Canadian Natural Resources Limited
Q1 2013 Earnings Call Transcript

Published: 3 May 2013

[Operator:]

Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2013 First Quarter Conference Call. I would 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, operator, and good morning. Thank you for joining the Canadian Natural Resources conference call where we will discuss our 2013 first quarter financial and operating results and receive an update on our many projects and operational activities. With me this morning are Steve Laut, our President; and Corey Bieber, our Chief Financial Officer and Senior Vice President. Not with us today for the first time in 3 decades is John Langille. John is enjoying his first day of retirement, and I would imagine attending his golf clubs, which are probably a little rusty and in need of some attention. Before we start, I would refer you to the comments regarding forward-looking information contained in our press release and also note that all dollar amounts are in Canadian dollars and production and reserves are each expressed as before royalties unless otherwise stated. As Steve discusses our operating results, project updates and our overall returns to shareholders, you will note the size and diversity of Canadian Natural's asset base, the complementary balance of our production that comprises the record first quarter production volumes of approximately 681,000 BOE per day, together with our focused and systematic development of this asset base. Steve will update us on our outlook for WCS versus WTI differentials and WTI versus Brent differentials, both of which are viewed positively in the near and midterm. As Corey discusses our financial results, balance sheet strength, commodity hedging program, dividend program and the results to date of our share buyback program, you will see that our financial strength allows us flexibility in our choices for reinvestment, the opportunity for opportunistic acquisitions and the opportunity to return capital to our shareholders. It also allows us to execute our planned programs in the near, mid and long term for the benefit of our shareholders. And now I will turn the meeting over to Steve.

[Steve W. Laut:]

Thanks, Doug, and good morning, everyone. As you've seen, we had a very strong operations in Q1, with record quarterly BOE production of 681,000 BOEs a day and record oil production of 489,000 barrels a day. This was driven by record primary heavy oil production at 133,000 barrels a day, with targeted year-over-year growth of 12%. Thermal heavy oil production at 109,000 barrels a day and targeted 5% year-over-year growth. Pelican Lake, up to 38,000 barrels a day and targeting 16% growth. Light oil and NGLs production in Canada, a record 65,000 barrels a day, and gas production is up slightly from Q4. And international volumes are relatively flat quarter-to-quarter. As expected, heavy oil differentials and condensate premiums impacted first quarter cash flow. In the second quarter, heavy oil differentials have reversed themselves, also as expected. Operating costs are higher in Q1, as is normally the case in the winter. And the additional cold and heavy snowfall experienced this winter added some costs. As you would expect, winter happens every year and was accounted for in our yearly guidance. We are very confident that op costs will be lower in Q2 and Q3, and our op cost for the year will be on guidance, operating costs that are top tier in Canada. Operationally, the year looks very strong. Our guidance numbers remain unchanged. With significantly improving heavy oil differentials, lower condensate premiums and lower operating costs, our cash flow is also expected to further strengthen as we move through 2013. As I comment briefly on our strategy and highlight each of our assets this morning, there are 4 key points to listen for

[Corey B. Bieber:]

Thank you, Steve, and good morning. As Steve noted, the first quarter of 2013 was an excellent operational start to the year, with record quarterly production for both BOEs and liquids. All production guidance targets were met, with the bias towards the top end of guidance. From a product pricing perspective, the benefit of volatile but strong WTI pricing, averaging $94 a barrel, was offset by higher heavy oil differentials, averaging almost $32 for Q1 versus the $18 realized in Q4 of 2012. This, coupled with higher condensate blending costs, reduced our average crude oil realizations to $60.87 a barrel from the $66.55 a barrel realized in Q4 of 2012. During the first quarter, the corporation generated $1.57 billion in cash flow, up 1.5% from the previous quarter and 22.5% from the same period last year. Importantly, our previously articulated views on heavy oil differentials narrowing were borne out by the market. While the differential averaged 35% in Q1, as expected, in April, it narrowed to 25% and then further narrowed to 15% in May, providing additional support for our cash flow generation capabilities. And as you're aware, returning funds to shareholders is part of our balanced approach to capital allocation, along with continued production growth and development of our high-quality long-life assets. As such, dividends have grown for 13 consecutive years and when combined with share repurchases, represented 38% compound annual growth rate in funds returned to shareholders for the period 2008 through 2012. As part of this tradition, on March 7, we announced a further dividend increase of 19% and so far in 2013, have purchased almost 3 million common shares under our Normal Course Issuer Bid for over $95 million. In my opinion, we have shown that we are one of the few companies able to meaningfully grow production in the near, mid and long terms, while, at the same time, returning cash to shareholders and maintaining a strong balance sheet. Quarter end debt marginally increased partially due to the timing of capital versus cash flows, as well as foreign exchange movements. However, our credit metrics remained strong at 1.2x EBITDA and 28% debt-to-book-capitalization ratio. During the first quarter, we repaid $400 million of Canadian medium-term notes, as well as $400 million of U.S. notes via a combination of cash flow and available lines of credit. Significantly, during the quarter, we further diversified our sources of credit support and reduced our overall borrowing costs through the initiation of the U.S. dollar commercial paper program. This program has been very well received by the markets. Beyond this, our liquidity remained strong with available lines of credit of approximately $2.4 billion and no further debt maturities until late 2014. Finally, I believe our prudent commodity hedging program protects investment returns, ensures ongoing balance sheet strength and supports the company's cash flow for its capital expenditure programs. Approximately 52% of forecasted 2013 crude oil volumes are currently hedged using price collars and physical crude oil sales contracts with fixed heavy oil differentials. Details of our commodity hedging program can be found on our website but can be summarized as follows

