Friday, September 19, 2014

The Two Energy Revolutions Are Progressing in Tandem

Last year I wrote about the two major energy revolutions happening globally, the shale revolution--mainly in the US--and the renewable energy revolution, focused more on technologies than geography but with big concentrations in Europe and increasingly Asia and the Americas. Two stories in the Financial Times (registration/subscription required), which has lately been doing an excellent job covering energy, illustrate that we are still in the early days of both. Bigger changes lie ahead.

One story covers the development of the "South Central Oklahoma Oil Play", or SCOOP, an acronym that's new to me and, I suspect, many of my readers. Continental Oil, a major player in the Bakken and other shale oil resource areas, has apparently reported that SCOOP may contain up to 3.6 billion barrels (oil equivalent) of recoverable oil and gas. That's more oil than was produced in Alaska in the last 15 years, based on the graphic accompanying the article.

Along with the unconventional portions of the Permian Basin in Texas and New Mexico and Ohio's Utica shale, and with the reviving liquids production from Wyoming's Powder River Basin and elsewhere, the upside for US oil output still looks significant. Its economics may become challenging if oil prices remain weak for more than the next year or two, but our picture of oil and gas as mature resources may need to be revised.

The title of the other article, "US Solar and Wind Start to Outshine Gas" seized my attention. Its key quote is from the head of power, energy & infrastructure at investment bank Lazard: "We used to say some day solar and wind power would be competitive with conventional generation. Well, now it is some day"--at least for some technologies, in some locations, at larger scales.  The firm's latest analysis shows continued cost declines for wind and solar.

It also raises a very interesting and pertinent question about whether subsidies for residential-scale solar (i.e., rooftop PV, which remains much costlier than at utility scale) are "distorting the long-term energy planning process." That's a question we are likely to hear a lot more about when the current US 30% investment tax credit for solar equipment, which benefits higher-cost installations more than cheap ones, comes up for renewal. Nevertheless, solar power, particularly in combination with emerging energy storage solutions, looks increasingly likely to transform the utility landscape in the years ahead.

You may have noticed a decrease in my blogging frequency, recently. I've been preoccupied with project work and personal matters for the last couple months, but I should be back to my normal pace by October. There's certainly no shortage of topics worth discussing here.

Friday, September 12, 2014

Exporting US Oil to Mexico

  • Mexico could become a major export destination for surplus US light crude oil, despite being one of the largest oil suppliers to the US, mainly of heavy oil.
  • If structured as an exchange for other barrels, such exports might not require re-writing US oil export regulations, unlike sales to non-neighboring countries.
Two of the biggest energy stories of the last twelve months have been the reform of Mexico's oil sector after 75 years of state monopoly and the US oil industry's drive to gain approval to export a growing surplus of domestic light crude oil. The prospect of exporting US oil to Mexico connects these developments in a surprising way. It should make sense geographically and economically, though regulatory hurdles remain. Yet it could also increase tension between US oil producers and refiners over the merits of exporting crude versus refined products.

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

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

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

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

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

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

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

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

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

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

Wednesday, August 27, 2014

Threats and Opportunities of Distributed Power Generation

  • Rooftop solar panels aren't the only distributed generation technology that could challenge existing utility business models as it grows.
  • Some power companies see DG as an opportunity and are entering this segment in ways that could prove challenging to their start-up competitors.
Two recent news stories highlighted different ways that utilities and large generating companies are beginning to respond to the emergence of distributed generation (DG) as more than back-up power. Arizona Public Service (APS) is launching its version of potentially the most challenging type of DG for utilities, rooftop solar. Meanwhile, Exelon Corp. announced an investment partnership with a provider of gas-powered fuel cells. The success of such ventures and the evolution of DG will have implications for electrical grid stability and our future energy mix, including the role of flexible, large-scale gas-fired generation.

APS is seeking regulatory approval for a program that might be characterized as free rooftop solar. In effect, they would lease approved homeowners' rooftops for $30 per month, in order to host a total of 20 MW of solar panels that would be owned and controlled by APS. The idea has generated some controversy, partly due to the utility's rocky relationship with the solar industry over issues like "net metering". 

The plan would enable homeowners who might not otherwise qualify for solar leasing from third parties to have solar installed on their homes, although they would apparently still receive their electricity through the meter from the grid, rather than mainly from the rooftop installation. That's a very different model from most DG approaches, though under current market conditions the net benefit to consumers reportedly would match or exceed that from solar leasing.

