John G. Langille - Vice Chairman Steve W. Laut - Principal Executive Officer, President and Director 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 David McColl - Morningstar Inc., Research Division Christopher Feltin - Macquarie Research

Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2012 First Quarter 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. John G. Langille: Thank you, operator, and good morning, everyone. Thank you for attending this conference call, where we will discuss our first quarter 2012 results and review our planned activity for the balance of 2012, and in some cases, beyond that. Participating with me today are Steve Laut, our President; and Doug Proll, our Chief Financial Officer. 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 make some initial comments before I turn the call over to Steve and Doug for their in-depth discussion. We have come out of a challenging first quarter with even more conviction that our business strategy, plans and principles are right for our industry. Part of our strategy is to maintain an extensive base of assets which can, firstly, contribute strong current production to generate significant cash flow; secondly, provide excellent economic development opportunities in the near- to mid-term frame -- time frames; and thirdly, establish significant growth vehicles for production growth in the 5-plus year time period. As Steve reviews our projects, you will see this base of assets has been set up and is delivering on this strategy. Natural gas economics have been under pressure for a number of years, as less and less natural gas projects have been able to achieve a recycle ratio of greater than 2. Reacting to this, our drilling operations and natural gas projects have been reducing each year for the past 6 years, and this year will be no different. We continue to monitor our producing areas, and we'll take any necessary steps, including shutting in production, to ensure we are making positive cash flows from these areas, and in very limited situations, carrying out activities that will provide adequate returns. On the other hand, E&P activities on oil prospects continue to be robust. Over 90% of our revenue now comes from sales of oil. We are reaching new levels of production and cash flow achievements. Our light medium oil production in Canada is now averaging over 40,000 barrels per day, as new plays and EOR opportunities are pursued. In addition, production of NGLs climbed to over 25,000 barrels. Strong drilling results in our primary heavy oil areas has resulted in first quarter production of 120,000 barrels per day. One year ago, we were only producing 97,000 barrels. Our international operations continue to contribute free cash flow, with $180 million of free cash flow in excess of the capital requirements of our international operations in the first quarter. And as expected, now that the scheming cycle is ending at Primrose, our thermal in situ property, production is starting to ramp up again and is together targeted to increase daily production to over 100,000 barrels from this quarter's 80,000 barrels. Our mining asset incurred some unplanned maintenance time in the first quarter, as repairs had to be carried out on the fractionator tower. These repairs were completed in a timely fashion and the production recommenced in mid-March, with April's production reaching almost 112,000 barrels per day. Oil pricing continued to be volatile and continues today to be volatile, especially with respect to the discounts being charged in Canadian oil production in the first quarter, including synthetic crude oil. The discount climbed dramatically in the first quarter from the last quarter in 2011, as planned and unplanned maintenance issues caused a number of refinery shut-ins during the first quarter and into the early part of the second quarter. As expected, as these refineries are placed back online, the discount is tightening up again. Additional pipeline capacity, some of which is under construction and close to being completed, should also help to alleviate these discounts and the disconnect between Brent pricing and WTI pricing. We are at a very strong financial position, with our operation providing cash flow to carry out our capital programs; take advantage of any opportunistic acquisitions that may arise; pay dividends, an increase of 17% over last year; and buy back shares if appropriate. Our teams are strong, and we are looking forward to carrying out our objectives over the remainder of 2012. Now I'd like to turn the call over to Steve for a more detailed analysis of our properties. Steve? Steve W. Laut: Thanks, John, and good morning, everyone. In the first quarter, Canadian Natural continued to execute our proven strategy, based on effective and efficient operations and optimizing capital allocation to ensure we maximize the return on capital, generate free cash flow, maintain our strong balance sheet through the price cycles, 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 was 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. We have, on a consistent basis, been able to effectively allocate capital and maximize return on capital over the long run and throughout commodity price cycles. Today, with oil prices and low -- 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 16%, primary heavy oil growth will grow by 19% and thermal in situ will grow by 8%. Horizon is back on, and we expect solid performance for the rest of the year. In addition, we're investing significantly in 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. At Horizon, our expansion plans to take production 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 oil are unfolding as expected. We also have vast natural gas assets, which, when gas