EnCana Corporation (ECA)
October 04, 2011 11:00 am ET
Michael M. Graham - Executive Vice President and President of Canadian Division
Kevin Smith - Vice President of the Fort Nelson Business Unit & Canadian Unconventional Gas Exploration
Ryder McRitchie - Vice President of Investor Relations
David Thorn -
Mark Gilman - The Benchmark Company, LLC, Research Division
Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Horn River Conference Call. As a reminder, today's call is being recorded. [Operator Instructions]
I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations. Please go ahead Mr. McRitchie.
Thank you, operator, and welcome, everyone, to the first of our planned 2011 conference call series. In place of our traditional Investor Day and field tours, we felt it was more effective to feature 2 key areas in our portfolio that have been receiving a lot of investor attention. Today's session focused on the Horn River. We'll highlight the worker teams have been doing over the past year and how this has lowered our overall cost structures and how this resource play truly is a world-class asset.
We have scheduled a second call for Wednesday, November 2. It will focus on our Haynesville Shale resource play, and we will also provide an update on our U.S.A division, operations and market fundamentals at that time.
But first, before we get into our presentation, a bit of housekeeping. As we will be talking about Encana's future, I need you to be aware of this advisory -- of our advisories regarding the use of future-oriented information that will be stated in today's presentation.
In addition, Encana is a Canadian-headquartered company. Therefore, I'm required by Canadian Securities regulators to encourage you to read the advisories located at the end of this presentation, which have also been posted to our website at www.encana.com.
We report our financial results in U.S. dollars and our operating results according to U.S. protocols. Encana's production volumes and reserve quantities are reported on an after-royalties basis unless otherwise noted. So now onto our presentations.
Mike Graham, Executive President and President of our Canadian division will start off with a brief overview of Encana's Canadian portfolio and ongoing efforts to continue to reduce cost structures. Then Kevin Smith, Vice President, Fort Nelson Business Unit & Canadian New Ventures, will get into the details of our Horn River resource play. And then Dave Thorn, Vice President of Canadian Marketing, will conclude with a discussion of the Western Canadian pipeline and infrastructure, including our plans for the Kitimat LNG facility. And then we will open up the lines for questions.
I will now turn the call over to Mike.
Michael M. Graham
Thanks, Ryder. Good morning, everyone. I'm excited to speak to you today about our operations in the Horn River. Encana is and has been the industry leader in the application of technology in trading the highly successful resource play development model now widely used in North America. Because of the success of this development model, oil and natural gas plays that were among the highest costs to develop just a few years ago are now among the lowest. Natural gas has gone from being in short supply to being abundant. And the production of oil and natural gas liquids is on a growth curve in North America for the first time since the mid-'70s.
Encana's industry leadership has positioned us well. We have a great asset base and innovative value-driven team, and we have a clear vision for the future. Our goal is to achieve the greatest long-term value creation for our shareholders while at the same time stewarding the company both financially and operationally to maintain and grow shareholder value in the short term.
Today, Encana is one of North America's largest natural gas resource play companies with among the largest and highest quality portfolio of undeveloped resources. Encana is the largest natural gas producer in Canada at 1.5 billion cubic feet equivalent per day and the second largest producer in North America at 3.5 billion cubic feet equivalent per day. Because we entered these plays at an early stage, we have amassed large concentrated contiguous land positions in the core of many of North America's best natural gas resource plays at low costs. Our portfolio also includes large land positions in what we believe to be the highly prospective oil and liquids-rich natural gas plays. We now hold more than 2 million net acres that are prospective for natural gas liquids and oil. With almost 12 million net acres of land, we are very well-positioned, usually in the heart of the play, in every region in which we operate. If you include the additional land where we have royalty interest, we have close to 13.5 million net acres.
In the Canadian division, we have about 9.3 million net acres of land, the majority of which is comprised of large contiguous land blocks. I like to say that no one is better positioned for growth in Canada than Encana. From the second quarter of 2010 to the second quarter of this year, the Canadian division increased production by 9% to over 1.5 billion cubic feet equivalent per day with Deep Panuke volumes coming on in early 2012 at somewhere between 200 to 300 million cubic feet per day. Growth again in 2012 should be very strong for Encana's Canadian division.
