John Langille – Vice Chairman Allan Markin – Chairman Steve Laut – President Lyle Stevens – SVP, Exploitation Real Doucet – SVP, Horizon Projects Doug Proll – SVP, Finance and CFO

Andrew Fairbanks – Bank of America Arjun Murti – Goldman Sachs Greg Pardy – RBC Capital Markets Dominique Sabbia [ph] – Interstate Asset Advisors [ph] David Weiler [ph] – AllianceBernstein Mark Friesen – Versant Partners Kam Sandhar – Peters & Company Brian Dutton – Credit Suisse

Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2009 fourth quarter and year end results conference call. I would now like to turn the meeting over to Mr. John Langille, Vice Chairman, of Canadian Natural Resources. Please go ahead, sir.

Thank you, operator and good morning, everyone. Thank you for attending our conference call. We will discuss our 2009 results and also, update our plans for 2010. Participating with me today are Allan Markin, our Chairman, Steve Laut, our President; Lyle Stevens, our Senior VP of Exploitation, who will discuss reserves, Real Doucet, our Senior Vice President of Oil Sands, who will talk about the progress we're making at Horizon and Doug Proll, our Senior Vice President of Finance, who will discuss our overall financial position. Before we start, I would 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 just make some initial comments before I turn the call over to the other participants. I think you can see that, reflective of our disciplined allocation of capital over the last several years and the completion of our oil mining project, we can see Canadian Natural evolving into a very large, oil-weighted producer with a great amount of economic natural gas production. In the fourth quarter of 2009, our oil production, including synthetic oil, amounted to 64% of production on a volume basis and almost 80% on a revenue basis. The last half of 2008 into 2009 saw a weakening in commodity prices. Crude oil prices in the last half of 2009 recovered to the $65 to $75 West Texas range. However, natural gas prices continued to be under pressure throughout the year. We were able to mitigate the resulting decline in our revenues through our very strong hedging strategy for about one half of our oil production. As a result of our ability to generate strong cash flow and our disciplined approached to capital expenditures, we have repaid a significant amount of our long-term debt and exited 2009 with a debt-to-equity ratio of 33%, under the low end of our targeted level. At this time we are also targeting further debt reductions during 2010. It appears crude oil pricing will continue to hold at recent levels of $70 to $80, West Texas, with accompanying differentials for heavy oil in the low-to-mid teens. Natural gas prices continue to be under pressure. Accordingly, as Steve discusses our properties and developments, you will see a relatively small allocation of capital to natural gas projects and continued emphasis on our oil prospects. We have allocated some of our free cash flow with a 43% increase in dividends and potential for share buyback. In addition, we will be proposing to the shareholders at our upcoming AGM to split our shares on a two-for-one basis. Before we turn the call over the Steve, I'd ask Allan to make some comments. Allan?

Thanks, John. Good morning. Canadian Natural's defined growth plan continues to deliver value to our shareholders in all economic conditions. 2009 proved to be an unpredictable year for commodity prices as oil remained low through the first half of the year and natural gas prices continued to be unstable. However, with a large inventory of projects and by using our expertise within the company, we were able to deliver another solid year at Canadian Natural. Production at Horizon commencing near the beginning of the year was a milestone for the company. The amount we have learned during construction and through ramp up is invaluable. And our team continues to apply their knowledge of the plant to ensure reliable production for years to come. We continue to unlock the enormous value of this resource. Our conventional business delivered another quarter and full year of strong results. Our industry-leading position in heavy crude oil in Western Canada is allowing us to capture significant value as heavy oil differentials remain favorable. We continue to apply our marketing strategies to the business to make certain that we deliver the best return from our assets. In our continued effort to generate returns for our shareholders, the board of directors has approved a quarterly dividend increase to $0.60 per common share, a 43% increase over '09. The company began paying dividends in 2001 and has subsequently increased the amount every year since, which, again, shows discipline in our approach and the ability to provide value creation to our shareholders. Now, as 2010 is well underway, we continue to add value for our shareholders. We are always evaluating our assets and look to develop them in the most cost-effective manner to ensure we deliver the best possible returns for many years to come. Our people, plan and assets will deliver.

