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EnCana Corp. (NYSE:ECA)

Q3 2010 Earnings Call

October 20, 2010 01:00 pm ET

Executives

Ryder McRitchie - VP, IR

Randy Eresman - President & CEO

Jeff Wojahn - EVP & President, USA Division

Mike Graham - EVP & President, Canadian Division

Sherri Brillon - EVP & CFO

Bob Grant - EVP, Corporate Development, EH&S and Reserves

Renee Zemljak - EVP, Midstream, Marketing & Fundamentals

Analysts

Greg Pardy - RBC Capital Markets

Andrew Potter - CIBC

Brian Singer - Goldman Sachs

Mark Gilman - The Benchmark Company

Mark Polak - Scotia Capital

Bob Morris - Citigroup

Aaron Diamond - Highfields Capital

George Toriola - UBS

Judy Myrden - The Chronicle Herald

Amanda Fraser - AllNovaScotia.com

Shaun Polczer - Calgary Herald

Operator

Good day ladies and gentlemen and thank you for standing by. Welcome to EnCana Corporation's third quarter 2010 results conference call. As a reminder, today's call is being recorded. At this time all participants are in a listen-only mode. Following the presentation we will conduct a question-and-answer session. (Operator Instructions). Members of the investment community will have the opportunity to ask questions first. At the conclusion of that session, members of the media may then ask questions. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of EnCana Corporation. I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations. Please go ahead Mr. McRitchie.

Ryder McRitchie

Thank you operator and hello from Denver. Welcome everyone to our discussion of EnCana's 2010 third quarter results. Before we get started I must refer you to the advisory on forward-looking statements contained in the news release as well as the advisory on page 49 of EnCana's annual information form dated February 18, 2010 the later of which is available on SEDAR.

I'd like to draw your attention in particular to the material factors and assumptions in those advisories. In addition I want to remind everyone that EnCana reports its financial results in US dollars and operating results according to US protocols which means that production, reserves and resources volumes are reported on an after royalty basis.

Accordingly, any reference to dollars, production and reserves or resources information in this call will be in US dollars and US protocols unless otherwise noted. To provide a clear understanding of the new post split EnCana the prior period, comparative information discussed in this conference call represents EnCana's financial and operating results on a pro forma basis.

In this pro forma presentation, the results associated with the assets and operations transferred to Cenovus Energy are eliminated from EnCana's consolidated results and adjustments specific to the split transaction are removed.

Financial information that reconciles EnCana's consolidated financial statements and pro forma financial statements can be found in EnCana's news release dated October 20, 2010 available on our website. Randy Eresman will start off with the highlights of our operating results today and then Jeff Wojahn, Executive Vice President and President of our USA Division and Mike Graham, Executive Vice-President and President of our Canadian Division will then touch on some highlights from each of their areas before turning the call over to Sherri Brillon, EnCana's Chief Financial Officer to discuss EnCana's financial performance. Following some closing comments from Randy, our leadership team will then be available for questions.

I will now turn the call over to Randy Eresman, EnCana's President and CEO.

Randy Eresman

Thank you Ryder and thanks everyone for joining us today. Today's call will highlight EnCana's performance during the third quarter of 2010. We've achieved strong financial and operating results this quarter and for the first nine months of the year. Fractions of the quarter averaged just over 3.3 billion cubic feet equivalent per day at 15% increase over third quarter 2009 pro forma volumes.

Natural gas production per share for the third quarter increased 19% compared to 2009 third quarter pro forma volumes. Despite benchmark natural gas prices that averaged $4.39 per million Btu's this quarter. Cash flow remained robust at $1.1 billion due to production growth and a strong commodity hedging program that resulted in average realized gas prices of $5.27 per thousand cubic feet.

Although we're pleased with our year-to-date performance, we are concerned with near term natural gas prices. Initially in EnCana's hedge position for the remainder of 2010 and going into 2011 is lower than it has been historically. These factors when combined with cost pressures and operational constraints that I'll speak to momentarily have brought us to the conclusion that we need to adjust our capital investment and production expectations for the remainder of the year. We've lowered our expected 2010 capital investment plans from $5 billion, down to $4.8 billion.

Average production guidance has also been decreased by about 50 million cubic feet equivalent per day to just over 3.3 billion cubic feet equivalent per day. This results in approximately 12% per share growth over in EnCana's 2009 average pro forma volumes. Our updated guidance is available on our corporate website. Primary reason for these adjustments to our corporate guidance is capacity constraints for completion services at our operation in Louisiana and East Texas. These constraints are delaying us from completing some of Haynesville wells in a cost efficient manner. This will affect our base of development in the near term as we will not pursue growth at any cost.

Currently our teams are working very hard to develop new and innovative solutions for managing our pumping equipment requirements including the development of new fit-for-purpose completions equipment. I expect that these efforts should cost effectively reduce our backlog of wells awaiting completion by the second half of next year.

Capital discipline, combined to the focus on increasing operating efficiencies are at the forefront of EnCana's growth strategy. Well, Jeff Wojahn and Mike Graham will speak more about some exciting initiatives we've undertaken to further reduce costs and improve operating efficiencies in their areas.

I'll now turn the call over to Jeff Wojahn, President of the USA division.

Jeff Wojahn

Thanks Randy, and good morning. In the USA division production volumes averaged just over 1.8 billion cubic feet equivalent per day for the quarter, a 16% increase over a year ago. This production growth is net of approximately 60 million cubic feet equivalent per day of net divestiture volumes. The USA division's year-over-year growth is partly due to bringing our 2009 capacity with actions back online earlier this year and is partly driven by successes across our entire portfolio, especially in our operations in the Haynesville Shale and in the Piceance Basin. The division's year-to-date operating cost of $0.56 per thousand cubic feet equivalent are approximately 7% below guidance due to continued operating efficiencies first implemented in 2009.

We are forecasting this trend to continue for the remainder of the year and as all of the operating teams are extremely focused on reducing costs.

Now turning to the Haynesville. In the first nine months of this year we drilled 73 net wells in the Haynesville, the vast majority of which were driven by our land retention strategy. In Canada, the land retention strategy has helped us to delineate a significant portion of our core acreage position. We now believe that our least retention obligations will moderate significantly in future years and we expect to focus more and more on future gas factory development.

Increased industry activity in shale gas and liquid rich shale plays have contributed to significant completion services capacity constraints and cost inflation. Again our number one mantra is our focus on cost reduction and increased operating efficiency. As such we have pulled back on treating some of our Haynesville well inventory.

At the end of the third quarter, we have 20 net wells waiting on completions and we forecast that this inventory will grow to 35 net wells by year end. EnCana is not willing to accept current return expectations of some completion service companies and as Randy mentioned we are working on solutions to mitigate cost escalation and equipment shortages but this will affect our pace of development and until additional capacity becomes available.

