Good morning, ladies and gentlemen. Welcome to the Canadian Natural Resources 2010 third quarter results conference call. I would now like to turn the meeting over to Mr. John Langille, Vice-Chairman of Canadian Natural Resources.
Good morning everyone. Thank you for attending our conference call. We will discuss our 2010 third quarter results and also update our operational plans for the remainder of 2010 and into 2011.
Participating with me today are Allan Markin, our Chairman; Steve Laut, our President; Peter Janson, our Vice President of Horizon Operations, and Doug Proll, our Senior Vice President of Finance.
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.
Again in the third quarter, as a result of strong operational results and efficient control over our operating costs, we achieved significant cash flow of over $1.5 billion, well in excess of our capital expenditures. This is in line with our overall plans for 2010, where we originally budgeted the 2010 year to produce somewhere between $2.5 billion to 2.8 billion of free cash flow. We have used this free cash flow to increase the dividends paid in 2010 by 42%, repay some of our debt and strengthen our balance sheet and acquire some strategic assets and institute a share buyback program.
All of the acquisitions have complemented our activities in our core areas and provide opportunities for value creation through reductions in cash operating costs and the assets purchased, synergetic sharing of production facilities and increases in our land bases for future development.
Our developments continue to be primarily focused on low projects and oil sales contributed 86% of our gross revenue stream.
Commodity prices continue to follow the trend they have been in for the last several years. Oil prices are relatively strong and natural gas prices continue to weaken under the oversupply situation we find in North America.
In the last month of the third quarter, the discount factor for heavy oil price compared to the West Texas price widened as a result of a number of pipeline outages caused by ruptured pipe on one of the export pipelines transporting heavy oil out of Canada.
This differential remained high until it was clear that the pipeline was repaired and put back into service. Upon resumption of pipeline deliveries, the differential has fallen back to levels prior to the outage.
Before we turn this call over to Steve for the operating details, I would ask Allan to make some comments. Allen.
Hello and good morning everyone. It was at this time last year that we reaffirmed our commitment to our core values, spending where we need to, maintaining balance and continuing to optimize costs and production through safe and effective operations. And since that time, the company has remained disciplined in its approach to expenditures.
We have maintained a diversified portfolio of assets of crude oil and natural gas, and we have demonstrated our ability to adhere to our effective strategy. And looking to third quarter performance, the company had a well-grounded three months where all of our teams continually worked towards strong operational performance and cost optimization and efficiency.
At Horizon, things are progressing, and we continue to fine-tune operations in the plant in order to reach a state of reliability at the nameplate production capacity.
At our thermal operations, we are progressing steadily with our growth plan. We have expanded the Kirby asset through acquisition growth, and we are moving ahead with Kirby Phase 1 after recently receiving Board sanction.
As we have indicated many times before, our long term objectives, especially production, have not changed as we remain prudent in our approach. This year is not different, as we will end the year on a positive production and financial note.
Primary heavy oil and natural gas continue to deliver. We are confident in our execution strategy, as we continue to create consistent value for our shareholders. Steve.
As both Al and John have pointed out, Canadian Natural is in a very enviable position.
Our strong, well-balanced assets, combined with our capital discipline, focus on execution and effective operations has again delivered a strong quarter, even with slightly lower production volumes than expected.
Operating costs are very good, with overall operating costs for the first nine months of 2010 down 6% year-over-year on a boe basis, driven by a 17% reduction in oil operating costs in North America, and our capital spending is on track. This reflects the strength of Canadian Natural's assets and our ability to generate free cash flow.
Based on the current strip pricing, we'd expect to generate between $2.5 billion and $2.7 billion of free cash flow over what is required to deliver production growth, excluding discretionary property acquisitions.
In the third quarter we have been able to execute additional opportunistic and strategic acquisitions to strengthen our asset base in the near and long term. As a result, we expect to allocate $1.5 billion of this $2.5 billion to $2.7 billion of free cash flow to property acquisitions for 2010, up approximately $500 million from our expectation at the end of Q2. Taking into account property acquisitions, we expect to deliver between $1 billion and $1.2 billion of free cash flow in 2010, which will be used to further strengthen our balance sheet.
It is clear that Canadian Natural assets are strong and well balanced. We're delivering production, dropping operating costs, reducing capital spending and setting Canadian Natural up for significant value growth, while at the same time generating significant free cash flow. Few, if any of our peer group, are in a stronger position as Canadian Natural is going forward.
Turning in more detail asset-by-asset, starting with gas in Canada. As you know, Canadian Natural has the largest land base in Western Canada. Canadian Natural dominates the land base and infrastructure in our core areas. And as a result, we are low cost producer and are able to stand what is expected to be a prolonged period of low gas prices.
