Ovintiv Inc. (OVV) Q3 2011 Earnings Report, Transcript and Summary

Michael G. McAllister - Executive Vice-President and Senior Vice-President of Canadian Division Jeff E. Wojahn - Executive Vice President and President of USA Division Eric D. Marsh - Executive Vice-President And Senior Vice-President Of Usa Division Renee E. Zemljak - Executive Vice President of Midstream Marketing & Fundamentals 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 Ryder McRitchie - Vice President of Investor Relations

Dan Healing Brian Singer - Goldman Sachs Group Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research Mark Gilman - The Benchmark Company, LLC, Research Division Greg M. Pardy - RBC Capital Markets, LLC, Research Division Brian C. Dutton - Crédit Suisse AG, Research Division George Toriola - UBS Investment Bank, Research Division Unknown Analyst - Robert Brackett

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Third Quarter 2011 Conference Call. [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.

Thank you, operator, and welcome, everyone, to our discussion of Encana's 2011 third quarter results, which we are hosting from our Denver office. 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 the 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, 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'll now turn the call over to Randy Eresman, Encana's President and CEO.

Well, thank you, Ryder, and thank you, all, for joining us today. During the third quarter, Encana continued to deliver solid operational performance and generated strong cash flow and operating earnings. In fact, throughout 2011, our company has performed at one of the highest operational levels in our history. The third quarter total production of approximately 3.5 billion cubic feet equivalent per day was up 6% per share from the same period in 2010, and we remain on track for the full year as well. Cash flow for the quarter was approximately $1.2 billion, and operating earnings totaled $171 million. Within the first 9 months of the year, cash flow totaled $3.2 billion, and operating earnings totaled $352 million. During the quarter, capital expenditures excluding acquisitions and divestitures totaled about $1.2 billion. Year-to-date, we've invested about $3.6 billion out of our planned $4.6 billion to $4.8 billion capital program, and we are on track for the full year as well. During the first 9 months of the year, we completed the divestiture of noncore assets for proceeds of about $500 million. We've also taken significant steps toward achieving our divestiture target for the year, driven largely through the sale of midstream assets. In September, we announced the sale of a portion of our Piceance gas gatherings assets for about $590 million, and earlier this month, we announced the sale of our interest in the Cabin Gas Plant for proceeds of about $220 million. In both cases, we received very strong valuations for the assets. Further, these transactions, in effect, recapture some capital and reduce future midstream capital requirements. Both transactions are expected to close by year end. We have a number of additional sales processes in various stages of negotiation, which include the Cutbank Ridge midstream assets in Alberta and British Columbia, our North Texas property in the Barnett shale and a portion of our Jean Marie assets in northeast British Columbia. So we're well positioned to achieve our stated $1 billion to $2 billion worth of net divestiture targets by around year end. In addition, we continue to explore joint venture opportunities for the undeveloped British Columbia lands in the Cutbank Ridge area. Although I won't comment on the specific deals until definitive agreements have been signed, I can tell you that the interest level is very high, indicative of the high quality of these assets. These are all highly competitive processes. We expect to be in a position to provide more information by around year end. The assets we typically consider for these types of joint ventures are plays where our future drilling inventories can be measured in decades. Once we fully delineated the resource and through implementation of a resource play hub processes, we can demonstrate a line of sight to the lowest cost structures that we think can be achieved from the assets. We then create optimal opportunity to accelerate the capture of value through joint venture arrangements. Third-party capital dollars invested in our assets in this way will accelerate the pace of development, and due to the disproportionate nature of the capital spent during their interest, the third-party dollar support our net growth, further lower our cost structures and improve our returns. Our teams have been very, very busy in this regard. At the same time, we're also in the midst of developing our 2012 capital program. And although there are clearly a number of moving parts, which have the potential to further strengthen the company's balance sheet, we're at this time taking a conservative view to natural gas pricing and developing our capital investment plan accordingly. Our high-level approach for next year is to align capital investment plus anticipated dividends with our expected cash flow generation before divestiture proceeds. With continued divestitures, these proceeds will provide additional and unallocated financial flexibility. Within the 2012 budget, it's expected that many of our drier natural gas plays will see a reduced capital program, while a growing portion of next year's capital investment will be directed towards our extensive oil and liquid-rich development and exploration opportunities. From our existing development plays, we expect increase natural gas liquids production by about 55,000 barrels per day, which will take the company's total liquids production from the current level of about 25,000 barrels per day to about 80,000 barrels per day by 2015. Beyond this, we're pursuing extensive additional organic growth through a continued exploration work across our portfolio of liquid-rich lands. So this is just the beginning of our expected liquids production growth. There will be more to come from other plays as we proceed through the year. But this is what we are prepared to forecast with confidence at this time. Although natural gas prices have resulted in less capital being allocated to our drier gas assets, I want to stress that even at the current strip prices, the full cycle economics on many of these plays are still very economic. This is in part due to their inherent high quality, but also in part to the longer-term agreements we've established with our suppliers and service providers across Encana's operations and the continued implementation of our resource play hub development model, which has enabled us to offset cost increases with increased capital and operating efficiencies. With that, I'll now turn the call over to Mike Graham for an update on the third quarter results for the Canadian division.