We have chosen to reduce our plant drilling program from 110 net wells to 90 net wells for 2010. Despite the completion equipment shortage resolved from Haynesville are solid, with our third quarter production averaging 335 million cubic feet equivalent per day are greater than 300% increase over last year.

For 2010, we expect average 290 million cubic feet equivalent per day in the Haynesville shale. In certain core areas, we continue to see tight curve improvements and better performance than forecast at year end 2009. These areas will be the focus of future gas factory development. EnCana is advancing its industry leading gas factory development approach in Haynesville shale with three current gas factory operations. Here we can drill all the wells from a single location. We will not need to move the rig each time a new well is drilled. Plus in many cases we have previously delineated the target zone from apparent lab retention well. We plan to conduct simultaneous operations of drilling completions and production all occurring at the same time very much like an assembly line or manufacturing process.

This approach has generated significant savings and efficiencies both in terms of time and capital and other areas of the company such as in Piceance basin. Today, we have been able to offset the majority of our inflationary increases with operational efficiencies.

Now, I am going to turn the call over to Mike Graham, who is the President of our Canadian division.

Mike Graham

Well thanks Jeff and good morning everyone in the Canadian division we've had an excellent year so far. Third quarter production was approximately 1.5 billion cubic feet equivalent per day a 14% increase over the same period in 2009. This overall production increase is net of divestiture volumes of approximately 70 million cubic feet equivalent per day for this quarter when compared to the third quarter of 2009.

Our production growth is partly due to brining on our 2009 capacity reductions back online and also due to successful drilling programs in the Canadian deep basin business units which includes Bighorn and Cutback Ridge. Year-to-date operating cost which are 7% below expected guidance were unchanged at a $2 per thousand cubic feet equivalent when compared to same period in 2009.

Excluding the impacts of foreign exchange year-to-date operating cost were $0.90 per thousand cubic feet of equivalent in 2010 or approximately 12% lower than the comparable period in 2009. Lower per unit cost were attributable to production growth and improved operating efficiencies across all of our resource place. Recently we haven't spend a lot of time discussing our Coalbed Methane asset but its in the area that has been performing well this year, despite the wet weather delays we have had throughout the spring and summer. We have drilled more than 430 wells so far this year and production for the first 9 months of 2010 was 312 million cubic feet equivalent per day. We currently have 13 rigs operating in this area due to our significant fee land ownership, average royalties are low here about 2% and drill complete and high end cost are around 5% below our 2010 budget estimate. We are making good returns on this play, even at today's gas prices.

At Cutbank Ridge which includes our money asset, third quarter production average 446 million cubic feet equivalent per day, about 37% higher than at this time last year. We drilled 60 net wells at Cutbank this quarter, 13 of which targeted the Montney formation.

For 2010, we expect to average 12 hydraulic fracs per well in the Montney formation. Our costs have continued to come down, recent all in the fracture cost and the Montney that is cost that include drilling, completion and high end have averaged about 500,000 per stage, down more than 20% from our 2009 average cost per frac or stage of 650,000.

Last quarter we told you about a cattaman horizontal that we drilled at Cutbank to a total measured depth of greater than 19,500 feet, this 14 stage well has been completed and is currently flowing at approximately 80% above our expected tight curve at about 6 million cubic feet equivalent per day. This is another example of how our teams are pushing technology to maximize reservoir access and exceed previous expectation, and we are doing this through all of our resources place.

At out Deep Basin Big Horn asset production averaged 260 million cubic feet equivalent per day, 52% increase over the third quarter of 2009, here our flare horizontal wells are completed with about 13 hydraulic facture stage of each and recently our first month initial production rates have been averaging nine million cubic feet equivalent per day again well ahead of our tight curve. Our vertical wells drilled are inline with our expectations and our full cycle cost for the first nine wells of our 2010 program were more than 10% below our 2009 cost, based on the success we have experienced, we have increased our 2010 production and capital investment guidance at Big Horn. We now plan to invest about $340 million this year, with 2010 average production up by 10 million cubic feet equivalent per day to 240.

EnCana's Deep Basin asset produce with a reasonable high liquids content, usually in the range of 10 to 40 barrels per million cubic feet, depending on the well location. We are therefore moving ahead with the addition of liquids extraction equipment such as refrigeration plans and turbo expanders at some of our mid stream facilities in this area. This will allow us to strip out the liquids from our gas stream thereby capturing more value and enhancing returns. Now nothing looking at Horn River, production averaged about 33 million cubic feet equivalent per day during the quarter. We've completed fracture operations on the south half of our 63-K pad with over 255 hydraulic fractures completed till the end of the quarter. This is the largest frac program to date in the Horn River. Over the course of about 110 days, we've completed an average of 2.3 fracs per day. Early production results are meeting our expectations with per well rate as high as 20 million cubic feet equivalent per day. Our Debolt water treatment facility is up and running and being used at our 63-K pad and the non-potable water from this formation currently averages 80% of the total water used at this gas factory. The cost of sourcing and supplying water represents about 12% of the total $600,000 per stage cost all in were approximately $75,000. With the Debolt water treatment plant, our teams expect to decrease this cost component by about 40%. Our realized year-to-date savings by using Debolt water have been approximately $5 million.

Lastly, our farm-out agreement with Kogas Canada Limited has been progressing well. In the Montney we've drilled a total of four wells year-to-date and we plan to drill about three more wells under this farm-out arrangement in 2010. At Kiwigana in the Horn River, our third quarter Kogas farm-out activity focused on constructing our first well site for a planned 10 well pad. We expect to start our first horizontal well in this area later this year. We believe there is a potential for expansion of our farm-out agreement with Kogas. So overall as I said at the start, very strong operational performance for the Canadian division.

I will now turn the call over to EnCana's Chief Financial Officer, Sherri Brillon, who will discuss our overall financial performance for the quarter.

Sherri Brillon

Thanks Mike and good morning. EnCana's third quarter financial results are strong particularly given prevailing lower natural gas prices. As Randy mentioned, cash flow for the quarter was approximately $1.1 billion or $1.54 per common share diluted. For the nine months ended September 30, cash flow was just above $3.5 billion or $4.75 per common share diluted. This keeps us on track to meet our full year cash flow guidance of $4.4 billion to $4.6 billion or $5.95 to $6.20 per common share diluted.

Third quarter cash flow was supported by increased production and realized after tax commodity hedging gains of approximately $211 million.

Net earnings for the quarter were just under $570 million or $0.77 per common share diluted. This figure represents more than a $1 billion increase when compared to EnCana's second quarter 2010 net loss of just over $500 million, largely due to the impact of two non-cash items, unrealized after tax hedging gains and losses, and non-operating after-tax foreign exchange gains and losses.

