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. When I started working in the oil industry in the late '70s, there was 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, cheap 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.

Last week the International Energy Agency (IEA) reported that the amount of carbon dioxide emitted for each unit of global energy use was essentially unchanged between 1990 and 2010, despite the implementation of global climate agreements and the expenditure of hundreds of billions of dollars for renewable energy projects and incentives.  Just a few days earlier, the US Environmental Protection Agency released its annual inventory of US greenhouse gas (GHG) emissions, showing a 1.6% reduction from 2010 to 2011.  US emissions were up 8% since 1990 but have fallen 5% since 2000 and nearly 8% from their pre-recession peak in 2007.  Much of the US's recent divergence from the global trend is attributable to the displacement of coal from the power sector by shale gas.   

As unwelcome as the IEA's finding was, it is unlikely to  have shocked anyone who understands the scale of global energy systems and the continued reliance of many developed and developing countries on coal for power generation.  The transition to lower-carbon energy systems is underway, as reflected in the details of the IEA report.  However, it will take additional decades to reach targets consistent with limiting the projected global temperature increase to 2° C, which the IEA indicates would require a 60% reduction in the carbon intensity of energy by 2050 from current levels.  That implies that energy companies still need to develop additional oil and gas resources in the interim, in order to support the economic activity that--among other things--will be necessary to fund the recommended investments in cleaner energy and energy efficiency. 

At first glance that might seem paradoxical.  After all, oil and gas account for 55% of US GHG emissions and around 40% of global emissions today.  However, when gas displaces a higher-emitting fuel like coal, global emissions fall.  This has been a matter of some controversy, due to uncertainty about the contribution of fugitive methane emissions from shale gas wells. Yet the estimates in the EPA inventory indicate that methane emissions from US natural gas systems actually fell by 9% between 2005 and 2011, even though US natural gas production grew by 27% over that interval, with shale gas output increasing by 950%.  A new analysis from ExxonMobil indicates that on a lifecycle basis, replacing coal with shale gas in power generation reduces GHG emissions by an average of 53%, while also reducing overall freshwater consumption by half.

Assessing the role of oil in the decarbonization of global energy is more complicated.  Oil exploration and development must continue, even in a static or eventually shrinking market, because reserves that have been produced must be replaced, by either new discoveries or further development of existing fields. Simply allowing today's oil fields to decline and hoping to make up their energy contribution from other sources would be very risky, particularly for the transportation sector with its extremely high reliance on oil. Moreover, four-fifths of the emissions from petroleum occur during end-use combustion.  That means that most emission reductions from petroleum must come about through reduced demand, via some combination of increased fuel efficiency, fuel substitution--particularly in those markets where oil is still used in electricity generation--and/or reductions in transportation metrics such as vehicle miles traveled.  

In a recent Bloomberg op-ed, Michael Levy of the Council on Foreign Relations considered the impact of increasing US oil production from the standpoint of both the "social cost of carbon" and its incremental contribution to global emissions.  He concluded that even at a high estimated environmental cost, the climate impact of an extra barrel of US oil would come in under $10 per barrel, well below its economic value.  He also concluded that significantly higher US oil production would add little to global emissions.  Its impact would be even smaller if OPEC producers reduced output to try to preserve high oil prices.  Mr. Levy addressed that scenario in an earlier op-ed.

Last week's IEA report concluded that the world is not yet on track to reduce emissions by enough to limit future temperature increases to 2° C, and more must be done.  Yet even if we were on track, the IEA forecasts upon which the report was based suggest that combined oil and gas consumption in 2035 would still be about 2% higher in 2035 than in 2010, with a bit of a shift from oil to gas.  On today's trajectory, both oil and gas will grow, even as renewable energy and energy efficiency expand significantly.  On either basis, an all-of-the-above approach to energy encompassing oil and gas, along with renewables, carbon sequestration, nuclear power and efficiency is fully consistent with addressing climate change.

The latest threats from North Korea don't appear to have rattled global markets very much.  The North has a track record of empty bluster, though it also has a history of unexpected provocations, such as the 2010 sinking of a South Korean patrol vessel and subsequent artillery barrage on South Korean territory, and stretching back to its seizure of the USS Pueblo in 1968.  Yet while experts attribute recent warnings of "thermonuclear war" to a state functioning as a "protection racket", the consequences for energy markets of a miscalculation resulting in armed conflict could be significant.