Thanks, Al and good morning, everyone. As both John and Al have said, Q4 was a strong quarter for Canadian Natural. Oil production was up 18% over the fourth quarter 2008, driven by strong performance, production volumes at Horizon and our heavy oil assets. In Q4 we made good progress at Primrose East. And, at Horizon, we are making good although bumpy progress towards reliable operations at design capacity. It's clear that design and functionality of Horizon as they're deliver at or above nameplate capacity. What we have struggled to achieve over the cold winter months is plant reliability. As expected, our operating costs remain low and well within our operating cost guidance for the year, which we lowered in Q2. Our capital program in 2010 will be $3.9 billion, up 26% from 2009 capital program, with increased capital allocations to oil, 80% of all capital and, in particular, primary heavy oil, Pelican Lake, Horizon expansion preparation and increased, enhanced oil recovery projects in our portfolio. As well, we are kicking off the early stages of the first phase of the Septimus/Montney shale gas development. As a result of this capital program and capital programs in prior years, we'll see production grow 7% year over year and 17% entry to exit, generating a 12% increase in cash flow and, more importantly, free cash flow in the $2 billion to $2.6 billion range. Clearly, this reflects the strength of Canadian Natural's balanced and diverse asset base, our focus on low-cost, disciplined and effective operations, as well as the overall soundness of our strategy. We are growing production and generating substantial free cash flow. We are in a great position. In 2010, Canadian Natural will allocate the free cash flow in the following three priorities, pay down debt and further strengthen our balance sheet is ongoing. Allocate capitals, additional asset development opportunities and acquisitions. At this point, we have not allocated any additional capital. Dividends, as you heard, have increased by 43% today and share buybacks – we have issued a Normal Quick Course Issuer Bid. Doug will address both dividends and share buybacks in a few minutes. But, before I briefly update you on each of our assets, I'll ask Lyle to give you a brief overview of yearend reserves.

Good morning, ladies and gentlemen. Before I start our reserves discussion, I'd like to point out that, as in previous years, 100% of our reserves are externally evaluated and reviewed by independent, qualified evaluators. To better understand our disclosure, I'd like to briefly outline two items that may help as you review our 2009 yearend reserves. The first is that, as of January 1, 2010, the synthetic crude oil reserves associated with Horizon are now reported with crude oil and natural gas reserves, due to changes in the SEC regulations. The second is related to the impact of the SEC pricing upon our reserves. This pricing model averages the prices from the first day of every month in 2009. For 2009, this resulted in a significant decrease in the natural gas prices from the 2008 evaluation and a significant increase in crude oil prices. The decrease in natural gas pricing has resulted in the loss of some late-life reserves and, also, some – also the loss of some reserves associated with undeveloped drilling opportunities. The increase in crude oil prices improves economics, but results in higher calculated royalties for Alberta oil sands projects and also accelerates payout of these projects. This impacts the net reserves that we report for Horizon, our thermal assets, Pelican Lake and a few of our primary heavy oil assets. Now, moving on to our results, with the addition of the Horizon synthetic crude oil, our net crude oil and NGL reserves now total 3.03 billion barrels and 4.74 billion barrels for net proved and probable. For natural gas, our total net proved reserves are 3.18 Tcf. And our net proved and probable reserves are 4.21 Tcf. Our 2009 net proved finding and on-stream costs were $19.81 per BOE and $22.64 per BOE for proved and probable. These numbers exclude Horizon reserves and capital. Now that Horizon is on stream, the company's proved undeveloped reserves total 25% of our total proved reserves, a very low percentage, revisions due to price for net proved gas results in the loss of 337 bcf. For proved crude oil, including Horizon, revisions due to price resulted in the loss of 326 million barrels. Excluding the impact of price revisions that I just mentioned, our finding and on-stream costs would have been very good. $12.28 per BOE for proved reserves and $7.74 for proved and probable reserves. Both numbers exclude Horizon. In North American operations, again excluding Horizon, we achieved solid finding and on-stream costs of $12.78 per BOE for net proved reserves and $16.10 per BOE for net proved and probable reserves. Without the price revisions, these numbers would have been a very impressive $6.45 per BOE for proved and $5.32 per BOE for proved and probable. Internationally, we had positive revisions due to price, but these were largely offset by negative technical revisions. This resulted in no net increase in our international reserves. In summary, these results reflect the strength and depth of our asset base. In 2009, even in a challenging price environment, we're able to high grade our capital program and direct activity to those assets that provided the best returns and lowest finding costs. I'd now like to return the call back to Steve.

