Navigant Research Blog

Going Small, Gas-to-Liquids Finds a Niche

— July 2, 2014

Typically, converting gaseous fuels like natural gas to liquids requires high upfront capital investment and substantial energy inputs to maintain operations and results in significant energy loss.  Despite these challenges, smaller-scale gas-to-liquid (GTL) deals have increased sharply of late.  They include a joint development project involving Waste Management, NRG Energy, Velocys, and Ventech to develop a platform than can convert landfill gas to renewable fuels and chemicals.

To date, GTL projects have been built in only the most extreme cases – where macroeconomic trends are especially favorable or when liquid fuels are unavailable (e.g., Germany during World War II and South Africa under apartheid, both of which relied on coal-to-liquid conversion).

These narrow circumstances explain why just five GTL facilities are in operation globally today, despite GTL technologies being proven commercially.  The most high-profile project, Shell’s Pearl Plant in Qatar, commissioned in 2011, cost a whopping $18 billion to construct, or about $8 per gallon of annual production capacity.  With such a high price tag, the project’s return on investment (ROI) hinges on a free supply of natural gas feedstock and a per-barrel oil price in excess of $40 (brent crude was trading at about $110 per barrel just before ISIS’ recent advance in Iraq).  Meanwhile, Shell recently cancelled another high-profile GTL project slated to be built in Louisiana, citing high estimated capital costs and market uncertainty regarding natural gas and petroleum product prices.  In short, commodity prices matter.

Modular Mode

In light of this limited market uptake, the recent surge of smaller-scale GTL projects is unexpected.  Targeting stranded or associated gas resources, however, these systems are able to skirt many of the macroeconomic barriers to the large-scale GTL projects described above.

Usually wasted or unused, stranded or associated gas presents a number of financial challenges to bring to market using conventional infrastructure.  In other words, the problem lies not in getting the gas out of the ground, but in finding a practical, economical, and efficient way of moving it to market.

In the case of stranded gas – gas fields located near local markets that are usually too small or in places too distant from industrialized markets – smaller-scale GTL processing can convert natural gas into a liquid product that is cheaper to transport.  In associated gas applications, where gas is either flared or injected into oilfields to maximize recovery, smaller-scale GTL can unlock new revenue streams.

Smaller and Safer

In both cases, smaller-scale GTL conversion has significant advantages over conventional infrastructure.  Shrinking the hardware allows greater tailoring of systems to the local resource supply and reduced construction costs.  The modularity of GTL systems allows capital to be allocated in phases, reducing risk to project investors.  And because the modules and reactors are designed only once and then manufactured many times, much of the plant can be standardized and shop-fabricated in skid-mounted modules.

The opportunity for smaller-scale GTL remains significant.  Stranded and associated gas is relatively abundant (estimated at 40%-60% of the world’s proven gas reserves).  One of the more exciting opportunities that has gained attention more recently is the pairing of frontend conversion technologies for processing abundantly available solid biomass and waste into synthetic gas (or syngas) which unlocks many more opportunities globally for smaller GTL platforms.  Navigant Research’s recently published Smart Waste report forecasts that annual revenue from municipal solid waste energy recovery will increase to $6.5 billion worldwide by 2023, due in part to the expansion of emerging technologies like small-scale GTL.

 

Russia-China Gas Deal Narrows Window for U.S. Exports

— May 30, 2014

Russia and China’s grand bargain on energy, a 30-year, $400 billion deal to pipe natural gas from Russia’s Far East to China, has prompted much commentary on the agreement’s potential to reshape global energy markets and tilt the balance of influence in Ukraine and, more broadly, in Europe.  The deal has “upped the ante for Europeans to diversify their gas imports away from Russia,” said Erica Downs of the Brookings Institution; it means producers of liquefied natural gas (LNG) “may face more competitive markets in Japan and South Korea, which together bought more than half of the world’s supply in 2013,” wrote Chou Hui Hong, a Singapore-based reporter for Bloomberg News; “the implications are potentially huge for Russia, for China and much of Asia, and also for Europe,” declared Keith Johnson, covering all the bases in Foreign Policy.

