Kitimat 'Right Project At Right Time' for Asian LNG Demand
Apache Corp.'s proposed Kitimat liquefied natural gas (LNG) project in the western Canadian province of British Columbia has already passed many milestones in the past two years, including the receipt of its export license in 2011.
Now, the partnership between Apache and Chevron Corp. for Apache's Kitimat LNG project and shale assets in Western Canada, which was finalized earlier this month, will create a strong and experienced team that will enable the two companies to bring the project to fruition.
The partnership, announced Dec. 24 of last year (link in first part of sentence), will draw on the two companies strengths: Chevron's experience as a renown LNG developer, and Apache and its ability to explore for and develop shale resources, said Janine McArdle, senior vice president of gas monetization with Apache and president of the Kitimat LNG project, at the Platts 12th Annual Liquefied Natural Gas Conference last week in Houston.
Chevron entered the partnership as a 50 percent owner through the full value chain of Kitimat and Horn River and Liard shale assets. The companies also acquired additional acres from Kitimat partners EOG Resources Inc. and Encana Corporation during the process of Chevron entering the partnership, giving them a 220,000-acre position in the Horn River play and 424,000 acres in the Liard play.
Chevron brings to the table expertise with LNG projects in Angola in West Africa and the Gorgon and Wheatstone LNG projects in Australia, while Apache's efforts developing the Horn River shale in Alberta over the past seven to eight years has enabled the company to bring costs down, McArdle told conference attendees.
Chevron and Apache already have a relationship in the LNG space through the Wheatstone LNG project, so it made sense for Apache to approach Chevron as a potential partner for Kitimat, McArdle commented. Chevron holds a 64 percent interest stake in Wheatstone, which is scheduled to begin delivering LNG at the end of 2016, and Apache holds 13 percent interest.
"We feel these two projects together as partners position us quite well for the markets naturally looking for Western Australia assets as well as diversity into Canadian LNG," McArdle commented.
At this time, the Kitimat partners are working to derisk the project schedule and cost and understanding the rocks after clearing trees from the hilly site, including the placement of the tanks, a critical part of an LNG development schedule. Because the site has marine clays and granite, the site's elevation will be changed to better accommodate the infrastructure. Rocks will be grinded from the site to use for roads to improve accessibility to the site.
The Kitimat partners are also working on derisking the construction schedule for the pipeline that will bring supply from the Horn River and Liard plays to the Kitimat export terminal. It will take approximately three years to clear the pipeline route and construct the 42-inch, 287-mile 463-kilometer pipeline, which starts in a benign area but traverses into rough, mountainous terrain. The pipeline will be capable of carrying 10 to 20 million tonnes per annum. Because of weather and migratory animal patterns, the companies are working now to derisk the pipeline cost and schedule, McArdle noted. First Nations native group will handle logging activity around the pipeline route, which creates a win-win situation for everyone, McArdle said.
U.S.-based producer Apache is moving forward with the Kitimat project to seek new markets for Canadian shale gas.
"Back in the 2000s, when prices were $10 to $12, everything was economic, and therefore we we had lots of time to explore these shales and technology. Over time, we got very good at what we did, so good we found too much resource in Canada and Lower 48," McArdle added.
In addition to growth in shale gas during the 2000s, liquids rich shales in the Lower 48, or continental United States is allowing production of natural gas to continue even at a time of low natural gas prices, resulting in production off the chart, said McArdle. Because of that, supply is backing up into Canada, which only uses 6 billion cubic feet a day (Bcf/d) to 7 Bcf/d and exports between 9 Bcf/d and 11 Bcf/d, depending on the season. Currently, Canadian gas exports into the United States are down by half.
Canadian LNG exports would appear to be a natural fit for meeting LNG demand in Asia, where LNG prices are linked to oil, and demand is on the upswing in countries such as China, where demand has gone from nothing in the 2000s to 24 million tonnes per annum, with forecasts calling for that demand to double by 2020. The only constraint on China is when LNG import terminals will be constructed, McArdle commented.
Japanese LNG demand has also risen as the country seeks to replace nuclear power with LNG to meet demand after the 2011 tsunami and earthquake in Japan that crippled the nation's nuclear power facilities, McArdle noted.
However, Canadian LNG export projects face a number of issues, including rising costs. The fact that no brownfield sites exist on Canada's west coast, means Canadian LNG export projects must be constructed on greenfield sites, to the cost, and will require a pricing mechanism that will underpin LNG projects at a fair return.
The fact that gas prices in the Lower 48 and Canada are very regional – with prices all over the place at some points – also presents another financial challenge. McArdle, who has worked in the industry for the past two decades, has seen gas prices trading as low as $2.20/MMcf (million cubic feet) in 2000 to between $7 and $12/MMcf in 2005.
The full cycle cost of LNG economics means that producers really need $5/MMcf, not $3 or $4 dollars, so they can pay their shareholders and workers, said Bill Gwozd, senior vice president of gas services at Ziff Energy.
