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

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.

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.

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.

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.

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

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.

Rare Earths Not So Rare?

• The bankruptcy of the main US producer of "rare earth" materials signals the end of a multi-year crisis over their global supply and cost.

The announced Chapter 11 filing of US-based rare earths mining and refining company Molycorp effectively marks the end of a crisis that managed to escape the notice of most people. Rare earths are elements of low abundance, compared to the ores of metals like iron and copper. Despite their relative scarcity, they have proved extremely useful in industrial applications including renewable energy technologies. Five years ago it appeared that China had cornered the market on rare earths and was exercising its market power to, among other aims, lure businesses reliant on these minerals to shift their operations to China.

Molycorp's modernization of its rare earth mine in California and subsequent expansion into other aspects of the business were responses to a perceived global crisis. China's restrictions on rare earth exports threatened the economic competitiveness of hybrid and electric cars, wind turbines, non-silicon solar cells, compact fluorescent lighting (CFL), and other devices of interest to energy markets and policy makers.

The situation also raised concerns in the defense industry, due to the importance of rare earth metals and alloys in the manufacture of missile components, radar and sonar equipment, and other military hardware. Governments created or expanded strategic stockpiles for these materials, and took other steps to manage their reliance on supplies from China.

However, as reported by the Council on Foreign Relations last fall, the effectiveness of efforts by the Chinese government to leverage their control of rare earth supplies was short-lived. Its policies led to mostly market-based responses, involving both supply and demand, that undermined China's near-monopoly and ultimately contributed to Molycorp's present financial difficulties.

Molycorp wasn't the only company to bring new supplies into production, or the only one to struggle as the crisis unwound. New supplies were already in the pipeline at the time China restricted its exports, in reaction to price spikes that preceded the policy as global demand bumped up against the output of China's mines and processing facilities. Nor was government control of China's fragmented rare earth industry sufficient to prevent continued exports exploiting loopholes of the restrictions.

Finally, and probably most importantly for both China-based and non-China-based producers, innovators in the industries using these materials found ways to make do with lower proportions of rare earths in permanent magnet motors and generators, or to do without them altogether.

The upshot from an energy perspective is that if anything will slow the expansion of wind and solar power, hybrid cars and EVs, and other alternative energy and energy-saving technologies, it is unlikely to be a shortage of rare earths. They may be rare relative to other industrial commodities, but in the small proportions used it seems they are not rare enough to pose more than a temporary bottleneck.

Where Is the Stimulus from Cheap Oil?

• Those expecting a boost to the US economy from lower oil prices--the opposite effect of past oil price spikes--have been disappointed by the anemic response so far.
• In GDP terms cheaper net oil imports have been offset by cuts in oil & gas investment. However, consumers now have billions saved at the gas pump to spend elsewhere.

For the last couple of months media coverage has reflected skepticism about the benefits of lower oil prices, and especially cheaper gasoline, for the US economy. This is somewhat puzzling, since the US is still a net importer of crude oil, and as such has enjoyed significant savings on our collective oil import bill during this period. And while the fallout for US oil producers whose rising output helped to trigger last fall's oil price collapse might negate some of the upside of that decline for the nation as a whole, the benefits for consumers ought to be more obvious.  

 

Start with some basic figures. From January to September of last year, West Texas Intermediate crude oil, the main benchmark for US petroleum, averaged $100 per barrel (bbl), in line with the average of the previous three years. From October through mid-May of this year, WTI has averaged just over $60/bbl, near where it trades today. The data for what US refineries paid to acquire imported oil through April reflect a similar drop, implying national savings of around $60 billion since the price of oil fell below the previous year's lows last October, on the basis of 7 million bbl/day of net crude oil imports. That equates to $94 billion on an annualized basis.

 

However, as I've noted before, the US has become a significant net exporter of refined petroleum products like gasoline and diesel fuel. If the revenue from those sales has fallen in parallel with oil prices, that would shrink the benefit for overall US petroleum trade by about a third.

 

At that level, the GDP gains from cheaper imported oil appear to be more than offset by cuts of over $90 billion in capital expenses as US oil producers seek to reduce their costs and manage their cash flow in a low-price environment.  Those cuts, along with reduced operating expenses, ripple through oil companies and their supply chains, resulting in job losses and suppliers that have less, in turn, to invest in new equipment.  

