Ovintiv Inc. (OVV) Q1 2011 Earnings Report, Transcript and Summary

Randall Eresman - Chief Executive Officer, President and Director Michael Graham - Executive Vice President and President of Canadian Division Bob Grant - Jeff Wojahn - Executive Vice President and President of USA Region Ryder McRitchie - Vice President of Investor Relations Michael McAllister - Executive Vice-President and Senior Vice-President of Canadian Division Unknown Executive - Sherri Brillon - Chief Financial Officer and Executive Vice President

Brian Singer - Goldman Sachs Group Inc. Bill Holland George Toriola - UBS Investment Bank David Tameron - Wells Fargo Securities, LLC Mark Gilman - The Benchmark Company, LLC Greg Pardy - RBC Capital Markets, LLC Shaun Polczer - The Calgary Herald John Herrlin - Societe Generale Cross Asset Research Kam Sandhar - Peters & Co. Limited Amanda Fraser - AllNovaScotia.com Carrie Tait - National Post Menno Hulshof - TD Newcrest Capital Inc. Barbara Betanski - UBS Global Harry Mateer - Barclays Capital Andrew Potter Edward Welch

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's First 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 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.

Thank you, operator, and welcome everyone to our discussion of Encana's 2011 first 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. Previously, the company prepared its financial statements in accordance with Canadian generally accepted accounting principles or 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, the most significant area of impact was the adoption of the IFRS upstream accounting principles. Reconciliations between previous GAAP and IFRS financial information can be found in the consolidated financial statement available on the company's website at www.encana.com. Turning to our call, Randy Eresman will start off with some highlights from the quarter, 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.

Thank you, Ryder, and thank you, everyone, for joining us today. Today's conference call will highlight our performance in the first quarter of 2011 and provide an update on several key initiatives we're pursuing to enhance shareholder value. During the first quarter of 2011, Encana continued to generate strong cash flow, despite the persistence of low natural gas prices, which at an average NYMEX price of $4.11 was $1.19 lower than the average price in the first quarter of 2010. Cash flow for the quarter was approximately $955 million, and operating earnings were approximately $15 million. Our first quarter total production of approximately 3.3 billion cubic feet equivalent per day was slightly ahead of our expectations, and we're well positioned to achieve our 2011 target average annual production rate of approximately 3.5 billion cubic feet per day. In the first 3 months of this year, we invested about $1.3 billion of our planned 2011 $4.6 billion to $4.8 billion capital program. This capital investment has worked to advance the development of several established and emerging resource plays while at the same time generating production growth. We're firm believers in the benefits of high-grading our portfolio and are continuously looking for opportunities to divest assets that no longer fit with our future development plans, as well as adding new lands in promising areas. In the first quarter, we completed the divestiture of non-core assets for proceeds of approximately $100 million in the Canadian division and approximately $300 million in our USA division. This included the Fort Lupton natural gas processing plants in Colorado. We advanced several key initiatives in the first 3 months of the year, most notably, the signing of a Co-operation Agreement with PetroChina that would see PetroChina pay CAD $5.4 billion to acquire a 50% interest in our Cutbank Ridge business assets in British Columbia and Alberta. Negotiations are ongoing, and the transaction remains subject to regulatory approval by both the Canadian and Chinese authorities. Canada's industry department recently announced that it has extended its review of the transaction by 30 days, which is not unusual. The due diligence process is well underway, and we're working to close the transaction in an efficient and timely manner. Expanding on our plans to continue attracting third-party capital to our high quality assets, we recently initiated a new process seeking joint venture partners on certain assets in the Horn River and Greater Sierra areas. We're also offering an acquisition opportunity for a portion of the Jean Marie assets within the Greater Sierra resource play. RBC Capital Markets and Jefferies & Company have been retained to conduct the potential joint venture and divestiture processes. This new initiative builds on our previous announcements of a farm-out agreement with Kogas Canada Ltd., as well as agreement we're working towards with PetroChina. Also in the quarter, we acquired a 30% interest in the planned Kitimat LNG export terminal and the associated natural gas pipeline. By investing in this planned international trade facility, we're helping diversify the markets for North America natural gas toward exporting production for the first time from Canada to overseas markets. Expect that this project will help to expand North America's natural gas economy across the Pacific to markets where demand is growing, and natural gas prices are more closely tied to oil prices. With oil and NGLs commanding a significant energy price payment over natural gas, in the past year, we have sharpened our focus on oil and NGLs production. In our portfolio, liquids content of 10 barrels per million cubic feet of natural gas decreases the average supply cost by $0.30 to $0.50 per thousand cubic feet. Currently, liquids production on a 6-1 basis makes up about 4% of Encana's total production volumes, but we plan to significantly increase our liquid weighting over the next few years. To do so, we have redirected a portion of our capital investments to oil and natural gas liquids development and exploration. We’re building facilities to extract more liquids from a high energy content natural gas streams at several of our natural gas processing plants. We're drilling liquids prone targets on our existing lands, expanding development into liquid rich areas, exploring for oil and acquiring large and significant positions of highly prospective liquid-rich lands as well. Of our 2011 capital budget, about $1 billion is directed towards activities that will increase our future liquids recovery. For the past year, we've identified or added to our land base more than 1.7 million net acres of land with oil and liquids production potential. In Alberta, we hold about 190,000 net acres in the Duvernay shale, in the Simonette and Kaybob areas, which we acquired for about $300 million or an average cost of about CAD $1,600 per acre. The results of a vertical test well completed in January confirm our expectations of achieving results similar to other operators in the area when we drill our horizontal wells. This exciting new play has the potential to add significant liquids production to the Canadian division and is a promising complement to our liquids rich acreage in the Montney where we have 495,000 acres of land with liquids potential on it, in addition to 380,000 net acres in the Alberta Deep Basin area. In Colorado, we hold 240,000 net acres in the Piceance and the Denver-Julesburg Basin or the DJ where the company has identified liquids potential in the Niobrara and Mancos shales. We plan to test both of these opportunities with re-completions and drilling projects in 2011. Additionally, the 425,000 acres we hold in the Collingwood shale in Michigan are also expected to be perspective for liquids. We plan to drill 4 wells in the play this year, 2 vertical wells in our northern oil play and 2 horizontal wells in liquids-rich southern portion of this natural gas play. Initial drilling results and indications in each of the prospective formations that I just described are showing promise as we step up our evaluation and identification of its liquids potential. Over the next few years, these plays have a potential to deliver substantial volumes of high-value liquids production to Encana's portfolio. By bringing on new oil and NGL production and stripping out more NGLs from our natural gas stream [ph], we expect to significantly increase the weighting of liquids in our portfolio capturing more value and enhancing returns. With that, I'll now turn the call over to Mike Graham for an update on the first quarter results for the Canadian division.

