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Encana, (NYSE:ECA)

Q2 2011 Earnings Call, Jul 21, 2011

July 21, 2011 1:00 pm ET

Executives

Jeff E. Wojahn - Executive Vice President and President of USA Division

Renee E. Zemljak - Executive Vice President of Midstream Marketing & Fundamentals

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

Randall K. Eresman - Chief Executive officer, President and Director

Sherri A. Brillon - Chief Financial officer and Executive Vice-President

Michael M. Graham - Executive Vice President and President of Canadian Division

Bob Grant -

Ryder McRitchie - Vice President of Investor Relations

Unknown Executive -

William A. Stevenson - Chief Accounting officer and Executive Vice-President

Analysts

Dan Healing

John P. Herrlin - Societe Generale Cross Asset Research

Scott Haggett - Reuters

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

Amanda Fraser - AllNovaScotia.com

Robert Bellinski - Morningstar Inc., Research Division

Carrie Tait - National Post

George Toriola - UBS Investment Bank, Research Division

Brian C. Dutton - Crédit Suisse AG, Research Division

Lauren Krugel

Mark Polak - Scotia Capital Inc., Research Division

Robert Brackett

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Second Quarter 2011 Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the express 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 welcome, everyone, to our discussion of EnCana's 2011 second 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 36 of Encana’s Annual Information Form dated February 17, 2011, the latter 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, please note that as of January 1, 2011, Encana adopted International Financial Reporting Standards for financial reporting purposes, referred to as IFRS throughout this call. Prior to 2011, the company prepared its financial statements in accordance with Canadian Generally Accepted Accounting Principles, referred to as previous GAAP.

The company reports its financial results in U.S. dollars. Accordingly, any reference to dollars, reserves, resources or production information in this call will be in U.S. dollars and U.S. protocols unless otherwise noted.

The adoption of IFRS has not had an impact on the company's operations, strategic positions or cash flow. Reconciliations between previous GAAP and IFRS financial information can be found in the consolidated financial statements available on the company's website at www.encana.com.

Randy Eresman will start off with some highlights from the quarter, and then Mike Graham and Jeff Wojahn will provide an overview of the operating results from the Canadian and U.S. divisions. And then we will turn 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.

Randall K. Eresman

Well, thank you, Ryder, and thank you, everyone, for joining us today. During the second quarter, Encana generated strong cash flow and operating earnings in spite of natural gas prices that remain at levels that we believe are unsustainably low in the long term. Cash flow for the quarter was approximately $1.1 billion, and operating earnings totaled about $166 million. For the first half of the year, cash flow totaled about $2 billion, and operating earnings totaled about $181 million. The second quarter total production of approximately 3.46 billion cubic feet equivalent per day was ahead of our expectations, and we're on track to achieve our 2011 targeted average annual production rate of approximately 3.5 billion cubic feet equivalent per day.

During the quarter, capital expenditures, excluding acquisitions and divestitures, totaled about $1.1 billion. And year-to-date, we've invested about $2.4 billion of our planned $4.6 billion to $4.8 billion capital program. We're focusing capital on our highest value natural gas resource plays while investing in the foundation of growing the capacity for production across a number of promising plays with significant liquids potential.

The first 6 months of the year, we completed the divestiture of noncore assets for approximately $127 million in the Canadian division and about $313 million in the U.S.A. division. That included the sale of our Fort Lupton natural gas processing plant in Colorado.

We currently have a number of competitive sale processes underway in both Canada and the United States, and we have set our net divestiture target for the year at between $1 billion and $2 billion. The assets for sale include a number of our midstream and processing facilities such as the Cutbank Ridge midstream assets in Alberta and British Columbia, our Piceance gas gathering system in the U.S. Rockies and our interest in the Cabin Gas Plant, which is under construction in Northeast British Columbia. We also have divestiture processes underway on a portion of our Jean Marie property in the Greater Sierra key resource play. Expected proceeds from the assets I just mentioned, together with those from the divestitures of noncore properties, will supplement our cash flow generation in the current low-price environment and will provide us financial flexibility going into 2012.

Expanding on our plans to attract third-party capital investments in our high-quality undeveloped assets, we completed an upstream joint venture development agreement with Northwest Natural Gas Company, which will result in Northwest Natural investing about $250 million over the next 5 years to earn a working interest in certain sections of our Jonah field in Wyoming. Structure of the transaction provided favorable funding for Encana and allowed the utility to earn a regulated return on their investment, while providing its customers with a reliable gas supply at a more predicable cost rather than at fluctuating market prices. We believe that this innovative transaction can form a template for similar future deals.

We also entered into an agreement to be the sole supplier of liquefied natural gas to a fleet of 200 LNG, heavy-duty trucks in Louisiana through our mobile LNG fueling station. In addition, we opened 2 compressed natural gas fleet fueling stations in Colorado and British Columbia. The cost advantage and environmental benefits of natural gas create a compelling case for Encana and others to adopt natural gas as a transportation fuel of choice in North America.

I'd like to take a moment now to discuss the end of our negotiations with PetroChina on the proposed joint venture involving our Cutbank Ridge business assets. Despite a strong desire by both parties to complete this transaction, we were not able to achieve substantial alignment with respect to key elements of the proposed transaction, including the joint operating agreement. We'll continue to respect the confidentiality provisions of our discussions with PetroChina, so I'm not able to provide more details on specific elements of the deal that we could not come to agreement on. However, what I can share with you is that the process we undertook has gone a long way to demonstrate the tremendous value that we've created at Cutbank Ridge.

We're committed to pursuing the right transaction for our shareholders, and we'll continue to explore opportunities to accelerate recognition of that value. And as such, we're moving forward with a variety of joint venture opportunities for portions of the undeveloped resources. We have accomplished history of realizing significant value from our enormous resource potential through competitive processes that secure premium joint venture partners. Although we won't comment on the specific details until definitive agreements have been signed, I can tell you that interest has been strong, and it is indicative of the high quality of these assets.

With that, I'll now turn the call over to Mike Graham for an update on the second quarter results from the Canadian division.

Michael M. Graham

Thanks, Randy, and good morning, everyone. The second quarter of 2011 was another period of excellent performance from the Canadian division. Production for the quarter was approximately 1.5 billion cubic feet equivalent per day, up about 9% from the same period last year due to a successful drilling program. Year-to-date, production from the Canadian division is up 13% compared to the first 6 months of 2010.

Our second quarter operating costs averaged $1.08 per thousand cubic feet equivalent, up 13% compared to the second quarter of 2010 due to higher electricity costs and a stronger Canadian dollar and higher repair and maintenance costs, partially offset by longer or lower long-term compensation costs. Excluding the impact of foreign exchange, operating costs were $1.02 per thousand cubic feet equivalent.