Thanks, Lyle. As you can see, Canadian Natural's in a very strong reserve position and is set to deliver strong value growth in the years to come. Turning to more detail, asset-by-asset, firstly, gas in Canada, as you know, Canadian Natural has the largest land base in Western Canada. Canadian Natural dominates the land base and infrastructure in our core areas. And, as a result, we are a low-cost producer. Our gas land base is well positioned with strong assets in teams and conventional, foothills, resource and unconventional plays. Canadian Natural's plan in 2010 is not only to preserve but to strengthen our dominant gas asset base. Over the last two to three years, Canadian Natural has quietly been transforming the makeup of our dominant land base to the point where, today, roughly 50% of our gas location inventory is made up of tight sand or shale gas, unconventional gas plays. Unfortunately, we do not see a robust gas price environment in 2010. And 2011 does not look much better, as we believe there's an abundant supply of gas currently available and that the supply response may overwhelm any positive gas price pressure that might materialize. As a result of this view and the fact that our returns on oil portion of our portfolio are so much better than gas, we will drill only 93 gas wells in 2010. This limited gas program is mostly focused on strategic wells, land expirees and drainage concerns. However, in 2010, we'll continue to shift into the more, deep, tight, unconventional targets, with roughly 55% of the drilling focused in these areas versus 35% in 2009. The greater emphasis to deeper, longer life and more expensive wells will result in the decline of our production, effectively bottoming out in Q4 2010 and position us to return to gas growth in 2011 if we so choose. This is particularly impressive considering we're only drilling 93 gas wells in 2010, compared to 900 gas wells in 2005 when we were growing gas at 5%. This leads us to believe, which I stated earlier, that any positive price increase will likely be met with a significant supply response. It pays to be patient and cautious. A path Canadian Natural has the luxury to pursue because of our balanced asset portfolio and our strong oil assets. And Canadian Natural's heavy and thermal oil assets in Canada are very strong and will continue to add tremendous value for Canadian Natural shareholders. Our thermal assets alone have 33 billion barrels of oil in place with $5.6 billion recoverable in our defined plan. Our plan is to add approximately 300,000 barrels a day of heavy oil production in a very step-wise, disciplined, cost-controlled manner. In 2010, we will continue to execute the defined plan, with roughly $500 million being allocated to our thermal properties. Most of this capital is allocated to the continued development of Primrose, at Primrose North, East and Wolf Lake. Production will average between 80,000 to 90,000 barrels a day in 2010. And, since this is a cyclic process, we will see peaks and troughs of between 60,000 to 100,000 barrels a day. Primrose East is our most recent incremental step on the road to 300,000 barrels a day of incremental production. As is well known, we had a containment issue at Primrose East in early 2009. Diagnostic steaming is proceeding to plan and we expect to see production average roughly 16,000 to 20,000 barrels in 2010 as we slowly return to normal steaming activities. At Kirby, our next incremental, 45,000-barrels-a-day production addition, we expect to receive regulatory approval in 2010. We'll complete the detailed engineering design work and develop a more detailed cost estimate with the target of sanctioning Kirby in Q4 2010. We are taking a very disciplined approach to the engineering and construction of Kirby to ensure effective cost control, with first team in targeted for mid 2013. At Pelican Lake, we continue in 2010 to rollout our program to convert the field to a highly successful polymer flood. With roughly $450 million allocated to Pelican, we'll push the area to feel better polymer flood from 28% to 40% by the end of 2010. As you know, Pelican Lake is a world-class pool, with 4 billion barrels in place and between 350 million and 475 million barrels recoverable with polymer flood - a very large pool with very robust development economics. Pelican Lake continues to generate significant value for shareholders. Our primary heavy oil program continues to roll on effectively and efficiently. And, in this commodity and cost environment, primary heavy oil generates top decile returns on capital in our asset portfolio. It, importantly, also generates the quickest payout and largest cash-on-cash return. In 2010, we'll drill 600 primary heavy wells, a record number of primary wells for Canadian Natural, roughly, 25% more than we drilled in 2009. Our dominant, high-quality land base, infrastructure and effective operations allow us to drill a program on a very cost-effective basis, making primary heavy oil one of the best value generators in our portfolio. Although we don't spend much time talking about our light oil portfolio in Canada, we have been quietly working these assets over the last number of years. The fruits of that work will begin to be executed this year. We'll allocate over $300 million to light oil in Canada, drill over 100 wells, up from 42 in 2009, initiate the optimization and development of significant EOR projects on existing light oil pools. And, keeping with light oil, in the North Sea, production has been steady. In Q1, we were preparing to start up one drill string in Ninian in April and drill two wells, complete three well interventions, as well as undertake some subsea work on the T-block and upgrade facilities in all five platforms. In the North Sea, we're also preserving our capability to allocate additional capital by having the ability to start up a second drill string later in 2010. In offshore West Africa at Olowi in Gabon, we continue to drill off the B platform and monitor production from the C platform. As we have previously stated in the 2009 results, from the C platform has been well below expectations and may potentially have an impact on reserves. But, based on the performance to date on the C platform, we have now taken a $150-million write-down. The oil results for the B platform look better at this point than C and we are currently drilling the fourth well on the platform. The pipelines and umbilicals have been connected from the FPSO to platform B and we are currently commissioning the platform, with first oil from platform B expected by the end of April. Although it's too early to tell, we are optimistic that platform B production will be better than platform C. In Cote d'Ivoire, we are currently installing the additional compression at Espoir to handle increased associated gas production. And production performance at both Espoir and Baobab in Cote d'Ivoire is strong and meeting our expectations. It is important to note that offshore West Africa has some of the highest return on capital projects in our portfolio and, along with the North Sea, generates significant free cash flow for Canadian Natural. Turning to Horizon, we continue to make good progress driving towards sustained reliability. There is no question the operation can and has delivered at or above 110,000 barrels a day of SCO Design capacity. We do, however, continue to struggle with maintaining plant reliability, as we continue to work out operational kinks, equipment failures and the compounding effect of cold weather in December and January has had on our ability to quickly recover from equipment failures. The production by month is as follows. October – 71,202 barrels a day, November – 97,287 barrels a day, December, when we had equipment problems, 42,495 barrels a day. We recovered in January to 72,000 barrels a day. And now, in February, we're running around 84,200 barrels a day and looking strong so far in March. We have faced many issues. Almost all seem to be first-time issues here at Horizon. And we are working our way through all these issues and expect at some point in the near future we will see the end of a string of equipment and operational issues. I will turn it over to Real now to give you a brief account of some of these issues we have faced and what risks we could see that could impact us in 2010, Real?