All the bases, that is, except one: the United States.  The shale gas revolution in the States has led natural gas producers to envision an export boom in which U.S. companies become key suppliers to East Asia while countering Russian influence by shipping large amounts of LNG to Europe.  President Obama said in 2012 that the U.S. is becoming “the Saudia Arabia of natural gas.”

Better Hurry

Indeed, U.S. petroleum exports reached 3.5 million barrels a day in 2013, roughly double the level of 5 years ago, according to the Energy Information Administration.  Proponents of increased LNG exports argue that the gas export boom will bring in billions in profits for American companies, create thousands of high-paying jobs, and reduce the influence of undesirable LNG suppliers, i.e., Vladimir Putin’s Russia.

All of that is, potentially, true.  But there are signals that, even before the Russo-Chinese gas deal, natural gas advocates were overstating the potential market.  And with China building pipelines to ship LNG across Central Asia, the market opportunity is dwindling fast.

The United States has been slow off the mark in building export capacity.  Thirty-one applications for LNG export licenses have been approved since 2011; only seven have been approved, six conditionally.

In 2012, on assignment for Fortune, I visited the Sabine Pass natural gas terminal on Texas’ Gulf Coast.  Built by Cheniere Energy in the 2000s as an import facility, the port had been retooled to load LNG on big tankers for export to Europe and Asia.  Cheniere is the only producer that has won full DOE approval to export gas; and the window for an export boom may already be closing.

The Shrinking Spread

U.S. supremacy in international gas markets depends largely on the wide spread between the cost of producing natural gas in this country and the prices that countries like Japan, South Korea, and Germany are accustomed to paying.  As Karim Rahemtulla, the chief investment strategist at Oil & Energy Daily, points out, that spread narrows rapidly once you liquefy the gas and ship it, via tanker, overseas.

Competition in the international gas markets is bound to heat up, and the United States may have already missed its opportunity for an LNG export bonanza.  Expanding pipelines, more export terminals, and better technology for liquefying and shipping natural gas will all help globalize the natural market, in the way the crude oil market is already globalized.  Already, the relatively low price that China will pay for Russian gas (around $350 per thousand cubic meters, analysts estimate) is putting downward pressure on higher prices for Japan and South Korea.

Earlier this month Dominion Resources won approval from the U.S. Federal Energy Regulatory Commission to build an LNG export facility at Cove Point on Maryland’s Chesapeake Bay.  The company said the $3.8 billion terminal could begin shipping gas as early as 2017.

That could be too late.

 

In Reinvention, TVA Wrestles with Uncertainty

— May 9, 2014

This week’s release of the Third National Climate Assessment – which demonstrates that the effects of climate change today are much more widespread, pervasive, and destructive than previously understood – and the decision by Stanford University to cleanse its endowment of $18 billion in investments in the coal industry have increased the pressure on U.S. utilities to reform their business models, restructure their fuel mixes toward cleaner fuels and away from coal, and embrace the distributed energy model that is gradually replacing the centralized grid.  Nowhere are those pressures more apparent than at the TVA Towers, the Knoxville, Tennessee headquarters of the Tennessee Valley Authority (TVA).

TVA is being forced to remake itself at a more rapid pace than other utilities, thanks to the settlement of a historic lawsuit filed by the state of North Carolina and the U.S. Environmental Protection Agency in 2011.  The agreement called for a drastic reduction in TVA’s coal-fired power generation capacity and a variety of clean-up measures at the remaining plants.  In essence, TVA – which is one of the nation’s largest operators of both coal and nuclear plants and is attempting to complete and fire up the second nuclear power reactor at its Watts Bar Plant in central Tennessee – is being shoved out of the business of burning coal.

Time to Go

In fact it is time, according to a new report from the conservative Heritage Foundation, for TVA to go the way of the Works Progress Administration and the Rural Electrification Administration – other New Deal federal agencies created to create jobs, spur economic development, and bring light and power to America in the depths of the Depression – and shut its doors.

