Source: Profiler
Higher oil prices boost oilsands and conventional activity, while natural gas producers continue to face challenges
By Jim Bentein
The massive oil spill in the Gulf of Mexico, caused by an explosion on a BP offshore platform that occurred in mid April, will lead to a shift towards more oilsands development in Canada, says a Houston-based energy industry consultant.
Robert Peterson, a vice-president with Charles River Associates (CRA), predicted that the explosion, which killed 11 workers on Transocean’s Deepwater Horizon rig and caused a spill that threatened the shorelines of several southern U.S. states, will lead to a moratorium on drilling in the Gulf, where 25 per cent of U.S. oil and gas supplies come from.
Peterson, who specializes in the oilsands sector, said that as a result, the spill will likely lead to U.S. politicians not allowing offshore development in the Pacific or the Atlantic, where U.S. President Barack Obama recently lifted drilling restrictions.
“The Gulf of Mexico incident will also lead to a moratorium on drilling in the Gulf of Mexico that will last one or two years, during which the details of the catastrophe will need to be better understood,” he noted.
He said the most likely outcome is that concerns about “dirty oil” from the oilsands will fade into the background.
“Suddenly heavy oil, which was viewed as a dirtier oil because of its higher carbon content, looks a lot safer than oil from offshore.”
He predicted the disaster may also restrict the development of offshore oil and gas in Atlantic Canada.
After the 2008 credit crisis hit, several oilsands projects were postponed. But the sector has started to make a comeback, one that Peterson thinks will only accelerate as a result of the disaster in the Gulf of Mexico.
He predicts U.S. federal legislation that might have targeted oilsands crude will now be on the backburner, as U.S. lawmakers begin to realize the country, which imports a total of over 11 million barrels a day (bbl a day) of crude and liquids, 57 per cent of its needs, is able to rely less on offshore production.
“There could be a significant shift to the oilsands,” he said.
CRA believes oil prices will be somewhat volatile but will average in the $70 a barrel range, which Peterson said provides for a good return.
“Supply costs [to develop oilsands projects] are down somewhat but it is still costing $55 to $60 a barrel to develop projects,” he said. “That still provides for a good, solid return. It’s like investing in a 30-year annuity.”
Peterson predicts the environmental performance of oilsands operators will only improve, as oilsands miners improve their tailings management and water use and steam assisted gravity drainage (SAGD) operators improve the technology.
He also believes environmentalists will now shift their attention to offshore production. “After all, look what can happen offshore, compared to the known of on-land development.”
Peter Howard, president of the Calgary based Canadian Energy Research Institute (CERI), said he wouldn’t disagree with Peterson’s view that the focus of the environmental movement will now shift from the oilsands to offshore energy development, but he’s also not as sure that will lead to a ban on new drilling in the Gulf.
“If [President Obama] puts a ban on offshore drilling, his energy security policy will go out the window,” said the CERI head. “What I could see is the development of a new offshore protocol, where a relief well needs to be drilled before companies drill into their target areas.”
That would drive up the cost of offshore development.
He agrees with Peterson that offshore development in the Atlantic and the Pacific is likely to be prohibited.
All things being equal that should lead to a spurt of oilsands development, he said, except there are signs labour and material costs are “creeping up again,” after they dropped 15 per cent and more during the Great Recession.
As a result, Howard believes only larger, cash-rich companies will look at new projects, beyond what is already known.
CERI has forecast oilsands production will reach about three million bbl per day by 2020, and Howard believes that will still be the case. But it also believes there will be a new spurt of development from 2020 through to 2040, when oilsands output will hit 4.4 million bbl per day.
OILSANDS RESURGENCE
Oilsands project planning and development has escalated since the 2008 financial collapse. Cenovus Energy announced plans earlier this year to spend US$500 to US$600 million to increase production from its SAGD projects. Devon Energy revealed plans to build a third phase of its Jackfish project, which would take total production above 100,000 bbl per day, and also announced it was spending $500 million to acquire 50 per cent of BP’s interest in the Kirby oilsands project, which the two plan to expand to as much as 170,000 bbl per day.
BP announced plans in March to partner with Calgary-based junior Value Creation to develop the firm’s Terre de Grace in situ project; China Investment said it will invest $817 million to develop oilsands assets held by Penn West Energy in the Peace River area; and Husky Energy has completed front-end engineering for its proposed 60,000-bbl-per-day first phase of the Sunrise project (BP is a partner).
In addition, Suncor Energy is proceeding with a 62,500 bbl per day expansion of its Firebag SAGD project and there have been a number of smaller announcements regarding SAGD projects.
Oilsands mining projects are starting to move ahead as well, with Imperial Oil spending $8 billion on phase one of its Kearl project, which will produce 110,000 bbl per day (it would eventually produce 354,000 bbl per day) and Royal Dutch Shell is well underway with the 100,000 bbl per day expansion of its Athabasca Oil Sands Project, which would lift production to over 265,000 bbl per day.
CRA has been predicting total oilsands production will reach three million barrels a day by 2020, from about 1.5 million a day now. But the offshore catastrophe may lead to an increase in that forecast, Peterson said.
As for the conventional oil sector, production will get a boost because of the growth of shale oil plays such as the Bakken, but even at that Howard said CERI doesn’t see production reaching much more than 200,000 bbl per day, up from about 70,000 to 80,000 bbl per day now.
CERI believes oil prices will average between $77 and $81 West Texas Intermediate this year.
NATURAL GAS
While most paint a bright picture for oil development in Canada, the country’s natural gas sector still faces challenges. The problem is that North America is awash in the stuff, thanks to the advance of horizontal drilling and other technologies that have unlocked huge shale and tight gas resources.
