Friday, March 28, 2014

How Can US Natural Gas Reduce Europe's Dependence on Russia?

  • The EU's dependence on Russian natural gas is directly linked to its own gas production, which has fallen faster than EU member countries' demand for gas.
  • While US LNG exports aren't an immediate remedy, due to permitting and construction time lags, the prospect of their availability is already affecting the gas market.
Russia's annexation of Ukraine's Crimean Peninsula has drawn new attention to Europe's reliance on energy supplies from Russia, particularly for natural gas. Lacking the means to force Russia's president to back down, US politicians and leading newspapers have latched onto the idea of exporting shale gas to reduce the EU's vulnerability to an accidental or intentional disruption of these supplies.  The efficacy of this strategy depends on more than the logistics and timing of US liquefied natural gas (LNG) projects.

The European Union is expected to import 15.5 billion cubic feet (BCF) per day of natural gas from Russia this year, roughly half of which would normally be transported by pipelines passing through Ukraine. Worries about the security of these supplies in the current crisis are compounded by Europe's increasing reliance on gas imports from all sources.

While EU gas consumption, based on the union's 28 current member countries, has been essentially flat over the last decade, its production has declined by more than a third, as shown in the chart below. As of the end of 2012, EU self-sufficiency in gas stood at just 35%. The widening of the gap between EU gas demand and production bears a close resemblance to the situation in which the US found itself with regard to crude oil prior to the shale revolution, and it is the main source of Europe's vulnerability in natural gas.

After Russia, the EU's main gas suppliers are Norway and Algeria, primarily by pipeline, followed by LNG sourced from Qatar, Nigeria and other countries.  Russia's leading role in supplying Europe's gas is consistent with its status as the world's second-largest gas producer and largest gas exporter, its proximity to the EU, and its pipeline network developed over multiple decades. Europe's gas supply mix includes ample political risk, but none of the EU's other suppliers are geopolitical rivals like Russia.

The EU has three main options for reducing its dependence on gas imports from Russia. It could shrink natural gas consumption, which is already happening to a modest degree as pricey gas-fired power generation is being squeezed out between subsidized wind and solar power and cheaper coal power, in a mirror image of US trends of the last several years.  This seems inconsistent with the EU's long-term emission goals and its need for gas to back up intermittent renewable electricity generation, so the further scope for this option appears limited, at least for the next decade.

EU countries could also attempt to revive domestic gas production. Europe's conventional gas fields may be in decline, other than in non-EU Norway, but its shale gas potential was estimated at 470 trillion cubic feet (TCF) in the US Energy Information Administration's global shale assessment last year. That's about 40% bigger than Europe's reserves and technically recoverable resources of conventional gas. Uncertainties on this estimate are still large, but it's in the same ballpark with the Marcellus shale in the eastern US, which currently produces over 14 BCF/day.

Unfortunately, initial efforts in Poland's shale have been disappointing, while Germany, France, and other countries have imposed explicit or implicit moratoria on shale gas development. Unless these policies are reversed in the aftermath of the Ukraine crisis, the EU will be unable to grow its way out of its dependence on Russia.

That leaves import diversification as the likeliest path for weaning Europe off Russian gas. This process is underway incrementally, hastened by previous Russian gas brinksmanship. Interest in US gas is understandable on many levels, not least because even after increasing production by around 17 BCF/day since 2006, US shale resources are expected to add another 13 BCF/day by 2020.

Energy experts have been quick to point out that the first US LNG exports won't be available for at least several years, and that companies, rather than governments, are the main parties involved in gas contracts. Customers in Europe will have to compete for US and other LNG supplies with customers elsewhere, especially in Asia, where China's gas demand is growing and Japan's post-Fukushima nuclear shutdowns have dramatically increased LNG imports.

These constraints are real. However, they ignore the ways in which changing the market's expectations about future LNG supplies--and potentially prices--could affect the calculations of Europe's gas buyers today and limit the political leverage that Russia's dominant gas export position conveys. Anecdotal reports suggest that US LNG is already a factor in contract renegotiations in Eastern Europe. As Amy Myers Jaffe of UC Davis and formerly the Baker Institute tweeted a few weeks ago, "it isn't about physical LNG cargo to Europe; it is about US exports promoting market liberalization (and) greater liquidity." 