Our gas land base is very well positioned with strong assets and teams in conventional, foothills, resource and unconventional plays. Canadian Natural has over the last four years been quietly transforming the make-up of our gas portfolio with 63% of our very large gas inventory made up of resource and unconventional play types, with only 27% of the inventory from conventional play types.
Our Septimus/Montney gas development is one example of our unconventional asset base. We've completed our 2010 drilling program with 13 wells drilled. Costs have been excellent, coming in 20% less than expected. Completions are all done on all the wells now, with costs coming in as expected, and flow rates on these wells are very strong. Average initial rates from the first 11 wells are 8 million cubic feet a day at 1,600 pounds wellhead pressure and are on expectation.
Our 50 million a day Septimus gas plant is nearing completion, and we expect to have production ramped up to 50 million a day by the end of the year on cost and on schedule. We've reset this can deliver 200 million cubic feet a day, if and when we expect to bring on future development phases.
With the current low prices, we have also shut-in roughly 35 million day of gas production in Q3. This gas will remain shut-in until we see prices in the $5 range.
Turning to oil in Canada, oil production in Canada was down from our expectations, driven by strategic decision to take advantage of an opportunity to optimize our steaming strategy and capture additional value in mid-August.
On our recent pad additions at Primrose, Canadian Natural has drilled it tighter into well spacing. We're down to 80 meters versus 190 meters to capture additional recoverable oil and ultimately higher recovery rates.
After the first steam production cycle, it became apparent that we achieved a higher degree of inter-well communication and expected after first cycle which was completed in August. This was good news. With inter-well communications giving Canadian Natural the opportunity to adjust our steaming practices to increase overall effectiveness, greater recovery and lower cost in the next cycles.
As a result a result we have increased the amount of steam injected and as a result the time required to inject these larger steam volumes into late August, September and part of October. This has caused the production volumes to be less than expected in Q3 as we essentially continue to steam versus bring the wells back on production, in the production cycle in late August.
Hopefully this will result in higher production volumes for Q4. And our production cycle was initiated a year in late October, and early results have been better than expected. With significant volumes matching our flat capacity and more importantly and unfortunately matching in our ability to handle a vast amount of heat coming back at us in this initial stages of flow back.
As a result, we're curtailed some production in the short term and to amount of heat diminishes as we have progressed to the production cycle. Although the flow back volumes and the amount of heat with these volumes has been difficult to handle initially. It is a very positive indication on the performance of our new pads and our modified steaming strategy.
I would also point out this reflects the strength of our thermal, technical and operational teams. We're recognizing opportunity of maximized value and we're able to very quickly modify our strategy to capture this opportunity, a strength that is encouraged and highly valued in the Canadian Natural culture. These strengths will continue to be important as we unlock the huge value in Canadian Natural's dominant heavy oil and thermal oil position in Canada.
As you heard me say before, we believe our heavy oil and thermal assets are the hidden gem in our portfolio. Heavy and thermal oil are delivering significant value today and with our disciplined cost effective drilling program are adding tremendous value in the future. Our thermal assets alone have 33 billion barrels of oil in place and 6.2 billion recoverable in our defined plan.
To put this in perspective, 6.2 billion barrels of thermal oil is essentially the same as 6 billion barrels recoverable at a world class horizon operation. A vast amount of oil of our tremendous value became natural shareholders. Our plan to unlock this value, targets adding 285,000 barrels a day of heavy oil production in a very disciplined stepwise cost control manner. And taking total production facility capacity to over 400,000 barrels a day, again very similar to the 500,000 barrels a day we ultimately achieved at Horizon at/or phase 5.
In the third quarter Canadian Natural strengthen our asset base even further with the acquisition of additional lands adjacent to our Kirby development. The Kirby acquisition adds 520 million barrels of recoverable oil at a cost of $405 million. And much like Primrose we have been able to leverage the development of Primrose north and east, around the central facilities at Primrose and Wolf Lake.
We will leverage the development of these lands around the central Kirby facilities built on our existing lands and capture significant capital and operating cost synergies.
Canadian Natural's originally Kirby project which we now call Kirby Phase 1, we have received all regulatory approvals. In addition, the company has sanctioned the first phase of Kirby development. Kirby Phase 1 will be developed with 47 SAGD horizontal well pairs drilled from seven surface pads.
The facility we built is capable of generating 118,000 barrels a day of steam, treating 118,000 barrels a day of water and processing 40,000 barrels a day of oil. Canadian Natural's targeted cost of this development of Phase 1 at $1.25 billion and that will cost roughly $31,250 a barrel a day of capacity.
Drilling work at the site has now been kicked off with joint schedule to begin in April 2011 and the first steaming is expected Q4, 2013. It is highly likely that we'd all like the Kirby Phase 1 facilities to accommodate the development of a portion of the newly acquired lands, and there will be a Kirby Phase 2 in the future.
