Douglas A. Proll - Executive Vice President Corey B. Bieber - Chief Financial Officer and Senior Vice President of Finance Steve W. Laut - Principal Executive Officer, President, Non-Independent Director and Member of Health, Safety & Environmental Committee

Greg M. Pardy - RBC Capital Markets, LLC, Research Division Philip R. Skolnick - Canaccord Genuity, Research Division Mark Polak - Scotiabank Global Banking and Markets, Research Division Christopher Feltin - Macquarie Research Michael P. Dunn - FirstEnergy Capital Corp., Research Division John P. Herrlin - Societe Generale Cross Asset Research

Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2013 Third Quarter Conference Call. I would now like to turn the meeting over to Mr. Doug Proll, Executive Vice President of Canadian Natural Resources. Please go ahead, Mr. Proll. Douglas A. Proll: Thank you. Good morning, and thank you for joining the conference call to discuss our third quarter financial and operating results; receive an update on certain projects, including Kirby South at Horizon Phase 2/3; an update on Primrose; and the 2014 production and capital budget. With me this morning are Steve Laut, our President; and Corey Bieber, our Chief Financial Officer and Senior Vice President of Finance. Before we begin, I would refer you to the comments regarding forward-looking information contained in our press releases and also note that the dollar amounts are in Canadian dollars and production and reserves are expressed as before royalties, unless otherwise stated. I would like to make a few brief comments on the third quarter before turning the call over to Steve and Corey. A PDF copy of the slides is available on our website, and for those of you turned to our webcast, please refer to Slide 4. Cash flow from operations amounted to $2.45 million (sic) [$2.45 billion] for the quarter or $2.26 per share. Cash flow for the 9 months was $5.7 million -- $5.7 billion or $5.23 per share, an increase of 28% over the same period in 2012. Net earnings and adjusted net earnings from operations for the third quarter were also very strong at $1.07 and $0.93 per share, respectively. This record quarterly cash flow was driven by new levels of production from each of primary heavy oil, Pelican Lake, Septimus liquids, thermal in situ, and Horizon Oil Sands. These achievements resulted in record quarterly production of 509,000 barrels per day of liquids and 703,000 barrels of oil equivalent -- barrels of oil equivalent per day. We also realized significantly higher netbacks for crude oil, natural gas liquids and synthetic crude oil, driven by higher WTI and data benchmark pricing, lower heavy oil differentials for Western Canadian Select and lower overall operating costs. Our product mix continues to diversify where light oil, natural gas liquids and SCO represents 30% of BOE production. Heavy Pelican Lake and bitumen crude oil is 42% and natural gas is 28%. I would like to mention the importance of diversification across the various product streams is further emphasized where, for the third quarter, 93% of revenue was generated by crude oil, largely due to the erosion of North American natural gas prices. Compare this to 2008, where approximately 70% of revenue was generated by crude oil. On the product side, first steam was injected into the Kirby South SAGD project in September, ahead of schedule and on budget. All steaming and production equipment are in service and now wait for the full response to take effect and we ramp up production to a targeted 40,000 barrels of oil per day by the end of 2014. Operating performance at Horizon has been consistently strong and reliable since we completed the first major turnaround in May. Production averaged 112,000 barrels of synthetic crude oil for the third quarter. The plant expansion at Septimus was completed in the third quarter. And in early September, production levels were achieved to the expanded plant capacity of 125 million cubic feet per day and 12,200 barrels of liquids per day. Septimus is, of course, our liquids-rich Montney natural gas play. As previously announced, we finalized the agreements with the government of South Africa and Total, which resulted in the disposition of a 50% working interest and transfer of operatorship to Total. This transaction advances the drilling of the first exploration well on the offshore block and validates the value of this exploration opportunity. The first exploration well is targeted to be drilled in 2014. As we continue to maximize shareholder value from our very strong and diverse asset base, the continued focus on safe reliable operations, continued strong operational results and the advancement to completion of our project inventory, the Board of Directors has increased the quarterly dividend payable on January 1, 2014 to $0.20 per share. This is the 14th year of consecutive annual increases and represents a 60% increase in the annualized dividend rate to $0.80 per share from $0.50 per share. This also represents a 24% compound annual growth rate in the dividend from its inception in 2001, and a 31% compound annual growth rate since 2009 when we completed Phase 1 of the Horizon project. I will now turn you over to Corey for his review. Corey B. Bieber: Thank you, Doug, and good morning. Turning to Slide 5, as Doug noted, the third quarter of 2013 provided exceptional cash flows as well as record production levels. From a pricing perspective, the market developed largely as we had forecast, and our production growth accelerated from Q2 levels by 17%, with production increases realized in almost all segments except in, as expected, international. This growth was delivered just as WTI pricing was increasing and heavy oil differentials were narrowing. This record cash flow of $2.45 billion, combined with proceeds received -- realized on the South African property farm-out, helped facilitate a reduction in our debt by about $600 million from June 30 levels. That was even as we expended $1.9 billion in capital expenditures to further grow our business. The net result is that our balance sheet continues to strengthen, with debt-to-book cap, flat; and debt-to-EBITDA targeted to end in 2013 at approximately 1x versus the 1.2x recorded at the end of 2012. These key metrics are expected to continue into 2014, with virtually no change despite an increase in dividends and a robust capital program which Steve will discuss shortly. Further, financial liquidity remains very strong, with available liquidity of approximately $2.9 billion under our committed bank lines, and very good access-to-market continued through our recently renewed shelf prospectuses in both Canada and the U.S. Our team has confidence in our ability to deliver the defined plan. We have a proven track record showing we are nimble through the -- even the low end of the business cycle, be it $2 natural gas or 45% heavy oil differentials. We have also proven we are just as adept at capturing market opportunities, such as acquisitions, and at preserving value and optionality of assets at the low end of our business cycle. Our significant size as well as our balance and diverse asset base, coupled with management's willingness to make the hard decisions, affords us ample opportunity to effectively allocate capital to the greatest returns while also retaining flexibility in the event of downward pricing. Our prudent hedging practices also afford further downside protection. We currently have about 317,000 barrels a day of crude oil volumes in Q4 of '13 hedged and a further 184,000 barrels a day hedged for 2014, all designed to either limit downside risk to indexed crude oil prices or differentials. Similarly, we have approximately 500 million a day of 2014 summer gas protected with $0.50 