Thanks, Randy, and good morning, everyone. The first quarter of 2011 was another period of excellent performance for the Canadian division. Production for the quarter was approximately 1.5 billion cubic feet equivalent per day, up about 18% from this time last year due to a successful drilling program and lower royalty rates, which offset natural declines in some areas. Production growth was led by Cutbank Ridge, up 40%, as well as Horn River, which grew to 70 million cubic feet equivalent per day from 11 million cubic feet equivalent per day a year earlier. Our first quarter operating cost averaged $1.23 per thousand cubic feet equivalent, up slightly compared to the first quarter of 2010 due to higher long-term compensation expense and a stronger Canadian dollar, partially offset by lower electricity costs and higher volume. Excluding the impact of long-term compensation and foreign exchange, operating cost were $1.05 per thousand cubic feet equivalent or approximately 15% lower than a year ago on a comparative basis. In Horn River, we continue to see an exceptional result in terms of operating efficiencies as we advance our resource play hub development approach in this resource play. In March, we finished completion operations on the 76-K pad, pumping 156 simulations into 11 wells on this pad. First cast production through test wells was brought on recently, and the initial results have been very encouraging. Over 96% of the water used on the 76-K pad was sourced from the Debolt water plant, which reduced our environmental footprint and also saved us over $3 million in water supply cost. We are very active during the quarter in the Montney -- we were very active in the quarter during the Montney, where we currently have 5 rigs running. We drilled 10 net Montney wells in the quarter and plan to drill about another 49 net wells throughout the year. First quarter production from the Montney averaged around 335 million cubic feet equivalent per day, up 68% from the first quarter of 2010. Our 2011 Dawson Montney wells are anticipated to average 14 stages per well with anticipated drills complete and tie-in costs of about CAD $470,000 per stage. This represents about a 10% reduction from 2010 cost levels. At approximately 240 million cubic feet equivalent per day, production from our Bighorn resource play in the Alberta Deep Basin was 20% higher than the first quarter of 2010, but 4% lower than the fourth quarter 2010 volumes due to planned TransCanada pipeline maintenance outages. We drilled 13 net wells in the quarter and are currently running 5 rigs in this play. As Randy mentioned, we are pursuing the development of liquids rich plays across our portfolio. And we are very excited about some of the results we've seen recently in our Bighorn resource play. In Resthaven, we drilled the longest full layer horizontal well to date at more than 5,000 meters total measured depth or 16,500 feet. The well was completed with a 20-stage simulation program, yielding preliminary restricted rate of 10 million cubic feet equivalent per day and about 25 barrels per million cubic feet of liquid. We have identified an additional 70 locations on our land. In the Devonian, we drilled a 4,400 meter horizontal measure depth or a 14,500-foot horizontal well, which was completed with 15 stages and showed preliminary production rate of 10 million cubic feet equivalent per day and liquids content of about 45 barrels per million cubic feet. At our CBM resource play, we achieved first quarter production of 469 million cubic feet equivalent per day, 8% higher than the first quarter of 2010 and ahead of our expectations, primarily due to a favorable weather conditions that allowed us to accelerate our drilling programs. We drilled 320 net wells and brought 538 net wells on stream. For the year, we plan to drill about 450 net wells in CBM. Our farm-out agreement with Kogas Canada Ltd., a subsidiary of Korea Gas Corporation or KOGAS, continues to progress. In Kiwigana, we drilled our sixth well on a 10-well pad. Here, we achieved a Horn River record bit run of 3,392 meters on a recently -- on a well we recently drilled. At West Cutbank, we drilled an additional 2 wells this quarter for a total of 9 wells to date. And we have another 2 planned for the remainder of the year. We remain very pleased with the progression of the farm-out agreement with KOGAS, and we continue to believe there is potential for expansion of the agreement. The construction campaign at Deep Panuke is largely complete, with final tie-ins to be completed upon arrival of the production field center from Abu Dhabi. We expect the platform to arrive around midyear, and we anticipate first gas production from Deep Panuke in the fourth quarter of 2011. So overall, another strong quarter of operational performance for the Canadian division. Now I'll turn the call over to Jeff who will provide an update of the results of the USA division.

Thanks, Mike, and good morning, everyone. In the USA division, we invested approximately $640 million in the first quarter towards advancing the development of our established and emerging resource plays. At nearly 1.9 billion cubic feet equivalent per day, production was 8% lower on a year-over-year basis, primarily due to net divestitures of approximately 85 million cubic feet equivalent per day and the impact of 2009 voluntary capacity reduction volumes brought back online in the first quarter of 2010. The comparative decrease in production was partially offset by drilling and operational success in the Haynesville shale this quarter. Our first quarter operating cost averaged $0.75 per thousand cubic feet equivalent, up compared to the first quarter of 2010, primarily due to higher long-term compensation expenses, workovers, property taxes and general field activity. Excluding the impact of long-term compensation expense, operating costs were $0.60 per thousand cubic feet equivalent, in line with our expectations. Our primary goal in developing Encana's resource play is maintaining or improving the margins we receive relative to capital we deploy. Cost pressures on pumping services continues to be challenging in the current environment and in the foreseeable future. In response, our team has developed innovative ways to manage completion cost and capacity availability through strategic efficiency-based agreements with cost structure transparency. Encana has entered into 3 different business agreements to employ 5 dedicated completion crews into the division. In support of these crews, we are self-sourcing commodities such as profit, sand, fuel and chemicals. These arrangements will enable Encana to continue our efforts to be the lowest cost natural gas producer. Turning now to the results in the Haynesville. First quarter production averaged 412 million cubic feet equivalent per day, up 118% from the first quarter of 2010. We drilled 22 net wells in the first quarter and plan to drill a total of 85 net wells over the course of the year. Encana's currently operating 13 rigs and participating in 9 non-operated rigs. With respect to completions, we averaged 166 simulation stages per month in the first quarter by deploying 2 Haynesville dedicated completion crews. In the second quarter, we plan to launch a dedicated fit-for-purpose completion's crew with the objective of executing 100-plus stages per month. Our current inventory of wells requiring stimulation in the Haynesville is stable at about 12 wells per month. We have transitioned the majority of our Haynesville program from land retention drilling to resource play hub development. About 70% of our capital in the first quarter was dedicated to resource play hub style drilling, and the early results to date have been encouraging. In the first quarter alone, we achieved a 50% increase in the number of wells simulations per day and a 20% reduction in drilling days. Increased well stimulation costs resulting from higher sand and water volumes have partially offset the drilling cost reductions, resulting in overall well cost reduction of around 10%. We are still in early stages of optimizing completion design in the Haynesville by employing a design of experiment approach. As a rule of thumb, we believe that increased water volumes correlate best to higher initial productivity and that higher sand quantity yields higher expected ultimate recoveries. With this in mind, we are pursuing increased water and sand volume schedules in our completion design. Through continued optimization, we believe we are on track to improve our type curve performance as well as reducing overall costs. Additionally, for all of our resource plays, longer horizontal lateral lengths bring increased initial productivity rates and overall type curve performance. As such, we have filed a regulatory application for the Haynesville shale that if successful would allow drilling 7,500 foot horizontal length wells across the existing block of 3 section units. We are expecting regulatory approval shortly, and we are hopeful that the future of resource play development in Louisiana will consist of long reach multi-section horizontal wells. As Randy noted earlier, we hold approximately 40,000 net acres in the liquids-rich DJ Basin. We expect to drill a horizontal Niobrara well in the second quarter to begin testing this opportunity, and we are planning to drill an additional 2 to 4 wells by year end. If successful, up to 175 wells may be drilled on our lands in the basin. Additionally, in the Piceance Basin, we are testing liquids rich opportunities for drilling and recompletion. Early results are favorable, and we are excited about the potential of these emerging plays. I will now turn the call over to Sherri Brillon who will discuss the overall financial performance for the quarter.

