Ovintiv Inc. (OVV) Q4 2010 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to EnCana Corporation's Fourth Quarter and Year-End 2010 Results Conference Call. [Operator Instructions] 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. Welcome everyone, and thank you for joining us today. Before we get started, I must refer you to the advisory on forward-looking statements contained in the news release as well as the advisory on Page 49 of EnCana’s Annual Information Form dated February 18, 2010, the 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, I want to remind everyone that EnCana reports its financial results in U.S. dollars, and production volumes are reported on an after-royalties basis. References to reserves, or resources information will be on an after-royalties basis, employing forecast prices and costs unless otherwise noted. To provide a clear understanding of the post-split EnCana, the prior period comparative information discussed in this conference call represents EnCana's financial and operating results on a pro forma basis. In this pro forma presentation, the 2009 results associated with the assets and operations transferred to Cenovus Energy are eliminated from EnCana's consolidated results and adjustments specific to the split transaction have been removed. EnCana's fourth quarter consolidated financial statements and supplemental information with 2009 pro forma comparatives are available on our website. Randy Eresman will start off with the highlights of the Co-operation Agreement we've reached with PetroChina, as well as an overview of our 2010 operating results and 2011 budget. Jeff Wojahn, Executive Vice President and President of our U.S.A. division; and Mike Graham, Executive Vice President and President of our Canadian division, will then touch on some highlights from each of their areas before turning the call over to Sherri Brillon, EnCana's Chief Financial Officer, to discuss EnCana's financial performance. Following some closing comments from Randy, our leadership team will then be available for questions. I will now turn the call over to Randy Eresman, EnCana's President and CEO.

Thank you, Ryder, and thank you, everyone, for joining us today. I'm very excited to speak to you about the Co-operation Agreement we've reached with PetroChina, as well as our 2010 results and our 2011 capital program. The agreement we announced yesterday with PetroChina represents a major step forward in our plans to unlock the value contained in our enormous portfolio of natural gas resource plays and to double EnCana's production per share over the next five years. For the last number of years, the North American natural gas industry has undergone significant and permanent change. Technological advancements and operating practice innovations have changed the game, rapidly transforming supply sources that were once thought to be a high cost to some of the most prolific mid- to low-cost basins in North America. EnCana has been at the forefront of this transformation, leading to innovation and cost reduction. We've assembled some of the best natural gas resource plays in North America by focusing on high-quality resources, creating technological advancements and applying innovative operating practices to help develop these plays to some of the lowest cost in the industry. However, the value of our company and the effect the value of natural gas resource plays relative to historical views on conventional asset bases is something we believe the market has under-appreciated. As a result of the significant increases we've achieved in the size and the quality of our asset base, it has become clear to us that the greatest value proposition for our shareholders is to bring forward the value of certain of these assets by developing them at a sustainably higher growth rate. Last March, at our 2010 Investor Day, I told you about our plans to double EnCana's production per share over the coming five years. An integral component in the execution of this plan was to attract sizable third-party capital to advance the rate at which we develop our assets. We set a target at that time for a range of $1 billion to $2 billion per year. And as you can see, this agreement we signed with PetroChina goes a long way towards meeting that target. But before we discuss the details of Encana's proposed joint venture transaction with PetroChina, I'd like to briefly talk about the assets that are specific to this deal. We first established a sizable position in Cutbank Ridge in 2003, 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, it also enabled us to study the basin long before for others and then build our land position predominantly in the core of the resource. This practice of identifying high potential plays and acquiring land early is the best way we believe we can create long-term value for our shareholders. And today, eight years after our initial entry into these plays, we believe the deal we've announced further validates our business philosophy. The key producing zones in the greater Cutbank Ridge area are the Montney, the Cadomin, and Doig formations. January daily average production in this area was approximately 510 million cubic feet of natural gas equivalent. This is one of EnCana's lowest-cost natural gas resource plays, with a 2010 supply cost of about $3.15 per million BTU. In Montney, in particular, we've achieved a steady progression of improved cost structures by leveraging technology and continually optimizing all facets of the development process. Our 2010 average supply cost for the Montney program was approximately $3 per Mcf, making it one of the most economic place in our portfolio. And we expect to lower our future supply cost in this play even further. The evolution of the development and economics associated with the Montney provides an excellent analog for what we expect to achieve in other plays throughout our portfolio. At year end 2010, Independent Qualified Reserves Evaluators or IQREs, estimated that our Cutbank Ridge lands had proved reserves of about 2 trillion cubic feet of natural gas equivalent. Our proved reserves represent the very tip of the iceberg when it comes to what we ultimately expect to develop on our existing resource base. A sizable portion of our company's future resource potential resides on our extensive lands in British Columbia and Alberta. And we anticipate this joint venture agreement with PetroChina will help develop a significant volume of natural gas from these promising economic and clean energy opportunities. Upon completion of the deal, PetroChina would pay $5.4 billion to acquire a 50% interest in the Cutbank Ridge business assets, an interest that represents current daily production of about 255 million cubic feet equivalent per day, proved reserves of about 1 trillion cubic feet of natural gas equivalent as of the end of 2010 and about 635,000 net acres of land. The planned joint venture infrastructure, on a 100% basis, includes about 700 million cubic feet per day of processing capacity, about 3,400 kilometers of pipelines and the Hythe natural gas storage facility. Going forward, each company will contribute equally to future development capital requirements. EnCana will initially operate the assets and market the production. Following the completion of the transaction, the joint venture will operate under the direction of a joint management committee. We expect to develop and sign a joint operating agreement with PetroChina, which will require regulatory approval from both the Canadian and Chinese governments. In addition, the Co-operation Agreement is subject to due diligence and negotiation and execution of various transaction agreements, including the joint operating agreement. The economic adjustment date of the transaction is expected to be January 1, 2011, with a closing date depending on the timing of various government and regulatory approvals. We look forward to working with PetroChina as we jointly develop these top-tier assets, and we continue to look for other opportunities to implement similar arrangements, both in Canada and the United States. So now we'll move on to our achievements of 2010. As a natural gas producer, it can be difficult to feel excited in a sub-450 natural gas price environment, but despite the low natural gas prices that persisted through 2010 the execution of our teams in meeting their operational targets was firsts rate, which showed total production growth of 12% per share. And we saw a superior performance from our key resource plays across our portfolio, which delivered 19% production growth year-over-year. In addition, we grew our total proved reserves by 12% to 14.3 trillion cubic feet equivalents, replacing more than 250% of our 2010 production, volume forecast prices and costs on an after-royalties basis. At a company-wide level, we met or exceeded our targets for the suspected production cash flow and per share growth. Additionally, we're in line with our targets for capital spending and administrative expenses, and below our targets for operating costs and DD&A. I believe these results underscore the strength of our asset base and the capability of our teams to continuously improve, innovate and drive down costs. At about $4.40 per thousand cubic feet, the average NYMEX price was the biggest challenge facing natural gas producers in 2010. However, a long-standing approach to risk management served us well, as our commodity price hedges generated realized hedging gains of $808 million after tax and helped to stabilize our financial performance for the year. Another area we saw a strong execution in 2010 was from our asset divestitures. We are continuously looking for opportunities to high-grade our portfolio by divesting of assets that no longer fit with our future development plans. In 2010, the company completed the divestitures of non-core assets for proceeds of approximately $288 million in the Canadian division and $595 million in the U.S.A. division. Some of these assets included production, which resulted in a year-over-year production decrease of about 130 million cubic feet equivalent per day. Additionally, last month, we announced the sale of our Fort Lupton natural gas processing plant and gathering systems in Colorado to a subsidiary of Western Gas Partners, LP for approximately $300 million. We also recently issued a request for proposals to companies interested in buying and completing the construction of the Cabin Gas Plant in the Horn River Basin. Sale of these assets is part of our ongoing initiative to capture significant incremental value from our midstream assets. We also made significant strides last year in the implementation of natural gas as an affordable, clean burning fuel source across our operations. I'm happy to report that we now have now nine natural gas fuel drilling rigs in our fleet, and we also have one natural gas filling station up and running with another four currently under construction. Additionally, the conversion of our fleet vehicles to natural gas engines continues. Now the year-end reserves. We're very pleased with our reserve additions in 2010. The efforts of our teams resulted in proved reserve additions, which replaced more than 250% of 2010 production. Our reserve life index remains at about 12 years. Compared to 2009, total proved reserves increased 12% to 14.3 trillion cubic feet equivalent. Proved undeveloped reserves, or PUDs, accounted for 49% of total proved reserves, and are scheduled to be converted to proved developed reserves within the next five years. The average future development costs associated with our PUDs is approximately $1.65 per thousand cubic feet equivalent. With respect to economic contingent resources, our 2010 1C or low estimate economic contingent resources are estimated at about 20 trillion cubic feet equivalent, a 26% increase over 2009. The low estimate is the most conservative category and carries with it the greatest degree of confidence, 90% that these resources will be recovered. Each classification of contingent resources has the same degree of technical certainty as the corresponding reserves category, but the resources are not yet commercial due to contingencies, such as the timing and pace of development, or the need for additional infrastructure. All of our reserves and contingent resources continue to be 100% externally evaluated by Independent Qualified Reserves Evaluators, not just reviewed our audited. Additions to reserves and resources in 2010 were led by the Haynesville and the Greater Sierra key resource plays. In the Haynesville, as a result of delineating our large acreage position to our land retention program, we added about 1.3 trillion cubic feet equivalent of proved reserves. In the Horn River area of Greater Sierra, the continued assessment of enormous resource potential within the basin allowed us to book an additional 300 billion cubic feet equivalent of proved reserves. For your reference, 2010 reserves and economic contingent resources for each of our key resource plays, as well as our 2011 corporate guidance documents, have been posted to our website at encana.com. Now looking through to 2011, we've chosen the 2011 capital program, which balances the company's priorities of responding appropriately to the current economic environment with continued investment in our long-term capacity to grow production more aggressively and at lower cost. Encana's focus in 2011 us to position itself to maintain momentum, control the things we can control and react to changes in the external environment with speed and discipline. We set our 2011 capital program at approximately $4.6 billion to $4.8 billion, largely in line with our 2010 capital program. With this level of spending, we expect to achieve production in the range 3.475 billion cubic feet equivalent per day to 3.525 billion cubic feet equivalent per day, about a 5% to 7% per share increase above 2010 levels. Our 2011 cash flow is projected to be in the range of about $4.0 billion to $4.3 billion as supported by our hedging program. As always, our operational teams remain absolutely focused on driving down costs, optimizing production efficiencies and maximizing margins. It is important to recognize that underlying our 2011 guidance numbers are several factors which could directly impact our plans as the year progresses. Completions of our negotiation with PetroChina and the additional joint venture opportunities to employ third-party capital on our lands could lead to an expansion of our program. We'll continue to closely monitor the business environment and the key signposts related to commodity price drivers as the year progresses. I'll now turn the call over to Jeff Wojahn, President of the U.S.A division, who will provide us with a recap of the U.S.A division's 2010 results.

