Encana Corporation - Special Call

| About: Encana Corporation (ECA)

EnCana Corporation (NYSE:ECA)

November 07, 2011 11:00 am ET


Eric D. Marsh - Executive Vice-President And Senior Vice-President Of Usa Division

David Nicks -

Paul Sander -

Lorna Klose -


Michael P. Dunn - FirstEnergy Capital Corp.

Peter K. Ogden - BofA Merrill Lynch, Research Division

Menno Hulshof - TD Newcrest Capital Inc., Research Division

Mark Gilman - The Benchmark Company, LLC, Research Division

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

Kam S. Sandhar - Peters & Co. Limited, Research Division


Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Haynesville Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] I would now like to turn the conference call over to Ms. Lorna Klose, Manager of Investor Relations. Please go ahead, Ms. Klose.

Lorna Klose

Thank you, operator, and welcome, everyone, to the second call in our planned 2011 conference call series. In place of our traditional investor event and field tour, we felt it was more effective to feature 2 key plays in our portfolio that had been receiving a lot of investor attention. Today's session focus on the Haynesville Shale will highlight our work -- the work our teams have been doing over the past year, how this has lowered our overall cost structures and how this resource play truly a world class asset. But first, a brief bit of housekeeping.

As we will be talking about Encana's future, I need you to be aware of this advisory regarding the use of future-oriented information in this presentation and in subsequent presentations. In addition, Encana is a Canadian-headquartered company. Therefore, I am required by Canadian securities regulators to encourage you to read the advisory located at the end of this presentation, which has 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. protocol. Encana's production volumes and reserve quantities are reported on an after royalties basis unless otherwise noted.

Now on to the presentation. Eric Marsh, Executive Vice President, Encana Corporation and Senior Vice President U.S.A. Division, will start off with a brief overview of Encana's portfolio and a discussion of the company's strategy and ongoing efforts to continue to reduce cost structures. Paul Sander, Vice President, Mid-Continent business Unit, will provide a review of our Haynesville resource play; and David Nicks, Vice President, U.S.A. Gas Marketing, will conclude with a discussion of demand-side developments in the natural gas industry.

I will now turn the call over to Eric.

Eric D. Marsh

Thanks, Lorna, and good morning. I'm Eric Marsh, Executive Vice President, Encana Corporation and Senior Vice President of Encana's U.S.A. Division. I'm very happy to be here this morning to discuss Encana and our operations in Haynesville. Today, Encana is one of North America's largest natural gas resource play companies with among the largest and highest quality portfolio of undeveloped resource. We are the second largest producer of natural gas in North America at 3.5 billion cubic feet equivalent per day. Because we entered these plays in an early stage, we have amassed large, concentrated, contiguous land positions in a core of many of North America's best natural gas resource plays and at low cost. We have 6 facets, or tactics, that we focus on to help us deliver our strategy of unlocking the value inherent in our reserves and resource base.

This morning, our discussion will focus a fair amount on resource play hub development and how this improves operational efficiencies and reduces cost structures. And I'll also discuss our focus on increasing Encana's exposure to oil and natural gas liquids.

At year end 2010, Independent Qualified Reserves Evaluators estimated that Encana had proved reserves of just over 14 trillion cubic feet of natural gas equivalent. Above and beyond these proved reserves, we have expanded the disclosure of our resource in accordance with the frameworks established by the Society of Petroleum Engineers and in the Canadian Oil and Gas Evaluation Handbook. Using these frameworks, the same Independent Qualified Reserve Evaluators have estimated that our total reserve ranges from 14 to 27 Tcf equivalent, and our economic contingent resource range from 20 to 57 Tcf equivalent. This enormous quantity is represented by the water in the glass which is layered by classification and shaded roughly by the probability of being recovered. You could say that Encana's glass of resources is not just half-full, it is very full.

Compared to our most recent years production of 1.2 trillion cubic feet the equivalent for the entire year, you can get a good sense for the incredible depth of this inventory and our recent approach to try all means to reveal its value. Based on just our highest probability reserves and economic contingent resource, we have a significant drilling inventory, more than 20 years based on our 2011 development pace. Based on our best estimate case, our inventory increases to more than 50 years.

Encana's assets span across North America continent from the Horn River, Montney, Duvernay basins in the northeast British Columbia and Alberta, throughout the Piceance and the DJ Basin in the Rockies, Collingwood Shale in Michigan and down to the Haynesville Shale in Louisiana and Texas, and including the Tuscaloosa marine shale in Mississippi and Louisiana. 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. Our portfolio also includes large land positions in what we believe to be highly prospective oil and gas -- oil and liquids-rich natural gas plays. We now hold more than 2 million net acres that are perspective for natural gas, liquids and oil.