AECO/NYMEX differential locked in, again, a prudent move. A summary of our financial and fiscal hedge books is available in our financial statements and on our website. It is a strong endorsement of our confidence to deliver the defined plan, which has led to the announced 60% increase in our quarterly dividend rate. It also reflects our successful execution to date on the Horizon Phase 2/3 development, both in terms of the construction accomplished and cost performance to date, as well as the amount of future contracts that have been awarded. To date, over 2/3 of project costs have been completed or have been moved to the contracting stage. We have always contended that our transition to a low-decline, long-life asset base would ultimately lead to higher returns and more free cash flow being returned to shareholders. Our shareholders have been the beneficiaries of a significant share buyback program in 2012 and year-to-date 2013, under which more than 18 million shares have been bought back at a cost of approximately $562 million. With today's announcement of the increased dividend, our shareholders have also been the beneficiary of a 31% compound annual growth rate in dividends since rise in Phase 1's completion in 2009. The continued delivery of our defined plan augurs well for continuing that tradition of both growing our business and returning money to shareholders while maintaining a very financially strong balance sheet. With that overview of our financial strength and positioning, I'll now turn the call over to Steve Laut to detail our 2014 growth and value enhancement initiative. Steve W. Laut: Good morning, everyone, and thanks, Corey and Doug. As Doug and Corey have both pointed out, our second quarter was a very strong quarter for Canadian Natural and we expect 2014 to be a strong year as well. Before I get into highlights of the budget, I'll start by making a few comments about Canadian Natural's business model, starting on Slide 7. As you know, Canadian Natural has, and will continue to build, a premium value, defined growth in the tenet. We're one of the few companies in our peer group that has the assets to deliver free cash flow on a sustainable basis, a direct result of the strength of our assets, the robustness of our business model and strategies and our ability to effectually execute these strategies. It all starts with Canadian Natural's diversified and well-balanced asset base that is delivering significant cash flow. An asset base we're able to grow by utilizing roughly half of our cash flow, generating significant free cash flow. Free cash flow that is set to increase dramatically as a result of the effective and strategic capital allocation choices we have made. Canadian Natural has essentially 4 free cash flow allocation choices. The development of our large resource base, which receives a lion's share of the capital location at this point, which in turn increases the strength of our asset base and increases our ability to generate even greater amounts of cash flow, and due to long-life, low-decline nature of these resources, even greater amounts of more sustainable free cash flow going forward. Secondly, we can and have returned free cash flow to shareholders. It has grown significantly at a 31% CAGR the last 5 years, as we've announced today, increase significantly in 2014. Reflection of our increasing free cash flow, the confidence and ability of our assets to deliver sustainable free cash flow, the progress we've made with Horizon expansion and our confidence in our ability to effectively execute on a cost-effective and timely basis our defined growth plan, unlocking ever-increasing free cash flow from our resource base. Thirdly, we can allocate some of our free cash flow to opportunistic acquisitions, if they're available, add value and strengthen our asset portfolio. Finally, we can allocate free cash flow to strengthening the balance sheet, a balance sheet that is already very strong. This model is highly effective, it starts with our balanced diversified asset base and is driven by effective capital allocation, effective and efficient operations and strong management. Canadian Natural is in a very enviable position and has a clear advantage compared to many of our peers when it comes to unlocking the value and free cash flow from our long-life, low-decline resources. It all starts with the strength of our large well-balanced asset base, Slide 8. At 4 billion BOEs, Canadian Natural has the largest proved reserve base amongst our Canadian and U.S. peer group. On a proved and probable basis, Slide 9, Canadian Natural has 8 billion BOEs, the largest reserve base compared to our Canadian peers. Our reserve base is large, but our long-life, low-decline resource base is even larger, Slide 10. Canadian Natural has significant resource base we are developing in a disciplined, cost-effective approach, unlocking huge value and significantly increasing our sustainable free cash flow. We can add an additional 14 billion BOEs to our reserve base, most of which are long-life, low-decline assets at Horizon, thermal and Pelican, with an additional 1.8 billion BOEs or 11 Tcf of undeveloped gas to develop in the Deep Basin or Montney alone. We own, operate and control all the resources and will more than quadruple the proved reserve base of the company to 22 billion BOEs. Few, if any, of our peers have the assets, the balance sheet, the expertise or the free cash flow to fund the cost-effective [indiscernible] of our resource base, allowing Canadian Natural, over time, to more than quadruple our proved reserve base and not only grow our reserved cash flow significantly, but increase the sustainability of this free cash flow. Although our reserve base has the capacity to be almost quadruple, our primary goal is value growth and to drive ever-increasing economies of scale to generate even greater profitability. Canadian Natural's resource base is unique and places us in an enviable position relative to our peers, Slide 11. Our resources are long-life and low-decline. As you can see, we are effectively transitioning our overall asset base to an ever-increasing proportion of long-life, low-decline assets that generate increasingly more sustainable free cash flow going forward. Canadian Natural's focused on free cash flow generation, Slide 12. Our plan has us allocating roughly $7 billion to $8 billion of capital per year for the next 3 to 4 years, well below our cash flow, assuming relatively stable commodity prices. In 2017, capital requirements to transition to longer-life, low-decline assets dropped dramatically. Canadian Natural's free cash flow is significant, over $1 billion in 2014, rising to just under $2 billion by 2016, then substantially increasing at a 75% CAGR to a sustainable $5.5 billion to $6.5 billion a year thereafter, assuming, of course, a stable commodity price and economic and regulatory environment. Canadian Natural's ability to grow and sustain free cash flow is one of the key factors that differentiates us from our peer group and is, in my opinion, unrivaled. Canadian Natural has always been prudent allocators of capital and it's one of the major reasons we are in the enviable position we are today. Going forward, Slide 13, you can expect we will continue to be prudent allocators of our free cash flow, allocating cash flows as follows. The development of our long-life assets at roughly the same levels we have for the last 2 years. However, as Phase 2/3 at Horizon executes and progresses and is complete in 2017, a portion of our free cash flow allocated to resource development will drop dramatically. To dividends, as you know we've increased dividends at a compound 31% CAGR since Horizon Phase 1 came onstream in 2009. And today, we've announced a 