We are currently working in the optimal way to develop these lands and leverage our existing development to capture all the development synergies and maximize value. Although it's early, we expect Kirby Phase 2 to be in the 30,000 barrels a day to 60,000 barrels a day range, plus a development (inaudible) Kirby Phase 1. This will take Kirby optimum production capacity to 70,000 barrels a day to 100,000 barrels a day range, a significant development by any measure.
At Pelican Lake, we are on track with our program to create the fields for a highly successful polymer flood. By the end of 2010, we plan to push the Pelican area under polymer flood to 44% of the total pool. As we continue to clear Pelican to polymer flood, we expect production to reach a plateau of roughly 80,000 barrels a day of low cost production by 2015, roughly double the 38,000 barrels a day produced in Q3.
It is clear that Pelican Lake is a world class pool with 4 billion barrels in place and roughly 560 million barrels of recoverable resource with polymer flood, a very large pool with very robust development economics. Pelican Lake continues to generate significant value for shareholders and generate some of the highest returns in our portfolio.
Keeping with the theme of high returns, our primary heavy oil program continues to roll along effectively and efficiently. And in this commodity and cost environment, primary heavy oil generates top-docile returns on capital and our asset portfolio. Importantly, it also generates the quickest payout and largest cash-on-cash return.
In the three quarters of 2010, we have drilled 497 wells and expect to drill 650 primary heavy oil wells for the year, an additional 50 wells from our expectations on our Q2 press release and as a record number of primary heavy oil wells for Canadian Natural, roughly 35% more than we drilled in 2009. Our dominant high quality land base, infrastructure, and effective operations allow us to drill this size of program on a very cost effective basis, making primary heavy oil one of the best value generators in our portfolio.
Turning to the North Sea, major planned turnarounds were undertaken in Q3 and as expected, production was down in Q3. All turnarounds are now complete and we're on cost and on schedule. With the exception of Murchison where we encountered integrity issues with the production header, an additional time was taken to replace valves on that header and has pushed time into Q4.
We also had a shutdown in the quarter at Ninian to repair the flare gas system which reduced production slightly. Drilling and workover activities have been ongoing at Ninian, with safety critical workovers being completed and one more direct injection well drilled. Currently we are drilling a (inaudible) targeting uronic zone. As well, we want to take some subsea work on the T-Block.
In offshore West Africa, at Olowi, and Gabon, the B Platform is being on stream during the third quarter. Although early production results look good, we are seeing rising gas-oil ratios and will be monitoring us very closely.
We're currently drilling on Platform A with the first well on stream on last week at a rate of 2,500 barrels a day. The early production results were good. However, Olowi is a very complex field, and we'll need to monitor results over time before we can determine if this well will meet expectations. Production at Olowi is currently 8,000 barrels a day, was expected to peak out of 12,000 barrels a day when all four platforms are on stream.
In Côte d'Ivoire, production at Baobab, Espoir are both stable. Espoir gas production has increased by roughly 10,000 million a day with the additional compression being installed in Q2. It is important to note that Offshore West Africa has some of the highest return on capital projects in our portfolio, and along with the North Sea, generates significant free cash flow for Canadian Natural.
Turning to Horizon, we continued to make good progress driving towards sustained reliability. There is no question, the operation can and has delivered at or above 110,000 barrels a day of SCO design capacity. Our focus has been and will continue to be on reliability going forward.
The production by month is as follows; July, 93,300 barrels a day; August, 50,500 barrels a day; September, 108,000 barrels a day; and October, 87,500 barrels a day. Production has been strong and we're confident of the capacity of the plant and our ability to effectively run the operation. It is however very complex and a heat integrated plant and appears that it may us take some time until we are fully optimized and reliable.
As an example, much like July where we have been running very strong for the month of September and most of October, however it became apparent in October that several maintenance issues needed to be addressed on a proactive basis, particularly before the approach of winter. This activity was not in our 2010 plan.
Therefore, it was scheduled for October 23, and the entire plan was brought down, so we could address all these issues on an effective basis and before the winter season. The plant has begun the start-up procedure this week with first oil back on as of yesterday.
I'll turn it over to Peter Janson to give you a more detailed explanation of this plant outage, what type of issues were driving these outages, and the level of preparedness we are in for winter. Peter.
There were three primary objectives in the most recent maintenance outage at Horizon. Firstly, the dry gas seals on our wet gas compressor began to leak, and we did need to replace them. This was our critical path job going into the outage, and we want to make sure we had planned and staged all the materials and people to minimize our duration.
Second objective was to include other opportune maintenance within this outage window so that we can prove our reliability after start-up. Similarly, all this work was also planned and staged prior to the outage. Scopes of work from the other areas of the plan included a conveyor belt splice, a screen change out and the OPP, cyclone pack renewal and instrumentation installations in (inaudible), coke heater pegging, heat exchanger inspection and repairs, the installation of a new burner in one of our two sulphur units and some pump maintenance.
