the NYMEX at all--or legitimize every position they take as non-speculative. However, it's a far cry from the stereotypical view of asset-class commodity speculation by pension funds and hedge funds, executed by twenty-somethings who wouldn't know an octane from an antelope. That's important, because long-established oil trading firms like Vitol have institutional memories that span many up and down cycles of the oil market and know that a trend can turn when you least expect it. It doesn't mean they wouldn't risk a big loss to make a big profit, but in my estimation it makes them poor candidates to be the driving force behind a wave of speculation perceived to have pushed the price of oil beyond the level that could be explained by the fundamentals alone.

The roughly 20% drop in oil prices since the beginning of July should calibrate our estimates of the influence of such speculation. It was clearly not sufficient to maintain momentum in the face of weakening fundamentals of demand, supply and risk. At the same time, our response ought to distinguish between the kind of speculation represented by oil market neophytes hoping to cash in on an attractive investment trend, and the speculation that is an absolute requirement of a smoothly-functioning commodities market. Anyone who thinks the oil market would work just fine with only producers, refiners and end-users has never spent a day trading, or seen liquidity vanish just when a specific transaction was most desirable or necessary, because there was no middleman willing to take it on as a bet. But regardless of whether one variety of speculation should concern us more than another, the market's dramatic response to sliding demand serves notice to policy makers that their best and most productive avenue for addressing the impact of high oil prices is surely prompt and meaningful action on supply and demand, rather than rounding up today's version of the usual suspects.

Market Memory

Sometimes I wonder if the greatest flaw in the global oil market is that it has such a precise memory. Anyone with an internet connection can see what the price of oil was in New York fifteen minutes ago, and then view another website and track its movements all the way back to a Wednesday in March twenty-five years ago when the NYMEX West Texas Crude Oil (WTI) contract began trading. The problem with this is that, because the market can't forget, and because each moment's price is set with reference to the previous price, there is little opportunity for the market to catch its breath, weigh all of the fundamentals, and arrive at today's price from scratch. As a result, any distortions that creep in take a while to be expunged, if they ever truly are.

Most days I am grateful that I am no longer an oil trader, with one eye always glued to a screen displaying the gyrations of the global energy commodity exchanges. It's not good for one's health, even if you have a calm disposition. That's especially true these days, when a single news item can send the entire market up or down by as much as $4 per barrel from a starting point over $100/bbl. The process was different when I traded crude oil on the West Coast in the late 1980s. Although the NYMEX contract was becoming a bigger factor in the pricing of physical grades of crude oil, such as the cargoes of Alaskan North Slope crude I bought for Texaco's Los Angeles and Anacortes, WA refineries, it was still quite common to buy and sell pipeline quantities of oil at a premium or discount to posted prices--periodically-updated fixed prices at which refiners or traders solicited producers to sell them oil--or as often as not, at a fixed price unique for that deal on that day, e.g., $17.21/bbl for 2,000 bbl/day of Buena Vista Light during April 1987. (It's getting hard to believe oil was ever that cheap.)

Because of the way such deals were struck, a trader and the refinery for which he was buying had to have a very clear sense of the intrinsic value of that oil, either in terms of the products into which it could be refined, or the price at which it could be resold before delivery, if requirements changed. This process involved significant risks that could not easily be hedged, then. The stakes were high enough that, unless the counterparty was a long-term, reliable supplier or customer, deals could fall apart over a difference of 5 cents per bbl. Without suggesting that traders today are any less diligent or astute, I believe a market in which most prices are set with reference to WTI, Brent, or some other ultra-transparent exchange-traded marker entails less accountability for ensuring that the price involved is reasonable, rather than defensible--i.e., "Well, I paid the market price for it."

In a popular film of a few years ago, "Memento," the protagonist had an unusual form of amnesia and woke up each morning without any clear recollection of the previous day. He had to rely on notes he had previously scribbled to himself. What if the oil market worked that way, and each day, traders had to re-establish the price of oil from scratch, relying only on the fundamentals of supply, demand and inventory? A classical economist might suggest that the result would be no different, because the market price is merely the level at which supply and demand are balanced, every day. I'm less sure things are that simple, and I suspect that the practitioners of behavioral economics might be skeptical, as well. For example, yesterday's increase in the price of WTI to $111/bbl in response to an unanticipated 3 million bbl drop in US crude inventories only makes sense if you accept that $108/bbl accurately reflected all of the market factors before that news. However, a similar overall configuration of global inventory and spare production capacity in 2005 yielded prices in the mid-$50s to mid-$60s. $111 makes more sense as the net sum of three years of individual price movements, than as the bottom-up evaluation of all the factors in today's market.

I recently received a copy of an academic paper by a Ph.D. candidate at the University of Michigan and his professor. It tackles the question of whether the oil futures market provides a reliable forecast of future oil prices and finds that it does not. Even my view that it is a good indicator of current expectations of future prices seems shaky, in their analysis. Taken together with my concern that the market may be influenced more by its own price history than it ought to be, I conclude that decision makers, policy makers, and consumers would be well-served to take a somewhat more jaundiced view of that daily WTI settlement price that the media has grown so fond of displaying. Its impact on fuel prices and on our trade deficit is certainly real and tangible, but it might not be telling us as much about the world and the future as we have come to believe.