Where to Go?

Some say transportation should be a market grail for natural gas, while others aren't so sure

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie Brown
In his best-selling 1958 book The Affluent Society, Canadian-born economist John Kenneth Galbraith popularized the concept of conventional wisdom. “It will be convenient to have a name for the ideas which are esteemed at any time for their acceptability, and it should be a term that emphasizes this predictability,” he wrote. “I shall refer to these ideas henceforth as the conventional wisdom.” The problem with conventional wisdom is that it isn’t always true. Contrarians are often right.

Price Bull
It’s worth keeping that truism in mind as we develop the case for building new natural gas markets in North America. In a recent comment, author and analyst Peter Tertzakian argued that the rapid decline in drilling for natural gas across North America raises the question of whether natural gas is likely to continue to be in a serious state of oversupply. Tertzakian notes that for the first time in 15 years half of the US drilling fleet is drilling for oil, compared to less than 20% of rigs for the last decade. Such a dramatic decline in drilling almost certainly suggests that production levels will decline, he suggests.

He then moves on to the killer argument: “Let’s say (gas) production starts retreating in earnest this year and natural gas prices rise back to some fictional level like six dollars per MCF. Notionally, the (conventional) wisdom goes that producers will dispatch more rigs to ramp up production and thus clobber prices again. There is a problem with this line of thinking: why would producers do that when more money is to be made elsewhere?” He suggests that as long as oil is valued at more than four times the value of gas (energy equivalency basis), there is little motivation for the industry to shift toward more gas drilling. The result? Declining supply and still higher gas prices until a cost-reward rebalance restores aggressive natural gas drilling.

Supply Bull
Since Tertzakian is such an unusual voice in the wilderness, the balance of this article assumes that the conventional wisdom is true. Gas supplies are likely to continue to be plentiful, and there will continue to be a need to develop new markets. One of the most interesting advocates of greater markets is the legendary oilman T. Boone Pickens, who says he has invested $70 million in developing and promoting The Pickens Plan.

An 83-year-old geologist who received his degree in geology in 1951, as a young man the Texas-born Pickens spent a decade in Calgary. In a broadcast interview, he said he opened an office in Calgary in 1959, and lived in the province with his family in the 1960s. After moving back to the United States, he made a multibillion-dollar fortune in exploration and development and, much more publicly, as a corporate raider. His current passion is to promote the Pickens Plan.

“For 40 years the United States has had no energy plan,” he explained. “We’ve just been drifting. Just drifting means you are just importing more oil from the Middle East, countries that the state department recommends we not visit.”

Pickens is adamant that the United States should reduce its dependency on overseas oil, and he believes that renewables like wind and solar aren’t viable anymore because of cheap gas.

“Natural gas is the only thing we have that can replace non-North American foreign oil. We import 5 million barrels from the Mid East. That’s the oil I want to replace with gas. If you had 8 million 18-wheelers (in the US trucking fleet fuelled with natural gas), that would cut OPEC imports in half.” He added, “If the US administration announced that from now on all new government vehicles would use domestic fuel that would be a powerful message to send to the world.”

“This is a security issue for me. I don’t want to be dependent on the enemy for energy,” he said. Until gas prices cratered, Pickens was a strong advocate of wind energy, and he was leading an effort to finance a multi-billion dollar wind farm in the Texas Panhandle. He uses this fact to support his green credentials. “Natural gas is 30% cleaner than diesel. We have the cleaner, cheaper, abundant fuel here, and it will replace the dirty fuel from the Mid-East.”

Pickens is also an advocate of continental fuel switching – in particular, substituting natural gas for coal in power generation facilities.

For many years most commentators have believed that the United States could never become self-sufficient in energy, Pickens said, but “things have changed. We have so much natural gas – the US has a 100 years supply, and the Canadians have a lot up in Horn River, for example, and the Canadians have a lot of oilsands (oil). Let’s use that to make North America energy self-sufficient.” He added, “When people say to me, ‘Hey, Pickens, I don’t like your plan!’ I say ‘Fine, what’s your plan? If you don’t have a plan your plan is to import more oil from the Middle East.’”

Not many oilmen are as colourful as T. Boone Pickens or as motivated by worries about enemies in the Middle East. However, there are a lot of other natural gas supply bulls.

Exxon-Mobil, for example, demonstrated its belief by plunking down $31 billion for gas-focused XTO Energy a year and a half ago. A company vice president, William Colton, recently told the New York Times that “If there is any kind of major trend, we think it’s going to be a shift toward more natural gas.” He added that “Natural gas is available. It’s the most efficient way to generate massive power. It’s affordable. We already have gas infrastructure in place. From a CO2 emissions standpoint, it’s 60 per cent cleaner than coal, and (the U.S. has) 100 years of supply.”

Agency Bull
America’s Energy Information Agency, whose job is to forecast supply and demand based on best-guess current trends, doesn’t appear to see much of a plan to promote greater use of natural gas anywhere in the future. According to the early-bird version of the 2011 forecast, “Non-hydro renewables and natural gas are the fastest growing fuels used to generate electricity, but coal remains the dominant energy source for electricity generation because of continued reliance on existing coal-fired plants” well into the foreseeable future.

According to the EIA, the agency has revised its methodology for gas prices “to better reflect a lessening of the influence of oil prices on natural gas prices, in part because of the increase in shale gas supply and improvements in natural gas extraction technologies.”

Of course, as Peter Tertzakian argues at the beginning of this article, it might be a mug’s game to discount energy equivalency too deeply when you are calculating the relative values of oil and gas.

Whatever methodology the organization uses, the EIA does forecast an increase in North America’s natural gas demand, but its estimates seem paltry compared to the aggressive development that T Boone Pickens, for example, is promoting.

The agency forecasts a strong near-term increasing demand because of a “strong recovery in near-term industrial production, growth in combined heat and power, and relatively low natural gas prices.” Look farther out into the future, however, and the agency’s forecasters are more circumspect than the gas supply bulls. “U.S. natural gas consumption rises 16 percent from 22.7 trillion cubic feet in 2009,” they intone, “to 26.5 trillion cubic feet in 2035.”