The third objective in this outage was to complete the last few scopes for work for winterization, specifically some electrical heat tracing and winterization of the OPP equipment. As you can sense, aside from necessary maintenance, we took this opportunity to enhance some of our equipment reliability and to ensure the plant was ready for winter.
Just prior to going into this outage, we did experience an exchanger leak in the hydrogen unit, which did have an impact on our adsorber performance in that unit. Maintenance on this exchanger did create a two-day extension to the outage, but all other works were generally completed within the window.
Of concern to us coming out of this shutdown is the peak capacity limit of the pressure sling adsorber unit. Initial indications are that we have lost some unit capacity as a result of contamination from the exchanger leak. If sustained, this will limit our maximum peak production capacity until December, when the absorbent material can be changed out.
At this point, it's difficult to assess the impact, but it may reduce capacity by 20,000 to 30,000 barrels a day of capacity.
As we move forward in Horizon, we continue look for improvements to equipment and processes that will enhance our production sustainability.
Back to you, Steve.
Thanks, Peter. As you can see, we are taking all the necessary steps to set us up for increased liability and performance going forward.
As you noticed, operating costs for Q3 are very good at $34.35 a barrel, about $2 a barrel higher than Q2, which is very impressive considering the lower production in Q3. On the sustaining capital side, we were tracking to, or below budget.
As I said earlier, this is a complex plant and will take some time to fully optimize. Going forward, our ops teams believe that we can achieve lower operating cost not just from higher production levels but more effective operations. Although we are not there yet, we see many opportunities to further improve performance.
Horizon is a world-class asset with over 6 billion barrels recoverable oil. We've targeted increased production through phases 2 and 3 to 232,000 barrels a day, and further expansions in phases 4 and 5 to just under 500,000 barrels a day, or 0.5 million barrels a day of light, sweet, crude, with no declines for 40 years and virtually no reserve replacement costs.
In 2010, we'll continue to complete work on Tranche 2 of our Phase 2/3 expansion. And spending wise, we are on track to our budget, which we reduced in Q2. Our detailed lessons learnt from Phase 1 are nearing completion and remain on track and we will incorporate any cost reduction effect of these measures into future expansions.
Along with this work we continue to do engineering work on future expansions and to (prepare) a more detailed cost estimate. It is our expectation that we will have a more detailed cost estimate early in 2011 and a better understanding of any modifications we will make to our execution strategy. This work will be completed to get better certainty on costing in various environments.
Canadian Natural is committed to the expansion of Horizon to 232,000 barrels a day, and ultimately just under 500,000 barrels a day of light, sweet, 34˚ API crude. As always, Canadian Natural is very focused on cost and cost control and creating value for shareholders, and we will be sanctioning the expansion of Horizon, but only when we can be assured that reasonable cost certainty is there and our return on capital requirements can be achieved.
It is clear that Canadian Natural is in a very strong and enviable position. Horizon is a world-class asset that is and will continue to add tremendous value to shareholders. Our thermal heavy oil assets can add value similar to the magnitude of Verizon, yet in more manageable sizes, and in my opinion are the hidden gem in our portfolio and in this low gas priced environment generate even greater value for shareholders.
Our light oil assets both internationally and Canada, as well as our primary heavy oil assets in Canada continue to generate strong returns. And in this low gas priced environment, our strategy of maintaining a well balanced portfolio and the fact that we are the low cost producer will ensure that we will be able to withstand and weather a very sustained period of low gas prices.
Our teams are strong throughout the company. And as Doug would point out, our balance sheet is strong and getting stronger. We have a very flexible capital program, giving Canadian Natural the ability not only to maximize the value of our well-balanced portfolio, but also capture any opportunities that would present themselves in this environment.
Canadian Natural is in a great position, and in today's environment, with our team, our strategy and our assets, I believe Canadian Natural is better positioned than ever before to generate significant value for shareholders.
With that I'll it turn it over to Doug to update you on our financial position and our prudent financial management.
Thank you, Steve, and good morning. Q3, 2010 marked the seventh consecutive quarter of positive free cash flow. During this period, we have applied most of this free cash flow to a reduction of long term debt, which has resulted in a stronger balance sheet where our debt-to-book capitalization is now 28%, and debt-to-EBITDA is 1.1 times. Additionally, our unused bank lines exceeded $3 billion at September 30.
This increase in balance sheet strength has not gone unnoticed by the rating agencies. Moody's upgraded the company's debt rating to Baa1 from Baa2 in October. This followed the change in Standard & Poor's outlook from 'stable' to 'positive' upon the affirmation of our BBB rating in August, and the confirmation of our BBB high rating by DBRS this past spring.
