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.

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.

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…

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…

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…

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.

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?

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.

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?

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.

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?

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.

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?

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.

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?

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.

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.

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?

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.

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?

Sorry, Chris, I didn't catch what you said right at the very first of your question.

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.

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.

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?

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.

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?

We're planning to get steaming here at Primrose East in the, I would say, March, April timeframe.

Okay. So all indications are that the regulators will have some approvals to you soon here, I guess?

That's their decision, so I'm not going to suppose.

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]?

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.

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.