Thanks, Randy, and good morning. 2010 marked another solid year for the U.S.A division, with production volumes averaging just over 1.9 billion cubic feet equivalent per day, up nearly 14% over 2009 volumes. This growth was achieved despite the impact of divestitures, which resulted in a year-over-year decrease of approximately 65 million cubic feet equivalent per day on an annualized basis. Our year-over-year growth is partly due to bringing our 2009 capacity reductions back online at the beginning of the year, and is partly driven by strong results across our division, particularly our operations in the Haynesville shale and in the Piceance Basin. The U.S.A division's 2010 operating costs of $0.56 per thousand cubic feet equivalent are more than 10% below our original March 2010 guidance. A credit to our teams and their ability to continue implementing operating efficiencies across our business. This reduction in operating costs was achieved despite average cost inflation of about 9% in the U.S.A division last year. Cost pressure has been greatest on pumping services where last year we saw average cost increases of 10% to 40%, depending on the basin or area we operated. This combined with declining natural gas prices, led us to the decision mid-year to pull back our spending and release some of our higher-priced equipment. We began to look for innovative ways to manage our completion costs and realized that we needed to change our relationship with our vendors from short-term service agreements to long-term strategic partnerships. By developing unique, long-term low risk collaborative solutions with our vendors, we believe we can play a larger part in managing the distribution of services, and as a result, achieve significant efficiencies in the field and maximize our realized margins. We now have long-term contracts in place with three service companies who will be providing enhanced pumping equipment to us starting in the second quarter of 2011. With completion costs now representing around 40% of our all-in capital cost per well, we expect the implementation of this more durable equipment to have a meaningful impact on our ability to manage costs. Another way we feel we can reduce cost is to change our position in the supply chain by sourcing commodities directly from suppliers. Commodities account for about 10% to 20% of our overall well costs. On a per well basis, the total cost can reach over $1 million in some areas such as the Haynesville shale. Accessing these materials directly from the supplier could potentially reduce our commodity costs by 30% to 40%. Turning now to the performance of our key resource plays, I'd like to take a moment to comment on our East Texas play area. Production from the play came up slightly short of 2010 guidance, as volumes in the third and fourth quarters dropped off in the first half of the year. Recent well results from the Bossier sands have not met our expectations. And as a result, the expected well inventory associated with that zone has been reduced. We will continue to reduce our activity levels in this area, focusing our development activities on the Mid-Bossier shale, as well as shifting more of our resources to Haynesville and other opportunities. Although there were minor reserve revisions in East Texas, we are still very encouraged by newly identified opportunities in other parts of the play, and going forward, we will continue to evaluate their potential. Now let's look at our Haynesville results. With fourth quarter production averaging 410 million cubic feet equivalent per day, this play has transitioned quickly from an emerging resource play to one of the company's top producing plays. Our development program in the Haynesville has now shifted from lease retention to multi-well pad drilling, as we ended the year with 10 operated rigs drilling at multi-well pad locations. To date, the production performance from our first multi-well pad drilling site in North Louisiana has been strong, with six of the most recent wells coming on at an average 30-day initial production rate of 16 million cubic feet equivalent per day. Additionally, in shifting to manufacturing style drilling, our drilling costs are approximately 18% lower, drilling time is 10% faster, and we've achieved a 40% increase in the number of frac stages pumped on a per monthly basis. As I mentioned, the bulk of our land retention drilling program is complete, and having to further delineate the play, we've identified some areas that are more structurally complex and challenging to produce. These have been important learnings for us. By gaining this knowledge, we are now better positioned for commercial development in the most prospective areas of the play. However, this did result in us choosing to drill fewer Haynesville wells than originally planned in the second half of the year. And we've let approximately 12,500 acres of less prospective leases expire. We also saw excellent results this year from our Piceance Basin operations, where annual production volumes were up 23% compared to 2009. This increase was attributable to better-than-expected well performance, strong base production and the addition of approximately 14 million cubic feet equivalent per day of production, which we acquired in the first quarter of 2010. Our teams are very excited about the Niobrara shale potential that we've identified on our existing lands, in both the Piceance Basin and the DJ Basin in Colorado. In the Piceance Basin, we have over 600,000 net acres of land, which we believe has Niobrara and Mancos shale potential. We continue to evaluate this play, having drilled five wells to date and with another three planned for the early first half of 2011. Our position in the liquids-rich DJ Basin totals about 40,000 net acres, and although we haven't drilled any wells to date, we are very encouraged by the results from wells offsetting our acreage. Of note, Noble Energy drilled in the median offset to our acreage during the first quarter of 2010. The well was drilled with a 4,000 foot lateral that completed with 18 stages and produced 60,000 barrels of oil equivalent in the first 60 days. I'd also like to provide a quick update on another liquids-rich emerging play, the Collingwood shale in Michigan. In the last six months, we increased our land position to 424,000 net acres. This land was acquired at an average cost of around $200 per acre, and is another example of Encana's ability to act as a first mover, identifying new plays early on, assembling a sizable land position in the heart of the play before others understand its full potential. We've drilled two evaluation wells to date, and we plan to drill an additional three to six wells in 2011. We are still very much in science mode with this play, as our new ventures team works to determine which completion technology will be the most effective for this play. That said, we are encouraged by the results we've seen so far, so stay tuned for more details on the play as our drilling program progresses. I will now turn the call over to Mike Graham, President of the Canadian division.