Our Cutbank Ridge key resource play performed exceptionally well during the quarter, driven by production from the Montney formation. We saw strong results across the play despite the unusually wet weather experienced during the quarter in the Peace Country. Production averaged 535 million cubic feet equivalent per day, up 20% from the second quarter of 2010 and up 3% from the first quarter of 2011.

During the quarter, we saw some very promising results from wells drilled across our Cutbank Ridge land. We successfully completed our second Steeprock Doig horizontal well with an initial production rate of 18 million cubic feet per day, and we plan to drill 2 additional wells in this formation in the second half of the year. Additionally, we commissioned to add 2 well pads in the Montney where the condensate-to-gas ratio exceeded our tight curve expectation by 25% on average. The initial production rates from these wells were 3.5 million cubic feet per day and 4.1 million cubic feet per day with condensate levels of 40 barrels per million cubic feet and 90 barrels per million cubic feet, respectively.

In the Horn River, we commenced completion operations on the north half of the d-1-D pad. And by the end of the quarter, we had completed about 60% of our planned stimulation. Our partner, Apache, completed stimulations operations on the 34-L pad, pumping 162 stimulations into the 9 wells on this pad. So far, the wells are performing at or above expectations. For the 5 [indiscernible] wells, the 30-day average initial production rate per completion interval was 15% higher than our expectations or about 12 million cubic feet per day per well. The 4 EV wells had an average 30-day initial production rate of 10 million cubic feet per day equivalent, which is about 3x better than the previous EV wells.

The Debolt water plant performed exceptionally well during the completion operations at 34-L. Over 95% of the water used in the completions was sourced from the Debolt plant, which reduced our environmental footprint and also saved us over $3 million or about $0.80 per barrel in water supply costs.

We are seeing excellent performance this year from our Jean Marie play. We have maintained a flat 2011 production profile with only a 2-rig program. Our dual multi-lateral wells are producing about 20% more than single wells and require only about 10% more capital. Similarly, our triple multi-lateral wells are producing about 40% more gas than single wells for only 20% more capital.

At our CBM resource play, second quarter production of 476 million cubic feet equivalent per day was 12% higher than the second quarter of 2010 as a result of successful drilling, acquisitions and third-party production. Liquids production during the quarter averaged over 7,000 barrels per day and was ahead of our expectations primarily due to incremental royalty production from third-party activity.

As I mentioned last quarter, we are pursuing the development of liquids-rich plays across our portfolio. And we are very excited about the acreage position we have built in the Duvernay shale. Thanks to the efforts of our Canadian team, who worked quietly and diligently to acquire a large contiguous land position early and at a low cost, we currently hold about 365,000 net acres or about 570 sections in what we believe to be some of the best acreage on this play. This figure includes acreage purchased at recent land sales and acreage we have not previously disclosed. We completed one vertical test well in the first quarter of the year, and we plan to drill 2 more horizontals in the second half of the year. It is still early days, but we are very excited about the potential of the Duvernay shale to add meaningful liquids to our production profile in Canada.

We are also pursuing 3 projects in the Canadian Deep Basin, which involve deep cut processing to extract liquids from the natural gas in this area. All 3 projects involve fee-for-service arrangements with third-party mid-streamers and are anticipated to be online within 2 years. These projects have the potential to more than triple Encana's Canadian division natural gas liquids production from about 10,000 barrels per day to 30,000 barrels per day over the next few years. The first project is expected to be completed by year end.

Turning to our offshore gas development at Deep Panuke. The production field centre or PFC arrived in Mulgrave, Nova Scotia on June 25 after a nearly 2-month journey from Abu Dhabi. After the completion of the inshore construction program in Mulgrave, the PFC will be towed out for installation at the Deep Panuke location offshore Nova Scotia. We plan to complete final tie-ins after installation and commissioning of the facilities. First gas is expected in the fourth quarter of this year, with production ramping up to about 200 million cubic feet equivalent per day.

Turning now to the proposed Kitimat LNG terminal, of which Encana has a 30% interest. The Kitimat partners are currently undertaking a Front End Engineering and Design, or FEED, study, so capital costs for the project will be defined by the study, which is expected to be completed by year end. Following the completion of the study, as well as the negotiation of long-term offtake agreement, the partners will make a decision on proceeding with investing the capital to construct the first phase of the project. The export license hearing concluded last week, and final approval for the license is expected before the end of the year. At this point, all of the major regulatory approvals for Phase 1 have been received. The Kitimat partners are currently negotiating a long-term offtake agreement that will be backstopped with Western Canadian gas. Overall, another quarter of tremendous results from the Canadian division.

And now I'll turn the call over to Jeff, who will provide an update on the results from the USA division.

Jeff E. Wojahn

Thanks, Mike, and good morning, everyone. The USA division delivered solid results in the second quarter of the year. Production averaged 1.9 billion cubic feet equivalent per day, up 66 million cubic feet equivalent from the first quarter of the year. Production volumes were slightly lower than in the second quarter of 2010 primarily due to net divestitures and the impact of 2009 volumes under voluntary capacity reduction that were brought back online in the first half of 2010. This comparative decrease in production was partially offset by drilling and operational success in the Haynesville Shale this quarter. We expect to see strong year-over-year production growth as we move forward into the second half of the year. Our second quarter operating costs averaged $0.57 per thousand cubic feet equivalent, down 5% from the second quarter of 2010 primarily due to longer term compensation expenses.

Turning now to our results in the Haynesville Shale. Second quarter production averaged 487 million cubic feet equivalent per day, up 89% from the second quarter of 2010. We drilled 23 wells in the second quarter or a total of 45 wells in the first half of the year, and we plan to drill a total of about 85 net wells by year end. Encana is currently operating 11 rigs and participating in 9 operated rigs. We continue to advance our resource play hub development strategy in the play and are implementing various horizontal well pilots to determine optimal spacing, stimulation design and horizontal length. Drilling completion cost performance continues to improve in both our resource play hub development and our lease retention program. In addition, drilling cycle times are down over 20% year-over-year.

Also during the quarter, we obtained regulatory approval for our first Louisiana cross-unit alternate unit wells. This approval allows us to drill 7,500-foot horizontal length wells across the existing block of 3 sections. We plan to spud our first unit well in the third quarter of this year. Additionally, we have several more unitization applications under review, and we expect to receive the results of these applications in 2012.

As I discussed last quarter, we are pursuing several opportunities in the oil- and liquid-rich gas plays. In the Collingwood shale play in Michigan, we are currently drilling 2 wells, and we expect to have initial results by the third quarter. We currently hold about 425,000 net acres in this play. On our Niobrara lands in the DJ Basin or more specifically the Wattenberg Field, we drilled one well, which has been brought on production, and we are currently drilling another. We plan to drill as many as 5 wells in 2011 to evaluate this resource. Additionally, we have captured more than 250,000 net acres in the Tuscaloosa marine shale located in Mississippi and Louisiana. We will drill our first horizontal well starting next month. Although unproven today, we see this opportunity as a large unconventional oil- and liquids-rich natural gas resource play.

