Donald Trump vs. OPEC

As of last week's price report from the US Energy Information Administration, the average US pump price of regular gasoline has gone up by $0.19 per gallon since the first week of March. That reflects normal seasonal factors but is mainly due to a jump in international crude oil prices of around $8 per barrel in the same period. President Trump's accusation that OPEC is responsible for rising fuel costs shouldn't have surprised anyone:

Last Friday's tweet prompted a quick retort from Saudi Oil Minister al-Falih: "there is no such thing as an artificial price." It doesn't require a deep study of OPEC or economics to conclude that, however phrased, Mr. Trump's remark was closer to the truth than his chosen foil's reply on this issue.

The more interesting question is whether OPEC's very intentional efforts in conjunction with Russia to tighten oil markets are actually harmful to US interests at this point. Could our instinctive reaction to rising oil prices be based on outdated thinking from the long era of perceived scarcity that began with the oil crises of the 1970s and ended, more or less, with this decade's US shale boom?

Let's recall that less than four years ago oil prices fell below $100 per barrel as the rapidly growing output of US shale, or "tight oil" production from wells in North Dakota and South and West Texas created a global oil surplus and rising oil inventories. Oil prices went into free fall around the end of 2014--eventually bottoming out below $30 per barrel--after Saudi Arabia and the rest of OPEC abandoned their output quotas and opened up the taps.

That response to the shale wave began the only period in at least four decades when the oil market could truly be characterized as free, when all producers essentially pumped as much oil as they desired. Some referred to it as OPEC's "war on shale."

However, those conditions proved to be just as hard on OPEC as on US shale producers, and by the end of 2016 OPEC blinked. The output agreement between OPEC's members and a group of non-OPEC producing countries led by Russia has been in place over a year, and it has taken this long to dry up the excess inventories that had accumulated in 2015-16. OPEC's quota compliance--historically mediocre at best--was aided significantly by geopolitical factors affecting several producers, notably the ongoing implosion of Venezuela's economy and the oil industry on which it depends.

Given all this, it's fair to say that OPEC has engineered today's higher oil prices, while its leading members contemplate even higher prices. It's much less obvious that this is bad for the US, which now has a vibrant and diverse energy sector and is finally approaching the energy independence that politicians have touted since the late 1970s.

Prior to the shift in the focus of the shale revolution from natural gas to oil, the US was still a substantial net importer of petroleum and its products. In 2010, we imported over 9 million barrels per day more than we exported. That was around half of our total petroleum supply. Today, these figures are under 4 million barrels per day and 20%, respectively.

That means that when the price of oil rises, this is no longer followed by enormous outflows of dollars leaving the US to enrich Middle East and other producers. Something like 80 cents of every dollar increase in the price of oil stays in the US, and in the short run the effect may be even more beneficial as investment in US production steps up in response.

In other words, when oil prices go up and gasoline and diesel prices follow, the main effect on the US economy is to shift money from one portion of the economy to another, rather than the whole economy springing a large leak. What makes that shift challenging is that consumers come out on the short end, while oil exploration and production companies, and to some extent oil refiners, gain.

A useful way to gauge the impact on consumers is to compare one year's prices to the previous year's. When oil prices were falling a few years ago, year-on-year drops of as much as $1.00 per gallon for gasoline (2014-15) put up to $100 billion a year back into the pockets of consumers. That provided a timely stimulus for an economy still recovering from the financial crisis of the previous decade.

As oil prices started to recover last year, these comparisons turned negative. Currently, the average regular gasoline price is $0.31/gal. higher than last year at this time. If gas prices were to stay that much higher than last year's for the rest of 2018, it would impose a drag of about $45 billion on consumer spending. $2.75/gal. is the highest US average unleaded regular price for April since 2014. Although gas is still nearly $1.00/gal. cheaper than it was then, memories tend to be short.

We may be living in a new era of energy abundance, but I am skeptical that our political instincts have caught up with these altered circumstances. The price of gasoline is still arguably the most visible price in America. When it goes up week after week, consumers notice, even in an economy running at essentially "full employment" and growing at 3% per year.

Most of those consumers are potential voters, and this is another election year with much at stake. In that light, I would not expect President Trump to abandon his attack on "artificial prices" for oil, even if it's arguable that the US economy as a whole may not be worse off with oil over $70 instead of below $60 per barrel.

OPEC's War on US Producers

The comments of Saudi Arabia's oil minister at the annual CERAWeek conference in Houston this week provided some sobering insights into the strategy that the Kingdom, along with other members of OPEC, has been pursuing for the last year and a half. Perhaps the ongoing oil price collapse is not just the result of market forces, but of a conscious decision to attempt to force certain non-OPEC producers out of the market.