prices strengthen, will provide the opportunity to unlock significant value for shareholders. Turning to gas, and as you know and as John said, outlook for gas pricing has been bearish. We expect gas prices to be low for the next 5 to 10 years. Therefore, it's fortunate we are able to leverage our dominant land base and infrastructure to maintain our position as the most effective and efficient producer. Currently, we have roughly 16 million cubic feet a day shut-in due to low gas prices. And if gas prices drop below $2 for a sustained period, and we're pretty close to making that call today, we'll shut in another 22 million cubic feet a day of gas. And if they fall below $1.75 for a sustained period, another 28 million could be shut in, a reflection of the strength of our gas assets and Canadian Natural's effective and efficient operations. The Septimus expansion remains on track. The plan will be expanded from 60 million to 110 million a day, with liquids capacity increasing from 5,200 barrels a day to 10,000 barrels a day. Drilling is meeting expectations and costs are on track. That being said, we have deferred 7 wells under the 2012 program. Although gas prices are challenging for our gas assets, they make the returns on our thermal heavy oil assets even greater. Canadian Natural has a dominant land position in the high-quality fairway for the 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 assets. Canadian Natural is executing a disciplined stepwise plan to unlock the huge value of this asset by bringing on 40,000 to 60,000 barrels a day every 2 to 3 years and taking production capacity to 480,000 barrels a day at 100% working interest. So far in 2012, we're on track to achieve our targeted pressure growth of 8% at the midpoint of guidance as additional Primrose development comes onstream. The 2012 Primrose development plan, where we're developing 5 pads at Primrose East that will add 20,000 barrels a day in 2012 and ramp up to 30,000 barrels a day in 2013. At Primrose South, we're developing 3 pads that will add roughly 15,000 barrels a day in 2012 and ramp up to 20,000 barrels a day in 2013, both at a cost of $13,000 a flowing barrel. Primrose pads are some of the lowest cost production capacity additions in the industry, as are Canadian Natural's operating costs, which are targeted to come in under $9 a barrel in 2012, even lower than our benchmark operating costs in 2011, making Canadian Natural's thermal in situ heavy oil production very profitable, if not the most profitable, in Canada. At Kirby, we remain on track. The Kirby South development is, on an overall basis, 42% complete and 4% ahead of plan, with construction 32% complete. All major equipment has been ordered and we've committed over $835 million or 69% of the total budget. Overall drilling completions is 47% complete, with a rig now on the third pad. Most importantly, we are seeing 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 plus 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 develop to 80,000 barrels a day in 2 phases for a total capacity of 140,000 barrels a day. At Kirby North, the DDS is -- engineering is 40% complete and on schedule. The regulatory process remains on schedule, with the application submitted in Q4 of 2011. The main access road, clearing on the main plant site and stockpiling gravel is complete, and we've also ordered some long-lead equipment ahead of schedule to lock in lower costs. First steam-in for Kirby North is targeted for early 2016. At Grouse, regulatory application for 40,000 barrels a day in capacity has been submitted this quarter. And our Grouse DBM engineering is on track to be completed in 2012, and the EDS engineering will be kicked off this year as well. Grouse's first steam-in 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 120,000 barrels a day of primary heavy oil production, we are the largest primary heavy oil producer in Canada, and as you know, primary heavy oil generates the highest return on capital in our portfolio. In 2012, heavy oil production will grow by 19% year-over-year, with the drilling of 818 wells, up 10 wells and on budget. And production is up -- growth is up from 16%, largely on the back of the excellent results we have been having from our new Woodenhouse area, which is about 75 kilometers north of Pelican Lake. Results from our Woodenhouse primary/heavy oil wells are running about 150 barrels a day, which is outstanding for primary/heavy oil wells, and above our expectations. Currently, we are producing about 4,300 barrels a day from this area. We have drilled 9 pads and 61 wells. Six of the 9 pads are now onstream, and we expect to bring on another 3 pads onstream after breakup. We'll drill 3 more pads or 26 wells by year end, and we expect to exit 2012 at 8,800 barrels a day. We have running room at Woodenhouse to drill another 245 wells over time, significant production growth for this new primary heavy oil area outside of the traditional northeast primary heavy oil corridor. Woodenhouse is a new area and oil volumes are trucked to Pelican Lake for treating and shipping. Also, as with most prolific primary heavy oil wells, sand production is very high in initial months. These extra costs plus battery issues at Lindbergh and Beartrap caused us to truck additional volumes to other batteries and along with some cost inflation, drove oil operating costs significantly higher in the quarter. Although Q1 oil costs are higher, we expect to meet our overall operating cost guidance for the year, as the Lindbergh and Beartrap battery issues are behind us, and we add additional battery facilities at Pelican to handle the Woodenhouse volumes. Our world-class Pelican Lake oil pool, Canadian Natural's leading edge polymer flood, has been very successful. We