 A decision by the US government to streamline the permitting and development of LNG facilities wouldn't enable US exports to displace Russian gas in Europe this year or next, but it would put Russia on notice that in the future it must compete in a market in which gas customers in Europe and elsewhere will have much greater choice. That would certainly complicate President Putin's plans.
A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Wednesday, March 19, 2014

Making Oil-by-Rail Safer

  • A series of rail accidents involving trains carrying crude oil has focused attention on safety procedures and even the tank cars used in this service.
  • Another concern is the variable characteristics of the "light tight oil "now shipped by rail in large quantities. That isn't the result of "fracking", but of the oil's inherent chemistry.   
The growth of North American oil production from unconventional sources has resulted in a dramatic expansion in the volume of crude oil shipped by rail. Unfortunately, as crude oil rail traffic has increased, so have rail accidents involving crude oil, including the tragic explosion and fire in Lac-Megantic, Quebec last July. That event and subsequent accidents have focused railroads, regulators and shippers on the need to improve the safety of oil-by-rail as quickly as possible.

In the immediate aftermath of Lac-Megantic, the Federal Railroad Administration issued an emergency order on procedures railroads must follow when transporting flammable and other hazardous materials. And on February 21, 2014 railroads reached a voluntary agreement with the US Department of Transportation (DOT) on additional steps, including reduced speed limits for oil trains passing through cities, increased track inspection, and upgraded response plans. These steps have the highest priority, because crude oil loaded in tank cars doesn't cause rail accidents. Every incident I've seen reported in the last year began with a derailment or similar event.

At the same time, the packaging and characteristics of the oil can affect the severity of an accident.  Investigators have focused on two specific issues in this regard, starting with the structural integrity of the tank cars carrying the oil. The vast majority of tank cars in this service are designated as DOT-111--essentially unpressurized and normally non-insulated cylinders on wheels. These cars routinely carry a variety of cargoes aside from crude oil, including gasoline and other petroleum products, ethanol, caustic soda, sulfuric acid, hydrogen peroxide, and other chemicals and petrochemicals.

Their basic design goes back decades, and even the older DOT-111s incorporate learnings from earlier accidents. A growing proportion of the US fleet of around 37,000 DOT-111 tank cars in oil service consists of post-2011, upgraded cars that have been strengthened to resist punctures, but the majority is still made up of older, unreinforced models. The Pipeline and Hazardous Materials Safety Administration (PHMSA) is studying whether to make upgrades mandatory, but some railroads and shippers aren't waiting. Last month Burlington Northern Santa Fe Railway, owned by Warren Buffet's Berkshire Hathaway, announced it would buy up to 5,000 new, more accident-resistant tank cars.

Another issue that has received much attention since Lac-Megantic concerns the flammability of the light crude from shale formations like North Dakota's Bakken crude, which accounts for over 700,000 barrels per day of US crude-by-rail. The Wall Street Journal published the results of its own investigation, reporting that Bakken crude had a higher vapor pressure--a  measure of volatility and an indicator of flammability--than many other common crude oil types.

The Journal apparently based its findings on crude oil assay test data assembled by the Capline Pipeline.  Although a Reid Vapor Pressure of over 8 pounds per square inch (psi) for Bakken crude is higher than for typical US crudes, it's not unusual for oil as light as this. That's especially true where, due to lack of field infrastructure, only the co-produced natural gas is separated out, leaving all liquids in the crude oil stream.

What makes this situation unfamiliar in the US is that domestic production of oil as light as Bakken had nearly disappeared before the techniques of precision horizontal drilling and hydraulic fracturing were applied to the Bakken shale and similar "source rock" deposits. (Note: High vapor pressures are characteristic of the naturally-occurring mix of hydrocarbons in very light crudes, rather than a result of the "fracking" process.) Nor is the reported vapor pressure for Bakken or Eagle Ford crude higher than that of gasoline, a product that is federally certified for transportation in the same DOT-111 tank cars that carry crude oil.

The variability of the vapor pressure data that the Journal's reporters identified for Bakken crude may result from another unfamiliar feature of such "light tight oil". Crude produced from conventional reservoirs, which are much more porous than the Bakken shale, tends to be relatively homogeneous. However, because the Bakken and other shales are so much less porous, limiting diffusion within the source rock reservoir, the composition of their liquids can vary much more between wells.

In any case, vapor pressure isn't the preferred measure of fuel flammability. Actual rail cargo classifications are based on flash point and initial boiling point. These routine quality tests aren't included in Capline's publicly available data. PHMSA initiated "Operation Classification" to ensure that manifests and tank car placards for crude oil shipments accurately reflect the potential hazards of each cargo, based on such measurements. The agency has determined that it hasn't always been done consistently, and DOT issued another emergency order requiring shippers to test oil for proper classification.

