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 Lyle G. Stevens - Senior Vice President of Exploitation

Greg M. Pardy - RBC Capital Markets, LLC, Research Division Christopher Feltin - Macquarie Research Christopher Cox - Raymond James Ltd., Research Division Michael P. Dunn - FirstEnergy Capital Corp., Research Division

Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2013 Fourth Quarter and Year End Conference Call. I would now like to turn the meeting over to Mr. Corey Bieber, Chief Financial Officer and Senior Vice President, Finance of Natural Resources. Please go ahead, Mr. Bieber. Corey B. Bieber: Thank you, operator, and good morning, ladies and gentlemen. Thank you for joining our conference call to discuss our fourth quarter financial and operating results, as well as 2013 results and reserves. With me this morning are our President, Steve Laut; and Lyle Stevens, our Executive Vice President, Canadian Conventional Operations. Before we begin, I would like to refer you to the comments regarding forward-looking information contained in our press releases, and also note that dollar amounts are in Canadian dollars and production reserves are expressed as before royalties, unless otherwise stated. With that, I will hold my comments until the financial aspects of the quarter and ask Steve to give his comments and operational update. Steve W. Laut: Thanks, Corey, and good morning, everyone. 2013 was another strong year for Canadian Natural as we continue to build a premium-value, defined-growth independent. We're one of the few companies in our peer group that has diversified and well-balanced assets that deliver free cash flow on a sustainable basis. A direct result of Canadian Natural's proven and effective strategy that optimize capital allocation and maximize value ensure we have -- ensures we have effective balance not only in our assets, but in our capital allocation between asset growth near, mid and long term, return to shareholders and balance sheet strength. This gives Canadian Natural a clear advantage compared to our peer group. The Canadian Natural advantage starts with our strong, free-cash-flow-generating conventional assets. Canadian Natural's conventional assets are the backbone and the underlying driver of our transition to a longer-life, low-decline asset mix of providing the funding for the transition. The strength of our conventional assets is in their concentrated nature, where we dominate both the land base and infrastructure, as well as the area of knowledge that drives effective and efficient operations and substantial free cash flow. All our conventional assets generate free cash flow and at the same time, we're able to grow the conventional volumes in a 2% to 4% range. The free cash flow from our conventional assets then fund the development of our long-life, low-decline assets at Horizon, our thermal in situ assets, and at Pelican Lake. As production ramps up from these assets, Canadian Natural's free cash flow grows rapidly and is much more sustainable, as the reserve replacement cost for these assets is very low. Both thermal and Pelican are today generating significant and sustainable free cash flow. As our free cash flow ramps up, Canadian Natural is effectively balancing the allocation of free cash flow to our priorities. Our first priority is to resource development and in 2014, we expect to allocate roughly $400 million to Horizon to capture additional cost certainty. All other assets in our portfolio are at or near optimal capital allocation. Additional allocation to high-return projects such as primary heavy oil would result in erosion in capital efficiencies, a choice Canadian Natural will not make. Our second priority is return to shareholders via dividends and share buybacks. Dividends have increased for the last consecutive 14 years and since Horizon Phase 1 has come onstream, has increased at a 34% CAGR. Dividends increased in aggregate 90% in 2013, which included a onetime dividend increase we announced in November 2013. In addition, as we announced today, we have increased quarterly dividends by $0.025 a share, in line with when we historically increase dividends each year. We also bought back roughly $318 million of shares in 2012, roughly $320 million in 2013 and year-to-date in 2014, have bought back roughly $53 million of shares and, depending on market conditions, expect to be in the $300 million to $400 million range in 2014, share buyback levels that rank us at top tier in our peer group. Thirdly, to opportunistic acquisitions, and the recent Devon Asset acquisitions is opportunistic and clearly demonstrates our ability to be nimble. Fourthly, to debt repayment, our balance sheet is very strong and after the Devon acquisition, still remains strong and is the last priority for free cash flow allocation. Canadian Natural's strategy works and we continue to balance the allocation of our free cash flow effectively. Operationally, we're sound and delivering. In 2013, our reserve replacement was 149% on a proved basis, adding 369 million barrels or BOEs. Our E&P capital cost, including acquisitions, was $4.2 billion. Overall, an excellent result. At Horizon, both reliability and production performance have been strong. Our expansion at Horizon is going well and we're tracking 10% below our cost estimates and will bring on Phase 2A, adding 12,000 barrels a day, in 2014 versus the 2015 original plan. Kirby South came onstream ahead of schedule and on cost, and the reservoir performance is tracking to expectations, with production expected to ramp up to 40,000 