believe the Pelican Lake polymer flood will ultimately recover 536 million additional barrels of oil. We've seen solid polymer response in the last quarter of 2011 and in the first quarter of 2012. So we will drill 70 producers and 8 injectors, delivering 4% production growth. Battery extensions have accelerated in 2012 to handle the increased production we expect from the portion accrual converted to polymer flood in the last 2 years and that begins to ramp up and to handle the unexpected higher pressure volumes from Woodenhouse. Canadian Natural's light oil and NGL growth in Canada has been -- production and growth has become significant, and we're running about 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. A positive outcome in Q1 has been our ability to drill slightly longer horizontal multi-fracs, with more fracs per well than originally planned. This results in higher completion costs per well than originally budgeted. However, reserves per well have increased and our F&D costs are lower. We expect this trend to continue for the remainder of the year. We'll grow our light oil and NGL production at the targeted rate of 15% in 2012, significant growth. In the next 5 years, we target delivering production growth in the 4% to 9% range. Turning to our international operations. Our strategy is to maintain our existing operations and convert our undeveloped resources as slots become available in the platforms, progress the Big E exploration in South Africa, moderate our acquisition opportunities and generate free cash flow. The planning for the ground and emergent platform is also progressing on schedule. In Offshore Africa, at Espoir we have contracted an alternative rig to complete the infill drilling program scheduled to begin in late 2012. Production increases will begin ramping up in 2013 and increasing to 6,500 BOEs a day at the completion of the drilling program, with a total cost of $143 million, about $75 million of which will be spent in 2012 for an overall cost of $24,000 a flowing barrel. We've also been awarded a 36% interest in Lot 514 in Cote d'Ivoire. We acquired 3 seismic and look to drill a well in the next 3 years on what we believe to be a prospective deepwater cretaceous channel/fan play, similar to the recent discoveries in Ghana and elsewhere in Offshore West Africa. In Q1, we continue to progress tying up the regulatory requirements before drilling our South African exploration well. This series of very large prospects is at the ready-to-drill stage and has the potential for billion-barrel structures, with our best estimate in place of 3 billion barrels. We own this block 100%, which is in deepwater with 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. Turning to Horizon, where we continue to focus on operations discipline, utilizing conservative start-up practices and a philosophy of safe, steady, reliable operations. The addition of the third OPP plant has made a significant difference since the start-up in March. With only 2 OPPs in Q4 of 2011, our availability was 81%, which is a big improvement over 2010 availability of 71%. However, with the addition of the third OPP, we have achieved 98% availability in April, a significant improvement. As a result, our reliance on intermediate tankage has been reduced and we can more effectively utilize these tanks to achieve overall high reliability and steady-state operations in the upgrader, which results in less maintenance and equipment failures. Our April production came in at 111,500 barrels a day. 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 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. At this point, our strategy is working well and we are on track, with capital costs running slightly under our cost estimates. We expect this strategy of breaking into smaller pieces, stopping and redefining scope and rebidding, if necessary, will continue to pay dividends going forward, even as market conditions potentially heat up. We have also been able to achieve significant lump-sum EPC contracts that will provide a higher degree of cost certainty going forward. As you heard me discuss at the last conference call, the expansion to 250,000 barrels a day will add significant value for shareholders. Not only in the increased production, but will result in significant reduction in operating costs and increased plant reliability, a key and often overlooked component of expansion economics. Let me take a minute to reiterate these important points. The expansion will have a significant impact on operating costs, as with the exception of mining costs and natural gas costs, our operating costs are largely fixed with the biggest component being labor. Q1 showed you that. Mining costs are roughly $8.50 a barrel at the current time, and with the expansion, we could see small efficiency gains. Natural gas costs are roughly $250 a barrel, assuming a $350 gas price. Therefore, expansion economics look very favorable as operating costs for the entire production stream 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 in itself, produces operating costs on a per-unit basis, make a significant contribution to the return on capital for Horizon expansions. Truly, Canadian Natural's in great shape, with significant production growth and value to unlock our oil assets. And recently, there have been market anomalies that have caused some concern. In particular, the logistical constraints at Cushing have caused the WTI-to-Brent differential to blow out. We believe that this is an anomaly and will be short-lived as the Seaway reversal kicks in this month. Worldwide expansion in Q1 2013 relieving the bottlenecks at Cushing. Ultimately, with the Keystone-Cushing market link coming in Q2 2013, we believe the WTI-Brent differential will