Notwithstanding Mr. Al-Naimi's assertion that, "We have not declared war on shale or on production from any given country or company," the actions taken by Saudi Arabia and OPEC in late 2014 and subsequently have had that effect. When he talks about expensive oil, the producers of which must "find a way to lower their costs, borrow cash or liquidate," it's fairly obvious what he is referring to: non-OPEC oil, especially US shale production, as well as conventional production in places like the North Sea, which now faces extinction. If these statements and the actions that go with them had been made in another industry, such as steel, semiconductors or cars, they would likely be labeled as anti-competitive and predatory.

We tend to think of the OPEC cartel as a group of producers that periodically cuts back output to push up the price of oil. As I've explained previously, that reputation was largely established in a few episodes in which OPEC was able to create consensus among its diverse member countries to reduce output quotas and have them adhere to the cuts, more or less.

However, cartels and monopolies have another mode of operation: flooding the market with cheap product to drive out competitors. It may be only coincidental, but shortly after OPEC concluded in November 2014 that it was abandoning its long-established strategy of cutting production to support prices, Saudi Arabia appears to have increased its output by roughly 1 million barrels per day, as shown in a recent chart in the Financial Times. This added to a glut that has rendered a large fraction of non-OPEC oil production uneconomic, as evidenced by the fourth-quarter losses reported by many publicly traded oil companies.

That matters not just to the shareholders--of which I am one--and employees of these companies, but to the global economy and anyone who uses energy, anywhere. OPEC cannot produce more than around 37% of the oil the world uses every day. The proportion that non-OPEC producers can supply will start shrinking within a few years, as natural decline rates take hold and the effects of the $380 billion in cuts to future exploration and production projects that these companies have been forced to make propagate through the system.

Cutting through the jargon, that means that because oil companies can't invest enough today, future oil production will be less than required, and prices cannot be sustained at today's low level indefinitely without a corresponding collapse in demand. Nor could biofuels and electric vehicles, which made up 0.7% of US new-car sales last year, ramp up quickly enough to fill the looming gap.

Consider what's at stake, in terms of the financial, employment and energy security gains the US has made since 2007, when shale energy was just emerging. That year, the US trade deficit in goods and services stood at over $700 billion. Energy accounted for 40% of it (see chart below), the result of relentless growth in US oil imports since the mid-1980s. Rising US petroleum consumption and falling production added to the pressure on oil markets in the early 2000s as China's growth surged. By the time oil prices spiked to nearly $150 per barrel in 2008, oil and imported petroleum products made up almost two-thirds of the US trade deficit.

Today, oil's share of a somewhat smaller trade imbalance is just over 10%. Since 2008 the US bill for net oil imports--after subtracting exports of refined products and, more recently, crude oil--has been cut by $300 billion per year. That measures only the direct displacement of millions of barrels per day of imported oil by US shale, or "tight oil" and the downward pressure on global petroleum prices exerted by that displacement. It misses the trade benefit from improved US competitiveness due to cheaper energy inputs, especially natural gas.

Compared with 2007, higher US natural gas production, a portion of which is linked to oil production, is saving American businesses and consumers around $100 billion per year, despite consumption increasing by about 20%--in the process replacing  more than a fifth of coal-fired power generation and reducing CO2 emissions. $25 billion of those savings come from lower natural gas imports, which were also on an upward trend before shale hit its stride.

 

The employment impact of the shale revolution has also been significant, particularly in the crucial period following the financial crisis and recession. From 2007 to the end of 2012, US oil and gas employment grew by 162,000 jobs, ignoring the "multiplier effect." The latter impact is evident at the state level, where US states with active shale development appear to have lost fewer jobs and added more than a million new jobs from 2008-14, while "non-shale" states struggled to get back to pre-recession employment. That effect was also visible at the county level in states like Pennsylvania, where counties with drilling gained more jobs than those without, and Ohio, where "shale counties" reduced unemployment at a faster pace than the average for the state, or the US as a whole.

 

If the shale revolution had never gotten off the ground, US oil production would be almost 5 million barrels per day lower today, and these improvements in our trade deficit and unemployment would not have happened. The price of oil would assuredly not be in the low $30s, but much likelier at $100 or more, extending the situation that prevailed from 2011's "Arab Spring" until late 2014. If OPEC succeeds in bankrupting a large part of the US shale industry, we might not revert to the energy situation of the mid-2000s overnight, but some of the most positive trends of the last few years would turn sharply negative.

 

Now, in fairness, I'm not suggesting that this situation can be explained as simply as the kind of old-fashioned price war that used to crop up periodically between gas stations on opposite corners of an intersection. The motivations of the key players are too opaque, and cause-and-effect certainly includes geopolitical considerations in the Middle East, along with the ripple effects of the shale technology revolution. It might even be possible, as some suggest, that OPEC has simply lost control of the oil market amidst increased complexity.  

 

However, to the extent that the "decimation" of the US oil and gas exploration and production sector now underway is the result of a deliberate strategy by OPEC or some of its members, that is not something that the US should treat with indifference.

