IEA Sees Fundamental Shifts in the Current Oil Price Drop

• The IEA's latest medium-term oil forecast is a useful update to the thinking behind its current long-term outlook, which predated much of the current price drop.
• They expect shale output to be relatively resilient and rely on Iraq's capacity to expand output in spite of significant security risks.

When the International Energy Agency issued its most recent long-term energy forecast last November 12th, Brent crude oil traded just above $80 per barrel. At that point it had fallen only half as far as it would by January 2015, compared to its June 2014 high of $115. As a result, the IEA's assessment of the price drop in its 2015 World Energy Outlook was incomplete, to say the least. The agency's Medium-Term Oil Market Report, issued in February, provides a necessary update and some interesting insights about how--and how far--they envision the oil market recovering.

Anyone expecting the IEA to provide a detailed oil-price forecast for the next five years will be disappointed. The current report reproduces recent oil futures price curves and generally endorses the consensus that prices won't rise as high as the level from which they have just fallen, at least by the end of the decade. At the same time, in the Executive Summary they remind their audience, "The futures market's record as price forecaster is of course notoriously mixed."  Six months ago West Texas Intermediate Crude for delivery in April 2015 was selling for around $90/bbl; yesterday it closed under $52. So much for the predictive power of futures markets, as most participants are aware.

The report's analysis of the factors influencing the oil supply and demand balance over the next five years is more useful. First and foremost, it recognizes that the factors contributing to this price correction bear little resemblance to the price drops of 1998 and 2008, and share only a few common threads with the big correction of 1986, chiefly involving OPEC's behavior. The biggest differences relate to the nature of the North American shale sector, which drove strong non-OPEC supply growth for the last several years, and the economic and policy factors--slowing growth in China, subsidy phaseouts, and currency depreciation-- likely to dampen the global demand response to cheaper oil.

With regard to shale, the IEA suggests that the current pressures on the US oil industry will prove temporary. They apparently expect the growth of unconventional production from both shale and oil sands to slow but remain the largest source of non-OPEC supply increases through 2020, outstripping increases in OPEC's capacity and offsetting declines elsewhere. Those declines include a 500,000 bbl/day drop in Russian production, mainly due to the effect of sanctions over Russia's involvement in Ukraine.

The agency even suggests that North American shale could emerge from this experience stronger, because of its inherent resiliency. The same factors that should see shale output slow sooner than that from big conventional projects taking years to develop would allow it to ramp up faster, once the current global oil surplus has been consumed. Meanwhile, with larger projects delayed or canceled, conventional production would take longer to return to net growth above normal decline rates. 

That could become the factor that dispels the current skepticism concerning shale oil opportunities outside North America, as apparently exemplified in BP's latest long-term outlook. Companies looking for growth opportunities in a few years might regard developing the shale resources of China, Argentina and Russia--assuming sanctions on the latter end--as lower-cost, lower-risk investments than some deepwater or other big-ticket projects.

As for OPEC, its production growth through 2020 seems to come down to a single country. The report assesses the current situation in Iraq and concludes that despite the threat from the Islamic State and the country's ongoing internal frictions, output should continue to grow by another million bbl/day or so. That strikes me as optimistic, particularly considering the proximity of ISIS forces to Kirkuk, which formerly accounted for around 10% of Iraqi production. Postwar development has focused on the big fields in southern Iraq, which have so far proved to be beyond the reach of ISIS, but a further deterioration of security in the Kurdish north could jeopardize future expansion plans.

The wild card on the supply side is Iran, which under international sanctions has seen its oil exports cut by roughly half. The Medium-Term Oil Market Report explicitly assumes that sanctions will continue. However, if current nuclear talks reached an agreement, sales could ramp up by a million bbl/day over the next year, if buyers could be found. That would alter the IEA's supply/demand calculations substantially.

And that leads us to demand, which at this point is still a key uncertainty. I concur with the report's general assessment that the world has changed since previous oil price drops and rebounds in ways that make a sharp rise in oil use less likely. US demand is up, but as I described in a recent post large groups of consumers around the world have seen little or no relief at the gas pump that might stimulate more consumption.

When I wrote about the IEA's World Energy Outlook last December, I focused on its themes of stress and the potential for a false sense of security. In the short time since then the oil and gas industry has experienced a large dose of stress, but I've seen few signs of complacency on the part of consumers beyond a recovery in the US sales of SUVs and light trucks. That may change if low oil prices persist for a few years.