barrels a day by year end. Our primary heavy oil program is very effective and efficient, delivering some of the highest returns in our portfolio. At Pelican Lake, Canadian Natural's leading-edge polymer flood continues to perform and deliver long-life, low-decline value. The $65 [ph] million a day and 6,100-barrel-a-day expansion at our Septimus Montney development, taking total capacity 125 million cubic feet per day and 12,200 barrels a day of liquids is complete and delivering as expected. Looking at 2014. Our cash flow will be strong, production growth is strong, targeted at 10% at the midpoint of guidance, excluding the Devon acquisition. Heavy oil differentials are expected to average in the 22% to 24% range, driving very good heavy oil pricing, and gas prices are looking good for 2014 as a result of the cold winter and the need to rebuild storage levels this summer. As a result, the targeted cash flow will be between $9.5 billion and $9.7 billion, generating $1.8 billion to $2 billion of free cash flow, again, excluding the Devon acquisition. Significant free cash flow that grows and becomes more sustainable as we continue our transition to a longer-life, low-decline asset base. Canadian National assets are strong, our balance sheet is strong, we are effective and efficient operators, our strategy works and most importantly, we have very strong teams committed to delivering value. Turning to our assets. Let me give you a brief update, beginning with thermal in situ heavy oil. Canadian Natural's thermal heavy oil resources are vast. We have 97 billion barrels in place and we expect to recover 10.6 billion barrels. Canadian Natural is executing a disciplined, stepwise plan to unlock the huge value of this asset base by bringing on 40,000 to 60,000 barrels a day every 2 to 3 years, taking production facility capacity to 510,000 barrels a day or 0.5 million barrels a day all at a 100% working interest. 365,000 barrels a day of this 510,000 barrels a day, roughly 70%, will be coming from our SAGD developments. Kirby South is the first major SAGD step in our SAGD development plan. As you know, we delivered Kirby South ahead of schedule in 2013 and on cost. The reservoir is performing as expected with no surprises. We expect Kirby South to ramp up to 40,000 barrels a day by year end, and current production is right on track at roughly 7,000 barrels a day. Kirby North is our next 40,000-barrel-a-day step and we expect to sanction this project mid-2014, with first oil scheduled for 2016. Grouse will follow Kirby North with a 40,000-barrel-a-day facility. The geological, engineering and military work on Grouse is proceeding to plan. Kirby South, Kirby North and Grouse all contribute to our transition to a longer-life, lower-declining asset mix. At Primrose, our cyclic steam production declined as expected in Q4 due to the normal timing of production cycles and the curtailment of production in Primrose East. The first 2 months of Q1 will also be in the low part of the cycle as we begin to see production ramp up in March, and in Q2, coincidentally with a stronger demand seen for heavy oil in Q2 and Q3. Production volumes in Primrose are lower than expected in Q4, as steaming in Primrose North, which is distant from for the seepages, was delayed until February 2014, causing production to be roughly 1,000 barrels a day below the bottom end of guidance. March production volumes are expected to be in the 100,000-barrel-a-day range. The clean up of seepages we experienced in 2013 is complete on 3 of the 4 sites, with the fourth site expected to be completed before spring breakup. Our investigation of the seepages is ongoing with significant data collected. All data collected to date points to the root causes of seepage being wellbore failure in legacy wells. To be more clear, no data collected to date indicates any other mechanism as possible root causes for seepages to occur. We have looked and we will continue to look for data that would indicate any mechanism other than wellbore failures. As we said on our last conference call, this issue is totally solvable and the solution to prevent seepages is the same for all probable mechanisms that could cause this issue. The solution includes the following: All wells will be reviewed, including all legacy wells, to determine their integrity. Those with identified concerns or issues will be repaired prior to steaming. Enhanced monitoring of any potential leases from the Clearwater into the Grand Rapids will be employed. This along with our advanced understanding of potential release signals provides an effective early warning system. If we do see infrequent subsurface releases from the Clearwater into the Grand Rapids, we have an enhanced response, which includes ceasing preinjection into the Clearwater and/or immediate flowback of a horizontal injector producer, relieving the pressure and ensuring fluid movement cannot propagate further into the Grand Rapids. As a result, no fluids released in the Grand Rapids will able to mitigate or migrate through any pathway to the surface. We'll also modify how we steam, as well as the growth in steam volumes in successive cycles will be modified to provide greater certainty that all fluids remain in the Clearwater. We're currently employing this system in our Primrose North operations, which are distant from seepages and have been successful. Additionally, in Primrose East, where 3 of the 4 seepages have occurred, we'll be converting to a steam flood after initial steam simulation cycles in Area 1, which is operated at conditions that make it