This is an issue that should be receiving much more attention at the highest levels of government. The reasons it hasn't may include consumers' understandable enjoyment of the lowest gasoline prices in a decade, along with the belief in some quarters that oil is "yesterday's energy." We will eventually learn whether these views were shortsighted or premature.

Has OPEC Lost Control of the Price of Oil?

• The shale revolution effectively sidelined OPEC's control over global oil prices, but the consequences of a year of low prices are shifting power back to the cartel.

In the aftermath of another inconclusive meeting of the Organization of Petroleum Exporting Countries, oil prices have been testing their lows from the 2008-9 financial crisis,  For all the attention and speculation devoted to OPEC-watching whenever they meet, the question we should be asking about OPEC is whether the current situation shares enough of the elements that defined those periods in the past when the cartel's actual market control lived up to its reputation.

That reputation was established during the twin oil crises of the 1970s. US oil production peaked in late 1970, and to the extent there was then a global oil market, the key influence in setting its supply--and thus prices--passed from the Texas Railroad Commission to OPEC, which had been around since 1960.  From 1972 to 1980, the nominal price of a barrel of oil imported from the Persian Gulf increased roughly ten-fold, with disastrous effects on the global economy.

Just a few years later, however, oil prices collapsed.  OPEC's control was undermined by new non-OPEC production from places like the North Sea and Alaskan North Slope and a remarkable 10% contraction in global oil demand. The turning point came in 1985. Saudi Arabia, which had successively cut its output from 10 million barrels per day (MBD) in 1981 to just 3.6 MBD, introduced  "netback pricing" as a way to protect and recover market share.

That move helped set up nearly 20 years of moderate oil prices, during which OPEC's most successful intervention came in response to the Asian Economic Crisis of the late 1990s, when together with Mexico, Norway, Oman and Russia, it sharply curtailed production to pull the oil market out of a tailspin.

The proponents of today's "lower for longer" view of oil prices may see compelling parallels in the circumstances of the mid-1980s, compared to today's. Production from new sources, mainly US "tight oil" from shale, has created another global oil surplus. In the 1980s nuclear power and coal were pushing oil out of its established role in power generation. Now, renewables and electricity are beginning to erode oil's share of transportation energy, while the slowdown of China's economic growth and concerns about CO2 emissions raise doubts about the future growth of oil demand.

However, these similarities break down on some fundamental points. First, the production profile of shale wells is radically different from that of large, conventional onshore oil fields or offshore platforms. Once drilled, the latter produce at substantial rates for decades, while tight oil wells may deliver two-thirds of their lifetime output in just the first three years of operation. Sustaining shale production requires continuous drilling. In fact, new non-shale projects similar to the ones that underpinned oil-price stability from 1986-2003 make up the bulk of the $200 billion of industry investment that has reportedly been cancelled in response to the current price slump.

Another major difference relates to spare capacity. During most of the 1980s and '90s, OPEC maintained significant spare oil production capacity, much of it in Saudi Arabia. That wasn't necessarily by choice, but it was what enabled OPEC to absorb the loss of around 3.5 MBD from Kuwait and Iraq in 1990-91 while continuing to meet the needs of a growing global market. The virtual disappearance of that spare capacity was a key trigger of the oil price spike of 2004-8. (See chart below.)  A little-discussed consequence of OPEC's current strategy to maintain, and in the case of Saudi Arabia to increase output has been a decline in OPEC's effective spare capacity, to just over 2 MBD, compared to 3.5 MBD in the spring of 2014.

As a result, global spare oil production capacity is essentially shifting from Saudi Arabia, which historically was willing to tap it to alleviate market disruptions, to Iran, Iraq and US shale. The responsiveness of all of these is subject to large uncertainties. Iran's production capacity has atrophied under sanctions, and it isn't clear how quickly it can ramp back up once sanctions are fully lifted. Iraq's capacity and output have increased rapidly, but key portions are threatened by ISIS.

Meanwhile, US tight oil production is falling, although numerous wells have been drilled but not completed, presumably enabling them to be brought online quickly, later--perhaps mimicking spare capacity. How that would work in practice remains to be seen. One uncertainty that was recently resolved was whether such oil could be exported from the US. As part of its recent budget compromise, Congress voted to lift the 1970s-vintage oil export restrictions. Even with US oil exports as a potential stabilizing factor, a world of lower or more uncertain spare capacity is likely be a world of higher and more volatile oil prices.

Oil prices were largely unshackled from OPEC's influence last year, after Saudi Arabia engineered a new OPEC strategy aimed at maximizing market share. However, with oil demand continuing to grow and millions of barrels per day of future non-OPEC production having been canceled--and unlikely to be reinstated any time soon--and with OPEC's spare capacity approaching its low levels of the mid-2000s, the potential price leverage of a cut in OPEC's output quota is arguably greater than it has been in some time.