Exelon's announcement seems aimed at a different segment of the market, and based on a very different technology. The company would finance the installation of 21 MW of Bloom Energy's fuel cell generators at businesses in several states, including California. Bloom made quite a splash when it introduced its "energy servers", including a popular segment on "60 Minutes" in 2010.

Bloom's devices, which come in models producing either 100 kW or 200 kW, are built around solid oxide fuel cells.  At that scale they are too large for individual homes but suitable for many businesses. And because they are modular, they can be combined to meet the energy needs of larger offices or commercial facilities such as data centers. Unlike the fuel cells being deployed in limited numbers of automobiles, they do not require a source of hydrogen gas. Instead they run directly on natural gas from which hydrogen is extracted ("auto-reformed") inside the box.

In that respect, despite their novel technology, Bloom's servers are much closer than rooftop solar to traditional distributed energy, in which a customer owns or leases a small generator to which it supplies fuel. The advantages of Bloom's model are that its servers are designed for highly efficient 24x7 operation, without the expensive energy storage necessary to turn solar into 24x7 power, and with much lower greenhouse gas emissions and local pollution than a diesel generator.

In order to qualify as true zero-emission energy, these installations would need to be connected to a source of biogas, e.g., landfill gas, which effectively creates a closed emissions loop or recycles emissions that would have occurred elsewhere.  Even running on ordinary natural gas, the stated emissions of Bloom's energy servers are roughly a third less than the average emissions for US grid electricity, or 20% lower than the average for other natural gas generation. However, their emissions are over 10% higher than the 2012 average for California's grid.

I find it interesting that Exelon, the largest nuclear power operator in the US and owner of a full array of utility-scale gas, coal, hydro, wind and solar power, would make a high-profile investment in a technology that could ultimately slash the demand for its large central power plants. The company has invested in utility-scale solar and wind power, and as the press release indicated, is already involved in "onsite solar, emergency generation and cogeneration" via its Constellation subsidiary. In fact, it has apparently already achieved its goal of eliminating the equivalent of its 2001 carbon footprint.  However, the press release hints that something else might have attracted them to this deal.

Consider all the changes in store for the power grid. Baseload coal power is declining due to the combination of economic forces and strong emissions regulations such as the EPA's Clean Power Plan. Even some nuclear power plants, which have been the workhorses of the fleet for the last several decades, are facing premature retirement for non-operational reasons. At the same time, grid operators must integrate steadily growing proportions of intermittent renewable energy (wind and solar), along with increasingly sophisticated tools like demand response and energy storage. If any of this goes wrong, electric reliability will likely suffer.

From that perspective, Exelon's small--for them--step into DG also looks like a bet on the future value of reliability--"non-intermittent...reliable, resilient and distributed power." That's a bet even an old oil trader can understand: Uncertainty creates volatility, and volatility creates opportunities. I will be very interested to see how this turns out. 

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

Wednesday, August 06, 2014

The Missing Oil Crisis of 2014

  • While the full impact of the surge in US "tight oil" may be masked by problems elsewhere, it is on the same scale--but opposite direction--as key factors that led to the 2007-8 oil price spike.
  • In that light it does not seem like hyperbole to credit the recent revival of US oil output with averting another global oil crisis.
Several speakers at last month's annual EIA Energy Conference in Washington, DC reminded the audience that energy security extends beyond oil, starting with Maria van der Hoeven, Executive Director of the International Energy Agency (IEA). In her keynote remarks Monday morning she was quick to point out that it also encompasses electricity, sustainability, and energy's effects on the climate and vice versa. Still, the comment that got my wheels turning came from Dan Yergin, author and Vice Chairman of IHS. During his lunch keynote he suggested that without US tight oil production, this year's conference would have been dominated by another oil crisis.

Although shale energy development certainly deserves to be called revolutionary, crediting it with averting an oil crisis calls for a bit of "show me." Yet with problems in Libya, Nigeria and Iraq, while Iranian oil remains under sanctions and oil demand picks up again, even at first glance Mr. Yergin's assertion looks like more than a casual, lunch-speech sound-bite.

Start with current US tight oil (LTO) production of over 3 million barrels per day (MBD) and estimates of future LTO production rising to as much as 8 MBD--also the subject of much discussion at the conference. As recently as 2008 total US crude oil output had fallen to just 5 MBD and was only expected to recover to around 6 MBD by 2014, with minimal contribution from unconventional oil. Instead, the US is on track to beat 2013's 22-year record of 7.4 MBD, perhaps by as much as another million bbl/day.

