As one of the world’s top oil and gas producers, Canada has gained prominence for being a reliable source of hydrocarbon resources that have maintained investors’ attention for decades.

Emerging opportunities, including shale plays like the Montney and Duvernay—still considered to be frontier—as well as acreage offshore the country’s east coast that could lead to even more supplies. But just like other countries blessed with abundant natural resources, oil and gas developments in Canada, where oil production led by the oil sands is predicted to grow by an annual average of 175 Mbbl/d until 2030, still face obstacles.

For starters, falling oil prices have further squeezed the budgets of E&P companies, which have become more focused in spending, strategically cutting loose assets that are not in sync with their missions. Regulatory and environmental pressures remain. In addition, the globalization of the industry has heightened competition as Canada’s E&P sector moves from scarcity to abundance, according to Barry Munro, EY’s oil and gas leader for Canada. With an evolving energy environment, he said that the implications of cost matter, organizations must think globally and innovation is key.

“There is a pretty prolific resource, and I believe the fiscal terms are attractive to source capital. There are some who believe that offshore Canada looks oiler than offshore the northeastern part of the U.S.,” Munro told E&P. So “it would appear that the geology is right and they have the right level of players and the infrastructure and policy support. But the challenge from the scarcity world to abundance world is that there are competing alternatives for capital for the E&P companies who would have to drive the exploration forward.”

These companies are looking for places with the strongest opportunities, and Canada remains attractive for some companies, including Exxon Mobil. The company operates one of the country’s largest offshore fields—Hibernia—with a massive 52-well development, called Hebron, underway just 32 km (20 miles) southeast of the Hibernia project. Estimated to produce more than 700 MMbbl of recoverable oil, the heavy oil field is located offshore Newfoundland and Labrador in the Jeanne d’Arc Basin.

Offshore Opportunity

Nearly 35 years after its discovery in 1980, the $14 billion Hebron oilfield development is progressing in about 91 m (300 ft) of water, with first oil expected by year-end 2017. Hebron, just like Hibernia, will produce through a gravity-based structure (GBS) and an integrated topsides deck.

“We knew we would be facing challenging environmental conditions in designing Hebron because of the arctic environment of our offshore field, the Grand Banks. At this location we are faced with icebergs, significant waves, seismic activity and fog,” Geoff Parker, senior project manager for Hebron, told E&P in an emailed statement. “We’ve designed the platform to address these conditions. One example is that we carried out wave model testing to determine global wave loads and local impact loads on the GBS.”

The GBS, constructed by Kiewit-Kvaerner Contractors with 130 Mcm (4.6 MMcf) of reinforced concrete, was towed from dry dock to the deepwater construction site at Bull Arm in July 2014.

“Following that, a flotilla was assembled around the GBS. After the flotilla was established, the GBS contractor commenced a concrete slip forming operation at the deepwater site, which concluded in November,” Parker said. “This raised the GBS height another 44 meters [144 ft] to approximately 71 meters [233 ft]. Next year we will take it up to its full height of approximately 120 meters [394 ft].”

Parker added that mechanical outfitting, another key activity at the deepwater site, is expected to continue for the next year or so until the GBS is ready for mating with the topsides. The topsides will be sized for an oil production rate of 150 Mbbl/d, and the standalone concrete GBS will be designed to store about 1.2 MMbbl of crude oil.

The development—operated by ExxonMobil Canada Properties with 36% interest and partners Chevron Canada Ltd., Suncor Energy, Statoil Canada and Nalcor Energy Oil and Gas—has come a long way, considering its history. Test results at the Hebron asset in the 1980s showed uneconomic rates of oil in the Ben Nevis reservoir and gas/condensate in the A Marker and Lower Hibernia reservoirs, according to Hebron’s field development plan. Good news came with the second phase of delineation drilling in 1999, when more than 1 Bbbl of stock tank original oil in place was encountered while testing the Ben Nevis reservoir on the “Hebron horst” fault block.

“The Hebron asset currently contains three discovered fields: the Hebron Field, the West Ben Nevis Field and the Ben Nevis Field,” Parker said. “The Ben Nevis reservoir within the Hebron Field is the core of the Hebron project and is anticipated to produce approximately 80% of the Hebron project’s crude oil.”

Unlike the Hibernia development, which produces light crude, Hebron’s crude is heavier and more viscous at 20˚API, Parker noted.

“The Hebron project will extend the life of the offshore oil and gas industry in Newfoundland and Labrador,” he added after noting, however, that the size and complexity of the project have posed challenges in finding sufficient skilled individuals within a small labor pool. This has led to the development of training programs. “It represents an important next step in the development of a sustainable offshore oil and gas industry in Newfoundland and Labrador.”

While hopes are high for Atlantic Canada’s ability to raise oil volumes, Canada is already witnessing a surge in natural gas production, prompting companies to pursue LNG exports despite competition—nearby and afar—being ahead in development.

“From a Canadian perspective, our biggest customer has become our biggest competitor,” Munro said. “We have a Canadian natural gas industry that was built around supplying natural gas to the U.S., and that customer has gone away.”

LNG Competition

Last year around this time, Munro said global buyers of LNG would have looked to the U.S. with skepticism given the uncertainty concerning whether there would be sufficient political support to accelerate export LNG development in the U.S. This, in turn, would drive prospective buyers to Canada, where there weren’t as many question marks around LNG export regulations.