The current episode includes much of the standard, alternate-reality rhetoric from Pyongyang, along with new elements such as its declaration that the armistice ending the Korean War in 1953 is invalid, and threats to shut the Kaesong Industrial Complex.  The latter jointly operated enterprise zone in North Korea was an outgrowth of North/South cooperation during a previous thaw.  However, at least one expert sees the main difference this time in the reaction of the US, which has responded to pressure from Kim Jong Un, grandson of North Korea's founder Kim Il Sung, by demonstrating its capability to deploy a wide range of advanced offensive and defensive weaponry to the region.

 The risks to energy markets from all this saber rattling might seem remote.  Conflict is usually bullish for oil, but neither South or North Korea is a major producer or exporter of oil or gas.  In fact, South Korea ranks among the world's top oil importers, consuming around 2.5 million barrels per day while producing less than 100,000 barrels per day, itself.  However, South Korea's refineries are an important element in regional refined products supply chains; three are ranked among the 10 largest refineries in the world.  According to Platts, refined petroleum product exports accounted for over 40% of the country's refinery output and became South Korea's largest exports by value last year.  That's remarkable, considering the country's exports of consumer electronics, cars and appliances.

Nor is it a coincidence that the South's three largest refineries were built as far as possible from the border with North Korea, with two located within the historic "Pusan Perimeter"--the portion of South Korea that was not overrun in the 1950 invasion by the North--and another nearby.  That places the bulk of South Korean refining capacity well beyond the range of the artillery that threatens Seoul , though not outside the range of the North's ballistic missiles.  SK Energy's smaller, under-utilized Incheon refinery, roughly the same distance from the border as Seoul, looks most vulnerable, at least on proximity.

South Korea's  refineries are generally less complex than similar US refineries, but what they lack in upgrading capacity they make up for in overall throughput.  Conversion hardware for producing transportation fuels account for half or less of downstream capacity per barrel of crude processed, compared to the average US refinery.  In general these facilities must run significantly more crude oil, or lighter crudes, to yield the same volume of gasoline, diesel and jet fuel.  In the process they make large quantities of other products, such as petrochemical feedstocks and fuel oil for further processing or export.  And they always seem to be engaged in various expansion projects, as I learned first-hand when I was involved in Caltex's investments in its Korean affiliate, now called GS Caltex.

In the event of an actual military crisis on the Korean peninsula , whether intentional or due to miscalculation, global and regional energy markets could be affected in two principal ways.  Large quantities of crude oil and LNG bound for Korean ports would likely have to be diverted on short notice to other destinations, raising uncertainty about subsequent shipments. That should put downward pressure on both markets, at least in the near term.  At the same time, refined product exports from South Korea might be curtailed, even if the country's refineries had not been attacked directly.  That would result in a scramble for products in the region, including in China, which along with Japan and Singapore is a major export destination for Korean refiners.  An analysis from 2010 saw the possibility of inflationary pressures and reduced economic output in China in such a scenario. 

Another Korean conflict would certainly feed energy market volatility, while the North's nuclear weapons, however crude they might be, add a significant dimension of risk and unpredictability to an already dangerous situation.

Recent comments by Saudi Arabia's oil minister, Ali Al-Naimi, indicated that Saudi Aramco would soon begin exploring the country's shale gas resources.  As another means of reducing oil consumption in the Kingdom's electricity sector, in order to preserve oil exports, this appears to make both practical and economic sense.  However, as noted by the Wall St. Journal, compared to the US Saudi Arabia has much less water available for the hydraulic fracturing of shale and tight gas reservoirs.  Absent a reallocation of its substantial conventional gas production, Saudi shale gas could become a key factor in global energy security.  However, the techniques employed to extract it might be different from those that currently dominate the US shale gas scene.

It must seem odd that Saudi Arabia would even be interested in shale gas, a resource that wasn't exploited in the US until conventional gas production was declining steadily.  Saudi Arabia might still be the world's largest oil producer, at least for now, but it is not the "Saudi Arabia of natural gas".  Although the country has proved gas reserves comparable to those of the US, it apparently didn't win nature's gas lottery on the Arabian Peninsula.  Saudi gas reserves and production amount to only about 10% and 19%, respectively, of the Middle East's gas totals.  Iran and Qatar are far ahead.  And while Saudi gas production has doubled since 2000, output in neighboring Qatar has expanded by a factor of six in the same interval. 

