Corey B. Bieber - Vice President of Finance & Investor Relations Allan P. Markin - Chairman and Member of Safety, Health & Environmental Committee Steve W. Laut - Principal Executive Officer, President and Director Lyle G. Stevens - Senior Vice President of Exploitation Douglas A. Proll - Chief Financial Officer and Senior Vice President of Finance

George Toriola - UBS Investment Bank, Research Division Greg M. Pardy - RBC Capital Markets, LLC, Research Division Robert S. Morris - Citigroup Inc, Research Division

Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2011 Fourth Quarter and Year-end Results Conference Call. I would now like to turn the meeting over to Mr. Corey Bieber, Vice President, Finance and Investor Relations for Canadian Natural Resources. Please go ahead, Mr. Bieber. Corey B. Bieber: Thank you, operator, and good morning, everyone. Thank you for attending this conference call, where we'll discuss our fourth quarter and annual 2011 results, which was included in our press release issued earlier today. Participating with me today are Allan Markin, our Chairman; Steve Laut, our President; Doug Proll, our Chief Financial Officer; and Lyle Stevens, our Senior Vice President of Exploitation. Before I start, I would like to refer you to the comments regarding forward-looking information contained in our press release, and also note that all dollar amounts are in Canadian dollars, and production and reserves are both expressed as before royalties unless otherwise stated. I'll make some initial comments before I turn the call over to the other participants. I believe the fourth quarter of 2011 was very strong from both an operational and financial perspective, with record quarterly crude oil drilling, total crude oil and NGLs production, total BOE production, and of course, record quarterly cash flow. During 2011, we also replaced almost 4x of our production on a 2B basis and exit with a very impressive 21.4-year proved life -- proved reserve life index or 33.3-year proved and probable reserve life index. I believe that as you hear Allan, Steve, Lyle and Doug talk about the company's prospects, diverse asset base and strong balance sheet, you will agree the company is well positioned to continue a strong track record of profitable growth. I'll now turn it over to Allan to give his thoughts on the quarter. Allan P. Markin: Thanks, Corey. Good morning, everyone. We are delivering. We ended the year strong, achieving record quarterly cash flow from operations of $2.16 billion, driven by quarterly production of over 657,000 barrels per day, a record. In 2011, we economically grew our diverse asset base, increasing gross proved plus probable crude oil, bitumen, SCO and NGL reserves by 10% and increasing gross proven plus probable natural gas reserves by 6%, resulting in total company gross proved plus probable reserves of 7.5 billion BOE. Our total proved plus probable reserve replacement ratio was 390%. Our dedicated team delivered strong results from our North American crude oil E&P operations in 2011. Our light oil and primary heavy oil operations executed record drilling programs and achieved 10% and 11% average annual production growth, respectively. At Pelican Lake, response to the polymer flood continued to be positive, increasing gross proved crude oil reserves by 15%. And we focused on maximizing oil recoveries through effective well configuration and injection techniques. Thermal in situ operations achieved 9% production growth as a result of optimizing steaming techniques and low-cost pad developments at Primrose. We continue to advance the development of our high-quality SAGD projects through an active strat well program and through construction on Kirby South Phase 1. In 2011, we were selective in our approach to developing our natural gas assets and focused primarily on liquids-rich plays in Northeast British Columbia and Northwest Alberta. At Septimus, our unconventional Montney shale gas play, we continued to see results that exceeded expectations. And in the fourth quarter, we completed the tie-in to a deep cut facility to increase liquid recoveries. Internationally, we continue to optimize operations in the North Sea and sanctioned an infill drilling program at Espoir in offshore Africa targeted to begin in late 2012. We are committed to creating value. We are confident in Canadian Natural's ability to generate significant shareholder value in 2012 through our oil-weighted growth. We will and are continuing to deliver strong operational discipline. Over to our President, Steve Laut. Steve W. Laut: Thanks, Al, and good morning, everyone. As both Corey and Allan said, the fourth quarter was a strong quarter for Canadian Natural. Cash flow is up 30% over Q4 2010 with strong production performance, driven largely by a very strong oil growth across the company and the solid return of Horizon production in Q4. In Q4, Canadian Natural continued to execute our strategy based on effective and efficient operations and optimizing capital allocation to ensure we maximize our return on capital, generate significant free cash flow, maintain our strong balance sheet through the price cycles and transition our asset base to a more sustainable, long-term asset base and provide the ability to increase dividends on a consistent basis. Canadian Natural is one of the few companies in our peer group that has a strong, well-balanced and diverse asset base with significant upside in each component of our business. Our asset base, combined with our effective business practices and people, are Canadian Natural's competitive advantage. We have, on a consistent basis, been able to effectively allocate capital. As a result, we generate significant free cash flow and maximize return on capital to the long run and throughout the commodity price cycles. Today, with strong oil prices and low