[Douglas A. Proll:]

Thank you, Steve and Corey. Operator, I would like to now open up the call to questions.

[Operator:]

[Operator Instructions] And the first question is from Greg Pardy from RBC Capital Markets.

[Greg M. Pardy:]

Steve, there's a lot of debate right now going around on the capital intensity of mining projects. You guys have said all along that you think you can do it at 100,000 or less of flowing barrel per day. Just wondering if you can give a little bit more color as to why that is and how much of that number is related to prepurchased equipment.

[Steve W. Laut:]

Thanks, Greg. We're very confident we can do it for 100,000 barrels -- or 100,000 a barrel or less, and we're tracking to 10% below that right now. A lot of it -- I wouldn't -- I can't give you the exact number. A percentage of the costs has already been prebuilt. But as you know, all the pipe racks, all -- a lot of the pumps and compressors have been signed for Phase 3 rates, so we don't need to add additional equipment. That's one of the reasons why we'll get enhanced reliability when we get to Phase 3 rates because a lot of these pumps are running actually at the low end of their performance window. So when we go to 250,000, they'll actually run better than they run right now. So I can't give you an exact number, but it does make a significant difference to the return on capital.

[Operator:]

The next question is from David McColl from Morningstar.

[David McColl:]

I'm just a little bit curious kind of going back to your comments on being really bullish for heavy oil prices. Just wondering if you could maybe give some thoughts on how you view diluent costs going forward. And specifically, when you think about getting down to the Gulf Coast, how do you see price realizations for the heavy crude?

[Steve W. Laut:]

So I guess, David, we've been fairly consistent for probably the last year what we think heavy oil pricing is going to do. We believe heavy oil pricing going forward here will probably be in that 20% off WTI range. There'll be some volatility, obviously, as we have new production coming on and new demand at BP Whiting and Detroit Marathon. Also, Valhalla had a short-term issue. I think there'll be more demand created than supply brought on. That's why we're bullish on near-term heavy oil pricing. The -- in the midterm, in Q2 2014, Flanagan South Enbridge will be complete, and that will add another 585,000 barrels a day of access to the Gulf Coast. So you add that on top of what the 340,000 a day of incremental demand in PADD II, that gives you quite a bit of demand for Canadian heavy oil, that we're probably not going to be able to fill right away. And we know when we get to the Gulf Coast that there's 1 million barrels a day roughly of heavy oil demand that's not being met by Venezuelan and Mexican crudes. So we know we have a market for the Canadian heavy oil, so that won't be an issue. Longer term, we believe that we will ultimately need Keystone or we'll need access to the water off either the West Coast or East Coast of Canada. As far as diluent goes for heavy oil prices, you've seen the diluent prices come down here in Q2 and we expect to stay down here in Q3. A lot of that is seasonal because you need more diluent -- there's more demand for diluent in the winter because it's colder -- to get to pipeline spec. One of the things, I think, will control condensate prices, as you know, whatever gas drilling is getting done in Canada and the U.S. is liquids-rich gas drilling, which brings on more supply of condensate. And the other thing that's going on, there is quite a bit of rail going on. And one of the ways that you can reduce your rail costs is to backhaul condensate for heavy oil blending in the railcars coming back from the Gulf Coast or from Chicago. So we think condensate prices, although there will be a premium, we don't expect to see them to get out of control. Hopefully, that answers your question, Dave.