Much of the Kingdom's conventional gas reserves are associated with oil production and are often required to be reinjected to maintain reservoir pressure and oil output.  Available Saudi gas has been preferentially allocated to industrial projects, such as petrochemicals expansion.  As a result, little new gas was supplied for power generation, so  the Saudi electricity sector has been burning large and increasing quantities of oil that could otherwise be exported.  The need for additional gas has become acute, but exploration in the vast Empty Quarter has not yielded the expected gas bonanza, while the internal price of natural gas has been constrained at levels well below even recent low US natural gas prices--too low to make most new production attractive on its own merits.

As if the economics of shale gas development weren't challenging enough in such an environment, the key ingredient that has fueled the US shale revolution, water, is in short supply in Saudi Arabia.  The needs of cities and industry in this arid country exceed the water supply from aquifers to such an extent as to require 27 desalination facilities, delivering nearly 300 billion gallons annually.  At several million gallons of water per hydraulically fractured shale gas well, the logic of burning oil to desalinate water to produce gas looks questionable.  Fortunately, there are multiple emerging pathways for reducing or eliminating net water consumption in "fracking". 

For starters, many US producers now routinely recycle the 10-30% of injected water that typically flows back from the well after hydraulic fracturing, for use in subsequent wells.  Recycling has become the standard in places like Pennsylvania's portion of the Marcellus shale, reducing the call on fresh water for fracking. The oil services industry offers various techniques for cleaning "flowback" water, and new ones are under development, including the use of algae. 

Drillers can further reduce freshwater consumption through the use of nitrogen in foam or other forms.  ERDA, a precursor of the US Department of Energy, conducted research on that technique in the 1970s, and it has been refined since then.  Nitrogen is readily available from air separation plants and does not depend on water, though it does require energy.

Another approach for waterless fracking has been field-tested in Canada, using gelled propane.  A blog post in Scientific American described some of the pros and cons of this method, which is more expensive where water is cheap but might fit the bill in dry regions where LPG is readily available.  For that matter, it might make sense in New Mexico if the Mancos Shale of the San Juan Basin turns out to be another viable tight oil play. 

The upshot is that a shortage of fresh water shouldn't constitute an insurmountable obstacle to exploiting Saudi Arabia's unconventional gas resources, which Mr. Al-Naimi cited at 600 trillion cubic feet.  However, it remains to be seen whether shale gas development is the best answer to a problem that has been created by selling natural gas to industry for as little as $0.75 per million BTUs, while burning $100 oil ($17 per million BTU) to generate electricity.  Whether the ultimate solution is shale gas or something else, resolving this gap in Saudi industrial policy could have a significant impact on future oil prices.  

The publication of the State Department's latest environmental impact report on the Keystone XL pipeline project has sparked great interest in the logistics of shipping crude oil by rail.  As described in a long article in the Washington Post, the availability of a rail option for oil sands crude could prove to be a crucial element in determining whether the pending decision to permit the pipeline to cross the US border would actually affect Canada's oil sands output, and thus its greenhouse gas emissions.  As the article makes clear, however, oil's rail trend is already well underway , thanks to the surge of "tight oil" production from shale formations. Moving crude oil by train is experiencing a "Back to the Future" moment.

Oil shipments in rail cars are nothing new; the practice dates back to the earliest days of the oil industry.  In fact, control of key railroad routes for oil and petroleum products was an important aspect of the US government's anti-trust case against  the original Standard Oil a century ago.  My first exposure to crude-by-rail was in the 1980s, when significant quantities of heavy crude from California's San Joaquin valley were routinely transported to Los Angeles refineries by dedicated "unit trains", because there wasn't sufficient pipeline capacity available.

The same dynamic applies today, with the rapid expansion of tight oil production in North Dakota's Bakken fields quickly outstripping the capacity of the state's few existing pipelines to transport the oil to market.  A tank car loading rack requires much less time and money to build than a new pipeline or pipeline expansion. US railroads are also eager for the traffic, since coal deliveries, which accounted for 45% of US rail traffic in 2011, fell by nearly 11% last year as natural gas eroded coal's share of power generation.  Meanwhile oil shipments by rail grew by 46% in 2012.  