Unique among U.S. utilities, TVA is a quasi-federal agency that was created with an explicit socioeconomic mission beyond the business of supplying electricity to its customers: to develop the Tennessee River into a navigable waterway, to bring prosperity to some of America’s least developed regions, and to be a steward of the region’s resources.

“The navigation waterway is built, though lightly used,” writes Ken Glozer, author of the Heritage report.  “Electricity is widely available, though rates are among the highest in the Southeast; and the people of Tennessee enjoy a good standard of living.  The most effective way to restore efficiency to the TVA system and to relieve federal taxpayers of a significant liability is to sell the Authority’s assets in a competitive auction.”

End of the Coal Era

Going fully private is hardly what TVA CEO Bill Johnson had in mind when he told shareholders and audience members at the Authority’s May 8 board meeting in Memphis that the 81-year-old organization is cutting expenses and refashioning its power generation business in order to meet the region’s power demands with rates below the U.S. average, while replacing coal with more renewable sources of power generation and instituting far-reaching conservation and efficiency measures.  TVA has already shut down its John Sevier coal plant near Rogersville, replacing it with a state-of-the-art combined cycle natural gas plant, and plans to shut down several more, including the massive Johnsonville plant, the largest coal plant in its fleet.

Johnson also said that TVA’s debt, which in recent years has edged closer to the $30 billion limit imposed by Congress, is coming down.  Debt reduction, he argues, will help the authority in its plans to open new co-generation plants that would use biomass in combination with coal to produce both heat and steam.  The co-generation project “is a perfect example of how our improved financial condition has put us in a condition to take the steps to do this,” said finance chairman Peter Mahurin at the board meeting.

The steps TVA is taking to remake itself for the 21st century are ambitious and could provide a model for other large utilities – unencumbered by TVA’s ties to the federal government, its complicated history, and its high debt load – to follow.  Whether they’ll be enough to enable the Authority to survive and prosper remains to be seen.

 

Waiting for the Methane Hydrates Boom

— November 20, 2013

Even as the heralded natural gas energy revolution is still gearing up, the natural gas vehicle industry may be looking ahead to the next revolution.  While shale gas is having a significant impact on U.S. energy economics, some in the natural gas truck and bus industry are already eyeing the potential that methane hydrates could secure natural gas as the energy source for transportation in the 21st century.

During the research for my upcoming report, Natural Gas Trucks and Buses, methane hydrates came up twice in conversations, which made me curious as to how real this prospect is.  Methane hydrate (also known as methane calthrate) is methane trapped inside a water molecule, so that the molecule is flammable.  Estimates for the quantity of methane available in methane hydrates vary widely, from 100,000 trillion cubic feet (tcf) to 100 million tcf of methane.  Worldwide methane consumption was 113 tcf in 2010, according to the U.S. Energy Information Administration.  As my colleague Sam Jaffe wrote in a recent blog, though, the methane hydrates revolution is far from a certainty due to environmental and economic concerns, as well as a lack of mining infrastructure.

The Next Revolution?

The Canadians, rich in shale gas, ended their research into methane hydrates this year, which makes the Japanese the leader in R&D on mining technologies.  In March of this year, Japan produced 120,000 cubic meters of gas from methane hydrates in a 6-day offshore test.  On October 31, the Japanese officially requested that the U.S. collaborate on developing mining technologies, with a target of production beginning in 2018 or 2019.

In terms of politics and energy consumption, 2018 seems like a long way off.  But natural gas power plants can take up to 3 years from design, approval, and construction to operation, and most vehicle manufacturers are already planning or actively working on 2017 model year vehicles.  That’s why methane hydrates are coming up in conversations now.

What isn’t clear is whether the research into methane hydrates mining can get political support before the shale gas revolution has run its course or before biomethane and coal seam gas become economically competitive.  Clearly, in Canada, the answer is no.  Now that methane hydrates are known to exist and have been proven technically minable, countries with the means and needs for new energy sources (Japan, Germany, South Korea, and perhaps even China) are likely to push ahead to improve the economics of this potential new revolution.  If methane hydrates can be recovered in an environmentally sustainable and economically viable way, they are unlikely to remain underwater for long.

 

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