A century ago, a single oilfield in east Texas met the vast majority of the United States’s petroleum needs. In those days, oil was primarily refined into kerosene or burned in a barely distilled form as bunker fuel in ships. Forty per cent of what was brought to the surface was discarded. Producers would have to develop new products and uses for the resource—gasoline, diesel, heating oil, asphalt, lubricants, petrochemicals and aviation fuel—before oil supplanted coal, wood and whale oil, the dominant energy sources of the day. Increased usefulness brought about black gold’s golden age. By the 1973 oil supply shock, petroleum provided 50% of the world’s energy; overall demand is much higher today, but oil still represents 35% of total demand.
Eric Marsh, head of EnCana Corp.’s Natural Gas Economy team, thinks another energy revolution is upon us—and once again, it starts in east Texas. In the early 2000s, junior exploration company Mitchell Energy and Development used newly available directional drilling rigs to plumb a slab of rock nearly a mile underground called the Barnett Shale. It had long tantalized geologists with its gas potential but to date had proven tough to crack. These brainy engineers working on the outskirts of Fort Worth, dubbed “mildcatters” by Texas Monthly magazine, then blew the layer up in 100-metre segments, one at a time, using bursts of water, sand and chemicals. Fracture stimulation of this sort had been experimented with, in both oil and gas wells, since the 1950s with mixed results. But by “fracking” horizontally in stages from a single drill hole and using sand to prop open the cracks, Mitchell now recovered unprecedented volumes of gas.
It was a muted revolution at first. Gas prices were probing new highs. The conventional wisdom was that North America, like Europe before it, was running out of gas. But in 2004, oil major Devon Energy bought Mitchell and the secrets of the Barnett began to leak out. Fracking techniques spread to shales in Arkansas, Pennsylvania and British Columbia, increasing supplies and depressing prices. Then, in late 2009, Exxon Mobil, the biggest of Big Oil companies, bought shale gas producer XTO Energy for US$41 billion. People were beginning to get a glimpse of how fracking shale would rock our world.
Those implications are now widely apparent. A Golden Age of Gas may be upon us, the International Energy Agency postulated in its 2011 Outlook release in June. It described a scenario whereby gas begins to replace coal and oil as a transportation and electricity-generating fuel and satisfies a dominant share of new demand. Assuming that takes place, gas will overtake coal as a source of world energy supply by 2030 and pull even with oil by 2035.
Will natural gas be the fuel that takes us beyond the petroleum era? A growing number of people are convinced it will. This past April, the United States Energy Information Agency released an estimate that fracking has effectively increased the volume of recoverable gas in the world six times over, to the point where it could satisfy current demand for 250 years—and that isn’t counting a number of countries including Russia where the necessary geological data were unavailable. EnCana’s Marsh thinks it will one day supply more than half humanity’s energy needs, up from 22.6% today. With high oil prices persistently poised to derail the global economy, with large economies like Germany and Japan swearing off nuclear in the wake of the Fukushima Daiichi disaster, with coal hampered by looming emissions caps, unexpectedly abundant gas seems poised to fill the energy void. But first, the IEA pointed out, it will take a US$8-trillion investment in gas supply infrastructure. Like the cagey Texas oilmen of a century ago, producers and their government allies must also engineer a massive conversion of big energy users, notably power plants, cars and trucks, to natural gas over perhaps 20 years. But first, the industry must prove shale gas extraction is even safe.
We already use gas to heat our homes and generate some power, but a golden age would involve greatly expanding its use. The easiest market for gas to conquer is electrical generation. Already, gas plants account for the lion’s share, 40%, of American electrical capacity. But that capacity is only used 30% to 40% of the time, meaning gas generates only a quarter of the electricity actually used. Historically, gas plants were reserved for peaking power—additional production for times of highest demand. Base load power, the residual power that has to be generated day-in, day-out, came primarily from burning coal, typically in a plant located right at a mine site owned by the power company. In this way, the utility controlled the cost of its raw material. Natural gas, which has to be bought on a volatile market, was considered unsuitable for load power production.
However the shale gale appears to have depressed gas prices for the foreseeable future, and gas producers are eager to lock into long-term supply contracts, making gas load power economically feasible for the first time. Shale has changed the old economics of oil and gas whereby increased demand could only be met with harder-to-get, costlier fuel. Energy research group IHS CERA calculates that fully one-half the U.S. shale resource—a 30-year supply at today’s rate of consumption—could be produced at today’s prices or less, meaning the market can accommodate a jump in demand without a corresponding price increase. Coal remains cheaper, but when you factor in the reduced capital cost (gas plants cost between a quarter and a third what coal plants of equivalent output do), the life-cycle costs point to gas, even in the absence of a price on carbon emissions.