By way of example, EnCana's third quarter net earnings include unrealized after-tax gains on commodity hedging of roughly $331 million, whereas during the second quarter of this year we booked a $340 million unrealized after-tax loss. The same can be said for foreign exchange fluctuations with respect to our US dollar denominated debt. During the second quarter the weakening Canadian dollar resulted in a non-operating after tax foreign exchange loss of about $246 million, but this quarter with the dollar strengthening we have recorded an after-tax gain of approximately up $140 million.

We believe that operating earnings which exclude the volatility of unrealized hedging gains and losses and non-operating foreign exchange gains and losses are a better measure of the company's performance. For the third quarter EnCana's operating earnings were $98 million or $0.13 per common share diluted. For the first nine months of 2010, operating earnings were $597 million or $0.81 per common share diluted.

Before turning to our costs for the quarter, I'll talk briefly about our current hedge position. In Canada it is relatively well positioned when compared to our peers having approximately 45% of its remaining expected 2010 natural gas production or about 1.5 billion cubic feet per day sold forward at an average NYMEX price of $6.19 per thousand cubic feet.

For 2011, we have approximately 1.2 billion cubic feet per day of expected production hedged at $6.33 per thousand cubic feet and for 2012 approximately one billion cubic feet per day of expected production is hedged at $6.46 per thousand cubic feet. Hedging helps provide greater certainly to our cash flow thereby allowing us to execute more consistently on our capital and operating programs and our projected dividend.

Now turning to costs. Combined upstream and operating and administrative costs for the quarter were approximately $0.99 per thousand cubic feet equivalent. This represents about 17% year-over-year decrease. Our overall year-to-date operating costs have been trending below guidance, but due to potential fluctuations in foreign exchange and other expenses that are typically higher during the fourth quarter such as chemical costs, we have let our operating cost guidance at $0.80 per thousand cubic feet equivalent. However, we have reduced our expected administrative expenses from $0.35 to $0.30 per thousand cubic feet equivalent in our revised guidance resulting in a combined upstream operating and administrative guidance expense of $1.10 per thousand cubic feet equivalent for 2010.

Managing our cost is central to EnCana's long-term and disciplined growth strategy of maximizing margins to create shareholder value. As Jeff said in the US Division specifically, we have experienced overall year-to-date cost inflation of about 8%. So as mentioned earlier we have offset the majority of inflationary increases with improved operational efficiencies. Importantly, we do not foresee the same level of cost inflation in our Canadian operations, with this projected to be more in the low single-digit range for 2010.

As I mentioned during our second quarter conference call, I'd like to take a moment now to comment briefly on our DD&A expense and its impact when comparing EnCana to our US peers. Upstream DD&A expenses determined by the applicable depletion rate and associated level of production. EnCana utilizes full cost accounting where rates are determined and costs are depleted on a country by country basis, using total proved reserves based on a forecast price case.

Currently, EnCana's depletion rate is higher than some of our US full cost accounting peers, as a result of significant cost write-downs recorded by those peers in 2008 and 2009. These write-downs were primarily due to differences in price forecast used to determine proved reserve quantities required under US GAAP when compared to Canadian GAAP.

Subsequently, the impairment booked by our US peers allows them to apply a lower depletion rate. We expect EnCana's rate to trend down overtime due to the lower cost nature of our current and future development program. Note 23 of our 2009 year-end financial statements will provide you further details regarding EnCana's depletion expense under US GAAP.

Throughout this lower natural gas price environment, we have continued to maintain an exceptionally strong balance sheet with $1.4 billion in cash and cash equivalent and $4.9 billion available to us under unused committed bank credit facilities.

As of September 30, EnCana's debt-to-capitalization ratio was 30% and debt-to-adjusted EBITDA was 1.3 times on a pro forma trailing 12-month basis, we Steward the company to have a debt-to-capitalization of less than 40% and a debt-to-adjusted EBITDA of less than two times. All of EnCana's outstanding debt is composed of long-term fixed rate debt with an average remaining term of about 13 years. All of these factors worked together to help maintain the company's investment grade credit ratings.

Overall, EnCana's third quarter and year-to-date financial results have been solid. Cash flow remained strong. Our balance sheet is sound and our cost structure has continued to come down.

I will now turn the call back to Randy.

Randy Eresman

Well, thank you Sherri. The comments seen and I'm sure you picked up on and throughout our call today is our continued focus on maintaining and further lowering our cost structures. This was meant to underline that despite EnCana's stated shift towards a higher long-term growth rate, capital discipline remains at the forefront of our investment decisions. As I've said, we will not chase production growth at any cost.

EnCana's decision to pullback on it's completion in the Haynesville rather than pay inflated prices for some of the service providers is another example of the disciplined manner in which our teams operates. There are other more cost effective solutions for the short-term problems and our teams have focused on delivering those solutions in a timely manner. We apply this line of reasoning and this form of discipline across our entire portfolio of resource plays.

Speaking more broadly, we are constantly working to reduce our cost structures in order to maximize our margins and ultimately our returns on every single Mcf that we produce. Its part of our normal course of business, we continually hydrate our resource played portfolio by divesting the properties that no longer fit our future development plans. Grab higher cost structures and other plays in our portfolio.

To this end, we have divested total of about $600 million in assets so far this year, and we continue to look closely at other assets that maybe a good fit for potential divestitures including some of our midstream assets.

Joint ventures are and will continue to be another component of our business model that help to accelerate the value recognition of our tremendous resource base. Mike mentioned our farm out arrangement with Coal Gas and we also have numerous other similar arrangements either already in effect were under negotiation.

With the past three years EnCana secured more than $4 billion and third party capital investments. These arrangements include far most the target, the development of strong revenue streams with minimal capital risk. And the US are 2010 joint venture commitments include about $300 million in joint venture capital largely in a Piceance basin and the Haynesville that are helping to drive the assessment of our resource base.

Those stage assembly of our large land base, our first mover advantage is made EnCana an opportunity rich company with more than a 20 year drilling inventory. Finding new and innovative ways of turning all that opportunity into shareholder value on a timely basis is our ongoing focus. Looking forward, we believe that the current NYMEX natural gas price below $4 per million BTU is unsustainably low. They are continuing to be short term industry and market factors such as access to debt, lease hold requirements and lower demand growth to name only a few they are causing market price pressure.

Natural gas prices are lower than we had originally forecast and the flattening of the forward curve hindered our ability to hedge as much as we normally would have liked to.

This is an example of the November 2010 NYMEX contract is now trading at about $3.50 per million BTU, a level not seen since November contract of 2001. Given North America's ongoing over supplied natural gas and resulting low prices, we are following the near term growth rate through this capital investment and delayed completion of wells.

For longer term we plan to continue to build the underlying productive capacity of our enormous resource portfolio for future growth by advancing gas factory technologies, equipment and processes and by securing capacities for future growth.