gas prices, Canadian Natural continues to allocate capital disproportionately to oil projects. In 2012, we will deliver significant production growth. Light oil and NGLs in Canada will grow by 17%, primary heavy oil will grow by 16% and thermal in situ heavy oil will grow by 10%. And although we stumbled out of the gate, we expect solid Horizon production for the remainder of the year. In addition, we're investing significantly in the future production and value growth in a disciplined, cost-effective manner which also provides us a high level of capital flexibility. Our thermal in situ program will see production increase from 100,000 barrels a day to 480,000 barrels a day of low-cost, high-value heavy oil production. At Pelican Lake, our leading edge polymer flood continues to generate significant value for shareholders as we develop the polymer flood across the pool. And at Horizon, our expansion plans to take production from 110,000 barrels a day to 250,000 barrels a day, and ultimately, 500,000 barrels a day of light sweet 34-degree API crude are unfolding as expected. We also we have a vast natural gas assets, which when gas prices strengthen, will provide the opportunity to unlock significant value for shareholders. As we're a heavily weighted oil company, I'll briefly comment on the oil markets and the volatility we have seen recently before discussing the status of our operations across the company. Let me start first with the Brent-WTI differential, which has been very wide, and as is widely known, due to logistical constraints at Cushing, caused in large part by the increasing Bakken production. In our view, this is a short-term situation. We expect, when the Seaway reversal comes effective June of this year, this differential to narrow substantially. And then we'll turn to more typical differentials in early 2013 as Seaway is expanded to 400,000 barrels a day. The return to more typical Brent-WTI spreads will lift all oil prices, light and heavy. On the heavy oil side, we have seen significant heavy oil differentials widen significantly. This, in our view, is a short-term situation caused by planned and unplanned refinery outages. It has greater than 350,000 barrels a day of planned and unplanned of refinery outages in PADD II, Canada and the West Coast in April and May, which run largely at heavy oil slate. The loss of demand for this period is the key reason why heavy oil differentials have widened. Considering Canada produces about 1.7 million barrels a day of heavy oil, with 350,000 barrels a day out of service in the short term, it's pretty easy to see why heavy oil differentials have widened significantly. It is also clear that they will return to previous levels once these refineries come back on. Looking forward, we see the expansion of heavy oil refinery capacity of approximately 300,000 barrels a day in PADD II between the end of 2012 and mid-2013. That will help offset incremental heavy oil supply in 2012 and 2013. In summary, we expect to see significant improvement in our all net backs in the second quarter of 2012 and beyond. I'll now walk through each of our assets, starting with Horizon, which accounts for just under 17% of our production, that has of late and rightly so garnered lots of attention. Let me first give you a brief description of events that have happened in the first quarter and update you as to where we are today, talk about concerns regarding our operations' reliability, and finally, update you on the ongoing expansion of Horizon. Firstly, January production was less than expected and was down from the expectations for 2 reasons: oil preparation plant or OPP issues, and a leak in a blowdown line in primary upgrading. As you know, we are scheduled to complete commissioning of the third OPP in early December and then start up the third OPP. Given the risks of the completion with Christmas approaching, start-up of the third OPP was deferred until after New Year's. Confirming our decision to -- for start-up, the January start-up did not go as smooth as expected. This delay in the third OPP start-up also extended the maintenance on both OPP 1 and OPP 2, which caused some downtime and production shortfalls in January. We also had a minor leak in a blowdown line in late January that required a controlled shutdown in primary upgrading. The shutdown lasted 3 days to complete the repair. And absent the January OPP issues, we have been running at roughly 117,000 barrels a day in January. So all things being equal, this type of shutdown would've caused production to come in just under 110,000 barrels a day for January and is part of our budget downtime we anticipate for the year. The current shutdown occurred as we were bringing the primary upgrading plant back up after repairing the blowdown line. In this case, we pulled in a slug of water from the drill bit tanks, that resulted in damage to the fractionator trees. Taking a slug of water into a fractionator tower should not happen. Unfortunately, taking the water into the fractionator is not uncommon in the oil sands, as a drill bit can't contain water. Our process and procedures are designed to prevent water from entering the fractionator. And if water does make it to the fractionator, minimize any damage. In this case, we believe the damage to the fractionator was minimal. And now we would like to be shut down for a short time to repair trades in the fractionator that likely have been dislodged from their supports. This belief was based on a fractionator performance after the event and gamma scans completed after the incident. At one point, we contemplated running to the 2013 turnaround and not taking a shutdown. However, it would have been more expensive to replace poisoned hydro-treated catalysts caused by poor fractionator performance. And it is unlikely the catalyst will make it to the 2013 turnaround