Thanks, Randy, and good morning, everyone. In the Canadian division, we've had an excellent year so far. Production for the quarter was approximately 1.55 billion cubic feet equivalent per day, up about 5% from the same period last year. Year-to-date, production from the Canadian division is up 10% compared to the first 9 months of 2010 as a result of successful drilling programs across all of our key resource plays. Our third quarter operating costs averaged $0.94 per thousand cubic feet equivalent, up 3% compared to the third quarter of 2010 due to scheduled plant turnaround cost and a stronger Canadian dollar, partially offset by lower electricity costs and lower long-term compensations costs. Excluding the impact of foreign exchange, operating costs were $0.89 per thousand cubic feet equivalent. We had another strong -- we had another quarter of strong results from the Cutbank Ridge key resource play, which produced an average of 539 million cubic feet equivalent per day. Production was up 5% from the third quarter of 2010 despite a plant turnaround at Steeprock, which impacted production volumes by about 20 million cubic feet equivalent per day. During the quarter, we saw some very promising results from wells drilled in the Pipestone area of our Montney development, where we own about 300 net sections of land. Our latest well tested at 6.2 million cubic feet equivalent per day with condensate levels of 55 barrels per million cubic feet, and we have reduced our horizontal drilling times in this area by 20% over the last 12 months. At Bighorn, we drilled our longest horizontal well to date during the quarter. Drilled in the Wilrich formation, the well had a total measured depth of about 19,000 feet and a horizontal length of about 8,000 feet. We plan to complete the well with a 25-interval stimulation program during the fourth quarter. We also saw strong results this quarter from a horizontal well drilled in the Fahler formation. The well was completed with 20 stimulation intervals and is producing at a rate of about 8 million cubic feet equivalent per day. Well performance is above our expectations, both in terms of rate and on a cumulative basis. We are very encouraged by the well results we are seeing for the numerous zones across the Bighorn key resource play, where we have an inventory of over 700 horizontal net well locations. At our Greater Sierra key resource play, production was up 16% over the third quarter of last year, led by increased production from the Horn River where production more than tripled from the same period last year. We completed stimulation operations on the north half of the d-1-D pad. By the end of the quarter, 3 of the 7 wells had flowed at test rates within our expectations or about 15 million cubic feet equivalent per day per well. The remaining 4 wells have been undergoing cleanup and are flowing through test equipment. Work is currently progressing to have the first set of wells through permanent facilities by late October and the second set of wells to follow approximately 10 days later. Production from the 34-L pad continues to track at or slightly above our predicted tight curve, confirming our expectation that wider well spacing and fewer completions per acre of reservoir can be a more efficient development approach. In July, as part of our plans to attract third-party capital investment in our undeveloped assets, we expanded our Horn River farm-out agreement with KOGAS, which will see them invest an additional CAD $185 million in approximately 20,000 additional acres in the Kiwigana area. We are very pleased with the expansion of our original CAD $565 million farm-out agreement with KOGAS, which has allowed us to accelerate our drilling program both at Kiwigana and in the West Cutbank area. Currently in Kiwigana, the drilling of the first well pad is now complete and following completions work this coming winter, we expect production to come on stream in the spring of 2012. All 10 wells on the first pad have been drilled in preparation for completion activities are underway. At the second pad, all 7 surface casings have been set, and the first well is nearing completion of the horizontal lane. We plan to drill the wells to a total measured depth of about 18,850 feet. Based on our current pace, we expect that 3 of the 7 wells should be rig released by the end of the 2011 on this pad. At our CBM resource play, third quarter production of 473 million cubic feet equivalent per day was 13% higher than the third quarter of 2010 as a result of successful drilling, acquisitions and third-party royalty production. Liquids production during the quarter averaged over 7,600 barrels per day in this area and was ahead of our expectations, primarily due to incremental royalty production from the third-party activity. I'll turn now to one of the hottest new plays in Western Canada, the Duvernay shale. We plan to spud 3 wells in this play during the fourth quarter, 2 in the Willesden Green area and one in Simonette. We hold about 365,000 net acres in what we believe to be some of the best liquid-rich acreage in the play. As I said before, it's still early days, but we are very excited about the potential of the Duvernay shale to add significant liquid volumes to the production profile of the Canadian division. We expect to be even more active in this play next year, but are finalizing the details through our budgeting process. We are seeing good progress on 3 deep cut facilities, facility projects in the Canadian Deep Basin which extract larger volumes of natural gas or NGLs from the natural gas in this area. In December, approximately 5,000 barrels per day of additional natural gas liquids are expected to be captured from the expanded facilities being installed at the Musreau natural gas processing plant. There are additional expansions planned at the Gordondale and Resthaven facilities as well. As Randy mentioned, longer term, through continued production growth and additional deep cut extraction, we now expect to increase our Deep Basin liquids volumes by about 55,000 barrels per day by 2015. Turning now to the East Coast offshore gas development at Deep Panuke, the production field centre or PSC was towed out for installation at the Deep Panuke offshore location at the end of July. The subsea hookup program is underway and is expected to be complete by early November. We now expect first gas from Deep Panuke by the end of the first quarter of 2012. Additional production rates are expected to exceed 200 million cubic feet per day. Switching to the West Coast and the proposed Kitimat LNG Terminal, of which Encana has a 30% interest, just last week, the Canadian government provided approval for the export license, which will allow a total of 1.4 billion cubic feet per day to be exported over a 20-year period. This is a significant project milestone. At this point, all of the major regulatory approvals for Phase 1 have been received. The Kitimat partners are currently negotiating long-term offtake agreement that will be back stopped with Western Canadian gas. The Front End Engineering Design or FEED study undertaken to evaluate the capital cost of the project is expected to be completed by the end of the first quarter of 2012. Following the completion of the study, as well as the negotiation of long-term offtake agreements, the partners will make a decision on proceeding with investing the capital to construct the first phase of this project. Overall, we had an exceptional quarter in the Canadian division. Now I'll turn call over to Jeff, who will provide an update on the results for the USA division.