Our low cost assets are capable of achieving our standard objective, doubling our production per share over five years from 2009 levels. However these low prices persist we will adjust our growth rate to align with our capacity to generate cash flow.

Thank you very much for joining us today, our team is now ready to take your questions.

Question-and-Answer Session

Operator

(Operator Instructions). We will now begin the question and answer session, and go to the first caller. You first question comes from the line of Greg Pardy from RBC Capital Markets. Your line is now open.

Greg Pardy - RBC Capital Markets

Good afternoon Randy just couple of questions. I hear what you are saying around un-sustainably low gas prices, but could you just remind us where you are headed at in terms of long term pricing now, that would be the first question and second one is just around the sharpening your focus on liquid for as you mentioned the Montney. But what are the other areas that you would be tapping into and then is there, is there like a waiting of liquids that you'd like to move towards over the next two or three years.

Randy Eresman

Our long term natural gas price expectation that we last than time we put it out. We thought the marginal cost to balance markets in North America was in the $6 to $7 range. I'd say with the advent of additional technologies that have helped us lower cost. Our expectation is probably on the lower end of that range going forward.

But we are today well below that and I am guessing that many of the industry players will have difficulty matching their cash flows in this kind of environment.

With respect to liquids rich plays in our portfolio. Largely the Deep Basin is an area that has a lot of liquids which are liquid rich gas or high BTO gas. There are few areas in the US operations where we are also pursuing opportunities to increase our liquids production.

But we are not stewarding towards any specific percentage mix of liquids in our portfolio. Its really going to be whatever part of our portfolio generates the best return that will attract our capital investments.

Greg Pardy - RBC Capital Markets

Okay thanks Randy and maybe just one follow up; it kind of comes back to the strategy. So just to be clear, if I look at my model now I think I am probably 13% or 14% growth rate in 2011. I think you have mentioned before its about $6 billion capital and $5 gas price to support that doubling of production over the next five years.

Is it safe to say that for sort of in $4 to $5 world debt? You would significantly scale back growth rates and potentially plough any free cash flow you might have in other areas like share buybacks or what have you?

Randy Eresman

What you said is exactly right that our long-term growth to develop production over the next five years was based on getting up to a capital investment, average of $6 billion per year and would have required an average annual growth rate of about 14%. We're in excellent financial shape. The company as Sherry said, we've got $1.4 billion of cash on the balance sheet. We have access to short-term debt, in a range of almost $5 billion. We will still have a fairly strong cash flow stream coming out based on our existing hedging program going into 2010 and our expectation for average prices. However our view right now is that in light of what could be an extended period of lower prices, its just not prudent for us to continue to develop natural gas production rate at that same pace in the short run but given the overall size of our inventory and our view that we do have one of the lowest cost inventories in the industry, that our goal should continue to be to build towards the opportunity to double production on a per share basis over the next five years.

Now what that really means for us is spending a lot of our energy now on honing and developing, the equipment and processes that are going to be required to get to even lower cost structures in the future using the gas factory approach to development which we are maturing, I would say in areas like the Montney and in the Horn River where we're getting to a bad pace, where we are starting to see some pretty interesting and amazing things happing. We're just at the early stages in the Haynesville and we've got other place in the portfolio such as in the US Rockies and the Piceance where we've been doing it for a while now. So we'll be spending and so that's one element of it and then the other element is there's several places in our portfolio where we will need to continue to expand processing capacity such as in the Horn and in the Montney. Those areas you know the build out on that equipment does take several years and so we will be continue to expand equipment for that future growth in those areas.

Operator

Your next question comes from the line of Andrew Potter from CIBC. Your line is now open.

Andrew Potter - CIBC

Sure just two quick question. Maybe if you could just update us a little bit on the joint venture activity, specifically the discussions with CNPC, so for instance does that mean thoughts on timing and confidence level that deal comes through? And then the second, turning the attention to Haynesville. As we move to this gas factory type of approach, maybe you can give us a bit of an idea in terms of what does this mean for overall activity levels in the Haynesville for you guys as we look in to 2011? I think you are saying 90 wells, your revised count in 2010, but if you go to gas factory, does that mean a higher well count or roughly the same or any thoughts on that would be appreciated.

Randy Eresman

I didn't mention anything with respect to our negotiations with PetroChina, CNPC on a conference call because we're still in the midst of those negotiations and I am not sure where they are going to go at this point in time but we are also working on putting out packages throughout many of our natural gas plays in Western Canada and the United States for potential participation by third parties and I think, let me get Bob Grant to just provide a brief update at where he's out on that but there will be more news about that shortly.

Bob Grant

Yes, we are just working with our advisors to prepare packages and we should have some Canadian properties ready to go within a few weeks and probably a month outbound have some properties in the US ready to go. So, the goal here is basically to find third party funding to help us accelerate the development of our properties where we wouldn't otherwise be able to get to for 10 past years in advance. So its fine to get some recognition for the value in the portfolio that we've developed and its really bigger then we can handle in short run. With respect to the Haynesville development, I am going to turn that over to Jeff Wojahn to provide some color.

Jeff Wojahn

You know the question on phase development we did turn our program back in the Haynesville from 110 to 90. One of the big positives I would say coming out of the last six months of activity in the Haynesville is that we have been successfully been able to negotiate with land owners I'll say more flexible provisions in regards to land profession, and in Louisiana most of the fee land requires one producing quantity well persecution and in some cases we may not approve it.

Now as well as that, as we've gone through the land retention program, by and large we delineate it our land, our core position is much better and we've also been able to make decisions on some land either to allow to expire because of challenges related to drilling your structure and also related to core performance. And so we think there will be about 12,000 acres of land that we can allow to expire through the process but of course through that process we've also been able to develop a great deal more confidence in what the core area, what the gas factory drilling, so geological evaluation is something that is a benefit that comes out of the land retention strategy.

Those factors I think next year, we have three gas factory operations going on right now, one of those gas factory operations has been in operations for I'll say six months and the results have been very strong, above our tight curve and our EUR. So clearly we'll be able to move into the best geological areas and also focus on improving our drilling and completion activities.

The challenges of course we have in regards to pace development there you know as Randy mentioned, I mentioned were around completion equipment and availability and cost structures. We're working diligently on that. But I don't perceive that we materially will be able to bring in new solutions, intermediate solutions until the second half of next year.

So overall pace of development in Haynesville we have more flexibility, and I would believe depending on where we land in our budget cases, that we will see a moderation in our drilling activity as we move forward. We have 30 operated rigs currently running in the ploy. When we look at the scenarios for next year, clearly we're not as much land retention focused and clearly we'll be moving to gas focused drilling, but the likelihood is that we'll have a moderate program to what extent we'll get more clarity as we move through the budget.