In 2011, we directed about $1 billion of our capital investment towards liquids-rich and oil development opportunities. We are just now in the process of setting our 2012 budget, so I don't have firm capital investment numbers that I can share with you yet. But I think it's safe to say that directionally, we intend to invest a significant portion of our cash flow into our liquids and oil opportunities in the Alberta deep basin, as well as the early life play such as the Duvernay, the Collingwood, the Niobrara and the Tuscaloosa marine shale.

This slides shows a 3D cross-section of a resource play hub. This is what a typical pad in the Haynesville 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 cost of $3 per thousand cubic feet equivalent over the next 3 to 5 years. Some of our plays are already there.

This development model starts with a resource play or what we call highly concentrated resources within contiguous land tracts. The underlying resource are developed using multiple long reach deviated or horizontal wells drilled from central pad sites.

In the Haynesville, we have natural gas in place of up to 225 Bcf equivalent 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 cost. The end product is the resource play hub, highly efficient, low-cost, low impact to the environment developments that drive down costs and improve cycle times.

Corporately, we've reduced our supply cost. 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 Mcfe, which includes about $0.30 for general and administrative expenses. It's our goal to continue to reduce our supply cost to $3 per Mcfe over the next 3 to 5 years.

Okay, on to the Haynesville. Paul Sander is going to talk to you this morning about some of the exciting work we've been undertaking in this play, our resource play hub strategy and the great result that it's been giving us, as well as our initiatives to drill a longer laterals in some of the latest technical advancements we've implemented on the completion side. But first, I wanted to step back a minute and highlight the tremendous growth our teams have made happen in this play over a very short period of time. Currently, we hold about 350,000 net acres in the Haynesville. We discovered this play in 2006, joint ventured with Shell on a portion of our acreage in late 2007 and our first year of production in 2008, we averaged 10 million cubic feet per day. Fast-forward 3 years and for 2011, we expect to average 505 million cubic feet per day, more than 50x what we were producing just 3 short years ago.

The Haynesville Shale represents extraordinary opportunity for Encana and its shareholders, with our land positioned right at the core of the play, we're able to build on a very things we do best at Encana: engineering efficiency, advancing horizontal drilling, optimization of completion and reducing cost structures to make a highly competitive, economically robust resource play that is here for the long-term.

We've successfully done this before at our resource plays like the Horn River, Montney and the Piceance. Now with land retention largely complete, it's time for us to build on that success in the Haynesville.

I will now turn the call over to Paul Sander.

Paul Sander

Good morning, and thanks, Eric. I would like to start by acknowledging my counterparts across Encana for the very strong operational performance so far in 2011. And the teams in Dallas here, too, for their accomplishments. Much of this will be covered off in today's Haynesville update, but our teams in north and east Texas have had a strong year, too.

Regarding the Haynesville, today, we will provide an update on the progress of our strategic initiatives, an update on performance with specific focus on resource play hub developments, and then we'll touch on where we are heading for 2012 and beyond.

The Haynesville is a great asset and Encana has a very strong position in the heart of the play in Texas and Louisiana. Over the past few years, our priority has been on retaining the core part of our land base. It is expected that to these efforts, Encana will retain around 250,000 net acres in the heart of the Haynesville and mid-Bossier plays. Ultimately, Encana expects to produce over 20 Tcf net over the life of the field.

Encana's Haynesville operational performance continues to improve, and this is all the more important given the persistently low natural gas prices we have been experiencing in our industry. These significant improvements in our operations have been achieved partly through the careful implementation of improved technology and also in part due to better execution.

Currently, our Haynesville supply cost is $3.70 per Mcf for resource play hub development, and we are now targeting supply costs of less than $3 per Mcf. We expect to achieve this through a combination of improved well performance and reduced cost structures, primarily through the implementation of our resource play hub model. Drilling and completing longer wells is also part of our point forward plan.

As Eric mentioned earlier, Encana discovered the Haynesville in 2006 with the drilling and completion of 3 vertical wells, including the A. F. Walker No. 1, Martin Timber #1 and Adcock #1, Today, we still lead the way in many, if not most, respects.

The Haynesville is now the largest producing gas play in North America. The entire play is currently producing over 6.5 Bcf a day, a number all the more impressive that when you consider in 2007 there was no Haynesville production. This represents around 10% of daily natural gas production in the United States today.