Thank you, Steve. Good morning, everyone. I will give you just an example of issues we have to deal with, starting with the mine. We had the mine ore body issue, which was a combination of high-clay content and low blending capabilities since we were operating the mine at the beginning only on two benches. Since August, we have accelerated the opening of the third bench, which is fully operational now. We have also stockpiled the high-clay-content ore, which we are trickling back into the production, about 10% rate. And we have also developed new operating parameters in the froth treatment plant to cope with this combination. All in all, right now, we have seen great success with this approach and this problem is behind us now. A second one is in the ore preparation plan. We have higher wear than anticipated into this plan and the component change-out. Schedule is coming faster at us than anticipated. So we had to readjust our preventative maintenance. Combined with this, also, was a design change for our secondary crusher, which was a first in the oil sands of this kind. And that change right now – We have confirmed here over the past two weeks that the design is adequate. And this problem now is behind us. Our maintenance schedule has been readjusted, as well, to cope with the wear that we have on this plant. So this issue also is behind us now. Going into the hydrogen plant, this is the one we had a major issue in December, where we have the forced-draft fan problems. And this was due to a startup problem that we had when we put this plant in operation. That has been fixed also. And it's behind us. In the hydrogen plant, we had also hot tubes in the reformer and we had a couple leaks, which have been plugged. And this problem is behind us as well. So, has the – If you remember, we've talked about the PSE valves. We have 84 valves that have to be changed in this plant because of bad design, bad fabrication to start with from the suppliers. And we have changed them. We entered into a program with the suppliers to change them. And, two weeks ago, they have been all changed out now and the schedule was based on the capability of the supplier to supply these valves. So this problem is behind us now and the hydrogen plant has been performing really well since. And all these issues are behind us. And the last one is the coker. We have coking in the furnace, which we had to prematurely de-coke. And we also had to change one of the convection sections because it was coked beyond de-coking. So we have enhanced our operational procedures with the help of the licenser. We have also changed our peaking sequence. And this problem also, even though not totally behind us yet, will be behind us also by the end of March. We also had a heat exchanger that we were operating under lower performance for a while until we received a new one. We did receive the new one here three weeks ago and it has been changed already. And, the sulfur plant now is performing according to spec. So, all in all, right now, all of these problems, or the majority of them, are behind us. We don't foresee any major issue from now on. However, we want to be cautious about it. And we're predicting that, throughout the summer, we should be back here into high performance on this plant.

Thanks, Real. As you can see, we've faced many issues, but we have very quickly mitigated most of these issues, reflecting the strength and dedication of our operations team. It's important to remember that Horizon is a world-class asset with over 6 billion barrels of recoverable oil. And we have targeted to increase production through phases 2 and 3 to 232,000 barrels a day and future expansions in phases 4 and 5 to just under 500,000 barrels a day, or 0.5 million barrels a day of light, sweet crude with no declines for 40 years and virtually no reserve replacement costs. In 2010, we continue to work on Tranche 2 of our Phase 2/3 expansion. In addition, we are well on our way to completing our detailed lessons learned from Phase 1, so we can incorporate any cost reduction or effectiveness measures into future expansions. Along with this work, we'll complete significant engineering on future expansions and prepare a more detailed cost estimate. It is our expectation that we will have a more detailed cost estimate by Q4 2010 and a better understanding of any modifications that may make our execution strategy more effective. This work will be completed to give better certainty on costing in various environments. Canadian Natural is committed to the expansion of Horizon to 232,000 barrels a day and, ultimately, just under 500,000 barrels a day a day of light, sweet, 34-degree, API oil. As always, Canadian Natural is very focused on cost control and creating value for shareholders. And we will be sanctioning the expansion of Horizon but only when we can ensure that reasonable cost certainty can be achieved. It is clear that Canadian Natural is in a very strong and enviable position. Horizon is a world-class asset that is and will continue to add tremendous value to shareholders. Our thermal heavy oil assets can add value similar to magnitude of Horizon, getting more manageable sizes. And, in my opinion are the hidden gem, in our portfolio. And, in this low-cost, gas price environment, generate even greater value for our shareholders. Our light oil assets, both international and Canada as well as our primary heavy oil assets Canada continue to generate strong returns. And in this low gas price environment our strategy of maintaining a well balanced portfolio and the fact that we are a low-cost producer will ensure that we could be able to weather a sustained period of low gas prices. Our teams are strong throughout the company. And as Doug will point out, our balance sheet is strong and getting stronger. Our capital program is very flexible, giving Canadian Natural the ability not only to maximize the value of our well-balanced portfolio. But also capture any opportunities that will present themselves in this environment. Canadian Natural is in a great position. And in today's environment, with our team, our strategy and our assets, I believe Canadian Natural has a clear competitive advantage. With that, I'll turn it over to Doug to update you on our strong financial position.