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

A Lesson in Oil Pricing

• The recent oil-price collapse confirms what we should have learned in 2007-8 about the influence of the last increments of supply and demand on price.
• This also means that future oil prices should be largely independent of the size of the oil market, even in a decarbonizing world.

In 2008, near the peak of a historic oil-price spike, the US Energy Information Administration (EIA) published a study projecting that opening the Arctic National Wildlife Refuge (ANWR) for drilling would reduce oil prices by no more than $1.44 per barrel, compared to their forecast without ANWR. Adding up to 1.5 million barrels per day to US production by 2028 would thus save motorists less than 4¢ per gallon. That result appeared during a Presidential election campaign that featured the slogan, "Drill, baby, drill!" and received significant attention.  I hope the authors of that study have been watching the current oil price collapse, because it provides some useful lessons in how oil prices are determined.

Oil traders and most economists understand that oil prices are ultimately set by the last few million barrels per day of supply and demand in the market, and resulting changes in inventory. The oil price spike of 2007-8 provided firm evidence for this phenomenon, as rapidly growing demand and production problems eroded global spare production capacity to a level of around 2 million barrels per day (MBD) compared to more than 5 MBD in late 2002, prior to the Venezuelan oil strike and the start of the Iraq War. This may have been obscured by the rise of the widely publicized Peak Oil meme, which provided a more viscerally appealing explanation for high oil prices until it ran out of steam recently.

A chart from one of the International Energy Agency's recent Oil Market Reports provides a neat illustration of the main factors leading to the recent price collapse. (See below.) Here, the emergence of a sustained surplus of 1-1.5 MBD starting in early 2014--less than 2% of the global oil market of around 93 MBD--was instrumental in depressing oil prices by more than half. Another factor was that, contrary to a key assumption of the 2008 EIA study, OPEC elected not to "neutralize any potential price impact of (additional US) oil production by reducing its oil exports." While shale technology has expanded US oil output by a multiple of what the EIA expected ANWR might add, the benefit for consumers isn't just pennies per gallon, but more than a dollar, at least for now.

Since the price of oil is set at the margin, it is also essentially independent of the total size of the oil market. That has important implications for how we envision the future of the oil market, especially in a world that is increasingly concerned about greenhouse gas emissions and transitioning to cleaner sources of energy. Even if future oil production were to be increasingly constrained by energy efficiency improvements and environmental policies, it doesn't necessarily follow that future oil prices must be low. That would only be the case if producers mistakenly invested in more production capacity than the market actually ended up needing.

As things stand today, there is a significant risk that the industry will not invest enough in future capacity, and that prices will again rise sharply before electric vehicles and other alternatives could scale up sufficiently to fill the gap, particularly if low oil prices also deter their growth. That's because without large investments in new oil output, current production will eventually decline from today's levels. Field-level decline rates range from just a few percent to 65% per year, depending on whether we're looking at the conventional oil reservoirs that make up over 90% of global supply, or at US shale production, which accounts for less than 5% of world oil.

Perhaps the bottom-line lesson is that we should never become complacent about the potential price volatility of what is still, at this point, an indispensable commodity. The shale revolution and OPEC's current behavior don't guarantee that oil prices must remain depressed, any more than previous concerns about Peak Oil meant they would remain high indefinitely.





 

What Will Fuel Today's Advanced Vehicles?

Last month I attended the annual "policy day" at the Washington Auto Show, which typically emphasizes green cars and related technology. This year it included several high-profile awards and announcements, along with a keynote address by US Secretary of Energy Ernest Moniz.  Yet while the environmental benefits of EVs and other advanced vehicles are a major factor in their proliferation, I didn't hear much about how the energy for these new car types would be produced.

The green car definition used by the DC car show encompasses hybrids, plug-in electric vehicles (EVs), fuel cell cars, and advanced internal-combustion cars including clean diesels. One trend that struck me after missing last year's show was that most of the green cars on display have become harder to distinguish visually from conventional models. For Volkswagen's eGolf EV, which shared North American Car of the Year honors in Detroit with its gas and diesel siblings, and Ford's Fusion energi plug-in hybrid the differences are mainly under the hood, rather than in the sheet-metal.

Of course some new models looked every bit as exotic as you might expect. That included BMW's i8 plug-in hybrid, which beat Tesla's updated 2015 Model S as Green Car Journal's "Green Luxury Car of the Year", and Toyota's Mirai fuel-cell car. The Mirai is expected to go on sale this fall in California, still the nation's leading green car market due to its longstanding Zero-Emission Vehicle mandate focused on tailpipe emissions. 