The Haynesville has led Encana's growth over the past few years. Our net production is currently around 600 million cubic feet per day and will average over 500 million cubic feet per day in 2011. The Haynesville, of course, has excellent well performance. It is ideally located from a marketing and transfer perspective, and the field infrastructure is fully developed. We are well-positioned.

Encana has tremendous flexibility in developing this wonderful asset at a pace responsive to improved commodity pricing now that the majority of our land is held by production. In 2012, we expect that our operations will focus on resource play hub development, drilling longer lateral wells under optimized spacing and completions that not only enhance recoveries, but also lower costs.

Encana has positioned the Haynesville to be a low-cost development play through the implementation of resource plays hub models. Drilling multiple wells from pads reduces the environmental impact of our operations and at the same time, results in higher efficiencies and lower cost structures.

Leading edge technology and practices are also a huge part of the Haynesville story. By designing, developing and using fit-for-purpose natural gas driven rigs, drilling longer horizontal laterals and now vertically integrating fit-for-purpose completions equipment with our service provider value, Encana has led the way. Our supply costs have improved significantly, even from just last year. And as we'll discuss in a few minutes, our drilling times have come down and we've become even more efficient in our completions. Resource play hub development is the prize that we have been working towards, and it is delivering today.

Our Bolan Section 27 is a single section development that has produced as high as $200 million a day. It demonstrates the potential of the Haynesville and the value that can be created through the resource play hub model. This section has a total of 11 wells. It has both 80- and 40-acre space wells as part of the development. The 40-acre wells will be used to accelerate the tiger[ph] reservoir simulation, which will be used to determine the optimal future well spacing.

Ultimately, many parts of the play, including the Bolan Section 27, will be drilled into mid-Bossier 2. Imagine the efficiencies created by developing a resource play hub section with 15 new wells. Or even better, imagine if we could recover the same amount of gas with only 11 new wells. Our team is taking it one step further and looking at plans to recover the same amount of gas on new sections with effectively 7 new longer, lateral cross-section wells. The goal is to recover -- is to maximize recovery and value with pure, longer and better performing wells. Our culture at Encana is all about innovation. We have superior assets, that is our people, that make them stellar.

Our drilling performance is an example of this performance culture. A structured innovation process has resulted in continuous improvement in drilling costs and drill times. Standard operating practices have been developed to systematically control and improve performance.

As an example, we have reduced our drill times and costs by 38% and 30%, respectively, and are at 100% working interest Credence area since 2009. At Encana, teams identify and implement best practices within own operations and coordinate with our partner, Shell. We use lean processes sometimes also referred to as continuous improvement, or 6 Sigma, to create a highly efficient manufacturing approach to drilling operations.

And while execution is important, technology is a key lever, too. Encana identifies and tests new technology, such as hot hole tools and rotary steerable drilling assemblies that may result in even better performance in the years to come.

Completion efficiency has also improved with resource play hubs. Costs continue to improve even as well lengths and completion intensity is increasing. Encana has worked with our service providers to analyze and systematically improve efficiency. It is very much a team effort. Our service providers have done a great job in improving equipment uptime and move time. Encana has improved job design to reduce screen outs and the cycle time around setting plugs and perforating. Having multiple wells on a single pad improves efficiencies, too. The chart on the right-hand side of this slide shows how the number of jobs pumped per month has doubled since the first quarter of 2010. Most recently, we pumped as many as 145 completion stages from a single crew in a single month, and more stages means lower average costs.

Since we began our operations in the Haynesville, we have focused our efforts on continuously optimizing our execution. And over the years, this has served to offset some inflationary costs associated with services and fuel. The plot on the right-hand side of the slide shows how well completion costs have trended downward. You've seen our costs come down by around 7%. This has been accomplished all the while more stages and bigger completions are pumped.

Our completion teams are working smart and creating value. The slide shows how completion designs have changed over time. Aside from longer wells, generally, job sizes are getting larger. Our earlier vintage wells pumped the smaller completions and wider cluster spacing had higher-than-expected declines. Our technical analysis of this and subsequent work concluded that fracture on activity or effective length of these earlier completions was deteriorating over time. This was likely due to proppant embedment. Over the past few years, we have successfully increased the completions intensity and placed more sand in the completions network to reduce the impact of proppant embedment. The result is improved well performance.

The plot on the top right illustrates how normalized well performance has improved over time. Notice how declines have moderated over time. We expect that new generation completion designs will build on these improvements. This value-driven approach is yielding better wells at a lower cost and is a big part of our success in driving the supply costs down.

