The Montney Formation’s potential for Canada’s natural gas market is strong. But amid low domestic prices and waning LNG demand, is it on track to fail?
There’s a lot riding on the Montney Formation. The liquids-rich shale gas play is already a fairly large player in Canada’s natural gas market, producing around 3.5 billion cubic feet of natural gas per day (bcf/d), or 25 percent of natural gas production in the Western Canadian Sedimentary Basin (WCSB). But it has the potential to be much larger. A recent joint study by the National Energy Board, Alberta Energy Regulator, the B.C. Oil and Gas Commission and the B.C. ministry of natural gas found that the Montney holds about 449 trillion cubic feet (tcf) of marketable gas and nearly 15 billion barrels of marketable natural gas liquids. Analysts at Wood Mackenzie predicted in 2013 that Montney production could surpass the 5 bcf/d mark in 2018, while production elsewhere in the WCSB is set to decline.
Major players like Shell Canada, ExxonMobiland Progress Energy have bought sprawling plots of land in the Montney in the hopes that new LNG export facilities on the West Coast would eventually provide access to higher international prices for their product. But actually building those facilities – the B.C. government website lists 21 proposals – has been slow amid regulatory delays and worries over a glut of new supply from the U.S., Russia and Australia. In January, Shell became the first project to get a B.C. government permit, but it has yet to take a final investment decision (FID). The feedstock of all LNG projects proposed in B.C. amounts to a an almost comical total of 41.9 bcf/d in capacity, so clearly only a few – if any – will ever be built. Still, the most likely projects to reach an FID will be sourced almost entirely by Montney gas.
Meanwhile, producers are expecting low prices for an extended period as a flood of natural gas makes its way westward, from the Marcellus Formation in the northeastern U.S. to the U.S. Midwest. Production in the Marcellus is among the lowest-cost in North America, but producers don’t receive competitive prices for their gas. That could soon change as a significant buildout of pipelines in the Marcellus gradually comes online over the next few years, potentially saturating the North American market. However with per-well costs between $4 million and $10 million in the Montney, compared to $6 million to $8 million in the Marcellus, according to a report by the Royal Bank of Canada, analysts believe the formation will remain competitive despite an extended low-price environment. “Our party line is that the Montney is probably the second-best gas play in North America,” says Brook Papua, an analyst with ITG Investment Research in Calgary. “A lot of Montney producers can produce at that $2 [per million btu] level. Meanwhile, a Marcellus operator today is getting screwed because of price differentials between northeast Pennsylvania and Henry Hub.” He says some Marcellus producers are getting as little at $1 per million btu for their product. But with Canada’s LNG hopes in doubt, and amid “lower for longer” natural gas prices, can the Montney still meet its soaring potential?
Much of that production potential is linked to the construction of new LNG export facilities on Canada’s West coast. Progress Energy Canada, a fully-owned subsidiary of Malaysia’s state-owned Petronas, has the largest area of contiguous land of any player in the Montney with between 600,000 and one million acres of holdings, according to analyst estimates. How much of that land is exploited depends upon whether its sister company, Pacific Northwest LNG (also owned by Petronas), will eventually complete its proposed LNG export facility on Lelu Island, a short distance south of Prince Rupert. The project is one of the most likely to first reach a final investment decision, though it has run into snags over local opposition to the project, regulatory uncertainty and cost concerns. Should Petronas decide to shutter the project, it will result in “two billion cubic feet that isn’t coming online,” Papau says.
ExxonMobil, for its part, is awaiting a green light for its LNG facility after it bought Celtic’s natural gas assets in the northeastern corner of B.C. for $3.1 billion in 2013. ExxonMobil, along with its subsidiary Imperial Oil, owns 340,000 net acres in the Horn River Basin tied to the construction of West Coast Canada LNG, which is planned for construction at Tuck Inlet, within the town limits of Prince Rupert. “If the facility doesn’t get built, the gas probably won’t get developed,” Papau says. Taken together, the eight LNG projects that had received NEB approval by the end of 2014 amounted to over 17 bcf/d of potential LNG exports, most of which would be sourced from the Montney.