 

In 2016 we will see whether OPEC finally pulls that trigger, or instead chooses to remain on a "lower for longer" path that raises big questions about the long-term aims of its biggest producers.

 

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

An Energy Perspective on the Iran Nuclear Framework

• With enormous natural gas reserves and renewables potential, Iran has little need for nuclear power, and even less for uranium enrichment.
• If Iran's sacrifices in pursuit of its nuclear program cannot be explained by a gap in its energy mix, what will motivate its leaders to abide by the current nuclear deal?

The coverage of the recently agreed international nuclear framework for Iran's nuclear program has missed an important aspect of the story. Nearly all of the reporting and analysis I have read considered the deal from a security and geopolitical perspective, without examining the merits of civilian nuclear power within Iran's domestic energy mix. That goes to the heart of Iran's motivation for future adherence to the terms of the detailed agreement that must shortly follow the broad framework negotiated in Switzerland.

This line of analysis dates back to an article I wrote for Geopolitics of Energy, published by the Canadian Energy Research Institute exactly 10 years ago, in April 2005, and subsequently reprinted in my blog. Other than some outdated figures on energy consumption, reserves and cost, it has held up pretty well, particularly in terms of its main proposition:

"Iran makes an unusual candidate for civilian nuclear power, compared to other countries with nuclear power. Most of these fall into either of two categories: those that lack other energy resources to support their economies, such as France, Japan and South Korea, and resource-rich countries that developed nuclear power as a consequence of their pursuit of nuclear weapons, including the US, former USSR, UK, and arguably China. Blessed as it is with hydrocarbon reserves, Iran does not fall into the former category, and it claims not to fall into the latter. Does it represent a unique case?"

In the years since I wrote that, we've seen a growing interest in nuclear energy elsewhere in the Middle East, including a reported memorandum of understanding between Saudi Arabia and Korea for constructing civilian power reactors in the Kingdom. Such projects in energy-rich Gulf States beg the same questions as in Iran, although the "displacement of oil for export" rationale holds up better for Saudi Arabia and the UAE than for Iran under the current circumstances.

As in 2005, the key to understanding the fit of nuclear power within Iran's energy mix is natural gas. In the most recent country analysis by the US Energy Information Administration (EIA) Iran's domestic energy consumption has grown by roughly two-thirds since the 2003 data on which I based my 2005 article. The EIA data indicate that around 75% of that growth has been fueled by gas. That's not surprising, since Iran now claims 18% of the world's proved reserves of natural gas, having leapfrogged Russia for the top spot a few years ago. At current production rates, Iran has over 200 years of proved gas reserves, compared to about 14 years for the US. (Higher US estimates are based on the less-restrictive category of resources, not reserves.)

Moreover, since 2005 the cost of building nuclear power plants has increased, in some cases significantly, while the cost of natural gas-fired combined cycle turbine power plants has generally declined, thanks to substantial efficiency improvements. For that matter, the cost of alternatives like solar power, which Iran's geography favors, has declined even more in the interim.

A decade after I first examined this question, it is still hard to find a compelling energy rationale for Iran to pursue civilian nuclear power with the persistence it has demonstrated. Developing more of its abundant natural gas would be more cost-effective, perhaps in combination with solar power, which presents natural synergies with gas relating to solar's intermittency. These options would not have triggered the kind of economic constraints to which Iran's choices have led.

Nor does the other rationale to which I alluded above withstand scrutiny in this case, involving the application of domestic nuclear power to free up for export oil and gas that would otherwise be consumed to generate electricity. The implied cost of Iranian gas displaced from power generation would likely be higher than the cost of new gas development, especially when the costs of the full nuclear fuel cycle that is the crux of international concerns are included. If anything, Iran's pursuit of nuclear energy in the last decade has functioned as a reverse fuel displacement mechanism, resulting in costly reductions in oil exports due to international sanctions.

As for the benefits of nuclear energy in cutting greenhouse gas emissions, Iran did not include nuclear power in the list of mitigation measures it presented at the UN climate summit in Durban in 2011, nor did it commit to specific emissions reductions at the Cancun Climate Conference in 2012.

On balance, Iran's objective need for civilian nuclear power scarcely justifies the sacrifices it has endured, or the lengths to which it has gone to secure its nuclear program. Over the last 10 years, buying time through engagement and negotiations led to an opportunity for the "P5 +1" countries to impose the tough sanctions that brought Iran to the point of the current deal, once rising US shale oil production effectively defused Iran's "oil weapon." However, if the current agreement merely buys more time, it risks squandering the best chance to bell this cat. We cannot count on having more slack in energy markets 10 years hence than we do today.

Viewed from an energy perspective, the primary purpose of Iran's nuclear program seems unlikely to be an expanded energy supply, rather than a weapons capability. In that context, the concerns about this deal recently expressed by two former US Secretaries of State who negotiated Cold War arms control agreements with the Soviet Union should be sobering. They deserve serious consideration by both the White House and a Congress that seeks its own opportunity to weigh in.