impossible for fluids to be released from the Clearwater. We expect regulatory response shortly and are set to being the steam flood as soon as approval is obtained. In summary, we're confident in the cause of these seepages, the cleanup is essentially complete, our causation review is well underway and has not yielded any data that does not support that wellbore failures of the root cause. We're confident that the solution going forward will prevent seepages from occurring in the future. Our production guidance for 2014 remains unchanged, delivering a targeted 23% increase in production as Kirby production ramps up to 40,000 barrels a day by 2014 year end. At our world-class Pelican Lake pool, 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 under polymer flood. In Q4, Pelican achieved record quarterly production of 46,000 barrels a day, a 27% increase over Q4 2013. We're seeing good production response from the polymer flood and we'll see production increase by 2% in 2014, with the drilling of only 17 wells. Pelican Lake is a great example of Canadian Natural's ability to develop and implement new technology, allowing Canadian Natural to not only produce 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's primary heavy oil assets are excellent. We are the largest primary heavy oil producer in Canada, we dominate the land base and the infrastructure. We have over 8,500 locations in the inventory, due in part to our dominance and our excellent teams. We have excellent capital efficiencies and low operating costs, making primary heavy oil one of the highest return-on-capital projects in our portfolio and generates significant free cash flow. Q4 production volumes were less than expected for 2 reasons, one of which was in our control and one out of our control. As you are aware, there was an unplanned TCPL outage in October. This event was out of our control and caused an interruption of fuel gas at Woodenhouse reducing Q4 production volumes by about 1,200 barrels a day. In our control is Canadian Natural's strategic decision to curtail heavy oil production volumes late in Q4. December heavy oil differentials were 40% off WTI. In our view, this very wide differential was very short term in nature and we expect differentials to tighten in January and February, which they did. Actual January differentials were 31% and February was at 19%, and March currently indicating 21%. For roughly a month in Q4, Canadian Natural curtailed just over 10,500 barrels a day of heavy oil production, with the view that producing this production with December differentials at 40% versus the expected lower differentials in January and February made good business sense. Canadian Natural's light oil program continues to drive good value for horizontal multi-frac wells, waterflood optimization and increasing NGL production, driving record quarterly growth in Q4 at 73,400 barrels a day, up 13% over Q4 2012. We target light oil NGL production to grow 8% in 2014, excluding light oil and NGL volumes from the Devon acquisition. In Q4, international production increased 6% over Q3 as we came out of turnarounds in the North Sea, which is offset by mooring line failures at Baobab. This caused Baobab to be shut in December until late January, when production was restored temporarily. In March, we'll complete the final permanent mooring line repairs. North Sea drilling is underway with 2 drill streams as a result of successful Brownfield Allowances. At Espoir and Cote d'Ivoire, we're in the process of obtaining a drilling rig to complete an 11 gross, 5.9 net well drilling infill program in the second half of 2014, which is targeted at 5,900 barrels of net BOEs when completed. At Baobab, we secured a rig to drill a 6 gross, 3.5 net well infill program that will commence drilling late 2014 or early 2015 and when complete, is targeted to add 11,000 BOEs of net production. In offshore Africa, we'll initiate exploration activities in 2014. In Cote d'Ivoire, we're targeting deepwater turbidite fan systems similar to Jubilee Field in Ghana. On Block 12, Canadian Natural operates with 60% interest and we have completed seismic operations, and we'll evaluate the seismic in 2014 and potentially drill an exploration well in 2015. On Block 514, where we have a 36% working interest, the exploration well is targeted to spud in March, with potential structure sizes in the 0.8 billion to 1.4 billion barrel range. After drilling the 514 well, the rig will then mobilize to South Africa to drill the exploration well in our South African block that contains 5 significant structures with sizes up to 1 billion barrels. Turning to Horizon, our world-class oil sands mining operation, where we have 14.4 billion barrels in the ground, with just under 6 billion barrels of oil to recover, which will likely grow to closer to 8 billion barrels as we expand our pit limits and seize opportunities as drilling improves the oil body delineation. In the fourth quarter, production averaged a very strong 112,000 barrels a day on the heels of an equally strong third quarter, also at roughly 112,000 barrels a day. The first 2 months of 2014 have averaged 111,000 barrels per day and we expect a stronger March. Reliability improved substantially and we've been able to deliver quarter-over-quarter increases in reliability at Horizon since May 2012, almost 2 years. We made significant progress but we're not done yet, and I expect increasing reliability as we progress through 2014, as well as improved production optimization. Horizon Phase 2/3 expansion has been going very well. Because of this good progress, we will be able to complete the Phase 2A expansion, or coker expansion, ahead of the 2015 turnaround. And tie-in is still on target for September 2014. By completing this tie-in, stream day capacity will increase 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. At the end of Q4, the expansion reached the 34% fiscal completion point, with each individual phase progressing to plan as outlined in the press release. Today, we're running about 10% under our cost estimate, and to this point, construction is going very well and we may be in an opportune construction window in 2014. 