Geology shines on a shale gas boom in British Columbia
Says one vice-president, 'The rocks in B.C. are very good'
Ron Bailey, vice-president of shale gas with Nexen Inc.
Photograph by Phillip Chin
Sidebar: Storm Watch
In April there were troubling signs that the oil and gas industry’s love affair with British Columbia’s unconventional gas plays was on the rocks. “Thrill gone for B.C. shale gas exploration rights” was the headline on a Globe and Mail story that revealed the B.C. government had brought in just $17 million in its first three land sale auctions of 2011 – a pace that was woefully behind the $844 million the province netted from all of its land sales in 2010. Some viewed the weak results as proof that the fickle oil patch was turning away from Canada’s western-most province and was back to courting an old lover, Alberta, which roughly two months after the Globe story ran, would see the oil and gas industry spend $842 million during a single land sale – the highest total ever in Alberta’s history.
But if there is any handwringing that B.C.’s shale gas boom is about to go belly-up, it’s hard to notice in communities like Fort St. John, Dawson Creek and Fort Nelson that lie in the heart of the plays that brought the industry here in the first place – the Horn River and Montney basins. “When I go up to Fort Nelson there is always somebody showing me the car they bought because they were able to get employment,” says Robert Spitzer, vice-president of exploration for Apache Canada Ltd., one of the key players in the Horn River basin. “Anybody that wants a job has pretty much got one.”
Drilling statistics from the Canadian Association of Oilwell Drilling Contractors also indicate the lackluster land sales are not affecting activity on the ground. As this magazine went to press, the number of active rigs in B.C. had reached a weekly high of 66 in 2011 and the province was still the third-busiest drilling jurisdiction in Canada behind Alberta and Saskatchewan. The numbers are in line with B.C.’s drilling activity levels in 2010. However, the larger question that hangs over this region is not whether the financial windfalls from land sales will return (they probably won’t, as the best land in northeastern B.C. is already spoken for) but what heights the development in the Horn River and Montney basins will ultimately reach.
It’s a fair question. The Horn River and the Montney plays are still in the nascent stage of development, and tucked away in a northerly corner of B.C., they are far away from markets and in locations that present producers with operational and cost challenges. Meanwhile, in places like Texas, Pennsylvania and Arkansas, advances in horizontal drilling and hydraulic fracturing techniques have released vast reserves of gas from North America’s big shale gas reservoirs – the Barnett, Marcellus, Fayetteville, Hainesville and the Woodford. The Barnett shale alone accounts for 8.5 per cent of the United States’ total gas production and shale gas makes up 14 per cent of the total U.S. supply.
This gas overflow has had a profound impact on the North American natural gas market with prices hovering around US$4 per million British thermal units (Btu) since 2009. Prices are expected to rise due to gradual increases in consumption and the U.S. Energy Information Administration (EIA) forecasts natural gas prices hitting US$7.07 per Btu in 2035. Still, 2035 is a long way off for companies looking for a quick rebound in prices in order to take development in the Horn River and Montney to the next level. Given the financial and operating challenges facing companies active in B.C.’s shale gas plays, it’s uncertain if they will ever take their place alongside the continent’s other great unconventional gas producing regions.
If it doesn’t happen, it won’t be from lack of effort. The Horn River and the Montney formations have garnered significant interest from the industry. The Montney, which is actually a shale and tight gas reservoir, has attracted the likes of Encana Corp., Talisman Energy Inc., Murphy Oil, ARC Resources Ltd. and Progress Energy Resources Corp. In the Horn River the players range from heavyweights like Encana (again), to Apache Canada, Nexen Inc., Imperial Oil and right down to junior Quicksilver Resources.
The industry’s interest is understandable because the prize is so great. A recent resource assessment report on the Horn River basin done by the National Energy Board and the B.C. Ministry of Energy and Mines pegged the marketable natural gas there at 78 trillion cubic feet (tcf) with the ultimate gas in place being anywhere from 372 to 529 tcf. As for the Montney, the reserve numbers are also big. The Canadian Society of Unconventional Gas estimates the Montney basin may hold 250 tcf of natural gas.
That kind of potential – even with all the shale gas being coaxed out of the Barnett, Marcellus and other U.S. plays – will get anybody’s attention. “We’ve been in a lot of data rooms in North America and have compared what we see on these other assets as compared to what we see in northeast B.C.,” says Ron Bailey, vice-president of shale gas with Nexen Inc. “The rocks in B.C. are very good, very thick and very fraccable.”