Thanks, Jeff, and good morning. Encana's 2011 first quarter financial results were solid, in spite of low natural gas prices. Cash flow for the quarter was $955 million or $1.29 per common share diluted. Despite year-over-year production growth and higher realized financial hedging gain, cash flow was impacted by lower commodity prices, which were down 20% from the first quarter of 2010. For the quarter, Encana's hedge position contributed a realized before tax gains of approximately $205 million for an additional $0.70 per thousand cubic feet equivalent to the average price. As of March 31, 2011, we had about 1.8 billion cubic feet per day or about 50% of expected April to December natural gas production hedged under fixed-price contract at an average NYMEX price of $5.75 per thousand cubic feet. Additionally, Encana has hedged approximately 1.8 billion cubic feet per day of expected 2012 natural gas production at an average price of about $5.87 per thousand cubic feet and approximately 395 million cubic feet per day of expected 2013 natural gas production at an average price of $5.29 per thousand cubic feet. Having these hedges in place increases the certainty of our cash flow generation, helping to ensure stability for our capital programs and dividend payments. Over the past 5 years, Encana's commodity price hedging has resulted in about $7.3 billion of pretax cash flow in excess of what would have been generated had we not employed price hedging. Operating earnings for the quarter were approximately $15 million or $0.02 per common share diluted, $382 million less than the first quarter of 2010, primarily due to lower commodity prices, higher long-term compensation cost and a higher U.S.-Canadian dollar exchange rate, offset partially by higher realized after-tax financial hedging gain and increased production volume. Now turning to our cost for the quarter, combined operating and administrative cost of $1.41 per thousand cubic feet equivalent were $0.37 higher over the year-over-year and are above our 2011 guidance expectation of $1.15 to $1.20 per thousand cubic feet equivalent. This was mainly due to higher long-term incentive cost of about $0.33 and the impact of a stronger Canadian dollar. Combined operating and administrative cost, excluding long-term compensation cost and foreign exchange, were $1.02 per thousand cubic feet equivalent in the quarter compared to $1.05 per thousand cubic feet equivalent in 2010. Despite the increase in the first quarter, we still expect our operating cost to fall within our target range for the year. Depreciation, depletion and amortization or DD&A was $814 million in the first quarter, largely unchanged compared to 2010. As I mentioned on our year-end conference call, Encana's depletion rate is higher than some of our U.S. full cost accounting peers as a result of significant cost write-downs reported by those peers in 2008 and 2009. These write-downs were primarily due to differences in price forecast used to determine proof reserve quantities required under U.S. GAAP when compared to Canadian GAAP. Subsequently, the impairment booked by our U.S. peers allows them to acquire lower depletion rate. Based on 2010 year-end reserve, Encana's first quarter 2011 DD&A rate if it were reported on a U.S. GAAP basis, would have been approximately $1.55 per thousand cubic feet equivalent versus about $2.65 per thousand cubic feet equivalent under IFRS. Using the 2010 year end U.S. GAAP DD&A rate, we estimate that our first quarter operating earnings would have -- be approximately $225 million after-tax or about $0.30 per share. Given the significant differences that persist between U.S. GAAP, Canadian GAAP and IFRS, we have undertaken an internal evaluation of the potential benefit of adopting U.S. GAAP reporting. Encana's balance sheet remains healthy as we move into the second quarter. However, I'd like to take a minute to talk about our debt ratio. Our debt to capitalization ratio at the end of the quarter was 32%, aligned with our target metric of less than 40%. However, our debt to adjusted EBITDA ratio at 2.2x on a trailing 12-month basis was above our target of less than 2x, primarily due to lower natural gas prices. Excluding the impact of unrealized hedging gains and losses for this 12-month period, the adjusted debt-to-EBITDA ratio was 1.9x, while the debt to debt adjusted cash flow ratio was 1.8x. We expect the debt to adjusted EBITDA ratio will remain under some pressure until the natural gas price environment improves. We have always strived to manage our balance sheet in a conservative manner and stay below our debt target. As we navigate through this extended period of cyclically low natural gas prices, a modest increase in leverage has allowed us to continue to take advantage of opportunities that have the potential to generate long-term value for our shareholders. In 2011, we expect to achieve net divestitures of $500 million to $1 billion and close our transaction with PetroChina, which will further enhance our financial flexibility. As Randy indicated, we have chosen to shift a portion of our capital program to the evaluation, exploration and development of oil and liquids opportunities within our existing asset base. We have about $1 billion directed to liquids projects in our portfolio. Careful consideration was given to the funding of these projects, which we expect will help provide significant value uplift to our net backs in the coming years. While a portion of the 2011 liquids focus capital will be directed to development activities, which will have an immediate impact on our liquids production volume, the majority of the capital will be geared toward the evaluation of prospective plays, which we can expect to add significant oil and liquids production to our portfolio over the next few years. Overall, and given in the context of the current natural gas price environment, Encana's financial results for the quarter are very positive. I will now turn the call back to Randy.

