Royalty cuts by the British Columbia (BC) government ignited natural gas production development with potential to match or exceed the supply addition represented by the proposed Alaska pipeline from the North Slope, Canadian industry analysts say.
Output from BC’s Horn River shale formation has potential to reach 5 Bcf/d within 10 years, according to research by the Calgary energy shares boutique Peters & Co. Early results are already apparent, according to data collected by rival investment house FirstEnergy Capital Corp. BC production is rising while Alberta and Saskatchewan taper off.
“Unlike many unconventional natural gas plays before it, horizontal (drilling) exploitation of the Horn River Basin will not require high natural gas prices, remaining economic at Nymex prices below US$5/Mcf,” the Peters analysis says.
“In addition, we anticipate further cost improvements will be achieved through operator and service company experience, a migration towards fewer yet longer wellbores and an increasing number of stimulation events (high-pressure “frac” injections to break open flow channels) per well. We estimate that the development of the Horn River shale could generate superior economics when compared to other unconventional natural gas plays across the Western Canadian Sedimentary Basin and the United States, despite near-term infrastructure challenges.”
The activity trigger is a BC net-profit royalty regime that is a clone of the enticing approach Alberta enacted for its oilsands in the mid-1990s, Peters says.
In the gas case, the rate is held down to 2% until costs including infrastructure such as roads and pipelines are recovered from new production. After that “payout” point, the provincial levies can rise on a sliding scale determined by market conditions, but are only collected on net profits or revenues after expenses rather than following customary royalty practices of taking a share of gross sales.
The BC regime makes the break-even price for new Horn River production US$4.86/Mcf, even at the current beginner state of the shale gas art in Canada, the Peters analysts estimate. At US$5.50/Mcf, current wells are forecast to hit a 20% rate of return that makes the northern BC deposit competitive with all shale targets across Canada and the U.S.
“Assuming a long-term natural gas price of US$5.50/Mcf, the average royalty rate paid on a Horn River well would be about 15%, significantly lower than royalties paid in comparable shale plays in the U.S. and Canada,” the Peters research calculates. “This royalty framework has many similarities to…the Alberta oilsands royalty, which was a key driver behind spurring significant investment in the oil sands in the late 1990s and early 2000s.”
Alberta has set a precedent for a provincial government largely resisting temptation to end the generosity when energy prices take a sharp turn upwards, when a priority development target is involved. Although high crude prices led to increases in maximum potential oil sands rates by 2009 royalty reforms, the collections continue to be on a net-profit basis and did not ignite any counterpart to a marathon — and successful — industry resistance campaign against hikes for conventional crude and gas production. BC has repeatedly pledged to make the shale gas net-profit royalty a permanent fixture and honor project agreements based on the regime.
At the current level of BC shale gas performance, the analysts estimate the Horn River’s 5 Bcf/d potential could be reached by about 2,900 jumbo horizontal wells costing a total of C$36 billion (US$35 billion). The total is roughly comparable to projected costs of the proposed Alaska pipeline alone, excluding the Arctic gas production installations that would be necessary to fill it.
At the top of BC near its boundary with the Yukon and Northwest Territories, the Horn River deposit is a remote 5,000-square-mile patch of trackless forest and muskeg swamp, virtually uninhabited even by northern hermits, and rarely visited by aboriginal hunters. But by Canadian industry standards the area is its “near frontier,” within far easier reach than Arctic gas on the Mackenzie Delta or the Alaskan coast of the Beaufort Sea.
The region has been a target of sporadic but gradually spreading conventional drilling for decades, and is served by Spectra Energy’s (Westcoast) pipeline grid and its gas processing plant about 80 kilometers (50 miles) from Fort Nelson, the nearest community.
While participants in the Horn River drilling rush have so far made full public disclosures of performances by only eight of their 230 wells to date, they have made it plain the results are highly encouraging by supporting infrastructure development.
Expansions of the Spectra facilities are in regulatory approval and construction stages, along with an extension of Alberta’s Nova pipeline grid into the area by TransCanada Corp. Plans for the area by EnCana Corp. include the world’s biggest gas plant, a 2.4-Bcf/d complex to be built in six phases, with work on the first 400 MMcf/d stage scheduled to begin this year. Also potentially drawing gas from the area is the Kitimat LNG proposal for exports to Asia via a new BC Pacific coast tanker terminal, a project gaining momentum under new ownership by Horn River developers Apache Corp. and EOG Resources.
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