John Langille – Vice Chairman Allan Markin – Chairman Steve Laut – Vice President Peter Janson – SVP, Horizon Operations Doug Proll – SVP, Finance and CFO

Andrew Fairbanks – Banc of America/Merrill Lynch Arjun Murti – Goldman Sachs Bob Morris – Citigroup Mark Polak – Scotia Capital

Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2010 first quarter 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, Mr. Langille.

Thank you operator and good morning everyone. Thank you for attending our conference call. We will discuss our 2010 first results and also update our plans for the balance of 2010. Participating with me today are Allan Markin, our Chairman; Steve Laut, our Vice President; Peter Janson, our Senior Vice President of Horizon Operations who will talk about the operational progress we are making at Horizon; and Doug Proll, our Senior Vice President, 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 will make a couple of initial comments before I turn the call over to the other participants. The first quarter again saw Canadian Natural achieve strong cash flow of over $1.5 billion, which was about $0.5 billion more than our total CapEx in the quarter and the first quarter is traditionally our highest spend quarter for drilling and development. As a result of course, our balance sheet continues to strengthen at debt-to-book capital of 31%, well below the bottom of our range. Steve will cover more details of our drilling and development activities, then he will review each of our operating areas. Our production mix continues to focus more on oil than natural gas as we direct more capital to the higher return oil projects. In the first quarter, we realized 82% of our revenues from oil sales, with a production mix of 64% oil. Our netbacks, being revenue per unit of sales less the royalties and operating costs continued to be strong with over $44 per barrel netback for oil sales and over 350 for gas sales. This reflects a continuous focus on reducing budget of operating costs in all of our business units. At our annual shareholders meeting held yesterday, the shareholders approved the amendments to our stock option plan and the 2-for-1 stock split. It is expected our common shares will trade on the new basis around May 19th in Toronto and May 28th in New York. The Directors declared a quarterly dividend which amounts to $0.075 per share on the new post-split basis. We have allocated about $1 billion from our expected realized excess cash flow to augment our capital expenditures on a number of property acquisitions that are core operating regions of Northwest Alberta and Northeast British Columbia. These properties will provide additional production volumes in cash flow after the acquisitions are closed later in the second quarter of this year. Before we turn the call over to Steve, I would ask Allan to make some comments. Allan?

Thanks John. Good morning ladies and gentlemen. We had an excellent start in 2010. We are delivering significant value over the upcoming year and will deliver for future years to come. The company’s production in the first quarter showed strong results, placing us in line with or above expectations in our international operations and North American assets. We commenced a record drilling program in conventional heavy crude oil drilling 150 wells in the first quarter. Heavy oil growth is strong. The company continues to leverage its large land base and dominant infrastructure in the Western Canadian sedimentary basin. First quarter production results at Horizon indicate the company’s move towards sustainable production. We achieved production at the high end of our guidance and our team maintains its focus in reaching operational reliability. We continue to focus on efficiencies and execution, maximizing the value of every dollar spent in both crude oil and natural gas. During the quarter, despite a reduction in natural gas drilling, we have been able to maintain reasonable operating costs. This demonstrates the efforts of our committed and dedicated team of people to promote efficient and low-cost operations. Over to you, Steve.

