Navigant Research Blog

With Cheap Oil Flowing, U.S. Looks to Next Energy Revolution

— January 26, 2015

With oil prices continuing to languish and Saudi Arabia moving through a royal succession upon the death of King Abdullah, the idea that the “OPEC era is over” has gained credence among government officials and industry analysts. “Did the United States kill OPEC?” asks New York Times economics reporter Eduardo Porter. The answer, he argues, is essentially yes: “The Nixon administration and Congress laid the foundation of an industrial policy that over the span of four decades developed the technologies needed to unleash American shale oil and natural gas onto world markets,” thus loosening OPEC’s grip.

The reality is a bit more complicated than that: OPEC still produces nearly 40% of the world’s oil; the United States produces less than 18%. And oil at $50 a barrel could actually increase OPEC’s power as producers of unconventional reserves, which are more costly to produce, are driven from the market. Like the coal industry, OPEC is not going anywhere anytime soon.

The Big Opportunity

The shale revolution does, however, offer some other welcome knock-on effects, if policymakers are alert and astute enough to take advantage of them.  “Cheaper oil and gas will contribute an estimated $2,000 per American household this year, and $74 billion to state and federal governments coffers,” note Ted Nordhaus and Michael Shellenberger of the Breakthrough Institute, a San Francisco-based energy and climate think tank. The Breakthrough Institute has done extensive research on the role of public-private partnerships in the development of the seismic and drilling technology advances that underlie the shale revolution. Should the government choose to take advantage of it, this windfall could fund a multi-decade R&D program for renewable energy similar to the one that led to the shale boom.

“We can afford to spend a tiny fraction of the benefits of the bounty that cheap oil and gas have brought so that our children and grandchildren can similarly benefit from cheap and clean energy in the future,” declare Nordhaus and Shellenberger.

The Gas Tax Solution

That’s an inspiring concept. The execution is likely to be messy, though. Any such spending would probably need congressional support, or at least consent – and the U.S. Senate only last week finally reached agreement that “climate change is real and not a hoax.” That’s a long way from dedicating billions to develop alternative energy sources.

One suggestion put forth by clean energy activists is an increase in the U.S. gas tax. A few cents extra per gallon (on gas that’s about half the price it was a year ago) could help fund a massive crash program to develop inexpensive, clean energy technology (not to mention shore up the failing U.S. Highway Trust Fund).

But raising the gas tax is like the National Popular Vote – a terrific idea that’s unlikely to happen in our lifetimes. Even though polls consistently indicate that consumers are willing to spend slightly more for the energy they consume in order to limit climate change, actually slapping extra taxes on motorists at the pump is unlikely to be a winning move in Washington – which explains why President Obama left it out of his call for a “bipartisan infrastructure plan” in his State of the Union address.

 

As Demand Soars, Construction of LNG Terminals Booms

— November 24, 2014

International marine construction companies are seeing a bonanza of new projects as countries around the world approve massive new terminals for liquefied natural gas (LNG) – for imports in most cases, and for exports from North America, Australia, and some Southeast Asian countries.  Altogether, this frenzy of port building could amount to hundreds of billions of dollars over the next decade as seaborne trade in LNG climbs to meet spiraling demand, particularly in the energy-hungry countries of China, India, and other Asian nations.

Total deliveries of LNG were flat in 2013 compared to 2012, according to the BG Group, but this masks pent-up demand, as producers in the United States are ramping up export capacity and importing countries are scrambling to build import terminals.  BG Group forecasts that worldwide LNG demand is expected to increase at a rate of 5% annually through 2025, with much higher rates in the developing countries of Asia.

North America

In September, the U.S. Federal Energy Regulatory Commission (FERC) gave final approval to the Cove Point LNG facility, overruling the objections of environmental groups and bringing to four the number of U.S. export terminals officially approved and under construction.  All told, 14 terminals are seeking approval by federal regulators in the United States, on the Gulf Coast, the East Coast, and the Pacific Northwest.  The Northwest facilities, in particular, face fierce opposition from environmentalists opposed to the increased fracking that large quantities of U.S. exports will entail.  With big potential markets waiting not only across the Pacific, but also in Europe, U.S. oil & gas companies and their representatives in Washington, D.C. are eager for more export capacity to come online.  There are also at least a dozen LNG terminals proposed along the coast of British Columbia.

