The Impact of the Global "Sweet" Crude Bulge

• The recent slide in global oil prices has been compounded by the pressure that rising US shale oil production is putting on the price of sweet crude benchmarks like Brent.
• OPEC's producers may suffer as much as those in the US, while consumers benefit from significantly lower fuel prices than last year.

When the US went to war in Iraq in 2003, the price of oil embarked on a trend that took it from around $30 per barrel to nearly $150 before collapsing in the recession in 2008. This time, as a new US-led coalition takes on ISIS with a bombing campaign in Iraq and Syria, the price of oil is falling, down 20% in the last two months. It's not just that global economic growth has weakened recently, or that soaring shale oil output in the US has averted another oil crisis. Oil's current downturn also reflects the fact that new production from the Bakken, Eagle Ford and other shale deposits is particularly well-suited to undermine oil's global benchmark prices, for Brent and West Texas Intermediate, both of which are made up of light sweet crude oil streams.

The numbers for US shale, or "light tight oil" (LTO) as it's often called, are impressive, especially to those accustomed to watching the gradual ebb and flow of different oil sources over long periods. In the 12 months ending in June 2014, US oil production grew by 1.3 million barrels per day (MBD), not far short of Libya's pre-revolution exports. Since January 2011, the US added 3 MBD, or about what the UK produced at its peak in 1999. In fact, since 2010 incremental US LTO production has exceeded the net decline of the entire North Sea (Denmark, Norway and UK) by around 2 MBD, contributing to a significant expansion of Atlantic Basin light sweet crude supply.

The New York Mercantile Exchange defines light sweet crude as having sulfur content below 0.42% and an API gravity between 37 and 42 degrees. That's less dense than light olive oil. The specification for Brent is similar. Much of the LTO produced from US shale formations fits those specifications, and what doesn't is typically even lighter and lower in sulfur.

The current "contango" in Brent pricing, in which contracts for later delivery sell for more than those for delivery in the next month or two, is another sign of a market that is physically over-supplied: more oil than refineries want to process, with the excess going into storage. However we also see indications that the historical premium assigned to lighter, sweeter crude versus heavier, higher-sulfur crude is under pressure.

One example of this is the gap or "differential" between Louisiana Light Sweet, which wasn't caught up in the delivery problems that plagued West Texas Intermediate for the last several years, and Mars blend, a sour crude mix from platforms in the Gulf of Mexico. From 2007-13 LLS averaged around $4.50 per barrel higher than Mars, while for the first half of this year it was only $2.75 higher and today stands at around $3.40 over Mars.

And while OPEC's reported Reference Basket price has been falling in tandem with Brent, its discount to Brent had also narrowed by about $1 per barrel, prior to the price plunge of the last couple of weeks, compared with the average for 2007-13. Considering that OPEC's basket includes light sweet crudes from Algeria, Libya and Nigeria that sell into some of the same Atlantic Basin markets as Brent, that looks significant.

By itself a narrowing of the sweet/sour "spread" of only a dollar or so per barrel isn't earth-shattering. However, because the surge of US oil production is effectively focused on the oil market segment represented by the price of Brent, it compounds the pressure on OPEC, many of whose members link the price of their output to Brent. This might help explain why the response of OPEC's leading producer, Saudi Arabia, has been to cut prices rather than output, in an apparent effort to maintain market share rather than price level.

The Saudis know better than anyone how that movie could end. The Kingdom's1986 decision to implement "netback pricing", linking the price of its oil to the value of its customers' refined petroleum products, helped precipitate a price collapse so deep that it took oil prices 18 years to reach $30/bbl again, by which time the dollar had lost a third of its value.

Whether aimed at US shale producers or as a reminder to the rest of OPEC, which appears to be unprepared to make the output cuts necessary to defend higher oil prices, the Saudi action increases the chances that oil prices will over-correct to the downside, rather than rebounding quickly. If so, the impact of the sweet crude bulge in the Atlantic Basin--only a little more than 3% of global oil supplies--could play a disproportionate role in prolonging the pain producers will experience until oil markets eventually reach a new equilibrium.