Well, thank you very much, Sherri. Despite the persistence of low natural gas prices, we had a very strong quarter, and we're on track to meet our 2011 guidance. I'd now like to take a moment to address our near-term plans for growth given the extended period of unsustainably low natural gas prices that we're currently experiencing. Roughly a year ago, we announced our strategy to increase our pace of development with the goal of a double production per share over 5 years. This very aggressive, but also what we believe to be a very achievable goal, meant that the underlying growth rate for our asset base would have to increase from about 10% per share per year to just under 14% or just over 14% per share per year for that five-year period. Recognizing the potential to accelerate our pace of value recognition through joint ventures and the sale of non-core assets, we fully expected to complement a higher physical growth rate with meaningful share repurchases along the way. At that time, it looked like full economic recovery was imminent and long-term NYMEX natural gas prices would average in the $6 to $7 per thousand cubic feet range. Unfortunately, a full North America economic recovery did not occur as quickly as expected and natural gas prices retreated further at a time when it was clear that natural gas supply was growing rapidly in North America. Combination of these 2 factors has led to significant lower short-term North American natural gas prices and has had a major impact both on Encana's near-term ability to generate cash flow and on our long-term price expectations. This in turn has impacted our project -- program economics and long-term development planning. So in response to this reality, we lowered our long-term price expectations. Our long-term planning is now based on roughly a $6 NYMEX natural gas price in line with the forward strip. We also aggressively added to our hedge program and dialed back our short-term growth rate to better align with our ability to generate cash flow. I'd like to emphasize that we have not abandoned our goal to double our size on a per share basis. We have just accepted that it may take a little longer than we originally planned to achieve it. So while we are investing capital today in a low price environment, over the next several years, the production yield from that investment is expected to benefit from the upside in longer term prices. Based on our modeling and excluding any potential upside from our hedging program, we expect that our cumulative natural gas production over the next 8 to 10 years will be exposed to a weighted average NYMEX gas price of about $6 and generate a 35% rate of return on a go-forward basis. So despite the trough of low natural gas prices we currently find ourselves in, Encana is positioned well. We're a leading North American resource play company with a steadfast focus on generating value for our shareholders. We plan to achieve this through providing high-quality comprehensive disclosure of our reserves and resources, accelerating the pace of asset development, the dancing resource play hub design and -- sorry, design and development, and increasing our exposure to oil and liquids place while attracting third-party investments in our undeveloped assets and by growing the North American market for natural gas. We have clear vision of the future, and we intend to capitalize on the opportunities we see unfolding in front of us. We'll be hosting our Annual General Meeting this afternoon in Calgary and if you're not planning on attending in person, I encourage you to join us via webcast, as I will discuss in further detail Encana's vision of the future and our approach to achieving success in a highly dynamic global energy market. Thank you for joining us today. Our team is now ready to take your questions.

[Operator Instructions] Your first question comes from the line of Andrew Potter with CIBC.

Two questions. Maybe first if you could talk a little bit about some goalposts for your liquids exposure. I mean, you're roughly 4% liquids today. Is the goal to get this to 10% or 20% over the next number of years? Maybe a little color on that. And then second, just on the Horn River JV, maybe you can just give us a little bit of color in terms of how we should think about this, I mean, are you, should we expect something along the similar lines as the Montney where it's potentially 1 big deal covering the whole area or more like the Kogas, smaller deal targeting the fringes or unevaluated portions of the play?

Well, thank you for your questions, Andrew. Regarding the liquids targets, as you are well aware, we didn't set a specific goal at this point in time. We have been accumulating quite a bit of land the last little while. We've been evaluating our land base, and we see that there are a tremendous number of opportunities. It's just a little bit early day for us to be making the forecast. I guess the most specific forecast we could make is the liquids additions that we're going to make to by extracting deeper cutting our extraction facilities in Western Canada. I think in that area we're up. What's the near-term target, guys?

We're going from about 10,000 barrels a day equivalent to about 30,000 barrels a day over the next couple of years.

But we have a lot of irons in the fire right now regarding our exposure to liquids. And I'd say you're going to hear more and more as each quarter unfolds. Regarding the joint venture programs that we've announced in the Jean Marie or Greater Sierra area and the Horn River, our goal would probably to be to get one large JV first, they're just a little bit easier to manage but if the market necessitates, we break them down into smaller pieces, we're willing to look at that as well.

Right now, Andrew, we actually have about 52 net sections that we own 100% of the Horn River. And so the deal on the farm-out would probably look a little bit more like Kogas than it would the CNPC deal. So we have a huge inventory up there on the Horn River, something like a 20-year inventory of wells to be drilled, and we think like the Kogas deal, this would be very accretive to us.

Okay. So the JV would target more of your 100% plans as opposed to the stuff -- your 50-50 on with Apache, I guess.

Right, that's what we're thinking right now. You bet.

Okay. Perfect. Thank you.

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

Just a couple of questions, maybe even tying in a bit to the Horn River. Just interested in what the program is going to look like this year? And then, Randy, could you touch on just on the next series of steps in terms of getting LNG from the contemplation mode just to construction? And I guess the other question is to go on to Andrew's query around how high a liquid number are we talking, would you be open to acquisitions to accelerate that? Or do you feel as though, look the land position we have is sufficient, and we're going to take more of a patient approach?

Okay, I guess, Mike, do you want to give a little color on the Horn River development program this year?

Yes, Greg, we've actually kind of slowed down our capital somewhat in the Horn River. We're going to actually drill about 11 net wells in the Horn River this year. We're finishing off a couple of the pads. We're just starting to drill what we call our D1D pad, and it's been drilled out. We're frac-ing it right now. Apache, we have a 9-well pad that we're frac-ing. Now what we call 34L [ph]. They're frac-ing at about 4 wells or 4 fracs per day. So execution is going tremendous in the Horn River. Also 76-K, which is another pad, has been frac-ed out. We have 11 wells on that pad. We currently bring them on -- we brought on our first 4 wells and I can tell you we're encouraged by the results of those first 4 wells at about 10 million cubic feet a day. Also Kiwigana which is the joint venture with Kogas, we've drilled 6 out of our 10 wells that we're going drill on that pad. And we're going to be frac-ing later on this year. So we’re really emphasizing a bit more in the frac-ing with some of the wells that we have drilled, a little bit less than the drilling. Like I said, execution wise, we're going very nice along nicely in the Horn River.

Okay, thanks for that.

Greg, your question about our entry into the Kitimat LNG project, we're following the lead essentially of Apache who's the operator of that project, and they're currently conducting a FEED study to determine the financial feasibility of proceeding with the project. And the project, I think you're aware, is designed in 2 stages. The first stage is to get to about 700 million cubic feet per day of natural gas used in the facility and then the possibility to double that size in the future. So we are seeing results as they're coming in but it's kind of early days, and probably we won't have a significant update on that until about year end, I would guess. Regarding increasing our exposure to liquids in our portfolio, we've had a great success over our company's history in exploring into plays. We believe that, that is the way in which we can create the most value. And so it is our preference today. There really isn't a play that I guess we'd significantly want to increase exposure to that we don't have a capability to build within our own portfolio.

Okay. Great. Thanks a lot, Randy.

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

I had a couple of things. Randy, give me an idea where you think your current supply cost is.

Current supply cost, our supply cost, we call it that flat NYMEX price that’s required to deliver our cost of capital. We use a 9% after-tax [indiscernible] as a proxy for that. I believe it's around $3.60 right now. For the -- and that's for our development portfolio. So this year’s capital expenditures program. $3.70, sorry, including G&A. $3.70.

