Ovintiv Inc. (OVV) Q4 2011 Earnings Report, Transcript and Summary

Ryder McRitchie - Vice President of Investor Relations Randall K. Eresman - Chief Executive officer, President and Director Michael G. McAllister - Executive Vice-President and Senior Vice-President of Canadian Division Jeff E. Wojahn - Executive Vice President and President of USA Division Sherri A. Brillon - Chief Financial officer and Executive Vice-President Eric D. Marsh - Executive Vice-President and Interim President - Canadian Division Renee E. Zemljak - Executive Vice President of Midstream Marketing & Fundamentals

Andrew Potter - CIBC World Markets Inc., Research Division Brian C. Dutton - Crédit Suisse AG, Research Division Greg M. Pardy - RBC Capital Markets, LLC, Research Division Mark Polak - Scotiabank Global Banking and Market, Research Division Michael P. Dunn - FirstEnergy Capital Corp. George Toriola - UBS Investment Bank, Research Division Philip R. Skolnick - Canaccord Genuity, Research Division Mark Gilman - The Benchmark Company, LLC, Research Division Craig Shere - Tuohy Brothers Investment Research, Inc. Robert Brackett Brian Singer - Goldman Sachs Group Inc., Research Division Robert S. Morris - Citigroup Inc, Research Division Geoff Bird Brett Bundale Scott Haggett Pat Roche Jeremy van Loon

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Fourth Quarter 2011 Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Encana Corporation. I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations. Please go ahead, Mr. McRitchie.

Thank you, operator, and welcome, everyone, to our discussion of EnCana's fourth quarter and year-end results for 2011. 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 operational and strategic decisions or cash flow. Reconciliations between previous GAAP and IFRS financial information can be found in the consolidated financial statements available on the company's website at www.encana.com. Also, for your reference, 2011 reserves and economic contingent resources for each of our key resource plays, as well as our 2012 corporate guidance, have been posted to our website. Randy Eresman will start off this morning with the highlights from our 2011 operating results and year-end reserves position, as well as an overview of our 2012 capital program. Mike McAllister, Executive Vice President and acting President of our Canadian Division; and Jeff Wojahn, Executive Vice President and President of our USA division, will then touch on some highlights from each of their areas before turning the call over to Sherri Brillon, EnCana's Chief Financial Officer, to discuss EnCana's 2011 financial performance. Eric Marsh, Executive Vice President and Senior Vice President of the USA division, will then speak to some of the initiatives that Encana is pursuing to grow the demand for North American natural gas. 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. Lots to talk about this morning. I'm very pleased to be in a position to speak not only about our 2011 results and our 2012 budget, but also about the Cutbank Ridge Partnership agreement we've reached with Mitsubishi. The agreement we announced this morning with Mitsubishi Corporation to jointly develop our B.C. Cutbank Ridge undeveloped lands represents a major step forward in our plans to unlock the tremendous value contained in our asset base. Upon completion of the deal, which we expect to close later this month, Mitsubishi would invest CAD 2.9 billion for a 40% interest in the partnership, which holds about 409,000 net acres of undeveloped Montney natural gas lands in British Columbia. Encana will own 60% and Mitsubishi will own 40% of the partnership. Mitsubishi will pay approximately CAD 1.45 billion on closing and it will invest another CAD 1.45 billion in addition to its 40% of the partnership's future capital investment for a commitment period which is expected to be about 5 years, thereby reducing Encana's capital funding commitments to 30% of the total expected capital investment over that period. The Cutbank Ridge Partnership is a great example of Encana's track record of creating value from grassroots. They identify high-quality, early-life resources, assemble large contiguous land positions, leverage technological advancements and apply innovative practices to develop these plays at some of the lowest costs in the industry. The result of these efforts is a deep portfolio of high-quality, low-cost assets which can be profitably developed for several decades. We first began assembling our sizable position in Cutbank Ridge over a decade ago, acquiring the majority of our land at an average cost of about $700 per acre. Our early-mover approach not only allowed us to acquire a low-cost position, but also enabled us to study the basin long before others and build our land position predominantly in the core of the resource. Since then, we have achieved a steady progression of improving cost structures by leveraging technology and continually optimizing all facets of the development process. Today, Cutbank Ridge is one of the lowest-cost assets in our portfolio and our current production which is not included in this partnership, is nearly 600 million cubic feet per day. This transaction sets the foundation for accelerating the long-term development and value recognition of our undeveloped lands in the British Columbia portion of Cutbank Ridge, a major natural gas field capable of delivering a long-term affordable supply of natural gas to domestic and future export markets. We believe that the partnership we announced this morning with Mitsubishi crystallizes the value we identified at Cutbank Ridge over a decade ago, and further validates our strategy of building value from the ground up. The $2.9 billion investment by Mitsubishi reflects the value of a well-delineated world-class resource play that is being developed in a highly efficient manner. This partnership provides an excellent analogue for what we expect to achieve in several other plays throughout our portfolio. We continue to advance potential joint ventures in a number of other areas, both in Canada and in the United States. In a normal price environment, this transaction would've accelerated Encana's overall pace of development as a result of the increased capital spending profile on these assets. However, in this lower natural gas price environment, we plan to more than offset the transaction’s near-term impact to North American natural gas production oversupply by reducing spending and production across our entire natural gas portfolio. I'll talk more about this in a minute. I'm very proud of EnCana's strong operational performance during a year that was very difficult for natural gas producers. Throughout 2011, natural gas prices remain depressed, but Encana stayed true to our history of meeting our commitments. We delivered excellent operational results despite the low gas price and many cost and operational challenges reported by other operators. We made several advancements in our resource play hub development model with many of our resource plays now trending towards sub-$3 per MCF supply costs. Our low-cost structures were major factors in our ability to deliver solid cash flow and operating earnings in this low natural gas price environment. At a company-wide level, we met our targets with respect to total production, cash flow and capital spending, while our operating costs and administrative expenses came in lower than our guidance. I believe these results underscore the quality of our asset base and the strength of our teams in delivering low-cost production. Our 2011 natural gas production of approximately 3.3 billion cubic feet per day was up 5% from 2010 and our oil and natural gas liquid production of about 24,000 barrels per day was also up 5% compared to 2010 volumes. On average, our natural gas production has a Btu content of about 1,060, which has provided a minor uplift to our average annualized price. Another area where we saw strong execution in 2011 was from our asset divestitures. We're continuously looking for opportunities to hybrid our portfolio by divesting assets that no longer fit with our future development plans or are more highly valued by others. In 2011, we received about $1.6 billion in net divestitures proceeds and another $1 billion was received earlier this year from divestitures announced last year. These proceeds, along with the $1.45 billion from Mitsubishi's initial investment, will provide us with greater financial flexibility through 2012 and as we look ahead to 2013. Another key achievement during the year was the continued assembly of several large low-cost positions in what we believe will be a significant portion of our portfolio of oil and liquids-rich resources. We currently hold over 2.5 million net acres of land which we believe is prospective for oil or natural gas liquids, some from plays you've heard us talk about before, and some from plays we're speaking about publicly for the first time today. You'll hear more about these opportunities from Mike McAllister and Jeff Wojahn in a minute. But I'd like to convey just how excited we are about the potential impact these plays could have on our commodity mix as we transition to a more balanced portfolio. Now to year end reserves. Encana’s proved reserves totaled 14.2 trillion cubic feet equivalent at the end of 2011, down 1% compared to year-end 2010. This was achieved in spite of lower forecast pricing assumptions used to evaluate the reserves and a divestiture of over 1 Tcfe of proved reserves. Our proved reserve additions of 2.3 Tcfe before acquisitions and divestitures replaced 180% of our production. Our additions include about 54 million barrels of proved oil and natural gas liquids in 2011, resulting in proved liquid reserves of 133 million barrels, a net increase of 43% from the end of 2010. Our proved Reserve Life Index is now 11 years. Proved undeveloped reserves or PUDs account for 48% of total proved reserves and are scheduled to be converted to proved developed reserves within the next 5 years. The average future development cost associated with our PUDs is approximately $1.94 per thousand cubic feet equivalent. With respect to economic contingent resources, our 2011 1C or low estimate economic contingent resources, are estimated at about 25 trillion cubic feet equivalent, a 25% increase over 2010. The low estimate is the most conservative category and carries with the greatest degree of confidence, 90%, that these resources will be recovered. All of our reserves and contingent resources continue to be 100% externally evaluated by independent qualified reserve evaluators, not just reviewed or audited. As we look to 2012, it's abundantly clear that continued reduction in natural gas drilling activity will be required to restore market balance. We continue to believe that the long-term future for natural gas remains promising. However, until we see signs of a sustainable recovery in prices, we will be reducing our pace of natural gas development and restricting production from some of our natural gas wells to preserve value. Our 2012 budget has 3 primary objectives: first, it's designed to live within projected cash flow after dividends; second, to minimize capital investments in dry gas plays; and third, to aggressively evaluate our new prospective liquids plays. We're projecting 2012 cash flow of approximately $3.5 billion, which includes our strong natural gas head position, growing oil and natural gas liquids production, as well as a reduction in natural gas production. Our planned capital program will be $2.9 billion and reflects a reduction in spending of about 37% compared to 2011. Approximately $1.5 billion or more than 55% of our projected 2012 upstream capital is expected to be directed towards development exploration and delineation drilling for oil and liquids-rich natural gas. This includes about $400 million towards the drilling of about 40 assessment wells by midyear to further delineate plays such as the Tuscaloosa marine shale, the Duvernay Shale, the DJ Niobrara, the San Juan Niobrara, the Utica Collingwood shale, the Piceance Niobrara and Mancos, the Eaglebine and the Mississippian line. And based on the success of these potential liquids plays, we may further increase our liquid spend in the latter half of the year. Reduced capital investments in our dry natural gas programs is expected to lower natural gas production to about 3.1 billion cubic feet per day after royalties, a decrease of about 250 million cubic feet per day from 2011 annualized production volumes. In addition, we're immediately taking action to restrict or shut in an additional 250 million cubic feet per day of production, half the royalties from existing well bores, largely in areas subject to higher decline rates. Our teams are actively working to decide where and how to accomplish this. The duration of voluntary reductions will be subject a number of factors, including a recovery in prices, and, therefore, it is uncertain at this time. The combined total natural gas volume reduction would remove about 600 million cubic feet per day from the market when royalty volumes are also taken into consideration. Most of the planned $1.2 billion of upstream investments in dry natural gas is directed to completing work on previously initiated drilling programs and to the execution of drilling programs with our joint venture partners, which are often attractively leveraged by our partners’ incremental funding arrangements, meaning investment is largely directed towards preserving substantial value already identified by drilling success. These investments preserve substantial value by offering attractive future growth opportunities when more favorable market conditions warrant. Overall, in 2012, we plan to live within our means while we preserve the value of our immense natural gas resource base and advanced evaluation of our liquids opportunities. As the year progresses, we'll have greater clarity on the success and timing of other dispositions and joint venture initiatives, as well as progress made on our liquids play evaluations. We'll continue to assess the near-term uncertainty in the economic environment, gauge the plans and activities of our partners and peers and monitor key signposts related to commodity price drivers. Guided by these considerations and the success of our current initiatives, we will re-evaluate our plans and make necessary adjustments in the second half of 2012. I'll now turn the call over to Mike McAllister, acting President of the Canadian Division, who will provide us with a recap of the Canadian division's 2011 results, as well as an overview of our 2012 plans in the Canadian division.