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 and achieve cost certainty and savings. Our base plan has us spending $2.5 billion [ph] between phases and up to $2.9 million [ph] , if conditions remain favorable. At this point, conditions are still favorable. Canadian Natural is the second largest natural gas producer in Canada and with a very large land base and effective and efficient operations. When gas prices strengthen, as we've seen so far in 2014, 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, allowing us to quickly and efficiently increase gas drilling and production at very effective costs. We've added this strong asset base with agreements to acquire Devon Canada's Canadian conventional assets, excluding the Horn River, for $3.125 billion effective January 1, 2014, with a closing target on April 1, 2014. This acquisition fits our strategy of opportunistically adding to our existing core areas where it can provide immediate value, with the opportunity to add value in the future. The acquired assets are largely operated, as are the owned facilities and infrastructure, and are a very good fit for Canadian Natural's existing assets and infrastructure. Current production is 86,633 BOEs a day, with 2014 estimated to average production target at 82,500 BOEs a day. Proved reserves completed provide Devon by an independent reserve value, are 272.2 million BOES. We'll also acquire 2.2 million acres of undeveloped land. The assets also contain a significant revenue stream, which is projected to be roughly $75 million in 2014 plus 2.7 million acres of fee simple and royalty lands. The acquisition of these assets make good sense for Canadian Natural. The assets are very good, both in Canadian Natural's land and infrastructure, and we'll be able to achieve synergies on the combined operations to enhance operational effectiveness and efficiency. At Canadian Natural, one of our core strengths is our ability to optimize conventional assets, particularly those that fit so well with our existing operations. In effect, we have homefield advantage. The deal metrics are attractive and the acquisition adds 11% to our production for 2014, and on a 9-month basis for closing on April 1, 8% to 9%. As we said earlier, the Devon assets have significant royalty revenue of $75 million. This provides Canadian Natural an opportunity to combine significant royalty revenue on these assets with Canadian Natural's current royalty income on our existing assets, which are targeted on a combined basis to deliver between $140 million and $150 million of cash flow in 2014. In 2014, we look to monetize this royalty revenue stream through a direct sale or potentially creating a new vehicle to provide steady cash flow to our current shareholders. There's also a liquids-rich natural gas and light oil site in the 2.2 million acres of undeveloped land in the Montney, Wilrich, Glock, Cardium and the Dunvegan plays. In addition, we see significant synergies once the assets have been integrated of between $50 million to $70 million in G&A, and $65 million to $75 million a year in op cost savings. The acquisition of Devon assets make sense. It is opportunistic, demonstrates Canadian Natural's ability to be nimble and most importantly, adds value in the near, mid and long term. With that, I'll turn it over to Lyle, who will highlight the very strong reserve additions we've achieved in 2013. Lyle G. Stevens: Thanks, Steve. Good morning, ladies and gentlemen. To start our reserves review, I'd like to point out that as in previous years, 100% of our reserves are externally evaluated and reviewed by Independent Qualified Reserves Evaluators. Our 2013 reserves disclosures is presented in accordance with Canadian reporting requirements, using forecast pricing and escalated costs. The Canadian standards also require the disclosure of reserves on a the company gross working interest share before royalties. In 2013, we had another very strong year, replacing 149% of our production on a proved basis; 152% for crude oil, NGLs, bitumen and synthetic crude; and 140% for natural gas. On the proved-plus-probable basis, we replaced 143% of our production; 130% for crude oil, NGLs, bitumen and synthetic crude; and 176% for natural gas. Total corporate proved reserves increased by 2% to 5.14 billion BOE. Proved additions and revisions, excluding production, totaled 364 million BOE, 73% of which were liquids, primarily in North American heavy crude oil and thermal bitumen. On a proved-plus-probable basis, total company reserves increased by 1% to 7.99 billion BOE. On a 2P basis, additions and revisions, excluding production, totaled 350 million BOE, 65% of which were liquid additions. If we exclude Horizon, proved additions and revisions total 369 million BOE and proved plus probable total 376 million BOE, both excluding production. These additions correspond to a capital spend of $4.24 billion including acquisitions. Our 2013 North American E&P results were