Tuesday, December 29, 2015

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

Wednesday, December 16, 2015

A Grand Compromise on Energy?

The idea of  a Congressional "grand compromise" on energy has been debated for years. A decade ago, such an agreement might have opened up access for drilling in the Arctic National Wildlife Refuge, in exchange for "cap and trade" or some other comprehensive national greenhouse gas emissions policy. By comparison, the deal apparently included in the 2016 spending and tax bill is small beer but still worthwhile: In exchange for lifting the outdated restrictions on exporting US crude oil, Congress will respectively revive and extend tax credits for wind and solar power.

Anticipation about the prospect of US oil exports seemed higher last year, when production was growing rapidly and threatening to outgrow the capacity of US oil refineries to handle the volumes of high-quality "tight oil" flowing from shale deposits. Just this week Michael Levi of the Council on Foreign Relations, citing a study by the Energy Information Administration, suggested that allowing such exports might now be nearly inconsequential in most respects.

Although little additional oil may flow in the short term, given the current global surplus, it's worth recalling that the gap between domestic and international oil prices hasn't always been as narrow as it is today. The discount for West Texas Intermediate relative to UK Brent crude has averaged around $4 per barrel this year, but within the last three years it has been as wide as $15-20. Oil traders will tell you that average differentials between markets are essentially irrelevant. What counts is the windows when those gaps widen, during which  a lot of cargoes can move in short periods.

No matter how much or little US oil is ultimately exported, and how much additional production the lifting of the export ban will actually stimulate, the bigger impact on the global oil market is likely to be psychological. Having to find new outlets for oil shipped from West Africa, for example, because US refiners are processing more US crude and importing less from elsewhere is one thing; having to compete directly with cargoes of US oil is going to be quite another. That's where US consumers will benefit in the long run, from lower global oil prices that translate into lower prices at the gas pump.

Finally, if OPEC can choose to cease acting like a cartel--at least for the moment--and treat crude oil as a normal market, then it's timely for the US to follow suit and end an oil export ban that originated in the same 1970s oil crisis that put OPEC on the map.

How about the other side of this deal? What do we get for retroactively reinstating the expired wind production tax credit (PTC), along with extending the 30% solar tax credit that would have expired at the end of next year?

We'll certainly get more wind farms, along with some stability for an industry that has been whipsawed by past expirations and last-minute extensions of a tax credit that has been a major driver of new installations throughout its 20+ year history. Wind energy accounted for 4.4% of US grid electricity in the 12 months through September, up from a little over 1% in 2008.

However, this tax credit isn't cheap . The 4,800 Megawatts of new wind turbines installed in 2014 will receive a total of nearly $2.5 billion in subsidies--equivalent to around $19 per barrel--during the 10 years in which they will be eligible for the PTC, and 2015's additions are on track to beat that. The PTC is also the policy that enables wind power producers in places like Texas to sell electricity at prices below zero--still pocketing the 2.3¢ per kilowatt-hour (kWh) tax credit--distorting wholesale electricity markets and capacity planning.

As for solar power, it's not obvious that the tax credit extension was necessary at all, in light of the rapid decline in the cost of solar photovoltaic energy (PV). In any case, because the tax credit for solar is calculated as a percentage of installed cost, rather than a fixed subsidy per kWh of output like for wind, the technology's progress has provided an inherent phaseout of the dollar benefit. Solar's rapid growth seems likely to continue, with or without the tax credit.

The big missed opportunity from a clean energy and climate perspective is that these tax credit extensions channel billions of dollars to technologies that, at least in the case of wind, are essentially mature and widely regarded as inadequate to support a large-scale, long-term transition to low-emission energy. I would have preferred to see these federal dollars targeted to help incubate new energy technologies, along the lines of the Breakthrough Energy Coalition announced by Bill Gates and other high-tech leaders at the Paris climate conference.

The current deal, embedded within a $1.6 trillion "omnibus" spending bill, must still pass the Congress and be signed by the President. It won't please everyone, but it is at least consistent with the "all of the above" approach that has been our de facto energy strategy, at least since 2012. It also serves as a reminder that despite the commitments at Paris to reduce emissions of CO2 and other greenhouse gases, renewable energy will of necessity coexist with oil and gas for many years to come.

Monday, November 23, 2015

Shrinking the Strategic Petroleum Reserve

  • Selling oil from the Strategic Petroleum Reserve as part of the Congressional budget compromise raises serious questions about the SPR's future role.
  • Shrinking the SPR without first bringing its coverage into line with 21st century needs risks strengthening OPEC's hand. 
Last month's Congressional budget compromise included plans to sell 58 million barrels of oil from the US Strategic Petroleum Reserve, beginning in 2018. That decision raises serious questions. The world has changed enormously since the SPR was established in the 1970s, but the realignment of such an asset for the 21st century deserves a full strategic review and debate. Leaping ahead to treat the SPR like an ATM  seems unwise on multiple grounds.

My initial reaction was that the sale would result in the US government effectively buying high and selling low. However, using the last-in, first-out (LIFO) accounting common in the oil industry, the SPR release during the 2011 Libyan revolution should have removed any barrels purchased as prices surged past $100 per barrel (bbl) to over $140, prior to the financial crisis. The oil now slated to be sold in 2018-25 was likely injected between December 2003 and June 2005, when West Texas Intermediate crude oil averaged around $44/bbl. The Treasury should at least break even on these sales, allowing us to dispense with judging the trading acumen of the Congress and focus on the strategic aspects of this decision.

It is also true that the combination of revived US oil production and lower domestic petroleum demand effectively doubled the notional import protection that the SPR provides. That has made policy makers comfortable enough with the coverage the reserve provides to consider shrinking it. Yet as Energy Secretary Moniz  and a growing body of experts have concluded, the SPR's present configuration is inadequate to deal with whole categories of plausible oil-supply disruptions.