Thanks Al, and good morning everyone. The first quarter was strong, with a 10% production growth over Q1 2009 as well as strong sustainable free cash flow resulting in significant debt repayment, all in line with our projections for the year in which we expect to deliver 10% production growth, 11% cash flow growth, while only spending 73% of our cash flow and having between $1.7 billion and $2.1 billion of free cash flow to pay down debt and make our already strong balance sheet even stronger. The results from our first quarter drilling program have been very good. As a result, our production performance overall is towards a high end of guidance. Progress has also been very good on our long-term developments, particularly towards achieving long-term reliability at Horizon. As always, we remain focused on cost discipline, our capital costs are good, and we are delivering our projects at or below our expectations, and are offering costs at the low end of guidance. And if not for the unplanned maintenance issues in January and early February at Horizon, Horizon’s operating costs would also be well within guidance, with March and April operating costs in the $32 range right now. Operations-wise, we are off to a great start in 2010, and we have no reason to believe we will not be able to continue to deliver for the remainder of the year. Now turning in more detail, asset-by-asset, firstly gas in Canada, Canadian Natural, as you know has the largest land base in Western Canada. We dominate the land base and infrastructure in our core areas, and as a result, we are a low-cost producer. First quarter production exceeded the upper end of our guidance range, reflecting the success of our small 45-well first quarter drilling program and the strength of our gas assets. Our gas land base is very well positioned with strong assets and teams in the conventional, foothills, resource and unconventional plays. As we stated in our last conference call, Canadian Natural's plan for 2010 is not only to preserve but to strengthen our dominant gas asset base. As a result of the success of our first quarter drilling program, we have added roughly $75 million to our gas development budget to preserve additional land as well as we made a number of acquisitions in core areas that have properties to both oil and gas asset base. Although, we believe we will not see a robust gas price environment in 2010 or 2011 for that matter, we believe it’s prudent just trying to preserve additional sparring [ph] land to make these property acquisitions in our core areas, extending our land and infrastructure dominance. In the long run, we believe gas prices will return to more reasonable levels and it makes sense to preserve additional high quality land and pick up select properties that fit well and we consolidate within our core areas. Both land expirees and acquisitions as you know are time-sensitive and won’t be there when gas prices strengthen. Canadian Natural also dominates our heavy oil and thermal oil asset base in Canada. As you have heard me say before, we believe our high oil and thermal assets are the hidden gem in our portfolio, which adds tremendous value, yet are unappreciated by the Street. Our thermal assets alone have 33 billion barrels of oil in place and over 6 billion [ph] recoverable in our defined plan. Our plan targets adding approximately 285,000 barrels of incremental heavy oil production in a very disciplined, step-wise, and cost-controlled manner. In the first quarter, our progress has been good and is expected in our Primrose development at Primrose North and 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 60,000 to over 100,000 barrels a day. We have also allocated another $50 million to these properties for 2010 to drill another additional 22 wells and increasing facility capacity preparing for the increased production expected in 2011. Primrose East is our most recent incremental step on the road to 285,000 barrels a day, and as is well known, we had a containment issue at Primrose East in early 2009. Diagnostic steaming is complete and now has been successful. We are now proceeding to surveillance steaming, collections expected to average roughly 16,000 to 20,000 barrels a day in 2010 as we slowly returned to normal steaming activities. I am happy to report the return of Primrose East remains on track. At Kirby, our next thermal project, we expect to receive regulatory approval in 2010. We will complete a detailed engineering design work and develop a more detailed costs 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 targeted for mid 2013. In anticipation of Kirby’s sanction, we have allocated initial $10 million in 2010 to take advantage of some cost-saving opportunities as well as proceed with some early work at Kirby. At Pelican Lake, we will in 2010 continue with our program to convert the field to a highly successful polymer flood. We are on track with our 2010 plant to push the Pelican area on our polymer flood from 28% to 40% by the end of 2010. One of the challenges we have had at Pelican Lake is the prediction of polymer performance, with actual performance exceeding expectations. To ensure we have a fully capacity required in 2011 and that we don’t get trapped and ensure we can handle production ramp from our 2010 program, we have allocated additional $50 million in 2010 to make sure it’s ready. As you know, Pelican Lake is a world-class pool, with 4 billion barrels in place and roughly 560 million barrels of resource 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. In this commodity and cost environment, primary heavy oil generates top decile returns on capital in our asset portfolio and importantly, it also generates the quickest payout and largest cash-on-cash return. In the first quarter, we had drilled 150 wells. For the year, we will drill 600 primary heavy oil 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 excited program on a very cost-effective basis, making primary heavy oil one of the best value generators in our portfolio. Turning to the North Sea, production has been steady and near the top end of our production guidance for Q1. As planned, we started up the drill string in Ninian for the plan to drill one well and completed three well interventions in 2010. We are on the first intervention right now, as well as undertake subsea work at the T-block and upgrade facilities in all five platforms in 2010. In the North Sea, we are also preserving our capability to allocate additional capital and 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 have brought on three of the first six wells in platform B last week, with the fourth well to be brought on shortly. Although very early, the results from the first two wells do look encouraging. Initial rates in the C wells has been 8,000 to 10,000 barrels a day range, which is very encouraging, however we expect these wells to fall of quickly down to the 3,000 to 4,000 barrels a day range. After the completing the fifth and sixth wells on platform B, we will move the rig to platform A, with first production targeted for Q4 of 2010. In Cote d'Ivoire, production is stable. However, Espoir will be shutting down as planned for an extended period in Q2 as we install additional compression in the Espoir to handle increased associated gas production. This will impact future production and is reflected in our guidance numbers. 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 synthetic crude production and the design capacity. We had struggled in the first half of the quarter, while maintaining plant reliability, as we continue to work out operational kinks, equipment failures and the compounding effect of cold weather we had on our ability to quickly recover from equipment failures. Since mid-February, we made significant progress in our ability to operate and optimize the Horizon operation. The production by month is as follows January, 72,000; February, just over 84,000; March, just over 103,000; and April just under 101,000 barrels a day. The issues we had in January and February resulted in additional maintenance expenses during the period and as a result, the operating costs for Q1 was outside our guidance. Our operating costs for March and April are running in the $32 a barrel range, and we expect that higher volumes in the second half of the year to maintain our operating cost guidance for the year. Overall, we are doing well, and we are gaining increased confidence in our ability to operate the plant reliably as well as our ability to predict the likelihood of upcoming issues. With that in mind, we will be proactively taking some selective planned outages in May to address issues that may impair our ability to operate higher and more reliable levels and prepare us with sustained run of design production rates of 110,000 barrels a day for the remainder of the year. As a result, we expect May production to be in the 75,000 to 80,000 barrels a day range for May. I will now turn it over to Peter Janson who was recently promoted to Senior Vice President of Horizon Operations in February, allowing Real Doucet, our Senior Vice President of Horizon Projects to focus on a very important task of preparing and executing the Horizon Phase 2 and 3 expansion. Pete will give you a brief account of some of the activities we will be undertaking in May and what risks remain that could impact us in 2010. Peter?