We are also starting to transition the Canadian division to more liquids production, and we are well-positioned in several emerging liquids-rich plays. Encana is well-positioned in the Deep Basin of Alberta and British Columbia where we plan to increase natural gas liquids production from 10,000 barrels per day to 30,000 barrels per day in the next couple of years by putting in deep cut facilities. The first of these should come on in the fourth quarter of this year at [indiscernible], thereby increasing Encana's liquids production by around 5,000 barrels per day. We have also assembled 365,000 net acres, including royalty interest land in the Duvernay. And we are drilling 2 horizontal wells prior to year end, which will help us delineate this exciting liquids rich play in Alberta.
In the natural gas industry, technology advancements are occurring quickly. At Encana, we embrace these changes and use technology to our advantage. We're drilling longer laterals. In the Montney and in the Horn River, we've drilled horizontal laterals to more than 10,000 feet, and we are designing larger completions to optimize recovery and reduce supply costs.
Encana has about 278,000 net acres of land in the Horn River. Production for the second quarter of 2011 average about 85 million cubic feet equivalent per day, and we are targeting an average of 95 million cubic feet equivalent per day for this year.
For background, in early 2003, Encana was drilling a Middle Devonian [indiscernible] test when the well took a kick in the Muskwa shale formation. While the primary objective did not yield economic gas rate, this significant gas shale in the shale formation intrigued the geologists on the team. Once we assessed the potential of this resource and made preliminary estimates around deliverability, infrastructure and marketing, we made a decision to move ahead with land acquisition and we developed a 50-50 partnership with Apache.
Today, the Horn River has taken the form of multi-well pads with as many as 16 horizontal wells with up to 28 completions stages in each horizontal well. Encana and Apache's part of the Horn River is currently producing close to 300 million cubic feet equivalent per day on a combined gross raw basis.
Now before moving on to talk about the resource play hub, I want to provide some context for why this form of resource play development is so important and how this fits into Encana's approach to value creation. We believe that our 6-faceted approach to value creation will deliver strong results, not only in the near term, but also well into the future. Each of these 6 components are aligned with our corporate goals of unlocking the value that is not being recognized in our asset base. As today's conference call focuses on the Horn River and the work we've been doing there to reduce costs, our presentation this morning centers on the detailed discussion of resource play hub, the third bullet here highlighted in orange, and how this framework combined with careful sourcing and supply management initiative has been integral in helping to lower Encana's overall corporate supply costs.
This slide shows a 3D cross-section of the resource play hub. It is what a typical pad in the Horn River would look like. Designed for operational efficiency, cost reduction and to reduce our environmental footprint, resource play hubs are at the heart of Encana's goal to lower our supply costs to $3 per thousand cubic feet equivalent over the next 3 to 5 years, and some of our plays are already there. This development mile starts with the resource play or what we call highly concentrated resources with contiguous land tracts. The underlying resources are developed using multiple long-reach deviated or horizontal wells drilled from central well sites.
In the Horn River, we have natural gas in place of up to 230 billion cubic feet per section and up to 250 billion cubic feet per section in the Montney, a tremendous resource per section. Repeatable operations lend themselves to ongoing optimization of equipment and processes, using continuous improvement techniques. New fit-for-purpose equipment and processes further drive down unit costs. The end product is a resource play hub, highly efficient, low cost, low-impact development.
Corporately, we've reduced our supply costs. That is, the flat NYMEX price that yields an after-tax rate of return of 9% by 25% since 2008. Today, our corporate supply cost is approximately $3.70 per thousand cubic feet equivalent, which includes about $0.30 for general and administrative expenses. It is our goal to continue to reduce our supply cost to $3 per thousand cubic feet equivalent over the next 3 to 5 years.
Before turning the call over to Kevin Smith who will talk about the Horn River, I wanted to discuss industry inflation briefly and the steps we've been undertaking in the Canadian division and at Encana more broadly to minimize our exposure to cost inflation.
There are number of factors that are currently affecting inflation in our industry. The key elements that are pushing market inflation up are wages, steel and services.
Although Encana is primarily a natural gas company fluctuations in oil prices have a significant impact on our costs. First is the direct costs of diesel to run our equipment. Second is the demand for services and margin expectations from service companies, particularly, for completion services. These inflationary pressures are expected to recede in the coming years as new equipment becomes available in the market. At Encana, we have adopted a proactive approach to eliminating bottlenecks and mitigating the risks associated with inflation.
