How Will Low Oil Prices Affect Natural Gas?

• The growth of US natural gas output in recent years has been sustained partly by gas produced in conjunction with shale or "tight" oil.
• The slowdown in oil drilling in response to lower oil prices could also affect future natural gas production, and thus prices, especially in the US.

Media coverage of energy has focused heavily on oil prices, lately, for understandable reasons. Oil's dramatic plunge and subsequent volatility would be newsworthy, even if petroleum weren't still our leading source of energy, especially for transportation. In this context, the dog that hasn't barked is natural gas, although oil and gas are still linked by common drilling hardware and often produced from the same wells. With oil drilling being curtailed in response to low oil prices, should we be concerned about natural gas supplies in the months and years ahead?

At first glance the answer ought to be a straightforward "no." As most people now know, US drillers figured out how to tap the country's vast shale gas resources economically. US gas production is at record levels, after rising steadily since 2006 and surpassing former top producer Russia around 2009. US natural gas inventories were severely depleted following last year's "Polar Vortex" winter, but output grew fast enough to keep the benchmark price of gas below $4 per million BTUs this winter, despite below-average temperatures east of the Mississippi. 

However, in assessing gas supply under low oil prices we must factor in the industry's response to the natural gas price collapse in 2008. The prices of oil and gas both dropped precipitously during the financial crisis, but gas didn't recover to the same extent as oil. In 2007 the average spot price of natural gas on an energy equivalent basis was just over half that of West Texas Intermediate crude (WTI). By 2010 gas was worth only a third as much as oil, and by 2012 just 17%--the equivalent of $16 per barrel in a world of $100 oil. Drillers responded accordingly.

As the Energy Information Administration (EIA) chart below depicts, drilling for gas fell sharply from 2009-12, while  "oil-directed drilling" rose just as sharply. In fact, these were mainly the same rigs, redeployed to pursue different targets--sometimes in the same shale basin--as gas grew cheaper.

 So shouldn't natural gas production have fallen in tandem with the decline in rigs drilling for gas? The extremely useful charts in the EIA's latest Drilling Productivity Report help to explain why gas output continued to climb. First, just as the increasing productivity of shale oil drilling has confounded expectations about how soon US shale oil production would begin to decline after prices fell below $50 per barrel, shale gas drilling productivity improved rapidly following the gas price collapse.

For example, between 2009 and 2012 average gas production per rig--not per well--in the mainly gas-yielding Marcellus Shale more than tripled. From 2012 -14 it doubled again. Those gains reflect the combination of improvements in drilling efficiency (more wells or more feet drilled per month), improvements in hydraulic fracturing effectiveness, and companies targeting more productive well sites as knowledge of the basin's geology increased.

A key development following the gas price collapse was the growth of gas production from wells drilled in pursuit of shale oil. The best example of this is in the Eagle Ford Shale in Texas. While oil production there grew from virtually nothing to over 1.7 million bbl/day, the region's gas output nearly quadrupled, to 7.5 billion cubic feet (BCF) per day, or 10% of total US gas production.

Now we've entered a new chapter, due to a global oil surplus. As of the latest drilling rig count from Baker Hughes, oil-directed rigs employed in the US have fallen by around 45% since November 2014, and gas-directed rigs are down  by a quarter. A few companies may have shifted from oil back to gas, but the overall rig trend is still down for both.

The net result is that the EIA expects oil production from the major US shale basins to remain essentially flat from March to April, while gas production should still grow by about 0.3%. How much farther would US shale oil and gas drilling have to contract before lower rig counts swamped productivity improvements for gas? Comparing those figures to the growth rates in previous months, perhaps not very much.

Of course the US represents only about a fifth of the global gas market. Elsewhere, especially in Europe and Asia, many gas sales contracts are pegged to oil prices, while supply is dominated not by flexible shale, but by large conventional gas fields and the trade in liquefied natural gas (LNG). So outside the US, lower oil prices may do more to stimulate gas demand than to shrink supply. Cheaper gas imports into China are apparently already having an impact on coal consumption.

That could create new opportunities for companies developing LNG facilities to export US gas, at the same time that the economics of such exports become more challenging. In markets like Asia, the effect of lower oil prices has cut the gap between landed LNG prices and US pipeline gas--and hence the motivation for exports--by more than half.

Even after oil's collapse, US natural gas at the Henry Hub has recently traded at about one-third of the price of WTI, per-BTU of energy. The contraction of drilling in response to low oil prices may tighten supplies and nudge the prices of both commodities higher, reminding us that gas isn't entirely immune to oil's influence. However, with US gas inventories ample, the market doesn't seem to anticipate either a spike in gas prices this summer, or a narrowing of gas's discount vs. oil any time soon.

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

The IEA's Stressful Outlook

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

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

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

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

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

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

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

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

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

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

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

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

Will Russia's Gas Deal with China Block Other Suppliers?

• The recent natural gas deal between Russia and China involves volumes comparable to the gas production of the US Gulf of Mexico.
• Barring a major economic slowdown, meeting China's projected growth in gas demand will require this Russian gas, more LNG imports, and China's own shale gas.