With conventional production in Alaska and California declining or at best flat, and with Gulf of Mexico output just starting to recover from the post-Deepwater Horizon drilling moratorium and subsequent "permitorium", the net increase in US crude production attributable to LTO today is in the range of 2.5-3.5 MBD and growing, thanks to soaring output in North Dakota, Texas and other states.

That might not sound like much in a global oil market of over 90 MBD, but it brackets the IEA's latest estimate of OPEC's effective unused production capacity of 3.3 MBD. Spare capacity and changes in inventory are key measures of how much slack the oil market has at any time. When OPEC spare capacity fell below 2 MBD in 2007-8, oil prices rose sharply from around $70 per barrel to their all-time nominal high of $145 per barrel. It took a global recession and financial crisis to extinguish that price spike, and high oil prices were likely a major contributor to the recession.

Global oil inventories are now a little below their seasonal average for this time of the year. Compensating for the absence of over 3 MBD of US tight oil would require higher production elsewhere, lower demand, or a drain on those inventories that would by itself push prices steadily higher.

Concerning production, if the US tight oil boom hadn't happened, more investment might have flowed to other exploration and production opportunities. However, for non-LTO production to have grown by an extra 3 MBD, companies would have had to invest--starting in the middle of the last decade--in the projects necessary to deliver that oil now. Were that many deepwater and conventional onshore projects deferred or canceled because companies anticipated today's level of LTO production more than 5 years ago? And would Iraq, Libya and Nigeria be more reliable suppliers today if US companies hadn't been drilling thousands of wells in shale formations for the last several years? Both propositions seem doubtful.

As for adjustments in demand, US petroleum consumption is  already over 8% less than in 2007. And as we learned in the run-up to 2008, much of the oil demand in the developing world, where it has grown fastest, is less sensitive to changes in oil prices than demand in developed countries, due to high levels of consumer petroleum subsidies in the former. Petroleum product prices in the latter must increase significantly in order to get consumers there to cut their usage by enough to balance tight global supplies. That dynamic played an important role in oil prices coming very close to $150 per barrel six years ago, when average retail unleaded regular in the US peaked at $4.11 per gallon, equivalent to nearly $4.50 per gallon today.

So to summarize, if the US tight oil boom hadn't happened, it's unlikely that other non-OPEC production would have increased by a similar amount in the meantime, or that OPEC would have the capability or inclination to make up the resulting shortfall versus current demand out of its spare capacity. Demand would have had to adjust lower, and that only happens when oil and product prices rise significantly. With oil already at $100 per barrel, it's not hard to imagine such a scenario adding at least $40 to oil prices--just over half the 2007-8 spike. Combined with higher net oil imports, that would have expanded this year's US trade deficit by around $230 billion. US gasoline prices today would average near $4.60 per gallon, instead of $3.54, taking an extra $140 billion a year out of consumers' pockets.

We can never be certain about what would have happened without the current surge in US tight oil, but for a reminder of how a similar situation was characterized just a few years ago, please Google "2008 oil crisis".  If we found ourselves in similar circumstances today, then the heated Congressional hearings and angry consumers to which Mr. Yergin alluded in his remarks would almost certainly have been major topics at EIA's 2014 conference, instead of the realistic prospect of legalized US oil exports.

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

Tuesday, July 29, 2014

Bakken Shale Gas Flaring Highlights Global Problem

  • High rates of natural gas flaring in the Bakken shale formation are symptomatic of infrastructure limitations that prevent this gas from reaching a market.
  • Although various technical options could reduce flaring from high-output well sites, none matches the benefits of developing large-scale outlets for the gas.
The Wall St. Journal recently reported on the high rate at which excess natural gas from wells in North Dakota's Bakken shale formation is burned off, or "flared."  The Journal cited state data indicating 10.3 billion cubic feet (BCF) of gas were flared there during April 2014. That represented 30% of total gas production in the state for the month.

North Dakota's governor attributed the high volume of gas flared in his state to the great speed at which the Bakken shale has been developed, outpacing gas recovery efforts. Oil output ramped up from 200,000 barrels per day five years ago to just over a million today, in a region lacking the dense oil and gas infrastructure of Texas and other states with a legacy of high production.