Thanks, Mike, and good morning, everyone. The operational results from the USA division in the third quarter were first-rate. Production averaged 1.96 billion cubic feet equivalent per day, up 6% from the third quarter of 2010, primarily due to a successful drilling program in the Haynesville Shale. For the first 9 months of the year, production was down slightly, primarily due to net divestitures and strong production performance in early 2010 from shut-in volumes that were brought online. Our third quarter operating costs averaged $0.52 per thousand cubic feet equivalent, down 12% from the third quarter of 2010, primarily due to lower long-term compensation expenses and decreased workover activity. In the Haynesville Shale, the Haynesville Shale performed exceptionally well during the quarter. Production averaged 524 million cubic feet equivalent per day, up about 70% from the third quarter of 2010. We've drilled 20 net wells in the third quarter for a total of 65 net wells in the first 3 quarters of the year, and we plan to drill a total of about 85 net wells by year end. We currently have 11 operated rigs running in the area, as well as an additional 9 rigs operated by our partners. Drilling and completion efficiencies continue to improve with our resource play hub development model, and infill wells are producing as expected. In the Credence area of the DeSoto Parish, drilling days averaged 32 days versus the 2010 average of 42 days. This is a 24% year-over-year improvement. Our experience in developing resource plays has taught us that longer horizontal lateral lengths brings increased initial production rates, higher expected ultimate recoveries and improved supply costs. To that end, we drilled 2 record length Haynesville horizontal wells in the Sabine area of East Texas during the quarter. Both wells were drilled with a horizontal length of about 7,500 feet and completion of the wells begins this quarter with up to 30 to 35 completion stages per lateral. We expect to achieve expected ultimate recoveries from these wells between 11 and 13 Bcf per well. And just a few weeks ago, we successfully drilled 2 record length horizontal wells in North Louisiana. The first lateral section was drilled to a length of 6,879 feet and one week later, we raised the bar by drilling a lateral section reaching 8,003 feet. If you'll recall, we obtained regulatory approval in Louisiana to drill extended length wells across a 3-section unit where previously lateral length was limited by the lease boundary to approximately 4,500 feet. We are currently drilling 2 additional long lateral wells, and we'll then have a total of 4 unit wells in Louisiana of approximately 7,000 feet in length, which are expected to be completed before the end of the year. We have several more applications under review in Louisiana, and we expect to receive the results of those applications in the upcoming months. Our Mid-Continent team continues to deliver when it comes to optimizing completion design and driving down cycle times. A year ago, we thought that pumping up to 80 completion stages per month was pushing the limits of our technical abilities. In the month of September, one of our completion crews pumped a total of 145 stages. The combined efforts of our field staff and our service providers have significantly accelerated the pace, as we are both advancing the design and execution of completions in the play. Our Haynesville dedicated fit-for-purpose completion crews have only been up and running for -- the most recent crew has only been up and running for 3 months, and already they have completed a total of 90 stimulation intervals in September, reaching this milestone much faster than we had expected. Our goal is to have this new crew execute an average of 140 stages per month by the end of the year, at about 1/3 of the time it took our previous crew to do that same feat. And our teams are well on their way to achieving this objective. Although it's still early days, we are very excited about the oil and liquids rich natural gas opportunities we are pursuing in the division. During the quarter, we captured additional acreage in the Tuscaloosa marine shale, bringing our total land position in this play to approximately 270,000 net acres. We completed an existing horizontal well in Emmett County as part of our joint venture agreement, and we are very encouraged by the results. The well had a 30-day initial production rate of 310 barrels per day in light oil from 5 effective completion stages. This well has been on production for about 125 days, and we forecasted expected ultimate recovery of 145,000 barrels of oil. We are currently drilling the first of 2 planned horizontal wells, targeting a 7,500-foot lateral length with 30 planned completion stages and expect to begin completion activities in November. In the Collingwood shale in Michigan, we drilled 2 horizontal wells in the southern liquids rich gas part of the play. The second horizontal well was drilled to a total measured depth of 16,900 feet with an effective horizontal length of 7,500 feet. Both wells are expected to be completed during the fourth quarter. Services are somewhat scarce in Michigan compared to other parts of the country, but we have contracted a completions crew and expect to have them arrive in Michigan later this month. Moving to Colorado. During the quarter, we drilled 5 horizontal Niobrara wells in the DJ Basin. The wells have an average lateral length of 4,250 feet and an average true vertical depth of 7,300 feet. Four of the wells have now been completed with an average of 17 stimulation stages and are on production. The fifth well is expected to be completed in early November and should be flowing by mid-November. We are currently evaluating production results, but the early data is encouraging. You should expect to see a higher level of activity in each of these plays in the first half of 2012, and it will continue to increase as we gather more information. We'll have more details on each play once we've completed our budget process. As we progress through the final months of the year, I'm extremely pleased with the operational execution and performance of the division as we remain on track to reach our targets for the year. I will now turn the call over to Sherri Brillon, who will discuss our overall financial performance for the quarter. Sherri?