 

$400 billion deals aren't announced every week--even by heads of state--although the new natural gas supply agreement between Russia and China had been in the works for some time. However, the crucial element of price apparently wasn't agreed until a negotiating session that lasted until 4:00 AM, Shanghai time. "Our Chinese friends are difficult, hard negotiators," said President Putin. They certainly waited for the right moment, with Russia pressed by sanctions in the aftermath of its annexation of Crimea.

The numbers are all impressive: After investing more than $50 billion in gas field and pipeline development in Eastern Siberia, Russia will sell 38 billion cubic meters (BCM) of gas per year to China for 30 years, and China will reportedly invest $20 billion for gas infrastructure and market development within its borders. Deliveries are set to start in 2018 and could eventually ramp up to 60 BCM/yr.

To put that in perspective, 38 BCM/yr equates to 3.7 billion cubic feet (BCF) per day. That's on par with the entire natural gas production of the Eagle Ford shale formation in south Texas, or the federal waters of the Gulf of Mexico.  Of greater relevance is that it's also nearly twice the output of Australia's Gorgon LNG project, which is expected to begin production in 2015. So from the perspective of the regional gas market and alternative supplies, this is a very significant quantity of gas, especially with a number of new Australian LNG projects under development or consideration.

As of 2012 China's gas market was already the largest in Asia, ahead of Japan, based on BP's annual Statistical Review of World Energy. This deal represents 27% of China's current gas demand, so it's tempting to conclude that squeezing Russian gas into China must come at the expense of other potential suppliers. If China's gas market were mature, such a zero-sum view could not be ignored, particularly by marginal LNG projects in Australia, Indonesia and the US that have not yet begun construction.

Competition with Russian gas could also impede development funding and access to infrastructure for China's nascent shale gas industry. The US Energy Information Administration's 2013 global survey of technically recoverable shale resources found that China could have over a quadrillion cubic feet--1,115 TCF--of shale gas in the ground, or nearly twice as much as the US. Yet China's progress in tapping this resource has been slow, and hardly a week goes by without another article explaining why it will be difficult if not impossible for others to replicate the US shale gas boom any time soon.

The growth of demand will largely shape the competitive environment for gas in China. In 2012 natural gas accounted for less than 5% of the country's total primary energy consumption, compared to 13% for Taiwan, 17% for South Korea and 22% for Japan, none of which are significant gas producers. From 2007-12 China's gas market grew at a compound average rate of 15% per year. In their just-released Medium-Term Gas Market Report, the International Energy Agency (IEA) forecasts China's gas demand growing by 90% by 2019, while their latest World Energy Outlook anticipated it tripling by 2025 and quadrupling by 2035, eventually reaching 11% of energy consumption. Achieving that would require the equivalent of ten gas deals the size of this one.

That outcome isn't a certainty, for many reasons. Having all that gas turn up at the right time poses a massive logistical and capital investment challenge, and China's economy might slow further. Meanwhile, the price implied in the media coverage of the Russia/China deal is around $350 per 1000 cubic meters ($10 per million BTUs) or more than double the current US wellhead price. That's a lot cheaper than most of the LNG delivered to Asia, but it won't outcompete Chinese coal on economics alone, and it won't jump-start new, gas-reliant industries the way the US shale gas revolution is beginning to do.

The scale of market development implicit in the IEA's forecasts for China would require a substantial expansion of gas-fired power generation, which in any case is the logical complement to China's aggressive expansion of wind and solar power installations. It also entails a significant shift from solid and liquid heating and cooking fuels to gas, where at least in the case of liquids, $10 gas would have the edge over products derived from $100 oil. It might even encompass gas-based distributed power generation using fuel cells, which is still in its infancy in the US. Such developments will benefit all potential suppliers, not just Russia.

It's also worth considering what this deal means for Russia. While many reports have suggested it provides a counterweight to Russia's dependence on the European gas market, that's really only true in a financial sense. The deal represents a major growth opportunity for Gazprom, Russia's majority-state-owned natural gas company, but this isn't the same gas that now supplies the EU. It will mainly be production from new gas fields. The potential upside for Russia may depend on its ability to leverage the infrastructure built for this deal into a larger gas network for supplying growth throughout Asia--in competition with US and other LNG projects eyeing that market.

"Milestone" is an over-used term, but it fits this deal. If the parties can iron out all the remaining details and proceed to construction and ultimately delivery, it could prove to be a key step in giving gas a much bigger role in fueling Asia's growth. That would have important environmental benefits, in both mitigating the air pollution in Asia's major cities and reducing carbon emissions, perhaps by enough to bend the curve of the region's greenhouse gas growth.

 

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

ABCs of LNG

• Current debates over LNG export often ignore its primary benefits, such as enabling gas to be produced for sale to markets beyond the realistic reach of pipelines.
• It also allows gas to compete with petroleum liquids where energy density is important, such as in powering ships, trains and land vehicles.  

