The Return of Iran's Oil

• If approved by all parties the negotiated nuclear agreement with Iraq could affect energy markets both directly and indirectly.
• By adding to the current global oil glut, it would make big oil projects elsewhere riskier, while undermining outdated restrictions on US oil exports.

The signing of a nuclear agreement between Iran and the five permanent members of the UN Security Council plus Germany represents more than a geopolitical milestone. In the context of today's lower oil prices it puts additional pressure on near-term prices, but perhaps more importantly creates the potential for significant shifts within the oil industry. Iran's expanded exports--once the conditions of the deal are met--will arrive in a market quite different from the one that prevailed when they were restricted in early 2012.

These differences include an OPEC that is now engaged in a contest for global market share, rather than one focused on maintaining oil prices at around $100 per barrel. This is the cartel's response to the rapid growth of non-OPEC production, mainly from US shale, or "tight oil" formations. Based on data from the International Energy Agency, non-OPEC production has increased by 5 million barrels per day (bpd) since 2012, while global demand has grown by just 3 million bpd.  The return of anywhere from 600,000 to 1 million bpd of Iranian exports would expand a global oil surplus and intensify competition.

 Iran's oil traders may find that placing additional volumes with refiners will not be as easy as it would have been just a few years ago. As the Wall Street Journal noted, the likeliest home for most of this incremental supply is in Asia, where competition between Saudi, Iraqi and Russian barrels is already keen. China and India have been the largest purchasers of Iranian oil during the sanctions (see chart below) but Iran is not the only producer seeking to expand its output of similar crude oil.  

 

Oil prices have two main dimensions, only one of which is widely understood outside the industry. Media reports focus on the absolute price level, particularly for benchmark grades such as Brent and West Texas Intermediate (WTI). However, differentials--the gaps in price for oils of different quality, or of similar quality in different regions--are nearly as important for producers and often more so for refiners.

Iranian oil is mainly sour (high in sulfur) and so competes principally with other sour grades, including those from Saudi Arabia, which is already at record output, and Iraq, where production is approaching 4 million bpd, compared with just under 3 million in 2012. OPEC's other big producers seem no more inclined to cut output to make room for extra Iranian oil than they were to accommodate surging US tight oil. Meanwhile, refineries in Europe, where sanctions on Iranian oil had the largest impact, are also "spoiled for choice" with various crude streams displaced from US refineries by the shale revolution.

If Iran's restored exports keep oil prices lower for longer, they are also likely to widen the "sweet/sour spread", or premium for light sweet crudes like those produced in the Bakken and Eagle Ford shales, over sour crudes like Saudi medium or Iranian heavy. That would lend greater urgency to calls for an end to 1970s-vintage restrictions on exporting US crude oil, because it would expand the potential economic opportunity for US exports.

As a result of opening the taps in Iran, we could also see deeper shifts in the structure of the global oil industry. OPEC's current production policy may be targeted at US shale, but shale producers have proven themselves much more adaptable than expected to prices in the $50-60 range. The same cannot necessarily be said for new conventional oil projects with price tags in the hundreds of millions to billions of dollars. 

Barring another shift as dramatic as the one that rippled through oil markets last fall, we may have witnessed the end of an era in which low-cost producers in OPEC held back production to drive up prices and, in the process, made room for much higher-cost production elsewhere. Iran appears poised to go beyond its pre-sanctions exports by inviting international investment in new developments that would be profitable at current prices.  If Iran's terms are attractive, the losers won't be shale producers that operate at dramatically lower scales of investment and risk per well, but big projects in places like the North Sea, which has already seen a wave of project cancellations. The recent lackluster Mexican bid round might be another signpost.

Could we end up in a few years with a global oil industry in which prices would be determined mainly by a new balance between a resurgent OPEC and US shale producers? That would be a very different world than we have experienced recently, and probably one with more price volatility.

Of course before any of this could happen, the nuclear agreement with Iran would have to go into effect and be widely seen to be holding. For anyone who recalls the periodic inspection crises with Iraq in the late 1990s, that can't be a foregone conclusion, even if the agreement survives review by a US Congress that asserted its right to scrutinize the deal's provisions and includes some surprising skeptics.