Thanks, Jeff, and good morning, everyone. We've achieved tremendous results in the Canadian division in 2010, with total annual production averaging about 1.4 billion cubic feet equivalent per day, up 6% from 2009. This year-over-year growth was achieved despite the impact of net divestitures, which resulted in a decrease of approximately 65 million cubic feet equivalent per day on an annualized basis. Our production growth was partly a result of bringing our 2009 capacity reductions back online, but mainly due to successful drilling programs. 2010 operating costs came in about 4% below guidance expectations at $1.06 per thousand cubic feet equivalent, which were more than 10% lower than our original March 2010 guidance. Excluding the impact of foreign exchange, operating costs were $0.96 per thousand cubic feet equivalent in 2010 or approximately 12% lower than 2009. Lower per unit costs are attributable to production growth and improved operating efficiencies across all our resource plays. The most notable production increase in 2010 came from our Deep Basin business unit where our Bighorn and Cutbank Ridge key resource plays delivered average annual production growth rate of 37% and 28%, respectively. At Bighorn, 2010 production volumes averaged 239 million cubic feet equivalent per day as we continued to see impressive results from our Falher horizontal drilling program. To date, eight Falher horizontal wells have been drilled and completed in Kakwa, seven of which are on production. The wells were completed with an average of 13 frac stages, and initial flow rates have averaged 9 million cubic feet equivalent per day. These seven wells have significantly exceeded expectations. Additionally, during the fourth quarter, we drilled and completed our first horizontal well in the well rich formation at Redrock. The well has flowed at a restricted rate of 9.5 million cubic feet equivalent per day for approximately three months, which is well above our tight curve expectation. Three additional vertical wells were also drilled into this formation and are awaiting completion. At Cutbank Ridge, annual average production totaled 401 million cubic feet equivalent per day, and we continued to see impressive results from both our Montney and Cadomin drilling programs. In the Montney, 2010 production averaged 274 million cubic feet equivalent per day, representing a 58% increase over 2009. Over the year, we continued to increase our average frac count per well to 13 in 2010 compared to an average of nine fracs per well in 2009. Year-over-year, our Montney well costs are down more than 20% from 2009 levels, and are currently averaging about 500,000 per interval. Recently, we completed the set well with 24 frac intervals, which had an initial flow rate of 16 million cubic feet equivalent. This is our best well to date in the Montney, with our lowest-cost yet, at about $300,000 per interval, drilled, completed and tied-in. Moving on to the Horn River. Production for the year averaged 29 million cubic feet equivalent per day, lower than our original target of 50 million cubic feet equivalent per day, primarily due to delays in bringing on production. In October, we completed frac operations on the 63-K Pad where we pumped a total of 316 fracs and 14 wells. This was the largest frac program ever conducted in the Horn River shale. All 14 wells on the 63-K Pad are on production, and after 30 days, had an average daily production rate of 12 million cubic feet equivalent per well. Our interval costs on the 63-K Pad at 680,000 were somewhat higher than the 600,000 we estimated earlier. These higher costs were attributable to pumping difficulty causing lower efficiencies early in the operation, as well as a conscious decision to test higher frac volumes per stage in 10 of our 14 wells. Building on our efficiencies and further utilizing fit-for-purpose technology, we expect to reduce per interval costs to the $500,000 range. The Debolt water plant performed exceptionally well through the second half of the year, supplying 5 million barrels of water for use in the 63-K Pad site frac-ing operations. During the last half of the program, the Debolt was supplying approximately 75% to 80% of the daily frac-ed water requirements. And in 2011, we expect it to provide close to 100% of our frac water requirement. We expect that sourcing water from the Debolt plant will reduce our environmental footprint and also lower our water costs. As I mentioned during our third quarter conference call, we have been moving ahead with the additions of liquids extraction equipment such as refrigeration plants and turbo expanders at some of our midstream facilities in the Deep Basin. In the fourth quarter, we signed two deep cap processing deals, securing 105 million cubic feet equivalent per day of firm processing capacity at Musrol and up to 90 million cubic feet equivalent per day of firm processing capacity at Gordondale. These arrangements will allow us to strip out liquids from our gas ring, thereby, capturing more value and enhancing return. We expect to triple our condensate and NGL production in the Canadian division from about 10,000 barrels per day currently to about 30,000 barrels per day over the next few years. We are also increasing our focus on liquids-rich plays. To this end, we have established a large land position in the Duvernay shale in Alberta, a play that has demonstrated significant liquids potential. We are planning further evaluation of this play and expect to continue appraisal drilling in 2011. I'd also like to provide an update on our farm-out agreement with Korea Gas Corporation, KOGAS, with whom we are developing acreage in both the Montney at West Cutbank and Kiwigana area in the Horn River. In the Montney, we drilled a total of seven wells in 2010, and we plan to drill about six more wells under this farm-out arrangement in 2011. The first KOGAS well was brought on production in October at a restricted rate of about 6 million cubic feet of total per day and is meeting expectations. Improved frac designs in the Montney have significantly lowered our completion costs from about $850,000 per frac to $380,000 per frac. And initial production rates have increased from 3.7 million cubic feet equivalent per day to 7.1 million cubic feet equivalent per day. At Kiwigana in the Horn River, we are currently drilling our third main hole on our planned 10-well path. We are very pleased with the progression of the farm-out agreement with KOGAS, and we believe there is potential for further expansion of this agreement. Now looking at our CBM resource play. In 2010, well costs were approximately 15% below 2009 levels, and we expect further efficiencies from increased PAD style drilling. As part of our CBM acquisition strategy, we successfully closed acquisitions of approximately $200 million in 2010, and we are continuing to pursue tuck-in acquisitions for 2011. Lastly, our project at Deep Panuke is nearing completion. We are expecting the offshore platform to arrive in Nova Scotia in the third quarter of this year, with first gas production commencing in the fourth quarter at approximately 200 million cubic feet equivalent per day. Our total capital costs for the project is now expected to be about $960 million, which includes approximately $100 million to be spent in 2011. In closing, I would like to highlight that the Canadian division holds more than 9 million net acres of petroleum and natural gas rights. As such, we will continue to pursue additional farm-out and joint venture arrangements like the ones that were accomplished with PetroChina and KOGAS. Over the last couple of years, we have farmed out more than 1 million net acres on several emerging oil plays, including the Cardium, the Aksho or the Bakken as some people call it, and the Viking. A significant portion of these farm-outs are in Kanafi land where we own the mineral rights. Third parties are paying 100% of the costs, and we are receiving royalties from the wells they drill. This type of arrangement advances our knowledge of the potential resource on our land in a low-risk, capital efficient manner. I will now turn the call over to EnCana's Chief Financial Officer, Sherri Brillon, who will discuss our overall financial performance for the year.