Precise data on just how much crude oil is currently moving by rail are hard to find.  The American Association of Railroads doesn't differentiate between crude oil and refined petroleum products, which until recently accounted for most oil-related rail shipments.  The US Energy Information Agency (EIA) reported last summer that crude oil had grown to roughly 30% of total petroleum rail deliveries, which would equate to around 300,000 barrels per day (bpd) on average for 2012. Yet EIA's analysis of recent trends suggested that crude-by-rail increased by nearly 250,000 bpd last year alone.  The CEO of the Burlington Northern Santa Fe recently indicated that his railroad's total oil-related shipments alone could expand to around 1 million bpd, roughly double today's level.

It would be easy to conclude that all this growth reflects a temporary expedient, until the nation's pipeline capacity can be expanded and realigned to match rising output and the reversal of long-standing import trends.  That view is clearly not shared by oil companies and traders who are lining up to purchase or lease new tank cars for this service.  Perhaps that's because rail provides a degree of flexibility that would be nearly impossible to match by pipeline.  For example, it creates an opportunity to supply domestic crude to East Coast refineries like Delta Airlines' Trainer, Pennsylvania facility, which had previously become uneconomical to operate on a diet of imported crude cargoes. Similarly, even if a pipeline from North Dakota to the San Francisco Bay Area could be justified economically, it would likely never receive the necessary permits.  Yet Valero's Benicia refinery might soon receive up to 70,000 barrels per day of Bakken crude by rail.  

Railroads are also surprisingly efficient. At an industry average of 480 ton-miles per gallon, my analysis indicates that shipping a barrel of crude from North Dakota to a refinery in either Houston or Philadelphia consumes a quantity of diesel fuel equivalent to just 1% of the energy content of the oil, while adding slightly over 1% to the typical well-to-wheels emissions for gasoline refined from it.  That's higher than for pipelines, but not by enough to render the option unattractive.

Pipelines remain the preferred option for moving high volumes of oil safely over long distances and, when capacity exists, are usually cheaper for shippers.  However, rapidly shifting sources of production and the high capital costs of new pipelines, combined with an increasingly challenging regulatory environment, could provide a durable opportunity for oil-by-rail, just as it has for moving petroleum products and ethanol by train. 

It's ironic that "Argo", a film set against the backdrop of the 1979 Iranian Revolution, should win this year's Academy Award for Best Picture just two days before the start of a new round of nuclear talks involving the inheritors of that revolution.  The pressure from UN sanctions on Iran and the potential for armed conflict if the current stalemate breaks down continue to burden global energy markets, contributing to the current high price of UK Brent crude, the global oil benchmark.  Resolving these tensions will require proving a negative with regard to Iran's intentions and overcoming three-plus decades of mutual distrust and suspicion. That's a tall order for the latest set of negotiations being held this week in Kazakhstan.  

Assessing the likelihood of a diplomatic breakthrough depends on the answers to two fundamental questions.  The first concerns the true purpose of Iran's nuclear program, which encompasses the entire fuel cycle from enrichment and fuel fabrication to civilian research and power reactors.  If all the regime has in mind is adding capacity to its domestic energy mix, the nuclear route represents an extraordinary choice for a country so rich in hydrocarbons. 

Recently, the price and availability of natural gas and renewable energy have impaired the economics of new nuclear power in the US and Europe, but this is old news in Iran.  With 16% of the world's natural gas reserves, Iran produces just 4.6% of world gas output--a distant fourth behind the US, Russia and Canada. So Iran's easiest  and least controversial energy option would be to ramp up its gas industry.  Combined-cycle gas turbines are highly efficient, and their cost per megawatt of capacity is a fraction of nuclear's.  Factoring in the external constraints that the country's nuclear efforts have also attracted, it's hard to see why any government would pursue this choice so relentlessly if it didn't also intend to create at least the option for building nuclear weapons in the future. The cost of those constraints has grown in the last several years. 

Tighter international sanctions have limited Iran's oil exports and its access to the global financial system.  In its January Oil Market Report, the International Energy Agency reported that Iran's oil production fell by 650,000 barrels per day (bdp) last year and is now a million bpd below recent capacity. Iran lost around $40 billion in export revenue last year, at official selling prices, equating to 8% of the country's economy at official exchange rates.  If sustained, sanctions could shrink Iran's long-term oil production capacity.

Despite these costs Iran has taken a relatively hard line going into the talks in Almaty. Its actions beforehand sent mixed signals, including the deployment of a new generation of uranium-concentrating centrifuges and the selection of up to 16 new nuclear reactor sites.  This was tempered by a move to convert part of its concentrated uranium stock into fuel for its research reactor.  Meanwhile, Iran has dragged out discussions with the International Atomic Energy Agency, the UN's nuclear watchdog, aimed at resolving suspicions about past clandestine nuclear weapons work. 