 

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

The Pros and Cons of Exporting US Crude Oil

• Calls for an end to the effective ban on exporting most crude oil produced in the US are based on a growing imbalance in domestic crude quality.
• At least recently, the ban has likely benefited refiners more than consumers. Assessing the impact of its repeal on energy security requires further study. 

Senator Lisa Murkowski (R-AK), the ranking member of the Senate Energy & Natural Resources Committee, issued a white paper earlier this month calling for an end to the current ban on US crude oil exports. Her characterization of existing regulations in this area as "antiquated" is spot on; the policy is a legacy of the 1970s Arab Oil Embargo. However, not everyone sees it the same way, either in Congress or the energy industry.

This isn't just a matter of politics, or of self-interest on the part of those benefiting from the current rules. Questions of economics and energy security must also be considered. The main reason these restrictions are still in place is that for much of the last three decades US oil production was declining. The main challenges for the US oil industry were slowing that decline while ensuring that US refineries were equipped to receive and process the increasingly heavy and "sour" (high sulfur) crudes available in the global market. The shale revolution has sharply reversed these trends in just a few years.

No one would suggest that the US has more oil than it needs. Despite the recent revival of production, the US still imported around 48% of its net crude oil requirements last year. Even when production reaches its previous high of 9.6 million barrels per day (MBD) as the Energy Information Agency now projects to occur by 2017, the country is still expected to import a net 38% of refinery inputs, or 25% of total liquid fuel supply. The US is a long way from becoming a net oil exporter.

The driving force behind the current interest in exporting US crude oil is quality, not quantity, coupled with logistics. If the shale deposits of North Dakota and Texas yielded oil of similar quality to what most US refineries have been configured to process optimally, exports would be unnecessary; US refiners would be willing to pay as much for the new production as any non-US buyer might. Instead, the new production is mainly what Senator Murkowski's report refers to as "LTO"--light tight oil. It's too good for the hardware in many US refineries to handle in large quantities, and for most that can process it, its better yield of transportation fuels doesn't justify as large a price premium as for international refineries with less complex equipment.

As a result, and with exports to most non-US destinations other than Canada or a few special exceptions effectively barred, US producers of LTO must discount it to sell it to domestic refiners. Based on recent oil prices and market differentials, producers might be able to earn as much as $5-10 per barrel more by exporting it. Meanwhile the refiners currently processing this oil are enjoying something of a buyer's market and are able to expand their margins. The export issue thus pits shale oil producers and large, integrated companies (those with both production and refining) such as ExxonMobil against independent refiners like Valero.

Producers are justified in claiming that these regulations penalize them and threaten their growth as available domestic refining capacity for LTO becomes saturated. Additional production is forced to compete mainly with other LTO production, rather than with imports and OPEC.

I believe producers are also largely correct that claims that crude exports would raise US refined product prices are mistaken. The US markets for gasoline, diesel fuel, jet fuel and other refined petroleum products have long been linked to global markets, with prices especially near the coasts generally moving in sync with global product prices, plus or minus freight costs. I participated in that trade myself in the 1980s and '90s. What's at stake here isn't so much pump prices for consumers as US refinery margins and utilization rates.

Petroleum product exports have become a major factor in US refining profitability, and refiners are reportedly investing and reconfiguring to enhance their export capabilities. This provides a hedge against tepid domestic demand. Nationally, refined products have become the largest US export sector and contributed to shrinking the US trade deficit to its lowest level in four years.  If prices for light tight oil rose to world levels US refineries might be unable to sustain their current export pace. It's up to policymakers to assess whether that risk is merely of concern to the shareholders of refining companies or a potential threat to US GDP and employment.

The quest to capture the "value added"--the difference between the value of manufactured products and raw materials--from petroleum production is not new. It helped motivate the creation of the integrated US oil companies more than a century ago and impelled national oil companies such as Saudi Aramco, Kuwait Petroleum Company, and Venezuela's PdVSA to purchase or buy into refineries in Europe, North America and Asia in the 1980s and '90s.

On the whole, OPEC's producers probably would have been better off investing in T-bills or the stock market, because the return on capital employed in refining has frequently averaged at or below the cost of capital over the last several decades. It's no accident most of the major oil companies have reduced their exposure to this sector. When today's US refiners argue that it is in the national interest to preserve the advantage that discounted LTO gives them they are swimming against the tide of oil industry history.