Preserving the connectivity and making a better well is also dependent on production practices. We've been actively testing slowback over the last year. Slowback is a production practice that limits the production rate on a well in order to control the surface pressure drop to less than 25 psi per day. The practice is expected to work better on well spaced further apart than those closely spaced.

Over the past year, well results where we've been using the slowback method have shown demonstrable positive benefits. Expected ultimate recoveries, or EURs, are estimated to improve in resource play hub wells by about 5%. And when combined with bigger completions, EURs are showing a 10% to 15% improvement.

Around half of our wells employed this practice in 2011 and it is now our standard practice. So in 2012, we'll be focusing our well design and completions based on 7,500-foot laterals, increasing job sizes and using slowback.

This completion strategy fits with our goal of developing the play with fewer, better wells, using less capital and all the while recovering the same amount or greater amount of gas. Towards this effort, we have conducted numerous spacing trials in 2011 to determine the optimum future well spacing.

The diagram on this slide illustrates a planned test where one section is developed on an 80-acre spacing pattern and the section right above it is developed on a 106-acre spacing pattern. The northern wells were completed with much larger completion stages. We believe that it will be more capital-efficient to use the completions truck than the drilling rig. In other words, it is less costly for us to invest in bigger completions on fewer wells than it is for us to drill more wells with smaller completions.

As stated earlier, we expect that slowback will be more helpful in the 106-acre space wells than those drilled on 80s. So ultimately, we are heading to 106-acre spaced wells or even 160-acre spaced wells.

We have various spacing pilots underway in 2011. Each pilot is paired with a reservoir simulation model constructed to model the specific rock properties and completion design. Actual well performance is compared to the model predictions. Model parameters are then tuned to match the actual performance. We can then confidently use these models to predict well performance and to make value decisions on field development. The plot on the top right demonstrates the initial resource play hub performance is tracking with expectations.

While significant progress has been made on the well completion and spacing, there have been limits on how long wells can be drilled. Longer laterals will provide the net -- next step change in reducing supply cost and creating value. Encana has led the way in working with the state of Louisiana and has several approved permits for cross unit wells. Most of our new development point forward will be long lateral wells. There are certain limitations due to the current exemption base permit process. And ultimately, the state will require some regulatory reform to routinely allow wells to cross existing units. Working with the state on this is a top priority for Encana. These necessary reforms will make Louisiana competitive with other jurisdictions.

Our drilling and completions teams have done a great job of meeting the technical challenges, associated with the drilling and completing of the longest wells drilled in the Haynesville. Encana has successfully drilled 2 cross unit long lateral wells in Louisiana. They were drilled spud to rig release in 43 and 50 days and have around 6,900 and more than 8,000 feet of lateral lengths, respectively.

These wells should reduce our finding and development costs by around 20% compared to the 4,600-foot wells. Once these well lengths become routine, we plan to drill wells with up to 10,000-foot lengths.

In Texas, we are already set-up to drill longer lateral wells and are in the midst of completing our Sabine wells. Each of these has over 7,500 feet and will be completed with 30 stages. These are the longest and deepest wells drilled in the Haynesville today. With the increased stimulations optimized to fit this high-pressure reservoir, we have increased our EURs in this area from 1.4 to 1.6 Bcf per thousand feet of lateral length. Just like in Louisiana, wells here benefit from improved completions and slowback.

So significant progress has been made in 2011. Looking forward, we have visibility to $3 per thousand cubic feet equivalent supply cost with the 7,500-foot longer laterals. We are making better wells and our execution is resulting in lower well costs. Our resource play hub model is delivering.

Now before turning the call over to David Nicks, I'll speak briefly about our activity in the mid-Bossier and the exciting opportunity that this resource presents for Encana. Our Haynesville is really 2 reservoirs: the Haynesville, which has been the focus due to land retention; and also the mid-Bossier, which we drilled to, to get to the Haynesville. The mid-Bossier is a highly prospective reservoir and a key goal this year has been to delineate this reservoir.

We expect to drill 20 mid-Bossier wells in 2011, focusing on transferring our learnings from the Haynesville Shale development. Most of our program will come on production later in the year. The plot shows that even though completion evolution is at a very early stage, some of our early results are very encouraging. We expect that as much as 200,000 net acres of our position will be competitive with the Haynesville.

The mid-Bossier trend also extends into the Amoruso, East Texas area as well. The rock quality for this resource is very compelling. We drilled the horizontal well into this play in late 2010 and its performance shown on this graph is quite strong. The size of the resource could be as large as a contingent resource in the main part of the Haynesville/mid-Bossier play in Louisiana and Texas.

