Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2012 Second Quarter Conference Call. I would now like to turn the meeting over to Mr. John Langille, Vice-Chairman of Canadian Natural Resources. Please go ahead, Mr. Langille.
Thank you, operator and good morning everyone. Thank you for attending this conference call where we will discuss our second quarter results and review our planned activities for the balance of 2012 and in some cases beyond that. Participating with me today are Steve Laut, our President, and Doug Proll, our Chief Financial Officer.
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 both expressed as before royalties unless otherwise stated. I’d like to make some initial comments before I turn the call over to Steve and Doug for their in-depth discussion.
The second quarter saw us meet our production guidance and achieve record production. Crude oil production grew to over 470,000 barrels per day from the 395,000 barrels per day in the first quarter, and natural gas production remained at over 1.2 bcf per day. This growth was driven by firstly, the best quarterly production of SCO ever from Horizon, our oil mining project. Quarterly production averaged over 115,000 barrels per day as the completion of a third ore preparation plant greatly enhanced reliability.
Secondly, we have continued strong production from our primary heavy oil areas, which averaged over 122,000 barrels per day. And thirdly, production response of our thermal in situ project at Primrose returned to a production cycle from a steaming cycle. Daily average production from this project grew to 94,000 barrels from the first quarter average of 80,000 barrels.
This strong production together with emphasis on cost control and reduction of cost contributed to the growth in our quarterly earnings and cash flow. Cash flow amounted to $1.75 billion, up from $1.28 billion in the first quarter of this year. The cash flow gave us significant room to complete our second quarter capital program of $1.3 billion, payout dividends that have increased by 17% over last year and to buy back 6.2 million common shares under our Normal Course Issuer Bid.
Commodity prices continue to be volatile with a mixed outlook. Natural gas supply demand is out of balance. However, the recent record high temperatures in eastern North America have provided some additional market for natural gas usage, and it does appear that recently there has been a pull-back on development of new production, which may help to stabilize the supply of natural gas. However, having said that, our average price received for natural gas in the second quarter of this year decreased by 54% from the price received in the second quarter of 2011. Clearly the economics of natural gas development has been further compromised and we have curtailed our capital exposure accordingly.
Planned and unplanned maintenance activities at refineries and unplanned pipeline restrictions continue to affect the differential charge against heavy oil. The WCS differential averaged 24% of West Texas price in the second quarter of the year, somewhat higher than the 17% differential in the second quarter of 2011. We are able to positively manage our business over these cycles, and as additional refining capacity and new pipelines are put into service, we will be in a very good position to benefit from these additional markets for heavy oil.
We continue to ensure our business remains balanced and our financial position remains strong by reallocating capital expenditures. We have adjusted our targeted capital expenditures for the year downward by almost $700 million. This reduction in CapEx, however, does not adversely affect our oil production guidance for the 2012 year. As Steve will show you, our balance asset base is very strong. We have tremendous opportunities to increase our reserves and production and most importantly we have a very defined plan to accomplish that. With that, I will hand the meeting over to Steve and then to Doug to discuss our financial position. Steve?
Thanks, John and good morning, everyone. As you can see in the second quarter our balanced and diverse assets, proven and effective strategy, executed by our strong teams delivered a very strong quarter. Production was up and operating costs were down across the board in North America. In addition, we’ve been nimble, effectively optimizing our capital allocation in the quarter in response to market conditions. We’ve reduced our capital spending in 2012 by roughly $700 million, a 10% reduction, and at the same time slightly increased our overall production guidance for 2012.
Canadian Natural’s ability to quickly and effectively reallocate capital and at the same time increase production, confirms the strength of Canadian Natural’s assets, our capital flexibility, the effectiveness of our strategies and the ability of our teams to effectively execute. Few, if any, companies in our peer group can effectively reduce capital spending and deliver a production increase.
I’ll briefly comment on each of our areas, starting with gas. As you know, we’ve been bearish on gas prices and that’s not changed. In Q2, we proactively reduced our gas drilling program for the year by half, from 71 wells to 35 wells. As well, we deferred the well completions on our Septimus program and as a result we’ve deferred $110 million of gas capital out of the 2012 plan. This deferral of capital impacts gas and NGL production exit rates, since all these wells, especially at Septimus, were liquids-rich wells. We’ve also proactively shut in 20 million cubic feet of gas in 2012.