Is OPEC Washed Up?

• OPEC's unwillingness or inability to reduce output to defend high oil prices raises doubts about the cartel's effectiveness and future.
• Absent cuts by OPEC, it is not yet clear whether the burden of rebalancing oil markets will fall on shale production or larger, more traditional oil projects.

As oil prices continued their slide following OPEC's meeting on Thanksgiving Day, speculation has grown concerning whether the cartel might have run its course. Is OPEC now at the mercy of forces beyond its control? Will its apparent strategy, as widely supposed, mainly affect US shale oil producers, or could more conventional, but still relatively high-cost oil projects elsewhere bear the brunt--or OPEC itself?

A quick review of OPEC's history of reining in production to prop up oil prices reflects a mixed record. At least three distinct episodes come to mind:

• Following the oil crises of the 1970s the cartel was unable to keep prices above $30 per barrel ($70 in today's money) in the face of surging output from the North Sea and North Slope, and a 10% decline in global oil demand from 1979-83. By summer 1986 oil had fallen to just over $10, despite Saudi Arabia's having cut production by up to 6.7 million bbl/day from 1981-85, along with the loss of another couple million bbl/day  of supply due to the Iran/Iraq War. Aside from a spike prior to the Gulf War, oil was rarely much above $20 for the next two decades.
  
• OPEC's response to the Asian Economic Crisis of the late 1990s was more successful. When the growth of such "Asian Tigers" as Indonesia, Malaysia, Singapore, South Korea and Thailand stalled amid contagious currency crises, oil inventories swelled and prices collapsed from the mid-$20s to low teens and less. In March 1999 OPEC agreed to reduce output by around 2 million bbl/day, including voluntary cuts by Mexico, Norway and Russia. Although historical data raises doubts that the latter countries ever followed through on these commitments, this move stabilized prices and restored them to pre-crisis levels by year-end.
  
• After oil prices went into free fall during the financial crisis of 2008, OPEC's members agreed in late 2008 to cut over 4 million bbl/day. They apparently achieved around 75% of that figure. Together with the measures taken by central banks and governments to restore confidence, that was enough to boost oil prices from the low $40s to mid-$70s by late 2009, still well short of the $145 peak in June 2008.

If today's situation were simply the result of slowing economic growth in Europe and Asia, a temporary cut similar to that of 1999 might have received wider support in Vienna. However, the analogy to the 1980s must have resonated strongly, especially with OPEC's longtime-but-not-this-time "swing producer", Saudi Arabia. The Kingdom bore most of the pain then, for little gain. It appears able to weather the current storm, at least financially.

The roughly 4 million bbl/day of "light tight oil" production (LTO) added from US shale deposits since 2008 has certainly depressed oil prices. It's hard to tell by exactly how much, because the growth of shale coincided with high geopolitical risk in oil markets and a volatile global economy. Superficially, it resembles the supply surge of the 1980s. LTO is also generally understood to be high-cost production. Estimates of full-cycle costs vary widely, from the $60s to $90s per barrel.

These factors support the narrative that OPEC, and the Saudis in particular, might be trying to "sweat" shale producers. It's even bolstered by forecasts from the US Energy Information Administration, predating the price drop, suggesting LTO production could plateau within a couple of years and decline not long thereafter.

I see two problems with this scenario. First, shale producers have various options for reducing costs, including some that a more receptive Congress might be inclined to facilitate next year. Then there's the recent history of shale gas pricing. I recall industry conferences in the late 2000s in which speaker after speaker presented curves indicating that the true cost of many US shale gas plays was likely over $6 per million BTUs, and certainly above $5. If that had been accurate, shale gas output should have started to shrink shortly after the spot price of natural gas fell below $4 in 2011. Instead, it has grown by around 13%. This suggests that estimates from outside the shale sector have generally exaggerated production costs that at least one analyst suggests might be as low as $25/bbl on a short-term basis.

If you take a long view, as Saudi Arabia and other Persian Gulf producers arguably must, it's questionable whether the bigger threat to OPEC comes from shale wells that cost a few million dollars each and decline rapidly, or from large-scale projects that can produce for 30 years. An example of the latter is Chevron's new Jack/St. Malo platform, which just began production in the deepwater Gulf of Mexico. (Disclosure: My portfolio includes Chevron stock.) This $7.5 billion facility is expected to recover at least 500 million barrels over its long lifetime. Sub-$70 oil surely means fewer such developments will proceed in the next few years, including offshore opportunities arising from Mexico's sweeping oil reforms. That will have implications for production stretching decades into the future.