Thanks, Jeff, and good morning. Encana's third quarter financial results continue to be strong and in line with guidance. Cash flow for the quarter was $1.2 billion or $1.57 per share diluted. Cash flow was up about 2% compared to the third quarter of 2010, primarily due to higher commodity prices and higher production volumes, partially offset by lower realized financial hedging gains. Year-to-date, cash flow totaled about $3.2 billion or $4.34 per share diluted. Compared to the third quarter of 2010, operating earnings were double at $171 million or $0.23 per share diluted. This increase was primarily due to higher average commodity prices, higher production volume and lower long-term compensation cost, partially offset by lower realized financial hedging gains. Year-to-date, operating earnings totaled $352 million or $0.48 per share diluted. For the quarter, Encana's hedge position contributed a realized after-tax gain of approximately $145 million or an additional $0.69 per thousand cubic feet to the average natural gas price. As of September 30, 2011, we had about 1.8 billion cubic feet per day or about 50% of expected October to December natural gas production hedged under price, fixed-price contract at an average NYMEX price of $5.76 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 about 500 million cubic feet per day of expected 2013 natural gas production at an average NYMEX price of $5.24 per thousand cubic feet. So we are well positioned for the rest of this year and through 2012. Having these hedges in place increases the certainty of our cash flow generation, helping to ensure stability for our capital programs and anticipated dividend payments. Since the beginning of 2006, Encana's commodity price hedging has resulted in about $7.9 billion of pretax cash flow in excess of what would have been generated had we not employed price hedging. Now turning to our cost for the quarter. Combined operating and administrative costs of $0.84 per thousand cubic feet equivalent were $0.12 lower year-over-year, mainly due to lower long-term incentive costs. On a year-to-date basis, combined operating and administrative costs were $1.08 per thousand cubic feet equivalent. We have maintained our 2011 guidance expectations for combined operating and administrative costs of $1.15 to $1.20 per thousand cubic feet equivalent. Under IFRS reporting, depreciation, depletion and amortization or DD&A was $2.63 per thousand cubic feet equivalent in the third quarter. As I've highlighted on previous conference calls, on a U.S. GAAP basis, the DD&A would have been approximately $1.70 per thousand cubic feet equivalent. On a U.S. GAAP basis, we estimate that our third quarter operating earnings would have been approximately $511 million after tax or about $0.69 per share diluted. We continue to assess the potential benefits of converting to U.S. GAAP as we believe that it will facilitate easier comparisons of our financial results to those of our U.S. peers. Tomorrow, we plan to post to our website additional supplemental information, which reconciles key components of Encana's third quarter financial results with U.S. GAAP financial results. Maintaining the strength and flexibility of Encana's balance sheet remains a top priority. Our debt-to-capitalization ratio at the end of the quarter was 34%, and our debt-to-adjusted EBITDA ratio was 2.1x on a trailing 12-month basis. Debt-to-debt adjusted cash flow, which excludes the volatility of unrealized gains and losses on risk management activities with other noncash items, was 1.9x on a trailing 12-month basis. At year end, we expect our debt metrics will land well below our internally managed maximum target levels as we book the proceeds from our announced divestitures of the Piceance midstream assets and the Cabin Gas Plant, which total approximately $800 million. These upcoming divestitures are disclosed as assets held for sale in Note 9 of our third quarter consolidated financial statements. These, along with other divestitures expected to close before year end, will be used to reduce debt and lower the associated ratios. In the interim, Encana does have a $500 million debt maturity on November 1, 2011. We expect to repay the maturing notes from cash balances and through our commercial paper program. I am pleased to note that Encana has recently renewed its Canadian committed revolving bank credit facility, and a U.S. subsidiary is in the process of renewing a U.S. credit facility. We renewed our Canadian facility at CAD $4 billion and are increasing the amount available under our U.S. facility from $565 million to $1 billion. Both facilities have accordion features, which allow the board to request additional capacity of CAD $500 million and $400 million, respectively. The maturity date for both facilities has been extended by 4 years to October 31, 2015, and this extension of these committed credit facilities further enhances our financial flexibility. As we head into the final months of 2011, Encana remains well positioned and poised to endure the current challenging economic conditions. I will now turn the call back to Randy.