Today's SPR consists entirely of crude oil stored in caverns near the major refining centers of the Gulf Coast, to which it is connected via pipelines. However, while crude oil imports into the Gulf Coast have fallen dramatically, the long-term decline of oil production in Alaska and California has forced West Coast refiners to import 1-1.5 million bbl/day of oil, including more than half of California's crude supply, much of it from OPEC producers. In the event of an interruption of those deliveries, and under current oil-export restrictions, getting SPR oil from Texas and Louisiana to L.A. and San Francisco would pose enormous logistical challenges.

We have also learned that natural disasters such as hurricanes Katrina and Rita in 2005 and Superstorm Sandy in 2012 affect refinery operations, as well as oil deliveries.  A crude oil SPR is of little value if its contents can't be processed into the fuels that consumers and industry actually use.  The newer Northeast heating oil and gasoline reserves were intended to address that limitation, though on a much smaller scale.

It is thus fair to say that the SPR established in the Ford Administration and filled by the next five US presidents to a level now equivalent to 137 days of US crude oil imports is not diverse enough in its composition or locations, and too big for our current needs. If we could count on a continuation of cheap, abundant oil for the next two decades, selling off some SPR inventory wouldn't create problems. However, the purpose of such a reserve is to mitigate the risks of uncertain and inherently unpredictable future conditions and events. That should be factored into any decision to shrink it.

We don't have to look far to find reasons to suspect that oil prices might someday be higher and more volatile--perhaps as soon as the 2018-25 legislated sales period--or to worry that oil supplies from the Middle East might become less secure. Consider the consequences of the oil price collapse that began over a year ago. Low oil prices have indeed put pressure on the highly flexible US shale sector, where production is now expected to drop by around 500,000 bbl/day by next year. The impact on large-scale, long-lead-time capital investments in places like Canada, the North Sea and Gulf of Mexico has been even more profound. Over $200 billion of new projects and exploration activity have been deferred or canceled. Unlike shale, most of these projects could not be revived quickly if prices rebounded.

As production from existing fields declines without replacement, the current global oil surplus will dissipate, bringing the market back into balance. However, that balance is likely to be more precarious than before, since last fall's strategic shift by OPEC to protect its market share instead of managing prices entails the depletion of OPEC's "spare capacity." That means that in a future crisis, Saudi Arabia and other OPEC producers will have little flexibility to increase production to make up for lost output elsewhere.

Barring an unforeseen reduction in global  oil demand, the scenario that is beginning to take shape fits the  pattern of risks that the SPR was originally intended to address. It includes the prospect of rising US oil imports, increasing reliance on OPEC, and the threat posed by ISIS in the world's oil "breadbasket".  In that light it is hard to justify reducing the size of the SPR without a clear plan for making the remaining volume more effective at shoring up future vulnerabilities in US energy security.

In their haste to reach a deal, Congressional negotiators may also have overlooked some SPR-related alternatives that could generate revenue without draining inventories. These might include allowing other countries to buy into the reserve by means of "special drawing rights," or simply selling long-dated call options backed by the SPR, to be settled in the future by delivery or cash, at the government's discretion.

Taken together, there are ample reasons for the next Congress and administration to revisit the SPR sales provisions of the 2016 budget deal, before they go into effect.

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

Tuesday, November 10, 2015

The Keystone Rejection and the Shift Back toward OPEC

Although the International Energy Agency's latest warning of future energy security risks doesn't mention the Keystone XL pipeline, it provides important context for assessing President Obama's decision turning down that project's application. The IEA's newly issued global energy forecast indicates that if oil prices remain low until the end of the decade, it "would trigger energy-security concerns by heightening reliance on a small number of low-cost producers," a polite way of referring to OPEC. The Keystone verdict could help reinforce that shift.

I've devoted a lot of posts to different aspects of the Keystone issue. In a post last year on the State Department's Final Supplemental Environmental Impact Statement, I pointed out the pipeline's relatively modest potential to affect climate change, with a range of incremental greenhouse gas emissions (GHGs) equating to 0.02-0.4% of total US emissions. Even if the full lifecycle emissions of the oil sands crude it would have transported were included, they would still not have exceed around 0.3% of global CO2-equivalent emissions. For these and other reasons, I have consistently concluded that the decision would be made on political, rather than technical grounds, consistent with the symbolism the project has taken on with environmental activists during this administration.

Whether the Keystone rejection is attributable mainly to domestic political considerations or to positioning in advance of next month's Paris climate conference is a minor distinction. As the editors of the Washington Post put it, the distortion and politicization of the issue "was a national embarrassment, reflecting poorly on the United States’ capability to treat parties equitably under law and regulation." If the IEA's assessment of the trends underlying today's low oil prices is correct, we may come to regret last Friday's ruling for other reasons, too.

Recall that last year's oil-price collapse had two principal triggers: surging US oil production from shale deposits in Texas, North Dakota and several other states, and a decision by OPEC to forgo its historic role as balancers of the global oil market and instead to produce full out. The latter explains why oil remains below $50 per barrel, even though US shale output is now retreating.

Yet while shale production is expected to rebound once prices start to recover--whenever that might occur--the same cannot necessarily be said for conventional non-OPEC production from places like the North Sea and other high-cost, mature regions. Oil companies have canceled or deferred over $200 billion in exploration and production projects, while existing oil fields accounting for more than 10 times the output of US shale will continue to decline at rates of perhaps 5-10% per year.

