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Executives

Douglas A. Proll - Executive Vice President

Steve W. Laut - Principal Executive Officer, President and Non-Independent Director

Corey B. Bieber - Chief Financial Officer and Senior Vice President of Finance

Analysts

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

David McColl - Morningstar Inc., Research Division

Fai Lee

Harry Mateer - Barclays Capital, Research Division

Kyle Preston - National Bank Financial, Inc., Research Division

George Toriola - UBS Investment Bank, Research Division

Michael P. Dunn - FirstEnergy Capital Corp., Research Division

Canadian Natural Resources Limited (CNQ) Q1 2013 Earnings Call May 3, 2013 11:00 AM ET

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: firstly, our view on heavy oil and light oil differentials and market access; Horizon reliability; Horizon turnaround update; and an update of Kirby development. All 4 of these points will have a significant positive impact on Canadian Natural's cash flow and earnings going forward.

Canadian Natural has and will continue to build at premium value, defined growth independent. 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 our ability to effectively execute our strategies. Canadian Natural has the largest reserve base in our peer group, a reserve base that ranks with global industry players. It is balanced and is delivering significant cash flow.

Critical to our ability to continue to grow free cash flow is our very large undeveloped resources that we own and control, resources that are long life and low decline and importantly, will only require a portion of our cash flow to grow current year production, about 47% in 2013, reflecting the strength of our assets and Canadian Natural's capital flexibility. The remaining cash flow could be utilized to increase the strength of our free cash flow and reserves by unlocking the value of undeveloped resources, return to shareholders through increased dividends and share buybacks, acquisitions or pay down debt.

Probably most importantly of all, we have the people, the expertise and the experience to execute our programs and operate effective, efficient operations. Our balance sheet is strong, with capacity to capture opportunities and weather any commodity price volatility we might encounter. 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 the free cash flow from our long-life, low-decline resources.

Highlighting our assets, and starting with gas. As you know, 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 is 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, allow us to quickly and efficiently increase gas drilling and production at very effective costs. Gas prices have strengthened somewhat with the company averaging -- average pricing of $3.51 an Mcf in Q1, up 28% from the $2.73 an Mcf we received in Q1 2012. As a reminder, every dollar increase in pricing translate to additional $300 million of yearly cash flow.

At Septimus, we're progressing on track the expansion of our plant to 125 million cubic feet a day and 12,200 barrels a day of liquids. The plant expansion is 80% complete, and 8 of the planned 14 wells have been rig-leased, with frac-ing on the wells getting under way last week. We expect first production through the expansion in June, adding 22 million cubic feet a day, bringing production to 79 million cubic feet a day and 7,700 barrels a day of liquids, growing to 125 million cubic feet a day and 12,200 barrels a day of liquids by August, driving a positive impact on Q3 cash flow.

Canadian Natural has a dominant Montney land position with over 1 million high-quality net acres, the largest in the industry. In order to maximize the value of this important asset, Canadian Natural has begun a process to modernize -- or monetize approximately 250,000 net acres, approximately 390 net sections of our Montney land base in a liquids-rich fairway in a Kremgogs [ph] area of northeast British Columbia.

Under the process, Canadian Natural considered either an outright sale of the lands or joint venture partner with an LNG expertise to jointly develop the lands. This process meets our internal targets, and a transaction is completed. Canadian Natural continue to have one of the largest undeveloped Montney land bases in Canada, with lands contained in 2 major areas in Septimus, which is in BC, and northwest Alberta. At this point, we've been running the process internally. However, an external adviser has been recently appointed.

Now before I touch on our oil assets, I'll comment on the current North American oil markets and Canadian Natural's view of the market. Canadian Natural's view on heavy oil markets is well known, a view that we have seen unfold in Q1 and Q2. We are bullish on heavy oil pricing in 2013, as well as the mid and long term, as there is significant heavy oil conversion capacity coming onstream in PADD II, significant current underutilized heavy oil refinery capacity on the Gulf Coast, and we see the infrastructure constraints to get to Gulf Coast being removed.

Although there'll be some headwinds for light production, we believe these are manageable. Cushing is on its way to being debottlenecked, which will reduce the LLS to WTI differential. Although we expect light oil production to keep increasing, we believe the access to incremental light oil markets in North America will be realized as rail becomes more of a transportation factor.

So far in 2013, we have seen pricing reflect the changes in infrastructure. Heavy oil differentials in January were 35%; February, 39%; March, 28%; April, 25%; May is at 15%; and although it's early, June differentials are very good, in the 19% range, assuming WTI stays at current levels. The WTI to Brent spread is narrowed from $20 -- $21.83 in Q4 to $18 in Q1, with current spreads at $9. Condensate premiums are somewhat seasonal and running at $7.30 a barrel premium in Q2 versus a $13 premium in Q1, a 44% reduction. WTI prices have come up a bit from Q1 levels. But all in all, all good news for heavy oil -- or all producers and particularly good news for heavy oil producers.