The international reaction to Russia's annexation of Ukraine's Crimean peninsula has put a spotlight on liquefied natural gas (LNG), which was already under debate in the US as a mechanism for exporting increasingly abundant shale gas. Meanwhile, LNG is emerging as a fuel in its own right, rather than just a means of transporting gas from source to market. What links these trends is LNG's capability to enable natural gas to approach the convenience and energy density of petroleum.

The big driver for this is economic: UK Brent crude is currently over $100 per barrel, while natural gas in the US Gulf Coast trades at the energy equivalent of around $25 per barrel. That creates a significant incentive to build LNG plants, despite the recent escalation in their cost. Even after adding the equivalent of $20-30/bbl in expenses for liquefaction, shipping, and regasification to convert the LNG back into pipeline gas at its destination, the opportunity is significant. In Asia, where LNG sells for $14 or $15 per million BTUs, that's still less than $90 per equivalent barrel. And because gas can only be produced if it can be connected to a market, LNG enables more gas to compete in more markets, while providing customers a cleaner and cheaper fuel.

This is not a new technology. Early demonstrations in the 1940s and '50s were followed by commercial-scale plants built to export LNG from Alaska, Algeria and Indonesia, establishing what has since become a global industry. Every LNG plant is designed to take advantage of the fact that at atmospheric pressure natural gas becomes a liquid at -259 °F ( -161 °C)--about 60°F warmer than liquid nitrogen--shrinking by a factor of 600:1 in the process. As long as it is kept below that temperature, it can be stored and transported as a liquid.

That has important advantages over the alternative of compressing natural gas to create a denser fuel. For example, a gallon of LNG has around 2.2 times as much energy (based on lower heating values) as the same volume of compressed natural gas (CNG) at 3,000-3,600 pounds per square inch (psi). A gallon of LNG also has 98% of the energy of ethanol, and 64% that of gasoline. This makes LNG dense enough to transport economically over long distances, unlike CNG.

These differences have a practical impact on the gradual penetration of the transportation fuel market by natural gas. While most natural gas passenger cars are based on the simpler CNG approach, LNG is gaining a foothold in trucking, particularly where the combination of low emissions and denser fuel--yielding longer range--is important.

LNG is also emerging as an option for transportation modes that have had few viable alternative to oil-based fuels, such as in shipping and even rail where electrification is impractical. Replacing ships' bunker fuel with LNG could be a key strategy for responding to increasingly strict international regulations on sulfur and nitrogen oxide pollution from ocean-going vessels.

The environmental benefits of LNG can be significant, when it replaces higher-emitting fuels like coal and fuel oil. Even after accounting for the energy consumed in the liquefaction process-- equivalent to 8% or less of the gas input to a new LNG plant--and in storage and transportation, lifecycle emissions from LNG in power generation are 40-60% lower than those from coal. Its advantage in marine engines is smaller, but still positive at around 8%, while reducing local pollution significantly.

LNG isn't without drawbacks, including "boil-off", the gradual tendency of LNG in storage to evaporate due to heating from the environment outside the insulated tank. In stationary facilities the resulting gas can either be re-liquefied or delivered to meet local gas demand. In vehicles, it is vented after a specified holding time of around a week or more. That makes it more suitable for vehicles that are used frequently, rather than sitting idle for extended periods.

It's worth noting that while LNG is increasingly linked to shale gas in North America, nearly all the LNG currently marketed around the world is produced from conventional gas reservoirs, such as the supergiant North Field in Qatar, or the gas fields of Australia's North West Shelf. That would also be the case for a new LNG plant based on Alaskan North Slope gas, as described in a post here in 2012.

Only a few years ago, government and industry forecasts were unanimous in projecting a large and growing US LNG import requirement, as domestic gas production declined. The number of US LNG import facilities expanded to meet this new demand, but the combination of the recession and the shale gas revolution has resulted in imports shrinking substantially since 2007. The Energy Information Administration now expects the US to become a net exporter of LNG in 2016, including exports from repurposed import facilities. They will join a market that now supplies around 10% of global natural gas consumption and accounts for a third of global gas trade.

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

Environmental Groups Gear Up to Stop US LNG Exports

• The Sierra Club and other groups are taking on US LNG exports just when LNG is gaining support as a key response to Russia's aggressive behavior in Ukraine.

• The science behind their claims does not withstand scrutiny, and their timing couldn't be worse, geopolitically.

A collection of environmental groups, including the Sierra Club, Friends of the Earth and 350.org recently wrote to President Obama, urging him to require a Keystone-XL-style environmental review--presumably entailing similar delays--for the proposed Cove Point, Maryland liquefied natural gas (LNG) export terminal. Given the President’s explicit support for wider natural gas use and the administration's new commitment to our European allies to enable LNG exports, the hyperbole-laden letter seems likelier to rev up the groups’ activist bases than to influence the administration’s policies.

Either way, its timing could hardly be coincidental, coming just as opinion leaders across the political spectrum have seized on LNG exports as a concrete strategy for countering Russian energy leverage over Europe in the aftermath of President Putin’s seizure of Crimea. If, as the Washington Post and energy blogger Robert Rapier have suggested, the Keystone XL pipeline is the wrong battle for environmentalists, taking on LNG exports now is an even more misguided fight, at least on its merits.

