Canada / Shale Daily / Horn River

Information on the Horn River Basin

Horn river map


Background Information


There doesn’t seem to be much question about the potential for natural gas out of the Horn River Basin, Liard Basin, and the Cordova Embayment in Northeast British Columbia. The Horn River alone may possess up to 650 Tcf of reserves, and one eye opening estimate prepared by Sproule Associates in 2012 suggests these three formations may have combined resources between 809 and 2,222 Tcf. What is in question, however, is just how much these areas will be developed, and can it be done economically? That remains to be seen, but as we discuss below, there are several companies who are betting that it will.

Our main focus in this article is the Horn River Basin, and we will refer to that almost exclusively hereafter, since that area is farthest along in its development among these three plays (although activity in the Horn River itself is still in its infancy). However, many of the issues we raise below apply to all three areas.

First, a quick description of these areas:

Horn River Basin –The Horn River Basin is a dry natural gas basin that encompasses 1.1 million hectares, and contains several separate shale formations: the Evie, Klua, Otter Park, and Muskwa Shales. These shales lie at vertical depths between 6500’-13000’. Horizontal drilling in the Horn River began in earnest in 2008.

We estimate that total natural gas production in the Horn River was less than 250 MMcf/d as of July 2013. One of the factors for this is that production from the Horn River is generally sour gas, which must be treated before it is of pipeline quality. Spectra Energy has roughly 1.2 Bcf/d of gathering and processing capacity in the area.

In June 2013, Encana pegged Horn River horizontal drilling and completion costs between C$16-C$22 million per well, with IP rates at either side of 30 MMcf/d, and EURs between 15-35 Bcf, depending on lateral length. Many wells in the area are now being drilled via multi-well pads. 

Horn river map

Liard Basin - Questerre Energy and Transeuro Energy did some of the early drilling in the Liard Basin, but more recently, the Apache Corporation (APA) may have advanced the ball quite significantly. In June 2012, APA announced long-term test results from three wells at Liard, including the D-34-K well, which was drilled to a vertical depth of 12,600 feet with a 2,900-foot lateral and a six-stage hydraulic fracturing completion. The 30-day initial production rate averaged 21.3 MMcf/d, or 3.6 MMcf/d per frac stage. The ultimate recovery from the D-34-K well is estimated to be a prolific 18 Bcf. Chevron has since partnered with APA in the Liard, but in July 2014, Apache announced its intention to sell its Liard and Horn River assets, in order to concentrate on operations in the United States.

Other companies with a presence in the Liard are CNOOC (through Nexen Energy), Paramount Resources, and STX Energy. 

Cordova Embayment –This area is very similar geologically to the Horn River Basin, and is underlain by the same shale formations. The Cordova lies over a much smaller area, though, just 379,000 hectares in the Northeast corner of BC and extending into the Northwest Territories. There are not many players in the Cordova just yet, and only a handful of wells have been drilled to date. Interestingly, much of the potential interest in the Cordova is coming from Asia, should the Cordova ever turn into an international supply basin. In 2010, Mitsubishi purchased 50% of Penn West Energy Trust’s Cordova acreage, and a year later, Mitsubishi sold pieces of its stake to Chubu Electric Power, Tokyo Gas, Osaka Gas, and KOGAS. CNOOC also holds acreage there, through its acquisition of Nexen.

Jean Marie (not pictured)– This natural gas play is more a mix of traditional conventional, carbonate, and tight sands. There have been very few horizontal wells drilled here to date. 

Development in the Horn River may still be in its early innings, but there are a number of companies who are working to ramp up production in the play. Eleven of the largest acreage holders in the Horn River Basin have combined to form the Horn River Basin Producers Group (HRBPG), in an effort to share information about the basin, to minimize land surface disruptions, and to serve as a liaison to the surrounding community. HRBPG members include Apache, ConocoPhillips, Devon, Encana, EOG Resources, Exxon/Imperial Oil, Nexen (now part of CNOOC), Pengrowth, Quicksilver Resources, Suncor, and Stone Mountain.

Quicksilver Resources (KWK) certainly has an added incentive to develop the Horn River, as it has transportation commitments to deliver up to 1.1 Tcf of Horn River production over the next ten years, depending on the ultimate outcome of the now delayed Komie North Pipeline project (more than 900 Bcf of that commitment is after the year 2017). As of year-end 2012, KWK only had 105 Bcf in proved reserves, only 10% of its committed volumes.