Your current [audio gap] don't make that look terribly credible.

I'm sorry, what's that?

The results that you reported this morning would challenge, at least based on our analysis, the credibility of that number. And you've set a $3.70 target going forward. I mean, I would imagine that you're well over $4 right now as we speak, aren't you?

Yes. We said a $3 target for all of our major resource plays going forward. I think what the problem is the issue that Sherri talked about earlier is there's a significant difference between our GAAP reporting between IFRS and U.S. GAAP, which gives the impression that we're making a lot less earnings on the money that we're investing.

Okay. Let me just shift for a second, can you give me a rough idea in terms of the liquids rich exposure? How your various plays breakdown between NGL and condensate? It would appear to me that they are primarily condensate oriented. And in your answer if you could address what you're seeing in terms of the liquids rich characteristics of the Collingwood, I guess, I haven't seen or heard much in terms of what that might be.

Okay, we can talk about individually in the Canadian division and the U.S. division about the products that we're getting on the liquid side. In the Collingwood, what we've identified is a liquid-rich area in the southern part of the play. And moving towards an oil window, we believe, in the northern part of the play. There are just very few data points on that play at this point in time, so we really don't have anything more to offer. But go ahead, Mike.

Mike Graham here. Just as -- we have a lot of liquids rich opportunities in Western Canada, and the Canadian Western sedimentary basin really has a wonderful source rock in the middle of the Devonian, but I can step you through a few of the plays, the Bighorn, which is a Cretaceous stack, we essentially have NGL production of about 10 to 30 barrels per million there. The Montney, sort of, in our Cutbank Ridge area, you can get anywhere from 30 write-ups to about 90 barrels per million cubic feet up there when you assume sort of deep cut processing as well. And we talked a little bit, Randy talked somewhat on our position in the Duvernay. Now we put together about 200,000 net acres in the Duvernay, in the Simonette, Kaybob area. Looking at some of the other competitors in the area, they can have anywhere latest results on one of the horizontals. There's about 5 million cubic feet a day at about 75 barrels per million and like we talked about -- we've drilled 1 vertical into that play, and we have very encouraging results off that 1 vertical so we plan to drill a few more horizontals into it this year. So a lot of our liquids in Canada, we have a lot of liquid potential in Canada. We think we can drill. Today, we’re doing about 14,000 barrels a day of liquids, oil and natural gas liquids. And we think we can double that over the next couple of years to around 30,000.

And, Jeff, do you want to add?

Sure. Going into the DJ Basin where I talked a little bit about our program or the plan to drill horizontals, that is a very liquids-rich plays that generates both oil and NGLs and natural gas. And depending on where you are in the play, it ranges from a predominantly oil system to a rich natural gas stream. So I think, obviously, we haven't drilled the well yet, so I don't want to comment specifically about the yields around the wells that we're drilling. But our expectations are that the numbers will be pretty oily and also have fairly rich condensate yields.

Mark, Randy Eresman here again. I just want to talk a little bit more about the comment you made about the credibility of our numbers. Our future development costs are determined by our external, or by independent qualified reserve evaluators, have determined that our future development costs or conversion cost of our PUDs is about $1.75 per Mcf. Last year, our planning and development costs were around $1.50. And if we looked at our entire portfolio today, our planning and development costs range between about $1 and $2 for all of our major resource plays [ph]. So there is a significant amount of credibility in our ability to get our -- all of our existing supply cost number of around $3.60 to $3.70 and our ability to get down to a much lower supply cost as we continue to advance our resource play help strategy on our key plays.

Randy, thank you. I just had 1 more, I assume that your entry cost into Kitimat was fairly naught [ph], is that accurate?

Actually, I didn't hear your question. But we haven't disclosed our entry cost. It's really just because of the agreement between the partners.

Okay. Thanks a lot, guys.

Your next question comes from the line of Brian Singer with Goldman Sachs.

Randy, you've been cautious on gas prices versus oil prices the last year and especially going back to the analysts meeting a year ago where you'd highlighted your low-cost position and the ability to really thrive in a lower gas price environment. Can you talk to what the tipping point or change was in either your relative price expectations or in what you're seeing in your resource base now to make you shift your capital investments a bit more towards liquids?

Well, the main one is that -- I mean, the value proposition is there, and we're also having to see that technology that has been applied to the more liquid-rich plays areas of the shale gas plays. It appears to be working quite well. We maybe a little bit cautious, but fortunately, we have a large land position where we are exposed to many of these play types, and we don't have to go out and buy them from scratch. But our optimism is really based on industry’s success of applying the current technology that we are -- the exact same technology that we're using for our natural gas plays.

Great, thanks. And then given that you're not raising your capital budget meaningfully here, where in the portfolio are you lowering activity to make room for the increase in investment liquids?

I'll get Mike and Jeff to make a quick comment on that.

Yes, Brian, Mike Graham here again. Like Randy talked about, sort of, our liquid there, but I think he pointed out that sort of any 10 barrels per million will reduce our supply cost $0.30 to $0.60. So it really does bode well for anywhere where you have sort of natural gas liquids, and that's why we've diverted quite a bit of our capital away from our dry gas plays areas like the Horn River, the Jean Marie and we've moved them into areas like the Deep Basin, the Montney, the Alberta Cretaceous stack and like we say, the Duvernay as well.

Yes, Brian, Jeff Wojahn. Fairly modest changes in the U.S. relative to our original guidance on the budget. We did take a little bit of capital and redirected it to Western Canada, primarily out of the Rockies area where we had dry gas opportunities that didn't compete as favorably with some of the opportunities that Mike described.

Great. Thanks. And lastly, have you received any clarity regarding the structure of the proceeds from PetroChina and the timing of whether you'd get those all at once or over some period of time and is that or receiving those proceeds the catalyst to accelerating your repurchase program?

We haven't gotten any further insight from PetroChina as to how they will pay for the assets that they’re acquiring. And I fully don't expect that to occur until closing.

Great. Thank you.

Your next question comes from the line of Harry Mateer with Barclays Capital.

First question, as you note it in your earnings release, your debt-to-EBITDA metric is now above your targeted level. Can you just talk about what your plans are to restore that, to within the target range, barring an uptick in natural gas prices?

Sherri, do you want to lay out the plan?

Well, actually, granted that natural gas prices have pushed our target above the Encana targeted range, we do have from time to time extended our leverage that gets us a little bit out of the range. But that being said, we do have a very active disposition program in place and the proceeds from those dispositions can go to our repayment of debt that's maturing, say in November. So we do have some -- well, we have an aggressive plan relative to our continued spend in increasing our opportunities for long-term value addition. We do also have proceeds that are going to be coming in the door, whether it be through the PetroChina joint venture or some of the other joint ventures that we're anticipating.