In the meantime, US consumers are benefiting from gasoline prices that are already $0.15 per gallon lower than this week last year. Today's wholesale gasoline futures price for November equates to an average retail price well below $3.00 per gallon, after factoring in fuel taxes and dealer margins, compared to last year's average retail price for November of $3.24. After factoring in lower diesel and heating oil prices, the fall in oil prices could put an extra $10 billion in shoppers' pockets for this year's holiday season.

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

Will Shale Oil Growth Lead to New US Refineries?

• The revival of US oil production is spurring new investments in refineries, including the restart or new construction of small refineries near these resources.
• How well such investments perform will depend on both the longevity of shale oil production and policies concerning its export.

An article on the revival of some mothballed US oil refineries and the possible construction of new ones provided yet another indication of industry confidence that record growth in oil production from US shale deposits isn't just a temporary phenomenon.  Refineries--even small ones--aren't usually quick-return investments. Restarting one or building a new one requires a positive view of future feedstock availability, product demand and other uncertainties.

The number of US refineries has fallen steadily, from 301 in 1982 to 143 last year. Because this mainly involved the retirement of smaller, less efficient facilities, while larger refineries "de-bottlenecked" or expanded, US refinery capacity actually grew over this period. It's generally cheaper to expand an existing facility, leveraging its infrastructure and experienced staff, than building a "grassroots" facility.

The hurdles facing new refinery construction in the US have been compounded by environmental regulations covering permits, emissions and product specifications. The time when a new entrant could simply distill light crude oil, sprinkle in some tetraethyl lead and other additives, and sell a full slate of refined products is long gone. New refineries in North Dakota, Texas and Utah are apparently focused on producing diesel fuel from the shale, or "tight" oil in the Bakken, Eagle Ford, and Uinta shales, respectively, and selling the rest of their output to other refiners or petrochemical plants as feedstocks .

With diesel demand in the producing areas booming, thanks to the needs of drilling rigs and the trucks that haul water, sand and equipment, as well as oil from leases not connected to pipeline gathering systems, this opportunity could last as long as the drilling-intensive shale development does. In other words, the demand aspiring refiners see appears to be linked directly to their source of supply.

Meanwhile larger plants, such as several of  Valero's Texas refineries, are in various stages of investments to enable them to process more light oil, reversing a multi-decade trend of investment to handle increasingly heavy and sour (high-sulfur) imported crudes. As with the smaller refineries, this shift requires high confidence in the long-term availability and favorable pricing of these high-quality domestic crude oil types.

The reasonableness of that assumption depends on the longevity of tight oil production. Large conventional inland oil fields typically reach peak output within a few years and then decline gradually, with long plateaus. Whether shale deposits, with their distinct geology, will follow the same pattern remains to be seen. Despite a few projections suggesting that tight oil output of the major shale basins could soon peak and decline rapidly, most mainstream forecasts suggest a long life for these resources, particularly as the technology to develop them continues to improve. 

For example, in its latest Annual Energy Outlook, the US Energy Information Administration (EIA) anticipates US tight oil production reaching 4.8 million barrels per day (MBD) by 2021, before gradually declining back to levels near today's in 2040. By contrast BP's just-released Energy Outlook 2035 sees comparable growth over the next few years but little subsequent decline, with tight oil at 4.5 MBD in 2035. Meanwhile, ICF International recently issued its Detailed Production Report, projecting shale/tight oil production in the US and Canada to reach 6.3 MBD by 2035, including 1.3 MBD from the tight oil zones of the Permian Basin of Texas.

The other big uncertainty concerning the availability of light tight oil for new or expanded US refineries depends on federal export policy, which I addressed in a recent post. This issue is highly controversial. A quick reversal of existing rules would be surprising, though as the New York Times noted, possible compromises under existing law could facilitate an expansion of crude oil exports beyond current shipments to Canada. While unlikely to dry up domestic availability of tight oil, such measures could shrink the current discounts for these crudes, compared to internationally traded light crudes like UK Brent. That seems less of a risk for small, simple, inland refineries than for larger facilities, especially those near coastal ports.