In addition, Chevron made a substantial commitment to Northeast British Columbia in December 2012, when it agreed to pay an estimated $1.3 billion for a 50% stake in the proposed Kitimat LNG export facility and connecting Pacific Trail Pipeline, and a 50% interest in approximately 644,000 acres in the Horn River and Liard Basins.

In February 2013, the National Energy Board of Canada said projections that Horn River production could grow to 3.5-4.0 Bcf/d were “plausible.” Current low natural gas prices are choking off some investment in the play for now, but most operators in the Horn River have up to 10 years before they start losing their lease positions. However, in order to achieve significant large scale production in the Horn River, we believe the industry must overcome the following issues that face all the natural gas formations in Northeastern British Columbia:

Lumpy Progress on Infrastructure –Midstream capacity in the Horn River continues to grow, but at a very uneven pace. In May 2012, TransCanada Corporation expanded its Alberta System into the Horn River Basin, which added 1 Bcf/d of takeaway capacity from the play. However, plans to further expand into the Horn River were shot down when the NEB rejected TransCanada’s proposed Komie North Expansion project, because the company had only obtained one shipper (Quicksilver Resources). Quicksilver now believes Komie North will not be completed until 2017.

Spectra Energy currently has 1.2 Bcf/d of treating capacity and gathering pipelines in the Ft. Nelson area, including the 250 MMcf/d Ft. Nelson North processing facility it placed in service in 2013 (see below). On the other hand, Enbridge and its partners announced in October 2012 plans to defer both phases of its proposed 800 MMcf/d Cabin Gas Plant indefinitely. That additional 800 MMcf/d of capacity is probably not necessary to accommodate current production and drilling activity in the region, but we believe the decision to delay the project does underscore the lack of coordinated infrastructure growth between producers and midstream companies that is typical of more developed and less remote natural gas areas, such as the Marcellus Shale.


Relatively Poor Economics -Despite the fact that royalty rates in British Columbia are quite low by industry standards, in February 2013, the National Energy Board estimated that supply costs in the Horn River averaged C$3.50/Mcf (U.S. dollar at par), well above competing gas plays in the United States. Much of that cost is no doubt the result of high transportation costs spread over lower volume. A lack of infrastructure always creates something of a chicken and the egg problem. High drilling costs prevent producers from drilling, which in turn makes them less likely to underwrite gathering and pipeline projects. On the other hand, if producers had enough infrastructure in place, they could ramp up production, and lower unit costs.

But even after prolific drilling and anticipated efficiency improvements improve economies of scale, Horn River expenses are still projected to average C$2.20/Mcf in time, the NEB concluded. Moreover, producers must contend with weak basis differentials, and Horn River production is dry gas, so they do not receive an economic uplift from NGL sales.

According to the Short-Term Canadian Natural Gas Deliverability 2014-2016 report issued by the NEB in May 2014, drilling in deeper dry gas formations like the Horn River would not be significant unless prices were to reach US$6.00/MMBtu, which the NEB calls its higher price case.  If prices were to average US$6.00/MMbtu in 2016, then the NEB assumes Horn River shale gas deliverability increases from 11 106m³/d (380 MMcf/d) in 2013 to 13 106m³/d (468 MMcf/d) in 2016. In its mid-range case, where prices would average US$4.35 in 2016, “drilling in the Horn River Basin is minimal at 14 wells in 2016.” But in its lower price case, prices average US$3.75 in 2016, which the NEB believes would be too low to spark any new drilling in dry gas plays.

As of November 3, 2014 the CME/NYMEX futures strip stood at just US$3.98/MMbtu, which would suggest little to no new drilling in the Horn River area for the next several quarters. 


Competing Supply -Gas volumes flowing east on TransCanada’s mainline have decreased in recent years, in no small part because of they must now compete with growing volumes from the Marcellus Shale. Moreover, if the Ohio Utica/Pt. Pleasant Shale formation and maybe even the Upper Devonian Shale reach full development mode, that may compete directly with gas from TransCanada into the Midwest. Horn River gas also has to contend with other emerging Western Canadian plays, such as the Duvernay, Montney, and possibly even the Bakken Shale if more gas infrastructure is built there. Western Canada will no doubt need growing production from unconventional sources to help counter natural declines in its legacy production. However, given these other emerging areas, Horn River production may not be necessary to achieve that.


LNG Export Facilities to the Rescue?