In closing, the Haynesville continues to be a high-quality material growth asset for Encana. Significant progress has been made in reducing supply costs and we expect further progress as we move forward. The land retention program is a much smaller component with the program for 2012 and will be largely completed in 2013. As such, we expect to reduce the program investment in 2012, focusing more investment in liquids-rich plays.

Our focus in the Haynesville will be on long lateral resource play hub developments, which will place the Haynesville among the most competitive plays in North America. Drilling and completing long reach horizontal wells is where Encana is truly at its best, and this is exactly where the lion's share of our efforts will focus going forward.

Thank you. And I'll now turn the call over to David Nicks.

David Nicks

Good morning. Thanks, Paul. I'm David Nicks, Vice President U.S.A. Gas Marketing. This morning, I will discuss with you the macro environment as it relates to demand for natural gas and some of the initiatives Encana has been undertaking to grow demand for natural gas. I'll also review the infrastructure and demand centers that are specific to the Haynesville Shale.

Before I discuss the market regions supplied by the Haynesville Shale, I'll talk about the initiative Encana is undertaken to grow demand from North American natural gas. Technology breakthroughs have created a new reality for the natural gas industry, one that enables a new energy plan, focused on the increased usage of abundant natural gas.

Natural gas has always been considered a viable and desired fuel for power generation and that trend will grow. With the increase and availability of firm supply, natural gas is now being actively considered as an alternative transport fuel, as a fuel in expanded industrial application and as liquid for export growing global LNG markets.

This slide shows the total energy consumption by sector, the natural gas consumption by sector, in billions of cubic feet per day. The message is that there is a significant potential to increase the demand for natural gas in existing energy complex.

The key areas of focus in the near term will be in electric power generation and transportation markets. In addition to the current markets, we will speak later to the potential for North American LNG export capabilities by 2015.

Encana's view and vision to growing natural gas demand by as much 38 Bcf a day by 2030. The primary growth opportunities are in the power generation and transportation sectors. In the near term, natural gas consumption power generation could grow by as much as 13 Bcf a day, 5 Bcf a day from natural growth associated with the economy and 8 Bcf a day associated with natural gas fired coal displacement. Growth in the transportation sector could be as much as 3 Bcf a day by the end of the decade. By 2030, natural gas consumption could increase by over 50% from 2010 alone.

Encana has been very busy walking and talking with regard to natural gas demand. Our efforts to date have been split between advocacy and building demonstration or early adoption projects. Encana has taken an active role in various North American trade associations, with an emphasis on American (sic) [America's] Natural Gas Alliance, or ANGA. Our employees chair or participate in nearly all of the committees. Through ANGA, we can impact a lot of policymaking in Washington. We have expanded our successful efforts in the United States to Canada as well through the Canadian Natural Gas Initiative, or CNGI.

Moving to LNG and CNG, Encana is a 30% partner in the 1.4 Bcf a day Kitimat LNG export facility, which has recently received NEB approval to export LNG for 20 years. This project will allow North American natural gas to supply the growing Asian markets.

In addition, Encana has been on the forefront of increasing demand for natural gas vehicles. We are converting our fleet vehicles to consume natural gas, we're building natural gas fueling station and developing liquefaction capacity to supply LNG fuel for additional domestic uses. The potential for expanded use in natural gas industrial applications is significant, as well as displacing diesel use in stationary equipment and increasing use in another industrial applications.

I would like to now focus on the Haynesville market region. Encana's Haynesville Shale assets are situated in close proximity to the highest concentration of North American industrial natural gas demand and at one of the future gateways to global energy markets. The growth of this play is due to the relatively low supply costs, the magnitude of the land area and resource potential and the location, with approximate to industrial demand, pipeline infrastructure and power demand. In short, the asset is a critical contributor to near-term demand that sits well-positioned for the future.

As can be seen from this slide, Haynesville sits on the heart of the producing region in the Southeast United States. Drivers [ph] in blue were the major trading hubs in the region with the Henry Hub clearing port referenced by a blue star. The white line represents the various natural gas pipelines in the area.

With the growth of production from Texas and Louisiana over the last several years, significant infrastructure additions have been funded to ensure adequate takeaway and access to various markets. Over the last 5 years, over 20 Bcf a day of new pipeline capacity has been added in the region. As of today, the infrastructure additions have outpaced production growth, yielding approximately 5 Bcf a day of spare pipeline capacity.