A few of the initiatives we are undertaking include load leveling our operations, establishing long-term contracts with our service providers, direct sourcing of input commodities and as I mentioned earlier, focusing on continuous improvement in our operations. Importantly, all of these initiatives center around the Encana resource play hub. Our ongoing efforts to offset inflation are paying off. While we are forecasting industry inflation in Canada for 2011 of somewhere between 7% to 9%, we expect Encana's realized inflation to be between 4% to 6%, with a bias towards the lower end of that range. Our continual focus on capital and operational efficiencies through the resource play hub development model will help us to more than offset forecasted increases.
I'll close my part of today's presentation this morning with a few high-level points that summarize why Encana is a leader among North American energy companies. We are a leading resource play company with a large diversified and low-cost asset base in many of the most prolific basins across North America. We are fiscally responsible and we have the innovative value-driven culture needed to thrive in this highly competitive industry. We are focused on pursuing long-term value creation for our shareholders.
Thank you. I'll now turn the call over to Kevin Smith.
Good morning, and thanks, Mike. I'm Kevin Smith, Vice President, Fort Nelson Business Unit & Canadian New Ventures. I'm very happy to have the opportunity to speak with you this morning about some of the exciting initiatives our teams have been undertaking in the Horn River.
The primary focus of today's conference call will be to showcase all of the components of Encana's Horn River asset and how each of these pieces work together to make this play a truly world-class asset. The Horn River has all the characteristics of a great play. It has a large high-quality resource in place in which we apply Encana's resource play hub strategy. It is well connected to natural gas infrastructure and is well backed with a strong regulatory system and competitive government fiscal policy.
I'll start with an overview of the resource and then move on to our innovative development approach, the resource play hub. I'll also discuss the favorable royalty regime and government support that we have in Horn River and the assets, connectivity and market. Lastly, we'll review the investment returns we currently receive and where we see things go in the future.
First, the resource. As Mike mentioned earlier, Encana first discovered the Horn River in 2003. Once we had a good understanding of the potential of natural gas resource in plays, we then began quietly and inexpensively accumulating our land position. With the advent of horizontal, multi-stage completion technology, producers quickly move to secure large-scale positions. And between 2006 and 2008, the vast majority of the acreage in the basin was leased.
The Horn River basin covers over 2 million acres, making it one of the most prolific gas plays in North America. Today, we have a significant land position here, as Mike mentioned, of 278,000 net acres or about 435 net sections of land. This is a sizable asset for Encana with significant growth potential.
The resource base in the Horn River is enormous, highly accessible and will certainly play a key role in North American, Canadian global gas supply in the years to come. We estimate a total basin resource size of approximately 500 Tcf of natural gas in plays. On Encana lands, natural gas in plays ranges from 130 to 230 Bcf per section, equating to a total of about 90 trillion cubic feet.
The Horn River shales are great rocks that are up to 180 meters thick with all of the attributes needed for productivity, those being permeability, porosity, organic content, brittleness and all in an over pressured reservoir system. As we optimize our drilling in the Horn River, we see that results keep getting better and better, the wells are prolific and economics work even in tough gas markets.
The Horn River also has high initial production rates relative to other North American shale gas resource plays, but it also enjoys a generally lower decline rate, particularly in the first years of production. Importantly, this contributes to a very attractive EUR results. On average, we experience about 0.75 billion to 1 billion cubic feet of natural gas per interval on our Horn River wells.
Next, I'll discuss some of the exciting work our teams have been doing in the Horn River to advance our resource play hub design. Full-scale implementation of this model not only means optimizing below-ground operations such as perfecting completion techniques or developing the optimal well spacing for the reservoir, it also means designing our aboveground operations to function in the most cost-effective and efficient manner possible.
At 63-KPad pictured here, we designed our resource play hub to have all the elements for resource development contained within a very small surface area. Encana's 63-KPad is an example of a 14-well Horn River design with concurrent drilling and completion operations all within a minimal footprint of one pad. Not only is this important from an environmental conservation perspective, wells on a 16-acre surface area actually drain something close to 6 square miles of reservoir, but helps us to optimize the location of all the equipment we need: coal tubing, completions equipment, wire line units and drilling and all of the other materials that we need such as diesel, wire and sand supplies are close at hand.