BMW i8 plug-in hybrid

Toyota Mirai fuel-cell car

Many of these cars have electric drivetrains, increasingly seen as the long-term alternative to petroleum-fueled cars. Although Secretary Moniz pointed out that the US government isn't attempting to pick a vehicle technology winner, there seemed to be a definite emphasis on vehicle electrification and much less on biofuels than in past years.

Another announcement at last month's session addressed where such vehicles might connect to the grid. BMW and VW have partnered with Chargepoint, an EV infrastructure company, to install high-voltage fast-chargers in corridors along the US east and west coasts to facilitate longer-range travel by EV. In making the announcement BMW's representative indicated that EVs will need fast recharging in order to compete with low gasoline prices. With the relative cost advantage of electricity having become a lot less compelling than when gasoline was near $4 per gallon, EV manufacturers need to mitigate the convenience concerns raised by cars with typical ranges of 100 miles or less. 

Getting energy to these cars more conveniently still leaves open the basic question of the ultimate source of that energy.  Perhaps one reason this isn't discussed much is that unlike for gasoline or diesel-powered cars, there's no simple answer. The source of US grid electricity varies much more than for petroleum fuels: by location, by season, and by time of day. However, even in California, which on average now gets 30% of its electricity from renewable sources and has set its sights on 50% from renewables by 2030, the marginal kilowatt-hour (kWh) of demand is likely met by power plants burning natural gas, due to their flexibility. That's especially true if many of these cars will be recharged near peak-usage times, instead of overnight as the EV industry expects.

Based on data from the EPA's fuel economy website, most of the plug-in cars I saw at the Washington Auto Show use around 35 kWh per 100 miles of combined driving. That reflects notionally equivalent miles-per-gallon figures ranging from 76 for the BMW i8 to 116 mpg for the eGolf. On that basis an EV driven 12,000 miles a year would increase natural gas demand at nearby power plants by around 30 thousand cubic feet (MCF) per year. That equates to 40% of the annual natural gas consumption of a US household in 2009. 

To put that in perspective, if we attained the President's goal of one million EVs on the road this year--a figure that may not be achieved until the end of the decade--they would consume about 30 billion cubic feet (BCF) of gas annually, or a little over 0.1% of US natural gas production. With plug-in EVs making up just 0.7% of US new-car sales in 2014, they are unlikely to strain US energy supplies anytime soon. 

It's also worth assessing how much gasoline these EVs will displace. That requires careful consideration of the more conventional models with which each EV competes. While a Tesla Model S surely lures buyers away from luxury-sport models like the BMW 6-series, thus saving around 500 gallons per year, an e-Golf likely replaces either a diesel Golf or a Prius-type hybrid, saving 250-300 gallons per year.  A million EVs saving an average of 350 gallons each per year would reduce US gasoline demand by 22,000 barrels per day, or 0.25%.

At this point the glass for electric vehicles seems both half-full and half-empty. The number of attractive plug-in models expands every year, as does the public recharging infrastructure to serve them. However, they still depend on generous tax credits and must now compete with gasoline near $2 per gallon. More importantly, at current levels their US sales are too low to have much impact on emissions or oil use for many years.

 

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

How Much Will Low Oil Prices Stimulate Demand?

• Since weak oil demand growth is a major ingredient in the current oil price crash, higher demand stimulated by low prices could be a moderating factor.
• While US demand has risen since prices fell, there are several reasons why the global response may be slower to appear and less dramatic.

One of the main factors that will determine the depth and duration of the current slump in oil prices is the extent and timing of a resulting rebound in demand. It is likely to occur first in countries like the US, where fuel taxes are low and consumers see the results of lower oil prices at the  gas pump relatively quickly--a $1.65 per gallon drop already, since June. However, other factors besides taxes could impede faster demand growth elsewhere. 

From 2007 to 2009 the combination of high oil prices and a weak economy reduced US petroleum demand by almost 2 million barrels (bbl) per day, compared to its 2006 peak. The first volumes backed out of the market were imported refined products, which had grown rapidly from the mid-1990s until 2005. Low domestic demand and expanding US oil production then led US oil refiners to seek new markets, particularly in Latin America. US petroleum product exports have increased by around 1.7 million bbl/day since the recession began.