The combination of all these factors sets the stage for a future oil market very different from what we've experienced in the past few decades. If OPEC and particularly Saudi Arabia assume the role of baseload, rather than swing producers, the price of oil will be set by the last, most expensive barrels to be supplied. That would constitute a much more normal market than one that has been dominated by OPEC production quotas, but it would also lack the margin of 3-5 million barrels per day of "spare capacity" that OPEC has typically held in reserve. That is a recipe for increased risk and volatility ahead.

If this comes to pass, the result might not be an exact re-run of the oil crises of the 1970s. The global economy is much less reliant on oil than it was four decades ago, especially for electricity generation, which as the IEA points out will increasingly come from renewable sources. However, oil will remain indispensable for transportation for many years. In a global oil market again dominated by OPEC, additional pipeline-based supplies from a reliable neighbor like Canada would be highly desirable, and the US Strategic Petroleum Reserve, which the Congress just voted to shrink in order to raise a couple of billion dollars of revenue, could become a lot more valuable.

The decision to reject TransCanada's application for the Keystone XL pipeline was ostensibly made on long-term considerations related to climate change, but it reflects a short-sighted view of energy markets. In that light, the President's conclusion that Keystone "would not serve the national interests of the United States" seems very likely to be revisited by a future US president.

Wednesday, October 21, 2015

VW Scandal Puts Diesel's Future at Risk

  • If the VW scandal sours consumers on diesel cars, the potential winners and losers extend well beyond the auto industry.
  • European refineries look especially vulnerable to such a shift, while US refiners, along with manufacturers of electric vehicles, stand to gain.
Whether or not Volkswagen's diesel deception proves to be "worse than Enron," as a Yale business school dean commented, it is more than just the business scandal du jour. Its repercussions could affect other carmakers, especially those headquartered in Europe. And if it triggered a large-scale shift by consumers away from diesel passenger cars, that would have major consequences for the global oil refining industry, oil and gas producers, and sales of electric and other low-emission cars.

The scale of the problem ensures that it will not blow over quickly. Nearly 500,000 VW diesel cars in the US were equipped with software to circumvent federal and state emissions testing, and the company has indicated that 11 million vehicles are affected, worldwide. Even if Volkswagen's retrofit plan passes muster with regulators in the US, Europe and Asia, the resulting recall could take years to complete.

It's also still unclear whether VW's diesel models are unique in polluting significantly more under real-world conditions than in laboratory testing. Regulators in Europe appear to suspect the problem is more widespread. Other companies use similar emission-control technologies--from the same vendors--to control the NOx and particulates from smaller cars equipped with diesel engines. The French government announced plans to subject 100 diesel cars chosen at random from consumers and rental fleets to more realistic testing.

VW faces investigations and lawsuits in multiple countries. While those are underway, the claims of every carmaker selling "clean diesels" and the reputation of a technology that European governments have bet on as a crucial tool for reducing CO2 emissions and oil imports are likely to be under a cloud. How consumers react to all this will determine the future, not only of diesel cars, but of the future global mix of transportation fuels and vehicle types.

Start with oil refining. As long ago as the early 1990s, when I traded petroleum products in London, the European shift to diesel was creating a regional surplus of motor gasoline and a growing deficit of diesel fuel, or "gasoil" as it is often called outside North America. Initially, trade was the solution: The US was importing increasing volumes of gasoline to meet growing demand and had diesel to spare. The fuel imbalances of the US and EU were well-matched, in the short-to-medium term.

As this shift continued, the wholesale prices of diesel and gasoline in the global market adjusted, affecting refinery margins on both sides of the Atlantic. Marginal facilities in Europe shut down, while others invested in the hardware to increase their yield of diesel and reduce gasoline production. US refiners also invested in diesel-making equipment.

The aftermath of the financial crisis and recession increased the pressure on Europe's refiners, as did the rapid growth of "light tight oil" production in the US. Europe's biggest export market for gasoline dried up as fuels demand slowed and US refineries reinvented themselves as major exporters of gasoline.

Diesel cars still make up less than 1% of US new car sales but have accounted for around 50% of European sales for some time. If governments and consumers were now to lose their confidence in diesels and shift back toward gasoline, it would wrong-foot Europe's refineries and leave them with some big, underperforming investments in diesel hardware.  A persistent slowdown in diesel demand would alter corporate plans and strategies as refinery profits shifted. In the meantime, US refineries stand to benefit from a bigger outlet for their steadily rising gasoline output.   

If consumers did retreat from diesel passenger cars--trucks are unlikely to be affected--the shift back to gasoline is likely to be less than gallon-for-gallon, because competing technology hasn't stood still since 2007, when the US Congress enacted stricter fuel economy standards and the Environmental Protection Agency's tougher tailpipe NOx standard went into effect. New gasoline cars are closing the efficiency gap with diesels, thanks to direct injection, hybridization and other strategies. At the same time, the number of new electric vehicle (EV) models is growing rapidly, their cost is coming down, and infrastructure for EV charging is sprouting all over.

EVs still accounted for less than 1% of the US car market last year, but the combined sales of the Chevrolet Volt, Nissan Leaf, Tesla Model S and over a dozen other plug-in hybrid and battery-electric models nearly matched those of the standard Prius hybrid "liftback". EVs are still not cheap, despite generous government incentives that mainly benefit high-income taxpayers. Most still come with a dose of "range anxiety", but they are greatly improved and getting better with each new model year.

Even in Europe, where EVs haven't sold very well outside Norway, a big shift away from diesel would surely help EVs gain market share. If European consumers bought 9 gasoline cars and one EV for every 10 new diesels they avoided, European refiners would soon see not just a shift, but a net drop in total fuel sales. Nor would refineries be the only part of the petroleum value chain to be affected. Global oil demand would grow more slowly as well, bringing "peak demand" that much closer.