Encana deploys the same industry-leading resource play hub strategy in Horn River as we do across our portfolio in plays like the Haynesville, Piceance, Montney and coming soon to the Duvernay. Encana has created a culture of innovation within the company around the resource play hub as it encourages teams to continuously improve the model and to not be satisfied with the status quo. But all performance and costs have improved leaps and bounds and we've yet to find a limit of the resource play hub exploitation strategy.
This map highlights Encana Horn River lands with the Two Island Lake area on the right and our farm out with Korean Gas Corporation or KOGAS, the Kiwigana, on the lower left.
As you can see, there's still considerable amount of acreage developed over both properties. There have been some key themes to developing the Horn River over the past 4 years. In 2008, our program focused on assessing that potential. The B-C76-K 10-stage well with no major offsetting wells was critical since its success led us to verify reservoir deliverability.
In 2009, we completed a 4-well downspacing pilot with 14 stages per well and achieved results that demonstrated commerciality.
In 2010, we concentrated on execution excellence, further extending the lateral length of our wells up to 10,000 feet in a number of completion stages to well over 20,000.
This year has been about understanding our tight curves and optimizing our per-interval spacing as well as continued cost-reduction efforts. 2011 has seen the first pad drill in Kiwigana with the next 2 pads being drilled by the end of 2012. Completions will be starting on the first pad in Kiwigana later this month. We've been very happy with our partnership with KOGAS. And earlier this year, we expanded our partnership with the farmout of an additional 31 growth sections.
For 2012 forward, the Horn River play is well-positioned with key infrastructure in place, a solid understanding of the reservoir. We are in a position to remain flexible in time of natural gas prices fluctuating.
The Horn River resource play hub design has changed and continues to evolve as we learn more about this huge reservoir and how we can best tap into its potential and optimize the gas recovery per well.
What you see here is an example of how we are working to understand how to best stimulator reservoir by optimizing inter-well spacing and the inter-stage completion spacing. This shows how we are increasing our frac spacing from 8 to 14 to 30 acres, which will further reduce our supply costs. We are working to optimize our well spacing in order to maximize value while developing the most resource from a single pad location. Encana has been increasing its lateral well lengths and number of frac stages over time, and is seeing corresponding increases in production with these wells. We've increased the number of stages from 3 in 2007 to as many as 30 this year with demonstrated improvement in production rates and well recoveries.
In September, we began bringing on our latest pad, the 1-D pad where early results have initial production rates in excess of our benchmark, 63-KPad. With the larger per-interval spacing on 1-D, we are expecting to see a higher recovery per stage than we will see on the 63-KPad.
The star shown on this production chart represents the first 2 weeks or so of production on the 1-D pad.
This an example of what the Horn River team has achieved as we've been implementing our resource play hub strategy. The slide shows costs improving over time with a percentage of supply costs attributed to well capital and operating expenses decreasing from 66% in 2009 to 60% in 2010 with a forward-looking target of driving these costs down to only 54% of our supply costs. Most of these improvements to date have come from a combination of lowering costs and improving well performance. The main drivers have been increasing the number of intervals in our longer laterals, becoming more efficient in our completions and self-sourcing many of our consumables. In conjunction with our lower costs, more reserves accessed per pad and improved production performance have also led to lower supply costs.
The same way we optimize our fit-for-purpose drilling equipment over the past decade, we are now exploring opportunities with our existing completion service provider to work together and redesign how our completion programs are executed with using new technology such as natural gas-driven frac pumps.
Initiatives like cabin gas plant, which will increase competition in the midstream space and the Kitimat LNG terminal, which had reduced the market differential, both impact the green space above. This potential decrease has not been captured in the target supply cost represented here from $3.50 to $3.75 per thousand cubic feet.
Our ability to source water cheaply is key to cost-efficient development to the Horn River resource. Surface water was initially used to provide -- approve the feasibility of the play, but is not sufficiently available at Two Island Lake to meet our demands from either a rate or volume perspective. Source from a highly -- high permeability carbonated formation at 800 meters depth, Debolt water has proven to be a viable, nonpotable source of water for our Horn River operations. We designed a code system that processes 16,000 cubic meters per day, giving us enough water now to execute up of 3 to 4 completions per day. The Debolt water has been a win-win for the Horn River as it lowers the fresh water usage while also increasing efficiencies in our completion operations. Over the 3 pads completed this year, about 95% of completion fluid was sourced from the Debolt.