Canadian Natural has very strong gas assets and with this significant capital reallocation and gas shut-ins, we still remain within gas production guidance and our operating costs are down 15% as expected in Q2. Even in this very low price environment, our average wellhead net-backs after royalties and op costs are $0.58 in Mcf, a reflection of the strength of our gas assets and our effective operations.
Our light oil and NGL assets in Canada are strong. Light oil and NGL volumes will grow at 12% in 2012 to 63,000 barrels a day at the midpoint of guidance. Very strong growth reflects the strength of our light oil asset base as we progress waterfloods, EOR development and horizontal multi-fracs across our large asset base.
In the North Sea production was down as the BP-operated Ninian pipeline system was offline for three weeks versus the four days they had scheduled. Operating costs were also adversely impacted in the quarter. And also, Africa, we’re still on track for the startup of the Espoir infill program in Q4 2012. This program will begin to deliver production in 2013 and ramp up to 6,500 BOEs a day at a cost of 24,000 per flowing BOE.
In Q3 there’ll be turnarounds at Ninian North and Central, a smaller turnaround at Tiffany as well as a pipeline outage on the Ninian pipeline system in the North Sea. In Africa, turnarounds at Espoir and Baobab will be undertaken in Q3 as well. The production impact is reflected in our production guidance.
We’ve also finalized all the necessary regulatory work with our 100%-owned South Africa deep water prospect. This prospect has billion barrel type structures on our block, which we own 100%. This fall we’ll begin the process of taking on a partner to drill an exploration well at the earliest in 2013.
Turning to heavy oil, as you know primary heavy oil has the highest return on capital in our overall inventory and generates significant free cash flow. We have in this quarter allocated additional capital to primary heavy oil, and our 2012 record drilling program has been increased by 54 wells to 872 wells in 2012. With increased drilling and the success of our program, we now expect production growth to be 20% in 2012, or roughly 124,000 barrels a day at the midpoint of guidance.
As we mentioned in the last conference call, our new Woodenhouse play has added significant volumes. Currently, we are producing 9,300 barrels a day, well ahead of expectations, and exit rates for the year are targeted at roughly 12,000 barrels a day. We’ve drilled 50 wells so far this year, have 32 completed with 17 wells left to drill in 2012. Production rates have been excellent at 170 barrels a day per well.
We have over 200 drilling locations left to drill at Woodenhouse to add to our significant and extensive 8,000 well inventory of heavy oil locations, ensuring significant heavy oil production growth in the future.
At Pelican, we continue to effectively implement the polymer flood across a pool and we’re now seeing good polymer response from essentially all portions of the pool. We will drill another 72 wells at Pelican in 2012 and continue the expansion of the facilities to handle the increased Pelican Lake and Woodenhouse production. Pelican Lake production will grow 4% year-over-year, but more importantly, the polymer-driven production profile delivers very low declining production and significantly adds to our long-life, low-decline asset base.
Our thermal operations at Primrose and Kirby are strong. At Primrose, we continue to effectively deliver production volumes at the lowest operating costs in the industry. In 2012, Primrose development plan, we are developing five pads at Primrose East that will add 20,000 barrels a day in 2012 and ramp up to 30,000 barrels a day in 2013. At Primrose South, we’re developing three pads that will add roughly 15,000 barrels a day in 2012 and ramp up to 20,000 barrels a day in 2013, both at a cost of $13,000 flowing barrel. At Primrose, we continue to optimize our streaming strategies, leveraging learnings and capturing new opportunities to maximize value.
In Q2, we have adjusted our steaming strategy slightly, steaming new pads longer and injecting more steam volumes. As a result, our recovery per cycle will increase and our SOR on a cycle basis will decrease. This has impacted production slightly for 2012, as we will not bring these new pads on to the production portion of this cycle as early as first planned. Production guidance for the year has not changed. Primrose pads are some of the lowest cost production capacity additions in the industry. As our Canadian Natural’s operating costs, which are targeted to come in at $9 a barrel in 2012, making Canadian Natural’s thermal in situ heavy oil production very profitable, if not the most profitable in Canada.