These refiners might reasonably expect their domestic and foreign markets to grow faster with oil prices dramatically lower. So far, it's hard to see more than hints of this in the lagged data from the US government or API, which reported December gasoline demand at a 7-year high. It's also hard to discern how much can be attributed to oil prices, rather than to US economic growth and a falling unemployment rate. The October update of vehicle miles traveled from the US Department of Transportation was still well below its 2008 peak but showed a modest upward trend, although that seems to have begun before oil prices fell.

Other indicators are also mixed. By the end of last year sales-weighted fuel economy of new vehicles sold in the US had declined by 0.7 miles per gallon from its August 2014 peak. That reflected US consumers buying larger vehicles, including more SUVs, fewer hybrids and only slightly more plug-in electric cars than in the prior year. Despite this retreat, full-year-average fuel economy tracked by the University of Michigan still showed a more than 5 mpg gain since 2007, equating to 20% better fuel efficiency. So the roughly 45 million cars and light trucks sold in the US in the last three years--nearly a fifth of today's light-duty fleet--will use less gasoline than the ones they replaced, even in the most robust response to low gas prices imaginable.

Globally, growth prospects seem equally mixed. Since last July the International Energy Agency has reduced its forecast of 2015 petroleum demand growth by a cumulative 500,000 bbl/day, to +0.9 million bbl/day, as the global economy weakened.  These conditions could combine with currency-related effects to dampen, or at least delay, a potential surge in global oil demand due to low prices. 

Because oil is traded in US dollars, the dollar's recent strength shrinks the oil savings experienced by other importing countries. While all of these countries are paying less for oil than they did last summer, exchange rates have eroded 10-30% of that benefit. The chart above displays this effect for the Euro and Japanese Yen. Closer to home, currencies like the Mexican and Colombian Pesos have depreciated by 12% and 29% since June, respectively.  That could prove significant, since Mexico's refined product imports from the US averaged over 500,000 bbl/day in 2014 (through October), along with over a million bbl/day to the rest of Latin America.

Since petroleum products are sold in local currency, after tax at the pump, consumers in many countries have seen a smaller drop to which they might respond, compared to US consumers. The average German gasoline price has fallen by just 19% since June and the average UK price by 20%, compared to 42% in the US. Meanwhile state-controlled gasoline prices in Brazil and Mexico have  gone up. That's unlikely to induce more driving.

So far the weekly figures  for US refinery throughput are up compared to last year, implying higher expected product sales. However, US inventories of gasoline and diesel fuel have also been growing for the last several months. If rising demand doesn't erode inventory gains soon, refiners may need to reduce processing rates, and that would feed back to oil prices. The next few months of energy statistics should tell a very interesting story.

 

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

Was 2014 Really the Warmest Year?

• The media is widely reporting 2014 as the warmest year on record, yet the underlying data don't support that conclusion.
• The data actually lead to a different finding, of 2014 tied with 2010 and 2005 within the margin of error, reflecting little warming since 2005.

When I opened today's Washington Post and turned to the Opinion section, I found two op-eds that began almost identically: Eugene Robinson's column stated, "We now know that 2014 was the hottest year in recorded history," while Catherine Rampell announced, "Last year, government scientists tell us, was the hottest year on record." The President even repeated this in his State of the Union address. However, that is not really what the figures in question indicate.

I suppose it's understandable that the Post's editors and those of many other media reporting the same finding might rely on the expertise of the government agencies involved, rather than digging deeper. The Post's columnists apparently based their comments on information provided to the media by NASA's Goddard Space Flight Center. The NASA press release, entitled, "NASA, NOAA Find 2014 Warmest Year in Modern Record," included links enabling one to scrutinize the raw data upon which this conclusion was based. I've reproduced the relevant portion below in picture form as of noon today, since this data is subject to periodic revisions.

NASA's dataset displays the differences between measured temperatures and the 14.0°C average from 1951-80. On this basis it confirms that the average recorded temperature in 2014 was 0.02°C higher than the average for the previous warmest year, 2010, which was in turn 0.01°C higher than 2005's. Unfortunately, neither that page nor the press release includes any information about the uncertainty inherent in these figures, which turns out to be larger than the increase from 2010-14.

All physical measurements, including those from the weather stations providing data to NASA, are plus-or-minus some error. Averaging them doesn't entirely negate that. Within the accuracy of these temperatures, it's not possible to distinguish among 2005, 2010 and 2014; they represent a statistical tie. That fact was explained more clearly than I have done in a report on January 14, 2015, from the team of scientists at Berkeley Earth. Hardly climate skeptics, this is the same group that made headlines a couple of years ago with a comprehensive study of existing climate data.

