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.

Energy 2013: More Shifts Ahead?

• 2013 was an eventful year for energy, though perhaps with fewer earth-shaking implications for the future than in other recent years.
• Several developments concerning global oil production, when taken together, improved the odds of lower oil prices in the next several years.

Year-in-review posts have become standard fare for energy blogs; I've written my share in the past. However, while 2013 hardly lacked for interesting energy-related news and events to populate a top-ten list, most fell short of the potential to affect energy markets strongly for years to come.

For example, it is newsworthy that another year has passed without an indication of whether the White House will approve or reject the cross-border permit for the Keystone XL pipeline project. Yet the consequences of that decision are becoming less significant, at least in the reported view of Bakken shale pioneer Harold Hamm. That's due in large measure to the dramatic increase in the transportation of oil by rail, which should be on anyone's top-ten list. Nor is it clear that the EPA's proposal to scale back the Renewable Fuel Standard's (RFS) corn ethanol quota for 2014 will affect more than this year's fuel market, unlike pending Congressional legislation to reform the RFS.  California's adoption of an energy storage mandate for utilities is another notable event, but its long-term impact is contingent on the development of cost-effective storage technology and business models to enable much greater integration of renewable energy on the grid.

Instead of extending that list, I'd like to focus on three stories in which I see significant, related implications for oil markets. The first involves the temporary international agreement concerning Iran's pursuit of nuclear technology. Although relaxation of the sanctions limiting Iranian oil exports depends on a highly uncertain final agreement governing uranium enrichment, the  Arak reactor's plutonium potential, and a more intrusive inspections regime, the interim deal signals that around a million barrels per day of Iran's oil--and eventually more--could be back on the market in less than two years.

If that happens, it won't be because the Iranian government's repeated assurances of its aversion to nuclear weapons have suddenly become credible, but because most of the permanent members of the UN Security Council plus Germany--the "P5 + 1" negotiating with Iran--are tiring of the protracted confrontation and understandably have no appetite to address this in the same way that the collapsing UN sanctions regime for Iraq was resolved in 2003.

Next consider the stunning reversal of the Mexican government's 75-year-old nationalization of oil and gas. As a result of the reforms just enacted by their congress and ratified by a majority of Mexico's states, the state oil company Pemex will be run along more commercial lines, and foreign firms will be allowed to partner with Pemex in developing the country's large untapped hydrocarbon resources. If the terms prove attractive for international energy firms, the result will move North America even closer to net energy independence. Meanwhile the Transboundary Hydrocarbon Agreement between the US and Mexico that was just passed by the US Congress will simplify energy development that straddles the border.

Mexico's potential could be even more significant for oil markets than an unconstrained Iran. The former's production has declined by 24% since 2004--a loss of 900,000 bbl/day-- mainly due to limited reinvestment. Foreign investment can help to restore that output, but the upside potential is much bigger. Pemex has barely scratched the surface of its deepwater resources in the Gulf. Its proven and contingent reserves are estimated at 45 billion barrels, while US estimates put Mexico's shale oil, or "tight oil" resources at 13 billion barrels, slightly more than the country's proved conventional reserves. (Shale gas could exceed 500 trillion cubic feet.)

Mexico's oil output has grown dramatically before. In the decade following the Arab Oil Embargo of 1973 production increased from 500,000 bbl/day to around 3 million. A similar performance seems possible again from a higher starting point, but it's unlikely to happen overnight. As Dan Yergen pointed out in a recent Wall St. Journal op-ed, "exploration and development could take another five to 10 years" beyond the first bid rounds.

And that brings us to Saudi Arabia's options for dealing with a shifting market that will include projected US crude oil output of 9.6 million bbl/day by 2016, the recovery and growth of Iraqi production, possible exports from Canada to Asia, Mexico's potential, and the eventual return of full Iranian exports. Whether or not this wave of new or restored production will be sufficient to replace production declines elsewhere, it must undermine OPEC's control of pricing in this decade. In that light, it's hard to ignore reported indications that Saudi Arabia might abandon its role of swing producer, particularly when it comes to unilateral output cuts to balance new non-OPEC supplies.

Haven't we seen this movie before? After a dozen years of high prices and tight markets OPEC steadily lost market share in the 1980s as new fields in Alaska, Mexico and the North Sea came online. That trend culminated in Saudi Arabia's 1986 "netback pricing" decision, linking the price of its oil to the value of its customers' refined petroleum products. Following the price collapse that policy helped precipitate,  oil prices took 18 years to reach $30/bbl again, by which time the dollar had lost a third of its value.

I doubt we're in for anything that dramatic. Back then, most demand growth came from the developed countries of the OECD, rather than from the expanding middle classes of developing Asia and the Middle East itself. Moreover, today's new production has higher costs--up to $70-80 per barrel--ruling out a return to $20 oil. With many serious geopolitical risks still in play, an oil-price price correction or extended soft market seems likelier than another price collapse. In the meantime, if we're seeking $20 oil, we already have it in the form of US shale gas that averaged the equivalent of $21.64/bbl last year. And that's the early, odds-on favorite for the energy story of the decade.

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