60% increase in dividends to $0.80 a share, reflecting our increased free cash flow, the strength of our assets, our ability to execute and the significant progress we've made on Horizon Phase 2/3 expansion. To share repurchase, which have become a larger part of our free cash flow allocation in 2013, we are on track to allocate about $300 million to share buybacks. To opportunistic acquisitions, it's something we are good at. That being said, we have no real gas on our portfolio, so any acquisition will need to have significant value. Or we can pay down debt, however, our balance sheet is very strong, running right at the bottom of our target debt-to-book range of 25% to 45%. Canadian Natural has taken a balanced and prudent approach -- prudent allocation with our free cash flow, Slide 14, with free cash flow return to shareholders increasing at 31% CAGR since 2009 when we brought on Horizon Phase 1. A very important step in Canadian Natural's transition to longer-life, low-decline assets and our ability to deliver increasing and sustainable free cash flow. In 2014, Slide 15, Canadian Natural targets generating $8.7 billion of cash flow, up 15% from 2013. Our base capital program will increase slightly, 7.6% to $7.7 billion, generating $1 billion of free cash flow, 115% increase in free cash flow over 2013. In 2014, the free cash flow will be allocated to dividends at $870 million, up 66% over 2013, to share repurchases depending on market conditions and, potentially, to Horizon Phase 2/3, which is dependent on construction market conditions. As a result, we'll utilize the balance sheet to a minor extent. However, as the increase in equity and EBITDA, the balance sheet strength, for me, remains intact or strengthens, depending on the flex capital and share repurchase allocation. Consistent with our track record, Slide 16, as our free cash flow increases and we effectively progress our transition to longer-life, low-decline assets, of Kirby South ramping up, and both Pelican and polymer flood conversion, and Horizon Phase 2/3 expansion on track, and significant capital behind us, we've increased our return to shareholders significantly at 35% CAGR. The 2014 budget, Slide 17, our capital program will be between $7.7 billion and $8.1 billion, delivering near-term 2014 oil production growth of 9% at the midpoint. The capital program is allocating $3.6 billion or 45% of the capital budget to projects that do not deliver production in 2014 and has a significant capital flexibility, with $3.2 billion of the capital budget able to quickly be curtailed if we choose. Slide 18 breaks down the capital budget by area. The highest are a decrease in Pelican spending as our facility expansion is complete, an increase in thermal spending as Kirby South is complete and Kirby North begins to ramp up, the increase in international spending as we increase drilling in North Sea and commence the Espoir infill drilling program, the raised capital spending on Horizon sustaining capital and turnarounds, balanced with increased spending in Horizon projects. Slide 19 breaks down the production growth by area, with strong 9% growth in liquids overall, driven by thermal production at Kirby, Horizon, primary and light oil growth. Natural gas production is growing year-over-year, although slightly flat, entry to exit, for 2014. Now before I highlight each of our assets, let me make a few comments about the oil markets, Slide 20. As you know, the market is essentially unfolded as we predicted. And also, as you know, the transportation infrastructure is complex and misconceptions are common. It's important to remember that there is significant demand for Canadian heavy oil coming, with the Whiting Refinery and PADD II getting closer to adding 260,000 barrels a day demand, with additional transportation access, 3 billion -- 3 million barrels a day demand in the U.S. Gulf Coast is also coming. Transportation to PADD II is a lesser concern than to the U.S. Gulf Coast. However, many transportation opportunities exist with 400,000 barrels a day of mainline optimization, 600,000 barrels a day in the Q2 2014 at Flanagan South, providing incremental access to the Gulf Coast, as well as Keystone at 830,000 barrels a day to the Gulf Coast, Gateway and TMX to the West Coast with a combined 1.4 million barrels a day, and Energy East to East Coast at 1.1 million barrels a day. Although these all require approvals to be built, they will provide access for Canadian heavy oil production. Of course, the timing of regulatory approvals are difficult to predict. As a result, there could be short-term gaps in transportation takeaway capacity. These gaps are expected be short term and can be filled with additional real capacity. Canadian Natural believes that pipeline transportation is the preferred method of transportation. It is the safest, most environmentally friendly and most economic solution. As a result, we expect very strong heavy oil pricing in 2014 and beyond. There'll be periods of short-term volatility, but they'll be very short-term in nature. Turning to our assets, starting with natural gas, Slide 22. Canadian Natural is the second-largest natural gas producer in Canada, with a very large land base and effective and efficient operations. When gas prices strengthen, Canadian Natural's in great shape. Our vast asset base in conventional and unconventional gas and our dominant infrastructure position allow us to maximize the benefits of higher gas prices if we choose, allows us to quickly and efficiently increase gas drilling and production at very effective costs. Gas prices are strengthened somewhat in 2013 and the widening of the AECO bases, which occurred in Q3 has returned to normal levels as expected. With a November bias -- basis running at $0.24, December at $0.31 and the strip for 2014 at $0.48. And as Corey pointed out, we've locked in April to September AECO basis at $0.49 for 500,000 -- 500 million a day. Canadian Natural has a dominant land position, Slide 23, with over 1 million net high-quality acres, the largest in the industry. In order to maximize the value of this important asset, Canadian Natural has began a process to monetize approximately 243,000 net acres, approximately 375 net sections of our Montney land base in the liquids-rich fairway in the Graham Kobes area of Northeast B.C. On the process, Canadian Natural considered either an outright sale of the lands or a joint venture partner with LNG expertise to jointly develop the lands. If this process meets our internal targets and a transaction is completed, Canadian Natural will continue to have one of the largest undeveloped Montney land bases in Canada, with lands contained in 2 major areas at Septimus and B.C. as well as Northwest Alberta. The process is well underway with lots of activity in the data room. Our 2014 plans, Slide 24, sees us increase gas drilling to 61 wells from the 42 wells we expect to drill in 2013, as we target additional liquids-rich wells at Septimus and the Deep Basin. On our Canadian Natural's thermal heavy oil lands, Slide 25, we have 97 billion barrels in place and we expect to recover 10.6 billion barrels from our vast thermal heavy oil resources. Canadian Natural is executing a disciplined step-wise plan, Slide 26, to unlock the huge value of this asset base by bringing on 40,000 to 60,000 barrels a day every 2 to 3 years, taking production facility capacity to 510,000 barrels a day or 0.5 million barrels a day, all at 100% working interest. 