collapse, back to essentially the approximate total rate between Cushing and the Gulf Coast, good news for all North American oil producers. On the heavy side, the blow-out of heavy oil differential in the first quarter is almost entirely due to planned and unplanned outages of heavy oil requirement capacity, as John mentioned. As this capacity comes back online, we have seen a dramatic narrowing of heavy oil differentials. Main spot differentials are $20 a barrel or 19% of WTI, below our long-term estimate of 22% to 24%, and current June indications are in the 14% range. Now there is some concern that additional Canadian heavy oil volumes slated to come onstream by year end, we will see a widening of differentials at that time. We believe this is unlikely, as an additional 300,000 barrels a day of heavy oil conversion capacity is also slated to come onstream. In summary, capital expenditure for 2012 will be $7.35 billion, which includes $100 million allocated for property acquisitions and another $150 million of our free cash flow recently allocated to long-term oil projects for the second half of 2012, which does not add any material volumes for our 2012 guidance, however, will push us up slightly within that guidance range. We are increasing the oil development capital to capture additional value-adding opportunities not contemplated in the original budget. These projects make good sense and are an excellent use of our free cash flow. In more detail, this includes the following items: longer horizontal light oil wells with more fracs; additional oil cost reduction projects, converting our primary heavy oil wells from propane to natural gas, adding water disposal wells and importantly, sand-handling facilities; drilling 10 additional wells in Q4 at Pelican; additional battery facilities at Pelican to handle increased polymer and Woodenhouse volumes. Kirby South facilities are running ahead of schedule, good news, so costs are accelerated. Kirby North, we accelerated ordering of long leads to lock in lower costs. And at Primrose, we've added more pad facilities in Q4, and we've acquired additional exploration block in Cote d'Ivoire. In addition to all this, we've seen some cost inflation in our very active primary heavy oil areas in the order of about 5%. Canadian Natural targets cash flow between $7.2 billion and $8 billion at the strip, giving a free cash flow between $800 million and $900 million in 2012. And as I just mentioned, we're putting some of that free cash flow to excellent use in our long-term, value-adding projects. Our production growth is very solid at 10% Q4 over Q4 '12 to '11, very impressive when you consider this growth is organic, and 54% of our capital program does not deliver production in 2012. Considering the volatility in the global economy today, it's also important that we have a significant flexibility to reduce our capital program by up to $3 billion or 40% if a significant event were to occur, ensuring we preserve our strong balance sheet, which in 2012 becomes stronger, with debt reduction of over $300 million and debt-to-book shrinking to 24.5% at the midpoint of guidance. Canadian Natural is in a very strong position. With our effective capital allocation strategy, our balanced assets which contain significant upside, we are delivering strong, oil-weighted production growth. Investing significantly in future production growth, we are retaining capital flexibility, paying down debt and generating free cash flow. 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, 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. Cash flow from operations amounted to $1.28 billion or $1.16 per share, and adjusted net earnings amounted to $300 million or $0.27 per share in the first quarter of 2012. Our financial results for the first quarter of 2012 were impacted by the production disruption discussed by Steve at Horizon, as well as lower netback realizations for our Western Canadian Select crude oil and our natural gas sales. The reduced cash flow from Horizon operations also resulted in a temporary increase in our effective income tax rate on adjusted earnings in the quarter to 35%, as a result of the proportionate share of income allocated to higher tax jurisdictions outside Alberta, in particular, the United Kingdom. We believe that with Horizon operating as planned with improved reliability, our annualized effective income tax rate will return to our expected range of 26% to 30%. Our balance sheet metrics remain strong. We exited the quarter with $8.2 billion of long-term debt, below the $8.6 billion at the end of 2011. Our debt-to-book capitalization at the end of the quarter is 26% and debt to EBITDA is 1x. Our liquid resources also remained strong. At March 31, our undrawn bank lines amounted to over $4 billion. Our commodity hedging program has been further enhanced and now includes 150,000 barrels per day of Brent collars with a floor of USD $80 for the remainder of 2012 and then reducing for the first half of 2013 to 50,000 barrels per day. In addition, we have $80 puts for 100,000 barrels per day for the remainder of 2012. Our Q1 results reinforce our commitment to a strong balance sheet, adequate liquid resources and a flexible capital structure to weather uncertain commodity prices and unpredictable events, whether they be short-term, event-driven or long-term, cyclical changes in our business environment. Thank you, and I'll return you to John for some closing comments. John G. Langille: Thanks, Doug and Steve, for your comments and discussions. As always, we will continue to grow our business in a prudent manner, with the ultimate mandate to create value for the company's shareholders. With that, operator, I'd now like to open the call to questions participants may have.