This isn't the first time investors have considered the need for new US refineries. There was similar interest after hurricanes Katrina and Rita slashed Gulf Coast refinery output for several weeks in 2005, though it ultimately led nowhere. If today's circumstances prove more supportive, it will be because the US hasn't experienced anything comparable to the shale revolution since the 1920s and '30s, when rapid oil production growth was accompanied by a wave of refinery construction, though in a very different business and regulatory climate. If that parallel holds, consumers stand to benefit from the resulting increase in competition.

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.

Comparing US Energy Growth in 2012

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 equivalencies 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 Administration (EIA) data on production and generation for the full year won't be available until the end of the month, so the figures below are based on published data for the most recent available 12-month periods.

Through November oil production posted impressive gains last year , 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 748,000 bbl/day on a December-November basis, or around 13%. In fact, November's production of 6.9 million bbl/day was the highest for any month since November 1993. Recent production looks even higher.

Natural gas also grew rapidly in 2012, with "marketed gas production", including gas liquids like ethane, propane and butane, growing by 1.4 trillion cubic feet for the 12 months ending in November 2012, compared to the same period a year earlier.  That's equivalent to adding at least 650,000 bbl/day of oil.  US gas production appears to have set an all-time record last October.

Wind power also had a banner year, with developers installing a record 13,124 MW of new capacity in the US.   Much of that 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 18 billion kWh more last year than the previous year.  That equates to 126 billion cubic feet (BCF) of natural gas, or around 59,000 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 December-November basis new solar panels added roughly 2.5 billion kWh of reported generation last year, equivalent to 17 BCF of gas or 8,100 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 to match the recent energy contributions of new fossil fuel production, both have earned credibility by advancing to the point of being measurable on the same scale as oil and gas.  Both also 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 roughly 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.  

This is an updated version of a posting that was previously published on the website of Pacific Energy Development Corporation.

Will California Be the Next Big Shale Oil Play?

I've spent the last couple of weeks contemplating California's Monterey shale, which has been widely discussed recently as the country's next Bakken-style oil play, or even bigger.   The Bakken shale has turned North Dakota into the second-biggest oil-producing state in the US, at the same time that development of the Eagle Ford shale has been shoring up Texas's claim to the number one spot.  So far, The Golden State has largely missed out on the shale revolution, despite having shale oil resources estimated to exceed the rest of the US combined. The scale of the opportunity makes it an intriguing subject, but I find it particularly interesting, because the Monterey is deeply intertwined with the long history of the California oil industry, in which I spent the first half of my career. 

The Monterey shale is hardly a new prospect.  One of the first documents my search turned up was a 1905 USGS report on its fossil content, noting its oil potential.  First production from this shale apparently occurred a decade earlier.  Moreover, it appears that the Monterey formation, which underlies many of the state's conventional oil fields, is actually the "source rock" for those fields: the zone from which the hydrocarbons trapped in their reservoirs originated.  So the estimated 400 billion barrels or so of original oil in place in the Monterey have presumably already yielded a substantial share of the roughly 29 billion barrels of oil that California's oil fields have produced to date.

Development of this play doesn't just lag shale projects elsewhere because of California's well-known environmental sensitivity.  The geology of this deposit also differs significantly from that of the Bakken and other east-of-Rockies shale plays, partly due to its relative youth, as well as the effects of the Golden State's seismic activity.  Its oil-bearing strata are thick and often jumbled up by past earthquakes. One expert characterized this as signifying that the Monterey wasn't a "resource play" but a "structural play."  So unlike the Bakken or Eagle Ford, individual wells carry higher risks of failing to yield commercially useful output.  It also makes it less likely that steady efforts in the Monterey will result in an easily replicable recipe for unlocking the entire deposit. 

That brings us to fracking, which is surely as controversial in California as anywhere, even though, as in many other locations, it's been done safely and with little fanfare for decades.  The state recently announced preliminary fracking regulations, but this may have less impact on development of the Monterey shale than one might suppose.  That's because this formation seems to be less amenable to fracking, or at least to the combination of horizontal wells and multi-stage fracking that's been a game-changer elsewhere. Other techniques, such as acid injection, may prove more useful.