The impact of low oil prices could be even more significant for conventional non-OPEC oil production  in more mature regions. Oil investments are expected to fall by 14% next  year in Norway, threatening that country's energy-focused economy. Prospects in the UK North Sea look no better, with a leading expert warning of long-term damage to the regional oil industry. An announced 2% cut in tax rates on extraction profits hardly seems adequate to offset a 38% price decline since June. As things stand now, voters in Scotland dodged a bullet when they  rejected independence, the economics of which depended in part on a sustained recovery in North Sea oil revenues.

Whether shale producers or large investment projects are squeezed more by OPEC's decision to stand pat, it could take months or perhaps years for lower production to appear. As Michael Levi of the Council on Foreign Relations noted, we shouldn't discount OPEC's willingness to act on the basis of its initial reaction to a crisis. However, history also suggests that even if OPEC ultimately acts decisively to defend its desired price level, the outcome may diverge significantly from what they intend. Energy consumers have more choices every day, and that could be the biggest constraint on OPEC's market power going forward.

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

Will Falling Prices Shift Oil Industry's Focus to Cost Reduction?

• Lower oil prices may have less impact on US oil production from shale than competitors in Saudi Arabia and elsewhere appear to assume.
• The cost of  producing tight oil is not static, and US producers have various options for cost reduction, including optimizing their logistics. The newly elected Congress can help.

Oil prices have dropped by more than 20% since July, based on futures contracts for UK Brent crude. Some expect prices to rebound relatively quickly, apparently including at least one large oil services company. However, indications that the official policy of Saudi Arabia may have shifted away from its customary role of "swing producer" raise the possibility of an extended period of lower prices. This is new territory for the relatively young US shale industry.

From the end of 2010 to the first half of this year, as the rapid development of light tight oil (LTO) from shale deposits was adding more than 2.9 million barrels per day (bpd) to US output, the benchmark price of West Texas Intermediate crude oil (WTI) averaged $96/bbl. The global oil price, represented by UK Brent, averaged $110/bbl for the same period. Having now fallen to the $80s, if prices were to stay here or lower for long, we should expect to learn a great deal about the actual cost structure of new and existing LTO production in the Bakken, Eagle Ford, Permian Basin and other shale plays.

Based on my experience of several oil-price declines from the inside during my time at Texaco, Inc., I'm skeptical that many LTO producers would be inclined to trim output from currently producing wells, other than as a last resort. From late 1997 to the end of '98, WTI prices fell by almost half, from around $20/bbl to under $11--equivalent to roughly $15 today.  Prices for heavier grades of oil fell to single digits. After months of that, revenues from some oil fields no longer covered variable costs, and upstream management took the decision to shut in high-cost production. Once prices revived, they discovered that some of that capacity had been lost essentially permanently.

I suspect there would be even greater uncertainty and hesitation today about shutting in producing shale wells for any significant period, especially in light of the limited experience with such wells. The bigger question is whether the drilling of new wells would slow or stop, resulting in a gradual slide in output as existing wells decline.

Then and presumably now, however, the first option in a situation like this is generally to cut costs, rather than output. I saw this in the mid-1980s, when oil prices fell by nearly 60% and took more than a decade to recover fully, then again in the late '90s, and during periodic, smaller market corrections. Suppliers were squeezed, big projects deferred, and employees saw travel, raises and benefits curtailed. Similar actions now could make a difference in keeping new shale drilling going.

Even for relatively efficient operators, it can be surprising how much expense can be reduced without affecting near-term productivity, and many of those savings would persist if prices recovered. LTO producers might ultimately become more profitable after weathering a period of weak prices.

A heightened focus on costs would also likely extend beyond producing company budgets and supplier agreements. One of the biggest non-production costs for LTO is transportation, whether paid directly by the producer or deducted by the purchaser from the market price.  Because of its rapid growth and the constraints of existing infrastructure, a high proportion of LTO output must currently be shipped by rail--up to one million bpd in the second quarter of 2014.

Rail offers flexibility and can reach many destinations, but it is expensive.  For example, if it costs over $10/bbl to ship Bakken crude to the Gulf Coast by rail, that means that with WTI at $78/bbl the producer might realize less than $70/bbl at the wellhead.  Pipelines are often cheaper to use, though not in all cases. The current tariff on the existing Keystone Pipeline for taking oil from the Canadian border to Cushing, OK, the storage hub for WTI, works out to around $4/bbl. If oil prices stayed low for a while, that might increase interest in the proposed Bakken Marketlink Project. It would connect the Bakken shale operations to the Keystone XL pipeline, the prospects for which look decidedly better after the outcome of Tuesday's mid-term election.

Another aspect of transportation costs that could come under a different kind of pressure relates to federal restrictions on shipping oil and petroleum products by vessel between US ports. Under the "Jones Act", only US-flagged, -owned and -crewed ships can perform such deliveries, even though the rates for such shipments are normally significantly higher than on foreign-flag tankers in comparable service. This is a significant factor in current petroleum trade patterns, in which refined products from Gulf Coast refineries are often shipped halfway around the world, while blenders and marketers on the east and west coasts must import gasoline and other products from outside North America.