This move to gas-fuelled base load power is already happening. In July, electrical utility Enmax Corp. started construction of the Shepard generating station in its hometown of Calgary. With a capacity of 800 megawatts, the plant will supply half the city’s electrical needs. The Shepard plant follows two smaller gas-fired plants Enmax brought online, in Crossfield, Alta., in 2009 and downtown Calgary this year. Currently Enmax still gets most of its power from coal-fired plants, but those power purchase agreements are due to expire in 2013 and 2020, when the generating plants will be at or near the end of their operating lives. Beyond that, the utility expects it will get most if not all its power from a combination of gas and wind.
Enmax made the decision to move away from coal when gas prices were still expensive, notes executive vice-president of generation and wholesale energy Dave Rehn. Gas had other advantages, including lower emissions, lower capital costs and the ability to locate the plant right where the customers are in Calgary since gas pipelines are everywhere, he explains. That removed any need to pay costly electrical transmission tolls, and allows Enmax to capture heat given off by the plant and use that to heat downtown buildings. Though it’s at the forefront in Canada, Enmax is not alone in its move to gas. A poll taken at a recent conference of American utility CEOs suggested almost all plan to build natural gas plants for their next generation of capacity. Anticipating this demand, the manufacturers of power plant equipment—Siemens, Mitsubishi, Hitachi, GE—are focusing their energies on coming out with new gas-fuelled systems.
Transportation will doubtless be a harder market for natural gas to crack. Lacking the density of liquid fuels, gas requires large tanks for the compressed fuel and even then has a more limited driving range than gasoline or diesel. For most of the past decade, in fact, the number of natural gas vehicles (NGVs) on North American roads has been declining. Canada was home to about 30,000 NGVs in 2002. Now there are fewer than half that many, in large part due to the worsening economics of natural gas as a fuel up to 2008.
That doesn’t deter Marsh. The transportation sector is “too big an opportunity not to work on,” he says, noting that the potential market for automobile fuels is greater than all the natural gas produced in North America today. Even NGVs’ 10% to 20% market penetration seen in Pakistan, Argentina, Brazil and Italy would mean serious growth. And today’s gasoline prices make natural gas a very compelling alternative. Traditionally, he says, oil and natural gas traded at a six-to-one ratio of cost per unit of energy. With gas at US$4 per mmBtu, “that would be equal to a $24 barrel of oil.”
Those fuel-price economics make sense not just for EnCana, which has converted 163 of its 1,700 vehicles and 15 of its drilling rigs to natural gas, but for larger fleet operators with no special interest in promoting gas. Waste Management Inc., North America’s largest commercial garbage hauler, now has 930 CNG (compressed natural gas) trucks among its 20,000 vehicles, and plans to introduce more as diesel trucks are retired.
Natural gas may soon make inroads with consumers as well. This fall, Honda Motor Co. is launching the natural-gas-powered Civic GX, hitherto available in just four states across the U.S. In the absence of natural gas fuel stations, these commuter cars are meant to be refuelled in your garage from your domestic gas line. A linchpin to consumer adoption of NGVs, Marsh acknowledges, is the availability of affordable compressors for home refuelling—something that suffered a setback with the 2009 bankruptcy of Toronto-based Fuelmaker, partly owned by Honda. Seven years earlier, Fuelmaker introduced a home fuelling system called Phill, priced from US$2,000 and up. There remain home compressors on the market, but at the more prohibitive price point of $5,000. However the high gasoline prices of the past year and increased acceptance of home-charged electric cars are helping condition consumers to adopt urban vehicles with limited range as a trade-off to escape the high cost of gasoline. Marsh envisions “bifuel” vehicles that run on natural gas for commuting but switch to gasoline for longer journeys. In terms of engineering, it would be simpler to design than existing gasoline-electric hybrids, since both fuels could be burned in the same engine.
Even if NGVs fail to catch on, there are other ways natural gas could end up powering our transportation. The proliferation of electric cars such as the Chevrolet Volt, enjoying a big-league marketing push this year, may be a back-door win for gas, in that that’s where much of the additional electrical generation required to keep their batteries charged is going to come from.