This last quarter was somewhat unusual in that we did acquire a significant amount of land in oil prone or liquid rich areas. And we had a couple of other items that were sort of one timers in our portfolio. We expect over time with the additional JVs that we're doing and the divestiture program that we will come back on side. Although quite frankly, we use the range and expect to use the range in the low price environment, and so this will be just a temporary situation, we believe, for the company.

So is it fair to say the intention as now is to pay down the maturity in November out of available cash rather than coming back to the bond market?

I can't give the details of that at this time.

That’s speculative at this point.

There's a lot of things that will happen between now and November.

Okay. And then can you just talk about any preference you guys have for the structure of transactions in the Horn River, Greater Sierra in terms of proceeds, so do you prefer to get carry drilling or cash up front, any commentary that you can give us on the structure of those deals would help.

No. We just evaluate the deal. We're not, we’re less [indiscernible] about the structure. I know -- we'll just want to make sure that it has the -- is most impactful for the company as a whole.

Okay. Thanks.

Your next question comes from the line of Kam Sandhar with Peters & Co. Kam Sandhar - Peters & Co. Limited: Just have a couple of questions. First of all, Mike, I'm wondering if you just give me a bit more detail of what the plan is for the Duvernay shale in terms of number of wells to be drilled vertical or horizontal, and then if you could just comment on whether you expect most of your increase to be liquids-rich perspective or there is a dry gas or oil window there. And then the second question, again, on the Deep Basin would be -- you talked about your flare [ph] well that you drilled. I'm just wondering if you can be a bit more specific about how much running you would have there in terms of number of locations?

Yes, Kam, Mike Graham here and I also have Mike McAllister with me as well, who kind of looks after the Deep Basin so he can maybe talk to the flare [ph] but like Randy pointed out, we put together close to 200,000 net acres in the Simonette, Kaybob area of the Duvernay. The Duvernay play seems similar to the Eagle Ford and that there -- we could go from sort of a dry gas window into a liquids-rich window. And you've seen that the first couple of tests that were announced by competitors are talking in and around that 75 barrels per million. So the bulk of our acreage, probably 2/3 of our acreage, we think certainly will be in that liquids-rich area. And like I say, Kam, we haven't released the results. But it's very encouraging the results we got on the first vertical well. We expect if we drill a horizontal, our results would be similar to what some of the competitors announced. The only difference being that we can probably do them quite a bit cheaper than what's recently announced if you put our resource play hub together there. So anyway, we'll talk a lot more of the Duvernay sort of as time goes on. We plan to drill probably another 3 or possibly 4 horizontal wells into this year, starting in around August. So we'll get quite a bit more results. So like I say, it's very, very early in the play. We put together a nice land position and look forward to more results for the rest of the year. Mike, you want to talk about flare [ph].

Yes. Hi there, Kam. It's Mike McAllister here. With respect to our flare [ph] horizontal, yes, we're really encouraged with that result. And, in fact, we've had some tremendous results in the Cretaceous Deep Basin on our horizontal wells. I think the 70 wells we refer to is just on that one floor trend, but we have an inventory in excess of 700 horizontal well locations that we've identified in the Cretaceous Deep Basin or in our Bighorn resource play. Kam Sandhar - Peters & Co. Limited: And would that include the Will [ph] Ridge also or just the flare [ph]?

That would also include the Will [ph] Ridge. When I used the term 700, I was referring to all the zones that we've identified that would have the horizontal potential. Kam Sandhar - Peters & Co. Limited: Okay. Thank you.

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

I have 3 quick ones, for the 3 [indiscernible] it doesn't include land cost, so what are the land cost per Mcf?

There's obviously a wide range of that from almost nothing to I think some entry cost are as much as $1 but that's to and far between in our portfolio.

You have a corporate average of $3.70, you must have a corporate average for land, so what's the average?

$0.25 is about the average.

Okay, that's fine. With Kitimat, can you say whether it was promoter [ph] or heads-up?

Largely, heads-up.

Okay. Last one for me, in terms of considering going to U.S. GAAP, could you give a ballpark range of how large an impairment you'd take?

The impairment has already been taken or recorded on our notes, our financials in the last couple of years. We've got our chief accounting officer on line.

Yes. So in our U.S. full cost reconciliation, there is notes and it’s the end of our year end financial statement. And in there, in '08 and '09, we would have taken impairments just like all of our U.S. full cost peers, and the information would be held in that.

No. I realized that and it’s rather substantial. I'm just wondering if you can give an update on what that amount is?

Yes, on our conversion to U.S. GAAP, we wouldn't have to take another impairment.

Okay. Thank you.

Your next question comes from the line of Barbara Betanski with Addenda Capital.

It's a bit of a follow-up to Brian's question on the PetroChina joint venture, just three short ones. The first, is I know there's some uncertainty around exactly what type of payment is going to be made by PetroChina, but would share buyback be a priority if there was a large upfront payment?

Share buyback, the way we've done them in the past is if we sell cash flow generating assets, we try to, as a minimum, stay whole and because in this transaction, there is a component of production which has gone into the deal, you should likely expect that a portion of the receipts would go to share buyback to offset that. I can't be any more specific. We knew we bought a share buyback, we have a normal-course issuer bid, that's outstanding and it allows us to buyback 5% of our shares to the end of this year I believe.

Okay. And then secondly, once that deal is finalized, is there, what sort of magnitude, a change in guidance would you expect with this year? Would there be any sort of major changes or pretty much run the course for the year?

The program -- sorry, because the changing guidance that would occur would be the amount of production that goes towards PetroChina, which is about 250 million cubic feet equivalent per day, our capital would be reduced in the Cutbank Ridge area, would be reduced by $200 million to $300 million? Okay. So it's basically a true-up in capital and cash flow from January 1 which is the expected economic date of the transaction.

Okay. And then just finally, in terms of the set up of the agreement, you've set it up as a sort of a joint operating company and I just wonder in terms of operational control whether what you sort of sacrifice or gain in terms of setting it up as a joint operatorship?

We're actually just working through that piece now but in our agreement that we have, in our Co-operation Agreement that we signed earlier this year, it specifies that Encana will operate for the first 2 years, and then we will form a joint operating company. And so the form of that and how that will work has not been fully worked through yet.

Okay. Thank you very much.

Your next question comes from the line of David Tameron with Wells Fargo.

Quick question, you talked briefly about the Mancos Shale, can you give me more detail about, I assume that's the Piceance? And can you just tell me -- you said it's liquid rich, can you give us more color there? I'm assuming this is all acreage in the Piceance, not [indiscernible] is that correct?