 

Of course the flip side of that is that with US net petroleum imports below 5 million bbl/day, out of total consumption of just over 19 million bbl/day, the country would suffer much less than previously from a sudden increase in oil prices due to some geopolitical event or a further change in OPEC's strategy.

 

Nor does this alter the fact that US consumers whose jobs are not tied to the oil industry have more left to spend or save every month, thanks to lower prices at the gas pump. Since the beginning of last October, US retail gasoline prices have averaged $0.84 per gallon less than at the same point a year earlier, peaking at a $1.25 year-on-year discount in mid-April. Current prices for all grades average $0.92/gal. less than in early June of 2014, following the Memorial Day weekend. As a result, consumers have gained around $90 billion in gasoline savings through May, equivalent to $137 billion per year.

 

If they're not yet spending the difference on other goods and services, they have reacted in other ways more directly related to cheaper gasoline: They appear to be driving more. The US Department of Transportation's gauge of vehicle miles traveled is up sharply, at or near a new high. API's oil statistics for the first quarter of 2015 show total US gasoline consumption ahead by 2.9%, compared to the first quarter of 2014. As cold and snowy as the past winter was, that's surprising.  If this trend persists, it could indicate a reversal of the generally downward trend in US gasoline demand since the financial crisis.

 

Consumers also appear to be purchasing larger, somewhat less fuel-efficient new cars. The Transportation Research Institute at the University of Michigan reported that average US new-car fuel economy of new cars sold in April was 0.6 mpg lower than at its peak last August, though still up by 5.1 mpg since October 2007.  Consistent with the figures on fuel economy, sales of hybrid cars fell by 16% in the first quarter, compared to last year, and now make up just over 2% of US new cars. Plug-in hybrids fell by nearly a third. Only battery-electric EVs bucked this trend, driven largely by Tesla's growth in sales.

 

Despite these shifts, I don't believe the return--for however long--of fuel prices that start with a "2" instead of a "3" or "4" will turn the US back into a nation of gas guzzlers. Consumers are only spending a fraction of their savings at the pump buying more fuel, and the preference of many for cars larger than those they were buying when gas prices reached $4 per gallon seasonally in much of the country doesn't alter the fact that even light trucks are becoming steadily more efficient.

 

Wherever the rest of that $100-plus billion a year from cheaper gasoline is going today, Americans would be wise not to assume it will carry into the future indefinitely. Oil prices remain volatile and uncertain. Although OPEC might be correct in projecting that we will not see $100 per barrel again soon, current prices may not prove sustainable, either. 

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

 

EPA's Blown Call on Ethanol

• EPA's proposed revision to renewable fuel quotas achieves the appearance of compromise by cutting non-existent volumes, while still attempting to force more ethanol into the market than consumers seem to want.

Last Friday the US Environmental Protection Agency released its long-awaited proposal for untangling a broken federal Renewable Fuels Standard (RFS). Although it provides all parties with greater certainty, it fails to resolve the regulation's fundamental flaws. This is all the more disappointing for the duration of the wait involved, finalizing 2014's quotas 18 months late and leaving refiners and fuel blenders to operate for the first five months of this year on hints and guesswork about how much ethanol and biodiesel they would be required to sell in 2015.

The proposal meets at least one definition of a compromise, with most affected constituencies apparently disappointed or irate about the result. To someone unfamiliar with the situation, it might even seem that, as ethanol groups claim, the agency has leaned far in the direction of assuaging the concerns of the petroleum refining industry by cutting a total of 11 billion gallons from the 2014-16 quotas for ethanol and other biofuels. However, as EPA's accompanying analysis makes clear, the omitted volumes were unlikely ever to be purchased by end-users, given the decline in US motor fuels consumption since the statutes imposing the RFS were passed in 2005 and 2007. Nor do the facilities yet exist to produce the quantities of cellulosic biofuels that account for the lion's share of the proposed cuts.

EPA's documentation repeatedly cites the "intent of Congress." This seems to refer to the Congressional sessions that bequeathed us this policy, rather than to the current Congress, which is waking up to the fact that the program has largely been superseded by reality. The RFS was designed to address two problems: US fuel scarcity and transportation-sector emissions of greenhouse gases. The former has been overcome mainly thanks to the shale revolution, transforming the US from a net importer of refined petroleum products to the world's largest exporter.