anyway. As fast decision was made on February 2 to take what was believed to be a relatively short shutdown to replace some trees in the fractionator. Once we cooled down the fractionator and we were able to assess the damage, it became clear that the damage was significantly more than -- more severe than anticipated. At that time, we issued a press release outlining the time to complete repairs. The fractionator is designed for Phase 2 rates of 250,000 barrels a day. As a result, the performance impairment was less than expected for this type of damage, as we were running at just under half the designed rates. The repair to the fractionator is on track, and we've made significant progress on our repairs. And we are tracking to our original expectations to be back onstream somewhere between the middle and the end of March, returning to full production rates at that time. The cost to repair the fractionator is roughly $35 million. As you expect, this instance has caused us to review and reevaluate the reliability of our operation going forward. On investigation of the incident, it became evident that our lower levels of operating discipline has increased significantly in the past year, and our procedures are appropriate and effective. There was a gap in our critical start-up guidelines. Probably most significantly was the allowance with the ability within our guidelines to conduct critical start-up activities on the night shift, in this case, at 1:30 a.m., when operation supervision and leadership, as well as technical process engineering expertise is thin and tired. Clearly, this is a gap that is easy to close and has been closed, with restrictions for the critical start-up activities to occur only on day shift, unless a fresh team of operation supervision and engineering expertise can be mobilized. As a result of this gap, operations' personnel missed steps in the start-up procedure that should not have been missed and would have prevented the damage caused by the water pulled in the drill bit tanks. In other words, while pulling water from the drill bit tanks is not uncommon, I believe that had we closed this small gap in our guidelines, which is now closed and has become a requirement, this instance would have been prevented. Going forward, we believe we're in good shape, and there will be a continued emphasis, an increased emphasis on operations discipline. In order to increase our confidence and to cover all the bases, we have brought in an independent third party to do a critical review of our operations, our asset integrity, reliability and our operations discipline. This is a relatively new approach but has been used in refineries, chemical plants and the aviation industry. The goal is essentially to identify any potential issues, hazards or gaps before they occur. Going forward, we expect Horizon reliability to be enhanced significantly with the commencement of full operations at the third OPP. This will provide us with the ability to ensure we always have 2 fully running OPPs. Historically, the OPPs, due to the brute force work undertaken in the OPP, had given us the most issues with reliability, as we have limited intermediate drill bit tankage available to maintain steady and consistent feed to the upgrader. Historically, we've been slowing down the PDD upgrader, or in some cases, putting the upgrader into circulation until the drill bit tanks' levels have increased and then increased to upgrader rates. To carry this further, continual rate changes and start-ups are higher, on an upgrading equivalent, which in itself creates reliability issues on the upgrader. With the third OPP, we expect to be able to keep the drill bit tanks full, and thereby, keep the upgrader running at steady, consistent rates going forward. We anticipate the third OPP will be ready to go once we start it back up. However, it is a new plant and did not get much run time before this outage, so it's likely there'll be a few kinks left to work out once we start up. You have noticed that we are taking a very conservative view on Horizon production guidance for 2012. To put all our production guidance in perspective, depending on whether we start up this mid- or late March, we'll be required to deliver on average, from April through the rest of the year, between 97,000 barrels a day and 103,000 barrels a day to achieve the low end of guidance. In the fourth quarter, with only 2 OPPs, we averaged 103,000 barrels a day. To achieve the high end of guidance and again, depending on start-up in mid- or late March, we will need to average 110,000 barrels a day to 116,000 barrels a day to achieve the high end in our guidance. In January, absent OPP issues, we were running 117,000 barrels a day. Therefore, our revised guidance is conservative, and we should have no issues achieving the guidance range. Turning to Horizon expansion. Our plan is to expand from 110,000 barrels a day to 250,000 barrels a day, and then ultimately, 500,000 barrels a day of light sweet 34-degree API crude with no declines for 40 years. As you know, we've broken the expansion into 5 parts with 46 different pieces to ensure cost control and capital flexibility. The expansion to 250,000 barrels a day will add significant value for shareholders, not only in the increased production, but will result in a significant reduction in operating costs and increased plant reliability, a key and often overlooked component of expansion economics. Currently, with the exception of the OPPs, we have a single-train operation. With the expansion, we will have in most cases a 2-train operation, providing increased operations flexibility and significantly enhanced reliability, as we will be able to swing from train to train to perform maintenance, thereby reducing impacts to production. Expansion will also have a significant impact on operating costs. With the exception