However it is eventually unlocked, the Monterey shale offers significant benefits to California.  Start with the fact that the state's oil production has been in steady decline since the mid-1980s. Together with the depletion of Alaska's North Slope field, that has meant that the US West Coast, which was once a net exporter of oil, now imports increasing quantities of oil--half of it from OPEC--to meet local demand.  That trend has continued even as the import dependence of the rest of the country has fallen substantially due to higher production and receding demand.  The Monterey could slash California's imports, while adding billions of dollars a year to the local economy and to the shaky state budget, along with lots of good jobs.

It could even provide environmental benefits. Restoring oil self-sufficiency would reduce the risk of spills from the tankers bringing in imports, while refilling existing infrastructure.  And if the Monterey yields oil similar in quality to the light, sweet crude now being produced from the Bakken and Eagle Ford shales, it could actually cut both greenhouse gas emissions and local pollution by reducing the refining intensity required to turn the state's current diet of heavier crudes into ultra-low sulfur gasoline and diesel fuel. 

I suspect from my research in the last few weeks that anyone betting on an imminent explosion of oil output from the Monterey shale is likely to be disappointed.  The process seems likely to be slower than elsewhere, though with a bigger potential payoff.  But that doesn't make it irrelevant to a state that has set its sights on being at the forefront of the transformation to cleaner energy sources.  California still consumes 1.8 million barrels per day of petroleum products, and it will burn many more billions of barrels on its way to its chosen future of electric vehicles running on wind and solar power, and trucks and buses burning compressed or liquefied natural gas. Developing the Monterey shale won't solve all of California's energy challenges and might create a few new ones, yet it could prove another timely contribution from a local oil industry that has been a major driver of the state's economy for well over a century. 

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.

Could Oil's Surge Sink Renewable Energy?

A new forecast of global oil production by the end of the decade attracted a fair amount of attention this week.  The study, from Harvard's Kennedy School of Government, indicates that oil production could expand by about 20% by 2020 from current levels.  The Wall St. Journal's Heard on the Street column cited this in support of the view that the influence of "peak oil" on the market has itself peaked and fallen into decline.  I was particularly intrigued by a scenario suggested in MIT's Technology Review that this wave of new oil supplies could trigger an oil price collapse similar to the one in the mid-1980s that helped roll back the renewable energy programs that were started during the oil crises of the 1970s.  That's possible, though I'm not sure this should be the biggest worry that manufacturers of wind turbines and solar panels have today.

The Harvard forecast is based on a detailed, risked country-by-country assessment of production potential, with the bulk of the projected net increase in capacity from today's level of around 93 million barrels per day (MBD) to just over 110 MBD coming from four countries: Iraq, the US, Canada and Brazil. However, the study's lead author, former Eni executive Leonardo Maugeri, sees broad capacity growth in nearly all of today's producing countries, except for Iran, Mexico, Norway and the UK.  Although this is certainly a diametrically opposed view of oil's trajectory than the one promoted by advocates of the peak oil viewpoint, it is accompanied by the customary caveats about political and other risks, along with new concerns about environmental push-back.  The latter point is particularly important, since much of the expansion is based on what Mr. Maugeri refers to as the "de-conventionalization of oil supplies", based on the expansion of unconventional output from heavy oil, oil sands, Brazil's "pre-salt" oil, and the "tight oil" that has reversed the US production decline. 

Although this de-conventionalization trend is very real, it's one thing to envision a shift to an environment in which oil supplies could accommodate, rather than constrain global economic growth; it's another to see these new supplies bringing about an oil price collapse.  It's helpful in this regard to consider the three previous oil-price collapses that we've experienced in the last several decades.  The mid-1980s collapse is the one that Kevin Bullis of Technology Review seems to have latched onto, because much like today's expansion of unconventional oil, the wave of new non-OPEC production that broke OPEC's hold on the market was the direct result of the sharp oil price increases of the previous decade, after allowing for inherent development time lags. The analogy to this period looks even more interesting if the new Administrator of the Energy Information Agency of the Department of Energy is correct in speculating that the US government might be willing to allow exports of light sweet crude from the Bakken, Eagle Ford and other shale plays, to enable Gulf Coast refineries to continue to run the imported heavy crudes for which they have been optimized at great expense.  That could dramatically alter the dynamics of the global oil market.