“When you’re in an oversupplied market like we’re in, you have to find new markets,” says Marsh. That’s what those Texas oilmen once did, and that’s what EnCana is trying to do today. The opportunity for the Calgary-based company, which produces about 5% of the gas in North America, is not so much to grow demand of a commodity, but to develop new business lines around these new applications. Further, for gas to become a globally traded commodity like oil will take a huge expansion of the infrastructure to ship it over oceans; hence EnCana is a 30% partner in Kitimat LNG, the closest to fruition of four liquefied-natural-gas export terminals proposed for Canada’s west coast, with a target date of 2015 for first shipment. Shell, meanwhile, is planning to build the world’s largest ship, the Prelude, to function as a floating LNG liquefaction terminal. The idea is to park the vessel atop submarine gas fields off the coast of Australia, liquefy the product and ship it to nearby Asian markets.
Grand as these visions sound, gas will never rise to dominance unless the industry can prove that shale extraction is safe in the first place. Responding to pressure from environmental opponents and fearful residents, shale-rich Quebec, France, New York and New Jersey have all imposed moratoriums on shale gas drilling pending further study of environmental and health impacts. Even Texas, the birthplace of shale fracking, recently passed a law requiring drillers to disclose the chemicals they use. “We are committed to making sure that it is done properly or it won’t be done at all,” Quebec Environment Minister Pierre Arcand said in calling a halt to new exploration.
Residents in some U.S. fracking locales have linked the practice to water contamination, including incidents of tapwater made flammable by the presence of methane. Fracking was the subject of a damning documentary, Gasland, and celebrities such as Mark Ruffalo, Ethan Hawke and Zoe Saldana have campaigned against it.
But so far there have been few scientific studies supporting the link between fracking and contamination, and nothing conclusive. One study out of Duke University found a higher-than-average presence of methane in water wells located close to fracking operations, but methane in groundwater can come from a variety of sources, including organic decomposition near the surface. Further, the Duke study did not detect fracking fluids in any of the wells tested.
In addition to fears of groundwater contamination, there are other issues such as the disposal of fracture fluids and simply the volume of water used by the activity. One 2010 drilling program by Apache Corp. near Fort Nelson, B.C., (described as “the world’s largest frack”) had to be halted when water withdrawals caused the level of nearby Two Island Lake to fall 15 centimetres.
More ambiguous is the debate around greenhouse-gas emissions. Switching to gas is, in the short term, the quickest and easiest way to reduce GHG emissions globally. Burning gas emits just 40% of the CO2 as deriving the same unit of energy from coal, and between 65% and 75% the emissions of oil. But fracking opponents claim that, though natural gas is considered the greenest of fossil fuels, shale extraction is significantly more carbon-intensive than conventional production and may result in the release of large quantities of methane, itself a greenhouse gas. Cheap gas, others warn, will hamper investment in renewable energy.
Still, the largest environmental NGOs appear ambivalent about fracking. The Sierra Club turned down a motion by chapters in New York and Pennsylvania to call for a nationwide ban. The largest NGOs opposed to fracking, such as the Natural Resources Defense Council, are not calling for a permanent ban, but tighter regulation, removal of legal loopholes and selective bans in sensitive areas.
It is unlikely, then, that environmental concerns will halt shale gas development. Most of the potential causes of groundwater contamination, such as fluid or gases travelling along well bores, are avoidable and there are ways to conserve fresh water. Industry organizations such as the Canadian Association of Petroleum Producers have adopted voluntary codes meant to improve environmental stewardship and transparency. “There are a number of studies underway that are going to clarify the environmental impacts around shale that will hopefully put to rest a number of questions,” says Mary Barcella, IHS CERA’s director of global gas. “At the moment, there is almost a hysteria around it.”
A viewpoint common in the energy industry, and articulated in a recent report by Calgary-based Altacorp Capital Inc., The Energy Reality, is that the transition to renewable energy will be much more expensive and take much longer than is now imagined. Comparing the capital and operating costs of various forms of energy—even factoring in US$50 a tonne for carbon emissions (a higher rate than is currently levied by any North American state or province)—natural gas comes out as a clear winner. “As a result, this fuel will play a central role in meeting energy demand in the coming decades,” the report said.
While questions linger about the environmental impact of shale gas, the answers are likely to govern not whether we extract it, but how. Purely on existing economics, the role of gas in the global energy portfolio will grow. If combined with a political consensus in key consuming countries, it will indeed become this century’s oil.