The question of how many – or, for that matter, whether any – facilities complete construction is significant. Increasingly, demand for proposed LNG facilities along Canada’s coast is tapering off. A report byIHS, a consultancy firm, said that of the 90 LNG facilities that have been proposed globally in the past five years, only about 20 are needed to meet demand. With a raft of new facilities set to come online soon – particularly in the U.S., which boasts as many as 38 proposals – IHS analysts predict only a handful of new facilities around the world are required to meet the remaining demand in Asia. Weakening Asian economies are cited as a major reason for the slide in demand, as well as a glut of cheap coal supplies and Japan preparing to restore some of its nuclear power supply. In 2011, the International Energy Agency forecasted demand for LNG to rise 16 percent by 2016, but its most recent expectations suggest it could be closer to 11 percent.
Despite the seemingly waning promise of LNG, many Montney producers won’t be deeply affected by the absence of new export routes. “We never saw LNG as being a big value lift for natural gas prices in Canada, and so we don’t see the loss of LNG as being a big detriment,” says Samir Kayande of ITG. Instead, in the absence of any meaningful volumes of LNG exports, the biggest threat is medium-term low prices, which show no sign of lifting any time soon.
Marcellus’s 24 bcf/d new pipeline capacity coming online in the next few years presents the potential for a staggering market shift (by comparison, the entire output of the WCSB is 14 bcf/d). All of that westward-moving gas from Marcellus and Utica has investors concerned that natural gas prices will remain low in North American markets, causing producers in more far-flung regions to be backed out of the market.
At the same time, Montney production shows signs of being constrained due to a shortage of pipeline capacity, Kayande says. He bases this upon the differential between AECO prices and prices at Station 2, a hub located on Spectra Energy’s natural gas network in northern B.C. that represents the received price for many Montney producers. That differential has been up to 50 cents for prolonged periods, or around a fifth of the price of AECO gas in recent months. There is also a shortage of processing facilities: In its proposal to the NEB to build its Groundbirch Mainline, TransCanada says that to absorb all of the gas expected to be produced by 2020 requires up to 14 new processing facilities.
But the $570-million expansion of TransCanada’s NGTL System, which the company announced in November 2015, should ease those constraints somewhat. The expansion comes after NOVA Gas Transmission, a subsidiary of TransCanada, announced it had signed 2.7 bcf/d worth of contracts with shippers. Construction is scheduled for completion in 2018 and includes the North Montney Mainline, which will ease capacity constraints for producers in the northwestern limits of the formation.
Kayande says larger players in the region should be able to withstand low prices, and notes that larger companies like Encana and Seven Generations Energy are particularly well-positioned. Small players in the region, many of whom based their valuations on the backs of LNG potential, are likely to suffer. But there are outliers like Painted Pony Petroleum, which has some of the best-producing wells in the formation and estimates that its debt-to-funds flow ratio in 2016 will be 1.3 to 1. Advantage Oil and Gas is among the lowest-cost producers in the Montney, and its CEO has said the company could break even at prices of US$1 per thousand cubic feet. “It comes down to risk,” says Martin Pelletier, a portfolio manager at TriVest Wealth Counsel in Calgary. “The smaller participants in the Montney are at the margin, and the margin is higher risk. The larger players in the region are going to be just fine.”
The Montney has lost some of its shine in recent years in terms of reaching its full potential, but Kayande and other analysts say the formation remains Canada’s most competitive natural gas play. “We are not concerned that Appalachian [Marcellus and Utica] gas will preferentially back out Alberta gas in the near-term,” he says. “What you want to be investing in is the lowest cost of gas supply no matter where you are anywhere in North America. From that perspective, the Montney competes well.” Despite the expectation that North American gas prices will remain low, the Montney will remain competitive with shale plays in the U.S. But due to a shrinking need for LNG imports in Asia, overall gas production from the Montney is likely to rise at a slower clip than previously thought.
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