[David McColl:]

It does, Steve. If I could, just a real quick follow-up. In your latest presentation, you talked about really having secured about 100,000 barrels per day of capacity to a Gulf Coast refinery. Just wondering if there's -- any additional kind of plans in the works that you can maybe comment on for additional capacity. And with that, I'll kind of leave my questions.

[Steve W. Laut:]

Okay. So we've had 120,000 barrels a day of transportation capacity on Keystone. We've had that for quite some time. We're one of the initial supporters of Keystone. And to back that up, we made sure we had a market on the Gulf Coast. We entered into an agreement with a major refinery on the Gulf Coast to purchase 100,000 of that 120,000 at market price. So nothing's changed since then, and we're pretty confident and happy with that position.

[Operator:]

The next question is from Fai Lee from Odlum Brown.

[Fai Lee:]

It's Fai here. Canadian Natural's vast land base was highlighted earlier in the call, and another energy company recently brought the issue of land expiries and how much money is required to keep a hold on that undeveloped land. Could you comment on your strategy for managing your land expiries?

[Steve W. Laut:]

As you know, we have one of the largest land bases in Canada, and it's extensive. And what we do is we have a very well-thought-out plan to execute, where we ensure we drill enough wells, undertake enough seismic activity to control and continue all what we consider the prime land in our land base. So we do let land expire, but we do continue a lot of land. If you look at our undeveloped land year-over-year, it's pretty consistent, if not increasing. So I think it shows that we are very effective at controlling that undeveloped land by making sure we drill and continue the land that we need to continue, that we deem to be high-quality and premium land. So we don't see any issues going forward. We've done this for the last 4, 5 years, and we'll continue to do it going forward.

[Fai Lee:]

Okay. And just related to that question, you've also mentioned the potential for acquisitions. How do you prioritize between spending money on acquisition or spending the money on developing your undeveloped lands?

[Steve W. Laut:]

So for us, what we do is everything has to compete for capital at Canadian Natural. All organic projects, so gas drilling, light oil drilling, heavy oil drilling, international, thermal, Horizon projects, land acquisitions and property acquisitions will have to meet our criteria. And what we do is we always look for the opportunity to have the highest return on capital. So it's all based on return on capital. And if you look at our portfolio now, we really have no gap to fill. So we're not looking for acquisitions to fill any gap. It's all in a case where we can see that we can deliver upside from that acquisition, and those are getting tougher and tougher to find, quite frankly.

[Operator:]

The next question is from Harry Mateer from Barclays.

[Harry Mateer:]

Corey, just a question on the revolver borrowings. I think they're up to about $2 billion at the end of the quarter, as you guys paid down the maturities in the first quarter. You're still well below your targeted leverage metrics, so is there a consideration to perhaps term that out with a bond yield given how attractive rates are?

[Corey B. Bieber:]

Harry, thanks for the question. Yes, it's something we look at on an ongoing basis. Some of things we consider are the average cost of borrowing, our view on rates and certainly, as we look forward into future years, what those maturities are and additionally, the free cash flow generation capacity we're going to have a few years out as Horizon comes back on. So it is something we're looking at. I wouldn't say that we've made a definitive decision either way at this point.

[Operator:]

The next question is from Kyle Preston from National Bank.

[Kyle Preston:]

Just a couple of questions on your thermal business. Within the press release there, you mentioned that on some of your thermal cycles, the steaming cycle is narrowing. I just wonder if you can expand on that. And then also on Kirby, with the advancement in your steaming timelines, when are you expecting first oil from Kirby?

[Steve W. Laut:]

Okay, thanks, Kyle. So I'll talk about the thermal cycle. So as you know, we have, basically, a sine wave where you have peaks and troughs in the production cycle based on steaming. And as we go forward, as we develop more and more pads, we're able to schedule the steam so that the, basically, distance from the top of the peak to the trough on the production cycle becomes smaller. So we're actually smoothing out that sine wave of production cycles as we go forward. And we think as we continue to develop Primrose, we'll be able to narrow that so we won't see as much of a swing in production from quarter-to-quarter at Primrose. So that's the plan. As far as Kirby, basically, we've been able to get the completion of the project done sooner than expected, and commissioning will start earlier than expected. And so we'll be into commissioning, and then we'll hopefully start -- as I say, we will start steaming in Q3, and then we expect to see some production in the fourth quarter, probably late in the fourth quarter, but it will be small numbers as we basically warm up the pads and the well pairs and then slowly bring them on to production. As you know, there's a fairly rigorous and well-thought-out plan how you start up a SAGD pair, and we're following that very, very carefully.