The other basic question underlying these talks concerns the resolve of the "P5 + 1" group--the US, UK, France, Germany, Russia and China--to maintain pressure on Iran over this issue.  This has multiple dimensions.  On the economic front, sanctions on Iran have cut world oil supplies by around a million bpd, while outages in Sudan, China and elsewhere are contributing another million bpd of lost output.  As a result, oil prices have remained persistently high, despite weak demand in the US and EU and the dramatic resurgence of US oil production, which has grown by a million bpd since 2009.  If Iran sanctions and the risk of conflict there have added $10 per barrel to the global price of oil, then the impact on the US and Europe would be on the order of $70 billion per year.  That's less of a burden to these economies than $40 billion of lost revenue is to Iran, but it's still an unwelcome drag at a time of general economic weakness. 

From a security perspective, none of the P5 + 1 would be eager to see another war in the Middle East, let alone to prosecute one.  Secretary of State Kerry warned of "terrible consequences" if negotiations eventually failed, but the Pentagon faces sharp budget cuts, and European participants seem prepared to negotiate indefinitely, regardless of the outcome.  Moreover, throughout the confrontation with Iran, critics have argued that a nuclear-armed Iran could be contained and deterred in much the same way the Soviet Union was.  This rationale comes from think tanks across the political spectrum. If it were more widely accepted, it would undermine the case for the military option that represents the ultimate backstop of carrot-and-stick diplomacy with Iran.

There are few paths out of this maze that don't lead to "red lines."  If Iran wants only nuclear power, it can yield; if it wants nuclear weapons, it can't.  Otherwise, if the current talks or the inevitable next round lead to an easing of sanctions--and potentially lower oil prices--it would likely be because the rest of the world has grown as tired as Iran of the pain of perpetual sanctions.  Time is now on Iran's side. 

by Geoffrey Styles, Managing Director of GSW Strategy Group

The spread between the US and international crude markets has grown very wide.  West Texas Intermediate crude currently sells at about a $21 per barrel discount to UK Brent crude--an extraordinary markdown for a grade of oil that was the world standard just a few years ago. In a post last December I discussed the influence of pipeline bottlenecks, particularly in the middle of the US, on this relationship.  This week I read an interview with an oil investment analyst questioning the notion that relieving those bottlenecks would bring US crude back into alignment with the global market.  His argument hinges on the capability of US Gulf Coast refineries to adapt to a diet of lighter, sweeter crude oil, compared to the heavy grades they've been accustomed to running.   Although his point serves as a useful reminder of the complexities affecting oil prices, I can't help wondering if it underestimates the flexibility of the US refining system.

I doubt there's a generic answer to the question Mr. Schaefer of the Oil & Gas Investment Bulletin poses.  It's not just a matter of whether it might be more profitable for these refineries to process heavy oil and export light, as I've suggested in the past, but if refineries that have been modified for a heavy crude slate can still revert to running the lighter crudes coming out of the Bakken and Eagle Ford shales, which seem broadly similar to those for which many of them were originally designed.

To a large extent that would depend on the specific configuration of each refinery, along with the market it serves.  Understanding why requires at least a cursory understanding of how refineries work.  If you look at even a simple refinery flow schematic, you'll notice numerous interconnections between the various process units.  Unfinished products flow from one unit to the next until blended finished products come out the other end, but those aren't the only important flows.  What makes today's refineries around 90% efficient is clever recycling of heat and byproducts like hydrogen and fuel gas.  In order for the whole facility to operate smoothly, all its units must remain in balance with each other.  If you feed the atmospheric distillation column, or "crude unit" at the front end with very light crude oils that, when distilled into their components, overwhelm some downstream units and starve others, that careful integration will break down. 

This seems to be the essence of Mr. Shaefer's point: that the Bakken and Eagle Ford crude streams are too light, yielding abundant LPG, gasoline and diesel but insufficient "gas oil" and residue to keep the fluid cat cracker--the gasoline-making heart of a modern refinery--and other downstream units running properly.  For some facilities in some locations that could be an important insight and limitation.  Certainly the California refinery where I once worked as a process engineer would have choked on 47 gravity Eagle Ford or 43 gravity North Dakota Sweet, having been designed for an average API gravity (a measure of crude oil density) of around 20.  However, it's worth recalling that no significant new oil refinery has been built in the US since the 1970s, although many have been upgraded substantially since then. That means that most of today's Gulf Coast refineries have cores that were built at a time when domestic light sweet crude was still abundant.