The third quarter also marked the reactivation of our normal course issue re-bid with the purchase of 2 million common shares. This active share buyback program, together with all four of our business segments generating positive free cash flow ensures our allocation of capital model is fully functional. Our commodity hedging program remains active, albeit at lower volumes which results from our improved balance sheet strength.
For the remainder of 2010, we have 150,000 barrels per day of oil hedged with WTI price callers with floors of $60 to $70 U.S. For 2011, we have 50,000 barrels per day hedge with a floor of U.S. $70 per barrel. In addition, we have established puts on 100,000 barrels per day with the strike price of $70.
For natural gas, we have equal floors of $6 on 220,000 GJ's per day for the fourth quarter of 2010. Details of all of our positions are available in the notes to the financial statements, and on our website. As a final note, our internal team has made excellent progress in the drive to be IFRS compliant for 2011.
Our system changes are virtually complete; our analysis of and compliance with IFRS accounting policies requiring change from Canadian GAAP standards is also nearing completion and are summarized in our management disclosure and analysis. We are therefore comfortable based on our analysis standard in place today to estimate that shareholders equity as at January 1, 2010 will decrease by less than 4% under IFRS.
We do not anticipate any significant differences in reported cash flow from operations. As we move through the remainder of Q4 and into Q1, our focus will be to finalize our analysis and to adopt the new requirements for reporting as required by the CICA and the security bodies in Canada.
Thank you. I will now return it to John for some closing comments.
Thank you very much. As you can see, we are following our 2010 plan as we had anticipated last fall. We are in the process of finalizing our 2011 plans, which will also establish our targeted 2011 budget. We remain focused and disciplined to ensure we are creating long-term shareholder value.
With that Operator, I would open up the call to questions participants may have.
(Operator Instructions) Our first question is from Andrew Fairbanks from Bank of America.
Andrew Fairbanks - Bank of America
I was wondering what timeframe are you thinking of now for the decision on the Horizon expansion. Will it still be sometime early winter, or would you expect that might be drifting into the springtime?
Our timeframe for Horizon is that we're looking to have the execution strategy, a more detailed cost estimate I would say in the first quarter of 2011. And at that time we will decide how and when we will expand Horizon. So I would expect some news on that in the first quarter of 2011 to the Street.
Andrew Fairbanks - Bank of America
And I guess a follow up question. I know it sounds kind of prudish to be talking about hedging, and as you move into potentially an expensive Horizon expansion project, how do you think about hedging at this point? You know, are you so large that you wouldn't feel you'd need a great deal of hedging to accommodate the capital spending period for the Horizon expansion, or would you just go ahead and kind of as you're doing this year and next, match some degree of hedging to the capital you're going to be spending?
That's a very good question. It actually will be part of overall execution strategy. We feel we don't have to hedge as much going forward, mainly because we have a bigger base to work from now, a larger cash flow. Also, our execution strategy will have a greater degree of flexibility in it than we had in Phase 1. And we will be taking this in a stepwise approach and would probably limit the amount of capital spending per year. So that gives us a much more robust project, and also I think gives us a larger degree of cost control going forward.
We'll detail that more as we announce the 2011 budget giving more detail on how we plan to execute Horizon. In that budget I think we'll target to announce it to the Street towards the end of November, early December.
Our next question is from Joe Citarrella from Goldman Sachs.
Joe Citarrella - Goldman Sachs
In terms of just following up on Horizon here on future phases is, we are waiting for more detailed cost estimates. I was hoping you could offer some early thoughts on how you expect costs to compare to the first phase. I mean, should we be thinking about close to the $88,000 per barrel a day that we had from Phase 1 or anticipating anything meaningfully different here? Thank you.
I think Joe, right now we're still in the final stages of it. We're kind of in a unique window right now. And the cost estimates that we've had before may look a little high compared to what we are able to execute in this environment.
However, a concern is, once you start announcing projects, we could get the industry as a whole back into that inflationary period, and we would have cost pressures again. So all our execution strategy is built around giving us the maximum flexibility and the ability to control cost and stop and start as we go forward.
As far as $88,000 or $89,000 which we did Phase 1 for, I think it would be difficult to achieve that level of cost going forward in expansions.
So, it will be higher than the $89,000 in Phase 1. Just how much higher, we haven't nailed down exactly yet.
Joe Citarrella - Goldman Sachs
Got it. And similar lines on Kirby, hoping you just provide some additional color there. I mean, you're expanding the whole project to 70,000 to 100,000 per day now, and you mentioned capital of about 31,000 for the first phase. Should we be thinking about a lower capital spend for the remainder of the project given expected synergies? And also any thoughts on timing for production here? Thank you.
So Kirby Phase 1, (first) team and his 23rd team, and then the oil will come up you know around let's say, (diesel) won't be like cyclic where it comes out at you right away. So it will take some time, probably in 2014 when we start production.