The energy security case for crude exports looks harder to make. An excellent article from the Associated Press quoted Michael Levi of the Council on Foreign Relations as saying, "It runs against the conventional wisdom about what oil security means. Something seems upside-down when we say energy security means producing oil and sending it somewhere else."  The argument hinges on whether allowing US crude exports would simultaneously promote more production and increase the pressure on global oil prices. That makes sense to me as a former crude oil and refined products trader, but it will be a harder sell to Senators, Members of Congress, and their constituencies back home.

The politics of exports may be easing somewhat, though, as a Senate vacancy in Montana could lead to a new Chair at Energy & Natural Resources who would be a natural partner for Senator Murkowski on this issue. (That shift may incidentally be part of a strategy to help Democrats retain control of the Senate.) Will that be enough to overcome election-year inertia and the populist arguments arrayed against it?

As for logistics, the administration could ease the pressure on producers without opening the export floodgates by exempting the oil output from the Bakken, Eagle Ford and other shale deposits from the Jones Act requirement to use only US-flag tankers between US ports. That could open up new domestic markets for today's light tight oil, while allowing Congress the time necessary to debate the complex and thorny export question.

Senator Murkowski wasn't alone in calling for an end to the oil export ban. In his annual State of American Energy speech presented the day as the Senator's remarks, Jack Gerard, CEO of the American Petroleum Institute, noted, "We should consider and review quickly the role of crude exports along with LNG exports and finished products exports, because of the advantages it creates for this country and job creation and in our balance of payments." In a similar address on Wednesday, the head of the US Chamber of Commerce stated, "I want to lift the ban. It's not going to happen overnight, but it's going to happen."  I'd wager he at least has the timing right.

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

Canada: From Energy Supplier to Competitor?

• In addition to its impact on global oil and natural gas pricing and trade, the shale revolution is altering the energy relationship between the US and Canada.
• This long-standing supplier/customer relationship is becoming more complex as producers in both countries seek new markets outside North America.

In remarks last month the Canadian Natural Resources Minister, Joe Oliver, suggested that with the continued growth of unconventional oil production in the US, "Our only customer will become a competitor." Considering plans for liquefied natural gas export facilities on both sides of the border, he might have included LNG in that comment, too. Let's take a look at the kind of competition he might have had in mind.

Canada has long been an important supplier of crude oil to US refineries, since at least the 1950s. For much of the 1980s and '90s it was in a virtual three-way tie with Mexico and Venezuela for the #2 spot on the list of top oil exporters to the US, behind Saudi Arabia. Since 2004 Canada has claimed first place on that list as its production expanded, while Mexican and Venezuelan output declined and some Saudi oil went to other markets. From 2010 to 2012 exports of Canadian crude oil to the US, including oil sands crude, increased by 23% to over 2.4 million barrels per day (bpd). This has provided Canada with a reliable outlet for its production and the US with additional supplies not exposed--except for price--to ongoing instability in the Middle East and other regions.

However, with or without the Keystone XL Pipeline, the competition to feed US refineries is becoming more intense.  Canada's growing crude exports, including significant quantities of heavy and/or sour crude oil, must displace similar crudes imported into the US from  Latin America and the Middle East without losing ground to the expanded light oil production from US shale plays such as the Bakken and Eagle Ford, and the otherwise mature Permian Basin of Texas and New Mexico. Each of these areas now yields a million bpd. These dynamics are compounded by 1970s-vintage US oil-export rules that keep domestic crude bottled up in the Gulf Coast and weaken the economics of oil production throughout much of North America. 

If it seems odd for a Canadian official to talk about competition within the US market in this way, consider that the main country exempted from current US oil export restrictions is Canada. US oil exports to eastern Canada by rail and by tanker have grown rapidly in the last two years and are likely to expand beyond the current 100,000 bpd level, if export license applications are any indication. US oil exports to Canada may be displacing non-North American crudes today, but they likely also have an adverse effect on the economics of projects intended to ship more western Canadian crude eastward. So Canada now understandably looks towards Asia, home to the world's fastest oil-demand growth, as the logical destination for at least some of its future oil production.