Thank you, Sherri. Well, as you've heard this morning, Encana executed another solid quarter both operationally and financially, and we remain on track to meet our 2011 guidance. We've assembled an abundance of internally generated exploration and development opportunities, which we expect will continue to be economic even in the current natural gas market. We're very optimistic about the future and the upside of our company because of our incredible resource base and the low cost structures that our staff have achieved. Our strategy is simple and it remains unchanged. We're focused on unlocking the tremendous value that is unrecognized within our asset base by accelerating the pace of development of our assets and doing it at the lowest possible cost. This acceleration can be achieved by prudently deploying Encana's capital and by leveraging third-party capital through farm-outs and joint venture transactions. Responding to the reality of lower natural gas prices, we're dialing back our short-term internally funded growth to better align with our ability to generate cash flow. Over the longer term, we have a more bullish view of future natural gas prices in line with the future curves, and our resource play hub development initiatives will help to ensure that we capture greater margins in any natural gas price environment. In the next few years, we expect to significantly increase the proportion of liquids production in our portfolio and have increased our pace of exploration and delineation on many of our oil and natural gas liquid plays. Ultimately, this should enable us to diversify our portfolio and increase returns, while at the same time taking advantage of the expertise that we have developed, drilling and completing long-ridge horizontal wells in our natural gas resource plays. We have a well-established methodology for extracting value from all of our resource plays from our low-cost entry approach through our relentless focus on lowering cost structures. In the future, we will continue to do so both on our existing natural gas plays, as well as with any new oil or liquids-rich plays we develop. Encana has never been a company that sits still. It's exactly this proactive thinking that forms our strategy. Our decision to invest more capital in oil and liquids-rich opportunities is a function of allocating capital to projects that we believe have the potential to provide more attractive returns. We balance the full-cycle economics of investing in new opportunities against the go forward or half-cycle economics of investing in our current portfolio. And we take the portfolio approach investing in projects that are at various stages of their life cycle in a diversified range of geographic areas. To help ensure that we're financially well positioned during these uncertain times, we've undertaken a number of measures to improve and maintain a conservative balance sheet. In 2012, we're targeting a balanced budget through reducing our capital expenditures to be within our cash flow after dividends. We've advanced joint venture arrangements on many of our plays to help maintain momentum and capture value during this period of reduced capital expenditures. Thirdly, we are targeting our net divestiture proceeds of $1 billion to $2 billion in 2011, which will increase our financial flexibility as we enter 2012. Combined, we believe we've put in motion all of the measures we need to weather the current economic environment. We have a clear vision of the future, and we intend to capitalize on the opportunities that we see unfolding in front of us. Thank you very much for joining us today, and our team is now ready to take any questions you may have.

[Operator Instructions] Your first question comes from the line of Greg Pardy with RBC Capital Markets.

Just a couple of questions, Randy. I guess the first one is you mentioned that you're going to be adopting a conservative outlook for Henry Hub pricing next year. You guys are, I don't know, 4.5% or so in North American supply. What are you seeing from an industry cost standpoint? And that would be question one, and how does that -- how do you reflect that, I guess, in your pricing outlook? And the second question is just around the dividends. So we're getting questions from all quarters right now as to how we should be thinking about your dividend policy as you get into 2012 and '13.

Thank you, Greg, for the questions. I'm going to answer the dividend question first and then I'm going to turn it over to Renee Zemljak and she'll talk a little bit more about our natural gas outlooks and views. With regard to the dividend, we believe that our dividend policy is a very strong component of our overall shareholder return, and we believe that's an important part of creating discipline in our investment decision making. And we have no plans to change our dividend policy at this time. Sherri (sic) [Renee]?

Okay, Greg. This is Renee Zemljak. With regards to our view on natural gas prices, I'll go ahead and start off with our view on near-term prices. We do believe that the market is going to continue to be challenged with the surplus overhang that we have going into 2012. Looking at 2013, there are things that could happen like, maybe, redirection of a downward move on the gas-directed drilling rigs could cause some price uplift for 2013. But more importantly, it's really what our view is on our long-term prices, and the way that we look at our long-term prices is exactly what you had suggested. It's really on the marginal cost of the supply, and Encana does a very extensive study every year on what the resource potential is for North America. And in that study, we study the supply costs for over 154 different supply basins. And in our study, we believe that the marginal cost of supply is probably somewhere around $6. And we get to that view because we don't believe that the lower cost shale plays actually will be able to supply that demand that we have coming on into the future, hence, that means that we'll have to drill into the slightly higher cost plays in order to meet demand growth. So I would say that we believe longer term, our natural gas prices are closer to the $6 cost or $6 price, which is driven off of our long-term marginal cost of supply view.

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

So I'll just follow up on Greg's question and just maybe you can provide a little bit of a further insight into -- in your outlook for natural gas, is this going to be supply-driven or demand-driven? That's the change in sort of your longer term here, which side would drive the recovery more? That's the first part of my question.

Okay, this is Renee again. We believe that what's going to drive it more is really the demand side, and we're really optimistic about the demand initiatives that have been ongoing. I mean, Encana has been quite involved in trying to help create additional demand and growth in North America, which explains why we are actually in the Kitimat project. If you look at the number of LNG export projects that have been announced over the last year, it really is quite telling. I think there are somewhere between 10 to 15 projects actually that have been announced with 3 of them out of the Gulf Coast that really have a lot of momentum and regulatory support behind them. The Kitimat project itself is also well on track to be a great facility to go into service early 2016. So we do think that the longer-term prices are going to be more demand-driven than supply-driven.

Okay. And essentially, you will be export-driven off of North America is what you're saying?

Export-driven, as well as driven off of the coal to gas displacement. We're very optimistic about the regulatory things that are happening that will increase the natural gas demand as a result of power generation as well. And we have Eric Marsh here. He could probably provide a little bit more detail on that.

George, we, at Encana, we've worked really hard on transportation initiatives. We've actually opened 5 natural gas refueling stations, and we see about $1.5 billion has been spent this year across North America, working on those kind of initiatives. And I think, in general, you're going to see those begin to pick up a little bit of that demand.