Thank you, Randy, and good morning, everyone. 2011 marked another year of impressive operational performance for the Canadian Division. Natural gas production for the year was approximately 1.5 billion cubic feet per day and oil and natural gas production averaged 14,500 barrels per day. Both natural gas liquids volumes were up 10% compared -- both natural gas and liquids volumes were up both about 10% compared to 2010 production levels as a result of successful drilling programs in our key resource plays. Capital investment in Canada totaled just over $2 billion. Acquisitions for the year were about $410 million and divestitures came in at approximately $350 million. As Randy mentioned, we are very excited about the partnership agreement we've entered into with Mitsubishi Corporation to develop our British Columbia North Cutbank Ridge undeveloped natural gas lands. Mitsubishi is a world-class partner and we look forward to working with them. In addition to the Montney, the partnership assets also contained land and production potential from the Cadomin and Doig formations. The undeveloped land contains estimated natural gas initially in place of about 130 trillion cubic feet. We see a tremendous amount of potential in these assets, and to be clear, this transaction does not include any of EnCana's current production, processing plants, gathering systems or Alberta landholdings. For the next couple of years, the partnership planned capital investment and partnership assets will ramp up modestly and incrementally. It is not our intention to accelerate natural gas production into an already oversupplied market. Our focus will be to be largely on developing the productive capacity and processing infrastructure of the land base. We expect that the production profile of the assets will align well with the expected start up of planned West Coast LNG export facilities. Under the agreement with Mitsubishi, Encana will be managing partner of the partnership. The transaction has received advanced ruling certificate from Canada's competition bureau and subject to customary closing conditions, is expected to close by the end of February. With respect our capital program, the prolonged weakness in natural gas prices has mandated a 2012 capital program, which focuses predominantly on the development of plays that have the potential to produce meaningful volumes of oil and NGLs. So while we are very pleased with the 2011 performance of the Canadian division key resource plays, we have chosen to cut back spending in our dry gas key resource plays, namely our coalbed methane play and Greater Sierra, which includes the Horn River and Jean Marie plays. In Greater Sierra, we are limiting the development funding to the Horn River and to capital focused on operations associated with KOGAS farm-out in Kiwigana, as well as some minimal contractual spending. Mature Jean Marie play, which is dry gas, will not receive any development funding this year. Similarly, our coalbed methane resource play will see a very limited -- will receive very limited development funding in 2012. We halted our drilling program in January, and in addition, invested play -- in the play will consist only of completions of previously drilled wells for potential joint venture funding. We believe that limiting funding in these dry gas plays is the prudent course of action to preserve the value of these assets until the commodity price recovers. Additionally, first gas at our deep fitted project located offshore Nova Scotia has been delayed until later this year. We continue to work with the project's third-party contractor to complete the final stages of preparation for startup. The project is expected to come on midyear at a rate exceeding 200 million cubic feet per day from 4 wells. So the bulk of our 2012 planned spending in the capital -- in the Canadian division is allocated to our existing and prospective liquids-rich assets where we are planning an ambitious development program, tempered by existing infrastructure limitations and our desire to manage inflationary pressures on service costs. Our Cutbank Ridge and Big Horn assets are currently producing meaningful volumes in natural gas liquids with average liquids content between 50 to 90 barrels per million cubic feet. At Cutbank Ridge, through 2012 -- in 2012, we plan to spend $500 million, drill about 60 wells and achieve an annualized liquids production of about 3,000 barrels per day. At Big Horn, we expect to spend approximately $450 million, drill 55 wells and reach liquids production target by year end of 9,500 barrels per day. Additionally, we are planning to accelerate our pace of evaluation of the Duvernay Shale, where we currently hold 375,000 net acres. In 2011, we drilled 2 horizontal wells and 1 vertical well into the play. The vertical and 1 of the horizontal wells are located in the north portion of the play in the Kaybob area, with the other horizontal well located in South, in the Williston Green area. In addition to those first 2 horizontal wells, we plan to execute a 5-well exploration program in the first half of 2012. While we do not expect to provide an update on drilling results until midyear, I can tell you that we are very encouraged by what we have seen so far. Recent industry reported results support our observations of condensate yields in the 75 to 300 barrels per million cubic feet range. Our 11 of 8 vertical well in Kaybob was flow tested last year over 3 months with liquid yields in the upper end of that range and the total production matches our horizontal type curve expectations on a per stated basis. At this point, we're not prepared to talk specifically about our data in the Williston Green area of the play, other than to say that we see consistent and positive liquid yields out there as well. The second component of our liquids growth initiative in the Canadian division is the expansion of NGL extraction from Deep Basin. Last year, we negotiated supply agreements that will see midstream processors make substantial investments in 3 Alberta natural gas plants to increase liquids extraction from our natural gas production. The first expansion at Musreau plant is on stream with about 5,000 barrels per day of additional NGL extraction capacity. We expect to grow our incremental NGL production from the Deep Basin by about 55,000 barrels per day by 2015. With that, I will now turn the call over to Jeff Wojahn, who will discuss the 2011 performance of the USA division, as well as their plans for 2012.