For now, this scenario is hypothetical. VW may yet solve its technical problem, bringing the 11 million affected vehicles into compliance with minimal impact on performing and fuel economy. Meanwhile, regulators could find that most other carmakers have been in compliance all along, particularly those selling cars that use the urea-based Selective Catalytic Reduction NOx technology; the rest might only need a few tweaks.

​In that case, the scandal might eventually die down without putting small diesel cars into the grave, as a mock obituary in the Financial Times suggested. Carmakers would have a hard time increasing diesel's penetration of markets like the US, but loyal diesel customers around the world might conclude that these cars still provide them the best combination of value, convenience and drivability. Having driven a number of diesels as rentals and at auto shows, I wouldn't dismiss that possibility too lightly. The jury is likely to be out for a while.

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

Friday, October 09, 2015

What the Congressional Hearing on VW Missed

I made time in my schedule to watch yesterday's Congressional hearing on the VW scandal on C-SPAN. It left me with very much the same sense tweeted by Amy Harder of the Wall Street Journal, though perhaps for different reasons:

Similarly to the Deepwater Horizon hearing, some of the Members of the House Energy and Commerce Committee used the occasion to demonstrate that their outrage over this event equaled or exceeded that of their constituents back home. This is par for the course. But just as when confronted with the highly technical issues of a well blowout in the deep water of the Gulf of Mexico, the committee's members would also have benefited from more technical advice prior to and during the hearing.

In particular, I thought they missed key opportunities to follow up on answers given by the CEO of Volskwagen's US subsidiary, Michael Horn. One example followed Mr. Horn's response to a question about the timeline for attempting to fix the company's non-complying diesel cars from model years 2009-2015.

He explained that the affected models included three generations of engine and emissions treatment technology. The oldest, which he described as "Gen-1" would be the hardest to fix and was clearly not amenable to merely updating the engine management software to remove the "defeat device" code. However, he also indicated that the newest generation might be fixed in exactly that way. That's because they already incorporate the Selective Catalytic Reduction and urea technology used in bigger, more expensive models. The question left hanging in the air but never asked was why VW would have abandoned the exhaust-gas-recirculation (EGR) technology that had been matched to the 2-liter diesel engine since 2009, if it was convinced the cheaper technology was doing the job.

Several members of the committee pointed out to both Mr. Horn and Christopher Grundler, the EPA official responsible for emissions compliance, that although the EPA had indicated these cars were safe to drive and would not be pulled off the road, they would be emitting unacceptable levels of NOx until they were recalled and repaired.  Mr. Horn had already indicated that might take up to two years, which seemed quite realistic.

Despite Mr. Grundler's expertise, everyone seemed to treat these emissions as an unalterable circumstance, ignoring the fact that NOx is a traded commodity in the US. In fact, the markets for NOx and SOx emissions credits--overseen by the EPA--have been so effective that they provided the intellectual spark for the whole idea of CO2 cap-and-trade. In light of that, I was surprised that no one suggested that VW, either voluntarily or at the direction of the EPA, should immediately purchase NOx credits equivalent to the excess emissions of the affected cars until they have been brought into compliance.

Of course that wouldn't be a perfect substitute for tailpipe compliance. Unlike CO2, NOx acts locally, rather than globally. However, as I understand it the NOx markets function regionally, and I would be surprised if there wasn't a reasonable overlap between the geographic concentrations of VW diesel car sales and the focus of the NOx markets in the Northeast, Midwest and California. Buying large blocks of  NOx credits would push  up the price for these instruments and prompt more emissions reductions from power plants and other participants in these markets, leaving the air cleaner.

I am sure many of those watching the hearings shook their heads when Mr. Horn expressed his belief that the responsibility for circumventing the cars' emission controls likely rested with a few software engineers, rather than a corporate decision. Representative Chris Collins (R-NY) channeled a lot of frustration when he rejected that idea on the basis that if VW had found software to fix diesel emissions it would have rushed to patent the idea. I'm less certain of that in this age of widespread technology outsourcing. For VW's diesels, much of the key hardware came from vendors, and I would expect the same to be true for software. I was hoping someone would ask whether the "defeat device" software itself had been sourced from a vendor.

Either way, it was clear that Mr. Horn was struggling with the disconnect between his own beliefs about the situation and the facts that had emerged. I experienced something similar when my former employer, Texaco Inc., was embroiled in a scandal over diversity in the 1990s. The newspaper accounts I read of blatant discrimination in closed-door meetings were at odds with everything I knew about a company for which I had worked for two decades. Mr. Horn expressed similar feelings, but I doubt they provided much consolation to those whom VW's actions have harmed.

In that vein, there was a lot of speculation about damages and remedies at yesterday's hearing.  It was clear that most of the committee shared the view of one member, who advised VW to be "aggressively compliant" in responding to its customers and dealers. However, suggestions that the company offer "loaners" to all 500,000 affected customers seemed detached from reality, as did the notion that VW should voluntarily refund the full purchase price of these cars. A quick calculation puts the price tag on that idea in the $10-20 billion range, before paying any of the fines and penalties that seem inevitable in this case. I don't know what compensation I'd want if I had bought a diesel VW, instead of a gasoline model, but I don't think I'd be counting on getting my purchase price back.

Yesterday's hearing had its share of posturing, but on balance I thought it contributed to our understanding of the scandal and the next steps in the process. The panel treated Mr. Horn with remarkable civility, under the circumstances. That is likely attributable to his having been among the first to admit that the company had "screwed up." Perhaps his most telling remark yesterday was that they would have to figure out how to manage a company of 600,000 people differently, after this. "This company has to bloody learn," was how he put it. I imagine we'll be hearing a lot more in the weeks and months ahead about exactly what those lessons are, and how much they will cost.