Andrew Potter - CIBC

Then just coming back to the joint venture question, the Canadian property that you're putting the package there in the coming weeks, are those similar properties to what you were considering with CNPC? I mean I guess what I'm guessing at is there a read through from these packages coming on to the market in terms of your confidence level with the other process?

Randy Eresman

The packages will also include Alberta based properties.

Operator

Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is now open.

Brian Singer - Goldman Sachs

Following up on a couple of the earlier questions, you commented you plan to drill less aggressively in the resource plays as this gas prices, though when we look at a $200 million deferral in your CapEx plan, it seems to be more a function of the completion constraints that you highlighted. Can you provide more color on what specific actions you would take if the current future curve does not rise from here and I guess somewhat similarly at what gas price or reduction in Haynesville costs would you resume your prior trajectory?

Randy Eresman

I think Brian what I was referring mainly was for 2011 preliminary thoughts around the capital budget would be significantly lower if the current prices are maintained. We would take into consideration our view of the sustainability of that price. We would take into consideration our cash flow and our ability to continue to access cash that we have on hand and debt. We want to make sure that we run our company relatively conservatively, but we also have some of the lowest cost structures in the industry and so there will be programs that we will continue to move forward with. And as I said, there are certain areas of the company that will need long-term processing capacity and also we are still developing the understanding of the ultimate cost structures that will exist once we get into full gas factory work that we would continue to pursue. We have less requirements as Jeff said to retain land, so we have considerable flexibility across our portfolio as to where we put our money. But I would think that if it persists, we will cut back further on our CapEx program and look closer to what we were otherwise planning to our cash flow. I wouldn't say we are going to live exactly within cash flow.

Brian Singer - Goldman Sachs

And then going to the Haynesville, I have some questions for Jeff here: first, what do you think you are when particularly your midstream constraints and what land retention you may have left into next year? What is the recount you may have to deploy there, and then when you think about the combination of current delays and getting facts done combined with your gas factory strategies. How many days does it take to get a well drilled, completed and tied in today and where do you expect that to be in 2011 or 2012?

Jeff Wojahn

Brian, this is Jeff Wojahn. You asked a lot of question, so I will try to sort through them a little bit. I wanted to talk a little bit about completion costs and our thoughts on that which was I think one of your earlier comments. We are trying to find a happy medium with our vendors so that they have an acceptable return to maintain viability in their business, long-term. I think our philosophy towards our vendors as we move more towards gas factory drilling it's more of a partnership relationship and potentially longer term relationships versus I'll say more of a traditional model. And one other thing that we haven't been happy with in the Haynesville Shale as we move through our land retention strategy, the technology, the completion equipment itself or their current equipment that is in the market that's so called conventional humping equipment just is not built for the duty cycles that we require in the Haynesville. It's not built for the high pressures and we've had a lot of problems which were a liability and maintenance of equipment.

So we envision, as we go through the periods where we move more towards gas factory that there's an opportunity to develop more reliable and an increased technological focus around the type of completion equipment we have. So you know on the short term, we need to have higher reliability and more reliability around robust pumps and redundancy and horsepower. As we move forward longer term, then I think what we're going to be looking at is fit-for-purpose equipment that's suited specifically for pad drilling around gas factories and the solutions for that, I think the intermediate stage of higher reliability and more robust pump technologies will be at a minimum six to nine months out probably 12 to 24 months out and then fit-for-purpose full blown, the way we envision it would be starting 24 months out from now. So that's a strategic initiative that I think you'll hear more from EnCana going forward.

Cycle times, I mentioned earlier, we had 20 net wells. We've clearly seen cycle times widen because we're increasing the number of standing wells and we talk about existing the year at 35, and currently we have a operated rig fleet of around 30. So we haven't envisioned dropping that rig count significantly. We'll do it in an orderly manner depending partly on contractual arrangements that we have with our service providers but also relative to the choices we choose, the choices relative to our budgets moving forward. So I think you'll hear more about that as we introduce the budget cases and more specifically, the budget and the plan around the Haynesville.

Brian Singer - Goldman Sachs

And just a last follow up on your comments just there. If we go ahead 24 months, where do you expect the average well cost to be in the Haynesville relative to you and how long do you think a well takes to drill?

Jeff Wojahn

Well cost in the Haynesville depending on the depth, the pressures and the temperatures vary between $7 million and $9 million for us, and we average about $9 million in our current program and we can envision. Everything that's happening is the scope of the programs changing. We are drilling longer laterals with higher intensity, but assuming that we stay at the current well section horizontal, so 4,300 foot horizontals, we envision that there will be savings in the 15% to 20% range over the next 24 months associated with gas factory drilling. And of course when I look at fit-for-purpose drilling technology that we have talked about a great deal longer term as we move through generations of efficiencies, we've seen 30% to 40% decreases in well times and in efficiencies, and I wouldn't be surprise to see that kind of efficiencies longer term related to our pumping times.

Cycle times, I don't have that information specifically there but I think the time would be probably higher percentage improvement in cycle times than the cost savings that I just mentioned.

Operator

Your next question comes from the line of Mark Gilman from The Benchmark Company. Your line is now open.

Mark Gilman - The Benchmark Company

I had a couple of things. Could you comment Randy or anyone else on whether there was shut-in gas specifically not differed completions but shut-ins in the third quarter and what your plans on that subject might be going forward?

Randy Eresman

Mark, we didn't shut any gas in at all this year. We know we brought a bunch of gas back on in the first and second quarters of the year than we had shut in last fall. I think we are now getting to prices or we start considering it, its one of the things we do on a field-by-field basis try to make sure we understand particularly those areas that have the highest variable cost and have the least implications from a shut-in. So that's one of the things we would be going through as we speak. But we have…

Mark Gilman - The Benchmark Company

Okay if I could raise another one, Sherri you talked about DD&A rates trending down can you perhaps provide a little bit more specificity in that regard both in terms of timing and extent?

Randy Eresman

Mark I am going to answer that, whereas Sherri would be thinking about that is in respect to our expectations for continually driving down our overall F&D cost with the lower cost assets and resource development that we're currently undertaking. In our expectation on a go-forward basis is that our F&D cost would get in the range of $50 in the short run, now I'm not going to say that specifically what's going to happen at year end this year but that's sort of what our technical looks like.

And in the longer run we see that it could possibly get down further than that and so balancing that and the pace of development of new resources against our existing resource basis what would tend to make that come down

Mark Gilman - The Benchmark Company

Okay thanks Randy and one word for Mike Graham if I could, Mike regarding the liquids stripping that you were talking about. Are we talking primarily about additional ethane extraction and given what's going on with respect to ethane prices and the weakness that we are seeing as a result of this activity being relatively wide spread? Are you convinced this is an economic route to go?