Thank you, Mike, and good morning. I'm extremely pleased with the performance of the USA division in 2011. Our teams rose to the challenge and delivered results reflective of our leading operational capability. Capital investment in the division totaled about $2.4 billion. Total acquisitions came in at approximately $105 million and our divestiture program brought in proceeds totaling $1.7 billion. The assets divested include the Fort Lupton natural gas processing plant, our South Piceance natural gas gathering assets and our Barnett Shale producing assets. Looking ahead to 2012, we have designed this year’s capital program with the goals of preserving the value of our dry gas assets and accelerating the evaluation of our many potential oil and liquids-rich gas assets. We have several exciting new oil and liquids opportunities in our portfolio where we can utilize the same skills, technologies and execution methodologies that have worked so far -- so well for us in developing to dry natural gas assets. Many of those assets will remain as key holdings in our portfolio over the long term. But given the current weakness in natural gas prices, we have chosen to significantly limit our spending in these plays. At Jonah Field in Wyoming, our activity levels will be determined by the amount of third-party capital we deploy and could range from 1 to 4 drilling rigs, including 1 rig dedicated to the Northwest natural joint venture. With this well-defined drilling inventory, stable, predictable production profile and a lower risk nature of this asset, we see great potential for significant additional joint venture interest in this play. From the Piceance basin in Colorado, our capital program is driven almost inclusively by our commitments to existing joint ventures in the evaluation of our position in the liquids-rich portions of the Niobrara and Mancos formations. The joint venture programs we are funding total of about $130 million in capital commitments from Encana. Since these projects also employ carry capital from our partners, the economics remain robust. Our 2012 capital program in the Haynesville shale reflects a reduction in spending of almost 60% compared to last year. EnCana's operated drilling program is expected to be complete by the end of the first quarter, and remaining 2012 activity will be limited to that conducted by our partners in the play. Our operated program is designed to carry our commercial scale testing of our long lateral drilling program and our latest completion designs. While it may not be possible to retain all of the land associated with 2012 land expiries, the impact to the overall resource capture will not be significant. The reduction in activity will provide an opportunity to position the play for sub-$3 per MCF supply cost moving forward. During our activity break, we expect to confirm the optimal future well spacing and completion designs for our various pilots and we will continue to work with the state of Louisiana to facilitate future development that will permit the drilling of 7,500-foot to 10,000-foot lateral wells. In the Tuscaloosa marine shale, where Encana currently controls about 290,000 net acres, we recently completed 2 wells. The first well, which I mentioned during our third quarter conference call, was a completion of a well drilled by a previous operator and its production averaged 330 barrels of oil per day in its first month. The second well which was drilled and completed by Encana, saw production averaging about 700 barrels per day from 17 completed stages in the first month. We plan to operate 3 rigs in the Tuscaloosa throughout the spring and we plan to drill up to 6 wells by midyear. Also worth noting is that this play produces Louisiana light sweet crude which trades at a premium to WTI pricing. On our 48,000 net acres in the DJ Basin, Wattenberg Field of Colorado, Encana has drilled 5 liquids-rich horizontal wells in the Niobrara formation, each delivering initial liquids production of between 260 and 540 barrels per day, plus associated natural gas liquids of 100 to 200 barrels per day during their first month of production. We plan to drill a total of at least 10 additional wells during the first half of the year. We have identified nearly 200 well locations on our existing acreage. In the Utica Collingwood shale in Michigan, where we hold about 430,000 net acres, we recently completed drilling of 2 horizontal wells. Although we previously referred to this play as simply the Collingwood, I must note that we are also targeting the Utica and Collingwood formations jointly, together. Two recent wells are now in production at average first 7-day sales volumes of 6.5 million and 3.1 million cubic feet per day. If processed through NGL extraction facilities, these wells would yield NGL volumes of approximately 90 barrels per million cubic feet, with small amounts of lease condensate. During 2012, we are also evaluating plans to further delineate our lands and further commercially demonstrate this resource. More information on our future plans for this play will be available as we gather more production data, but I can tell you that we are very encouraged by the results that we've seen so far in this play. I'd like to take a moment now to tell you about a few other promising early life plays that we highlighted in the news release, which we believe are prospective for oil and liquids-rich natural gas. In the Piceance basin, we control about 240,000 net acreage in the liquids-rich window of the Niobrara and Mancos formations. In 2012, we plan to drill 6 horizontal wells to test the prospectivity of this area. In the Eaglebine formation or area of -- which overlies some of our East Texas acreage, Encana controls over 45,000 net acres. We've drilled and completed one well in the play which produced an average initial 30-day production rate of 230 barrels per day of oil. We recently finished drilling a second well and completions in that well are currently underway. We plan to drill a total of 6 wells in the play during the first half of the year. In the San Juan basin of New Mexico, Encana controls over 130,000 net acres. We are currently drilling the second of a 5-well exploration program targeting oil and natural gas liquids-rich from the Gallup formation. We expect to be in a position to discuss those drilling results by midyear. Additionally, we control over 140,000 net acres in the Mississippi Lime play in Oklahoma and Kansas, and we have an ongoing leasing program with a goal to lease a total of 250,000 acres. This is currently one of the most active plays in the industry, with about 50 rigs currently operating. This year, we plan to drill about 6 to 8 wells early in this first half of the year to understand the prospectivity of this play. Overall, in a relatively short period of time, our teams have assembled a tremendous portfolio of potential liquids-rich opportunities across the United States, totaling over 1.3 million net acres. As we progress through 2012, I hope to have more information to share with you on the advancements we've made in unlocking the commercial potential on many of these promising liquids plays. I'll now turn the call over to Encana's Chief Financial Officer, Sherri Brillon, who will discuss our financial performance for the year.