Thank you, Steve. And good morning. Financially, 2009 for Canadian Natural will stand out for several reasons – production of synthetic crude oil from the Horizon oil sands mining and upgrading operations commenced established a new product stream further diversifying our oil and natural gas portfolio. All of our operating divisions, North American conventional, Horizon oil sands mining and upgrading, the North Sea and offshore West Africa are generating positive free cash flow. The balance sheet strength was significantly improved. Long-term debt was reduced by $3.3 billion to $9.7 billion in 2009. Our balance sheet metrics of debt to book capitalization and debt to EBITDA are 33% and 1.4 times, respectively. A strong cash liquidity position has been maintained over the last several years and we exited 2009 with $2 billion of available credit under our banking facilities. Other financial highlights for 2009 included the generation of over $6 billion of cash flow from operations or $11.24 per share underpinned by our 2009 commodity hedge program and the generation of $3 billion of free cash flow, which was substantially applied to debt. We continue to carry on with an active commodity hedge program due to the relative uncertainty of the economic recovery and continued volatility in commodity prices. We have close to 50% of our 2010 first half oil production with collars with a floor exceeding $60 WTI. Second half production is hedged at roughly 25% of budgeted production. We also have several natural gas collars in place with a floor of $6 AECO on 17% of our production, as well as more – as well some are positions on 400,000 GJs per year with a floor of $4.50 AECO. These positions are detailed in the financial statements and are posted on our website. As you've heard previously, the board of directors in assessing the financial and operational strength and maturity of Canadian Natural declared a 43% increase in the quarterly dividend to $0.15 per share. They also proposed that we file a normal course issuer bid for up to 2.5% of the company's issued shares subject to regulatory acceptance. And finally, they proposed a two for one subdivision of common shares, subject to shareholders approval in May. We believe that these three events provide top tier returns to our shareholders. Strengthen our commitment to invest in the highest return opportunities and enhance the liquidity of the common shares. Thank you and I will return you to John.

Thank you very much, everyone for your summaries and additional comments. I think you can see that we are all looking forward to execution of our plans throughout the balance of 2010 and into 2011. And with that, operator, I would open up the call to questions that people may have.

Thank you, sir. (Operator Instructions) Our first question is from Andrew Fairbanks from Bank of America. Please go ahead. Andrew Fairbanks – Bank of America: Hi. Good morning, guys. I had two questions for you. First, as you look at the opportunities in your conventional Canadian business. Where do you rank out the most economic projects? I mean you mentioned the primary heavy. I don't know if that would be the very best versus polymer or other light oil projects you might have. I don't know if within your asset base, there is anything Cardium light that may be intriguing that may not be developed this year but might be interesting going forward.

Andrew, Steve Laut here. So that's a good question. And I'd say it depends how you want to evaluate the economic parameters. Primary heavy oil obviously gives us a very quick payout and great return on capital. Polymer flooding at Pelican Lake also gives us a very good return. But obviously, the payouts are a little longer and it's a longer life project. Again, if you look at thermal again, the payouts are a little longer, but returns on capital are robust – probably not as robust as primary heavy oil. But again, the project life is much longer and more sustainable. As far as light oil, we do have as you know, the second largest or the largest land base in Western Canada. And almost by definition, we do know we have a lot of this tight oil, Cardium like oil plays that can be unlocked with technology. And we are working on some of those. But they're not going to really move the dial for us. But we do have those opportunities. And of course, gas obviously in North America is– just has a tough time competing with any of the oil projects. Andrew Fairbanks – Bank of America: Right. No. That's great. Thanks. And then just a small question. Would you have a sense for what the Horizon operating costs would have been in November when you were running well?

Our operating costs in November were $33 a barrel Canadian. Andrew Fairbanks – Bank of America: Great. Thanks, Steve.

Thank you. Following question is from Arjun Murti from Goldman Sachs. Please go ahead. Arjun Murti – Goldman Sachs: Thank you. First question was just on your upgrader strategy in light of I think, what is generally a narrower outlook for light heavy spreads. I think I'm pretty familiar that with the thermal oil expansions or at least Kirby or the next few. You're no longer planning to go forward with the big upgrader you'd mentioned several years ago. But I was wondering how the light heavy outlook would impact Horizon. We've always assumed that all the future phases of Horizon get the type of big upgraders like you built in phase 1. But I was wondering if you could provide any comments in terms of how the environment might impact upgraders for Horizon in the future? Thank you.