Nor is this situation unique to the Bakken. The World Bank has estimated that around 14 BCF of gas is flared every day, globally. Such flaring is a problem for more than governments and other mineral-rights owners that worry about missing potential royalties.  Aside from our natural aversion to waste, flaring natural gas has environmental consequences.

The tight oil produced from the Bakken shale is quite low in sulfur, and so is most of the associated gas, but some of it contains relatively high percentages of hydrogen sulfide (H2S). When that gas is flared, rather than processed, the resulting SOx emissions can affect local or even regional air quality.

Gas flaring also contributes to the greenhouse gas emissions implicated in global warming, although it must be noted that flaring is 28-84 times less climate-altering, pound for pound, than venting the same quantity of methane to the atmosphere.  When annualized, and assuming complete combustion of the gas, North Dakota's recent level of flaring equates to around 6.7 million metric tons of CO2 emissions, or nearly a fifth of total estimated US CO2 emissions from natural gas systems in 2012. That means this one source accounts for around 0.1% of total US greenhouse gas emissions, or somewhat less than US ammonia production.

Why would anyone flare gas in the first place? As the Journal pointed out, the oil produced from Bakken wells is worth significantly more than the gas, although the energy-equivalent price ratio favors oil by more like 4:1 than the 20:1 cited in the article. Still, the economics of Bakken drilling are mainly driven by oil that can be sold at the lease and delivered by pipeline or rail, and not by the associated gas, particularly after tallying the cost of capturing and processing it, and then hoping capacity will be available to deliver it to a market that in the case of the Bakken might be hundreds or thousands of miles away. The characteristics of shale wells, with their steep decline curves, raise this hurdle even higher: Shale gas infrastructure at the well must pay for itself quickly, before output tails off.

There is no shortage of technical options for putting this gas to use, instead of flaring it. An industry conference in Bismarck, ND this spring featured an excellent presentation on this subject from the Energy & Environmental Research Center (EERC) of the University of North Dakota. Among the options listed by the presenter were onsite removal of gas liquids (NGLs), using gas to displace diesel fuel in drilling operations, and compressing it for use by local trucking or delivery to fleet fueling locations. However,  contrary to the intuition of the rancher interviewed by the Journal, none of these options would reduce high-volume flaring by more than a fraction, despite investment costs in the tens or hundreds of thousands of dollars per site.

Even in the case of the most technically interesting option, small-scale gas-to-liquids conversion to produce synthetic diesel or high-quality synthetic crude, EERC estimated this would divert only 8% of the output from a multi-well site flaring 300 million cubic feet per day, while requiring an investment of $250 million. And to make this option yet more challenging to implement, of the 200-plus such locations EERC identified in the state, fewer than two dozen flared consistently at that level over a six-month period. The problem moves around as older wells tail off and new ones are drilled.

Significantly reducing or eliminating natural gas flaring ultimately requires a large-scale market for the hydrocarbons being burned off. That's as true in North Dakota as in Nigeria. While various technical options could incrementally reduce gas flaring from Bakken wells, the highest-impact solutions would be those that promote market creation. That would include fast-tracking long-distance gas pipeline projects or building gas-fired power plants nearby. Absent large new customers for Bakken gas, additional regulations on flaring will either be ineffective or impede the region's strategically important oil output.

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

Friday, July 18, 2014

Condensate Pries Open the Oil Export Lid

  •  A US ruling to allow limited exports of condensate, a light hydrocarbon mix similar to light crude oil, has implications for both producers and refiners, though not consumers.

  • Whether or not it leads to wider US exports of condensate and crude, it signals just how much the US energy situation has changed since the oil export ban was first imposed.

Last month we learned that the US Commerce Department gave two US companies permission to export condensate that would otherwise be trapped here under a 1970s-vintage ban on US oil exports. This validates the view, as described in a white paper from the office of Senator Lisa Murkowski (R-AK) earlier this year, that the administration has the statutory authority necessary to allow such exports. An entire session at this week's annual EIA Energy Conference was devoted to the details of this ruling, and whether it paves the way for broader exports of a growing US surplus of condensate and light sweet crude oil.

Over the past several decades US refineries invested an estimated $100 billion to enable them to process the increasingly heavy and sour crude oil types available for import. As a result, most US refineries, particularly on the Gulf and west coasts, are no longer equipped to run large volumes of the extremely light condensates and oils now coming from onshore shale deposits. Allowing producers to achieve world-market prices for their output should boost the economy and raise tax receipts, yet is unlikely to harm consumers.