Such a small increase in forecast demand – 16% over 25 years – suggests that the EIA’s gas supply bulls aren’t as optimistic as Pickens; he might complain that they “don’t have a plan.” You could equally argue that there are contrarians among them.

The Road to Success

Canada's shale gas producers are paving the way to successful exploitation of a massive resource

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie-Brown

The shale gas revolution has turned the natural gas business upside down at a pace no one could ever have imagined. There is now tough competition in North American gas markets and the legendary successes of junior oil companies in the province—a crowning achievement of western Canada’s way of doing business –is in decline. Juniors can’t be really small anymore because they now generally require a lot of start-up capital. Crashing gas prices have put some into receivership, forced many to merge and forced all to change.

Perhaps Winter Petroleum—a small, privately held company—typifies the situation for little gas producers. With operations in the northwest corner of Alberta, the company got its name because its properties can only be drilled during the winter, according to president Duncan McCowan, a geologist.

“Winter drilling requires a lot of equipment and it’s expensive,” he says, “and our production is remote from major markets. Because of cost structure and transportation, we’re finding it tough to compete in U.S. markets.”

His company hasn’t let any employees go, however. “We are still slightly profitable, but we can’t grow. We’ve cut back our capital spending completely and many of our operational items too. (Dry gas) activity in that part of the province is at a standstill.”

McCowan points to a decline in the number of junior companies, partly through bankruptcies like that of Drake Energy, which was a neighbour to his own gas company, Winter Pete.

“Today you need pretty serious money for a start-up. A few million dollars won’t go very far anymore, because the new technologies we’re using involve horizontal wells and multi-stage fraccing. It used to be you could drill a well for a couple hundred thousand dollars. Today it takes millions, and financing groups are putting together a fund of, say, $35 to $70 million and then putting an experienced management team in charge. There are fewer mom and pop petroleum companies around.”

Peter Tertzakian of ARC Financial Corp. says two other important trends favour consolidation and larger companies.

“Bulking up to get costs down helps you deal with lower prices. It gives you economies of scale. A related factor is that a lot of companies are migrating to horizontal drilling and completion strategies, but that’s very expensive.”

On average those wells cost $4.5 million, and there have been many wells that cost $8 million or more. “By drilling fewer wells that are more expensive each, you need more backbone – you need to be a bigger company.”

The companies most at risk are those that are heavily leveraged and biased to natural gas, but many of the smaller ones are successfully implementing what he calls “revitalization strategies: shifting their focus to liquids-rich gas, or even prospecting for oil. A small amount of liquids in the gas stream can make a big difference” since it often has a greater market value than oil.

Compare that situation to the one announced in February, when PetroChina made a huge counter-intuitive deal with EnCana Corp. While other major Asian investments in the Canadian petroleum industry have mostly gone into the oilsands, Petro-China put its money into shale gas. The two companies announced that they had inked a $5.4 billion deal by which they would become equal partners in EnCana’s Cutbank Ridge gas field in British Columbia. This investment, which surpasses Sinopec Corp.’s $4.65 billion acquisition of ConocoPhillips’ stake in Syncrude last year, is Asia’s largest single bet on North America’s energy sector.

According to EnCana spokesman Alan Boras, the focus of this effort is natural gas, not the associated gas liquids.

“We are always looking for ways to maximize the value of our assets, and natural gas liquids extraction is an important part of that process,” he says. “However, that is not our major focus.”

Since the company does not see natural gas prices above $6.63 per thousand cubic feet in the foreseeable future (2021), EnCana clearly is basing its business plan on something other than an upward move in North American gas prices.

One of those ideas is low-cost production. According to Boras, “In the Montney, where we have done the deal with PetroChina, our wellhead cost is about $3.15 (per thousand cubic feet).”

The deal will enable the Chinese to “get an early return on their investment, and then take the technology back to China to use it there. That certainly is part of what they’re thinking. The Chinese have recently talked openly about their need to increase domestic gas use.”

In addition to low-cost production, new pipe in a region already riddled with infrastructure could lower future transportation costs. This is the significance of the National Energy Board’s recent approval of TransCanada Corp.’s plan to build a $310 million pipeline to connect British Columbia’s Horn River shale gas region to its Alberta mainline system.

Ascendancy?
While the gas industry isn’t exactly in the ascendant, some trends suggest that ascendancy might not be far off. This isn’t readily apparent, since shale gas has backed Canadian producers out of traditional U.S. markets and driven down prices.

Low prices have made much of Canada’s conventional gas uneconomic in distant U.S. markets, and many producers are in trouble. In recent years the only major commodity to decline in price and stay there, natural gas has mostly defied winter demand for heat and summer demand for air conditioning.

The price collapse is forcing the industry to dramatically restructure, clouding the outlook. Such legacy assets as Canada’s Arctic gas fields look increasingly like white elephants: the likelihood of a pipeline from north to south is slipping ever farther into the future.

According to Robin Mann, president of AJM Petroleum Consulting, “Because of the development of shale gas formations like Montney and Horn River and others with great potential right next to infrastructure and pipelines, and with our existing conventional gas and our exports to the United States going down daily, we have more than enough (gas) for our own (use) so why is it important to build these pipelines? Why are we worrying about anything north of Alberta and B.C.?”

Consumers are happy with lower prices. Companies are not, however, and neither is the government of Alberta—now into its fifth consecutive year of deficit budgets.

One Alberta politician with ideas on the issue is Wildrose Alliance leader Danielle Smith, who doesn’t have to worry about balancing this year’s provincial budget. She sees the collapse in gas prices as an opportunity.

“There is so much we can do now to increase demand: fuel switching, the Pickens Plan (to increase gas use in automotive transport) in the United States, increasing use of gas for power generation.”

She even talks about installing modern-day gas-fired Stirling engines in our homes, to generate both heat and power. “If we do these things, consumers win. So does the environment and so do gas producers.”

In a way, those simple ideas describe a path that could bring the industry out of its funk. They are also consistent with much of what the industry is already doing in response to a rapidly changing business environment.

One industry response has been to reduce natural gas drilling--at this writing, at a one-year low. Companies are focusing instead on drilling for oil. According to ARC Financial’s Tertzakian, “this capital migration continues to be a positive leading indicator for natural gas price recovery.”