Okay. And so, I guess, the one question along those lines is do you expect that some sort of government bargain would have to -- would this be completely commercially driven or there'll be some fiscal incentive to back this demand up here?

George, I don't think you're going to need the government incentive. If you really look at what's going on, it's really going on just by private business and public companies getting out and moving it forward. We estimate that there's probably around 75 natural gas stations have been built in North America this year. Lot of LNG opportunities to use LNG for both transportation and for the big equipment such as Caterpillars and especially even in drilling. So we have rigs running now on LNG. We have rigs running on compressed natural gas as well. A lot of the large manufacturing-type equipment can go ahead and use natural gas as well.

Okay. So just quickly, the second part of my question is obviously very strong cost performance, operating cost performance here. So just 2 things. First of all, wondering how much of your operating cost is fixed, how much is variable? And what we've seen this quarter both in Canada and the U.S. is that -- what we can take as the new normal.

Mike and Jeff will give some flavors to the operating cost mix within their areas.

; Yes, George, Mike Graham here with Canadian division. We have actually seen our operating costs have been pretty good in Encana that we did have a little bit of FX challenges, but we did see our power cost coming down, as well as we have been selling off over the last 8 years some of our higher operating cost properties, and we continue to do that. So operating cost performance in Canada have been very good over the last couple of years.

Jeff Wojahn with the U.S. division. George, when you look at operating cost, you have to keep in mind that there's direct operating cost and indirect operating cost. And what we've really seen during the quarter is a decrease in our indirect long-term incentive costs. That's what's driving performance right now. I can say that we have done a very strong job overall in our direct operating cost that by the nature of our unconventional resource plays, we tend to have stable and predictable operating cost going forward. And the guidance that we put out represents where we think we're going to be for the remainder of the year.

Your next question comes from the line of Bob Brackett with Bernstein Research.

Probably question for Jeff on some of those Niobrara wells in the DJ Basin. You said you've got 4 online and you're looking at production results. Can you give -- even say a 24-hour IP on some of those?

I could, but I would prefer not to at this point. I think it's fair to say that I will give you -- the issue for us right now is we do have some IP results to date. We're looking at the decline characteristics. We have a tight curve expectation the team has set relative to the length of the wells and the horizontal stages we put forward. And we're really interested in how the wells are going to perform over a longer term. The issue in the DJ and the Wattenberg Basin for us is really about longer-term performance and ultimately expected EUR. So next quarter. Give me a quarter, and I'll have a lot more fulsome data for you.

Fair enough. I'll try then on the Collingwood. You said you've drilled, but not yet completed these wells. Is there any core that you cut or at least looking at cuttings, where you've got fluorescence, anything indicative of oil and what it might be like?

Yes, we cut core in a number of wells, and we've done a fair amount of what I could categorize as science wells in the area. And we know the Utica-Collingwood section in Michigan is hydrocarbon bearing, and it's really about finding a commercial recipe to unlock the resource. So we're hopeful. We like what we see, but the proof will be really relative to the results of our horizontal program.

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

I had a couple of things. With respect to the sales of some of the midstream assets and the processing facilities in particular, can Mike and Jeff individually give us an idea as to the relation between the processing fees that you've negotiated for the supply you'll be providing to those facilities relative to the base level of such costs? I mean, I would imagine they're quite a bit higher.

Go ahead, Mike.

Yes, Mark. As you know, we've actually recently sold the Cabin Gas Plant, and we're also looking to sell the Cutbank Ridge facilities, in particular Steeprock and Hythe. And we're doing these in somewhere in the 10 to even higher than 10 to 12x EBITDA. So typically, we'll sell some in and around that 10% and invest it in somewhere around 20-plus percent, so very good economics for us to do things like that. Our operating cost will go up slightly. Our transportation cost will go up slightly. But overall, it's really quite negligible in the entirety of Encana. Jeff?

Sure, Mark. Jeff Wojahn. Got a couple of numbers for you. Related to the announced dispositions that we've provided this year, we estimate on a facility basis the charges for our assets will increase by $0.20 and on a U.S. division basis, it impacts us very minimally, as Mike said earlier, about $0.03 per Mcf net.

Okay. Mike, you talked about, I think, in conjunction with the CBM area, some third-party royalty oriented increases in liquids. Could you flush that out just a little bit? Is that a one-time thing? What is the origin of it? Give it some color.

Okay. That's probably a little easier question for me to answer, Mark. But yes, we do have a big, big fee position in Alberta, somewhere in the order of about 5 million net acres. And we have been ramping up activity in that. We've got a lot of people drilling on our fee lands where we get very attractive royalties anywhere from 20% to 30-plus percent royalty, if you will. Currently today, we're up about 1,500 barrels per day on our budget, and a lot of that is due to the royalty interest volume. So we have a lot people drilling us Viking wells in and around Hardisty. We have a lot of people drilling us wells in the Glauconite where we get attractive royalties. Again we have people drilling us Cardium wells and Lochend and also a big play in Southern Alberta, the Alberta Bakken or the Exshaw, some very exciting results. Some of the smaller companies actually had wells as much as 250 barrels per day and some of those are on Encana fee land. So it's something that we've been working hard at over the last few years, and we've really ramped up our royalty interest volumes. We probably have about 75 million cubic feet a day equivalent, about 5,000 of that which is oil. So look for that to increase. It's hard to really forecast increases out of that, but like I say we've done a lot with third parties and a lot with the juniors and we have a tremendous fee position and a lot of it is oil and natural gas prone. So we'll try and give you a bit more detail in that as we go forward.