Referring to unspecified ”emerging and credible analysis”, the letter evokes the thoroughly discredited argument that shale gas, pejoratively referred to here as “fracked gas”, is as bad or worse for the environment as coal. In fact, in a similar letter sent to Mr. Obama one year ago, some of the same groups cited a 2007 paper in Environmental Science & Technology that clearly showed that, even when converted into LNG, the greenhouse gas (GHG) emissions of natural gas in electricity generation are still significantly lower than those of coal, despite the extra emissions of the liquefaction and regasification processes.

The current letter also implies that emissions from shale gas are higher than those for conventional gas, a notion convincingly dispelled by last year’s University of Texas study, sponsored by the Environmental Defense Fund, that measured actual, rather than estimated or modeled, emissions from hundreds of gas wells at dozens of sites in the US.

It’s also surprising that the letter’s authors would choose to cite the International Energy Agency’s 2011 scenario report on a potential “Golden Age of Gas” in support of their claims. That’s because the IEA’s analysis found that the expanded use of gas foreseen in that scenario would reduce global emissions by 160 million CO2-equivalent tons annually by 2035, mainly through competition with coal in power generation in developing countries, addressing the principal source of global greenhouse gas emissions growth today.

The groups take another wrong turn in suggesting that President Obama increase support for wind and solar power instead of supporting gas. The contribution of new renewables to the US energy mix has grown rapidly, thanks to significant federal and state support, but it remains small. Despite record US wind turbine and solar power additions, shale gas and shale oil added more than 20 times as much energy output on an equivalent basis in 2012, and last year’s gains look similarly disproportional. Simply put, the US isn’t enjoying a return to energy security or becoming a major energy exporter because of renewables. It is counterproductive for renewables to pit them against gas as they have done here.

Experts disagree on how much and how quickly US LNG exports can influence gas markets in Europe and elsewhere. Yet while none of the currently permitted or proposed LNG facilities will be ready to ship cargoes until at least late next year, the knowledge that they are coming will inevitably have an impact on traders and contracts, including contracts for Russian gas in the EU. Whether or not US natural gas molecules ever reach Europe, they can serve a useful role in the necessary response to Russia’s aggression in Ukraine. Attempting to block this for spurious reasons puts opponents in jeopardy of becoming what Mr. Putin in his previous career might have called “useful idiots.”

It’s tempting to speculate on what this new campaign says about the participating groups’ perceptions of how the Keystone XL fight is going. Win or lose, they might soon need a new cause, or face the dispersal of the protesters and financial contributors it has galvanized. Blocking LNG may look conveniently similar--even if similarly mistaken--but I can’t help feeling these groups would gain more traction with their fellow citizens by focusing on what they are for, rather than expending so much energy in opposition.

A different version of this posting was previously published on Energy Trends Insider.

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.

Converting Coal to Synthetic Natural Gas in China

•  With so much attention focused on China's shale gas potential, its growing synthetic natural gas industry is a wild card.

• In light of China's severe air quality problems,  trading smog for higher CO2 emissions is an understandable choice, but one with global implications.

In its latest Medium-Term Coal Market Report the International Energy Agency (IEA) forecasts a slowing of coal demand growth but no retreat in its global use. That won’t surprise energy realists, but the item I wasn’t expecting was the reference in the IEA press release to growing efforts in China to convert coal into liquid fuels and especially synthetic natural gas (SNG).  It’s not hard to imagine China’s planners viewing SNG as a promising avenue for addressing the severe local air pollution in that country’s major cities, but the resulting increase in CO2 emissions could be substantial. It could also affect the economics of natural gas projects around the Pacific Rim.

Air quality in China’s cities has fallen to levels not seen in developed countries for many decades. There’s even a smartphone app to help residents and visitors avoid the worst exposures. Much of this pollution, in the form of oxides of sulfur and nitrogen and particulate matter, is the result of coal combustion in power plants. Although China is adding wind and solar power capacity at a rapid clip, after years of exporting most of their solar panel output, the scale of the country’s coal use doesn’t lend itself to easy or quick substitution by these renewables.

Natural gas offers a lower-emitting alternative to coal on a larger scale than renewables. Existing coal-fired power plants could be converted to run on gas or replaced with modern combined-cycle gas turbine power plants. Gas-fired power plants emit up to 99% fewer local, or “criteria” pollutants than coal plants, especially those with minimal exhaust scrubbing.

Unfortunately, China doesn’t have enough domestic natural gas to go around. Despite potentially world-class shale gas resources and the rapid growth of coal-bed methane and more conventional gas sources, natural gas supplies only 4% of China’s energy needs. Imported LNG can help fill the gap, but it isn’t cheap. What China has in abundance is coal. Converting some of it to SNG could boost China’s gas supply relatively quickly–perhaps faster than the country’s shale gas infrastructure and expertise can gear up.