As far as costs going forward for the expansion on Kirby Phase 2 and the de-bottlenecking we'd expect to be able to leverage the infrastructure we've built here for Kirby Phase 1. And the de-bottlenecking for sure will give us better cost energies. So we think it will be lower.
At this point in time, we haven't quantified how much lower that will be, but we expect it to trend lower for future expansions. We'd also expect to see operating cost to be a little bit lower with expansions.
Our next question is from Mark Polak from Scotia Capital.
Mark Polak - Scotia Capital
A quick question for you. Now that you've acquired the (interspersed) lands around Kirby, that expansion and the bottleneck, should we think about that sort of pushing out Grouse and all the other projects a little further and sort of coming on in that 2016 timeframe?
That's a good question. Mark, we're still looking at it. What we're planning to do with both Grouse and Birch Mountain East is that we're looking now at the possibility of making regulatory applications for both of those in 2011 and trying to put Kirby 2 in there in between. So we're not sure exactly how the schedule would be, but there maybe some juggling of schedules. You would think just logically Kirby 2 would probably become before; however, Grouse is looking very good, so we may try to do Grouse first or very close together with Kirby 2.
Mark Polak - Scotia Capital
Okay, but no chance to the overall, kind of adding 30,000 to 60,000 barrels at average 2 to 3 years? Is that still sort of the pace you are comfortable with?
We are very comfortable with that pace, and we think basically the contracting and construction market can handle that. If we get going too far, you are going to outrun the construction market and overrun the engineering firm's ability to deliver for you.
Mark Polak - Scotia Capital
And just curious what you are seeing in terms of inflation as you're working through the latter stages of, you know, looking at Horizon here we've seen costs go up on (curl), and some (inaudible) mentioned this morning that after a fairly sharp reduction and the slowdown of '08, '09 costs are coming up, so you are getting busy as you look at that pipeline. Just curious what you're thinking there?
We are Mark, concerned about inflation and about the ability to reignite inflation. I will say that on our projects on Tranche 2 we are tracking below our control estimate or cost estimate at this point in time and that's one of the reasons why we reduced capital spending in 2010 because of their ability to do their work with less. So we are seeing our ability to do it for less, and we (constricted). But going forward, I think it's all a matter of activity. So it becomes very difficult to say that going forward you're going to be able to do it for less. But we haven't seen inflation yet on that side.
Our next question is from George Toriola from UBS Securities.
George Toriola - UBS Securities
The question is around operating costs in the North Sea. Obviously in the quarter, you had some other issues. But just looking at that business, where would you expect operating costs to be, and what are the drivers you have to the extent that you can bring costs down, what drivers do you have?
The biggest driver in the North Sea for operating costs are the production volumes. Mostly operating costs are essentially fixed. So we didn't have as we had in the third quarter all the turnarounds, and that's the time to do it is in the summer and the water conditions are better. Your production's down and your operating costs go up significantly.
So for us, maintaining production volumes is the biggest driver, and increasing volumes if we can. As you know, we started up a drill string in Ninian this year. Obviously we took a hiatus in 2009. Mainly because of the uncertainty in the global financial market, we want to reduce our capital spending. As a result, there's a lot of safety-critical work we have to do here in 2010 and 2011 we had to get to before we get to really see some of the juicier production volume adds. So as we get to that we'll see production more stable and operating costs stabilize as well.
George Toriola - UBS Securities
Sort of, where do you expect that to settle out at? What sort of numbers would you expect?
We're saying for this year, operating costs are $30 to $31 a barrel. I would expect us to be very close to that in 2011.
George Toriola - UBS Securities
And then quickly on Horizon, is it fair to say that as you push Phase 1 volumes towards sort of design capacities here that you are now getting to test some of the pieces of equipment there, and that's where you're starting to see some of this reliability issues. Is that a fair way to look at it?
Actually George, I don't think that's the case actually. When we're at higher volumes we actually run better. It's when we have upsets; we go down and go back up, that's when we have issues with reliability; starting equipment up and pulling it down causes reliability issues. When we run at design capacity, that's the best time we run; everything runs smooth, it just spurs along.
So, really what we're finding here, to be blunt, the hydrogen exchanger that we had here was a manufacturing error here that occurred and was not detected by their quality control or our quality control. I don't know if you could have detected it actually. And it took this long before it actually generated a leak. So we're still working through some of those issues which occurred in that 2007, 2008 period with all the hyperinflation, and every vendor was trying to get as much equipment out the door as possible.
And so we still have some of those things coming back to bite us.
George Toriola - UBS Securities
So it's not really sort of the pushing the envelope, but more and more issues from start-up so to speak.
Not at all. When we run at higher rates, that's when we run best.
That's what the equipment is designed to run, that it mixes sweet spot at that rate.