excellent, with total proved reserves increasing 7% to 2.58 billion BOE and proved plus probable reserves increasing 4% to 4.19 billion BOE. The most significant reserves increases were in primary heavy crude oil, thermal bitumen and natural gas. In primary heavy oil, proved reserves increased 20% to 244 million barrels. This was driven by the outstanding results from our 2013 drilling program and positive technical revisions, reflecting the strong performance from our base production. On our thermal assets, proved reserves continue to grow as we enhance our development plans and improve our definition of the reservoirs. Proved thermal bitumen reserves increased 9% to 1.16 billion barrels, as a result of pool extensions at Primrose North and South, increased definition of the Wabiska reservoir at Kirby South and reclassification of a portion of the Kirby North probable reserves to proved. Moving to natural gas, our proved reserves increased 4% to 4.16 Tcf. This growth reflects the excellent results from our concentrated liquids-rich natural gas drilling program, recognition of flattening production declines in the Deep Basin of Alberta and minor acquisitions. There is also a corresponding increase in NGL reserves, where proved reserves increased by 17% from year end 2012. Crude oil, NGLs, bitumen and synthetic crude now account for 86% of our proved reserves and 87% on a proved-plus-probable basis. The reserve life index for the company is 23 years using proved reserves and 35 years using proved plus probable reserves. If we exclude the Horizon reserves, we still have very long reserve life indices, which reflects the strength of our asset base. It's 15 years using proved reserves and 24 years on a proved-plus-probable basis. In summary, these excellent results reflect the strength, balance and opportunities that we have on our asset base. I'd now like to return the call back to Corey. Corey B. Bieber: Thank you, Lyle. As Steve noted, during 2013, we increased crude oil production by 6% from 2012 levels, which helped drive a 24% increase in annual cash flow to $7.5 billion, a record for the company. This cash flow facilitated both a strong capital program and the additional return of cash to investors. Our capital program grew reserves by 143% of production and continue the development of our Kirby and Horizon Oil Sands major projects. Today, Canadian Natural's gross 2P reserves are approximately 8 billion barrels of oil equivalent. Shareholders directly benefited from quarterly dividend increasing by 90% and the repurchase of 10.2 million common shares under our Normal Course Issuer Bid at an average price of $31.46. This was all accomplished while maintaining our debt-to-book capitalization at 27% and debt-to-EBITDA at 1.1x. It is clear that our defined plan for profitable growth and emphasis on long-life, low-decline projects has created significant economic value for our shareholders. The continued delivery of this defined plan also bodes well for future continued growth of our business and the increased return of money to shareholders, all while maintaining a very financially strong balance sheet. To that end, and as part of the annual year-end review of dividend sustainability, the Board of Directors approved a 12.5% increase in the quarterly dividend, to $0.225 from $0.20. The outlook for 2014 and beyond remains strong. Before the inclusion of the Devon asset acquisition, we currently target liquids production growth in 2014 at around 8%, with natural gas production increasing about 2%. This, coupled with stronger netbacks and current strip pricing, results in cash flows of approximately $9.5 billion to $9.7 billion. The Devon asset acquisition only increases that production growth and free cash flow generation capacity. Our size and cash flow-generating capacity also allows us to make strategic and tactical decisions, where many of our competitors do not have the same flexibility. The decision to proactively reduce production in November and December to partially avoid the revenue impact of the temporary spike in heavy oil differentials is an example of this. Our financial strength allowed us to defer cash flow during this period until pricing recovered to a more reasonable level. This garnered additional returns for our shareholders. We also proactively managed downside risk through an active commodity hedging program, which utilizes a combination of costless collars, financial puts and physical Western Canadian Select contracts. Currently, on average, approximately 272,000 barrels a day of 2014 crude oil volumes and approximately 8,000 barrels a day of currently forecasted 2015 crude oil volumes were hedged using collars. For natural gas, both 500,000 MMBtu a day of natural gas AECO basis swaps at $0.50 were completed, and 750,000 barrels or GJs a day of AECO puts at $3.10 were hedged for the period April through October 2014. Further details related to the company's commodity hedge program can be found at our financial statements and on our website. At the end of 2013, our available liquidity under bank lines was approximately $2.9 billion. This liquidity, together with the new $1 billion non-revolving bank facility, which is available upon close of the Devon transaction, coupled with free cash flow from our business, will more than facilitate the close of the $3.1 billion Devon acquisition in April. That being said, we continue to manage our ongoing liquidity options. We remain cognizant of upcoming bond maturities later in 2014, as well as the potential monetization of royalty revenue streams. We also consider