[Operator Instructions] Our first question is from George Toriola from UBS. George Toriola - UBS Investment Bank, Research Division: Just my question is around -- Steve, you've talked about the organic growth, which is quite impressive. Now based on all of this is heavy oil, so the question really is around at what price -- and my understanding is the underlying reason, one of the underlying reasons for the growth is obviously higher oil prices. So at what crude oil price would you start to take a second look at your heavy oil portfolio? If you could talk about WTI prices and also what discount so heavy oil differentials would be bothersome to that growth? Steve W. Laut: Thanks, George, and I would say you're right, the majority of our growth is heavy oil, but there's significant light oil growth in the synthetic from Horizon. And obviously, our light oil growth in Canada is growing at 15% from about 65,000 barrels a day. So we do have light oil growth, so there's good balance there, but a lot of it is coming from heavy oil from our terminal projects and from primary heavy oil and at Pelican. So each one of those things would probably have a different cutoff point. I would say if you start with thermal heavy oil depending what your gas price is, if you had gas prices in the $5 range, and obviously, we're a lot lower than that today, but if you had gas prices in the $5 range, you would probably look at about a $55 to $65 range to cut off. Our primary heavy oil would probably be maybe even lower than that in the $50 range. And then Pelican Lake, I would say it'd be close to the same as primary in that $50 range. Now obviously, with lower gas prices, our thermal heavy oil would have a lower cut point. Now differentials are -- obviously play a big part of it, so we're assuming we have announced prices at that normal range of 22% to 24% WTI. That's where we think, long term, where we'll end up. And we could tell -- obviously, our primary heavy oil wells are very effective. Woodenhouse, for example, those wells are paying out in less than 6 months. So I hope that gives you color, George. George Toriola - UBS Investment Bank, Research Division: Okay, that's helpful. I guess just one quick follow-up. And we've seen the gyrations in differentials and you talked about your expectations for the differentials tightening here. As you look into the future, are you -- would you look at any downstream opportunities just to be able to capture some of that -- some of those directions that generate outside profits on the downstream side? Would that be something you'd consider at all? Steve W. Laut: We have looked at it in the past and we did consider it, and I guess I'll point out that we are progressing the engineering at Redwater, our partnership with Northwest. The upgrader there is going to be built in Edmonton. That's 50,000 barrels a day. The engineering is progressing on track, and we expect to sanction that project this year. So we're working on that part of it. We've been unable to do, as many other producers have been doing, is trading reserves for downstream assets, mainly because our view is we can build upgrading and refinery assets but we can't build reserves in the ground. So for us, it's been tough to make that deal work. But obviously we're open to it, but I think our path right now is through the Redwater upgrader and getting increased access to heavy oil refining markets. To that end, we do believe Keystone will be approved. Or it won't be approved until after the election, obviously. And when that happens, plus all the other pipeline activity you see, we should be able to access significant heavy oil markets in the Gulf Coast.