Europe

With unrest in Ukraine giving rise to fears of disruptions of natural gas supplies from Russia, which provides 30% of Europe’s natural gas, European governments and companies are scrambling to build new import facilities.  Paradoxically, with international supplies limited and with Japan, which relies more heavily on imported natural gas for its energy supply than any other country, soaking up much of the available supply at inflated prices, imports to Europe have declined in the last couple of years.  The Gate terminal on the North Sea coast near Rotterdam was built with the support of the Dutch government to maintain the Netherlands’ status as a regional gas hub.  It is now running at 10% of capacity, according to The Economist.

Nevertheless, imports from the United States are sure to increase, and the European Union sees the construction of new import terminals as a critical matter of regional energy security.  Lithuania, for example, is due to open a massive new floating terminal this year or in early 2015.  New terminals are especially important along Europe’s vulnerable southeastern coast, as currently countries in the area are essentially captive customers to Russia’s Gazprom.

Amos Hochstein, the acting U.S. special envoy and coordinator for international energy affairs, testified recently before the Senate Foreign Relations Committee, saying that “[there is a] critical need for Europe to improve its energy infrastructure by constructing new pipelines, upgrading interconnectors to allow bidirectional flow, and building new LNG terminals to diversify fuel sources … We support proposals to build LNG terminals at critical points on European coasts, from Poland to Croatia to the Baltics.”

Asia

The biggest building boom is underway in China, where three import new terminals came online in 2013 and at least two more are expected begin operation before the end of this year.  Already, half of the world’s capacity for regasification (the conversion of LNG to conventional natural gas, for transport by pipeline) is located in Asia.

“China’s imports of liquefied natural gas (LNG) are growing at a record pace,” reported Reuters earlier this year, “as it aims to use cleaner fuels to cut smog in big cities, creating a powerful new source of demand that has the potential to reshape the market for the super-chilled gas.”  China’s LNG imports grew 35% in the first quarter of this year compared to the same period in 2013.

Meanwhile, new production is emerging from Southeast Asia, particularly in Indonesia and Papua New Guinea.  Also, Singapore, which sits at the mouth of the Strait of Malacca, through which passes more than half of the world’s seaborne LNG, has formed ambitious plans to be the LNG trading hub for Southeast and East Asia.

These LNG terminals tend to cost around $10 billion apiece.  It’s a good time to be in the business of building them.

 

A Better Way to Extract Shale Oil

— November 5, 2014

Last month the Colorado Fuel Cell Center (CFCC) at the Colorado School of Mines hosted the first public demonstration of IEP Technology’s Geothermic Fuel Cell (GFC).  This innovative technology uses the waste heat produced by fuel cells to convert the kerogen in oil shale into unconventional hydrocarbons onsite.

Using standard fuel cell technology, the GFC flips the application on its head by taking a heat-first, power-second approach.  The system uses solid-oxide fuel cells, manufactured by Delphi Automotive, in tubular modules that can be linked end-to-end to create a long string of fuel cells encased in a steel cylinder.  The long-term plan is to insert vertical stacks that are up to 1,000 feet long into oil shale formations, spaced 10 to 15 feet apart in a grid pattern.  In this configuration, the fuel cells can generate temperatures of up to 1,200°F, which will be used to heat the formation and drive pyrolysis (thermal decomposition of the oil shale).

Giving Shale Oil a Better Name

Currently, shale oil is most commonly extracted ex situ, or offsite.  The oil shale is mined and taken to an above-ground processing facility where it is crushed, heated to temperatures suitable for pyrolysis (500-1,100°F), and the unconventional hydrocarbons (shale oil and natural gas) are collected, cooled, and refined.  This process is expensive, inefficient, and extremely damaging to the environment, and it has earned shale oil extraction a bad name.

IEP’s technology, on the other hand, performs the processing in situ, or onsite, by applying heat underground and extracting the shale oil and natural gas via wells that sit among the boreholes, leaving the formation intact.  The only byproducts are electricity that can be sold back to the grid, small amounts of clean water, and CO2.  It may seem odd to think of the electricity as a byproduct, but that’s the beauty of IEP’s approach.  If a single 1,000-foot stack contains 100 to 300 of Delphi’s 1.5 kW fuel cells, you’re talking 150 kW to 450 kW of baseload power per stack over a projected 5-year lifespan, which is no small thing when you consider the potential revenue.