Thanks, Mike, and good morning. Well, Randy covered most of the details of the Co-operation Agreement with PetroChina. I'll address our thoughts on the use of proceeds. With the transaction anticipated proceeds, we will continue to pursue a balanced approach to disciplined capital investments, maintaining financial flexibility and liquidity and strong investment grade rating, while providing strong returns to shareholders through dividends and share purchases under our normal course issuer bid. As always, we will continue to manage our capital programs and balance sheet in a highly disciplined manner. To be clear, the 2011 capital program we announced today was planned with a direct line of sight to the potential foreign agreement with PetroChina. We will not pursue growth at any cost, but this transaction will enhance our ability to take a longer-term investment view as we pursue the development of our assets. Let's turn now to our 2010 performance. Despite the challenging economic environment, we achieved solid financial results in 2010. Proof of our continued focus on risk management, capital discipline and our company-wide efforts to lower costs and maximize margins. In 2010, EnCana achieved cash flow of $4.4 billion or $6 per share on a diluted basis, which represents a 10% decrease on a per share basis year-over-year. This was accompanied by operating earnings of $0.90 per share on a diluted basis compared to 2009 operating earnings of $2.35 per share diluted. The lower comparative results in both cash flow and operating earnings generally reflect a combination of lower realized financial hedging gain, higher transportation expense and higher interest expense. Additionally, higher depreciation, depletion and amortization impacted operating earnings. These factors were partially offset by higher production volumes and higher realized commodity prices before hedging. Net earnings in 2010 were about $1.5 billion or $2.03 per share diluted, compared to about $750 million or $1 per share diluted in 2009. Our net earnings were affected by the net impact of higher realized and unrealized hedging gains, as well as lower non-operating foreign exchange gains. Unrealized after-tax financial hedging gains were $634 million compared to losses of $1.35 billion in 2009, while realized after-tax hedging gains were $808 million compared to $2.3 billion in 2009. 2010 non-operating foreign exchange gains were about $200 million after-tax compared to $334 million after-tax in 2009, primarily due to foreign exchange on U.S. dollar GAAP. The magnitude of the impact these items have on net earnings reinforces our belief that operating earnings are a better comparative measure of our performance between periods because they remove the variability associated with unrealized mark-to-market accounting gains and losses and non-operating foreign exchange gains and losses. On the cost side, operating costs were $0.77 per thousand cubic feet equivalent, and administrative costs were $0.30 per thousand cubic feet equivalent. Both these items decreased year-over-year, primarily due to operating efficiencies, increased volumes and lower long-term incentive costs. Depreciation, depletion and amortization or DD&A was $3.2 billion in 2010 versus $2.8 billion in 2009, primarily due to increased volumes and a stronger Canadian dollar. Foreign exchange accounted for about $120 million of the increase. Upstream DD&A expense is determined by the applicable depletion rate and the associated level of production. EnCana utilizes full cost accounting where rates are determined and costs depleted on a country-by-country basis using total proved reserves based on a forecast price case. Currently, EnCana's depletion rate is higher than some of our U.S. full cost accounting periods as a result of significant cost write-downs recorded by those periods in 2008 and 2009. These write-downs were primarily due to differences in price forecast used to determine the proved reserve quantities required under U.S. GAAP when compared to Canadian GAAP. Subsequently, the impairment booked by our U.S. peers allows them to apply a lower depletion rate. As a comparison, EnCana's 2010 DD&A rate, if it were reported on a U.S. GAAP basis, would have been approximately $1.60 per thousand cubic feet equivalent versus $2.60 per thousand cubic feet under Canadian GAAP. For more information, please refer to Note 21 in our 2010 year-end consolidated financial statement. These financial statements will be available on SEDAR and on our website later next week. Our debt metrics remained very strong in 2010 with a year-end debt to capitalization ratio of 31% and a debt to adjusted EBITDA ratio of 1.4x. Both metrics improved from year-end 2009 and were well below our targets of less than 40%, and less than 2x, respectively. For 2011, we have chosen a conservative investment plan that will help us to maintain our financial strength during this time of continued low gas prices. With cash and cash equivalents of $0.6 billion, $5.1 billion of unused committed bank credit facilities, strong investment grade credit ratings from three agencies, manageable upcoming debt maturities of $500 million in November and the anticipated culmination of the PetroChina transaction, we believe that EnCana's financial position will continue to provide us with ample flexibility to manage our large portfolio of opportunities. I will now turn the call back to Randy.