Now I've talked before about the steadfast focus of the USA division on maintaining or improving the margins we receive relative to the capital we deploy. Like every other producer in the United States, we are experiencing cost pressures on pumping services and face limited availability of completion crews. In response, our teams have developed innovative ways to manage completion costs and capital availability through strategic, efficiency-based agreements with cost structure transparency.

To counter the high demand and inflationary rates for well completion equipment, we have established long-term, dedicated completion crews, 3 of which have commenced work in Louisiana and Colorado today. In addition, by applying effective logistics management and leveraging Encana's demand, we have reduced our commodities costs by self-sourcing steel, sand and fuel. This integrated approach to our major cost drivers helps eliminate bottlenecks and mitigates risk associated with inflation. This gives Encana longer term contracts at competitive prices to help ensure the security of supply for our major cost strategies. Items such as rigs and steel have been secured at below market pricing and allow for only small incremental pricing changes of 2% to 3% and 4% to 5%, respectively. These agreements align with our overall integrated approach to managing our costs in an inflationary market. While industry inflation in the U.S. this year is expected to average 10% to 12%, we expect Encana's realized inflation in the U.S. to average between 5% to 7%.

Furthermore, our cost structures remain in line with our original guidance and expectations.

Overall, as we progress through the second half of the year, the USA division is on track, on budget and working to mitigate future costs. I will now turn the call over to Sherri Brillon, who will discuss our overall financial performance for the quarter.

Sherri A. Brillon

Thanks, Jeff, and good morning. Encana's second quarter financial results continue to be strong and in line with guidance. Cash flow for the quarter was $1.1 billion or $1.47 per share diluted. Cash flow was down about 11% compared to the second quarter of 2010 primarily due to lower realized financial hedging gains and higher transportation expense, partially offset by higher average commodity prices and higher production volumes.

Year-to-date, cash flow totaled about $2 billion or $2.77 per share diluted. Compared to the second quarter of 2010, operating earnings were 152% higher or $166 million or 22 percent (sic) [$0.22] per share diluted. The increase was primarily due to higher average commodity prices, higher production volume, lower long-term compensation costs and lower deferred tax expense, partially offset by lower realized financial hedging gain and higher transportation expense. Year-to-date, operating earnings totaled $181 million or $0.25 per share diluted.

In the second quarter, we resolved a few minor audit issues related to earlier taxation years, which increased our recovery for the quarter by about $31 million and is reflected in the lower effective tax rate for the quarter. We estimate that our income tax recovery for the year will be slightly higher than the 2010 recovery amount. This is before consideration of the divestiture proceeds expected in the second half of the year.

Our effective tax rate is a function of the relationship between total tax, that is current and deferred, and the amount of net earnings before income tax for the year. The effective tax rate differs from the Canadian statutory rate as it takes into account consideration of permanent differences, adjustments to estimates, changes to tax rates and other tax legislation in each jurisdiction Encana operates.

For the quarter, Encana's hedge position contributed a realized after-tax gain of approximately $131 million or an additional $0.67 per thousand cubic feet to the average natural gas price. As of June 30, 2011, we had about 1.8 billion cubic feet per day or about 50% of our expected July to December natural gas production hedged under fixed-price contracts at an average NYMEX price of $5.75 per thousand cubic feet. Additionally, Encana has hedged approximately 2 billion cubic feet per day of expected 2012 natural gas production at an average NYMEX price of about $5.80 per thousand cubic feet, and approximately 405 million cubic feet per day of expected 2013 natural gas production at an average NYMEX price of $5.29 per thousand cubic feet. So we are well positioned for the rest of the year entering 2012.

Having these hedges in place increases the certainty of our cash flow generation, helping to ensure stability for our capital program and dividend payments. Since the beginning of 2006, Encana's commodity price hedging has resulted in about $7.7 billion of pretax cash flow in excess of what would have been generated had we not employed price hedging.

Now turning to our costs for the quarter. Combined operating and administrative costs of $1.01 per thousand cubic equivalent were $0.10 lower year-over-year mainly due to lower long-term incentive costs. We have maintained our 2011 guidance expectation for a combined operating administrative cost of $1.15 to $1.20 per thousand cubic feet equivalent.

Depreciation, depletion and amortization or DD&A was $2.65 per thousand cubic feet equivalent in the second quarter. As I have mentioned on previous conference calls, Encana's depletion rate is higher than some of our U.S. 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 forecasts used to determine proved reserve quantities required under U.S. GAAP when compared to Canadian GAAP. Subsequently, the impairment booked by U.S. peers allows them to apply a lower depletion rate. Encana's second quarter 2011 DD&A rate, if it were reported on a U.S. GAAP basis, would have been approximately $1.75 per thousand cubic feet equivalent versus about $2.65 per thousand cubic feet equivalent under IFRS. Using the U.S. GAAP DD&A rate, we estimate that our second quarter operating earnings would have been approximately $321 million after-tax or about $0.44 per share. We continue to assess the potential benefits of converting to U.S. GAAP as we believe it may facilitate easier comparisons of our financial results to those of our U.S. peers. But we have not yet made that decision. Tomorrow, we do plan to post to our website additional supplemental information, which reconciles key components of Encana's second quarter financial results with U.S. GAAP.

Overall, the flexibility of Encana's balance sheet remains intact. Our debt-to-capitalization ratio at the end of the quarter was 33%, and our debt-to-adjusted EBITDA ratio was 2x on a trailing 12-month basis. Debt-to-debt-adjusted cash flow was 1.9x on a trailing 12-month basis, and this ratio excludes the volatility of the unrealized gains and losses on risk management activity.

As I mentioned on our first quarter conference call, we have always tried to preserve the strength of our balance sheet, maintain capital discipline and stay within our debt metric target ranges. We manage our business with a focus on generating value for our shareholders over the long term.

During this period of cyclically low natural gas prices, our leverage over the short term has increased modestly, which has allowed us to continue to take advantage of promising opportunities for future growth, some of which you heard more about today. In addition to expected divestiture proceeds of $1 billion to $2 billion by the end of the year, our liquidity is maintained by the availability of a $4.4 billion of unused, committed revolving bank credit facility, which further enhance our financial flexibility.

Overall, Encana's financial results for the second quarter and first half of 2011 were solid. As we head into the second half of 2011, Encana's balance sheet remains both healthy and flexible. I will now turn the call back to Randy.

Randall K. Eresman

All right. Thank you, Sherri. So as you've heard this morning, Encana has had a solid second quarter, both operationally and financially, and we are on track to meet our 2011 guidance. Although low natural gas prices persist, we're beginning to see some encouraging signs that a price recovery is coming. Some of these positive signals include the end of significant land retention drilling in many gas-weighted basins in the United States, the continuing increasing shift from drilling for dry gas to drilling for oil- and liquids-rich gas, increasing momentum behind export potential for North American liquefied natural gas and stronger government support on both sides of the border that are starting to recognize natural gas as an energy supply of choice and an opportunity to provide jobs to help fuel the economic recovery.