Yes, Jeff Wojahn speaking. Yes. We have recognized the Mancos as a petroleum system and there's been a number of industry vertical tests, and we've done a little bit of recompletion yet. But one of our objectives for the remainder of the year is to give a little bit more information on the nature of the Mancos petroleum system. So I don't really have anything specific to say right now other than that we have a very large position on it, and we are stewarding our interest towards liquid-rich plays and we've identified that as a fairly significant opportunity relative to our land base. And I think Randy talked about 200,000 net acres, I think Encana owns in that particular area. And I think in the upcoming quarters as we get more results, I’ll have more to show about that.

Okay. So I mean is it different than what they're chasing in the [indiscernible] basin assuming it's the same system?

It's the same petroleum system albeit in a different depositional environment, different structural environment. So I think we recognize that it has significant amount of potential. And there is some historical production in the basin that we're working with that data right now to understand a little more, so more to come.

[indiscernible] 1 more thing, you said more to come and you’re going to talk about it in future quarters, I mean, is the plan to throw a rig out there and drill a handful of wells or any magnitude?

We have current activities right now ongoing relative to recompletion of some of the -- we're pretty big plays. So it's easy for us to go and test some concepts, as well as potentially drill a few wells into it.

Okay. I appreciate that. Thanks, Jeff.

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

So just a question on the CBM in Canada, just looking at the growth that you have out of the CBM, just wondering how the economics of the CBM compare with the economics of the rest of your portfolio. So I guess it's a three-part question. Could you talk about F&D cost and net backs and possibly future development capital as well and compare those to -- essentially what I'm trying to get to here is when you say your supply costs on average is $3.7 an MCF, what range are we looking at here? And is CBM at the lower end of the range or at the high end of the range?

Yes, George, Mike Graham here. If you look at CBM, it's essentially a dry gas in sort of central Alberta, if you will. Now we have very good results at CBM. We actually average about 469 million cubic feet equivalent over the first quarter which is actually quite a bit ahead of our budget and quite a bit ahead of sort of Q4 of last year. We actually finished -- we actually drilled about 320 wells like we said. And typically, our CBM programs, we drill them during the winter, if you will. So Q1 will be very busy for us. And then we’ll wait until the farmers get all their crops off, and then we'll move back in, in Q4. So Q4 and Q1 really are big quarters. But everything on track there. We've taken a lot of wells from sort of single vertical wells to pad drilling where we've gone from 1 well per pad, if you will, to 4 wells per pad. And that will reduce our supply cost. We think from about $3.50 down to close to $3. So it really starts to compete in our portfolio. You got to understand that we own a tremendous amount of infrastructure out there and most of our CBM lands are on fee lands, which means that Encana owns the mineral right so we don't pay any royalties on those. And so CBM really does have one of the highest net backs of any of our business units because of the low royalties and the relatively cheap operating cost out there. So it truly is probably 1 of the dry gas plays that competes nicely in our portfolio. Maybe unlike areas like the Jean Marie and a little bit tougher just because of the dry nature of it. So, anyway, George?

Yes. But to be just a little bit more specific to answer the question. When you talk about our $3.70 corporate supply cost, that includes about a $0.30 of G&A, which means that on a play basis, our average supply cost is about $3.40 and it just so happens that our CBM play is right at that average, it's right mid-portfolio. But it's a play that -- and it gets there because it has a lot of great attributes because largely on our existing fee land base, so we do pay low royalties, and we have relatively low operating cost. What Mike is talking about is as we try to develop resource play hub type techniques that we're using elsewhere in our portfolio, here, we expect that we can even get the supply costs down further. So despite the fact that a lot of others will be having some challenges with coalbed methane in Canada, it actually does quite well in our portfolio today.

It generates a lot of free cash flow for us, and we’ll typically drill anywhere from 500 to 1,000 wells per year. This year, we plan about 450 and like I say, we've already did 320. And we have a relatively large inventory somewhere in the order of 15,000 to 20,000 wells in our portfolio. So we like it. We can wind it down very easily if we want because there is no lease retention here and for the most part it's all on EnCana fee land.

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

I've got a couple of questions. I'm just going to start a follow-up to David's question on the Piceance. Looking to last year's CapEx, it looks like you spent roughly $165 million in the play and then if I'm looking to 2011 guidance for the Piceance, you're guiding to $525 million. So aside from the increase in the well count, which was addressed in the press release, where is the rest of this capital going?

Thank you. Jeff Wojahn speaking. The reason why there's such a high variance of capital with Piceance is related to the timing of a number of joint venture transactions. We have about 4 or 5 historical joint ventures in there. And last year, the number was abnormally low, by and large, because we were carried by other parties. But our activity levels have been fairly stable from a rig count point of view in the basin over the last several years. But that's really the change, it’s just more working interest changes, rather than I'll say a big pickup in activity by Encana. We are looking, we are doing more exploratory work as I mentioned before in regards to taking a closer look at some of the shale potential in the basin and that to some degree has increased our capital as well.

So here, you'd be looking in the sort of tens of millions of dollars?

Yes. And again, that's really a function of some of the scope or some of the activities that we have ongoing and what we see -- if we are encouraged, we may direct some more capital towards liquids rich areas of the basin as we talked about before as well.

Okay. Perfect. Now, I've just got one more question for you relating to production volumes out of Fort Worth in East Texas. So if you just look at the trend, production has been falling since early 2010 so my question is how should we be thinking of base declines in the production profile for that region looking forward?

A couple of things. Actually North Texas is a program that we like to see or I think we're looking at 2 to 3 rig program in that area, and we've actually seen very fairly good supply cost overall in the Barnett shale, more related to liquids-rich components of the play. And it today is mid portfolio and I think our long-term objective for that asset would be to maintain production and that was 1 of the reasons why we changed our guidance. So that we rolled it all in into East Texas as well. In East Texas, we, by and large, have moved towards looking at delineating some of the Bossier sand and Mid-Bossier opportunities outside of the main [indiscernible] field area and we have a number of pretty impactful targets that we're targeting over the next quarter or 2. And I think from there, we'll be able to get a little more guidance on the kind of growth profiles moving forward in that area.

Perfect. Thank you.

Ladies and gentlemen, we will now take questions from members of the media. [Operator Instructions] Your next question comes from the line of Amanda Fraser with AllNovaScotia.com.

I was wondering if you can tell me a little bit about what the impact of the legal action that's going in FBM that's taken against Encana. I guess what impact did that have on the Deep Panuke project?

Amanda, Mike Graham here. Yes, we are -- that is before the court so we are not really going to comment on any of that but it will not affect the timing in any way. So we're still looking to get the production field center out of the Middle East, sort of in Q2. We expect gas production still to come on in and around October. So Q4 this year and then we'll take that production and we'll ramp it up. We're actually got design capability of about 300 million cubic feet a day and we have firm service of about somewhere around 200 million cubic feet a day. So that's kind of the plans for Deep Panuke. It's going to sail out of the Middle East shortly here and arrive in Nova Scotia and be outfitted there and should be on production in Q4. So no impact from any of the losses.