The industry is also responding to low prices with rapid adaptation of technology. It is cutting costs, seeking profitable niches and developing better markets. In addition, consumers are responding to the attractive price of natural gas, and policymakers are seeing it as a low-carbon alternative to other fuels.

And North America’s dominance in shale gas development makes it for the first time a potential large-scale manufacturer of liquids made from natural gas.

Gas-to-liquids
The gas-to-liquids concept is most evident in the billion-dollar deal Talisman Energy struck late last year with Sasol, the South African petrochemicals giant. The deal involved selling a 50 per cent interest in Talisman’s Farrell Creek shale gas properties in British Columbia. Eventually, the partnership could develop a plant using Sasol’s gas-to-liquids technology to turn the gas into a desirable liquid fuel. This is proven technology: Shell, for example, is constructing a $6 billion gas-to-liquids project in Qatar, the tiny Middle Eastern country with 15 per cent of the world’s proved natural gas reserves.

Another way to solve the stranded gas problem is to create liquefaction facilities for natural gas exports. When finished, the $3 billion Kitimat LNG project will become another face in the global LNG market—competing with, for example, Qatar.

According to Rosemary Boulton, the founding president of Kitimat LNG, “we’re experiencing a bigger gas bubble than we have seen in western Canada for 20 years, and this makes (LNG exports) a particularly viable proposition. We need to develop LNG to meet the needs of gas markets other than those in the U.S.”

Apache Corporation and EOG Resources obviously agree, since in December they bought out her start-up company—after it had received development approvals—and Canadian gas giant Encana Corp. came onboard with a 30 per cent interest this past March.

Countries like India and China will eventually begin developing their own shale gas resources but at present “Japan and Korea are the world’s biggest importers of natural gas,” says Boulton, “and they have no indigenous supply.”

She adds that “there are a number of ways you can write a price contract, and one of them is based on the price of WTI. That’s a pretty good price for exporters. For importers, it’s a lot better than a contract based on the price of Brent (North Sea) oil. Markets in Asia price natural gas relative to the price of oil, so that could be very attractive.”

Bill Gwozd, a vice president of Calgary-based Ziff Energy Services, agrees. “If you have an Asian market that’s prepared to pay (an LNG) price that’s linked to oil, we think (shale gas production) can surge.”

Boulton sees room for expansion of Canada’s international LNG business. “The Kitimat project is approved for five metric tonnes or 700 million cubic feet per day. The pipeline will be capable of supporting a much bigger project—doubling (project capacity) is certainly viable.”

She doesn’t see a lot of LNG shipments leaving from B.C.’s Lower Mainland, however. “Projects are all about location. I see a lot of objections to a project (there) because of the nature of some communities on the Left Coast.”

Stakeholder engagement
A year ago, American filmmaker Josh Fox released a film called Gasland, which purported to document the dangers of hydraulic fracturing for shale gas. One landowner after another talked about the dangers of shale gas to their health, and some spectacular footage showed a man setting water from his kitchen tap alight – the result, he said, of shale gas polluting his water well.

Ziff Energy’s Bill Gwozd is sceptical. While he acknowledges that the consumption of large amounts of water for fraccing can be an environmental problem in areas where water is in short supply, he’s sceptical about the rest. “Shale gas and ground water are peanut butter and oil,” he says. “They don’t touch each other.

There are a lot of people who want to talk about shale gas polluting groundwater but it just isn’t going to happen.”

He points out that the geological zones which hold groundwater and shale gas can be literally thousands of feet apart, and that dirt and rock under pressure are anything but porous. “So how could deep zones of shale gas pollute groundwater, which is maybe 1500 metres up?”

“You’ve got to believe that the answer is in the details,” he says. “A lot of people complain about shale gas development without bothering to understand the technical issue. When you get into that conversation, they have to come to the conclusion that there is no problem here.”

Well, not entirely. In March Québec’s environment minister, Pierre Arcand, said the government didn’t have enough scientific information about hydraulic fracturing to sanction its further use. Until his department completed its research into what had become a heated public issue, the government imposed a drilling moratorium on Québec’s promising Utica shales.

Ziff’s Gwozd has a kind of conspiracy theory respecting public concern about shale gas. “Who’s driving the environmental objections?” he asks, rhetorically, then offers his own answer: “Anybody (with an interest in) conventional gas, in LNG, in coal, in energy alternatives. If you complain about it, you make it an issue. (To say these worries are based on science) is like the fox telling the bird he doesn’t want to cook it for turkey day.”

Enter Lane Wells, the principal at head•stock, a public consultation firm which specializes in aboriginal communities. Wells describes effective stakeholder engagement as involving “thoughtful, non-adversarial and respectful exchanges of information. Listening to stakeholders is important. Responding to what you have heard is critical.” Stakeholder engagement is becoming increasingly crucial if you want public policies that give you the right just to develop shale gas.

Changing Policy
Public policy is becoming increasingly important in other ways, too. For example, the Obama administration is now behind a drive to make natural gas the fuel of choice in as many energy-consuming applications as possible, with an emphasis on switching coal-fired power plants to gas.

Senior Democrats in Congress are getting behind the stuff, portraying it as an alternative fuel for transportation that can serve as a stopgap until renewable sources of energy, like solar and wind power, become economical on a broad scale.

Reflecting this policy, last year Rahm Emanuel—a congressman and formerly President Barack Obama’s chief of staff—introduced legislation which would have offered tax credits to both gas producers and consumers. The legislation died with last fall’s election, which unceremoniously turfed Emanuel and other Democrats from the House.

The promotion of natural gas as a fuel is popular within the industry also. The New York Times cites William M. Colton, ExxonMobil’s vice president for corporate strategic planning, as a serious natural gas enthusiast.

“If there is any kind of major trend, we think it’s going to be a shift toward more natural gas. Natural gas is available. It’s the most efficient way to generate massive power. It’s affordable. We already have gas infrastructure in place. From a CO2 emissions standpoint, it’s 60 per cent cleaner than coal, and (the U.S. has) 100 years of supply.”

As these issues get resolved, a leaner and meaner industry using advanced technologies and far more capital is emerging. The industry is opening its collective eyes to a brave new world of natural gas—one in which surplus supplies are convulsing the sector in many ways.