SNG is hardly a new idea; the Great Plains Synfuels Plant has been producing it in North Dakota since the 1980s. When that facility was built, natural gas prices were volatile and rising, and greenhouse gas emissions appeared on no one’s radar. The process for making SNG from coal is straightforward, and its primary building block, the gasification unit, is off-the-shelf technology. I worked with this technology briefly in the 1980s, and my former employer, Texaco, licensed dozens of gasification units in China before the technology was eventually purchased by GE. Other vendors offer similar processes.

Gasifying coal adds a layer of complexity, compared to gasifying liquid hydrocarbons but this, too, has been demonstrated in commercial operations. Most of the output of the facilities Texaco sold to China was used to make chemicals, but the chemistry of turning syngas (hydrogen plus carbon monoxide) into pipeline-quality methane is no more challenging.

This effort is already under way in China. Last October Scientific American reported that the first of China’s SNG facilities had started shipping gas to customers, with four more plants in various stages of construction and another five approved earlier this year. The combined capacity of China’s nine identified SNG projects comes to around 3.5 billion cubic feet per day, or a bit more than the entire Barnett Shale near Dallas, Texas produced in 2007 as US shale gas production was ramping up. It’s also just over a quarter of China’s total natural gas consumption in 2012, including imported LNG.

To put that in perspective, if that quantity of SNG were converted to electricity in efficient combined cycle plants their output would be roughly double that of China’s 75,000 MW of installed wind turbines in 2012, when wind generated around 2% of the country’s electricity.

The appeal of converting millions of tons a year of dirty coal into clean-burning natural gas, in facilities located far from China’s population centers, is clear. This strategy even has some similarities to one pursued by southern California’s utilities, which for years imported power from the big coal-fired plants at Four Corners.  For that matter, the gasification process has some key advantages over the standard coal power plant technologies in the ease with which criteria pollutants can be addressed. Generating power from coal-based SNG might actually reduce total criteria pollutants, rather than just relocating them.

However, wherever these plants are built they would add around 500 million metric tons per year of CO2, or around 5% of China’s 2012 emissions, a figure that dwarfs even the most pessimistic estimates of the emissions consequences of building the Keystone XL pipeline. That’s because the lifecycle emissions for SNG-generated power have been estimated at seven times those from natural gas, and 36-82% higher than simply burning the coal for power generation.

What could possibly lead China’s government to pursue such an option, in spite of widespread concerns about climate change and China’s own commitments to reduce the emissions intensity of its economy? Having lived in Los Angeles when it was still experiencing frequent first-stage smog alerts and occasional second-stage alerts, I have some sympathy for their problem. China’s air pollution causes even more serious health and economic impacts and has been blamed for over a million premature deaths each year. By comparison the consequences of greenhouse gas emissions are more indirect, remote and uncertain. Any rational system of governance would have to put a higher priority on air pollution at China’s current levels than on CO2 emissions.

It might even turn out to be a reasonable call on emissions, if China’s planners envision carbon capture and sequestration (CCS) becoming economical within the next decade. It’s much easier to capture high-purity, sequestration-ready CO2 from a gasifier than a pulverized coal power plant. (At one time I sold the 99% pure CO2 from the gasifier at what was then Texaco’s Los Angeles refinery to companies that produced food-grade dry ice.) It should also be much easier and cheaper to retrofit a gasifier for CCS than a power plant.

In an internal context the trade-off that China is choosing in converting coal into synthetic natural gas is understandable. However, that perspective is unlikely to be shared by other countries that won’t benefit from the resulting improvement in local air quality and view China’s rising CO2 emissions with alarm. I would be surprised if the emissions from SNG were factored into anyone’s projections, and nine SNG plants could be just the camel’s nose under the tent.

In an environment that the IEA has described as a potential Golden Age of Natural Gas, large-scale production of SNG could also constitute an unexpected wild card for energy markets. When added to China’s shale gas potential, it’s another trend for LNG developers and exporters in North America and elsewhere to monitor closely.

A different version of this posting was previously published on Energy Trends Insider.

Canada: From Energy Supplier to Competitor?

• In addition to its impact on global oil and natural gas pricing and trade, the shale revolution is altering the energy relationship between the US and Canada.
• This long-standing supplier/customer relationship is becoming more complex as producers in both countries seek new markets outside North America.

In remarks last month the Canadian Natural Resources Minister, Joe Oliver, suggested that with the continued growth of unconventional oil production in the US, "Our only customer will become a competitor." Considering plans for liquefied natural gas export facilities on both sides of the border, he might have included LNG in that comment, too. Let's take a look at the kind of competition he might have had in mind.

Canada has long been an important supplier of crude oil to US refineries, since at least the 1950s. For much of the 1980s and '90s it was in a virtual three-way tie with Mexico and Venezuela for the #2 spot on the list of top oil exporters to the US, behind Saudi Arabia. Since 2004 Canada has claimed first place on that list as its production expanded, while Mexican and Venezuelan output declined and some Saudi oil went to other markets. From 2010 to 2012 exports of Canadian crude oil to the US, including oil sands crude, increased by 23% to over 2.4 million barrels per day (bpd). This has provided Canada with a reliable outlet for its production and the US with additional supplies not exposed--except for price--to ongoing instability in the Middle East and other regions.