Due to the capital-intensive nature of LNG projects, LNG projects will require stronger incentives on pricing from a buyers' perspective, depending on the risk profile. A more transparent pricing mechanism than Henry Hub will be needed to underpin the investment at a fair return or LNG projects will not get built, said McArdle.
A more transparent pricing mechanism exists for oil versus gas, McArdle said. While gas prices in the United States and Canada are more volatile because there are captive markets, oil prices are more impacted by global economies and needs, since oil is in everything.
Additionally, more pipeline capacity will be needed into the Kitimat and Prince Rupert areas on British Columbia's west coast to supply gas to planned LNG export terminals in these areas. Discussions have been underway with TransCanada Corporation, Spectra Energy and Enbridge Inc. to expand pipeline capacity into the area from the existing pipeline grid.
However, Apache believes the Kitimat project is the right opportunity at the right time. The project has the backing of both the British Columbia government and First Nations tribe, as well as a prime acreage position in the core of the prolific shales in the Canadian markets. Apache has also successfully lowered the cost of producing its Horn River and Liard assets thanks to technological advances, said McArdle.
Additionally, the LNG facility and pipeline have received all major environmental permit approvals, and a deepwater site on the British Columbia coast that faces no threat of hurricanes.
"We see ourselves as well positioned for success," McArdle concluded.
Apache led the way in terms of working out the wrinkles in the LNG project application process, said Nick Kangles, senior partner and co-chair national energy group at Norton Rose Canada LLP. Traditionally, Canada's National Energy Board (NEB) has had two processes through which companies could apply to export gas from Canada – a short-term process that allows exports for up to four years, and a second process for exports of up to 25 years. The latter type of license is what Apache and other LNG project backers have obtained.
No long-term gas export license application had been submitted for several years prior to the first LNG export license application, with most Canadian gas exports to the United States being done on a short-term basis. NEB has been working with counsel to streamline the process, Kangles noted. The agency will focus on whether enough gas supply exists to meet Canadian demand when deciding, not Aboriginal rights and environmental concerns and uses of the port, as other agencies exist that can address these issues.
Apache Took Right Approach on Native Land Rights Issues
The company also took the right approach by dealing with Aboriginal land rights issues right away, pursuing the necessary relation and agreement building with these groups. Acreage proposed for the Kitimat pipeline route includes land that falls under First Nations tribal lands. In Canada, Aboriginal tribes have strong rights that, over time, have been developed through treaties and court decisions. As a result, companies have a duty to consult with Aboriginal tribes that can become a duty to accommodate needs or make financial arrangements to make up for financial damage done to a certain group.
The sites in British Columbia where LNG export terminals have been proposed run through First Nations and treaty areas.
Even in the western half of British Columbia at the port sites, no land treaties exist but companies still must deal with land claims.
The Canadian political environment remains favorable to LNG projects, with the Canadian federal government encouraging investment in Canadian LNG projects by foreign companies.
The British Columbian government supports LNG export terminals has a way to create economic growth and jobs in the province. Major progress has been made towards the BC Jobs Plans goal of having three LNG facilities operating in British Columbia by 2020, according to a report released this month by the provincial government. LNG development is currently expected to create an average 39,000 new full-time jobs during a nine-year construction period. As many as 75,000 new, annual full-time jobs could be created once all LNG plants are in full operation.
Over the past year, approximately $6 billion has been invested to prepare and accelerate the province's natural gas sector growth prospects and an additional $1 billion to further LNG proposals. The number of large projects proposed has also risen to five from the two facilities proposed for development when the province's LNG strategy was released last year, according to the report.
If five large LNG plants are built, the cumulative gross domestic product benefit to British Columbia is expected to add up to $1 trillion by 2046. LNG also will increase long-term revenue-generating gas production in northeast British Columbia. Based on higher production volumes alone, at least $1 billion in royalty revenues could be achieved by 2020 from the first three LNG projects.
In December of last year, the Canadian government changed its rules for reviewing investments in Canadian companies by foreign state-owned enterprises, such as limiting access to Canada's oil sands. The changes primarily impacted investment by state-owned entities, but not investments by other types of foreign companies.
In terms of LNG, the rules didn't change at all, Kangles noted.
"The test has always been since the Investment Canada Act was implemented that the transaction must be for net benefit of Canada," Kangles commented, noting that there has been very little interference over time into investments by foreign companies in Canada.
Though it holds a relatively small share of the world's proven natural gas reserves, Canada ranks third in dry natural gas production, according to a 2012 report by the U.S. Energy Information Administration. The country is the fourth largest exporter of natural gas behind Russia, Norway and Qatar.
Canada's technically recoverable shale gas resources are estimated at 388 trillion cubic feet (Tcf), 355 Tcf of which are in five large sedimentary basins in Western Canada with thick, organic-rich shales. These basins include the Horn River, Cordova Embayment, and Liard in northern British Columbia, the Deep Basin/Montney in central Alberta and British Columbia, and the Colorado Group in central and southern Alberta. The Horn River Basin accounts for the largest share of the total resource.
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