Continuous improvement is a fundamental mindset in our operations. There have been some exciting new technologies employed in the Horn River by Encana this past year, which have been working to reduce our operational footprint and create efficiencies to further drive our supply costs down.
For example, at Kiwigana, we will use a buried surface rig to collect microseismic data during the entire completion operation. This data will allow us to optimize future completion designs.
The second examples are adoption of the use of soil stabilizers to replace more costly wooden mats on drilling pads. The soil stabilizer technology provides a hard durable surface that will last 5 to 10 years and will improve safety. Reclamation is simple and inexpensive.
A third example is Encana's newly constructed sand tent at Kiwigana. Sand tent holds up to 25,000 tons of sand and its primarily use is as a buffer to ensure that we always have adequate low-cost supply of sand for completion operations. If we have a disruption in supply of any consumable, we incur nonproductive time, or NPT, where we pay for equipment and services that are not being fully utilized.
Additionally, we're implementing the use of bi-fuel completions equipment. After using natural gas fuel drilling rigs in the Horn River over the past 3 years, Encana has successfully piloted the use of bi-fuel system on our vendors completion fleet. The equipment runs on natural gas and diesel to power pumping equipment. It's projected to reduce our diesel costs by up to 60%.
Encana is also proceeding ahead with further fit-for-purpose completions initiatives that, along with reducing our diesel consumption, are expected to reduce our overall environmental footprint and improve maintenance costs.
Government support and a competitive fiscal regime is important with the resource that has this much potential, but is distant from the end markets. The province of British Columbia has designed a fiscal regime that is responsive to market changes. The Net Profit Royalty Program helps to establish commerciality and competitiveness of the Horn River Basin by recognizing that the asset is a long way for markets. We have a highly competitive royalty structure at Two Island Lake where we pay a 2% royalty until project payout inside the ring fence or 10 years, whichever is sooner.
Additionally, the infrastructure credit program encourages development in new or remote areas. In the early years of development, it is critical for a play like the Horn River to have the benefit of program such as this that recognize the significant upfront infrastructure costs. The Deep Royalty Credit is a targeted program that provides upfront royalty relief to incent drilling activities in plays like the Horn River where deep long-reach, multistage horizontal wells are the norm. And more recently, it's encouraging that the B.C. government has been very vocal in its support of a future LNG industry for the province.
Compared to other North American shale plays, the Horn River is very competitive on royalty and taxation front. On average, royalties are about 5% lower than many of the largest U.S. shale plays, including the Haynesville, Marcellus, Fayetteville, Barnett and the Eagle Ford. We also have lower taxes than these other plays. On average, about 20% lower. These progressive royalty and tax terms provide an offset that approximates the forecasted AECO to Henry hub differentials. When combined with the long mineral tenure that we have on our Horn River land, this fiscal and regulatory regime allows for a logical and methodical development of this play.
Market connectivity is important, too. And despite its remote location, the Horn River does have options. The Horn River is well-connected to infrastructure and has the option to deliver into multiple markets. In addition to the traditional markets in Canada and U.S., the potential exists for the Horn River to access some of the key growth demands centers such Alberta oil sands and the future West Coast LNG export terminals. Encana recently purchased a 30% working interest in the proposed Kitimat LNG facility and Dave Thorn, who's speaking next, will provide an update on Encana's involvement.
Before turning the presentation over to Dave, I'll spend just a brief moment reviewing the strong investment returns we're seeing in the Horn River today and what we expect in the future. As I mentioned earlier, our target supply cost for the Horn River falls in the $3.50 to $3.75 per thousand cubic feet. The left graph shows the target Horn River supply cost versus the forward strip prices as of last month. Even at current breakeven prices, there will be sufficient margin to incent producers to develop this vast resource in the future.
The right-hand side shows the CERA Basin forecast, that has the Horn River reaching 2 billion cubic feet per day by 2015 and 5 billion cubic feet by 2020. In the right price environment, this is very achievable. The star represents the approximate current production in the basin at about 375 to 425 million cubic feet per day. The Horn River is a world-class natural gas shale basin that Encana believes will play an important role in meeting North American and Asian energy markets demand requirements.
