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.

Should Alaska Export More LNG to Asia?

The Governor of Alaska reportedly met this week with officials from the South Korean national gas company to discuss exports of liquefied natural gas (LNG). Ever since crude oil production on Alaska's North Slope ramped up in the 1980s, industry observers have speculated about the ultimate disposition of the significant associated natural gas reserves found with the oil. In a letter filed with the state of Alaska, BP, ConocoPhillips and ExxonMobil, the three main North Slope producers, together with pipeline company Transcanada, recently confirmed their plans for a potential liquefied natural gas (LNG) project, instead of the long-mooted pipeline to deliver the gas to America's lower-48 states. The contemplated megaproject would validate both the scale of Asia's future LNG market and the long-term nature of the US shale gas revolution.

Alaska's North Slope has already yielded 15 billion barrels of oil. Production peaked at over 2 million barrels per day in 1988 and subsequently declined to less than 600,000 barrels per day last year. With around 6 billion barrels of remaining reserves, it's still a very significant field but well past its prime. While the public has focused on its oil output, the producers and the state have long had their eyes on how best to harvest the value of the 35 trillion cubic feet (TCF) of gas dissolved in the oil. In fact, the North Slope complex has produced several TCF per year of gas for years, ranking it among the largest gas fields in the world, but almost all of that gas has been reinjected into the formation to aid oil recovery--and for lack of a market in an isolated and sparsely-populated state.

For decades the default assumption was that a pipeline would eventually be built across Alaska and Canada to link this gas to the existing network feeding the contiguous US. That idea gained traction when US marketed gas production stalled around 2000 and then began to decline. The economics of an Alaskan gas pipeline compared poorly with gas produced along the Gulf Coast, but competing with rising LNG imports looked much more feasible. Then along came unconventional gas, starting with coal-bed methane and culminating with the surge of shale production since 2005. The US gas market now has enough domestic supply to shrink coal's contribution to US power generation by 7% since 2008 and revive gas-intensive industries.

If shale gas were only a short-term phenomenon, as some have suggested, it would be of little relevance to the plans of the North Slope producers. All they'd need to do would be to delay their pipeline for a few more years, and the market would come to them. However, estimates put US shale gas resources at between 482 and 686 TCF--a 60-90 year supply at current shale production rates. And the fact that all three of the main North Slope producers have invested in significant acreage positions and production in US shale basins surely gives them insights into the longevity of those resources.
Nor is time on the side of the Alaskan producers. As oil production declines the economics of the North Slope operation will deteriorate, while keeping the Trans Alaska Pipeline full becomes more problematic. Finding an attractive outlet for the North Slope "gas cap" wouldn't just provide a new revenue source; it could keep oil production going for additional decades.

The LNG option offers several advantages, despite its estimated $45-65 billion price tag and technical complexity. For starters, it cuts roughly 1,000 miles of difficult terrain off the distance that the gas must be pipelined, in this case to a site on the southern Alaskan coast. That location is much closer to Asia, the world's largest LNG market, than export projects intended to ship LNG from the US Gulf Coast. The Asian market is also growing, thanks in part to Japan's post-Fukushima reassessment of nuclear power. The Japanese government has backed away, at least for now, from plans for a firm nuclear phase-out, but it seeks to diversify its energy sources. Among other steps taken in the aftermath of the Sendai quake and nuclear disaster, it has instituted the world's most attractive solar power incentives. Yet Japan's solar resources provide just a few hours of peak output per day, on average, requiring substantial fossil fuel generation to fill in the gaps. Power plants burning LNG are well-suited to that task.

China presents a more complex picture, with its own significant shale gas potential and an energy market expected to add as much natural gas demand by 2035 as all the world's developed countries put together. Considering the scale of eventual demand and the infrastructure necessary to bring China's shale gas to market, it seems likely that the growth of the market in the interim must depend heavily on LNG imports.

Assuming that the state of Alaska presents no obstacles and that US export permits would be forthcoming, because Alaskan LNG exports wouldn't impact US natural gas prices, the main questions that will determine the future of this project can't be answered definitively today. Among these are whether the numerous competing LNG projects being planned and built around the Pacific Rim and elsewhere will saturate the global market in the meantime, and whether the market will provide an attractive price for Alaskan LNG, influenced more by crude oil prices than by US shale gas. The North Slope producers are already immersed in these issues via their other activities, including ConocoPhillips' small LNG plant in Kenai, Alaska, which has been shipping LNG to Asia for more than 40 years. The project timeline provided to the state includes at least three go/no-go decisions along the way as the answers to these questions unfold.

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

Should the US Become An Oil Exporter, Again?

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

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

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

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

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

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

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

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

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