of the mining costs and natural gas costs, our operating costs are largely fixed with the biggest component being labor. Mining costs are roughly $8.50 a barrel at the current time. And with the expansion, we should see some small efficiency gains. Natural gas costs are roughly $2.50 a barrel, assuming a 350 Mcf gas price. Therefore, expansion economics was very favorable, as operating costs for the entire productions team are reduced significantly. And in a $5 gas world, we expect operating costs to be in the $22-to $28-a-barrel range. This reduction in operating costs, plus increased reliability, which not only provides more stable revenue, but in itself reduces operating costs on a premier basis, make a significant contribution to the return on capital for Horizon expansions. Briefly, our expansion projects are on track. We're surveying slightly under our cost expectations overall, and we're close to schedule but somewhat behind as we take extra time to get better cost control. Our strategy will continue to utilize going forward. Hopefully, we'll be able to achieve the same type of success going forward as we've achieved to date. Also of note has been our various secured lump-sum contracts with 3 significant components of expansion: Froth Treatment, Gasoil Hydrotreating and Hydrogen Plant, much more than what's anticipated for Phase 2, 3 expansion. For reference, in Phase 1, the plants that were constructed in the lump-sum contracts had the best performance in a cost and execution perspective. Okay, that's enough on Horizon. Of all the chronologies significant for Horizon, it's only 17% of our overall production, and the most recent event has caused us to miss less than 2% of our annual production, but has certainly got much more than 2% of the air time this morning. So turning to gas. As you all know, the gas pricing has been various for years, and that has not changed. We accept -- expect gas prices to be low for the next 5 to 10 years. Therefore, it's fortunate that we are able to leverage our dominant land base and infrastructure to maintain our position as the most effective and efficient producer. It allows our operations to be cash flow positive even at $2 gas prices. Currently, we have roughly $10 million-a-day shut-in due to low gas price. As you know, operating costs vary from field to field, an average $1.10 to $1.15 an Mcf, which gives us the ability to be cash flow positive even at these severely depressed gas prices. If gas prices drop below $2 for a long period of time, and that is a realistic possibility, we'd likely shut in another 22 million cubic feet a day. If it's far below $1.75 and stay there, another 28 million cubic feet a day will be shut in. A reflection of the strength of our gas assets and Canadian Natural's effective and efficient operations. In light of the recent gas prices, we've taken out roughly $170 million from the remaining $550 million of capital allocated to gas for Q2 to Q4 in 2012, down to $380 million. Of the $380 million, $160 million is allocated to our liquids-rich Septimus development, which is on the 90 barrels a million of liquids. The remaining capital is allocated for some strategic drilling in land, but largely for turnarounds and to progress required gasoil's elements. This capital reduction result in gas-centric exit rates being reduced by roughly 39 million cubic feet a day and 1,000 barrels of NGLs. Average rates for the year are down 20 million and 460 barrels a day of NGLs. Gas guidance for the year is now 1,247 million cubic feet a day to 1,297 million cubic feet a day. The capital reallocated to debt can potentially increase oil activity later in the year. The Septimus expansion remains on track. The plant will be expanded from 60 million to 130 million cubic feet a day, with liquids production increasing from 5,200 barrels a day to 10,000 barrels a day. Drilling is meeting expectations, and costs are on track. Low -- although low gas prices are challenging for our gas assets, they make returns on our thermal heavy oil assets even greater. Canadian Natural has a dominant land position in the high-quality fairway for thermal in situ development. These lands have 78 billion barrels in place, and we expect to recover 8.5 billion barrels from our vast thermal heavy oil resources. Canadian Natural is executing a disciplined stepwise plan to unlock the huge value of this asset base by bringing on 40,000 to 60,000 barrels a day every 2 to 3 years, taking production facility capacity to 480,000 barrels a day of 100% working interest production. So far in 2012, we're on track to achieve our targeted production growth of 10% or 107,000 barrels a day at the midpoint of guidance, as additional Primrose development comes onstream. The 2012 Primrose development, where we're developing 5 pads of Primrose East that will add 20,000 barrels a day in 2012 and ramp up to 30,000 barrels a day in 2013 at a cost of just under $13,000 a flowing barrel. At Primrose South, we're developing 3 pads that will add 15,000 barrels a day in 2012 and ramp up to 20,000 barrels a day in 2013, for the cost of $13,000 a flowing barrel. Primrose pad adds are some of the lowest cost production pads additions in the industry, as our -- Canadian Natural's operating costs, which are targeted to come in under $9 a barrel at 2012, even lower than our benchmark operating costs in 2011, making Canadian Natural thermal and situ heavy oil production very profitable, if not the most profitable in Canada. Our Kirby remain on track. The Kirby South anomaly is, on an overall basis, 33% complete and 3% ahead of schedule, with construction 23% complete. All major equipment has been ordered, and we have committed over $685 million or 58% of the total budget. Overall drilling completion is 31% -- completions is 31% complete, with a rig now in the third pad. And most importantly, we