 Natural gas creates another, perhaps more plausible arena for export competition between Canada and the US. Canada envisions a resurgence in gas production similar to what the US has experienced, based on a combination of conventional gas discoveries, such as in the Mackenzie Delta of the Northwest Territories, as well as the shales of Alberta and British Columbia. It also stands to gain additional gas reserves if it is successful in its bid to claim more of the Arctic. As Canadian gas is displaced from its long-standing export market in the US by the shale boom in the lower-48, LNG exports from B.C. are looking more attractive. The province lists five projects in different stages of development and highlights B.C.'s advantageous shipping route to Asia.

Many more LNG export projects have been proposed for the US, with at least four having received approval to sell to countries with which the US does not have free-trade agreements. A number of these are based on existing, or at least previously permitted, LNG import facilities, giving developers a head-start on construction. The US also has a big edge in proved natural gas reserves and technically recoverable gas resources, including shale gas.

Despite these US advantages, aspiring Canadian LNG exporters won't have to contend with an enormous domestic market for their gas, in which many industries are competing to use more gas in power generation, chemicals and other manufacturing, and different paths for displacing oil from transportation, including CNG, LNG, methanol, ethanol or gas-to-liquids fuels. As a result, I suspect that a Canadian LNG plant could count on a more stable long-term cost of gas than one on the US Gulf Coast.

The protracted controversy over the Keystone XL Pipeline project has focused a great deal of public attention on a single aspect of our energy relationship with Canada, while obscuring other aspects that are beginning to shift. Adding a new competitive overlay to our long-standing energy supply chains could ultimately increase North American leverage on OPEC's pricing power, while helping to develop a deeper and more flexible global market for LNG, with resulting environmental benefits. While this might result in winners and losers at the project and company level, the overall effect should be positive for both countries.

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

Will the Keystone XL Decision Be Based on Incorrect Assumptions?

• Some of the facts about the Keystone XL pipeline project that President Obama cited in an interview last month turned out to be wrong. That's significant, if he is the ultimate decision-maker on this question.
• Whatever his assessment of the pros and cons of the project, the politics of Keystone are trumping the facts, indicating the decision is likely to be deferred as long as possible. 

When President Obama commented on the merits of the Keystone XL pipeline project in an interview in the New York Times last month, the Washington Post suggested that his remarks “give opponents reason for hope.” Although he confirmed that the White House’s main objective criterion for making this decision was still the pipeline’s greenhouse gas impact, the President also speculated about the project’s job-creation potential and the ultimate destination of the crude oil it would carry. This appeared to endorse arguments raised by opponents of the project. These issues deserve more than the dismissive treatment they received in the interview.

With regard to the number of direct construction jobs that the northern leg of the Keystone XL Pipeline (KXL) might create, I don’t know whether the right number is the 2,000 the President cited or the tens of thousands estimated in an earlier State Department study. However, fact checking by both PolitiFact and AP concluded he was wrong.

In any case, this administration lacks credibility on counting such jobs. Consider the White House's metric of “jobs created or saved” for assessing the impact of the 2009 stimulus, or the routine touting of projects with “green jobs” potential, not just in terms of their direct employment gains, but also their indirect job creation estimated via generous multiplier effects. Either indirect jobs are always relevant, in which case KXL would create far more jobs across the economy than the President seems willing to admit, or they also aren’t relevant to justifying clean energy and other, more favored infrastructure projects.

The more interesting issue Mr. Obama brought up relates to the disposition of the oil-sands crude that the KXL would ultimately carry from Alberta to the Gulf Coast. For starters, this isn’t relevant for whatever volume of North Dakota production the pipeline might also carry, since current rules prohibit its export to anywhere except Canada. Of the pipeline’s planned capacity of 830,000 barrels per day, some would be used to ship US crude to US destinations, some would carry Canadian  oil destined for US refineries in the mid-continent, while an unspecified remainder would arrive at the Gulf Coast.  However large the latter figure might be, it’s doubtful that much of it would ever leave these shores. To understand why, you need to consider the quantity of US oil imports of similar quality currently coming into the Gulf.