the continued significant growth in free cash flow expected from the business in the coming years, as the major development projects transition from build phase to operation. In short, we are in an enviable position not only in our project development optionality, but in our financial strength and liquidity optionality. With that, I'll hand the call back to Steve for his closing comments. Steve W. Laut: Thanks, Corey. Canadian Natural is in great shape. Our balance reserve base is the largest in our peer group, a reserve base that ranks with global industry players and delivers significant cash flow. We're able to leverage our dominant land base and infrastructure in our conventional assets, allowing us to generate significant free cash flow, which funds the development of the long-life, low-decline asset base. We're developing our vast, high-quality, long-life, low-decline resource base in a very disciplined manner, unlocking significant value and sustainable cash flow. Cash flow is increasing and becoming even more sustainable as we move forward. In 2014, Canadian Natural's free cash flow is significant at $1.8 billion to $2 billion at strip pricing and excluding the Devon acquisition, providing Canadian Natural additional free cash flow to allocate to our priorities, priorities we're balancing effectively, with dividends increasing by 90% in 2013 and another 12.5% this quarterly -- this quarterly as announced. As well as share buybacks will be in the $300 million to $400 million range for 2014. As we bring on the next stages of our long-life, low-decline asset base, free cash flow will rise to a sustainable $5.5 billion to $6.5 billion a year by 2018, assuming, of course, a stable commodity price, economic and regulatory environment. Canadian Natural's ability to grow production from our asset base, as well as 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. With that, operator, we'll be happy to take any questions.

[Operator Instructions] The first question is from Greg Pardy from RBC Capital Markets. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Steve, 3 questions for you. First, just around Côte d'Ivoire, wanted to check, was the predrill on that somewhere between -- or is the predrill somewhere between 800 million and 1 billion barrels? Steve W. Laut: Yes, the first structure in 514, the structure size is 0.8 billion to 1.4 billion barrels. We won't know what's in the structure until we drill it. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay, fantastic. Second, I mean, you referred to the transition the company has been making for the last several years towards long-lived assets and so on. Are you -- is there a decline rate that you're looking to get to corporate-wide? I'm just wondering where you would peg your corporate decline all-in now and what that number might look like in 2017 once Horizon is full up? Steve W. Laut: So, Greg, I don't think -- we don't actually have a target for decline rate. What we're targeting is return on capital. So we focus on each projects, and we're looking at the return on capital, try to have a good mix between near-term, midterm and long-term projects, and we'll rank everything by return on capital. Clearly, for some of the very long projects like Horizon, we're willing to take a little bit less return on capital to get that longevity. But everything on our portfolio was driven off a 15% after-tax return on capital hurdle. So we don't have other hurdles where we're chasing decline rate. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay, okay. And the last question for me is just the -- what's the game plan then with respect to steaming at Primrose based upon -- based on what you know now? Steve W. Laut: Our game plan hasn't changed, so our guidance for the year hasn't changed at all, Greg. So we're continuing with the causation review. We got a lot of data now, we're continuing to drill as well. And as I said earlier, all the data points to wellbore failures as a cause. And we have a revised steaming plan here that we're very confident will prevent any seepages in the future. And so now, it's just the regular course of getting the review completed, getting that into the AER and getting that approved, and we'll go into steaming. So we're looking in Primrose East where the seepages have occurred in Area 1. We do have an application to go to steam flooding. And as you know, with steam flooding, the pressures you inject are very low and as a result, actually just by normal gradient, you cannot release from the Clearwater, so there will be no seepages with steam flooding. So we've got that application into the AER, and we're awaiting their response. So the plan is according to track, and we'll hit our guidance this year. Greg M. Pardy - RBC Capital Markets, LLC, Research Division: Okay. And last one for me is you're operating cost at Horizon, quite good actually in the fourth quarter. How do you -- what's driving that? Are you continuing to shed some of the contractors, and does the path just continue to look better as we go through 2014? Steve W. Laut: Well, as you know, Greg, most of the costs at Horizon are fixed, and so production does have a big impact. So we had good, steady production, that drives our cost down. We have been shedding contractors and we're getting better reliability. And as you go through the winter months, you see more issues with belt tears and these things that happen which drive up your cost in the winter. We expect costs as we go through 2014 to get better as we go into the summer and into the Q4 as we get better reliability.