have seen no reservoir surprises and have been able to place the SAGD wells where we want them. Kirby South is targeted at 40,000 barrels a day of SAGD production, with facility room to grow to 45,000 barrels a day at a cost of $32,000 per flowing barrel. First steam is scheduled for November 2013. The overall Kirby development will see Kirby South capacity increase to 60,000 barrels a day and Kirby North development to 80,000 barrels a day in 2 phases, for a total capacity of 140,000 barrels a day. At Kirby North, the DBM engineering was completed in Q4, and we are progressing EDS engineering now. The regulatory process remains on schedule, with the applications submitted in Q4 2011. We are constructing the main access road, cleaning the main plant site and start piling gravel in Q1. First steam in Kirby North is targeted for early 2016. At Grouse, the regulatory application for 40,000 barrels a day of capacity has been submitted this quarter, and Grouse DBM engineering will be completed, and EDS engineering kicked off this year. Grouse first steam is targeted for late 2017. Turning to primary heavy oil. Canadian Natural has a dominant land and infrastructure position, with over 8,000 drilling locations in inventory. As a result, our operations are very effective and efficient, and we are the low-cost producer, with over 110,000 barrels a day of primary heavy oil production. We are the largest primary heavy oil producer in Canada. As you know, primary heavy oil generates the highest returns on capital in our portfolio. In 2012, heavy oil production will grow by 16% year-over-year, with the drilling of 808 wells and a capital program of $990 million. With Canadian Natural's large inventory of wells, we expect to continue to grow production in the 8%-per-year range for the next 3 to 4 years. At our world-class Pelican Lake oil pool, Canadian Natural's leading-edge polymer flood has been very successful and has significantly increased oil recoveries. And as Lyle will point out, still an increase for proved reserves at Pelican Lake by 15% at year end. We believe the Pelican Lake polymer flood will ultimately recover 536 million barrels of additional oil. As you know, in 2011, we deferred our drilling program, which was scheduled to start up in September 2011, until, at the earliest, after breakup 2012 to confirm the learnings we achieved in 2011, ensure we have the right drilling configuration and maximized execution of polymer flood conversions to maximize capital efficiency going forward. I'm happy to say that we're seeing response in the polymer flood in the southern portion of the pool as we expected, and we'll proceed with the planned 2012 program. Canadian Natural's light oil and NGL growth in Canada has become significant. And in roughly 65,000 barrels a day, as we begin to reap the benefits of leveraging technology to water flooding, EOR and horizontal multi-fracs over our large light oil assets in Canada. We're on track to grow our light oil and NGL production at a target rate of 17% in 2012, significant production growth. 2012 capital program will be $550 million to continue the development of our large light oil assets. We target allocating roughly this amount over the next 5 years and do a repression growth in the 4% to 9% post-2012. Turning to our international operations. Our strategy is to maintain our existing operations and convert undeveloped resources as slots become available on the platforms, progress the Big E exploration in South Africa, monitor acquisition opportunities and generate free cash flow. And planning for the environment of the Murchison platform is also progressing on schedule. In the North Sea, production increased slightly as we came off maintenance, which offset natural declines in Q4. In Q1, we're on track with required workovers and maintenance, as well as subsea work at Lyell, injection wells at Ninian and production wells at Tiffany. As you know, Canadian Natural has curtailed much of the volume-added investments. That was in our long-range plans due to the tax changes in the U.K. As expected, production declined in the North Sea. In addition, in December of 2011, a severe storm in the North Sea took out 5 of 10 anchors in the Banff FPSO, causing damage to FPSO and damaging the subsea umbilicals. This difficult operational situation was handled safely and effectively by our teams in Aberdeen. The Banff FPSO has been safely moved to dry dock. Repairs are expected to take roughly 18 months. We'll lose roughly 3,500 barrels a day for 2012 from Banff and Kyle, and it's reflected in our production guidance numbers. We have insurance to cover the cost of repairs and business interruption insurance to cover the lost revenue. In Offshore West Africa, as expected, production is declining as we maximize the uses of our existing slots before we begin our infill drilling programs at Baobab and Espoir. The Espoir infill drilling program is scheduled to begin in late 2012, when the tender [ph] in situ drilling rig becomes available, with production increases ramping up in 2013 and expected production increases of 6,550 barrels a day at the completion of the drilling program. With a total cost of $143 million, $75 million of which will be spent in 2012, for an overall cost of $24,000 per flowing barrel a day. There is a potential risk, however. The schedule may get deferred, as the rig may get held up completing work for another operator. We're working to confirm this schedule and potentially make arrangements for alternate rigs, if need be. We're also making slow but sure progress in tying up all the regulatory requirements before drilling our South Africa exploration well. These series of very large prospects is ready -- is at a ready-to-drill stage and has potential for billion-barrel structures with our best estimate in place of 3 billion barrels. We own this