“Our intent is to tough it out,” says Winter Petroleum’s Duncan McCowan. “So we’re doing creative things to cut costs—jointly handling gas with our neighbours, for example. We’re optimistic about our geology—the horizontal potential is huge, but we couldn’t justify (horizontal drilling) in this price environment. Sure, we’re pessimistic about gas prices, but we know they’re going to turn. We don’t know when, but when they do we think it’s going to be pretty quick.”

A sustainable future

Effectively marketing Canada's vast unconventional gas resources can help ensure global sustainability

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie-Brown
If you want to understand how important unconventional gas has become, consider a couple of facts from EnCana – one of North America’s premier gas-producing companies.

According to company spokesman Alan Boras, in 2010 “we replaced 250 percent of our production. We (now) have14.3 tcf of proved reserves.” Of course, much of the company’s new reserves have come from its aggressive shale gas development. But consider this: “Coalbed methane is also an important part of our production – about 10 percent.”

EnCana’s numbers illustrate the remarkable success of the unconventional gas narrative. The big kid on the block is shale gas, but other sources like coal bed methane and tight gas are also important parts of the mix. Unless market conditions somehow kill the development of new supply, gas will remain plentiful and affordable for a long time to come.

This prospect provides Canada’s petroleum sector with a number of opportunities. One is the development of LNG capacity. Another is to use the fuel as a cheap input for oilsands development. A third is to go into shaley formations in the quest for NGLs and other valuable light liquids. The fourth is for oilsands producers to develop both gas and NGLs for financial hedging. Let’s look at these in turn.

LNG
Even though the federal government has given Cabinet approval for Arctic pipeline development, many people in the oilpatch are skeptical that development will begin soon. Put another way, such legacy assets as Canada’s arctic gas fields look increasingly like white elephants.
For example, Robin Mann, president of AJM petroleum consultants puts the issues in a complex question. “Because of the development of shale gas formations like (BC’s) Montney and Horn River and others with great potential right next to infrastructure and pipelines, and with our existing conventional gas and our exports to the United States going down daily, we have more than enough (gas) for our own (use) so why is it important to build these pipelines? Why are we worrying about anything north of Alberta and BC?”

He adds that the costs of the northern pipeline keep going up. “Maybe the best way is to develop LNG facilities in the north, but what will the economics of that kind of project be? Will the price of (Arctic) LNG justify building facilities up there?”

Bill Gwozd, a vice president of Ziff Energy, is much more sanguine about arctic gas. His firm’s model suggests there will be a North American market for Arctic gas beginning in the 2020s, “so it’s important to get ready now to activate those pipelines,” which will take a long time to build and commission.

The need for Arctic gas in North America 15 years from now doesn’t exclude the prospect of beginning now to develop overseas exports, however. In fact, three big and successful companies – Apache, EOG and EnCana – are betting good money that they can make a serious buck out of the Kitimat LNG Project. According to Gwozd, the chances of winning that bet are pretty good. “World-wide, LNG is maybe 10 percent of supply. There’s plenty of room to grow it.”

According to the Kitimat LNG Project’s founding president Rosemary Boulton, “the development of shale gas has developed a gas bubble that’s especially big in Canada. (For conventional gas) it’s worse than anything we’ve seen in a very long time. That makes LNG development more important now than ever.” She adds that “Shale gas is basically a technology play. The industry has found ways to get it gas that we knew was there before, but couldn’t develop. And the better companies are finding ways to producing more efficiently. Efficiency and technology translate in a fairly linear way to a decrease in cost.”

“These projects are all about location,” she adds. “You really have to have a supportive community to make them happen. First Nations and other communities along the pipeline route and around Kitimat were very supportive of the idea of having this project there.” Because the company was able to develop this support under her leadership, both the pipeline and the terminal had received regulatory approvals before the new owners acquired the project.

The Athabasca Oil Sands Story
In a rapidly evolving industry, companies are finding imaginative ways to develop natural gas plays. One of the most interesting examples is Athabasca oil Sands Corp., which has become well known for several years as an oilsands producer wannabee. Through a series of summertime raids at Alberta land sales, in 2006-2007 the company became the single biggest landowner in the oilsands sector – a position it held until the Suncor/PetroCanada merger. But oilsands development is a long-term proposal, and after farming out some of its land to PetroChina, the company had cash in the bank but no cash flow in prospect until its first in situ project comes to life next year.

So what did the company do? Still holding a very large oilsands land position, the company acquired more than a million acres in northwestern Alberta’s gassy Deep Basin. “This is an excellent way for Athabasca to use its cash until needed for our oil sands development,” according to president and CEO Sveinung Svarte. “This area offers the potential for a very short pay-back time and we plan to reinvest that quick return in the oilsands.”

Athabasca’s exploration strategy is to look for liquids and light oil in a gas-prone basin. The company will do this by drilling into Deep Basin formations, where it believes liquids are likely to be found and easily developed. The Athabasca story is almost a reverse image of the breakup of EnCana into pure play companies. According to Svarte, within his company the synergies of diversifying its land position are great. His geoscience and drilling teams can work in oilsands or tight sands with equal dexterity.

More importantly, perhaps, iversification will hedge the company as its oilsands projects begin coming on stream. If diluent prices are high and bitumen prices low, having diluent production of its own will help make that problem right. Of course, the sector in general uses a lot of natural gas – to supply heat for production and upgrading operations, to produce hydrogen for upgrading, and to generate electricity. Companies with gas production could find themselves well hedged if gas prices rise. As Svarte puts it, “we expect gas to be almost a free by-product of our Deep Basin development, so this hedge is well-priced.”

whatIf?
With the help of an Ottawa-based thinktank called whatIf? Technologies, Alberta’s former ADM for Oil, Bob Taylor, thinks a forecasting tool he helped develop could enable policy-makers to better feel, touch and imagine Canada’s possible energy futures. According to Taylor, the recent surge in gas supply reflects a pattern that has been continually recurring in Canada for a century: “Too much gas; too little price.”