However, with or without the Keystone XL Pipeline, the competition to feed US refineries is becoming more intense.  Canada's growing crude exports, including significant quantities of heavy and/or sour crude oil, must displace similar crudes imported into the US from  Latin America and the Middle East without losing ground to the expanded light oil production from US shale plays such as the Bakken and Eagle Ford, and the otherwise mature Permian Basin of Texas and New Mexico. Each of these areas now yields a million bpd. These dynamics are compounded by 1970s-vintage US oil-export rules that keep domestic crude bottled up in the Gulf Coast and weaken the economics of oil production throughout much of North America. 

If it seems odd for a Canadian official to talk about competition within the US market in this way, consider that the main country exempted from current US oil export restrictions is Canada. US oil exports to eastern Canada by rail and by tanker have grown rapidly in the last two years and are likely to expand beyond the current 100,000 bpd level, if export license applications are any indication. US oil exports to Canada may be displacing non-North American crudes today, but they likely also have an adverse effect on the economics of projects intended to ship more western Canadian crude eastward. So Canada now understandably looks towards Asia, home to the world's fastest oil-demand growth, as the logical destination for at least some of its future oil production.

 Natural gas creates another, perhaps more plausible arena for export competition between Canada and the US. Canada envisions a resurgence in gas production similar to what the US has experienced, based on a combination of conventional gas discoveries, such as in the Mackenzie Delta of the Northwest Territories, as well as the shales of Alberta and British Columbia. It also stands to gain additional gas reserves if it is successful in its bid to claim more of the Arctic. As Canadian gas is displaced from its long-standing export market in the US by the shale boom in the lower-48, LNG exports from B.C. are looking more attractive. The province lists five projects in different stages of development and highlights B.C.'s advantageous shipping route to Asia.

Many more LNG export projects have been proposed for the US, with at least four having received approval to sell to countries with which the US does not have free-trade agreements. A number of these are based on existing, or at least previously permitted, LNG import facilities, giving developers a head-start on construction. The US also has a big edge in proved natural gas reserves and technically recoverable gas resources, including shale gas.

Despite these US advantages, aspiring Canadian LNG exporters won't have to contend with an enormous domestic market for their gas, in which many industries are competing to use more gas in power generation, chemicals and other manufacturing, and different paths for displacing oil from transportation, including CNG, LNG, methanol, ethanol or gas-to-liquids fuels. As a result, I suspect that a Canadian LNG plant could count on a more stable long-term cost of gas than one on the US Gulf Coast.

The protracted controversy over the Keystone XL Pipeline project has focused a great deal of public attention on a single aspect of our energy relationship with Canada, while obscuring other aspects that are beginning to shift. Adding a new competitive overlay to our long-standing energy supply chains could ultimately increase North American leverage on OPEC's pricing power, while helping to develop a deeper and more flexible global market for LNG, with resulting environmental benefits. While this might result in winners and losers at the project and company level, the overall effect should be positive for both countries.

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

The LPG Echo of the Shale Gas Boom

• Increased US production of LPG and natural gas liquids is an outgrowth of the shale gas revolution and a key ingredient for translating its benefits into industrial growth.
• The infrastructure investments, export opportunities and price relationships for these liquids represent a microcosm of the similar issues for shale gas and LNG.

An article in the Wall St. Journal last month on the impact of a Midwest propane shortage on farmers trying to dry their corn harvest caught my attention. How could propane be in short supply, when US production is soaring due to shale gas? While it turns out that the shortfall in question was localized and temporary, it prompted me to take a closer look at LPG supply and demand than I have in many years. I found yet another market that is being transformed by the shale gas revolution.

Like most Americans--except for those in the roughly 5% of US homes heated with it-- I normally think about LPG only when I have to change the tank on my barbecue grill. That wasn't always the case; early in my career I traded LPGs for Texaco's west coast refining system. I'm happy to see that some of my former colleagues from that period are still involved and frequently quoted as experts on it. Although the LPG market is obscure to many, it represents a microcosm of the issues of reindustrialization and product exports arising from the recent turnaround in US energy output trends.

In order to follow these developments, we first need to clarify some confusingly similar acronyms, starting with LPG. Although often used synonymously with propane, it actually stands for "liquefied petroleum gas" and covers mainly propane and butane, though some in the industry include ethane in this category. The term reflects the oil refinery source of much of their supply, both historically and to an important extent today.  LPG overlaps with natural gas liquid (NGL)--ethane, propane, butane, isobutane and "natural gasoline"-- that has been separated from "wet" ( liquids-rich) natural gas during processing. NGLs are entirely distinct from the anagrammatical LNG, or liquefied natural gas, which consists mainly of methane that has been chilled until it becomes a liquid. By contrast, NGLs and LPG are typically stored at or near ambient temperature but under pressure to keep them in the liquid state.