365,000 barrels a day of this 510,000, roughly 70%, will be coming from SAGD developments. And 2014, Slide 27, sees a 23% increased production as Kirby production ramps up to 40,000 barrels a day by 2014 year-end. Capital spending is down as we're drilling less Primrose seepages and the Kirby South facilities have been completed in 2013. I will now spend a few minutes on the Primrose seepages we have experienced, starting at Slide 28. The seepage is contained, the clean-up is greater than 80% complete and no incremental environmental surface damage is expected going forward. The causation review is well underway and we're confident that the root cause of these seepages are wellbore failures. Now there's a certain amount of complexity around these seepages and, as a result, the actual seepage mechanism is quite often misunderstood. So I'll take a few minutes to explain what is happening at Primrose, the wellbore geometry and, importantly, the rock mechanics that govern what actually feasibly can and cannot happen, Slide 29. As you can see on this slide, we showed the various geological sections starting with the Quaternary at surface, going deeper to the Lea Park shale, a very thick Colorado Group shales; the Grand Rapids, which is essentially a sand interlaid with shales and is filled with saltwater; the Clearwater shale, the Clearwater sand, which contains the oil we stimulate with cyclic steam to recover the oil and is at 500 meters below the surface; and below this lies the Wabiska and Paleo zones. There are 3 major rock formations that prevent fluids from leaving the Clearwater sand when we are cyclic steaming. Clearwater shale cap that is between 4 and 6 meters thick; the Grand Rapids zone itself, which is roughly 100 meters thick; and a thick columns of shale in the Colorado Group, which is over 150 meters thick, and are the ultimate barrier to vertical fluid flow. This schematic shows a horizontal injector/producer in the Clearwater and various verticals stratigraphic wells or strat wells, fueled to remain at the reservoirs as well as thermal fiber observation wells to monitor pressure, temperature and seismic activity in the saltwater-filled Grand Rapids sand. As an example, you can see that these strat wells are drilled into the Paleo to ensure the bottom of the Clearwater is mapped, and to calibrate geological models. When a Clearwater cyclic steam is stimulated, steam is injected into a horizontal well. After predetermined volumes, the injection is stopped. The well is left to soak for a period of time and then the horizontal well is produced backed [ph]. The now heated and less viscous bitumen, flows into horizontal well and is processed through separation facilities at surface. The maximum pressure that steam can be injected into Clearwater sand is governed by rock mechanics. At this maximum pressure fluid, steam and hot water moves to the Clearwater sand in a vertical or horizontal plane away from the horizontal well until a steam injection is stopped. It is physically impossible to inject steam or fluids above the maximum pressure governed by rock mechanics in the Clearwater. The fluids simply continues to move through the Clearwater sand and as a result, the pressure cannot exceed this maximum pressure. At these pressures, the Clearwater shale contains all the fluids in the Clearwater. However, subtle changes in the shale thickness, rock composition and structure combined to cause locally restricted areas a weakness. As a result, fluids can escape from the Clearwater into large saltwater-filled Grand Rapids zones. This happens infrequently and we have seen evidence for these subsurface releases in the Grand Rapids at roughly 450 meters deep with our observation wells. The Clearwater shale is the first barrier to vertical flow and, clearly, in almost all cases, contains the fluids in the Clearwater. The saltwater-filled Grand Rapids is itself a significant barrier that absorbs and contains any fluids that infrequently release at the sub-surface about 450 meters deep through the Clearwater shale. Importantly, it also serves as an early warning system that we can, with enhanced marking use to detect fluid releases from the Clearwater. If fluids are released in the Grand Rapids sands, the fluids will move vertically to the Grand Rapids, dissipating the pressure or, if the release from the Clearwater is larger, they travel vertically until it reaches the base of the thick column shales of the Colorado Group. The fluids then will move horizontally to the Grand Rapids zones until the pressure is dissipated where a fluid encounters a failed wellbore and, depending on the size of the release, allow fluids to migrate up the failed wellbore to higher levels in the Colorado. The rock mechanics and the stress states in the shale for the base of the Colorado Group prevent the fluids from entering the Colorado. This has been confirmed by all of the stress state measurements, material testing in the Colorado shale and over 30 years of steaming with thousands of wells. All of the evidence and data collected to date in the causation review points to the conclusion that the only way the fluids can make it through the shales at the base of the Colorado Group is by a failed or partially-failed wellbore that allows fluids to travel into higher levels in the Colorado via a failed wellbore. We are, however, collecting evidence to determine if there's potentially any other possible route for emulsion to seep the surface. Today, we have not seen any evidence that would indicate any other possible route to surface. The failed wellbore can be in the form of poor or faulty cement job on abandoned legacy strat wells or in a case well itself, as the casing may have parted in the well. Once fluids migrate up via a failed wellbore at higher levels in the Colorado, fluids can move horizontally through the Colorado. In all cases and, importantly, on strat wells, a second cement plug is placed from the upper Colorado to surface, preventing fluid migration. As a result, if fluids do travel up the failed wellbore, they are stopped at or near the upper Colorado where they then can travel horizontally through the upper Colorado until the pressure is dissipated. The geology of the upper Colorado differs in that it has some natural preexisting vertical or near-vertical fractures. Once fluids migrate up via failed wellbore to these higher levels in Colorado, they can, if they encounter a fracture, they can then flow horizontally and vertically through the upper Colorado until the pressure is dissipated. If it encounters a set of interconnected fractures, it can then make its way up to the Lea Park and Quaternary and results in seepages at the surface. All evidence gathered to date supports this as the mechanism resulting in seepage to surface. It is sound and is governed by rock mechanics and the basic laws of physics. Of course, geology does have a contributing role to play in the seepage mechanism, as natural fractures in the upper Colorado are required for the seepage to travel to surface. However, for fluids to make it to the upper Colorado, a failed wellbore is required and is the root cause of the seepages. In addition, at Primrose East, where the 3 seepages -- 3 of the seepages have occurred, the Paleo Zone below the Clearwater has a tendency to cause lost circulation when drilling and cementing. This may be a geological factor in causing wellbore failures and legacy strat wells that were drilled to the Paleo, as the integrity of cement jobs in these wells may have been compromised. More recent strat drilling have modified drilling and cementing procedures to ensure cement integrity for strat wells. Our causation review is still underway, Slide 30, and we're looking -- working well with the Alberta Energy Regulator in progressing the causation review. Today, we have identified 4 legacy wells as the most likely wellbore failures that are the root cause of seepages. Two of these 4 wells have identified mechanical failures and we are undertaking additional work to prove this conclusively. One well is currently under review and the remaining well is waiting for surface access approval. Working Canadian Naturals entire Primrose area, we have identified 31 legacy wells that are low abandoned according to regulations, we now believe post a higher risk potential for future wellbore failures. 