Thanks, Jeff, and good morning. During 2011, we were able to execute a number of initiatives that strengthened our financial position. First, we completed a divestiture program with proceeds net of acquisitions totaling approximately $1.6 billion for the year. Second, we renewed the committed revolving bank facility for Encana at our U.S. subsidiary. The Canadian facility was renewed for CAD 4 billion and the U.S. facility was renewed for $1 billion. The maturity date for both facilities has been extended to October 31, 2015. And third, we completed a $1 billion debt offering at very attractive rates. The successful execution of these initiatives, combined with Mitsubishi's CAD 1.45 billion initial investment, provides us with greater financial flexibility, both in 2012 and as we look ahead to 2013. Let's turn now to our 2011 financial performance. In 2011, Encana achieved cash flow of $4.2 billion or $5.66 per share on a diluted basis, which represents a 5% decrease on a per-share basis year-over-year. This was accompanied by operating earnings of $398 million or $0.54 per share on a diluted basis, compared to 2010 operating earnings of $0.81 per share diluted. The lower comparative results in both cash flow and operating earnings generally reflect the combination of lower natural gas prices, lower realized financial hedging gains and higher transportation expense. These factors were partially offset by higher production volumes and higher liquids prices. Encana's net earnings for the year were $128 million compared to about $1.2 billion in 2010. Net earnings were impacted by a noncash asset impairment of $854 million, after-tax compared with $371 million after-tax in 2010. Triggered by lower forecasted natural gas prices and a change in future development plans, these impairments are noncash items which do not impact operating earnings or cash flow. The magnitude of the impact, which these items have on their earnings, reinforces our belief that operating earnings are a better comparative measure of our performance between periods because they remove the variability associated with some nonrecurring and noncash items. Since the beginning of 2006, EnCana's commodity price hedging has resulted in about $8.3 billion of pretax cash flow in excess of what it would have generated had we not employed price hedging. For the year, EnCana's hedge position contributed unrealized before tax gain of approximately $948 million or an additional $0.79 per thousand cubic feet, the average natural gas price. As of December 31, 2011, we had about 2 billion cubic feet per day, or about 65% of our expected 2012 natural gas production hedged under fixed price contracts at an average NYMEX price of $5.80 per thousand cubic feet. Additionally, Encana has hedged approximately 505 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 the year, but we recognize the price exposure we have in 2013. And as a result, we are accumulating cash from the announced transactions to fortify our balance sheet heading into 2013. On the cost side, operating costs are $0.81 per thousand cubic feet equivalent and administration costs were $0.27 per thousand cubic feet equivalent. On a combined basis, these items came in about 6% below the low-end of our 2011 guidance. Under IFRS reporting, 2011 depreciation, depletion and amortization, or DD&A, was $3.4 billion or $2.62 per thousand cubic feet equivalent, compared to $3.3 billion or $2.66 per thousand cubic feet equivalent in 2010. As I've highlighted on previous conference calls on a U.S. GAAP basis, the DD&A would've been approximately $1.73 per thousand cubic feet equivalent. On a U.S. GAAP basis, we estimate that our 2011 operating earnings would've been approximately $1.2 billion after-tax or about $1.62 per share diluted. As per our December 8 news release, Encana has adopted U.S. GAAP for 2012 financial reporting. We believe that U.S. GAAP will facilitate easier comparisons of our financial results to those of our U.S. peers. Next week, we plan to post on our website additional supplemental information which reconciles key components of EnCana's fourth quarter and 2011 year-end financial results with U.S. GAAP financial results. We are focused on maintaining investment grade credit ratings and we monitor a variety of financial metrics in managing our capital structure. We saw quarter-over-quarter improvement in our debt metrics at year end, with the receipt of proceeds from our successful 2011 divestiture program. Our debt-to-debt adjusted cash flow, which excludes the volatility of noncash items, was 1.8x on a trailing 12-month basis. As Randy mentioned, Encana is well positioned financially for 2012. We have developed a conservative investment plan that will help us to preserve our financial strength during this time of continued low gas prices. With cash and cash equivalents of about $730 million at year-end 2011, about $1 billion of divestiture proceeds received so far in the first quarter of 2012, the CAD 1.45 billion from the impending transaction with Mitsubishi, $4.9 billion of unused committed revolving bank credit facilities, investment grade credit ratings from 3 agencies and manageable upcoming debt maturities of only CAD 500 million in March, we believe that Encana will continue to have ample flexibility to manage our large portfolio of opportunities for 2012. By the time Cutbank Ridge Partnership transaction closes, we expect to have an excess of $3 billion in cash and cash equivalents on our balance sheet. I will now turn the call over to Eric Marsh, Executive Vice President and Senior Vice President of the U.S. Division

Thanks, Sherri, and good morning, everyone. I'd like to take a few minutes to speak about the strategic initiatives Encana has undertaken over the last few years to increase the demand for North America's natural gas. These initiatives include increasing consumption in existing sectors such as power generation and industrial use, and creating new markets for natural gas in the transportation sector and LNG export for North America. Our modeling suggests that if the natural industry is successful in executing many of the current demand initiatives, demand for natural gas in North America could expand from the current level of about 70 billion to 75 billion cubic feet per day to over 100 billion cubic feet per day in the next decade. First, let's talk about what we see for demand increases in the short term. Due to the prevailing supply overhang, natural gas prices are currently at a level that incents additional demand to help balance the market. One of the largest sources of incremental gas demand in 2012 is expected to be coal to gas displacement in the electricity sector. Coal displacement is the market's reaction to the all-in cost advantage of consuming natural gas for electricity generation versus consuming coal in less-efficient coal-generating units. The sweet spot for displacement has historically been in the $3 to $5 per MMBtu range. Our measurement of average coal displacement from January 2009 to October of 2011 was about 3.5 billion cubic feet per day. In November, data indicates that up to 6 Bcf per day is currently being displaced. Based on the prevailing forward curves for the 2 commodities, we estimate that in the coming months, this fuel switching could approach 7 billion cubic feet per day. The longer-term displacement of coal with natural gas is even more profound when we consider the material capital cost required to retrofit coal-fire generation to comply with numerous environmental regulations that are expected to come into effect in the next 3 to 5 years. Our analyses suggest that 50 to 70 gigawatts of coal capacity could be retired. The most economic solution will be to replace it with new and currently underutilized combined-cycle natural gas power generation. At reasonable electricity demand growth levels, these retirements could contribute to natural gas demand in excess of 10 billion cubic feet per day in North America by 2020. Given that much of the coal capacity that is likely to be retired is currently being displaced, these economic and environmental conditions open the door for an additional 3 billion to 5 billion cubic feet per day of truly new natural gas-powered demand. There are already been the equivalent of 3.4 billion cubic feet per day of coal retirements announced by the power generators, and we expect many more utilities to announce retirements in the coming months. Encana has first-hand experience in achieving cost savings by using natural gas-fired electricity. With our ownership in 2 power plants in Southern Alberta, we have received lower electricity cost compared to market prices, which are dominated by coal-fired power generation. We have typically flowed these savings through to operating costs in the Canadian division. However, another way to look at it is an uplift to the price we've received for the gas consumed in our power plant. This equates to about $10 per MCF. Now let me talk a little about the use of natural gas in the transportation sector to displace gasoline and diesel. This is an exciting, although emerging new market. It was recently acknowledged by U.S. President Obama as a key means to achieving energy diversity and independence in the United States. At Encana, we have been pursuing this opportunity with advocacy and investments for over 2 years, and we are well positioned to drive it forward. Let me take give you some examples of what we've done and the fuel cost savings that we've realized. For starters, as of year-end 2011, we have converted about 15% of our pickup fleet to run on compressed natural gas or CNG. We operate 5 CNG fueling stations, and over the next few years, we intend to build at least 4 to 5 more service stations to service our fleet of 1,500 trucks. In 2011, we saved over $100,000 in fuel cost with about 180 trucks converted. We plan to have an entire fleet converted in the next 2 to 3 years. One of our most exciting projects has been investing in the infrastructure required to produce and distribute LNG for on-road trucking. We also see future markets for LNG use in other heavy-duty applications such as marine, rail, mining and remote power. These are all markets that will take several years to develop, but we are starting today and expect that demand increases will affect our business. Our fleet of mobile LNG fueling equipment is working today in Louisiana with one of our water supply chain vendors, Heckmann Corporation, where they placed the largest Class 8 LNG truck order ever. The plan is to see 200 trucks operating by mid-2012. We are working on similar projects in other areas where we operate, including Alberta, Northeast B.C. and Colorado. Depending on the application and the location, we have experienced an uplift in dry gas margins from $3.50 to $8 per million cubic feet in these early transportation projects. At the same time, we've achieved end-user savings that range from 20% to 40% of the equivalent fueling cost using gasoline or diesel. It's still early days, but we expect the impact to become even more meaningful over time. In addition, in 2011, we operated 15 natural gas or LNG-powered drilling rigs, which saved us about $11 million on fuel costs. We are also piloting conversions of our completion equipment to run on natural gas. Finally, with the increased abundance of natural gas, our ability to access new markets via LNG export is an increasingly important initiative. The Kitimat LNG export project, of which Encana owns 30%, is moving forward as planned. The facility is expected to have an export capacity totaling 0.7 billion cubic feet per day, expanding up to 1.4 billion cubic feet per day with Phase 2. We expect to receive an uplift in price by selling natural gas to world markets at a price linked to global oil pricing. As you can see, the future of natural gas is indeed very bright when you consider the opportunities we see in power generation, transportation and industrial use, both in North America and abroad. We believe that in the next 3 to 5 years, demand will increase significantly as we utilize this abundant, affordable source of energy. I'll now turn the call back over to Randy.