Our next question is from Monroe Helm from Barrow Hanley.
Monroe Helm - Barrow Hanley
I think you said $1.5 billion dollars worth of acquisition opportunities this year. I know it is going to be hard for next year to know, because it depends on what comes on the market, but how should we think about how much of your capital would go into acquisitions next year?
You are right Monroe, that's a very difficult question to answer. As you know, we are very opportunistic. We are very, very selective. Every acquisition we made this year has been able to reduce operating cost rate out of the shoot as soon as we integrate it into our infrastructure, with the exception of Kirby obviously, because there's no production there. But every other one, we have been able to lower operating costs, and we have looked at a tremendous number of acquisitions. So we looked at everything that comes through our core area that's up for sale, and we've been very, very selective.
Now what's going to come up for sale in 2011, it's hard to say. I guess, probably depends what the (inaudible) phases are and how other companies react.
Monroe Helm - Barrow Hanley
Given the comment you made that you think gas prices are going to stay depressed for quite a while to come, can you kind of give us what are the key things you look for, for gas acquisitions? Obviously, for the bolt-ons, you can integrate them in and lower the operating cost. What else would make a gas property attractive from an acquisition standpoint at this point of time, especially in light of the fact that the forward curve is a lock-in, but that would contribute regular rates of return?
Yes, obviously you have to be able to buy it at the right price and you need to be able to get operating cost synergies right out of the shoot. And hopefully there will be upsides in those assets that at some point in the future you'll be able to leverage. And I agree; it's difficult. And those are some of the key things. We are not going to tell you the whole parameters for us on acquisitions, because we want to keep that to ourselves.
Monroe Helm - Barrow Hanley
Can you show would this carry your view on gas prices? How long do you think this oversupply could last? Do you have any thoughts that you want to share with us?
I don't if we got a good feel for it or not, but we do know that we believe shale gas production's real. It looks like shale gas reserves are real, but I don't think that's for sure yet. And it looks like shale gas might work at $4 an Mcf, but maybe owing to sweet spots and maybe owing to liquid rich. So it's difficult to say, but I could see us being here for three to maybe seven years.
Monroe Helm - Barrow Hanley
One last question. Maybe I didn't hear this right. Did you say that the excess cash flow that you have this year, free cash flow after CapEx dividends and acquisition is going to reduce debt?
Our next question comes from Mike Dunn from FirstEnergy Capital.
Mike Dunn - FirstEnergy Capital
A couple of question on Kirby and the new property acquisition there. I think you've mentioned sort of an ultimate range of production between 70,000 and 100,000 barrels a day. Just wondering what some of that uncertainty in the high versus the low end of that is?
And I think looking through old enterprise disclosures, some of those resources were I think in the Wabasca as opposed to the McMurray. So I'm not sure if you can comment on how you view sort of the variety of resource there. Is co-gen an option for Kirby, what are you thinking about there?
The range 70,000 to 100,000 is just our range on what is the optimum plant size to maximize value. And so depending on your price assumptions, your gas cost assumptions and basically the kind of tight curve we use for each of the production well or pads we expect to drill, you get a different answer. And I would say there is economics to go to 60,000 barrel a day expansion, and there is economics to 30,000. It's just a matter of what is the optimum NPV. So we got a choice. We know what's at 60. We know what's at 30. We're just trying to maximize the value. That's why I gave you the range.
But on the Wabasca for Kirby, there is Wabasca that's a substantial part of the acquisition. And not all Wabascas create a (depot). A lot of it has a significant amount of clays in it. And when you steam it, it basically locks it up. So Wabasca in general terms has always been deemed to be non-SAGDiable.
We've done much work on the Wabasca and particularly in this Wabasca zone around Kirby and what we acquired here in this acquisition, and we are strongly of the belief that it can be SAGD-ied and it's in our reserves.
Mike Dunn - FirstEnergy Capital
On co-gen, Steve?
Right now, it doesn't look like co-gen makes sense for us. We're not to the scale. But maybe when we expand, if we go to that 70,000 or 100,000 barrels a day, we will look at it at that point in time. But right now, for Phase 1, that's not prudent.
Mike Dunn - FirstEnergy Capital
Do you guys have anything to update us in regards to progress or negotiations with terms for the North West upgrade?
We are still in negotiations with the operative government. I would say they are going along pretty well. It's obviously a very tough agreement and everybody wants to make it sure they get it right. So that's where we're making good progress, but we're not there yet.
Our next question is from John Herrlin from Société Générale.
John Herrlin - Société Générale
With IFRS, can you indicate how you've allocated the charges, like how much is PP&E versus stock options, et cetera?
John, I don't think that we're in a position to discuss those allocations right now. The largest, as you know, would be the stock compensation, because there is a change in the way you calculate it to more of a block shows and away from cash determination. The other one that's outstanding right now that is giving us a little bit of angst is the ARO and what rate to use in discounting the factor.