At Kirby, we remain on track. The Kirby self-development is on an overall basis, 53% complete; 2% ahead of plan with construction 42% complete. All major equipment has been ordered and we’ve committed over $979 million or 83% of the total budget. Overall drilling and completions is 56% complete, with a rig now on the fourth pad.
Most importantly, we have seen no reservoir surprises and have been able to place the SAGD wells where we want them. Kirby South is targeted to add 40,000 barrels a day of SAGD production, with facility room to grow to 45,000 barrels a day at a cost of $32,000 per flowing barrel. First steam is scheduled for November 2013. The overall Kirby development will see Kirby’s self-capacity increase to 60,000 barrels a day and Kirby North develop to 80,000 barrels a day in two phases for a total capacity of 140,000 barrels a day.
At Kirby North, EDS engineering is 80% complete and on schedule. The regulatory process remains on schedule with the applications submitted in Q4 of 2011. Clearing of the central plant site is complete and we’ve ordered the evaporators and steam generators. First steam in for Kirby North is targeted for early 2016.
At Grouse, the regulatory application for 40,000 barrels a day capacity has been submitted this quarter. Grouse DBM engineering is on track to be completed in 2012 and EDS engineering will be kicked off this year. Grouse first steam is targeted for late 2017. Overall, our thermal in situ development program is on track and set to unlock significant value for shareholders.
At Horizon, we had a very strong quarter. Production averaged 115,800 barrels a day as we continue to make good progress on enhancing our levels of operation discipline and increasing reliability, particularly in our upstream operations with the addition of a third OPP. Operating costs in the Q2 were good at $36.98. That being said, we are confident that with our disciplined and proactive approach to operations, we will over time deliver ever-increasing levels of reliability, which will result in more effective and efficient operations with lower operating costs. Sustained costs came in roughly at – sustaining capital costs came in roughly at $5 a barrel in Q2.
We will continue to proactively maintain the operation, delivering over the long run a more steady, safe, reliable and effective plant. We schedule planned maintenance in Q3 to proactively repair various heat exchanges and repairs to a couple of mechanical seals on rotating equipment, increasing reliability going forward and optimizing overall plant performance. As a result, we target Q3 production average in 100,000 barrel a day range rather than 115,000 barrel a day range in Q2. However, we target Q4 production average closer to the rates seen in Q2 in that 115,000 barrel a day range.
Overall, we expect strong performance and have raised our full year midpoint production guidance by 4,000 barrels a day with the range now at 90,000 to 98,000 barrels a day. Phase II/III expansion at Horizon is going very well and we continue to track to just below cost on an overall basis. Our strategy of breaking the project into individual pieces with the ability to slow down or stop if market conditions are not favorable has been very effective.
Capital spending in 2012 is now targeted at just over $1.5 billion, roughly $330 million below budget, as we continue to see cost savings and more importantly take extra time to properly split out bid packages to achieve better costs and execution certainty. In addition, we have awarded four large, lump-sum bids for major components of the expansion. These four plants, Froth Treatment, Gas Oil Hydrotreater, Hydrogen plant and the VDU/DRU unit represent most of the larger, more complex components of the plant expansion, and as a result, will be able to achieve a higher degree of cost certainty going forward.
As you know, expansion will have a significant impact on our operating costs. With the exception of the mining costs and natural gas costs, our operating costs are largely fixed, with the biggest component being labor. Mining costs are roughly $8.50 a barrel at the current time and with the expansion, we should see small gains in efficiency. Natural gas are roughly $2.50 a barrel, assuming a $3.50 gas price. Therefore expansion economics look very favorable as operating costs for the entire production stream are reduced significantly. And in a $5 gas world, we expect operating costs to be in the $22 to $28 a barrel range. This reduction in operating costs, plus increased reliability, which not only provides more stable revenue, but in itself reduces operating costs on a per-unit basis, making a significant contribution to the return on capital for Horizon operating expansions.