And as long as US crude oil exports are prohibited, with a few exceptions, the combination of the Jones Act and the export ban effectively keep LTO bottled up on the Gulf Coast--depressing its price--or force it onto rail. Amending the Jones Act to exempt LTO, or the issuance of a waiver to that effect from the Executive Branch, could increase producers' margins while expanding the supply options for US refineries on the other coasts. I wouldn't be surprised to see this taken up by the new Congress early next year.

 Based on the current behavior of oil markets, the global impact of the US shale oil boom has been greater than many expected and seems very much in the national interest of the US--and of US consumers--to keep it going. It remains to be seen whether measures such as new pipeline infrastructure and reform of shipping regulations, together with more traditional forms of expense reduction, could boost producers' returns on LTO sufficiently to sustain drilling at roughly current rates while oil prices are weak. 

Even if both drilling and tight oil production slowed for a while, this price correction won't spell the end of the shale boom. As the Heard on the Street column in the Wall Street Journal put it recently, "Once someone has cracked it, it can't be unlearned. Barring a prolonged period of very low prices, the US oil industry isn't about to disintegrate." Rather than an existential crisis, the current weakness in oil markets looks like a test of adaptability for this new but important energy sector.

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

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

Energy 2013: More Shifts Ahead?

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

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

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

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

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

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

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

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

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

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

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

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

Energy Security Four Decades After the Arab Oil Embargo

• The Arab Oil Embargo of 1973-74 focused our attention on energy security and set in motion drastic changes in the way we produce, trade and consume energy.
• With US energy output approaching or exceeding 1970s levels, some experts now advocate prioritizing competition from non-petroleum fuels over reducing oil imports.

Forty years ago this month the United States and other Western countries experienced a new phenomenon as an embargo on oil deliveries from a group of the world’s largest oil exporters took effect. The embargo was a response to the military support that the US and some of its allies were providing to Israel during the Yom Kippur War then underway in the Middle East. A recent session hosted by the US Energy Security Council commemorating these events included a fascinating conversation between Ted Koppel and Dr. James Schlesinger, US Secretary of Defense at the time of the embargo and later the first US Energy Secretary.

The other, related purpose of the meeting was a presentation and discussion on the proposition that fuel competition provides a surer means of achieving energy security than our pursuit of energy independence for the next four decades following the Arab Oil Embargo. This idea warrants serious consideration, since energy independence, at least in the sense of no net imports from outside North America, is finally beginning to appear achievable.

The 1973-74 embargo was the first oil shock of a tumultuous decade, and it triggered a true crisis. The US had relied on oil costing around $3 per barrel (bbl), not just to fuel our transportation system, but also for 17% of our electricity generation and numerous other uses. The US was then one of the world’s largest oil producers but required imports comprising about one-third of supply to balance our growing demand. With the sudden loss of over a million barrels per day of oil imports from the Middle East, and lacking the sort of strategic petroleum reserve that was established a few years later, an economy already battling inflation was tipped into recession.

The embargo rattled more than the US economy; it challenged basic assumptions of American life, including our sense of entitlement to cheap and plentiful gasoline. Before the oil crisis, gasoline prices hovered around the mid-30-cent mark, with occasional local “gas wars” taking the price down to the high-20s--the inflation-adjusted equivalent of $1.60 per gallon now. Of course with average fuel economy around 13 miles per gallon, the effective real cost per mile wasn’t necessarily lower than today’s.

Within a year gas was over 50¢ at the pump, and by the end of the decade it passed $1.00/gal. for the first time. The gas lines that resulted from the unexpected supply shortfall and the federal government’s efforts to limit the ensuing increase in prices were an affront to drivers, a category that encompassed most of the over-16 population.

That first oil crisis and the subsequent energy crisis resulting from the Iranian Revolution in 1979 set in motion a number of important changes, including a sharply increased focus on energy efficiency, a deliberate effort to diversify our sources of imported oil, a pronounced shift away from oil in power generation — to the point that it now makes up less than 1% of US power plant fuel — and the beginnings of our search for affordable, renewable alternatives to oil.

The US Energy Security Council is an impressive group that includes many former government officials and captains of industry. They’ve clearly spent a lot of time studying this issue, and their report is worth reading. As I understand their conclusions and recommendations, they regard high oil prices as a bigger risk to the US economy than oil imports, per se, because of the impact of oil prices on consumer spending and the balance of trade. They have concluded that the most effective way to apply downward pressure on prices is not simply to reduce US oil imports, but to introduce meaningful fuel competition into transportation markets, where oil remains dominant with a share of around 93%.