16 of these 31 wells are within 1 kilometer of areas to be steamed in 2014. One of these wells have been confirmed and repaired, one well has good integrity and has been equipped with enhanced monitoring, and the remaining 14 are waiting on surface access approval. The plan going forward, Slide 31, is to review all wells, including all legacy wells to determine their integrity. Those with identified concerns or issues will be prepared prior to steaming. Enhanced marking of any potential leases from the Clearwater into Grand Rapids will be employed. This, along with our advanced understanding of potential lease signals, provides an effective early warning system. If we do see infrequent surface releases from the Clearwater into the Grand Rapids at about 450 meters, we'll have an enhanced response, which includes ceasing injection into the Clearwater and/or immediate flowback to the horizontal injector/producer, relieving the pressure, ensuring fluid movement cannot propagate further into the Grand Rapids. We'll also modify how we steam and the growth of the steam volumes in successive cycles. We'll also be modifying to provide greater certainty that all fluids remain in the Clearwater. In Primrose East, we'll convert into a steam flood after initial steam stimulation cycles, which is operated at conditions that make it impossible for fluids to release from the Clearwater. Once we have regulatory approval, we expect to implement this in 2014. In summary, we are confident in the cause of these seepages, the cleanup is greater than 80% complete, our causation review is well underway, and the steps we will take and the plan going forward is robust. And we'll ensure that likelihood of future seepages is effectively mitigated. This is a technical, operational challenge that is totally solvable. Returning to the budget. Canadian Natural's primary heavy oil assets are excellent, Slide 32. We are the largest primary heavy oil producer in Canada, we dominate the land base and infrastructure, we have over 8,500 locations in inventory. And due, in part, to our dominance and our excellent teams, we have excellent capital efficiencies and lower operating costs, making primary heavy oil the highest return on capital projects in our portfolio, generating significant free cash flow. In 2014, Slide 33, Canadian Natural drilled 900 wells, up 5% from 2013. 183 of these wells are horizontal. Our capital spend is the same as 2013 and we'll drill over 2% growth with guidance in the 142,000 to 146,000 barrel a day range for 2014. Q4 production volumes were impacted by the TCPL gas line outage. As a result, our October production was down approximately 3,000 barrels a day and we're currently using propane as fuel gas, with natural gas service expected to return by November 30 of this year. At our world-class Pelican Lake pool, Slide 34, our leading-edge polymer flood is driving significant reserves and value growth. We have over 4 billion barrels of oil in place and expect to recover 550 million barrels on our polymer flood. Our plan in 2014 at Pelican, Slide 35, is to continue development of polymer flood. We're seeing good production response on our polymer flood and we'll see production increase by 2%. Capital is down significantly to 245 million barrels -- $245 million as the battery inspection is behind us and we drilled 17 wells versus 33 in 2013. Pelican Lake is a great example of Canadian Natural's ability to develop and implement new technology. Allowing Canadian Natural to not only accrue oil from what was thought to be unproducible reservoir, but develop a leading-edge polymer flood to increase recovery and drive increasingly effective and efficient operations. Canadian Natural has an extensive light oil base in Canada, Slide 36. We have significant water flood operations, which we continue to operate -- optimize, as well as leverage horizontal multi-frac technology targeting new play developments. Much of our development will be focused on the Triassic in Northwest Alberta, where we have 1.4 million acres, that may contain significant potential to add light oil reserves and produce -- production utilizing horizontal multi-frac technology. In 2014, we'll drill 93 wells. Capital spending will be $540 million, driving 10% production growth in 2014. In 2014, our international operations, Slide 37, will be an inflection year. After a period of restricted capital allocation due to tax increases in North Sea and a significant production declines, we will see international volumes begin in 2014 to turn the corner, with yearly production up 1.4% but, more importantly, we'll see international exit volumes increase by 30% in 2014, which has a significant impact on unit operating costs and free cash flow going forward. In the North Sea, we've received Brownfield Allowances and will drill 4 producers, 4 injectors and 2 well upgrades at Ninian. In Cote d'Ivoire, at Espoir, we will commence an 11-well infill drilling program in the second half of 2012 -- or '14, which is targeted at 5,900 BOEs a day when complete. In Baobab, we'll progress the development plans for a 7-well infill program that will commence drilling in 2015. 2014 will also be a year we initiate exploration activities in offshore Africa. In Cote d'Ivoire, we are targeting a deepwater turbidite fan systems similar to the Jubilee Field in Ghana. On Block 12, Canadian Natural operates a 60% interest and will commence seismic operations in Q4 2013. We evaluate the seismic at 2014 and potentially drill an exploration well in 2015. On Block 514, where we have a 36% interest, seismic has been shot and processed and a drilling rig has been contracted to commence drilling in the first half of 2014. In Q3, we announced the disposition of 50% of our South African exploration block, Slide 38. This block has 5 significant structures, which sizes up to 1 billion barrels in place. Our partner, Total, will carry -- operate and carry Canadian Natural on the first well up to USD 150 million of gross well costs. As well, a net cash consideration of USD 250 million, including a recovery of USD 14 million of past incurred costs has been received. In addition, if commercial discovery is made, an additional USD 450 million cash consideration for an oil discovery or USD 120 million if a gas discovery is made, will be paid. A drilling rig has been contracted and long lead equipment ordered, with the first exploration well targeted to drill in 2014. This farm-out deal was completed after a very competitive bidding process, in which a number of comparable bids were received, which reflects the value and potential of Canadian Natural South African exploration block. Turning to Horizon, Slide 39. Our world-class oil sands mining operation where we have recovered -- have 14.4 billion barrels in the ground, which is under 6 billion barrels of oil to recover, which will likely grow to closer to 8 billion barrels as we expand our pad limits and seize opportunities as drilling improves the orebody delineation. Our current capacity is 110,000 barrels a day and we're on track to the expansion to 250,000 barrels a day of light sweet 34 API crude, with the ability to expand to 500,000 barrels a day with no decline for 40 years and, virtually, no reserve replacement costs. Horizon will generate significant free cash flow for decades to come. In 2014, the Horizon operation plan, Slide 40, builds on the reliability increases we achieved in 2013. In 2013, we successfully completed our