As a reminder, we have roughly 6 billion barrels to recover at Horizon and we’ll ultimately expand to 500,000 barrels a day, with a reserve life of 40 years of production with no decline. Although we’ve had some issues in early years, we are very confident in our ability to deliver safe, steady and reliable operations over the next 50 years for this truly world-class asset. Clearly Canadian Natural is in great shape, with significant production growth and value to unlock our oil assets. Recently, there’ve been market anomalies that have caused some concern, in particular, the logistical constraints at Cushing that have caused a WTI differential to widen. We believe that this anomaly will be short-lived, as the Seaway Reversal came on-stream in May, followed by an expansion in Q1 2013, leaving the bottlenecks at Cushing.
Ultimately, with the Keystone Cushing market link, which has received final permits and scheduled to be in service mid-2013 at 700,000 barrels a day, we believe the WTI to Brent differential will collapse back to essentially the approximate total rate between Cushing and the Gulf Coast, which of course is good news for all North American oil producers in the short to mid-term.
Over the longer term, we believe the concerns that we may see very wide differentials between WTI and Brent becoming the norm, are very unlikely. Although the concern that increasing light oil growth from unconventional sources in North America is valid, the impact on North American light pricing is not likely to be as severe as many on the street believe. Today the U.S. imports, outside of North America, roughly 800,000 barrels a day of light oil into the Gulf Coast, so even if unconventional light oil continues to grow at recent growth rates, we have some time to go before all foreign barrels are pushed out of the Gulf Coast. Of course there is some debate if the unconventional growth rates can be maintained.
Regardless, if and when we push out foreign light oil barrels in the Gulf, there is still significant volume of medium oil imported into Gulf up to 1.5 million barrels a day. These medium barrels will also be pushed out of the Gulf Coast as light oil will ultimately be blended with heavier, North American barrels to meet the refining demand in the Gulf Coast. Light oil used to blend will be subject to some price discounts, but nowhere near the degree that WTI has discounted to Brent with the current logistical constraints.
Turning to heavy oil, we are very bullish on heavy oil pricing. The blowout on heavy oil differential seen in the first quarter is almost entirely due to planned and unplanned refinery or heavy oil refinery capacity. As this capacity came back online, we saw a dramatic narrowing of heavy oil differentials in May and June. As a result, Q2 differentials averaged about 24% of WTI, well within our long-term estimate of 22% to 25%. We do however expect to see occasional anomalies in heavy oil differentials in 2012, as the refineries go down for planned and unplanned maintenance.
However, with a 300,000 barrel a day of heavy oil conversion capacity slated to come on-stream from the end of 2012 to the first half of 2013, these issues will disappear and actually put downward pressure on heavy oil differentials. Add to this, the strong likelihood that Keystone will be approved allowing North American heavy barrels to displace to roughly 2.4 million barrels of heavy oil imports into the Gulf Coast, as well as provide blending opportunities to displace medium oil imports, heavy oil pricing looks very strong going forward.
As you know, the economics for heavy oil have been very strong and we believe we’re about to enter an outstanding era for heavy oil and in particular for thermal or in situ heavy oil, an era where for the first time, most if not all the key factors are in our favor. Increasing demand for heavy oil, strong heavy oil pricing, low gas prices which drive thermal in situ heavy oil operating costs lower, and lower premiums for diluents with increased supply of liquid diluent from liquids-rich drilling, all adding to the further strength of economics for heavy oil.
As a reminder, Canadian Natural has 8.5 billion barrels of heavy oil resources to develop, and 8,000 primary heavy oil locations in inventory. Clearly Canadian Natural is in a great position to capture the opportunities created by a very robust heavy oil market going forward. Canadian Natural is in an enviable position. Our assets are very strong with future resources to unlock, but more importantly, Canadian Natural has the largest reserve base in our peer group.
As we all know, reserves are real value. Canadian Natural’s strategies are proven and effective. Our ability to effectively reduce capital spending and increase production guidance is unique. As can be seen in the second quarter, we’re operating in a high level of discipline, effectiveness and efficiency with record production and lower operating costs across the board in Canada. On top of this, our balance sheet is strong, and as Doug will discuss, our financial management is disciplined and prudent. Doug?