In many cases, the economics for us are far superior by farming them out than by developing them ourselves. So we look forward to the tremendous success of our partners.

Mike, is there any seasonality that you could identify on your unit Canadian operating costs? There seems to be a pattern. First quarter high, second quarter a little lower, excuse me, third quarter a little lower than that and the fourth quarter jumps back up. Am I misreading it?

No. That's a tremendous observation, Mark. Typically, we have a lot of winter operations in Canada, and we'll go in and we'll replenish methanol, replenish our chemicals. A lot of these areas we only get to them in the wintertime. So you will see our Q1 operating costs and as well our Q4 operating costs a little bit higher than you would in the summer months, so for that exact reason. So that's a great observation.

Okay, and just one more to clarify, Mike. As those royalty volumes go up, arithmetically, your unit operating costs are going down.

Yes, that's right. Our unit operating costs are going down. And obviously, our netbacks are going up as well. If you look at our Clearwater business unit probably has some of the best netbacks in the company.

Your next question comes from the line of Brian Dutton with Credit Suisse. Brian C. Dutton - Crédit Suisse AG, Research Division: Sherri, I was wondering if you could give us a little more detail on the renegotiation of your credit facilities. Are they on the same terms or the terms changed with the newest extension?

Sure, Brian. Actually, we were quite pleased in getting our facilities renewed. There's certainly higher cost than what we had originally when we set them and acquired them 4 years ago. But that being said, we have about, I don't know, probably 20, 29, 27 banks involved. So we have a very large syndicate of banks. The maturity is 4 years. We have a good sort of fixed-loading component to the pricing on our drawn pricing. It's sort of DAs plus 125 basis points, and then we had our undrawn pricing is 25 basis points. So I think that we've been able to negotiate pretty good terms on our arrangements. We have closed the Canadian facility, and we're continuing to work on the U.S. facility. I think we're supposed have that closed either late today or tomorrow. Brian C. Dutton - Crédit Suisse AG, Research Division: Further on the balance sheet I guess you have some plans here to raise a lot of cash but at the same time, you have some big debt maturities coming out in 2012, '13 and '14. Do you plan to use the cash to pay off those debt maturities or do you plan to reissue those debt maturities and simply keep cash on the balance sheet?

Actually, we're probably going to, for the maturity coming up, we'll use our cash available, as well as our credit facility and our commercial paper to basically look after the first maturity. And with the disposition proceeds coming in over the next couple of months, we'll probably have sufficient cash in order to address our March maturity. We continue to monitor the bond market and look at opportunities there. And if the right opportunity arises, we'll look at doing something on that side. Brian C. Dutton - Crédit Suisse AG, Research Division: So if by chance you sign a big JV agreement, get a big slug of cash coming in the door as an upfront payment, would you simply then just keep that cash sitting on the balance sheet?

I'm not sure. I'd like to have that flexibility to basically make the assessment of whether we want to basically utilize it against our debt or if we've got an opportunity that we think that we'd like to fund. So I'm trying to be flexible as to how the proceeds are going to be managed at this stage of the game.

But Brian, yes, I mean, you're right on target with respect to the kind of discussions we're having within the financial group of the company right now.

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

As you look to balance CapEx with cash flow after dividend next year and simultaneously dedicate more capital to your liquids exploration opportunities, can you just talk to what that means for your natural gas-focused rig count and the trajectory of your U.S. and Canadian gas production? You kind of highlighted, I think, your expectations for what this pricing environment would do for the market broadly. I'm interested in your thoughts especially as you take a bit more of a conservative capital strategy.

The kinds of things that we look at when we are trying to decide on the exact size of the capital program directed to natural gas elements of the company for next year will include the long-term rig and frac crew commitments that we've got. We'll look at the processing commitments that we have in areas, and we'll look at the maturity of the plays and where we think we need to spend money to further understand them versus those that we well understood and can manage and allow them to be underinvested or decline. Having said all that, we've looked at a range of potential outcomes that we could have and one of the flexibilities, of course, that we have for next year is in terms of our overall production of the company is Deep Panuke is likely going to be coming on late in the first quarter. And when it comes on, it provides about, for the year, we're estimating around 200 million cubic feet per day. But it will also have the capability of growing up to about 300 million cubic feet per day instantaneously. So that in itself gives us some flexibility. So the long answer to the question of what our potential growth rate might be overall is in the order of about plus or minus 5%, considering that we will be taking -- we know we'll be taking and redirecting some of our money to the oil and liquid-rich plays. That is a number that can kind of use as a guideline right now, and it's subject to change. We'll probably get our capital budgets and the rest of our budget projections done at our year-end conference call scheduled in February. And at that time, we'll also have a little bit more information on some of those early life liquids rich and oil plays, and that will help us understand how much we want to guide in that direction. And it also gives a few more months to look and see how the natural gas market is unfolding.

Great. That's helpful. And a follow-up question to Jeff in the Tuscaloosa marine shale, the well that you mentioned earlier in your comment. What was the cost for that well and what do you expect a 30-stage, 7,500-foot lateral well to cost?