Thanks, Arjun. And thanks for that question. It gives me a good chance to talk to my favorite topic. As you know, the light heavy spreads have narrowed considerably, particularly with the expansion of pipeline capacity to Gulf Coast and that future capacity that will be there. So as historically, to heavy oil differentials have been in that 30 to 45% averaging about 32% for Canadian heavy crude. We think that has structurally changed. And right now, as you know, Canadian heavy crude differentials are probably in that 10% range very low. We don't see that sustainable. We think we probably – Canadian heavy crude will move to the historical average that you've seen for Mayan crude in that 22 or maybe 24%. So that's where we think we'll be. As far as upgraders go in Horizon, we still see that putting an upgrader at Horizon does make sense. A standalone upgrader is difficult and you have to have some very good economic conditions to make it work in the long run. That being said, we do know that heavy oil prices do swing. It's a volatile market and it does make sense to have some sort of hedge or natural hedge by having upgrading capacity. When it comes to Horizon itself, the upgrader is in a sense a special situation. As you know, we capture a tremendous amount of heat from the upgrader. We'll also capture CO2 from the upgrader on the hydrogen plant and I'll talk a minute why that's important. And as the heat integration obviously lowers our cost overall, because we use the low grade heat from the upgrader to help in extraction. The other thing is for us to sell bitumen direct versus upgrading means we would have to switch from a naphthenic to a paraffinic process in the extraction plant. That process is the same process that Shell and Exxon will be using at Cold Lake. And obviously, it can be done. The cost and capital costs are much higher. And for us to go to that for the next phases – the incremental capital costs versus the incremental capital costs of building an upgrader and capturing that value and the heat make more sense for us to go to a fully integrated upgrading solution at Horizon. And unless things change, that looks likely which where we in. Of course, we're evaluating that all the time. I'm giving a long winded answer here, but I want to talk a little bit about the CO2. One of the advantages we have with the Horizon is we are right now trucking CO2 to Horizon. We'll capture CO2 here in our Tranche 3 of expansion from the hydrogen plant. That CO2, we mix with our tailings as it's sent up to the tailings pond. And we are getting excellent results. We're getting excellent separation at the tailings pond on a weighted tailings pond so that we, in fact, actually have 12 meters of relatively clear water in our tailings pond. What this means is that we are now essentially recycling water and we have only used 12% of our utilization of water that we expected out of the river. So in essence on the process side, we are using total recycled water to run the process. That's all due to the fact that our CO2 process from the tailings is working really well. This obviously captures the CO2 and sequesters it forever. So it's a great environmental thing. It reduces the size of the pond as well. So when we go to the next stage, we'll look at putting in thickeners on the tailings. That will again, allow us to get the water back sooner and be warmer and reduce our costs as well. So there's an operating cost savings as well. So thanks for the question allowing me to get on the soapbox. Arjun Murti – Goldman Sachs: Steve, thank you very much. That's a very thorough and helpful answer. I think I have a very short follow-up, which is on your Primrose East comments and the 16 to 20,000 barrels a day, I think you said for 2010. How should we think about the timeframe for ramping that back up? Is that progressively over the year or second half and any thoughts there?

I think we'll slowly increase the steam up as we go through the year. We're being very cautious. The regulator wants us to be cautious and quite frankly, we're bound by what the regulator requests us to do or allows us to do. We think we'll increase the steaming as we go throughout 2010. I would see us probably get back to steaming production levels in 2011 closer to design capacity. But I think that would be more like mid 2011. But it all depends what happens. We don't – as we're still in diagnostic steaming, you can't actually predict when you're going to have something happen to you. So we've got to go through the process. Arjun Murti – Goldman Sachs: That makes sense. Thank you very much.

Thank you. The following question is from Greg Pardy from RBC Capital Markets. Please go ahead. Greg Pardy – RBC Capital Markets: Thanks. Good morning. Most of my questions have been answered. But Steve, just rectifying the clay content in the fourth quarter, did that impact Horizon operating costs all that much or was it mostly just volume?

It didn't impact the operating costs that much. It might have increased us maybe $0.50 to at the most $0.70 a barrel in fourth quarter. Obviously, we're still stockpiling right now. But that will end here once we get the bench three fully opened up. And obviously, we've got to move that material twice, so it's stockpiled. So it's the cost of moving it back into the process. So we'll have to be done mostly in 2010. Greg Pardy – RBC Capital Markets: Okay. Thanks very much.

Thank you. (Operator instructions) The following question is from Dominique Sabbia [ph] from Interstate Asset Advisors [ph]. Please go ahead. Dominique Sabbia – Interstate Asset Advisors: Yes. My question is about cash flow. – My question is about cash flow and I wanted to know about your Horizon project, about the future royalties. How soon will you have to pay the higher royalties to the Canadian government for – after you reach full return of your money out? Do you have any idea how far out that would be?