Thank you Steve. Horizon Operations were utilized the month of May to complete a number of major preventive maintenance activities, including some component replacements in the oil preparation plant. During this period, we will be addressing some of the risks that remain outstanding from the beginning of the year in our January and February events. Some specifics on what we are doing in each area as follows. In mining, we are doing a shovel preventive maintenance where we do one a month and currently we have three electric and two hydraulic shovels in service. In the oil preparation plant, we were replacing one of two surge bin feed conveyors and we are changing out one of two screens, and these screens we rebuild them to replace on a four-month schedule currently. We are also replacing a number of valves on retaining boxes due to wear and as you can see, there is a lot of activity in the oil preparation plant. (inaudible) which is fairly routine and primary upgrading, we are currently pigging our coker furnace tubes. It looks like we are getting two to two-and-a-half months of run before we go to a pigging cycle on a sustained basis. Our sulfur units, we have had a peak restriction due to a burner issue in one of our two trains, and that burner replacement and repair has been completed in the month of May. Secondary upgrading, we have had in the past a number of reliability issues with PSA valves in the reformer, this is going to resolve, so we no longer have a concern there. In utilities, we are having our oiler annual inspections, the control testing is underway. There is a gas turbine generator outage and maintenance and we have some power line and break repairs that we will be undertaking in the month of May. So, coming out of these outages, the expectation is that we should see a slight improvement in peak production capacity as both sulfur units will be at peak performance. We called back in June of 2009 we peaked to have 121,000 barrels a day. I would like to do be able to do that again and more frequently. We continue towards sustained 11,000 barrels a day SCO capacity as Steve has mentioned. In February of this year, we had 8 consecutive days at or above 110,000 barrels. In March, we had 10 consecutive days. And then in April, 7; and then another 12 days at or above 110,000 barrels a day. I do need to however balance the optimism by highlighting some of the residual risks we still carry in the operation. In the mining area, we have increased maintenance on mobile equipment, which is resulting from longer halt distances associated with blending our ore. Dozer availability does need to improve. In oil preparation plant, maintenance planning and execution strategies need to be adapted as the wear rates do seem high. Overall availability of the LPP is a key factor in long-term sustained production, we need to keep the coker for. In primary upgrading, longer-term coker heater firing and burner management is required to control the coking effects and the de-coking and pigging cycle in the heater tubes. Secondary upgrading, we are monitoring sealed reliability on the pumps, and we do have vibration on our hydrogen plant for strap bands [ph] that we continue to monitor. In summary, the single most important factor going forward in Horizon is our ability to foresee maintenance requirements, and then plan and successfully execute the work. If we miss, there is a direct correlation to production and increased costs to do maintenance. Back to you, Steve.