“Fast-forward to today--I think that there has been a market shift in what appears to be political support for LNG exports out of the U.S., and all of them are at stages of development that are farther along than any of the Canadian projects,” Munro said. “Now there is this intense competition for customers. … People do realize that the demand for LNG isn’t infinite. Now you have direct Canadian-U.S. competition for export LNG.”

About 18 LNG projects have been proposed for Canada’s east and west coasts, with British Columbia’s Pacific coast having multiple proposals clustered at the ports of Kitimat and Prince Rupert. As of mid-November, none had reached the sanctioning phase. The proposed projects, if all are built, amount to 130 million tonnes per annum that could grow to more than 300 million tonnes per annum at full-phase buildout, said Jeff Fetterly, principal for oilfield services analysis with Calgary-based Peters & Co. Ltd.

“Asia is clearly the market opportunity for most of Canadian energy exports,” Fetterly said, speaking at Hart Energy’s North American LNG Exports Conference. “When you look at the Asia-Pacific basins specifically, supply is at a deficit to demand, and as a result there is an opportunity here for North American LNG, and specifically Canadian LNG.”

However, he said, there is more liquefaction capacity under construction now than regasification capacity. “So the race is on” among potential LNG suppliers, Fetterly said, later adding that Canada is competitive but probably at a “modest deficit” compared to projects proposed for the U.S. coast.

Fetterly noted that one emerging piece in Canada’s LNG development that appears to be under the radar is floating LNG, which six proposed projects plan to utilize. He called this move advantageous from several perspectives, including from capital cost and scalability standpoints.

However, the vertically integrated model typical of Canadian LNG projects means significant upstream costs.

“We estimate that somewhere between two-thirds and three-quarters of the total capital cost of a project is going to be associated with developing the upstream resource. In the case of the Petronas and Shell projects, they both have sizable resources that have been accumulated in the Montney region,” Fetterly said. “But the average well cost in those regions is north of $8 million if you include associated infrastructure.”

He estimated that more than 6,000 wells would have to be drilled for the Petronas LNG project over the span of 25 years to generate sufficient gas supply to meet the project’s needs. Yet active drilling programs in Canada where existing production is about 450 MMcm/d (15 Bcf/d) are among the country’s strong points.

Significant gas resource potential exists in the Montney and Horn River plays, and at least one large LNG operation could have a significant impact on the pace of development, he said. At the time, gas production in the region was around 105 MMcm/d (3.5 Bcf/d) with about 5,000 wells drilled since 2000.

“The impact from a services/upstream development standpoint is pretty staggering on what could ultimately happen. The risk obviously from an inflation standpoint is there as well,” Fetterly added. Pipeline costs are among the downsides, considering one pipeline could cost $7 billion or more to build. “The capital cost to build a pipeline from the Montney, both on the British Columbia side and the Alberta side, to the coast is significant for topography, capital and time,” he said.

Compared to the U.S., however, Canada’s west coast is far closer to the Asian market than the U.S. Gulf Coast, Munro said. He also pointed out that Canada’s projects are all greenfield projects that require intense amounts of regulatory and First Nations support to proceed with buildout.

“In the U.S. they are building off of brownfield assets. The question is whether the plant construction costs in the U.S. by repurposing existing facilities offset the shipping cost disadvantage that U.S. projects would have,” Munro said. “We’re witnessing an intense level of competition in that regard.

“What Canadian E&P companies are learning very quickly is that that move toward globalization means they need to have a much deeper understanding of market forces and factors across multiple jurisdictions,” he added.

Oil-sands Development

An area where Canada soars above the competition is oil-sands development, with related production accounting for 56%, or 1.98 MMbbl/d, of the country’s total oil and oil equivalent production average of 3.5 MMbbl/d in 2013, according to a November 2014 Canadian Energy Research Institute report.

Oil-sands bitumen production is forecasted to grow from its 2013 level of 1.98 MMbbl/d to more than 5 MMbbl/d by 2030, according to the report.

“The oil sands will continue to attract multiple billions of dollars’ worth of capital investment and continue to ramp up production,” Munro said. “The issue that oil sands developers have to deal with is in part sort of ensuring adequate market access—that’s either a pipeline south, a pipeline west or a pipeline east.”

That was among the reasons Statoil chose to delay its Corner Field development at the Kai Kos Dehseh oil sands in Alberta for at least three years. But its Leismer steam-assisted gravity drainage development continues operations.

“Costs for labor and materials have continued to rise in recent years and are working against the economics of new projects. Market access issues also play a role—including limited pipeline access, which weighs on prices for Alberta oil, squeezing margins and making it difficult for sustainable financial returns,” Statoil Canada Country Manager Ståle Tungesvik said in a news release.

The world’s plentiful oil supply, led by historic high production from North American shale plays thanks to horizontal drilling, hydraulic fracturing and other technologies, has left many to ponder when the economics of developing these hydrocarbon resources will cause producers, particularly in the U.S., to slow down production. West Texas Intermediate has dropped from a high of $102 in 2014 to about $67 in early December, while Brent has stumbled from about $116/bbl to about $70/bbl.

However, Munro believes in the long run big companies will continue to invest in the oil sands because it is a massive resource.

“You’re dealing with a resource that has a 50-year life, so there is a view that you have to look beyond the current commodity price cycle,” Munro said. “You also believe that over time technology will continue to unlock more barrels or do it more cheaply.”

But innovation is not only technology, “it is also innovation around organization structure, job processes and funding models,” Munro added. “People are going to feel an even greater pinch point around their margins from a cost perspective,” so innovation is a necessity.