Calgary-based Canadian Society for Unconventional Gas (CSUG) released a report in May that illustrates just how much gas there is in Canada—and supplies are even more impressive in the United States.
The report concluded that Canada’s natural gas in place resource is almost 4,000 trillion cubic feet, with the marketable portion being 700 to 1,300 tcf.
A recent report by the U.S. Potential Gas Committee, which looked at the natural gas potential in the Lower 48 states, reached the same general conclusion, predicting that there are 1,836 tcf of technically recoverable gas resources in those states.
CERI’s Howard said that means natural gas prices will stay in a range of $4 to $6 per mcf for many years.
“The shift will be towards resource plays, such as shale gas,” he said. “Only the big companies with deep pockets can afford to go there, since it requires economies of scale. Unfortunately, that creates a problem for small companies.”
Juniors will try to survive by developing the “edge plays,” mostly shallow gas reserves that larger companies find uneconomic.
“But what if a junior invests in a shallow play and the next year gas prices drop to $3 per mcf?”
He predicts there will be a good deal of merger and acquisition activity, as companies have to grow larger to survive.
“One of the big challenges faced by gas producers is what it can do as an industry to create new markets,” added Peterson.
The best immediate potential market is in the conversion of coal-fired power plants in the United States to cleaner-burning gas, since about half of the electricity in the United States is produced by coal-fired plants.
But he said the “coal lobby” in the United States is preventing this from happening. As a result, CRA also sees natural gas prices ranging between $4 to $6 per mcf for the foreseeable future.
“My experience tells me most operators need $5-plus gas and even $6 to make a profit,” Peterson said.
Encana, Canada’s largest natural gas producer, has taken a lead in finding growth markets for future production, working with groups in the United States and Canada to present a case of more gas consumption in the power and transportation sectors.
Howard said there is a growth opportunity for gas-fired power in Ontario, where the shift to renewables such as wind and solar requires a backup power source such as natural gas (which burns about 50 per cent cleaner than coal). But he doubts the shift will be widespread across North America.
“Coal is here to stay,” he said.
Mike Dawson, president of CSUG, agreed that finding new markets is critical.
One hopeful development is plans by Kitimat LNG to spend $3 billion to develop an export terminal to send liquefied natural gas (LNG) from the Port of Kitimat, British Columbia, to Asian gas markets. Apache Canada recently agreed to acquire a 51 per cent interest in the project, in which the state-owned Korea National Oil Company also plans to invest. That company also recently announced plans to invest US$1.1 billion to jointly develop Canadian gas fields with Encana.
Dawson said the use of horizontal drilling and multi-stage fracturing to unlock shale gas plays has fundamentally altered the natural gas business in North America.
“There’s strong confidence the gas is there, so the risk profile is changed from geology to engineering,” he said. “It becomes a manufacturing process and you have to be a low-cost operator.”
Dawson isn’t ready to write off juniors.
“But they’ll have to redefine their business model,” to survive in a world of permanently lower gas prices, he said.
However, the National Energy Board (NEB), Canada’s main energy industry regulator and forecaster, isn’t quite as pessimistic.
Paul Mortensen, technical leader for hydrocarbon resources at the Calgary-based agency, said there’s no doubt shale gas has been a “game-changer,” but the NEB believes it’s too soon to assume prices will stay low for many years.
He said the NEB now expects gas prices to average about $5.50 per mcf this year, rising to $6 in 2011 and $6.75 in 2012.
But the trend is not Canada’s friend, as exports of natural gas to the United States continue to decline.
In 2009, for instance, gas exports dropped by almost 11 per cent, caused by falling demand because of the recession and growing U.S. supplies. The NEB recently forecast total Canadian production—down to 14.4 bcf per day in 2009 from 15.8 bcf daily in 2008—will decline to 13.04 bcf per day by 2012.
The impact on the drilling sector of the decline in gas production has been devastating, Mortensen said.
“We’re calling for 4,800 gas wells to be drilled in 2010. [In 2009, 4,000 were drilled],” he said.
The all-time high for wells drilled in Canada was in 2005, when 25,000 were punched. In 2009, one of the worst years in recent history for the drilling sector in Canada, only 8,400 wells were drilled across the country.
The Petroleum Services Association of Canada recently predicted there will be 11,250 oil and gas wells drilled in Canada this year, up from an earlier forecast of 8,000.
The shift to unconventional gas has meant wells are costlier to drill and take longer (an average of nine days, as opposed to less than six in the past per well).
Despite the shift to unconventional gas, shale gas wells are still only a small percentage of the total. For instance, of the 4,000 gas wells drilled last year only 300 were in the Montney basin, the hottest shale gas play. In total, less than 500 mmcf of shale gas was produced last year in Canada.
“It will be a long time before unconventional gas matches production from conventional gas areas,” said Mortensen.
In the United States, where 56 bcf of gas a day was produced last year, only 8.7 bcf came from shale gas plays.
However, the share of shale and tight gas production will rise over time to crowd out conventional production, he said.
A similar trend towards unconventional oil production is occurring in Canada, he said.
By 2020, the oilsands share of total Canadian production is expected to double, from about 40 per cent now to 80 per cent, reaching about 2.8 million to 2.9 million barrels per day.
However, oilsands production could be much higher than that, depending on economic and other factors, he said.
“The trend towards more unconventional production [of both oil and gas] will be gradual,” said Mortensen.
And although natural gas producers face challenging times, especially with accessing U.S. markets, he said Canadian crude and liquids will continue to maintain and even grow its market share, especially as more oilsands crude is brought on. Canadian crudes and liquids are already responsible for about 2.49 million bbl per day of the 11.1 million bbl per day imported by the United States, according to the U.S. Energy Information Administration.
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