As mentioned in an oil-by-rail webinar yesterday, hosted by Argus Media, assigning the proper classification to oil shipments may seem like a bureaucratic concern--it doesn't necessarily affect the tank car type chosen to transport the crude--but it can have a significant impact on operational factors such as routing and the notification of first responders along the route.

There's no quick and simple way to make the transportation of crude oil by rail as safe as hauling a dry bulk cargo like grain. Tank car fleets can't be replaced overnight, not just because of the cost involved, but due to limited manufacturing capacity. However, in the meantime significant improvements can be achieved through a combination of government attention and sustained industry initiatives. Since the new crude streams traveling by rail play a key role in increasing North America's energy security, this is in the interest of everyone involved--producers, shippers, railroads, and not least the communities through which this oil travels.

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

Tuesday, March 11, 2014

Will Shale Oil Growth Lead to New US Refineries?

  • The revival of US oil production is spurring new investments in refineries, including the restart or new construction of small refineries near these resources.
  • How well such investments perform will depend on both the longevity of shale oil production and policies concerning its export.
An article on the revival of some mothballed US oil refineries and the possible construction of new ones provided yet another indication of industry confidence that record growth in oil production from US shale deposits isn't just a temporary phenomenon.  Refineries--even small ones--aren't usually quick-return investments. Restarting one or building a new one requires a positive view of future feedstock availability, product demand and other uncertainties.

The number of US refineries has fallen steadily, from 301 in 1982 to 143 last year. Because this mainly involved the retirement of smaller, less efficient facilities, while larger refineries "de-bottlenecked" or expanded, US refinery capacity actually grew over this period. It's generally cheaper to expand an existing facility, leveraging its infrastructure and experienced staff, than building a "grassroots" facility.

The hurdles facing new refinery construction in the US have been compounded by environmental regulations covering permits, emissions and product specifications. The time when a new entrant could simply distill light crude oil, sprinkle in some tetraethyl lead and other additives, and sell a full slate of refined products is long gone. New refineries in North Dakota, Texas and Utah are apparently focused on producing diesel fuel from the shale, or "tight" oil in the Bakken, Eagle Ford, and Uinta shales, respectively, and selling the rest of their output to other refiners or petrochemical plants as feedstocks .

With diesel demand in the producing areas booming, thanks to the needs of drilling rigs and the trucks that haul water, sand and equipment, as well as oil from leases not connected to pipeline gathering systems, this opportunity could last as long as the drilling-intensive shale development does. In other words, the demand aspiring refiners see appears to be linked directly to their source of supply.

Meanwhile larger plants, such as several of  Valero's Texas refineries, are in various stages of investments to enable them to process more light oil, reversing a multi-decade trend of investment to handle increasingly heavy and sour (high-sulfur) imported crudes. As with the smaller refineries, this shift requires high confidence in the long-term availability and favorable pricing of these high-quality domestic crude oil types.

The reasonableness of that assumption depends on the longevity of tight oil production. Large conventional inland oil fields typically reach peak output within a few years and then decline gradually, with long plateaus. Whether shale deposits, with their distinct geology, will follow the same pattern remains to be seen. Despite a few projections suggesting that tight oil output of the major shale basins could soon peak and decline rapidly, most mainstream forecasts suggest a long life for these resources, particularly as the technology to develop them continues to improve

For example, in its latest Annual Energy Outlook, the US Energy Information Administration (EIA) anticipates US tight oil production reaching 4.8 million barrels per day (MBD) by 2021, before gradually declining back to levels near today's in 2040. By contrast BP's just-released Energy Outlook 2035 sees comparable growth over the next few years but little subsequent decline, with tight oil at 4.5 MBD in 2035. Meanwhile, ICF International recently issued its Detailed Production Report, projecting shale/tight oil production in the US and Canada to reach 6.3 MBD by 2035, including 1.3 MBD from the tight oil zones of the Permian Basin of Texas.

The other big uncertainty concerning the availability of light tight oil for new or expanded US refineries depends on federal export policy, which I addressed in a recent post. This issue is highly controversial. A quick reversal of existing rules would be surprising, though as the New York Times noted, possible compromises under existing law could facilitate an expansion of crude oil exports beyond current shipments to Canada. While unlikely to dry up domestic availability of tight oil, such measures could shrink the current discounts for these crudes, compared to internationally traded light crudes like UK Brent. That seems less of a risk for small, simple, inland refineries than for larger facilities, especially those near coastal ports.