And of course there's two rates out there. There's the risk adjusted and the risk free rate. And we're looking for some feedback on those two rates from our advisors on that. So to discuss the allocation between the various areas I think would be premature.
John Herrlin - Société Générale
One other kind of related to question to that, though. You gave country pools from the reporting basis. Going forward, do you think you'll have any sort of different operational reporting?
John Herrlin - Société Générale
You're seeing a lot of EMPs in North America, returned to North America after having explored abroad. You're obviously in the North Sea and West Africa. Are you still going to be pursuing more even to kind of keep a status quo with respect to international (E&D).
We're in the North Sea, as you said, and offshore West Africa. We're very happy with the results we've had in North Sea and offshore West Africa. It's a significant free cash flow generator for the company. We are open and would look to expand those operations if they are available, although it has been a very tough to do so here in the last few years. So we're going to stay there, and we'll look for opportunities to leverage our expertise into other opportunities if they show up.
Our next question is from Kam Sandhar from Peters & Co.
Kam Sandhar - Peters & Co.
Just wondering if you could give us your steam-roller expectations for Kirby. And then the second one is just on where you're at in terms of the sequencing of projects obviously given this acquisition of additional lands at Kirby and whether that changes on the heavy oil side? And then, I am just wondering where you are at in terms of regulatory applications for those projects and whether you see that being a potential bottleneck?
There are a bunch of ways to answer that. As you know, on SAGD, the profile starts out high and then drops down to a lower number as you get lined out and then at nearly end of the life it tails up again. So we'd expect the lower end of it to be that, sort of 2.4 SOR but when you take over the whole life of the pad, we're probably in at 3 SOR to 3.2 SOR which is very similar to, I would say, Jackfish and may be not quite as good as Foster Creek.
As far as the sequence goes, it eluded to that earlier. Right now, we're going to stick with our sequence, but we are looking at potentially adjusting Kirby 2 to maybe sneak in there or maybe bump somebody back a bit.
Regulatory approval, we're going to start the regulatory process in Grouse and Birch Mountain East in 2011, and we'll also look at what we need to do for Kirby 2. And is your bottleneck there? There could be, and we've allowed for extra time to get to re-processing our plan.
Kam Sandhar - Peters & Co.
When you elude to obviously your inventory shifting to a conventional gas septum as being the one that you're working on in the near-term, can you highlight maybe some other areas that you are looking potentially to putting more capital to work in?
We are looking to put very little capital to work in any (inaudible) gas properties and kind of the conventional gas most of it in 2011 we'll talk more about this when to the budget, might get it finalized (from) being a bit premature. But I would expect most of it to be strategic and land preserving drilling and it will be a small program. Most of our unconventional, as you say, is in the Montney, in BC, Alberta and to the Northern BC. We also have strong plays in the Deep Basin in Northwest Alberta.
(Operator Instructions) Our next question is from Barbara Betanski from Addenda Capital.
Barbara Betanski - Addenda Capital
Just a follow-up on the gas, given that you are expecting this week an extended period, would you expect your gas production overall to continue to decline over the next number of years, or have sort of curb the decline with the transition to the resource play? And then, I am wondering what volume of gas did you acquire this year?
We expected in 2011 and going forward, as gas prices increase, we'll preserve our land base, but I expect to see gas production decline. In our case, we can hold the land and preserve it for when gas prices come back. So it makes no sense, particularly when we have lots and lots of oil projects in a hopper to drill up. So we are not going to drill gas when we don't need, so you'll see production decline.
And we did buy gas. In our acquisitions, so far we bought about 214 a day of gas and about 9,000 barrels a day of oil (inaudible) and that's the sort of initial rates. Obviously, they decline as you go through the year.
Barbara Betanski - Addenda Capital
In terms of when you might plan to significantly ramp up spending on Horizon's sales tow and three, so I'm sort of thinking about that high level of free cash that you're generating currently, would you expect that to be reduced perhaps in 2012 or 2013, or can you talk about that right now?
We're still working on how the execution strategy is going to portray and how we want to go forward and we need to get cost certainty assured for Horizon before we go ahead. And we also need to ensure that we have our return on capital criteria met. And as you know, the costs are high and we need to make sure it's going to work.
We don't want to have ourselves caught in a position like we did in Phase 1 where hyperinflation sort of took control of the process. We want to be in control of the process this time.
Thank you. There are no further questions registered at this time. I would turn the meeting back over to Mr. Langille.
Thank you very much, operator. And thank you ladies and gentlemen for attending our conference call. And as usual, if you have any further questions, don't hesitate to contact us. And have a good day everybody. Thank you.
Thank you. The conference has now ended. Please disconnect your lines at this time. And we thank you for your participation.
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