LPG and NGLs make up a distinct segment of US and global energy markets, falling between the markets for natural gas and refined petroleum products. They are also linked to these larger markets, both logistically and economically. For example, gas marketers vary the amount of liquids they leave in "dry gas" to meet pipeline natural gas specifications based on price and other factors, and oil refiners blend varying quantities of butane into gasoline, depending on seasonal requirements. Propane and butane are mainly used as fuels, while ethane and isobutane are chiefly chemical feedstocks.

The development of shale gas in the US and Canada has affected the supply of NGLs and LPG in several important ways. First, starting around 2007 increasing shale gas output helped to halt and then reverse the decline in US natural gas production from which US NGLs are sourced. Then, following the financial crisis, diverging natural gas and crude oil/liquids prices pushed shale drillers toward the liquids-rich portions of shale basins like the Eagle Ford in Texas, in order to maximize their revenue. The resulting surge of US NGL production in late 2009 reinforced the decline of US LPG imports that began with the recession. According to US Energy Information Administration data, the US became a fairly consistent net exporter of LPG in 2011.

The current US LPG surplus is around 100,000 bbl/day, out of total production of around 2.7 million bbl/day. That surplus and its expected growth provides the basis for a number of announced LPG  export projects, as well as the anticipated development of new domestic chemical facilities such as ethylene crackers that would consume substantial portions of new supply, particularly of ethane.

The success of those projects depends on significant investments in new infrastructure, including gas processing, NGL fractionators to split the raw NGL into its components, and pipelines to deliver NGL to fractionators and LPG to markets. This is particularly true for the Marcellus and Utica shale gas in the Northeast, from which little or no ethane has been extracted due to limited local demand. Not only is that a missed manufacturing opportunity, but it constitutes a potential constraint on further liquids-rich gas development, since leaving too much ethane in the marketed gas would cause it to exceed pipeline BTU specifications.

In the meantime we're left with a situation that's analogous to the growth of tight oil production from the Bakken  shale. New sources of production have come on-stream faster than the infrastructure necessary to deliver them efficiently to where they can be processed or consumed. That puts a growing US surplus of propane and other NGLs in tension with tight regional markets for these fuels in the Midwest and Northeast, where residential propane prices are running well ahead of last year's at this time.  The resolution of this apparent paradox will depend on which infrastructure and demand projects are eventually completed, and how soon.

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

Energy Projects Seem Less Urgent in A Post-Energy-Crisis World

• Rather than being another component of an ongoing energy crisis, opposition to various energy projects points to the alleviation of a decades-long string of US energy crises.
• The audience for concerns about pipelines and fracking would be much smaller if oil were still at $145 per barrel and natural gas over $10 per million BTUs.

To someone living in 1974, during the first energy crisis of the last 40 years, the idea of mass protests to block a pipeline for importing crude oil from Canada would have seemed incomprehensible.  Our environmental awareness has expanded in the interim, along with new channels for exchanging information, including "enduring misconceptions".  Yet the current opposition to so many different energy projects--natural gas drilling, long-distance transmission lines and even wind farms--can also be viewed as an unintended consequence of recent energy successes on a broad front.

The alleviation of what seemed to many a permanent energy crisis might not be obvious, because it has crept up on us. But consider a few of the big-picture elements that have changed:

In crisis mode, US energy security was focused on steadily rising oil and later natural gas imports, while "energy independence" was a goal embraced by politicians but rarely energy experts. Cars offering better fuel economy were available but entailed trade-offs in size and performance. Today, oil imports are falling, the US is a net exporter of refined petroleum products, and public concern about Peak Oil is waning, as measured by internet search activity. Ethanol from corn supplies 10% of US gasoline demand, while other forms of renewable energy are growing rapidly, from a small base. The big question for the federal government this summer is how many natural gas export facilities to allow. Meanwhile, the threshold for fuel-efficient cars has shifted from 30 mpg to 40 mpg, offered in numerous attractive models.

Another way to gauge the success of technologies like hydraulic fracturing, or "fracking", in shifting our energy landscape is to remind ourselves how bad we thought today's situation would be, just a few years ago.  In 2005 the official US annual energy forecast projected oil imports to increase from 11 million barrels per day (MBD) in 2003 to nearly 15 MBD by this year, due to rising demand and domestic production that was expected to remain flat, at best (see below chart.)

The Energy Information Agency (EIA) also expected US natural gas imports to increase steadily, reaching 3.5 trillion cubic feet  (TCF) of LNG imports this year, on their way to 6 TCF per year by 2022. As a consequence, in 2005 the EIA forecast that coal would still generate 48% of US electricity by 2013.
 

Now imagine energy prices in that alternative 2013. With US natural gas suppliers importing an average of 90 LNG tankers per month, would the wellhead price of gas still be under $4 per million BTUs, or closer to the $16 price paid in some international markets? And with US refiners importing up to twice as much crude oil as they are actually on track to do this year, in the context of sanctions on Iran and turmoil in North Africa, how likely does it seem that oil would be at $105-110/bbl, instead of much higher? $100 oil is a drag on the economy, but US consumers have adjusted to gasoline priced around $3.50-3.75/gal., on average. Every $1 per gallon above that would take another $130 billion per year away from other purchases, with adverse effects on the US economy.