As for automobile-related emissions, they are being managed more effectively by fuel economy improvements and new vehicle technology. The RFS may even be counterproductive in its overall emissions impacts, as noted in a press release from the Environmental Working Group. Nor are emissions the only issue for which crop-based ethanol may be doing more harm than good. Evidence points to periodic impacts on global food prices. It's hard to conclude we could divert 38% of the US corn crop without causing unintended consequences somewhere.

EPA's analysis of the snarl at the core of the existing RFS is perplexing. First it describes how ethanol has effectively reached its maximum possible penetration of the US market for ordinary gasoline containing up to 10% ethanol (E10)--the so-called "blend wall." It goes on to acknowledge that sales of gasoline blends containing up to 15% or 85% ethanol, respectively, remain minuscule relative to total gasoline sales. However, it then ignores these facts and persists in the hope that by continuing to increase its ethanol quota, albeit more slowly, it can convince consumers to embrace fuels for which they had little appetite even when gasoline cost $1 more per gallon than it does today.

As the Washington Post noted, most car manufacturers still warn automobile owners that using gasoline containing more than 10% ethanol could result in engine damage not covered by their warranties. Although I was pleased to see that the car I recently purchased is warranted up to 15% ethanol, I cannot envision buying a single gallon of E15 unless it was priced at a discount to E10 gasoline, reflecting its inherently lower fuel economy and range. As for E85, in only a handful of states does the market discount meet or exceed the fuel's 27% calculated deficit in delivered energy, compared to E10. Is it any wonder that for a decade E85 has failed to take off as envisioned by the EPA and previous Congresses?

The EPA does not have a free hand to rewrite this regulation in any manner it would like, to fit the greatly altered circumstances in which the US now finds itself. The agency may well believe it has gone as far in that direction as it could, although I suspect it could have justified freezing ethanol from all sources at current levels, and allowing cellulosic ethanol gradually to displace corn-based fuel as new facilities come online. However, no adjustments that EPA seems prepared to make can repair a biofuels policy that was fundamentally broken at its inception, due to its inherent contradictions with other policies and consumer preferences.

We have reached the point at which conflicting federal biofuel quotas, emissions regulations, and  chronically weak GDP growth have rendered the original goals of the RFS not just ambitious but unattainable. The EPA has taken its best shot at addressing this and come up short. It is now up to the US Congress and the Administration to work together to fix this mess, before the consequences of inaction put a damper on one of the few bright spots of the current economy.

US Energy Independence in Sight?

• The data analysis arm of the US Department of Energy is forecasting that despite low oil prices, the US will become energy independent within a decade. 
• That result depends on frugality as much as resource abundance, and it includes substantial volumes of energy trade with the rest of the world.

The US Energy Information Administration's latest Annual Energy Outlook features the key finding that the US is on track to reduce its net energy imports to essentially zero by 2030, if not sooner. That might seem surprising, in light of the recent collapse of oil prices and the resulting significant slowdown in drilling. EIA has covered that base, as well, in a side-case in which oil prices remain under $80 per barrel through 2040, and net imports bottom out at around 5% of total energy demand. Either way, this is as close to true US energy independence as I ever expected to see.

It wasn't that many years ago that such an outcome seemed ludicrously unattainable. I recall patiently explaining to various audiences that we simply couldn't drill our way to energy independence. The forecast of self-sufficiency that EIA has assembled depends on a lot more than just drilling, but without the development of previously inaccessible oil and gas resources through advanced drilling technology and hydraulic fracturing, a.k.a. "fracking", it couldn't be made at all. The growing contributions of various renewables are still dwarfed by oil and natural gas, for now.

Every forecast depends on assumptions, and it's important to understand what would be necessary in order for conditions to turn out as the EIA now expects in its "reference case", or main scenario. This includes a gradual but pronounced oil-price recovery, to average just over $70/bbl next year, $80 within five years, and back to around $100 by the end of the 2020s. That helps support a resumption of oil production growth next year, followed by a plateau just above 10 million bbl/day--surpassing 1971's peak output--for the next decade and a gradual decline thereafter. EIA also expects natural gas prices to head back towards $5 per million BTUs by the end of this decade, in tandem with a further 34% expansion of US gas production by 2040.  