[Operator:]

The next question is from George Toriola from UBS.

[George Toriola:]

Just a couple of questions for me. The first one is a follow-up one, what -- the question Greg had asked. On the 100,000 you talked about, Steve, are you able to break that down into what you think would be mining and what you think is attributable to upgrading?

[Steve W. Laut:]

We can break that down, George, but I don't have that right with me. So you can maybe call IR department, we'll see what we can do. But we haven't broken that down before.

[George Toriola:]

Okay. And just in terms of the timeline that you have projected for the Phase 2/3 expansion all the way to 2017, what's the driver for that? Is that just based on how you think you can reasonably execute this? Is it based on when you think labor loosens? What's the driver for that timeline?

[Steve W. Laut:]

Well, what the driver is in everything we do here, George, is capital efficiency. So you know that there is an optimum way to build things, so you don't want to have too much overhead on your contractors. So we believe with that schedule, we have a very good pace. And we have a very well-disciplined and effective project at site, and we have maximized our productivity at site by not having too many people. And that's what's driving us here is cost control on all sectors, and part of that is ensuring you have optimum productivity from your contractors. So we're making sure that we have the right balance between schedule and costs, and the cost is a major driver here. So that's what's driving that timeline.

[George Toriola:]

That is helpful. And last question is just how does -- the 250,000 acres that you want to put up in BC, how does that compare -- how does the opportunity on those lands compare with Septimus, for example?

[Steve W. Laut:]

Our view is that these are very high-quality lands, and they're very comparable to Septimus. They're farther out and probably closer to the West Coast of BC and would be more, I'd say, advantageous for maybe an LNG player. So that's the advantage over Septimus. But other than that, quality-wise, they're not that far apart.

[George Toriola:]

And liquids content as well or does -- or much less so than Septimus?

[Steve W. Laut:]

I think the liquids content will be about the same.

[Operator:]

[Operator Instructions] And the next question is from Mike Dunn from FirstEnergy.

[Michael P. Dunn:]

Kyle asked most of my questions on thermal, but just maybe a bit of clarification. In your quarterly release, you talked about sustaining production there out of Primrose at about 120,000 to 125,000 barrels a day. Guidance is obviously lower than that for this year, but you've got a pad coming on or maybe more than one pad late in the year. Should we be thinking about sort of run rate average annual volumes in that 120,000 to 125,000 barrel a day range post this year?

[Steve W. Laut:]

I think, Mike, what we've got here is we believe that we can develop pads and add production to get to that 120,000 to 125,000 barrel a day range. So we'll do that in a very sort of stepwise, cost-effective way. And once we get there, we think we can handle the -- leave at that level for at least 5 to 10 years. I think at that point -- and that's what we're doing right now is we're evaluating whether we should actually consider expanding the facility at Primrose to handle more production and generate more steam to increase that production capacity. So I guess, really, what it's telling you is we have quite a bit of run room left at Primrose for pad adds, which are very, very cost effective as you know at $13,000 per flowing barrel.

[Michael P. Dunn:]

Right. And then should I then be assuming that if you accelerate and you add sort of steam capacity there that 5- to 10-year window sort of becomes shorter or peak rates at a shorter time?

[Steve W. Laut:]

We're just in evaluation of that right now, Mike. So that would be one option or you can see -- likely seeing higher rates and be able to stay in that for longer. Obviously, you have to make it economic, so you just can't increase your production rate for a short period of time. So if we increased production rates from the 100,000 to 125,000 range, we expect to be able to handle that for another 10 years probably.

[Operator:]

There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Proll.

[Douglas A. Proll:]

Thank you, operator, and thank you, ladies and gentlemen, for attending our conference call. Canadian Natural has a very diverse asset base, a complementary balance of production and a systematic development plan for our asset base. We concentrate on safe, efficient and reliable operations and a strong financial position. We are focused on returns to shareholders in the near, medium and long term. If you have any further questions you would like clarity on, please do not hesitate to give us a call. Thank you again, and have a great spring day.

[Operator:]

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