Why does this distinction matter? After all, measured temperatures have warmed nearly 2° Fahrenheit since the early 20th century, as shown in the graph above. Whether last year or 2010 was warmer might seem like more of an academic point than a practical one. However, the refrain of "record temperature" reports gives a false sense that the warming is accelerating. Instead, as the Berkeley Earth report found, "the Earth's average temperature for the last decade has changed very little." That's a very different impression than the one created by the stories I saw, with implications for how we respond to the risks of climate change.
 

How the Oil Price Slump Helps Renewable Energy

Intuition suggests that the current sharp correction in oil prices must be bad for the deployment of renewable and other alternative energy technologies. As the Wall Street Journal's Heard on the Street column noted Wednesday, EV makers like Tesla face a wall of cheap gasoline. Meanwhile, ethanol producers are squeezed between falling oil and rising corn prices. Yet although individual projects and companies may struggle in a low-oil-price environment, the sector as a whole should benefit from the economic stimulus cheap oil provides.

The biggest threat to the kind of large-scale investment in low-carbon energy foreseen by the International Energy Agency (IEA) and others is not cheaper oil, but a global recession and/or financial crisis that would also threaten the emerging consensus on a new UN climate deal. We have already seen renewable energy subsidies cut or revoked in Europe as the EU has sought to address unsustainable deficits and shaky member countries on its periphery.

Earlier this week the World Bank reduced its forecast of economic growth in 2015 by 0.4% as the so-called BRICs slow and the Eurozone flirts with recession and deflation. The Bank's view apparently factors in the stimulus from global oil prices, without which things would look worse. The US Energy Information Administration's latest short-term forecast cut the expected average price of Brent crude oil for this year to $58 per barrel. That's a drop of $41 compared to the average for 2014, which was already $10/bbl below 2013. Across the 93 million bbl/day of global demand the IEA expects this year, that works out to a $1.4 trillion savings for the countries that are net importers of oil--including the US. This equates to just under 2% of global GDP.

Although the strengthening US dollar mitigates part of those savings for some importers, it's still a massive stimulus--on the order of what was delivered by governments during the financial crisis of 2008-9. Even after taking account of the reduced recycling of "petrodollars" from oil producing nations, which have historically invested billions of dollars a year outside their borders, the pressure on governments to reduce expenditures on programs including renewable energy should be lower than it would be without this unexpected bonus.    

Just as the arrival of $100 oil in the last decade didn't produce an overnight transformation to renewable energy, $50 oil seems unlikely to harm the sector much, particularly in light of the cost reductions that wind, solar PV and other technologies have demonstrated in the last several years. If developers use this opportunity to shrink their costs further and become economically competitive with low or no subsidies, they will be well-positioned when oil prices inevitably recover, whether a few months or a few years in the future.

2014 in Review: Shale Energy's First Price Cycle

2014 was an extraordinary year in energy, vividly illustrating both sides of the Chinese proverb about interesting times. Oil market volatility was the big story for much of the year, with the dominance of geopolitical risks finally yielding to surging supplies. Of the two energy revolutions underway, shale wields the bigger stick for now, while the growth of renewables gathers momentum. All of this has implications for 2015 and beyond.

The US remained the epicenter of the shale revolution this year, with development elsewhere still subject to uncertainties about economic production potential, infrastructure, and the rules of the road. A comparison of oil-equivalent additions to US energy supplies from oil, gas and non-hydro renewables for the first nine months of the year highlights both the significance of shale and the differences in relative scale that impede a rapid shift to renewables.

US shale drilling added over a million barrels per day of "light tight oil" (LTO) production, compared to 2013, based on US Energy Information Administration data for the first nine months of the year. That brings cumulative gains since 2011 to nearly 3 million bbl/day. This hasn't just upended the global oil market; it has also revolutionized the way oil moves across North America. Over a million bbl/day now moves by rail, a figure recently projected to peak at 1.5 million by 2016. Nor is that entirely the result of delays to pipeline projects like Keystone XL. One proposed pipeline for Bakken LTO was reportedly canceled due to a lack of interest from shippers. Rail is expensive but provides producers and refiners with greater flexibility in both volume and destinations than fixed pipelines.