Okay. Just considering the, I guess, the challenges that you've had with the project, where does it fit into your portfolio now?

Well, Amanda, like I say, we're going to get meaningful production coming out here. These wells can produce about 50 million cubic feet a day each and every well. So right now, most of our capital has been spent. We said our capital program now in its entirety is going to be about $960 million. And essentially, all of that, most of that capital has been spent except for about $100 million is left to be spent just to really hook the production field center up. So right now, things are looking pretty good, and we're very encouraged to see the production coming on in Q4.

Okay, thanks.

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

I'm wondering how and why you can strike a major joint venture with PetroChina without knowing how you're going to be paid?

We know very well how we're going to be paid. I just don't have the ability because of our confidentiality agreement to provide that information to the public at this time. It will become clear at the time that the deal is closed. We will make it public at that time.

Okay. And my other question, I have 2 more. With gas prices going -- if gas prices were higher, would you still be chasing the amount of joint ventures that you're after?

Yes, we would likely be doing the same thing because it's really based on the number of wells that we have in our inventory, and we're measuring the wells in our inventory in the range of 30 to 50 years today. And it's just much more than we can do on our own. It just makes sense, economic financial sense, to attract third-party investment dollars to help recognize the value that we have in our portfolio and also help us accelerate that pace of development.

Even if gas was at $6 do you predict?

Gas, it was the time that gas was at $6 that we put out our strategy and our strategy at that time was to try to attract between $1 billion and $2 billion per year of third-party capital through joint venture arrangements.

Okay. And now if you look for oil, is there a regret that you hadn't shifted so much of the oil to Cenovus, that you would have held onto some of it?

These are vastly different things and the primary reason for splitting Cenovus and Encana was to get recognition for in the marketplace for the individual values of the businesses that were being run. Today, because oil is in a high-priced environment and it's clear, there's a clear execution plan on the Cenovus side, the valuation that they're getting is exactly what we were hoping would be achieved. On the natural gas side, unfortunately, we're suffering through prolonged environment of low prices and it's not as clear, I'd say, to the investment community when a turn will occur in the market. So very different commodities but we think the deal that we did then and we do the same deal today. It's just unfortunate that the natural gas market isn't a little bit more positive for us.

Do you think you would be chasing as much oil right now if -- when you did split and you sort of had the expectations of where prices would be, did you think that there was a chance that oil would become part of your portfolio then? Or if everything would have went according to plan, you would have stayed away?

Well, it's really got to do with the valuation difference that has occurred. In the last year, we've seen oil go from about almost twice as high as it was at the time that we split the company. So it's just becoming more and more attractive to pursue liquids-rich opportunities today.

So it is fair to say you didn't expect to go down that route when you split?

It was hard to say what we would do in the future at the time that we split. But I mean chasing liquids because of the value proposition today and also because I spoke about this sort of a bit earlier, it wasn't as clear that the technologies that were working so well for resource play development of natural gas were going to be as effective in liquids rich and oil plays. So that technology has really -- and we're enablers of that technology. And users of the technology and it makes sense now in our portfolio that we can expand into those liquid-rich windows.

Okay. Thanks so much.

Your next question comes from the line of Shaun Polczer with the Calgary Herald.

Just going back to the Duvernay, is there a sense of how much you guys have spent on land, say since last summer?

Mike, you want to go ahead?

Yes, Shaun, Mike Graham here. Randy actually talked about that in his conference call. But anyways, we spent about $300 million on our land today, which actually works out to be above $1,500 per acre. So it's pretty reasonable what we've done so far in the Duvernay. Like Randy pointed out, we like to get into these plays early. We've been accumulating land for some time now in the Duvernay and we've got a tremendous land position in it and like most Encana plays, we get in early and relatively cheap.

Is there any sense of how Duvernay would stack up, say, compared to Horn River given that it's so much closer to infrastructure and markets?

Well, like Randy pointed out, sort of these plays with the natural gas liquids, in the Duvernay, based on our test and based on some test of some of the competitors has a tremendous amount of liquid, 75-plus barrels per million. So if you put in the liquids with a high oil to gas ratio, if you will, the Duvernay stacks up very nicely, probably top quartile in our play. But like I say, it’s very, very early and we've only got one vertical test into a few competitors involved into it.

No, I can appreciate that. But given the high liquids content, would it become a priority or would you just kind of go on your normal way like you've kind of done with Horn River?

Well, like we're hoping that the Duvernay will be another key resource play for us going forward like the Horn River or like the Montney or the Deep Basin of Alberta, so we think it has the potential to be very material to Encana going forward. And produce a lot of liquids as well.

Okay. And then finally, is it a play that you would consider joint venturing with?

Well, we sure might, Shaun. I mean, like Randy pointed out, we've got 30 to 50 [indiscernible] inventory. So right now, we're just -- our land position together and we're going to, like we say, drill another 3 or 4 horizontal wells into it and then we sure may consider joint venturing it because we do have already a very big land position on it.

Okay. Thank you.

Your next question comes from the line of Bill Holland with Platts.

One question on the Horn River Greater Sierra JV, do you have any thoughts about the potential size of acres of that? And a target price you're looking to get for it?

Bob Grant is here, he can provide some colors there.

Yes. This is Bob Grant. What we're entertaining right now, Mike mentioned, we have some 100% land there and there are 52 net sections. So that's 100%.

That's the Horn River, but Greater Sierra?

And Greater Sierra, it's about 2,700 net sections.

So it's a very large area.

And a target price?

No, we don't have a target price that we make public at this point in time.

Thank you.

The next question comes from the line of Edward Welch with Dow Jones.

I was wondering the cumulative production growth per share that you're going to have every year under this plan to grow to double over 5 years is I think you said just over 14% per year. Natural gas production per share is up 4% from last year as of this last quarter. I'm just wondering since you're dialing back near-term growth, could you put -- I don't know if you've done this somewhere -- put a dollar value on how much less I guess you are spending as opposed to what you thought you would be last year?

When we put the plan together, the long-term average was $6 billion per year. It wasn't meant to get there immediately but that was what the average was going to be to get the double in 5 in the timeframe. So we pulled back almost 1/3 in terms of the capital, and it takes still a substantial amount of capital to offset underlying decline that's why the growth rate is only in the 4% range for this quarter.

Okay so you're down to just over $4 billion per year now? Is that [indiscernible] right now?

That which is directed towards development type activity. There has been some additional money spent as we talked about in land acquisition and entries into new plays.

Okay. Thanks a lot.

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

Thank you, everyone, for joining us today. Just as a reminder, I encourage you to listen in this afternoon to Randy's AGM presentation. For now, though, our conference call is complete.

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