However, I see two significant differences in the circumstances of the 1980s price collapse, compared to today. First, oil consumption was then dominated by a small number of industrialized countries, the economies of which were still much more reliant on oil for economic growth than they are today. Second, these economies were already emerging from the major recession of the late-1970s and early '80s--a downturn in which the 1970s' energy price spikes played a leading role.  For example, US GDP grew at an annual rate of 7.2% in 1984, the year before oil prices began their slide from the high $20s to mid-teens per barrel.  So when new supplies from the North Slope and North Sea came onstream, the market was ready and eager to use them.  Lower, relatively stable oil prices persisted for more than a decade. 

Current global economic conditions have much more in common with either the late-1990s Asian Economic Crisis or the combined recession and financial crisis from which we're still emerging.  Each of these situations included a short-lived global oil price collapse that ended when OPEC constrained output and the economy moved past the point of sharpest contraction.  The late-90s oil price collapse looks especially relevant for today, because increased production contributed to it.

A new factor that would tend to make any oil-price slump due to unconventional oil self-limiting is its relatively high cost.  Mr. Maugeri makes it clear that his output forecast depends on prices remaining generally above $70/bbl, and that any drop below $50-60/bbl would result in curtailed investment and slower expansion.  The picture that this paints for me is one in which new oil supplies would be there if we need them to meet growing demand but not otherwise.  That should narrow the implications of such an expansion for renewable energy.

As Mr. Bullis reminds his readers, the connection between oil and renewable energy is much more tenuous than many of the latter's proponents imagine.  The US gets less than 1% of its electricity supply from burning oil, so technologies like wind and solar power simply have no bearing on oil consumption, and vice versa.  That is less true outside the US, but the trends there are also moving in this direction.  So other than for biofuels, a steep drop in oil prices for any reason would have little impact on the rationale for renewables, except perhaps psychologically.  The two factors on which renewable energy investors and manufacturers should stay focused are the economy and the price of natural gas, against which renewables actually do compete and have generally been losing the battle, recently. 

Time will tell whether the Harvard oil production forecast turns out to be more accurate than other, more pessimistic views.  Yet while a drop in oil prices due to expanding supply wouldn't do any good for renewables, the single biggest risk the latter face is the same one that would be likeliest to trigger a major oil price collapse: not surging unconventional oil output, the impact of which OPEC will strive hard to manage, but a return to the kind of weak economy and frozen credit that we should all be able to recall vividly.  If anything, the consequences for renewables from that risk look much bigger today than a couple of years ago, because of the global overcapacity in wind turbine and solar panel manufacturing that built up as the industry responded to policy-induced irrational exuberance in several key markets.

How Helpless Are We in the Face of Rising Oil Prices?

Oil is rarely not political, and with gasoline prices hitting record levels early in a presidential election year, we shouldn't be surprised that both the President and his challengers have focused on energy policy. President Obama gave what was billed as a major speech on energy at the University of Miami in Florida yesterday. After urging more students to study engineering--a sentiment I would strongly second--he laid out his view of the situation and its solutions. He got a lot right, including the long-term nature of the problem and the value of improving the efficiency of our vehicle fleet. But unfortunately, he also missed the mark in many ways and generally reflected the exaggerated fatalism that his administration has consistently exhibited towards oil prices. Boosting domestic supply is not the only answer, but it could be far more effective in moderating high oil prices and their impact on the economy than the President admitted.