block 100%, which is in deepwater, the challenging sea conditions. We will in 2012 begin the process of selecting a partner to drill the first exploration well in South Africa, likely in 2013 at the earliest. At this point, I'll turn it over to Lyle, who will update you on our very strong reserve position at 2011 year end. Lyle G. Stevens: Thanks, Steve. Good morning, ladies and gentlemen. To start our reserve discussion, I'd like to point out that, as in previous years, 100% of our reserves are externally evaluated and reviewed by independent qualified reserves evaluators. Our 2011 reserve disclosure is presented in accordance with Canadian reporting requirements using forecast prices and escalated cost. Canadian standards also require the disclosure of our reserves on a gross basis before royalties and on a net basis after royalties. Moving on to our results. In 2011, we had another strong year of reserves growth, replacing 249% of our production on a proved basis and 185% for crude oil, bitumen and NGLs, and 140% for natural gas. On a proved plus probable basis, we replaced 390% of our production, 189% for crude oil, bitumen and NGLs, and 173% for natural gas. Total corporate proved reserves increased by 7% or 326 million BOEs to 4.8 billion BOEs. This consists of 4.4 Tcf of gross proved natural gas reserves and 4.1 billion barrels of gross proved liquids reserves, which includes crude oil, bitumen, SCO and NGL. On a proved plus probable basis, total reserves increased by 9% or 636 million BOEs to 7.5 billion BOEs. This is comprised of 6.1 Tcf of gross natural gas reserves and 6.5 billion barrels of liquids reserves. The largest increases in reserves were in SCO at Horizon and Pelican Lake heavy crude oil and in primary heavy crude oil. On the Horizon mining side, proved plus probable synthetic crude oil reserves increased 467 million barrels, a 16% increase. This is a result of a continued delineation of the north pit and the identification and delineation of an adjacent pit. At Pelican Lake, on a proved plus probable basis, heavy crude oil reserves increased by 40 million barrels, an 11% increase, primarily as a result of positive technical revisions due to the continued strong response from polymer flooding and derisking of the process in other regions of the pool. In primary heavy crude oil, proved plus probable reserves increased by 32 million barrels, a 15% increase from 2010. This was largely driven by the excellent results of our record heavy oil drilling program. We still have good reserves growth in both natural gas and NGLs as a result of acquisitions, coupled with a modest natural gas capital program. On a proved plus probable basis, natural gas increased by 334 Bcf, a 6% increase. Natural gas liquids increased by 51 million barrels, a 61% increase, which was the result of our drilling program that was focused almost entirely on liquids-rich plays, the strong performance of our Montney project at Septimus and acquisitions. Crude oil, bitumen, SCO and NGLs now account for 85% of our proved reserves and 87% on a proved plus probable basis. Our reserve life index for the company is now 21.4 years using proved reserves and 33.3 years using proved plus probable reserves. Even if Horizon is excluded, we still have long reserve life indices, which reflects the strength of our asset base. It's 14.5 years using proved reserves and 22.3 years using proved plus probable reserves. In summary, these excellent results reflect the strength, balance and depth that we have in our asset base. I'd now like to turn the call back to Steve. Steve W. Laut: Thanks, Lyle. As you can see, Canadian Natural's assets are strong and are delivering value with strong reserve replacements and F&D costs. In summary, Canadian Natural targets cash flow of $8.2 billion to $8.6 billion at the strip, with the capital program of $7 billion, generating significant free cash flow between $1.2 billion and $1.6 billion in 2012. Our production growth is very solid at 10% Q4 '11 over Q4 '12, very impressive when you consider this growth is organic, and 53% of our capital program does not deliver production in 2012. Considering the volatility in the global economy today, it's important to point out that we have significant flexibility to reduce our capital program by up to $3 billion or 42% if a significant event were to occur. We certainly preserve our strong balance sheet, which in 2012 becomes stronger, with debt reduction of over $1 billion and debt to book shrinking to 22% at the midpoint of guidance. Canadian Natural is in a very strong position and a very effective capital allocation strategy, our balanced assets which can aid significant upside, we are delivering strong oil-weighted production growth, investing significantly in future production growth, then retaining capital flexibility, paying down debt and generating significant free cash flow between $1.2 billion and $1.6 billion. Canadian Natural allocated free cash flow in 2012 to opportunistic acquisitions if they are available, add value and able to compete for capital. We've increased dividends consecutively for the last 12 years. And has Doug will discuss, we increased our dividend 17% in 2012, and we anticipate this to continue going forward. As well, we'll continue to pay down debt, and lastly, buy back shares. In closing, it's clear that Canadian Natural is in great shape. Our management, business philosophies and practices work. We have a strong, well-balanced and diverse asset base with vast opportunities. Our strategy is balanced, effective and proven. And we have control over capital allocation and are nimble enough to capture opportunities. Our strong assets, combined with our great teams of people and our culture, which is focused on execution excellence, effective operations and cost control, allows Canadian Natural to build an even stronger, more sustainable asset base, which will generate even more significant free cash flow in the future. With that, I'll turn it over to Doug to discuss our prudent financial management. Douglas A. Proll: Thank you, Steve, and good morning. 