Part of his solution to the dilemma this creates was a computer model that could deal with supply and demand without factoring in price. Economists would call that heresy; Taylor calls it “dynamic and robust.” Using numbers the Canadian Society for Unconventional Gas generated using the whatIf? model, he added that the potential ranges of recoverable resource range from a conservative case of 636tcf to an optimistic case of about 1400 tcf.

Those are extraordinary numbers, but such energy wealth won’t be developed without trials. “My worry is that much of this unconventional gas potential remains unproved. For that reason I recommend joint government-industry efforts,” according to Taylor. For political reasons and because of local worries, he adds, it “may not be recoverable in places like Eastern Quebec and offshore BC.” While these are serious concerns, he believes they can be resolved – “but it will require leadership and action.”

A lot is riding on the outcome. If the technical and environmental issues are solved, Taylor thinks Canada’s plentiful supplies of unconventional gas “can be a contributor to helping the world achieve 9 billion sustainable lifestyles by 2050.”

LNG Trumped

Image via Wikipedia

The burst of enthusiasm for shale gas could put LNG on the sidelines of global gas trade

This article appears in the October 2010 issue of Oilweek

By Peter McKenzie-Brown

If you want to understand the performance of global natural gas markets in the next few years, think hockey. On one side the team captain is liquefied natural gas (LNG); on the other natural gas from shale reservoirs (“shale gas”).

The matches are serious, but they are also friendly. Each side is a team of rivals. The squads frequently swap players in and out, but they can play nail-biting games.

Robin Mann’s description of an annual CBM conference in Asia calls the game during two days of play. The first day of the Singapore conference, the president of AJM Petroleum Consultants says, the dominant theme was that “if there is a lot of shale gas development in India, Europe and China, there will be no need for much LNG project development.”

Shale Gas one; LNG zip.

On the second day, however, “the speakers suggested that new LNG projects will be needed no matter how much shale gas is developed in those countries. LNG development might not be as dynamic as people had thought it would be, but the projects now built or on the books to be built will remain viable.”

Game tied.

He cautions, though, that “In the end price will be the deciding factor.” Of course, everything from geopolitics to economics can influence price. This is the recurring theme in the competition between LNG and shale gas.
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Three Sources of Gas
From the perspective of North American producers, the future of three gas sources (not two) is of interest. The first is the wild success of shale gas production in the US and Canada. The shale gas revolution, as it is called, is largely the result of rapid innovation in such down-hole technologies as horizontal drilling, better bit design, coil tubing, down-hole motors, geo-steering, microseismic, measurement-while-drilling tools and more powerful fraccing systems. It has truly been a revolutionary development.

The second is the evolution of a global market for liquefied natural gas. This development has been decades in the making, and it has eliminated the need for pipelines to tie stranded gas into the world’s industrial markets. To cite the extreme example, Qatar is developing liquefaction facilities for an offshore reservoir with more than a quadrillion cubic feet of proved reserves, and it will be able to deliver that gas around the world for a century or more.
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The gas industry’s third area of interest lies in the huge conventional gas reserves in Alaska and the Northwest Territories. While companies are proposing expensive pipeline systems to deliver those resources to southern markets, Mann doubts that those proposals will go ahead in the foreseeable future. “Because of the development of shale gas formations like the Montney and Horn River and other with great potential right next to infrastructure and right next to pipelines, and with our existing conventional gas and our exports to the United States going down daily, we have more than enough (gas) for our own (use) so why is it important to build these pipelines? Why are we worrying about anything north of Alberta and BC?” asks Mann.

“Their costs keep going up and up and up, and economics will trump any national sovereignty argument for the Canadian pipeline. Maybe the best way is to develop LNG facilities in the north, but what will the economics of that kind of project be? Will the price of LNG justify building facilities up there? Certainly at the Singapore conference there was no strong feeling that there would be much in the way of LNG exports from North America, apart from a few small projects” like the proposed LNG terminal in Kitimat, BC. The only really positive argument for developing LNG facilities is that the many existing receiver terminals in the world offer a lot of flexibility. Given a Northwest Passage free of ice, you could take Arctic LNG anywhere – if the price were right.
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Arctic Gas Pipelines: benched.
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International sketches
While Robin Mann acknowledges the large potential for shale gas development in Asia, especially in China and India, he is sceptical that this will happen in the near term. “North America’s shale gas sector is advanced, it’s more of a mature industry” he says, sketching out the situation around the world. “Europe is in its infancy. In Asia it isn’t even that far – it’s in its beginning stages. People have barely gone beyond looking at resource potential. The idea of unconventional gas in Australia, China, India and Indonesia is still CBM” (coal bed methane) – a resource the North American industry is not heavily investing in anymore. “Europe is more interested in shale gas because they don’t have much CBM.”

One problem those countries face in developing a shale gas industry is “getting the hardware needed to properly develop the resource – getting the right equipment to the right spot and (having) the expertise and manpower to get things developed. That’s why CBM is still on the books in those regions. To manage in the CBM world you don’t need (heavy-duty) frac equipment or (specialized) manpower.”

Here is the kind of problem he is talking about. Huge fraccing jobs for shale gas development in north-eastern B.C. require a great deal of logistical support. Each horizontal hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. To take on one such project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks. This equipment isn’t widely available outside North America, and there are gas-bearing shales around the world that are remote from the kind of sand quarries needed.

Moreover, a great deal of water is required. While the water commonly comes from deep formations, a typical shale gas fraccing job requires a large water storage pit in addition to a string of high-volume steel tanks. According to Dave Russum, an AJM vice president who also attended the Singapore conference, “in India and Australia they are drilling their first holes into shale just to gather information. They aren’t even into pilot projects yet.” Given those realities, Mann concludes that shale gas will not have a large impact on LNG development – at least not initially
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Geopolitics and the local community
As a domestic source of supply, shale gas is an attractive alternative to imports. For the United States, which has huge trade deficits, it slows down the haemorrhage of US dollars. For Europe it offers a geopolitically smart alternative to Russian supply. Also, governments want this kind of development because it contributes to security of supply
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In recent years Russia has turned off the taps a couple of times because of disputes with Ukraine over payment. As collateral damage, countries in the European Union were temporarily cut off, too. It is therefore ironic that the best shale gas prospects in the European Union are in the north – especially Poland, Ukraine’s neighbour. In northern Europe, according to Mann, “you can get access to enough land to make a viable shale gas project.” In more developed and densely populated southern parts of the union, this is much harder.