Thanks Peter. As you can see, we have got many issues we have faced, but we quickly mitigated most of those and we have got a proactive plan here going ahead, which I think reflects the strength and dedication of our operations team. Now, it’s important to remember that Horizon is a world-class asset with over 6 billion barrels of recoverable oil. We have targeted increased production to Phases 2 to 3 to 232,000 barrels a day and look further expansions in Phase 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. Horizon definitely is a world-class asset. In 2010, we continue to complete work on Tranche 2 of our Phase 2 and 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, we will complete significant engineering work on future expansions and prepare a more detailed cost. It is our expectation that we will have a more detailed cost estimate by Q4 2010 and a better understanding of any modifications we may make to our execution strategy. This work will be completed to give a better certainty on costing and 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 of light sweet crude. 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 be assured that reasonable cost synergy can be achieved. We are not there yet. 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 similar value in magnitude to Horizon, getting more manageable sizes and in my opinion, are the hidden gem of our portfolio, and in this low-cost gas price environment, generating greater value for shareholders. Our light oil assets both international and Canada as well as our primary heavy oil assets in 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 will 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, given Canadian Natural’s 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 is better positioned than ever before. So, with that, I will turn it over to Doug to update you on our financial position and our prudent financial management.

Thank you Steve and good morning. In the first quarter of 2010, as John mentioned, Canadian Natural generated over $1.5 billion of cash flow from operations and capital expenditures just over $1 billion, allowing us to continue to reduce our long-term debt to $8.9 billion at the end of March. Year-over-year, we have reduced long-term debt by $4.2 billion. Debt-to-book capitalization is now 31%, debt-to-EBITDA 1.3 times, resulting in a strong and healthy balance sheet. This is good news to our shareholders and debt investors as we had written a significant financial market volatility this not seen since 2008. Our commodity hedge program remains active. On the crude oil side, we have 200,000 barrels per day collars for the second quarter with floors of US WTI $60 and $65. We also have 150,000 barrels per day completed for the second half with floors of US WTI of $60 to $70. On the natural gas front, we have 620,000 GJs per day, with AECO pricing floors of $4.50 and $6 for Q2 and Q3 and 220,000 GJs per day, with an AECO pricing floor of $6 for Q4. The details of these positions are included in our press release and are also posted on our Website. We believe these positions combined with our focus on cost control, our capital expenditure flexibility and our balance sheet strength will ensure that we can complete our capital program, build our inventories of lands and prospects and allow us the confidence to focus on mid and long-term projects. Canadian Natural continues to grow and diversify its production base and focus on being the low-cost producer, while at the same time building a strong and flexible balance sheet and providing returns to our shareholders in the form of dividends and value enhancement. Thank you, and I will return you to John.

Thank you very much gentlemen. As you can see, we are on track for another very successful year, and as always, our balanced business plan and focus will be directed towards achieving shareholder value and what seems like an almost continuous volatile marketplace that we deal in. With that, operator, I would like to open up the meeting for any questions that people may have.

(Operator instructions) The first question is from Andrew Fairbanks from Banc of America/Merrill Lynch. Please go ahead. Andrew Fairbanks – Banc of America/Merrill Lynch: Thank you. Good morning guys. I have a question on Kirby, as you start to move down the road on pricing that out, as you look at the various components, do you think that the overall returns are going to be most impacted by lower materials costs, labor inputs, or just construction efficiency and process efficiency if you will?

Thanks Andrew, it’s Steve here. Obviously, we are very focused on costs and cost control and certainly at Kirby, and where we see the fixed impact here is two-fold. We really – it’s going to come from construction, which is going to be driven by engineering and being well prepared before we start. So, we are very focused on getting engineering correct and at a very high of completion before we start. And we believe with that and being very focused on the control and monitoring of the project, we will have controlled construction costs, but really construction is where we get the cost overruns, but it starts certainly with the engineering. If you don’t have the engineering right, you have a very difficult time getting construction running. Andrew Fairbanks – Banc of America/Merrill Lynch: That’s great. Thanks and recognizing that the look-back study isn’t 100% complete, are there some lessons that you have learnt so far that you are incorporating into the Kirby design?