2011 was another financial success for Canadian Natural. Cash flow from operations was $6.5 billion or $5.98 per share, which covered our capital expenditure programs of $6.4 billion. Net income was $2.6 billion, and adjusted net income amounted to $2.5 billion. We exited 2011 with $8.6 billion of long-term debt compared to $8.5 billion at December 31, 2010. We retired $400 million of U.S. dollar debt securities in July and then issued USD $500 million of 3-year notes at 1.45% and $500 million of 10-year notes at 3.45% in November. These 2 issuances were largely precautionary and recognize the very uncertain financial and economic environment. At December 31, 2011, we had $3.8 billion of undrawn bank facilities. Our balance sheet metrics strengthened, where debt-to-book capitalization is 27% and debt to EBITDA is 1.1x. Our commodity hedging program was enhanced over the last few months to include rent collars on 100,000 barrels per day for the remainder of 2012 with a floor of USD $80 and a ceiling of approximately USD $135. In addition, we have put options at WTI, $80 for 100,000 barrels per day for the remainder of the year. We remain unhedged in our natural gas production. The combination of strong balance sheet metrics, available liquid resources and strong commodity hedging program positions Canadian Natural to execute its business plan for 2012 and plan for the exploitation and development of our diverse asset base. In addition to our long-standing adherence to maintaining a strong balance sheet, we have also adhered to a proactive dividend policy. Commencing in 2001, Canadian Natural has implemented a program of consecutive annual increases in our dividend payments to our shareholders. For 2012, we have increased the quarterly dividend to $0.105 per common share or approximately 17%. This is the 12th consecutive year of increases and represents a 21% compound annual growth rate since the inception of the program. And lastly, we closed the books on the Horizon coker fire incident. The company has finalized the business interruption, insurance and property damage insurance claims with the insurers for combined proceeds of $726 million. Thank you. And I will return you to Corey for some closing comments. Corey B. Bieber: Thank you, Doug, and thank you, gentlemen, for your comments. Operator, at this time, we'll now open up the call for any questions from the floor.

[Operator Instructions] The first question is from George Toriola from UBS. George Toriola - UBS Investment Bank, Research Division: This question is for Steve. Just based on the performance of Horizon, what gives you the confidence that we'll see reliable operations going forward? That's the first part of my question. Steve W. Laut: Thanks, George. That is a very good question. Obviously, we've taken a hard look at ourselves and our operations going forward. I think we have a lot of confidence going forward because we've obviously seen operation discipline increased significantly. I'd be concerned or have less confidence if we didn't understand what had happened and why it happened and if we didn't understand how we could fix it. And even that is in place. Obviously, we know what happened, and we know how to fix it. We know the discipline is there, and probably gives us the confidence going forward is we know we have the people in place, and the supervision and the leadership to get us that, a sustained level of operations excellence and deliver production going forward. Obviously, we lowered our production guidance here going forward from April 1 just to give ourself more room and to be more confident in delivering, and in a way, to take a little bit of the heat off of the operations personnel at Horizon, who are very keen to get back to high levels of production. So that's what gives us that confidence. George Toriola - UBS Investment Bank, Research Division: Okay. And I guess the other part of my question is, what is your targeted level of reliability? And if you can link the reliability -- the percentage reliability to your operating costs, so supposing, just as an example, if you were operating at 80% reliability, what will be the operating costs? Or maybe just to -- another way to look at that is, how much of your operating costs do you really think is variable? Just trying to get a sense between reliability and your operating costs here. And if you can answer that targeted level of reliability, please. Steve W. Laut: Okay. So targeted level of reliability, we believe the plant can do roughly between 117,000 and 123,000 barrels a day, and we target for about 97% to 96% reliability overall. So that would take in to sort of that 113,000, 114,000 barrels a day of production. And obviously, we build in for taking some downtime, and that assumes we have 3 OPPs going, so that's our reliability. On operating costs, I've mentioned it in the call that our operating costs are mostly fixed. What's variable is natural gas pricing, which is about $2.50 a barrel, and mining costs, obviously, you don't mine unless you're producing, at about $8.50 a barrel. That's the variable costs. So if you take that, which is about $11 a barrel, we have about $36 a barrel operating costs on average. And say that's where we're going to be in 2012 going forward, so you take off $11, you're down to about $25 a barrel, if we have 80% reliability, although it's probably a coarse way of doing it and probably overestimates your operating costs, you could just ratio the 80% reliability to a 97% or 95% reliability range to get your operating costs. So operating costs will go up on that $25 portion -- ratio of the production.