Refinery engineers and the supply departments that work with them can also be quite resourceful. I recall that when I was a trader for Texaco's US West Coast operations in the 1980s, we routinely purchased intermediate feedstocks from other refiners, to keep our refineries' cat crackers and cokers running during crude unit maintenance or when their current crude slates didn't naturally provide enough.  Between shifts in the mix of other crude oils run in conjunction with light oil, and supplementing with feedstock purchases, Gulf Coast refiners might have more flexibility to maximize purchases of shale oil, or "tight oil" than Mr. Shaefer's argument credits.

Ultimately this issue factors into a larger debate concerning how to extract the greatest benefit from the new oil bounty that shale production techniques are providing.  Are we better off with constrained pipelines that force some producers to discount their output so it can still reach market by rail or truck, and incidentally provide some refineries with a cheap source of crude?  Does the maximum advantage accrue from ensuring that all US crude production is processed in US refineries, even if they increasingly export their products internationally, in light of weak US demand?  Or should we suspend outdated crude oil export restrictions and allow both producers and refiners to compete in the same global market that already sets most US refined product prices?  That's a worthwhile debate, and I'd be surprised if it were settled based on the physical constraints of the sophisticated refineries of the US Gulf Coast.

by Geoffrey Styles, Managing Director  of GSW Strategy Group

2012 was a remarkable year for energy in the US, with domestic output of oil, gas, wind and solar energy all advancing strongly.  This was the result of an unfolding revolution in unconventional oil and gas, along with federal, state and local incentives and regulations promoting renewable energy.  Yet despite extensive media coverage and vocal constituencies for each of these energy sources, I haven't seen any recent efforts to compare their respective contributions to US energy supplies. 

That may be due in part to the confusing array of energy units involved. It's daunting to match up oil in 42-gallon barrels (bbl), gas in cubic feet or British Thermal Units (BTUs), and wind and solar in kilowatts (kW) or Megawatts (MW) of capacity, or kilowatt-hours (kWh) or Megawatt-hours (MWh) of actual generation.  Conversion factors among these various units are easy to find on the internet.  However,  meaningful comparisons are complicated by important distinctions between liquid or gaseous fuels and grid electricity, and the fact that these energy sources compete with each other only in specific situations. 

For purposes of comparison, since wind and solar routinely compete with gas-fired generation, let's assume that the output of wind turbines and solar panels can be equated to the power from a natural gas turbine with an effective heat rate of 7,000 BTU/kWh.  That recognizes the efficiency losses in fossil generation and the premium value of electricity to end users.  Gas and gas-equivalent renewables can be further equated to oil using the standard conversion factor of 5.8 million BTU/bbl.  So even though wind and solar rarely compete with oil in the real world, because less than 0.6% of US electricity is now generated from petroleum products or byproducts, we can still assess their relative contributions to America's energy economy in familiar terms.  Please note that Energy Information Agency (EIA) data on production and generation for the full year won't be available for a few months, so the figures below are based on published data for the most recent 12-month periods.

Natural gas posted the biggest gain last year, with "marketed gas production", including gas liquids like ethane, propane and butane, growing by 1.57 trillion cubic feet for the 12 months ending in October 2012, compared to the same period a year earlier.  That's equivalent to adding at least 750,000 bbl/day of oil.  US gas production appears to have set an all-time record last October.

Oil production also grew rapidly in 2012, as noted several times in the presidential campaign and debates. Thanks to surging tight oil (shale oil) production in North Dakota, Texas, and elsewhere, US crude oil output increased by 710,000 bbl/day on a November-October basis.  In fact, October's production of 6.82 million bbl/day was the highest for any month since December 1993.  Recent production looks even higher.

Although final installation data aren't in yet, wind power also had a banner year, with developers on track to install between 11,000 and 12,000 MW of new capacity in the US.   Much of this growth was attributable to companies accelerating projects in anticipation of the scheduled December 31, 2012 expiration of the federal Production Tax Credit, or PTC, the main US tax incentive for wind energy. As it turned out, the Congress extended the PTC for another year as part of the recent "fiscal cliff" deal. On the basis of the most recent 12-month comparisons from the EIA, US wind farms generated 21.6 million MWh more last year than the previous year.  That equates to 150 billion cubic feet (BCF) of natural gas, or around 71,000 bbl/day of oil.