first major turnaround and increased reliability to 8% unplanned downtime post turnaround. This compares to our North American average refinery downtime of 6%. We are confident we can increase our liability in 2014 and bring our own planned downtime closer to 6% level and possibly lower in 2014. In Q3, we averaged 112,000 barrels a day with September production at 117,000 barrels a day and October coming in at 105,600 barrels a day, down due to a loss of fuel gas, in which we lost 3 days of uptime, reducing our October production by roughly 10,000 barrels a day. Our stream day capacity at Horizon has increased slightly after the catalyst change-out to 120,000 barrels a day. As a result, Q3 unplanned downtime was 6.6%, including the fuel gas outage. Our guidance for Q4 is 110,000 to 115,000 barrels a day or 8% to 4% unplanned downtime. As we stated in the previous calls, our Horizon Phase 2/3 expansion has been going very well. Because of this good progress, in 2014, we have the ability to complete the Phase 2A expansion or coker expansion ahead of the 2015 turnaround. By playing this tie-in, stream day capacity will be increased to 133,000 barrels a day, adding 13,000 barrels a day of stream day capacity. And depending on unplanned downtime, roughly 12,000 barrels a day of sales capacity. This time, it's scheduled for September 2014 and will take between 20 and 25 days to complete. Because of the extra stream day capacity, post tie-in, the production guidance for 2014 remains essentially the same, even with 20- to 25-day outage. Importantly, it increases our stream day capacity sooner, it takes work of the 2015 turnaround and mitigates potential congestion issues in the 2015 turnaround. All in all, a very good result and reflects continued strong execution at Horizon. As a result, 2014 production guidance, Slide 41, we will be between 107,000 and 115,000 barrels a day. Sustaining capital is down 18% to $650 a barrel with operating costs down 12%. Guidance is set at $36 to $39 a barrel. Horizon Phase 2/3 expansion, Slide 42, has been going very well and, at the end of Q3, have reached the physical 30% completion point. We've incurred 27% of the cost estimate or about $3.9 billion. And we are committed to roughly half of the project, mostly with lump sum contracts that provide a high degree of cost certainty. In addition, we are at AFE stage or contract negotiation stage for another 1/3 of the project, taking us to 2/3 of the project with very good cost certainty. Today, we're running about 10% under our cost estimate. This plutonic construction is going very well and we may be in the construction window in 2014 similar to 2013 where contractors are focused on sharpening their pencils. This construction and cost certainty performance has brought additional confidence in the execution of Horizon and is part of the reason the board felt confident to raise the dividends. With our detailed engineering complete, we have decided to preserve the opportunity to allocate an additional $400 million to Horizon if construction market conditions remain favorable to achieve cost certainty and savings. Our base plan has us spending $2.5 billion between phases and up to $2.9 billion, if conditions remained favorable. Our target for expansion production additions, Slide 43, will see us accelerate the Phase 2A into 2014 and now increase to 12,000 barrels a day versus expected 10,000 barrels a day. Phase 2B will add 45,000 barrels a day in 2016 and will not be accelerated even if we spend additional capital in 2014 as the critical path remains unchanged. Phase 3 will add 80,000 barrels a day targeted for 2017. And as always, Canadian Natural remains cost-driven, not schedule-driven, and will push out the schedule if we see market conditions become unfavorable. The Phase 2/3 expansion at Horizon is unique when compared to other mining and upgrading developments, Slide 44. The optimal design and performance of Horizon is achieved when we reach 250,000 barrels a day. At these levels, we're able to leverage all pre-built infrastructure in Phase 1, for Phase 2/3, increase reliability as additional redundancy will be achieved and significantly lower operating costs will be achieved, as most of the cost at Horizon are fixed, and will not increase at the same level as production increases. These factors, optimal design, leveraging Phase 1 prebuild, increasing reliability and lower operating cost for all 3 phases of production, allow the expansion of Horizon to achieve our after-tax return on capital criteria. Importantly, Horizon has a very long reserve life, delivering significant cash flow for decades, a cash flow that's sustainable for 50-plus years. Horizon has a very flat production profile, Slide 45, with virtually no reserve replacement costs and in 50 years will have produced 4.6 billion barrels of light sweet 34 API oil. And to replicate this profile require about 13,700 average Bakken wells or 7,100 average Permian wells and require, for D&C costs alone, roughly $110 billion and $46 billion, respectively. A major advantage our Horizon has over normal conventional drilling is the risk around reserve replacement cost and a no-decline production profile. Although the returns for horizontal multi-fracs oil wells are higher, once you drill the sweet spots, replacing reserves becomes very difficult, driving F&D costs higher and returns lower. Canadian Natural is in great shape, Slide 46. Our balance sheet reserve base is the largest in our peer group, a reserve base that ranks with global industry players and delivers significant cash flow. We have a vast, high-quality long-life, low-decline resource base, which we're developing in a very disciplined manner, unlocking significant value and sustainable cash flow for shareholders, which delivers increasing and even more sustainable free cash flow as we move forward. Canadian Natural's free cash flow is significant, Slide 47, over $1 billion in 2014 rising to just under $2 billion by 2016 and then substantially increasing at a 75% CAGR to a sustainable $5.5 billion to $6.5 billion a year thereafter, assuming, of course, a stable commodity price, economic and regulatory environment. So as I said before, Canadian Natural's ability to grow and sustain free cash flow is one of the key factors that differentiates us from our peer group and is unrivaled in my view. Canadian Natural priority for free cash flow has been consistent, Slide 48. Our capital program will be in the $7 billion to $8 billion range for the next 3 to 4 years and then drop as Horizon Phase 2/3 expansion is completing, leaving the additional free cash flow to allocate to the priorities outside resource development. In summary, Slide 49, Canadian Natural's cash flow will be $8.7 billion in 2014; capital spending of $7.7 billion, which includes $2.5 billion of Horizon spending, delivering $1 billion of free cash flow; we'll allocate $870 million to dividends, up 66%, and up to $400 million in the Horizon expansion, depending on market conditions; and yet to be determined share buyback program also dependent on [indiscernible] skewed stock price and commodity prices, leaving our balance sheet still very strong with improved debt-to-book metrics. Canadian Natural is in a very enviable position, Slide 50. Our assets are strong to deliver free cash flow, which we have been very prudent allocators of in the past and we'll continue to do so going forward. And our balance sheet is strong. We have effective and efficient operations and a strong management team that understands the asset base and knows how to effectively allocate capital. With that, I'll turn it over to Doug for a closing comment. Douglas A. Proll: Thank you, Steve, and Corey. Jake, I would look to open up the call for questions, please.