As a result of this spared capacity and multiple pipe options, the value spreads across the region are considerably tight, represents slide of value indications for the highlighted hub showing pricing in near parity with the Henry Hub benchmark. Unlike many regions currently experiencing growth in the United States, Haynesville is adequately piped for today's volumes with considerable room for future growth. Encana has secured 650 million cubic feet a day of firm takeaway capacity from the region.

Following the discussion of regional and Encana pipeline capacity, I'll shift the focus to demand. The Gulf Coast of Texas and Louisiana has a current industrial natural gas demand of approximately 6 Bcf a day. In addition to the existing demand, numerous projects have been announced that have the potential to more than double the current industrial demand in the region. Potential LNG exports from the U.S. had received a considerable amount of press over the last year. Encana has joined in supporting the benefits of exporting natural gas from North America.

Highlighted here are the potential U.S. Gulf Coast LNG export projects that are in the various stages of development. These projects have the potential to bring an additional 5.8 Bcf a day of demand for the Gulf Coast as early as 2015. The abundance of natural gas in North America has resulted in numerous projects, potentially capitalizing on resource availability in the attractive spreads other thermal fuels. We have depicted a recent announcement from Sasol regarding a potential gas to liquids facility located in the Lake Charles area as an example.

This proposal facility capitalizes resource availability and a relative value in the region, when compared to higher value liquid products namely diesel. It is Encana's thinking [ph] that the current value natural gas will continue to drive this type of investment.

In addition to the industrial loads depicted in the last slide, the power generation plays a significant role in the Southeast United States natural gas demand. In addition, the push for clean air and emission restrictions will further support incremental natural gas for our power generation.

Over the next several years, older vintage coal-fire generating facilities that cannot economically meet emission standards will be retired and replaced with the natural gas-fired units. The range of outcome for potential coal facility retirements is large, with substitutions announced to date adding approximately 2 Bcf a day of gas demand in the Southeast United States alone. There is reasonable potential for additional 3 to 9 Bcf a day of incremental demand. Again, Haynesville's ideally situated and capable of providing this fuel requirement.

Although near-term prices continue to challenge dry gas development, it is critical to focus on the demand side of the equation. Globalized in turn of North America, not only for gas reserve acquisitions and LNG supply, but also as a location for industrial and agricultural capital investment. Haynesville currently produces approximately 10% of North America's natural gas requirement. It is capable of not only meeting domestic obligation both now and in the future, but also yielding an opportunity for North America to compete in global energy markets.

Thank you for the time this morning, and I will now turn the call back over to Eric Marsh for concluding remarks. Eric?

Eric D. Marsh

Thanks, David. I'd like to close this morning's conference call in saying that Encana is and has been the industry leader in application of technology in creating a highly successful resource play development model. 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 that production of oil and natural gas liquids is on a growth curve in North America for the first time since mid-1970s.

Encana's industry leadership has positioned us well. We have a great asset base and innovative value-driven teams, and we have a clear vision of 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.

Thank you. Lorna?

Lorna Klose

This concludes the formal part of our presentation. As a reminder, a video showcasing Encana's Haynesville operations is now available online. The website address is stated on the slide above and in our news release from last week.

Thank you for participating in our conference call today. We will now take questions.

Question-and-Answer Session


[Operator Instructions] The first question comes from the line of Mark Gilman from the Benchmark Company.

Mark Gilman - The Benchmark Company, LLC, Research Division

Paul, I was just wondering. Have you considered or looked at potential use of dual laterals given the degree of overlap between the mid-Bossier and the Haynesville across your acreage?

Paul Sander

Mark, it's Paul here. Good question. Yes, multi-laterals has been something that we've been looking for a few years now. It's a technology that has application to many of the plays across Encana. And right now, we're looking at where is the best place in Encana to apply that technology. I think you'll see us try something in 2012 in a lower risk environment. And as we learn how to do it, we can take that application to move into a Haynesville-type environment


Mark Gilman - The Benchmark Company, LLC, Research Division

Paul, if I can just follow up, I guess, wouldn't you want to prioritize reaching a conclusion on this issue as early as possible, given that it might very much relate to development plans on the here and now?

Paul Sander

It's something that we're very interested in moving forward, Mark. Right now, our focus is on drilling the longer wells. We think we can get the most bang for our buck with that effort and with a bigger completions. That's really where we see the next step change. The multilateral design for the Haynesville is really not an off-the-shelf technology at this stage. And there's a fair amount of inherent risk associated with trying to make that the preferred solution today. So it's something that we'll get to, but right now, where we're headed is the longer laterals.