Yes, one of the lessons we learnt is that even though at Horizon, we had a high degree of engineering complete before we started, we found that the more engineering we have and more Canadian Natural direct involvement in construction, the better control we had on costs. And if you look at Primrose East, which is a good example of that, we had a high level of engineering done and we have a much more direct involvement of key management personnel in the construction and Primrose East was built at the same time, we had a much better cost control. So, we are going to take that lessons into Kirby and we are going to try to apply that going forward at Horizon. Andrew Fairbanks – Banc of America/Merrill Lynch: Terrific. Thanks Steve.

Thank you. The next question is from Arjun Murti from Goldman Sachs. Please go ahead. Arjun Murti – Goldman Sachs: Thank you. You provided some comments on the billing dollars of property acquisitions. It sounded like it was a mixture of natural gas and oil property. I was wondering if you had any more color in terms of either reserves acquired, how much of it is more just acreage acquisitions and the types of play that – it sounds like the matter and the things within your core areas, but if you did have any more details, that would be appreciated.

: Arjun Murti – Goldman Sachs: It’s sounds like on the natural gas point, maybe I was trying to feel better about the cost structures come down enough and you are going to continue to build your property base, is that – obviously gas prices are low, but there is an offsetting cost reduction of steam capacity as well?

Yes, I think on the cost side, we are probably as low as we are going to get. I don’t think the supply of service companies can go much lower. So, we are still confident of where we are and feel confident on our ability to execute. Really, it does tell you that we believe that long run, and I don’t think we have a balance sheet and the portfolio that we can look at the long run and live more than maybe five or six years ago, we believe gas prices will come back to reasonable levels. It may take two or three years before that happens, and when that does happen, we will have a very dominant position and a very dominant land position, high-quality land position that we are able to execute on. And so, this is a proactive step consolidating our infrastructure land base and if any goes with that. Arjun Murti – Goldman Sachs: That’s terrific. And then just switching gears to Horizon, I think in the earnings release, you mentioned very good production cost numbers for March including natural gas with $32.50, it sounds like in your absolute cash costs for the quarter, there must be some amount therefore that’s not recurring. If I simply take your total cash cost and divide by the March production, you get to a number higher. How do you all gain confidence? You know, so many of the other operators had so many ongoing issues, how do you gain confidence besides just being your assets that you can kind of sustain those lower cash cost numbers that you alluded to for the month of March in your press release?

I think we feel fairly confident,. Obviously, we have limits to that confidence, because there is always an issue that can happen, Horizon is a very complex plant. But when we run in March and April, when we run at those levels for periods in November last year and June and July of last year as well, we know where our costs are. So, it’s really a matter of – if our production volumes are there, our costs would be there, and we think we are going to actually overtime drive them even lower, that is mainly because we are newer plant, we are more newer plant, we are more heating greater than any available plants, and we have new equipment. And that’s why we are seeing capital costs lowered as well. Overtime, we will probably on a steaming side, that will increase as we had to buy more trucks and shovels, because we are out, but right now, it’s very good. Arjun Murti – Goldman Sachs: And in terms of driving them lower, is that just more volumes debottlenecking and so forth or can the absolute cash cost actually come down?

I think probably both. And maybe I will get Peter to talk about it a little, but obviously the people get there on time maintenance, our costs on maintenance are actually lower to do the same work if we can see it coming ahead of time. You want to talk about both the difference between planned and unplanned, Pete?

Yes, absolutely, thanks. The planned activities allow us to prepare materials and people and therefore we only need demand up in number of people required for a planned activity whereas unplanned activity does create a chaos and that you tend to drive manpower numbers up, you tend to expedite materials, and that does drive the cost, in some cases more than double of what would otherwise be expected on a planned basis. And the other one point I would want to make is as we bring a unit down because we are tightly heat integrated, it has actually cost us more energy to continue or sustain the operation with an partial planned outage. So, there are in fact a double-whammy when we do come down. Arjun Murti – Goldman Sachs: That’s very helpful color. Thank you very much.