However, attainment of zero net imports also depends on the continuation of some important trends, including energy consumption that grows at a rate well below that of population, and a continued decoupling of energy and GDP growth. This is crucial, because through 2040 EIA assumes the US population will grow by another 20% and GDP by 85%, while total energy consumption increases by just 10%. That has important implications for greenhouse gas emissions, too. Energy-related emissions barely grow at all in this scenario.

Renewable energy output is also expected to continue growing, with US electricity generated from wind surpassing that from hydropower in the late 2030s and solar power in 2040 yielding roughly as many megawatt-hours as wind did in 2008.

Finally, reaching a balance between US energy imports and exports also depends on the continued contribution of nuclear power at roughly current levels. That suggests that new reactors in other locations will replace those that are retired, including for economic reasons.

In last month's rollout presentation at the Center for Strategic & International Studies (CSIS) in Washington, EIA Administrator Sieminski also emphasized what is not included in the Outlook's assumptions, notably the EPA's "Clean Power Plan" that is currently under review.  It would be hard to imagine US coal consumption remaining essentially unchanged at 18% of the total energy mix in 2040, if EPA's plan to reduce emissions from the electricity sector by 30% by 2030 were fully implemented. EIA will apparently issue its analysis of the impact of the Clean Power Plan this month.

It's also worth comparing EIA's view of zero net energy imports with popular notions of what energy independence. It certainly does not mean that the US would no longer import any oil, natural gas, or other fuels from other countries. Even as the US approaches zero net imports, routine imports and exports of various energy streams will remain necessary to address imbalances between regions and fuel types.

Because EIA's forecast is predicated on current laws and regulations, it does not include any significant growth in oil exports. As a result, exports of refined products such as propane, gasoline and diesel fuel would continue to expand, eventually exceeding 6 million bbl/day gross and 4 million net of imports. In its "High Oil and Gas Resource" case the constraint on US oil exports forces an expansion of refined product exports that seems nearly incredible when refinery capacity in Asia and the Middle East is also slated for expansion, while refined product demand growth slows globally. Perhaps this is EIA's subtle way of focusing attention on the US's outdated oil export regulations. 

Exports of liquefied natural gas (LNG) would also take off, accounting for around 9% of US production by 2040, while imports of pipeline gas from Canada would shrink but not disappear. In the high resource case, US LNG exports would grow dramatically until the late 2030s, reaching 20% of a much bigger supply.

The report provides a few surprises, including one that won't be welcomed by advocates of biofuels and a continuation of the current federal Renewable Fuels Standard, the reform of which has gradually become a topic of lively debate in the US Congress. EIA's figures show total US biofuel consumption growing by less than 1% per year, with ethanol's only real growth coming in the form of a modest increase in sales of E85, a mixture of 85% ethanol and 15% gasoline, to around 3% of gasoline demand in 2040.

Overall, I'm struck by several things. First, the value of the EIA's forecasts comes mainly from identifying the implications of current trends and policies, rather than accurately predicting the future. Administrator  Sieminski seemed appropriately humble about the latter task in his remarks at CSIS. Yet the reference case this time suggests an eventual reversion to pre-oil-crash conditions, ending in 2040 at the same oil price in 2013 dollars as last year's forecast--a level that would exceed the 2008 peak by a sizeable margin. That seems inconsistent with a world of expanding energy options, improved drilling efficiency, at least for shale, and a growing focus on the decarbonization of energy.

There also appears to be a disconnect between the forecast's rising real price of natural gas, with implications for the cost of electricity generation, and its virtual flatlining of solar power's expansion after the scheduled expiration of the current solar tax credit in 2016. This looks like a bet against further solar cost reductions and technology improvements, along with structural changes that are already occurring in some electricity markets.

Despite these reservations, I wouldn't dispute the headline finding of steady progress toward a version of US energy independence featuring large volumes of energy trade with both North America and the rest of the world. The combination of resource growth and steady energy efficiency improvements looks like a recipe for finally putting the US on an energy footing that politicians of both major parties have only dreamed of for the last 40 years.

 

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