Now thank you, Eric. A great summary and strong reasons why we continue to believe in the North American natural gas market. 2011 was one of EnCana's best operational years ever. We accomplished what we set out to do, yet the abundance of natural gas in North America continues to outpace demand growth. And when combined with a mild winter across the continent, prices are currently at levels that are below what it cost to add new supplies for most dry natural gas basins. While we firmly believe the future for natural gas remains very promising, until we see a recovery in natural gas prices, we are adapting to the reality of the market. We're taking meaningful steps towards product and revenue diversification by transferring our industry-leading technical expertise to the exploration and development of potential liquids-rich resource plays, at the same time, continuing to preserve the value of our natural gas assets. As we further refine our 2012 plans, we will continue to adhere to the underlying strategic principles that have been integral to our company's evolution and success so far. We'll focus on what we're best at, the identification and development of resource plays and disciplined capital investment in the highest return projects. We'll strive to preserve the long-term value of our enormous resource potential, maintain our financial flexibility and provide strong returns to our shareholders through dividends. Mike and Jeff highlighted for you the numerous liquids opportunities we're advancing this year. On this current group of plays, we expect to develop 3 or 4 of them in the key resource plays over the next several years. On a rough equivalency basis, each key liquids resource play would be expected to have about 100 million barrels of recoverable reserves and be capable of producing in the range of 20,000 barrels per day. Two years ago, we'd limited liquids production on our land base, but we've made tremendous progress in evaluation in a very short period of time. Combined with the 80,000 barrels per day we expect to reach from our current oil and NGL production and planned NGL extraction initiatives, this will represent a significant shift in our commodity and revenue mix. With today's announcement of our partnership agreement with Mitsubishi, I feel confident that we'll make significant strides in 2012 towards gaining market recognition of the tremendous underlying value of our assets. I expect this to continue as we apply this approach to other areas in our portfolio, and as we further advance our goals of increasing our exposure to oil and natural gas liquids. Thank you very much for joining us today. Our team is now standing by to take your questions.

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

Just, first some question on contingent resources. At what point in the year will you have enough data to provide contingent resource estimates for some of these emerging liquids plays? I mean is that a midyear type thing? Or is that more this point next year? And then second, just a few questions on Kitimat. Maybe if you can talk a little bit about timing for FID and then maybe just address a little bit of market speculation. There's been a lot of speculation going around that you’re looking to sell your interest in the projects, so maybe you can address that. And there’s also been a fair bit of skepticism in the market lately about the ability to lock in oil-linked contracts so maybe can just talk a little bit about the interest you're seeing or confidence, I guess, in being able to lock down those contracts.

Regarding the contingent resources on our new resource plays, we would typically do that at the end of the year with our -- because we use our reserve evaluators to also look at and evaluate our contingent resource base. So although we'll be feeding them information during the year as we get the results, the evaluation and update will likely not occur until this time next year. Now regarding Kitimat, Apache, of course, is the operator of the project, and we have been actively marketing the project, and also completing the FEED study on the project. And we would expect to be in a position some time this year to make the FID decision. As part of that decision -- the final investment decision and part of the offtake agreements, we will likely reduce down some of the interest in the project as a result of providing equity to an anchor offtaker. Beyond that, we have not made any decision or commitments to reduce our interest any further.

Your next question comes from the line of Brian Dutton with Crédit Suisse. Brian C. Dutton - Crédit Suisse AG, Research Division: There's a concern in the marketplace that deals such as what you've announced today will result in more gas being put into North American markets. So could you maybe expand on your statement at the beginning of the call, that this deal will not result in accelerated CapEx? And a second and related question is, into what market do you expect your new JV partner to deliver its share of gas or its share of future gas production?

Okay. Well, we've already taken actions such that by reducing our overall capital spend this year and particularly our spend on our dry gas projects that we will end up the year more than offsetting any additional spending by our partners, certainly for this year. Likely that would be the same going into next year as well, but a little early to start planning for that. And as a result, overall, and with our shut-ins, we're expecting to take some 600 million cubic feet per day off the market this year. Any of the JVs that we've been doing will not be contributing production anywhere near those levels. That's expected it would be relatively minor in the next year or so. Brian C. Dutton - Crédit Suisse AG, Research Division: And second question, where do you expect your partner to be delivering its share of future gas production?

Okay, well, our partner's already announced, I believe, that they intend to take some quantity of their production to -- back to Japan, in the Japanese marketplace, through LNG.

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

Just a few questions. One of them is just around operating costs. So if you’ve got shut-ins and you've got volumes expected to be going down for a bit this year, how much upper pressure do you expect on unit operating costs? That would be one question. Secondly, with the number of plays that you've outlined, if you were to think about maybe a targeted exit rates, we're not going to hold you to the number, but a targeted exit rate on oil and liquids in 2012, we'd be very interested in that, if you've got a number. And the last question is just around the processing capacity you're bringing on. How much incremental ethane will you be bringing into the mix? And how do you see that affecting realizations?

Okay, Greg, I'll attempt to answer some of them and I'll attempt to delay answering some of them as well. We're going to -- basically our decision to reduce capital spend and to shut in gas has been a top-down decision and we've gone through on the capital side to make sure where we're reducing our capital spend, we're having the least impact that we can possibly have on operating cost in any other fixed cost structures that we have. The gas that we shut in, again, is also a top-down decision. And so our marketing teams and our production teams will be going out and trying to find the areas that have the least impact on operating costs. So these are the areas that primarily have the most flexibility with respect to production arrangements, but also have the highest variable operating cost. I expect at the end of the day that it will not have a material impact on our costs, although there may be, in some cases, areas where we do have to find ways of managing our transportation commitments and some of our commitments that we have to drilling and completion of long-term contracts, per se. Now with respect to exit rates, it would be premature to give a forecast on the liquids side. And since we don't know how much gas we're going to have shut in for the year, a little bit early on that. But we are planning on having an Investor Day in -- at the end of June or middle June? Okay, In June sometime, but I'm not sure what the dates are. At that time, we'd likely be able to do a little bit better job of forecasting for the year.

Okay, great. And then just on that, maybe a question around the ethane and processing and so on?

Okay. Renee Zemljak can provide some thoughts there.

With regards to the ethane that we're going to be bringing on to the market from our Canadian properties, we're not concerned about bringing that supply into the market. Our view on natural gas liquids pricing over the long term is really quite robust and we feel that the ethane market is going to be fairly balanced. There could be some challenges with regards to the timing of when the supply comes on versus the demand or infrastructure development, so there could be periods of time, short periods of time where we think that there could be some downward price pressures on the ethane overall. But for the most part, we're not concerned with it. And with regards to Encana-specific ethane contracts, we have secured our pricing for our ethane for the next 2 to 5 years out.

Okay. And can you just give me an idea where that would be trading vis-à-vis Edmonton or WTI or whatever you want?

Where it would be trading with regards to --

Yes, just in terms of realizations on ethane right now, just as a vantage point.

I think you could expect ethane values out of our Canadian properties to be more related to an ACO pricing, and I would say anywhere from $1 to $2 premium to ACO.

Okay, and last question for me. It's just on the tax base with the Cutbank assets that you've sold, how much of the tax hit, cash tax hit would you expect with that and I'm assuming that would just be associated with the cash coming in the door, not the whole transaction value.