Mike Graham

Mark I am going to turn that question over to Renee Zemljak head of our gas Marketing & Fundamentals.

Renee Zemljak

Hi, thank you Mark, we've done quite an extensive study this summer with regards to all the fundamentals on asset supply and demand and specifically we spent a lot time on ethane because we are unlike Mike said looking at some deep cut opportunities for the Deep Basin. Over the long-term there could be some constraints associated with ethane pricing.

But based on the economics that we have ran very recently we are not seeing that as bottle neck. In fact the contracts that we could actually lock in over the long-term make these projects very economic.

Operator

Your next question comes from the line of Mark Polak from Scotia Capital your line is now open.

Mark Polak - Scotia Capital

Thank you couple of questions first we will just, with your more subdued outlook on gas prices and growth in the short-term does that effect your thinking on the negotiations you see in terms of timing of a deal or scope or anything like that.

Randy Eresman

I think that effects the forward curve has some impact on everybody's views of what the value of any asset is. And so on any of our negotiations right now you will take into consideration what you think the price deal is but you also take into consideration what the quality of the asset is and what it might be able to deliver.

Mark Polak - Scotia Capital

Thanks and couple of questions on the Haynesville for Jeff if I could. You mentioned 30 operated rigs is that 30 EnCana operated rigs that does not include shales as well.

Randy Eresman

That includes shales as well although shale does operate rigs within our EMI area as well.

Mark Polak - Scotia Capital

And just looking out into next year for the land retention strategy was differing some of the completions this year, I think previously you talked about having about 50 wells remaining next year to get through your retention so does that be about kind of 60 to 70 wells needed to finish that up next year and that would occur sometime second half of the year?

Randy Eresman

We are starting to think that through land negotiations that 50 plus, the deferral of those wells this year can be two fold spread out over the next two to three years but also some of those wells being actually negotiated through cooling to the extent where we don't require to drill as many as well so you know that 60 wells maybe half as much that is required to drill from a land retention point of view and those remain other 60 maybe 30 would be required but that 30 maybe spread out over next 2 or 3 years so we think the scope will be quite small relative to our overall program and I think its going to be something that's really quite manageable on our day-to-day operations.

Mark Polak - Scotia Capital

And then the last one would be just is that something that you see sort of for the broader industry in the Haynesville in terms of negotiations and do you see land retention in general being less of an issue in the next couple of years and being more manageable. What is your thoughts on where the overall rig count is now and heading?

Randy Eresman

The answer is yes. I think this is not only a solution that is great for EnCana but I think other operators and the land owners as a whole in Louisiana are looking at more constructive solutions as a whole so I think a lot of the land retention drilling within the Haynesville will moderate throughout next year and by mid-year you are going to see a lot of other operators saying that the hard work is behind them.

Operator

Your next question comes from the line of Bob Morris from Citigroup; your line is now open

Bob Morris - Citigroup

Jeff and Mike, you mentioned the volume that you sold in the US and Canada a year ago but you didn't mention the volume that was shut in both US and Canada that was brought back online versus a year ago. I know one time it was 300 million a day but some of that went into Cenovus when you did a spin off. So I was just wondering what on a pro forma basis the shut in volumes worth it, added to that growth year-over-year?

Jeff Wojahn

Yeah 300 million, this is Jeff Wojahn speaking. The 300 seems like a good number it could have been a little higher than that certainly places like East Texas where we very large volumes and Piceance Basin is where we had very large volumes but you know we do a look back if anything that base performed a little better than we had thought.

Bob Morris - Citigroup

And Randy, driving down your cost here, and looking at issues you are having in the Haynesville frac equipment both availability and durability or technology of the equipment and one point you mentioned that vertically integrating and perhaps owning your own equipment in cleaning frac equipment is that something that is still a consideration.

Randy Eresman

Bob what we are really focused on right now two-fold; one is the short, dealing of the short-term issues that Jeff has spoken about which we are in the process of doing, and those will be done through third party arrangements. But what we are also looking at is and what is a long-term equipment that we need that is going to be specific fit for purpose equipment for the Horn River for the Motney, for the Piceance, et cetera in our portfolio.

That equipment we have been spending last year designing, we got some really good thoughts about what that might look like in terms of physical equipments, we haven't finalized it yet its going to take a while longer but the phase that follows that will be what kind of commercial arrangements do we enter into to make that equipment happen, and it could be a vertical integration model although that would be a deviation from the way we have acted historically or it could be working with service providers to provide us specific arrangements or relationships which could take any kind of form. So, we are not there yet, but we are open to all sorts of thoughts about how we might do this.

Bob Morris - Citigroup

Okay. Jeff, quickly on when you are talking about the gas factory and pad drilling on the Haynesville I though I heard you mention improved EURs. What are you seeing as far as the EURs on the better areas in your drilling care on the gas factory side?

Jeff Wojahn

What we've see in the Haynesville and like what we've seen in the Horn River and other areas is longer linked higher factory complexity, higher stimulated rock volumes provides higher EURs. So, we are seeing that evolution in the Haynesville like other Shale plays and specifically in the gas factory areas, one of the gas factory areas that we were able to conduct operations this year, we were able to form an irregular section so to speak, it allowed us to drill a little longer and because we are able to drill longer we are able demonstrate that we were able to get higher EURs.

So and the other part it of course is we are selecting the gas factory locations in the absolute best reservoir in the Haynesville, and that in itself gives us above average type of a performance. And that kind of customized solution in the core areas will give us higher EURs.

Bob Morris - Citigroup

So we are talking above 6.5 Bcf EURs or order magnitude.

Jeff Wojahn

Yes, we are talking 7.5 Bcf EURs to hire.

Bob Morris - Citigroup

And then last question, any update on the Collingwood Shale? I know you had drilled your first horizontal well. Earlier this year there was a land sale program last quarter so you can talk about it, but have you drilled a second well there or what is going on there?

Randy Eresman

The land sale is next Tuesday, so we are not going to comment.

Operator

Your next question comes from the line of John Hurlin from (inaudible). Your line is now open.

Unidentified Analyst

Just some quick ones. Jeff mentioned how many wells would be waiting fracing at year end in the Haynesville, but what about Kent?

Randy Eresman

Mike, do you have any? We always have an inventory of course you know that John, but I don't think we have we're backed up really in the same way as we were in the Haynesville, but I'll like Mike Graham answer that.

Mike Graham

For all of Canada, is it John you were talking?

Unidentified Analyst

Yes, well the company as a whole, but yes the Haynesville, Piceance, et cetera.