Despite the aforementioned challenges, development of the Horn River could receive a major shot in the arm if several of the 17 export facilities that have been proposed along the west coast of British Columbia (or the 2 being proposed in Oregon) are built. The price of LNG delivered to Japan has been more than US $10/MMbtu higher than the Westcoast St. 2 price since May 2011, and no doubt Canadian producers would love to take advantage of that spread. We believe the Horn River is particularly well suited for exports, since it is relatively closer to the coast of British Columbia than most other Canadian producing regions, and it is dry gas, so that would likely give it some cost advantage over more liquids rich gas that would first have to have those liquids removed.



But there are several major impediments working against potential Canadian LNG exports that may prove to be too difficult to overcome. One is obtaining firm supply contracts, and doing so at favorable pricing. Canadian LNG would flow to the Far East, and there are already several major projects being built to export LNG to that area, particularly in Australia. Every day that Canada is unable to start building its own export facilities is another day some other gas producing nation can. We believe many British Columbia export facility project owners are holding out hope that they can receive oil based prices for their LNG, even though we also think that buyers in the Far East would prefer prices that are linked to a gas index, such as the Henry Hub. A second challenge is that many of the proposed pipelines that would connect Canadian production to these B.C. export facilities are facing major Aboriginal resistance within the province. If such opposition does not prevent these pipes from being built, it may delay their progress long enough for buyers in the Far East to seek LNG from other nations. Finally, building LNG liquefaction facilities are extremely expensive, and the recent decline in crude oil projects will make it that much more difficult to obtain project financing, in our view.

We believe Kitimat LNG is an excellent case study on the future potential of Canadian LNG exports, at least in the shorter term. Kitimat LNG was the first of the proposed 17 projects to apply with the National Energy Board of Canada, which means it has had a significant head start over its competitors. In addition, its main owner is Chevron, a company with deep pockets and plenty of experience in the international LNG industry. These factors should give this project a major competitive advantage, but as of November 2014, Kitimat LNG still had yet to make its final investment decision. Moreover, and perhaps even more indicting, is that Apache Resources and EOG Resources, two of Kitimat’s three original sponsors, have pulled out of the project.

Chevron’s Jeff Shellebarger, President of North American E&P, noted on the company’s 3Q14 earnings conference call that while “Apache has announced their intent to fully exit the project, we are still committed to this project. We think that the low cost potentially prolific reserves up in the Liard and Horn River are going to make an attractive LNG project in time. We have been very clear that we will not take FID [final investment decision] at this project until we have gas contract signed and we know that we have got a value adding economic project.

With respect to FID, we haven’t given a data on that and we continue to do the feed work on the plant, the plant site. We continue to work with the government of British Columbia. We are encouraged by the recent news that’s come out of there with respect to how they want to treat LNG in taxes, but our primary focus up there is really the appraisal and the delineation work that we’ve got going on in the Liard Basin.” Chevron further states in the latest version of the Kitimat Project Overview on its website that “a Final Investment Decision for the proposed Kitimat LNG project will require a stable and competitive fiscal framework, greater cost and project execution certainty, additional First Nations support, and firm LNG sales agreements.”

The British Columbia government is certainly trying to do its part to help make the proposed LNG projects in its province a reality. In October 2014, provincial Finance Minister Mike de Jong pared the rate of a special tax on LNG export terminals down to 3.5% of net or after-expense revenue from 7% proposed last spring. As originally announced, the LNG export tax would be held down to a nominal 1.5% of terminals' net revenues until capital costs of building them are paid off. The policy sets a target of eventually regaining lost ground by raising the rate to 5%, but not until 2037.

The finance minister also outlined a forthcoming credit against general corporate taxes for "any LNG income taxpayer that has a permanent establishment in BC." Details remain sketchy. But the policy sets the highest rewards for terminal project sponsors that generate the greatest levels of northern BC gas drilling and production. "This credit will be calculated based on the natural gas acquired for an LNG facility," the government stated. "The credit will have the effect of reducing the provincial corporate income tax rate from 11% to as low as 8% for that company."

Provincial estimates of tax revenues from the first 10 years of operations by a typical LNG export terminal have been dropped to C$800 million ($712 million) from a forecast last spring of C$1.5 billion ($1.3 billion).

Two other potential catalysts for Horn River production could be the continued growth of Canadian Oilsands production, which requires a significant amount of natural gas, as well as any gas-to-liquids (GTL) projects that may be planned in the future. However, the latter option may not be imminent, especially since Sasol has already shelved a proposal to build a GTL project in the Montney Shale. 


British Columbia