As Europe develops shale gas, geopolitics is again likely to enter the fray compliments of the Russian bear. “Are the Russians just going to sit by and let Poland and northern Europe develop natural gas so they can turn off the taps from Russia?” asks Mann. “I don’t think so. They could retaliate with price, and make shale gas uneconomic.”

So could LNG producers. In fact, rather than shale gas driving LNG out of global markets, the exact opposite could take place, with LNG putting the screws to shale gas development irrespective of its geopolitical and trade balance advantages. Qatar, you will recall, has huge reserves that it can liquefy and deliver cheaply, causing international gas prices to crater and rendering some shale gas projects uneconomic.

Yemen and other exporters could do the same. According to Dave Russum, “It wouldn’t take much of a gas surplus on the oceans to really drop the price of gas in many markets. Although (shale gas) reservoirs can be prolific, gas from shale is not cheap, and whether production is sustainable over time is a real question.”

In addition to the prospect of price competition, shale gas development is likely to face environmental and population density issues in Europe and Asia. Environmental concern is likely to be most intense in Europe, and to echo concerns already being expressed in a number of places in the US. Will fraccing contaminate groundwater reservoirs? Are the chemicals used in development safe? Will shale gas production lead to unintended consequences of the undesirable kind?

The matter of population density ranges from critical in India and coastal China to highly significant in much of the southern states in the European Union, where the industry can’t get access to enough land to develop a viable shale gas project. Shale gas development requires drilling many wells. Multilateral horizontal drilling and fraccing from a single pad can take weeks and even months to complete. These drilling pads are large and operations can be dirty and noisy. Moreover, in densely populated countries good drilling prospects can be covered over with villages, small farming operations, markets and industrial operations. This inconvenient truth is hard to ignore

Game plans
Mann’s assessment of the situation involves pretty raw political analysis of the situation. “In China the communist government would just do it,” he speculates. The country has almost the same landmass as Canada, yet the population is mostly located along a relatively thin band along the east coast. There are many prospective sedimentary basins within the country, which is geologically more like the United States than Canada. “The ones that are now being looked at for shale gas are out in a desert in the western China, where there is virtually a zero population problem and access is not a problem either. None of these projects are commercial yet, they are just at the stages of looking at resource potential, doing some tests, seeing whether they are viable and then going down the road” to development.

Having said that, he recalls an argument from Singapore that “Even if China developed shale gas at the same rate and volume as North America did over the past ten years they would still require LNG because (in ten years) shale gas would meet only around 15% of their total requirements.” That’s a compelling argument against the notion that shale gas will displace global LNG
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Shale gas development is going to be difficult in most places except northern Europe, potentially China and eventually India. “In India, you do have British law covering land ownership so you do have land issues but you wouldn’t have the same environmental issues as you have in Europe. (Gas producers) could get (to viable projects) if they worked with the local population, most of whom have very low incomes. In much of Europe, where the amount people make on average is much higher and people have a much higher standard of living, it would likely be more difficult to work with local populations.”

Shale gas and LNG can coexist, but as team captains for the gas industry’s two big new hockey clubs there are many ways they can affect price and therefore development. Too much LNG on world markets could hinder development of shale gas in certain parts of the world. A great deal of shale gas development could hinder LNG development in others. But, says Mann, “Either thing could happen. It’s going to depend on geography, on what resources you have, on governments’ want to develop security of supply – a whole bunch of political things can get rolled up into that.”

“North America is a great example,” he concludes. “A few years ago we wanted to have LNG receiver terminals dotting the east coast, the southern coast and the west coast of North America. People didn’t want them. Then all of a sudden by some miracle we ended up with the shale gas revolution and we suddenly found we didn’t need them. So LNG – go away.”

For North America, at least, shale gas was the game changer. Shale Gas five; LNG one.

Unconventional Challenges

There's nothing unconventional about shale gas in western Canada, but the technology to get at it? Now that's a different story

Photo: Rig for coil tubing. This article appears in the June Unconventional Gas Guide

By Peter McKenzie-Brown

In a recent presentation to the Petroleum History Society, Dave Russum – geosciences vice-president for AJM Petroleum Consulting – recounted the development of unconventional gas in Western Canada. According to Russum, evolving technology is making unconventional gas – what he says should correctly be called “conventional gas from unconventional reservoirs” – a commercially viable commodity. Despite the lower-price environment for natural gas, rapid innovation in down-hole technologies has made shale reservoirs viable sources of gas production.

The most important of these is horizontal drilling. Since the technology became widespread in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors.

Geo-steering is another increasingly critical down-hole technology. In recent years it has been given a lift by high-impact measurement-while-drilling (MWD) tools and techniques.

Another contributor to the shale-gas revolution is multi-lateral horizontal drilling – the ability to drill several laterals from a single well. As one example, last year Trident Exploration drilled a 2,400-metre vertical well into the Montney formation near Dawson Creek. At depth, the company drilled two 1,000-metre horizontal laterals. This achievement illustrates the revolution taking place in horizontal drilling – although 1,000-metre laterals are puny by the standards of some drilling programs.

Two other technologies are more directly related to reservoir production. The industry can now isolate many completion zones in horizontal wellbores. This makes reservoir fracturing possible over long distances. What’s more, microseismic technologies now enable geo-engineers to improve reservoir development and productivity by monitoring fracture efficiency within reservoirs.

Although these technologies are increasing in sophistication and declining in relative cost, they have led to a fundamental change in gas-field economics. The petroleum sector’s spending patterns are shifting, with a much bigger portion of the development pie now being invested underground. For the first time, the industry is investing more down-hole than in gathering lines and other surface facilities.

Microseismic
Microseismic has made great strides in the last decade. One of the leaders in this area is Houston-based Microseismic Inc. The company was founded in 2006 by Peter Duncan, who originally hales from New Brunswick, got his Ph. D. in geophysics from the University of Toronto, and cut his teeth in resource development in Alberta and offshore Nova Scotia working for Shell Canada. He stresses that the technology in itself is not new. It is well established academically and within government organizations – for use in earthquake location, for example. Applying the technology to producing reservoirs, however, is a new and rapidly developing field.