Mike Graham

Yes, well I can tell you in the Horn River we've essentially finished fracing our 63-K pad, but we've moved on to the next pad and we're drilling that, so it will be a while before we frac anymore wells there. In Le Monde, we continue to have some wells kind of to come on, but not anywhere probably like the Haynesville. So you've seen tremendous growth out of both Le Monde and in the deep basin of Alberta what we call Big Horn as well, so to that extent John, probably not as much. We do have a fairly big inventory of CBM wells to be completed. We drilled a lot of CBM wells this year, about 430 year-to-date, and we plan to drill 880 and get those tied in. So I think you'll see production especially in the CBM kind of ramp up and then as we bring our new 63-K pad on you will see quite a bit of production come out of Greater Sierra in particular Horn River sort of in Q4 if you will. But we are kind of moving along we got one frac who is working for us in the Horn River and about three or four I think in the Deep Basin.

Unidentified Analyst

Thanks. With respect to GTPM, you mentioned I think Randy mentioned that you might consider monetizing assets, does that mean a trust or an LP or an outright sale?

Randy Eresman

I'm sorry we didn't actually hear what you said.

Unidentified Analyst

I'm sorry you had mentioned you'd possibly monetize GTPM assets processing assets.

Randy Eresman

I'm sorry okay we have quite a large inventory of midstream assets in our portfolio. There maybe an opportunity for us to monetize in such one of the areas we're looking at. And then the far amounts are a form of monetization that we also think them as a form of acceleration because what we farm out is things that we wouldn't be able to get to for a very long period of time.

Unidentified Analyst

Last one from me is with respect to hedging; you're disposing a manufacturing analogy your good look host operator. Prices given the lack of areas to entry in today's world would add free capital. Free capital means that we could have pricing cycles be more compressed to past. But if the who of you to hedge more going forward than historically done have you thought about that?

Randy Eresman

We think about that all the time, we think about what we could have done, what we should have done. We do acknowledge that there is a lot of reasons for prices to be lower and then historical expectations have been and in our view is the way in which just to play this game is to have the lowest cost structures in the industry. So that's what our number one focus is but having said that when it comes to developing our capital program for the year we have taken into consideration our outlook on prices for the year but also the amount of hedging that we have done for the year and it does play and this year it's going to play a bigger role and amazed in other years in terms of our capital programs. I know that's not a complete answer for your question but that's a pretty tough question.

Operator

Your next question comes from the line of Aaron Diamond from Highfields Capital; your line is now open.

Aaron Diamond - Highfields Capital

Hi guys. Just a quick question with respect to sort of where gas prices are and what the opportunity could be relative to your stock. Does it make any sense to cut back further on capital spend and become more aggressive in repurchasing shares, just to give you opportunity to wait for the time the gas prices could come back and at the same time buy your stock. It looks like really attractive prices, and my understanding is I wouldn't want to do that if you didn't have the cash available to do it. Which is why I asked by restraining potential capital spend.

Randy Eresman

Again tough question, view I guess that we would have is that our stock is undervalued; of course we would view that. In terms of maybe not so much on the pricing side but on the idea of the size of the inventory and the quality of the inventory that we have.

Aaron Diamond - Highfields Capital

We would definitely agree with that.

Randy Eresman

Thank you.

Aaron Diamond - Highfields Capital

But I guess, so the reason I asked that is if that's the case, does it make sense when returns aren't as good as they been for a long time to just spend a whole lot less and just take advantage of that opportunity that you don't seem to be getting paid for now in the stock market.

Randy Eresman

Right. And that's kind of what I'm signaling is what you might expect for next year is that I won't say we're going to accelerate share repurchases but reduce spending which would be directly towards the growth element of the company while at the same time making sure that we position the company for long-term growth because we do believe that the near term prices are lower than really what the industry requires to continue.

I think there's a lot of factors in plays right now that were causing the short term pricing to be lower than what it will take to for industry investors to make money.

Aaron Diamond - Highfields Capital

Oh yes, no we would defiantly agree. The other thing, it would just seem like if you look at the price of private transactions, they would just seemingly be much higher than where any of the stocks trade to that. It would just support what you say.

Randy Eresman

Yes.

Operator

Your next question comes from the line of George Toriola from UBS. Your line is now open.

George Toriola - UBS

Randy, you've talked about what your supply cost for natural gas is but if you could go through what your full cycle cost, if you were to include land and infrastructure and all of those things, what's your average full cycle cost on your resource plays would be today?

Randy Eresman

All right, one of the things that we do or have been historically on an annual basis is we've been holding an investor day and I don't think we've have got one scheduled just yet but during that investor day we normally put out a fairly comprehensive book about our entire portfolio which goes through each of the plays in terms of what their supply cost are and all of the other inputs into the supply cost, but given that coming into 2010 what we did say is that out half cycle, so that's the go forward cost that we require, what we call a supply cost is the price that we require, the NYMEX price that we require adjusted to our fields, to get a cost to capital return and we use 9% after-tax as a proxy for that.

That supply cost coming into this year, I believe was about 385 for our average portfolio of investments and if we added on to that, so that is fully loaded with G&A, what it doesn't have is the cost of the land but it does include all of the infrastructure and all the go forward cost to develop. So, given that land cost can be on his recourse plays. There is a range of prices but I would say on average for our portfolio it's less than $0.50 per Mcf and in most plays our land was achieved years ago at very low cost and so is substantially less than that. Going forward, our view is that with an estimate of technical reserve additions that we are seeing and Mike talked about numbers you can get to less than a dollar and other points in our portfolio of $1.50. If we get into that range we could probably see another $0.50 to $1 being pulled off of that supply cost once we get to full manufacturing operations. So hope that's giving you an answer George, but if you want more of the detail on the individual plays, it's one of the things we do have detailed in some of our investment material.

George Toriola - UBS

And secondly, as you talked about the focus on liquids-rich place, would that be suggestive that we will see more capital spend in Canada versus the US going forward?

Randy Eresman

We will look for those areas in our play and our portfolio where liquids exist, but it is really our capital investments going to be determined on what or where we see the highest value generation. It won't really matter whether it's liquids or not but today with a price difference between NYMEX oil price and/or say WTI oil price and gas prices it does seem logical to have more liquids-rich and oil plays in your portfolio.

George Toriola - UBS

And then finally just looking at the well count, just in the US looking at the gross wells you drilled Q1 through Q3 and looking at your sort of production profile, there seems to be and I am not sure if this is just due to wells within completion, but it seems like your well count is growing, but your production profile is not as a total, is not necessarily growing, would that be something you can comment on. Is that due to wells within completion or how should we be looking at that?

Randy Eresman

There's two factors that apply here: one was third quarter of, a certain fourth quarter of 2009. We shut in a significant amount of production in a couple of our players, one was in East Texas and one was in the Piceance, in the US. And to some degree I think we would join as well. So, that production was brought back and you kind of in the first quarter of this year, first and second quarter and it appears to be a surge of production coming in which affects our profile and then secondly we do have that deferral of completions in the hands of the whole area. And I don't know, Jeff if you got any more to add, but it does cause an erratic profile in many areas of our company this year.