It turns out geology is one advantage the B.C. plays have over their better-known U.S. brethren. Shale gas wells commonly have high decline rates after the first year of production, in some cases as much as 80 to 90 per cent. The B.C. decline rates are lower. According to the Canadian Energy Research Institute’s (CERI) Shale Gas Plays in North America report, the first-year decline rate is 50 per cent in the Montney and Horn River. It’s a significant difference and one that provides companies operating in B.C. with more certainty they will have a consistent revenue stream coming from their producing wells.
However, it’s not just geology that has smiled on northeastern B.C.’s shale plays – government policies have as well. The land tenure system in B.C. also works in the favor of the companies who have chosen to invest in the Horn River and Montney basins. In the U.S., the land tenure system operates on the “use-it-or-lose-it” principle, where companies must demonstrate production within three to five years of obtaining a lease or else they lose the rights to operate on it. This system forces companies into a frenzy of drilling in order to prove production regardless of where natural gas prices are sitting.
Not so in B.C., where firms have a five-year window to prove production on their leases. And if a well has commercial quantities of natural gas, companies are then given 10 years to bring that production online. “It’s a big difference in cost, a big difference in the pace of development and a big difference in the ability to hold land,” says ARC Resources CEO John Dielwart, whose Calgary-based company was one of the first to enter the Montney play in 2003. “The land tenure situation is much, much better in northeast B.C. [than the U.S.]”
The province’s fiscal regime also doesn’t hurt the future development prospects of the region. The B.C. government has developed a suite of industry-friendly royalty programs to encourage development of its unconventional gas resources. The showcase is its Net Profit Royalty Program where royalties from shale gas production are two per cent of gross revenues for 10 years or until capital costs are paid off, whichever comes first. Once capital costs are paid off or the 10-year period elapses, the royalty rates rise in tiers reaching 15, 20 and 35 per cent of net revenues.
The province even has an Infrastructure Royalty Credit Program, where companies can apply for a credit to the royalties they would otherwise pay to the province for building roads, pipelines and other associated facilities. The B.C. Ministry of Energy and Mines says as of August 2010, over $600 million in royalty infrastructure credits had been given to oil and gas companies. It’s resulted in 76 new or upgraded all-season roads and 97 pipeline projects in B.C. The industry-friendly regime has been well received by the companies operating in the Horn River and Montney. “That’s a critical factor because we live at the end of a pipeline and we have to pay transportation costs of between 60 cents and $1 per thousand cubic feet,” says Nexen’s Bailey. “But that is more than offset by the fiscal policy and tax regime of B.C.”
One final aspect of northeastern B.C. that bodes well for ramping up development to a Barnett-style scale is it is a sparsely populated area with a long history of oil and gas activity. The fraccing that’s required to wrest shale gas from its rocky prison is controversial. Concerns that the chemical-laced fraccing fluids – injected under high pressure to crack open gas-bearing rock – can contaminate drinking water and even cause minor earthquakes has led to vigorous opposition to shale gas activity in New York state – home of the Marcellus basin – Arkansas and even in Texas. That’s been less of a bugaboo in northeastern B.C. “In places like the Horn River it’s basically you and the bears out there,” says CERI executive director Peter Howard. “You aren’t incurring ‘not-in-my-backyard’ issues.”
ARC Resources’ Dielwart agrees. “When you get into areas like the Marcellus there’s a fear of the unknown. What they know about industry is what they see on the news like the [BP] Macondo well last year,” he says. “The nice thing about what we’re doing in the Montney is it’s an oil and gas operating area, and while there is still tight regulatory control and not everybody is thrilled with the level of activity, on the whole from a job creation component and as a contributor to government revenues, it’s viewed as a positive thing.”
Despite the frequent press reports and the advantages Horn River and the Montney plays have going for them – huge reserves, favorable royalty and regulatory policies and a (mostly) understanding local population – the fact is production there is still miniscule compared to North America’s great shale gas reservoirs. A March 2011 report by Edinburgh-based consulting firm Wood Mackenzie assessing the liquefied natural gas (LNG) and natural gas market in North America noted that production from the Montney in 2010 was 0.6 billion cubic feet (bcf) per day and 0.2 bcf per day from the Horn River. That’s a mere six per cent of Canada’s 2010 daily gas production of 14.4 bcf per day.