That brings us to solar, which was on pace to set a record of around 3,200 MW of new installations in the US in 2012.  On a November-October basis new solar panels added roughly 2.3 million MWh of reported generation last year, equivalent to 16 BCF of gas or 7,600 bbl/day of oil. This probably doesn't capture the contribution of all grid-independent installations, but it's unlikely to be off by more than a factor of 2.

Although the above chart shows that wind and solar power have a long way to go, both have earned credibility by advancing to the point of being measurable on the same scale as oil and gas.  Both contribute to reducing emissions. At the same time, the significance of developments in US unconventional hydrocarbons leaps off the page.  In just the last year, for the second year in a row, shale gas has added domestic energy production equivalent to the entire current output of all US non-hydro renewable electricity generation: wind, solar, geothermal, biomass and waste power. Tight oil added a like amount in 2012.  We're clearly in the midst of an energy transformation, but it doesn't much resemble the one that was anticipated just a few years ago.   

As an article in the Financial Times noted Monday, the simple question "What is the price of oil?" became much harder to answer this year.  The gap between the price of UK Brent crude, which the US Department of Energy recently announced it was adopting as its indicator of global oil prices, and West Texas Intermediate (WTI), their former planning benchmark and the price most commonly identified with oil by the media and US public, has grown too large to ignore.  Blame that on a combination of pipeline bottlenecks and a rapidly growing offshoot of the shale gas revolution, in the form of so-called "tight oil" or "shale oil."  Whatever the cause, the spread between Brent and some of the crude sources that are reviving US hopes of energy independence now exceeds the total price of crude oil as recently as 2003. That has big consequences for producers, refiners and consumers.

When the year began, WTI was only about $8 per barrel below Brent-- a hefty discount for a crude that routinely traded at parity or a slight premium to Brent until a couple of years ago.  As of today, however, Brent's advantage is closer to $21/bbl.  Nor is this just a US/European difference.  Recent settlements for the "swap" between WTI and Louisiana Light Sweet (LLS), a Gulf Coast crude unaffected by the massive bottlenecks in the Midcontinent, were around $22/bbl.   And if that doesn't seem like a big enough discount for a transportation disadvantage, consider that similar crudes produced near Midland, TX--another hotspot of the US crude oil resurgence--were recently selling at nearly $10/bbl below WTI. 

It's important to note that these price differences are too big to be explained by distinctions in quality. Most of these crude types are quite similar, light and sweet--low in sulfur and relatively easy to refine into valuable products like diesel and gasoline.  Instead, the discounts reflect the absence of a low-cost means of delivering much of this production from source to refinery as existing pipeline capacity has been filled or as new production unserved by pipelines emerges.  To illustrate the magnitude of this problem, in a recent panel discussion on the future of fuels Frank Verrastro of the Center for Strategic and International Studies indicated that 1.4 million barrels per day of US crude production is currently shipped by rail. 

That's a figure that ought to cause opponents of pipelines like the Keystone XL to reflect on the unintended consequences of their success in delaying such projects.  It should also warm the hearts of railroad shareholders, since rail freight is much costlier than pipeline tariffs, and the volume in question is nearly double that of US corn ethanol, which also largely moves in railcars.  Yet while this benefits railroads and refineries such as PBF's Delaware City plant, which is installing facilities to receive up to 110,000 barrels per day of low-cost crude by rail, it exacts a substantial penalty from those domestic producers who receive well below world prices for their output.   

At current price levels, that hasn't impeded the rapid growth of production in places like North Dakota. However, if global oil prices declined significantly, and the discounts between new sources and benchmark Brent didn't compress dramatically, then some of the output that the US is counting on to drive out imports could become uneconomical to produce.  Some refiners and Midwestern consumers have gained a temporary advantage from the bottlenecks that are trapping hundreds of thousands of barrels per day of oil in the Midcontinent or forcing it onto railcars. However, they, along with producers, stand to benefit more in the long run from new pipeline capacity that would make today's production more recession-proof, while supporting further development.