Operator

Ladies and gentlemen at this time we will now take questions from the media. (Operator Instructions) Your next question comes from the line of Judy Myrden from The Chronicle Herald. Your line is now open.

Judy Myrden - The Chronicle Herald

This question may be directed to Mike Graham. I am just wondering on the Deep Panuke offshore project, I understand costs are going to be up slightly higher than $800 million now?

Mike Graham

Yeah Judy, Mike Graham here. We have a sense to finish the drilling operations on the East Coast of Canada now. We have released the Rowan Gorilla III, so we actually did recompleted those four production wells. They actually looked pretty good 50 to 100 million cubic feet a day, so there were right where we expected. To do with costs, we have experienced a little bit of cost increase are on Deep Panuke but its more to do with probably FX for one, the other one is weather, it took us a little longer to re-complete the wells and we first expected. We had a hurricane kind of go through so we took everybody off the Rowan Gorilla III there for a while, then we just had a little bit of problem getting under the harbors as well but the legacy costs are up slightly in Panuke we are talking maybe 15%, 20% sort of from when we first talked about the projects and first as we approve the project. So not too bad and overall the production field center is planned to come out to Abu Dabi sort of Q1 and really the last remaining bit of work to do there is just to bring the production field center out of the middle east and hook it up, so we do expect first gas still sort of second half of 2011 about a year behind of what we originally targeted.

Judy Myrden - The Chronicle Herald

Up 15% to 20%, so what would that put the price take at like slightly over 800 million or…

Mike Graham

Yes we are still kind of getting a tally in all the cost, we did say that we come out just on exactly where we are at after our drilling program so legacy we are just, we've just released the rig and we are tallying on those up but you know somewhere in that order.

Judy Myrden - The Chronicle Herald

Just one last question, just on production and with the low natural gas prices would you consider shutting in Deep Panuke.

Mike Graham

Well you know I was to hazard, I guess at that probably not in Deep Panuke, we have a lot, we have a lot of fixed sort of cost with the production field center and what not and maybe Renee would like to comment a little bit more.

Renee Zemljak

Sure the net back associated with the properties because it does access a market that's a premium, we have price really isn't all that different than what we would receive in a net back for our WCSB product.

Judy Myrden - The Chronicle Herald

So what are you expecting production to be at Deep Panuke when it comes on stream?

Mike Graham

We've actually designed the facilities for about 300 million cubic feet a day we have contracting capacity for 200 so we'll probably bringing that on in an around that 200 million cubic feet a day where you know we will have the ability affairs excess capacity to flow it higher than that.

Judy Myrden - The Chronicle Herald

Right so I know people being talking about these low gas prices, but do you still expect production to be strong at Deep Panuke?

Mike Graham

Yes like you say all the well tested very strongly all for re-completions we did the wells tested very good, so we are happy to see that and you know we are definitely able to flow in access of 200 million cubic feet in the second half of 2011.

Operator

Your next question comes from the line of Amanda Fraser from AllNovaScotia.com, your line is now open

Amanda Fraser - AllNovaScotia.com

We learnt yesterday that maritime in (inaudible) pipeline was looking at an increase to the total on the actually inside of the line, I was just wondering what that effect would have, what that, how it would affect production in Deep Panuke.

Mike Graham

Yes Amanda, Mike Graham here we are looking at that yes they have said they were going increase that I think just the Canadian portion of our total actually increase is what I understand but we are looking at it right now and trying to get our heads around it.

Amanda Fraser - AllNovaScotia.com

If the increase does go through how will that affect production for Deep Panuke.

Mike Graham

Well like what Renee we do have a fairly strong price at that point so obviously production will still be the same.

Amanda Fraser - AllNovaScotia.com

With the potential total increase and the price of natural gas how do the general economics of the project look right now?.

Mike Graham

Well since most of the capital has been spent there with the economics going forward are obviously very, very strong. So our overall may be not quite as strong as we would have thought at the time when we actually approved the project.

Amanda Fraser - AllNovaScotia.com

Can you elaborate a bit on that?.

Mike Graham

You know well I guess they were still tallying up the costs that we will kind of figure that our that at the end. But like you see overall you know we're still definitely economic in for the mid-teens thing on return overall somewhere in that order.

Operator

Your next question comes from the line of Shaun Polczer from Calgary Herald, your line is now open.

Shaun Polczer - Calgary Herald

In terms of some of these service constraints that you are experiencing in the United States, is it because of a lack of fracturing capacity or is it just more in terms of the rates that the service companies are wanting to charge?

Randy Eresman

Those are two interrelated things because of the high demand for hydraulic pressuring equipments in many of the shale gas plays across United States there is high demand and then high demands creates opportunistic pricing and so what our view is that some of that opportunistic pricing we can avoid by entering into longer term arrangements with service providers, and so that's what we're doing. We just stopped paying up today.

Shaun Polczer - Calgary Herald

And are you experiencing any of those same issues in Canada?

Randy Eresman

Not to the same extent at this time.

Operator

Your next question comes from the line of Jeff Jones from Reuters. Your line is now open.

Jeff Jones - Reuters

My question relates to the stakes that you'll be offering in longer term Canadian and US plays, and it's kind of a two part. The first one is do you have sort of a minimum and maximum size of interest you'd be offering? And then second of all, I mean how much of this is related to the gas price environment? And by that I mean considering that they are long-term plays would you be still seeking to unlock this type of value if gas prices were higher?

Randy Eresman

I would say yes it has very little to do with the current gas price environment, and everything to do with the size of the inventory that we carry. When we started developing our inventory we far exceeded our expectations for the quality of resource and the size of the inventory that we actually created. And so it presented an opportunity for us to find ways to accelerate the development of those resources.

We are primarily with a program that Bob Grant has talked about. We'll be looking for large industry partners for large participation for large deals. And these deals will be largely centered on areas of our portfolio that we wouldn't otherwise be able to get to for very long period of time. We are and have for years been doing smaller deals on specific assets and I would imagine that we outside of this program we will continue to do that into the future.

Jeff Jones - Reuters

So you would looking at some point maybe even to give up sort of a majority stake in some of these or would it all be sort of up to 50% kind of thing.

Randy Eresman

I think in our largest highest quality assets it's unlikely that we would farm-out more than 50% and most likely the way a lot of these deals are structured, we are taking a piece of the asset, not the entire asset and farming that out. So our stake in the assets and our biggest ones will likely always be higher than 50%.

Operator

At this time we have completed the question-and-answer session and will now turn the call back over to Mr. McRitchie.

Ryder McRitchie

Thank you everyone for joining us today to review EnCana's third quarter results. Our conference call is now complete.

Operator

Ladies and gentlemen this concludes today's conference call. You may now disconnect.

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