We're beginning to see beyond this trough of weak natural gas prices, but our focus remains on being amongst the lowest cost producers in the natural gas industry. Our pursuit of capital discipline is enhancing returns as we continue to see strong operational performance from our key resource plays.

At Encana, we've taken a long-term integrated approach to supply management, which has positioned us well to offset growing industry inflationary pressures. We have multiyear agreements in place for a majority of our key spend items such as drilling rigs, pumping services and steel. Ongoing efforts toward increased cost transparency and understanding of the complete supply chain with respect to materials and services have us well positioned to offset a significant degree of industry inflation.

While we're forecasting industry inflation for 2011 at about 10%, expect to see Encana's inflation to be approximately half that level. Our continued focus on capital and operating efficiencies through our resource play hub development model will help us to more than offset these forecasted increases.

Encana remains positioned to excel in our goal to be the lowest cost, highest gross senior natural gas producer in North America. As we've highlighted in the past, through our early-mover, low-cost entry approach, we've assembled a tremendous portfolio of resource plays. We continue to high-grade our portfolio through the divestiture of noncore assets and addition of new land positions with emerging liquids-rich opportunities. Again, we're doing so in a way that we believe creates the most value for our shareholders by pursuing a full-cycle holistic approach starting with a quiet "low cost of entry" position based on leveraging the expertise of our new ventures teams. We shared a few of these new plays with you, like Collingwood, Niobrara, Duvernay and the Tuscaloosa, and we will have more of these to talk about later.

Our portfolio both warrants and is capable of supporting significantly higher growth. However, during this period of continued low natural gas prices, we believe it is prudent in the near term to live within the boundaries of our cash flow generation supported by divestitures to maintain our financial flexibility. We remain clearly focused on unlocking the tremendous value inherent in our asset base and increasing the net asset value of every Encana share.

Thank you for joining us today. Our team is now ready to take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Mark Polak with Scotia Capital.

Mark Polak - Scotia Capital Inc., Research Division

I just had a few quick questions, if I could. First was for Mike. I was wondering if you could expand on the vertical test you did in the Duvernay in terms of rates and anything else you might have learned from that well.

Michael M. Graham

Yes, Mark. Mike Graham here. We really haven't said too much other than we're encouraged by the test in the Duvernay, or so I think you've seen some of the competitors' tests that was similar to that, good liquids content, and we'll be able to talk more about horizontal results hopefully by the end of the year.

Mark Polak - Scotia Capital Inc., Research Division

Fair enough. And then just maybe in the U.S. then for Jeff. I know you haven't drilled anything yet but just curious to hear your sense of the geology in the Tuscaloosa. My sense, my understanding initially is that because it's silica rich, it's fairly brittle and hopefully should mean high-productivity wells. But just curious if that's consistent with what you guys are thinking there.

Jeff E. Wojahn

Geologically, obviously, our new ventures teams do spend a great deal of time screening the different types of opportunities across North America, and they've identified the Tuscaloosa as a promising liquids-rich opportunity. And some of those attributes are related to how the rock breaks, the hydrocarbon content and gas in place and the like. And we're really going to find out more from our upcoming drilling programs where we're going to be able to quantify some of those attributes and see how the play fits within our portfolio. But we're excited about what we've seen to date. And obviously, we'd like to verify that with some data in the upcoming months.

Mark Polak - Scotia Capital Inc., Research Division

And then last one for me just in terms of divestitures and joint ventures. I believe proposals are due next week for Greater Sierra and Horn River but just curious if you could give a sense of timing on the midstream divestitures and sort of the revised plan for the Cutbank JVs and when that process kicks off.

Randall K. Eresman

Yes, Bob Grant will provide some insight on that.

Bob Grant

With respect to Horn River and Greater Sierra, it is our view [indiscernible]. What was the second question?

Unknown Executive

[Indiscernible].

Bob Grant

In terms of the midstream assets at Cabin Gas Plant, project as well as in [indiscernible] as well [indiscernible] as well, the midstream assets with respect to the Montney, that will be later in the year, probably late Q3.

Unknown Executive

And the JVs?

Bob Grant

And the JVs are well underway as well. The Montney, we should be out with teasers early next week.

Mark Polak - Scotia Capital Inc., Research Division

That's great.

Operator

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

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

Most of my questions have been asked, but 2 quick ones then. Randy, you mentioned living more or less within cash flow plus planned dispositions. This is a bigger year, obviously, with $1 billion, $2 billion in dispositions. What kind of a number should we be thinking about as you get into 2012 and beyond? And then just one -- like many questions, just assuming you guys have no production shut-in at this stage.

Randall K. Eresman

No, you're right. I don't think we have any production shut-in. That wouldn't be beyond normal operations. Now I have said before that we thought our undeveloped resource potential for the company would support ongoing joint venture investments in the order of $1 billion to $2 billion per year. And we're still of the mind that, that is the kind of level that we could continue to bring in. When we set our development plan in 2010 and our target was to try to double production per share over a 5-year period, at that time our estimate was that we would require about $6 billion per year of capital and that in order to do that, I think at the time we were -- our forecasted long-term price was around $6 or $6.50. Our forecasted long-term price now is a little bit lower than that, but also our cost structures have come down a little bit. So I'm kind of anticipating that if we were to be on that sort of track, we'd probably require about $5.5 billion a year. But where we're at today, our cash flow generation is a little bit lower than that. So we'll probably need about $1 billion a year of ongoing support in order to maintain a healthy growth rate until prices recover to the levels that we anticipate that they will. And I guess we're, as I said earlier, we're reasonably positive. We're seeing reasonably positive signs of, say, a recovery of price towards the curve by 2012 to '13, that sort of timeframe.

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

Okay. So $1 billion to $2 billion of announced JVs perhaps in a given year, but cash coming in at least $1 billion. Is that about right?

Randall K. Eresman

That will depend on the structures of the transaction. What the JVs will do, of course, is reduce our capital requirements off of that sort of $5 billion, $5.5 billion number I talked about annually. It'll just reduce the amount of cash we need in order to get to the same place, kind of growth rate.

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

Okay, very good.

Operator

Your next question comes from the line of Brian Dutton with Crédit Suisse.

Brian C. Dutton - Crédit Suisse AG, Research Division

Jeff, there is lots to read about supply chain management in textbooks. But could you give us some specific examples of how Encana is self-sourcing materials and implementing efficiency-based contracts?

Jeff E. Wojahn

Well, I’ll stay away from the textbook answers, as you said. One of the things that we've done when we've looked at talking to contractors and vendors is to -- and I talked in my notes about cost transparency, is to really understand the cost structures of the business. And rather go through a RFP process or request for process-type arrangement, bid process, we looked more at the supply chain from what was an acceptable return for providing services to Encana. And so we've really taken our supply chain management philosophy from the shorter term bid-type process to a longer term acceptable return on services. And I think that's somewhat unique for the industry.