Condensates are a class of hydrocarbons distinct from crude oil, though they share enough oil-like characteristics frequently to be lumped in with the latter, as in US export regulations. The technical definition of condensates encompasses both the “natural gasoline” extracted during the processing of natural gas produced from oil fields (“associated gas”,) as well as the heaviest liquids separated from “non-associated” gas, i.e. from gas fields, rather than oil fields.

The condensate being exported in this case comes mainly from liquids-rich shale deposits like the Eagle Ford in Texas, which produces varying proportions of dry gas, “wet” gas containing NGLs and condensate, and crude oil, depending on well location. Condensate apparently accounts for around 20-40% of Eagle Ford “tight oil” output.

Condensate mainly consists of natural gas liquids like ethane, propane and butane, along with substantial quantities of naphtha, a low-octane mix of hydrocarbons that boils in the gasoline range, plus much smaller proportions of diesel and heavier “gas oils” than would be typical of crude oil. The naphtha in condensate can sometimes be blended into gasoline, depending on its specific qualities, or processed in a refinery to yield higher-quality gasoline components.

Subsequent to the phase-out of tetraethyl lead, most gasoline from US refineries has been a blend of higher-octane naphtha produced by catalytic cracking units and the “reformate” from catalytic reforming units, with provision for further blending during distribution with up to 10% ethanol. Last month US refineries set an all-time record for gasoline production, at over 10 million barrels per day. They are unlikely to miss the naphtha exported in condensate.

Historically, the global market for condensate has had important distinctions from the broader crude oil market, based on the inherent characteristics of these liquids and the end-users seeking them. Refiners running mainly heavy oils sometimes buy condensate for blending, to lighten their average inputs and fill gaps in their processing capacities.

With the Gulf Coast now drowning in light “tight oil” from shale, this is becoming too much of a good thing, as refiners increasingly have more light material in their feedstock than their facilities can easily handle. One presenter at the EIA conference described the situation as building toward a "day of reckoning", when the discounts required to induce US refiners to process excess light crude instead of imported heavier crude would reach the level at which producers must throttle back oil production. Another expert with whom I spoke was adamant that that day of reckoning has already arrived. One result is investment in new facilities to provide minimal processing–really just distillation–for condensate.

By contrast, petrochemical producers, particularly in Asia, are expected to import growing volumes of condensate for use in the production of olefins like ethylene and propylene, and aromatics like toluene and benzene, from which to make plastics, solvents and other petrochemicals. In that market, US condensate will compete with condensate from other gas producing nations, and with exports of refinery naphtha from Europe and elsewhere. This looks like a good opportunity for US producers.

Some advocates of lifting the ban on crude oil exports see the Commerce Department’s ruling as a precedent for allowing exports of all types of oil, or at least a good first step. However, other reports have focused on this ruling as an end-run around the export rules by redefining minimally processed condensates as a petroleum product, and thus exempt from the ban. In that view, the resulting precedent from condensates for exports of true crude oil may be weaker than that from ongoing, permitted oil exports to Canada.

Either way, allowing condensate exports is a smart move that, if continued, should ease crude congestion on the Gulf Coast and reduce the discounts that could make domestic oil less economical to produce, to the benefit of foreign suppliers. It might even push the problem beyond the current election year and enable Congress to consider normalizing all oil exports without the inhibiting effect of populist pressures at the polls. In the meantime, you can bet these condensate exports will be closely scrutinized for any noticeable effects, good or bad.

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

Wednesday, July 09, 2014

ISIS Threatens Iraq's Oil Upside

  • Even if its threat to Iraq's oil exports can be contained, the newly asserted "Islamic State of Iraq and Syria" has altered the political risk of projects there.
  • That could hamper future production that was expected to be a major factor in meeting growing oil demand later this decade.
Last month's blitzkrieg advance of Al Qaeda spinoff ISIS in northwestern Iraq rattled global oil markets and politicians. Oil prices have risen by only a few dollars, reflecting the remoteness of the current threat from Iraq's main producing region and validating OPEC's recent characterization of the global oil market as "adequately supplied." Yet even as the rebel offensive appears to stall, the escalation of risk in Iraq and its neighbors could affect geopolitics, oil supplies and fuel prices for the rest of the decade.

Iraq currently exports around 2.7 million barrels per day (MBD) of oil, or 7% of global oil exports. It is effectively the number two producer in OPEC. Having recovered beyond pre-war levels, Iraq's oil industry has been growing, while Iran's exports are constrained by international sanctions and Libya's output has become highly erratic following that country's revolution.