It is quite a ways out. Right now, it all depends on what kind of oil price forecast you use. I think we're looking well into 2020 and maybe into 2030 before it pays out. So obviously, the government is changed the way the royalties work so you do pay a higher royalty before payout now. And its oil price based in Alberta. And so the payout is quite a ways away yet. And we see around bitumen side of the process. Dominique Sabbia – Interstate Asset Advisors: One follow-up question. Will you have forecasts by month for Horizon for the first four months of '10? And will they be on your website?

We won't have forecasts. We have guidance for the year and quarterly guidance for Horizon, which is on our website but not by month. What we will do is we will publish the production as it becomes available on our website for past months. So that people can keep closer track of our production. Dominique Sabbia – Interstate Asset Advisors: All right. Thank you very much.

Thank you. The following question is from David Weiler [ph] from AllianceBernstein. Please go ahead. David Weiler – AllianceBernstein: Good morning. Steve, you might want to do when you publish the monthly production numbers that also would be helpful would be to publish a monthly operating cost number for Horizon, like you provided for November. I've got two questions. Gas production, you mentioned you've got the option to return to growth after the fourth quarter of 2010. Knowing what you know about service costs, what gas price would it take to return to growth?

I think it's a two part question, what kind of gas price it would require. It also depends how good our oil projects are because we allocate capital obviously, to the highest return projects. So I think even if you had gas prices at 6 bucks an mcf, oil's still a lot better. So you do more gas but oil still looks a lot better. So if you get into that $5.5 to $6 range I think we would start to look at some of our better gas plays allocating more capital. But again, it depends on what the oil price is and how we allocate capital relative to each other. David Weiler – AllianceBernstein: Okay.

As far as op costs go, you just about gave our accountants here a heart attack by saying that – publish op costs within the same month. It takes a while to get all the costs in, so. David Weiler – AllianceBernstein: Makes sense. And on that – If we had an environment of $5.5 or $6 gas and we allocated a bit more to the gas projects. Would that kind of give you a flattish growth profile, do you think?

Yeah. I think we – to be honest with you, as you can tell from our comments, we're not really optimistic that gas prices are going to come back very soon. So it's not something that we are really spending a lot of time planning. Our view is gas prices are going to be fairly low for 2010. And it might be tough to get any kind of price increase for 2011. So at this point in time, it's probably too early for us to sort of speculate what we do on the gas side. David Weiler – AllianceBernstein: Okay. And can you guys provide – you touched on it in your prepared comments. But reserve – negative reserve revisions and the oil sands either the thermal or Horizon and you mentioned there was a royalty effect and accelerated that? Can you go through where the reserves came down? Was it on the thermal or Horizon? By how much and what were the factors?

I don't know if we can give you all a complete, detailed breakdown. But I think Lyle can tell you generally where it came from and what caused each, if you like.

Sure. Horizon is very simple. And that's actually in our disclosure. So we lost $307 million barrels at Horizon. The other most significant impact was on our thermal operations, where we lost $70 million barrels due to pricing. And then at Pelican Lake, it's a significantly smaller amount around $7 million barrels and even smaller on our primary heavy oil assets. David Weiler – AllianceBernstein: And when you say due to pricing, help me out there.

What we end up doing to calculate the impact due to pricing is we take last year's reserves and we run it with this year's prices. And the difference in reserves is called a price revision. So it incorporates shutting off reserves if they become economic. It incorporates changes in the royalties. So for our Horizon and our thermal operations, almost all the impact is due to changing in the royalties. David Weiler – AllianceBernstein: Right. Right. Okay.

As you know, David, the royalties increase with price increase now with the Alberta royalties. So the higher prices means we have less net reserves to put on our books. David Weiler – AllianceBernstein: Yes. Now I'm with you. Okay. Thanks very much.

Thank you. Following question is from Mark Friesen from Versant Partners. Please go ahead. Mark Friesen – Versant Partners: Thank you. Follow-up question with respect to your comments on Horizon, Steve. I was wondering if CNQ has any I guess, disputes with the provincial government with respect to the deemed bitumen price and if there's been any holdback to your royalty payments to the government on that?

Mark, we don't have any disputes with the Alberta government at this time. And we're working well with them. So there's no holdbacks or anything else going on. Mark Friesen – Versant Partners: Okay. Good. With respect to Pelican, I was wondering if you could go through the impact of the poly flood as it relates to the reserve bookings expectations for 2010 and going forward?

We don't actually try to give predictions of what we're going to do for reserve adds in the year going ahead. We do know and maybe Lyle can expand on this a little bit more on the reserve side of it. But we will be drilling quite a few wells at Pelican Lake. A lot of those are producers and a lot of them are injectors for polymer. And as you know, it takes a while before you get production performance. We would expect that that would convert some of our proven undeveloped reserves at Pelican Lake into producing. And it would add – also will add more proved, undeveloped polymer flood area into our reserves. So I don't know if Lyle can actually make a very good prediction as to what the magnitude of that would be for 2010. But it will be substantial then.