Michael M. Graham

Brian, Mike Graham here. I could maybe add a little bit. In Canada, we're doing the same thing similar to what Jeff is. We are sourcing sand. We've gone out and bought steel, and we've done a lot of long-term agreements with the rig companies. We're not afraid to go out and do 5-year deals with quite a few of the rig companies: with Ensign, Precision, Trinidad. Essentially, we have built-for-purpose rigs. We helped them design the rig, and we consider them part of our fleet. And we may be running sort of 15 of those big rigs at any one time. Also, in the frac-ing equipment, we'll go for -- contract for 2 years plus another as well. And like gas, we're sourcing our sand. We're looking after a lot of the logistics of that, chemicals and whatnot. So our supply chain guys are very close to the U.S. We'll go out and we’ll buy steel together. We'll look at contracting rigs or other services together, and I think it works out very well for us.

Randall K. Eresman

And, Brian, it's Randy Eresman back here again. The supply chain management is just one of the many steps that we've taken to lower our overall cost structures. And really, it's a result of Encana's move to a more manufacturing approach to development. And we try to take all of those elements that are opportunities for us to enhance the cost effectiveness of our operations. And now we've coined a phrase or the terminology resource play hub to encapsulate all of the things that we do that will continually help us drive down our costs. And you're starting to see it in the results that we've had in the last couple of years with our supply costs coming down from -- I think it was at about 550 in 2008 now down to in the order of 370 today. So that's part of it. And some of our input costs are actually at the same level as they were back at that time. So it really means we've got efficiency both in the way we manage our cost, but also efficiency in the way we have been able to extract more resource for the dollar.

Brian C. Dutton - Crédit Suisse AG, Research Division

And along those lines, Randy, I get a lot of questions on why doesn't Encana just cut their CapEx program now in a low gas price environment then bring it back up again when prices improve? So how does load leveling your program come into play here in your cost structure?

Randall K. Eresman

It goes a long way to have a continuous level of operation in the company in order to be able to create the efficiencies that we talk about. And one of the reasons we were so happy a few years ago when we were able to have continuous operations in Northern Alberta and Northern British Columbia, an area where we traditionally would move in, in the winter and move out once breakup started to occur, the simple, I guess, the opportunity that was presented to us by having -- to be able to have maps to drill on and maps to operate off in that area allowed us to have the operations on an annual basis. So a continuous operation. Mike can speak more to the effect of it, but it's been great for his team and great for the cost structure of the company.

Michael M. Graham

Yes, Brian. And if you look at the Horn River, we've taken our days down from probably 40, 50 days where we can drill them right down to 20 days, even sub-20 days now in some of the Horn River wells. As Randy said we're drilling continuously. We'll drill as much as maybe 16 wells per pad in the Horn River. So you get very, very efficient at it. And it's just, like we point out, really a manufacturing type of approach to doing it. And it's the same thing. It doesn't matter if it's a deep basin or the Montney up there in the Peace River Arch or CBM or whatever. We have the rigs going continuously. And you get very, very good at it by doing that much repetition 365 days a year.

Operator

Our next question comes from the line of Bob Brackett with Sanford Bernstein.

Robert Brackett

Two questions, one relating to the Haynesville. Can you talk about the inventory of drilled but uncompleted wells there? And is that rising or falling quarter-on-quarter, year-on-year?

Jeff E. Wojahn

Yes, Bob, it's Jeff. Are you referring to the industry or Encana specifically?

Robert Brackett

You guys specifically.

Jeff E. Wojahn

Okay. We currently are -- we drill about half of our expected program. We're about 45 wells out of 85 net well program. I think we're bringing on a new pad in the Credence area next -- or, I'm sorry, in the Bolan area next week. So we have about 8 wells that are coming on in a couple of weeks from now. But beyond that, I think our inventory levels are normal. So we're not waiting on -- we don't have a big list of wells, like you've heard by some of the other producers, on completion crews. In fact, we're caught up.

Robert Brackett

The other question I had was for more broadly, you talked about service cost inflation at 10%, and you all being sort of half that. If I see service cost inflation go to 15%, how should I think about your specific cost inflation?

Jeff E. Wojahn

Really because of the nature of our long-term contracts, as we mentioned on our major cost structures, they're really locked in. So I don't anticipate any significant increase in our cost structures for the next -- upcoming 2011 or 2012 period.

Operator

Your next question comes from the line of George Toriola with UBS Securities.

George Toriola - UBS Investment Bank, Research Division

This question is for -- I have a couple of questions. The first is a 2-part question for Randy. When you talk about gas prices being unsustainably low, could you just provide an insight into how -- what do you mean by that from your perspective, not the industry perspective right now?

Randall K. Eresman

Okay. I guess from our perspective, we're pretty knowledgeable about what the cost structures are amongst our industry players in North America. And obviously, we absolutely know our internal cost structures. And when we're starting to see and feel the pressures associated with the current gas price environment, and we acknowledge and know that our cost structures can be $1 to $2 lower, I guess, than many of the industry players and some of the -- that gas is absolutely necessary to meet the demand, then we recognize that others will be having a much tougher time. And therefore, the price has got to ultimately respond. All sorts of things can happen in the short run. But our own fundamental work would suggest that sometime in the next year or 2, we should see some form of recovery.

George Toriola - UBS Investment Bank, Research Division

So from your -- I get that. But from your perspective just based on your supply cost, and the efficiencies that you guys have been able to drive out of the business, would you suggest that gas prices, at least what we know now and what we can see, would that be sufficient for you to generate your own required returns?

Randall K. Eresman

Our own supply costs on average for the program that we're conducting this year is about 370. And so the supply cost and that -- and what we call our supply cost is the long-term NYMEX price that we require to get a cost-to-capital return, and we use a proxy of 9% after-tax for that. So even in this environment on a go-forward basis, we're probably making -- at this -- at the current price assuming that was flat, where would we be at, guys, around 15%? Higher? 20% return? Something like that.

George Toriola - UBS Investment Bank, Research Division

Okay, that's very helpful. I guess the other part of the question I have, the second question I have is how would you then look at return on capital given all of that? I don't know if you have a certain -- you have targets for return on capital employed. Well, how would you look at that? And how does that -- to the extent that you target certain metrics, how does your JV with third-party capital plan go into all of that?