This is Sherri speaking. The actual arrangement is a partnership. So Mitsubishi will be subscribing for a 40% interest in an Encana wholly owned partnership called Cutbank Ridge Partnership, where Encana will be the manager partnering and operator. Encana and its affiliates have sufficient attributes and tax pools associated with Cutbank Ridge Partnership that can be used in this transaction. And accordingly, we don't anticipate any cash tax on the transaction. The partnership lands are non-producing and Mitsubishi will join the partnership at closing which is expected before the end of February.

Your next question comes from the line of Mark Polak with Scotiabank.

When you guys just look at the supply side for the industry, I wonder if you could update thoughts on the marginal supply costs for the industry. Is that still in the 5-plus region in your mind? Or with all the liquids plays emerging is that -- are you seeing some downward pressure on that and how does that think -- affect your thinking on long-term natural gas prices?

Mark, clearly, that the market is oversupplied in the short run and marginal supply costs is not likely setting the price. But when we look at variety plays across our portfolio and what we see others doing as well on a sort of half-cycle basis is what we call the marginal supply cost, the range we would come up is something in like $4.50, plus or minus $1. It really depends on the range of between the drier gas plays versus the more liquids-rich plays. Right now, we do know that natural gas prices are well below that, so the situation will ultimately clear itself up.

Okay. And then on your emerging liquids plays, you talked about the 80,000-barrel per day target by 2015 from adding more deep cut capacity. In that sort of same timeframe, what do you think is a reasonable target for that same timeframe that the emerging plays could contribute to your liquids mix? I know you talked about eventually hoping they all get up to 20,000 barrels per day. Would you expect to see much on top of that 80,000 from those plays in that same timeframe?

We haven't picked a specific number yet. It's really too early to do that. But we did give you some examples of how fast we think the individual plays that are successful might ramp up. You can -- if there are oil plays you could probably ramp them up in 3, 4 years. If they have much more liquid -- more liquids-rich plays there’s sometimes more infrastructure that needs to developed, and those can take a little bit longer.

Okay, that's helpful. And last one for me, the production that'll be shutting in, at what range of gas prices would you look to start bringing those volumes back on?

We haven't decided. There's going to be an awful lot of factors that'll come into play before we make that decision, but you can count on us shutting it in, though.

Your next question comes from the line of Mike Dunn with First Energy.

I got on the call a bit late, so if you've already answered this, I can follow up later, but just wondering if you can provide an update on how active, I guess, discussions are with some of the remaining assets you were looking to divest, probably most specifically the Jean Marie area stuff, what -- do you have anything to update us on that?

We don't have anything to update today beyond what we've done. I think we've updated to the markets on a substantial number of items already. But we have been quite active, and you should expect us to be able to accomplish the $0.5 billion net divestiture target. That's really a divestiture through proceeds of JVs through the year. As I'm thinking it's really going to be really a minimum. We've got so many things underway right now and so many other potential things that we could do, that the number's probably going to be better than that.

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

My question, I've got a couple of questions. So the first one is, looking through to 2013, obviously, you have a lower amount of gas volumes hedged. Assuming current industry prices of $3.80 or so, how -- what would your production profile for 2013 look like?

Hard to answer that one right now. That's a little bit far out. Our decline rates at this level of spending will definitely be lower than it has been historically, and so it really depends on then how much capital we decide to put into a group. We really are putting a lot of -- keeping a lot of cash on our balance sheet right now and we expect to have at least that amount available to us for 2013 should we need it. So and I'd say 2012 hasn't happened yet, so a little bit too early to be doing detailed forecasting for 2013.

But maybe just to follow up on that, so I guess the, when you say your cash, you have that available through 2013, you could sort of take -- you would not necessarily follow what you're doing this year in terms of living within cash next day, if cash is much lower?

Too early to make that decision. It would depend to some degree on how much cash we generate from additional divestiture receipts as well. Now we're really trying to make sure that we have lots of flexibility this year and lots of flexibility going into 2013. There may be opportunities to start hedging 2013 at higher prices than today if Eric and others are successful in growing North American natural gas demand. I’d just say it's way too early.

Okay, and just a second question. You talked about the volumes you're looking to shut in. What's the primary -- when you do and you said there's a number of factors, maybe just to follow up quickly, is it cash costs that will be the primary driver for what volumes would be shut in? And if you could just -- we know the cash cost you have in the Canadian business and the U.S. business, but if you could speak quickly to which assets are the highest cash cost assets in the business, that will be helpful.

Okay. We're not making -- at this point, all of our production is cash positive. If prices continue to slide, we could make that decision on a property-by-property basis, but basically, what we're doing right now is making a corporate decision to shut in an additional 250 million cubic feet per day, which, when added with our forecasted decline from our less -- from our reduced capital spend this year, should take about 500 million per day of royalty -- production after royalties off the market, and our royalty volume associated with that would be about another $100 million, so we think about $600 million will come off the market. But like I said, we're not at the point yet at a property level where we're having to do it based on cash costs.

Your next question comes from the line of Phil Skolnick with Canaccord Genuity.

Any plans with share buybacks maybe, given all the cash that you'll have to do something in excess of what you've done historically?

I wouldn't consider it at this point in time. But if there are additional divestiture receipts or JV funding, it's something that I could take back and talk with our board about.

Okay. And are there any other hurdles left for this JV that, outside of the normal ones that you have to deal with?

There's really nothing. We're expecting to close end of next week.

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

A couple things. On the Mitsubishi partnership, is the partnership level of spending mandated as part of the joint venture agreement?

What we have is a 5-year plan, which has been agreed to with partners, and that plan will be updated every year. And right now, it anticipates, and you could calculate it based on the spend volume, roughly a $5 billion spend over that period of time.

And Randy, are the annual outlays mandated? In other words, is there a number for the partnership for 2012? I mean, you said it would ramp up. Is that number $500 million, $750 million?

Yes, it is in accordance with our 5-year plan and it does ramp up, yes, over time.

Okay. Let me try another one, if I could. You mentioned, Randy, that there were other, there's interest in establishing other joint ventures. Yet, the only play that you mentioned, at least I believe, was the possibility of something in Jonah. Are your thoughts in this regard pretty much confined to the dry gas plays? Or are you looking at joint venture opportunities with respect to liquids-rich plays as well?

Well, we're looking at the possibility of doing some additional Mitsubishi-like deals. We do have another 10% interest in a partnership that we would consider marketing as well. We also are evaluating the Devon-like deal that's been recently done. And that may be a means for us to accelerate the evaluation of the multiple oil and liquids-rich plays that we have in the U.S. and Canada. And then on our dry gas properties, we continue to find unique markets that are interested in investing and even possibly acquiring some interest in those lands. Although we just mentioned the Jonah property, we are actively engaged in other negotiations as we speak. And that goes to why I'm speaking with a higher level of confidence than you would normally hear me talk about divestitures and JVs.

Okay. One more for me. Jeff, could you give us your thoughts on well cost at the Tuscaloosa marine? What did that well that you operated run you, and where you expect such to be in the future? These are pretty deep wells.

Mark, it's Jeff. The well costs, I'm not going to disclose the specific well costs because I don't think they're indicative of the commercial plans by the teams. The zone itself, Tuscaloosa, on our property, ranges in depth, Eric, from 10,000 to 12,000 feet?

Yes, from probably 9,000 to 12,000.

So we're looking at 9,000 to 12,000 feet depth and then we're looking at 5,000-foot horizontals today and with planned drill 7,500-foot horizontals within the defined spacing units that are established in Mississippi. Long term, we feel that the play is really not that dissimilar from a drilling point-of-view to the Haynesville shale. Those are -- we often drill 12,000-foot wells; we are currently doing a 7,500-foot horizontal project in the Haynesville. And those wells are in the $10 million range so I have no reason to believe that with the same type of commercial development in the Tuscaloosa that we will be looking to approach the defined cost structures and capabilities that our Haynesville team has demonstrated.