Well, thank you, Sherri. As you've just heard, despite the low natural gas prices that continued throughout the year, 2010 was another year of strong operational and financial execution for EnCana. And with the announcement of our Co-operation Agreement with PetroChina, I feel confident that despite the persistence of lower gas prices, we will make significant strides in 2011 towards advancing our goals of increasing our productive capacity and gaining recognition of the underlying value of our assets. As we further refine our 2011 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 are best at, the identification and development of resource plays and a disciplined capital and project execution. We continue to high-grade the portfolio and maintain financial and operational flexibility while delivering on our commitments. Since the redefinition of EnCana at the end of 2009, we continue to demonstrate our ability to deliver solid cash flow and earnings, pay a stable dividend and reduce costs and continue to invest in the underlying productive capacity of our huge resource portfolio for future years' growth. And we have indeed been able to do this in a period of low natural gas prices. Our 2011 capital program appropriately balances our priorities to grow production over the long term and advance strategic priorities on managing the realities of current commodity prices and continued focus on reducing costs. I'd like to take this opportunity to welcome Mike McAllister to our Executive team. Mike currently leads our Canadian Deep Basin business unit, and was instrumental in achieving the Co-operation Agreement we've achieved with Petrochina. Mike's involvement at the executive level will provide strong leadership and oversight of this joint venture. 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 Fairbanks with Bank of America.

I had a question for Jeff, if I could. I wanted to see if you could add some details to your plans for the Haynesville in 2011? And secondly, there seems to be a bit of controversy out there on what the Haynesville returns actually are like. I wanted to give you an opportunity to say how you see the returns on your lands versus the rest of the portfolio, if you could.

Andrew, Jeff Wojahn here. Plans for the Haynesville for the upcoming year will be to transition from primarily a land retention strategy to primarily what we call a gas factory, or multi-well pad drilling scenario. And I think, when you talk about the economics and what the industry has gone through, we have gone from delineating the entire basin, so to speak, through land retention drilling. And certainly EnCana and our partner, Shell, have undertaken it for fairly significant effort over the last 30 months to go through that exercise. And what we've learned is, obviously, that there are fair quality reservoir areas and more challenging reservoir areas. And when I speak of more challenging reservoir areas, in general, clay content and more material for a geological point of view, of the Haynesville increases to the north and into the West. And in those areas, we've had dispositions this year, and also as you move east and more deep into the basin, we tend to be challenged by high pressure, high temperatures, which the industry is working on from a technology point of view, as well as faulting and structure. And into that end, we've been able to evaluate some of our lands, and we revised, we've allowed 12,500 acres to expire in some of those challenging environments. So that's kind of the exercise we've gone through and I think when we look at it today, we think we have a very comprehensive understanding of the priority of drilling opportunities moving forward. And we feel that those activities are leading opportunities within our portfolio, certainly in the tri-gas component of our portfolio. Obviously, it plays at our liquid advantage today, tend to be the cream of our crop from a portfolio point of view. Earlier, certainly internally in the company, we talked about our ability to achieve a $4 supply cost throughout our operations with the long-term target of achieving $3 supply costs. And I see no reason that the Haynesville cannot be leading the company or being part of the company's desire to move to more than $3 supply costs as we move to gas factory drilling and more efficient operations than we have today.

Would you see long-term production still reaching or exceeding the one Bcf a day level?

Absolutely. When we look at the resource potential of our land and the reserve recognition that we've been able to achieve through the land retention drilling, we see the Haynesville being a very strong contributor to not only the U.S. division's growth, but also the corporation from a long-term perspective.

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

So just maybe a couple of MIDI questions up front. With the proceeds of $5.4 billion, will there be any tax impact, or is that a clean number in terms of the proceeds that will accrue to you?

Greg, there will be some tax implications resulting from the sale of the shares of the subsidiary, likely to be a capital gain type transaction. Sherri Brillon can expand on this.

Yes, Greg. This will be a structured transaction. So under the Co-operation Agreement, it's currently contemplated that EnCana's going to sell to PetroChina all of the shares of a wholly-owned operating sub that holds 50% interest in the Cutbank Ridge business asset. And so what we're expecting is that the tax on the capital gains. We'll make every effort to try to minimize that from the disposition of shares by using our existing capital losses.

Is it a material number, do you think at this -- I mean, you've obviously looked at it, I'm sure of it.

Is it a material number? Well, I think once you do the math on the capital gain, you'll see that the number looks reasonable in light of the size of transaction.