Turning to our oil assets. On Canadian Natural's thermal heavy oil lands, 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, stepwise plan to unlock the huge value of this asset by bringing on 40,000 to 60,000 barrels a day every 2 to 3 years, taking facility -- production facility capacity to 510,000 barrels a day or 0.5 million barrels a day, all at 100% working interest.

At Primrose, we continue to add pads at a very effective cost of roughly $13,000 a flowing barrel and our op costs are under $11 a barrel, making Primrose one of the most robust thermal projects in the industry. Primrose production was strong in Q1 at 109,000 barrels a day, at the top end of guidance. Primrose is a cyclic process, with Q2 rates expected to be in the 92,000 to 100,000 barrels a day range. The pressure will then cycle higher with stronger rates in Q3 and Q4. And production guidance for the year is 100,000 to 107,000 barrels a day, up 5% over 2012.

At Kirby South, we're ahead of schedule and on cost with first steam scheduled for Q3, moved up from the original November timing, with production ramping up to 40,000 barrels a day by late 2014 at a cost of $3,000 per flowing barrel. Kirby South is the first phase of a stepwise development to take the greater Kirby area production to 140,000 barrels a day. With additional lands acquired in 2012, we are evaluating the optimum production level for the Kirby area, with the potential to increase it to the 180,000 barrel a day range.

Canadian Natural is the largest primary heavy oil producer in Canada. We dominate the land base and the infrastructure, and we have over 8,500 locations in inventory. Due in part to our dominance, we have excellent capital efficiencies and low operating costs, making primary heavy oil the highest return on capital projects in our portfolio and generate significant free cash flow. Canadian Natural drilled 226 wells in the first quarter, out of expected 890-well program for the year. Production is on track, up 11% from Q1 2012 at 133,000 barrels a day. We expect to deliver 12% production growth to just over 140,000 barrels a day at the midpoint of guidance for the year.

At our world-class Pelican Lake pool, our leading-edge polymer flood is driving significant reserves and value growth. We have over 550 million barrels to develop under polymer flood. Our plan in 2013 at Pelican is to continue the development of the polymer flood with 56% of the pool converted by the end of 2013. We are seeing good production response from our polymer flood and see production increases by 16% in 2013. In the first quarter, production averaged approximately 38,000 barrels a day, up only 4% from the fourth quarter, as volumes at Pelican Lake were restricted due to polymer treatments and facility constraints.

New Pelican Lake facility with a capacity of 20,000 barrels a day is expected onstream early June, and at that time, we expect to see a step increase production in volumes both at Pelican and Woodenhouse.

We are currently holding back roughly 4,000 barrels a day of production at Pelican Lake and another 8,000 barrels a day at Woodenhouse for a total of 12,000 barrels a day of field production capacity, which we will start to bring on in June.

Turning to light oil in Canada. We continue to optimize our existing waterfloods and leverage technology over extensive land base. The first quarter unfolded as expected, and we're now on track to deliver a solid 2012 production growth of 5% to 67,000 barrels a day at the midpoint of guidance. We'll continue to progress our secondary and tertiary recovery projects and drill 40 net wells targeting new play developments that were initiated in 2012.

In the North Sea, production was relatively flat Q1 to Q4. And in 2013, we'll run 2 rigs in the North Sea and drill 3.6 net wells, as well as perform a number of workovers and safety-critical works on the platforms. This drilling program is being undertaken in 2013 as a result of the brownfield allowance program, and it's contingent on timing approval of allowances by the U.K. government. The drilling will add incremental production, which will mostly impact 2014 production levels, and will begin the reversal of increasing operating costs in the North Sea.

In offshore Africa, in Cote d'Ivoire, the start-up of our tender assisted rig on Espoir has been delayed somewhat, as we ensure the rig meets our safety specs. When completed, the in-field program will add 6,500 BOE a day of light oil at a cost of $24,000 per flowing barrel. At Baobab, we've sanctioned the in-field program, which will add 5 production wells and a couple of injectors. The drilling is scheduled to begin in 2015 and then will be completed -- and when completed, will add over 10,000 barrels a day and an incremental 42 million barrels of light oil reserves. Long lead items have already been ordered. Also in Cote d'Ivoire, exploration activity is under way on Block 514, with a seismic program now completed. We believe 514 has potential for light oil discoveries on trend with the deepwater channel/fan structures similar to Jubilee in Ghana. We have a 36% interest in Block 514.