Wood Mackenzie does see gas production growing substantially from northeast B.C. though, rising to 8.6 bcf per day by 2033. But estimates looking that far out into the future are highly uncertain and there are some factors that could seriously impede northeastern B.C.’s shale gas plays from ascending to the production heights of its gassy southern cousins. For starters, finding markets willing to buy the shale gas for a decent price is vital to the development dreams of the companies in northeastern B.C. On that front, the EIA’s long-term natural gas price forecast in its Annual Energy Outlook 2011 in April couldn’t have inspired much confidence. It predicted the price for natural gas wouldn’t pass the US$5 Btu mark until 2020.
Those relatively low prices in North America challenge the economics of almost any natural gas project, forcing companies operating in the Montney and Horn River to look for markets outside the U.S and Canada. “What we need to do to get this resource fully developed over the next 10 to 20 years is to have an additional market,” says Michael Culbert, president and CEO of Calgary-based Progress Energy.
Asia could be that market, where natural gas prices more closely follow crude oil prices. The lure of accessing LNG-hungry countries like South Korea and Japan is what is driving Encana’s decision to acquire a 30 per cent interest in the Kitimat LNG project with Apache Canada and EOG Resources Canada – a project that would ship five million tonnes per year of LNG to Asian markets. And it is what caused Progress Energy to ink a deal with Malaysia’s state-owned Petronas in June that will see Petronas pay $1.07 billion to partner with Progress Energy on developing three gas fields in the Montney. The two companies say they will also launch a feasibility study that will look at building an LNG export terminal in B.C.
Beyond the worries about accessing new markets for B.C. shale and tight gas, cost escalations in the oil patch could also hinder plans to turn the Horn River and Montney into Canadian versions of the Marcellus or the Barnett. The horizontal drilling and fraccing techniques that have made the development of these shale gas plays possible also require more crews and equipment to complete than the vertical wells traditionally drilled in Western Canada.
But companies drilling in northeastern B.C. aren’t the only ones looking for crews and equipment. High oil prices are stoking development plans in the oil sands and in old reservoirs where companies are using the same techniques employed to extract shale gas to recover conventional oil. The competition for workers and equipment is already leading to cost increases in the Western Canadian Sedimentary Basin (WCSB) and the situation could get worse, warns Calgary-based investment house Peters & Co. “In the WCSB, the ongoing shortage of skilled labor will be exacerbated by rising oil sands activity levels, which we forecast should translate into higher prices,” it noted in a recent research brief. “As such we now forecast that fracturing and deep drilling rig prices will slightly exceed peak levels.”
To be sure, there is a lot that must go right for the Montney and Horn River plays to reach their substantial potential. But for those that worry the recent land sales in B.C. indicate activity levels in the region are about to nosedive, it’s worth considering recent oil sands land sales in Alberta. While the province was celebrating its record-breaking $842 million land sale in June, similar sales for the oil sands had netted $34 million so far in 2011 – a far cry from results like the $559 million an oil sands land sale brought in back in February 2006.
Yet declining returns from land sales aren’t affecting development in Alberta’s bitumen belt. A crude oil forecast from the Canadian Association of Petroleum Producers now sees production from the oil sands growing from 1.6 million barrels per day in 2011 to 3.7 million barrels per day in 2025. At the same time, a spring CERI report looking at the economic impacts of new Canadian oil sands projects in Alberta from 2010 to 2035 predicts the impact on Canada’s gross domestic product will be $2.1 trillion. If these projections are anywhere close to being right, the oil sands sector is going to be very busy over the next 25 years.
The same thing could very well occur in B.C.’s shale and tight gas plays. Demand for the cleanest-burning fossil fuel continues to increase, and with conventional supplies declining in North America, there’s a need for natural gas even if the pricing environment doesn’t look very promising right now. Besides, companies like Encana, Nexen and Talisman look beyond current markets and price trends when investing in risky plays like the Montney and the Horn River. They know these basins possess huge resources and they also know nothing comes easy in the oil patch.
The industry – much like it did with the oil sands – will have to be patient, work to reduce costs and increase efficiencies so it’s in a position to strike when the time is right in B.C. The companies that are active in the Horn River and the Montney basins also view the depressed North American natural gas environment as a temporary roadblock – one they will be able to overcome by being innovative and waiting out the shale gale. “We’re not building a short-term business here, we’re building a long-term business,” says Nexen’s Ron Bailey. “Our firm belief is that in three to five years, the floor price for natural gas in North America is going to be closer to US$6. We can make a great return at those kinds of numbers.”
More posts by Darren Campbell
- Energy development must include aboriginal input
- Pacific Rubiales to supply Colombian LNG project
- Could the robocall scandal ensnare Joe Oliver?
- Three U.S. shale plays that are keeping pipes full
- The oil patch – slowly – cleans up its act