I guess the other big question is just timing in terms of cash flows and so on. And I understand that PetroChina then has the option for a fixed, a lump sum payment or payments over time. Obviously , that's going to impact the potential for you to flow some of the proceeds into a share buyback. Just wanted to understand on what you're thinking, or is it still a little bit too soon, given that the transaction really hasn't been consummated?

I'd say that is the case right now. We would prefer to be much more clear on the details of use of proceeds following the close of the transaction. And we're fully expecting that the transaction will close by about mid-year. The biggest hurdles to overcome are the Canadian, and from a time perspective, it's the Canadian and Chinese regulatory approvals.

But Randy, no change of philosophy, though, insofar as maintaining per unit growth? I mean, you've done that in the past where you've put money into share buybacks or in the dispositions, No change there from this perspective, right, on this deal?

Yes, I would expect you would see a consistency in behavior.

The other question I wanted to ask you is just around the Montney. So obviously you've sold the lion's share of the production. But there's still a significant resource. What does that profile look like when you actually get down to business? Like just from a production standpoint, would you expect to replace that $250 million a day within three or four years? I just want to get an understanding there.

We have developed some plans, but we're not really ready to fully disclose them. But what we can say is that we will increase our pace of developments at a rate which is much higher than otherwise would have been. But it will also be a very orderly growth in our pace of development as we have to put in place in the years ahead, a considerable additional infrastructure.

And maybe just the last one, around the Horn River. So I understand the comments around scaling back activity levels a little bit, but what does 2011 look like, just sort of your activity levels from the Horn, and where would you expect to exit '11?

Mike Graham will provide some insight at that.

We're a little bit light, we talked about on our production coming out of the Horn River. So we averaged in 2010 at about 29 million cubic feet a day, and we're hoping to be about 50 million cubic feet a day. We're probably a little over 75 million cubic feet a day now out of the Horn River. The wells are performing wonderfully. The beauty of the Horn River is that we really do have a low decline or much lower than most shale plays in North America. And we still think we can get estimated ultimate recovery on a per well basis right up to 15 Bcf per well, which is really quite amazing. So it's good that way. For 2011, our capital, we have a partner, 50% partner with Apache there. So we think we're going to probably scale back our program a little bit there, but still a sizable program. And we would expect to average somewhere around a little over 100 million, about 110 million cubic feet a day for 2011.

Is that net, Mike?

Yes, all those numbers are net.

And what do you think the exit looks like in '11?

Well, it'll somewhere north of 180 million. It's probably somewhere, we said to close to 200 million in the past, but I don't know if it will be quite that high if we scale back a bit. But it's still probably north of 150 million cubic feet a day, net again.

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

Question for Jeff on the Haynesville. As you start to move into the manufacturing process, would you also be doing a bit more work on the Mid-Bossier and trying to get both sections?

Yes, absolutely. Across EnCana's land base in the Haynesville, we see tremendous potential in the Mid-Bossier. And certainly as you move south and west across our land base, the quality of the Mid-Bossier reservoir increases. And when it comes to the land retention strategy, our primary objective was to save the land. But we haven't done as much work as we would have preferred or like to have done in the Mid-Bossier. But I think moving forward, we're going to move towards an equal effort in regards to production out of the Mid-Bossier.

And then you guys had mentioned last year at the investor day that you planned at some point to test the 40 acres basin. Have you had a chance to do that yet, given the land retention program, or are any plans coming up to try that out?

The gas factory results that I've mentioned earlier in my comments were on 88 respacing. That's the tightest we've drilled to date.

And any plans to test 40 in the near future, or is that further down the road?

Thank that's further down the road. I think when we look at our inventory, we have a lot of 80-acre drilling do before we have to worry about down spacing from there.

Your next question comes from the line of Andrew Potter with CIBC.

Just a question on gas marketing. When these assets become jointly operated, I guess you've marketed the gas together, and I guess the second part of that question is, can you comment at all in terms of the interest or PetroChina's interest in terms of LNG exports, and whether you guys would participate in that if they did decide to go that route?

Our current agreement specifies our allowance EnCana to market the gas for up to the first five years, and then after that period of time, PetroChina would be responsible for its own. We fully expect that they will advance their capability much sooner than that. In the longer term, they have expressed a desire to be involved in the North American LNG market, but we have not discussed any details of that at this point in time. We are, of course, very interested in the expansion and the creation of an LNG export market from North America. And we do think it makes a tremendous amount of sense for that market to be linked to the Asian market from a proximity point of view. And so we look forward to supporting that in any way we can.

And then one other question if you could maybe comment at all on the potential size of other JVs. I mean presumably, we're not looking at another $5 billion deal. But maybe a little bit of color roughly on how they big they could be. Then specifically the Horn River, I think you'd mentioned you've been discussing with Apache to split up the JV lands, and I guess how that's proceeding? And is that a barrier to doing JVs in the Horn River as it stands right now?

There's a lot of questions there which we don't have, I'd say, a lot of answers at this point in time. We are exploring the possibility of doing additional joint ventures on significant parts of our land base. We do like to have a fairly good understanding of the value of the place before we put them out. But we are sort of testing it right now in terms of what we might be able to do on a number plays, both in Canada and the United States. I would say, though, that because of the deals that we've already put in place, both in Canada and the United States, they have generally met our longer-term objective. And so, our speed at which we might enter into more agreements might be more paced at this point in time.

. Your next question comes from the line of Ross Payne with Wells Fargo.

On the payment of the $5.4 billion, my first question is, are there any performance parameters related to earnings of $5.4 billion?

There are no performance parameters. Basically, PetroChina has the option of paying the entire amount upfront or to have some of it paid over time. But at this point in time, we're not able to provide the details of that. But the PV of it, basically, it's the $5.4 billion.

So it could be lower?

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

Can you speak more specifically regarding the breakout of oil versus gas versus NGLs you're seeing in the Collingwood and on the Piceance Basin and the Niobrara? And any additional color on the well results and well costs you've seen so far?

Probably not. I'm going to turn that over to Jeff. The Collingwood, it's really early days. We just know the characteristics of the reservoir, and we have had some results that indicate some liquids-rich in oil areas, but not enough to provide us with the ability to make any predictions. And I'd say in the Piceance Basin, I'll turn it over to Jeff to answer.