In South Africa, we're tracking to plan in our process to bring in a partner for Big E exploration project. As a reminder, this development has up to 5 significant structures on our lands, billion-barrel-type structures, that we currently own 100%. We have selected a partner to join and conduct exploration drilling. And currently, we're in the process to compete all the necessary regulatory documentation to bring in a partner with the South African government. We expect the process to go well, however, it will take time to execute. The likely earliest drilling date for the South African exploration well would be late 2013, early 2014. Long lead equipment to drill this well has been ordered.

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 closer to 8 billion barrels as we expand our pit limits and drilling improves ore body delineation. Our current capacity is 110,000 barrels a day, and we're on track for 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. We have made significant progress to improve operations reliability at Horizon in the past year. We're progressing today and we will continue to progress as we go forward.

Our more conservative approach focused on operation discipline and change in maintenance strategy is delivering. Production in the first quarter was solid at just under 109,000 barrels a day. April production came in at just under 104,000 barrels a day, with significant improvements in reliability seen in the first part of 2013. We expect reliability improvement over the course of 2013, with a step-change in reliability after completion of our May turnaround that is now under way.

The turnaround is scheduled for 24 days. This is the first major turnaround at Horizon, and we have put considerable effort to address all known issues that have hampered reliability, as well as the inspection of pressure vessels and exchangers. We expect enhanced reliability and strong production performance coming out of the turnaround, with 2013 yearly production in the 100,000 to 108,000 barrels a day range. The turnaround is scheduled for 24 days, and barring any significant found work, we're confident all key turnaround work will be completed in the 24-day schedule. Canadian Natural's execution strategy to expand Horizon has been very effective, and we're tracking to schedule and are running below our cost estimates by about 10%.

The availability of construction contractors and related services has been better than expected. As a result, we continue to see bidders sharpen their pencils as we let out additional work. Today, we're roughly 20% complete on the combined Phase 2/3 expansion. We're 87% compete on reliability; 17% on Directive 74; 52% on Phase 2a, which will add 10,000 barrels a day in 2015; and 11% on Phase 2b, which will add 45,000 barrels a day in 2016; and 11% on Phase 3, which will add 80,000 barrels a day. Although it's early, we're only at the overall 20% mark, we may have hit a window with a lull in construction activity making the control of costs and maintaining schedule somewhat easier.

The Phase 2/3 expansion at Horizon is unique when compared to other mining and upgrading developments. The optimal design and performance at Horizon is achieved when we reach the 250,000 barrel a day mark. At these levels, we'll be able to leverage all the prebuilt 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 costs at Horizon are fixed and will not increase at the same level as production increases.

These factors -- optimal design, leveraging Phase 1 prebuild, increased reliability and lower operating costs for all 3 phases of Horizon -- allow expansion of Horizon to achieve our after-tax return on capital criteria. In addition, Horizon has a 40-year reserve life with no declines and virtually no reserve replacement costs, allowing decades of sustainable and significant free cash flow.

In summary, Canadian Natural is in great shape. Our balanced reserve base is the largest in our peer group and a reserve base that ranks with global industry players and delivers significant cash flow. Importantly, we're able to effectively allocate a portion of the free cash flow to our very large undeveloped resources that we own and control, resources that are long life and low decline, which further strengthens our ability to generate even greater amounts of free cash flow in the future, providing ever-increasing amounts of free cash for allocation outside of development of our vast resource base, as well as increase our ability to withstand commodity price downturns in the future. And probably most important of all, we have the people, the expertise and experience to execute our programs and operate effective and efficient operations.

And as Corey will point out, our balance sheet is strong with the capacity to capture opportunities and weather commodity price volatility. Corey?

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: 100,000 barrels a day of Brent collars with an average floor of USD 80 a barrel and ceiling of USD 137; 150,000 barrels a day of WTI collars at USD 80 by $106; and about 9,000 barrels a day of WCS differentials at $20.75, all through the remainder of 2013.

With those comments, I'll pass it back to you, Doug, for the regular Q&A.

Douglas A. Proll

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

Question-and-Answer Session

Operator

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

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

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 - Morningstar Inc., Research Division

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 - Morningstar Inc., Research Division

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 - Barclays Capital, Research Division

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 - National Bank Financial, Inc., Research Division

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 - UBS Investment Bank, Research Division

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 - UBS Investment Bank, Research Division

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 - UBS Investment Bank, Research Division

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 - UBS Investment Bank, Research Division

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 - FirstEnergy Capital Corp., Research Division

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 - FirstEnergy Capital Corp., Research Division

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.

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