Duncan explains microseismic with vivid analogies. “Regular oil and gas seismic is like an X-ray,” he says. “Microseismic is more like a stethoscope. You can ‘hear’ the sound of fluids underground.” This is an area of rapid technological growth.

According to Duncan, “We can cement geophones on the surface and underground to enable people to better produce these gas shales, and monitor production for the life of the field. With the developments we are making today, these arrays are like a big-dish microphone. (Using a computer) you can essentially beam-steer that array around the reservoir to find out what’s going on where. The cost-effective way to do this is to set up a permanent array of phones to monitor the fraccing of every well during the development of the field.” For shale gas production, a key feature of this technology is that it can tell you where well fraccing has been effective, and where it hasn’t.

“With this system, you can monitor other subsurface phenomena – for example, the injection of water or other production fluids into the reservoir. An important application has been the use of these systems to monitor cyclic steam injection in the oilsands.” Both Shell and Esso have been doing this, although using different microseismic suppliers.

What’s the cost? Microseismic is more expensive in the Montney formation than it is in the Barnett shales of northern Texas, for example. However, a technical paper from EnCana has suggested that the incremental cost of monitoring a frac stage with one of these permanent arrays is relatively small – fully amortized, about $10,000 per frac stage. If that monitoring enables geo-engineers to increase ultimate gas production by correcting fracturing inefficiencies, it’s a small price to pay for what could be much greater cash flow.

Coil Tubing
The workhorse of underground technologies is coil (“coiled”) tubing – a tool that began to make big inroads into industry operations around 1990, and has since transformed many aspects of underground drilling and workover operations. It refers to metal piping spooled on a large reel and used for interventions in wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry out operations previously done by wirelining. The main benefit of coil tubing over wireline is that you can pump chemicals through the coil. With coil tubing you are able to push tools and chemicals into the hole; wirelining relies on gravity.

The tool string at the bottom of the coil can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the coil, to a larger string of logging tools, depending on the operations. Coil tubing is also used for relatively inexpensive work-over operations. It is used to perform open-hole drilling operations.

Of particular importance in the context of shale gas production, coil tubing can be used to fracture the well – a process where fluid is pressurized to thousands of psi on a specific point in a well. This blasts the rock into rubble, thereby permitting the flow of hydrocarbons to the well-bore.

Fractious
The move to more intensive down-hole spending is shifting the industry away from its traditional ways of doing business, and even the seasonal patterns it follows. Consider fraccing.

Fraccing is a stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pumps a mix of water, sand and some soluble chemicals into the well at high pressure, thus fracturing the formation and holding the fractures open so hydrocarbons can flow more freely into the wellbore.

Dave Russum takes the story from this simple explanation to the use of multi-stage fracturing techniques on horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you isolate an interval close to the toe and frac that region. Then you move back towards the heel, isolate another interval and do another frac. This breaks up a lot of rock, making a lot more gas available. These new technologies are enabling us to access a whole lot more low-permeability rock than you would ever be able to reach with a vertical well.”

In the days of vertical drilling, producers generally fracced just one or two zones per well. With today’s technology, it is possible to frac a single well up to 17 times – although a well that required so much work would likely have a horizontal reach of 3,000 metres or more.

To fracture just one of EnCana’s Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with perhaps 45,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” said Kevin Lo of FirstEnergy Capital in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.

Dale Dusterhoft, a senior vice president at Trican Well Service, paints an even grimmer picture. “Some of the Horn River wells require up to 45,000 horsepower of compression,” he says, “and with 10 holes per pad you may have 40,000 horsepower tied up for 10 weeks.” He adds, “There will be shortages of equipment when we get up to full development of the shales” – a plus for service companies like his own, which will then charge premium day rates, but a worry for the big players in the region.

Although environmentalists have voiced concern that fraccing chemicals may contaminate groundwater, Dusterhoft argues that before wells are fracced the formations are securely sealed away from potential fresh-water reservoirs. And anyway, he says, in the unconventional wells in north-eastern BC “we only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand.” When fraccing is completely successful, he says, “All the fractures connect up with each other, so we can get maximum production. We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs like those in north-eastern BC require a great deal of logistical support. Each hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. Imagine the parade of trucks bringing such a harvest of ancient beach sand up the road to north-eastern BC – often from quarries in Saskatchewan. To take on such a project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks.

Because so much water is required, a typical job requires a large water storage pit in addition to a string of high-volume steel tanks. The amount of water being used in these jobs has actually led to a seasonal shift in the fraccing business. According to Dusterhoft, “Now (the industry is) drilling during winter freeze-up, as we always have, but fraccing in the summer. All the bigger operators are trending in that direction.” The reason is that the water is easier to deal with in warmer weather. In the longer term this will require upgrading to all weather-roads to Horn River and Montney. Until those upgrades are completed, service companies are leaving equipment in the area during freeze-up.

The shift to unconventional gas production occurred much more quickly than anyone expected, Dusterhoft said, and it has important implications. For one thing, it is contributing directly to the reduced number of wells being drilled in Western Canada. There are now about as many horizontal wells being drilled as those being directionally drilled.

To put that in perspective, drilling costs at Horn River are in the $5-7 million range per well, while they are maybe $4-5 million each at Montney. Add to that the cost of fraccing – say, $2-3 million per well – and it’s clear that the industry is putting a lot of money in the ground. But the production profiles for these wells make it worth the cost. These wells may produce 7.5 million cubic feet of gas per day for the first year. Production declines rapidly in the early stages but the optimists believe they may level off at, say, 2 million cubic feet per day and maintain those production levels for years.

Challenging to Extract
AJM’s Russum disputes this. “Each reservoir is different,” he says. “We don’t fully understand the science of shale gas reservoirs. I certainly don’t think we can apply a one-size-fits-all model to their production profiles. Some wells may simply stop producing in only a year or two.”

In wrapping up this commentary, it may be useful to return to Dave Russum’s assertion that there is no unconventional gas – only “conventional gas from unconventional reservoirs.” Russum stressed that shale gas plays are only one part of this important new resource, and that they have all benefitted from advancing technology. He defined this commodity as “any methane not trapped in a porous, permeable, buoyancy-driven system.”