Randall K. Eresman

I'm not quite sure I fully understand the question. But we don't have targets on return on capital employed specifically. We do have -- for our capital programs, we use a variety of financial metrics, which are designed to have return cutoffs, which are substantially higher than our cost of capital. And for example, and one of the metrics that we would have had in the play coming into this year's capital program, we cut off our last program at a rate of return above 20% per sé, targeting a long-term and full cycle return above 15%, which we believe is pretty solid in the longer term. For the JVs that we do, we're looking to always enhance the present value of our assets. And so in all cases, we'll be wanting to improve or to be doing deals that are better than our cost of capital. And in many cases, what we're doing is bringing forward the value of assets that we wouldn't ourselves be able to develop in the long term in a reasonable timeframe. And so by doing the third-party deal, we're really accelerating the development of assets from it. In the case of Cutbank Ridge where we have something like a 40-year inventory, what, 50-year inventory, that's way too long. And so we could see the opportunity to bring that value forward. And many of our other plays are similar to that where we have a resource which is just more than we will ever be able to manage on our own.

Operator

Your next question comes from the line of John Herrlin with Société Générale.

John P. Herrlin - Societe Generale Cross Asset Research

A bunch of quick ones. You had $124 million in exploration expenses in the quarter. You haven't -- you didn't have much in the first quarter. Could you give us a sense of what kind of run rate you're anticipating for the second half?

Randall K. Eresman

Yes, just please, Jeff?

Jeff E. Wojahn

Yes, John, it's Jeff Wojahn. I know in the U.S. we don't anticipate any further exploration expenses for the second half.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. You mentioned U.S. GAAP still an $11 billion impairment in the event that you went there.

Randall K. Eresman

Yes, and that's an historical impairment. It's already been taken.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, right. For your cash flow statement, you had $44 million in other. Could you tell me what the other was?

Randall K. Eresman

I've got my Chief Accounting Officer here.

William A. Stevenson

Yes, it's made up of a lot of smaller items. I don't have the detail right in front of me. We can get back to you on the answer on that.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, that's fine. Tuscaloosa, well cost. Any idea what a complete well cost would be, ballpark?

Eric D. Marsh

John, this is Eric Marsh. We obviously haven't drilled the well yet, but we do anticipate that the first well we drill will be in the $8 million range. It's about a 12,000-foot well, and we hope to get a 7,500-foot lateral out of it. And so we're thinking in the first well there'd be a lot of science involved, some coring and things. But overall, it will be in that range to start with.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Last one for me is with the JV, is this all going to be capital cost reductions? Or should we expect some lower op cost as well?

Randall K. Eresman

It'll likely be partly an infusion of cash for part of the JVs, and the rest will be likely in the form of a carry on the capital side. It shouldn't have much impact at all on the operating side.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, that's what I thought. I just wanted to confirm.

Operator

Your next question comes from the line of Mark Gilman with Benchmark Company.

Mark Gilman - The Benchmark Company, LLC, Research Division

I guess I had a couple of things. First, could Mike and Jeff broaden the question concerning the uncompleted well inventory to plays other than the Haynesville? Give me a rough idea what it is? If there's anything significant in any of the other plays?

Jeff E. Wojahn

Sure, Mark. I can start. We by and large are in pretty good shape across the division. One outstanding area is the Piceance Basin where we have a, let's say, a 3- or 4-month inventory of standing vertical wells in the Williams Fork. But I wouldn't characterize it as being material to the division's guidance.

Michael M. Graham

Mark, Mike Graham here. We would have about in the order of maybe 50, 60 wells in the Deep Basin yet to be completed and tied in. And we're pretty much caught up in our CBM program, so we pretty much run Q4 and Q1, if you will. So we don't have too terribly much more to do in CBM. We're going to drill about 500 wells this year in our coal bed methane. And in the Horn River, actually we only have the one rig running right now in the Kiwigana lands with our JV with KOGAS. And we are bringing on or we just brought on our 34-L pad with Apache, which is what, the 9-well pad. And so we have about maybe our d-1-D pad, which is about another I think it's 8 wells on that pad to come on for the last half of the year. So that would be about it for inventory.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay. Jeff, it's been suggested by some that the Tuscaloosa marine shale is stratigraphically equivalent to the Eagle Ford. Do you share those views? Or do you see it a little bit differently?

Jeff E. Wojahn

I've been told by our geologist not to say that the way you had described it because I'm not an expert in the regional geology. But from what I understand, the Eagle Ford is separated by kind of the Sabine platform uplift. And really, although it looks laterally equivalent, it is a different type of play than the Eagle Ford. So hopefully, I didn't offend any geologists by the way I described it.

Mark Gilman - The Benchmark Company, LLC, Research Division

Could you elaborate what you mean by that, Jeff, in terms of different type of play?

Jeff E. Wojahn

Well, it's a reservoir that has some silt and sand content in it versus the Eagle Ford, which is a clean shale.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay. Could you give us just a little bit of an idea what the acreage costs were for your entry into the Tuscaloosa and the additional Duvernay acreage, which you acquired?

Jeff E. Wojahn

Sure. I'll start with the Tuscaloosa. This is a play that we entered very early for very low costs. We have a number of options and commitments, so I can't get specific on the range. But it ranges $42,000 to $50,000 area, somewhere between $40 million and $50 million.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay.

Michael M. Graham

Mark, Mike here again for Canada. Typically in Canada, we've been very early in a lot of these plays, and the Duvernay is no exception. We got into the Horn River and the Montney at probably less than $1,000 an acre. We might be a little bit higher than that on the Duvernay, but we've got a tremendous land position. I think it's somewhere around $1,500 per acre. And so we didn't really pay some of the big prices that we've seen at the last sale. But like I say, we've got 365,000 net acres now in the Duvernay or a little over 500 sections. And so we've got a very big land position, we think, in some of the best parts of the play and for a pretty reasonable cost.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay. So a final one for me for Sherri. Sherri, can you just refresh my memory as to what the tax recoveries were in 2010 and the relationship again that you expected in '11 to that number?

Sherri A. Brillon

Yes, the tax recoveries in 2010 were $213 million. And so we expect that those will be higher than that number into 2011. However, that does not include the impact of the dispositions that we're expecting to see into the second half. And the reason I can't really give you a great number on that is that we haven't really assessed the structures around this disposition.

Mark Gilman - The Benchmark Company, LLC, Research Division

And Sherri, this relates to prior period kinds of events and should not be part of an effective tax rate, say, going into 2012?

Sherri A. Brillon

That's right. We basically had settled with CRA some of our outstanding matters related to tax audits back to I think it was 2000 to 2003.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay. So we should expect a more normal effective tax rate in '12?

Sherri A. Brillon

Well, yes. I mean, we do have loss -- we're in a loss position right now. So we're basically being able to carry back 3 years to 2009.

Mark Gilman - The Benchmark Company, LLC, Research Division

And the size of that loss?

Ryder McRitchie

Mark, it's Ryder here. We paid a big tax bill in 2009, roughly of the $1.7 billion type of range. So we're able to carry back for 3 years go forward from that period and reclaim some of those taxes paid in that year.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay, got it.

Operator

The next question comes from the line of Robert Bellinski with Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

I was hoping that you could provide some perspective on what kind of response you've seen or you might expect to see from service firms pertaining to their willingness to provide services that contain a substantial degree of intellectual property in plays where you've partnered with a Chinese firm.