IEP estimates that the gross capital and operating costs of a GFC installation will be less than $30 per barrel of shale oil when the revenue from the sale of electricity and surplus gases is taken into consideration.  This would give GFCs a significant cost advantage over the competition.  More significantly, IEP’s technology allegedly has an energy return on energy invested (EROEI) of 22:1, which would be a monumental improvement on the current best-in-class EROEI for oil shale, which is closer to 5:1.  The technology seems easy enough to replicate, but IEP has patented its idea, which should give it some protection from competitors.

The Real Cost

However, a couple of questions come to mind.  First, what will the actual installed cost of the systems be?  It could take thousands of fuel cells to develop a single formation.

Second, you have to run a fuel source out to the site, which is probably fairly remote, in order to run the GFC.  You also have to run transmission lines out to the site and build a substation in order to sell power back to the grid, and the fuel cells will only be running at that site for 5 years, so it’s a temporary installation.  How many utilities would be interested in doing that?  These questions must be addressed, and we won’t know how the economics and EROEI shake out until mid-2015, when the GFC is expected to be field-tested.  But this appears to be a very promising technology.

 

The Road to Clean Energy is Greased With Fossil Fuels

— August 14, 2013

In recent months, both the United Kingdom and Germany have initiated fossil fuel expansion plans in the face of coal and nuclear retirements during the next decade.  Although the development plans coincide with ambitious clean energy agendas, the respective governments’ decisive shifts in favor of fossil-based generation stand in direct contrast to their official decarbonization policies in accordance with EU’s Renewable Energy Directive.

Currently in the midst of a comprehensive Energy Market Reform (EMR) effort to spark investment in renewables, the U.K. government has doubled its shale reserve estimates and cut shale production’s tax rate by half.  In Germany, momentum has been building this year behind efforts to expand the nation’s coal fleet, with a number of new projects slated for development across the country.

In both cases, recent developments in oil and natural gas markets have played a decisive role with unpredictable consequences for renewable deployments.

Coffee and Tea

The interplay of oil and natural gas commodities is a funny business.  Although oil’s primary role is to power a massive, worldwide transportation network, traded globally, its fluctuating value serves as a proxy in electricity markets for everything from natural gas prices to power purchases agreements (PPAs).  Natural gas, for its part, is at once a climate change nuisance in its natural state – it is roughly 70 to 90 percent methane by volume, a greenhouse gas 21 times more potent than carbon dioxide – and a climate change boon for countries like the United States, seeking to decarbonize power production with ample supplies of relatively clean-burning natural gas, instead of coal.  It is also a commodity produced and consumed in relatively close proximity.

The indexing of natural gas prices to crude oil – or fixing the traded price of the former to the latter – has helped insulate high-priced renewables seeking a foothold in economies throughout Europe and Asia.  A function of European importers who needed a price reference for newly produced natural gas in the 1960s, the practice remains common through many European and Asian markets.

Although steeped in historical precedent, oil-gas indexing is not without its critics.  It “makes about as much sense as pegging the contract price for coffee supplies to tea prices, adjusted for caffeine content,” commented Michael Lynch in a recent Forbes article.

Tale of Two Countries

Dependent on natural gas imports from Russia, for now, Germany is handcuffed by this reality.  The indexing of natural gas to Brent crude, which has hovered mostly above $100 per barrel since the beginning of 2011 makes natural gas a high-priced commodity.  For a country that derives 22 percent of its total primary energy supply from natural gas, energy independence remains an elusive goal.

Even so, Germany has pursued an ambitious effort to become more self-reliant in energy.  Aided by an aggressive Feed-in-Tariff (FiT) and insulated from cheap natural gas, Germany has seen a rapid uptake of distributed renewables like solar, wind, and biogas.  With nuclear facilities shutting down in the wake of the Fukushima Daiichi accident, and renewables still unable to deliver the scale of capacity expansion needed, the country has been forced to double down on coal.

By virtue of historical circumstance, natural gas prices are not nearly as intertwined with international oil prices in the U.K. as they are in continental Europe.  Though the country is a few years behind the U.S. with respect to exploiting shale gas deposits, natural gas will figure heavily into the future U.K. generation mix.

In recognition of this reality, the U.K. government recently eliminated subsidies that, since its inception, would have been available to dedicated biopower under EMR.  Though biopower is one of the few renewable options that can supply baseload power – a stabilizing force in electricity markets – the U.K. government has always expressed reservations about the cost-benefits associated with dedicated electricity production from biomass.

The contrasting German and U.K. experiences muddle predictions for the future uptake of renewables.  While recent movements in the relative price of oil and natural gas have begun to upend long-held structure in the energy production sector, renewables remain both a beneficiary and a victim.

 

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