The group doesn’t dismiss the benefits of increasing US oil production from sources such as the Bakken, Eagle Ford and other shale formations, but because these are relatively high-cost supplies, they have concluded that their leverage on global oil prices is limited. That means that higher US oil output couldn’t provide a path back to the price levels that prevailed before the Iraq War, when West Texas Intermediate crude averaged $26/bbl in 2002 and gasoline retailed for $1.35/gal.

This is a reasonable argument, though it’s worth considering that a return to $75/bbl might be feasible, if US production kept rising. That could yield US retail gasoline prices around $2.75/gal., equating to $2.15 in 2002 dollars. This isn’t as far-fetched as it might seem, because the global oil price is determined not by the entire 90 million bbl/day of world supply and demand, but by the last few million bbl/day of incremental supply, demand, and inventory changes.

The Council’s view also appears to emphasize the direct impact of oil prices on consumer spending without recognizing that rising production and falling imports shield the economy as a whole from the worst effects of high oil prices. With oil’s contribution to the trade deficit shrinking steadily, the main impact of higher oil prices is to divert money from consumers to shareholders of oil companies — of which I should disclose I am one. While exacerbating income inequality, that should at least result in a smaller impact on GDP and employment than the combination of rising oil prices and rising imports.

If the discussion had stopped at that point, the meeting would have been just another interesting Washington gabfest. However, the group’s analysis includes a set of actions it has identified as necessary for achieving their desired outcome: US energy security extending beyond the current US oil boom, underpinned by an expanding unconventional gas revolution that is widely expected to last for decades.

Their recommendations include giving fuels like methanol derived mainly from natural gas the chance to compete with gasoline made from oil, and with biofuels.They would start with revisions to the current US Corporate Average Fuel Economy standards to give carmakers incentives — not cash subsidies or mandates — to make at least half of all new vehicles fully fuel-flexible, capable of tolerating a wide range of blends of methanol, ethanol and gasoline. That seems like a no-regrets approach that could be achieved at a very low incremental cost per car. Even if you never bought a gallon of E85, M85, or M15, it could pay for itself by protecting your car from the damage that might result if you inadvertently filled up with gasoline containing more than the 10% of ethanol that carmakers believe is safe for non-flex-fuel cars. Other recommendations include easing regulations for retrofitting existing cars for flex-fuel and forming an alcohol-fuels alliance with China and Brazil.

Yet while I repeatedly heard that the group wasn’t promoting any single fuel, talk of methanol dominated the conversation. The moderator, Ann Korin, even joked that the session sounded like an “alcohol party.” As I later pointed out to her, there wasn’t a single mention of drop-in fuels — gasoline and diesel lookalikes derived from natural gas or biomass. I regard that as a crucial omission, because such fuels would be fully compatible with the billion cars already on the road, rather than just the 60 million or so new cars produced each year. They could provide greater leverage on oil prices by producing pipeline-ready products with which consumers are already familiar, from sources other than crude oil.

Part of the appeal of methanol seemed to be the potential for producing it from shale gas at a cost well below the cost of gasoline, even on an energy-equivalent basis — an important caveat, because a gallon of methanol contains half the energy of a gallon of gasoline. I hear the same argument in support of various pathways for producing jet fuel from non-oil sources, and it subscribes to the same fallacy: that market prices are set by manufacturing costs rather than supply and demand.

Fuel is a volume game. For a non-oil gasoline substitute to drive down oil prices –and thus motor fuel prices– as far as the Council apparently envisions, it would take at least several million barrels per day, on an oil-equivalent basis. Producing six million bbl/day of methanol from natural gas would consume 20 billion cubic feet per day of it. That’s 30% of last year’s US dry natural gas production, requiring 100% of the Energy Information Administration’s forecasted growth of US natural gas production through 2034. A number of other entities have their eyes on that same gas for other applications.

As many of the speakers at the Energy Security Council event reminded us, the world is a very different place than it was in 1973. Among other changes, US energy trends are headed in the right direction, with oil demand flat or declining, production rising and imports falling. That alone makes us more energy secure than we were, either five years ago or in 1972. Future oil supply disruptions are also unlikely to look much like the Arab Oil Embargo.

The Council is certainly correct that our unexpected shale gas bonanza, producing large quantities of new energy at a price equivalent to oil at $25 or less per barrel, provides a unique opportunity to weaken OPEC’s influence on oil prices. In pursuing that goal, however, it’s essential to remain flexible concerning the best pathways for gas to compete in transportation fuel markets, whether as CNG or LNG, or through conversion to electricity, methanol, or petroleum-product lookalikes. Consumer acceptance could prove to be the biggest uncertainty governing the ultimate outcome.

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

Will Water Limit Fracking in Arabia?

• Poor water availability could hamper efforts to develop Saudi Arabia's shale gas resources, in order to meet growing gas demand from Saudi industry.
• Water recycling and alternative fracking fluids could provide the solution.  

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

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

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

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

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

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

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

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

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