To see why requires a sense of how the oil market works, as well as the uses to which we put oil today, rather than a generation ago. For starters, although the President has worked hard to improve conditions for renewable energy sources like wind and solar power--sources that certainly have an important role to play in our long-term energy mix--these technologies, along with nuclear power, are out of place in a conversation about oil prices in 2012. That's because they produce electricity rather than liquid fuels, and less than 1% of US electricity is generated from oil today, compared to more than 10% in 1980. Electricity from renewable and nuclear power doesn't compete with imported oil or any other kind of oil; it competes with domestic energy sources like coal and natural gas, most of which now comes from conventional and unconventional gas fields, rather than as a byproduct of producing oil. So by all means lets have a conversation about renewables in the context of reducing greenhouse gas emissions today and displacing oil from transportation when there are tens of millions of electric vehicles on the road in the future, but in terms of oil prices now and in the near future, they are a rhetorical diversion.

Fuel efficiency and plain old conservation can play an important role in reducing both our exposure to higher oil prices and in contributing to lower prices, because both attack demand directly, and demand is a big factor in oil prices. The President is right to emphasize this. Americans have cut back on oil consumption to the tune of 1.8 million barrels per day since 2007, and this was a significant factor in the oil price collapse in late 2008 and the generally lower prices we've enjoyed since then. Unfortunately, that happened largely as a result of the recession and financial crisis, rather than a sudden spike in fuel efficiency. If Americans buy the new, more efficient cars that Detroit must make under the administration's stricter Corporate Average Fuel Economy standards, then over the next decades the efficiency of the US car fleet will improve significantly, and even after rebound effects our oil demand and need for imported oil should fall. But let's not delude ourselves that this can happen overnight. There are roughly 250 million cars, SUVs and light trucks on the road in the US today, and even at pre-recession sales levels it will take more than a decade to turn over enough of them to make a serious dent in oil consumption.

President Obama made only a passing reference to biofuels in his speech, and for good reason. At current production levels ethanol displaces up to 600,000 bbl/day of petroleum gasoline, after adjusting for its lower energy content. That's good, but we've essentially played that card already and can't play it again. Almost all the gasoline sold in the US today contains 10% ethanol, the maximum level that most cars can tolerate without damaging their fuel systems or voiding their warranties. There's little appetite among consumers for the 85% ethanol E85 blend that flexible fuel vehicles can use, and there's even less appetite among fuel distributors for the 15% ethanol blend that the EPA blessed in 2010. With ethanol maxed out for now, our focus must shift to biofuels that are much more compatible with gasoline and diesel fuel, and that rely on technologies that haven't yet been demonstrated at commercial scale or competitive cost.

And that brings us back to the potential for reducing our dependence on oil imports and moderating oil prices by producing more domestic oil. Now, it's certainly true that US oil production and consumption are only part of a much larger global oil market, where prices are actually set. The US couldn't control the global price of oil, as it once did, even if we imported virtually no oil from outside North America. However, it's simply not correct to gauge the potential impact of an extra million bbl/day of US production--a figure that is well within the range of what a more aggressive domestic drilling program could deliver--by comparing it to the entire global output of nearly 90 million bbl/day. As with other commodities like grain and coffee, the price of oil is determined by relatively small changes in supply, demand, inventories, and in the case of oil, spare capacity. What really counts is the last few million barrels per day that are traded, whether inventories are rising or falling, and how large global spare capacity is and who owns it. The last three times that oil prices collapsed, in the mid-1980s, late-1990s, and 2008, it happened as a result of net changes in these parameters amounting to less than about 3 million bbl/day.

Yesterday the President cited statistics indicating that US oil production has returned to levels we hadn't seen for several years. That's true, and it's equally true that this modest surge of about 14% is the result of factors over which his administration had no control: oil prices and federal policies in the previous administration and the application of improved drilling technologies in the deepwater Gulf of Mexico and onshore locations like North Dakota's Bakken formation and the Eagle Ford shale of Texas. Moreover, it's only technically accurate to state that he has "opened millions of acres for oil and gas exploration", when the lease sales in question were originally scheduled to have taken place earlier, and were to have encompassed much more acreage, including offshore acreage that has been off limits for decades, such as offshore Virginia. The Deepwater Horizon accident certainly changed the context for the President's previous drilling plans, but his administration's responsibility for the subsequent decline in offshore production, the slower pace of development and tighter geographic constraints on where the industry can look for oil since then must be acknowledged in this discussion.