The collapse of oil prices has prompted many producers to reassess drilling plans, although it has been a boon for refiners and consumers.  Refining margins look relatively healthy, at least based on the proxy of "crack spreads", the difference between the wholesale prices of gasoline and diesel and the oil from which they are made. Some refiners also anticipate that low prices will spur demand growth, as described in a fascinating Wall St. Journal interview with Tom O'Malley, who has turned a succession of castoff refineries into profitable businesses. 

We may already be seeing the demand response to lower prices. November US volumes were at a 7-year high, according to API. This is unlikely to be replicated quickly elsewhere, however, for the same reasons that global oil demand was slow to moderate when prices rose over the last several years: In many countries the influence of oil prices on consumer behavior is overwhelmed by fuel taxes or subsidies. With prices now falling, some developing countries are capitalizing on the opportunity to unwind billions of dollars in consumption subsidies, offsetting market drops. That could have important implications for future oil demand and greenhouse gas emissions.

Meanwhile US consumers have watched retail gasoline prices fall by $1.39 per gallon since July and by over a dollar compared to a year ago. If sustained, the effective stimulus could exceed $100 billion annually, ignoring the effect of lower prices for jet fuel, diesel and other products. It's not surprising that half of respondents in last month's Wall St. Journal/NBC poll indicated this was important for their families.

While oil has been making headlines, shale gas without much fanfare added the equivalent of another half-million bbl/day to US production. That explains why despite enormous drawdowns of gas during last winter's "Polar Vortex", gas inventories began this winter much closer to normal levels than was widely expected in the  spring. Gas has lost a little ground in electricity generation to coal in the last two years, but few reading the EPA's proposed Clean Power Plan regulation would expect that trend to continue.

Shale gas remains controversial in some areas due to perceived environmental and community impacts. New York state is apparently making its temporary ban on hydraulic fracturing ("fracking") permanent, preferring to rely on shale gas supplies from neighboring Pennsylvania. Yet while shale drilling in North Dakota has led to an increase in gas flaring--burning off gas that can't economically reach a market--the latest findings from the University of Texas and Environmental Defense Fund measured methane leakage from gas wells at an average of 0.43%. That shrinks gas's emissions footprint and enhances its potential role in climate change mitigation.

Turning to renewables, wind energy now provides a little over 4% of US electricity. However, its growth has slowed due to uncertainty about continued federal subsidies. The wind production tax credit, or PTC, had previously been extended through 2013 in a way that allowed projects brought online later to benefit from the extension. It was just extended again through the end of 2014, along with a broad package of other expiring tax benefits. This late revival might be a gift to a few projects already under construction, but it seems unlikely to spur additional projects without further legislative action in the new Congress.

Solar power has also made great strides, with costs falling rapidly and US additions in 2014 expected to reach 6,500 MW, likely outpacing wind additions. This is happening despite the ongoing trade dispute between the US and China over imported solar modules. Utilities are already experiencing solar's impact on their traditional business model. Yet as important as wind and solar power are likely to be in the future energy mix, their impact in 2014, at least in the US, was still dwarfed by the growth of shale resources. Drilling is already slowing down, however, so renewables could take the lead in 2015 as shale is expected to post smaller gains.

Looking ahead, the global focus on greenhouse gas emissions will increase in the run-up to the Paris climate conference in December.  It remains to be seen whether enough progress was made in the recently completed talks in Lima, Peru, to resolve the significant remaining obstacles to a new global climate agreement. And while oil supply gains trumped geopolitics in 2014, a list of risk hot-spots from the Council on Foreign Relations includes several scenarios with major implications for oil and/or natural gas prices. Meanwhile we can expect the new Congress to take up Keystone XL, oil exports, EPA regulations, and other energy-related issues. I'd bet on another lively year.

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

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.

The IEA's Stressful Outlook

• The latest long-term forecast from the International Energy Agency suggests that the benefits of today's low oil prices might be temporary, with more volatility ahead.
• The report focuses on a number of risks, including the adequacy of investment in both new oil capacity and low-emission energy, and the scale of nuclear plant retirements.

For an organization established by energy-importing countries in the aftermath of an oil crisis, the recent launch of the International Energy Agency's annual World Energy Outlook (WEO) took surprisingly little satisfaction in the current dip in oil prices, and none in the difficulties it is causing for OPEC.  Instead, the presentation  was peppered with terms  like "stress", "risk" and  "doubts",  and references to a "false sense of security" and a "stormy energy future." I see that as an indication of how much the global energy agenda has changed and broadened in the last decade or so.