Thursday, October 01, 2015

How Shale Reduced US Energy Risks from Hurricanes

  • The Gulf of Mexico will be a key region for energy supplies for years to come, but shale development has boosted output elsewhere to such an extent that the US is much less vulnerable than a decade ago to shortages resulting from hurricanes.
Just in time for the 10-year anniversary of Hurricane Katrina last month, the US Energy Information Administration (EIA) reported on the reduced vulnerability of US energy supplies to Atlantic hurricanes, as a result of the energy shifts of the last decade. As the Houston Chronicle noted, this illustrates another benefit of the revolution in shale oil and gas. However, with oil still below $50 per barrel, it is also worth considering how durable these particular effects might be if low oil prices were to persist much longer.

Following hurricanes Katrina and Rita, which made landfall on the Gulf Coast within a few weeks of each other in 2005, I recall some lively  discussions concerning the concentration of US energy assets in the region, and what that meant for US energy security. There was talk of new inland refineries, and even proposed legislation to promote them. With the exception of one small refinery in North Dakota, which came online earlier this year, most of that talk led nowhere. The synergies of the Gulf Coast refining and petrochemical complex were and still are overwhelming.

From the perspective of diversifying US crude oil and natural gas supplies, the situation looked equally daunting in 2005, excluding higher imports of both--an outcome that already seemed unavoidable. The country's main onshore oil fields, including the Alaska North Slope, were in decline. In 2004 their combined output averaged less than 4 million barrels per day for the first time since the 1940s. The deep waters of the Gulf of Mexico were where the majority of accessible, unexploited US oil and gas was expected to be found.

With hindsight it now seems clear that in 2005 the first large-scale application of hydraulic fracturing ("fracking") and horizontal drilling to shale in the Barnett gas field near Dallas, TX was pointing to an entirely different set of possibilities.  The Barnett had just passed a major milestone: one billion cubic feet per day of production. However, other than visionary entrepreneurs like George Mitchell, few energy experts then foresaw how rapidly shale could scale up elsewhere.

Fast-forward to 2015, and the country has experienced a profound geographical diversification of its energy sources. As the following key chart from the EIA's analysis shows, since 2003 the offshore Gulf of Mexico's share of US production has fallen by 40% for crude oil and by nearly 80% for natural gas.

The divergence in those figures may seem surprising. "Tight" oil from deposits North Dakota, onshore Texas and the mountain West supplemented deepwater production that post-Deepwater Horizon has recovered to roughly the level of 2004, bringing total US oil output close to an all-time record earlier this year.  Meanwhile, rising shale gas output in Arkansas, Louisiana, Ohio and Pennsylvania  more than compensated for  the steady, long-term decline of Gulf of Mexico gas production. The extent of the shift in US gas sources has even raised questions about the viability of the benchmark Henry Hub (Louisiana) trading point for the main gas-futures contract

In fact, when we look beyond oil and gas to factor in the growth of renewable energy and the recent decline in coal consumption in the power sector, since 2004 the equivalent energy dependence of the US on the Gulf of Mexico--including imports--has fallen from 7% to roughly 4%, in terms of total energy consumption.

If oil prices had remained where they were a year ago, above $90 per barrel, there would be little doubt that this trend would continue. However, the latest short-term forecast from the EIA suggests that US onshore oil production will fall by about 6%, due to reduced shale drilling, while Gulf of Mexico production ticks up about the same percentage, as more projects that were begun under higher oil prices come onstream. This is generally consistent with the outlook of the International Energy Agency. By itself that could cause a small increase in Gulf of Mexico dependence.

As for gas, EIA projects that US onshore natural gas production will continue to grow, though at a slower rate than recently, while offshore gas continues its decline, reinforcing the shift away from the Gulf. The technology and techniques for developing onshore shale gas continue to improve, even with low natural gas prices, while the identified gas resources of the eastern Gulf of Mexico remain off-limits.

The relative importance of the large refining centers on the Gulf Coast may be evolving, too, for different reasons. US refined product exports have grown substantially since the financial crisis, with most of them sourced from the Gulf Coast. To the extent such shipments could be delayed in an emergency or swapped for product sourced abroad to be delivered to their original destinations, that effectively creates a buffer against storm-related disruptions in domestic deliveries.

The abundance of natural resources and the legacy of decades of infrastructure investment guarantee that the US Gulf Coast will remain a key region for US energy supplies. However, the technology for tapping resources elsewhere has greatly reduced the chances for a repeat of the events of 2005, when a pair of hurricanes set the stage for the highest natural gas prices in US history. Low oil prices might slow down further reductions in the relative energy contribution of the Gulf, but a significant reversal of this trend looks unlikely under either low or high oil prices.
A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Wednesday, September 23, 2015

The Fallout from Volkswagen's "Defeat Device"

  • The repercussions from VW's error in judgment seem likely to extend beyond the hit to their reputation and stock price, and the unnecessary extra pollution from these cars.
  • This incident will make a useful, fuel-saving alternative to gasoline cars less attractive, at least for now, resulting in higher future oil consumption and CO2 emissions.

I find the revelations concerning Volkswagen's reported efforts to circumvent vehicle emissions rules disturbing, especially as a VW owner and someone who has advocated diesel technology as a tool for reducing oil consumption and greenhouse gas emissions. VW has apparently admitted its colossal error. However, I haven't seen anyone attempt to explore the implicit emissions tradeoffs involved. As bad as this decision was, did it at least, on balance, help the environment?

The details that have emerged so far have focused on a software routine that manipulated diesel engine performance to produce one level of emissions in regulatory testing, presumably on a dynamometer, and different, much less acceptable results in real-world driving. Aside from the obvious questions about ethics and compliance, what did this mean for actual emissions?