Randall K. Eresman

Okay, we're trying to figure this one out. Go ahead, Mike.

Michael M. Graham

Yes, Robert. Mike Graham here. We really haven't partnered with any Chinese firms, be it service firms or E&P companies, to date. So we really couldn't comment on that.

Robert Bellinski - Morningstar Inc., Research Division

And just to be specific, I'm not talking about Chinese service firms but U.S. service firms and the partner in -- or like a joint venture in acreage with a Chinese firm.

Randall K. Eresman

We haven't done any, so we have no experience in that.

Operator

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

Menno Hulshof - TD Newcrest Capital Inc., Research Division

I'm going to start out with a more strategic question for Randy. Given the obvious near-term challenges for North American gas and your expertise in shale gas development, like what are your current thoughts on seeking out international shale opportunities? And how active would you be in that regard, if at all?

Randall K. Eresman

We have been looking at opportunities internationally. We haven't signed any agreements yet, but we are pursuing the possibility. There are certain places on the planet that look like they would be great places to both do business and where shale gas opportunities exist where we could put our expertise to play and potentially benefit from that. But I can't announce anything because I don't have anything yet.

Menno Hulshof - TD Newcrest Capital Inc., Research Division

But it's not outside of the realm of possibility that we see something within the next call it a year or so?

Randall K. Eresman

Well, we have been looking at it for several years now. And so it's a pretty long screening process. Others have moved into areas where we think that there are opportunities for us to move in as well.

Menno Hulshof - TD Newcrest Capital Inc., Research Division

Okay, perfect. And then I've just got a quick follow-up question on Kitimat. Can you give us any sense of the timing of the signing of LNG offtake agreements and how many counterparties you would ultimately be targeting?

Randall K. Eresman

I'm going to let Renee Zemljak provide a little update on Kitimat.

Renee E. Zemljak

This is Renee. The Kitimat project is going quite well. As expected, we have had several negotiations with many potential offtake markets, so we're quite optimistic about the level of discussions that we're currently engaged in. It's very difficult to tag a certain number to how many offtake markets we think that we will secure. I can tell you that it's most likely going to be more than 2 and less than half a dozen, I don't know. So the number's uncertain at this point in time. But the project's moving along quite well.

Operator

At this time, we will open the questions up to the media. [Operator Instructions] Your first question comes from Amanda Fraser with AllNovaScotia.com.

Amanda Fraser - AllNovaScotia.com

I just had a few questions about the Deep Panuke project. I was wondering when that platform is going to reach well grade.

Michael M. Graham

Yes, Amanda. Mike Graham here. Essentially all the work is complete now on the platform that we needed to do within -- in the Mulgrave harbor there. And so we expect a platform to leave any day now, so over the next few days, hopefully. We're just making sure that the weather is okay. And then once that leaves the harbor, it's about 40 hours out to site. So we're looking for a weather window of that sort of duration, if you will, and then we have to jack it up and place it where it's going to stay for the next 15 years.

Amanda Fraser - AllNovaScotia.com

Okay. And I think in the last call, you had mentioned that it might come online at 250 Mcf per day and -- or there you had said 200. Is there any particular reason for the change or...

Michael M. Graham

Well, no, Amanda. The facility’s, actually, going to be designed for about 300 million cubic feet a day. We do have firm service, like we said, on Maritime & Northeast of 200 million cubic feet per day, but it does look like there may be more capacity available there. So we plan to bring it on at about 200 and -- but it will have the capability to flow up to about 300. So we're kind of looking at what the optimum flow rate to produce that is.

Amanda Fraser - AllNovaScotia.com

Okay. And can you talk a little bit about the overall economics in the project as well?

Michael M. Graham

Well, obviously, the capital has been spent in it and we talked about the $960 million but obviously with a reasonable rate of return at project sanction, that's for sure, and the prices have come down a little bit. But right now, we're really excited about the project. We expect first gas coming on hopefully in Q4. We're even thinking maybe as quick as October or so. So we'll talk to you at the end of that time.

Amanda Fraser - AllNovaScotia.com

Okay. And then just one other question. You talked a bit about divestitures. Do you ever foresee a sale of the project?

Michael M. Graham

Right now, we have nothing active on the sale of Deep Panuke. Or like we're going to bring it on, and we're going to -- in 6 months, you'll have a pretty good idea how big the reservoir is. We've got 500 to 1.5 Tcf of possibility for production out of it. So we'll kind of have a good idea after 6 months, and we'll have a good idea then.

Amanda Fraser - AllNovaScotia.com

Okay, great.

Operator

Your next question comes from the line of Carrie Tait with Globe and Mail.

Carrie Tait - National Post

I'm wondering, you've mentioned $1 billion of asset sales that you're hoping to work through each year to supplement cash flow. I'm wondering -- in part to support financial flexibility. I'm wondering if you would do that if prices weren't so low.

Randall K. Eresman

Carrie, actually that was the plan that we had established more than a year ago. And it really doesn't relate to the price environment. It more relates to the idea that we have so much undeveloped resource that we really couldn't get value out of -- at the pace that we could develop it by ourselves. And so by extracting some of that value, we do a couple things in our portfolio. First of all, it will allow us greater financial flexibility. With the money that we take out, we can either use it to support our capital program in days like today when the price is low, we can use it to help accelerate our pace of development as well, or we can help it to lower our overall cost structures. So there are many benefits for us for doing it. But they're not really related to -- they're not -- we would be doing these even in a higher price environment is what I'm trying to say.

Carrie Tait - National Post

Sorry. I guess I meant more just the infrastructure like the pipes and processing facilities rather than the joint ventures tied to land sales.

Randall K. Eresman

Oh, we wanted to do that for a very long time. And we were doing a lot of these kind of transactions in our U.S. operations where exposures to the MLPs allowed foreign investors with lower cost of capital to build those facilities rather than us with a somewhat higher cost of capital and offsetting what we would otherwise be able to do with the money, which is invest in well bores with higher returns. It's really only been more recently that we've seen the opportunity in Canada to do the same kind of deals with very, very competitive returns. And so we've been holding back for years where we may have wanted to do it. We just didn't see the financial opportunity to do it.

Carrie Tait - National Post

Okay. You mentioned LNG fueling in Louisiana and I think in Colorado. Is this a business that you want to grow, get into?

Randall K. Eresman

We're not sure if we want to do this for ourselves, but we know we need to show leadership. And we want to make sure that LNG is used in transportation in North America, and we're basically walking the talk.

Carrie Tait - National Post

How do you decide if it's something that you want to do?

Randall K. Eresman

We will have to look at the competitiveness of the financial model. And it's going to take us a little while before we fully understand that. We know that there are going to be opportunities in and around our areas of operation that will probably make sense for us to be in some portion of that value chain. We're just going to have to figure out over time what that's going to be. In the meantime, we're investing on a variety of these kind of things in the order of $50 million to $100 million a year.