Your next question comes from the line of Craig Shere with Tuohy Brothers.

I have a couple of questions also. Hopefully, they're somewhat short. First, I'm a little unclear. If you do wind up picking up liquids-rich CapEx in the second half of the year, is the intent at this point for that to be additive to the $2.9 billion full year budget? Or would that be displaced -- a displacement of gassy production in the second half?

It could be either or both at this point in time. One of the things that we're able -- one of the things we're trying to manage within the company right now is some of our longer-term rig and completion equipment that we have under our longer-term contract. And we're managing within the gas program now, but if we accelerate the oil program, if we're able to be successful and accelerate it, we are able to move some of that equipment across. Part of it would be funded as well, if we are successful, which I believe we will be in having incremental divestiture or JV receipts coming in for the year.

Well, that kind of fits a little into my next question, which has to do with potential for mutually beneficial contractor structurings. It's one thing to move a rig from one place to another if you're still paying for that rig. But if you have a commitment to fill some pipe in a certain region, can you negotiate what that midstream operator: hey, let's do something in a nearby liquids play and we'll give you an attractive contract there and fill those pipes a little longer-term on the gassy side. And then what can be done with the JV partners with their carried interest? Does it make sense for you to get some cash upfront in lieu of drilling carries on activity that both of you would want to delay for sometime anyhow?

You're talking about all of the things that our teams are working on at any one point in time. And as we're making the call as to reduce activity in one area and we'll look at how it impacts our processing and pipeline commitments and who the players are involved and these conversations are normal business -- course of business. We're hoping to mitigate as much as we possibly can and create as much flexibility as we possibly can in the programs. Some of our contracts with -- or JV partners have some out provisions when it comes to pricing. So we're not committed to spending in an environment where we don't want to spend in. So lots in a variety of things, and these discussions typically come up. Rigs, we can sometimes move across the border as well. There’s maybe less activity in one play in the U.S. but we have a demand for that same type of rig in Canada. We can do also cross-border exchanges. So our teams are very active, I'll tell you, working on all of those kind of deal arrangements.

Okay. And last questions, Renee, I appreciate your answers about ethane for Greg's question. And Canada multiyear ethane contracts are kind of common, I think. South of the Canadian border, it's obviously much less common. Do you see any prospects for demand from petrochems for longer-term ethane contracting in the States? And then the final question, in terms of longer-term gas production, looking into '13 and beyond -- I'm not looking for production numbers. In terms of the decision-making, is it an absolute question of economic earnings? In other words, if we have 400, 450 gas and we can make x percent internal rate of return, we'll do it? Or if your liquids plays really turn out to be robust, is it a comparative decision as you decide whether really put limited resources into one versus the other?

Renee?

Okay, so I'll go ahead and answer your first question with regards to the petrochemical market. Yes, we very strongly believe that there is going to be a return of that demand to North America, and we think that this shale revolution that we're actually experiencing is going to provide a great opportunity for North America to bring that type of market back to the States. So yes, we believe that there will be demand creation from the Petrochems. Your second question, I'm not quite sure I followed exactly what you were asking. If you could...

I'm sorry, the second wasn't necessarily for you, Renee, but it was the decision about gassy production activity in '13 and beyond, after you all have had a much better look at what you see in 2012 from your liquids plays. The question is, is the decision to go back and drill in the gassy plays an absolute one based on the economics of that play? In other words, we can make a 30% rate of return because gas is at $4.50. Or is it a relative decision because maybe we can get 80% returns for a lot more opportunities now in our liquids-rich zones?

I think it'll likely be a portfolio decision based on our historical experiences and forward expectations for pricing.

Let me ask it one last way. If you can get -- if you have a lot of liquids opportunities in 2013, would you limit gassy drilling even if it's economic to 30% or 40%? If you can do much, much better in the liquids plays, would you still let the gas sit there until maybe another day?

Again, a little bit hard to say. We have so much resource. We continue to try to figure out ways of extracting value from that resource and we would try to invest in what we thought would be the best long-term economic projects and the portfolio management that we attempt to do all the time.

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

In terms of getting those Haynesville economic sub-3, can you talk about what sort of EUR you would need for that and what sort of well cost?

Let me have Eric partially answer the question, but it's really got to do with our ability to put in the long-reach horizontal wells in what we call resource play hub development environments. And the longer-reach horizontal wells that we're able to put in right now tend to be around 7,500 feet in length. That adds basically 50% to 60% more EUR per well as a result of the longer length. And then secondly, when we are able to develop them in multiwell pads and I think these pads, now, Eric, are around 6-well pads? We're able to get substantial savings as a result of being able to operate on a, effectively a pad environment and employing manufacturing type in operations on those pads. But Eric, anything further? I mean I know you've been doing slowback. You've been doing a whole bunch of things that have also been turning out really well. And we're -- I think we're getting closer to $3, right?

Yes, the long laterals, we're able to get a 7,500-foot lateral. We're probably sub-$3 on a supply cost. And what you're really looking at is a well that might cost $13 million to $14 million and be 12 to 13 Bcf type of well. But overall, what you're really, and Randy described it very well, is just, if you have 30 fracs, you it 30 fracs times that EUR from each interval and the longer the lateral can be, the greater the EUR gets. So we do think in the future that there might be a time in we're able to drill 10,000-foot laterals as well, and so that's our next step. But right now we have, we've actually drilled 10 7,500-foot or greater laterals not only in North Louisiana, but also in East Texas. So we're pretty much into it right now.

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

I wanted to follow up on a couple of the earlier questions that I think we're really centering around how you think about spending within cash flow. If we go back to, I think, September, it was, you talked at the industry conference about staying within cash flow before asset sales, after dividend. And I think it goes back to a couple of these earlier questions to maybe re-ask or ask in a different way, should we expect that, that will be the case, going forward especially as we look at -- you're building cash this year, and then how we think about the interplay between the spending on liquids, the spending on natural gas and the hedges that are rolling off at the end of the year?

Yes, I think, Brian, it really relates more to the situation that we found ourselves in September with natural gas prices falling substantially and reducing our cash flow, so putting our debt at a higher level then we felt comfortable. So that was setting the stage for -- as a, largely a natural gas company, wanting to make sure that we weren't overspending on our cash inflows. As we transition to a more balanced portfolio by adding additional liquids, there may be times that we think it does make sense to outspend our capital budget -- outspend our cash flow. But in the, let's say in the near-term, the next year or two, probably going to be relatively -- probably be relatively close to our cash flow, unless we are able to bring in significant additional proceeds from JVs or from asset divestitures that help us advance our liquids program at a faster pace. So put those caveats around it.

That's helpful. And then secondly, can you talk more granularly, or geographically granularly, regarding where we should expect the rig reductions, particularly how you're thinking about that Haynesville rig count and then when we think about the gas production declining over the course of the year, are there areas where that will be more pronounced versus less pronounced?

I think you're -- talk about the Haynesville. We've already had a fairly substantial reduction in rig count in Haynesville and future rig count reduction will depend, to some degree, on what I said earlier was managing some of our commitments, but also at how quickly we can move them to some of the more liquids-rich plays that can utilize those big horsepower rigs. I’m going to let Jeff and Eric and Mike McAllister identify some additional information.

Mike, it's Jeff Wojahn speaking. Roughly, when you look at 2011, on our average portfolio across the United States, we have about 30 operated rigs running at any given time. Today we're looking and managing towards a target of around 10 to 12 rigs, and you get specific about certain areas, programs like the Haynesville had 12 to 14 operated rigs working last year and we're really talking about reducing those programs. Today, we're at 3 rigs working in north Louisiana and 3 in East Texas. With an idea, again, looking at how we manage all of those things that Randy talked about, of reducing that program, to virtually no activities beyond our non-operated partners’ activities after the completion of the first quarter. So it gives you an indicative idea of what we're doing. And likewise, when you looked across our portfolio of dry gas assets, what are -- I think, Mike McAllister talked earlier about reducing activities in the Greater Sierra and CBM plays to minimal levels. And likewise, across the Rockies, we're also looking at minimal operated levels beyond our joint venture commitments and supply chain commitments.