Thank you, Steve and good morning. I would like to briefly summarize a few financial highlights for Canadian Natural in the second quarter and first half of 2012. In the second quarter we generated $1.75 billion of cash flow from operations and incurred $1.3 billion of capital expenditures. This resulted in first half cash flow from operations of $3 billion and capital expenditures of $2.9 billion. After taking into consideration our dividend program and the purchase of common shares under our Normal Course Issuer Bid, long-term debt at June 30, 2012 was $8.5 billion, roughly in-line with our year-end long-term debt of $8.6 billion.
Our balance sheet metrics remained very strong, with debt-to-book capitalization of 26% and debt-to-EBITDA of one times, considerably below our internal targets. We focused our attention on liquid resources and long-term debt maturity schedule in the second quarter. In June, we extended our $1.5 billion revolving bank facility to June 2016, and issued $500 million of seven-year Canadian medium-term notes with a coupon rate of 3.05%. At June 30, our available unused bank lines amounted to $4.4 billion, which allow for the retirement of the roughly $1 billion of debt maturing in October of this year and January and February of 2013.
In addition, we can prepare our 2013 capital budget knowing that available resources are available to back-stop commodity price volatility and to continue to manage our day-to-day business. In a constantly changing environment for commodity prices and ongoing economic news impacting North America and European economies, liquid resources are a must. Our commodity-hedging program continues to be actively managed. Currently we have Brent Collars for 150,000 barrels per day with a floor of US$80 for the remainder of 2012. This reduces to 50,000 barrels per day for the first half of 2013. In addition, we have US$80 puts in place for 100,000 barrels a day for the remainder of this year.
In conclusion, I believe we are very well positioned to continue to develop our diverse asset base, including strategic projects at Horizon and Kirby. Our strong cash flow, balance sheet strength and adequate liquid resources ensure that we are able to complete our business plans. This financial strength complements our management strategies and the company’s disciplined approach to project execution and operational excellence. Thank you. And I will return you to John, for some closing comments.
Thanks, Doug and Steve. As you can see, we are very well positioned to weather all the cycles that occur in this business. And we are able to drive our own agenda with the added amount of flexibility to ensure that we can control costs in an environment that often-times creates its own inflation. We will ensure that we continue to create value for our shareholders. With that, operator, I would like to open up the call to the questions that participants may have.
Certainly, sir. Ladies and gentlemen, we will now take questions from the telephone lines. (Operator Instructions) And the first question is from David McColl at morning – I beg your pardon – George Toriola at UBS, please go ahead. Your line is now open.
George Toriola – UBS
Thanks, and good morning. I have a couple of questions, three questions. Just quickly, we’ve seen some industry players go away from CHOPS development to smaller scale thermal projects. Could you sort of address the way you look at your primary heavily oil growth and what you see along those lines as compared to what some of the other industry players are doing? That’s the first question. Secondly, you’ve talked about growth for this year 21%, could you provide an outlook over the next three years, what type of growth rates you would expect from primary heavy oil production if crude oil prices stay where they are at right now? And then lastly, on the CapEx reduction as far as the Horizon is concerned, is that due to cost inflation or some other thing? If you could do that, that would be helpful. Thanks.
Okay. Thanks, George. Steve, here. Could you maybe – I’m not sure what the first question really was about, smaller thermal projects and the primary heavy oil growth versus bigger projects. Is that what you’re asking or?
George Toriola – UBS
Okay. So the first question was around we’ve seen some – on your primary heavy oil, we’ve seen some industry players say that CHOPS production does not really serve well if you look at it from reserve recoveries and that standpoint. Could you address that? You guys obviously – you probably see it differently so that would be helpful to understand how you look at heavy oil development versus other techniques that you might be able to use?
Well, good. Thanks, for that clarification because that’s a very important question and, as you know, Canadian Natural has a very large heavy oil asset base and we cover the whole range. So, you have to utilize the most effective technology that generates the greatest return on capital for each individual reservoir and type of reservoir. So, on our primary heavy oil production, we are targeting essentially thin sands that are unconsolidated and why the recoveries in primary heavy oil production work so well, is that the sand is actually mobilized and produced, that’s what the CHOPS production is, and you get very good recovery rate in terms of production rate. The actual recovery of oil out of the reservoir is probably in that 10% to 15% of original oil in place with that method.