[Operator Instructions] First question is from Greg Pardy from RBC Capital Markets. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Steve, just a couple of questions. Dividend increased, obviously, very large, just curious as to what prompted you to increase dividend in that order of magnitude? And the second question, just around your 2014 cash flow guidance. I may have missed it, but could you tell me what you're using in terms of your WCS dip for 2014? Steve W. Laut: Thanks, Greg. As I said in the call, the dividend increase is large and it does reflect the strength of our asset base. The amount of free cash flow that we have and then the sustainability of that free cash flow, particularly going forward, you're going to see that increase. It's also a reflection of how we're making that transition to longer-life assets. Horizon, as we said before, we're at the 30% mark in terms of completions. We've got quite a bit of capital behind us. We have basically incurred -- committed to over half the project with lump sum contracts, so we've got very good cost certainty there. And we are at the, basically, contract negotiation stage, or AFE stage, for another 1/3. So about 67% of the expansion, we have pretty good cost control going forward and we see good market in construction going forward. Plus Kirby is on, so we made another step up in our long-life assets. Pelican is stabilized and is growing. And we can see that our plan is unfolding as we expect it and that plan includes increasing free cash flow that we're seeing, and that gives us the confidence to increase dividends. And obviously, our free cash flow will increase as we go forward but that, obviously, depends on commodity prices. The differentials we use are on the website, and we also have hedging to balance off that 2014 cash flow. But the differentials we're using are 24% WCS differentials.

The next question is from Phil Skolnick from Canaccord Genuity. Philip R. Skolnick - Canaccord Genuity, Research Division: Two questions on Horizon. How long will it take for the new coker expansion to ramp-up once that comes online and to reach peak? And then, also, how should we think about op costs given the large fixed nature of this project? Steve W. Laut: Thanks, Phil. So we expect the -- we're going to take 20 to 25 days. We may be able to do it faster to do the tie-ins. And the actual ramp-up will be very quick. I would think within a month, we'll be up to the volumes because, really, what we're doing is we're bringing on 2 more coke drums and 2 coker furnaces. So really, the only difference is we're running 6 coke drums instead of 4, and we're adding additional coker furnaces that are all tied into our systems, so that should very quick and very effective. And we got teams working on it here for the last year, ensuring that we have all the operational issues identified and our procedures modified for a 6-drum operation versus 4 drums. Operating costs will be essentially almost linear, except for mining cost, because as you produce more oil, you need more trucks and more people to run it. But the rest of the plants will be essentially on a fixed cost, there'll be chemical costs as that will go with production, but it's largely fixed. So as we increase production, the operating costs for the bitumen extraction and the upgrading portion will be relatively the same or on a total basis. But on a unit basis, will go down. We believe that over the course of 2014, we'll be able to reduce the operating costs, that's why you're seeing a drop to range. And we believe, over time, we can actually get better. We're still very focused on reliability and being conservative in that approach. As we move forward, we expect to more be focused on production optimization and then you're going to start to see operating costs come down. We're very confident that we can do a lot better job on operating costs but we're not promising anything at this point for 2014 other than that 12% drop. Philip R. Skolnick - Canaccord Genuity, Research Division: Okay. And I'm not sure if you'd mentioned this, but how much would have Horizon averaged in October if it wasn't for the TransCanada outage? Steve W. Laut: We would've probably been in about 115,000 to 116,000 barrels a day.

The next question is from Mark Polak from Scotiabank. Mark Polak - Scotiabank Global Banking and Markets, Research Division: The first question, just, again, on the dividend. Historically, you guys have always increased in March. Is this the sort of timing around the year-end that we can expect going forward, is it possible for another increase in March? Steve W. Laut: Thanks, Mark. Traditionally, we always review the dividend policy in the March time frame at that board meeting. We'll continue to do that. This was probably a unique case. As I said earlier, our cash flow is strong. We've got lots of free cash flow and our sustainable free cash flow looks pretty good going forward. And particularly Horizon, capital spending is well behind us, a lot of big chunk of it, plus Kirby coming on. And Pelican, a stabilized production to lower decline rates gives us that confidence to do it now. We will again look at it in March. Mark Polak - Scotiabank Global Banking and Markets, Research Division: And then just in terms of Primrose, just in terms of your conclusion, just curious on your discussions with the AER, if they're in agreement with you to date, and when do you expect that review to be completed? Steve W. Laut: So we are ongoing in the review and, obviously, we need to get surface access to a lot of these wells to get onto them. And we're waiting for that. Part of it is, it's -- obviously, summer is wet, so that some of you wait for frost. I would say, the Alberta Energy Regulator is working very well with us. Obviously, we're collecting data everyday and we provide that data to AER in increments, at specific times. So I think what the AER will tell you is that, so far, they're happy with the review and they're waiting for more data. And we'll get the full report and they'll make their conclusion at that point. But I would say the AER has been working very well with us. And my view from the information I get, in meetings I have with them, I think we're all on the same page. As I said earlier, this is all governed by rock mechanics and the basic laws of physics. So it's pretty hard to go against the law of physics. So we're planning that to our 2014 budget is set, assuming that we get this completed here by the end of the year, early into Q1, get a report in, have the revised plan, which I kind of scoped out how we're going to go forward. I get that approved by the AER and other regulatory bodies that are required, and then start proceeding. So as I said earlier, this is a totally solvable challenge and we will able to handle it going forward.