The following question is from Greg Pardy from RBC Capital Markets. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Steve, just a couple of questions and one is just on the Canadian oil liquids' OpEx. How much of the delta do you think was related to onetime items? And how much of a reversal would you expect as we get into the second and third quarter? And second question is just more strategic. You acquired about $1 billion of nat gas properties last year. Is this the kind of market where you're going to continue to consolidate, just given pricing and so on? Steve W. Laut: Yes, I think -- let's talk about the gas price first, then I'll get back to the operating costs, so I don't forget gas. I have a hard time keeping focused on gas. We think there are opportunities out there for gas price, but right now we are not seeing a lot of it. And obviously, it has to fit with us and it has to make sense. And so we haven't really done too much yet, but we obviously monitor the market and we evaluate everything that's in our core area. As towards operating costs, almost the largest part of that is onetime events. Obviously, the Beartrap and Lindbergh batteries caused us to truck volumes all over the place. We have additional sand that we had to truck. Now we have the sand-handling facilities coming onstream. We have additional sand disposal wells, and both Lindbergh and Beartrap are back onstream at full capacity after the upset. So most of that's going to go away, and that's why we believe we're going to be right within the guidance that we set out at the start of the year, and that's $11 to $13 a barrel versus the $15.40 we had here in the first quarter. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay, great. And then the last thing that threw us a little bit was just that it was like a $94 million charge. I hate modeling questions, but it was like a $94 million charge, I think, on FX and so forth. Could you speak to that as well? Douglas A. Proll: Greg, basically, what we have is we have outstanding foreign exchange positions related to our currency management in our business, and those positions settle monthly. So the positions -- the ones that you saw in the first quarter, the $84 million were the losses. We would expect some reversal of those in the second quarter. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay, partial or... Douglas A. Proll: Well, it's tough to predict the movement of the Canadian dollar vis-à-vis the U.S. dollar on a monthly basis, but yes, we would see some reversal in April.

The following question is from David McColl from Morningstar. David McColl - Morningstar Inc., Research Division: Two questions I have here. The first one's kind of on Horizon, and the other's just jumping back to production expenses. So for Horizon, the state of the capital costs are running slightly under your cost estimates. I'm just wondering if you could give any clarification on what those cost estimates are looking at right now for Phases 2a and b. And the production expense question relates to natural gas, kind of related to the oil question. Now can you kind of give some extra insight into what part of that 15% higher cost relative to Q1 2011 are kind of onetime events? Or are we going to be looking at higher costs going forward for natural gas? Steve W. Laut: Thanks for bringing up that operating costs and gas, because I missed that. Obviously, our natural gas price costs are higher in the first quarter, and that is due entirely to some acquisitions that we had closed in the fourth quarter, and it takes us some time to get those things assimilated into our system and see those costs drop. So again, that's on the processing. We made good progress in the first quarter, and we haven't changed our guidance for operating costs in gas for the year because we believe and we are well on track to getting those costs back in line. So we'll be within guidance on gas, so that's a onetime event on natural gas. Horizon capital, we're running slightly under and I would say it's maybe about 5% under and some parts are 10%, with over only 5% and we'll see how that continues. Obviously, we have some concerns if the market will heat up and we'll not be able to continue to get those discounts going forward, but we're going to do our best. David McColl - Morningstar Inc., Research Division: Could you give any clarification on dollar per barrel amount there, total cost? Douglas A. Proll: We haven't done that at any time in the past, and we're not going to give out capital costs, mainly because it creates expectations in the construction and contracting market.

[Operator Instructions] The following question is from Chris Feltin from Macquarie. Christopher Feltin - Macquarie Research: Quick question just with regards to the Woodenhouse asset. Just wondering if you could mention what zone that is, curious if it's a Wabiska play, something you see that's a regional. And kind of looking beyond this year, like how much running room do you see in that play? Second related question would be on the royalties there. Just given the location, is it something where you're also getting oil sands equivalent royalty? Or would it look more like a typical heavy oil royalty for conventional oil in Alberta? Steve W. Laut: Woodenhouse is in the Wabiska zone as you mentioned. It is primary heavy oil. We see quite a bit of running room, like I say, we have 245 wells to drill. It does get the 1% royalty, it's oil sands royalty to a payout. We believe on Woodenhouse alone, the overall pool is probably about 282 million barrels in place. However, I'd say the sweet spot is probably about 163 million barrels in place. And recoveries look to be about 15%, but with the performance we're getting, that might creep up over time, but it's too early to see that kind of increase in recoveries.

There are no further questions registered. I'd like to turn the meeting back over to Mr. Langille. John G. Langille: Thank you very much, operator, and thank you, participants, for listening in to our conference call today. As usual, any further questions you might have, don't delay contacting us and have a good day. Thank you very much.

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