What are the characteristics of these unconventional reservoirs? They are extremely variable. The methane within them is not freely dispersed and they have low or heterogeneous permeability. The source rock and the reservoir are closely related, and these resources represent large but low-concentration resources. They have unusual pressure regimes, and in many cases they represent a lower-quality version of conventional reservoirs. In short, they are more challenging to extract – a state of affairs that can best be resolved with evolving technology, as the story of shale gas amply illustrates.

A Natural Gas Crisis Coming?

This resource triangle illustrates that conventional resources (the apex of the triangle) represent a relatively small volume of the total hydrocarbons in an area or basin. Unconventional hydrocarbons depicted by the lower part of the triangle tend to occur in substantially higher volumes. Early exploration and production is focussed on the apex of the triangle. Industry only pursues opportunities lower in the triangle when the opportunities at the top of the triangle are inadequate to meet demand and consumers are prepared to pay to make the opportunities economic. The oval illustrates that the Alberta oil and gas industry has moved significantly down the triangle in pursuing both oil (heavy oil, tar sands) and gas (coalbed methane, tight gas).

By Dave Russum

The final years of the 20th century saw a rapid escalation in natural gas drilling in Western Canada. For the first time, however, the rate of production growth began to falter. In early 2000, as Murphy Oil, Apache and Beau Canada announced their discovery of the Ladyfern Slave Point gas field in a remote area of Northeastern British Columbia, their achievement seemed to herald a new era of successful wildcat exploration.

As word of a major discovery leaked out, many of the significant players in the industry jumped on the bandwagon. A frenzy of land purchases, drilling and pipeline construction followed. In little more than a year, production from the new fields rose to more than 700 million cubic feet per day - and this from an area only accessible during the cold winter months. Production from this region helped raise Canada's gas production to a new peak (in late 2001) of 17.4 billion cubic feet of sales gas per day.

Rather than representing a new era of large discoveries, Ladyfern appears to have been just another increasingly-rare large gas find. During boom periods in the 1950s, for example, gas exploration yielded large new gas fields almost every year, and many discoveries waited for years to be tied into the pipeline network. As the industry matured, such discoveries became unusual. Prior to Ladyfern, the last large gas discovery had been at Caroline, more than ten years earlier.

Unconventional gas: In any given area, free-flowing, buoyancy-driven conventional gas represents a very small fraction of the natural gas resources present. Unconventional gas represents possibly hundreds of times more natural gas resource than there is for conventional gas. It comes from five major sources:

 1. One is shallow, biogenically-derived gas in mixed sand and shale sequences. Shallow biogenic gas is considered to be an unconventional gas resource since it is not generated in the same temperature and pressure systems found in conventional hydrocarbon generation. The Milk River and Medicine Hat sands of southeastern Alberta and southwestern Saskatchewan are classic examples of this type of unconventional gas. This is the area where gas was first produced in western Canada, and it is still a major producing region. This continuously gas-producing area is the largest in the Western Canadian Sedimentary Basin.

 2. Coalbed methane is natural gas within the structure of coal. Special production techniques to remove this gas from its coal seam reservoir include lowering reservoir pressures rather than keeping them high. Coalbed methane knowledge has advanced rapidly. So has the development of water-free natural gas from coal in the Horseshoe Canyon Formation in Central Alberta. First commercial production only occurred in 2002, but current production is already more than 500 million cubic feet per day.

 3. Tight gas is gas in low-permeability rock. Reservoirs require artificial fracturing to enable the gas to flow. Canadian Hunter Exploration in the 1970s identified a huge gas resource in the Deep Basin of western Alberta. In this area, much of the sedimentary section is charged with natural gas. The rock can have extremely low permeability but production is not hampered by the presence of water. Similar gas-charged areas have been found in many parts of the world; a common term for this kind of reservoir is "basin-centred gas".

 4. Shale gas is held in shale reservoirs. This is also a low-permeability, highly-challenging resource. Large volumes of gas molecules are trapped in shales which represent one of the commonest rock types in any sedimentary sequence. Shale gas production has been pursued in the United States since the early days of the natural gas industry, and in recent years the Barnett Shale in west Texas has been a tremendous success. Many companies are experimenting with shale gas production in Saskatchewan, Alberta and northeastern British Columbia, but a commercially viable project has yet to be announced.

 5. Gas hydrates consist of natural gas trapped in ice crystals in areas of permafrost and on the ocean floor. In 1985, unconventional gas production received a boost when the United States introduced incentives to encourage the development of energy alternative. This incentive advanced the technical understanding of the resources themselves and of ways to develop them. Canada has benefited from this, learning new ways to exploit her own unconventional resources.

Complacency: The existence of these resources has led to complacency among consumers, who still assume they will always be supplied with gas at "reasonable" rates. Developing these resources can have substantial impacts on the environment through closer well spacing, more intensive infrastructure, additional noise from compression, the challenges of water disposal, NIMBY issues, and other factors. More to the point, most people do not understand that little unconventional gas is extractable in large volumes at lower prices. Consider this matter in the context that natural gas producers generally buy mineral rights from the Crown but must negotiate surface access and other land rights with their neighbours. In this environment, the chances are high that some projects will face delays as a result of public hearings - for example, as Shell and the other contenders did at the Caroline hearing. After all, those with an interest in a single land use decision could include petroleum producers, Aboriginals, landowners, farmers, ranchers, loggers, trappers, campers, sports and environmental groups, and others.

Many conflicting interests need to be resolved. Forecasters now commonly suggest that western Canada's conventional gas production has peaked and will continue to decline. Gaps between traditional supply and growing demand are already being filled with gas from such diverse sources as tight sands; coalbed methane; and since January 2000, frontier gas and liquids from Nova Scotia's Sable Offshore Energy Project. Other possible future sources include Mackenzie delta gas and liquefied natural gas from abroad. This suggests higher future costs and risks, and that suggests higher-priced future energy.

Note to readers: This article first appeared as part of a series in Wikipedia. To read it in context, click here. Then scroll down until you find the "resource triangle" graphic.