For oil in particular, the IEA sees today's growth in North American production masking the consequences of the ongoing turmoil in the Middle East. In Iraq and other countries in the region, uncertainty is delaying investments that should be made now, if future supplies are to meet demand growth after US "tight oil" and other non-OPEC  expansion has plateaued. And that point could come sooner than expected if drillers reduce US shale investments by 10% next year, as IEA anticipates, or if the significant governance problems of Brazil's oil sector, which were only hinted at, are not resolved soon.

The launch covered several other areas, as well, none of which escaped suggested stresses of their own. Start with natural gas. IEA sees gas on its way eventually to become the "first fuel", consistent with the view of their "Golden Age of Gas" scenario of 2011. This would be driven in part by a large increase in LNG production from new sources such as East Africa, Russia and North America, along with growth from traditional LNG suppliers in North Africa and Australia. IEA expects increased competition from LNG with pipeline gas to improve energy security, especially in Europe, but not necessarily gas prices for end users. In fact, the high relative cost of LNG could impede the displacement of coal by gas in Asia. 

The presentation also highlighted the significant challenges IEA expects in the electricity sector in the period to 2040, a longer interval for which this year's WEO provides the first glimpse. A net expansion of global power generation by around 75% is more challenging than even that figure suggests, because it must incorporate the replacement of more than a third of today's generating capacity. As a result, only oil-fired generation will experience a net decline.  IEA forecasts up to half of new capacity through 2040 coming from renewables, on a scale posing significant risks for power system reliability, especially in Europe.

Nuclear power, a major source of baseload low-carbon electricity, is an area of special focus in this year's report, along with Africa. The expected growth of nuclear energy over the next several decades occurs mainly in the developing world, while 38% of today's nuclear capacity--nearly 200 reactors--will be retired by 2040. Many of those retirements will occur in Europe, and the Chief Economist of the IEA, Fatih Birol, expressed concern about the policies and budgets supporting such decommissioning on an unprecedented scale.

By 2040 the balance of nuclear power capacity would have shifted from around 80% in OECD countries and 20% in today's developing countries, to roughly 50/50. While the report also draws attention to the growing policy problem of nuclear waste disposal, it identifies nuclear as "one of a limited number of options available at scale to reduce CO2 emissions."

The largest source of stress in the report appears to be the disconnect between the narrowing window for reducing greenhouse gas emissions to a level that climate models indicate would limit global warming to 2°C, and the higher emissions inherent in the IEA's central "New Policies" scenario. Meeting the 2° target would require increasing average annual investments in low-carbon energy, including energy efficiency, by a factor of four compared to 2013. At last month's G20 summit in Australia we heard that "red warning lights are once again flashing on the dashboard of the global economy."  Could even the IEA's middle view of energy investments proceed if much of the world slid back into recession?

The presentation wasn't all gloomy, of course. Dr. Birol pointed out the competitive advantage that low energy costs confer on the US, and both he and IEA Executive Director Maria van der Hoevan highlighted the recent China/US emissions deal as a very positive development. (My own analysis concluded that it would still allow China's emissions to grow dramatically before peaking.) They also conceded that lower oil prices would provide oil-importing countries with some timely "breathing space."  And for the first time I heard that three out of four cars sold in the world are now covered by fuel economy regulations, suggesting increases in energy efficiency to come.

It also struck me that some of the negatives in the presentation might tend to cancel each other out. If the global oil industry, especially in the Middle East, fails to invest sufficiently in the next few years to ensure that supplies continue to grow in the 2020s, then the resulting higher oil prices could accelerate the transition to natural gas and renewables, while providing greater incentives for energy efficiency. That combination might reduce emissions sooner than IEA's main forecast indicates.

Last year the IEA's World Energy Outlook failed to anticipate the drop in oil prices; how many other forecasters likewise missed it? It featured some of the same big themes repeated this year, including the ongoing shift of the energy world's center of gravity toward Asia and the scale of the global emissions challenge. On a more basic level, however, a comparison of the two documents suggests that the agency is still trying to understand the transformation of global energy markets by the parallel shale and renewable energy revolutions. They aren't alone in that, either.

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

Energy and the New Congress: Beyond Keystone

• The Keystone XL pipeline is likely to get another opportunity for approval once the new Congress is sworn in next January.
• However, it will not be the most important part of a new Congressional energy agenda, and it might not even be the most urgent.