However, any other technique for that type of reservoir, if you use a thermal process it’s too thin, and also the sand production is huge, it’d be very difficult to run a thermal process. So you use the best technology there. On thicker, more cleaner sands, you’ll either look at the SAGD process and/or the cyclic process if there’s gas entrapped in the reservoir and oil. So cyclic is much more robust, so it may handle dirtier sand. SAGD needs to be thicker and cleaner and it can work with less gas, so there’s a trade-off there. And for us, we optimize based on the reservoir in our asset base the effective recovery.
So the big thing here is, if we can find a way, and we’re working on the technology, we have found nothing yet, but we’re working on a few things, to improve that recovery on CHOPS production. If we could find a secondary recovery process, we have another 8 billion barrels roughly of untapped oil with a lot of wells already drilled. If we could find that there’d be huge recovery. So long answer to that first question.
On primary heavy oil growth it’s about 20%, 21% this year, and we think in the next three years we can probably do about a 10% growth rate. Obviously we’ve exceeded that this year and we’ll see what 2013 brings, but our plan says we can grow for about 10% for the next three years and then it’ll start to taper off. As you know, we’ve got a big treadmill here as we grow production, and we think we can go up to about 160,000 barrels a day and then the growth will tap-off or taper-off.
As far as Horizon, why the CapEx has been reduced? Two reasons, one is we are seeing cost savings and that cost savings has come essentially from our strategy. As you know, we broke this thing into smaller pieces and we are not schedule driven, we’re cost driven. And so many times, I think we talked about this before, where we’ve gone back, when we get bids that do not meet our cost expectations, we go back and we break that bid out into smaller pieces, change the scope of the work and rebid it, and we’ve been able to come under. That takes more time and essentially that is the other reason why the CapEx is down in 2013 – or 2012, for Horizon. Because we’re taking more time and we’re getting better costs and better execution strategy. Of course you defer the execution.
Will that have an impact in 2013? We think maybe the same strategy will happen in 2013. And really what we’re doing is, in our schedule, we’re using up the float on our schedule. So we don’t see any impact on production and – when we had targeted production from Horizon. But we are using our scheduled float to the most advantage to get better costs and cost certainty in terms of execution. So, we believe it’s been very positive. We know there’s more cost pressures coming and we think it’s going to work for us in the future as well.
George Toriola – UBS
Okay. Maybe just to quickly follow-up on that. So it’s not a cost deferment. The cost, $405 million that you’ve taken out here is not coming back in future or it’s gone completely?
It’s not. Part of it is deferred into future years and part of its cost savings.
George Toriola – UBS
Okay. And then maybe...
About 30% is cost savings. The rest is pushed out into future years as we re-bid the packages and get better costs with that.
George Toriola – UBS
Okay. Thanks. And maybe you can just talk about – I mean you’ve talked about sort of the capital efficiencies you need to generate the rates of returns that you require, could you broadly talk about – based on the capital efficiencies you’ve talked about before, is there a percentage cost savings overall that you’ve seen to date? Are you able to provide that type of insight?
I think what we’re seeing right now – I think we’re hesitant to predict the future because we’re pretty early on and we know there’s going to be cost pressures. But at Horizon, we believe we need to be below $100,000 a flowing barrel, which we are. And so that’ll give us our strong returns on capital. On thermal projects, we probably need to be below $35,000 to $36,000 a flowing barrel. And we’re about $32,000 at Kirby so we feel pretty comfortable there. The expansion should be better. So right now I’d say in situ looks slightly better than mining and the economics. One of the things on mining you’ve got to remember is, we do reap a huge operating cost benefit with expansion at Horizon.
George Toriola – UBS
Thank you very much.
Thank you. The next question is from David McColl at Morningstar. Please go ahead. Your line is now open.