[Operator Instructions] We have a question from Peter Ogden from Bank of America.

Peter K. Ogden - BofA Merrill Lynch, Research Division

Just quick question on the 500 million cubic feet a day on 5.1 Bcf. How do you guys think about that reserve number because, I mean, by my calculations, that's a 28-year reserve life. How much future development capital is booked against that reserve number and how do you go about monetizing even just the 3P number, never mind getting into the 3C number?

Eric D. Marsh

Peter, this is Eric Marsh. I think, the question can really be answered that as you look at the Haynesville, our focus is really been on developing the resource and understanding the reserve number. And then as price dictates, we can accelerate that pace of development and try to reduce that reserve life index as time goes on. I think it's also fair to say that we're just now in initial phases of understanding the mid-Bossier as well, so that even complicates it even more. So like in many of our areas, we certainly will understand their resource. And then at some point, we may consider accelerating the pace of the development, either with our own capital or through a JV structure like what we've done in other areas.

Peter K. Ogden - BofA Merrill Lynch, Research Division

Do you guys have a sense of how much future development capitals booked against reserves in the Haynesville?

Eric D. Marsh

We probably ought to get back to you on that because we've got a very significant amount that also is booked into the mid-Bossier, so we'll get back to you with the exact number.

Peter K. Ogden - BofA Merrill Lynch, Research Division

And just one maybe related question, but how do you guy think of the capital efficiency in the Haynesville? Like obviously, I think you've guys have signaled that you're going to take capital away from the Haynesville and go into liquids-rich plays. I mean, is it -- how do you see that capital efficiency moving next year with this gas hub development? Can you maintain production on lower capital on the same number of wells? Or do you actually see production falling off a little bit? Because we've seen a lot of operators pull rigs out of the Haynesville as well and that's the direction we think it's going, but...

Eric D. Marsh

Yes. I think that's a fair statement. I think a year ago, we were in the 160 rig count. Today, we're at around 120, probably declines a little bit into 2011. But one thing that I think often gets left behind is that the efficiencies of some of the things that we're doing as well as perhaps others, are really reducing the amount of time it takes to drill, complete wells. And so with fewer rigs, you're going to maintain production more than what a lot of folks think. I think production could stay relatively flat in 2012 and then start to decline. But overall, the rig count is really being offset right now by the efficiencies that are being gained and the improved well performance. So I think overall, the Haynesville is at a state where it's still not as efficient as it can be. And so it's got the potential to grow.

Peter K. Ogden - BofA Merrill Lynch, Research Division

And finally, I guess, all the land tenure issues, I think you might have addressed right at the beginning of the call. All the land tenure issues have been -- they're gone. There's not really that kind of issue going forward on the mid-Bossier or the Haynesville?

Eric D. Marsh

Well, not necessarily gone. We will have a certain capital commitment in the order of $150 million in 2012 and a lesser amount probably in 2013, but similar. But at the end of 2013, the land retention is, for the most part, finished up. But the amount is reduced significantly from 2011 to '12, and then it will go down a bit more in '13. But yes, there's still be some continuous drilling clauses and there's still some land retention in '13, albeit smaller.


Your next question comes from the line of Greg Pardy with RBC Capital Markets.

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

Just wondering if you can comment on the capital efficiency gained as a result of going to the longer laterals versus what you've been doing up to now?

Eric D. Marsh

Yes, I think we can. I think we talked about it in the third quarter. If we can get to that point where were drilling 7,500-foot laterals, we see wells making somewhere in the order of 12 to 13 Bcf for a number that's between $11 million and $12 million of spend on a typical well. So the actual economics of that well are significantly enhanced compared to the 4,500-foot laterals. So it will compete with any play that's out there in North America from an economics perspective. So it's very much a critical part of our program going forward and really, we're going to spend as much effort as we can to drill as many long laterals as we can because of the enhanced capital efficiencies that's created from it.

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

And may be just an adjunct to that, as it relates to the landholders, are you -- and I guess, just working through regulations in the State of Louisiana. In terms of being able to get land owner approval to be doing this, and I think you commented on this on the call, but what needs to happen now for you to drill well beyond the section that you've been focused on before?

Paul Sander

Greg, this is Paul. It's a good question. So right now in order to create a across unit, alternate unit, that will allow us to drill longer wells, we need a 100% of the working interest to approve and also 100% of the mineral interest owners to approve. And it is your classic win-win. Everybody wins. I mean our owners win, we win and the state wins, but sometimes we have tens if not hundreds of different mineral owners in these things. So getting 100% approval is very difficult. What we'd like to do is get those approval limits down to a more reasonable limit like other states have, and that will allow us to -- on a routine basis, form these cross units and allows to drill longer wells.