For many years regulators have been tightening restrictions on allowable emissions of so-called criteria pollutants from cars. These include oxides of sulfur and nitrogen, particulates, and hydrocarbons, but not CO2. A whole gamut of technology was developed to tackle these pollutants, starting with catalytic converters on cars and deep desulfurization of fuels in refineries. Today's cars are much cleaner than those of a generation ago.

Oxides of nitrogen, referred to as NOx, are combustion byproducts that don't originate in a car's fuel, but from the nitrogen and oxygen in the air in which it is burned. NOx emissions from diesel engines have always been challenging, because they operate at higher temperatures and compression ratios than gasoline engines. Manufacturers that produce diesel vehicles have deployed different technologies to control NOx. As far as I know the VW Group uses at least two, depending on model.

Larger (and more expensive) vehicles appear to use a process called Selective Catalytic Reduction (SCR), in which small amounts of a liquid chemical such as urea chemically react with the NOx. The liquid must be refilled at service intervals. The technical manual for VW's 2-liter diesel engine involved in the current fiasco indicates it uses EGR, or exhaust-gas recirculation, which reduces the oxygen in the engine available to form NOx .

If controlling emissions from diesels is so challenging, why bother with them? Well, a typical diesel car uses up to a third less fuel than a comparably equipped gasoline model. After adjusting for the carbon content of the fuels, the lifecycle CO2 emissions are around 20% lower than for gasoline. Given the shortcomings of similarly priced electric vehicles in range and convenience, diesel provides a useful option. That helps explain why roughly half of European cars today are diesels, in many cases promoted by national fuel- and/or engine-tax policies.

That leads us to the question of whether such a reduction in CO2 might be worthwhile, even if it came at a penalty in NOx emissions, which act locally, rather than globally. To arrive at a ballpark answer let's assume that the 482,000 affected diesel cars couldn't have been sold at all if their engine software didn't fool emissions testers, and that the buyers would have otherwise chosen a comparable gasoline car. For comparison, the EPA rated the 2015 Jetta diesel at 36 miles per gallon (mpg) overall, while the 1.8 L turbo gasoline Jetta gets 30 mpg. At an average of 12,000 miles per year each, the collective annual fuel savings of the cars involved would be 32 million gallons, resulting in avoided CO2 emissions of about 300,000 metric tons per year, or 0.005% of US annual CO2 emissions.

If the tradeoff in extra NOx emissions is based on the reported maximum estimate of 40 times the EPA's allowed level of 0.07 grams per mile, then the affected cars would collectively emit an extra 16,000 metric tons of NOx per year. That's roughly 1% of the annual US NOx emissions tracked under the Clean Air Interstate and Acid Rain Program cap-and-trade markets in 2012. Even recognizing that those programs don't count all US NOx pollution, and that NOx and CO2 are very much apples and oranges in their environmental and health impacts, the relative proportions I calculated don't make this seem like a tradeoff worth making.

Whoever made the decision to circumvent the pollution controls on these cars did enormous damage to VW's brand and reputation. Unfortunately, the response in Europe and Asia suggests that this event has also raised questions about the emissions testing and compliance of the entire car fleet. Resolving them will take time and money, and if they are not seen to be dealt with properly, the impact on the public's trust of these processes on both sides--manufacturers and regulators--could be long-lasting.

Unlike in Europe, diesels made up just under 1% of new cars sold in the US last year. However, the technology was finally shedding the poor reputation that low-quality diesel cars earned in the 1980s, and the "take rate" was growing, along with the number of models offered.  VW's diesels are among the most affordable in the market. The NOx reduction technologies they use have been proven to work, when they are not circumvented, but that is not the message that this debacle will leave with the average consumer. Carmakers will have to work harder to convince buyers that this driver-friendly alternative to gasoline cars is worth a look, and that has implications for future oil consumption and CO2 emissions.

Monday, August 31, 2015

What Do Futures Markets Tell Us About Long-term Oil Prices?

  • The tendency to believe that the prices of oil futures contracts are predicting the future price of oil is understandable but not supported by the track record of such bets.
  • The prices of long-dated oil futures merely reflect where buyers and sellers are willing to strike a deal today, for their own, diverse reasons.
A recent article in the Wall Street Journal reminded me of numerous debates about the significance of energy futures prices, when I was a trader and later a trading manager for the former Texaco, Inc.  Do changes in futures contract prices actually predict future oil prices as the Journal's reporter suggests? If so, then it might be reasonable to conclude that today's low oil prices could persist for years. However, from my perspective that over-interprets the market data and ignores some important oil fundamentals.

As tempting as it might be to think so, the futures market for West Texas Intermediate (WTI) crude oil isn't a crystal ball, and neither is the market for UK Brent crude. A futures price is simply the price someone is willing to pay or receive now for oil to be delivered (or settled without delivery) later. It is typically based on business needs, rather than deep analysis.  A concrete example might be helpful.

The parties who on August 11th bought or sold oil for $56 or $57 in December 2017 likely did so, not because they were certain what the price would be then, but because they couldn't be sure and either needed to hedge another transaction or activity, or thought it constituted a reasonable bet. Aggregating a modest number of such transactions--long-dated futures trade much less frequently than those for the near months--doesn't improve the accuracy of these bets on an inherently unpredictable commodity over long intervals. Anyone who thinks it does should examine the track record of oil futures as predictions; it is a sobering exercise, especially for those who have traded this market.

Consider that while the September 2015 WTI contract closed at a little over $43 per barrel that afternoon, traders were buying and selling the same contract for more than twice as much during long stretches of 2012--about as far removed from us as the late-2017 contract prices cited in the Journal article as evidence of a persistent oil-price slump. Prices for the September 2015 contract were even higher in the middle of last year, when traders knew nearly as much about the growth of US tight oil production and its rising productivity as we do today, but crucially didn't know that OPEC would choose not to cut output to alleviate an over-supplied market as they had done in the early 1980s and late 1990s. Similar examples abound.