The next question is from Greg Pardy from RBC Capital Markets. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Steve, maybe just to continue on with Horizon. Could you remind me what you think your all-in OpEx will be, post the expansion? And also when you double capacity, how much of an increase do you think you're going to see in your headcount? Steve W. Laut: Okay. So we're going to take capacity to 250,000 barrels a day. And labor will increase because, obviously, you need more miners, but that's why I say variable cost for mining. That's where most of your -- more trust in shovels. As far as the technical staff, it doesn't change much. You only need a few operators. But our efficiency on a sort of barrel production per person on staff will almost double as we get to 250,000. So labor does not have to increase that much as we go to 250,000 barrels a day because it is on fixed plants for the most part. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay. So I thought you threw out some numbers; I didn't quite jot them down. Like what -- given the numbers you've just given George, when you double this, what do you think a realistic number is for OpEx taking into account, not only the expansion, but as well as just labor inflation, everything else going on? Steve W. Laut: So we think at today's rates, and assuming a $5 gas price -- obviously, we're a lot lower than that today -- we would be in that $22- to $28-a-barrel range for expansion, probably somewhere right in the middle is where we're likely going to be. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay. $22 to $28, all in? Steve W. Laut: All in. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay. Yes, that does good things for the economics. Wanted just a nip then, just with Kirby South, looks like the capital there went from $350 million to $480 million. Just curious what I'm missing. Steve W. Laut: Actually, Kirby, I'm not sure what you're referring too, but the Kirby capital has been unchanged. Maybe that's in Kirby North, but Kirby South capital all-in will be about $1.2 billion to bring on the 40,000 barrels a day. That number has not changed. It's just the timing when the capital is spent. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay, okay. And then the last question is -- and this question does come up to returns and things like that, but also your point around the transition to longer -- a longer-term sustaining asset base, with that comment, are you really speaking to the expansions you're doing at Horizon? Or are there additional pieces of the company that are going to move into place as you grow? Steve W. Laut: Okay. So let me just go back on Kirby before we talk about the transition. The difference in capital, Greg, is strat wells for future drilling. That's what throws you off. Okay, so the transition, obviously, part of it is Horizon. Part of it is our thermal expansions at Kirby, Primrose, Grouse, Birch Mountain, [indiscernible] also, we are, as you know, in our light oil properties implementing more and more EOR, and water flood projects, which actually gives you a longer reserve life and more stable production base. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay. And the last question for me then, what's your natural decline rate in nat gas? And then what would it be in oil x synthetic -- oil and liquids x synthetic? Steve W. Laut: So gas declines all-in with our drilling that we got going on right now, probably about 19%. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Sorry, I missed that, Steve? Steve W. Laut: 19%. And I would say before -- probably back in 2007, it was closer to 25%. So you see the transition of gas asset base. Our light oil asset base without synthetic is probably about 15%. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay. And would the light also include the -- Primrose and everything else? Or is that just light? Steve W. Laut: That includes all the oils. Actually no, it doesn't. I threw you off there. Our Primrose is actually quite a bit less declined. That's all oil including primary. Not as similar. Sorry.

The next question is from Bob Morris from Citigroup. Robert S. Morris - Citigroup Inc, Research Division: Steve, did you say that you had already set in about 10 million cubic feet per day of natural gas production at this point? Steve W. Laut: That's right. We've got 10 million shut in today. Robert S. Morris - Citigroup Inc, Research Division: So is that 10 million that has a free cash flow breakeven well above $2? Is that why that's shut in? Steve W. Laut: That shut in, most of that is higher operating costs, and a lot of it is what little gas we have going to third-party plants. It is on sort of not a fixed-rate, take-or-pay contract, so we can shut it in anytime we want. Robert S. Morris - Citigroup Inc, Research Division: Okay. And then on the reduction in the natural gas spending of $170 million, from what you've said before, my understanding was that before you were already then just drilling on liquids-rich plays, and then unconventional plays. So the reduction of $170 million, where exactly is that being cut from? Steve W. Laut: That has been cutting from all our plays, except Septimus. So in Northwest Alberta, in our liquids-rich plays, we are cutting that drilling as well, so it's in that $170 million. We're drilling a few strategic wells to delineate plays and to preserve some land, but almost all our drilling, on all wells except Septimus today. Robert S. Morris - Citigroup Inc, Research Division: If you're cutting on liquids-rich plays -- I thought those economics were still pretty good -- what is the situation there? Is that just the transportation or the -- what is it that makes those liquids rich plays there uneconomic? Steve W. Laut: Depends on the degree of liquid rich. So we're -- obviously, at Septimus we're making 90 barrels a million. That goes easily at $2 of gas price. But as you get down into the 20- or 30-barrel-a-million plays that we have in some of the Northwest areas, the return on capital is just not that good, so we'll preserve that to when prices increase, and we'll take that capital and either pay down debt or potentially increase heavy oil drilling later in the year, which gives us a better return on capital, which as you know, is our whole strategy of maximizing capital return.

[Operator Instructions] There are no more questions at this time. Please go ahead. Steve W. Laut: Thank you, ladies and gentlemen, for participating in this call. As always, if you do have any follow-up questions, please don't hesitate to call our Investor Relations line. Good morning to everyone, and thank you.

Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.