The next question is from Chris Feltin from Macquarie. Christopher Feltin - Macquarie Research: A couple of quick questions. First off, on the gas side and the reserves, just taking a look at the technical revisions, look like some pretty healthy positive revisions that actually outpaced the new additions. Just curious, and kind of if you could give a little bit more color where that is? Is that Septimus, Deep Basin, and just kind of wondering if you could give even a little bit more color in terms of what the reserve bookings are on a per-well basis at Septimus, in particular. Second question, kind of gets back to the strategy of curtailing the heavy oil volumes, just taking a look at the operating netbacks there for the quarter, still pretty healthy at $34 a barrel. Comparatively, back in the first quarter of last year, it was around $24. I don't recall you guys ever having taken the strategy in the past. Just kind of wondering what changed this particular quarter to have you look at curtailing production and what was deemed to be a bit of a short-term view on differentials? Steve W. Laut: So I'll answer the second question first, Chris. So what we did here, and I think it is a new strategy for us, we're looking at the differentials and we're seeing that there's some predictability, particularly when you go into December. You know that differentials widen in December, almost every year. It's just demand is less, refiners like to get the inventories low for the year end. And with the production volumes coming, we realize that differentials would be wide, they're already wide at 40%. And we expect the differentials to go down, as I said, they did go down in January and February, which is a good sign. So I think you'll see us do more of this. As we go forward, we're going to try to utilize our capacity and manage the fluctuations going forward. And importantly, one of the things we have here as a company, we have a very strong balance sheet and the financial strength to make these decisions and create value for shareholders. If we can produce oil in a 20% differential or 30% differential versus a 40% differential, we're creating significant value for shareholders by doing that. And that's what we're going to do going forward. As for the gas reserves, I'll -- we got Lyle here, and he'll be able to answer that question for you. Lyle G. Stevens: Chris, I'll answer your question on Septimus reserves first. On the existing wells that are there, on a proved-plus-probable basis, we get approximately 5.3 Bcf booked per well and around 500,000 barrels per well of NGLs. On the undeveloped reserves at Septimus, we're booking approximately 4.4 Bcf per well and around 410,000 barrels per well of NGLs. The positive revisions that we had on the technical side were primarily in the Deep Basin, although there was some in British Columbia as well. And that's really the flattening of the decline curves and recognition of that by our reserves evaluator. So the declines now range anywhere from 6% to 12%, and are flattening out, and extending the tail of those reserves is really what drove the increase there.