So how else might one explain the fact that long-dated oil contracts are trading for less today than they were this spring, if not as a prediction of a longer period of low prices ahead? Behavior and learning play key roles. With the  first anniversary of this historic price collapse just a few months off, expectations of a quick rebound in prices have faded. The possibility that the US could produce as much tight oil, for now, with fewer than half as many drilling rigs in operation as a year ago has sunk in. So has the reality that as painful as $50 oil is for some of OPEC's members, cartel leaders like Saudi Arabia show little inclination to blink first.

However, others are blinking, and that's why I'm skeptical that oil prices can remain this low indefinitely. The cuts in staff and investment budgets by major oil companies and their national oil company peers have been breathtaking, totaling $180 billion this year according to one analysis. The cuts suggest that the projects in question require significantly higher oil prices to be profitable, even after recent cost reductions, or have become too risky at current prices.

Few of these companies are big players in shale. Their bread and butter is large, conventional onshore oil fields and enormously expensive deepwater oil projects, the collective output of which is inherently subject to annual declines in output. Decline is the "silent killer" of output, to the tune of 5% or so every year. The only way to offset this trend within the portfolios of these producers is to spend large sums every year on new wells and new projects--projects that according to Rystad Energy, as cited by Bloomberg, have been cut more than at any time since 1986.

We must also put the US shale revolution in its proper context. When added to a global market that was balanced between supply and demand at around $100 per barrel, it was a game-changer, not least because no other producer or group of producers was willing to reduce output enough to accommodate this new source. However, even at today's 5.4 million barrels per day US tight oil represents only about 6% of global supply. The combination of shale plus OPEC covers less than half the world's oil demand.

The remainder must come from onshore and offshore oil fields in non-OPEC countries like Brazil, Canada, Mexico, Norway, and Russia. This non-OPEC supply has grown thanks to  a wave of completions of  large projects begun 5-10 years ago, when prices were rising rapidly. However, reduced investment now surely means lower non-OPEC production within a year or two.

The key question for future oil prices is therefore when demand, which according to the International Energy Agency is growing rapidly under low prices, and supply, for which new investment has suddenly shifted from the accelerator to the brake pedal, will cross over, erasing today's glut. It's hard to infer the answer from the thinly traded market for long-dated oil futures contracts.

Wednesday, August 12, 2015

The Return of Iran's Oil

  • If approved by all parties the negotiated nuclear agreement with Iraq could affect energy markets both directly and indirectly.
  • By adding to the current global oil glut, it would make big oil projects elsewhere riskier, while undermining outdated restrictions on US oil exports.
The signing of a nuclear agreement between Iran and the five permanent members of the UN Security Council plus Germany represents more than a geopolitical milestone. In the context of today's lower oil prices it puts additional pressure on near-term prices, but perhaps more importantly creates the potential for significant shifts within the oil industry. Iran's expanded exports--once the conditions of the deal are met--will arrive in a market quite different from the one that prevailed when they were restricted in early 2012.

These differences include an OPEC that is now engaged in a contest for global market share, rather than one focused on maintaining oil prices at around $100 per barrel. This is the cartel's response to the rapid growth of non-OPEC production, mainly from US shale, or "tight oil" formations. Based on data from the International Energy Agency, non-OPEC production has increased by 5 million barrels per day (bpd) since 2012, while global demand has grown by just 3 million bpd.  The return of anywhere from 600,000 to 1 million bpd of Iranian exports would expand a global oil surplus and intensify competition.

 Iran's oil traders may find that placing additional volumes with refiners will not be as easy as it would have been just a few years ago. As the Wall Street Journal noted, the likeliest home for most of this incremental supply is in Asia, where competition between Saudi, Iraqi and Russian barrels is already keen. China and India have been the largest purchasers of Iranian oil during the sanctions (see chart below) but Iran is not the only producer seeking to expand its output of similar crude oil.  

Oil prices have two main dimensions, only one of which is widely understood outside the industry. Media reports focus on the absolute price level, particularly for benchmark grades such as Brent and West Texas Intermediate (WTI). However, differentials--the gaps in price for oils of different quality, or of similar quality in different regions--are nearly as important for producers and often more so for refiners.

Iranian oil is mainly sour (high in sulfur) and so competes principally with other sour grades, including those from Saudi Arabia, which is already at record output, and Iraq, where production is approaching 4 million bpd, compared with just under 3 million in 2012. OPEC's other big producers seem no more inclined to cut output to make room for extra Iranian oil than they were to accommodate surging US tight oil. Meanwhile, refineries in Europe, where sanctions on Iranian oil had the largest impact, are also "spoiled for choice" with various crude streams displaced from US refineries by the shale revolution.

If Iran's restored exports keep oil prices lower for longer, they are also likely to widen the "sweet/sour spread", or premium for light sweet crudes like those produced in the Bakken and Eagle Ford shales, over sour crudes like Saudi medium or Iranian heavy. That would lend greater urgency to calls for an end to 1970s-vintage restrictions on exporting US crude oil, because it would expand the potential economic opportunity for US exports.

As a result of opening the taps in Iran, we could also see deeper shifts in the structure of the global oil industry. OPEC's current production policy may be targeted at US shale, but shale producers have proven themselves much more adaptable than expected to prices in the $50-60 range. The same cannot necessarily be said for new conventional oil projects with price tags in the hundreds of millions to billions of dollars. 

Barring another shift as dramatic as the one that rippled through oil markets last fall, we may have witnessed the end of an era in which low-cost producers in OPEC held back production to drive up prices and, in the process, made room for much higher-cost production elsewhere. Iran appears poised to go beyond its pre-sanctions exports by inviting international investment in new developments that would be profitable at current prices.  If Iran's terms are attractive, the losers won't be shale producers that operate at dramatically lower scales of investment and risk per well, but big projects in places like the North Sea, which has already seen a wave of project cancellations. The recent lackluster Mexican bid round might be another signpost.