Yeah. It does get tough to predict for 2010. Certainly, over the past three years that we've been injecting polymer. The performance has continued to improve. In our reserves that are currently booked, the best performing areas are now up to a 27% ultimate recovery factor. And of course, there's a full range anywhere from 5 to 27%. And over time with more historical data, we're hopeful that, that will continue to grow.

So Mark, to help you out as you know, we've got about 28% of the pool under polymer flood today. Mark Friesen – Versant Partners: Okay.

And we hope by the end of the year we'll have about 40% under polymer flood. And Lyle's kind of giving you the range. If we go from primary about 5% and then the very, very best 27%, I think we'd say we can get to 25% if we do well. So it gives you a magnitude of where it could be based on the percentage of polymer flood that the field will be under this year. Mark Friesen – Versant Partners: Okay. That's a great answer, thank you. Just want to touch on one thing you had mentioned in your prepared remarks. You mentioned something about you have an intention to strengthen your land base surrounding your natural gas position. And then you made several comments with respect to not more aggressively pursuing your natural gas portfolio at present. So I wonder if you could reconcile that thought for me?

I think what you have to look at, Mark, is as you know, we are the largest land base holder in Western Canada. And by definition, we do have a lot of exposure to every play including shale gas plays, tight gas plays and unconventional resource gas plays. What I mean by strengthening that means is we are drilling wells to preserve land and we're drilling strategic wells to prove up some of these plays and ensure that we keep the land we want and to further augment our inventory of gas locations. That's what I meant by strengthening our gas plays or asset base. Mark Friesen – Versant Partners: Any sense of natural gas pricing that you'd want to see before you more aggressively start drilling?

Again, I think you got to see $6 and then you got to see what the oil price is and see what competes. We're going – allocate the capital at the highest return projects, so if you got $80 or $90 oil and 6 bucks gas price, gas does have a tough time competing although some does. Mark Friesen – Versant Partners: Okay. Great. Thank you very much, Steve.

Thank you. The following question is from Kam Sandhar from Peters & Company. Please go ahead. Kam Sandhar – Peters & Company: Hi, Steve. Two questions. First of all, can you just elaborate a little bit more on the price revisions really to gas as to what areas they were in? And then the second question is, you talked about the NCIB that you guys put in place. Given that you've got $2 to $2.6 billion free cash. Do you have the intention that you would buyback up to 2.5% in 2010?

I'll answer the second question first and then I'll get Lyle to give you a general overview of where the gas revisions. I think it's – the gas is probably widespread. But on the normal course issuer bid, it's for 2.5% and that's the maximum we go. I think obviously, we're going to take a very disciplined approach on how we proceed with buying back shares. And I guess the answer to that is we're going to see what the market conditions are. And we will try to minimize the dilution due to option exercise within the company and probably, gain some of that back over the course of the year.

And Kam, getting back to your question on gas revisions. The gas revisions that Steve mentioned are widespread across the company. I think that the late life reserves get cut off. I'd say, all across Western Canada. There is – we lost a total of 335 bcf unproved in Canada. Of that, 158 bcf is related to locations proved, undeveloped locations. Those locations are primarily from Southern Alberta and they would be shallow gas wells. Kam Sandhar – Peters & Company: Okay. So just to clarify, that's mostly – is that just because of the slowdown in your drilling activity then? And it doesn't fit into that five year window?

No. It's primarily because the SEC pricing of $379. Those wells are uneconomic for us to drill. Kam Sandhar – Peters & Company: Okay.

Thank you.

Thank you. Following question is from Brian Dutton from Credit Suisse. Please go ahead. Brian Dutton – Credit Suisse: Yes, Steve. Just to circle back to the question on the reserve revisions say, for Horizon. Just to clarify, there's $307 million barrels you're talking about on a net basis. Would there have been any revisions if you were looking at the Horizon reserves on a growth before royalty basis?

Absolutely not. Brian Dutton – Credit Suisse: Perfect. Thank you.

Thank you. There are no further questions registered. I would like to turn the meeting back – I do apologize. We have another question from Mark Friesen from Versant Partners. Please go ahead. Mark Friesen – Versant Partners: Thank you. I was just wondering how many of the price driven negative revisions would be back on the books with prices as they are currently?

That's a hard question. I would think the majority would be on. Mark Friesen – Versant Partners: Okay. Thanks, Lyle.

Thank you. There are no further questions registered. I would like to turn the meeting back over to Mr. Langille.

Thank you very much, operator. And thank you, everyone for attending this conference call. As usual of course, if you have any further questions, do not hesitate to get a hold of anyone in our IR department and we will look after the answer for you. And have a good day. And we look forward to continuing our progress throughout this year and into 2011. Thank you very much.

Thank you, gentlemen. This concludes today's conference call. Please disconnect your lines. And thank you for your participation.