Thank you. The next question is from Bob Morris from Citigroup. Please go ahead. Bob Morris – Citigroup: Thank you. Steve, just following up on the – it looks like on the natural gas acquisitions, it was about $750 million, you mentioned that you spent about $75 million incrementally on those assets that you acquired. Is that something you expect to get a return on at today’s gas price, or is that just purely investment to hold the acreage and we are spending a lot of money here, two to three years ahead of when you think natural gas prices might recover, have you lowered the bar on what is the breakeven gas price you need to get a return and I guess also any of this in anticipation of the royalty changing beginning next year and trying to get ahead of the pack here in picking up what might be more economic properties looking forward.

Hi Bob. I think maybe I wasn’t as clear as I should have been. That $75 million incremental capital spending on the drilling program is really on existing assets. So, basically after first quarter, we are drilling program to conserve land and some strategic wells. The results from that program are much better than expected. And so, some land that we are thinking maybe we will let expire has more value and we are going to drill that land to preserve it. I would say that in most cases, almost all the cases, all those things in our projects with goods return at $5 gas price. Now, all things being equal, we wouldn’t drill those wells, it was an expiring, because our oil properties generated even higher returns. So, just wouldn’t get the capital allocation. So, everything we do generates on the gas side gets return $5 gas. No, we are not $5 gas sales. Bob Morris – Citigroup: And then just the thought behind making such a huge investment to the three years ahead of when you think gas might get back above 5 where you can get a return, why not wait or is this just stuff that you paying might go up in price as the rest of the industry anticipates, people jumping in here and again how much of this is perhaps associated with the royalty change that will be coming in Alberta?

I would say on acquisitions, it seems buying land, let me go buy once. So, when gas prices return, these acquisitions won’t be there. Somebody else is welcome. So, we will have another player in our quarter that we have to compete with, and the land will expire, and if you want to buy back, you have to buy it back probably at higher price. Part of it, the drilling program I would say small parts and maybe now 20% left in the drilling activity is due to royalty changes in Alberta. They are positive and that is reflected in our program. Bob Morris – Citigroup: Okay. And I guess just finally here. Having spent $1 billion in the first quarter, how much more do you think with the excess cash that you have got here, how much more do you think you might be able to allocate to similar-type acquisitions versus share buybacks and others, but specifically, how much more do you think you might be able to spend on acquisitions here?

That’s a hard call to make, Bob, and I think our view is, and I think we said this all along is that price of buck, we thought our abilities to buy properties would be fairly low. And I can say this is tremendous amount of properties that have been put on the street, and we have looked a lot of them and most of them, we have bid on. If we do bid, we are not even running. So, we always look if it’s in a core area, and so there could be more that is pretty hard to predict. Obviously to say, we would have to meet our criteria at our hurdle [ph] rates and it has to be opportunistic and strategic. Bob Morris – Citigroup: Can you just finally, can you tell us the associated production with $1 billion in acquisition, what the production-wise you got?

We got about just under, I would say 28,000 barrels BOE per day of production. Bob Morris – Citigroup: Great, thank you.

(Operator instructions) The next question is from Mark Polak from Scotia Capital. Please go ahead. Mark Polak – Scotia Capital: Good morning guys. You mentioned strong well performance at Ninian in the release. The last public data I was able to see in January, I think it was running around 17,000 barrels a day. Just wondering if that’s gone up at all from there and if you guys see that field remaining flat through sort of the 2012 timeframe?

: Mark Polak – Scotia Capital: Great. Thank you. And then last one from me just on Olowi, good news on the first three wells around platform B. Just wondering if you have a sense after those wells now what that field might peak at for you guys and when you would see that occurring?

I think earlier when you talked Mark, and other time, I thought we might make 12,000 barrels a day as a peak. We have actually been above that here with these royalties coming on, but that’s flush production. So, I still think that we will sort of a peak, sustain rate might be around 12,000 to 15,000 barrels a day versus 20,000 barrels a day, which we thought when we started this project. So, platform C definitely has hurdles on volumes and resources. Mark Polak – Scotia Capital: Okay, that’s very helpful. Thank you.

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

Thank you very much operator, and thank you ladies and gentlemen for attending our conference call. And of course, as always, if you have any further questions, do not hesitate to contact us. Thank you very much and have a good day.

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