David McColl – Morningstar
Thank you, and good morning, guys. So as George mentioned, there’s the issue with the lower cost for Horizon. So I just want to build-off that a little bit. Guidance is showing higher costs for Kirby South and Primrose, relative to the previous guidance. So I’m trying to just get a handle on what’s kind of driving this? Are we seeing higher costs for in situ on the inflation side or are you guys trying to escalate a few things to as alluded to kind of get ahead of the curve for higher costs coming forward? Thank you.
I think, David, what you’re seeing here is a little difference in what – how we’re managing the project. Obviously to build Kirby is a smaller project than Horizon and quite frankly it’s less complex. So if you heard me talk this morning, Kirby’s ahead of schedule. We’re about 2% ahead of plan, so you expect the costs to be ahead of schedule as well. So we’re actually moving costs from probably 2013 into 2012 so that’s why the costs have gone up, capital cost have gone up on Kirby, because we’re actually able to execute at a faster rate. And that’s mainly because it’s a smaller project and we’re doing civil and structural mechanical work in 2012 that we’ve been able to accelerate and we’ll do more of the smaller piping and electrical instrumentation later in 2012 and 2013 and that’s where we use a lot of labor.
So we’ll see how that works but we’re very confident we’re going to do well on Kirby cost. At Horizon it’s a case of – it’s more of a mega project, a bigger project, more complex, so we’ve taken our time. You’ve seen these four lump-sum bids. It’s taken us longer to get those contracts executed as we take the time to make sure we have the scope totally defined, the engineering complete, so that the lump-sum bids we get are very good, and they are good bids. That takes more time. And of course time to get the contract before they execute in the field and so the cost spend is lower mainly because they haven’t got to the field as soon as we had in the original schedule. Which all in all, is actually a good thing to get the better cost, and to let the schedule slip because we have float in the schedule at Horizon. And you can see here we’re driven in all cases to cost, not schedule.
David McColl – Morningstar
So is there any thought just to follow up then on looking at Grouse and the other in situ projects to maybe try to pull up the schedule a little bit on those again to try to avoid some higher costs down the road?
Our view on cost is that you need to ensure you have your engineering complete and have – particularly in situ. And this is a mistake a lot of players have made in the past is they don’t get the engineering up front done. They don’t have enough geological definition and their modeling done before they start because it’s very easy on a SAGD project to get your wells placed in the wrong position, and for us we do not want to have to re-drill the wells as many of operators have, even the operators that have – are widely recognized as being very good SAGD operators, have had to re-drill wells. So it’s easy to do.
So to accelerate is actually not a good thing. It’s probably going to be – destroy capital efficiency by trying to accelerate, so we’re being very disciplined, keeping to our schedule, making sure we got all the right data, collected data, and have the engineering complete before we start, so you won’t see us accelerate.
David McColl – Morningstar
That’s great. Thank you.
Thank you. The next question is from Greg Pardy at RBC Capital Markets. Please go ahead. Your line is now open.
Greg Pardy – RBC Capital Markets
Hi. Thanks. Good morning, Steve. Just a couple things; I want to come back to Horizon. Just looking at the OpEx in the quarter, which just surprised me, it seemed a little bit higher just given where the run rates were. But the absolute number looked bigger, and I’m curious as to whether any additional costs are being loaded into that number? And the same question would almost hold true on the depletion side for Horizon, just to get our numbers right? And then the more strategic question, obviously there’s lots of talk now with LNG and so forth, and you guys have vast resources, the Montney and the Duvernay, just curious as to what your plans are for that acreage? Is this effectively the stuff you’re going to leave as an option when prices move higher or could you see yourself doing something sooner? Thanks very much.
Thanks, Greg. So the higher operating costs in Horizon I think are a little higher than we would like. They’re good, but they’re not great, and I think it’s a case of we are totally focused here in 2012 on operating discipline and safe, steady, realizable operations. And in effect what we’ve done here is not focused so much on operating costs, but focused on reliability and steadiness in the operation.