Sure. The well I quoted was a well that -- are you talking about the well that we're currently drilling -- is that what you're...

Well, that was one of them, right, and then the past well that you mentioned earlier.

The past well is one we inherited through a joint venture partnership. So I don't have the information on that. The well that we're drilling today is not really going to be indicative of our long-term development costs. So it's very difficult to peg that particular wells, but I think early days the wells will be in the $10 million range. And then as we are able to apply scale to them, we'll come down to a lower number.

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

Just some quick ones for me. With the new super duper Haynesville well, what kind of an IP rate are you looking for, for those extended ridge wells?

Eric, do you want to answer it?

Sure. We use slowback -- or starting to use slowback almost exclusively. So typical IPs in the past have been in the $20 million range. We'll probably be a little bit less than that, about $15 million to $18 million. What that really does is it extends that $18 million at higher rate for a longer period of time by managing the pressure. So overall, both the IPs will be somewhat similar to what you've seen in the past.

But generally, you're going for recovery, that's fine.

Yes. And as far as recoveries go, the recoveries improve materially from -- at 8 Bcf kind of range up into the 13 Bcf range.

Okay. Great. In terms of other well costs, what will the completed well costs be for the Collingwood and also the Duvernay?

I can jump in on that. On the Collingwood, it's early, but depending on the length and the stages, it will be in the $6 million to $8 million range.

John, we are purely drilling. We just had an intermediate casing actually in our first Duvernay horizontal well. We think, long term, we're going to get the cost in and around that $12 million per well. These are relatively deep in the order of 3,500-plus meters, but similar to the Horn River. It's essentially the same formation just on the south side of the Peace River Arch. So we're very, very familiar with the Horn River. We've drilled a lot of wells there. So hopefully, we can get them down in and around that $12 million range. And with the liquids we forecast, we're thinking anywhere from 100 to 200 barrels a million. We think that's going to be a very economic project for us.

Great. Last one for me is, I guess, more of a philosophical one in terms of the balance sheet. You're growing, and you're saying you could grow 5% next year. But your stock's basically below 2008 lows. Instead of going for volume growth, why not shrink the denominator and execute your Normal Course Issuer Bid? Why not buy in stock?

That's part of the balancing act, again, that...

We haven't done it in a long time, Randy.

We haven't done it in a long time, you're right. We'll take that into consideration as we're putting everything else together. We will likely be reissuing our Normal Course Issuer Bid.

Yes, we will be renewing the Normal Course Issuer Bid for up to 5% of buyback.

With regard to proceeds from transactions such as those that we're selling some of the producing assets and where we're bringing in potential cash related to the JVs, we're kind of expecting that we're going to have more cash available next year that is unallocated in a lot of ways, and so that would be one of the things we might consider. And we are, as I said earlier, we are also considering slowing down our natural gas growth in this environment, and so that could free up additional cash beyond which I've talked about.

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

A question for Randy. Shell has announced that they bought some property at Kitimat where they might put an LNG export terminal. I was just wondering how you greet that news as a company that's a competitor on that front, but then also a company that's producing a lot of dry gas that could go there?

I think we broadly stated that we would welcome as many LNG export facilities as can be constructed in North America because of the imbalance that currently exists between the ability to import natural gas with, really at this point in time, no ability to export natural gas. And so in that respect, I think it's a great announcement, and we look forward to hearing other ones as well. There's plenty of room for additional projects on the West Coast. So we're supporters.

Okay. Great. And I also wanted to ask, are things progressing as expected on the joint venture? I think you said that there -- you expected an announcement by year end. Where is that at?

I'm going to let Mike McAllister who's more deeply involved in the transaction to give you an update.

Dan, yes, it's Mike McAllister here. So we're looking at sort of a traditional joint venture, traditional cash and carry for 40% to 50% of our undeveloped lands in British Columbia in the Cutbank Ridge resource play. And we expect to be in a position to evaluate our first-round bids here by the end of November and so basically take it from there.

Okay. So you had launched bids or...

We're not at that point in the process yet. Lots of strong interest though, I'd say..

Your next question comes from the line of Jeff Lewis [ph].

Just had 3 questions about Kitimat LNG. First off, what kind of conversations, if any, have you had with KOGAS following the NEB approval of the Kitimat LNG project?

I'll go ahead and take that, Jeff. This is Renee Zemljak. We're in discussions with multiple parties, so I don't think we're really at liberty to discuss who we're in advanced discussions with at this point in time,

Okay. And what percentage of that 1.4 Bcf will come from Encana properties or is there any way you can break that down?

Currently, we're a 30% owner. So you would assume that 30% of that capacity will be filled from Encana supply.

Okay. And are there any properties that Encana properties that would contribute more to those export volumes than others?

Not really. It just gives Encana the ability to develop all of its properties. The way that the pipeline grid works in Western Canada is the supply really gets all commingled. So we'll either bring Encana supply directly in or buy gas from the pools to bring to the facility, but it will allow Encana to continue to develop all of our plays.

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

Thank you, everyone, for joining us today to review Encana's third quarter results. I'd like to take this opportunity to just point out that due to conflicts with the third quarter reporting by other companies, we will be moving our upcoming Haynesville Conference Call to Monday, November 7. We will be sending out a notice to this effect and a news release prior to the date with call-in information. That's all for today. Our conference call is now complete.