The next question is from Chris Feltin from Macquarie Securities. Christopher Feltin - Macquarie Research: Maybe just a quick follow-up to Mark's question there on Primrose. I can see how those old strat wells provide that conduit to get up above the shallower Colorado. But just in terms of the potential that you mentioned to be losing some bitumen from the Clearwater into the Grand Rapids, and then looking at that as a conduit into those strat wells, and I know that you mentioned that you're looking at maybe revising your steam injection practices to make sure that you stay within the Clearwater. But just kind of curious if you've seen evidence, one way or the other, like what that pathway is? Is it from the Clearwater into the strat wells or the Grand Rapids? And I guess, secondly, with these revised practices, like what do you -- does this have an impact on what the injection pressures will be in that project? And I guess, just a final tagalong would be, is there any clarity on timing of when you'll get that steam into the ground here, is it going to be before the end of this year? Are we looking more like Q1 '14? Steve W. Laut: Okay. Thanks, Chris. So lots of questions. We believe that the conduit is through the old strat wells or a failed wellbore. Strat wells, we think it comes through mostly to the Grand Rapids. If we'd had a conduit through a filled strat well directly from the Clearwater, I think the response would be different, and we're going to see a much quicker release. So we're done seeing that, so we believe it's going through the Grand Rapids and we could actually see that with our observation. And when you go back and look at our history here, when you have a release into Clearwater, it does tie with some of the releases to seepages to surface. Injection pressures for steam flooding, which we're looking to do, will be less than the high-pressure steaming and then we're using that at Primrose East. That Primrose East has a very, very thick Clearwater sand. And after you have the initial steam cycles, that is actually the optimum way to go and we have planned to do that anyway, so that will be part of the plan going forward. As far as regulatory approval, obviously, we have to get the causation review completed and that will take time. And we've got -- we can't predict all these, but we expect to be -- I would think it's going to be more likely to be Q1 2014 than by the end of the year. Christopher Feltin - Macquarie Research: Okay. And I guess with those modified practices, the targeted rates from Primrose are now 110 to 120, does that have an impact on where the ultimate rate is from that project now? Like I understand how, longer term, this won't have an impact on the recoverable resource, but would that have more of an impact in terms of the near-term rates at all? Steve W. Laut: Not really because what we do is that the major part of the modified strategy will be how we grow the volumes, so it probably change how many cycles we have during the year. So the cycles will be smaller injections and smaller production flowbacks. But you have more cycles in the year rather than what we have now, which are very much larger steam injections and larger production cycles. So really, you're just going at smaller volumes but at a greater frequency in the cycle.

The next question is from Mike Dunn from FirstEnergy. Michael P. Dunn - FirstEnergy Capital Corp., Research Division: A couple of questions. First, maybe on Pelican Lake. If I look at just referencing back to your Investor Day slides at June, you're spending less next year at Pelican Lake than what you had suggested in your slides at June. And the average production looks lower, too. Is that merely capital allocation decision for next year or are there other reasons why maybe you're not being as aggressive there at Pelican Lake next year? Steve W. Laut: Thanks, Mike. And I'm glad you brought that up because at Pelican Lake, I would earnestly say, we're seeing great response from the polymer flood. As you know, this a leading-edge technical polymer flood. There's only 2 polymer floods in the world with heavy oil, and Pelican Lake is the only one that actually works. So we're getting, as we said many times over the last few years, learning as we go. So the reason the capital allocation is less or the -- less capital this year is facilities are behind us, so that takes out a big chunk, we did that in 2013. Also, we are, in a way, reducing capital allocation and that's by choice. It allows us to give ourselves a bit of a breather here in the first part of 2014 and watch the response we're seeing from the polymer flood. And as you know, at some, areas respond very quickly, some a little slower. And we're going to take some time here. That's one of the beauties of Canadian Natural and our balanced portfolio. We're not driven to do anything just for the sake of growing production volumes. We're here about value growth. So we'll take some time, watch the response as it develops here in the Pelican Lake, and that will have an effect on how we space our drilling program, how we inject our polymer. We're looking at different ways of injecting polymer, reducing polymer viscosity. And in some cases, we have done a small experiment, which will continue in 2014, where we fill the polymer injection with water. This improves injectivity and also reduces our operating costs going forward. So we have a bunch of things we want to make sure we get nailed down. And so that when we do spend capital, ramp it up again, that we have the most efficient and capital-efficient drilling program to unroll the polymer flood going forward. So it's a bit of a slowdown. It's a capital allocation choice, but it also improves our capital efficiency going forward and make sure we get it right at Pelican Lake. Michael P. Dunn - FirstEnergy Capital Corp., Research Division: Great. And the OpEx guidance next year, Steve, is sub-$9 a barrel, I believe, I read. Any reason for me to think that that's anomalous or generally just a relationship with production going up and, I guess, probably I'm not sure if there's processing cost that have gone down there or not. But is that -- is there anything anomalous to be below that number for next year? Steve W. Laut: No, that's the way we see it going forward. Obviously, with the battery being built in 2013, we get better efficiencies. And we're seeing the production response coming, so that costs are lower. That's what we expected. Michael P. Dunn - FirstEnergy Capital Corp., Research Division: Great. And if I may, a similar line of question, I guess, on your conventional light oil in Western Canada. Again, back to the Investor Day slides, a little bit less growth next year than maybe you suggested and I'm thinking, June, you didn't have the Barrick acquisition in there. So just maybe walk us through how you're thinking it's changed there versus, let's say, 6 months ago? Steve W. Laut: Well, we did those capital allocation choice during 2013. As you know, we've got a lot of capital flexibility, so we allocated capital away from light oil just based on some of the response we've seen. And we want to -- as you know, we're drilling a bunch of Triassic plays in Northwest Alberta. We have drilled a lot of really good wells, but what we want to do is get production response or a performance, on a history on that, before we start our drilling programs. So in 2013, we drilled less light oil wells than we expected and as a result, production is less.

[Operator Instructions] The next question is from John Herrlin from Société Générale. John P. Herrlin - Societe Generale Cross Asset Research: Just a quick one. You'll be generating free cash and, historically, you're a contrarian property buyer. Recently, you did a small bite-sized acquisition with Barrick. Will you be doing more bite-sized type things or it depends on the opportunity in terms of doing something more strategic? Steve W. Laut: Thanks, John for that question. Really, as you know, our portfolio, our asset base is pretty strong. As I said earlier, we don't have any gaps in our asset base, so there is no need for us to do any acquisition unless it can add value and is opportunistic. And in the case of Barrick, that was clearly a very opportunistic acquisition. And we are able to simulate that into our asset base very quickly. So I don't think -- unless something is very strategic out there and very opportunistic, you won't see us doing much of acquisitions. But again, we always watch and see what's going on. John P. Herrlin - Societe Generale Cross Asset Research: Are you getting a lot of calls from private equity shops given the diversity of your base? Steve W. Laut: Not really, no.

There are no further questions registered at this time. I would like to turn the meeting back over to Mr. Proll. Douglas A. Proll: Thank you, Jane, and thank you, ladies and gentlemen, for attending our conference call. As you have seen today, Canadian Natural has a very strong and diverse asset base, a complementary balance of production proportion to light oil and synthetic oil production, heavy oil and natural gas and a strong well-developed plan for the systematic development of this asset base. We concentrate on safe, efficient and reliable operations and a strong financial position, supported by our readily available liquid resources. We are focused on returns to shareholders in the near-, mid- and long-term. And so thank you, all. And if you have any further questions, please give us a call. Thank you, and have a great festive end to holiday season.

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