Within the Encana portfolio, the Horn River represents a significant growth potential, not only because of the norms resource in place, but also because of the remarkable advancements we've been able to achieve in terms of operating efficiency and cost reduction, advancements that are shared across the entire Encana asset portfolio. The Horn River play is very much in its infancy, and we believe we are very well-positioned to grow with a strengthening price environment.
With that, I'll pass the presentation on to Dave Thorn.
Thank you, Kevin, and good morning. I'm Dave Thorn, Vice President of Canadian Marketing. This morning, I'm going to discuss our Kitimat project and the Pacific trails pipeline, as well as an overview of natural gas demand in the Asian marketplace today and out to 2020.
Encana holds a 30% working interest in the proposed Kitimat facility, located in Bish Cove, British Columbia, about 650 kilometers north of Vancouver. Our partners in this facility are EOG who also has a 30% working interest and Apache who has a 40% working interest and is operator. The facility has a proposed export capacity of 1.4 billion cubic feet per day, comprised of two 700 million cubic feet per day phases. The front-end engineering and design or FEED study is being completed this year, following which final investment decision will be made, and we expect to ramp up construction in 2012.
For Encana, one of the benefits that we see this project as providing is an opportunity to convert a portion of our natural gas production to crude oil linked pricing. The Kitimat project may be source for many of our British Columbia or Alberta natural gas resource plays, and we expect it to contribute to an overall increase in natural gas prices to a more sustainable level.
Natural gas supplied to the Kitimat project will be transported on either the Spectra or TCPL systems, or both, to station 4A, which is the interconnect of the Pacific Trail Pipeline.
Expanding partially within an existing right of way, the Pacific Trail Pipelines is expected to be 465 kilometers in length. The new pipe will be a 36-inch high pressure line designed to move 1.4 billion cubic feet per day of natural gas. Compression requirements will be a function of the capacity of the Kitimat facility. More compression will be required to service the second train that would take the facility from 700 million cubic feet per day of capacity to 1.4 billion cubic feet per day.
An additional 15-kilometer spur will also be required to move the gas from the Pacific Trail Pipeline to the Kitimat facility. We expect the pipeline to be in service in 2015, commensurate with the start-up of the Kitimat LNG facility.
Kitimat is well situated for shipping LNG to Asian markets, and we're not alone in seeing the potential benefits of exporting natural gas in North America. Already there have been several other LNG project proposals announced by other industry participants. However, before we proceed with the project, we need to get more clarity on the overall project economics. The 2 key components are obviously greater revenue and cost certainty.
On the cost side, we're currently undertaking a FEED study, which is being undertaken by Kellogg Brown & Root, or KBR, and they are working currently towards delivery of a cost estimate. KBR has significant LNG experience worldwide. Their construction accounts for over 85 million tons per annum of worldwide liquefaction capacity, often in challenging locations with reliable and consistent performance. The Kitimat project is based upon KBR's experience with the sea gas LNG facility in Egypt, which is also located within compact plot size and operating on sales quality gas. It will include electric motor-driven refrigerant compressors with supply -- power supply from the local grid. Kitimat has its environmental impact certificate in place, and we have recently completed the National Energy Board hearings for the projects export license, a total of 1.4 billion cubic feet per day over a 20-year period. The process went very well and a final ruling is expected later this month. First exports are expected to be in late 2015.
On the revenue front, led by Apache, we are participating in the negotiation of potential off-take agreements. The discussions are based on volumes associated a with 2-train facility. As with current contracts in the region, we expect there to be a linkage with Japanese Custom-Cleared or JCC crude pricing. There's been very strong interest to date. The expression of interest range from simply LNG supply to existing our planned regasification facilities through the participation all along the value chain, including shipping, equity interest in the Kitimat facility, as well as upstream participation. We expect to have contracts for significant portions at Kitimat capacity in place to support the final investment decision expected in early 2012.
Demand for natural gas in Asia is expected to be very strong through the 2020. Countries are seeking to both meet their forecasts growth, as well as to diversify their sources of supply. The highest growth regions are expected to be India and China. Japan is still expected to be a significant market, and depending upon their decisions regarding nuclear capacity, could provide additional upsizes in terms of market growth. And there are all a number of other Asian-based countries that we anticipate will have growing demand.