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

Okay. And are you encouraged there with the folks you talk to in the state capital and so on?

Paul Sander

Yes, I think we're making good progress. As I said, Encana sort of led the way in terms of getting the permits that we currently have. We were the first company that's permitted these longer laterals in Louisiana, so they've really been working with us on this initiative. And I think where we need to go is just the next step and make it a routine effort.


Your next question comes from the line of Kam Sandhar with Peters & Co.

Kam S. Sandhar - Peters & Co. Limited, Research Division

Just a couple of questions. First of all, just to clarify on your land retention drilling. So will you be left with 250,000 net acres after you've completed all of your land retention drilling? Or is that just your acreage position in the heart of the play? And then second thing is you mentioned on one of the earlier answers that you're targeting $11 million to $12 million well cost. Just wondering whether your assumptions for what your IP rates will be on -- or target IP rates will be on those wells?

Paul Sander

I'll take it. It's Paul Sander here. So we do expect that ultimately, our land will be around 250,000 net acres preserved, that's both on the Texas and Louisiana side. And it really is in the heart of the play. We've been allowing some land to expire and we've been doing some divestitures and trades with other parts of the play that we don't view to be in the core. So 250,000 net acres is a substantial position. It will easily allow us to preserve our contingent resource and get to the previous targets that we've talked about, like getting to a Bcf a day. So it's a substantial position. With respect to the longer laterals, I think that we can be targeting $12 million well costs somewhere in that range with around 13 Bcf reserves. So we see around a 20% improvement in F&D cost compared to 4,600-foot laterals. And I'm not sure, I might have missed one of your questions.

Kam S. Sandhar - Peters & Co. Limited, Research Division

Just specifically on what sort of -- whether how the IP rates have changed relative to the longer foot laterals versus the older wells that you're drilling, or what your target IP is?

Paul Sander

Yes. Probably, the target IP is probably going to be in that 12 million to 15 million a day range. And remember, we've gone to what we call a slowback process, so that limits the amount of drawdown that we take on the well. The wells are capable of probably 30 million a day at increased drawdowns, and have unbelievable AOS. But probably 15 million a day for an extended period of time is what you should be thinking about.


Your next question comes from the line of Mike Dunn with FirstEnergy Capital.

Michael P. Dunn - FirstEnergy Capital Corp.

Part of my question's has been answered, but just wondering what your contingent resource estimates, is there a significant amount of mid-Bossier included in that? And if not, how should we be thinking about the potential there?

Paul Sander

Yes. Mike, it's Paul Sander again. Around 1/4 to 1/3 of our contingent resource is mid-Bossier and it is included in that sort of roughly between our

reserves and our 3C number, 20 Tcf or so.

Michael P. Dunn - FirstEnergy Capital Corp.

Okay. And then I think you mentioned earlier on the call that you might have up to 200,000 net acres of mid-Bossier that looks comparable in quality, is that -- did I understand you correctly?

Paul Sander

Yes, that's right. We expect that we're going to retain around 250,000 net acres, which will be in the core of the Haynesville play. And of that 200,000 will be in the core of the mid-Bossier play.

Michael P. Dunn - FirstEnergy Capital Corp.

Right. Okay. So Is that sort of proves up -- you'll be hoping to see some lift to your resource estimates for the mid-Bossier, I would assume then?

Paul Sander

Yes, that's right. We're always looking to lift those up.


Your next question comes from the line of Menno Hulshof with TD Securities.

Menno Hulshof - TD Newcrest Capital Inc., Research Division

I have one question for Paul on the 40-acre trials. I was just wondering if you give us some sense of scale, what you're expecting to see and when you would expect to be in a position to talk about some of the preliminary results?

Paul Sander

Okay. Yes, we did 40-acre trials in both 100% Credence area and in our Bolan area in the northern part of Red River Parish. And really the goal was to determine -- get a pressure and a production match to our reservoir simulation. We actually expected the production to deviate from the 80-acre wells almost immediately. And surprisingly, the wells are hanging in there a little bit better than we thought, which is I think encouraging for where we -- the overall infill development in the field. I think that maybe part of our next year's investor review, we'll probably be ready to show you some of the results of our 40-acre wells.


There are no further questions at this time. I would now turn the call back over to Ms. Lorna Klose.

Lorna Klose

Thank you. This concludes our call today.

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