Brian, it's Jeff. Yes, Randy's absolutely right on the Collingwood. We're still cutting cords and trying to understand the reservoirs in Michigan, in the Collingwood. It's a very underexplored area, and very in its infancy from an understanding point of view by the industry and by EnCana. In the Piceance Basin, it's the same thing, like the amount of information that we have to date in regards to the basin itself from a liquids content point of view is something that we're trying to understand. So I think there's more to come on that. I talked earlier in my comments that we drilled a few wells to date gathering information. And I think on the first half of the year, we'll be gathering a little bit more information to answer specifically that question that you have. And I think the economics and the opportunity that present itself in that basin are very much a function of liquids content moving forward. So more to come on that.

And then when we think about a more big picture, how material do you see your liquids production becoming based on what you know now about our portfolio, and how willing or you to consider making acquisitions that could add liquids exposure or frankly gas for that matter, given that you used to have a stronger balance sheet post closing the PetroChina JV?

What we'll do is, of course, look at our interpretation of the risk return associated with any acquisition we make, whether it's a land acquisition or property acquisition. And we'll also look at what the risk return expectation is in any exploration activity that we undertake. We do know that we have some fairly significant potential on our lands for liquids-rich plays. But we are, again, at a very early stage on many of these plays, and results from our own activity and from other industry activity will probably give us a better sense of what the potential is, I would say, even as this year unfolds. So it maybe a little bit early right now, but I think the potential is significant in the future.

Just following up on the last part of the last question. You mentioned that PetroChina has the option to potentially pay the $5.4 billion over time. Can you just add a bit more color as to when that decision needs to be made, and what is the longest period over which you would receive the proceeds?

I can't really provide that detail to you right now. But it's a portion of the $5.4 billion can be paid over time. And that decision will be one that PetroChina will have to make. And I expect that they won't make that decision until closing.

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

Can you give me an idea of what the year-end inventory of wells yet to be completed was, split by division?

I think Jeff and Mike have that information with them. I'm not sure if they do, but --

Mark, I don't think in wells, I think in months. But in several places where we are sure of the completion services like the Piceance Basin and the Haynesville, we have -- I think in the Haynesville we have several months' wells, which is maybe a little bit longer than we'd like to carry. And in the Piceance, I think we have four or five months of inventory. So at a regular pace. But specifics, I can get back to you on.

I think what we're really saying is, we did get backlogged little bit in the Haynesville and in mid-year, and Piceance Basin may be a little bit later in the year.

And on the Canadian side of the border, Mike?

We don't have a lot as well, Mark. We've probably got somewhere in the order of 50 to 70. But I can tell you in our CBM, we really had, I think, a lot of operating, as we were talking about, wet weather we had in Alberta over the summer. So we really got sort of backlogged. But in the last part of the year, we actually drilled about 600 wells in CBM. And that production is starting just to come on as we speak here over the next quarter or two. So we're seeing very strong volumes out of our CBM now and should have a great year and in 2011.

So Mark, sort of the answer to the broader question is that we were seeing some equipment -- seeing some completion equipment shortages in the U.S., which we are in the process of resolving. In Canada, it was more of a weather-related issue.

Randy, can you give me an idea how much Duvernay acreage you acquired, and at what cost?

I'm going to give that to Mike Graham to answer.

Well, Mark, I tell you, it was actually a pretty good year to buy land in Canada. And we bought a lot of land in the 500,000 net acres at a cost of about $650 per acre. Like Randy alluded to, a lot of that is on liquids-rich plays, plays like the Duvernay areas and the Montney where there's a lot of liquid areas, and the Deep Basin of Alberta, the well rich and the Fahler. So we're really adding to our land position relatively cheaply. We're not specifically seeing our increased position in the Duvernay. It is very material to EnCana. And we're out there, we drilled the well into an island. And we currently have the well on test. So we're not going to say too much until we probably get out of the first quarter.

Randy, it occurs to me that there are certain elements of establishing the arrangement with PetroChina where the interest of the two parties may not be entirely congruent, relating to activity levels, relating to dividends back to respective parents, potential problems and issues on a 50/50 type arrangement. Can you talk a little bit about what you're thinking is on that subject, and how it would be handled?

Well, whenever we have joint venture arrangements, we always have to deal with those kind of general issues, not maybe not the dividend one, which I haven't really thought about. I don't necessarily think it applies either. But with respect to -- the biggest issue is always about the pace of development and then the respective size of the capital program. And we're very fortunate to be doing this deal with PetroChina, a very financially strong corporation. And because this is one of the lowest-cost plays in our portfolio, it's the one that's most likely to attract an investment. So in that regard, I think we're fairly aligned. We both believe that this property has tremendous resource potential and has the potential to grow at a significant rate. We may not be fully aligned ever on what our expectations are going to be for North American natural gas prices and such. But I think in many areas we're going to have a fairly strong alignment. And when these are the kind of issues over the next six months as well. We will have to start putting them into the operating agreements.

Can I ask you how you're going to account for the joint venture on the books? Is there going to be equity, it proportional consolidation? What are you going to do in that regard?

I'm told it's proportional consolidation.

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

The 250 million cubic feet a day that PetroChina is getting, is that included or excluded from guidance? I guess the question is that your production CapEx you put out for '11 to date, is that going to be adjusted when this deal closes?

Our guidance is, with respect to the current business and should we be successful in closing the deal with PetroChina, then we would make a new adjusted guidance at the time.

So does that mean we could maybe see increasing CapEx spending at all?

It means that pretty much everything is open at that point in time. We'll probably give more guidance on number of outstanding issues.

[Operator Instructions] Your next question will come from the line of Amanda Fraser with allnovascotia.com.

You'd mentioned that the PFC won't arise in Nova Scotia until Q3, why is that?

Mike Graham here, Amanda. Maybe just to talk about Deep Panuke, we completed our pipeline to shore. We completed our drilling and completed programs, so everything is pretty much done there. What we know in terms of our capital increase, we've gone up a bit in capital numbers, we think about $960 million overall. It's up a little bit about 20% kind of from where some of our original estimates in 2008, 2009,. FX weather delays and a few other issues on there. So not too bad overall. The production field center is getting very close to being done. It's like 95% done in Abu Dhabi, and there's been a sale out of the Middle East here in about six weeks. So it's coming our relatively quickly, and I think it takes 40 or 50 days to get over the Nova Scotia. So it's coming real quick. We do expect to get first gas production in the second half of the year. We've actually budgeted for it to start-up in Q4 of 2011. And we're excited to see production come over. We're going to bring it on in about 250 million cubic feet a day, which is around our full capacity on Maritime Northeast. But it'll be actually able to flow if there's interruptible space in the pipe, maybe right up to close to 300 million cubic feet a day. When we tested the wells out there, Amanda, and there are no surprises, all the production wells looked very strong. So we're excited to see production coming on here in the second half of 2011.