China represents the largest potential source of demand growth for natural gas, which will be supported in part by LNG imports. The best case scenario projects Chinese demand for natural gas will increase from approximately 10 million cubic feet per day in 2010 to about 35 billion cubic feet per day by 2020. This assumes that natural gas represents about 8% of the country's total primary energy demand. If the government plans to change natural gas' share of primary energy demand by 2020 to 10% come through, China will need an additional 15 billion cubic feet per day of supply to meet that requirement.
As you can see, there is a gap between supply sources and contract in LNG in Asia. Additional LNG import contract requirements are expected to decline from less than 1 billion cubic feet per day in 2010 to about 24 billion cubic feet per day in 2020. The potential demand increase could require an additional 15 billion cubic feet per day of LNG imports by 2020, if China follows through with its plans to increase natural gas share of market.
The additional potential demand shown by that light blue line is approximately 15 billion cubic feet per day. And as mentioned, it's the difference between natural gas in China reaching 8% of primary energy demand to its new target of 10% in 2020.
In summary, the next steps for the Kitimat project include: Phase 1 early site work include site preparation and geotechnical data gathering. That work has already begun. In addition, the project has received approval to proceed with site preparation and work is being completed to finalize decisions related to the material offloading facility, roads, power lines, camps and catering. The project group has also acquired an industrial site close to Kitimat that will initially be used for logistics purposes. We expect the FEED study to be completed by year end and expect to be in a position to make a final investment decision in the first quarter of next year.
The project is moving forward and we're very excited about market demand for LNG. North America is well-positioned to participate in that growth.
Thank you for listening to my presentation this morning, and I'd like to return the call back to Ryder McRitchie.
Thanks, David. So this concludes the formal part of our presentation. As a reminder, a video showcasing Encana's operations in the Horn River is now available online. The website address is stated on the slide above, as well as in our news release.
Thank you for participating in the conference call today, and we'll now open up the lines for questions.
[Operator Instructions] Your first question comes from the line of Mark Gilman with Benchmark.
Mark Gilman - The Benchmark Company, LLC, Research Division
Two questions, if I could. First, although it may be a little bit early, can you give us any rough assessment of the all-in cost of moving Horn River gas from the well head into the Asian market as LNG on a delivered basis? My second question relates to what you might be able to say at this point to Horn River level of activity from a drilling standpoint, 2012, 2011 per-year indications, the well count, net well count drop-down, do you envision it moving it back up in 2012 or is that going to be a function of the price environment at the time?
Michael M. Graham
Yes, Mark, thanks for your question. I guess, the first one we'll turn over to Dave Thorn.
Yes, I think it's probably a little preliminary at this point to give in all-in delivered costs. As you are aware, FEED studies are underway for both the PTP pipeline and the Kitimat LNG facility. And until we have a better handle on where those costs truly come in, obviously difficult to translate that into all-delivered costs. Needless to say that the spread between Asian pricing and what we're seeing in North America looks very supportive, but to give you an actual cost at this point is probably preliminary.
Michael M. Graham
Mark, Kevin Smith can probably answer your second question. I think it's safe to assume that though Encana is trying to move part of our portfolio to more liquids-rich plays and obviously with the price of liquids rich or oil, as you will, compared to natural gas, we'll be moving a bit more of our capital towards those plays. But Kevin can answer specifically on the Horn River.
Sure. Thanks, Mark for that question. We are still working through our detailed budget process, but directionally, we're looking at reducing our activity at Two Island Lake. We get a fair amount of results from 2011 from the 3 pads that we brought on that we're really going to watch and given the price environment, it's probably the right thing to just pull back a little bit. At Kiwigana with our joint venture with KOGAS, we will be continuing on with our operations there. We'll be completing the first pad we drilled up a little later on this month. And we will be having 2 more pads that we will be drilling after -- to the end of next year.
[Operator Instructions] There are no further questions at this time. We have completed the question-and-answer session.
We will turn the call back over to Mr. McRitchie.
Okay, I would like to thank everybody for joining us today. If you have any follow-up questions, please feel free to contact our Investor Relations group or Media Relations team, and we look forward to talking to you then. Thanks again, and have a good day.
This concludes today's conference call. You may now disconnect.
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