Then there's that other shibboleth of oil prices, speculation, which was also mentioned yesterday. As I've discussed previously, there are times when speculation can increase some oil prices, at least for a brief period. However, it's worth recalling that for every trader buying futures contracts or options in hopes they will go even higher, some seller must take the position that current prices are high enough and likely to be lower, later. This adds a froth of sentiment to the market, but it can't sustain prices for long if fundamentals aren't supportive and if the physical market doesn't follow. So while politicians see a $10/bbl rise this month in the price of West Texas Intermediate on the futures market as a symptom of speculation, they tend to ignore data like the much larger recent increase in the spot price for Louisiana Light Sweet crude, for which someone must take physical delivery at St. James, Louisiana, rather than just offsetting against another "paper barrel". When you look at physical oil inventories, there's no evidence that speculators are taking delivery of large quantities of oil and storing it so refiners can't buy it.

The key factors driving the recent increase in oil prices are tensions with Iran and the fact that, with production off-line in places like Sudan and still not back to pre-revolution levels in Libya, OPEC's effective spare capacity is below 3 million bbl/day, not much above the level that contributed greatly to oil's near-$150 peak in mid-2008. So despite relatively weak demand growth, the market looks tight now, with the prospect of Iran cutting off sales--or being embargoed via sanctions from buyers--by a volume that would erode that cushion of spare capacity in Saudi Arabia and a few other Persian Gulf producers even further--capacity that mostly sits inside the Strait of Hormuz.

So what levers does this President--or any President--really have with which to try to moderate oil prices over the next few years? It's clearly not renewable energy policy at this point. It could include foreign policy, particularly if you agree with the view of Washington Post columnist David Ignatius that Iran has displayed a clear pattern of backing down in the face of "overwhelming force". Resolving the Iranian threat to Gulf shipping and setting the outlines of a solution to Iran's nuclear program could take $20/bbl off the price of oil in fairly short order, though I wouldn't suggest that looks easy. Yet even though a decision to expand access to US oil resources significantly, along the lines of the President's pre-Deepwater Horizon plan, would not deliver new production quickly, it's wrong to be dismissive about the impact of more drilling on prices or in mitigating the impact of those prices on the economy. And in the case of onshore opportunities for which infrastructure is already in place or in the works--and here I would include the Keystone XL pipeline--it need not take 10 years for the first barrels to reach market. Together with a strong, technology-neutral effort on fuel economy, a new, more expansive approach to exploiting domestic resources would affect the back end of the futures price curve, and that could start to nudge down nearer-term prices, as well. Even if I'm wrong about that, it's still the case that at current prices every additional 1,000 bbl/day we produce here would reduce our trade deficit and the drag on our economy by about $40 million--and there are a lot more thousands of barrels per day we could be producing.

At least one of the President's potential challengers has described a plan for getting gas prices back to $2.50 per gallon. Perhaps this had something to do with President Obama's choice of topic yesterday. I will devote a lot more time to analyzing such proposals once the Republicans have chosen their nominee. However, it's worth noting that as outlandish as $2.50/gal. sounds when the average price of unleaded regular has jumped to $3.59/gal. this week, it works out to an effective crude price of around $70/bbl, after subtracting state and federal taxes and refiner and dealer margins. That's roughly what oil cost in 2006 and 2007 and more than in 2009. It's also a higher price than most oil industry experts even imagined would be possible just a few years earlier.

I don't know if Mr. Gingrich's plan would work, and I suspect that the economics of at least some of the new production necessary to force OPEC to compete on price again, rather than managing the price to suit their own needs, might be challenging at $70/bbl. Yet I'd be much more inclined for us to work towards such a goal than to dismiss it as impossible or irrelevant and fatalistically accept the consequences of $100+ oil for another decade or more. The President should at least be as open to these possibilities as he is to the possibilities of renewable energy for reducing emissions.