Could we end up in a few years with a global oil industry in which prices would be determined mainly by a new balance between a resurgent OPEC and US shale producers? That would be a very different world than we have experienced recently, and probably one with more price volatility.

Of course before any of this could happen, the nuclear agreement with Iran would have to go into effect and be widely seen to be holding. For anyone who recalls the periodic inspection crises with Iraq in the late 1990s, that can't be a foregone conclusion, even if the agreement survives review by a US Congress that asserted its right to scrutinize the deal's provisions and includes some surprising skeptics.
A different version of this posting was previously published on the website of Pacific Energy Development Corporation

Tuesday, July 07, 2015

Energy Storage and the Cost of Going Off-Grid

  • New energy storage offerings from Tesla and other manufacturers are widely expected to enhance the attractiveness of rooftop solar power and other renewables.
  • However, recent analysis from the Brattle Group shows that even with rapid cost reductions, grid-independence will remain beyond the reach of most consumers.
Last month's Annual Energy Conference of the US Energy Information Administration included speakers and panels on topics such as crude-by-rail, potential US oil exports, and the role of the Strategic Petroleum Reserve, all of which should be familiar to my readers here. However, the topic that really caught my interest this year was energy storage.

Storage has been in the news lately, particularly since the launch of Tesla's new home and commercial energy storage products. In fact, Tesla's Chief Technology Officer spoke on the first morning of the conference. Much of his talk (very large file) focused on Tesla's expectations for the cost of storage to decline sharply as electric vehicles (EVs) and non-vehicle battery applications grow. Whether battery costs can drop as quickly as those for solar photovoltaic (PV) cells or not, storage is likely to become a more important factor in energy markets in the years ahead.

One of the most interesting presentations I saw examined a provocative aspect of this question. Michael Kline of The Brattle Group, which consults extensively on electricity, took a detailed look at whether rooftop PV and home energy storage might become sufficiently attractive that a large number of consumers would employ the combination to enable them to disconnect from the power grid entirely.  That would be an extremely appealing idea for a lot of people. The author of a book I received from the publisher a few years ago referred to it as a movement.

Most people by now appear to understand that solar panels alone can't make a household independent of the grid. The daily and seasonal incidence of sunlight aligns imperfectly with the peaks and troughs of typical home electricity demand. This is why "net metering", under which PV owners sell excess power to their local utility--effectively using the grid as a free battery--has become contentious in some electricity markets.

In a true off-grid scenario, net metering would be unavailable. Onsite storage would thus be necessary to shift in time the kilowatt-hours of energy produced from a home PV array. However, a standalone PV + storage system must be sized to deliver enough instantaneous peak power to handle periodic high-load events like the startup of air conditioners and other devices. Another presenter on the same panel had a nifty chart demonstrating how wide those variations can be, with multiple spikes each day averaging above 12 kilowatts (kW)--several times the output of a typical rooftop PV array.

Brattle's off-grid model included PV and storage optimized to "meet load in every hour given a battery with 3 days of storage (at average load levels.)" Although that is still probably less than the peak load such a system would encounter, it is the equivalent of multiple Tesla "Powerwall" units and would only be practical with the kind of drastic cost reductions Mr. Kline assumed by 2025: PV at $1.50/W and storage at $100/kWh, installed. That equates to around a third of last year's average US residential PV installation and 1/7th the estimated installed cost of Tesla's offering on a retail basis.  

Mr. Kline framed this exercise as a "stress test", not just of the off-grid proposition but of the future of the electric power grid. If many millions of customers were to "cut the cord" for electricity as others have for wireline telephone service, even a "smart" power grid would become much less important and might shrink over time. That same logic should extend to the power generators supplying the grid. If most consumers went off-grid, the value of even the most flexible generation on the grid, which today is often provided by natural gas turbines, would fall, as would demand for the fuel on which they run.

In Brattle's assessment, despite the assumption of very cheap PV and storage, that prospect seems remote. For the three markets analyzed (California, Texas and Westchester County, NY) the levelized cost of energy (LCOE) for the off-grid configuration modeled was significantly more expensive than the EIA's projected cost of electricity in those markets in 2025. In fact, for consumers in California and Texas, as well as in all cases of the parallel commercial customer analysis Brattle performed, PV + storage would  be expected to cost a multiple of retail electricity prices.

As Mr. Kline explained, under more realistic assumptions the comparison was likely to be even worse for off-grid options. However, his conclusion that , "going off-grid...is unlikely to be the least expensive option for most consumers" does not mean that some consumers would not choose to do so, anyway. To them, a premium of 10-20 cents per kWh might seem like a small price to pay for personal energy independence. Yet at that price, it is hard to envision it would become a mass-market choice. 

Mr. Kline made a point of reminding his audience that Brattle's analysis did not mean that distributed energy  would  not be competitive in the future, or that it could not provide valuable services to customers and to the grid. Importantly, the figures he presented underlined the continued value of the power grid to customers, even in a future in which large quantities of PV and storage are deployed.  As he put it, "Distributed energy is a complement to the grid, not a substitute for it."

By extension, flexible generating assets like fast-reacting gas turbines should also continue to provide significant value, especially during those seasons when daily solar input is low, and in locations where average sun exposure is generally much weaker than in the US Southwest and other prime solar resource regions.  As appealing as the idea might be to some, storage seems unlikely to make either the grid or any class of generating technologies obsolete for the foreseeable future. As Bill Gates recently observed, that has implications for the cost of a wholesale shift to current renewables and away from fossil fuels.

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