Carrie Tait - National Post

Are they making money?

Randall K. Eresman

I'm going to turn that over to Eric Marsh.

Eric D. Marsh

Yes. I think the answer is that the natural gas stations that we have, we actually have 5 operating, and 4 of them actually can -- will make money on a monthly basis. But what really dictates the money that you make is the throughput. So as -- if you're breaking even today and the number of vehicles that you have in that area grow, they begin to become profitable. But yes, that's our plan, is to be profitable on every CNG station that we make.

Randall K. Eresman

Carrie, the benefit for the users, those that convert their vehicles to natural gas, in the same way where we converted our drilling rigs to natural gas or starting to look at our frac-ing equipment in natural gas, financial benefits to us are huge. It really is just getting more places where people can fill up their vehicles and more opportunities for fleets to convert that is required, and I guess more people aware of what the huge price advantages or cost advantages to moving towards using more natural gas in the transportation sector.

Carrie Tait - National Post

How long have you had fleets and stations? Or not fleets of your own, I guess. I mean, the natural gas stations. You mentioned the 5 stations.

Randall K. Eresman

No, these are all things we've done within the last 2 years or even less. So we're really just starting to build it out.

Carrie Tait - National Post

Now you also mentioned the inflation prediction. It had gone up since, I think, the last 1 or 2 conference calls. What are you seeing that has caused you to raise your inflation prediction?

Randall K. Eresman

I guess it's really just our observations of what is happening overall in industry.

Carrie Tait - National Post

Or what are some of the specifics that have changed since last time?

Michael M. Graham

Yes, Carrie. Mike Graham here. Like, our inflation is pretty close to what it was, we said 3% to 5% in Canada and we're saying maybe 4% to 6% now. So maybe up 1%. Obviously, that's big oil prices in the world, I guess, is affecting the oil sands. So the labor market in Western Canada is definitely tight again, similar to where it was in 2007, early 2008 when we had the big run-up in oil price again so. But other than that, like Jeff mentioned and I mentioned, we have a lot of our services locked in. We've got rigs contracted. We've got completion, frac-ing services contracted for long term. So we don't see sort of the big inflation that maybe the rest of the industry is going to see. So it's still running at a pretty low rate.

Carrie Tait - National Post

And my last question. And when you're looking internationally for shale opportunities, are you looking to do that with a partner?

Randall K. Eresman

Very likely it would be with a partner, yes.

Operator

Your next question comes from the line of Dan Healing with Calgary Herald.

Dan Healing

I just had a question on the LNG front. There seems to be a great deal of interest in -- from other parties looking at building LNG. So I'm wondering if the partners are talking at all about going earlier to the doubling of that proposed plant or expanding it in any way.

Renee E. Zemljak

This is Renee. The intent on the plant as we sit today is -- our goal is really to do both train 1 and train 2. So as we move forward in our marketing efforts, we are at this point in time trying to secure enough offtake markets to allow us to make a positive FIB on both Phases 1 and 2.

Dan Healing

Okay. But the project that you've proposed to regulators is only for #1 or am I -- have I got that wrong?

Renee E. Zemljak

The project, as proposed through the MEB [ph] process for the export license, did actually includes for Phases 1 and 2. I think what you heard earlier today is that we have all major regulatory approvals for train 1, which is Phase 1 of the project. So we are aggressively trying to move forward to do both phases of the project at this time.

Dan Healing

Okay. Did that change recently?

Renee E. Zemljak

No, that's been the scope of the project. The economics of the project significantly increase if we actually do both phases. So it's -- we've been looking at that from the beginning.

Dan Healing

Okay. My other question was on Cutbank Ridge. Given the breaking down of the joint venture, is the company looking for a similar-sized joint venture? Are you looking at breaking that up into smaller joint ventures?

Randall K. Eresman

The way we're rolling it out is we are separating the midstream assets at Cutbank Ridge from the producing assets and from the undeveloped resources. And we're really only looking to do a joint venture on the undeveloped resources. Our intention is to retain the production. And also, our intention is to do a deal with a midstreamer which would be effectively a sale of the midstream assets. And so by holding back the production, we're really talking about -- and it's really difficult for me to put a number in front of you exact, but it's sort of $1.5 billion to $2 billion is what the value of that production might have been. Therefore, you would anticipate that the total of the deal might be lowered by that amount, but our net effect to the company is it would be about the same.

Operator

Your next question comes from the line of Scott Haggett with Reuters.

Scott Haggett - Reuters

Randy, just if I could get you to reiterate the time -- you mentioned the timing of potential agreements being signed for joint ventures. My phone kind of dropped off, so I’m hoping that I can get you to reiterate that.

Randall K. Eresman

Okay. Well, for the joint ventures, there's a number of them ongoing. But the Cutbank Ridge, which is the larger of the ones that we're doing, we would be anticipating that, that would be sometime around year end. We do have some other ones ongoing with the Greater Sierra area, our Jean Marie prospect. And that could be earlier. With respect to some of the midstream, which is your sales of assets, those could be as early as the October time period.

Scott Haggett - Reuters

I just wanted to turn back to -- you mentioned looking at international projects. Given, I guess, both the scope of your inventory in North America and your withdrawal from the international arena several years ago, what sort of size do you see this eventually being in the international forum?

Randall K. Eresman

It is really way too early to say what size. And before we go out there, it has to be meaningful to Encana. So we wouldn't go and just do little bits and pieces of deals. We have a real expertise developed in our company. And before we're going to transfer that expertise to other parts of the world, it's going to have to be meaningful to us. So you can read whatever you want into that potential size. Going out into -- we pulled back from the international, but we pulled back from the international because we didn't really have a lot to offer on the international front outside of maybe waving the Canadian flag. As we go out and look at plays in the world where we may be able to transfer our expertise, it is truly expertise that we are carrying into the [indiscernible]. So that's the reason now that we go there.

Operator

Your last question comes from the line of Lauren Krugel with Canadian Press.

Lauren Krugel

I just had a quick question on the international matter. I just wanted to know what areas of the world you would be potentially interested in. Are we talking Europe or anywhere else?

Randall K. Eresman

We wouldn't rule out any place in the world unless that didn't meet our screening criteria. But our screening criteria is pretty stringent, and so it really only allows us to go into places in the world that would have well-developed markets and rule of law.

Lauren Krugel

And could you kind of give me a little bit of perspective on how high up this is on your priority list vis-à-vis what you're up to in North America, how much work and time and effort you might be putting into it at this stage?

Randall K. Eresman

We don't see it as required. We see it as an opportunity.

Lauren Krugel

Okay, great.

Operator

At this time, we have concluded the question-and-answer session and we’ll turn the call back to Mr. McRitchie.

Ryder McRitchie

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

Operator

This concludes today's conference call. You may now disconnect.

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Source: Encana, Management Discusses Q2 2011 Results - Earnings Call, Jul 21, 2011 Transcript
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