And very, very lastly, should we expect that there will be any benefit from wells that are currently drilled and not completed that are being brought on or completed waiting time and brought from disproportionate backlog, will that be aiding production this year? And is there a gas price at which we should expect that you will increase – or what is the gas price that would increase activity back up again?

We just have a normal level of backlog that we would always have and we more or less caught up over the course of 2010 and 2011 on all of our completion. So there's nothing out of the ordinary that you should expect. We may, as part of the reduction in gas production, we may choose not to be bringing on all of the wells as fast as we normally would, or we may also choose to bring them on at lower rates. These are the choices that the teams are currently going through. And if prices do respond significantly over the course of the year and we see movement in both the short-term and longer-term price periods, we could be bringing that gas back on. That will be the economic decision that the company will be making as a whole. But for now, our intent is to slow down and shut in gas.

Your next question comes from the line of Bob Morris with Citigroup.

Randy, when you think about shutting in production, you mentioned that all that production is cash flow positive and so there's no investment just to keep the valve opening and keeping it flowing. And as you know, effectively what you're doing is you're -- you don't get that gas production back until the end of the life of the well. So I was just wondering how you think about that in a sense that you're postponing having that cash for 10, 15 years as opposed to just having that cash today to be able to reinvest in accelerating some of your oil and liquids projects.

Thanks for that, but not normally the way it really works. A lot of the wells that have really high decline, and they basically have storage capacity near the wellbore caused by the fracture system. And what we've found historically is if we shut in wells that have very little liquids production and water in this case. They will -- and they were high decline wells to start with. What really happens in the reservoir is as gas continues to flow towards the wellbore and you get a build up. So you get a lot of flush production when you bring the wells back on. And so the value is not pushed out 20 years. It's -- there'll always be some that's pushed out over time. But what you're hoping for is a combination of that flush production coming back and a higher price would more than offset the loss of cash flow in the long-term.

But you really don't extend the life of the well in doing that.

No, really, for those kinds of wells, it has really no impact on the long-term nature of the well.

Okay. I guess your thought is that you turn the well back on when the gas price is materially higher to get that short period of flush production at a higher price, as opposed to having that cash today?

You can look at what we did 2 years ago. And we had similar kind of shut-in and you'll see the distortion that occurs in our production over the course of time when we shut it in and then when we bring it back on again, I think it was -- was it Jonah that we did it? Jonah and East Texas. Yes, we shut in East Texas and Jonah and we saw some real, real flush production response when the wells came back on. So we really didn't push it out 20 years.

We will now be taking questions from the media and your first question comes from the line of Geoff Bird with allNovaScotia.com.

I was wondering if you could tell me what's left to be done at Deep Panuke before production starts.

So Mike McAllister, are you up to speed on Deep Panuke yet?

Yes, I think we're still in the process of commissioning the facility and we're targeting July 1 start. Again, we want to make sure work's done efficiently and effectively and safely so -- but that's the target start update.

And I know that Mike Graham had previously said he was expecting yearly cash flow of $200 million to $300 million. I'm wondering there's a revised number there?

No. What we had said in the past wasn't a cash flow number, it was a production number. And the facility itself is designed to be able to be -- produced up to 300 million cubic feet per day, and an economic range of production might be in the range of 100 million to 300 million cubic feet per day at any one given point in time. How we produce the facility is something we will still -- we will decide as we go and it'll, to some degree, be related to the market at that time.

So you're saying there's a potential to sort of reduce the flow from that rig?

It has a fixed cost structure, so you'd likely want to cover the costs of it. But after that, it's -- we have a lot of flexibility. These kind of wells are really -- how do you describe them? These 4 wells that are going to be producing the 300 million per day, these are really strong producing wells and we have the ability to turn them up or down as we like.

Right, and so what would you expect, maybe initially?

The current plan is to produce at about 200 million cubic feet per day. So it's right in the middle of the range.

Your next question comes from the line of Brett Bundale with the Chronicle Herald.

I think Geoff actually answered or asked the question or the main question I had, but maybe if you could speak -- I don't know if you're aware of any potential hurdles or maybe it's too soon to say. But between now and July sort of you mentioned the commissioning work. Is there anything that you're expecting could cause further delays or. . .

Nothing we're expecting. We weren't expecting the delays that we've had. So we're just going to make sure the facility is safe to operate and ready at the time that we turn it on.

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

I'm just wondering if you could tell us how you came up with the 600 figure; why not more or why not less?

We were already reducing our -- by trying to stay within our capital program for the year and by allocating as much as we could to our liquids plays. It resulted in a 250 million per day decline in our 2012 production. There was no magic in the number. We just thought a number of that magnitude would have some impact on the overall markets.

Okay. If I could, just one more, is Deep Panuke volumes -- are they still going to Repsol?

Yes, they are still going to Repsol.

Your next question comes from Pat Roche with The Daily Oil Bulletin.

Can you be more specific at all about when you plan to make a final investment decision on Kitimat LNG?

Again, we're not the operator, but the conditions that will have to be met is, we'll need to have an offtake agreement for a significant portion of the project and we'll have to have the FEED study completed with the, I guess, a degree of risk reduced to a level that we feel we're comfortable going ahead with the project. We're fully hoping that it would be midyear.

Midyear this year?

This year.

Okay, did you say, I didn't really understand the answer when you were asked about reducing your interest in Kitimat LNG. Did you say your interest will be reduced? If so by how much and why?

Okay. The partners had agreed very early that we would be willing to provide an equity interest to a significant offtaker, basically an anchor offtake agreement; we'd be able to give up some interest. I'm not sure if that was disclosed how much by the partner?

What do you mean by an anchor offtake?

Okay. Sorry, the way these facilities are generally contracted is through a -- an offtake agreement by a buyer. In this case, we would be expecting Asian buyers to commit to taking a certain amount of the capacity in the facility in terms of a long-term commitment. In exchange for that long-term commitment, we would be guaranteed a price that they take it at, and we would also provide them with an opportunity to take an equity interest in a portion of this facility and possibly also to provide them with an equity interest in some associated upstream capacity.

Okay, and at this point, can you say roughly what that equity interest might be, roughly?

No, we haven't, but there are markers in the industry that could check on.

Your next question comes from the line of Jeremy van Loon from Bloomberg news.

Just a follow-up to the previous question. I'm just wondering, I'm looking at the release from Japan actually on the agreement, and they're quoting a much higher value of the transaction, JPY 480 billion which is about $6 billion. Is Mitsubishi planning to become an anchor offtaker in Kitimat?

I'm sorry, we're just trying to catch up. But at this point in time, Mitsubishi has their own investment.

It's the total investment maybe.

I guess what you're seeing is, Mitsubishi's expected total investments over 5 years in the partnership.

Okay. Except that it seems to be almost, well, 40% or 50% higher than the figure that you're citing.

It's not related to Kitimat. It's basically...

It's Mike McAllister here. So what Mitsubishi has in their release is they're talking to the total investment made by the partnership over the next 5 years is what they're referring to as $6 billion. So take 100% gross expenditures over the next 5 years; what they've got in their release is what you'll come up with.

Okay. And one last question, if I may. I'm just wondering, again, regarding Kitimat, why would you say it's been -- it's seems like it's been a little bit difficult for you guys to find offtakers. Is it a question of price? Or why has it been difficult?

I don't know that it has been difficult. It's -- these things just take a while. The actual study, the FEED study has not yet been completed. So that would be one of the factors. The offtakers, of course, like to know what it's going to cost.

Right. And you don't have a number for that.

And the timing, and we're simply working towards that.

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

Thank you, everyone, for joining us today. Our conference call is now complete.

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