In the International Energy Agency's latest Medium-Term Oil Market Report Iraq accounts for 60% of OPEC's incremental production capacity through 2019 (see chart below) and nearly a fifth of all new barrels expected to come to market in that period. This is a more conservative view of Iraq's growth potential than in previous scenarios, but it still leaves Iraqi oil, together with " tight oil" in the US and elsewhere, as the bright spots of the IEA's supply forecast.

Following ISIS's capture of Mosul in northern Iraq, the Heard on the Street column in the Wall St. Journal painted a stark picture of how the destabilization of Iraq could limit investment in the country's oil industry, truncating its expansion. That would increase longer-term oil price volatility and make investments elsewhere more attractive, not just in North American tight oil but also in energy efficiency and alternatives to oil.

Warning signs seem ample. The "Islamic State in Iraq and Syria" might never capture Baghdad or directly threaten the giant oil fields of southern Iraq that are reviving with help from international firms like BP, ExxonMobil and Shell. However, ISIS's actions in the territory they now control, and the fears they incite across a much larger swath of Iraq, are sparking renewed sectarian violence and prompting foreign companies to evacuate personnel. This undermines the IEA's medium-term forecast, which despite being "laden with downside risk" will apparently not be revised in light of recent events. It also raises the potential for jumps in nearer-term oil and petroleum product prices.

It is noteworthy that oil prices haven't gone up significantly, as they did when Libya's revolution began. From February 15 to April 15, 2011 the price of UK Brent Crude jumped 22%.  Iraq's troubles added about 5% to the Brent price, some of which has already dissipated. However, average US gasoline prices are $0.21 per gallon ahead of their level for the same week last year, in part because tensions in Iraq and elsewhere have forestalled the typical post-Memorial Day price drop.

The market's relatively muted response could change abruptly if the Iraqi military suffered further setbacks at the hands of ISIS and its allies, or if ISIS turned its attention to the oil infrastructure of central and southern Iraq. They attacked the country's largest refinery at Baiji, north of Baghdad, and I have seen conflicting reports of its current status.

As several analysts have noted, anything that threatened the country's oil exports, most of which pass through the Gulf port of Basra, could send oil prices substantially higher. That's because other supply outages have reduced usable spare production capacity elsewhere--oil that isn't now being produced but could ramp up quickly--to less than 4 MBD, a narrower margin than in several years. Even if lost Iraqi output were made up by Saudi Arabia and the UAE, the further contraction of spare capacity would drastically increase price volatility and boost oil prices from today's level, until Iraq's exports--or Iran's--were restored.

Nor would booming domestic oil and gas-liquids production, which is surely helping to hold down global oil prices, insulate US consumers from increases at the gas pump. The oil that US refineries process and the products they sell are still priced based on the global market. If Brent crude spikes, so will US gasoline and diesel. That would have less impact on the US economy than in the past, when imports made up a much higher share of supply, but shifting money from the pockets of consumers to those of oil company shareholders is rarely popular.

An Iraq-driven oil price spike would affect politics and geopolitics, too. An unstable Iraq makes it more difficult to maintain the sanctions pressure on Iran, particularly if the US and Iran ended up coordinating their responses  in Iraq. It's even harder to envision a consensus on keeping  more than 1 MBD of Iran's oil bottled up if oil prices returned to $150/bbl.

That could also complicate the debate over exporting US crude oil, already a tough sell for politicians who came up during the era of energy scarcity. As a practical matter, if exports began while prices were rising sharply for other reasons, convincing US voters that the two factors were unrelated would be challenging. A full-blown oil crisis in Iraq or the wider Middle East would likely result in the idea being tabled for an extended period.

It's tempting to view the success of ISIS in seizing territory on both sides of the Iraq/Syria border as a temporary outgrowth of Syria's civil war. If that were the case, the situation might revert to the status quo ante, once the Iraqi army--with some outside help--mopped up ISIS.

Even if this genie could be rebottled, however, the aftermath of the Iraq War and the "Arab Spring" revolutions is exerting  great stresses on the post-World War I regional order, overlaid on 13 centuries of animosity between Sunnis and Shi'ites.  An accident of history and geology has made this area home to much of the world's undeveloped conventional onshore oil reserves. Can its stability be restored with a few deft military and diplomatic moves, or might that require a complete rethinking of boundaries and nations, as recently suggested by the foreign affairs columnist of the Washington Post?

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