Voters in the US mid-term election earlier this month might be forgiven for assuming that its result assures quick approval of the Keystone XL pipeline (KXL), notwithstanding the drama over a Keystone bill in the "lame duck "session last week. The pipeline has been under review by the Executive Branch for six years, yet despite its symbolic importance to both sides of the debate, and an apparent majority in both houses of the newly elected Congress favoring its construction, its future remains uncertain. Nor is KXL necessarily the most urgent or important energy issue that the new Congress is expected to take up.

It's worth recalling that the Senators who just lost their seats  were elected in the aftermath of the oil-price shock of 2007-8, amid great concern about increasing US dependence on imported oil and natural gas. They took office in 2009 with a President whose main energy policies focused on addressing global warming, with energy security inescapably linked to climate change. Largely as a result of the shale revolution, the new class of Senators will begin their jobs in an entirely different energy environment. That will have a bearing on both the priorities and approach of the new Congressional leadership.

The energy agenda for the two years of the 114th Congress will most likely include not just the status of KXL, but also restrictions on US crude oil exports, reform or repeal of the Renewable Fuel Standard (RFS), the extension of renewable energy tax credits for solar power (expiring at the end of 2016) and wind power (already expired),  regulation of greenhouse gases by the Environmental Protection Agency under the Clean Air Act of 1990, expanded oil and gas drilling on federal lands and waters, and a stalled piece of energy efficiency legislation that might be the least controversial energy bill, on its merits, that either chamber has considered in years. Support for nuclear power and the disposition of nuclear waste could get another look, too.

Tax incentives for both renewable and conventional energy may also be swept up in efforts to reform the US corporate and individual tax systems, a high priority for some incoming committee chairmen. The least likely measures to be considered, however, are comprehensive energy legislation along the lines of the Energy Independence and Security Act of 2007 or climate legislation similar to the Waxman-Markey bill of 2009 that subsequently died in the Senate.

It is also possible that the 113th Congress could clear some of its backlog of energy measures before handing off to the new Congress in January. The dynamics of the lame duck session will be different from the pre-election period, and the outgoing leadership could be motivated to strike deals on measures such as the restoration of the wind power tax credit (PTC) within a larger package of expiring tax measures called the "extenders bill."

Aside from KXL, perhaps the most pressing energy matter for the new Congress is to address is the question of US oil exports, which are restricted under 1970s-era laws and regulations. The urgency of debating oil exports is twofold: One company has already indicated its intention to export condensate, which is treated as crude oil under current regulations, without government approval. And with oil prices having fallen by 20-25% since summer, oil exports and related shipping regulations could provide a crucial relief valve as US producers of light tight oil (LTO) from shale deposits seek to reduce their costs and find higher-priced markets.  Senator Lisa Murkowski (R-AK) is slated to chair the Senate Energy & Natural Resources Committee, and this is one of her big issues.

However, the cooperation Sen. Murkowski will receive from the other party in getting export legislation to the Senate floor could depend on the result of December's runoff in Louisiana.  If Mary Landrieu, current chair of Energy & Natural Resources, falls to Representative Bill Cassidy (R-LA), her replacement as ranking member for the minority on that committee is expected to be Maria Cantwell (D-WA). Senator Cantwell appears to be more skeptical about oil exports, as well as on other issues the oil and gas industry might hope would advance next year. 

For that matter, while gaining approval of KXL and reining in the EPA are clearly part of the incoming Republican agenda for energy, other issues cut across party lines in ways that make their outcomes less easily predictable. For example, proponents of reforming or repealing the RFS may have as much difficulty getting traction in the 114th Congress as in the 113th. Geography, rather than party affiliation, seems like a better predictor of whether new Senators like Joni Ernst (R-IA) or Mike Rounds (R-SD) would support or oppose changing the rules for biofuels. That could apply to the wind tax credit, too.  Even an oil export bill might similarly split both parties.

That brings us back to Keystone XL. The election result put both chambers of Congress on the same page on this issue for the first time and has apparently increased support for KXL to the crucial 60-vote threshold. That would be sufficient to obtain "cloture" and prevent a filibuster, though not to overturn a presidential veto.

Before Senator Landrieu's bill came up short last week, the President's real position on KXL began to emerge from the opacity he maintained through two elections. Nor does the fallout from his recent actions on other issues bode well for striking a deal with the new Congress on Keystone, short of it being attached to some essential piece of legislation like the budget or defense authorizations. Other parts of the likely Congressional energy agenda could fall into the same gap, and I'm less optimistic than I was after November 4th about opportunities for cooperation on energy between the White House and a unified Congress. 

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