Overall, Gulf Coast crude oil imports have fallen by around a third since 2007, but they still amount to around 4 million barrels per day – 5x the total capacity of the KXL. Unsurprisingly, much of the crude imported into the Gulf is either sour or heavy, since the refineries in the region have invested billions of dollars in the hardware required to process such crudes, which are typically cheaper than lighter, sweeter grades. A quick glance at the countries of origin of the import mix confirms this, with suppliers such as Mexico, Saudi Arabia, Venezuela, and Iraq dominating recent imports. Imports from Algeria, Angola, and Nigeria have been slashed by surging production of light, sweet crude in Texas and other states.

In the interview, President Obama said, “So what we also know is, is that that oil is going to be piped down to the Gulf to be sold on the world oil markets, so it does not bring down gas prices here in the United States.” For him to be right about that, we must believe that the current importers of around 2.7 million barrels per day of generally similar crude from South America and the Middle East would ignore the arrival in their market of new supplies from Canada and continue to buy from existing suppliers, and that those other suppliers would be able to continue to charge the same prices as before, despite significant new competition. Although I wouldn’t argue that oil sands crude would never be exported from the Gulf, imagining that most of it would simply sail right by the closest and largest global refining center equipped to handle this type of crude oil reflects a remarkably superficial view of how oil markets actually work.

The Keystone XL decision process clearly encompasses both factual and political considerations.  On the facts alone and the criteria set by the administration, the pipeline would eventually have to be approved, since even in the worst realistic case its impact on global greenhouse gases would be minimal--on the order of 0.4% of global emissions--while it offers clear benefits including reliability of supply. The protracted delays in approving this project provide all the evidence needed to confirm that political considerations outweigh the facts. Deciding now in favor of either side offers limited political benefits but carries huge risks; continuing to leave the issue in suspense has paid dividends at little apparent political cost.

A different version of this posting was previously published on Energy Trends Insider. 

Could US Oil Trends Alter How Oil Prices Are Set?

• Oil prices weren't always set by a transparent global market. Current pricing mechanisms emerged from much less transparent precursors.
• Resurgent US production, combined with restrictions on US oil exports, could disconnect the US from the global oil market, with unexpected results.

If you follow energy closely, you've likely lost count of the number of times you've heard an economist, executive or government official explain that oil prices are set by the global market, and not by oil companies or the US government.  Although somewhat over-simplified, this statement has been valid for roughly 30 years.  However, it hasn't always been the case. Current trends in US production, together with existing regulations, make me wonder if it will remain accurate in the future, as the US inches closer to what is commonly referred to as energy independence. 

The market-based system of oil prices, with its transparency and easy trading among regions, didn't appear overnight.  Until the early 1970s, Texas played a role similar to Saudi Arabia's current swing producer role within OPEC.  By limiting the output of the state's oil wells, the Texas Railroad Commission effectively determined the global price of oil--to the extent there was one--until Texas had no spare capacity left.  That set the stage for OPEC, a succession of oil crises, and the US oil price controls that were imposed in the 1970s in an attempt to help manage inflation. There was also no single, representative oil price.  Instead, prices were set by producers' contract terms and the discounts large refiners could negotiate, or by federal regulations.  The current system emerged from a series of developments in the 1980s.

When US oil price controls ended in 1981, oil futures trading was just getting underway on the New York Mercantile Exchange.  The heating oil contract was launched in 1980, followed by the West Texas Intermediate (WTI) crude oil contract in 1983. This combined large-scale oil trading with an unprecedented level of transparency.   It was also significant that the US, the world's biggest oil consumer, had become a major oil importer after domestic production peaked in 1970.  Because refineries on the coasts competed for oil supplies with refiners on other continents, the price of WTI couldn't get too far out of line with imported crudes without creating arbitrage opportunities for traders.  And any part of the US connected by pipeline to the Gulf Coast was effectively linked to oil prices in Europe, the Middle East and Asia.

After OPEC miscalculated the response to the very high prices its members were demanding in that period--reaching $100 per barrel in today's dollars--global oil demand shrank by nearly 10% from 1979 to 1983, while non-OPEC production grew by more than 12%.  Prices soon collapsed, and OPEC's dominance of oil markets faded for most of the next two decades, during which the futures exchanges and trading relationships of the modern oil market took hold. 