Relief is on its way, and at least one project, the reversal of the existing Seaway pipeline, has already started shipping oil.  Adding more capacity to transport crude oil from the Plains states and Midcontinent to the major refining centers of the Gulf Coast makes strategic sense and should eventually narrow the price differentials described above.  Despite opposition motivated by environmental concerns and organized via social media, it seems likely that many of these pipeline projects will ultimately be built, because their economic, trade and even environmental, health and safety advantages look compelling.  But that doesn't mean it will happen overnight, or without a lengthy process of give-and-take with regulators and stakeholders.  Until this new infrastructure is in place, whenever someone tells you the price of oil, be sure to ask which oil they have in mind, and where. 

The announcement of a $21 billion project to capitalize on abundant, low-cost US natural gas ought to catch the attention of everyone interested in this resource.  As reported in the New York Times, Sasol, a South African energy company, intends to build a 96,000 barrel-per-day gas-to-liquids (GTL) plant in southwestern Louisiana, in conjunction with a new gas processing plant and ethylene cracker.  The synthetic diesel fuel produced by this facility would provide a different pathway for shale gas to displace imported crude oil in the US transportation sector, in competition with compressed or liquefied natural gas (CNG or LNG.)

GTL involves a two-step conversion of the methane that makes up the bulk of natural gas into synthesis gas and hydrogen, which are recombined into liquid hydrocarbons by means of the decades-old Fischer-Tropsch (FT) process.  GTL is also energy-intensive, with an overall efficiency around 60%.  South African companies have vast experience with such synthetic fuels. Sasol are partners in the Oryx GTL plant in Qatar, and their coal-to-liquids plants in South Africa utilize a similar syngas step and the same FT process as GTL. 

With the US suddenly perceived to be sitting atop a century's worth of natural gas, mainly in the form of unconventional gas from shale, tight gas formations and coal-bed methane, T. Boone Pickens isn't the only one to see an opportunity to displace imported oil with gas.  Yet as attractive as that sounds for reasons of energy security and trade, it isn't obvious whether the public or even fleet operators are willing to switch on a larger scale to a lower-density gaseous fuel requiring both new distribution networks and new or modified powertrains. Only 0.1% of the natural gas consumed in the US now finds its way into vehicles, equivalent to less than 0.1% of US oil demand.  Under the circumstances, it would be surprising if someone weren't looking seriously at GTL, one of the few practical ways to circumvent the mechanical and logistical barriers that have impeded the fueling  of more US cars and trucks with natural gas.

When I read about Sasol's proposed project, I immediately thought of another, less well-known South African synfuels facility.  Since 1992 the Mossel Bay GTL plant has been turning natural gas into gasoline, diesel and other fuels, drawing first on the Mossel Bay gas field and then on newer fields as the original one depleted.  Although owned by another firm, the ongoing struggles to keep the "Mossgas" plant supplied are well-known in South African energy circles.  I can't imagine Sasol embarking on a project like the one in Louisiana if they had any doubt about their ability to keep it supplied for decades.

Of course volume and price are two very different aspects of supply.  A decade ago, conventional wisdom held that GTL required a gas cost of around $1 per million BTUs to be viable.  Even with the shale bonanza today's US natural gas price is well above that level.  What now makes it possible to conceive of GTL in the US is that the price of the crude oil used to make diesel and other fuels has risen so much higher than that of natural gas.  That comparison is more obvious  when one converts natural gas prices into their energy equivalent in crude oil.  Today's US natural gas price is around the same $23 per equivalent barrel that it was in 2001.  Meanwhile crude oil has increased from about $26 to $95 per barrel.  The drastically improved attraction of GTL becomes even clearer when comparing ten years of wholesale US Gulf Coast diesel prices to natural gas prices using the approximate GTL conversion rate of 10 million BTUs of gas per barrel of product. 

As the chart above reveals, this theoretical GTL margin has exploded since 2009.  Yet it also shows that if gas prices returned to the levels we experienced just a few years earlier, the proposed project would encounter significant risks.  Perhaps that helps explain Sasol's concept of a larger integrated gas complex with multiple sources of margin, capitalizing on the waste heat from the GTL process and the lighter hydrocarbons it yields as byproducts.

It remains to be seen whether GTL will prove an attractive means of leveraging the US shale gas revolution to back out imported oil.  However, if Sasol and others proceed with US GTL projects, anyone eyeing our gas surplus for other purposes, whether in manufacturing, fertilizer production or power generation, would face serious competition linked to the global oil market. That includes potential LNG exporters, who have just passed an important hurdle with the publication of a favorable analysis by the Department of Energy.