[Operator Instructions] The next question is from Chris Cox from Raymond James. Christopher Cox - Raymond James Ltd., Research Division: My first question sort of pertains to development activities for the second half of the year. I do recall kind of back in the -- during the conference call for the Devon acquisition, you did mention that there's maybe a possibility of some accelerated drilling, maybe in liquids-rich gas in the second half of the year. I guess I'm just wondering when might we see maybe greater clarity in terms of any changes to that plan for the second half of the year? And to what degree would this maybe be contingent upon how the Devon assets integrate over the course of the year with the existing line base? Steve W. Laut: Chris, it's a good question, and as we said in the conference call, we will look to deploy additional capital here on our E&P business. And as you know, as a company, the way we work, after the first quarter, we look at the results of all our conventional E&P and unconventional E&P activities. And then we reallocate capital based on the highest return on projects. So what you'll see us do here in April, we're targeting to close Devon in April 1. We're actually talking with the Devon folks right now, and going through their assets, looking at their plans, and what we'll do is we're going to basically reallocate capital across the company on the conventional side. We'll likely increase the capital budget for the E&P business by, I would say, just on a rough terms, maybe $75 million. But we'll take -- we'll high-grade all the projects. And so some of the projects we have on the Canadian Natural side, they may not make the cut, and some of the liquids-rich drilling in the Devon properties will probably make the cut, plus we have the initial $75 million, at this point, we're looking to allocate to the properties in both Canadian Natural side and the Devon conventional side. So we'll get further clarity after we get that done in May. Christopher Cox - Raymond James Ltd., Research Division: And then just the last question from me here, the decision to curtail production this quarter does kind of beg the question, in my view, of how the marketing plans are unfolding for 2014. And maybe specifically, I was kind of hoping you could provide your views in terms of how expanding your rail transport may be evolving over the course of the year, and if we can maybe see anything more meaningful developed in this arena over the near term? Steve W. Laut: Sorry, Chris, I didn't catch what you said right at the very first of your question. Christopher Cox - Raymond James Ltd., Research Division: I mean, just the decision to curtail heavy oil volumes does kind of beg the question of what is happening with marketing plans for the course of the year. Steve W. Laut: Right. Okay, so -- and how it relates to rail. As you know, we prefer pipelines. And we think pipelines are the safest, most reliable, most environmentally-friendly and the lowest cost option to transport oil to market. We will use rail if we need to, and as you know, right now, we're not a big rail user or use. About 15,000 barrels a day of our products is moved by rail. The rest we're moving on by pipe. I think you see at the industry and you've seen in the reports that there's significant amount of rail loading capacity being built here in Alberta and Western Canada. And if that capacity gets built, which it is being built, that will effectively offset all the volumes that were planned to go down in Keystone in effect. So we think as an industry, between the pipeline de-bottlenecks that are going on at Enbridge and the rail capacity being built, the industry in itself should not see these big spikes in volatility in heavy oil. It may be there for a little bit, but only short periods of times. So that's how we're managing going forward.

The next question is from Mike Dunn from FirstEnergy. Michael P. Dunn - FirstEnergy Capital Corp., Research Division: I have 3 questions. First, on the royalty business you guys are looking to monetize later this year. Steve, if you can't sell it outright, would you be looking to monetize via an IPO? Or is just spinning it out -- spinning out shares in this to shareholders something you'd consider as well? Steve W. Laut: Thanks, Mike. I think the answer to that, you probably know what I'm going to say. The answer is going to be we're going to look at all options and we're going to choose the option that maximizes the value for shareholders. So we're in that process right now. We've got to get the Devon assets closed to make sure we understand what they are very well, and then we'll start that process. But we are open to any and all options, and we're going to choose the one that maximizes the value for shareholders. Michael P. Dunn - FirstEnergy Capital Corp., Research Division: Okay. And secondly, at Primrose, in terms of your -- I guess, in terms of your thermal guidance for the year -- I think Greg was getting at this earlier. But just wondering, to meet your guidance for thermal production, roughly when do you need to get back steaming at Primrose East? Steve W. Laut: We're planning to get steaming here at Primrose East in the, I would say, March, April timeframe. Michael P. Dunn - FirstEnergy Capital Corp., Research Division: Okay. So all indications are that the regulators will have some approvals to you soon here, I guess? Steve W. Laut: That's their decision, so I'm not going to suppose. Michael P. Dunn - FirstEnergy Capital Corp., Research Division: Okay, sure. And then maybe, I'm not sure if this is for Lyle, but just a question on the reserves, gentlemen. Bitumen, the thermal oil reserves on a 2P basis, you had 100 million barrels of extensions. Is that just improved recovery rates or is that projects moving into bitumen [ph]? Lyle G. Stevens: Yes, there's a few reasons there. Somewhat it relates to increased recovery factors in the Wabiska reservoir at Kirby. So the main producing zone today at Kirby is the McMurray. There's also a thick Wabiska sand there, so there's increased recovery factors there that increased the probables. There is also additional drilling potential that we've delineated at Primrose North and Primrose South.

There are no further questions at this time. I'd like to return the meeting back over to Mr Bieber. Corey B. Bieber: Thank you, operator, and thank you, all, for joining us for the call this morning. As always, if there are any follow-up questions, please do not hesitate to contact our Investor Relations department. And once again, thank you, and good morning.

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