What could shake the current system of oil prices?  It has already withstood recessions, wars in the Middle East, the collapse of the Soviet Union, and the explosive growth of Asia, with China alone adding oil demand comparable to that of the EU's five largest economies.  However, since the current system is based on the free flow of oil between regions, anything that impedes that flow could undermine the way oil is currently priced.

Setting aside conflict scenarios, consider the potential impact of sustained growth in US production, combined with flat or declining demand and no change in the current prohibition on most US crude oil exports.  The gyrating differential between WTI and UK Brent crude, reflecting rising production in the mid-continent and serious logistical bottlenecks, provides a glimpse of what this could be like.  With much of the new US production coming in the form of oils lighter than those for which most Gulf Coast refineries have been optimized, keeping rising US crude output bottled up here could result in US crude prices diverging even farther  from global prices, while forcing US refineries to operate less efficiently and import and export more refined products.  With oil imports drastically reduced and oil exports still banned, US oil prices might be influenced more by the global market for refined products, with its different dynamics and players, than by the global crude oil market .

In some respects, that sounds a lot like what many politicians and "energy hawks" have been seeking for years: a US no longer subject to foreign oil producers' price demands.  Yet this same scenario could yield all sorts of unintended consequences, including a less competitive US refining industry and higher or at least more volatile prices for gasoline, diesel and jet fuel.  And just as we've seen with cheap natural gas, cheaper oil could undermine the economics of the unconventional oil and gas production that makes it possible in the first place. 

US oil export policy merits a thorough reevaluation, and soon, because the regional impacts of a continued no-export stance could become pronounced, even if the US never reached overall oil self-sufficiency. Such a review should include related regulations, such as the Jones Act restrictions on shipping. With crude oil exports to Canada -- virtually the only allowed export destination for our newly abundant crude types--already rising rapidly, some Canadian refineries may be positioned to supply US east coast fuel markets more cheaply than refineries in New Jersey.  That certainly qualifies as an unintended consequence.

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

Should the US Become An Oil Exporter, Again?

Last week I missed attending a fascinating panel on the growth of US oil production, hosted by  the New America Foundation in Washington, D.C. Fortunately, I was able to catch most of the live webcast, which is still available for replay. Much of the discussion focused on the potential of new "tight oil" production techniques, similar to those used to extract shale gas, to help usher in a new period of relative oil abundance.  If this comes to pass, among other things it could challenge long-established views about exporting US oil.  The politics of oil exports look absolutely dire at the moment, but the economic and logistical benefits--not just for oil companies but to the nation--are such that we shouldn't dismiss the possibility lightly.

Two hours was not enough time to do justice to all the ramifications of resurgent US oil production, and I know from following the Twitter feed for the event that some in the web audience were frustrated by the limited attention given to the climate implications of these developments.  However, if you'd like an overview of the possible economic and geopolitical impact of the US becoming more self-sufficient in petroleum for at least the next decade or two, this stellar panel was highly informative and worth your time.  Much of the discussion focused on tight oil, liquid hydrocarbons trapped in rocks that can't be economically tapped by conventional drilling, but that have proved susceptible to combinations of horizontal drilling and hydraulic fracturing similar to those that have unleashed the current shale gas boom. Although the full potential of this resource hasn't been reflected in the latest forecasts from the Energy Information Agency (EIA) of the US Department of Energy, the results from the Bakken shale in the Dakotas and the Eagle Ford shale in Texas are instructive.  Together these two fields now produce around 750,000 barrels per day, or 12% of current US crude oil output, up from just a trickle a few years ago.  They also hold billions, and possibly tens of billions of barrels of recoverable resources.

I was a little surprised that the first panelist to mention the possibility of exporting some of this oil--with appropriate caveats--was Adam Sieminski, the newly confirmed EIA Administrator. After all, current US law restricts the export of most US crude oil production, with special exceptions for some oil from Alaska, California, and near the Canadian border.  In practice, crude exports from those fields have declined to very low levels.  Despite that, and even after significant reductions in imports since the onset of the recession, the US is still a major net oil importer.  If that's the case, and if US refineries can benefit from the increasing domestic output, why would we even consider exporting any of this new oil?