More to the point, in such an environment how much tolerance would there be for opposition to oil pipelines or gas drilling that had the potential to lower energy prices, or at least reduce imports and enhance energy security? If oil were above its 2008 high of $145/bbl, and gasoline flirting with $5 per gallon, it would surely be much harder for elected officials to delay approving projects like the Keystone XL pipeline, or to sustain gas drilling moratoria. Ironically then, the successful large-scale application of shale drilling techniques, which has resulted in a 29% increase in US natural gas production and 33% rise in oil production since 2004, helped make it possible for opponents of Keystone or fracking to be heard, rather than dismissed out of hand.

I was recently struck by a reported remark by a pipeline executive. "Shale is everywhere," he said, but it won't be produced everywhere because "people make choices." I agree with that insight, while recognizing that such choices are available mainly because altered economic conditions and the same technologies to which some now object have enabled us to shed an energy crisis mindset.  This situation might have future parallels for other technologies that have escaped much pushback, so far. 

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

Natural Gas Vehicles Already Big in Italy, Iran

The sudden abundance of natural gas in the US triggered a startling divergence of crude oil and natural gas prices that, in turn, has energized the advocates of using more gas in transportation. Yet despite the availability of wholesale natural gas at less than $0.60 per gasoline gallon equivalent (GGE), and with retail compressed natural gas (CNG) prices under $2.00/GGE in many locations, natural gas accounted for less than 3% of US transportation energy consumption in 2011--most of it attributable to pipeline compressors. The picture is very different in countries like Italy and Pakistan, where CNG has a significant market share in motor fuels. As the US looks ahead to greater reliance on secure domestic gas for road transport, it's worth considering why other countries have such a big head start.

The obstacles to greater market penetration by natural gas in transportation are well known. CNG and LNG (liquefied natural gas) require new infrastructure. Many more retail gas facilities would be needed to assure motorists of convenient access at service stations. CNG takes a separate dispenser and compressor on the forecourt, while LNG requires both a new pump and insulated storage. Where pipeline gas is unavailable, such as in parts of the northeast, additional investments in the local "gas grid" may also be necessary.

Vehicle conversion costs represent another significant barrier. Engine modifications and crash-resistant fuel tanks add significant costs for both new vehicles and retrofits. Even with gas priced well below gasoline or diesel fuel, the payback for these costs can be lengthy. That's one reason that gas has made greater strides in bus, truck and delivery fleets in the US than for personal cars, since the more intensive use of such vehicles substantially shortens the resulting payout periods. Countries with high gas-vehicle penetration typically have government policies and incentives in place to promote the use of gas by mitigating these obstacles.

Italy leads the EU in CNG vehicle adoption, with more than 11% of new passenger cars equipped for natural gas last year. That compares to 0.01% for the US in 2012, where only one CNG model, a Honda, was sold. The Italian government promotes natural gas use in vehicles both directly and indirectly. The country provides a subsidy of €700 ($945) to purchasers of CNG automobiles, while manufacturers like Fiat offer discounts to expand their market for CNG cars. Incentives were even larger a few years ago. The government also makes retail petroleum products extraordinarily expensive with high taxes. So even though Italy is a large net importer of natural gas, CNG is much cheaper than gasoline or diesel at the pump.

Fuel availability may also have something to do with the disparity in adoption rates. Despite having an 83% smaller overall vehicle population , Italy has over 40% more CNG or "Autogas" refueling stations than the entire US, at around 900. This is due in part to state-level incentives, with 50-70% of the cost of a new CNG filling station reimbursed by regions such as Liguria, Lombardy, and Piemonte.

In terms of market penetration, Pakistan, which appears to be self-sufficient in gas, leads the world in natural gas vehicles, at 80%. That translates into over 2 million CNG vehicles, the result of a determined effort on the part of the government to reduce imports of petroleum by shifting to domestic fuels, with gas as its best option. This is a common theme in the non-oil-exporting developing world, where oil imports impose a large drag on national trade balances. CNG use in Iran is even higher than in Pakistan, as an unintended consequence of protracted international sanctions.

For the US, where oil production is increasing and oil imports declining, a shift to natural gas for transportation is likely to remain an opportunity, rather than a matter of necessity. The "NATGAS Act", a bill proposing incentives for CNG and LNG along the lines of the Italian model has languished in the US Congress for several years. It remains to be seen whether this will become a higher priority in the new Congress, which has shown early signs of interest in breaking the recent logjam on energy legislation.

In the meantime, adoption of natural gas vehicles in the US will proceed based on market forces, supported by a small advantage in the way CNG cars are counted in manufacturers' fleets under the stringent federal fuel economy regulations issued last summer. That could lead to natural gas fueling 3% of US vehicles --mostly trucks--by 2020, based on the analysis of a partner at McKinsey & Co. Much like the case for energy efficiency investments, the available savings indicate a much larger potential, but funds for CNG/LNG transport must compete with other priorities.

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