We believe with time, as we become more focused on reliability and the discipline that goes with it, you will see operating costs come down. But I think it’s maybe a case of conservatism; we made sure we had extra maintenance and probably loaded up on maintenance costs that in hindsight probably was not as necessary as we thought. But we believe that there’s a lot of room to grow on operating costs yet. So still our guidance is good, but I think over the long run you’ll our see operating costs come down. So I don’t know if I answered your question? But that’s really the operating costs. DD&A has basically determined how much we would pull out of the mine.
As far as LNG and the Montney and the Duvernay, obviously we do have a huge gas asset base. Our review right now is we’re just going to use it as an option. We are not looking at LNG, however it’s something that we won’t rule out, but at this time, we’re not looking at it. But we are obviously strong cheerleaders for everyone who is building an LNG plant.
Greg Pardy – RBC Capital Markets
Okay. So I appreciate what you’re saying in terms of the steadiness and the reliability. So 2Q probably not a bad idea as a run rate for the balance of the year, given sort of 110,000, 115,000?
I would say it’s probably – I think Q3 might be bit higher than that. Clearly we’ve got some maintenance we’re going to do here, and the rates are going to be down because of that. So you might see a little bit of a bump in Q3.
Greg Pardy – RBC Capital Markets
Okay. Thanks a lot, Steve.
Thank you. (Operator Instructions) And the next question is from John Herrlin at Societe Generale. Please go ahead. Your line is now open.
John Herrlin – Societe Generale
Yeah, hi. Thank you. With Horizon now being back to its normal operational status and more free cash flow being generated, will you consider having stock buybacks a more active part of your capital management program given the fact that your balance sheet isn’t over-levered?
I think I’ll maybe get Doug to answer more fully this question, but I think right now we’re happy with the way we’re doing our stock purchase bid and I don’t think we’re considering to do anything more substantial than we have in our plans right now. Doug, you want to add to that?
I think, Steve, I think it’s a – the stock buybacks are a function of making sure that we have the right use of capital across the company, as well as taking care of dilution. Year-to-date, we’ve actually bought back more shares than have been exercised under the stock option program, so we’re ahead of schedule on that plan. And going forward, it’s a function of the use of the availability of cash to initiate that program. I think that you can expect to see increased dividends going forward because that’s part of our plan. We have increased dividends for the last 11 years and the stock buyback program is a basic part of our financial plan.
So to add to that, John, our main uses for free cash flow on a priority are acquisitions if they’re there, and we haven’t seen anything that meets our criteria, increased dividends, which is probably where we’re more focused on and stock buybacks would be the third, but we have been doing that as well. So...
John Herrlin – Societe Generale
That leads me to my next question, M&A, during down pricing periods, you tend to be more aggressive, you just haven’t, as you’ve just said, nothing has met your criteria?
That’s right. We don’t see anything at this point in time. We look at a lot of properties and nothing has really met our criteria in this environment, or at least what we’re willing to pay, I would say.
John Herrlin – Societe Generale
Okay. Last two from me, quickly, services costs, you are getting more active in heavy activities, are you seeing any real changes at all?
I would say the service costs are sort of tale of two cities. On the heavy oil side, and primary heavy oil in particular, we’re starting to see pressure there, sort of continue in trucking costs and some of these service costs. On the gas side, we’re seeing obviously fracking costs are coming down and gas drilling rigs, which tend to be the deeper rigs, we’re seeing rates come down on the softness there. In Horizon and some of the major projects there, we are starting to see some pressure in some components, but interestingly, there’s – it’s sort of a mixed response; sum is nothing yet.
John Herrlin – Societe Generale
Okay. Last one for me is just housekeeping with Doug, some of the companies in the U.K. are announcing third quarter or fourth quarter P&A deferred tax charges. Do you have any sense of what yours may be?
Yeah. I think we mentioned in our notes but it’s looking like it’ll be about $58 million.
John Herrlin – Societe Generale
Okay. Thanks. I missed that. Thank you.
Thank you. There are no further questions. I would like to turn the conference back over to you, Mr. Langille.
Thank you very much, operator, and thank you, everyone, for attending our call. As usual, if you have further questions with us, do not hesitate to contact our Investor Relations department and have a very good day. Thank you.
Thank you. Ladies and gentlemen, your conference has now ended. All callers are asked to hang up their lines at this time and thank you, for your participation.
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