And you also mentioned, too, that you are budgeting $100 million to spend in 2011. What will that be for?

Most of the costs, like I say, Amanda, are complete now. Really, all we have to do with it is hook the well up to the production fuel center. So that's about it. It's just the cost to hook the wells up to the production fuel center. So out of the $960 million, only $100 million more to spend.

The fact that it's not going to arrive here until Q3, does that leave enough of a window in the first half of Q4?

Yes, David Tomlinson [ph 01:22:34]says yes, that will be the case. So we're pretty darn comfortable that we can we'll have gas flowing in Q4 of this year.

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

In the press release and today, EnCana had said that it will be the operator of the project, it will be the initial operator of the project. I'm wondering if you can sort of explain why it's just initial, how long that initial period will be, and if that means PetroChina could eventually take over?

Initially, EnCana will continue to operate. And in the long term it will likely be EnCana people that are dominantly part of the operating team. It doesn't mean that -- it'll be operating basically under the guidance of a management committee, represented 50% by EnCana and 50% by PetroChina. It's really just trying to explain that after a couple of years after closing the deal, we will evolve into a new sort of corporate form, which has not really been disclosed yet nor fully discussed.

And my second question, when Sinopec invested in Syncrude and when KNOC bought Harvest, both of those companies had to make spending commitments to the federal government to get approval, some as far as 10 years out. I'm wondering if PetroChina has its spending commitments in line, and how they fit into this deal?

I'm certain those have not been discussed at this point in time.

They haven't been discussed with EnCana?

They haven't been discussed, I would say, with anybody at this point in time. So we'll be just filing our application for investment in Canada shortly.

And my final question is, with the initial prediction that EnCana would strike joint ventures between $1 billion and $2 billion per year, I'm wondering why EnCana went so far beyond that this time and has and continues to pursue joint ventures?

The $1 billion to $2 billion per year, I was talking at that time in reference to a five-year plan. And so that would be between $5 billion and $10 billion of third-party money coming into the corporation. So this represents a significant portion of that, it doesn't represent all of that. And at that time, it wasn't anticipated that we would have a sale of production as part it -- so you have to kind of back that up, too. So the part which is really part of the joint venture deal is a bit smaller, although I can't provide you with those exact details. But back to your first question, Carrie, our anticipation is that there's going to be a substantial amount of expenditures made by both Encana and by PetroChina and that we will have -- that the level of expenditure will be much higher than it would've otherwise been had EnCana just been developing the assets on their own.

So just to clarify, you expect EnCana will spend more now than that it has a partner rather than developing on its own? Is that because of the pace of development?

What I'm saying is in aggregate, it'll be significantly more, whether or not EnCana spends more now that we have two 50-50 partners in the deal. We expect that it will build to a much higher rate of investment at a faster pace of development than we would have otherwise done on our own.

Oh, spending on the project rather than on EnCana's spending?

Right. I can't comment on EnCana's spending specifically.

So is the $5 billion to $10 billion of joint venture over five years, is that still sort of the goal?

It certainly is something we are thinking we have the opportunity to do. Relative to what we've done today or what we have done in the past in aggregate what we've done today, we've substantially achieved that target already. And so, our belief is that we have an opportunity to do quite a bit more in our portfolio. But not all of the opportunities that we would like to conduct joint ventures on are at the same state of maturity and we think the value recognition, once you get to a higher state of maturity, is a better proposition.

Your next question comes from the line of Tonya Zelinsky with Upstream International.

I just want to touch back on what was discussed earlier regarding LNG, and I'm wondering what role LNG played when looking at potential exports and making this deal with PetroChina. Were you looking ahead and thinking this would be something that could be viable, working this deal out?

We think it will be an interesting additional component to the deal. We've talked about the need for export LNG capacity in North America since the recognition of the abundance of natural gas in North America and the acknowledgment that we have multiple points of import for LNG, but no real export points for LNG. And to make the market more fluid and functional, we think it needs both. And we think there is now, a capacity from the resources that exist in North America to have a substantial amount of LNG on the continent. And more specifically, we think there's an opportunity with Asian players who demand more natural gas in their energy portfolios.

How far ahead into the future are you looking with this? Do you have a tentative timeline in place?

Realistically, to bring additional LNG into North America, you've got to be looking at five-year sort of time frames for the first ones and 10 to 20 years out, we guess if you'd like to have a significant quantity in North America.

Your next question comes from the line of Elsie Ross with The Daily Oil Bulletin.

To follow-up on the LNG question, would you be looking at providing getting some sort of access to the Kitimat project?

There's obviously an opportunity to supply natural gas to that project. We haven't been in specific discussions with that at this point in time.

So it's something you'd be pursuing?

We're looking at LNG across North America, so of course we'd be looking at that.

And the other question is, just a really sort of basic little question. How many CBM wells are you going to be doing in Canada this year?

Mike Graham here. We did actually drill about 1,044 CBM wells in 2010. So we were actually very active in CBM. We had a great program and it still continues to compete nicely in our portfolio. So right now, we haven't actually set our capital -- -- well, we have set our capital budget, I guess, but we haven't figured out each and every one of our resource plays. So it will probably somewhere in that level, maybe just a take down from that. But I can tell you over the last several years, we've been very active in CBM, anywhere from 500 to 1,000 wells a year. And we think we have an inventory of somewhere around 16,000 wells that we could drill in CBM still.

Just mainly Horseshoe Canyon?

Yes, that's right, Elsie. Essentially, all of them are in Horseshoe Canyon. We are doing some small pilots in the Mancos as well.

Your next question comes from the line of Marcus Earnish [ph] with Calgary Sun.

I'm sorry to belabor this LNG business, but Randy, could you perhaps tell me what role, if any that eventual gas exports to Asia play in reaching the deal in PetroChina? Was it part at all of your discussions?

It wasn't part of our discussions at all, although I fully understand and appreciate the desire for PetroChina to link up with LNG in North America.

I'm just trying to figure out that PetroChina's rationale. Are they trying to gain expertise by partnering with you, or is it the export opportunity of gas to Asia? But I guess that's the question to best ask PetroChina?

I think you've answered that.

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

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

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