This isn't the first time investors have considered the need for new US refineries. There was similar interest after hurricanes Katrina and Rita slashed Gulf Coast refinery output for several weeks in 2005, though it ultimately led nowhere. If today's circumstances prove more supportive, it will be because the US hasn't experienced anything comparable to the shale revolution since the 1920s and '30s, when rapid oil production growth was accompanied by a wave of refinery construction, though in a very different business and regulatory climate. If that parallel holds, consumers stand to benefit from the resulting increase in competition.

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

Tuesday, March 04, 2014

Energy Risks of the Ukraine Crisis

  • Russia's intervention in the Crimean Peninsula poses few risks to Europe's energy supplies, but escalation or Western sanctions could change that assessment.
  • If the crisis expanded to mainland Ukraine, the integrity of that country's pipelines and the natural gas they carry to EU members would be the most immediate energy concern.
Although Ukraine's energy assets don't appear to be a major focus of Russia's occupation of the Crimean peninsula, any escalation of the crisis could have serious energy consequences, regionally and globally. The initial reaction of energy markets has been cautious, with Monday's jump of around 2% for Brent crude and nearly 10% for European gas futures largely erased in Tuesday's trading. While some of Russia's oil exports to Europe transit through Ukraine, the latter's natural gas pipelines are the bigger worry, especially in light of Russia's past use of the "gas weapon."

It's always dicey commenting on an unfolding event of this magnitude, which various observers have nominated as the most serious geopolitical crisis in post-Cold War Europe. I've spent the last few days following developments, listening to conference calls, and speaking with a Russia expert of my acquaintance. Dismissing the current events as out of tune with the 21st century ignores the complex history of a region that has seen multiple episodes of great-power conflict, just as trying to impose a Western mindset on President Putin's intentions is likely to come up short.

His latest reported comments suggest that he may have achieved his initial goals, at least insofar as giving him, rather than the new government in Kiev, control over Russia's access to the strategic Black Sea naval installations. Any broader goals are unclear at this point, and as a military expert highlighted in a media call hosted by the Council on Foreign Relations, the current confrontation in Crimea runs the risk of "unintended escalation." Wars have started this way.

So what's at stake, in energy terms? An infographic from Business Insider puts the gas situation in perspective. Russia's share of Europe's gas supply has fallen to 22% as EU members diversified their sources of supply in the aftermath of past interruptions in Russian gas deliveries. Still, roughly two-thirds of Russian gas sent to the EU passes through Ukraine's territory, and the pipelines that transit Belarus and the Baltic Sea lack sufficient capacity to reroute the entire volume should Ukraine's pipelines be disrupted.

Whether that occurred as an intentional reaction by Russia to steps that the US and EU are considering in response to its intervention in Crimea, or as a result of armed conflict in mainland Ukraine, natural gas prices in Europe would spike, even with ample gas in storage after a relatively warm winter. That would adversely affect EU economies still recovering from recession and the EU's financial crisis.

European natural gas prices are already much higher than those in the US, and any further increase would ratchet up the pressure on the EU's manufacturing sector. Nor is there nearly as much LNG available globally to make up any shortfall as there will be in just a few years, once US exports gear up and several large Australian LNG projects come onstream. Ironically, Ukraine is building its own LNG import facility to diversity its supplies--luckily not sited in Crimea.

The threat to oil deliveries seems less acute, short of an embargo that would hurt Russia as much as its customers. In 2012 Russia exported around 6 million barrels per day of oil and condensate to European refineries by various routes, including the southern leg of the Druzhba pipeline that crosses Ukraine on its way to the Czech Republic, Hungary and Slovakia. While a disruption of this flow could force refiners in those countries to scramble for alternative supplies, Russian oil would probably still find its way to world markets via other routes, including to the Baltic ports. Ensuing world oil price increases would likelier reflect an overall risk premium than a more localized physical shortfall.

Even if the situation doesn't progress beyond its current state, longer-term energy impacts could still follow. These include a recognition of heightened political risk for investments in Russia and its "near abroad" neighbors, along with the results of any financial sanctions that might be imposed.

If Mr. Putin is satisfied to engineer greater Crimean autonomy or independence from a more EU-oriented government in Kiev, and if the EU/US response is limited to financial measures to prop up that government, then the consequences--similar to those for Russia's ongoing occupation of part of Georgia--could be minimal. The EU can't go any farther than Germany will support, and thanks to the Nordstream gas pipeline led by its former Chancellor, Germany has less at stake in Ukraine than some of its neighbors. It has already distanced itself from suggestions of evicting Russia from the G8 group of nations. In that context, the US administration seems unlikely to sustain a harder line than Brussels.