Unfortunately, the answer doesn't reduce to a neat soundbite; it depends on two key factors that require a bit of explanation.  The first issue is the quality of the oil coming out of these tight oil plays, which at least so far has been very high. Oil from different fields varies as much as fingerprints, even when we consider only a few characteristics of concern to refiners, and these differences strongly influence the market values of the various grades of oil.  Light crudes refine easily into valuable products like gasoline, diesel and jet fuel, while heavier crudes require more processing, using more expensive hardware, and often yield large quantities of low-value products like petroleum coke, even after intensive refining. There's also sulfur content--the sweet to sour spectrum that overlays the light/heavy distinctions--as well as other impurities.  Eagle Ford crude is light and sweet, as is the North Dakota Sweet crude produced from the Bakken. These crudes compare favorably with West Texas Intermediate (WTI), Brent and other premium crude streams.

The second, related factor involves the complexity of US oil refineries and the crude diet they've evolved to run. As production of high quality crudes in the continental US declined over the last four decades, many refiners invested billions of dollars to enable their facilities to run some of the heaviest, most sour crudes from around the world, because these were more readily available and usually significantly cheaper than the light sweet crudes.  This trend was particularly evident on the West Coast and Gulf Coast. The addition of complex processing hardware like hydrocrackers, delayed or fluid cokers, and residuum fluid catalytic crackers has given these refineries tremendous flexibility, but it also increased their operating costs and made it harder for them to go back to a diet of much lighter crudes.  As a result, while many of them could handle significant quantities of light crude from the tight oil fields, this would be less than optimal, resulting in economic penalties and perhaps eroding the advantages that have recently enabled gulf coast refiners to capitalize on export markets for their products. Those penalties would translate into discounts for the tight oil grades, compared to similar international crudes, much like the large gap in value we currently see for WTI compared to Brent, though for different reasons as discussed previously.

At current production levels, the mismatch of quality and capabilities isn't as big a problem as the lack of infrastructure for transporting these crudes to market.  That has resulted in discounts so large that it makes sense for private equity firm Carlyle to plan to ship large quantities of Bakken crude by rail from North Dakota to the Philadelphia refinery they've just acquired from Sunoco.  However, if tight oil output grows in line with forecasts such as those in a recent analysis from Citibank, domestic sweet crude refiners will have more than enough supply and the excess must either be sold to heavy crude refineries at a discount or left in the ground.  That's where exports come in. 

The last time exporting domestic crude became a big issue was in the late 1980s, when output from Alaska's North Slope (ANS) field reached peak levels of roughly 2 million barrels per day, far more than west coast refineries could absorb. I was trading crude on the West Coast at the time, and I observed first-hand the effects of the export restrictions that had been put in place when the Trans Alaska Pipeline was originally approved.  Those restrictions didn't just depress the price of ANS crude; they also depressed the price of the California crudes with which ANS competed, and made both types less attractive to produce. West coast consumers benefited from a few years of lower gasoline prices than they would have otherwise paid, but the net result was less industry investment and probably higher oil imports in the long run.  By the time ANS exports were finally approved in 1996, the field was already in decline and the biggest opportunity had been missed. 

The advantages of allowing a portion of these new tight-oil streams to be exported would derive from the difference between the global market premium for crude of this quality and the typical discount paid for the lower-quality crudes that gulf coast refiners would continue to import in order to optimize their product yields and costs.  A difference of just $5 per barrel across a million barrels per day of exports would translate into a nearly $2 billion per year improvement in the US trade balance.  The benefits might also include higher tax revenues and royalties if exports supported higher production.  The biggest drawback I see is that in the event of a global supply disruption, some domestic crude would be committed to non-US buyers, reducing our emergency cushion.  However, that problem might be circumvented by requiring exporters to include provisions in their contracts allowing them to suspend deliveries whenever the US government released oil from the Strategic Petroleum Reserve, or a similar contingency.

Perhaps the best summary of the benefits that US oil exports could provide was given by President Clinton, when he authorized exports from the Alaskan North Slope: "Permitting this oil to move freely in international commerce will contribute to economic growth, reduce dependence on imported oil and create new jobs for American workers."  It's probably premature to provide a similar exemption for tight oil now, but it's certainly not too soon to start the national debate that should precede such a decision.